United Kingdom Oil and Gas Fields Commemorative Millennium Volume
Geological Society Memoirs
Society Book Editors A. J. FLEET (CHIEF EDITOR) P. DOYLE F. J. GREGORY J. S. GRIFFITHS A. J. HARTLEY R. E. HOLDSWORTH A. C. MORTON N. S. ROBINS M. S. STOKER J. P. TURNER
Society books reviewing procedures The Society makes every effort to ensure that the scientific and production quality of its books matches that of its journals. Since 1997, all book proposals have been refereed by specialist reviewers as well as by the Society's Books Editorial Committee. If the referees identify weaknesses in the proposal, these must be addressed before the proposal is accepted. Once the book is accepted, the Society has a team of Book Editors (listed above) who ensure that the volume editors follow strict guidelines on refereeing and quality control. We insist that individual papers can only be accepted after satisfactory review by two independent referees. The questions on the review forms are similar to those for Journal of the Geological Society. The referees' forms and comments must be available to the Society's Book Editors on request. Although many of the books result from meetings, the editors are expected to commission papers that were not presented at the meeting to ensure that the book provides a balanced coverage of the subject. Being accepted for presentation at the meeting does not guarantee inclusion in the book. Geological Society Special Publications are included in the ISI Science Citation Index, but they do not have an impact factor, the latter being applicable only to journals. More information about submitting a proposal and producing a Society Publication can be found on the Society's web site: www. geolsoc.org.uk.
GEOLOGICAL SOCIETY MEMOIRS NO. 20
United Kingdom Oil and Gas Fields Commemorative Millennium Volume EDITED
BY
J. G. G L U Y A S Acorn Oil & Gas Ltd, Staines, Middlesex, UK
H. M. H I C H E N S Oil and Gas Directorate, London, UK
2003 Published by The Geological Society London
THE GEOLOGICAL SOCIETY The Geological Society of London (GSL) was founded in 1807. It is the oldest national geological society in the world and the largest in Europe. It was incorporated under Royal Charter in 1825 and is Registered Charity 210161. The Society is the U K national learned and professional society for geology with a worldwide Fellowship (FGS) of 9000. The Society has the power to confer Chartered status on suitably qualified Fellows, and about 2000 of the Fellowship carry the title (CGeol). Chartered Geologists may also obtain the equivalent European title, European Geologist (EurGeol). One fifth of the Society's fellowship resides outside the UK. To find out more about the Society, log on to www.geolsoc.org.uk. The Geological Society Publishing House (Bath, UK) produces the Society's international journals and books, and acts as European distributor for selected publications of the American Association of Petroleum Geologists (AAPG), the American Geological Institute (AGI), the Indonesian Petroleum Association (IPA), the Geological Society of America (GSA), the Society for Sedimentary Geology (SEPM) and the Geologists' Association (GA). Joint marketing agreements ensure that GSL Fellows may purchase these societies' publications at a discount. The Society's online bookshop (accessible from www.geolsoc.org.uk) offers secure book purchasing with your credit or debit card. To find out about joining the Society and benefiting from substantial discounts on publications of GSL and other societies worldwide, consult www.geolsoc.org.uk, or contact the Fellowship Department at: The Geological Society, Burlington House, Piccadilly, London W1J 0BG: Tel. +44 (0)20 7434 9944; Fax +44 (0)20 7439 8975; Email: www.geolsoc.org.uk
[email protected].
Published by The Geological Society from: The Geological Society Publishing House Unit 7, Brassmill Enterprise Centre Brassmill Lane Bath BA1 3JN, UK (Orders: Tel. +44 (0)1225 445046 Fax +44 (0)1225 442836) Online bookshop: http://bookshop.geolsoc.org.uk The publishers make no representation, express or implied, with regard to the accuracy of the information contained in this book and cannot accept any legal responsibility for any errors or omissions that may be made. ~) The Geological Society of London 2003. All rights reserved. No reproduction, copy or transmission of this publication may be made without written permission. No paragraph of this publication may be reproduced, copied or transmitted save with the provisions of the Copyright Licensing Agency, 90 Tottenham Court Road, London W1P 9HE. Users registered with the Copyright Clearance Center, 27 Congress Street, Salem, MA 01970, USA: the item-fee code for this publication is 0435-4052/03/$15.00.
British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. ISBN 1-86239-089-4 ISBN 0435~4052
Typeset by Aarontype Ltd, Bristol, UK Project management by Swales & Willis Printed by Alden Press, Oxford, UK
Distributors USA AAPG Bookstore PO Box 979 Tulsa OK 74101-0979 USA Orders: Tel. +1 918 584-2555 Fax +1 918 560-2652 E-mail
[email protected] India Affiliated East-West Press PVT Ltd G-l/16 Ansari Road, Daryaganj, New Delhi 110 002 India Orders." Tel. +91 11 327-9113 Fax +91 11 326-0538 E-mail affiliat @ nda.vsnl.net.in Japan Kanda Book Trading Co. Cityhouse Tama 204 Tsurumaki 1-3-10 Tama-shi Tokyo 206-0034 Japan Orders." Tel. +81 (0)423 57-7650 Fax +81 (0)423 57-7651
Contents
Foreword
vii
Part 1: Introduction UK Oil and Gas Fields - An Overview by J. G. GLUYAS & H. M. HICHENS Lessons from oil and gas exploration in and around Britain by R. F. P. HARDMAN The tectonic and stratigraphic framework of the United Kingdom's oil and gas fields by J. R. UNDERHILL
3 5 17
Part 2: East Irish Sea Fields The Douglas Oil Field, Block 110/13b, East Irish Sea by A. YALIZ & N. McKIM The Hamilton and Hamilton North Gas Fields, Block 110/13a, East Irish Sea by A. YALIZ & P. TAYLOR The Lennox Oil and Gas Field, Block 110/15, East Irish Sea by A. YALIZ & T. CHAPMAN The North Morecambe Field, Block 110/2a, East Irish Sea by G. COWAN & T. BOYCOTT-BROWN The South Morecambe Gas Field, Blocks 110/2a, 110/3a, ll0/Ta and l10/8a, East Irish Sea by J. C. BASTIN, T. BOYCOTT-BROWN,A. SIMS & R. WOODHOUSE
63 77
97
107
121
Part 4: Viking Graben Fields The Andrew and Cyrus Fields, Blocks 16/27a, 16/28, UK North Sea by J. E. JOLLEY The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields by I. A. STUART The Beryl Field, Block 9/13, UK North Sea, by R. M. KARASEK, R. L. VAUGHAN 8~; T. T. MASUDA The Birch Oil Field, Block 16/12a, UK North Sea by J. HOOK, A. ABHVANI, J. G. GLUYAS & M. LAWLOR The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea by K. J. FLETCHER The East Brae Field, Blocks 16/03a, 16/03b, UK North Sea by S. R. F. BRANTER The North Brae and Beinn Fields, Block 16/7a, UK North Sea by J. A. BREHM The South Brae Field, Blocks 16/07a, 16/07b, UK North Sea by K. J. FLETCHER The West Brae and Sedgwick Fields, Blocks 16/06a, 16/07a, UK North Sea by S. D. WRIGHT The Brent Field, Block 211/29, UK North Sea by S. R. TAYLOR, J. ALMOND, S. ARNOTT, D. KEMSHELL & D. TAYLOR The Deveron Field, Block 211/18a, UK North Sea by A. M. BROWN & A. D. MILNE The Don Field, Blocks 211/13a, 211/14, 211/18a, 211/19a, UK North Sea by A. D. MILNE & A. M. BROWN
265
283 291 305 315 327
335 355 369 383
87
Part 3: Atlantic Margin Fields The Foinaven Field, Blocks 204/19, 204/24a, UK North Sea by A. G. CARRUTH
The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14, 3/15, UK North Sea by J. S. RITCHIE The Harding Field, Block 9/23b by A. J. BECKLY, T. NASH, R. POLLARD, C. BRUCE, P. FREEMAN & G. PAGE The Heather Field, Block 2/5, UK North Sea by S. KAY The Kingfisher Field, Block 16/8a, UK North Sea by S. SPENCE & H. KREUTZ The North Cormorant Field, Block 211/21a, UK North Sea by L. BAYER The Staffa Field, Block 3/8b, UK North Sea by J. G. GLUYAS & J. R. UNDERHILL The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211/24, 211/25 UK sector, Northern North Sea by K. A. GIBBONS, C. A. JOURDAN & J. HESTHAMMER The Strathspey Field, Block 3/4a, UK North Sea by G. MAXWELL, e . E. STANLEY & D. C. WHITE The T-Block Fields, Block 16/17, UK North Sea by M. GAMBARO & V. DONAGEMMA The Thistle Field, Blocks 211/18a, 211/19a, UK North Sea by A. M. BROWN, A. D. MILNE & A. KAY
Part 5: Moray Firth Fields The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea by M. GAMBARO • M. CURRIE The Britannia Field, Blocks 15/29a, 15/30, 16/26, 16/27a, 16/27b, UK North Sea by P. J. HILL & A. J. PALFREY The Captain Field, Block 13/22a, UK North Sea by S. J. PINNOCK & A. R. J. CLITHEROE The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea by M. A. HARVEY & S. CURRIE The MacCulloch Field, Block 15/24b, UK North Sea by C. GUNN, J. A. MACLEOD, P. SALVADOR & J. TOMKINSON The Scott Field, Blocks 15/21a, 15/22, UK North Sea by S. GUSCOTT, K. RUSSELL, A. THICKPENNY & R. PODDUBIUK
395 415 431 443
453
467
133
Part 6: Central Graben Fields 139 153 167 183 191 199 211 223
233 251 257
The Auk Field, Block 30/16, UK North Sea by N. H. TREWIN, S. G. FRYBERGER & H. KREUTZ The Banff Field, Blocks 22/27a, 29/2a, UK North Sea by N. EVANS, J. A. MACLEOD, N. MACMILLAN, P. RORISON r P. SALVADOR The Curlew Field, Block 29/7, UK North Sea by G. ENEYOK, P. BUSSINK ~: A. MAAN The Erskine Field, Block 23/26, UK North Sea by R. N. COWARD The Fife and Fergus Fields, Block 31/26a, UK North Sea by M. SHEPHERD, A. MACGREGOR, K. BUSH & J. WAKEFIELD The Flora Field, Blocks 31/26a, 31/26c, UK North Sea by R. D. HAYWARD,C. A. L. MARTIN, D. HARRISON, G. VAN DORY, S. GUTHRIE & N. PADGET The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea by A. CARTER & J. HEALE The Fulmar Field, Blocks 30/16, 30/1 lb, UK North Sea by O. KUHN, S. W. SMITH, K. VAN NOORT & B. LOISEAU The Maureen Field, Block 16/29a, UK Central North Sea by P. M. CHANDLER & B. DICKINSON
485
497 509 523
537
549 557
563 587
vi The Moira Field, Block 16/29a, U K Central North Sea by P. M. CHANDLER & B. DICKINSON The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, 22/18, 22/23a, U K North Sea by A. J. C. HOGG The Nelson Field, Blocks 22/tl, 22/6a, 22/7, 22/12a, UK North Sea by J. M. KUNKA, G. WILLIAMS, B. CULLEN, J. BOYD-GORST, G. R. DYER, J. A. GARNHAM, A. WARNOCK, J. WARDELL, A. DAVIES & P. LYNES The Pierce Field, Blocks 23/22a, 23/27, UK North Sea by P. BIRCH & J. HAYNES
CONTENTS
603 611
617 647
Part 7: Southern North Sea Gas Fields The Barque Field, Blocks 48/13a, 48/14, U K North Sea by M. J. SARGINSON The Boulton Field, Block 44/21a, U K North Sea by A. M. CONWAY & C. VALVATNE The Camelot Fields, Blocks 53/la, 53/2, U K North Sea by R. M. KARASEK & J. R. HUNT The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea by M. J. SARGINSON The Corvette Field, Block 49/24, UK Southern North Sea by A. P. HILLIER The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, U K North Sea by C. W. MCCRONE The Gawain Field, Blocks 49/24, 49/29a, UK North Sea by R. A. OSBON, O. C. WERNGREN, A. KYEI, D. MANLEY & J. SIX The Guinevere Field, Block 48/17b, UK North Sea by M. LAPPIN, D. J. HENDRY, I. A. SAIKIA The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields by P. COOKE-YARBOROUGH & E. SMITH The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea by C. W. MCCRONE, M. GAINSKI & P. J. LUMSDEN The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea by D. E. LAWTON & P. P. ROBERSON The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea by A. P. HILLIER The Malory Field, Block 48/12d, UK North Sea by R. E. O'BRIEN, M. LAPPIN, F. KOMLOSI & J. A. LOFTUS The Mercury and Neptune Fields, Blocks 47/9b, 47/4b, 47/5a, 42/29, UK North Sea by B. SMITH & V. STARCHER
663 671 681 691
The Murdoch Gas Field, Block 44/22a, UK Southern North Sea by A. M. CONWAY & C. VALVATNE The Pickerill Field, Blocks 48/11a, 48/11b, 48/12c, 48/17b, UK North Sea by O. C. WERNGP,EN, D. MANLEY & A. P. HEWARD The Schooner Field, Blocks 44/26a, 43/30a, U K North Sea by A. MOSCARIELLO The Scan North, Scan South and Scan East Fields, Block 49/25a, U K North Sea by A. P. HILLIER The Trent Gas Field, Block 43/24a, UK North Sea by P. T. O'MARA, M. MERRYWEATHER, M. STOCKWELL & M. M. BOWLER The Tyne Gas Fields, Block 44/18a, UK North Sea by P. T. O'MARA, M. MERRYWEATHER & D. S. COOPER The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea by J. COURTIER & H. RICHES The Viking Field, Blocks 49/12a, 49/16, 49/17, U K North Sea by H. RICHES The Waveney Field, Block 48/17c, UK Southern North Sea by D. R. S. BRUCE & P. REBORA The Windermere Gas Field, Blocks 49/9b, 49/4a, U K Southern North Sea by R. J. BAILEY & J. E. CLEVER
789
799 811 825
835
851 861 871 881 893
699
Part 8: East Midlands Basin Fields 705
713 723
731
741
749
The Hatfield Moors and Hatfield West Gas (storage) Fields, South Yorkshire by J. WARD, A. CHAN & B. RAMSAY The Saltfleetby Field, Block L 47/16, Licence PEDL 005, Onshore UK by T. HODGE The West Firsby Oilfield, Development Licence 003, Lincolnshire by R. J. BAILEY
905 911 921
Part 9: Weald and Wessex Basin Fields The Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey and Sussex, UK Onshore by S. TRUEMAN The Kimmeridge Bay Oilfield, Dorset, UK Onshore by J. G. GLUYAS, I. J. EVANS & D. RICHARDS
929 943
761 Appendix 1
949
Appendix 2
979
Index
995
771
777
It is recommended that reference to all or part of this book should be made in one of the following ways: GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20. YALIZ, A. & McKIM, N. 2003. The Douglas Oil Field, Block 110/13b, East Irish Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 63-75.
Foreword
It was interesting to review the articles in this volume having also been involved in its predecessor volume ten years ago. Some industry trends have followed an expected path but some have not. The developed fields are more numerous and are smaller, as predicted by a conventional creaming curve. The first volume documented 64 oil and gas fields, which had been found and developed during the first 25 years of life of the UK North Sea. They had an average reserve size in excess of 300 mmboe. The current volume describes approximately double that number, including at least 40 new fields developed in the next ten-year period. These new fields have a reduced average reserve size of approximately 100 MMBOE. More unexpectedly, the average period from discovery to production (approximately 12 years) and the average number of appraisal wells (3), are essentially unchanged. Some developments now happen very rapidly but the statistics for the last ten years are affected by the inclusion of the first heavy oil and H P - H T gas condensate developments. It seems that we are not always getting a quicker payback on exploration investment. It is clear however that the industry has made considerable progress in terms of developing smaller and more challenging fields. In addition to the reduction in average field size noted above, the minimum developed field size has also reduced, from 7-10 M M B O E to 2-4 MMBOE. Our industry is also routinely developing fields with more and more problematical reservoir and fluid characteristics. The various methods by which these challenges are met are documented within the volume. The day of the new, big, central, processing platforms seem to be over. Recurring themes include: 9 9 9 9 9 9
Unmanned or not-normally manned, minimum facility platforms. High angle/horizontal, long reach wells. Sub-sea completion technology. Extended well test and FPSO technology. Mechanical stimulation of low permeability reservoirs. Improved seismic definition.
All of these techniques are being combined to increase well productivity and recovery for less cost and at less risk. They provide evidence of an innovative and successful industry. It is hoped that this volume will help to inspire the next phase of innovation and success in the UK North Sea. I. L. Abbots Den Haag April 2001
Front cover illustrations:
PES6GB PESGB, 2nd Floor, 41-48 Kent House, 87 Regent Street, London W i B 4EH Tel. 0207 494 1933, fax. 0207 494 1944, web www.pesgb.org.uk Part-title maps:
Reproduced with the permission of Wood MacKenzie.
UK Oil and Gas F i e l d s - An Overview
This volume was conceived when one of us (JG) returned to the U K in mid-1996. Having not worked the U K offshore since the late 1980s it was clear that there had been many changes, not least in the number of fields on production. During that first year back in the UK, JG's copy of Abbots (1991) UK Oil and Gas Fields, 25 Years Commemorative Volume became exceedingly well used. A casual comment to Wendy Cawthorne of the Geological Society library to this effect solicited the response that JG was not alone in finding Abbots (1991) useful. Memoir 14 was the Geological Society's 'best seller'. However, although Abbots (1991) continues to sell well, it was by 1996 out of date insofar as it contains papers describing only about half of the fields then on production. A combination of egotistical zeal, wishing for a bestseller and altruism towards the U K industry led us to make an offer to the Geological Society to revise Memoir 14. The offer was accepted and by April 1998, editors had been appointed and letters of invitation to contribute to the memoir were sent to exploration managers in all the U K operating companies. The responses to those letters were for the most part positive. A request was made to authors for manuscripts to be sent to the editors by June 1999. The first to arrive was six months ahead of schedule (thanks A. Yaliz & N. McKim for their paper on the Douglas Field). However, neither the editors, nor we suspect the authors anticipated how much the industry was going to change in 1999 and 2000. The U K licence map was literally redrawn as companies merged and others were taken over. In this turmoil, it is astonishing to us that so many authors were able to complete their papers. As we draft this introduction in April 2001, it is clear that the volume has captured an enormous quantity of hitherto unpublished information on the oil and gas fields of the UK. It is also clear that it is already out of date. Only when petroleum ceases to be produced by the U K will it be possible to fully complete a volume such as this.
What is in this book? This book contains a forward by Ian Abbots (Gulf Canada), editor of the best-selling Memoir 14, a review of how the major plays were discovered by Richard Hardman (Amerada Hess) and an introduction to the stratigraphical context of the U K ' s petroleum resources by John Underhilt (University of Edinburgh). Maps showing all of the U K fields in the context of their plays support Underhill's chapter. The main part of the book is divided into eight parts covering: 9 9 9 9 9 9 9 9
East Irish Sea Fields Atlantic Margin Fields Viking Graben Fields Moray Firth Fields Central Graben Fields Southern N o r t h Sea Gas Fields East Midlands Basin Fields Weald and Wessex Basin Fields
Each of these sections is further divided into one or more chapters, whereby each chapter describes a field or cluster of fields. Each of the field description chapters follows a simple constant format: LOCATION HISTORY
DISCOVERY METHOD STRUCTURE
Pre-discovery Discovery Post-discovery
STRATIGRAPHY TRAP
Trap type Seals Faults etc
RESERVOIR
Depositional setting Pore types & diagenesis Porosity, permeability Pressure relationships
SOURCE
Source beds Maturation Migration and charge
RESERVES A N D PRODUCTION
Petroleum in place Petroleum reserves Cumulative production Recovery factor and reserves Recovery factor through time, impact of geological work on reserves Production rate
This common format should enable readers to get the data they need easily and efficiently. In general readers will find that for the older fields there is greater emphasis on the production story while on new fields the geological description is pre-eminent. There are about 130 fields described in this volume. One of the significant strengths of Memoir 14 is the presence of a large appendix containing summarized field data that includes geology, reservoir properties and fluid composition and properties. A similar table exists in Appendix 1 of this volume.
Sources of additional data on U K oil and gas fields It was our hope at the outset of this project to capture all the fields currently on production. This did not prove possible for a number of reasons. While most of the operating companies were positive about this project and gave freely the time of their staff to act as authors, a few companies declined to participate. In the absence of chapters on some fields we have striven to maintain the comprehensive nature of this volume by providing an extensive bibliography. Appendix 2 lists all the fields onshore and offshore that have produced oil and or gas, together with some of the larger fields still undergoing development. To our surprise there are more than 300 fields in the U K that have produced petroleum. References are given for papers in which the fields are described and reference location maps are provided at the front of each part. In addition to this memoir and Memoir 14, the primary sources of data on U K oil and gas fields are: (1)
(2)
(3)
(3) Tectonic history Regional structure Local structure
GLUYAS, J. G. & HICHENS, H. M. (eds) 2002. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 3-4.
The Petroleum Geology of Northwest Europe conference volumes. There are five such volumes, each with slightly different names and published in 1975, 1981, 1987, 1993 and 1999. They are currently published by the Geological Society although older volumes were published by other organizations. They are often collectively referred to as the Barbican volumes after the venue for the last few of the conferences. The Geological Society Memoir 2 was published in 1960. It contains a thorough account of the early years for petroleum exploration and production for onshore UK. The journals of Petroleum Geoscience (Geological Society & r A G E Publication) and Marine and Petroleum Geology (Elsevier) are also common depositories for field specific information on U K oil and gas fields. The American Association of Petroleum Geologists (AAPG) has published several volumes titled Giant Fields of the Decade within its memoir series. These books are also a useful source of field specific data for the larger U K fields.
4
J.G. GLUYAS & H. M. HICHENS
Acknowledgements In a large book such as this there are hundreds of authors and hundreds more reviewers that have generously contributed their time. Inevitably a few individuals provided an enormous amount of help, making the task of editing easier. We thank Jonathan Evans who helped get this project off the ground; making all of those initial contacts that ultimately delivered this volume. We also thank Alex Kay for her effort in chasing manuscripts within what was then the newly merged BP-Amoco-Arco organization. Beverly Smith and
Bill Bailey reviewed far more than their fair share of manuscripts thank you! Dom Manley, Mark Lappin, Martin Currie, Alan Rezigh, Donal O'Driscol, Steve Taylor and Stan Milne acted as co-ordinators of manuscripts from their respective companies. We would also like to thank Brian Forrester of Wood MacKenzie for his work on the part-title maps. We thank you all. Enjoy the read. Jon Gluyas & Helen Hichens London, April 2001
Lessons from oil and gas exploration in and around Britain R. F. P. H A R D M A N Amerada Hess International Ltd., 33 Grosvenor Place, London S W 1 X 7HY, UK Present address: The Long Barn, Treen, St Levan, Penzance, Cornwall TR19 6LG, UK (e-mail:
[email protected]) Abstract: After 35 years, exploration in and around Britain has reached a mature stage. Pure oil and gas exploration has with certain exceptions given way to the search for small fields close to infrastructure and maximizing recovery from existing fields. To examine the lessons of 35 years of exploration before many of the major players leave the stage is opportune. Lessons learned can be applied elsewhere. An examination of the history suggests that lessons can be grouped under four headings: organization, technical skills, personal qualities and tactics. Successful companies optimize all of these. Unsuccessful companies, on the other hand, often fail because of a particular flaw in one of them. It is concluded that successful exploration companies would field a team captained by a technically competent open-minded manager closely linked to skilled geoscientists, all of whom would have a deep understanding (through relatively long service) of the area being explored. Both managers and geoscientists would be able to take sensible risks and would not confuse the primary concern of the technical merits of a prospect with the secondary concern of the economics of success. Finally, luck appears to play an important part but there is no doubt that successful companies work hard for their luck. Other lessons centre on the quirkiness of individual behaviour. This is something that no amount of study can eliminate. When asked by Jon Gluyas to write a paper of introduction to an updated U K C S Fields Volume to supplement Geological Society Memoir 14 (Abbotts 1991), I was faced with a daunting task. Bowen's (1991) introduction to Memoir 14, 25 years of UK North Sea Exploration, could not really be improved upon. A large amount of history had already been published by PESGB in their 30th Anniversary Book, Tales from early UK Oil Exploration, edited by Richard Moreton (1995). Plus, various other accounts have also surfaced over the years, such as Peter Hinde's book Fortune in the North Sea (1966) and most comprehensively Brennand et al. (1998)
Historical Review of North Sea Exploration. Yet, with a personal record of U K C S exploration stretching from the day in the autumn of 1969 when I joined Amoco (UK) Exploration and the first oil well in the U K C S North Sea 22/18-1 was being tested, I have been almost continually involved in North Sea exploration. Surveying the literature, it struck me that nobody had attempted to draw the type of lesson from this exploration history that with profit could be applied elsewhere. It is with considerable trepidation that this task is undertaken, for it was no less an authority than A. J. P. Taylor who said 'The lesson of history is that there is no lesson'. This then is a very personal account. It is an attempt to make sense and order out of happenings which had multiple causes and where chance was as likely to play at least as great a part as intent. If this paper succeeds it will be by persuading key members of the industry to analyse past events in their field of endeavour and to reflect. If they are fellow explorers, I expect that they will take great pleasure in reading about the exploration itself, with perhaps an even greater pleasure in recalling the discovery of commercial fields. This provides a bond linking us in the discipline. This paper is put forward with huge thanks to all those I have worked with over the last 30 years. The inscription on a bench halfway up the steep climb from a beach near Zennor in Cornwall sums up my feelings, 'To the friends whose love has supported me'. It would be a mark of success if this paper to any degree helps friends in the same way that over the years I have been helped.
Background Schoolboys in wartime Britain were taught in Geography that the North Sea was a shallow sea and that over much of its area Salisbury Cathedral spire, at 365 feet from base to tip, would project from below the waves into the air at both high and low fide. Geography did not then concern itself much with explanations but was more interested in descriptions. It was later, much later, that the history of North Sea coastlines and sea levels came to be investigated in detail. Before 1964, beyond the fishing industry the
economic value of these shallow seas was not recognized. Moreton (1995) states that, 'it was not unusual at the time to switch off one's brain automatically at a coastline'. The first offshore well in the Gulf of Mexico was not drilled until 1949. The link between the offshore and the onshore was missing and consequently, although offshore exploration started just after the First World War in Trinidad, not until after the 1959 discovery of gas at Groningen did anyone think about the North Sea as a possible site of commercial hydrocarbons. Later, the variation through time of land and shallow sea distribution was studied with almost religious fervour by oil geologists including the Exxon school headed by Peter Vail (Vail & Mitchum 1977). Thereafter studies gathered momentum, aided by input from the booming academic world of sedimentology. Technologies were developed, particularly 3D mufti-channel reflection seismic surveying, which gave a detailed understanding of the geometry of the seabed and more critically of the structures and sediments beneath. Early exploration for oil and gas onshore Britain was documented by Lees & Cox (1937) and Lees & Tait (1946). Gas had been accidentally discovered at Heathfield in Sussex in 1902 but the first oil produced from a well specifically drilled for hydrocarbons was at Hardstoft-1 in Derbyshire just after the First World War. Subsequent appraisal wells failed to confirm the discovery. Lees & Cox (1937), with what now must be seen as great foresight, listed the most likely source rocks as the Oil Shale Group of the Lower Carboniferous in Scotland and the blackstone band of the Kimmeridge Shale in Dorset. They also drew attention to the Oxford Clay, the Lias and the Carboniferous Yoredale Series. At that time the process whereby shales rich in organic matter yielded oil was not well understood. They state: Our final drilling proposals were based on positive evidence of the existence of oil in certain formations rather than on theoretical considerations of source rocks. Falcoln & Kent (1960) described the onshore search for hydrocarbons from 1945-1957 and Kent (1985) summarized the entire onshore efforts between 1930 and 1964. The most significant discoveries made in this period came just before and during the Second World War, around Eakring near Nottingham, after Eakring-1 had discovered oil in the Carboniferous in 1939. Kent (1985) states that some 30 million barrels of oil were produced from several small fields in the area from the Millstone Grit. Minor production was obtained from Pleistocene-aged peat at Formby on the shores of Morecambe Bay where despite deep drilling no truly commercial oil was discovered until Hamilton Brothers discovered the Lennox Field, immediately west of the Formby Fault in 1992 (Yaliz & Chapman 2003).
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 5-16.
6
R.F.P.
HARDMAN
At the end of t964 the favoured tax treatment of onshore hydrocarbon production was ended and exploration virtually ceased. At this time there was a widespread belief that although oil and gas exploration onshore was of scientific interest it could not reasonably be expected to lead to 'oil pools of commercial magnitude' (Anonymous 1934). In 1964 the attitude in leading companies such as BP continued to reflect this view. Bowen (1991) states that when he was at university in the 1950s the thought that the United Kingdom would become a significant producer of petroleum would have been viewed as utterly ridiculous. This is a point to be underlined when considering lessons to be learned from exploration of the British Isles for hydrocarbons. The prevailing view in the geological establishment that onshore U K would not yield any major discoveries hampered the search. Although BP was in a long-standing partnership with Gas Council for onshore exploration in Britain it was Gas Council and not BP who discovered the only major field in Britain. Gas Council took over as operator of the Western half of Britain from BP in 1972 and armed with self-belief and fewer prejudices set about the task. Colter & Harvard (1981) described how, after finding oil-bearing Lower Jurassic Bridport Sands at Wytch Farm, they concluded that there was a mechanism whereby the Triassic Sherwood Sandstone below could also have been charged with oil. The key piece of data came from a well drilled on the Isle of Wight, Arreton-2, which showed rich mature marine Lias and Kimmeridge Clay source rocks. Subsequently Wytch Farm D5 found oil-bearing Sherwood Sandstone. The field has been proved to extend under Bournemouth Bay from the shores of Poole Harbour. BP assumed the operatorship in the break-up of the British Gas Corporation. Thanks to world-record extended-reach drilling, BP and partners have secured a reserve of some 400 million barrels, by far and away the largest field onshore Britain and also the largest onshore Europe. The next largest onshore field in Britain is Welton, with only some 15 million barrels.
discovered the Groningen gas field, which at 85 trillion cubic feet is one of the largest gas fields in the world. Suddenly pennies dropped in the minds of many geologists and many oil companies and the possibility of the extension into the Southern North Sea of the Groningen reservoir province became a reasonable premise (Fig. 1). The oil industry geared itself up for major exploration of Northwest Europe, a state of readiness not reflected in the preparedness of target countries. Legislation was not in place. Some exciting times were experienced in the Netherlands where the Napoleonic mining code allowed wells to be drilled on approval by the landholder, but only the Government had the right to award permits to exploit any hydrocarbons discovered. Consequently there was often no clear title to the hydrocarbon deposits found. A more serious problem was the lack of offshore boundaries delimiting the areas of sovereignty of the countries bordering the North Sea. The Geneva Convention of 1958 attempted to define national jurisdiction as far as the 200m isobath (Fig. 2). In 1964 Britain became the 22nd country to ratify the Geneva Convention thus allowing a division of the North Sea, an essential prelude to any licensing process. Britain was then able to offer much of the North Sea under its own jurisdiction for licensing, on the basis of quadrants of 1~ of latitude and 1~ of longitude divided into 30 blocks, each 10' of latitude by 12' longitude. Some 960 blocks extending as far north as 61 ~ were on offer. Norway too offered acreage in 1965 but the blocks were larger, 15' latitude by 20' of longitude. In retrospect this was a crucial difference; it may have reflected initial pessimism about oil exploration in a country with a landmass largely composed of unprospective Paleozoic and PreCambian rocks. The thought of oil in Norwegian territory did not seem especially logical. |-
i:
i
G r o n i n g e n and the aftermath In 1959 a well drilled in the Netherlands changed the attitude to offshore petroleum exploration in Europe overnight (Moreton 1995). Slochteren-1, drilled onshore in the north of the country,
----)
\ 9
SCOTLAND
NI
BRITAIN
--."
[.
....
Overlying Tertiary and Cretaceous Sediments ...,~- - -^- --A-.--A-.-.-A-~-^...~ .... .,~.,~-~-;-,--A AA ^ A ^ A AA A AA . .^. . . .A ^. A. . ^. . A. . . A A
A''t~''A A A A A A A A A A A A A A A A A A A AAA A/~A~AA A
~A A A A A A A A A A A A A A , A A A A /~ A ^ A ^ A A
^^A
A
^
A A A A A A
A A A A A A
A
A A A A A A
^
^
AAA A A A A AAA A AAA A A A A A A A A A A A A A A A A A
^
A A A A A A A A A A A A A ~
~.~.2.o ..........
2
A A A A A A ,
*'~
A A A A A A A A A A A A A A A ^ A ^ A ^ A 9
A A A A A A A A A A A A A A A ^ A ^ A ^ A 9
Zechste,n(Perm,an) X A A A A ^
A A A A A
....
A A A A A 9 .
A A A A A-A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A A ~.,..A...Lk...L~.,.~,~.~ A .
.
.
.
.
.
.
.
~"A'''~" A A A ^ A AAA A A A ^ A A A A ^ A A P~ A A A A A A ^ A
| " "r. A 7~'~'TP~. A "'~, A AAAAA | A A A A AI A AAA| A AAA 9
I
S a l t ^ , ^^ ^^ A A AA ^ ^ A ^ ^ A^A^ A ^ 'A|
A--A-A A A A A A A A A A A A A A A A . A ~ A .
9
A-A AAA A A A A A ^ A
A ~' A A A ~ A A ^ A A A ^ A A A A ^ A A ^ ^ A A ~"'':'.~. A
A A AAAAA A A A A A A A A A A A ~A
......
Rotiiegenoes (Permian) Sandstone
A
A AA
A A A A A A A A
A A A A A
AA| AAA| A A| A A A A | A A A A A| A 9
I
"..,.^..^." ^ ~, J
^ .... t
v
LS,,=.',-,'.Lz .........7
Fig. 1. Simplified Stratigraphic succession of Groningen gas field (after Moreton 1995).
Fig. 2. Map of North Sea showing original territorial allocations 1964 (these were later changed on appeal by Germany who gained territory at the expense of Denmark and the Netherlands).
LESSONS FROM OIL AND GAS EXPLORATION IN AND AROUND BRITAIN In early September 1964 the British Government announced that 53 licences consisting of 374 blocks had been awarded to 22 consortia involving 51 companies. This diversity was in marked contrast to Germany and Denmark where in each country the whole of the offshore was secured by a single consortium led by Brigitta in 1963 in Germany, and by A. P. Moiler in 1962 in Denmark. In the Netherlands, offshore licensing did not take place until 1968 because of a delay in passing the required legislation. Thus ten years after Groningen had been discovered virtually the whole of the prospective part of the North Sea, south of 58 ~, had been licensed to oil companies of various sizes and nationalities. Because at this time the industry was dominated by US companies, the majority of awards went to companies or consortia with a large North American component. The licensing authority in Britain preferred to think of Shell and Esso as British because of their longstanding presence on filling station forecourts. This enabled the Government to counter the argument that the offshore had been given away to foreigners. Naturally the concentration of awards reflected the early expectation that the play was for gas in the Rotliegend Sandstone. The possibility of oil had only been hinted at. Moreton (1995) records that as late as 1970 there was a view expressed by Eric Drake, the Chairman of BP, that there were no major oil fields to be found in the N o r t h Sea. In fact Myles Bowen (in Moreton 1995) records that if the same view had not prevailed in Shell he might not have become Exploration Manager of the company's U K subsidiary, Shell believing that all the worthwhile United Kingdom fields had already been found, in the Southern Gas Basin.
Salient discoveries offshore (see Table 1) G a s - S o u t h e r n G a s B a s i n or S o u t h P e r m i a n B a s i n
Moreton (1995) states when in early September 1964 Licences in the First Offshore Licensing Round were awarded for the favoured belt of blocks in the Southern North Sea, there were eight applications for every block. Blocks were awarded on a discretionary basis, with Angus Beckett, an Under-Secretary at the Ministry of Power wielding immense influence. A surprise of the first round was that BP, in which the Government and the Bank of England together held a majority stake, was absent from the prime blocks in the southern part of the trend. Subsequently it transpired that on regional grounds the company had decided to concentrate on blocks located to the north of a line joining Groningen and a recent discovery made by Home Oil of Canada onshore in Yorkshire at
7
Lockton. Thus BP deprived themselves of the possibility of being involved in the discovery of the largest Southern Gas Basin fields Leman, Indefatigable, Hewett, Victor and Viking. Besides regional concerns there was perhaps another consideration at work in BP. At that time BP was the most successful exploration company in the world controlling 22% of the free world's oil reserves (Hardman & Brooks 1990). After all their efforts to obtain concessions and explore, often under conditions of great physical and personal hardship, they could scarcely believe there were major hydrocarbon deposits under their very noses. Their experience had been that hydrocarbons in quantity only existed where the going was rough! Further the BP hierarchy was closely attached to the academic community in Britain, which was notably less interested in applied geology than colleagues overseas. When Lees had presented his paper on British oil prospects to the Geological Society in 1936 he had not received a sympathetic hearing. Kent (1985) records that no less an authority than V. C. Illing expressed himself very dubious. Shell, the discoverers of Leman Field had a different perspective. In many respects they were coming from behind, for despite their success at Slochteren they were known at the time, perhaps unfairly, as the company who applied the most science yet failed to find the most commercial oil or gas. They approached the basin with an open mind on the basis of what they could observe on seismic data connected to sparse well control around the basin's margins. They, and the Amoco/Gas Council Group which included Amerada (with a 10% British Government holding) and Texas Eastern (a US onshore pipeline expert), were awarded the most attractive blocks for the Rotliegend play in the first round.
West Sole. Yet for all that it was to BP that the honour fell of making the first commercial gas discovery. Hornabrook (t967), had in 1964 just returned from Libya where he had been involved with the discovery and appraisal of the five billion barrel Serir Field. He has described how West Sole Field was discovered and the critical part that correct time-to-depth conversion played in identifying valid structural closures. The Zechstein Evaporites proved an exceptionally complex depth-conversion problem. The West Sole field, from which 48/6-1 tested gas in December 1965, is still producing. Recently, an informed source suggested that ultimate recoverable reserves may reach 3 TCF.
The industry was much encouraged by the discovery of West Sole. However, the uncertainty about the gas potential of the southern part of the basin remained and it was with considerable relief that the industry greeted the news in early 1966 L e m a n and Indefatigable.
Table 1. Significant discoveries in and around Brita#~ Date
Field
Onshore 1974
Wytch Farm
Offshore 1965/6
West Sole
48/6-1
1971 1972
Leman Indefatigible Abroath Forties Brent Beryl
49/26-1 49/18-1 22/t8-1 2I/I0-1 211/29-I 9/13-1
1973 1974 t 984 1988 1992
Piper Morecambe Scott Nelson Foinaven
1969/70
Well no.
Discovery horizon
Reason for including
Approx reserves
Jurassic/Triassic
Culmination of onshore exploration
400 MMBO
Rotliegend Gas
Proof that similar conditions to Groningen existed in UK Southern North Sea Largest UK Permian gas field Proof of gas productive trend First indications of oil in UK sector Largest Paleocene oil field in UK Proof of North Viking Graben Potential Proof of South Viking Graben Potential
3.0 TCF
Rotliegend Gas Rottiegend Gas Pateocene Oil Paleocene Oil Middle Jurassic Oil Middle Jurassic Triassic Oil 15/17-1A Upper Jurassic Oil I 10/2-1 Triassic Gas 15/22-4 Upper Jurassic Oil 22/11-5 Paleocene Oil 204/24a-2 Paleocene Oil
Outer Moray Firth proved as major oil province Hydrocarbon potential of Irish Sea established Major Potential overlooked by earlier exploration Major Paleocene field overlooked by earlier exploration First commercial oil field West of Shetland sparked major exploration effort
11.3 TCF 4.7 TCF 150 MMBO 2200 MMBO 2000 MMBO + 1.5 TCF t000 MMBO + 1.5 TCF 1000 MMBO 5.35 TCF 500 MMBO 425 MMBO 250 MMBO
8
R.F.P.
HARDMAN
that the Shell-Esso partnership had tested gas from well 49/26-1 at Leman Bank. This was quickly followed up by the Amoco/Gas Council Group successfully drilling 49/27-1 into the southwestern part of the structure. In the regulations covering the first licensing round there was no provision for field unitization. This led to considerable acrimony between the Shell-Esso partnership on the one hand and the East Leman Unit Partnership on the other. East Leman Unit was a partnership formed by the Amoco/Gas Council Group, with Mobil operator of blocks 53/1 and 53/2 and Arco operator of 49/28. The dispute was resolved by the monopoly purchaser of the gas, Gas Council, who determined gas would only be purchased in proportion to the gas existing under each tract, thus forcing de facto unitization. The omission in the regulations of a provision for unitization was rectified by legislation covering subsequent rounds. Currently Leman Field is determined to have contained some 11 T C F of producible gas with 50.28% in the East Leman Unit and 49.72% in Shell-Esso's acreage. Meanwhile the Amoco/Gas Council Group themselves discovered gas in well 49/18-1. Again the Indefatigable Field was shared with the Shell-Esso group but simpler geophysical and geological conditions allowed a much more straightforward determination of field ownership. With these three discoveries the hunt for Southern Gas Basin reserves was in full swing and continued until the monopoly gas market became saturated, Gas Council taking the view that as a premium fuel and a national asset gas should not be used for power generation. We can only speculate as to whether this view was a direct result of successive British Governments wishing to safeguard jobs in the coal mining industry. The state of affairs was ended when the Gas Council monopoly was ended by which time gas to electricity technology had greatly improved in efficiency and objections to burning a premium fuel carried less weight. Figure 3 illustrates the dramatic effect that this change had on exploration for gas in the southern North Sea. What lessons from this brief history can be applied to future exploration efforts? In the first place, preconceived ideas are no friend to the would-be successful explorer. That BP's views, though
damaging did not prove fatal to their position in the Southern Gas Basin, may appear at first sight to be luck. Oil and gas do not occur where strategy determines but where nature places them. The views of academics were based on observation of outcrops on land and to a far lesser extent on borehole data. The oil industry had a better data set, were naturally far more interested in applying seismic than most academics, and were able to reach more relevant conclusions. To have heeded people without questioning the source of their views was a mistake. Secondly, a certain humility is always required of explorers. Success in one province does not endow the successful explorer with a magic aura of infallibility that ensures success in a different province. One must build a case on facts and deductions before applying intuitive prejudice. Thirdly, there is no doubt that BP, Shell-Esso and Amoco/Gas Council had sufficient influence with the Government of the day to obtain awards of the licences they most coveted. Without this influence it is an open question as to whom the blocks would have been awarded. For a long time afterwards stories circulated the industry of all those companies who had spotted the Leman structure but had been denied a share by the licensing system. Only in a cash bonus bid system is the question of influence irrelevant.
O i l - Central Graben or Northern Permian Basin Arbroath. In the first U K licensing round, acreage was acquired by companies in all areas that they then saw as prospective. Gulf, for instance, acquired five blocks in Morecambe Bay and Hamilton Oil were awarded a circle of blocks in the Inner Moray Firth. The industry correctly surmized that Permian evaporites were present not only in the Southern North Sea but also to the north of the Dogger Bank High. The so-called North Permian Basin extends from the Central part of the British North Sea into Danish and southern Norwegian waters (Fig. 4). With all the prevailing uncertainties most of the major players wished to hedge their bets and therefore applied for acreage in what is now known as the
60
10000 9000
W e s t Sole
8000
Leman ,Indefatigable
Steady discovery rate of small fields using exisitng infrastructure for production
Amethyst
50
7000 40 m II
6000 Note lack of exploration from 1975 until price rise for new gas in 1981
5000 4000
Monopoly Market Saturated
L
W i
0
20
3000 2000
10 1000
0
1965
1970
1975
1980
1985 Year
Fig. 3. Southern North Sea total discovered commercial reserves.
~.
30
1990
1995
LESSONS FROM OIL AND GAS EXPLORATION IN AND AROUND BRITAIN
9
first well on the trend, 22/11-1, and tested oil and gas cut mud from a gross oil column of 178' in shaly sands in the Paleocene, the Rotliegend objective was still uppermost in peoples' minds. In the autumn of 1969 the Amoco Group took BP's new semi-submersible Sea Quest on charter and drilled 22/18-1, discovering oil in Paleocene sands. According to Leon Hess the surprise was so great that the galley had to be raided for pickle jars to store samples of crude oil. Great efforts to keep the information from the well secret were frustrated when, unknown to the Amoco Group, the well-site geologist left a copy of the log on board Sea Quest. The rig then went back to BP bearing the vital information.
========================================= :::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::::: " " : ~"~'4":-'-'-'-" ' . ' . ' . ' - ' . ' - ' . "-'-'-" ' . ' . ' A "~C."~'.'.'.'.'~, " ~ " "-" ". 9~ . . . .
+1
.
.
.
A
.
.
" ~
" " "'q
.
.
"~--'"
'
"
+
. ..-.-.-...-....--.-....,.r....
9
,
+
*
~
+
-
*
~
+
"
,:...:.:.:.: :.:.:.: :.:.:.
::::::::::::::::::::::::::::::::::::::::::::::::::: ii i i i i ! ::ii!i::ili
.....
.+
Forties Field. In the autumn of 1969 BP now had enough information to allow them to drill the Forties structure. They had secured both the key wells, 22/11-1 and 22/18-1, and yet they still hesitated. These were the only wells in their possession showing the possibility of a sandstone reservoir in the Paleocene. To the south were scores of wells with a Tertiary section with no sand present. Worse, the two key wells allowed a tie to the Forties structure where at top Paleocene level closure could be seen to be no more than between 20 and 40 ms. Was this enough to cause a commercial accumulation at a time when the prevailing oil price was less than $3.30/bb1? The decision in the end was forced upon them. The BP drilling rig Sea Quest was scheduled to drill a farm-in well but the Forties structure was the only one available over which a site survey had been shot. It was better to drill than have the rig standing by. As is now history 21/10-1 found an oil column which eventually proved to be over 600 ~ in high quality Paleocene sands (Walmsley 1975). The full extent of the closure had not been appreciated
g
J
0 I
0
lookm i
,50 miles
Fig. 4. Location of North and South Permian Basins (after Taylor 1981).
Central Graben. The Amoco/Gas Council Group, BP, Shell-Esso and Gulf all applied. Some of the most hotly contested blocks lay on a prominent N W - S E tending pre-Tertiary ridge. From northwest to southeast the blocks were: (1)
(2) (3) (4)
21/9 and 21/10, offshore Scotland, which, given the patriotic instincts of the Scottish Chief Geophysicist of the time, D a n n y Malone, were applied for enthusiastically on the basis of a gently southeastwards plunging base Tertiary nose and awarded 100% to BP. The sparse but encouraging data set over these blocks was common to most potential bidders, but Amoco did not apply. Their Head of Exploration in Chicago had ruled that prospects in water depths greater than 300 r would not be economic until a long way into the future. Water depths over blocks 21/9 and 21/10 are over 420 t. The fact that structural closure could not be demonstrated with confidence weakened the resolve of Amoco's London office to challenge Chicago's view of commerciality. 22/6 was awarded to Shell-Esso. 22/11 was awarded to Gulf. 22/17, 22/18 plus 22/22 and 22/23 were awarded to the Amoco/Gas Council Group. Here water depths were just within the 300 ~ embargo and a clearly defined four-way dip closure was present at base Tertiary level.
At this stage it is impossible to reconstruct how all these companies viewed the prospectivity but a personal communication from Leon Hess, Chairman of Amerada Hess, a member of the Amoco/Gas Council Group, leaves no doubt that Rotliegend gas was their target. Even after Gulf jointly with Shell-Esso drilled the
MORECAMBE BAY
SOUTHERN BASIN
(~AS
/
/
i
./
WYTCH FARM
Fig. 5. Main structural provinces UKCS.
10
R . F . P . HARDMAN
because of the sparseness of seismic cover and because of velocity variations in an E - W sense across the structure. This, the first major oil field in British waters was discovered a short while after Phillips (in Norwegian block 2/4) had found a long oil column of uncertain commerciality in Danian and Cretaceous Chalk. After extensive testing this discovery came to be known as the Ekofisk Field, like the Forties, a field similarly in the multibillion barrel class. Thus, in early 1970 the Central Graben became firmly established as a significant new oil province (Fig. 5). The complex tectonics of the area coupled with a very rich mature source rock, the Kimmeridge Clay, ensured that in the ensuing years many fields of moderate size would be found. The creaming curve (Fig. 6) illustrates this point. As in the case of the Southern Gas Basin exploration of the Central Graben underlined how dangerous prejudice can be to exploration. In this case it was dogma about water depth and the related economic outcomes that were damaging to the Amoco/Gas Council Group. Secondly, all the companies had spotted the Tertiary nose which proved to be the Forties Field. With both luck and good management BP were able to secure and drill the prize. From this two points can be made: (1) The management structure of BP allowed individuals to act in what they saw as the best interests of the company; the individuals concerned realized the limits of their knowledge and did not try to run economic cases when their knowledge was so sketchy as to make detailed economic cases meaningless. There is no doubt that if economics had been the determinant, BP would never have drilled the Forties discovery. Moreton (1995) relates that in fact Block 21/10 was almost farmed out to Shell. Shell it transpires had correctly analysed the Forties anomaly as containing over one billion barrels but they were so afraid that the Shell management would think them ridiculous that they arbitrarily reduced the reserve calculation to 'over 200 million barrels' to obtain permission for the farm-in attempt. Shell, in common with many other companies, had trouble with a prospect that deviated significantly from the mean. Why did neither Gulf nor Shell-Esso recognize the significance of well 22/11-1? We shall consider this below.
O i l - The opening up o f the Viking Graben North Viking Graben - Brent Field. Bowen (1992) has given a full account of the discovery of the Brent Field which, in the subsequent Fourth U K Licensing Round, triggered an acreage scramble worthy of the Californian Gold Rush. What Bowen is far too modest to state in his paper is that it was the foresight and courage of his team, which included their Chief Geologist John Jennings, a future chairman of Shell, linked to the trust of an empowered manager, George Williams, that allowed Shell to apply in the Third Round in 1972 for Block 211/29 in an area which was then considered deep water (426'). Bowen (1992) records that in addition to Shell-Esso, who picked up two blocks, Conoco (four) and Texaco (one) were the only other companies to secure licences in an area remote from land and infrastructure. The nearest well at this time was more than 300 nautical miles to the south. The Third Round was a thin round but there is no doubt that the embargo imposed from Chicago on deep-water activities was a severe handicap to the Amoco/Gas Council Group. The only block of note which they were able to secure, 23/21 in the Central Graben, contained the modest sized Lomond gas condensate Field. Well 211/29-1 was drilled under conditions of intense secrecy. Maps on the walls of Shell's office showed the well as a dry hole but rumours circulated. The technical staff at Amoco deduced the correct answer but they were only half believed by no less a person than the President of the Company, who was worried that a discovery had been made in the Paleocene rather than the Jurassic. The Fourth Round was called on 25 June 1971, only six days after core was recovered from 211/29-1, the Brent discovery well. At about this time Total were drilling well 3/25-1. The Amoco/Gas Council Group had obtained a trade for the well but, in view of the sensitivity and value of the information to the round, Total tried to delay giving up the data. The case was taken to a judge in chambers who ruled that Well Trade Agreements were legal documents and must be honoured. The French Exploration Manager of Total was under such strain that he had a nervous breakdown. The excitement generated by the round persuaded the British Government to offer for the first time a certain number of blocks (15) as bid blocks in
60
10000 9000
Montrose Arbroath Forties
50
8000 7000
40 L
6000 O m 5 5
I1 30
5000
~. W 0
4000
20 3000 2000
10
1000
0
1965
1970
1975
1980
1985 Year
Fig. 6. Central North Sea total discovered commercial reserves.
1990
1995
LESSONS FROM OIL AND GAS EXPLORATION IN AND AROUND BRITAIN
11
18000
60 Brent Beryl
Hudson , (Last significant find)
16000 50 14000
12000
40
4) 10000 0 (II
=i IE
@
30 ~. m
8000
6000
20
4000 10
2000
1965
1970
1975
1980
1985
1990
1995
Year Fig. 7. UK Viking Graben total discovered commercial reserves.
addition to the normal discretionary offering. Of the bid blocks, one of the most attractive was a tilted fault block of 'Brent' style, 211/21. When the bids were opened, in a theatre to conform to the atmosphere of high drama, the industry was amazed to find that Shell-Esso had bid s million with the next highest bidder at s million. In composing this staggering bid (more like s million in today's money), worries of what Total and the A m o c o / G a s C o u n c i k Group had found out must have played a part in Shell-Esso's calculations and there was always the nagging doubt that even super-tight wells do not stay leak-proof forever. Block 211/21, and Block 211/26, which was subsequently awarded to Shell-Esso in recognition no doubt of their services to the Treasury, turned out to contain the Cormorant Field, with comparatively modest reserves, 700 million barrels (compared with over two billion barrels for Brent), but well worth the bid sum. During the Fourth Round all the prospective acreage in the North Viking Graben was awarded. Virtually all the tilted fault block closures proved to contain oil and in some cases gas. So far, no really subtle traps have worked, thus underlining the old adage that explorers must match their tactics to the style of prospectivity of the basin. Tactics appropriate for the Central Graben where there is great structural complexity do not apply to the N o r t h Viking Graben, where for the most part structure is simple and easily understood.
South Vik&g Graben- Beryl Field. In the Fourth Round, in addition to the North Viking Graben, the industry had identified the South Viking Graben and the Outer Moray Firth as of particular interest. In the Outer Moray Firth, tilted fault blocks similar in style to those in the North Viking Graben had been observed. In the South Viking Graben a block of major interest was 9/13 where a large domal closure was present. Amoco, on behalf of their partnership, Gas Council, Amerada Hess and Texas Eastern, strengthened by the addition of Mobil for the Fourth Round on the insistence of Denis Rooke (then Exploration and Production
Manager of Gas Council) calculated the economics of a nearly billion barrel size prospect as likely to yield a rate of return of 50%. However the President of Amoco International, Frank Osment, in a decision which later in life he was bitterly to regret, decided that to bid cash in Britain for exploration acreage, draining off funds which could be used for exploration itself, was not to be encouraged. He therefore decreed that Amoco was not to compete for the cash bonus bid blocks. However Amoco did not want to offend the Government and placed small token bids winning Block 30/22 and thereby defeating the whole thrust of their strategy. Amoco were not alone in this regard, the Chairman of BP also announced publicly that BP did not approve of cash bonus bidding. BP ended up by winning the third most expensive block, 15/26, paying some s million. Block 9/13 was one of the bid blocks. Lacking Amoco, the partnership had to be rapidly rearranged. It was agreed that Mobil with 50% would be operator, Amerada Hess and Texas Eastern would have 20% each and Gas Council 10%, the percentages largely based on what each company could afford. The bid strategy was constructed by Mobil under one of their planners, Richard Barry. In his book, The Management of International Oil Operations, Barry (1993) describes how the bid sum was arrived at. When the bids were opened it transpired that the Mobil led partnership had won the block, bidding s million, just enough to beat Occidental who had tendered s million. In 1972 Mobil spudded the first well on the block discovering the Beryl Field. With the discovery well they were able to trade the Brent Field discovery well, 211/29-1. Armed with the knowledge that they had discovered a commercial field they were soon able to place an order in Stavanger for a concrete structure of a new type, 'Condeep', to act as storage and deck support for Beryl 'A' platform. Perhaps as a result of the well log from 211/29-1 and the order for an expensive innovative product of Norwegian manufacture, they were then able to persuade the Norwegian authorities to award them operatorship and 20% interest in the Norwegian blocks offsetting the Brent Field, Norwegian Blocks 33/9 and 33/12.
12
R . F . P . HARDMAN
In these two blocks, with an extension into U K Block 211/24, the largest oil field in the North Sea, Statfjord of some four billion barrels, was subsequently discovered (Fig. 7). History might have been very different if the Amoco President had not taken the line he did on U K cash bonus bidding. The clear lesson is that seizing opportunities is crucial to the success of any given company. Many opportunities can be neglected but missing a critical opening can set back a company to a point where recovery is impossible. With refusal to bid on 9/13, Amoco surrendered its most promising position in U K Exploration and was never again seen as a leader alongside such companies as BP, Shell and Esso.
the Piper structure and it is true that just before drilling 15/17-1 Occidental were not very hopeful of success. It was after all their third-best prospect. However, as can be seen on Figure 8 the discovery of Piper Field caused an upsurge of interest in the Moray Firth Basin in which over 4.5 billion barrels of oil equivalents have been discovered to date. Occidental had successfully jumped onto the bandwagon of an important emerging new petroleum province. They were lucky but they had earned their luck and been prepared to take sensible risks.
Fields that were missed at the first attempt
O i l - the Outer Moray Firth
Introduction
Piper Field. One of the companies who had sat out the first three rounds waiting to see what would happen was Occidental but by the time the Fourth Round was announced their chairman, the legendary Armand Hammer, decided that his company needed to be involved. The structural style of the Outer Moray Firth, which appeared to be very similar to that existing in the North Viking Graben, attracted Occidental. In the Fourth Round they were awarded blocks 14/19, 15/11 and 15/17. It was know that at the time Hammer was friendly with the British Royal Family. Whether this had a bearing on the Fourth Round discretionary awards it is hard to say but it is unlikely to have been a detriment. Using an old converted Norwegian Whaling Factory Ship, Occidental drilled three wells, one on each block. The second, although Occidental and its partners did not realize it at the time, the oil bearing sands being of poor reservoir quality, discovered the Claymore Field. The third in 15/17, discovered the Piper Field of nearly a billion barrels. Upper Jurassic sandstones proved to be reservoirs of exceptional quality with a recovery factor now expected to reach 73.4% (Harker 1998). Many companies had not obtained enough seismic data before the Fourth Round to map
A technical account of wells in this section has been given by Dean (1996). There is little point in dwelling here on the technical aspects of the discoveries, beyond understanding enough to bring out lessons learned.
Morecambe Besides the more recent account by Dean (1996), Colter & Barr (1975) and Colter (1978) have all published on the Morecambe Field. The first well was drilled into what came to be known as the Morecambe Field by Gulf Oil in 1966 in Block 110/8, but both 110/8-1 and 110/8-2 were abandoned as dry holes without testing. Amoco who were in partnership with Gas Council at the time were interested in exploration of the Irish Sea and considered applying for Block 110/7 but after Gas Council insisted on a work programme including a firm well they dropped out. According to Colter (Morton 1995), in March 1973, on the basis of ownership of 110/7, Gas Council acquired the logs from the Gulf wells in return
60
10000 9000 8000
Andrew, Piper Britannia Claymore--IVRR, Tartan Maureen
50 Alba, Scott
Captain, Rubie
McCulloch, Telford
Blake
7000 4O L
tl Q
6000 O O El
it._
30~.
5000
_w m
4000 20
3000 2000 10
1000 0
1965
n l'lll 1970
1975
1980
1985 Year
Fig. 8. Moray Firth total discovered commercial reserves.
1990
1995
Q
LESSONS FROM OIL AND GAS EXPLORATION IN AND AROUND BRITAIN for which Gas Council agreed to give Gulf logs from any well they might drill in the area in future. The Gas Council log analyst John Bains, was most surprised to find that well 110/8-2 contained a hydrocarbon column of over 600 ~ in Sherwood Sandstone of Triassic age. Gulf were even more surprised after they had been apprised of this and, when at last their resistance to the unpalatable fact had been overcome, they attempted to withdraw the notice of relinquishment that had recently been given to the Department of Energy. The Department of Energy were unimpressed by Gulf's lack of competence and refused to rescind the notice. Perhaps they were persuaded by Denis Rooke, who, as head of Gas Council Exploration, was a most formidable manager and a most persuasive person. He was quite capable on his own of convincing the Government not to give Gulf a second chance. Consequently, in 1974 when a Labour Government was returned and the blocks were awarded it was to Hydrocarbons Great Britain, a 100% Gas Council subsidiary. Previously in the Fourth Round, Gas Council had acquired 110/2 and now controlled all the key acreage over Morecambe Field structures. After a disappointment with 110/2-1, the Morecambe Field was duly confirmed in blocks 110/2, 110/3 and 110/8, which have proved to contain 6.5 T C F of gas. What lessons can be learned from this? How was Gas Council with a very small technical staff able to succeed when major Companies with large staff numbers such as Gulf, Amoco and indeed Conoco, who they tried to interest in a farm-in, failed to spot the opportunity? The answer appears to lie with sound technical work; good personal relations that helped obtain the vital well logs; and a management team who trusted the technical team. In turn the technical team had been given clear responsibilities by a manager with whom they were in day-to-day communication. They were empowered and although success was required they were allowed to make mistakes and survive. The Gas Council team was in place for a long time. They saw personnel of the staff of companies with whom they were associated change rapidly, taking knowledge with them and leaving mistakes to be sorted out by their successors. This is undoubtedly one of the major lessons from the exploration history of the British sector or indeed for many basins around the world and many companies.
Ne&on
The discovery of the Nelson Field has been comprehensively documented by Whyatt et al. (1992). As is made clear in their account the first well 22/11-1 was drilled by Gulf on behalf of themselves and Shell-Esso at the boundary between blocks 22/11 (Gulf) and 22/6 (Shell-Esso). The well found a 178 ~ oil column and failed to test hydrocarbons at a commercial rate. Later, Enterprise Oil, on the basis of an understanding of Paleocene Forties sand submarine channel systems, correctly analysed the well as having tested an interchannel area. They farmed and swapped into 22/11 acquiring 100% interest and in 1988 drilled two wells to prove the presence of a major oil field of over 400 million barrels of recoverable oil. The names of companies either holding title to Block 22/11 or holding part of the structure from the year the well was drilled until Enterprise acquired 100%, includes some of the most illustrious names in the exploration business. Besides Gulf and Shell-Esso (who subsequently it was determined had title to some 43% by virtue of ownership of 22/6), Conoco, Britoil and Chevron all had held interests. How was it that Enterprise alone could see the merit of the prospect? The fact is that Shell, who had amongst their staff an expert on the Palaeocene, John Parker, whose 1975 paper was a seminal work, did know about it. At about this time, when Tim Brennand was Exploration Manager of Shell, it was reported that Shell intended to drill a well to re-test the prospect but as they had calculated an uneconomic scoping reserve number of 50 million barrels in the end the well was not drilled. Then under subsequent exploration managers the prospect was lost sight of, illustrating once again the importance of continuity and persistence in exploration.
13
The other lesson to be gained concerns the use of economics to determine which prospects should be drilled. The 50 million barrels pre-drilling calculated by Shell-Esso is in marked contrast to the 425 million barrels reserves currently estimated. Economics have a place in decision making but they are used literally by far too many companies. The truth is that if you know what the well will find there is little point in drilling it. There needs to be an in-depth understanding of every factor when the results of economic runs on exploration prospects are considered. Big fields are nearly always bigger than you imagine as there is a natural tendency to view prospects as conforming to the basin mean, as with Shell's view of Forties already discussed. It is far better to drill prospects which have a real chance of finding significant reserves and take a chance on the economic out-turn than drill prospects which are geologically poor with robust economics. In the former case you take a chance on the economics; in the latter case, geologically poor prospects are unlikely to contain oil or gas so the economics are irrelevant.
Scott
Scott has not been written up in the same way as Nelson but the story as Dean (1996) points out is very similar. Well 15/22-3 was drilled by Amoco in 1975, with contribution from licensees of the adjoining Block 15/21 operated by Monsanto. It was drilled on the crest of a large four-way dip-closed anticline, defined weakly at base Cretaceous level, but much more strongly at top Middle Jurassic volcanics level. The well failed to find any sand in the Piper Formation and passed straight from Kimmeridge Clay into coals of the Pentland Formation. There were no other sands of Mesozoic age in the well. Later, in 1984, Amoco recognized that the sands may have been absent due to erosion or faulting and spudded a down-dip well, 15/22-4. They found two sand intervals separated by a 40' shale at the equivalent horizon to the Piper Field sands. The upper sand which was about 130 / thick contained overpressured water but the lower of some 110' was oil-bearing and tested at commercial rates. Amoco was convinced that for the structure to be commercial, reserves of a minimum of 120-140 million barrels were necessary. Therefore they obtained approval from the partnership, Enterprise, Mobil, Amerada Hess and Texas Eastern, to sidetrack a well down-dip to a location where the minimum reserve would be secured. Members of the partnership were not altogether convinced and obtained an undertaking that, in return for agreement to drill the down-dip well, an up-dip well near the crest of the structure would be drilled. The down-dip well 15/22-5 was duly drilled and proved the sands entirely water-bearing. The up-dip well was not drilled. Shortly afterwards the operator of the adjoining Block 15/21 Monsanto announced that the entire oil-related assets of that company were up for sale. Armed with a belief that a major field had been missed Amerada Hess was able to secure Monsanto U K at a favourable price within ten days of visiting the data room, a clear example of the benefits of an exploration team closely coupled to the management of the company. In the winter of 1986, well 15/21-15 was drilled by Amerada Hess with a contribution from the Amoco Group. The well found over 400 / of oil pay and tested at rates of up to 9000 BOPD. The Scott Field had been confirmed. Subsequently after unitization as the largest interest holder, Amerada Hess (34.95%) became operator of the field. The brief history of Scott supports the view that over reliance on economic indicators can lead to bad decision making. Economics for exploration and appraisal decisions are at best a guide and should take second place to geological analysis. What really confounded the Amoco prediction was that in general the Scott Field reservoir sands thicken westwards. This had not been taken into account in their geological model and consequently economics. As Ian Vann (currently Technology Vice President at BP) remarked at a recent meeting of explorers, 'Always keep at least two geological models in your head at any one time - and preferably three'.
14
R . F . P . HARDMAN
Fig. 9. UKCS production 1968-2030.
Where we are today and the future Forecasts of UKCS production between 1984 and 1996 (Fig. 9) showed increases in predictions of production throughout the forecast period. In 1998 Britain with some three million BOPD of oil production and nine BCFD per day of gas production was the sixth in the league table of hydrocarbon-producing nations. Since then predictions of the future have changed. The rate of increase of reserves has slowed and even been reversed. Table 2 shows that until 1995 there was a steady increase in the forecast ultimate Table 2. Yet to Find Analysi~ UKCS Authority
UKCS DTiw Essot
Billion barrels oil equivalents 1990
1995
1999
Found Yet to find*
32.2 18.0
40.8 27.8
45.0 18.0
Found Yet to find
43.0 10.0
15.3
7.6
North Sea DTiw Found Yet to find*
BP$
Found Yet to find
12.1
40.0 8.0
9 5.0
Comments
Preliminary estimates show reserve adds from new fields from 1990-1997 of 1 BBOE b In 1999 infonnaUy BP and Esso forecast +5.0 BBOE yet to find
* Mean, the average of DTi high and low estimates. Barrels oil equivalent (billions). tR. F. P. Hardman (1992). M. C. Daly, M. S. Bell & Smith (1996). wDepartment of Energy/Trade and Industry Brown Books.
reserve potential by the Department of Trade and Industry. In 1990 the mean expectation was that 50.2 billion barrels oil equivalents (BOE) would be found but by 1995 the forecast had increased to 68.6 billion BOE. However in the 1998 Brown Book the number had shrunk to 63.0 BOE. Table 2 also shows that informal forecasts by two major oil companies over the same period show reductions. Why is this? The key probably lies with the West of Shetland area. In 1992 BP found the Foinaven Field, called after a mountain in Scotland, though popularly believed to be named after a racehorse Foinavon which in 1967 won the Grand National at 100-1 after a pile-up at the 23rd fence, avoided by the horse's jockey John Buckingham. In 1992 only BP and Amerada Hess were still seriously exploring the West of Shetlands. BP had transferred staff from the Gulf of Mexico to Aberdeen. They spotted seismic amplitudes in Paleocene age sediments that reminded them of the signatures given by hydrocarbon-bearing sediments in the Gulf of Mexico. Shell who were 50/50 partners with BP (with BP being operator) were not convinced. BP farmed-up, reducing Shell's interest to 20%, and discovered a field with reserves of the order of 250 million barrels. Subsequently the partnership went on to discover the larger Schiehallion field, which is shared with the Amerada Hess Group. This led to widespread industry enthusiasm for West of Shetlands exploration and a heavy exploratory drilling campaign in 19931995 when 39 exploration wells were drilled. With the exception of some small additions to the major discoveries at Foinaven and Schiehallion nothing much of significance has been found. The Department of Trade and Industry and the oil industry itself, now that the division of the undesignated zone between the Faroes and Scotland has taken place, is looking forward to renewed exploration in what has proved a most difficult province. It is uncertain how this will turn out; few in the industry now believe the West of Shetlands to be a major province once thought possible. This in turn has reduced forecasts of the ultimate reserve potential (see Fig. 10). In summary, with the possible exception of the West of Shetlands, where a few significant fields may yet be found, the North Sea is a mature province. Oil and gas exploration is likely to concentrate on a handful of new plays, such as the Kopervik trend
LESSONS FROM OIL AND GAS EXPLORATION IN AND AROUND BRITAIN
15 60
10000 9000
50 8000 7000
40
M Q
6000 4) 0 II)
=E
=_
L
3o
5000 Clair
Foinaven
W
Schiehallion
m
4000
2000
I
]
1000 0
1965
20
"k
3000
r-k
1970
1975
1980
1985
1990
~,
liln
10
0
1995
Year Fig. 10. West of Shetlands total discovered commercial reserves. in the Moray Firth where Blake and Goldeneye were recently found, and on value-led exploration for small fields that can be tied back to existing infrastructure quickly and cheaply. Nonetheless, as Figure 9 shows, there will continue to be significant production-led geological activity in the U K C S for many years to come in connection with existing fields and, for those companies that have the technology and the imagination, discovery of the remaining 10% or so of reserves will be a challenging but profitable goal.
Conclusions In this review an attempt has been made to emphasize the motives of the individuals who played the really important parts in this history. Normally we assume decisions are the result of logical processes. In fact, in business as in life, decisions are made by people not companies. They reflect individual prejudices, character traits and above all a desire to minimize risk; a conscious effort by each individual to keep him or her in their own personal comfort zone. Managers of commercial companies will tell you that their job is to manage commercial risk. W h a t they do not say is that they are motivated by a desire to avoid discomfort or risks to their own careers or company positions. Risks of that sort induce stress. In the foregoing account there is only one clear example of stress affecting an individual's health. Yet, with a few exceptions, stress affects all of us in a way we find unpleasant. If life is about taking sensible risks, the only way risks are seen as sensible is after the event. Between risk taking and outcome can seem a very long time. This principle helps understanding of events in the narrative. For instance we can speculate that the Vice President of Exploration of Amoco who decreed that fields in water depths greater than 300' would not prove economic was in fact attempting to avoid personal stress based on an understanding that technology for fields in water depths greater than 300' had not at that time been developed. When Shell Exploration personnel minimized the likely reserves in the Forties structure they were afraid their credibility would be damaged if they gave their management the true results of their calculations and their advice would not be heeded. Generally
with explorers the problem goes the other way. When explorers are afraid that their favourite prospect will not be drilled it is usually because it is too small. An explorer whose prospect is not drilled is an unknown explorer. An explorer who makes a discovery is a hero no matter that the size of the discovery is less than predicted. Hence, exaggeration is the general rule. Only large potential structures are given the shrinking treatment. Another lesson concerns secrecy about technical information. There is clearly a dilemma for every company between attempting to maintain a commercial advantage through limiting commercially sensitive information to a handful and disseminating knowledge widely to take maximum benefit. When I joined Amoco in 1969 only three people in the local company had access to the logs from 22/18-1 for a considerable time. Even apart from the unfortunate accident that gave BP the log, it is a moot point whether commercial advantage was better served by restricting knowledge of the well to such a small group, or whether it would have been maximized by allowing access to the information by a wider group who would then have been able to exploit the advantages it conferred, possibly by farm-in or even by acquisition for cash of the acreage of better placed companies. The reasons for Gulf's abject failure in Northwest Europe is curious. Not only did they miss the Morecambe Bay and Nelson Fields in U K waters but they drilled the first well on the South Arne structure in Denmark which tested oil but they did not follow it up to find the real potential. They also drilled on the Ula Field anomaly in Norwegian waters but failed to drill deep enough to make a discovery. There must have been something structurally wrong with the company. Gulf, in partnership with BP in the Kuwait Oil Company, espoused the view that a good manager could manage anything. They experimented with switching people into jobs with which they were not familiar. For instance, the Chief Geologist of the years 1962-1964, Richard Stephens, became Head of Stores. Could it be that their exploration campaign in Northwest Europe was flawed because they moved people into key positions who could not handle the risk of exploration? Perhaps the final lesson of the last 35 years is that companies need to ensure that their managers have appropriate qualifications, experience and
16
R.F.P.
a p t i t u d e s for the j o b s to w h i c h they are a p p o i n t e d . Failure to obey this simple p r e c e p t c a n lead to the u n d o i n g o f the w h o l e glorious c o m p a n y edifice. The foregoing account is based on the author's experiences over 30 years of oil and gas exploration in northwest Europe. He is indebted to Amerada Hess Limited for giving permission to present the paper and to C. J. Campbell for discussions on the North Sea reserve potential; R. A. Barry for detailed history on the Beryl Field; J. M. Bowen, J. Hornabrook and P. Hinde for discussion on the history of Shell, BP and Gas Council activities in the years up to 1975; J. P. B. Lovell for suggestions on certain aspects of the text. The opinions presented are the author's own and do not necessarily reflect the views of Amerada Hess or any of the other authorities consulted. Particular thanks to Michael Murphy for drawing up the creaming curves and Michelle Thomas for assisting with the research for this paper, and finally to Ruth Hart-Leverton for her patience and help with the preparation of the manuscript.
References ABBOTS, J. L. (ed.) 1991. UK Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14. ANONYMOUS. 1934. Petroleum in Great Britain. Nature, London, 133, 487-488. BARRY, R. A. 1993. The Management of International Oil Operations. Penwell Publishing Co., Tulsa. BOWEN, J. M. 1991.25 Years of North Sea Exploration. In: Abbots, I. (ed.) United Kingdom Oil and Gas Fields 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 1-7. BOWEN, J. M. 1992. Exploration of the Brent Province. In: MORTON, A. C., HASZELDINE, R. S., GLEES, M. R. & BROWN, (eds) Geology of the Brent Group. Geological Society, Special Publications, 61, 3-14. BRENNAND, Y. P., & VAN HOORN, B., JAMES, K. H. & GLENNIE, K. W. 1998. Historical Review of North Sea Exploration. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology' of the North Sea (4th Edition). Blackwell Science Ltd, Oxford. COLTER, V. S. 1978. Exploration for Gas in the Irish Sea. Geologic en M(jnboun, 57, 503-516. COLTER, V. S. & BARR, K. W. 1975. Recent Developments in the Geology and the Continental Shelf of North-West Europe (Vol. l). Applied Science Publishers, London, 61 75. COLTER, V. S. & HARVARD, D. J. 1981. The Wytch Farm Oil Field, Dorset in Petroleum Geology of the Continental Shelf of North-West Europe. Institute of Petroleum, London, 494-503. DALY, M. C., BELL, M. S. & SMITH, P. J. 1996. In: GLENNIE, K. & HURST, A. (eds) AD 1995." N W Europe's Hydrocarbon Industry. Geological Society, London, 187-193. DEAN, G. 1996. Undiscovery Wells of the UK Continental Shelf. In: GLENNIE, K. & HURST, A. (eds) AD 1995: N W Europe's Hydrocarbon Industry. Geological Society, London, 69-80.
HARDMAN FALCOLN, N. I. & KENT, P. E. 1960. Geological Results of Petroleum Exploration in Britain 1945-1957. Geological Society, London, Memoir, 2. HARDMAN, R. F. P. (ed.) 1992. Exploration Britain - Geological Insights for the Next Decade. Geological Society, Special Publications, 67, HARDMAN, R. F. P. & BROOKS, J. (eds) 1990. Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society Special Publications, 55, HARKER, S. D. 1998. The Palingenesy of the Piper Oil Field UK North Sea. Petroleum Geoscience, 4(3), 271-286. HINDE, P. 1966. Fortune in the North Sea. Foulis and Co Ltd Publishers, HORNABROOK, J. T. 1967. Seismic Interpretation Problems in the North Sea with Special Reference to the Discovery Well 48/6-1. In: Origin of Oil, Geology and Geophysics Proceedings, World Petroleum Congress Mexico 1967 Volume 2 pp. 837-856, John Wiley and Sons, Chichester. KENT, P. E. 1985. UK Onshore Oil Exploration, 1930-1964. Marine and Petroleum Geology, 2(1), 56-64. LEES, G. M. & Cox, P. E. 1937. The Geological Basis of the Present Search for Oil in Great Britain. Quarterly Journal of the Geological Society, London, 93(2), 156-194. LEES, G. M. & TAITT, A. H. 1946. The Geological Results of the Search for Oilfields in Great Britain. Quarterly Journal of the Geological Society', London, 101, 255-317. MORETON, R. (ed.) 1995. Tales from Early UK Oil Exploration 1960-1979. Petroleum Exploration Society of Great Britain, 30th Anniversary Book, PARKER, R. J. 1975. Lower Tertiary Sand Development in the Central North Sea. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of North-West Europe (Vol. 1). Applied Science Publishers, Barking, 447-453. TAYLOR, J. C. M. 1981. Zechstein Facies and Petroleum Prospects in the Central and Northern North Sea. In: ILLIN6, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of North- West Europe. Institute of Petroleum, 176-185. VALE, P. R. & MITCHUM, R. M. JR. 1977. Seismic Stratigraphy and Global Changes of Sea Level Part 1 Overview. In: PAYTON, C. E. (ed.) Seismic Stratigraphy-Application to Hydrocarbon Exploration. American Association of Petroleum Geologists, Tulsa, Memoir, 26. WALMSLEY, P. J. 1975. The Forties Field. In: WOODLAND, A. W. (ed.) Petroleum and The Continental Shelf of North West Europe (Vol. 1). Applied Science Publishers, Barking, 447-487. WHYATT, M., BOWEN, J. M. & RHODES, D. N. 1992. The Nelson Field; a Successful Application of a Development Geoseismic Model in North Sea Exploration. In: HARDMAN, R. F. P. (ed.) 1992 Exploration Britain Geological Insights for the Next Decade. Geological Society, Special Publications, 67, 238-305. YALIZ, A. & CHAPMAN, T. 2003. The Lennox Oil and Gas Field, Block 110/15, East Irish Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) 2003 United Kingdom Oil & Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 87-96.
The tectonic and stratigraphic framework of the United Kingdom's oil and gas fields JOHN
R. U N D E R H I L L
School of Geosciences, The University of Edinburgh, Grant Institute of Earth Science, King's Buildings, West Mains Road, Edinburgh EH9 3JW, Scotland, UK (e.mail:
[email protected])
Abstract: Onshore exploration success during the first half of the 20th century led to petroleum production from many, relatively small oil and gas accumulations in areas like the East Midlands, North Yorkshire and Midland Valley of Scotland. Despite this, the notion that exploration of the United Kingdom's continental shelf (UKCS) might lead to the country having self-sufficiency in oil and gas production would have been viewed as extremely fanciful as recently as the late 1950s. Yet as we pass into the new century, only thirty-five years on from the drilling of the first offshore well, that is exactly the position Britain finds itself in. By 2001, around three million barrels of oil equivalent were being produced each day from 239 fields. The producing fields have a wide geographical distribution, occur in a number of discrete sedimentary basins and contain a wide spectrum of reservoirs that were originally deposited in diverse sedimentary and stratigraphic units ranging from Devonian to Eocene in age. Although carbonates are represented, the main producing horizons have primarily proved to be siliciclastic in nature and were deposited in environments ranging from aeolian and fluviatile continental red beds, coastal plain, nearshore beach and shelfal settings all the way through to deep-marine, submarine fan sediments. This chapter attempts to place each of the main producing fields into their proper stratigraphic, tectonic and sedimentological context in order to demonstrate how a wide variety of factors have successfully combined to produce each of the prospective petroleum play fairways and hence, make the UKCS such a prolific and important petroleum province.
Introduction Exploration and development activity in offshore areas of the North Sea, West Shetlands and Irish Sea and onshore areas of the East Midlands, Midland Valley of Scotland, Cleveland, Weald and Wessex Basins has led to petroleum being produced from 204 offshore and 35 onshore fields up to the end of 2001 (Fig. 1). Daily production from the fields found in the United Kingdom Continental Shelf (UKCS) averaged 4.3 million barrels of oil equivalent during 2001 (Fig. 2), meaning that the U K was self-sufficient in oil and gas. Oil production alone totalled around 2.5 million b/d (Fig. 2), which represented over 3% of World oil production that year. Having reached a maximum in 1999, daily production declined in 2000 and 2001 and is expected to continue to fall. However, the U K remains the European Union's only significant oil and gas exporter, this despite being ranked in the top fifteen oil consuming countries. In total, petroleum has been produced from 136 oil, 87 gas and 16 condensate fields which exploit a large variety of clastic and carbonate reservoirs that extend in age from Devonian to Eocene (Fig. 3) and were deposited in multifarious sedimentary environments that range from terrestrial red bed to deep-marine clastic settings. In addition, at least two fields (Emerald and Clair) are known to have produced some of their oil from fractured Precambrian basement. During the 390 Ma time period encompassed by the sedimentary reservoirs, the British Isles and North Sea areas experienced significant changes in each of the fundamental variables on stratigraphy, namely: tectonic regime, climate, eustacy and sediment supply. It is the main aim of this chapter to document how changes in the first three of these variables have combined with each other to influence the tectonic structure and reservoir sedimentology of the oil and gas fields of the UK. The chapter also attempts to show how the stratigraphic elements have controlled other component parts of the petroleum system such as seal, source rock development, the various basins' maturation and migration histories and the preservation of accumulations. As a result it is hoped that this chapter will provide a tectonic and stratigraphic overview and the framework through which to better understand both the setting for each of the individual fields described in this memoir, and the main controls on the petroleum play fairways in which they lie (Johnson & Fisher 1998).
Plate tectonic framework The British Isles experienced two complete plate tectonic cycles during the Phanerozoic: the Caledonian and Variscan Plate Cycles,
both of which have involved the construction (rift-drift) and destruction (subduction and mountain building) of major oceans (Glennie & Underhill 1998). Since the Permo-Carboniferous Variscan Orogeny, however, the British Isles have lain in an intraplate setting and hence, have primarily only been affected by far-field stresses (e.g. diffuse extension and structural inversion caused by the compressional reactivation of former normal faults) generated by active plate margin forces and by deformation caused by thermal effects (e.g. the generation and decay of mantle plume heads). Only the Early Cenozoic could be considered an exception to this general intraplate setting when the stratigraphic development of the British Isles was more closely associated with the opening of the North Atlantic Ocean that propagated north at that time.
The Caledonian Plate Cycle The Early Palaeozoic history of the British Isles and North Sea areas was dominated by the Late Cambrian to Late Silurian, Athollian (former Grampian) and Caledonian Orogenies, which are seen variously as the products of continent-ocean, continent-continent collision and major transpression (Glennie & Underhill 1998; fig. 4). Prior to these events, the North Sea area comprised widely separated continental fragments in, and marginal to, different parts of the Early Palaeozoic S W - N E trending Iapetus Ocean and the N W - S E trending Tornquist Sea (Fig. 4). Closure of the Iapetus Ocean seems to have been both diachronous and to have been achieved by both N W directed and SE directed subduction (Phillips et al. 1976). Within the British Isles, the line of closure is marked by a suture that can be traced from the Shannon estuary in Western Ireland through the NE-trending Solway Firth to the Northumberland coast and beyond (Fig. 4). This suture possibly meets that of the Tornquist Sea at a triple junction within what was later to become the Central Graben, to the north of the Mid North Sea High. Final closure of the Iapetus Ocean resulted in the creation of the mega-continent Laurussia and in uplift of a major mountain range that stretched from the southern United States to eastern Canada (Appalachians) through northern Britain to the northern end of the Greenland-Scandinavia craton (Caledonides). The final stages of collision were accompanied by the intrusion of Early Devonian granites, which were to play an important role in the subsequent location of extensional fault blocks (e.g. during the periods of Carboniferous and Late Jurassic extension).
GLUYAS, J. G. & HIeHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 17-59.
18
J . R . UNDERHILL
The Variscan Plate Cycle The Variscan Plate Cycle lasted from Devonian to Late Carboniferous times. It began with Devono-Carboniferous rifting initially driven by intramontane collapse and the creation of the ProtoTethys or Rheic Ocean to the south in what is now continental Europe (Fig. 5). The structural configuration of the British area was largely controlled by the occurrence and reactivation of Caledonian and other basement lineaments together with the presence of granitic plutons. Whilst an E - W trending passive continental margin primarily consisting of S-dipping normal fault systems was developed that extended across much of southern parts of England and Wales, a series of intracontinental extensional half-graben char-
acterized more northern areas (e.g. East Midlands and Northern England, Fig. 6). Where the basement lineaments or the margins of Caledonian granitic intrusions were not favourably oriented to take up dip-slip extensional displacement, strike- or oblique-slip ensued (e.g. Midland Valley of Scotland, the Dent Fault and the Southern North Sea; Underhill et al., 1988). The Late Carboniferous Variscan Orogeny marked the closure of the Rheic Ocean and the creation of the supercontinent Pangaea. It led to the former passive continental margin being telescoped to form a mountain belt and a foredeep (foreland) basin that stretched from SW Ireland through South Wales, Devon and Cornwall to Kent, the Ardennes of Belgium and beyond (Fig. 7). The effects of the contractional deformation and associated metamorphism place
Fig. 1. Location map illustrating the distribution of the oil, gas and condensate fields of the United Kingdom Continental Shelf (UKCS). The diagram highlights the location of other figures used throughout the text.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
19
Fig. 2. Production figures for the period 1970-2001 for the UKCS. The histogram shows that oil and gas production intially peaked in 1986. After falling in the late 1980s it then rose steadily to reach a maximum of around 4.6 m barrels oil equivalent per day (boed) in 1999, since which time it has fallen. Further decline is expected over the next decade. In 2001, oil production accounted for around 2.5 m boed; gas production accounted for a further 1.8 m boed. effective limits on the southern extent of Devonian and Carboniferous play fairways. Further north, the intracratonic extensional and strike-slip basins of central and northern parts of the U K took up Variscan deformation through the contractional reactivation (structural inversion) of the former extensional faults and regional uplift (Underhill et al. 1988; Fraser & Gawthorpe 1990; Underhill & Brodie 1993; Corfield et al. 1996; Fig. 6b).
Intraplate deformation
Early Permian subsidence led to the development of two, E - W trending sedimentary depocentres, the Northern and Southern Permian Basins (Fig. 8; Glennie 1998; Ziegler 1982, 1990a, b). The formation of these two major basins was locally accompanied by rift-related igneous intrusions and volcanic products (Fig. 8). These included the development of E - W trending dyke swarms in the Midland Valley of Scotland, the intrusion of the Whin Sill igneous complex in NE England and the occurrence of volcaniclastic sediments across what is now the Dutch continental shelf and other parts of Europe (e.g. the Polish Trough and Oslo Graben). Extensional activity appears to have persisted into the Triassic with the development of numerous half-graben depocentres in areas like the Irish Sea, Wessex Basin and parts of Norway (e.g. the Stord and Egersund Basins, where there was accompanying igneous activity). Although the occurrence and trend of the Permo-Triassic faults are often thought to be a major contributory factor in subsequent
fault activity, recent seismic interpretation in the Northern North Sea has suggested that the earlier events are largely independent of Late Jurassic extension. Consequently, there is little evidence that the trilete rift system, that dominated Late Jurassic-Recent history of the North Sea, can be attributed to the reactivation of PermoTriassic structures. The Permian and Triassic periods of extensional basin development were largely succeeded by thermal subsidence. The period of post-rift activity, which continued into Early Jurassic times, was al~ruptly terminated by a phase of latest Early Jurassic to Middle Jurassic doming, which was accompanied by igneous activity (the Rattray Volcanic Series; Dixon et al. 1981). The uplift is interpreted to have resulted from the development of a warm, diffuse and transient plume head in central parts of the North Sea (the North Sea Dome; Fig. 9); Underhill & Partington 1993, 1994). Erosion of the domed area led to dispersal and progradation of significant volumes of fluvio-deltaic sediments, the most significant of which led to the development of the Brent Group delta in the East Shetland Basin of the Northern North Sea (Budding & Inglin 1981; Eynon 1981; Graue et al. 1987; Helland-Hansen et al. 1992). The subsequent collapse of the thermal dome, helped initiate Late Jurassic to earliest Cretaceous extensional tectonics. The associated extensional deformation led to the development of the trilete rift system consisting of the Viking Graben, Central Graben and Moray Firth (Fig. 10; Underhill 1991; Davies et al. 2001), all of which were themselves characterized internally by fault-block rotations and the formation of major structural traps (Christie & Sclater
20
J . R . UNDERHILL
Fig. 3. Summary of the main stratigraphic units that comprise the prospective reservoirs and source rocks of the UKCS. (a) Northern North Sea; (b) South Viking Graben and Central North Sea; (e) Southern North Sea; (d) Irish Sea Basin; and (e) the Wessex Basin of Southern England. Columns (a) and (b) are modified after Pegrum & Spencer (1990).
Fig. 4. Structural foundation for NW Europe showing the areas affected by Variscan and Caledonian orogenic deformation. Modified after Ziegler (1982, 1990b).
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
21
Fig. 5. Middle Devonian Palaeogeography showing the predominance of non-marine intramontane basins in Northern Britain and the occurrence of the fully-marine, passive continental margin associated with the developing Rheic Ocean to the south. Development of non-marine shales deposited within a permanent lake located within the Orcadian Basin, led to the development of a source rock that later provided some of the charge within the Inner Moray Firth (e.g. the Beatrice Field). Modified after Ziegler (1982, 1990a).
1980; Beach 1984; Badley et al. 1988; Yielding 1990; Yielding et al. 1992). The phase of Late Jurassic extentional basin development was followed by a phase of Cretaceous-Cenozoic post-rift thermal subsidence during which Carboniferous Coal Measures and the Late Jurassic Kimmeridge Clay Formation source rocks were buried sufficiently deep enough to mature. It is the migration of petroleum out from the deepest and parts of the basin to charge reservoirs contained within sealed traps (Figs 11, 12 & 13) that has made the United Kingdom's continental shelf in general, and the North Sea basin in particular, the prolific oil and gas province that it has become. In western parts of the UK, any Late Jurassic North Sea tectonic influence was superceded during Cretaceous and Early Cenozoic times by extension linked to the northeastward propagation and
eventual onset of sea-floor spreading in the North Atlantic Ocean in Early Eocene times (e.g. Knott et al. 1993). Regional extension in the area caused the development of several N E - S W trending sedimentary basins in the Cretaceous, which then primarily underwent thermal subsidence during the Cenozoic (e.g. the Faroe-Shetland Basin; Duindam & Van Hoorn 1987; Mudge & Rashid 1987; Earle et al. 1989; Lamers & Carmichael 1999). However, the initial development of the Iceland hot-spot (White 1988, 1989; Clift et al. 1995) and the subsequent opening of the Atlantic Ocean led to the development of the Tertiary Igneous Province (Fig. 14; Mussett et al. 1988; White 1992). Both tectonic processes also caused the post-rift subsidence to be punc-tuated and were major factors in the Cenozoic uplift and exhumation of parts of the British Isles, including the
Fig. 6. (a) Structural cross-section across the Widmerpool Gulf, East Midlands (after Fraser & Gawthorpe, 1990). The section demonstrates the typical extensional, half-graben geometries that characterized basin development in Northern Britain during the Early Carboniferous. Location of the cross-section is depicted in Fig. 18. (b): Structural cross-section across the Eakring and Farley's Wood oilfields of the East Midlands (After Fraser & Gawthorpe, 1990). The section demonstrates how the two fields have both resulted from Late Carboniferous-Early Permian (Variscan) structural compressive reactivation (inversion) of extensional that originally controlled deposition during early Carboniferous times (cf. Fig. 6a). Similar contractional deformation in the Variscan foreland led to the development of many, analogous and prospective inversion structures in the east Midlands, beneath the Cleveland Basin and in offshore waters of the Southern North Sea. Location of the cross-section is depicted in Figure 18.
Fig. 7. Late Carboniferous palaeogeography showing the effect that the Variscan Mountain Belt had in controlling the development of a foreland (foredeep) basin and the deposition of paralic sediments ascribed to the Coal Measures Group, a significant reservoir unit in the Southern North Sea Basin. Modified after Ziegler (1982, 1990a).
p
c~
z~
~ ~~
o
~~ ~
- ~ ' ~
~~ ~
0
0
-g
.,..~
~-~
~.~
. ,...~
o
.
o,-~
~
~
~-~
~.~
N
~
.,.~
~:
24
J . R . UNDERHILL
Fig. 9. Maximum aerial extent of the Central North Sea Dome that heavily influenced the nature and distribution of reservoirs deposited during Middle Jurassic times (after Underhill & Partington, 1994). The dome is interpreted to have been initiated and then deflated in response to a warm, diffuse and transient mantle plume head, which was located beneath the Central North Sea. Uplift associated with the thermal event led directly to non-marine deposition replacing marine conditions in the area and the development of the highly prospective, Brent Group delta in the Northern North Sea as sediment was redirected off the emergent domed landmass. western rift arm in the North Sea, the Inner Moray Firth (Hillis et al. 1993; Thomson & Underhill 1993; Nadin et al. 1995). Creation of the ocean helped initiate intraplate compression, which together with the far-field compressional effects of Alpine collision led to the tectonic inversion of former sedimentary basins across N W Europe (e.g the Wessex Basin, Fig. 15; Colter & Harvard 1981; Underhill & Paterson 1998; Underhill & Stoneley 1998), the Weald Basin (Butler & Pullan 1990) and in the Southern North Sea (e.g. Glennie & Boegner 1981; Van Hoorn 1987; Ziegler 1987; Badley et al. 1989). As with the North Sea, it was the Atlantic Margin's post-rift subsidence history which ultimately led to sufficient burial of Kimmeridge Clay Formation to cause up-dip charge of petroleum into fields that occur along the margins of the Faroe-Shetland Basin (Fig. 13).
Fig. 10. Diagram depicting the trilete North Sea rift system, which developed during Middle and Late Jurassic times. Each of the three rift arms (the Moray Firth, Viking Graben and Central Graben) was characterized by active normal faulting with the development of numerous, highly prospective footwall closures containing tilted and rotated pre-rift reservoirs. Modified after Pegrum & Spencer (1990).
grew and dominated polar regions ('icehouse conditions'). In total, seven oscillations appear to have characterized the Phanerozoic (Fig. 17). Icehouse conditions appear to have prevailed during the Late Proterozoic-early Phanerozoic (800-570Ma), Late Ordovicianearly Silurian (458-428Ma), Early Carboniferous-Late Permian (333-258 Ma) and Early Cenozoic onwards (55 Ma to the presentday). Greenhouse conditions appear to have prevailed at other times, namely: during the Early Cambrian-Late Ordovician (570-458 Ma), Early Silurian-Early Carboniferous (428-333 Ma) and Late Permian-Early Cenozoic (258-55 Ma).
Eustacy through time Climate through time Superimposed upon the changing pattern of crustal fragmentation and reunification was an overall slow northward passive drift of the continents. This drift took the North Sea area from south of the Equator prior to the Carboniferous to its present location over half way from the Equator to the Northern Pole (Fig. 16; Habicht 1979; Smith et al. 1981). The inexorable northward-drift had a pronounced effect on fauna and on sedimentation as the area passed through successive latitudes and climatic belts. An additional global climatic control appears to have overprinted or modified the effects of northward drift. During the Phanerozoic, the Earth's climate appears to have oscillated between a state of global warming and incubation ('greenhouse conditions') and one of global cooling and refrigeration during which ice sheets
Global (eustatic) sea levels have varied throughout geological time largely as a consequence of changing the volume of ocean water or by changing the volume of ocean basins themselves. Changes in the water volume may be achieved either by an increase in the amount of land ice, a change in water temperature or the dessication of enclosed bodies of water that previously connected to the oceans (e.g. the Mediterranean during the Messinian). Changes in the ocean basins are thought to result from variations in sea-floor spreading rates, continental deformation or to occur at times of high sediment supply. Whatever the cause, the variation in global sea level has influenced the nature of sedimentation largely by determining the extent to which continental land masses have been flooded, the depth of water in oceans and the degree of water circulation within and between basins.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
25
donian Orogeny, which resulted from the closure of the Iapetus Ocean and Tornquist Sea. In the case of some of the Precambrian rocks, they also experienced the effects of Laxfordian and Scourian deformation as well.
Devonian
Devonian sedimentation records the erosion of the mountain belt that was formed by the Caledonian Orogeny. In northern Britain and the North Sea area, deposition largely appears to have taken place in a series of post-orogenic basins created through the extensional collapse of the fold-and-thrust belt (Fig. 4). It has long been recognized that erosion in an almost vegetation-free, arid, continental climate that experienced seasonal rainfall resulted in deposition of widespread red, clastic sediments dominated by alluvial, fluvial and aeolian sequences (e.g. Barrell 1916; Allen & Marshall 1981) with only minor marine incursions (Marshall et al. 1996). The rivers appear to have largely flowed into closed drainage basins. In one notable case, the drainage system terminated in the development of an extensive intramontane lacustrine basin, Lake Orcadie (Fig. 14). Fish beds in the lacustrine sediments of the Orcadian Basin are famed for the richness and diversity of their contained species, and have been considered as a potential source of oil in the Inner Moray Firth (Duncan & Hamilton 1988; Peters et al. 1989). Reservoir rocks can be found in Mid and Upper Old Red Sandstone fluvial and aeolian sediments equivalent to those that are exposed in Caithness, Orkney and Shetland. Devonian and Carboniferous red bed successions form the subordinate reservoirs in the Argyll Field (Robson 1991) and the Embla (Knight et al. 1993) and West Brae Discoveries (Downie 1998). It forms the main reservoirs in the Buchan (Edwards 1991) and Stirling Fields in the North Sea and the Clair Field, West of Shetland (Coney et al. 1993; Johnston et al. 1995; Downie 1998). Fig. 11. Aerial extent of mature source rocks belonging to the Upper Jurassic, Kimmeridge Clay Formation (KCF) at the present-day. The KCF has been shown geochemicallyto have provided the vast majority of the petroleum produced from the East Shetland Basin and Viking Graben areas of the Northern North Sea, the Central Graben, the Witch Ground Graben area of the Outer Moray Firth and the Faroe-Shetland Basin, West of Britain. It may also have previously been mature over large areas of the Inner Moray Firth, prior to that basin's uplift during the Cenozoic.
It is generally accepted that global sea-levels achieved their maximum level during the Late Cambrian-Early Ordovician and again in the Late Cretaceous (Fig. 17). The second of these periods had a profound effect on the stratigraphy of the North Sea and British Isles since it led to a severe reduction in terrigenous supply across the European continental shelf. Conversely, eustatic minima during the Permian and Triassic led to the dominance of thick continental red bed successions.
Tectonic and stratigraphic controls on the development of petroleum play fairways of the United Kingdom Pre-Devonian
Precambrian and Lower Palaeozoic rocks effectively form the economic basement to the petroleum reservoir section of the UKCS. With the exception of the oil obtained from the fractured metamorphic rocks in the Clair and Emerald Fields (Stewart & Faulkner 1991; Coney et al. 1993; Johnston et al. 1995), in the West of Shetlands and Northern North Sea respectively, no significant petroleum reserves have been discovered in rocks older than Devonian age. This is largely because they all suffered the effects of folding, thrusting, metamorphism and igneous intrusion associated with the Cale-
Carboniferous
With the slow northerly drift of Laurussia, Early Carboniferous sedimentation represents a transition from the relatively arid conditions of the southern hemisphere tropics that prevailed at the end of the Devonian to the more humid equatorial conditions of Coal Measures Group deposition. The patterns of sedimentation were strongly influenced by syn-sedimentary tectonics with many of the strong NW-SE and NE-SE structural trends developed in the northern England Carboniferous were inherited from the late Palaeozoic Caledonian Orogeny. These fault trends were consistently reactivated throughout the Carboniferous in an extensional and, at the end of the Carboniferous, in a compressional sense (Corfield et al. 1996; Figs 4-7). The structural framework of Central and Northern England was dominated by the formation of numerous extensional basins during early Carboniferous times (e.g. the Northumberland, Stainmore and Gainsborough Troughs, the Bowland Basin and the Widmerpool Gulf; Fig. 4; Fraser & Gawthorpe 1990). Their Late Devonian-Early Carboniferous (Fammenian-Brigantian) syn-rift deposition was characterized by mixed clastic and carbonate sedimentation. During the extensional episode, tectonic subsidence generally exceeded the rate of sediment supply such that clastic deltas remained confined to northern areas (Midland Valley of Scotland and Northern England) with clastic turbidites being deposited in basinal areas and carbonate reefs forming along basin margins and as progradational wedges on depositional slopes in more southerly areas (e.g. the East Midlands; Fraser & Gawthorpe 1990). Post-rift thermal subsidence appears to have become established by early Namurian (Pendalian) times and continued into the Westphalian. Reduced subsidence led to an expansion of clastic systems and fluvio-deltaic sediments of the Millstone Grit and Coal Measures prograded southwards to become established over the
26
J.R.
UNDERHILL
Z
~
o . 9
~~
"-~
" ~
"-~ ~ ~
~
0
0
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
Fig. 13. Diagram depicting the aerial extent of mature source rocks belonging to the carboniferous Coal Measures group in the Southern North Sea. Their distribution and maturity was controlled by the extent of Mesozoic subsidence and was arrested by subsequent structural inversion events. After Alberts & Underhill (1991). East Midlands and Southern North Sea. Further tectonic instability was initiated in the Late Westphalian and continued into the Stephanian. It resulted from the onset of Variscan deformation to the south and led to the formation of a major foreland basin immediately ahead of the rising mountain front. The basin appears to have stretched from Southern Ireland through the South Wales Coalfield
27
to the Southern North Sea and beyond. Compartmentalization of the basin into smaller successor basins and the northward-directed run-off of coarse clastic material from the mountain belt appears to have led to the development of the Barren Red Measures during the Stephanian (Besly e t al. 1993). Continued syn- and post-depositional compression across the Variscan foreland (i.e. ahead of the thrust front) resulted in folding, the partial or complete structural inversion of many former extensional faults and peneplanation driven by regional uplift, prior to deposition of the Rotliegend in Permian times. Drilling of preserved footwall highs formed during the earlier extensional episode has led to local production of Carboniferous sourced oil from Dinantian carbonates (e.g. at Hardscroft). However, by far and away the most prospective structures have proved to be those formed by structural inversion ofsyn- and post-rift clastic sequences during the Late Carboniferous. This contractional deformation led to the formation of hangingwall anticlines adjacent to the reactivated former normal faults (e.g. Eakring Field; Fraser & Gawthorpe 1990; Fig. 7). The successful drilling and appraisal of such structures has led to production from numerous fields in the East Midlands (e.g. the Beckering, Beckingham, Belvoir, Bothamhall, Brigg, Callow, Caunton, Cold Hanworth, Corringham, Cropwell Butler, Crosby Warren, Eakring (Fraser & Gawthrope 1990), Eakring Dukeswood (Storey & Nash 1993), East Glentworth, Egmanton, Farley's Wood, Fiskerton Airport, Gainsborough, Glentworth, Hatfield Moors and Hatfield West (Ward e t al. 2003), Keddington, Kelham, Kirklington, Langer, Long Clawson, Nettleham, Plungar, Rempstone, Saltfleetby (Hodge 2003), Scampton, Scampton North, Scupholme, South Laverton, Stainton, Torskey, Trumfleet, Welton, Whisby and West Firsby (Bailey 2003) fields (Fig. 18) and Northern England (e.g. the Malton and Kirby Misperton fields; Fig. 19). The Carboniferous play of the Southern North Sea is very similar to its East Midlands counterpart (Leeder & Hardman 1990), except that the main (Carboniferous, Coal Measures Group) source rock is gas-prone rather than oil-prone. The main reservoir potential exists in clastic reservoirs of Namurian, Westphalian and StephanJan age that were folded and erosionally truncated by the Variscan Unconformity (Fig. 20; Besly 1998). Although the play fairway
Fig. 14. Diagrams depicting Palaeocene and Late Oligocene plate reconstructions in NW Europe. Development of the proto-Iceland hotspot during Palaeocene times and the subsequent opening of the North Atlantic Ocean heavily influenced the tectonic, stratigraphic and sedimentological development of the UKCS, all of which had immediate consequences for Paleogene reservoir prospectivity in the Faroe-Shetlands and North Sea Basins. Modified after Torsvik et al. (2002). The circle in (a) depicts the approximate extent of plume-related igneous activity during the Palaeocene.
SOUTH
NORTH PORTSDOWN RIDGE
WEALD
BASIN
LONDON PLATFORM
LITTLEHAMPTON
STORRINGTON- BOLNEY GODLEYBRIDGE GUILDFORD HENFtELD ANTICLINE --~ BA"" (ALFOLD)ANTICLINE SHALFORD TERTIARY ANTICLINE PRO3E.C~.u _.~ K . . . . . . . . . .. ANTICLINE ~~--c.~-~-'~'" ,.- . . . . . . . . . . . . . . . . . . . . . . . . . . " . . . ... . ... . . . . . ._.". . . . ...... . :....~,~TERTIARY,~ ,, COAST / , " , ' ,"C~', ,, ,':, ~ . '-, ~ I I WEALDENANDPURBECKIAN/
J
~h A 4 ~ ~ AAAA
~
5000 -
10000
(c)
Jt 0
i
1Ok , ,
'
'
4,~ 4 4
.
AAAA~AAAAAA~
,
,
,
, *
A4
L
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
Fig. 16. Graph showing the steady northward drift experienced by the UKCS area over the past 450 Myrs, which led to the systematic development of different climate zones through time. That climatic influence provided one of the main controls on the nature and character of the sedimentary rocks, which comprise the reservoir and source rocks of the UKCS. Modified after Glennie & Underhill (1998).
29
received a lot of attention during the late 1980s and early 1990s, it remains poorly understood. To date production has only occurred in nine gas fields (Fig. 19), namely: the Boulton (Conway & Valvatne 2003a), Caister C (Ritchie & Pratsides 1993; Ritchie et al. 1998), Johnston (Lawton & Roberson 2003), Murdoch (Fig. 21a; Conway & Valvatne 2003b), Schooner (Moscariello 2002), Trent (Fig. 21b; O'Mara et al. 1999, 2003a) and Tyne North, South and West (O'Mara et al. 2003b) fields (Fig. 19), which together contribute around 5% of U K gas production. Lower Carboniferous clastic reservoirs belonging to the Strathclyde and Inverclyde Groups (formerly known as the Calciferous Sandstone Series) have also produced waxy crude in the Cousland and Midlothian (D'Arcy) Fields of East Lothian and the Milton of Balgonie discovery in Fife in the Eastern Midland Valley of Scotland. These three structures all lie on the margins of the LothianFife syncline and form part of a local, unique small petroleum province in the eastern Midland Valley of Scotland. The petroleum appears to have been derived from the Lower Carboniferous, Lothian Oil Shales, a series of organic mudstones that were deposited in a restricted lake setting developed ahead of the westerly prograding deltaic complexes. They were subsequently charged as burial occurred beneath the Lothian-Fife syncline prior to Variscan uplift. The main synformal axis and its associated structural closures appear to have formed in response to progressive strike-slip deformation during Carboniferous and Variscan events. Production is also recorded locally from Carboniferous reservoirs that lie beneath younger reservoir horions in North Sea Fields. The best known example occurs in the Outer Moray Firth, where
Fig. 17. Changes in temperature and eustatic sea-levels throughout the Phanerozoic. As with climate, development of greenhouse or icehouse conditions and global sea-level fluctuations have played a significant role in controlling the nature and character of the sedimentary rocks, which comprise the reservoir and source rocks of the UKCS. Modified after Doyle et al. (1994).
Fig. 15. Effects of structural inversion of Mesozoic basins in Southern England. (a & b) Show N-S cross-sections constructed across the Wessex Basin of South Dorset. They show the present and restored structural configuration of the basin and highlight the important role that tectonic inversion of the former extensional faults has had in setting up and destroying fault-bound and folded closures in the basin. With the exception of one small inversion-related fold (Kimmeridge Bay oilfield), prospectivity has been limited to extensional fault closures unaffected by the effects of Cenozoic inversion (e.g. Wytch Farm oilfield). Diagram after Underhill & Stoneley (1998). (c) Depicts a N-S cross-section across the Weald Basin of SE England. It also highlights the role that reactivated deep-seated planar normal faults had in controlling the structural configuration of the basin. The prospective structures that lie along the rim of the basin largely result from Mesozoic charge and have remained valid because they were unbreached by subsequent contractional deformation or were ideally located to be filled by remigration during the Cenozoic events. In both the Weald and the Wessex Basins the main charge was provided by the Lower Jurassic Lias Group source rocks rather than the Kimmeridge Clay Formation. Modified after Butler & Pullan (1990).
30
J.R. UNDERHILL
Fig. 18. Distribution of sedimentary basins and oil fields in the East Midlands. The reservoir units in the fields are of Carboniferous age. The prospective structures are largely the result of Early Carboniferous extension or Late Carboniferous-Early Permian (Variscan) tectonic inversion as depicted in the cross-sections used in Fig.6.
oil has been produced from a structurally-elevated horst block in the Claymore Field, which contains a Namurian, coal-bearing fluvial reservoir succession beneath the main productive Jurassic and Cretaceous horizons (Harker et al. 1991). In the southermost part of the Central Graben, oil is also produced from Upper Carboniferous sandstones within the Flora Field (Hayward et al. 2003). Finally, recent advances in technology have seen the exploitation of coal bed methane from Carboniferous sources. For example, in the Midland Valley of Scotland, where the Limestone Coal Group provides dry gas in the Airth-1 well near Kincardine.
Permian
Parts of the Variscan Mountains already had begun to collapse during the late stages of the orogeny with the development of several important E-W trending, intramontane basins, the most important of which in the UKCS were the Northern and Southern Permian Basins (Fig. 8). With little rainfall and strong deflation, wide expanses of arid desert characterized the sediment-starved basins. It has been suggested that by the time of the Late Permian
Zechstein marine transgression, the deepest parts of these basins were occupied by desert lakes whose surfaces were probably some 200-300 m below sea level (Glennie 1998).
Rotliegend Group. The Rotliegend Leman Sandstone Formation (Rhys 1974) forms the main productive reservoir in the largest gas fields of the Southern North Sea (Fig. 19). It extends over southern parts of the Southern Permian Basin and consists primarily of crossbedded, dune sandstones that were deposited in an aeolian erg setting (Fig. 22; Glennie 1998; Sweet 1999). Fluvial (wadi) gravels evidently locally dissected the aeolian system (Sweet 1999) and form subsidiary reservoirs in some fields (e.g. Rough; Stuart 1991, fig. 6). The main fields containing Leman Sandstone Formation as the reservoir include the Amythyst (Garland 1991), Brigantine, Bell, Davy, Bessemer, Beaufort and Brown (McCrone 2003), Barque (Farmer & Hillier 1991a; Sarginson 2003a), Caister (Ritchie & Pratsides 1993), Camelot (Holmes 1991; Karasek & Hunt 2003), Cleeton (Heinrich 1991a), Clipper (Farmer & Hillier 1991b; Sarginson 2003b), Corvette (Hillier 2003a), Gawain (Osbon et al. 2003), Guinevere (Lappin et al. 2003), Leman (Van Veen 1975; Hillier & Williams
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
31
Fig. 19. Distribution of fields in the Southern North Sea region. The fields fall into several fairly exclusive categories, namely: Carboniferous gas fields that are sealed by shales belonging to the Permian, Silverpit Formation (brown ornament); Permian, Rotliegend Group, Leman Sandstone Formation gas-filled reservoirs (yellow ornament); and, Triassic, Bunter Group gas fields located adjacent to salt withdrawal structures in Quadrant 43 or in the Hewett Field (violet ornament). Carbonates of the Upper Permian, Zechstein Group also form the reservoir in the Hewett Field and in several onshore fields located within the Cleveland Basin (purple ornament).
199 l; Hillier 2003b), Hyde (Steele et al. 1993)~,Indefatigable (Pearson et al. 1991; McCrone et al. 2003), Malory (O'Brien et al. 2003), M a r k h a m (Meyres et al. 1995), Mercury and Neptune (Smith & Starcher 2003), Pickerill (Werngren et al. 2003), Ravenspurn North & South (Ketter 1991b; Heinrich, 1991b; Turner et al. 1993), Rough (Stuart 1991), Sean North and South (Hobson & Hillier 1991; Hillier 2003c), Thames, Yare and Bure (Werngreen 1991), Victor (Lambert 1991), Viking (Morgan 1991; Riches 2003) and the other V fields (Pritchard 1991; Courtier & Riches 2003), Waverney (Bruce & Rebora 2003), West Sole (Winter & King 1991) and Windermere (Bailey & Clover 2003) fields (Fig. 19).
In northern parts of the same basin, the Leman Sandstone Formation is replaced by the Silverpit Formation, a mudstonedominated facies with subsidiary evaporitic units, that was deposited in a desert lake (sabkha) setting (Figs 22 & 23). Whilst the Silverpit Formation has no reservoir potential, it remains an important component for prospectivity since it acts as the main seal for underlying Carboniferous sandstones. The Silverpit Formation interdigitates with the Leman Sandstone Formation in intermediate areas, where it consists of a transitional continental sandy sabkha facies that is often a 'waste zone' being neither a reservoir nor a sealing unit (Fig. 23; Alberts & Underhill 1991).
32
J.R. UNDERHILL
Fig. 20. Carboniferous subcrop patterns found beneath the base Permian in the Southern North Sea, which resulted from an important phase of folding in the foreland to the Variscan mountain belt.
Reddened Rotliegend sandstones are also known to exist beneath the Central Graben, where they provide reservoirs in the Auk (Brennand & Van Veen 1975; Heward 1991; Trewin & Bramwell 1991; Trewin et al. 2003), Argyll (Bifani et al. 1987) and Innes fields (Robson 1991; Fig. 20). Like the Rotliegend of the Southern North Sea, they largely consist of mixed aeolian and fluvial lithofacies associations. Their floral data suggests that the sediments are Upper Permian in age rather than being Lower Permian as previously thought (Glennie 1997, 1998).
Zechstein Group
The Zechstein Group consists of six sedimentary cycles (ZI-Z6), which reflect deposition in response to marine recharge and its subsequent regression and evaporation in the Northern and Southern Permian Basins. Each cycle begins with a pronounced marine incursion (e.g. the Kupferschiefer or Marl Slate, coincidentally a minor oilprone source rock, which marks the first such incursion) and ends with the deposition of widespread evaporates, many of which were remobilized to form diapirs and salt pillows long after deposition. As well as the vertical variation in sedimentary facies, lateral facies change also characterizes the Zechstein Group in the Southern North Sea and adjacent land areas (e.g. Cleveland Basin). Non-marine red bed deposition on the basin margins passes into carbonates and eventually into evaporates towards the axis of the basin.
Zechstein evaporates form a very effective seal for the underlying Rotliegend Leman Sandstone reservoirs. The only exceptions occur where evaporite mobility has led to complete withdrawal and grounding of the overburden. When this has occurred seal breach and gas escape into the Triassic and younger sediments has resulted. Zechstein carbonates also form reservoirs in and around the periphery to the Southern North Sea Basin (e.g. in the Cleveland Basin; Fig. 19) and in one or two other local areas (e.g. Ettrick Field in the Outer Moray Firth (Amiri-Garroussi & Taylor 1987) and Auk and Argyll Fields in the Central North Sea; Trewin & Bramwell 1991; Robson 1991). To date, producing reservoirs in North Yorkshire have been restricted to the Kirkham Abbey Formation, the carbonate-bearing unit of the Z2 cycle that was formerly known as the Middle Magnesian Limestone and is equivalent to the Hauptdolomite of the Southern North Sea (e.g. in the Kirby Misperton, Malton and Marishes gas fields; Fig. 19). However, gas has also been discovered in, and may soon be produced from, the Z3 carbonates, which are ascribed to the Brotherton Formation or Upper Magnesian Limestone and is equivalent to the Plattendolomite in neighbouring offshore waters.
Triassic
During the Triassic renewed tensional stresses affected the crust and led to the development of a network of half grabens in and around
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
33
Fig. 21. Representative strike and dip cross-sections along and across the Murdoch Field in the Southern North Sea. The lines show the narrow, highly-faulted structural style that characterizes the Carboniferous gas fields in the area and has been ascribed to flower structures. These are believed to have resulted due to post-depositional strike- and oblique-slip movements on throughgoing and reactivated NW-SE trending lineaments first formed during the closure of the Tornquist Sea during the Caledonian Orogeny.
the British Isles that include the Cheshire, Wessex, Hebridean (Steel & Wilson 1975) and Irish Sea basins. The largest of the deep Triassic troughs was the East Irish Sea Basin in which over 4 km of sediment was deposited (Jackson & Mulholland 1993). Irrespective of their onshore or offshore location, the basins seem largely to have formed along the lines of inherited basement weaknesses. Productive Triassic reservoirs are extensive in the U K C S being found in the Southern North Sea (Fig. 19), Irish Sea (Fig. 24), Wessex Basin (Fig. 25), Central North Sea (Fig. 26) and Northern North Sea (Fig. 27). The occurrence of petroleum in the Strathmore discovery shows that there may also be Triassic reservoir potential in the West Shetlands area. Irrespective of geographical location, the Triassic sediments are dominated by red bed sequences that
were deposited in a range of continental environments that ranged from fluvial to lacustrine (salina or sabkha) settings. Unlike Central Europe, the whole succession is devoid of any significant marine influence throughout. This does not allow the Triassic to be easily correlated with the classic tripartite division of the Buntsandstein, Muschelkalk and Keuper and has led to local lithostratigraphic schemes being produced for each individual basin. Sediments of the Triassic Group are subdivided into three main lithostratigraphic units in the Southern North Sea: the Bacton Group, the Haisborough Group and the Dudgeon Group. Of these, only the Bacton Group provides a significant contribution to the petroleum production of the basin through the occurrence of the Bunter Sandstone, an extensive fluvial red bed succession which
34
J . R . UNDERHILL
Fig. 22. Permian, Rotliegend Group palaeogeography of the Southern North Sea Basin. The map shows the spatial distribution of the main Leman Sandstone Formation reservoirs, the non-reservoir facies ascibed to the Silverpit Claystone Formation and the extent of the intermediate waste zone in which some major gasfields still occur.
forms a major reservoir unit in the Hewett (Cumming & W y n d h a m 1975; Cooke-Yarborough 1991; Cooke-Yarborough & Smith 2003), Caister B (Ritchie & Pratsides 1993), Esmond, Forbes, Gordon (Ketter 1991 a) and Little Dotty gas fields (Fig. 19). It is sealed by the overlying Rot Halite Member, the basal unit of the Haisborough Group.
Triassic sediments also form important productive reservoirs in other sub-basins in and around the UK. They are of particular importance in the Irish Sea and Wessex Basins (Figs 24 & 25), where they are known as the Sherwood Sandstone Group. In both areas, they consist of mixed aeolian and fluvial coarse-grained sediments
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
Fig. 23. Schematic diagram depicting the range and distribution of sedimentary facies in the Permian Rotliegend Group of the Southern North Sea (After Alberts & Underhill, 1991).
and form the main reservoirs in the Morecambe North and South gas fields (Stuart & Cowan 1991; Stuart 1993; Cowan 1996; Cowan & Boycott-Brown 2003; Bastin et al. 2003), Dalton, Douglas (Yaliz & McKim 2003), Hamilton, Hamilton North (Yaliz & Taylor 2003), Lennox (Yaliz & Chapman 2003) and Millom fields and the Calder and Oryx discoveries in the Irish Sea and the Wytch Farm and Wareham fields of the Wessex Basin (McKie et al. 1998; Underhill & Stoneley 1998; Hogg et al. 1999). Triassic sediments also form important reservoirs in the Central North Sea (Fig. 26), where their facies distribution appears to have been largely controlled by the syn-sedimentary effects of evaporite mobility. It appears that whilst shaley successions ascribed to the Smith Bank Formation were being deposited in areas that were experiencing evaporite evacuation, coarse-grained reservoir sandstones of the Skaggerak Formation were being laid down above the crests of rising evaporite diapirs. Although this has led to a particularly complex distribution of coarse clastics, it is effective enough to form significant reservoirs in many of the fault blocks that developed during the Late Jurassic rift episode. These include the Gannet C, E and F fields (Armstrong et al. 1987) and the Elgin and Franklin (Lasocki et al. 1999), Egret, Heron, Judy, Marnock, Puffin, Shearwater and Skua fields (e.g. Pooler & Amory 1999; Fig. 26). There are several fields in the Northern North Sea that produce from Triassic reservoirs, the largest of which, Snorre, forms part of a pre-rift sequence within a Late Jurassic extensional tilted fault block in Norwegian waters. Production in Snorre comes from the Lunde, Lomvi and Teist Formations, the component parts of the Hegre Group. Unlike Norwegian waters, little attempt has been made to subdivide the Triassic stratigraphy in the U K Northern North Sea and the red beds are simply ascribed to the Cormorant Formation. Production from the Cormorant Formation occurs in the Cormorant North and South (Taylor & Dietvorst 1991), Pelican and Tern (van Panhuys-Sigler et al. 1991) fields (Fig. 27) and is expected to occur from the Penguin field in the East Shetland Basin in the near future. More recently, the results of deep drilling has shown that large quantities of condensate reside beneath some of
Fig. 24. Distribution of oil and gas fields in the East Irish Sea Basin. Production is exclusively from the Triassic, Sherwood Sandstone Group in the offshore fields.
35
36
J.R. UNDERHILL
Fig. 25. Petroleum habitat in the Wessex Basin of Southern England. The diagram shows the location of the Kimmeridge, Wareham, Stoborough and Wytch Farm oilfields and the former extent of the Lower Jurassic, Lias Group kitchen areas prior to Cenozoic uplift and structural inversion.
Fig. 26. Distribution of fields containing Triassic reservoirs in the Central North Sea. The fields all lie within footwall closures adjacent to normal faults that were active during Late Jurassic rifting. The fields occur within a region characterized by high pressure and high temperature (HP-HT) conditions.
Fig. 27. Distribution of fields containing Triassic reservoirs in the East Shetland Basin and South Viking Graben areas of the Northern North Sea. The fields all lie within footwall closures adjacent to normal faults that were active during Late Jurassic rifting.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
37
Fig. 28. E-W trending structural cross-section through the Alwyn Field of the East Shetland Basin. The field originally produced oil and gas from reservoirs located within the Middle Jurassic, Brent Group and Triassic-Lower Jurassic Statfjord Formation. Drilling of the 3/10b-2 well led to the recognition that Triassic prospectivity existed and the subsequent drilling of wells N33, N34 and N35 proved up a major, deep gas condensate play, which is likely to extend the life of the Alwyn Field by twenty five years or more. Its discovery may lead to a wider reappraisal of Triassic prospectivity beneath other well-established fields in the East Shetland Basin. NAA = North Alwyn A Platform.
the other fields of the Brent Province (e.g. Alwyn North field; Harker et al., 2003; Fig. 28) in the Northern North Sea suggesting that there is a potential to discover and produce from deeper stratigraphic levels and thus, extend the life of some fields that are approaching the end of their original production life. Oil has also been produced Triassic Cormorant Formation reservoirs from more southerly areas of the Northern North Sea, particularly in and around the Beryl Embayment area in the South Viking Graben. Although production has been from the Beryl (Knutson & Munro 1991), Crawford (Yaliz 1990) and Linnhe fields to date, it will also be extracted from the Nevis field in the near future. Finally, it is worth noting that oil has been found in the Triassic, Otter Bank Sandstone in the Strathmore Discovery (Fig. 23), which straddles U K Blocks 204/30a and 205/26a in the West Shetlands (Herries et al. 1999), since it provides hope for additional Triassic prospectivity in this frontier area.
Jurassic
Late Triassic and Early Jurassic patterns of subsidence appear to have been more uniform than those that characterized the Permian and early Triassic suggesting that rifting gave way to a phase of post-rift thermal relaxation. Sedimentation in these post-rift sag basins became more and more marine dominated until flooding eventually occurred in early Jurassic times (as recorded by the Blue Lias). Thermal subsidence appears to have continued until Toarclan times when the North Sea region began to be influenced by a phase of uplift that was ultimately to lead to the development of the 'Mid Cimmerian Unconformity' (Fig. 7; Underhill & Partington 1993, 1994).
The Banks Group is the lithostratigraphic term used in the U K sector of the North Sea to describe a lower, Statfjord Formation containing the Triassic-Jurassic boundary and an
L o w e r Jurassic.
upper, Nansen Formation (Richards et al. 1993). Its introduction has updated and replaced previous lithostratigraphic divisions of Deegan & Scull (1977) and Vollset & Dor6 (1984) who referred to the same interval as the Statfjord Formation and subdivided it into a lower (Raude Member), a middle (Eiriksson Member) and an upper (Nansen Member). Reservoirs belonging to the Nansen and Stafjord Formations form important reservoir intervals within the Alwyn North (Inglis & Gerard 1991), Brent (Struijk & Green 1991), Bruce (Beckly et al. 1993) and Statfjord fields in the Northern North Sea (Fig. 29). Deposition of the Statfjord Formation occurred as climatic conditions were changing from semi-arid to humid, and as regional sea-levels were rising (Roe & Steel 1985). Wells from the Horda Platform and Tampen Spur in the Norwegian sector demonstrate that the Statfjord Formation records an episode of sediment progradation (Steel 1993). Full development of the Statfjord Formation is restricted to regions of that lie to the east of the Hutton-Ninian trend (Johnson & Stewart 1985), one of the few fault arrays that have a demonstrable influence on Early Jurassic deposition in the Northern North Sea. The Statfjord Formation consists of fine to coarse grained cross-bedded sandstones containing evidence for channel incision (Ryseth & Ramm 1996). Taken together with evidence from the finer grained intervals, including mottled mudstones, rootlets and thin or scattered coals, the depositional setting is interpreted to be one in which perennial braided streams cut across moderately- to poorly-drained low-lying interfluves (MacDonald & Halland 1993). Studies in the Northern North Sea indicate that the Nansen Formation has a wider distribution than the underlying Statfjord Formation and records progressive onlap onto the margins of the basin. The unit consists of light-coloured, fine to coarse grained well sorted pebbly quartzitic calcareous sandstones. It is a timetransgressive shallow-marine sand that records the retreat and local ravinement of the Statfjord alluvial system. The diachroneity of the Nansen Formation suggests that in part it is laterally equivalent to the Statfjord Formation (Johnson & Stewart 1985).
38
J.R. UNDERHILL preted to represent the onset of thermal doming (Underhill & Partington 1993, 1994). Of the four subdivisions of the Dunlin Group, significant oil production has only been achieved from shallowmarine sandstones belonging to the Cook Formation in some fields in the Norwegian Northern North Sea (e.g. Gullfaks, Oseberg, Statfjord and Snorre fields; Fig. 29). Lower Jurassic sediments have also been penetrated in exploration boreholes in western parts of the Moray Firth Rift Arm, where they form the prospective lower reservoir units in the Beatrice oilfield (Linsley et al. 1980; Stevens 1991; Stephen et al. 1993; Fig. 30). The siliciclastic sequence has recently been ascribed to the Dunrobin Bay Group which comprises the Golspie, Mains, Lady's Walk and Orrin formations and ranges in age from Hettangian to Early Toarcian. Some of the oil in the Beatrice Field has been produced from the Pliensbachian-Toarcian, progradational, shallow marine, Orrin Formation, a 45-60 in thick unit which records the progradation of a major deltaic system (Stephen et al. 1993). Lower Jurassic deposition in southern areas of Britain and adjacent regions was characterized by a distal marine, argillaceous sequence ascribed to the Lias or Altena Group. Hettangian to Pliensbachian organic-rich mudstones (e.g. the Posidonia Shale Member of Toarcian age in the Dutch Sector) characterized several geographically-restricted basins and form potential source rock horizons that have proven successful in the Weald, Wessex (Fig. 25) and Paris Basins (Fleet et al. 1987; Espitalie et al. 1987; Butler & Pullan 1990; Underhill & Stoneley 1998; Evans et al. 1998, Gluyas et al. 2003). Onshore, the Lias Group also contains one of the basin's main reservoir units, the Bridport Sandstone, a diachronous storm-dominated shallow marine sandstone, which has produced oil in the Wytch Farm and Wareham fields of the Wessex Basin (Fig. 25; Hogg et al. 1999). In Humbly Grove, a small oil field located on the NW flank of the Wessex Basin, some production has been achieved from the Rhaetic, Penarth Group (Trueman 2003).
Middle
Fig. 29. Distribution of fields containing Triassic-Early Jurassic Banks Group reservoirs in the East Shetland Basin and South Viking Graben. As with the Triassic fields, the Banks Group, StatI]ord Formation reservoirs of the Stafjord, Brent, Alwyn and Bruce fields all lie within footwall closures adjacent to normal faults that were active during late Jurassic rifting.
Subsequent Lower Jurassic sedimentation in the Northern North Sea was dominated by fine-grained clastic sediments, which are ascribed to the Hettangian-Toarcian, Dunlin Group (Marjanac 1995). The onset of its deposition is marked by a change from variably-cemented sandstones of the Nansen Formation to bioturbated and carbonaceous mudstones and siltstones (Marjanac & Steel 1997). The lowest unit, the Amundsen Formation, coarsens-up from gray mudstones to siltstones and fine-grained sandstones. The Burton Formation comprises a dominantly mudstone succession containing rare, millimeter-thick lenticular, parallel and ripplelaminated sandstones. It represents deposition in a low-energy shelf setting which, due to its relatively low level of bioturbation, may have experienced partially restricted circulation and was prone to sediment starvation and condensation. The Cook Formation is a laterally persistent sand-prone unit of Pliensbachian age, which is found encased in mudstones belonging to the Burton and Drake Formations (Steel 1993). The Cook Formation is overlain by a unit of sandy and calcareous grey marine mudstones that is ascribed to the Drake Formation. The 'Mid Cimmerian Unconformity' separates the Drake Formation from the Middle Jurassic, Brent Group (Underhill & Partington 1993, 1994). Where preserved, the upper parts of the Drake Formation show evidence for progradation and shallowing immediately beneath the unconformity which is inter-
Jurassic
Volumetrically, the Middle Jurassic Brent Group contains the most significant oil-bearing reservoirs in the UKCS (Spencer et al. 1996). It occurs in combined structural and stratigraphic traps consisting of variably-degraded, Late Jurassic tilted, extensional fault blocks (Figs 11 & 31) sealed by draping Cretaceous sediments of the Cromer Knoll and Chalk Groups (e.g. the Brent Field; Fig. 32; Underhil11998), The unit consists ofa prograding-retrograding delta that built out towards the north in response to thermal doming in the Central North Sea (Underhill & Partington 1993, 1994). The clastic wedge locally exceeds 500 rain thickness, and ranges from Aalenian to Early Bathonian in age (Graue et al. 1987; Helland-Hansen et al. 1992; Mitchener et al. 1992). Chronostratigraphic relationships show that it is partly time-equivalent with the Hugin and Sleipner Formations of the South Viking Graben (Partington et al. 1993a; Rattey & Hayward 1993; Underhill & Partington 1993, 1994). Although the stratigraphic subdivision of the Brent Group has proved too simplistic for field management purposes, it has classically been subdivided into five component lithostratigraphic units: the Broom, Rannoch, Etive, Ness and Tarbert Formations (Deegan & Scull 1977), each of which reflects specific depositional facies associations within the deltaic complex (Budding & Inglin 1981; Eynon 1981; Johnson & Stewart 1985). The basal sequence of the Brent Group is termed the Broom Formation in the UK and the Oseberg Formation in Norwegian waters. It comprises medium or coarse grained cross-stratified marine sandstones and rare pebbly sandstones that lie above an unconformity or correlative conformity. Their deposition is interpreted to be the result of single of multi-storey, progradational sandbodies that formed part of an amalgamated series of fan deltas shed transversely into the East Shetland Basin (Graue et al. 1987; Helland-Hansen et al. 1992; Steel 1993). The progradational part of the Brent Group is marked by deposition of the Rannoch, Etive and Ness formations. The Rannoch Formation consists of a coarsening-up, cleaning-up fine-grained,
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
39
Fig. 30. Representative seismic dip-line across the Beatrice Field in the Inner Moray Firth showing its classic combined structural (footwall trap) and stratigraphic play. The main reservoir units in Beatrice consist of Middle and Lower Jurassic clastic sediments. After Thomson & Underhill (1993). micaceous sandstones, u n d u l a t o r y lamination m i c a - p o o r alternations lapping laminae (Scott
d o m i n a t e d by horizontal to low-angle a n d (<15 ~ dip) characterized by mica-rich a n d and cut by steep-sided scours filled by on1992). Its sedimentary characteristics lead to
Fig. 31. Distribution of fields containing Middle Jurassic Brent and Fladen Group reservoirs in (a) the East Shetland Basin and (b) South Viking Graben areas. As with the other fields containing pre-rift reservoirs, the Banks Group, Statfjord Formation reservoirs of the Stafjord, Brent, Alwyn and Bruce fields all lie within footwall closures adjacent to normal faults that were active during Late Jurassic rifting.
the interpretation of the R a n n o c h F o r m a t i o n as being deposited in a middle shoreface e n v i r o n m e n t of the p r o g r a d a t i o n a l Brent G r o u p , which was affected by c o m b i n e d unidirectional and oscillatory flows in a high-energy, s t o r m - d o m i n a t e d shoreface environment.
40
J. R. UNDERHILL
Fig. 32. Schematic E-W trending cross-section across the Brent Field showing the structural style and stratigraphic character of the main reservoir units in the tilted fault block footwall closure. The structure is sealed by a combination of syn-rift Humber Group and post-rift Cromer Knoll Group and Chalk Group sediments. Modified after Struijk & Green (1991).
Two sedimentary sequences commonly characterize the Etive Formation. One consists of an upward-coarsening profile from the underlying middle shoreface, and is dominated by parallel and lowangle laminations interpreted to represent a prograding barrier beach. The second fines upward and is characterized by sharpbased, cross-bedded sandstones marked locally by mud rip-up clasts and muddy laminations. The second facies association is interpreted to represent the deposits of a barrier-beach system whose orientation was controlled by tidal inlet channels (Johnson & Stewart 1985). Overall, the Etive Formation is thought to represent a complex three-dimensional onshore topography that records the development of a microtidal, wave-dominated barrier island made up of nearshore bar and trough systems cut by tidal inlet channels, which pass up into a foreshore environment. The Ness Formation consists of a heterolithic sequence of interbedded sandstones, mudstones and coals interpreted to have been deposited in a delta-top setting containing a wide spectrum of subenvironments including lagoonal muds, distributory channels, levees mouth bars and lagoonal shoals. The Ness Formation is often subdivided into three component parts, a lower interbedded unit, the Mid Ness Shale and an upper sandstone-dominated unit. Overall, the Ness Formation is considered to record the last part of the main phase of northward progradation of the Brent delta and the onset of its retrogradation (Graue et al. 1987; Helland-Hansen et al. 1992; Mitchener et al. 1992; Partington et al. 1993a; Rattey & Hayward 1993). The units ascribed to the Tarbert Formation demonstrate a marked back-stepping (retrogradational) profile interpreted to result from a punctuated southerly-directed marine transgression of the former Brent delta (Mitchener et al. 1992; Underhill & Partington 1993). The transgressive pattern may also be followed eastward onto the Horda Platform and westwards onto the East Shetland Platform. Evidence from the Brent Province suggests that the Tarbert Formation is a stratigraphic unit which is distinct from the underlying Brent formations being separated from them by an unconformity. It also shows a quite different spatial distribution, being restricted to downflank areas of the tilted fault blocks and is interpreted to represent the early stages of footwall uplift and hangingwall subsidence associated with extensional movements of the tilt-block bounding faults (Underhill et al. 1997; Davies et al. 2000). The Brent Group provides the main reservoir in the tilted fault blocks which form the Alwyn North (Fig. 28; Inglis & Gerard 1991), Alwyn South, Brent (Fig. 32; Bowen 1981; Struijk & Green 1991; Taylor et al. 2003), Columba B, D, and E, Cormorant North (Demyttenaere et al. 1993; Bater 2003), Cormorant South (Taylor & Dietvorst 1991), Deveron (Williams 1991; Brown & Milne 2003), Don
(Morrison et al. 1991; Milne & Brown 2003), Dunbar (Ritchie 2003), Dunlin (Baumann & O'Cathain 1991), Dunlin SW, Egret, Eider (Wensrich et al. 1991), Ellon and Grant (Ritchie 2003), Heather (Penny 1991; Kay 2003), Hudson, Hutton (Haig 1991), Hutton N W (Johnes & Gauer 1991), Lyell, Murchison (Warrender 1991; Ashcroft & Ridgway 1996), Ness, Ninian (Van Vessem & Gan 1991), Osprey (Erickson & Van Panhuys 1991), Staffa (Gluyas & Underhill 2003), Statfjord (Gibbons et al. 2003), Strathspey (Maxwell et al. 2003), Tern (Van Panhuys-Sigler et al. 1991; Black et al. 1999) and Thistle (Williams & Milne 1991; Brown et al. 2003) fields in the U K sector (Fig. 31) and many others in the Norwegian sector. In recent years, advances in technology and improved seismic acquisition and processing has enabled production from the structurally complex, degraded fault block crests that had formed due to extensional collapse of footwall areas adjacent to Late Jurassic submarine fault scarps (McLeod & Underhill 1999). Production from the fault scarp degradation complexes has been achieved in Brent (Coutts et al. 1996), Ninian (Underhill et al. 1997) and Statfjord (Hesthammer et al. 1999). Oil production has also been achieved from other Middle Jurassic sedimentary reservoirs ascribed to the Fladen Group, which also occur within Late Jurassic tilted fault blocks. The Fladen Group itself consists of the following four formations: the Pentland, Brora Coal, Beatrice and Hugin Formations (Richards et al. 1993), the naming of which depends upon their geographical location. Recent biostratigraphic studies (primarily palynology and other forms ofmicropalaeontology) have led to a far better understanding of the temporal and spatial relationships between these various lithostratigraphic units and accurate correlations can now be made in many offshore areas (Partington et al. 1993a; Veldkamp et al. 1996; Jeremiah & Nicholson 1999) and extended to the onshore, non-marine equivalents of the Ravenscar Group in East Yorkshire (Fisher & Hancock 1985). Major coal-bearing fluvial sediments ascribed to the Pentland Formation characterize those areas of the South Viking Graben (including those previously ascribed to the Beryl Formation) and Central North Sea that lay behind the Brent delta. They have proven to have had petroleum potential and form subsidiary reservoirs in the Beryl Embayment (e.g. in the Beryl Field itself (Knutson & Munro 1991; Robertson 1993; Maxwell et al. 1999; Karasek et al. 2003) and the Bruce (Beckly et al. 1993), Buckland, Linnhe and Nevis fields) and in some of the Central North Sea fields (e.g. the Heron, Puffin and Shearwater fields; Fig. 33; e.g. Pooler & Amory 1999). The Hugin Formation is the lithostratigraphic term originally introduced by Vollset & Dore (1984) to describe a diachronous set
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
41
Fig. 33. Distribution of fields containing Middle Jurassic reservoirs in (a) the South Viking Graben and (b) Central Graben area. The fields all lie within footwall closures adjacent to normal faults that were active during Late Jurassic rifting. The fields lie within an area largely characterized by high pressure and high temperature (HP-HT) conditions. of marine sandstones and mudstones lying beneath marine mudstones of the Heather Formation and above the heterolithic continental clastics of the Sleipner or Pentland formations of the South Viking Graben (Cockings et al. 1992). In the Inner M o r a y Firth, the fluvio-deltaic sediments belonging to the Brora Coal Formation and shallow marine belonging to the Beatrice Formation sediments have proved to be time-equivalent to the Pentland Formation. They form important series of reservoir sandstones in the Beatrice oilfield (Fig. 30), where they are informally known as the A, B, C, D E, F and G sands (Linsley et al. 1980; Steven 1991) and represent the initial stages in Middle to Late Jurassic east-directed marine flooding of the Moray Firth (Stephen et al. 1993). Although having no reservoir potential whatsoever, an important component part of the Pentland Formation are volcanic rocks ascribed to the Rattray Volcanics Member and the Ron Volcanics Member (Richards et al. 1993). The Rattray Volcanics Member occurs in and around the North Sea triple junction area in Quadrants 15, 16, 21 and 22) and consists of undersaturated porphyritic, alkali olivine basaltic lavas and volcaniclastic sediments (Dixon et al. 1981; Fall et al. 1982; Latin et al. 1990a, b). Their occurrence provides
Fig. 34. Distribution of fields containing Middle Jurassic Great Oolite reservoirs in the Weald Basin of the Southern England. The fields either lie within footwall closures adjacent to normal faults that were active during Mesozoic extension or in inversion structures formed during Cenozoic contraction. The location of the cross-section used in Fig. 15 is highlighted.
important evidence in support of the thermal genesis of the North Sea Dome (Underhill & Partington 1993, 1994), the main control on Middle and Upper Jurassic reservoir distribution (Fig. 9). Although less well documented, prospective Middle Jurassic reservoirs are not restricted to the North Sea and production has occurred from several fields in Southern England. Indeed, in the Weald Basin of East Hampshire, Sussex, Surrey and parts of Kent, it is the Middle Jurassic, Great Oolite Formation that forms the main productive reservoir (Butler & Pullan 1990). The producing fields include the Albury, Bletchingley, Brockham, Goodworth, Herriard, Horndean, Humbly Grove, Palmer's Wood, Singleton, Stockbridge and Storrington fields (Fig. 34; Trueman 2003). Further to the west, in the Wessex Basin, production has occurred from the Cornbrash in Kimmeridge Bay (Butler 1998; Evans et al. 1998; Gluyas et al. 2003) and the Frome Clay in Wytch Farm.
U p p e r Jurassic. Rifting followed the thermal decay of the North Sea Dome and saw the creation of the trilete, Viking G r a b e n Central G r a b e n - M o r a y Firth rift system. Structures in each of the rift arms are consistent with an interpretation as extensional fault
42
J. R. UNDERHILL
blocks similar to those seen in other classic rift provinces. The fault system appears to have been the result of the growth, propagation and linkage of planar, normal faults throughout the rift interval (Underhill 1998; Dawers & Underhill 2000; McLeod et al. 2000 & 2002; Young et al. 2001; Fraser et al. 2002). Each fault block was characterized by pronounced footwall uplift and hangingwall subsidence leading to the development of numerous structural traps in areas like the East Shetland Basin on the western flank of the North Viking Graben (the so-called Brent Province). Uplift of the footwalls of the extensional faults led in many cases to pronounced erosion (as well as the fault scarp degradation; Underhill et al. 1997), and in some cases erosion has reached down to Triassic levels. The structural configuration of the Central Graben is made up of a number of intra-basinal highs (e.g. Forties-Montrose High), terraces (such as the Cod Terrace) and sub-basins (such as the Sogne Basin in Norwegian waters). In contrast to the other two rift arms, extension in the East Central Graben appears to have been more complex because of the influence of halokinesis. Movement on the basin-bounding faults led to rapid subsidence in the Eastern Trough of the Central Graben, which initiated differential flow of salt at depth. The effect was to initiate regional salt evacuation from the graben centre, which eventually led to the development of salt pillows and localized diapiric intrusions during the Cretaceous and Tertiary. Such salt pillows created petroleum-bearing structures in overlying Cretaceous Chalk and Tertiary reservoirs. In the Central North Sea, the presence of the underlying Zechstein Group evaporites also allowed shallow detachments to develop. The main effect was to control the structural wavelength and hence trap size of Jurassic fault blocks, which were more limited in width (4-10 km) in the Central Graben than in the Viking Graben. The consequence for oilfield size has been considerable with Central North Sea fields largely being one order of magnitude smaller (100-200 million barrels Stock Tank Oil Initially In Place (STOIIP) than their north-
ern counterparts, such as. Brent, Snorre, Ninian and Statfjord, which are all billion barrel STOIIP fields (Hodgson et al. 1992). The accelerated subsidence that resulted from Late Oxfordian and Kimmeridgian rifting heralded significant shoreline retreat and basin deepening in all three rift arms (Underhill & Partington 1993, 1994). However, transgression was not continuous but instead was characterized by a punctuated back-stepping (retrogradation) of highly bioturbated (Gowland 1996; Martin & Pollard 1996), shallow marine, shelfal and shoreline shorelines throughout the Oxfordian, Kimmeridgian and early Volgian (Partington et al. 1993a). Depending upon their location, these clastic sediments are ascribed to the Fulmar or Piper Formations, both of which are component parts of the Humber Group (Richards et al. 1993) and form some of the most important reservoirs in tilted fault blocks within each of the rift arms. In the Central Graben, the main Fulmar Formation reservoir is either normally pressured as in the Clyde Field (Stevens & Wallis 1991; Turner 1993) and the Fulmar Field itself (Johnson et al. 1986; Stockbridge & Gray 1991; Spaak et al. 1999; Kuhn et al. 2003; Fig. 35) or lie within the high temperature/high pressure (HP/HT) setting as with the Elgin, Franklin (Lasocki et al. 1999), Erskine (Coward 2003) and Shearwater Fields (Erratt 1993; Penge et al. 1993; Jeremiah & Nicholson 1999). Although notoriously more difficult to predict, the exact distribution of the Fulmar Formation sandstones along the edge of the Western Platform in the West Central Graben now appears to be closely related to halokinetic activity of Zechstein Group evaporites (Wakefield et al. 1993) and erosion of basin-margin and intra-basinal highs such as the Forties-Montrose Ridge. Salt withdrawal during the Triassic led to the development of thick packages of claystones in rim synclines termed 'Smith Bank pods'. Subsequent sedimentation above areas affected by salt diapirism was marked by coarse clastic deposition of the Triassic, Skagerrak Formation, which is interpreted to record the infill of topographic lows formed in response to ground-water dissolution of the salt pillows. This complex tectono-sedimentary behaviour left a legacy by also exercising a control on sediment drainage patterns during the Late Jurassic (Stewart et al. 1999). A relative sea-level rise during the Callovian to Early Kimmeridgian caused widespread flooding of the Western Platform, led to reworking of the older Skagerrak palaeovalleys and resulted in deposition of the Fulmar shallowmarine deposystem. The reservoir quality of the Fulmar Formation depends largely upon the original sedimentary facies distributions
13
15
14 Claymore
Higlande~r9
Piper Iona ~.,~Saltire
~qr.--Chanter
Petronella es ' ~ Scott Tarta i ~11 ~ Galley Hamish - -,a,~,Telford Glamis Ivanhoe t-'- Rob Roy '~ Renee D 9 Rubie
Phoenix
Ross'~ 19
i16
20
!21
22
~Ettrick t ~Buzzard
~St. Fergus 1 0 Oil Fields O Gas Condensate Fields Fig. 35. Distribution of fields containing Upper Jurassic Humber Group reservoirs in the Central Graben. Many of the fields lie within an area largely characterised by high pressure and high temperature (HP HT) conditions making them particularly difficult to explore for and produce.
0
km
40
Fig. 36. Distribution of fields containing Upper Jurassic Humber Group reservoirs in the Outer Moray Firth. The fields predominantly consist of shallow marine shelfal reservoirs located in closures on the upthrown (footwall) side of major syn-sedimentary extensional faults.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS (e.g. Johnson et al. 1986) and their relative effect on diagenesis (e.g. Gannet Field; Armstrong et al. 1987). An attractive subtle stratigraphic play has resulted with sandstones of the Fulmar Formation forming linear reservoir bodies that are laterally sealed by shales of the Smith Bank Formation and capped by the Kimmeridge Clay Formation, as exemplified by the Kittiwake (Glennie & Armstrong 1991), Durward and Dauntless Fields (e.g. Stewart et al. 1999; Fig. 35). The Piper Formation is the term assigned to the marine, sandstone-dominated sedimentary unit that lies between the Kimmeridge Clay Formation and Middle Jurassic continental sediments in the Outer Moray Firth Basin (Richards et al. 1993). The formation is typified by units in the Piper oilfield itself, a major extensional fault block located on the northern edge of the Witch Ground Graben (Williams et al. 1975; Maher 1981; Schmitt & Gordon 1991; Harker 1998). The Piper Formation is interpreted as a fluvial to wave-influenced shallow marine deltaic to shelfal depositional system (Boote & Gustav 1987; Harker et al. 1993). Although fraught with difficulty (see Hesketh & Underhill 2002 for discussion), recent advances in biostratigraphic control in the Outer Moray Firth Late Jurassic has afforded a greater level of correlation and the construction of accurate palaeogeographic and play fairway maps (Davies et al. 1996; Kadolsky et al. 1999). These studies help to demonstrate that each of the major sandstone bodies within the Piper Formation suggests that they represent individual progradational cycles that probably represent short-lived regressive pulses within an overall transgressive phase (e.g. in the Piper Field itself (Maher 1981; Schmitt & Gordon 1991; Harker 1998), Chanter (Schmitt 1991), Hamish, Ivanhoe, Rob Roy (Parker 1991; Currie, 1996; Harvey & Currie 2003), Scott (Guscott et al. 2003), Telford (Syms et al. 1999), and Renee fields located on the margins of the Witch Ground Graben (Fig. 36). Irrespective of exact geographical locality, the distal, muddy equivalents of the clastic sediments are ascribed to the Heather and Kimmeridge Clay Formations depending upon their age (Richards et al. 1993; Jeremiah & Nicholson 1999). The term Kimmeridge Clay Formation was imported from onshore exposures in South Dorset to describe organic-rich mudstones of Late Jurassic age in the North Sea Basin. Importantly, the stratigraphic unit consists not only of claystones but also contains several
43
reservoir sandstones that were deposited in submarine-apron fans, basin-floor fans or shallow marine shelves. In general, the claystone facies represent marine hemipelagic deposition in an environment in which bottom waters were commonly anoxic (Tyson et al. 1979; Tyson 1995; Cornford 1998), which favoured the accumulation and preservation of organic material. As a result, the Late Oxfordian to Ryazanian stratigraphic interval was an exceptional period of very widespread source-rock deposition in the Boreal Realm. In the North Sea and West Shetlands areas, the tectonic setting appears to have an influence on deposition of the Kimmeridge Clay Formation by promoting oxygen deficiency and by effecting a marked decrease in sediment accumulation rates in half-graben depocentres. In all but basin margin locations, where higher sedimentation rates generally resulted in clastic dilution of the mudstones, the Kimmeridge Clay has prolific source-rock potential and has been proven as the main source for hydrocarbon discoveries throughout the Central and Northern North Sea (Fig. 13; MacKenzie et al. 1987; Burley 1993) and West Shetlands (Bailey et al. 1987). Coarse clastic deposition characterized by eastward thinning and fining sedimentary wedges occurs along some of the margins of the main rift systems in the North Sea (Fig. 37). These units are ascribed to the Brae Formation. They resulted from the erosion of the rift flanks and led to the development of a series of marine slope apron breccias and conglomerates along the line the main basinbounding extensional faults (Stow et al. 1982) similar to analogues exposed in East Greenland (Surlyk 1978). The fans show important lateral facies variations and interfinger with the shale-prone Kimmeridge Clay Formation, which forms both the all-important lateral seal and source rock for hydrocarbon charge. They form particularly important reservoirs in the Brae fields of the South Viking Graben, namely in the East Brae (Branter 2003), Central Brae (Turner & Allen 1991; Fletcher 2003a), South Brae (Turner et al. 1987; Roberts 1991; Fletcher 2003b), North Brae (Stephenson 1991), Beinn (Brehm 2003), Larch, Birch (Hook et al. 2003), Elm, Pine and the T-Block fields (Toni, Thelma and Tiffany; Kerlogue et al. 1995; Gambaro et al. 2003; Fig. 38). Coeval deep-water turbidite deposition outboard of, and alongstrike from the coarse basin-margin fans has also led to the occurrence of other reservoir sandstones, ascribed to the Kimmeridge
Fig. 37. Schematic cross section constructed through the Upper Jurassic fanglomerate deposits that form the main reservoir facies within downthrown (hangingwall) traps along the western side of the South Viking Graben (e.g. in the Brae, Larch, Birch, Pine, Toni, Tiffany and Thelma fields etc.).
44
J. R. UNDERHILL the Norwegian sector of the Northern North Sea (Dahl & Solli 1993; Dawers et al. 1999) suggests that considerable stratigraphic trapping potential remains within the deep water sandstones ascribed to the Kimmeridgian Sandstone Member, which may yet provide fresh impetus for exploration for subtle traps in the North Sea Upper Jurassic succession. Important production also exists to the north of the Brent Province as demonstrated by the Magnus Field (Shepherd 1991), which remains the most northerly producing field in the UK sector of the North Sea. The field produces from Late Jurassic submarine fan sequences which, unlike the Northern North Sea fields, form an early syn-rift sequence lying within a tilted fault block formed during the latest Jurassic and early Cretaceous (De'ath & Schuyleman 1981; Partington et al. 1993b), when the locus of active extension had moved to the West Shetlands area (Rattey & Hayward 1993). Finally, it is worth noting that production also occurs in the Angus, Fife and Fergus Fields, which lies in an isolated area adjacent to the Mid North Sea in UK Quadrants 31 and 39 in the southernmost part of the UK Central North Sea (Hall 1992; Mackertich 1996; Currie et al. 1999; Shepherd et al. 2003). The main reservoir in these fields consists of shallow marine Volgian sandstones informally ascribed to the Angus or Fife Sandstones (Hall 1992; Mackertich 1996).
Cretaceous
Fig. 38. Distribution of fields containing Upper Jurassic Humber Group reservoirs in the South Viking Graben. The fields predominantly consist of coarse grained submarine turbiditic and slope-fan reservoirs located in closures on the downthrown (hangingwall) side of major syn-sedimentary extensional faults. Sandstone Member (Richards et al. 1993; Partington et al. 1993a, b), in the Miller (Rooksby 1991; Garland 1993) and Kingfisher (Spence & Krantz 2003) fields of the South Viking Graben (Fig. 29). Similarly, Volgian, deep-water turbidite submarine fan sandstones form the main reservoir for Upper Jurassic fields in the Outer Moray Firth (Turner et al. 1984) including Claymore (Harker et al. 1991), Saltire (Casey et al. 1993) and Tartan (Coward et al. 1991; Fig. 36). The recent successful appraisal of the Buzzard discovery in the Outer Moray Firth (UKCS Blocks 19/5, 19/10, 20/1 & 20/6) and in
Lower Cretaceous. The Lower Cretaceous is generally considered to represent the onset of thermal subsidence in the North Sea Basin. Despite the largely passive nature of faulting, the underfilled nature of the basin at the end of the Jurassic meant that fault scarps continued to play a role in controlling bathymetry and sediment supply through the denudation of submarine slopes. This effect is exemplified in the Outer Moray Firth where production has been achieved from early Valanginian to late Hauterivian clastic sequences that are encased within mudstones belonging to the Valhall Formation. These largely occur in the down-flank (hangingwall) areas (e.g. in the Claymore (Harker et al. 1991), Highlander (Whitehead & Pinhock 1991), Petronella (Waddams & Clark 1991), Saltire and Scapa (McGann et al. 1991; Harker & Chermak 1992;) fields of the Outer Moray Firth; Fig. 39). They predominantly consist of very coarse conglomerates and sandstones, ascribed to the Scapa Sandstone Member, that resulted from the continued degradation of fault-scarp remnants of the Late Jurassic rift episode (Harker et al. 1991; Whitehead & Pinnock 1991; Harker & Chermak 1992).
Fig. 39. Distribution of fields containing Lower Cretaceous Cromer Knoll Group reservoirs in the Outer Moray Firth. A schematic outline of the various Lower Cretaceous clastic play fairways is highlighted.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
45
In recent years the Lower Cretaceous has become an important reservoir target within the Outer Moray Firth where Late Barremian, Aptian and Early Albian turbiditic sandstones lie within a 130-km long and up to 10km-wide channelised system that is referred to as the Kopervik play fairway (Fig. 39; Jeremiah 2000; Law et al. 2000). To date, petroleum has been produced along the fairway from the Brittania Field (Jones et al. 1999; Hill & Palfrey 2003), which is characterized by pervaisive soft sedimentary deformation (Porter et al. 2000). Further developments are expected in the near future including the Blake, Cromarty, Goldeneye and Hannay Discoveries (Law et al. 2000); petroleum is also resident at this level beneath the Andrew Field. It is worth noting that reservoir sandstones are not restricted to the basin axis and massive high-density and channelized turbidite feeder systems that lie on the crest of the Halibut Horst, an intrabasinal high within the Outer Moray Firth have also given rise to production from the Wick Formation, in the Captain Field (Fig. 39; Rose 1999; Rose et al. 2000; Pinnock & Clitheroe 2003). Finally, although not a producing field, gas has also been found in the Lower Cretaceous sediments of the Victory Field, 50 km N W of the Shetland Islands (Fig. 30), where shallow marine sandstones and conglomerates directly overlie Precambrian (Lewisian) basement (Goodchild et al. 1999). Its discovery lends some optimism to the idea that additional discoveries may be made in the Lower Cretaceous of the Faroe-Shetland area.
Fig. 40. Distribution of fields containing Upper Cretaceous Chalk Group reservoirs in the Central Graben. The diagram shows that the UKCS Chalk Group discoveries are only a sub-set of a much larger play, which extends across several international boundaries
Fig. 41. Structural cross-section through the Banff Field in the central North Sea highlighting the control that evaporite diapirism had in creating the trap. Modified after Evans et al. (1999).
Upper Cretaceous. The Upper Cretaceous was a time when global climates appear to have experienced extreme hothouse conditions, which resulted in a lack of ice and a rise in eustatic sea-levels to reach their highest levels in the Phanerozoic (Fig. 17). Few areas remained above sea-level and there was little terrigenous supply into the sedimentary basins that lay in and around the UK. Instead,
46
J.R. UNDERHILL
deposition was largely dominated by carbonates of the Chalk Group. Only northern areas saw deposition of mudstones belonging to the Shetland Group. The Chalk Group play fairway is complex and hydrocarbon migration and trapping mechanisms remain poorly understood. To date, Chalk Group carbonates within one or more intervals within the Cenomanian Hudra, Hod and Tor Formations and the early Danian Ekofisk Formation form the reservoir sections in the Banff (Evans et al. 1999), Curlew, Fife, Flora (Hayward et al. 2003), Joanne, Kyle, Machar (Foster & Rattey 1993) and Pierce fields of the UKCS (Fig. 40). From their distribution, it has been suggested that prospectivity is largely restricted to those areas of early source maturation (Megson & Hardman 2001). Intriguingly, several of the fields have steeply-dipping oil-water contacts and a large element of stratigraphic trapping. It has long been known that the Cromer Knoll Group was affected by syn-sedimentary and post-depositional effects resulting from the mobility of buried evaporates belonging to the Zechstein Group. Down-slope translation of carbonate breccias and turbidites through slumping and gravity flows appears to have characterized some areas and led to the formation of primary reservoir potential in some of the Chalk Group fields (Hatton 1986). Importantly, the post-depositional doming and consequent fracturing of the Chalk Group carbonates (e.g. in the Banff Field; Fig. 41; Evans et al. 1999) has also led to the development of secondary, fracture porosity that has been exploited in many fields in the Central North Sea in UK, Norwegian and Danish waters. Finally, although not well documented, oil production has also been achieved from Chalk Group reservoirs above the Bruce Field in the Beryl Embayment of the Northern North Sea.
Palaeogene
The structural framework for the North Sea Cenozoic was largely inherited from the Late Jurassic rift configuration, which had produced the trilete rift system. Although post-rift, thermal subsidence led to the development of an elongate sedimentary basin (Fig. 42), the low sediment supply that characterized the Cretaceous meant that it remained underfilled (sediment-starved) until the Early Cenozoic. It was during Palaeogene thermal subsidence that the Kimmeridge Clay Formation is thought to have first reached maturity to cause the initial migration of oil from the deeper parts of the basin (e.g. Burley 1993). The combined effects of thermal uplift of the West Shetlands area and eustatic sea level fall led to the exhumation and erosion of large tracts of the Scottish mainland and adjacent areas. The sediment supplied through uplift and regression led to the progradation of major deltaic complexes (Parker 1975) and construction of deep-water channel systems within the Moray Firth basin and along the western margins of the Viking and Central Grabens (Stewart 1987; Bowman 1998). The Paleocene and Eocene lithostratigraphy of the resultant North Sea clastic succession is subdivided into three main component parts: the Montrose, Moray and Stronsay Groups (Knox & Holloway 1992), each of which include important hydrocarbonbearing reservoir intervals. The Montrose Group consists of the Maureen and Lista Formations, the latter of which includes the productive, Heimdal and Mey Sandstone Members (Dickinson et al. 2001). The Moray Group consists of the Dornoch, Sele and Balder Formations. In the Central North Sea, the Sele Formation contains
Fig. 42. Distribution of fields and the main reservoir play fairway containing Palaeocene clastic sediments in the North Sea. The occurrence of the submarine fan sandstones was largely controlled by the effects of easterly sediment dispersal resulting from uplift, tilting and exhumation of the British Isles, which is thought to have resulted due to the initiation of the proto-Iceland hotspot.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
47
Fig. 43. Diagram depicting the role that sandstone channel distribution had in controlling the extent of exploration success within the Palaeocene of the Central North Sea. The recognition that the channel complexes were of finite width was fundamental in the discovery and exploitation of many fields in the area and was especially important in the development of the Nelson Field. Modified after Wyatt (1992).
the Cromarty and Forties Sandstone Members, the latter of which contains particularly significant amounts of oil. The Stronsay Group consists of the Mousa and Horda Formations, the latter of which contains the petroleum-bearing Tay, Grid and Frigg Sandstone Members. After the Brent Group, the Forties Formation forms the next most important oil-producing reservoir in the North Sea. The unit consists of the turbiditic sandstones that were derived from the uplifted Scottish Highlands ahead of the deltaic sediments that prograded along the Moray Firth (Parker 1975; Fig. 42). The sandstones primarily occur in a series of linear channelized facies belts
that are incased in fine-grained mudstones. Subsequent mobility of evaporates (including the formation of spectacular diapiric intrusions) and the compactional drape above the underlying Jurassic rift structure or the sandstones themselves has led to the formation of both domal structures and large, low-relief closures through which the channel play fairways pass (Fig. 43). Before the advent of 3D seismic data, drilling of crestal areas often led to disappointing well results (e.g. Gulf's unsuccessful well above Nelson). However, with the widespread use of seismic attribute mapping, individual channel complexes can now be mapped with confidence and exploited (Fig. 43; e.g. Wyatt et al. 1992).
48
J.R. UNDERHILL
Fig. 44. Diagram showing the various Paleogene play concepts in the Central North Sea Basin. Modified after Ahmadi et al. (2002). To date, production has occurred in the Andrew (Jolley 2003), Arbroath (Crawford et al. 1991), Arkwright (Kantorowicz et al. 1999; Hogg 2003), Balmoral (Tonkin & Fraser 1991; Gambero & Currie 2003), Banff (Evans et al. 1999, 2003), Bladon, Blair, Blenheim (Dickinson et al. 2001), Brae West, Crawford, Curlew (Eneyok et al. 2003), Cyrus (Mound et al. 1991; Jolley op. cit.), Donan, Everest (O'Connor & Walker 1993), Fleming, Drake and Hawkins (Armada Fields; Stuart 2003) Forties (Wills 1991) and Brimmond
(Carman & Young 1981; Carter & Heale 2003), Gannet B, C and D (Armstrong et al. 1987), Glamis (Fraser & Tonkin 1991), Joanne, Lomond, MacCulloch (Gunn et al. 2003), Machar (Foster & Rattey 1993), Maureen (Cutts 1991; Chandler & Dickson 2003a), Moira (Chandler & Dickson 2003b), Monan, Montrose (Crawford et al. 1991 : Hogg op. cir.), Mungo, Nelson (Wyatt et al. 1992; Kunka et al. 2003), Orion, Pierce (Birch & Haynes 2003) and Sedgewick fields (Fig. 42), which occur in a variety of play types (Fig. 44).
Fig. 45. Map showing the main structural elements and petroleum occurrence in the Faroe-Shetlands Basin, west of Britain.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
49
Fig. 46. Cross-section across the Faroe-Shetland Basin showing the Mesozoic rift structure and the easterly up-dip pinch out of the prospective, Paleocene (post-rift) clastic succession that forms the main reservoir in the Schiehallion and Foinaven Fields and the numerous other discoveries of the West Shetland petroleum province. The Palaeogene stratigraphy of the West Shetlands area is very similar to that of the North Sea (Ebdon et al. 1995; Mudge & Bujak 2001), reflecting the similarity in tectonic, climatic and eustatic controls. It consists of two main units: the Faroe, Moray and Stronsay Groups. Whilst the Faroe Group is subdivided into the Vaila and Lamba Formations, the Moray Group is separated into the Flett and Balder Formations. The main reservoirs for the Foinaven (Cooper et al. 1999; Carruth 2003) and Schiehallion (Leach et al. 1999; Fig. 45) oilfields occur within the Vaila Formation within sandstones that are equivalent to those of the Andrew Member that lies at the base of the Lista Formation in the North Sea (Cooper et al. 1999; Leach et al. 1999). They primarily consist of channelized siliciclastic turbidite sandstone reservoirs formed in a submarine slope setting (Stewart 1987; Cooper et al. 1999; Jowitt et al. 1999; Lamers & Carmichael 1999; Leach et al. 1999) which show up-dip pinch-out on the eastern flank of the basin (Fig. 46). By the end of Paleocene times, sediment supply through fan aggradation had caused water depths within the basin to become much more shallow. As a result, deltaic sediments were able to build out much further into the basin. Local incision of the prograding deltas has led to the local development of palaeogeomorphic traps (e.g. the Bressay Discovery; Underhill 2001). Finally, oil production has also been achieved from Palaeocene reservoirs that either lie within the South Viking Graben (e.g. Crawford field; Yaliz 1991) or on the platform areas that lie on its western flank (e.g. West Brae; Wright 2003).
Eocene. The early Eocene was marked by rapid and widespread marine transgression of the tuffaceous Balder Formation, which punctuated the otherwise shallowing-upward cycle of Palaeogene sedimentation. Its deposition was coincident with the first magnaetic anomalies within the North Atlantic Ocean suggesting a causal link with the onset of sea-floor spreading West of Britain. Despite the transgressive event, deltas continued to build-out into the North Sea Basin and fed deep-marine clastics into deeper parts of the basin, albeit on a smaller scale than before. The most notable examples of the resultant deep-water submarine fan turbidites are the Tay Sandstone Member and the Frigg Sandstone Member. The Tay Sandstone Member is the main productive reservoir horizon in the Gannet A, B and D (Armstrong et al. 1987), Guillemot A, D and West (Banner et al. 1992) fields in the Central North Sea (Fig. 47). The Frigg Sandstone Member forms the reservoir in the Frigg Field itself (Brewster 1991) and the Nuggets array to the north in UKCS Quadrant 3 (Fig. 48). Finally, oil has also been produced from subtle soft sedimentary deformation features that
primarily consist of sandstone dyke and sill injection complexes in submarine fan sandstones belonging to the Eocene Frigg Sandstone member such as in the Alba (Newton & Flanagan 1993), Gryphon (Newman et al. 1993) and Harding (Beckly et al. 2003) fields. Conclusions Throughout the Phanerozoic, fundamental changes in tectonic, climatic and eustatic regimes combined to produce structural, sedimentoiogical and stratigraphic conditions that have proved
Fig. 47. Distribution of fields containing Eocene clastic, submarine fan reservoirs in the Central Graben.
50
J . R . UNDERHILL of their staff, Brian Forrester, to devise and draft several of the diagrams produced in this chapter and those used as Chapter Frontispieces throughout the Memoir. Gerard White is thanked for drafting the others. Finally, I would like to acknowledge all the members of the oil industry from senior managers to technical experts for both their release of data to me and their enthusiastic support of research studies in Edinburgh which have culminated in this paper.
References
Fig. 48. Distribution of fields containing Eocene reservoirs in the Viking Graben. The diagram highlights the interpreted limits to the main submarine fan clastic play fairways in the area. extremely favourable for the petroleum p r o d u c t i o n from sedimentary basins of the U n i t e d K i n g d o m . So m u c h so that just thirty-five years after the first offshore exploratory well was drilled, the U K is n o w self-sufficient in p e t r o l e u m p r o d u c t i o n with a daily production of a r o u n d 4.3 million barrels of oil equivalent occurring f r o m its 239 offshore and onshore fields in 2001. Whilst 136 of these fields are primarily oil producers, a further 87 p r o d u c e dry gas and the other 16 produce condensate. The c o m b i n a t i o n of advances in seismic acquisition, processing a n d interpretation with the relatively recent widespread use of 3D seismic data have enabled new, robust structural interpretations to be m a d e and the m a i n tectonic controls on petroleum prospectivity in the various basins to be deduced. F u r t h e r integration of i m p r o v e d biostratigraphic correlations and a better u n d e r s t a n d i n g of the sedim e n t o l o g y of key reservoir horizons o b t a i n e d t h r o u g h the analysis of electrical well logs and cores available from exploration, appraisal a n d p r o d u c t i o n borehole data provides the new f r a m e w o r k in which to u n d e r s t a n d the U K ' s petroleum system. As a result, it is n o w possible to accurately synthesize a n d characterize the main controls on the prospective p e t r o l e u m play fairways that occur in both onshore and offshore areas of the U n i t e d K i n g d o m ' s continental shelf. This review has benefitted from discussion with Jon Gluyas (Acorn Oil & Gas), who conceived, devised and steered this Memoir into production. Diana Swan and Sarah Gibbs of the Geological Society Publishing House and Richard Willis of Swales & Willis are thanked for their trouble help and patience in seeing this chapter through to completion. The management of Wood MacKenzie's Edinburgh Office are thanked for allowing a member
AHMADI, Z., SAWYERS, M., KENYON-ROBERTS, S., STANWORTH, B., KUGLER, K., KRISTENSEN,J. & FUGELLI, E. 2002. Paleocene. In: EVANS,D., GRAHAM, C., ARMOUR, A. & BATHURST, B. (eds and co-ordinators). The Millennium Atlas: Petroleum Geology of the Central and North Sea. Geological Society, London, 235-259. ALBERTS, M. A. & UNDERHILL,J. R. 1991. The effect of Tertiary structuration on Permian gas prospectivity, Cleaver Bank area, southern North Sea, UK. In: SPENCER, A. M. (ed.) Generation, Accumulation and Production of Europe's Hydrocarbons. European Association of Petroleum Geoscientists, Memoirs, 1, 161-173. ALLEN, P. A. & MARSHALL, J. E. A. 1981. Depositional enviromnents and palynology of the Devonian South-East Shetland Basin. Scottish Journal of Geology, 17, 257-273. AMIRI-GARROUSSI, K. & TAYLOR, J. C. M. 1987. Complex diagenesis in Zechstein dolomites of the Ettrick Oil Field. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 577-589. ARMSTRONG, L. A., TEN HAVE, A. & JOHNSON, H. D. 1987. The geology of the Gannet Fields, Central North Sea, UK Sector. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 533 548. ASHCROFT, W. A. & RIDGWAY,M. S. 1996. Early discordant diagenesis in the Brent Group, Murchison Field, UK North Sea, detected in high values of seismic-derived acoustic impedance. Petroleum Geoscience, 2, 75-81. BADLEY, M. E., PRICE, J. D. & BACKSHALL,L. C. 1989. Inversion, reactivated faults and related structures: seismic examples from the southern North Sea. In: COOPER, M. A. & WILLIAMS, G. D. (eds) Inversion Tectonics. Geological Society, London, Special Publications, 44, 201-219. BADLEY, M. E., PRICE, J. D., RAMBECH DAHL, C. & AGDESTEIN, T. 1988. The structural evolution of the northern Viking Graben and its bearing upon extensional modes of basin formation. Journal of the Geological Society, 145, 455-472. BAILEY, N. J. L., WALKO, P. & SAUER, M. J. 1987. Geochemistry and source rock potential of the west of Shetlands. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 711-721. BAILEY, R. J. 2003. The West Firsby Oilfield, Development Licence 003, Lincolnshire. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 921-926. BAILEY, R. J. & CLOVER, J. E. 2003. The Windermere Gas Field, Blocks 49/9b, 49/4a, UK Southern North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 893-901. BANNER, J. A., CHATELLIER, J.-Y., FEURER, J. R. & NEUHAUS, D. 1992. Guillemot D: a successful appraisal through alternative interpretation. In: HARDMAN, R. F. P. (ed.) Exploration Britain - Geological insights jor the next decade. Geological Society, London, Special Publications, 67, 129-149. BARRELL, J. 1916. The dominantly fluvial origin under seasonal rainfall of the Old Red Sandstone. Bulletin of the Geological Soc&ty of America, 27, 345-386. BASTiN, J. C., BOYCOTT-BROWN, T., SIMS, A. & WOODHOUSE, R. 2003. The South Morecambe Gas Field, Blocks 110/2a, 110/3a, l10/7a and 110/ 8a, East Irish Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 107-118. BATER, L. 2003. The North Cormorant Field, Block 211/21a, UK North Sea. In: GLUYAS,J. G. & HICHENS,H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 315-325. BAUMANN, A. & O'CATHAIN, B. 1991. The Dunlin Field, Blocks 211/23a, 211/24a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 95-102.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS BEACH, A. 1984. Structural evolution of the Witch Ground Graben. Journal of the Geological Society, 141, 621-628. BECKLY, A., DODD, C. & LOS, A. 1993. The Bruce Field. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1453-1464. BECKLY, A. J., HASH, T., POLLARD, R., BRUCE, C., FREEMAN, P. & PAGE, G. 2003. The Harding Field (Block 9/23b). In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 283-290. BESLY, B. 1998. Carboniferous. In: GLENNm, K. W. (ed.) Petroleum Geology of the North Sea." Basic Concepts and Recent Advances. Blackwell Science, Oxford, 104-136. BESLY, B., BURLEY, S. D. & TURNER, P. 1993. The late Carboniferous 'Barren Red Bed' play of the Silver Pit area, Southern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 727-740. BIFANI, R., GEORGE, G. T. & LEVER, A. 1987. Geological and reservoir characteristics of the Rotliegend sandstones in the Argyll field. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 509-522. BIRCH, P. & HAYNES, J. 2003. The Pierce Field, Blocks 23/22a, 23/27, UK North Sea, UKCS: Altitude with Attitude. In: GLUYAS,J. a . & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 647-659. BLACK, R. C., POLLEN, H. J., ROBERTS, M. J. & RODDY, S. E. 1999. Tern Field development: a marriage of new technologies for business benefit. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1063-1075. BOOTE, D. R. D. & GUSTAV, S. H. 1987. Evolving depositional systems within an active rift, Witch Ground Graben, North Sea. In: BROOKS,J. & GLENNIE,K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 819-833. BOWEN, J. M. 1975. The Brent Oil Field. In: WOODLAND,A. W. (ed.) Petroleum and The Continental Shelf of Northwest Europe. Applied Science Publishers, London, 353-360. BOWMAN, M. 1998. Cenozoic. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea: Basic Concepts and Recent Advances. Blackwell Science, Oxford, 350-375. BRANTER, S. R. F. 2003. The East Brae Field, Blocks 16/03a, 16/03b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 191-197. BREHM, J. A. 2003. The North Brae and Beinn Fields, Block 16/7a, U K North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 199-209. BRENNAND, T. P. & VAN VEEN, F. R. 1975. The Auk field. In: WOODLAND, A. W. (ed.) Petroleum and The Continental Shelf of Northwest Europe. Applied Science Publishers, London, 275-285. BREWSTER,J. t 991. The Frigg Field, Block 10/1, U K North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 117-126. BROWN, A. M. & MILNE, A. D. 2003. The Deveron Field, Block 211/18a, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 251-255. BROWN, A. M., MILNE, A. D. & KAY, A. 2003. The Thistle Field, Blocks 211/18a, 211/19a, UK North Sea. In: GLUYAS, J. G. & HICHENS,H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 383-392. BRUCE, D. R. S. & REBORA, P. 2003. The Waveney Field, Block 48/17c, UK Southern North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 881-891. BUDDING, M. C. & INGLIN, H. F. 1981. A reservoir geological model of the Brent Sands in Southern Cormorant. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Cont#wntal Shelf of North- West Europe. Heyden, London, 326-334. BURLEY, S. D. 1993. Models of burial diagenesis for deep exploration in Jurassic fault traps of the Central and Northern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1353-1375.
51
BUTLER, M. 1998. The Geological History of the Wessex Basin- A review of new information from oil exploration. In: UNDERHILL, J. R. (ed.) Development and Evolution of the Wessex Basin. Geological Society, London, Special Publications, 133, 67-86. BUTLER, M. & PULLAN, C. P. 1990. Tertiary structures and hydrocarbon entrapment in the Weald basin of Southern England. In: HARDMAN, R. F. P. & BROOKS,J. (eds) Tectonic Events Responsible for Britain ~ Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391. CARMAN, G. J. & YOUNG, R. 1981. Reservoir geology of the Forties oilfield. In: ILLING, L. V. & HOBSON, G. D. (eds), Petroleum Geology of the Continental Shelf of Northwest Europe. Heyden & Son, Chichester, 371-379. CARRUTH, A. G. 2003. Foinaven Field, Blocks 204/19 and 204/24a, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 121-130. CARTER, A. & HEALE, J. 2003. The Forties and Brimmond Field, Blocks 21/10, 22/6a, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 557-561. CASEY, B. J., ROMANI, R. S. & SCHMITT, R. H. 1993. Appraisal geology of the Saltire Field, Witch Ground Graben, North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 507-518. CHANDLER,P. M. & DICKSON, B. 2003a. The Maureen Field, Block 16/29a, UK Central North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 587-601. CHANDLER, P. M. & DICKSON, B. 2003b. The Moira Field, Block 16/2%, UK Central North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 603 609. CHRISTIE, P. A. & SCLATER,J. G. 1980. An extensional origin of the Buchan and Witchground Graben in the North Sea. Nature, 283, 729-732. CLIFT, P. D., TURNER, J. & ODP LEG 152 SCIENTIFIC PARTY. 1995. Dynamic support by the Iceland Plume and its effect on the subsidence of the northern Atlantic margins. Journal of the Geological Society, 152, 935-941. COCKINGS, J. H., KESSLER,L. G., MAZZA, T. A. & RILEY, L. A. 1992. Bathonian to mid-Oxfordian sequence stratigraphy of the south Viking Graben, North Sea. In: HARDMAN, R. F. P. (ed.) Exploration Britain." Geological Insights for the Next Decade. Geological Society, London, Special Publications, 67, 65-105. COLTER, V. S. & HARVARD, D. J. 1981. The Wytch Farm Oil Field, Dorset. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of North- West Europe. Heyden, London, 494-503. CONEY, D., FYFE, T. B., RETAIL, P. & SMITH, P. J. 1993. Clair appraisal: the benefits of a co-operative approach, ln: PARKER, J. R. (ed.) Petroleum Geology of North-West Europe." Proceedings of the 4th Conference. Geological Society, London, 1409-1420. CONWAY, A. M. & VALVATNE,C. 2003a. The Boulton Field, Block 44/21a, UK North Sea. In: GLUYAS,J. G. & H1CHENS,H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 671-680. CONWAY, A. M. & VALVATNE,C. 2003b. The Murdoch Gas Field, Block 44/ 22a, UK Southern North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 789-798. COOKE-YARBOROUGH, P. 1991. The Hewett Field, Blocks 48/28-29-30, 52/4a-5a, UK North Sea. In: ARBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 433-442. COOKE-YARBOROUGH, P. & SMITH, E. 2003. The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields. In: GL~YAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 731-739. COOPER, M. M., EVANS, A. C., LYNCH, D. J., NEVILLE, G. & NEWLEY, T. 1999. The Foinaven Field: managing reservoir development uncertainty prior to start-up. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 675-682.
52
J. R. U N D E R H I L L
CORFIELD, S. M., GAWTHORPE, R. L., GAGE, M., FRASER, A. J. & BESLY, B. M. 1996. Inversion tectonics of the Variscan foreland of the British Isles. Journal oj'the Geological Society,, 153, 17 32. CORNFORD, C. 1998. Source rocks and hydrocarbons of the North Sea. In: GLENN1E, K. W. (ed.) Petroleum Geology' of the North Sea." Basic concepts and recent advances. Blackwell Science, Oxford, 376-462. COURTIER, J. & RICHES, H. 2003. The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, U K North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas"Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 861 870. COUTTS, S. D., LARSSON, S. Y. & ROSMAN, R. 1996. Development of the slumped crestal area of the Brent Reservoir, Brent Field: an integrated approach. Petroleum Geoscience, 2, 219-229. COWAN, a . 1996. The development of the North Morecambe Gas Field, East Irish Sea Basin, UK. Petroleum Geoscience, 2, 43 52. COWAN, a . & BOYCOTT-BROWN, T. 2003. The North Morecambe Field, Block 110/2a, East irish Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 97-105. COWARD, R. N. 2003. The Erksine Field, Block 23/26, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 523-536. COWARD, R. N., CLARK, N. M. & PINNOCK, S. J. 1991. The Tartan Field, Block 15/16, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 377-384. CRAWFORD, R., LITTLEFAIR, R. W. & AFFLECH, L. G. 1991. The Arbroath and Montrose Fields, Blocks, 211/7a, 211/12a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 211 217. CUMMING, A. D. & WYNDHAM, C. L. 1975. The geology and development of the Hewett gas field. In: WOODLAND, A. W. (ed.) Petroh, um and The Continental She[/" oJ' Northwest Europe. Applied Science Publishers, London, 313 325. CURRIE, S. 1996. The development of the Ivanhoe, Rob Roy and Hamish Fields, Block 15/21A, UK North Sea. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERT1CH, D. S. (eds) Geology of the Humber Group." Central Grahen and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 329-341. CURRIE, S., GOWLAND, S., TAYLOR, A. & WOODWARD, M. 1999. The reservoir development of the Fife Field. hz: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroh, um Geology ~] Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1135 1146. CUTTS, P. L. 1991. The Maureen Field, Block 16/29a, UK North Sea. hi: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas FieMs, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 347 352. DAHL, N. & SOLLL T. 1993. The structural evolution of the Snorre Field and surrounding areas. In: PARKER, J. R. (ed.) Petroleum Geology oJ'Northwest Europe." Proceedings' of the 4th Confierence. Geological Society, London, 1157 1166. DAWES, R. J., STEPHEN, K. S. & UNDERHILL, J. R. 1996. A re-evaluation of the Middle and Upper Jurassic Stratigraphy and Flooding History of the Moray Firth Rift System, North Sea. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERTICH, D. S. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 81 108. DAVIES, R. J., TURNER, J. & UNDERH1LL, J. R. 2001. Sequential dip-slip movement during rifting: a new model for the evolution of the Jurassic trilete North sea rift system. Petroleum Geoscience, 7, 371-388. DAVIES, S. J., DAWERS, N. H., MCLEOD, A. E. & UNDERHILL, J. R. 2000. The structural and sedimentological evolution of early syn-rift successions: the Middle Jurassic tarbert Formation, North Sea. Basin Research, 12, 343-365. DAWERS, N. & UNDERHILL, J. R. 2000. The role of fault interaction and linkage in controlling syn-rift stratigraphic sequences: Statfjord East area, Northern North Sea. American Association of Petroleum Geologists, Bulletin, 84, 45-64. DAWERS, N. H., BERGE, A. M., HAGER, K.-O., PUIGDEFABREGAS, C. & UNDERmLL, J. R. 1999. Controls on late Jurassic, subtle sand distribution in the Tampen Spur area, Northern North Sea. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 827-838.
DE'ATH, N. G. & SCHUYLEMAN, S. F. 1981. The geology of the Magnus Oilfield. In: ILHNG, L. V. & HOBSON, G. P. (eds) Petroleum Geology of the Con tinen tal Shelf of North- West Europe. Heyden, London, 342-351. DEEGAN, C. E. & SCULL, B. J. 1977. A standard lithostratigraphic nomenclature for the Central and Northern North Sea. Institute of Geological Sciences Report 77/25 (Bulletin of the Norwegian Petroleum Directorate, No. 1). DEMYTTENAERE, R. R. A., SLUIJK, A. H. & BENTLEY, M. R. 1993. A fundamental reappraisal of the structure of the Cormorant Field and its impact on field development strategy. In: PARKER, J. R. (ed.) Petroleum Geology oJ'North-West Europe." Proceedings' oJ'the 4th Conference. Geological Society, London, 1151-1157. DICKINSON, B., WATERHOUSE, M., GOODALL, J. & HOLMES, N. 2001. Blenheim Field: the appraisal of a small oil field with a horizontal well. Petroleum Geoscience, 7, 81-95. DIXON, J. E., FITTON, J. G. & FROST, R. T. C. 1981. The tectonic significance of post-Carboniferous igneous activity in the North Sea Basin. In: ILLING, L. V. & HOBSON, G. D. (eds)Petroleum Geology oJ'the Continental Shelf of North- West Europe. Heyden, London, 121-137. DOWNIE, R. 1998. Devonian. In: GLENNJE, K. W. (ed.) Petroleum Geology of the North Sea." Basic Concepts and Recent Advances. Blackwell Science, Oxford, 85 103. DUINDAM, P. & VAN HOORN, B. 1987. Structural evolution of the West Shetland continental margin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology ol~ North-West Europe. Graham & Trotman, London, 765-773. DUNCAN, A. D. & HAMILTON, R. F. M. 1988. Palaeo-linmology and organic geochemistry of the Middle Devonian in the Orcadian Basin. In: FLEET, A. J., KELTS, K. & TALBOT, M. R. (eds) Lacustrine Petroleum Source Rocks. Geological Society, London, Special Publications, 40, 173-202. EARLE, M. M., JANKOWSK[, E. J. & VANN, I. R. 1989. Structural and stratigraphic evolution of the Faeroe Shetland Channel and Northern Rockall Trough. In: TANKARD, A. J. & BALKW[LL, H. R. (eds) Extensional Tectonics and Stratigraphy of the North Atlantic Margins. American Association of Petroleum Geologists, Memoirs, 46, 461 469. EBDON, C. C., GRANGER, P. J., JOHNSON, H. D. & EVANS, A. M. 1995. Early Tertiary evolution and sequence stratigraphy of the Faeroe-Shetland Basin: implications for hydrocarbon prospectivity, hi: SCRUTTON,R. A., STOKER, M. S., SHIMMIELD, G. B. & TUDHOPE, A. W. (eds) The Tectonics, Sedimentation and Palaeoceanography of the North Atlantic Region. Geological Society, London, Special Publications, 90, 51-69. EDWARDS, C. W. 1991. The Buchan Field, Blocks 20/5a, 21/la, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields', 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 253-260. ENEYOK, G., BUSS1NK,P. & MAAN, A. 2003. The Curlew Field, Block 29/7, UK North Sea. In: GLtJYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas' Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 509 522. ERICKSON, J. W. & VAN PANH{JYS, C. D. 1991. The Osprey Field, Blocks, 211/18a, 211/23a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas' Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 183-190. ERRATT, D. 1993. Relationships between basement faulting, salt withdrawal and Late Jurassic rifting, UK Central Graben. hi: PARKER, J. R. (ed.) Petroleum Geology (~1'"Northwes't Europe." Proceedings' ()f the 4th ConJerence. Geological Society, London, 1211-1219. ESPITALtE, J. 1987. Organic Geochemistry of the Paris Basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 71-86. EVANS, J., JENKINS, D. & GLUYAS, J. 1998. The Kimmeridge Bay oilfield: an enigma demystified. In: UNDERHILL, J. R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publications, 133, 407-413. EVANS, N., RORISON,P. & SYKES, G. 1999. BanffField, UK Central Graben evaluation of a steeply dipping, fractured chalk reservoir. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 975-992. EVANS, N., MACLEOD, J. A., MACMILLAN, N., RORISON, P. & SALVADOR,P. 2003. The BanffField, Blocks 22/27a, 29/2a, U K North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 497-507.
TECTONIC AND STRATIGRAPHIC F R A M E W O R K OF THE UNITED KINGDOM'S OIL AND GAS FIELDS EYNON, G. 1981. Basin development and sedimentation in the Middle Jurassic of the Northern North Sea. In: ILL|NG,L. V. & HOI~SON, G. D. (eds) Petroleum Geology of the Continental She[f of North-West Europe. Heyden, London 196-204. FALL, H. G., GIBB, F. G. F. & KANARIS-SOTIRIOU, R. 1982. Jurassic volcanic rocks of the northern North Sea. Journal o['the Geological Society, 139, 277-292. FARMER, R. T. & HILLIER, A. P. 1991a. The Barque Field, Blocks, 48/13a, 48/14, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 395-400. FARMER, R. T. & HILLIER, A. P. 1991b. The Clipper Field, Blocks, 48/19a, 48/19c, UK North Sea. ln: ABBOTTS,1. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 417-424. FISHER, M. J. & HANCOCK, N. J. 1985. The Scalby Formation (M. Jurassic, Ravenscar Group) of Yorkshire: reassessment of age and depositional environment. Proceedings of the Yorkshire Geological Society, 45, 293-298. FLEET, A. J., CLAYTON, C. J., JENKYNS, H. C. & PARKINSON, D. N. 1987. Liassic source rock deposition in western Europe. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 59-70. FLETCHER, K. J. 2003a. The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 183 190. FLETCHER, K. J. 2003b. The South Brae Field, Blocks 16/07a, 16/07b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 211-221. FOSTER, P. T. & RATTEY, P. R. 1993. The evolution of a fractured chalk reservoir: Machar Oilfield, UK North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1445-1452. FRASER, A. J. & GAWTHORPE, R. L. 1990. Tectono-stratigraphic development and hydrocarbon habitat of the Carboniferous in northern England. In: HARDMAN, R. P. F. & BROOKS, J. (eds) Tectonic Events Responsible ,['or Britain's' Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86. FRASER, A. R. & TONKIN, P. C. 1991. The Glamis Field, Block 16/21a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingclom Oil and Gas Fields; 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 317-322. FRASER, S. I., ROBINSON, A. M., JOHNSON, H. D., UNDERHILL, J. R., KADOLSKY, D. G. A., CONNELL, R., JOHANNESSEN, P. & RAVNAS, R. 2002. Upper Jurassic. In: EVANS, D., GRAHAM, C., ARMOUR, A. & BATHURST, P. (eds & co-ordinators) The Millennium Atlas: Petroleum Geology of the Central and Northern North Sea. Geological Society, London, 157-189. GAMBARO, M. & CURRIE, M. 2003. The Balmoral, Glamis and Stifling Fields, Block 16/21, UK Central North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 395-413. GAMBARO, M. & DONAGEMMA, V. 2003. The T-Block Fields, Block 16/17, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 369-382. GARLAND, C. R. 1991. The Amethyst Field, Blocks 47/8a, 47/9a, 47/13a, 47/14a, 47/15a, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 387-394. GARLAND, C. R. 1993. Miller Field: reservoir stratigraphy and its impact on development. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th ConJ'erence. Geological Society, London, 401-414. GIBBONS, K. A. JOURDAN, C. A. & HESTHAMMER, J. 2003. The Statfjord Field, Blocks 33/9, 33/12, Norwegian sector, Blocks 211/24 & 211/25, UK sector, Northern North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 335-353. GLENN|E, K. W. 1997. Recent advances in understanding the southern North Sea basin: a summary. In: ZIEGLER, K., TURNER, P. & DAINES, S. R.
53
(eds) Petroleum Geology of the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 17-29. GLENNIE, K. W. 1998. Lower Permian-Rotliegend. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea: Basic Concepts and Recent Advances. Blackwell Science, Oxford, 137-173. GLENNIE, K. W. & ARMSTRONG, L. A. 1991. The Kittiwake Field, Block 21/18, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 339-345. GLENNIE, K. W. & BOEGNER,P. 1981. Sole Pit inversion tectonics. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of North West Europe. Heyden, London, 110-120. GLENNIE, K. W. & UNDERHILL, J. R. 1998. Development and Evolution of Structural Styles. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea: Basic Concepts and Recent Advances. Blackwell Science, Oxford, 42-84. GOODCHILD, M. W., HENRY, K. L., HINKLEY, R. J. & IMBUS, S. W. 1999. The Victory gas field, West of Shetland. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 713-726. GLUYAS, J. G. & UNDERHILL, J. R. 2003. The Staffa Field, Block 3/8b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 327-333. GLUYAS, J. G., EVANS, I. J. & RICHARDS, O. 2003. The Kimmeridge Bay Oilfield, Dorset, UK Onshore. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 943-948. GOWLAND, S. 1996. Facies characteristics and depositional models of highly bioturbated shallow marine siliciclastic strata: an example from the Fulmar Formation (Late Jurassic), UK Central Graben. In: HURST, A., JOHNSON, H. O., BURLEY, S. O., CANHAM, A. C. & MACKERTICH, O. S. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 185 214. GRAUE, E., HELLAND-HANSEN, W., JOHNSEN, J., LOMO, L., NOTTVEDT, A., RONNING, K., RYSETH, A. & STEEL, R. 1987. Advance and retreat of the Brent delta system, Norwegian North Sea. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 915-937. GUNN, C., MACLEOD, J. A., SALVADOR, P. & TOMKINSON, J. 2003. The MacCulloch Field, Block 15/24b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 453-466. GUSCOTT, S., RUSSELL, K., THICKPENNY, A. & PODDUBIUK, R. 2003. The Scott Field, Blocks 15/21a, 15/22, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 467-482. HABICHT, J. K. A. 1979. Palaeoclimate, Palaeomagnatism and Continental Drift. American Association of Petroleum Geologists, Tulsa. Studies in Geology. HAIG, D. B. 1991. The Hutton Field, Blocks, 211/28, 211/27, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 135 144. HALL, S. A. 1992. The Angus Field, a subtle trap. In: HARDMAN, R. F. P. (ed.) Exploration Britain Geological Insights for the Next Decade. Geological Society, London, Special Publications, 67, 151-185. HARKER, S. D. 1998. The palingenesy of the Piper oil field, UK North Sea. Petroleum Geoscience, 4, 271 286. HARKER, S. D. & CHERMAK, A. 1992. Detection and prediction of Lower Cretaceous sandstone distribution in the Scapa Field, North Sea. In: HARDMAN, R. F. P. (ed.) Exploration Britain Geological Insights Jor the Next Decade. Geological Society, London, Special Publications, 67, 221-246. HARKER, S. D., GREEN, S. C. H. & ROMANI, R. S. 1991. The Claymore Field, Block 14/19, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdora Oil and Gas Field~, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 269 278. HARKER, S. O., MANTELL, K. A., MORTON, D. J. & RILEY, L. A. 1993. The stratigraphy of Oxfordian-Kimmeridgian (late Jurassic) reservoir sandstones in the Witch Ground Graben, United Kingdom North Sea. American Association of Petroleum Geologists, Bulletin, 77, 1693-1709.
54
J.R. UNDERHILL
HARKER, S. D., RICHARDSON, G., SIDES, L. E. & COOPER, R. 2003. Alwyn North Triassic Main gas-condensate: drilling deeper promotes production. Petroleum Geoscience, 9, 133-142. HARVEY, M. A. & CURRIE, S. 2003. The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea, In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 443-451. HATTON, I. R. 1986. Geometry of allochthonous Chalk Group members, Central Trough, North Sea. Marine and Petroleum Geology, 3, 79-97. HAYWARD, R. D., MARTIN, C. A. L., HARRISON, D. VAN DORT, G., GUTHRIE, S. & PADGET, N. 2003. The Flora Field, Blocks 31/26a, 31/26c, UK North Sea. In: GEUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 549-555. HEINRICH, R. D. 1991a. The Cleeton Field, Block 42/29, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14,409-416. HEINRICH, R. D. 1991b. The Ravenspurn South Field, Blocks 42/29, 42/30, 43/26, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields', 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 469-476. HELLAND-HANSEN, W., ASHTON, M., LOMO, L. & STEEL, R. 1992. Advance and retreat of the Brent delta: recent contributions to the depositional model. In: MORTON, A. C., HASZELDINE, R. S., GLEES, M. R. & BROWN, S. (eds) Geology of the Brent Group. Geological Society, London, Special Publications, 61, 109 127. HERRIES, R., PODDUBIUK, R. & WILCOCKSON, P. 1999. Solan, Strathmore and the back basin play, West of Shetland. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of' Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 693-712. HESKETH, R. A. P. & UNDERHIEE, J. R. 2002. The biostratigraphic calibration of the Scottish and Outer Moray Firth Upper Jurassic successions: a new basis for the correlation of Late Oxfordian-Early Kimmeridgian Humber Group reservoirs in the North Sea Basin. Marine & Petroleum Geology, 19, 541 562. HESTHAMMER, J., JOURDAN, C. A., NIELSEN, P. E., EKERN, T. E. & GIBBONS, K. A. 1999. A tectonostratigraphic framework for the Statfjord Field, northern North Sea. Petroleum Geoscience, 5, 241-256. HEWARD, A. P. 1991. Inside Auk - The anatomy of an eolian oil reservoir. In: MIALL, A. D. & TYLER, N. (eds) The three dimensional architecture of terrigeneous clastic sedimen ts and its irnplications for hydrocarbon discovery and recover),. SEPM (Society for Sedimentary Geology), Special Publication, Concepts in Sedimentology and Palaeontology, 3, 44-56. HILL, P. J. & PALFREY, A. J. 2003. The Britannia Field, Blocks 15/2%, 15/30, 16/26, 16/27a, 16/27b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 415-429. HILLIER, A. P. 2003a. The Corvette Field, Block 49/24, UK Southern North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Field~, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 699-704. HILLIER, A. P. 2003b. The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea. In: GEUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 761 770. HILLIER, A. P. 2003c. The Sean North, Sean South and Sean East Fields, Block 49/25a, UK North Sea. In: GEUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 825-833. HILLIER, A. P. & WILLIAMS, B. P. J. 1991. The Leman Field, Blocks, 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 451-458. HILLIS, R. R., THOMSON,K. & UNDERHILL,J. R. 1993. Quantification of Tertiary erosion in the Inner Moray Firth by sonic velocity data from the Chalk and Kimmeridge Clay. Marine & Petroleum Geology, l l , 283-293. HOBSON, G. D. & HILLIER, A. P. 1991. The Sean North and Sean South Fields, Block 49/25a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 485-490. HODGE, T. 2003. The Saltfleetby Field, Block L47/16, Licence PEDL 005, Onshore UK. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 911 919.
HODGSON, N. A., FARNSWORTH, J. d~; FRASER, A. J. 1992. Salt-related tectonics, sedimentation and hydrocarbon plays in the Central Graben, North Sea UKCS. In: HARDMAN, R. F. P. (ed.) Exploration Britain Geological insights for the next decade. Geological Society, London, Special Publications, 67, 31-63. HOGG, A. J. C. 2003. The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, 22/18, 22/23a, U K North Sea. In: GLUYAS, J. G. HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 611-616. HOGG, A. J. C., EVANS, I. J., HARRISON, P. F., MELING, T., SMITH, G. S., THOMPSON, S. D. & WATTS, G. F. T. 1999. Reservoir management of the Wytch Farm Oil Field, Dorset, UK: Providing options for growth into later field life. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1157-1174. HOLMES, A. J. 1991. The Camelot Fields, Blocks, 53/la, 53/2, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Field~, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 401-408. HOOK, J., ABHVANI, A., GEUYAS, J. G. & LAWLOR, M. 2003. The Birch Field, Block 16/12a, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 167-181. HUSMO, T., HAMER, G. P., HOILAND, 0., JOHANNESSEN, E. P., ROMULD, A., SPENCER, A. M. & TITTERTON, R. 2002. Lower and Middle Jurassic. ln: EVANS, D., GRAHAM, C., ARMOUR, A. & BATHURST, B. (eds & co-ordinators) The Millennium Atlas. Petroleum Geology of the Central and Northern North Sea, 129-155. INGLIS, I. & GERARD, J. 1991. The Alwyn North Field, Blocks 3/9a, 3/4a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 21-32. JACKSON, D. I. & MULHOLLAND,P. 1993. Tectonic and stratigraphic aspects of the East Irish Sea Basin and adjacent areas: contrasts in their postCarboniferous structural styles. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings oJ"the 4th Con/erence. Geological Society, London, 791-808. JEREMIAH, J. M. 2000. Lower Cretaceous turbidites of the Moray Firth: sequence stratigraphical framework and reservoir distribution. Petroleum Geoscience, 6, 309-328. JEREMIAH, J. M. & NICHOLSON, P. H. 1999. Middle Oxfordian to Vogian sequence stratigraphy of the Greater Shearwater area. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology oj Northwest Europe: Proceedings o[ the 5th ConJerence. Geological Society, London, 153 170. JOHNES, L. H. & GAUER, M. B. 1991. The Northwest Hutton Field, Block 211/27, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 145-152. JOHNSON, H. D. & FISHER, M. J. 1998. North Sea plays: geological controls on hydrocarbon distribution. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea Basic Concepts and Recent Advances. Blackwell Science, Oxford, 463 547. JOHNSON, H. D. & STEWART, D. J. 1985. Role of clastic sedimentology in the exploration and production of oil and gas in the North Sea. In: BRENCHLEY, P. J. & WILLIAMS, B. P. J. (eds) Sedimentology: Recent developments and Applied Aspects. Geological Society, London, Special Publications, 17, 249 310. JOHNSON, H. D., MACKAY, T. A. ~; STEWART, D. J. 1986. The Fulmar oilfield (Central North Sea): geological aspects of its discovery, appraisal and development. Marine and Petroleum Geology, 3, 99 125. JOHNSTON, S. C., SMITH, R. I. & UNDERHILL, J. R. 1995. The Clair Discovery, west of the Shetland Isles. Scottish Journal of Geology, 31, 187-190. JOELEY, J. E. 2003. The Andrew and Cyrus Fields, Blocks 16/27a, 16/28, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 133-137. JONES, L. S., GARRETT, S. W., MACLEOD, M., GuY, M., CONDON, P. J. & NOTMAN, L. 1999. Brittania Field, UK Central North Sea: modelling heterogeneity in unusual deep-water deposits. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings o)c the 5th Conference. Geological Society, London, 1115-1124. JOWITT, R., HINDLE, A., JONES, D. & ROSE, P. 1999. Petroleum systems analysis of the Paleocene play in the West of Shetland area. In:
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 1367-1382. KADOLSKY, D., JOHANSEN, S. J. & DUXBURY, S. 1999. Sequence stratigraphy and sedimentary history of the Humber Group (Late JurassicRyazanian) in the Outer Moray Firth (UKCS, North Sea). In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings o f the 5th Conference. Geological Society, London, 839-860. KANTOROWICZ,J. D., ANDREWS,I. J., DHANANI,S., GILLIS,M., JENNINGS,C., LUMSDEN, P. J., ORR, G., SIMM, R. W. & WILLIAMS, J. 1999. Innovation and risk management in a small subsea-tieback: Arkwright Field, Central North Sea. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1125 1134. KARASEK, R. M. & HUNT, J. R. 2003. The Camelot Fields, Blocks 53/la, 53/2, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 681-689. KARASEK, R. M., VAUGHAN,R. L. & MASUDA, T. T. 2003. The Beryl Field, Block 9/13, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 153-166. KERLOGUE, A., CHERRY, S., DAVIES,H., QUINE, M. & SPOTTI, G. 1995. The Tiffany and Toni oil fields, Upper Jurassic submarine fan reservoirs, South Viking Graben, UK North Sea. Petroleum Geoscience, 1,279-285. KErrER, F. J. 1991a. The Esmond, Forbes and Gordon Fields, Blocks 43/8a, 43/13a, 43/15a, 43/20a, UK North Sea. In: ABBOrrS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 425-432. KETTER, F. J. 1991b. The Ravenspurn North Field, Blocks 42/30, 43/26a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 459-467. KNIGHT, I. A., ALLEN, L. R., COIPEL, J., JACOBS, L. & SCANLAN,M. J. 1993. The Embla Field. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1433 1444. KNOTT, S. D., BURCHELL, M. T., JOLLEY, E. J. & FRASER, A. J. 1993. Mesozoic to Cenozoic plate reconstructions of the North Atlantic and hydrocarbon plays of the Atlantic margins. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 953-974. KNOX, R. W. O'B. & HOLLOWAY, S. 1992. Paleogene of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY,W. G. (eds) Lithostratigraphic nomenclature of the UK North Sea. British Geological Survey, Nottingham. KNUTSON, C. A. & MUNRO, I. C. 1991. The Beryl Field, Block 9/13, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 33-42. KUHN, O., SMITH, S. W., VAN NOORT, K. & LOISEAU, B. 2003. The Fulmar Field, U K North Sea. In: GLUYAS, J. G. & HICHENS, U. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 563-585. KUNKA, J. M., WILLIAMS, G., CULLEN, B., BOYD-GORST, J., DYER, G. R., GARNHAM, J. A., WARNOCK,A., WARDELL,J., DAVIES,A. & LYNES,P. 2003. The Nelson Field, Block 22/11, 22/6a. 22/7, 22/12a, UK Central North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 617-646. LAMBERT, R. A. 1991. The Victor Field, Blocks 49/17, 49/22, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 503-508. LAMERS, E. & CARMICHAEL, S. M. M. 1999. The Paleocene deepwater sandstone play, West of Shetland. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 645-660. LAPPIN, M., HENDRY, D. J. & SAIKIA, I. A. 2003. The Guinevere Field, Block 48/17b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 723-730. LASOCKI,J., GUEMENE, J.-M., HEDAYATI,A., LEGORJUS, C. & PAGE, W. M. 1999. The Elgin and Franklin Fields, UK Blocks 22/30c, 22/30b and
55
29/5b. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 1007-1020. LATIN, D. M., DIXON, J. E. & FITTON, J. G. 1990a. Rift-related magmatism in the North Sea basin. In: BLUNDELL,D. J. & GIBBS, A. D. (eds) Tectonic Evolution of the North Sea Rifts. Oxford Science, Oxford, 101-144. LATIN, D. E., DIXON, J. E., FITTON, J. G. & WHITE, N. 1990b. Mesozoic magmatic activity in the North Sea Basin: implications for stretching history. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic events responsible for Britain's' Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 207-227. LAW, A., RAYMOND, A., WHITE, G., ATKINSON, A., CLIFTON, M., ATHERTON, T., DAWES, I., ROBERTSON, E., MELVIN, A. & BRAYLEY, S. 2000. The Kopervik fairway, Moray Firth, UK. Petroleum Geoscience, 6, 265-274. LAWTON, D. E. & ROBERSON,P. P. 2003. The Johnston Gas Field, Blocks 43/ 26a, 43/27a, UK Southern North Sea. In: GLUYAS,J. G. & HICHENS,H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 749-759. LEEDER, M. R. & HARDMAN, M. 1990. Carboniferous geology of the southern North Sea basin and controls on hydrocarbon prospectivity. In: HARDMAN, R. F. P. & BROOKS,J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 87-105. LEACH, H. M., HERBERT, N., LOS, A. & SMITH, R. L. 1999. The Schiehallion development. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 683-692. LINSLEY, P. N., POTTER, H. C., MCNAB, G. & RACHER, D. 1980. The Beatrice Field, Inner Moray Field, UK North Sea. In: HALBOUTY, M. T. (ed.) Giant Oilfields of the Decade. American Association of Petroleum Geologists, Tulsa, Memoirs, 30, 117-129. MCCRONE, C. W. 2003. Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 705-712. MCCRONE, C. W., GAINSKI, M. & LUMSDEN, P. J. 2003. The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas' Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 741-747. MACDONALD, A. C. & HALLAND, E. K. 1993. Sedimentology and shale modelling of a sandstone-rich fluvial reservoir: Upper Statfjord Formation, Statfjord Field, Northern North Sea. American Association of Petroleum Geologists, Bulletin, 77, 1016-1040. MACKENZIE, A. S., LEYTHAEUSER, D., MULLER, P., RADKE, M. & SCHAEFER,R. G. 1987. The expulsion of petroleum from Kimmeridge Clay source rocks in the area of the Brae Oilfield, UK. In: BROOKS,J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 865-878. MACKERTICH, D. 1996. The Fife Field, UK Central North Sea. Petroleum Geoscience, 2, 373-380. MCGANN, G. J., GREEN, S. C. H., HARKER, S. D. & ROMANI, R. S. 1991. The Scapa Field, Block 14/19, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 369-376. McKIE, T., AGGETT, J. & HOGG, A. J. C. 1998. Reservoir Architecture of the upper Sherwood Sandstone, Wytch Farm Field, southern England. In: UNDERHILL, J. R. (ed.) Development and Evolution of the Wessex Basin. Geological Society, London, Special Publications, 133, 399-406. MCLEOD, A. E. & UNDERHILL,J. R. 1999. Processes and products of footwall degradation, northern Brent Field, Northern North Sea. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 91-106. MCLEOD, A. E., DAWERS,N. H. & UNDERHILL,J. R. 2000. The propagation and linkage of normal faults: insights from the Strathspey-BrentStatfjord fault array, northern North Sea. Basin Research, 12, 263-284. MCLEOD, A. E., UNDERmLL, J. R., DAVIES, S. J. & DAWERS, N. J. 2002. The influence of fault array evolution on synrift sedimentation patterns: controls on deposition in the Strathspey-Brent-Statfjord halfgraben, Northern North Sea. American Association of Petroleum Geologists Bulletin, 86, 1061-1093.
56
J.R. UNDERHILL
MAHER, C. E. 1981. The Piper Oilfield. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of North-West Europe, Heyden, London, 358-370. MARJANAC, T. 1995. Architecture and sequence stratigraphic perspectives of the Dunlin Group formations and proposal for new type- and referencewells. In: STEEL, R. J., FELT, V. L., JOHANNESSEN, E. P. & MATHIEU, C. (eds) Sequence Stratigraphy on the Northwest European Margin. Norwegian Petroleum Society, Special Publications, 5, 143-165. MARJANAC, Y. & STEEL, R. J. 1997. Dunlin Group Sequence Stratigraphy in the Northern North Sea." A Model for Cook Sandstone Deposition. American Association of Petroleum Geologists, Bulletin, 81, 276-292. MARSHALL, J. E. A., ROGERS, D. A. & WHITELEY, 1996. Devonian marine incursions into the Orcadian Basin, Scotland. Journal o/ the Geological Society, 153, 451-466. MARTIN, M. A. & POLLARD, J. E. 1996. The role of trace fossil (ichnofabric) analysis in the development of depositional models for the Upper Jurassic Fulmar Formation of the Kittiwake Field (Quadrant 21 UKCS). In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM,A. C. & MACKERTICH, D. S. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 163-183. MAXWELL, G., HARTLEY, A. & CRANE, J. 1999. High resolution zonation within a tide-dominated deltaic reservoir: the Middle Jurassic Beryl Formation, Beryl Field, UKCS. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conferenee. Geological Society, London, 1187 1198. MAXWELL, G., STANLEY, R. E. & WHITE, D. C. 2003. The Strathspey Field, Block 3/4a, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 355-368. MEGSON, J. & HARDMAN, R. 2001. Exploration for and development of hydrocarbons in the Chalk of the North Sea: a low permeability system. Petroleum Geoscience, 7, 3-12. MEYERS, J. C., JONES, A. F. & TOWART, J. M. 1995. The Markham Field: UK Blocks 49/5a and 49/10b, Netherlands Blocks J3b and JG. Petroleum Geoscience, 1, 303-309. MILNE, A. D. & BROWN,A. M. 2003. The Don Field, Blocks 211/13a, 211/14, 211/18a, 211/19a, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 257-263. MITCHENER, B. C.. LAWRENCE,D. A., PARTINGTON,M. A., BOWMAN,M. B. J. & GLUYAS, J. 1992. Brent Group: sequence stratigraphy and regional implications. In: MORTON, A. C., HASZELD|NE, R. S., GILES, M. R. & BROWN, S. (eds) Geology (~]" the Brent Group. Geological Society, London, Special Publications, 61, 45-80. MORGAN, C. P. 1991. The Viking Complex Field, Blocks 49/12a, 49/16, 49/17, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas FieMs, 25 Years Commemorative Voh~me. Geological Society, London, Memoirs, 14, 509 516. MORRISON, D., BENNET, G. G. & BAYAT, M. G. 1991. The Don Field, Blocks 211/13a, 211/14, 211/18a, 211/19a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 89-94. MOSCARIELLO, A. 2003. The Schooner Field, Blocks 44/26a, 43/30a, UK North Sea. ln: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 811-824. MOUND, D. G., ROBERTSON,I. D. & WALLIS, R. J. 1991. The Cyrus Field, Block 16/28, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Field~, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 295-300. MUDGE, D. C. & BUJAK, J. 2001. Biostratigraphic evidence for evolving palaeoenvironments in the Lower Paleogene of the Faeroe-Shetland Basin. Marine and Petroleum Geology, 18, 577-590. MUDGE, D. C. & RASHID, B. 1987. The geology of the Faeroe Basin area. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 751-763. MUSSETT,A. E., DAGLEY,P. & SKELTHORN,R. R. 1988. Time and duration of activity in the British Tertiary Igneous Province. In: MORTON, A. C. & PARSON, L. M. (eds) Early Tertiary Volcanism and the opening of the NE Atlantic. Geological Society, London, Special Publications, 39, 337-348. NADIN, P. A., KUSZNIR, N. J. & TOTH, J. 1995. Transient regional uplift in the Early Tertiary of the northern North Sea and the development of the Iceland Plume. Journal of the Geological Society, 152, 953-958.
NEWMAN, M. ST J., REEDER, M. L., WOODRUFF, A. H. F. & HATTON, I. R. 1993. The geology of the Gryphon Field. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 123 134. NEWTON, S. K. & FLANAGAN, K. P. 1993. The Alba Field: evolution of the depositional model. In: PARKER, J. R. (ed.) Petroleum Geology of NorthWest Europe." Proceedings of the 4th Conference. Geological Society, London, 161-174. O'BRIEN, R. E., LAPPIN, M., KOMLOSI, F. & LOFTUS,J. A. 2003. The Malory Field, Block 48/12d, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 771-776. O'CONNOR, S. J. & WALKER, D. 1993. Paleocene reservoirs of the Everest Trend. In: PARKER, J. R. (ed.) Petroleum Geology of North-West Europe." Proceedings of the 4th Conference. Geological Society, London, 145-160. O'MARA, P. T., MERRYWEATHER, M., STOCKWELL, M. & BOWLER, M. M. 1999. The Trent Gas Field: correlation and reservoir quality within a complex carboniferous stratigraphy. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 809-824. O'MARA, P. T., MERRYWEATHER, M., STOCKWELL,M. & BOWLER, M. M. 2003a. The Trent Gas Field, Block 43/24a, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Field~, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 835-849. O'MARA, P. T., MERRYWEATHER, M. • COOPER, D. S. 2003b. The Tyne Gas Fields, Block 44/18a, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 851 860. OSBON, R. A., WERNGREN, 0. C., KYEI, A., MANLEY, D. & Six, J. 2003. The Gawain Field, Blocks 49/24, 49/29a, UK North Sea. In: GLUYAS, J. G. & H1CHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 713 722. PARKER, J. R. 1975. Lower Tertiary sand development in the central North Sea. In: WOODLAND, A. W. (ed.) Petroleum and The Continental Shelf o[ Northwest Europe. Applied Science Publishers, London, 447 453. PARKER, R. H. 1991. The Ivanhoe and Rob Roy Fields, Block 15/21a b, U K North Sea. In: ABBOTTS, 1. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 331 338. PART1NGTON, M. A., COPESTAKE, P., M1TCHENER, B. C. & UNDERH|LL,J. R. 1993a. Biostratigraphic calibration of genetic stratigraphic sequences in the Jurassi~lowermost Cretaceous (Hettangian to Ryazanian) of the North Sea and adjacent areas, hi: PARKER,J. R. (ed.) Petroleum Geology ~[" Northwest Europe." Proceedings (~[ the 4th Conference. Geological Society, London, 371 386. PARTINGTON, M. A., MITCHENER, B. C., MILTON, N. J. & FRASER, A. J. 1993b. Genetic sequence stratigraphy for the North Sea Late Jurassic and early Cretaceous: distribution and prediction of Kimmeridgia~ Late Ryazanian reservoirs in the North Sea and adjacent areas. In: PARKER, J. R. (ed.) Petroleum Geology (~["Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 347-370. PEARSON, J. F. S., YOUNGS, R. A. & SMITH,A. 1991. The Indefatigable Field, Blocks 48/18, 48/19, 48/23, 48/24, UK North Sea. h~: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 443-450. PEGRUM, R. M. & SPENCER, A. M. 1990. Hydrocarbon plays in the North Sea. In: BROOKS, J. (ed.) Classic Petroleum Provinces. Geological Society, London, Special Publications, 50, 441-470. PENGE, J., TAYLOR, B., HUCKERBY, J. A. & MUNNS, J. W. 1993. Extension and salt tectonics in the East Central Graben. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings ()["the 4th Conference. Geological Society, London, 1197-1210. PENNY, B. 1991. The Heather Field, Block 2/5, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 127 134. PETERS, K. E., MULDOWAN, J. M., DRISCOLE, A. R. & DEMAISON, G. J. 1989. Origin of Beatrice oil by co-sourcing from Devonian and Middle Jurassic source rocks, Inner Moray Firth. American Association of Petroleum Geologists, Bulletin, 73, 454-471. PHILLIPS, W. E. A., STILLMAN, C. J. & MURPHY, T. 1976. A Caledonian plate tectonics model. Journal of the Geological Society, I32, 579-609.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS PINNOCK, S. J. & CLITHEROE,A. R. J. 2003. The Captain Field, Block 13/22a, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdora Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 431-441. POOLER, J. & AMORY, M. 1999. A subsurface perspective on E T A P - an integrated development of seven Central North Sea fields. In: FLEET,A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 993-1006. PORTER, J. R., KNIPE, R. J., FISHER, Q. J., FARMER, A. B., ALLIN, N. S., JONES, L. S., PALFREY, A. J., GARRET, S. W. & LEWIS, G. 2000. Deformation processes in the Britannia Field, UKCS. Petroleum Geoscience, 6, 241-254. PRITCHARD, M. J. 1991. The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, U K North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 497-502. RATTEY, R. P. & HAYWARD, A. B. 1993. Sequence stratigraphy of a failed rift system: The Middle Jurassic to early Cretaceous basin evolution of the Central and Northern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 215-249. RHYS, G. H. 1974. A proposed standard lithostratigraphic nomenclature for the southern North Sea and an outline structural nomenclature for the whole of the (UK) North Sea. Institute of Geological Sciences, Report 74[8, 14. RICHARDS, P. C., LOTT, G. K., JOHNSON, H., KNOX, R. W. O'B. & RIDING, J. B. 1993. Jurassic of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Society, Nottingham. RICHES, H. 2003. The Viking Field, Blocks 49/12a, 49/16, 49/17, U K North Sea. In: GLUYAS,J. G. & HICHENS,H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 871-880. RITCHIE, J. S. 2003. The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14, 3/15, UK North Sea. In: GLUYAS, J. G. & HICHENS,H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volmne. Geological Society, London, Memoirs, 20, 265-281. RITCHIE, J. S. & PRATSIDES,P. 1993. The Caister Fields, Block 44/23a, UK North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 759-770. RITCHIE, J. S., PILLING, D. & HAYES, S. 1998. Reservoir development, sequence stratigraphy and geological modelling of Westphalian fluvial reservoirs of the Caister C Field, UK Southern North Sea. Petroleum Geoscience, 4, 203-211. ROBERTS, M. J. 1991. The South Brae Field, Block 16/Ta, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 55-62. ROBERTSON, G. 1993. Beryl Field: geological evolution and reservoir behaviour. In: PARKER, J. R. (ed.) Petroleum Geology of North-West Europe." Proceedings of the 4th Conference. Geological Society, London, 1491-1502. ROBSON, D. 1991. The Argyll, Duncan and Innes Fields, Blocks 30/24, 30/25a, UK North Sea. In: ABBOTTS, 1. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 219-226. ROE, S. L. & STEEL, R. 1985. Sedimentation, sea-level rise and tectonics at the Triassic-Jurassic Boundary (Statfjord Formation), Tampen Spur, northern North Sea. Journal of Petroleum Geology, 8, 163-186. ROOKESBY, S. K. 1991. The Miller Field, Blocks 16/7B, 16/8B, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 159-164.
ROSE, P. T. S. 1999. Reservoir characterization in the Captain Field: integration of horizontal and vertical well data. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology o f Northwest Europe." Proceedings o f the 5th Conference. Geological Society London, 1101-1114. ROSE, P. T. S., MANIGHETTI, A. A., REGAN, K. J. & SMITH, T. 2000. Sand body geometry, constrained and predicted during a horizontal drilling campaign in a Lower Cretaceous turbidite sand system, Captain Field, UKCS Block 13/22a. Petroleum Geoscience, 6, 255-263. RYSETH, m. & RAMM, M. 1996. Alluvial architecture and differential subsidence in the Statfjord Formation, North Sea: prediction of reservoir potential. Petroleum Geoscience, 2, 271-287.
57
SARGINSON, M. J. 2003a. The Barque Field, Blocks 48/13a, 48/14, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 663-670. SARGINSON, M. J. 2003b. The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 691-698. SCHMITT, H. R. H. 1991. The Chanter Field, Block 15/17, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 261-268. SCHMITr, H. R. H. & GORDON, A. F. 1991. The Piper Field, Block 15/17, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 361-368. SCOTT, E. S. 1992. The palaeoenvironments and dynamics of the RannochEtive nearshore and coastal succession, Brent Group, Northern North Sea. In: MORTON, A. C., HASZELDINE,R. S., GILES, M. R. & BROWN, S. (eds) Geology of the Brent Group. Geological Society, London, Special Publications, 61, 129-147. SHEPHERD, M. 1991. The Magnus Field, Blocks 211/7, 211/12a, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 153-158. SHEPHERD, M., MACGREGOR, A., BUSH, K. & WAKEFIELD, J. 2003. The Fife and Fergus Fields, Block 31/26a, UK North Sea. In: GLUYAS, J. G. & HICHENS,H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 537-547. SMITH, B. & STARCHER,V. 2003. The Mercury and Neptune Fields, Blocks 47/9b, 47/4b, 47/5a, 42/29, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 777-787. SMITH, m. G., HURLEY, m. M. & BRIDEN, J. C. 1981. Phanerozoic Palaeocontinental Worm Maps. Cambridge University Press, Cambridge, 101pp. SPAAK, P., ALMOND, J., SALAHUDIN, S., MOHD SALLEH, Z. & TOSUN, O. 1999. Fulmar: a mature field revisited. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology o f Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1089-1100. SPENCE, S. & KREUTZ, H. 2003. The Kingfisher Field, Block 16/8a, U K North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 305-314. SPENCER, A. M., LECKIE, G. G. & CHEW, K. J. 1996. North Sea hydrocarbon plays and their resources. First Break, 14, 345-357. STEEL, R. 1993. Triassic-Jurassic megasequence stratigraphy in the Northern North Sea: rift to post-rift evolution. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 299-315. STEEL, R. J. & WILSON, A. C. 1975. Sedimentation and tectonism (?PermoTriassic) on the margin of the North Minch Basin, Lewis. Journal o f the Geological Society, 131, 183-202. STEELE, R. P., ALLAN, R. M., ALLINSON, G. J. & BOOTH, A. J. 1993. Hyde: a proposed field development in the Southern North Sea using horizontal wells. In: PARKER, J. R. (ed.) Petroleum Geology o f Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1465-1472. STEPHEN, K., UNDERHILL, J. R., PARTINGTON, M. & HEDLEY, R. 1993. Hettangian-Oxfordian Sequence Stratigraphy of the Inner Moray Firth basin. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings o f the 4th Conference. Geological Society, London, 485-505. STEPHENSON, M. A. 1991. The North Brae Field, Block 16/7a, U K North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 43 -48. STEVENS, V. 1991. The Beatrice Field, Block 11/30a, UK North Sea. In: ABBOTrS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 245-252. STEVENS, D. A. & WALLIS, R. J. 1991. The Clyde Field, Block 30/17b, U K North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 279-286.
58
J.R. UNDERHILL
STEWART, D. M. & FAULKNER, A. J. G. 1991. The Emerald Field, Blocks 2/10a, 2/15a, 3/llb, U K North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 111-116. STEWART, I. J. 1987. A revised stratigraphic interpretation of the Early Palaeogene of the central North Sea. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 557-576. STEWART, S. A., FRASER, S. I., CARTWRIGHT,J. A., CLARK, J. A. & JOHNson, H. D. 1999. Controls on Upper Jurassic sediment distribution in the Durward-Dauntless area, UK Blocks 21/11, 21/16. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 879-896. STOCKBRIDGE, C. P. GRAY, D. I. 1991. The Fulmar Field, Blocks 30/16, 30/1 lb, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 309-316. STOREY, M. W. &NASH, D. F. 1993. The Eakring Dukeswood oil field: an unconventional technique to describe a field's geology. In: PARKER, J. R. (ed.) Petroleum Geology of North-West Europe: Proceedings of the 4th Conference. Geological Society, London, 1527-1539. STOW, D. A. V., BISHOP, C. D. & M~LLS, S. J. 1982. Sedimentology of the Brae Oil Field, North Sea: fan models and controls. Journal of Petroleum Geology, 5, 129 148. STRUIJK, A. P. & GREEN, R. T. 1991. The Brent Field, Block 211/29, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Field~, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 63-72. STUART, I. A. 1991. The Rough Gas Storage Field, Blocks 47/3d, 47/8b, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 477-484. STUART, I. A. 1993. The geology of the North Morecambe Gas Field, East Irish Sea Basin. In: PARKER, J. R. (ed.) Petroleum Geology of" NorthWest Europe: Proeeedings of the 4th Conference. Geological Society, London, 883 898. STUART, |. A. 2003. The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 139-151. STUART, I. A. & COWAN, G. 1991. The South Morecambe Field, Blocks l10/2a, l10/3a, ll0/8a, UK East Irish Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 527-541. SURLYK, F. 1978. Submarine fan sedimentation along fault scarps on tilted fault blocks (Jurassic-Cretaceous boundary, East Greenland). Gronlands Geologiske Undersogelse, Bulletin, 28, 1 103. SWEET, M. L. 1999. Interaction between Aeolian, fluvial and playa environments in the Permian, Upper Rotliegend Group, UK southern North Sea. Sedimentology, 46, 171-187. SYMS, R. M., SAVORY, D. F., WARD, C. J., EBDON, C. C. & GRIFFIN, A. 1999. Integrating sequence stratigraphy in field development and reservoir management - The Telford Field. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology ~/" Northwest Europe." Proceedings ~[" the 5th Conference. Geological Society, London, 1075-1088. TAYLOR, D. J. & DIETVORST, J. P. A. 1991. The Cormorant Field, Blocks 211/21a, 211/26a, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdorn Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 73-81. TAYLOR, S. R., ALMOND, J., ARNOTT, S., KEMSHALL, D. & TAYLOR, U. 2003. The Brent Field, Block 211/29, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 233-250. THOMSON, K. & UNDERHILL, J. R. 1993. Controls on the development and evolution of structural styles in the Inner Moray Firth Basin. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1167-1178. TONKIN, P. C. & FRASER, A. R. 1991. The Balmoral Field, Block 16/21, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 237-244.
TORSVIK,T. H., CARLOS,D., MOSAR, M., COCKS,L. R. M. & MALME,T. 2002. Global reconstructions and North Atlantic paleogeography 440 Ma to recent. In: FIDE, E. A. BA TLA S - Mid Norway plate reconstruction atlas withglobalandAtlanticperspectives. Geological SurveyofNorway, 18 39. TREWIN, N. H. & BRAMWELL, M. G. 1991. The Auk Field, Block 30/16, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 227-236. TREWIN, N. H., FRYBERGER, S. G. & KREUTZ, H. 2003. The Auk Field, Block 30/16, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 485-496. TRUEMAN, S. 2003. The Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey and Sussex, UK Onshore. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 929-941. TURNER, C. C. & ALLEN, P. J. 1990. The Central Brae Field, Block, 16/7a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 49-54. TURNER, C. C., RICHARDS, P. C., SWALLOW,J. L. & GRIMSHAW, S. P. 1984. Upper Jurassic stratigraphy and sedimentary facies in the Central Outer Moray Firth Basin, North Sea. Marine and Petroleum Geology, 1, 105-117. TURNER, C. C., COHEN, J. M. COHEN, E. R., CONNELL, R. & COOPER, D. M. 1987. A depositional model for the South Brae oilfield. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 853-864. TURNER, P., JONES, M., PROSSER, D. J., WILLIAMS,G. D. & SEARL,A. 1993. Structural and sedimentological controls on diagenesis in the Ravenspurn North gas reservoir, UK Southern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 771 788. TURNER, P. J. 1993. Clyde: reappraisal of a producing field. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1503-1512. TYSON, R. V., WILSON, R. C. L. & DOWNIE, C. 1979. A stratified water column environment model for the Type Kimmeridge Clay. Nature, 277, 377-380. TYSON, R. V. 1995. Sequence stratigraphical interpretation of organic facies variations in marine siliciclastic systems: general principles and application to the onshore Kimmeridge Clay Formation, UK. In: HESSELBO, S. P. & PARKINSON, D. N. (eds) Sequence Stratigraphy in British Geology. Geological Society, London, Special Publications, 103, 75 96. UNDERHILL, J. R. 1991. Implications of Mesozoic Recent basin development in the western lnner Moray Firth, UK Marine & Petroleum Geology, 8, 359 369. UNDERHILL, J. R. 1998. Jurassic. In: GLENNIE, K. W. (ed.) Petroleum geology of the North Sea: Basic concepts and recent advances. Blackwell Science, Oxford, 245-293. UNDERHILL, J. R. 2001. Controls on the genesis and prospectivity of Paleogene palaeogeomorphic traps, East Shetland Platform, UK North Sea. Marine & Petroleum Geology, 18, 259-281. UNDERHILL, J. R. & BRODIE, J. A. 1993. Structural geology of the Easter Ross Peninsula, Scotland: implications for movement on the Great Glen Fault Zone. Journal of the Geological Society, 150, 515-527. UNDERHILL, J. R. & PARTINGTON, M. A. 1993. Jurassic Thermal Doming and Deflation in the North Sea: Implications of the Sequence Stratigraphic Evidence. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 337-345. UNDERHILL, J. R. & PART1NGTON, M. A. 1994. Use of maximum flooding surfaces in determining a regional control on the Intra-Aalenian (Mid Cimmerian) sequence boundary: Implications for North Sea basin development and Exxon's Sea-Level Chart. In: POSAMENTIER,H. W. & WIEMER, P. J. (eds) Recent Advances in Siliciclastic Sequence Stratigraphy. American Association of Petroleum Geologists, Tulsa, Memoirs, 58, 449-484. UNDERHILL, J. R. & PATERSON,S. 1998. Genesis of Tectonic Inversion Structures: Seismic Evidence for the development of key structures along the Purbeck-Isle of Wight Monocline. Journal of the Geological Society, 155, 975-992.
TECTONIC AND STRATIGRAPHIC FRAMEWORK OF THE UNITED KINGDOM'S OIL AND GAS FIELDS
UNDERHILL,J. R. & STONELEY,R. 1998. Introduction to the development, evolution and petroleum geology of the Wessex Basin. In: UNDERHILL, J. R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publication, 133, 1-18. UNDERHILL, J. R., GAYER, R. A., WOODCOCK, N. H., DONNELLY, R., JOLLEY, E. J. & STIMPSON,I. G. 1988. The Dent Fault System, northern England - reinterpreted as a major oblique-slip fault zone. Journal of the Geological Society, 145, 303-316. UNDERHILL, J. R., SAWYER, M. J., HODGSON, P., SHALLCROSS, M. D. & GAWTHORPE, R. L. 1997. Implications of fault scarp degradation for Brent Group prospectivity, Ninian Field, Northern North Sea. Ameri~can Association of Petroleum Geologists, Bulletin, 81, 295-311. VAN HOORN, B., 1987. Structural evolution, timing and tectonic style of the Sole Pit inversion. Tectonophysics, 137, 239-284. VAN VESSEM, E. J. & GAN, T. L. 1991. The Ninian Field, Blocks 3/3 & 3/8, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Field~, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 175-182. VAN PANHUYS-SIGLER, M., BAUMANN, A. ~: HOLLAND, T. C. 1991. The Tern Field, Block 210/25a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields', 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 191-198. VAN VEEN, F. R. 1975. Geology of the Leman Field. In: WOODLAND,A. W. (ed.) Petroleum and The Continental Shelf of Northwest Europe. Applied Science Publishers, London, 223-232. VELDKAMP,J. J., GAILLARD,M. G., JONKERS,H. A. & LEVELL, B. K. 1996. A Kimmeridgian time-slice through the Humber Group of the central North Sea: a test of sequence stratigraphic models. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM,A. C. & MACKERTICH,D. S. (eds) Geology o f the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 1-28. VOLLSET, J. & DORE, A. G. 1984. A revised Triassic and Jurassic lithostratigraphic nomenclature for the Norwegian North Sea. Norwegian Petroleum Directorate, Bulletin 3. WADDAMS, P. & CLARK, N. M. 1991. The Petronella Field, Block 14/20b, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields', 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 353-360. WAKEFIELD, L. L., DROSTE, H., GILES, M. R. ~; JANSSEN, R. 1993. Late Jurassic plays along the western margin of the Central Graben. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 459-468. WARD, J., CHAN, A. & RAMSAY,B. 2003. The Hatfield Moors and Hatfield West Gas (Storage) Fields, South Yorkshire, UK Onshore. In: GLUYAS, J. G. & HICNENS,H. M. (eds) United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 905-910. WARRENDER,J. 1991. The Murchison Field, Block 211/19a. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 165-174. WENSRICH, M. D., EASTWOOD, K. M., VAN PANHUYS, C. D. & SMART, J. M. 1991. The Eider Field, Blocks, 211/16a, 211/21a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 103-110. WERNGREN, O. C. 1991. The Thames, Yare and Bure Fields, Block 49/28, UK North Sea. In: ABBOrrS, I. L. (ed.) United Kingdom Oil and Gas Field~, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 491-496. WERNGREN, O. C., MANLEY,D. & HEWARD,A. P. 2003. The Pickerill Field, Blocks 48/11a, 48/11b, 48/12c, 48/17b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 799-809. WHITE, R. S. 1988. A hot-spot model for early Tertiary volcanism in the North Atlantic. In: MORTON, A. C. & PARSON, L. M. (eds) Early Tertiary Volcanism and the Opening of the NE Atlantic. Geological Society, London, Special Publications, 39, 3-13. WHITE, R. S. 1989. Initiation of the Iceland Plume and the opening of the North Atlantic Margins. In: TANKARD, A. J. & BALKWlLL,H. R. (eds) Extensional Tectonics and Stratigraphy of the North Atlantic Margins. American Association of Petroleum Geologists, Memoirs, 46, 149-154.
59
WHITE, R. S. 1992. Crustal structure and magmatism of North Atlantic ontinental margins. Journal of the Geological Society, 149, 841-854. WHITEHEAD,M. • PINNOCK,S. J. 1991. The Highlander Field, Block 14/20b, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 323-330. WILLIAMS, R. R. 1991, The Deveron Field, Block 211/18a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 83-88. WILLIAMS, e. R. & MILNE, A. D. 1991. The Thistle Field, Blocks 211/18a and 211/19, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 199-210. WILLIAMS,J. J., CONNER, D. C. & PETERSON,K. E. 1975. The Piper Oil-field, UK North Sea: a Fault-Block Structure with Upper Jurassic Beach-Bar Reservoir Sands. American Association of Petroleum Geologists, Bulletin, 59, 1581-1601. WILLS, J. M. 1991. The Forties Field, Blocks 21/10, 22/6a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 301-308. WINTER, D. A. & King, B. 1991. The West Sole Field, Block 48/6, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 517-526. WRIGHT, S. D. 2003. The West Brae and Sedgwick Fields, Blocks 16/06a & 16/ 07a, U K North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 223-231. WYATT, M., BOWEN, J. M. & RHODES, D. N. 1992, The Nelson Field: a successful application of a development geoseismic model in North Sea exploration. In: HARDMAN, R. F. P. (ed.) Exploration Britain- Geological insights for the next decade. Geological Society, London, Special Publications, 67, 283-305. YALIZ, A. 1991. The Crawford Field, Block 9/28a, UK North Sea. In: A~BOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 287-294. YALIZ, A. & MCK1M, N. 2003. The Douglas Oil Field, Block 110/13b, East Irish Sea. In: GLUYAS, J. G. & HICHENS, H, M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 63-75. YALIZ, A. & TAYLOR, P. 2003. The Hamilton and Hamilton North Gas Fields, Block l10/13a, East Irish Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 77-86. YALIZ, A. & CHAPMAN, T. 2003. The Lennox Oil and Gas Field, Block 110/15, East Irish Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 87-96. YIELDING, G. 1990. Footwall Uplift associated with Late Jurassic normal faulting in the northern North Sea. Journal of Geological Society, 147, 219-222. YIELDING, G., BADLEY,M. E. & ROBERTS, A. M. 1992. The structural evolution of the Brent Province. In: MORTON, A. C., HASZELDINE,R. S., GILES, M. R. & BROWN, S. (eds) Geology of the Brent Group. Geological Society, London, Special Publications, 61, 27-43. YOUNG, M. J., GAWTHORPE, R. L. & HARDY, S. 2001. Growth and linkage of a segmented normal fault zone: the Late Jurassic MurchisonStatfjord North Fault, northern North Sea. Journal of Structural Geology, 23, 1933-1952. ZIEGLER, P. A. 1982. Geological Atlas of Western and Central Europe. Elsevier, Amsterdam. ZIEGLER, P. A. 1987. Late Cretaceous and Cenozoic intra-plate compressional deformations in the Alpine Foreland - geodynamic model. Tectonophysics, 137, 389-420. ZmGLER, P. A. 1990a. Geological Atlas of Western and Central Europe. Elsevier Scientific Publishing Co., Amsterdam (2 vols). ZIEGLER, P. A. 1990b. Tectonic and palaeogeographic development of the North Sea rift system. In: BLUNDELL, D. J. & GIBBS, A. D. (eds) Tectonic Evolution of the North Sea Rifts. Oxford Science Publications, Oxford, 1-36.
DOUGLAS OIL FIELD Hamilton Field. This is overlain by the Calder Sandstone Member (Wilmslow Sandstone equivalent), a sequence of predominantly fine- to medium-grained sandy braided river deposits. These two members form the St. Bees Sandstone Formation. The overlying Ormskirk Sandstone Formation (Helsby Sandstone equivalent) is the principle reservoir target in the East Irish Sea Basin. It consists of fluvial and aeolian sandstones of variable grain size. Many of the fluvial sands have a high proportion of reworked aeolian grains and there are rapid thickness variations of fluvial and aeolian facies. The Ormskirk Sandstone Formation is divided into three members: OS 1, OS2a and OS2b, which were formerly known as the Thurstaston, Delamere and Frodsham Members, respectively (Meadows & Beach 1993). These can be easily recognized on the Wirral and in all the wells drilled in Block 110/13. They exhibit very distinct gamma ray and sonic log characteristics. The OS1 Member includes a mixed sequence of fluvial and aeolian sediments. The OS2a Member is predominantly fluvial with occasional playa lake claystones. The uppermost OS2b Member represents predominantly aeolian conditions, although a sequence of fluvial facies is present in the middle of the unit. The Mercia Mudstone Group consists of a cyclic sequence with alternating sandy mudstones and Halites. The Rossall and Mythop Halites are each less than 50 ft thick and the Preesall Halite has a thickness of around 500 ft.
Structure Three principal seismic marker horizons can be identified from the 3D seismic data: Top Ormskirk Sandstone Formation (top reservoir); Top Collyhurst Sandstone Formation; and Top Carboniferous. Top Ormskirk pick is the most prominent and consistent seismic marker over the whole area. The main factors controlling seismic data quality over the Douglas Field are the variation of structural complexity, diffractions and other fault noise and seafloor conditions. The top reservoir map was depth-converted using a velocity v. seismic two-way-time function combined with a V0 value that varies spatially depending on the geology of the overburden. Latest development drilling has shown that the interpretation of a reliable top reservoir depth structure depends on a good understanding of the near surface formations. The structural history of the East Irish Sea Basin has been discussed in considerable detail elsewhere (Bushell 1986; Green 1986; Jackson et al. 1987; Stuart & Cowan 1991; Jackson & Mulholland 1993; Yaliz 1997). Structural interpretation of seismic data in Block 110/13 supports the view that post-Variscan tectonics were responsible for basin evolution and trap-forming events in the area (Fig. 3). Extension during the Early Permian led to half-graben structures with N-S faults controlling facies and thickness variations. All faults of the Permian framework of the area were active during the Triassic. As a result of continuing fault activity during the Early Triassic the Sherwood Sandstone Group shows a marked increase in thickness towards the Gogarth fault (Fig. 4). The overall thickness of this group in the Douglas area is around 3000ft compared with 5000 ft in the East Deemster basin (the Lennox area). Further rifting and extension took place during the late Triassic. The Mercia Mudstone Group of this age shows development of intermediate-scale structures and locally severe block-fault rotation. Due to the effects of erosion no Jurassic is seen in the basin, and extension during this period is inferred from data outside the area (Jackson et al. 1987). The post Jurassic history of the Douglas area is also difficult to constrain as the Triassic is immediately overlain by Quaternary drift. However, various authors have shown that the East Irish Sea Basin experienced a major phase of inversion and uplift during Tertiary (Lewis et al. 1992; Hardman et al. 1993; Williams & Eaton 1993; Cope 1994). Fault controlled structures formed during Triassic-Jurassic rifting were modified during early Tertiary inversion and new structures were generated. The Douglas structure is principally controlled by the Gogarth Fault, which is a shallow dipping (0-45~ N-S oriented feature lying to the west of Block 110/13 (Fig. 4). A deep master detach-
65
ment fault extending into Carboniferous shales gives rise to the Gogarth fault ramp-flat listric system beneath the Douglas Field. The topography of the Gogarth fault plane has played a major role in the development of the Douglas trap during extension and its adjustment during later inversion. Contractional movements (thrusting) along the Gogarth ramp-flat listric fault during Tertiary uplift caused the Douglas structure to move westwards to its present day position at the crest of an anticlinal feature. This gave rise to a small net extension at the Gogarth fault as the contractional movements stopped before a reverse fault was developed. The Hamilton Field lies on the eastern side of the crestal collapse graben within an antithetic fault province.
Trap The Douglas Field trap consists of three major fault blocks elongated N-S and dipping at approximately 15~ to the west (Figs 5 and 6). The Douglas trap was formed within the fault footwalls of these fault blocks during a major phase of extensional faulting in Triassic-Jurassic times. Drilling results have shown that the boundary faults are planar dipping at around 45 ~ to the east. Seismic data indicate that cross-fault transfer zones are not common at reservoir level, but a few widely spaced examples can be mapped from high resolution aeromagnetic data. The structure as a whole is fault bounded to the east, and dip closed to the north, west and south. The culmination of the structure is at 2140ft in the central fault
5 934 000
5 932 000
5 930 000
461 000
463 000
Fig. 5. Top reservoir depth structure map of the Douglas Field showing the exploration/appraisal and development well locations and the field-wide oilwater contacts.
DOUGLAS
OIL FIELD
67
Zonation and reservoir quality
indicate the development and migration of several dunes in response to increased sand supply. Aeolian sandsheet facies are characterized by single grain to millimetre scale horizontal and low angle, planar cross-stratification and are interbedded with aeolian dune sandstones as finely laminated sequences. Their thickness range is 0.5 to 1.5ft. This indicates that aeolian sandsheet conditions were episodically developed on a low relief plain. Aeolian Sabkha facies are very fine- to fine-grained, poor to moderately sorted and comprise subangular to well rounded grains. The individual beds range from 0.25 to 1.5ft in thickness and are characterized by an irregular flat lamination style. They typically occur as 5-10ft thick units which can be correlated over several kilometres within Block 110/13. They are almost always associated with the aeolian dune and aeolian sandsheet deposits and often contain high concentrations (up to 15%) of dolomite and anhydrite. Fluvial channel sandstones have been deposited within active and abandonment channels. They form stacked sand bodies which are poorly sorted and grade from fine to coarse sand. Sedimentary structures include low to moderate tabular cross-stratification with preserved set thicknesses ranging from 0.35 to 4ft, and flat laminations. A stacked sequence is commonly made of 10-12 channels and has an average thickness of about 15 ft. The sandstones are usually characterized by abundant small intraclasts which are dolomite cemented, green siltstone and pink very fine-grained sandstone fragments. Fluvial abandonment sediments are characterized by siltstone dominated units, 0.4 10 ft thick. They form the upper section of broadly fining-upward sequences of fluvial channel facies. Playa lake andfloodplain deposits are not common, but where present they form laterally extensive grey-black mudstone and siltstone units, generally occurring in the middle of fluvial channel sequences. They are considered to form effective vertical reservoir barriers due to their lack of any permeability.
The vertical distribution of sedimentary lithofacies in the Douglas wells can be subdivided into four distinct zones, which can be easily identified by wireline logs and core analysis data (Figs 9 and 10). Zones I, II and III are the OS2b, OS2a and OS1 Members, and Zone IV is the St. Bees Sandstone Formation. Zone I is further sub-divided into three parts. The uppermost Zone IA has a fairly uniform thickness of around 80 ft and consists of several units of aeolian dune and aeolian sandsheet alternating with aeolian sabkha sandstones. It is the most significant layer, containing almost half of the field's reserves. Permeability in the aeolian dune facies is often several darcies, while the porosities have a range of 20-30%. Zone IB, with an average thickness of 35 ft, is a low quality reservoir consisting of thinly interbedded fluvial channel and fluvial abandonment deposits. Zone IC with high permeability aeolian sandstones is similar to Zone IA but its thickness averages only 45 ft. Zone II consists exclusively of fluvial deposits, with its thickness increasing from 250 ft in the east to 350 ft in the west, towards the Gogarth fault. Zone III has a fairly uniform thickness of around 200 ft and includes a variety of aeolian dune, sandsheet and aeolian sabkha facies. Very little oil is present in Zone III. Zone IV consists of fluvial sandstones and is principally mapped as an aquifer. The reservoir characteristics of each zone based on core porosity and permeability data are illustrated in Figure 11. A good log-linear relationship exists between the porosity and permeability values in all zones except Zone II. However, the slope and the intercept of the regression lines show slight differences between zones. The 'shotgun effect' seen in Zone II data is thought to be an artifact of the numerous small shale clasts it typically contains. The highest porosity and permeability values (27% and 10 000 md, respectively) were measured in the aeolian dune and sandsheet facies in Zones IA
South
North 110/13-6 GR
MO
~! .... _ -- ~i
~d----7-1, ,,oi,.
110113-13
110/13-10
110t13-2 GR
SONIC
GR
.......>~ -.
SS
SONIC
GR g
-{
-"
4~
MD
SONIC
,
MD
110113-11
SONIC ,, ......
GR
~_.~
,I
MO
SONIC
t, '
-~~i,
J
_5: ~
-
-
If
-
4 9
,
I
~
.....
~.c~
"
-
"2400
"
~
"
~ .
]
!
.
,,-
_
-
o "~ ...._.~ ~
- 2780 -
~
~
JN00
-
9
.
-
~u~,
=
,,
'-'
'
9
"Y i -
~
9
2ZO0
-
?
*
_
"%
1
: 9
_ 1
.
,.,..
.
F'-- "-~. 110113b I BHP
i
;g-
:
I
L I
[e
N
E
i
r
~
1
.
.
.
.
.
,~,w
I
~1(;"; i,:
1 ;
,,
(
i-]
9
~
'
Fig. 9. Reservoir zone correlation between the exploration/appraisal wells in the Douglas Field. Individual sandstone units can often be correlated over several hundred metres.
DOUGLAS OIL FIELD I ? I
TRIASSIC
I ?
JURASSIC
71 I ?
CRETACEOUS
TERTIARY
I
BIODEGRATION I!~!i!!!!!i!i!iiiiiiiiiiiiiiiiiiiiiiii!i!!!]WATER WASHING [.. ,. ,:.:.:.:.:..:.............
..,,c.
INCR. WAXINESS ::::::::::::::::::::::::::::::
HIC's lost
Low GOR
t:.: :::.:+::-::-:~+:.::.:.~:.:.:+:.
Very light condensate charge
NHG's (N2, C02, H2S)
OII Window
!i:
:
" Condensate
I .................... :'il
'i
Early oil, few traces left
Main oil charge
'
Light-medium /~
Bitumens
I Depth of Source Rock
gravity,
non-waxy, sweet
.
- Dry Gas
t:,~. . . . . . . . . i.......... ::1
Fig. 14. Hydrocarbon filling history of the Douglas Field showing at least two oil and one light condensate charges during the Jurassic and Cretaceous. for peak gas generation (1.2%) and approaches the base oil window threshold (1.3%). The source rocks for the Douglas Field are considered to be fairly local, probably lying towards the southwestern part of the field where they have reached the required thermal maturity levels to generate the Douglas oil (Fig. 13).
Outcrops of Namurian Holywell Shales in North Wales contain rocks rich in amorphous organic material, with TOC values of 2-5%. Seismic data and drilling information have shown that the Namurian Holywell Shales are present in Block 110/13 and these rocks are believed to be the source rocks for the Douglas oil (Armstrong et al. 1997). Evaluation of the cuttings samples from the Namurian interval of the Hamilton well 110/13-1, which is 8 km NE of the Douglas Field, revealed the presence of significant amounts of organic carbon, with TOC ranging between 1.0 and 1.6%. The range of vitrinite reflectance values showed a wide range from 0.55% to 1.17 %. It was concluded that the present day maturity level of these sediments is in the range 1.15-1.19%, which is close to the threshold
110113-2
Hydrocarbon filling history Various proprietary studies by the Geochem Group on a suite of oil and gas samples from the Douglas and Lennox Fields indicate that the hydrocarbon filling histories in these fields were complex but
110113-D2
SW
NE
2000' 2100' Mercia Mudstone 2200'
1 1
~.
2300' U) O
I
i~
21110'
Q-
2~0'
i... 11
.
x
.,,.-
<- . . . . . . . . . .
"
r- OWC-
II
2600' I I
2700'
I
i
I
II11 -" ~" \
I
2800'
1
2900'
....-
.-
IV I
0
I
..-"
1
1
11
I 11
1
1 ..,~1 I
1 1 t i
1
III
I I
11"*"
v - ~-"
"IV
I % ~ II
1 1
I
1
III
100m
Fig. 15. Geological interpretation along wells 110/13-2 and 110/13-D2. The actual position of the boundary fault was found to be approximately 60m further west than prognosed and as a result the producer well D2 was completed in Zone I only.
74
A. YALIZ & N. McKIM
Hydrocarbon volumes and development plans
Douglas Field data summary
The current estimated oil-in-place, based on volumetrics calculations, is 202 MMBBL. At Annex B approval the STOIIP estimate was 225 MMBBL. The decrease to the current value results from improved geological understanding. Firstly, within the bitumen layer log-derived effective porosities were overestimated because of uncertainties in the fluid and matrix density values. Well data has confirmed the presence and extent of the bitumen zone which gently dips (1-2 ~) north-northwest. Secondly, prediction of the major fault positions from the 3D seismic data proved to be difficult, as illustrated by well 110/13-D2 in Figure 15. As a result, the seismic data were reprocessed using pre-stack depth migration techniques. The decreased STOIIP has been countered by a better than expected production performance. Contrary to earlier predictions no deterioration of the reservoir quality was observed near the faults, where log analysis indicated excellent porosities. Further, communication between fault blocks and reservoir layers has been better than expected. These factors lead to an expectation of improved waterflood sweep efficiency. Field pressure maintenance is achieved by a combination of natural aquifer influx and sea-water injection. Despite the large volumes, the aquifer has contributed only some 20% of the total pressure support. Between 1994 and 1999 ten producers and six water injectors were drilled, most being long step-out wells. Currently, however, one of the producers is being used as a condensate injector and one of the water injectors is a gas injector. Typical well trajectories for both producers and injectors are illustrated in Figure 16. Long step-out wells have S-shaped paths with a long horizontal section in the Mercia Mudstone. The wells are designed to penetrate the reservoirs parallel to the major fault planes. The producers are placed near the crest of each tilted fault block, between 50 and 75 m away from the fault plane. By placing the producers close to faults the recovery of the 'attic' oil beneath the fault planes is greatly improved during the waterflood. All production wells have an electrical submersible pump (ESP) for artificial lift, which are placed just above the top reservoir. The Douglas Field forms part of BHP Petroleum's Liverpool Bay Integrated Development scheme as illustrated in Figure 17. Douglas complex is also designed to handle the processing and export of hydrocarbons from the Hamilton (gas), Hamilton North (gas) and Lennox (oil and gas) fields. The first oil was produced in February 1996, and the expected field life is up to 15 years. Water injection rates vary according to average production rates so that sufficient voidage replacement is achieved in each block of the field. The Douglas complex dehydrates and sweetens the Douglas and Lennox oils prior to their export via pipeline to an offshore storage barge. A subsea pipeline transports crude from the Douglas complex to an offshore loading unit. The Hamilton and Hamilton North gas goes to BHP Petroleum's Point of Ayr terminal. After further processing and the sulphur removal at the terminal, the gas is delivered to PowerGen's power station at Connah's Quay. Forward field development planning is being based on a full field 3D geocellular model, providing a much improved structural model and reservoir facies description. The geological grid was constructed with 50 x 50 • 1 m grid cells and 120 layers resulting in a total of one million cells for the full field. A facies grid is shown in Figure 18. The geological grids were upscaled to a simulator model with a cell size of 50 x 100 x 5 m. This model has been history matched with three years of production data and is now providing a means to optimize future development drilling plans.
Trap Type Depth to crest Hydrocarbon contacts Oil column
Structural 2140 ft TVSS 2515-2535 ft TVSS 375 ft max
Main pay zone Formation Age Net/gross ratio Cut-off for N/G Porosity average Permeability average (air) Productivity index
Ormskirk Sandstone Triassic 0.90-1.0 3 mD 18% Zone I, 13.7% Zone II 2000 mD Zone I, 300 mD Zone II 5-30 BOPD/PSI
Hydrocarbons Oil gravity Oil type Bubble point Gas/oil ratio Formation volume factor
44~ API Low sulphur 285 PSI 170 SCF/BBL 1.075 RB/STB
Formation water Salinity Resistivity
270 000 ppm NaC1 equivalent 0.030 ohm-m at 30~
Reservoir conditions Temperature Pressure Pressure gradient in reservoir
30~ l125PSI at 2240ft TVSS 0.35 PSI/ft
Field size Area Gross rock volume STOIIP Drive mechanism
6.5 sq km 240 000 ac-ft 202 MMBBL water injection
This paper is published by permission of BHP Petroleum Ltd and the Liverpool Bay Group participants; LASMO (ULX) Ltd and Centrica plc. Contributions of N. Meadows, S. Habesch and N. Bailey of Geochem Group to the understanding of the sedimentology and the geochemistry of the field, H. E. Edwards to the understanding of the structural history, and all efforts of C. Bryan in interpreting the complex seismic data are gratefully acknowledged.
Production Start-up date Development scheme
Number/type of wells
February 1996 Central 24-slot wellhead tower, oil exported via pipeline to offshore storage unit for export by tanker. 5 exploration/appraisal 11 producers 7 water injectors
References ARMSTRONG, J. P., SMITH, J., D'ELIA, g. A. A. & TRUEBLOOD,S. P. 1997. The occurrence and correlation of oils and Namurian source rocks in the Liverpool Bay-North Wales area. In: MEADOWS, N. S., TRUEBLOOD,S. P., HARDMAN,M. & COWAN,G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 195-211. BUSHELL, T. P. 1986. Reservoir geology of the Morecambe Field. In: BROOKS, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N.W. Europe. Geological Society, London, Special Publications, 23,
189-208. COPE, J. C. W. 1994. A latest Cretaceous hotspot and the south-easterly tilt of Britain. Journal of the Geological Society, London, 151, 905-908. GREEN, P. F. 1986. On the thermotectonic evolution of Northern England: evidence from fission track analysis. Geological Magazine, 123, 493-506. HARDMAN, M., BUCHANAN, J., HERRINGTON, P. 8z. CARR, A. 1993. Geochemical modelling of the East Irish Sea Basin: its influence on predicting hydrocarbon type and quality. In: PARKER,J. R. (ed.) Petroleum Geology of North West Europe." Proceedings of the 4th Conference. Geological Society, London, 809-821.
DOUGLAS OIL FIELD HERRIES, R. D. & COWAN, G. 1997. Challenging the 'sheetflood' myth: the role of water-table-controlled sabkha deposits in redefining the depositional model for the Ormskirk Sandstone Formation (Lower Triassic), East Irish Sea Basin. In: MEADOWS,S. S., TRUEBLOOD,S. P., HARDMAN, M. 8~ COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 253-276. JACKSON, D. I., JOHNSON, U. ~ SMITH, N. J. P. 1997. Stratigraphical relationships and a revised lithostratigraphical nomenclature for the Carboniferous, Permian and Triassic rocks of the offshore East Irish Sea Basin. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 11-32. JACKSON, U. I. & MULHOLLAND,P. 1993. Tectonic and stratigraphic aspects of the East Irish Sea basin and adjacent areas: contrasts in their postCarboniferous structural styles. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the 4th Conference. Geological Society, London, 791-808. JACKSON, D. I., MULHOLLAND, P., JONES, S. M. & WARRINGTON, G. 1987. The geological framework of the East Irish Sea basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham and Trotman, London, 191-203. LEwis, C. L. E., GREEN, P. F., CARTER, A. & HURFORD, A. J. 1992. Elevated K/T palaeotemperatures throughout Northwest England: three
75
kilometres of Tertiary erosion? Earth and Planetary Science Letters, 112, 141-145. LOMANDO, A. J. 1992. The influence of solid reservoir bitumen on reservoir quality. Bulletin of the American Association of Petroleum Geologists, 76, 1137-1152. MEADOWS, N. S. & BEACH, A. 1993. Structural and climatic controls on facies distribution in a mixed fluvial and aeolian reservoir: the Triassic Sherwood sandstone in the Irish Sea. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Fluvial and Aeolian Reservoirs. Geological Society, London, Special Publications, 73, 247-264. STUART, I. A. • COWAN, G. 1991. Morecambe Gas Field, Blocks 110/2a, 110/3a, 110/Sa, U.K. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 527-541. WILLIAMS, G. D. & EATON, G. P. 1993. Stratigraphic and structural analysis of the Late Palaeozoic-Mesozoic of NE Wales and Liverpool Bay: implications for hydrocarbon prospectivity. Journal of the Geological Society, London, 150, 489-499. YALIZ, M. A. 1997. The Douglas Oil Field. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 399-416.
The Hamilton and Hamilton North Gas Fields, Block l10/13a, East Irish Sea A. YALIZ
& P. T A Y L O R
B H P Billiton Petroleum, Neathouse Place, London S W 1 V 1LH, UK (e-mail."
[email protected] and phil.
[email protected]) Abstract: The Hamilton and Hamilton North Fields are located in Block 110/13a in the East Irish Sea, and contain 627 BCF and 230 BCF GIIP, respectively. First gas was produced from the Hamilton North Field in December 1995. The fields are being developed with four producers in the Hamilton Field and three in the Hamilton North Field. The Hamilton Field structure consists of a N S trending horst block with dip closure to the north and south, while the Hamilton North structure is defined by major faults to the north and west with dip closure to the east and south. The gas is trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprises high porosity aeolian and fluvial sandstones. Depth to reservoir is shallow (2300-2600 ft) with the gas-water contact being at 2910 ft in the Hamilton Field and 3166 ft in the Hamilton North Field. Reservoir quality is principally controlled by primary depositional processes and no significant diagenetic effects are observed. The hydrocarbon filling history was complex, with at least two phases of hydrocarbon generation. Hamilton North gas is sweet whereas the Hamilton gas contains up to 1100ppm H2S, which is removed during processing at the Douglas complex and at the Point of Ayr gas terminal. Cumulative gas production to May 1999 was 180 BCF and no water-cut has been observed to date.
Fig. 1. East Irish Sea Basin exploration and development activity map showing the locations of the Hamilton and Hamilton North Fields together with the discovery to appraisal wells. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 77-86.
77
78
A. YALIZ & P. TAYLOR
History The Hamilton and Hamilton North Fields are situated in Block 110/13a of the East Irish Sea about 13 km from the Lancashire coast in 30m of water (Fig. 1). Block 110/13 was awarded to the P710 Licence Group as part of the 1 l th U K offshore licensing round in 1989. The current unit participants are BHP Petroleum Ltd (46.1%), Lasmo (ULX) Ltd (45.0%) and Centrica Resources Ltd (8.9%). The Hamilton Field was discovered in 1990 by well 110/13-1 and the Hamilton North Field by well 110/13-5 in 1991 (Fig. 1). Both wells were drilled on a sparse grid of speculative seismic data shot in 1986-1987. Well 110/13-1 (Fig. 2a) encountered a pay section of 508 ft, with an average permeability of 1 d, and well 110/13-5 (Fig. 2b) found a 474 ft gas column. The quality of the Ormskirk Sandstone reservoir was extremely high with average porosities of 19% in the Hamilton Field and 14.1% in the Hamilton North Field. Well 110/13-1 was tested over two separate intervals of 190ft and 170 ft, at a rate of 35 M M S C F / d each, and well 110/13-5 was tested over an interval of 170 ft at a rate of 70 MMSCF/d, both through a 2" choke. Hamilton Field appraisal was completed with the drilling of further two wells, 110/13-3 and 110/13-4, which confirmed the extension of the field to the north and south. No appraisal wells were drilled in the Hamilton North Field. A 3D seismic survey was acquired over Block 110/13 in 1992, and Annex B approval of the field development was given in the same year. Four gas producers in the Hamilton Field and three producers in the Hamilton North Field were drilled between 1995 and 1998 (Fig. 2). The Hamilton North Field has been producing gas since December 1995. Gas production from the Hamilton Field
started later in February 1997. The fields are developed as part of the Liverpool Bay Integrated Development scheme with an unmanned platform at each field connected to the Douglas Complex via gas export pipelines. The produced gas is delivered via BHP Petroleum's Point of Ayr terminal to PowerGen's power station at Connah's Quay.
Stratigraphy A generalized stratigraphic column for Block 110/13 based on Jackson et al. (1997) is shown in Figure 3. Carboniferous Hollywell Shale Formation is the oldest rock penetrated in the area, and is predominantly clastic with deep water shales deposited via a broad fluvio-deltaic regime that existed across north and east England during the Namurian. The Hollywell Shale is the source rock for gas in the area. The overlying Permian, above a major unconformity, consists of desert sandstones (Collyhurst Sandstone Formation) and red mudstones (Manchester Marl Formation). The Triassic is divided into the Sherwood Sandstone Group and the Mercia Mudstone Group. The former consists of sandstones, siltstones and mudstones deposited in a semi-arid environment, whilst the latter is composed of shales and thick halite units deposited in lakes subject to periodic flooding and desiccation, and forms a laterally extensive and competent seal over the Hamilton and Hamilton North Fields. The reservoir rocks can be correlated with those found offshore in the Douglas and Lennox Fields (Fig. 1) and onshore in the
Fig. 2. Top reservoir depth structure maps of the Hamilton and Hamilton North Fields showing development well locations.
HAMILTON AND HAMILTON NORTH GAS FIELDS 0
GR
150
140 Quaternary Dowbdclge Mudstone Mix
1000
Preesall HaliteFm
j~,_
Cleveleys Mudstone Mbr
MythopHaliteMbr BlackpoolMudMoneMbr Ros~ll HaliteMbr AnsdellMudstoneMM OS2bMbr OS2aMbr Ormskirk Sst Fm OSI Mbr
3000
CalderSst Mbr
~e
t. r-
4000
'i L
Sst Member
5OOO
- ~
ManchesterMarlFm
6000
7000
79
Wirral and the Cheshire Basin. The lowest unit is the Rottington Sandstone Member equivalent to the Chester Pebble Beds of the Cheshire Basin. This is overlain by the Calder Sandstone Member (Wilmslow Sandstone equivalent), a sequence of predominantly fine to medium grained, sandy, braided river deposits. These two members form the St. Bees Sandstone Formation. The overlying Ormskirk Sandstone Formation (Helsby Sandstone equivalent) is the principle reservoir target in the East Irish Sea Basin. It consists of fluvial and aeolian sandstones of variable grain size. The facies show rapid thickness variations. The Ormskirk Sandstone Formation is divided into three members; OS1, OS2a and OS2b, which were formerly known as Thurstaston, Delamere and Frodsham (Meadows & Beach 1993), respectively. They exhibit very distinct gamma ray and sonic log characteristics. The OS1 Member includes a mixed sequence of aeolian dunes and sandsheets. The OS2a Member is predominantly fluvial with some aeolian facies. The uppermost OS2b Member represents predominantly aeolian conditions but towards the south of the Hamilton Field fluvial facies replace the aeolian sandstones at the base of the unit. The Mercia Mudstone Group consists of a cyclic sequence of sandy mudstones and halites. The Rossall and Mythop halites are each less than 50 ft thick and the Preesall Halite has a thickness of between 500 and 730 ft.
Collyhurst 5st Fm
Structure
Fig. 3. The Hamilton Field discovery well 110/13a-I showing generalized stratigraphy in Block 110/13 of the Liverpool Bay development area. The reservoir rock is the Ormskirk Sandstone Formation and the source rock is the Hollywell Shale Formation.
Three principal seismic marker horizons can be identified from the 3D seismic data (Fig. 4): Top Ormskirk Sandstone Formation; Top Collyhurst Sandstone Formation; and the Permian/Carboniferous unconformity. The top Ormskirk pick is the most consistent seismic marker over the whole of Block 110/13 while the pick at the top Carboniferous unconformity is the poorest. A 3D seismic survey was acquired in March 1992 to cover Block 110/13, including the Hamilton, Hamilton North and Douglas Fields. A total of 2660 sail
Fig. 4. N-S seismic cross-section through the Hamilton Field showing the three principal seismic horizons: top Ormskirk Sandstone Formation; top Collyhurst Sandstone Formation; and the top Carboniferous unconformity. The top Ormskirk pick is the most consistent seismic marker over the whole of Block 110/l 3.
80
A. YALIZ & P. TAYLOR line kilometres of seismic data were acquired using three 120 channel 1500 metre streamers with a 12.5 metre group interval, operating at a depth of 6-7 m. This system was set-up to acquire data with four subsurface lines spaced 37.5 metres apart with in-line bin spacing of 12.5 metres. Shotpoint spacing was 25 metres on each sub-surface line which provided a fold of coverage of 3000%. The structural history of the East Irish Sea Basin has been discussed in detail elsewhere (Bushell 1986; Cope 1994; Green 1986; Jackson et al. 1987; Stuart & Cowan 1991; Jackson & Mulholland 1993; Williams & Eaton 1993; Yaliz 1997). The Hamilton and Hamilton North Fields are located on the southern edge of the East Irish Sea Basin within the Gogarth sub-basin (Fig. 5). The eastern edge of this sub-basin is bounded by the N - S trending East Deemster Fault and the western edge by the Gogarth Fault. The western edge of the Hamilton and Hamilton North horst structure is defined by the N - S trending Hamilton Fault, which throws the top Sherwood Sandstone Group down by several hundred feet below the gas-water contacts. Structural interpretation of seismic data in Block 110/13 indicates that extension during the Early Permian led to graben structures with N-S faults controlling facies and thickness variations. The fault activity continued during the Late Permian and the Triassic.
Trap
Fig. 5. Generalized structural elements of the East Irish Sea Basin (modified from Jackson et al. 1987). The Hamilton and Hamilton North Fields both lie on the Hamilton horst.
The Hamilton Field structure is a simple horst block, about 10 km long and 3 km wide, with a slight dip to the east, north and south (Fig. 6). The structure trends north-south and is cut by minor eastwest and north-south faulting. All faults within the field have sand to sand contact and do not provide barriers to gas flow. This has been confirmed by pressure data from the development wells. The trap is provided to the north and south by dip closure. The crest of the structure at the reservoir level is at around 2300 ft TVDSS with the gas-water contact being at 2910ft TVDSS.
Fig. 6. N-S and E-W structural cross-sections showing reservoir Zones I to IV through the Hamilton Field.
HAMILTON AND HAMILTON NORTH GAS FIELDS
(a)
South
81
North
110/13-5 N1
2,200
3,000-
3WC 3,1
~2 s 4,801Y
5,000.
(b)
West
East
110113-5 N3 N1 ~ N2
2,200 i
3,000-
~ i
i
8WC 3,166
4,000-
1
500 m
5,000
Fig. 7. N-S and E-W structural cross-sections showing reservoir Zones I to IV through the Hamilton North Field.
The Hamilton North Field block lies at the northern end of the Hamilton horst feature running through Block 110/13. It is a simple fault block 3 km long and 2 km wide with the main dip to the south (Fig. 7). The northern part of the field is progressively down-faulted by a set of E - W trending faults, which are antithetic to the main east-west boundary fault to the Deemster Platform. The crest of the structure at the reservoir level is at around 2600 ft TVDSS with the gas-water contact being at 3166 ft TVDSS. The top seal in both fields is provided by the Mercia Mudstone Group. However, the Ansdell Mudstone Member immediately above the Ormskirk Sandstone Formation (Fig. 3) is a finely laminated sandstone and mudstone sequence and gives rise to significant gas shows during drilling. For this reason the ultimate effective seal to the Hamilton and Hamilton reservoirs is considered to be the Rossall Halite with the Ansdell Mudstone being a 'waste' zone.
Reservoir
Depositional setting Facies distributions in the Fast Irish Sea Basin have been described by Meadows & Beach (1993) and Herries & Cowan (1997). Detailed facies analysis of cores and wireline logs has revealed the presence of six major facies types (Fig. 8): (1) Aeolian dune facies have preserved set thicknesses of 1-6 ft and suggest accumulation in the form of relatively small dunes. (2) Aeolian sandsheet facies are found interbedded with aeolian dune sands as finely laminated sequences with set thicknesses of 0.5 to 1.5 ft. (3) Aeolian sabkha facies are very fine to fine-grained, poorly to moderately sorted sandstone. The indi-
Fig. 8. Reservoir type log (110/13a-I) showing reservoir zonation and major facies associations in the Hamilton and Hamilton North Fields. Zones I and III comprise predominantly aeolian dune, aeolian sandsheet and sabkha sandstones, and Zones II and IV consist of stacked sequence of fluvial channel deposits.
vidual beds range 0.25 to 1.5 ft in thickness and typically occur in 5-10ft thick units which are correlatable over several hundred metres. (4) Fluvial channel facies have been deposited within active and abandonment channels. They form stacked sand bodies with preserved set thicknesses of 0.3 to 4ft. A stacked sequence is commonly made of 10-12 channels and has an average thickness of about 15 ft. (5) Fluvial abandonment sediments are dominated by units of siltstones which are typically 0.5-5 ft thick. (6) Playa lake andflood plain deposits are not common but they can form laterally extensive mudstone units giving rise to effective reservoir barriers.
Zonation and reservoir quality The Ormskirk Sandstone Formation has been divided into three distinct zones based on vertical distribution of sedimentary lithofacies (Figs 9 and 10): Zone I (OS2b), Zone II (OS2a) and Zone III (OS1). The underlying St. Bees Sandstone Formation contains a small amount of gas and for the purpose of volumetric estimates it is identified as Zone IV. Zone I is the uppermost reservoir unit and comprises predominantly aeolian dune and sabkha sandstones and has a rather uniform thickness of 170 ft in the Hamilton and 140 ft in the Hamilton North Fields. However, a thin unit (15-20 ft) of fluvial sandstones is present in the middle part of the zone. The upper parts of Zone I becomes fluvial-dominated towards the southern areas of the Hamilton Field as seen in well 110/13-4. Zone II predominantly consists of fluvial sandstones formed as a stacked sequence of channel deposits and varies in thickness between 165 and 220ft in
82
A. Y A L I Z & P. T A Y L O R
Well 1 1 0 / 1 3 a - H 4
Hamilton Field P r e s s u r e D a t a
Depth ff T V D S S -2300
R e s e r v o i r Section
= 110/13-1 .... . 110/13-3 110/13-4 9 110/13-H3 o t10/13-H4 ....
-2350gR
~g[
~,
a aa
irm t E[T
ta~Pae '"'"" ...... ~1
Zone & Porosity -2401
6067 (-2408) :
!
i
-2450
'
-2500
I
~ , ~ H 4 . , I ........
17.8% -2550
.~ ..~ -2600 /rr/ L n[
~
::;,o ;s, :::]
-265;"-
57~
-2700-
II
OBO0
Z erig na
depletion :;
11.7%
.
.
.
.
.
.
, ,~i, , P r e s s u r e .......... i Gradient
-27507aO~,
.........
,2~ ?!
-2850'
,i,, i............
III
-jg0o ,_ ....,]i
18.1%
GWC: 7345
1 ---,,
906) -2950 ......
-owu TD: 7653 MD (-3046 TVDSS)
IV 1 1 , 1 %
. . . . . . . . . . . . . . . . . .
,
9 ,, ,~,.....
..... i ......... X ....... :
l ....... :
-3050 1200
: i
....
:
1250
1300
X
i
1350
1400
................... k"
1450
; 1500
1550
1600
Pressure psi Fig. 9. A type well (110/13-H4) in the Hamilton Field showing reservoir zonation and zone characteristics. Zones I and Ill have the best porosities due to abundance of aeolian dune facies. The R F T pressure data shows that the reservoir has been depleted uniformly by 150 PSI indicating that there are no significant barriers to gas flow within the reservoir.
Well 1 10/13a-N3 Reservoir Section I
~rEEr L ~ - . . . . .
,UP.uJ. . . . . . .
.
Zone & Porosity
Depth ft TVDSS -2600
Hamilton North Field Pressure Data ol10/13-5
i 110/13-N3
-2700
Perfs. ~
aooo
I
13.3% ....................................... 2800
...... !ii_.,I i . ~ 6 5 84psi I
310(1
-2900
3200
II
J
12.6%
Original Pressure
I -3000
Gradient
I
33 O0
-3100
GWC (Logs):
31 5
3394 (-3161)
III
14.6%
[
3166'
i
-3200
psi
3500
-dJUU 3000
IV
13.5% -3400
-3500 . . . . . . . . 1400 1500
" ' ' . . . . . . . . . 1600 1700
! 1800
P r e s s u r e psi Fig. 10. A type well (110/13-N3) in the Hamilton North Field showing reservoir zonation and zone characteristics. Zone I shows a lower average porosity than that in the Hamilton Field due to the aeolian dune facies being replaced by sabkha and fluvial channel facies. The R F T pressure data shows that the reservoir has been depleted uniformly by 65 PSI indicating that there are no significant barriers to gas flow within the reservoir.
HAMILTON AND HAMILTON NORTH GAS FIELDS Table 1. Summary of reservoir characteristics in Hamilton Field
Zone
Thickness (ft)
Porosity (%)
Permeability (Geometric avg. rod)
Reservoir quality
1
160-180
2 3 4
165-220 165-195 200+
18.6 11.2 17.8 13.1
2100 320 370 320
Excellent Moderate Good Moderate
giving rise to minor carbonate and illite precipitation. A late stage influx of sulphate-rich fluids is indicated by the presence of anhydrite cements.
Reservoir fluid parameters Extensive laboratory analysis have been performed on gas samples obtained during drill stem tests. The fluid compositions are summarized in Table 3. Both fields contain a dry gas with 83 tool% methane, 8.2 tool% nitrogen and a condensate/gas ratio of 2-4 stb/ mmscf. The Hamilton gas is sour containing about 1100 ppm HzS whereas the Hamilton North gas contains less than 30ppm H2S. The gas expansion factors and the initial gas viscosities are 108 and 120 S C F / R C F and 0.0139 and 0.0175cP in the Hamilton and Hamilton North Fields, respectively. The reservoir temperature is only 30~ and the formation water is highly saline with NaC1 content greater than 300 000 ppm
Table 2. Summary of reservoir characteristics in Hamilton North Field
Zone
Thickness (ft)
Porosity (%)
Permeability (Geometric avg. md)
Reservoir quality
1 2 3 4
140 255 230 200+
14.7 13.0 17.0 13.0
400 240 350 240
Good Moderate Good Moderate
83
Source Rock and Hydrocarbon Migration Carboniferous strata, occurring at various stages of thermal maturity, are present throughout the East Irish Sea Basin and contain the hydrocarbon source rocks (Fig. 1 I). Namurian prodelta to basinal shales have been identified as the source rock for both the sour gas and oil in all Liverpool Bay fields where no Westphalian sediments (the source rocks for the sweet Morecambe Field gas) were preserved (Hardman et al. 1993; Armstrong et al. 1997). The Namurian source rocks were penetrated beneath the Hamilton Field in well 110/13-1 at depths of 8000-9000 ft. Hydrocarbon filling history of the fields was complex. An early phase of oil generation, possibly during Jurassic times, is indicated by traces of bitumen seen throughout the Hamilton reservoir. Trace amounts of bitumen were emplaced probably during the Late Jurassic as a result of degradation of early phase of oil by gas deasphalting and/or water-washing processes. The bitumen is found mainly in the coarse grained laminae of the cross-bedded aeolian units throughout the reservoirs. Due to subsequent breaching during the Cimmerian uplift and erosion all live hydrocarbons including the gas were lost. After the source rocks entered the dry gas zone, the main phase of hydrocarbon gas generation took place during the Late Cretaceous and Tertiary giving rise to the present gas accumulations. Small amounts of nitrogen, carbon dioxide, hydrogen sulphide and mercaptans were also produced and migrated into the reservoirs. Due to a major phase of inversion and uplift during Palaeogene all post-Triassic rocks were eroded from the area (Cope 1994). However, the hydrocarbon accumulations appear to have survived this Tertiary uplift and erosion.
the Hamilton Field but shows a rather uniform thickness of 255 ft in the Hamilton North Field. Zone III is a mixed sequence of aeolian dune, aeolian sabkha and minor fluvial channels and shows a thickness variation between 165 and 195 ft in the Hamilton Field. In the Hamilton North Field it has a uniform thickness of 230 ft. Zone IV comprises a stacked sequence of fluvial channel deposits 200+ ft in thickness. Zone I has the best reservoir quality with an average porosity value of 18.6% in the Hamilton Field and 14.7% in the Hamilton North Field. Reservoir quality in Zone II is relatively poor with the average porosity varying between 11 and 13% throughout the area. The average porosity in Zone III is around 17.5% in both fields. The net/gross sand ratio in both fields is very high and varies between 80 and 100%. Fluvial abandonement and playa lake facies are the only potential permeability barriers. However, pressure data (RFT) from the recent development wells have shown that the reservoir has been depleting uniformly indicating that no field-wide permeability baffles or barriers exist. A summary of reservoir characteristics of the zones is given in Tables 1 and 2.
Diagenetic history The Ormskirk Sandstone Formation is classified as a subfeldspatic arenite, with 5-25% feldspar. Textural maturity is broadly related to facies type with aeolian sandstones being the most mature. Clay cements are practically absent in both fields. The authigenic minerals occur in minor amounts (1-3%) and have no effect on reservoir quality. They consist of carbonates (ferroan and nonferroan calcite and dolomite), quartz, gypsum, anhydrite, feldspar, pyrite, illite, chlorite and halite. Early compaction resulted in the onset of minor quartz overgrowths. During later stages (Triassic to Tertiary) the ionic concentration of the remaining fluids increased
Hydrocarbon volumes and development plans The current gas in-place estimates in the Hamilton and Hamilton North Fields are based on material balance techniques and the most likely estimates are 627 BCF and 230 BCF, respectively. Table 4 summarizes the gas in-place estimates.
Table 3. Hamilton and Hamilton North Fields fluid compositions compared to other Liverpool Bay Fields' (mol% unless otherwise stated) Field
HzS
Mercaptans
N2
CO2
C!
C2
C3
C4
C5
C6+
Hamilton Hamilton North Lennox Oil Lennox Gas Douglas 'Lambda'
1100 ppm 30 ppm 0.12 400 ppm 0.5 0.01 ppm
-
8.3 8.1 1.7 12.3 0.7 9.3
0.4 0.4 0.1 0.1 0.1 0.04
83 83 30 77 2 82
5 5 7 5 4 5
1.5 1.8 7 2.5 5 1.8
1.1 1.3 7 1.4 8 1.3
0.5 0.6 5 0.5 7 0.6
0.3 0.5 41.3 0.5 72 0.4
450 ppm 1000 ppm -
84
A. YALIZ & P. TAYLOR
Fig. 11. A geological cross-section across the Liverpool Bay Fields (Douglas, Hamilton and Lennox) showing the relationship between the source rock (Namurian) and the reservoir rock (Sherwood Sandstone). Generated hydrocarbons migrated along various routes; along faults, vertically through the Collyhurst Sandstone and laterally along the base of the Mercia Mudstone seal. The Hamilton and Hamilton North gas was probably generated within the East Deemster Basin.
Fig. 12. Schematic map showing the Liverpool Bay integrated development scheme. The produced gas from the Hamilton and Hamilton North Fields is carried to the Douglas platform for processing before being transported to an onshore gas terminal for further processing.
HAMILTON AND HAMILTON NORTH GAS FIELDS
Table 4. Distribution o.1"GIIP (BCF) in the Hamilton and Hamilton
Reservoir conditions
North Fields"
Temperature Pressure Pressure gradient in gas leg Pressure gradient in water leg
Hamilton Field Hamilton North Field
P90
P50
P10
580 210
627 230
659 250
Two producers were drilled in The H a m i l t o n North Field in S e p t e m b e r - O c t o b e r 1995 followed by a third producer in October 1996 (Fig. 2b). The first three producers in the H a m i l t o n Field were completed between April and September 1996 and a forth producer was drilled in August 1998 (Fig. 2a). These seven producers currently have more than enough capacity to provide the required production rates. The producer wells are deviated having S-shaped profiles and were drilled from a small, not normally m a n n e d platform located at each field. The produced gas is transported to the Douglas Complex via a 14" pipeline from the H a m i l t o n N o r t h Field and via a 20" pipeline from the H a m i l t o n Field, as part of Liverpool Bay integrated development scheme as illustrated in Figure 12. After removing the liquids on the Douglas Complex the gas is transported to the B H P Petroleum's Point of Ayr gas terminal, where gas processing occurs to bring the gas into specification suitable for the C o n n a h ' s Quay gas fired power station. F o r w a r d field development planning is based on a full field model combining both fields, which has been history matched with three years of production data. Reservoir pressure data (RFT's) recorded in later producer wells indicate that the reservoirs are being depleted fairly uniformly and no significant barriers to flow are present. F o r example, the pressure depletions in wells 110/13-H4 (Hamilton Field in August 1 9 9 8 ) a n d 110/13-N3 (Hamilton N o r t h Field in October 1996) were 150 PSI and 65 PSI, respectively (Figs 9 and 10). There are currently no plans to drill additional wells. Cumulative gas production was 115 BCF from the H a m i l t o n Field and 65 B C F from the H a m i l t o n N o r t h Field by M a y 1999, and no water-cut from the fields has been observed to date. This paper is published by permission of BHP Petroleum Ltd and the Liverpool Bay Group participants; Lasmo (ULX) Ltd and Centrica plc. Thanks are due to N. Meadows, S. Habesch and N. Bailey of Geochem Group for their contributions to the understanding of the sedimentology and the geochemistry of the fields, and to H. E. Edwards for contributing to the understanding of the structural history of the area. Chris Bryan's seismic interpretations and Ali Abhvani and Stuart Catterall's modelling work during the initial stages of the development are gratefully acknowledged.
85
30~ 1404PSI at 2600ft TVSS 0.038 PSI/ft 0.51 PSI/ft
Field size
Area Gross rock volume GIIP Drive mechanism
15 sq km 1 100 000 ac-ft 627 BCF Natural water drive
Production
Start-up date Development scheme
Number/type of wells
February 1997 Central 6-slot wellhead tower, gas is exported via 20" pipeline to Douglas complex for processing and then exporting to gas terminal 3 exploration/appraisal 4 gas producers
Hamilton North Field data summary Trap
Type Depth to crest GWC Gas Column
Structural 2600 ft TVDSS 3166 ft TVDSS 466 ft
Main pay' zone
Formation Age Cut-off for N/G Porosity range Permeability range (air)
Ormskirk Sandstone Triassic No cut-off used 13-17% 240-400 md
Hydrocarbons
Gas gravity Heating value Condensate/gas ratio Gas expansion factor
0.67 1035 BTU/SCF 3.5-3.8 STB/MMSCF 120 SCF/RCF
Formation water
Hamilton Field data summary
Salinity Resistivity
300 000 ppm NaC1 equivalent 0.039 ohm-m at 30~
Trap
Type Depth to crest GWC Gas Column
Structural 230O ft TVDSS 2910 ft TVDSS 610ft
Reservoir conditions
Ormskirk Sandstone Triassic No cut-off used 11-19% 300-2100 md
Field size
Temperature Pressure Pressure gradient in gas leg Pressure gradient in water leg
30~ 1535PSI at 2900 ft TVSS 0.042 PSI/ft 0.51 PSI/ft
Main pay zone
Formation Age Cut-off for N/G Porosity range Permeability range (air)
0.65 1030 BTU/SCF 1.8-2.2 STB/MMSCF 108 SCF/RCF
Start-up date Development scheme
Nmnber/type of wells
Formation water
Salinity Resistivity
8 sq km 390 000 ac-ft 230 BCF Natural water drive
Production
Hydrocarbons
Gas gravity Heating value Condensate/gas ratio Gas expansion factor
Area Gross rock volume GIIP Drive mechanism
300000 ppm NaC1 equivalent 0.039 ohm-m at 30~
December 1995 Central 6-slot wellhead tower, gas is exported via 14" pipeline to Douglas complex for processing and then exporting to gas terminal 1 exploration 3 gas producers
86
A. YALIZ & P. TAYLOR
References ARMSTRONG, J. P., SMITH, J., D'ELIA, V. A. A. & TRUEBLOOD, S. P. 1997. The occurrence and correlation of oils and Namurian source rocks in the Liverpool Bay-North Wales area. In: MEADOWS,N. S., TRUEBLOOD, S. P., HARDMAN, M. &, COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 195-211. BUSHELL, T. P. 1986. Reservoir geology of the Morecambe Field. In: BROOKS, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N.W. Europe. Geological Society, London, Special Publications, 23, 189-208.
COeE, J. C. W. 1994. A latest Cretaceous hotspot and the south-easterly tilt of Britain. Journal of the Geological Society, London, 151, 905-908. GREEN, P. F. 1986. On the thermo-tectonic evolution of Northern England: evidence from fission track analysis. Geological Magazine, 123, 493-506. HARDMAN, M., BUCHANAN, J., HERRINGTON, P. & CARR, A. 1993. Geochemical modelling of the East Irish Sea Basin: its influence on predicting hydrocarbon type and quality. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe." Proceedings of the 4th ConJerence. Geological Society, London, 809-821. HERRIES, R D. & COWAN, G. 1997. Challenging the 'sheetflood' myth: the role of water-table-controlled sabkha deposits in redefining the depositional model for the Ormskirk Sandstone Formation (Lower Triassic), East Irish Sea Basin. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 253-276. JACKSON, D. I. & MULHOLLAND,P. 1993. Tectonic and stratigraphic aspects of the East Irish Sea basin and adjacent areas: contrasts in their post-
Carboniferous structural styles. In: PARKER, J. R. (ed) Petroleum Geology of North West Europe: Proceedings of the 4th Conference. Geological Society, London, 791-808. JACKSON, D. I., MULHOLLAND,P., JONES, S. M. & WARRINGTON, G. 1987. The geological framework of the East Irish Sea basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham and Trotman, London, 191-203. JACKSON, D. I., JOHNSON, H. & SMITH, N. J. P. 1997. Stratigraphical relationships and a revised lithostratigraphical nomenclature for the Carboniferous, Permian and Triassic rocks of the offshore East Irish Sea Basin. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. &, COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 11-32. MEADOWS, N. S. & BEACH, A. 1993. Structural and climatic controls on facies distribution in a mixed fluvial and aeolian reservoir: the Triassic Sherwood sandstone in the Irish Sea. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Fluvial and Aeolian Reservoirs. Geological Society, Special Publications, 73, 247-264. STUART, I. A. & COWAN, G. 1991. Morecambe Gas Field, Blocks 110/2a, l10/3a, 110/8a, U.K. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 527-541. WILLIAMS, G. D. & EATON, G. P. 1993. Stratigraphic and structural analysis of the Late Palaeozoic-Mesozoic of NE Wales and Liverpool Bay: implications for hydrocarbon prospectivity. Journal of the Geological Society, London, 150, 489-499. YALIZ, M. A. 1997. The Douglas Oil Field. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. &, COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, Special Publications, 124, 399-416.
The Lennox Oil and Gas Field, Block 110/15, East Irish Sea A. Y A L I Z
& T. C H A P M A N
B H P Billiton Petroleum, Neathouse Place, London S W 1 V 1 L H , U K (e-mail: ayk.
[email protected] and
[email protected])
Abstract: The Lennox Field, located in blocks 110/15 and 110/14, was the second oil field to be developed in the East Irish Sea Basin. It contains 184 MMBBL of oil in-place within a 143 ft thick oil rim overlain by a large gas cap up to 750ft thick. The GIIP is estimated to be 497 BCF. The field came on stream in February 1996, and it is now being developed with seven horizontal oil producers, including two multi-lateral wells and two crestal gas injectors. Production from the field can be divided into two distinct phases; the oil rim development phase, and the gas cap blow-down phase. The latter phase is currently anticipated to commence in 2004. The field structure consists of a roll-over anticline formed in the hanging wall of the Formby Point Fault during extensional faulting in Triassic-early Jurassic times, and later readjusted by contractional movements during Tertiary inversion. The oil and gas are trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprise high porosity aeolian and fluvial sandstones occurring at a shallow depth (c. 2500 ft) with a maximum gas column of 750ft above an oil rim of 143ft. The reservoir quality is principally controlled by primary depositional processes as no significant adverse diagenetic effects are observed. The hydrocarbon filling history was complex, with at least three phases of oil and gas generation. The field contains a light, saturated oil (45~ API) with a GOR of 650 SCF/BBL. The crude contains high levels of H2S (0. l mol%) and mercaptans (450 ppm), which are removed during processing at the Douglas complex. Water cut from the field is currently around 2-5%, and no free gas production has been observed to date. Gas production from Lennox is anticipated to start in 2004.
History The Lennox oil and gas field is situated in Blocks 110/15 and 110/14 of the East Irish Sea about 5 km from the Lancashire coast in 40 ft of water (Fig. 1). Block 110/15 was awarded to the P791 Licence Group as part of the 12th U K offshore licensing round in 1991. The current unit participants are BHP Petroleum Ltd (46.1%), Lasmo (ULX) Ltd (45.0%) and Centrica (8.9%). The field was discovered in 1992 by well 110/15-6 which was drilled at the crest of the Lennox structure at a depth of 2514ft TVDSS. The well encountered a 743 ft gas column overlying a 143 ft oil rim. The quality of the Ormskirk Sandstone reservoir was extremely high with the zonal average porosity varying between 13% and 20% and the permeabilities varying from a few hundred md to ten darcy. The oil leg in the well was tested over a small interval (30ft) at a rate of 870 BOPD through a 20/64" choke. A 20 ft interval in the gas zone was also tested at a rate of 61 mmscf/d through a 96/64" choke. Field appraisal was completed with the drilling of a further three wells; 110/15-6Z, 110/15-7 and 110/14-3. The latter was drilled by British Gas in December 1993 and confirmed the extension of a small part of the field into Block 110/14. Annex B approval of the field development was given in 1993 and a 3D seismic survey was acquired over the field in 1996. Based on the appraisal and development drilling results and the 3D seismic data, the field structure is interpreted to be a roll-over anticline about 4 km long and 4 km wide. Two gas injectors and seven horizontal oil producers were drilled between 1995 and 1998 (Fig. 2). The field has been producing oil since February 1996 and gas sales are expected to begin in 2004. The Lennox field has been developed as part of the Liverpool Bay Integrated Development scheme with an unmanned platform at Lennox connected to the Douglas Complex via oil and gas export and gas injection pipelines.
stones (Collyhurst Sandstone Formation) and red mudstones (Manchester Marl Formation). The Triassic is divided into the Sherwood Sandstone Group and the Mercia Mudstone Group. The former consists of sandstone, siltstone and mudstones deposited in a semi-arid environment, whilst the latter is composed of shales and thick halite units deposited in ephemeral lakes subject to periodic flooding and desiccation, and forms a laterally extensive and competent seal over the Lennox Field. The Lennox reservoir rocks can be correlated with those found in the Douglas and Hamilton fields, on the Wirral and in the Cheshire Basin. The lowest unit is the Rottington Sandstone Member consisting of a thick sandstone deposited in stacked fluvial channels (Chester Pebble Beds equivalent in the Cheshire Basin). This is overlain by the Calder Sandstone Member (Wilmslow Sandstone equivalent), a sequence of predominantly fine to medium grained sandy braided river deposits. These two members form the St. Bees Sandstone Formation. The overlying Ormskirk Sandstone Formation (Helsby Sandstone equivalent) is the principle reservoir target in the East Irish Sea Basin. It consists of fluvial and aeolian sandstones of variable grain size and is divided into three members; OS1, OS2a and OS2b, which were formerly known as Thurstaston, Delamere and Frodsham, respectively. They exhibit very distinct gamma ray and sonic log characteristics (see Fig. 3). The OS1 Member includes a mixed sequence aeolian dunes and sandsheets. The OS2a Member is predominantly fluvial with some aeolian facies occurring in discrete metre scale horizons throughout the section. The uppermost OS2b Member represents predominantly aeolian conditions but towards the west of the field fluvial facies replace the aeolian sandstones in the upper hundred feet of the unit due to lateral facies changes. The Mercia Mudstone Group consists of a cyclic sequence with alternating sandy mudstones and Halites. The Rossall and Mythop halites are each less than 50 ft thick and the Preesall Halite has a thickness of around 700 ft.
Stratigraphy Structure The geology of the Lennox field was originally described by Haig et al. (1997). A generalized stratigraphic column for Block 110/15 based on Jackson et al. (1997) is shown in Figure 3. Carboniferous Dinantian is the oldest rock penetrated in the area. Overlying this is the Hollywell Shale Formation, which is predominantly clastic with deep water shales deposited via a broad fluvio-deltaic regime that existed across north and east England during the Namurian. Although not penetrated in Block 110/15 the Permian is known, from drilling in Block 110/13, to consists of desert fluvial sand-
Three principal seismic marker horizons can be identified from the 3D seismic data; Top Ormskirk Sandstone Formation, Top Collyhurst Sandstone Formation and Top Carboniferous. The Top Ormskirk pick is the most consistent seismic marker over the whole Lennox area. The structural history of the East Irish Sea Basin has been discussed in detail elsewhere (Bushell 1986; Cope 1994; Green 1986; Jackson et al. 1987; Stuart & Cowan 1991; Jackson & Mulholland
GLUYAS, J. G. & HIeHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 87-96.
87
88
A. YALIZ & T. CHAPMAN
Fig. 1. East Irish Sea Basin exploration and development activity map showing the Lennox Field location.
1993; Williams & Eaton 1993; Yaliz 1997). Structural interpretation of seismic data in Block 110/15 indicates that extension during the Early Permian led to graben structures with N - S faults controlling facies and thickness variations. The fault activity continued during the Late Permian and the Triassic. The Lennox Field is located on the south-eastern edge of the East Irish Sea Basin within the East Deemster sub-basin (Fig. 4). The eastern edge of this sub-basin is bounded by the N - S trending Formby Point Fault which bisects Block 110/15 and gives rise to two distinct structural provinces: (1)
(2)
An eastern area where Carboniferous and Permo-Triassic rocks have not undergone extensive burial and where the Triassic Mercia Mudstone Group is thin or absent. A western area where deep burial has occurred followed by Tertiary inversion (Lewis et al. 1992; Hardman et al. 1993). The Mercia Mudstone and the Sherwood Sandstone groups
are thickly developed and are well preserved in this area. The throw on the Formby Point Fault is estimated from seismic data to be in excess of 6000 ft (Fig. 5).
Trap The Lennox structure is a faulted, roll-over anticline on the hanging wall of the Formby Point Fault. The structure has been formed in response to uplift of a ramp directly underlying the Lennox field followed by subsequent collapse. The field is fault bounded to the east and south and dip-closed to the west and north. The eastern part of the field consists of several westerly tilted fault blocks, as a result of antithetic faulting to the Formby Point Fault (Fig. 5). A horizontal well (L3) drilled in the eastern area proved the existence of several faults and severe fracturing. The western part of the
5945000
0 I I I
1 km i Depthsin Feet I ! L~____.
l
I I I Horizontal 0il 5943000
(in Fig. 5&9)
r
Fig. 2. Top reservoir depth structure map of the Lennox Field showing the locations of the exploration/appraisal and the horizontal oil producers drilled radially from a single platform. Porosity and permeability have been reduced in the eastern area due to faulting and fracturing associated with the Formby
L8 5 941 000
488000
486000 o
GR
1so
490 000
140
Sonic
4o Qua~mary Dowbddge Mudstone Mbr
I;
I
ID. O
1000
Preesall Halite Fm
i Cleveleys Mudstone Mix Mythop He!~ Mbr Blackpool Mudstone Mbr Rommll l'lulltw "ImUl Ansdell Mud~r Mbr OS2h Mbr OS2.aMbr Ormskirk Sst Fm OSI Mbr
zuoll
UIIlI--
lk i
i
j
,-mmn 3OO0
l
[
alL..
--
gl.
Calder Set Mbr
Rottington Sst Member 5OOO
t
L
~UMU
F
7OO0
Manchester Mad Fm
Collyhurst Set Fm ~r-
Fig. 3. Generalized stratigraphy in the Liverpool Bay development area as seen in the Hamilton Field discovery well 110/13a-1 (Fig. 1). The reservoir rock in all Liverpool Bay Fields is the Ormskirk Sandstone Formation and the source rock is the Holywell Shale Formation. The effective cap rock is considered to be the Rossall Halite with the Ansdell Mudstone forming a waste zone.
i ~r
8000
Holywell Shale Fm 900O
(.9
|
4UIRI
k
.!
90
A. YALIZ & T. CHAPMAN field shows little or no faulting and the structure gently dips (4-5 degrees) towards the north, west and south. The crest of the structure at the reservoir level is 2500 ft T V D S S with the gas-oil contact at 3257 ft T V D S S and the oil-water contact at 3400 ft TVDSS. The Ansdell M u d s t o n e M e m b e r lies above the Ormskirk Sandstone F o r m a t i o n a n d consists of finely laminated sandstone and m u d s t o n e sequences, and gives rise to significant gas shows during drilling. F o r this reason the effective ultimate seal to the L e n n o x reservoir is considered to be the Rossall Halite with the Ansdell M u d s t o n e being a 'waste' zone.
Reservoir
Depositional setting
Fig. 4. Generalized structural elements of the East Irish Sea Basin (modified from Jackson et al. 1987). The Lennox Field lies in the East Deemster Basin close to the Formby Point Fault.
Facies distributions in the East Irish Sea Basin have been described by M e a d o w s & Beach (1993) and Herries & C o w a n (1997). Detailed facies analysis of cores a n d wireline logs has revealed the presence of six m a j o r facies types: (1) Aeolian dune facies have preserved set thicknesses of 1-6 ft a n d suggest a c c u m u l a t i o n in the form of relatively small dunes. (2) Aeolian sandsheet facies are f o u n d interbedded with aeolian d u n e sands as finely laminated sequences with set thicknesses of 0.5 to 1.5 ft. (3) Aeolian sabkha facies are very fine to fine-grained, p o o r to m o d e r a t e l y sorted sandstones. The individual beds range from 0.25 to 1.5 ft in thickness and typically occur as 5 - 1 0 f t thick units which are correlatable over several h u n d r e d metres. (4) Fluvial channel facies have been deposited within active and a b a n d o n m e n t channels. They form stacked sand bodies with preserved set thicknesses of 0.3 to 4ft. A stacked sequence is c o m m o n l y m a d e of 10-12 channels and has an average thickness of about 15 ft. (5) Fluvial abandonment sediments are d o m i n a t e d by units of siltstones which are typically 0.5-5 ft thick. (6) Playa lake and flood plain deposits are not c o m m o n but they can form laterally extensive m u d s t o n e units giving rise to effective reservoir barriers with a thickness of up to 7 feet.
Fig. 5. E-W structural cross-section through the Lennox Field. The eastern area is highly faulted and fractured as seen in well L3. Seismic velocities in the eastern area are higher than anywhere else in the field. This was caused by significant changes in lithology across an antithetic fault which soles out towards the east at the top reservoir level. The line of section is shown on the Lennox map in Figure 2.
LENNOX FIELD
91
Fig. 6. Reservoir correlation and facies distribution in the Lennox Field. Zone 1 is predominantly aeolian dune and sandsheet facies, Zone 2 fluvial, and Zone 3 aeolian dune, aeolian sandsheet and fluvial facies. Playa lake facies occurring at the top of Zone 2 is considered to form partial barrier to fluid flow.
The facies units are well developed laterally and can be easily correlated between wells as shown in Figure 6 a facies correlation between wells 110/14-1, 110/15-7, 110/15-6Z and 110/15-6.
horizontal producer well 110/15-L3 (Fig. 2) where the porosities were found to be reduced by up to 3-4 porosity units due to intensive fracturing and granulation. A summary of reservoir characteristics of the zones is given in Table 1.
Zonation and reservoir quality The Ormskirk Sandstone Formation has been divided into three distinct zones based on vertical distribution of sedimentary lithofacies (Fig. 7): Zone 1 (OS2b), Zone 2 (OS2a) and Zone 3 (OS1). The underlying St. Bees Sandstone Formation contains very little hydrocarbons and for the purpose of volumetric estimates it is identified as Zone 4. Zone 1 is the uppermost reservoir unit and comprises predominantly of aeolian dune and sabkha sandstones with a fairly uniform thickness of around 260 ft. The upper parts of this zone (up to 100ft) become fluvial dominated towards the western areas of the field. Zone 2 with a thickness variation of 300-380ft, predominantly consists of fluvial sandstones although in some areas aeolian dune and sabkha sandstones are equally important. Zone 3 is a mixed sequence of aeolian dune, aeolian sabkha and fluvial channels and shows a thickness variation between 250 and 320ft. Zone 4 comprises a stacked sequence of fluvial channel deposits and its thickness is assumed to be 200 ft for calculation of gross rock volume. Zone 1 has the best reservoir quality with field average porosity and permeability values of 18 % and 1 darcy, respectively. Reservoir quality in Zone 2 is relatively poor with average porosity being 13%. However, where aeolian dune sandstones are present the reservoir quality matches that of Zone 1. The average porosity in Zone 3 is 15.5% and permeability is around 500 md. The eastern part of the field has been much affected by faulting and fracturing associated with the nearby Formby Fault. This has caused significant degradation in the reservoir quality as seen in the
Diagenetic history The Ormskirk Sandstone Formation is classified as a subfeldspatic arenite, with 5-25% feldspar. Textural maturity is broadly related to facies type with aeolian sandstones being the most mature. Clay cementation is practically non-existent in the Lennox Field. The authigenic minerals consist of carbonates, quartz, gypsum, anhydrite, feldspar, pyrite, illite, chlorite and halite. Early compaction resulted in the onset of minor quartz overgrowths. During the mesogenesis phase (Triassic to Tertiary) the ionic concentration of the remaining fluids increased giving rise to carbonate and illite precipitation. A phase of bitumen emplacement took place during Late Jurassic? as a result of degradation of early phase of oil upon uplift and water washing. The bitumen is found mainly in the uppermost 40-50 ft of the reservoir. A late stage influx of sulphaterich fluids is indicated by the presence of anhydrite cements which post date bitumen. The authigenic cements have limited effect on reservoir quality which is mainly controlled by primary depositional parameters, including grain size, grain type and textural maturity. The only cements which occur in quantities sufficient to affect reservoir quality are quartz overgrowths and carbonates, and this only occurs in the fluvial channel sandstones. The amount of total cement is estimated to be 10-15% in the fluvial channel sandstones and 0-5% in the aeolian sandstones.
92
A. YALIZ & T. CHAPMAN a GOR of 650 SCF/STB. The oil viscosity is 0.5 cP at reservoir conditions and the bubble point is 1620 PSIA. The formation factor for oil is 1.3 rb/stb and the gas expansion factor is 125 SCF/RCF. The fluid compositions of the gas and oil are summarized in Table 2.
L e n n o x Well 110/15-L1
Zone l Source rock and hydrocarbon migration
Por: 20.3%
Zone II Por: 13.2%
Zone III Pot: 15.4%
Zone IV
Carboniferous strata, occurring at various stages of thermal maturity, are present throughout the East Irish Sea Basin and contain the hydrocarbon source rocks. Sterane fingerprint analysis of the crude oils from the Lennox, Douglas and Formby fields indicates that all three oils were generated from the same source rock (Armstrong et al. 1997). The Namurian Holywell Shale has been identified as the source rock for both the gas and oil in the Lennox Field. The source rocks are considered to be present directly beneath the field at depths of 10000-12000 ft in the hanging wall of the Formby Point Fault (Fig. 8). Various proprietary studies (e.g. Geochem Group) indicated that the hydrocarbon filling history of the field was similar to that of the Douglas Field and is summarized below: (1)
(2)
Por: 11.9%
(3) Fig. 7. A type well (ll0/15-L1) in the Lennox Field showing reservoir zonation and zone characteristics. The field-wide average zonal porosities are lower than those in this well. As 110/15-L1 was drilled at a high angle through a tilted fault block the log does not show the true stratigraphic thicknesses.
Reservoir f l u i d p a r a m e t e r s
Early oil generation during the Early Jurassic. Bitumen was formed due to heavy alteration of this early oil by water washing. Due to subsequent breaching during Cimmerian uplift and erosion all live hydrocarbons were lost but the bitumen remained in the uppermost 40-50 ft of the reservoir. A second phase of oil generation took place during Late Jurassic-Early Cretaceous times giving rise to the current accumulation. The waxiness of the oil was caused by partial biodegradation during the Cretaceous resulting in the severe alteration of the light ends to C12. During the Cretaceous a very light condensate migrated into reservoir. This was followed, after the source rocks entered the dry gas zone, by the main phase of hydrocarbon gas generation during Late Cretaceous and Tertiary. Small amounts of nitrogen, carbon dioxide, hydrogen sulphide and mercaptans were also produced and migrated into the Lennox reservoir. '1
Hydrocarbon volumes and development plans
Extensive laboratory analysis have been performed on oil and gas samples obtained during drill stem tests. The gas cap of the Lennox Field contains a dry gas with a condensate/gas ratio of 3 STB/ MMSCF. The oil rim contains a light, saturated oil (45 ~ API) with
Table 1. Summary of reservoir characteristics in Lennox Field Zone
Thickness (ft)
Porosity (%)
Permeability (rod)
Reservoir Quality
1 2 3 4
250-270 300-380 250-320 200
13-21 11-14 14-17 11-13
200-10000 50-800 200-1000 20-200
Excellent Moderate Good Moderate
The current hydrocarbon in-place estimates are based on volumetrically calculated GIIP of 497 BCF and STOIIP of 184 MMBBL. Approximately 22 BCF gas and 14 MMBBL oil is present in the eastern area of the field (Fig. 2) where the reservoir is degraded due to severe faulting and fracturing. Table 3 summarizes the in-place estimates. Between 1994 and 1998 seven horizontal oil producers and two gas injectors were drilled. Horizontal producing wells have been used exclusively on this development, and the potential to use multilateral wells has been recognized from an early date. Two wells have been drilled as multilateral producers, L6 as a bilateral well and L8 as a tri-lateral. The horizontal oil producers were drilled at 3365ft TVDSS, 35ft above the OWC, with a vertical drilling tolerance of + / - 10 ft. The gas injector wells were drilled at the crestal area of the field to provide pressure support for the oil
Table 2. Lennox Field fluid compositions compared to other Liverpool Bay fields (mol % unless otherwise stated) Field
HzS
Mercaptans
N2
CO 2
C1
C2
C3
C4
C5
C6+
Lennox Oil Lennox Gas Douglas Hamilton Hamilton North Hamilton East
0.12 400 ppm 0.5 1100 ppm 30 ppm 0.01 ppm
450 ppm 1000 ppm -
1.7 12.3 0.7 8.3 8.1 9.3
0.1 0.1 0.1 0.4 0.4 0.04
30 77 2 83 83 82
7 5 4 5 5 5
7 2.5 5 1.5 1.8 1.8
7 1.4 8 1.1 1.3 1.3
5 0.5 7 0.5 0.6 0.6
41.3 0.5 72 0.3 0.5 0.4
LENNOX FIELD
93
Fig. 8. A geological cross-section across the Douglas, Hamilton and Lennox Fields showing the relationship between the source rock (Namurian) and the reservoir rock (Sherwood Sandstone) in the Liverpool Bay Fields. Generated hydrocarbons migrated along various routes; along faults, vertically through the Collyhurst Sandstone and laterally along the base of the Mercia Mudstone seal. The line of section is shown in Figure 4. Table 3. Summary of in-place volumetrics in Lennox Field GIIP (BCF) Zone
Western Area
Eastern Area
1 2 3 4
338 115 22 475
19 3 22
Total
STOIIP (MMBBL) Western Area
Eastern Area
89 54 26 1
170
9 4 1 -
14
producers. Figure 9 shows an E - W geological cross-section illustrating the positions o f the gas injectors and typical oil producers. All the wells drilled came in very close to prognosis including well L3 in the eastern area which showed faulting a n d fracturing of the reservoir as predicted in the A n n e x B. The field has been developed by a m i n i m u m facilities, not n o r m a l l y m a n n e d wellhead platform. The platform has a steel deck and a conventional jacket piled to the sea bed in seven metres of water. The platform has a 12 slot capacity. A wellhead separator is i n c o r p o r a t e d on the p l a t f o r m to provide first stage separation of gas and liquids, which are t r a n s p o r t e d along separate lines to the
F i g . 9. E-W geological cross-section of the Lennox Field showing the two hydrocarbon contacts and the locations of typical oil producers and the two gas injectors (L1 and L9). FMI logs run in well L3 showed severe fracturing causing reservoir degradation in the eastern area of the field. The line of section is shown on the Lennox map in Figure 2.
Fig. 10. Schematic map showing the Liverpool Bay integrated development scheme. The produced Lennox oil is pumped to the Douglas platform for processing before being transported to an offshore barge for storage. Gas is injected from the Douglas platform back into the Lennox gas cap for pressure maintenance.
Fig. 11. 3D simulation model with 150 000 cells of the Lennox Field, looking north and showing the top reservoir structure and the well locations. The simulation grid has a cell size of 50 x 50 x 5 m. Upscaling from a 3D geocellular model (cell size 50 • 50 x 1 m) was carried out using the IRAP RMS 3D reservoir characterization software. The blue horizon represents the OWC at 3400 ft TVDSS.
LENNOX FIELD Douglas complex where full separation is completed. The Lennox gas is combined with offgas from the Douglas field, compressed and sent along an injection line to Lennox, where it is injected into the gas cap to provide pressure maintenance. The addition of the Douglas field offgas provides sufficient volume to give full voidage replacement. Production from the field can be split into two distinct phases: (1) The current oil rim development phase, and (2) the gas cap blowdown phase. During the oil rim development phase, the oil recovery is maximized by replacing the voidage with gas injected into the gas cap. This approach helps to keep the OWC at the original depth, while oil is displaced towards the producers by advancing gas cap. The challenge with this development is to manage voidage replacement whilst minimizing early cresting and cusping of gas into the producing oil wells. Water-cut from the field is currently around 2-5%, and the gas/ oil ratio is at associated gas levels as no free gas production has been observed to date. Sales gas production from Lennox will commence when it is required to maintain the gas sales plateau from the two existing gas fields in the Liverpool Bay Development, and is anticipated to start in 2004. Gas sales will result in the movement of the OWC upwards towards the horizontal producers, which will be progressively re-perforated to maximize oil production as the oil leg is displaced upwards. During the gas cap blowdown phase the field will primarily be a gas producer, although oil production via the re-perforated producers will occur. The Lennox Field forms part of Liverpool Bay Integrated Development scheme as illustrated in Figure 10. The produced hydrocarbons are sent to Douglas complex for processing. The oil is then transported to an offshore loading unit via a subsea pipeline and produced gas is re-injected into the Lennox gas cap. Forward field development planning is now based on a full field 3D geocellular model (generated using the IRAP RMS software package) and provides a much improved structural model and reservoir facies description, as the earlier models were based on 2D maps with average reservoir zone parameters. The geological grid was constructed with 50 x 5 0 x l m grid cells and 285 layers resulting in a total of two million cells for the full field. The geological grids were upscaled to a simulator model with a cell size of 50 x 50 x 5 m (Fig. 11). This model has been history matched with three years of production data and is now providing a means to optimize future development drilling plans. This paper is published by permission of BHP Petroleum Ltd and the Liverpool Bay Group participants; Lasmo (ULX) Ltd and Centrica plc. Thanks are due to N. Meadows, S. Habesch and N. Bailey of Geochem Group for contributing to the understanding of the sedimentology and the geochemistry of the field, and to H. E. Edwards for contributing to the understanding of the structural history. Chris Bryan's efforts in interpreting the complex seismic data, and Phil Harries's modelling work during the initial stages of the development are gratefully acknowledged.
Tabulated Lennox Field data summary Trap Type Depth to crest Hydrocarbon contacts
Gas Column Oil column Main pay zone Formation Age Net/gross ratio Cut-off for N/G Porosity range Permeability range (air) Productivity index
Structural 2500 ft TVDSS GOC at 3257 ft TVDSS, OWC at 3400 ft TVDSS 760 ft 143 ft
Ormskirk Sandstone Triassic 0.9-1.0 3 md
11-21% 50 md-10 darcy 50-350 BOPD/PSI
95
Hydrocarbons Oil gravity Oil type Bubble point Oil viscosity Gas/oil ratio Formation volume factor Gas gravity Gas expansion factor
45~ API Low sulphur 1620 psia 0.5 cP 650 SCF/BBL 1.3 RB/STB 0.69 125 SCF/RCF
Formation water Salinity Resistivity
280 000 ppm NaC1 equivalent 0.037 ohm-m at 30~
Reservoir conditions Temperature Pressure Pressure gradient in gas leg Pressure gradient in oil leg Pressure gradient in water leg
30~ 1620psi at 3257 ft TVSS 0.046 psi/ft 0.32 psi/ft 0.51 psi/ft
Field size Area Gross rock volume STOIIP GIIP Drive mechanism
9 sq km Gas: 518000 ac-ft, Oil: 310000 ac-ft 184 MMBBL 497 BCF Gas injection
Production Start-up date Development scheme
Number/type of wells
February 1996 Central 12-slot wellhead tower, oil exported via pipeline to Douglas complex for processing and then exporting to tanker. 4 exploration/appraisal 7 oil producers 2 gas injectors
References ARMSTRONG, J. P., SMITH, J., D'ELIA, V. A. A. & TRUEBLOOD,S. P. 1997. The occurrence and correlation of oils and Namurian source rocks in the Liverpool Bay-North Wales area. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN,M. & COWAN,G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 195-211. BUSHELL, T. P. 1986. Reservoir geology of the Morecambe Field. In: BROOKS, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N.W. Europe. Geological Society, London, Special Publications, 23, 189-208. COPE, J. C. W. 1994. A latest Cretaceous hotspot and the south-easterly tilt of Britain. Journal of the Geological Society', London, 151,905 908. GREEN, P. F. 1986. On the thermo-tectonic evolution of Northern England: evidence from fission track analysis. Geological Magazine, 123, 493-506. HARDMAN, M., BUCHANAN, J., HERRINGTON, P. & CARR, A. 1993. Geochemical modelling of the East Irish Sea Basin: its influence on predicting hydrocarbon type and quality, In: PARKER, J. R. (ed.) Petroleum Geology oJ North West Europe." Proceedings of the 4th Conference. Geological Society, London, 809-821. HAIG, D. B., PICKERING,S. C. & PROBERT, R. 1997. The Lennox Oil & Gas Field. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. &, COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 417-436. HERR~ES, R. D. & COWAN, G. 1997. Challenging the 'sheetflood' myth: the role of water-table-controlled sabkha deposits in redefining the depositional model for the Ormskirk Sandstone Formation (Lower Triassic), East Irish Sea Basin. In: MEADOWS,N. S., TRUEBLOOD,S. P., HARDMAN, M. & COWAN,O. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 253-276.
96
A. YALIZ & T. CHAPMAN
JACKSON, D. I. & MULHOLLAND,P. 1993. Tectonic and stratigraphic aspects of the East Irish Sea basin and adjacent areas: contrasts in their postCarboniferous structural styles. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the 4th Conference. Geological Society, London, 791-808. JACKSON, D. I., MULHOLLAND,P., JONES, S. M. & WARRINGTON, G. 1987. The geological framework of the East Irish Sea basin. In: BROOKS,J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham and Trotman, London, 191-203. JACKSON, D. I., JOHNSON, H. & SMITH, N. J. P. 1997. Stratigraphical relationships and a revised lithostratigraphical nomenclature for the Carboniferous, Permian and Triassic rocks of the offshore East Irish Sea Basin. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. t~;, COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 11-32. LEWIS, C. L. E., GREEN, P. F., CARTER, A. & HURFORD, A. J. 1992. Elevated K/T palaeotemperatures throughout Northwest England: three kilometres of Tertiary erosion? Earth and Planetary Science Letters, 112, 141-145.
MEADOWS, N. S. & BEACH, A. 1993. Structural and climatic controls on facies distribution in a mixed fluvial and aeolian reservoir: the Triassic Sherwood sandstone in the Irish Sea. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Fluvial and Aeolian Reservoirs. Geological Society, London, Special Publications, 73, 247-264. STUART, ]. A. t%COWAN, G. 1991. Morecambe Gas Field, Blocks 110/2a, 110/ 3a, 110/8a, U.K. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields." 25 years Commemorative Volume. Geological Society, London, Memoir, 14, 527-541. WILLIAMS, G. D. • EATON, G. P. 1993. Stratigraphic and structural analysis of the Late Palaeozoic - Mesozoic of NE Wales and Liverpool Bay: implications for hydrocarbon prospectivity. Journal of the Geological Society, London, 150, 489-499. YALIZ, M. A. 1997. The Douglas Oil Field. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 399-416.
The North Morecambe Field, Block l10/2a, East Irish Sea G. C O W A N 1 & T. B O Y C O T T - B R O W N
2
1 Rashid Petroleum Company, 38 Road 270, New Maadi, Cairo, Egypt Present address: BG Exploration and Production India Ltd, Sahar Plaza, M V Road, Andheri East, Mumbai, India (e-mail: greig, cowan @ bg-group, corn) 2 Hydrocarbon Resources Ltd., Charter Court, 50 Windsor Rd, Slough SL1 2HA, UK (e-mail.
[email protected]) Abstract: The North Morecambe Gas Field in the East Irish Sea Basin was discovered by well 110/2-3 in 1976 and contains ultimately recoverable reserves of over one TCF. The structure is fault closed on three sides and dip closed to the north. Development was by ten conventionally drilled high angle deviated wells, from a not normally manned platform. Gas is exported through a dedicated pipeline to a new terminal at Barrow. The Triassic Sherwood Sandstone Group reservoir is composed of sandstones deposited in a semi-arid, fluvial and aeolian setting. Thin aeolian sandstones dominate flow into the well bore. Platy illite reduces the permeability by two to three orders of magnitude in the lower, illite affected zone of the reservoir. RFT measurements from the first development well proved that the free water level was 25 feet higher than expected, giving a maximum gas column of 975 feet. Re-mapping after drilling has shown that 56% of the GIIP is contained in the high permeability illite-free zone.
Stuart (1993) described the geology of the N o r t h M o r e c a m b e Field using data from four appraisal wells. This paper describes the geological models that evolved during development drilling and is adapted from C o w a n (1996) on which it is heavily reliant. There have been some technical additions to the evaluation of the field since 1996 and it was therefore thought worthwhile to update Cowan's paper for the present publication. The N o r t h M o r e c a m b e Field is contained entirely within Block l10/2a in the East Irish Sea Basin (EISB, Fig. 1). This block was acquired by H y d r o c a r b o n s Great Britain, a wholly o w n e d subsidiary of British Gas, in the fourth licensing r o u n d in 1971.
British Gas's first offshore exploration well, 110/2-1 was drilled in 1974 and discovered the South M o r e c a m b e Field. Further appraisal drilling on what was t h o u g h t to be a single structure led, by 1976, to the drilling of well 110/2-3 on a separate structure, the N o r t h M o r e c a m b e Field. This well encountered the gas-bearing Sherwood Sandstone G r o u p sediments at - 2 9 5 0 ft TVDss, with a log-derived gas-water contact (GWC) at - 3 9 5 0 f t TVDss, some 200 ft deeper than that encountered in the South M o r e c a m b e Field. Three further appraisal wells were drilled on the structure between 1976 and 1983. The second, 110/2-4, encountered the field's eastern b o u n d i n g fault and found no gas-bearing reservoir.
Fig. 1. Location of North Morcambe Field and structural elements.
GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 97-105.
97
98
G. COWAN & T. BOYCOTT-BROWN the informal stratigraphical terminology used for field development. The 'P' and 'Q' markers can be identified using measurement whilst drilling (MWD) tools and are used to locate the 9~- inch casing points above the reservoir. The Sherwood Sandstone Group is over 4000 ft thick in the field area. Seal is provided by salts and shales of the overlying Mercia Mudstone Group and no postTriassic sediments, other than Quaternary fluvio-glacial deposits, have been encountered whilst drilling in the EISB. Individual salt beds can reach up to 500 ft in thickness over the field and can be identified on the seismic sections over the crest of the field, but correlation becomes problematic around the field margins, where there is evidence of halokinesis (Fig. 3). It is therefore difficult to trace, with confidence, the salt stratigraphy throughout the basin using seismic data. However, salts and shales exhibit characteristic log motifs which allow them to be correlated across the basin by well control. The gas was sourced from underlying Upper Carboniferous coals and marine shales (Bushell 1986; I t a r d m a n et al. 1993).
Geophysics
Fig. 2. North Morecambe Field Triassic stratigraphy.
Stratigraphy The reservoir section is composed of the Ormskirk Sandstone and the St Bees Sandstone Members of Sherwood Sandstone Group which is presumed to be Scythian (Triassic) in age. Figure 2 shows
Many vintages of seismic data have been acquired over the structure since the 1970s, however 262 km of the H874 2D survey were acquired in 1986 specifically for the purpose of field development. This survey was acquired with a spacing of 0.5km in a N E - S W orientation (Fig. 4). In 1992 a 120 km 2D survey was acquired over the northern flanks of the field and the adjacent Millom structure. At that time it was felt that a 3D survey would not influence the development plan since the field's bounding, faults and high relief clearly defined the structure. The Top Sherwood Sandstone provides a strong reflection, especially when gas-bearing, giving a high degree of certainty in the mapping. Depth conversion was by a velocity depth function using a single layer model of the overlying Mercia Mudstone Group, with velocities varying from 10639 ft/s to 10157ft/s in the appraisal wells. Velocity variation in the mixed halite/mudstone of the Mercia Mudstone Group, compounded by the effects of halokinesis, were felt to hold the greatest uncertainty on depth conversion and hence reservoir risk, prior to development drilling. The field is now covered by a regional 3D survey completed in March 1995. Interpretation of the 3D seismic has confirmed the field structure is essentially as mapped from 2D seismic. The 3D data has revealed previously unseen in-field faults and some minor
Fig. 3. West to east 3D seismic section through wells N1 and N3.
NORTH MORECAMBE FIELD
99
variations in structure in time at the Top Ormskirk reflector. The structure in time was converted to depth using a velocity function of the form: V = Vo + k d
where, V, velocity; Vo, mapped variable at surface; k, constant from well data trend; and d, depth to top reservoir in well. Figure 5 shows the current view of the structure of North Morecambe.
Structure and contacts
Fig. 4. 2D seismic lines over North Morecambe Field.
Fig. 5. Top Ormskirk~depth (ft).
The field is fault-closed on three sides and dip-closed to the northwest. The general dip of the structure is to the northwest, which contrasts with the easterly dip of South Morecambe. The graben separating North and South Morecambe therefore forms a zone of tilt-transfer (Knipe et al. 1993). The crest of the structure is at - 2 9 5 0 f t TVDss and closure exists down to - 4 4 0 0 f t TVDss. Although residual gas exists down to -4300 ft TVDss, R F T data showed the free water level (FWL) to be at - 3 9 2 5 f t TVDss. Typical water saturations at the F W L are 60%. This makes G W C identification from logs impossible and emphasizes the importance of downhole pressure measurements. M a n y small scale in-field faults, are mapped at top Sherwood level but only one major N - S trending fault was believed to be of significant size to be included in the preliminary single phase simulation model. This fault has a throw of about 100 ft and separates a fault terrace from the rest of
100
G. COWAN & T. BOYCOTT-BROWN
Fig. 6. Major facies associations.
Fig. 7. Depositional model for siliciclastic sabkha.
Fig. 8. Depositional model for fluvial facies association.
NORTH MORECAMBE FIELD
101
under the initial production conditions. The presence of platy illite in the aquifer is suspected to be the cause of differential sealing.
Sedimentological reservoir model O r m s k i r k Sandstone F o r m a t i o n
! A
E 1 1 I , m
m
E L
o
..!
-1
-2
-3
5
10
15
20
25
3O
Porosity (%) Stacked Fluvial
Aeolian Dune
9
+
Ephemeral Fluvial o
Aeolian Sandsheet X
Playa/ Abandonment
Sabkha
S t Bees Sandstone F o r m a t i o n
Fig. 9. Porosity permeability cross-plot for fully cored well 110/2a-N1.
the field (Fig. 5). RFT data from the N3 well show that the FWL is some 24 ft higher in this terrace than the rest of the field, therefore, a downhole pressure gauge has been placed in this well to test fault transmissibility under production conditions. Preliminary data from this gauge show that the fault does not form a seal to gas 110/2a-N2
Fig. 10. Correlation panel through development wells.
Bushell (1986) and Meadows & Beach (1993) described the sedimentology of the Ormskirk Sandstone Formation (Fig. 6). Cowan (1993) stressed the presence and importance of aeolian deposits within the EISB, which were first identified by Woodward & Curtis (1987). Deposition was in a semi-setting characterized by siliciclastic sabkha and aeolian sedimentation alternating with laterally extensive braided fluvial sedimentation (Figs 7 & 8). The term siliciclastic sabkha (Fryberger et al. 1983) here replaces the more commonly used 'sheetflood' for this complex facies association, since the 'sheetflood' facies associations contain many features analogous to those described by Fryberger et al. (1983), including accretion warts, algal gas escape bubbles and thin pinstripe laminated subcritical climbing ripples (Herries 1992). Herries (1992) has re-assessed the role and mechanisms of siliciclastic sabkha and aeolian sandsheet deposition in the East Irish Sea Basin and shown that aeolian development is controlled by a mixture of water table rise and sand supply. During periods when sand supply exceeds water table rise, climbing dune morphologies can form. The stacking of these dunes can form laterally extensive dry aeolian sheets without wet interdune deposits separating individual dunes. Water table rise into these laterally extensive aeolian deposits allows preservation of the basal dune toe-sets. Hence the preponderance of flat laminated aeolian sediments with the EISB. A return to fluvial deposition erodes and re-works the dune topography. This mechanism can explain the presence of thin yet laterally persistent aeolian deposits interlaminated with fluvial deposits within the Ormskirk Sandstone Group.
Since the Ormskirk Sandstone Formation is less than 800ft thick in the North Morecambe area, the underlying St Bees Sandstone Formation forms part of the reservoir below the crestal region of the field as well as forming the greater part of the aquifer. Recently Barnes et al. (1994) proposed that the uppermost section of the St Bees Sandstone Formation be renamed Calder Sandstone Formation in the Sellafield area, onshore Cumbria. The existing usage has become established for the offshore area and is retained here. The top of the St Bees Sandstone Formation is marked by a basin wide increase in gamma ray API values and a decrease in 110/2a-N6
11012a-N3
:i~'~
l"
110/2a-H4
110/2aN7
110/2a-N1
110/2a-H5
102
G. COWAN & T. BOYCOTT-BROWN
interval transit times. This log response marks the change from the dominantly stacked braided fluvial facies of the St Bees Sandstone Formation to the lowermost aeolian sandsheet facies of the Ormskirk Sandstone Formation (Fig. 6).
Diagenetic controls on reservoir properties Like the larger South Morecambe Field, the North Morecambe Field reservoir can be divided into two diagenetic zones, an uppermost illite-free zone and lower illite-affected zone. The top of the illitized zone forms a tilted surface which marks a palaeo hydrocarbon-water contact (see Colter & Ebbern 1978; Bushell 1986; Woodward & Curtis 1987; Stuart 1993 for detailed discussion.) The illite reduces the permeability by two to three orders of magnitude and is the single most important factor controlling reservoir properties (Fig. 9). Within the EISB, the distribution of platy illite is restricted to the area between the Keys and Tynwald Fault zones, and the North and South Morecambe structures (Fig. 1). This illitized fairway (or perhaps 'rough' is a more appropriate term) marks out a migration pathway from the deeply buried kitchen area to the north, the Keys Basin. Other diagenetic features include quartz over-growths and microdolomite nodules, which have been discussed by Stuart (1993). Carbonate and evaporite cements reduce porosity but have little effect on permeability. However, the highest porosities are preserved near the crest of the structure, and cement abundance increases down flank. Thus the arithmetic average porosity values, 12.3% of the illite-free layer preserved on the crest of structure, are reduced to 7.9% on the flanks (l10/2a-N2). Stuart (1993) stated that petrographical evidence, along with high CO2 compositions in the North Morecambe gas, suggested that the field had been filled by a single hydrocarbon charge. Although the petrographical evidence is ambiguous, core from the development wells shows dead oil staining which supports the view that the North Morecambe structure, like the larger South Morecambe structure was filled by at least two distinct hydrocarbon phases (Stuart & Cowan 1991).
Primary depositional controls on reservoir properties The effects of illite overprints, but does not destroy, primary depositional controls on reservoir properties (Fig. 9). Aeolian facies have the best reservoir properties, followed by fluvial facies, with playa facies having the poorest. The siliciclastic sabkha facies (sheetflood of Busheil 1986; Stuart & Cowan 1991; Stuart 1993) contain the greatest range of porosity and permeability values and this is a reflection of the fact that both wet and dry siliciclastic sabkha are included within the same broad facies classification. At the wet end of the siliciclastic sabkha spectrum can be found true playa, deposits, with virtually no permeability, whilst the dry end can include thinly bedded, aeolian, wind-rippled sandstones with permeabilities in the 1 10D range. Between these, interlaminated sandstone/mudstone heterolithics and accretion-rippled sandstones occur in a continuum. Wavy interlamination is a characteristic of sediments of the siliciclastic sabkha facies.
Table 1. Gas composition (tool%)
H2 He N2 CO2 C1 C 2+ Gravity Condensate ratio (Bbl/MMSCF)
North Morecambe
South Morecambe
0.08 0.02 6.88 5.89 81.02 6.11 0.693 3.6
0.00 0.03 7.77 0.56 84.84 6.8 0.650 4.5
layering scheme was used comprising three layers; the illite-free, illite-affected and St Bees Sandstone Formation (which always contains illite). The top of the illite-affected layer intersects the top of the Sherwood Sandstone over the north of the field, therefore the illite-free reservoir has no direct aquifer contact. It is believed that this fact will reduce water influx over field life. Although production logs and permeability profiles show layers to be heterogeneous and that flow into the well bore is often concentrated into a few high permeability layers. The permeability is sufficiently high to allow the upper layers to behave in a tank-like manner away from the well-bore, at least during the early phase of field life. A more detailed layering scheme has been constructed for use in a two phase simulation model.
Gas composition Table l shows the composition of North and South Morecambe gases. No two fields in the East Irish Sea have similar gas compositions, and none have British National Transmission System (NTS) specification gas. Due to the corrosive effects of the 6% CO2 content, a new pipeline was required to export North Morecambe gas and a new processing terminal, the largest in Europe, was needed to remove both the CO2 and the N2 to produce NTS specification gas. The gas is fairly lean, with a condensate ratio of only 3.6 BBL/MMSCF.
Development plan The development called for up to 12 wells, produced through a 36' pipeline to a new dedicated terminal at Barrow. The plan was to pre-drill eight development wells using the F. G. Mclintock jack-up rig skidded onto the platform prior to topsides installation. Topsides were fabricated onshore and lifted on to the platform as a single unit. After topsides installation and well testing a decision was to be made on the final number of wells required to meet the design daily contract rate of 310 MMSCFD. In the event, ten wells were drilled before topsides installation and, since on average each well performed 25% better on testing than expected, ten were sufficient to achieve the planned production profile.
Reservoir layering Well targeting Reservoir layering in the North Morecambe Field is complicated by the fact that diagenetic alteration cross-cuts the primary depositional layering. Primary depositional layering is remarkably consistent across the field and can be extended into South Morecambe and northwesterly into Block 113/26a. To the north of the field area, wet siliciclastic sabkha sediments become more abundant than the stacked fluvial, facies, although the high porosity aeolian layers can still be identified on core and wireline logs. Figure 10 shows a correlation panel though the development wells. For initial single-phase simulation modelling a simple
Since the field comprises a high permeability upper layer and a low permeability lower layer, wells were targeted on the thickest illitefree sections of the field. This was because simulation sensitivity modelling shows that the most efficient method of producing gas from the poor quality illite-affected reservoir is to obtain maximum drawdown of the illite-free layer and produce gas from the illiteaffected layer via the former layer. To achieve this, wells were clustered near the crest of the structure, in the region of highest permeability. This area has the highest absolute permeability
NORTH MORECAMBE FIELD ~.. 200 I-
103 178
I 113127 BGE&P
a
I ....
I
100
!, 50 ~ , j 0l~_~-1"454 ~-~0[~ i i ~-2i -~ I "r n -100 "c- -50
g
-23
7
-74
N1
N2
N3
N4
N5
N6
N7
N8
N9
N10
Well 110/2a[-7 Top S h e r w o o d S a n d s t o n e 1
Illite Free T h i c k n e s s
Fig. 12. Chart showing the errors in predicting depth to top Sherwood and illite-free thickness in the development wells.
W e l l results. ~ 0
=
m
~
0Km ,,
t .0 M~lo
110/2b BGE&P
Fig. 11. Illitc-free hydrocarbon pore thickness map (HCPT).
values, since it has suffered less diagenetic porosity loss. It is also the area of maximum permeability-height product, because it is the area of thickest illite-free reservoir. Sufficient slots are available to drill infill wells for drainage into the illite-affected zone during later field life if this is necessary. Figure 11 shows the illite-free hydrocarbon pore thickness map and illustrates the fact that most wells were targeted to the east of the platform. The second development well was drilled as a long step-out well to gain reservoir data in the unappraised northwest part of the field. The first three wells were fully cored and the illite-affected zone of the fourth well was cored, the upper part having being cored in the nearby discovery well 110/2-3, which it twinned. Over 5000ft of core was recovered. The first three wells also penetrated the aquifer. Well 110/2a-N1 was cased over the aquifer section to allow monitoring of aquifer movement. The other two were plugged back before running the production liner to reduce the risk of water bypassing cement during production.
Fig. 13. Cross-section showing increase in illite-free gross rock volume (GRV) over prognosis.
Figure 12 shows the accuracy of prediction of depth to top reservoir for each of the development wells. This was felt to hold the greatest uncertainty in field development. The results, however, showed that most wells came in within 50ft of prognosis. Significantly, the greatest error was encountered in the N2 well, which was drilled into the unappraised northwest flank of the field. After drilling the fourth well, prediction of depth to top Sherwood became very accurate; however, the last well (N10) came in 74ft low. This was unexpected since it was drilled on the same seismic line as, and in between, wells N5 and N6. It is thought that this well encountered a fault which was sub-parallel to the 2D seismic grid. Of greater importance to field development was the fact that the thickness of the illite-free reservoir was underestimated prior to development drilling (Fig. 12). This is shown diagrammatically in Figure 13. Before drilling it was estimated that 60% of the GIIP was in the poor quality illite-affected reservoir; after drilling it was found that only 44% of the gas initially in place (GIIP) was in the illite-affected reservoir. The fact that most wells came in higher than prognosed and that the illite-free gross rock volume (GRV) was greater than predicted should have increased field reserves; however, pre-drilling estimates of porosity were higher than those actually encountered. Figure 14 shows that porosity was overestimated on the flanks of the field. The prognosed porosity of the flank well 110/2a-N2 was 11.3%, but the porosity encountered was only 7.9%, a reduction
104
G. COWAN & T. BOYCOTT-BROWN
of some 30%. This has a direct impact on GIIP along with the fact that the F W L was 25 ft higher than expected. Thus the postdrilling reserves of 1.0 T C F do not differ significantly from the pre-drilling estimate of 1.08 TCF.
Permeability-height product Kh (mD-ft] 300000 [
2700,00
2500001
250000
200000 1
Test rates
All the development wells were tested, in most wells the illitefree and illite-affected zones were tested Separately, since once the illite-free zone is perforated it is not possible to draw the illiteaffected down sufficiently to allow it to contribute to net flow into the well-bore under test conditions. Test rates varied from 92 to 108 M M S C F D through a 2" choke with a maximum drawdown of only 80psi. These figures do not represent the true well productivity since all the wells were tubing constrained. The well test permeability-height product varied from 30 343 mD-ft (N2) to 270 000 mD-ft (N8) and these wells achieved 92 and 104 M M S C F D
150000] ~3-~
130000 100050
000:11 i N1
58000 i~
N9
N6
N8
N4
N5
5900[~
N7
N10
Well Fig. 16. Permeability-height product (mD-ft) in the development wells. This figure provides a more accurate picture of potential well performance during the decline phase of the field life.
Cored Wells
20000 A =< v oe. o
0
15ooo
O0
-1 300
10000
O
2 o_
-2 ot._ o a.
4o0
(J 09
--~
200 z:>'
-3
-4
'o~176
o
110/2a-N1
110/2a-N2
110/2a-N3
110/2a-N4
[ ] Illite Free Layer 9 Illite Affected Layer
CalendarMonth Fig. 17. Monthly production from North Morecambe.
Fig. 14. Porosity prognosis. The two flank wells (N2 and N3) encountered lower than predicted porosity in the illite-free zone.
Maximum
F l o w Rate ( M M S C F D )
120 100 80
_ ~
_
~
_ "--I [
:
I
m m
60
,oo
/ N1
N9
i II N6
N8
! N4
N5
N7
N10
N2
P r o d u c t i o n profile
N3
r-] All Zones
1
respectively. Figures 15 and 16 illustrate the inadequacy of using well test rates to estimate reservoir productivity. Well l10/2a-N8 was drilled through the reservoir at a constant angle of 70 degrees to test increased production of the illite-affected reservoir as a consequence of drilling high angle completions. The results of this test were disappointing as this well flowed only ten M M S C F D from the illite-affected zone. The crestal, low-angle well, l10/2a-N4, which encountered gas-bearing aeolian sandsheet and sabkha facies of the lowermost Ormskirk Sandstone Formation, achieved 57 M M S C F D from the illite-affected zone.
Illite Affected
Fig. 15. Maximum flow rate (MMSCFD) from well tests. This figure does not represent true well productivity since all wells are tubing constrained. (2" choke, 80psi drawdown at high rate test. Maximum flow from illite-affected aeolial sequence (black bar) in crestal wells N4 and N6.
Since the reservoir can be considered a highly permeable tank above a low permeability reservoir, the production profile is characterized by a short plateau of 267 M M S C F D with a peak of 518 M M S C F D (1.67 swing). The most likely plateau duration is four years. The decline phase is estimated to take 40 years as the gas is drained from the less permeable illite-affected reservoir. Production to date is shown in Figure 17. The authors would like to thank Hydrocarbon Resources Limited for permission to publish this paper.
N O R T H MORECAMBE FIELD
North Morcambe Field summary Field name Trap Type Depth to crest Lowest closing contour FWL Gas column Pay zone Formation Age Gross thickness Net : gross : illite free illite affected Porosity (average well values) illite-free lllite-affected Permeability average (range) illite-affected Petroleum saturation Productivity index
Formation water Salinity Resistivity
References
North Moreeambe
units
Faulted roll-over -2950 -4400 -3925 975
ft ft ft ft
Ormskirk Sandstone St Bees Sandstone Triassic - presumed Scythian (270 Ma) 4000 85 to 99 55 to 92 8 t o 12
-
9 t o 15 25 to 180
% mD
0.02 to 1.0 65 at FWL 100 at crest 1.25
mD %
Petroleum Gas gravity 0.648 Viscosity Bubble point Dew point 1795 Condensate yield 3.6 Formation volume factor 0.0070 Gas expansion factor 143
105
ft % % %
mmscfd/psi
cp psig psig bbl/mmscf scf/rcf
270 000 0.05
NaC1 eq ppm ohm m @ 77 deg F
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Gas initially in place Recovery factor Drive mechanism Recoverable gas Recoverable NGL/condensate
5930 2 820 000 1800 0.055 92 1290 80 volumetric depletion 1050 1.2
acres acre ft psi @ -3625ft TVDSS psi/ft deg F bcf %
Production Start-up date Production rate plateau gas
Oct-94 265
Number/type of well Number/type of well
10 production 4 appraisal
bcf mmbbl
mmscfd
BARNES, R. P., AMBROSE, K., HOLLIDAY, D. W. & JONES, N. S. 1994. Lithostratigraphical subdivision of the Triassic Sherwood Sandstone Group in West Cumbria. Proceedings of the Yorkshire Geological Society, 50, 51-60. BUSHELL, T. P. 1986. Reservoir geology of the Morecambe Field. In: BROOKS, J., GOFF, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic gas in N W Europe. Geological Society, London, Special Publications, 23, 189-208. COLTER, V. S. & EBBERN, J. 1978. The petrography and reservoir properties of some Triassic: sandstones of the Northern Irish Sea. Journal of the Geological Society, London, 135, 57-62. COWAN, G. 1993. The identification and significance of aeolian deposits within the dominantly fluvial Sherwood Sandstone Group of the East Irish Sea Basin UK. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Aeolian and Fluvial Reservoirs. Geological Society, London, Special Publications, 73, 249. COWAN, G. 1996. The development of the North Morecambe Gas Field, East Irish Sea Basin, UK. Petroleum Geoscience, 2, 43-52. FRYBERGER, S. G., AL-SARI, M. & CLISHAM, T. J. 1983. Eolian dune, interdune, sandsheet and siliciclastic sabkha sediments of an offshore prograding sand sea, Dhahran area, Saudi Arabia. American Association of Petroleum Geologists Bulletin, 67, 208-312. HARDMAN, M., BUCHANAN, J., HERRINGTON, P. & CARR, A. 1993. Geochemical modelling in the East Irish Sea Basin, its influence on predicting hydrocarbon type and quality. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. Geological Society, London, 809-821. HERRIES, R D. 1992. Sedimentology of erg-margin interaction, PhD thesis, University of Aberdeen. KNIPE, R., COWAN, G. & BALENDRAN, V. S. 1993. The structural history of the East Irish Sea Basin with special reference to the Morecambe Field. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. Geological Society, London, 857-866. MEADOWS, N. S. & BEACH, A. 1993. Controls on reservoir quality in the Triassic Sherwood sandstone of the East Irish Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. Geological Society, London, 823-833. STUART, I. A. 1993. The Geology of the North Morecambe Gas Field, East Irish Sea Basin. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. Geological Society, London, 883-895. STUART, I. A. & COWAN, G. 1991. The South Morecambe Gas Field, Blocks 110/2a, 110/3a and 110/8a, UK. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 527-541. WOODWARD, K. & CURTIS, C. D. 1987. Predictive modelling for the distribution of production constraining illites, Morecambe Gas Field, Irish Sea, Offshore UK. In: Brooks, J. & GLENNJE, K. (eds) Petroleum Geology of N W Europe. Graham & Trottman, London, 205-215.
The South Morecambe Gas Field, Blocks l10/2a, l10/3a, l10/7a and l10/8a, East Irish Sea J. C. B A S T I N l, T. B O Y C O T T - B R O W N 1, A. SIMS 2, R.
WOODHOUSE
3
1 Centrica/Hydrocarbon Resources Ltd., Charter Court, 50 Windsor Road, Slough SL1 2HA, UK 2 Merlin Energy Resources Limited, Newberry House, Ledbury HR8 2E J, UK 3 'Fariswood', Sheerwater Avenue, Woodham, Weybridge, Surrey KT15 3DR, UK
Abstract" South Morecambe Gas
Field is situated in the East Irish Sea and produces gas from the Triassic Sherwood Sandstone Group. Exploration of the basin commenced in 1966 and the discovery well, 110/2-1, was drilled in 1974. Appraisal was complete by 1983 and development was carried out in two phases with the object of providing deliverability to help to satisfy the winter peak in demand. First gas was produced in January 1985 and production during the winter can be sustained at 5 0 M M C M D (1750mmscfd). The stratigraphic succession of the East Irish Sea Basin (EISB) consists of Carboniferous (Dinantian to Westphalian) strata unconformably overlain by 15000 to 20000 feet of continental Permo-Triassic strata. The Triassic Sherwood Sandstone Group contains reservoir rocks and the overlying Mercia Mudstone Group evaporites provide a seal. Seismic cover of the area includes 2D and 3D data, the latter providing good images that form the basis of the current structural interpretation. The structural development of the basin commenced with extension in the Permo-Triassic followed by inversions in the late Jurassic and early Tertiary. The reservoir has been zoned using a scheme that recognizes primary depositional facies as the main criterion for correlation. The petrophysical evaluation has introduced new methods of calculating porosity, Sw and net pay. The latest reservoir pressure data has been used in a material balance study and a two tank simulation model, both give GIIP estimates which are in line with earlier estimates. The new petrophysically derived reservoir parameters were also used to make a volumetric estimate of GIIP. Remaining recoverable reserves are at least 3 Tcf.
S o u t h M o r e c a m b e Field lies b e n e a t h the Irish Sea s o m e 20 miles W o f Blackpool. G a s is p r o d u c e d f r o m S h e r w o o d s a n d s t o n e s t h a t are only 3000 feet below the seabed. W a t e r d e p t h is 100 ft, b u t the tidal range is 3 0 f t resulting in exceptionally s t r o n g currents. T h e M o r e c a m b e Structure c o n t a i n s t w o fields, S o u t h M o r e c a m b e a n d N o r t h M o r e c a m b e , s e p a r a t e d by a deep, n a r r o w graben. T h e two
fields have separate fluid contacts, pressures a n d gas c o m p o s i t i o n s . G a s p r o d u c t i o n f r o m S o u t h M o r e c a m b e takes place f r o m a netw o r k o f f o u r n o r m a l l y u n m a n n e d p l a t f o r m s w h i c h are c o n n e c t e d by gas g a t h e r i n g lines to a central gas processing a n d t r a n s m i s s i o n complex. A 36 inch d i a m e t e r pipeline c o n v e y s the gas p r o d u c e d to the B a r r o w T e r m i n a l where it is p r o c e s s e d a n d m e t e r e d for entry
Fig. 1.
Location of South Morecambe Field and structural elements.
GLUYAS,J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 107-118.
107
108
J.C. BASTIN E T A L .
to the National Transmission System. A Field Management and Support base at Heysham and a Heliport at Blackpool provide support for the offshore activity. First Gas from South Morecambe was produced in January 1985. Figure 1 shows the location of the field and pipelines. This paper describes the discovery, development and recent technical advances in the understanding of the reservoir. The literature contains several accounts of the field (listed in the references) published at intervals since its discovery in 1975, when CoRer & Barr (1975) described developments in the Irish Sea and Cheshire Basins.
History The Morecambe Fields lie wholly within the UK Blocks 110/2a, 110/ 3a and l10/Sa (Fig. 2). These blocks are now licensed to Hydrocarbon Resources Ltd, one of the Centrica group of companies, following the demerger of British Gas into Centrica plc and BG plc in February 1997. They were originally licensed to Hydrocarbons Great Britain Ltd (HGB), a wholly owned subsidiary of British Gas, later to become Gas Council (Exploration) Ltd and then British Gas Exploration and Production Ltd. The discovery of the field followed an interesting chain of events showing how important the early stages of exploration in a new
basin are for the companies involved. East Irish Sea blocks were first offered in the second UKCS licensing round of 1966. A Gulf/NCB consortium was awarded 110/3 and 110/8. Two wells were drilled in 1969, both reaching TD in the Carboniferous. Well 110/8-1 on the Deemster Platform was dry having encountered the Sherwood Sandstone Group immediately beneath thin drift deposits. The second well on the Block 110/8-2, was drilled to 10 100 ft and reported a Carboniferous bottom hole formation. The well was classified as a dry hole and plugged and abandoned although the log records 240 000 ppm of methane gas in the Sherwood Sandstone. In 1972 Hydrocarbons GB Ltd, a subsidiary of the British Gas Corporation, was awarded Block 110/2 in the fourth round. It had pretraded 110/8-2 with Gulf and intended to use the data in planning the drilling of 110/2-1. The log analyst responsible for planning 110/2-1 recognized that 110/8-2 had in fact penetrated a 600 ft gas column in the Sherwood Sandstone. Meanwhile Gulf had issued notice to relinquish 110/8. Hydrocarbons GB alerted Gulf to their evaluation of the 110/8-2 well and Gulf tried unsuccessfully to retract the relinquishment. The South Morecambe discovery well, 110/2-1, was drilled in 1974 and tested at the relatively modest rate of 10mmscfd from a 212ft interval perforated in the Sherwood Sandstone. Subsequently Block 110/8 together with 110/7 was awarded to Hydrocarbons GB Ltd as a Special Award in August 1976. Figure 2 shows the field outline and infrastructure together with the location of the discovery, appraisal and production wells.
Fig. 2. South Morecambe Field showing structural elements, wells, pipelines and platform locations.
SOUTH MORECAMBE FIELD
109
Fig. 3. E-W seismic line over South Morecambe showing 110/2-1 and production well F6.
Appraisal Well 110/2-1 had encountered a gas column but nearly missed the field, it drilled through the western boundary fault of the accumulation and much of the Sherwood Sandstone was cut out. Figure 3 shows the track of the well on 3D seismic acquired in 1994-1995. Subsequent appraisal, carried out by drilling a further five wells on the field, proved much better deliverability from the reservoir. The results are given in the table below.
Well
Dates
Drill Stem Tests (DST)
Rate (mmscfd)
110/2-2 110/3-1 110/3-3 110/2-6 110/2-7
2-10-75to 21-11-75 16-7-77 to 27-8-77 26-11-77to 3-1-78 3-8-78 to 11-10-78 25-8-83 to 7-11-83
6 1 (multi-rate) 8 7 3
23.5 41 24.2 0.75 to 22 2.7 to 39
Well 110/2-2 drilled very close to the E - W trending steep sided graben, which separates North Morecambe Field from South Morecambe. It proved gas with DST over several intervals although there is, in effect, one single gas column. The wells 110/2-3, 4a and 5 were all drilled on North Morecambe Field, which has a different free water level, gas water contact and gas composition.
Development Development plans for South Morecambe Field were drawn up in the late 1970s and early 1980s. At that time the increase in the domestic/industrial ratio in gas consumption was causing an increasing peak winter demand for gas. The development plan was based on the concept of using the field as a seasonal supply facility (peak shaver), to produce gas at very high rates over the winter. The
development was designed to produce at a rate of 1220 mmscfd, and is capable of producing at even higher rates for short periods. The first stage of the development was implemented in the mid1980s with the installation of a Central Processing Platform (CPP1), an Accommodation Platform (AP1), and three Slant Drilling Platforms (DP1, DP3 and DP4). The latter are unmanned and remotely controlled from the CPP1. A 36 inch trunk pipeline connects the CPP1 to the South Morecambe shore terminal at Barrow. The remote drilling platforms (DPs) are linked to the CPP1 by 24 inch infield pipelines (Fig. 2). Between August 1984 and August 1987, 19 development wells were drilled and completed from the three DPs. The reservoir is exceptionally shallow, so slant drilling was employed to ensure maximum step-out without the hole angle reaching more than 72 degrees. First gas flowed in January 1985. In the severe winter weather of January 1987 the field produced at a peak rate of 970 mmscfd at a time when only 14 wells had been completed. A second stage of development followed with the installation of two further remote drilling platforms, DP6 and DP8, on the northern limb of the South Morecambe structure. Drilling of 14 additional development wells from these platforms took place between M a y 1989 and July 1991. Development drilling was so successful that the peak rate from the field was increased to 1800 mmscfd. Design life for the facilities is about 40 years.
Stratigraphy The East Irish Sea Basin is one of the largest and deepest postCarboniferous depocentres west of Britain. It is divided into several sub-basins and highs, and contains an estimated 15 000 to 20 000 feet of Permo-Triassic strata in its deepest parts, with Carboniferous rocks extending to a depth of nearly 30000 feet (Jackson et al. 1987). The component basins were formed by the development of grabens or half-grabens, and so the maximum thickness of Permo-Triassic sediment is generally found adjacent to the bounding faults. The maximum present-day throw of the major syndepositional faults can be as much as 12000 feet. Carboniferous
110
J. C. BASTIN E T AL.
CHRONOSTRATIGRAPHIC SUBDIVISION
_~ ~O
LITHOSTRATIGRAPHIC SUBDIVISION
QuaternaryTerb~fy +
NORIAN
,7
UNITE MUDSTONES
CARNIAN
w LKESLEY HALITE
LADINIAN
UNITD MUDS'TONES ,
ANISIAN
O
p
f~
'
UNITC MUDSTONES
I
MYTHOPHALITE
(3 ~
PREESALL
HALITE
UNITB MUC(STONES
ROSSALLHALITE UNiTA MUD,STONES 'Brown'Salt ORMSKIRKSANDSTONEF O R M A ~
~~ 8~
SCYTHIAN
UPPER PERMIAN (ZECH-~TEIN)
a_
LOWER PERMIAN (ROTLIEGEND)
~ o Lu{e
ST BEESSANDSTONEFORMATION
~- ~- ~" ] BARROVVMOUTHMUDSTONE FORMATION
!~ ~ ~ ~ ~
: $. . . . . . . . . . . . . . . . . . . . . [
............. FM
STEPHANIAN
u_
g
6
CANTABRIAN
~_z~)
WESTPHALIAN
~c, ~
NAMURIAN
< ~
DINANTIAN
i~
a lesser extent North Morecambe) is such that on the crest of the structure the lower part of the gas column extends into the St Bees Sandstone Formation. The Sherwood Sandstone Group is overlain by a thick Middle and Upper Triassic succession of halites and mudstones assigned to the Mercia Mudstone Group. This unit provides the reservoir top seal to the Morecambe Fields. Individual halite beds can reach up to 500 ft in thickness in the field area and can be identified on the seismic sections over the crest of the field (Fig. 3). The picks degrade around the field margins where there is evidence of halokinesis, making correlation by seismic methods impractical. However, halites and mudstones exhibit characteristic log motifs that allow them to be correlated across the basin by well control. The 'P' and 'Q' mudstone markers within the lower section of the 'Brown' Salt, immediately above the Sherwood reservoirs, are easily identified with Measurement Whilst Drilling (MWD) tools and were used to pick the nine 5/8 inch casing points above the reservoir during development drilling of South Morecambe Field.
~g
KIDSTONGRoUP
81SAT .....
C,ARaOOOGROUP
Fig. 4. Stratigraphy of the Morecambe area.
strata occur widely; Westphalian strata are preserved at or near the seabed to the west of the basin. Elsewhere, the base of the PermoTriassic overlaps Westphalian strata to rest on Namurian and Dinantian rocks. The basin is bounded to the south and west by the erosional base of the Permo-Triassic, and to the north by the Lagman Fault which defines the southern limit of the Ramsey-Whitehaven Ridge (Fig. 1). The Lake District Boundary and Haverigg faults are major syn-depositional faults that mark, or guide, its eastern margin. In the southeast, the Formby Point Fault and its stepped onshore counterpart, the Boundary Fault of the Lancashire Coalfield, are major synthetic faults influencing the limit of the thick Permo-Triassic strata. Permo-Triassic rocks are absent from the Ogham Platform, where Carboniferous strata subcrop at the seabed. Figure 4 shows the general stratigraphy in the immediate Morecambe Fields area. The Carboniferous is known from wells 110/8-2, 113/26-1, 113/27-3, 110/2b-9, 110/2b-10, 110/3-2 and 110/ 3b-4. The Permian sequence falls into two lithological divisions; the Lower Permian Collyhurst Sandstone Formation consisting of barren continental clastics and the Upper Permian consisting of poorly fossiliferous marine and marginal marine evaporites and fine-grained clastics. The latter division comprises the Lower St Bees Evaporites Formation and Upper Barrowmouth Mudstone Formation. Rapid basin subsidence during the early Triassic led to the accumulation of a very thick sequence of continental clastics represented by the Sherwood Sandstone Group. This consists of a thick lower unit, the St Bees Sandstone Formation, and a thinner upper unit, the Ormskirk Sandstone Formation. The boundary between the two corresponds to an abrupt and conspicuous facies change. The St Bees Sandstone Formation is 4000 ft thick in South Morecambe well 110/8-2, the only one which fully penetrates it, while the Ormskirk Sandstone varies from 650 to 850ft thick over the two fields. The vertical relief of the South Morecambe structure (and to
Geophysics Seismic cover of the field and surrounding area dates from 1968 when Gulf began to explore the basin with a sleeve exploder sourced survey. They acquired 30 km (24 fold cover) on N - S and E - W lines spaced at approximately 8 km. This was followed by a series of similar surveys from 15 to 80 km all of similar quality and very difficult to interpret. In 1975 Hydrocarbons GB shot 560 km of data with an air gun source. Interpretation was still problematic, the top Sherwood Sandstone reflector was seen as inconsistent from well to well. An advance in data quality occurred in 1979 when a 48 fold, 520km survey was acquired with an Aquapulse source. The processing sequence included migration (wave equation) for the first time, which made it easier to interpret the faults. The next improvement, in 1983, resulted from the deployment of a water gun source. This avoided difficulties associated with air gun bubble oscillations. Frequency content was increased and the directional properties of the array attenuated noise. The consistent well ties obtained with the new data heightened the confidence in the interpretation. It was recognized that the state of the art solution to map a structurally complex field such as Morecambe would be to acquire 3D seismic. However the number of platforms already in the survey area, the time required and the cost of such an exercise brought about the decision to proceed with the development using 2D data. In order to address the 2D migration issue a 'Radial' survey was acquired with lines aligned in the dip direction rather than on a regular grid. Phase I of the development proceeded without the Radial survey, which was used in Phase II, the drilling from DP6 and DPS. Depth conversion of the two way time maps was effected by the use of mapped average velocity to the Top Sherwood Sandstone. The velocities were derived from checkshot data, which had been acquired on each of the discovery and appraisal wells as well as the vertical development wells. The error expected from this method was estimated to be 50 to 140 feet. This proved to be the case on nine of the I 1 development wells subsequently drilled. In 1994-1995 a 700 s q k m 3D survey was finally acquired over Morecambe and the adjacent fields. This involved undershooting six platforms. Although the footprints of the platforms are visible on the data the deeper reflectors can be discerned. In contrast to the previous interpretations, the Top Sherwood reflector was identified by matching synthetic seismograms to the seismic survey data. The Top Sherwood reflector appears as a negative acoustic impedance break on the synthetic and as a peak on normal polarity seismic. The reflection varies in amplitude over the known accumulation. This is the result of thickness changes in the Stannah Member of the Mercia Mudstone Group, as well as porosity changes and type of fluid fill in the pores of the underlying Ormskirk Sandstone reservoir. The anhydrites and dolomites which make up the Stannah member produce a tuned signal between the top of the Stannah and its base (which is also the top Sherwood). The field
SOUTH MORECAMBE FIELD
ll I
Fig. 5. South Morecambe field structure in depth (ft TVDss) at Top Sherwood Sandstone Group. was remapped in 1997 using the 3D data. Because the earlier 2D data was acquired to optimize migration it was not suitably oriented to detect the E - W trending faults. The 3D data has shown an array of faults on this trend. One strikes through 110/8a-C4 and a previously undetected conjugate pair divides the eastern flank of the field into two. Figure 5 shows the latest map of structure in depth at the top of the Sherwood Sandstone Group. The quality of these data, backed up by petrophysical studies, encouraged Hydrocarbon Resources Ltd to carry out acoustic impedance inversion over the area of the Morecambe fields. The acoustic impedance data shows sequence boundaries which can be correlated with the well based reservoir layering scheme and it also shows that acoustic
impedance responds to changes in fluid fill in the pores. An example line is shown in Figure 6. The data is now being used to refine the current geological reservoir model.
Structural history The Permo-Triassic strata were laid down on the pre-existing Carboniferous basin during an extensional tectonic regime. The sediments thicken into N-S trending major faults. Outcrop examples of the structural style can be seen in North Wales in the Vale of Clwyd in North Wales. Jackson et al. (1987) documented
112
J. C. BASTIN E T A L .
Fig. 6. Acoustic impedance section oriented E-W across the eastern flank of the field. Blue colours denote high impedance, red denotes low impedance.
the main structural elements of the area. Subsidence continued at least into the Jurassic as evidenced by samples of Jurassic strata that were recovered from shallow seabed bores in the Keys Basin. Study of the isopachs (Knipe et al. 1993) of the Permian to top Sherwood Sandstone Group interval shows that the Keys Fault and Tynwald Fault Zone were growing during deposition with sediment accumulating on the east of these faults. Further south the Deemster Platform represents a central horst in the Permian rift basin. The Formby Point fault and others throwing down to the west dominate the southern part of the basin. South Morecambe Field lies on a transfer zone between these two structural patterns and initially formed as a complex domal arch responding to extension on these opposing fault trends. Later phases of extension, inversion, uplift and renewed subsidence have modified the initial structure but the exact history is difficult to determine due to the lack of stratigraphic record younger than late Triassic. An inversion took place in the late Jurassic to early Cretaceous followed by renewed subsidence throughout the rest of the Cretaceous. An early Tertiary event caused uplift and erosion leading to the present day
structure. The profile of the Western Boundary Fault of South Morecambe and associated folds indicates sinistral strike slip movement probably took place on this fault.
Source rocks A number of wells have penetrated Carboniferous strata, particularly those drilled early in the exploration of the basin. Vitrinite reflectance data have been analysed (Hardman et al. 1993; Lenehan 1997) and indicates that geothermal gradients were fairly uniform across the basin but that uplift has brought the strata to new shallower depths inconsistent with their reflectance. Movement has been fault controlled, as described above, so the strata in different fault blocks were probably uplifted by different amounts. Reflectance values range from 0.5% Ro to 3.0% Ro. The source potential of the Carboniferous rocks is affected by earlier phases of burial and erosion in addition to their organic content. Westphalian
Fig. 7. Burial history (after Hardman et al. 1993).
SOUTH MORECAMBE FIELD sediments tend to have high total organic carbon (TOC) but it is mostly inertinite and therefore unproductive. The Namurian sediments (Holywell Shale and Bowland Shale equivalents) have better hydrocarbon potential because they contain sapropels. A burial history curve is shown in Figure 7 using an East Irish Sea Basin well, which penetrated the Carboniferous. This analysis predicts oil generation from late Carboniferous times and then some early gas generation during the Cretaceous. Thick carrier beds provided by the Sherwood Sandstone Group could have conveyed gas from a deeper depocentre than the one represented by the burial curve. This deeper part of the basin can be found to the north of the Morecambe fields and could have pushed the Namurian source rocks well into the gas generating window as early as Triassic times (Lenehan 1997). On the South Morecambe Field, analysis of fluid inclusions, isotope data, diagenetic mineral overgrowths and apatite fission tracks has led to the conclusion that a pre-existing structure was filled with oil. It was then breached by fault movement in the late Jurassic leaving oil stains, bitumen and the imprint of a palaeo-contact that is marked by the top of the illite affected reservoir. The modified structure was then filled with gas during the late Cretaceous to early Tertiary.
Reservoir As outlined above, the bulk of the South Morecambe gas in place lies within the Ormskirk Sandstone Formation, with some additional volumes in the underlying St. Bees Sandstone. Previous contributions have outlined the lithologies and characteristics of both reservoirs in great detail (Colter & Ebbern 1978; Bushel 1986; Stuart & Cowan 1991 and references therein). It is not the purpose of this paper to reiterate that work. However recent studies have resulted in a reappraisal of the reservoir layering scheme and a subtle change in the way that the illite affected reservoir is handled in the reservoir models. Authigenic platy illite is widespread across the northern and western areas of South Morecambe Field, but is only present below what has been interpreted as a palaeo-hydrocarbon-water contact (Bushel 1986; Woodward & Curtis 1987). Below this level, which is somewhat diffuse and defined only by the closeness of sidewall cores, platy illite levels reach 11% before declining downwards into the aquifer. Platy illite is absent on the Eastern flank of the field. Initially, for modelling purposes the subdivision of the Sherwood Sandstone Group reservoir of South Morecambe Field assumed that the presence of authigenic platy illite in the pore space was the overriding control on reservoir properties. This layering scheme was erected to meet the needs of the initial reservoir simulation model and reflected the understanding of the dynamic behaviour of the reservoir during pre- and early production times. During this period production was restricted to winter months and production levels were very small with respect to the gas in place. Consequently, only the gross permeability characteristics of the hydrocarbon column were exposed to 'investigation' by production drawdown. As the presence or absence of platy illite was clearly the most significant factor in controlling these gross permeability characteristics, it was an obvious step to subdivide the reservoir on the basis of illite content. This resulted in the primary division of the field into an illite-affected western fault block and an illite-free eastern flank. Further subdivision of the reservoir in the illiteaffected western area was then necessary in order to capture additional significant variations in permeability. This further subdivision was made on lithostratigraphic grounds and implies the recognition that within the illite affected area there was a facies control on permeability (Fig. 8). The resulting reservoir simulation model, therefore, captured facies controls on permeability in the illite affected area only. A figure in the Annex B submission, reproduced here as Figure 9 showed the 'illite-centric' view of permeability distribution in the reservoir by overlaying permeability profiles for both illitefree and illite-affected type sections. This figure illustrates the gross
113
permeability control exerted by the platy illite, with differences in absolute Kh of two orders of magnitude between the two rock types. However, the diagram also offers strong pointers towards there being a fundamental facies control on the permeability, which was subsequently reinforced by illite authigenesis. In particular: (a)
(b)
(c)
Permeabilities for both illite-free and illite-affected rock suddenly become equivalent at the base of the Ormskirk Sandstone, a major facies break. Porosity appears to be related to facies changes, and permeability to follow porosity in both illite-free and illiteaffected section There is a suggestion from the diagram that the stratigraphic members have differences in net to gross ratio, average porosity and average permeability both in illite-free and illiteaffected sections.
In the light of these observations and the need for a more refined simulation model for the illite free east flank of the field, it was decided to revise the reservoir subdivision. This subdivision seeks to extend flow layers on a field-wide basis, and to follow up the suggestion that flow layers were fundamentally controlled by sedimentary facies, with an illite affect superimposed in certain areas. An earlier suggestion of such an approach was documented by Cowan (1993). Following the example of Cowan & Bradney (1997), the new reservoir zonation recognized that facies associations on the South Morecambe Field could be viewed within a 'sequence stratigraphic' framework. Herries (1992) and Herries & Cowan (1997) have presented new sedimentological models for the Ormskirk Sandstone of the East Irish Sea Basin, which are based on sequence concepts. They show that deposition of the Ormskirk Sandstone was controlled by climatic cycles, with wet interludes characterized by deposition of fluvial sequences (or lacustrine shales) and dry intervals characterized by aeolian sediments. Drying upward cycles are apparent throughout the formation and can be correlated from well to well across the basin. The two critical controls on facies in the drier phases of the cycle were: (1) the position of the water table with respect to the sediment surface; and (2) the amount of aeolian sediment input. The balance of these two factors was key: high water table and/ or low sediment input led to the development of widespread clastic sabkhas while drier and/or higher sediment fluxes resulted in aeolian sandsheet and dune development. While the clastic sabkha facies suffers from early cementation and, today, is a poor quality reservoir, the aeolian sandsheet and dune facies are highly porous
Fig. 8. Comparison of reservoir zonation schemes.
114
J. C. BASTIN E T A L . PORO~n'Y1%)
UI'HO.06~ ~
ENVIRONMENT ~ ~
0
Io
20
0t
3O
IO
Kit PERMEABILITY 10 I00 1000 IO0s
=inuodtyt in - r sand= L~usfrine -r o~ndonmlm flood -r162162
?:i:!:i:!:!:!: j.
I
Stocluld N i l orgoniled ~
iiiiiiiiiiii?i
lendl
.:.:.:,:.:.:.:
Overbar&
z~
finNL ..........
"~:7.-i~~
Smmflood r
$
~oy ~
.%,.~,-,r
r
=and=
Welorganiud l #(ackcKlchannel s~ds Channela ~ flood samls
S~oMary/ep~-alm
m
Floodplain finu
i ~b':.:?i':?.
ShNtfloodlands
-~,
5~r
-/i-
~
UM=
R~/o I lacu=tl~
~ 1 and remain a high quality reservoir, even when illite cemented. Wet-phase fluvial facies are of moderate to good porosity and are variably affected by illite authigenesis. Based on a simplified application of these models to the cored well data set, it was possible to show that field wide reservoir zones could be established and that they would be suitable for populating a dynamic model. The new subdivision (Fig. 8) could be carried from the cored wells to the logged wells on the basis of petrofacies. In the illite affected wells, the new reservoir layering is closely compatible with that of the initial scheme. Additional stratgraphic layers have been included (Layers 1 to 3) in the upper part of the Ormskirk Sandstone and the whole layering scheme carries through into the illite free areas of the field. Not surprisingly the revised reservoir layering has much in common with the original lithostratigraphic subdivision of the field (Colter & Barr 1975).
35 I ....................................................................................... i
~
~ i................................................................... I
I =er
Fig. 9. Schematic representation of Sherwood Sandstone Group reservoir properties.
Petrophysical evaluation Recent field pressure and production performance have indicated a discrepancy between material balance estimates of gas in place and the corresponding volumetric estimates. A revision of the petrophysical analysis was carried out in 1998. The present work has led to revisions of the porosity and permeability evaluation methods and to components of the water saturation (Sw) evaluation. The changes to the Sw method include revised formation resistivities (Rt) and the use of the Archie equation with revised parameters 'a' and 'm'. Sw v. height equations were also developed. An outline of the analysis is described below. In the new porosity evaluation, advantage has been taken of the similarity in this field of the shale density and sandstone matrix densities. The density log can therefore be used alone to calculate effective porosity, after satisfactory hydrocarbon correction.
!i ............ ~i
30 "O
25 ,,.-,.
i,. O I.)
if)
O
O
,.
E
O
s
o
15
0,e
10
5 0 2.8
2.7
2.6
2.5
2.4
2.3
Uncorrected bulk density log (gm/cc)
2.2
2.1
2.0
Fig. 10. Compaction corrected core porosity v. log bulk density Iilite-free gas bearing layers.). Data from 17 South Morecambe cored wells n = 3717. Data includes mudstone beds. When RHOB = 2.26, porosity > 1.3719 - 0.5119 * RHOB. When RHOB < 2.26, porosity = 0.6930 - 0.2115 * RHOB.
SOUTH MORECAMBE FIELD Attempts were made to fit 'y on x' least squares regression curves to the data set of compacted core porosity and the density log, core porosity being the dependent variable. The previous compaction correction of 0.9744 was used. A simple straight line does not fit the data because of the increasing gas effect at higher porosities. Because of the rapid change in the shape of the data below about 2.3 gm/cc, no automatic curve-fit was found that satisfactorily fitted the data. A two-part manual line-fit that has the essential properties as a 'y on x' regression was therefore selected. This is shown in Figure 10. After calculating effective porosity, the invaded zone water saturation was estimated based from the porosity and Rxo. This evaluation method avoids complex interactive hydrocarbon correction and clay volume equations that require perfectly correlated Rxo, neutron and density logs to calculate effective porosity, the most important output. A simple gamma ray log based clay volume was also estimated using linear interpolation between maximum and minimum values.
True resistivity (Rt) and evaluation o f Sw The previous interpretation of water saturation was calculated directly from the Laterolog Groningen (LLG) log. The L L G was previously selected because the standard deep laterlog (LLD) deep laterolog resistivity can increase in the Morecambe conditions where very high resistivity beds (halites) occur above the deep laterolog position. The effect is exaggerated when casing is set through the overlying halite bed. The affected section of the L L D should be limited to a maximum of about 300 feet below the casing shoe (Woodhouse 1978). In the new work, all the resistivity logs were reviewed to determine whether the L L G is an appropriate source for Rt. In a majority of wells the L L G reads the same or slightly less than the L L D but in some wells it reads less than the LLS. Because of the configuration of its electrodes, the shallow laterlog (LLS) never exhibits the Groningen Effect. If the L L G curve was, in reality, a properly corrected L L D then, in Morecambe, it should never read values lower than the LLS, and should be reasonably close to the L L D in most circumstances. Schlumberger has informed H R L that the L L G curve is designed only as an indicator to show where the Groningen Effect is occurring; it does not provide a corrected LLD. For this reason the L L D was therefore selected as a better source of Rt. The presence of salt saturated water mud invasion causes the L L D and the LLS to be lower than Rt. Ideally invasion corrections
Fig. 11. Permeability prediction from log derived porosity (Illite-free gas bearing layer and layers L16 and below.).
l l5
would use all three LLD, LLS and M S F L readings. Such ideal corrections are, however, not very robust because good values of all three logs are required at each depth to generate a good Rt. An alternative simplified but more robust method was proposed in the technical paper that initially introduced the Laterolog 9 (Suau et al. 1972). This simplified method avoids the need for good M S F L measurements and uses only the L L D and LLS logs to create an un-invaded zone resistivity Rt using, for the DLT-E sondes, the formula: Rt = 1.59 x L L D - 0.59 x LLS Rt is slightly higher than the L L D almost everywhere and this leads directly to slightly reduced Sw values. Sw and therefore gas saturation were calculated using the Archie formula. Rw was derived from produced water measurements and an 'n' of 1.55 was determined from laboratory electrical measurements. Water bearing Sherwood Sandstone layers provide a robust in situ method to establish an appropriate combination of Rw, 'a' and 'm'. Representative values of formation resistivity and porosity were plotted from six wells with significant water bearing sections below the residual gas layer. The weighting of the higher porosity values was increased during the line-fitting because of their importance in the GIIP determination. The line-fit gives values for 'a' and 'm' of 0.51 and 2.44, when an Rw of 0.036 ohm-m is used. The laboratory measured formation factor data show a distribution about the water-zone derived 'a' and 'm' values. The higher than usual value for 'm' results from the inclusion of two or more lithologles in the one data set. The resulting Sw values in the water zones are satisfactorily spread around 100% Sw. The Sw of lower porosity sands is slightly increased by using the revised 'a' and 'm' values. Sw values measured directly on preserved oil-base mud cores, the best estimate of true reservoir water saturation (Woodhouse 1998), are not available in the Morecambe Fields. Acquiring such data may resolve the question of why low permeability rocks frequently have lower calculated Sw values than those of higher permeability rocks.
Net pay - development of revised porosity cut-offs Net pay was previously determined by porosity cut-offs related to a permeability of 0.1 mD at ambient laboratory conditions. Recent work has led to higher porosity cut-off values for all zones. The previous choice of a cut-off of 0.1 mD ambient permeability was
116
J. C. BASTIN ET AL. A
ffl
11012a-F1
40
e" .m ~,-
30
O e~
20
eO
s
~ w
m w
_
!~ ~900
10
1
U
..1 -t
"O 0
i
'c--
"I"
0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
30
Porosity cut-off (p.u.) Fig. 13. Sensitivity of net pay to porosity cut-off: Well 110/3a-A7 (Illite free (1992) layers.).
)100
,
I
Jl
.~r~"
11 3200
.IMP --. ~
L_---2w
-I
340o
--
r
.-nr-.
m
.
w .i
t
Further evidence of in situ permeability was found in the buildup of mud-cake resulting from mud invasion. In two appraisal wells (110/2-1 and 110/2-2) a microlog-caliper tool (MLC) was run. These logs detect mud-cake from the response of the pad-mounted 1" and 2" logs and the reduction of hole-size. Figure 12 shows there is invasion where the porosity cut-offs include the formation as 'pay'. The sensitivity of the resulting net hydrocarbon pore volume to changes in the porosity cut-off is examined for well A-7, in Figure 13. There is practically no gas-in-place below the 7% porosity cut-off. In the illite-affected layers approximately 15% of the apparent gas-in-place is eliminated by the new 11% porosity cut-off.
9
1
G a s - w a t e r contact and f r e e water level i
3701 IMP..
i
l
b
,
_
J
m I
3901
r
f
f
"1
"t
400(
t t
410(
L
1
Fig. 12. Well 110/2a-F1 showing net pay, porosity, permeability and moveable hydrocarbons. subjective. Laboratory core preparation methods often exaggerate the effective permeability of shales, claystones and shaly sandstones. These rocks are one of the sources of the low permeability values. Compaction corrections indicate that 0. lmd relates to about 0.01 mD at reservoir conditions. A more realistic ambient cut-off is now seen to be 0.2mD. Evidence of gas flow on production logs gives little help in the choice of porosity cut-off. The main gas flows often come from the very high permeability (1000 mD) layers. Even the 100 m D layers do not flow when they are co-mingled with the 1000mD layers. Clearly, over time, the 100mD and 10roD layers will contribute to production by gas movement in the reservoir, even if they are not directly contributing at the well. In the new permeability evaluation the zonal permeability versus porosity data sets have been used and are shown in Figure 11. The zones below the Upper Platy Illite have been combined into one zone to determine the porosity cut-off of 11 porosity units. In the illite-free zone the net pay porosity cut-off is seven porosity units.
Formation pressures were obtained from the appraisal wells and from a few of the development wells. The majority of the development wells terminated 100 vertical feet above the free water level (FWL) as a precaution against water coning and therefore did not provide data which could be used to determine a FWL. Figure 14 shows R F T pressure profiles which establish the FWL in South Morecambe Field as 3750 ft TVDSS. All these R F T profiles were taken before the change in production philosophy in 1990 when the field was put on to much higher annual production takes. Phase II of the field development consisted of installing DP6 and DP8 in 1989. Seven wells were drilled from each platform from 1989 to 1991 and analysis of log data and depletion affected R F T measurements were initially thought to indicate a locally shallower F W L (3657 ft TVDSS) in the vicinity of DP8. However more recent analysis suggests that lower permeability reservoir units interbedded
1750
1800 1850 1900 1950 ' ..........................................
-2500~ ' ' '
2000
+
9" "
-2750 1
=.,ooo -3250
!
" + .............................................................. + O . . . . . . . . . . . . . .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
x C 1 22/9184
i
.
+ ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
,
.................................. •....
.................................................................
...~.
[]A5913/87
o 03 4/3/85
i + F1 21/7/89
t
~~._[~.~_o
ni0
-3500 ............................................... § .................................................................................... : -3750
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
H 1 318/89
.
.
.
.
.
.
.
.
.
.
.
.
_
LXH3 20/12/89
-400O
Pressure (psia)
Fig. 14. RFT pressures defining the free water level at 3750 ft TVDss.
SOUTH MORECAMBE FIELD
117
South Morecambe Field data summary Trap Type Depth to crest Lowest closing contour FWL Gas column Pay Zone Formation
Fig. 15. South Morecambe gas production from first gas (Jan 1985). with more permeable and therefore depleted units prevents any firm conclusions being drawn as the FWL in this area.
Reserves and production Gas production takes place from a network of four normally unmanned platforms, which are connected by gas gathering lines to a central gas processing and transmission complex. This central complex includes a production platform with a further eight development wells, giving a current total of 34 development wells. Thirty-two of these are active, one never produced, and one succumbed at an early stage to what is believed to be localized water encroachment. First gas from South Morecambe was produced in January 1985. The development plan was based on the concept of using the field as a seasonal supply facility (peak shaver), to produce gas at very high rates over the winter. Figure 15 shows the monthly production since first gas. The pattern of peak winter production is clearly displayed. Analysis of the historical dynamic performance of the South Morecambe field leads to the conclusion that on a gross basis, the reservoir behaves in a 'tank-like' fashion; that is to say, there appears to be a high degree of lateral communication throughout the reservoir, and a predictable relationship exists between the cumulative gas production and the average reservoir pressure (classic volumetric depletion). Reservoir pressures have been collected from the field wells at least once a year throughout the field history, either from wellhead measurements during platform shut-downs, or from direct downhole gauge measurements. The historical pressure data shows no obvious indication of water influx, or significant recharging of the reservoir during low offtake periods from gas volumes trapped in low permeability rock. The main reservoir area appears from historical pressure data to be in good pressure equilibrium, with average summer static reservoir pressures varying by <10psi throughout. The main reservoir area encompasses all the South Morecambe field except the area drained by the H1, H3, H4, and H7 wells of the DP-8 platform, and the area to the north of these wells up to the northern field boundary. Pressure data from these northern wells (H1, H3, H4, and H7) indicates a more complex situation, suggesting a 'bottleneck' in this area, which impedes the flow of gas from the northern area through to the main area. The available data suggest that the pressure gradient across the greater part of the northern area is less severe than it is locally around the DP-8 platform. Gas initially in place in the South Morecambe field is estimated from dynamic performance (material balance) methods to be 5.5 Tcf and by volumetric methods to be 6.3 Tcf. Remaining recoverable reserves are at least 3 Tcf. The authors thank Centrica/HRL for permission to publish this paper and wish to acknowledge the contribution of the many other workers who have written and in many cases published so much material bringing our understanding of the petroleum geology of this field to its current state.
Tilted Fault Blocks -2200~ -4050fi -3750~ 1300~
Age Gross thickness Net/gross average (range) Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Ormskirk Sandstone St Bees Sandstone Triassic 870 + 3100 ft 79% (100 to 60%) 14% (7 to 22%) 150roD (0.3 to 1000mD) 75% (92 to 60%) 2.4 mmscfd/psi
Petroleum Gas gravity Viscosity Dew point Condensate yield Formation volume factor Gas expansion factor
0.64 0.016 cp 1795 psia 3.1 bbl/mmscf 0.0068 146 scf/rcf
Formation water Salinity Resistivity
300 000 NaC1 eq. ppm 0.036 Ohm m
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Gas initially in place Recovery factor Drive mechanism Recoverable gas Recoverable NGL/condensate
20 700 acres 1.18 • 107 acreft 1861 psi 0.0475 psi/ft 91~ 5500 bcf 93% Volumetric depletion 5100 bcf 14 mmbbls
Production Start-up date Production rate plateau gas Number/type of well Number/type of well
January 1985 1800 mmscfd 34 production 7 appraisal
References BUSHELL, T. P. 1986. Reservoir Geology of the Morecambe Field. In: BROOKS, J., GOFF, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in Northwest Europe. Geological Society, London, Special Publications, 23, 189-207. COLTER, V. S. & BARR, K. W. 1975. Recent Developments in the Geology of the Irish Sea and Cheshire Basins. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of North-West Europe, Volume 1: Geology. Applied Science Publishers, London, 61-75. COLTER,V. S. 8~;EBBERN,J. 1978. The petrography and reservoir properties of some Triassic sandstones of the Northern Irish Sea Basin. Journal of the Geological Society, London, 135, 57-62. COWAN, G. 1993. Identification and significance of aeolian deposits within the dominantly fluvial Sherwood Sandstone Group of the East Irish Sea Basin, UK. In: NORTH, C. P. & PROSSER, J. (eds) Characterisation of fluvial and aeolian reservoirs. Geological Society, London, Special Publications, 73, 231-245. COWAN, G. 8,: BRADNEY, J. 1997. Regional diagenetic controls on reservoir properties in the Millom accumulation: implication for field development. In: MEADOWS, N. S., TRUEBLOOD,S. P., HARDMAN, M
118
J. C. BASTIN E T AL.
COWAN, G. (eds) Petroleum Geology of the Irish Sea and Adjacent areas. Geological Society, London, Special Publications, 124, 373-386. HARDMAN, M., BUCHANAN, J., HERRINGTON, P. & CARR, A. 1993. Geochemical modelling of the East Irish Sea Basin: its influence on predicting hydrocarbon type and quality. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference, Volume 2. Geological Society, London, 857-866. HERRIES, R. D. 1992. Sedimentology of continental erg-margin interactions. PhD thesis, University of Aberdeen. HERRIES, R. D. & COWAN, G. 1997. Challenging the 'sheetflood' myth: the role of water-table-controlled sabkha deposits in redefining the depositional model for the Ormskirk Sandstone Formation (Lower Triassic), East Irish Sea Basin. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the Irish Sea and Adjacent areas. Geological Society, London, Special Publications, 124, 253-276. JACKSON, D. I., MULHOLLAND,P., JONES, S. M. & WARRINGTON, G. 1987. The geological framework of the East Irish Sea Basin. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum geology of North West Europe. Graham and Trotman, London, 191-203. KNIPE, R. J., COWAN, G. & BALENDRAN,V. S. 1993. The Tectonic history of the East irish Sea Basin with reference to the Morecambe Fields. In:
PARKER, J. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference Volume 2. Geological Society, London, 857-866. LENEHAN, T. 1997. An investigation into thermo-tectonic and maturation histories in Northwest Britain. Unpublished PhD thesis, The University of Leeds. SUAU, J., GRIMALDI, P., POUPON, A. • SOUHAITE, P. 1972. The Dual Laterolog-Rxo tool. 47th Annual SPE meeting, Paper SPE 4018. STUART, I. A. & COWAN,G. 1991. The South Morecambe Field, Blocks 110/ 2a, 110/3a, 110/8a, UK East Irish Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 527-541. WOODHOUSE, R. 1978. The Groningen Phantom can cost you money. SPWLA 19th Annual Symposium, Paper R. WOODHOUSE, R. 1998: Accurate Reservoir Water Saturations from Oil-Mud Cores - Questions and Answers from Prudhoe Bay and Beyond. The Log Analyst, May-June, 23-47. WOODWARD, K. & CURTIS, C. D. 1987. Predictive modelling of the distribution of production constraining illites Morecambe Gas Field, Irish Sea, Offshore UK. In: BROOKS,J. & GLENNIE,K. W. (eds) Petroleum geology of North West Europe. Graham and Trotman, London, 205-215.
DOUGLAS OIL FIELD Hamilton Field. This is overlain by the Calder Sandstone Member (Wilmslow Sandstone equivalent), a sequence of predominantly fine- to medium-grained sandy braided river deposits. These two members form the St. Bees Sandstone Formation. The overlying Ormskirk Sandstone Formation (Helsby Sandstone equivalent) is the principle reservoir target in the East Irish Sea Basin. It consists of fluvial and aeolian sandstones of variable grain size. Many of the fluvial sands have a high proportion of reworked aeolian grains and there are rapid thickness variations of fluvial and aeolian facies. The Ormskirk Sandstone Formation is divided into three members: OS 1, OS2a and OS2b, which were formerly known as the Thurstaston, Delamere and Frodsham Members, respectively (Meadows & Beach 1993). These can be easily recognized on the Wirral and in all the wells drilled in Block 110/13. They exhibit very distinct gamma ray and sonic log characteristics. The OS1 Member includes a mixed sequence of fluvial and aeolian sediments. The OS2a Member is predominantly fluvial with occasional playa lake claystones. The uppermost OS2b Member represents predominantly aeolian conditions, although a sequence of fluvial facies is present in the middle of the unit. The Mercia Mudstone Group consists of a cyclic sequence with alternating sandy mudstones and Halites. The Rossall and Mythop Halites are each less than 50 ft thick and the Preesall Halite has a thickness of around 500 ft.
Structure Three principal seismic marker horizons can be identified from the 3D seismic data: Top Ormskirk Sandstone Formation (top reservoir); Top Collyhurst Sandstone Formation; and Top Carboniferous. Top Ormskirk pick is the most prominent and consistent seismic marker over the whole area. The main factors controlling seismic data quality over the Douglas Field are the variation of structural complexity, diffractions and other fault noise and seafloor conditions. The top reservoir map was depth-converted using a velocity v. seismic two-way-time function combined with a V0 value that varies spatially depending on the geology of the overburden. Latest development drilling has shown that the interpretation of a reliable top reservoir depth structure depends on a good understanding of the near surface formations. The structural history of the East Irish Sea Basin has been discussed in considerable detail elsewhere (Bushell 1986; Green 1986; Jackson et al. 1987; Stuart & Cowan 1991; Jackson & Mulholland 1993; Yaliz 1997). Structural interpretation of seismic data in Block 110/13 supports the view that post-Variscan tectonics were responsible for basin evolution and trap-forming events in the area (Fig. 3). Extension during the Early Permian led to half-graben structures with N-S faults controlling facies and thickness variations. All faults of the Permian framework of the area were active during the Triassic. As a result of continuing fault activity during the Early Triassic the Sherwood Sandstone Group shows a marked increase in thickness towards the Gogarth fault (Fig. 4). The overall thickness of this group in the Douglas area is around 3000ft compared with 5000 ft in the East Deemster basin (the Lennox area). Further rifting and extension took place during the late Triassic. The Mercia Mudstone Group of this age shows development of intermediate-scale structures and locally severe block-fault rotation. Due to the effects of erosion no Jurassic is seen in the basin, and extension during this period is inferred from data outside the area (Jackson et al. 1987). The post Jurassic history of the Douglas area is also difficult to constrain as the Triassic is immediately overlain by Quaternary drift. However, various authors have shown that the East Irish Sea Basin experienced a major phase of inversion and uplift during Tertiary (Lewis et al. 1992; Hardman et al. 1993; Williams & Eaton 1993; Cope 1994). Fault controlled structures formed during Triassic-Jurassic rifting were modified during early Tertiary inversion and new structures were generated. The Douglas structure is principally controlled by the Gogarth Fault, which is a shallow dipping (0-45~ N-S oriented feature lying to the west of Block 110/13 (Fig. 4). A deep master detach-
65
ment fault extending into Carboniferous shales gives rise to the Gogarth fault ramp-flat listric system beneath the Douglas Field. The topography of the Gogarth fault plane has played a major role in the development of the Douglas trap during extension and its adjustment during later inversion. Contractional movements (thrusting) along the Gogarth ramp-flat listric fault during Tertiary uplift caused the Douglas structure to move westwards to its present day position at the crest of an anticlinal feature. This gave rise to a small net extension at the Gogarth fault as the contractional movements stopped before a reverse fault was developed. The Hamilton Field lies on the eastern side of the crestal collapse graben within an antithetic fault province.
Trap The Douglas Field trap consists of three major fault blocks elongated N-S and dipping at approximately 15~ to the west (Figs 5 and 6). The Douglas trap was formed within the fault footwalls of these fault blocks during a major phase of extensional faulting in Triassic-Jurassic times. Drilling results have shown that the boundary faults are planar dipping at around 45 ~ to the east. Seismic data indicate that cross-fault transfer zones are not common at reservoir level, but a few widely spaced examples can be mapped from high resolution aeromagnetic data. The structure as a whole is fault bounded to the east, and dip closed to the north, west and south. The culmination of the structure is at 2140ft in the central fault
5 934 000
5 932 000
5 930 000
461 000
463 000
Fig. 5. Top reservoir depth structure map of the Douglas Field showing the exploration/appraisal and development well locations and the field-wide oilwater contacts.
DOUGLAS
OIL FIELD
67
Zonation and reservoir quality
indicate the development and migration of several dunes in response to increased sand supply. Aeolian sandsheet facies are characterized by single grain to millimetre scale horizontal and low angle, planar cross-stratification and are interbedded with aeolian dune sandstones as finely laminated sequences. Their thickness range is 0.5 to 1.5ft. This indicates that aeolian sandsheet conditions were episodically developed on a low relief plain. Aeolian Sabkha facies are very fine- to fine-grained, poor to moderately sorted and comprise subangular to well rounded grains. The individual beds range from 0.25 to 1.5ft in thickness and are characterized by an irregular flat lamination style. They typically occur as 5-10ft thick units which can be correlated over several kilometres within Block 110/13. They are almost always associated with the aeolian dune and aeolian sandsheet deposits and often contain high concentrations (up to 15%) of dolomite and anhydrite. Fluvial channel sandstones have been deposited within active and abandonment channels. They form stacked sand bodies which are poorly sorted and grade from fine to coarse sand. Sedimentary structures include low to moderate tabular cross-stratification with preserved set thicknesses ranging from 0.35 to 4ft, and flat laminations. A stacked sequence is commonly made of 10-12 channels and has an average thickness of about 15 ft. The sandstones are usually characterized by abundant small intraclasts which are dolomite cemented, green siltstone and pink very fine-grained sandstone fragments. Fluvial abandonment sediments are characterized by siltstone dominated units, 0.4 10 ft thick. They form the upper section of broadly fining-upward sequences of fluvial channel facies. Playa lake andfloodplain deposits are not common, but where present they form laterally extensive grey-black mudstone and siltstone units, generally occurring in the middle of fluvial channel sequences. They are considered to form effective vertical reservoir barriers due to their lack of any permeability.
The vertical distribution of sedimentary lithofacies in the Douglas wells can be subdivided into four distinct zones, which can be easily identified by wireline logs and core analysis data (Figs 9 and 10). Zones I, II and III are the OS2b, OS2a and OS1 Members, and Zone IV is the St. Bees Sandstone Formation. Zone I is further sub-divided into three parts. The uppermost Zone IA has a fairly uniform thickness of around 80 ft and consists of several units of aeolian dune and aeolian sandsheet alternating with aeolian sabkha sandstones. It is the most significant layer, containing almost half of the field's reserves. Permeability in the aeolian dune facies is often several darcies, while the porosities have a range of 20-30%. Zone IB, with an average thickness of 35 ft, is a low quality reservoir consisting of thinly interbedded fluvial channel and fluvial abandonment deposits. Zone IC with high permeability aeolian sandstones is similar to Zone IA but its thickness averages only 45 ft. Zone II consists exclusively of fluvial deposits, with its thickness increasing from 250 ft in the east to 350 ft in the west, towards the Gogarth fault. Zone III has a fairly uniform thickness of around 200 ft and includes a variety of aeolian dune, sandsheet and aeolian sabkha facies. Very little oil is present in Zone III. Zone IV consists of fluvial sandstones and is principally mapped as an aquifer. The reservoir characteristics of each zone based on core porosity and permeability data are illustrated in Figure 11. A good log-linear relationship exists between the porosity and permeability values in all zones except Zone II. However, the slope and the intercept of the regression lines show slight differences between zones. The 'shotgun effect' seen in Zone II data is thought to be an artifact of the numerous small shale clasts it typically contains. The highest porosity and permeability values (27% and 10 000 md, respectively) were measured in the aeolian dune and sandsheet facies in Zones IA
South
North 110/13-6 GR
MO
~! .... _ -- ~i
~d----7-1, ,,oi,.
110113-13
110/13-10
110t13-2 GR
SONIC
GR
.......>~ -.
SS
SONIC
GR g
-{
-"
4~
MD
SONIC
,
MD
110113-11
SONIC ,, ......
GR
~_.~
,I
MO
SONIC
t, '
-~~i,
J
_5: ~
-
-
If
-
4 9
,
I
~
.....
~.c~
"
-
"2400
"
~
"
~ .
]
!
.
,,-
_
-
o "~ ...._.~ ~
- 2780 -
~
~
JN00
-
9
.
-
~u~,
=
,,
'-'
'
9
"Y i -
~
9
2ZO0
-
?
*
_
"%
1
: 9
_ 1
.
,.,..
.
F'-- "-~. 110113b I BHP
i
;g-
:
I
L I
[e
N
E
i
r
~
1
.
.
.
.
.
,~,w
I
~1(;"; i,:
1 ;
,,
(
i-]
9
~
'
Fig. 9. Reservoir zone correlation between the exploration/appraisal wells in the Douglas Field. Individual sandstone units can often be correlated over several hundred metres.
DOUGLAS OIL FIELD I ? I
TRIASSIC
I ?
JURASSIC
71 I ?
CRETACEOUS
TERTIARY
I
BIODEGRATION I!~!i!!!!!i!i!iiiiiiiiiiiiiiiiiiiiiiii!i!!!]WATER WASHING [.. ,. ,:.:.:.:.:..:.............
..,,c.
INCR. WAXINESS ::::::::::::::::::::::::::::::
HIC's lost
Low GOR
t:.: :::.:+::-::-:~+:.::.:.~:.:.:+:.
Very light condensate charge
NHG's (N2, C02, H2S)
OII Window
!i:
:
" Condensate
I .................... :'il
'i
Early oil, few traces left
Main oil charge
'
Light-medium /~
Bitumens
I Depth of Source Rock
gravity,
non-waxy, sweet
.
- Dry Gas
t:,~. . . . . . . . . i.......... ::1
Fig. 14. Hydrocarbon filling history of the Douglas Field showing at least two oil and one light condensate charges during the Jurassic and Cretaceous. for peak gas generation (1.2%) and approaches the base oil window threshold (1.3%). The source rocks for the Douglas Field are considered to be fairly local, probably lying towards the southwestern part of the field where they have reached the required thermal maturity levels to generate the Douglas oil (Fig. 13).
Outcrops of Namurian Holywell Shales in North Wales contain rocks rich in amorphous organic material, with TOC values of 2-5%. Seismic data and drilling information have shown that the Namurian Holywell Shales are present in Block 110/13 and these rocks are believed to be the source rocks for the Douglas oil (Armstrong et al. 1997). Evaluation of the cuttings samples from the Namurian interval of the Hamilton well 110/13-1, which is 8 km NE of the Douglas Field, revealed the presence of significant amounts of organic carbon, with TOC ranging between 1.0 and 1.6%. The range of vitrinite reflectance values showed a wide range from 0.55% to 1.17 %. It was concluded that the present day maturity level of these sediments is in the range 1.15-1.19%, which is close to the threshold
110113-2
Hydrocarbon filling history Various proprietary studies by the Geochem Group on a suite of oil and gas samples from the Douglas and Lennox Fields indicate that the hydrocarbon filling histories in these fields were complex but
110113-D2
SW
NE
2000' 2100' Mercia Mudstone 2200'
1 1
~.
2300' U) O
I
i~
21110'
Q-
2~0'
i... 11
.
x
.,,.-
<- . . . . . . . . . .
"
r- OWC-
II
2600' I I
2700'
I
i
I
II11 -" ~" \
I
2800'
1
2900'
....-
.-
IV I
0
I
..-"
1
1
11
I 11
1
1 ..,~1 I
1 1 t i
1
III
I I
11"*"
v - ~-"
"IV
I % ~ II
1 1
I
1
III
100m
Fig. 15. Geological interpretation along wells 110/13-2 and 110/13-D2. The actual position of the boundary fault was found to be approximately 60m further west than prognosed and as a result the producer well D2 was completed in Zone I only.
74
A. YALIZ & N. McKIM
Hydrocarbon volumes and development plans
Douglas Field data summary
The current estimated oil-in-place, based on volumetrics calculations, is 202 MMBBL. At Annex B approval the STOIIP estimate was 225 MMBBL. The decrease to the current value results from improved geological understanding. Firstly, within the bitumen layer log-derived effective porosities were overestimated because of uncertainties in the fluid and matrix density values. Well data has confirmed the presence and extent of the bitumen zone which gently dips (1-2 ~) north-northwest. Secondly, prediction of the major fault positions from the 3D seismic data proved to be difficult, as illustrated by well 110/13-D2 in Figure 15. As a result, the seismic data were reprocessed using pre-stack depth migration techniques. The decreased STOIIP has been countered by a better than expected production performance. Contrary to earlier predictions no deterioration of the reservoir quality was observed near the faults, where log analysis indicated excellent porosities. Further, communication between fault blocks and reservoir layers has been better than expected. These factors lead to an expectation of improved waterflood sweep efficiency. Field pressure maintenance is achieved by a combination of natural aquifer influx and sea-water injection. Despite the large volumes, the aquifer has contributed only some 20% of the total pressure support. Between 1994 and 1999 ten producers and six water injectors were drilled, most being long step-out wells. Currently, however, one of the producers is being used as a condensate injector and one of the water injectors is a gas injector. Typical well trajectories for both producers and injectors are illustrated in Figure 16. Long step-out wells have S-shaped paths with a long horizontal section in the Mercia Mudstone. The wells are designed to penetrate the reservoirs parallel to the major fault planes. The producers are placed near the crest of each tilted fault block, between 50 and 75 m away from the fault plane. By placing the producers close to faults the recovery of the 'attic' oil beneath the fault planes is greatly improved during the waterflood. All production wells have an electrical submersible pump (ESP) for artificial lift, which are placed just above the top reservoir. The Douglas Field forms part of BHP Petroleum's Liverpool Bay Integrated Development scheme as illustrated in Figure 17. Douglas complex is also designed to handle the processing and export of hydrocarbons from the Hamilton (gas), Hamilton North (gas) and Lennox (oil and gas) fields. The first oil was produced in February 1996, and the expected field life is up to 15 years. Water injection rates vary according to average production rates so that sufficient voidage replacement is achieved in each block of the field. The Douglas complex dehydrates and sweetens the Douglas and Lennox oils prior to their export via pipeline to an offshore storage barge. A subsea pipeline transports crude from the Douglas complex to an offshore loading unit. The Hamilton and Hamilton North gas goes to BHP Petroleum's Point of Ayr terminal. After further processing and the sulphur removal at the terminal, the gas is delivered to PowerGen's power station at Connah's Quay. Forward field development planning is being based on a full field 3D geocellular model, providing a much improved structural model and reservoir facies description. The geological grid was constructed with 50 x 50 • 1 m grid cells and 120 layers resulting in a total of one million cells for the full field. A facies grid is shown in Figure 18. The geological grids were upscaled to a simulator model with a cell size of 50 x 100 x 5 m. This model has been history matched with three years of production data and is now providing a means to optimize future development drilling plans.
Trap Type Depth to crest Hydrocarbon contacts Oil column
Structural 2140 ft TVSS 2515-2535 ft TVSS 375 ft max
Main pay zone Formation Age Net/gross ratio Cut-off for N/G Porosity average Permeability average (air) Productivity index
Ormskirk Sandstone Triassic 0.90-1.0 3 mD 18% Zone I, 13.7% Zone II 2000 mD Zone I, 300 mD Zone II 5-30 BOPD/PSI
Hydrocarbons Oil gravity Oil type Bubble point Gas/oil ratio Formation volume factor
44~ API Low sulphur 285 PSI 170 SCF/BBL 1.075 RB/STB
Formation water Salinity Resistivity
270 000 ppm NaC1 equivalent 0.030 ohm-m at 30~
Reservoir conditions Temperature Pressure Pressure gradient in reservoir
30~ l125PSI at 2240ft TVSS 0.35 PSI/ft
Field size Area Gross rock volume STOIIP Drive mechanism
6.5 sq km 240 000 ac-ft 202 MMBBL water injection
This paper is published by permission of BHP Petroleum Ltd and the Liverpool Bay Group participants; LASMO (ULX) Ltd and Centrica plc. Contributions of N. Meadows, S. Habesch and N. Bailey of Geochem Group to the understanding of the sedimentology and the geochemistry of the field, H. E. Edwards to the understanding of the structural history, and all efforts of C. Bryan in interpreting the complex seismic data are gratefully acknowledged.
Production Start-up date Development scheme
Number/type of wells
February 1996 Central 24-slot wellhead tower, oil exported via pipeline to offshore storage unit for export by tanker. 5 exploration/appraisal 11 producers 7 water injectors
References ARMSTRONG, J. P., SMITH, J., D'ELIA, g. A. A. & TRUEBLOOD,S. P. 1997. The occurrence and correlation of oils and Namurian source rocks in the Liverpool Bay-North Wales area. In: MEADOWS, N. S., TRUEBLOOD,S. P., HARDMAN,M. & COWAN,G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 195-211. BUSHELL, T. P. 1986. Reservoir geology of the Morecambe Field. In: BROOKS, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N.W. Europe. Geological Society, London, Special Publications, 23,
189-208. COPE, J. C. W. 1994. A latest Cretaceous hotspot and the south-easterly tilt of Britain. Journal of the Geological Society, London, 151, 905-908. GREEN, P. F. 1986. On the thermotectonic evolution of Northern England: evidence from fission track analysis. Geological Magazine, 123, 493-506. HARDMAN, M., BUCHANAN, J., HERRINGTON, P. 8z. CARR, A. 1993. Geochemical modelling of the East Irish Sea Basin: its influence on predicting hydrocarbon type and quality. In: PARKER,J. R. (ed.) Petroleum Geology of North West Europe." Proceedings of the 4th Conference. Geological Society, London, 809-821.
DOUGLAS OIL FIELD HERRIES, R. D. & COWAN, G. 1997. Challenging the 'sheetflood' myth: the role of water-table-controlled sabkha deposits in redefining the depositional model for the Ormskirk Sandstone Formation (Lower Triassic), East Irish Sea Basin. In: MEADOWS,S. S., TRUEBLOOD,S. P., HARDMAN, M. 8~ COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 253-276. JACKSON, D. I., JOHNSON, U. ~ SMITH, N. J. P. 1997. Stratigraphical relationships and a revised lithostratigraphical nomenclature for the Carboniferous, Permian and Triassic rocks of the offshore East Irish Sea Basin. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 11-32. JACKSON, U. I. & MULHOLLAND,P. 1993. Tectonic and stratigraphic aspects of the East Irish Sea basin and adjacent areas: contrasts in their postCarboniferous structural styles. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the 4th Conference. Geological Society, London, 791-808. JACKSON, D. I., MULHOLLAND, P., JONES, S. M. & WARRINGTON, G. 1987. The geological framework of the East Irish Sea basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham and Trotman, London, 191-203. LEwis, C. L. E., GREEN, P. F., CARTER, A. & HURFORD, A. J. 1992. Elevated K/T palaeotemperatures throughout Northwest England: three
75
kilometres of Tertiary erosion? Earth and Planetary Science Letters, 112, 141-145. LOMANDO, A. J. 1992. The influence of solid reservoir bitumen on reservoir quality. Bulletin of the American Association of Petroleum Geologists, 76, 1137-1152. MEADOWS, N. S. & BEACH, A. 1993. Structural and climatic controls on facies distribution in a mixed fluvial and aeolian reservoir: the Triassic Sherwood sandstone in the Irish Sea. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Fluvial and Aeolian Reservoirs. Geological Society, London, Special Publications, 73, 247-264. STUART, I. A. • COWAN, G. 1991. Morecambe Gas Field, Blocks 110/2a, 110/3a, 110/Sa, U.K. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 527-541. WILLIAMS, G. D. & EATON, G. P. 1993. Stratigraphic and structural analysis of the Late Palaeozoic-Mesozoic of NE Wales and Liverpool Bay: implications for hydrocarbon prospectivity. Journal of the Geological Society, London, 150, 489-499. YALIZ, M. A. 1997. The Douglas Oil Field. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the East Irish Sea and Adjacent Areas. Geological Society, London, Special Publications, 124, 399-416.
ANDREW AND CYRUS FIELDS ultimate reserves still remains, with C1Z and C2Z watercuts not rising as steeply as predicted from modelling work, and with lower water cuts than 16/28-13Z. Therefore ultimate reserves could continue to creep up. Seismic imaging and rock property work is planned to identify remaining oil in place, which may be targeted in the future as part of a side-track or infill programme.
Discovery
137
Amalgamated, channel sandstones are separated by poorer thinner mud prone interchannel deposits. These mud prone packages represent the main permeability barriers within the reservoir and are believed to be discontinuous with dimensions in the order of hundreds of meters. The reservoir is split into two zones Unit A and B overlain by the Andrew Shale. Unit A average porosity from density logs is 14.9% and for Unit B is 19.6%. Net has been determined by imposing a 9% porosity cut off and a 35% V Shale cut off. 36.6% is used for Unit A and 95.7% for Unit B. Quality decreases upwards, and the horizontal well trajectories aim to cut across key shale horizons increasing vertical connectivity.
The Cyrus Field was discovered in 1979 by well 16/28-4, 4S which encountered a 35m oil column in Paleocene Andrew Formation sands (Mound et al. 1991).
Reserves and production Structure, stratigraphy, trap and source The Cyrus Field overlies a Zechstein salt dome, actively emplaced during the Tertiary. The Cyrus reservoir is Paleocene sandstones of the Andrew Formation. Cyrus is a combined structural four-way dip closed trap with crest at 2520m sub-sea. The second well on Cyrus 16/28-10 encountered an O W C at 2558 m sub-sea, 8 m deeper than the discovery well 16/28-4st (2550m sub-sea). The 16/28-13 well established that the probable contact is between the first two values and 2554m sub-sea has been accepted as the most likely OWC. Cyrus oil was sourced from the Jurassic Kimmeridge Clay Formation.
Cyrus STOIIP remains at 82 M M B B L with 19.6 BCF of associated gas. Cyrus field reserves have decreased from Annex B estimations but remain highly uncertain. By end 1992, the field had produced 4.4MMSTB reserves through the Cyrus SWOPS production. The 1994 Annex B expected mean oil reserve to be recovered by re-developing Cyrus as a sub-sea tie back to Andrew was 23.5 MMSTB. Current reserve estimates after three years of production are 16.25 MMSTB.
Reference Reservoir Cyrus is a Paleocene age, submarine fan sandstone reservoir, consisting of a series of juxtaposed and superimposed channel systems.
MOUND, D. G., ROBERTSON,I. D. & WALLIS,R. J. 1991. The Cyrus Field, Block 16/28, UK North Sea. In: ABBOTS,I. L. (ed.) United Kingdom Oil and Gas Fields 25 Years Commemerative Volume. Geological Society, London, Memoir, 14, 295-300
The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields I. A. S T U A R T
BG Group, 100 Thames Valley Park Drive, Reading RG6 1PT, UK
Abstract: In 1994 the Armada partnership sanctioned the simultaneous development of the Fleming, Drake and Hawkins Gascondensate Fields by means of shared facilities; the overall project was called the Armada Development. The operator is BG International (formerly British Gas). The development was interesting because the component fields are not only separate accumulations, but are of completely different geological type. The Fleming Field is a Palaeocene, Maureen Formation high-density turbidite reservoir, sourced from the north but pinching out eastwards against the N-S Utsira/Jaeren High and Hawkins-Varg Ridge, and therefore forming a 20 km long, continuous, but very narrow reservoir. The Drake Field is an Upper Jurassic, Fulmar Formation, shallow marine, shore-face reservoir, with excellent reservoir quality in a compact fault block. The Hawkins Field reservoir is poorer quality Fulmar Formation, typical of a more distal setting; the trap is formed by closure over a salt dome, and the structure is consequently quite heavily faulted. The challenge was to develop these disparate reservoirs from a single surface site, to capture the awkward shape of Fleming and the distance between Drake and Hawkins. This was achieved by means of extended reach drilling; although the high cost of such wells meant that every one had to be designed for maximum yield. Overall eight wells were drilled, five to Fleming, two to Drake and one to Hawkins (these numbers being approximately proportional to gas-in-place). These wells are capable of delivering the project design peak rate of 450 mmscfd off-platform (equivalent to about 480 mmscfd reservoir gas), and up to 24000 BOPD condensate. Armada began production on schedule in October 1997.
Introduction and history Exploration and pre-development This paper discusses the development of the Armada fields, and describes some aspects of their geology which have been of importance to their development. Armada is located in the Central North Sea on the 58~ parallel of latitude, and lies c. 250 km N E of Aberdeen, c. 22 km S of the Maureen Oil Field and c. 22 km N of the Everest Gas-condensate Field. Water depth is about 89 m (292 ft). Armada comprises three separate gas-condensate fields (Fig. 1): (1) (2) (3)
Fleming: Palaeocene Maureen Formation reservoir, approximate depth 9000 feet Hawkins: Upper Jurassic Fulmar Formation reservoir, approximate depth 10 000 feet Drake: Upper Jurassic Fuhnar Formation reservoir, approximate depth 11 000 feet
The term 'Armada' describes the simultaneous development of these three fields. Armada is operated by BG International (formerly British Gas), on behalf of a joint venture partnership, which also includes (current ownership) Agip, BP Amoco, TotalFina, Phillips, and Yorkshire Energy. The sanction of field development in 1994 by the Armada partnership marked the culmination of nearly 30 years of exploration, appraisal, and pre-development activity, starting from the award of the first licence in 1965. The Armada Unit extends across parts of five U K licence blocks:
Block
Operator
License
Awarded
Round
22/5a 16/29a 22/4a 22/5b 16/29c
BP Amoco Phillips Phillips BG Phillips
P066 P 110 P355 P356 P591
1965 1970 1980 1980 1987
2 3 7 7 10
interval (Fulmar Formation), and this marked the discovery of Hawkins Field. The well also encountered a thin (about 10ft) Palaeocene sandstone, which appeared to be hydrocarbon bearing on logs, but was not tested. The discovery of Drake and Fleming followed in 1982 when Superior (then operator of 22/5b) drilled Well 22/5b-2. This encountered gas-condensate-bearing sandstone intervals at both Palaeocene (Maureen Formation) and Upper Jurassic (Fulmar Formation) levels. The Jurassic discovery was named Drake, the Palaeocene 'Howard'. Well 22/4-3 (1986/87) was drilled by Phillips down-dip from the thin Palaeocene sandstone seen in 22/5a-1A. This well discovered gas-condensate in a thick Palaeocene sandstone interval, and this discovery was named 'Maggie'. Several appraisal wells were drilled by the various licence operators spread across all five of the blocks listed above. By the late 1980s it was realized that 'Howard' and 'Maggie' were in fact a single continuous accumulation, overlying the two Upper Jurassic accumulations Drake and Hawkins. In 1992 the name Fleming was adopted to replace 'Maggie' and 'Howard'. To the south of Armada lies the Everest Gas-condensate Field, the entry point to the CATS (Central Area Transmission System) gas pipeline to Teesside. The decision to proceed with the CATS development was taken in 1990. The development of Everest and CATS was a prerequisite for the development of Armada. A period of technical studies and commercial negotiations followed, during which a series of swaps and buy-outs reduced the number of the Armada coventurers in the five blocks down to six. British Gas Exploration and Production (now BG International) was appointed Armada operator in March 1992. Between 1992 and 1994 technical and engineering studies proceeded in parallel with commercial negotiations in the key areas of gas sales, transportation and unitization. The commercial issues that required resolution before the project could proceed were unusually complex for the time; these are described in Baldwin (1994). The Armada development received joint venture approval on 18th May 1994, and Annex B approval followed in June. Project execution was carried out in the period 1994 to 1997, and Armada came into production, on schedule, on 1st October 1997.
Unitization The locations of the exploration and appraisal wells drilled on and around the Armada fields are shown on Figure 1. The discovery of Armada dates back to 1980 when Amoco drilled well 22/5a-lA on what is now recognized as the Hawkins salt diapair. This well encountered a gas-condensate-bearing Upper Jurassic sandstone
Although Fleming, Drake and Hawkins are separate fields, they have been unitized as a single unit. Furthermore, the equities in the unit were permanently fixed at the time of project approval (May 1994), and are not subject to any re-determination. Armada was
GLUYAS, J. G. & HICHENS,H. M. (eds) 2002. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 139-151.
139
140
I. A. STUART
Fig. 1. Location map.
one of first UK developments to achieve a fixed-equity unitization. This was considered a major technical and commercial achievement, in view of the complexity of the situation (three fields, five licence blocks, six companies). Substantial cost savings have been secured from the fixed equity unitization, as a result of the elimination of elaborate procedures and lengthy re-determinations. Furthermore, fixed equity has allowed the development to proceed with maximum technical efficiency and allows for optimum technical decision-making. The equities are: BG, 45.27%; BP Amoco, 18.20%; TotalFina, 12.53 %; Phillips Petroleum, 11.45 %; Yorkshire Energy, 6.97%; and Agip, 5.58%.
Development Armada has been developed by means of a single 21-slot production, quarters and wellheads platform, supported on a piled four legged steel jacket structure, located mid-way between Drake and Hawkins. The platform process includes: separation, dehydration, compression, and metering of the gas and condensate export streams. Off-platform capacity is 450 mmscfd. Gas and condensate are exported, in separate pipelines, to the North Everest riser platform for onward transmission. The gas is transported to Teesside via the CATS pipeline, and the condensate passes to Cruden Bay (and hence Grangemouth) via the Forties pipeline. Initial development planning had assumed that two platforms would be required, one each over Drake and Hawkins, in order to access both these fields, and to allow for adequate drainage of the Fleming Field (which is about 20 km N-S, see Fig. 1). However, evaluation of lower cost options demonstrated that very consider-
able savings could be achieved by development from a single platform, centrally located between Drake and Hawkins. The challenge was to develop these disparate reservoirs from a single surface site, optimizing the development to account for the size and elongate shape of Fleming, and the separation between Drake and Hawkins. This was achieved by means of extended reach drilling; although the cost of such wells meant that every one had to be designed for maximum production as well as optimum reserves recovery. One of the main challenges for the geoscientists was to quantify geological uncertainty in a programme of very high angle extended reach wells, in order to minimize technical risk. This work was greatly aided by the Armada 3D seismic survey, which was acquired in 1992-1993, and which formed the definitive seismic dataset upon which the development was based. Eight development wells (five to Fleming, two to Drake, and one to Hawkins, these numbers being approximately proportional to gas-in-place) were drilled in 1995-1996 from the Santa Fe 135 semi-submersible, through a ten-slot pre-drilling template. The two additional slots on the template provided a contingency to drill one or two further wells, in the event of poor results from one or more of the first eight wells. However, the outcome of the first eight wells meant that these extra slots were not needed. Several of the development wells had total depths well in excess of 20000 feet, and reached angles well over 70 ~. The longest well was drilled at 77 ~ and had a total depth of 23 905 feet, which was a world record for a well drilled from a semi-submersible. The paths of two of these wells are illustrated, at true scale, on Figure 2. These wells were tied back and completed by a jack-up, the Santa Fe Magellan, operating in tender assist mode, following platform installation in 1997. Later platform drilling, during production, will be performed by a jack-up in tender assist mode.
ARMADA DEVELOPMENT
141
North
South ARMADA PLATFORM
0
0 20004000-
Well 22/5b-A2 - Drake Total Depth 18970ft Maximum Deviation 63 -o dropping to 38-~in the Reservoir
Well 22/5b-A8 - Fleming Total Length 23905ft Maximum Deviation 77 ~
-4000 6000
6000FLEMING
80001000012000-
-2000
8000 DRAKE
10000 12000
HAWKINS
0
10000 ft
r
I
I
Horizontal Scale No verticalexaggeration
Fig. 2. Schematic, true-scale, cross-section through the Armada Fields, illustrating the well paths of two of the Armada development wells, one each to Fleming and Drake. The adoption of the single platform development and extended reach drilling techniques contributed to a development cost of <35 per barrel of oil equivalent for Armada, amongst the lowest achieved in the North Sea.
Stratigraphy and regional setting Armada lies on the southeast margin of the South Viking Graben in the region where it intersects the Outer Moray Firth (Witch Ground
Fig. 3. Armada area stratigraphy.
Graben) and the northern end of the East Central Graben. The Jaeren High, which forms the eastern flank of the Graben in this area, lies to the east of the Armada fields and has significantly influenced their geological development, particularly of the Fleming Field. To the southwest lies the Fisher Bank Basin, which is presumed to have been the source area for the Armada hydrocarbons. This is a major Early Cretaceous depocentre resulting from the thermal collapse of the triple junction. To the south of Drake, the Jaeren Fault system has influenced the distribution of the Upper Jurassic Sandstone system.
142
I . A . STUART ........~ ........................ ,
South Viking Graben 9
i Ut$ira
Structural geology and seismic considerations
Maureen Field Diapir 9
9
pinchout/shaleout of the Maureen Formation sandsones. The Lista Formation mudstones provide the cap-rock.
Armada
J
The structure map on the top of the Maureen Formation is shown on Figure 5. The Fleming Field is an N - S trending High, c. 20 km long and 4 km wide. Closure to the east is provided by pinchout/ shaleout of the Maureen Formation against the Utsira/Jaeren High, with dip closure to the north, west, and south. Figure 6 shows an E - W seismic line through the field, demonstrating the pinchout. Pinchout of the reservoir is defined where the Maureen Formation time thickness reaches a constant value of about 12 msecs. The southern part of the field has very low relief, but the northern and central part of the field has undergone uplift over the Hawkins salt diapir and as a result the structure dips quite steeply to the west. Most of the salt movement responsible for the topography in the northern and central part of Fleming occurred during the Eocene and Oligocene. As a result, the Maureen Formation pinchout line does not follow the present day structural contours; the pinchout line roughly follows the N-S line of the Hawkins diapir, but rises up and over the crest rather than following the structural contours around the periphery. An understanding of the structural history of the Fleming Field is important as a means to appreciating the structural controls on Maureen Formation deposition. In the earliest Paleocene
High
9
\
1~
f J
FgEE y TE
J
i i
r Grabon
i
..... ~
9
Fig. 4. Base Cretaceous time map of Fisher Bank Basin with Jurassic structural elements.
/~~
16129c
r
( ~.,.... 16/29a
"\
' "':"'
\ Figure 1 shows the relative positions of the three fields within the five licence blocks, and Figure 3 shows the stratigraphy in the Armada area. Figure 4 shows the relationships of the main structural elements mentioned in this paper. The oldest rocks penetrated in the Armada wells are Zechstein salts and anhydrites, in the well 22/5a-lA on the crest of the Hawkins diapair. Salt diapirism has overprinted and complicated the present day picture. Salt movement may have been initiated as early as the Triassic, but was accentuated by Jurassic rifting and continued well into the Tertiary. Much of the apparent complexity of the PreCretaceous stratigraphy, such as differential erosion, faulting, and inversion, is believed to have resulted from the effects of diapirism. The Hawkins Field is situated over a diapir that lies at the southern end of a salt ridge, which extends from Hawkins northwards as far as the Varg Field in Norway; this is referred to here as the Hawkins-Varg ridge.
22/5~' \
58~
\ EASTERN LIMITI OFSANDSTONE '\
-~ J)!.
% :
'L;n;igf r~6 tiOn
\
?i i
Fleming Field 22/4b
Introductory remarks
[-~A3 Fleming is the largest of the three fields, containing over 60% of the total Armada gas-in-place and reserves. The reservoir sandstones lie within the Palaeocene Maureen Formation (Knox & Holloway 1992). The Fleming Field is an N-S elongate structure and lies at c. 9000 feet below mean sea level. Closure depends upon eastwards
22/4a
Phase One Development ] wells to Fleming, BHL and Top Reservoir
Note: Line of Section for Figure 7 coincides with well path of 22/5b-A4
22/5a
0 I
2 km I
Fig. 5. Fleming Field, depth structure map of top Maureen Formation reservoir with locations of development wells, and key for Figures 6 and 7.
Fig. 6. West to east seismic line through the Fleming Field, to illustrate the updip thinning and pinchout of the Maureen Formation.
Fig. 7. Seismic line through Fleming Field development well 22/5b-A4. The line illustrates the very low 'Attack Angle' between the well path and the reservoir, and also the 'Flat Spot' which represents the gas-water contact.
144
I.A. STUART
the Armada area was a low-relief basin, confined to the east by the Utsira/Jaeren Highs, with a gentle westward palaeoslope towards to Fisher Bank Basin. Palaeocene sedimentation was broadly controlled by the Utsira/Jaeren Highs, with turbidites flowing down the axis of the basin. However, local salt features also had a significant influence: the Hawkins-Varg ridge, as well as the Maureen Field salt diapir to the north, appear to have influenced palaeocurrent directions during Maureen Formation times. High-density turbidity currents entered the area from the NNW, maintaining a S-SE palaeoflow as they passed the incipient Maureen Field diapir. The incipient Hawkins-Varg ridge appears to have had sufficient elevation to prevent the turbidity currents from flowing over the top; instead the currents were deflected southwards. The Maureen Formation shows an asymmetric distribution across the Hawkins-Varg ridge with 300 to 400 feet having been deposited on the western (basinward) side, but only about 60 feet of pelagic mudstones on the eastern side. The younger Lista and Sele Formations do not display the same thickness asymmetry across the Hawkins-Varg ridge, but simply thicken gradually westwards towards the basin centre. The basin topography was largely infilled by the end of the Lower Paleocene. The structure is not highly faulted; the only area where a significant degree of faulting is apparent is on the part of the structure that lies over the crest of the Hawkins salt diapir, the area of maximum structural inversion. Over part of the field the fluid contact manifests itself as a very distinct direct-hydrocarbon-indicator (flat spot) on the 3D seismic data, shown on Figure 7. This can be mapped throughout much of the north and central part of the field. The flat spot is not seen in the southern part of the field, because of the very shallow dip and the relatively thin nature of the section. A significant source of uncertainty, even after development drilling, is depth conversion. The two seismic horizons of interest are Top Maureen Formation and Top 'Chalk' (strictly top Maureen carbonate). Although the two horizons can be independently depth converted, the more reliable method is to depth convert directly down to Top 'Chalk', then generate a Top Maureen Formation depth surface by subtracting a Maureen Formation isochore generated by use of a linear function, which relates interval time to thickness. The quantification of uncertainty due to depth conversion can be investigated by conducting a range of deterministic techniques, but a fuller appreciation of this uncertainty can be attained by use of stochastic techniques. In this case, stochastic depth conversion has been carried out using the 'Horizon' module within the 'STORM' stochastic modelling package. Stochastic simulations generate a range of possible outcomes, which permit a better understanding of the uncertainty. The input velocity dataset comprised raw stacking velocities, thereby preserving the true variability in the velocity data. The resulting stochastic gross rock volume distribution can be used to calibrate deterministic methods (see Fig. 8). In addition to gross rock volumes, isoprobability maps can be generated to show the probability of a given point on a surface being above or below a given depth (normally the gas-water contact depth).
Reservoir
Three large Paleocene turbidite complexes are developed across the Central Graben and South Viking Graben area, the oldest of which is the Maureen Formation. On a regional basis the lower Palaeogene turbidite systems may be termed basin floor fans, deposited during sea-level lowstands (den Hartog Jager et al. 1993). The entire Maureen depositional system forms part of a lowstand systems tract (Vining et al. 1993) produced as a response to large-scale regression at the beginning of the Paleocene. Uplift and tilting of the East Shetland Platform provided a large amount of clastic detritus, which was transported long distance and entered the Armada area along a N N W to SSE palaeocurrent direction. The structural controls on palaeoflow have been discussed in the preceding section. Away from the pinchout edge the Maureen Formation over the Fleming
Fig. 8. Fleming and Drake Fields. Frequency of volumetric realizations (expressed as gross rock volume) from stochastic depth conversion exercise. Field is about 300 to 400 feet thick, with a net/gross of around 60%. Figure 9 shows the reservoir in a typical well. By far the most important facies type in the Maureen Formation is fine to medium grained, moderately- to poorly-sorted homogeneous sandstones. These are generally massively bedded and destructured while sedimentary structures are dominated by water escape features. The sandstones are separated by hemipelagic bioturbated mudstones. Transitions between the sandstones and the mudstones are sharp and small-scale interbedding is not observed. These sandstones were deposited from very sand-rich high-density sediment gravity flows, which entered an otherwise quiescent basinal environment. Individual flows may be up to six feet thick, but can be stacked into massive amalgamated sandstone units, with a maximum thickness of 75 feet. Gross reservoir properties are fairly uniform through any sandstone unit (Fig. 9). The sandstones are considered to have been deposited as thick-bedded submarine sand lobes (Mutti 1985); these can be very extensive both longitudinally and laterally and have a slab-like geometry. This has important implications for reservoir continuity, and contrasts with more confined channelized deposits which would have resulted in a much more elaborate internal geometry within the reservoir sequence. A problem that has to be addressed when dealing with this type of reservoir is the degree of continuity of the intra-reservoir mudstones. Less than adequate biostratigraphical data leads to ambiguities in inter-well correlation. However, modern probabilistic techniques (known as graphic correlation, and ranking and scaling) can be applied in an attempt to minimize these ambiguities. This work has shown that thick-bedded sand lobes can correlate with time-equivalent mud rocks over short distances, particularly in the upper part of the reservoir interval. This geometry is explained by a system of nested lobes, which can combine to make more extensive sand bodies. Lateral connectivity between lobes is expected to be mostly very high. Although the major intra-reservoir mudstones are likely to have been laterally extensive across the field, high levels of slumping and sand remobilization and scouring at the base of composite sandstone intervals is likely to have produced discontinuities in even the most extensive mudstones. As a result a high degree of vertical connectivity is to be expected over the majority of the field.
ARMADA DEVELOPMENT
145
Fig. 9. Fleming Field. Reservoir sequence with log and core information in a typical well (16/29a-9), illustrating the uniformity of reservoir properties within individual sandstone units. It is also interesting that, despite the small scale complexity, the net/gross for the overall Maureen Formation follows a fairly simple, predictable pattern, which has proved highly reliable in predicting net/gross in the development wells.
Development drilling Five long reach wells were drilled prior to production. Their locations are shown on Figure 5. These included several highly challenging extended reach wells. Target selection was a critical issue for these wells; if targeted too far east, they would have penetrated the reservoir towards the Maureen Formation pinch out. This would result in a thin reservoir with relatively low deliverability. On the other hand, targeting the wells too far to the west, whilst ensuring a thick Maureen Formation, would have placed the wells at risk of penetrating the gas-water contact. Such wells might have had a high initial deliverability but would decline or water out rapidly. Figure 2 is a true-scale representation of well 22/5b-A8 to illustrate the geometry of the longest of these wells. Figure 7 shows the path of the well 22/5b-A4, drilled at an angle of about 72 ~ on a N N W trajectory in an area where the structure dips to the northwest. The difficulty with this and several of the other development wells was that the well path was, of necessity, designed to approach the reservoir at a high angle on a down-dip trajectory. Depth conversion uncertainties added further risk to well placement; fortunately, the direct hydrocarbon indicator, which represents the known gas-water contact (described above), was a considerable aid in well positioning. All of the development wells penetrated the reservoir at high angles, 60 ~ to 74~ these behave virtually as horizontal wells, enhancing well deliverability.
Drake Field
Introductory remarks Drake is the larger of the two Jurassic fields, and contains about 27% of the Armada gas-in-place and reserves. The reservoir comprises shallow marine shore face sandstones of the Upper Jurassic (Oxfordian) Fulmar Formation (Richards et al. 1993). The reservoir is overlain and sealed by Upper Jurassic mudstones of the Heather and Kimmeridge Clay Formations. Underlying the Fulmar Formation is the Middle Jurassic Pentland Formation. The Drake Field lies within Block 22/5b at about 11,000 feet below mean sea level, deeper than, and partly underlying, the Fleming Field.
Structural geology and seismic considerations The composite structure map on the top of the Fulmar Formation is shown on Figure 10. On N W - S E seismic lines (Fig. 11) the Drake structure appears as a tilted fault block. A western bounding fault provides fault closure with complete reservoir offset. The structure is dip-closed to the north, east and south. On the western part of the structure the Heather and Kimmeridge Clay Formations, together with much of the Fulmar Formation, are truncated at Base Cretaceous. The present day structure is the product of a several stages of structural evolution and basin development, described in the following paragraphs. Prior to deposition of the Fulmar Formation, the coals, shales and sandstones of the Pentland Formation were deposited in a low relief, northward draining floodplain. The top of the Pentland is
146
I. A. STUART
Fig. 10. Drake Field, depth structure map on top Fulmar Formation reservoir.
Fig. 11. NW-SE seismic line through the Drake structure, showing the Drake Western Bounding Fault on the left, and the Jaeren Fault, which was fundamental to the structural development of Drake, on the right.
marked by a prominent coal, which forms an important seismic marker across much of the Armada area. The basin was flooded during the early Oxfordian and a N - S shoreline was established along its eastern margin. The Hugin Formation (late Callovian to earliest Oxfordian very shallow marine to nearshore facies) is not clearly developed in Drake, although the basal cycle (see below) may be Hugin-equivalent. The Oxfordian Fulmar Formation was deposited under shallow marine conditions. Active salt withdrawal was occurring to the southeast of Drake during Fulmar deposition, allowing the Fulmar to reach a thickness of 1000 feet or more.
The shoreline was drowned in the late Oxfordian and retreated eastwards. The Heather Formation mudstones (latest Oxfordian to middle Kimmeridgian) were deposited later, in the resulting offshore open marine conditions. From the early Kimmeridgian, major N W - S E extension occurred, with large scale rotation focused on the Jaeren Fault. The western bounding fault of the Drake Field was formed at this time. This phase of extension and rotation resulted in emergence and erosion of the fault block crest, so that the upper portion of the Fulmar has been progressively truncated towards the fault block
ARMADA DEVELOPMENT
Fig. 12. Schematic representation of stratigraphy N W to SE across Drake Field. Compare seismic line, Figure 11.
Fig. 13. South to north seismic line through the Drake structure.
147
148
I . A . STUART
crest, along what is now the western part of the Drake Field. At the same time the Heather and lower parts of the Kimmeridge Clay Formations thicken southeastwards away from Drake towards the Jaeren Fault (Fig. 12). The tilted fault blocks were drowned during the Volgian and draped by thin deep marine mudstones of the later Kimmeridge Clay Formations. This was followed by early Cretaceous inversion along a N N W - S S E trend, coupled with high angle reverse faulting along the northern side of the field. As a result, in N-S cross-section, the Drake structure now has the appearance of a north-facing monocline (Fig. 13). This phase resulted in steep southwards dip at Top Fulmar Formation over most of the Drake structure. The faulting along the northern part of field shows very little offset, and with sand-on-sand juxtaposition along its length, may form a partial transmissibility barrier to flow, but does not form a seal. The inverted structure was finally onlapped by Early Cretaceous marls (Cromer Knoll Group). Two seismic horizons define the top to the reservoir: the Base Cretaceous Unconformity, and Base Kimmeridge Clay Formation (Top Oxfordian). The top reservoir structure map (Fig. 10) is thus a composite of these two seismic horizons; in the east the top reservoir surface is true Top Fulmar, whereas on the west of the structure, where the Fulmar is partially truncated, the top reservoir surface coincides with Base Cretaceous Unconformity. The Top Pentland (Middle Jurassic Coal) event defines the base of the reservoir. In addition, three intra-reservoir events are apparent, and are useful in guiding the mapping of reservoir subdivisions away from the wells. As with the Fleming Field, depth conversion remains a key uncertainty, even after development drilling, and the uncertainty may likewise be assessed using a range of deterministic techniques in conjunction with stochastic simulations carried out in the 'STORM' stochastic modelling package (see above for discussion of methods). The resulting stochastic gross rock volume distribution is shown on Figure 8.
Reservoir The Drake reservoir comprises mainly fine-grained sandstones belonging to the Fulmar Formation of Oxfordian, Upper Jurassic age. These are shallow marine sediments, and the facies reflect deposition under conditions ranging from offshore to shore face. The Fulmar Formation in the Drake Field comprises stacked, broadly coarsening-upwards (or at least cleaning-upwards) cycles, which represent repeated shoaling on a very low angle shallow marine shelf. The shoaling cycles are separated by minor transgressive flooding surfaces. The typical Fulmar Formation in the Drake Field is shown on Figure 14, which illustrates the typical upward cleaning and coarsening log and poroperm profiles. The best reservoir properties are developed at the tops of each cycle in the middle to upper shore face, but the majority of the cleaner sands are lower shore face, in which intense bioturbation has obliterated any primary bedding structures. The lower portions of each cycle belong to the proximal end of the offshore-transition zone, also characterized by intense bioturbation. The offshore-transition zone facies are also often characterized by an abundance of siliceous sponge spicules Rhaxella. Offshore shelf mudstones are not present within the Drake reservoir sequence. The lowermost cycle (up to about 50 feet) represents the initial progradation across a stable shelf, and is of relatively constant thickness. The overlying cycles are each up to 400 feet thick, and the overall Fulmar Formation is believed to exceed 1000 feet in thickness (the 22/5b-7 well did not reach the base of the Fulmar Formation). The thickness of the individual cycles and the overall thickness of the Fulmar Formation at Drake are caused by localized salt withdrawal underneath and to the southeast of what is now the Drake structure. The Fulmar Formation thickens rapidly down-dip to the east and south, providing a substantial aquifer, but the upper portions are progressively truncated from a line west of the wells 22/5b-2 and 22/5b-A6 westwards to the crest along the western bounding fault (see Figure 15).
Fig. 14. Well 22/5b-2 summary log.
Development drilling The result of this depositional and structural history is a geometry in which the top reservoir surface dips to the south over the majority of the field area, whereas there is an internal eastward dip of layers within the reservoir as a result of the Kimmeridgian rotation. This posed considerable difficulties for development drilling, and the difficulties were compounded by the high degree of depth uncertainty on the top reservoir structure. Wells drilled from the central platform location needed to approach Drake at deviations of over 60 ~ southwards towards a structure which itself has a substantial southwards dip. The difficulties were overcome by drilling S-shaped wells, and in one case designing the well path to turn westwards on its approach to the reservoir to mitigate against the effects of erosion at the top of the reservoir sequence and to intersect the best reservoir properties at the top of each cycle in the optimum position.
Hawkins Field
Introductory remarks Hawkins is the smaller of the two Jurassic fields, containing just 12% of the Armada gas-in-place. It is the least important of the three fields in terms of its reserves and deliverability. The Hawkins Field reservoir comprises shallow marine shore face sandstones of the Upper Jurassic Fulmar Formation. The Hawkins Field lies mainly in Block 22/5a, but extends into 22/5b and 16/29a, and underlies the Fleming Field at approximately 10 000 feet below mean sea level. The overall stratigraphy is similar to Drake in that the Pentland, Fulmar, Heather and Kimmeridge Clay Formations are all present.
Structural geology and seismic considerations The structural/stratigraphical configuration of the Hawkins Field is illustrated on the west to east cross-section shown on Figure 16.
ARMADA DEVELOPMENT
149
Fig. 15. Drake Field reservoir correlation.
The Hawkins structure is complex because the field lies above a salt diapir, which forms the southern culmination of the Hawkins-Varg ridge. A key feature of the structure is a major N N E - S S W low angle fault, which soles out on the top of the Zechstein salt, and has the effect of dividing the Hawkins structure into two distinct fault blocks. There are numerous small-scale faults, but they are difficult to correlate over any distance. The Hawkins structure is an inverted Late Jurassic half graben but the former extent of this is difficult to reconstruct. Severe diapirism started in the late Jurassic, and was reactivated intermittently. Major episodes of growth occurred in the early Cretaceous, and again in the Eocene and Oligocene. Movement on the major N N E SSW fault occurred mainly during the Cretaceous.
The seismic horizons that define the reservoir are the same as for the Drake Field. Again, depth conversion remains a major source of uncertainty.
Reservoir The Hawkins reservoir comprises shallow marine shore-face sandstones of the Fulmar Formation, of Oxfordian, Upper Jurassic age. Although the Fulmar Formation in the Hawkins Field can be closely correlated with that of the Drake Field, the facies present in the Hawkins Field are generally more distal in nature. The upper
Fig. 16. Hawkins Field. West to east seismicbased cross-section illustrating stratigraphy and structural development.
150
I.A.
STUART
9 9
8
9
@
[.,,,,
t"--.-
w. r
eq
r
~,,
,.-.,
o
o
9 9 ~[--,
,,<.<
,,< .,<
o
9
E~
O
,..-.- ,,.....- c q
o
6S~
tth
~.o. ~0 q'h
%,, r.~
6 s
6
8~
9
8
+.~
~
~
s~
~
~
~ ~
o ~
+..a
ARMADA DEVELOPMENT part of the Fulmar Formation consists mainly of distal offshore sediments with high clay content and relatively low permeability. Sandstones in the lower part of the reservoir sequence are, in part, of better reservoir quality. The top of the lower cycle is a 'spiculite', composed largely of Rhaxella sponge spicules.
D e v e l o p m e n t drilling
Just one development well was drilled to Hawkins prior to production. This was drilled to the eastern side of the field, and was a relatively straightforward deviated well.
151
by natural depletion. The development is designed to deliver a peak production rate of 450 M M S C F D and up to 24 000 BPD condensate. Armada began production on schedule in October 1997, and quickly built up to these peak rates of production. The author would like to thank the management of BG International and its coventurers in Armada for permission to publish this paper. Particular thanks are due to colleagues in BG International development geoscience and petroleum engineering groups whose work has contributed substantially to our understanding of the Armada fields, and hence to the contents of this paper.
References Source and fluid composition The Armada hydrocarbons are presumed to have been sourced from the Fisher Bank Basin. They comprise a lean gas-condensate, with condensate-to-gas ratios in the region of 50 BBLS/MMSCF. The compositions of the three fields are very similar, with slightly higher CGRs and slightly higher CO2 content in the Jurassic compared with the Paleocene.
Reserves and production The Fleming and Drake Fields both comprise high quality reservoirs, and are proven to have high deliverabilities. The Hawkins Field is the least important of the Armada fields, but is a good example of a small, complex field that is nevertheless capable of development through synergy with the development of the larger Drake and Fleming Fields. It is estimated that the three fields contain a total wet gas-in-place of about 1760 BCF, which will provide reserves of approximately 1200 BCF sales gas and 70 MMBBL of liquids (condensate and NGLs). The fields will be produced
BALDWIN, T. J. 1994. The Armada Project." The Commercial Challenges. London and Southern Gas Association. DEN HARTOGJAGER,D., GILES,M. R. & GRIFFITHS,G. R. 1993. Evolution of Paleogene submarine fans of the North Sea in space and time. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 59-72. KNOX, R. W. O'B. & HOLLOWAY,S. 1992. Paleogene of the Central and Northern North Sea. In: KNOX,R. W. O'B. & CORDEY,W. G. (eds)Lithostratigraphic Nomenclature qf the UK North Sea. British Geological Society, Nottingham. MUTTI, E. 1985. Turbidite systems and their relation to depositional sequences. In: ZL'Vl.'A,G. G. (ed.) Provenance ofArenites. NATO Advanced Scientific Institute Series, 65-73. RICHARDS, P. C., LOTT, G. K., JOHNSON,H., KNOX, R. W. O'B. & RIDING, J. B. 1993. Jurassic of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY,W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Society, Nottingham. VINING, B. A., IOANNIDES,N. S. & PICKERING, K. T. 1993. Stratigraphic relationships of some Tertiary lowstand depositional systems in the Central North Sea. In: PARKER,J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 17-30.
The Beryl Field, Block 9/13, UK North Sea R. M . K A R A S E K ,
R. L. V A U G H A N
& T. T. M A S U D A
Mobil North Sea Ltd., Grampian House, Union Row, Aberdeen ABIO 1SA, UK (e-mail."
[email protected],
[email protected] and
[email protected])
Abstract: The Beryl Field is located within Block 9/13 in the UK North Sea, in the west central part of the Viking Graben. The block was awarded in 1971 to a Mobil operated partnership, and the 9/13-1 discovery well drilled in 1972. The Beryl A platform was installed in 1975 and oil production started up the following year. The Beryl B platform was added in 1983 and production and gas re-injection pressure support commenced in 1984. The first 3D seismic survey was shot over the field in 1986, and the most recent in 1997. As of January 1999, 133 wells have been drilled into the field and development drilling is expected to continue well into the twenty-first century. Commercial hydrocarbons occur in sandstone reservoirs ranging in age from Triassic to late Jurassic, with the primary reservoir being the Middle Jurassic Beryl Formation (1.4 billion barrels of oil originally in place). Total ultimate recovery for all reservoirs in the field is expected to be about 960 million barrels of oil (MMBBL) and 2.1 trillion cubic feet (TCF) of gas. As of January 1999, the field has produced nearly 710 MMBBL of oil, or almost 75 % of the ultimate oil recovery. The field has been described previously by Knutson and Munro (1991), and Robertson (1993). Recent drilling data (more than 30 new wells) and new 3D seismic have updated the initial field descriptions. These data allow the mapping of two key unconformities, the Mid Cinunerian (Jt) event and a Base Callovian (Jb3) event. Reservoir facies models and isochore maps have also been developed, which together with the refined structural model, allow a better understanding of the reservoir distributions and will guide future production strategies.
The Beryl Field is located in Block 9/13 in the N E N o r t h Sea, approximately 215 miles N E of A b e r d e e n (Fig. 1). The field covers an area of a b o u t 12000 acres and water depths range from 350 to 400 ft. The Beryl Field is the largest of several h y d r o c a r b o n - b e a r i n g structures in the block, and is divided into two p r o d u c i n g areas: Beryl (A) A l p h a in the south and Beryl (B) Bravo in the north. The Ness, Nevis and K a t r i n e satellite fields all rely on the Beryl producing infrastructure. The current estimate of stock tank oil in place (STOIIP), based on recent mapping, for Beryl A and B is 2322 M M B B L . Gas-inplace (GIIP), consisting primarily of solution gas, is estimated at
a b o u t three T C F . P r o d u c t i o n is from six reservoirs, ranging in age from the late Triassic to the late Jurassic. The M i d d l e Jurassic B a t h o n i a n to Callovian age, Beryl F o r m a t i o n is the m a i n reservoir unit, and contains a b o u t 78% of the total ultimate recovery. The Beryl Field has been described previously by K n u t s o n & M u n r o (1991) a n d R o b e r t s o n (1993). This p a p e r provides an u p d a t e to those studies with six years of additional drilling on the block, including m o r e than 30 wells on the field alone. The new well data, including core a n d petrophysical analyses, have been incorp o r a t e d into detailed facies models and isochore maps (using T V T thicknesses, u n c o r r e c t e d for c o m p a c t i o n ) for each of the m a j o r reservoir units.
Fig. 1. Location map of the Beryl Field within the Beryl Embayment.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 153-166.
153
154
R. M. KARASEK E T AL. Table 1. Licence Interests in Block 9/13, a b and c Company
Initial interest (Dec 1971)
Current interest (1/1/1999)
Mobil North Sea Ltd. Amerada Hess Ltd. Texas Eastern (UK) Ltd. North Sea Ltd. (BG) Enterprise Oil plc OMV (UK) Ltd.
50% 20% 20% 10%
50% 22.22%
22.78% 5%
In Block 9/13d OMV(UK) Ltd. does not hold an interest and Mobil North Sea Ltd. holds an additional 5% working interest.
Discovery
Block 9/13 was acquired to test a large structural closure mapped seismically at the Paleocene level. Pre-Cretaceous sediments beneath the Base Cretaceous unconformity were recognized as a deeper secondary target. The discovery well 9/13-1, drilled in September 1972, found Paleocene reservoir quality sandstone with minor traces of hydrocarbons. The well also encountered 350ft of oil-bearing Jurassic sandstone, beneath the Base Cretaceous unconformity and reached a total depth o f - 1 0 300 ft TVSS without penetrating an oil-water contact. The Jurassic section flowed 30 ~ API oil at a rate of 3400 barrels of oil per day (BOPD) through a 3/4in. choke.
Post-discovery
Fig. 2. Colour draped Base Cretaceous relief map of the Beryl Embayment (red, shallow; blue, deep). Illuminated from the northwest.
Our understanding of the fields has also been enhanced by a new 3D seismic data set shot in 1997. This 3D data set has been merged with offsetting surveys to develop a more regional view of the Beryl structure (Fig. 2). Interpretation of the new seismic data together with the results of recent drilling has allowed the detailed mapping of two key unconformities: a regional Mid Cimmerian (Jt) event and more recently a Base Callovian (Jb3) unconformity. These unconformities together with the Base Cretaceous event strongly influence reservoir distribution, particularly in the footwall areas.
History Pre-discovery
Block 9/13 was awarded in the United Kingdom, Fourth Offshore, Licensing Round as Licence P.139 in December 1971. Following mandatory relinquishments, Block 9/13 was sub-divided into four partial blocks, designated 9/13a to 9/13d, or Licences P.139 (9/13a), P.337 (9/13b and c) and P.629 (9/13d). The initial and current Mobil operated partnership and participating interests in Blocks 9/13a, b and c are summarized in Table 1. In December 1996 the participating interests were reassigned as a result of British Gas transferring 5% of their interest in the field to Mobil as part of Take or Pay negotiations. Amerada and Enterprise acquired the remaining British Gas interest in the field.
In April 1973, well 9/13-2 was drilled 1.5 miles south of the discovery well and penetrated 460 ft of pay in the Triassic section, with an oil-water contact at - 1 0 7 7 0 ft TVSS and the well flowed 35 ~ API oil at a rate of 5500 BOPD. The Beryl Field was declared commercial and the construction of a 40-slot 'Condeep' platform began in 1973. Between 1973 and 1974, two more appraisal wells were drilled: 9/13-5 and 9/13-6. These wells penetrated combined Jurassic and Triassic net oil sections of 359 and 344 ft, respectively. The Beryl A platform was landed in July 1975 and oil production began a year later in July 1976. Well 9/13-7, drilled in April 1975, showed the Beryl accumulation extended several miles to the north (Beryl B area). This well penetrated 125ft of net gas pay and 225 ft of net oil pay in the Lower and Middle Jurassic sandstones with an oil water contact encountered at - 11 304 ft TVSS in the Beryl Formation. Middle Jurassic hydrocarbons were also encountered in subsequent appraisal wells, 9/13-12, 15 and 19. The intervening wells were either dry or had hydrocarbon shows. The 9/13-15 well was tied-back to the Beryl A platform and went on production in January 1979, at a rate of 14500 BOPD. A 21-slot tubular steel jacket was commissioned for this area and construction began in March 1981. The Beryl B platform was installed in June 1983, over a sub-sea drilling template from which six wells had been predrilled. The first oil production from Beryl B was in July 1984, eight years after initial production from Beryl A. As of January 1999, 72 platform wells and seven sub-sea wells (65 producers, eight water injectors, five gas injectors) have been drilled in the Beryl A area. Currently 28 wells are actively producing in the field with, no significant gas injection and reduced water injection. The emphasis on pressure support, particularly gas injection, changed significantly when gas sales from the Beryl Field began in 1992. It was at this time that the blow down of the gas cap in Beryl A began. In Beryl B 48 platform wells and six sub-sea wells (33 producers, ten water injectors and five gas injectors) have been completed. There are currently 16 producing wells in the field, with one gas injector (9/13a-B22) and eight water injectors.
BERYL FIELD
155
Table 2. BerylfieM history Year
Event
1971 1972 1975 1975 1976 1977 1979
Block 9/13 awarded to Mobil (operator) 9/13-1 discovery well 9/13-7 Beryl B discovery well Beryl A Condeep platform installed First oil from Beryl A platform Gas injection begins (Beryl A) Water Injection begins (Beryl A) First 3D seismic survey (Beryl B) Peak Beryl A oil production 122.9 thousand barrels per day (TBD) First Beryl A 3D seismic survey Beryl B platform installed (Steel Jacket) First oil from Beryl B platform Beryl B 3D seismic reprocessed Beryl B gas injection begins Beryl B water injection begins Ness Field production to Beryl B begins Peak Beryl B oil production 86.7 TBD 3D seismic survey reacquired Beryl A gas export begins Nevis Field production to Beryl A begins Beryl Field 20-year anniversary 3D seismic survey reacquired Production License expires
1980 1982 1983 1984 1984 1986 1987 1988 !991 1992 1996 1996 1997 2017
Cumulative oil and gas production, as of December 1998, was 448 M M B B L and 517 billion cubic feet of gas (BCFG) for Beryl A and 269 M M B B L and 381 B C F G for Beryl B respectively.
Seismic surveys
Fig. 3. (a) C-C', 1991 3D seismic line and (b) C-C' improved imaging on the 1997 data set showing the interpreted Base Callovian Unconformity (Jb3).
The first 3D seismic datasets were acquired in 1979 (Beryl B area) and subsequently in 1982 in the Beryl A area (Table 2). The first field wide 3D survey was acquired during 1991 and 1992 and has been the mainstay for structural interpretation until delivery of the most recent data in June 1998. Major improvements in structural imaging, between 1991 and 1998, are due to a combination of both seismic acquisition, and seismic processing enhancements (Fig. 3). The 1991 acquisition program used two 1.9 mile analogue streamers and 1750 cubic inch dual sleeve gun source arrays. The positioning system was poor compared with today's technology and the navigation data required extensive processing. The 1997 survey was acquired with six digital streamers, each 2.2 miles long, more powerful Bolt airgun arrays of 3707 cubic inches and a modern positioning system. The resulting, higher fold, 1997 data had improved signal fidelity and there is greater confidence in the navigation data. The major difference in processing between 1991 and 1997, apart from general algorithm improvements for signal processing such as DMO, is the inclusion in 1998 of a pre-stack time migration step. This results in an improved velocity field for the subsurface image, and better sorting of the data over areas of complex structure prior to stacking. The 1998 image has been further enhanced by Mobil proprietary techniques for seismic data whitening and noise reduction.
Regional structure and tectonic evolution The Beryl Field is situated within the Beryl Embayment, a halfgraben on the western margin of the South Viking Graben. The Embayment is bound by the East Shetland Platform Fault to the west and the Crawford Spur Fault to the southeast (Fig. 4). Peacock & Sanderson (1994) describe this overlap of the East Shetland and Crawford faults as a large-scale relay ramp or transfer zone. The East Shetland Fault has a number of distinct changes in orientation (Fig. 4). The largest change is at the northern end of the
Fig. 4. Brent province structural elements.
156
R . M . KARASEK E T AL.
Beryl Embayment, where the East Shetland Fault is offset to the east. Donato & Tully (1982) and Swallow (1986) suggest that this offset may be caused by the deflection of the East Shetland Fault around a Caledonian aged granite intrusion. Another major change in orientation occurs in Block 9/12 where the East Shetland Fault is composed of a number of overlapping segments. Sediment distribution, interpreted from both well and seismic data, suggest this area was a major conduit for sediment into the basin from the Middle Jurassic until the Tertiary. Other similar changes in the orientation of the boundary fault are likely to be similar transfer zones and may also provide sediment entry points (e.g. Fig. 19). Regional seismic data show Lower Triassic and Upper Jurassic sedimentary packages thicken towards the East Shetland Fault. Correlation of biostratigraphic data from the wells to the sedimentary packages interpreted on the seismic data show the thickest Jurassic growth packages are Callovian to Oxfordian in age. Hence the main phase of Jurassic rifting is interpreted to be Callovian to Oxfordian. This is in contrast to the southern part of the South Viking Graben where the main phase of Jurassic rifting is interpreted as late Oxfordian to Volgian (Faersth et al. 1997). Many of the faults within the hanging wall of the East Shetland Fault were probably not present during the Triassic, but developed later to accommodate Jurassic movement of the East Shetland Fault. In the southern part of the Beryl Embayment, at the termination of the Crawford Spur Fault, these hanging wall faults form a series of grabens divided by horst blocks. Jurassic section is preserved within the grabens but Triassic rocks subcrop the Cretaceous section on the horsts. Further north the stratigraphy is divided by a series of rotated fault blocks synthetic to the East Shetland Fault.
Fig. 5. Top Beryl Formation structure map over Beryl A and B and satellite fields in Block 9/13.
Subsequent to Mesozoic rifting phases the basin subsided due to post-rift thermal cooling of the thinned lithosphere. Cretaceous and Tertiary rocks progressively buried the underlying Mesozoic fault blocks. Lower Cretaceous sediments, which onlap the Base Cretaceous (J) unconformity, are absent over much of the Beryl Embayment probably due to non-deposition.
Local structure
The Beryl Field is a large, fault-bounded structural trap, with an overall length of nine miles and a width which ranges from approximately three miles in the Beryl A area to five miles in the Beryl B area (Fig. 4). A detailed discussion of the geological evolution of the field can be found in Robertson (1993). The field is situated between two major N N E - S S W trending normal faults, F1 & F3, that down-throw to the east (Figs 6a, b). The F1 fault defines the field's eastern boundary. The western boundary is defined by westward dip closure (Fig. 5). Beryl A can be divided into a west-dipping west flank, a low relief central horst area and an east flank subdivided by a series of roughly N-S-trending, sub-parallel normal faults. Regional dip reverses to the east in the east flank area of the field probably as a result of footwall collapse. Further compartmentalization is defined by antithetic faults and cross cutting N W - S E and NE-SW-trending faults (Fig. 6b). Many of these faults are sealing and create isolated pressure compartments, which are swept by downdip water injection and crestal gas injection.
Fig. 6. (a) East-west cross-section A - N (seismic inline 1310) through Beryl B and (b) B-B' (seismic inline 960) through Beryl A showing main mapping horizons and fault style.
BERYL FIELD Beryl B is separated by a saddle from Beryl A and is structurally less complicated. It is subdivided into west-dipping, domino-style, tilted fault blocks by a series of NNE-SSW-trending synthetic (down-to-the-east) normal faults (Fig. 6a). The multi-stage structural development of the Beryl area has significantly affected both the deposition of reservoir sandstones and the preserved thicknesses. Thicker sequences seen on isochore maps are clearly controlled by subsidence on the major faults. Erosion on footwall areas, particularly on the Beryl Horst and east flank, has also progressively removed older reservoir section to the east. In addition, to the Base Cretaceous unconformity (J), recent drilling has highlighted the importance of a Toarcian (Jt) or the Cimmerian Event (Davies et. al. 1999) and a lowermost Callovian (Jb3) erosional event.
Trap The Beryl Field is a fault-bounded structural closure with hydrocarbons trapped in late Triassic to late Jurassic sandstone reservoirs. In crestal areas, where the Upper Jurassic is thin due to erosion, Upper Cretaceous marls and limestones above the Base Cretaceous unconformity (J) form the primary seal. In areas where the unconformity is less erosive, thick sections of Upper Jurassic shales comprise both lateral and top seals. Multiple oil water contacts and reservoir compartments in the fields are related to fault seals (lateral barriers) and intraformational seals (shale, coal and carbonate-cemented zones) forming vertical barriers (Knutson & Erga 1991). There is some limited evidence to suggest that some of larger sealing faults may break
157
down over large pressure differentials. Oil water contacts are shallowest on the crest of the field and become deeper towards the flanks, with hydrocarbon levels controlled by seal integrity of the overlying cap rocks. (Robertson 1993). In off flank areas thickly developed shales (cap rock) define regions with greater seal capacity and as a result larger potential hydrocarbon columns.
Stratigraphy The oldest succession penetrated in the Beryl Field is Devonian (undifferentiated). The principal hydrocarbon-bearing reservoirs occur in Triassic to Upper Jurassic strata and are summarized in Figure 7. The reservoirs in the Beryl Field can be divided into three sedimentary packages. The Cormorant, Statfjord and Dunlin Groups comprise the oldest package and record a transition from fluvial/ alluvial to marine conditions. Uplift in the early Jurassic (Toarcian to Aalenian) interrupted this sequence and resulted in depositional thinning and erosion resulting in the Mid Cimmerian (Jt) unconformity. Coastal and deltaic sequences of the Middle Jurassic Beryl Embayment Group onlap this older sequence to form the second package. Fault block rotation during the late Bathonian to early Callovian resulted in footwall crestal erosion along the east flank of the field, producing a local Base Callovian (Jb3) unconformity. A marine transgression and the deposition of the thick marine sequence known as the Humber Group followed this (Jb3) event. The final phase of Jurassic sedimentation was terminated by major tectonism in the late Jurassic, with uplift and erosion and footwall collapse, resulting in the Base Cretaceous (J) unconformity.
Fig. 7. Triassic and Jurassic stratigraphy in the Beryl area showing the principal reservoirs and unconformities (after Roberston 1993).
158
R. M. KARASEK ET AL.
Reservoirs The six reservoirs in the Beryl Field comprise the Lewis Formation of the Cormorant Group, the Eiriksson and Nansen Formations of the Statfjord Group, the Linnhe and Beryl Formations of the Beryl Embayment Group, and the Katrine Member of the Heather Formation (Figs 7 and 8). The Middle Jurassic age Beryl Formation contains 73 % of the total ultimate oil recovery of the field, which is in a mature stage of development. The Middle and Lower Jurassic Linnhe, Nansen and Eiriksson Formations and the Triassic Cormorant Group contain an additional 17% and 8% of the ultimate oil recovery respectively, with the remainder coming from the Heather Formation. The Triassic reservoir is at a less mature stage of development because of the heterogeneous nature and poor continuity of the reservoir.
Cormorant group The informally-defined Lewis Formation of the Triassic Cormorant Group has an average thickness of 1000ft and is subdivided into four lithostratigraphic units (Units I-IV). The formation consists of a sequence of fluvial/alluvial sandstones, siltstones, shales and caliche horizons described by O'Donnell (1993) and summarized in Table 3. Deposition took place in a low-lying basin under semi-arid conditions with alluvial fan systems supplying the sediment. Principal reservoir rocks are fluvial, channel-fill and proximal sheetflood sandstones. Non-reservoir facies are floodplain deposits distal sheetflood and rare lacustrine mudstone units (Fig. 9). Fluvial channel-fill sandstones have the best reservoir characteristics within the Lewis Formation. Wells in the southern part of Block 9/13 have average porosities of 18% and average permeabilities of 271 millidarcies (mD) in the fluvial channel facies. Not all the fluvial deposits are good reservoir. Some fluvial sands have very poor potential due to a number of factors such as the presence of mud clasts, patchily developed dolomite and silica cementation due to the absence of early clay coatings, and early, pedogenic calcite cements. Reservoir quality is influenced by a number of factors, i.e. (a) primary depositional facies, (b) burial diagenesis, (c) pedogenesis (d) near surface weathering, all of which influence the abundance of detrital and diagenetic clays. Fine-grained, unchannelized sandstones tend to have lower porosity and permeability than coarser counterparts. Feldspar-rich sandstones are prone to burial diagenesis where detrital potassium feldspar alters to pore filling Kaolinite and grain coating quartz.
Statfjord group The Statfjord Group is late Triassic to early Jurassic in age and consists of the Raude, Eiriksson and Nansen Formations. These formations represent the transition from the alluvial plain to a fluvial system, followed by a marine transgression and the deposition of marine shoreline facies in the Nansen Formation. The marine transgression is driven by basin subsidence coupled with flooding due to eustatic sea level rise and a change in climate to wetter conditions in late Triassic to earliest Jurassic time (Manspeizer 1982). The Raude Formation is Rhaetic in age and is a non-reservoir unit consisting of interbedded siltstones, rare sandstones and shales with a distinctive reddish colour. These deposits are interpreted as alluvial plain deposits. The Eiriksson is Hettangian in age, up to 350 ft thick (Fig. 10) and consists of interbedded fluvial sandstones, siltstones and shales. The sandstones are white or grey, generally medium grained and moderately sorted. The net-to-gross ratios range from 0.4 to 0.7, average porosities from 14-17% and permeabilities from 0.5 - 1000 mD.
Fig. 8. Type log (9/13-17 stratigraphic test) showing the principle reservoirs and electric log character.
BERYL FIELD
159
Table 3. Summary of Triassic reservoir units Formation
Thickness
N/G
%
Lewis IV
300'
0.4-0.5
13-16
0.5-0.95
10-24
Lewis III
60-235 ~
Lewis II
60~
Lewis I
400 ~
Kh 0.1-500 md
40 md
13 15
Grey brown med.-fine grained sandstone. Variable quality reservoir which degrades northwards (distal floodplain facies). Reasonable reservoir quality. Heavily bioturbated fine-medium grained sandstone with intermittent calcrete horizons - reservoir quality degrades eastwards (finer grained) Lacustrine mudstones with extensive pedogenic horizons, caliches and agal mats.
Non-reservoir 0.3-0.6
Description
0.1-500 md
Thin fine grained fluvial sandstone (Beryl B) with poor lateral connectivity with thick floodplain sequences. Calcretes towards top.
Levee deposits, fluvial deposits and crevasse splays have been interpreted from core descriptions, and the sands were deposited in a flood plain setting in low-sinuosity fluvial channels (Fig. 11). The Eiriksson F o r m a t i o n is recognized t h r o u g h o u t Block 9/13 except for parts of the Beryl A eastern horst block and the Beryl B East F l a n k where the unit has been r e m o v e d by successive Jurassic erosive events (the Jr, Jb3 & J Unconformities).
The Sinemurian age Nansen F o r m a t i o n overlies the Eiriksson F o r m a t i o n and consists of a massive, g o o d quality sandstone reservoir. The contact with the underlying Eiriksson F o r m a t i o n is m a r k e d by a conglomerate which, in c o m b i n a t i o n with shales developed at the top of the Eiriksson Formation, can form a pressure barrier of up to 1500 p o u n d s per square inch (psi). The N a n s e n F o r m a t i o n can be subdivided into two units, separated by a
Fig. 9. Triassic depositional environments.
Fig. 10. Eiriksson Formation isochore map.
160
R. M. KARASEK ET AL.
Fig. 11. Depositional environments of the Eiriksson Formation (after Robertson Group 1990). thin shaley horizon, which is also a minor pressure barrier. The sandstones have a fairly uniform thickness of about 200 ft except where they thin and are eroded in the Beryl Eastern area and on the East Shetland Platform (Fig. 12). The Nansen consists of transgressive marine shoreline deposits, shallow marine shoreface deposits and reworked subtidal channel sediments (Fig. 13). The sandstones are typically white to pale yellow in colour, medium-grained and moderately sorted with primary bedding is obscured through bioturbation.
Fig. 13. Depositional environments of the Nansen Formation (after Robertson Group 1990).
Dunlin group The early Jurassic age Dunlin Group consists of marine shales with some interbedded siltstones and sandstones. The sequence is thickest to the south and SE of the Beryl B platform, where a maximum thickness of 255 ft has been penetrated. Elsewhere across the field the Dunlin Group ranges from 110 ft to 190 ft. The original depositional thickness is unknown due to erosion by the Mid Cimmerian (Jt) unconformity. The Dunlin Group is effectively nonreservoir although poor quality, storm bed sandstones were successfully completed in one well.
Beryl embayment group
Fig. 12. Nansen Formation isochore map.
The Mid Cimmerian (Jt) event is associated with up to 500ft of erosion in the footwall, crestal portions of the Beryl Field. Overlying the Jt Unconformity and onlapping the Dunlin Group are Middle Jurassic age sediments, referred to as the Beryl Embayment Group (Roberston 1993). At the base of the group is the Bajocian age Linnhe Formation, a sequence of interbedded sandstones, shales and coals. Above the Linnhe Formation is the Bathonian to early Callovian age Beryl Formation, a sand-rich (tidal) deltaic sequence. The thickness of the Linnhe Formation is highly variable over the field (0 to 760 ft) attributed to fault controlled subsidence during deposition and in-fill over the Mid-Cimmerian (Jt) unconformity (Fig. 14). The Linnhe Formation consists of coals, sandstones, siltstones and shales interpreted as fluvial and estuarine deposits (Richards 1991). Three general environments have been recognized: coastal plain/swamp, lagoon/shoreface and tidal channel and inlet fills (Fig. 15). Linnhe Formation carbonaceous sandstones are light olive to light grey and yellowish grey in colour, very fine to occasionally coarse grained. Reservoir quality in these sandstones is highly variable. In Linnhe Unit I which is generally sand poor, fluvial channel sandstones with shoestring geometries have the best reservoir potential. In Linnhe Unit II, elongate tidal channels and lagoonal, shoreface sheet sands comprise the best reservoirs. Coals, representing bayfill deposits, characterize the Linnhe Formation and occur in beds up to 12ft thick and form effective vertical permeability barriers. The Beryl Formation conformably overlies the Linnhe Formation and contains the primary reservoir of the Beryl Field. The complete sequence attains a thickness of up to 1000 ft in the eastern
BERYL FIELD
161
Fig. 14. Linnhe Formation Isochore.
Fig. 16. Beryl Formation Isochore.
Fig. 15. Depositional environments of the Linnhe Formation (after Robertson Group 1992).
part of the area. Thickness variations are primarily due to syndepositional faulting in hanging walls and erosion on footwall crests (Fig. 16). The Beryl formation is interpreted as a NNE-prograding tidally dominated delta and is divided into five informal, lithostratigraphic units I-V (Maxwell et al. 1999). Unit I of the Beryl Formation is a variable quality reservoir, generally 100ft to 200ft thick, with a net-to-gross ratio ranging from 0.15 to 0.95. It consists of a massive sand unit together with occasional shales and coals. It represents a continuation of the estuarine sedimentation established during deposition of the Linnhe Formation but shows a greater marine influence. Sediment input was primarily from the southwest, although a northerly subordinate source can also be recognized. The southerly fluvial distributary system became progressively more tidally influenced as it approached the Beryl Field, passing into tidal bar deposits north and east of Beryl B (Fig. 17a). Sand continuity and pressure communication within Unit 1 in the Beryl B area are good, and the response to water injection has been favourable. Around Beryl A the unit progressively pinches-out onto the Beryl A Triassic horst and consists of thin, disconnected, ratty sandstones and shales with very poor reservoir potential. These deposits were probably locally sourced and by-passed by the main fluvial system.
162
R. M. KARASEK E T AL.
Fig. 17. Palaeogeography of the Beryl Formation, (a) Unit 1; (b) Unit 11; (e) Unit 111; (d) Unit IV; (e) Unit V. Beryl Unit II is a 30-60ft shale (Fig. 17b) which forms an important field-wide permeability barrier that allows Unit I to be produced separately from Units III-V and represents a marine transgression/flooding event. This shale supports substantial differential pressures up to 1564 PSI in well 9/13a-B18 drilled in 1988. Beryl Formation Units III to V form a relatively continuous reservoir section and provide the majority of production in the Beryl Field. The sandstones are generally white, grey or buff in colour, fine to medium grained, less commonly coarse-grained, moderately to well-sorted and carbonaceous. Massive sandstones are trough crossstratified in fluvial and tidal channel sandstones whereas heterolithic sandstones and shales are typically wavy or ripple laminated with extensive bioturbation and a marine ichnofauna. Beryl Unit III represents maximum progradation of the tidal delta into the Beryl Embayment following the Unit II transgression (Fig. 17c). Sediment was supplied largely from the south. Fluvial channels flowed northwards into tidally-influenced channels in the Beryl A and the southern Beryl B areas before passing into tidal shoals. In the Beryl B area, the amount of northerly progradation was controlled by differential subsidence associated with extensional fault activity. Westerly-directed transgression of the northern part of the embayment began at the end of Unit III deposition. This resulted in
a southerly shift of facies during the deposition of Units IV and V and the establishment of open marine sedimentation as far south as the Beryl B platform (Fig. 17d, e). Sediment supply continued via the southern distributary system, with delta lobes locally apparently controlled by fault activity. Fluvio-tidal channels transported sediment into tidal shoals and passed basinwards through delta front facies into the offshore transition zone where units IV and V become predominantly non-reservoir marine shales north of Beryl B. Overall, reservoir quality in Units III-V is excellent, but production performance and pressure histories indicate some complications due to vertical permeability heterogeneities, typically due to finer-grained facies developed associated with maximum flooding surfaces (Maxwell et al. 1999). Thin, interbedded coals, siltstones or shales and locally carbonate cemented doggers can restrict vertical permeability and cause significant differential depletion. Core permeability measurements and detailed R F T pressure logging (Knutson & Erga 1991; Maxwell et al. 1999), indicate that, even in apparently massive sandstone sequences, vertical heterogeneities support differential pressures typically in the order of 10-100psi. Differential depletion has increased the challenges associated with drilling development wells in the Beryl Field. As a result specific zones have been targeted with high angle or horizontal wells in order to improve sweep efficiency. Also consideration has to be
BERYL FIELD given to significant pressure breaks across major shale breaks to avoid differential sticking problems whilst drilling.
Humber group
163
platform (Fig. 19). These are similar in composition to Beryl Formation sandstones, and were probably also sourced locally off the footwall areas. In the Beryl A area Humber Group sandstones are up to 300 ft thick, although syndepositional faulting and sedimentary onlap result in rapid lateral variations of reservoir thickness. Net-to-gross ratios are typically about 0.7 in this area. In Beryl B these sandstones occur in sequences up to 180 ft thick with a fan shaped geometry. They are white or grey to buff in colour and generally fine-grained and are interpreted as turbidite deposits. Net-to-gross ratios are high, up to 0.85, but the sandstones thin abruptly and usually grade to siltstone and shale within two miles. Sandstones within late Kimmeridgian/Volgian age shales are often conglomeratic and are compositionally unrelated to the Beryl Formation sediments. These sandstones are mostly sourced from the East Shetland Platform to the west and deposited as debris flows and turbidites within a submarine fan setting. Similar deposits in the $33 area were derived from the Beryl Horst (Fig. 19).
In the early Callovian, a marine transgression drowned the Beryl Formation delta and initiated deposition of the shale-dominated Upper Jurassic Humber Group. This sequence reaches more than 1200 ft thick south west of the Beryl Field area (Fig 18). Biostratigraphic evidence indicates a gradual deepening from Callovian through the Volgian with water depths ranging from lower sheifal to upper bathyal. A decrease in terrestrial clastic input into the Beryl Embayment is also recorded in the wells. Footwall uplift and fault block rotation due to extension caused local erosion and subsequently the deposition of submarine channel and lobe sands (Fig. 19). These are preserved within the thick marine shale sequences of the Callovian-Oxfordian Heather Formation and the Kimmeridge Clay Formation. Most of these sandstones appear to be limited in extent and have poor reservoir quality and were derived locally from eroded footwall crests. Within the Beryl Field, a productive Oxfordian sandstone occurs within the Heather Formation and is informally referred to as the Katrine Member. This reservoir is better quality than most of the sandstones within the Humber Group and contains a sand rich sequence up to 300 ft thick. The thickest accumulations of Oxfordian-Callovian sands occur in the western Beryl B area (B12) and west of the Beryl A
Three basic oil types have been sampled in the Beryl Field area. These oils mostly fall between 30 ~ and 40 ~ API gravity and have sulphur contents between 0.1% and 0.5%, a carbon isotopic ratio ranging from -29.8 to -28.3 per mil, a pristane/phytane ratio ranging from 1.2 to 1.6 and a saturated/aromatic ratio between 1.0 and 2.0.
Fig. 18. Top Beryl to Base Cretaceous Isochore.
Fig. 19. Distribution of Humber Group sandstones (showing probable dispersal patterns).
Source
164
R. M. KARASEK E T A L . there is a free gas cap whereas in Beryl and the eastern area of Beryl A a secondary gas cap has formed due to production. The initial reservoir conditions for the Jurassic reservoirs, as calculated from PVT data, were 207 ~ F and 4900 PSI (at -10,500 ft TVSS datum). Initial reservoir conditions for the Triassic reservoirs were 215~ and 5300psi (at - 1 0 500 ft TVSS datum). PVT analysis indicates that bubble point pressures vary by reservoir and within reservoirs (see data summary). These bubble point variations appear to be a function of both area and depth in the majority of the reservoirs. The exceptions to this are in the Nansen and Eiriksson Formation reservoirs, in which it appears to be simply a function of depth. Initial gas-oil ratios range from about 750-950 standard cubic feet per stock tank barrel (SCF/STB) for most of the reservoirs, but are measured as high as 1500 SCF/STB in the Beryl Formation reservoir. Water analyses for the various reservoirs are obtained primarily from produced water samples. The chemistry of the waters is quite variable, ranging from 50 000 to 90 000 parts per million (ppm) of total dissolved solids (TDS), but fractional analyses can usually differentiate the specific reservoir from which the water is derived. The chemical variation of water from an individual reservoir is generally less than 1500 ppm TDS and concentrations of calcium, magnesium and barium are especially definitive in identifying the source reservoir.
Reserves
Fig. 20. Beryl area hydrocarbon types and inferred migration routes. (after Waiters in press). Variations in the chemistry of the Beryl Field hydrocarbons can be explained using a multiple source model (Walters et al. in press). The primary source consists of organic rich marine shales of the Kimmeridge Clay Formation. Marine shales of the organically-lean Oxfordian-Callovian Heather Formation constitute a secondary source. Lower Jurassic coals may also play a minor role in gas/ condensate generation in the Beryl Field area. The distribution of oil and gas in the Beryl Field is attributed to multiple migration pathways of hydrocarbons from two main source areas (Fig. 20). Two of the three oil types were apparently derived from the 'Frigg kitchen', a large half-graben depocentre to the northeast. The third type appears to have originated in the 'Beryl kitchen', a smaller depocentre located to the east of the field. Expulsion of oil from the Kimmeridge Clay Formation in the Frigg and Beryl kitchens is estimated to have begun about 4 0 M a and 20 Ma, respectively. The Heather Formation is presently of sufficient maturity to expel light oil and gas from the Frigg kitchen, but has not reached sufficient levels of kerogen conversion to expel hydrocarbons from the Beryl kitchen. Migration conduits were probably through the Jurassic sandstones interbedded with and lateral to the Upper Jurassic source rocks. Migration may also have been focused beneath the Base Cretaceous Unconformity. A complicated migration history due to faulting is indicated by variations in original fluid contacts across the field and by the presence of water bearing fault blocks upthrown to oil-bearing blocks at the same stratigraphic level.
The Beryl Field is estimated to have a total original oil-in-place volume of about 2322 MMBBL and a risked ultimate recovery of about 800 MMBBL. The Beryl Formation is the primary reservoir in the field and has supplied 80% of the production to date. As of December 1998 cumulative production from the field has been 710 MMBBL oil with cumulative injection of one trillion standard cubic feet of gas and 741 MMBBL of water. The average daily production in 1998 for the Beryl Field was 61 MBBL of oil, 332 million cubic feet (MMCF) of gas, with 32 M M C F of gas injection and 159 thousand barrels of water injection (Fig. 21). Reserves of about 256 MMBBL oil and 1265 BCF gas remain in the field. The Beryl Field is produced from the Beryl A and Beryl B platforms in conjunction with a number of sub-sea wells. Four water injectors are tied by sub-sea flowlines to the Beryl B platform. Production from the Beryl B platform is transferred to the Beryl A platform along with production from three Beryl A sub-sea producers. One sub-sea producer in the Beryl B area is tied by sub-sea flowline to the Beryl A platform. The crude is stored in concrete cells at the base of the Beryl A platform which are capable of holding up to 864 MBBLs. The crude is offloaded into tankers through two single point mooring systems. The first oil was produced from the Beryl A platform in June 1976, and from the Beryl B platform in July 1984. Initial rates from early wells in the Beryl Formation were as high as 15 000 to 20 000 BOPD.
Hydrocarbons Oil gravity in the Beryl Field is generally 36-39 ~ API and the gas gravity is about 0.70 ~ In the Beryl B central and western areas
Fig. 21. Beryl Field production and injection history.
,.o o
>
~o
,..a
~o
o
0
~E ' ~
~~
-~
. ,...~ ~
o ~0 I
~
~
~
~ eq
o ~
~
< ~ ~ .
R ~
&~
~
:~
o
0o
.~
~
.
Oo o
~.
;>
4..a 9
~ Pa~
~ oo
-~~.
~
,.~
m
o c ~
-
~
.,~ ~x,
~.~ 0 ~ o ~
~-.
~, ~ - ~ . o ~
O~ ,--.~ 0
,-.~ ~
o<
7
o~
o~
=
~ " C~
~
r,~
;>
,..o o
;>
o
o,s
,-a o~
,,._,, ~
~ o o oo
o o r,~
r,~
o
;>
~o = o o
r
~
~.
0a
o~ o~ o
o~
oo
o~
.o
r
Oo~ o
~-
;>
r,~
~>
,.el
o
i
.~
. ,...~ kO
o~
..,-~
7 o
o
o
o,1
9
O~
~o
~C~e
q
t,'q tr~ ~ .,-r 0
~.~
.-e = o
Zc~
eq
o~ ,-j
o
~.~
~o
~6
"O
.~
~ o ~
o. ,.el
,.o
~ "6" .~-
~
~...o
~.~'~
-~
~
~. ~ ~
.~
~
~
o~
.~
"~
o~ <
~
~
~
~'~
o
166
R. M. KARASEK E T AL.
The primary development strategy for the Beryl Formation has been displacement of oil by reinjection of associated gas into a secondary gas cap, along with down-dip flank water injection. Gravity drainage is also important because of the moderately steep structural dip of the reservoir (10 to 25~ The initial gas injection scheme was chosen for the Beryl Formation because no gas export route was available and because early pseudo-compositional reservoir modeling estimated that an ultimate Beryl Formation recovery of 55% of the oil-in-place could be accomplished (Steele & Adams 1984). Gas injection into the Beryl Formation began in November 1977, the first example of pressure maintenance through gas injection in the North Sea. Reservoir performance to date supports the prediction of an overall 55% recovery, even though vertical and horizontal permeability restrictions significantly complicate reservoir depletion (Knutson & Erga 1991). Water injection into the Beryl Formation began in January 1979, initially limited to the well 9/13-A14 in the southern Beryl A area. From 1986 to 1992, seven water injection wells in the Beryl Bravo area and one additional injector in the Beryl Alpha area were completed to provide increased pressure support. Gas sales from the Beryl Field then commenced in 1992 at which time gas injection was significantly reduced. Since that time four additional water injection wells were completed, two in the Beryl Alpha area and two in the Beryl Bravo area. Presently water injection provides the majority of the voidage replacement in the Beryl reservoir. The development of the five other reservoirs in the Beryl Field is not as advanced as for the Beryl Formation reservoir. The Katrine Member, Linnhe Formation and Lewis Formation reservoirs have been produced historically by primary depletion and recovery factors in the range of 10-25% are expected. Water injection to enhance recovery from these reservoirs is planned and an injection programme for the Lewis Formation commenced late 1989. The Katrine Member production is currently shut in and the reservoir is being re-evaluated for future development well locations. Production from the Nansen and Eiriksson Formation reservoirs has been supported by gas and water injection and recovery factors are estimated at 15-30%. A possible Water-Alternating-Gas injection scheme is under evaluation for the Lewis Formation. The authors wish to thank Mobil North Sea Ltd. and its partners Amerada Hess Ltd., Enterprise Oil plc and OMV (UK) Ltd. for permission to publish this paper. The Authors have drawn on the extensive knowledge of colleagues from the Beryl Subsurface Team. In particular we would like to acknowledge the technical contribution of geoscientists Hugh Kerr, Robert Young and the drafting office for preparing the figures.
References DAVIES, R. J., O'DONNELL, D., BENTHAM,P. N., GIBSON,J. P. C., CURRY, M. R., DUNAY,R. E. & MAYNARD,J. R. 1999. The origin and genesis of major Jurassic unconformities within the triple junction area of
the North Sea, UK. In: FLEET, A. J. BOLDY,S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 117-131. DONATO, J. A. & TULLY, M. C. 1982. A proposed granite batholoth along the western flank of the North Sea Viking Graben. Geophysical Journal of the Royal Astronomical Society, 69, 187 195. FAERSTH, R. B., KNUDSEN, B. E., LILJEDHAL, T., MIDBOE, P. S. & SODERSTROM, B. 1997. Oblique rifting and sequential faulting in the Jurassic development of the northern North Sea. Journal of Structural Geology, 19, 1285-1302. KNUTSON, C. A. & ERGA, R. E. 1991. Effect of horizontal and vertical permeability restrictions in the Beryl reservoir. Journal of Petroleum Technology, 43, 1502-1509. SPE Paper 19299. KNUTSON, C. A & MUNRO, I. C. 1991. The Beryl Field, Block 9/13, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Year Commemorative Volume. Geological Society, London, Memoir, 14, 33-42. MANSPEIZER, W. 1982. Triassic-Liassic basin and climate of the Atlantic passive margins. Geologische Rundschau, 71, 895-917. MAXWELL, G., HARTLEY,A. & CRANE, J. 1999. High resolution zonation within a tide-dominated deltaic reservoir: the Middle Jurassic Beryl Formation, Beryl Field, UKCS. In: FLEET, A. J. & BOLDY,S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1187-1198. O'DONNELL, D. 1993, Enhancing the oil potential of secondary Triassic Reservoirs in the Beryl A Field, UK North Sea. In: SPENCER, A. M. (eds) Generation, Accumulation and Production of Europe's Hydrocarbons 111. European Association o/" Petroleum Geoscientists, Special Publication, 3, 37-44. PEACOCK, D. C. P. & SANDERSON,D. J. 1994, Geometry and development of relay ramps in normal fault systems. AAPG Bulletin, 78, 147-165. RICHARDS, P. C. 1991. Evolution of Lower Jurassic coastal plain and fan delta sediments in the Beryl Embayment, North Sea. Journal of the Geological Society, London, 148, 1037-1047. ROBERTSON, G. 1993. Beryl Field: geological evolution and reservoir behaviour. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings o[ he 4th Conference. Geological Society, London, 1491 1502. ROBERSTONGROUP 1990. A sedimentological and petrographic stud), qf cores 1-7 (Nansen and Eiriksson).[i'om the Mobil well 9~13a-B21. Mobil North Sea Ltd., Proprietary Report. ROBERSTONGROUP 1992. Linnhe Formation facies types and interpretation of basin .fill sequences based on cored wells in Blocks 9/13 and 9/8. Mobil North Sea Ltd., Proprietary Report. STEELE, C. E. & ADAMS, G. W. 1984. A review of the northern North Sea's Beryl field after seven years production. Proceedings of the European Petroleum Conference, London, 51-58. SPE Paper 12960. SWALLOW, J. L. 1986. The seismic expression of a low angel detachment (S06 fault) from the Beryl Embayment, control Viking Graben. Scottish Journal of Geology, 22, 315-324. WALTERS, C. C., CHUNG, M. H., BUCK, S. P. & BINGHAM,G. C. in press. Geochemical complexity of oils in the Beryl and satellite fields of the South Viking Graben, North Sea. Submitted to the American Association of Petroleum Geologists.
The Birch Field, Block 16/12a, UK North Sea J. H O O K 1, A. A B H V A N I 2, J. G. G L U Y A S 3 & M. L A W L O R 4
L A S M O plc, 101 Bishopsgate, London E C 2 M 3XH, UK 1 Present address." Vico Indonesia, Kuningan Plaza, South Tower, J L H R Rasuna Said, Kay C 11-14, PO Box 2828, Jakarta 12940 2 Present address." C N R Inernational (UK) Ltd, Ranger House, Walnut Tree Close, Guildford, Surrey GU1 4US, UK 3 Present address. Acorn Oil & Gas, Ash House, Fairfield Avenue, Staines, Middlesex TW18 4AN, UK (e-mail." jon.gluyas@ acorn-oil, corn) 4 Present address: E N I - L A S M O , London Technical Exchange, Bowater House, 68 Knightsbridge, London S W 1 X 7BN, UK
Abstract: The Birch Field is an oil field located in Block 16/12a on the UK Continental Shelf (UKCS) and is part of the wellestablished 'Brae Trend'. Birch produces an undersaturated volatile oil from the Brae Conglomerate, a locally thick conglomeratic unit within the Late Jurassic Brae Formation. The reservoir was deposited as a small submarine fan in the hanging wall of the main fault bounding the western side of the South Viking Graben. The current estimate for oil in place is about 70 MMSTB with expected ultimate oil reserves of 30 MMSTB. The field was brought on stream in September 1995 as a phased waterflood subsea development, tied back to Marathon's Brae 'A' platform in neighbouring Block 16/7a. During Phase I the discovery and both appraisal wells were re-completed as two oil producers and one water injection well. Phase II comprised a third oil production well and a second water injection well drilled and completed in 1996-1997. Oil production peaked at e. 28 000 BOPD in the second half of 1996. The field is currently in decline and production in June 1999 was c. 7000 BOPD with a water-cut of c. 40%. Cumulative oil production to end June 1999 was 21 MMSTB and remaining oil reserves are estimated as 9 MMSTB.
The Birch Field is located in Block 16/12a, approximately 150 miles NE of Aberdeen on the United Kingdom Continental Shelf (UKCS) (Fig. 1). The block straddles the faulted eastern margin of the Fladen Ground Spur that forms the western margin of the South Viking Graben (Fig. 1). The field comprises a series of petroleum accumulations reservoired in the Upper Jurassic, Brae Conglomerate adjacent to the Graben Bounding Fault that separates the Fladen Ground Spur from the South Viking Graben (Fig. 1). These collectively form a conspicuous linear trend of fields, known as the 'Brae Trend', extending from the Brae fields in the north (Block 16/7a) to the 'T Block' fields in the south (Block 16/17). The 'Trees Block', 16/12a, lies between these two blocks and takes its name from the naming convention of prospects and discoveries after trees.
a fault terrace of the Graben Bounding Fault (Fig. 1). At least some of the failures, including 16/12-1 and 16/12a-2, can be attributed to uncertainty in mapping the Graben Bounding Fault and the unintentional penetration of the footwall, on which the Brae Conglomerate is thin or absent. Notably, well 16/12a-4 (Fig. 2) drilled in 1983, down-dip and to the northeast of the Birch Field, penetrated the Brae Formation at - 1 4 5 0 3 t TVDSS, some way below the Birch OWC at - 1 3 8 1 5 ' TVDSS. Although this well failed to discover Birch, it did encounter a distal facies of the Brae Formation with oil shows and the results of this well influenced subsequent exploration that resulted in the discovery of the Birch Field.
Discovery History Block 16/12 was awarded as part of the 4th Round Licence P.212 to Hunt International and Viking Oil in 1972. The original block, 16/12, had an area of 274 square kilometres. In 1978 a mandatory 50% relinquishment was made and part Block 16/12a was created (Fig. 1). Since award of the block, there have been a number of changes in the partnership with three different operators up to 1990 (Hunt, Placid Oil and Occidental) when LASMO took over operatorship. The partnership at the time of writing comprised LASMO, Veba Oil and Gas, and British Borneo. In 2001 Venture took operatorship.
Birch was mapped as a conspicuous anticlinal structure at the Base Cretaceous Unconformity on the 2D seismic data available at the time. The Birch discovery well, 16/12a-8, was drilled in 1985 on the flank of this feature. Well 16/12a-8 penetrated some 244 feet of oil-bearing, Brae Formation conglomerates (Fig. 3). An oil-water contact was not observed owing to the presence of pervasively calcite-cemented conglomerate at the base of the oil column. A drill stem test was conducted over the upper part of the Brae Conglomerate and tested 8964BOPD and 2 0 . 7 M M S C F D gas through a one-inch choke. The oil produced was light, 42-43 ~ API. The well was subsequently suspended as an oil discovery.
Post-discovery Pre-discovery Prior to the discovery of Birch in 1985, the 'Brae Trend' had been established both north and south of the block confirming the 'Brae Conglomerate Play'. Discoveries at this time included the North Brae (1975), Central Brae (1976) and South Brae (1977) fields in Block 16/7a; Thelma (1976), Toni (1977) and Tiffany (1979) fields in Block 16/17 (Kerlogue et al. 1994). All seven wells drilled on 16/12(a), before the Birch discovery well, shared similar Late Jurassic targets. These recorded mixed success, including the discovery of the Elm Field in 1984 (16/12a-5) on
The 16/12a-8 discovery well was re-entered in 1989 to perform an extended well test that produced about 0.5 MMSTB. Pressure data from this indicated a STOIIP of around 70 MMSTB. The well was then re-suspended for use as a future producer. A proprietary 3D seismic survey was acquired in 1986-1987 by Occidental prior to appraisal wells 16/12a- 15, - 18, and - 18z which were drilled during 1991-1992. Well 16/12a-15 was a step-out to the S-SE designed to establish the oil-water contact and effectiveness of the aquifer. However, degradation of the reservoir with depth in the field has prevented the clear definition of the oil-water contact;
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 167-181.
167
168
J. HOOK E T A L .
log, core and DST data converge on an oil-water contact at approximately - 1 3 8 1 5 ~ TVDSS. The well was tested at a rate of over 5000 BOPD and the well was then suspended as a future water injector. However, sufficient injectivity could only be achieved by injecting into both the water and oil legs Well 16/12a-18 was designed as a step-out, intended to appraise the western limit of the field. The well actually penetrated the footwall, indicating that the graben bounding fault was further east than mapped. Although the well encountered a thin succession of Brae Conglomerate (93 ft) with oil shows, repeat formation test measurements indicated that the section was impermeable. This was taken to indicate that the Birch accumulation was essentially confined to the hangingwall. The Brae succession in this well appears to lie with marked unconformity on autochthonous brecciated footwall which passes with depth into undeformed footwall, collectively regarded as Devonian. The well was subsequently sidetracked to the east.
16/12a Block Boundary
The 16/12a-18z sidetrack penetrated the Brae Conglomerate reservoir in the hanging wall and it is the structurally highest well on the field, drilled just off the crest (-12941 feet TVDSS). The well encountered the best reservoir quality observed to date. When the field was brought on stream, this well produced with a productivity index (PI) of 120BBL/D/PSI, much greater than the PI recorded in wells 16/12a-8 and 15 (5 BBL/D/psi in both). The 16/12a-18z well also encountered a small separate oil accumulation in the Ryazanian Rowan Sandstone Member, encased within the Kimmeridge Clay Formation, above the main Brae reservoir. Wade et al. (1995) have described this in detail. The different pressures and oil properties recorded in this horizon indicated that it was isolated from the underlying Brae reservoir. This well was suspended as a future oil producer. The Birch Field was brought on stream in September 1995 and two further development wells, 16/12a-21 and -22 were drilled in 1996-1997.
+3 ~12
13
Extent of Cedar Closure
Larch Field
jY" J
19.
/-"\
/
........
I\
Birch Field
Extent of Rowan Sandstone Member
U-
// ....
i
Graben Boundin Fault at Top Brae
Elm Field
;
i
I/
t
PLAtfoRm,
!/?
~
L
~~,,~ Graben Bounding Fault at Base Brae
5knl
Fig. 1. Block 16/12a location map. The block straddles the Graben Bounding Fault (GBF) separating the Fladen Ground Spur (FGS) from the South Viking Graben (SVG). The location of the GBF is shown at top and base Brae Formation in the hanging wall. The Middle Jurassic Cedar structure which partially underlies the field is outlined as is the extent of the overlying Ryazanian Rowan Sandstone Member (modified from Wade et al. 1995).
BIRCH FIELD
Development method The development method for the field involved water injection for pressure maintenance and sweep. Due to the high formation volume factor of Birch crude, partial pressure maintenance was proposed in order to maximize oil recovery by natural pressure depletion and still maintain productivity at the wells. A phased development was proposed in order to allow additional data to be acquired prior to further development. During Phase I the discovery well and one of the two appraisal wells, 16/12a-8 and -18z respectively, were completed as oil producers, whilst the other appraisal well, 16/12a-15, was completed as a water injector. In 1996, the 16/12a partnership participated in a regional multi-client 3D seismic survey which was processed and interpreted prior to the Phase II development drilling. During Phase II, well 16/12a-21 was drilled to provide the third oil producer and well 16/12a-22 the second water injector (Fig. 2). Sub-sea wellheads are tied to back to a manifold on the seabed which itself is tied back to the Marathon operated Brae 'A' platform located in the contiguous 16/7a Block (Fig. 4). Oil production is via
1 6/1
169
a 10" line to a dedicated production train on Brae A. Oil and N G L are exported from Brae A to Kinneil via the Forties Pipeline System and gas is utilized on the platform. Desulphonated sea water is injected via a 12" injection line. This treatment mitigates the scaling tendency of the relatively high barium connate waters. A 4" service line permits chemical treatments and intermittent gas lift. Permanent gas-lift, not included in the original design, was installed in late 1999.
Structure Tectonic history The tectonic history of the block has been intimately associated with the evolution of the South Viking Graben. The principal rifting event is believed to have taken place in the Middle Jurassic (Rattey & Hayward 1993) creating considerable relief across the N - S trending, down-to-the-east, graben bounding fault. The Brae Conglomerate reservoir comprises a syn-rift to post-rift infill of the
2-11
16/12
Line of Section in Figure 5
398000
-
....
"]::,".....,i'L"
o. . . . . . .
400000
Fig. 2. Top Brae Formation depth structure map (ft). The Birch Field PRT boundary and the OWC are outlined. Well deviations from the Birch manifold located close to the 16/12a-8 well surface location are shown. Well symbols mark the position of the wells at top Brae Formation.
170
J. HOOK E T AL.
relief generated during rifting and is essentially the product of mass wasting of the footwall. An episode of Late Jurassic inversion appears to mark the end of the Brae Conglomerate deposition and has locally resulted in the elevation of parts of the hanging wall above the footwall (Fig. 5). The reversal of movement along pre-existing normal faults as well as the generation of minor reverse faulting accompanied inversion.
CHRONOSTRATIGRAPHY EPOCH
PERIOD
Regional
structure
The Birch Field lies on the faulted eastern margin of the Fladen Ground Spur, which forms the western margin of the South Viking Graben (Fig. 1). The graben-bounding fault separates these two structural elements and results in the dominant north-south structural grain in the area. The graben edge manifests itself throughout
LITHO-STRATIGRAPHY GROUP
LITHOLOGY
FORMATION
W
E
SEA LEVEL SEA BED ILl Z ILl
0 .J la.
~......
Z
NORDLAND GROUP
iii Ill U. U.
uJ z
>n,'
_
LU
uJ (..) O
z_-_
-;
Z
C3
OLIGOCENE
UJ
m
In,, ILl I-
m
kZ
HORDALAND GROUP
iii iii ii ii
EOCENE
C3 Z
BALDER FM.
MONTROSE GROUP
HEIMDALFM.
iii
O LU
- .--: .--: .--: .~ i - ? .
S E L E FM. LIST,:, F,=,;
z uJ L)
v v v v v V'V, ~ ~ V V ~
MORAY GROUP
E~llI ;1=1=1~l =IL~
.
.
.
.
.
,--
..L --L ..L --L ~
--L
E K O F I S K FM.
p L : _ ~
TOR FM.
O
ILl
UPPER
i I I I - _ - - - _ - -. ~
CHALK GROUP
.
FOUNDER FM. U.I
HERRING F M . PLENUS M A R L F M
IZ r
HIDRA
LOWER
CROMER KNOLL GROUP
.
.
.
FM.
FM. SOLA FM. VALHALL FM.
fO m 03
UPPER
HUMBER GROUP
BRAEFM. HEATHER
MIDDLE Fig. 3. Stratigraphy of the Jurassic to Tertiary section in the area of the Birch Field.
.
.
.
-
; :
.
~ . . ~ _ x
.......
•
RODBY
K I M M E R I D G E C L A Y FM.
03
.
-__-__ _ ~ - ~
FM.
KIMM. CLAY FM.
HUGIN SLEIPNER
FM. FM.
I
~
I
,
1
i
, ....... , [....
BIRCH FIELD
171
Stratigraphy
the overburden, which exhibits a marked thickness change across the underlying fault (Fig. 5).
The Brae Formation is Late Jurassic in age and is intercalated within the Kimmeridge Clay Formation (McClure & Brown 1992). The Brae Conglomerate is an informal subdivision of the Brae Formation where the latter is locally conglomeratic in Blocks 16/7a, 16/12a and 16/17. Until recently, the deepest seismically mappable event was the overlying Base Cretaceous Unconformity bounding the top of the Kimmeridge Clay Formation, however recent reprocessing of the 3D seismic data has permitted good imaging of the top Brae Formation as well as revealing some intra-Brae events. The Brae Formation in 16/12a is highly variable in thickness. It displays a patchy distribution on the footwall and is absent in the west of the block. The updip pinch-out to the west is constrained by a number of well penetrations including 16/12a-2, -11 and -16 (Fig. 1). Where the Brae Conglomerate is present on the footwall, it typically rests with marked unconformity on barren 'red beds' assigned to the Devonian. In contrast, the base of the Brae Formarion has not been penetrated in any of the wells drilled in the hangingwall in the east of the block. The greatest penetration of Brae Conglomerate in 16/12a to date is 1458 feet in well 16/12a-18z. Biostratigraphy performed on wells in Block 16/12a record ages ranging from Kimmeridgian to Early Volgian for this formation. Bright reflectors identified on seismic data beneath the deepest well penetration are believed to be Middle Jurassic coals. These indicate that the Brae Formation reaches a thickness in the order of 25004000 feet beneath the Birch Field and exhibits a marked thinning eastwards in a basinward direction. Typically, wells in the field display a serrated low gamma ray profile (Fig. 6) and lack well defined trends on any scale, suggesting
L o c a l structure
The Birch Field comprises a hangingwall anticline in the Graben Bounding Fault (Figs 2 and 5). The anticlinal nature of the field is believed to reflect the original geometry of the Birch fan, augmented by differential compaction and inversion, although the relative contributions of these two mechanisms are unclear. Birch is partially underlain by a large undrilled Middle Jurassic structure, the Cedar prospect, which may account for the somewhat larger closure in Birch than in the nearby Larch and Pine fields, to the north to the south respectively (Fig. 1). The closure of both Birch and Larch is effected by compactional drape across the fan. Marked thickness changes are apparent in the Late Jurassic Kimmeridge Clay Formation and Lower Cretaceous, Cromer Knoll Group successions that are attenuated over the crest of the field. This indicates the existence of a topographic high by at least end Jurassic times. The origin of this relief was originally attributed to simple differential compaction. It was assumed that a concentric pattern of facies emanated from a single sediment entry point in the grabenbounding fault, becoming more distal in nature with increased distance from this point source. This entry point in the grabenbounding fault was assumed to be immediately west of the crest. However, more recently, inversion has been recognized as playing an important role in the development of relief on the field.
B R A E 'A'
BP Forties to Kinneil (including Block 16/12a Oil Export) BP Miller 10" Production Pipeline (Duplex)
New Permanq Gas Lift Line
4" Service Pipeline (Carbon Steel) 12" Water Injection Pipeline (Carbon Steel)
LARCH DEVELOPMENT
5" Control Umbilical Approx,
Manifold
'Z6
12.5 kms
~7~
Control Umbilical
Manifold Assembly /
~
~
I 16/12a-15
16/12a-22
Fig. 4. Surface infrastructure for the Birch Field sub-sea tie-back to Marathon Brae A platform.
172
J. HOOK ET AL.
deposition was largely aggradational in nature. Few palynomorphs have been recovered from the Brae Formation due to the paucity of shales and coarseness of the sandstones and conglomerates. This, together with a lack of age diagnostic taxa, has hampered attempts to correlate the reservoir in the field and only a crude division of the Brae Conglomerate has been possible to date. This contrasts with the overlying Kimmeridge Clay Formation where good palynological recovery permits the reliable dating of this formation. The nature of the contact between the Brae Conglomerate and the overlying Kimmeridge Clay Formation appears to vary with well location. The structurally highest and most central well in the field, the 16/12a- 18z sidetrack, like the original 16/12a- 18 penetration in the footwall, displays a sharp boundary between the Brae Conglomerate and the overlying Kimmeridge Clay Formation. This is interpreted as reflecting proximity to the depocentre. Furthermore, biostratigraphic analysis of the 16/12a-18 well suggests that the uppermost Brae Conglomerate is younger than that present at the top of the 16/12a-18z well. This diachroneity may reflect the westward migration of the depocentre onto the footwall towards the end of the Brae deposition. However, it is also possible that the inversion that appears to mark the end of Brae deposition also resulted in the truncation of the Brae Conglomerate in the 16/12a- 18z well. In most wells, however, the upward passage from the Brae Conglomerate into the overlying Kimmeridge Clay Formation is accompanied by a more gradual increase in gamma count, reflecting an increasing shale content, interpreted as recording the progressive drowning of the section. Several wells in Block 16/12a display a unit of interbedded sandstone and shales, marking the transition from the Brae Conglomerate into the overlying Kimmeridge Clay Formation. These deposits are commonly of poor reservoir quality and referred to
as the 'Sand-Shale' unit on composite logs. On the southern flank of the field this is manifest as a thick development of fine-grained sandstones in the 16/12a-21 and 22 wells (Fig. 6). These heterolithic deposits display a distinctive lamination and are often referred to as 'tiger-striped'. These sands may be the age equivalent of the Fiona Sands (Deegan & Scull 1977). The overlying Kimmeridge Clay Formation in wells 16/12a-8 and -18z is punctuated by the Late Jurassic/Early Cretaceous Rowan Sandstone (Fig. 1). This thickens downdip considerably into the nearby 16/12a-4 well. The type section of the Rowan Sandstone is described from well 16/12a-18z by Wade et al. (l 995), who assign a Ryazanian age to it. The base of the overlying Lower Cretaceous section is often missing which may again reflect inversion at this time. However, seismic and well data indicate a relatively complete stratigraphic section in the overburden above the Base Cretaceous Unconformity.
Trap Trap type
The trap is a hanging wall anticline associated with the Graben Bounding Fault (Fig. 2). The field only displays minor independent four-way dip closure at the very crest, below which, trapping is formed by a combination of faulting to the west and dip closure in other directions. This western seal might comprise cementation along the Graben Bounding Fault; juxtaposition against indurated Devonian lithologies in the footwall or may even be the product of a conjectured non-reservoir talus zone. Lateral seal is discussed below.
Fig. 5. Wes~East seismic line through well 16/12a-18z. Rare steep dipping reflectors permit differentiation of the hanging wall and foot wall sequences. Minor reverse faulting at top Brae Formation is attributed to mild late Jurassic inversion. Bright reflectors in the lower right of the figure are believed to be Middle Jurassic coals close to the top of the undrilled Cedar prospect that partially underlies Birch.
BIRCH FIELD
Seals The Kimmeridge Clay Formation which exhibits a marked thinning over the crest of the structure provides top seal. A separate small oil accumulation in the Rowan Sandstone Member penetrated in well 16/12a-18z. This suggests that just the lower 100 feet or so of the Kimmeridge Clay Formation, between the base of this sandstone unit and the top of the Brae Conglomerate, provides the topseal to the Birch field and its attendant c. 950' oil column. The oil-water contact at - 1 3 815' TVDSS is some way below the lowest closing contour (13250ft TVDSS), indicating that a lateral seal must also be present to the north and south of the field. The exact nature of this lateral seal has not been established. Both interfan shales and sealing faults could be responsible. Traditionally, the anticlinal nature of the field has been regarded as the product of differential compaction over a point sourced submarine fan in which conglomerates pass distally and laterally into shales of the Kimmeridge Clay Formation. These shales have traditionally been regarded as providing the lateral seal to the field. However, recently, W N W - E S E trending faults have also been mapped and they are broadly coincident with the northern and southern margins of the field (Fig. 2). The anticlinal nature of the field and development of these faults has recently been attributed to Late Jurassic inversion. These faults only display a
173
minor offset at the top Brae Conglomerate. This is taken to suggest that if they do provide seal they must also be cemented.
Faults Faulting has little expression at the Base Cretaceous Unconformity/ top Brae Formation. Indeed, even the Graben Bounding Fault only manifests itself as a small inflexion on the Base Cretaceous Unconformity and only rarely do fault plane reflectors permit differentiation of the Brae Conglomerate in the hangingwall from the Palaeozoic lithologies in the footwall (Fig. 5). The W N W - E S E trending faults bounding the northern and southern margins of the field also display only minor offset at the Base Cretaceous Unconformity/top Brae Formation. Extensive core data reveal a paucity of fractures, although strong cementation in cores from the 16/12a-21 well, by silica and pyrite, together with locally intensive barite, are believed to be fault related. Pressure and production data indicate that all the wells are in good communication suggesting the absence of any intervening sealing faults. However, the relatively modest oil production from the 16/12a-21 well indicates that faults have an impact on productivity and may act as baffles. Clearly the great thickness of Brae Conglomerate, together with the paucity of shales in the
Fig. 6. Well correlation through the Birch Field. Wells reach TD within the thick Brae Formation and typically display fairly flat low gamma ray logs recording thick aggradational conglomeratic sequences with a paucity of shales. Correlation of the wells is difficult and only a crude division has been possible. The boundary between the Brae Conglomerate and the overlying Kimmeridge Clay Formation varies from sharp to gradational.
174
J. HOOK ET AL.
section, mitigate the effects of any intra-field faulting. Notably, some of the faults that are mapped appear to display reversal that is attributed to a Late Jurassic phase of inversion (Fig. 5).
Reservoir Depositional setting In Late Jurassic times, the 16/12a area was marginal to a deep marine basin occupying the South Viking Graben. Conglomeratic submarine fans, including the Birch fan, developed along the margins of the South Viking Graben in the hanging wall of the graben-bounding fault. The principal source of sediment was probably derived by mass wasting of the fault scarps. The Fladen Ground Spur is believed to have provided a subordinate source of sediment to the Birch fan, although the entry points for the introduction of this sediment remain unclear. The Brae Conglomerate is believed to have been deposited in a proximal submarine fan setting by a variety of gravity flow processes, accumulating in overlapping, partly channelised, submarine fan systems. Rapid sedimentation through the Late Jurassic subdued much of the relief generated by Middle Jurassic rifting by end Jurassic times. The Brae Conglomerate reservoir in the Birch Field principally comprises massive polymict clast- and matrix-supported conglomerates with subordinate sandstones. Well logs typically display a serrated but overall low gamma ray response over the Brae Conglomerate interval (Fig. 6), reflecting the paucity of both discrete shales as well as argillaceous matrix within the reservoir. However, reservoir quality in the field is strongly heterogeneous
reflecting both a strong primary depositional as well as secondary diagenetic controls. The best reservoir quality is displayed in the most central and structurally highest wells, 16/12a- 18z. This is largely attributed to the proximal setting of this well, although the well is also free of any obvious fault related cementation. The well recorded a PI of 120 BBL/D/psi when brought on production. The variation in facies in the field is illustrated by well 16/12a- 15 in which two thick units of 'tiger-striped' laminated sandstones are present, interbedded with the conglomerates (Fig. 6). These sands are only observed in this well and are believed to reflect its proximity to the margin of the fan, testifying to its relatively small size. This well only achieved a PI of 5 BBL/D/psi.
Pore types and diagenesis Reservoir quality is principally associated with the sandy matrix of the conglomerates. Although clasts in cores tend be oil saturated, their permeability is somewhat lower than the surrounding matrix. Clast/matrix ratios determined from core are regarded as an important measure of the effective porosity. These range from 21% to 38%. The principal pore type comprises reduced primary intergranular porosity within areas of sandy matrix of the conglomerates. This matrix tends to be medium grained and somewhat coarser than in the discrete, commonly 'tiger-striped', sandstones interbedded with, and overlying, the Brae Conglomerate. Sandstone clasts are the most common clast type and the sandy matrix is regarded as being the disaggregated product of the same lithologies
Fig. 7. Porosity versus permeability cross plot. Extensive core data reveals the heterogeneous nature of the Brae reservoir. Notably, the 16/12a-18z well displays excellent reservoir quality. Poor reservoir quality in well 16/12a-21 reflects degradation by strong authigenic cements.
BIRCH FIELD from which the clasts are derived i.e. Devonian sandstones exposed in the footwall scarps. Typically, moderate compaction has reduced primary porosity, although clasts may well have provided a framework that resisted further compaction. Widespread silica cements are the principal pore reducing cement and these tend to be weakly to moderately developed. Locally, pervasive cementation overprints the otherwise strong primary depositional control on reservoir quality. Reservoir quality in the 16/12a-8 well appears to be confined to the uppermost 244 feet of the Brae Conglomerate. Strong degradation below this depth appears to be the product of pervasive calcite cementation within the oil leg. Carbonate cements also appear to render the Brae Conglomerate in the footwall penetration, 16/12a-18, nonreservoir. These wells contrast with the 16/12a-21 well where pervasive silica and pyrite cements, together with locally strong barite cements degrade the reservoir. These cements are also considered to be fault related. Subordinate secondary porosity is also observed and ranges from intragranular porosity within partially leached feldspars to
175
elongate and oversized pores suggestive of complete framework grain dissolution. This is evident in both clasts and matrix.
Porosity, permeability The highly variable reservoir quality in the field was recognized at an early stage and has promoted extensive coring programmes with all five wells cored over much of the oil column. Although clast percentage is regarded as a key factor in reservoir quality, the relatively small clast sizes have made characterisation of clast and matrix poroperms difficult. Core porosity reaches as high as 28 % with permeability up to 4500 mD recorded, however porosity and permeability tend to be highly variable (Fig. 7). Reservoir quality in all the wells displays a marked degradation with depth (Fig. 8). Depth below the top Brae Conglomerate appears to be a stronger control on reservoir quality than absolute burial depth. The consequence of these lateral and vertical changes
Fig. 8. Porosity versus depth plot (Phase I wells only). Extensive core data reveals the reservoir heterogeneity over the c. 950' oil column in thc field. A marked degradation of reservoir quality in the 16/12a-8 well is due to pervasive calcite cementation. The two intervals of relatively low porosity in well 16/12a-I 5 are associated with distal 'tiger-striped' sands.
176
J. HOOK ET AL.
in reservoir quality is that satisfactory water injection can only be achieved in the two peripheral water injectors, 16/12a-15 and -22, by injecting primarily into the oil legs of these wells.
Pressure relationships Extensive pressure data has been acquired from various sources during the exploration, appraisal and development phases of the field. This includes an EWT, open hole pressure measurements recorded in all five development wells, including two wells drilled after field start-up, and downhole pressure measurements from the three production wells. RFT pressures measured in the discovery well, 16/12a-8, established that the field is slightly overpressured at 7462 psia (at a datum of 13 500 ft TVDSS) compared with hydrostatic pressure of about 6000psia. An EWT was performed on this well in 1989 and produced c. 0.5 MMSTB of oil. On conclusion of the test, a thirteen
day long pressure build-up was performed and the final pressure indicated a pressure drop of 235psia from initial pressure. The subsequent appraisal well, 16/12a- 15, recorded a further build-up of 72 psia by 1991. Furthermore, this pressure increase was observed throughout the oil column (Fig. 9). A further build-up of 6 psia was observed in the subsequent appraisal well, 16/12a-18z, drilled in 1992 which again displayed a uniform pressure build-up across the entire oil column. Data from these two wells suggest there is only a small aquifer influx. The subsequent Phase II wells, 16/12a-21 and -22 were drilled consecutively and after field start-up. These indicated a depletion of 1800 and 2000 psia respectively. Furthermore, a uniform pressure decline over the upper 600' of the oil column is displayed in the 16/ 12a-21 well (Fig. 9). Despite the relatively poor reservoir in this well, this data confirms the excellent vertical connectivity which has led to the piston-like displacement of the oil column during production. Fewer data were acquired from 16/12a-22 but the same trend was observed (Fig. 9). A gradual increase in pressure towards the base of the oil column and into the aquifer is observed in both
Fig. 9. Open Hole Pressure Data in the Birch Field. Pressure data reveal the lack of vertical barriers to flow in the field. Pressures in wells 16/12a-15 and -18z reflect the EWT performed on well 16/12a-8. Wells 16/12a-21 and -22 were drilled after field start-up and record uniform drainage over much of the oil column; differential depletion at the base of these wells is attributed to reservoir degradation.
BIRCH FIELD
177
Fig. 10. Flowing Bottom Hole Pressure (FBHP) at the production wells since field start-up. Data is reported at gauge depth and correction to datum would largely superimpose the curves. The good match in the data reveals an excellent communication between the three producers. The early difference in pressure recorded in well 16/12a-21 reflects production from partially drained sand above the Brae Conglomerate not encountered in the other wells. Marked pressure build-ups were recorded during field shut-ins in March 1997, June 1997 and June 1999 (the first of which had continued water injection). The late increase in pressure recorded in 16/12a-18z followed shut-in of this well at high water-cuts.
these wells and suggests differential depletion has taken place. This appears to reflect reservoir quality. Permanent downhole pressure gauges installed in the three producers, 16/12a-8, - 18z and -21, have provided continuous pressure data since start-up. These indicate that despite the heterogeneous nature of the reservoir, the wells are in excellent communication (Fig. 10). Furthermore, pressures in the production wells are responsive to water injection. The production strategy has been to maintain the reservoir pressure with a safe margin above the bubble point of 4225 psia.
Source
Source rock The regionally widespread and prolific Kimmeridge Clay Formation source rock immediately overlies the Brae Conglomerate in the field. This is regarded as the source of the 35 ~ API oil reservoired in the Rowan Sandstone. However, the Birch crude is somewhat lighter with a gravity of 42 ~ API and G O R of around 2650 SCF/STB. This is unusually light for a field at this depth in this area. Like many fields in the 'Brae Trend', the nearby Larch field (Fig. 1), at a similar depth to Birch, produces oil with a gravity of 35 ~ API and has a G O R of around 700 SCF/STB. However, the North Brae Field in Block 16/7a (Brehm 2003) displays an oil similar to Birch. Geochemical analysis, including G C - M S and saturate fraction chromatography, points to the predominant source for the Birch crude being from the pre-Kimmeridge Clay Formation Late Jurassic Heather Formation and/or the Middle Jurassic Hugin Formation (Fig. 3), although neither formation has been encountered in the block. Both formations are absent from the footwall penetrations through erosion and/or non-deposition; none of the wells drilled in the hangingwall penetrate the base of the Brae Conglomerate. However, wells in 16/7a do penetrate Heather and
Hugin formations beneath Brae Conglomerate, demonstrating their presence in the area. Furthermore, bright reflectors observed on seismic data below and to the east of the Birch Field (Fig. 5) are interpreted as Middle Jurassic coals, suggesting that the Hugin Formation may be present there too.
Maturation The Kimmeridge Clay Formation overlying the Birch Field is currently mature for the generation of oil and is believed to have sourced the small oil accumulation in the Rowan Sandstone encased within this formation. Although geochemical data suggests the Kimmeridge Clay Formation provided only a minor contribution to the oil reservoired in the underlying Brae Formation, this does indicate that the Heather and/or Hugin formations, if present, must have reached at least this level of maturity. Indeed, given that the depth of either formation is likely to be in excess of 17 000 t, it is probable that they are now post-mature.
Migration and charge The contrasting oil type in Birch with other 'Brae Trend' discoveries is reconciled with the presence of a marked closure at Middle Jurassic level (the undrilled Cedar prospect) which at least partially underlies the Birch Field (Fig. 1). Spill or leakage from Cedar may account for the unique properties of the Birch oil. Also, the structural closure associated with Cedar may have acted to focus oil migration pathways upward into the overlying Birch structure. It is noteworthy that a similar origin for the uncharacteristically light oils reservoired in the North Brae field has been proposed by (Brehm 2002), which itself is underlain by the Middle Jurassic Beinn Field.
178
J. HOOK ET AL.
Oil reservoired in the Rowan Sandstone, encountered in well 16/12a-18z, is consistent with it having been charged from the surrounding Kimmeridge Clay Formation which envelops this unit. The original fan geometry augmented by early inversion is assumed to have provided a trap relatively early in the fields history. Birch is assumed to be full-to-spill, however until the nature of the lateral seal is understood, this cannot be confirmed.
Reserves and production
recent simulation study compared to 34% for the matrix alone. Also, prior to the acquisition of 3D seismic data over the field, the Graben Bounding Fault was mapped somewhat further west than at present which led to an overestimate of the gross rock volume. This was reduced to agree with the STOIIP determined from the E W T by employing a c. 200 metre wide zone of nonreservoir talus along the faulted western margin of the field. The former was justified by the presence of a thick oil saturated nonreservoir talus deposit in the 16/12a-20 well (Fig. 1). Subsequently, however, the Graben Bounding Fault has been mapped somewhat further east, eliminating the need for such an extensive talus zone.
Petroleum in place An extended well test performed on the discovery well provided an early indication of STOIIP of around 75 MMSTB. Current material balance estimates range from 66 to 88 MMSTB. The range reflects the presence of some 17% of the total STOIIP in somewhat poorer communication with the main accumulation. This oil might be reservoired in deeper poorer quality reservoir and/or in the udpip region close to the Graben Bounding Fault where complex faulting may have sequestrated oil. Deterministic volumetrics based on geological and geophysical mapping, calculated at various periods during the field's history, have been at variance with volume calculated from material balance studies. This difference is attributed to a number of uncertainties, several of which remain unresolved, including the contribution of clasts to production, the presence and extent of any talus zone, the exact location of the Graben Bounding Fault and the nature of the lateral seals. Early models regarded the clasts as non-net reservoir, however nuclear magnetic resonance data from the Larch Field suggests that there is at least some clast contribution to production. It is now envisaged that the clasts have liberated some of their oil during the reduction in field pressure but that their lower permeability has rendered them largely unswept by injection waters. As a consequence of the clasts not being swept, residual oil saturations as high as 50% for the total system (matrix and clasts) have been used in a
Petroleum reserves The current reserve estimates are only slightly below those presented at the time of the field development plan submission in 1994. Expected ultimate reserves at the time were predicted to be 31.7 MMSTB of oil, together with 4.5 MMSTB of N G L ' s and 66.0 BCF of gas. The estimates at end June 1999 were 30 MMSTB of oil, together with 4.1 MMSTB of N G L ' s and 54 BCF of gas. The close agreement of these figures reflects the reliable estimate of STOIIP and reserves provided by the extended well test.
Recovery factor Simulation studies performed prior to sanction predicted a waterflood pattern with good areal and vertical sweep. These factors contributed to the recovery factor of 39% assumed in the field development plan. Excellent communication of the wells has been observed together with a waterflood behaviour that has largely met expectations. A change in the mapped gross rock volume, together with a different perception of the role of the clasts, in terms of their contribution of oil to production, has resulted in a modest revision of STOIIP. The revised recovery factor is 42%.
Fig. 11. Field and well oil production. Well 16/12a-18z dominated production during the early field life; this well has ceased to flow naturally at high water-cuts and has been shut-in since August 1998. First oil from well 16/12a-8 was delayed owing to mechanical problems; the recent production decline in this well reflects increasing water-cut. The relatively poorer production from well 16/12a-21 is the result of poor reservoir quality; recent increase in production from this well reflects the removal of pressure constraints imposed by the other producers.
BIRCH FIELD
179
Fig. 12. Field cumulative production (gas, oil and water) and injection (water). The Birch crude is a highly volatile oil and there is thus significant associated gas production. Water injection was delayed until April 1996 due to the presence of a hydrate plug in the injection well 16/12a-15. Water breakthrough occurred in November 1997 at well 16/12a-18z and in November 1998 ion well 16/12a-8.
A number of favourable factors contribute to this high recovery factor, including the relatively high dip of the field, lack of vertical permeability barriers, permeability degradation with depth and the favourable mobility ratio. Collectively, these factors are considered to have promoted slumping of injection waters, resulting in a piston-like displacement of the oil column observed on pressure data acquired in wells 16/12a-21 and -22, post start-up (Fig. 9).
Production rate The field and well oil production rates are shown in Figure 11. First oil was achieved ahead of schedule on 14th September 1995. Phase I production was forecast to start at a peak plateau rate of 23 500 BOPD from two wells, 16/12a-8 and -18z, with water injection into the 16/12a-15 well from start-up. Following problems with both the 16/12a-8 and -15 wells, however, early production came solely from the prolific 16/12a- 18z well without the benefit of the water injection (Fig. 11). This resulted in a marked pressure decline during this period (Fig. 10). Water injection was recommenced in well 16/12a-15 in April 1996 with initial injection rates of c. 20 000 BWPD that increased to over 35000BWPD by June 1996, indicative of thermal fracturing. Production from the 16/12a-8 well was restored in May 1996 and, following drilling and completion of the 16/12a-21 well in July 1996, a peak rate of c. 28 000BOPD was achieved in August 1996. The Phase II wells, 16/12a-21 and -22, were originally scheduled for 9-12 months after first oil to help maintain plateau production. Production from well 16/12a-21 has, however, been disappointing and field production has fallen steadily without an extended plateau period (this has been exacerbated by poor water injection performance). Well 16/12a-21 encountered poorer reservoir quality than forecast and initial production was only c. 4000 BOPD, dropping to about 1000 BOPD over a six month period (Fig. 11), albeit pressure constrained due too it's low PI. This marked decline is attributed to the depletion of a small and hitherto unrecognised sand overlying but in communication with the Brae Conglomerate (Figs 6 and 9).
The 16/12a-22 well was completed in December 1996. Injection rates for this well are c. 16 000 BWPD and the well does not appear to have benefited from the thermal fracturing as observed in well 16/12a-15. Water breakthrough was first observed in November 1997 in well 16/12a-18z. At this time, field oil production was c. 17 000 BOPD. The well water-cut increased rapidly to 80% by April 1998 with a consequent decline in the oil production rate. The well was shut-in in August 1998 (Fig. 10), awaiting future attempts to offload it with permanent gaslift. By this time, field oil production rate had declined to c. 10 000 BOPD. Well 16/12a-21, which had previously been pressure constrained, displayed an increase in production over the same period (Fig. 11). In November 1998 the 16/12a-8 well also began to cut water, however this well displayed a more gradual water-cut development than that observed in well 16/12a-18z. At end June 1999, water-cut in well 16/12a-8 was c. 50%. Overall water-cut at this time was more or less as forecast in the Development Plan, however water-cut development started earlier and has been more rapid than forecast. Permanent gas-lift, not catered for in the field development plan, was installed in late 1999 in order to restore production in the 16/12a-18z well and extend life of well 16/12a-8. No water cut has been observed in well 16/12a-21 to date and field production at end June 1999 was c. 7000BOPD with a c. 40% water-cut.
Cumulative production The field cumulative production data is shown in Figure 12. At end June 1999, this comprised 21.2MMSTB of oil, 3.0MMSTB of NGL's and 48.4 BCF of gas. Individual well contributions (Fig. 11) were 16/12a-8: 7,2MMSTB; 16/12a-18z: 12.3 MMSTB; 16/12a-21: 1.7MMSTB. Cumulative water injection at this time was 37.2 MMSTB; 24.6 MMSTB in well 16/12a-15 and 12.6 MMSTB in well 16/12a-22. Cumulative water production over this same period was 2.0 MMSTB. The cumulative voidage replacement is c. 73%, in line with the field development plan estimates and reservoir pressure at the end of June 1999 had declined from 7300 psia to c. 5000 psia.
180
J. HOOK E T AL.
Birch Field data summary Trap
Type Depth to crest Lowest closing contour
Combination Structural/Stratigraphic lowside closure 12868ft 13250ft
Gas-oil contact Oil-water contact Gas column Oil column
n/aft 13815ft n/aft 947 ft
LCC for 3 way dip/fault seal; lateral seal extends closure below this depth No free gas in field Defined by core, log and DST data from 16/12a-15 & -18z Undersaturated oil Formation thickness greater than height of closure
Pay zone
Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Brae Formation/Brae Conglomerate Late Jurassic 947 ft 83% 10.5 (0.8 to 27.7)% 94.3 (0.01 to 4480)mD 70.2%
Ambient Core Porosity (core data from all five wells) Horizontal Air Permeability (core data from all five wells) Average log Water Saturation 29.8 16/12a-8, - 15 & - 18z
5 to 120 BOPD/psi
16/12a-15 to 16/12a-18z
42-43 deg API Undersaturated volatile oil 0.90 0.14 cp 4225 psia n/a psia 2648 SCF/STB n/a BBL/MMSCF 2.4 rb/stb n/a SCF/RCF
Well -8 and -15 Separator Test Data
100000 NaC1 eq ppm 0.0935 ohm m
Water sample from DST 1A in 16/12a-15 @ 60~ DST 1A 16/12a-15 BHSIA-2
Volgian to Kimmeridgian
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
Associated Gas Gravity (wells -8 and -15) Well -15 Viscosity at Intitial Pressure Well -15 at Reservoir Temperature (270deg F) From Updated PVT Study (1998) At Initial Reservoir Pressure (Updated PVT Study,1998)
Formation water
Salinity Resistivity
100 000 TDS mg/1
Field characteristics
Area Gross rock volume Initial pressure Pressure gradient
988 acres 423 343 acre ft 7462 psia 0.248 psi/ft
Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
270~ 75 MMBBL n/a BCF 42% Waterflood 30 MMBBL 54 BCF 4.1 MMBBL
@ Datum 13 500 TVDSS From RFT data in oil legs from -8, - 15 & - 18z agrees with oil density measurements from PVT @ Datum 13 500 TVDSS from DST's Well -8 EWT Material Balance Estimate No free gas Partial pressure maintenance 1998 Subsurface Update 1998 Subsurface Update 1998 Subsurface Update
Production
Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
14 September 1995 28000 BOPD 70000 M C F / D 1 exploration 3 appraisal 2 development
Many colleagues at LASMO have worked on the Birch Field and much of the data and ideas presented here have been borrowed freely from their reports. Similarly, the 16/12a participants, in particular those from erstwhile partners Hardy and Deminex, have contributed to the successful development of this small and complex field. Their successors, British Borneo and Veba have kindly agreed to the publication of this manuscript.
No plateau peak rate achieved in August 1996 No plateau peak rate achieved in August 1996 16/12a-8 (reused as an oil producer) 16/12a- 15 (reused as a water injector), - 18 (abandoned), - 18z (reused as an oil producer) 16/12a-21 (oil producer), -22 (water injector)
References BREHM, J. A. 2003. The North Brae and Beinn Fields. In: GLUYAS, J. & H~CHENS, H. (eds) UK Oil & Gas Fields, Millennium Volume. Geological Society, London, Memoir, 20, 199-209.
BIRCH FIELD DEEGAN, C. E. & SCULL, B. J. 1977. A standard tithostratigraphic nomenclature for the Central and Northern North Sea. Institute of Geological Sciences Report 77/25. KERLOGUE, A., CHERRY, S., DAVIES, H., QUINE, M. & SPOTT1,G. 1994. The Tiffany and Toni oil fields, Upper Jurassic submarine fan reservoirs, South Viking Graben, UK North Sea. Petroleum Geoscience, 1,279-285. McCLURE, N. M. & BROWN, A. A. 1992. Miller Field: A subtle Upper Jurassic submarine fan trap in the South Viking Graben, UK sector, North Sea. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Fields oJ" the Decade 1978-1988. American Association of Petroleum Geologists, Memoir, 54, 307-322.
181
RATTEY, R. P. & HAYWARD, A. B. 1993. Sequence stratigraphy of a failed rift system: the Middle Jurassic to Early Cretaceous basin evolution of the Central and Northern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 214-249. WADE, D. N., LAWRENCE, D. A. & RILEY, L. A. 1995. The Rowan Sandstone Member (Upper Jurassic to Lower Cretaceous): stratigraphic definition and implications for North Sea Exploration. Journal of Petroleum Geology, 18(2), 223-230.
The Central Brae Field, Blocks 16]07a, 16/07b, UK North Sea KEITH
J. F L E T C H E R
Marathon Oil UK, Ltd., Marathon House, Rubislaw Hill, Anderson Drive, Aberdeen AB15 6FZ, UK Present address: Shell UK Exploration and Production, 1 Altens Farm Road, Nigg, Aberdeen AB12 3 F Y
Abstract: The Central Brae Oilfield is the smallest of three Upper Jurassic felds being developed in UK, Block 16/07a. The field was discovered in 1976 and commenced production in September 1989 through a sub-sea template tied back to the Brae 'A' platform in the South Brae Oilfield. The field STOOIP is 244 MMBBLs, and by May 1999 cumulative exports of oil and NGL reached 44 MMBBLs. The Central Brae reservoir is a proximal submarine fan sequence, comprising dominantly sand-matrix conglomerate and sandstone with minor mudstone units. The sediments were shed eastwards off the Fladen Ground Spur and were deposited as a relatively small and steep fan at the margin of the South Viking Graben. Mudstone facies border the submarine fan deposits to the north and south, forming stratigraphic seals. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous, initially formed as a hangingwall anticline during extension but subsequently tightened during compressional phases. The western boundary of the field is formed by a sealing fault, whilst to the east, there is an oil-water contact at 13 426 ft TVDss. The overlying seal is the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards and provides the source of the hydrocarbons.
The Central Brae Field is located between the South Brae and North Brae Fields in U K Blocks 16/07a and 16/07b, some 165 miles NE of Aberdeen (Fig. 1). Central Brae is an oilfield, with fluid properties that are similar to South Brae but distinctly different from the gas condensate of North Brae. The areal extent of the field (approximately 1800 acres) is considerably less than that of either of the other fields, but there is high relief (maximum 1676 ft) which equals that of South Brae and greatly exceeds that of North Brae. Production commenced in September 1989 through a sub-sea template, set over well 16/07a-27 in 350ft of water, tied back to the Brae 'A' Platform in the South Brae Field. The Central Brae structure is a faulted anticline formed at the margin of the South Viking Graben. The reservoir comprises sandstone, conglomerate and minor sandstone deposited as a relatively small, discrete late Jurassic submarine fan, between the much larger submarine fans of South Brae and North Brae.
History The history of Licence P.108, which covers Block 16/07a, is described by Fletcher (2003). Central Brae was discovered by well 16/07-3 which was drilled by Pan Ocean in 1975-1976 as an appraisal well to the North Brae discovery, 16/07-1. Well 16/07-3 was sited on an anticline extending southwards from the North Brae domal feature, and tested oil at a cumulative rate of over 13000 BOPD from five Upper Jurassic intervals. Following Marathon's acquisition of Pan Ocean in 1976, well 16/07a-9 was drilled in 1977 between Central Brae and North Brae, as an appraisal of the 16/07-3 discovery (Fig. 1). This well encountered an Upper Jurassic sequence dominated by mudstone and was plugged and abandoned without testing. In 1980, well 16/07a-15 was drilled to the south of well 16/07-3 with similar results to well 16/07a-9. Three successful Central Brae appraisal wells, 16/07a-22, 27 and 29 were then drilled between 1983 and 1985. Well 16/07a-29 was drilled as a deviated well from the 16/07a-27 location, and it was over these wellheads that the sub-sea template was placed in April 1989; both of these wells are now utilized for production. A total of ten subsequent development wells have been drilled up to May 1999, comprising four wells drilled for injection support and seven production wells. Eight of these wells were drilled through the template but with modern drilling technology it has been possible to drill the last two wells from the Brae 'A' (South Brae) and Brae 'B' (North Brae) platforms. These extended reach, high angle wells (c. 22 300 ft roD, 60 degrees) are of a cost comparable to drilling from a semi-submersible, yet provide a better scope for future well intervention programmes and can access any part of the Central Brae reservoir.
Marathon Oil UK, Limited operates the Licence on behalf of Brae Group co-venturers: BP Exploration Operating Company Limited, International Limited, British-Borneo U K Limited, Burlington Resources (UK) Inc., Kerr-McGee Oil (UK) PLC, Lundin Oil and Gas Limited and Talisman Energy (UK) Limited.
Field stratigraphy The general geological history of Block 16/07a is described by Fletcher (2003) and the stratigraphy of the Central Brae Field is shown in Figure 2 with reference to well 16/07a-C7. The Upper Jurassic Brae Formation forms the reservoir, which is overlain by, and in a regional sense interdigitates with, the Kimmeridge Clay Formation (Turner et al. 1987). The Central Brae reservoir is a discrete submarine fan sequence, the bulk of which is Kimmeridgian to early Volgian in age. This fan system is separate from the South Brae and North Brae submarine fans, where deposition continued after the cessation of deposition on the Central Brae fan (Fig. 3). Basin margin slope sediments that separate the three fields were penetrated with appraisal wells 16/07a-9 and 16/07a- 15.
Geophysics Seismic surveys A 1998 3D seismic survey covering Central and South Brae is the current survey upon which interpretations are based. For a history of other surveys acquired and seismic interpretation see Fletcher (2003).
Trap Central Brae is a structural/stratigraphic trap formed by a combination of folding at the western margin of the South Viking Graben, lateral stratigraphic pinch-out of reservoir quality rocks and abutment against impermeable rocks of the Fladen Ground Spur. The western margin of the field is interpreted to abut onto an eastward-dipping eroded fault scarp (the western boundary fault) which forms part of the underlying fault terrace of older Devonian rocks. In a simplified form this gives rise to a ramp-flat type geometry (Figs 4 and 5). It was this feature which was important in the formation of the overall anticlinal structure; firstly to amplify a hanging wall rollover anticline formed during extension, and secondly as a focus for compressional forces during inversion post
GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 183-190.
183
184
K. J. FLETCHER
Fig. 1. Location of the Central Brae Field.
deposition of the Central Brae reservoir sequence. The anticline was therefore tightened further and numerous reverse faults with N - S strikes, parallel to the inversion structure, were formed. The eastern margin of the field is defined by an oil-water contact at 13426ft TVDss (Fig. 6). The northern and southern margins of the field are formed by the stratigraphic pinch-out of the reservoir sandstone and conglomerate into the siltstone and mudstone sequence encountered in wells 16/07a-9 and l 5. The reservoir vertical seal is the overlying Kimmeridge Clay Formation.
Reservoir The Central Brae submarine fan is thought to have been a relatively small, steep cone of sediment radiating basinwards from a sediment entry area on the faulted margin of the Fladen Ground Spur. The
actual point of entry is not clearly imaged on seismic data, although from well control it lies directly west of well 16/07a-22. This is in part due to the presence of the Fladen Ground Spur high (Fig. 5) restricting the size of the Central Brae catchment area, which is in marked contrast to the large sediment source areas of South and North Brae. The Central Brae Member contains six lithofacies: (1) sandmatrix conglomerate; (2) mud-matrix breccia; (3) medium to thickbedded sandstone; (4) alternating thin-bedded sandstone with interlaminated sandstone-mudstone; (5) interlaminated thin-bedded sandstone-mudstone; and (6) laminated mudstone. These facies are similar to those described in detail for the South Brae Field by Turner et al. (1987). Sand-matrix conglomerate and medium to thick-bedded sandstone are the most common Central Brae reservoir facies. These were deposited in the proximal and central parts of a submarine
CENTRAL BRAE FIELD
185
Fig. 2. Brae formation stratigraphic terminology & example correlation.
fan system by high-density debris flows and high-density turbidite currents. Unlike the South Brae and North Brae submarine fans, no obvious channelways of coarse clastic sediments were recognized during early field development. However, with more wells, production information and modern seismic data it is apparent that broadly E - W channelization occurs. Therefore the current Central Brae depositional model is more akin to the channels of South Brae, as opposed to sheet-like deposition, and results in a far higher degree of areal heterogeneity in the reservoir than was initially thought (Fig. 7). There is also a rapid change (within 1 kin) from predominantly conglomerate (e.g. wells 16/07a-3 and 22) to predominantly sandstone facies (e.g. well 16/07a-23) in a down-dip sense, as can be
seen in Figure 2. This probably reflects a marked change in depositional slope and also illustrates the more restricted nature of the Central Brae fan system when compared with the South Brae fan, which deposited conglomerates up to 4 km and sandstones up to 20 km from the entry point. The extent of the deeper Central Brae sands are also affected by the Miller fan, which prevented progradation of the Central Brae fan and resulted in a zone of interdigitation and mixing of the fan systems roughly 4 km into the basin. In the marginal and distal parts of the fan, the finer grained, and more thinly bedded sediments become the dominant lithology interspersed with units of mud-matrix breccia close to the graben margin fault. The reservoir facies are completely replaced by the
Fig. 3. Comparative upper Jurassic stratigraphy in Central, South & North Brae. From Turner & Allen (1991).
Fig. 4. Structural cross-section through Central Brae.
CENTRAL BRAE FIELD
187
Fig. 5. 3D seismic line through Central Brae.
finer grained sediments in the inter-fan sequences drilled in wells 16/07a-9 and 15. Core porosities range up to 12% in conglomerate and 18% in thick-bedded sandstone, and air horizontal permeabilities range up to 100 mD and 1000roD, respectively. Porosity generally decreases with depth and there is a significant division of the reservoir into two broad units. The upper unit has a greater sandstone/conglomerate ratio and is therefore less affected by pervasive calcite cementation, which tends to be concentrated in the conglomeratic facies. The nature of the calcite cementation is not easy to explain, although early calcite cementation was probably caused by fluids being expelled from the basin at the graben margin (McLaughlin 1992). Secondary porosity development due to dissolution of early calcite cement occurred preferentially in the sandstones and therefore the upper unit is by far the most important in terms of oil recovery (90% of current oil production).
Correlation within the reservoir Correlatable units within the Central Brae reservoir are difficult to recognize. However, with the drilling of more development wells it is evident that there is a greater degree of stratification within the reservoir than was previously identified. The techniques used for correlation are similar to those utilized for the South Brae Field (Fletcher 2003), although there are some differences outlined below.
Litho- and biostratigraphy Wireline log character is distinctive within the Kimmeridge Clay Formation, at top reservoir level and for identification of the intrareservoir claystone unit separating upper from lower reservoir units. Any finer reservoir scale correlation, based purely upon log character, is open to interpretation as a result of debris flow conglomerate/sandstones appearing the same, even when deposited by different flow events.
Despite a marked thickness change of the Kimmeridge Clay Formation from the east flank of the field to the crest (e.g. 1030 ft in well 16/07a-29, and 300 ft in well 16/07-3), correlations based on log character and detailed palynology (Riley et al. 1989) indicate that the lowest part of this formation is essentially the same age across almost the entire fan. Therefore, the upper part of the underlying reservoir is also considered the same age (early Volgian, JBI0 zone of Riley et al. 1989) across most of the field. There are localized developments of younger sandstones (earliest middle Volgian, JB8 age) representing the final phase of submarine fan deposition, particularly along the field margins. The biostratigraphy can provide a broad indication of age within the reservoir but is of limited use for detailed correlations.
Reservoir engineering The water breakthrough and pressure data through time is one of the most useful tools for correlation and has been integrated into the most recent correlation scheme. Pressure plots through time are used for the individual reservoir layers, although there are fewer data points available than for South Brae as a result of mechanical failure of sub-sea pressure gauges and limited access to the sub-sea template wells. Formation pressure tests show well defined layering in the distal wells, where sandstone bodies are separated by claystones (Fig. 2), but less distinct pressure barriers in proximal areas of the field where stacked conglomerate/sandstone sequences exist. Water breakthrough data shows that there is poor communication in a N-S direction, perpendicular to the channel trend. Using the above techniques and integrating them with seismic information has allowed six reservoir zones to be correlated across the field. In a basinwide sense the uppermost layers are restricted in areal extent, whereas the lower layers interdigitate and are in fluid communication with Miller sandstones. This is supported by the fact that prior to any Central Brae Field production some reservoir layers had suffered depletion via production from the South Brae Field.
188
K . J . FLETCHER
Fig. 6. Base Cretaceous time structure map & Central Brae Field outline.
Source The Kimmeridge Clay Formation is the source rock for the oil accumulations in the Brae area (Cornford 1984; MacKenzie et al. 1987). Compositional analyses of Central Brae hydrocarbons indicate only a very short migration path, suggesting that the oil was generated on the flanks of the structure or in the immediate surrounding area. Hydrocarbon generation and migration from Kimmeridge Clay interdigitated with the Brae member has occurred since the Late Cretaceous.
Hydrocarbons The maximum individual DST flow rate from the Central Brae wells was 5572 BOPD on a one-inch choke from well 16/07-3. The oil composition is relatively uniform, and has an API gravity of approximately 33 ~ Associated gas has a CO2 content of 25-30%
and an H2S content of about 25 ppm. Other hydrocarbon and water properties are shown on the field data summary.
Reserves Central Brae contains 244 M M B B L s STOOIP with an estimated 65-75 M M B B L s of recoverable oil and NGL. As of May 1999, cumulative oil and N G L production was 44 MMBBLs. There is aquifer support in the lower reservoir layers and in addition to this water injection has provided pressure support since 1991 from two wells. The potential exists to use Water Alternating Gas tertiary recovery to access residual and unswept oil, a project that has been successful on South Brae. Current field potential is 11000 BOPD, having come off plateau in 1992 when maximum rates were 20 530 BOPD (Fig. 8). This paper is published with permission of Marathon Oil UK, Ltd., the Operator of Central Brae, and Participants, BP Exploration Operating
CENTRAL BRAE FIELD Gross thickness (average; range) Conglomerate + sandstone/shale ratio (average) Net/gross ratio (average) Cut-off porosity for net pay Porosity (average) Hydrocarbon saturation Permeability (average; range)
189 800 ft; 0-1676 ft 0.7 0.6 8% sandstones 3% conglomerates 11.5% 80% 100mD; 1-1000 mD
Hydrocarbons
Fluid type Oil gravity Bubble point Gas/oil ratio Formation volume factor
Black oil 33 ~ API 4112 psia 1415 SCF/STB 1.77 RB/STB
Formation water
Salinity Resistivity
79 000 ppm NaC1 equivalent 0.098 ohm m at 60~
Reservoir conditions
Fig. 7. Channelization of a single reservoir zone.
Company Limited, International Limited, British-Borneo UK Limited, Burlington Resources (UK) Inc, Kerr-McGee Oil (UK) PLC, Lundin Oil and Gas Limited and Talisman Energy (UK) Limited. I would like to acknowledge the many people who have contributed to the understanding of the Brae area and in particular the Central Brae Field over the many years of production and exploration.
Central Brae Field data summary
Temperature Pressure Pressure gradient in reservoir
246~ at 12 600 ft TVDss 7057 psia at 12 600 ft TVDss 0.327 psi/ft
Field size
Area Gross rock volume Hydrocarbon pore volume Recovery factor Primary recovery method Secondary recovery method Recoverable hydrocarbons
1800 Acres 675 000 ac. ft 37 250 ac. ft 20% Waterdrive Water injection Oil & NGL: 65-75 MMBBLs
Production Trap
Type Depth to crest Lowest cosing contour Hydrocarbon-water contact Oil column
Structural/stratigraphic 11 750 ft TVDss 12000 ft TVDss 13 426 ft TVDss 1676 ft
Pay zone
Formation Age
Brae Late Jurassic (Kimmeridgian-Early Volgian)
Fig. 8. Central Brae production profile through time.
Start-up date Development scheme Production rate (May 1999) Cumulative production to May 1999 Number/type of wells
September 1989 Sub-sea template and pipeline to Brae 'A' 7500 BOPD 44 MMBBLs 1 exploration 5 appraisal 10 development (to May 1999)
190
K.J. FLETCHER
References CORNFORD, C. 1984. Source rocks and hydrocarbons of the North Sea. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford, 171-209. FLETCHER, K. J. 2003. The South Brae Field, Blocks 16/07a & 16/07b, UK North Sea. In: GLUYAS, J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 211-221. MACKENZIE, A. S., PRICE, I., LEYTHAEUSER,D., MULLER, P., RADKE, M. & SCHAEFER,R. G. 1987. The expulsion of petroleum from Kimmeridge Clay source-rocks in the area of the Brae Oilfield, UK continental shelf. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 865-877.
MCLAUGHLIN, O. M. 1992. Isotopic and textural evidence for diagenetic fluid mixing in the South Brae oil .field, North Sea. PhD thesis, Glasgow University. RILEY, L. A., ROBERTS, M. J. & CONNELL,E. R. 1989. The application of palynology in the interpretation of Brae Formation stratigraphy and reservoir geology in the South Brae Field area, British North Sea. In: COLLINSON, J. D. (ed.) Correlation in Hydrocarbon Exploration. Graham & Trotman, London, 339-356. TURNER, C. C. & ALLEN, P. J. 1991. The Central Brae Field, Block 16/7a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields', 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 49-54. TURNER, C. C., COHEN, J. M., CONNELL, E. R. & COOPER, D. M. 1987. A depositional model for the South Brae oilfield. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 853-864.
The East Brae Field, Blocks 16[03a, 16]03b, UK North Sea STEPHEN
R. F. BRANTER
Marathon Oil U K Ltd., Marathon House, Rubislaw Hill, Anderson Drive, Aberdeen AB15 6FZ, U K Present address: Shell U K Exploration, 1 Alten Farm Road, Nigg, Aberdeen A B 1 2 3 F Y
Abstract: The East Brae gas condensate field is the most northern of the four Upper Jurassic fields operated by Marathon Oil
U K Limited in the U K North Sea. The field lies at the western margin of the South Viking Graben in U K Blocks 16/03a and 16/03b. The field was discovered in 1980 and commenced production in December 1993 from the East Brae platform. Recoverable reserves are estimated as 242 MMBBL of condensate and 1530 BSCF of sales gas. The reservoir is composed predominantly of medium grained sandstones which were deposited by turbidity currents. The East Brae reservoir sequence is currently interpreted to be the basin floor lateral equivalent of the North Brae feeder system to the southwest. The structure is a faulted anticline developed during the latest Jurassic and early Cretaceous in response to regional compression. The reservoir is enclosed by the Kimmeridge Clay Formation, which also interdigitates with the coarser facies basinwards, and provides the source of the hydrocarbons.
Fig. 1. Location of the East Brae Field in the South Viking Graben.
GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 191 197.
191
192
S . R . F . BRANTER
The East Brae Field is located in Quadrant 16, some 265km NE of Aberdeen, in the UK Sector of the Northern North Sea (Fig. 1). East Brae was discovered in 1980 by well 16/03a-1 which encountered gas condensate in the Upper Jurassic Brae sandstones. Production commenced in December 1993 through the East Brae platform. Like the North Brae Field, East Brae is being developed
by gas recycling. The North Brae and East Brae reservoirs are interpreted to be part of the same sub-sea fan: North Brae is a proximal, conglomeratic deposit and East Brae is the sandy basin floor equivalent (Brehm 2003). The sediments were deposited from a high density turbidity current.
Fig. 2. Generalized East Brae stratigraphic log & reservoir stratigraphy (Well 16/03a-1).
EAST BRAE FIELD
History The East Brae discovery well, 16/03a-1, was drilled and completed by Marathon Oil UK Limited in 1980, on the crest of a broad anticlinal structure located on the western margin of the South Viking Graben. The well encountered a gross hydrocarbon column of 650 ft and was tested at a maximum flow rate of 3817 BOPD and 29.3 MMSCFD. Five appraisal wells, 16/03a-2, 16/03b-3, 16/03b-5, 16/03b-7 and 16/03b-9 were then drilled between 1982 and 1986 (Fig. 1). All five wells encountered a similar gross package to that seen in well 16/03a-1 (Fig. 2). The fieldwide hydrocarbon water contact is at 13 735 ft TVDss. Well 16/03b-9 drilled on the northern flank of the East Brae structure, penetrated 660 ft of the East Brae sand succession, but was water-bearing. This well was abandoned in February 1986 as a dry hole (Leishman 1994). In common with the other Brae Fields in the hanging wall of the South Viking Graben, the East Brae Field is operated by Marathon Oil UK Ltd., on behalf of BP Exploration Operating Company Limited, Talisman Energy (UK) Limited, Kerr-McGee Oil (UK) PLC, BG International Limited, Burlington Resources (UK) Inc., Lundin Oil and Gas Limited and British-Borneo UK Limited.
193
produced above the eastern edge of the erosional scarp. In map form the inversion anticline is an irregularly shaped dome (Coward 1996). The western side of the dome is relatively smooth and grades into a N E - S W trending syncline. The eastern side of the dome is highly irregular with east and SE trending arms (Fig. 3). Several episodes of inversion during the Cretaceous and Tertiary can be seen from the truncations, onlaps and growth sequences (Fig. 4 demonstrates the onlap of the Valhall Formation onto the crest of the East Brae structure). The earliest uplift occurred during the Late Jurassic with thinning of the Upper Brae sandstones and Kimmeridge Clay across the crest of the East Brae structure being attributed to the first stages of uplift. This early inversion was followed by other pulses throughout the Cretaceous and Tertiary. The East Brae trap is entirely structural, with a four-way dip closure being mapped. A spill point, controlling the hydrocarbon water contact at -13,735 ft TVDss is observed to the south (Fig. 3). The reservoir is sealed by the overlying Kimmeridge Clay Formation. The field is divided into three panels, by Faults X and Y which have an E S E - W N W trend. Further segmentation along the same trend occurs by smaller, extensional faults. Well-to-well thickness comparisons and seismic interpretation indicate that many of the faults were syndepositional. The faults are baffles to flow and compartmentalize the field.
Structure The Brae Province of the South Viking Graben can be divided into several sub-basins, separated by transfer faults. The East Brae Field lies within the East Brae sub-basin. The East Brae structure was formed by basin inversion. This was associated with backrotation of the faults, causing basinward dip of the post-rift sediments above the erosional scarp. A hanging wall anticline was
Fig. 3. East Brae top reservoir structure map, showing the East Brae Field outline.
Field stratigraphy The stratigraphy of the East Brae Field is shown in Figure 2 using well 16/03a- 1 as a reference. The East Brae reservoir consists of thick, massive and amalgamated beds of predominantly medium grained sandstones of the Upper Jurassic Brae Formation. The Brae
194
S.R.F.
BRANTER
r
.,..a O
g o
t~
EAST BRAE FIELD Formation is a coarse clastic member inserted into the basinal mudstones of the Kimmeridge Clay Formation by turbidity currents (Leishman 1994). As such, the Brae Formation is both overlain and underlain by the Kimmeridge Clay Formation (Turner et al. 1987) which acts as seal and source rock. The reservoir rocks are Kimmeridgian to Mid-Late Volgian in age, and coeval with the North Brae reservoir. Based on palaeomagnetic fabric, basin bathymetry, net to gross and thickness trends, the main sand source direction is interpreted to be from the North Brae system to the southwest. This interpretation is supported by the fact that both fields share a common aquifer and are in pressure communication. The East Brae succession is broadly subdivided into an Upper and Lower Unit which are separated by a 40-60 ft thick shale (the D1 shale). The reservoir is further subdivided into seven layers (Layers A-E) as illustrated in Figure 2. These correlations are based on palynological analysis (Riley et al. 1989), log character and pressure data.
Geophysics S e i s m i c surveys
Several 2D seismic surveys were acquired over the East Brae area in the period 1980-1985. In 1990, a 3D seismic survey covering an area of 212 km 2 containing 6600 km of sail-line data was acquired with a line spacing of 75 m. The objective of the 3D survey was to allow more detailed and accurate structural and stratigraphic interpretation of the reservoir. This 3D survey was reprocessed in 1998 in an attempt to suppress multiple energy and so improve seismic resolution and reflector continuity in the Upper and Middle Jurassic sections.
S e i s m i c interpretation
The East Brae 3D seismic survey is a significant improvement on the 2D surveys from the early 1980s and has increased confidence in
Fig. 5. Schematic cross-section through the East Brae Field.
195
the seismic interpretation. The data quality is good down to the Base Cretaceous reflector (Top Kimmeridge Clay). Below this strong reflector the seismic data quality decreases and it is not possible to interpret a reliable top reservoir event. The top reservoir is defined by adding a geologically derived isochore of the Kimmeridge Clay Formation to the geophysically-derived Base Cretaceous depth map (Fig. 4). In the reservoir, seismic data quality is at best moderate, but several horizons can be correlated across the field with varying degrees of confidence.
Reservoir The East Brae reservoir sandstones were deposited during the Early to gate-Volgian by high-density turbidites sourced from the uplifted Fladen Ground Spur. The sediment transport direction has proved enigmatic at East Brae, but is currently believed to be from the southwest via the North Brae feeder system. The East Brae reservoir contains four lithotypes, as defined by Aggett 1997: (1) High-density turbidite sandstones; (2) Low-density turbidite sandstones; (3) Remobilized deposits; and (4) 'Background' hemipelagic deposits. Note that no conglomerates are present at East Brae, unlike North Brae (Brehm 2003). The lower reservoir consists of three units (Figs 5 and 6). The E Sand (Early Volgian) is characterized by massive to thin bedded sands. The E Shale forms the upper boundary to the E Sand and varies in thickness, from 50 ft in the west of the field to less than 10 ft in the east. The overlying D2 Sand (Mid-Volgian) consists of massive to interlaminated sandstones with mudstone. Average porosities are slightly higher than the E Sands, at 15%. The lower reservoir is widespread across the field and was deposited rapidly, controlled by a period of high rates of subsidence and sediment input (Kessler 1996). The D1 Shale (Mid-Volgian) represents a major flooding event in the graben, and is persistent across the field. In reservoir terms, the D1 Shale is important because it is seen to act as a fieldwide barrier both from pressure profiles and production history. The upper reservoir is also subdivided into three units (Figs 5 and 6), the A, B and C Sands (Mid-Late Volgian), which
196
S . R . F . BRANTER
Fig. 6. Well correlation lu
west to east through East Brae. Illustrates the stacked nature of the sands and the confined nature of the upper reservoir sands on the western and eastern margins.
appear more confined than the underlying lower reservoir, with a western and eastern sand limit defined by the wells (Fig. 6). This characterizes a N N E - S S W trend of high-energy, amalgamated channel complexes. Palynology indicates that the upper reservoir units were deposited over a longer period (4.5-6 Ma), when subsidence rates were slower, but sediment input was still high (Kessler 1996). The A, B, C, D2 and E Sands are all hydrocarbon bearing and under production at East Brae. The East Brae reservoir comprises typically good to excellent quality sandstones in thick amalgamated packages separated by thinner shales. The core porosities in the massive sandstones range up to 28% and horizontal permeabilities range up to 8490 mD. The arithmetic mean porosity is 17% and horizontal air permeability averages 558 m D for the massive sandstones. A depositional control on reservoir quality can be defined, principally related to grain size and detrital clay content. However, quartz cementation has a major impact on reservoir quality, and is seen to overprint the depositional fabric. A high degree of quartz cementation related to styolitization is also present, particularly in the northwest part of the field. Reservoir quality is also affected by minor amounts of kaolinite/illite, calcite cementation and tar mats (Aggett 1997). Calcite stringers and tarmats may act as baffles to flow, in conjunction with partially sealing faults.
Source The Kimmeridge Clay Formation is the source rock for the hydrocarbon accumulations in the Brae area (Cornford 1984). Compositional analyses of black oil from the South and Central Brae Fields indicates a very short migration path, suggesting that the oil was generated on the flanks of the structure or in the immediate surrounding area. The gas condensate of the East Brae and North Brae Fields, is likely to have had a longer migration pathway (Reitsema 1983). It is possible that gas generated from the Kimmeridge Clay Formation in deeper parts of the graben to the
east could have migrated through the fan sequence into the East and North Brae structures (Stephenson 1991). Maturity modelling indicates that the onset of oil generation (R0 > 0.5) began during the Danian, with the onset of oil generation of light oil (R0 > 1.0) by the end of the Neogene.
Hydrocarbons The hydrocarbon is a retrograde gas condensate which exhibits compositional variation with depth. The fluid becomes richer with depth grading into a volatile oil at the base of the column. The gas/ oil ratio varies between 9000 SCF/STB at the crest of the structure and 2500 SCF/STB near the hydrocarbon water contact, and the dew point varies similarly between 6330-7356psia. The original pressure was 7456psia at the hydrocarbon-water contact. The formation water has a specific gravity of 1.038-1.05l at 60~ a pH of 6.92-7.19, a salinity of 45 000-72 000 ppm NaC1 equivalent and total dissolved solids content of 55 380-74 760 ppm.
Reserves and production In common with the North Brae Field, the East Brae Field is being developed by the application of gas recycling to enhance recovery. This involves the re-injection of the produced dry gas from North and East Brae, in order to maintain reservoir pressure and to sweep the wet gas to the production wells (Brehm 2003). The estimated recoverable reserves are 242 M M B B L s of condensate and 1530 BSCF of sales gas. Production well rates range from 10 to 150MMSCFD of wet gas. Peak production of sour dry gas was 680 M M S C F and peak oil production was 115 331 BOPD in 1994. In 1998, average production rates were 658 M M S C F D of sour dry gas, 38 979 BPD of condensate and 13 097 BPD of water. (Water production is primarily from coning.) Gas injection rates averaged 547 M M S C F D of sour dry gas in 1998.
EAST BRAE FIELD This paper is published by permission of Marathon Oil UK Ltd., the Operator of Blocks 16/03a and 16/03b, and the Brae Group participants, BP Exploration Operating Company Limited, Talisman Energy (UK) Limited, Kerr-McGee Oil (UK) PLC, BG International Limited, Burlington Resources (UK) Inc., Lundin Oil and Gas Limited and British-Borneo Oil UK Limited. Thanks are due to Marathon personnel whose work contributed to the contents of this paper, in particular Jeff Brehm. Thanks also to John Cowie, Mark Stephenson, Charles R. Speh and Paul Lovatt-Smith for their suggested improvements on earlier versions of the manuscript.
Production Start-up date Production rate plateau oil Production rate plateau gas Number/type of wells
East Brae Field data summary Trap Type Depth to crest Lowest closing contour Hydrocarbon Water contact Gas column Pay zone Formation Brae Age
Gross thickness Net gross average Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index Petroleum Fluid type Oil gravity Gas gravity Viscosity Dew point Gas/oil ratio Condensate yield
Formation volume factor
Oil initially in-place Wet gas initially in-place Recovery factor: Gas Drive mechanism Recoverable gas (Dry sour) Recoverable NGL/condensate
Four-way dip closure 12 680 ft TVDss 13 735 ft TVDss 13 735 ft TVDss 1055 ft
197 447 MMSTB 2303 BCF 80% Gas recycle 1530 BSCF sales gas 242 MMBBLs (Condensate)/ 19 MMBBLsNGL
December 1993 115331 BOPD 750 MMSCF wet gas 1 exploration well 5 appraisal wells 26 development wells
References Late Jurassic (KimmeridgianLate Mid-Volgian) 1055 ft 0.85 17% (3.4-28.7%) 558 mD (0.04-8490 mD) 84% (80-95%) 20-100 MSCFD/psi (wet gas)
Gas condensate 39-49 ~ API 0.85 0.05 0.11 cp 6330-7356 psia 2.5-9.0 MSCF/BBL 250 BBL/MMSCF (Initial production) 1.04 RB/STB (0.6~).72 RB/MSCF Wet Gas)
Formation water Salinity Resistivity
45 000-72 000 NaCI eq. ppm 0.04616 o h m m at 255~
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature
5302 acres 1.32 x 106 acre ft 7456 psia 0.174-0.282 psi/ft 254.7~
AGGETT, J. 1997. Reservoir quality evaluation of the East Brae reservoir. Unpublished Badley Ashton Report 95061. BREHM, J. 2003. The North Brae and Beinn Fields, Block 16/7a, UK North Sea. In: GLUYAS,J. G. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoirs, 20, 199-209. CORNFORD, C. 1984. Source rocks and hydrocarbons of the North Sea. In: GLENN~E, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford, 171-209. COWARD, M. 1996. Forward Modelling of the East Brae Structure. Marathon Internal Report. KESSLER, L. G. 1996. East Brae depositional model and stratigraphic reevaluation. Marathon Internal Report. LEISHMAN, P. M. 1994. Sedimentology, reservoir geometry and reservoir quality of the East Brae Field, UK North Sea. PhD thesis, University of Aberdeen. REITSEMA, R.H. 1983. Geochemistry of North and South Brae areas, North Sea. ln: BROOKS, J. (eds) Petroleum Geochemistry and Exploration of Europe. Geological Society, London, Special Publications, 12, 203-212. RILEY, L. A., ROBERTS, M. J. & CO?WELL, E. R. 1989. The application of palynology in the interpretation of Brae Formation Stratigraphy and reservoir geology. In: Correlation in Hydrocarbon Exploration. Graham & Trotman, London, 339-356. STEPHENSON, M. A. 1991. The North Brae Field, Block 16/7a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 43-48. TURNER, C. C., COHEN, J. M., CONNELL, E. R. & COOPER, D. M. 1987. A depositional model for the South Brae Oilfield. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 853-864.
The North Brae and Beinn Fields, Block 16/7a, UK North Sea J. A . B R E H M
Marathon Petroleum Company ( N o r w a y ) , Bjergstedveien 1, 4007 Stavanger, Norway Abstract: North Brae is located in Block 16/07a, and was discovered in 1975 by Pan Ocean Oil Company. The field was purchased by Marathon Oil Company in 1976 and was delineated in the early 1980s. Production by gas recycling was commenced in 1988. Liquid reserves are estimated at 207 MMBBLs with recoverable dry gas of 800 BCF. The North Brae Field is one of three gas/condensate fields in the Brae fields area of the South Viking Graben in the U K Sector of the North Sea. The reservoir is part of a large turbidite and debris flow, submarine fan system that also encompasses the East Brae and Kingfisher fields to the northeast of North Brae. North Brae is located at the proximal end of this fan system, and channelized massive conglomerates and sandstones characterize its reservoirs. The stratigraphy of the fan system was influenced by highly variable changes in relative sea level that controlled sediment input. Structural activity was also important, such as syn-sedimentary normal faulting related to the subsidence of the South Viking Graben, and structural inversion, in a series of regional compressive episodes commencing in the Late Jurassic and Early Cretaceous.
Fig. 1. Location map for North Brae Field, the Beinn accumulation lies beneath North Brae. North Brae is reservoired in the Brae Formation and Beinn in the Hugin Formation. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 199-209.
199
200
J.A. BREHM
The North Brae Field is located in the NE corner of U K Block 16/07a, on the western margin of the South Viking Graben, 170 miles NE of Aberdeen (Fig. 1). Unlike the South and Central Brae oil fields in the same block, North Brae is predominantly a gas/condensate field, with minor peripheral oil-prone reservoirs. The field has an area of 4700 acres, is shallower and exhibits lower structural relief than the fields to the south. The North Brae field is a complex, faulted anticline. Its reservoir consists of Upper Jurassic submarine-fan conglomerates and sandstones of the Brae Formation, that is interbedded with the Kimmeridge Clay Formation. Depositional heterogeneity and syn- and post-sedimentary structural influences have segmented the North Brae reservoir into several semi-isolated compartments (North Brae and Bracken) which exhibit independent hydrocarbon-water contacts and varying hydrocarbon types (Fig. 2). The field is at the proximal end of a large, structurally influenced, turbidite and debris flow fan system. The main reservoirs in the field were deposited during a period of high sedimentation rates into the South Viking Graben, which began in the Early Volgian and ceased
in the Late Volgian. This corresponds to a period of extensive erosion due to major graben fault activity and uplift of the adjacent Fladen Ground Spur immediately to the west. In the Brae area, eroded sandstones and angular conglomerates entered through at least three entry points immediately to the west of the South, Central and North Brae fields. To the east of these fields, distal equivalents of the fans extended into the basin more than 20 miles to the northeast. Syn- and post-depositional inversion of pre-existing normal faults along the margins of the South Viking Graben caused the formation of North and East Brae. Hydrocarbon filling of these structures began in the Late Cretaceous, when the kerogen-rich Kimmeridge Clay reached thermal maturity. At least two episodes of hydrocarbon generation are thought to have occurred in the Brae area. An initial phase of mainly black oil generation (seen at South and Central Brae) was followed by a second phase of gas generation that displaced oil at North Brae yielding a compostionally stratified gas/condensate system. This paper is an update to that published by Stephenson (1991).
Fig. 2. Detailed location map for the Brae Formation accumulations within North Brae. The southern part of North Brae contains condensate while the Bracken area is light oil. Although both pools have stratigraphic trapping elements the 'oil down to' measurements in Bracken are deeper than the oil water contacts in North Brae.
NORTH BRAE AND BEINN FIELDS
History North Brae was the first of the Brae fields to be discovered by the Pan Ocean group, when the 16/07-1 well was drilled in 1975. The discovery well flowed at a combined rate of over 21 000 BOPD and 100 M M C F G P D (million cubic feet per day) from perforations from 12112 to 12 548 ft, measured depth. Marathon acquired Pan Ocean in 1976, but further delineation drilling in North Brae did not commence until 1980. Four further delineation wells were drilled from 1980 to 1982. The 16/07a-14, 16/07a-17B and 16/07a-19 wells were
201
drilled to the west of the discovery well and confirmed the size and nature of the North Brae reservoir and hydrocarbon accumulation. Well 16/07a-16 drilled to the N N E of the 16/07-1 discovery well, encountered mainly non-reservoir, and it flowed hydrocarbons at very low rates. Two further wells, 16/07-5 and 16/07a-7 were drilled to the west of the North Brae anticline, at the margins of the Viking Graben. The former well encountered low-porosity conglomerates, the latter a thin sandstone reservoir which tested oil and gas. An Annex B for a gas-recycling development system at North Brae was first submitted in 1984. Following approval, a production
Fig. 3. Interpreted depositional system for the Lower Brae reservoir in the area of the North Brae and East Brae fields.
202
J.A. BREHM
platform was set in 1987 in 326ft of water near the 16/07-1 discovery well location, and production commenced in March 1988. To date, 28 development wells have been drilled in the North Brae field area. The field reached a peak production rate of 81 500 BOPD in 1990. The current rate (August 1999) is 9000 BOPD from nine production wells. Four wells are also completed for dry gas reinjection. In November 1988, a deeper reservoir under the northern limb of the North Brae Field was discovered with the 16/07a-30Z exploratory well (Fig. 1). That well encountered >250 ft of pay in the Oxfordian (Jurassic) Hugin formation at a depth of 14400 ft. The find was named the Beinn Field. An Annex B for development was submitted in 1990 and the first Beinn development well was drilled from the North Brae platform and completed in 1992. A total of four development wells have been drilled to the Beinn reservoir. The maximum rate from the Beinn field was 20 000 BOPD. The current production rate (August 1999) from the Beinn Field is 1500 BOPD from two wells. The North Brae platform also receives oil and gas from the Kingfisher and Central Brae fields. Current Kingfisher production is about 20 000 BOPD. Production from the B24 Central Brae well adds about 3500 BOPD to the platform rate. The North Brae field is operated by Marathon on behalf of BP Exploration Operating Co. Ltd, Talisman Energy (UK), Ltd., BG International, Ltd., Kerr-McGee Oil (UK) PLC, Burlington Resources (UK) Inc., Lundin Oil & Gas, Ltd. and British-Borneo (UK), Ltd.
Stratigraphy The North Brae field was initially interpreted to be a series of stacked sub-aerial fan delta sequences, comprised of arcuate sheets of coarse clastics, overlying inclined, finer grained marine sands and foreset shales (Harms et al. 1981). Subsequent delineation and development drilling in the Brae area in the mid-1980s showed that the Brae sediments were in fact deep marine turbidites and debris flow deposits. Further, the submarine fan deposits were found to be more extensive than could be accounted for in early depositional models. The conglomerates and sandstones at North Brae are the proximal part of an extensive submarine fan system. The East Brae field, previously thought to be a separate locally sourced fan, is now interpreted to be at the distal end of the same fan (Fig. 3). The sediment in the North Brae submarine fan system was deposited in two major sediment input 'pulses' at the end of the Jurassic. The sequences, which can be broadly defined as the Upper and Lower Brae reservoirs, occur from J63 to J73 (Partington et al. 1993). Sandwiched between them is a thin, but regionally persistent shaley horizon known locally as the D I shale, which corresponds to J66B. The Upper Reservoir is capped by a variable thickness of Kimmeridge Clay (J73-J76), which forms the overall seal for the reservoir (Fig. 4). The general stratigraphic history, within a regional framework, is interpreted as follows:
Early Lower Brae Reservoir Deposition (J66a, Fig. 3) Thick, locally derived conglomerate slope apron facies had been deposited (pre-J64), more or less continuously, along the western margin of the Viking Graben since the Oxfordian. In the western part of North Brae, immediately east of the interpreted sediment entry point, the J66a sediments are represented by thick, uniform, sand-matrix conglomerate sequences (>600 ft thick) deposited as debris-flows. The Hudlestoni Maximum Flooding Surface (Partington et al. 1993) marks the top of this sequence.
Late Lower Brae Reservoir Deposition (J66a/b) In the early mid-Volgian, an episode of apparent weak regional compression and subsequent structural inversion caused the reversal of pre-existing normal faults in North Brae. Localized
uplift resulted in thinning of the J66a/b reservoir sequences in the western half of the field. Depositional flow paths through the area may have also been affected, as some conglomeratic material appears to have been diverted around the northern flank of the North Brae Field. The regional Fittoni flooding event at the end of this period (J66b) apparently caused sediment input into the North Brae field to pause (Turner & Connell 1991).
D1 Shale Deposition (J66b) (Fig. 5) The D1 Shale horizon, corresponding to the Fittoni flooding surface (Partington, et al. 1993), a mid-Volgian regional transgressive event, largely shut off coarse clastic sediment input into North Brae. However, sedimentation of a thick wedge of mainly silty material, with a low volume of sand seems to have persisted at North Brae throughout this period.
Upper Brae Reservoir Deposition (J71-J73) (Fig. 6) Following the D 1 shale deposition, sedimentation of coarse clastics at North Brae resumed. A channelized sand-matrix conglomerate sequence was deposited from west to east through the field area. This package is thick (>700 ft in places), and is comprised of sand matrix conglomerates and thin sandstones. The conglomerate to sandstone ratio decreases rapidly downstream toward the east side of North Brae. The channel is asymmetric northward, bounded by or influenced by faults along its northern margin. Extensional faulting during the Upper Brae deposition was immediately followed by a second period of apparent structural inversion, beginning J73, which began the process of the formation of the present day structure. This inversion episode also coincided with the cessation of sediment input into the North Brae fan.
Kimmeridge Clay Depostion (J74-J76) A final late Jurassic transgression in the South Viking Graben area drowned the remaining sediment source areas to the west (Rattey & Hayward 1993) and causing the cessation of North Brae fan sedimentation. A uniform clay layer was deposited over the top of the Brae sandstones and conglomerates. The thickness of this layer is variable (from less than 20 to over 200ft in thickness within relatively short distances), due to continued weak syn-sedimentary inversion of the Brae structures at this time.
Structural history Early structural models for the Brae area fields placed them in a purely extensional rift system. The gentle anticlinal folding at the western margin of the Viking Graben was thought to be due to accomodation along the major graben margin fault (Harms et al. 1981). Additional delineation and development drilling, along with improved 3D seismic surveys in the 1980s revealed a more complex structural history. Multiple episodes of weak compression, with local inversion along pre-existing faults, particularly in the Late Jurassic and Early Cretaceous, were documented at nearby fields, and by extension has been incorporated into Brae structural histories. The onset of rifting in the Brae area of the South Viking Graben began in the Triassic, and by the end of the Jurassic, over 5000 ft of sediments had accumulated along its western margin. The depositional environment also changed markedly through this period of active rifting, from fluvial-deltaic deposits in the Lower and Middle Jurassic to the deep-water marine turbidites of the Late Jurassic. Beginning in the mid-Volgian (Jurassic), the region was subjected to several episodes of weak compression that was manifested as inversion structures at the margins of the Viking Graben. These compressional episodes appear to coincide with Alpine-related transpression along the WNW-ESE trending Tornquist Zone
N O R T H BRAE A N D BEINN FIELDS
Fig. 4. Stratigraphy and reservoir correlation for North Brea, Kingfisher and East Brae fields.
203
204
J.A. BREHM
Fig. 5. Interpreted depositional system for the D1 shale horizon that separates the Upper Brae and Lower Brae sandstone reservoirs in North Brae (legend as for Fig. 3).
(Pegrum 1984). Structural inversion and consequent stratigraphic thinning is noted on the basinward side of pre-existing normal faults with a N E - S W orientation. Similar effects of this inversion are also seen to the south in the Tiffany and Toni field areas (Cherry 1993) and at the Sleipner Gamma Gas Field 30 miles SE in the Norwegian sector (Pegrum 1984). The earliest syn-sedimentary inversion episodes occurred during Brae Reservoir deposition. The first and less important is observed within the Lower Brae Reservoir (mid-Volgian) which resulted in localized thinning and diversion of the sands and conglomerates from the southwest side of the North Brae Field. The second and more important episode, from the latest Upper Brae Reservoir deposition into the Lower Cretaceous, resulted in more general lofting of North Brae.
Reservoir geology of the North Brae Field The North Brae field can be subdivided into two major compartments, the Main Channel area and the Bracken area (Fig. 2).
Despite major differences in reservoir thickness and clastic grain size between the two areas, they are age-equivalent, and represent different facies types within the same depositionally related system. The two reservoirs contain hydrocarbons with somewhat different compostions and with different hydrocarbon-water contacts. M a i n c h a n n e l area. The main channel area is volumetrically the larger of the two areas in North Brae, covering the southern twothirds of the field. Hydrocarbons within this part of the field are mainly gas and condensate, although close to the hydrocarbon contact at 12475 ft, the liquid phase becomes a light volatile oil. Two reservoir subunits are recognized: the channelized conglomeratic Upper Brae Reservoir sequence (J71-J73, described above) and the Lower Brae Reservoir sequence (J66a and J66b), which is comprised of sandstone with locally thick conglomerates. The two reservoirs are separated by the regional D1 shale (J66b). Along the axis of the channel, the Upper Brae rests disconformably on the Lower Brae, having scoured and removed the intervening D 1 shale (Fig. 7).
NORTH BRAE AND BEINN FIELDS
205
I f JI .........
y
]
~
~
~ STATUTEMILES ~ ~ .........
Fig. 6. Interpreted depositional system for the Upper Brae sandstone reservoir of the North Brae and East Brae fields (legend as for Fig. 3).
The northern boundary of the Main Channel area is an orthogonal set of normal faults with N W - S E and N E - S W orientations (Fig. 3). These faults had normal movement throughout most of their history, although two periods of weak syn-sedimentary inversion previously described have reversed or laterally offset these fault planes. The effect of the normal fault movement was to create a palaeobathymetric low which accomodated the high-energy con-
glomeratic sequences into a sinuous E - W oriented channel. To the south of the bounding fault, the conglomerates rapidly thin and grade into more interbedded sandstone and shale sequences (Fig. 7). At the southern edge of the field area, both the Upper and Lower Brae sandstone equivalents are predominantly shale and siltstone with only thinly bedded sandstones. Further south at Central Brae, the North Brae reservoir sequence consists entirely of shale.
206
J . A . BREHM
Fig. 7. Sediment stacking and erosion relationships in the fault bounded main channel area of North Brae. The contrast in reservoir development between Bracken and North Brae is clear.
Porosity in the Main Channel reservoir varies from 16 to 22% in clean sandstones (average 17.8%) and between 10 and 15% in conglomerates (average 12.7%). Average permeability is 300mD. The thick conglomerate and sandstone reservoirs in the Main Channel maintain pressure continuity across the field. Liquids are removed from produced fluids, and lean gas is re-injected near the structural crest to maintain reservoir pressure. In the 13 years since the field began producing, lean gas breakthrough from re-injected gas has occurred in most parts of the Main Channel area, and overall liquid yield has declined. Additional reservoir pressure support comes from an active aquifer on the eastern of the field, where rapid water encroachment has been observed. Several production wells on the eastern end of the field have been suspended due to high rates of water production. Sluggish or non-existent water encroachment from the north and south margins of the field provides further evidence of lateral reservoir degradation within a relatively short distance from the main channel axis.
The northern third of the field is unofficially called the Bracken area. While not a separate field, it behaves in a different manner compared to the Main Channel area. Hydrocarbons in this area tend to be light oils with lower gas/oil ratios. The hydrocarbon-water contact is unknown, but oil-down-to determinations from electric logs and pressure data indicate that each of the three reservoir sandstones in the Bracken area maintain separ-
B r a c k e n area.
ate contacts, all of which are deeper than the - 1 2 475 ft contact in the Main Channel area. The Bracken area reservoirs are probably splay deposits, originating from the faulted northern margin of the Main Channel. The principle reservoirs are predominantly sandstone and are much thinner and more interbedded than the age equivalent reservoirs to the south (Fig. 7). This may indicate that sands were deposited as intermittent overbank splays during times of high rates of deposition in the Main Channel. The lowermost Bracken reservoir is conglomeratic, and may represent a diversion of coarser material to the northern side of the field during the early episode of structural inversion described previously. The general shape of the Bracken reservoirs is probably elongate in a N E - S W direction, parallel to but discontinuous with the Main Channel to the south. Lying between the two sediment fairways is a region of thinned, though time-equivalent non-reservoir rocks. This area probably remained bathymetrically shallow throughout most of the Brae Reservoir deposition, probably due to continued halokinetic uplift of the underlying Beinn structure (seismic section, Fig. 8). The area is cut by numerous N E - S W trending normal faults, some of which have probably undergone reversal during periods of inversion mentioned above. Porosity in the Upper Bracken sandstones is in the range of 19-26% (average 21.2%). In the Lower Bracken conglomerates, porosity falls to 12-16% (average 13.7%). Permeability can be as high as 4000 m D in the Upper Bracken sandstones, with an average of 1000 mD.
0 o
~0
o o
~0
o
01)
"0
o
0
.,..~ o
o
e~
..~
208
J.A. BREHM
Oil production from the Bracken accumulation is by primary pressure depletion from two wells, with no artificial pressure support. Because of its excellent reservoir qualities and observed water production, the Bracken appears to have strong aquifer support.
Geophysics Seismic surveys
Several vintages of seismic surveys have been acquired over the North Brae field since its discovery in 1974. Until 1985, when the Brae-Miller 3D survey was acquired, field seismic data was relatively widely spaced 2D data. The most recent survey over North Brae, the 3D Beinn survey was acquired in 1994.
Seismic interpretation
Recent re-interpretations of the 3D Beinn survey have allowed a more accurate determination of the structure at the top of the Kimmeridge Clay formation. When combined with the high density of exploratory and development wells, a more comprehensive reservoir interpretation has been made. While data quality below the Kimmeridge Clay formation is still moderate to poor, clues as to the distribution of sediments with the field can be found in subtle structural details at or above the Kimmeridge Clay, matched to well data and the overall depositional model framework described above.
minor terrestrial plant material. The Kimmeridge is currently sufficiently mature to generate oil. While this may account for the sourcing of the oils in reservoirs in Miller, South and Central Brae Fields, the gas/condensate reservoirs of North and East Brae and Kingfisher Fields may have an entirely different source history. Gas may have been generated from the Kimmeridge Clay in more deeply buried, post-mature parts of the graben, or from deeper source rocks in the Heather or Sleipner formations underlying the condensate fields. The increasing richness with depth of the hydrocatbon columns, seen in both fields, and in the upper reservoirs of Kingfisher may indicate a displacement of an original oil accumulation by later gas generation.
Reserves Prior to production, the N o r t h Brae field contained an estimated 207 million barrels of recoverable liquid hydrocarbons and 1.0 T C F of wet gas. Production of liquid hydrocarbons to date is 155 million barrels.
North Brae Field data summary Trap Type Depth to Crest Hydrocarbon-water contact
Trap The North Brae Field was formed overall by a combination of folding, which provides dip closure on the north, south and east, and reservoir quality degradation and abutment against impermeable Devonian or older rocks of the Fladen Ground Spur on the west. This western limit of North Brae sediments is along a series of N - S trending listric normal faults that define the Viking Graben Margin. At least one fault terrace of Devonian rocks is present to the west of the field, which is overlain by poor quality conglomerates and mud-matrix breccias. Complicating the picture is the presence of multiple internal boundaries in the reservoir, which segment the field into areas with different hydrocarbon-water contacts. The central part of the reservoir, the main conglomerate channel, contains gas and condensate, which has a hydrocarbon-water contact at -12475ft. However, to the north of this channel, in the Bracken area, the composition is somewhat more oil-prone and has multiple, deeper contacts. To the south is an area with a shallower contact, probably perched by lack of effective permeability down-dip. The boundaries that separate these different contact areas are probably large-scale synsedimentary faults that have undergone later inversion. Evidence of restoration and reversal of at least some of the original throw of these faults is seen on seismic in the form of locally pronounced folding at the Kimmeridge Clay level. The Kimmeridge Clay formation, overlying the Brae Formation reservoir sequence provides the vertical trap. The clay is variable in thickness from 55 to over 250ft in thickness, with thicker clay occurring in areas of more rapid reservoir subsidence in main channel areas.
Source The Kimmeridge Clay Formation is the most likely source rock for hydrocarbons in all of the Brae area fields. The high total organic carbon content (up to 15.2%) of this formation results from deposition in the restricted, anoxic environment which characterized the conditions in the Viking Graben in the Upper Jurassic. The organic components of the clay are primarily algal kerogens with
Pay zone Formation Age
Gross thickness Net/gross average Porosity average (range) Permeability average (range) Petroleum saturation (average) Productivity index Petroleum Fluid type Oil gravity Gas gravity Viscosity Dew point Gas/oil ratio Condensate yield
Three-way dip + Fault 11920 ft TVD SS 12475 ft TVD SS (Deeper contacts noted on northern flank)
Brae Late Jurassic (Kimmeridgian-mid-Volgian) Variable 800-1150 ft 0.85 15% (7-23%) 300 mD (0.3-2000 mD) 85% 60 MSCF/psi
Formation volume factor
Gas/condensate 39-50 ~ API 0.85 0.05-0.11 cp 5500-6000 psi 2500-6500 SCF/STB 230 STB/MMSCFG @ 12475 TVD SS 0.00064 RB/SCF
Formation water Salinity Resistivity
77000 ppm NaC1 equivalent 0.12 ohm-m at 60~
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Recovery factor (gas) Drive Mechanism Recoverable gas Recoverable NGL/condensate
4700 acres 1 600 000 Acre-feet 6900psi at 12475TVD SS 0.191 psi/ft 260~ 80% gas recycle 800 BCFG (Dry) 207 MMBL
Production Start-up date Production rate plateau (liquids) Production rate plateau (gas)
March 1988 81500 BOPD 600 MCFG/D
N O R T H BRAE AND BEINN FIELDS Cumulative production (Aug 1999) Total well penetrations
154 MMBL 1 Discovery well 6 Appraisal wells 27 Development wells
References CHERRY, S. T. J. 1993. The Interaction of Structure and Sedimentary Process Controlling Deposition of the Upper Jurassic Brae Formation Conglomerate, Block 16/17, North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 387-400. HARMS, J. C., TACKENBERG, P., PICKLES, E. & POLLOCK, R. E. 1981. The Brae Oilfield Area. In: ILLING, X. & HOBSON, X. (eds) Petroleum Geology" of the Continental Shelf of North-West Europe. Institute of Petroleum, London, 352-357. PART1NGTON, M. A. MITCHENER, B. C., MILTIN, N. J. & FRASER, A. J. 1993. Genetic Sequence Stratigraphy for the North Sea Late Jurassic and
209
Early Cretaceous: Distribution and Prediction of Kimmeridgian Late Ryazanian Reservoirs in the North Sea and Adjacent Areas. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 347-370. PEGRUM, R. M. 1984. Structural Development of the Southwestern Margin of the Russian-Fennoscandian Platform. In: SPENCER, A. M. Er AL. (eds) Petroleum Geology of the North European Margin. Norwegian Petroleum Society, Graham & Trotman, London, 359-369. RATTEY, R. P. • HAYWARD, A. B. 1993. Sequence Stratigraphy of a Failed Rift System: The Middle Jurassic to Early Cretaceous Basin Evolution of the Central and Northern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 215-249. STEPHENSON,M. A. 1991. The North Brae Field, Block 16/7a, UK North Sea. In: ABBOTTS,I. (ed.) United Kingdom Oil and Gas Fields 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 43-48. TURNER, C. C. & CONNELL, E. R. 1991. Stratigraphic Relationships Between Upper Jurassic Submarine Fan Sequences in the Brae Area, UK North Sea." The Implications for Reservoir Distribution. 23rd Annual Offshore Technology Conference, Houston.
The South Brae Field, Blocks 16/07a, 16[07b, UK North Sea KEITH
J. F L E T C H E R
Marathon Oil UK, Ltd., Marathon House, Rubislaw Hill, Anderson Drive, Aberdeen AB15 6FZ, UK Present address: Shell UK Exploration and Production, 1 Altens Farm Road, Nigg, Aberdeen AB12 3 F Y
Abstract: The South Brae Oilfield lies at the western margin of the South Viking Graben, 161 miles NE of Aberdeen. Oil production began in July 1983 from a single platform located in 368 ft of water. The field STOOIP is 795 MMBBLs, and in May 1999, cumulative exports of oil and NGL reached 265 MMBBLs. The reservoir lies at depths in excess of 11 800 ft TVDss, has a maximum gross hydrocarbon column of 1670 ft, and covers an area of approximately 6000 acres. The reservoir consists of Upper Jurassic Brae Formation sandstones and conglomerates deposited as submarine fan complexes that are downfaulted against tight sealing rocks of probable Devonian age at the western margin of the field. The other field margins are constrained by a combination of structural dip and stratigraphic pinchout. The reservoir is capped by, and interdigitates with, organic rich mudstones of the Kimmeridge Clay and Brae Formations. This intimate association of source rock and reservoir facies allows for short migration routes into the reservoir.
Fig. 1. Location of the South Brae Field. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 211-221.
211
212
K. J. FLETCHER
The South Brae Oilfield is located in Blocks 16/07a and 16/07b adjacent to the western margin of the South Viking Graben, 161 miles NE of Aberdeen (Fig. 1). The field is being produced using a single, fixed, steel platform (Brae A) set in 368 ft of water. South Brae is one of the major oilfields of the UK North Sea, covering an area of approximately 6000 acres, having a maximum gross oil column of 1670 ft and containing 795 MMBBLs of oil plus natural gas liquids (NGL). The reservoir sequence is of Upper Jurassic age and comprises thick units of sand-matrix conglomerate and sandstone, alternating with other thick units of mudstone and interbedded sandstone, which are commonly combined into largescale fining upward facies associations. The reservoir system is
Fig. 2. Brae Formation stratigraphic terminology.
interpreted to have been deposited as the proximal part of a complex submarine fan system. The name 'Brae' is defined from the old Scots word meaning hill.
History Production Licence P. 108, covering UK Blocks 16/07 and 16/03 was issued in 1970 as part of the third round of licence awards to Pan Ocean Oil (UK) Ltd. and Syracuse Oils (UK) Ltd. Subsequently, other participants joined in the venture and in 1976, Pan Ocean became a wholly owned subsidiary of Marathon Oil Company. In
SOUTH BRAE FIELD June 1976, a 50% relinquishment of Licence P.108 became effective with Block 16/07a and Block 16/03a constituting the remaining part of the Licence, which was then renewed for 40 years. Marathon Oil UK, Ltd. operates the Licence on behalf of the Brae Group co-venturers: BP Exploration Operating Company Limited, BG Exploration International Limited, British-Borneo UK Limited, Burlington Resources (UK) Inc., Kerr-McGee Oil (UK) PLC, Lundin Oil and Gas Limited and Talisman Energy (UK) Limited. The field discovery well, 16/07a-8 was drilled in 1977 at a location near the crest of an anticlinal structure mapped at Base Cretaceous level on 2D seismic data. The well penetrated a gross hydrocarbon column of 1505 ft and black oil was flowed to surface from five drill-stem tests. Maximum flow rates of 7800 BOPD were achieved. Four additional appraisal wells were drilled in Block 16/07a during 1977 and 1978. An Annex B for field development was submitted in July 1979 and approved by the Department of Energy in January 1980. BP drilled two additional appraisal wells in 1984 on the eastern flank of the field, in Block 16/07b. This portion of Block 16/07b subsequently came under Brae Group ownership in December 1988. Following the installation of the Brae A platform, first oil was delivered in July 1983. South Brae crude oil and NGL is exported from Brae A via a 30 inch diameter pipeline 73 miles to BP's Forties 'C' platform, and then through the Forties pipeline system to Cruden Bay, northeast Scotland. A total of 42 development wells have been drilled into the South Brae reservoir (to May 1999).
Field stratigraphy
213
that in order to obtain such an inversion structure requires a bend or ramp-flat type structure in the footwall that also acts as the focal point for the generation of reverse faults. Two broad fault trends are evident (Fig. 6); firstly an E-W trend of reactivated normal faults which appear to be related to the underlying clastic channels and secondly a N-S trend formed during compression. Thick late Cretaceous and Tertiary sequences were subsequently deposited over a much broader basin extending far beyond the South Viking Graben. The last reactivation of the graben margin faults was during the late Paleocene to early Eocene, which resulted in minor displacement of the lower Tertiary and older sequences.
Geophysics Seismic surveys
Various vintages of 2D seismic data were acquired between 1970 and 1976, and were used to map the structure prior to the drilling of the field discovery well. During 1977 a 3D seismic survey was acquired, and reprocessing of these data in 1983/84 provided the basis for initial development mapping. In 1985 an extensive 3D survey was acquired over Blocks 16/07a, 16/07b, 16/08a, 16/08b and 16/08c in co-operation with the operators of these blocks. As field development and marginal exploitation in the area continues a further 3D survey covering South Brae, Central Brae and the western flank of the Miller Field was acquired in 1998. This is presently undergoing interpretation.
A well illustrating the typical stratigraphy of the Upper Jurassic Brae Formation (Turner et al. 1987) and the overlying Kimmeridge Clay Formation is shown in Figure 2. Palynological study of both formations has led to the establishment of a detailed biostratigraphic zonation scheme (Riley et al. 1989) which allows the major stratigraphic units to be dated and correlated. A general stratigraphic log indicating the lithologies and formations of the postJurassic sequence is shown in Figure 3.
Geological history In the South Brae area of the South Viking Graben the main period of Upper Jurassic rifting along the graben-boundary fault system can be broadly dated as Callovian to Volgian (Turner & Connell 1991; Cockings et al. 1992; Thomas & Coward 1996). Deep seismic data (6.0 seconds two-way-time) beneath South Brae suggests evidence of faulting in horizons that could be Triassic in age. A Middle Jurassic, Bathonian-Bajocian, coal-bearing paralic sequence of uniform thickness overlies these horizons and was deposited under more stable tectonic conditions. It is in the sequence immediately overlying this that a pronounced syntectonic wedge of sediments of Callovian to Volgian age can be seen on seismic to thicken dramatically westward towards the basin bounding fault system (Fig. 4). This is borne out by the Deep South Brae well (16/07a-33), which penetrated sediments of no older than late Oxfordian and clearly indicates the presence of this syntectonic thickening at depth. The South Brae reservoir is located in the uppermost sediments of this wedge and is composed of coarse to fine grained submarine fan sediments. These are overlain by and interdigitate with the organic rich hemipelagic mudstones of the Kimmeridge Clay Formation. Continued extension along the main boundary fault, interspersed with repeated NE-SW compressional events (Cherry 1993; Thomas & Coward 1996), occurs from mid Volgian times onwards. These compressional phases led to the development of the South Brae Field structure; that of an inversion anticline striking N-S and offset from the basin bounding fault by approximately 1 km at Base Cretaceous level (Figs 4 & 5). Differential compaction within the clastic sequence will also have played a role in developing the mounded structure. Modelling studies (McClay 1995) suggest
Fig. 3. Generalized South Brae Stratigraphic Log. From Roberts (1991).
214
K.J.
FLETCHER
9
o
r.~
.a
SOUTH BRAE FIELD
215
Fig. 5. 3D seismic line through South Brae.
S e i s m i c interpretation
The Top Kimmeridge Clay Formation (Base Cretaceous) reflector is clearly seen on all vintages of data, and can be unequivocally identified across most of the field. However, this reflector is a strong multiple generator, and on the older seismic data multiple energy largely masked or interfered with internal events within the Upper Jurassic. For the latest 3D seismic data, careful selection of stacking velocities and deconvolution operators has attenuated multiples to a large degree. The 1998 3D data have allowed more accurate mapping of the Base Cretaceous, particularly in the structurally complex areas near the western margin of the South Viking Graben. Fault definition has been improved, particularly from top reservoir through the Lower Cretaceous and this has been crucial in developing the new structural model. The basin bounding fault zone has also been imaged much more clearly, thus aiding the mapping of the basement. Seismic definition and analysis at reservoir scale looks possible compared to that previously achieved and will hopefully aid in channel delineation.
Trap The South Brae trap was formed by a combination of faulting, folding, and lateral stratigraphic changes. The maximum oil column is 1670 ft in height, of which structural closure on the Top Brae Formation accounts for roughly 300 ft. The main trapping element, the major western fault zone, marking the edge of the Fladen Ground Spur, where Brae Formation clastic rocks abut impermeable Devonian sandstones. South Brae is therefore a classic example of a hanging wall fault closure trap. South Brae comprises two main structural areas. The major part of the field is a N-S trending anticline with a gentle easterly dip and an associated syncline to the west that is more steeply dipping and faulted (Figs 4 & 5). To the north of the major structure, a low
relief compactional saddle separates a smaller submarine fan feature known as the 'Northern Lobe' (Fig. 1). Coarse clastic sediments within this feature, delineated by Well 16/07a-6 prior to development, are interpreted to be the product of a separate fan entry point. The lobe shares the same original oil-water contact with the main part of the field, reservoir communication being permitted through laterally overlapping coarse clastic sequences. To the south of the main field and north of the northern lobe, the South Brae reservoir passes laterally into non-reservoir fine grained, laminated mudstone and fault scarp breccia sequences. In the east, the field is in part bounded by original oil-water contact at 13 488 ft TVDss and in part by reservoir pinchout. The overlying Kimmeridge Clay Formation provides an effective vertical seal.
Reservoir The South Brae reservoir is the proximal part of a vertically stacked complex of submarine fan systems, which is the product of erosion of Devonian sandstones and probably also younger Palaeozoic and Mesozoic sediments of the adjacent Fladen Ground Spur. In order to analyse the varied lithologies making up the Brae Formation, at South Brae alone, over 24 000 ft of core have been described and interpreted. From this extensive database, six major lithofacies are recognised, based on lithology and internal sedimentary structures, as follows: (1) sand-matrix conglomerate; (2) mud-matrix breccia; (3) medium to thick-bedded sandstone; (4) alternating thin-bedded sandstone with interlaminated sandstone-mudstone; (5) interlaminated sandstone/mudstone; and (6) laminated mudstone. These lithofacies and their depositional processes were described in detail by Turner et al. (1987). The conglomerate and sandstone facies are the product of various types of sediment gravity flows. The presence of variable but generally small components of comminuted marine fossil debris in the coarse clastic facies and the character of the palynological assemblages within the associated mudstones (Riley et al. 1989) demonstrates that the sediment gravity flow
216
K. J. FLETCHER
Fig. 6. Base Cretaceous time structure map & South Brae Field outline. processes were operating in an entirely submarine setting. Mudstones within the sequence are the product of both hemipelagic settling of silt and clay-grade material and turbidite deposition. There is a degree of vertical organization of facies within the South Brae reservoir. Large-scale upward-fining sequences can be recognized (Fig. 7), which are of the order of tens to hundreds of feet in thickness. The bases of these sequences are commonly erosional and sharply defined, while the overall upward fining results from interbedding and replacement of coarser facies by finer facies. The upward repetition of such sequences gives the reservoir a welldeveloped vertical succession of coarse grained packages (Facies 1 and 3) and finer-grained packages (Facies 4, 5 and 6), as shown in Figure 8. In three dimensions, particularly in the 'upper' Brae Formation the coarse grained packages often occur as channel-like bodies which radiate basinwards from an apex to the west of the field, and which are separated by fine-grained interchannel sediments. An example of a simplified facies distribution for a single reservoir layer is shown in Figure 9. The channel-like bodies become less conglomeratic and sandier basinwards, passing into the lobe sequences of what is the Miller Field (Garland 1993). To the northwest and southwest of the fan system and in close proximity to the graben margin fault zone the dominant facies are mud-matrix breccia and mudstone of the basin margin slope facies association.
Fig. 7. Example of the most common South Brae facies associations. From Roberts (1991).
SOUTH BRAE FIELD
217
,--:, t'--
..= .~
o
O
d ,..a 9
9 ,s= 9
Z
218
K. J. FLETCHER
Fig. 9. Facies distribution map for an upper reservoir layer in South Brae.
Regional studies have established a large catchment area to the west for South Brae sediments and confirmed the location of the entry point ( W - N W of well 16/07a-8). Sediments were funnelled into this around a N-S trending basement high on the Fladen Ground Spur, which has been imaged far better on the modern seismic data (Fig. 5 and Central Brae Field, Fletcher 2003, fig. 5). The actual fan entry point appears to be fairly restricted (<500m wide) and is not visible on seismic data. This is in marked contrast to the incised source of the North Brae Field (Brehm 2003). Subsequent transgression into the embayment during the Volgian appears to have caused abandonment of the South Brae fan system. Diagenetic processes have served both to reduce and subsequently enhance porosity within sandstones and conglomerates (McLaughlin 1992). Early carbonate cementation was probably initially extensive, although not pervasive, and in the areas not affected by this process quartz overgrowths are common and sparse illitic rims occur on some quartz grains. Much of the early carbonate cement, together with some shell debris and significant amounts of feldspar were dissolved during an important later stage of secondary porosity development, which preceded oil emplacement. Although not as noticeable as in Central Brae (Fletcher 2003), this late stage dissolution is concentrated in the sandier facies and higher in the reservoir. Therefore the upper reservoir layers are by far the most prolific producers (70% of current production) due to two main factors: the final deposition on the South Brae fan was more sand rich as relative sea levels rose and subsequent diagenetic processes succeeded in enhancing the reservoir quality.
and are used to facilitate correlation, particularly in the absence of core information. However, since the channel sequences are always similar, correlation based on log character alone can be erroneous. In addition to vertical facies variations lateral changes also occur, from coarse to fine-grained facies, in a direction perpendicular to sediment flow. For prediction of flow patterns it is the mapping of these fine grained interchannel areas which forms one of the most crucial aspects of South Brae development geology. An extensive palynological data set from the Brae area has been integrated into a biostratigraphic framework that appears to have regional application within Quadrant 16 (Riley et al. 1989). Nineteen biostratigraphic zones have been identified, which span the Callovian-Ryazanian interval. This biostratigraphic zonation scheme allows stratigraphic correlation to be made where significant lateral facies changes occur, both within the reservoir and adjacent to the margins of the submarine fan systems. Whilst palynomorphs have been extracted from a very large number of sample types since exploration drilling began in South South
Brae
Upper
Reservoir
Layer
Formation
Pressures
7500
6500
Correlation within the reservoir The techniques used for correlation within the South Brae reservoir can be grouped into four main categories: lithostratigraphy, biostratigraphy, reservoir engineering surveillance and seismic data.
5500
9
9
Commence water injection
Litho- and biostratigraphy 4500
The large-scale upward-fining sequences aid correlations between adjacent wells. Electric-log responses clearly reflect these sequences
Jul-83
,
9
9
Jul-86
Jul-89
Jul-92
~.......... , . . . . .
Jul-95
Jul-98
Fig. 10. Formation pressure plot through time for a single reservoir layer.
S O U T H BRAE FIELD
219
,,.-:.,
o
O
r
o
E
220
K.J. FLETCHER
Brae, recovery is best from the mudstone facies. The high energy, proximal nature of the sedimentation results in reworking and generally poor recovery of diagnostic dinocysts. Therefore detailed intra-reservoir correlation based upon biostratigraphic information alone is not possible.
also smaller scale sector models concentrating on one layer or a particular part of the field but attempting to isolate the dual facies/ porosity nature of the reservoir.
Source rocks Reservoir engineering As production from the South Brae Field has continued, a vital tool for reservoir correlation has been the availability of various reservoir surveillance data. Formation pressures when the well is first drilled are the most accurate and reliable sources of information but other data sources include pressure build ups, pressure fall offs and static pressure tests. Prior to the start of production, a single oil pressure gradient and a single water pressure gradient were evident throughout the field. However, production and injection have affected reservoir layers in differing ways due to the presence of laterally extensive mudstones and faulting forming local pressure barriers. Local pressure depletion of reservoir layers provides support for the correlation of reservoir units and the degree of connection within reservoir bodies. Figure 2 illustrates that there is vertical pressure heterogeneity; a fact that was not anticipated in early field life due to only thin interlayer mudstones being observed and apparent amalgamation of reservoir layers at the field crest. The use of datumized pressure plots through time (Fig. 10) for each reservoir layer are used to predict current layer pressures and to support the correlations by indicating which wells lie off trend for that layer, therefore suggesting problems with the correlation or compartmentalization.
The Brae Formation is both overlain by and regionally interdigitates with the organic-rich Kimmeridge Clay Formation which, together with mudstones within the Brae Formation, are considered to be the source rocks for the South Brae oil accumulation (Reitsema 1983). This intimate association allows relatively short migration pathways for the hydrocarbons into the South Brae structure. It is considered that hydrocarbon generation and migration has been occurring from the Late Cretaceous onwards.
Hydrocarbons The maximum DST flow rate on the South Brae Field discovery well 16/07a-8 was 7800 BOPD on a 1.25 inch choke. The crude oil gravity ranges from 33 ~ to 37 ~ API, and the gas-oil ratio at initial pressure is 1343 SCF/STB. Separator gases show specific gravities ranging from 1.02 to 1.05, CO2 contents ranging from 32% to 35%, and low concentrations of H2S (85 ppm). The oil formation volume factor ranges from 1.73 RB/STB at an initial reservoir pressure of 7128 psia, to 1.86 RB/STB at the bubble point pressure of 3702psia. The crude oil therefore exhibits a relatively large shrinkage factor due to its high content of dissolved gas. This characteristic has necessitated an extensive pressure maintenance programme during development.
Seismic data
Reserves
Finally the 1998 seismic dataset is being utilized to aid in the discrimination of channel features and faulting by using amplitude data, inverted data and attribute analysis. Apart from a reasonable 'top reservoir' pick the correlation of individual reservoir layers over the field is below the resolution of the seismic data. However, improved seismic data may allow large scale geometries within the reservoir to be defined in certain areas. If so, this will be a significant development in field description. Using the above techniques in an integrated approach has allowed a reservoir subdivision scheme to be interpreted. A total of seven reservoir layers are correlated within the field, with an example of reservoir correlation shown in Figure 11. Porosity and permeability are highly variable within each of the layers and are largely controlled by the facies distribution. The best quality reservoir rock is the Facies 3 (medium and thick bedded) sandstone in the uppermost Brae Formation, where layer average porosities and air horizontal permeabilities range up to 21% and 2180 mD respectively. Both of these parameters show a decline with depth. Typical conglomerate matrix parameters are 12% porosity and 20mD permeability; parameters within the clasts vary with clast lithology, but are generally significantly worse than the matrix. Essentially a dual facies/ porosity system exists, with sandstone beds acting as flow conduits to the wellbore but accessing the oil in the conglomerate matrix over a large areal extent. Production data supports this as production logging tools show that even over hundreds of feet of perforated conglomerate/sandstone interval it will only be the thin sandstone beds directly contributing to flow. The sandstone beds water out as the flood front progresses but then they continue to produce at a high water cut for years afterwards; the interpretation being that this oil is sourced from the adjacent conglomerates. This is supported by wells drilled adjacent to one another that clearly illustrate conglomeratic intervals becoming swept over time, as demonstrated by thermal-decay-tool logs. As a result two kinds of reservoir engineering models are used; firstly a full-field model including all mapped reservoir layers but
South Brae STOOIP is 795 MMBBLs, originally containing 310330 MMBBLs of recoverable oil plus NGL. The pressure maintenance scheme has primarily been peripheral waterflood with some crestal gas injection. The effect of injection maintaining pressure within a layer can clearly be seen on Figure 10. A trial project using down-dip gas injection followed by a bank of water (Water Alternating Gas (WAG) secondary recovery) to access residual and unswept oil was highly successful from 1994 to 1997 and therefore full-field W A G is being implemented. Field production has stabilized at just under l0 000 BOPD since the field came off plateau in 1988, when maximum rates exceeded 100 000 BOPD (Fig. 12). As of May 1999, cumulative oil and NGL production is 265 MMBBLs.
South Brae Daily Production 140
120
100
8O ~
60 -9
40
0 ~
1983
I'
'T
't'
1987
1991
1995
Fig. 12. South Brae production profile through time.
1999
SOUTH BRAE FIELD This paper is published with permission of Marathon Oil UK, Ltd., the Operator of South Brae, and Participants, BP Exploration Operating Company Limited, BG International Limited, British-Borneo UK Limited, Burlington Resources (UK) Inc., Kerr-McGee Oil (UK) PLC, Lundin Oil and Gas Limited and Talisman Energy (UK) Limited. I would like to acknowledge the many people who have contributed to the understanding of the Brae area and in particular the South Brae Field over the many years of production and exploration.
Production rate (May 1999) Cumulative production to May 1999 Number/type of wells
221 9500 BOPD (Peak 115 000 BOPD, November 1986) 265 MMBBLs oil plus N G L 2 exploration 6 appraisal 42 development (to May 1999)
References S o u t h B r a e Field d a t a s u m m a r y Trap Type Depth to crest Lowest closing contour Hydrocarbon-water contact Oil column Pay zone Formation Age Gross thickness (average; range) Net/gross ratio (average) Cut-off for net pay Porosity (average) Original hydrocarbon saturation (average) Permeability (average; range) Productivity index (range)
Combination structural/stratigraphic 1 l 821 ft TVDss 12100ft TVDss 13 488 ft TVDss 1670 ft
Brae Upper Jurassic (Kimmeridgian to mid-Volgian) 800 ft; 0-1670 ft 0.75 7% porosity in Sandstones; 3% porosity in Conglomerate 11.5% 80% 131 mD; 1-2100roD 10~40 BOPD/psi
Hydrocarbons Fluid type Oil gravity (range) Gas gravity (relative to air) Bubble point Gas/oil ratio Formation volume factor
Black oil 33 ~ to 37 ~ API 1.02 to 1.05 3702 psia 1343 SCF/STB 1.73 RB/STB
Formation water Salinity Resistivity
75 000 ppm MaC 1 Equivalent 0.120ohmm at 60~
Reservoir conditions Temperature Pressure Pressure gradient in reservoir
253~ at 12740ft TVDss 7128psia at 12740ft TVDss 0.295 psift
Field Size Area Gross rock volume Recovery factor Primary recovery method Secondary recovery method Tertiary recovery method Recoverable hydrocarbons
6000 Acres 2 750 300 acre ft 33% Waterdrive Water injection Water alternate gas injection (WAG) Oil & NGL: 310-330 MMBBLs
Production Start-up date Development scheme
July 1983 Production-processing~trilling platform
BREHM, J. A. 2003. The North Brae and Bevin Fields, Block 16/17a, UK North Sea. In: GLUYAS, J. & HICHENS, H. (eds) UK Oil and Gas Fields" Millennium Commemorative Volume. Geological Society, Memoirs, 20, 199-209. CHERRY, S. T. C. 1993. The interaction of structure and sedimentary processes controlling deposition of the Upper Jurassic Brae Formation conglomerate, Block 16/17, North Sea. In: PARKER, J. R. (ed.) Petroleum Geology oJ'Northwest Europe." Proceedings of the Forth Conference, Geological Society, London, 387-400. COCKINGS, J. H., KESSLER, L. G., MAZZA, T. A. & RILEY, L. A. 1992. Bathonian to mid-Oxfordian sequence stratigraphy of the South Viking Graben, North Sea. In: HARDMAN, R. F. P. (ed.) Exploration Britain." Geological Insights' for the Next Decade. Geological Society, London, Special Publications, 67, 65-105. FLETCHER, K. J. 2003. The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea. In: GLUYAS, J. & HICHENS, H. (eds) UK Oil and Gas Fields Millennium Commemorative Volume. Geological Society, Memoirs, 20, 183-190. GARLAND, C. R. 1993. Miller Field: Reservoir stratigraphy and its impact on development. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the Forth Conference. Geological Society, London, 401-414. MCCLAY, K. R. 1995. The geometrics and kinematics of inverted fault systems: a review of analogue model studies. In: BUCHANAN, J. O. & BUCHANAN, P. G. (eds) Basin Inversion. Geological Society, London, Special Publications, 88, 97-118. MCLAUGHLIN, O. M. 1992. Isotopic and textural evidence for diagenetic fluid mixing in the South Brae oil field, North Sea. PhD Thesis, Glasgow University. REITSEMA, R. H. 1983. Geochemistry of North and South Brae areas, North Sea. In: BROOKS, J. (ed,) Petroleum Geochemistry and Exploration of Europe. Geological Society, London, Special Publications, 12, 203-212. RILEY, L. A., ROBERTS, M. J., & CONNELL, E. R. 1989. The Application of palynology in the interpretation of Brae Formation stratigraphy and reservoir geology in the South Brae Field area, British North Sea. In: COLLINSON, J. D. (ed.) Correlation in Hydrocarbon Exploration. Norwegian Petroleum Society, Graham & Trotman, London, 339-356. ROBERTS, M. J. 1991. The South Brae Field, Block t6/7a, UK North Sea. In" ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume, Geological Society, London, Memoir, 14, 55-62. THOMAS, D. W. & COWARD, M. P. 1996. Mesozoic regional tectonics and South Viking Graben formation: evidence for localised thin skinned detachments during rift development and inversion. Marine and Petroleum Geology, 13, 149-177. TURNER, C. C., COHEN, J. M., CONNELL, E. R. & COOPER, D. M. 1987. A depositional model for the South Brae Oilfield. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe. Graham & Trotman, London, 853-864. TURNER, C. C. & CONNELL, E. R. 1991. Stratigraphic relationships between Upper Jurassic submarine fan sequences in the Brae area, UK North Sea: The implications for reservoir distribution. In: 23rdAnnual Offshore Technology Conference, Houston.
The West Brae and Sedgwick Fields, Blocks 16/06a, 16/07a, UK North Sea SIMON
D. WRIGHT
Marathon Oil U K Ltd., Rubislaw Hill, Anderson Drive, Aberdeen A B 1 5 6 F Z , U K
Abstract: The Marathon-operated West Brae Field straddles Blocks 16/06a and 16/07a in the UK Central North Sea approximately 140 miles (225 km) NE of Aberdeen. The field was discovered in 1975 with drilling of exploration well 16/07-2. The West Brae reservoirs consist of Eocene Balder Formation and Upper Sele Formation Sandstones that were deposited in NW-SE trending submarine channels across the area. Development of the field commenced in April 1997 with first oil being achieved in October the same year. The field has been developed using sub-sea tie-back to the Brae A platform, which lies 5.6 miles (9 km) SE of the sub-sea manifold. Recoverable reserves are estimated to be 60 MMBBLs, of which some 23 MMBBLs had been produced by 31 December 1999.
Fig. 1. Location of West Brae Field in the Central North Sea shown in relation to neighbouring Jurassic fields which lie on the southern margin of the South Viking Graben. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 223-231.
223
224
S.D. WRIGHT
The Production Licence P.108, covering Block 16/07 was awarded to Pan Ocean Oil (UK) Ltd and Syracuse Oils (UK) in July 1970 as part of the 3rd U K Offshore Licensing Round. Other participants subsequently joined the venture and in 1976 Pan Ocean became a wholly owned subsidiary of Marathon Oil Company. The West Brae Field was discovered in 1975 with Pan Ocean well 16/07-2 (Fig. 1) which found 52 ft of Balder gas and 92 ft of oil in the deeper Sele Formation Flugga Sandstone Member. A distinct oil-water contact (OWC) of -5652 ft TVDss was observed in the Flugga Sandstone. Gas and oil tested from these two intervals at rates of 8 M M S C F D and 4018 BOPD (23 ~ API), respectively. An attempt to delineate the field was made in 1990 with the drilling of well 16/07a- 31 located one mile (1.6 km) N W of the discovery well. This well found a small volume of oil in younger Eocene Sandstones, and gas in very thin Balder sandstones which do not communicate with the 16/07-2 accumulation. A final predevelopment appraisal well, 16/07a-32, was drilled in 1991, 1312ft (400 m) W of the discovery well. This well found a section similar to well 16/07-2 and tested 28 M M S C F D from a 68 ft Balder gas sand and 5000 BOPD from a 143 ft Flugga oil sand. The neighbouring block (16/06a) is covered under the P.205 Production Licence which was awarded to a Conoco led group in the 4th Licensing Round in 1972. Enterprise, who earned a 25% interest in the block by drilling well 16/06a-2, made a discovery in November 1985. The well found that the Balder sand had 6ft of gas overlying 185 ft of oil column with a -5620 ft TVDss OWC. A DST was performed yielding 2127 BOPD (21 ~ API). The 16/06a accumulation was believed to be separate from the oil discovered earlier in Block 16/07a and was named the Sedgwick Field after the nineteenth century geologist Adam Sedgwick. Two unsuccessful appraisal wells (16/06a-3 and 3Z) were drilled by Conoco on the northern flank of the field in December 1989. Enterprise became operator of the northern part of Block 16/06a, which contains the Sedgwick Field, in 1992. Final appraisal wells 16/06a-4 and horizontal sidetrack 16/06a-4Z were drilled in September 1993 by Bow Valley (Talisman) as part of a 20% farm in. A two week extended well test was conducted on the horizontal well averaging 5262 BOPD from the Balder Sandstone. Enterprise sold their interest in the block to Summit in 1998 and operatorship was transferred to Talisman. A list of the current 16/06a and 16/07a coventurers is given in Table 1. The original joint development plan proposed three horizontal Flugga producers at West Brae, one horizontal Balder producer at
Table 1. Co-venturers and their percentage share in Blocks' 16/06a and 16/07a Block 16/06a
Block 16/07a
Company
%
Company
%
Sumitomo
40.0
Marathon Oil UK, Ltd. (Operator)
38.0
Talisman Energy (UK) Limited (Operator)
20.0
BP Exploration Operating Company Limited
20.0
BP Exploration Operating Company Limited
20.0
Talisman Energy (UK) Limited
14.0
Lundin Oil and Gas Limited
20.0
Kerr-McGee Oil (UK) PLC c/o Kerr-McGee North Sea (UK) Limited
8.0
BG International Limited
7.7
Burlington Resources (UK) Inc.
6.3
Lundin Oil and Gas Limited 4.0 British-Borneo UK Limited
2.0
Sedgwick and a common water injector mid-way between the two fields. The plan of development assumed that the Sedgwick Balder reservoir was in communication with the Flugga reservoir at West Brae. The Sedgwick producer was to be tied back to a manifold located in the south of West Brae which itself would be tied back to the Brae A platform. Drilling commenced on 29 April 1997. At the start of development drilling, it was recognized that the West Brae Field was not fully appraised and the plan of development involved considerable geological risk that could be managed by the careful placement of pilot holes. The first pilot hole, 16/07a-W1, was drilled to the southwest of well 16/07a-2 and proved up the existence of Balder oil in Block 16/07a with a contact o f - 5 6 2 2 f t TVDss. This was sufficiently close to that seen at Sedgwick so as to indicate hydrocarbon communication. The Balder contact was 32 ft shallower to that seen in the Flugga Sandstone and demonstrated that the Flugga and Balder reservoirs were separated. The Flugga reservoir was water bearing in the 16/07a-W1 pilot.
Early Eocene
Balder ~ . Flugga Base Flugga
Ekofisk
Fig. 2. West-east seismic cross-section through West Brae Field intersecting wells 16/07a-W4, 16/07a-32 and 16/07-2.
WEST BRAE FIELD The first pilot hole had a deleterious effect on Flugga reserves and initiated a rapid re-characterization of the West Brae geological model. Fortunately, a reprocessed 1993 vintage 3D seismic survey had just become available which significantly improved the resolution of sand-prone submarine channels (Fig. 2). Additionally, a fieldwide biostratigraphic review had just been completed which complemented the seismic interpretation. The revised development plan was issued in July 1997 and consisted of one horizontal Flugga producer and two horizontal Balder producers at West Brae and a common Balder injector between the two fields. The single horizontal Balder producer at Sedgwick remained unchanged. Drilling and completion of these
Fig. 3. Generalized West Brae stratigraphy with reference to well 16/07a-32.
225
wells was concluded on 17 May 1998 with first oil having been achieved on 21 October 1997. Oil production for 1998 averaged 30 850 BOPD. Following the initial development phase, appraisal well 16/07aW5, was drilled in the south of the West Brae Field targeting the Balder Sandstones. This well found 38 ft of poor quality reservoir on the Balder channel margin. There was insufficient thickness and reservoir quality to warrant a completion in this part of the field. An additional appraisal well with two deviated sidetracks (16/07a-34, 34Z and 34Y) was drilled in September 1998 in the northern part of the West Brae Field. These wells proved a northerly extension to the Flugga reservoir and a second horizontal Flugga
226
S. D. WRIGHT
well was drilled in this area in April 1999. This well commenced production in May 1999 at a rate of 8000 BOPD. In M a y 1999 the two fields were re-determined as one field by the Department of Trade and Industry with the name West Brae being retained.
Stratigraphy A generalized stratigraphic column with reference to well 16/07a-32 for the West Brae Field is shown in Figure 3. The initiation of the Cimmerian orogeny in the late Triassic marked the onset of major rifting and the formation of the South Viking Graben to the east. West Brae is located at the eastern margin of the Fladen Ground Spur, which constitutes the uplifted western flank of the South Viking Graben. The Fladen Ground Spur (Fig. 1) was a positive feature throughout most of the Mesozoic. Rocks of the Fladen Ground Spur were uplifted and eroded during Cimmerian times resulting in a major unconformity at the Top Devonian level. Carboniferous, Permian and Triassic age rocks are absent in the West Brae area. A thin transgressive Upper Jurassic Sandstone, followed by a thin sequence of organic rich Kimmeridge Clay Formation shale locally overlies the eroded Devonian surface. Elsewhere, the Devonian is unconformably overlain by a 50 ft sequence of Lower Cretaceous marls and mudstones representing the onset of marine
conditions. Deeper seas prevailed in the Upper Cretaceous and Lower Paleocene which comprise a 300-400 ft condensed sequence of chalk, marls and mudstones. These sediments lie unconformably on the Lower Cretaceous marls and mudstone following a phase of early Cretaceous inversion. The cessation of chalk deposition in the early Paleocene gave way to a rapid and continued influx of sands and deep water hemipelagic mudstones which filled the subsiding basin with up to 4000 ft of sediment in the West Brae area. Sands were deposited by turbidity currents that were sourced from an uplifted shelf to the northwest. The older Paleocene submarine fans are sheet-like basin floor fans composed of networks of interconnecting channels. By Eocene times, sand supply became more restricted with a higher proportion of mud in the turbidite systems (Den Hartog Jager et al. 1993). As a result, the younger fans of the Sele, Balder and Horda Formations are more channelized and shoestring-like in the West Brae area. In the early Eocene, tuffaceous mudstones of the Balder Formation were deposited over a wide area of the Central and Northern North Sea. These form a convenient marker horizon that separates the Sele Formation Flugga reservoir from the overlying Balder Formation reservoir at West Brae. The Balder Formation is overlain by 1800-2500 ft of the Horda Formation Mudstone. A further 2500 to 3000 ft of basinal mudstones and sandstones of the Westeray Group, of Oligocene to mid Miocene age, and the Nordland Group of mid Miocene to Recent age, overly the Horda
Fig. 4. West Brae Top Balder Formation structure map illustrating the field outline. Contours are in feet TVDss.
WEST BRAE FIELD Formation. The Kimmeridge Clay was sufficiently buried in the South Viking Graben to the east for oil generation to commence in the Oligocene.
227
The Flugga structure is full to spill with an OWC at - 5 6 5 2 f t TVDss, 32 ft deeper than that seen in the overlying Balder reservoir (Fig. 6). The reservoir spill point lies on the northern limit of the field. The Flugga reservoir has a gas cap with a GOC of -5500 ft TVDss.
Trap The Balder trap is orientated N W - S E following the Balder Channel fairway and is approximately 3.8 miles long (6.1 km) and 0.62 miles wide (1 km) with an areal closure of 1213 acres (Fig. 4). The structure is dip closed on all sides with the exception of the northern limits in Blocks 16/06a and 16/07a, where the channel margin provides local stratigraphic closure. The Balder reservoir is full to spill with the fieldwide OWC lying at a depth of -5620 ft TVDss. The spill point is located within a structural saddle that lies on the western limit of the field in Block 16/06a. Overlying Horda Claystones provide the seal for the Balder reservoir. The Balder structure consists of two local highs (Fig. 5), one in Block 16/06a and the other in Block 16/07a. A structural saddle which lies above the fieldwide OWC separates the two highs at the block boundary. A gas cap partially fills the eastern high in Block 16/07a with a gas-oil contact (GOC) o f - 5 5 1 6 f t TVDss. The Block 16/06a high has a smaller gas cap with a shallower GOC of -5433 ft TVDss. The Balder high in Block 16/06a is a result of sandstone drape over a deeper structure, which itself is the result of differential compaction of a locally developed thickness of Heimdal Sandstones. The Balder structure in Block 16/07a has formed as a consequence of sandstone drape over a N-S trending basement high which is a relic of the upthrown western margin of the South Viking Graben (Fig. 2). Inversion of the basement structure at the end of the Lower Eocene created an early trap in Block 16/07a for migrating hydrocarbons from the deeper Mesozoic reservoirs to the east. The Upper Sele Formation $3 Mudstone separates the Balder reservoir from the underlying Flugga reservoir and acts as a seal and barrier. The Flugga trap lies solely in Block 16/07 and has been formed by sandstone drape over a N-S basement structure. It mirrors the deeper basement and is approximately 2.2 miles (3.5 kin) long and 0.62 miles wide (1 km) with an areal closure of 650 acres (Fig. 4). Late Lower Eocene inversion accentuated the early structure.
Reservoir The reservoirs at West Brae comprise massive sandstones of the Early Eocene Balder and Sele Formations (Fig. 7). Sands were deposited over Blocks 16/06a and 16/07a by southeasterly trending submarine channels fed from uplifted areas to the northwest. The current reservoir zonation conforms to the lithostratigraphic scheme defined by Knox & Holloway (1992) and is shown in Figure 3. The top of the Balder Formation is taken at the base of a high gamma peak which occurs at the base of the Horda Formation. The Top Balder Formation is identified palynologically by an influx of Inaperturopollenites hiatus and the first downhole occurrence of Deflandrea oebisfeldensis. The Balder Formation is subdivided into an Upper B2 Unit consisting of sandstones that interdigitate with age equivalent mudstones and a Lower B1 Unit comprising laminated mudstones with abundant tuff layers. The sandstones range from a few feet to over 300 ft in thickness. The tuffaceous Lower Unit has a characteristic low gamma log signature coupled with a low porosity claystone response on spontaneous potential and neutron-density logs. The B1/B2 subdivision is also associated with an increase in Caryapollenities simplex. The Balder tuffaceous unit is typically 40-60 ft thick across the field where preserved. The Balder tufts are underlain by a 20-30 ft Upper Sele Formation grey mudstone that displays an increasing gamma response with depth and is identified palynologically by abundant Cerodinium wardenense. This mudstone forms the uppermost $3 layer of Knox & Holloway's (1992) threefold lithostratigraphic subdivision of the Sele Formation. A relatively thin sandstone, up to 100 ft in thickness, is locally developed within the $3 Mudstone (S3B Sandstone Unit). The Flugga Sandstone Member, forming part of the $2 subdivision of the Sele Formation, underlies the $3 unit. Flugga Sandstones vary from a few feet to over 500 ft in thickness. The
Fig. 5. Northwest-southeast geoseismic cross-section through West Brae Field. Refer to Figure 4 for line of section.
228
S.D. WRIGHT
Fig. 6. South-north geoseismic cross-section through West Brae Field. Refer to Figure 4 for line of section.
Fig. 7. Structural well correlation illustrating typical West Brae log character and fluid contacts. Wells are displayed relative to TVDss.
WEST BRAE FIELD base of the Flugga reservoir is marked by grey $2 Mudstones that are characterized palynologically by Top Cerodinium speciosum
glabrum. The Flugga Sandstones occupy two submarine channels which have been identified from 3D seismic surveys. A W N W - E S E channel converges with a N-S trending channel over the main field high in Block 16/07a (Fig. 8). The channels are interpreted to follow pre-existing basement lows that have been accentuated by erosion from turbidity currents passing through to the deeper basin to the east. Back filling of the sands from later turbidity flows is believed to have occurred in a series of pulsed events. Two younger channels, containing mostly Balder sediments, overlie the flanks of the Flugga channel system and converge in Block 16/07a (Fig. 8). S3B Sandstones are only locally developed along the base of the southern channel. These sands represent deposits from sporadic turbidite flows that began to switch from the main underlying Flugga Sandstone fairways as the Upper Sele clastic fan was abandoned. The southerly channel contains thick sequences of Balder Sandstone from over 300 ft in Block 16/06a to around 200 ft in Block 16/07a and forms the main West Brae Balder reservoir in both blocks. In Block 16/06a the southern channel is deep and erosive, having removed Balder Tufts and Sele 3 Mudstones. Moving east along this channel, sands become progressively thinner, less confined and the channel less erosive such that in Block 16/07a Balder Tufts and Sele $3 Mudstones are preserved beneath the channel axis. Here, the Balder Tufts and Sele 3 Mudstone act as a seal for the underlying Flugga reservoir. The northern Balder channel is thinner and more sinuous than the southern channel. Well control indicates that it is erosive, but
229
only partially back filled with massive sandstone. The majority of northern channel fill seen in well 16/07a-34 comprises thin Balder Sandstones interbedded with mudstones and siltsones. The channel thins and is less erosive as it passes over the underlying Flugga high in Block 16/07a to join with the main Balder channel to the south. Abandonment of the Balder channel system is sometimes indicated by a fining upward sequence from sandstone, siltstone to mudstone. More commonly the Top Balder is marked by an abrupt change from sandstone into overlying Horda Mudstone. Submarine channel axes are characterized by amalgamated units of massive unconsolidated sands showing very little internal structure. Water escape structures are occasionally in evidence suggesting deposition from high density turbidity currents. On the channel margins sandstones are less well bedded, and interfingering siltstones and mudstones become more common. Sandstones are relatively homogeneous and are typically fine to medium grained, moderately well sorted, and texturally mature falling into the quartz to subfeldspathic arenite classification. Porosities are high due to the uncompacted nature of the sands and the lack of significant grain coating clays and intergranular cements. Average porosities range from 26-35% for the Flugga, 23-31% for the S3B and 25-36% for the Balder reservoirs. Typical reservoir permeabilities range from 3 to 7.5 Darcies. The best reservoir properties are found along the axes of the submarine channels with rapid deterioration at the channel margins. Diagenetic clays and cements do not degrade porosity significantly except for the locally developed nodular carbonate cements which appear to be randomly distributed throughout the reservoir. Distribution of these cements is partially controlled by the distribution of microfossils and shelly debris that provide a nucleus for
Fig. 8. Schematic West Brae submarine channel model illustrating sandstone architecture.
230
S.D. WRIGHT
cement growth. The cements occlude the pore space such that porosity can be reduced by factors of ten to 100 times. Precipitation of calcite and a later ferroan calcite cement is thought to have occurred during the first few hundred metres of burial by bacterial oxidation of an early oil charge as it spread vertically through a meteoric aquifer. Ferroan dolomite cements are thought to have followed later with deeper burial as basin pore water mixed with meteoric water. Methanogenic fermentation of oil provided the main bicarbonate source ferroan dolomite for cements. The ferroan calcite and dolomite cements have been preferentially leached by a later influx of acid basinal pore waters. Dissolution has generated extensive secondary porosity with porosities of up to 25%. However, permeability through leached carbonate cement zones remains low and range between 50 and 110mD. Carbonate cemented zones in the reservoir are interpreted to form local baffles to fluid flow rather than barriers.
Source The hydrocarbons in the West Brae reservoirs consist of heavy 22 ~ API oil overlain by dry gas. Geochemical isotopic and molecular evidence indicates that West Brae hydrocarbons have been sourced by Kimmeridge Clay Formation in the South Viking Graben via spillage from the adjacent North Brae Field. The Kimmeridge Clay Formation in the South Viking Graben reached maturity and commenced oil generation in the late Eocene. The expelled oil followed relatively short migration routes into the interdigitating Upper Jurassic North Brae reservoir. Re-migration of hydrocarbons into the West Brae trap occurred later, possibly in the Miocene. Wet gas is inferred to have arrived first in Block 16/07a since the cored intervals containing the gas legs show no significant oil staining. The gas is interpreted as a late maturation product of the oil prone Kimmeridge Clay Formation which first displaced trapped oil in the North Brae reservoir. Some of the gas was able to migrate into the Lower Eocene sands via faults on the western margin of the South Viking Graben. The displaced North Brae medium gravity oils arrived later, accumulating below the gas legs in Block 16/07a and spilling into Block 16/06a. This oil migrated across the western faulted margin of the North Brae Field into basement Devonian rocks and then vertically up into the Eocene sands. Influx of oxygenated meteoric waters caused biodegradation of the oil and gas in the Eocene reservoirs resulting in decreased oil API gravity and gas wetness. Biodegradation started with the first arrival of hydrocarbons and ceased during Holocene to Recent times when burial of the reservoir created temperatures greater than 60~ (140~ Following biodegradation, a recent phase of gasoline range hydrocarbons has entered the reservoir and mixed with the heavy oil, reducing API gravity and decreasing viscosity.
standing of the field. Additionally, the author would like to recognize the significant contribution made by Marathon's consultant organizations, specifically Ichron Sedimentological and Biostratigraphical Consultants, Integrated Geochemical Interpretation Ltd. and the Department of Geology at the University of Glasgow. Thanks are also due to Marathon's mapping and drafting group for preparation of figures for this paper.
West Brae Field data summary Flugga Reservoir
Balder Reservoir
Type Depth to crest Lowest closing contour Gas-oil contact
Structural -5450ft TVDss -5652 ft TVDss -5500ft TVDss (16/07a)
Oil-water contact
-5652 ft TVDss (16/07a)
Structural/Stratigraphic -5350ft TVDss -5620 ft TVDss -5516ft TVDss (16/07a) -5433 ft TVDss (16/06a) -5620 ft TVDss
Maximum gross gas column Maximum gross oil column
50ft (16/07a)
Trap
Pay zone
Gross thickness (average) Net/gross ratio (average) Porosity (average) Permeability (average) Oil saturation (average) PI (Horizontal wells)
72 ft 85% 29.2% 6000 mD 92% 250 BOPD/psi
58 ft 87% 31.0% 7500 mD 92% 350-500 BOPD/psi
22~ API Saturated, low wax (0.3%), high tan (2.5) 3.5cp 2485 psi 296 SCF/STB 1.15 RB/STB 170 SCF/RCF
22~ API Saturated, low wax (0.3%), high tan (2.5) 5.75cp 2455-2485 psi 271 SCF/STB 1.16 RB/STB 170 SCF/RCF
60 000 ppm (NaCl equivalent) 0.138 ohm at 60~
60 000 ppm (NaC1equivalent) 0.138 ohm at 60~
Pressure gradient Temperature Oil initially in place Gas initially in place
650 acres 46 968 acre ft (oil) 2640 psi at -5652 ft TVDss 0.37 psi/ft 145~ 76 MMBBLs 5 BCF (16/07a)
Recovery factor Drive mechanism Recoverable oil
31.5% Water drive 24 MMBBLs
1213 acres 69 936 acre ft (oil) 2525 psi at -5620 ft TVDss 0.37 psi/ft 145~ 116 MMBBLs 35 BCF (16/07a), 0.34 BCF (16/06a) 31% Water drive 36 MMBBLs
Petroleum
Oil density Oil type
Viscosity Bubble point Gas/oil ratio Formation volume factor Gas expansion factor Formation salinity
Salinity Resistivity (Rw)
Reserves and production The bulk of the West Brae oil-in-place lies in the Balder reservoir with an estimated 116 MMBBLs. The Flugga reservoir is estimated to contain 76 MMBBLs oil-in-place. Production comes from three horizontal Balder producers and two horizontal Flugga producers. A single water injection well provides pressure support in the Balder reservoir. To date, aquifer influx in the Flugga reservoir has kept up with production and there are currently no plans to inject water into the Flugga. Production commenced in October 1997 with an average production rate of 35 000 BOPD being achieved by June 1998. Recoverable reserves are estimated at 60 MMBBLs, of which 23 MMBBLs had been produced by 31 December 1999. The recovery factor for the field is estimated at 31%. This paper is published with the permission of Marathon Oil UK Ltd., the Operator of the West Brae Field, and the working interest owners in Blocks 16/06a and 16/07a (Table 1). The author would like to thank all the members of the West Brae Subsurface Team who have contributed to the under-
152 ft (16/07a)
166ft (16/07a) 13 ft (16/06a) 104 ft (16/07a) 187 ft (16/06a)
Field characteristics
Area Gross rock volume Initial pressure (at OWC)
Production
Start-up-date 20 October 1997 Production rate plateau oil 35 000 BOPD (first 4 wells only) Number/type of well 5 Horizontal producers, 1 water injector
WEST BRAE FIELD
References DEN HARTOGJAGER, D., GILES, M. R. & GRIFFITHS, G. R. 1993. Evaluation of Paleogene Submarine Fans of the North Sea in Space and Time. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 59-71.
231
KNox, R. W. O'B. & HOLLOWAY, R. 1992. Paleocene of the Central and Northern North Sea. In: KNox, R. W. O'B. & CORDLEY, W. G. (eds) Lithostratigraphic Nomenclature of the Northern North Sea, Part 1. British Geological Survey, Nottingham.
The Brent Field, Block 211/29, UK North Sea S. R. T A Y L O R 1, J. A L M O N D a, S. A R N O T T 1, D. K E M S H E L L 1 & D. T A Y L O R 2
1Shell UK Exploration & Production, 1 Altens Farm Road, Nigg, Aberdeen AB9 2HY, UK Present address: ONP/1, Petroleum Development Oman, PO Box 81, Muscat 113, Sultanate of Oman (e-mail: steve,
[email protected]) 2 Exxon/Mobil International Ltd, Esso House, 96 Victoria St, London, S W 1 E 5JW, UK Present address: UPR, Petroleum Development Oman, PO Box 81, Muscat 113, Sultanate of Oman
Abstract: The Brent Field was the first discovery in the northern part of the North Sea, and is one of the largest hydrocarbon accumulations in the United Kingdom licence area. There are two separate major accumulations: one in the Middle Jurassic (Brent Group reservoir) and one in the Lower Jurassic/Triassic (Statfjord Formation reservoir). The Brent Field lies entirely within UK licence Block 211/29 at latitude 61~ and longitude 2~ the adjacent Brent South accumulation extends into Block 3/4A. The water depth is 460 ft. The Brent Field discovery well was drilled in 1971, and was followed by six further exploration and appraisal wells. Seismic data over the Brent Field has been acquired in four separate vintages. The latest acquisition in 1995 allowed detailed mapping of the complex eastern margin of the field for the first time. The Brent Field is developed from four fixed platforms (Alpha, Bravo, Charlie, Delta) installed between 1975 and 1978. Production commenced in 1976 and, for the first 22 years of field life, the platforms provided production, water injection and gas injection facilities for both the Brent and Statfjord Formation reservoirs. The Brent South accumulation is produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells. In 1992, the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. In January 1998, water injection into the main field was stopped and depressurization of the field initiated. As of January 2000, a total of 220 platform wells and three sub-sea wells (173 producers, 50 water injectors) have been drilled in the Brent Field. The original oil/condensate-in-place is currently estimated at 3.8 MMMSTB, and the estimated original wet gas-in-place is 7.5 TSCF. Total ultimate recovery for all reservoirs is expected to be 1988 MMSTB oil and condensate and 6000 BSCF gas. Cumulative oil and net gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas. This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir.
The Brent Field is located approximately 100 miles N E of the Shetland Islands and 300 miles N N E of Aberdeen in water depths of some 460 ft (Fig. 1). The discovery well location is at latitude 61~ North longitude 1~ East. The Brent Field covers an area of approximately ten miles from north to south by three miles from east to west. The hydrocarbons occur in a westerly dipping fault block in a fault controlled unconformity trap located within the central part of a major fault terrace on the western margin of the Viking Graben. The terrace can be traced over 40 miles from the North Alwyn Field in the south to the Statfjord Field in the north. With total hydrocarbons initially in place of some 3.8 MMMSTB oil and 7.5 TSCF of gas, the Brent Field is ranked as one of the largest fields in the Northern North Sea. Production is from two distinct reservoirs, the Brent Group and the Statfjord Formation, which are of Middle Jurassic and Lower Jurassic/Triassic age respectively. Two major E - W orientated faults divide the field into three separate production areas (Main, Graben and Horst blocks), whilst a structurally complex zone along the crest of the field (referred to as the Brent and Statfjord Slumps) forms a fourth production area (Fig. 2). The Brent South Field is a separate accumulation in a fault block located to the south of the Brent Field and north of the Strathspey Field. Brent South reservoirs are produced via the Brent Alpha platform, through sub-sea tie-backs and extended reach wells (Fig.3). The Brent Field has been described previously by Struijk & Green (1991). This paper summarizes the current understanding of the field based on acquisition of new 3D seismic data, 130 new wells, detailed structural and sedimentological modelling, development of the complex crestal part of the field and finally, the initiation of an extensive brown field re-development project to depressurize the reservoir.
History Pre-discovery The Brent Field is located entirely in Block 211/29 of the United K i n g d o m licence area in the northern North Sea. The field was developed by Shell UK. Exploration and Production on behalf of the Shell/Esso joint venture under Production Licence P.117, granted in the 3rd Round on 29 July 1970, for an initial term of six years, subsequently extended to 2018.
Discovery The discovery well, 211/29-1, was drilled from May to July 1971. The objective of this well was to test a monoclinally dipping sequence below a pronounced regional unconformity (the X-unconformity) in the Viking Graben. The well encountered the X-unconformity at 8462 ft TVSS and then penetrated the Upper Jurassic Kimmeridge Clay prior to entering the Brent reservoir in a downdip position. The Brent reservoir comprised an 800 ft thick sequence of interbedded sandstone, siltstone, shale and coal. The well proved 466 ft net sand including 140 ft of oil bearing sandstone. Formation tests confirmed light oil of 38~
Post-discovery Subsequent appraisal wells drilled from June 1972 to 1974 confirmed that the 870 ft thick Brent Group contained a single 480 ft thick oil column overlain by a 320 ft thick gas-cap with the OOWC at 9040ft TVSS and OGOC at 8560ft TVSS. Well 211/29-4 discovered saturated oil in the deeper, 800 ft thick Statfjord Formation sandstones. The Statfjord reservoir OOWC was subsequently proven at 9690ft TVSS. The exploration well 211/29-5 tested the
GLUYAS,J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 233-250.
233
234
S. R. TAYLOR E T AL.
Fig. 1. Location of the Brent Field.
deeper Triassic sequence, but found the sandstones water-bearing. Well 211/29-8, drilled in 1982, tested the sedimentary sequence adjacent to the eastern boundary fault of the Brent structure. It found Upper Jurassic sandstones with residual oil saturations and water-bearing Brent Group sandstones. The primary Brent Field development plan involved dedicated crestal producers for the Statfjord reservoir and dedicated mid-oil column producers for the Brent reservoir. Pressure support for both reservoirs was provided by down-dip water injection and crestal gas injection. Four platforms installed between August 1975 and June 1978 provide a total of 154 well slots. Production commenced in 1976 with oil initially exported via tankers loading at the Brent Spar loading buoy. Since November 1979 oil has been mainly transported through the Brent System pipeline to the oil terminal at Sullom Voe in the Shetlands. Brent Field gas has been exported via the FLAGS line to St Fergus in Scotland since May 1982. Annual oil production peaked in 1984 at 410 MBBL/D whilst a
record annual gas production level of over 860 MMSCF/D was achieved in 1999. Well data acquired in the 1980s indicated that the crestal area of the Brent Field had a complex structure that necessitated a dedicated development scheme (Fig. 4). Development of this area, now known as the Brent and Statfjord Slumps was initiated in 1994 with dedicated horizontal oil producers and water injectors. Brent South was discovered in 1973 by well 3/4A-1, drilled in block 3/4A. The well encountered 45 ft of oil-bearing sandstones in the Brent Group and showed that the OOWC was close to that of the Brent Field at 9040ft TVSS. Well 3/4A-11 encountered 51 ft of gas in the Statfjord Formation with an OGWC at 9851 ft TVSS. The block was sold to Shell/Esso in 1991, and the Brent accumulation was developed over the Alpha platform via extended reach wells and tied back sub-sea wells. Pressure support is provided by down-dip water injection. Since the mid 1980s, oil production has been declining. However, because of the high solution GOR (ranging from 1400 to
BRENT FIELD
235
Fig. 2. Top Brent reservoir structure.
5500 SCF/STB) substantial gas reserves remain, dissolved in the residual and bypassed oil. In 1992 the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil, extending the field's life by 5-10 years. This would entail redevelopment of three of the four Brent platforms at a total cost of s billion to install process facilities for low pressure operations, to reduce operating costs, to implement safety upgrades, and to refurbish facilities. The fourth platform was also upgraded but no low pressure facilities were installed. Water injection was partially ceased in early 1997, and preparation of the platforms for long term field development was completed at the end of 1997, within
budget and ahead of time. Since 1994 there has been an aggressive, and successful, infill drilling campaign to develop all remaining thin oil rim and attic oil potential ahead of depressurization. On 1st January 1998, some 450 MBBL/D water injection, representing 90% of the field total, was switched off, leaving the Alpha platform injecting some 50 MBBL/D into areas which are not part of the depressurization project. This event marked a step change in the management of the field and in the operation of the platforms. As of January 2000, a total of 220 platform wells and three subsea wells (173 producers, 50 water injectors) have been drilled in the Brent Field. The busiest year ever for the Brent Field was 1999 in
236
S. R. TAYLOR E T A L .
Fig. 3. Brent Field overview.
terms of total well activities, with 14 wells sidetracked, 200 well entries and 12 recompletions. Over 90 wells are capable of producing. Cumulative oil and wet gas production, as of 1st January 2000, was 1875 MMSTB oil and 4196 BSCF gas.
Seismic data Seismic data over the Brent Field has been acquired on four occasions. The discovery of the main Brent field was based on a 1970 sparse grid of 2D data, augmented by other seismic datasets dating from 1966. The interpretation of this early seismic data outlined the N - S trend of the Tertiary Basin. Intermediate levels within the prospective Paleocene interval were examined for appreciable closures, but none could be proven owing to the absence of reliable correlatable reflectors. An important objective
Fig. 4. East-West cross-section through the Brent Field.
of the 211/29-1 discovery well, however, was a deep-seated feature (the Brent Field) beneath an unconformity observed at an estimated depth of 8850 ft TVSS. A close spaced (200 m) grid, oriented E - W recorded from 1980 to 1982 was processed as a pseudo-3D dataset with a sampling interval of 25 m x 200 m. This represented a marked improvement over the older 2D seismic datasets, allowing reservoir horizons to be mapped. However, it still proved insufficient to image the faulting within the crestal and graben areas of the field. In 1986 the first 3D Brent seismic survey was recorded with the objective of resolving the complex fault pattern of the eastern flank. Acquisition was on a grid spacing of 12.5m E - W by 37.5m N-S, but the data was initially processed on a 25 m x 37.5 m grid. Seismic resolution was improved significantly compared with the earlier pseudo-3D data, enabling more accurate interpretation of the west flank. However, imaging of the slump blocks on the eastern flank was still insufficient to meet the demands of drilling operations and
BRENT FIELD
237
Table 1. Key dates in fieM development
Discovery Declared commercial Production start-up First tanker loaded First oil to Sullom Voe First year peak production Last year peak production
1971 1972 Nov. 1976 (Brent B into storage) December 1976 November 1979 1983 (oil), 1986 (NGL), 1984 (gas) 1986 (oil) 'A' Platform
'B' Platform
'C' Platform
'D' Platform
Contract placed Installed Production drilling started First gas injection First water injection Production start-up Start of gas export Low pressure redevelopment completed Number of producer wells drilled (1/ 1/2000) Number of injector wells drilled (1/1/2000)
December, 1972 May 1976 December 1977 April 1979 December 1979 June 1978 March 1982 n.a 45 12
August 1973 August 1975 February 1976 February 1980 October 1979 November 1976 May 1982 November 1995 47 13
December 1973 June 1978 Late 1979 September 1981 September 1980 June 1981 August 1982 October 1996 37 11
May 1974 July 1976 January 1977 October 1978 October 1979 November 1977 September 1982 September 1997 42 13
Spar Contract placed Installed Decommissioned
March 1973 June 1976 August 1991
detailed static modelling. Reprocessing of this survey, carried out in 1989 and again in 1993, resulted in only marginal improvements in image quality. After promising results from a walkaway 3D-VSP shot in 1993 (Van der Pal et al. 1996), a new high-resolution 3D survey was acquired in 1995. The survey was acquired with an eight streamer/ single source configuration and covered an area of 320km 2, resulting in subsurface sampling some four times denser than the 1986 3D survey. A significant improvement in data quality was achieved by this survey, allowing detailed mapping of the Brent and Statfjord eastern margins and slumps for the first time (Van Dierendonck et al. 1997, Fig. 5). However, resolution of small scale faults and internal reservoir architecture remain elusive due to limited bandwidth and signal/noise ratio in the data.
Fig. 5. Seismic E-W section through the Brent Field structure.
Structure
Regional structure The Brent Field is located at the western margin of the Viking Graben, the northern extension of a 600 mile long rift system that continues into the Central North Sea Graben to the south. The field lies in a major fault terrace, some 12 miles wide (E-W) and over 40 miles long (N-S), that can be traced from the North Alwyn Field in the south to the Statfjord Field in the north (Fig. 1). This terrace is bounded to the west by the Hutton Dunlin-Murchison fault zone and to the east, by the so-called Eastern Boundary Fault. Both these fault zones were thought to have been active during deposition of the reservoir sandstones.
238
S. R. TAYLOR ET AL.
Local structure Associated with the N-S orientated Eastern Boundary Fault are a series of NW-SE trending faults that die out to the west of the accumulation (Fig. 2). The faults effectively divide the northern area of the field into a two mile wide graben and one mile wide horst feature, both of which are of significance to field development strategies. These faults display variable throw and are believed to be accommodation features produced by reactivation of underlying Caledonian faults within the basement during differential tilting and uplift along the major fault terrace. The southern boundary of the Brent Field is defined by a WSW-ENE fault that dies out to the west of the accumulation. During the opening of the Viking Graben and rotation of the fault terrace, periodic reactivation of the Brent Field faults occurred. In addition, the crest of the field was deformed by local, gravitationally induced fault scarp failure. Palaeontological evidence suggests that crestal failure occurred at two main times; during the Middle Jurassic (Bathonian) along the Brent Group crestal area, and during the early Cretaceous (pre-Santonian) mainly along the Statfjord Formation crestal area (Fig. 4).
Brent slumps At Brent Group level, complex subaqueous collapse of the gravitationally unstable crestal fault scarps occurred during the Late Jurassic, leading to tectonic degradation of the consolidated reservoir. This failure occurred along a series of mainly N-S oriented listric faults soling out in the Cook Formation (the Brent Main Slump Fault) or within the thicker shale intervals of the Brent Group itself. These landslide complexes are known as the 'Brent Slumps'. The seismically resolvable listric faults range in length from 3003300ft with throws of 30-150ft; the slump blocks are typically 150-650 ft wide (E-W) and 1500-5000 ft long (N-S). The deformation observed in post-glacial landslide complexes, found along large parts of the southern UK coastline, is similar both in scale and style to that in the Brent Slumps. Detailed studies of these landslides (Pitts 1983; Hutchinson et al. 1991) show that the dominant deformation mechanism is translation along the bedding parallel or shallow basal detachment coupled with collapse of the hanging wall adjacent to the main fault. Strata in this
collapsed area are generally rotated towards the main slump scar as a result of the underlying listric fault geometry. Studies of submarine slides, e.g. exhumed Jurassic fault blocks which crop out along the coast of East Greenland, have also improved the understanding of out-of-sequence stratigraphic relationships within the Brent Slump complex. The relatively coherent landslide blocks from the southern U.K. and the allochthonous Mesozoic blocks from East Greenland are illustrative of two end-member products of submarine slope degradation. The structural model applied to the Brent Slumps is based on these two analogues. Acquisition of new 3D seismic in 1995, combined with the arrival of improved seismic imaging tools and modern 3D reservoir geological modelling tools, has enabled construction of the first realistic description of the Brent Slumps (Fig. 6). The model represents the synthesis of detailed seismic interpretations, well log data, cross-section balancing, core data and knowledge gained from structural analogues.
Statfjord slumps At Statfjord Formation level, the style of crestal deformation is broadly analogous to that seen in the crestal part of the Brent Group reservoir, although the amount of throw and block rotation is significantly greater than observed in the Brent Group level slumps. A series of listric faults sole out near the base of the Statfjord Formation, where sandstone-rich intervals overlie shale dominated intervals.
Stratigraphy The general stratigraphy of the Brent Field is shown in Figure 7 and follows the nomenclature of Deegan & Scull (1977). The oldest reservoir interval comprises the Statfjord Formation (Rhaetian to Lower Sinemurian age) which conformably overlies the Triassic Cormorant Formation. The Statfjord thickness ranges from 1000 ft in the south to 880 ft in the north and is formally subdivided into a lower fluvial interval (Eiriksson and Raude Members) and an upper. shoreface interval (the Nansen and Calcareous Members). The Statfjord Formation is separated from the overlying Brent Group by
Fig. 6. Brent Slumps structural model - Delta Graben and Horst area viewed from the southeast.
BRENT FIELD
239
Formation comprises fine to coarse grained offshore sandstones and mudstones. The Rannoch Formation consists of a stacked sequence of fine to medium grained shoreface sandstones that are overlain by medium to coarse grained fluvial/tidal sandstones of the Etive Formation. The Ness Formation is a heterogeneous interval of coastal plain deposits, comprising a variety of coarse to fine grained sandstones, siltstones and mudstones together with significant thicknesses of coals (up to 30 ft in total). The overlying Tarbert Formation consists of a varied assemblage of shallow marine deposits ranging from fine to coarse grained sandstones to mudstones. The Humber Group is subdivided into the Heather and the Kimmeridge Clay Formations, the latter being the main source rock of the region. The Heather Formation contains pale grey mudstones of mostly Bathonian age, the Callovian stage being largely missing due to the first of a number of unconformities and condensed sequences that characterize the late Jurassic and early Cretaceous in the Brent Field and elsewhere in the region. The dark organic rich shales of the Kimmeridge Clay Formation are of Oxfordian to Ryazanian age.
Trap Both the Statfjord Formation and Brent Group reservoirs are contained in a simple fault-bounded, monoclinal structure, dipping 8 ~ to the west, with crestal truncation unconformity traps (Fig. 4). The lower reservoir, the Statfjord Formation, is additionally partly trapped by fault juxtaposition of Lower Cretaceous mudstones east of the culmination. The top seal is provided by a series of mudstones or calcareous mudstones and marls overlying the composite unconformity surfaces. In comparison to other oil fields in the area, the Brent Field structure is relatively simple and lateral closure is provided by non-reservoir juxtaposition across E-W and NW-SEtrending faults (Fig. 2). The trap was formed by Mid-Cretaceous times, long before oil migrated into the structure during the Eocene. Overpressures probably developed gradually during Tertiary burial of the structure.
Reservoir The Statfjord Formation and Brent Group reservoirs were deposited in significantly different depositional environments which resulted in widely different development strategies and challenges over the last 25 years. Since 1998, the reservoir correlation and geological models for both the Brent Group and Statfjord Formation have been reviewed and updated. Detailed 3D reservoir models of both reservoirs have been constructed using the Shell proprietary GEOCAP software.
Statfjord formation
Fig. 7. Brent Field stratigraphy. up to 850ft of mudstones and siltstones of the Dunlin Group. Four formations are recognized within the Dunlin Group; the Amundsen, Burton, Cook and Drake which is the youngest, being Toarcian in age. The second reservoir sequence, the Brent Group, is of Aalenian to Bajocian age and is subdivided from bottom to top into five formations: the Broom, Rannoch, Etive, Ness and Tarbert Formations. The maximum thickness of the reservoir is 850 ft in the south, thinning to 750 ft in the north. The lowermost Broom
The Statfjord Formation comprises an upwards coarsening fluvial sequence displaying a vertical transition from a low net to gross (N/G) floodplain dominated interval (Raude Member) to a high N/G, multi-storey channel complex (Eiriksson Member, Fig. 8). The vertical change in fluvial style is directly attributed to a change in climate from semi-arid to more humid conditions and possible rejuvenation in the hinterland resulting in a greater influx of sand into the basin. The fluvial sandstones are overlain by transgressive, shallow marine shoreface sandstones of the Nansen Member (Fig. 9). These are in turn sharply overlain by the non-reservoir quality Calcareous Member which consists of very fine grained shallow marine sandstones and mudstones. The Statfjord Formation attains a maximum thickness of 1000 ft in the Alpha Platform area, thinning northwards to 850 ft in the Delta area. The Member sub-division of the Statfjord Formation reservoir sandstones proved too coarse for reservoir management purposes and a more detailed reservoir sub-division based on a combination
240
S.R. TAYLOR E T AL.
Fig. 8. Statfjord Formation type log. of sedimentological, petrographic, RFT pressure and field performance data was devised. Due to a lack of reliable chronostratigraphic markers an essentially lithostratigraphic sub-division was constructed, grouping together intervals of similar facies characteristics within a framework governed by the occurrence of two thin, but laterally extensive semi-regional shales forming important pressure barriers within the field. On this basis the Statfjord reservoir is sub-divided into three main and six subunits. Northsouth cross-sections through the Statfjord Formation 3D geological model showing lateral and vertical facies and permeability distributions are shown in Figure 10.
Statfjord Unit $3. The $3 is the lowest of the Statfjord Formation reservoir units displaying a vertical transition from a low to high N/G fluvial system. It ranges from 650-800 ft in thickness and is further sub-divided into four sub-units. The lowermost $3.4 (Raude Member) comprises a thick (200300ft), low N/G interval of mudstones and siltstones locally containing thin, poor reservoir quality (porosity 10-24%, permeability 10-500mD) isolated channel sands and thin, non-reservoir quality sheetflood sands. It exhibits a gradual transition from the underlying red beds of the Triassic Cormorant Formation. The continuation of semi-arid conditions is evident by the occurrence of
BRENT FIELD
241
Fig. 9. Statfjord Formation depositional setting.
Fig. 10. Statfjord Formation N-S facies and permeability cross-sections through the 3D geological model.
several well-developed floodplain soil horizons which are locally used to correlate and sub-divide the reservoir in some parts of the field. Overall, an upwards increase in channel sand development occurs, but both vertical and lateral channel connectivity remains low. This, coupled with a lack of direct injection support means oil recovery from this zone is poor. The succeeding $3.3 to $3.1 sub-units (Eiriksson Member) comprise a heterogeneous interval of good reservoir quality (porosity typically 20-27%, permeability 100mD-1000mD) single and multi-storey channel sands with erosional remnant floodplain siltstones and shales. An overall upwards increase in channel sand
development and reservoir connectivity occurs, although within sub-units both sandstone character and connectivity can vary both laterally and vertically across the field. Further sub-division is made upon the occurrence of floodplain shales which form localised variable pressure barriers (i.e. within the $3.3 and $3.1 and top $3.2). The uppermost $3.1 sub-unit dominantly comprises single storey channel sands that have limited direct sand connectivity with the overlying $2 unit. The overall high lateral connectivity within the $3.3 to $3.1 interval means that the oil recovery is good and characterized by an even sweep, aided by the favourable mobility ratio of the Statfjord reservoir hydrocarbons.
242
S. R. TAYLOR ET AL. of the field reduces vertical communication with the overlying S1. The distribution of channel and inter-channel facies belts exerts a strong influence on the efficiency of water injection and sweep.
Statfiord Unit S1. The SI (Nansen Member) comprises high energy, shallow marine sandstones that form a continuous sheet of excellent reservoir quality sands (porosity 20-28%, permeability 500-3000 mD), ranging from 61 to 110 ft in thickness across the field. The high kv/kh ratio means the unit behaves as a single flow unit with excellent recovery efficiency. The position and shape of the oil rim is strongly influenced by the pattern of water and gas injection. Brent Group The Brent Group sediments range from up to 900 ft in thickness in the south of the field (Alpha Platform area) to 700 ft in thickness in the north (Delta Platform area). It is formally sub-divided into five formations (Broom, Rannoch, Etive, Ness and Tarbert), but field performance data has resulted in the Group being subdivided into four cycles (Cycles B 1, B2, B3 and B4) which describe the large scale flow units (Fig. 11). Each cycle is further sub-divided into a series of sub-cycles and sub-sub-cycles by abundant field wide coals and RFT pressure data which has defined internal barriers to vertical permeability. The Brent Group sediments were deposited in a range of sub-environments occurring within a shallow marine and coastal plain setting (Fig. 12).
Fig. 11. Brent Group type log.
Statfjord Unit $2. The $2 (Eiriksson Member) unit typically averages 80 ft in thickness and comprises a low to moderate N/G interval of overbank sheetflood sands with locally well developed, good quality (porosity 16-28%, permeability 100-2000 mD) channels encased in floodplain siltstones, shales and coaly palaeosol horizons. A thin shale bed present at the top of the $2 over large areas
Fig. 12. Brent Group depositional setting.
Brent B4 Cycle. The B4 comprises the oldest Brent Group sediments and is sub-divided into three sub-cycles equivalent to the Broom (B4.3) Rannoch (B4.2) and Etive Formations (B4.1 and B3.4). The B4.3 (Broom Formation) comprises a highly variable interval of coarse to fine grained, highly bioturbated sandstones that were deposited as distal lower shoreface sediments or offshore sandsheets interbedded with shales. The sands are dominantly of poor reservoir quality and are generally not in communication with the overlying B4.2. Lateral connectivity and oil recovery from this sub-cycle is poor. The B4.2 (Rannoch Formation) comprises an upwards coarsening sequence of stacked, fine to medium grained, micaceous shoreface sediments, of variable reservoir quality (porosity 20-25%,
BRENT FIELD permeability 10's-100'smD), ranging from 140 to 200 ft in thickness. It is further sub-divided into six parasequences (B4.2a-f) based on the recognition of distinct upwards coarsening packages, bounded by marine flooding surfaces (clinoforms) that can be correlated across the field. The parasequences define the pulsed progradation of shoreface sediments in a N W - S E direction. In the more proximal S-SE part of the field (Alpha Platform area) the dominantly sandy character of the parasequences results in good vertical communication throughout the B4.2 interval. Traced to the north and west however, the increasing distal and shalier character of the sediments results in individual parasequences acting as distinct flow units (Fig. 13) with limited aquifer support. The B4.1 (Etive Formation) erosively overlies the B4.2 and comprises a valley-fill sequence of well sorted, medium to coarse grained sandstones, of excellent reservoir quality (porosity 20-28 % permeabilty 1000'smD) representing an amalgamated sequence of fluvial to increasingly tidal channel sands. It ranges from 50 to 150 ft in thickness and the oil recovery is high, with the sweep depending upon the pattern of injectors and producers. Across much of the field, the B4.1 and the uppermost B4.2 are in communication, locally however a low permeability layer at top B4.2 hinders vertical communication and results in an uneven sweep of the uppermost B4.2. Within the Etive, low N/G, heterolithic intervals (B3.4) representing the abandonment and fill of tidal channel deposits are locally present. These sediments are best developed in the Alpha Platform area and north Charlie- south Delta Platform area (up to 30 ft in thickness); elsewhere the B3.4 comprises a ca. 10 ft shaley interval, capped by a field-wide coal. The low N / G B3.4 and shaley base to the overlying B3 Cycle serve to provide pressure separation between the B3 and B4 Cycles.
Brent B3 Cycle. The B3 Cycle (Lower Ness Formation) ranges from 180 to 200 ft in thickness and comprises a heterolithic interval of sandstones, shales and coals deposited in a lower coastal plain
243
environment (Fig. 14). It is further sub-divided into three sub-cycles (B3.1, B3.2, B3.3) by the occurrence of field-wide shale and coal intervals. Each sub-cycle exhibits an overall upwards coarsening trend depicted by a vertical transition from a lower interval of shoreface and/or mouthbar sands to an upper interval of channel sands (Fig. 15) Vertical communication, both between and within sub-cycles, is poor (Fig. 16). The channel belts are oriented E - W and are typically several miles in width. The channels exhibit good internal communication, although connectivity between channel belts is fair to poor. Individual shoreface and mouthbar sands range from several miles to field wide extent and whilst lateral communication may be good, vertical communication is locally poor. The best reservoir quality occurs within channel, upper mouthbar and proximal shoreface sands (porosity 21-27%, permeability 100's-1000'smD) with more variable, moderate to poor reservoir quality present within crevasse, lower shoreface and lower mouthbar facies. Oil recovery from the B3 is moderate to good, but the sweep pattern can be highly irregular and locally, individual sands may have been isolated from injection support.
Brent B2 Cycle. The B2 (Upper Ness Formation) thins gradually from south (c. 250ft) to north (170ft) and is further sub-divided into five sub-cycles based upon the occurrence of field-wide shales and coals. It comprises a heterolithic interval of coastal plain sediments, similar to the B3, although locally more shaley (B2.3) and with more marine influenced intervals (B2.5) present (Fig. 15). The lowermost B2.5 (Mid Ness Shale) comprises a thick (c. 10 to 20f t) marginal marine shale interval that forms an effective pressure barrier with the underlying B3 Cycle. The shale is overlain by an upwards coarsening sequence of shoreface sands that in the Alpha, Bravo and Charlie areas are incised into by W - E trending amalgamated channels. The B2.4 sub-cycle comprises an interval of stacked shoreface and wave-influenced mouthbar sands that are
Fig. 13. Brent Group E-W permeability cross-section through the Broom/Rannoch 3D geological model.
244
S. R. TAYLOR E T AL.
Fig. 14. Brent Group 3D geological model - Ness Formation. incised by channel sands in the Alpha and Bravo areas. The interchannel areas comprise floodplain siltstones and thin crevasse sands. Vertical communication is best within the southern part of the field, but decreases to the north as the amount of channel incision decreases. The B2.3 is a 20 to 30ft thick interval of aggradational floodplain shales and coals with minor thin, poor reservoir quality mouthbar and channel sands. This shaley interval forms an effective barrier separating the B2.1/2 and B2.4/5 across most of the field. The upper B2 (B2.2 and B2.1) exhibits an overall increase in more laterally extensive stacked channel sands encased within floodplain shales. The best reservoir quality occurs within channel, upper mouthbar and proximal shoreface sands (porosity 16-27%, permeability 100's-1000'smD) with more variable, moderate to poor reservoir quality present within crevasse, lower shoreface and lower mouthbar facies. As for the B3, oil recovery from
the B2 is moderate to good, but the sweep pattern can also be highly irregular and some sands may have been isolated from injection support.
Brent B1 Cycle. The B1 comprises the uppermost of the Brent Group sediments, typically ranging from 30 to 70ft in thickness and is further sub-divided into four sub-cycles which, with the exception of the uppermost BI.1 (eroded in South Alpha) can be correlated across the field. The B1.4, B1.3 sub-cycles and lower part of the B1.2 sub-cycle comprise the upper part of the Ness Formation whilst the upper part of the BI.2 and BI.1 sub-cycles are equivalent to the Tarbert Formation. The B 1.4 to B1.2 sub-cycles dominantly consist of fine to medium grained, upwards coarsening, shoreface deposits, interbedded with
Fig. 15. Facies cross-sections through the Lower and Upper Ness Formation 3D geological models.
BRENT FIELD
245
Fig. 16. Permeability cross-section through the Lower Ness Formation 3D geological model.
marginal marine and floodplain shales and coals. The shoreface sands are of variable, moderate to good reservoir quality (porosity 20-26%, permeability 10's-1000's mD) and locally, within the B1.4 and B1.3 are cut by thin, isolated channel sands. Several stacked shoreface sequences may be present within the sub-cycles and vertical and lateral communication is variable. The B I.1 comprises a coarsening upwards, shallow marine sandstone, representing a vertical transition from heavily bioturbated shoreface to massively bedded shallow marine/estuarine sediments. The sands are of excellent reservoir quality (porosity 2026%, permeability 1000's mD). Across much of the field, the BI.1 and B1.2 tend to act as a single flow unit, though some vertical separation can occur, as evidenced by differential movement of the OWC in some parts of the field.
Source There are two main source areas for hydrocarbons in the Brent Field: the Viking Graben and the East Shetland Basin. The dominant oil source rock is the Kimmeridge Clay Formation. In addition, the Brent Group coals and Heather Formation are capable of sourcing dry gas. The Kimmeridge Clay Formation reaches thicknesses of 1600ft in the East Shetland Basin and is over 3300ft thick in the Viking Graben. It has an average total organic carbon (TOC) of 5.6% (maximum 12.5%) in the East Shetland Basin (Goff 1983). The immature organic material is classified as Type II (degraded liptinite) kerogen and the non-soluble matter is dominantly sapropel (80%) with subordinate (20%) humic/coaly material (Brooks & Thusu 1977). Diagenetic studies suggest that the Brent Field structure was filled by early Eocene times (Sommer 1978). There are two vertical migration routes into the fault block crest; up the steep faulted eastern scarp and up the shallower western dip slope of the block. The nature of the hydrocarbons and the oil-water contact depths in the fields along the Alwyn to Statfjord fault terrace provide some evidence for lateral migration paths from the south to the north. Firstly, the reservoirs become less gaseous towards the north. The North Alwyn Field accumulations are gas condensate whilst the Brent Field reservoirs contain gas caps and the Statfjord Field reservoirs contain high G O R oil. Secondly, the progressive shallowing of the oil-water contacts towards the north, combined with the
filling of the hydrocarbon accumulations to their spill points, is indicative of a fill-spill type charge mechanism.
Hydrocarbons Both the Brent Group and Statfjord Formation reservoirs contain a reservoir fluid whose properties vary with depth. The variation can be explained by the action of gravity or possibly by recent migration of gas. The oil of the Brent Group reservoir has an average density of 30 ~ API, a viscosity of 0.26 cP and an initial G O R of 1600 SCF/STB. The saturation pressure is 4961 PSIa at 8800 ft TVSS. The composition of the Brent Group reservoir crude is: C1, 0,55; C2, 0.08; C3, 0.06; C4, 0.03; C5, 0.02; C6, 0.02; C7+, 0.22; N02, <0.01; C02, <0.02. The Statfjord Formation reservoir contains a supercritical fluid. Extensive fluid sampling has established that the hydrocarbon fluid column varies continuously with depth without a distinct gas-oil contact. The fluid column changes from a dew point fluid at the top to a bubble point fluid at the bottom, without a distinct phase change boundary. The transition occurs over an interval of about 100ft from 9100ft to 9200ft TVSS. The oil of the Statfjord Formation reservoir has an average density of 34 ~ API, a viscosity of 0.23 cP and an initial G O R of 2160 SCF/STB. The saturation pressure is 5170PSIa at 9400ft TVSS compared to the initial reservoir pressure at this depth of 6020 PSIa. The composition of the Statfjord Formation reservoir crude is: C1, 0.59; C2, 0.08; C3, 0.06; C, 0.03; C5, 0.02; C6, 0.02; C7+, 0.18; N02, <0.01; C02, <0.01.
Reserves and production This section provides a summary of petroleum in place, reserves, cumulative production and production rate followed by a brief synopsis of the field's development history.
Petroleum in place The Brent Field (including Brent South) has a currently estimated STOIIP of 3.8 MMMSTB and a GIIP of 7.5 TSCF, of which 6.1 TSCF is solution gas and 1.4 TSCF free gas. The initial in place volumes per major reservoir asset are given below.
246
S.R. TAYLOR E T AL.
West Flank
Slumps
Brent South
4458 2260
447 214
110 70
Statfjord Formation reservoirs GIIP (BSCF) 2209 STOIIP (MMSTB) 1090
200 98
62 10
Brent Group reservoirs GIIP (BSCF) STOIIP (MMSTB)
97 000 BBL/D in 1999. Prior to 1998, gas was produced at a rate of some 500 MMSCF/D. In 1999, produced gas volumes rose to 866 MMSCF/D; the highest ever in the field's history. With the initiation of depressurization in 1998, gross liquid production was 625 000 BBL/D, another record for the field. Also the Brent Field's busiest year ever in terms of the number of well entries and string months was 1999.
Summary of field development The Brent Field STOIIP and GIIP (excluding Brent South) estimates have only undergone minor changes (STOIIP >5%; GIIP > 10%) since 1991 (Struijk & Green), with the upward revisions reflecting changes to hydrocarbon saturation models, PVT descriptions and adjustments to the Statfjord reservoir solution GOR. Petroleum reserves
The current estimated ultimate recoveries from the Brent Main Field (excluding Brent South) are 1950 MMSTB of oil and condensate and 5918 BSCF gas with approximately two-thirds coming from the Brent Group reservoir and one-third from the Statfjord Formation reservoir. The estimated ultimate recovery from the Brent South accumulation is 38.4 MMBBL oil/condensate and 79 BSCF gas. A significant revision to ultimate recovery occurred in 1992, when the decision was taken to depressurize the Brent Field to recover an additional 1.5 TSCF of gas and 34 MMSTB of oil. With the de-pressurization project now well advanced, it is worth noting that oil ultimate recovery is virtually unchanged from that in the 1992 plan that formed the basis for project sanction. Gas ultimate recovery has been increased, due to a reduction in expected critical gas saturation (Ligthelm et al. 1997). Cumulative production
Total production as of 1.1.2000 was 1875 MMSTB oil/condensate and 4196 BSCF gas which includes 33.5 MMSTB oil/condensate and 54 BSCF gas produced from Brent South.
Production rate
Plateau oil production of some 400000 BBL/D was maintained from 1983 to 1986 (Fig. 17). Thereafter production declined to
Fig. 17. Brent Field production history plot.
The original oil rims were c. 500 ft thick with all the layers within the Brent or Statfjord reservoirs having common contacts. The primary development scheme involved dedicated crestal producers for the Statfjord reservoir and dedicated mid-oil column producers for the Brent reservoir. Pressure support for both reservoirs was provided by down-dip water injection and crestal gas injection. Oil production began in November 1976, but due to the lack of a gas export system, all the produced gas beyond the fuel and flare requirements had to be re-injected into the reservoirs. As a result, the initial development of the field concentrated on the lower G O R oil found in the Brent B3 and B4 cycles; most of the produced gas was also re-injected into these zones to maintain the reservoir pressure. Water injection to provide pressure support commenced in 1979. In May 1982, the FLAGS gas export system became available and gas export began, leading to increased development activity on the higher GOR Brent B1 and B2 cycles and the Statfjord reservoir. To maximize oil production, gas re-injection continued even after gas export began, and was focussed more on the B1, B2 and S1 reservoir zones. At some stage in the field's development, gas has been injected into all the Brent and Statfjord cycles, with the greatest quantity, of over 380 BSCF, having been injected into the Statfjord S1 reservoir. This laterally extensive, high permeability, shallow marine sandstone is an ideal gas storage reservoir. It also had the added advantage of first contact miscibility between the reservoir oil and the injected separator gas (Jense et al. 1988). As down-dip oil completions watered out, the wells were either re-completed on a higher cycle, or sidetracked to a structurally higher position within the oil rim. A selective cycle-based completion policy was maintained during development of the oil rims. This development strategy, combined with the highly stratified nature of both reservoirs led to the evolution of numerous thin oil rims which, with continuing production, have become thinner and moved upwards into the originally gas bearing crest of the West Flank. The current oil rims are typically 50 to 100ft thick. The contacts have been moving by up to 20-30 ft per year, and gas, oil,
BRENT FIELD and water can occur in any sequence in a vertical section of different reservoir layers. The systematic and regular mapping of gas-oil and oil-water contacts, within each of the Brent and Statfjord reservoir units and areally across the West Flank is the key to depressurization reservoir management and identifying remaining oil infill targets. The process of systematically and regularly mapping the gas-oil and oil-water contacts requires the rapid integration of all recent field observations (e.g. well production characteristics and surveillance data) together with geological knowledge of the structure and internal facies/sediment architecture, well status and location (Gallagher et al. 1999; Quint 1999). The remaining rims are being actively developed through recompletions and new sidetracks.
Fig. 18. Brent Lower Ness Formation geological model
Fig. 19. Brent Field depressurization process.
potential bypassed oil.
247
In addition to defining the distribution of the oil rims, significant effort has gone into locating poorly swept zones behind the main flood front. By its very nature, well surveillance data in the flooded part of the field is limited and hence the balance of work to define by-passed fluid distribution tends more towards predictive modelling as opposed to observation. This modelling is based on highly detailed 3D descriptions of the reservoir's porosity and permeability architecture (James et. al. 1998). Fine scale simulation of these 3D descriptions, incorporating all injection and production history in the area of interest, enables movement of the flood front to be determined and potentially poorly swept zones identified (Fig. 18). The predictive capability of this analysis was proved with a recently drilled enhanced voidage well.
248
S. R. TAYLOR E T AL. with poor connectivity to the West Flank. In contrast, pressure data, tracer data and production behaviour have shown that the Brent Slumps have varying connectivity to the West Flank with significant cross-flow occurring in certain areas. The construction of a detailed 3D geological model considerably improved the understanding of the 3D geometry of the Brent Slumps complex (Fig. 6), a fact that has been of critical importance
A targeted development of the Brent Slumps commenced in 1994 with the drilling of a number of horizontal wells oriented eastwest through the Slump complex (Coutts et al. 1997). Dedicated water injection support was provided by four of the wells. Comparable development of the Statfjord Slumps with horizontal wells began in 1996. Production performance of the Statfjord Slump wells indicated that the complex is internally highly compartmentalised (a)
Brent Field - Brent Reservoir West Flank Pressures Actual v.1992 Depressurisation Plan 6500
6000 "t,J~."
";
5500
'~,',,
"
9
"'
"
",'i:-"-.-
"
~"
. ' " :
~ J ~ "~ i ' ~ ' :
~,j~:C~:~;l~,;,.,~,.'-'~.,..-
.
"|
*
9
9
~,:.-~,
...':
."
"
'"'
~" '"
.9 " ' . : . " "
~
; ;""
."
"'"
:'L "
:..:'" ,'.
"
i...-t
....--.5000
",r ' ' N . _ " 9
,
.I
"t .*
'
r
,~ .....
9
.
4500
E 4000
.,.---- 1992 D e p r e s s u r i s a t i o n Plan 9 x
3500
Main Block Delta Platform a r e a - Horst/Graben
x o
3000 r
h-
OO
O3
O3
O30"~
O~
(b)
C)
---
O30~
r
03
O3
O30~
~
tr
qD
I~=
O3
O3
O30~
~O
O~
O
O~
O~
~
~
03
~
O30"~
~
r163
I'~
O0
O~
O~
O3
O3
O3
O30
O
Brent Field - Statfjord Reservoir West Flank Pressures Actual v.1992 Depressurisation Plan 6500 ~
"":~
6000
9
9
ask
:.
9 ~;,~.J',,.:~v,~.-~,:.
s :.."
~"
,
.
L
5500
9
9
,
~.!~
v
.
:.~.
,-.-, 5000 :." G
:,
4500
E 4000
9- , - -
1992 D e p r e s s u r i s a t i o n Plan
9 >:
3500
3000 qO t~. O~
Main Block Delta Platform a r e a - HorstlGraben
l
!
r
!
i
if
l
i
i
i
i
l
v
v
i
i
!
I'~ hO~
CO I~O')
O~ I~O~
C) CO O~
,vQO 03
~ O0 03
03 O0 03
"~" CO O~
143 O0 O~
tO O0 03
~ GO 03
O0 00 O~
03 OO or)
O 03 03
,v03 03
@q 03 03
03 03 03
Fig. 20. Brent Field pressure plots.
T
~ 03 03
v
i
I
i
I
LO 03 03
qD O~ 03
h~ O~ 03
CO O~ 03
03 (3] O~
C~ O O
BRENT FIELD to maximizing value from the Brent Slumps asset. Integration of the geological model with the complex production history of the Brent Slumps highlighted the impact reservoir architecture has on hydrocarbon recovery, both in terms of fault block connectivity within the Slumps, and their juxtaposition with the West Flank of the field. High quality reservoir within the Slumps has been preferentially swept, particularly in the proximal blocks nearest the West Flank. However, the distal (more easterly) blocks and poorer quality reservoir in the proximal blocks have been very poorly swept. The creation of a realistic integrated static/dynamic model improved the confidence of predicting the location of target reservoir zones for a horizontal well infill campaign that commenced in 1999 and continues into 2000. The 1992 re-development plan (Braithwaite & Schulte 1992; Schulte et al. 1993; Linthorst et al. 1997) is to depressurize the reservoir in order to release solution gas from the bypassed (unswept) and remaining (swept) oil. The gas is produced once it has migrated to the crest of the structure (Fig. 19). Depressurization will recover an additional 1.5 TSCF of gas and 34 M M S T B of oil, extending the field's life by 5-10 years. Initially the depressurization is aimed at the West Flank of the Brent and Statfjord reservoirs with water injection helping to optimize recovery in Brent South, and locally in the crestal slumps, for some years. Maintaining sufficient gross liquid production from the start of depressurization in 1998 has necessitated installing gas lift in a number of wells. As the reservoir pressure declines, rates from gas-lifted wells will reduce and a number of high rate electric submersible pumps (ESPs) will be installed to enhance voidage and fully depressurize the reservoir; the so called Enhanced Voidage project. The management of the depressurization process is described fully in Gallagher et al. (1999). Some two years after ceasing West Flank pressure maintenance, reservoir performance is, in broad terms, according to the 1992 plan that formed the basis for project sanction. West Flank reservoir pressures are declining in line with this plan (Fig. 20a); a few points lie below the line, but these tend to be localized production effects in heterogeneous cycle B3 sands where thin coals and/or shales act as baffles to flow. In the more structurally complex Horst and Graben area the scatter in the data is larger, both before and after the start of depressurization. However, here too, pressures are generally in line with plan. In the Main Block Statfjord reservoir, the pressure data situation is similar (Fig. 20b), although pressures in all areas of the field lie within a much tighter band than in the Brent reservoir, reflecting the higher average net/gross, and the completion strategy of co-mingling the Eiriksson Member. Field surveillance data show that the gas cap size is, as predicted, stabilising at reservoir conditions and that the gas caps are being replenished by gas liberated from the swept zone and the remaining thin oil rims. Oil production rates and the results of new wells are in line with the 1992 plan. The authors thank Shell UK and Exxon/Mobil International Ltd. for giving permission to publish this paper.
Brent Field data summary Brent Reservoir
Statfjord Reservoir
Trap
Type Depth to crest Lowest closing contour Gas/oil contact Oil/water contact Gas column Oil column
Unconformity: tilted fault block 8240 ft TVSS 9 000 ft TVSS 9300ft TVSS 10 700 ft TVSS 8560 ft TVSS 9 100 ft TVSS 9040 ft TVSS 9 690 ft TVSS 320 ft 100 ft 480 ft 590 ft
Pay zone
Formation Age
Brent Group Middle Jurassic
Statfjord Formation Lower Jurassic/ Triassic
Gross thickness (average/range) Porosity (average/range) Permeability (average/range)
249 810 ft; 780-850 ft 21%; 16-28% 650 mD; 10-6000 mD
850 ft; 800-1000 ft 23%; 16-29% 500 mD; 20-10 000 mD
Hydrocarbons
54.7 Ibm/ft 3 Low sulphur light crude 0.74 Gas gravity 4326-5750 psia Saturation Pressure 1.58 KSCF/STB Gas/oil ratio (average) 138 BBL/MSCF Condensate yield Formation volume factor 1.80 BBL/STB (average) Oil gravity Oil type
53.0 Ibm/ft 3 Low sulphur light crude 0.76 4400-5625 psia 2.17 KSCF/STB 268 BBL/MSCF 2.04 BBL/STB
Formation water
Salinity Resistivity
25 000 ppm NaCI eqv 0.236 ohm m at 77~
24000 ppm NaCI eqv 0.270ohm m at 77~
204~ 5785 psia 0.274 psi/ft (oil)
218~ 6020 psia 0.256 psi/ft (oil)
Reservoir conditions
Temperature Pressure Pressure gradient in reservoir Field size
Area 30 sq miles Drive mechanism Water injection, gas injection; depressurization Recoverable oil/ 1988 MMBBL condensate Recoverable sol./free gas 6 TSCF Production
Start-up date Development scheme Production rate (1999) Cumulative production 1/1/2000
November 1976 4 platforms: export by tanker & pipeline 97 000 BBL/D oil and 866 MMSCF/D gas 1875 MMBBL oil and 4196 BSCF gas
References BRAITHWAITE,C. I. M. & SCHULTE,W. M. 1992. Transforming the Future of the Brent Field." Depressurisation - The Next Development Phase. Paper SPE 25026 presented at Europec, Cannes, France, 16-18 November 1992. BROOKS,J. & THUSU,B. 1977. Oil source identification and characterisation of Jurassic sediments in the northern North Sea. Chemical Geology, 20, 283-294. COUTTS, S. D., JURGENS, T., VAN KESSEL, O., PRONK, D. & WARD, V. C. 1997. Phase 2 development of the slumped crestal area of the Brent reservoir, Brent Field. Paper SPE 38476 presented at Offshore Europe, Aberdeen, Scotland, 9-12 September 1997. DEEGAN, C. E & SCULL, B. J. 1977. A standard lithostratigraphic nomenclature for the Central and Northern North Sea. Institute of Geological Sciences Report 77/25. GALLAGHER,J. J., KEMSHELL, D. M., TAYLOR, S. R. & MITRO, R. J. 1999. Brent Field Depressurization Management. SPE 56973 presented at Offshore Europe 99, Aberdeen. GOFF, J. C. 1983. Hydrocarbon Generation and Migration from Jurassic Source Rocks in the East Shetland Basin and Viking Graben of the Northern North Sea. Journal of the Geological Society, London, 140, 445-474. HUTCHINSON, J. N., BROMHEAD, E. N. & CHANDLER, M. P. 1991. Investigations of landslides at St Catherine's Point, Isle of Wight. In: CHANDLER, R. J. (ed.) Slope stability engineering; developments' and applications. Thomas Telford, 169-179. JAMES, S., PRONK, D., ABBOTS, F., WARD, V., VAN DIERENDONCK, A. & STEVENS, D. 1998, The Brent Field: improving subsurface characterisation for late field life management. In: FLEET, A. J. & BOLDY,S. A.R
250
S. R. TAYLOR E T AL.
(eds) Petroleum Geology of N W Europe: Proceedings of the 5th Conference. Geological Society, London, 1039-1049. JENS~, A. G. C., DING, C. N. & SMITH, 1. F. 1988. Reservoir Management in the Brent Field. Norwegian Petrolemn Society, Stavanger. LIGTHELM, D. J., REIJNEN, G., WIT, K., WEISSENBORN, A. J. & SCHERPENISSE, W. 1997. Critical gas saturation during depressurisation and its importance in the Brent Field. Paper SPE 38475 presented at Offshore Europe, Aberdeen, Scotland, 9-12 September 1997. LINTHORST, S. J. M., VAN STIPHOUT, M. T. & COUTTS, S. D. 1997. The Brent Full Field Model- The reservoir management tool for depressurisation. Paper SPE 38474 presented at Offshore Europe, Aberdeen, Scotland, 9-12 September 1997. P~TTS, J. 1983. The temporal and spatial development of landslides in the Axmouth-Lyme Regis undercliffs National Nature Reserve, Devon. Earth Surface Processes and Landjorms, 8, 589-603. QUINT, E. 1999. Monitoring Contact Movement in Depressurizing Brent Reservoirs. Paper SPE $6951 presented at Offshore Europe, Aberdeen, Scotland, 7-9 September 1999.
SCHULTE, W. M., VAN ROSSEM, H. & VAN DE VIJVER, W. 1993. Current Challenges in the Brent Field. Paper SPE 26788 presented at Offshore Europe, Aberdeen, Scotland, 7-10 September 1993. SOMMER, F. 1978. Diagenesis of Jurassic Sandstones in the Viking Graben, Journal of the Geological Society, London, 135, 63-67. STP,UIJK, A. P. & GREEN, R. T. 1991. The Brent Field, Block 211/29, UK North Sea. In: ABOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, Memoirs, 14, 63-72. VAN DER PAL, R., BACON, M. & PRONK, D. 1996. 3D Walkaway VSP, enhancing seismic resolution for development optimisation of the Brent field. First Break, 14, 463-469. VAN DIERENDONCK,A. I., PRONK, D. W. & WARD, V. C. 1997. New Seismic on an old Field." The impact of the 1995 Brent 3D seismic survey. Paper SPE 38471 presented at Offshore Europe, Aberdeen, Scotland, 9-12 September 1997.
The Deveron Field, Block 211/18a, UK North Sea A. M. B R O W N & A. D. M I L N E 1 BP, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB, UK (e-mail: brownam @bp.com) 1Present address." 90 Hamilton Place, Aberdeen AB15 5BA, UK (e-mail:
[email protected]) Abstract: Cumulative oil production at the end of 2000 was 15.4 MMBO, which for a STOIIP of 61.3 MMBO, represents a recovery to date of 25%. Deveron shares facilities on the Thistle Alpha platform and has been on production since 1984, from two (originally three) deviated platform wells. The performance of these wells has been steady, subject to well and plant uptimes. Field management activity continues to focus on monitoring and maintaining the two production wells, and defining field and production enhancement opportunities.
The Deveron Field lies in Block 211/18a in 530ft of water, approximately 580km NE of Aberdeen (Fig. 1). The field is a small, structurally trapped oil pool lying approximately 2 km W of the neighbouring Thistle Field (Fig. 2). Deveron is a satellite development with extended reach wells drilled from the Thistle platform. Hydrocarbons are produced to the Thistle Platform and the oil is transported by pipeline via the Dunlin platform and then the Brent Pipeline System to the Sullom Voe Oil Terminal.
History The field was discovered and tested in 1972 by the first well in Block 211/18-1. Subsequent activity in the block focused on the very much larger Thistle accumulation, as well as other pools (e.g. Don), to the extent that the first appraisal well on Deveron was platform well A44, which was drilled in 1982, and put on extended test in 1983. On the basis of this appraisal data, Development and
Fig. 1. Location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 251-255.
251
252
A . M . BROWN & A. D. MILNE
Fig. 3. Top reservoir structure map.
Key PRT Fences Block Boundaries
.......................................
Boundaries for Don Unit and Area DSW
Fig. 2. Thistle area fields.
Production Consent Approval was granted in 1984 and production began via well A44. In 1985, well A48 was drilled on a more northerly target and penetrated the reservoir below the field oil-water contact of 8910ft sub-sea, approximately 400ft higher than the Thistle Field contact (Fig. 3). This well was sidetracked to the east as A48Z. With these two wells, Deveron oil production reached a peak of 6500 BOPD in 1986. In 1988, a third well, A51, was drilled as a southerly producer. There has since been no further drilling activity on Deveron, with well A48Z being suspended in 1992. This was caused by inadvertently milling through the casing while attempting to remove a damaged section of pipe. While provisions were made for water injection into the field to provide pressure support this was considered unnecessary on the basis of initial field performance. The original Field Development Plan (Oct 1983) was expected to recover approximately 14 M M B O with three producers and one water injector well, and an end of field life expected in the year 2000. At the end of 2000 over 15 M M B O was produced from three producers therefore no water injection wells were required. Although Deveron is produced exclusively through the Thistle platform, it has separate field status, and has separate Petroleum Revenue Tax boundaries. Deveron oil is co-mingled with Thistle production and is allocated on the basis of well tests.
The originally complex partnership splits in Licence P236 have been simplified considerably in recent years, to the extent that in Deveron there are now only two equity holders: BP Amoco (Britoil plc) (81.72%) and Conoco (UK) Theta Ltd (18.28%). The history of Licence P236 and the Deveron Field has been detailed by Williams 1991.
Discovery The Deveron Field was discovered in 1972 with well 211/18-1, which encountered 65 ft of oil in Upper Jurassic Brent Sand at a depth of 8845 ft sub-sea. Subsequent drilling proved a gross oil column of 260 ft.
Field stratigraphy The stratigraphy of the reservoir sequence found in Deveron wells is broadly typical for this part of the Brent Province (Fig. 4). However, in detail, correlation between these wells is complicated, due to the prevalence and dip of faults, and also to the relatively high angle of individual wellbores. This uncertainty is crucial in reservoir description, particularly in defining isochores of reservoir units. An additional complication is the evidence from biostratigraphy of diachronism between some wells in the youngest part of the Brent sequence.
Structure Deveron lies close to the edge of the Viking Graben, and is a typical, albeit small, example of a Brent Province oilfield. The trap
DEVERON FIELD
is an easterly dipping rotated fault block, with closure up-dip to the west, and to the north, being defined by large scale faulting, and to the east and south, by structural dip (Fig. 3). Well control is provided by five wells, mostly located high on the crest of the structure. Structural definition of the field has been historically based on the 1983 Thistle/Deveron 3D seismic data set. However, a second 3D survey, centered over neighbouring Block 211/18b and acquired in 1989, has been used in reviewing further possible reservoir options. This dataset confirms the earlier picture of the Deveron Field as an asymmetric four-way dip closure at Base Cretaceous level, with the underlying Jurassic and older section cut by N-S, N W - S E and N E - S W faulting. Within this closure and beneath a thin Humber Group shale section, the reservoir is interpreted as thickening downdip off-structure, reflecting a combination of condensed deposition and erosion over the higher parts of the structure.
253
Geophysics Deveron and the northern part of Thistle are entirely covered by the 1989 3D seismic survey. This survey provides the basis for most of the current understanding of the Deveron reservoir. These data were re-interpreted in 1997, using conventional workstation techniques, as well as attribute mapping. The newer data, combined with these modern interpretation techniques, give better correlation and definition of faults, and greater confidence in their interpretation, particularly of the smaller displacement faults. In an area that is known for poor seismic reflection quality, due probably to gas charge in the mainly shaly post-Jurassic section, the survey data are at best of moderate quality. While Base Cretaceous is a characteristically strong event, deeper reflectors are less well defined, although better than in the original 1983 3D survey. Top
254
A. M. BROWN & A. D. MILNE
Brent is a particularly weak reflector with the higher parts of the structure usually obscured by tuning effects associated with the shallower Base Cretaceous event. However, Top Rannoch Shale, which equals base effective reservoir, does have acoustic expression and is mappable, as is a Top Statfjord event. The Top Brent Map has been produced by subtracting a geologically derived Brent reservoir isochore, based on well control, from the seismically defined Top Rannoch Shale. Structurally, the 1989 data set confirms much of the earlier picture of the Deveron Field. The only substantial difference relates to northerly closure to the field. The original interpretation had closure effected by E N E - W S W faulting (Fig. 3). The recent reinterpretation has a more pronounced northerly component to this faulting, which makes the field open to the north.
Reservoir The Deveron reservoir comprises mostly high quality sandstones (Fig. 4), with porosities averaging 24% and permeabilities of up to three Darcies. As with most Brent sections, the reservoir is a layered sequence with a degree of pressure isolation vertically between zones. This has been amply demonstrated by the behaviour of the three production wells on the structure, and underpins the strategy of successive perforation of undrained zones. In addition, lateral reservoir continuity appears to be good, subject locally to the potential effects of fault-related compartmentalization. Reservoir drive is from active natural aquifer support. Unusually for a Brent reservoir, there are no supporting water injectors. Initial extended testing on Deveron well A44 suggested the presence of a large and active, well connected aquifer. This has been borne
Fig. 5. Production and water injection profile and watercut development.
out by subsequent experience, since Deveron reservoir pressure has been largely maintained, despite a long term off-take of 10000 barrels of fluid per day. Further evidence that testifies to the high degree of regional connectivity in the Brent reservoir in the Deveron area is that produced water from the Deveron wells is typically entirely formation water, however in the late 1980s traces of sea water were detected. Since contamination of samples was considered and discounted, this sea water was attributed to injection water, derived most likely from the nearest accessible part of Thistle main field, the Southern Fault Block.
Fluids Deveron oil is a highly undersaturated, low sulphur crude of 38 ~ API gravity. Chemically it is a typical Brent Province crude, derived from the prolific Kimmeridge Clay Formation. Reservoir pressure is 5000psi at 8800 ft TVDss, indicating a modest degree of overpressure. Produced water is essentially pure formation water, with dissolved solids of 23 500ppm. Because of the water's consequent scaling tendency (Barium Sulphate), Deveron wells typically need to have scale inhibitor squeeze treatments at regular intervals, which can have a negative impact on productivity indices. Scale can also be a problem at the surface with separators handling Deveron wells.
Reserves The 1997 seismic remapping, well correlation and volumetrics resulted in an upgrading of Deveron Field STOIIP to 61.3 MMBO. The previous STOIIP carried had been 45.3 MMBO, based on an
DEVERON FIELD
earlier cross-section study in 1990. The main reason for the increased volume is a larger bulk rock volume, resulting from a more optimistic Top Brent depth map. Deveron production from field start-up in 1984 to end 2000 is illustrated in Figure 5. The only remaining p r o d u c t i o n well is presently producing at a r o u n d 400 B O P D , and water-cut is over 90%. C u m u l a t i v e oil p r o d u c t i o n to end 2000 is 15.4 M M B O , representing a field recovery to date of 25%. The m a i n threat to realising remaining reserves is well integrity. Indeed, well A51 in particular is p r o n e to sanding and the well is currently shut-in. Possible e n h a n c e m e n t s to D e v e r o n production, in addition to regular well m a n a g e m e n t and interventions, have been and continue to be considered.
Devonian Field data summary
Gas-oil ratio Condensate yield Formation volume factor Gas expansion factor
255 150 SCF/BBL BBL/MMSCF 1.133 RB/SCF SCF/RCF
Formation water
Salinity
13 000
Resistivity
NaC1 eq ppm 23 500 prom tds 0.253 ohm m
Field Characteristics
Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor
512 acres 50 000 acre ft 4700 psig psi/ft 220~ 54 MMBBL BCF 28.5%
Drive mechanism
Depletion
Recoverable oil Recoverable gas Recoverable NGL/condensate
15.4 MMBBL BCF MMBBL
Trap
Type Depth to crest Lowest closing contour Gas-oil contact Oil-water contact Gas column Oil column
Rotated fault block/dip 8700 TVDss ft 9000 TVDss ft None ft 8910 TVDss ft None ft 210 ft
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Brent group Middle Jurassic 450 ft ft 24 (16-30) (100-3000)mD 70% BOPD/psi
only 16% in Area 6; Thistle 50% Strong aquifer support
Production
Start-up date
Pay zone
at 8800 TVDss
Production rate plateau oil Production rate plateau gas Number/type of well in 2000
September 1984 ERD from Thistle Platform 2-3 km 7000 BOPD MCF/D 3 platforms; 1 abandoned in 1 producer Oct 1992 + 1 closed in 2000
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point
38 ~ API Light, low sulphur
Reference
1.05 cp at 4500psia 617 psig psig
WILLIAMS, R. R. 1991. The Deveron Field, Blocks 211/18a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Field~: 25 Years Commemorative Volume. Geological Society, Memoir, 14, 83 87.
The Don Field, Blocks 211/13a, 211/14, 211/18a, 211/19a, UK North Sea A. D. M I L N E 1 & A. M. B R O W N
BP, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB, UK (e-mail:
[email protected]) 1Present address." 90 Hamilton Place, Aberdeen AB15 5BA, UK (e-mail."
[email protected])
Abstract: Cumulative oil production to the end of 2000 from the Don Field was 15.4 MMBBLS, which with an estimated STOIIP of 152 MMBBLS represents a recovery to date of 10%. Don has been producing for over ten years. The field lies 15 km N of the Thistle Field, at the western edge of the Viking Graben in the northern North Sea. The structure of the field is complex, and it comprises several segments, the two largest of which have been developed, Don NE and Don SW. The reservoir sequence is Middle Jurassic Brent Formation, but more deeply buried and of a more distal facies than is typical for other fields in the province. The Don Field is a sub-sea development tied-back to the Thistle platform, and Britoil (BP) is the operator. The field has been developed with five producers, three in NE and two in SW, with a supporting water injection well in each part of the field. All wells have been drill deviated from a seabed manifold located over Don NE.
The D o n Field is located in over 500ft of water, some 5 9 0 k m northeast of A b e r d e e n (Fig.l). The field lies in Blocks 211/18a and 211/19a, and extends n o r t h w a r d s into 211/13a a n d 211/14. Its nearest neighbours are the M a g n u s Field to the northwest, and Thistle to the south (Fig. 2). H y d r o c a r b o n s are p r o d u c e d to the
Thistle Platform and the oil is transported by pipeline via D u n l i n platform and then the Brent Pipeline System to the Sullon Voe Oil Terminal. Two eight inch pipelines, approximately 17 k m long, link the D o n Field with the Thistle platform. One line is for p r o d u c t i o n and the second line carries injection water to the field.
Fig. 1. Regional setting of the Don Field. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 257-263.
257
258
A . D . MILNE & A. M. BROWN
Fig. 3. Top Don reservoir structure map.
Fig. 2. Don Field location map.
History The licence P236 was awarded in the U K C S 4th Round in March 1972 to the Halibut Group led by Signal Oil Company. The field was discovered and tested in 1976 by the first well on the Don SW structure, 211/18-12, followed the same year by 211/18-13 on D o n NE. A total of seven appraisal wells were drilled subsequently to define the structure, before the first development well in 1989. There were also a further three oil bearing wells on terrace features immediately to the south of the field. The originally complex partnership splits inherited from Licence P236 and adjoining blocks in neighbouring licences have been simplified considerably in recent years, to the extent that in D o n there are now only two equity holders:
BP Amoco (Britoil plc, operator) Conoco (UK) Theta Ltd
Don NE
Don SW
80.3% 19.7%
58.3% 41.7%
The seven appraisal wells drilled in the 1980s confirmed not only the field limits, but also its geological complexity, (Figs 3 and 4).
Each well encountered different fluid contacts with different reservoir and fluid properties indicating reservoir compartmentalization. A 3D seismic survey was acquired in 1983 and repeated in 1994. Due to suspected reservoir compartmentalization a phased development strategy was adopted to mitigate risks and allow maximum flexibility. A 17 km sub-sea tie back to the Thistle Platform was selected. First oil was achieved in late 1989 and the field has been on constant production since then. Individual wells have reached maximum sustained production rates of c. 8 MBOPD. However initial production results were disappointing and water injection support has had mixed success. In the late 1980s the development of the Don Field satellite was seen as an important part of the late-life strategy of the Thistle Field and platform, whereby new production from Don would compensate for the decline on Thistle. Prior to field development an Annex B document was submitted in 1988, which presented the case for a phased development of the field. Phase 1 was intended to drill two production wells on Don NE, with the option for a supporting water injector. Phase 2 allowed for further drilling of D o n NE, plus initial development of Don SW. Phase 3 was full development of the field. The initial concentration on D o n N E was based on the view that reservoir quality was better in this part of the field, even though the in-place oil volume in D o n N E was smaller than Don SW (58 v110 M M B O in the volumetrics of the day). This view derived from the interpretation of Productivity Indices calculated from drill stem tests on appraisal wells, backed up by inferences from petrological studies of core material. The plan was to place a seabed production and injection manifold over the Don N E discovery well, to export oil back to the Thistle platform via an 8" pipeline. The discovery well 211/18-13 was re-entered and completed as (vertical) production well N01, in M a y 1989. A second well, N02, was then drilled in July 1989 and deviated N N W into a separate fault segment from the same surface location. Both wells were put
DON FIELD
259
Fig. 4. Seismic section across Don NE (SW to NE).
on stream and for a short time were flowed at 23 000 BOPD for a test of the pipeline potential. Subsequently combined flow dropped quickly to below 10 000 BOPD and the drop in bottomhole flowing pressure indicated a loss of reservoir pressure of approximately 100 PSI per day. Bubble point was quite low at c. 2950 psi, however there was clearly a need for pressure support in the form of a water injection well. The source of the problem was attributed to faultrelated compartmentalization. After detailed scrutiny of the seismic data it was decided to drill the injector in support of the N02 producer, on the basis that this part of the field appeared less complex, the pressure decline on initial production had been less dramatic, and the mapped oil volume was greater. The background to this well, and the contingency plans that were made, have been described in detail by Richardson et al. (1991). The N03 water injection well was then drilled in September 1990 and found substantial depletion in the reservoir, indicating communication in this part of the field. Once it was put on stream the injector immediately had a beneficial effect on N02, with the result that this well produced 6 M M B O in its lifetime, as had been anticipated in the Annex B. The N01 well had received no pressure support from the N03 water injector. Reservoir pressure continued to fall and the well was shut in as it approached bubble point. Apart from the late stage depletion production discussed below, well N01 has produced less than 1 MMBO. In the Annex B the expectation had been 16 MMBO. This very major discrepancy was attributed to faulting close to the west of the well, which had not been recognized on the original processing of the 1983 Don 3D seismic survey. The next stage of the Don N E development was to drill a third producer, N04, to the west of N01, i.e. the area that N01 was intended to drain in the original plan. On seismic this area appeared
structurally undisturbed. The N04 well was drilled in November 1990 and an oil-water contact was encountered 90 ft shallower than expected from earlier wells. When this well was put on production it proved to be in communication with only a small connected volume. The well has only produced 0.4 M M B O and the crude produced has different properties (higher API gravity, lower GOR) than the earlier Don N E producers. The initial Phase 1 development of D o n N E had drilled three producers and one water injector, all from the same central manifold. After a review of the seismic data a location for the first Don SW well was chosen in an area of apparent structural simplicity. The well was spudded from the Don N E manifold, the rationale being that the well could then be completed and put on stream immediately. The alternative option, to drill a vertical well and then tie it back via a flowline to existing D o n production facilities, was rejected because of the delay to startup of production caused by installation of the flowline. The well, N05, was spudded in April 1993 as a 4 km stepout from the sub-sea manifold. At Jurassic target level, the well encountered a major surprise when it drilled hydrocarbon bearing Brent only 35 ft thick, sitting directly on dated basal Dunlin age mudstones. This meant that the well, located in a seismically quiet area, had drilled through a fault of at least 550 ft displacement. The well was then sidetracked to a location 130 m N N W of the initial penetration and encountered a fuller Brent section. After penetrating the Brent, which again was reduced in thickness because of a fault, the well drilled Dunlin and Statfjord Formations and terminated in Triassic. The well was completed and the Brent was tested. The well was put on stream in September 1993 and has continued to flow dry oil until recently. Significantly the Statfjord sandstones were hydrocarbon-bearing, with an oil-water contact corresponding to that predicted for the Brent in D o n SW. The
260
A . D . MILNE & A. M. BROWN
crude properties of the N05Z well are identical to those of the earlier Don SW wells, 211/18-12 and 211/18-21. From the experience on D o n NE, it was expected that the N05Z well would drain only a small compartment. However, from the surprises encountered in drilling N05 and N05Z, confidence that the existing seismic survey accurately imaged the Jurassic reservoir was low. It was decided to re-shoot the 3D seismic over the entire D o n Field. This was done from November 1993 through to January 1994. The data were processed and interpreted, and a new reservoir simulation model built in early 1994. The new reservoir model indicated that given the reservoir layering peculiar to Don an injector well located down-dip from N05Z would flood out the producer prematurely. While the injector would accelerate production initially, it would quickly kill the well, to the extent that the incremental production would not pay for the injection well. Alternative injector locations were considered but were deemed risky. In addition, the production decline from the N05Z well proved to be much less than had been anticipated, implying a much larger connected fluid volume. Material balance calculations suggested that the well was connected to a volume at least as great as the entire STOIIP of D o n SW. This indicated the requirement for a water injector to support N05Z production was much less urgent than had been originally thought. Consequently it was decided to drill a second production well in a crestal position in Don SW; N06 was spudded in November 1994, close to the original discovery well, 211/18-12. This well was another 4 km stepout and encountered a number of drilling problems which added considerably to the well cost. It was completed successfully, although the upper high permeability horizon was partly faulted out. Significantly, this well did register some pressure depletion due to N05Z production. Well N06X was put on production and is still online today. Crude properties are the same as for the earlier Don SW wells. The last well drilled to date in Don SW was the N07 water injector, spudded in June 1996. The benefits of this well were predicated by the apparently widespread pressure communication within the field, and the consistency of oil properties between wells. A series of injection well location options were considered and modelled to evaluate their benefits. A downflank central location was selected that should support both producers N05Z and N06X. The well was deviated from the Don NE manifold, and put on injection in September 1996. After an initial high rate, injection declined significantly and injection pressure increased. Sustained rates of 2000-3000 BWPD were achieved, only a fraction of the design specification. The interpretation is that the well was drilled into a leaky compartment in Don SW. The N07 well is presently injecting 2500 BWPD. After ten years' production, Don SW continues to produce c. 2000 BOPD, from one producer, N06X, weakly supported by the water injector well N07. Don N E presently has no production wells in service. The last production from Don N E was from well N01 in 1998. This well has no water injection support and pressure build up to enable flow is via a weak aquifer support. In 1998 well N01 only managed to lift a few thousand barrels with approximately 50% watercut (formation water). The Don Field is one of the earliest sub-sea developments in the UKCS. It has suffered from the lack of accessibility and high cost of any interventions, typical of marginal sub-sea developments. Recently field management has also been marred by failure of down hole pressure gauges causing paucity of reservoir data to determine reservoir performance. The low production levels cause severe slugging into the Thistle Platform plant. The siting of the sub-sea manifold above Don NE, which was at the time the preferred development, made subsequent development of the Don SW segments more costly due to extended reach drilling.
Discovery The Don Field was discovered in 1976 by the first well on the structure, 211/18-12, on Don SW. This well encountered 140 + ft of
oil in the Upper Jurassic Brent Sands at a depth of 11 006 ft TVD sub-sea. This well was followed the same year by 211/18-13 which drilled the Don N E structure and encountered 185 + ft of oil in the Upper Jurassic Brent Sands at a depth of 11 100 ft TVD sub-sea.
Field stratigraphy The stratigraphy of the Brent reservoir sequence found in Don wells shows typical cyclical character, with a grossly coarsening-upward lower Brent being overlain by a transgressive Tarbert unit (Fig. 5). However the Don sequence is distinctive in two important respects. Firstly, it is overall consistently finer grained than classical Brent, and secondly, it has little or no development of Ness-type, delta-top facies. Both of these factors can be attributed to the position of the field within the systems tract. With the Brent barrier bar complex prograding progressively northwards, Don is located in a much more distal, basinward position. The depositional geology of the Don reservoir has been described in detail by Morrison et al. (1991). The Brent is overlain unconformably by mudstones of the Humber Group: Heather and Kimmeridge Clay Formations, which provide seal and the hydrocarbon source rock.
Geophysics Like the other fields in Block 211/18, the Don Field discovery was made on the basis of 1970s 2D seismic data. A 3D survey was acquired originally in 1976/77, but this was superseded by a larger survey in 1982 and 1983. The later data set comprised 181 lines with 75 m spacing and shot in a N W - S E direction. The common depth point (CDP) interval was 12.5 m. Because of the line spacing, cross line migration was poor. The data set was interpolated and remigrated in 1985. The original 1983 processing formed the basis of the Annex B submission in 1987, while most of the initial development drilling was carried out using the 1985 reprocessed set. This included all the Don N E development drilling, and the first well on Don SW, 211/18a-N05/N05Z. Following the Don SW 211/18a-N05/N05Z well, it was decided to re-shoot the seismic data in late 1993 and early 1994. A small survey was shot over an area of 40 square kilometres, to cover the entire field and terraces. The new seismic data had been acquired in a N E - S W direction, on a 25 m line spacing and with a 12.5 m C D P interval. Two wells have been drilled subsequently using these data.
Trap The structure of the Don Field is highly complex. The field lies within a northeasterly plunging, asymmetric anticlinal feature. The anticline is cut by both N E trending and N-S and N N W - S S E faults. These faults are clearly defined by seismic data and have subdivided the major structure into compartments, the two largest being Don NE and D o n SW. In addition, there is both core and production evidence for the presence of smaller scale faulting, much of which is below seismic resolution. It is these small-scale faults which have been largely responsible for the disappointing production performance of the Don Field.
Reservoir The Don field was described originally by Morrison et al. (1991). Since then little has changed in the interpretation either of the structure or stratigraphy. The main update from that description is the ability of the reservoir to deliver. The sealing and partly sealing nature of most of the faults has been substantiated. More data (production, 3D seismic) have shown more faults. The reservoir stratigraphy of a typical Don Field well is shown in Figure 5. Individual reservoir zones can be identified readily
DON FIELD GAMMA
ADOPTED RESERVOIR ZONAL SCHEME
C}I~ [",PI {I
~o D E P T H i42s (FEET)
,~ONC
~4o
4c
~"
:,~or,= ~2A-
Zc~,e 2~
STANDARD LITHOSTRATIGRAPHIC NOMENCLATURE
O O ,-oc T I'-j ,-"~s ...................2~ ~:~..........!~s .......... -";
9 1so ......... zoo.
7,~r,e
261
.
I :::::
I
HEATHERFM.
.................... ~'=13.1%
~
)
11200
K--
ir
,n
TOP RESERVOIR SAND
~'d-U ......
L TARBERT
(
FM.
j
tZ'=I 7 . 5 %
I
K=10-1000mD
9
~=18%
? x. ,
{ Zc~e
3
~'=16%
:~
t ................. 1 1 3 0 0
K=I 0-80roD
1
i
...........................
'~
NESS FM.
f
tl
,> K=I 0-50OmD
??
' :.
h ~
K=3-40mD
rl D
i
11400
O
!
rr
i
"~!
ETIVE
(_9
FM
l-Z W
!
,,,,\
I .......
rn
m
rn ZoPe 6
e=I6%
} ::'
K=l mO
r 4
~_.
} f
;!
.2
i 11600
,-"
i)
RANNOCH
'x
!i:;ii..4II ....
.,' L
FM,
(SAND)
" BASE RESERVOIR SAND .....................................
.................................... .............................
i
i1
'~'
.....i"
RANNOCH
FM
(SHALE)
i : . . . . - ..................
DUNLIN G R O U P I:: ................:: ::1
Fig. 5. Don reservoir stratigraphy.
from electric logs. Rather than artificially adapt the normal Brent nomenclature to this atypical, Don facies association, an alphanumeric zonal system has been applied, the most recent of which is illustrated in Figure 5. Electric log correlation of the Brent reservoir units between wells is straightforward. Noticeably, over the area of the field drilled to date there are few major depositional thickness changes. For the most part thickness disparities in wells have been interpreted as being due to faulting. The Don Field has a high net to gross. The sandstones are variably arkosic, and the most important mineral variant is mica, which largely accounts for the variation in log responses (particularly gamma and density) between different units. Rock quality is moderate, with porosity in the range 12-18%, and core permeability of a few millidarcies up to one darcy locally (Fig. 5). The highest permeabilities occur in two zones, each approximately 25 ft thick, in Zones 2a and 4 respectively. These two intervals cause the Brent to behave very much as a layered reservoir, despite the very high quartz content of the section. Spinner surveys conducted during flow tests of both production and water injection wells have shown that these two zones between them account for more than 90% of flow in the respective wells. It has been policy on all Don (sub-sea) wells to blanket perforate all the net reservoir sands, the productivity (or injectivity) index of any Don well being largely controlled by the aggregate thickness penetrated of these two zones. Noticeably, Zones 1 and 6 have low permeabilities, often less than 0.1 mD. These intervals, corresponding to the Tarbert and Rannoch Formations, have a high mica content and are both counted
as non-pay. They account for approximately 50% of the 400ft gross thickness of the Brent. The rock quality of the Don reservoir is largely controlled by original depositional texture, modified by burial compaction to its present depth of 11000-11500ft TVDss. Diagenesis is also an important control on rock quality, mainly through the agency of polyphase quartz cementation.
Source Within the various segments of the Don Field, there is a clear trend from northeast to southwest of oils that become slightly heavier and less gassy. One interpretation of this information is that charging with hydrocarbons from the northeast progressively displaced fluids upstructure to the southwest. In addition, it has been noted that any piece of Brent Formation core from a Don well will have some degree of oil saturation. This is such a consistent occurrence that it leads to the suspicion that the oil column was once much more extensive than it is today, and that oil has spilled or leaked out of the structure.
Fluids Don oil is a variably undersaturated, low sulphur crude with API gravity ranging from 38 ~ to 42 ~ Chemically it is a normal Kimmeridge Clay oil. The original reservoir pressure was 7460 psi at l l500ft TVDss, indicating a high degree of overpressure
262
A . D . MILNE & A. M. BROWN
[] Don SW, bopd [] Don NE, bopd
Fig. 6. Don Field production history.
(0.66 psi/ft). Formation water is comparatively fresh, with dissolved solids of 17 000 ppm. Barium sulphate scaling has been a problem in the past, the N02 well having required scale inhibitor treatment by bullheading, with inevitable loss subsequently of productivity.
Don Field has been producing there have been no downhole well interventions on any of the sub-sea wells. Scale inhibitor squeezes are carried out by bullheading from the Thistle platform. The main threat to realizing remaining reserves in Don NE and SW is well and pipeline integrity.
Lesson learned Don Field data summary Further dynamic data from the appraisal well tests would have been beneficial. None of the tests were long enough to recognize serious barriers/compartmentalization, and there was considerable doubt as to the validity of fluid samples. The appraisal wells essentially did little more than prove up STOIIP. The inference that Don NE was better than SW, because of reservoir quality, was based on too little information, and could be incorrect. The decision to drill the Don SW wells as long stepouts from the Don N E manifold was probably not a good one. The resulting very high drilling costs and time delays negated any benefit. A Don Field development, given what we know now, and armed with present day drilling technology, would probable consist of one or two sea bed development sites, with the main one over Don SW. High angle or horizontal wells would probably be used to optimize reservoir penetration and to minimize the effects of reservoir compartmentalization.
Trap
Type Depth to crest Lowest closing contour OWC Oil column
fault blocks 10 900 ft tvdss 115 00 ft tvdss 11 320-11 430 ft (variable) 500 ft
Pay zone
Formation Age Gross thickness Net:gross Porosity average (range) Permeability average (range) Productivity index
Brent Group Middle Jurassic 420 ft 20-80 ft 0.16 (0.12-0.28)% (5 40) rod 4 to 15 BOPD/psi
Petroleum
Reserves The most recent review of the Don Field was carried out in 1997. This comprehensive study examined all the options for future drilling in the light of a new seismic interpretation, petrophysical description, production history and volumetrics. While several opportunities were identified, all carry a significant degree of risk and are currently economically unattractive. The main method of accessing further reserves is with further drilling, ideally from a surface location somewhere over Don SW. In the ten years that the
Oil density Oil type Gas gravity Viscosity Bubble point Gas/oil ratio Formation volume factor
37-42 ~API light, low sulphur 0.32 0.87 cp 1225-2940 psig 335-944 SCF/BBL 1.25 1.47 RB/STB (1.25 Don SW + 1.47 Don NE)
Formation water
Salinity Resistivity
21 596 NaC1 eq ppm 0.314 ohm m
DON FIELD Field characteristics Area Gross rock volume Initial pressure Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Production Start-up date
700 acres 200 000 acre ft 7240-7350psi (at 11 200ft tvdss) 265~ 52 (NE), 99 (SW) MMBBL
Production rate plateau oil Number/type of well in 2000
263 10 000 BOPD 1 water injection
References 14.6 (NE), 8 (SW)% Depletion, wateflood 7.6 (NE), 8.2 (SW) MMBBL
August 1989 (sub-sea tie-back 17 km to Thistle platform)
MORRISON, D., BENNETT, D. D. & BAYAT, M. G. 1991. The Don Field, Blocks 211 / 13a, 211 / 14, 211 / 18a, 211 / 19a, UK North Sea. In: ABBOTTS, I. L. (eds) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, Memoir, 14, 89-93. RICHARDSON, S. M., BLACKBURN, N. A. & SHERE, A. J. 1991. The Don Field." A Flexible Approach to the Development of a Marginal Field. Society of Petroleum Engineers, London 23078.
The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3[14, 3/15, UK North Sea J. S. R I T C H I E
Total Fina E l f Exploration UK PLC, Crawpeel Road, Altens, Aberdeen AB12 3FG, UK (e-mail." jim.ritchie@ tfeeuk.co.uk)
Abstract: The Dunbar, Ellon and Grant oil and gas fields (also known as the Alwyn South area) are located in the southeastern part of the East Shetland Basin, approximately 140 km E of the Shetland Islands. Most of the accumulations lie in Blocks 3/9, 3/14 and 3/15, which are parts of Licence P090 operated by Total Oil Marine plc (33.33 %) with Elf Exploration UK PLC as sole partner (66.67%). Ellon was discovered in 1972, Dunbar in 1973 and Grant in 1977. Dunbar consists of a number of generally N-S trending, westerly dipping Mesozoic fault blocks with variable amounts of crestal erosion. Reservoir is provided by fluvial, deltaic and shallow marine sandstones of the Middle Jurassic Brent Group, Lower Jurassic Statfjord Formation and Upper Triassic Upper Lunde Formation. The Brent oil composition of Dunbar varies with depth and evolves from volatile oil at the base of the column to gas condensate at the top without a discontinuity of composition. In addition there is a small gas accumulation within a Paleocene submarine fan reservoir in a compactional structure. Ellon consists of two westerly dipping fault blocks with gas condensate contained within the Brent Group. Grant is one westerly dipping fault block with gas condensate in the Brent Group. In both the Ellon panels and also in Grant, thin waxy oil 'rims' are found below the gas. The depth of the shallowest structural crest within the Alwyn South complex is 3100 m TVDSS, with the deepest proven hydrocarbon at around 3800m TVDSS. Sealing for the Alwyn South accumulations is provided by various combinations of Cretaceous, Upper Jurassic (Heather and Kimmeridge Clay Formations) and Lower Jurassic (Dunlin Group) mudstones. The source rock for the hydrocarbons is the Upper Jurassic Kimmeridge Clay Formation, which is mature and adjacent to the fields. These accumulations are being developed from a tender-assisted minimally manned fixed platform with a total of 28 well slots located over the Dunbar Field, in a water depth of 145 m. The Ellon and Grant Fields are produced as sub-sea satellites to Dunbar from a well-head cluster located between Ellon and Grant, in a water depth of 135 m. First oil and gas production from Dunbar and Ellon was in December 1994 and gas production commenced from Grant in July 1998. The time lag between discovery and development reflects the complex geology (structure, compartmentalization, reservoir thickness variations, diagenesis and differing hydrocarbon compositions) with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. Total oil and gas initially in place is in the order of 850 MMBBL and 2.62 TCF respectively, with the current estimate for ultimate recoverable reserves being 200 MMBBL liquids and 1.28 TCF gas.
Introduction The D u n b a r , Ellon a n d G r a n t Fields, collectively k n o w n as the A l w y n South area, lie approximately 1 4 0 k m E of the Shetland Islands, in the south eastern part of the East Shetland Basin (Figs 1 and 2). The m e d i a n line between the U n i t e d K i n g d o m a n d N o r w a y lies approximately 6 k m E of the Ellon East accumulation. The fields lie within Blocks 3/8a, 3/9b, 3/13a, 3/14 a n d 3/15 with the D u n b a r p l a t f o r m located in Block 3/14a in a water depth of 145 m. Ellon a n d G r a n t are operated as sub-sea satellites to D u n b a r , with a well-head cluster (in Block 3/15) 9 k m to the SE of the D u n b a r platform, in a water depth o f 135 m. P r o d u c t i o n is f r o m a n u m b e r of tilted fault blocks within the U p p e r Triassic U p p e r L u n d e F o r m a t i o n , L o w e r Jurassic Statfjord F o r m a t i o n and M i d d l e Jurassic Brent G r o u p reservoirs. H y d r o c a r b o n - b e a r i n g reservoirs are f o u n d at depths between 3 1 0 0 m T V D S S and 3 8 0 0 m TVDSS. Total oil and gas initially in place is a r o u n d 850 M M B B L a n d 2.62 T C F respectively, with estimated reserves f r o m panels u n d e r d e v e l o p m e n t at the end of June 1999 of 200 M M B B L liquids a n d 1.28 T C F gas. The 3/14a-1 discovery was informally k n o w n as A l w y n and subsequently, following the A l w y n N o r t h discovery, the area b e c a m e k n o w n as A l w y n South. One reported origin of the n a m e A l w y n is the Old English Aelfwine of w h i c h A e / f m e a n s Elf a n d wine m e a n s friend ( J o h n s o n & Essuytier 1987). The n a m i n g of D u n b a r , Ellon and G r a n t reflects the use o f Scottish place names for Total operated N o r t h e r n N o r t h Sea fields.
E x p l o r a t i o n U K PLC, 66.67%. At the time of allocation the acreage was the most northerly a w a r d e d in the N o r t h Sea a n d the stratig r a p h y and detailed configurations of potential h y d r o c a r b o n traps in the East Shetland Basin was u n k n o w n . The only guideline for
History and discovery method P r o d u c t i o n Licence P090, comprising ten blocks, was issued to the Total/Elf/Aquitaine consortium, each with a one third share, as part of the second r o u n d of licence awards in 1965. The current equities in the licence are Total Oil M a r i n e plc (operator) 33.33% and Elf
Fig. 1. Alwyn South fields location map showing principle hydrocarbon accumulations and major faults. Note that Dunbar straddles the Hutton-Ninian trend fault zone.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 265-281.
265
266
J . S . RITCHIE
W
U.K. ] NORWAY
E
Fig. 2. Schematic regional structural cross-section showing the Alwyn South area adjacent to the North Viking Graben.
Fig. 3. Schematic Alwyn South structural cross-section showing the presence of syn-sedimentary faults (A-E). Note the absence of hydrocarbons in the lower part of the Brent in Grant due to the presence of an intra-Brent bottom seal.
Fig. 4. Seismic section (1993 3D survey) illustrating the main seismic reflectors and faults on the Alwyn South Fields. Note that the cross-section is not in the same position as Figure 3.
DUNBAR, ELLON AND G R A N T FIELDS
319a 3114a
3/10a
60~
3115
WELLHEADS CLUSTER
X 4
E/A WELl
9 A02
PRODUs
Contour intE tN EAST
,4
GRAN" ,LON W E S T 3/
01~
Fig. 5. Ellon and Grant Fields top Brent reservoir depth map showing exploration/appraisal and development wells (as at end June 1999).
locating wells was structural closure on a seismic horizon, then of unknown age, but which was later proven to be the Base Cretaceous Unconformity. For this reason the licensees initially explored the blocks where the structural configuration was most clearly defined. The exploration drilling of the licence began in 1971 in Block 3/25, followed by well 3/15-1 (Figs 3, 4 and 5) in 1972, soon after the discovery of the Brent Field to the north. Well 3/15-1 was drilled on a prominent anticline structure at Base Cretaceous level and was abandoned because of a stuck drill bit and the onset of winter. The well was successful, however, as it showed the sequence below the Base Cretaceous marker to be of Jurassic age; it contained sandstones, and gas was present in the deepest part of the well. Since no logs could be run over the deep section, no more detailed evaluation was possible, nonetheless it is still considered the discovery well of the Ellon Field. Well 3/15-1 gave enough encouragement for two follow-up wells, 3/15-2 in 1973, to the west, and 3/15-3 in 1974, to the east (Figs 3 and 5). Well 3/15-2 flowed gas and paraffinic oil from thin Middle Jurassic Brent Group sandstones with poor reservoir quality; well 3/15-3 found a good quality but thin and water-bearing Brent section. Well 3/15-2 reached the Triassic, but the Lower Jurassic Statfjord Formation and Triassic Upper Lunde Formation reservoirs were dry. It was evident that both wells had drilled through faults and that the Brent reservoir was strongly faulted in this area, with the quality of the sub-Cretaceous seismic data being inadequate for the appraisal of the field. Attention was then focused on Block 3/14, with the drilling of well 3/14a-1 in 1973 (Fig. 6). This well was located on a preCretaceous high to the west of Ellon and discovered oil-bearing
267
Statfjord and Triassic reservoirs; the Brent was absent due to erosion. The discovery was informally called Alwyn and was later named Dunbar. Two appraisal wells, 3/14a-2B and 3/14a-3 were drilled in 1974 (Figs 3, 6 and 7). The former encountered oil-bearing Statfjord and Triassic reservoirs, with the Brent again being absent. The latter found, for the first time on the block, Brent sandstones which, although thin at 43m, had good reservoir properties and were oil-bearing throughout. The 40 m thick Statfjord Formation was also oil-bearing. Activity was then focused on structures in the north of the licence area with the discovery of the Alwyn North Field in 1975, followed by three more wells in that area by the end of 1976 (Inglis & Gerard 1991). Between 1977 and 1980 three further wells were drilled close to the Ellon Field. The first of these, 3/14a-4, located to the west of Ellon, found for the first time a full, un-faulted Brent sequence, the upper part of which contains a small gas/condensate and oil column; hydrocarbon contacts were some 300m deeper than at Ellon, and this separate structure was subsequently named Grant. The other two wells were 3/15-4, an exploration well to the east of Ellon, and 3/14a-6, an appraisal well to the north of Grant; both were dry (Figs 3 and 5). Following the acquisition and interpretation of 2D seismic surveys over Dunbar (1974, 1977 and 1978) five delineation wells were drilled on Dunbar between 1980 and 1984. These showed the field to be structurally complex, as well as having very variable reservoir thickness and quality. In 1984 a complete re-evaluation of Dunbar was performed using the 3D seismic survey (the first on the field) which was acquired in 1982, leading to the drilling of a further seven delineation wells in the period 1985 to 1989. The last two of these, 3/14a-14z and 3/14a-15, were deviated from the future platform location and included long duration tests which confirmed significant hydrocarbon volumes connected to the wells; they were suspended as future producers, and subsequently re-named D01 and D02 respectively (Fig. 7). A 3D seismic survey was acquired over Ellon and Grant in 1978 (one of the first shot in U K waters), and processed in 1979. This was re-processed in 1984 and also in 1991; advances in technology resulted in much better definition of the Jurassic. In addition, the stratigraphy of the Brent was now well defined from surrounding wells and in 1988 an Ellon appraisal well (3/15-5) was drilled (Figs 3 and 5). This at last encountered a full un-faulted Brent sequence with a 60 m gas/condensate column. An extended flow test confirmed significant volumes connected to the well and the Ellon Field was considered to be appraised. A thin paraffinic oil 'rim' was also found. A 3D seismic survey over the entire Alwyn South area was acquired in 1993 and was used to plan the development wells. This proved to be inadequate for reservoir characterization purposes and was re-processed in 1997. A final appraisal well, 3/14a-17 (Fig. 7), was drilled in 1997 in the southern part of Dunbar (named Dunbar South), which is particularly complex. This part of the field will be developed using a combination of extended reach platform and sub-sea wells. Because the only well on Grant was in a downdip position, in 1998 an up-dip appraisal well (3/15-7) was drilled and completed as an early production system well (re-named G01) (Figs 3 and 5). Although the entire Brent sequence is present in this well, the Lower Brent is water-bearing. This is due to a Ness A shale and coal prone section acting as a field-wide bottom seal.
Regional structure and stratigraphy The Alwyn South accumulations are located in the south eastern part of the East Shetland Basin, a faulted terrace area between the East Shetland Platform and Northern Viking Graben. The East Shetland Basin contains several hydrocarbon-bearing structures, typically westerly dipping, which are aligned along a series of major, generally N-S trending, fault zones which down-throw to the east (Figs 1 and 2). Dunbar lies on the same trend as Ninian and Hutton, to the north, whilst Ellon and Grant are associated with the fault zone extending south from Brent through Strathspey to Alwyn North. Of note in the Alwyn South area is the role played
268
J. S. RITCHIE
60~
X
PLATFORM
3
E/A WELL
3/8a 3/13a
| MAIN LANK ffjord)
eD16 PRODUCER eD22 ERD PRODUCER .~DO6 WATER INJECTOR
N
Ikm
DUNBAR Rt~IITH HORST Triassic)
1/14a 3/14e
01~
Fig. 6. Dunbar Field top Statfjord/Triassic reservoir depth map showing exploration/appraisal and development wells (as at end June 1999). by syn-sedimentary faults, which have been periodically active throughout the Jurassic, as discussed later in the reservoir section. A detailed description of the Alwyn area regional and local stratigraphy and depositional history, including syn-sedimentary faulting, is provided by Johnson & Eyssautier (1987).
Trap The Alwyn South accumulations are a series of westerly dipping fault blocks, limited to the east by major faults downthrowing to the east. The thick mudstones of the Upper Jurassic Heather and Kimmeridge Clay Formations provide top and, by fault juxtaposition, lateral sealing to the Brent reservoirs. The upper part of the Brent on the crest of the Dunbar West Flank is eroded by an intraHeather unconformity (Fig. 3). The thick shales of the Dunlin Group provide both the bottom seal for the West Flank Brent and
also the top seal for the Statfjord of the West Flank. The Statfjord and Triassic of the South Horst are sealed by Heather, Kimmeridge Clay and thick Cretaceous mudstones. The Dunbar Field is compartmentalized, consisting of several fault-bounded panels (i.e. West Flank North & South, Central North, West & South, Frontal North & South, East Frontal, Dunbar South Horst - Figs 3, 6 and 7). In addition there are several intra-panel faults and fluid transmissibility barriers which typically trend either N-S or NE-SW, probably reflecting re-activation during Jurassic extension of the weaknesses in the Caledonian basement. The amount of compartmentalization and fluid movement between panels caused major uncertainty in assessing the potential of the field and in optimizing the development plan, particularly the possibility for secondary recovery. The low seismic resolution together with, on the West Flank and Central Panel, the relatively thin reservoir restricts the use of seismic data in the definition of reservoir heterogeneity. As a result the development plan for
DUNBAR, ELLON AND GRANT FIELDS
318a
269
N
3/9b
0
1 km
L
X 4
4 60o40,N
DUNBAR MAIN
PLATFORM E/A WELL
9 D03
PRODUCER
',,
HORIZONTALPRODUCER
,~'
WATER INJECTOR
Ill
-'"
I ...'.,\\
~
~"r
I~
~\D02
PANELS
D18
O WEST FLANK O CENTRAL NORTH (~) CENTRAL WEST | CENTRAL SOUTH | FRONTAL NORTH FRONTAL SOUTH (~ EAST FRONTAL
Contour interval 100m
DUNBAR SOUTH
3114b
3/14a
\1
01~ Fig. 7. Dunbar Field top Brent reservoir depth map showing exploration/appraisal and development wells (as at end June 1999).
Dunbar allows for the additional static and dynamic data acquired during the development drilling to be incorporated into the geological and reservoir models, with subsequent fine tuning of the development plan. Reservoir pressure monitoring such as formation pressure tests, bottom hole pressure surveys and interference testing were all found to be particularly useful in identifying vertical and lateral barriers. Non-pressure techniques such as Strontium residual salt analysis (SrRSA), organic geochemical fingerprinting, production logging and saturation logging also proved to be very useful (Bigno et al. 1998). These techniques have proven to be extremely effective in identification of barriers, both between and also within wells. The SrRSA work (Fig. 8) shows that certain shale and coal beds are laterally continuous features with the capacity to isolate hydrocarbon volumes; examples are the West Flank Ness A/Etive
boundary and the Tarbert/Ness B boundary in the Frontal Panel. As well as indicating the presence of lateral barriers, such as the isolation of the northern part of the West Flank North and the limit between the West Flank North & South, the use of SrRSA also shows which faults are not sealing on a field production time-scale; an example is the evident communication between the Central South and Frontal Panels. Appraisal well 3/9b- 10 and development well 3/14a-D 10, located on the northern part of the Dunbar West Flank, were both sidetracked (Figs 6 and 7). The Jurassic sections, both in the initial boreholes and also in the side-tracks, were faulted with parts of the Brent absent. Despite the side-tracks being located close to the original bore-holes, the drilled section in each was different (Fig. 9). This is interpreted as resulting from gravitational collapse which has
270
J.S. RITCHIE
3400
3450 O 0~
<>
3500
r
/
E Q.
"t
3550
r
~
3650 0,711
NESS A / L, BRENTVERTICAL PERMEABILITY BARRIERS
D D"D o
1308LiES OFF TREND SUGGESTING BARRIERTO LATERAL CONNECTIVITY BETWEEN THIS AND WEST FLANK 'MAIN'
3600
~
.
.
.
.
.
.
.
.
POOR LATERALCONNECTIVITYi ~ INFERRED IN LOWER BRENT. SUPPORTED BY OILSAMPLE ! Z~. GEOCHEMISTRY J "~
[314b-9 UMS/NB
0 14a-10 NESS B
SrRSA 0.715 9 D04 UMSINB
9 D04 NA
O14a-10 NESS A
X 14b-9L.BRT
0,712
.
0.714
0.713
0.716
XX~
0,717
<~ D08 UMS/NB
• 14b-9 NA
~ 14a-10 LBRT
V D04 L.BRT
0.718
Fig. 8. Dunbar Field West Flank SrRSA results showing inferred vertical and lateral permeability barriers. created a fault scarp degradation complex on the northern part of the Dunbar Field West Flank. Further south, in Dunbar South West Flank well 3/14a-17, slumping is evident on cores as well as repetition of the lower part of the Brent Group and upper part of the Dunlin Formation. In addition, bed rotation is seen on cores cut from the Brent of well 3/14a-12. These features are believed to be related to uplift of the Dunbar South Horst with resultant oversteepening and instability of the adjacent West Flank. The structural complexities described above are very poorly imaged on the current seismic data, and the successful development of these structurally complex areas is one of the future challenges of the Dunbar Field.
The Ellon and Grant structures are westerly dipping fault blocks bounded to the east by major faults downthrowing to the east. Top and lateral seal are provided by thick mudstones of the Upper Jurassic Heather and Kimmeridge Clay Formations. The N E - S W Caledonian fault trend is important in defining the northern limits of the Ellon and Grant panels; the majority of the intra-panel faults evident on seismic data are aligned on this trend (Fig. 5). A feature of the Grant structure is the presence of a 25m thick shale and coal section at the base of the Ness A below which the Lower Brent Formations are water-bearing in up-dip appraisal well 3/15-7 (GO 1). The Grant structure is relatively un-faulted and fault throws are
S.W.
N.E.
3/9b-10
mTVDSS 3500 - -
3/9b-10z
TARBERT BASE CRETACEOUS
3600
DUNLIN
9s AtFJbR .
3700
TRtAS
\
"
\
X\HUMSER N
3800 0
I
100
..................... ,
200m
1
Fig. 9. Structural cross-section across the northern part of the Dunbar West Flank, showing wells 3/9b-10 & 3/9b-10z and the interpreted crestal erosion and fault scarp degradation. Note that there is no vertical exaggeration.
DUNBAR, ELLON AND G R A N T FIELDS
271
Fig. 10. Example Brent reservoir log (Dunbar well 3/14a-7) showing reservoir layering, log interpretation, interpreted depositional environments and major sequence stratigraphic surfaces. Note the synthetic test permeability trace which is calculated for each layer using cross-plots of core permeability v. Rt and porosity; this allows production of a pseudo-permeability trace where there is no core data.
272
J. S. RITCHIE
rather small (Figs 4 and 5). As a result this shale and coal section appears to form a field-wide bottom seal (unusual in the East Shetland Basin) to the Grant accumulation. The Upper Brent of the Grant structure is in juxtaposition across the eastern structurebounding fault with mature Kimmeridge Clay, offering a simple hydrocarbon migration route into the structure. From examination of the seismic data it appears that this is not the case for the Lower Brent and it is believed that this is dry over the entire Grant structure due to the lack of a suitable migration route. There is a Paleocene high trend running W N W - E S E across the West Flank of Dunbar. This trend reflects a sand-rich channel zone with wells showing rapid variations in gross sand thickness, from 2 m to 60 m. The sand thicks are pod-like on seismic data and form isolated structural highs. One of these was drilled by well D02 which encountered a 10m thick gas column overlying a 5 m thick oil leg. This pod has a small seismic bright spot; a similar D H I is seen on one other pod, whilst a third has no direct hydrocarbon indicator (DHI). Total GIIP for these pods is estimated at around 20 BCF and it is planned to evaluate their development potential at a late stage in the Dunbar Field development.
SEDIMENTARY STRUCTURES GR 0
INTERPRETATION
GRAIN SiZE v~c. ~v~ ~ M
t00
SHOREFACE
~
SB
cL
m ~J
t~
<
-
~
~
TIDAL COMPLEX {? INCISED VALLEY FILL)
DELTA P L A I N
P .
LITTORAL BARRIER COMPLEX
PROGRADING MIDDLE SHOREFACE
.EWORKED
~176176 DUNUN
OA'TA
SB
Reservoir In the Alwyn South area, large thickness variations are evident at Brent, Dunlin and Statfjord levels (Fig. 3). From well and seismic evidence these thickness variations are interpreted as reflecting synsedimentary faulting, which appears to have acted intermittently throughout the Jurassic; depositional environments are also affected by this tectonic activity. There are no Brent or Dunlin sediments preserved in the Dunbar South Horst and erosion of the Statfjord and Triassic is progressively deeper to the south. Erosion of the Brent is also seen in wells near to the crest of the Dunbar West Flank as well as in Central West and Central North Panels. The Alwyn South area benefits from extensive core coverage which has allowed detailed sedimentological, structural and petrographic studies and, consequently, enhanced understanding of the Mesozoic reservoirs.
LEGEND SB
SEQUENCEBOUNDARY
SWALEY DROSS*BEDDING
WRS
WAVE RAVtNEMENTSURFACE
HUMMOCKYCROSS-BEDDING
MFS
MAXIMUMFLOODING SURFACE
i
LOW ANG~ LAMINATIONS
~/
//A/
TABULARCROSS.BEDDING
~,
_z~)
TANGENTIALC~QSS-BEDDING
~
SHELL DEBRIS
00%0 CO~LOMERATE
ROOTS SIDERITE NODULES
Fig. 11. Core description with interpreted depositional environments and sequence stratigraphy surfaces for the Brent Group section of Dunbar West Flank well 3/14b-9. Note that the entire Brent section is cored, as are the contacts with the Heather Formation and Dunlin Group.
GR
100j
HEATHER
< - %
SEDIMENTARY STRUCTURES
INTERPRETATION
GRAIN SIZE vcc u FVI'IM
;I~
The Brent Group shows a very pronounced eastwards thickening from 90 m (pre-erosion) in Dunbar West Flank to over 300 m to the east of Ellon. The Brent summary log for well 3/14a-7 is shown in Figure 10; the 17 reservoir layers used in building the Brent 3D geological and reservoir models for the Alwyn South panels are shown. Of interest is the synthetic test permeability trace which is calculated for each layer using cross-plots of core permeability v. Rt and porosity; this allows production of a pseudo-permeability trace where there is no core data. The core description log, with interpreted depositional environments, for the Brent in well 3/14b-9 is shown in Figure 11, whilst that for the Tarbert in well 3/14a-7 is shown in Figure 12. Figure 13 shows the stratigraphic correlation through the Brent Group from Dunbar to Grant and Ellon; this illustrates thickness and facies variations. Together these form the reference figures for the Brent reservoir description of the Alwyn South area. The Lower Brent Broom Formation conglomeratic, coarse to medium grained sandstones, whose base is a sequence boundary, are interpreted as fan delta sediments reworked during marine transgression. The sandstones are capped by shaly bioturbated offshore siltstones, corresponding to the base Rannoch Formation maximum flooding surface. The fine grained, micaceous Rannoch sandstones, which are characterized by swaley and hummocky cross-stratification, were deposited in a prograding middle shoreface setting; they are continuous and homogeneous throughout the area. A relative stillstand allowed the outbuilding from the south of the Etive Formation, which represents a wave dominated littoral barrier complex. This consists of a variety of depositional environments:
RIPPLES SLUMP
BiOTURBATION BURROWS
TROUGH CROSS-BEDDING
l0
Bren t
~
~,
i
......
22=:~::::
'
:_,:
~ '
-
Z
<
u}
u.
w
m
a13
~
STORM REWORED
FAN DELTA
>
-
[
LOBES
lore
9 E w
Q,
/ O,,SHORE "J ss ,
FAN DELTA REWORKED AS TRANSGRESSIVE L A G
" p.
,
,
WRS
Fig. 12. Core description with interpreted depositional environments and sequence stratigraphy surfaces for the Tarbert Formation equivalent section of Dunbar Frontal Panel well 3/14a-7. The thick stacked storm re-worked fan delta lobes developed over the Frontal Panel contrasts with the thin lower shoreface to upper foreshore Tarbert sediments of the Dunbar West Flank (Fig. 11). Note that the complete Basal Sands section, together with the contact with the Ness B was cored in Frontal Panel well 3/14a-8. The legend is shown on Figure 11.
DUNBAR,
ELLON
AND
GRANT
FIELDS
273
k~ o o
o
b ,..o
b X_a
s~ .,..,
. ,...~
~m rn
. ,...~
i= [-- ,.e
,.-,
9
~.~
9
o
m
~
,.~
9 ,...~
a~
9
..~ .~
274
J.S. RITCHIE facies variations show the transgression and erosion of a deltaic flood plain by a high energy shoreline. Marine flooding begins within a delta plain, on which were deposited tidal sediments passing seaward to shoreface sediments. The coastline becomes progressively eroded by wave ravinement, resulting in the shoreface overlying tidal complexes separated by wave ravinement surfaces. In D u n b a r West Flank and Central Panel the Ness B is interpreted as incised valley fill sediments. In Dunbar West Flank and Central Panel total Ness thickness is approximately 35 m whilst in the Frontal Panel it is 150m and in well 3/15-4 it attains a thickness of 225m. Tectonic activity was marked during deposition of the youngest Brent sediments with differential subsidence between relatively uplifted and downthrown blocks. As a result major thickness and facies variations are observed across the area. Footwall uplift was sufficient to emerge the crest of the D u n b a r West Flank, Central North & West Panels and Dunbar South Horst as well as the area to the east of well 3/15-4, with resultant significant erosion. In the Dunbar Frontal Panel there is a 120m thick Tarbert Formation equivalent unit; the heavy mineral assemblage from this matches the average for the full Brent, implying that the local erosion products were re-deposited in the Dunbar Frontal Panel. This unit is subdivided into three members informally called the Basal Sand (BS), Middle Shale (MS) and Upper Massive Sand (UMS). The 10-15 m thick Basal Sand, which is also present in Ellon and Grant, consists of coarse grained sandstones which are interpreted as fan delta sediments re-worked as transgressive lag or upper shoreface deposits. At this time erosion was taking place on Dunbar West Flank so the transgressive Basal Sands is correlated to a local tectonically-induced sequence boundary. The overlying 10m thick offshore shale interval, the Middle Shale, has a time equivalent thin shale at the top of the Brent in Ellon and Grant. The upper part of the Middle Shale is interpreted as a maximum flooding surface. The
foreshore to upper shoreface barrier sands, tidal inlet sands and tidal sand flats, back barrier lagoonal shale and minor coal. Flooding surfaces are evident in most wells, represented by spikes on density and gamma logs, as a result of the concentration of either mica or heavy minerals. The Lower Brent (Broom, Rannoch and Etive Formations) sequence shows little variation over the Alwyn South area with depositional processes being controlled primarily by eustatic fluctuations. The Ness Formation is divided into lower (Ness A) and upper (Ness B) units. The Ness A consisting of delta plain sediments, is sub-divided into two units. The lower Ness A (NA1) in the Dunbar Frontal Panel and also in well 3/15-4 consists of stacked and amalgamated fluvial distributary channels forming a laterally extensive and well connected sandy section. As a contrast the NA1 unit in both Ellon and Grant is represented by laterally equivalent delta plain shales, coals and palaeosols. The upper unit (NA2) is composed of aggrading then back-stepping deltaic flood plain siltstones and shales with interbedded, poorly connected distributary channels, crevasse channels and crevasse splays. There appears to be two channel belts correlatable from Grant to Ellon. In Dunbar West Flank the Ness A is much thinner than to the east and is not sub-divided but consists of similar facies as unit NA2. The Ness B in Dunbar West Flank consists of a tidal complex including sand-filled channels, sand flat and mud flat sediments. In Dunbar Frontal Panel the Ness B is represented by two tidal complexes which are constrained at the base and the top by correlatable coal beds and black lagoonal shales. These complexes form extensive flow units and are correlatable from the Dunbar Frontal Panel to Grant and Ellon. The tidal interpretation is based on the presence of bi-directional tangential cross-bedding, back flow ripples, re-activation surfaces and clay drapes. In well 3/15-4, to the east of Ellon, only shoreface sediments are present. These lateral
I I -13 CALCITE CEMENT
i --= " 91e.i~ p ,,.E'3Pnkdm ==t T_JIV_ili, rll f
9
9 ~
3600
9
\i=
9
9
9
~
._.L.- ==.re, m
% ~
b,,,
..W== .. n=~ll _dP =in ..-9 =.. = = _ r 9= 1 4 9 9 9 =Ir =q. 9 iI b 9 9 = UP ~Ir=~ 9 9 , , ,, _IL4;. ~m'jf ~ 9 9 9 Frame Ha"'= u 9 9 =, "=_I'.', = i,P mR. -ILnuni~rll ~" in
=,
.
"
m
",',,41/'~
.
,,-I~I,D;=-dP
=
" ~ .
---r
9
- - - ,m 9 I
r
3650
.
"l ira
--
""
1 ~
.:I._.IL'-,C:'.,I'JP=.7, 9 9
9. 9
9
-l
m
"
,n
. -
~
=,~,,==
ml~- ..t 9 r~dplTiiiir
~--=1
9 4~--
i
~
-
,
=.m
wELLs
._
-/'.L=-=IL==~, - - ~
.~m~-.---- "llil"Sll
= II ~llll.~_
_
J
m
9 nm .ii=.iJ='l-m m 9 9 ' m mI,4",S.9 I 9
"1" 3
oo
r {n
..o~
,
I 3700
n
I
0.01
liE 9
~
.,.
NimBi Jli
r
...
3750 I
I
I
I
I fill,
0.1
I
I
I
I I III
,I
1
I
I
I
i I Ill
I
10
1
I
I
I I Ill
I
I
I
I
J I I i
100
Horizontal Permeability ( m D )
Fig. 14. Dunbar Frontal Panel UMS layer 2 horizontal permeability v. sub-sea depth cross-plot, showing the pronounced decrease in permeability at 3650 m TVDSS.
1000
DUNBAR, ELLON AND GRANT FIELDS time equivalent in the Dunbar West Flank is a shaly, bioturbated, lower shoreface to foreshore sandstone which, where not eroded, is approximately 20m thick. The 90-100m thick, high net/gross, Upper Massive Sands are only present in the Dunbar Frontal Panel. This unit consists of medium to very coarse grained sandstones interpreted as representing storm-reworked fan delta lobes, set along fault scarps to the west. A flooding event which splits the UMS into two reservoir units (UMS 1 and UMS 2) can be correlated across the Frontal Panel. Finally the area was flooded and capped by marine shales of the Heather and Kimmeridge Clay Formations; in the Dunbar West Flank there is evidence of intra-Heather erosion and non-deposition. A feature of Dunbar is the presence of tight zones in the lowermost parts of the Brent reservoir of the West Flank and Frontal Panel hydrocarbon accumulations; these contain significant volumes of hydrocarbon in reservoirs with permeabilities of less than 5 mD. One of the challenges in development of Dunbar is to economically produce these tight zones. In early 1998 a 1000m lateral drain (D05z), whose trajectory was designed from the 3D geological model and which was very challenging to engineer, was successfully drilled from Frontal Panel well D05 (Fig. 7). This proved the feasibility of developing these tight reservoirs; several horizontal and multi-lateral wells are planned to produce their reserves. The tight reservoir is mainly caused by diagenetic illite which occurs in two forms; the first is the platy form consisting of pore lining and pore filling networks, resulting f r o m the epigenetic transformation of kaolinite (Jourdan et al. 1987). The second is the fibrous neogenic form, consisting of fibrous masses which can bridge and block pore spaces and pore throats. The two forms both result from the late transformation of kaolinite to illite, caused by the circulation of hot acid waters, fibrous illite being the later stage. Illite is also formed at this stage directly from the dissolution of feldspar. Both the diagenetic illite forms have little effect on porosity and there is also little reduction in permeability resulting from platy illite. The formation of fibrous illite does, however, have a severely damaging effect on permeability, reducing effective pore space and blocking pore throats. There is a marked reduction in permeability at a depth of approximately 3650m TVDSS in the Frontal Panel (Fig. 14) and 3560 m TVDSS in the West Flank as a result of a sharp downwards change in morphology of detrital illite from platy to fibrous form. In the West Flank this is believed to result from staged charging of the reservoir (Jourdan et al. 1987) with structurally higher hydrocarbon-charged parts of the reservoir being protected whilst the deeper, at the time water-bearing parts, being subject to diagenetic fibrous illite diagenesis due to the circulation of hot acidic waters, possibly from maturing Dunlin shales. This interpretation is supported by the presence of bitumen impregnation in West Flank wells, occurring in intervals about 2 m thick over a depth range of 3510m TVDSS to 3550m TVDSS. No bitumen is present in Frontal Panel wells so it is not clear if the diagenetic variations seen here are also as a result of staged charging history; the contact between the two forms of illite also deepens to the north of the panel. In the southern area of the Frontal Panel the reservoir is also degraded by the presence of syntaxial silica cement in well 3/14a-8 and, in well 3/14a-13 by the presence of poikilotopic calcite crystals (Fig. 14). Well 3/14a-13 drilled through the major fault forming the eastern edge of the Dunbar South Horst (Fig. 7), with the well penetrating the fault after drilling ten metres of Dunlin Formation. The bulk of the Brent in the well exhibits pervasive calcite cementation, which is interpreted as being precipitated from fluids rich in calcite prior to hydrocarbon charging.
Statfjord
The Statfjord Formation will now be described and the main sequence stratigraphy surfaces indicated. It should be noted that, whilst core coverage is good for Dunbar West Flank, it is very poor to the east. Sedimentological interpretations for the eastern area are
275
based on interpretations from logs as well as regional core data, notably from the Alwyn North Field, and also incorporate published regional data (e.g. Steel 1993). The application of the Deegan & Scull (1977) nomenclature is rather difficult in the Alwyn area and a local stratigraphy is used in which the Statfjord is informally defined as a group composed of three formations, from base to top named Interbedded, Massive and Calcareous. The Interbedded unit essentially equates with the Eiricksson and Raude Members, whilst the Massive and Calcareous units are equivalent to the Nansen Member (Deegan & Scull 1977). The Statfjord and Triassic summary log for well 3/14a-2B is shown as Figure 15; on this are shown the reservoir units used in building the 3D geological and reservoir models for the Statfjord and Triassic of the Alwyn South panels. Note that the well is to the west of the D u n b a r N i n i a n - H u t t o n trend fault zone so the Statfjord is thin; the upper part of the Calcareous Member is eroded. The core description log, with interpreted depositional environments, for the Statfjord of well 3/14b-9 is shown as Figure 16. Figure 17 shows a stratigraphic correlation through the Statfjord Formation from Dunbar to Grant and Ellon; this illustrates thickness and facies variations. Together these form the reference figures for the Statfjord reservoir description of the Alwyn South area. The Interbedded unit consists of stacked, low sinuosity, braided fluvial and alluvial fan sediments passing upwards to a more sinuous fluvial system. Channel fills are sandy with sand bodies tending to show a fining-up pattern with erosive bases. Rooted and mottled palaeosols, indicating fluctuating base levels, are common in the overbank floodplain sediments. Net/gross ratios are in the order of 25-50% and sand bodies are well connected giving extensive alluvial sheet sands. The Massive unit consists of two parts; a lower interval interpreted as a braid plain or fluvial dominated fan delta with the upper representing sediments deposited in coastal plain environments with tidal inlets, with the upwards-fining sand bodies representing stacked tidal channels and coastal barrier bars; the interbedded mottled and intermittently burrowed shales represent lagoonal environments. Net/gross ratio is typically 75-80% with well connected sand bodies that form laterally extensive sheets. In the Dunbar Field West Flank the Statfjord is thin and the subdivision of the Massive unit is not recognized. Sediments here are interpreted as littoral with tidal influences. T h e top of the Massive unit is marked by a shaly level, interpreted as a marine flooding surface above which the Calcareous unit is developed. This consists of a basal transgressive lag overlain by several coarsening upward sequences interpreted as distal delta front bars. Net/gross ratio is very variable (25-80%) reflecting the high degree of calcite cementation, related to numerous storm graded beds with abundant shell debris often present at the base. The Statfjord shows a very large eastwards thickening due to syn-sedimentary faulting from 3 0 - 4 0 m in Dunbar West Flank, through 70 m in Dunbar Central Panel, 150 m in Dunbar Frontal Panel, 175 m in Grant to 250m in Ellon. Recent development drilling has also shown the local importance of generally N E - S W trending faults in capturing streams in the Interbedded unit in tectonic depressions, resulting in a much thicker section with stacked sandstones giving a high net/gross unit. It is interpreted that the lower part of the Massive unit east of the D u n b a r - N i n i a n - H u t t o n fault trend (Fault B on Figs 3 and 17) is a time equivalent of the lowermost Interbedded unit in the Dunbar West Flank. The transition between the two members of the Massive unit east of Fault B which is interpreted as reflecting an increase i n t h e accommodation space, is the time equivalent of the shaly interval of the upper part of the Interbedded unit in Dunbar West Flank. The upper part of the Massive unit east of Fault B is correlated with the Massive unit of Dunbar West Flank. The vertical succession from Interbedded through Massive then Calcareous units up to the Dunlin Group marine mud defines an overall transgression. The transgression, whether it is due to eustacy or tectonically induced increase in accommodation, has a regional influence and is recorded on both sides of the D u n b a r - N i n i a n - H u t t o n fault trend, although the basal part of the series is absent and the remainder is condensed in the West Flank of Dunbar.
276
J.S. RITCHIE i
i 9
ZONE
~1
DEPTH ~1 (metres) l
I T V D S S MD i
o
LOWER CRETACEOUS
"K~I M'M~E R2i D G E --
GRiiiiiiii:
RtLD
DEPOSITtONAL ENVIRONMENTS 200!I.01
COREAIR K 10K (mD) 0.3 Log 1~ O! l O9
Log SW
3200
I NEARSHORE BARS I SHOREFACE
~ l~u,~ssrvE (/~
LITTORAL (? TIDE DOMINATED)
ALLUVIAL
I {NTER-
B R A I D PLAIN
18EODE~ A
,,-.
3250
LL
B1
~F--
3300
0
ALLUVIAL
ii
3350
PLAIN
60
WITH
60
<
t~
LOW
3400
I
ii i
B2a
SINUOSITY I
1I
I--
-ODT 3404.5m T V D S S i ~
. . . . . . .
J :::3 ii
WUT 3459.5m TVDSS -'
143
B2b
i
i
~
i
I [ J
EL 3500
CHANNELS
t
- 3450
3500+---
-,4
I
i
i
i
i
I
Fig. 15. Example Statfjord and Triassic reservoir log (Dunbar well 3/14a-2B) showing reservoir layering, log interpretation and interpreted depositional environments. Note that the well is to the west of the Dunbar Ninian-Hutton trend fault zone, so the Statfjord is thin and the upper part of the Calcareous Member is eroded.
Triassic
Source
Triassic depositional environments are continental, with meandering, sand-filled, fluvial channels interbedded with flood plain and lacustrine shales (Fig. 15). Individual channel sandstones are thin (5-10 m) and net/gross values are a r o u n d 2 0 - 3 0 % .
The main potential source rock in this area is the Late Kimmeridgian to Volgian Kimmeridge Clay Formation, which is present in all Alwyn South wells, even on the D u n b a r South Horst where erosion has removed all of the Brent, Dunlin and in some places the
DUNBAR, ELLON AND GRANT FIELDS
GR 0
SEDIMENTARY STRUCTURES GRAINSIZE 100 vcc.~v~s I IIII I
277
INTERPRETATION
IXINUN l~
M F S
z :
MFS
:E "~ n- '< O O a
10,.
~
OFFSHORE BARS & TRANSGRESSIVELAGS
MFS MFS LITTORAL (? TIDEINFLUENCED)
~
o i,-
~
w
CHANNELISED ALLUVIAL PLAIN
t
Fig. 16, Core description with interpreted depositional environments and sequence stratigraphy surfaces for the Statfjord Formation section of the Dunbar
West Flank well 3/14b-9. The legend is shown on Figure 11.
uppermost Triassic. It has a drilled thickness ranging from 2 m to 125 m in the Alwyn South area. Total organic carbon (TOC) ranges between 2% and 10%, with an hydrogen index (mg/g) of 100-800. The Brent Group coals and Dunlin Formation shales are also potential source rocks in this area, with TOC of 60-70% and 1-7%, respectively, and with an hydrogen index (mg/g) of 240 and 212, respectively. Matching of oils and source extracts shows that the oils in the Alwyn South reservoirs are a mixture from various source rocks. For details on source rock potential and maturation in this area the reader is referred to Johnson & Eyssautier (1987), whilst details of fluid movements in space and time in the Alwyn area, including hydrocarbon charging of the Alwyn South structures, are described by Jourdan et al. (1987). The Alwyn South structures are surrounded by mature Kimmeridge Clay Formation source rocks (Fig. 18). Simple, short distance migration routes are apparent for the Brent in the major panels and for the Statfjord of the Dunbar West Flank, as a result of juxtaposition of source rock with reservoir across structure-bounding faults (Fig. 3). In addition, the Dunbar South Horst reservoirs lie beneath mature (albeit thin) Kimmeridge Clay Formation and along the eroded crest of the Dunbar West Flank the Brent may lie beneath mature Kimmeridge Clay Formation (Fig. 3). Jourdan et al. (1987) conclude that charging of the Alwyn South structures commenced around 6 0 M a with hydrocarbons migrating from the North Viking Graben; western structures started to be charged at around 40 Ma, with hydrocarbons from both the North Viking Graben and local mature sub-basins to the west and south, within the East Shetland Basin. As discussed in the reservoir section, t h e presence of bitumen and different forms of illite in the Brent of the West Flank and Frontal Panel may be indicative of staged charging. The Statfjord and Triassic are hydrocarbon-bearing in the Dunbar South Horst (where erosion has removed all of the Brent and Dunlin) and the Statfjord is hydrocarbon-bearing in the Dunbar West Flank and Central North Panel. In contrast, the Statfjord and Triassic reservoirs of the Dunbar Frontal Panel as well as the Ellon and Grant structures are water-bearing. This is believed to be
the result of a combination of unsuitable formation juxtapositions across faults and the lack of viable migration routes from the source areas. In the Alwyn South area the faults appear to be sealing only when shale is down-faulted against the reservoirs. In the Ellon and Grant structures the Brent Group reservoirs are sealed in this way, but the Statfjord and Triassic of the footwall are in juxtaposition with the Brent of the hanging wall (Fig. 3). Any potential for hydrocarbons requires, therefore, the fault zone to provide a seal. In addition, regional studies have shown the lack of viable migration routes from mature Kimmeridge Clay source rock into the Triassic. Ellon wells 3/15-2 and 3/15-3 tested the Statfjord near to the crest of the western and eastern panels respectively but in both wells the formation is water-bearing (Fig. 3). Well 3/15-2 also drilled the Triassic in a structurally high position but the reservoirs were found to be water bearing. Dunbar Frontal Panel South Brent development well D18 (Fig. 7), was deepened to explore the Starfjord and Triassic reservoirs in a crestal position. No hydrocarbons were found in these reservoirs.
R e s e r v e s and p r o d u c t i o n
First oil and gas production from Dunbar and Ellon was in December 1994, with first production from Grant in July 1998. The long time from discovery to development is a reflection of the complex geology with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. The Alwyn South accumulations are developed as a satellite of the Alwyn North twin platforms. The development philosophy is to make maximum use of the existing Alwyn North facilities and infrastructure. To avoid topsides separation, Alwyn South hydrocarbons flow in diphasic mode from Dunbar to Alwyn North, where receiving facilities were installed, through a 16/20 inch double-wall insulated pipeline, to prevent hydrate formation. Ellon and Grant are operated as sub-sea satellites to Dunbar, with a wellhead cluster 9 km to the south east of the Dunbar platform. The oil is transported via the Cormorant Alpha platform through the
278
J.S. RITCHIE 9 C 9
N
I-f~ w
I,
s n'o~
0
1 1
V
~
Id 0
:J
~
A
uvonvo
a
~ S
N
0
S
V
s
-i
Pl
i
V
1
S 0300~8N31NI
~
li!i!i ::
,/
@
o
/
O 9
,
.
.
,
@ ...,~ ,xZ
~l 9
< rm
/
@ O 9
@ O ,..a
O
O
|
O
~2 ,.a
z
o
N
W
rv 0
< u,_
~
:D
z~. ua
~en
Ul
wo
b~
w
E 0
w
o~or41~lS
"7
0DS
l~l ,i
' |
o
DUNBAR, ELLON AND GRANT FIELDS
279 Psia
8000
8200
8400
8600
8800
I
I
I
I
3O00
ELLON 3200--
~
\
9 BRENT + STATFJORD + TRIASSIC
--~. ooc-a=s9
3300--
3400 -
i
3500 -
k
.,,
owc
,
3600 w.F.
owc-
2o
\.
oo,. .o 3700 --
3800 --
3900--
Fig. 18. Maturity map for the top Kimmeridge Clay Formation, Alwyn South area. Brent pipeline system to the Suilom Voe terminal on the Shetland Islands. The gas is transported via the Frigg Field through the Total Oil Marine operated transportation system to the St. Fergus gas terminal in Aberdeenshire. The Dunbar platform is a minimally manned fixed platform with minimum processing facilities and with 28 well slots which was installed in a water depth of 145m in the summer of 1994. The 167 m high, 9250 ton steel jacket was installed using a crane barge. The 9000 ton topsides were also crane lifted onto the jacket, in a single lift. During the development drilling phase, operations, in the form of accommodation, mud and cement facilities and general utilities, are supported by the Sedco 706 semi-submersible linked to the platform by a telescopic gangway. Alwyn North, 22 km to the north, provides all the necessary power for the Dunbar installation, together with pressurized water for the injection wells via a ten-inch water injection line. Four Dunbar and two Elion wells were drilled from a semisubmersible rig through a modular template between February 1993 and March 1994 in a water depth of 145 m and 135 m respectively, prior to installation of the Dunbar platform. These wells were completed after the platform installation, along with the final two appraisal wells, to provide early production. The drilling of platform wells commenced in February, 1995. Full use is being made of recent advances in drilling technology to drill extended reach, horizontal and multi-drain wells. By the end of June, 1999, in addition to the six template wells fifteen platforna wells (four of which are horizontal) had been drilled on the main Dunbar panels, with a further five planned (all of which are horizontal or multi-lateral), giving a total of 26 development wells. It is planned to drill additional laterals to several existing wells, using both 'conventional' as well as coiled tubing drilling, to access untapped and undrained pockets of oil. The first of these, D23, was drilled at the end of 1998 as a side-track to well D01, which had been shut-in due to water production. The first development well on the Dunbar South panels (D22) was drilled in June 1999; a further platform well is planned and one or more sub-sea drains may be drilled, depending on the results of the platform drilling. The Dunbar hydrocarbons are being developed using a combination of pressure maintenance by water injection, in the West Flank Brent & Statfjord and Frontal
4000
Fig. 19. Alwyn South reservoir pressure v. depth cross-plot. Brent panels, and depletion in the other panels. There are currently two producers on Ellon and one on Grant, with possibly one more additional well to be drilled on each. The Dunbar reservoir fluid is an under-saturated hydrocarbon whose composition varies with depth and evolves from volatile oil at the bottom of the column to gas condensate at the top; being close to the critical conditions no G O C is developed. Irrespective of the reservoirs the fluids appear to share the same trends and to have similar characteristics. The Ellon panels and Grant contain gas condensate overlying oil 'rims' with high density, high content of wax and asphaltene, high pour point and high viscosity. The hydrocarbon-bearing reservoirs of Alwyn South are found at depths between 3100m TVDSS and 3800m TVDSS. The reservoir pressure v. depth plot (Fig. 19) shows all Dunbar Brent panels to be in pressure communication through the hydrocarbon leg. No OWC has been proven on the Dunbar West Flank Brent; proven ODT is 3650 m TVDSS which is supported by pressure data, although the contact could be as deep as 3670 m TVDSS. For the Frontal Panel Brent an O D T is identified on well data at 3797m TVDSS, which is supported by pressure data. The Dunbar West Flank Statfjord and Dunbar South Horst appear to be in pressure communication through the hydrocarbon leg and have a higher reservoir pressure than the Brent. No contact has been proven from the well but from the reservoir pressure data the OWC is interpreted to be 3620 m TVDSS. Both the O W C and G O C are identified on log and pressure data for the Ellon and Grant panels. Both Ellon panels are in pressure communication with common OWC and G O C of 3282 m TVDSS and 3239 m TVDSS respectively. In Grant the G O C is identified on log and reservoir pressure data at 3534m TVDSS with the OWC at 3555 m TVDSS. The Grant hydrocarbon leg has a higher pressure than Ellon but these fields appear to be in pressure communication through the aquifer. Total oil and gas initially in place for Alwyn South is approximately 850 M M B B L and 2.62 T C F respectively, with estimate recoverable of 200 M M B B L oil and condensate and 1.28 T C F gas. Cumulative production at end December 1998 was 70 M M B B L liquids and 260 BCF gas. Production rates at end December 1998 were 50 000 BPD liquids and 220 M M S C F D gas. A field fact sheet, summarizing the characteristics of each field, is given in Table 1.
280 Table
J.S. RITCHIE 1. Field fact sheet
Field name
Trap Type Depth to crest Lowest clearing contour GOC OWC Gas column (m) Oil column (m) Pay Zone Formation Age Gross thickness (m) (non-eroded) Average net : gross Average porosity (%) Average permeability (mD) Average petroleum saturation (%) Productivity index BOPD/PSI or ksm3/d/bar (gas) Petroleum Oil type Oil density (~ API) Pour point (~ Gas gravity (air = 1.0) Oil viscosity (cp) Bubble point (bar at ~ Dew point (bar at ~ G O R (Sm3/Sm 3) Condensate density (kg/m 3) Condensate yield (bbl/mmscf) Formation volume factor (Sm3/m 3) Gas expansion factor (Sm3/m 3) Formation Water Salinity (NaCI ppm) Resistivity (ohmm at ~ Field Characteristics Area (km 2) Gross rock volume (106m ~) Initial pressure (bar) Pressure gradient (bar/m) Temperature (~ STOIIP (surface conditions) (mmbbl) GIIP (surface conditions) (bcf) Recovery factor oil, gas Drive mechanism Recoverable oil/cond. (mmbbl) Recoverable gas (bcf) Production Start up date Production rate plateau, oil (BOPD) Production rate plateau, gas (mmcfpd) Number/type of well (planned)
Dunbar
Tilted fault blocks West Flank Frontal/Central 3300 3500 3670 3800 3650 (ODT) 3797 (ODT) 350+ 297+ Brent M. Jurrasic West Flank Frontal 90 280 0.8 0.7 16 14 54 32 90 75 6 3
43 1.3 0.09 375 at 126 375 at 126 500 -
Volatile oil 42 1.3 0.12 350 at 136 350 at 136 300 -
Dunbar
Tilted fault blocks 3130 3620 3620 490 Stat0ord L. Jurrasic Stat0ord 40 0.38 12 43 82 6
Upper Lunde U. Triassic Lunde 449+ 0.13 13 2 57 6
Volatile oil 41 -
1.3 0.15 355 at 132 355 at 132 250 -
3.0
2.7
2.4
21000 0.29 at 25
35 000 0.19 at 25
21000 0.29 at 25
Ellon
Grant
Tilted fault blocks
Tilted fault blocks
3120 3280 3239 3282 119 43
3280 3550 3534 3555 254 21
Brent M. Jurassic
Brent M. Jurassic
185 0.47 18 536 88 70
190 0.6 19 500 86 100
Condensate + oil rim 45 (cond) 26 (oil) 36 0.664 2.6 (oil rim) 433 (oil rim) at 117 546 at 117 2450 789 72 1.5 (oil rim)
Condensate + oil rim 45 (cond) 28 (oil) 36 0.682 3.37 (oil rim) 316 (oil rim) at 118 533 at 118 2531 789 70 1.42 (oil rim)
325
314
50000 0.13 at 25
36000 0.173 at 25
6 438 565 0.034 117 131
3.5 345 586 0.035 118 27
33 2734 570 0.05 128 561
15 1496 575 0.05 130 129
1709 0.29, 0.49 water injection 161 833
339 0.19, 0.42 wateri~ection 25 145
332 0.06, 0.42 natural depletion 8 138
237 0.22, 0.68 natural depletion 6 162
December 1994 40000 90
December 1994 10000 15
December 1994 9000 88
December 1994 5800 88
17 producers 5 water injectors
3 producers 1 water injector 1 subsea producer
2-3 producers (subsea)
1-2 producers (subsea)
N.B. All depths are mTVDss. The discovery, appraisal and development of the Alwyn South complex was achieved as a result of the technical expertise, dedication and determination of numerous geoscientists and reservoir engineers from both companies as well as several contractor companies whose efforts are acknowledged. The author wishes to thank those individuals, too numerous to mention by name, who contributed to the internal Total documents which were used to compile much of this paper. John Giuyas, Jim Harris and Dave Pilling are thanked for their constructive comments. The permission of Total and Elf to publish this paper is gratefully acknowledged.
References
BIGNO, Y., BAILLIE, J. M. & COOMBES,T. P. 1998. The interpretation of Reservoir Pressure Data in the Dunbar Field (UKCS). SPE Reservoir Evaluation & Engineering, Paper 51383. DEEGAN, C. E. & SCULL, B. J. 1977. A standard lithostratigraphic nomenclature for the Central and Northern North Sea. Institute of Geological Sciences, Report 77/25.
DUNBAR, ELLON AND GRANT FIELDS INGLIS, I. & GERARD, J. 1991. The Alwyn North Field, Blocks 3/9a, 3/4a, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 21-32. JOHNSON, A. • EYSSAUTIER,U. 1987. Alwyn North Field and it's regional geological context. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 963-970. JOURDAN, A., THOMAS, M., BREVART, O., ROBSON, P., SOMMER, F. & SULLIVAN, M. 1987. Diagenesis as the control of the Brent sandstone
281
reservoir properties in the Greater Alwyn area (East Shetland Basin). In: BROOKS, J. & GLENN~E, K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, 951-961. STEEL, R. J. 1993. Triassic-Jurassic megasequence stratigraphy in the northern North Sea, In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the 4th Conference. Geological Society, London, 299-315.
The Harding Field, Block 9/23b A. J. BECKLY I'2, T. N A S H 1, R. P O L L A R D 1, C. B R U C E 1, P. F R E E M A N 1, & G.
PAGE 3
1BP Exploration, Burnside Road, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB, UK 2 Present Address." Reservoir Management Ltd, 7 Bon Accord Square, Aberdeen A B l l 6D J, UK9 (e-mail: a.beckly @ rml.co, uk) 3 Baker Atlas Geoscience, Kettoc Lodge, Balgownie Drive, Aberdeen AB22 8GU, UK
Abstract: The Harding Field was discovered in 1988 and lies within Block 9/23b, 320 km NE of Aberdeen, on the western flank of the Crawford Ridge. Appraisal drilling found a series of Tertiary accumulations along the Crawford Ridge, and, though most have an apparent element of stratigraphic trapping, a larger structural closure is possible. The present development comprises two heavy oil accumulations, Central and South, reservoired in massive sands of the Eocene Balder Formation. Deposited by mass flow processes, these clean and well-sorted sands have been further homogenized by post depositional remobilization and injection. There are seven horizontal producers in Central and three in South, with pressure support by water injection. Reservoir quality is exceptional, with permeability in excess of ten darcies and PI's for the horizontal producers in excess of 1000 STB/psi. Production started in April 1996 achieving a plateau rate in excess of 90 MMSTBPD with 40% of the estimated 200 MMSTB reserves recovered in the first three years. Four smaller Tertiary satellite pools are presently under appraisal and development by extended reach drilling from the platform.
The Harding Field lies within Block 9/23b, 320 km NE of Aberdeen on the western flank of the Crawford Ridge. Originally sanctioned in 1992 as the Forth Field, it was renamed the Harding Field in 1993, in memory of David Harding, chief executive of BPX U K operations during field appraisal. The primary development is of two Eocene heavy oil accumulations, reservoired in massive sands of exceptional quality, which lie within the Balder Formation. Four satellite accumulations, discovered during the appraisal phase, are the focus of current activity but are not yet in production, and these are briefly discussed in the context of the field history. The Harding pools form part of the same play fairway as the Gryphon Field to the north.
History Block 9/23 was awarded in the third licensing round of 1970, but following three unsuccessful wells the western part of the block was relinquished. This part block (9/23b) was awarded to Britoil (70% operator), Hispanol (now Repsol 25%) and Berkeley (now Ranger
5%) in the ninth UKCS licensing round of 1985. In 1987 BP acquired Britoil but operatorship of the licence remained in Britoil's name. The second exploration well on 9/23b, located using 1984 2D seismic and drilled in 1986, encountered thin oil bearing sands in a secondary Eocene target, but these gave a poor flow rate on test. Later that year an additional 70 km of seismic data were acquired leading to the identification of a 'seismic mound' at the top of the Balder Formation, and the third exploration well was targeted at this in January 1988. The well encountered oil and gas in a 'Massive Sand' within the Balder Formation and achieved good flow rates on test. The Gryphon Field had been discovered in August 1987, and there followed an extensive exploration and appraisal drilling programme of the Eocene trend between 1989 and 1991 (Fig. 1). This drilling activity was still primarily based on 2D seismic data, which had been supplemented with an additional 150 km of data shot in 1988. A large (210km 2) 3D seismic survey, covering the Harding and Gryphon Fields was shot in 1990, but was not available for the majority of the appraisal drilling.
Fig. 1. Location map with appraisal drilling history. GLUYAS, J. G. & H~CHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 283-290.
283
284
A.J. BECKLY E T AL.
At the end of this drilling programme six Tertiary oil accumulations had been discovered within 9/23b along the length of the Crawford Ridge. Apart from Harding NE, the other satellites are at different stratigraphic levels to the main accumulations, Harding SE and Deep South are both within the Sele Formation whilst the North accumulation lies immediately above the top of the Balder Formation, and this interval has locally been referred to as the Frigg Formation equivalent (Newman et al. 1993). The key appraisal data was obtained in 1991 when a horizontal well, 9/23b-26y, was drilled and completed close to the OWC. Not only did the well demonstrate that the drilling and completion of horizontal wells was possible, but also maintained dry oil production over a period of 16 days at a rate of 6700 STBPD. This demonstrated higher permeabilites than had been obtained from core analysis and the capacity to successfully produce the oil despite the adverse mobility ratios with respect to both water and gas. Field development was sanctioned in 1992, and an innovative design of a three-legged jack-up platform, above a concrete gravity storage base, was selected. Export is by tanker loading. Prior to the start of development drilling the 3D seismic data was reprocessed and the first development well was spudded on 27 February 1996. First oil was on 22 April 1996 and by de-bottlenecking the plant a peak rate of 95 MBD has been achieved through a facility originally designed for a plateau rate of 64 MBD.
Structure The Crawford Ridge is the dominant structural feature of the area, a palaeo-high that separates the Bruce-Beryl Embayment from the Viking Graben. Below the Base Cretaceous Unconformity the Crawford Ridge is effectively the truncated crest of a rotational fault block generated by the large faults that down-throw the BruceBeryl Embayment from the East Shetland Platform (Fig. 2). At the
Tertiary reservoir level it is expressed as a broad compactional anticline. Wells drilled down to the Crawford Ridge have penetrated a thin Cretaceous cover over Permian and older strata, though later Mesozoic sediments thicken to the west within the Bruce-Beryl Embayment and are preserved to the east in the Viking Graben. Cross faults trending E - W dissect the Crawford Ridge and appear to have a subtle impact on the Tertiary reservoirs distribution, of which the northern edge of the Central sand body is a possible example (Fig. 3). However, there is little visible offset of the sand bodies by faults, the pools lying sufficiently west to be unaffected by the fault system bounding the Viking Graben, elements of which do appear to cut strata of similar age on the crest and eastern side of the Crawford Ridge. The most striking feature of the Harding reservoirs is the post depositional deformation of the sand bodies resulting in complex injection structures. These occur both at the small scale, as recognized in core (Newman et al. 1993; Dixon et al. 1995), and on the scale of the reservoir itself, with well A06z (Fig. 5) confirming the injected northern limb to Harding South, as predicted from seismic (Fig. 5). Such large-scale injection has been described from outcrop in California (Molyneaux 1999).
Stratigraphy The lithostratigraphic nomenclature largely follows that of Knox & Holloway (1992), with the main exception being the designation of the interval immediately above the top Balder as the 'Frigg Formation Equivalent' (as in Newman et al. 1993). The formations approximate closely the sequence stratigraphic breakdown of Dixon & Pearce (1994). In the absence of sands, the late Paleocene to Eocene interval can be correlated on logs with some confidence using the characteristic response of the Balder Tuff, and a series of gamma-spikes, taken to indicate flooding events, marking the tops
Fig. 2. Semi-regional seismic line showing depostional relationship to the Crawford Ridge.
HARDING FIELD
Fig. 3. Top Balder Time Surface. Sand bodies clearly shown due to differential compaction.
285
reservoir quality with permeability in excess of ten darcies, porosity close to 35%, and in the case of Central, a kv/kh value of 0.9. The consequence of this is that fluid variability, at least in the Massive Sand of Central, is as significant as that of the lithologies. The sand-bodies were deposited against the subtle drape feature of the Crawford Ridge by mass-flow processes and this is readily apparent from the top Balder Surface (Fig. 3). Given this partially ponded nature, neither the slope fan (Timbrell 1993) nor the basin floor fan (Shanmugam et al. 1996) is entirely appropriate. Deposition is clearly by the 'freezing' of a mass flow, though the total absence of sedimentary structures makes discrimination of the flow character difficult. A major uncertainty is the scale of the flows that deposited the sand bodies. The gross rock volumes contained in the accumulations could be deposited by single events, though biostratigraphic data indicates a degree of diachroneity in Central. The total absence of mudstone laminae or clasts in the 300 ft of Massive Sand cored in 9/23b-7, also suggests there was little erosion by the flow, or that it was flowing over earlier sand bodies. The main diagenetic element is carbonate cement though the controls on its distribution are uncertain. In Harding Central there is virtually none, but in Harding South there are obvious cemented zones, nodular in character, with variable distribution both vertically and laterally. From the horizontal wells there is some suggestion that the cements may be associated with subtle lineaments apparent on coherency processed seismic data. In Harding North there are more pervasively cemented zones, apparently due to the amalgamation of nodules. In all cases, the carbonate cements in the hydrocarbon leg have an isotopic composition identical to a non-ferroan calcite cement, identified as early (Watson et al. 1995). The absence of compartments in Central is further confirmed by its dynamic behaviour with no evidence of any barriers either horizontal or vertical; the pressure data have shown that the injected sands are also in communication. However, in Harding South the dynamic data does indicate areal subdivision (see section on Production) and there is also a subtle indication of layering. Figure 7 shows a correlation line through the wells that have penetrated Harding South. This illustrates a number of features, notably the presence of some earlier sand bodies but more particularly a thin interval circa 20 ft below the top. When well A06 was drilled the sands above this were depleted by 10 psi as compared to a depletion of 5 psi in the underlying section. Not only does this indicate a barrier, but also that there is a degree of regional communication despite the apparently isolated nature of the bodies.
Trap of sequences T45 (Sele), T50 (Balder) and T60 (Frigg) (Fig. 4; Dixon & Pearce 1994, fig. 3). Two different gross sand facies are recognized within the Balder Formation: the Massive Sand, arbitrarily taken as the clean sand below the deepest mudstone unit, and an Upper Sandy Unit which encompasses the interval from the top of the Massive Sand to the top of the shallowest associated sand. The Upper Sandy Unit is primarily present in Harding Central, and has not been observed to extend above the top of the T60. Where cored, or imaging data are available, the sand units in the Upper Sandy Unit are generally highly disturbed, in many cases clearly injected, and hence there is no direct evidence to assume that any of the them are depositional (Fig. 4). When the Upper Sandy Unit is well developed, the Top T50, and hence Top Balder pick, can become difficult to identify on a limited log suite and can easily be confused with the gamma-spike at the top of the T60. In this situation the Top Balder needs biostratigraphic control, though the seismic pick often remains reliable.
The isolated nature of the sand bodies gives the impression that each is a discreet pool with the depositional limits acting as a stratigraphic trap in all directions except the west. To the west there is a structural closure generated by the compactional drape over the Crawford Ridge. However, the similarity of live and residual hydrocarbon contacts between the pools and the indications of pressure communication between the accumulations, suggests the stratigraphic element may be more apparent than real. The difficulty in determining a structural spill point is two-fold with uncertainty in both the areal distribution of sand-bodies relative to any mappable horizon and the stratigraphic level of the spill-point relative to that surface as a result of sandstone injection. Injected sands are not seen above the top of the T60 interval, and though this is not a consistently mappable seismic horizon it probably represents the 'regional' seal, though the effective seal may be deeper locally.
Hydrocarbons and their source Reservoir The sands are clean, well sorted, and of fine to medium grain size. This, and the general lack of compaction, gives rise to exceptional
The hydrocarbons of the Harding pools are a heavy acid crude overlain by a gas cap of almost pure methane. The origin of the oil is presumed to be the conventional Kimmeridge Clay Formation
286
A . J . BECKLY E T A L .
Fig. 4. Stratigraphic column and characteristic log responses to both fluid and lithology.
HARDING FIELD
287
Fig. 5. N-S seismic line and geoseismic section through Harding Sorth and Harding Central. source in the Viking Graben that has subsequently been biodegraded within the reservoir. The gas~ volumes suggest significant thermogenic gas, though some may be a product of biodegradation of the oil. That the gas is nearly pure methane may also suggest that it has itself been biodegraded. In Harding Central, between the dry gas and heavy oil is a 'light oil rim', ~which has been observed consistently in all wells prior to the start of production (Fig. 4). The origin of this is poorly understood as are its precise characteristics, though it seems likely that it is some sort of fall out of fluids from the gas cap which are able to accumulate on the fluid interface because of the exceptional reservoir quality. It is interesting to note that the neutron-density logs respond to the top of this fluid whilst the sonic log responds to the base (Fig. 4) The hydrocarbons vary in propertie~ both between pools and vertically within pools. The main depth related changes are an increase in gravity and decrease in bubble point with depth. This is used to advantage in well management and is discussed further below.
Reserves and production The present estimate of oil in place (STOII~) for the two pools is 322 MMSTB, which is a reduction from the sanction estimate of 399 MMSTB. The primary reasons for this are the downgrading of the area of Harding Central west of the appraisal wells and a revised depth conversion of Harding South, which put more reservoir into the gas leg. These risks were recognised on the reprocessed seismic, prior to the start of drilling, and have been confirmed subsequently. The primary uncertainty on the volume of oil in place remains the position of the base reservoir and since the production wells were drilled without pilot holes, this has reduced the scope to demonstrate upside. The principle of the development has been to drill horizontal production wells greater than 600 m in length at a standoff of circa 70 ft from the GOC. These wells have productivity indices in excess of 1000 STB/psi and this allows minimal drawdown avoiding both gas coning and taking the reservoir pressure below bubble point at the level of the well. Pressure support and sweep is by water injec-
tion, and due to the high barium content of the formation water, the injection water is produced from the overlying Grid Member (Fig. 4). Associated gas is being re-injected into Harding Central. A detailed description of the development drilling has been given in a series of papers in World Oil (McLellan et al. 1998). Despite the reduced oil in place, reserve estimates have been increased from 185 MMSTB to 200 MMSTB over the same period. There are three main reasons for this: (1) The production wells are longer than planned and have been further optimised for recovery and sweep; (2) The residual oil saturation has been reduced from 28% to 23% based on laboratory measurements, and there is also evidence of lower relative permeability to water; and (3) Two additional production wells have been drilled into Harding Central, targeted at predicted attic oil in late field life. There was no pre-drilling of wells and therefore the ramp-up in production was determined by the speed with which wells were drilled and brought on stream. The initial plan had been to rely on natural pressure support to sustain production from two wells on Central whilst South was developed. The reduced completion length of the second well, together with the perceived more rapid pressure decline of Central, caused the activation of a contingency plan and the completion of the Central development with water injection prior to drilling on South. Two primary rules have governed reservoir management to date: avoidance of gas coning and to maintain the reservoir single phase around the producers. Despite the presence of a gas cap, the latter has been possible, even with some decline in reservoir pressure, due to vertical variation in fluid properties. Bubble point pressure decreases with depth, whilst reservoir pressure increases, thus providing a pressure difference greater than the required drawdown. The management strategy for gas coning has been to maintain a prudent rate, and to choke wells back as additional production becomes available. The production history for the two pools is shown in Figure 8, which also shows that production rate has considerably exceeded the original plan of 64 MBD. This has been made possible by the de-bottlenecking of the plant in response to the well potential. The result of this has been that 80 MMSTB have been produced in the first three years. The reservoir behaviour has been different between the two pools. In Harding Central water breakthrough and even tilting of
288
A. J. B E C K L Y E T A L .
I 6,575,000
I I I
t~ .O
~
g
~39/23B-11
9/23b
/
Abandoned Oil Producer
/
'--...~~/
Oil Producer
,,~ A10
~ o ~/Y
~
,,~A05
/
Water Injector
/
Water Producer
~.~ _rz.
Gas Injector
~.1 &
u) I
Contour Interval 5Oft in South lOOft in Central
I . 9J23B-lO
* 9/23-2
6,570,000 -
0.11 0
413,000
6,572,500 -
012SllltUlll MII05 (3.5l'Qlometre~
415,000
I
417,500
I
Fig. 6. Isochore of Massive Sand with developmemt well locations shown.
the gas-oil contact have been very well predicted by the reservoir model, corroborating the exceptional reservoir quality and homogeneity. In Harding South, the initial indications were very similar, with the first two producers, A06z and A09, showing an identical decline in pressure. However, when water injection was introduced, A06z showed much more marked pressure recovery and a divergent pressure trend from both A09 and the subsequent producer A14. On shut in, the pressure in A06z slowly declines as it rises in the other two producers. There is clearly a partial barrier isolating A06z,
and though there are potential lineaments on seismic there is little to distinguish these from others, which have no apparent impact. Production is presently being maintained in excess of 90 MBD, though water cut is slowly rising and will ultimately take the field off plateau. To this end the water-handling system is to be expanded and this is anticipated to extend plateau production to the middle of 2000. In addition the northern satellites and Harding Southeast are under appraisal and development using extended reach drilling. Oil production is expected to continue until 2010.
H A R D I N G FIELD
289
5of,I
SELE 'SPIKE' Fig. 7. Correlation line through appraisal wells and high angle development wells for Harding South.
Fig. 8. Production profile for the field showing distribution between wells and between Central and South.
The authors would like to thank Repsol UK Ltd, Ranger Oil (UK) Ltd. and BP Amoco for permission to publish this paper. Many people have contributed to the understanding of the Harding Field and in addition to those that appear in the reference list we would like to acknowledge the contributions made by team members, past and present: Dr Adrian Pearce, Dr Sue Fowler, Duncan Robertson, Jim Henderson, Nick Cameron, Stig Dale, Richard Pollard, Colin Bruce and Paul Butcher.
References DIXON, R. J. & PEARCE, J. 1994. Tertiary sequence stratigraphy and play fairway definition, Bruce- Beryl Embayment. Quadrant 9. In: STEEL, R.
(ed.) Sequence stratigraphy: Applications.for Exploration and Production in North West Europe. Norwegian Petroleum Society (NPF), Special Publication, 5, 443-467. DIXON, R. J., SCHOFIELD, K., ANDERTON, R., REYNOLDS, A. D., ALEXANDER, R. W. S., WILLIAMS, M. C. & DAVIES, K. G. 1995. Sandstone diapirism and clastic intrusion in the Tertiary fans of the Bruce-Beryl Embayment, Quadrant 9 UKCS. In: HARTLEY, A. & PROSSER, J. (eds) Reservoir characterisation of deep marine clastic systems. Geological Society, London, Special Publications, 94, 77-94. KNOX, R. W. O'B. & HOOLOWAY,S. 1992. 1 Palaeogene of the Central and Northern North Sea. In: KNOX, R. W. O'B & CORDEY, W. G. (eds) Lithostratigraphic nomenclature of the UK North Sea. British Geological Survey, Nottingham.
A . J . BECKLY E T A L .
290
MOLYNEAUX, S. 1999. Giant clastic dykes and sills of Santa Cruz, coastal California. Petroleum Exploration Society of Great Britain Newsletter, Feb 1999, t 20-125. NEWMAN, M. St. J., REEDER, M. L., WOODRUFF, A. H. W. & HATTON, I. R. 1993. The geology of the Gryphon Field. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 123-133. SHANMUGAM, G., BLOCH, R. B., MITCHELL, S. M., DAMUTH, J. E., BEAMISH, G. W. J., HODGKINSON, R. J., STRAUME, T., SYVERTSEN, S. E. & SHrELDS, K. E. 1996. Slump and debris-flow dominated basin -floor fans in the North Sea: an evaluation of conceptual sequence-stratigraphic models based on conventional core data. In: HESSELBO, S. P. & PARKINSON, D. N. (eds) Sequence Stratigraphy in British Geology. Geological Society, London, Special Publications, 103, 145-175. TIMBRELL, G. 1993. Sandstone architecture of Balder Formation depositional systems, UKCS Quadrant 9 and adjacent areas. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 107-t23. WATSON, R. S., TREWIN, N. H. & FALLICK, A. E. 1995. The formation of carbonate cements in the Forth and Balmoral Fields, northern North Sea: a case of biodegradation, carbonate cementation and oil leakage during early burial. In: HARTLEY, A. & PROSSER, J. (eds) Reservoir characterisation of deep marine clastic systems. Geological Society, London, Special Publiations, 94, 177 200.
Harding Field data summary
Trap Type Depth to crest (massive sand) GOC OWC Gas column (proven) Oil column
Pay zone Formation Age Gross thickness (massive sand)
Central
South
Structural/ stratigraphic' 5080 ft 5500 ft 5735 ft 700 ft 235 ft
Structural/ stratigraphic 5240 ft 5489 ft 5682 ft 249 ft 193 ft
Balder Fm Eocene 0-475 ft
Balder Fm Eocene 0-150 ft
Net/gross ratio Porosity (average range) Permeability (average range) Oil Saturation (average range) Productivity index
99% 35% 10 000 mD 92% > 1000 BOPD/psi
93 % 34%
20 Biodegraded 0.57 10 Depth variable 238 1.11
23 Biodegraded 0.57 5 Depth vairable 303 1.136
scf/rcf
168
168
NaC1 eq ppm ohm m
43 000 0.103
43 000 0.103
Field characteristics Area Gross rock volume Initial pressure (OWC) Pressuregradient (gas/oil) Temperature Oil initially in place (MS) Gas initially in place (MS) Recovery factor Drive mechanism Recoverable oil Recoverable gas
914 acres 107548 acre ft 2580 psi 0.055/0.38 psi/ft 140~ 236 MMBBL 257 BCF 60% waterflood 154 MMBBL 206 BCF
731 acres 44158 acre ft 2550 psi 0.055/0.38 psi/ft 140~ 86 MMBBL 34 BCF 53% waterflood 46 MMBBL 35 BCF
Production Start-up date
23rd April 1996
Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Gas oil ratio Formation volume factor Gas expansion factor Formation water Salinity Resistivity
Deg API
cp psig
Production rate plateau oil Number/type of well
89% > 1000 BOPD/psi
22nd December 1996 93000 BOPD 7 production 3 production 1 gas injection 0 gas injection 2 water injection 1 water injection
The Heather Field, Block 2/5, UK North Sea SIMON KAY
DNO Heather Team, R D S Resource Limited, Peregrine Road, Westhill Business Park, Aberdeen AB32 6JL, UK Present address." GeoPrize Ltd, Blackhall House, Drumoak, Banchory, AB31 5EU, UK
Abstract: The Heather oil field is located in Block 2/5 in the Northern North Sea. Oil is produced from sandstones of the Middle Jurassic Brent Group, at depths between 9500 ft and 11 600 ft below sea level. The field has been in production for over 20 years, and to date 120 M M S T B of oil have been produced out of an oil-in-place volume of 464 MMSTB. Although approaching noncommercial flow rates, an ambitious programme of field re-evaluation has been conducted since 1997 to identify remaining infill potential, and to investigate the development potential of satellite accumulations. New 3D seismic surveys shot in 1995 and 1997 have been combined to produce a continuous top reservoir map of the main field and adjacent satellite structures. The new mapping and an updated reservoir description were integrated with reservoir simulation models to identify zones of unswept oil. Main field infill projects have been identified which target the unswept oil, allowing extension of field life to be planned in conjunction with satellite field development. An additional 57 M M S T B of recoverable oil are expected to be produced from Middle Jurassic reservoirs in the main field and in satellite areas.
Fig. 1. Heather Field, location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 291-304.
291
292
S. KAY
The Heather oil field is located in Block 2/5 in the Northern North Sea, approximately 90 miles NE of the Shetland Islands (Fig. 1). Oil is produced from sandstones of the Middle Jurassic Brent Group, at depths between 9500ft and 11 600ft below sea level. Current (mid-1999) production is 5000 barrels of oil per day (BOPD) plus 25 000 barrels of water per day (BWPD), representing a field watercut of 83%. To date, 120 million stock tank barrels (MMSTB) of
oil have been produced from the Heather Field out of an estimated oil-in-place volume of 464 MMSTB. Production is from 21 gaslifted wells with pressure support from nine water injectors. The production facility is a single steel-jacketed platform set in 470 ft of water. Gas is imported from the western leg of the Far North Liquids and Associated Gas System (FLAGS). Oil is exported to the Sullom Voe Terminal via the Ninian Pipeline system.
Fig. 2. Heather Field: simplified depth map at top Brent Group. For clarity, only exploration and appraisal wells are shown on this and most subsequent figures.
HEATHER FIELD
History Block 2/5 was awarded in the fourth round of licensing in 1972, to a group of four companies with Unocal Exploration and Production Co. (UK) Ltd. (Unocal) as the Operator. Det Norske Oljeselskap (DNO) was one of the original licensees and is the only participant that has been involved in the field from the original application to the present day. The group had identified a large Mesozoic structure on a reconnaissance seismic survey shot in 1971. The structure was further defined prior to drilling by a seismic survey shot in 1972 at a 2 km line spacing. The Heather Field discovery well, 2/5-1, was drilled in 1973. Between 1974 and 1987, sixteen more exploration and appraisal wells were drilled in Block 2/5. These demonstrated that, in addition to the main field area, a down flank oil accumulation was present in Northwest Heather; and satellite oil accumulations were present to the south and west. The latter were referred to as the North Terrace, Southwest Heather and West Heather (Fig. 2). To date, all production has been from Brent Group sands. Oil was also encountered in Southwest and West Heather in sands tentatively identified as Emerald (Callovian) Sandstone, which has been productive in the Emerald Field in neighbouring Block 2/10 (Stewart & Faulkener 1991). Triassic-age Cormorant Formation sands are also oil-bearing in the crest of the main field, and in Northwest, Southwest and West Heather. In the main field, a series of producer and injector wells designated 2/5-H1 to 2/5-H48 were drilled between 1978 and 1987. These formed the basis for the production infrastructure. In the mid1980s Unocal undertook a major field re-evaluation exercise. All of the geoscience work was compiled into a series of interpretative reports that formed a useful basis for later life-of-field extension work. As a result of field re-evaluation studies between 1988 and 1991, Unocal drilled a further ten wells (2/5-H49 to 2/5-H58Z) as infill projects. These targeted various parts of the main field plus an area where narrow faulted terraces of Brent Group could have been expected on the southeast flank, downthrown from the main field area. They were important in maintaining production and arresting the rate of field decline, but failed to locate new oil in the southeast flank.
Fig. 3. Seismic line across the Heather Field (see Fig. 2 for line location).
293
Oil production from the Heather Field commenced in October 1978 and peaked at a yearly average of 33 500 BOPD in 1982. Since then production rates have slowly declined. By the early 1990s Unocal was considering cessation of production (COP) and a draft COP document was prepared in 1993. COP was tentatively scheduled for late 1994 or early 1995. However, DNO, originally a minority partner, believed that it was possible to extend field life and took over as Operator in July 1997. D N O is the current Operator and holds 100% beneficial interest. This paper describes progress in Heather Field development and production since 1991, as an update of the paper published by Penny (1991). However, it does not repeat the basic field history and description included in that paper. The focus is on the changing understanding of key aspects of the field; notably structural framework, field extent, evaluation of satellite structures, oil-in-place, recovery, and potential for increased production.
Structure and trap At top Brent level, the Greater Heather area appears as an unusually wide terrace protruding from the N - S oriented East Shetland Platform margin (Fig. 2). On seismic, the terrace has a tilted fault block appearance, with pre-Middle Jurassic strata dipping down to the northwest (Fig. 3). A large N E - S W trending normal fault zone bounds the crestal area of the Heather Field. The fault displaces basement and the throw across the fault zone is of the order of thousands of feet. The fault zone is poorly imaged by even the most recent (1997) 3D seismic data. The large throw may, in fact, be accommodated by a series of narrow terraces. In contrast to the basement-involved faulting, smaller faults within the field appear to have a listric form and sole out in basement (Fig. 3). Main field closure is by normal faulting down to the basin on the east, northeast and southeast sides, by dip closure to the northwest, and by fault closure against a major East Shetland Platform Boundary (ESPB) fault to the west.
294
S. KAY
The East Shetland Basin formed in response to E - W extension during the Mesozoic, with the geometry of the basin and fault orientations influenced by older structural trends. Extension probably peaked in late Jurassic times, followed by post-rift subsidence during the early Cretaceous (Roberts et al. 1993). It is clear that faulting in the Heather Field is influenced by N E - S W Caledonian trends and N - S Variscan trends, with later Mesozoic extension reactivating the older compressional features. Seismic data indicate that movement on large faults such as the ESPB fault continued until Miocene times. The Cormorant Formation was deposited during an earlier Triassic syn-rift phase and thickens considerably from west to east: from 300 ft true vertical thickness (TVT) in well 2/5-8b to 3500 ft TVT in well 2/5-4. The Dunlin Group and the lower Brent Group were deposited within a gently subsiding intra-cratonic basin
and are pre-rift sequences. The lower part of the Brent Group (the Broom, Rannoch and Etive Formations) maintains a fairly constant thickness across the field of approximately 140 ft TVT, while the upper part (the Ness and Tarbert Formations) is more variable in thickness. The Upper Brent is a syn-rift sequence and the thickness variation reflects the onset of rifting during early Bajocian time. Ness Formation thickness variation (from absent in crestal areas to 122 ft TVT in the extreme east of the Heather Field) is caused by a combination of factors: crestal erosion, net-to-gross variations related to frequency of channel sands, and fault-related thickening to the east of the field. The Tarbert Formation exhibits similar thickness variation: it is absent at the crest of the Heather Field and reaches a maximum of 112 ft TVT to the east of the field. The Tarbert Formation also thickens downflank to the N W and to the SE.
Fig. 4. Improvements in top Brent mapping between 1987 and 1997. Contour interval 500 ft. (a) Map produced in 1987 based on 1979/1981 3D seismic data. (b) Map produced in 1997 based on scanned and reinterpreted 1979/1981 3D seismic data. (c) Map produced in 1997 based on 1997 3D seismic data.
HEATHER FIELD This thickening is probably a result of deposition of sands eroded from the field crest. Crestal erosion had ceased by the late Bathonian and the Heather Field is blanketed by late Jurassic Heather and Kimmeridge Clay Formation mudstones. Movement on the ESPB Faults continued into the Callovian, as indicated by thickening of syn-rift Emerald Sand deposits towards the platform margin in Southwest Heather.
(2) (3) (4) (5) (6)
295
Continuity cube processing to assist in fault pattern recognition. Semi-regional structural geology review to guide fault interpretation. Generation of well 1D synthetic seismic traces to tie wells to seismic and pick the top reservoir event. 2D modelling to examine and characterize the variability in top reservoir seismic response. Review of acoustic impedance and other seismic attributes with respect to reservoir layer properties. Feasibility study of full field seismic inversion.
Top reservoir mapping
(7)
As is typically the case with many North Sea fields, Heather has been subject to several generations of seismic survey and interpretation, leading to progressive refinement of the understanding of structural complexity. At the same time, new well and production data have been used to identify faults and production barriers at or below seismic resolution. The field was originally recognized, on a reconnaissance seismic survey shot in 1971, as a large Mesozoic structure. A 2-km grid was shot in 1972 that defined the structure as a northwesterly dipping tilted fault block. Gray & Barnes (1981) and Penny (1991) have published earlier examples of top reservoir maps. Four 3D surveys have been acquired: the first two were shot in 1979 and 1981. These surveys were among the first 3D surveys shot in the North Sea. The 1979 survey covered the main field area at 75-m line spacing, while the 1981 survey covered the main field flank at the same spacing, with overlap onto the 1979 survey. These surveys formed the basis for structural control on the field through peak production years, plateau and initial decline (Fig. 4a). Unfortunately, part of the 1979/1981 digital 3D dataset was subsequently lost during the transfer of operatorship. In order to update the interpretation, D N O attempted a reinterpretation of the 1979/1981 data set using scanned seismic images from paper copies. The scanning process degraded data quality and it was hard to see smaller scale faulting. The resultant map (Fig. 4b) lost much of the structural coherence of the earlier Unocal map. It was then recognized that a new 3D dataset was required to provide an improved reservoir description and for infill project evaluation. In 1995 a 3D survey was acquired over the western part of the Greater Heather area, followed by the most recent survey in 1997 over the main field. Both surveys were shot at 25-m line spacing using virtually the same acquisition and processing parameters. The 1995 survey was shot by Western Geophysical and processed by Ensign Geophysics Limited. The 1997 survey was shot by GECO and processed by Veritas DGC. On the 1981 data, the base Brent Group (top Dunlin Group) reflector was mapped and top reservoir maps were generated by isochoring up from the base Brent Group. Improved resolution and processing enabled a direct pick of the top Brent reflector to be made on the 1995 and 1997 data. The latest top reservoir map (Fig. 4c) closely resembles the earlier Unocal map (Fig. 4a) but the field boundaries are better constrained. Note that for the first time the field is recognized as extending west as far as an ESPB Fault. The field is intensely faulted, with multiple small faults of varying orientations connecting a predominant N E - S W series of faults (Fig. 4c). Variation in the topography of the basal detachment recognized on seismic surveys (Fig. 3) may have been responsible for the multidirectional nature of the minor faulting. The fault pattern within the field is fairly well constrained by the interpretation of production data. It is likely that the density of faulting in the satellite areas is similar to that of the main field, but has not been as well resolved by older seismic.
Continuity processing was used to generate a fault pattern from disruptions to the trace-to-trace wavelet continuity pattern (Fig. 5a, b). Fault-related discontinuities are not the only source of disruption to trace patterns. Other seismically-generated noise and lithological variations will generate similar features. Also, the direction of shooting can generate artificial trends. It is therefore necessary to exercise care when interpreting faults using continuity data as a guide. The continuity cube was employed as a guiding backdrop to the detailed seismic interpretation. The continuity display (Fig. 5a, b) clearly shows areas of intense faulting as highly
Seismic interpretation and modelling Modelling studies were conducted to aid interpretation of the 1997 3D seismic data. The modelling approach was structured in the following order: (1)
3D seismic acquisition and processing with independent quality control.
Fig. 5. Heather map field top Brent continuity display, 1997 3D seismic dataset. (a) Platform and well tracks only. (b) Interpreted fault pattern.
296
S. KAY
disrupted, black and white speckled areas, with lower fault density displayed as smoother more uniformly white to pale grey areas. Oil recovery is lower in intensely faulted areas and the continuity display also functions as a crude indicator of oil recovery (with good recovery in areas with little disruption). In down-flank areas northwest of the platform the relationship of faulting with oil recovery fails to apply. Here, the display indicates non-disrupted areas where recovery should be good, but recovery is actually poor in places. Core data have shown that this is the result of heavy calcite cementation and clay diagenesis at depth. It was recognized early in the interpretation process that the seismic signature of the top Brent Group changes spatially across the field. One-dimensional synthetic seismic well ties were generated using all wells with valid data. These confirm that the data polarity is North Sea normal, with an increase in acoustic impedance represented by a trough. The entire Brent Group is typically represented by a peak-trough-peak (PTP) signature across most of the Heather Field (Fig. 6). The narrow signature underlines the difficulty of applying seismic attribute mapping on the field. The Top Brent response is dependent upon changes not only within the topmost Brent, but also upon lithology-related density changes just above the Brent in the basal Heather sequence. A peak does not solely represent the top Brent: a low impedance event in the basal Heather Formation occurs over most of the field, and this contributes strongly to the generation of a peak. Below this, the top Brent is usually represented as a zero crossing and occasionally as a trough. The PTP signature changes to a peak-trough (PT) response over the crest of the field, related to Brent section thinning (Fig. 6).
In areas where there is a thicker Brent section (for example around well 2/5-3) a change to a trough-peak-trough-peak (TPTP) signature occurs, which represents the total Brent sequence. A TPTP signature is also seen in other parts of the field where the Brent sequence is thicker, such as around well 2/5-9. In two areas of the field a peak-trough-peak-trough-peak (PTPTP) signature (Fig. 6) represents the Brent reservoir. This does not relate to a variation in the thickness of the Brent, but may reflect a relationship between seismic response and variation in reservoir quality. These areas are known to be more heavily calcite cemented. This could be further studied through detailed facies analysis. Acoustic impedance trends were derived from well log data and cross-plotted against Brent Group zonal averages for porosity, net sand and water saturation. Porosity was found to be the dominant influence on acoustic impedance within the reservoir sequence. A residual porosity variation was estimated by removing the effect of depth to highlight the influence of lithology, facies and diagenesis. Heterogeneity based on these influences can account for porosity variations up to 6%. No interdependent relationships were observed between acoustic impedance and net sand thickness or water saturation. Acoustic impedance is variable between different formations of the Brent Group. The Lower Brent is of fairly constant thickness across much of the field, but is overlain by Ness Formation deltaic deposits and Tarbert Formation marine sands of more marked thickness variation. The Ness Formation has lower acoustic impedance due to the presence of coals. Where the Tarbert Formation is absent over the field crest, the Ness Formation dominates the top Brent seismic response. The Lower Brent generally shows a gradual top to bottom increase in acoustic impedance. The lowermost 100 ft of the Heather Formation and the uppermost 100 ft of the Dunlin Formation were used to help visualize the acoustic impedance contrasts at the top and the base of the reservoir. Depth/porosity/ acoustic impedance trends were different for different Brent formations, indicating variation in response to compaction with depth of burial. As a result the ability to discriminate between zones using acoustic impedance is greater where the reservoir is buried more deeply. This will have significant effect on the seismic expression of the reservoir, which varies with depth across the field. At the crest of the field, there is a convergence of acoustic impedance trends, reducing the seismic contrasts of intra-reservoir reflections. A seismic inversion of the entire Heather Field was not pursued at this stage due to bandwidth limitations (the peak frequency at Brent level is only 25 Hz), wavelet variations, and presence of a base Cretaceous multiple problem over part of the field.
Trap
Fig. 6. Variation in seismic response across the Heather Field. Display convention is North Sea normal polarity.
Until the top Brent reservoir was remapped using 1997 3D seismic data, the extent of the oil pool was poorly understood. The Heather Field is highly compartmentalized by faulting, and apart from in Northwest Heather, down flank reservoir porosity is heavily occluded by calcite cement. No field-wide oil-water contact (OWC) had been encountered, but the reason for this was not clear. The waterbearing reservoir between the main field and Northwest Heather oil pools is a heavily calcite-cemented zone. Oil was not able to migrate through the zone because calcite cement growth predated oil emplacement (Miller 1992). Well 2/5-15 demonstrated that Northwest Heather and the main field are connected via a zone adjacent to a branch of the ESPB Fault. The ESPB Fault strikes N-S along the boundary between Blocks 2/4 and 2/5 (Fig. 2). In most parts of the main field, the entire Brent Group is oil-bearing. It now appears that the Heather Field is probably full to spill, with a spill point down-dip of well 2/5-14Z. The extreme eastern part of the field, around well 2/5-3, is isolated from the main field by faulting. Well 2/5-3 encountered water-bearing reservoir. An OWC was encountered at 10 437 ft true vertical depth sub-sea (TVDSS) in former production well 2/5-H 11, approximately 1 km south of well 2/5-3. This is the only part of the main field where the OWC has been encountered.
HEATHER FIELD Where oil extends as far as the ESPB Fault, cross-fault seal is provided by metamorphic basement lithologies. Top seal is provided throughout the area by mudstones of the late Jurassic Humber Group. The Humber Group extends across the crest of the Heather Field, demonstrating that crestal Brent erosion must therefore have occurred during the mid to late Jurassic. West Heather, Southwest Heather and the North Terrace also trap oil in a structurally higher terrace adjacent to the ESPB Fault. In addition to oil in the Brent Group reservoir, a younger Callovianage oil-bearing sand is present in West and Southwest Heather. The younger sand is believed to correlate with the Emerald Sand, the reservoir for the Emerald Field located to the south in Blocks 2/10, 2/15 and 3/11. In the Heather area, this sand is informally referred to as the Emerald Sand. The Emerald Sand directly overlies eroded basal Brent Group sands in West and Southwest Heather. The Emerald Sand is absent in the North Terrace, but there is a fully developed Brent Group sequence. Note that there has been no production to date from any of the Heather area satellite discoveries and these await further appraisal.
Fig. 7. Heather Field: Triassic and Jurassic reservoir distribution.
297
Table 1. Basin margin reservoir distribution Well
Area
Reservoir
2/3-1
East Shetland Platform
Paleocene overlying Lower Brent, Dunlin and Cormorant
2/4-1
East Shetland Platform margin
Paleocene overlying Cormorant
2/4-2
East Shetland Platform margin
Kimmeridge Clay overlying metamorphic basement
2/5-8b
Terrace between platform margin and Heather Field
Emerald Sand overlying eroded Brent, Dunlin and Cormorant
2/5-17
Terrace between platform margin and Heather Field
Complete Brent overlying Dunlin and Cormorant
298
S. KAY
As already stated, Triassic age Cormorant Formation nonmarine sands also hold oil beneath Jurassic strata in the crestal part of the main field (tested by wells 2/5-4 and 2/5-7) and in Northwest, Southwest and West Heather. Drill stem test permeabilities from well 2/5-4 ranged between 0.14 and 2.3 millidarcies (mD). The risk on reservoir continuity and permeability has been considered too high to attempt production from Triassic sands, although future consideration may be given to a long horizontal well targeting the Triassic in the crestal field area.
Reservoir stratigraphy It has proved difficult to predict the distribution of reservoir units at the East Shetland Basin margin. Basin margin wells encountered a varied stratigraphy (Table 1). The Brent Group reservoir is patchily present on the East Shetland Platform. It is present in well 2/3-1, west of Heather, and can be convincingly mapped on seismic surveys. However, it appears to be absent on those parts of the platform margin adjacent to the Heather Field, and is absent in wells 2/4-1 and 2/4-2. Both the Emerald Sand and the Brent Group sands are preserved in the terrace between the platform margin and the main field (Fig. 7).
Jurassic sediments overlie Triassic continental red beds, which were deposited in a braided stream fluvial setting. Triassic sediments are assigned to the Cormorant Formation. The Cormorant Formation tends to have poor reservoir quality as a result of clay and calcite cementation. However, within the Heather Field the upper part of the Cormorant Formation can have better reservoir quality, where sands appear to be cleaner fluvial deposits of meandering channel type. No new geoscience work has been conducted to further evaluate the Triassic of the Heather area. The well correlation (Fig. 8) and chronostratigraphic summary (Fig. 9) illustrate Jurassic reservoir stratigraphy. The regional stratigraphy of the Brent Group has been well documented elsewhere (Morton et al. 1992; Rattey & Hayward 1993), and a description of Heather Field Brent Group stratigraphy and depositional setting has also been published (Penny 1991). There is full development of the five constituent Brent Group formations in the Heather Field: the Broom, Rannoch, Etive, Ness and Tarbert Formations. The Lower Brent (Broom, Rannoch and Etive Formations) has a fairly consistent thickness across the Heather Field, averaging approximately 140ft thick. Most of the thickness variation in the Brent Group (see isochore background on Fig. 6) occurs in the Upper Brent (Ness and Tarbert Formations) as a result of faulting, either as erosion across the field crest or thickening in local areas of fault subsidence.
Fig. 8. Heather Area Well Correlation. The correlation datum is at top Brent Group and logs are displayed in feet true vertical depth sub-sea.
HEATHER
FIELD
299
Fig. 9. J u r a s s i c c h r o n o s t r a t i g r a p h y .
There is biostratigraphic evidence for a time gap between the Tarbert Formation and the rest of the Brent Group (Fig. 9). The Tarbert Formation may in part have been deposited from eroded and reworked Lower Brent section. The Tarbert and Ness Formations are thin to absent over the crest of the Heather Field. Over the crest Lower Brent is overlain by Heather Formation mudstones, suggesting the period of erosion was probably in the Callovian. In the terrace area to the west, Brent Group sands and older Triassic sands may have been eroded to form the source of the Heather or Emerald Sand. In Southwest Heather, as in the Emerald Field, the Emerald Sand thickens to the west, indicating syn-depositional movement on the faults of the East Shetland Platform margin. In Southwest Heather, there is a reduction in grain size in the Emerald Sand, from west to east, from sandstone in well 2/5-10 to siltstone in well 2/5-11.
5
10
1
0
9o
**~
35
4~
~
-10000 ~ ~176
I oO
o~
;t 1
-10500
O'
s,1 r
Reservoir quality
Porosity, %
-9500
oO~ o
~ -11000
'L ~
~
,
c-
There is a strong depth and facies control on Brent Group reservoir quality. The porosity trend with depth for the entire Brent Group is illustrated (Fig. 10). Northwest Heather shows relatively better porosities at depth than the main field. This may be related to early oil migration into Northwest Heather (see discussion on oil source and maturity, below). Brent Group formations are largely defined by depositional facies (Table 2). The overall Brent sequence in the Northern North Sea is one of delta progradation, with sediments becoming increasingly non-marine, until the final phase of marine transgression and flooding of the delta. In the Heather area, the predominant facies are shoreline-related. Highest quality reservoir sands are located in the Tarbert and Etive Formations, which are both upper shoreface sands. Oil production has been predominantly from these formations. The Tarbert Formation is probably reworked Ness Formation, winnowed, washed and cleaned by wave action. Sedimentary facies can be ranked in terms of reservoir quality as indicated in Table 3.
a
::*~ ~
-11500
9 ~
~
J ~A o~
-12000
J
-12500
J ~
9
Main Field
~
A
Northwest Heather
................................................................... ~...........................................................................................................................................................................................................................
Fig. 10. P o r o s i t y / d e p t h trends.
300
S. KAY
Table 2. Depositional facies of Brent Formations Formation
Facies
Tarbert Ness Etive Rannoch Broom
Shoreface, delta abandonment Delta plain, marsh & bay Upper Shoreface/Foreshore Mid-Lower Shoreface Fan Delta
Table 3. Reservoir quality of Brent Group depositional facies
Best
Worst
Facies
Porosity, % Range (Avg.)
Perm, mD Range (Avg.)
Upper shoreface Foreshore Fan delta Lower shoreface Distributary channel Distributary mouth bar Washover Crevasse splay Tidal flat
1 25, 2-24, 1-26, 1-25, 4 21, 4-19, 8-14, <1-27, 1.5-14,
0.01-2024, 134 0.01-1489, 108 0-1852, 70 0.01-888, 51 0.01-691, 49 0.01-117, 14 1-41, 13 0.01-188, 9 0.01-111, 11
Shelf
16 16 11 14.5 14 15 12 11 9
~10, 4
0.01 1.5, 0.4
The Heather Field Brent reservoir is heavily affected by diagenesis. Carbonate cements (primarily calcite) have the biggest negative impact on reservoir quality, followed by quartz, K-feldspar and clay minerals. Calcite cement was precipitated mainly during early burial (less than 5000 ft), as shown by loose packing of grains in the cemented zones. Unocal had previously mapped gross reservoir calcite content from electric log response. The Broom and Rannoch Formations are most heavily impacted by calcite cement, but degradation of porosity is not uniform across the field. The highest part of the structure is least affected. There is no evidence of crestal dissolution of calcite cements, implying that calcite was not precipitated in crestal areas. Meteoric flushing during the late Jurassic to early Cretaceous probably inhibited cementation at the crest (Glasmann et al. 1989). Major calcite cementation is restricted largely to the northeast and southwest parts of the field. Northwest Heather is much less affected. In downflank areas, illite and kaolinite growth significantly reduces productivity in the Broom and Rannoch Formations, and there is a depth cutoff of approximately 11 000ft TVDSS for productive reservoir. The depth cutoff may be related to growth of clay minerals such as illite, although quantitative data are not sufficient to prove this. K/Ar dates for illite are between 30 to 40 million years, with oldest dates between 50 and 57 million years. Illite formation may have ceased with oil emplacement that is thought to have commenced in the early Tertiary. The Etive and Tarbert Formations are potentially productive down to 12 500 ft TVDSS, based on test results from appraisal wells 2/5-13 and 2/5-14Z. These formations may have better reservoir quality at depth because a lower detrital feldspar content may restrict the formation of authigenic clay minerals. Also, early migration of oil into the more permeable sands of these formations may have arrested illite and quartz cementation sooner than in the other formations of the Brent Group (Miller 1992). The Mid Jurassic reservoir sequence in well 2/5-8b was completely cored. Thus there is a good understanding of reservoir quality in the West Heather terrace. At the base is a coarse-grained fan delta sand that is assumed to correlate with the Broom Formation. This is separated from the overlying Emerald Sand by a thin marine mudstone. The basal part of the Emerald Sand is a coarse-grained fan delta sand very similar to the underlying Broom Formation. The coarse basal unit passes up into very fine to medium-grained shoreface sands, similar to those of the Etive or Tarbert Formations. Muddy shoreface sandstones at the top of the
Emerald Sand indicate deepening water conditions. The shoreface sand component of the Emerald Sand in West Heather shows the same upper and lower subdivision as in the Emerald Field, with a high gamma ray micaceous sand marking the base of the upper unit. Well 2/5-8b does not show the same degree of fining-up as in the Emerald Field, so the reservoir quality of the upper unit may be better in West Heather. In well 2/5-8b, average Emerald Sand porosity is 18%, with net to gross sand ratio greater than 90%. Permeabilities are typically 100 to 500 roD, although thin high permeability sand beds exceed 1000 inD. The available Emerald Sand biostratigraphic data are poor. Although considered to be early to late Callovian, the reservoir age could be anything from early Bajocian to late Callovian.
Source Extensive geochemical studies were conducted by Unocal addressing source rock type, geothermal modelling, oil type analyses and pore water isotope studies. These are summarized here. Geochemical data have established the marine Kimmeridge Clay Formation (KCF) as the source rock for all Heather area oils. Two local source kitchens were identified by geothermal modelling, one to the north of the field and the second to the south and east (Fig. 11). Peak oil generation (defined as a vitrinite reflectance equivalent, Ro, of 0.9 %) was first reached in the deepest parts of the kitchens during Eocene times. Generation has continued until the present day. The K C F remains immature for oil generation directly above the Heather Field and West Heather terrace area. The K C F in the deepest parts of the kitchens should currently be in the gas generation window. Stable isotope data from kaolinite that formed during early diagenesis by feldspar dissolution suggest that the Brent Group was completely flushed by meteoric water during the early Cretaceous. More prolonged flushing at the crest of the Heather structure may have been responsible for inhibition of calcite diagenesis compared with deeper parts of the field. Today, formation water salinity is low (only two-thirds the salinity of seawater). Fluid inclusion and iilite isotopic composition data indicate that a limited amount of evolved saline compaction fluid entered the Brent Group prior to oil emplacement. These saline fluids are likely to have been expelled from the K C F and Heather Formation. Since the overall present day pore water composition is less saline than evolved compaction fluids, it does not appear that enough water was expelled from source rocks to flush meteoric water from the pore spaces. This implies that sourcing was relatively local and large fluid movements have not occurred. Relative thermal maturities of oil have been established using biomarkers such as hopanes, moretanes and steranes. These included phytane/nCl8 and pristane/nC17 ratios and trisnor-hopane pentacyclic compounds. The distribution of oil types (Fig. 11) indicates that least mature oils are located in West Heather, Southwest Heather, the North Terrace and adjacent parts of the main field. Most of the main field area contains oil of an intermediate maturity type. Most mature oils were found in the Triassic Cormorant Formation below the main field crestal area, in Northwest Heather and in a horst area north of well 2/5-3. Mixing of successive pulses of migrating oil is likely to have occurred. Triassic oil in well 2/5-7 shows a degree of oil gravity segregation, varying from 29 ~API to 38 ~ API. Wells 2/5-6 and 2/5-17 show a similar pattern of heavier oil at depth (15 ~ API) to 33 ~ API at the top of the Brent Group. Oil in wells 2/5-6 and 2/5-17 shows evidence of having been water-washed. Gas/oil ratio (GOR) distribution matches the oil maturities well (Fig. 11) with highest G O R associated with the most mature oil.
Impact of geoscience projects on reserves and production The D N O strategy on assuming Heather Field operatorship was initially to increase main field production by workover of existing wells and drilling of infill wells to target areas of unswept oil,
HEATHER FIELD
301
Fig. 11. Source rock kitchens and oil types of the Greater Heather area.
particularly in the lower permeability parts of the Brent Group. Once this was addressed, DNO would initiate satellite field development. In November 1999 D N O acquired 100% beneficial ownership of Blocks 2/4 and 2/5, and will commence a new phase of development drilling in 2000. Geoscience projects formed the basis for the DNO strategy, and were phased to match production requirements: (1)
(2)
(3)
Phase 1 - Reservoir model refinement through acquisition, interpretation and mapping of new 3D seismic data, mapping reservoir parameters, and recalculating oil-in-place to compare with produced volumes. STOIIP re-evaluation helped identify undrilled fault compartments containing significant oil volumes, although the main field STOIIP estimate did not change overall. The reservoir simulation model identified unswept areas of oil (Fig. 12). Phase 2 - Detailed reservoir mapping to identify zones of better quality, particularly downflank where diagenesis has impacted reservoir quality. Phase 3 - Concurrent with Phase 2 evaluation of satellite prospects and identification of appraisal drilling locations.
These three phases have been completed. Phase 1 and 2 results are being used to locally refine the reservoir simulation model in fault compartments in order to optimize infill producer and injector locations. At this late stage of field life, a complete rebuild of the full field reservoir simulation model was not considered worthwhile. As well as insights gained from new data gathering, reworking of old data also helped in understanding the field (for example, improvement of local reservoir models using existing calcite distribution maps coupled with a better understanding of reservoir quality/depth relationships). Future projects may include improved permeability mapping by depositional facies, improvement of porosity/permeability transform equations, quantitative clay diagenesis studies, evaluation of channel sand connectivity in the Ness Formation, and seismic inversion work. In 1991, it was estimated that the Heather Field recoverable reserves would total 100 MMSTB (Penny 1991). To date, 120 MMSTB have been produced. This is still only 25% of the estimated oil-in-place. The low recovery is primarily a result of the highly fault-compartmentalized reservoir and calcite diagenesis in flank areas. In the Heather Field, it is estimated that 13.5 MMSTB of oil remains to be recovered from the Brent Group from existing
302
S. KAY
Fig. 12. Movable reservoir barrels of oil. Total reservoir at end 1999 (bbl/acre). Polygons labelled A, B, C, D, E, F, G and H are producing blocks defined by differences in production and injection response, oil type, GOR and/or pressure.
drainage points. This could be boosted to 25 M M S T B by implementing the identified infill projects and drilling into u n t a p p e d fault c o m p a r t m e n t s . In addition, an estimated 32.3 M M S T B of oil could be recovered from the Brent G r o u p and Emerald Sand in N o r t h Terrace, Southwest and West H e a t h e r satellite accumulations. Reserves extension projects are itemized in Table 4 and illustrated by Figure 13. R e m a i n i n g oil can be recovered economic-
ally even at prices less than $15 per barrel. In the past year operating costs have been cut by 35% and the field can r e m a i n e c o n o m i c at t h r o u g h p u t as low as 3500 B O P D . Meanwhile innovative low-cost drilling options are being actively explored. It is h o p e d that the next published H e a t h e r Field update will be able to report p r o d u c t i o n from the Greater H e a t h e r area totalling at least 160 M M S T B .
Table 4. EmeraM Sand and Brent Group reserves extension projects
Opportunity
Drilling programme
Target
Expected recoverable oil volume, MMSTB
Main Field Baseline Life Extension
None - ongoing production
Brent Group
13.2
Main Field Infill
2 infill producers and 2 injectors
Brent Group
7.4
Main Field Compartments
3 producers and 3 injectors in undrilled fault compartments
Brent Group
4.1
West Heather
2 producers and 2 injectors - sub-sea tie-backs to Heather
Emerald Sand and Brent
15.3
North Terrace
2 producers and 1 injector - sub-sea tie-backs to Heather
Group Brent Group
12.3
Southwest Heather
No wells currently planned - additional seismic required
Total
Emerald Sand and Brent Group
4.7
57.0
HEATHER FIELD
303
Fig. 13. Planned additional well locations. Light green areas denote extent of oil accumulation, blue areas indicate water.
Conclusions The H e a t h e r Field has p r o d u c e d oil for Over 20 years. A l t h o u g h a p p r o a c h i n g n o n - c o m m e r c i a l flow rates, an ambitious p r o g r a m m e of field re-evaluation has been c o n d u c t e d since 1997 to identify remaining infill potential, and to quantify oil in satellite accumulations. N e w projects have been c o m b i n e d with reviews of existing field data to improve the reservoir description, u n d e r s t a n d i n g of oil pool distribution and relationships between the m a i n field and its satellites. Infill projects can be p l a n n e d in c o n j u n c t i o n with satellite field development to maximize extension of field life. Falling oil prices during 1999 led to a delay in implementing d e v e l o p m e n t projects. Infill drilling is n o w scheduled for J a n u a r y 2000 a n d incremental p r o d u c t i o n is expected to begin in the second q u a r t e r of 2000. The author wishes to acknowledge the contributions made by staff at DNO Heather Limited and Helix-RDS Limited. We are also indebted to the geoscience staff of the former Operator, Unocal, for extensively documenting their understanding of the Heather Field, in particular Brian Penny as the principal author of the field re-evaluation study.
Trap
Tilted fault block 9450
ft TVDSS
No gas cap Free water level not seen 1598 ft in main field
ft ft ft
Average Gross thickness (range)
0.1 to 10
% mD % BOPD/psi
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Gas/oil ratio Formation volume factor
32-37 low sulphur (0.7%) c. 0.91 0.4 to 0.66 1910 to 3890 450 to 1280 1.234-1.743
~API
22 000 0.326 @ 60~
NaC1 eq. ppm ohm m
13 947 4950 at 10 250 ft 0.29 to 0.31 227 to 242 464 31 water flood 146
acres psi psi/ft ~ mmbbl %
cp psig SCF/STB
Formation water
Salinity Resistivity
Area Initial pressure Pressure gradient Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil
mmbbl
Production
Pay zone
Formation Age
0.48 (0-1.0) 14.5 (10-24) 20 (0.1-2000) 41 (8-100)
Field characteristics
Heather Field data summary
Type Depth to crest Lowest closing contour GOC or GWC OWC Oil column
Ave Net/gross (range) Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Brent Group sandstones Middle Jurassic (Aalenian-Bathonian) 224 (125-370)
Start-up date Peak production rate oil Number/type of wells
October 10 1978 38 000 21 gas-lifted producers 9 water injectors
bopd
304
S. KAY
References GLASMANN, J. R., LUNDEGARD, P. D., CLARK, R. A., PENNY, B. K. & COLLINS,I. D. 1989. Isotopic evidence for the history of fluid migration and diagenesis: Brent Sandstone, Heather Field, North Sea. Clay Mineralogy, 24, 225-284. GRAY, W. D. T. & BARNES, G. 1981. The Heather Oil Field. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of N W Europe. Institute of Petroleum, London, 335-341. MILLER, J. A. 1992. Heather Field Re-Evaluation. SPE 22340. Paper presented at the SPE International Meeting on Petroleum Engineering, Beijing, China, 24-27 March 1992, 807-816. MORTON, A. C., HASZELDINE,R. S., GILES, M. R. & BROWN, S. (eds) 1992. Geology of the Brent Group. Geological Society, London, Special Publications, 61. PENNY, B. 1991. The Heather Field, Block 2/5, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 127-134.
RATTEY, R. P. & HAYWARD, A. B. 1993. Sequence stratigraphy of a failed rift system: the Middle Jurassic to Early Cretaceous basin evolution of the Central and Northern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe, Proceedings of the 4th Conference. Geological Society, London, 215-249. ROBERTS, A. M., YIELDING, G., KUSZNIR, N. J., WALKER, I. & DORNLOPEZ, D. 1993. Mesozoic extension in the North Sea: constraints from flexural backstripping, forward modelling and fault populations. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1123-1136. STEWART, D. M. 8z; FAULKENER,A. J. G. 1991. The Emerald Field, Blocks 2/10a, 2/15a, 3/1 lb, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdora Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 111-116.
The Kingfisher Field, Block 16/8a, UK North Sea SAMANTHA
SPENCE & HELGE KREUTZ
Shell UK Exploration and Production, 1 Altens Farm Road, Nigg, Aberdeen AB12 3FY, UK (e-mail.
[email protected] and
[email protected])
Abstract: The Kingfisher Field is located in the South Viking Graben, Block 16/8a, with a minor extension into Block 16/8c. Block 16/8 was initially awarded in June 1970 to Shell and Esso, with the Kingfisher discovery well 16/8-1 spudded in 1972. The well tested high HzS oil at marginal rates from Upper Jurassic Brae Formation sandstones. Subsequent appraisal well 16/8a-4 (1984) tested gas/condensate from better quality Brae Formation sandstone reservoirs. This well also discovered the deeper Middle Jurassic Heather Formation sandstone gas/condensate accumulation at near-HPHT conditions. The Brae and Heather Formation sandstones contain stacked hydrocarbon accumulations in separate combinations of stratigraphic and structural traps. Production by natural aquifer drive commenced from a sub-sea satellite to Marathon's Brae B platform in 1997, initially from the Brae reservoirs. To date, three production wells have been completed and a fourth well is planned to be on stream in 2000. The Brae Formation sandstones at Kingfisher are interpreted as distal deposits of the Brae/Miller fan-apron system and range in quality from excellent to very poor across the field. The Heather Formation reservoir consists of medium quality sands deposited within a submarine incised valley. The most recent volumetric estimate (1998) for the total field predicts an ultimate recovery of 41.2 MMBBL of pipeline liquids and 280 BCF of dry export gas. Regional reservoir architecture and connectivity as well as hydrocarbon composition are key to understanding the production performance of the critical gas/condensate below dewpoint. Advances in sub-sea and horizontal drilling technology have enabled field development.
The Kingfisher Field is situated 153 miles NE of Aberdeen, in a water depth of 110 m (Fig. 1). The structure at the Upper Jurassic Brae Formation sandstone level consists of a N W - S E elongated anticline which is fault-bounded to the northeast and stratigraphically closed to the east. At the Middle Jurassic Heather Formation sandstone level the structure comprises a tilted fault block with a steep southwesterly dip and stratigraphic closure to the east. The Upper Jurassic Kimmeridge Clay Formation and Middle Jurassic
Heather Formation shales provide the top seals to the Brae Formation and Heather Formation reservoirs respectively. Hydrocarbons are sourced from the Kimmeridge Clay Formation in the deeper Viking Graben. The free water levels for the Brae Formation sandstone accumulations are between 13 100 and 13220ft TVSS. The Heather Formation sandstone free water level is at 15 700 ft TVSS. The current licence holders for the Kingfisher Unitized Area are Marathon Oil U K (operator for Block 16/8c and the Brae 'B' Platform), Shell U K Exploration and Production (operator for Block 16/8a and Kingfisher), and Esso Exploration and Production UK. This paper outlines the geology and development history of the Kingfisher Field.
History
Pre-discovery and discovery Licence P. 116, initially comprising the Auk/Fulmar Block 30/16, the Kingfisher Block 16/8, and Block 22/2, was granted to Shell/Esso during the third Licensing R o u n d in 1970. Block 16/8 had been applied for to test the Middle Jurassic Brent play, with the Brent Field having been discovered just a few months before the drilling of Kingfisher discovery well 16/8-1 (Fig. 1). Whilst drilling the intermediate hole section in well 16/8-1, the rig reported sand traces within the Kimmeridge Clay Formation which later became named the Brae Formation sandstone and which tested 1276 BOPD with 500 ppm H2S. Reservoir was not encountered in the Middle Jurassic. Well 16/8-1 reached total depth after a high pressure/low volume water kick was encountered in the Pentland Formation, too high in pressure to be managed by any rig at that time. The Kingfisher discovery remained unnamed until 1995 but has been frequently referred to in the literature as 'Miller East'.
Pre-development appraisal
Fig. 1. Location map of the Kingfisher, Miller and Brae Fields in the South Viking Graben.
A large part of Block 16/8 was relinquished in 1976 but the more prospective Auk/Fulmar acreage, in Block 30/16, was retained. The western part (16/8b) together with the subsequent Miller discovery was later licensed to Conoco, whilst the eastern part (16/8c) was awarded to a joint venture led by Marathon Oil UK. Even though Shell/Esso recognized from the beginning the submarine depositional environment of the Brae Formation sandstones with a westerly provenance area, appraisal appeared uneconomic due to the distal location from the sand source until 12 years later when a further structure at Heather Formation level was identified. Well
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 305-314.
305
306
S. SPENCE & H. KREUTZ
Fig. 2. Top Brae Formation Unit 1 structure map. 16/8a-4 (1984) proved this structure to be hydrocarbon bearing and also confirmed the predicted improvement in Brae Formation sandstone quality to the west (Figs 2 and 3). Two separate tests of the Brae Formation sandstones produced volatile oil in the deeper Brae interval and gas/condensate from the shallower interval. Another appraisal well (16/8a-8, 1988) was therefore drilled to obtain information about the gas/condensate accumulation at Brae Formation level and again found a better reservoir than the previous wells, testing at a rate of 4115 BPD condensate. The final appraisal well, 16/8a-9 & 9Z (1989), was drilled to appraise at Brae Formation level the transition from prolific channelized lobe sandstones in well 16/8a-8 to marginal fringe deposits in well 16/8-1, but the well found poorer sand quality than expected. Well 16/8a-9Z appraised and confirmed the Heather Formation level accumulation, discovered by well 16/8a-4. Development feasibility studies concluded that the only economic development for the field would be via sub-sea tie-back, however neither technology or infrastructure capacity were available at this time. Three-dimensional seismic data was initially acquired in 1985 but proved to be too poor in quality to resolve the deep Heather Formation accumulation. A more extensive 3D survey was acquired in 1993, coordinated by BP, which has significantly improved resolution.
Development and early production By 1995, sub-sea technology had sufficiently progressed to consider development of the field. The main breakthrough was reached when it became possible to commingle near-high pressure/high temperature Heather Formation production with lower pressure Brae Formation production in one pipeline system, by means of the world's first sub-sea HIPPS (High Integrity Pressure Protection System) (Spence et al. 1999). The large pressure difference between both
reservoirs also required the commissioning of Super Duplex stainless steel choke valves with a design temperature as low as -60~ The field was brought on stream in October 1997 as a sub-sea satellite to Marathon's Brae 'B' platform (Fig. 1). One vertical gas/ condensate producer for the Brae Formation reservoir was predrilled and two further horizontal producers for this reservoir were brought on stream by mid-1998. These were the first horizontal wells drilled in the South Viking Graben. The first horizontal Heather Formation producer is expected to be brought on stream later in 2000. Early production results confirm that the Brae Formation sandstone accumulations share two complex aquifers with the surrounding Miller and Brae Fields. The combined offtake of the fields from the upper aquifer, which is connected to the gas/condensate accumulations of the North and East Brae Fields, as expected had brought the pressure down to around dew point at first oil.
Structure The Kingfisher area has undergone three major tectonic phases. Rotational block faulting during graben development took place during the Middle Jurassic and was followed by slump and slide listric faulting associated with Zechstein salt movements, starting at the end of the Jurassic and continuing into the Lower Cretaceous (Roberts 1991; Partington et al. 1993). In the final phase during the Tertiary only gentle salt movements and subsidence continued to form the present structure. Structure at Middle Jurassic Heather Formation and Upper Jurassic Brae Formation level are therefore distinctly different (Figs 4, 5a and b). The Heather Formation accumulation is trapped in a N W - S E trending tilted fault block, bound to the northeast by a major normal fault (Fig. 3). Small scale faulting inside the block is dense at top sandstone level whilst the underlying top Pentland Formation
THE KINGFISHER FIELD
307
Fig. 3. Top Heather Sandstone unit structure map. coal marker is nearly unfaulted. This has led to the interpretation of numerous short/minor listric faults soling out on Pentland Formation coals and dipping mainly southwest in the same direction as the tilted fault block. Very few of these faults have throws of more than 100 ft and are thus insuff• to fully offset the Heather Formation sandstone reservoir. To the east the Heather Formation rises above a major salt high and is increasingly broken up into smaller rotated fault blocks. The larger throw of faults in this area would be sufficient to fully offset the reservoir and seal it against Heather Formation shale, however, a stratigraphic trap in this direction is equally likely to explain the hydrocarbon distribution. At Brae Formation sandstone level, the structure forms an elongated N W - S E trending anticline in the footwall of a major normal fault trending sub-parallel, but located further northeast than the bounding fault to the Heather accumulation (Figs 2, 4, 5a and b). Salt uplift during the late Jurassic re-activated both normal faults leading to the northeast block sliding down and rotating against the upthrown block in the southwest. The resulting fault shape within the Upper Jurassic is strongly listric. The bounding fault to the Heather accumulation shows similar rejuvenation, forming a separate but less pronounced Upper Jurassic high around well 16/8a-4 (Figs 4 and 5). Salt movements might have started during the Upper Jurassic but are completely disguised by a strong regional tilt of the graben towards the west, which created accommodation space for the Brae Formation sandstone deposition. At Lower Cretaceous level, when the extensional movements forming the Viking Graben slowed down, localized salt migration took over and controlled sediment deposition. Accumulation of
Cromer Knoll marl and shale filled up the space created by the rotating blocks above the listric fault planes (Fig. 4). Minor lineations with a predominantly W - E trend fill the space between both fault planes and increase in density eastwards towards the center of the underlying salt high. Tertiary movements had little impact on the structural configuration and consist only of a gentle rise of the salt high to the east of Kingfisher. Minor faulting of post-Lower Cretaceous levels is visible in this area. The quality of the 1993 vintage 3D seismic at Brae Unit 1 and Brae Unit 2 level is reasonable, exhibiting some but not all of the Brae Formation sandstone architecture. Resolution at Heather/ Pentland Formation level is moderate in the main Kingfisher block, where a strong Pentland coal marker is present, however elsewhere resolution is poor.
Stratigraphy The general stratigraphic sequence of the Kingfisher Field is shown in Figure 6. Unconformities are present in the area at late Middle Jurassic, early Upper Jurassic, base Cretaceous, base Upper Cretaceous, and sub-Paleocene level.
Middle Jurassic Pentland Formation Two wells within the Kingfisher Field penetrate the Bajocian to Bathonian Pentland Formation. This is a sequence of sandstones,
308
S. SPENCE & H. KREUTZ
Fig. 4. SW-NE seismic section across Kingfisher (refer to Figures 2 & 3 for location). siltstones, and mudstones and coals deposited in a lower coastal plain environment. The increasing coal content towards the top of the formation forms a prominent seismic marker in some fault blocks (Figs 4 and 5). Elsewhere the top Pentland Formation cannot be reliably identified, either due to small-scale faulting or the absence of well developed coal markers.
Middle to Upper Jurassic Heather Formation The Heather Formation ranges from Bathonian to Oxfordian in age and predominantly consists of deep marine mudstones and siltstones. Erosively encased into these mudstones are turbidite channels trending roughly in a SE-NW direction. None of the Kingfisher wells have penetrated the stratigraphic top of this formation, due to the presence of listric low angle faulting.
Upper Jurassic Kimmeridge Clay Formation Deep marine Kimmeridge Clay deposition prevailed throughout the Oxfordian to Ryazanian period. Dark grey, organic-rich mudstones are interbedded with turbiditic sandstones of the Brae Formation, which form the main reservoir in the Kingfisher Field. The Kimmeridge Clay Formation can be reliably subdivided into biostratigraphic zones in the east and center of Kingfisher, where
mudstone deposition is dominant. Partington et al. (1993) describes the Late Jurassic genetic sequence stratigraphy in the South Viking Graben. The sand content increases westward and upwards from Lower Volgian times before sand deposition terminates in the Middle Volgian. The top seal for the Brae Formation reservoirs comprises Upper Volgian and Lower Ryazanian mudstones. Based on biostratigraphy and heavy mineral analysis the Brae Formation is subdivided into two reservoir units (Brae Unit 1 and Brae Unit 2) and a further non-reservoir subunit (Brae Unit 3) which can be related to different sediment point sources to the northwest, west, and southwest of the Kingfisher Field.
Cretaceous The Cretaceous comprises a 4000ft thick sequence of marls, limestone and claystones that accumulated within the gently subsiding South Viking Graben. No allochthonous chalk or sandstone facies are identified.
Tertiary The Tertiary stratigraphy is dominated by an 8000 to 9000 ft thick sequence of claystone, siltstones, sandstones and marls. The complete stratigraphic subdivision of the Tertiary section is shown in Figure 6.
THE KINGFISHER FIELD
309
Fig. 5. (a) NW-SE seismic section across Kingfisher. (b) NW-SE schematic cross-section across Kingfisher.
Trap The tilted fault block containing the Heather Formation sandstone accumulation provides dip closure to the west and southwest and fault closure to the northeast (Fig. 3). Towards the east, where the reservoir is thinner, there is either stratigraphic or fault closure. Heather Formation shale and Lower Kimmeridge Clay form the top seal for the highly overpressured reservoir (4800PSI above hydrostatic) against less overpressured Brae Formation sandstones (1200PSI over hydrostatic). The gas-water contact (GWC) at 15 700 ft TVDSS coincides with the structural spillpoint to the west. The Brae Formation accumulations are dip closed to the west and southwest, dip/fault closed to the northeast, and stratigraphically closed to the east (Fig. 2). A field-wide correlatable
intra-reservoir shale within the Brae Unit 2 reservoir and the Upper Kimmeridge Clay provide the top seals for the two Brae Formation accumulations (Figs 5b and 7). The GWC in Brae Unit 1 almost coincides with the structural spillpoint to the west, towards the North Brae Field, whilst the oil-water contact (OWC) in the Brae Unit 2 is some 100 ft above the structural spillpoint.
Reservoirs Heather Formation The Heather Formation sandstones comprise medium quality, very fine to coarse-grained sandstones (quartz arenites) interbedded with
310
S. SPENCE & H. KREUTZ porosity. Late stage dissolution of feldspars and unstable lithic grains generated a secondary pore network, which has been partially occluded by ferroan dolomite cement. Heather Formation reservoir sandstones are characterized by low core porosities (12 to 15%), and horizontal permeabilities (5 to 20mD). The Heather Formation reservoir is gas condensate-bearing with a GWC at 15 700ft TVDSS. The PVT condensate/gas ratio ranges from 85 to 175 BBL/MMSCF with indications of gravity segregation and fluids contain 5% CO2 and no H2S. The Heather Formation reservoir falls in the near H P H T category, with initial reservoir pressures of 11745 psig, overpressure of approximately 4800 psi and high temperature of 290~ Well 16/8a-9Z, located near the crest of the structure tested 34 M M S C F / d and 4000 STB/d condensate.
Brae Formation
Fig. 6. Kingfisher area generalized stratigraphy.
dark grey, fissile hemipelagic marine shales. The sandstones frequently form massive amalgamated sequences (up to 40 ft thick) with a variety of internal structural fabrics. Individual sand units are predominantly well sorted, clean and structureless, whilst other units exhibit low angle/horizontal laminations or disorganised internal fabrics, indicating de-watering and slumping. Some sand units contain rare deformed mudclasts. The sandstones have sharp basal and upper contacts resulting in a blocky gamma ray profile (Fig. 7). Grain size trends are not always evident although indications of fining upward trends are observed from core. Heather Formation sandstones are thought to be deposited from channelized, variable high and low density turbidite flow regimes in a proximal slope setting. The channels are believed to be sourced from the southeast and trend in a N - N W direction across the field. Sand body geometries are uncertain due to poor seismic resolution and a limited number of well penetrations. Channel widths are estimated to be between 250 and 400 ft. The Heather Sandstone Member in well 16/8a-4 has a gross thickness of approximately 400 ft. The main control on reservoir quality is the extensive development of quartz overgrowths which locally occlude primary
The Upper Jurassic Brae Formation comprises a thick sequence of interbedded conglomerates, sandstones and mudstones that form an eastwards thinning wedge juxtaposed against the faulted western margin of the graben. These sediments were deposited as a complex series of partially coalesced submarine fan systems, sourced from the Fladen Ground Spur to the west via entry points along the evolving basin margin. Brae Unit 2 sandstones were predominantly sourced via the South Brae/Miller and Central Brae fan systems and range from Early Volgian to earliest Middle Volgian in age (Fig. 8). The Kingfisher Field is located at the frontal channelized lobe to distal margin setting of this complex fan system. Brae Unit 2 oil-bearing reservoir sandstones are separated from the overlying gas condensate-bearing sandstones of Brae Unit 1 by a field-wide transgressive shale. Brae Unit 1 submarine fan sandstones are early to mid Middle Volgian in age and are interpreted to have been sourced from the North and East Brae fan systems (Fig. 8). Brae Unit 1 and Brae Unit 2 reservoir sandstones in the Kingfisher Field represent the most distal part of the Brae submarine fan systems to be developed in the Brae/Miller/Kingfisher area, being located approximately 15-20 km east of the graben-bounding fault. Brae Formation lithologies in the Kingfisher Field are dominated by very fine to coarse grained sandstones interbedded with siltstones and mudstones. Unlike the South Brae and North Brae Fields (Roberts 1991; Stephenson 1991), conglomerates have not been seen in the extensively cored intervals in the Kingfisher wells. The frequency and distribution of lithofacies observed in core varies both vertically and laterally across the Kingfisher structure. Sandstones vary in thickness and show varied degrees of internal organization with the most common fabrics characterized by low angle laminations, de-watering escape structures, dominated by mud clasts or often a complete absence of any internal structure. These units were probably deposited by variably high to low density turbidity currents. Mud dominated, poorly sorted units also occur, probably deposited from debris flows, slumps or low density turbidites. These lithofacies types were deposited in varied submarine fan settings ranging from high energy channels to channelized lobe and to lobe fringe environments (Figs 7 and 8).
Brae Unit 2 Reservoir The Kingfisher Field is located on the distal margins of the main Miller basin-floor fan system which was predominantly sourced via the South and Central Brae fan systems (Turner & Connell 1991; Garland 1993). Brae Unit 2 reservoir quality is highly variable due to the distal submarine fan setting. Correlation between seismic amplitude anomalies and reservoir quality in the Brae Unit 2 is poor although seismic facies analysis suggest that the main channelized lobe is restricted to the down-dip western area of the field (around well 16/8a-8). In well 16/8-1, thin sands and very low net/gross ratios indicate the northern margin of the submarine channel and sand deposition in a distal lobe fringe setting. Brae Unit 2 has a maximum gross thickness of 800 ft in the Kingfisher Field and is subdivided
o
o
o
9
312
S. SPENCE & H. K R E U T Z
DEPOSITIONAL ENVIRONMENT INNER FAN Proximal slope apron channels Slope/Interlobe siltstones/ mudstones
MID FAN Channelised lobe
OUTER FAN Proximal lobe fringe Distal lobe fringe
BASINAL Deep marine mudstones/ siltstones Deep marine mudstones and distal basinal turbidites
5 km I
Fig. 8. Regional depositional settings of Brae Formation reservoir units (After Turner & Connell 1991; Garland 1993).
THE KINGFISHER FIELD into Units 2.1-2.4, based on biostratigraphic zonation and log correlation (see fig 7). Brae Unit 2.2 sandstones provide the reservoir for the Brae Unit 2 oil accumulation in the Kingfisher Field. The overlying Brae Unit 2.1 is a shale-dominated sequence, which can be correlated in wells across the Kingfisher Field and provides the seal to the Brae Unit 2.2 oil accumulation. Brae Unit 2.1 is thought to represent the abandonment of the South Brae/Miller Field fan systems. Both the shale-dominated Brae Unit 2.3 and Brae Unit 2.4 sandstones are waterbearing. The Brae Unit 2.2 reservoir sandstones (286 ft gross thickness) are characterized by moderate porosity (11 to 15%, average 14%) and horizontal permeability (10 to 250mD). Volatile oils in this interval have a gravity of 35 to 40 ~ API and a gas/oil ratio of 2000 to 2900 SCF/BBL. Brae Unit 2 has currently been developed by a single southeast orientated horizontal producer towards appraisal well 16/8a-9. Structural configuration precludes a target in the main channelized lobe as this would be too near the OWC, at approximately 13220ft TVDSS. Appraisal wells 16/8a-4, 16/8a-8 and 16/8a-9 tested respectively, at 4474 STB/d with 10 MMSCF/d, 3795 STB/d with 8 M M S C F / d and 3934 STB/d with 11 MMSCF/d. From the base to the top there are three major hydraulic units which prior to intial production were all on the same pressure regime. The Brae Unit 2.4 and Brae Unit 3 Sandstones (Late Kimmeridgian-Lower Volgian) are waterbearing and do not contribute to the aquifer support. Sealed by the Brae Unit 2.3 shale against the Middle Volgian Brae Unit 2.2 oil accumulation, they are still at original pressure. Volatile oil in the Brae Unit 2.2 accumulation is sealed by a thin Brae Unit 2.1 shale against the gas/ condensate accumulation of the Brae Unit 1 (Middle Volgian). Brae Unit 2.2 and Brae Unit 1 reservoirs have different hydrocarbon contacts (13220 and 13 100ft TVDSS respectively) and show a different pressure decline on a regional level. The Brae Unit 2.2 reservoir is in communication with the Miller and South Brae Fields as demonstrated by the 350 psi pressure depletion seen in appraisal wells 16/8a-9 and 16/8a-9Z in 1987/88 and the further 1200psi pressure depletion seen in horizontal development well 16/8a-K4Z (1998). The initial reservoir pressure was 7250psi at 13000ft TVDSS and the bubble point pressure is 5385 psia. The South Brae Field was brought on stream in 1983 and reservoir pressure has been maintained via water injection at about 5800 psi, above the bubble poil~t pressure. The Miller Field commenced production in 1992 with reservoir pressures found to be depleted by South Brae production (Garland 1993).
Brae Unit 1 Reservoir Brae Unit 1 comprises a stacked sequence of interbedded sandstones and shales and is the main reservoir in terms of reserves in the Kingfisher Field. Regional correlation suggests that the Brae Unit 1 sands were mainly deposited via the North Brae turbidite fan system, following the abandonment of the South Brae/Miller fan system. Brae Unit 1 has a gross thickness of 246ft. Across Kingfisher there is a lateral transition from massive, amalgamated fine to medium grained sandstones with occasional granule grade clasts in the northwest (well 16/8a-8 area), to thin bedded finer grained sandstones in the southeast (well 16/8-1 area). This trend of decreasing sand thickness and net/gross values towards the southeast of the field reflects the transition from proximal channelized lobe (N/G 85%) to a distal lobe fringe (N/G < 10%) depositional setting (Figs 7 and 8). The highly variable reservoir quality ranges from excellent in well 16/8a-8 to marginal in well 16/8a-9. Porosity values range from 10 to 22% (average 21%) with horizontal permeabilities ranging from 10 to 800mD. The deterioration of reservoir quality in the southeastern part of the field is also associated with an increase in calcite cementation. Cores from well 16/8-1, taken from Brae Unit 1 are both highly fractured and cemented by calcite. It is thought that the cements may be associated with the high density of faulting in this area. The G W C is estimated to be at 13 100ft TVDSS. Brae Unit 1 contains gas condensate with an above dew point condensate/gas
313
ratio of some 260 wellstream B B L / M M S C F . The Brae Unit 1 reservoir has been developed by a near vertical producer (16/8a-K 1) adjacent to the appraisal well 16/8a-8 and a southeasterly directed horizontal producer (16/Sa-K2) which has connected both proximal and distal lobe sandstone bodies (Fig. 2). R F T pressure data, acquired in 1997 from producer 16/8a-K1, has shown a significant pressure drop (1000psi) in the Brae Unit 1 reservoir since the Kingfisher appraisal wells were drilled. This confirms that the Brae Unit 1 reservoir is in pressure communication with the aquifer supporting the producing North and East Brae Fields.
Hydrocarbons The Upper Jurassic Kimmeridge Clay Formation in the deeper parts of the South Viking Graben is the main source rock for the Kingfisher Field. Maturation took place from late Tertiary times. The migration path for the Heather Sandstone gas/condensate is not fully resolved. The Brae Unit 1 gas/condensate migrated into Kingfisher from a source area to the northeast and spilled westwards into the North Brae Field. The Brae Unit 2 volatile oil originated from a southerly source area, migrating via the Miller Field, spilling from the southwest into Kingfisher. The composition of all three hydrocarbon types is significantly different. The Heather Formation gas/condensate (43-46~ is relatively lean, has no H2S, and only 5% CO2. The Brae Unit 2 volatile oil with an API gravity of 35 to 40 ~ contains 200-500 ppm H2S and 14% COz The Brae Unit 1 heavy gas/condensate (3944~ contains 15 ppm H2S and 12% CO>
Reserves The latest estimate (1998) of ultimate recovery for the Kingfisher Field is 41.2 M M B B L of pipeline liquids and 280 BCF of dry export gas. About 50% of these reserves, on a BOE basis, are contained within the Brae Unit 1 accumulation. Reserves estimates increased with the appraisal of the Heather Formation and the delineation of the Brae Formation reservoirs to the west. However, prior to field development, reserves estimates decreased when it was realized that pressure maintenance in the Brae Unit 1 was not feasible due to the combined offtake of all fields in the area sharing the aquifer. We would like to thank Shell UK Exploration and Production, Esso Exploration & Production (UK) Ltd, and Marathon Oil UK for their permission to publish this paper. This paper has been based extensively on the work of a large number of Shell and Esso employees who have been involved in the detailed evaluation of Block 16/8 since 1970. The authors wish to acknowledge their efforts and contributions and also thank Roger McIlroy for permission to use his reservoir engineering analysis and for his critical review of this paper.
References GARLAND,C. R. 1993. Miller Field: reservoir stratigraphy and its impact on development. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 401-414. PARTINGTON, M. A., MITCHENER, B. C., MILTON, N. J. 8~ FRASER, A. J. 1993. Genetic sequence stratigraphy for the North Sea Late Jurassic and Early Cretaceous: distribution and prediction of KimmeridgianLate Ryazanian reservoirs in the North Sea and adjacent areas. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 347-370. ROBERTS,M. J. 1991. The South Brae Field, Block 16/7a, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 55-62.
314
S. SPENCE & H. KREUTZ
SPENCE, S., MCILROY, R., LEYSHON,L. & KREUTZ, H. 1999. The Kingfisher Field." Combined Development of Corrosive Brae and Near H P / H T Heather Reservoirs. Paper SPE 56927 presented at the 1999 SPE Offshore Europe Conference, September 7-10, Aberdeen. STEeHENSON, M. A. 1991. The North Brae Field, Block 16/7a, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields:25 Years
Commemorative Volume. Geological Society, London, Memoirs, 14, 43-48. TURNER, C. C. & COYNELL, E. R. 1991. Stratigraphic relationships between Upper Jurassic submarine fan sequences in the Brae area, UK North Sea: the implications for reservoir distribution. In: Proceedings of the 23rd Annual Offshore Technology Conference, Offshore Technology Conference 6508, Houston, Texas, May 6-9, 1991.
Kingfisher Field data summary Reservoir Trap Type Depth to crest Lowest closing contour GWC OWC Gas column Oil column
Pay zone Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability range Hc saturation range Current productivity index Hydrocarbons Oil density Oil type HzS CO2 Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Initial Condensate yield Formation volume factor Gas expansion factor
(ft TVDSS) (ft TVDSS) (ft TVDSS) (ft TVDSS) (ft) (ft)
(ft) (%) (mD) (%) (BOPD/psi)
(~ (ppm) (mol%) (cP) (psia) (psia) (scf/bbl) (bbl/MMscf) (rb/stb) [scf/rcf]
Formation water Salinity Resistivity Field Characteristics Area Gross rock volume Datum depth Initial pressure Pressure gradient in reservoir Temperature Oil initially in place Gas initially in place Recovery factor (oil) Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate Production Start-up date Development scheme Production rate plateau oil/NGL's Production rate plateau gas Number/type of well
Brae Unit 1
Brae Unit 2
Heather
structural/strat, 12 600 13 125 13 100 n/a 500 n/a
structural/strat, 12 800 13 320 n/a 13 220 n/a 420
structural/strat 14 800 15 700 15 700 n/a 900 n/a
Brae Unit 1 U Jurassic 246 0.06-0.86 21 (10-22) 10-800 70-85 20
Brae Unit 2.2 U Jurassic 286 0.15-0.67 14 (11-15) 10-250 70-85 1
Heather M Jurassic 404 0.14-0.46 13.5 (12-15) 5-20 70-80 20
39-44 Gas Cond. 15 11.6 0.804 0.03 n/a 5781 3000-4000 250-310 n/a 240
35-40 volatile oil 200-500 14.1
43-46 Gas Cond. 0 5.2
0.27 5385 n/a 2000-2900 n/a 2.46 n/a
0.02 n/a 6325 6000-9000 85-175 n/a 351
70 000 ppm NaC1 equivalent 0.034 ohm m at 250~
(kin 2) (acre ft) (ft TVDSS) (psi) (psi/if) (~ (MMstb) (Bcf export) (%) (MMstb) (Bcf) (MMstb)
21 (5190 acres) 532012 13 000 7160 0.22 250 total field: 104 total field: 610 total field: 32% natural depletion total field: 30 total field: 280 total field: 11.2
21 (5190 acres) 313 445 13000 7250 0.28 250
Oct 1997 Jul 1998 Sub-sea drill centre and two multiphase pipelines to Brae 'B' Platform 19600/8400 BOPD 130 MMscf/d dry export gas 5 exploration/appraisal 3 development wells completed
70 000ppm 0.034ohmm
12 (2970 acres) 504986 15 000 ll 800 0.20 290
Aug 2000 (expected)
The North Cormorant Field, Block 211/21a, UK North Sea LOUISE
BATER
Shell U K Exploration and Production, 1 Altens Farm Road, Aberdeen A B 1 2 3 F Y , U K
Abstract: The Cormorant Field was discovered by exploration well 211/26-1 in 1972; the fifth field to be discovered in the Northern North Sea. It straddles blocks 211/21a and 211/26a and is made up of four discrete accumulations spread along a major N-S trending fault terrace. Oil is produced from the sandstones belonging to the Brent Group. The sedimentary rocks comprising the Brent Group were deposited in a fluvial-wave dominated delta system during the Middle Jurassic. The field is developed from two fixed platforms and an underwater manifold centre and the oil is exported through the Brent system to Sullom Voe in the Shetland Islands. For development purposes the field is split in half; north and south, and it is the northern part, developed by the North Cormorant platform, that is the subject of this review.
The Cormorant Field is located in the centre of the East Shetland Basin (Fig. 1) in the U K sector of the Northern North Sea, approximately 500km NE of Aberdeen, in water depths of 500-550 ft. It consists of four discrete structural-stratigraphic traps spread along a N-S fault terrace, straddling blocks 211/21a and 211/26a. The field extends approximately 25 km in a N-S direction and is 6 km E - W at its widest point. For development purposes, the Cormorant Field is split into six blocks (Ia, Ib, Ic, II, III and IV). Blocks Ic, III and IV are developed from the North Cormorant platform and are the subject of this review. Blocks Ia and II are developed from the Cormorant Alpha platform and Block Ib from the Cormorant Underwater Manifold Centre (UMC). The field is defined within a single Petroleum Revenue Tax (PRT) fence, with the exception of Block II, which is the subject of a separate PRT area. The Cormorant Field is owned on a 50/50 basis by Shell (UK) Ltd and Esso (UK) Ltd and operated on behalf of the partners by Shell (UK) Exploration and Production Ltd. As with all Shell operated offshore oil fields in the Central and Northern North Sea, the Cormorant Field is named after a sea bird.
History
Pre-discovery Blocks 211/21 and 211/26 were awarded to Shell/Esso as part of licence P232 in the fourth round allocation of 1972. In 1977 North Cormorant was re-designated P258 (South Cormorant remained P232). These licences expire in 2018.
Production tests of the Brent interval proved a net 123 ft of oil sandstone, capable of flows up to 7800 BBL/D. Oil was found to the base of the Brent sands and hence the position of the OWC could not be deduced. Deeper still, the Lower Jurassic Statfjord Formation was also found to be water-bearing. Hydrocarbon indications were noted in the underlying Triassic Cormorant Formation but no flow was obtained during testing. Total depth was reached in the sub-Devonian metamorphic basement. The Cormorant Field was subsequently appraised with eight wells, drilled between 1973 and 1977; the main events in the development of North Cormorant are summarized in Table 1. The large areal extent of the field complicated the development planning and so it was split into two areas; north and south. The Cormorant Alpha platform, a concrete gravity structure, was installed in the southern part of the field in May 1978. It was positioned to optimally develop Block II and the southern part o f Block I, with the provision to tie-back a U M C from which the central Cormorant area could be developed, at a later date. (The U M C was subsequently installed in August 1982.) A steel platform, the North Cormorant, was installed half-way between Blocks III and IV in August 1981 and production started in February 1982. Oil is exported from the platform through a pipeline to the Cormorant A l p h a platform and thereafter into the Brent system and on to the crude terminal at Sullom Voe in the Shetland Islands. Sales gas is evacuated through the western leg of the Far North Liquids and Associated Gas System (FLAGS).
Table 1. Summary of the main events in the development of the North
Cormorant field Year
Event
Discovery method
1972
Following acquisition of blocks 211/21 and 211/26, Shell/Esso shot six E - W seismic lines and obtained two N-S lines by data trade. Combining these with the existing data set formed a grid with an average spacing of 2 km E - W and 3 km N-S. Regional correlations and comparisons were made between Block 211/26 and the Brent discovery well 211/29-1. Two possible plays were identified, Paleocene and Jurassic, and evaluated by drilling.
1974 1975 1979 1981 1982 1983 1984 1984 1991
Blocks 211/21 and 211/26 awarded to Shell/Esso. 211/21-1 discovery well drilled into Block I Block 1V discovered by well 211/21-2 Block III discovered by well 211/21-3S1 First 3D seismic survey acquired North Cormorant platform installed Oil production started Water injection started Second 3D seismic survey acquired Peak production at 122655 BBL/D New Year storm caused structural damage to the platform (lost part of the passive fire protection). Production shut-down for approximately six weeks in April-May. Third 3D seismic survey acquired. Water injection system repairs Fifth water injection pump installed Fourth 3D seismic survey acquired 'Deliver the limit' initiative to drill more wells at a lower cost in a shorter time Production licence expires
Discovery The first Cormorant exploration well, 211/26-1, was drilled into Block I in 1972. The objective of the well was to test a large, Paleocene, anticlinal structure and a secondary pre-Cretaceous structure. Disappointingly, the Paleocene sands were less than 100 ft thick and water-bearing but deeper down the well penetrated 236ft of oil-bearing Middle Jurassic Brent Group sandstones.
1992-4 1995 1998 1999 2018
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 315-325.
315
316
L. BATER
Fig. 1. Regional structure map for the East Shetland Basin.
Post-discovery The development concept for both blocks III and IV was based on rows of up-dip producers supported by down-dip water injectors. When the North Cormorant platform was installed the size and shape of the hydrocarbon accumulations were not clear and it was decided to use a conventional platform plus an underwater passive distribution manifold (PDM) to provide injection support in the south of Block IV. This concept of up-dip producers and down-dip water injectors has been maintained in Block III but the production history of the first couple of wells drilled in Block IV proved it to be largely compartmentalized and therefore requiring producerinjector pairs in each fault block. This concept is illustrated by the well positioning on the Top Brent structure map in Figure 2. In addition, the first wells drilled in the south of Block IV (211/21A-9, 211/21A-9S1, 211/21A-12 and 211/21A-14S1), which were intended
to be tied back to the P D M once it was installed, showed disappointing injectivity indexes when tested as a result of the reservoir properties. The P D M was no longer considered to be a feasible project and, as an alternative, highly deviated injection wells were to be drilled from the platform. Secondary development was to be based on drilling side-tracks from existing wells to recover bypassed oil. The North Cormorant platform has 40 slots on the deck, the last of which was used in 1995. Since then, as per the revised development plan, the only economic option has been to side-track wells with a high water cut to other targets within the field, thereby developing additional reserves. To date (1/1/2000) 42 oil producers (OP) and 20 water injectors (WI) have been drilled and completed from the platform ( 1 0 P and 1 WI in Block Ic, 9 0 P and 5 WI in Block III and 32 OP and 14 WI in Block IV). In addition there have been 11 geological sidetracks, mostly necessitated by the proposed well not penetrating a sufficient reservoir section as a result of fault cut-out.
Fig. 2. North Cormorant Top Brent structure map.
318
L. BATER
Seismic surveys The Cormorant Field is covered by some 2D data and a number of 3D seismic surveys. The first 3D survey was shot over North Cormorant in 1979, with subsequent surveys shot in 1984, 1991 (re-processed in 1996) and 1998. The 1998 survey produced a high resolution data set and subsequent pre-stack image (PSI) processing has resulted in an improvement in structural resolution across the field. Favourable drilling results following a pre-stack depth migration (PSDM) exercise on several single lines has led to the decision to carry this out on the whole 3D data cube.
Current challenges and the future With the field average water cut at approximately 87% and 90% of the expected ultimate recovery produced, North Cormorant is a mature field. As would be expected, remaining reserves targets are small and sit in relatively small attics and inefficiently swept, faultbounded corners of the field. It has become increasingly difficult to find wells available to be side-tracked as time has passed and the addition of new slots is a high cost activity, which can not be justified by small target volumes. In the short-term, the application of technologies such as more efficient motors, rotary steerable assemblies and slim hole through-completion drilling is expected to cut the cost of drilling such targets with conventional side-tracks. Thereafter it will become necessary to utilize new technologies such as multi-target wells in order to economically develop the field's remaining reserves.
W - E seismic section through Block IV in Figure 4). On the eastern side of Block III, in the area of the original oil-water contact (OOWC), there is a complex of major N-S faults and there is also a series of minor faults, trending NW-SE, in the centre of the block. The fault pattern in Block IV shows three main trends; N E - S W in the south, N-S in the centre and N W - S E in the north. Large faults in the Brent can be correlated to faults in the basement and hence the Top Brent fault pattern is broadly similar to that of the basement. This suggests that movement during the Brent followed basement gradients. The faulting in the Brent Group is further complicated by relatively low angle faults that were active throughout its deposition, tilting the fault blocks and resulting in (fault controlled) stratigraphic thinning. The timing of this internal faulting can be estimated by changes in the thickness of sediment across the block; the Dunlin, Brent and Humber Groups all show dramatic thickness increases towards the west (Fig. 4). A number of faults cut the base Cretaceous unconformity and appear to extend into the overlying Cromer Knoll Group, proving that fault movement continued into the mid-Cretaceous. The mass of sediment on the crest of Block IV became unstable sometime in the Cretaceous and collapsed along its eastern edge under the influence of gravity. Tertiary sediments are draped across the top of the structure as a result of both differential compaction and limited extension.
Stratigraphy Structure Tectonic history The Cormorant Field sits on the eastern side of the Viking Graben, which developed as a N-S trending fault system in the early Permian times and caused extension related subsidence. A second phase of extension during the Triassic resulted in limited fault-block rotation and the development of the East Shetland Basin. Finally, and most importantly in the context of the Cormorant Field, further extensional deformation took place towards the end of the Jurassic, causing the East Shetland Basin to break into a series of N-S oriented fault terraces. A secondary set of faults, trending N W - S E and NE-SW, were also active at this time. The extensional regime caused the fault blocks to tilt towards the west, producing the severely rotated fault blocks that characterize the East Shetland Basin, and resulted in crestal erosion of the Brent Group. In this area the fault blocks are typically aligned SW-SE, parallel to the Caledonian structural grain. Much later, Upper Cretaceous to Cenozoic subsidence caused the burial of the Jurassic to between 8000 and 9000 ft, resulting in the Kimmeridge Formation source rock becoming mature and expelling oil into the Brent sandstones.
Regional structure The hydrocarbon accumulations in the Cormorant Field (Blocks I, II and III) are contained in westerly dipping, rotated, fault blocks, truncated by faulting and erosion on their eastern edge. Block IV is unique as it is a down-faulted portion of the crest of the main Cormorant fault block. It has a dome-shaped structure and significant internal faulting. These structures are clearly illustrated in the 3D view of the Top Brent surface across the Tern-Eider-North Cormorant area shown in Figure 3.
Local structure The Top Brent structure map in Figure 2 shows that Block III is relatively unfaulted whilst Block IV is heavily faulted (see also
A general stratigraphic column for the East Shetland Basin is shown in Figure 5 and applies to the North Cormorant Field. The Basement in the Cormorant area is made up of pre-Devonian garnet-mica schists and weathered amphibolites. Overlying this is the Triassic Cormorant Formation; silty claystones interbedded with fine to coarse grained sandstones, thought to have been deposited in an alluvial plain environment. Due to the presence of carbonate cements the Cormorant Formation is usually a poor reservoir, although oil has been produced during tests in Block II. Above the Cormorant Formation lies the Lower Jurassic Statfjord Formation. This is a calcareous sandstone and is thin in the Cormorant area. The Statfjord is overlain by the marine shales and interbedded siltstones of the Dunlin Group. The Brent Group is Middle Jurassic in age and lies on top of the Dunlin Group. It is made up of wave-dominated, fluvio-deltaic deposits of the Brent delta system, sourced from a structural high in the Central North Sea area, located towards the south. The delta prograded from the S-SE towards the N - N W across the East Shetland Basin, depositing a sedimentary package in the range of 300-400 ft thick. The Brent Group is subdivided into five formations (from base to top); the Broom, Rannoch, Etive, Ness and Tarbert. The main reservoir units in the Cormorant Field are the Etive and the Upper Ness sandstones. Nevertheless, important volumes of hydrocarbons are still produced from the Tarbert, Lower Ness, Rannoch and Broom formations. The Brent Group is overlain by the marine shales of the Heather and Kimmeridge formations (Humber Group). The thickness of the Humber Group changes dramatically across the field due to the large variation in available accommodation space at the time of its deposition. This is the direct consequence of the underlying fault controlled topography and resulted in a thin package of shales being present on the crest and thickening off structure. The Base Cretaceous unconformity marks the boundary between the Jurassic sequence and the limestones and marls of the Lower Cretaceous Cromer Knoll Group above. The Base Shetland unconformity is found at the top of the Cromer Knoll Group, separating it from the limestones and marls of the Upper Cretaceous Shetland Group. Above this lie Tertiary to Recent, largely unconsolidated, marine claystones and sandstones of the Montrose Group, Rogaland Group and North Sea Group.
NORTH
CORMORANT
FIELD
319
r~
9
O O
O
z
[-..
t,r
320
Fig. 4. West-East sections across the centre of Block IV.
L. B A T E R
NORTH CORMORANT FIELD
321
Fig. 5. General stratigraphic column for the East Shetland Basin.
Trap The trapping mechanism of the whole Cormorant Field is a combined structural-stratigraphic feature. On a large-scale, the geometry of the trap is controlled by regional faulting but, due to crestal erosion associated with the rotation of the fault blocks, the reservoir is typically truncated and sealed by an unconformable contact with the overlying Heather shal'es o f the Humber Group.
The trapping of the hydrocarbons in Block IV is additionally controlled by dip closures along its eroded eastern edge. Internal faults in Block III are not completely sealing but may act as transmissibility barriers. The faults in Block IV also act as transmissibility barriers and some of the larger ones are responsible for compartmentalizing the reservoir; the evidence for this comes from R F T measurements and the presence of different OOWCs in different fault blocks.
322
L. BATER
Reservoir
in the Rannoch, Etive and Lower Ness formations across the fault, indicating the episodic nature of the fault movements.
Depositional setting The Brent Group, deposited during the progradation of the Brent delta across the East Shetland Basin, is subdivided into five formations (from base to top); the Broom, Rannoch, Etive, Ness and Tarbert. The Broom formation is a coarse-grained delta front and is sedimentologically distinct from the overlying, genetically linked, prograding delta deposits of the Rannoch, Etive and Lower Ness formations. The Rannoch formation represents the lower shoreface and the Etive formation represents the upper shoreface. The Ness formation comprises coastal-plain and fluvial deposits separated by lagoonal mudstones (e.g. the mid-Ness shale). The uppermost formation, the Tarbert, is a medium to coarse-grained estuarine sandstone and sits unconformably on top of the Ness. The Tarbert and/or some of the Ness are missing in parts of Block III and IV due to post-Brent erosion in structurally high areas. A type log of the Brent reservoir in the North Cormorant Field is shown in Figure 6 with a more detailed description of each of the formations given below. The Broom formation has a sharp contact with the underlying Dunlin Group, indicating a sudden influx of sand into the depositional system. It has a blocky gamma ray response at the base and fines up towards the top, where another sharp contact is seen. The Broom is a coarse-grained, bioturbated sand and contains several cemented layers. The presence of these cements causes the generally poor reservoir quality seen in the Broom (0.65 net/gross (N/G), 18-19% porosity ( ~ ) , 0-100 mD permeability (K)) and limits vertical connectivity. The formation represents a period of sediment supply from the margins of the basin. The Rannoch formation was deposited during the earliest part of the Brent delta progradation and represents the lower shoreface. It is composed of fine-grained sands, which gradually coarsen upwards into cleaner, more micaceous sands. The reservoir quality of the Rannoch formation is variable (0.5-0.9N/G, 15-20% ~ , 10-100+ mD K) and it is typically in communication with the basal part of the Etive. The Etive formation represents the upper shoreface and is composed of medium to coarse grained, well sorted sands. It is part of the same system as the Rannoch and represents relatively rapid progradation of the delta across the area. The Etive displays excellent reservoir properties (0.9+ N/G, 22-23% ~ , 100-1000+ mD K) and hence is the most important reservoir interval,in blocks III and IV. It has a very sharp upper boundary. The Ness formation is made up of interbedded channelized sandstone bodies and shales deposited in a coastal plain environment. In the North Cormorant Field, this heterogeneous, channelized sequence gives rise to poor vertical communication but good lateral communication (along the channel bodies). An excellent example of this is the lowermost sand of the Upper Ness, which behaves as a 'thief zone' throughout Block IV and is often found to be flushed in otherwise oil-bearing sections. The mid-Ness shale is a 10-20 ft thick, regionally correlatable lagoonal mudstone and forms a complete pressure barrier between the Upper Ness and Lower Ness formations in the Cormorant Field. Excluding the mid-Ness shale, typical reservoir properties for the Ness formation are 0.450.7 N/G, 18-21% ~ and 100-1000 mD K. The Upper Ness tends to contain thicker sand and shale beds than the Lower Ness. The Tarbert formation is a package of medium to coarsegrained sand with a shallow marine origin and good reservoir properties (0.65-0.8N/G, 18-21% ~ , 100-500mD K). It has a sharp base and a gradational (fining upwards) top into the Heather shale. There is an unconformable contact between the Tarbert and the Upper Ness. The depositional setting of Block IV is complicated by intermittent movement on its western boundary fault during Brent deposition. The evidence for this is in significant changes in thickness of the Dunlin Group, Broom, Upper Ness and Tarbert formations across the fault. There are no such thickness variations
Pore types and diagenesis The Brent Group sandstones range from very fine to coarse-grained and are variably sorted. Petrographic analysis indicates that the whole reservoir underwent a broadly similar pattern of postdepositional alteration. The presence of kaolinite, detrital feldspar and mica have an important effect on reservoir quality. Mica and kaolinite reduce the amount of primary pore space, thereby decreasing porosity and permeability.
Porosity, permeability, pressure relationships In a broad sense, permeability increases with increasing porosity across the North Cormorant Field. Porosity generally decreases with depth, as a result of compaction and permeability is largely affected by grain size, sorting and the presence of diagenetic minerals. In the early stages of the field's development R F T data showed differential depletion in response to production, indicating compartmentalization of the reservoir. This has subsequently been confirmed by development drilling, which has established six different OOWCs. Analysis of production data has shown that it is possible to produce across faults which might be expected to seal on a geological timescale by altering the reservoir conditions sufficiently to cause the seal to break down. One such method involves increasing the reservoir pressure by water injection.
Source The source rock for the hydrocarbons found in the Brent Group, in the Cormorant Field, is the Kimmeridge Clay Formation. Stratigraphically, this lies above the Brent Group but it becomes mature off structure, in the deeper parts of the graben. In the vicinity of the Cormorant Field the Kimmeridge Clay reaches a maximum thickness of 535 ft. These organic-rich shales are the most prominent oil source rocks of the northern North Sea and have an average total organic carbon content (TOC) of 5.6% (maximum 12.5%). The estimated vitrinite reflectance is 0.6% and type II kerogen indicates that the source organisms were spores and cuticles. The reservoir fluid properties differ slightly between the blocks (see data summary table) but the oil is highly undersaturated throughout the field and therefore there are no gas caps. Hydrocarbon generation from the Kimmeridge Clay Formation began approximately 65 million years ago, during the Paleocene, and peaked between 40 and 50 million years ago. Goff (1983) calculated the overall efficiency of hydrocarbon generation, migration and entrapment for the East Shetland Basin to be between 20 and 30%. The migration path for the oil was probably from the Ninian area northwestwards towards Cormorant, Tern and Eider. The Cormorant structure was charged from the west.
Reserves and production
Petroleum-in-place The Cormorant Field has a currently estimated STOIIP of 1625 MMSTB, of which 1075 MMSTB are found in North Cormorant. This estimate has only undergone a minor change (+3.5%) since 1991 (Taylor & Dietvorst 1991), largely as the result of improved modelling techniques.
Fig. 6. Type log: Well CN25.
324
L. B A T E R
o
.o
o
o
Z tz
NORTH CORMORANT FIELD
325
North Cormorant field data summary Block III
Block IV
OOWC
9230r TVDss
Sectors l&2: 10040' TVDss Sector 3A: 9360' TVDss Sector 3B: 9530' TVDss Sector 4A & 5: 9800' TVDss Sector 4B: 9600' TVDss
Reservoir properties
Average gross thickness (ft) N/G (average/range) Porosity (average/range) Sh (average/range) Permeability (average/range)
300 0.72/0.4-1.0 20%/15-27% 0.75/0.5-0.85 • mD/0-2000 mD
400 0.69/0.3-1.0 20%/16-26% 0.70/0.4-0.85 +100 mD/0-1000 mD
Hydrocarbons
Oil type Oil density Bubble point (Pb) Viscosity GOR Formation volume factor
Low sulphur crude 36 API 1040 psia 0.82 (@ Pb) 224 SCF/STB 1.191 RB/STB (@ Pb)
Low sulphur crude 34.5 API 1390 psia 0.77 (@ Pb) 311 SCF/STB 1.245 RB/STB (@ Pb)
Reservoir conditions
Temperature Initial pressure
195~ 4825 psia (@ 8690' TVDss datum)
210~ 5262psia (@ 9100 TVDss datum)
P e t r o l e u m reserves
The current estimated ultimate recovery from the Brent reservoir in the Cormorant Field is 624 MMSTB, 401 M M S T B of which will be produced via the North Cormorant platform. This corresponds to an overall recovery factor of 38%, which is in line with Taylor & Dietvorst (1991). The overall recovery factor of 42% for Block III v. 34% for Block IV is a direct result of the structural complexity of Block IV.
Block IV is approximately 35% but this is reduced to the region of 5% in the absence of water injection.
Production rate
Cumulative production
Well performance has typically been characterized by high initial rates and rapid declines, a trend reflected in the performance plot for North Cormorant (Fig. 7). Peak production occurred in November 1984 at 122 655 BBL/D but thereafter declined, until a plateau of some 30000BBL/D was reached in 1991, which has since been maintained.
Total production at the beginning of 2000 was 523 MMSTB; of this 344 M M S T B has been produced from the North Cormorant platform and 179 MMSTB from the Cormorant Alpha platform (including the UMC).
The author thanks Shell UK Exploration and Production Ltd and Esso (UK) Ltd for their permission to publish this paper. The data and interpretations presented here are the culmination of many years of study by both Shell and Esso staff, past and present, who are also acknowledged.
Controls on recovery
References
Recovery is expected to be moderate to good in the Cormorant Field. Due to the weakness of the aquifer in the region, oil production relies on water injection (for both pressure maintenance and to displace oil towards the producing wells). Detailed reservoir management is essential because the permeability contrasts between layers leads to uneven water advance. Sweep efficiency is further reduced by the presence of faults which compartmentalize the reservoir, particularly in Block IV. The average recovery factor for
GOFF, J. C. 1983. Hydrocarbon generation and migration from Jurassic source rocks in the East Shetland basin and Viking graben of the northern North Sea. Journal of the Geological Society, London, 140, 445-474. TAYLOR, D. J. & DIETVORST,J. P. A. 1991. The Cormorant Field, Blocks 211/21a, 211/26a, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 73-81.
The Staffa Field, Block 3]8b, UK North Sea J. G .
GLUYAS
l & J. R . U N D E R H I L L
2
1Lasmo plc, 101 Bishopsgate, London E C 2 M 3XH, UK Present address." Acorn Oil & Gas Ltd, Ash House, Fairfield Avenue, Staines, Middlesex TW18 4AN, UK 2 School of Geosciences, The University o f Edinburgh, Grant Institute o f Earth Science, King's Buildings, West Mains Road, Edinburgh EH9 3JW,, UK Abstract: The Staffa Field occurs at the crest of an intermediate tilted fault block that is located between the Ninian and Alwyn fields in the northern North Sea. The partnership BP, Lasmo and Ranger discovered the field with well 3/8b-10 in 1985. By 1990, BP had left the partnership while Lasmo and Ranger had received Annex B approval for development. First production from this small field reservoired in sandstones belonging to the Middle Jurassic, Brent Group was obtained in 1992. At sanction, reserves were estimated to be about 5.5 MMBBL together with 26.8 BCF corresponding to a recovery factor of 18%. Field life was expected to be about 7.5 years (to 2000) and the plateau length six months. Although initial production exceeded the planned plateau rate of 8000 BOPD, production ceased in June 1993 when the pipeline to Ninian became blocked with wax or wax hydrates. Remedial solvent treatment failed to remove the blockage and replacement of the blocked section was undertaken. This too became blocked soon after resumption of production and the field was shut-in in November 1994. It was then abandoned, since further replacement of the line was not justified economically. At abandonment the field had produced 3.9 MMBBL of oil, 0.296 MMBBL of N G L and 6.457 BCF of gas (just 13% of its original STOIIP). Location and history T h e Staffa Field occurs w i t h i n a small tilted fault block in a structurally low p o s i t i o n b e t w e e n the giant N i n i a n a n d A l w y n fields (Figs 1-3). Staffa was discovered by well 3/8b-10 drilled in 1985 by
the p a r t n e r s h i p o f BP, L a s m o a n d R a n g e r . T h e well was p a r t o f a l o n g - t e r m e x p l o i t a t i o n strategy designed to evaluate the m a n y terraces o f tilted fault blocks to the s o u t h a n d east o f the N i n i a n Field. T h e same e x p l o r a t i o n p r o g r a m m e delivered the C o l u m b a fields i m m e d i a t e l y s o u t h o f Ninian.
Fig. 1. Location map.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 327-333.
327
328
J. G. GLUYAS & J. R. UNDERHILL
Fig. 2. Detailed location map for the Staffa Field showing position of wells and key faults. Contours are metres sub-sea on top of Brent.
In the discovery well, oil was found in sandstones ascribed to the Tarbert and Ness Formations, component parts of the Middle Jurassic Brent Group. Three zones were tested. They flowed at 2760 BOPD (lower Ness Formation), 4100 BOPD (upper Ness Formation) and 2500 BOPD (Tarbert Formation). A 58 m oil column was found in the Lower Ness Formation. The combined oil column in the Upper Ness and Tarbert Formation was 105 m. The oil obtained on test was light (39-44 ~ API) and sour (20 ppm H2S) with 3% CO2 and a solution G O R of 1940 SCF/BBL. The 3/8b-10 discovery was initially appraised with well 3/8b-11, which was drilled about 3 km to the north to test what was originally thought to be the same structure. Although well 11 found oil, the well results indicated that it was not in communication with well 10 and instead that it occurred in a separate fault block. Oil failed to flow to surface during the test programme. The failure of the well was ascribed to low permeability in the petroleum bearing Brent sandstones. Despite the failure of well 11 to produce petroleum or prove the northerly extension of the Staffa structure, there was in 1987 considered to be enough petroleum in the fault block containing 3/8b-10 to justify development. At that time oil-in-place was calculated to be
58.8 M M B B L (P50), with a range (P90-P10) of 40-82 MMBBL. A recovery factor of 30-35 % on the basis of water flood was thought possible (12-29 M M B B L reserves). The development scheme involved export through the Alwyn system and first oil in 1990. Later in 1987, reserves were downgraded following the drilling of the deviated 3/8b- 13 appraisal well in the same fault block as the discovery well (Fig. 2). The appraisal well was drilled down-dip of well 10. Its primary aim was to determine the level of the oil-water contact in the upper reservoir as well as refine understanding of the reservoir quality and oil properties. However, data obtained from the well were equivocal. The oil-water contact was not clear although there were oil shows down to a depth of 4171.5 m sub-sea. Although the difficulty of determining the oil-water contact was initially put down to the extremely low permeability of the Brent sandstones, subsequent drilling suggests that the well lay outwith the field's structural closure. The reservoir interval in well 13 was subject to both production and injection tests. The production test failed to produce water to surface but the equivalent of 101 BWPD were displaced into the borehole. The average test permeability was calculated to be only
STAFFA FIELD
329
o
g
9
9 .1 o
8
...a
2
. ,....,
r.~
,< o .,o
"O
Z
9
9
c~ 9
g~
~.-~=
330
J. G. GLUYAS & J. R. UNDERHILL
Fig. 4. Oil-in-place, reserves and produced volumes in the Staffa Field as a function of time. 0.1 mD and the permeability height only 23 mD ft (skin +4). The maximum injection rate achieved as 15 550 BWPD at a well head injection pressure of 6353 psig (bottom hole injection pressure of 10 609 psig). Injection did not commence until a well head pressure of 4000psig had been attained although following the maximum rate at 6353 psig it was found that injection could be maintained at lower pressures. The sustained injectivity was ascribed to the formation of a fracture of half-length 170ft. Both oil-in-place and reserves estimates were reduced to 52.1 MMBBL (STOIIP) and 13.4 MMBBL (reserves). Lasmo and Ranger purchased the BP interest in 1988 and by mid-year 1990 submitted an Annex B development and production programme. Further seismic data were acquired and another appraisal well drilled in preparation for the Annex B. The original well, 3/8b-14 encountered poor quality reservoir in the southern, down-dip part of the field, as had well 13. Well 14 was sidetracked to a location close to the discovery well (3/8b-10). It was highly productive testing the two reservoir zones at 6056 BOPD and 8200 BOPD. By the time the Annex B was issued, the oil-inplace and reserves had been further reduced ( S T O I I P - P90 22.9 MMBBL, P50 30.7 MMBBL, P10 33.9 MMBBL; reserves P90 2.9 MMBBL, P50 5.5 MMBBL, PI0 7.1 MMBBL, Fig. 4). Production began in 1992 from wells 10 and 14z at about 8000 BOPD and oil was exported via the Ninian system. The field was abandoned less than two years later after 3.9 MMBBL had been produced and severe waxing problems had been encountered.
Structure, trap, seal and stratigraphy Block 3/8b lies within the Brent oil province in the southern part of the East Shetland Basin. The area is bounded to the east by the North Viking Graben and to the west by the East Shetland Platform. The basin and graben areas were created during two phases of rifting in the Permian to early Triassic and in the Bathonian to Ryazanian. The rifting resulted in the development of a series of tilted fault blocks, which contained rotated Middle Jurassic and older pre-rift sediments. Block 3/8b lies within a synclinal area separating the major tilted fault blocks that now form
the Ninian and Alwyn fields. The overall geometry of the tilted fault blocks within 3/8b is similar to that of the giant fields to the east and west. However the scale of faulting and hence overall size of structure is much less. Specifically, the tilted fault block containing Staffa contains at least two more fault segments alongstrike (Fig. 2) in addition to that penetrated by the discovery well 10 and appraisal wells 13, 14 and 14z. Immediately north of Staffa is an untested fault block and further north still is a segment, the footwall closure was tested by 8/8b-11, and although petroleum-bearing failed to produce oil on testing. The pre-rift sedimentary rocks within the Staffa and adjacent tilted fault blocks contain Brent Group and older Dunlin Group, paralic to shallow marine deposits (Fig. 3). The syn-rift interval comprises mudstones belonging to the Humber Group (Heather Formation and Kimmeridge Clay Formation). The post-rift stratigraphy in the area is also mudstone dominated. Limestones are developed only poorly in the lowermost Cretaceous while sandstones are present in the Late Paleocene Montrose Group (Lista, Andrew and Forties sandstones). The top seal for the Brent Group reservoirs is provided by mudstones of the Heather Formation, a component part of the Humber Group, and onlap of uppermost Jurassic to lowermost Cretaceous onto the Staffa structure (Fig. 3). In contrast to neighbouring fields, there is no indication of erosion at the top of the Brent Group, suggesting that the small, extensional fault block remained subaqueous throughout Late Jurassic rifting. The eastern edge of Staffa is fault-bounded against mudstones of the Heather Formation, which provide the side-seal for the structure. To the west the field is dip-closed with a closing contour at 4120m subsea (Fig. 2). It is also likely to be dip-closed to both the south and north although faulting may have further enhanced these closures. An internal mudstone horizon within the Ness Formation (midNess shale) acts as an intrafield seal to vertical fluid flow.
Reservoir A full sequence of the five Brent Group formations occurs with Block 3/8b although the basal Broom Formation is only poorly
STAFFA FIELD
331
Fig. 5. Structural correlation panel for the Staffa Field wells and 3/8b-11 showing the distribution of petroleum and internal reservoir stratigraphy. Line of section used is highlighted in Fig. 2.
developed and possibly faulted out in 3/8b-14 (Fig. 5). The lower to upper shoreface of the Rannoch to Etive complex has been penetrated by each of the wells in 3/8b although nowhere has it been seen to be oil bearing. A short interval of oil bearing Sandstone was found in the low net to gross Lower Ness interval in 3/8b-10. A possible correlative equivalent sandstone in nearby well 14z was not oil bearing. More than 95% of the oil-in-place in Staffa occurs within the uppermost part of the Ness Formation and the overlying Tarbert Formation (Fig. 5). The oil bearing reservoir interval in Staffa was extensively cored (Fig. 5) allowing detailed lithofacies and reservoir quality analyses and subsequently construction of a core-based reservoir zonation. Tarbert Formation zones 8-10 (Fig. 5), comprises massive, upper shoreface sandstones, weakly bioturbated transitional sandstones and intensely bioturbated lower shoreface sandstones. Zone 7 (Tarbert) contains only one lithofacies, cross stratified, fine to medium grained, moderate to moderately well sorted sandstones overlying a granule grade quartzose conglomerate. Zone 6 (Tarbert) is also represented by a single lithofacies, fine grained, moderately well sorted and slightly bioturbated sandstones. Within the area of the Staffa Field, the two upwards coarsening units and older uniform grain size sandstone that make up the Tarbert Formation have been interpreted as exposed progradational shorefaces overlying channelized delta front deposits. Although the channelized body is likely to display variations in thickness, such changes are small across the limited footprint of the Staffa Field.
The lithofacies that comprise the Ness Formation are typically a heterogeneous combination of upwards-fining sandstones units (5-12 m), smaller (2.5 m) upwards coarsening sandstone units, mudstones and coals. Deposition of the Ness sedimentary rocks is interpreted to have occurred within a delta top setting as fluvio-deltaic, distributary channel fills, crevasse-splay sandstones and interdistributary mudstones and coals. Reservoir quality within the Tarbert and Ness Formation sandstones of Staffa is highly variable. Moreover, the poorer quality sandstones have such low permeability that they cannot be considered effective reservoir. Although the fine to medium grained sandstones would at deposition have been excellent reservoirs a combination of compaction and cementation by quartz and illite reduced their quality dramatically. In the oil bearing interval of 3/8b-10 the average porosity of the net pay is 11% and in 14z, 11.5% while in wells 11, 13 and 14 the average porosity is 8%, 7.5% and 8.5%, respectively. The small difference between the better and poorer wells translates into an order of magnitude difference in arithmetic average permeability between 3/8b-10 and 3/8b-14z and the remaining wells (10 s to 100 s mD v. a few mD). Moreover, high permeability intervals of > I D remain in 3/8b-14z but are absent from the down-dip wells. The dramatic change in permeability from crest to flank of Staffa results from a decrease in the pore coordination number associated with increased quartz cement and illite cement down dip. Evidence gained from quantitative analysis of fluid inclusion homogenization temperatures, radiometric dating
332
J . G . GLUYAS & J. R. UNDERHILL
Fig. 6. Oil and GOR production profile for the Staffa Field.
of illite precipitation ages and modelling of petroleum migration into the trap indicates that cementation and petroleum filling of the reservoir occurred simultaneously (Robinson & Gluyas 1992). In such a setting early oil-fill of the crest of Staffa protected the sandstones from cementation but down-flank cementation continued so reducing reservoir quality.
Source The main source rock for the oil found within the Staffa Field is the Kimmeridge Clay Formation. The oil generation threshold for the base of the Kimmeridge Clay Formation in the area around Staffa was towards the end of the Cretaceous with an oil generation maximum reached at the end of the Paleocene (Robinson & Gluyas 1992). Expulsion and migration into Staffa would have occurred shortly after the oil generation threshold was achieved (England et al. 1987). At the time of the Annex B (1990), the source of the petroleum was understandably ascribed to the Kimmeridge Clay Formation. However, the presence of abundant wax in the petroleum (see production section) forces a re-evaluation of the assumed single source for the oil. Staffa is currently at 137~ At this temperature and certainly at the high temperatures down-dip it is possible that the additional oil has been generated from the Brent Group coals and mudstones containing wax-prone organic matter.
Development and production Development of Staffa used the discovery well 3/8b-10 and three, deviated appraisal wells, 3/8b-13, 3/8b-14 and 3/Sb-14z. Whilst wells 10, 14 and 14z were recompleted for production and tied back to the Ninian Field, well 13 was used as a water injector. The short production life of the Staffa Field began in March 1992 under primary gas exsolution drive and less than two years later, in November 1994, the field was shut-in, only to be abandoned shortly thereafter (Fig. 6). Although the initial rates achieved by producing from wells 10 and 14z exceeded expectation, being above the planned plateau rate of 8000 BOPD, decline was extremely rapid. By the summer of 1993, production was shut-in because of waxing problems within the export line to Ninian. Although solvent treatments were tried, the only effective solution proved to be partial replacement of the line. Production was resumed towards the end of 1993 and again the initial rate was good. The high productivity was not to last and within a few months production
had fallen to below 4000 BOPD. The line was again blocked but this time an additional problem was witnessed as the gas/oil ratio of the produced fluid began to rise. The increasing G O R was taken to indicate that the oil pool had been depleted and that by February 1994 the reservoir pressure was below the bubble point of the oil. This coupled with pressure analysis from wells 10 and 14z, indicating a barrier between the wells together with the waxing problems, was used to justify abandonment of the field with production at 3.9 MMBBL, that is approximately 13% of the Annex B STOIIP.
Staffa Field summary data Trap
Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column
tilted fault block 4180 n/a 4180 n/a 145
ft m m m m m
Par' zone
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Tarbert & Ness Middle Jurassic nl
76 10.4
% % mD % BOPD/psi
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor Water saturation
39-44
~ API
0.18-0.21
cp psig psig SCF/BBL BBL/MMSCF
1686-1789
1.99 17
SCF/RCF %
STAFFA FIELD
Formation water Salinity Resistivity
0.2645
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanismg Recoverable oil Recoverable gas Recoverable NGL/condensate
3.02 km 2 143 x 106 m 3 7760psi @ 4050mTVD psi 0.28 psi/ft 276 ~ 23-31-34 MMBBL n/a BCF 18 % gas exsolution and aquifer inflow 5.5 MMBBL 27 BCF n/a MMBBL
NaC1 eq ppm ohm m
Production Strat-up date Production rate plateau oil Production rate plateau gas Number/type of well
333
3 February 1992 12 000 n/a two production
BOPD MCF/D
References ENGLAND, W. A., MACKENZIE, A. S., MANN, D. & QUIGLEY, T. M. 1987. The movement and entrapment of petroleum fluids in the sub-surface. Journal of the Geological Society, London, 144, 327-347. ROBINSON, A. G. & GLUYAS, J. G. 1992. Duration of quartz cementation in sandstones, North Sea and Haltenbanken Basins. Marine and Petroleum Geology, 9, 324-327.
The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211]24, 211]25 UK sector, Northern North Sea K. A. GIBBONS, C. A. J O U R D A N & J. H E S T H A M M E R 1 Statoil, 4035 Stavanger, Norway 1 Present address. Department of" Earth Sciences, University of Bergen, Allegiaten 41, 5007 Bergen, Norway (e-mail." jonny, hesthammer@geo, rib.no)
Abstract: The Statfjord Field, the largest oil field in the Northern North Sea, straddles the Norway/UK boundary and is located on the southwestern part of the Tampen Spur within the East Shetland Basin. The accunmlation is trapped in a 6-8 ~ W-NW dipping rotated fault block comprised of Jurassic-Triassic strata sealed by Middle to Upper Jurassic and Cretaceous shales. Reserves are located in three separate reservoirs: Middle Jurassic deltaic sediments of the Brent Group, Lower Jurassic marine-shelf sandstones and siltstones of the Dunlin Group; and Upper Triassic-lowermost Jurassic fluviatile sediments of the Statfjord Formation. The majority of reserves are contained within the Brent Group; and Statfjord Formation sediments which exhibit good to excellent reservoir properties with porosities ranging from 20-30% permeabilities ranging up to several darcies, and an average net-to-gross of 60-75%. The sandstones and siltstones of the Dunlin Group have poorer reservoir properties where the best reservoir unit exhibits an average porosity of 22%, an average permeability 300 mD and net-to-gross of 45%. Structurally, the field is subdivided into a main field area characterized by relatively undeformed W-NW dipping strata, and a heavily deformed east flank area characterized by several phases of 'eastward' gravitational collapse. Production from the field commenced in 1979 and as of January 2000, 176 wells have been drilled. The oil is undersaturated and no natural gas-cap is present. The drainage strategy has been to develop the Brent and Dunlin Group reservoir with pressure maintenance using water injection and the Statfjord Formation reservoir by miscible gas flood. However, a strategy to improve recovery by implemeiating water alternating gas (WAG) methods is gradually being implemented for both the Brent and Statfjord reservoirs. Current estimates indicate that by 2015 a total of 666 x 1 0 6 S m 3 (4192 MMBBL) of oil will be recovered and 75 GSm3 (2.66 TCF) gas will be exported from the field.
The Statfjord Field is situated in the northern North Sea approximately 220km N W of Bergen, Norway (Fig. 1). The field lies primarily within Norwegian Petroleum Production Licence 037, Blocks 33/9 and 33/12, but extends across the N o r w a y / U K boundary into U K offshore Licence P.104, Blocks 211/24 and 211/25. The field has a hydrocarbon bearing area of approxima~tely 2 4 k m by 4 k m making the Statfjord Field the largest oil field irk the Northern North '.. Sea (Roberts et al. 1987). Structurally, the field is characterized by a relatively undeformed main field area, comprised of strata which dip W - N W and a heavily deformed east flank area characterized by several phases of gravitational collapse (Fig. 2). The main field area comprises strata in a 6-8 ~ W - N W dipping rotated fault block that is cut by predominantly N W - S E trending faults and gravitational collapse structures (Fig. 2). The Upper Triassic to Middle Jurassic sediments of the Statfjord Formation, Dunlin Group, and Brent Group comprise the main reservoirs (Fig. 3a, b,c). For reservoir management purposes the Brent Group reservoir is further subdivided into seven units, whereas the Dunlin Group and Statfjord Formation are subdivided into five and four units, respectively. The field is capped by Middle to Late Jurassic marine shales of the Viking Group (Heather and Draupne Formations) and Lower Cretaceous limestones and shales. Water depths across the field average 145 m increasing slightly from south to north.
production licence. Equity redeterminations were carried out in 1979, 1991 and 1998. The last redetermination, in 1998, resulted in a tract participation of 85.47% for the Norwegian Partners and 14.53% for the U K Partners. The current ownership of the Statfjord Field is detailed in Table 1.
History The Norwegian Petroleum Production Licence 037 was granted in 1973 to a consortium of oil companies: Den norske stats oljeseskap (Statoil), Mobil Exploration Norway (designated field operator), Norske Conoco, Esso Exploration Norway, Norske Shell, Saga, Amoco Norway, Amerada Hess and Texas Eastern. The U K Blocks 211/24 and 211/25 had already been licensed in 1971 to Conoco U K (Operator), Gulf Oil Corporation and the National Coal Board which transferred its share to BNOC (Exploration) Limited in 1973. The intervening years have seen changes in both operatorship and ownership. Den norske statosljeselskap (Statoil) took over as Operator in 1985 in accordance with the conditions set out by the
Fig. 1. The structural setting of the Statfjord Field.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 335-353.
335
336
K. A. GIBBONS E T AL.
Fig. 2. (a) Regional profile across the northern North Sea and the Statfjord Field (from Hesthammer & Fossen 1999). (b) fault map of the North Sea Rift System location map showing location of profile in (a) (modified from Spencer & Pegrum 1990). (e) Schematic cross-section across the Statfjord Field (fig. 2 from Hesthammer et. al. 1999). Several major hydrocarbon discoveries within the UK sector, in particular the Brent Field, prompted drilling of exploration wells as soon as the production licence was signed. The first well, 211/24-1, spudded mid-1973, lay on-trend with the Brent Field to the south but encountered water filled sandstones of the Brent Group and Statfjord Formation. The discovery well, 33/12-1, spudded in December1973, was drilled just west of the structural crest and proved a 161m oil column, filling the entire Brent section. The Statfjord Formation was water bearing. The well was plugged and abandoned in February 1974 after testing to the capacity of the separator at 1590 Sm 3 d -1 (10000 BOPD). The Brent reservoir oilwater contact was established in 1974 with well 33/9-1, located to the north of, but structurally down-dip of well 33/12-1. The field was declared commercial in 1974 and in the period 1974-1977 a rapid succession of exploration and appraisal wells were drilled. Of these, well 33/12-2 (1974) established oil-bearing Statfjord Formation and well 211/24-4 proved oil-bearing Brent Group reservoir sandstones, thus confirming the southern extension of the field within the UK sector. Initial exploration/appraisal of the field was completed in 1977 with the drilling of well 33/9-9. However, in 1991 renewed exploration/appraisal of the field commenced with the drilling of well 33/9-C27, which proved oil-bearing Brent Group sandstones on the eastern side of the main boundary fault (Fig. 3). Then, in 1997, appraisal well 33/9-G3H was drilled as part of the development of the north flank of the Statfjord Field. Exploration of prospective Upper Jurassic sandstones was carried out in 1998 as part of the objective for a new production well, 3 3 / 9 - C 1 9 A , located to the north of well 33/9-C27 (Fig. 3a). The well did not penetrate sand in either the exploration or the production target. Nevertheless, evaluation of prospects in Upper Jurassic sandstones continues. Development of the Brent Group and Statfjord Formation reservoirs took place in three phases utilizing three Condeep concrete gravity-base platforms, each with a Single Point Mooring for tanker loading. The first phase of development began with oil production from the centrally placed 'A' platform in November 1979. A second phase was initiated with oil production from the southern 'B' platform in November 1982 and a third phase with production from the northern 'C' platform in July 1985 from which
world record extended reach wells 33/9-C10, 33/9-C2 and 33/9-C3 (Fig. 3a) were drilled during 1990-1991. Production of the Dunlin reservoir started in 1994 utilizing existing production wells. Today the Statfjord Field infrastructure (Fig. 4) plays a central role in the transport and distribution of gas from other Norwegian fields and to the UK. Since 1992 oil production from the neighbouring Snorre Field has been fed through the Statfjord 'A' platform. Subsequent sub-sea development of the Statfjord satellite fields, Statfjord Ost (1994) and Statfjord Nord (1995), is linked to the Statfjord 'C' platform. The north flank of the Statfjord Field and the Sygna Field are currently under development. The first oil production from the Statfjord north flank started in August 1999 and oil production from the Sygna Field is planned in the year 2000. Both are sub-sea developments linked to the Statfjord 'C' platform (Fig. 4). At the start of 2000 cumulative production from the Statfjord Field had reached 584x 106Sin 3 (3675 MMBBL) of oil and 140GSm 3 (4.93 TCF) gas of which approximately 55GSm 3 (1.94 TCF) has been exported. Average daily production in 1999 was 40 000 Sm3/d (252 000 BOPD). Plateau production was reached in 1986 and production decline commenced in 1995.
Table 1. Sta(J)ord unit owners Company
Participating interests
Den norsk stats oljeselskap (Statoil) Mobil Exploration Norway Norske Conoco Esso Exploration Norway Norske Shell Saga Petroleum Enterprise Oil Norge
42.73434% 12.82030% 10.32747% 8.54687% 8.54687% 1.60254% 0.89030%
Total Norwegian interests
85.46869%
BP Amoco Chevron UK Conoco UK Total UK interests
Fig. 3. Well location maps of the Statfjord Field. (a) Top Brent reservoir. (b) Top Dunlin reservoir. (c) Top Statfjord reservoir.
4.84377% 4.84377% 4.84377% 14.53131%
LEGEND Horizontal well path New well 97/98 Active well Penetrates Former well track/interval Exploration well East Flank Undiff. Brent Water flooded East Flank Main Field Water flooded Start B I truncation Original OWC Faults interpreted as partially sealing
338
K. A. GIBBONS E T AL.
STATFJORD FIELD
339
Fig. 4. Statfjord Field infrastructure. Structural setting and evolution The Statfjord Field (Kirk 1980) is situated in a sub-platform position (Gabrielsen 1986; Gabrielsen et al. 1990) within the East Shetland Basin on the western margin of the North Sea Rift System. The East Shetland Basin is bounded by the East Shetland Platform to the south and west, the More Basin and Tampen Spur to the north and northeast and the North Viking Graben to the east (Fig. 1). The field is located along the crest of a N E - S W trending fault block which is tilted gently towards the northwest (Fig. 2a). The Statfjord and Brent Fields lie within the same major fault block. The Ninian, Hutton, Dunlin and Murchison Fields lie within the next major fault block to the west. The western part of the North Viking Graben is characterized by a series of N N E - S S W trending structural lineaments which parallel the graben (Fig. 2a). In general, these N N E - S S W trending faults bound the fields to the east, and are often referred to as bounding or main boundary faults. These lineaments are cut by N W - S E trending faults that divide the sub-platform area into individual fault blocks and which separate the Brent Field from the Statfjord Field. The area underwent at least two major rift phases which postdate the Devonian thinning and regional stretching of the Caledonian crust (Hesthammer et al. 1999). The first, Permo-Triassic rift phase, resulted in the establishment of the Viking Graben (e.g. Badley et al. 1984, 1988; Beach et al. 1987; Roberts et al. 1995). The second main rift phase (e.g. Brown 1984; Thorne & Watts 1989), in the latest middle Jurassic to earliest Cretaceous, resulted in a generally N W - S E extension (Roberts et al. 1990a, b). A relative rise in sea level followed the second rift phase, resulting in a progressive burial of the Triassic and Jurassic reservoirs. This burial continued during the thermal subsidence in the post-rift stage of the entire North Sea Basin in the Cretaceous and Paleocene. The Statfjord Field is subdivided into two main structural domains (Fig. 2c): a relatively undeformed main field characterized by W - N W dipping strata and an east flank area characterized by gravity collapse structures in the form of rotational block slides and associated erosional/degradational products. The two structural domains are separated by a surface termed the base of slope failure
(BSF) which starts with the first block slide east of the field's crest and can to some extent be mapped seismically. Seismic interpretation is aided by log data from more than 80 wells which penetrate the BSF. In most cases this surface is represented in wells by the lowermost observed fault which separates reservoir zones which are part of the deformed east flank from the less deformed main field area (Hesthammer et al. 1999). Over the main field, several N W - S E trending, steep-dipping cross faults commonly offset the base Cretaceous (Fig. 3). Transpressional structures formed during the Tertiary are identified in the northern and central part of the field and in the hanging wall to the main boundary fault. The east flank area is dominated by rotational block slides that cut into the reservoir and are defined between the crest of the field and the major boundary fault to the east of the crest (Fig. 2c). Several phases of gravity block sliding, related to regional tectonic activity associated with the middle-late Jurassic rift event, are interpreted. With each phase the gravity slides cut progressively westwards at shallow levels and deeper, down through the Brent, Dunlin and Statfjord reservoir sections. The final stages of gravity sliding affected the Statfjord Formation in the easternmost parts of the field, adjacent to the main boundary fault, and the upper part of the Brent Group to the west. Hydrocarbons are produced from the hanging wall of the main boundary fault, in the area of well 33/9-C27 (Fig. 3). The reservoir in this well is interpreted as remnant block slides and/ or erosional products that formed during the first phases of movement along the main boundary fault. Degradation products (erosion of underlying slump blocks) overlie depressions in the east flank area. Two minor erosional events acted on the field. One is defined at the base of the Draupne Formation, where major collapse is recognized, whereas the other defines the base of the Cretaceous.
Lithostratigraphy and tectonic framework The large amount of seismic and well data available from the Statfjord Field has enabled a consistent tectonostratigraphic framework to be developed. The summary below is largely based
,,o c
E
a,, c
q~ ~o ~E
g
E'g ~,
~
.i ~ ,~o
E~
e
"5 CO I-Z W > w
< Z
SE
o
o o
m E
-z
~ o~
o_o
~
~, _~ _
8
0 u_l
~
~ .~
~ ~
.E o m
~,::
F_go~
~ ~
~~
o
=
#_. -~ -,::, u
8
,g
,~o
,-,g
zo ~ g,~ g
1~V11~31
9no3ovzga3
~noa9
1N3~8
dNO~O
rY
NI7NnO/,/~o~or~•
3~93H
/,
s
0T
9 == o
o
ill
o
"i"~
7-
i!! ~i~~J
d
UNDIFFERENTIATED
w ~z
E =
i~~
7-
=2
[~
31V7
A~IVIIW31
31v7
sk7~IV-9
sn033V_l_3~lO
31ssvEinr
9-
o
.~
0
37aallAl/~,7blv=J
31SSVlEI_L
N2
STATFJORD FIELD on the framework as detailed by Hesthammer et al. (1999). The stratigraphic column for the Statfjord Field shown in Figure 5 is modified after Deegan & Scull (1977) and Vollset & Dore (1984). The chronostratigraphy of the Dunlin Group is adjusted slightly in light of the evaluation of biostratigraphic data from wells and recently published literature (Parkinson & Hines 1995).
Hegre Group (Scythian-Rhaetian) The Scythian-Rhaetian Hegre Group represents the oldest strata penetrated in the Statfjord Field. The group covers the entire Northern North Sea and represents extensive development of thick continental red-bed sequences which accumulated in a rapidly subsiding intracratonic rift system associated with the Permo-Triassic rift event and consists of interbedded intervals of sandstone, claystone and shale associated with sequences of dominantly sand or shale/claystone. The deepest well on the Statfjord Field, well 33/12-5, penetrated 1840 m of the Triassic Hegre Group, but did not reach the base of the Triassic. Furthermore, the base of the Hegre Group has not been penetrated in the Viking Graben and the thickness of this unit in this area remains unknown. Gravity surveys and regional deepseismic lines indicate that only a thin unit of sediments exists between the Triassic sedimentary rocks and crystalline basement in the region (Christiansson et al. 2000; Odinsen et al. 2000a, b). From seismic data, an eastward thickening of the Hegre Group on the Statfjord Field is observed. This thickening is consistent with a regional thickening of the Triassic and Lower Jurassic sediments in the Tampen area first documented by Hay (1978) and may be related to thermal subsidence towards the Viking Graben during the final stages of the Permo-Triassic rift event of the Viking Graben area (Hesthammer et al. 1999).
Statfjord Formation (latest Rhaetian-latest Sinemurian) The Upper Rhaetian to Sinemurian Statfjord Formation consists of interlayered sandstone/siltstone and shale deposited with apparent conformity on the underlying Hegre Group. Together with the Hegre Group the Statfjord Formation forms the thick continental basin-fill rift and post-rift sequences deposited within the Viking Graben. The transition from the Hegre Group to the Statfjord Formation is often difficult to define. However, in the Statfjord area the boundary is often recognized at the base of a coarsening upwards sequence which marks the passage from the more shaly fluvial and fluviolacustrine deposits of the Lunde Formation (Hegre Group) to the massive alluvial plain/braided stream deposits of the Statfjord Formation (Fig. 6). The transition from the Lunde Formation (Hegre Group) to the Raude Member of the Statfjord Formation represents a major regional basinwards facies shift (Parkinson & Hines 1995). The general palaeoenvironmental setting for the Statfjord Formation is that of alluvial plain deposits cut by northwards flowing axial rivers with local lateral fans along the graben margins. The Statfjord Formation is subdivided into three members (Fig. 6). The Raude and Eiriksson Members comprise the heterogeneous, fluvially dominated section and the Nansen Member, a relatively thin transgressive sandstone unit with good reservoir properties. The Raude Member consists of isolated fluvial channel sandstones embedded in a mudstone matrix, whereas the overlying Eiriksson Member comprises amalgamated fluvial channel sandstones and interbeded mudstones. Continued subsidence combined with a regional rise in sea-level resulted in a marine transgression across the area represented by the sandstones of the Nansen member. The Nansen Member is commonly interpreted as timetransgressive and may be underlain by a transgressive erosion surface (Parkinson & Hines 1995). In the Statfjord Field, the three members are informally referred to as $4 and $3 (Raude Member), $2 (Eiriksson Member) and S1 (Nansen Member) (Fig. 6).
341
The Statfjord Formation ranges in thickness from 150 to 300 m and displays a thinning trend towards the NNE along the field. Similar trends are also observed on a more regional scale for the Tampen area (Hesthammer et al. 1999). The Statfjord Formation exhibits a localized thickening trend in the northernmost parts of the field, reflecting a change in depositional environment which may be related to contemporaneous activity of the Alwyn-NinianHutton fault zone (Fig. 1) to the southwest (Johnson & Eyssautier 1987; Richards et al. 1993). There is no clear indication of movement along the Statfjord Field boundary fault during deposition of the Statfjord Formation.
Dunlin Group (latest Sinemurian-earliest Bajocian) The Dunlin Group conformably overlies the Statfjord Formation and comprises shallow marine mudstones, siltstones and sandstones ranging in age from latest Sinemurian to earliest Bajocian. The lower part of the Dunlin Group was deposited in response to continued basin subsidence and a general rise in sea-level initiated during deposition of the upper part of the Statfjord Formation. The transition from the underlying Statfjord Formation is clearly marked by gamma ray log breaks due to the change from sandstones of the upper Statfjord Formation to silty mudstones of the lower Dunlin Group. The Dunlin Group generally has a more regular log character than the underlying Statfjord Formation and the overlying Brent Group The group consists of four formations, the Amundsen (oldest), Burton, Cook and Drake (youngest) Formations, and has a total thickness in the range of 230-260m. In the Statfjord Field, these formations are informally referred to as D3 (Amundsen and Burton Formations), D2 (Cook Formation) and D1 (Drake Formation) (Fig. 7). All four formations are very heterolithic with common thinbed alternation of sandstone and mudstone. The Amundsen and Burton Formations comprise shallow marine siltstones and mudstones with the Burton Formation tending to be the most shaly, consisting largely of offshore open marine mudstones. Locally, in the southwestern part of the Statfjord Field, a calcareous sandstone is developed near the base of the Amundsen Formation and represents the transition from the marine sandstones of the Nansen Member to the marine shales of the Amundsen Formation (Fig. 7). The Burton Formation is overlain by the sandstones and mudstones of the Cook Formation. Sequence stratigraphic studies (Parkinson & Hines 1995; Dreyer & Wiig 1995) recognize a regional regression, or rapid fall in sea-level during the late Pliensbachian-early Toarcian corresponding to the deposition of the Cook Formation. In general, the formation comprises two large scale coarsening upwards sequences consisting of heterolithic sandstones and mudstones deposited in wave-influenced lower shoreface to offshore environments. A more tide-dominated deltaic setting is indicated for the upper part of the Cook Formation in the Gullfaks area to the east (Dreyer & Wiig 1995). Some authors do recognize a possible westerly source area for deposits in the area of the Statfjord Field (Parkinson & Hines 1995). The regional regression is possibly coupled to a phase of pre-rift doming/tectonic uplift along the eastern flank of the Viking Graben Rift Basin. At the end of the early Toarcian, a widespread relative sea-level rise resulted in an overall transgression and deposition of the marine mudstones of the Drake Formation. The regional N - N E thinning trend observed in the Statfjord Formation continued during deposition of the Dunlin Group. Thicker Amundsen and Burton Formations are observed in the hanging wall side to the main boundary fault in well 33/9-C27, suggesting fault activity during deposition of these units in the latest Sinemurian to Pliensbachian. Deposition has probably kept pace with the displacement of the faults, thus subduing the topographic relief. No evidence of fault activity is recorded during deposition of the Cook Formation in late Pliensbachian-earliest Toarcian. However, the Drake Formation in well 33/9-C27 is thicker than the surrounding areas, suggesting further activity along the main fault on the Statfjord Field in the Toarcian-earliest Bajocian (Hesthammer et al. 1999).
342
Fig. 6. Statfjord Formation - type well log 33/9-A33.
K. A. G I B B O N S E T AL.
STATFJORD FIELD
Fig. 7. Dunlin Group - type well log 33/12-1.
343
344
K. A. GIBBONS ET AL.
Brent Group ( Bajocian-mid-Bathonian )
The faulting noted during deposition of the Drake Formation is probably related to Late Toarcian uplift, precursor to the Cimmerian rift phase, in central parts of the North Sea. This uplift created a general doming to the south of the Statfjord area which resulted in a regression and overall northward progression of the Brent Group during the Early Bajocian to mid-Bathonian (Hesthammer et al. 1999). Minor fault activity in Toarcian-earliest Bajocian time continued during deposition of the lowermost part of the Brent Group, the Broom Formation, and terminated prior to deposition of the Rannoch Formation (Fig. 5). This is suggested by a thicker early Bajocian Broom Formation in well 33/9-C27. There are indications that minor fault activity started again during deposition of the uppermost parts of the Brent Group, the Tarbert Formation (Hesthammer et al. 1999). In the Statfjord Field the Brent Group is 180-250m thick and consists of sandstone, siltstone, shale and coal deposited in a fluviodeltaic system that in general decreases in thickness towards the northeast. The group can be considered as one long term regressivetransgressive sequence and recent sequence stratigraphic studies (e.g. Johannessen et al. 1995) recognize several third order transgressive-regressive cycles within the group. The unit is divided into five formations, the Broom, Rannoch, Etive, Ness and Tarbert Formations. In the Statfjord Field, the Brent Group is also informally subdivided into zones B1 B6. Zones B1 to B3 correspond to the Ness and Tarbert Formations, whereas zones B4 to B6 correspond to the Etive, Rannoch and Broom Formations (Fig. 8). A field wide pressure shale is present within zone B3 (Ness Formation). The lower three formations, also referred to as the Lower Brent (Fig. 8), are generally interpreted as being deposited in a coastal to shallow marine environment and represent progradation deposits of the deltaic complex. The sediments show a change in depositional environments from the storm deposits and small distal bar build-ups on a shallow marine platform of the Broom Formation, to the storm wave dominated pro-delta, delta front and ebb-tidal deposits of the Rannoch Formation, through to the tidal inlet/ebb tidal, upper shoreface foreshore and lagoon barrier deposits of the Etive Formation. The upper two formations, also called the Upper Brent (Fig. 8), are interpreted as representing the maximum progradation of the delta and subsequent onset of regression, as indicated by the fluvial channel delta plain deposits of the Ness Formation and the overlying shallow marine deposits of the Tarbert Formation. The transgressional nature of the Tarbert Formation is widely debated. In the southern part of the Statfjord Field the sandstones of the Tarbert Formation inter-finger with shales and are interpreted as fluviodeltaic whereas towards the northern part of the field and into the Statfjord Nord Field the sandstones are interpreted as middle to lower shoreface (Johannessen et al. 1995). There is probably a significant Bajocian-early Bathonian hiatus over the field within the Upper Brent section.
Viking Group
The marine shales and siltstones of the Viking Group overlie the Brent Group and range in age from middle Bathonian to early Ryazanian. The group is subdivided into the Heather and Draupne Formations. The shales are extensive in the East Shetland Basin and were deposited in response to extensional tectonic activity and subsidence related to the late Jurassic evolution of the Viking Graben. The main period of tectonic activity on the Statfjord Field took place during, and after deposition of the upper part of the Heather Formation. Episodes of uplift, rotational block sliding, faulting and differential subsidence associated with the regional tectonic events are evidenced by thickness variations, erosion, and missing or repeat sections on the field. The Middle Bathonian to Upper Oxfordian Heather Formation consists of silty marine shales. The base of the Heather Forma-
tion is identified over most of the Statfjord Field and is mainly conformable with the Brent Group. However, in the east flank area, this formation is missing in several wells, probably due to minor erosion prior to gravity failure and associated rotational block sliding. In addition, an E-NE thinning of the Heather Formation indicates that the westward tilting of the Statfjord Field related to the late Jurassic rift event started during, and possibly just prior to, deposition of the lowermost parts of the Heather Formation (Hesthammer et al. 1999) Increased westward tilting of the structure took place towards the end of, and after, deposition of the upper Heather Formation as indicated by several erosional boundaries. An approximately six million year hiatus at the base of the Draupne Formation eroded the Brent Group locally at the crest of the structure. The largest amount of erosion of the Brent Group is recorded along the crest in the northernmost and southernmost parts of the field which are believed to represent topographic highs during and after the main extensional event. Footwall uplift is a natural mechanism for lifting the crest of the structure and exposing it to erosion and gravitational collapse. In general only minor (tens of metres) erosion of the Brent Group is observed along the present crest of the structure. It is possible that erosion of the Brent Group increases in the east flank area towards the main boundary fault since, prior to slumping, the crest of the structure was located immediately adjacent to the main boundary fault and would therefore experience most erosion (Hesthammer et al. 1999). The major period of deformation on the Statfjord Field occurred during or immediately after deposition of the uppermost Heather Formation. Uplift along the main boundary fault created instabilities in the partly consolidated sediments which resulted in the formation of gravitational collapse structures. On the basis of well data and seismic data three main stages of gravitational sliding have been identified on the east flank of the Statfjord Field (see Fig. 9, Hesthammer & Fossen 1999; Hesthammer et al. 1999, for details). The first major episode of slumping occurred in the Brent Group which detached within shales of the Ness Formation. As offset along the main fault increased, shales within the Dunlin Group became exposed across the fault precipitating the next, deeper level of detachment and slumping, particularly within the shales of the Amundsen Formation (D3). A shallower level of slumping within the Brent Group probably occurred along the new breakaway zone formed after onset of slumping within the Dunlin Group. The third stage was initiated as shales of the lowermost part of the Statfjord Forrriation and uppermost part of the Hegre Group became exposed across the fault (Hesthammer & Fossen 1999) Exposed slump blocks of primarily Brent Group were subject to mainly submarine erosion and degradation during slumping. The erosional products of these sediments were re-deposited as a thin veneer, mainly sandstone, covering much of the area affected by slumping. On the Statfjord Field, the upper parts of wells 33/12-B21 and 33/12-B29 (Fig. 3a) are interpreted as producing from such a degraded package of reworked Brent Group sediments. Seismic data indicate that the surface expression was not completely smoothed by the degradation products, and thus some topographic relief existed at the time of Draupne deposition. Organic-rich Kimmeridgian-Upper Ryazanian Draupne Formation was deposited over most of the Statfjord Field after the main tectonic event, during post-rifting subsidence. The shales of the Draupne Formation are thickest on the west flank of the Statfjord Field and within the slumped areas where topographic relief was created during gravity sliding. Little or no Draupne Formation was deposited along the top of the structure as well as in topographic highs in the northern and southern parts of the field (see Hesthammer et al. 1999, Fig. 6c).
Cretaceous-Tertiary
Another hiatus exists between the top of the Draupne Formation and the base of the Cretaceous. Minor erosion occurred (likely immediately after deposition of the Draupne Formation) mainly
STATFJORD FIELD
Fig. 8. Brent Group - type well log 33/9-A15.
345
346
Fig. 9.
K. A. GIBBONS E T AL.
Seismic section across the Statfjord Field (from Hesthammer et al. 1999).
along the top of the structure. The base of the Cretaceous probably conformably overlies the Draupne Formation on the western flank of the structure. Northwest-Southeast trending faults were reactivated in Cretaceous and Tertiary time causing local transpression along the north-trending part of the main boundary fault in the northern area (Hesthammer et al. 1999). Further south, in the well 33/12-B16 area, indications of compression are observed, but with no movement along the main boundary fault after deposition of the Balder Formation. This indicates that compression, possibly related to post-rift thermal cooling, occurred during the Cretaceous. Similar inversion structures observed elsewhere in the Viking Graben are attributed to the post-rifting stage (e.g. Gabrielsen el al. 1990). A post-Balder north-tilting of the Statfjord Field resulted in an estimated 1 3 0 ~ 0 0 m topographic relief between the southern and northern parts of the structure during the Tertiary.
Geophysics Basic seismic data acquisition over the Statfjord Field was conducted in the following periods: 1973-1977: 1979-1980: 1991: 1997:
Acquisition in six surveys of 2D reflection profiles totalling 3600 km. A 3D survey covering 3300 subsurface kilometres to supplement the 1973-1977 data. A 3D survey covering 10000 subsurface kilometres with an inline spacing of 25 m. A 3D survey with the same subsurface coverage as the 1991 survey, but with an inline spacing of 12.5 m rather than 25 m.
The number of seismic horizons mapped has varied with each survey and is dependent on data quality, particularly regarding interpretation of intra-Brent horizons and the structurally complex east flank area. The most recent surveys have identified top Balder, base Cretaceous, top Reservoir (Upper Brent Group), top Lower Brent (Etive Formation), top Dunlin, top Statfjord and base Statfjord and the base of slope failure. The 1991 3D survey was of sufficient quality for analysis of volume related attributes and provided a link between seismic attributes, particularly amplitude, and lithology and fluid content in the main field area. The primary objective of the 1997 3D survey was to carry out time-lapse (4D) evaluation and identification of remaining oil pockets, particularly in the main field area. Furthermore, acquisition parameters were optimized to improve imaging of the structurally complex east flank. | n conjunction with the 1997 survey a three-dimensional-four component Ocean Bottom Cable (3D-4C OBC) survey with an aerial coverage of about 100 km 2 was acquired over the southeastern part of the field. The 3 D - 4 C OBC survey on the Statfjord Field was designed to test the potential application of four-component in imaging the fault block geometry in the east flank area. Results from the 1991 and 1997 3D surveys are actively used in the evaluation and planning of in-fill well locations in the main field area. Preliminary results from the 3 D - 4 C OBC survey indicate that these data provide a better image than the best available conventional 3D surface data and thus improve resolution of fault blocks in the east flank area (Rogno et al. 1999).
Trap The trapping mechanism on the Statfjord Field has both structural and stratigraphic components. The Triassic-Jurassic strata lie
STATFJORD FIELD within a WNW-dipping main fault block. Total displacement across the main eastern boundary fault is estimated to be 1500 m at top Statfjord Formation level. The Upper Jurassic and Cretaceous shales provide the sealing mechanism. In general, closure of the structure to the south is provided by a combination of a structural saddle and down-to-the south normal faulting and to the west and north by structural dip. Variations in oil-water contacts picked from well log and pressure data indicate that there is no single field-wide contact for any of the main reservoirs (ie. Brent Group, Dunlin Group and Statfjord Formation). Variations in oil-water contacts are found to be localized such that it is possible to recognize separate oil-water compartments or domains throughout the field. Domainal boundaries are defined by faults which are inferred to be partially sealing. In general, domains in the main field area are delineated by N W - S E trending faults. In the east flank, domains are defined by the geometry of the gravity induced fault blocks together with the N W - S E trending faults which are interpreted as partially sealing in the main field area. Juxtaposition of structurally thinned sandstone units against shaly sequences across the base of slope failure is interpreted to be the main sealing mechanism. The Brent Group has an oil-water contact of 2586.3m over most of the field (Fig. 3a). Domains with deeper oil-water contacts within this reservoir are identified in (a) the north flank, (b) the easternmost part of the east flank and (c) the well 33/9-C27 area. (a)
(b)
(c)
In the north flank an oil-water contact of 2597.0m is constrained to the northeast by the interpreted spill point for the field and to the southwest by a series of faults interpreted to have been activated by transpressional movements during the Tertiary. These movements are believed to post-date hydrocarbon migration, and a combination of fault sealing together with northward tilting of the structure during the Tertiary is probably the mechanism by which the deeper oil-contact was preserved. In the easternmost part of the east flank, adjacent to the main boundary fault, two domains are delineated for the Brent Group. One in the vicinity of well 33/9-A8, at 2593.0 m and a second around well 33/12-4, at 2676.4m. Here, juxtaposition of Brent Group sandstones with Dunlin Group shales along NW trending faults together with N-S trending faults created by gravitational collapse structures is interpreted as the sealing mechanism. Well 33/9-C27 is situated on the hanging wall of the main boundary fault. The well proved an oil-water contact of 2607.0 m within a rotated fault block comprised of Brent Group sandstones. The area is bounded by the main boundary fault to the west and by structural dip to the east.
In the Dunlin Group an oil-water contact is defined, for most of the main field area, at 2604.4 m. (Fig. 3b). An oil-water contact of 2673.8 m is delineated in the northeastern part of the east flank and a shallower contact of 2538.3m is identified in the southernmost part of the Statfjord Field on the basis of data from wells 33/12-B 19 and 33/12-B24. As for the Brent Group, sealing is probably along NW trending faults and N-S trending faults created by gravity collapse structures. In the Statfjord Formation, the oil-water contact in the southern part of the field is at 2806.3m and deepens northwards to 2814.0m and 2829.9m (Fig. 3c). The domains are defined by N W - S E trending faults. The Statfjord Formation is water bearing north of the down-to-the-north N W - S E trending fault penetrated by exploration well 33/9-4.
Depositional setting and reservoir quality The Statfjord Formation consists of an overall progradational, coarsening-upwards, sequence of interbedded sandstones, siltstone, shales, and limestone stringers representing a shift in depositional
347
environment from the shaly alluvial/brackish deposits of the Hegre Group to more sand-rich alluvial plain/braided stream deposits of the Statfjord Formation. Sand body density and interconnectivity increases progressively upwards from Raude Member ($4,$3) to the Eiriksson Member ($2). The Raude Member ($4, $3) consists of red and green shales and siltstones interbedded with thin, fine-to medium grained sandstones. A shale at the top of $4 is interpreted as a barrier separating oil bearing Statfjord ($3, $2 and S1) from water bearing section ($4). The Eiriksson Member ($2) is comprised of inter-stratified amalgamated sandstones and mudstones which typically exhibit a 'blocky' log pattern compared with the underlying Raude Member (Fig. 6). Sandstones in the Eiriksson Member are fine to very coarse and conglomeratic, feldspathic to arkosic containing both a kaolinitic matrix and calcite cement. The sandstones are interbedded with dark grey, carbonaceous shales and coals. The shift from the red-green shale units of the Raude Member to the gray-black shales of the Eiriksson Member is also reflected in the clay mineralogy composition of the shales which exhibit decreasing mixed-layer, smectite/illite, clay content and increasing kaolinite content (Paul Nadeau, pers. comm.). A major climatic change from semi-arid to humid conditions between deposition of the Raude Member and the Eiriksson Member is interpreted (Chauvin & Valachi 1980). Furthermore, caliche-soil profiles followed by a field-wide lacustrine shale, which is also a field-wide pressure barrier, mark the boundary between these members ($2 and $3). The overlying Nansen Member (S1) marks the top of the overall coarsening upwards trend of the Statfjord Formation and represents a relatively thin (1-17m), clean transgressive marine sand. The overall reservoir quality of the Statfjord Formation increases upwards (Table 2). Modelling of the vertical and lateral connectivity of the sand bodies, particularly within the $3 unit, is critical to reservoir management and optimal well placement. Horizontal wells play an important role for increased recovery from these units. In the southern part of the Statfjord Field the transition from the Statfjord Formation to the overlying Dunlin Group is marked by a calcareous sandstone unit representing a regional transgression and shift to the marine shelf mudstones/siltstones of the Amundsen Formation (Fig. 7). In other parts of the field the transition is marked by a chamositic shale characterized by sharp peaks on the neutron porosity log and a bow shaped response on the gamma-ray log. This distinctive log response is indicative of a complete basal Dunlin sequence and, when present, is an important tool for determining the position of faults and/or detachment surfaces in the east flank area. The Dunlin Group consists mainly of shallow marine shales with some interbedded sandstone/siltstones in the middle portion. The logs from the Dunlin Group generally show a very regular pattern throughout the field. The Cook Formation (D2A, D2B) is the main reservoir unit consisting of marine distal shoreface heterolithic sandstones with generally poor permeability but good porosity
Table 2. Typical reservoir properties
Tarbert Ness Etive Rannoch Broom Dunlin Nansen Eiriksson Raude
B1 B2 B3 B4 B5A B5B B6 D2A D2B S1 $2 $3
Porosity (%)
Water Sat.(%)
N/G (%)
H. Perm (mD)
30 26 19 29 29 24 17 22 11 29 25 20
7 25 39 6 8 24 58 34 30 11 15 20
94 61 21 99 85 74 47 45 5 100 70 40
3800 1900 100 4100 1300 300 10 300 5 5000 1250 100
348
K.A.
GIBBONS E T AL.
o
. ,,..~
STATFJORD FIELD values (Table 2). The Cook Formation consists of two large scale coarsening upwards sequences defined as units D2A and D2B. The Brent Group represents the progradation and retreat of the fluvio-deltaic sediments of the Brent-delta complex and is subdivided into seven reservoir units (Fig. 8). In the deformed east flank area of the field these units are identified by the prefix Undifferentiated B1 etc. The lowermost unit, the Broom Formation (B6), is the thinnest unit (1-12mTVD) and consists of coarse, pebbly sandstones deposited as lowstand offshore storm deposits. It is subject to debate whether it represents the onset of the prograding Brent delta-complex or whether it represents a separate event of sand input to the basin. The Rannoch Formation is an overall coarsening upwards sequence consisting of well laminated silty to very fine micaceous sandstones with calcite layers deposited in a lower to middle shoreface storm dominated environment. The formation is further subdivided into reservoir units, B5A and B5B. The uppermost B5A unit is comparatively 'cleaner', less micaceous than the lowermost B5B unit. The Etive Formation (B4) is composed of massive, clean, nonmicaceous sandstones of excellent reservoir quality. The Etive Formation is interpreted as upper shoreface foreshore beach barrier/strand plain deposits. A detailed sequence stratigraphic interpretation of the Rannoch and Etive Formations based on core descriptions and log data indicates that the formations comprise several northwards prograding-aggrading shoreface sequences. Figure 10 is a S-N section along the field and illustrates the permeability distribution within the sequence stratigraphic framework. Three hierarchic levels of base level fall and rise are interpreted: (1) high frequency; (2) intermediate frequency; and (3) long term (Fig. 10). Overall, permeability within each cycle increases upwards. However, in the basinward direction, permeability decreases, grading from fine grained to very fine grained, micaceous sandstones (Fig. 10). Bounding surfaces between cycles are often characterized by permeability minima represented by siltstone and/or carbonate cemented surfaces. In general, the lowest permeability units within a cycle correspond to the more distal, micaceous sandstones of the lower shoreface B5B unit, intermediate permeability units to the proximal, less micaceous, lower shoreface sandstones of the B5A and the highest permeability units to the upper shoreface B4 type sandstones of the Etive Formation. This interpretation contrasts with a purely lithostratigraphic driven interpretation and has been important to the planning of wells and recent changes to the drainage strategy of the field. Permeability contrasts between the individual cycles result in water override which is augmented by the baffles or local barriers at the boundary surfaces between cycles. Placement of horizontal wells relative to these baffles has proved crucial to recovery from the B5B sandstone units. Furthermore, simulation of W A G (water-alternating-gas) processes, based on this interpretation, show that these vertical permeability contrasts contribute to vertical segregation of the injected water and gas thereby reducing recovery. The Ness Formation is subdivided into two units, B3 and B4. The B3 unit represents the maximum progadation of the fluviodeltaic Brent Group deposits, expressed as a heterogeneous succession of interbedded sandstones, shales and coals deposited in a lagoonal to coastal plain setting with fluvial distributary channels. This unit is often seen on logs as a thick shale with some sandstone and coal beds and acts as a field-wide pressure barrier separating the lower reservoir units (B4, B5A and B5B) from the upper B2 and B1 reservoir units. The B3 shale is interpreted as a major detachment surface for gravitational collapse structures. The B2 unit represents a very heterogeneous interval comprising interbedded sandstones, shales and coals deposited in a fluvial dominated coastal plain environment. Lateral and vertical distribution of the fluvial sandstones is important to effective sweep and recovery. The Tarbert Formation (B 1) represents a relatively homogeneous sandstone unit with excellent reservoir properties deposited in a marginal marine and tidal-influenced environment indicating the onset of a transgression culminating in the deposition of the overlying marine shales of the Viking Group. A trend towards increasing shale and coal content from north to south is observed in this unit.
349
Source The oil in the Statfjord Field has been generated from the Late Jurassic Draupne Formation shales. These shales are immature at depths of 2400-2500 m over the crest of the field, but are known to commence oil generation and expulsion at approximately 3000 m in the greater Statfjord area. Although sourced from the Draupne Formation, oils in the Brent Group and Statfjord Formation reservoirs show different geochemical characteristics. Source rock-oil correlations and oil migration modelling suggest that the Statfjord Field has been filled by oil migration from both local and more distant oil kitchens by lateral migration and this is the most likely explanation for the observed differences in oil composition. Oil in the Statfjord Formation was most probably generated in the half-graben to the east of the Statfjord and Brent Fields. The oil subsequently migrated northward and then across and up the main boundary fault of the Statfjord Field. In the half-graben directly east of the Brent Field, the Draupne Formation juxtaposes the Statfjord Formation along the southern margin of the Statfjord Field providing a direct migration pathway into the Statfjord Formation. In the half-graben to the west of the Statfjord Field the Draupne Formation is largely immature and unlikely to have generated oil. The oils in the Brent Group of the Statfjord and Brent Fields are believed to have been generated in the Viking Graben and East Shetland Basin further south and migrated northwards by fill-spill from the North Alwyn Field up to the Statfjord Field (Fig. 1). This interpretation is supported by observations that these fields all appear to be filled to spill-point in the Brent Group and by the fact that the oil-water contacts of these fields progressively shallow northwards (Alwyn North Field 3231-3240 m, Brent Field 2758 m, Statfjord Field 2586m. Furthermore, the hydrocarbons become progressively less gaseous in a northwards direction (Struijk & Green 1991). The Draupne Formation is known to have commenced oil generation and expulsion as early as mid-Cretaceous in the deepest parts of the Viking Graben and the East Shetland Basin. Oil was expelled from the half-grabens east of the Brent and Statfjord Fields during the Early Tertiary and reservoirs in both the Statfjord Formation and Brent Group were progressively filled between late Paleocene to Miocene times. Hydrocarbons in all reservoirs on the Statfjord Field are of a similar type having low sulphur content and a gravity around 0.80.85 g/cm 3 (API of 38-39 ~ . They are undersaturated and there is no natural gas cap in the field.
Reserves and production Production from the the Statfjord Field began in 1979 and plateau production rates of approximately 40 x 106 Sm 3 a -1 (250 MMBBL per annum) and an average rate of l l 0 0 0 0 S m 3 d -1 (692000 BOPD) were reached in 1986 (Fig. 11). The field is currently in the middle to late stage of decline with a production rate of 15 x 106 Sm 3 a -1 (94.3 MMBBL per annum) at an average rate Table 3. Cumulative production and injection per reservoir as of 1 Jan. 2000 Reservoir unit
Oil Water Gas Water Gas production production production injection injection (x106Sm 3) (x106Sm 3) (GSm 3) (x106Sm 3) (GSm 3)
Upper Brent Lower Brent Dunlin Statfjord
236.57
104.88
45.32
452.13
1.08
231.67
106.48
44.04
401.92
0.86
2.96 113.09
0.68 15.33
0.51 49.80
4.01 17.67
0 68.49
Field Total 584.29
227.37
139.67
875.73
70.43
350
K. A. GIBBONS E T AL.
50 Actual >
~
North flank I1~ Statfjord
30
C
o
I ~ Dunlin
- - 2O
I
i i m m
i i m
E
Brent
10
0
Fig. 11. Production history by reservoir, Statfjord Field.
120000 Year
Profile
Est. Recoverable Reserves (x 106 S m ~)
I00000
J
m
1982
520
1991
530
1993
585
1997
650
.... --
---
--
i
E
80O00
a) 4.a
t~ ,v"
60000
r..
\',.
i I
O
\ ~.'~ ~k
40000
20000
i
Year Fig. 12. Historical production forecasts, Statfjord Field.
.
.
.
.
.
.
.
STATFJORD FIELD
351
666.4 x 106 Sm 3 (4192 M M B B L ) ofoil will be p r o d u c e d by 2015 with an overall recovery factor of 66%. Estimates of recoverable reserves have varied considerably since the start of production: 1982:520 x 106Sm 3 (3271 M M B B L ) ; 1 9 9 3 : 5 8 5 x 106Sm 3 (3680 M M B B L ) ; 1997: 6 5 0 x 106Sin 3 (4088 M M B B L ) (Fig. 12). This variation reflects increased understanding of the reservoir units through i m p r o v e d reservoir description studies c o m b i n e d with a relatively
of 40 000 Sm 3 d i (252 000 B O P D ) in 1999. As of J a n u a r y 1st 2000 a total of 5 8 4 x 1 0 6 S m 3 (3675 M M B B L ) oil and 1 4 0 G S m 3 (4.93 T C F ) gas has been p r o d u c e d from the field of which 70 G S m 3 (2.49 T C F ) has been re-injected, largely into the Statfjord F o r m a tion. Cumulative p r o d u c t i o n and injection are shown in Table 3. Results from recent field evaluation studies give a total oil-inplace of 1009.2 x 106 Sm 3 (6348 M M B B L ) , of which an estimated
S t a t f j o r d Field d a t a s u m m a r y Brent reservoir
Dunlin reservoir
Statfjord reservoir
Structural/stratigraphic 2360 2586 226
Structural/stratigraphic 2475 2604 129
Structural/stratigraphic 2575 2814 239
Brent Group/sandstone Middle Jurassi~Bathonian Bajocian 200 0.75 (0.47-0.99) 27 (17 30) 2500 (10-4100) -52 approx 2700
Cook formation (Dunlin II)/sandstone Early Jurassic-Toacian 20 0.05 0.45 11-22 150 (5-300) -4 approx 1000
Statfjord formation/sandtstone Early Jurassic/Sinemurian-Rhaetian 185 0.6 (0.4 1.0) 22 (20 29) 470 (100-5000) -10 approx 2500
38.4 low sulphur crude 0.943 0.37 @ 5561 psi 3900 1039 (185)
36.4 low sulphur crude 0.943 0.44 @ 5561 psi 3553 825 (147)
39.6 low sulphur crude 1.0 0.36 @ 5864psi 2900 879.3 (156.6)
1.528 @ 5561 psi
1.428 @ 5561 psi -
1.484 @ 5864psi -
14 000 ppm 0.122 @ 77~
0.122 @ 77~
13600 ppm 0.128 @ 83~
21 000 (85) 5.40 (6.66)
5000 (20) 1.162 (1.433)
11 000 (45) 2.275 (2.806)
5561@ 2469ross 0.29 192 @ 2469ross 4894 5.030 66 water drive/WAG 3249 2.5
5561@ 2469 mss 0.29 201 @ 2469mss 135 0.113 18 water drive 25 0.021
5864 @ 2701 mss 0.29 206 @ 2701 mss 1319 1.158 70 gas/water drive 918 0.14
1979
1994 750 000 (Brent + Statfjord)
1979
Trap
Type Depth to crest (mTVDSS) OWC (mTVDSS)* Oil column (m) at crest Pay zone
Formation Age Gross thickness (In) Net/gross average (range) Porosity average (range)% Permeability average (range)roD Petroleum saturation (range) Productivity index (BOPD/psi) Petroleum
Oil density (~ Oil type Gas gravity Viscosity (cp) Bubble point (psig) Gas/oil-ratio (SCF/BBL (Sm3/Sm3)) Formation volume factor Gas expansion factor (SCF/RCF) Formation water
Salinity (NaC1 eq. ppm) Resistivity (ohm m) Field Character&tics
Area acres (kin2) Gross rock volume mm acre ft (km 3) Initial pressure (psi) Pressure gradient (psi/ft) Temperature (~ Oil initially in place (MMBBL) Gas initiallly in place (TCF) Recovery factor % Drive mechanism Recoverable oil (MMBBL) Recoverable gas for export (tcf) Production
Start-up-date Field production rate plateau oil (BOPD) Production rate plateau gas (mcf/d) Number / type of well per 1.1.2000 Cumulative oil production 1.1.2000 (MMBBL) Cumulative gas production 1.1.2000 (TCF) Cumulative gas injection 1.1.2000 (TCF)
Initially gas from the field was reinjected into the Statfjord Formation due to lack of export pipeline plateau rate for gas export 12.5 mill. Sm3/day 19 OP, 2 WI, 3 GI, 3 WAG, 3WI/GI 65 OP, 18 W1, 6 WAG 3 0 P , 2 WI 2945.1
18.62
711.3
3.15
0.018
1.76
0.068
0
2.42
* OWC's for main field ; deeper contacts are identified in some areas of the field
352
K . A . GIBBONS E T AL.
aggressive yearly drilling and workover schedule. On average ten wells or side-tracks are drilled per year and as of January 1st 2000, 176 production and injection wells have been drilled on the field. Focus on methods for increasing oil recovery has lead to a change in development strategy which is currently under implementation. The development strategy for each of the main reservoirs is discussed below. The reservoir units of the Brent Group have been developed with pressure maintenance using water injection. In general, the first production wells on the main field were completed in structurally high and stratigraphically low positions. The initial drainage strategy was to place emphasis on production from the Lower Brent reservoir units and the Upper Brent, Ness Formation (B2). Two separate lines of injectors were drilled in order to provide pressure support to the reservoir units in the Lower and Upper Brent. As the water cut increased in the Lower Brent producers, oil production was compensated by recompleting wells in the highly productive Tarbert Formation (B1). This strategy is currently under modification to also include down-dip water alternating gas (WAG) injection in order to increase sweep and reduce residual oil saturation. The management plan for the Brent Group is to increase the pressure from 300-330 bars (4350-4785 psi to 340-360 bars (4930-5220 psi) in order to secure enough lift capacity at high water cuts and to get closer to miscibility between the oil and gas in the reservoir. This new strategy is expected to improve oil recovery from the Brent reservoir by 12.5 x 106 Sm 3 (79 MMBBL) from 498 x 106 Sm 3 (3132 MMBBL). An additional 6.0 • 106 Sm 3 (37.7 MMBBL) oil is to be recovered through development of the Statfjord north flank area bringing the expected oil recovery from the Brent Group to 516.5 x 106Sm 3 (3249 MMBBL) or approximately 66.4% of the resources. In the structurally deformed east flank area, the development strategy for the Brent Group has been to produce through wells originally completed in the Statfjord Formation and to drill highlydeviated or near horizontal production wells in order to penetrate several fault blocks and optimize penetration of sandstone units. For the most part, water injection from the main field area provides pressure support to areas of the east flank which are directly adjacent to the crest of the field. However, for fault blocks which are observed to be isolated due to faulting (Fig. 3a), several dedicated water injectors have been drilled in order to optimize production. Development of the Dunlin reservoir started in 1994. The drainage strategy has mainly relied on phasing in existing wells which penetrate the reservoir, although some dedicated wells have been drilled. Production is primarily from wells located in the north-central part of the field. The relatively poor reservoir quality of this reservoir unit, combined with low connectivity, as a result of faulting, gives a low overall recovery factor of approximately 19%. Water injection is also implemented in order to maintain pressure and obtain the best possible recovery. The Statfjord Formation reservoir has markedly different initial reservoir pressures, GOR, bubble-point and oil-water contacts compared with the overlying Brent and Dunlin Group reservoirs. The composition of the oil and reservoir properties of the Statfjord reservoir units are suitable for high-pressure, miscible gas flood as a means of optimizing recovery. Production of gas from both the Brent Group and Statfjord Formation reservoirs has provided sufficient volumes for a complete gas flood. Production wells are located in high stratigraphic positions and as close to the oil-water contact as possible without incurring early water breakthrough or coning. Results from studies and pilots have indicated that oil recovery from the Statfjord reservoir could be improved by the implementation of down-dip W A G in the lowermost part of the Statfjord Formation (Raude Member) combined with supplementary up-dip water injection in the uppermost units of the Statfjord Formation. This revised drainage strategy is gradually being implemented. The initial drainage strategy for the Statfjord Formation has been extremely successful and it is expected that ultimate oil recovery will be around 70%.
The authors wish to acknowledge Statoil and partners for permission to publish these results. Special thanks are extended to Dave Renshaw, John Milne, Inge Kaas, Atle Brendsdal, Peter E. Nielsen and Alan Booth for their contribution to this paper. Recognition is also extended to the long list of colleagues of the Statfjord Production Division and Statfjord Unit Partners who have contributed to the understanding of the field though out the development and production of the field.
References BADLEY, M. E., EGEBERG, T. & NIPEN, O. 1984. Development of rift basins illustrated by the structural evolution of the Oseberg structure, Block 30/6, offshore Norway. Journal of the Geological Society, London, 141, 639-649. BADLEY, M. E., PRICE, J. D., RAMBECH DAHL, C. & ABDESTEIN, T. 1988. The structural evolution of the northern Viking Graben and its bearing upon extensional modes of graben formation. Journal of the Geological Society, London, 145, 455-472. BEACH, A., BIRD, T. & GIBBS, A. 1987. Extensional tectonics and crustal structure: deep seismic reflection data from the northern North Sea Viking Graben. In: COWARD, M. P., DEWEY,J. F. & HANCOCK, P. L. (eds) Continental extensional tectonics. Geological Society, London, Special Publications, 28, 467 476. BROWN, G. 1984. Jurassic. In: GLENNIE, K. W. (ed.) Introduction to the petroleum geology of the North Sea. Blackwell Science Publications, Oxford, 103-131. CHAUVIN, A. L. & VALACHI, n. Z. 1980. Sedimentology of the Brent and Statfjord Formations of the Statfjord Field. In: The Sedimentation of the North Sea Reservoir Rocks. Norwegian Petroleum Society, Article XVI. CHRISTIANSSON, P., FALEIDE, J. I. & BERGE, A. M. 2000. Crustal structure in the North Sea - an integrated geophysical study. In: NDTTVEDT, A. (ed.) Dynamics of the Norwegian Margin. Geological Society, London, Special Publications, (IBS volume). DEEGAN, C. E. & SCULL, B. J. 1977. A proposed standard lithostratigraphic nomenclature Jor the Central and Northern North Sea. Institute of Geological Sciences Report, 77/25. DREYER, T. & WIIG, M. 1995. Reservoir architecture of the Cook Formation on the Gullfaks Field based on sequence stratigraphic concepts. In: STEEL, R. J. et al. (eds) Sequence Stratigraphy on the Northwest European Margin. Elsevier, Amsterdam, 109-142. GABRIELSEN, R. H. 1986. Structural elements in graben systems and their influence on hydrocarbon trap types. In: SPENCER, A. M. et al. (eds) Habitat qf hydrocarbons on the Norwegian continental shelf. Graham and Trotman, London, 55-60. GABRIELSEN, R. H., F/ERSETH, R. B., STEEL, R. J., IDIL, S. & KLOVJAN, O. S. 1990. Architectural styles of basin fill in the northern Viking Graben. In: BLUNDELL, D. J. & GIBBS, A. D. (eds) Tectonic evolution of the North Sea rifts. Clarendon Press, Oxford, 158-179. HAY, J. T. C, 1978 Structural development in the northern North Sea. Journal q/ Petroleum Geology, l, 65-77. HESTHAMMER, J. & FOSSEN, H. 1999. Evolution and geometries of gravitational collapse structures with examples from the Statfjord Field, northern North Sea. Marine and Petroleum Geology, 16, 259-281. HESTHAMMER,J., JOURDAN,C. A., NIELSEN,P. E., EKERN,T. E. & GIBBONS, K. A. 1999. A tectonostratigraphic framework for the Statfjord Field, northern North Sea. Petroleum Geoscience, 5, 241-256 JOHNSON, A, & EYSSAUTIER, M. 1987. Alwyn North Field and its regional geological context. In: BROOKS,J. & GLENNIE, K. W. (eds) Petroleum geology of North West Europe. Graham and Trotman, London, 963-977. JOHANNESSEN, E. P., MJOS, R., RENSHAW, D. & JACOBSEN, T. 1995. Northern Limit of the 'Brent Delta' at the Tampen Spur - a sequence stratigraphic approach for sandstone prediction. In: STEEL, R. J. et al. (eds) Sequence Stratigraphy on the Northwest European Margin. Elsevier, Amsterdam, 213-256. KIRK, R. H. 1980, Statfjord Field - a North Sea giant. In: HALBOUTY,M. T. (ed.) Giant oil and gas fields of the decade 1968-1978. American Association of Petroleum Geologists, Memoir, 30, 95-116. ODINSEN, T., CHRISTIANSSON, P., GABRIELSEN, R. H., FALEIDE, J. I. & BERGE, A. M. 2000a. The geometries and deep structure of the northern North Sea rift system. In: NOTTVEDT, A. et al. (eds) Dynamics of the Norwegian Margin. Geological Society, London, Special Publications. ODINSEN, T., REEMST, P., VAN DER BEEK, P., FALEIDE, J. I. & GABRIELSEN, R. H. 2000b. Permo-Triassic and Jurassic extension in the northern North Sea: results from tectonostratigraphic forward modelling. In:
STATFJORD FIELD NOTTVEDT, A. et al. (eds) Dynamics of the Norwegian Margin. Geological Society, London, Special Publications, 167, 83-103. PARKINSON, D. N. & HINES, F. M. 1995. The Lower Jurassic of the North Viking Graben in the context of Western European Lower Jurassic stratigraphy. In: STEEL, R. J. et al. (eds) Sequence Stratigraphy on the Northwest European Margin. Elsevier, Amsterdam, 97-107. RICHARDS, P. C., LOTT, G. K., JOHNSON, H., KNOX, R. W. O'B. & RIDING, J. B. 1993. Jurassic of the Central and northern North Sea. In: KNOX, R. W. O'B., & CORDEY, W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. ROBERTS, A. M., PRICE, J. D. & OLSEN, T. S. 1990a. Late Jurassic halfgraben control on the siting and structure of hydrocarbon accumulations: UK/Norwegian Central Graben. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's" Oil and Gas Reserves. Geological Society, London, Special Publications, 55,229-257. ROBERTS, A. M., YIELDING, G. & BADLEY, M. E. 1990b. A kinematic model for the orthogonal opening of the Late Jurassic North Sea rift system, Denmark-Mid Norway. In: BLUNDELL,D. J. & GIBBS, A. D. (eds) Tectonic Evolution of the North Sea Rifts. Clarendon Press, Oxford, 180-199. ROBERTS, A. M., YIELDING, G., KUSZNIR, N. J., WALKER,I. U. & DORNLOPEZ, D. 1995. Quantitative analysis of Triassic extension in the northern Viking Graben. Journal of the Geological Society, London, 152, 15 26.
353
ROBERTS, J. D., MATHIESON, A. S. & HAMPSON, J. M. 1987. Statfjord. In: SPENCER, A. M. et al. (eds) Geology of the Norwegian Oil and Gas Fields. Norwegian Petroleum Society. Graham & Trotman, London, 319-340. ROGNO, H., KRISTENSEN, A. & AMUNDSEN, L. 1999. The Statfjord 3-D 4-C OBC survey. The Leading Edge. Society of Exploration Geophysicists, 18(11), 1301-1305. SPENCER, A. M. & PEGRUM, R. M. 1990. Hydrocarbon plays and rifting in the northern North Sea. In: BLUNDELL, D. J. & GIBBS, A. D. (eds) Tectonic Evolution of the North Sea RiJts. Clarendon Press, Oxford, 262-270. STRUlJK, A. P. & GREEN, R. T. 1991. The Brent Field, Block 211/29, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geolocical Society, London, Memoirs, 14, 63-72. THORNE, J. A. & WATTS, A. B. 1989. Quantitative analysis of North Sea subsidence. American Association of Petroleum Geologists, Bulletin, 73, 88-116. VOLLSET, J. & DORE, A. G. 1984. A revised Triassic and Jurassic lithostratigraphic nomenclature for the Norwegian North Sea. Norwegian Petroleum Directorate Bulletin, Stavanger, 3.
The Strathspey Field, Block 3/4a, UK North Sea G. M A X W E L L ,
R. E. S T A N L E Y
& D. C. W H I T E
Texaco North Sea UK Co, Langlands House, Huntly Street, Aberdeen ABIO 1SH, UK
Abstract: The Strathspey Field was the first sub-sea development in the North Sea to be tied back to a third party operator, the Ninian Field now operated by Canadian Natural Resources (CNR). The field was discovered in 1975 by well 3/4-4 and lies wholly within Block 3/4a. The field is a tilted fault block, unconformity trap and consists of two separate reservoirs, a volatile oil and a gas condensate reservoir: the Middle Jurassic, Brent Group and the Lower Jurassic/Upper Triassic, Banks Group respectively. Two 3D seismic surveys cover the field, the most recent being a Vertical Cable Seismic survey recorded in 1996. The Banks Group reservoir is produced under depletion drive by five wells and the Brent Group reservoir by water flooding with 3 water injectors and 6 producing wells. In place volumes arc 290BCF and 90MMSTB for the Banks Group and 120 MMSTR in the Brent Group Reservoir. Ultimate recoveries are estimated to be 230 BSCF, 22 MMBBL and 70 MMSTB, 88 BSCF respectively. Oil export is via the Ninian pipeline system to Sullom Voe, while gas export is through the Far North Liquids and Gas System (FLAGS) pipeline system to St Fergus.]
The Strathspey Field is a sub-sea production facility located approximately 100 miles NE of the Shetland Islands, 300 miles N N E of Aberdeen and is tied back to the Ninian Central platform via a ten mile long pipeline (Fig. 1). The discovery well 3/4-4 is located at 60~ '' North and 1~ East in a water depth of 450' (Fig. 2). The field consists of a volatile oil and a gas condensate reservoir: the Middle Jurassic, Brent Group (Fig. 3) and the Lower Jurassic/Upper Triassic, Banks Group respectively (Fig. 4). These reservoirs are found in a shallow, westerly dipping tilted fault block within a fault controlled unconformity trap. Both have eroded crestal structures with fault scarp degradation products present on their eastern edges (Fig. 5). The field was named after a traditional Scottish country-dance following the Scottish theme of other Texaco operated N o r t h Sea fields.
History Field discover), The Strathspey Field lies wholly within Block 3/4a (Fig. 2). The block was awarded to Texaco North Sea U K as Block 3/4 under Licence P.119 in July 1970 after the Third Licensing Round. Texaco reduced its acreage to Block 3/4a after compulsory relinquishments with the licence expiring in June 2016. Hydrocarbons were discovered in 1973 at the Brent Group level by well, 3/4-1, in the Brent South accumulation, now an extension of the Brent Field development. The accumulations in the Brent and Banks Group reservoirs that comprise the Strathspey Field were found in 1975 by wells 3/4-4 and 3/4-5 respectively. Well 3/4-4 found a partially eroded Brent Group reservoir and an oil-water contact (OWC) significantly lower than that found in the north by well 3/4-1. The Banks Group reservoir was dry at the 3/4-4 location. Well 3/4-5 was drilled to test this zone 1 km further up-dip resulting in the discovery of hydrocarbons and the fluid contact at this level. To the south of the Strathspey Field, the wells 3/4a-6 and 3/4a-8 successfully tested hydrocarbons in separate structures and this resulted in the sale of these reserves to the Alwyn Field Group in 1982. From 1985 to 1991 Texaco North Sea U K gradually divested interest in the reserves discovered by well 3/4-1 in the northern part of the block to Shell U K Ltd and Esso Exploration and Production U K Ltd allowing the development of the Brent South accumulation. Current partners in the Strathspey Field Group are: Texaco North Sea U.K. Ltd., 67%; Shell U.K. Ltd., 13.25%; Esso Exploration and Production U K Ltd., 13.25%; Canadian Natural Resources 6.5%.
Field appraisal Appraisal of the Strathspey Field was achieved by the drilling of a further seven wells and the acquisition of 3D seismic data in 1985. Also in 1985, the first two appraisal wells, 3/4a-9 and 3/4a-10 tested the structural blocks immediately north of those penetrated by the discovery wells at Brent and Banks Group levels respectively. Well 3/4a-10 was extensively tested in the Banks Group reservoir to further determine the nature of the hydrocarbons at different structural levels. This proved the presence of both gas and volatile oil in the column, no discrete gas-oil contact and large compositional gradients, especially in the lower part of the reservoir. Well 3/4a-12 was drilled in 1986 confirming oil in the southernmost fault block of the Brent Group reservoir and a single field OWC in the main Strathspey accumulation. In 1987 the drilling was concentrated in the northern part of the block initially in the graben between wells 3/4-1 and 3/4a-9. The well 3/4a-13z (Fig. 2) proved oil at the Brent reservoir level in a separate structure but no clear OWC could be determined. Water in this well was found higher than in the main Strathspey accumulation to the south and lower than the OWC found the 3/4-1 well (Brent South) to the north suggesting a separate accumulation in this area. The final Brent Group appraisal well was 3/4a-14, which had the main objective to carry out injectivity and pulse testing to assess reservoir performance under water flood conditions. The final appraisal well for the Banks Group was 3/4a-16 and this confirmed both the field mapping and the southern extension of the accumulation.
Field development Development was undertaken using a sub-sea production facility tied back to the Ninian Central platform where the produced gas, oil and water are processed and production operations controlled. Oil export is via the Ninian pipeline system to Sullom Voe while gas export is through the F L A G S pipeline system to St Fergus. Water injection is supplied from the Ninian South platform. Currently the Brent Group reservoir is produced by 6 wells and supported by 3 injectors. Five wells were drilled from the manifold, four of which were highly deviated and one was horizontal. Two appraisal wells, 3/4a-9 and 3/4a-14 were subsequently tied back to the sub-sea manifold and re-used as development wells. The Banks Group reservoir is produced under natural depletion and has five production wells of which, two are horizontal. Annex B submission took place in July 1991 and was approved in October 1991. The sub-sea manifold was deployed in July 1993 near the 3/4-4, discovery well. First oil production was achieved in December 1993 with first gas production in May 1994. Peak
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Vohtme. Geological Society, London, Memoir, 20, 355 368.
355
356
G. MAXWELL E T AL.
Fig. 1. Location of the Strathspey Field. production rates reached 53000b/d of liquid in 1996 and 143 MSCF/d of gas in 1998. The expected field life at the time of development was ten years. Total field ultimate recoveries are estimated to be 92 MMSTB liquids, 320 BSCF of gas.
Discovery method Structure
The Strathspey Field has had two full 3D seismic surveys shot across it. The original survey was aquired in 1985 for the develop-
ment planning and in 1995/1996 a Vertical Cable Seismic Survey (VCS) was recorded. The VCS survey was planned to better image the crest of the field where low-angle rotational slides cut both Brent and Banks Group reservoirs forming footwall degradation complexes (Leach 1999). The VSC survey clearly demonstrates better imaging of the crest of the structure, of reflectors within the Brent Group and basal reflectors of the Raude Formation vastly improving interpretation (Fig. 6). The field itself is situated on part of the N-S trending, major tilted fault block structure that runs from the North Alwyn Field in the south to the Statfjord Field in the north (Fig. 1). The fault block is approximately 15 km wide at Strathspey and bounded by normal
STRATHSPEY FIELD
357
Fig. 2. Strathspey Field map.
faults that down throw to the east with magnitudes of up to 4000 ft. Average bed dip is 10 to the west, toward the next major block fault, the Ninian-Hutton Fault. The major boundary fault trends N-S, as in the Brent Field (Struijk & Green 1991), in the northern part of the field. However, to the south the fault orientation changes to NE-SW, creating part of the dip closure for both reservoirs (Figs 2 and 3). Within the field E-W and NNW-SSE orientated faults cut both reservoirs offsetting reservoir intervals by a maximum of 400 ft. These faults die out to the west of the main field areas. On the crest of the structure, at the Brent Group reservoir level, they can display a decrease in offset between the top and base reservoir. The block
rotation responsible for the structural configuration of the Strathspey Field was largely created during the Upper Jurassic extension of the North Viking Graben as described by Badley et al. (1988). On the eastern crest of the structure at each reservoir level are eroded remnants of footwall degradation complexes similar to those described by Underhill et al. 1997. These were created during uplift and block fault rotation caused by the Upper Jurassic rifting and were subsequently eroded prior to depositional onlap in the late Upper Jurassic. The continued uplift and rotation of the footwall structure caused slope instability and gravitational collapse (Courts et al. 1996). In the Strathspey Field this has manifested itself
358
G. MAXWELL E T AL.
Fig. 4. Top Banks Group reservoir structure map.
Fig. 3. Top Brent Group reservoir structure map.
in different forms at Brent and Banks Group reservoir levels. The Brent Group reservoir (Figs 3 and 5) is characterized by thin, eroded, low angle fault terraces at the western edge of the degradation complex. East of these, listric slide geometry can be illustrated more clearly where there is greater preservation of the hanging wall section and greater throw can be demonstrated across the gravitational slides (Fig. 5). On the eastern edge allochthonous blocks of Ness Formation have been penetrated overlying truncated Dunlin Group. In contrast at the Banks Group reservoir level the degrada-
Fig. 5. Geo-seismic cross-section.
tion complex is separated from the undeformed main field by a major rotational fault which displays up to 500' of displacement (Fig. 4). The hanging wall section consists of allochthonous Brent Group overlying Dunlin Group mudstones and reservoir sandstones of the Banks Group. Internal structure or stratigraphy within the Banks Group deformation complex is difficult to image but chemostratigraphic data from well 3/4a-M12 suggests Nansen and either E2 or E4 sandstones were present. This loss of section suggests the well may have penetrated the Heron Group on up-thrown side of the D D N D fault (Fig. 4). The increased throw at the Banks Group level may be related to increased relief on the footwall block at the time of Banks Group deformation (Hesthammer et al. 1999).
STRATHSPEY FIELD
359
Fig. 6. Comparison between Vertical Cable Seismic (VCS) and previous 3D seismic survey.
Stratigraphy Heron Group This unit has been penetrated by wells targeting the crestal area of Banks Group reservoir. It is a low net to gross unit that consists
of predominantly red and brown mudstones and minor thin sandstones. The transition from Heron to Banks Group has been interpreted as the change from red, high maturity, aridisols of the upper Cormorant Formation of the upper Heron Group (Knox & Cordey 1993) to the varicoloured, variable maturity, vertisols of the Banks Group. This boundary forms a consistent seismic marker
G. MAXWELL ET AL.
360
$/g~=@ PERIOD
~
GP.
DEPTH
LITH.
j TVDSS t (Feet)
GAMMA RAY 0
t-Z
_
j
_____
.
.
.
.
Heather Fm.
.~
1000
_
.
DEPTH ~DSS
(Feet)
]-_-_-_-_-:~ . . . . . .
200
~,,E (B7)
_
.
......
I-
B6c
UJ rr I-Z
III O III re
,
LM t-"~
...... ...... ......
z
Lu
V---
w O uJ rr
z w O O
Z uJ rr uJ
'
, III
~i U
LL II
>-
z
o
~ D
nr"
LU
_~
O
w
re UJ
-J
uJ O
IX.
w
- 2000
B6a \
~
B5d
~
BSc
,
-9600
~" tn
. . . . . .
3000
=a la.
B5a B4d B4c "-" B4b/ B4a/
t~
~
_-~
o ~ g ~,
Z
mo z
,-.
, -~-~
-4000
v
m
B3a A
v
v
v
5000
~"~E (B2)
E
~'~ I ----IBlb OE'T-8==,,133
~'g:l "-'l B l a
a_.,o+
Dunlin Gp 6000
=)
~/~=@
7000
o ,,,
<
I-UJ rr
=o
Z< w< o~
ez ~ 5
GAMMA RAY o
t-W
8000
Dunlin Gp. Nansen Fm.
-r rn
O
200
LOWER
APTIAN TO ALBIAN
CROMER KNOLL
UPPER
CALL. TO RYAZ.
HUMBER----~. ~ .
.
.
.
.
- 9000
.
z-_--... <,
m
z z
_z
~
_
J
~_~
4~
< re
rr W ~:
~ ~ ,~
z ~ o co
~
0 j
~ _ = ~R~
~,, Z' ......
O
~: CE
_ IT
w
a_ 13_
z
_
~ <
. . . . .
. . . . . .
.
.
.
11,oo0
.
1:13 - _ - _ - _ - _ - _ Z
O rr w
12,000 .
.
.
.
.
.
. . . . . .
Fig. 7. Strathspey Field stratigraphy.
across the field and is suspected to have been caused by a climate change from arid conditions during upper Heron Group deposition to wetter conditions during Banks Group deposition. The boundary is poorly age dated due to the lack of microfossil preservation but is suspected to be near the top of the Triassic (Rhaetian) from offset correlation (Knox & Cordey 1993).
Banks Group Overlying the Cormorant Formation are the Hettangian to Sinemurian sediments of the Banks Group which are found up to 800' thick and form the lower of the two reservoir sections in the Strathspey Field. This unit has been sub-divided into the Nansen
S T R A T H S P E Y FIELD
361
o
o
9 r~
362
G. MAXWELL ET AL.
and Statfjord Formations (Knox & Cordey 1993). The Statfjord Formation is approximately 700 ft thick and increases in net to gross rapidly from the underlying Cormorant Formation. It consists of medium to coarse grained, braided fluvial channel sandstones interbedded with mudstone prone overbank sediments and palaeosol horizons. At the top of the section, coals and organic rich mudstones become more common overbank deposits. The Nansen Formation is up to 100 ft thick and sharply overlies the Statfjord Formation forming a clean, tabular sandstone which was deposited under shallow marine conditions.
Rogaland Group-Nordland Group This section consists of up to 6500 ft ofmudstones and sandstones of the Moray Group. Of interest are the Paleocene/Eocene Dornoch and Eocene Balder Formations that contain a sub-economic heavy oil accumulation within them, southwest of the main Strathspey Field and centred on well 3/4a-12 (Fig. 2). They were deposited within a wave dominated, deltaic depositional environment.2
Trap Dunlin Group The Dunlin Group is a mudstone and siltstone unit that separates the Brent and Banks Group reservoirs. It is has a uniform thickness of 850ft in the Brent-Strathspey-Alwyn area (Struijk & Green 1991) and was deposited under marine shelf conditions. It ranges in age from Sinemurian to Toarcian and can be split into four formations: Drake, Cook, Burton and the Amundsen, which is the oldest and Sinemurian in age.
Brent Group The Brent Group forms the youngest reservoir interval in the Strathspey Field. It is approximately 800 ft thick and can be subdivided into five Formations: Broom, Rannoch, Etive, Ness and Tarbert. They date from the eldest, the Broom, in the Aalenian to the Bathonian. The basal Broom Formation is thin (15ft) in the Strathspey Field and is coarse grained, shallow marine sandstone sharply overlying the Dunlin Group mudstones. The Rannoch and Etive Formations consist of up to 200ft of very fine to coarse grained sandstones which were deposited in shallow marine shoreface and marginal marine barrier environments. The Ness Formation is a lower net to gross unit of up to 500 ft thick. It consists of fine to coarse grained sandstones, mudstones and coals deposited in lower and upper delta plain environments with variable salinity shoreface and fluvial channel facies forming the major reservoir sandstones. The Tarbert Formation has a maximum thickness of 100 ft and is a fine to coarse grained sandstone unit that sharply overlies the mixed lithology Ness Formation. It was deposited under shallow marine conditions prior to the deeper marine conditions of the mudstone Humber Group.
Humber Group The Brent Group is capped by the Callovian to Ryazanian Humber Group and can be divided into the Heather and Kimmeridge Clay Formations. These are separated from the Brent Group and from each other by unconformities related to the extension of the North Viking Graben and block fault rotation of the Strathspey structure in the late Middle and Upper Jurassic. The thickness of this unit varies over the field; on the erosive crest it can be less than 20 ft thick but increases to 300 ft in the western injector wells towards the hanging wall of the Ninian-Hutton Fault. The Heather and Kimmeridge Clay Formations are both deep marine mudstones with the Kimmeridge Clay Formation displaying a higher organic carbon content.
Cromer Knoll and Shetland Group The Cretaceous sediments form the thick cap rock for the Strathspey Field. They are split into the Cromer Knoll and Shetland Groups. The Lower Cretaceous, Cromer Knoll Group directly overlies the Humber Group and consists of red claystones, white crystalline limestones and marls. Above this lies the Upper Cretaceous Shetland Group that consists of several thousand feet of marls and mudstones.
The trap for the Strathspey Field was created during the late Middle Jurassic and Upper Jurassic extension when block rotation of the Strathspey structure occurred and was subsequently onlapped by non-reservoir, Cretaceous mudstones and marls. The Brent Group accumulations are constrained purely by dip closure to the north, south and west. To the east the onlap of the thick Cretaceous deposits provide lateral and top seal. The trapping mechanism for the Banks Group reservoir is constrained by dip closure to the south and west of the field. To the east, lateral and partial top seal is again provided by the thick Cretaceous marl and mudstone sections. The main field hydrocarbon contact is controlled by the juxtaposition of the Dunlin Group mudstones against Banks Group sandstones in the north of the field at fault D D N H (Fig. 4) creating a spill point at the transposition of Banks Group sediments. The Dunlin Group mudstones provide top seal for the main reservoir. Within the reservoir, the main field shows pressure separation from the footwall degradation blocks penetrated by well 3/4a-M12 suggesting that this fault is sealing (Fig. 5). Within the Heron Group just below the base of the Banks Group reservoir thin hydrocarbon bearing sandstones have been encountered which are thought to be laterally discontinuous, fluvial channel sandstones forming small stratigraphic traps within this low net to gross unit (Fig. 5).
Banks Group Reservoir Correlation and sedimentology The Banks Group reservoir is subdivided into seven layers in the Strathspey Field; six within the fluvial Statfjord Formation and one for the Nansen Formation (Fig. 8). The correlation has been derived from sedimentological data, sand body correlation using isotopic Samarium/Neodymium provenance studies (Paterson 1997) and palaeosol geochemistry (A1 Anboori 1997). The base of the reservoir is represented by a clear seismic marker and can be correlated using both the isotopic correlation technique and the change in palaeosol type that occurs across it (Fig. 8). The E1 zone is the least important reservoir zone with single and multi-storey fluvial channel sandstones present with both pedified and non-pedified overbank sediments and crevasse splay sandstones. This represents the first major influx of coarse clastic material after the upper Cormorant Formation and shows a distinct isotopic signature (Fig. 8). The E2 zone is the first major multi-storey, multi-lateral channel system within the reservoir. It is characterized by thick (80 ft maximum thickness), composite sand bodies which contain pebble to coarse grained, cross stratified sandstones deposited within an upper alluvial plain, braided fluvial depositional environment with channel axes trending N W - S E (Mulcahy 1998). Their composition shows a high degree of extra basinal material present and can also be typed clearly using the isotopic data (Fig. 8) where separate units have distinct isotopic provenances. Interbedded within these sandstones are discontinuous, non-pedified, black mudstone lacustrine deposits. The unit base is formed by a mature vertisol of variable thickness. The top of the unit displays a weak seismic marker across the field that corresponds to a well-developed palaeosol. This is a candidate vertical permeability boundary within the field, created by a sharp reduction in coarse clastic supply to the area at this time and widespread floodplain aggradation.
STRATHSPEY FIELD
363
Fig. 9. An example of Banks Group reservoir quality.
The E3a unit also shows this reduction in sand supply and forms a low net to gross alluvial unit prior to the re-initiation of major fluvial sandstone deposition within the E3 and E4 units. Both these units display similar sedimentological characteristics to the E2 unit although the overall net to gross is lower but can be differentiated by the sandstone isotopic provenance and are separated by a geochemically distinct palaeosol marker (A1 Anboori 1997). The E5 unit has similar provenance to the E4 unit below it, but is marked by a distinct change in depositional environment. The final
evidence for upper alluvial plain deposition occurs at the base of the E5 unit with the formation of a well-developed vertisol which was caused by successive wetting and drying cycles. Above this, overbank settings are dominated by coals and heavily rootleted, black mudstones suggesting a rise and stabilisation in water table during E5 deposition. Sandstones can be characterised as relatively thin (>20ft thick) fluvial channels that have an increase in associated crevasse channel and splay sandstones and a meandering fluvial channel morphology, different from the lower units. This is
364
G. MAXWEEL E T AL.
d~ 9
9
3 . ,...~ 9
STRATHSPEY FIELD backed up by the scant dipmeter interpretation that shows variable palaeocurrent direction, typical of a meandering system. These changes suggest that E5 deposition occurred on the upper delta plain. Sharply overlying the E5 unit is the high net to gross, tabular Nansen Formation that can be up to 100 ft thick. It contains both fining and coarsening upward grainsize trends of well to moderate sorted, medium and coarse grained, cross-stratified sandstones which display a young isotopic provenance age similar to those described by Dalland et al. (1995). These have been interpreted as shallow marine in origin and their generation is related to the overall transgression of the area that began within the E5 unit and ends with the marine mudstone deposition of the Dunlin Group.
Reservoir quality The reservoir quality of the Banks Group is largely controlled by the depositional facies, particularly grain size and mineralogy (Fig. 9) with the quantity of detrital clay and feldspar affecting the degree of authigenic degradation and compactional loss of reservoir sandstone porosity. The Statfjord Formation sandstones are moderate to poorly sorted and sub-arkosic to arkosic arenite in composition. The E5 and E2 channel sandstones display the best reservoir quality material (Fig. 9). The Nansen Formation is the major reservoir unit and contains the best quality reservoir sandstones overall. They are cleaner in composition (sub-arkosic to arenitic) and commonly better sorted. Well 3/4a-M 12 was completed in the Nansen Formation in the degradation terrace and encountered a decreased reservoir quality in this area of the field possibly related to the increased deformation in this well caused by footwall degradation (Fig. 9). Overall the major diagenetic processes affecting reservoir quality were early, siderite and quartz overgrowth precipitation and the alteration of detrital feldspar, mica and clay to kaolinite and illite. Fibrous illite primarily occurs within the water leg only.
Brent Group Reservoir Correlation and sedimentology The Brent Group is subdivided into 18 separate reservoir units for the purposes of reservoir modelling, volumetric analysis and simulation studies. The zonation was derived from biostratigraphic, sedimentological (Bray et al. 1995) and dynamic pressure data further sub-dividing the coarser scale lithostratigraphy (Fig. 10). The base of the Brent Group is a major regressive surface characterized by a coarse grained gravel lag separating the offshore marine mudstones of the Dunlin Group from the shallow marine sandstones of the Broom Formation. The B1 and B2 units record initial progradation of this sand rich, shallow and marginal marine environment with the deposition o f bioturbated and hummocky cross-stratified, fine grained sandstones of the lower and middle shoreface at the unit base. This coarsens upward into medium and coarse grained sandstones of the upper shoreface and barrier/tidal inlet complex at the top of the B2 unit. These units are overlain by the low net to gross B3 unit of the Ness Formation, containing minor fluvial channel, mouth bar and crevasse sandstones with thin coals, and pedified flood plain mudstones of the upper coastal plain. The B4 unit is the second tabular sandstone in the Brent Group reservoir and consists of distributary channel, tidal inlet and shoreface sandstones related to the minor transgression of the Brent delta that can be correlated with the Mid Ness Shale of the Brent Field (Struijk & Green 1991). The B5 unit records the return to alluvial plain deposition that is initially similar to the B3 unit below. The unit is progradational and at the unit top there is a more frequent occurrence of thick (up to 25ft), amalgamated fluvial distributary channel sandstones sandstones. This unit may have some tectonic influences on deposition and positioning of distributary channels with crestal wells showing decreases in thickness and net to gross (e.g. well 3/4aM6 compared with 3/4a-9, Fig. 10). The B6 unit is the final unit of the Ness Formation and records the initiation of the final transgression of the Brent delta with the deposition of bioturbated
365
and wave dominated, stacked variable salinity shoreface sandstones and mouth bars interbedded with black lagoonal mudstones. The sharp transition from Ness Formation to the Tarbert Formation (B7) is recorded with a coarse grained gravel lag overlain by bioturbated and cross stratified medium grained sandstones. These were deposited under shallow marine conditions with possible tidal influence. This is manifested with rhythmic bimodal grainsize distributions between cross set laminae and rare mudstone drapes. These sandstones form the major reservoir unit in the field. Reservoir quality The Brent Group sandstones have a similar diagenetic scheme to the Banks Group described earlier and the major controls on reservoir quality are primarily related to depositional environment (Fig. 11). The tabular sandstone reservoir units show a varied but generally upward increasing quality with lower and middle shoreface micaceous and bioturbated sandstones of the B1 unit having the worst reservoir quality (less than 100rod permeability). The coarser grained, shallow and marginal marine sandstones of the B2 and B7 units are more consistent and better in quality as a result of their higher energy depositional processes. The B4 unit has the greatest variation in reservoir quality related to the mixture of high quality, clean tidal inlet and distributary channel sandstones and poorer quality sandstones associated with crevasse channel deposition. The heterogeneous B3, B5 and B6 units also show a large variation in reservoir quality (Fig. 11). The best quality material in these layers is related to the thick, fluvial distributary channels primarily of the B5 unit (up to 9000.roD) but may also be found in lesser amounts in the B3 and B6 units. The diagenetic history for these facies is subtly different from the Banks Group, enhanced by early quartz overgrowth cementation (retarding compaction) and a later phase of feldspar dissolution preserving and increasing already high porosities, particularly of the fluvial channel facies. In contrast to these are less productive, low energy shoreface sandstones of the B6 unit and the thin channel sandstones of the B3 unit that demonstrates mostly poor reservoir quality.
Source The source rocks responsible for creating the Strathspey Field hydrocarbons are from the Upper Jurassic, Humber Group. The Banks Group reservoir fluid is thought to consist of a mixture of fluids from thin, oil prone Kimmeridge Clay Formation and thicker, gas prone Dunlin Group from the Oseberg kitchen to the south east of the field (Thomas et al. 1985). The migration route is predominantly from over-spill routes from the North Alwyn Field to the south with possible contribution from the graben to the east of the field. Recent oil geochemistry studies of the Banks Group hydrocarbon suggest a two phase emplacement with an initial oil fill which was subsequently gas washed to form the complex fluid found today (Thomas 1998). The Brent Group reservoir may also have been filled partially by a similar mechanism to the Banks Group but also with contribution from oil prone source rocks (Kimmeridge Clay Formation) in the Ninian kitchen to the west of the field (Thomas et al. 1985).
Reserves and production B a n k s Group Reservoir At the time of Annex B submission the Banks Group in place volumes were initially estimated at 460.2 BCF and 89.2 MMSTB with 268 BCF and 27.5 MMSTB reserves. The in place volumes have subsequently been reduced to 290 BSCF and 90 MMSTB with ultimate recoverable reserves of 230 BSCF and 22 MMSTB overall reduction in reserves was due to the overestimation of reserves in the footwall degradation complex, a result of poor seismic control in this area of the field prior to the acquisition of the VCS survey.
366
G. MAXWELL
E T AL.
Fig. 11. An example of Brent Group reservoir quality. However, the increase to liquid in place volumes was due to an improvement in the PVT characterization reducing the impact of the structural changes to liquid reserves. The reservoir is produced under depletion drive with minor aquifer support by five wells: two
crestal condensate producers, 3/4a-M 1 and 3/4a-M2Z and two horizontal producers located towards the base of the hydrocarbon column, 3/4a-M4 and 3/4a-M8 to maximise liquid recovery. The most recent well 3/4a-M 12 produces from the degradation complex.
STRATHSPEY FIELD
367
S t r a t h s p e y Field P r o d u c t i o n N o v e m b e r 1993 - July 1999 60,000
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
_
_
.......
Brent Banks
Group Reservoir P r o d u c t i o n Group Reservoir P r o d u c t i o n
I.M9z St]rt-up
50,000
I|
,~J[i, MIO Startup irr
,0000
20,000
J
I~.
o
""i h3
~
O
r,D
r
,:.O
_
'
hO
i O
""
""
~
hO
""
""
~
c..O
Fig. 12. Strathspey Field production.
The production rates required from the Banks Group wells are driven by gas nominations (Fig. 12). For the first few years of field life well deliverability exceeded demand and the horizontal wells were produced in preference for their higher associated condensate yield. Currently the wells produce to their maximum capability on high nomination days and on low nomination days when there is an excess deliverability wells are prioritised depending on operational constraints. The 3/4a-M8 well, closest to the water contact, has watered out in the Banks Group and has recently been routed through the Brent Group test separator (a lower pressure system) and flowed successfully. It is planned to do this with other wells when they stop flowing to the higher pressured Banks Group system.
Brent Group Reservoir The Annex B identified in place volumes of 101 MMSTB in the Brent Group reservoir with current ultimate recoverable reserves of 70 MMSTB oil and 88 BSCF of solution gas. The reservoir has been produced from seven wells and supported by three water injectors. Peak rates from separate wells averaged around 10 000 BOPD with the highest average daily rate recorded from 3/4a-M10 at over 17 913 BOPD. The highest average daily rate from the reservoir was over 39 000 BOPD (Fig. 12). Three of these wells have since watered out: 3/4a-M3, 3/4a-9 and 3/4a-14. Two of these were Tarbert Formation producers close to the OWC and the third a crestal Ness Formation producer suffered from early water break through. The reservoir abandonment pressure in the Brent is estimated at 4200 psi and field management has required a strong water injection programme from project start-up. This has consisted of an injector well within each of the two structural blocks supporting all of the major reservoir zones. This currently gives an injection to production voidage ratio of about 1.009, mitigating the decline in pressure caused by production.
The authors would like to thank the field partners, Shell UK, Esso Exploration and Production UK, and Kerr McGee North Sea Ltd for permission to publish this paper and Rebecca Chambers for draughting the figures.
References AL ANBOORI, S., A. 1997. High resolution correlation in the Statf/ord Formation, Strathspey Field. MSc Thesis, University of Aberdeen. BADLEY, M. E., PRICE, J. D., RAMBECHDAHL, C. & AGDESTEIN,T. 1988. The structural evolution of the northern Viking Graben and its bearing upon extensional modes of basin formation. Journal of the Geological Society', London, 145, 455 472. BRAY,T., BUTLER,N. & HIGGS,K. 1995. An Integrated Sedimentological and Biostratigraphic Study of the Brent Group to Assist Reservoir Simulation and Field Development. Simon Petroleum Technologies Report 7485/Id. COUTTS, S. D., LARSSON, S. Y. & ROSMAN, R. 1996. Development of the slumped crestal area of the Brent Reservoir, Brent Field: an integrated approach. Petroleum Geoscience, 2, 219-229. DALLAND, A., MEARNS, E. W. & MCBRIDE, J. J. 1995. The application of samarium-neodymium (Sn-Nd) Provenance Ages to correlation of biostratigraphically barren strata: a case study of the Statfjord Formation in the Gullfaks Oilfield, Norwegian North Sea. In: DUNAY,R. E. & HAILWOOD,E. A. (eds) Non-biostratigraphical Methods of Dating and Correlation. Geological Society, London, Special Publications, 89, 201-222. HESTHAMMER, J., JOURDAN, C. A., NIELSEN, P. E., EKERN, T. E. & GIBBONS, K. A. 1999. A tectonstratigraphic framework for the Statfjord Field, northern North Sea. Petroleum Geoscience, 5, 241-256. KNOX, W. W. O'B. & CORDEY, W. G. 1993. Triassic, Permian and prePermian lithostratigraphy of the Central and Northern North Sea. In: KNOX, R. W. & HOLLOWAY,S. Lithostratigraphic nomenclature of the U.K. North Sea. British Geological Survey, Nottingham. LEACH, P. E. 1999. Strathspey vertical cable seismic survey: a North Sea first. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings" of the 5th Conference. The Geological Society, London, 1125 1242.
G. M A X W E L L E T AL.
368
MULCAHY, M. 1998. OBDT psuedo-imaging processing, structural and sedimentological interpretations, 3~4a-M2. Internal Report ABJ
76220. PATERSON, B., A. 1997. Neodymium isotope stratigraphy of the Statfjord Formation, Wells 3/4a-10, 3~4a-M1, 3/4a-16, Strathspey Field. Internal Report J967/01. STRUIJK, A. P. & GREEN, R. T. 1991 The Brent Field, Block 211/29, UK. North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commerative Volume. Geological Society, London, Memoirs, 14, 63-72.
THOMAS, A. 1998. A comparative study of Banks Group hydrocarbon geochemistry. Texaco Internal Report, Upstream Technology, Houston. THOMAS, B. M., MOLLER-PEDERSON, P., WHITAKER, M. F. & SHAW, N. D. 1985. Organic facies and hydrocarbon distributuions in the Norwegian North Sea. In: THOMAS, B. M. et al. (eds) Petroleum Geochemistry in Exploration of the Norwegian Shelf. Graham and Trotman, London, 3-26. UNDERHILL, J. R., SAWYER, M. J., HODGSON, P., SHALLCROSS, M. D. & GAWTHORPE, R. L. 1997. Implications of fault scarp degradation Jot Brent Group prospectivity, Ninian Field, Northern North Sea. American Association of Petroleum Geologists, Bulletin, 81, 999-1022.
Strathspey Field data summary Brent Group Reservoir
Banks Group Reservoir
Trap Depth to crest Lowest closing contour OWC Gas column Oil column
Pay zone Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor Formation water Salinity Resistivity Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil/condensate initially in place Gas initially in place Recovery factor oil (condensate) Recovery factor (gas) Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate Production Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
Type -8900 -9380 -9380' 480'
ft ft ft ft ft
Unconformity: tilted fault block - 9 700' - 1 0 267' - 10 267' -567'
Brent Goup Middle Jurassic 800' 0.46 20.3 (12.8-30.4) 1045 (10-9750) 0.86 (0.93-0.62)
ft ft % mD %
Banks Group Lower Jurassic/Triassic 750' 0.44 14.7 (10.4-25.5) 356 (15 8425) 0.82 (0.93-0.71)
38.9 ~ API Low sulphur light crude
~' API -
40-49 ~ API
0.1840 4223
cp psig psig BBL/MMSCF SCF/RCF
6236 PSIa 1800-7900 SCF/STB 127-556 2.2 RB/MMSCF 0.613
260 000 0.313 (,; 60~
NaC1 eq. ppm ohm m
240 000 0.3 (a; 60~
2581 232 427 5865 @ 9250' TVDss 0.2685 212~=F @ -9250' 101
acres acre ft psi psi/ft ~ mmbbl BCF
1730 243018 6405 PSIa @ 10182' TVDss 0.178 (gas) & 0.237 (oil) 220~ @ - 1 0 182' 95 281 0.21 0.68 natural depletion
1604 SCF/STB 1.879
0.61 solution gas water flood 57.7 61.1
Nov 93 39 340 55 7 producers, 2 water injectors
% MMBBL BCF MMBBL
BOPD MCF/D
190 20
May 94 14 000 127 5 producers
The T-Block Fields, Block 16]17, UK North Sea M. G A M B A R O & V. D O N A G E M M A Agip (UK) Ltd, Wellington Circle, Aberdeen A B 1 Z 3JG
Abstract: The Tiffany, Toni, Thelma and SE Thelma fields, collectively referred to as the T-Block fields lie wholly within UK Block 16/17 at the southern end of the South Viking Graben. The four fields were discovered between 1976 and 1980 and despite the fact that they share a common reservoir, the Upper Jurassic Brae Formation, they are quite distinct in terms of their petroleum content (type), reservoir quality and production performance. This paper summarizes the characteristics of the T-Block petroleum accumulations and highlights the differences between each of the fields.
Block 16/17 (T-Block) is located at the southern end of the South Viking Graben, about 160 miles N E of Aberdeen (Fig. 1). The block forms part of Licence P225 operated by Agip (UK) Ltd. for which the current equity holders are Agip, Fina, M u r p h y and Burlington (Table 1). Licence P225 was awarded to a Phillips operated group in the Fourth Round of Licensing in 1972. Agip (UK) Ltd. became Licence Operator in 1986 after the acquisition of the greater part of Phillips's interests. Between 1976 and 1992, 20 exploration wells were drilled and the oil fields of Tiffany, Toni, Thelma and SE Thelma were discovered (fi'om which the name T-Block is derived). Field development plans were sanctioned by the Department of Trade and Industry for Tiffany in 1989, for Toni in 1990 and for Thelma and SE Thelma in 1995. Production from the Tiffany Field commenced in November 1993 followed by Toni and Thelma-SE Thelma in December 1993 and October 1996, respectively. All the T-Fields produce oil from sandstones and conglomerates belonging to the Upper Jurassic Brae Formation. Despite having a common reservoir, each field presents different characteristics and development challenges.
History Exploration and appraisal The exploration of the block began in 1976, when the Thelma discovery well 16/17-1 was drilled (Fig. 2). It tested the Brae Formation, which flowed at maximum rates of 5732 BOPD and 12 MSCFPD. The well also penetrated an oil-water contact at - 1 2 0 9 6 f t true vertical depth sub-sea (TVDss). The Toni Field was discovered in 1977 by well 16/17-4. The well encountered 700 ft of gross pay in the Brae Formation and was tested at a maximum rate of 9594 BOPD. With the subsequent appraisal drilling of well 16/17-6 in 1978 and well 16/17-16 in 1988, similar reservoir sections were found and a common O W C at - 1 2 932ft TVDss was confirmed. The northwestern and southern limits of the field had been delineated already by wells 16/17-2a and 16/17-5 respectively. The discovery of the Tiffany Field followed in 1979 when well 16/17-8a drilled around 1300ft of the Brae Formation and was tested at a maximum rate of 8314 BOPD. The well established an
Fig. 1. Regional location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 369 382.
369
370
M. GAMBARO & V. DONAGEMMA
Table 1. Equity holders in T-Block (16/17) Operator
%
Joint Venture Participants
%
Agip (UK) Ltd.
47.48
Fina Exploration Ltd. Murphy Petroleum Ltd. Burlington Resources
30.00 11.26 11.26
O W C at 13 920ft TVDss and three further successful appraisal wells, 16/17-11, 13 and 15 subsequently confirmed this contact. Two delineation wells, 16/17-9 and 16/17-14, established reservoir limits to the SE while well 16/17-17 located the position of the basement Terrace/Graben edge to the west. In 1980, the SE Thelma accumulation was discovered by the down-dip appraisal well 16/17-10 that identified a deeper OWC (12 743 ft TVDss) than that encountered in the Thelma discovery well. Maximum flow rates from the side-tracked hole (16/17-10ST) yielded 7370 BOPD with 11.6 M S C F P D of associated gas.
Development drilling Tiffany. The Tiffany Field commenced production from four predrilled vertical wells (16/17-A 1, A2, A3 and A4). A further producer was drilled in 1995 (16/17-A5) but encountered a poor reservoir section and was side-tracked (16/17-A5Z). Injection wells 16/17-A6 and A7 were also drilled during 1995. Well 16/17-A8 was drilled as an injector but was initially completed as a producer and then converted to injection in June 1997. Well 16/17-A9 was drilled in 1996 as a south Tiffany appraisal well but did not encounter Brae reservoir. It was side-tracked as well 16/17-A 10 to drain a southern extension to Tiffany, south of a major bounding fault. The well was successfully completed in April 1997. During 1997 the N W Tiffany appraisal well 16/17-A11 was drilled. The well found only a thin, uneconomic reservoir section and for this reason was side-tracked down-dip to the east as A11Z. The well came on production in September 1997 but the oil rate rapidly declined from 3500 to 1500 BOPD and since the summer of 1998 the well has been a marginal producer with oil rates around 200 BOPD maintained through gas lift.
Fig. 2. Top reservoir depth map.
The field currently produces from seven wells (16/17-A1, A2, A3, A4, A5Z, A10 and A11Z) and has three water injectors (16/17A6, A7 and A8).
Toni. The Toni Field commenced production from four predrilled wells (drilled in 1992) 16/17-B1, B2, B3 and B4. The two injection wells (16/17-B5 and B6) were drilled in 1993. However, there are no plans for further drilling on Toni as the field is considered to be fully developed.
Thelma-SE Thelma. Thelma-SE Thelma wells 16/17-C1, C2 and C3 were pre-drilled during 1995. The horizontal side-track of 16/17-C 1, C 1Z, is the only Thelma producer. The horizontal well allowed the Thelma reservoir to be drained by a single well. Well 16/17-C2 flows at a stabilized rate of around 4000 BOPD. Well 16/17-C3 failed to encounter sufficient reservoir and was side-tracked to the C3Z location in late 1996. The SE Thelma well 16/17-C4 was drilled in early 1997 and successfully completed in April 1997. Well 16/17-C5 was drilled in the first half of 1997 to a northerly location within SE Thelma in an area previously considered in the Annex B to be unproven. The well did not find the SE Thelma reservoir and was consequently side-tracked to a location in the southwest area of the field. Well 16/17-C5Z encountered some mechanical problems and finally well C5Y was successfully completed in October 1997.
Structural setting Structural regional lineaments pre-dating the dominant N - S South Viking Graben Jurassic trend are apparent from gravity and magnetic data. A N E - S W trend is probably Caledonian in origin whilst the N W - S E lineament is parallel to the Tornquist trend. Both these trends were reactivated as transfer faults during late Jurassic extension. Locally, the N - S lineation of the South Viking Graben dominates the structure in Block 16/17. Much of the block, including the area containing all the oil fields, lies within the hanging wall of
T-BLOCK FIELDS the major bounding fault that separates the South Viking Graben from the high Fladen Ground Spur immediately to the west.
371
A final major phase of transpression during the middle Eocene, resulted in the reactivation of many Jurassic transfer faults and significant reversal of the graben boundary fault in the vicinity of the Toni Field.
Stratigraphy The pre-Jurassic interval in Block 16/17 consists of Old Red Sandstone strata unconformably overlain by Lower Permian Rotliegendes, Upper Permian marginal marine Zechstein facies and eroded Lower Triassic continental mudstones and sandstones. Bathonian to Middle Callovian volcanic and paralic successions, which overlie eroded Triassic sediments in Block 16/17, are essentially pre-rift deposits that accumulated in response to regional thermal relaxation of the crust. The Late Callovian, however, was characterized by a significant increase in clastic input from the Fladen Ground Spur, suggesting that rifting may have been initiated at this time. The Late Callovian age shallow marine and estuarine sandstones of the Hugin Formation, which make up these early syn-rift deposits, are host to a secondary undeveloped gas-condensate reservoir beneath the Toni Field. The end of the Callovian was marked by a regional change from the paralic and near shore facies of the Sleipner and Hugin Formations to the deeper water conditions of the Heather Formation mudstones. This change marked the beginning of the main phase of E-W extension in the south of Quadrant 16. During the Early Oxfordian, the gradient across the increasingly active graben boundary fault was sufficient to allow gravity-driven mass flow deposits to accumulate. This is a marginal undeveloped hydrocarbon bearing reservoir beneath the Thelma Field. By the latest Middle Oxfordian, oxic Heather mudstones were replaced by dysaerobic Kimmeridge Clay suggesting a further increase in the rate of subsidence and basin isolation. During the main phase of Jurassic extension, from Late Oxfordian to Early Volgian times, progressive footwall collapse allowed preservation of a thin, transgressive, late syn-rift to early post-rift succession over the graben terrace zone and the deposition of a thick, fan turbidite infill succession in the graben itself. Major rifting and rapid sedimentation ceased during the Early Volgian, with widespread deposition of a prominent transgressive mudstone (the Hudlestoni Shale). During the early part of the postrift cycle (latest Early Volgian to mid Late Ryazanian), fan sands continued to accumulate. These mass flow sands (the informally named Sand Shale Unit) gradually gave way to hot shales as relative sea level gradually rose and clastic input fell. A change in facies from Kimmeridge Clay anoxic mudstones to pelagic carbonates of the Valhall Formation marks the onset of true basin starvation during the mid late Ryazanian. The presence of thin, late Hauterivian, turbiditic sands in the Tiffany area, suggests an episode of minor uplift along the Fladen Ground Spur. There is, however, some evidence that minor inversion had commenced even prior to this date in the Toni area. During the latest Barremian to early Aptian, the south of Quadrant 16 underwent major basinal restructuring. Down to the basin tilting, uplift of the Fladen Ground Spur and inversion of the late Jurassic graben boundary faults resulted in the development of a significant hiatus and in the return of dysaerobic water conditions. The sequence boundary was gradually onlapped from the north by Late Aptian to Early Albian turbidites (Britannia Sandstones), sourced from the rejuvenated Fladen Ground Spur. These turbidites form a secondary reservoir in Tiffany area. A further phase of basin restructuring took place during the Middle Albian resulting in the re-establishment of clastic starvation and a return to oxic bottom water conditions. There is ample evidence that pulsed, albeit minor, inversion continued over the Toni Field area during the deposition of the Hidra, Herring and Flounder Formation (Cenomanian to early Campanian). The deposition of Flounder marls was terminated by basin-wide restructuring at the end of Early Campanian. Inversion tectonics continued to have an important effect on field morphology in the Toni Field area during the late Campanian and Maastrichtian.
Geophysics Agip (UK) has been involved in exploration of Block 16/17 since the third round of Licensing and has acquired an extensive database of both 2D and 3D seismic data across the block. Various vintages of 2D seismic were acquired between 1972 to 1978. The first 3D seismic survey was shot between 1981 and 1982 and covered 3276 km 2. These data were reprocessed in 1987. A second 3D seismic survey of 375 km 2 was acquired and processed in 1994. Reprocessing of these data in pre-stack time migration is currently underway. Despite the improvement in structural resolution, picking the top reservoir or any other event within the Upper Jurassic is still difficult. This is due to the poor reflectivity of the reservoir sediments as seen on the acoustic logs. Furthermore, the top reservoir does not represent a unique sedimentary event but is the convolution of a heterolithic series of conglomerates, sands and shale with different acoustic characters. The difficulty in defining the lateral and vertical limits of the Brae reservoir has had a major impact on the development history of Tiffany and Thelma. This has resulted in the drilling of unsuccessful wells in areas initially considered proven (wells 16/17-A5 and C3) or probable (wells 16/17-A9, A11 and C5). Seismic sections through the fields are shown in Figures 3 and 4. The Base Cretaceous event on the other hand is represented by a strong persistent horizon that is well defined across the whole block. A late Callovian event can be recognized below the reservoir interval in the graben area whereas on the terrace area the top basement is poorly imaged.
Trap The trapping mechanism for all the T-Block Fields is a combination of structure and stratigraphy formed by dip-slip inversion on the basin boundary fault zone to the west and lateral pinchout of the reservoir facies along the strike. In all the fields the closing contour seen on the top reservoir maps does not coincide with the established OWC. For the Tiffany Field, well data support the interpretation that lateral pinchouts of the fan conglomerates control the extent of the field along strike. This contrasts with the Toni Field where structural closure against WNW-ESE sealing faults seems predominant. The trap configuration for Thelma and SE Thelma fields a complex interaction of structural compartmentalization and depositional facies variations. This combination of structural and stratigraphic segmentation is also responsible for the petroleum distribution in the field. The up-dip seal for all the fields is thought to be the faulted contact with the impermeable Pre-Jurassic rocks. The top seal to the reservoirs is the Kimmeridge Clay Formation.
Source The source rock for the Upper Jurassic Brae Formation reservoir is the overlying Kimmeridge Clay Formation. The latest Volgian to Early Ryazanian 'hot shale' facies, also sources the Lower Cretaceous Britannia Sandstone that forms a secondary reservoir in Tiffany area. A mixed source, with contributions from Middle Jurassic coals and shale, Heather mudstone and the lowermost Kimmeridge Clay is interpreted as having charged the Late Callovian, Hugin Sandstone, gas condensate pool beneath the Toni Field. According to geochemical models the main phase of oil generation from the Kimmeridge Clay commenced during the Eocene and continues until the present day. Condensate generation
9
zp~
cs~
T-BLOCK FIELDS
373
<5 c,o
"-d . .,..~
[..,
Y:
e..) ....~
b .< ,4
374
M. GAMBARO & V. DONAGEMMA
from the Middle Jurassic coals and shale appears to have begun a little later, in the Oligocene, with Heather and Kimmeridge Clay contributing only recently.
Petroleum The Tiffany reservoir hydrocarbon is oil with 35.6 ~ API density, 0.23 cp viscosity and 885 SCF/STB solution GOR. Toni reservoir fluid is an oil of 34.8 ~ API density, 0.21 cp viscosity and 2170 SCF/STB solution G O R with a high carbon dioxide content (19mo1%) and few parts per million of hydrogen sulphide. In the Thelma and SE Thelma Fields, different PVT properties were found in separate regions but basically two main oil types can be distinguished. High-GOR oil is present in Thelma (38.5 ~ API density, 0.13 cp viscosity, 2720 SCF/STB solution GOR) while a less volatile oil characterizes SE Thelma (34.8 ~ API, 0.22cp and 1250 SCF/STB GOR). CO2 content reaches more than 18% with a few parts per million of hydrogen sulphide.
Reservoir Although generated by essentially the same processes, each of the fans that constitute the reservoirs in Block 16/17 exhibits a distinct character in terms of facies assemblage. The variation can be broadly attributed to distance from the source area, volume of sediment input and structural evolution (Fig. 5). In the Tiffany Field Brae Formation reservoir is dominated by conglomeratic and sandstone facies with argillaceous intervals restricted to the distal/ interfan locations. The Toni Field is similarly characterized by massive conglomeratic centre (16/17-16, B 1), but with a greater volume of sandstones and shale on the flanks of the structure compared with Tiffany. The Thelma reservoir is a wedge shaped coarse-grained sedimentary body shaling out towards east and south. SE Thelma is more clearly stratified with the presence of frequent shaly layers. The relationship between Thelma and SE Thelma reservoirs is explainable by a complex interaction of layers pinching-out and fault sealing. The Sand Shale Unit overlays the Brae Formation and represents a separate reservoir with generally poorer reservoir quality but locally containing significant volumes of movable oil (16/17-C2). The T-Block logs and core database is composed of: 9 A complete and homogeneous set of raw wireline and interpreted logs. 9 Standard core analyses that cover almost 30% of the reservoir section of the four fields. 9 Special core analysis on wells 16/17-15, -A1, -A2 (Tiffany); 16/1712 and -19 (Thelma and SE Thelma); 16/17-16, -B2, -B3 (Toni). 9 Strontium residual salt analysis (87Sr/a6Sr) from all the fields. 9 Biostratigraphical zonations for most of the T-Block wells. Strontium data were successfully integrated in 1997/98 in a Thelma study with considerable impact on the geological interpretation of the field (Fig. 6). The Tiffany Field results were less conclusive due to the predominance of the conglomeratic facies and absence of internal layering. The Toni Field data is currently being interpreted. A Cluster Analysis utilizing the gamma ray, density, neutron and sonic logs used to characterize the heterogeneity of the reservoir. Such an approach allows the identification of elementary units (classes or facies) each with specific lithological and petrophysical characteristics that are derived from calibration with core. The result of the statistical processing is graphically represented by the dendrogram (Fig. 7) where a tree-type structure defines the path between the end members of one class per sample and one class for the total population. Classes with almost the same lithological and petrophysical meaning are aggregated in more comprehensive facies directly matching the sedimentological core
description. The resulting aggregated facies, although characterized by a higher statistical variance, represent the general synthesis of the reservoir characteristics and, hence, the productive potential. An initial cluster analysis of all Block 16/17 wells was performed in 1988. Using that experience and the more extensive database now available it is possible to conduct specific field based studies (Fig. 8). The Brae Formation in Block 16/17 has been subdivided into seven main lithofacies (Table 2). Facies A and B are generated by hyperconcentrated flows; facies C and D are related to gravelly high density turbidite currents; facies SSH and E represent low density turbidity currents deposits. The Cluster Analysis generated was then used to obtain an accurate definition of the main petrophysical parameters:
Porosity. In all the T-Block Fields the porosity data have been evaluated on the log interpreted track carefully matched with the core data available. The quantitative interpretation has been carried out using the proprietary software LINEAR, using the same logs used for the statistical processing, in order to provide a high degree of consistency for the whole interpretation. In all the T-Block studies, four components (sand, low density clasts, high density clasts and shale) have been used to create three main interpretative models defined for the key wells of each cluster process. Model 1 for conglomeratic facies, model 2 for sandy facies and model 3 for shaly facies. Porosity overburden correction was applied with a constant value of 6.35% for all the lithotypes in Tiffany, 6.4% in Thelma and 7% in the Toni Field.
Permeability. In T-Block studies, permeability prediction has been evaluated using different approaches, but always dependant on cluster analysis results for accurate characterization of class properties. In the most recent studies, the database comprising of cluster results was not directly used for permeability evaluations. Instead, an accurate analysis and re-elaboration was performed in order to match the original core data. The main steps of the analysis were: Application of a 'shoulder effect' filter to reduce the 'noise' inside each single class due to the non consistent facies samples and generated by the smoothed reading of the logs. Practically the 'shoulder effect' is represented by single class values between continuous sections of two different classes. This filter eliminated a significant amount of the values responsible for the dispersion often present in the k/phi cross-plot. The best statistical parameter to be used for each class to match the core data (mode, median, arithmetic average, geometry average) was then defined. An initial set of permeability values was generated after these two preliminary steps. After checking these permeability tracks, a second statistical analyses with filter by facies, by well and by geological unit were performed to better define the compaction-diagenesis effect with depth according to the geology of the layering. The same approaches were repeated on different well associations in order to characterize trends and regions inside the geological units. Where possible (SE Thelma and sandier facies) an accurate K/Phi relationship analysis was also applied. In this way, rather than having one single
Table 2. Lithofacies within the Brae Formation of T-Block fields A0 A B-B1 C-CI D-D1 SSH E
Mud supported conglomerate Sand matrix supported conglomerate Clast supported conglomerate Pebbly sandstone with or without granules arranged in traction carpets Very coarse to coarse sandstone Lower medium size sandstone/shale interbedding Laminated mudstone
o
376
M. GAMBARO & V. DONAGEMMA
permeability value characterizing the facies (classic Cluster method), it was possible to obtain different values for one single class, changing with depth or area, but always honouring the total class distribution previously defined. The detailed analyses were aimed to better represent the contrasts between higher and lower permeability values, some of the most important data for the dynamic model. An example of the difference between the original and final synthetic permeability track is shown in Figure 9. In each field the most appropriate methodology was finally applied in order to preserve the original permeability contrasts and a check with the interpreted PLT curves and DST results was performed to validate the theoretical approach with field dynamic data (Fig. 10). The analysis of the different approaches to the synthetic permeability prediction could be summarized in two main observations: (1) cluster result was always used to generates a base case permeability; and (2) use of improved techniques was necessary to avoid smoothed representation of the reservoir heterogeneity.
Net/gross The definition of the net/gross ratio has been one of the main uncertainties on the T-block Field characterization. The particular lithology of the reservoir, mainly dominated by conglomerates with high statistical dispersion of the petrophysical data, suggested a constant review of the N/G determination approach. The quality and reliability of the geological layering on which the N/G evaluation has been applied increased through: (a) (b) (c) (d)
implementation of new techniques (like proportion curves analysis and residual salt analysis 87Sr/86Sr); update of the sedimentological and petrographical studies; full integration of well data (RFT, DST, PLT, new biostratigraphical data, fault analysis); and increased amount of core data available.
For net/gross definition two different methodologies were used and compared in the studies carried out on T-Block Fields.
Cluster based procedure. With this procedure all the classes with average K > l m D were assumed to be pay classes while all the classes with average K < 1 mD were non-pay. This method is generally good in clear sand/shale sequences and was used only during the early stages of the development. A more sophisticated variation of the cluster based procedure was the use of 'partially pay' classes. On these classes the percentage of core samples above the cut-off value defines the pay coefficient. This methodology is necessary when a lot of intermediate classes present a dispersed permeability characterization as in Tiffany and Toni Fields. Synthetic permeability procedure. In this case the permeability cutoff is directly applied to the permeability profile and all the partially pay classes are included in the pay portion. The method is preferred when a detailed permeability characterization of the partially pay classes is possible (by depth, area, well) and a good match is obtained between synthetic K and core data. This method was used in the Thelma Field. Water saturation The Indonesian equation was applied in the computation of true resistivity of the formation, determined from medium and deep induction logs that guarantee a high degree of reliability in oil-based mud. Formation water resistivity (0.1 ohm at 60~ and shale resistivity (10 ohm) were assumed to be the same for all the wells of T-Block. The cementation exponent 'm' was determined on the basis of compaction study results. A certain degree of variation has been seen between the fields and the main facies. The saturation exponent 'n' was also derived from the same wells special core analysis. The 'n' values were used to match the measured (Dean Stark) irreducible water saturation from core. As a result, empirical correlations based on permeability or porosity and height above on the oil-water contact were used for Sw mapping in all the T-Block Fields. Tiffany and Toni Fields 1993: Log (Sw) = a*H -c-b*l~ K
Fig. 6. Strontium isotopes data base flattened to sand shale trend (well C1 used as depth scale reference).
T-BLOCK FIELDS
377
o
o
o ..~
,...,
~4
378
M. GAMBARO & V. DONAGEMMA
Fig. 8. Main characteristics of most recent cluster analysis and comparison between lithofacies distribution.
where, a, b and c are average values derived from correlation; H is the height above oil-water contact; and K is the permeability. Thelma and Toni Fields 1996: Log(Sw)-- a l L o g H + a2PHI + a3 where, al, a2 and a3 are empirical coefficients; PHI is the porosity (from CPI); and H is the height on the oil-water contact.
on the last update of the studies, in order to define better layering of improved geological meaning, must be highlighted. Diagenetic effects were also taken into account largely for permeability mapping: (a) (b)
Tiffany Field 1998: The original interpreted saturation track obtained with the L I N E A R tool was matched by a non-parametric function based on log porosity and logarithmic distance from the oil-water contact. The methodology applied (presented at the Improved Oil Recovery Symposium, Tulsa, OK, April 21, 1996.) generates an optimal correlation between a dependent variable and multiple independent variables. The saturation function is on the form: Sw -- al* (SumTr)A2 + a2*SumTr + a3 where, al, a2 and a3 are three coefficients tuned on the best fit of the dependent and independent variables and SumTr is the sum of the two transformed independent variables: transformed logarithmic distance from OWC and transformed porosity.
(c) (d)
permeability reduction in water zone due to the presence of fibrous authigenic illite; permeability reduction around faults active during the Later Cretaceous-Early Tertiary, as result of possible calcite phase II cementation; permeability reduction in the region of the western boundary fault due to cementation or mylonitization; and enhanced permeability in the attic area created by dissolution and secondary porosity.
The history of the geological volumetric evaluation of each T-Block Field is summarized in Figure 11. It is evident that Tiffany and Thelma development drilling and data acquisition has strongly affected gross bulk volume (GBV) calculations and has also had some impact on the petrophysical characterization (N/G and Sw). In particular the drilling of wells 16/17-A5, A9 and A l l in Tiffany and the drilling of well 16/17-C3, and C5 in the Thelma Field resulted in a strong reduction of GBV. In the Toni Field the situation is very different. The development wells, all drilled in a short period of time, did not substantially alter the original picture and consequently the variations in STOOIP simply reflect a variation in geological model correlations and parameter definition methodology.
Oil in place, reserves and production
Distribution of reservoir parameters and OOIP
Production and reserves
Facies thickness and trends were used to condition the layer mapping in order to create a consistent data set of meaningful geological maps. In particular, the use of proportion curves analysis
The Tiffany Field commenced production in November 1993. The field has produced 58 MMSTB of oil to the end of 1999 and is expected to continue production until the end of 2006. Peak production
T-BLOCK FIELDS
379
expected to continue production until the end of 2006. Peak production was reached in 1995 at 33000 BOPD. Currently the field has potential to produce around 13 000 BOPD from the four producing wells while the two water injectors provide an average injection rate of 32 000 BWPD. Total recoverable oil reserves for the Toni Field, are currently estimated to be between 45 and 49 MMSTB. The upgrade of the reserves with respect to Annex B is related to the generally good performance of the field and particularly to a substantial delay in water breakthrough. The Thelma Field came on production with the horizontal well 16/17-C1Z in October 1996. The first SE Thelma development well 16/17-C2 came into production in mid-November 1996. The next SE Thelma well, the side-tracked 16/17-C3Z, came into production in January 1997. During 1997, two wells were successfully completed and put into production. Well 16/17-C4 came on production in April 1997 and drains the main east flank of SE Thelma together with well 16/17-C3Z. The initial rate was 10 500 BOPD and since June 1997 a stable rate of 7500 BOPD has been maintained. Well 16/17-C5Y is a side-track of well C5 and appraised the SW area of the field. Well 16/17-C5y came on production in October 1997 with an initial rate of 7000 BOPD rapidly declining to 3500 BOPD due to reservoir heterogeneity. The first phase of the development was completed in October 1997 when five wells were finally in production and the expected peak production rate of 25 000 BOPD was exceeded. At the end of March 1998 new perforations were successfully added to well 16/17-C2. Production increased from 3500 BOPD to above 6000 BOPD and is still constantly maintained. In well 16/17-C3z, after producing 5.3 MMSTB of oil, the water cut reached 75% and oil production dropped below 1000 BOPD during spring 1999. Unfortunately, due to low pressures, well 16/17-C5Y became an intermittent and marginal producer during 1998. The possibility of abandoning this well and drilling a new well (16/17-C6) utilizing the refurbished Christmas tree of well 16/17-C5Y is now under evaluation. However the present production potential of the field is still above 20 000 BOPD. In total Thelma and SE Thelma Fields have produced 26 MMSTB to the end of 1999 and are expected to continue in production until end 2006. Total recoverable oil reserves for the Thelma / SE Thelma Fields are currently estimated to be around 41 MMSTB. This is based upon updated results of the full field 3D model, assuming no water injection, and fully confirms the Annex B volumes, even if a totally different model is now adopted. In summary, each field had a different behaviour with respect to original expectations (Fig. 11): (1) (2)
(3)
Fig. 9. Synthetic permeability track comparison. was reached in 1995 at 44000 BOPD. At the end of 1997 the potential of the field rapidly declined after water breakthrough in wells 16/17-A1-A10. Water breakthrough has now also occurred in well 16/17-A2 while well 16/17-A5Z is producing with a water cut above 90% and well 16/17-A3 is completely watered out. At the end of 1998 gas lift installation was carried out in wells 16/17-A1 and A2. Now all the producing wells are gas lifted. Production is supported by water injection, currently from two wells, injecting a total of 20 000 BWPD. The total recoverable oil from the Tiffany Field is currently estimated by Agip (UK) to be in the region of 75 MMSTB. The Toni Field came on production in November 1993. The field has produced 38 MMSTB of oil to the end of 1999 and is
Tiffany Field production up to the end of 1999 has been just above 50% of that originally planned. Toni Field has already produced almost 85% of the original proven reserves. It is probable that during the year 2001 the original target will be overtaken, The main difference with respect to the old evaluations is the delay in water breakthrough and the slower water cut evolution observed in the wells. Thelma Field behaviour is close to the originally planned performance. In fact, despite the reduction in STOOIP and the minor contribution of 16/17-C5Y to production the last 3D reservoir model confirmed the original evaluation of ultimate reserves.
This range of production results is a confirmation of the degree of uncertainty that characterized the earliest phase of development.
Production facilities and transportation The Tiffany fixed steel platform with a 16 well-slot template stands in a water depth of 125 m and is located to the west of the 16/17-13 appraisal well. The platform has capacity to handle 100 000 BOPD, 120 MSCFPD gas and to inject 100 000 BWPD. Production from the Toni field is via a sub-sea manifold, through individual flow lines from each well to the Tiffany platform.
380
M. G A M B A R O & V. D O N A G E M M A
,--1
I r/l
=
"4
~z
,,....
..,.,.
o [....
T-BLOCK FIELDS
381
Fig. 11. STOOIP evaluation and field production history.
Treated water for injection is supplied by the Tiffany platform to the Toni template via a single sub-sea flowline. In December 1996 a high pressure pump for Toni water injection was installed on the Tiffany platform which increased the possible peak injection rate from 35000 to 41000 BWPD. The pump became operational in February 1997. The Thelma/SE Thelma Fields are produced via a sub-sea manifold, through two flow lines (6" and 10") tied back to the Tiffany facilities. Oil and spiked N G L s are exported from the Tiffany platform via a 12" linking pipeline to the Brae-Forties pipeline. From
Forties the crude is piped to Cruden Bay and from there to Grangemouth. All associated gas from the Tiffany Field, which is not required for fuel, is exported via a 34 km 10" pipeline to the Brae Field where it is sold to Marathon.
The authors would like to thank the co-ventures in the T-Block development for permission to publish this paper. Particular thanks are due to colleagues whose work during the last years substantially contributed to the contents of this paper.
382
M. G A M B A R O & V. D O N A G E M M A
T-Block Fields data summary
Trap Type Depth to crest OWC Oil column
Units
Tiffany Field
Toni Field
Thelma Field
SE Thelma Field
TVDss R TVDss
Structural/stratigraphy 12 520 13 920 1400
Structural/stratigraphy 11 755 12932 1177
Structural/stratigraphy 11 780 12096 316
Structural/stratigraphy 11 900 12 743 843
Brae
Brae
Brae
Pay zone Formation
Age Gross thickness Net/gross Porosity average Permeability average Petroleum saturation average
ft % % mD %
Upper Jurassic 1100 58 11 75 66
Upper Jurassic 1000 35 11 150 78
Upper Jurassic 1000 52 13.5 200 7O
Brae and Sand Shale Unit Upper Jurassic 600 38 12 0-1000 7O
Petroleum Oil density Gas gravity Viscosity Bubble point GOR Formation volume factor
~ API air = 1 cp psi SCF/STB RB/STB
35.6 0.7 0.23 3045 885 1.574
34.8 0.7 0.21 4480 2170 2.198
38.5 0.63 0.14 4450 2700 2.58
34.7 0.67 0.22 3300-3600 1200 1.79
Formation water Salinity Resistivity
NaC1 eq. ppm ohm m @ 60~
95 000 0.1
95 000 0.1
95 000 0.1
95 000 0.1
Km 2 MMBBL psi ~ ft ssl psi/ft MMSTBBL
6.2 5970 7455 275 13 300 0.3 156 water injection 43-47 68-75
6.8 8700 7000 258 12 815 0.27 121 water injection 40 48
10.2 2660 6655 260 12 096 0.26 52 natural water drive 21 11
10.2 9070 6945 26O 12 743 0.29 194 natural water drive 16 3O
Field characteristics Area Gross rock volume Initial pressure Initial temperature Datum depth Pressure gradient Oil initially in place Drive mechanism Recovery factor Recoverable oil
% MMSTBBL
The Thistle Field, Blocks 211/18a, 211/19a, UK North Sea A. M. B R O W N ,
A. D. M I L N E 1 & A. K A Y
BP, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB, U K 1 Present address." 90 Hamilton Place, Aberdeen AB15 5BA, U K
Abstract: Cumulative production of oil from the Thistle Field had reached almost 400 MMBBL by the end of 2000. Thistle is a success story and has been producing for over 20 years. It is now in its late stage of field life and is close to achieving a 50% recovery factor of its estimated 824 MMBBL STOIIP. The millennium challenge is to continue economic production and further increase reserves recovery. It has survived the full range of oil price fluctuations with all the accompanying cost cutting initiatives in late life becoming the benchmark for end of field life performance.
Thistle Field lies in blocks 211/18a and 211/19a, approximately 580km NE of Aberdeen (Fig. 1). Area 6 is a downthrown fault block on the northern flank of Thistle. Deveron is a satellite development to the west of the Thistle platform in Block 211/18a, developed by 2 to 3 km extended reach wells, and the D o n Field is a sub-sea development tied-back to the Thistle platform 17km to the south (Fig. 2). Britoil, a wholly owned subsidiary of BP, is operator. The Thistle Area fields (Thistle/Area 6/Deveron/Don) are produced through a single 60 slot steel drilling and production
platform. Oil is transported by pipeline via Dunlin platform and then the Brent Pipeline System to Sullom Voe Oil Terminal.
History The Licence P236 was awarded in the UKCS fourth round in March 1972 to the Halibut Group led by Signal Oil Company. The field was discovered by well 211/18-2 drilled on the crest of a Base
Fig. 1. Location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 383-392.
383
384
A. M. B R O W N E T A L .
Key .......................................PRT .. Fences ..... Block Boundaries
Boundaries for Don Unit and Area DSW
Fig. 2. Thistle Area Fields.
THISTLE FIELD Cretaceous unconformity high identified on 2D seismic data. An array of appraisal wells generally confirmed the field limits and proved the field's extension into Block 211/19a (Licence P104). The field was declared commercial in 1973. A single steel platform was installed in 1976 and development drilling commenced in September 1977. First oil was February 1978 and was produced initially via an offshore loading system until a pipeline link was completed to Sullom Voe by late 1978. All gas was flared until 1983 with the completion of the Northern Leg Gas Pipeline (NLGP) tied into Far North Liquids and Associated Gas System (FLAGS) to St. Fergus. There are nine appraisal wells and 48 development wells, located across the entire structure and although the field was discovered on 2D seismic data, structural definition has been historically based on the 1983 Thistle/Deveron 3D seismic data set. In addition, a 3D survey, acquired in 1989 and centred over neighbouring Block 211/18b, has been used in field management and in reviewing further possible reservoir options. Initial production declined steeply due to limited aquifer support and reduced pressure demanding immediate water injection support. Injection commenced in 1979 and has been key to maintaining the reservoir potential ever since. During the 1980s, the Thistle Field development team expected the field to have upside potential. In 1990, an infill well encountered flooded reservoir section and this combined with failure to meet production targets and rising costs resulted in restructuring of Thistle field management (Clyne et al. 1993). Thistle has made and continues to make significant efforts to extend field life by cutting costs, improving efficiency and maximizing production. After over 20 years' production, Thistle is producing at an average water cut of 96% with gross fluid rate daily in excess of 200 000 BFPD. The millennium challenge for Thistle is to continue economic production.
Major Events 1973 1974 1976 1977 1978 1982 1983
1984 1987 1989 1990 1992 1993
1994 1995 1998
Discovery of Thistle Field by well 211/18-2 Approval of Development Plan Single steel platform, Thistle Alpha, installed on location Discovery of Don Field by well 211/18-12 Development Drilling started First oil in February 1978, exported via offshore loading buoy (SALM) Maximum plateau production averaging 124 000 BOPD (Peak Prod 139 000) Associated gas export started via NLGP Acquisition of 3D seismic over Thistle and over Don Fields Area 6 well A46(45) drilled and on stream Deveron Field on production Don Annex B submitted Reprocessing of Don 3D seismic data Drilling of Don NE production wells N01 and N02 First oil from Don in late 1989 Don NE Injector N03 and producer N04 drilled Last Thistle Field well 211/18a-54 abandoned One Thistle drilling rig removed Don SW production well 211/18a-N05/N05Z drilled and completed First Don SW oil in September, 1993 New Don 3D seismic data set acquired late 1993, early 1994 Creation of MAST, which included Thistle Asset Don SW production well N06 drilled and completed Don SW injector well N07 drilled and on stream Don well NO 1 back on stream for three months
Discovery The Thistle Field was discovered in 1973 with well 211/18-2 which encountered 402ft of oil in the Middle Jurassic Brent Sands at a depth of 8920 ft sub-sea.
385
Structure Thistle is close to the edge of the Viking Graben, and like its near neighbour Deveron, is a typical example o f a Brent Province Oilfield. The trap is an easterly dipping rotated fault block, with closure updip to the west, and to the north, being defined by large scale faulting, and to the east and south, by structural dip (Figs 3 & 4).
Stratigraphy The stratigraphy of the reservoir sequence found in Thistle wells is broadly typical for this part of the Brent Province (Figs 5 & 6), and has already been described by Williams & Milne (1991). In this area, the Brent is composed of four lithostratigraphic sandstone units, the Rannoch (B1/A), Etive (B2), Ness (Cla, C l b , C2) and Tarbert (D). The Brent Group was deposited in shallow marine, prograding shoreface, deltaic system and is overlain unconformably by mudstones of the Humber Group, Heather and Kimmeridge Clay Formations, which provide seal and the hydrocarbon source rock. The net to gross of the reservoir is variable but generally quite high with good porosity. The system is highly layered with extreme permeability variability (Fig. 6). Detailed correlation between individual wells has been frequently difficult, due to the prevalence and dip of faults, and in many cases to the relatively high angle of the wellbores. Very often the faults involved are not seen on seismic data.
Geophysics The discovery and development of the Thistle Field was based on a network of overlapping 2D seismic surveys. These surveys, acquired in the late 1960s and early 1970s, were of variable quality, but were still sufficient to allow definition of the main structural features down to Base Cretaceous level. Pre-Cretaceous resolution was poor. These shortcomings of definition at reservoir level soon became apparent once development drilling began in late 1977, and production began in early 1978. Once initial water injectors were commissioned, it became apparent that some producers were receiving only limited pressure support. This was attributed to compartmentalization caused mainly by faults which clearly were not being detected from the available seismic data. To obtain further definition of reservoir architecture, a 3D survey was acquired over the field in 1983. It was not possible to undershoot the platform with 3D, but a 120 km survey of 2D data was acquired to fill this gap in late 1987. The 1983 3D seismic acquisition and processing had not fully succeeded in addressing the challenge of defining internal complexity. Consequently the whole data set was reprocessed in 1988, specifically to attain more definition of the pre-Cretaceous strata. However, again this was not completely successful. In 1992, a small additional 2D survey to infill the gap beneath the Thistle platform was acquired with the aim of more fully defining possible targets in the central part of the field. In 1989, a large 3D survey was acquired over Block 211/18b. This survey extended over the northern two thirds of the Thistle Field, as well as completely covering Deveron. While data from this survey was variable in quality, due largely to gas within the shaly Cretaceous and younger overburden rocks, it was an improvement on earlier surveys. This data set was interpreted using conventional workstation techniques, as well as seismic attribute mapping and has given better correlation and definition of faults, and greater confidence in their interpretation, particularly of smaller displacement faults. Structurally this data set confirms the earlier picture of the Thistle Field as an asymmetric four-way dip closure at Base Cretaceous level. Within the underlying Jurassic and older section, N-S, N W - S E and N E - S W faulting prevails; the strong E - W trend identified in earlier work is less apparent. Closure at reservoir level is provided to west and north by faulting, and to east and south by structural dip and plunge respectively. Within the rotated fault
Fig. 3. Thistle Fault blocks and top reservoir structure.
THISTLE FIELD
387
~5
.9
Z
?:
388
Fig. 5. Thistle Field general stratigraphy.
A. M. BROWN E T A L .
THISTLE FIELD
389
Fig. 6. Reservoir sand units and permeability distribution.
block and beneath a wedging Humber Group shale seal, the Brent reservoir is interpreted as thickening down-dip, reflecting a combination of condensed deposition and erosion over the higher parts of the structure.
Reservoir The Thistle field was described originally by Hay (1977) and updated by Williams & Milne (1991). Little has changed in the interpretation
390
A . M . BROWN E T AL.
either of the structure or stratigraphy. The field comprises faulted Middle Jurassic Brent Group. A faulted area to the north, referred to as Area 6 has limited communication with the main field. The Deveron Field is in a separate fault structure to the west and is tied into the Thistle platform by extended reach wells. A further, more complex highly fault compartmentalized Brent reservoir, the Don Field, has been developed sub-sea and tied back to the Thistle platform by a 17 km pipeline. The main Thistle field comprises an easterly dipping tilted fault block with oil-water contact at 9322 ft TVDss. The field performance has shown the faulting to be partially sealing and the field is significantly compartmentalized which has impacted field performance and evolution of field development. In this area, the Brent is composed of four lithostratigraphic sandstone units, the Rannoch (B1/A), Etive (B2), Ness (Cla, Clb, C2) and Tarbert (D), ranging in thickness from 200 to 550 ft (Fig. 6). The sedimentological model for the Brent Group of the Thistle Field remains unchanged from the early 1980s. The reservoir sands were deposited in shallow marine, prograding shoreface, deltaic environment. The Brent is overlain unconformably by mudstones of the Humber Group: Heather and Kimmeridge Clay Formations, which provide seal and the hydrocarbon source rock. A more recent sequence stratigraphic interpretation has refined this picture with the identification of four sequence boundaries, at the base of the Broom, Rannoch, Etive and at the base of the Tarbert (D2) formations. From a reservoir development viewpoint, the main conclusion of this model is that depositional geometry is predominantly sheetlike, which is borne out by the generally good lateral communication between wells, subject to fault compartmentalization. The repetition of flooding events accounts for the layered, vertically isolated reservoir zonation. The Thistle reservoir comprises mostly high quality sandstones, with porosities ranging 16-30% and horizontal permeabilities of up to 9 Darcies (Fig. 6). Large extremes of permeability variation within this layered system effectively further complicate the compartmentalization of the reservoir. The net to gross of the reservoir is variable (20-100%), but generally quite high (70%). This layered reservoir sequence has a large degree of pressure isolation vertically between zones which has been repeatedly demonstrated by the behaviour of the production and injection wells on the structure and this is key to Thistle's strategy of selective perforation and successive zonal depletion. Extensive petrographic work on Thistle core material indicates that the porosity of the reservoir sandstones is mainly primary in origin, with little diagenetic overprint. Variations in permeability and porosity are principally determined by original sedimentary facies, with diagenesis serving to emphasize the original differences in grain size and composition. The dominant control on reservoir quality is the presence of mica. The high porosity found in Thistle is more than would be expected from normal compactional trends and the preservation of original porosity is thought to be due to overpressuring of pore fluids.
Fluids Thistle oil is an undersaturated, light crude of 38 ~ API gravity, and of low sulphur content. Chemically it is a typical Brent Province crude, derived from the prolific Kimmeridge Clay Formation. Original reservoir pressure was 6060 psig at 9200 ft TVDss, indicating a considerable degree of overpressure. There is no gas cap, and the gas content of the oil is low, with G O R of 290 SCF/BBL, and a bubble point of 960psig. Thistle formation water is quite fresh with dissolved solids of 23 000 ppm. The aquifer is large and variably active, but only really appears to benefit the peripheral parts of the field because of the internal fault compartmentalization within the field. The Eastern and Southern Fault Blocks benefit most for aquifer drive in contrast to the north of the field. Area 6 which is dependent on aquifer recharge, has very poor support.
Reserves Unlike many Northern Brent Province fields, Thistle oil-in-place and reserve estimates have remained relatively constant since the beginning of field life. The STOIIP has not changed since updated in 1989 at 824 MMSTB. The high degree of structural and stratigraphic compartmentalization and heterogeneity, as well as fractional flow behaviour, resulted in Thistle never achieving its planned plateau rate of 180 MBOPD. Ultimate recovery has been sustained however by additional injection and production wells. Thistle production from field start-up in 1978 up to the end of 2000 is illustrated in Figure 7 along with water injection and field water cut development. The are presently 24 producing wells and seven water injectors, and water cut is nearly 96%. Cumulative oil production to the end of 2000 is 392.2 MMBO (Fig. 7), representing a field recovery of 47.6%. The main threats to realizing remaining reserves are well and plant integrity, and voidage replacement. Reservoir behaviour at high water cuts such as are found in Thistle tends to be fairly consistent and predictable, provided reservoir pressure is maintained. Historically the main plant problems on the Thistle platform have been gas-lift compressor uptime, and turbine efficiency for electrical power and therefore water injection.
Field management For the last ten years the field management philosophy on Thistle has been centred on optimizing the existing well stock and plant. No wells have been drilled on Thistle since the end of 1989, for the simple reason that there have not been any commercially feasible locations identified. On the basis of an updated and more detailed reservoir description in 1989, a number of possible areas of unswept oil were identified. Most of the infill drilling opportunities had B1A targets, and effectively depended on the fact that the poorer quality Rannoch sands at the base of the Brent sequence were deemed to be less efficiently swept than higher levels in the reservoir. The most favourable of these infill targets was drilled in late 1989/early 1990, in well 211 / 18a-A54. Results showed this well was flooded to a much higher degree than had been anticipated, and although some oil was found at the base of the section, it was not considered worth completing, and the well was abandoned. The disappointing results of this well and some B1A well intervention operations at the same time, proved to be a turning point in Thistle Field management strategy. A geological and reservoir engineering study of the B1A was carried out, which brought about a change in the understanding of the Thistle reservoir. This study changed the view of the drainage mechanism within the B1A. It concluded that downward gravitational slumping of injection water from the overlying and early flooded B2 reservoir unit was a much more dominant process than had previously been suspected, and the depth of invasion was time-dependent. The corollary of this mechanism was that much B1A oil has been displaced vertically into the B2, and produced via perforations at that level. The study indicated that most of the undrained B1A oil previously identified, and thus infill drilling targets did not exist. Since reaching this conclusion, the strategic direction of Thistle Field reservoir management shifted from infield drilling to rigorous and innovative operations on the existing well stock (Clyne et al. 1993). Drilling activity for new reserves in the asset shifted instead to the large satellite, the Don Field, which is the subject of a separate paper in this volume. The main components in the Thistle Field management strategy, in addition to ever-present cost control are: (1)
(2)
Rigorous voidage replacement, requiring high water injection rates and efficiency, and selectively shutting in production wells, or batch production, as appropriate. Optimized well interventions, to maximize the benefit of individual well operations, and minimize the number of wells out
THISTLE FIELD
391
Fig. 7. Production and water injection profile and field watercut development.
(3)
(4)
of service. In addition to surveillance work these operations include reperforation or the addition of new perforations to bring in unswept zones, scale squeezes and water shut-off gel treatments. Maintaining a testing programme to ensure accurate production potential estimation, well allocation and well problem recognition and diagnosis. Minimization of plant downtime by tracking of production losses to identify potential efficiency gains.
In spite of the emphasis on management of Thistle existing well stock, the search for commercially viable options that could be drilled, either conventionally or by coiled tubing, continues. The continued focus on gaining further reservoir understanding and further gathering of basic reservoir data will enable reserves maximization and production optimization of the Thistle Field. Thistle's fate, like many of the 1970s giants in their twilight years, will be predominately dependent on future oil price.
Thistle Field data summary Trap
Type Depth to crest Lowest closing contour OWC Oil column Original pressure @ datum Current (2000) pressure @ datum Original temperature Datum depth
Rotated fault block 8500 ft TVDss 9322 ft TVDss 9322 (original) ft TVDss 822 ft 6060 psi 5500 psi 220 ft 9200 ft TVDss
Pay zone
Formation Age
Brent Group Middle Jurassic
392 Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Petroleum Oil density Oil type Viscosity Oil Gas/oil ratio Formation volume factor (Bo) Gas expansion factor
A. M. BROWN E T A L . <550fl 20-100% 0.24 (0.16-0.30)% (40-40 000) mD
Oil initially in place Recovery factor Drive mechanism Recoverable oil
Production Start-up date Feb 78 Production rate plateau oil 124000 BOPD Number/type of well 60 slots in 2000 22 production 7 water injection
78 (60-85)%
38.4 ~ API light, low suplhur 0.85-0.915 cp 290 SCF/BBL 1.18 RB/STB
13 000 NaCI eq. ppm 0.253 ohmrn @ 77~
Field characteristics Area Gross rock volume Initial pressure Temperature
3410 acres 910 000 acre ft 6060 psig 220~
Steel Platform 8/76
2 GL well, 1 dual completions
0.92cp @ 5000psia @ 5000 psia
References
SCF/RCF
Formation water Salinity Resistivity
824 MMBBL 49% waterflood 404 MMBBL
23 000 ppm tds
@ 92001 TVDss @ 9200' TVDss
CLYNE, P. A., BAJSAROWICZ, C. J., JONES, K., MILNE, D. & RICHARDSON, S. M. 1993. Saving Thistle's Bacon: The Role of Reservoir Management in Optimising a High Watercut Field. SPE 26787. HAY, S.M. 1977. The Thistle Oilfield: Mesozoic Northern North Sea Symposium. Norwegian Petroleum Society, Oslo. WILLIAMS, R. R. & MILNE, A. D. 1991. The Thistle Field, Blocks 211/18a and 211/19. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields': Commemorative Volume. Geological Society, London, Memoirs, 14, 199-297.
The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea M. G A M B A R O
& M. C U R R I E
Agip ( U K ) Ltd, Wellington Circle, Aberdeen AB12 3JG
Abstract: The Balmoral Oilfield is a mature asset in its final phase of production. Associated with the Bahnoral development have been the less significant Glamis and Stirling Fields. Each field is different from the perspective of geology and many other issues. Balmoral is a typical Paleocene oilfield with good water drive from a large regional aquifer. Interestingly this was not recognized at the start of the development when water injection facilities were commissioned. Glamis is a smaller field of Late Jurassic age containing somewhat lighter oil than Bahnoral. Water injection has been necessary to maximize recovery in this field. Stirling is one of the few fields in the North Sea to produce commercially from the naturally fractured Devonian Sandstone. This field is developed by a single horizontal well. Balmoral oil recovery has significantly exceeded original expectations, whilst Glamis and Stirling have produced as much as expected. The Balmoral Field lies within Blocks 16/21a, 16/21b and 16/21c and forms part of the Licence P201 operated by Agip (U.K.) Limited (Fig. 1). Block 16/21 is located approximately 140 miles NE of Aberdeen. All the fields discovered in Block 16/21 were named after Scottish castles (Balmoral, Glamis, Stirling). Each field is located in a different formation (Fig. 2): 9 9 9
Balmoral produces from the good quality, high permeability Andrew Sandstone. Stirling is a fractured Devonian Old Red Sandstone reservoir that underlies the Balmoral Field. Glamis is located 8 km south of Balmoral and the reservoir is Jurassic in age (Glamis Sandstone).
The Block 16/21 fields were operated by Sun Oil Britain from production start up in 1986 to December 1996 when Agip (U.K.) Limited acquired the company. The current equity participation in Balmoral Field is as follows:
reason why it has been decided to include the three fields together in one report in order to save duplicating the areas of commonality between the fields. Balmoral has produced 103.3 MMBBLs up to the end of 1999 and represents the most significant of the three fields. Glamis has produced 18.4 MMBBLs and Stirling 2.6 MMBBLs. Ultimate recoveries are expected to be around 110 MMBBLs for Balmoral, 19 MMBBLs for Glamis and 3 MMBBLs for Stirling. Future recovery depends closely on abandonment date which itself could be controlled by both the reservoir performance and economic factors. Current expectations are for abandonment in 2003. This is significantly better than initial expectations. When Agip (UK) Limited commenced operations in 1996 our original expectation for abandonment was 1999. G o o d reservoir performance combined with a significant reduction in operating costs have extended the life of field by four years.
Exploration & development history Operator
%
Joint venture participants
%
Agip (U.K.) Limited
58.99%
Kerr McGee VEBA Oil Pentex Summit Talisman
12.47 12.47 6.65 6.75 2.67
The Glamis Field is entirely located inside Block 16/21a, for which the current participating companies are: Operator
%
Joint venture participants
%
Agip (U.K) Limited
62.00
Kerr McGee VEBA Oil Pentex
15.00 15.00 8.00
The current equity participation in Stirling Field is as follows:
Operator
%
Joint venture participants
%
Agip (U.K.) Limited
54.88%
Kerr McGee VEBA Oil Pentex Summit Talisman
9.0 9.0 4.8 16.0 6.32
All three fields are produced to the Balmoral Floating Production Vessel and are operated as a single system. This is the
Balmoral Block 16/21 was awarded to British Sun (90%) and North Sea Exploitation and Research (10%) in the fourth Licensing Round in 1972, together with Block 211/22, as Licence P. 201. In March 1978 the mandatory 50% relinquishment took place: the retained 13 462 acres became Block 16/21a while the relinquished portion became Block 16/21b, which was subsequently awarded to British National Oil company in December 1980 as part of Licence P.344. In 1986 operatorship of Block 16/21b passed to A R C O British Limited which, at the end of the same year, retained Block 16/21b and 16/21c and relinquished Block 16/21d as open acreage to the north. The 16/21-1 discovery well for Balmoral was drilled in July 1975 to test the upthrown fault block closure of a section presumed to be of Jurassic age (Fig. 3). No hydrocarbon shows were encountered in the original target which actually proved to be of Devonian age, but a 78ft oil column was encountered in the late Paleocene Andrew Sandstone Member. The well was tested at a maximum rate of 4049 BOPD of 39.4 ~ API oil through a 1 inch choke. Further delineation drilling was not undertaken until 1979, when the well 16/21a-2 was drilled about 1.4 miles N E of the discovery well. It had been planned to test an apparently separate Paleocene structure, but the welt encountered an 88 ft oil column in the same Paleocene sandstone and with an oil-water contact (OWC) identical to that found in the 16/21-1 well. In addition hydrocarbons were discovered in fractured sandstone of late Devonian age. This second accumulation was subsequently named the Stirling Field. Appraisal of the Balmoral Field continued in 1981 with the drilling of wells 16/21a-3 and 16/21a-3st. The side tracked hole tested the Paleocene reservoir at a maximum rate of 5476 BOPD. Well 16/21b-4A was drilled by BNOC in 1982 near the southeastern
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 395-413.
395
400
M. GAMBARO & M. CURRIE
came in structurally higher than forecasted and for this reason was side tracked to a point closer to the oil-water contact. First oil from the Glamis development was produced in July 1989 from two producers at a rate of around 12000 BOPD.
Stirling The Stirling Field was discovered in 1980 by well 16/2la-2 (Fig. 5). The well was drilled as a Paleocene appraisal well for the Balmoral Field. The secondary objective, which proved to be a Devonian reservoir, was originally thought to be a Mesozoic structural feature. The well was suspended after testing an average of2130 BOPD of 37 ~ API oil from fractured Devonian sandstone and quartzite. In 1982 the presence of oil in the Devonian reservoir was confirmed by well 16/21b-4a whilst well 16/21a-7 was drilled on the downthrown side of a major E - W boundary fault. The well was found to be water-bearing in the Devonian but provided useful geological information (46 ft of cores) confirming the complexity of the reservoir. In 1985 two other wells targeting the Balmoral Field development also penetrated the Devonian. Well 16/21a-B3 encountered poor reservoir quality and a stable flow could not be established despite stimulation and nitrogen lift. Well 16/21a-16 was successfully cored and tested (1780 BOPD on 40/64 inch choke). In 1987-1988 an Extended Well Test (EWT) was conducted on the 16/21a-2 well. A total of 429 000 MSTB of oil with final water cut of 30% was produced. The rapid water breakthrough discouraged any further development through traditional vertical wells. At the beginning of 1990 the horizontal well technology had advanced sufficiently to encourage the decision to drill two appraisal wells to test fracture distribution and productivity of the formation in different areas of the field. In March 1991 oriented cores (208 ft) and the Circumferential Borehole Imaging Log from the inclined well 16/21a-20RE provided good information while encouraging results were obtained by the DST (4680 BOPD). The second well (also inclined though not horizontal), 16/21a-22, proved to be more shale prone, less fractured and less productive (rapid production decline during the well test from 2000 to 950 BOPD) than well 16/21a-20RE. In 1992 well 16/21a-20z, the horizontal side track of well 16/21a-20RE, was drilled along an azimuth of 1 l0 degrees. The horizontal section was around 3000 ft long and was completed with an uncemented 589 inch slotted liner. No coring was attempted but logging whilst drilling (LWD), conventional drill pipe conveyed logs and Acoustic Telescanner (ATS) were acquired. After a full revision of the available data, the permit for a six month EWT was obtained in March 1994. This was followed by sanctioned production under separate field development status with production continuing from the single horizontal well. The initial rate of the well was 4000 BOPD declining rapidly as water production encroached via the fracture system.
Stratigraphy and regional setting Balmoral All the Block 16/21 field structures are located at the southern tip of the Fladen Ground Spur, a N-S trending elongate extension of the East Shetland Platform (Fig. 1), composed of Devonian continental sedimentary rocks which locally separates the Witch Ground Graben to the west, the South Viking Graben to the east and the Fisher Bank basin to the south. The oldest rocks identified in Balmoral and Glamis area are continental deposits of Devonian age (Fig. 6). The Devonian sequence within Block 16/21 is over 12 000 ft thick and comprises a series of braided fluvial channel deposits with interbedded sheetflood/overbank sandstones and mudstones. These were uplifted, tilted and eroded as a result of Hercynian movement and no sedi-
ments of Carboniferous, Permian or Triassic age are present in the field (Tonkin & Fraser 1991). Cimmerian rifting during the late Triassic to Early Tertiary created the structural framework of the area. The Fladen Ground Spur was a positive feature for most of the Mesozoic; the thick Mesozoic sediments of the flanking Grabens are not present here. However, a thin wedge of Upper Jurassic to Lower Cretaceous sediments, which includes a thin sequence of Volgian sandstones (Glamis Sandstone), onlaps the Devonian basement to the south of block 16/21 (Fig. 2). The deposition of the Upper Jurassic Kimmeridge Clay Formation basinal muds along the flanks of the Fladen Ground Spur was related to the subsidence within the Southern Viking Graben. The late Jurassic rocks are absent in the crestal area underlying the Balmoral Field due to a non-deposition on the Fladen Ground Spur that subsided only during Early Cretaceous times when a relatively thin sequence of marls and chalks (Valhall Formation) were deposited. The Cretaceous sequence records a marine transgression from shallow shelf to a deep basinal marine setting. Flounder, Tor and Ekofisk Formations present a combined thickness of up to 600 ft in the Balmoral area. In the Tertiary the Orkney-Shetland Platform was uplifted and tilted giving rise to an easterly drainage pattern which shed large quantities of deep marine clastics into the subsiding basin areas. Paleocene-Eocene turbidity currents swept large volumes of sand and mud into the area, depositing them in major submarine fan systems. One such fan is the Upper Paleocene Andrew Formation (Deegan & Scull 1977). It formed in a broad anticlinal structure, primarily related to differential compaction and onlap, over the Devonian high in the Balmoral Field area. In Block 16/21 the thickness of the Andrew Formation increases from about 600 ft in the Balmoral area to more than 1000 ft in the south of the block. The reservoir seal is provided by the overlying Lista Formation claystone. The Forties Formation sandstone, another submarine fan system was deposited thinly in Block 16/21. The deposition of tuffaceous claystone mudstone (Balder Formation) marks the end of Paleocene sedimentation. Occasional localized turbidity flows and channel sands are present during Eocene times but in general the sedimentation from Oligocene to the present day is dominantly mudrocks, typical of a deep-water marine setting. This Eocene-Pliocene sequence is 50006000 ft thick and provided sufficient depth of burial to the Kimmeridge Clay Formation for maturation and oil generation starting from the Oligocene.
G~m~ The Upper Jurassic shallow marine sandstone that forms the Glamis reservoir was deposited during a marine transgression from the southwest, directly overlying the tilted Devonian strata. The Glamis Sandstone is overlain by the Kimmeridge Clay Formation. The deposition of these basinal muds along the flanks of the Fladen Ground Spur is related to the subsidence and subsequent fill of the Southern Viking Graben. After the deposition of the Kimmeridge Clay Formation the Glamis area was again exposed to erosion as a result of renewed Cimmerian uplift. For this reason the Kimmeridge Clay section is thin or locally absent, particularly in the crestal part of the field (Fraser & Tonkin 1991). During Cretaceous times the Fladen Ground Spur area subsided, resulting in a covering of a relatively thin sequence of marls and chalks. This sequence records a gradually deepening depositional environment, from marine transgression to a deep basinal marine setting. In the Tertiary, the Orkney-Shetland Platform was uplifted and tilted giving rise to an easterly drainage pattern which shed large quantities of deep marine clastics into the subsiding basin areas. Paleocene-Eocene turbidity currents swept large volumes of sand into the area, depositing them in major submarine fan systems. The overlying pelagic mudstones of the Lista Formation provide the seal to Paleocene fields such as Balmoral. Further
406
M. GAMBARO & M. CURRIE
conversion methodologies were analysed by Agip (U.K.) Limited; a layer cake approach and an average velocity approach which were compared to the previous methods. Each approach can give significantly different implication for STOIIP and connected volumes. The favoured approach by Agip was to use a layer cake technique which showed a reasonable possibility of closure for the northwest portion of the Balmoral Field. For the Glamis Field, the layer cake depth conversion was also applied using the following main horizons; Mean Sea Level-Top Balder F o r m a t i o n - T o p Andrew F o r m a t i o n - T o p Kimmeridge Clay Formation.
a datum depth of 10 150ft TVDSS. Formation water salinities are typically 84 500 ppm NaC1 equivalent. Oil in the Stirling Field is undersaturated with an API gravity of 37 ~ (0.840g/cc) and an original G O R of 290 SCF/STB at a reservoir pressure of 3625 psig. The average reservoir temperature is 226~ and formation waters have an equivalent salinity of 72 000 ppm NaC1.
Trap and source
Balmoral
The Balmoral structure is dip closed on all sides at Paleocene level. The seal is effected by the shales of the Lista Formation. The field average oil-water contact is assumed at 7050 ft TVDSS. There has been uncertainty over whether the structure is absolutely full to spill. The uncertainties in seismic depth conversion certainly opens the possibility of a northwestern spill point. A Kimmeridge Clay Formation source is indicated by the presence of bisnorhopane. This formation is absent or very thin in the Balmoral area (22 ft only in well 16/21b-9). Consequently it is thought that oil has migrated into the reservoir from thicker, more deeply buried intervals that have reached maturity in the Witch Ground Graben to the southwest. (Tonkin & Fraser 1991) The Glamis oil accumulation occupies a structural trap elongated in E-W direction. The trap, is fault bounded in the north by normal faults of significant throw and dipping toward the south where other low throw faults are present. The Glamis structure is overlain by thin shales of Kimmeridge Clay Formation that do not form a continuous seal and are absent at the structural crests and along the planes of major north dipping faults. Effective seal is thus provided by Flounder Formation marls. The oil-water contact was identified in wells 16/21a-6, 17 and 17z at 10306ft TVDSS. This is approximately equivalent to the lowest closing contour mapped at top structure. The oil in Glamis Field, again, was sourced from the Kimmeridge Clay Formation as indicated by the presence of bisnorhopane in oil from well 16/21a-6. However according to Ts/Tm ratio and the C28/C30 hopane ratio Glamis oil was generated from a maturer interval and from different facies of source formation than the Balmoral oil. The Stirling structure is a NW-SE oriented high, consisting of tilted fault blocks with scarps facing northeast, and dip slopes towards the southwest. The scarps have been eroded to give an unconformity surface that has subsequently been faulted as late as Late Cretaceous time. The structure is bordered by faults mainly W - E and W N W - E S E oriented probably fitting the regional trend of the Witch Ground Graben. Only the southeast area of the field appears to be bordered by N-S oriented faults probably fitting the regional trend of the South Viking Graben. The structural relief of post Devonian horizons is largely controlled by drape over the pre-existing Devonian fault related structures. The field is approximately 4.7 miles long and 1.8 miles wide with the top seal being provided by Late Cretaceous marls and chalk. The oil in the Block 16/21 area was sourced from the Kimmeridge Clay Formation. The migration of oil in the fractured Devonian units is believed to be from the NW and SE along the major joint and fault patterns.
The Andrew Formation sands in the Balmoral Field consist of 550-850 ft of thick-bedded sandstone with subordinate mudstone and thin to thickly bedded sandstone. The sandstones typically are massive, amalgate but can exhibit dish structures and water escape features such as pipes. The sandstone are fine to occasionally coarse grained, poor to moderately well sorted. Only localized zones are well cemented by calcite, elsewhere cementation is poor to moderate. The interbedded mudstones are green/grey in colour, non-calcareous, slightly micaceous and bioturbated. Micropalaeontological assemblages are generally abundant and in general the fauna reflects a middle/upper bathyal slope setting in excess of 200m water depth. The Andrew Formation has a relatively uniform mineralogy. Massively bedded sandstones are separated by less well bedded sandstone facies and occasional argillaceous units, which represent the abandonment of the sand depositional system and form the main baffles and barriers to fluid flow. The typical porosity average value for Andrew Formation sands is about 25% with an average permeability close to 1000mD. A diagenetic zone of friable sand occurs in the lower central part of the reservoir due to the absence of authigenic quartz overgrowths. Low permeabilities occur in the friable sands due to preferential precipitation of kaolinite which blocks pore throats. Thin calcite cemented sandstones (doggers) of limited extent are likely to provide local baffles to fluid flow, particularly in the lower oil leg and aquifer. Faults are not generally sealing and sand to sand connectivity appears to be good according to the production history of the field. Some possible areas of upswept oil could occur in the foot wall of faults where producing sands are juxtaposed against Lista Formation mudstone. This has not been tested by infill drilling due to the limited economic viability of such targets. According to the geological review of 1994, revised by Agip in 1997, six flow units have been correlated around the Balmoral Field. These cover the entire Andrew Formation and are labelled Unit A at the base through Unit F at the top. Small scale sub-units have been used within the upper part of the reservoir (Fig. 10). Unit A represents the basal Andrew Formation unit and overlies the Maureen Formation. The unit is mud dominated at the base but coarsens upwards into massive sands. It forms the lowest effective part of the aquifer. Unit B is between 100 to 200ft thick and includes at least two major sequences capped and separated by thin mudstone facies. On the structural crest these mudstone are absent having been eroded by submarine channels. Also Unit B is totally water bearing. Unit C is between 40 and 140 ft thick and oil bearing only in the crestal area of the field (e.g. well 16/21a-B2). The upper part of this unit is mud-dominated and forms a correlatable biostratagraphic event around the flanks of the field. In general Unit C can be distinguished by its relatively poor rock quality when compared with the intervals above and below it. Unit D is up to 100ft thick and unlike the previous two units is thicker along the field crest and absent at well 16/21b-9 in the southwest. It is sanddominated with a sharp mudstone top that is expected to act locally as an effective barrier to flow. Unit E constitutes the main reservoir. It is formed by two massive sands which are separated by a thin (7 ft) mudstone parting that can be completely eroded on the crest of the field. Unit E is capped by a continuous mudstone interval (8-25 ft thick) that is probably acting as a major barrier to vertical flow in the oil leg. Unit F is the top most reservoir unit. The sand is
Hydrocarbons The Balmoral oil is undersaturated with an API gravity of 39.9 ~ (0.826 g/cc) and an original G O R of 366 SCF/STB at a reservoir pressure of 3145psig. The average reservoir temperature is 207~ and formation waters have an equivalent salinity of 72 000 ppm NaC1. Seventeen of the Balmoral wells were drillstem tested, typically at rates of 2500 to 3500 BOPD. The Glamis oil is undersaturated with an API gravity of 41.5 ~ (0.818 g/cc) and an original GOR of 1037 SCF/STB, at a reservoir pressure of 4562 psig. The average reservoir temperature is 246~ at
Reservoir characterization
BALMORAL FIELD in pressure communication with the underlying reservoir through the aquifer and it is envisaged that the oil recovery from the unit should have a larger component of edge drive rather than bottom up water drive. Unconsolidated or friable sands are common in the Balmoral reservoir, especially within Units B C and D. This interval is up to 300 ft in thickness and detailed log correlations suggest that the upper and lower boundaries of this interval may cut across depositional boundaries. The unconsolidated interval contains only 15% of total STOOIP but in early stages strongly affected reservoir evaluations due to its lower permeability (200 mD) and consideration that it could have reduced sweep efficiency and aquifer response.
GNm~ The pre-Jurassic surface under the field provided a local tectonic feature onto which the Jurassic reservoir progressively onlapped. This caused the lower units to thin on to this feature and are totally absent in well 16/21a-26. It would appear that the lower intervals filled in and overstepped the Devonian erosion surface while the upper intervals were deposited over the entire area of the field. The entire upper Jurassic sequence pinches out to the northeast of Glamis where it onlaps the Balmoral high. In general the lack of sedimentary structures within the Glamis sands suggests a relatively low energy, lower to middle shore-face or inner shelf depositional environment. The Glamis Sandstone ranges in age from Late Kimmeridgian to Volgian over the field. This age range is insufficient to allow a reliable biostratigraphic correlation inside the reservoir. Since the time of Annex B (1987) four main lithofacies groups were identified: Facies la, lb, 2a and 2b. This four fold division formed the basis for all the following revisions (Fig. 11). The oldest unit is Facies 2b. This is a basal conglomerate comprising clasts of fractured Devonian sandstone, schist, quartzites and mudstones, with pyrite cemented sand matrix. Clast size varies from boulders to pebbles. The facies is very immature and locally may infill depressions in the Top Devonian erosion surface. Porosities (7-12%) and permeabilities (up to 80 mD) are relatively low and the unit is not believed to contribute significantly to the reservoir production. Facies 2a or 'lower sand unit' is a fine to coarse grained sandstone that is present in all the wells with the exception of well 16/21 a- 15. The unit is of shallow water, near shore origin and was subject to reworking by wave action, as evidenced by the lack of mudstone beds, the presence of wave ripple laminations and low angle cross-bedding. Typically the sands are medium to coarse, occasionally fine grained with local concentrations of glauconite pellets, phosphate clasts, carbonaceous material and heavy mineral bands. These bands correspond with very high gamma ray readings in several wells but although locally correlatable they do not occur sufficiently widely over the field to assist with reservoir zonation. Towards the top of the interval the sandstone becomes much finer, with more argillaceous layers occurring. Occasional coarse pebbly horizons occur as result of periodic storm deposits throughout the entire section. These sandstones of Facies 2a are exceptionally clean having Net to Gross rates above 95% in all wells. Porosities are consistently between 13 and 15% and permeabilities range from 50 to 800roD. Facies lb or upper sand unit comprises clean, well sorted, massive highly bioturbated sands with discrete coarsening upward cycles. These are interpreted as shoals related to a bar formation. The top of the unit is fine grained and represents a postdepositional phase of winnowing and reworking related to a sea level stillstand. N / G ratios are still above 95% as in Facies 2a. Porosity is varying between 18% along the bar axis and 13% towards the bar flanks. Permeability is very high, ranging between 500 and 1500 mD. Facies la presents an overall fining upwards trend and is interpreted as a transitional bar flank facies marking the end of the late Jurassic transgressive event. This unit occurs in wells 16/21a-6, 16/21a-15, 16/21a-26 and 16/21a-27 and is composed of very fine sands and silts. Porosity is around 9% and per-
409
meability is generally lower than 3 mD so the bulk of Facies la is non-reservoir. The unit is directly overlain by claystones of Kimmeridge Clay Formation.
Stirling The Mesozoic and Cenozoic lithostratigraphy of Block 16/21 shows reasonable continuity and correlation. By contrast, the internal Devonian subdivision and correlation is less obvious given the variability in lithofacies due to the depositional environment, structural complexity and lack of biostratigraphy. A four layer scheme for the Stirling Field was initially proposed in 1987 but discarded in 1994 and at present the reservoir is considered as a single heterolithic sequence. This is not only related to rapid lateral facies variations in the fluvial depositional environment but is also because the original layers are strongly tilted and eroded as demonstrated by several wells that encountered different sections of the Devonian sequence (Fig. 12). The reservoir is fairly tight with oil being produced primarily from the fractures. The fracture network is variable in its development and therefore there is a wide range of productivity from this field as demonstrated through the variable results from DST testing. Considering the cored intervals from eight wells on the Stirling Field, the average matrix porosity is 9.5% with an average permeability of 0.68mD. However, 13.5% of the cored interval has permeabilities higher than 0.75mD with an average horizontal permeability of 4.6 mD. The fracture network is defined at field scale by a hierarchical framework of discontinuities consisting of three systems: a subsiduary small-scale discontinuity system consisting of the fractures recognized on the cores; a main medium-scale discontinuity system consisting of the sub-seismic events recognized by the Continuity Cube; and a subsiduary large-scale discontinuity consisting of the seismically defined faults. The fracture study conducted by Agip estimated the average field fracture porosity to be 0.27 %. Concerning fracture characterization it is possible to highlight that: (a) (b) (c) (d) (e)
fractures are not distributed continuously and their distribution is complex; they are orientated subparallel/oblique/subvertical to bedding; most wells appear to be fractured towards the top of the succession; no single overriding fracture orientation exists; and, different orientations can occur at different levels.
The determination of a true oil-water contact is complicated in low permeability fractured reservoirs like Stirling. No R F T data are available and the determination of the oil-water contact comes from the interpretation of resistivity logs and from core analysis. At present for the central area of the field a contact at 8280 ft TVDSS is assumed. The volume of oil produced from the matrix is thought to be small in relation to the fractures. However, Stirling continues to produce steadily and longer than expected at low levels indicating probable contribution from the matrix within the later production phase.
P r o d u c t i o n and reserves
Balmoral In 1983 the Annex B STOIIP in the Balmoral Field was estimated between 180 and 235 MMSTB. This amount includes those portions of the field which extend into Block 16/21b (22.4 MMSTB). The base case forecast in 1983 assumed: 13 wells in production; six wells for water injection from the production start-up; 2.5 years
The Britannia Field, Blocks 15/29a, 15/30, 16/26, 16/27a, 16/27b, UK North Sea P. J. H I L L 1 & A . J. P A L F R E Y
2
Britannia Operator Limited, Royfold House, Hill o f Rubislaw, Aberdeen AB15 6GZ, UK 1 Present address." Conoco Phillips (UK) Ltd, Hill o f Rubislow, Aberdeen AB15 6GZ, UK 2 Present address." Chevron Texaco Overseas Petroleum, Southern Africa Business Unit, 4800 Fournace Place, Bellaire, Texas 77401, USA
Abstract: The Britannia Field is located 140 miles NE of Aberdeen at the southeast end of the Witch Ground Graben, on the southern flank of the Fladen Ground Spur. Gas and condensate are trapped in Lower Cretaceous (Aptian) deepwater, marine sandstones in a combined stratigraphic/structural trap that straddles four UKCS blocks. Reservoir quality varies from west to east across the field. The principal reservoirs in the west (Blocks 15/29a, 15/30) are in clean, blocky, high-density turbidite sands. The principal reservoirs in the east (Blocks 16/26, 16/27a, 16/27b) are in fine-grained sandstones and unusual slurried facies that have a high mud content and show gravity-driven structuring. The bulk of the field's reserves lies in the east and is produced via a 36-slot platform. A 14-slot sub-sea template tied back to the platform via a nine-mile flowline bundle produces the western area. Reserves are being developed by pressure depletion and are estimated at 3 TCF gas together with 131 MMBOE condensate and natural gas liquids. Britannia came on-stream in August 1998 and is expected to have a field life in the order of 30 years.
The Britannia gas and condensate field is located across Blocks 15/29a, 15/30, 16/26, 16/27a and 16/27b, 140 miles N E of A b e r d e e n in the U K sector of the Central N o r t h Sea (Fig. 1). The field lies in 450 ft of water a n d covers an area of 61 000 acres (250 square kilometres). Expected reserves are approximately 3 T C F gas and 131 M M B O E of condensate a n d natural gas liquids. The field is expected to supply 8 % of total U K winter gas c o n s u m p t i o n whilst on plateau. H y d r o c a r b o n s are trapped in L o w e r Cretaceous (Aptian), deepwater, marine sandstones in a p r e d o m i n a n t l y south-dipping structure with a stratigraphic pinch out to the north. Britannia O p e r a t o r Limited operates the field on behalf of co-venturers.
Exploration history Discovery The Britannia Field in the Central N o r t h Sea is part of the L o w e r Cretaceous, deep-marine, clastic play, which has h a d a long exploration history (Jones et al. 1999). Phillips well 16/27-1, drilled in F e b r u a r y 1975, tested a gas c o n d e n s a t e a c c u m u l a t i o n in L o w e r Cretaceous sands, which was christened 'Shirley'. Later that year, C o n o c o p r o v e d the presence of the play in Block 15/30 (Fig. la) with their ' L a p w o r t h ' discovery well 15/30-1. This f o u n d a L o w e r
Fig. la. Regional structural setting of the Britannia Field. Deep-seated lineations: SW-NE (Caledonian); NW-SE (Tornquist) and E-W, N-S (Variscan) define the essential structural framework of the area. The Britannia Field lies at the 'Triple Junction' between the Witch Ground, Central and Viking Grabens. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 415-429.
415
416
P. J. HILL & A. J. PALFREY
Fig. lb. Britannia Field outline and well database. The Britannia Field is produced from a 36-slot platform situated in Block 16/26 southwest of the tip of the Fladen Ground Spur and also via a N-slot sub-sea manifold to the south of the Axial High in Block 15/30. Lines of seismic section are shown together with E & A wells which penetrate the Lower Cretaceous section and older.
Appraisal
Cretaceous reservoir, which tested at 19.6 M M S C F G D of gas and 3065 B O P D of 47 ~ A P I condensate whilst drilling a Jurassic prospect. In 1976, Texaco m a d e the 'Bosun' oil discovery with well 15/29-2a a n d this led to the a d o p t i o n of the term 'Bosun Sandstone T r e n d ' for the L o w e r Cretaceous play as a whole. Finally the Transocean c o n s o r t i u m discovery well 16/26-2 in 1977, subsequently n a m e d 'Kilda', also p r o v e d h y d r o c a r b o n s in Lower Cretaceous rocks whilst en-route to a Jurassic target (Fig. l b).
Limited appraisal drilling in the 1980s met with varied success (Fig. 2). L o w e r Cretaceous sediments were poorly imaged on seismic data and it was difficult to predict the distribution of diachronous, deep-water sandstones across large geographical areas. Wells that were drilled in structurally up-dip locations often found thin sands, e.g. 15/30-3, 16/26-4 (Fig. lb). The patchy success, coupled with
w
•ogr -
2
~,
,,~
~
Single field delineation
,,~
,'-"
/ i
1
0
-
Fig. 2. Britannia Field - E & A drilling history by year. The initial Lower Cretaceous discoveries of the mid- to late 1970s, made whilst drilling Jurassic prospects, remained largely unappraised until the early 1980s. Wells 15/30-4 and 16/27b-4 in 1982 found either thin or no reservoir. The Lower Cretaceous play fell out of favour again, particularly after the discovery of the Alba Field which opened up the Tertiary potential of the area. A concerted drilling campaign in the early 1990s established that the reservoir would produce at economic rates and that the discoveries were linked in a single accumulation. Following equity determination, which was then fixed, project sanction was given in 1994 and field development began under the control of Britannia Operator Ltd.
BRITANNIA FIELD the discovery of the Alba Field by the 'Kilda' appraisal well 16/26-5 in 1984, resulted in the main exploration activity in the area shifting to the Tertiary plays. Renewed interest in the Lower Cretaceous discoveries was kindled by a string of successful appraisal wells in the late 1980s, e.g. 15/30-6, 16/26-16. These were drilled far enough down-dip to find thick, good permeability sands and also encountered hydrocarbon-water contacts. The further appraisal drilling of wells 16/26-21z and 16/26-23 proved that the 'Kilda' and 'Lapworth' discoveries were linked in a single accumulation with reservoir stratigraphic continuity. These wells also proved a common hydrocarbon contact ( - 1 3 154ft TVDSS) in both Block 15/30 and the western part of Block 16/26. Between 1990 and 1993, 3D seismic surveys were acquired over the four main blocks and merged into a single volume. Also in this period, Texaco proved the western limit to the field with gas well 15/ 29a-5 and Phillips proved the eastern limit with their 16/27a-6 well. Appraisal drilling was completed in 1993 with wells 15/30-10 and 16/26-24, both of which underwent extensive testing programmes. Development
Government sanction for field development was granted in 1994, following the agreement between the operators of Blocks 15/30 (Conoco) and 16/26 (Chevron) to develop the renamed single
417
accumulation by a jointly owned company, Britannia Operator Ltd. (B.O.L.). This co-operation in field development was and still is unique in a North Sea project. B.O.L. personnel are drawn from Conoco, Chevron and the major contractor service providers. A 17-well predrill programme was undertaken between 1995 and 1996 with two semi-submersible drilling rigs operating simultaneously at the two template locations. A 28 600 tonne steel platform was installed in Block 16/26, to which was tied a 750 tonne 14-slot sub-sea manifold in Block 15/30 (Fig. la). Installation of the facilities was undertaken from 1996 through 1998 with commissioning work ensuring that first sales gas was delivered on August 3rd 1998. Up to 800 M M S C F G D of dry gas is delivered via a dedicated 27" pipeline to the SAGE installation at St. Fergus and up to 50000 BOPD of condensate is exported via a 14" pipeline to Forties Unity.
Regional structure & tectonic history For the most part, the regional structural framework of the area where the Britannia Field is located had been established by the time of reservoir deposition (Oakman & Partington 1998). Deep-seated basement lineations (Fig. 1) running SW-NE (Caledonian), W N W ESE (Tornquist) and E - W / N - S (Variscan) were re-activated during the Mid-Cimmerian event (Fig. 3) of syn-rift thermal doming and
Kimmeridge Clay source in Witch Ground Graben goes into Gas Window. Britannia receives 2nd (condensate) charge.
Oligocene
4 Kimmeridge Clay source in Witch Ground Graben goes into Oil Window. Britannia receives 1st (oil) charge.
Eocene
<
Palaeocene Maastrichtian to Cenomanian
Onset of series of Tertiary inversions
Alpine Orogeny
Local structural inversion.
Austro-Alpine Event
Sola/Rodby shales seal Britannia Field reservoir. Regional subsidence.
Albian
Aptian
Onset of Britannia Field reservoir deposition into Witch Ground Graben.
Barremian to Berriasian
Austrian Event
North Sea Triple Junction fails. Tectonic stress regime changes from transtensional to transpressional
4~
Late Cimmerian Event
Upper Jurassic < Middle Jurassic
I
Sea Level
Onset of transtensional rifting. Witch Ground Graben begins I f~176
d I
Mid-Cimmerian Event
Fig. 3. Britannia Field - Tectonic correlation and geological history. Based on Ziegler (1990) and Knott et al. (1993). Major plate-wide tectonic events which influence reservoir deposition, trap formation and hydrocarbon charging of the field.
418
P. J. HILL & A. J. PALFREY
volcanism centred on the Forties Volcanic Province (Stewart 1999). Further re-activation during the phase of major regional extension during the Late Cimmerian event resulted in the formation of a complex, interconnected series of grabens and half-grabens separated by horsts and tilted blocks with relatively high structural relief (e.g. Halibut Horst and Buchan Graben). Of particular importance to the Britannia Field was the formation of the Witch Ground Graben which trends W N W - E S E (Fig. 1). Extension continued into the earliest Cretaceous times. Hemipelagic shales and thin limestones were deposited in the deepening waters of an open marine environment and infilled much of the rift topography in the Witch Ground Graben and also the nearby Viking and Central grabens. Beginning in Aptian times, the tectonic stress regime changed from E - W transtensional to N-S transpressional as the focus of Atlantic rifting moved west from the 'Triple Junction'. This was succeeded by the 'Austrian Event' (Fig. 3), the early effects of Alpine collision, which had commenced on the northern margin of the Tethys Ocean. The change caused rejuvenation of source areas at the basin margins and locally on intra-basin highs, resulting in the deposition of basin-slope sands that comprise the Britannia Field reservoir in the Witch Ground Graben. By early Albian times the sediment source areas had been sufficiently denuded for mud deposition to predominate, forming the shales
that seal the Britannia reservoir. Finally, late Cretaceous and early Tertiary deformation emphasized the structural component of the trap geometry seen today.
Geophysics The Jurassic prospects, which formed the initial exploration targets in the early 1970s, were defined originally on 2D seismic. Additional 2D seismic surveys were shot following the discovery wells until a multi-block 3D survey was acquired and processed between 1990 and 1993. The survey was reprocessed in 1999 to improve lateral and vertical resolution within the Lower Cretaceous section (Figs 4 and 5). Data quality is adversely affected by the presence of a thick chalk overburden (>2000 ft), which attenuates the high frequency element to approximately 30 Hz and reduces vertical resolution in the Lower Cretaceous to approximately 80 ft. Tertiary sands of the Alba Formation (Eocene) and Forties Formation (Paleocene) locally disturb the overburden velocities, smearing the imaging of deeper events. Limestones in the Lower Cretaceous Herring Formation also generate a seabed pegleg multiple, which occurs
Fig. 4. South-North seismic line across the Fladen Ground Spur in Block 16/26. The seismic data has a dominant frequency of approx. 30 Hz, which limits vertical resolution to about 80 ft. Data quality is affected by a 2000 ft. Chalk section above the Herring formation. Faults are poorly imaged and the lack of contrast between the Britannia reservoir and the underlying Valhall shales makes the basal reservoir pick problematic.
BRITANNIA FIELD
419
Fig. 5. South-North seismic section across the Axial high in Block 15/30. Major faults affecting the Base Cretaceous pick do not appear to cut the Top Britannia Sandstone event. The Britannia reservoir section expands into the Witch Ground Graben but the pinch-out to the north is poorly imaged and is established primarily by well control.
in the middle of the reservoir zone. The 'Top Britannia Sand' seismic pick also varies from west to east across the field with the reservoir geology. The ambiguities in the seismic data were only overcome by the appraisal drilling of the early 1990s, which proved that the 'Lapworth' and 'Kilda' accumulations were one field. Seismic interpretation shows that the Britannia Field lies on the southern flanks of two structural highs: the Fladen Ground Spur in Block 16/26 and a complex of tilted, Jurassic fault blocks in the centre of Block 15/30, informally termed the Axial High (Fig. 6). The Base Cretaceous TWT surface (Fig. 7) shows the complex network of faults resultant from the Mesozoic rifting of the preexisting Caledonide and Tornquist structural grain on the Axial High in Block 15/30. However, these large faults have little displacement at Britannia reservoir level (Fig. 8) and generally the structure appears to drape over the deeper topography both here and on the Fladen Ground Spur. The seismic data also suggests that gravity-driven processes affect the reservoir section. The suggestion that sediments may have been disturbed by slumping and sliding in the muddier parts of the Britannia section is imaged on seismic coherency and edge detection displays as areas of low trace-to-trace continuity (Fig. 9). The area of poorest coherency is to the west of the installation in Block 16/26 where the underlying Base Cretaceous surface falls away into the Witch Ground Graben and the total sediment thickness of the Lower Cretaceous section increases. Depth conversion is not a critical issue over much of the field. T W T v. depth linear functions are
used to give a range of predictions, which are then validated against local well results in the current development-drilling programme.
Trap A combined stratigraphic/structural mechanism forms the trap in the Britannia Field. To the north, a string of wells with little or no reservoir sands define a pinch-out line (Fig. 6). The pinch-out is imaged well by seismic data in the eastern part of the field but it remains enigmatic in the west, where there is no obvious seal between laterally equivalent sands containing Britannia hydrocarbons to the south and Bosun oil to the north (Fig. 10). Structural dip into a major syncline in Block 16/27 and up-dip facies degradation to non-pay sands in well 16/27a-7 form the trap in the eastern part of the field. Lower Cretaceous shales seal the Britannia Field vertically. The shales thin from west to east and the presence of shallow gas east of the platform in Block 16/27 may indicate an imperfect seal. The southern limit of the field is defined by the gas-liquid contact. The Britannia reservoir cross-section in Figure 10 shows a difference of almost 400 ft in hydrocarbon-water contacts across the field. The current interpretation of the variance in the initial gas-liquid contacts across the field implies the presence of different mechanisms contributing to apparent compartment boundaries.
Fig. 6. Britannia Field - Top Britannia Formation depth structure. The Britannia Field is primarily a stratigraphic trap with a structural component. Reservoir pinch-out is well imaged on seismic data across the Fladen Ground Spur but becomes enigmatic westwards in the northern parts o f Blocks 15/29a and 15/30 where it is established by well data. Maximum elevation is -11800 ft TVDSS in Block 16/26 and vertical elevation is over 1200 ft. The Britannia reservoir is cut by few faults resolvable on seismic. Reserves are estimated at 3 TCF gas and 131 M M B O E condensate.
Fig. 7. Base Cretaceous surface, colour-draped and illuminated from the southwest. The extensive faulting of older lineations on the Axial High is clearly shown. The throw of the faults is to the north. This degree of faulting has largely finished by the time of Britannia reservoir deposition which drapes across the high. Well 15/30-1 was spudded on the basis of a dip/fault closed Jurassic prospect and discovered gas in the Lower Cretaceous whilst drilling to TD.
BRITANNIA FIELD
421
Fig. 8. Britannia Sandstone surface, colour-draped and illuminated from the southwest. The draping of the Britannia reservoir over the Axial High is clearly apparent, with little evidence of major faulting affecting the surface. Poor reservoir, both in terms of quantity and quality in the 15/30-2, 15/30-3 and 15/30-4 wells may point to the Axial High having influenced reservoir deposition and distribution.
Major stratigraphic changes in the reservoir zones mark the change from the deep contact ( - 1 3 154ft TVDSS) in Blocks 15/29, 15/30 and the western part of 16/26 to that in the area around the production platform ( - 13 070 ft TVDSS). Structural changes may account for the further contact differences in the platform area and eastwards. Faulting associated with the N-S extension of the Fladen Ground Spur (Fig. l) may account for the apparent jump from - 1 3 0 1 4 f t TVDSS in the 16/26-B08 production well to - 1 2 760 ft TVDSS in 16/27a-6. The stratigraphy of the 16/27a-6 well is similar to that of the platform area (Figs 10 and 11). Whereas a faulted compartment boundary can be mapped with some confidence in this area, isolating some of the other potential compartments is more problematic. A lack of resolution in the seismic data usually impedes the identification of subtle faulting. Compartmentalization in the field seems to be in the aquifer and not the gas leg. Initial datum-corrected gas pressures were the same throughout field at 5990psia. (Fig. 12). Reservoir temperatures are higher in the east than in the west, 145~ as opposed to 129~ Fluids are also more saline to the east: well 16/27a-6 has over 100000ppm NaC1 as opposed to 17 000ppm NaC1 equivalent in well 15/30-9. Both sets of observations perhaps relate to the occurrence of salt, which is known to exist in this area (Andrew Field wells 16/27-1, 16/27a-2). Pressure data from one of the recent production wells is anomalous and may hint at the presence of other mechanisms affecting the observed contacts. Well 16/26-B13z was drilled to the east of the ridge between Blocks 16/26 and 16/27a in 1999 (Fig. 1a). Initial gas pressures encountered in the upper reservoir layers,
Zones 50 and 45, showed a 'depletion' of over 1000psia with respect to the reservoir pressure of 5990psia at the start of production in 1998. Aquifer pressures are higher in the east but are less depleted relative to the initial pressure (Fig. 12). Integrated reservoir studies and further data acquisition, both current and planned, will be necessary to arrive at a complete understanding of the contact differences in the field.
Reservoir Lithostratigraphy Johnson & Lott (1993) proposed the Britannia Sandstone Formation for localized sand developments from late Barremian to late Aptian age. However, the Lower Cretaceous lithostratigraphic scheme used for the Britannia Field (Fig. 13) is that of Ainsworth & Riley (1994) and Ainsworth et al. (2000), and differs somewhat from that of Johnson & Lott (1993) by being more field-specific. The term Sola Formation is retained for the dark grey, organic rich, non-calcareous shales, which lie above the light grey calcareous shales of the Valhall Formation. The Britannia Sandstone Formation sands are of mass flow origin, comprising deposits from high and low density turbidites, slurry flows and debris flows. Guy (1992) and Lowe & Guy (2000), document facies variability within the formation and describe the Britannia sandstones as being a relatively unique development of
Fig. 9. Coherency display of 3D Top Britannia Sandstone T W T surface and line of seismic section. Black and broken areas on the coherency display represent features (green circled) on the seismic section, i.e. small, slump/thrust faults at reservoir level (yellow horizon) in the platform area of Block 16/26.
Fig. 10. Britannia Field - Reservoir cross-section and hydrocarbon contact variations. The principal gas-bearing reservoir sands vary from west to east across the field being concentrated in the lower (Valhall) zones in the west and subsea centre, whilst in the upper (Sola) zones in the east. Some reservoir development is restricted, e.g. Zone 7 in the subsea area and Zone 10 in the platform area. Zone 30 shales are developed in the west but are absent east of the midfield area. Hydrocarbon-water contacts also become shallower to the east, with a variation of over 400 ft across the field. An oil ribbon, up to 100 ft thick exists in the west, lying in Zone 20 sands. The oil ribbon becomes discontinuous eastwards and in the platform area, gas is in direct contact with water in Zone 20 sands.
BRITANNIA
FIELD
423
Y= ==
[..
8
S ,...,, ,,.a
O
a ...a
8
o
;>
S
o
rae~ O
8~
-a
424
P. J. HILL & A. J. PALFREY
Fig. 12. Britannia Field - Discrete initial reservoir pressures plotted against TVDSS. Gas and water gradients are constant although their intercept, and hence hydrocarbon-water contact, shallows from west to east.
deposits. They include assemblages of sandstone beds deposited by a variety of depositional flow types, ranging from turbidity currents to debris flows with a spectrum of intermediate types termed 'slurry flows' and which represent sand-rich liquefied flows.
High density turbidite deposits. High-density turbidity (HDT) currents deposited thick, clean, fine to medium grained sandstones which have a low mud content and show dish-structuring. They correspond to $3 sands (Fig. 14) described by Lowe (1982) and form an important reservoir facies, primarily in Zone 20 in the west of the field. Most beds are greater than 10 ft in thickness with a maximum development of up to 120ft in amalgamated units. Typical mud contents average 8-10%. The mud tends to be redistributed during dewatering processes to become concentrated on dish structures. Permeabilities may reach 100 mD with an average of 60mD. Porosities average 15%. Nanded slurryflow deposits. The majority of gas-in-place is located in Zones 40, 45 & 50 in the east of the field. These pay facies are interpreted to be the deposits of slurry flows (Lowe & Guy 2000). They contain a high proportion of mud content (10-35%) and exhibit unusual primary depositional sedimentary features. Typically, individual elements appear as sequences of light and dark banded couplets. The couplets vary in scale, depending on initial mud concentration, from millimetre-sized microbands to decimetresized megabands (Fig. 14). They then have unusual water-escape features superimposed on the primary depositional fabric. In some instances, particularly in the zone 50 sands, the banded elements are
capped by 'mixed slurried' sediments, which progressively fine up into turbiditic and then hemipelagic mudstones. The 'mixed slurried' sands result from a decrease in overall sediment grain size and are the muddy fall-out from the main depositing flow. The mud content remains entrained within the unit rather than fractionating during deposition (Fig. 14). The banded slurry units amalgamate into beds, ranging from 3ft to 140ft, with most being 12-40ft thick. They exhibit porosities averaging 15% but have reduced permeabilities relative to HDT deposits, reaching a maximum of 60 mD with an average of 30 mD.
Debris flow deposits'. Debris flow deposits and heterogeneous mixed slumps and slide masses are present throughout the Britannia Formation and are clear evidence for post-depositional flow reworking. They are most common within mudstone layers in Zones 40, 45 and 50. Debris flow deposits are locally responsible for changes in intrabasinal topography, controlling accommodation space and therefore influencing the areal extent of subsequent sand deposition and associated sand body thickness. The debris flow deposits themselves range in thickness from a few inches to over 15 ft and typically have poroperm characteristics which render them non-pay
Other lithofacies. Low-density turbidites (Bouma Tc-Te divisions), volcanic ashes and both hemipelagic and turbiditic shales complete the range of primary depositional lithofacies seen in the Britannia Sandstone Formation.
BRITANNIA FIELD
425
Lithostratigraphy Johnson & Lott (1993) Ainsworth & Rile~, 1994 Turonian
Plenus Marl Formation
Early Late
Cenomanian
Albian
Plenus Marl Formation o "= eu
H3
H2
~"
H2
H1
~
H1
~ m
H3
Middle
~. e
Early
~
E
Upper Late Rodby i FormaUon I Lower Middle nodby Formation Upper Early Sola Formation Late
Sola Formation
E
R4 R3 R2
o "= ea ~ ~ ~ ~ ~
R1 $4
$3 $2
~ ~,
~ ~
!
GR
J
~
Z
0
is4
' ," ,
45
KP6B
~~'---~m-~
~
/
S1
**
Carrack Formation
KF2
"r34~ mma, KPSA "_v~ "v~
50
,
R1
z ~
s2 "fi4 "~gl
, #,9 **
82
Z
16/26-21 Type Log
,d t#
R3
Z
o*
BNI KF3A BN2
~'7~a" ~,'
"s~3~
Aptian S1
V4
Early
,-1
I
Late Barre~a.
Middle
.~., =
Ewaidi Marl
~ ~ -" ~
V4 I I Fischschiefer V3D V3C V3B
Blatterton
Early
.
20
.
V7
V4 =K~7~E, BN4C , n . v,n "sTu~'
~'~ ~
"
..,~ iiI
~
]o
.~ ~~ "~
V6 V5
~
V4
~J"
7
V3 Munk Marl
V3A
.
~
7 ] ~ ~ ' ~
*,~
-
V3
'~'~,,
. "*r
Ewaidi~9A : BN4D1
Marl " =' ,m i,. m m KF3D KPgB BN5
_ . .. FischK~II~ ~N6~ "KF4 V4 =I~I~' sch~e j ~I~ ,... KPI2 BN6C V3D "K~! KF5 ... BtqTA~ . . KPI4A~ --==--~r ~ Kr6 ~o,=1~c " ~ v3c .'~t~ , - Kin6 B~ V3B KIP17 BNIO
Fig. 13. Britannia Field - Reservoir correlation. The lithostratigraphic correlation is based on Ainsworth & Riley (1994) and is more field-specific than Johnson & Lott (1993). Extensive coring has allowed detailed zonation of the reservoir section.
Biostratigraphy Well 16/26-21 provided core through several hundred feet of shale with thin sands and allowed the establishment of three separate biostratigraphic schemes based on palynology, calcareous nannoplankton and micropaleontology (Fig. 13). Data are more detailed for the Valhall equivalent section where taxa are less long ranging than in the overlying Sola Formation. Calcareous nannoplankton are much more common in the Valhall Formation and have proved to be useful in sand body correlation in the western part of the field.
Sequence stratigraphy Attempts to fit the Britannia Sandstone Formation within a sequence stratigraphic framework (e.g. Oakman & Partington 1998) are difficult. Although major carbonate units such as the Ewaldi Marl (Fig. 13) may be traced across northwest Europe and may represent regional maximum flooding surfaces, the influence of global sea level changes on sand supply is more difficult to unravel from more local events. Sediment supply was influenced by several Jurassic structural highs. Accommodation space was influenced by local tectonism, gravity-driven deformation and by basin-floor topography resulting from sand and debris-flow deposits within the
Britannia Sandstone Formation. Bed correlations in the platform and sub-sea areas reveal the restricted nature and extent of some of the sand bodies.
Coring Core has been the single most important tool for establishing the geological model of the Britannia Field and has been extensively studied by utilizing a database in excess of 20 000 ft from over 30 cored wells. Core measurements provide the most reliable indicator of permeability and 13 out of the 17 pre-drilled production wells were cored to allow estimation of initial well delivery capacity during the drilling campaign. The Britannia Field has had a contractual requirement to deliver a fixed volume of gas from startup and coring offered the most certain means of ensuring that production from the pre-drilled wells would be sufficient to meet this obligation.
Reservoir zonation The Britannia reservoir zonation scheme (Fig. 13) is based primarily on biostratigraphic zonation schemes in the Valhall Formation
426
P. J. H I L L
& A. J. P A L F R E Y
94"-'
0
9 ~.~
-4~
IF o
0
I
..=j
0
..=
"
e~
,m 83
o
"4 o '4~, 9 9
N
"a
f_)
"a
o
o
9 ,,..4
~
o
~2
o
o
9.4
~ -
~
~
~ g~ ~ ,S,
. ,...~
o
9
,4
BRITANNIA FIELD and on more limited biostratigraphy coupled with lithostratigraphy in the Sola Formation, especially the use of ash bands. In the west the main reservoir sands (Figs 10 and 11) are located in the lower reservoir Zones (7, 10 and 20), whilst in the east the main reservoir sands are located in the upper Zones (40, 45 and 50).
Zone 7. This zone equates to the Valhall V3D. It is late Barremian to earliest Aptian in age and is generally sand-free. However, where sands do exist in the western part of the field (Block 15/30) they form excellent reservoir units with high permeability (up to 120 mD).
Zone 10. This zone is early Aptian in age and encompasses the Fischschiefer and lower half of the Ewaldi Marl (lower Valhall V4). The zone contains the first major influx of sand into the basin, primarily derived from the Fladen Ground Spur.
Zone 20. This zone contains the upper half of the Ewaldi Marl and the remainder of the Valhall V4. Calcareous nannoplankton zonation is used to mark the transition from the calcareous shales of the Valhall Formation to non-or slightly calcareous low-density shales of the Sola Formation which occurs at the top of Zone 20. Shales in the upper part of this zone are commonly stained red, due to the presence of haematite. In the eastern part of the field (Block 16/26), Zone 20 contains several apparently isolated and uncorrelated sand bodies. In the west, Zone 20 is the major reservoir unit containing thick, clean high-density turbidite deposits. All current data supports sediment derivation from local highs to the north of the basin, which may have involved storage and re-working of sands on and around the Axial High.
Zone 30. Zone 30 is only defined in the western part of the field and disappears in the east where the equivalent section is denoted as lower Zone 40 (Figs 10 and 11). Zone 30 contains occasional sands in a characteristic lithofacies development of thin-bedded turbidites, ash bands and shales.
Zone 40. Zone 40 is the only zone defined on purely sedimentological criteria, occurring in the east of the field where Zone 30 is absent. It contains thick, well-correlated sands that generally show slight normal grading; have blocky to upward cleaning tog profiles; are sharp topped; but are of varying sand facies types. These criteria are used to differentiate them from the overlying Zone 45 sands and allow the subdivision of an otherwise thick sand succession in the east of the field. Zone 40 sands are thought to be confined flows of small lateral extent. Petrographic data suggests a southern source for the Zone 40 sands, although evidence of a northern source area is also noted.
Zone 45. Zone 45 sands show strong normal grading and fine upwards into mud. The top of the zone is taken as the uppermost of two prominent ash bands. In the east of the field, this also coincides with the base of the lowermost sand in Zone 50. Zone 45 contains the largest proportion of gas in place in the field, concentrated in the area below the platform in Block 16/26. In the east of the field Zone 45 contains sheet-like flows which are predominantly sourced from the southeast. The exceptions are the uppermost beds, which apparently are sourced from the north and indicate a change in depositional regime. In the west of the field, Zone 45 contains sheetlike flows sourced from the north and the youngest sand forms the Top Britannia Sandstone seismic marker (Fig. 5).
Zone 50. The Sola S1 ash band defines the top of the uppermost zone of the Britannia Sandstone Formation. In the east, the zone is sand-prone with well-correlated sheet-like sands, the uppermost of
427
which forms the Top Britannia Sandstone Formation seismic marker (Fig. 4). The sands are derived from the Fladen Ground Spur to the north and extend from Block 16/26 through to Block 16/28 beneath the Andrew Field. Blocks 15/29a and 15/30 in the west of the field have a largely mud-prone Zone 50 development.
Source The Kimmeridge Clay Formation is the hydrocarbon source for Britannia. The field overlies the deepest, eastern part of the Witch Ground Graben where presently the Kimmeridge Clay is mature for light oil and gas. Short path, vertical migration routes are invoked, with charging via small, subtle faults that link the Kimmeridge Clay with the Britannia sands. To the east of the Britannia Field, the Kimmeridge Clay deepens into the Fisher Bank Basin/Central Graben and may provide a component of gas charge via longer distance migration routes. Oil window maturity and subsequent migration occurred during post-Paleocene times. Residual oil staining indicates the Britannia Field has had at least two phases of hydrocarbon fill. Most likely an initial oil charge filled the early structural closure in the Early Eocene (Cole & Turner 1997), followed in post-Oligocene times (Robertson Research International 1985a, b) by a gas condensate charge, possibly displacing the oil to the Alba sands in the Eocene section above. In the west of the field, a continuous oil ribbon up to 100 ft thick underlies the gas. The oil ribbon becomes discontinuous eastwards and drops to below 30ft in thickness close to the platform. The low relative permeability of the Britannia Sandstone Formation to oil prevents the latter from being a viable production target. Additionally, the creation of asphaltenes as the oil phase reacts with condensate can cause restrictions in the sub-sea completion facilities.
Reserves and production Reserves
Reserves are estimated at 3 TCF gas and 131 MMBBO condensate and natural gas liquids. These figures have remained constant even after pre-drilling 17 wells, indicating a robust geological model in the main part of the field. Wet gas in place (condensate in vapour phase) is calculated to be 4.6 4- 0.7 TCF, with net reservoir cut-offs of 0.1 mD permeability, 10% porosity and a conservative geological risk applied to the undrilled areas.
Pre-drilled production wells
Production from pre-drilled wells was estimated using probabilistic methods prior to first gas (Diamond et al. 1996). Key uncertainties at the start of production were: 9 9 9 9
the impact of condensate banking on well productivity; effective permeability and it's relation to core permeability; compartmentalization effects; and gas-in-place in undrilled areas
Condensate banking and effective permeability uncertainties were identified as key issues in the pre-production phase of the project because of the overall fine-grain nature of the reservoir rocks and the possibility that condensing liquids would choke the pore throats as the reservoir pressure decreased. These have proved to be less of a problem than anticipated and generally good reservoir performance has been experienced. A suite of modelling studies (Jones et al. 1999) showed that compartmentalization is not an issue in an area of high net-gross sand, such as that which the pre-drill wells have penetrated. Field production data gathered since first gas shows real production
428
P . J . HILL & A. J. PALFREY Pay zone Formation Age Gross thickness Net/gross ratio Porosity
Permeability
Fig. 15. Britannia Field - Actual v. predicted well production. Platform area wells are producing at just below predicted levels (Diamond et al. 1996) whilst the subsea area wells are exceeding pre-production forecasts. B2 and B6 have yet to be brought on production. High-angle well B9Z may have encountered a thinner reservoir section affected by faulting.
levels to be similar to the predicted P50 level in general. Well p r o d u c t i o n rates are generally better in the sub-sea centre than in the platform area (Fig. 15).
Improving well productivity The attractiveness of drilling wells other than those of the 'conventional' type to improve productivity has yet to be solved. High-angle well 16/26-B9z e n c o u n t e r e d a disappointing reservoir section in which key sand beds in p r o d u c i n g Zones 40 and 45 were absent (Fig. la). Well 16/26-B11 was a b a n d o n e d for hole-stability reasons and the sidetrack was drilled as a 'conventional' well. Wells 16/26-B2 and 16/26-B6 were fractured to overcome poor reservoir properties but not yet on-line due to processing difficulties and operational priorities. The success of the 'conventional' wells is attributed to good drilling and completion practice with minimal f o r m a t i o n d a m a g e (negative skins), which has c o n t i n u e d with the m o r e recent (post 1st gas) wells.
Future production wells At the time of writing (1999), thirteen of the of planned p r o d u c t i o n wells had been completed. F u t u r e wells will be balanced between low-risk, near-platform producers and higher-risk, longer step-out p r o d u c t i o n / a p p r a i s a l wells into the large undrilled areas to the east and south of the platform with the aim of extending plateau life. The authors would like to thank Steve Garrett, Ditta Neumann, Stuart Archer and Mike Donovan at B.O.L. for their help in the preparation and review of this manuscript and to the external reviewers for their comments and suggestions. Thanks are also due to the co-venturers, Conoco UK Ltd., Chevron UK Ltd., Arco British Ltd., Philips Petroleum Co. UK Ltd., Saga Petroleum UK Ltd. and Texaco Ltd. for permission to publish this paper.
Britannia Field data summary Trap Type Depth to crest Gas-water contact Gas column Oil column
Combined stratigraphic/structural 11 800 ft TVDSS Variable, 12 760 to 13 154ft TVDSS Variable, West 1000 ft, East 1250 ft Variable, 0-85 ft
Britannia Lower Cretaceous (Aptian) Range 100-600 ft (average 250 ft) Variable, 12-30% West, 28-58% East Range 0-20%, average 15% (net pay > 10%) West Range 0.1-800 mD, average 60 mD (net pay > 0.1 roD) East Range 0.1-400 mD, average 30 mD (net pay >0.1 mD)
Hydrocarbons Gas saturation Gas type Condensate yield
68% Wet gas Average 65 BBL/MMSCFG (Initial)
Formation water Salinity Resistivity
17 000-100 000+ ppm NaC1 eq. 0.04- 0.11 Ohm m
Reservoir conditions Temperature Pressure Dew point
West 129~ East 145~ 5990psia at start of production 5600 psi
Field size Area IGIIP/reserves 4.6
Drive mechanism Production First gas Development scheme
Number of wells Plateau rate Field life
61000 acres TCF (wet gas)/3 TCF (dry gas) and 131 MMBBL condensate and NGLs Pressure depletion
1st August 1998 36 slot platform in Block 16/26 14 slot subssea tieback in Block 15/30 19 gas/condensate producers to date. Approx. 22 additional wells planned 800 MMSCFGD/50 MBOPD condensate Approx. 30 years
References AINSWORTH, N. & RILEY, L. 1994. Britannia Field Stratigraphic Study, U.K. Blocks 15/29, 15/30, 16/26 and 16/27. Chevron Internal Report. AINSWORTH, N., RILEY, L. A. & GALLAGHER, L. T. 2000. An Early Cretaceous lithostratigraphic and biostratigraphic framework for the Britannia Field reservoir (Late Barremian-Late Aptian), UK North Sea. Petroleum Geoscience, 6, 345-367. COLE, J. & TURNER, J. 1997. The Maturation History of Oil-Prone Source rocks in the Moray Firth Rift Arm and the Central North Sea. M.Res. thesis, University of Edinburgh. DIAMOND, P. H., PRESSNEY, R. A., SNYDER, D. E. & SELIGMANN, P. R. 1996. Probabilistic prediction of Well Performance in a gas condensate reservoir. Society of Petroleum Engineers 36894. Paper presented at European Petroleum Conference, Milan, Italy 1996. GuY, M. 1992. Facies analysis of the Kopervic sand interval, Kilda Field, Block 16/26, UK North Sea. In: HARDMAN, R. P. F. (ed.) Exploration Britain." geological insights for the next decade. Geological Society, London, Special Publications, 67, 187-220. JOHNSON, H. & LOTT, G. K. 1993. 2. Cretaceous of the Central and Northern North Sea. In: KNOX, R. W. & CORDEY, W. G. (eds) Lithostratigraphic nomenclature of the UK North Sea. British Geological Survey, Nottingham. JONES, L. S., GARRETT, S. W., MACLEOD, M., GuY, M., CONDON, P. J. & NOTMAN, L. 1999. Britannia Field, UK Central North Sea: Modelling Heterogeneity in Unusual Deep Water Deposits. In: FLEET, A. J & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5 th Conference. Geological Society, London, 1115-1124. KNOTT, S. D., BURCHELL, M. T., JOLLEY, E. J. & FRASER, A. J. 1993. Mesozoic to Cenozoic plate reconstructions of the North Atlantic and
BRITANNIA FIELD hydrocarbon plays of the Atlantic margins. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 953-974. LOWE, D. R. 1982. Sediment Gravity Flows II: Depositional Models with specific reference to the deposits of high-density turbidity currents. Journal of Sedimentary Petrology, 52, 279-297. LOWE, D. R. & GuY, U. 2000. Slurry-flow deposits in the Britannia Formation (Lower Cretaceous), North Sea: A new perspective on the turbidity current and debris flow problem: Sedimentology, 47, 31-70. OAKMAN, C. D. & PARTINGTON, M. A. 1998. Cretaceous. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea - basic concepts and recent advances' (4th Edition). Blackwell Science, Oxford, 294-349.
429
ROBERTSON RESEARCHINTERNATIONALLTD 1985. The Clastic Reservoirs of the Inner and Outer Moray Firth areas, UK North Sea. Robertson Research International, Llandudno ROBERTSON RESEARCH INTERNATIONALLIMITED 1985. Stratigraphy, Petroleum Geochemistry and Petroleum Geology. In: The Moray Firth Area, North Sea. STEWART, S. A. 1999. Mid-Jurassic volcanic structures in the Outer Moray Firth Basin, UK. Journal of the Geological Society, London, 156, 487-499. ZlEGLER, P. A. 1990. Geological Atlas of western and central Europe, 2nd Edition. Shell Internationale Petroleum Maatschappij b.v./Geological Society, London.
The Captain Field, Block 13/22a, UK North Sea S. J. P I N N O C K Updated
1 & A . R . J. C L I T H E R O E
2'3
b y P. T. S. R O S E 2'4
1 Texaco Ltd., 1 Westferry Circus, Canary Wharf, London E l 4 4HA, UK Present address." EDCO Oil & Gas Ltd, 39 Portman Square, London, W I H 6LS, UK 2 Texaco Ltd., Langlands House, Huntly St., Aberdeen, ABIO 1SH, UK (e-mail
[email protected]) 3 Present address: ChevronTexaco Upstream Europe, Seafield House, Hill of Rubislaw, Aberdeen AB15 6XL, UK 4 Present address." Landmark E A M E Ltd, Wellheads Crescent, Dyce, Aberdeen AB21 7GA, UK
Abstract: The Captain Field is located in Block 13/22a in the Western Moray Firth Basin of the UK North Sea, 80 miles NE of Aberdeen in a water depth of 340 ft. Hydrocarbons are trapped in two geographical regions, the Main and Eastern closures, both with a significant stratigraphic pinchout component. The principal reservoirs consist of turbidite sandstones of Lower Cretaceous age which have been informally subdivided into two stratigraphic units comprising the Upper and Lower Captain Sandstones. At the base of the preserved Jurassic section the Heather Sandstone, Oxfordian in age, provides a secondary reservoir. Reservoir quality is uniformly excellent in the Lower Cretaceous with in situ, Klinkenberg corrected permeability averaging 7 Darcies and porosity in the range 28-34%. The reservoir is generally poorly consolidated sandstone with the depth to the crest of the field at -2700 ft TVDss. The reservoirs contain a total oil-in-place of 1000 MMBO. The Upper Captain Sandstone has a small associated gas cap containing 16 BCF gas-in-place. The oil is heavy, by North Sea standards, with oil gravity ranging from 19~ to 21 ~ API and has high in situ viscosity, 150 to 47 cP, at the mean reservoir temperature of 87~ The fluid properties and offshore location necessitate the employment of innovative horizontal drilling methods, completion design and artificial lift technology in order to achieve an economically viable field development. Extended reach horizontal wells, with reservoir completion lengths of up to 8000ft, are drilled for all oil producers and water injectors. Development risks were significantly reduced following two appraisal drilling campaigns in 1990 and 1993 culminating with the successful drilling and extended testing of a prototype horizontal field development well (13/22a-10). The field is being developed in two phases, Area A and Area B. First oil production commenced from the Captain platform in March 1997 from Area A and the field now produces at between 50 000 and 70 000 BOPD. Area B development is now underway with first oil planned for December 2000. Completion of this phase of the development will increase the plateau production rate to 85 000 BOPD.
T h e C a p t a i n Field is located o n the western m a r g i n o f the H a l i b u t H o r s t ( C a p t a i n Ridge) in the W e s t e r n M o r a y F i r t h region o f the U K N o r t h Sea (Fig. 1). T h e field c o m p r i s e s a three-way dip closed structure a n d s t r a t i g r a p h i c p i n c h o u t trap. T h e principal reservoir
consists o f turbidite s a n d s t o n e s , i n f o r m a l l y referred to as the U p p e r a n d L o w e r C a p t a i n S a n d s t o n e . V a r i a t i o n s in relief o f closure across the s t r u c t u r e c o m b i n e d w i t h internal reservoir d i s t r i b u t i o n lead to the f o r m a t i o n o f three s t r u c t u r a l regions w i t h i n the field ( M a i n ,
Fig. 1. Structural setting of the Western Moray Firth Basin (after Roberts et al. 1990) showing the location of the Captain Field and regional distribution of the Captain Sandstone Member (from Rose 1999).
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 431-441.
431
432
S. J. P I N N O C K & A. R. J. C L I T H E R O E
o
9
o
ea~
,.s=
O
+..;. C,.) o [.., e,i
CAPTAIN FIELD
UTII0m'IMW m~
J
|,
[
::;:; - l
[
:: ( l
1
"
I W N
1
|-
-
:|!
o 9
r
HI
tl~
t,u -
-
FJR.Y
-
o
,.
~
~.
L 9
,
"o
J
9
m
:: 1!
'i w
Fig. 3. Jurassic and Lower Cretaceous stratigraphy, Captain type well 13/22a-7.
Eastern and Southern Terrace, see Fig. 2). The Captain Sandstones are Late Aptian in age (Fig. 3) and are poorly consolidated, exhibiting excellent porosity and permeability (Table 1). The OxfordianKimmeridgian Heather Sandstone Member provides a secondary reservoir (Fig. 3). The accumulations are large with a combined STOIIP of 1000 MMBO. Although the field was discovered in 1977 the viscous nature of the crude oil inhibited earlier economic development. However, advances in horizontal drilling technology during the 1980s prompted a full and detailed re-evaluation of the discovery, leading to extended appraisal programmes in the early 1990s. Captain is one of the first offshore fields in the North Sea to be developed exclusively with horizontal wells. A well-head production platform was installed over the western part of the field (Area A, Fig. 4) in the summer of 1996 and tied back to a floating production, storage and off-loading vessel, initiating production from the Captain Field in March 1997. The eastern part of the field, Area B (Fig. 4), is currently under development with first oil production planned for December 2000. Development of Area B will increase the Captain Field fluid processing capacity with construction of a bridge-linked processing platform next to the Area A wellhead platform. This paper updates Pinnock & Clitheroe (1997) which documented the Captain Field history up to the initiation of the development phase.
History Texaco North Sea UK Limited acquired a 100% interest in Block 13/22 through the fourth UK Round of licensing in March 1972. The original licence, P237, which also included Blocks 14/20, 15/7, 15/16, 15/23 and 20/5, underwent a 50% relinquishment in March
433
1978. This saw Texaco's holding in 13/22 reduced to the area around the present day Captain Field. Following the development of the Tartan and Buchan fields, on Blocks 15/16 and 20/5 respectively, the licence was reassigned to P324. The Captain Field lies wholly in part Block 13/22a, operated by Texaco North Sea UK Company. The field was interpreted to extend into Block 13/17, and on this basis Texaco was awarded licence P809 in the 1994 Fourteenth UK Round. Subsequent evaluations of appraisal well data questioned this assumption and the 13/17 licence was relinquished in 1999. In April 1997 the Korea Captain Company Ltd, a joint venture between the Korean National Oil Company and Hanwha Energy Inc., acquired a 15% interest in the Captain Field. The Captain Field was discovered in 1977 by the drilling of the wildcat exploration well 13/22-1. Although over 200 ft of oil column was encountered the well failed to flow during a conventional well test. Subsequent evaluation of reverse-circulated oil samples showed the accumulation to consist of a relatively heavy oil (19 ~API) with an estimated viscosity, at reservoir conditions, of up to 200 cP. Due to unfavourable water mobility, and the potential for early water breakthrough and high water cut from prospective vertical or normally deviated production wells, economic development was considered to be highly problematic at that time. However, later advances in horizontal drilling technology through the mid 1980s, led to consideration of alternative options for development of Captain. An initial appraisal programme was undertaken during the period 1989 to 1990, with the drilling of six wells. The first of these, vertical well 13/22a-2, successfully production tested the accumulation at 740 BOPD from 60 ft of perforated interval, the oil being lifted by an electrical submersible pump (ESP). Subsequent vertical wells 13/22a-3, -5, -6 and -7 partially appraised the Main area of closure (Fig. 2). Well 13/22a-8 was drilled and completed with a 1000 ft horizontal section, in the Lower Captain Sandstone reservoir, and demonstrated the feasibility of drilling and completing horizontal wells in the poorly consolidated reservoirs. The well was pumped at 6600 BOPD, the rate being restricted by the surface test equipment. Following evaluation of the 1990 well results, and the processing and interpretation of the full field 3D seismic survey acquired in that year, the commercial viability of the field was established. The subsequent ambitious 1993 appraisal drilling campaign was designed to further delineate the Main area of closure, explore the Eastern area of closure, carry out a water coning test, and to drill and perform a long term production test from an extended reach horizontal well. The geological results of this programme confirmed the size of the Cretaceous accumulation together with the discovery of oil in the Heather Sandstone Member at the base of the local Jurassic section. The 90 day production in 13/22a-10 demonstrated that high productivity was achievable (150 bbls/psi/day PI) and on this basis a design rate of 15 000 BOPD was thought to be reasonable for Captain horizontal development wells. These positive results enabled the development to proceed, and ultimately, the submission of the field development plan in 1994. Field development has been phased because of the requirement for at least two drilling centres to effectively develop and produce all currently proven hydrocarbons. The initial development area, denoted Area A and covering the western sector of the Captain Field (Fig. 4), contains a Central manned drilling and Production Facility (CPF). The CPF comprises a Well-head Protection Platform (WPP), installed in August 1996, tied back through a suite of pipelines to a Floating Production, Storage and Oflloading vessel (FPSO) from which crude oil is exported by shuttle tanker. A drilling template was installed in 1995 and seven Area A development wells were successfully drilled that year using a semi-submersible drilling rig to allow earliest plateau production to be achieved. Since platform installation a further 13 development wells had been drilled by January 1999. First oil production from the Captain Field was established in March 1997. After early teething problems with the water supply and water injection systems, between 50 000 and 70 000 BOPD have been produced from the field. The engineering aspects of the Area A development are discussed by Pallent et al. (1995), Etebar (1997), Lach (1997), Tavendale (1997), Cohen (1997), Cohen & Dallas (1997) and Sutton (1997).
434
S.J. PINNOCK
& A. R. J. C L I T H E R O E
O
.fi 9
o
o
o
kI,
c.,.) '4
CAPTAIN FIELD Exploitation of Area B the eastern sector of Captain (Fig. 4), will comprise the second stage, and is an integral part of the development. The area B wells will be drilled from a sub-sea template tied back to a new processing platform bridge-linked to the Area A drilling platform. It is planned to lift oil in the sub-sea wells using hydraulic down-hole pumps, the first field-wide application of this technology in the North Sea. Hydraulic pumps are being used to mitigate the perceived inherent unreliability of electrical motors and for their superior gas handling capacity. The latter point is of key importance to the Area B development as the oil is overlain by a free gas cap over much of the area. The Area B facilities are currently under construction with a planned start up date in the 4th Quarter 2000. Completion of these facilities will increase peak oil production capacity to 100000 BOPD from a current design of 60 000 BOPD. Water handling capacity will increase from 230 000 BWPD with the Area A facilities to 400 000 BWPD after development of Area B.]
Field stratigraphy The stratigraphic succession within the Western Moray Firth Basin was influenced by the intermittent activity of a series of major fault systems. Basin formation began in the Permian (Roberts et al. 1990), in response to N-S orientated extensional forces. Evolution of the basin continued into the Jurassic, with the creation of a complex series of smaller basins by rotational block faulting under an extensional regime (Underhill 1991). Jurassic sediments are absent across the crest of the Halibut Horst, confirming this as a positive feature for most of this period. The Captain Ridge, the westerly extension of the Halibut Horst, was an important Jurassic footwall crest. The Jurassic forms a thickening wedge to the north and dramatically thickens to the south in the West Halibut Basin. Seismo-stratigraphic interpretation indicates that Lower Cretaceous sediments on-lap the Upper Jurassic section over the main structural highs in the Western Moray Firth Basin. Wedge-shaped fault aprons of early Lower Cretaceous sediment occur along the hanging walls of the major faults within the basin and are unconformable with respect to the underlying strata. It is inferred that major block rotation during the Upper Jurassic was followed by infilling of the basin topography during the Lower Cretaceous, without further significant tectonism. The overlying Chalk Group was deposited from pelagic suspension fall-out during a period of relative tectonic quiescence, and draped the Lower Cretaceous sea floor topography. Subsequent Tertiary uplift of the western-most portion of the Moray Firth Basin led to erosion of the Chalk Group and the Tertiary to the west of the Smith Bank Graben (see Fig. 1 for location). The type well for the stratigraphy of the Captain Field is 13/22a-7 (Fig. 3). This well was drilled to a total depth of 3950 ft and encountered sediments from Tertiary to Devonian in age. The pre-Chalk Mesozoic section comprises a condensed series of interbedded sandstones and shales lying unconformably on the Devonian. No remnant Permo-Triassic section is preserved across the Captain Field, although it is well developed to the north on the Smith Bank High, leading to the interpretation that the Captain Ridge was a positive feature at that time. Several unconformities occur within the Mesozoic succession on the Captain Ridge, again confirming this as a long lived structural high. The Upper Jurassic Heather Sandstone Member varies from Lower Oxfordian to Kimmeridgian in age. The diachronous nature of these sandstones across the field area can be demonstrated from the high density of well control; the oldest beds occurring in the west. This supports the regional Moray Firth Basin on-lap trend for basal Upper Jurassic sands (Underhill & Partington 1993), although it is likely that the ridge plunged westwards more steeply than the overall regional dip, allowing the rapid local diachroneity. The Heather Sandstone Member is interpreted to reflect a transgressive retrogradational package of shallow marine sandstones that form the basin margin equivalents of the more basinal, shale prone, Heather Formation. The sandstones are typically fine-medium
435
grained, becoming coarser grained towards the east, and contain a significant silicified sponge spicule component. Seismic interpretation suggests these sandstones represent pre- to early syn-rift deposition across the Captain Ridge and are capped by syn-rift deep marine Kimmeridgian shales. The Kimmeridge Clay Formation is attenuated and condensed in the area of the Captain Field and consists primarily of silty claystones, although one turbiditic sandstone unit is locally developed in the Mid Volgian. The Jurassic succession has been progressively eroded eastwards along the Captain Ridge by the Base Cretaceous Unconformity such that only a thin, remnant (Kimmeridgian shale) section is preserved in well 13/22a-3. The Lower Cretaceous interval records the passive infill of the half graben topography formed by basal Cretaceous tectonism. Again, the Captain Ridge formed a structural high, plunging to the west. The oldest and thickest Lower Cretaceous section occurs in the northwest of Block 13/22a with the westerly plunging ridge onlapped progressively eastwards. Early Hauterivian sands occur to the west whilst the Lower Cretaceous in well 13/22a-3 to the east is represented only by Late Aptian shales. The basal Cretaceous sands which initiate onlap of the Captain Ridge are assigned to the Coracle Sandstone Member of the Valhall/Wick Sandstone Formation (Johnson & Lott 1993) and are informally referred to as the Lower Wick Sandstone. These are overlain by Early Barremian distal, low density turbidite silts and shales with occasional sands. An Upper Barremian unconformity has been identified through field biostratigraphic studies, and is supported by data from other wells in the Western Moray Firth Basin. Above this unconformity lie the two reservoir sands of the Captain Sandstone Member. Both the Lower and Upper Captain Sandstones are dated as Late Aptian, consistent with the time of maximum Aptian coarse clastic development elsewhere in the Moray Firth Basin. A regional isochore map for the Aptian Captain Sandstone shows that the thickest sand is preserved to the north of the Captain Field against the Wick Fault (Fig. 1 cf. Johnson & Lott 1993). The sandstones are generally featureless and massive, dewatering structures and mud clast horizons are the most common sedimentary features seen in the sands. The encasing mudstones consist of parallel laminated distal turbidites and pelagic mudstones interbedded with abundant slump deposits. The sandstones are interpreted as highdensity turbidite deposits but abundant glauconite indicates that the sandstones were stored originally on a shallow shelf. The isochore distribution described above implies that the shelfal area was the East Shetland Platform. It is suggested that the sands were redeposited in the deeper water depths to the south of the East Shetland Platform during a period of relative sea-level low stand. The distributions of the Upper and Lower Captain Sandstone show strongly contrasting geometries over the Captain Field. The Upper Captain Sandstone pinches out to the south and does not cross the crest of the ridge whereas the Lower Captain Sandstone forms a restricted (2 km wide) thick fairway that crosses the ridge in a north northwest to south southeast orientation (Figs 5 and 6). Biostratigraphic data indicate that that the Lower Captain Sandstone overlays older sediments (Upper Hauterivian) in the thick centre of the fairway whereas in the thin marginal zones the Lower Captain Sandstone lies on Lower Aptian claystone. These relationships imply that the Lower Captain Sandstone was deposited in a pre-cut submarine channel that cut across the Captain Ridge. The geometry implied by this model has been confirmed by development drilling. The Upper Captain Sandstone is interpreted as a series of stacked unconfined turbidite lobes that did not cross the Captain Ridge. The Captain Ridge appears to have been an important positive feature that influenced deposition throughout the Aptian. Only thin age-equivalent sands have been encountered in the West Halibut Basin immediately to the south of the Captain Field. Thicker Aptian turbidite reservoir sands occur along the southern margin of the Halibut Horst in the Blake, Cromarty and Goldeneye Fields and on the eastern margin of the Moray Firth Basin (for example in the Britannia Field). The relationship of the Captain Sandstone Member with these other occurrences is, at present, unclear.
436
S . J . P I N N O C K & A. R. J. CLITHEROE
..-.k 9
o .,...,a t-'q
t"q
,,... r~ O
o o
9
o
o
9
o
g o 9 9
. ,....i
.=_ +..a
.$ o o
...a
g r~ O
9 o ,.sz: 9
Z ~d
L
CAPTAIN FIELD Between the Upper Captain Sandstone and the overlying Chalk top seal, lies a greatly condensed (25 ft thick) section of Latest Aptian and Albian claystones, informally termed the Sola/Rodby Shale. The lower formations of the Chalk Group are condensed over the Captain Field and further east can be seen onlapping the Captain Ridge and the Halibut Horst. The Upper Chalk drapes the structure in a generally layer cake fashion. Overlying the Chalk is a sequence of Early Paleocene sands and shales. The lower of these units are assumed to belong to the Maureen Formation (Knox & Holloway 1992) and contain interbedded, resedimented chalk horizons. There are limited stratigraphic data available for the Tertiary in the Western Moray Firth Basin, inhibiting any detailed evaluation. Tertiary uplift and erosion causes the Chalk to subcrop the sea bed only 25km W of the Captain Field on the Smith Bank High.
Geophysics The initial structural mapping of the Captain Field was based on a 375 line-km grid of 2D seismic lines, drawn from 21 different surveys. These 2D seismic data sets, of varied vintage, were recognized as being inadequate, hence a 14 238 km 3D seismic survey was designed and acquired in 1990 over the whole of Block 13/22a, to overcome these deficiencies. The relatively shallow reservoir target permitted use of multiple short (600 m) cables in the 3D seismic acquisition. This maximized the rate at which the data could be acquired, with associated reduction in acquisition costs. The current geophysical mapping is based on an interpretation of the 1990 3D seismic data set. Events associated with the shallower horizons are generally of good quality, in both continuity and character, throughout the mapped area, and were picked for depth conversion purposes. Below these the Base Chalk horizon forms the principal seismic event used to define the structural form of the underlying Captain Sandstone Member. This is a strong continuous seismic reflector formed at the interface between the Chalk and the
437
underlying poorly consolidated Albian/Aptian clastics. Unfortunately, degradation of data quality below the Chalk renders the seismic mapping of the Lower Cretaceous and Jurassic less reliable. The Captain reservoir sands are represented by weak, discontinuous seismic events just below Base Chalk level, but are often masked by water bottom and peg leg multiples. However, sand thickness variations and spatial distributions can be constrained by integrating the very tight development well control very closely with the seismic. The most variable stratigraphic unit over the Captain Field is the Lower Maureen Formation. This consists of differing amounts of allochthonous limestone and basin floor clastic sands and has a very marked impact on the seismic. No obvious geological trends are apparent within this unit despite the full coverage provided by the 3D seismic dataset. The unit appears to represent an interdigitation of reworked chalk debris-flow deposits, derived from the Halibut Horst to the east, with more typical Maureen Formation turbiditic clastics sourced from the north and west. Differential compaction has resulted in the present morphology with the sand rich zones forming pronounced mounds above the Base Tertiary surface; for example around 13/22a-12 (Fig. 7). Velocity push-down effects can be seen on the Base Tertiary horizon, below these low velocity sand mounds. The Maureen Formation sandstones are not considered prospective in this area due to the lack of any mechanism for hydrocarbon charge. Depth conversion has historically been problematic over the Captain Field, due to the dramatic effect small lateral velocity changes can have on such a large but low relief structure. In Captain this issue is exacerbated by the very inhomogeneous velocity structure of the Maureen interval described above together with lateral velocity changes within the Chalk. The most successful approach uses a three-layer depthconversion model in the undeveloped part of the field. In Area A multiple Top Upper Captain Sandstone and Base Chalk penetrations in the horizontal development wells give a high density of depth data. A simple model using contoured average velocities to Base Chalk is used for depth conversion in this area.
Fig. 7. North-South seismic section through the Captain Field, Area A (see Fig. 2 for location).
438
S. J. PINNOCK & A. R. J. CLITHEROE
Trap and top seal The Captain Field is a broad, low relief structure covering an area of 9400 acres. At the reservoir level the trap is defined by a combination of three-way dip closure and stratigraphic pinch-out. Top seal is provided by a combination of the Sola/Rodby Shale and the overlying Chalk Group. The stratigraphic element to the trap divides the field into three closure areas, Main, Eastern and Southern Terrace (see Fig. 2). In the Main Closure the reservoirs drape the westerly plunging core of the Captain Ridge. The structure is full to the westerly spill point with an oil-water contact (OWC) o f - 2 9 9 2 ft TVDss in the Lower Captain Sandstone and -2982 ft TVDss in the Upper Captain Sandstone. The Eastern Closure is separated from the Main Closure by a structural low that is probably coincident with absence of sand. In the east the reservoirs pinch out to the south against the rising Captain Ridge and the fluid contacts are higher, -2967ft TVDss in the Upper Captain Sandstone and -2921 ft TVDss in the Lower Captain Sandstone. Below the present day contacts a zone of residual hydrocarbon saturation occurs, typically extending down 16-50 ft into the present day aquifer. The base of this zone does not appear to be flat, implying structural tilting since the initial charge. The residual oil zone also appears to be thicker in the east of the field where the present day contacts are higher. It is suggested that oil may have leaked into the open fracture systems that are present in the Devonian of the Captain Ridge. This might help to explain why the OWC in the Lower Captain Sandstone is significantlyhigher than that in the Upper Captain Sandstone of the Eastern Closure. The Upper Captain Sandstone also contains free gas caps in both the Main and Eastern Closures. The very different gas-oil contacts (GOC) in these areas, -2799 ft TVDss in the Main Closure Upper Captain Sandstone and -2723 ft TVDss, indicate that there is a robust stratigraphic seal, interpreted as a sandstone absent zone, between these two areas of the field.
Reservoir The majority of the Captain Sandstone Member reservoirs are thick-bedded fine to medium grained sandstones with very little interbedded silt or claystone. These deposits are interpreted as highdensity turbidity current deposits. The Upper Captain Sandstone exhibits excellent reservoir characteristics throughout. The Lower Captain Sandstone is a little more heterogeneous. The bulk of the Lower Captain Sandstone has excellent porosity and permeability as in the Upper Captain Sandstone but there are a number of discrete, thin, fine-grained horizons. These horizons make up less than 10% of the gross volume of the Lower Captain Sandstone accumulation but they are expected to act as pressure baffles during production. The Lower Captain Sandstone is predominantly a very fine to fine grained subarkose. The Upper Captain Sandstone has a higher lithic component while still being predominantly subarkosic. It also tends to be slightly coarser grained, typically fine to medium grained. Detrital components are dominated by monocrystalline quartz, together with polycrystalline quartz, potassium feldspars (5-8%) and lithics. Detrital clays (smectite and illite) and authigenic clays (predominantly kaolin), comprise 5-10 % of the samples. Other authigenic phases include siderite, ferroan dolomite and calcite and some leaching and alteration of feldspars has occurred. However, the Captain Sandstones have undergone only minor diagenetic alteration and they are not significantly compacted. The Upper and Lower Captain Sandstones are separated by a shale interval of uniform thickness, the Mid Captain Shale, which contains minor thin interbedded silts, sands and tufts.
Formation water Representative formation water samples have been obtained from MDT samples, the 13/22a-12 water coning test and produced water
in areas of the field where aquifer water was produced prior to the start of injection. The formation brines are characterized by low total dissolved solids (12-25 000ppm TDS) with minor quantities of barium, calcium and strontium. There is a clear spatial and stratigraphic variation in formation water salinity within these Lower Cretaceous sandstones. Salinity decreases vertically up through the stratigraphy (Lower Wick Sandstone produced water salinity is 25 000 ppm TDS, average Captain Member native salinity is 13 000 ppm TDS). Log derived water salinities suggest that the formation waters increase in salinity with increasing depth within each reservoir. It is suggested that the low salinity is a result of dilution of the original formation water (sea-water salinity) by meteoric influxes sourced from the Halibut Horst. Fresh water pulses are also assumed to have been responsible for introducing oxygenated waters and bacteria, resulting in biodegradation of the crude oil.
Source and migration Evaluation of geochemical data has demonstrated that the organicrich shales of the Kimmeridge Clay Formation are mature for hydrocarbon generation in the basins adjacent to the Captain Field. Ashphaltine geochemistry suggests the oil was sourced from both the West Halibut Basin and Smith Bank Graben, with the primary phase of charging modelled to have occurred during the early Tertiary. The original crude is considered to have been a typical North Sea black oil which has been biodegraded, in situ, during the Tertiary. Isotopic analysis of samples from the free gas cap around well 13/22a-9A show this has a significant late thermogenic gas component. Fluid samples have been obtained by standard drill-stem tests and wireline sampling from all reservoirs and areas of the Captain Field. The reservoir oil from the Main and Eastern Closures can generally be described as heavy by North Sea standards with API gravity and in situ viscosity ranging between 19~ and 21 ~ and 150 to 47 cP respectively. While variations are observed between the closure areas, no variation has been seen within a contiguous oil column.
Development The Captain Field is being developed exclusively with horizontal wells with completions ranging from 3500 to 8000 ft in length. The primary reason for utilizing horizontal wells is to provide spatial coverage throughout the reservoirs with a relatively small number of wells, thus maximising cost-effective recovery. Reservoir simulation studies confirm that the optimum orientation for the horizontal completions would be parallel to each other; this is constrained in practise by the requirement to drill the wells from a common tophole location. The layout of the seventeen development wells drilled to date is illustrated on Figure 4. Production wells were designed to stay within the top 20 ft of the reservoir, where practical, to delay initial aquifer water breakthrough and injectors are placed either in the aquifer or close to the base of the reservoir. To achieve these requirements the risk associated with two critical uncertainties, the depth to the Base Chalk Unconformity and the detail of the reservoir thickness distribution had to be addressed. For producer wells, the uncertainty in the location of the roof of the reservoir is the key uncertainty. When landing the well in the 1288 hole section the depth conversion risk is controlled by close monitoring of log markers through the Chalk sequence using gamma and resistivity logging-while-drilling sensors located behind the mud motor. Once in the horizontal section (889 hole) near-bit logging sensors are used (azimuthal gamma and resistivity, Bruce et al. 1996). Where a shale is penetrated in a well it is possible to confirm whether it is above or below by using the azimuthal gamma and it is possible to take corrective action immediately. Depending on the angle of incidence between the shale and the well bore this might entail turning the well trajectory away from the shale or
CAPTAIN
FIELD
439
9 ,.z:
9
9
o 1>
Q ,.sz
L)
9 r~
440
S. J. PINNOCK & A. R. J. CLITHEROE
Fig. 9. Captain daily oil production from start-up to end 1998.
pulling the bit back and drilling a low-side sidetrack. Once a sidetrack decision has been taken, the original hole is commonly extended as an information pilot hole, even drilling extra sidetracks to enhance the data collection (e.g. Fig. 8). Extensive sidetrack drilling has been cost effective in the Captain Field because it has proved unnecessary to isolate the abandoned sections and the horizontal holes are drilled with exceptional penetration rates (average 350 ft per hour, up to 900 ft per hour). Injectors are ideally placed beneath the oil water contact. However, pressure waves move very slowly through viscous oil like the Captain crude and pressure maintenance is critical for efficient oil recovery. As a result parts of the accumulation that are underlain by shale cannot be supported by aquifer injector wells where they are too remote from the aquifer, requiring the drilling of oil zone injectors (Lach 1997). To plan these wells a detailed picture of the reservoir thickness distribution is required to accurately constrain the aquifer. Where injector targets have been located in areas of reservoir thickness uncertainty, for example on the western margin of the Lower Captain Sandstone channel, pilot drilling in 191tt hole) and horizontal (889 hole) sections have both the landing (._~ been used to reduce the risk. The development of Captain with horizontal wells has provided unusually detailed geological control on the reservoir structure and sand distribution. This has resulted in close definition of sand pinch-out edges and unexpected sand thin zones in the Upper Captain Sandstone and detailed definition of the western margin of the Lower Captain Sandstone channel. The data have proved that much of the topographic variation of the Base Chalk Unconformity reflects sandstone thickness variation. It is suggested that this topography is the result of an interaction of compactional drape, original depositional relief and post Upper Captain Sandstone scour and erosion of the Captain reservoir sequence. In the current reservoir modelling, analysis of the topographic variation of the Base Chalk Unconformity has been used in conjunction with interpretation of weak discontinuous seismic reflectors within the reservoir sequence to constrain the reservoir isochore in both the developed and undeveloped areas. The continual enhancement of the Captain geological model has allowed optimal placement of new development wells and realistic predictions from reservoir simulation for reservoir management. Production wells were initially drilled with oil based mud with sand control provided by pre-packed wire-wrapped screens. Concerns over productivity performance of some of these completions resulted in a move to water based drilling fluids with open-hole gravel-packs for sand control. This has been successful and horizontal sections as long as 8000 ft have been gravel packed. The Captain development has required long horizontal injectors to be drilled. A critical concern for these wells was achieving an even inflow profile, ensuring that not all the water entered the formation at the heel of the well where the injection pressure will be high-
est. This was achieved by spacing open screen sections between blank pipe. The amount of open screen is restricted near the heel of an injector and increased towards the toe. Production logging has confirmed that, in undamaged wells, this screen configuration results in an even inflow profile. Sand control in injectors is achieved with dual wire-wrapped screens. The development strategy requires full voidage replacement; consequently injection was initiated two months after first oil production with water from the Lower Wick Sandstone aquifer. Injection of the Lower Wick Sandstone water will continue until the end of field life. Significant water production is forecast to occur from every oil well. Consequently down-hole chemical injection has been built into the completion design of these wells, including a dual corrosion and scale inhibitor line and also a demulsifier capability. Following hook-up and commissioning of the WPP and the FPSO during the winter of 1996/97 the pre-drilled production wells were brought into operation during March and April 1997. By the end of 1998, ten production wells, four injectors and one aquifer supply well were operational, with individual well production rates between 5000 and 20000 BPD gross liquids. Field oil production rate reached the design rate of 60 000 BOPD in September 1997 and has remained at or close to this level as additional wells have been brought on stream (Fig. 9). The authors wish to thank the management of Texaco Ltd and Korea Captain Company Ltd for permission to publish this paper. We would also like to acknowledge the contribution made by many colleagues and the external referees in reviewing the manuscript. C a p t a i n Field data s u m m a r y Trap Type Maximum oil column
Drape anticline/stratigraphic pinch-out 270 ft
Pay zone Formation Member Age Sand body thickness Net/gross ratio Porosity Permeability Oil saturation
Valhall/Wick Sandstone Captain Sandstone Late Aptian Variable, up to 300 ft 0.95 (field average) 28-34%, 31% (field average) 1-12D, 7D (field average) 68-94%, 84% (field average)
Hydrocarbons Oil gravity Gas gravity Bubble point Gas/oil ratio Formation volume factor
19~ ~ API 0.52 g/cc 1270psia at 2799 ft TVDss 88-140 SCF/STB 1.03-1.06 RB/STB
CAPTAIN FIELD
Formation water Salinity Average resistivity for Captain reservoir
0.394ohm-m @ 87~
Reservoir conditions Temperature Pressure Oil Gradient
87~ 1340 psi at OWC (-2992 fl TVDss 0.400 psi/ft
Field size Area Recovery factor Oil-in-place Reserves Drive mechanism
9400 acres 20-40% 1000 MMBBL 300-350 MMBBL Full voidage replacement, water injection
Production First oil Plateau production Development scheme
12 000-25 000 ppm TDS
March 1997 55 000 BOPD increasing to 85-000 BOPD with Area B Area A. One manned well head platform tied back to floating offshore storage and production vessel. Area B. Sub-sea drilling centre tied back to additional processing facilities on a second platform bridge-linked to the Area A drilling centre.
References BRUCE, S., BEZANT, P. & PINNOCK, S. J. 1996. A review of three years work in Europe and Africa with an Instrumented Motor. In: Proceedings of the 1996 IADC/SPE Drilling Conference, 147-156. COHEN, D. J. 1997. Captain Field electric submersible pump, condition monitoring and completion systems. SPE 8510.
441
COHEN, D. J. & DALLAS, J. 1997. Development of a gas handling hydraulic submersible pump and planning a field trial, Captain Field. SPE 8511. CRITTENDEN, S., COLE, J. M. 8r KIRK, M. J. In press. The distribution of Aptian sands in the Central and Northern North Sea (UK Sector)a Lowstand Systems Tract hydrocarbon exploration play. Part 1: Stratigraphy, age determination and genesis of the sandstones. Journal of Petroleum Geology, in press. ETEBAR, S. 1997. Captain Field development project overview. SPE 8507. JOHNSON, H. 8r LOTT, G. K. 1993.2. Cretaceous of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic nomenclature of the UK North Sea. British Geological Survey, Nottingham. KNOX, R. W. O'B. & HOLLOWAY, S. 1992. 1. Paleogene of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic nomenclature of the UK North Sea. British Geological Survey, Nottingham. LACH, J. R. 1997. Captain Field reservoir development planning and horizontal well performance. SPE 8508. PALLENT, M. A., COHEN, D. J. & LACH, J. R. 1995. Reservoir engineering aspects of the Captain extended well test appraisal program. SPE 30437. PINNOCK, S. P. ~r CLITHEROE, A. R. J. In press. The Captain Field, UK North Sea: appraisal and development of a viscous oil accumulation. Petroleum Geoscience, in press. ROBERTS, A. M., BADLEY, M. E., PRICE, J. O. & HUCK, I. W. 1990. The structural history of a transtensional basin: Inner Moray Firth, NE Scotland. Journal of the Geological Society, 147, 87-103. SUTTON, J. E. 1997. Process equipment for offshore viscous crude handling: Captain Field. SPE 8512. TAVENDALE,F. M. 1997. Captain horizontal development wells: a review of key design and operational issues. SPE 8509. UNDERHILL, J. R. 1991. Implications of Mesozoic-Recent basin development in the western Inner Moray Firth, UK. Marine and Petroleum Geology, 8, 359-369. UNDERHILL, J. R. ~r PARTINGTON, M. A. 1993. Jurassic thermal doming and deflation in the North Sea: implications of the sequence stratigraphic evidence. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 337-345.
The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea M. A. HARVEY
1 & S. C U R R I E 2
1Helix RDS, Peregrine Road, Westhill Business Park, Aberdeen AB32 6JL, UK 2 Amerada Hess Exploration & Production Ltd., Scott House, Hareness Road, Altens, Aberdeen AB12 3LE, UK
Abstract: The Ivanhoe, Rob Roy and Hamish Fields lie in the Moray Firth of the UKCS in Block 15/21 and contain undersaturated oil trapped in the prolific Upper Jurassic Piper reservoir in tilted fault block traps. The fields were brought on stream in 1989 and since then the reservoir model has undergone several revisions with changes to the calculated oil in place volumes. The two main areas of uncertainty in the geological model are the position of the faults and the distribution of permeability. Improvements in the quality of the seismic data and the well ties brought about greater confidence in the seismic pick at top reservoir and the placement of the major bounding faults to the fields. The reservoir is generally sand-prone with a high net to gross ratio, porosity and permeability, which suggest that the reservoir would behave in a fairly homogeneous manner to fluid flow. Detailed reservoir description shows that this is not always the case. Improvements to the geological model permit a better understanding of the connection between the injector and producer wells and the degrees of influence from faults and heterogeneities in the reservoir to the fluid flow. Based on the current model the present recoverable reserves are estimated to be 187 MMBBL.
The I v a n h o e a n d R o b R o y Fields were previously described by P a r k e r (1991) a n d by Currie (1996). The fields are dealt with u n d e r a single heading since they share a c o m m o n reservoir and are p r o d u c e d t h r o u g h the same floating p r o d u c t i o n facility n a m e d AH001. The g r o u p o f fields includes the small H a m i s h accumulation and collectively are abbreviated as I V R R H . The I V R R H fields lie in the M o r a y Firth in Block 15/21; Figure 1 shows the field locations with respect to the licence boundaries. The fields comprise tilted fault blocks, oriented N W - S E along the Witch G r o u n d trend, with oil trapped in the U p p e r Jurassic Piper reservoir. Two sandstone reservoirs are present: the lower, M a i n Piper and the upper, Supra Piper that c o r r e s p o n d to the Scott and Piper M e m b e r s of the Scott Field. At A n n e x B the recoverable
reserves were 88 M M B B L and 69 BCF. The present licence holders are: A m e r a d a Hess Limited 76.56%, K e r r M c G e e Oil ( U K ) plc 19.7%, Premier Pict Petroleum Limited 3.75%. The field names are from the novels of Sir Walter Scott.
History The exploration history of the fields is described in P a r k e r (199l), and is s u m m a r i z e d here. Block 15/21 in Licence P218 was a w a r d e d in the 4th R o u n d to the M o n s a n t o Oil C o m p a n y . The I v a n h o e Field was discovered first, by well 15/21-3 in 1975 on a Base Cretaceous structure. The Jurassic fault blocks were m a p p e d in the late 1970s
Fig. 1. Location of the Ivanhoe, Rob Roy and Hamish Fields in relation to licence boundaries, major structur~il elements and adjacent producing fields. GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 443-451.
443
444
M. A. HARVEY & S. CURRIE
and subsequent appraisal wells on the Ivanhoe Field tested oil from both Supra and Main Piper reservoirs. The Rob Roy Field was discovered in 1984 by well 15/21a-ll that flowed oil from both reservoir intervals. Further appraisal drilling of the Rob Roy Field in 1984 confirmed the presence of commercial volumes of hydrocarbons and an Annex B was submitted in June 1985. In December 1985 Amerada Hess Limited purchased Monsanto Oil Company and assumed operatorship of licence P218. The previously relinquished part-Block 15/21b was re-acquired in the 10th Licensing Round as P588. Development wells were drilled on both fields to permit a plateau production rate of 60 000 BOPD shortly after field start-up. The small Hamish accumulation was discovered during this phase of drilling by well 15/21b-21 and later appraised by wells 15/21a-40 and 15/21a-40Z. The Hamish Field comprises only the Main Piper reservoir; the oil was produced via the Rob Roy Field production manifold, the field is now shut-in. Fluids are produced through manifolds located over each field, via flexible flowlines to a riser base manifold and then on to the production facility. Crude oil is exported to the Claymore 'A' Platform and then to the Flotta Terminal. Gas is exported to the Tartan 'A' Platform and ultimately to St Fergus. Field life is projected until end 2006 when ultimate recoverable reserves of 187.0 MMBBL is forecast. Peak flow rate was 80 000 BOPD and 166 MMBBL were produced at end 1999. Gas lift is used on most of the producing wells by re-injection of produced gas. The gas lift program commenced in July 1992 with wells IE32 and ID19 on the Ivanhoe Field. Production from the Supra Piper reservoir in the Rob Roy Field does not require gas lift as the oil has a higher G O R (1391 SCF/BBL). In February 1999 the production from the Phillips operated Renee-Rubie fields 10km to the south was routed to the AH001 facility. Additional crude and water handling facilities were required on the AH001 to process this production.
Structure The regional development of the Moray Firth is described elsewhere: Boldy & Brearly (1990), Harker et al. (1986), Hibbert & Mackertich (1993), O'Driscoll et al. (1990). The IVRRH fields lie in a part of the Moray Firth where three distinct structural lineaments interact to create a complex fault pattern (Fig. 1). Running N E - S W is the Caledonide trend also known as the Viking trend, and running NW-SE is the Witch Ground trend (Boldy & Brearly 1990). Two major E-W trending structures also occur in the area: the Halibut Horst to the north of the fields and the Renee Ridge to the south. The intersection and interference of the fault trends with the Halibut Horst produced a complex of subsidiary fault systems and locally inversion features in the vicinity of the fields. The Caledonian trend had significant control on deposition in the area during the mid- to late Jurassic, with thickened strata in the Theta Graben (Hibbert & Mackertich 1993) and across the Scott Field. The Witch Ground trend was active in the late Jurassic and had more influence on the formation of the trapping geometry of the fields. Crestal well 15/21 a-31 in the Rob Roy Field has a condensed and eroded section of the Supra Piper which indicates that there was footwall uplift during deposition along the large field bounding fault to the field. Figure 1 also shows the fields in a regional structural context, with the Scott and Telford Fields to the northeast. In the Scott Field it was the major Caledonian Trend fault that had the most significant effect on the Jurassic deposition in that area. In the Telford Field the N W - S E trending bounding fault is a major inversion feature that is associated with significant erosion at the crest of the field. From the most recent seismic interpretation performed in 1999 it is apparent that the Ivanhoe and Rob Roy Fields possess distinctly different densities of faulting (Fig. 2). The Rob Roy Field is dominated by the N W - S E bounding fault, whilst the Ivanhoe Field displays a more complex system of smaller faults that is considered
Fig. 2. Top Supra Piper structure surface with well locations and structural features.
IVANHOE, ROB ROY AND HAMISH FIELDS to be a result of interference between the tectonic episodes that created the Theta Graben to the west and the Renee Ridge to the south (Fig. 1 inset). The crestal areas of the two fields illustrate the different fault styles: in the Rob Roy Field there is a splay fault from the bounding fault, with associated thinning and erosion of the reservoir interval, whilst in the Ivanhoe Field there is a significant terrace structure downthrown to the northeast, but no crestal thinning or erosion. Figure 3 illustrates the different structural configuration in cross-section. Analysis of the fault throws in the Ivanhoe Field indicates that there are several locations where the sands of the Main Piper and Supra Piper reservoirs are juxtaposed. It is considered that these sand-to-sand contacts permitted an equilibration of fluid levels during the hydrocarbon-filling phase such that the field has a common contact in the two reservoirs. In the Rob Roy Field, however, these sand-to-sand contacts are very limited in number and do not appear to have acted as conduits during hydrocarbon filling. As a consequence the two reservoir intervals in the Rob Roy Field filled separately and at discovery had different OWCs. The Hamish Field is a small dip and fault closed structure. The present interpretation of reservoir distribution indicates that the Supra Piper reservoir in Hamish is limited to a thin silty equivalent to the sands encountered in Rob Roy and therefore oil production was limited to the Main Piper from this field.
Stratigraphy The depositional history of the Jurassic in the Moray Firth is described elsewhere (Harker et al. 1993) and is summarized here. The oldest sediments in the area are the Lower Carboniferous Forth Formation encountered in well 15/21a-21, succeeded unconformably by thin Permian and Triassic strata. The Lower Jurassic is absent and the thick volcanic sections, present in many of the wells, are assigned to the Rattray Formation. The volcanic lithologies give a wide variation of responses on the seismic data, and in general the pick for top Rattray Formation is considered unreliable. The variation in seismic response is thought to be the product of the degree
445
of weathering of the top of the volcanic strata and the different types of volcanic deposit, as lava flows or tufts. A subsequent transgression deposited carbonaceous, paralic clays overlain by marine clays and ultimately the marine sands of the Sgiath and Piper Members. The later Jurassic was marked by the deposition of the anoxic clays of the Kimmeridge Clay Formation that comprises the primary source rock in this area. (Fig. 4). At the time of the Annex B for the IVRRH fields the two reservoir sands were both assigned to the Piper Formation. Subsequent refinement of the stratigraphy of the Witch Ground Graben by Harker et al. (1993) showed that they could be correlated to the reservoirs in the Piper Field. The correlation may also be extended to the Scott Field: I V R R H Fields
Piper Field
Scott Field
Supra Piper Mid Shale Main Piper
Piper Member I Shale Sgiath Member
PiperMember I Shale Scott Member
Reservoir depositional environments & facies A detailed review of the regional aspects of the Piper reservoir was made in 1988 where the sands were interpreted as the deposits of a wave influenced delta, as summarized by Parker (1991). The lower and upper reservoir members were considered to be deposited as a series of cleaning and coarsening upwards cycles as the delta system prograded from east to west across Block 15/21 during a series of transgressions and regressions. Both offshore marine and terrestrial sediments are represented in the Piper reservoir (Harker et al. 1993). The most recent interpretation of the reservoir, by Lomond Associates, places the I V R R H fields in a regional context by linking the depositional system observed in the fields with the reservoirs in the Scott and Telford Fields. This interpretation places less emphasis on the cyclic nature of the sediments and uses an analogue of a tidally influenced shoreface and barrier system as found on the eastern sea-board of the USA (e.g. Sexton & Hayes 1996 and Caplan & Moslow 1999 for a modern example).
Fig. 3. Southwest-NE random 3D seismic line through Ivanhoe and Rob Roy with primary stratigraphic markers and structural features identified.
446
M. A. HARVEY & S. CURRIE
Offshore marine Identified in the lowest part of the Main Piper and comprising much of the Supra Piper, the sands coarsen and clean upwards from offshore marine claystones, through bioturbated distal transition zone sands to proximal offshore transition zone sands. Reservoir properties improve upwards with porosities up to 27% and permeabilities >2 Darcies.
Shoreface These lie above the proximal offshore transition zone sands and possess low angle, cross-bedded or parallel bedded clean sands with porosities up to 27% and permeabilities up to 9 Darcies.
Heterogeneous back-bar This unit was deposited behind the prograding sand barrier as a stacked series of lagoonal mudstones, thin coals and interbedded proximal and distal washover sands. Towards the barrier-bar in the northwest, proximal washover sands predominate as heterogeneous, laminated mainly clean sands. The lagoonal mudstones and coals are more common towards the southeast and reach 5-10ft thick in the eastern part of the Rob Roy Field where they are considered to form a regionally correlatable horizon that probably forms a barrier to vertical flow in that part of the field. Reservoir quality is variable with permeability 300-10 000 mD.
Flood tidal deltas
Fig. 4. Summary stratigraphy of the IVRRH fields.
The depositional evolution of the Main Piper reservoir is similar in each of the Ivanhoe, Rob Roy and Hamish Fields and is characterized by a lower unit of offshore marine sandstones overlain by a shoreface unit, a heterogeneous back-barrier unit, with a partly preserved transgressive sand as the uppermost unit of the Main Piper (Fig. 5). An initial relative lowering of sea level permitted the seaward advance of the beach barrier and back-barrier environments to the northwest with the barrier bar oriented SW-NE, whilst tidal incursions breached the barrier to give flood tidal delta deposits. In general, beach barrier and associated beach deposits have extremely poor preservation potential in this depositional setting and these facies are not observed within the Main Piper section. The heterogeneous unit comprises both proximal and distal washovers, with claystones and coals developed in the more proximal locations in the eastern part of Rob Roy. The end of deposition of the Main Piper sand was marked by a transgression, in response to a major marine-flooding event, represented by the MidShale claystone. A renewed lowering of relative sea-level instigated another phase of sand deposition as the Supra Piper reservoir. This is characterized by marine sands, which were deposited in distal to proximal marine shoreface conditions, similar to the lowest interval of the Main Piper. The distribution of the facies at the end of the Supra Piper indicates that while shoreface sediments were being laid down in the SE, progressively deeper water facies were being deposited further to the northwest. The transgression that ultimately deposited the sediments of the Kimmeridge Clay Formation is marked by a transition from the sands of the Supra Piper to an anoxic claystone. The depositional facies that make up the succession outlined above are described as follows (see Fig. 5):
Upper and lower flood tidal delta units have been identified and each has a proximal and distal facies. Each flood tidal delta is a cleaning upward unit of burrowed sands with clay drapes. The distal facies is more argillaceous, whilst the proximal facies is trough or cross bedded and clean. It may be possible to map out lobes of the flood tidal delta that represent loci where the beach barrier was reworked back into the lagoon. Reservoir quality is high with permeabilities reaching 8 Darcies in the coarser sands, with porosities up to 28%. The clay drapes are considered to only marginally inhibit fluid flow.
Transgressive sand This is a thin unit, <15 ft thick of strongly bioturbated, variably argillaceous sands interpreted as barrier sands reworked during the initial phase of the transgression that ultimately deposited the Mid-Shale.
Marine claystone This is a unit of laminated or slightly bioturbated or laminated mudstones and siltstones deposited under offshore marine conditions. This unit is also identified in Scott Field where the silty upper part forms a reservoir unit dominated by mass flow sands.
Mass flow sands This facies is restricted to the Supra Piper of the Ivanhoe Field and is characterized by moderately thick, clean, structureless sands. The beds thin to the NE and thicken towards the NW of the Ivanhoe Field. Correlation of the beds between wells is not certain. However, the Supra Piper in the Ivanhoe Field displays excellent sweep and therefore amalgamation and inter-fingering of the sands is
IVANHOE, ROB ROY AND HAMISH FIELDS
447
Fig. 5. Typical stratigraphy from the IVRRH fields with a comparison of the depositional facies with the reservoir flow units.
assumed in order to explain the good connectivity. The sands display some of the highest porosities in the reservoir in excess of 30% with permeabilities up to 4 Darcies.
Geological controls on reservoir quality The reservoir is little affected by diagenesis with only a minor volume of quartz overgrowths and localised carbonate cements. The latter can manifest as high-density intervals on logs < 10ft thick that are interpreted as doggers and are not expected to be
Fig. 6. Relationship between porosity, permeability and facies type.
laterally extensive. In some instances the cemented intervals may correspond to fault cuts in the wells that have permitted the ingress of cementing fluids. The strong relationship between facies, porosity and permeability is illustrated in Figure 6 with many of the facies possessing porosities in excess of 20% and permeabilities greater than 500roD. By comparison the reservoirs in the Scott Field are strongly affected by cementation, mostly quartz and carbonate. The difference in degree of diagenesis is primarily a result of the difference in depth of burial: in the I V R R H fields the crest of the Rob Roy Field is at 7550 ft sub-sea whilst the crest of the Scott Field is at 10 200 ft sub-sea.
448
M.A. HARVEY & S. CURRIE
Flow unit zonation The responses of the electric logs over parts of the reservoir would suggest that the reservoir is fairly homogenous, e.g. the flood tidal deltas and the offshore marine deposits (Fig. 5). However, closer inspection of the permeability data, when plotted on a linear scale, reveals a greater degree of heterogeneity in the reservoir. Within the flood tidal delta facies, the variation in permeability reflects the division between proximal and distal sub-facies. The variation in permeability imposes a greater degree of flow layering to the reservoir and this parameter was used as the primary guide for the construction of the flow unit zonation. Additional control was gained from the gamma-ray log and density-neutron log pair; the sonic log provides little information (see Fig. 5). The broad correlation between the depositional facies and the rock properties is reflected in the general correspondence between the flow unit zonation and the facies divisions in Figure 5. However, the finer scale heterogeneities seen in the permeability distribution result in an inexact match between the flow units and facies.
Reserves and production At the end of 1999 the IVRRH fields were in production decline although final recovery is expected to be high with projected recovery factors in excess of 70% for Ivanhoe and Rob Roy. Production from the fields is managed by optimization of the wells according to water cut and by the allocation of gas lift to the wells. The limit on production for the fields is the produced water-handling capacity of the AH001 facility. Figure 7 shows the production profile and water cut profile up to end 1999. Opportunities for water shut off at wells with high water cuts and the prioritisation of wells with higher oil rates are identified through the simulation model. The present simulation model is also used to identify additional opportunities for unswept oil as new wells or as workovers. However, the IVRRH fields are a sub-sea development and therefore workovers are high cost with some element of risk that must be carefully evaluated. The original perforation strategy was to perforate either the Supra Piper or Main Piper reservoir to permit reservoir management by isolating sands and zones and thereby control the flow to each producing well. Future options for well management have investigated opportunities for completing wells over both sands to permit commingled production, when water cuts are very high or to complete zones where bypassed oil has been identified from the simulation model.
Fig. 7. Oil production and water cut profiles to end 1999.
In general all the fields have a strong aquifer drive with additional support from water injection to maintain a reservoir pressure approximately 3000psi (Fig. 8). More specifically, each field has behaved differently: Hamish has a single producer with no injection support, but has received support from the Rob Roy Field injectors through the aquifer. The Rob Roy Field has two injectors, although the support pattern is complicated since injection into the Supra Piper in well RN17 provided support to the Main Piper reservoir through a fault offset in the aquifer. In the Ivanhoe Field aquifer support is restricted by the major southern bounding fault and therefore more injection support is required. The I V R R H fields have been on production for ten years and as is often seen in older fields there are additional factors that need to be managed. There is an increase in the level of H2S from some wells and a scavenger is used to control the amount of H2S in the export gas to an acceptable level. Performance of the wells is monitored by regular well tests and the variations in production index (PI) can indicate scaling or an increase in water cut. As all wells now produce a mix of seawater and formation water, scaling is a continual problem that requires treatment by scale inhibitor squeezes and topsides injection of inhibitor. Furthermore, over the life of the field the downhole gauges have become increasingly unreliable and therefore production monitoring is more difficult. Throughout the life of the field effort has been made to reconcile the produced volume of fluids with that predicted by the subsurface model. Two elements were critical in the construction of the structural framework for the subsurface model: the degree of confidence in the seismic pick at top reservoir and the accurate placement of the faults. Changes in confidence of the interpretation have resulted in changes in the calculated hydrocarbon volumes as shown in Figure 9 that illustrates the changes in STOIIP that have occurred since Annex B. The seismic data available in 1984 had poor resolution at top Piper and the most reliable pick was at top Rattray Formation. Therefore, for the Annex B the reservoir mapping was based on a surface picked at top Rattray Formation and the top Piper surface was obtained by stacking isochores up from that surface. The additional data gained from drilling between 1986 and 1988 were incorporated into the geological model of the reservoir in 1989 and a new top reservoir structure surface was derived, again based on mapping of the top Rattray Formation. In 1991, a volume discrepancy between the simulated production and actual production was identified. A reinterpretation of the fields was initiated with an emphasis on tying the well synthetics to the seismic data in order to map a top Piper surface based on the seismic pick. However, one uncertainty of the mapping was in the placement of the bounding faults to the fields, in particular the Rob Roy Field. The reinterpretation included a larger number of intrafield faults and a change in the geometry of the field bounding faults. The oil in place volumes calculated from this interpretation were broadly similar to that from 1989 but there was a redistribution of the volume within the fields. The simulation model derived from this work matched well with the production data from the Ivanhoe Field but not with the data from the Rob Roy Field and therefore was limited as a predictive tool. A series of workovers at that time to perforate the top of the Main Piper and to run TDT logs demonstrated the bottom-up water drive that operated in the fields. Integration of that data with the simulation model showed that an increase in field volume in the Rob Roy Field was required to obtain a history match. In 1993-1994 the 1984 seismic data were re-interpreted to give a new top reservoir structure with the bounding fault for the Rob Roy Field positioned farther to the northeast. The reservoir model built from this interpretation gave an increase in STOIIP and the simulation model could be history matched to the production data for both the Rob Roy and Ivanhoe Fields. During 1995 and 1996 an audit on the pressures from the production data confirmed the position of the OWCs, as shown in the field data summary, and a review of the simulation model highlighted a discrepancy between the mapped permeabilities and the Kh values obtained from the well test data. Previously, to
IVANHOE, ROB ROY AND HAMISH FIELDS
449
Fig. 8. Location of injector and producer wells with potentially unswept areas.
Fig. 9. Changes in field STOIIP over time. obtain permeability values in uncored reservoir sections, a simple porosity v. permeability relationship was used. However, with high values of porosity there is little linear relationship with permeability (Fig. 6) and the method becomes an unreliable predictor and therefore a multivariate transform technique was employed using the GR, density and sonic logs. Simultaneously, an interpretation of an alternative 3D seismic dataset (WGC1995, reprocessed 1996) resulted in two changes to the structural definition of the fields: the density of the intra-field faulting was reduced and the bounding fault to the Ivanhoe Field was moved approximately 200 m to the northeast. The reduction in the density of the intra-field faulting gave a fault pattern very similar to that mapped in 1989. The change in the interpretation of the bounding fault to the Ivanhoe Field placed a narrow terrace along the northeastern margin of the field, where the terrace-bounding fault corresponded to the previous location of the bounding fault. To bring all these studies together the complete subsurface model for the fields was revisited in 1999. The work program included: the interpretation of an alternative seismic dataset (Telford 3D, 1992), a sedimentological facies study to place the fields in a regional depositional model, a re-zonation of the flow units to include the
permeability data predicted from the multivariate analysis, a 3D structural model to ensure accuracy in volume calculation and a simulation model. The structure map generated from this interpretation is shown in Figure 2. The structural style is similar to that mapped in 1996-1997 with a limited number of intra-field faults in the Rob Roy Field, and a prominent southern bounding fault to the Ivanhoe Field. The mapping also confirmed the presence of the narrow terrace on the northeastern flank of the Ivanhoe Field. The oil in place volume for the Rob Roy Field is similar to that calculated in 1993; for the Ivanhoe Field the volume is increased due to the inclusion of the terrace feature. The revised subsurface description integrates both static and dynamic data and it may be used for surveillance and prediction of fluid flow: An analysis of the production and salinity data from injector well IF33 and producer wells ID19 and IK28 on the Ivanhoe Field, showed the primary conduit for fluids in the reservoir to be in zone Main 4 which possesses the highest permeabilities in the reservoir (Fig. 5). For a reservoir with such high permeabilities some water coning might be expected during production, but this effect is not seen in any of the producing wells. It would appear that there is sufficient heterogeneity in the layering of the heterogeneous back-bar
450
M . A . HARVEY & S. CURRIE
unit of the Main Piper, in flow units 4, 5 and 6, to reduce the vertical permeability to water. The location and throws of the faults in the Ivanhoe Field have a significant effect on the sweep pattern. The fault mapped to the north of injector well IF33 has acted as a shadow to the water injected from the well. Also, the southern bounding fault at the eastern flank of the field has sufficient offset to act as a baffle to aquifer ingress with the overall result that the eastern flank of the field is considered to be only partly swept. The 1999 mapping places a major fault at the southern boundary to the Ivanhoe Field that offsets both reservoirs except at a single location where aquifer support to the injectors can occur (Fig, 8). In the Ivanhoe Field the present injector sweep pattern and aquifer support implies that there will be unswept reserves in the Main Piper reservoir in the northern part of the field in the terrace structure. In the Rob Roy Field Main Piper reservoir a combination of good aquifer support and injection has provided excellent sweep of the reservoir and the limited number of faults in the Rob Roy Field provide little baffling to the flood front. The claystones present over the eastern part of the Rob Roy Field in Zones 5 and 6 do not appear to impede hydrocarbon production although the sweep pattern suggests that remaining reserves are present in the very eastern part of the field. From the correlation of reservoir pressure and cumulative voidage, the volume of aquifer support to the western part of the field is considered to be limited. An area of
potential upswept reserves therefore exists in the western part of the field, although the reduced reservoir thickness and quality in that area limit the volume of those reserves.
Conclusions The I V R R H fields are unusual in that they had a pre-development hydrocarbon volume that was smaller than the volumes produced to date. Throughout the life of the fields there has been a continuous process of reconciliation of the mapped hydrocarbon volumes with produced hydrocarbon volumes that has required continuous refinement of the subsurface model in light of the production data. The subsurface model for the fields was constructed within a regional context and with reference to other fields in the area that has permitted a greater understanding of the structural setting, the distribution of the reservoir facies and controls on rock properties. The definition of the static model has been hampered by the quality of the seismic data in this area and the uncertainty associated with the top reservoir pick and the placement of the faults. The dynamic data is limited by the failure of the bottom hole gauges and the cost of interventions in a sub-sea completion. A key requirement is that the geologist, geophysicist and engineer
Ivanhoe, Rob Roy and Hamish Fields data summary Field name
Ivanhoe Supra
Rob Roy Main
Supra
Hamish Main
Units
Main
Trap
Type Depth to crest OWC Oil column
structural 7590 8052 462
8052
structural 7550 7931 381
7994
structural 7750 7962 212
ff
Pay zone
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range)
50 0.981 0.226 530 0.867
300 0.997 0.229 2200 0.944
Piper sands upper Jurassic 100 0.936 0.224 520 0.937
220 0.992 0.228 2090 0.955
120 1.000 0.238 1080 0.945
ft ft % mD %
31 1800 360 1.188
29 1800 360 1.188
low sulphur crude 41 39 3460 1900 1391 613 1.679 1.344
39 1900 613 1.344
~API psig -
Petroleum
Oil type Gas gravity Bubble point Gas/oil ratio Formation volume factor Formation water
Salinity Resistivity
90 990 0.102
NaC1 eq. ppm o h n l nl
Field characteristics
Initial pressure Pressure gradient Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil
3510 0.345 175 34 43
3510 0.345 175 66 64 73.3
3510 3510 0.262 0.307 175 175 42 101 56 67 aquifer drive and water injection 109.9
3510 0.307 175 7 43
psi psi/ft oF
3.8
MMBBL
MMBBL %
Production
Start-up date Production rate plateau oil Number/type of well
Jul-89
Jul-89
Feb-90
80 000 2P 1I
1P lI
2p 2I
BOPD 3P 2I
1P
IVANHOE, ROB ROY AND HAMISH FIELDS u n d e r s t a n d the limitations of the datasets they each deal with and therefore the limitations of the models derived f r o m those data. The complexity of the subsurface m o d e l has increased over the life of the field. The perceived h o m o g e n e i t y of the Piper reservoir, used in early d y n a m i c models, was not reflected in the fluid behaviour and a m o r e detailed facies analysis has shown the permeability distribution in the reservoir is m u c h m o r e heterogeneous then previously thought. A n asset requires not only a robust and believable m o d e l but also a good u n d e r s t a n d i n g of h o w the fluid behaves in the subsurface relative to the geology. C o n t i n u o u s vigilance of an asset is necessary to identify potential unswept reserves and to identify well opportunities w h e t h e r these be interventions, water shut-offs or n e w wells. The m o d e l for the I V R R H fields is used to build a portfolio of such opportunities that can be valued and risked as part of the process of active field m a n a g e m e n t to realize the m a x i m u m value from the asset. The authors wish to thank M. Shepherd of Amerada Hess Exploration & Production Ltd., Ken Johnson, Tanya King, Marry Haynes and Russ Gilbert of Helix RDS and Ken Russell and Andy Thickpenny of Lomond Associates for input to this paper. The authors also wish to thank Kerr McGee Oil (UK) plc and Premier Pict Petroleum Limited plc for their permission to publish this paper.
References BOLDY, S. A. R. & BREARLY,S. 1990. Timing, nature and sedimentary result of Jurassic tectonism in the outer Moray Firth. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 259 279.
451
CAPLAN, M. L. & MOSLOW, T. F. 1999. Depositional origin and facies variability of a middle Triassic barrier island complex, Peejay Field, northeastern British Columbia. AAPG, Bulletin, 83, 128-154. CURtaL, S. 1996. The development of the Ivanhoe, Rob Roy and Hamish Fields, Block 15/21a, UK North Sea. In: HURST, A. et al. (eds) Geology of the Humber Group." Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 329-341. HARKER, S. D., GUSTAV, S. H. & RILEY, L. A. 1986. Triassic to Cenomanian stratigraphy of the Witch Ground Graben. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe. Geological Society, London, Special Publications, 809-818. HARKER, S. D., MANTEL, K. A., MORTON, D. J. & RILEY, L. A. 1993. The stratigraphy of Oxfordian-Kimmeridgian (Late Jurassic) Reservoir Sandstones in the Witch Ground Graben, United Kingdom, North Sea. AAPG, Bulletin, 77, 1693-1709. HIBBERT, M. J. & MACKERTICH,D. S. 1993. The structural evolution of the eastern end of the Halibut Horst, Block 15/21 outer moray Firth, UK North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1179-1188. O'DRISCOLL, D., HINDLE, A. D. & LONG, D. C. 1990. The structural controls on Upper Jurassic and Lower Cretaceous reservoir sandstones in the Witch Ground Graben, UK North Sea. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's" Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 299-323. PARKER, R. H. 1991. The Ivanhoe and Rob Roy Fields, Blocks 15/21a-b, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas" Fields'." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 331-338. SEXTON, W. J. & HAYES, M. O. 1996. Holocene deposits of reservoir quality sand along the central South Carolina coastline. AAPG, Bulletin, 80, 831-855.
The MacCulloch Field, Block 15/24b, UK North Sea C. G U N N , J. A. M A C L E O D , P. S A L V A D O R & J. T O M K I N S O N ConocoPhillips ( U K ) Ltd, Rubislaw House, N. Anderson Drive, Aberdeen A B 1 5 6 F Z , U K
Abstract: The MacCulloch Field lies within Block 15/24b in the UK Central North Sea and is located on the northern flank of the Witch Ground Graben. It was discovered by Conoco well 15/24b-3 in 1990. MacCulloch Field is a four-way dip closure at Top Paleocene over a deeper Mesozoic structure. The reservoir consists of Upper Balmoral Sandstones containing 32-37 ~ API oils derived from Kimmeridge Clay Formation shales and sealed by shales belonging to the Sele Formation. The field contains recoverable reserves of 60-90 MMBOE. Reservoir quality is generally Very good, with an average porosity of 28 % and core permeabilities (Kh) between 200 mD and 2 D. AVO anomalies and a seismic flat spot are associated with oil filled reservoir and the oil-water contact in certain areas of the field.
The MacCulloch Field is located approximately 440km N E of Aberdeen, on the northern flank of the Witch Ground Graben area of the Central North Sea (Fig. 1), in a water depth of 490 ft. The field is an elongate, four-way dip closed structure, formed by a combination of shale compaction over Upper Paleocene sandstone channels and reactivation of deep Jurassic faults. The Upper Balmoral Sandstones of the Lista Formation (Knox & Holloway 1992) form the reservoir for the field. The sandstones were deposited on a submarine shelf as channelized turbidites, derived from the northwest. The underlying sequence consists of sheet-like sandstones of the Maureen Formation and Andrew Sandstones (Fig. 2). An oil-water contact at - 6 2 4 0 f t TVDSS has been established across the field, based on core and petrophysical analysis. This matches the currently mapped spill-point of the field to the northwest. The maximum oil column is interpreted to be 240 ft, however the thickest proven oil column is 200 ft, drilled by well 15/24b-Wlz (Fig. 3). Reservoir quality is generally very good, with an average porosity of 28 % and permeabilities between 200 mD and 2 D. Reserves are estimated to be 60 M M B O E of 32-37 ~ API oil. First oil was achieved on 10 August 1997, from a Floating Production System and Offtake vessel (FPSO) called the North Sea Producer (Fig. 4). The vessel is operated by North Sea Production under contract to the field owners, while the subsurface facilities are operated by Conoco (UK) Limited on behalf of their partners, Lasmo (40%) and Talisman (20%). Oil and gas are transported by pipeline to the Piper Bravo platform. The field is named after John MacCulloch (1773-1835), a Scottish geologist who produced the first geological map of Scotland.
15/24-1 and investigating the deeper Upper Jurassic Piper sands. It encountered a 35 ft net oil column in the Paleocene, with an oilwater contact at -6235 ft TVDSS. Reservoir quality was good with porosities in the oil zone averaging 28%. Two DSTs were performed and an oil flow rate of 3900 BOPD was achieved. The Jurassic was found to be water bearing. The next wells on the field, 15/24b-5 and 6 were drilled in 1991 and 1992, respectively. These proved substantial quantities of oil in both the western and eastern parts of the field. Well 15/24b-5 found 180 ft of oil filled reservoir with 30% average porosity, while well 15/24b-6 encountered a 140 ft oil column in sandstones with 25% porosity. A 3D seismic survey was acquired in 1993 and subsequent remapping confirmed that sufficient hydrocarbon volumes were present to make the field economically viable. Field development approval was received on 22 November 1995 and Phase 1 development drilling began in March 1996. This consisted of drilling wells 15/24b-W1, 15/24b-W 1z and 15/24b-W 1y, and then pre-drilling horizontal producers 15/24b-W2, 15/24b-W3 and 15/24b-E1 (Fig. 3). Phase 2 drilling commenced a year later in June 1997, when the pilot holes 15/24b-W 1x and 15/24b-W 1w proved oil in two additional areas of the field into which production wells 15/24b-W4 and 15/24b-W5 were then drilled. All of these wells are tied back to the Floating Production System (Fig. 4). First oil was achieved on the 10 August 1997 with peak rates of up to 60 000 BOPD. In M a y 1999 the sixth production well, 15/24b-W6 was completed. As of November 1999 over 30 M M B B L has been produced with production currently exceeding 30 000 BOPD. Future wells may be drilled into undrained areas of the field.
History
Structure
Block 15/24 was initially awarded in the 4th Round of offshore licensing to Hamilton Brothers and subsequently relinquished. Conoco (UK) Ltd. and Lasmo plc were awarded Block 15/24b as Licence P.640 in the l lth Licensing Round. Conoco initially held 60% of the equity but sold 20% of the block to Rigel Petroleum in July 1997. Rigel's equity was acquired by Talisman Energy (UK) Ltd. by means of their purchase of Rigel in 1999. The first well on the structure was 15/24-1, which was drilled by Hamilton Brothers in July 1972. This had a primary objective of Paleocene sands, with secondary objectives in the Danian Chalk and the Lower Cretaceous/Jurassic sands. Oil shows were found in the Palaeocene, and casing was set at a shallow level to allow testing of this zone. As a result the Jurassic interval was never penetrated, the well being terminated at 8169ft TVDSS in the Danian. Two formation tests were performed on the late Paleocene sandstones, but these failed to flow. The current interpretation suggests that the well penetrated a low area in the middle of the field and found a palaeo-oil-water contact. Well 15/24b-3 was drilled by Conoco in January 1990, with the intention of appraising the Paleocene sandstones found by well
The MacCulloch Field lies in the Tertiary fill of the Witch Ground Graben area of the Central North Sea (Glennie 1984). The area underwent extension in the Mid and Late Jurassic in conjunction with the deflation of a Middle Jurassic volcanic centre in the North Sea 'triple junction' to the southeast (Boldy & Brealey 1990). At this time previously established basement lineations were re-utilized as extensional fault planes (Caledonian, Tornquist) resulting in a trapezoidal Jurassic fault pattern, the dominant trends being N E - S W , N W - S E and E - W (Bartholomew et al. 1993). Syn-depositional fill of evolving half grabens continued throughout the Upper Jurassic and, in places, into the Lower Cretaceous. The regional structural configuration was of a regional palaeo-high to the north and east (the Fladen Ground Spur) and an irregularly faulted slope into the basin centre to the south. The post-rift Cretaceous fill of the Lower Cretaceous Cromer Knoll Group and the Upper Cretaceous Chalk Group appears to have buried the remnant Jurassic topography in the outer Moray Firth (Boote & Gustav 1987) thereby creating a more or less monoclinal N W - S E oriented slope on which Tertiary sediments were deposited. The Cretaceous marked a period during which high
GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 453-466.
453
454
C. G U N N E T AL .
9
?,
MACCULLOCH FIELD
455
;L
cael
e4
456
C. G U N N E T AL.
~A 9
o
o f4
M A C C U L L O C H FIELD
457
o . ,...~
'5 9
9
458
C. GUNN E T AL.
subsidence rates, low sediment accumulation rates and globally high sea levels combined to produce a deep marine basin. The Palaeogene marks a return to clastic deposition and a close interplay of regional tectonic activity, associated with the opening of the North Atlantic (Den Hartog Jager et al. 1993). A shelfslope-basin configuration appears to have been present throughout the Tertiary. In the Paleocene the submarine shelf-slope break appears to have extended northeast to southwest across the Witch Ground Graben. The Upper Bahnoral Sandstone reservoir in MacCulloch appears to have been deposited in sinuous channels, which are analagous to the erosive/depositional Ainsa II channel complex described by Clark & Pickering (1996). The present day structure reflects mainly the combination of differential compaction of these channelized sandstones superimposed on an overall N W - S E dipping slope. Locally, discrete highs can be related to ribbon-like channels; however, some degree of caution must be exercised in assuming that a 'high' confirms the presence of sand because of the complicating factors of channel stacking patterns and the effects of late inversion. Faulting over the MacCulloch channel trend is very pronounced at Top Balder level. These faults outline the track of the major Balmoral and Forties channel systems in the area (Fig. 5). In section, the faults are extensional and appear to nucleate along the flanks of the Upper Balmoral channels. Faults appear to detach at various levels within the Paleocene section, but mainly in the Lista Formation shales overlying the Upper Balmoral Sandstone. In general, within the field area, faults are of minor significance with throws in the order of 20 ft-40 ft. Basin-wide compression at the end of the Eocene seems to have brought about slight inversion of some Jurassic faults, particularly those in an E-W orientation (probably from north-south-oriented compressional stresses). The influence of this inversion on the field's architecture is fundamental in the exploitation of such a low relief
structure. In particular, the area around well 15/24b-5 (Fig. 3) appears to have benefited from additional relief in this manner. A palaeo-oil leg exists beneath the current oil-water contact. The presence of a residual oil section would seem to support the idea of some late structural reconfiguration and tilting or breaching of the original trap.
Stratigraphy The Tertiary stratigraphy of MacCulloch Field is summarized in Figure 6. The stratigraphical nomenclature used is that of Knox & Holloway (1984). The reservoir is sandstone of the Late Paleocene Lista Formation, that is composed of the Upper and Lower Balmoral Sandstones underlain by the Andrew Sandstone (Fig. 2). The top of the Upper BaImoral Sandstone is marked by an abandonment sequence, which varies in thickness over the MacCulloch Field from less than 10ft to 40ft thick. This marks the final drowning of the channel system during transgression and the cut-off in supply of sandy turbidite flows. Four sandstone packages, called Zones 1 to 4 have been distinguished within the Upper Balmoral based on detailed biostratigraphic investigation and correlation (Costa 1999). The overlying Paleocene sequence, comprising the Sele Formation, is represented by basinal mudstones and marine shales, which form the seal for the MacCulloch Field reservoir. The Forties Sandstone Member is not present over the MacCulloch Field, as sandstone channels of this age appear to have been diverted to the south. The overlying Balder Formation forms a regionally correlatable seismic marker and a well-documented chronostratigraphic horizon. The Balder Formation consists of tuffaceous deposits, which mark a temporary increase in volcanic activity related to the
Fig. 5. ER-Mapper time shaded display of Top Balder time structure.
M A C C U L L O C H FIELD
Fig. 6. Generalized stratigraphy showing the relative thickness of overburden, geology and a detailed Upper Balmoral Sandstone reservoir section.
459
460
C. GUNN ET AL.
Fig. 7. Massive sands.
spreading of the North Atlantic and the development of a 'hot spot' responsible for volcanics found in western Scotland and the Isle of Skye (Knox & Morton 1988). This sequence drapes the entire area and forms an easily interpreted seismic horizon. Faulting within the Balder Formation is often compactional and is tied to the underlying sandstone channels, and 3D seismic displays of the Balder Formation in this area illustrate the dominant NW-SE trending sinuous channel systems and the influence of subtle Jurassic fault trends (Fig. 5). The Eocene and younger section is again a clastic section comprising basinal muds and prograding shelf/slope systems. A drilling hazard assessment of Blocks 15/19 and 15/24b indicates the presence of potential shallow gas hazards at the base of the Quaternary section above the field. A major erosive channel of the Quaternary Ling Bank Formation is also present in the sequence above the MacCulloch Field. The channel trends in a W S W - E N E direction may have an influence on seismic stacking velocities
Trap summary Hydrocarbons are trapped in MacCulloch Field by four-way dip closure created mainly by the mounded Upper Balmoral Sandstones. This topography is influenced both by reactivation of some deeper faults and by some post-Balder faulting, in addition to compactional drape. Spill appears to be up-channel to the northwest.
Reservoir The Upper Balmoral Sandstones were generally deposited as massive submarine debris flows. The most likely model suggests a very complex system of stacked channels and levees. The sand bodies are interpreted as being pod-like, or being linked as a string of 'pearls'. Sand deposition occurred within a sinuous channel thalweg, (Clark & Pickering 1996) that runs down-slope from NW-SE across the area (Fig. 5). Although sand deposition in the channel was aggradational over time, successive turbidite events probably switched around within the channel, seeking topographically low areas and filling them preferentially. Flow stripping (sensu Piper and Normark 1983) - a phenomenon whereby sand is preferentially deposited on the outside, down-stream portions of channel bends - is a probable depositional process in MacCulloch Field. Subsequent deposition leads to channel infill from the outside inwards. Genetically related features such as stacked massive sands (Fig. 7), sand injection and soft sediment disruption (Fig. 8), interchannel deposits (Fig. 8), bank collapse and mass wasting deposits (Fig. 9) and waning flow/low density turbidite deposits (Fig. 10) are also present. The degree of channel sinuosity may have been controlled by slope angle (Timbrell 1993), regional tectonism and/or progressive infilling of the basin, deflection of flows around and between local highs, minor reactivation or inversion of Jurassic basement or combinations of all of these.
MACCULLOCH FIELD
461
Fig. 8. Injected sands.
Individual Upper Balmoral channels appear to have some distinctive characteristics: (a)
(b) (c) (d)
They are narrower than the underlying channels, being in the region of 600-1000m in width as mapped on seismic and confirmed by wells; they appear to have undergone periodic abandonment and switching (avulsion); they contain local mud concentrations within the channel complex; and the sands are more radioactive and have a higher gamma-ray signature than the underlying Lower Balmoral Sandstone.
The boundary between the Lower and Upper Balmoral Sandstones has been interpreted to lie within a 'transgressive', laterally persistent shale which can be seen on some well logs in the area. This shale break is less obvious over the MacCulloch Field area within the main channel axis, where it may have been eroded. The Upper Balmoral Sandstone of the MacCulloch Field has been subdivided into four zones (Fig. 11). Note that Zone 1 consists of sand and shale and is equivalent to the top of the Upper Lista Formation. The zonation is based on biostratigraphical and lithostratigraphical correlations and each zone represents an episode of sand deposition, with the lower two zones being more sheet-like and the upper two zones more channelized. The top of reservoir sandstone may occur within Zones 1, 2 or 3 depending on location within the field.
Reservoir quality is generally very good, with an average porosity of 28% and core permeabilities between 200 mD and 2 D.
Source and migration The source rocks for MacCulloch Field are Jurassic Kimmeridge Clay Formation shales, which are currently modelled to be generating oil in the lows to the south and southeast of the field (Cole & Turner 1997). A geochemical study of the crude produced from well 15/24b-3 shows it to be derived from the Kimmeridge Clay Formation (Geochem 1993). It is derived from the same biofacies as Tertiary reservoired crudes from other wells in Quadrants 9, 15 and 16. The whole oil carbon isotope value of the oil suggests that it was sourced from sediments deposited under normal marine conditions. Oil migration is believed to have occurred vertically through faults which penetrate the chalk and then, laterally through Paleocene sheet and channel sandstones.
Seismic character Mapping of the top Balmoral Sandstone is often problematic, due to its low reflectivity and the complex stratigraphic relationships at this level. In general the top of the Balmoral unit (Zone 1 sand or
462
C. GUNN E T AL.
Fig. 9. Intra-channel sands.
Zone 2 where no Zone l sand is present) has a higher acoustic impedance than the overlying Lista shale and is mapped as a trough on SEG reverse polarity data. However, this pick does not always correspond with top sand, for example, at well 15/24b-Wlx the uppermost sand is deeper, in Zone 3. Four biostratigraphic zones within the Balmoral Sandstone have also been mapped on seismic, where picking confidence varied from good to poor. This has allowed the STOOIP and reserves to be calculated by zone, to aid well planning and maximize oil recovery. Where a thick Zone 1 sandstone is present at the top of the reservoir, such as in well 15/24b-6, the increase in impedance indicates that the top sand event is represented by a trough on a zero offset synthetic. However, synthetic amplitude versus offset (AVO) modelling of the well suggests that the amplitude of this event weakens with offset and becomes a peak on the far offsets i.e. a Class II type response using Rutherford and Williams, 1989 classification (Fig. 12). This behaviour complicates the expected full stack seismic response and suggests that the top reservoir pick can be better understood using partial offset volumes. Near and far seismic volumes have therefore been processed. In addition to AVO effects seen at the top reservoir, a strong AVO effect is observed on these 3D seismic data volumes at the oilwater contact over large parts of the field. This takes the form of a
fiat seismic event on the far-offset seismic volume. The increase in acoustic impedance at the oil-water contact is represented by a red trough, which has low amplitude on the near offset volume, and much stronger amplitude on the far-offset data. The synthetic gather shown in Figure 12 also predicts this effect. In addition to the AVO effects due to hydrocarbons, a thin oil column can cause significant tuning between the top sand and the oil-water contact seismic events on the lower frequency far volume. In Figure 13, the combination of AVO effects and tuning can be seen at well 15/24b-6. In some wells the top Balmoral section is shaly and no distinct AVO character is developed at top sand.
Hydrocarbons The MacCulloch Field contains a 32-37 ~ API black oil, analogous to that of nearby Tertiary fields. Selected properties of the crude at reservoir conditions are: 9 9 9
Formation Volume Factor Bubble point GOR
1.2 RB/STB 1700-2290psia 386-424 SCF/STB
MACCULLOCH FIELD
463
Fig. 10. Wanning flow facies.
The recombined reservoir fluid composition of samples taken from well 15/24b-5 in the core area of the field is tabulated overleaf:
Component
Mol. %
Nitrogen Hydrogen sulphide Carbon dioxide Methane Ethane Propane Isobutane N-Butane Isopentane N-Pentane Hexanes Heptanes +
0.46 0.00 0.20 33.26 2.85 3.2 1.44 2.87 1.61 1.6 2.3 50.21
Reserves and production First oil production occurred on 10 August 1997 with production levels up to 60 000 BOPD. To date the field has produced approxi-
mately 30 MMBLS. Water breakthrough occurred after about four months of production and the water cut has steadily risen, as expected, to the current levels of 65%. Production is through six horizontal producers, with a further producer planned for 2000. The horizontal wells vary in length from 850-3500 ft and are drilled at the top of the closure in order to maximize stand-off from the underlying water. Their length is optimized to maximize production efficiency whilst minimizing drawdown. Due to the friable nature of the sandstone they are completed with sand screens and all wells are completed with a gas lift capability. Produced fluid is taken via flexible flowlines to the 'North Sea Producer' FPSO where it is processed. Oil and gas are then exported via pipeline to the Piper-B platform, the oil being taken ashore via the Flotta pipeline system. The reservoir has a strong natural aquifer drive, which has maintained the reservoir pressure to within 150 psi of initial pressure, with no need for water injection to ensure pressure maintenance. Recovery and sweep is dominated by water coning effects. The high permeability sandstones ensure good deliverability to the wells, with rates of up to 28 000 BOPD from individual wells seen early in field life. As the water cut has risen the productivity has reduced as would be predicted by the relative permeability. On high water cuts gas lift has been implemented and optimized. Gas lift is now key to maintaining production and has provided significant uplift in volumes.
464
C. G U N N E T AL.
OWC
Fig. 11. Reservoir zonation model.
Full field s i m u l a t i o n indicates reserves o f a b o u t 6 0 - 9 0 M M B O E . I n d i v i d u a l wells m a y recover b e t w e e n 2 5 % a n d 55% o f the O O I P with which they are associated, the final recoveries being m a i n l y d e p e n d a n t o n the s t a n d - o f f f r o m the aquifer t h a t is achieved. The authors wish to thank ConocoPhillips (UK) Ltd, Lasmo North Sea PLC and Talisman Energy (UK) Ltd for permission to publish this paper.
MacCulloch Field data summary Trap Type
Depth to crest Lowest closing contour FWL
Oil column Pay zone Formation
Four-way dip closure over turbidite sandstone mound 6000 ft (1828 m) TVDss 6249 ft (1905 m) TVDss Between 6249 ft and 6232 ft (1905m and 1899m) TVDss (OWC dips gently to west) 240 ft (73 m)
Porosity average (range) Matrix permeability Average oil saturation Productivity index
Upper Balmoral Sandstone of Lista Formation Late Paleocene 175-540 ft (53 m-165 m) 0.4-0.9 Porosity 15% Vsh 25% 28% (24% 32%) 200 2000 mD (core Kh) 9O% 50-300 BOPD/psi
Hydrocarbons Oil gravity Oil type
32-37 ~ API Black oil
Age Gross thickness Net/gross ratio Net sand cut-off
Bubble point Gas/oil ratio Formation volume factor
1700-2290 psia 386-424 SCF/BBL 1.2 RB/STB
Formation water Salinity Resistivity
90 000 ppm NaC1 equivalent 0.0781 ohm-m at 25 ~ (77~
Reservoir conditions Temperature Pressure Pressure gradient in reservoir
175~ 2770psi at 6150ft (1874m) TVDss 0.33 psi/ft
Field eharucwristics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil
3334 acres ( 13.5 km 2) 205 769 acre-ft (254 • 106 m 3) 2770psia at 6150ft (1874m) TVDss 0.033 psi/ft (oil leg) 79~ (175~ 200 MMSTB 3O 35% Natural Aquifer 60-70 MMSTB
Production Start-up date Development scheme
Number/type of wells
Production rate
10 August 1997 2 drill centres with flexible flowlines tied back to an FPSO. Export via pipeline, with oil tanker offtake option. 4 exploration/appraisal 11 pilot and development wells, 6 of which are producers 60 000 BOPD maximum peak rate
MACCULLOCH FIELD
465
9
0 > < i
,.0 eq
..~
466
C. G U N N E T AL.
Fig. 13. Line through well 15/24b-6, illustrating the AVO effects.
References BARTHOLOMEW, I. D., PETERS, J. M. & POWELL, C. M. 1993. Regional structural evolution of the North Sea: oblique slip and the reactivation of basement lineaments. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. The Geological Society, London, 1109-122. BOLDY, S. A. R. & BREALEY, S. 1990. Jurassic Tectonism in the Outer Moray Firth. In: HARDMAN, R. P. F. & BROOKS, J. (eds) Tectonic Events" Responsible for Britain's Oil and Gas Reserves. The Geological Society, London, 259-279. BOOTE, D. R. D. & GUSTAV, S. H. 1987. Evolving depositional systems within an active rift, Witch Ground Graben, North Sea. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology oJ" North West Europe, Vol. 2. Graham & Trotman, London. CLARK, J. D. & PICKERING, K. Y. 1996. Submarine Channels." Processes and Architecture. Vallis Press, London, 127-132. COLE, J. & TURNER, J. 1997. The maturation history of oil-prone source rocks in the Moray Firth rift arm and Central North Sea. Unpublished University of Edinburgh Report for Conoco (UK) Limited. COSTA, L. I. 1999. Conoco (UK) MacCulloch Field Reservoir Biostrat(graphy. Robertsons Research International Report for Conoco (UK) Ltd. DEN HARTOG JAGER, D., GILES, M. R. & GRIFFITHS, G. R. 1993. Evolution of Paleogene submarine fans of the North Sea in space and time. In:
PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. The Geological Society, London, 59-71. GEOCHEM 1993. A geochemical stud)' into Tertiary North Sea crudes. Unpublished Report for Conoco (UK) Limited. GLENNIE, K. W. 1984. Outline of North Sea History and Structural Framework. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell, London, 34-77. KNOX, R. W. O'B. & HOLLOWAY, S. 1992. Paleogene of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea, Vol. 1. British Geological Survey, London. KNOX, R. W. O'B. & MORTON, A. C. 1988. The record of Tertiary North Atlantic volcanism in sediments of the North Sea Basin. In: MORTON, A. C. & PARSON, L. M. (eds) Early Tertiary Volcanism and the Opening of the NE Atlantic. Geological Society, London, Special Publications, 39, 407-419. PIPER, D. J. W. & NORMARK, W. R. 1983. Turbidite depositional patterns and flow characteristics, Navy submarine fan, California Borderlands. Sedimentology, 30, 681-694. RUTHERFORD, S. R. & WILLIAMS, R. H. 1989, Amplitude-versus- offset variations in gas sands. Geophysics, 54, 680-688. TIMBRELL, G. 1993. Sandstone architecture of the Balder Formation depositional system, UK Quadrant 9 and adjacent areas. In: PARKER, J. R. (ed) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. The Geological Society, London, 107-121.
The Scott Field, Blocks 15121a, 15/22, UK North Sea SIMON
GUSCOTT
1, K E N
R U S S E L L 2, A N D R E W
THICKPENNY
2 & ROBERT
PODDUBIUK
3
l Amerada Hess Limited, Scott House, Hareness Road, Aberdeen AB12 3LE, UK Present address." Amerada Hess Corporation, 500 Dallas St, Houston, T X 77002, USA 2 Lomond Associates, Lochwood, Johnshill, Lochwinnoch, Renfrewshire P A l 2 4EH, UK 3 Amerada Hess Limited, 33 Grosvenor Place, London SW1 7HY, UK
Abstract: The Scott Field straddles Blocks 15/21 and 15/22 on the southern flanks of the Witch Ground Graben in the Outer Moray Firth Basin, UKCS. The oil field is developed in the highly productive Upper Jurassic Humber Group sandstones of Oxfordian to Kimmeridgian age. The field was discovered in 1983, sanctioned in 1990, and produced first oil in 1993. The field structure, effectively a large southwards tilted fault block, is compartmentalized into a series of four main pressure isolated fault blocks by mid to late Jurassic faulting. The Kimmeridge Clay Formation provides both the top seal and the source of the trapped hydrocarbons. Fluid contact, overpressure and compositional trends suggest that the trap was filled primarily from the north. Some trap-defining faults were already active during the deposition of the reservoir intervals. Well data indicate that the development of accommodation space was tectonically controlled during this period, with subsidence occurring more rapidly in the western areas of the field. The Scott Field reservoir consists of two major sand packages, the Scott Sandstone Member and the Piper Sandstone Member, bounded above and below by marine flooding surfaces. The late Oxfordian Scott Sandstone Member consists of a westwards prograding marine shoreface sandstone overlain by aggradational and retrogradational back-barrier deposits. Above this, the Mid Shale is a regionally extensive flooding event separating the Scott Sandstone Member from the overlying Piper Sandstone Member. The early Kimmeridgian Piper Sandstone Member consists of stacked mass flow sandstones, overlain by a shoreface/back-barrier system. Lateral facies changes and thickness variations significantly affect reservoir distribution in both Scott and Piper intervals. The best reservoir quality occurs within the coarsest grained, highest energy facies, particularly the shoreface and proximal washover deposits. At the crest of the field, 10400ft TVDss, multi-Darcy permeabilities and porosities of 20% are common. However, reservoir quality declines progressively downflank due to increased quartz cementation and compaction. The Scott Field currently produces from 23 wells supported by 20 water injectors. Current modelling is aimed at targeting bypassed oil to increase ultimate recovery. The field has presently produced 300 MMSTB of oil from forecast reserves of 440 MMSTB with an estimated ultimate recovery factor of c. 46%.
The Scott Field is located on the southern flank o f the Witch G r o u n d G r a b e n in the Outer M o r a y Firth Basin (Figs 1 and 2). The U p p e r Jurassic reservoir interval is developed in a series of rotated fault blocks that straddle the b o u n d a r y between Blocks 15/21 and 15/22 of the U K C S . Reservoir sandstones o f late Oxfordian to early K i m m e r i d g i a n age are separated by laterally extensive mudstones. These sandstones are correlated with H u m b e r G r o u p reservoir sandstones in the Piper, Tartan, Ivanhoe, R o b R o y a n d Telford
Fields (Fig. 1). In the Outer M o r a y Firth Basin, H a r k e r & R i e u f (1996) estimate that these sandstones contain oil reserves of almost three billion barrels. The Scott Field was discovered by well 15/22-4 (Fig. 3) in 1983 a n d came on-stream in September 1993. The field has an areal extent o f c. 35 k m 2 and has been developed with a c o m b i n a t i o n o f sub-sea a n d platform drilled wells. There are currently 26 sub-sea wells tied back to five manifolds and a further 17 wells drilled directly from
Fig. 1. Location map of the Scott Field. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 467-482.
467
468
S. GUSCOTT E T AL. 13 100 ft TVDss (Figs 3 and 4); optimism regarding the value of the field was muted. The potential for a major oilfield associated with the Scott structure only became apparent when well 15/21 a-15 was drilled in 1987 (Figs 3, 4 & 5). The well penetrated top reservoir just below 11 100 ft TVDss and encountered nearly 400 ft of net pay. Moreover, oil pressure data lay on the same oil pressure gradient as that from well 15/22-4, over 1000 ft below (Fig. 4). A rapid programme of appraisal drilling over the following two years revealed the existence of several large oil pools with different pressure regimes in separate downthrown fault blocks to the north. The South Scott oil accumulation lies to the south of a syncline that separates it from the main Scott Field structure and was discovered by well 15/22-9 in 1990 (Fig. 3). This well penetrated top reservoir at approximately 11 840 ft TVDss and encountered 24 ft of oil-bearing Upper Jurassic sandstone. The well was side-tracked downdip and encountered 101 ft of net pay with an average oil saturation of >90% just below 12300ft TVDss. The economic nature of the area was finally proven by well 15/21a-43 (Fig. 3), drilled during 1991, which encountered 245 ft of net pay near the western limit of the South Scott structure.
Structural evolution
Fig. 2. The major structural elements of the Outer Moray Firth Basin in the vicinity of the Scott Field. The map is based on a composite seismic image created for the top Zechstein. Blocks 15/21 and 15/22 of the UKCS are shown in outline.
the Scott Platform. Peak production of c. 220000 STBd -I was achieved in 1995. Production in 1999 averaged c. 8 0 0 0 0 S T B d -I with a water cut of 60%. Ultimate recoverable reserves are estimated at 440 MMSTB, and as such the Scott Field was one of the largest developments to have come on stream in the UKCS during the 1990s. Current projections suggest that the field will continue producing oil into the latter part of the next decade.
History Blocks 15/21 and 15/22 were both awarded as part of the 4th Round of U K Offshore Licensing in 1972. Initial exploration focused on relatively shallow prospects, 7000 ft to 8000 ft TVDss, and resulted in the discovery of the Ivanhoe Field by well 15/21-3 in 1975. Appraisal of the deeper Scott structure, with a crest at 10400ft TVDss, began in 1977 when well 15/22-3 was drilled as a joint venture between the licence groups (Fig. 3). The well was targeted downflank from the crest of the structure but failed to find reservoir in the Upper Jurassic interval. Extensive crestal erosion was interpreted at the time and further appraisal was delayed for several years. In 1983, the 15/22 licence group returned to the Scott structure, drilling well 15/22-4 to a target location significantly further downdip than that of well 15/22-3 (Fig. 3). This well encountered c. 200 ft of Upper Jurassic reservoir just below 12 000 ft TVDss, comprising two main sandstones separated by a 50ft mudstone. The upper sandstone was water-bearing, but an oil-bearing lower sandstone (Fig. 4) demonstrated the existence of a charged trap. Further down-dip appraisal by well 15/22-5 in 1985 encountered a thin water-bearing interval of poor reservoir quality at approximately
The Scott Field reservoir is highly compartmentalized by faulting and is delineated by two main structural trends (Fig. 3). The first reflects those of the Theta Graben area of Block 15/21 (Hibbert & Mackertich 1993) and consists of both N-S and N E - S W fault systems. These systems are a combination of mid Cimmerian extension in the early Jurassic (N-S trending faults), and the reactivation of Caledonide fault trends ( N E - S W faulting). The second trend comprises E - W orientated faults that result from late Jurassic N - S extension in the Witch Ground Graben area to the north of the field. The E - W 'Witch Ground' trend faulting broadly post-dates the deposition of the reservoir interval. The crest of the Scott Field occurs at c. 10 400 ft TVDss and the main field structure, a southwards dipping complexly faulted block, can be broadly divided into two subequal areas by a substantial N E - S W trending fault system that down throws to the northwest (Fig. 3). This faulting isolates structural Block II from the rest of the field (Fig. 6a). To the south and east of this faulting lie Scott Field structural blocks I, Ib, III and IV (Fig. 3). Late Jurassic fault influence is most apparent in these blocks where the reservoir is compartmentalized by a series of broadly E - W orientated faults that downthrow northwards, towards the Witch Ground Graben (Fig. 6b). In the south of Block I a W N W - E S E orientated syncline defines the southern extent of the main Scott Field (Fig. 3). To the south of this syncline is the South Scott oil accumulation. The South Scott area is characterized by a complex E - W fault system that parallels the main bounding fault. The South Scott/Telford bounding fault downthrows approximately 1000ft to the north and separates the South Scott reservoir from the Telford and Marmion oil accumulations developed in the footwall of the structure. The South Scott reserves accumulated in a complex series of rotated fault blocks that are interpreted to have formed as a result of footwall collapse along the main bounding fault. Three dimensional structural restorations have identified a complex structural evolution for the field, with a number of episodes of fault movement recognized along both the main structural trends. Early post-Zechstein structural activity involved the major fault trends. The mid-Jurassic Rattray Formation volcanics are anomalous as their deposition appears to be controlled by a structural lineament trending NW-SE. This lineament also acted as a strain partition during later extension, but shows little vertical or horizontal displacement. Similar structures have been documented further east in Quad 15 where they also appear to control deposition of the Rattray Formation volcanics (Jones et al. 1999). In the late Oxfordian there is evidence from isopach data for syndepositional fault movement as a result of N W - S E orientated
SCOTT FIELD
Fig. 3. Top Piper Formation structure map for the Scott Field showing the location of exploration, appraisal and development wells.
Fig. 4. Reservoir fluid pressure data for exploration wells 15/22-4, 15/22-5 and 15/21a-15. Data shows oil and water pressure gradients in the Scott Field structural Block I and the inferred oil-water contacts in the block. Note that the oil-water contact in the Piper Sandstones is significantly shallower than that in the Scott Sandstones, creating a perched contact.
469
470
S. GUSCOTT E T A L .
Fig 5. Scott Field type well 15/21a-15. Well 15/21a-15 is defined as the reference well for the Sgiath Formation (Humber Group) by Harker et al. (1993). Spudded in 1987, the well was the first to prove the economic nature of the Scott structure. All four major sand packages (Upper Piper, Lower Piper, Upper Scott, Lower Scott) were oil-bearing (see text for details).
extension. The extension created a transtensional environment in the Scott Field area and, as a consequence, the area was gently folded. During the Kimmeridgian, extension continued along the main N E - S W trending structures, and by this time there is also evidence for limited extension along the east-west structures. Late Jurassic extension in the Witch Ground Graben area probably initiated in the latest Oxfordian, although the main phase of extension occurred during the Kimmeridgian and Volgian. The N-S orientated extension was accommodated by large E - W trending faults (Fig. 2) and resulted in significant thickening of the Kimmeridge Clay Formation mudstones in the hanging walls of the major faults controlling the extension. Thickened Kimmeridge Clay Formation sections are observed in the Block II area and into the main South Scott bounding fault (see Fig. 6a, b). Seismic data indicate that during the mid-late Cretaceous the Scott Field underwent inversion that resulted from transpression along the South Scott/Telford bounding fault. The inversion is also locally evident along the main N E - S W Block I/Block II bounding fault, where the base Cretaceous reflector shows positive relief in the immediate hanging wall to the fault (Fig. 6a), and probably continued into the Tertiary.
Stratigraphy The stratigraphy of the Upper Jurassic in the Witch Ground Graben has been addressed by a number of workers over the past ten years. A listing of the available published work is given in their introduction by Duxbury et al. (1999). Figure 7 shows the stratigraphic units presently recognized in the Scott Field and relates these to the regional scheme proposed by Harker et al. (1993). It also shows how the units compare with the U K O O A scheme for the North Sea (Richards et al. 1993), and to the previous published stratigraphy of the nearby Rob Roy Field (Boldy & Brealey 1990). Detailed correlation of the late Oxfordian to early Kimmeridgian interval has historically proved difficult due to poor biostratigraphic resolution, and there is still disagreement over the reliability of criteria used to define correlative marker events. On a broad scale however, there is now an emerging consensus that two major sand packages, bounded above and below by marine flooding episodes, can be widely recognized across the area. In the Scott Field, these are the Piper Sandstone Member and the Scott Sandstone Member, separated by the Mid Shale Member which can be correlated with the Mid Shale on Rob Roy Field and the I Shale on the Piper Field (Harker
SCOTT F I E L D
471
Fig. 6. (a) Seismic line A - A f (see inset for location) showing the N E - S W 'Theta' trend faulting that downthrows the Block II area of the Scott Field to the NW. Note the thickened Kimmeridge Clay Formation sections in the Block I and Block II areas compared to the Telford area to the extreme south on the diagram shown. (b) Seismic line B-B / (see inset for location) shows the rotated fault blocks that downthrow to the north in response to late Jurassic N - S extension in the Witch Ground Graben area. Each of the fault blocks shown has different hydrocarbon compositions and different overpressures relative to hydrostatic pressure.
472
S. GUSCOTT E T AL.
Scott Field This Paper
Time
Kimmeridge Clay Formation
Rob Roy Boldy & Brealey (1990)
Harker et al (1993)
Kimmeridge Clay Formation KimmeridgeClay Formation
KPT Unit >-~ i h-
.~_
~.~ U.Pipers ">~ ~E ~'~; L. Piper/< Sst >~ Mid Shale Member ~ o~~ ~E
E o ~-~
Middle Jurassic
u.sytt@ L. SScott s t f
Saltire
Member
Er ~~ E ~
Estuarine
-~~ o ~ iY.
~ E ~ ._~ o~
Transgressive Unit Supra Piper Sandstone Unit
Sandstone
f ~ ~-"-" I Shale
Scott Member ~ - - ~
~E ~.
Mid Shale Unit
iY_
Main Piper Sandstone Unit
Saltire Member
Skene Member
Coastal Plain Rattray
BGS/UKOOA Richards et al (1993)
Rattray
x: .-~ -~ ~ 5~E co~_
_~
Marine Unit
co -~ m
Paralic Unit
~
Kimmeridge Clay
~Formation
u_
, / O..Q 2E
~
~
u~ "~
E~ co~
Heather
: ~ Formation
~,
Gorse ember
Coal Unit
MiddleJurassic
Rattray
et al. 1993). These authors assign the Skene, Saltire and Scott
Sandstone Members to the Sgiath Formation, and the Mid Shale and Piper Sandstone Members to the overlying Piper Formation (Fig. 7). The oldest stratigraphic level penetrated by wells on the Scott Field is that of the Permian Zechstein, penetrated by well 15/22-E2 in the South Scott area. More typically, however, wells penetrate volcanic rocks of the Middle Jurassic (Fladen Group) Rattray Formation. Overlying the Rattray Formation, probably unconformably, are emergent coastal plain sediments and paralic estuarine mudstones that together comprise the Skene Member of the Sgiath Formation. Although not generally cored in the Scott Field, these are extensively cored in the Marmion and Telford areas immediately to the south, where they contain abundant reworked igneous clasts and localized rootlet traces. The Saltire Member, an open marine mudstone that represents the first widely correlatable marine flooding episode, overlies the Skene Member. Harker et al. (1993) equate this with the major regional flooding event that occurs within the glosense ammonite zone, although Kadolsky et al. (1999) equate it with the younger serratum zone (maximum flooding surface). Above the Saltire Member, the Sgiath Formation consists of a thick shallowing-upwards sandstone package, the Scott Sandstone Member, deposited by a westwards prograding shoreface and back-barrier system. The Scott Sandstone Member is divided into a thick Lower Scott Sandstone and a thinner Upper Scott Sandstone. The Lower Scott Sandstone was deposited during the main progradation and vertical aggradation phase of the system. The Upper Scott Sandstone was deposited during a later retrogradational period, during which barrier sands were reworked eastwards into the back-barrier lagoon as two stacked flood-tidal delta lobes. The Scott depositional system was terminated by the next major regional flooding episode, represented by the Mid Shale Member, marking a return to open marine conditions at the end of the late Oxfordian. It defines the boundary between the Sgiath and Piper Formations, and Harker et al. (1993) equate it with the major regional flooding episode within the rosenkrantzi ammonite zone. Overlying the Mid Shale Member is the second major sandstone package, the Piper Sandstone Member. This comprises two parts, a Lower Piper Sandstone and an Upper Piper Sandstone. The Lower Piper Sandstone consists of a series of stacked mass-flow sandstones that were deposited over a large area of the Scott Field. The Upper Piper Sandstone is a separate shallowing-upwards sandstone package, deposited by a westwards prograding shoreface and backbarrier system not unlike the Scott Sandstone Member, except that its progradation was more limited and it shales out progressively in the west of the field.
Fig. 7. Stratigraphic nomenclature utilized in the Scott Field compared to that previously published for the Witch Ground Graben area.
The Piper depositional system was effectively terminated by a third regional marine flooding episode, although a thin, very distal, prograding unit termed the Kimmeridge Piper Transition Unit (KPT) overlies it. A similar thin 'Transgressive Unit' is recognized in the Rob Roy Field (Boldy & Brealey 1990), and may correlate with the thin 'Hot Sand Unit' in the Tartan Field (Coward et al. 1991). The flooding event at the base of the KPT Unit appears widespread, but there is a lack of consensus as to its age, and which biostratigraphic markers may be used to reliably identify it. The eventual permanent drowning of the area, resulting in deposition of the Kimmeridge Clay Formation, is equated with a major regional flooding in the eudoxus ammonite zone (Harker et al. 1993). However, due to structural activity at this time, the flooding would have been controlled by local topography, and may be diachronous across different parts of the Witch Ground Graben.
Trap The Scott Field reservoir exhibits elements of both stratigraphical and structural trapping. The Kimmeridge Clay Formation forms the top seal for the reservoir across the majority of the field structure, although the base Cretaceous in the crestal areas of structural Blocks Ib, III, and IV (Fig. 6b) truncates the reservoir. The Kimmeridge Clay Formation also provides a lateral seal to the reservoir where major faults juxtapose the reservoir sandstones against Kimmeridge Clay Formation mudstones. At the crest of Block I this mechanism supports an oil column of 2000 ft in the Scott sandstones. The presence of significant pressure differentials between adjacent fault blocks and within individual fault blocks demonstrates that fault sealing is also an important trapping mechanism within the Scott Field. In the South Scott area the top seal is provided by the Kimmeridge Clay Formation whilst the southern lateral seal is against the main South Scott/Telford bounding fault that juxtaposes the reservoir interval against the underlying Rattray Formation volcanics and older strata. Within the reservoir interval the major mudstone intervals also act as significant barriers to vertical fluid flow. In Block I the oilwater contact in the Piper sandstones is > 1000 ft shallower than in the underlying Scott sandstones, this difference is sustained across the Mid Shale Member (Fig. 8). By contrast, in the neighbouring Block Ib, the Piper and Scott sandstones share a common oil-water contact. Table 1 lists the most likely oil-water contacts for the main structural blocks within the Scott Field.
SCOTT FIELD
473
Fig. 8. Structural cross-section through structural Blocks I, Ib and II of the Scott Field (see Fig. 3 for the location of the line of section). Diagram shows main structural elements, reservoir thickness changes and location of the oil water contacts. Table 1. Most likely oil-water contacts for the main structural blocks within the Scott Field
Piper Scott
Block I
Block Ib
Block II
Block IIa
Block III
Block iIIa
Block IV
South Scott
11 895 12 956
11 895 11 895
13 282 13 792
13 698 13 698
12 364 12 724
12105 wet
12 752 12 752
12189 12 956
All depths quoted in feet, TVDss
Reservoir interval Depositional setting
The reservoir interval was deposited by two major, westwards prograding, shoreface systems (the Scott and Piper Sandstone Members), separated by a major regional marine transgressive event (the Mid Shale Member). A younger, very distal, prograding unit (the KPT Unit) overlies the Piper Sandstone, but never reached full development across the field. Figure 9 illustrates (using three typical wells) how the reservoir units and sedimentary facies vary across the field. A complete prograding package typically consists of an interval up to several hundred feet in thickness, which coarsens (shallows) upwards from offshore mudstones to medium or coarse grained shoreface and back-barrier sandstones as the system progrades outwards into the marine basin. Published regional data (Maher 1980; O'Driscoll et al. 1990) indicate a north-easterly sediment source. Locally, however, the presence of positive areas such as the Telford High may have affected sediment transport and deposition. Thickness and facies trends from the marine parts of both the Scott and Piper systems in Blocks 15/21 and 15/22 show a general pattern of progradation from the southeast, although the sediments may have been transported laterally by longshore currents from fluvial sources lying beyond Scott Field to the northeast. In the descriptions that follow, beach face terminology (offshore, offshore-transition, shoreface) is used in the sense of Elliott (1986).
Saltire Member. The initial major marine transgression represented by the Saltire Member blanketed the major part of this area
with marine mudstones, containing scattered ammonites, belemnites and bivalve shell fragments, that typically in-fill relict preUpper Jurassic topography. However, in the Telford area to the south, and possibly also to the east of Scott, areas of higher relief resulted in non-deposition
Scott Sandstone Member. A major coarsening-upwards sandstone unit was deposited by a wave-dominated, barred shoreface system which prograded across the area of the Scott Field from the southeast. The contact with the underlying marine Saltire mudstones is typically gradational, and the progradational nature is shown by progressive shallowing from pervasively bioturbated, argillaceous shelf sandstones with a marine ichnofacies, to clean, bedded shoreface sandstones capped by an emergent (rootleted) coal. The barred nature of the shoreface is demonstrated by the presence of washover sandstones interfingering with back-barrier lagoonal mudstones above the coal (Fig. 10a). Although the local orientation of the facies belts (Fig. 10a and 10b) suggests land lay broadly to the southeast, with open sea to the northwest, there is no clear evidence of fluvial distributary channels feeding sediment directly into the Scott Field area. Instead, sediment transport is inferred to have been controlled by longshore currents, possibly sourcing sediment from a fluvial distributary lying along the coast further to the northeast. The Scott Sandstone Member can be separated into two units, Upper and Lower, related to changes in the style of deposition. The Lower Scott Sandstone commences in argillaceous, pervasively bioturbated, offshore-transition zone (OTZ) sands, and coarsens upwards to clean, bedded, shoreface sands, reflecting the progradational phase. This was followed by a phase of vertical
474
S. GUSCOTT ET AL.
Fig. 9. Schematic correlation-section through three Scott Field wells (see inset for location) showing major reservoir intervals and facies variations across the field. aggradation, with a thin marker coal overlain by thick back-barrier washover sands and lagoonal mudstones. Figure 10a shows facies distribution at this time, with the barrier lying just west of the field, and a well-developed washover sand apron behind it to the east, shaling out into lagoonal mudstones further to the east. The marine sands of the progradational phase are sheet-like in distribution, but the back-barrier sediments of the aggradational phase are prone to rapid lateral and vertical changes in facies. There is a clear pattern of westwards thickening in the Lower Scott Sandstone, and also in the underlying Skene and Saltire Members. The major structural control on this thickening is the N E - S W trending fault system that separates structural Block II from the rest of Scott Field (Fig. 3). In Block 15/22, the Lower Scott is typically less than 120 ft thick and thins rapidly eastwards. There is a marked thinning of the Lower Scott interval across the crest of structural Block Ib before the whole package thickens westwards into Block 15/21 where it exceeds 250 ft in the northwest of structural Block II. The observed westwards thickening trend is likely to be due to a combination of differential compaction of sand-rich and mud-rich areas of the field, and differential subsidence. The Upper Scott Sandstone reflects a continuation of the backbarrier environment across the field, but was deposited during a retrogradational phase, prior to drowning by the Mid Shale. Eastwards reworking of barrier sands resulted in deposition of two overlapping flood-tidal delta lobes which shale out into lagoonal mudstones over the eastern part of the field (see Fig. 10b). The flood-tidal delta interpretation is consistent with a number of observed characteristics. The lobes are relatively large sand bodies within a back-barrier lagoonal environment. They show a coarsening-upwards (prograding lobe) profile with thin (?tidal) clay drapes
in the lower part. They also pinch out very rapidly (from c. 50 ft of sandstone to lagoonal mudstone over less than 500m lateral distance). Because the lobes formed by landward reworking of the barrier sands, they were building eastwards from the barrier, back into the lagoon. Progradation, in that sense, would have been in the opposite direction to that of the shoreface in the underlying Lower Scott Sandstone.
Mid Shale Member. Upper Scott deposition was terminated by the semi-regional marine flooding episode represented by the Mid Shale. The Mid Shale consists of predominantly laminated silty mudstones. It contains a marked glauconitic horizon near the base over the central and eastern parts of the field, representing slow condensed sedimentation on a marine shelf. The Mid Shale is relatively uniformly developed over much of Scott Field, away from the crestal area where a marked thinning occurs. However, it also appears to thin below the depositional axis of the overlying Lower Piper mass flow sandstones (see below).
Piper Sandstone Member. The Piper Sandstone Member was deposited by the second major prograding shoreface system, but did not advance as far across the field to the west as the Scott system. It consists of two units, Upper and Lower. The Lower Piper Sandstone is interpreted as stacked mass flow sands, since individual sharp-based sandstone beds can be seen interbedded with much lower energy outer shelf mudstones. The beds are typically structureless or weakly laminated, and bed tops may be slightly burrowed. Some beds contain fine tip-up mudstone intraclasts towards the bed
SCOTT FIELD
475
Fig. 10. (a) Facies map showing the dominant facies that occur between the marker coal in the Lower Scott Sand and the base of the Upper Scott Sandstone. (b) Facies map showing the maximum eastwards progradation of the upper and lower flood tidal deltas in the Upper Scott Sandstone. (c) Facies map showing the principal occurrence of mass flow sands in the Lower Piper Sandstone. (d) Facies map showing the limit ofNW progradation at the end of Upper Piper sand deposition. Note the Upper Piper shoreface did not prograde across the entire Scott Field.
base, and examples of minor sand injection structures into adjacent mudstones have been noted. The mass flows may have originated from sediment collapse of an oversteepened basin margin (lying beyond Scott Field to the northeast), following a prolonged period when low sedimentation rates during deposition of the Mid Shale were unable to maintain pace with subsidence rates in the basin. The sands are clean and homogeneous, suggesting a winnowed shelf sand source, possibly to the northeast (Fig. 10c). As in the Lower Scott Sandstone, there is a pattern of subsidence-controlled thicken-
ing towards the west, demonstrating the increased accommodation space available in Block 15/21. Additionally, thickness considerations suggest a depositional axis (possibly a channel) running southwestwards across structural Blocks Ib and IV and then sweeping westwards into Block 15/21 (Fig. 10c). At their thickest in the west of the field, the mass flow sandstones exceed 150 ft, whilst in the east they reach 100 ft in the main channel axis but pinch out rapidly to the south and east (Fig. 9). The depositional pattern in Block 15/22 suggests that the crestal area of structural Block Ib was
476
S. GUSCOTT E T AL.
Fig. 10. (continued)
a positive feature in Lower Piper times, and that the E - W 'Witch Ground' trend faults were not yet active. On a local scale, lateral correlation of sand packages within the Lower Piper is problematic, since individual beds can pinch out very abruptly, and the geometry is therefore likely to consist of stacked and overlapping lobes of various dimensions. The Upper Piper Sandstone was deposited by a westwardsprograding shoreface and back-barrier system similar to the Scott Sandstone Member, but is not as thickly developed, and as shown
in the map (Fig. 10d), it did not prograde as far to the west. The trend of facies belts still clearly shows a broad N E - S W orientation. As with the Scott Sandstone Member, no direct fluvial sediment source is seen in the Scott Field area, and the sediment supply is inferred to be controlled by longshore currents (possibly from the northeast where the underlying Lower Piper mass flows also originated). The shallowing-upwards facies trends are similar to those in the Scott Sandstone, but the cleaner shoreface sands locally develop high G a m m a Ray log spikes that are probably related to heavy
SCOTT FIELD mineral concentrations. The Upper Piper Sandstone shales out westwards, so the net reservoir is confined to the eastern and central parts of the field. Unlike the underlying units, the Upper Piper Sandstone thins towards the west, consistent with greater compaction of the shalier lithology developed in that area (Fig. 9). The KPT Unit that overlies the Upper Piper Sandstone is a minor and very distal prograding unit of silty mudstones, glauconitic at the base. Core and log evidence show that although non-net over the Scott Field, it is thicker and shows a better coarsening-up profile towards the southeast corner of the field. Taken along with the Scott and Piper Sandstone Members, it forms the third of a series of 'prograding lobes' back-stepping towards the southeast, against a background of rising relative sea level.
Reservoir character
Sandstone composition Analysis of the reservoir sandstones of the Scott Field indicates that the detrital assemblage becomes increasingly mineralogically mature with progressive depth of burial. Whilst the sandstones of the Piper and Scott Sandstone Members are both presently quartz arenites,
Fig. 11. Horizontal permeability plotted against helimn porosity for shoreface and offshore-transition zone sandstones from Scott Field Block II. The plot shows how facies exerts a strong control on the permeability/porosity characteristics of individual sands.
477
reconstructions of their original detrital mineralogy indicate that the Piper sandstones were sub-arkosic to arkosic, and the Scott sandstones were quartz arenitic to subarkosic at the time of sediment deposition. The differences between the original detrital mineralogical compositions of the two main reservoir sandstones indicate that the sands were derived from different source lithologies. Data presented by Hallsworth et al. (1996) suggest however that the Scott and Piper sandstones were both derived from Palaeozoic rocks from the Fladen Ground Spur to the northeast (Fig. 2), although the Scott sandstones could alternatively have been derived from the East Shetland Platform to the north (Hallsworth et al. 1996). The compositional evolution of the Piper sandstones from arkoses/subarkoses to quartz arenites is interpreted to be the result of the dissolution of detrital feldspar from the sandstones during early to intermediate burial. Reservoir quality is not significantly enhanced by the feldspar dissolution, since secondary pores are generally occluded by blocky kaolinite formed as a reaction product of the dissolution.
Porosity and permeability The primary control on reservoir properties in the Scott Field is initial sediment grain size. This is illustrated by the positive correlation of reservoir permeability with depositional facies (Fig. 11). The air permeability of the Scott reservoir sandstones typically reaches several Darcies in coarser sands near the crest of the structure, declining below the 1 mD net pay cut-off in distal, silty, offshore-transition zone mudstones. Stratigraphically the most consistently high permeability sands are those of the Lower Scott upper shoreface and proximal washover deposits reflecting their reworking in the high-energy surf zone (Fig. 10a). However, the highest individual values are associated with even coarser and better sorted sands, developed within both the Upper Scott flood tidal delta
Fig. 12. Depth of burial versus helium porosity for mass flow sandstones from the Scott Field structural Block II. The plot shows that total porosity decreases with increasing depth of burial. This trend reflects both increasing quartz cementation with depth of burial and the effects of chemical compaction in downflank areas. Prior to plotting data points affected by early carbonate diagenesis were removed.
478
S. GUSCOTT ET AL.
complex (Fig. 10b) and the Lower Piper mass flow sands (Fig. 10c). For example, in well 15/22-D1 at the crest of the field, air permeabilities in excess of 6500 mD are recorded in the Upper Scott, and air permeabilities in the Lower Piper regularly exceed 4000 roD. The macropore networks of both main reservoir sandstones are dominated by primary intergranular porosity, with subordinate volumes of secondary grain dissolution porosity observed in the Piper Formation sandstones. At the crest of the field, in the cleanest shoreface facies, porosities up to 20% are commonly preserved, while in downflank areas porosities in similar sandstones decrease significantly. Figure 12 shows the porosity depth profile for the Lower Piper mass flow sands of structural Block II. These sandstones show similar grain size characteristics across the block and, as Figure 12 demonstrates, there is a clear trend of decreasing helium porosity with increasing depth of burial. The porosity decrease can be attributed to the effects of both diagenesis and increased compaction with increasing burial depth. Although quartz cementation and compaction degrade porosity, permeabilities are more seriously affected. In general the effect of permeability degrading factors becomes more severe as grain size declines and detrital clay content increases. Decreasing grain size and increasing clay content both act to accentuate depositional differences and concentrate net reservoir in upper shoreface and proximal back-barrier deposits of the Upper and Lower Scott Sandstones, and within the mass flow deposits of the Lower Piper Sandstone. This preferential degradation of reservoir quality in finegrained sediments appears to reflect two factors. Firstly, because these sediments tend to be richer in clay, the effects of both mechanical and chemical compaction are enhanced. Secondly, as sediment grain size and pore throat diameters decline the damaging effects of cement precipitation are accentuated. A cement layer that has little effect proportionately on a wide pore throat may completely occlude a narrow one.
Diagenesis
Authigenic quartz cements constitute the most important diagenetic alteration observed in the Scott Field, and are recognized in almost all the reservoir sandstones. The authigenic quartz occludes both primary and secondary intergranular pore space and reduces pore throat diameters. The quartz overgrowths post-date both
mechanical compaction and feldspar dissolution. Authigenic quartz increases with increasing depth of burial over the depth range 11 000ft-13 500ft TVDss in the Scott Field, commonly reaching abundances of 15% bulk rock volume, and results in significant porosity degradation (Fig. 12). Evidence from similar reservoir sandstones in the Ivanhoe, Rob Roy and Telford Fields indicates that quartz cementation initiates at around 8000 ft TVDss when reservoir temperatures exceed approximately 176~ (80~ Other subordinate diagenetic minerals recognized in the Scott Field core include calcite, dolomite, barite, pyrite, kaolinite and illite. Of these, the carbonates can be locally important. Early calcite nodules that formed close to the sediment-water interface during early burial, locally occlude all porosity and permeability but are volumetrically insignificant. A late calcite cement is commonly observed close to faults and can locally have a serious detrimental effect on local porosity and permeability.
Hydrocarbon composition and source The oils of the Scott Field are undersaturated low sulphur crudes with bubble points in the range 1930-3890psia and stabilized atmospheric flash gravities in the range 34-39 API units. All four major compartments comprising the Scott Field (Fig. 3) are overpressured relative to hydrostatic, and are pressure isolated from each other (Fig. 13). Each compartment contains hydrocarbons of slightly different character. Overpressures of 3000 psi relative to a hydrostatic pressure of c. 5000psia are observed in structural Block ! of the field. In the adjacent downthrown structural Blocks II and IV, oil leg pressures are respectively 150 and 200 psi higher, depth for depth, than found in structural Block I. Structural Block III, northernmost and closest to the axis of the Witch Ground Graben, is the most overpressured of all, by c. 3500psi relative to a hydrostatic pressure of 6000 psia (Fig. 13). Oil densities show more or less the reverse pattern, being highest in Block ! and progressively lower in structural Blocks IV, II and !II respectively. These patterns suggest that the most active and mature sourcing of the Scott Field has been from the north where mature Kimmeridge Clay Formation source rocks are present in the Witch Ground Graben. Filling of the structure from this direction is also consistent with the development of a major perched oil-water contact in the southern part of the field (Figs 4 & 8). The
Fig. 13, Virgin pressures encountered in each of the main Scott Field pressure compartments plotted against depth of burial. These data demonstrate that structural Block III, the closest fault block to the inferred Witch Ground Graben source area, is the most overpressured relative to hydrostatic pressure. Fault blocks further from the Witch Ground Graben show relatively decreasing degrees of overpressuring.
SCOTT FIELD highest gas/oil ratios observed in the Scott Field are observed in structural Blocks II and IIa which are downthrown relative to the crest of the field structure (Figs 5, 6a & 8). This pattern along with differences in the hydrocarbon composition suggest that the Block II area of the field may have been charged separately to the Block I, Ib, III, IV area with hydrocarbons sourced from the North Halibut Graben to the west of the Scott Field (Fig. 2).
Reserves and production history
Field development Annex B approval for the development of the Scott Field was given in 1990, six years after field discovery. The field was developed from two platforms, linked by bridges, with a production capacity of 225 000 BOPD. Subsea wells are tied back to the platform via five sub-sea manifolds. The Scott platform has an additional 28 drilling slots, 20 of which have been used to date. Oil is exported via the Forties pipeline to Cruden Bay, whilst gas export is via the SAGE pipeline to St Fergus. To accelerate early production, seven sub-sea producer-injector well pairs were drilled and completed prior to the installation of the platform. As a result, first oil was exported on 2 September 1993, several months ahead of schedule. Gas export commenced six weeks later as did water injection. The delayed water injection start-up was possible due to the overpressured nature of the reservoir and the low bubble points of the crude oils in place. In early 1994, development approval for the South Scott area was granted as an addendum to the main Scott Field development plan. Pressure maintenance is achieved using water injection wells in downflank areas, with producer wells situated up-dip. The crestal areas of the field were initially avoided as drilling targets because the seismic imaging quality in crestal areas was particularly poor. Water is injected into the oil leg since reservoir quality in the water leg is highly degraded and there is negligible aquifer support. Wells are commonly dedicated as either Piper or Scott producers and typically have monobore completions for improved access by wireline-based interventions. The perforating strategy for the startup wells involved the perforating of all net sand in the target interval, either Piper or Scott, with gaps in the perforations left to facilitate future well control. Currently, the Scott Field produces from 23 wells (ten on the Piper Sandstone Member, 13 on the Scott Sandstone Member), with support from 18 injector wells (seven injecting into the Piper Sandstone Member and 11 into the Scott Sandstone Member). Two wells inject water into both main reservoir sandstones. Including
Fig. 14. Oil production plotted against time since first oil. Also shown is the percentage water cut since water breakthrough. Major decreases in oil production correspond to the watering out of key reservoir intervals during field life. Typically oil production from wells declines rapidly once they have cut water.
479
exploration and appraisal wells, the Scott structure has been penetrated in excess of 60 times, and approximately 17 000 ft of core has been cut and recovered from the reservoir interval.
Production history Figure 14 shows the production profile for the Scott Field in stock tank barrels since first oil in 1993 until year-end 1999. Within three months of start-up the field was operating near capacity at c. 150 000 STB d -1 and between August 1994 and August 1995 the Scott Field production averaged 185 000 STB d -1. These high production rates were, however, accompanied by early and unexpected water breakthrough in several wells. The produced water was typically >80% injection water, with only subordinate volumes of formation water. Production was also adversely affected by two key factors. Firstly, the early platform wells sited towards the crest of the field were disappointing, several wells failed to find significant reservoir intervals, and resulted in the commissioning of a new 3D seismic survey. Secondly, a continued lack of voidage replacement coupled with poor injector performance in some areas of the field, meant that reservoir pressures continued to fall, thereby limiting the potential off-take. Initial oil rates from producing wells were however excellent, with typical rates of 30 000 STB d -1 and production indices typically in excess of 30 BOPD/psi. Indeed, Scott Field production for October 1995 averaged 200 000 STB d -1 with peaks in excess of 210 000 STBd -1 being obtained. Oil production in 1996 averaged only c. 150 000 STB d -1 at 26% water-cut, some 25 000-30 000 STB d -~ short of expectation. These figures at least partially reflected on-going problems with the water injection system, which was subsequently upgraded to a capacity of 440000 BWPD at 4500psi. By end August 1997 Scott Field had produced c. 220 MMSTB ofoil and c. 55 MMBBL of water, and injected 318.5 MMBBL of water. Daily rates by end 1997 approached 100 000 STBd -1 (Fig. 14). Significantly, all but one producer had cut water. As a result, an extensive well intervention campaign to isolate high water cut reservoir zones was undertaken. High water cuts were proving problematic for several reasons. Firstly, water cycling in some areas was proving inefficient and affecting rates for adjacent wells. Secondly, reservoir layers with high water cuts were shown to be inhibiting production from dry oil zones. Thirdly, water breakthrough in the Scott Field often has a severe effect on production rate. For example, well 15/22-J2 (Fig. 3) was producing 9600 STBd -1 in July 1997 but slumped to 960 STBd -1 after water breakthrough in January 1998 as a result of scale build up. Early water breakthrough at the crest of the field was also causing
480
S. GUSCOTT E T AL.
Fig, 15. Scott Field STOIIP, reserves, and recovery factor plotted against time. The first column shows data from the Scott Field Annex B in 1990. Subsequent columns show data from annual field reports since first oil in September 1993. Since the Annex B there has been a 20% decrease in field STOIIP, and a commensurate 14.5% decrease in field reserves. Over the same period, the projected recovery factor from the field has increased. concern as it was becoming increasingly apparent that water overrun in some high permeability reservoir zones was bypassing significant volumes of down-dip oil in less permeable zones. During 1998 production dropped below 100000 S T B d -1 as productive zones in key producing wells finally cut water (Fig. 14). More positively, development drilling, which had been suspended in early 1997, was resumed in mid-1998 as results of the 1996 3D seismic survey became available. The new data were a significant i m p r o v e m e n t over the 1993 dataset, although parts of the field crest were still poorly imaged. The imaging problem results from a weak acoustic impedance contrast between the oil-bearing sandstones and the overlying K i m m e r i d g e Clay F o r m a t i o n mudstones at the crest, coupled with the presence of strong seabed and interbed seismic multiples. One notable success of the new drilling campaign was well 15/22-J16 (Fig. 3). Drilled on the western flank of structural
Block I the well encountered a full reservoir section, with the Scott Sandstone at near virgin pressures. W h e n well 15/22-J16 came onstream initial production rates were close to 25 000 STB d -1 of dry oil. These rates ultimately declined due to lack of pressure support, although the well produced c. 3 M M S T B solely under depletion drive. In 1999, well 15/22-J19Z (Fig. 3) was drilled d o w n flank of well 15/22-J16 to provide pressure support to the Scott Sandstone Member. The well is currently injecting c. 35 000 B W P D and is in pressure c o m m u n i c a t i o n with well 15/22-J16. During 1999 the daily production averaged just over 83 000 STB d -1 at a water cut of c. 60%. Oil production also passed a benchmark of 300 M M S T B in late N o v e m b e r 1999. D e v e l o p m e n t drilling, which was suspended in mid-1999, will now be focused on economically locating and exploiting bypassed oil. Recent pre-stack depth migration of the 1996 3D seismic data is also providing grounds for
Fig. 16. Percentage change to field reserve versus the Geoscore complexity index for compartmentalized shallow marine and deltaic reservoirs in the North Sea. Data are taken from Dromgoole & Speers (1997). Geoscore is an estimate of field complexity. The plot shows that there is an inverse correlation between percentage change in reserves versus Geoscore, since as fields get more complex, there tends to be an associated decrease in reserve estimates during early field life. Data from the Scott Field are also shown and fit this trend.
SCOTT FIELD optimism. Early results indicate that it has significantly i m p r o v e d imaging over m u c h of the field. Consequently, drilling is expected to resume in late 2000 as a new generation of detailed 3D reservoir models become available and allow m o r e precise targeting of bypassed reservoir zones.
Reserves In 1990 A n n e x B reserves (including the South Scott area) stood at 515 M M S T B with a m a p p e d S T O I I P ( S t o c k - T a n k Oil Initially In Place) calculated as 1129.2 M M S T B (Fig. 15). These figures were carried t h r o u g h to 1997 w h e n reserves were d o w n g r a d e d to reflect the disappointing drilling results since first oil. O f the 19 platform wells drilled since 1993, four failed to e n c o u n t e r reservoir and a further five wells e n c o u n t e r e d partial sections as a result of crestal erosion (Fig. 6b) a n d / o r faulting. As a result, in A u g u s t 1997, the Scott Field reserves were written d o w n to c. 480 M M S T B . S T O I I P was also revised d o w n w a r d s to 1058.6 M M S T B (Fig.15). The 1999 reserve estimates were c. 440 M M S T B from a m a p p e d S T O I I P of just over 946 M M S T B . These figures represent a decrease of 20% f r o m the A n n e x B S T O I I P and a reserves shortfall of 14.5% c o m p a r e d with the A n n e x B prognosis. H o w e v e r , the anticipated recovery factor has risen f r o m an initial 44% to c. 46%. The decrease in reserves, although disappointing, is consistent with data from other c o m p a r t m e n t a l i z e d shallow marine and deltaic reservoirs in the N o r t h Sea ( D r o m g o o l e & Speers 1997; Fig. 16). These authors published data for a variety of N o r t h Sea fields that d e m o n s t r a t e an inverse correlation between estimated reservoir complexity or 'Geoscore' and the percentage change to field reserves between field sanction and four years into field p r o d u c t i o n life. W h e n plotted with the data of D r o m g o o l e & Speers (1997) the Scott Field appears to be fairly typical of m o d e r a t e l y to highly complex shoreface reservoirs in the N o r t h Sea (Fig. 16). F u r t h e r m o r e , in late field life, reserve estimates often increase once m o r e as p e r f o r m a n c e exceeds expectation ( D r o m g o o l e & Speers 1997). The authors wish to thank Amerada Hess Ltd, Veba Oil & Gas UK Ltd, PanCanadian Petroleum UK Ltd, Enterprise Oil plc, Kerr McGee Oil (UK) plc, Exxon Mobil Corp, and Premier Oil plc for permission to publish this paper. Over the years, many individuals in these companies have contributed to understanding of the Scott Field and without their work this paper would not have been possible, however the views expressed herein are solely those of the authors. The authors would also like to thank Jon Gluyas, Stuart Harker and Richard Bailey for constructive reviews of this manuscript, and Shona Smith of ODL Graphics for drafting the figures.
Scott Field data summary Trap Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column Pay zone Formation Age
Structural 10 400 n/a 11 895-13 792 n/a 500-2000
ft ft ft ft ft ft
Sgiath & Piper Formations Upper Jurassic (Latest Oxfordian to Kimmeridgian) Gross thickness c. 360 ft Net/gross 0.8 ft % Porosity average (range) 10-22 Permeability average (range) <0.1-c. 6500 mD % Petroleum saturation 85-97 average (range) Productivity index 1-50 BOPD/psi
481
Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
36 Low Sulphur Crude n/a 0.297-0.578 @ 8500psi 1930-3890 n/a 578-1398 n/a 1.328-1.761 @ 8500 psi n/a
Formation water Salinity Resistivity
110 000 0.027 @ 200~
NaC1 eq ppm ohm m
8650 3 114000 7879-9320 0.2884-0.3167 190-248 946 MMSTB Associated gas only 46.5 Water flood 441 MMSTB Associated gas only n/a
acres acre ft psi psi/ft ~ MMBBL BCF %
Field characterbtics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate Production Strat-up date Production rate plateau oil Production rate plateau gas Number/type of well
September 1993 >200 000 n/a 13 Scott oil producers 10 Piper oil producers 11 Scott water injectors 7 Piper water injectors 2 Scott/Piper water injectors
~ API
cp psig psig SCF/BBL BBL/MMSCF SCF/RCF
MMBBL BCF MMBBL
BOPD MCF/D
References BOLDY, S. R. & BREALEY,S. 1990. Timing, nature and sedimentary results of Jurassic tectonism in the Outer Moray Firth. In: HARDMAN,R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publication, 55, 254-279. COWARD, R. N., CLARK, N. M. • PINNOCK, S. J. 1991. Tartan, Block 15/16, United Kingdom. In: ABBOTTS,I. (ed.) UK Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 377-386. DROMGOOLE, P. & SPEERS, R. 1997. Geoscore: a method for quantifying uncertainty in field reserve estimates. Petroleum Geoscience, 3, 1-12. DUXBURY, S., KADOLSKY,D. & JOHANSEN, S. 1999. Sequence stratigraphic subdivision of the Humber Group in the Outer Moray Firth area (UKCS, North Sea). In: JONES, R. W. & SIMMONS, M. D. (eds) Biostratigraphy in Production and Development Geology. Geological Society, London, Special Publication, 152, 23-54. ELLIOTT, T. 1986. Siliciclastic Shorelines. In: READING, H. G. (ed.) Sedimentary Environments and Facies. Blackwell Scientific Publications, Oxford, 155-188. HALLSWORTH, C. R., MORTON, A. C. & DORE, G. 1996. Contrasting mineralogy of Upper Jurassic sandstones in the Outer Moray Firth, North Sea: implications for the evolution of sediment dispersal patterns. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERTICH,D. S. (eds) Geology of the Humber Group." Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 131-144. HARKER, S. D. & RIEUF, M. 1996. Genetic stratigraphy and sandstone distribution of the Moray Firth Humber Group (Upper Jurassic). In: HURST,
482
S. GUSCOTT E T AL.
A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERTICH, D. S. (eds) Geology of the Humber Group." Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publication, 114, 109-130. HARKER, S. D., MANTEL, K. A., MORTON, D. J. ~ RILEY, L. A. 1993. The stratigraphy of Oxfordian-Kimmeridgian (late Jurassic) reservoir sandstones in the Witch Ground Graben, United Kingdom North Sea. American Association of Petroleum Geologists Bulletin, 77, 1693-1709. HIBBERT, M. J. & MACKERTICH,D. S. 1993. The structural evolution of the eastern end of the Halibut Horst, Block 15/21, Outer Moray Firth, UK North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1179-1188. JONES, G., RORISON,P., FROST, R., KNIPE, R. & COLLERAN,J. 1999. Tectonostratigraphic development of the southern part of UKCS Quadrant 15 (eastern Witch Ground Graben): implications for the Mesozoic-Tertiary evolution of the Central North Sea Basin. In: FLEET, A. J & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 133-152.
KADOLSKY,D., JOHANSEN,S. J. 8z;DUXBURY, S. 1999. Sequence stratigraphy and sedimentary history of the Humber Group (Late JurassicRyazanian) in the Outer Moray Firth (UKCS, North Sea). In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology oJ'Northwest Europe: Proceedings' of the 5th Conference. Geological Society, London, 839-860. MAHER, C. E. 1980. Piper Oil Field. In: HALBOUTY,M. T. (ed.) Giant oil and gas fields' of the decade 1968-1978. The American Association of Petroleum Geologists, Memoirs, 30, 131-172. O'DRISCOLL, D., HINDLE,A. D. 8~;LONG, D. C. 1990. The structural controls on Upper Jurassic and Lower Cretaceous reservoir sandstones in the Witch Ground Graben, UK North Sea. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's" Oil and Gas Reserves. Geological Society, London, Special Publications, 55,299-323. RICHARDS, P. C., LOTT, G. K., JOHNSON, H., KNOX, R. W. O'B. & RIDING, J. B. 1993. Jurassic of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphical nomenclature of the UK North Sea. British Geological Survey, Nottingham.
The Auk Field, Block 30/16, UK North Sea NIGEL
H. T R E W I N 1, S T E V E N
G. F R Y B E R G E R 2 & H E L G E
KREUTZ
2
1Department of Geology and Petroleum Geology, University of Aberdeen, Aberdeen AB24 3UE, UK (e-mail." n. trewin @ abdn.ac, uk) 2 Shell UK Exploration and Production, 1 Altens Farm Road, Nigg, Aberdeen AB12 3FY, UK Abstract: The Auk Field is located in Block 30/16 at the western margin of the Central Graben. Block 30/16 was awarded in June 1970 to Shell/Esso, and the discovery well 30/16-1 spudded in September 1970. The well found oil in a complex horst block sealed by Upper Cretaceous chalk and Tertiary claystones. The field contained an original oil column of up to 400 ft within Rotliegend sandstones, Zechstein dolomites, Lower Cretaceous breccia and Upper Cretaceous chalk. Production by natural aquifer drive commenced from a steel platform in 1976, initially from the Zechstein carbonates and now predominantly from the Rotliegend sandstone. Artificial lift was installed in 1988 helping to maintain production at economic levels past the year 2000. A complex reservoir architecture with cross flow between the Rotliegend and Zechstein reservoirs, a strong aquifer causing early water breakthrough via faults, and a limited seismic definition led to significant production variations from the initial forecasts. Equally important for the field, horizontal well technology opened up additional reserves and accelerated production from the complex Rotliegend reservoir; the most recent volumetric estimate for the total field predicts an ultimate recovery of 151 MMBBL for the existing wells from a STOIIP of 795 MMBBL. Full field reservoir simulation and 3D seismic data acquisition took place since mid 1980s but only recently resulted in a satisfactory understanding of the reservoir behaviour. The field is situated about 270 km ESE from Aberdeen in 240-270 ft of water. It covers a tilted horst block with an area of 65 km 2, located at the western margin of the Central Graben. The Auk horst is bounded on the west by a series of faults with throws of up to 1000 ft, the eastern boundary fault has a throw of 5000 ft in the north reducing in throw southwards. The best reservoir lithology in the Zechstein is a vuggy fractured dolomite, and in the Rotliegend dune slipface sandstones provide the majority of the production. Both reservoirs and the overlying Lower Cretaceous breccia shared a common FWL at 7750 ft TVDss. The 38 ~ API oil with a G O R of 190 SCF/STB was sourced from organic-rich Kimmeridge Clay.
Fig. 1. Exploration and appraisal well locations in Block 30/16.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 485-496.
485
486
N. H. TREWIN
History Pre-discovery and discovery Licence P.116, initially comprising the Auk/Fulmar Block 30/16 (Fig. 1), the Kingfisher Block 16/8, and Block 22/2, was granted to Shell/Esso during the 3rd Round in 1970. Block 30/16 had been applied for to test the porous, but hitherto discarded as waterbearing, Rotliegend sandstones encountered in three wells previously drilled in the area. Due to the adjacent open acreage and upcoming licensing rounds, an exploration well proposal was approved within a month after licence acquisition on the basis of a sparse grid of 2D seismic data. Two months later, in September 1970, the semisubmersible rig 'Staflo' spudded the Auk discovery well, 30/16-1, as Shell Expro's sixth well in the Central North Sea. The well encountered only waterbearing sands in the Rotliegend, but tested oil from Zechstein carbonates at economic rates. As Shell Expro's first commercial oil discovery it was named 'Auk', starting the company's tradition that oil fields are named after seabirds.
Pre-development appraisal The preservation of porous, fractured carbonates on the eroded horst block came as a surprise to Shell/Esso (Brennand & van Veen 1975). The thin Zechstein interval was not resolved on contemporary 2D seismic data, and prior to well 30/16-1 it was believed to be fully eroded from the structure. Subsequent appraisal wells 30/16-2 and 30/16-3, respectively up-dip to the east and southeast of the discovery well, again encountered Zechstein but also tested oil from Rotliegend. A drilling campaign of three wells was proposed to delineate the extent of the Zechstein aquifer and the oil-water contact (OWC). However, the next well (30/16-4) found the Zechstein eroded and only tight Rotliegend preserved below the chalk. Based on this well the decision was made in late 1972 to develop primarily the Zechstein and to provide water injection facilities. The Zechstein was correctly interpreted to lack its own aquifer due to erosion in the east and southeast (Fig. 2). The remaining two appraisal wells were cancelled, and 30/16-5 was unsuccessfully drilled as an exploration well targeting the Devonian, at the time found to be hydrocarbon bearing in the Argyll Field. The large uncertainty in reserve estimates of 30-100 MMBBL at the time reflected the limited seismic resolution and the complex structural history indicated by the appraisal wells (Buchanan & Hoogteyling 1979). Below the Base Cretaceous unconformity the discovery well found Zechstein, the first appraisal well Triassic shales, the second appraisal well encountered Lower Cretaceous conglomerates, and the last pre-development appraisal well Rotliegend sandstones.
Development and early production A 10-slot steel drilling/production platform and a single buoy mooring offloading system were installed in 1974 and the initial development wells drilled for a production start in late 1975. Their static results came in close to prognosis, but unexpectedly by mid1976 the watercut in the first Zechstein producers started to increase, and it became evident that the reservoir was connected to a strong aquifer provided by Rotliegend sandstones. The water injection facilities were removed and used later on the neighbouring Fulmar platform. Due to the rapid increase in watercut, the field only achieved a short peak production of 70 000 BOPD in May 1977 and reserves estimates decreased from an expectation of 60 MMBBL at the start of production down to 55 MMBBL in 1978 (Buchanan 1979). The estimated end of field life (1979 at the time of development consent) moved backward to end 1980 in estimates made during the late 1970s and was further postponed year-by-year due to updates in
ET AL.
well performance. At this point in our discussion it may be useful to interrupt the historical description to look at the present knowledge about the reservoirs. The later development history is described at end of this chapter.
Structure The Auk structure is the result of multiple periods of uplift and subsidence along two NW-SE striking faults. The eastern boundary fault (Figs 3 and 4) bounds the Auk horst against the Central Graben to the east, and the west boundary fault (WBF) (Figs 2 and 3) in most areas forms the western limit of the oil accumulation. Situated on the western edge of the Central Graben the structure at Rotliegend level is broken up into several blocks with different characteristics (Fig. 2). The west flank of the field (Auk West) has preserved the most complete stratigraphic sequence due to westward tilting of the Auk High in the Early Cretaceous. Later, at the start of the Tertiary, this part of the field was uplifted and densely faulted by rejuvenation of the western boundary fault (WBF). Due to preservation of the overlying Triassic sequence the Zechstein and Rotliegend are located below the OWC. The present crest of Auk (Auk Main West) is the result of the same Tertiary uplift and is as densely faulted as Auk West, but does not contain any Triassic sediments. The main reservoir in Auk Main West is the Zechstein dolomite, with only a thin oil column in the Rotliegend sandstone. The east flank of the field has a low fault density. Two W-E trending faults split the east flank into three part blocks; Auk Main block, Auk Main North and Auk North blocks. Early Cretaceous uplift and erosion removed all of the strata between Zechstein and Upper Cretaceous chalk. In the eastern half of the flank towards the east boundary fault where erosion started first even the Zechstein is fully eroded. In some places Lower Cretaceous conglomerates have been deposited in isolated lenses. The most recent fault interpretation described above was only resolved on the 1991 vintage 3D seismic survey (Fig. 4). Earlier 3D seismic (1985) and 2D lines (1976, 1979) had led to a significantly different fault interpretation. The correct interpretation of the main faults in Auk is the key to understanding the reservoir performance and drainage. Interference tests and watercut development has shown that faults are open; oil and water can cross-flow between the reservoirs in areas where Rotliegend and Zechstein are juxtaposed along the main faults. The strong aquifer observed in the Zechstein producers turned out to be the Rotliegend aquifer in Auk Main West juxtaposed against the Zechstein in Auk Main along the WBF. Zechstein producers near the boundary between Auk Main and Auk North on the other hand show an abnormally high oil recovery and late watercut development due to drainage of the Rotliegend oil via fault juxtaposition. Overall, Zechstein wells have produced 80 MMBBL of oil, of which 55 MMBBL are now believed to be Rotliegend oil drained via fault cross-flow, based on recently completed dynamic modeling studies. On the other hand, after increasing the offtake from the Rotliegend and shutting down watered out Zechstein producers the water flowed back from Zechstein to Rotliegend causing wells to water out that are completed far above the OWC.
Stratigraphy The general stratigraphic sequence of the Auk Field is shown in Figure 5. Unconformities are present in the area at base Devonian, base Permian, base Trias, sub-Lower Cretaceous, sub-Upper Cretaceous, and sub-Palaeocene. These produce a considerable variation in stratigraphy in different parts of the field and in adjacent areas. Lower Palaeozoic basement was penetrated in well 30/16-5 and consists of steeply dipping low grade metamorphic siltstones and claystones with extensive quartz veining.
Fig. 2. Top Rotliegend structure map and well locations. The Zechstein is only preserved in the west part of the field, towards the east Early Cretaceous erosion has removed all of the Zechstein and cut into the Rotliegend reservoir.
488
E T AL .
N. H. TREWIN
1.1.1 o o
o
o
~
o
oo
o
o
"C.
,_.~-
o IJ.J m
Z
o
O
r o
,,..,
) \
.,..,
~D
0
) \
g~
o
g !
O9
Z
o \
o
~
o
! r'-..
(
t13
~b o,I
,..o
o r
,b
i
I
O
O3 !
<
Z
O I-
0~ ~ u . . (
O rr O
"1
k
kO
(sO Or) 03
o
o 9
_..1
f12
",~
~
cr
o . ,,..,
r I ~ 84184 ~:' i ~ i : 84184184 ~t
60 ILl ca0 m
:
n-C0
F
o-ua
o
t-,u_
o
llllM
oO
o co
o ~
~it
o
b
(t? I.U
o o
o ~
o
o
oo
o ~
~
o e4
AUK FIELD
489
Fig. 4. Seismic cross-section in SW-NE direction through the Auk Main North block. The quality of the 1991 3D seismic survey in the latest reprocessing, shown in this figure, is now sufficient to interpret reservoir juxtapositions reliably.
Devonian
Two Devonian carbonate units each up to 100 ft in thickness and separated by 200 ft of red-brown claystone rest unconformably on the basement with a thin basal conglomerate of locally derived material (Heward 1991). The carbonates are laminated peloidal calcareous dolomites and dolomites which have been reported to yield tabulate and rugose corals indicative of shallow-marine origin. Similar coral-bearing limestones in the Argyll Field are considered to be of Middle Devonian age (Pennington 1975). However, the finely laminated limestones resting on the basement in the core from well 30/16-5 could be of marginal lacustrine origin (Bessa 1991). Succeeding the carbonates with apparent conformity are up t o 3000ft of porous sandstones and shales of inferred Devonian age that are probably of floodplain origin.
deposited below wave base in the restricted marine setting of the Zechstein basin. The succeeding Zechstein dolomites/carbonates were deposited in a shallow marine to sabkha environment across the whole area. Zechstein dolomites, where preserved, average 28 ft in thickness and are probably a time equivalent of the Z1 carbonates of northern England. The dominant lithology in cores is a l a m i n a t e d dolomicrite with sub-parallel organic-rich laminae on a millimetre scale. Solution vugs after evaporite minerals occur, some o f which are confined by organic laminae. Ghosts of peloids, indeterminate fossil material, and scattered quartz grains occur in the dolomite. Pervasive brecciation is present, probably due to collapse of the more evaporite-rich lithologies. The top of the incomplete Zechstein sequence is formed by a massive anhydrite.
Triassic Permian
The Rotliegend in the Auk area was deposited in a broad, shallow basin that sloped gently southwest before thinning against the Mid North Sea High. The maximum thickness south of the field exceeds 1000ft whilst in Auk itself the Rotliegend is up to 900 ft thick. A conglomerate with basalt pebbles locally marks the base and a possible in situ flow of porphyritic leucite-nepheline basalt was encountered by one well. Thin conglomerates and sandstones of alluvial origin are followed by pinkish to red-brown dune sandstones with large scale cross-bedding. The main aquifer above this alluvial sequence consists of high net-to-gross barchanoid dune bodies, which in the top of the sequence grade into more complex and heterogeneous sands interpreted as a dunefield with more complex bedforms. The Rotliegend sequence is capped by waterlain massive mass flow and stratified sandstones, intraformational conglomerates and thin lacustrine shales, which yield an Upper Permian flora (Pennington 1975). The sandstones show only minor reworking at the top prior to deposition of the Kupferschiefer, a 3-5 ft thick bituminous shale
Red-brown to grey-green silty claystones of Early Triassic (Scythian) age, based on palynology, are thickest in the west of the field (500 ft), but have been extensively eroded on the t o p of the block. These rocks are interpreted as the flood plain deposits of a fluviatile system and are probably a part of the Smith Bank Formation.
Cretaceous
The four Lower Cretaceous lithological units recognized in t h e field are the Upper Carbonates breccia, a Hauterivian basalt flow, an Albian-Aptian conglomerate, and a marl. The Upper Carbonates breccia consists of Zechstein dolomite and possibly Triassic clasts in a matrix which includes rounded (Rotliegend derived) sand grains, and an open marine fauna of probably Neocomian a g e . This breccia only occurs in structurally low blocks between Zechstein and other Cretaceous deposits. Deposition of this breccia w a s associated with erosion, karstification and faulting of the h0rst i n Early
490
N. H. TREWIN ET AL.
Fig. 5. Lithostratigraphic summary for the Auk Field.
Cretaceous times. A basalt flow occurs in the northeast of the field and radiometric dating suggests a Hauterivian age. The AlbianAptian conglomerate fringes the basalt flow and contains rounded basalt and Zechstein pebbles in a matrix of sand. Shell fragments of an open marine fauna (Aptian-Albian) are present and bivalve borings are preserved in larger Zechstein clasts. A Lower Cretaceous marl was penetrated by some wells on top of the breccia or older Triassic sediments. Deposited in an open marine environment it illustrates the increasing subsidence of the area, and the end of the Jurassic/Early Cretaceous period of aerial exposure. The Upper Cretaceous chalk in the Auk Field is fully autochthonous and has been dated as Coniacian to Santonian. Lower parts are oil stained, but the denser upper parts form the main top seal of the field.
Tertiary Rapid subsidence during the Tertiary and especially during the Palaeo,: me pulled the east flank downwards, rotating the structure into its current position. A 7000 ft thick sequence of mudstones,
siltstones and shales was deposited in the area. Deep marine conditions prevailed during Tertiary times.
Trap The tilted horst block containing the Auk accumulation is capped by an asymmetric anticlinal structure at chalk level. Triassic shales seal the accumulation to the west with fault closure prevailing in the northwest and dip closure in the southwest. To the east and south the virtually impermeable upper parts of the chalk provide the top seal with a simple dip closure. In the extreme north, where the chalk is eroded down to a thickness of less than 50 ft and reservoir quality in the Rotliegend deteriorates, hydrocarbons are probably spilling slowly into low permeability Tertiary sediments. In most parts of the field the basal 30 ft of chalk is porous and contains some hydrocarbons thus providing a waste zone between the main reservoir and the Tertiary overburden. This explains the shallower OWC in the north part of the field (7710 ft TVDss) compared with 7750 ft TVDss in the Auk Main block, a feature which led to the proposal of a stratigraphic trap in an earlier paper (Trewin & Bramwell 1991).
AUK FIELD
491
Barchanoid Dune
Sand Sheet
10000
10000
1000
/ ///
100
~
//
10
(3_
,./
/
1
/
100
/
/
~
10 1
9
.1.
/ 4
8
12
16
20
24
28
,01 32
36
40
/
/ 0
4
8
12
16
Porosity
Slipface
28
32
36
Barchanoid Dune Field
/
fIA
100
_(3
/
10
1
Fig. 6. Porosity/permeability relationship for the different lithofacies in the Rotliegend unit 2 main reservoir. The permeability rarely exceeds 1000mD, in barchanoid dunes.
24
10000
1000
E
20
Porosity
10000
~.
/
/
/
/
1000
.1
0
/
S/
/
.01
/ /
4
8
/
1000
>, ._ ..Q
100
~
10
//
/
1
/
/ 12
16
20
24
28
32
36
Porosity
At the OWC, the field has a length of 16km in a N W - S E direction with an average width of 5 km. The crest at Top Zechstein is around 7300ft TVDss giving Auk a maximum hydrocarbon column of 450 ft.
Reservoirs
Rotliegend Rotliegend sediments in the Auk area were deposited unconformably onto Devonian and older basement rocks. The deepest Rotliegend unit in Auk (unit 5) consists of basal fluvial conglomerates, transported by ephemeral streams into the newly formed basin from the west or southwest. The sediments are indicative of the initial rapid subsidence north of the Mid North Sea High, with simultaneous movements along Auk's west boundary fault controlling local thickness variations. The overlying sandstones of units 4 and 3 represent thick dune deposits and are interpreted as a stack of barchanoid bed forms. They form the main aquifer for the field. Within the Rotliegend unit 2 reservoir quality is more variable, ranging from very marginal (< 1 mD) to good, but values are rarely greater than 1000 mD (see Fig. 6). A complex assemblage of different dune forms succeeds the better quality barchanoid dunes. In the youngest Rotliegend unit (unit 1) fresh water flooding of the area has resulted in widespread slumping and subaqueous reworking of the dunes. Figure 7 illustrates the vertical variations in reservoir quality within Rotliegend units 2 and 3. Cores from Auk wells exhibit two types of aeolian primary strata: ripple and avalanche. These strata dominate in the Rotliegend units 2, 3 and 4. Ripple strata in Auk has fair to poor reservoir quality whilst avalanche strata due to a coarser grain size and better sorting comprises the best reservoir. The Rotliegend unit 1 consists of slumped avalanche and ripple strata along with some subaqueous strata and shale. Cross-stratification styles and primary strata types
/
40
0
/
/ 4
8
12
16
20
24
28
32
36
40
Porosity
were used to identify lithofacies associations with different rock properties (see Figs 8 and 9). Variations of properties within a single lithofacies are fairly wide due to differences in grain size and sorting. The drive mechanism in the Auk Field in most areas can be best described as a complex, indirect bottom water drive caused by high permeability barchanoid dune sands in the Rotliegend unit 3 aquifer and large variations in permeability within the Rotliegend unit 2 oil zone. In addition, water cross-flows between Zechstein and Rotliegend reservoirs along fault juxtapositions in crestal areas. In line with the heterogeneous reservoir the productivity of vertical Rotliegend producers varies widely with PI's ranging from 0.5 to 18 BBL/psi. This is the main reason why horizontal well technology had a major impact on the field. The scale of the permeability variations is such that a medium reach or long reach horizontal well can slant through many productive sand bodies (Fig. 7) and is thus more predictable in PI than a vertical well. On the other hand, such a horizontal well requires a large undrained area to be successful, but the complex water drive makes the prediction of such areas difficult. Transient sand failure right from the start of production necessitates sand control by gravel pack (vertical wells) and/or prepacked screens (horizontal wells) thus further limiting the ability to control water production.
Zechstein A more detailed description of the Zechstein reservoir can be found in Vahrenkamp (1995). At the base of this formation a 1 ft thick layer of Kupferschiefer rests conformably on Rotliegend unit 1 sandstones, indicating the transition to restricted marine, anoxic conditions during the early Zechstein period. The thin, grey dolomite above the Kupferschiefer is characterized by current ripples and capped by a subaerial exposure surface. Above this surface a 30 ft thick sequence of stromatolites and dolo-mudstones have been
492
N . H . TREWIN E T AL.
Fig. 7. Typelog for the Rotliegend unit 2 reservoir and Rotliegend unit 3 aquifer, yellow indicates net reservoir whilst orange-brown indicates waste zones. The Rotliegend unit 1 and the Zechstein is eroded in this well.
deposited in an inter- to supratidal, highly saline environment. The dolomites form the main Zechstein reservoir. Their predominantly secondary moldic pore space originated from leaching of evaporites and fossils by Jurassic-Cretaceous subaerial exposure. Stylolites bridge some vugs indicating that compaction predated leaching, which in some parts of the rock is so extensive that it has caused mechanical collapse. The rock was further fractured during later faulting and uplift. Above the dolomites an organic-rich shale of 5-10ft thickness was deposited with gypsum bands, now replaced by calcite, dolomite, and silica. A massive anhydrite, interpreted as the equivalent of the Z1 (Werra) anhydrite, completes the sequence. The only reservoir rock within this sequence is the fractured dolo-mudstone described above. Primary porosity in this rock has been completely destroyed during early dolomitization. The secondary porosity consists of vugs created by the dissolution of evaporite material and intercrystalline porosity in micro-crystalline dolomite. According to Vahrenkamp (1995) the porosity ranges from 1.8 to 26% and core permeability is between 0.02 and 620mD. The calculated average porosity (13%) and permeability (53 mD) from cores is unlikely to be representative for the total reservoir. The core recovery is low and biased towards zones that are less fractured and therefore better conserved. This selective core recovery might explain why no core encountered significant flushing in the Zechstein despite early water breakthrough. The drainage of the reservoir is confined to intensively fractured zones and does not continue far into the unfractured dolomite due to poor connectivity of the vuggy pore space.
Lower Cretaceous The Lower Cretaceous breccia consists mainly of dolomitic clasts in a sandy to marly matrix (Vahrenkamp 1995). Local variations in clast and matrix composition cause large poroperm variations, ranging from 0.5 to 25% porosity and from 0.01 to 100 mD permeability. The Lower Cretaceous is only locally developed and has been produced commingled with the Zechstein in a few wells.
Hydrocarbons The source for the 38 ~API, low G O R and low sulphur oil is the Upper Jurassic Kimmeridge Clay in the Central Graben. Maturation took place from Late Tertiary times. The migration path is not fully resolved. One possible interpretation is that oil spilled over from the Fulmar area to the north, with gas leaking into the overlying Tertiary sediments where it is partly entrapped in Oligocene sediments (Trewin & Bramwell 1991).
Reserves and later development The latest estimate of ultimate recovery for the Auk Field is 151 MMBBL. Since the first official estimate in 1976 (30-100 MMBBL) reserves have increased continuously (Fig. 10), the main contributing factors being:
AUK FIELD
493
Fig. 8. Example for lithofacies identification in cores. Note fine scaled intercalations of oil stained (brown) and oil free reservoir (red).
Development plans for the Rotliegend. The exploration and preproduction appraisal wells encountered either a water bearing Rotliegend reservoir or marginal reservoir quality in the oil bearing interval. Initial estimates of ultimate recovery did not foresee a development of this formation. Limited seismic resolution.
The structural interpretation at field development was based on limited 2D seismic data. Faults were mainly interpreted from well penetrations and were not reliable. Structural interpretations outside of the core area were equally unreliable and appraisal results turned out to be unpredictable. Even on the first 3D seismic survey (1985) the fault pattern was too poorly resolved to be useful for reservoir simulation, but the data helped to identify additional reserves in the southeast flank of the field. After acquisition of better quality 3D seismic data (1991) the overall structural resolution improved and well 30/16-13 (1992) discovered a significant field extension to the north. However, only in the most recent reprocessing is the quality of the survey high
enough to resolve the internal fault pattern of the field, and the juxtaposition of the reservoirs.
Reliable full field simulation.
As mentioned above, a full understanding of the reservoir performance in the Auk Field is only possible with a full field simulation model that realistically models reservoir juxtaposition and heterogeneity. Full field simulation was attempted as early as 1982, but none of the models built in the past achieved a satisfying history match mainly due to shortcomings in the fault interpretation. A sophisticated 3D simulation model for the Zechstein, built in 1992, resolved the fluid movements within this dual-porosity reservoir but could not identify additional infill locations since the juxtaposition with Rotliegend aquifer could not be located accurately. Field forecasts were therefore constructed from decline curves which in Auk leads to a pessimistic assessment of remaining reserves. Only with the most recent seismic reprocessing could a reservoir model be built that yields a satisfactory history match, and hence is suitable to identify smaller infill
494
N.H.
TREWIN ET AL.
c~
9
,,..a
3 ~o
09.
t~
o
,....A
9
~0
o
AUK FIELD
495
Fig. 10. Changes of resreves estimates in the Auk Field were dictated by early water-break-through (1979), plans for installation of artificial lift (1985-1988), and horizontal well and seismic imaging technology (1990s).
Fig. 11. Production contribution of the individual reservoirs and well types in the Auk Field. Note that the amount of oil produced from Zechstein wells includes cross-flow from the Rotliegend reservoir.
locations. The recently drilled well 30/16-A25 is the first well in Auk located mainly on reservoir simulation.
Artificial lift.
In 1988, when artificial lift was installed, the estimates of ultimate recovery for the first time exceeded the pre-development high estimate. The conversion of wells to electro-submersible pumps is still ongoing, constrained by the power capacity of the platform.
Horizontal drilling. Due to heterogenity of the Rotliegend reservoir the deliverability of vertical wells ranges from marginal to poor and the number of geological sidetracks drilled to improve well performance is high. Many low-relief infill locations were uneconomic before horizontal well technology emerged. In addition, since
the Auk platform was built for the Zechstein only, there are only a limited number of slots available and well deliverability is key to the fast drainage of reserves. Horizontal well technology, implemented in Auk since 1992, has increased reserves by approximately 30 MMBBL to date. The impact of this technology on the production history of the field is illustrated in Figure 11. Since the first edition of the Memoir in 1991 several geologists and geophysicists have improved our understanding of the field. This summary would not be possible without the work of Janet Almond, who constructed the present reservoir model and analysed the production history. Elaine Scott planned and drilled the majority of the recent infill wells and Charlie Ash's seismic interpretation forms the basis for the current structural model. The authors wish to thank Sid Jain for the permission to use his reservoir engineering analysis and finally, we would like to thank Shell UK Exploration and Production and ExxonMobil International Ltd for the permission to publish this paper.
496
N. H. T R E W I N E T AL.
Auk Field data summary Trap Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column
structural 7300 ft TVDss 7750 ft TVDss n/a 7750 ft TVDss Oft 450 ft
Pay zone Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Hc saturation average (range) Productivity index
Auk Formation Rotliegend (Early Permian) 1000 ft 0.85 (0.46-0.92) 19% (11-27%) 5 mD (0.2-125 mD) 55-80% 1 BOPD/psi (vertical well average)
Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Productivity index
Zechstein dolomites Late Permian 30ft 1.0 (fractures) 13% (2-26%) 53 mD (0.02-620 mD) 50-159 BOPD/psi
Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
38 ~ API volatile oil, low sulphur (0.4%) solution gas only 0.9 cP 700 psi n/a 190 SCF/BBL n/a 1.154 RB/STB n/a
Formation water Salinity Resistivity
105 000 ppm NaC1 equivalent 0.025 ohm m @ 205~
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature
93 km 2 28 MM acre feet 4067 psi @ 7600 ft TVDss 0.33 psi/ft (oil) 215~
Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate Production Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
795 MMBBL 133 BCF 19% natural water drive/artificial lift 151 MMBBL n/a n/a
January 1976 70 000 BOPD peak rate n/a 10 exploration/appraisal 23 deviated development wells/production sidetracks 8 horizontal sidetracks
References BESSA, J. L. 1991. A re-interpretation of Devonian carbonates found in well 21/16-5, Auk Field, North Sea. Petroleum Geology MSc Thesis, University of Aberdeen. BRENNAND, T. P. & VAN VEEN, F. 1975. The Auk Field. In: WOODLAND, A. W. (ed.) Petroleum Geology' and the Continental Shelf of N W Europe. Applied Science Publishers Ltd., Barking, Essex, 271-281. BUCHANAN, R. 1979. Auk Field development: A case history, illustrating the need for a flexible plan. Journal of Petroleum Technology, 31, 1305-1312. BUCHANAN, R. & HOOGTEYLING, L. 1979. Auk Field development: a case history, illustrating the need for a flexible plan. Journal of Petroleum Technology, 31, 1305-1312. FOLLOWS, E. 1997. Integration of inclined pilot hole core with horizontal image logs to appraise an aeolian reservoir, Auk Field, Central North Sea. Petroleum Geoscience, 3, 45-55. HEWARD, A. P. 1991. Inside Auk - the anatomy of an aeolian reservoir. In: MIALL, A. D. & TYLER, N. (eds) Three-dimensional facies architecture of clastic sediments. SEPM Concepts in Sedimentology and Paleontology, 3, 44-56. PENNINGTON, J. J. 1975. The geology of the Argyll Field. In: WOODLAND, A. W. (ed.) Petroleum Geology of the Continental Shelf of N W Europe. Applied Science Publishers Ltd, Barking, Essex, 285-291. TREWIN, N. H. & BRAMWELL, M. G. [991. The Auk Field, block 30/16, UK North Sea. In: AnBorrs, I. L. (eds) United Kingdom Oil and Gas Fields'." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 227-236. VAHRENKAMP,g. C. 1995. The post-Rotliegend reservoirs of Auk Field, British North Sea: subaerial exposure and reservoir creation. In: But)o, D. A. et al. (eds) Unconformity and porosity in carbonate strata. American Association of Petroleum Geologists, Memoir, 63, 191-211.
The Banff Field, Blocks 22/27a, 29/2a, UK North Sea N. EVANS, J. A. MACLEOD, N. MACMILLAN, P. RORISON, & P. S A L V A D O R Conoco Phillips U K Ltd, Rubislaw House, N. Anderson Drive, Aberdeen A B 1 5 6FZ, U K
Abstract: The Banff Field is an oil field with a small gas cap containing an estimated 300 MMBO oil-in-place. The structure straddles the boundary between blocks 22/27a and 29/2a in the West Central Graben area of UK Central North Sea. The field was discovered by well 29/2a-6 in 1991. Banff Field is a steeply dipping raft of fractured Late Cretaceous and Danian Chalk on the flank of a salt diapir. Paleocene sands draped over the raft provide additional reservoir potential. A vertical oil column of over 3000 ft is present within the reservoir sourced from the underlying Upper Jurassic Kimmeridge Formation shales. Hydrocarbon migration into the trap is believed to have started in the Eocene. The highest reservoir productivity occurs in the Late Cretaceous Tor Formation, which is expected to yield most of the field's reserves. Chalk porosity ranges from 15% to 35%, but matrix permeabilities are generally less than 5 mD. Drainage is achieved through extensive faulting and fracturing. Initial uncertainties over reservoir performance and connectivity led to a phased development. Phase 1 comprised a six month Early Production System (EPS), during which time 5 MMBO were produced and the viability of the field was confirmed. Phase 2 production is by means of a Floating Production System and Offtake (FPSO) vessel named the Ramform Banff. First oil production was achieved on 30 January 1999 and ultimate reserves are expected to be in excess of 75 MMBO. The Banff Field is located approximately 200 km E of Aberdeen in the West Central Graben area of the U K North Sea, in 300 ft of water (Fig. 1). The field reservoir is a steeply dipping raft of fractured chalk on the flank of a N W - S E elongate salt diapir. The field is located in blocks 29/2a and 22/27a and is operated by Conoco (UK) Ltd on behalf of a partnership which includes Enterprise Oil plc, Ranger Oil (UK), British Borneo and Petrobras U K Ltd. A structural map of the field is shown in Figure 2. The field was discovered in 1991 by well 29/2a-6 and subsequently appraised by a further three wells (see Fig. 2). The crestal well, 22/27a-3 found the Cretaceous and Paleocene sections to be thin or absent. The appraisal wells proved the presence of a steeply dipping chalk raft on the southwest flank of the diapir, with a vertical oil column of over 3000 ft and a gas cap of approximately 300 ft. (Fig. 3). Oil gravity ranges from 38 ~ API at the base of the raft to 40 ~ at the crest. Maastrichtian (Tor Formation) and Danian (Ekofisk Formation) Chalks form the primary reservoir for the field, but hydrocarbons were also produced during testing from the carbonate cap-rock to the salt and from Lista Formation and Maureen Formation sandstones. Reserves are estimated to be in excess of 75 MMBO. Major reservoir uncertainties remained at the end of the appraisal phase and development of the field proceeded in two phases. Phase 1 consisted of a two well Early Production System, which produced hydrocarbons for six months. During this period almost 5 M M B O were produced at rates of up to 40 000 BOPD. Phase 2 development is via a dedicated Floating Production System and Offtake vessel named Ramform Banff (Fig. 4). Phase 2 production commenced in January 1999.
History Block 29/2 was awarded to Placid as operator and Caledonian in 1972 in the Fourth Round of Licensing. Conoco, Ranger, Saxon and Union Jack farmed in to the licence by drilling well 29/2a-2 in the south of the block, in 1984 and Conoco took over the operatorship. Enterprise acquired their equity in the block through the take-over of Saxon in 1985. Caledonian became Cairn Energy whose interests were acquired by Enterprise by means of an asset swap in 1990. Placid sold part of their interest to Trafalgar House, which de-merged its oil and gas assets to form Hardy Oil and Gas in 1989. The remainder of Placid's equity was acquired by L A S M O as part of their purchase of Placid in 1990 and subsequently sold on to Ranger and Hardy. Ranger took over Union Jack and increased their share of the licence through contribution to the well costs of 29/2a-6, which they drilled. Hardy Oil and Gas merged with British Borneo in October 1998.
The unit area of the Banff Field extends into Block 22/27a. Block 22/27 was awarded during the Third Round, in 1970, to Ranger (operator) and Scottish Canadian Oil and Transport Company. In June 1976 the Block 22/27 owners relinquished a portion of the, retaining the acreage which is now Block 22/27a. The owners of Block 22/27a at the time of the relinquishment were Ranger (operator), Scottish Canadian Oil and Transport Company (which became L A S M O in 1981) and IU Oil and Gas Ltd. The present owners of Block 22/27a are Ranger (44.85% operator), Enterprise (30.18%), BP Amoco (13.22%) and Petrobras (11.75%). Amoco sold their interest in the Banff Field to Enterprise. The field discovery well, 29/2a-6, was spudded by Ranger in August 1991. The original well was sidetracked to a Total Depth (TD) in the halite. Ranger then spudded well 29/2a-7 downdip of the discovery well, which reached T D in the Tor Formation Chalks and was plugged and temporarily abandoned as an oil well in February 1994. The crestal well, 22/27a-3 found the Cretaceous and Paleocene sections to be thin or absent. Conoco subsequently drilled appraisal well 29/2a-10 to the N W of the 29/2a-6 and 29/2a-7 wells (Fig. 2). The Banff Unit was formed in November 1995 with Conoco as Operator. Partners are Enterprise Oil plc, Ranger Oil U K Ltd, British-Borneo Oil and Gas plc and Petrobras U K Ltd. At this stage in the appraisal of the field it was apparent that significant uncertainties remained with regard to reservoir performance and volumetrics. A Phase 1 development was planned, which consisted of two producing wells. The EPS wells were drilled in 1996 and produced about 5 M M B O in the course of six months. Figure 5 is a three dimensional image of the Banff raft, showing the trajectories of the first two development wells. It was decided that Phase 2 development would be by means of an FPSO vessel. A production services contract was entered into with PGS and Atlantic Power to produce hydrocarbons from the field. Conoco retained operatorship of the subsurface. PGS constructed an FPSO using a novel Ramform hull design and the vessel, named Ramform Banff achieved first production in January 1999. As of November 1999 12.5 M M B O have been produced at rates up to 60 000 BOPD.
Seismic Seismic imaging and delineation of the chalk raft is compromised by the steep dips and by rapid lateral and vertical changes in velocity. Mapping the raft is also complicated by extensive fracturing and changes in the acoustic impedance of boundaries as a result of local facies variation. Reprocessing of the data using 3D pre-stack
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 497-507.
497
498
N. E V A N S E T AL.
~z
o O
BANFF FIELD
499
Fig. 2. Simplified Top Balder depth structure map.
depth migration over a 100 km 2 cube has improved the image of the raft and of the underlying diapiric structure. The most important improvement in seismic imaging was achieved by the use of pre-stack depth migration techniques to resolve sharp velocity increases between the Tertiary overburden and the chalk sections. These improvements have enabled more precise mapping of the extent of the chalk raft and have reduced uncertainty in volumetric calculations.
Structure The unusual geometry of the steeply dipping chalk raft is a result of a complex structural history (Evans et al. 1999). The Zechstein salt has clearly had a strong influence on the structure but growth of the salt dome was mainly passive or reactive, in response to extension and off-structure sediment loading (Vendeville & Jackson 1992). Evidence for active diapirism is confined to the Late Tertiary. The Zechstein salt began moving shortly after deposition, locally forming salt swells and walls in response to Lower Triassic extension (Fig. 6). A NW-SE oriented salt wall developed in the Banff area, controlled by basement lineaments (Bartholomew et al. 1993). More than 6500 ft of Jurassic sediments were deposited to the west of the Banff salt wall, reflecting continued extension. Growth on the graben-bounding fault on the western margin created the accommodation space. Sediment loading and tilting of the fault block to the west of Banff fed the gravity-driven passive growth of the salt
wall. It is thought that the salt maintained a position close to the seabed throughout the Jurassic. Relatively thin Cretaceous and Paleocene sequences are found in the Banff raft. These are considered to be condensed equivalents of thicker sections found in offset wells surrounding the diapir. Thinning of sequences onto the structure indicates that passive growth of the salt swell was continuing, but at a slower rate than sedimentation. By mid-Cretaceous an elongate proto-diapir structure had begun to develop at the intersection of N W - S E and E-W basement fault lineaments. Short periods of active, upward diapir growth may have accompanied fault-block tilting and mild inversion in the area (Sears et al. 1993). Early extensional faulting of the chalk raft probably began at this time during periods of diapir growth. Early faults would have been parallel to the axis of the elongate salt wall/diapir. Tectonic squeezing of the diapir stem led to upward growth of the diapir, and deformation of the thinned cover. The earliest growth period occurred in the Late Eocene, resulting in faulting, stretching and thinning of the Cretaceous and Paleocene section over the diapir. Rupturing of the cover along the NE edge of the diapir probably occurred at this time, allowing a crestal salt high to develop. A period of inactivity and passive subsidence followed, when the structure was covered by Oligocene and Miocene sediments. The main period of active diapirism occurred at the end of the Mid-Miocene, recorded by an angular unconformity above the structure. The raft on the SW flank tilted, allowing the salt piercemerit to exploit the thin cover at the location of the earlier northeast
500
N. EVANS E T AL. $W
29/2a~7 29/'2a.~6MST
Fig. 3. Structural cross-section of the Banff diapir.
Fig. 4. Ramform Banff FPSO.
21V2"l~ &3z
NE
BANFF FIELD
501
Fig. 5. 3D image of the Banff raft, showing the 29/2a -B 1 and 29/2a-B2 (Phase 1 development) well paths.
crestal salt high. The tilting of the raft was accompanied by further extensional faulting and fracturing. The original normal faults are now overturned in places to give the appearance of reverse faults. It was at this late stage that the chalk raft was partially disconnected from the surrounding chalks along a major fault zone at the southwest edge of the structure. Onlap of Late Miocene sediments over the structure mark the end of active diapirism. Subsidence has continued since the Miocene so that the chalk is now at its maximum depth of burial. A low relief structure at the seabed reflects a combination of continued downbuilding and natural buoyancy.
Stratigraphy In the area surrounding the salt diapir a full sequence of Tertiary shales and subordinate sandstones, Upper Cretaceous Chalk and Lower Cretaceous shales are preserved between the Base Cretaceous and Miocene unconformities. This sequence rests on Upper Jurassic shales and sandstones, which in turn overlie Triassic clastics. None of the offset wells in the area has penetrated the Zechstein. The generalized stratigraphy of Banff Field is shown in Figure 7. The Zechstein halite of the diapir is capped by anhydrite and dolomites. The chalks, which form the raft belong to the Tor and later Ekofisk Formations and are in places underlain by thin limestones and claystones of the Lower Cretaceous. The Maastrichtian Tor Formation and the Danian Ekofisk Formation in the Banff Field have been subdivided by nanoplankton zones (Robertson Research pers. comm., 1995). The N1 to N4 zones comprise the Ekofisk Formation with basal occurrence of Zygodiscus sigmoides marking the base of the Ekofisk. The Tor Formation is broken down into zones N5 to N8. A complete but condensed stratigraphic section from N7 to N1 is present in the crestal well 29/2a-6, suggesting gentle positive structural relief over the Banff diapir during deposition of the chalk.
Intervals of sandstone occur within the Ekofisk Formation in each of the Banff wells. The sands are immature, medium to coarse grained, feldspathic and lithic wackes and arenites. The sands are petrographically similar to the overlying Maureen Formation Sandstone. Contemporaneous sands have rarely been recognized in the Ekofisk Formation Chalk of the southern Central Graben and are not reported in any of the wells surrounding the Banff structure. The stratigraphic relationship of the sand units within the chalk is therefore problematical and unresolved. It is possible that the sands are Maureen Formation in age and were injected into fissures in the chalk. Core descriptions vary from discordant sand injection features to apparently conformable bedding features consistent with high-density turbidites. A relatively thin, but apparently complete sequence of Paleocene sandstones and claystones of the Maureen and Lista Formations, overly the Ekofisk Formation Chalk. They are interpreted to represent deep marine shales and turbidity channel deposits. From the the Oligocene upwards, the lithologic succession consists of marine shales interbedded with thin limestones and siltstones. The percentage of limestone and siltstone in the muds decreases upwards. This apparently monotonous sequence belies episodes of major diapirism in the Late Eocene and mid-Miocene, during which the salt mass almost breached the sea floor.
Trap The primary trapping mechanism for the Banff Field hydrocarbon accumulation is four-way structural dip created by the Banff diapir, which was created very early in the history of the feature. The structural dip was progressively accentuated such that the main chalk raft became isolated from the flanks at reservoir levels (Figs 6 & 8). RFT data from well 22/27a-3Z on the northern flank indicate that there may be lateral pressure continuity from the chalk reservoir into the Tertiary sands around the structure. An extension
502
N. EVANS ET AL.
Fig. 6. Structural history of the Banff diapir.
of the oil leg all around the structure cannot be ruled out if a chalkto-sand porosity network is maintained. Charging of the Tertiary sands, where it occurs is probably through contact with the chalk. Side-seal will exist where oil-bearing chalk contacts shale-rich Tertiary sediments. Top seal is provided by Tertiary shales. A seismically imaged gas cloud above the structure suggests that the structure is leaking at the present day.
lithofacies groups, related to their method of deposition (Evans et al. 1999):
Reservoir
(2)
Chalks belonging to the Upper Cretaceous Tor and Ekofisk Formations form the primary reservoir for the Banff Field. Secondary reservoirs include the Paleocene sand and the carbonate cap rock of the Zechstein salt. The chalks have been sub-divided into three
(1)
Debris Flow. Highest porosities and permeabilities occur in
proximal debris flow facies within the Tot Formation. The poorly sorted, subangular character of some of the pebbly intraclasts within the chalk debris flows suggests local reworking, probably associated with pulsed growth of the diapir structure. Fracture zones superimposed on the debris flows tend to dilate and create pervasive fracture networks. Pelagic. By contrast the more homogenous pelagic chalks are characterized by low permeability and argillaceous laminae. Fractures are less pervasive as stress can be taken up by ductile shear in the argillaceous content of the chalk. However, there are still sufficient fractures to allow high production rates from these chalks.
BANFF FIELD
503
Fig. 7. Type Log 29/2a-6MST.
(3)
Transported. A less well defined group, representing allochthonous chalks without the diagnostic slumped, chaotic and poorly sorted nature of the proximal debris flows. Distal turbidites are included in this group.
The fracture system is critical to effective drainage of the tight matrix and facilitating the imbibition process under waterflood. Analysis of the pressure data from the 29/2a-B 1 and 29/2a-B2 wells during the EPS indicates that the chalk raft has excellent vertical and lateral pressure communication through the fracture network. Fracture characterization using core observations to calibrate image logs (Western Atlas STAR2 and CBIL) and other wireline log data has been integral to the Banff reservoir modelling (Evans et al. 1999). Fracture associations range from sub-vertical faults and planar large scale tectonic fractures to vuggy/brecciated zones with pervasive open fracture frameworks. A complex interaction of fracture and fault sets has been described with successive phases of rotation and reactivation of earlier systems. The key observations are: 9 A consistent NW-SE tectonic fracture and fault strike is recognized in each of the Banff wells. 9 Tectonic fractures appear to be extensional with respect to bedding and form well-developed parallel sets. 9 Vuggy, pervasive open fracture zones are common in the upper raft. These high permeability zones are specific to debris flow
facies within the Tor Formation Chalk. Production logging data indicate a close relationship between high flow rates and the presence of these zones. Healed fractures are common in the lower raft, described as narrow zones of comminuted chalk matrix healed by cementation. The excellent data set available from the wells has been used to demonstrate the distribution of fracture types within the chalk reservoir (Fig. 9). Open fractures are only recognized in the upper raft (above c. 6000 ft TVDss). In situ stresses are inferred to exert a strong influence on the fracture type. In summary, a tensional open fracture system is indicated at the top of the raft and a compressive, closed fracture system at the base. DST results from the discovery and appraisal wells also indicate higher deliverabilities in the upper section of the raft (Sykes et al. 1996). The Banff reservoir pressure is close to normal hydrostatic and overpressure is not considered to have been a major factor in retaining porosity during burial. Gradual filling of the Banff raft with hydrocarbons during Oligo-Miocene burial had the effect of halting the porosity destroying process and can be related to depth in the high relief Banff raft. Similar relationships between reservoir quality, burial depth and timing of oil migration have been documented by other authors (e.g. Taylor & Lapre 1987; Foster & Rattey 1993). The controls on reservoir quality in the chalks are summarized in a schematic cross-section in Figure 10.
504
N. EVANS E T AL.
9
.9 , ,,,,~
BANFF FIELD
505
Fracture Index developed for reservoir modelling, based on core and wireline log data. Codes 1-3 Code O: Code -1:
Indicate increased flow enhancing capability Fractures regarded as neutral Cemented or healed fractures considered to be detrimental to reservoir performance.
Fig. 9. Porosity v. depth v. fracture index for five wells.
Source The source for the oil in the field is the Upper Jurassic Kimmeridge Formation shales, which are well developed in the area adjacent to the Banff Field. These algal sapropelic source rocks were deposited in moderately anoxic conditions and are characterised as Type 1A by Cooper & Barnard (1984). The source rocks are currently in the middle to top of the oil generation window and they may have begun generating oil in the Banff Field area as early as the Palaeocene, and peaked in the late Miocene. The lighter hydrocarbons found in this area were emplaced mainly through vertical migration (Cayley
1987). Migration into and through the chalk exploited fractures at the point of maximum flexuring above graben edge faults or via diapirically induced fault and fracture systems.
Hydrocarbons The Banff Field contains good quality sweet crude with an API gravity range of 38-40 ~, with lighter crude at shallower depths. Bubble point varies from 2660 psia at 180~ at the GOC down to 2200 psia at 180~ at the OWC. The solution G O R also varies with
506
N. EVANS E T A L .
Fig. 10. Schematic summary of controls on reservoir quality in the Tor Formation Chalk of the Banff raft.
depth, but wells typically produce in the range 650-700 SCF/STB. The formation volume factor is approximately 1.3. The crude has a tendency to foam in the facilities and although waxing was an initial concern it has not been a problem during production. The fluid composition from a recombined sample in appraisal well 29/2a-10 is as follows: Component
Mol %
N2 H2S CO2 ~ Methane Ethane Propane Isobutane N-Butane Isopentane N-Pentane Hexanes Heptanes +
0.15 0.0 1.3 34.9 7.7 6.4 1.1 3.6 1.3 2.2 3:0 38.5
Reserves and production Initial uncertainty in the ability to sustain long-term production from a low matrix permeabilty, potentially compartmentalized structure led to a phased development for the Banff Field. Phase 1 consisted of two producers drilled to maximize productivity from the chalk reservoirs, and to address some of the major reservoir uncertainties. The wells were tied back to a floating production unit (FPU), a converted semi-submersible drilling rig. Almost 5 MMBBL oil was exported via a shuttle tanker. The EPS showed that both wells were capable of more than 30 000 BOPD for extended periods and proved lateral and vertical connectivity in the reservoir. Approval for Phase 2, the full field development, was received in February 1997. Phase 2 production started in January 1999 and since then has reached rates of up to 60 000 BOPD. The development plan has retained the two EPS producers, 29/2a-B1 and 29/2a-B2. Two horizontal injectors, 29/2a-B3Z and 29/2a-B4, completed towards the base of the reservoir support the producers. The two producers, 29/2a-Bl and 29/2a-B2 were drilled stratigraphically following the dip of the reservoir and completed with cemen-ltl ted, perforated liners and >~ tubing. The two injectors, 29/2a-B3z
BANFF FIELD and 29/2a-B4 are horizontal and completed with u n c e m e n t e d , preperforated liners and 7" plastic-coated tubing. All four wells were stimulated with high-rate acid treatments from a stimulation vessel. The wells are completed subsea and are tied back to the novel R a m f o r m design FPSO. Oil is exported by two shuttle tankers, whilst gas is exported via a short spur to the Central Area Transmission System (CATS) line. M e a n S T O I I P for the productive Ekofisk and Tor F o r m a t i o n reservoirs is a b o u t 300 M M B O , Ultimate recovery is expected to be in excess of 75 M M B O . There is a further 60-70 M M B O in place in the overlying Paleocene sandstones and c a r b o n a t e caprock. However, these reservoirs are generally p o o r quality a n d are b r o k e n up by the m a n y faults on the raft structure. There m a y be some recovery by c o m m u n i c a t i o n with the chalk, but no dedicated development is currently planned. The authors wish to thank the Banff Unit partners: ConocoPhillips (UK) Ltd, Enterprise Oil plc, Ranger Oil (UK) Ltd, British-Borneo Oil and Gas plc and Petrobras UK Ltd, for permission to publish this paper. We must also acknowledge the contributions of numerous previous workers on Banff Field at ConocoPhillips and within the partnership.
Formation water Salinity Resistivity Reservoir conditions Temperature Pressure Pressure gradient in reservoir
Field characteristics Area
Gross rock volume Oil initially in place Recovery factor Drive mechanism
Banff Field data summary
Production Start-up date
Trap Type
Number/type of wells Production rate
Depth to crest Lowest closing contour FWL Oil column Gas-oil contact Gas column
Pay zone Formation
Age Gross thickness
Net/gross ratio Net pay cut-off
Porosity average (range) Matrix permeability Effective permeability Average oil saturation Productivity index
Hydrocarbons Oil gravity Oil type Bubble point Gas/oil ratio Formation volume factor
Four-way dip closure over salt diapir, with side, top and updip seal provided by shaly lithologies Approximately -4249 ft (1295m) TVDss Approximately -9600 ft (2926 m) TVDss. Structure is not full to spill -7610ft (2319m) TVDss 3059 ft (932 m) -4551 ft (1387m) TVDss Approximately 298 ft (91 m)
Ekofisk and Tor chalk. Oil is present in overlying Paleocene sands, but this oil is not considered recoverable except to the extent which it drains into the chalk. Late Cretaceous (Tor Formation) and Early Paleocene (Danian) (Ekofisk Formation) Ekofisk and Tor ranging from approximately 1000 ft (300 in) near FWL, thinning to zero at up-dip edges of raft. Mean 69.8% Porosity >20% for Upper Ekofisk, >15% for Lower Ekofisk and >12% for Tor (about equivalent to 0.1 mD permeability. Water saturation <55% for all reservoir units. Mean 20.3% (P90/P10 10-27%) 0.1-10mD for Chalk, 1-60mD for Paleocene. Up to 600mD Mean 62.3% 200-300 b/d/psi
38o-40 ~ API Sweet light 2660psia (183 bar) at GOC, 2200psia (152bar) at OWC, at 180~ (82~ 600-800 SCF/STB 1.31
507
64 000 ppm NaC1 0.115ohm-m @ 60~ (15.5~
77-99~ (25-37~ 2600-3570 psi (179-253 bar), depending on reservoir elevation. Gas gradient 0.07 psi/ft (0.016 bar/m) Oil gradient 0.30 psi/ft (0.068 bar/m) Water gradient 0.45 psi/ft (0.1 bar/m)
Main chalk raft, horizontal projection: approximately 1000acres (4 x 106 km 2) Total structure above -7610' (2319 m) TVDss (FWL): approximately 2700 acres (10.9 x 106 km 2) 563 928 acre-ft (695 x 106 m 3) 304 MMBBL 26% Water injection
Phase 1: 14th Sep 1996, Phase 2: 30th January 1999 2 Producers, 2 Injectors Up to 60 000 BOPD
References BARTHOLOMEW, I. D., PETERS, J. M. & POWELL, C. M. 1993. Regional structural evolution of the North Sea; oblique slip and reactivation of basement lineaments. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1109-1122. CAYLEY, G. T. 1987. Hydrocarbon migration in the Central North Sea. In: BROOKS, J. & GLENME, K. W. (eds) Petroleum Geology of Northwest Europe. Geological Society, London, 549-556. COOPER, B. S. & BARNARD,P. C. 1984. Source rocks and oils of the Central and Northern North Sea. In: DEMAISON, G. & ROELOF, J.M. (eds) Geochemistry and Basin Evaluation. American Association of Petroleum Geologists, Memoirs, 35. EVANS, N., RORISON,P. & SYKES,G. 1999. Banff Field, UK Central Graben Evaluation of a steeply dipping, fractured chalk reservoir. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 975-991. FOSTER, P. & RATTEY, P. 1993. The evolution of a fractured chalk reservoir: Machar Oilfield, UK North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1445-1452. SEARS, R. A., HARBURY, A. R., PROTOY, A. J. G. & STEWART, D. J. 1993. Structural Styles from the Central Graben in the UK and Norway. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedinfls of the 4th Conference. Geological Society, London, 1231-1243. SYKES, G., ABDELMALEK, N. & EVANS, N. 1996. B a n f f - A High Angled Fractured Chalk Development for the New Era. Society of Petroleum Engineers, SPE 36915. TAYLOR, S. R. & LAPRE, J. F. 1987. North Sea Chalk diagenesis: its effect on reservoir location and properties. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of Northwest Europe. Geological Society, London, 483-495. VENDEVILLE, B. C. & JACKSON, M. P. A. 1992. The rise of diapirs during thin-skinned extension. Marine and Petroleum Geology, 9, 331-353.
The Curlew Field, Block 29/7, UK North Sea G. ENEYOK,
P. B U S S I N K
& A. MAAN
Shell UK Exploration and Production, 1 Altens Farm Road, Nigg, Aberdeen AB12 3 FY, UK
Abstract: In 1964, Block 29/7 was awarded as part of the first licencing round to Shell and Esso (UK). The Curlew area comprises a series of terraces that step down from the Western Platform into the West Central Graben. Exploration drilling started in 1977 but it wasn't until 1990 that well 29/7-4 successfully tested a 100 ft column of undersaturated volatile oil in the Upper Jurassic Fulmar Formation sandstones. Further exploration drilling, aided by 3D seismic data (acquired in1991), yielded additional discoveries: Curlew C (1993, oil) and Curlew D (1994, condensate-rich gas). In Curlew D new technologies were successfully applied to describe and evaluate the isolated hanging wall compartment. Oil was discovered in what is now called Curlew D South in February 2000. Hydrocarbon accumulations in the Curlew area occur in dip-closed faulted anticlinal structures. The producing Upper Jurassic Fulmar Formation is a heterogeneous mix of bioturbated shallow marine sandstones, barrier sandstones, and lagoonal/ swamp deposits. The range in reservoir quality is reflected in the field porosity (5-27%) and permeability (0.001-8000 mD). Reservoir compartments in the field (Curlew B, D, and D South) are controlled by complex reservoir architecture, structure and fault geometry. Each reservoir compartment is characterized by a different fluid contact and a distinct fluid type. The reservoir heterogeneity provides potential for bypassed hydrocarbons in undrilled compartments, as was proven by the Curlew D South development. Curlew B, D, and D South have since been developed. Evacuation of hydrocarbons from the Curlew area is via the Maersk Curlew FPSO, to which the producing wells have been tied back. Gas is fed into the Fulmar Gas Line and oil is taken onshore by shuttle tankers. The initially-in-place volume in Curlew B at standard conditions is 24 MMSTB of oil and 25 BSCF of solution gas. Curlew B was developed via horizontal well 29/7-10y and came on stream in November 1997 at a rate of about 23 000 STB/D. The initially-in-place volume in Curlew D is 340 BSCF of gas and 100 MMSTB of condensate. Curlew D was developed via two vertical wells, 29/7-8z and 29/7-9, and started production in February 1998 with production rates up to 115 MMSCF/D of gas and 34000 STB/D. Gas production from the field is constrained, however, by the facilities. Curlew D South is developed by the vertical well 29/7-11, which came on stream in March 2000 after a North Sea record-time tie back of the original appraisal well.
T h e C u r l e w Field is located in Block 29/7, a p p r o x i m a t e l y 225 k m E o f A b e r d e e n o n the U n i t e d K i n g d o m C o n t i n e n t a l Shelf (Fig. 1). H y d r o c a r b o n a c c u m u l a t i o n s were discovered in C u r l e w A B, C a n d D. C u r l e w B a n d D discoveries were t o g e t h e r c o n s i d e r e d to be e c o n o m i c a l l y viable a n d h a v e been d e v e l o p e d via a F l o a t i n g P r o d u c t i o n Storage a n d Offtake ( F P S O ) facility.
History Pre-discovery Block 29/7 was originally a w a r d e d as p a r t o f the first licencing r o u n d ( P r o d u c t i o n Licence P.012) in 1964 to Shell U K a n d Esso
Fig. 1. Location map of Curlew Field (Block 29/7).
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 509-522.
509
510
CURLEW FIELD
UK on 50:50 equity basis. Exploration drilling started with well 29/7-1, drilled in 1977, and resulted in an oil discovery in the Paleocene Forties Formation known as Curlew A (Fig. 1). The target Upper Jurassic Fulmar Formation was, however, dry. A second exploration well (29/7-2) was drilled in 1979 but was also dry and subsequently abandoned. The discouraging results in Block 29/7 and the simultaneous success further north focused the exploration effort in other areas. Acquisition of 2D seismic data (1985, 1987) continued in Block 29/7 and a third exploration lead was matured and drilled (well 29/7-3) in 1987 but again was dry.
Discovery Curlew B the western most section of the Curlew prospects, was tested in 1990 by well 29/7-4 and penetrated a 490 ft thick sequence of Fulmar Formation sandstones at a depth of 10683ft TVDss (Fig. 2), of which the upper 100ft was hydrocarbon bearing. The well tested at 8800STB/D of 39~ undersaturated oil. Interpretation of the seismic data identified a larger upside in Curlew B than previously considered. This encouraged further appraisal drilling and justified the acquisition of 3D seismic data in 1881. The appraisal well (29/7-6) penetrated top Fulmar Formation significantly deeper than prognosis. As a consequence, the Fulmar Formation was water bearing with the exception of the uppermost 35 ft, which showed low oil saturation (15-30%). This result downgraded the Curlew B discovery. Curlew C is located east of Curlew B (Fig. 1). The discovery well, 29/7-5, drilled in 1993 encountered 191 ft of net oil column in the Cretaceous Chalk Group at a depth of 8316 ft TVDss. The well tested at 5000 STB/D of 39 ~ API undersaturated oil. However, the target Upper Jurassic Fulmar Formation was found to be waterbearing. The results of wells 29/7-5 and 29/7-6, although discouraging on their own, increased the probability of success for the exploration prospect Curlew D (flanked to the west by Curlew B and to the east by Curlew C; Fig. 1). Exploration well 29/7-7, located on the crest of the structure, successfully tested the prospect in 1994 (Fig. 2). It encountered 570ft of hydrocarbon bearing Fulmar Formation sandstones at a depth of 10 087 ft TVDss. The well was production tested and found to contain an undersaturated nearcritical rich gas-condensate in the upper part of the reservoir changing gradually into an undersaturated volatile oil at deeper levels. The added gas/condensate reserves proven by this well made further appraisal or an immediate (flexible) development of the area attractive, the latter being the preferred option.
adjacent to the exploration well. Both wells encountered a sequence very similar to that found in the exploration well 29/7-7. Curlew D started production in January 1998 when well 29/7-9 came on stream. Problems, however, with the removal of a plug from well 29/7-8 necessitated drilling a sidetrack well, 29/7-8z, which came into production in July 1998. Both wells have since produced at rates of up to 90 M M S C F / D . In the post-development review of Curlew D the southern bounding faults were re-interpreted to be further north than initially thought. This opened up the possibility of a significant accumulation in the hanging wall trap to the south. This prospect (Curlew D South) was further firmed up using geochemical methods and seismic-based direct hydrocarbon indicators. At the start of 2000, well 29/7-11 was drilled as an exploration well into this structure. The well encountered about 500 ft of oil-bearing Fulmar Formation sandstones and was tied back in recordbreaking time to the Curlew Maersk FPSO in March 2000 (Fig. 2). Figure 3 is a structural cross-section through Curlew B, D South and D showing initial accumulation conditions.
Development strategy All three development wells were completed sub-sea and tied back with flowlines to the Maersk Curlew FPSO (Fig. 4). Oil is exported via shuttle tankers and the gas is exported via the Fulmar Gas Line. The development plan for Curlew B and D assumed a strong aquifer that would maintain reservoir pressure. In Curlew B, the aquifer was expected to provide a good sweep of the reservoir whilst keeping the reservoir pressure above the bubble point during the production life of the field. The two development wells in Curlew D (29/7-8z and 29/7-9) also relied on the aquifer to mainitain the reservoir pressure above the dew point for a significant part of its producing life, so as to avoid the drop out of liquids in the reservoir. In order to deal with the risks outlined above, the following steps were taken: (1) permanent downhole gauges were installed in all producers to monitor the reservoir performance in real time; and (2) space was reserved on the FPSO to allow the installation of water injection facilities. However, in Curlew B reservoir pressure started to decline as soon as production commenced and the reservoir produced below the bubble point from February 1999. Curlew D went below the dew point in May 1999, and liquid production has reduced significantly due to condensate dropout in the reservoir. The provision made in the field dvelopment plan (FDP) for pressure maintenance via water injection turned out to be uneconomical, and both reservoirs went on to produce via natural depletion.
Post-discovery After the discovery of Curlew D it was decided to fast-track the development of the field without additional appraisal drilling. The concept of early development called for the use of a Floating Production Storage and Offtake (FPSO) vessel capable of handling the gas/condensate from Curlew D and oil from Curlew B. It was decided to lease the Maersk FPSO. Curlew B is bisected by an E - W trending fault into two compartments, both of which were to be developed via a duallateral well. The first leg of the dual-lateral (well 29/7-10) drilled in 1997 to develop the northern compartment found the Fulmar Formation water-bearing and was abandoned. As a consequence, a pilot well (29/7-10z) was drilled to test the oil-water contact (OWC) in the heel of the planned trajectory of the second lateral. This well found the OWC to be a shallow 46 foot compared with the discovery well, showing further evidence of compartmentalization in the reservoir. The second lateral, well 29/7-10y, was drilled as a horizontal producer to drain the southern compartment. Curlew B started production in November 1997 at an initial rate of about 23 000 STB/D. Curlew D is developed via two vertical wells, 29/7-8 and 29/7-9, which were drilled in 1996 on the crest of the structure immediately
Structure The Curlew Field is located in the southwestern part of the West Central Graben. Structurally, the area comprises a series of terraces that step down from the Western Platform into the West Central Graben. The westernmost terrace containing the Curlew B and D structures is bounded to the east by N W - S E and W N W - E S E trending fault systems and to the west by a N - S basin boundary fault (Eggink et al. 1996). The Curlew structure appears to show rapid lateral variations as illustrated in Figure 5. This line shows clear inversion of the Jurassic basin that lies to the south and east of Curlew D. The inversion related dome is onlapped by presumed Early Cretaceous sediments, indicating its age of initial formation to be latest Jurassic to earliest Cretaceous. Detailed mapping of the Curlew structure shows that the Curlew faults can be separated into those which cut the Base Cretaceous Unconformity (BCU) reflector or have generated topography at that time (even if no clear offset is present), and those which became inactive at or before the BCU. Figure 6 shows four patterns of fault activity mapped in the Curlew Field:
G. E N E Y O K ET AL.
511
d.
9
eO
ee
9
-0 b~
o
o
r~
G. ENEYOK ET AL.
513
Oil Gas Umbilical
Fig. 4. Curlew B and D infrastructure.
(a) (b) (c) (d)
Upper Jurassic extensional activity; Upper Jurassic extension and late Upper Jurassic /Early Cretaceous compressional/transpressional activity; Early Cretaceous extensional activity; Late Cretaceous/Tertiary compressional activity.
The fault pattern mapped at Jurassic reservoir levels is clearly complex, but it is noteworthy that the fault pattern present in the Curlew area is broadly similar to that described by Jones et al. (1997, in press) in the eastern Witch Ground Graben area.
Stratigraphy The Upper Jurassic stratigraphical synopsis for the Curlew Field is given in Figure 7. The Fulmar Formation is underlain by the Middle Jurassic Pentland Formation and overlain by the Upper Jurassic Heather/Kimmeridge Clay Formation. Regionally, the Fulmar Formation can be divided into two members, the Fulmar Formation s e n s u s t r i c t o and the Curlew Member. The Fulmar Formation s e n s u s t r i c t o consists of a sequence of bioturbated sandstones, with locally laminated sands, deposited in a shallow marine environment. It is also referred to as the Upper Fulmar Formation (Fig. 8). It is Kimmeridgian in age and is restricted to the Central North Sea area. The Curlew Member is generally Oxfordian in age, contains shallow marine to marginal marine or lagoonal (coals) deposits, and is restricted to the deeper part of the Central Graben. This Curlew Member comprises an upper and a basal sequence referred to as the Middle Fulmar and Lower Fulmar Formation, respectively (Fig. 8). The stratigraphy of the Upper Jurassic sequences in the Curlew area is very complex. Figure 9 shows apparent thickening of the uppermost Jurassic sequences across the Curlew D horst. The Kimmeridge Clay Formation penetrated in wells 29/7-7 and 29/711, with a separation of about 500m are 230 ft and ~625 ft thick,
respectively. The Heather Formation is not present on the basinal palaeo-highs, as seen for Curlew D in Figure 7. The variations in the stratigraphy described here as well as the onlapping sequences indicated on Figure 5 are most likely influenced by salt movements (Erratt 1993). Salt movement in the area may have already started during Middle Jurassic times and persisted through Kimmeridgian and Volgian times. Several unconformities recognized in wells 29/7-5 and 29/7-7 suggest episodic uplift of these structures. The Cretaceous section recorded in Curlew B is thicker and more complete, indicating more continuous subsidence. The Fulmar Formation interval is generally constant in thickness (490-640 ft) along a broad E N E - W S W trend from Curlew C to Curlew B. Further north-westward its thickness increases up to 1400 ft. A sharp thinning occurs at the E - W trending fault system separating the Curlew B and D areas from the Curlew A area. The Fulmar Formation thickness increases to over 1000ft across the fault bounding Curlew D to the south (Fig. 3), indicating active salt withdrawal during deposition. Similar variations in the Fulmar Formation have not been observed across the fault systems mapped on the Curlew B structure.
Trap The hydrocarbon accumulations of Curlew B and D occur in the dip-closed anticlinal Upper Jurassic Fulmar Formation (Fig. 2). Repeat formation test (RFT) pressure measurements (Fig. 10) show that both Curlew B and D are overpressured by some 3000 psi. Top seal is provided by the Kimmeridge Clay Formation. The Curlew B structure is dissected centrally by a N E - S W trending normal fault. Intra-reservoir faults provide lateral seal, which compartmentalize the field. Wells 29/7-4 and 29/7-10z logged different contacts, 10 768 ft TVDss and 10 722 ft TVDss for the foot
514
CURLEW
FIELD
=
=
9 r~
I
G. E N E Y O K ET AL.
515
,<
.,.a
516
CURLEW FIELD
SEAL~S(~JRCE
RESERVOIR
SOURCE (gasprone)
Fig. 7. Curlew stratigraphic synopsis.
and hanging wall, respectively. Therefore, the separating fault is assumed to be sealing (Knipe 1997). As the N E - S W fault does not appear to abut a N-S fault in the SW of the field, discovery of a different oil-water contact leads to the N E - S W fault being extended beyond its seismically resolvable length to compartmentalize the accumulation. This is supported by a recent fault seal study, which concluded that phyllosilicates within the Upper Fulmar Formation might be the main reason for sub-seismic seals to arise. Based on the present top Fulmar Formation depth map, with a spill-point at a depth of 10 900 ft TVDss, Curlew B appears to be under-filled. Figure 9 is a N-S seismic section through the Upper Jurassic stratigraphic sequence of Curlew D. The Curlew D structure is dissected by an E - W trending normal fault (Fig. 2). Well 29/7-7 logged hydrocarbon down to the base of the Fulmar Formation and the fluid contact was taken at a mapped spill point of 10 780 ft TVDss. During development, the gas-water contact (GWC) was reinterpreted at 10644 ft TVDss from RFT data taken in well 29/7-11. Curlew D south well (29/7-11) logged oil down to a depth of 10 935 ft TVDss and found water from 11043 ft TVDss. This well was drilled after Curlew B and D had been depleted by about 3000 psi and found Curlew D South to be slightly depleted (50 psi depletion). Therefore, the original OWC interpreted at 10890ft TVDss is shallower than the logged depth (10 935 ft TVDss).
Sedimentology In the Curlew Field, the Fulmar Formation is subdivided into three distinct units based on lithology and depositional setting. These units are, listed from the top stratigraphically, the Upper, Middle and Lower Fulmar Formation. The sedimentology of the subunits is described below. The sandstone distribution indicates successive barrier islands that are bounded up-dip by sandy lagoonal and swamp deposits. In general, the facies architecture of the Fulmar Formation is broadly comparable to ancient siliciclastic deposits of coastal-plain barrier setting (Hamilton 1995). The facies associations suggest that the Fulmar Formation was deposited in a transgressive coastal-plain setting (Fig. 8). The Fulmar Formation grades down-dip into offshore marine sandstones seen in well 29/7-1. Further description of the barrier geometry and the maximum position of the shoreline in the basin is not possible because well control is very sparse in the area. Figure 11 is a cross-plot of core derived porosity and permeability from well 29/7-7.
Upper Fulmar Formation The Upper Fulmar Formation consists of shallow marine sandstones which form an overall fining upward sequence. The sandstones
G.
ENEYOK
ET AL.
517
,.-z, r
o
o
_E
,-r o
o o
518
CURLEW
FIELD
r,.)
. o,,...., +,,,a
.,,,~
r.~
G. ENEYOK ET AL.
519
Fig. 10. Well 29/7-8 RFT plot.
are highly bioturbated, moderate to well sorted and fine to very fine-grained. Deposition is interpreted to have taken place in a lower shoreface setting (Fig. 8). The presence of argillaceous siltstone beds and stratified dolomite and calcite cements are likely to affect vertical communication within this predominantly sheet-like reservoir. Hydrocarbons in Curlew B are contained in the Upper Fulmar Formation with average porosity and permeability of 21% and 20mD, respectively. Towards Curlew D, the Upper Fulmar Formation starts to deteriorate and the average permeability reduces to some 5 m D (range: 0.001-174 mD). Based on the 29/7-7 core analysis, the optimum reservoir quality (30-174 mD) resides in fine-grained sandstones developed at the base of the unit. One notable exception is an eight-foot thick, permeable sand layer at the
Fig. 11. Well 27/9-8 porosity-permeability cross-plot.
uppermost part in well 29/7-7. This sand layer, which was not cored, is unique to well 29/7-7 and has better reservoir properties (from logs response) compared with the rest of the Upper Fulmar Formation.
Middle Fulmar Formation
The Middle Fulmar Formation corresponds to the upper part of the Curlew Member. This unit comprises a series of stacked, metre-scale cross-stratified sand bodies of barrier bar setting (Fig. 8). These sandstones are moderate to well sorted, fine to coarse-grained and are interpreted as having been deposited in a predominantly sandy
520
CURLEW FIELD
29/7-10y on; 29/7-9on; 11/1997 1/1998
Curlew B at Curlew D at bubble point; dew point; 2/1999 5/1999
29/7-8z on; 7/1998
29/7-10yquit; 10/1999
29/7-11on' 3t2000
C u r l e w G a s Rates
140
...........................................................................................................................................................................................................................
'~
I
t
120 "~' ........................................................................................................................................................................................................................... ........... 1. . . . . , ."P'-- Note: gas plateau r-~r ]1~ir ~ i~t I c~ i ine:d by facilities loo - 9 ....... ! ....................................... i
_•
=
60 .
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
J
20
0
Nov-97
Mar-9~
Jun-98
Sep-98
Dec-98
Apr-99
Jul-99
Date
~ G a s ExportRate
:...................................................................................
Fig. 12. Historical production in Curlew Field.
i
Oct-99
Jan-00
May-00
G. ENEYOK ET AL. shoreface environment with tidal channel influence. An alternative interpretation for this sandstone unit is an incised valley-fill, cutting across Curlew D and C. Overall, the Middle Fulmar Formation is in general a good quality reservoir. Petrographic analysis indicates a well connected primary intergranular pore network. Porosity ranges from 10% to 27% and average core permeability is 3000 m D (range: 0.1-8000 mD).
Lower Fulmar Formation The Lower Fulmar Formation corresponds to the basal part of the Curlew Member and represents deposition of a more heterogeneous facies. It comprises an assemblage of sandstones, siltstones, mudstones and coals, which represents a wide range of depositional environments from coastal plain swamps to various shoreface settings (Fig. 8). The Lower Fulmar Formation reservoir is thought to be deposited along an embayed coastal plain, which may have been restricted from the open sea by a coastal barrier system. The sandstones are very fine to medium-grained showing a moderate level of sorting and ranging in thickness from < 10 ft thick up to 30 ft thick. Sand bodies are mainly distributary channel fills and adjacent bay-margin shoreface deposits, similar to the Middle Fulmar Formation. However, bioturbated lower shoreface deposits similar to the Upper Fulmar Formation and thin crevasse splays of overbank deposits are common. Coaly rootlets can generally be found in these thin splays and siltstones in addition to the interbedded coal horizons. The presence of shell beds typifies the majority of the mudstones and add to the heterogeneous nature of the Lower Fulmar Formation. Reservoir quality is generally poor compared with the Middle Fulmar Formation. Porosity ranges from 5% to 25% and average permeability in this unit is 250 mD (range 0.001-2000 mD).
Charge Hydrocarbons in the area are sourced locally from Kimmeridge Clay Formation and Pentland Formation coals. The Pentland Formation coals appear to favour the preservation of both gas prone and oil prone. The differences in fluid types (Curlew B/C oil and Curlew D gas-condensate) are attributed to significance of contribution from Pentland Formation. From seismic data, the upper 100 ms of Pentland Formation in Curlew D shows an overall high root mean squared (RMS) amplitude content (Fig. 9), suggesting abundance of coals as encountered in well 29/7-7. The lower amplitudes across Curlew B and C possibly indicate a less coaly sequence as observed in wells 29/7-4 and 29/7-5. The seismic facies pattern suggests that Curlew D is likely to receive significant contribution from Pentland Formation coals. On the contrary, the contribution from coal is expected to be less in Curlew B and C.
Volumes and production Hydrocarbon-in-place The current (May 2000) estimates for initially-in-place volumes in Curlew B are some 24 MMSTB of oil and 25 BSCF of solution gas. The initially-in-place volumes in Curlew D are some 340 BSCF of gas and 100 M M S T B of associated condensate. Note that these numbers are at standard conditions. In the Field Development Plan, the in-place volume in Curlew B was 61 MMSTB of oil and 44 BSCF of gas. The current volumes are smaller because the northern fault block turned out to be dry and the southern block has a shallower contact at 10722ft TVDss. The in-place volume in Curlew D was 167MMSTB of oil and 642 BSCF of gas. The lower current Curlew D volumes are based
521
on a shallower contact at 10 644ft TVDss from the R F T data in well 29/7-8 (Fig. 10).
Reserves The recovery factor now estimated for Curlew B is about 26% for the oil and 21% for the gas (recoverable volumes 6.2 M M S T B ofoil and 5.1 BSCF of gas). The recovery factor for Curlew D is some 26% for the condensate and 32% for the gas (26 M M S T B of condensate and 109 BSCF of gas). The recovery factor predicted for Curlew B in the Field Development Plan (FDP) was 26%, assuming good aquifer support. Despite the lack of this and the compartmentalization of the reservoir, this recovery factor has been largely achieved. The recovery factor for Curlew D was estimated to be some 33% for the condensate and 36% for the gas, higher than the current estimates. There are a number of reasons for this reduction. Firstly, part of the volume is located behind faults that are currently interpreted as being sealing. Secondly, the Lower Fulmar Formation is currently seen as separated from the Middle Fulmar Formation, significantly reducing the recovery from this layer. Thirdly, a higher proportion of the in-place volume is in the Upper Fulmar Formation that has a lower recovery efficiency. Finally, due to condensate drop-out in the reservoir because of pressure depletion, the reduction in the recovery factor for the condensate is more pronounced than for the gas.
Production performance Up to May 2000, 6 . 2 M M S T B and 5.1 BSCF had been produced from Curlew B even though the reservoir stopped producing in March 2000 due to lack of reservoir pressure. Total production from Curlew D on the other hand has been some 20 M M S T B of condensate and 76 BSCF of gas. The Curlew B well 29/7-10y is a horizontal producer with a length of some 3500 ft and has achieved high historical rates: shortly after start-up this well produced some 2 3 0 0 0 B O P D (Fig. 11). However, within the first month of production a marked decline in rate was observed. Based on information from both the permanent downhole and the tubing head gauges, it was identified that the cause of the problems was not related to the well but to the decline in reservoir pressure, signifying a reduced in-place volume. In October 1999, the well started to show sluggish behaviour and after a trip did not come back on production. However, after diverting sufficient Curlew D gas the well came back on production and continued to produce until March 2000. No remedial action is currently planned since the reservoir pressure has dropped to a level where it equals the pressure drop of the hydrocarbon column in a static state. No significant water has been produced. The Curlew D started production in July 1998 (Fig. 12). The producers (29/7-8z and 29/7-9) are vertical wells with a very high inflow performance. After completion of 29/7-8z it became obvious that this well was not as prolific as 29/7-9. A production log (PLT) acquired in 1999 indicated near wellbore impairment, the well (29/7-8z) was subsequently reperforated to restore productivity. This operation was successful and both wells are now producing under almost identical conditions. Since completion, both wells are facilities constrained. The total FPSO production is limited to some 115 M M S C F / D . Individual wells can produce some 60 M M S C F / D , although in exceptional circumstances this can increase to 90 M M S C F / D , which was achieved by well 29/7-9. Originally both wells were producing at a C G R of 300 B/MSCF, but since mid-1999 this has steadily decreased to 200 B/MSCF. We would like to thank Shell UK (Exploration and Production) and Esso UK (Exploration and Production) for their permission to publish this paper. This paper has been based extensively on the work of a large number of Shell and Esso employees who have been involved in the detailed evaluation of Block 29/7 since 1968. The authors wish to acknowledge their efforts and contributions.
522
CURLEW FIELD
The Curlew Field data summary
Trap Type Depth to Crest Lowest closing contour Gas-water contact Oil-water contact Gas column Oil column Pay zone Formation Age Gross thickness Net/gross Porosity Permeability HC saturation Productivity index
Curlew B
Curlew D
Curlew D South
(ft TVDss) (ft TVDss) (ft TVDss) (ft TVDss) (ft) (ft)
Fault/dip 10550 10900 N/A 10722 N/A 172
Fault/dip 10 087 10 790 10 644 N/A 555 N/A
Fault/dip 10 300 11 000 N/A 10 890 N/A 590
(ft) (%) (%) (mD) (%) (BOPD/psi)
Upper Fulmar Upper Jurassic 530 87 (85-95) 21 (10-24) 20 (0.001-250) 54 (39 59) 20
Fulmar Upper Jurassic 568 82 (43-96) 17 (5-27) 450 (0.001-8000) 72 (50-96) 50
Fulmar Upper Jurassic 856 67 (40-90) 17 (5-26) 450 (0.001-3500) 51 (50-95) 58
44 Gas-condensate 0.86 0.1 N/A 4980 N/A 297 N/A 203
40 Volatile oil 0.86 0.2 (initial) 4255 N/A 2200 N/A 1.9 N/A
Hydrocarbons Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Initial condensate yield Formation volume factor Gas expansion factor
(cPoise) (psia) (psia) (SCF/BBL) (BBL/MMSCF) (rb/STB) (SCF/rcf)
39 Black oil 0.82 0.4 3130 N/A 1078 N/A 1.5 N/A
Formation water Salinity Resistivity
MaC1 eq. PPM Ohm in
200 000 0.014
200 000 0.014
200 000 0.014
(km 2) (acre It) (psi) (psi/ft) (~ (MMSTB) (BSCF) (%)
2.60 54438 7 298 0.30 250 24 25 25 Natural depletion 6 4 1
3.87 489 011 7319 0.22 250 100 340 32 Natural depletion 26 74 16
1.57 99 076 7285 0.24 252 8 17 25 Natural depletion 2 4.4 0
Nov. 1997 23 000 25 000 1 horizontal oil producer
Feb. 1998 34 000 115 000 2 vertical gas producers
March 2000 20 000 40 000 1 vertical oil producer
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially-in-place Gas initially-in-place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate Production Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
(~
(MMSTB) (BSCF) (MMSTB)
(BOPD) (MSCF/D)
References EGGINK, J. W., RIEGSTRA, D. E. & SUZANNE,P. 1996. Using 3D seismic to understand the structural evolution of the UK Central North Sea. Petroleum Geoscience, 2, 83-96. ERRATT, D. 1993. Relationships between basement faulting, salt withdrawal and Late Jurassic rifting, UK Central North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe; Proceedings of the 4th Conference. Geological Society, London, 1211-1219. HAMILTON, D. S. 1995. Approaches to identifying reservoir heterogeneity in barrier/strandplain reservoirs: an example from the prolific oil-
producing Jackson-Yegua trend, South Texas. Marine and Petroleum Geology, 12(3), 273-289. JONES, a . et al. (in press). Barbican Conference 1997; Geological Society of London. KMPE, R. J. 1997. Juxtaposition and seal diagrams to help analyse fault seals in hydrocarbon reservoirs. American Association of Petroleum Geologists, Bulletin, 81(2), 187-195. REINSON, a . E. 1992. Transgressive Barrier Island and Estuarine Systems. Geological Association of Canada, 179-194.
The Erskine Field, Block 23/26, UK North Sea R. N . C O W A R D
Texaco North Sea UK, Langlands House, Huntly Street, Aberdeen ABIO 1SH, UK
Abstract: The Erskine Field is a high temperature, high pressure (HTHP), gas condensate accumulation located on the western margin of the East Central Graben. The field was discovered in 1981 by the 23/26a-3RE well and subsequently delineated by six appraisal wells. Development approval was granted in 1995 and to date five development wells have been drilled. In December 1997, Erskine Field became the first HTHP field in the UKCS to achieve production. Hydrocarbons are produced from three separate Jurassic reservoirs. In order of decreasing importance, these are: the Late Oxfordian Erskine Sandstone (Puffin Formation), the Middle Jurassic Pentland Reservoir, and the Late Oxfordian Heather Turbidite Reservoir. The Erskine Sandstone is very fine to fine-grained highly bioturbated, shaley sandstone. The sandstones represent shallow marine progradational sequences, deposited predominantly in the offshore transition zone. Within the majority of the Erskine Sandstone, porosity is high (20-25%) but with relatively poor associated permeability (0.1-10roD). However, the tops of the coarsening upward sequences (E30 and E70 zones) have appreciably better permeability and are thought to be the major conduits for fluid flow. The E30 and E70 zones would not have been identified, had it not been for the extensive coring programme undertaken in the development wells. The Pentland Reservoir is a regionally extensive sequence of interbedded sandstone, shales, coals and siltstones, deposited in a fluvial-lacustrine environment in a delta plain setting. Permeability in the Pentland reservoir (0.1 mD-I D) is in general far superior to the values observed in the Erskine Sandstone. The main control on the observed variability in porosity and permeability characteristics is grain size, that in turn is controlled by facies. The Heather Turbidite Reservoir occurs within two thin predominantly fine-grained turbidite sandstone beds in the Heather Shale Formation. This reservoir is restricted to the Alpha Terrace region in the SW of the field, and is drained by a single development well. Total Erskine Field reserves are estimated at approx 400 BCF of gas and 66 MMBBL of condensate.
Location The Erskine Field is a high temperature (340~ high pressure (14 000 psia), gas condensate rich field, located 150 miles E of Aberdeen, in 300ft of water. Chevron Texaco operates the field on behalf of joint venture partners, BP. Regionally the field is located on the western flank of the East Central Graben, at the southern toe of the Forties-Montrose High in Block 23/26. (Fig. 1). Hydrocarbons are produced from three separate reservoirs of Jurassic age. In order of decreasing importance, these are: the Erskine Sandstone Reservoir (Puffin Formation), the Pentland Formation Reservoir, and the Heather Turbidite Reservoir. Neighbouring high temperature, high pressure (HTHP) fields which are in the process of development are the T F E operated Elgin and Franklin Fields and the Shell operated Shearwater Field. The Machar Field, which produces from overlying Chalk and Paleocene sandstone on the flank of the Machar salt dome, is located immediately to the NE. Erskine and Machar field boundaries partially overlap and are separated vertically at - 1 2 0 0 0 f t sub-sea.
History The field was discovered in 1981 by the 23/26a-3RE well and subsequently delineated by six appraisal wells, namely 23/26b-4, 23/26b-8, 23/26a-7, 23/26b-14, 23/26b-15 and 23/26a-19Y, drilled between 1984 and 1993 (Fig. 2). The protracted appraisal period reflected the high well cost and technical and commercial risk associated with such extreme reservoir conditions. In 1995, the government granted development approval. The jacket was installed above the 23/26b-14 appraisal well in March 1996. The first three development wells, 23/26b-W1, 23/26b-W2 and 23/26b-W3, were drilled through the jacket by Santa Fe's Monitor heavy duty jack-up rig. Wells 23/26b-W1 and 23/26b-W2 targeted the Pentland Reservoir and were positioned relatively down-dip on the Pentland Structure, such that they penetrated a thick section of overlying Erskine Sandstone. This strategy was adopted to allow the future workover of the wells to overlying Erskine Reservoir production, when the Pentland Reservoir waters out. Well 23/26b-W3 targeted the Erskine Sandstone to the south of the field, and drilling stopped in the Erskine Shale prior to penetrating the Pentland Coal.
In April 1997, following completion of drilling operations on wells 23/26b-W1 to 23/26b-W3, the deck and topsides were installed on the jacket. The pipeline between the Erskine Field and Lomond was pressurized in November 1997, and by December, first gas was exported, making the Erskine Field the first H T H P producing field in the U K North Sea. Since then two additional wells, 23/26b-W4 and 23/26b-W5, have been drilled in combined operations mode (i.e. with simultaneous producing and drilling operations). Well 23/26bW4 was drilled as a twin to 23/26b-15, and targeted the Heather Turbidite Sandstone in the Alpha Terrace. The fifth well, 23/26b-W5, targeted the Erskine Sandstone in the north of the field. Technical work is currently in progress to evaluate the need for a sixth well. The majority of the development wells drilled during this period were close to prognoses in terms of depth and reservoir thickness. Notable exceptions are the 23/26b-W2 and 23/26b-W5 wells, which had thinner and deeper Erskine Reservoir sections than anticipated. In these wells, depth errors were up to 150 ft for the Top Erskine, with thickness errors up to 80 ft. These observations resulted in the interpretation of an erosive event in the northern crestal region of the field at the Top Erskine level. Drilling of the wells is technically challenging due to the harsh environment and narrow margin between formation and fracture pressures. This demands careful monitoring of the geology, using well-site biostratigraphy and logging-while-drilling (L.W.D) to control casing positions. Prior to the development of the field the only core data available from the Erskine Sandstone was from well 23/26b-15, which is a relatively deep penetration in the Alpha Terrace structure block. No core data was available from wells in the Main Block. This presented a problem because permeability was identified as a key parameter in the estimation of reserves. Consequently, a comprehensive coring programme was undertaken in the Main Block development wells. This data proved invaluable for three reasons. Firstly, it showed that the majority of the Erskine Sandstone had a lower permeability than anticipated in this region. Secondly, it allowed for the recognition of two relatively high permeability and porosity zones (E30 and E70) resulting in a revision to the zonation scheme. Thirdly, it led to a change in the intended perforation policy, because rock mechanical tests on the core from the E30 and E70 zones indicated that the latter carried a risk of sanding at relatively low levels of pore pressure depletion. Consequently, the E70 zone has not been perforated in the development wells.
GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 523-536.
523
524
R. N. COWARD
to24'E 57o24'N
2o00'E
2~ 57~
57~
57 ~O0'N
56"48'N
56 ~ 1~
2~
2~
Fig. 1. Location map of the Erskine Field.
The hydrocarbons produced from the Erskine Field are exported from the normally unattended installation, via a single, multiphase pipeline, approximately 30kin to the Lomond platform. Processed liquids are dispatched via BP's Forties pipeline to Cruden Bay and the gas travels through the Central Area Transmission System (CATS) to Teeside.
Structure
The Erskine Field seismic database comprises a 3D dataset of some 12 500 line km, shot in 1989, with a spacing of 12.5 metres. The survey was reprocessed in 1992 using a proprietary post stack depth migration algorithm. Reprocessing substantially improved the imaging near the Machar salt diapir (northeastern margin of the field). However, lateral velocity anomalies, caused by wedging of the Cromer Knoll and Heather Formations across the crest of Erskine Field
have hindered seismic depth conversion, giving rise to poor prediction in development wells 23/26b-W2 and 23/26b-W5 at the Top Erskine level. The following seismic events have been mapped: Top Balder, Top and Base Chalk, Base Black Limestone Marker, Base Cretaceous, Top Erskine, and Top Pentland. The Black Limestone is a clean limestone bed occurring towards the Base of the Chalk Group, which is easily recognizable on L.W.D logs and seismic data. This horizon is mapped and identified real-time during drilling operations because it marks the onset of the pressure transition zone. This is the point at which pore pressures begin to rise rapidly, and consequently is an important casing point. All mapped events are generally of good quality in both character and continuity throughout the mapped area. However, over the crest of the structure, the Top Erskine event deteriorates as it approaches the Base Cretaceous Unconformity. The structure at the Top Pentland level is illustrated in Figure 2, along with the position of the lines of geoseismic strike and dip-sections (Fig. 3).
ERSKINE FIELD
525
6,324,000
6,321,000
57~
Fig. 2. Time structure map for the top of the Pentland Reservoir.
Three structural blocks are recognized within the field: the Main Block, the Beta Terrace, and the Alpha Terrace. All three are components of large scale block rotation associated with Late Cimmerian extensional tectonism. The Main Block captures the majority of the hydrocarbons associated with the Pentland and Erskine Reservoirs. The structure is a westerly-dipping, scallop-shaped, tilted fault block, cresting at approximately 15 000 ft sub-sea (3800 ms TWTT). The up-dip (eastern) edge of the Main Block has undergone progressive footwall erosion by the Base Cretaceous Unconformity. The erosion is most pronounced in the northeastern corner of the block, resulting in complete removal of the Erskine Sandstone in the crestal region of this quadrant. An earlier, less severe, intra-Heather erosive event is interpreted in wells 23/26b-W2 and 23/26b-W5. This event has the effect of removing several of the upper reservoir zones prior to the onset of the later Base Cretaceous erosion. The Beta Terrace is a series of small fault blocks downthrown to the east of the Main Block. This terrace is heavily faulted, with at
least three compartments recognized from the seismic data. No Top Erskine seismic event is mappable in this area, and the Erskine Sandstone is assumed to subcrop the Base Cretaceous. Taking into account the compartmentalization and the chance of fluid flow between the Beta Terrace fault blocks and the Main Block, risked reserves associated with the Beta Terrace are low. The Alpha Terrace structure block lies to the SW of the field. This terrace, which is downthrown to the Main Block, contains a relatively thick sequence of Heather Formation Shale encapsulating thin turbidite sandstone beds. Well 23/26a-15 was used to appraise this block, and found that the Heather Turbidite sandstones were gas charged, whilst the Erskine and Pentland Reservoir sections were wet.
Stratigraphy The Erskine Field litho- and chronostratigraphy is illustrated in Figure 4. The oldest rocks penetrated in the Erskine area were drilled
526
R. N. COWARD
Fig. 3. Lines of geoseismic dip and strike cross-section. by well 23/26a-7, which drilled 80 ft into the Triassic section. Lithologically the Triassic consists of an interbedded sequence of sandstones, siltstones and brick red mudstones assigned to the Skagerrak Formation. Unconformably overlying the Triassic rocks are Middle Jurrasic deposits of the Pentland Formation (Fladen Group). The Pentland Formation comprises a heterolithic sequence of sandstones, siltstones, mudstones and coals deposited in a fluvial to
lacustrine environment. The sequence is approximately 1800ft thick over the field area and yields long ranging taxa, making the rocks difficult to date. The majority of the formation is probably Bathonian or older. However, the upper units may be as young as Early Oxfordian (Geostrat 1997). Marine palynomorphs have been found in the upper part of the Pentland Formation, indicating that it was probably deposited in a marginal marine setting.
ERSKINE FIELD
DEPTH -8000
LITHOSTRAT
GR
DT
527
CHRONOSTRAT
L I T H O S T R A T AND RESERVOIR ZONATION
- fVX/N/',/
GR
0
l
/
Balder Fm. Forties Fm.
EARLY KIMM,
.~
,
Hordatand Group
CHRONO -STRAT.
150
PALAEOCENE
[Heather
Sst,
B
# ii
4--0 ~3
(D C3
Andrew Fm, Maureen Fm.
C9
Ekofisk
_0
O
Fm.
~
{ R o s e n k r a n t z ) M.F.S ,
(Serratum)
I
Tor
Fm,
M,F.S
Erskine
S i l t s t o n e , '1~"
~
LuW
,q
)
a)
~03
G
-
c~m
~_
L
-
r
~
~_
v
LATE CRETACEOUS
Lower Erskine Sst,
Erskine
Mackerel Fm. (Hod)
Black
LU
r
Shale
GIosense
/
M.F.S LE - M DDLE OXFOFtDIAN
Coal
Marker
ol P6OO
Lst, Mkr,
I
is
:1-I
P60B
Z
P60A II
Herring Fm.
~ETACEOUSl C
Cromer
P4O
JURASSIC
:~=
P30 P20
KnolIGp.
!
PIO
# i
~C3 C0cC
rrLL Dx -~0 LU _j>O-J orr
~<
LU
Fig. 4. Chrono- and Lithostratigraphy of the Erskine Field. The overlying, highly bioturbated, silty mudstones, of the Erskine Shale were deposited in an open marine environment and are Early-Late Oxfordian in age. Therefore, it has been suggested that the Erskine Shale and the upper part of the Pentland Formation are conformable, and were deposited during the gradual transgression of the eastern portion of the Central Graben starting in the earliest Oxfordian (SPT). The Erskine Shale may be time equivalent to the Franklin Sandstone in the Franklin Field to the west. The Erskine Shale has a uniform thickness across the field of approximately 100ft, and passes gradationally into the overlying Puffin Formation. The Late Oxfordian Puffin Formation is locally known as the Erskine Sandstone and is between 200 and 300 ft thick. This unit
consists of a very fine to fine-grained muddy sandstone, deposited in an offshore transition zone setting. The Erskine Sandstone typically passes gradationally into the overlying Heather Formation. However, there is evidence from well control for erosion at the crest of the fault block in development wells 23/26b-W2 and 23/26b-W5, which removed the uppermost parts of the Erskine Sandstone prior to the resumption of Heather Shale deposition. The Heather Shale above the Erskine Sandstone is of Late Oxfordian age, and its thickness is controlled largely by the degree of erosion by the Base Cretaceous Unconformity. The age of the Heather Formation immediately above the Erskine Sandstone has been confirmed by ammonites recovered from the core in the 23/26b-Wl well.
528
Fig. 5. Erskine Field correlation and reservoir zonation.
R.N.
COWARD
ERSKINE FIELD No Kimmeridge Clay Formation or Kimmeridgian age rocks have been penetrated in the Main Block of the field. The only wells with rocks of this age are the 23/26b- 15 and 23/26b-W4 twin pair in the Alpha Terrace, and wells 23/26a-19Y and 23/26a-2STRE to the NE of the accumulation. In wells 23/26b-15 and 23/26b-W4 all but a thin (10 ft thick) interval of Kimmeridge Clay has been removed by erosion. In wells 23/26a-2STRE and 23/26a-19Y several hundred feet of Kimmeridge Clay Formation is present. This ranges in age from Late Ryazanian to Kimmeridgian in the 23/26a-19Y well and from Early Volgian to Kimmeridgian in the 23/26a-2STRE well (Geostrat 1997), and is preserved on the downthrown side of a major graben-bounding fault. The top of the Jurassic sequence is marked by the Base Cretaceous Unconformity. Unconformably overlying the Heather Formation are the limestones and marls of the Lower Cretaceous Cromer Knoll Group. These range in age from Albian to the Barremian in the Main Block, and are often highly condensed and incomplete, with unconformities at the top, base and also within. The beds generally display an onlapping relationship to the Base Cretaceous Unconformity, and are absent in the southern part of the Main Block in the wells 23/26b-8 and 23/26b-4. The Cromer Knoll Group sections in 23/26a-2STRE and 23/26a-19Y are extensive, ranging from Late Albian to Ryazanian, and Late Albian to Hauterivian, respectively.
Trap In the Main Block the structural trap at the Pentland and Erskine Sandstone levels is a westerly dipping, tilted fault block. Several small faults cut this block. The most significant is a N-S trending fault immediately to the west of 23/26b-14, which downthrows to the west by up-to 100ft and produces a long thin narrow horst along the crestal portion of the fault block. The throw on the fault is almost sufficient to offset the Erskine Shale and juxtapose Erskine Sandstone against Pentland Formation Sandstone. It is of note that the Pentland hydrocarbon accumulation is largely restricted to the upthrown side of the fault (cf. Figs 2 & 3). This implies that at some stage during the charge of the Erskine Reservoir the Erskine Shale failed along the fault, allowing hydrocarbons to spill from the Pentland to the Erskine. This process resulted in the establishment of a fluid contact at 15 629 ft sub-sea in the Pentland Reservoir. The Erskine fluid contact is 198 ft shallower at 15 431 ft sub-sea. Despite the likely seal failure of the Erskine Shale in the past, it is apparent from the observed differences in fluid composition between the Erskine and Pentland reservoirs, and also from the RFT data, that the Erskine Shale currently acts as an effective pressure barrier. The shales of the Heather Formation cap the reservoir over the majority of the accumulation. However, over the crest of the field the Lower Cretaceous marls and claystones of the Cromer Knoll Group provide the top seal. The trapping mechanism at the Heather level is ambiguous due to the uncertainty in the distribution of these sandbodies, but a large stratigraphic component is assumed. No fluid contact has been penetrated in the Heather Turbidites.
Reservoirs
Erskine Reservoir (Puffin Formation) Sedimentology and reservoir zonation. The principal reservoir in terms of reserves in the Erskine Field is the Erskine Sandstone (Puffin Formation). The Erskine Sandstone is between 200 and 300 ft thick over the field and consists of a monotonous sequence of highly bioturbated shaley sandstone. The sandstones are interpreted to represent shallow marine progradational sequences deposited predominantly in the offshore transition zone, beneath fairweather wave base. Two subtle coarsening (from very fine to fine-grained) and cleaning upward cycles divide the Erskine Sandstone into lower and upper divisions. This trend is more readily
529
discernible in wells to the north of the field. Within the coarseningupwards cycles an upward change in bioturbation fabric from Phycosyphon-dominated to Ophiomorpha-rich can sometimes be recognized. Diplocraterion habiehii burrows are concentrated at the tops of some of the cycles and may represent a decrease in sedimentation rate (Lomond Associates 1997). Using these cycles as a framework for correlation in combination with relatively discontinuous cemented zones, and small variations in rock quality, the Erskine Sandstone has been divided into seven reservoir zones for modelling purposes (E10-E70; cf. Fig. 5).
Petrography. The detrital mineralogy of the Erskine Sandstone is dominated by monocrystalline quartz (45-56%), clay (16-32%), polycrystalline quartz (4-6%), metamorphic lithic grains (4-6%) and plagioclase (2-4%). Potassium feldspars are absent from the reservoir due to dissolution. The detrital clay is dominated by illite and typically occurs as grain coatings, distinct clay-rich seams and locally filling primary pores. Amorphous hydrocarbon is usually trapped in association with the clays. Muscovite and biotite are moderately abundant (1-4%), with both minerals typically showing compactional deformation. The sandstones usually classify as lithic greywacke. The most abundant cements are dolomite (1-42%), illite (0.57%) and authigenic quartz (trace 2.5%) with minor amounts of pyrite (trace 3%) and calcite (trace 0.5%). The dolomite cement is usually patchily distributed in thin section, often grain replacive, and is zoned, being more iron rich at its margins. However, from the core data it is apparent that the dolomite can be concentrated into doggers, which locally significantly degrade porosity within the Erskine Sandstone. These dogger beds are up to 10ft thick and are illustrated on Figure 5. It is clear that these cemented zones can occur at the same stratigraphical level in wells up to three kilometres apart. However, instances are also observed where log data clearly indicate a cemented zone that has not been identified in the core over the same interval. It is likely therefore that whilst the doggers occupy distinct stratigraphical intervals, they are patchily distributed. Authigenic illite is present in the Erskine Sandstone and has a fibrous to hairy morphology. Much of this appears to have formed from the recrystallization of detrital clay (which makes it difficult to distinguish in thin section). Quartz overgrowths are generally common in the Erskine Sandstone but show a decreasing abundance in the more shaley samples due to the inhibiting effect of clay grain coatings.
Reservoir quality. Grain size and volume of clay largely control rock quality in the Erskine Sandstone. This is illustrated by Figure 6a, which shows porosity and permeability depth profiles for well 23/26b-W1. It is apparent from this plot that permeability increases through the depositional cycles with increasing grain size and decreasing clay volume. Secondary porosity due to potassium feldspar dissolution is common throughout the Erskine Sandstone Reservoir and is approximately one fifth of the total pore volume. Microporosity, which is the difference between the visible porosity and the measured plug values, is the dominant porosity type, usually exceeding 50% of the total. The majority of the Erskine Sandstone has a porosity in the range of 20-25%. Permeability is typically low but variable, ranging from 0.1-10mD (Fig. 6b). This is due to the very fine-grained and clay-rich nature of the sandstones. The E30 and E70 zones have anomolously high porosities and permeabilities reflecting disproportionately coarser grain sizes (fine) and lower abundance of clay. The E70 reservoir zone has an average porosity of 30% and permeabilities up to 100mD (average 33 mD). The extremely high porosity of the E70 zone gave rise to concerns to its stability as the reservoir depletes. Rock mechanics tests on cores from the E70 zone indicate that the weaker nature of these sandstones may result in sand grain production following relatively low reduction in pore pressure. As a result the E70 reservoir zone has not been perforated. The reservoir quality of the E70 zone decreases to the north as
530
R. N. C O W A R D
ii l l l m
O O n_
o
ERSKINE FIELD
531
0
. ,...~ o
i-z
532
R. N. C O W A R D
:L
, ,,,,~ O
ERSKINE FIELD the unit becomes thinner and finer-grained. The E30 zone has an average porosity of 24% with permeability ranging from 1-200 mD (average 36 mD). The reservoir quality of the E30 zone increases to the north (Fig. 5). In terms of fluid flow in the reservoir, it is likely that the relatively permeable E30 and E70 reservoir zones will be the major conduits for fluid flow in the reservoir with the surrounding lower permeability layers feeding them. The intervals containing carbonate dogger cements will act as vertical permeability baffles. This is supported in part by recent PLT logging of well 23/26b-W5, which indicated that all flow is currently from the E30 reservoir zone (E70 not perforated). For reservoir modelling purposes simple linear regression equations derived from the core data are used to predict permeability in uncored intervals. Away from the points of well control, permeability and porosity are modelled as declining with depth. No field-wide porosity or permeability cut-off's are applied in the Erskine Sandstone for the construction of net/gross ratio maps. The only elements of the reservoir considered to be non-net are the carbonate-cemented horizons.
Pentland Reservoir Sedimentology and reservoir zonation. The Pentland Formation is a regionally extensive sequence of interbedded sandstone, shales, coals and siltstones deposited in a fluvial-lacustrine environment in a delta plain setting. Within the Pentland Formation there are laterally continuous lacustrine mudstone deposits (P30 and P50 zones), which can be correlated across the field, and may extend as far west as the Shearwater accumulation. These field-wide barriers to fluid flow have been used in combination with some thinner mudstone beds to divide the Pentland Reservoir into six major intervals for modelling purposes (P10 through P60). These reservoir zones are capped by a 30 ft interval dominated by coal beds visible seismically as an important regional marker (cf. Fig. 5). Using the available core data and extrapolating the log characteristics into uncored intervals, the Pentland Sandstone beds have been classified according to facies. This classification is illustrated in Figure 7. Layer P60c is dominated by discrete, continuous, stacked channel sandbodies against a background of shale. In comparison, reservoir unit P60b has a relatively small shale fraction, a larger component of crevasse deposits, and more poorly correlated channel sandstones. The P60a zone consists of mouthbar deposits with incised stacked channels. Mouthbar sandstones with thin interbedded shale beds dominate the P40 layer. The P40 and P60a intervals represent the infilling of lakes by mouthbars, into which lacustrine, non-bioturbated, anoxic laminated mud (P30 and P50) had previously been deposited. Petrography. Petrographically, the detrital mineralogy of the Pentland Sandstone is very similar to the overlying Erskine Reservoir. However, there are notable differences, in particular detrital clay is less abundant and the sandstones classify as quartz arenites. Furthermore, kaolinite is the dominant clay type with sub-ordinate illite. Also less plagioclase (trace 1.5%) is present in the Pentland Sandstone than the Erskine (2-4%). The relative enrichment of the Erskine Sandstone in plagioclase may indicate that the Upper Jurassic sandstones cannot be entirely sourced by reworking of the Pentland Formation. The variety of cements in the Pentland are the same as the Erskine Reservoir, however, quartz overgrowths are more common (trace 7%), due to the smaller proportion of grain coating clays which inhibit quartz precipitation.o Reservoir quality. Permeability in the Pentland Reservoir is in general far superior to the values observed in the Erskine Sandstone. The main control on the observed variability in porosity and permeability characteristics is grain size, that in turn is controlled
533
by facies. Figure 8 illustrates that in well 23/26b-14 the medium to coarse-grained channel and mouthbar facies display higher porosities and permeabilities than the finer-grained crevasse splays. The range in quality of the different facies is illustrated in Figure 8. Within the mouthbar and channel deposits, porosity is in the 15-25% range and permeability is 1 0 m D - 1 D . In the crevasse splays, permeability is approximately 0.1-10mD with porosity in the 5-15% range. In view of the high sand/shale ratio and continuity of the sandstone beds in the P40 and P60 zones (see Fig. 7), we anticipate that sandstone beds within these zones will be well connected. The lateral continuity of the P60 flow unit is supported by pressure data from development wells 23/26b-W1 and 23/26b-W2, which are at opposite ends of the field. When well 23/26b-W1 was initially completed in this zone it showed depletion by virtue of existing production from well 23/26b-W2. Furthermore, the pressure decline characteristics of wells 23/26b-W1 and 23/26b-W2 exhibit interference effects. In contrast, the P10 and P20 zones have a lower net/gross ratio and channel sandstones cannot be correlated confidently. Consequently, connectivity within these zones is expected to be relatively poor. No production characteristics are available in the lower zones, P 10 and P20, as these intervals are not currently perforated. However, the poor sand connectivity in these layers is supported by small pressure differentials observed in RFT measurements. In view of its heterogeneity, simple slab modelling of porosity and permeability is not appropriate for the Pentland Reservoir. Maps of porosity and permeability distribution have been generated successfully using sedimentary process modelling. This forwardmodelling technique attempts to simulate the depositional process and recreate a likely three dimensional geometry for the reservoir sands by varying input parameters such as precipitation, drainage basin size, and sea level variations. These maps are slowly being superseded by object based models, which can be more closely matched to the well data.
Heather Turbidite Reservoir The third reservoir in the Erskine Field occurs within thin turbidite sandstone beds in the Heather Shale Formation. Their presence over the Alpha Terrace was proved by appraisal well 23/26b-15, which penetrated two 30 ft sands (Figs 3b & 5), the lower of which was cored. It was found to be fine-grained stuctureless sandstone with permeability averaging 80mD and porosity 20%. The presence of thin seams of coarse grains in the sandstone is interpreted to represent amalgamation of several flows rather than single events. The distribution of this reservoir sandstone away from the well 23/26b-15 is unknown due to the lack of a definitive seismic response from the beds. However, in view of their depositional environment they probably form laterally restricted lobate to sheet or possibly ribbon-like sandbodies. Production data from this reservoir strongly supports the limited extent of these beds. Compositional and pressure data indicate that the two sandstone beds forming the Heather Turbidite Reservoir are not connected to each other or to the Erskine or Pentland Reservoirs
Source In general, the geochemical data for the Erskine Field condensates shows a mixture of fluids from two sources (Dodd 1993): a typical algal marine source, which corresponds to source rocks within the Upper Jurassic, and a lacustrine source, generating fluids with a high wax content typed to mudrocks in the Middle Jurassic. There is a systematic variation in the relative contribution from these two different sources in the Erskine Field Reservoirs. The data indicates that the Heather Turbidites are sourced largely from the Upper Jurassic source rocks. The Erskine and Pentland Reservoirs comprise a mixture of both sources, but with a larger component of the lacustrine source in the Pentland Reservoir.
140.0
50000
...........................................................................................................................................................................................................................
Gas 120.0
40O00 100.0 ~r
i
80.0 60.0
r
40.0
20.0
i 01/12/97
01/03/98
30000 Om
20000 "~r
3 10000
J 01/06/98
01/09/98
01/12/98
01/03199
Time
Fig. 9. Erskine Field production profile.
The Erskine Field data summary units Erskine
Pentland
Heather Turbidite
Tilted Fault Block -15000 -15500 -15431 300
Tilted Fault Block -15000 -15900 -15629 250
Stratigraphic ? ?
Puffin (Erskine Sandstone) Upper Jurassic 190 250 >95 23 (I 5-35) 10 (0.01 210) 83 (96 60)
Pentland Middle Jurassic 1800 60 16(8-30) 160(0.04 1600) 78(96 64)
Heather Upper Jurassic 60 83 20 (15-22) 93 (95-75)
mD %
30.5 0.085 6033 187 318
31.5 0.085 5830 208 306
31.3 0.085 5550 250 285
lb/ft 3 cp psig BBL/MMSCF SCF/rcf
180 000 0.016
180000 0.016
180000 0.016
NaCI eq ppm ohm m
Gross rock volume Initial pressure
222 700 13 938
229 200 13937
37000 13965-14025
acre fl psi
Pressure gradient Temperature Oil initially-in-place Gas initially-in-place Drive mechanism Recoverable oil
0.22 340 N/A 500 depletion drive Approx 70 MMSTBO from three reservoirs Approx 330 BCF from three reservoirs Approx 9 MMSTB from three reservoirs
0.22 340 N/A 20O dep + aquifer supp
0.22 340 N/A 8O depletion drive
psi/ft ~ MMBBL BCF
Dec 1997 Approx 25 000 BOPD from 3 reservoirs Approx 100 MMSCFPD from 3 reservoirs 2
Dec 1997
notes
Trap
Type Depth to crest Lowest closing contour GOC or GWC Gas column
9
60
Pay zone
Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Petroleum saturation average (range)
80 (50-200)
fl % %
Petroleum
Gas gravity Viscosity Dew point Condensate yield Gas expansion factor Formation water
Salinity Resistivity
approx @340~
Field characteristics
Recoverable gas Recoverable NGL/condensate
MMBBL BCF MMBBL
Production
Strat-up date Production rate plateau oil Production rate plateau gas Number/type of well
Jan 1998 BOPD MMSCF/D
2
1
@datum of - 15 200ss
ERSKINE FIELD
Reserves and production Hydrocarbon reserves totalling 330 BCF of gas and 70 MMBBL of condensate are trapped within three separate Jurassic reservoirs. In order of decreasing importance, these are the Erskine Sandstone Reservoir (Puffin Formation), the Pentland Reservoir, and lastly the Heather Turbidite Reservoir. In terms of well utility, there are two Pentland Reservoir producers, 23/26b-W1 and 23/26b-W2, two Erskine Reservoir producers, wells 23/26b-W3 and 23/26b-W5, and one Heather turbidite producer, well 23/26b-W4. From the field production profile illustrated in Figure 9 it is apparent that wells 23/26b-W 1 to 23/26b-W5 are currently producing a total of approximately 100 MMSCF(D) and 25 000 barrels of condensate per day. The Pentland wells are currently prioritized above the Erskine and Heather Turbidite wells, due to the higher condensate yield and reservoir management strategy. Within the Erskine Reservoir the major uncertainty recognized with regards to reserves prior to development was the lack of permeability data. A comprehensive coring programme undertaken in the development wells, in combination with well tests largely addressed this and is described in the History section of this paper. The gross rock volume is also a key uncertainty in the Erskine Reservoir, the determination of which is complicated by the uncertainty in the picking of Top Erskine in the vicinity of the erosional edge. Within the Pentland Reservoir, the major uncertainty that could impact upon reserves is the degree of aquifer support that this highly permeable reservoir will obtain. Initial observations from the production data suggest that the aquifer is less active than previously anticipated. This may be due to a greater decline in permeability with depth than currently modelled, or alternatively, more poorly connected sandbodies. The importance of sandbody
535
connectivity on reserves was illustrated prior to development, when the Pentland permeability modelling changed from a simple slab model, with straight forward interpolation of points of well control, to a more heterogeneous model based upon sandbody channel geometries (sedimentary process modelling). This variation gave rise to a reduction of reserves in the order of 20%. The lower aquifer support than anticipated may be a positive indication for reserves as it could result in less gas being trapped at high pressure by the ingress of water. The fact that the Heather Turbidites are below seismic resolution makes a confident estimation of gas-in-place using geological mapping difficult. Consequently, the amount of gas-in-place was estimated prior to development using a material balance on the 23/26b-15 well DST. This indicated sufficient reserves to justify a single development well, 23/26b-W4. In view of the geological uncertainty in the sandstone distribution, well 23/26b-W4 was a close twin to the 23/26b-15 well. Production data from the 23/26b-W4 supports the limited extent of the sandstone accumulation, and the reservoir is depleting rapidly, with no aquifer support. The Beta Terrace region to the east of the Main Field area (see Structure section) consists of a series of small fault terraces. This area is not included in the base case development programme, as risked reserves do not warrant a dedicated development well. Great uncertainty exists in this area with regards to the gross rock volume of Erskine Sandstone. In addition, the degree of communication between the individual terraces and the Main Block is open to interpretation. However, any Erskine sandstone preserved on the Beta Terraces will be juxtaposed against the Pentland Reservoir. Consequently, it is envisaged that hydrocarbons trapped within these terraces could be drained from the Pentland wells in the Main Block. I wish to thank my colleagues in the Erskine Team for reviewing the paper and our partners BP Amoco for their permission to publish.
The Fife and Fergus Fields, Block 31/26a, UK North Sea M.
SHEPHERD
1, A .
MACGREGOR
2, K .
B U S H 3 & J. W A K E F I E L D
4
1 Amerada Hess Limited, Scott House, Hareness Road, Aberdeen AB12 3LE, UK (e-mail. Mike.Shepherd@Hess. corn) 2 Present address." BP, Burnside Road, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB, UK 3 Present address." Burlington Resources (Energy Services) Inc., 37th Floor, One Canada Square, Canary Wharf, London E l 4 5AA, UK 4 Present address." Shell UK Ltd, Shell UK Exploration and Production, 1 Alten Farm Road, Nigg, Aberdeen AB12 3FY, UK
Abstract: The Fife Field and its smaller satellite the Fergus Field are the southernmost of the cluster of oil fields within the U K Central North Sea. The Fife Field lies at the intersection of four blocks, 31/26a, 31/27a, 39/la and 39/2a. It is a small to moderate size offshore field with reserves of 48.3 MMSTB and is produced by five sub-sea wells through a Floating, Production, Storage, Offloading (FPSO) vessel. The field was discovered in 1991 and the first oil was produced in 1995. The Fergus Field, located in Block 39/2a, is a satellite located 5 km SE of the Fife Field. It is produced by a single well tied-back by a sub-sea flowline to the Fife Field infrastructure. The Fergus Field was discovered in 1994 and first oil was produced in 1996. Reserves are estimated as 11.3 MMSTB. The main reservoir interval in both fields comprises fine-grained, heavily bioturbated, shallow marine shelf sandstones of Upper Jurassic age. Significant volumes of chert and carbonate cements, both banded and nodular, occlude porosity and impart reservoir layering within an otherwise thick sandy, mud deficient reservoir interval. Sandstone porosity is in the range 19-31%. Permeabilities are low in the Fife Field reservoir sandstones, typically less than 100roD. By contrast, better permeabilities (average 500 mD) are seen in the Fergus Field, where a more proximal shelf sandstone facies is present within the oil leg. Two thin intervals of pebbly, very coarse-grained sandstone are intercalated with the shelf sandstones in the crest of the Fife Field. These may represent submarine toes of fan deltas sourced from an active fault system located to the north of the field. The pebbly sandstones show permeabilities in excess of a Darcy and have caused early water breakthrough problems in production wells. A subsidiary reservoir is present within the Tor Formation of the Chalk Group in the Fife Field, but is not oil bearing within the Fergus Field. This comprises white to grey, intensely bioturbated, stylolitized chalk with an average porosity of 24.5% and an average air permeability of slightly less than a millidarcy. Both the Fife and Fergus Fields are defined by simple four-way dip closure at top Jurassic. An episode of structural inversion at the end of the Jurassic created both structures. The overlying Chalk oil pool in the Fife Field has a trap defined by dip closure on three sides and a probable diagenetic trapping element to the south.
Fig. 1. Location map for the Fife and Fergus oil fields. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 537-547.
537
538
M. SHEPHERD E T AL.
The Fife Field straddles the intersection of four Blocks, 31/26a, 31/27a, 39/la and 39/2a in the Central North Sea, 360 km E of the coast at the nearest landfall at Dunbar, Scotland (Fig. 1). It is located in the Fife Embayment, a minor basin on the western flank of the Central Graben. The field is named after a character in Shakespeare's play Macbeth.
Fig. 2. Fife Field area - stratigraphic column.
History The Fife Field was discovered by well 31/26a-9A in 1991 which targeted a four-way dip closure at base Cretaceous level. A total gross pay of 159 ft was encountered within a 482 ft thick Upper Jurassic sandstone reservoir. The well was tested and flowed 36.4 ~ API oil at
FIFE AND FERGUS FIELDS a rate of 11 540 BOPD. A thin oil leg was also found within the Chalk, which was tested at an unstabilized rate of 50-100 BOPD. Three appraisal wells were drilled in the period 1993-1994. These wells proved an oil pool within the Upper Jurassic, currently estimated to have a STOIIP of 132 M M S T B and ultimate recoverable reserves of 48.3 MMSTB. An additional 23 MMSTB STOIIP of oil is assigned to the Tor Formation of the Chalk Group, but with as yet no attributable reserves. The Fife Field came on-stream in 1995 and is produced through a Floating, Production, Storage, Oflloading (FPSO) vessel, the Uisge Gorm (Gaelic for blue water). Amerada Hess Ltd operates the field with an 85% interest, Premier Oil plc. have the remaining 15%. A small satellite oil pool was discovered 5 km SE of the field in 1994 by well 39/2-2Z and was named Fergus after the character in the Sir Walter Scott novel 'Waverley'. The field came on-stream in 1996 and is produced from a single well tied-back to the Fife template. The STOIIP of the Fergus Field is 16.3 MMSTB with estimated reserves of 11.3 MMSTB. The partner share for the Fergus Field is slightly different from that of the Fife Field, with Amerada Hess Ltd owning 65% and Premier Oil plc. 35%. The Flora Field (Hayward et al. 2003) was discovered in 1997, 9 km N of the Fife Field and is tied back and produced to the Uisge Gorm FPSO vessel.
Stratigraphy The pre-Jurassic stratigraphy comprises (Fig. 2): (1) (2) (3) (4)
Carboniferous fluvial sandstones and mudstones with associated lava flows; Lower to Middle Permian Rotliegendes Group sandstones, lava flows at the base; Upper Permian Zechstein Group evaporites and dolomite; and Triassic red bed mudstones of the Smith Bank Formation.
The earliest proven Jurassic sediments in the area are shallow marine shelf sandstones of Kimmeridgian to Volgian age. A local name of the Fife Sandstone is assigned to these sediments (Mackertich 1996). The sediments have an affinity to the Fulmar Formation in the Central Graben area, although the Fife Sandstone is younger than the Oxfordian to Kimmeridgian age reservoir interval of the Fulmar Field itself (Stockbridge & Gray 1991). Thin Kimmeridge Clay Formation mudstones are preserved on the flanks of the field although absent in the crest due to erosion. In one crestal well on Fife a thin Valanginian to Hauterivian limestone interval is preserved, otherwise Lower Cretaceous sediments are absent in wells over the Fife and Fergus Fields area. The Chalk Group generally overlies the Base Cretaceous Unconformity in Fife and ranges from Middle Turonian to Danian in age. The post Danian Tertiary sediments are mud dominated in the Fife and Fergus area.
Seismic The field has been interpreted using a 3D seismic survey shot in 1991. The data were partly re-processed and post-stack depth migrated in 1997. The data quality is good with an excellent seismic response at top Chalk, base Chalk (Base Cretaceous Unconformity/ top Fife Sandstone) and top Zechstein events (Figs 3 & 4). The top of the Fife Sandstone is well defined by an impedance decrease where it is overlain by the Chalk Group and this gives excellent control on mapping the top reservoir structure. The delineation of intra-reservoir faults is important in understanding fluid flow within the reservoir. These are defined by mapping the base reservoir (top Triassic) event as the faults rarely cut the base Chalk reflector. The base reservoir reflector is defined by the boundary between Jurassic sandstones and the siltstone/mudstone lithologies of the Triassic Smith Bank Formation. This interface has a weak and variable impedance contrast and has poorer seismic resolution as a result.
539
Structure The present day structure is dominated by the effects of late Jurassic faulting, which created the depocentre for sand deposition during the Kimmeridgian to Volgian in the Fife area. North-south trending faults control the long axis of the Fife Embayment, a minor basin with dimensions of 20 x 10 km on the flank of the Central Graben. The northern margin of the basin is controlled by an east-west fault termed the Epsilon Fault (Mackertich 1996). This fault is located just to the north of the Fife Field closure (Fig. 5). Over 400 ft thickness of shelf sands was deposited within the Fife Embayment. Examination of core shows that heavily bioturbated shallow marine sands dominate throughout, suggesting significant growth fault control on accommodation space. Major inversion along the north-south faults took place at latest Jurassic/earliest Cretaceous times and formed the Fife Field structure. The fault steps created by inversion were significantly eroded prior to deposition of Cretaceous sediments. A spectacular example of this is seen on the eastern margin of the Fife Field. A near vertical north-south trending fault shows about 400ft of throw at the base of the Fife Sandstone, but has no expression save minor folding at the Base Cretaceous Unconformity (Fig. 6). The depositional thickness of the Chalk Group is an expression of the positive structure created by earlier inversion, thinning from 700 ft on the flanks to 400 ft on the crest of the field. Within the Tor Formation interval, resedimentation of Chalk resulted in an increasing thickness of gravity flows, debris flows and minor slump structures down flank. Tertiary inversion created an anticlinal fold axis parallel to and, 2 km S of the Epsilon Fault, and this structure now defines the crest of the Fife reservoir.
Trap At the top of the Fife Sandstone, the Fife Field is defined by a simple four-way dip closure. The structure is low relief with the crest at a depth of 8250ft TVDss and the oil-water contact at 8512ft TVDs (Fig. 7). Most of the production wells have been located in the structural crest, where sufficient gross oil column thickness is available for economic flow rates. The overlying Chalk oil pool is defined by dip closure on three sides but is structurally open to the south at the top of the Tor Formation reservoir. It is thought that a diagenetic trap element exists here. A decrease in Chalk porosity off structure may be due to inhibition of diagenetic porosity degradation in the oil leg relative to the water leg. North/north-eastwards tilting of the Fife area in the Tertiary opened the structure to the south but oil was prevented from spilling by the high threshold capillary entry pressure of the more cemented chalk on the southern flank. The crest of the Tor Formation is at 8000 ft TVDss with top seal provided by the basal muddy, pelagic chalks of the Ekofisk Formation. The oil-water contact is highly variable across the structure and is sensitive to rock properties due to the dominance of capillary over gravitational forces in such a fine-grained rock as chalk. A maximum oil column thickness of 140 ft gross true vertical thickness (TVT) is seen. The free water level is much deeper than the matrix oil-water contact as is common in chalk fields, with an estimated depth close to the free water level for the Upper Jurassic reservoir. From this observation, it is plausible that the Chalk and Jurassic oil pools are hydraulically continuous and share the same free water level. The Fergus Field is a four-way dip closure at top Fife Sandstone level with a crestal depth of 8640 ft TVDss. The oil-water contact at 8780 ft TVDss is 268 ft deeper than the oil-water contact in the Fife Field. By contrast to the Fife Field, there is no oil within the Tor Formation in the Fergus area. This raises speculation that the two fields once shared a similar oil-water contact at 8780ft TVDss; however, a subsequent rupture of the top Jurassic seal in the Fife Field resulted in a loss of oil into the chalk. The presence of residual oil over an interval of at least 100 ft below the oil-water contact in the Fife Field is consistent with this idea.
vv~ TWT ms
Fife Field
I~ast !
__Top __Base
Chalk Cretaceous
Top Triassic Top Zechstein
Fig. 3. East-west seismic section through the Fife Field.
Top Chalk Base Cretaceous Top Triassic Top Zechstein
Fig. 4. North-south seismic section through the Fife Field.
FIFE AND FERGUS FIELDS
Fig. 5. Map showing the major structural elements in the Fife Area.
Fig. 6. East-west cross section through the Fife Field.
541
542
M. SHEPHERD ET AL.
Fig. 7. Fife Field, top Fife Sandstone depth map.
Reservoir The Kimmeridgian to Volgian Fife Sandstone comprises predominantly sheet-like, heavily bioturbated, fine-grained, silty shelf sandstones (Fig. 8). It shows few sedimentary structures due to the intensity of bioturbation. The sands have been colonized by shelfal fauna as indicated by the ichnofabric associations. The dominant burrow types include Palaeophycus, Planolites, Thalassinoides, Skolithus, Teichichnus, Phycosiphon, Chondrites and Ophiomorpha (Currie et al. 1999). Sponge spicules are abundant along with scattered belemnite guards, bivalve shells, serpulids and rare ammonites. Serpulids and bivalve shells are occasionally found concentrated in lag deposits. Rich and diverse marine microplankton assemblages occur throughout the Fife Sandstone suggesting deposition under fully marine shelfal conditions. Miospore assemblages reflect a hinterland vegetation dominated by upland conifers together with xerophytic, coastal plain floral elements and indications of minimal swamp development. Heavy mineral and palynological data indicate a sand source by reworking of Carboniferous and Upper Permian to Triassic sediments. These sediments probably originated from the Mid North Sea High with north and eastwards transport into the Fife Embayment. While showing reasonable porosities in a typical range of 19-31%, the shelf sands tend to have permeability values generally less than 100mD (Fig. 7). Permeabilities are low due to the fine grain size and microporous chert cementation. A field-wide, 1-2 ft thick, volcanic ash band is present within the reservoir about 250ft above the base of the Fife Sandstone and close to the initial oil-water contact at 8512ft TVDss.
A distinctive facies association within the Fife Sandstone comprises thin wedges up to 27 ft thick of poorly sorted, pebbly, coarse to very coarse-grained sandstone (Fig. 9). The wedges thicken northwards towards the Epsilon Fault. The coarse-grained sandstones are commonly massive, although in places they exhibit silty wisps and poorly preserved horizontal burrows defined by chert cement. The pebbles are predominantly quartzose and sub-rounded. Two main horizons of this facies occur intercalated with the background fine-grained shelf sandstones that dominate the succession. Permeabilities in these zones are in excess of a Darcy (Fig. 10).The uppermost interval occurs within the oil leg and was responsible for rapid water breakthrough in the early production wells drilled on the Fife Field (Currie et al. 1999). The origin of these coarse-grained sandstones is problematic, as they represent a major jump in depositional energy levels by comparison to the background fine-grained shelf sandstones. Their coarse clastic nature and the observation that they thicken northwards towards the Epsilon Fault suggest that they may represent gravity flows/submarine toes of fan deltas sourced from the footwall area of the fault. This interpretation is compatible with the inference that the accommodation space for Fife Sandstone deposition was controlled by growth faulting. Two diagenetic styles are seen in the shel~ sandstone facies association: carbonate dominated and chert dominated. These cements form about 20% of the bulk volume of the rock and provide the major element of heterogeneity within the sand dominated Fife Sandstone. Carbonate cement tends to be concentrated as bedding parallel, banded horizons, although a minor volume of cement is clearly
FIFE AND FERGUS FIELDS
Fig. 8. Bioturbated shelf sandstone, Fife Sandstone, core from Fife Field well 31/26a-A9.
nodular in form. The bands are typically in the order of 4-6 inches thick, occasionally thicker, and are spaced at a modal frequency of 6-8ft. The carbonate-cemented bands have negligible porosity (2.5%) and little to no effective permeability (0.01-1 mD). Carbonate cement appears to have preferentially cemented thin horizons rich in sponge spicules and shelly material. Mackertich (1996) noted a strong resemblance between the diagenetic character of the Fife Sandstone and that of the Bridport Sandstone in Dorset. He proposed, by analogy to the diagenetic model of Bryant et al. (1988), that these zones represent storm deposits that have concentrated bioclastic material. The current preferred hypothesis is that these horizons are due to fair weather wave winnowing of bioclastic material into discrete patches over the sea bed. The pervasive bioturbation of the Fife Sandstone suggests that storms were infrequent and of low magnitude. The carbonate bands act to significantly reduce the vertical permeability within the Fife Sandstone. However, pressure discontinuities across the cement bands on RFT pressure-depth plots are rare and give small pressure differentials only. There are several explanations for this observation. It is clear that many of the carbonate bands do not correlate from well to well and they are of limited lateral extent. In addition, the bands are frequently crossed by open fractures, some with thin sandstone intrusions up to an inch wide, similar to the 'fracture solution pipes' described by Bryant et al. (1988) from the Bridport Sandstone. Chert is the more common diagenetic cement phase within the Fife Sandstone. The silica is undoubtedly sourced from the abundant sponge spicules within the Fife Sandstone. The chert cement tends to form irregular, bulbous nodules, sometimes amalgamating to form extensively banded intervals. Chert cemented sandstone has low permeabilities (c. 1-3mD is common) but surprisingly high porosities by comparison (>15%). Thin sections show that this is due to abundant unfilled sponge spicule moulds. The moulds corn-
543
Fig. 9. Coarse-grained pebbly sandstone, Fife Sandstone, core from Fife Field well 31/26a-A6.
prise mostly unconnected microporosity and this explains the low permeabilities. This feature causes major problems with the petrophysical characterization of the Fife reservoir. For a narrow range in porosity within the shelf sandstones as a whole (15-20%), the variation in bulk volume chert cement results in a wide range of permeability values. Thus it is impossible to establish a reliable porosity/ permeability (phi/k) relationship (core derived permeability values are mapped instead). An additional petrophysical problem is the uncertainty in the log analysis interpretation due to the heterogeneity resulting from the chert nodules and carbonate bands. This is particularly problematic in characterizing log-derived water saturation as the sand bodies between the cement bands and nodules are often thinner than the vertical resolution of the logging tools, especially the resistivity tools. The Tor Formation is the reservoir interval within the Chalk Group, comprising white to grey, intensely bioturbated and stylolitized chalk. Allochthonous chalk dominates much of the interval and includes gravity flows, debris flows and occasional slumped units. The average porosity is 24.5% with an average air permeability of slightly less than I mD. Minor intervals of autochthonous chalk are represented by lower porosity, laminated to bioturbated pelagites with negligible oil staining in core. As is typical of chalk reservoirs, the best poroperm characteristics are to be found within the allochthonous chalk (e.g. Taylor and Lapre 1987). However, the Fife chalk rock properties are generally poorer than those of the larger Danish and Norwegian fields found further east. These fields are located within the Central Graben structure proper, where the intensity of reworking is greater than that seen on the margins of the Graben (D'Heur 1986). In chalk reservoirs, fractures and especially the large tectonic fractures can provide a major contribution to the effective reservoir permeability. The most common fracture types in the Fife chalk are healed fractures and stylolite associated fractures. The latter are
544
M. SHEPHERD E T AL.
Fig. 10. Dual permeability characteristics of the Fife Sandstone. The bulk of the Fife Sandstone comprises low permeability shelf sands (average permeability 40 mD). However, an upper interval of very coarse-grained pebbly sandstones show permeabilities of over a Darcy by contrast. This profile strongly controls the flow character of the Fife reservoir. centimetre scale vertical tension gashes which seed off stylolites. These serve to enhance matrix permeability at the core scale, possibly by as much as two to three-times. The large-scale tectonic fractures which significantly enhance production in chalk reservoirs such as that of the Ekofisk Field are rare. This may reflect the relatively 'quiet' inversion tectonic style for the Fife structure as opposed to salt piercement structures like the Ekofisk Field (Dangerfield and Brown 1987). The Jurassic reservoir geology of the Fergus Field is similar to that of the Fife Field. The sandstone rock properties are better developed than in the Fife Field with an average porosity of 26.5% and an average permeability of 500 mD. The upper interval of the Fife Sandstone in the Fergus Field comprises a higher energy and more proximal shelf sandstone lithofacies than is common in the main part of the Fife Field reservoir. The sands are slightly coarser and less argillaceous.
Source The Fife Field contains an undersaturated light oil (36.4 ~ API) with no free gas cap. Upper Jurassic organic rich shale of the KimFig. 11. Fife Field, CPI plot for the Jurassic reservoir, well 31/26a-A10.
meridge Clay Formation are the main source rock in the area. The Kimmeridge Clay Formation is immature in the Fife area but is mature in the U K southern Central Graben to the north. Lateral oil migration in the order of 40-45 km is thought to have occurred through inter-linked Jurassic sandstones between the southern Central Graben and the Fife/Fergus Fields. The datum pressure is 5650 psi at a datum depth of 8500 ft TVDss.
Reserves and production Throughout the development and production of the Fife Field, reservoir engineering work has comprised a combination of analytical and simulation studies. Results from the analytical work have been incorporated into the simulation model to improve history matching. The original development model was used for locating the first production wells in the field. At this time, the implications for reservoir management of the very high permeability intervals in the Fife Sandstone were not appreciated. These intervals caused problems when production started from the field due to rapid water breakthrough. Steadily increasing water cuts resulted which were
Well: 31/26a-A10
AT30_1
140
0
GAMMAI S OUS/F NIC GAPI
~N
PEF B/E
40
100
16
FT
OHMM
20
~PERFORATIONS~ o
AT601 20 O.2
OHMM
20
AT90_1 FT
1.95
G/C3
2.95 0.2
NEUTRON
/ M O BRT I TVO a s
._ C A.L. I. P . .E .R 6
02
5 45
v,v
OHMM
BVW
WATER
20
SATURATION
ILM_I =015 0 2
~ LOG POROSITY
O!SG"
20 1
OHMM
*
)I'
16
BVW :~ LOG POROSITY vN o
CORE PERMEABILITY LOGARITHMIC SCALE
CORE K LINEAR SCALE
VSH V]'~
! 01
9
MD
el0o00 0 9 MD4~00
l . [ 9,..:.
.....
-Swept~~:one4~~ ! I
<
<
< 4
I !
q
i
iii
" .......... I~1
.........
i!ii ill !~
!~i
,~i ~
:'~
''
i~:
ilii~ ~ii i~ii~ii)il l ~i~~i~i~i~
~i!!i 84~?i! ~-ii~ii i+iiiiii--
~~..... i~~ ~!+~i~i~I.i~i~ ~+~~i5,~!i~ :i ~iiiiiiiii. "ii~.~~iI~, ~
~ill
!ii+!ii ~!ili i!ii~i !i :i /
~ ~'~i:i:i
i/
"
i~~
i! i i ~
~'
546
M. SHEPHERD E T AL.
significantly higher than predicted. A field recovery plan was implemented to circumvent these early problems. Subsequent wells were cored to ensure that only the lower permeability shelf sandstones were perforated. Production well 31/26a-A10 drilled in December 1998 illustrates much of the prevalent production patterns. This was a crestal well with the objective of recovering oil from an unswept zone in the lower part of the oil leg. One remarkable feature of the well log CPI (Fig. 11) is the thick remaining oil column down to an oil-water contact unmoved at the initial depth of 8512ft TVDss. A single interval of high water saturation near the top of the reservoir is a zone of water over-run through the upper unit of pebbly coarsegrained sandstone. This is a relic of the early production problems experienced in the field. It is thought that the oil-water contact is unchanged due to the poor vertical permeability related to the volcanic ash and diagenetic
carbonate/chert cemented bands. Thus bottom water influx is suppressed by these features. Nevertheless, sustained production from wells in the crest, such as 31/26a-A10, has been adequately pressure supported and this indicates a dominant edge water drive mechanism for the field. The generally layer-cake, tabular geometry of the shelf sands in combination with the strong flow layering imposed by the cement bands acts to promote an edge water drive mechanism. The 'dual permeability' nature of the Fife reservoir controls the water influx pattern. Water over-run has occurred within the high permeability coarse-grained sand unit supported by an extensive chert cemented diagenetic band in the crest of the field. Oil has been bypassed in the lower permeability shelf sands above and below the coarse-grained sand unit. The volume of water produced through the high permeability coarse sands in combination with the rapidity with which water breakthrough occurred, suggests a direct permeability fairway to
Fife and Fergus Field data summary Field Name
Fife Field
Fergus Field
Fife Chalk oil pool
Units
Four-way dip closure 8250 8512 n/a 8512 none 262 ft vertical closure
Four-way dip closure 8640 8780 n/a 8780 none 140 ft vertical closure
Three-way dip closure/diagenetic trap 8000 n/a
150ft vertical closure
ft ft ft ft ft ft
Fife Sandstone Member Late Jurassic 300-500 81 24 (0-31) 50 (1-6000) 60
Fife Sandstone Member Late Jurassic 440 90 26.5 500 (1-4000) 60
Tor Formation Upper Cretaceous 180-360 45 24.5 (23-27) 0.75 (0-4) 40-60
ft % % mD %
20
29
n/a
BOPD/psi
As Fife
As Fife
Trap
Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column
variable, oil down to 8150ft ss
Pay zone
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
~ API
36.4 Undersaturated, sweet light oil 1.081 1.32 490 n/a 96 n/a 1.1018 n/a
cp psia psig SCF/STB BBL/MMSCF SCF/RCF
Formation water
Salinity Resistivity
61 340 0.041
NaC1 eq ppm ohm m
5650 (a! 8500' ss 0.665 226 132
16.3
23
37 Edge water drive/injection 48.3
69 Edge water drive 11.3
0 n/a 0
psi psi/ft deg F MMBBL BCF %
1995 50 000 (peak) 5 producers/1 injector
1996 18 000 (peak) 1 producer
n/a n/a n/a
Field characteristics
Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
MMBBL BCF MMBBL
Production
Start-up date Production rate plateau oil Number/type of well
BOPD
FIFE AND FERGUS FIELDS the aquifer. It is believed that cross fault communication has been responsible for this pattern. Although the zone of water over-run is represented to a certain extent within the existing simulation model, the water saturation variation is smeared across the layers in a more diffuse manner than is apparent from the petrophysical interpretations. The aim of the simulation model rebuild project which is currently under way is to further improve the control of the vertical permeability by the carbonate and chert bands so that the dynamic fluid saturation modelling is accurate enough to locate future in-fill wells. This work has also been complimented by the revision of the geological model to incorporate permeability flow units. These should better capture the step-like flow profile in the production wells. At the end of 1999, the Fife Field is developed with five production wells and one water injection well. Cumulative production has been 35.2 MMSTB out of reserves currently estimated at 48.3 MMSTB. The recovery factor of 37% is controlled mainly by the low permeability (average 50mD) of the sandstone reservoir. Reservoir complexity is minor with no major compartmentalization and lateral connectivity appears to be effective. Thus the recovery factor is arguably more sensitive to economics than due to geological/physical factors restricting sweep. The economic floor for the Fife Field will be dictated by the minimum production rate to counterbalance the operating expenses of the field. Given the low permeabilities and the small number of wells in the field, then this economic floor may be reached within a time span of only 2-3 years. There is an incentive for the reservoir management team to find extra production opportunities in the Fife area. These would prolong the life and the profitability of the production infrastructure and would shelter what would otherwise be a sub-economic lengthy production tail from the Fife reservoir. Fergus Field production results may be a good indication of what the ultimate recovery could approach for the Fife Field under favourable economic conditions. Oil flows from a single production well in the field at a rate of 4000 BOPD with an 83% water cut. Cumulative production to date is 9.5 MMSTB. Ultimate recoverable reserves are estimated as 11.3 MMSTB out of a STOIIP of
547
16.3 MMSTB. The recovery factor of 69 % for the Fergus Field compares positively with the 37% currently estimated for the Fife Field. The authors would like to thank Amerada Hess Ltd and Premier Oil plc. for permission to publish this paper.
References BRYANT, I. D., KANTOROWICZ,J. D. & LOVE, C. F. 1988. The origin and recognition of laterally continuous carbonate cemented horizons in the Upper Lias Sands of southern England. Marine and Petroleum Geology, 5, 108-133. CURRIE, S., GOWLAND,S., TAYLOR,A. & WOODWARD,M. 1999. The reservoir development of the Fife Field. In: FLEET, A. J. & BOLDY,S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1135-1145. DANGERFIELD, J. A. & BROWN,D. A. 1987. The Ekofisk Field. In: North Sea Oil and Gas Reservoirs. The Norwegian Institute of Technology, Graham & Trotman Ltd, 3-22. D'HEUR, M. 1986. The Norwegian Chalk Fields. In: Habitat of Itydrocarbons on the Norwegian Continental Shelf Norwegian Petroleum Society, Graham & Trotman Ltd, 77-89. HAYWARD, R. D., MARTIN, C. A. L., HARRISON, D., VAN DORT, G. & PADGET, N. 2003. The Flora Field, Blocks 31/26a, 31/26c, UK North Sea. In: GLUYAS,J. & HICHENS, H. M. (eds) United Kingdom Oil and Gas Fields'." Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 549 555. MACKERTICH,D. 1996. The Fife Field, UK Central North Sea. Petroleum Geoscience, 2, 373-380. STOCKBRIDGE,C. P. & GRAY, O. I. 1991. The Fulmar Field, Blocks 30/16 & 30/1 l b, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 309-316. TAYLOR,S. R. & LAPRE,J. F. 1987. North Sea Chalk diagenesis: its effect on reservoir location and properties. In: BROOKS,J. & GLENNIE,K. (eds) Petroleum Geology of North West Europe. Graham & Trotman Ltd, London, 483-495.
The Flora Field, Blocks 31[26a, 31]26c, UK North Sea R. D. H A Y W A R D , C. A. L. MARTIN, D. HARRISON, G. V A N DORT, S. G U T H R I E & N. P A D G E T Amerada Hess E&P, 33 Grosvenor Place, London S W 1 X 7 H Y , UK
Abstract: The Flora Field straddles Blocks 31/26a and 31/26c of the UK sector of the North Sea on the southern margin of the Central Graben. The field is located on the Grensen Nose, a long-lived structural high, and was discovered by the Amerada Hess operated well 31/26a-12 in mid-1997. The Flora Field accumulation is reservoired within the Flora Sandstone, an Upper Carboniferous fluvial deposit, and a thin Upper Jurassic veneer, trapped within a tilted fault block. Oil is sourced principally from the Kimmeridge Clay Formation o f the Central Graben and is sealed by overlying Lower Cretaceous marls and Upper Cretaceous Chalk Group. Reservoir quality is generally good with average net/gross of 85 % and porosity of 21%, although permeability (Kh) exhibits a great deal of heterogeneity with a range of 0.1 to >10000mD (average 300mD). The reservoir suffers both sub-horizontal (floodplain shales) and vertical (faults) compartmentalization, as well as fracturing and a tar mat at the oil-water contact modifying flow and sweep of the reservoir. Expected recoverable reserves currently stand at 13 MMBBL.
The Flora Field is located approximately 325 km SE of Aberdeen and 9 km N of the Fife Field on the southern margin of the Central Graben (Fig. 1). The Flora Field lies on the Grensen Nose, a Palaeozoic structural high that is flanked by the Jurassic Angus and Fife embayments to the west and south respectively. The reservoir of the field is the Flora Sandstone, an Upper Carboniferous high net/gross fluvial sandstone not previously encountered on the UKCS. Reservoir quality is generally good with a 245 ft column of undersaturated oil at the crest. The Flora Sandstone has an easterly dip of approximately 12 ~ with laterally continuous intrareservoir floodplain shales and numerous intra-field faults, which effectively compartmentalize the reservoir (Fig. 2). Field reserves are currently estimated at 13 MMSTB. The field is split into northern and southern segments with development achieved through a horizontal production well in each. Production in the northern area is supported through a water injector (31/26c-F2) while the southern well is adequately supported by a large aquifer. Evacuation is via a sub-sea tieback to the Uisge Gorm Floating Production Storage and Otttoading (FPSO) facility located on the Fife Field.
History Well 31/26-1, drilled by BNOC in 1980, was the first well targeting the Flora structure (Fig. 2). The well was p l u g g e d a n d abandoned
with oil shows, having unsuccessfully tested a possible tar mat developed at the limit of structural closure, it was not until August 1997 that the Flora Field was discovered by well 31/26a-12 (Fig. 2), which was drilled by Amerada Hess Ltd. The well encountered a 200 ft oil column within stacked fluvial channel sandbodies thought to be of Carboniferous or early Permian age. Two drill stem tests were performed, yielding a maximum flow rate of 6360 BOPD of 38.2 ~ API oil. The discovery was rapidly appraised with the drilling of well 31/26c- l 3 in November 1997 (Fig. 2). This down-dip well, targeted some 1.4km NE of well 31/26a-12, confirmed the field oil-water contact (OWC) at 8745ft TVDss. Well 31/26c-13 also established the continuity of high reservoir quality Upper Carboniferous sandstones in excess of 750ft thickness. Within this Carboniferous section 560 ft of conventional core was cut. 3D seismic data were acquired jointly by Amerada Hess Ltd (UK), Amerada Hess A/S (Denmark) and Phillips Petroleum Co. (Norway) in 1995, as part of a regional survey (PAG-95) over parts of UKCS Quadrants 31 and 39, Denmark Block 5603/30 and the southern Norwegian sector. These seismic data were generally of high quality and their interpretation resulted in the discovery and appraisal of Flora. Seismic reprocessing tests in 1998 confirmed that Radon demultiple and T a u - p deconvolution before stack improved resolution of the Flora reservoir section by removing multiple contamination in the critical section just beneath the Base Cretaceous Unconformity. A reprocessed subset of the PAG-95 data was produced over approximately 90 km 2 covering the Flora
Fig. 1. Location map for the Flora Field.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 549 555.
549
550
R . D . HAYWARD E T A L .
Fig. 2. Top Reservoir depth structure map. Field area, and the density of coverage was increased by interpolation from 25 x 25 m to 12.5 x 2.5 m. The aim of the reprocessing was to increase confidence in targeting the second horizontal producer 31/26a-F03, and to provide a more robust input for seismic inversion. Following the appraisal drilling of the field a development plan was submitted in February 1998 with approval granted in April 1998. The first development well, 31/26a-F01 (Fig. 2), was drilled and completed in the summer of 1998 with a horizontal section targeting the northern area of the field. Well 31/26c-13 was completed as a water injector to offer pressure support to the crestal production well. Production commenced on 26 October 1998 via a sub-sea tieback to the FPSO Uisge Gorm located over the Fife Field. A second horizontal production well, 31/26a-F03 (Fig. 2), was drilled and tied back to the Uisge Gorm in July 1999. Peak production from the field is 30 000 BOPD with estimated recoverable reserves of 13 M M B B L and a field life of 5 years.
Regional setting and structural development The Flora Field lies on the Grensen Nose, a long-lived structural high which forms a north-south extension of the Mid North Sea High. In addition, the Grensen Nose lies at the junction of N W - S E and north-south Mesozoic structural trends that reflect the U K and Danish/Dutch sectors of the Central Graben respectively. Hence the Flora Field has a complex structural history as outlined below. Across the Mid North Sea High, Late Devonian to Early Carboniferous extension created a series of N W - S E to W N W - E S E trending grabens and rotated fault blocks similar to those developed
onshore in the U K (cf. Fraser & Gawthorpe 1990; Chadwick et al. 1995). The Westphalian C-Stephanian crustal thinning associated with the culmination of this extensional phase resulted in the extrusion of basaltic lava flows over the Grensen Nose and surrounding areas. This was followed by a period of tectonic quiescence, and sedimentation. The Latest Carboniferous (Stephanian) was then characterized by a short phase of inversion along east-west trending faults. Martin et al. (in prep) interpret this unconformity to be equivalent to the Asturic Unconformity of Maynard et al. (1997). The Early Permian was characterized by extension along n o r t h south trending faults and the creation of a series of rotated fault blocks. Extension was concomitant with sedimentation and the extrusion of basaltic lavas across the eastern margin of the Mid North Sea High together with the Danish, Norwegian and U K grabens (Dixon et al. 1981; Serensen & Martinsen 1987). The subsequent Sakmarian-Kazanian was a period of uplift and erosion associated with the Saalian unconformity (Fraser & Gawthorpe 1990; Glennie 1997). There is no evidence for significant tectonic activity across the Grensen Nose area during the Triassic to Middle Jurassic. In the Late Jurassic, there was reactivation of normal faults coupled with a marine transgression resulting in the deposition of the Kimmeridgian to Volgian Fife Sandstones, both within the embayment areas and more locally across structural highs (Spathopoulos et al. 2000). Inversion during the Ryazanian across the Grensen Nose occurred along the north-south faults and was followed by clastic deposition during the Hauterivian to Albian which was concomitant with extension along W N W - E S E orientated faults. Across the Grensen Nose and other palaeo-highs this unit is highly condensed. Chalk sedimentation commenced in the Turonian, and blanketed
FLORA FIELD palaeotopographic highs, resulting in thin sections over the Mid North Sea High and Grensen Nose. In the Tertiary, broad uplift centred on the Fife area resulted in folding of Late Cretaceous sediments.
Stratigraphy A thick Palaeozoic section has been encountered in the Flora Field area, as illustrated in Figure 3. The Palaeozoic strata have proven to be largely barren of organic material and dating has relied heavily on the integration of K - A r dating of the lava flows with heavy mineral and petrological analyses of intervening sediments. The lower volcanic package of the Flora Field has been dated as 299 + 9 Ma and therefore Carboniferous in age (Fig. 3); (Martin et al. 1999). The upper volcanic package has been dated at 283 • 8 Ma and thus Permian, interpreted to form part of the Inge Volcanics Formation of the Rotliegend Group (Cameron 1993a). Between the two lava flows a sedimentary section in excess of 1500 ft thick is preserved across the Flora Field and Grensen Nose. This succession is composed of inter-bedded grey and reddened conglomerate, sandstone and mudstone within which an unconformity is mapped on seismic d a t a - the Asturic Unconformity (Fig. 4). Beneath the unconformity sediments are assigned to the informally termed Upper Flora Sandstone (Martin et al. 1999). The palynological assemblages of this unit indicate a Westphalian C/D age (D. McLean pers. comm.) and the sediments are therefore at least partly equivalent to the Schooner Formation (Conybeare Group) as developed in the southern North Sea (Cameron 1993b). The Upper Flora Sandstone is represented by a high net/gross section of conglomerate, sandstone and mudstone which were deposited in a variety of fluvial environments. This is the section which forms the principal reservoir of the Flora Field. Overlying the Asturic Unconformity, the informally termed Grensen Formation (Fig. 3) is represented by a low net/gross succession of interbedded mud-
551
stone and sandstone. Again, these sediments are inferred to have been deposited in fluvial or alluvial settings. The Grensen Formation is barren of organic material, but heavy mineral assemblages indicate a clear association with the Permian (C. Hallsworth pers. comm.) and the interval has therefore been assigned to the Lower Rotliegend Group. Due to the easterly dip of the Flora Sandstone in the field, the oldest part of the succession is encountered at the crest of the field with younger strata coming into closure to the south and east. Across the crest of the field and immediately above the Flora Sandstone a 2-5 ft thick Jurassic veneer has been encountered. The coarse-grained sandstones and conglomerates which constitute this section are barren of age deterministic organic material and age determination has been made on the basis of heavy mineral analyses and lithological correlation. The veneer is therefore assigned to the Upper Jurassic Humber Group (Fig. 3) with a more precise age determination being impossible. Across the southern portion of the field the Jurassic veneer is separated from the Flora Sandstone by a thin red mudstone with structural dips intermediate between those of the Palaeozoic section and Jurassic veneer. The age of the mudstone is indeterminate but it could form part of the Lower Rotliegend Group or indeed be Triassic (Fig. 3). Preserved unconformably above the Jurassic coarse-grained veneer is a thin (c. 10 ft), highly condensed Lower Cretaceous marl which is assigned to the Cromer Knoll Group. The Lower Cretaceous interval onlaps the eastern flank of the Flora Field but is absent across the crest where the Jurassic is overlain by the Upper Cretaceous Chalk Group. The Cretaceous section is in turn overlain by a thick succession of Tertiary mudstones.
Trap The trap is a relatively straightforward tilted fault block with threeway dip closure at the OWC of 8745 ft TVDss. The western margin of the field is fault-bounded (Fig. 2). The throw on this fault decreases dramatically from c. 400 ft at the northern end of the field to zero at the southern end, the spill point for the structure. In the northern part of the field, the top of the reservoir is defined seismically by the Base Cretaceous Unconformity which dips gently eastwards (Fig. 5). The eastern extent of the field is tightly constrained by well 31/26c-13 which penetrated the top reservoir approximately 12ft above the OWC. In the southern part of the field, the top of the reservoir is defined partly by the Base Cretaceous Unconformity and partly by the base of the more steeply dipping upper volcanics (Permian) package, which dips eastwards at approximately 12~ (Fig. 4) and was penetrated 4 km to the SE by well 31/26-2AST. The field is cut by several N E - S W trending faults which, while having relatively small throw at the Base Cretaceous Unconformity, effectively subdivide the field into northern and southern segments (Fig. 2).
Reservoir
Fig. 3. Generalized stratigraphy for the Flora Field.
The Upper Flora Sandstone forms the principal reservoir of the Flora Field. A small contribution also comes from the thin Jurassic veneer which sits above the Flora Sandstone across the crest of the field. The depositional model for the Flora Sandstone is that of a high net/gross, low sinuosity fluvial package deposited across an easterly advancing alluvial fan system. Across the field the Flora Sandstone subcrops the Mesozoic so that with the strata dipping at approximately 12~ towards the east, progressively younger sediments come into closure to the south and east of the structure (Figs 4 & 5). Wells are generally located in areas where they have penetrated the lower part of the stratigraphy and therefore a significant section of the seismically mappable unit is undrilled.
552
R. D. HAYWARD E T A L .
Fig. 4. West-east seismic section through the southern segment of the Flora Field. BCU, Base Cretaceous Unconformity; TIV, Top Inge Volcanics;TGF, Top Grensen formation; TFS-AUC, Top Flora Sandstone - Asturic Unconformity; TCV, Top Carboniferous Volcanics.
Facies analysis of the core intervals within the Flora Field reveals the section to be composed of vertically stacked fluvial channel fills, interbedded with minor amounts of fine-grained material of floodplain origin. Individual fluvial channels are identified through recognition of a basal erosional surface overlain by an upward fining channel fill, generally truncated by a subsequent channel. Individual fluvial channel fills are stacked vertically to produce three multi-storey sandbodies interpreted to represent the deposits of long-lived channel belt systems. These channel belts are separated by major argillaceous breaks (15-30ft thick) which correspond to periods of prolonged alluvial floodplain development. Between the multi-storey channel sandbodies clear changes in depositional style occur describing upwards cleaning and an overall upward increase in grain size. Three broad fluvial channel types (A to C) have been recognized from core which describe a vertical progradation from anastamosing to braided fluvial systems (Fig. 6). From well data it is possible to correlate the thick mudstone units that separate the channel belt deposits. In addition, there are a number of other major argillaceous breaks that appear to have a field-wide extent. This mudstone correlation has formed the basis for dividing the reservoir into seven major flow units. A further, more contentious, subdivision is based on permeability variation within the coarse-grained units and is undertaken primarily to aid reservoir simulation modelling. The reservoir units generally thicken in line with the dominant channel belt direction to the SE.
Contrasting areas of high and low amplitude are recognized on reflection 3D seismic data at top reservoir level. These possibly relate to changing reservoir quality, reflecting primary depositional facies. Seismic inversion to acoustic impedance, illustrated in Figures 4 & 5 has enabled a more detailed interpretation of the reservoir succession to be carried out, with the layering of the Flora Sandstone sand and shale units mapped. The areas of lowest acoustic impedance, which may be indicative of the best reservoir quality, correspond to the deposits of fluvial style C (Fig. 6). The Flora Sandstone is classified as a combination of subarkosic, arkosic and lithic arenite according to the classification scheme of Folk (1980). Ductile grains comprise muscovite, biotite and detrital clays while authigenic components are dominated by kaolinite, haematite and authigenic quartz with minor illite. Both net/gross (85%) and porosity (21%) are reasonably constant throughout the field. However, while unit average permeability (Kh) generally increases up through the section, each unit displays a great deal of heterogeneity (0.1- >10 000 mD). The log plot of permeability (Fig. 6) illustrates that permeability is generally good throughout the section, but a great deal of heterogeneity exists as shown on the linear plot of permeability. Many elements combine to control permeability within the sands, but grain size has proven dominant. A lack of core data in the oil leg means that the relative diagenetic histories of the oil and water legs are unclear; however, there may be a case for a diagenetic reduction in permeability
FLORA FIELD
553
Fig. 5. West-east seismic section through the northern segment of the Flora Field. Low acoustic impedance may highlight better quality reservoir.
within the oil leg. Vertical permeabilty within net sand is generally good (Kv/Kh of 0.5) but is reduced where micas are concentrated in fine-grained, parallel laminated sands. The Jurassic veneer is composed of conglomeratic to mediumgrained sands interbedded with very fine, glauconitic sands and is interpreted to represent a local reworking of the Flora Sandstone in a shallow marine environment. Although very thin (2-5 ft), it is interpreted to be present in all of the Flora Field wells. Reconciliation of well test data with core and log data has proven difficult when modelling permeability distribution. Filled fractures, identified from both core and image logs, are interpreted to reduce the overall matrix permeability. Permeability modelling has incorporated modified log and core data tied to a geological model, with well test results and seismic attribute maps. In addition to this, a possible tar mat identified at the OWC may provide a baffle to the potential aquifer support for the field. This has been highlighted by the need to apply a transmissability multiplier of 0.07 at the OWC to achieve a history match in the southern segment of the field.
Source Geochemical analysis indicates that the oil in the Flora Field is a mixture of oils derived from two sources. The principal hydro-
carbon source is the Upper Jurassic Kimmeridge Clay Formation of the Central Graben to the north of the field. However, oil was also derived from the laterally equivalent Farsund and Mandal Formations of the Dutch 61 Basin to the east. Oil migration occurred in the Tertiary, probably in the Palaeocene.
Reserves and production Production from the Flora Field began in October 1998, 14 months after the field was discovered, from a single horizontal producer, 31/26a-F01, in the northern area of the field (Fig. 2). The field appraisal well, 31/26c-13, had shown a 6psi depletion in reservoir pressure at the time of drilling. This was interpreted to represent depletion from the 31/26a-12 well test with the implication that water injection support would be required. The appraisal well was therefore suspended and later completed as a water injector, 31/26cF02 (Fig. 2). The Flora Field development carried a significant risk with the greatest single element coming from the uncertainty associated with the extension of the field and reservoir model into the southern segment (unappraised at the time of project sanction). The development was therefore phased with phase two commencing once the reservoir model and production profile had been successfully tested in the north. A second horizontal producer,
554
R . D . HAYWARD E T AL. Pay zone Formation Age
Average oil saturation
Flora Sandstone Westphalian C (Carboniferous) to Asselian (Permian) > 1000 ft Average 85% Vsh 50% Porosity 13% Average 21% l-10 000 mD (absolute permeability from core) 7O%
Hydrocarbons Oil type Oil gravity 3 Gas/oil ratio Formation volume factor Pressure gradient
Light undersaturated oil 8.20 ~ API 98 SCF/STB 1.129 RB/STB 0.343 psi/ft
Formation water Salinity Resistivity
69 000 ppm NaCI 0.1002 @ 770~
Field characteristics Initial pressure Pressure gradient Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil
5750 @ 8600 ft TVDss 0.668 @ 8600ft TVDss 2360~ 69 MMSTB 19% Aquifer Support/Water Injection 13 MMSTB
Production First oil Production rate peak oil Number/Type of well
October 1998 30 000 BOPD Two horizontal producers
Gross thickness Net/gross ratio Net sand cut-off Porosity average (Range) Matrix permeability
Fig, 6. GR log from well 31/26c-13(F2) with derived permeability plots and depositional settings.
References CAMERON, T. D. J. 1993a. Lithostratigraphic nomenclature of the UK 31/26a-F03, was successfully completed in the southern, previously undrilled area of the field (Fig. 2). A large aquifer is m a p p e d to the south and east of the field and this has so far provided adequate support for production. The in-place volume is reasonably well constrained in the Flora Field at 69 M M S T B (simulation m o d e l initialization volume). Reserves are currently estimated at 13 M M S T B , with a recovery factor of 19%. A l t h o u g h low, the recovery efficiency can be explained by a c o m b i n a t i o n of a low relief structure, a relatively thin oil leg underlain by water, and horizontal and vertical compartmentalization. The authors wish to thank both Amerada Hess Exploration and Production and Premier Oil plc, for permission to publish this paper. The authors have drawn on the work of colleagues that have been involved in the Flora development and would like to acknowledge their contribution to this paper, from exploration through appraisal and exploitation.
Flora Field data summary Trap Type Depth to crest Lowest closing contour FWL Oil column
Tilted Fault Block 8500 ft TVDss 8745 ft TVDss 8745 ft TVDss 245 ft
North Sea Volume 4. Triassic, Permian and Pre-Permian (Central and Northern North Sea). In: KNOX, R. W. O'B & CORDEY, W. G. (eds). CAMERON, T. D. J. 1993b. Lithostratigraphic nomenclature of the UK North Sea Volume 5. Carboniferous of the Southern North Sea. In: KNOX, R. W. O'B & CORDEY,W. G. (eds). CHADWICK,R. A., HOLLIDAY,D. W., HOLLOWAY,S. & HULBERT,A. G. 1995. The structure and evolution of the Northumberland-Solway Basin and adjacent areas. British Geological Survey Subsurface Memoir. DIXON, J. E., FITTON, J. G., FROST, R. T. C. 1981. The Tectonic significance of Post-Carboniferous ligneous activity in the North Sea Basin. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe. London, Heyden & Son, 121-137. FOLK, R. L. 1980. Petrology of sedimentary rocks. Austin, Hemphill. FRASER, A. J. & GAWTHORPE, R. L. 1990. Tectono-stratigraphic development and hydrocarbon habitat of the Carboniferous in northern England. In: HARDMAN, R. F.I P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publication, 55, 49286. GLENNIE, K. W. 1997. Recent advances in understanding the southern north sea Basin: a summary. In: ZIEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea." Future Potential. Geological Society, London, Special Publication, 123, 17-29. MARTIN, C. A. L., HAYWARD,R., DOUBLEDAY,P.A. & HARRISON,D. 1999. The Flora Sandstone: a carboniferous oil reservoir in the Central Graben. Abstract, July London Evening Lecture. Petroleum Exploration Society of Great Britain. MAYNARD, J. R., HOFMANN, W., DUNAY, R. E., BENTHAM, P. N., DEAN, K. P. & WATSON, I. 1997. The Carboniferous of western Europe: the development of a petroleum system. Petroleum Geoscience, 3, 97-115.
FLORA FIELD SORENSEN, S. ~; MARTINSEN, B. B. 1987. A Palaeogeographic reconstruction of the Rotliegend deposits in the north-eastern Permian Basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe, London, Graham & Trotman, 497-508.
555
SPATHOPOULOS, F., DOUBLEDAY, P. A. & HALLSWORTH, C. R. 2000. Structural and depostional controls on the distribution of the Upper Jurassic Fulmar Formation Sandstones in the Fife and Angus Field Areas, Quadrants 31 and 39, UK Central North Sea. Marine and Petroleum Geology. 17, 1053-1082.
The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea A. CARTER & J. H E A L E B P plc, Burnside Road, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB
This paper updates the earlier account of the Forties Field detailed in Geological Society Memoir 14 (Wills 1991), and gives a brief description of the Brimmond Field, a small Eocene accumulation overlying Forties (Fig. 1).
Forties History The Forties Field is located 180km ENE of Aberdeen. It was discovered in 1970 by well 21/10-1 which encountered 119 m of oil bearing Paleocene sands at a depth of 2131 m sub-sea. A five well appraisal programme confirmed the presence of a major discovery
including an extension into Block 22/6 to the southeast. Oil-in-place was estimated to be 4600MMSTB with recoverable reserves of 1800 MMSTB. The field was brought onto production in September 1975. Plateau production of 500 M B O D was reached in 1978, declining from 1981 to 77 M B O D in 1999. In September 1992 a programme of infill drilling commenced, which continues today. The earlier infill targets were identified using 3D seismic acquired in 1988. Acquisition of a further 3D survey in 1996 has allowed the infill drilling programme to continue with new seismic imaging of lithology, fluids and saturation changes. The performance of the 1997 drilling showed that high step-out and new technology wells, including multi-lateral and horizontal wells, did not deliver significantly better targets than drilling in previous years.
Fig. 1. Location map for the Forties and Brimmond Fields. GLUYAS, J. G. & HICtaEyS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 55%561.
557
558
A. CARTER & J. HEALE
In line with smaller targets, and in the current oil price environment, low cost technology is being developed through the 1999 drilling programme. Through Tubing Rotary Drilling (TTRD) is currently seen as the most promising way of achieving a step change in drilling costs, and to mid-1999 two T T R D wells have been completed on Forties Bravo. Current estimate of cessation of production for the Forties Field is 2010, some 35 years after start-up (Brand et al. 1995).
Source Forties oil was sourced from the Jurassic Kimmeridge Clay Formation.
Reserves and production The production history for the Forties Field was published by Wills (1991) and Brand et al. (1995). Production data for the field are plotted in Figure 2.
Discovery The Forties Field was discovered in 1970 by well 21/10-1 which encountered 119 m of oil bearing Paleocene sands at a depth of 2131 m sub-sea.
Brimmond History Structure The Forties and Brimmond Fields overly the crest of the Forties Montrose Ridge, situated close to the junction of the Central, Viking and Witch Ground Grabens.
Stratigraphy The Forties reservoir occurs in thick Upper Paleocene sandstones of the Montrose Formation.
Trap Forties is primarily a simple four way dip closed anticline overlying the Forties Montrose Ridge. Depth to the crest is 2030m subsea and vertical relief is about 190m. Reservoir seal is provided by the overlying conformable mudstones of the Sele Formation. The Charlie Sand is effectively isolated from the remainder of the field, and part of the reserves in this unit appear to lie below the structural spill point, stratigraphically trapped by a lateral facies change.
Reservoir The Forties reservoir occurs in thick Upper Paleocene sands deposited as a major sand rich submarine fan sequence. The reservoir consists of several stacked sandstone bodies. Based on seismic mapping integrated with the well log and biostratigraphic data, a new gross reservoir zonation has been defined, consisting of five zones as shown below:
Seismic Horizon
New Reservoir Zone
Approx. Former Zone
Top Reservoir Base Charlie Sand Base Echo Sand Top Main Sand Top Debris Flow
Charlie Sand Echo Sand Alpha-Bravo Sand Upper Main Sand Lower Main Sand Aquifer
Units Units Units Units Units Units
K K K H E D
& J & J & J G & F & D and below
This new zonation provides a framework for modelling that is more consistent with the depositional architecture of the reservoir than schemes used previously. There is potential for further subdivision of the reservoir based on seismic mapping. Much of the fine scale structural and depositional detail within the reservoir is already becoming apparent through the litholgy and fluid mapping based on seismic attributes. This has proved invaluable in helping to understand the factors that control fluid movements within the reservoir.
The Brimmond field is located in Block 22/6a, Licence P.084. Discovered in 1985 during development drilling of Forties, the Brimmond field is a small Eocene accumulation overlying, but completely separate from the main Paleocence reservoir of Forties. Originally the field was owned wholly by Shell and Esso, but was transferred to the Forties Unit on 11 June 1996. Development consent was received on 19 June 1996 following submission of a development programme for the field by Shell U K Exploration and Production. A phased development of this small field was proposed using in-casing recompletions of former Paleocene producers giving reserves of 4.5 MMSTB oil. The first workover conversion began in August 1996 when well FES03 was re-entered, the Paleocene section abandoned, a 5 m window over the Eocene was milled out and a gravel pack completion installed. An Electrical Submersible Pump (ESP) provides artificial lift and pressure gauges were run for reservoir monitoring. Brimmond came on stream the following October with the well reaching a peak rate of 3500 BOPD in November 1996. The second production well FES07ST came on line in April 1998 with a disappointing result. A pilot hole was planned to confirm the oil-wave contact (OWC) and gather reservoir data prior to drilling the horizontal section of the well. Severe mud losses forced the abandonment of the pilot before it reached the OWC. The horizontal section then encountered several minor faults which reduced the reservoir section to 24 m instead of the expected 100 m. Two further sidetracks were required before a 50m horizontal reservoir section could be drilled and completed. The anticipated high initial rates failed to materialize, water breakthrough times, watercut development and oil rates were slightly poorer than predicted by the reservoir model. FES03 pump failed in November and although uneconomic to workover in 1998, work currently is being done to justify a workover. Both Brimmond wells are expected to flow at between 85% and 90% watercut with 5 to 6 M B O D total fluids, giving a steady Brimmond oil potential of around 1.2 to 1.5 MBOD. Brimmond is expected to reach its economic limit in 2001.
Discovery The Brimmond Field was discovered in 1985 during development drilling of SE Forties.
Structure The Forties and Brimmond Fields overly the crest of the Forties Montrose Ridge, situated close to the junction of the Central, Viking and Witch Ground Grabens.
FORTIES AND BRIMMOND FIELD
559
4081
6[8
1
i
ii
500
i/I/'11/~il" '/'i
400
/;,!
i
llIlll
!i ~~I~l ~
.1/l~'/t
i]7i30
I
250 o~
i
388
I
I f
s
ilL3.8 ~ i i
,,
208
i
[ i
180 I '
/0
i r
J j- so
tr
/s;-/
"%~'I +
,~ za%, / /
1975
ll]O
1980
1985
19g5
1990
2000
t L 20135
Year
Fig. 2. Production history of the Forties Field.
Stratigraphy
Reserves and production
The B r i m m o n d reservoir is Eocene sandstones o f the R o g a l a n d Formation.
By end 1998, the field h a d p r o d u c e d 1.1 M M B O from the initial b o o k e d reserves of 3.4 M M B O . R e m a i n i n g B r i m m o n d reserves are 1.4 M M B O assuming it is e c o n o m i c to w o r k over slots 3 and 7 no further wells are drilled a n d end of platform life is no sooner than 2001.
Trap B r i m m o n d is a c o m b i n e d structural and stratigraphic trap with crest at 1950 m sub-sea.
Reservoir The B r i m m o n d reservoir is an Eocene age, submarine fan sandstone reservoir containing 23.9 ~ A P I oil.
Source F o r t i e s / B r i m m o n d oil was sourced from the Jurassic K i m m e r i d g e Clay F o r m a t i o n .
References BRAND, P. J., CLYNE, P. A., KIRKWOOD, F. G. & WILLIAMS, P. W. 1995. The Forties FieM- 20 years Young. Society of Petroleum Engineers, SPE 30440. WILLS, J. M. 1991. The Forties Field, Block 21/10, 22/6a, UK North Sea. In: ABBOTrS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 301-308.
560
A. CARTER & J. HEALE Brimmond
Field data summary
Trap Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column
Brimmond
Units
Notes
structure & stratigraphic 6365 6460
fi
@ 2000m
6460 -
50
Pay zone
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
no cores available Balder Eocene 30 33-34 1100 60-80 6-9
ft ft % mD % BOPD/psi
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
23.9
5.8
106
~ API
cp psig psig SCF/BBL BBL/MMSCF SCF/RCF
Formation water
Salinity Resistivity
45 700 0.056
NaC1 eq ppm ohm m
Field characteristics
Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
400-700 2863
14.8 10-15 aquifer support 1.4
acres acre ft psi psi/ft oF MMBBL BCF %
(orignal dev plan)
MMBBL BCF MMBL
assuming economic to w/o 3 & 7
Production
Strat-up date Production rate plateau oil Production rate plateau gas Number/type of well
September 1975 520 000 barrels/day 2
BOPD MCF/d producers
FORTIES AND BRIMMOND FIELD
561
Forties Field data summary Forties
Units
Notes
Trap
Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column
Four way dip closed anticline 6660 7274 7274 614
Pay zone
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Forties Formation Paleocene 1161/653-1539 0.65 0.27/0.10~3.36 700/30-4000 0.85 25/5-70
ft ft % mD % STB/D/psi
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
37 low sulphur
~ API
0.76 1142-1390 n/a 300 4 1.22
cp psig psig SCF/STB % RB/STB SCF/RCF
55 000 0.034
NaC1 eq ppm ohm m
@ 96~ @ 96~
total production
Formation water
Salinity Resistivity
@ 96~
Field characteristics
Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism
Recoverable oil Recoverable gas Recoverable NGL/condensate
23 000 64382 --3215 1.08 96 4196
acres mmcft psi psi/m ~ MMSTB BCF %
57 Predominantly bottom drive acquifier with peripheral water injection 2545 MMBBL 550-650 BCF 9 MMBBL
Production
Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
Sept 1975 520 000 barrels/day 142 103 59 11 72
well slots wells producers water injectors spares/dead
BOPD MCF/D
@ 7136 ft
The Fulmar Field, Blocks 30/16, 30/llb, UK North Sea O. K U H N ,
S. W . S M I T H ,
K. VAN
NOORT
& B. L O I S E A U
Shell U K Exploration and Production, 1 Altens Farm Road, Aberdeen A B 1 2 3 F Y , U K (e-mail: o.kuhn @shell. corn)
Abstract: The Fulmar Field is located on the southwestern margin of the Central Graben in Blocks 30/16 and 30/11 b of the UK sector of the North Sea. The Fulmar Field was discovered 1975 and began producing in 1982. Currently (2000) the field produces at a rate of 8000 BOPD at a watercut above 90% mainly through the process of rinsing of residual oil. Total STOIIP is 822 MMBBL and ultimate recovery is 567 MMBBL ofoil and 342 BSCF of wet gas. As of the end of 1999, 547 MMSTB ofoil and 325 BSCF of wet gas had been produced. The high recovery factor (69%) of the field is thought to be linked to the combination of well density, large length of reservoir perforated, excellent reservoir quality, sweep by water injection, good pressure support and oil stripping from a secondary gas cap formed early in field life. The Fulmar Field is a small triangular, partly eroded domal anticline with steeply dipping flanks, located on a fault terrace within the western margin of the South West Central Graben at a depth between 9900 and 11 500 ft TVDss. The field has been shaped by three major tectonic processes: (1) halokinesis, (2) syndepositional reactivation of Caledonian basement faults; and (3) syndepositional through post-depositional displacements along the nearby Auk Horst Boundary Fault. The reservoir consists of thick Upper Jurassic, shallow marine, very bioturbated sandstones of the Fulmar Formation overlain by the deeper marine Ribble Sands interbedded within the Kimmeridge Clay Formation. Reservoir seal is provided by the Kimmeridge Clay in the west and Upper Cretaceous chalks which unconformably overlie the Fulmar Formation in the east. The reservoir section has been lithostratigraphically subdivided into six reservoir units and 24 sub-units. Integration of bio- and lithostratigraphic data has led to a sequence stratigraphic model of the Jurassic succession in the Fulmar Field. In total four depositional sequences are identified, which progressively onlap Triassic basement towards the southwest. The older Jurassic sequences are characterized by rapid progradation of shoreface sands, whereas aggradation of thick sediment packages is typical of the younger intervals. This change of depositional architecture is linked to syndepositional reactivation of basement faults. Major transgressive intervals form intra-reservoir barriers or baffles to flow. Facies changes (Mersey-Clyde Sands) from proximal to distal facies are abrupt and are also linked to basement faults.
The F u l m a r Field was discovered in 1975 by well 30/16-6 in the U p p e r Jurassic F u l m a r F o r m a t i o n and is located approximately 170 miles SE of A b e r d e e n (Fig. 1). The field is situated mostly in Block 30/16 (Shell/Esso) but extends onto Block 30/11 b (BP A m o c o Exploration Co. a n d A m e r a d a Hess Ltd). The field is unitized and is operated by Shell. The S T O I I P is estimated to be 822 M M B B L oil with a gravity of 40 ~ A P I and a G O R of 614 SCF/STB. Ultimate recovery is 567 M M B B L oil, of which some 547 M M B B L h a d been p r o d u c e d by year-end 1999 t h r o u g h a total of 42 d e v e l o p m e n t wells (including 13 water injectors, one gas injector) from a 36 slot steel p l a t f o r m and a six slot sub-sea template and wellhead jacket. A total of 3900 ft has so far been perforated for p r o d u c t i o n and a total of 2500 ft for water/gas injection. At the end of 1999 14 wells were still p r o d u c i n g from the field. Detailed descriptions of the field have been
Table 1. Lithostratigraphic and reservoir unit terminology used in this"paper Formation
Member
Res. unit
Kimmeridge Clay Fm
Ribble Sands Avon Shale
1
1.1 1.2
Mersey Sands (Clyde Sands = distal equivalent)
3
3.1 3.2 3.3 3.4 3.5
Lydell Sands
4
4.1 a b 4.2
Usk Sands
5
5.1 5.2a b
Fulmar Fm
'Fulmar Main Sands'
c
5.3 Forth Sands
6
6.1 6.2
given by J o h n s o n et al. (1986), M e h e n n i & R o d d e n b u r g (1990), V a n der H e l m et al. (1990), Stockbridge & G r a y (1991) a n d Spaak et al. (1999). Alongside up-to-date p r o d u c t i o n figures, this paper presents a c h r o n o - and sequence stratigraphic review of the Jurassic succession o f the F u l m a r Field, as well as new insights into the tectonic history of the field and the impact on sediment deposition. Table 1 (below) shows the relationship between lithostratigraphic terms as used in this paper.
History Early 2D seismic lines shot over the A u k - F u l m a r area in 1970 and 1974 indicated a small closure b e n e a t h the Base Cretaceous u n c o n formity on the d o w n t h r o w n side o f the A u k H o r s t B o u n d a r y fault. The structure was tested in 1975 by the Shell/Esso well 30/16-6 located slightly southwest of the structural crest. The objective of the well was to test p r o g n o s e d U p p e r Jurassic sandstones overlying Zechstein evaporites. T h e well e n c o u n t e r e d an U p p e r Jurassic sequence consisting of 495 ft of K i m m e r i d g i a n shales (with some interbedded sandstones) b e n e a t h the Base Cretaceous U n c o n f o r m i t y and a 900ft thick sequence of intensely bioturbated, late Oxfordian to K i m m e r i d g i a n sandstones, initially called A u k Sands but later called the F u l m a r F o r m a t i o n . Reservoir quality was excellent. A 668 ft oil c o l u m n (607 ft net sand) was penetrated above an oil-water contact ( O W C ) at 10 840 ft TVDss. The well p e n e t r a t e d a further 1600 ft of Triassic r e d - b r o w n shales and occasional silty sandstones before reaching a total depth of 12 800 ft TVDss in Zechstein carbonates. A single appraisal well (Shell/Esso 30/16-7), located 600 m SW of the discovery well, was drilled in 1977. It was designed to test the steeply dipping flank of the structure identified on the seismic data. This well e n c o u n t e r e d a similar, but water-bearing, section of the F u l m a r F o r m a t i o n . The well also p r o v e d a second oil-bearing reservoir within the overlying K i m m e r i d g e Clay section which was 139 ft thick and separated from the F u l m a r M a i n Sands by 94ft of shale. This interval was later called the Ribble Sands. F u r t h e r appraisal was considered unnecessary. The field was declared
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 563 585.
563
564
O. KUHN E T A L .
Fig. 1. Location of the Fulmar Field in the UKCS Central North Sea area. Faults shown are the most important faults seen at Top Reservoir.
commercial with a STOIIP of 934 M M B B L and an expected ultimate recovery (UR) of 468 M M B B L and was named Fulmar after the sea bird. Annex B approval was obtained from the Secretary of State at the Department of Energy in 1978. One of the first 3D seismic surveys in the North Sea was shot over the Fulmar Field area in 1977 (pre- production), in order to plan and execute the development drilling. The initial development comprised 12 production wells, supported by ten down-dip water injectors and one crestal gas injector. A six slot template was installed in 1978 and four wells were drilled for early production. These wells showed that the field was more heterogeneous than indicated by the two exploration wells. The wells discovered (1) a shallower OWC in the north; (2) truncation of the Fulmar Formation sandstones by the Base Cretaceous Unconformity in the north and northeast; and (3) poorer quality reservoir rocks in the eastern part of the field. A wellhead jacket was placed over the template in 1979 and the main 36 slot steel platform was installed in 1980. The template wells were tied to the platform for first production in early 1982 with evacuation via the nearby Fulmar Floating Storage Unit (FSU). Figure 2 shows the historical pressure data in relation to key events during the field development history, such as onset of water injection, gas reinjection and water breakthrough. Water injection really took off in the summer of 1983, some 1.5 years after
production start. By this time reservoir pressures had already declined by c. 1200 psi. Prior to the completion of the Fulmar gas pipeline, surplus gas was re-injected into the crest of the Fulmar reservoir (FA-16) creating a secondary gas cap. Gas injection continued until 1986. The secondary gas cap was found to expand to a maximum of approximately 10 200 ft TVDss. From 1986, the gas cap was back-produced resulting in a high produced GOR. The total compressibility in the reservoir decreased thereafter because of a reduction in the amount of free gas. Due to the lower compressibility, variations in water injection performance have had an increasing impact on reservoir pressure. A water injection strategy was implemented aimed at sustaining reservoir pressure. The volume of water injected replenished the voidage and contributed to a gradual rise of the reservoir pressure (Fig. 2). A reservoir pressure of 5800 psi is being maintained to lift the high watercut wells. The producing wells were completed bottom up, and as these intervals watered out shallower intervals were perforated. In 1984, drilling was suspended after a total of 23 development wells had been drilled and the oil production potential was well in excess of the surface facilities' capacities. Plateau oil production of 165 000 BOPD oil was reached in mid-1987 along with gas export of 88 M M S C F D starting in mid-1986. Activity re-conamenced in 1988 by the drilling of five more crestal producers and additional perforations on the Ribble Sands,
THE FULMAR FIELD
565 9
8
9
_o
9
o 9
[..
9
O
+,a
~
566
O. K U H N E T A L .
Z~
o
THE FULMAR
FIELD
567
O
S
,._J" . ,,....,
9
O
8
.s
r.,r
y, b" ca~
o .i.,.a 9
,xZ . ,,...~
8 r.m
.v
568
O. K U H N E T AL.
o~
o o~ r
.-~8=
. ,.... 0"~
~
~.~
~
~.~ =2e~ ~ o
0
0
"~ ~
.s ~ .~
9w
~
r~ ~
m
~~~
2
~
THE FULMAR FIELD in an effort to sustain the oil production plateau as the watercut and GOR started to rise. The plateau was thus maintained until 1991. Oil production finally came off plateau as the watercut and the GOR increased due to back-production of the secondary gas cap into the gas-constrained facilities. To improve seismic imaging to assist in the further development, a second 3D seismic survey was shot in 1992 as part of the BP-operated Fulmar-Clyde survey. Figure 3 shows the current Top Fulmar Main Sands depth map which is based on an interpretation of the reprocessed 3D seismic data from 1992. Since 1991, an additional six wells/sidetracks have been drilled (five vertical/deviated crestal Fulmar Main Sand producers, one highly deviated eastern flank Clyde Sand producer). To increase and optimize oil production, various wells were reperforated in levels which contained bypassed oil. Oil production has subsequently declined, and at the end of 1999 the field was producing around 7800 BOPD of oil and 100 500 BBL/day of water (92.8% watercut). The high recovery factor (69%) of the field is thought to be linked to the combination of well density, the large length of reservoir perforated, excellent reservoir quality, continuous sweep by water injection, and the highly efficient pressure support and oil stripping from a secondary gas cap formed early in field life. The current development strategy of the field has changed little from that initially envisaged. It remains focused at continuing water injection to increase the reservoir pressure and to maximize oil production, no longer assisted by natural gas lift. Water injection performance is therefore crucial to the current development, as the reservoir pressure needs to be sufficiently high to sustain production from high watercut wells. Figure 4 shows the changes in the base case assumption on inplace volumes, ultimate recovery estimate and cumulative production. From these data it becomes apparent that the availability of the original 3D seismic data had a large impact on field volumetrics in the pre-development drilling phase. The reduction of STOIIP between 1978 and 1984 is mainly due to the results of the development campaign which included the drilling of 24 wells, which tied-down the structure and discovered a shallower OWC in the north of the field. Later acquisition of a new 3D data set, 4D reinterpretation, major reviews of geology, stratigraphy and petrophysical properties did not change this picture drastically. The history of ultimate recovery estimate in early field life is driven by a reduction in volumetric estimation (see above). The increase of ultimate recovery estimate from 1989 to 1993, however, is linked to the first generation of a 3D dynamic simulation in combination with the incoming production data indicating a much higher recovery factor than anticipated earlier. The latest reviews of field structure, stratigraphical correlation, and the most recent generation of 3D static and dynamic simulation have not significantely modified STOIIP or U R estimates.
569
of prograding to aggrading shoreface systems in the later phase of deposition of the Fulmar Main Sands. This phase is followed by rapid movement along the Auk Horst Boundary Fault, and tilting of Fulmar block during deposition of the Kimmeridge Clay. This tectonic pulse is partially responsible for the rapid deepening and the change from shallow marine deposition of the Fulmar Formation to the deep marine Kimmeridge Clay Formation. The seismic data indicate the presence of an antithetic, large offset fault at Top Zechstein and Top Triassic level, extending into the Jurassic sequence (Figs 5 & 7). This major feature runs S E - N W underneath the Fulmar A platform, forming a graben structure with the Auk Horst Boundary Fault. This fault system controlled the accumulation and facies development of the Fulmar Formation, dividing an area of rapid accumulation of more proximal stacked sands in the west of the Fulmar Field from an area of slower accumulation and more distal facies in the east. This control on sedimentation is exemplified by the shallowest stratigraphic unit of the Fulmar Formation (Unit 3), which is divided into a thick homogeneous Mersey facies on the west side of the fault and a transition into the thinner, heterogeneous more distal Clyde facies on the eastern side. The position of this reactivated basement fault coincides with the depositional feature referred to as the 'hinge line' in previous studies (Stockbridge & Gray 1991). A second similar, but smaller-scale, fault runs S E - N W along the western flank of the field, and could be responsible for facies change in the Ribble Sands unit. Figure 7 shows the Top Zechstein fault pattern (c. 12 500-13000 ft TVDss) and the isochore maps of stratigraphic Units 5 4, 3 and 1.1. The development of isochore patterns and facies are directly linked to the basement fault pattern. Three major fault orientations are observed to occur within the Fulmar Field. The Fulmar Formation in the southwest part of the field is cut by a series of N W - S E trending, normal faults, synthetic and antithetic to the Auk Horst Boundary Fault. In the northeast and eastern areas, an E N E - W S W fault system occurs. In the north the faults show an E-W, north-dipping orientation. These three fault orientations demarcate the triangular shape of the Fulmar Field (Fig. 3). An almost identical fault pattern is present on Top Zechstein level (Fig. 7). Most of the fault activity is pre-Cretaceous and linked to rifting, salt withdrawal and the rotation of the whole Fulmar block. Hence the amount of fault throw mapped on Top Reservoir in the northeast and north of the field where the Base Cretaceous Unconformity truncates the Jurassic sequence does not represent the true faulting within the reservoir section. Unfortunately, the quality of the 3D seismic data available still does not resolve the internal faulting in the reservoir. Because of this truncation, fault throws are expected to be larger within the Fulmar succession than mapped at Top Reservoir. This leads to a considerable structural uncertainty for any further development in the northern and north-eastern area.
Structure Fulmar Field Structure
Trap mechanism and hydrocarbons
The Fulmar Field is a small (11.3 kin2), triangular domal anticline (Fig. 3). It lies on a fault bounded terrace, within the western margin of the South West Central Graben, adjacent to the Auk Horst, at depths between 9900 TVDss and 11 500 ft TVDss. The west flank of the field dips steeply at 25~ elsewhere dips are less than 12~ Figure 5 shows a geological cross-section of the Fulmar Field. The Fulmar Field has been shaped by three major tectonic processes: (1) halokinesis, (2) syndepositional reactivation of Caledonian basement faults; and (3) syn- through post-depositional vertical displacement along the Auk Horst Boundary Fault. Figure 6 shows an interpretation of the structural history of the Fulmar Field. Two major pulses of tectonic activity are identified, next to the more gradual processes of salt withdrawal and regional subsidence. First, the reactivation of basement faults leading to a small graben system underneath the field area during the deposition of the Lydell and Mersey Units. This tectonic pulse is responsible for the change
The Fulmar Formation sandstones are overlain conformably by Kimmeridge Clay Formation shales, which provide the seal in the south and west. To the north and east there is progressive truncation of the reservoir, which is unconformably sealed by Upper Cretaceous Chalk. The mature, organic-rich (average T O C = 5 % ) shales of the Kimmeridge Clay Formation are the source of the oil in the Fulmar Field. Oil migration occurred during the early to middle Tertiary from the deeper parts of the Central Graben. Two different OWCs were identified in the Fulmar Main Sands during the initial development phase: a shallow contact placed at 10590ft TVDss seen in the north, and a deeper contact placed at 10 840 ft TVDss in the main part of the field (Fig. 3). The shallow OWC in the north of the field appears to be restricted to a faultbounded block. This OWC is interpreted as a perched contact resulting from a combination of fault juxtaposition of reservoir
570
O. K U H N E T A L .
Fig. 6. Schematic interpretation of the structural history of the Fulmar Field (not to scale).
THE F U L M A R FIELD
571
Fig. 7. Basement (Top Zechstein) fault pattern and isochores (from well control) of Unit 1 (Ribble Sands), Unit 3 (Mersey/Clyde Sands), Unit 4 (Lydell Sands) and Unit 5 (Usk Sands). A strong correlation of basement fault pattern and sediment stacking is observed in Units 1 to 4. The Lower Fulmar Units (5 and 6), which onlap the Triassic topography, do not show a link to basement faulting.
572
O.
KUHN
E T AL.
e,
2
9
9
9
......
,~. +..a
a. 2
t'-q r
i
Z
.~
THE FULMAR FIELD sands (northern area) against non-reservoir lithologies (main field area) and the restricted northerly extent of the reservoir sands due to deterioration in reservoir quality and erosion by the Chalk. The resultant 'perched water' model allows communication through the oil column. In general, the faults within the Fulmar Main Sands are not considered to be sealing, as shown by the field performance history and by the relatively uniform sweep that has occurred on the highly faulted western flank of the field. Some faults, however, are known to seal at deeper levels in the Fulmar Main Sands (Usk) where the sands are of much poorer quality and production reservoir intervals are thin. The OWC in the Ribble Sands occurs at 10 875 ft TVDss which is 45 ft deeper than that in the Main Sands units.
Lithology and depositional environment The Fulmar Formation comprises a stacked sequence of very fineto medium-grained, moderate- to well-sorted sandstones that were deposited in a shallow marine environment. In general, the sandstones are massive as a result of intense bioturbation or soft sediment deformation, but locally cross-bedding and ripples are preserved. Historically, the lack of any features of emergence and associated coastal plain sediments threw doubt on whether the Fulrnar Main Sands comprised shoreface or shelf sediments (Johnson et al. 1986). In the late 1980s the shelf setting was preferred and the largescale coarsening upwards sequences that are clearly depicted on the logs (Figs 8 & 13) were interpreted as regressive cycles representing the stacking of a complex series of offshore sand ridges separated by thin, transgressive intervals of poorer reservoir quality sands (Van der Helm et al. 1990; Stockbridge & Gray 1991). In a more recent study however, the Fulmar Main Sands were interpreted to locally comprise upper shoreface sediments; this points to deposition under intermediate wave energy conditions and is more likely to occur in an attached shoreface setting (Spaak et al. 1999). The absence of associated coastal plain deposits is explained by the position of the Fulmar Field directly adjacent to a footwall high. Sediment input into the area is assumed to be via a relay ramp located to the southeast. In these transfer zones the occurrence of attached coastal plain facies is considered to be more likely. These sediments were then redistributed by longshore currents and accumulated in the hangingwall trough. This re-interpretation of the Fulmar Main Sands as an interval of stacked shorefaces is in keeping with recent interpretations of similar Jurassic Fulmar sequences in the literature (Gowland 1996; Howell et al. 1996). Although the shoreface depositional model is now preferred, it is not considered to have a significant impact on the validity of the pre-existing lithostratigraphic correlation which was based on the shelf model. This is because the sediments deposited in both shelf and shoreface sequences are governed by the same depositional processes and in many respects the correlations of facies transitions in both these settings could, in practice, be the same. The Avon Shale covers the Fulmar Main Sands in the southwest and the crest of the field. Although the bulk of the Avon Shale is considered to be offshore facies, the presence of lenses of flaserbedded silt or fine-grained sands indicate its proximity to a detrital source. The Ribble sequence consists of up to 200 ft of sand-rich turbidites interlayered with shaley units. The turbiditic sand-bodies are sheet-like in character and are hence correlatable between the wells. These turbidites were deposited in an actively subsiding, structurally controlled submarine depression. From the thickness trends visible on isochore maps, the source of the material might either be the Auk platform and/or adjacent shorefaces, or an unknown source in the north. In wells along the southwest flank of the Fulmar structure, units comprising biogenically reworked silty sands (non- to poor reservoir quality) are present at the base and/or the top of the Ribble turbidites. The ichnofacies as well as its sedimentological features indicate a distal shoreface position. Biostratigraphic data show that these silty sands are similar in age to the Ribble turbidites. The distribution of this facies coincides with a structural discontinuity in the Zechstein and the Triassic (see
573
above), and might be linked to a rapid bathymetric change due to synsedimentary faulting.
Stratigraphy Lithostratigraphy
A major reservoir geological review was undertaken in 1988, which formed the basis for the reservoir correlation and a lithostratigraphic subdivision (summarized in Van der Helm et al. 1990). The subdivision and correlation were based on core and log character, and variations in net/gross (N/G) and reservoir quality (Figs 8 & 9). On the eastern flank of the field these lithostratigraphic variations could be traced with confidence; however, in the central and western parts of the field, where the reservoir consists of a stacked interval of high N/G sands these sequences are not well expressed and the correlation is considered tentative. Figure 9 shows a synthetic stratigraphical profile with the tithostratigraphic subdivision and an interpretation of depositional environment and sequence stratigraphy (see below). The Fulmar reservoir was originally subdivided into six members named after British rivers and based on the F U L M A R mnemonic. These are called, from the base: Forth (Unit 6), Usk (Unit 5), Lydell (Unit 4), Mersey (Unit 3), Avon (Unit 1.2) and Ribble (Unit 1.1). A seventh, the Clyde member (formerly Unit 2 now incorporated into Unit 3) is found in the east of the field and is a shaley equivalent of the Mersey member. These units are further subdivided into 24 correlatable reservoir sub-units (cf. Fig. 9). These units onlap onto greenish to reddish shales and fine-grained silts and sands of the Triassic Smith Bank Formation. The Triassic in the eastern side of the field is more sand/silt rich whereas the west contains more shaley intervals. This difference in facies expression is thought to be linked to the angular relationship of the Triassic subcrop with the onlapping Jurassic. In the west of the field the reservoir succession is conformably covered with a thick succession of Kimmeridge Clay Formation, whereas in the northeast of the field the reservoir interval is unconformably overlain by the Chalk Group due to the progressive truncation by the Base Cretaceous Unconformity. Figure 8 shows a S W - N E stratigraphical correlation through some of the key Fulmar Field wells.
Unit 1.1 (Ribble Sands). The Ribble Sands comprise an interval of turbiditic sandstone up to 200 ft thick intercalated between the deep marine Avon Shale and Kimmeridge Clay Formation. Two different facies developments are identified from core material and logs. In the western flank and on the crest of the Fulmar Field, the Ribble Sands comprise turbiditic massflow sands (Sub-units 1.1b, 1.1 d, 1.1 e), with intercalated laterally continuous shaley beds (Subunit 1. lc) and calcitic or dolomitic cement layers. Reservoir quality of the massflow sands is very good ( ~ = 2 0 - 3 0 % , K h = 3 0 0 6000roD). These mass-flow sub-units can be correlated between wells. Sub-units 1.1.e and d are only deposited along the axis of a topographical low oriented NW-SE, whereas Sub-unit 1.1b shows a broader distribution, also towards the east. The sub-units themselves consist of several turbiditic sand beds and interbedded thin shale packages, which show a similar facies to the Avon Shale. Amalgamation of individual turbidites, and mud/sand couplets, are the only identifiable sedimentological features in these sub-units. No pressure differentials are observed over the shales or cemented layers. The turbiditic Ribble Sands are thickest in the west and south of the field (c. 170 ft) and get thinner (c. 10-20 ft) towards the crest. The thickness reduction towards the crest can partly be explained by a combination of (1) depositional pinching-out of the turbiditic sand units; and (2) erosion of the Top Ribble by an intra Kimmeridge Clay unconformity. Such an intra Kimmeridge Clay unconformity intersecting with Top Ribble is observed in the 3D data set. Similar erosive unconformities were observed in the Kimmeridge Clay in other areas in the Jurassic of the North Sea, and in
574
O. KUHN ET AL.
Fig. 9. Chronostratigraphic diagram scaled by sequence (e.g. all sequences are allocated equal duration, although it is known that this is not the case) illustrating the development of the Fulmar Field area along an approximate SW-NE line. Reservoir sub-units and gross sedimentary facies are also indicated (modified after Stockbridge & Gray 1991).
Fulmar can be explained as synrift unconformities linked to the rotational tilt of the hanging wall (Ravn~ts & Steel 1998). In the westernmost down flank wells, and probably present even further west, Ribble Sands are developed as biogenically reworked fine-grained distal shoreface silts and sands (Sub-units 1.1a, Subunits 1.l f) with poor to moderate reservoir quality ( ~ - - 1 5 - 2 0 % , Kh > 150mD). This so-called Ribble shoreface-facies consists of strongly bioturbated, greyish fine-grained sands to silt with white, spherulitic chert concretions. The ichnofacies identified in this facies is typical for distal shoreface sediments. Extensive interpretation and correlation of the available core and log data indicate that this facies interfingers with the massflow deposits. In the southwest and the west part of the field only distal shoreface type facies are developed, while towards the east the distal shoreface sand is also present at both the base (Sub-unit 1.1 f) and the top (Sub-unit 1.1 a) of the turbiditic units. It is difficult to resolve the close intercalation of the Ribble shoreface-facies with the deeper marine turbiditic Ribble Sands, but the evidence points to either localized deposition of shoreface sands on adjacent fault controlled topographical highs or possible reworking of massflow emplaced sands during periods of quiescence in the basin. This facies change from massflow deposits to distal shoreface sands and silts takes place in less than 1 km, indicating a strong topographic control on facies development. The facies change parallels the orientation of the major tectonic elements in the area
(e.g. Auk Horst Boundary Fault, faults visible at Top Zechstein). Palynological data indicate that both the Ribble shoreface facies and the turbiditic facies are probably deposited within the same biostratigraphic zone. A more detailed description and interpretation of the sedimentology and stratigraphy of the Ribble Sands can be found in Robinson (1990).
Unit 1.2 (Avon Shale). The Avon Shale forms a northeast thinning wedge (133ft to Oft isochore) that was deposited on top of the Fulmar Formation. The contact between the formations is very sharp. No visible signs of condensed deposition or reworking occur. The Avon Shale succession consists of dark grey to black clays interbedded with lenticular to flaser silt/sand layers, interpreted as fine-grained, distal turbidites. Syndepositional tectonic features occur throughout the succession. Some wells show zones of strong synsedimentary brecciation of this unit, which is thought to be linked to the ongoing rapid movement on the Auk Horst Boundary Fault. The top of the Avon Shale is increasingly sandy and more bioturbated. Unit 3 (Mersey Sands~Clyde Sands). The Mersey Sands/Clyde Sands form the uppermost of the coarsening upward cycles seen within the Fulmar Formation. The majority of the Unit 3
THE FULMAR FIELD succession is deposited in a lower to upper shoreface setting. The unit is divided into five sub-units (3.1, 3.2, 3.3, 3.4 and 3.5). These sub-units are laterally extensive. Unit 3 reaches a maximum thickness of 800 ft in the western part of the field. The thickness of Unit 3 is reduced to approximately 100 to 150 ft to the northeast of the 'hinge line'. In the northeastern and eastern parts of the field, Unit 3 starts with the shaley to silty interval of Sub-unit 3.5. From lithological and ichnological data it is concluded that Sub-unit 3.5 was deposited in an offshore transition zone environment. Sub-unit 3.5 is also associated with a small pressure discontinuity in certain parts of the field and constitutes a vertical permeability barrier (Fig. 13). In the central and western parts of the field however, the deposition of a sand rich sequence continued uninterrupted from the underlying Lydell into the overlying Mersey Sands. The overlying Mersey Sub-units 3.4 to 3.1 comprise a homogeneous interval of stacked small scale coarsening upwards sequences. The top of the succession (Sub-unit 3.1) shows the shallowest depositional environment (upper shoreface). Sub-units 3.2 and 3.4 are both thickly bedded, homogeneous, strongly bioturbated intervals, with the occasional presence of cross-stratified intervals indicating higher depositional energy. Sub-unit 3.3 is a highly heterogeneous interval separating the good quality Sub-units 3.2 and 3.4. This interval is much more intensively cemented (mostly chert), and fractured than Sub-units 3.2 and 3.4. Nevertheless, RFT data show that the whole interval between Sub-units 3.4 and 3.1 is in full pressure communication. Unit 3 is thickest in the western part of the field where the sands are generally of excellent reservoir quality (~ = 20-25%, Kh = 500-2000 roD). Towards the crest of the field the Mersey interval thins, grain size diminishes and the interval becomes increasingly shalier, marking the transition into the laterally equivalent but more distal Clyde facies. The Clyde facies comprises a heterogeneous sequence of very fine- to fine-grained argillaceous sandstones with interbedded cemented layers (chert, carbonate) and brecciated units. The change from Mersey to Clyde facies coincides with an important structural lineament in the basement, and is interpreted to reflect a tectonic control over facies development. Porosities in the Clyde facies typically average 20% and permeabilities are in the order of typically 5-20 mD. Traced to the north the Clyde Sands are eroded at the Base Cretaceous Unconformity.
Unit 4 (Lydell Sands). The Lydell Sands form the most extensive stratigraphic unit in the Fulmar Field. Unit 4 is subdivided into three sub-units (4.1a, 4.1b, 4.2) based on core and log character. The Lydell Unit comprises up to 430ft of thick homogenous, intensely bioturbated shoreface sands, which contain various radioactive layers in the lower part of the succession. The whole cycle represents a coarsening upward trend. Sub-unit 4.2 (max. 50 ft) is a heterogeneous, dolomitic and slightly clayey unit that occurs at the base of Unit 4 in the crest and the northeast of the field. The thickness of Sub-unit 4.2 does not vary significantly, but the log expression (unchanged gamma ray log, decreased density) changes towards the east, suggesting more intense cementation in the more offshore, basinal direction. Unit 4.1 (max. 400 ft) is composed of thickly bedded, bioturbated, fine- to medium- (eventually coarse) grained sandstones with occasional micro-conglomeratic layers. Unit 4.1 is divided into two sub-units with different log response. Sub-unit 4. la is a homogeneous shoreface sand with rather uniform G R response, whereas 4.1b contains various GR-spikes. The depocentre of Unit 4 is shifted 0.5 to 1 km towards the southwest, when compared with that of the underlying units, and shifted slightly towards the northeast if compared to that seen in Unit 3. Towards the west of that line the thickness decreases from >350ft to Oft in 0.5 to 1 km, once again indicating a strong topographic control on its deposition (e.g. through synsedimentary reactivation of palaeo-faults). Unit 5 (Usk Sands). The Usk Sands comprise a relatively thin (max. 350ft) and heterogeneous package of the Fulmar Main Sands. The individual sub-units show good lateral correlatability
575
throughout the extent of Unit 5. The Usk Sands (Unit 5) are subdivided into three main sub-units (5.3, 5.2, 5.1) which are then further divided (5.3a, 5.3b, 5.2a, 5.2.b, 5.2c, 5.1). The Usk sub-units occur as sheet-like layers with high correlatability in the crestal and eastern part of the field. Towards the west the sub-units pinch-out rapidly along a more or less straight line between wells FT-02S3 to FA-30. Some wells located in the zone where the Usk sands pinchout show a condensed Usk succession, without the characteristic coarsening upwards cycles that occur to the east of that line. Sub-unit 5.1 is a heterogeneous succession of fine- to mediumgrained, homogeneous, bioturbated sands and occasional coarsegrained upper to middle shoreface sands with parallel lamination or cross bedding and occasional pebble lags. The Sub-unit 5.1 is neither clearly fining nor coarsening upwards. It contains clayey or silty beds intercalated and cemented intervals. A very distinctive dolomite cemented zone occurs in most of the wells in the mid part of Sub-unit 5.1. This cemented interval is 5 to 10ft thick. Sub-unit 5.2 is a very distinct succession (max. 170ft) of poor reservoir quality rocks (~ = 10-20%, K h = 0 . 5 - 5 0 m D ) intercalated between the good quality sandy intervals of Sub-units 5.3 and 5.1. Overall, Sub-unit 5.2 can be described as a fining upward cycle. In this study Sub-unit 5.2 is further divided into 5.2a, 5.2b and 5.2c, which can be correlated in the eastern and the crestal part of the field; however, the correlation to the western flank is tentative. Sub-units 5.2c (max. 60 ft) and 5.2b (max. 60 ft) are coarsening upwards cycles, whereas 5.2a (max. 40 ft) is a fining upwards cycle. Sub-units 5.2c and 5.2b are characterized by homogeneous, strongly bioturbated, fine-grained sands (lower shoreface), with little vertical lithological change. Sub-unit 5.2a is a dark grey, strongly bioturbated to partially laminated, silty claystone (transition zone facies). This Sub-unit is missing in the western area of the field and its thickness increases towards the east. The most important sedimentological features which occur in Sub-unit 5.2a are thin, homogeneous, and fine- to medium-grained sand layers. Available porosity and permeability data from core material from these layers indicate a much better reservoir quality rocks (~5 = 2025%, K h = 5 0 0 - 1 0 0 0 m D ) than the underlying distal shoreface sands of Sub-units 5.2b and 5.2c. These layers are most easily explained as storm beds. According to RFT data, the top of Subunit 5.2 (Sub-unit 5.2a) acts as an important pressure barrier in the crestal, north and eastern parts of the Fulmar Field. The transition from Sub-unit 5.2a into the middle to upper shoreface sands of Sub-unit 5.1 is abrupt on logs. Sub-unit 5.3 marks the top of the major coarsening upward cycle which starts with the deposition of the transition zone claystones of the Forth Unit. Sub-unit 5.3 reaches a maximum thickness of 90 ft and is easy to correlate in the crestal area, the north and the east of the field. Sub-unit 5.3b, which is missing in the western part of the field, becomes increasingly thicker towards the east, whereas Sub-unit 5.3a becomes thinner. Hence this unit can be best interpreted as a progradation of shoreface sands in a basinal direction over offshore mud.
Unit 6 (Forth Sands). The non-reservoir Unit 6 is generally characterized as a coarsening upward cycle (max. thickness 260 ft). It is subdivided into Sub-units 6.1 and 6.2, which themselves are small-scale coarsening upwards cycles. Due to the fact that Unit 6 is not a reservoir rock, the two sub-units are not discussed individually. Unit 6 consists of heavily bioturbated clay-rich silts to very fine-grained sands. The facies can be classified as offshore transition zone. Unit 6 is thickest in the northeast part of the field and wedges out towards the southwest along a N W - S E line between FT-02S3 and FA-30. The base of the Forth Sub-units 6.1 and 6.2 are marked by a series of reworked and strongly condensed glauconitic (rarely phosphoritic) layers. In well FA-30, greenish, rounded, clay clasts (< 1 cm), with a similar facies to the underlying Triassic are found in these layers. These pebbles or rip-up clasts can be interpreted as relicts of a transgressive lag. Dispersed glauconite occurs throughout Unit 6. Due to the condensation and reworking of older material, all biostratigraphic data must be used with care.
576
o. KUHN E T AL.
Biostratigraphy
Recently, all available biostratigraphic data were critically reviewed, resulting in an improved calibration of the Jurassic succession. Figure 9 shows the synthesized lithostratigraphic, biostratigraphic, and sequence stratigraphic matrix. The recovered palynological floras from the Ribble Sandstone unit (Unit 1.1) and Avon Shale unit (Unit 1.2) indicate a 'late' Kimmeridgian age (Autissiodoriensis to Eudoxus ammonite zone). The palynological signature of the
'Avon Shale' is typified by the influx of the dinocyst Perisseiasphaeridium pannosum regionally correlated to the Eudoxus ammonite zone and the corresponding UJ8.2b Peak Pannosum maximum flooding surface (mfs) (Duxbury et al. 1999; Eudoxus mfs sensu Partington et al. 1993). The main Fulmar succession, particularly the Mersey and Clyde Sands (Unit 3), is sand dominated with low amounts of silt-sized sediment, dramatically reducing the amount of recoverable fossils in some wells/samples. Despite this, the interval can be dated as Mutabilis to Eudoxus ammonite zones in wells with
Fig. 10. Schematic depositional history for the Jurassic succession in the Fuhnar Field. TST = Transgressive Systems Tract, HST = Highstand Systems Tract.
THE FULMAR FIELD better data quality. This, together with the confident calibration of the Ribble Sands and the Avon Shale, makes it most likely that the deposition of Unit 3 (Mersey and Clyde) extended from Mutabilis to the basal Eudoxus ammonite zones. The Lydell Sands (Unit 4) are similarly sandy and the recovered floras indicate an age range of Cymodoce to Mutabilis ammonite zones. The Usk Sands (Unit 5) have yielded floras indicating a lowermost Kimmeridgian, Baylei ammonite zone age. The palynofloral assemblages recovered from the shaley Sub-unit 5.2a provide good evidence for the presence of the U J7 Jurassica mfs (Duxbury et al. 1999, aka Baylei mfs of Partington et al. 1993; m f s = m a x i m u m flooding surface). The underlying Forth Sands (Unit 6) have yielded assemblages indicating a late Oxfordian age (Serratum (pars) to Rosenkrantzi ammonite zones). From the distribution of the different ages v. thickness of sediments, it can be seen that the base of the Fulmar Formation (Usk and Forth Sands) is condensed (late Oxfordian to early Kimmeridgian; max. 260 ft). This conclusion matches well with the presence of glauconitic and phosphoritic horizons, and the thinbedded character of these units. It can also be seen from the distribution of ages interpreted from the base of the Fulmar succession that the shoreface progressively backsteps towards the Auk Terrace.
Sequence Stratigraphy 1 Based on the current chronostratigraphic calibration, the Fulmar Formation can be subdivided into four regional (3rd order) sequences (sensu Vail et al. 1977), the oldest sequence being the Late Oxfordian UJ6 (Cladophora) sequence (Duxbury et al. 1999) and the youngest being the transgressive (and lowstand - although not identified in the current succession) systems tract of the Kimmeridgian UJS.2 (Peak Pannosum) sequencefl The Avon Shale, Ribble Sands and the lower part of the overlying Kimmeridge Clay encompass the mfs and HST of UJS.2 Peak Pannosum sequence. Figure 9 shows a chronostratigraphical synthesis. Figure 10 illustrates an interpretation of the depositional history of the Jurassic succession in the Fulmar Field area. Sequence 1 : U J 6 (Cladophora) sequence 3 - Late Oxfordian (Serratum (pars) to Rosenkrantzi ammonite zones). The oldest sequence is developed as a coarsening upward cycle starting with the argillaceous, very fine-grained sandstones of the Forth Sands (Sub-units 6.1 and 6.2). These pass upward into well sorted, clean sandstones (middle shoreface facies) of the Lower Usk Sands (Subunit 5.3). The presence of Triassic rip-up clasts incorporated at the very base of Sequence U J6 is evidence in support of this sequence marking the initial Jurassic marine transgression over the Triassic subcrop. The available biostratigraphic data indicate the age of this initial transgression as being shortly after the late Oxfordian 'U J6 sequence boundary '4. The U J6 sequence reaches a maximum thickness of 350 ft in the east of the Fulmar Field. However, to the west the sequence appears to onlap the Triassic and finally wedge out
1For the purposes of this paper sequence stratigraphic terminology refers to the published scheme of Duxbury et al. (1999). The scheme itself has been calibrated and where necessary adapted to conform with the Shell in-house scheme. Footnotes are provided to clarify any adaptations. 2 It should be noted that the in-house Shell 3rd order sequence stratigraphy does not recognize the presence of an extra sequence of Autissiodoriensis age as in the Duxbury scheme [UJ9.1 Crassinervum sequence]. Therefore, the usage herein of UJ8.2 Peak Pannosum sequence is sensu lato including the age interval covered by Duxbury's UJ8.2 and UJ9.1. 3 The usage of sequence UJ6 herein has been adapted to the shell in-house scheme and is used sensu lato. The interval covered by sequence UJ6 herein includes sequences UJ6a, UJ6b, and possibly some of U J5 (although this may be a calibration feature rather than anything else). 4 Note that in Duxbury et al. (1999) no terminology is used for the lower bounding surface of each sequence. Herein the lower bounding surface of a sequence is named after alpha-numeric representation of its corresponding contained maximum flooding surface.
577
completely towards the Auk Terrace along an approximate N W SE line running from well FT-02s3 to FT-01sl. The top surface of Sub-unit 5.3 is correlated to the UJ7 Jurassica sequence boundary, marking the upper limit of the U J6 Cladophora sequence. Sequence 2. UJ7 (Jurassica) sequence- Earliest Kimmeridgian (Baylei to Cymodoce ammonite zones). Increasing relative sea level resulting in the second transgressive event recorded in the Fulmar Formation is exemplified by the fining upwards cycle of the middle Usk (Sub-units 5.2a-c). The uppermost Sub-unit, 5.2a, comprises offshore shaley facies with intercalated mass flow beds (storm sands), interpreted to represent a maximum flooding surface. Sub-unit 5.2a is assigned a Baylei ammonite zone age based on the recovered palynofloras, and is confidently interpreted to contain the U J7 Jurassica maximum flooding surface. The base of the succeeding highstand systems tract is marked by the rapid progradation of Sub-unit 5.1 (middle to upper shoreface sands). The succeeding UJ8.2a sequence boundary is most likely located at the top of Sub-unit 5.1 based on the available biostratigraphic evidence. The whole U J7 sequence reaches a maximum thickness of 600 ft in the crest of the Fulmar Field and wedges out completely towards the west. This sequence is progressively truncated towards the northeast by the Base Cretaceous Unconformity. In the southwestern part of the field, U J7 sediments directly overlie the Triassic subcrop providing clear evidence for progressive backstepping of the Fulmar shoreface system towards the basin margin. The U J7 Jurassica sequence can be subdivided into several Sub-units (5.2c, 5.2b, 5.2a, 5.1), which are in themselves smallerscale coarsening upwards cycles (4th/5 th order sequences or parasequence sets). Sequence 3." UJ8.2a (Rare Pannosum) sequence (?Cymodoce to Mutabilis ammonite zones). The UJ8.2a Rare Pannosum sequence is the youngest complete sequence developed entirely within the Fulmar Main Sands. The UJ8.2a Rare Pannosum sequence coincides with a change from a mainly prograding, to an aggrading shoreface system, and displays the greatest facies variations from a depocentre in the southwest to condensed successions in the northeast. These characteristics are most probably linked to an enforced syndepositional subsidence of a N W - S E oriented 'mini' graben system transecting Fulmar field due to reactivation of basement faults and probable remobilization of Zechstein salt (see Figs 7 & 10). In the northeastern and eastern parts of the field, tectonic overprint appears to be at its least significant. Here, the Lydell Sands (Sub-units 4.2-4.1a) are overlain by the shaley, basal Mersey Sub-unit 3.5, indicating a relative deepening in the palaeoenvironment at this time. Biostratigraphic evidence from FA-10sl and FT-04 indicates that Sub-unit 3.5 can be correlated to the UJ8.2a Rare Pannosum maximum flooding event (Mutabilis ammonite zone). This sub-unit, where present, is also associated with a small pressure discontinuity in the reservoir and comprises a vertical permeability barrier. In the subsiding 'mini' graben located in the central and western parts of the field however, the deposition of a tectonically enhanced sand-rich succession continued uninterrupted into the overlying Mersey Sands. Consequently, stratigraphic calibration/correlation in this area is not necessarily conformable with the assigned lithostratigraphic units (in contrast to the more eustatically driven lower sequences). The time equivalent of Sub-unit 3.5/UJ8.2a Rare Pannosum mfs is not clearly biostratigraphically or lithostratigraphically represented due to the high sediment input rates and tectonic overprint. However, using the available biostratigraphic data the UJ8.2a Rare Pannosum mfs can be tentatively calibrated to lie (in most instances) within the interval Sub-unit 4. lb to upper Sub-unit 4.1a. The placement of the succeeding UJ8.2b sequence boundary is similarly hampered by the tectonic overprint. It is most probably located within the Mersey unit at the base of Sub-unit 3.3, or less likely in the uppermost Sub-unit 3.4. The UJ8.2a sequence reaches a maximum thickness of 800 ft in the western part of the field.
578
O. KUHN ET AL.
Fig. ll. SW-NE cross-section through the 3D permeability model, showing (1) the vertical stacking of non-reservoir and reservoir rocks linked to progradation of shoreface sands and transgressive events leading to deposition of distal shoreface sands and silts or offshore muds and (2) the lateral interfingering of poor to excellent reservoir sands within a stratigraphic layer.
Sequence 4." UJS.2b (Peak Pannosum) sequence (Eudoxus to Autissiodoriensis ammonite zones) 5. The lower part of the UJ8.2b (Peak Pannosum) sequence is developed within the Mersey Sands (Sub-units 3.1 to 3.3) and comprises an interval of aggradationally stacked small scale coarsening upwards sequences deposited in a shallow marine environment. The coincident sequence boundary and initial flooding surface of UJ8.2b is most likely located at the base of Mersey Sub-unit 3.3. This sub-unit is interpreted herein as lower to middle shoreface, in contrast with the aggradational middle to upper shoreface units above (Sub-units 3.1 and 3.2) and below (Sub-unit 3.4). As stated above, the placement of this surface is quite difficult because of the tectonic overprint continuing into this sequence. Despite this, biostratigraphic calibration does strongly suggest that the surface is located within the Mersey unit; however, as lithostratigraphic character may vary laterally its precise placement within the reservoir unit scheme is not necessarily fixed. The Mersey Sands (which in the current interpretation include the uppermost sediments of sequence UJ8.2a Rare Pannosum) are thickest in the western part of the field where the sands are generally of excellent reservoir quality. Traced towards the crest the Mersey Sands interval thins and becomes increasingly shalier, passing laterally into the equivalent but more distal Clyde Sand facies. Well FA-10sl penetrates this facies succession (see correlation Fig. 8); limited biostratigraphic data from this well lend support to the calibra-tion of the UJP8.2b sequence boundary to the base of Sub-unit 3.3. Deposition of the Mersey Sands (the uppermost unit of the 'Fulmar Main Sands') was terminated by an apparent rapid deepening resulting in the deposition of the non-reservoir Avon Shale (Unit 1.2, offshore facies) unit. The Avon Shale succeeds the Fulmar
s See footnote 2.
Main Sands in all areas of the field where the section has not been truncated by the Base Cretaceous Unconformity. The main factor driving this rapid increase in relative sea level is unclear, but it is almost certainly a combination of tectonism and ongoing eustatic sea level rise. The common occurrence of thin lenses of flaser-bedded silts and fine-grained sandstones in these shales still indicates proximity to a detrital source. This characteristic separates the Avon Shale unit from the Kimmeridge Clay Formation sensu stricto where such clastics are normally absent. Biostratigraphic evidence clearly calibrates the UJ8.2b Peak Pannosum maximum flooding surface (Eudoxus mrs) to within the Avon Shale. The Avon Shale is overlain by the mass flow sands of the Ribble Sands (Unit 1.1). Based on palynological data the top of Unit 1.1 falls within the UJ8.2b Peak Pannosum sequence (intra Kimmeridgian).
Reservoir Reservoir quality and connectivity The most important controls on reservoir quality are the primary depositional textures, notably grain size, clay content and sorting. Minor controls are the limited lateral continuity of sands, particularly in the turbiditic Ribble Sands, as well as reduction of porosity and permeability by diagenetic cements and the presence of clay-lined fractures decreasing permeability. Controls on reservoir continuity comprise fault juxtaposition of reservoir against non-reservoir intervals. Two major pressure discontinuities are identified (Unit 1.2, Sub-unit 5.2a) in the Fulmar Field (Fig. 14). These two layers separate the reservoir into three main flow units (Ribble Sands, Upper Fulmar Main Sands, Lower Fulmar Main Sands). Less extensive vertical permeability barriers are the argillaceous Mersey Sands Sub-unit 3.5 and the Lydell Sands Sub-unit 4.2. Although these
THE FULMAR FIELD
579
Fig. 12. Basement (Top Zechstein) fault pattern and porosity contours of Unit 1 (Ribble Sands), Unit 3 (Mersey/Clyde Sands), Unit 4 (Lydell Sands) and Unit 5 (Usk Sands). Best reservoir quality rocks occur within the depocentres, subsequently rotated into the crest of the field.
units do not appear as continous pressure discontinuities they act as baffles in the field. The inter-turbidite shales in the Ribble (e.g. Subunit 1.1c) and the cemented layers distributed throughout the Fulmar Main Sands seem to be of minor importance, because of the limited lateral extent and/or fault juxtaposition.
Porosity and permeability Porosity and permeability in all Fulmar Field reservoir units are mainly controlled by sediment texture with finer-grained, more poorly sorted and clay-rich sediments tending to have lower
580
O. KUHN E T AL.
Table 2. Porosity, N/G, Kh field averages for the stratigraphic units in the Fulmar Field, established from log data Reservoir Unit
Field avg. por.
1.1 0.26 3.1 0.25 3.2 0.24 3.3 0.22 3.4 0.23 3.5 0.22 4 0.22 5.1 0.20 5.2a 0.17 5.2b, 5.2c 0.19 5.3 0.22 6 0.17
St dev.
Field avg. N/G
St dev.
Field avg. Kh
St dev.
0.027 0.033 0.028 0.036 0.032 0.032 0.022 0.021 0.006 0.011 0.023 0.006
0.822 0.990 0.998 0.961 0.988 0.563 0.999 0.980 0.920 0.988 0.999 0.161
0.093 0.021 0.011 0.140 0.142 0.360 0.001 0.032 0.160 0.040 0.061 0.180
1012 784 608 588* 595* 51 624 203 2.8 6.2 156 <0.5
318 631 367 510" 533* 113 347 239 1.86 2.08 8.15 329
* Clyde facies: average Kh = 10mD, standard deviation 5 mD. All averages presented are calculated as arithmetic averages and normalized for thickness variations within layers. These field averages are only valid for the rock volume above the OWC. permeabilities than coarser, better sorted, clay-poor sediments. This simple relationship is modified in the presence ofdiagenetic minerals. The gradual improvement in reservoir quality upwards within the formation reflects a general increase in grainsize and sorting, accompanying the aggradation and northeast progradation of shorefaces within the Fulmar Field in response to tectonic control. However, the lateral distributions of the rock properties for all the reservoir units also show areas of higher porosity and permeability in the crest of the field and decreasing values downflank (Fig. 11). This area of better reservoir quality generally stretches NW-SE. It has been found that the zone of highest porosity moves progressively towards the southwest vertically through the stratigraphy by approximately 1 km in total from the Usk to the Ribble unit (Fig. 12). The orientation of the zone of highest porosity always parallels the zone of greatest reservoir thickness, but never coincides with it (cf. Figs 7 & 12). Highest porosities are always shifted slightly towards the northeast. A similar observation is also made from the Fulmar Formation in the Clyde Field. Two processes can be responsible for the development of this feature: (1) primary changes in petrographic composition of the sediments due to trapping and accumulation of coarse grains in depocentres and/or increased winnowing of fine-grained particles in an exposed position and deposition of finer-grained particles towards the northeast in deeper water; or (2) development of areas of less cementation or increased dissolution (secondary porosity) above tectonic lineaments because of increased fluid circulation. Table 2 summarizes average properties for the individual reservoir layers.
locally concentrated authigenic minerals (calcite, dolomite, pyrite, feldspar, and predecessor minerals of chert). The most significant diagenetic mineral is dolomite. Early diagenetic quartz and feldspar overgrowths contribute only a very small amount to pore space reduction. Later on, deeper burial grain dissolution and minor illitization of feldspars occurred. The reservoir however has never been subject to severe clay authigenesis and therefore the sands have generally retained their excellent quality. No evidence of increased diagenesis in the water leg has been observed. Soft sediment deformation structures are present throughout the Fulmar Main Sands and are especially abundant in the Clyde Sands facies of Unit 3. These structures are associated with dewatering, and possibly reflect the tectonic instability of the area resulting from salt withdrawal and/or fault movements. In the homogeneous reservoir units the amount of secondary mouldic porosity is small and its effect on reservoir quality is negligible. In the heterogeneous intervals (Lower Usk, Clyde Sands facies of Unit 3 Ribble Sands), porosities in cemented levels can be highly affected by secondary mouldic porosity because of dissolution of sponge spicules. This porosity is isolated or poorly connected through thin sheet-like inter crystalline pores within the cement. As a result the permeabilities can be very low although porosities are high. Hence prediction of permeability from porosity logs in cemented layers is not straightforward.
Faults and fractures The Fulmar Field has been subjected to several phases of faulting which have combined to produce a complex and dense fault pattern. In general, however, production and R F T data indicate that the field is being drained as one unit and that no isolated, fault bounded blocks appear to exist. Some cores show clay smear over shear zones, indicating that at least in the shalier, reservoir units (Ribble, Usk) faults could possibly have sealing capacity. But crossfault juxtaposition of reservoir against non-reservoir is much more important in the Ribble and Usk Sands than clay smear. The majority of fractures observed in cores are attributed to syn- and early post-depositional deformation. Cores reveal that the complex and locally intense fracturing is mainly concentrated in the western and northeastern part of the field, which is interpreted to be related to salt removal and tectonic movement along faults. Fracturing has led to a reduction of permeability across the features, confirmed by mini-permeameter measurements. However, it is concluded that fractures may reduce permeability but only in a limited lateral extent and are not significant in affecting fluid flow.
Field reservoir zonation and determination of flow, non-flow units
Diagenesis Environment-related diagenesis includes precipitation of silica and carbonate cements, which were supplied by local concentrations of siliceous sponge and shell debris. Some of the carbonate cements (e.g. in Sub-unit 5.1) are present in the same stratigraphic position over wide areas, possibly linked to primary concentration of carbonate (shell material, early cements) in the sediment. Mouldic porosity is observed in the Ribble Sands as well as the Mersey/ Clyde units where sponge spicules have suffered leaching. This leads to the development of high porosities but low permeabilities in cemented layers. Some of these environmentally controlled cements can be correlated. However, they do not seem to affect reservoir performance, probably due to a combination of their low intensity and irregular distribution and sub seismic fault juxtaposition of non-cemented intervals against each other. The majority of diagenetic changes undergone by the sediments occurred during early burial. This early diagenesis is the result of rapid burial in a closed system and results in dispersed or
The Fulmar Field seems to have been in full pressure communication on a geological time scale. No pressure breaks are recorded in the pre-development R F T data. However, results from development drilling (Figs 8 & 13) show that specific reservoir intervals are better drained and more depleted than others. Because of this, any further development needs to be based on a thorough understanding of flow units and their characteristics within the reservoir. The most important stratigraphic feature in the Jurassic succession of the Fulmar Field which impacts on production is the intercalation of reservoir and non-reservoir units, which controls the fluid flow. The non-reservoir units are found to be highly correlatable and are interpreted to be maximum flooding surfaces (Spaak et al. 1999). The good quality reservoir sands intercalated between the maximum flooding surfaces are also found to be highly correlatable. The non-reservoir intervals in the field were initially determined from descriptions of the cored intervals. These intervals were then calibrated with the well logs to identify non-reservoir intervals in the non-cored wells, and from R F T data.
THE FULMAR FIELD
581
Fig. 13. Pressure data from FA-14; flooding events (Sub-units 5.2 and 3.5) on the eastern side of the field are clearly associated with RFT pressure breaks.
The first level non-flow units comprise Unit 6 (Forth Sands), Unit 1.2 (Avon Shale) and Sub-unit 5.2a (shaley interval in the Usk Sands). The two latter units form pressure breaks on the R F T logs and seem to be able to hold pressure differences of several hundredPSI during production (Figs 13 & 14). Although the three intervals are not continuous over the extent of the whole field (truncation, onlap), they seem to remain flow barriers (cf. RFT) along their extent. Large-scale faulting is necessary to juxtapose good quality reservoir levels above and below these. According to that the Fulmar Field is divided into three main flow units: the Ribble Sands, the upper Main Sands (including Mersey, Lydell, Upper Usk) and the lower Main Sands (Sub-units 5.2, 5.3). Second level flow barriers are Sub-units 3.5, 4.2 and 1.1f. These units can show different developments of reservoir quality from non-reservoir up to moderate reservoir. If at all, only small pressure breaks (less than 50 PSI) are observed over these intervals during production. The lateral extent of these units is much more limited
than those of the first level. Locally, these levels might form barriers or baffles to vertical flow, if they are thick and not faulted. The third level flow 'barriers' comprise either thin shales (e.g. Sub-units 1.1c interturbidite shale), correlatable cement streaks (e.g. cement streaks in Sub-units 3.3, 5.1, 5.2b; Clyde Sands). These non- or poor flow units are not able to completely isolate flow units from each other. No pressure jumps are associated with these intervals. They might act as baffles or could deviate fluid flow in certain directions. The reservoir intervals can be subdivided into three classes of flow units:
(1)
'Fast and homogeneous' flowing units (Sub-units 3.1, 3.2, 3.4, 4) which have porosities in excess of 22% (max. 30%), very high N / G values of the reservoir sands in the order of 0.99 to 1 and an average Kh > 600 mD. Core plug evaluation of these units shows that permeabilities do not vary significantly
582
O. K U H N E T AL.
(a)
(b)
Fig. 14. Pressure differentials across fieldwide transgressive units against time: (a) Pressure differential across the Avon Shale as recorded by RFT data of development wells (production, injection). The Ribble Sands are generally less depleted than the Fulmar Main Sands. Exceptions where Ribble has been found to be more depleted than Main Sands can bc explained by local effects of pressure support of the Main Sands through nearby water injectors or depletion of the Ribble through production via nearby wells. (b) Pressure differential across the Usk Sub-unit 5.2a as recorded by RFT data of development wells. The Lower Fulmar Main Sands (Usk Sub-units 5.2-5.3) are generally less depleted than the Upper Fulmar Main Sands (Mersey-Usk Sub-unit 5.1) (exceptions explained as above). No or small pressure differentials are recorded across Unit 3.5 and Unit 4.2.
vertically. K v / K h is expected to be high. Fluid flow in these units is considered to be h o m o g e n e o u s a n d predictable with a great degree of confidence. The vast p r o p o r t i o n of these units are currently flushed. The remaining reserves linked to these units occur either as 'residual' oil, m o v i n g slowly because of the relative permeabilities of oil/water, or in small attics in the crest of the field.
(2)
'Fast but heterogeneous' flow units (Sub-units 1.1, 3.3, 5.1, 5.3). Porosities within these sandy units vary between 20 to 26%, due to the occurrence of c e m e n t e d layers or thin argillaceous layers. N / G varies between 0.8 to 1 K h values lie in the range 50 to 600 roD; except for the extremely permeable turbiditic Ribble Sands with average permeabilities of 1000mD. Core plug evaluation of these units shows that the porosities
T H E F U L M A R FIELD
583
2 9
o
2
cq c~
9
9
d 9
9
9
9
(IqqlNIN) eOep!oA eA!lelnuJno - (P/jOSlNIN) uop, oe.fUl s e 9 - (%) ~,noJe~,e/~A- (Pllqq,o00~) e~,e~l l!O
9
584
(3)
O. KUHN E T AL. and permeabilities vary vertically due to effects of cementation, secondary porosity and clay content. K v / K h is expected to be lower than in the homogeneous layers. Fluid flow in these units is considered to be difficult to predict especially in the light of fault juxtaposition. Some of the remaining reserves are still trapped within stratigraphical intervals belonging to this type of flow unit in tectonically isolated compartments or in thin rims of oil beneath non-flow units. 'Slow' flow units (Clyde Sands facies, Usk Sands Sub-unit 5.2). Porosities within these fine-grained sands are in the order of 18 to 22%. N / G varies between 0.5 (heterogeneous Clyde Sands) and 0.99 (homogeneous Mid Usk Sands). K h values are low, in the order of 1 to 50 mD. According to the sedimentological analyses and core plug data, reservoir properties vary vertically and laterally, probably due to effects of diagenesis and grain size variations. Kv/Kh values are expected to be low. Fluid is considered to move extremely slowly in these units (diffuse flow). The results of recent well evaluation and drilling (FA-27sl, FA-18sl and FA-02sl) suggest that these reservoir intervals may be only slightly drained and hardly flushed to date.
Reserves and production Total field STOIIP is estimated to be 822 MMBBL, 83% of which is contained in the Mersey and Lydell Sands and a further 8% in the Ribble Sands. The large oil column, steeply dipping flanks, and favourable mobility ratio make the Fulmar Field very suitable for development by flank water injection and crestal production. A total of 42 development wells/sidetracks (including 13 water injectors and one gas injector) have been drilled. Figure 2 shows the Fulmar Field pressure history with annotated key events and Figure 15 shows a production history plot. Plateau oil production has been 165 000 BOPD, with associated gas production of 102 M M S C F D and water injection of 205 000 BOPD. By the end of 1999, 547 M M B B L of oil and 325 BSCF had been produced with 987 M M B B L water and 84 BSCF of gas injected. The ultimate recovery is estimated to be 567 MMBBL oil and 342 BSCF wet gas. This would bring the overall recovery factor from 66% at the end of 1999 to 69% at end of field life. Due to reservoir quality, faulting and sweep efficiency, the recovery factor varies between the different reservoir units. The Mersey and Lydell Sands together have a recovery factor of up to 78% whilst the Ribble Sands have a recovery factor of 70%, and the Usk Sands Sub-units 5.1, 5.2, 5.3 have recovery factors of 70%, 11% and 33 % respectively. Fulmar wells have been reperforated/recompleted from the bottom up when intervals watered out. In this way production was maintained at plateau levels until about 1991. Since then the total oil rates have declined while the watercut increased. Since early 1997 the oil rates have stabilized at approximately 8000 BOPD with a field watercut of 92%. The current production stems from (1) 'rinsing' the Upper Main Sands with injection water in order to get as close as possible to the residual oil saturation (currently estimated as 15-17%); (2) by-passed oil in crestal and Usk Sand compartments; and (3) smaller volumes in the Ribble Sands. Compartmentalization, together with the barrier formed by the Avon Shale, prevents direct injection water support to some of the Ribble wells and this explains the intermittent behaviour of these wells. Most of the secondary gas cap has been back-produced through the current producers although the G O R in the crestal wells is still above the natural GOR. The water injection strategy is aimed at maintaining reservoir pressure around 5800PSI at datum to provide the high watercut wells with sufficient lift. Field life is expected to last until 2008. The data and interpretations presented in this paper are the result of many years of study by Shell and Esso staff. Since the first edition of the Memoir in 1991 several geologists, petrophysicists and geophysicists have improved our understanding of the field. Certainly this summary would not be possible without the recent work of Janet Ahnond, Charly Ash, Peter
Spaak, Shamir Salahuddin, Zac Mood Salleh, Michel Gaillard and John Ashbridge. The authors wish to thank the management of Shell UK Exploration and Production, Esso Exploration and Production UK Ltd, BP Amoco Exploration Co., and Amerada Hess Ltd for permission to publish this paper. It should be noted that the interpretations presented are those of Shell and do not necessarily represent the views of all the field owners.
Fulmar Field data summary Trap
Type Depth to crest OWC
Oil column
Salt induced eroded anticline 9900 ft TVDss Main field area OOWC 10 840 ft TVDss Ribble OOWC 10 875 ft TVDss Northern area OOWC 10 590 ft TVDss 930 ft
Pay zone
Formation
Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average P~oductivity index
Fulmar Formation Kimmeridge Clay Formation (Ribble Sands) Oxfordian-Kimmeridgian Maximum Fulmar Formation 1200ft Average 94% Average 23%; Range 17-28% Average 500mD, Range 10-2000mD Average 79% Average 80 BOPD/psi
Petroleum
Oil density Oil type Viscosity Bubble point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
40~ API Undersaturated 0.42 cP 1800 psi 614 SCF/BBL 0.25 MMBBL/BSCF 1.43 RB/BBL 0.68 RB/BBL
Formation water
Salinity Resistivity
138 000 ppm NaCI equivalent 0.018 ohm m at 285~
Field characteristics
Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
2825 acres 877 500 acre-ft 5700psi at 10 500ft TVDss Oil: 0.29 psi/ft (0.64 gm/cc) Water: 0.45 psi/ft (1.10 gm/cc) 285~ at 10 500ft TVDss 822 MMBBL 498 BSCF 69% Water flood, natural gas lift 567 MMBBL 342 BSCF 59 MMBBL
Production
Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
February 1982 165 MBOPD 103 MMSCFD 28 oil wells 13 water injectors 1 gas injector
References DUX~URY, S., KADOLSKY,D. & JOHANSEN,S. 1999. Sequence stratigraphic subdivision of the Humber Group in the Outer Moray Firth (UKCS, North Sea). In: JONES, R. W. & SIMMONS,M. D. (eds) Biostratigraphy in Production and Development Geology. Geological Society, London, Special Publications, 152, 23-54.
THE F U L M A R FIELD GOWLAND, S. 1996. Facies characteristics and depositional model of highly bioturbated shallow marine siliclastic strata: an example from the Fulmar Formation (late Jurassic), UK Central Graben. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM,A. C. & MACKERTICH, D. S. (eds) Geology of the Humber Group." Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 185-214. HOWELL, J. A., FLINT, S. S. & HUNT, C. 1996. Sedimentological aspects of the Humber group (Upper Jurassic) of the South Central Graben, UK North Sea. Sedimentology, 43, 89-114. JOHNSON, H. D., MACKAY, T. A. & STEWART, D. J. 1986. The Fulmar OilField (CNS): geological aspects of its discovery, appraisal and development. Marine and Petroleum Geology, 3, 99-125. MEHENNI, M. & RODDENBURG, W. Y. 1990. Fulmar F i e l d - UK. South Central Graben, North Sea. In: B~AtrMONT, E. A. & FOSTER,N. H. (eds) Structural Traps IV. American Association of Petroleum Geologists, Treatise of Petroleum Geology, 113-139. PARTINGTON, M. A., COPESTAKE,P., MITCHENER, B. C. & UNDERHILL., J. C. 1993. Biostratigraphic calibration of genetic stratigraphic sequences in the Jurassic of the North Sea and adjacent areas. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th conference. Geological Society, London, 371-386. RAVNAS, R. & STEELE, R. J. 1998. Architecture of marine rift-basin successions. American Association of Petroleum Geologists. Bulletin, 82/1, 110-146.
585
ROBINSON, A. J. 1990. The sedimentology and stratigraphy of the Ribble Sandstone Member and related deposits, Fulmar Field, CNS, UK sector. MSc thesis, Aberdeeen University. SPAAK, P., ALMOND, J., SALAHUDIN, S., MOHD SALLEH, Z. & TOSUN, O. 1999. Fulmar: a mature field revisited. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of North West Europe: Proceedings of the 5th Conference. Geological Society, London, 1089-1100. STOCKBRIDGE, C. P. & GRAY, D. I. 1991. The Fulmar Field, Block 30/16 and 30/1 lb, UK North Sea. In: ABOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society Memoirs, 14, 309-316. VAIL, P. R., MITCHUM, R. M. & THOMPSON, S. 1977. Seismic stratigraphy and global changes of sea level. Part 4: Global cycles of relative changes of sea level. In." PAYTON, C. E. (ed.) Seismic Stratigraphy - Applications to Hydrocarbon Exploration. American Association of Petroleum Geologists, Memoirs, 26, 83 97. VAN DER HELM, A. A., GRAY, D. I., COOK, M. A. & SCHULTE, A. M. 1990. Fulmar: The development of a large North Sea Field. In: BULLER,A. T. et al. (eds) North Sea Oil and Gas Reservoirs' H. Graham & Trotman, London, 25-45.
The Maureen Field, Block 16/29a, UK Central North Sea PETER
M. C H A N D L E R 1 & B A R B A R A
DICKINSON
2
1Phillips Petroleum Company United Kingdom Ltd, 35 Guildford Road, Woking, Surrey GU22 7QT, UK Present address." East House, Threeways, Star Hill, Churt, Surrey GUIO 2 H W (e-mail: petermchandler @ aol.com) 2 Dickinson GeoConsulting, 51 Medfield Street, Roehampton, London SW5 4JY, UK Abstract: The Maureen Field comprises the Maureen, Mary and Morag accumulations, the reservoirs being Palaeocene sandstones, Upper Jurassic sandstones and Permian dolomites respectively. The field lies about 10kin NNE of the Moira Palaeocene field. Maureen was discovered in 1973, came on-stream in 1983 and produced 217.4 MMBBL (from an estimated STOIIP of 397 MMBBL). The field ceased production in October 1999. It is trapped in a four-way dip closure over a salt dome and sealed by the overlying Lista Formation mudstones. The reservoir is up to 450 ft gross thickness, with core porosity from 18-28% and good sand connectivity. Morag was discovered in 1979, came on-stream in 1991 and produced 2.6 MMBBL before being shut-in in 1994. It produced from clean fractured dolomites in a stratigraphic trap. Mary was discovered and came onstream in 1991. The intial well died after 1 year. A later well was put on-stream in 1997. Mary produced 2.83 MMBBL before final shut-in in June 1999. Reservoir quality is reasonable, but sand distribution is problematic. All the oils are sourced from the Kimmeridge Clay Formation on the adjacent Maureen Shelf area.
The M a u r e e n Field lies in U K Block 16/29a, approximately 163 k m N E of A b e r d e e n and 3 k m W of the U K - N o r w a y M e d i a n Line (Fig. 1). A very small part of the field extends westwards into Block 16/29b (Fig. 2). The field lies in 325 ft (99 m) o f water, close to the intersection of the Viking, Central and Witch G r o u n d Grabens. The M a u r e e n Field has three reservoirs. The principal reservoir is formed by Palaeocene deep-water sandstones; secondary reservoirs are provided by U p p e r Jurassic shallow m a r i n e sandstones and Zechstein G r o u p dolomites. The three pools are informally referred
to as the M a u r e e n , M a r y and M o r a g Fields, a l t h o u g h the official Field D e t e r m i n a t i o n defines M a r y and M o r a g as part of the M a u r een Field. This paper describes all three accumulations. In writing this paper, reference has been m a d e to earlier published w o r k on the M a u r e e n Palaeocene a c c u m u l a t i o n (Cutts, 1991; L a m b et al. 1992), and to internal reports by the present a n d earlier authors.
History
Pre-discovery The Central N o r t h Sea was the first oil province discovered in U K waters. Initial discoveries in the late 1960s led to increased exploration of the area and the discovery of the giant Forties Field in 1971. Block 16/29 was a w a r d e d in the third U K Offshore Licence r o u n d (1970) to a c o n s o r t i u m led by Phillips Petroleum. The partnership n o w comprises Phillips P e t r o l e u m Co. U K Ltd (33.78%, Operator), F i n a E x p l o r a t i o n Ltd (28.96%), Agip ( U K ) Ltd (17.26%), BG I n t e r n a t i o n a l (11.50%) and Pentex Oil Ltd (8.50%).
Fig. 1. Location of Maureen, Mary and Morag Fields.
Fig. 2. Location of discovery, appraisal and initial development wells, Maureen Field.
GLUYAS, J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 587-601.
587
588
P.M. CHANDLER & B. DICKINSON
Block 16/29 was interpreted to lie within a belt of productive Early Tertiary sandstones. These were known to extend some 250 km from the Cod Field northwards via the Forties Field to the Frigg Field, although the detailed age relationships of the various sandstones were not then understood. In 1970, 135 km of seismic data were acquired over Block 16/29, five lines being acquired in each of north-south and east-west orientations. Interpretation revealed Mesozoic strata with complex faulting, overlain by a welldefined dome at Cretaceous and Tertiary horizons. This mapping showed closure at Top Palaeocene level of 6850 acres (27.7 km 2) with vertical relief of 600ft (183m). Based on a well (16/23-1) immediately to the north, gross sand thickness was estimated to be 400 ft (122m) and net sand 250 ft (76 m). The primary objective of the first exploration well was to test the predicted Eocene and Palaeocene sandstones, while secondary objectives were provided by Lower Cretaceous, Jurassic and Triassic sandstones, which were predicted to provide 250 ft (76 m) net pay in total.
The well tested four zones of the Palaeocene sandstones through 1 inch chokes. The lowest zone flowed 2300 barrels of oil per day (BOPD) (365m3/day) of 36 ~ API oil and 612 thousand standard cubic feet per day (MSCFD) (17.3Mm3/day) gas from a 31ft (9.5m) perforated interval. The upper three perforated zones, totalling 60 ft (18 m), flowed 3588 BOPD (570 m3/day) of 35.9 ~ API oil and 872 MSCFD (24.7 M m3/day) gas.
Morag. In 1979, development drilling commenced on the Maureen Field. The first well, 16/29a-A1, was drilled vertically under the platform. After proving 150 ft (45 m) net pay in the main Palaocene reservoir, the well was deepened to the Zechstein Group. It found clean oil-bearing dolomites of the Morag Member, Turbot Anhydrite Formation, below 9500 ft (2896m) TVDss, separated from a second oil-bearing dolomite by dolomitic shale. Tests on the two layers flowed 6250 BOPD (994m3/day), establishing the Morag reservoir.
Discovery Maureen. The 16/29-1 exploration well was spudded in November 1972, just south of the structural crest (Fig. 2). The well did not encounter Eocene sandstones, but in the basal part of the Palaeocene, below 8200 ft (2500 m) true vertical depth sub-sea (TVDss), it found approximately 100ft (30m) of oil-bearing sandstone. The well then encountered a 500ft (152m) Cretaceous Chalk section overlying 4000 ft (1220 m) of Lower Cretaceous marls, Upper Jurassic mudstones and Middle Jurassic sandstones and coals. Total depth (12900ft, 3922m TVDss) was reached in Permian halites. Figure 3 shows the generalized stratigraphy of the field area.
Mary. In 1991, the 16/29a-A15 well was side-tracked, as 16/29aA21 (Fig. 9), to test a Jurassic prospect 1.5kin NE of the platform. Below an argillaceous Upper Jurassic section, it encountered approximately 160ft (49m) vertical thickness of oil-filled Hugin Formation sandstone overlying 280 ft (85m) of interbedded coals, shales and sandstones of the Pentland Formation, which were also oil-bearing to 10 597ft (3230m) TVDss. This well, which tested at 13 000 BOPD (2067 m3/day), established the Mary reservoir.
Post-discovery
Fig. 3. Stratigraphic column, Maureen, Mary and Morag Fields.
Maureen 1973-1978. In 1973, 132km of infill seismic data were acquired, resulting in a 1.6km grid. The post-discovery mapping indicated a closed area of 4672 acres (18.9 km 2) with 600 ft (183 m) vertical relief. The structure was interpreted as a more narrowly elongated dome than in the original mapping, with a distinctly smaller closed area but the same vertical relief. The first appraisal well, 16/29-2, was spudded in 1973, 2.6km NW of the discovery well, to evaluate the western flank and define the oil-water contact (OWC) (Fig. 2). It found 317 ft (97 m) gross, 208 ft (63 m) net oil sand above an OWC interpreted at 8693 ft TVDss, thus giving a minimum oil column of 473 ft (144m). The second appraisal well, 16/29-3, was drilled in 1974, 4kin N of the discovery well. Although it penetrated 200ft (61m) gross, 102ft (31 m) net sandstone, only 17 ft (5.2m) net oil sand were encountered above the OWC at 8702ft TVDss, thus effectively defining the northern limit of the field. Following these two appraisal wells, stock tank oil initially in place (STOIIP) was calculated to be 305 million barrels (MMBBL) (48.5 million m3), later revised to 316 MMBBL (50.2 million m3). Further seismic data, totalling 107km, were acquired in 1978. Additional geological studies suggested uncertainties on reservoir distribution in the northeast of the field, which might, if proved correct, result in reduced STOIIP of 284 MMBBL (45.15 million m3). A third appraisal well, 16/29a-5, was drilled to examine this area: it encountered 178ft (54.3m) gross [138ft (42.1m) net] oilbearing sand, confirming the base case model. The Annex B was submitted in 1978, predicting recovery of 150 MMBBL (23.8 million m 3) from a STOIIP of 288.6 MMBBL (45.9 million m3). The development wells, including seven peripheral water injectors, would be pre-drilled from a template located toward the western side of the structural culmination, as then mapped, and a single integrated platform would be installed. Oil would be produced through the platform facilities into tanks in the base of the platform's tripod steel gravity structure. It would be exported through a 2 k m long, 24 inch (0.61m) diameter sub-sea pipeline to an articulated loading column for tanker export. Annex B approval was given in December 1978.
MAUREEN FIELD
Maureen 1979-1983. A 24-slot template was installed in June 1979 and development drilling commenced the same month. The first well, 16/29a-A1, was drilled vertically and, having proved 150ft (45.7m) of Palaeocene net pay, was deepened to the Zechstein Group. The second and subsequent wells were deviated to optimize drainage, step-outs at top reservoir ranging from 600 m to approximately 2500 m. By early 1982, ten producers and one injector had been drilled. Interpretation of new seismic data, together with the well data, led to an increase in STOIIP to 304.5 MMBBL (48.4 million m3). A new simulation model led to improved locations for four later injector wells. By July 1983, 12 producers had been drilled, one intended producer having been abandoned after a gas kick in the upper Tertiary. The water injectors had also been drilled, although well 16/29a-A15 encountered an anomalously sand-poor reservoir and was not used for injection. Maureen 1983-1991. The Maureen Palaeocene reservoir came on-stream in September 1983 through two wells (the remaining producers being hooked-up by April 1984) and water injection started in early 1984. All wells were on-stream by June 1984. Production built rapidly to approximately 80 000 BOPD (12 700 m3/day) and plateau production was maintained until 1987. Water breakthrough occurred first in western flank wells, and the flood front developed in a manner indicating piston-like displacement of the oil. Three watered-out producers on the western and southern flanks were turned to produced water injection. Two original sea-water injectors were converted to produced water injection and, by the end of field life, provided 80% of the total injected water. Wells were initially lifted naturally, gas-lift being added from 1984. Electrical submersible pumps (ESP) replaced gas-lift in some wells from 1994. Interpretation of seismic data and well results led to significant revision of the geological model. The STOIIP resulting from these new interpretations was 392.3 MMBBL (62.4 million m3), an increase of 87.8 MMBBL (14 million m 3) over the 1982 figure, and of 103.7 MMBBL.(16.5 million m 3) over the 1978 figure. As a result, a formal revision to the Annex B was required, and was made in 1985. Maureen 1991-1999. The 1991 side-track of well 16/29a-A15, named 16/29a-A21, encountered swept Palaeocene sandstones. However, a thermal-decay time log (TDT) in 1996 showed them to have been re-saturated; the well was therefore re-completed as an additional Maureen producer. In 1992, well 16/29a-A18 was sidetracked, as 16/29a-A22 (see Fig. 5d), with Palaeocene and Jurassic targets: it did not find Jurassic sandstones and was completed as a Palaeocene producer. In 1994, a field-wide 3D seismic survey was acquired. A Phillips proprietary inversion technique was applied to generate a 3D porosity data volume. At the same time a complete geological review of the field, including detailed reservoir biostratigraphy, was undertaken. The resulting revised geological model was incorporated into a new simulation model. Three possible infill targets were identified. The first, the crestal area up-dip of well 16/29a-A1, was tested by well 16/29a-A24 (see Fig. 5d) in 1996 and put on-stream. Two later wells, intended as Mary reservoir producers (see below), were also designed to evaluate the other potential Palaeocene infill targets. Both wells found higher than predicted water saturation in the Palaeocene and were not completed at that level. Morag. Following the Morag discovery, the second Maureen producer well, 16/29a-A2, was also drilled into the Zechstein Group. It flowed 2338 BOPD (372m3/day) and established an oildown-to (ODT) at 10602ft (3232m) TVDss at the base of the test perforations. Two other Maureen producers, 16/29a-A3 and 16/29a-A6, penetrated the Zechstein Group on the flanks, but they encountered anhydrite rather than dolomite, defining the limits of the accumulation.
589
An interpretation of 780km of 2D seismic data from the 1981 and 1984 surveys formed the basis of the Annex B for Morag. STOIIP calculated at this time was 5.5 MMBBL (0.87 million m 3) although some upside was recognized. Only the Morag discovery well was completed and it came on-stream through the Maureen facilities in March 1991. The 2D seismic dip line spacing was closer than 125 m enabling the data to be re-processed in 1990 into a pseudo-3D volume. Interpretation of this volume indicated four structural compartments containing a total of 16.5 MMBBL (2.6 million m3), with the producing well in a compartment with 5.8 MMBBL (0.92 million m 3) inplace. A potential drilling location was identified in a compartment with 7.4 MMBBL (1.18 million m3), and a watered-out Palaeocene producer was side-tracked to this target as well 16/29a-A23 (Fig. 8). Higher than predicted Zechstein Group formation pressures led to hole control problems, which caused the well to be abandoned. Reservoir pressure in well 16/29a-A1 fell from 6113psig (421 bars) initially to 1720psig (119 bars), and production from 12000 BOPD (1900 m3/day) to 3000 BOPD (477 m3/day) by October 1991. Although supported by gas lift, production and reservoir pressure continued to fall, and the well was shut-in in December 1994. Interpretation of the 3D seismic data in 1995 showed two compartments, separated by a major E - W fault. Seismic and production data indicate the presence of significant fault barriers within the northern compartment, making further wells uneconomic. In 1997, an attempt was made to re-pressure the reservoir by injecting some 1.3 MMBBL (206 600 m 3) of water. However, mechanical defects in the tubing thwarted attempts to flow the well.
Mary. The Mary discovery well, 16/29a-A21, was completed and came on-stream through the Maureen platform in October 1991 at a rate of 9500 BOPD (1510m3/day) and gas-oil ratio (GOR) of 300 SCF/STB. Water production averaged 50 BWPD (8m3/day) at maximum water cut of 5%. Production declined rapidly and by November 1992 was less than 1000 BOPD (159m3/day). The well was suspended after producing 0.523 MMBBL (83 147m3). The rapid decline was attributed to the well contacting only a small isolated volume. In 1992 a second Maureen injector, well 16/29a-A18, was sidetracked to the Mary reservoir as 16/29a-A22 (see Fig. 9). However, the Hugin Formation sandstones were absent and the well was completed only in the Palaeocene. The 1994, 3D seismic data showed considerable faulting over Mary, confirming the interpretation of the 16/29a-A21 production data. However, a further well location was identified and well 16/29a-A25 was drilled as a horizontal producer. The well encountered 791 ft (241 m) Measured Depth (MD) net oil-bearing Hugin sandstone in the horizontal section and tested at a maximum rate of 18 300 BOPD (2910 m 3/day), although the rate was not sustained. Repeat Formation Tester (RFT) data along the well showed some segmentation of the reservoir. The well came on-stream in August 1997 and gas-lift was installed in November 1997. A further well, 16/29a-A26, was drilled in 1998 less than 300m SE of 16/29a-A21 (Fig. 9). However, only 10ft (3m) of Hugin Formation sandstone was found at the reservoir entry point and sandstones were completely absent at a downdip location. The well was not completed.
Structure Tectonic history The tectonic history of the Maureen Field area commenced in the Permian with development of a Zechstein basin in which carbonates and evaporites were deposited. The earliest rifting episodes may have been initiated in the later Permian, with extension across a north-south axis. From this point onward, faulting and saltwithdrawal tectonics were an important feature in determining
590
P.M. CHANDLER & B. DICKINSON
basin geometry on the sub-regional scale. 3D seismic data reveal the presence of sediment 'pods' geometrically similar to those seen throughout the Central Graben area (e.g. Dickinson 1996). The sediment fill in pods in the Greater Maureen area ranges from Triassic to Late Jurassic in age. Significant regional uplift, possibly caused by inflation of a thermal dome in the Central North Sea (Underhill & Partington 1993), resulted in erosion of most of the Early Jurassic sediments in the Maureen area. The Middle Jurassic volcanic episode is well represented to the west and south of the Maureen Field. The development of the rift system reached its maximum during middle and later Jurassic times, and as the rift propagated southwards towards the apex of the earlier thermal dome a marine incursion followed. Seismic and well data reveal the continued importance of the interplay between faulting and salt-withdrawal tectonics in determining depositional geometry. Relative sea level rise in the later stages of rifting led to drowning of the Jurassic littoral throughout the graben system and to deposition of basinal argillaceous rocks. By the mid-Cretaceous, the extensional tectonic regime was replaced by post-rift subsidence, with chalk deposits gradually onlapping the earlier structure. Palaeocene uplift (Anderton 1993; Den Hartog Jager et al. 1993) of the Scottish landmass initiated the deposition of coarse-grained clastic sediments, whose earliest deposits form the Maureen Field Palaeocene reservoir. Later Tertiary sedimentation was restricted almost entirely to basinal mudstones deposited in a gently subsiding basin, with the only significant sandstones being those of the basal Miocene. The major role of salt tectonics in the Maureen area is evident throughout the Mesozoic. The interplay of salt withdrawal and faulting produced the great thickness variations and 'pod' features typical of the Triassic to Late Jurassic sequences around the Varg and Armada Fields and elsewhere (Phillips internal reports).
Fig. 4. Principal tectonic elements, Maureen Field area.
Regional structure (Fig. 4) The Maureen Field is situated on the Maureen Shelf, a terrace at the extreme southeastern end of the Viking Graben near its junction with the Witch Ground and Central Grabens. The shelf extends westwards towards the field, and extends northwards towards the southern part of the Utsira Terraces. The Maureen diapir is situated on the eastern side of the Maureen Shelf, which is delimited to the east by faults which controlled development of a Late Jurassic basin, the Maria Basin. The latter is delimited on its eastern side by the bounding faults of the Jaeren-Utsira High. The influence of positive salt tectonics is seen in the Maureen salt dome itself. This feature, which was probably initiated in the Triassic, continued to move until well into the Tertiary, and only stopped developing in latest Oligocene or earliest Miocene times. The rate of growth was probably relatively modest, since dome development was not sufficiently aggressive to pierce the overlying sediments.
Local structure (Figs 5 & 6) At Palaeocene level the Maureen Field is a four-way dip closed structure of approximately 6850 acres (27.7 km2), overlying a salt dome. The structure was first revealed by interpretation of 135 km of seismic data acquired in 1970. The dome was apparently simple, with only one fault of significance, elongated in a N W - S E direction. After drilling the discovery well, a further 132 km of seismic data were acquired to infill the original grid. The first two appraisal wells, when combined with these data, revealed the structure seen in Figure 5a, which was not significantly different from the original map. Further seismic acquisition in 1978 and a third appraisal well tended to confirm the picture, although they hinted at a northeastward bulge
MAUREEN FIELD
591
Fig. 5. Depth structure maps of Maureen Field. (a) 1974. (b) 1978. (e) 1985. (d) 1996. in the dome (Fig. 5b). A further 370 km of seismic data, with 250 m dip line spacing, was acquired in 1981, oriented ENE-WSW, but with six NW-SE cross-lines. 1982 (11 development wells) and 1985 (19 development wells) interpretations confirmed the trend of the structural culmination; they also indicated that the downdip part of the southeast flank trended more nearly north-south (Fig. 5c). The 1994 3D seismic data were acquired in a north-south direction, with inline and trace spacing of 12.5 m. The structure map resulting from this data (Fig. 5d) confirmed the 1985 interpretation. The well results confirmed that the salt dome supporting the Cretaceous and Palaeocene closure did not pierce the Triassic and Jurassic strata.
Morag. The Morag structure was first proved to be oil-bearing in 1979 when the 16/29a-A1 Palaeocene development well was drilled to the Zechstein Group and encountered oil-bearing dolomites.
When Palaeocene production came off-plateau in 1987, attention turned to the Zechstein Group reservoir as a means of enhancing production. Seismic data were available from the 1982 and 1984 surveys, which provided 242 km and 264 km of data respectively. The resulting map revealed the Morag structure as an upthrown fault block, bounded by faults to the southwest, south and southeast. The culmination of the fault block trended southeastwards from the discovery well. Vertical closure of approximately 1100ft (335m) above the ODT at t0602ft (3232m) TVDss was interpreted at Top Zechstein Group. Two small faults trending N W - S E just south of the discovery well hinted at internal subdivision of the accumulation, but complete compartmentalization was not revealed by the data. The 1994 3D seismic data were interpreted at Top Zechstein Group level. Figure 7 is an example line from this dataset. The map broadly confirmed the 1989 interpretation (Fig. 8). However,
592
P. M. CHANDLER & B. DICKINSON
Fig. 6. Seismic line N-S across Maureen Field: in-line from 1994 3D seismic dataset. Top layer F is the top of the reservoir in the 1995 reservoir model study (see Fig. 10).
the data revealed substantial faulting at Top Zechstein Group. In particular, it showed a major southward downthrown fault just north of the target of the failed 16/29a-A23 well. This fault effectively separates the southern area around well 16/29a-A23 from the main porous dolomite tested by, and produced through, the 16/29a-A1 well. The structural crest lies at approximately 9300ft (2835m) TVDss, giving closure of approximately 1300ft (396m) above the ODT.
Mary. In addition to the three Maureen exploration and appraisal wells, three Maureen Palaeocene development wells had investigated the pre-Cretaceous potential of the structure. Three wells, 16/29-2, 16/29a-A3 and 16/29a-A6, encountered Jurassic sandstones. Well 16/29a-A6 flowed oil from a 15 ft (4.6m) sand interval and well 16/29a-A3 flowed oil and water from a 30 ft (9.1 m) sand. The 1981, 1984 and 1988 seismic surveys were combined and processed to give a pseudo-3D data volume. Interpretation of these data revealed the existence of a combined Jurassic/Triassic prospect northeast of the salt dome (Fig. 7). The Upper Jurassic Hugin Formation sandstones were thought to pinch-out updip against the salt dome, and be fault closed to the north and south. The underlying Triassic structure was interpreted to be fault-bounded to the west and dip closed to the north, east and south. The 16/29a-A21 well found 150 ft (46 m) of Hugin Formation sandstones, compared with the 80ft (24.4m) predicted. However, a second well, 16/29a-A22, drilled 1 km to the southeast, found no sandstone, the Heather Formation lying directly on the Pentland Formation. Interpretation of the 1994 3D seismic data revealed that the Top Pentland surface around the 16/29a-A21 well formed a nose dipping to the northeast and was severely internally faulted (Fig. 9).
The Top Hugin Formation is picked on the seismic as a weak peak above the Pentland Formation, although this is not a consistent event. A lack of acoustic impedance contrast at the Heather/Hugin interface, and the sandstone thickness which is below seismic resolution, combine to make interpretation of the Hugin Formation sandstones difficult. This is borne out by the well results: wells 16/29a-A21 and 16/29a-A25 are less than 300m apart and have very similar seismic character. However, at the 16/29a-A21 location 150ft of sand is present whereas at the 16/29a-A25 location less than 10ft of sand is present, with no sand downdip. The sand distribution cannot therefore be predicted from the seismic data. Well 16/29a-A25 was drilled approximately 200 m north of well 16/29a-A21 to intersect the Top Hugin Formation in one fault block, cross a fault and penetrate it again in the downthrown block. The extended-reach well found 791 ft (241 m) m D of Hugin Formation sandstone in the two sand sections.
Stratigraphy The oldest rocks in the Maureen Field wells are Permian halites of the Shearwater Salt Formation and anhydrites and dolomites of the Turbot Anhydrite Formation. These are succeeded by Triassic continental mudstones and siltstones of the Smith Bank Formation (Fig. 3). These are thin or absent over the field crest and on the eastern flanks, but much thicker to the west and north. The succeeding sandstones and siltstones of the Skagerrak Formation are also absent on the crest but are seen in wells on the western and northern flanks. Early to mid-Jurassic uplift caused erosion of earlier sections and early Jurassic sediments are not seen in the Maureen Field. The Pentland Formation (Middle Jurassic) is widespread in this area and
MAUREEN FIELD
Fig. 7. Seismic line SW-NE through Mary and Morag Fields.
Fig. 8. Depth structure map, Top Zechstein Group, Morag Field.
Fig. 9. Depth structure map, Top Hugin Formation, Mary Field.
593
594
P.M. CHANDLER & B. DICKINSON
up to 400ft (122m) of sandstones, mudstones and coal are seen around the Maureen Field. The Middle Jurassic volcanic sequence is absent from the Maureen Field, although it is present immediately to the west and south. The onset of marine deposition is reflected by the development of shallow marine sandstones of the Hugin Formation, which form the reservoir in the Mary structure. The interplay of salt movements and faulting was superimposed on the marine transgression in a complex manner, and prediction of sand distribution is difficult. Relative sea-level rise in the late Jurassic was marked by a change to argillaceous sedimentation, represented by the mudstones of the Heather Formation. The later development of restricted circulation bottom waters is evidenced by the organic-rich mudstones of the Kimmeridge Clay Formation. Lower Cretaceous sediments, represented by mudstones and marls of the Cromer Knoll Group, were deposited over the area and up to 300 ft (91 m) of marls and mudstones are seen in field wells. Coarse-grained clastic deposits were limited to the basinal areas to the south of the field. Post-rift subsidence replaced the extensional rifting regime at the end of the Early Cretaceous, and coccolith oozes were deposited in an outer shelf to basinal setting, forming the chalks of the Hod to Ekofisk Formations. A major uplift episode affected the Scottish H i g h l a n d s Orkney/Shetland landmass at the beginning of the Palaeocene (Anderton 1993; Den Hartog Jager et al. 1993). Abundant coarse clastic debris was generated and was transported as turbidites to the axis of the Mesozoic graben system. The Maureen Formation represents sedimentation in both Danian and Thanetian times. In the former, the background basinal mudstones are distinctly calcareous, while the Thanetian mudstones are non-calcareous. In some areas, including the Maureen Field, the initial Palaeocene deposits (up to the top of the Maureen Formation) contained a considerable proportion of chalk debris. The chalk debris beds seen in the Maureen Field were at least partly sourced from the Jaeren-Utsira High. The Maureen Formation is over 450ft (137m) thick on the western fringes of the structure, and thins onto the crest of the structure and eastwards towards the Jaeren High. Later lowstand fans in-filled basin floor topography, and younger sandstones, such as those of the Mey Sandstone Member (Lista Formation), do not extend onto the Maureen High. In the Maureen Field the later Palaeocene sediments are the mudstones of the Lista and Sele Formations and the tufts and mudstones of the Balder Formation. The Eocene to Recent section is predominantly argillaceous, being represented by the mudstones of the Stronsay, Westray and Nordland Groups. However, there are developments of sandstones associated with later relative sea-level lowstands: Grid Sandstone Member (Horda Formation), Alba and Caran Sandstones of Newton & Flanagan, 1993. Although these are present around the Maureen area, they are not developed in the Maureen Field itself.
southeastern part of the dome led to the present configuration, where the lower dolomite subcrops the later Jurassic in the southeast and the upper dolomite subcrops at the structural culmination and in the northwest.
Trap
Reservoir: Maureen (Palaeocene)
Trap type
Lithofacies
Maureen Palaeocene. The Palaeocene accumulation has a structural trap provided by simple four-way dip closure over the Maureen salt dome. The dome is elongated NW-SE, being 7 km long and 3.7 km wide; the closed area is 4100 acres (16.6 kme). The field, which is full-to-spill, has a maximum oil column of approximately 650ft (198 m).
The Maureen Field reservoir is composed of massive sandstones, mudstones, interbedded mudstones and sandstones, and chalk conglomerates of the Maureen Formation, with sandstones predominating. Approximately 1200ft (366m) of core is available from seven appraisal and development wells, although only well, 16/29a-A1, has core from essentially the entire reservoir section. The massive sandstones are generally fine to medium grained, sub-angular to rounded, and moderately sorted. They are rather immature, being mainly sublithic arenites or subfeldspathic arenites. They occur in units 3-50ft (1-15m) thick, which are frequently bounded by a thin calcite-cemented zone in the lower part of the reservoir. Pebbles and granules of mudstones are sometimes concentrated at unit bases, but they are more commonly dispersed through the beds. Sole markings are rare and bioturbation is not evident. Dish structures are abundant, indicating very rapid de-watering of
Morag.
The Morag pool has a combined structural-stratigraphic trap. The location of the original dolomite reservoir within the anhydrite succession was controlled by contemporaneous basement faulting. Following evolution of the dolomite-shale-dolomite succession, salt movements during the Triassic led to erosion on the southeastern side of the carbonate body, leaving the lower dolomite subcropping the later Jurassic mudstones. Continued uplift of the
Mary.
The Pentland Formation underlying the Mary pool forms a spur plunging northwards off the main Maureen salt dome feature. The spur is dip- and fault-closed to the west, north and east and closes updip against the salt dome. This underlying structure approximates the area of Hugin sandstone development, the thickness relations implying some degree of inversion. The Mary pool is trapped by updip pinch-out/onlap of the Hugin Formation sandstones onto the Pentland Formation on the growing Maureen salt dome. Laterally it is also trapped by pinch-out of the sandstones against the overlying Heather and Kimmeridge Clay Formation mudstones. The Mary pool is internally faulted, and production and drill stem test (DST) data provide evidence that some faults, at least, are sealing.
Seals The Maureen Palaeocene accumulation is sealed above and to the sides by mudstones of the Lista Formation. The eastern limit of the overlying Mey Sandstone Member lies to the west of the closure. The Mary pool is sealed by mudstones of the overlying Heather and Kimmeridge Clay Formations, while the Zechstein Group dolomite reservoir in Morag is sealed by Triassic and Middle Jurassic mudstones, the bottom seal being provided by Zechstein Group halites.
Faults The Maureen Palaeocene reservoir is faulted to some degree. However, the sand thickness ensures that sand-to-sand displacement is the norm, and production data show no evidence of sealing faults affecting the reservoir. In Morag and Mary by contrast, 3D seismic, pressure and production data all reveal significant intra-reservoir faulting, which is sealing to some degree. In Morag, well 16/29a-A23 encountered pressures higher than those seen, post-production, in the northern block, suggesting a sealing fault. In Mary the 16/29a-A25 well penetrated the reservoir in an upthrown fault block and then crossed a fault to encounter the sandstones again in a downthrown position. RFT data along the well showed pressure depletion of 470 to 2043 psia compared to virgin pressure of 6262 psia at datum. Pressure differentials, normalized for depth, of 538, 1035 and 1573 psia were seen in three separate fault blocks, indicating that the faults are sealing.
MAUREEN FIELD the sandstones. The sandstones were deposited from high density turbidites as submarine fan lobes. Recent work has suggested that there is a significant degree of remobilization or slumping within the Maureen reservoir, perhaps triggered by uplift of the salt dome underlying the crest of the field. The interbedded mudstones and sandstones occur in units up to 2ft (0.6m) thick, the sandstones being slightly finer-grained and having a wider range of textures than the massive sandstones. The observed distortions of texture may be due to compactional or remobilization effects. They are probably the waning deposits of by-passing debris or turbidite flows. The mudstone facies are generally laterally persistent hemipelagic claystones with thin beds of siltstone and very fine-grained sandstone. Both grey-green and dark grey or black mudstones occur, the former being calcareous and the latter non-calcareous. The two types are also distinguished by their ichnofauna: the calcareous mudstones are abundantly burrowed with Chondrites, Planolites and Zoophycos, while the non-calcareous mudstones have a much sparser ichnofauna, from which Zoophycos may well be absent. The stratigraphic extent of the two mudstone types is quite different, the calcareous varieties occurring throughout most of the reservoir and the non-calcareous varieties being limited to the uppermost part. The Danian-Thanetian stage boundary marks the upper limit of calcareous mudstones. This limit also coincides with the intra-Maureen M 1 - M 2 lithostratigraphic boundary (Knox & Holloway 1992). Localized developments of calcareous mudstones also occur closely associated with chalk debris flows in the upper, Thanetian part of the Maureen reservoir in the northeast of the field. Chalk conglomerates occur at the base of the fan system, where they are interbedded with sandstones and mudstones shed into the basin in the initial Tertiary uplift episode. They occur as slumped limestones, large undeformed blocks of chalk and calcareous mudstones. These are interpreted as the initial deposits of the fan system initiated during the first Tertiary uplift episode. In some places sandstones appear to lie within the Ekofisk Formation, overlain by chalks. There is now biostratigraphic data to support an interpretation, first suggested by dipmeter trace data, that the overlying chalks are re-deposited, and that the underlying sandstones are coeval with the basal mudstones of the Maureen Field seen in other wells (Fig. 10, well 16/29a-A1). Chalk conglomerates also occur near the top of the Maureen Field (Fig. 7 northeast area of field; Fig. 10, well 16/29a-A16). Here they occur as discrete beds of chalk pebbles, cobbles or blocks, some of which have a sandy matrix, and which log data suggest pass laterally into calcite-cemented sandstones. Calcareous mudstones
595
are also associated with this horizon. These upper chalk conglomerates are restricted to the north and east of the field, and are interpreted to have an easterly source. A massive chalk section occurs in well 16/29a-A15 in the east of the field. It overlies much of the Maureen section and is clearly out of place. The biostratigraphic data indicate the under- and overlying sediments are normal; that the chalk section occurs at about the same horizon as the later chalk debris flows; and that the chalk section is not inverted, as would be expected if the section were re-worked as a series of debris flows. The chalk is thought to have slid, as a single entity, from the JaerenUtsira High into the adjacent basin, being arrested in its progress by the reverse slope of the Maureen salt dome. A similar extensive slump occurs south of the Maureen Field, at the base of the Maureen Formation.
Depositional setting The Maureen Field reservoir is a sequence of coarse-grained clastic deposits dominated by thick, massively bedded sandstones and subordinate mudstones and chalk conglomerates. The sandstones are thickest on the western flank of the field and thin eastwards toward the Jaeren-Utsira High. Sandstones may also occur near the base of the Maureen reservoir, but generally the basal deposits are marls and calcareous mudstones, the bulk of the formation is sandstones and interbedded mudstones and the terminal deposits are non-calcareous mudstones. The overall aspect is of deposition in a submarine fan system in lobes on the middle or outer fan, with a significant component of debris flow deposition, remobilization being evident in some units.
Pore types and diagenesis In general, diagenesis has had very little impact on overall reservoir quality and good porosity and permeability have been preserved. The only significant reduction in reservoir quality occurs at the boundaries of sandstones which are in contact with calcareous mudstones: significant calcite cements have developed, producing tight sandstones layers. These layers are generally thin and do not significantly degrade overall reservoir quality or performance. Elsewhere the good primary interparticle porosity is preserved. Six diagenetic phases are recognized: (1)
Early calcite growth boundaries.
at sandstone-calcareous
mudstone
Fig. 10. Reservoir correlation, Maureen Field. Datum: Top Ekofisk Fm. Note the presence of chalk debris flow in Layer A of 16/29a-A1 well, and above Layer F in 16/29a-A16. Note also thinning of reservoir section over crest of field (wells 16/29a-A 1 and 16/29a-A8); massive sandstones particularly in Layers B C, and E; upward improvement in porosity and oil saturation, especially in 16/29a-A5, 16/29a-A9 and 16/29a-A1 above Layer C.
P. M. CHANDLER & B. DICKINSON
596
(2) Minor quartz overgrowths (1-2%) on quartz grains, which (3)
(4)
(5) (6)
had little effect on reservoir quality. Kaolinite cementation, 2-3% of authigenic kaolinite occurring in most of the sandstones. It is present as booklets of hexagonal plates with some microporosity, partially filling scattered pore spaces. They have little effect on porosity, but reduce permeability to some degree. Chlorite growth. The chlorite occurs in minor amounts (3-7%) as crystals rimming grains and partly occluding pore space. It is more abundant in argillaceous sandstones (4%), where its habit noticeably reduces permeability by blocking pore throats. Late calcite cementation, occurring near the sandstone-mudstone contacts but rarely in massive sandstones. Grain dissolution welding, which is of minor extent in most sandstones, is more severe in argillaceous sandstones. It does not substantially reduce porosity or permeability.
Geological models Geological models of the field have been developed at four stages of field life: pre-Annex B (1974-78); mid-development drilling (1982); after development drilling (Annex B revision 1985); and late life (1996). These have differed significantly in the amount of well, production, biostratigraphic and seismic data available. The principal interpretational variables have been changes in definition of base and top reservoir and changes in ideas on reservoir architecture. The first model, used for development planning and sanction purposes, had only four wells and very limited 2D seismic data. The model had four layers on the flanks, but only three in crestal areas, the basal flank layer being interpreted as absent. Base reservoir was defined as the top of the Ekofisk Formation or, where present, at
the top of chalk debris flows. Top reservoir was defined as the top of main sandstones or, where present, at the top of the upper chalk debris flows. The second (1982) model, built with the benefit of 11 development wells, some additional seismic data and a pilot biostratigraphic study, had four layers, but these were different from the four layers of the initial model. This model had the shallowest base reservoir pick, defined as the base of the main sandstones; the top reservoir pick was similar to that of the 1974 model, except that the top was picked below the upper chalk debris flows, where these are present. Not all layers were field-wide. The 1985 model, which had only three layers, was built for the Annex B revision and for field management. All development wells plus additional biostratigraphic and seismic data were available. This model had the deepest base reservoir pick, at a level now recognized to lie within the Ekofisk Formation, while top reservoir was picked as approximately coincident with that of the 1982 model. The final model dates from 1996 and has six layers (Fig. 10). It benefited from 3D seismic data and an inversion volume as well as high-resolution biostratigraphic data. Base reservoir was picked at the top of the Ekofisk Formation, so that the chalk debris flows lie within the basal layer of the model. Top reservoir was taken rather higher than in earlier models, except around the northern and eastern flanks where it was placed below the upper chalk debris flows. The seismic inversion volume displays porosity quality as different colours. The best porosity is indicated by the darkest reds and the poorest porosity by the darkest blue (Fig. 11). The display can also be manipulated to show only porosity exceeding the pay cut-off. Study of the two 3D volumes in conjunction with the log data shows an overall four layer architecture (Figs 10 and 11). From bottom to top these are:
Fig. 11. Cross-section through 3D inversion volume porosity display. Note graben between 16/29a-A5 and 16/29a5 wells; mudstone dominated Layer A; massive sands in Layers B, C and E especially in west; heterolithic nature of layer D and shale-out in eastern part of layers E and F. Note also best porosity developed in upper layers: compare Layers B and C with Layer F around SP 1350-1300.
MAUREEN FIELD 9
9
9
9
Basal mudstone layer (model Layer A). Predominantly mudstone, with localized chalk debris flows and sandstones in the crestal area. Lower massive sandstone layer (model Layers B, C). This comprises thick massive sandstones with thin, laterally impersistent mudstones, the sandstones being particularly well developed on the western flanks. Middle heterolithic layer (model Layer D), comprising sandstones and mudstones, sandstones are much less massive and laterally persistent and mudstones much thicker and more laterally persistent that in the massive layers. Upper massive layer (model Layer E, F) is more sand-dominated than the heterolithic layer though less sand-rich than the lower massive layer. In particular, the sandstones in the upper layer shale out rapidly to the east and southeast of the crest.
The two massive sandstone layers are significantly thicker than the basal mudstones and middle heterolithic layers: they were therefore sub-divided to maintain stability in the simulation model. The division was made at the horizon of mudstones within the main sand bodies which as far as possible could be demonstrated as time equivalent across the field. In terms of the evolution of the field through time, the basal layer represents the initial period of deposition in the basin during the early Tertiary; the calcareous mudstones are the background basinal deposition and the sandstones and chalk debris flows are the initial erosional products from the basin margins deposited in the lowstand fan. The massive layers represent deposition of abundant sands, shed from the shelf and swept into the basin by gravity-flow processes. The intervening heterolithic layer represents a relatively quieter period where sand deposition was less intense.
597
Later marginal instability is marked by the upper chalk debris flows, shed into the basin from the east. Relative sea-level rise during the early Thanetian is marked by reduction in coarse-grained clastic supply and ultimately by drowning of the sand pile by hemipelagic mudstones.
Porosity and permeability The low degree of diagenetic alteration seen in the Maureen Paleocene reservoir has resulted in preservation of good porosity and permeability characteristics (Fig. 12). Uncompacted core porosity is in the range 18 to 28% and permeability 50mD to 1500mD, although higher values are seen. The significantly lower poroperm quality seen in some samples is due to calcite cementation at bed boundaries. Overall, reservoir quality is better in the upper part of the reservoir. The lower and upper parts of the lower massive sand (Layers B and C) have similar reservoir quality. The overlying heterolithic layer (Layer D), has a wider range of poroperm values, with a distinct better quality component, and there is a further small but distinct improvement in permeability passing into the upper massive sandstones (Fig. 12). Permeability in the aquifer is lower than in the oil leg, core permeability being generally 100 mD or less. Aquifer test permeability is even lower, being generally less than 20 mD. Net pay cut-off is taken at 15% porosity. Net to Gross ratio varies between layers. In Layer A effective pay is restricted to a zone trending southeastward from well 16/29a-A1 towards well 16/29a-A13. In Layers B and C the lower massive sand layers, Net to Gross is generally greater than 0.7; better values occur on the flanks, especially the eastern flank in Layer B and the northern and eastern flanks in Layer C. The heterolithic layer has significantly reduced Net to Gross, values below 0.6 being usual and below 0.5 being common. In western parts of the field in the upper massive sand layers, Net to Gross is higher, usually above 0.6 and frequently 0.8 or higher. However, Net to Gross is significantly lower in the east, reflecting the eastward shale-out of the reservoir.
Pressure relationships and fluid contacts The Maureen Palaeocene reservoir is normally pressured, with initial reservoir pressure of 3777 psia (260 bars) at datum of 8300 ft (2530m) TVDss. The reservoir fluid gradient is 0.324psi/ft. The oil-water contact was originally defined at 8702 ft (2652 m) TVDss on the basis of 60% Sw cut-off. However, in more recent studies a deeper contact, at 8730ft (2661 m) TVDss at 100% Sw, was preferred.
Reservoir: Morag (Zechstein Group)
Fig. 12. Core porosity and permeability, Maureen Formation reservoir divided by layer. Note better permeability in Layer F than in Layer E and better overall poroperm in Layers E and F than in Layers B and C.
The uppermost Zechstein Group section in the Maureen Field area varies from anhydrites in the 16/29a-A3 and 16/29a-A6 flank wells, through dolomitic shale in well 16/29-1 to clean dolomite in 16/ 29a-A1 and 16/29a-A2 (Fig. 13). All these units belong to the Turbot Anhydrite Formation, the dolomites forming the Morag Member (Cameron 1993). The reservoir comprises a lower clean dolomite approximately 60ft (18.3 m) thick, a 200ft (61 in) dolomitic shale and an upper 50ft (15.2m) section of clean dolomite. In well 16/29a-A2, erosion has removed the upper dolomite and the dolomitic shale leaving only 50 ft (15.2 m) of the lower dolomite. Matrix porosity averages only 2.6%. However, core from this well shows fracture porosity: the unstimulated production rates and volumes obtained from 16/29a-Al indicate that fracture porosity must be even more widely developed around that well. This is supported by the permeability-thickness data from Drill Stem Tests (DST), which is more than 100-times greater in 16/29a-A1 than in 16/29a-A2.
598
P. M. CHANDLER & B. DICKINSON
The reservoir quality dolomite is a clean, high-energy inter-tidal deposit, formed between low energy supra-tidal evaporites and more argillaceous sub-tidal dolomitic shale. The reservoir formed as a result of the interplay between transgressive and regressive episodes related to subsidence and uplift on underlying basement faults. In particular, the present tilt of the dolomite body downwards to the northwest is related to upward growth of the crestal area of the salt dome to the southeast. The Morag reservoir is slightly over-pressured, initial pressure being 6113psig (421.4 bars) at 8800ft (2682.2m) TVDss. The reservoir fluid gradient is approximately 0.32psi/ft. Pressure data from DST in the 16/29a-A1 and 16/29a-A2 wells show that the two wells are not in pressure communication.
Reservoir: Mary (Upper Jurassic) The Hugin Formation sandstones have not been cored in the Mary reservoir. However, in nearby cored wells they occur as shallow marine sands deposited in a proximal shoreface to barrier bar setting. Coarsening upward units are seen in core in some wells and are inferred from logs of wells 16/29a-A21 and 16/29a-A25. In common with other parts of the Central North Sea, the distribution of the Hugin Formation sandstones is difficult to predict, and this difficulty has led to failures with two of the four Mary wells. On a sub-regional scale, the interplay of faulting and salt tectonics has been the principal control on distribution of the Hugin (and Fulmar) Formation sandstone and the same factors are surely relevant at Mary. However, the thin sandstone intervals and lack of velocity contrast between the sandstones and their laterally equivalent mudstones has hampered resolution of the problem at Mary. In the Mary discovery well, 16/29a-A21, the reservoir is a 150 ft (46m) True Vertical Thickness (TVT) clean sand, without shale breaks, but it thins rapidly southwards to only 10ft (3m) within 300m. Log porosity in the Mary area is in the range 14 to 19% and Net to Gross is approximately 22%. The Mary reservoir is slightly over-pressured with respect to hydrostatic [virgin pressure was 6262 psia at 10 217 ft TVDss (431.6 bars at 3114m)] and the reservoir fluid gradient is 0.325 psi/ft. The later Mary wells show pressure depletion of over 2500 psi (172 bars) compared to virgin. Well 16/29a-A25 demonstrated pressure separation between three reservoir compartments.
Source Source beds The Maureen Field oils were sourced from the organic-rich shales and mudstones of the Kimmeridge Clay and Heather Formations. An earlier paper on the Maureen Field (Lamb et al. 1992, quoting Cayley, 1987) reported regional average total organic carbon (TOC) contents of approximately 8% for the Kimmeridge Clay with a maximum in excess of 15%. Recent data from the immediate Maureen Field area indicate TOC in the range 5.5-7% in the upper parts of the Kimmeridge Clay Formation, with 3 to 4% TOC lower in the Kimmeridge Clay and approximately 2 to 3 % in the Heather Formation. Earlier published work suggested that the Maureen oils were sourced from the Kimmeridge Clay of the Outer Witch Ground Graben, some 15 km from the field (Cutts 1991; Lamb et al. 1992). Recent studies indicate that the most likely source for all the Maureen Field oils is the Kimmeridge Clay Formation on the Maureen Shelf.
Maturation. Cutts (1991) and Lamb et al. (1992) suggested that early maturity in the Witch Ground Graben area occurred during the Mid- to Late Cretaceous, with peak oil generation during the early Tertiary. The more recent studies suggest that while oil expulsion may have started as early as 75 million years before present (Mabp) (Late Cretaceous) in the Fisher Bank Basin, generation and expulsion on the Maureen Shelf was much more recent, starting at approximately 35 Mabp (early Oligocene) and continuing to the present day. The oils indicate different maturity in the source rocks at the time of expulsion, the Morag oils being derived from a somewhat less mature source than the Maureen Palaeocene oils.
Migration and charge Migration from the Kimmeridge Clay Formation source commenced at approximately 35 Mabp. The most recent modelling studies show that oil migration commenced on the Maureen Shelf at approximately 30 Mabp, but the charge did not begin to fill the
Fig. 13. Reservoir correlation, Zechstein Group, Morag Field. Datum: Top Zechstein Halite.
MAUREEN FIELD Palaeocene sandstones at Maureen until approximately l0 Mabp. The modelling also suggests a very strong vertical migration path, with lateral migration not occurring until the charge had reached the Palaeocene sandstones. The Maureen Palaeocene reservoir was charged with mature paraffinic-napthenic under-saturated oils, 36 ~ API gravity, with initial G O R of 393 SCF/STB (69.2m3/m3). Wax content is 14.2% and sulphur content 0.35%. Charging of the older Mary and Morag reservoirs probably occurred slightly earlier. These oils are also low G O R oils, Morag 232 SCF/STB (40.9 m3/m 3) and Mary 501 SCF/STB (88.3 m3/m3).
Reserves and production
599
the pre-Annex B reduction in STOIIP was over 27%; the postAnnex B increases were 104.6% (1985) and 108% (1996).
Morag. Oil-in-place estimates for Morag made for the Annex B (1989) were based on the results of five wells and the seismic data from the 1981 and 1984 surveys. The base case volumetric STOIIP was 5.5 MMBBL (0.87 million m 3) but an upside case of 9.9 MMBBL (1.57 million m 3) was recognized. An updated calculation after interpretation of the pseudo-3D seismic volume yielded STOIIP of 16.6 MMBBL (2.64 million m3), divided into four compartments. The compartment with well 16/29a-A 1 had 5.8 MMBBL (0.92 million m 3) and that with the proposed 16/29a-A23 location added a further 7.4 MMBBL (1.18 million m3). The most recent calculation gives Morag STOIIP as 12.1 MMBBL (1.9 million m3).
Petroleum in place (Fig. 14) Maureen (Palaeocene).
Oil-in-place calculations have been made at eight stages since field discovery. In 1974, following the discovery and two appraisal wells, STOIIP was determined to be 304.7 MMBBL (48.4 million m3). Further geological studies led to revisions in 1976 and 1977, to 316.3 and 284.5 MMBBL (50.3 and 45.23 million m 3) respectively. Following further seismic acquisition and a third appraisal well in 1978, the Annex B STOIIP was calculated to be 288.6 MMBBL (45.9 million m3), a decrease of 16.1 MMBBL (2560 million m 3) from the 1974 figure and of 27.7 MMBBL (4.4 million m 3) from 1976. Re-calculation in 1982, with the benefit of the 1981 seismic data and the first 11 development wells, increased STOIIP by 15.9 MMBBL (2.53 million m 3) to 304.5 MMBBL (48.4 million m3). With the full suite of development wells and additional seismic data, the 1985 calculation increased the oil-in-place by 88.7 MMBBL (14.1 million m 3) to 393.2 MMBBL (62.5 million m3). There were upward revisions in 1987 (393.3 MMBBL; 62.5 million m 3) and 1996 (397.0 MMBBL; 63.1 million m3). Figure 14 shows the changes in STOIIP through time for the Maureen Palaeocene accumulation, together with changes in reserves and recovery factor. Two features of note are the decrease in STOIIP between discovery and the end ofthe appraisal stage and the large increase in STOIIP resulting from the development drilling and interpretation of new seismic data. In percentage terms,
Mary. Calculation of oil-in-place in the Mary reservoir is complicated by lateral impersistence of the sand, lack of a clearly identifiable reflector associated with the top of the reservoir and variation in OWC. The current volumetric estimate is 20.3 MMBBL (3.2 million m 3) in the Hugin Formation sandstones and 6.2 MMBBL (1.0 million m 3) in the Pentland Formation sandstones. Petroleum reserves (Fig. 14) Maureen (Palaeocene). Estimated reserves have changed significantly with time in parallel with the STOIIP changes. The original simulation model (1974) suggested reserves of 142.3 MMBBL (22.6 million m 3) after 10 years, while the 1976 model update suggested 145.5 MMBBL (23.1 million m3). When the Annex B was submitted in 1978, reserves were estimated at 150.0 MMBBL (23.8 million m3). Following drilling of the first 11 development wells and acquisition of new seismic data, the revised 1982 reservoir model estimated reserves of 151.9 MMBBL (24.1 million m3), a 1.3% increase. The 1985 simulation model, built after 2 years' production, indicated substantially greater reserves [184.8 MMBBL (29.4 million m3), a 23.3% increase over the Annex B estimates] from the same 12 wells. Further model revisions in 1987 and 1996 predicted reserves of 207.7 MMBBL (63.1 million m 3) and 219.0 MMBBL (34.8 million m 3) respectively. Morag. A material balance study of the 16/29a-A1 Morag production well suggested that the well contacted 5.15 MMBBL (0.82 million m3), of which 2.6 MMBBL (0.41 million m 3) was produced before the well was shut-in in 1994. Mary. Reservoir performance data from the initial 16/29a-A21 well indicated that the well was in contact with an isolated volume of between 1.8 and 3.0 MMBBL without external pressure support. The 16/29a-A25 well production data suggest that a STOIIP of approximately 25 MMBBL is connected to the well. The Mary wells produced 2.83 MMBBL before the field was shut-in. Cumulative production (Fig. 15)
Fig. 14. STOIIP, reserves and recovery factor through time, Maureen Field.
The Maureen Palaeocene reservoir was produced initially through 12 wells, starting in 1983. Two further wells were added, after 8 and 9 years respectively, by side-tracking existing wells. The field produced 217.4 MMBBL (34.5 million m 3) of oil and 160.7 MMBBL (25.5 million m 3) of water. Morag had produced a total of 2.6 MMBBL (0.41 million m 3) through a single well, 16/29a-Al, prior to the well dying in 1994. Mary reservoir has produced 2.83 MMBBL (0.45 million m 3) to date, 0.52 MMBBL (0.81 million m 3) through 16/29a-A21 and 2.32 MMBBL (0.37 million m 3) through 16/29a-A25.
600
P. M. CHANDLER & B. DICKINSON
Daily rate. MBBL 1 O0 Maureen - Palaeocene 80
Cumulative, MMBBL 250
200
~ /
l~ ? "kV,t
.,//
60
.~,~ II ')1-
II\_
I
I ~^}~l,)^f,'~//"~
40
0
t'/"
It,
>.
~ - ~
~
i
150
i
"
100
I~ /
Sep-83 Sep-86Sep-89Sep-92Sep-95Sep-98 Daily rate, MBBLL 10
Cumulative, MMBBL
3.0
Mary - Jurassic
r'-
-
/
2.5
/ /
2.0
/
1.5 1.0 0.5 0 Nov-91
I
I
Nov-93
Nov-95
Nov-97
Cumulative,
Daily rate, MBBL 12 Morag - Zechstein
10
I 0.0 Nov-99
/
The authors thank the Maureen Field partner companies for permission to publish this paper. We would also like to thank all those who have contributed to the success of the Maureen project since its discovery in 1972.
References
2.5
ANDERTON,R. 1993. Sedimentation and basin evolution in the Paleogene of the Northern North Sea and Faroe - Shetland Basins. In: PARKER,J. R. (ed.) Petroleum Geology q/'North West Europe." Proceedings of the Fourth Conference. Geological Society, London, 3 l. CAMERON, T. D. J. 1993.4. Triassic, Permian and Pre-Permian of the Central and Northern North Sea. In: KNox, R. W. O'B. & CORDEY,W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. CAYLEF, G. T. 1987. Hydrocarbon migration in the Central North Sea In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology' of North West Europe. Graham & Trotman, London, 549-555. CUTTS, P. L. 1991. The Maureen Field, Block 16/29a UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields. 25 Years Commemorative Volume. Geological Society Memoir, 14, 347-352. DEN HARTOGJAGER, D., GLEES,M. R. & GRIFFITHS, G. R. 1993. Evolution of Paleogene submarine fans of the North Sea in space and time. In: PARKER,J. R. (ed.) Petroleum Geology of North West Europe." Proceedings of the Fourth Conference. The Geological Society, London, 59-71. DICKINSON, B. 1996. The Puffin Field: the appraisal of a complex HP-HT gas-condensate accumulation. In: HURST, A. et al. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publication, 114, 299-327. KNOX, R. W. O'B. & HOLLOWAY,S. 1992. Paleogene of the Central and Northern North Sea. In: KNOX,R. W. O'B. & CORDEY,W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. LAMB, R. C., MCGAUGHRIN, P. M., D'HEUR, M. & CUTTS, P. L. 1992. Maureen Field - UK Central Graben, North Sea In: AAPG Atlas of Oil and Gas Fields of the World." Structural Traps VI. American Association of Petroleum Geologists, Tulsa, 175-196.
2.0
/
1.5 1.0 0.5
,/
~'
i
3an-93
Field production rate for the Maureen Palaeocene is shown in Figure 15. Maureen Palaeocene production peaked in May 1984 at approximately 96000 BOPD (15260m3/day), declining by the second quarter of 1999 to less than 5000 BOPD (795 m3/day). The most prolific well was 16/29a-A7, which produced 36 MMBBL (5.7 million m 3) at an average rate of 6575 BOPD (1045 m3/day) over 15 years. The shortest-lived well was 16/29a-A6, which produced approximately 6 MMBBL (954 200m 3) at an average rate of 5480 BOPD (0.95 million m3/day) over 3 years. Initially Maureen Palaeocene production was dominated by reservoir depletion drive and pressure dropped from 3792 psig (261 bars) at datum to approximately 2500psig (172 bars). Reservoir pressure increased in response to water injection. A pressure differential of approximately 450 psi (31 bars) has developed between the western (+3000psi, 207 bars) and eastern (+2550psi, 176 bars) wells, due to predominance of water injection on the western flank. Morag production achieved a maximum rate of 12 000 BOPD (1907m3/day) in 1991, but declined rapidly to below 4000 BOPD (636 m3/day) in 6 months. Morag was shut-in after 45 months at a rate of under 1000 BOPD (160 m3/day). Mary commenced production through one well in November 1991 at 9392 BOPD (1493 m3/day). This declined to 357.3 BOPD (57m3/day) in October 1992. In August 1997 a second Mary well came on-stream and flowed 1859 BOPD (296m3/day). This increased to a maximum of 6615 BOPD (1052m3/day) in the third month and then declined erratically to 2747 BOPD (436 m3/day) by November 1998. The field was shut-in when the rate was 60 BOPD (less than 10m3/day).
3.0
/
3an-92
P r o d u c t i o n rate
MMBBL
/
Jan-91
(Fig. 14). This compares with the Annex B prediction of 52% and the 1985 prediction of 47%. The Morag recovery factor, computed from the material balance STOIIP and production at shut-in, was 50%, while that for Mary was 9%.
3an-94
00 9
Jan-95
Oil, rate Water, rate Oil, cumulative Water, cumulative Fig. 15. Cumulative production Maureen Field. Recovery factor
The actual recovery factor from the Maureen Palaeocene pool at field shut-in was 54.6%. The 1996 reservoir model predicted the ultimate recovery factor at the end of economic life to be 55%
MAUREEN FIELD NEWTON, S. K. & FLANAGAN, K. P. 1993. The Alba Field: evolution of the Depositional Model. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the Fourth Conference. Geological Society, London, 216-249.
601
UNDERHILL, J. R. & PARTINGTON, M. A. 1993. Jurassic thermal doming and deflation in the North Sea: implications of the sequence stratigraphic evidence. In: PARKER, J. R. (ed.) Petroleum Geology of North West Europe: Proceedings of the Fourth Conference. Geological Society, London, 337-345.
Maureen Field data summary Units
Maureen (Palaeocene)
Mary
Morag
fl
4-way dip over salt dome -7950 -8730
Updip p i n c h - o u t t r a p -10050 10750
Stratigraphic -9200 10700
-8730
- 10 646
- 10 602 ODT
780
•
1400
Maureen Formation
Hugin Formation
Danian-Thanetian 125-450 0.4-0.7 15-27 10-1500 67 15
Late Jurassic 10-150 0.8 18-22 5-150 80 5-20
Morag Member, Turbot Anhydrite Formation Permian 300 0.67 Matrix 2.6 Fracture 85 0.5-25
~
36 Black oil
32 Black oil
31.3 Black oil
cp psia psig SCF/STB BBL/MMSCF STB/RB SCF/RCF
0.7 1786 393 1.29 -
0.7 2060
0.566 1938
550 1.33 -
750 1.614 -
NaC1 eq ppm ohm m
20 000-40 000
acres acre ft ft psi psi/ft ~ MMBBL BCF %
4100 854 000 -8300 3792 0.32 247 398 55 Aquifer 217.4 -
355 26 600 - 10 217 6262 0.325 274 25.0 9 Depletion drive 2.83 -
1175 19 400 -9800 6113 0.32 270 5.0 50 Solution gas 2.6 -
Trap Type Depth to crest Lowest closing contour GOC/GWC OWC Gas column Oil column
fl
Pay zone Formation Age Gross thickness Net/gross Porosity average (range) Permeability (range) Petroleum saturation average (range) Productivity index
ft % mD % BBL/D/psi
Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
Formation water Salinity Resistivity
Field characteristics Area Gross rock volume Reservoir datum Initial pressure @ datum Pressure gradient Temperature @ datum Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
MMBBL BCF MMBBL
The Moira Field, Block 16/29a, UK Central North Sea PETER
M. C H A N D L E R 1 & B A R B A R A
DICKINSON 2
1 Phillips Petroleum Company United Kingdom Ltd, 35 Guildford Road, Woking, Surrey GU22 7QT, UK Present address." East House, Threeways, Star Hill, Churt, Surrey GUIO 2 H W (e-mail:
[email protected]) 2 Dickinson GeoConsulting, 51 Medfield Street, Roehampton, London SW5 4JY, UK Abstract: The Moira Field, discovered in 1988, lies on the Maureen Shelf, 10km SSW of the Maureen Field. The reservoir comprises submarine fan sandstones in a four-way dip closure, draped over a Middle Jurassic fault block. The good quality reservoir (porosity 17-25%, permeability 80-400 roD) flowed 5100 BOPD of 42 ~ API oil in the discovery well. STOIIP was initially calculated as 20 MMBBL, but seismic pick and depth conversion uncertainites were revealed by later drilling. The most recent (1998) calculation yielded STOIIP of 12.4 MMBBL. Reserves of 4.2 MMBBL (34%), have been produced through a single deviated well tied-back to the Maureen platform. The field was shut-in in 1999. The Moira Field lies in U K Block 16/29a, approximately 10km SSW of the Maureen Field platform (Fig. 1). The field lies in approximately 320ft (97.5m) of water close to the intersection of the Viking, Central and Witch Ground Grabens. The Moira Field reservoir is formed by Palaeocene deepwater sandstones, very slightly younger than those of the nearby Maureen Field.
History
Pre-discovery Block 16/29 was awarded in the third U K Offshore Licence round (1970) to a consortium led by Phillips Petroleum. The partnership now comprises Phillips Petroleum Co. U K Ltd (33.78%, Operator), Fina Exploration Ltd (28.96%), Agip (UK) Ltd (17.26%), BG International Ltd (11.50%) and Pentex Oil Ltd (8.50%). Block 16/29 was interpreted to lie within a belt of productive Early Tertiary sandstones. These were known to extend some 250 km from the Cod Field northwards via the Forties Field to the Frigg Field. The discovery of the nearby Maureen Field in 1973 had proved the reservoir quality of the Palaeocene sands in this area. By 1987, three 2D seismic surveys totalling 400 line kilometres had been shot with the aim of identifying satellites which could be tied-back to the Maureen facilities. Interpretation of the data revealed a low relief, four-way dip closure at Top Palaeocene sand level, with faults on the western and southern flanks. The structure was tested in 1988 by well 16/29a-8. Following stuck-pipe, due to the hole packing off at the Horda Formation Balder Formation boundary, the well was side-tracked. It then encountered 56 ft (17 m) net oil in sandstones of the Maureen Formation below 8800 ft (2440 m) True Vertical Depth sub-sea (TVDss). The well was drilled to total depth of 14 406 ft (4391 m) TVDss in the Rattray Volcanics Member (Pentland Formation, Middle Jurassic). A Drill Stem Test (DST) of the upper 22 ft flowed 42 ~ API oil at a maximum rate of 5100 barrels of oil per day (BOPD) (811 m3/day). Revision of the maps and other reservoir studies in the light of the well results indicated stock tank oil initially in place (STOIIP) of 20 million barrels (MMBBL) (3.2 million m3). Reserves were estimated to be 6.8 M M B B L (1.1 million m3), and an Annex B was submitted in 1990. The development was originally planned on the basis of a single vertical producer well tied-back to the Maureen Platform by a subsea flowline. Water injection was not planned, the extensive regional aquifer being considered to provide sufficient pressure support. Later studies suggested that higher recovery was achievable through a horizontal well, since the greater deliverability could be achieved for lower drawdown, thus minimizing coning. The development plan was modified to employ a deviated pilot hole to confirm the exact top sand elevation, and then to plug back and side-track into a horizontal wellbore for completion. In 1990, the discovery well was side-tracked, as 16/29a-8z, to provide the deviated pilot hole for the planned production well.
It penetrated 54 ft (16.5 m) net pay to the west of the discovery well, but the massive sandstone seen in well 16/29a-8 was divided by a significant mudstone bed (see Fig. 6). This raised concerns that a horizontal producer would not be able to drain the reservoir properly. The pilot hole tested at a maximum rate of 5150 BOPD (819m3/day oil) and 1.2 million standard cubic feet of gas per day ( M M S C F D ) (34 million m3/day). The well was completed with gaslift, and was tied-back to the Maureen platform. The field came on-stream in August 1990. In 1993, well 16/29a-ll was drilled from the same surface location to a target 4 km to the southeast, to evaluate possible additional reserves in the southeastern lobe of the Palaeocene structure and to investigate the Mesozoic section. Two side-tracks, 16/29a-llz
Fig. 1. Location of Moira Field.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 603-609
603
604
P . M . CHANDLER & B. DICKINSON
and -1 l y, penetrated the mapped edge of the Moira accumulation, but did not confirm additional reserves. Indeed, the well resulted in downward revision of STOIIP to 10.8 M M B B L (1.7 million m3), because top reservoir came in low to prognosis as a result of seismic pick uncertainty (weak reflectors) and depth conversion uncertainties.
Structure The principal tectonic features are shown in Figure 2. The tectonic history and regional structure of the Greater Maureen area have been described elsewhere (Chandler & Dickinson 2002).
L o c a l structure The Moira Field was originally mapped as a low-relief, four-way dip closed structure resulting from drape over a Middle Jurassic fault block at the eastern edge of the Maureen Shelf. Post-discovery, the mapping was revised and the structure appeared as two lobes, one penetrated by the discovery well and another to the southeast separated by a narrow neck. Annex B depth conversion was by the average velocity method, controlled by 12 wells. The 1994 3D seismic data were acquired in a north-south direction, with inline and trace spacing of 12.5 m; an example east-west line across the field is shown in Figure 3. It reveals the low relief Moira feature, overlying an eastward-dipping Middle Jurassic fault block. The eastern end of the line shows the edge of the Late Jurassic Maria Basin, the source of the oil in Moira. The structure map resulting from interpretation of these data also shows two lobes, although the neck separating them is wider than in earlier interpretations (Fig. 4).
Fig. 2. Principal tectonic features.
Closed height is approximately 75ft (23m) above the oil-water contact (OWC) at 8927 ft (2721 m) TVDss.
Stratigraphy The pre-Palaeocene stratigraphy of the Greater Maureen area is discussed by Chandler & Dickinson (2002). Within the Palaeocene itself, there are some features of the Maureen Formation in the Moira Field which differ from those seen in the Maureen Field. The basal part of the Maureen Formation in the Maureen Field contains chalk debris flows and slumps derived from the JaerenUtsira High to the east. These are not seen in the Moira Field, the basal section being composed of calcareous mudstones, transitional from the underlying chalks and sandstones (Fig. 5). The Maureen Formation at Moira is approximately 700ft (213m) thick, compared with 450 ft (137 m) on the west flank of Maureen, indicating that the Danian-early Thanetian depocentre lay to the west of the Maureen Field. Later lowstand fans in-filled topography on the basin floor so that younger sands, such as those of the Mey Sandstone Member (Lista Formation), pinch-out immediately west of the Moira Field. Early work on the Moira reservoir interpreted the uppermost sandstones as belonging to the 'Andrew Formation', that is equivalent to Mey Sandstone Member, Lista Formation (Knox & Holloway 1992). However, a recent review of the biostratigraphic data dates all the reservoir sands as older than the Cenodiscus lenticularis biomarker, that is within the Maureen Formation (Fig. 5). However, the data also indicate that the uppermost sandstones in the Moira Field reservoir are slightly younger than the uppermost sandstones in the Maureen Field, suggesting that the sand fairway was moving westwards with time.
MOIRA FIELD
605
Fig. 3. Seismic line W - E across Moira Field. For location see Figure 4. Note low relief feature at Top Maureen reservoir horizon; eastwards dipping fault block at Middle Jurassic level, and Late Jurassic Maria Basin to east of Middle Jurassic fault block.
Fig. 4. Depth structure map, Top Maureen Formation reservoir.
606
P. M. CHANDLER & B. DICKINSON
Fig. 5. Palaeocene lithostratigraphy (from Knox & Holloway 1992), log display and CPI from 16/29a-8, the Moira discovery well, and principal biomarkers.
Trap The Moira Field sandstones are closed by four-way dip, formed by drape over an underlying Middle Jurassic fault block. The top and side seal is provided by mudstones of the Lista Formation, the basal Lista mudstones providing sufficient vertical and lateral separation from the Mey Sandstone Member to maintain seal. The Moira reservoir is faulted to some degree, but the faults are minor and do not threaten the seal.
mately 300 ft (91 m) of core is available from the 16/29a-8, 16/29a-8z and 16/29a-1 ly discovery and production wells. Figure 6 shows the reservoir section in these wells.
Lithofacies
High-density turbidite sandstones. These are fine- to mediumgrained, moderately to moderately well sorted, clean sandstones in units up to 7.5 ft (2.3 m) thick with sharp tops and bases. Individual units are stacked to form massive bodies, which may be over 50 ft (15.2 m) thick. Dewatering structures are common throughout. Variations in the type of dewatering structure through the sands are ascribed to varying degrees of remobilization, the majority having dewatered in situ, but some having been fully remobilized. The sandstones are sub-lithic to sub-feldspathic arenites.
The Maureen Formation reservoir in the Moira Field is a sequence of coarse clastic deposits comprising high-density turbidite sandstones, remobilized deposits, matrix-supported debris flows, and hemipelagic mudrocks with low-density turbidite stringers. The massive sandstones predominate and the matrix-supported debris flows are rare. Chalk slumps and debris flows are absent. Approxi-
Remobilized deposits. These comprise slump blocks and slurry deposits. The former are fine-grained, relatively well-cemented sandstone blocks and clasts within heterolithic sandstone-mudstone packages. The latter are chaotic assemblages of mud clasts in a typically fine-grained sandstone matrix.
Reservoir
MOIRA FIELD
607
Fig. 6. Log display from wells 16/29a-8z, 16/29a-8 and 16/29a-1 ly showing Moira reservoir interval. For location see Figure 4. Note massive sandstone units and intra-reservoir mudstones at 8900 ft TVDss in well 16/29a-8z.
Matrix-supported debris flows. These comprise thin chaotic beds of mudstone and sandstone clasts supported in a very fine-grained sandstone matrix. They typically have sharp bases and tops.
The diagenetic sequence is: (1) (2)
Hemipelagic mudstones and thin sandstone stringers. Within the upper part of the Moira reservoir, these are typically dark-grey, fissile, non-calcareous mudstones which are locally pyritic, although occasional lighter grey calcareous beds are seen. Lower in the reservoir, the light grey-green calcareous mudstones predominate. The mudstones are interbedded with thin (less than 1 ft) sandstones with typically sharp bed boundaries.
(3) (4)
(5)
growth of authigenic quartz, with localized major degradation of porosity and permeability; kaolinite partly intergrown with the authigenic quartz, producing moderate degradation of poroperm; plagioclase overgrowths on kaolinite platelets, with local minor poroperm degradation; dissolution of K-feldspars and rock fragments, moderate porosity enhancement and permeability improvement in better quality sandstones; and cementation by calcite or ferroan calcite and calcitization of K-feldspar, localized major reduction of poroperm quality, which is typically associated with mudrocks and sandstones immediately adjacent to calcareous mudstones.
Depositional setting The sequence of predominantly massive high-density turbidite sandstones, hemipelagic mudstones, and rarer, low density turbidites and debris flows is consistent with deposition in lobes on the middle or outer parts of a submarine fan. In particular, the absence of primary stratification, pebbly lags and fining or thinning upwards beds suggests a non-channelized environment.
Pore types and diagenesis The dominant pore system within the massive sandstones is macroporous, comprising open, well-connected interparticle, primary porosity, with local oversized pores due to dissolution of feldspar. Below the OWC, the same sandstones have a system dominated by poorly connected or isolated interparticle primary porosity, with some secondary dissolution pores and a distinct component of intercrystalline microporosity.
Porosity and permeability The low degree of diagenetic alteration seen in the massive sandstones has resulted in a good quality reservoir in which core porosity is typically in the range 17-25% and permeability is 80 to 400mD (Fig. 7; upper ellipse). In the thinner-bedded turbidites and debris flow material however, porosity is lower and permeability is up to an order of magnitude lower than in the massive sandstones (Fig. 7; lower ellipse).
Pressure relationships The Moira reservoir is normally pressured, with initial reservoir pressure of 3939psia (272.6bars) at datum of 8972ft (2735m) TVDss. The reservoir fluid gradient is 0.32 psi/ft and the OWC is at 8927 ft (2721 m) TVDss.
608
P . M . CHANDLER & B. DICKINSON
Fig. 7. Core porosity v. horizontal permeability, Moira Field discovery and production wells. Note: higher permeability for given porosity in massivebedded sandstones (upper ellipse) compared with thinner-bedded turbidites and debris flows (lower ellipse).
Source Source beds The Moira Field oils were sourced from the organic-rich shales and mudstones of the Kimmeridge Clay and Heather Formations. An earlier paper on the Maureen Field (Lamb et al. 1992, quoting Cayley 1987) reported regional average total organic carbon (TOC) contents of approximately 8% for the Kimmeridge Clay with a maximum in excess of 15%. Recent data from the immediate Moira/ Maureen area indicate TOC in the range 5.5-7% in the upper parts of the Kimmeridge Clay Formation, with 3 to 4% TOC in the lower parts, and approximately 2 to 3% in the Heather Formation. Earlier published work suggested that the Maureen oils, which are low G O R oils similar to the Moira oils, were sourced from the Kimmeridge Clay of the Outer Witch Ground Graben, some 15 km from the field (Cutts 1991; Lamb et al. 1992). However, recent unpublished studies based on geochemical and basin modelling indicate that the most likely source for all the Moira and Maureen oils is the Kimmeridge Clay Formation in the Maureen Shelf and adjacent areas, rather than the Witch Ground Graben.
Maturation Cutts (1991) and Lamb et al. (1992) suggested that early maturity in the Witch Ground Graben area occurred during the mid- to Late Cretaceous, with peak oil generation during the early Tertiary. The more recent studies suggest that while oil expulsion may have started as early as 75 million years before present (Mabp) (Late Cretaceous) in the Fisher Bank Basin, generation and expulsion on the Maureen Shelf was much more recent, starting at approximately 35 Mabp (early Oligocene) and continuing to the present day.
Migration and charge Migration from the Kimmeridge Clay Formation source commenced at approximately 35Mabp. The most recent modelling
Fig. 8. STOIIP, reserves and recovery factor with time. 1990 - Annex B. 1993: three wells plus production history. 1998: three wells plus further production history.
studies show that oil migration commenced on the Maureen Shelf at approximately 30 Mabp, but that charging of the Moira reservoir did not begin until approximately 10Mabp. The modelling also suggests a dominant vertical migration path, with lateral migration only occurring once the charge had reached the Palaeocene sands.
Reserves and production At the time of Annex B submission in 1990, STOIIP was calculated to be 20 M M B B L (3.2 million m3): based on production from a single horizontal well, reserves were estimated to be 6.8 M M B B L (I.1 million m3), a recovery factor of 34% (Fig. 8). In 1993, following drilling of the three wells, including those testing the southeastern lobe, and with the benefit of three years' production history, STOIIP was revised downwards to 14.2 M M B B L (2.3 million m 3) with reserves of 5.9 M M B B L (0.95 million m3). Another calculation in 1998 resulted in further reduction of STOIIP to 12.4 M M B B L (1.97 million m 3) and reserves of 4.2 M M B B L (0.67 million m3), using a recovery factor of 34%. Volumetric STOIIP calculations showed considerable variability, principally due to seismic pick uncertainties and the low relief structure. The 1993 calculations resulted in higher recoveries than the Annex B estimates (41.5% compared with 34%), but the 1993 values had the advantage of actual production behaviour as an input to the reserves calculation. Even in 1998, the volumetric STOIIP was sufficiently problematical for the value to require increasing from 10.9 to 12.4 M M B B L to achieve a match to production history. The ultimate recovery was lower than initially predicted (4.2 v. 6.8 MMBBL) due to the much reduced STOIIP, but ultimate recovery factor, 34%, was the same as the initial prediction. Production commenced in July 1990, and peaked the next month at 5800 BOPD (922m3/day) (Fig. 9). A plateau rate of approximately 4600 BOPD (731m3/day) was maintained until January 1991; the rate then declined reaching 1000 BOPD (160m3/day) in March 1995. The field was shut-in in 1999 following sub-sea control problems which were not economically repairable. The authors thank the Moira Field partner companies for permission to publish this paper. We would also like to thank all those who have contributed to the success of the Moira Field project since its discovery in 1990.
M O I R A FIELD
Oil Water BPD
Oil cumulative MMBBL 5.0
8,oo0
4.0
4"
6,000
3.0
Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
609
~ API
42 Black oil
cp psig psig SCF/STB BBL/MMSCF SCF/RCF
0.435 1345 220 1.254 -
NaC1 eq ppm ohm m
20 000 -
4,000 2.0 2,000 1.0 \
Jul-90
I
I
Jul-92
Jul-94
-
1[\
..
0.0
Jul-96
Jul-98
Oil, rate Water, rate - Oil, cumulative production
Fig. 9. Moira Field production rate and cumulative production.
Formation water Salinity Resistivity Field characteristics Area Gross rock volume Reservoir datum Initial pressure Pressure gradient Temperature Oil initially in place Gas initially in place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
acres acre ft ft TVDss psi psi/ft ~ MMBBL BCF % MMBBL BCF MMBBL
-8898 3912 0.32 245 12.4 34 Aquifer drive 4.2 -
Moira Field data summary Units
Moira
ft ft ft ft ft ft
4-way dip draped over fault block -8850 -8950 -8927 77
Trap Type Depth to crest Lowest closing contour GOC/GWC OWC Gas column Oil column Pay zone Formation Age Gross thickness Net/gross Porosity average (range) Permeability (range) Petroleum saturation average (range) Productivity index
Maureen Formation Danian-Thanetian ft % mD % BOPD/psi
0.8 17-25 40-400
References CAYLEY, G. T. 1987. Hydrocarbon migration in the Central North Sea In: BROOKS, J. & GLENN[E, K. W. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 549-555. CHANDLER P. M. • DICKINSON B. 2003. The Maureen Field: Block 16/29a, U K Central North Sea. In: GLUYAS, J. G. & HICHENS, B. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 587-601. Cgrrs, P. L. 1991. The Maureen Field, Block 16/29a U K North Sea. In: United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society Memoir, 14, 347-352. KNOX, R. W. O'B. & HOLLOWAY, S. 1992. Paleogene of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. LAMB, R. C., MCGAUGHRIN, P. M., D'HEUR, M. & CUTTS, P. L. 1992. Maureen Field - U K Central Graben, North Sea. In: Atlas of Oil and Gas Fields of the World." Structural Traps VI. American Association of Petroleum Geologists, Tulsa, 175-196.
The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, 22/18, 22/23a, UK North Sea A. J. C. H O G G BP Exploration Operating Co. Ltd, Farburn Industrial Estate, Dyce, Aberdeen AB21 7PB, UK Abstract: This paper updates the earlier account of the Montrose and Arbroath Fields by Crawford et al. detailed in Geological Society Memoir 14, and gives an additional description of the Arkwright Field, a satellite Paleocene accumulation some 7 miles
SE of Arbroath. The Montrose, Arbroath and Arkwright Fields are located in the Central Graben of the U K North Sea (Fig. 1) and produce oil from the Upper Paleocene Forties Sandstone Member, a major turbidite depositional system that extends across the Central Graben and mantles the Forties-Montrose High. The combined STOIIP is estimated to be 644 MMBBL.
Early seismic reconnaissance identified two culminations - the southern of these was termed Arbroath following the 22/18-1 (2160 BOPD) discovery well drilled in 1969 and represented the first commercial oil discovered in the U K northern North Sea. The northern culmination was termed Montrose following the 22/18-2 (4190 BOPD) discovery in 1970. The Montrose field was deemed economically more attractive and was developed first with the installation of a conventional eight-legged platform leading to first oil in June 1976. Arbroath was developed later using a four-legged satellite platform linked to Montrose by four pipelines, leading to first oil April in 1990. The Arkwright field lies entirely within the P.291 licence awarded in 1964 and was discovered by well 22/23a-3 in 1990. Arkwright was developed as a sub-sea tieback designed to accommodate three wells,
History The Montrose and Arbroath fields are located within Blocks 22/17 and 22/18 awarded in the first Offshore Licence Round in September 1964, as parts of licences P019 and P020 to an Amoco operated partnership.
'-71__._ l~
....... 2:,......... ' ................................. 'i........... FORTIES
"
......
;
i ......... ~1
BRI
~ i ."
F I•
=
.~
Watson
i
<>
MonVrose
13 ikKItIIwa~
,Ib,~-t
' I ~' I~
GIIIwlU ;
. i
Arbroath
i i L_
20t i
18
21/24-4
.
q @~,
25
Ji
t V---~
- -~t 16
_I
r--
q17
~
1_ K
~..~II) [ Aik, vright ~ i o
I
5
1o
- -
Km ................................................................
i............i
Fig. 1. Location map.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 611-616.
611
612
A. J. C. HOGG
and came on-stream in 1996. The three Arkwright development wells have drilled a Forties Sandstone section that has experienced formation pressure depletion due to production from the adjacent Arbroath Field, and even the 22/23a-3 exploration well drilled a slightly depleted section due to Montrose Field production.
abandonment shales are recognized, representing the development of individual channel and lobe systems which can be correlated locally using high resolution biostratigraphy (graphic correlation).
Trap Structure The Montrose, Arbroath and Arkwright Fields flank the eastern margin of the Forties Montrose High which represents a relic structural feature from Late Jurassic rift within the Central Graben.
The fields comprise three separate four-way anticlinal structures of Forties Sandstone, sealed by mudstone of the Sele Formation. The structures show a relief in excess of 200ft that has been amplified as a result of differential compaction. The structures are believed to have formed as a result of deformation associated with the Alpine orogeny.
Stratigraphy The Paleocene Forties sandstone forms the principal reservoir succession in the three fields and is sealed by mudstone attributed to the Sele Formation. In sequence stratigraphic terms, the reservoir is contained within the Forties Sequence bound at the base by the Top Lista condensed horizon which is marked by a down-section influx of Apectodinium margarita and Spiniferites spectabilis acme. The Forties Sequence is boun-ded above by the Top Forties condensed horizon marked by a downsection influx of Apectodinium spp. including A. augustum. The Forties Sequence is interpreted as a submarine, lowstand fan deposit, introduced onto the Forties-Montrose Horst from the NW. The Forties Sequence is characterized by fine- to mediumgrained sandstone interbedded with dark grey siltstone and mudstone. A number of higher order depositional packages bound by
Fig. 2. Arbroath full field production from 1990.
Reservoir Regionally, the Forties Sandstone Member comprises a deep marine basin-floor fan deposited by mass-flow processes. Progradation was from the N W creating local channelized 'thicks' trending approximately NW-SE. In the Montrose, Arbroath and Arkwright area, the reservoir comprises up to 500 ft of turbidite channel and sandlobe deposits, as well as channel marginal sequences. The sandstone is mostly fine- to medium-grained and is often massive with dish or other dewatering structures. Individual 5 10ft thick packages are stacked, forming 50-100ft thick sandbodies. These may be described as Mutti's B1 Facies and are interpreted as turbidite channel or sandlobe deposits. Laterally, individual sandstone beds are thin and are less frequently stacked. Slumping at the channel margin is common.
Fig. 3. Arkwright fluid production history.
Fig. 4. Montrose field oil and water production and water injection 1976 1998.
614
A . J . C . HOGG
Montrose Field data summary Field name
Montrose
Units
Discovered
1970
Trap Type Depth to crest Lowest closing contour OWC Oil column
Domal Antiform 8040 8250 8250 210
ft ft ft ft
Forties Palaeocene 330/260-440 0.5/0.3-0.8 24/3-30 80/1-2000 55
ft ft % mD %
0.631 40 0.32 2348 (West)/2737 (East) 600 (West)/800 (East) 1.467 (West)/1.557 (East)
g/cc ~ API cp psig SCF/BBL RB/STB
l 11 000 0.027
mg/I ohm m
9910 748 000 3744 257 236 41 Aquifer drive/gas lift 98 Negligible
acres acre ft psi oF MMBBL %
Notes
Pay zone
Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Petroleum
Oil density Oil gravity Viscosity Bubble point Gas/oil ratio Formation volume factor
at reservoir conditions at reservoir conditions
Formation water
Salinity Resistivity
@ 257~
Field characteristics
Area Gross rock volume Initial pressure Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil Recoverable NGL/condensate
@ 8150 ft
MMBBL MMBBL
Production
Start-up date Production rate plateau oil Number/type of well
1976 28 000 8 producers 6 injectors
Minor diagenetic modifications have taken place during burial. Petrographically, the sandstone is subarkosic and contains small amounts of authigenic quartz, kaolinite and ferroan calcite that average 3 - 5 % of the rock. The cements have reduced porosity but have no significant effect on the overall facies control on porositypermeability relationships for the sandstone. Integrated core and log analysis indicates that most pay is within the massive sandstone occurring in stacked channels and sandlobes in the main depositional fairways and as sandlobes in the more marginal areas. The depositional architecture and reservoir heterogeneity appear to control fluid movement in a number of ways. Firstly, strong basal aquifer support is provided where the field is underlain by a thick succession of older Paleocene sandstone. In contrast, edge water drive, or injection, provides pressure support where mudstone underlies the reservoir. Secondly, upward water movement may be inhibited by mudstone facies deposited as a result of abandonment and thus generally laterally extensive enough to form
BOPD
local seals. This may restrict water movement but conversely may focus depletion along higher permeability layers and ultimately lead to water override. Thirdly, permeability heterogeneity occurs within channels, enhancing communication parallel to channel axes, but reducing communication towards the margins. Finally, baffles are created by slumps along channel edges. Depending upon the degree of baffling, they may isolate oil within poorly drained pockets, creating infill potential.
Source Oil in the three fields has been typed to the Late Jurassic Kimmeridge Clay Formation that is mature within the area to the west. The N-S trending extensional faults at the margins of the FortiesMontrose High are thought to have acted as conduits for migration some 10-20 million years ago.
615
MONTROSE, ARBROATH AND ARKWRIGHT FIELDS
Arbroath Fierld data summary Field name
Arbroath
Discovered
1969
Units
Notes
Trap
Type Depth to crest Lowest closing contour OWC Oil column
Domal Antiform 8030 8250 8250 220
ft ss ft ft ft
Forties Palaeocence 330 (260-440) 0.5 (0.3-0.8) 24 (3-30) 80 (1-2000) 55 (25-65)
ft ft % mD %
0.28 38 42 0.4 1991 490 1.327
g/cc o API cp psig SCF/BBL RB/STB
135 000 0.023
mg/I
7712 555 000 3700 245 334 51 Aquifer drive/gas lift 170
acres acre ft psi oF MMBBL %
tilted
Pay zone
Formation Age Gross thickness average (range) Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range) Petroleum
Oil density Oil gravity Viscosity Bubble point Gas/oil ratio Formation volume factor
at original conditions
Formation water
Salinity Resistivity
ohm m
@ 245~
Field characteristics
Area Gross rock volume Initial pressure Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil
@ 8500 ft
MMBBL
Production
Start-up date Production rate plateau oil Number/type of well
1990 42 000 12 production wells 8 injection wells
Reserves and production STOIIP for the A r b r o a t h field is estimated to be 334 M M B B L . The A r b r o a t h field proved reserves figure of 169 M M B B L represents an increase of 59 M M B B L since first oil in 1990 due to an u p w a r d revision of STOIIP (from 278 M M B B L ) and improved recovery due to better than expected reservoir connectivity and pressure support from peripheral water injectors (Fig. 2). The Arkwright field STOIIP is estimated to be 74 M M B B L . Arkwright proved reserves have also increased since first oil in 1996. This is due to an upward STOIIP revision (from 43 M M B B L ) and improved recovery as a result of better than expected aquifer support. During 1998, one of the three producing wells was turned around to water injection. This i m p r o v e d reservoir sweep from the N W and increased reservoir pressure. Proven reserves are currently estimated to be 25 M M B B L . Production from Arkwright peaked shortly after start-up at 14 000 BOPD. It has n o w d r o p p e d to about 3000 B O P D (Fig. 3).
BOPD
STOIIP for the M o n t r o s e field is currently estimated to be 236 M M B B L . This represents an upward revision of 11 M M B B L since first oil in 1976. The greater oil in place has been offset by a reduction in recovery factor due to poorer than expected reservoir performance following an extended shut-in when the A r b r o a t h platform was tied-in during 1990. Current reserves are estimated to be 95 M M B B L , although significant upside potential has been identified by peripheral drilling on the flanks o f the field. The production profile for M o n t r o s e is shown in Figure 4.
References CRAWFORD,R., LITTLEFAIR,R. W. & AFFLECK,L. G. 1991. The Arbroath and Montrose Fields, Blocks 22/17, 18, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields'." 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 211-217.
616
A.J.C.
HOGG
Arkwright Field data summary Field name
Arkwright
Discovered
1990
Trap Type Depth to crest Lowest closing contour OWC Oil column
Four way dip closure 8500 8607 8607-8620 151
ft ft ft ft
Pay zone Formation Age Gross thickness Net/gross Porosity average (range) Permeability average (range) Petroleum saturation average (range)
Forties Palaeocene 502 0.78 (0.6-0.9) 19 (16-21) 40 (20-50) 51 (25-73)
fl ft %
Petroleum Oil density Oil gravity Viscosity Bubble point Gas/oil ratio Formation volume factor
0.66 38-42 0.43 2670 700 1.456
g/cc ~ API cp psig SCF/BBL
Formation water Salinity Resistivity
55 000 0.023
ppm C1ohm m
Field characteristics Area Gross rock volume Initial pressure Temperature Oil initially in place Recovery factor Drive mechanism Recoverable oil
1473 12 600 3700 250 73 34 Aquifer drive 25
acre acre fl psi ~ MMBBL %
Production Start-up date Production rate plateau oil Number/type of well
1996 8000 2 producers 1 injector well
Units
Notes
free water level, may be tilted
mD %
at reservoir pressure at reservoir pressure
RB/STB
MMBBL
BOPD
@ 245~
The Nelson Field, Blocks 22/11, 22/6a, 22/7, 22/12a, UK North Sea J. M. K U N K A 1, G. W I L L I A M S 2, B. C U L L E N 3, J. B O Y D - G O R S T l, G. R. D Y E R 2, J. A. G A R N H A M
l,
A. W A R N O C K 1, J. W A R D E L L 1, A. D A V I S 1 & P. L Y N E S 1
1Enterprise Oil plc, Victoria Tower, 62 M a r k e t Street, Aberdeen A B l l 5P J, U K 2 GeoStrat Ltd., Motherwell Business Centre, Dalziel Street, Motherwell M L 1 1P J, UK 3 Reservoir Associates North Sea, Hollydene, Brookside, Kingsley, Cheshire W A 6 8BG, U K
Abstract: The Nelson Field is located in Blocks 22/11, 22/6a, 22/7 and 22/12a in the UK Central North Sea. Nelson is a simple dip closed structure and is one of a series of Palaeocene Forties Sandstone Member oil accumulations situated on the FortiesMontrose High. The first exploration well on the prospect, 22/11-1, was drilled by Gulf Oil in 1967. Although hydrocarbon shows were encountered in a heterolithic section of Forties Sandstone Member, the well failed to flow on test and was abandoned. 3D seismic data were first acquired in 1985 and led to the discovery of Nelson in 1988 when the 22/11-5 well was drilled by Enterprise Oil plc. Following appraisal drilling, Nelson was granted production consent and the field came on-stream in February 1994. The hydrocarbon type is a light 40~ API crude with a GOR of 555 SCF/BBL and is believed to be sourced from the East Forties Basin. The Nelson Field is developed from a 36 slot minimum facilities platform. Currently there are 23 platform producers, four sub-sea producers and four platform water injectors. Oil export is via the Forties Pipeline System and gas export is via the Fulmar Gas System. Oil originally in place is estimated at 790 million barrels of oil (MMBBL). Up to end1999, the field had produced 261 MMBBL. Since the field was described by Whyatt et aI. (1992), a further 28 wells have been drilled resulting in the collection of a considerable amount of new geological and geophysical data. This now includes a total of 6500 ft of Palaeocene core and 4D seismic data. This has enabled a more detailed understanding of the structure and sequence stratigraphy of the Nelson Field. This paper illustrates the importance of seismic mapping, high resolution biostratigraphy and sedimentology in developing the Nelson Field model.
The Enterprise Oil plc operated Nelson Field is located in the U K sector of the Central North Sea approximately 180 km E of Aberdeen in 275 ft of water. It is one of a series of Palaeocene oil accumulations situated on the Forties-Montrose High (Fig. 1), a region of elevated Permian and Devonian basement. The field is a simple dip closed structure formed by structural uplift related to reactivation of deep seated basement faults. The reservoir is a submarine channel sandstone of the Palaeocene Forties Sandstone Member which, in the Nelson Field, comprises three principal channel complexes that run in a N W - S E direction across the structure. The Forties Sandstone Member occurs within Sele Unit S1 (Knox & Holloway 1992) which is subdivided into five zones in Nelson, Zones 1 to 5, of which Zone 5 is the youngest (Fig. 2). The Forties Sandstone Member is informally divided into upper and lower 'Members' (Whyatt et al. 1992), herein referred to as units, the boundary being placed at the top of a major field-wide slump (Zone 2). The field is filled to spill and connects via a regionally extensive acquifer to the Forties Field in the north and the Montrose and Arbroath Fields to the south. Nelson straddles four production licences and because of this the field has been unitized, resulting in the following interests by licence tract:
Block
Licence
Owner
% Interest
22/11
P 069
22/6a
P 255
22/7
P 087
22/12a
P 077
Enterprise Oil plc (Operator) Elf Intrepid Shell Esso Summit Svenska Lundin Oil UK Svenska
36.878737 11.524609 5.762304 21.228135 21.228135 0.348750 0.401250 1.314040 1.314040
Since the field was described by Whyatt et al. (1992), a further 28 wells have been drilled resulting in the collection of a considerable amount of new geological and geophysical data. This now includes a total of 6500 ft of Palaeocene core and 4D seismic data. This has enabled a more detailed understanding of the structure and sequence stratigraphy of the Nelson Field. This paper illustrates the
importance of seismic mapping, high resolution biostratigraphy and sedimentology in developing the Field model.
History The first exploration well on Nelson, 22/11-1, was drilled and unsuccessfully tested by Gulf Oil in 1967. Although aimed at a deeper target, the well encountered oil shows in a heterolithic section of Forties Sandstone Member. A drill stem test was run over a 489 ft section of Sele Shale and Forties Sandstone Member over a 6.5 hour duration. The test is recorded as delivering gas and oil cut mud with an oil gravity of 36.4 ~ API. Well 22/11-1 was subsequently plugged and abandoned. It was not until 1985 that 3D seismic data was acquired over Blocks 22/11 and 22/6a which led to the drilling of the field discovery wells, 22/11-5 and 22/11-6, in 1987 by Enterprise Oil plc following a series of asset swaps and farm-ins (Whyatt et al. 1992). This led to a 13 well appraisal campaign culminating in the drilling of 22/12a-6 in 1990. These included six wells in Block 22/11, four wells in Block 22/6a, two wells in Block 22/12a, and one well in Block 22/7. Well 22/11-11 proved a southerly extension of the field, now known as the 'southern satellite' and wells 22/12a-5 and 22/12a-6 successfully proved an easterly extension. Well 22/7a-3 tested a small accumulation to the east which proved a deeper oil-water contact at 7513ft TVDss, some 43 ft deeper than the contacts observed across the main Nelson accumulation. Development consent for the Nelson Field was granted in July 1991. In 1997, well 22/11-N24 was drilled and proved up an extension of the field in the southwest which resulted in an extension of the field unit area. A second 3D seismic survey was acquired in 1990 to help plan the future development of the field. The development concept was a 36 slot minimum facilities platform (Fig. 3) with a four well sub-sea template tied back to the platform. The production facilities have a peak daily capacity of 160000 barrels of oil and 65 million cubic feet of gas. Total liquid capacity is 250 000 BBL. Hydrocarbon type is a light 40 ~ API oil with a G O R of 555 SCF/BBL. Live crude is exported via Forties to Cruden Bay and gas is exported to the Fulmar Gas Pipeline via Kittiwake to St Fergus. Production commenced on 18 February 1994 from ten predrilled development wells comprising eight platform and two subsea producers. Further development drilling continued between
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 617-646.
617
618
J. M. KUNKA E T AL.
Fig. 1. Location of Nelson Field in relation to Forties-Montrose trend and established infrastructure.
1994 and 1999 resulting in 19 platform producers, four platform water injectors and four sub-sea producers.
Trap The Nelson Field is situated on the Forties-Montrose High and forms a relatively simple, low relief anticlinal structure with fourway dip closure (Fig. 4). Crestal elevation is at 7192 ft TVDss with
an average field-wide oil-water contact at 7470 ft TVDss giving a maximum oil column of 278 ft. The main Nelson accumulation has a tilted oil-water contact as a result of pressure depletion from the Forties Field which ranges from 7449ft TVDss in the south of the field to 7501 ft TVDss in the northwest. Structural dip is around 2-3 ~ with few major faults. Those faults that do exist throw between 25-50 ft with little evidence of fault seal based on production data. There is some evidence from well-test pressure build-up data that faults may form baffles to fluid flow.
NELSON FIELD
619
Fig. 2. Nelson lithostratigraphy of Sele Unit S1.
The Nelson structure (Fig. 5) is believed to have developed in response to Eocene and Miocene Alpine tectonic events which led to reactivation of underlying deep seated basement faults (Whyatt et al. 1992). Above the Palaeocene, structural expression diminishes progressively and growth of the structure probably ceased by the mid-Miocene (Fowler 1975; Walmsley 1975). Later subsidence took place during the Pliocene allowing local modification of the structural expression to continue, due to differential compaction.
Regional setting The Forties Sandstone Member (Knox & Holloway 1992) represents the primary reservoir unit in the majority of hydrocarbon accumulations situated on the Forties-Montrose High in the Central North Sea (Fig. 6). In the Nelson area, it is underlain by a thick and laterally extensive sequence of Lista Formation, partially equivalent to the Balmoral and Andrew fan systems. The Forties Fan System evolved during a very short period of geological time, perhaps between 56 and 54.8 Ma (Berggren et al. 1995). It represents a number of phases of fan activity and outbuilding, channel switching (avulsion cycles) and eventual abandonment which can be demonstrated from biostratigraphic and sedimentological infor-
mation derived from the Nelson Field (see section on reservoir stratigraphy below). The main period of Forties Fan deposition occurred during a predominantly transgressive phase synchronous with the thermal decay of the uplifted Scottish Tertiary Volcanic Province. Continuing thermal decay resulted in rising sea levels leading eventually to the flooding of the shelfal area, confinement of sandy deposition to the Dornoch delta within the Moray Firth and cessation of deep-water submarine fan sedimentation on the FortiesMontrose High. The sandstones and siltstones of the Forties Sandstone Member finally gave way to hemipelagic suspension sedimentation characterized by Sele Formation $2 and $3 shales (Knox & Holloway 1992).
Biostratigraphy and zonation of the Nelson reservoir High resolution biostratigraphy forms an important part of the reservoir zonation when integrated with seismic interpretation, lithostratigraphy, sedimentology and dynamic reservoir data. The reservoir zonation scheme forms the basis of zonal reservoir property mapping e.g. net/gross ratio, porosity and permeability. Reservoir property maps are the building blocks of the reservoir
620
J . M . K U N K A E T AL.
cA ,L)
9
z
NELSON FIELD
Fig. 4. Top Sele Unit SI depth structure map TVDss (contour interval = 50 ft). Reservoir above oil-water contact shaded.
621
622
J. M. K U N K A ET AL.
Z
9
. ,...~
NELSON FIELD
Fig. 6. Palaeocene palaeogeography of the Central Graben Area. Forties Sandstone Member depositional system [modifiedafter Kantorowicz et Kulpez & van Geuns (1990)].
simulation model which is used to predict the future performance of the reservoir and to highlight areas that may become future infill drilling targets. Zonal reservoir mapping in the Upper Forties reservoir is constrained by the Top Forties and a deeper seismic event coinciding with the top of the lower Forties unit, both of which have been mapped on intercept data. Individual zonal isochores are proportioned based on well data, constrained by the seismically derived upper Forties Sandstone Member isochore (Fig. 7). The Nelson Field biozonation scheme has become established through the appraisal and development stages of the field, based on quantitative analyses of 59 wells. The scheme has been developed and refined during the wellsite monitoring and geosteering of seven long reach and horizontal wells. In the Nelson Field, the basis for the zonal mapping is the identification of repeatable and field-wide bio-events. The events employed in this zonation include well documented regional events and local field-wide or sub-regional events which provide a robust chronostratigraphic framework for the reservoir zonation. The type of events used include regional inceptions and extinctions along with acmes and influxes. These are most commonly found in the finer grained heterolithic facies of the reservoir which are interpreted as channel abandonment events. These abandonment units are characterized by thin bedded tur-
623
al.
(1999) and
bidites and occasionally muddy debris flows. The sharp upwards transition from thin bedded heterolithic facies into the younger overlying erosional and depositional submarine channel facies is used in definition of intra-reservoir boundaries. The Nelson Field biozonation is based on a number of fossil groups, comprising marine dinoflagellate cysts, algae, diatoms, radiolaria and foraminifera, along with terrestrially derived pollen, pteridophyte miospores and fungal material. In addition, the recognition of reworked Lista Formation and basal Forties Sandstone Member sediments has played an important role in understanding the intra-reservoir stratigraphy. The Nelson Field biozonation (Fig. 8) comprises seven biozones (PP9a to PP9g) within the Sele Unit S 1, with further subdivision of biozones PP9f and PP9e. The bioevents described above can be quantified simply by numerical occurrence in the Nelson wells which reflects the reliability of the picks in defining the intra-reservoir zonation based on 51 vertical and sub-vertical wells (Fig. 9). Although some of the most reliable data are obtained from horizontal wells as a result of increased penetration length within shale beds, these are excluded from this analysis due to repeat penetrations. The key biostratigraphic events that define the reservoir zonation are highlighted in Table 1.
624
J. M. KUNKA ET AL.
Fig. 7. Upper Forties Sandstone Member isochore.
The events highlighted in bold in Table 1 are present in over 60% of Nelson wells and are highly reliable fourth order sequences, coinciding with seismic events which confirm their chronostratigraphic significance. The Nelson hydrocarbon reservoir occurs predominantly within the Forties Sandstone Member of Sele Unit S 1 which is characterized biostratigraphically by an increase in terrestrially derived microfloras, possibly as a result of change in sediment source in exposed vegetated delta plains to the northwest. The microfloral and microfaunal assemblages recovered from the uppermost Lista Formation and Sele Formation Units S1 and $2 claystones can be used to provide a palaeoenvironmental interpretation in a regional context. The main environmental changes are discussed with reference to Figure 8 Sele Formation Unit S1, Forties Sandstone Member, ranges and abundances of key taxa.
Lista formation Assemblages recovered from greenish-grey claystones of the upper part of the Lista Formation are characterized by abundant and diverse agglutinating foraminifera. These assemblages suggest a marine, outer shelf to upper bathyal environment with dysaerobic to aerobic sea floor conditions. Where cored, these sediments comprise heavily bioturbated soapy light green-grey claystones with abundant Zoophycos burrows. This distinguishes them from the non-bioturbated grey claystones of the Sele Formation which form the background sedimentation during the deposition of the Forties Sandstone Member (O'Connor & Walker 1993). The top of thisassemblage equates to the top of Zone PP8 and is broadly equivalent to the PT15/PT19.1 transition of Schr6der
NELSON FIELD
625
et0
. ,..,,~
O ~ ,.,,,~
O
Y~ H o i ....,q
,.o
626
J . M . KUNKA E T AL.
Bio Event
Fig. 9. Nelson Field bioevents. Numerical abundance in wells.
(1992). Thus a biostratigraphic rather than lithostratigraphic boundary is chosen.
Sele Formation SI Lower Forties Unit Zone 1
Zone 1 biozone PP9a, represents the establishment of the Forties Fan system in response to a fall in sea level following the Lista Formation maximum flooding surface. It is noted that Knox and Holloway (1992) place the top of the Lista Formation at the top of
Table 1. Nelson Field key biostratigraphic events Biozones
Reservoir zones
Depositional setting
PP9g/PP9fiv
Zone 5
Abandonment of the Forties Fan, submarine channel deposition in the eastern channel complex Western and eastern channel complexes dominant Western and eastern channel complexes dominant Central channel complex dominant Central channel complex dominant Regional slump event characterized by large scale lista reworking
PP9f iii and PP9f ii
Zone 4b
PP9fi
Zone 4a
PP9e ii and PP9e i
Zone 3b
PP 9d
Zone 3a
Lista Fm reworking
Zone 2
PP9b PP9a
Zone 2 Zone 1
PP8
Lista Formation
Channelized Facies dominant in the centre of the Field
this PP9a biozone. Within the Nelson Field biostratigraphic scheme, the Forties Sandstone Member is distinguished from the Lista Formation on the basis of anoxic bottom water conditions and associated lack of faunal and microfaunal diversity. The onset of Forties Fan sedimentation coincided with a cooler wetter climate, perhaps induced by pyroclastic activity (Schr6der 1992), which resulted in the establishment of anoxic bottom conditions and the elimination of an in situ benthonic microfauna by end Zone 1 (PP9a) times (Fig. 8). The increased volcanism probably created silica and nutrient enrichment of the water column, creating conditions favoured by a diatom microflora. Zone 1 is characterized by channel activity and possesses characteristic blocky log profiles with very little evidence of shale layers indicating a high degree of vertical aggradation and amalgamation. Channel sands of this age are believed to represent the early phase of axial fill of the submarine channel complexes e.g. in well 22/11-N24.
Zone 2
The top of Zone 2 represents the boundary between the upper and lower units of the Forties Sandstone Member in the Nelson Field. It can be readily identified from cuttings and core by the presence of extraformational microfloras and microfaunas derived from the Lista Formation and Zone 1 of the Forties Sandstone Member. It is the most robust intra-Forties seismic marker and can be correlated on a field-wide scale. The presence of abundant re-derived Lista Formation material within this lower unit of the Forties Sandstone Member is thought to be due to slope failure during a phase of sea level lowstand. The slumped and heterolithic nature of this reservoir unit is often reflected by the presence of a strong pressure break in postproduction wells indicating that this unit forms an intra-reservoir pressure seal. The reworking of Lista Formation microfaunas in itself is not diagnostic of Zone 2 as reworking is also recognized
NELSON FIELD in Zone 3a. However, there is a degree of chronostratigraphic significance associated with the Zone 2 slump event as it is a regionally mappable seismic event.
Sele Formation S1 Upper Forties Unit Zone 3 Subzone 3a. Zone 3a, equivalent to biozone PP9d, can be easily identified as the sand prone unit that overlies the Lower Forties Sandstone Member slump unit. It is characterized biostratigraphically by a progressive increase in terrestrially derived microfloras and kerogen, comprising miospores, fungal debris and humic kerogen
Fig. 10. Zone 3 net/gross.
627
(Fig. 8). The presence of major influxes of terrestrially derived spores and pollen indicates the maximum extent of the subaerial delta top and delta plain. Repeated occurrences of Lista Formation microfaunas throughout this zone could be the result of remobilization of Lower Forties age slumps or be related to channel incision in the Lower Forties age slumps. Zone 3a is characterized by major channel activity centred along the north-south axis of the Central Channel complex focused on the 22/11-N09/N18 area, and south towards the 22/11-N03/N08 and southern satellite areas where the system disperses and becomes less restricted (Figs 10 & 11). Deposition took place to a lesser extent in the Western Channel at this time. One of the thickest representative sections of Zone 3a is seen in well 22/1 l-N09 where 177 ft of submarine channel facies are penetrated. However, less
628
J.M. KUNKA ET AL.
Fig. 11. Zone 3 isochore. than 300 m to the east of well 22/1 l-N09, the age equivalent section in well 22/11-5 is much thinner and comprises channel margin heterolithics overlying a ripple laminated sandstone (Fig. 12). Seismic and well correlation sections illustrate the consistency of Zone 3 in a north-south direction along the Central Channel complex but demonstrate the variation in thickness of this reservoir subunit in an east-west direction (Fig. 13). The channelized nature of Zone 3a is confirmed by the presence of up to 15% erosional channel facies in well 22/1 l-N09 and up to 47% erosional channel facies association in well 22/11-11.
Subzone 3b. Zone 3b, equivalent to biozones PP9ei and PP9eii, represents the main period of fan aggradation in the Nelson Field
with deposition again focused along the axis of the Central Channel Complex as shown in the N T G and isochore maps (Figs 10 & 11). Miospore and pollen data indicate that the area of exposed vegetated delta plain was at a maximum during this time; this is reflected in a significant increase in terrestrial microfloras comprising pteridophyte miospores, Monoletes spp., Laevigatosporites spp., Cyathidites spp., Cicatricosisporites spp. and fungal debris (Fig. 8). Also present throughout this interval are significant numbers of the marine dinocyst Apectodinium spp. Angiosperm pollen is variably distributed through this part of the Forties Sandstone Member, being abundant in subzones PP9d to PP9ei and then increasing in numbers again in and above subzone PP9fiii. Schr6der (1992) suggests climatic control over the composition of angiosperm assemblages through this interval which could also reflect significant
N E L S O N FIELD
629
.3 . ,,,.q
"O
.3
,.o
o o
Z n
r r
|
. e ~ "-d
o . ,...~
~
0
o
~
~g
~
0
0
r~
.~
0
2~ ~
..,.~
630
Fig. 13. Nelson Field structural cross-sections.
J. M. K U N K A E T AL .
NELSON FIELD tectonic and volcanic episodes affecting sediment supply, run-off levels and water mass properties.
Zone 4 Subzone 4a. Evidence for initial flooding, which eventually led to the regional maximum flooding event at the top of Sele Unit S1, is seen from within subzone PP9eii. This is marked by an influx of diatoms in significant numbers and a progressive reduction in miospore numbers at the PP9eii/PP9fi (Reservoir Zone 3b/Zone 4a) boundary. The Central Channel Complex which predominated during the deposition of Zone 3 became less influential on sand fairway development in Zone 4 where main sedimentation was in the west and
631
east of the field (Figs 14 & 15). A remnant Central Channel Complex remained, focused around the area of wells 22/1 l-N03 and 22/11-7. The shift in deposition away from the central axis to the flanks of the Nelson Field could either be due to basement induced uplift along the axis of the Central Channel Complex or simply a reduction in accommodation space.
Subzone 4b. During the time of accumulation of Zone 4b sediments, deposition remained focused in the Eastern and Western Channel complexes representing the final stages of fan deposition prior to the abandonment of the Forties Fan System in Zone 5. Core data show this zone to be characterized by predominantly depositional channel facies with rare erosional channel facies.
632
J. M. KUNKA ET AL.
Fig. 15. Zone 4 isochore.
Evidence for abandonment of the Forties Fan System which began in late Zone 3b times continued in Zone 4b. Biofacies show an upward trend towards decreasing terrestrial influence and increasing marine influence e.g. diatom species. Fungal debris continues to be abundant through to the top of Zone 4b (biozone PP9fiii) and to a lesser degree to the top of Zone 5 (biozone PP9g). Pteridophyte miospore numbers decrease rapidly above subzone PP9fi and are replaced by an assemblage increasingly dominated by dinocysts, angiosperm pollen and a variety of algal forms. This latter assemblage reflects an impoverished Sele Formation shale assemblage into which it passes above the top of the Forties Sandstone Member. A significant shift in biofacies is seen at the top of biozone PP9fiii (Reservoir Zone 4b) represented by an influx of
Pterospermella spp., leiospheres, large fusiform leiospheres and dinocyst taxa Cerodinium depressum, Hystrichosphaeridium tubiferum and Spiniferites ramosus.
Zone 5 Zone 5 is equivalent to biozones PP9g and PP9fiv and represents the final transgressive stage of the Palaeocene tectonosequence culminating in the Sele Unit S l maximum flooding surface, a distinct gamma ray maximum which can be correlated over the entire field. The maximum flooding surface separates claystones,
NELSON
,.,..,.~
~.
FIELD
~.,~ r
~"c~ .,~
~ ~
~
9, - ~
~ .
. ~ - , - ,-~
~
~ 0: ~ ~ = ~
_:~
~_~
~_ ~ ..~ . :
..~
.,.-
, o ~ . ~.
~>==o_-~
,.o ~ ~
.
633
~ :' ~ ~ = ~ . o ~
.~ ~ . = ~:~ ~.~
~
~,.~
9 ,.=.d
o
o
~' =
~
.~o~.~o=
9,~
~
=~-~
~-~.~~-~,C:~'~n~-~
.~==~
~ = ~
~
o~_
~ ~
~
~e
~_~ ~
Oc.~
~
~~a~ n::~"
0,.r
~
0
~o.~.~ ~
~
~:~)
~-~-~4 ~ c ~
0
~a
o
o
~o
o 0
,..0 ,.0
o
~
~
~
E~
,-~
"~,'~
"~
~..
~
9
-o :>-.Z ~
~ ~-~ .,'-~
O~
0
~:~ "~3 ,~ 0 ~ J 0 .-. 9 c~
~ . ~
~
:;~-~ ~-.~'~V
~
~..
o
~.)
.,--d
Z
o
o
o~
2 ~:~
''"
~
~
~
o
~C~ ~l
o
~
o~
~ ' ~
~
~
~
~'~
~
o
;>~
- = ~ o
~
*--~ r~ ~
o
~
~
~.~
~
~.~
~
o.-~
, o "~ ~ "w~ ~ ,~. o_~
<
o +.~
.~.=~
o
(.,,)
b
634
J.M. KUNKA ET AL.
siltstones and sandstones of the Sele Formation S1 from dark-grey anoxic hemipelagic claystones of the Sele Formation $2 of Knox and Holloway (1992). This upper unit of the Sele Formation S1 is marked by biozone PP9g, the Apectodinium spp. acme and the extinctions of Apectodinium augustum and A. quinquelatum which are the most widely recorded biozones on the field. At the top of biozone PP9g, equating to the top of Unit S1 of the Sele Formation, are further influxes of Pterospermella spp. and leiospheres along with a significant re-influx of agglutinating foraminifera, diatoms and radiolaria. These bioevents define the base of Unit $2 of the Sele Formation (Knox & Holloway 1992) and the top of the Forties Sequence of Mudge and Bujak (1996). Lithologically, Zone 5 is represented by distal turbidite lithologies in the majority of Nelson wells in common with type well 21/10a-4 of Knox and Holloway (1992). These facies have been documented by Whyatt et al. (1992) in the uppermost interval of the cored Nelson discovery well 22/11-5 where they were described as late stage fan abandonment facies. Within the Forties Field, similar lithologies are described in Unit L by Wills and Peattie (1990) where they are also described as abandonment facies. Knox and Holloway (1992) observe that this unit includes thin distal turbidites and is probably represented by sandstones in sections nearer to the axis of the youngest Forties Fan (e.g. well 21/10-2). This phenomenon is also seen in the Eastern Channel Complex of the Nelson Field where one or two cycles of channel deposition immediately underlay the Sele Formation S 1 maximum flooding surface.
Formation, Guadalupe Mountains, Texas, USA, where an erosional stepped channel cuts into thin-bedded heterolithic channel margin facies. The Nelson channel fill model is analogous to that of Clark and Pickering (1996) in that they describe three phases of channel activity. These are applicable to individual channel storeys within the Nelson reservoir thus: (l)
(2)
(3)
Nelson Facies Model The facies analysis scheme is based on the sediment gravity flow classification of Mutti and Ricci-Lucchi (1972), which has been used throughout the Nelson Field development and is applied to all cored wells (Fig. 16). A total of 25 wells have been cored resulting in the collection of over 6500 ft of core through the reservoir which has enabled the construction of a robust facies model based on the recognition of eight primary facies divisions. The Forties Sandstone Member was deposited in the confined Central Graben basin, as a sand-rich, sheet-like, basin floor fan system (Den Hartog Jager et al. 1992). The main fairway axes described above demonstrate an offset stacking, indicating basin floor topography was an important control on sedimentation. The submarine channel axes comprise predominantly Facies B with minor Facies A C, D and F reflecting in-channel deposition dominated by high density turbidity currents. Towards the edges of the channelized fairways, sediments are seen to comprise more heterolithic facies with lesser amounts of Facies B and increased proportions of Facies C and D. With increasing distance away from the channelized fairways, Facies B and C give way to predominantly thin-bedded Facies D. The sand-rich fairways were undoubtedly sediment conduits as they form parallel to the NW-SE axis of fan progradation (Fig. 6). The more discrete bedded intervals are interpreted as lobes or splays formed as a result of unconfined flow outwith the axes of main sediment transport. A good model for the upper zones (4 to 5) of the Forties Fan in Nelson is described by Clark and Pickering (1996). They describe a 'high connectivity' sediment geometry, formed from a low sinuosity sand-rich system where the absence of levees allows rapid lateral migration of the channel thalweg over a broad unconfined braid plain. In the more confined topographic lows, these systems appear channel-like but are probably composed of sheet-like elements which simply onlap the pre-existing topography. Good outcrop analogues for this type of sand-rich system are found in the Eocene Gres d'Annot in the Alpes Maritime of southeastern France (Pickering & Hilton 1998). The lower parts of the Forties Fan in the Nelson Field (e.g. Zones 1 to 3a) are interpreted from seismic data to be more erosional which is evident from the higher proportions of conglomerate facies described in cored wells. An appropriate outcrop analogue for this would be a more erosional channel, as is described by Clark and Pickering (1996) for the Brushy Canyon
Erosion and sediment throughput. During this stage the channel exhibits basal erosional scouring and subsequently acted as a sediment transport path for large volume sandy turbidity currents. Deposition during this phase is characterized by tractive deposits, comprising organized pebbly sandstones, conglomerates (Facies A1) and rare cross-bedded sandstones (Facies B2). In addition, channel erosion and bank collapse contributed occasional sandy debris flows (Facies A2). Deposition by back-filling. During this phase any topography created during phase one is infilled by aggradational depositional channel elements. The majority of the reservoir in the Nelson Field is made up of these facies comprised of massive amalgamated dewatered sandstones (Facies B1), deposited from high density turbidity currents. The stacking of these depositional elements forms larger sheet-like sandbodies which onlap the channel edges and may overspill the axial portion of the channel, forming splay or lobe deposits (Facies C and D). Abandonment. Channel abandonment is marked by the deposition of draping low energy facies as sheet-like bodies of fine-grained heterolithic turbidites (Facies D) with and beyond the channel, often associated with muddy debris flows (Facies F). These represent switching of the channel to a different location accompanying the reduction in gradient caused by the filling of the channel cut.
The three phases of channel cut, fill and drape are apparent in many of the Nelson channel deposits, at a variety of scales. Within the composite multistorey sandbodies numerous phases of cut and fill are recognized suggesting subtle topographic controls leading to frequent channel switching. The Forties Fan has been classified as a 'Mud/Sand-Rich Ramp' by Reading and Richards (1994) apparently based on published net/gross data. Data from Nelson such as net/gross grids or well zonal averages display values greater than 70% indicating that a sand-rich ramp interpretation is appropriate. This is further supported by core sedimentological facies which are predominantly Facies B in common with the Forties Field where Wills and Peattie (1990) describe Facies B as forming the majority (approximately 80%) of lithofacies. An alternative model to describe sand-rich submarine fans is proposed by Hurst et al. (1999), who use the term 'Sand-Rich Fairways' to describe sediment conduits which appear channel-like but which are, in fact, composed of sheet-like elements. This is due to the processes of turbidite deposition in sediment conduits that are created either during an earlier phase of channel incision and are later backfilled or are simply topographic features created as a result of differential compaction adjacent to axes of earlier channel deposition. From the considerable amount of core material described for the Nelson Field, four main facies associations are identified:
S u b m a r i n e channel association
This is by far the most volumetrically important facies association on the Nelson Field and comprises both erosional and depositional channel elements, although erosional channel elements are less common, more commonly occurring in Zone 3. Typically, intrachannel facies are characterized by thick sequences of high density turbidites (Facies B1) with subordinate sandy clay-clast conglomerates (Facies A2) and pebbly sandstones (Facies A1) confined to the erosional channel elements (Fig. 17). The depositional channel
N E L S O N FIELD
635
,,...
Z
r
Y
.,,a
9
9
9
r
Z
Z 9
"-d e...
9
,....
636
J. M. K U N K A
E T AL .
. ,...,
o
o
Z~
~2
. ,...~
0
o
Z~
~'~
Z~
o
~
o
ug ~
o
NELSON FIELD facies are characterized by abundant de-watering structures e.g. dish structures and water escape pipes (Fig. 18). Individual submarine channels are relatively small, but are stacked to form composite multi-storey sandbodies. Because of the braided nature of these channels with frequent channel switching or avulsion, the correlation potential of the individual units is very low and for this reason they are modelled as amalgamated units. This is supported by field outcrop studies in the Gres d Annot (Hurst et al. 1999). Slumps (Facies F) together with muddy debris flows are most common towards the tops of the channel fill, probably reflecting channel bank collapse, whilst sandy debris flows (Facies A2) are more common at the bases. Permeabilities within the channelized facies typically average 200mD with corresponding porosities of 22%. Within the submarine channel facies association, the presence of localized shales and doggers may form baffles to fluid flow but there is no evidence that these facies form significant barriers to vertical fluid flow. This is confirmed by recent drilling and TDT/PLT logging which shows the Nelson reservoir to possess excellent vertical and lateral connectivity in common with the Forties Field (Wills & Peattie 1990). Zonal stacked channel abandonment facies comprise thinly bedded turbidites of Facies D and muddy debris flows that often form vertical permeability barriers, as is evident from RFT data acquired from wells drilled following the onset of oil production. Such events are interpreted to be laterally extensive, i.e. they extend beyond the channel complex and into the interchannel areas and are modelled as such within the 3D reservoir model. The presence of laterally extensive abandonment facies is also described by Wills and Peattie (1990) in the Forties Field.
Channel margin association Channel margins are characterized by a diverse facies association comprising discrete sandstone beds of Facies B1, B2, C1 and C2, interbedded with thin-bedded organized heterolithics of Facies D1-D3, together with muddy debris flows and disorganized slump deposits of Facies F. These are the products of turbidity currents depositing sand on the elevated flanks of the channel fairways, with decreasing sand content away from the axial reaches of the fairways. Such lateral facies transitions are demonstrated in outcrop analogues from the Annot Sandstone (Ravenne et al. 1997). An example of the transition from channelized fairway to channel margin can be observed from core in wells 22/1 l-N16y and N16z which are situated on the eastern margin of the Western Channel Complex (Figs 19 & 20). Another example is on the western margin of the Central Channel Complex in well 22/11-5 (Fig. 12), where sandstone mudstone couplets are interpreted to grade laterally into thick bedded amalgamated sandstones in well 22/1 lN09. The transition from 22/11-N09 to 22/11-5 shows the palaeotopographic effect of the underlying Lower Forties Sandstone Member in controlling the position of the Upper Forties Central Channel resulting in offset stacking of the two fan sequences (Fig. 11).
Interchannel facies association With increasing distance away from the channel fairways, channelized turbidites are expected to grade into tabular thin-bedded turbidites of Facies D2, D3, E and rare Facies G. These represent portions of the interchannel beyond the influence of the main fairways. Similar facies also represent the abandonment of the fan system (Fig. 21) which have previously been described as late stage fan abandonment facies by Whyatt et al. (1992). Homogeneous mudstone facies are not well developed within the Nelson reservoir, these intervals always contain some interbedded turbidite sandstones. Reservoir properties within the thin-bedded heterolithic facies are more variable than those within the submarine channel sandstones. Within the 3D reservoir model these facies are modelled
637
separately as it is important to characterize the discrete bedded nature of these facies where the ratio of vertical permeability to horizontal permeability (Kv/Kh) is much lower than in the submarine channel facies. Kulpecz and van Guens (1990) document Kv/Kh of 0.1 within the submarine channel facies but 0.01 to 0.001 within the heterolithic facies. This is due to the presence of interbedded mudstones and other non-net facies which form vertical permeability barriers within the reservoir.
Slumped and injected facies association Although injected sand facies are rare in Nelson, slumped facies F make up between 8 and 19% of cored facies in wells. Facies F comprise variably coherent slump deposits, argillaceous intraclastic muddy debris flow sandstones and injection complexes. This facies association is most common in the lower Forties Sandstone Member Zone 2 (Fig. 22), although it occurs infrequently in the upper Forties Sandstone Member associated with the channel margin facies association. Where injected facies occur in the reservoir (Fig. 23), pressure data and strontium isotope residual salt analysis data show these to be in communication with the main sand-rich fairways. Sandstone injection dykes and sills are described within the abandonment facies of the Charlie Channel in the Forties Field by Payne et al. (1999).
Controls on reservoir quality Petrographically, the reservoir sandstones from the Nelson Field are sublitharenites or subarkosic arenites under the classification scheme of Pettijohn (1975). Reservoir quality in the Nelson Field is typically excellent and is primarily controlled by depositional processes and to a lesser degree by diagenetic alteration. The principal factors controlling reservoir quality are sedimentary facies, grain size, sorting, clay matrix content, cementation and compaction. Porosity is largely independent of grain size but permeability can be shown to be strongly correlated with grain size. The frequency distribution of porosity derived from petrophysical analysis at a sample rate of 2 ft net average shows an almost normal distribution centred on a mean of 22% (Fig. 24). There is no clear relationship between porosity and permeability sufficient to allow the prediction of permeability in un-cored wells. The most permeable reservoir facies are relatively coarsegrained Facies A1, A1/B2, B1 and C2 arenites with low clay matrix content which display core permeabilities in excess of 1000 mD. Reservoir rocks with clay contents in excess of 20% possess permeabilities of less than 100 mD. Permeability measurements taken from samples in the aquifer display lower permeabilities as a result of chlorite representing a late stage diagenetic overprint. Ferroan calcite occurs both as dispersed intergranular cement and as stratabound 'doggers', especially within the submarine channel facies. Doggers typically display permeabilities of less than 1 mD and porosities of less than 12%. When seen in outcrop analogues, doggers are typically nodular and are often concentrated along a particular layer of strata. Within the reservoir, they are interpreted to behave as local baffles to fluid flow rather than laterally extensive barriers (see also Kulpecz & van Guens, 1990). The net reservoir cut-off can be applied at porosity values of less than or equal to 15% which approximates to permeabilities of 1 mD and less. In some rare cases, secondary porosity has been created through the dissolution of ferroan calcite, probably associated with acidic fluids prior to oil emplacement. Facies B sandstones are often friable making it difficult to obtain representative core measurements of permeability and porosity. It was found that core permeabilities often underestimated the true permeabilities obtained from well tests which were able to effectively sample these high permeability friable layers. For this reason, well test derived permeabilities have been used to derive measures of horizontal and vertical permeabilities for input into the reservoir simulation model. Figure 25 illustrates the
638
J.M.
K U N K A E T AL.
>: z
z 9
o oo
02,
_= r.~
eq eq
r
r
0...)
eq
~
e~0
NELSON FIELD
639
Fig. 23. Slumped and injected channel margin facies association - Nelson Producer N27. Facies comprise mudstones and siltstones injected with sandstone sills and dykes. Post depositional slump modification is also apparent in this sequence.
permeability frequency distribution derived from well test permeabilities by simplified facies for the Forties Sandstone Member at the sample scale of 2 ft net average. The early-diagenetic cement assemblage of the Forties Sandstone Member includes siderite, quartz overgrowths, kaolinite and framboidal pyrite. Kaolinite is by far the most abundant clay mineral and partially or completely fills pore spaces adjacent to feldspar grains. Ferroan calcite formed during early burial diagenesis prior to the main phase of compaction and was followed by crystallization of concretionary pyrite. Generation of minor secondary intergranular and intragranular (mouldic) porosity took place during early diagenesis and continued in late burial diagenesis. The emplacement of hydrocarbons within the reservoir is thought to have been accompanied by acidic brines which leached intergranular calcite cements and detrital grains resulting also in the development of secondary porosity. Authigenic chlorite is believed to have formed during both early diagenesis and late stage burial diagenesis when it was mainly confined to the acquifer, indicating continuation of diagenetic processes after oil emplacement and
contributing to reduced acquifer permeabilities. Average zonal reservoir properties for the Sele Unit S 1 Forties Sandstone Member reservoir are tabulated in Table 2.
Seismic reservoir characterisation and time lapse seismic The Nelson Field 3D seismic data have been used to characterize reservoir properties for each of the main reservoir zones and these maps provide an impression of the development of a series of channel complexes through time. Oil-bearing sandstones in the field give a Class I high impedance response (Rutherford & Williams 1989), which, under ideal conditions, give a phase reversal at far offset (Fig. 26). Water-bearing sandstones give an amplitude dimming but with no reversal. Far-offset data can be exploited to image oil sands directly, bearing in mind the resolution limitations, tuning issues towards the flanks of the field and additional complications due to facies changes. Since there is a recognized
640
J . M . KUNKA E T AL.
Fig. 24. Forties Sandstone Member log porosity distribution, all data, all zones. The net reservoir oil cut-off is applied to values of 15% and lower.
Well Test Permeability mD Fig. 25. Forties Sandstone Member. Well test permeability by simplified facies. The net permeability cut-off is applied to values of 1 mD or less.
amplitude v. offset (AVO) effect on the Nelson Field associated with fluid fill, reservoir characterization studies have been carried out using the intercept data to explore facies changes, and far offset or gradient data have been used to detect fluid related effects. This work includes a deterministic seismic inversion to acoustic impedance based on the intercept stack. The location of the channel complexes can be clearly imaged on this near-offset acoustic impedance data, as the time slices relating to Zones 3 and 4 illustrate (Fig. 27). In general, high acoustic impedance corresponds to areas of high net/gross but it is also recognized that a h y d r o c a r b o n effect causes a reduction in acoustic impedance in high net/gross areas of the field. Therefore, on its own, acoustic impedance is nondiscriminatory and a c o m b i n a t i o n of seismic attributes is necessary to adequately detect lithology (Connolly 1999).
Table 2. Sele Unit S1 Forties Sandstone Member. Zonal Reservoir Properties Net/gross
Zone Zone Zone Zone Zone
5 4b 4a 3b 3a
Log derived porosity I (%)
Well test derived permeability (mD)
Mean
Range
Mean
Range
Mean
Range
0.33 0.77 0.69 0.69 0.72
0.11-0.89 0.28-1 0.23-0.96 0.28-0.97 0.21-0.97
21.85 22.56 22.76 21.93 21.58
I5.22-33.72 15.08-37.91 15.15-34.27 15.01-29.46 15.01-37.49
166 153 312 243 232
10-359 7-639 18-1466 10-1610 46-967
1Net cut-off applied at 15%.
NELSON FIELD
641
Fig. 26. There is a Class 1 AVO response on Nelson which gives a phase reversal at far offset for oil bearing sands.
In July 1997, almost 3 and a half years after production startup, a time-lapse (4D) streamer survey was acquired to help detect fluid movements within the reservoir. At the time of the survey acquisition, the cumulative oil production was 171 M M B B L with associated cumulative water production of 31 MMBBL. Cumulative water injection at the time was 33 MMBBL. Pressure depletion was around 800-1000 psi from the initial reservoir pressure. Timelapse effects were found to be larger at far offsets compared with near offset, and the far offset, difference data show a clear seismic response due to rise in the oil-water contact which can be equated with the predicted hydrocarbon pore thickness change in July 1997 at the time the survey was acquired (Fig. 28). Because of the success of the survey, a second time lapse 3D survey was acquired in 2000.
Source rocks and migration There are two areas where mature Jurassic source rocks are situated: the East Forties Basin and West Forties Basin. Migration from the Kimmeridge Clay Formation into Palaeocene aged sediments could be by either (1) lateral migration followed by vertical migration through faults; and/or (2) vertical migration as a result of overpressure induced seal failure. Evidence for this is seen in the form of light hydrocarbon shows in the tight Cretaceous Tor Formation limestones in Blocks 22/7 and 22/8a. In the same area, seismic anomalies in the form of gas clouds could be evidence of continuing hydrocarbon generation. Following vertical migration,
642
J. M. KUNKA E T A L .
Fig. 27. Near offset acoustic impedance attributes approximating to Zones 3 and 4 of the Nelson Reservoir.
hydrocarbon migration would then be lateral and up-dip into the Palaeocene reservoirs on the Forties-Montrose High. Sourcing from the East Forties Basin is supported by Wills and Peattie (1990) who describe a hydrocarbon gradient across the Forties Field. This is characterized by an increase in G O R to the south reflecting proximity to a more mature source kitchen in the East Forties Basin (Fig. 29). This trend continues south from Forties to SE Forties, where the crude has an API of 36 ~ and a G O R of 392 SCF/STB, and on to the Nelson Field which has a G O R of 555 SCF/BBL and an API of 40.6 ~ Thermal modelling
studies described by Wills and Peattie (1990) suggest that the main phase of oil generation in the East Forties Basin was during Middle Eocene to Miocene times (50-10 Ma).
Reserves and production The initial development wells were targeted at the relatively high relief, channel axes to ensure rapid build-up to plateau production.
NELSON
FIELD
643
r-Z
. ,...q
s
8
[.. ~Z 06
644
J . M . K U N K A E T AL.
58 ~ E
Fig. 29. Hydrocarbon source kitchens in proximity to the Forties Montrose High.
Later d e v e l o p m e n t wells included the four peripheral water injection wells and several channel margin/inter-channel locations. The p r o d u c t i o n m e c h a n i s m is basal aquifer drive supplemented by water injection. Gas lift is used to aid p r o d u c t i o n of oil from high water-cut wells and an ongoing p r o g r a m m e of water shut-offs is used to reduce water p r o d u c t i o n and increase oil production. S T O I I P is estimated at a b o u t 790 M M B B L a n d at present the O p e r a t o r predicts the ultimate recoverable oil reserves to be in excess of 420 M M B B L over a remaining field life of approximately 20 years. U p to D e c e m b e r 1999 the field had p r o d u c e d 261
M M S T B , with an associated field watercut of almost 50%. A graph of m o n t h l y oil p r o d u c t i o n and field watercut is shown in Figure 30. The authors acknowledge the work carried out by all previous workers on the Nelson Field whose work has influenced the current development model, especially Rebecca Jones, Rebecca Nash, John McGuckin and Paul Harrison. Special thanks to Lorna Donald and Barry Gtennie for preparing the figures and Malu Jensen for computer mapping. The authors would like to thank the Nelson Field partners who gave their permission for us to publish, namely Shell, Exxon-Mobil, Elf, Intrepid, Svenska, Lundin and Summit. Finally, the authors would like to stress that this paper does not necessarily represent the views of the Nelson Field partnership.
NELSON FIELD
References
N e l s o n Field data summary Trap Depth to crest Oil-water contact
Oil column height
Reservoir zone Age Gross thickness (min/mean/max) Net to gross ratio (min/mean/max) Net porosity (min/mean/max) Net test permeability (min/mean/max)
Reservoir .fluid properties Oil Gravity Oil type GOR Formation volume factor Formation water salinity Reservoir temperature Reservoir pressure Initial pressure Bubble point Pressure gradient in oil leg STOIIP Recoverable oil Drive mechanism Production start-up Current well count
Development scheme Cumulative production to 31/12/1999
645
Antiformal 7192 (22/11-7) ft TVDss 7449-7501 ft TVDss (excluding 22/7a-3) Average 7470 ft TVDss 278 ft
Palaeocene (Forties Sandstone Member) 56 ft 257 ft 459 ft 0.25 0.7 0.97 15% 23% 38% 7roD 216mD 1610mD
40.6 ~ API Low sulphur crude 555 SCF/BBL 1.357 84 000 ppm NaC1 equivalent 224~ @ 7400 ft TVDss 2480 psia current 3322 psia 1550-1699psi @ 230~ 0.30psi/ft 790 MMBBL 420-450 MMBBL Basal acquifer supported by water injection February 1994 23 platform producers; 4 sub-sea producers and 4 water injectors Primary depletion with water injection 261 MMBBL
BERGGREN, W. A., KENT, D. V., AUBRY, M.-P. & HARDENBOL, J. 1995. Geochronology, Time Scales and Global Stratigraphic Correlation. Tulsa SEPM Special Publication, 54. CARMAN, G. J. & YOUNG, R. 1981. Reservoir geology of the Forties oilfield. In: ILLING, L. V. & DOBSON, G. D. (eds.) Petroleum Geology of the Continental Shelf of North West Europe. Heyden. London, 371 391. CLARK, J. D. & PICKERING, K. T. 1996. Submarine Channels, Processes and Architecture. Vallis Press, London. CONNOLLY, P. 1999. Elastic Impedance. The Leading Edge, April 1999, 438-452. DEN HARTOGJAGER, D., GILES, M. R. & GRIFFITHS,G. R. 1993. Evolution of Paleogene submarine fans of the North Sea in space and time. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 59-71. FOWLER, C. 1975. The geology of the Montrose Field. In: WOODLAND,A. W. (ed.) Petroleum and the Continental Shelf of North-West Europe. HURST, A., VERSTRALEN, I., CRONIN, B. & HARTLEY, A. 1999. Sand-rich fairways in deep-water clastic reservoirs: genetic units, capturing uncertainty, and a new approach to reservoir modelling. American Association of Petroleum Geologists, Bulletin, 83, 1096-1118. KANTOROWICZ, J. D. ANDREWS, I. J., DHANANI, S., JENNINGS, C., LUMSDEN, P. J., ORR, G., SIMM, R. W. • WILLIAMS, J. 1999. Innovation and risk management in a small subsea-tieback: Arkwright Field, Central North Sea, UK. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of North West Europe. Proceedings c4f the 5th Conference. Geological Society, London. 1125-1134. KNOX, R. W. O'B. and HOLLOWAY, S. 1992.1. Paleogene of the Central and Northern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. KULPECZ, A. A. & VAN GUENS, L. C. 1990. Geological modelling of a turbidite reservoir, Forties Field, North Sea. In: BARWIS,J. H., MCPHERSON, J. G. & STUDLICK,R. J. (eds) Sandstone Petroleum Reservoirs. SpringerVerlag, Berlin. MUDGE, D. C. and BUJAK, J. P. 1996. An integrated stratigraphy for the Paleocene and Eocene of the North Sea. In: KNOX, R. W. O'B., COREIELD, R. M. & DUNAY, R. (eds) Correlation of the Early Paleogene in Northwest Europe. Geological Society, London, Special Publication, 101, 91-113.
646
J. M. K U N K A E T AL.
MUTTI, E. & RICCI-LUCHI, F. 1975. Turbidite facies and facies associations. In: E. MUTTI et al. (eds) Examples of Turbidite Facies and Facies Associations from Selected Formations of the Northern Appenines. IX International Congress on Sedimentology, Nice, A-11, 21-36. O'CONNOR, S. J. & WALKER, D. 1993. Paleocene reservoirs of the Everest trend. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 145-160. PETTIJOHN, F. J. 1975. Sedimentary Rocks. Harper and Row, London. PICKERING, K. T. & HILTON, V. C. 1998. Turbidite Systems of Southeast France. Vallis Press, London. RAVENNE, E. T. 1997. American Association of Petroleum Geologists Fieldtrip Guide to the Gres d Annot. READING, H. G. & RICHARDS, M. 1994. Turbidite systems in deep-water basin margins classified by grain size and feeder system. American Association of Petroleum Geologits, Bulletin, 78, 792-822. RUTHERFORD, S. R. & WILLIAMS, R. H. 1989. Amplitude versus offset variation in gas sands. Geophysics, 54.
SCHRODER, T. 1992. A palynological zonation for the Paleocene of the North Sea Basin. Journal of Micropalaeontology, 11, 113-126. STEWART, I. J. 1987. A revised stratigraphic interpretation of the Early Paleogene of the Central North Sea. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe Vol 1. Graham and Trotman, London, 557-576. WALMSLEY, P. J. 1975. The Forties Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of North-West Europe. Applied Science, London. WHYATT, M., BOWEN, J. M. & RHODES, D. N. 1992. The Nelson Field: a successful application of a development geoseismic model in North Sea exploration. In: HARDMAN, R. F. P. (ed.) Exploration Britain: Geological Insights Jot the Next Decade. Geological Society, London, Special Publication, 67, 283-305. WILLS, J. M. & PEATTIE, D. K. 1990. The Forties Field and the Evolution of a Reservoir Management Strategy. In: North Sea Oil and Gas Reservoirs II. The Norwegian Institute of Technology, Graham and Trotman.
The Pierce Field, Blocks 23/22a, 23/27, UK North Sea PHILIP
BIRCH*
& JAMIE
HAYNES
Enterprise Oil plc, Victoria Tower, Market Street, Aberdeen A B l l 5P J, UK * Present address: Imperial Management School, 53 Prince's Gate, London S W 7 2PG, UK (e-mail: philip.birch @ ic.ac.uk)
Abstract: The Pierce Field contains oil and gas in Palaeocene Forties Sand and fractured Chalk, draped around the flanks of a pair of Central Graben salt diapirs. Whilst the two diapirs constitute a single field containing over 387 MMSTB AND 125 BCF, it took almost 25 years, and several advances in seismic, drilling and production technology, for the field to be brought into production. Many appraisal wells were drilled on the field. Data from these wells were interpreted to suggest the field was highly segmented both in terms of petroleum distribution and pressure variance. On the basis of this interpretation an economic development required a floating production system with long reach horizontal wells to penetrate the many reservoir segments. The results of development drilling have indicated that few pressure seals exist within the field, with concentric faults being more likely to seal than radial faults. The various reservoir pressures and oil-water contacts have been re-interpreted as a single, highly tilted oil-water contact, facilitated by the location of the field in the low permeability toe of the Forties submarine fan, a major conduit for the transport of basinal fluids away from the deep Central Graben. Palaeocene reservoir depositional patterns closely resemble those predicted by analogue models. The greatest reservoir thickness and net/gross are located in areas of flow velocity reduction (depletive flow), on the 'lee' side of the diapirs, but porosity and permeability are optimized in areas of increased flow velocity (accumulative flow), towards the crests of the diapirs. Strontium residual salt analysis has been used to study the charge history of the field. Interpretation suggests that South Pierce was filled before North Pierce, from a local Upper Jurassic source kitchen. Oil and gas subsequently spilled into North Pierce to form a composite trap with a single, tilted oil-water contact. The South Pierce gas cap has since been breached, and the escape of gas is currently leading to the retreat of the tilted water contact, once again isolating the two diapir structures. The Pierce Field is located in Blocks 23/22a and 23/27 of the U K Central North Sea (Fig. 1). It lies adjacent to the U K / N o r w a y median line, 250 km due east of Aberdeen, and in 280 ft (85 m) of water. The field contains an oil column and free gas in Palaeocene submarine fan sandstones at depths of between 6800 ft (2073m) TVDss and 10 170 ft (3100 m) TVDss. The trap comprises twin salt diapirs, which lie along the eastern margin of the Central Graben, equidistant between the Lomond and Cod diapir fields. Recent development drilling has suggested that the field is characterized by a tilted (hydrodynamic) oil-water contact. This has resulted in the delineation of significant upside reserves within the northwestern sector of the field. Estimated hydrocarbon in-place volumes for the principal, Forties Sand reservoir are 387 M M S T B and 125 BCF free gas, and significant, but as yet unquantified, upside volumes may lie in the underlying Chalk. This paper reviews the exploration and appraisal history of the Pierce Field. It provides an overview of the petroleum geology, and investigates the principal features of the trap, reservoir, and charge history which have been responsible for the present day hydrocarbon distribution.
Exploration and appraisal history The South Pierce accumulation was discovered in 1975 by Ranger well 23/27-3, located on the western flank of the Block 23/27 diapir (Fig. 2). This tested oil from Palaeocene Forties Sand, and encountered good oil shows in Upper Jurassic sandstones. Between 1978 and 1983, the Ranger group drilled a further three wells around the flanks of South Pierce, but the results were far from encouraging. Well 23/27-4, located on the eastern flank, tested small quantities of oil from low permeability, argillaceous Forties Sand, and penetrated a shallower water contact than encountered in the discovery well. It also found good shows within thick Upper Jurassic sandstones, but these tested only water. Wells 23/2%5 & 6 drilled down-flank in the southern part of the structure, were located within structural closure, but encountered water-bearing Forties Sand. The most reasonable interpretation of these drilling results suggested that South Pierce was highly segmented by sealing radial faults. Some of the segments were considered to have been either undercharged, or breached by episodic diapir movement. The Jurassic trap was interpreted as having been breached. Horizontal well
technology was still in its infancy during the early 1980s, and it was considered that the large number of near vertical development wells required, together with reserves uncertainty, made development unattractive. In 1990, BP commenced drilling on the adjacent North Pierce diapir (then Medan), within Block 23/22a. Their strategy of drilling as close to the salt stock as possible, and subsequently deviating a sidetrack well further down the diapir flank paid dividends. Wells 23/22a-2 & 2z and 23/22a-3 & 3z proved the presence of a significant gas cap and oil rim at North Pierce, and an oil-water contact was intersected in well 23/22a-3z. In the same year, the Ranger group adopted a similar drilling philosophy on South Pierce. Well 23/27-8 was drilled to appraise the accumulation up-dip of 23/27-3, and sidetrack well 23/27-8z was subsequently deviated into the gas cap. Wells 23/27-8z & 9 proved that a steeply dipping Palaeocene reservoir extended beyond the imaging limit of the 2D seismic grid, into a zone that had previously been interpreted as salt. Well 23/27-9 also proved the potential productivity of the Chalk by testing more than 6700 BOPD (after acidization) and 5.2 M M S C F D . During 1992, BP joined the Block 23/27 group and a joint 3D seismic survey was acquired across both diapirs, the interpretation of which confirmed the extent of the steep structural drag zones towards the salt plugs. An integration of structural and pressure data over the area was interpreted as providing further support for the model of two adjacent, steeply dipping diapir flank traps, segmented by sealing radial faults (Figs 2-4). A Field unitization agreement was signed during 1996. The combined group subsequently drilled a trial high-angle production well (23/27-10z), aimed at intersecting a number of separate structural compartments. The well penetrated 3590ft (1094m) mD of Palaeocene sandstones within two structural segments on the southwest flank of South Pierce. An extended well test (EWT) produced over 1 MMSTB, with initial flow rates exceeding 20 000 BOPD and 15 M M S C F D , representing a five-fold increase in productivity index over the vertical appraisal wells. The Field Development Plan was approved in 1997. It contained a further five high-angle production wells, three gas injectors, and a floating production vessel. Enterprise Oil acquired field operatorship in the same year, and commenced operations late in the year. First oil was produced on 1 February 1999, using three South Pierce production wells and one gas injection well. A plateau production rate of 45 000 BOPD was reached during mid-1999.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 647 659.
647
648
P. BIRCH & J. HAYNES
Fig. 1. Location map for the Pierce Field.
Geological summary Structural setting The N o r t h Pierce and South Pierce salt diapirs are approximately 1 km in diameter and penetrate to within 1500 m and 300 m of the
seabed, respectively (Figs 2 & 3). The two diapirs are interpreted as being linked by a salt wall that has grown along the footwall of the N W - S E trending Central Graben boundary fault, and the diapirs are probably located at the intersections of N E - S W trending crossfaults. Salt movement dates from the initiation of rifting during the Triassic, and continued into the Tertiary by a combination of
PIERCE FIELD
649
Fig. 2. Top Forties reservoir structure map, showing radial and concentric faults, the hydrocarbon contacts, and well locations.
sediment downbuilding and salt upbuilding (Davison et al. 1999). Diapiric growth at North Pierce ceased during the Oligocene, whilst the South Pierce diapir continued to grow into the Middle Miocene, probably in response to a phase of Alpine compression (Davison et al. 1999). This pinched the salt stem and broadened the crest to create a slight 'mushroom' geometry. Hydrocarbon trap The trap for the Pierce Field is formed by the tilting and termination of the Palaeocene and Chalk reservoirs against the flanks of the
salt diapirs. The trapping mechanism is dominantly structural, but hydrodynamic processes have modified its geometry. A top seal is provided by thick Tertiary mudstones of the Hordaland and Nordland Groups (Deegan & Scull 1977). Gas chimneys over the South Pierce diapir indicate that some gas leakage has taken place from this part of the structure, and this may provide one explanation for the presence of a smaller gas cap at South Pierce than at North Pierce. Furthermore, the presence of residual oil shows in the aquifer in South Pierce wells 23/27-4, 5 & 6 suggests that the oil-water contact might also have retreated in this part of the field.
650
P. BIRCH & J. HAYNES
Fig. 3. Interpreted N W - S E seismic section across the North Pierce and South Pierce structures.
Fig. 4. Schematic segmented OWC model for the Pierce Field, indicating the location of the main sealing faults, and the 23/22a-A3 pilot well.
PIERCE FIELD
Structural trap elements The magnitude of structural closure has been mapped as 2900 ft (884m) for North Pierce and 3400ft (1036m) at South Pierce, although uncertainty remains regarding the up-dip termination of the Palaeocene reservoir against the salt. A common structural spill point exists at approximately 9900ft (3018m) TVDss, located to the east of South Pierce. The saddle between the two diapirs lies at a depth of 9700 ft (2957 m) TVDss (Fig. 2). Exploration and appraisal wells located on the southern and eastern flanks of the field have indicated these sectors of the trap to be underfilled with respect to the mapped structural closure, and to have variable oil-water contacts. Gas bearing reservoirs were penetrated by wells 23/22a-2 and 23/27-8z. Pressure data suggest that North and South Pierce have separate gas-oil contacts at 8730ft (2661m) TVDss and 7316ft (2230m) TVDss, respectively.
Radial faults.
The original field development plan attributed the observed variations in oil-water contact to the presence of sealing radial faults, which were considered to segment the trap into a number of different reservoir compartments (Figs 2 & 4). At the time it was considered that this interpretation was supported by pressure data, which indicted different aquifer pressures for each compartment. It emphasized the requirement for horizontal development wells to intersect as many compartments as possible. Recent development drilling has indicated this early model to be largely incorrect. Nearly all of the reservoir segments penetrated to date on South Pierce have demonstrated pressure depletion related to the 1996 23/27-10z EWT, with the amount of depletion being inversely proportional to distance from the EWT well. This suggests that most areas of South Pierce are in direct pressure communication, and that most radial faults do not act as sealing faults; at best they provide zones of reduced transmissibility.
651
The only radial faults which have enough vertical displacement to seal (>200 ft or >60 m) are those which overlie major N W - S E and N E - S W trending basement fault zones. However, in common with other radial faults at Pierce, the displacements rapidly decrease away from the diapir, and it is considered that sealed compartments can only be formed in conjunction with concentric faults and/or stratigraphic trapping elements.
Concentric .faults. It is possible that concentric faults provide an important, yet difficult to image, trapping element at the Pierce Field. These faults accommodate most of the vertical strain involved in diapir growth, providing several hundred feet of vertical displacement at a low angle (or parallel) to the steeply dipping beds on the diapir flank. The largest concentric faults are interpreted as forming linked fault systems which produce a ring fault around much of the diapir, offset by large displacement radial faults. Such combinations of concentric and radial faults are most likely to create structurally isolated reservoir compartments high on a diapir flank, particularly in areas of the field characterized by a low net/gross reservoir. The potential importance of concentric faults in producing sealed compartments within low net/gross areas of the field, and the difficulty of imaging such faults using seismic data, is illustrated by the results of well 23/22a-A1 (Fig. 2). This horizontal development well has been drilled across the northeastern flank of South Pierce to a location up-dip of oil bearing appraisal well 23/27-4. Core from the Palaeocene reservoir in 23/27-4 indicates that the eastern flank of the diapir comprises low net/gross reservoir, with slickenside fabrics characterizing many of the shale layers. Whilst most of well 23/22a-A1 contains oil-bearing Forties Sand, part of the toe section is water bearing. The toe of the well is, therefore, structurally or stratigraphically sealed from both the remainder of the production well and from nearby well 23/27-4. Using the 3D seismic cube it is
Fig. 5. Schematic tilted OWC model for the Pierce Field, indicating the proposed tilted contact, and the 23/22a-A3 pilot well.
652
P. BIRCH & J. HAYNES
difficult to interpret any faults that could structurally isolate the water-bearing section. However, the slickenside fabrics observed in the appraisal well suggest that isolation could be by means of a sealing concentric fault zone; difficult to map due to being at a low angle to the steeply dipping bedding.
Hydrodynamic trap elements The observation that all the oil pressures within the field lie on a common gradient, yet the aquifer is characterized by distinctly different pressures, has recently been re-interpreted as evidence for a hydrodynamic oil-water contact which tilts down towards the west (Dennis et al. 1998). The interpretation explains the apparent underfilling of the southern and eastern portions of the field, whilst at the same time suggesting the presence of significant reserve upside in the west of North Pierce (Fig. 5). Pilot well 23/22a-A3y has subsequently located an oil-water contact at 10 170ft (3100m) TVDss on the western flank of North Pierce. This contact exists at almost 300ft (91m) TVDss deeper than the structural spill point for the field. It suggests that a tilted oil-water contact is appropriate for the Pierce field, with a I 115 ft (340 m) TVDss difference in the level of the contact across the field. Facilitating a highly tilted oil-water contact at the Pierce Field are the high relief of the structural trap, its location along a major Palaeocene channel sand fairway, and the relatively low permeability of the reservoir at this distal position within the fairway. The Forties submarine fan of the Central Graben provides a N W - S E trending conduit for aquifer flow from the toe of the fan to its seabed outcrop along the East Shetland Platform. Compaction fluids from sediment dewatering in the deep Danish Central Trough are transported through the Chalk to the more permeable Palaeocene fan sands, and then in a northwesterly direction, past numerous hydrocarbon traps, to their eventual discharge on the seafloor). Hydrocarbons within low permeability reservoirs along the path of the aquifer are displaced, with the oil-water contact being tilted downwards in the direction of fluid flow. The lower the reservoir permeability, the greater the angle of tilt.
BP 1996 ENT ZONAT- ZONATION ION
LITH 0
GR PROFILE API 100
_~___
F1
Severely tilted water contacts are observed in the Chalk fields of southern Norway and Denmark, and in fields with low permeability reservoirs within the southern (distal) part of the Forties Fan, including the Lomond, Pierce and Cod fields (Kesslar et al. 1980). By contrast, the higher permeability fields in the northern (proximal) part of the Forties Fan, including the Forties Field, exhibit only a minor hydrodynamic tilt to their hydrocarbon-water contact.
Reservoirs The principal reservoir for the Pierce Field is provided by the Forties sandstone member of the late Palaeocene Sele Formation (Fig. 6). Secondary reservoirs comprise the underlying Lista Formation sandstone and fractured Late Cretaceous to Palaeocene Chalk. Over 80% of field reserves lie within the Forties reservoir.
Palaeocene stratigraphic evolution Deposition at Pierce during the Palaeocene was controlled by the position of the field relative to the principal sand deposition fairways (Fig. 7), and the balance between diapir growth and sedimentation. An understanding of reservoir development and distribution has been achieved by the integration of facies and biostratigraphic analysis for all wells. The recognition of 28 correlatable biostratigraphic events for the Palaeocene at Pierce has enabled a detailed lithostratigraphic zonal scheme to be implemented, and a reconstruction of facies development to be made (Fig. 8). Submarine fan sedimentation commenced during the early Palaeocene, with sand facies belonging to the Maureen and Andrew/Lista formations prograding southeastwards along the axis of the Central Graben. The Pierce Field is located some 280 km down the Palaeocene depositional fairway, so early Palaeocene deposition was dominated by outer fan shale and low permeability, fine-grained argillaceous sands. Lista/Andrew deposition was controlled by renewed tectonic uplift along the NW-SE trending graben margin fault zone which
BIOSTRATIGRAPHIC EVENTS MUF1
Shaling upwards " Forties fan abandonment
MUF2
U-
MUF3
Pulse of channel sand deposition, with increasing dark grey shale Interbeds.
MUF4
Irn•N
O4
MUF5
U_
u_
MUF6
l.IJ
Silty channel / lobe margin coarsens up to stacked channel sands
O Od U_
LIJ Z 9 F3
F3
~
2~_
s z <s
MUF7
Regional slumping 9 reworked Lista mudstones
MLF1 Blocky channel and sandlobes with shale interbeds ' Extensive reworking of green / grey Lista mudstones.
oo
[J_
co uJ
O Lk
Pulse of channel sand deposition
MLF2
ii
.
.
.
.
.
.
.
MLF3 .Q ii
)2
t.O
Thin bedded sheet sands and sandlobes with shale interbeds 9 Extensive reworking of green / grey Lista mudstones.
. . . . . . . .
;;;;:; i-
- -
MLF4
LI_
u_
~ ;
Fig. 6. Pierce Field - Forties zonation scheme.
Coarsening upwards 9 Forties fan progradation. MLF5
PIERCE FIELD
653
Fig. 7. Gross Forties isochore for the Pierce Field.
transects the Pierce Field. The deposition of sand fairways was restricted to areas either side of the elongate footwall crest, which probably formed a bathymetric feature (Kneller & McCaffrey 1998). Lista/Andrew sand is consequently developed only at the eastern and western field margins, and much of the Pierce Field is dominated by non-reservoir shale facies. The Forties Sand member can be divided into two principal lithostratigraphic zones, the Lower Forties and Upper Forties, separated by a thin but laterally extensive Mid Forties Shale (Fig. 6). The two zones represent major depositional pulses along the Forties submarine fan, and are the products of regressive sedimentation during an overall late Palaeocene transgression. The tight biostratigraphic grid has enabled the Upper and Lower Forties to be further divided into a number of reservoir subzones, representing lesser depositional pulses. A progressive restriction of the basin during Forties deposition caused the background sedimentation to change progressively from light green/grey oxygenated shale to dark grey anoxic shale. Forties Fan sand deposition eventually gives way to a blanket of dark grey/brown Sele Shale, which forms the top seal for the Pierce Field. Whilst Lista/Andrew deposition was clearly controlled by a linear, salt supported footwall, sedimentation of the Forties Member was controlled by the growth of the two individual salt diapirs. This is suggested by the following observations (Fig. 9), which closely resemble predictive analogue models of the effects of
salt-induced topography on depositional patterns within submarine fans (Kneller & McCaffrey 1998): 9
The presence of heterolithic, fairway margin facies in wells drilled close to the diapir crests during the early deposition of both the Lower and Upper Forties. 9 The progressive onlap of channel sand facies onto the crest of both diapirs during the deposition of both the uppermost Lower Forties and the uppermost Upper Forties. 9 The deposition of thin, narrow channel sand fairways around the eastern and western diapir flanks (accumulative flow of Kneller and McCaffrey 1998). 9 The development of thick depositional aprons on the southern (lee) side of both diapirs (depletive flow of Kneller and McCaffrey 1998).
Principal reservoir." Palaeocene Forties Sandstone The quality of the Forties reservoir in the Pierce Field is controlled by the amount of clay (both detrital and authigenic) within the matrix (Banks 1998). Fine clay laminae block pore throats and inhibit permeability whilst causing only a slight reduction in porosity. For a field-wide permeability range of < 1 to >75 mD the overall porosity range is only 15 to 22%.
Fig. 8. Biostratigraphic correlations and facies development across the Pierce Field.
PIERCE FIELD
j
AccumulativeFlow Along Flanksof Diapir
655
Accumulative Flow Alio;gr Flanksof
~
23/22~,~6 23/22a-A3
/~
23/22a-3z
DepletiveFlow between Diapirs Associatedwith ChangeslofGlradient in
\
23/22a-A4 23/22a 23/27
~
~
~.
J
ACCwUmUlative
\
Accumulative Flow 23/22a-A5 23/22a-A12
\.,\
~
\
23/27.
Accumulative Flow
0
2 km
I
I
Depletive Flow in Lee of S.Pierce Diapir Associated with Decreasein Gradientand Flow Divergence
Fig. 9. Depositional patterns for the Forties sand at the Pierce Field.
Both porosity and permeability are considered to increase with depositional energy, due to an increase in the winnowing of detrital clay. There is, therefore, a broad relationship between porosity, permeability, and depositional environment. High porosity and permeability reservoir is usually located within channel sand facies along fairway axes, whilst the lowest quality reservoir is generally located within sand lobe facies at channel margins.
There is, however, not always a good relationship between channel sand thickness and reservoir quality. Extremely high energy, but thin channels, characterized by high porosity and permeability, are often developed over bathymetric highs and in other areas of accumulative flow. Periods of channel sand deposition over the diapir crest are characterized by the development of thin, but high quality reservoir sand units. This type of channel developes in areas
656
P. BIRCH & J. HAYNES
PIERCE FIELD
SrRSA 87Sr/86Sr Fig. 10. Strontium residual salt analysis graph, plotting depth against Sr87/Sr86 values for Pierce Field Wells.
PIERCE FIELD Table 1. Thickness weighted average petrophysical parameters jor the Forties reservoir at Pierce Zone
Subzone
Thickness ft (m)
Porosity
K (mD)
N/G (%)
Upper Forties
FI F2a F2b F2c
19 (5.8) 73 (22.3) 104 (31.7) 80 (24.4)
17 20 19 19
<1 22 40 37
1 75 77 71
Mid Shale
F3
11 (3.4)
17
13
9
Lower Forties
F4a F4b F5
75 (22.9) 71 (21.6) 45 (13.7)
19 18 16
19 14 8
68 57 19
of accumulative flow, located high on the diapir shoulders, during periods when deposition is restricted to the diapir flanks. A further ramification of this is that whilst isochore mapping provides a reasonable guide to sand fairways and net/gross (Fig. 7), it will only reflect reservoir porosity and permeability in areas where deposition has been unaffected by seafloor topography, in areas away from present day structural closure. Table 1 indicates that the average permeability of the Forties reservoir increases upwards to reach a maximum in the middle subzone of the Upper Forties, reflecting a gradual decrease in detrital clay content. Reservoir quality then decreases at the top of the Upper Forties in response to fan abandonment. There is no clear relationship between porosity and depth for any of the Pierce Field reservoirs.
S e c o n d a r y reservoir." Upper Cretaceous to Palaeocene C h a l k
A Chalk sheath surrounds each of the salt diapirs in the Pierce Field, and it can act as an effective reservoir where it is both porous and fractured. Oil and gas have been tested from steeply dipping and fractured chalk in wells drilled close to the salt. Typical flow rates are 1500 BOPD, increasing to 6700 BOPD after acid. A chalk reservoir facies with sufficient matrix porosity and permeability to facilitate communication with nearby fractures is represented as beds of resedimented chalk within the upper part of the Tor Formation and the overlying Ekofisk Formation. Nevertheless, fracturing is critical to the permeability, and therefore the productivity of this reservoir, and chalk reservoir effectiveness is measured by fracture intensity. Highly fractured chalk reservoir is characteristic of areas adjacent to the salt. Oil-bearing chalk in this structural setting has been cored by well 23/27-9, where several phases of fracturing and cementation are interpreted as having been associated with various pulses of diapir growth. The currently open fractures are aligned sub-parallel to the steeply dipping bedding, maximizing the surface area in communication with porous reservoir horizons, and providing excellent fractured reservoir fabric. Other areas of the field where the fracture density may be sufficient to form a productive reservoir include structural damage zones associated with major N W - S E trending basement faults, and outer-arc fracturing on hanging wall inversion folds associated with major N E - S W trending cross-faults. Whilst the Chalk could contain valuable additional reserves for the Pierce Field, no plan exists to further appraise this reservoir during the current phase of the development.
657
It is considered that the free gas has subsequently been derived from the same source rocks at a higher level of thermal maturity. Two potential source kitchens exist for the oil and gas at Pierce; a local kitchen associated with Jurassic source rocks within the Central Graben, or a more distant source within the Danish Central Graben. The latter would require long distance hydrocarbon migration along the Palaeocene fairway, and therefore seems less likely than the presence of a local kitchen. A local source is also suggested by the geochemical analysis of residual oils from the Jurassic of South Pierce, which are seen to be very similar to the Palaeocene oils of both South and North Pierce. The presence of a local source kitchen is further supported by strontium residual salt analysis (SRSA). High levels of SrS7/Sr86 enrichment are typical of connate fluids derived from deep, thermally mature sedimentary basins, whilst low levels of SrST/Srs6 enrichment are typical of thermally immature Tertiary basins. The technique involves the analysis of core samples (sidewall core samples rarely provide enough residual salt). Wells within many hydrocarbon accumulations display an increase in Sra7/SrS6 with depth, reflecting an increase in the maturity of the fluid charge with time. Cores from the South Pierce aquifer (well 23/27-1) contain water characterized by low levels of SrS7/SrS6 enrichment, typical of present day connate waters for the Palaeocene of the North Sea. If the Pierce oil reservoirs had been charged by hydrocarbon migration along this fairway, similarly low levels of SrS7/SrS6 enrichment could be expected for residual water in cores from the oil leg. By contrast, cores from the Palaeocene oil leg at South Pierce (wells 23/2%8 & 10)indicate a high level of Sr87/SrS6 enrichment (Fig. 10), suggesting the presence of residual fluids from a highly evolved, thermally mature basin. It can, therefore, be inferred that the Palaeocene reservoir at South Pierce was charged from a local source kitchen which also generated highly SrS7/Sr 86 enriched brines. However, analysis of residual water from cores in the Palaeocene oil leg at North Pierce (wells 23/27-2z & 3) indicates low levels of Sr87/SrS6 enrichment (Fig. 10). Whilst the North and South Pierce oils are geochemically identical, and therefore were probably generated from the same source kitchen, they clearly differed in their migration history. One explanation could be that the South Pierce trap was preferentially charged from the adjacent Jurassic source kitchen (Fig. 11). Once this part of this trap had been filled, hydrocarbons spilled into North Pierce, which would also have received a larger proportion of the subsequent gas charge. As the South Pierce trap spilled, the hydrocarbons destined for North Pierce would have mixed with low Sr87/Sr86 enrichment connate waters associated with the Palaeocene aquifer. There is little evidence to constrain the timing of the Pierce Field hydrocarbon charge. It is considered that hydrodynamism along the Palaeocene aquifer was possibly initiated when the head of the fairway was exposed by Middle Miocene erosion along the East Shetland Platform. The Pierce trap could have already been partially filled during the Oligocene and Early Miocene. However, a lack of residual oil in the Palaeocene of well 23/27-1, located within structural closure but outside the hydrodynamic trap, suggests that the trap was never filled to its structural spill point prior to the onset of hydrodynamism. It also indicates that a proportion of the charge must post-date the Middle Miocene. The presence of residual oil within the aquifer in South Pierce wells 23/27-5 & 6 suggests that the tilted water contact may have retreated slightly in response to the partial leakage of the South Pierce gas cap. This ongoing modification of the Pierce Field may have already disconnected the South and North Pierce oil pools by raising the oil-water contact at the intervening structural saddle.
Hydrocarbon charge
Conclusions
The Pierce Field contains 38 ~ API oil with a G O R of 1100 SCF/STB. Geochemically it is a typical North Sea oil, derived from Upper Jurassic, Kimmeridge Clay source rocks at peak thermal maturity.
The following conclusions can be drawn from the appraisal and development of the Pierce Field, some of which may be applicable to other diapir fields:
658
P. BIRCH & J. HAYNES
NW
North Pierce
SE
South Pierce
/ ~ S
_---- . . . . .
"-:-.
~
Oil + High 87Sr/86Sr Brine
OWC Palaeocene 6
:* Oil + High 87 Sr/86 Sr Brines Migrate into South Pierce Palaeocene Trap from Thermally Mature Upper Jurassic Source Kitchen
A,~ c e n e
m
Sand
~------.7..~.. ~ § -'2-~ ~ ~ ~
Kimmeridge Source Rock
~
Oil + High 87Sr/86Sr Brine Oil + Low 87Sr/86Sr Water OWC
<
,
Active
Low 87Sr/86Sr Water
Palaeocene
Aquifer
High 87Sr/86Sr
4-
B) M. Miocene 9 South Pierce Spills to North Pierce and North Pierce Oil Mixes with Low 87Sr/86Sr Water from Palaeocene Aquifer
-0-
"~"
"~
4-
4-O-
-O-
-0-
444-
4-
-O-O-
-0-
4-
l
Gas Seapage L at Diapir Crest
Retreating GOC New OWC OWC
- Old
Low 87Sr/86Sr Water
Active Palaeocene
Aquifer
C) Recent 9 Gas Cap Breached on South Pierce South Pierce GOC and OWC Retreat Disconnecting the Two Oil Pools at Intervening Saddle
Fig. 11. Cartoon showing postulated charge history for the Pierce Field.
PIERCE FIELD 9
9
9
9
9
9
Radial faults on the flanks of the field do not seal along their length, since fault displacement rapidly decreases away from the diapir. Concentric faults can seal, particularly in low net/gross reservoirs. They often a c c o m m o d a t e large displacements parallel to steeply dipping bedding, close to the salt domes, and can be difficult to image on seismic. A n active aquifer, a low permeability reservoir, and considerable vertical relief have c o m b i n e d to produce a highly tilted oilwater contact. Isochore mapping provides a poor guide to porosity and permeability, but a reasonable guide to net/gross. The best porosity and permeability exists in thin channel sands within areas of high flow velocity, at palaeo-topographic highs (areas of accumulative flow). Strontium residual salt analysis has provided a useful tool for the study of reservoir compartmentalization and charge history at the Pierce Field. Very little structural compartmentalization exists in the Pierce Field, but many of the faults may act as transmissibility baffles during the productive life of the field. High angle production wells and an appropriate perforation strategy, therefore, remain an important aspect of the development plan.
The author thanks Shell UK Exploration and Production, Oranje Nassau and Mitsubishi for their permission to publish this paper. Particular thanks
659
go to the Pierce Team at Enterprise Oil, and to Lorna Donald for drafting the figures. Thanks also to IAS for SRSA analysis.
References BANKS, J. Y. 1998. Turbidites: a permeability paradigm. MSc Thesis, University of Aberdeen, UK. DAVlSON,I., ALSOP,I., BIRCH,P. L., EVANS,N., NIC'HOLSON,H., ROR1SON,P. & WADE, D. 1999. Geometry and structural evolution of Central Graben salt diapirs, N. Sea. Marine and Petroleum Geology (in press). DEEGAN, C. E. & SCULL, B. J. 1977, A standard lithostratigraphic nomenclature for the Central and Northern North Sea. Inst. Geol. Sci. Rep. UK, 77, 25. DENNIS, H., BAILLIE, J., HOLT, T. & WESSEL-BERG, D. (in press). Hydrodynamic activity and tilted oil-water contacts in the North Sea. In: O~STAD. K. et al. (eds) Proceedings of the N P F Conference, 'Improving the Exploration Process by Learning From the Past', Elsevier, Netherlands. KESSLER, L. G., ZANG, R. D., ENGLEHORN, J. A. & EGER, J. D. 1980. Stratigraphy and sedimentology of a Paleocene submarine fan complex, Cod field, Norwegian North Sea. In: Sedimentation of the North Sea Reservoir Rocks. Norsk Petroleumsforening, Article VIII, 19p. KNELLER,B. & MCCAFFREY,W. 1998. Modelling the effects of salt-induced topography on deposition from turbidity currents. World Wide Web Address: http://earth.leeds.ac.uk/research/seddies/ben2/p2html.
The Barque Field, Blocks 48/13a, 48[14, UK North Sea M . J. S A R G I N S O N
Shell Expro, P.O. Box 4 Lothing Depot, North Quay, Lowestoft, Suffolk NR32 2TH, UK (e-mail. Marcus. Sarginson @ Shell.com)
Abstract: The Barque Field is associated with some of the earliest gas discoveries in the southern North Sea. In the Sole Pit area the reservoir, the Rotliegend Group Leman Sandstone Formation of Lower Permian age, occurs between Carboniferous Coal Measures, which source the gas, and Zechstein evaporites which form an excellent seal. Primarily aeolian, the sandstone has generally very low permeability resulting from deep burial of the Sole Pit Trough. The deepest burial and hence the maximum diagenetic damage to the reservoir was achieved in the early Late Cretaceous prior to two phases of inversion in Late Cretaceous and Mid-Tertiary. Compaction and diagenesis reduced reservoir permeability to such an extent that parts of the field would be non-productive were it not for the presence of effective natural fracture zones and well stimulation by hydraulic fracturing techniques. Though appraisal and evaluation have been relatively extensive, remaining uncertainties dictated a conservative development in conjunction with the adjacent Clipper Field. A selected initial area was developed for first gas in October 1990. Good reservoir performance from horizontal wells led to later development of the whole field. The Barque Field, some 45 miles off the Norfolk coast, lies within the Sole Pit area of the southern North Sea. It is located 60 miles east of Grimsby and a similar distance north of Great Yarmouth. An elongate feature with a northwest trend (Fig. 1), the field has a length of 15 miles and a maximum width of 2 miles, and covers an area of more than 9000 acres. Water depth varies between 15 and 25 fathoms (90-150ft) and the majority of the gas-bearing Rotliegend reservoir is found between 7500 and 8500 ft TVDss. The Rotliegend is 700-800ft thick over the field and consists mainly of aeolian quartzose sandstones, which are entirely gasbearing in the crestal sector. The gas is very dry, consisting of 95% methane with about 1.5% inert gas and a small proportion only of condensate, typical of this area of the North Sea. The Barque Field is now under development in conjunction with the adjacent Clipper Field. Together with other joint venture southern North Sea gas fields, Galleon and Skiff, these field names commemorate vessels from maritime history.
History Licence P.008 covering Blocks 48/13, 14, 19 and 20, was awarded to the joint-venture partners Shell U K Exploration and Production and Esso Exploration and Production U K in the first licensing round, September 1964, with Shell as operator. The first North Sea hydrocarbon discovery, BP's West Sole Gas Field in Block 48/6, was drilled and tested in late 1965 (Butler 1975). Shell/Esso drilling in Sole Pit began in mid-1966 with the discovery of gas in well 48/13-1, located to test a seismic high feature on the trend between Leman Field (Block 49/26 and 27) and West Sole Field. This well came in deep, encountering a tight, gasbearing Rotliegend section in what was later recognized as an independent closure immediately north of the prime target, the Barque Field. The well credited with the Barque Field discovery, 48/13a-2A, was drilled in 1971 in a near-crestal location about 3.5 miles N W of 48/13-1 and although reservoir quality appeared poor the well tested up to 9.7 M M S C F D after stimulation by acid and hydraulic fracturing (Moore 1989). Appraisal was delayed until 1983 when techniques had advanced and commercial development of a reservoir with such a low permeability matrix appeared feasible. That year saw the drilling of a crestal mid-field well 48/13a-4 which tested up to 50 M M S C F D after acidization and a southeastern appraisal, 48/14-1, which tested up to 25 M M S C F D (two zones flowing commingled) after acid and hydraulic fracture stimulation. Appraisal continued in 1984 with the drilling of another mid-field well, 48/13a-4, which tested up to 39 M M S C F D after acid/hydraulic fracture stimulation, followed by 48/13a-6 in the northwest extremity of the field which yielded less than 1 M M S C F D after stimulation. Later that year the sixth Barque well, 48/13a-7A, encountered a reduced section of Leman
Sandstone as a result of seismic uncertainty in mapping the boundary fault. Drilled northward from the location of 48/13a-4, as a highly deviated well, it passed from mid-Rotliegend through the major northern boundary fault to terminate in downthrown Zechstein evaporites. Testing in early 1985 failed to establish flow. All appraisal wells were plugged and abandoned after testing. Conventional core and well analyses confirmed the poor quality of the reservoir with in situ matrix permeability commonly averaging less than 1 mD. It was also apparent, however, that reservoir quality varied considerably and that zones of natural fractures, occurring at intervals throughout the field, increased productivity markedly if connected to the well bore. Several development plans were considered, the final choice being a phased development of the most favourable area of Barque together with a similar favourable area in the adjacent, low-permeability Clipper Field. In the case of Barque, the initial development area was located in the central/ northwest part of the field to maximize accessible gas-in-place in an area where fracture zones are likely to occur. The first unmanned 18-slot satellite platform (PB) was installed early in 1990. Development drilling commenced in January 1990 with a horizontal well predrilled from the platform position. Achieving a test flow rate of 48 M M S C F D , this well confirmed the potential benefits of this technique in tight matrix. Platform drilling on Barque commenced in mid-1990 with first gas production in October that year. A further ten development wells, eight of which were horizontal, were drilled from the PB platform between 1990 and 1994. Initial flow rates ranged between 4 and 33 M M S C F D . The second phase of the development commenced in 1994, with the installation of a second unmanned platform (PL) over the southeast part of the field (Barque Extension). To date, five horizontal development wells, including two dual laterals, have been drilled from this platform, with initial rates ranging between 20 and 100 M M S C F D . Two further wells will be drilled in 2000-2001. In 1998 a horizontal underbalanced well was drilled to appraise the Barque J structure, a low relief area to the north of the PL platform. The well encountered top reservoir 177 ft low to prognosis. It initially produced 14 M M S C F D but soon died following water production. Development options for this area are currently under review. The PB and PL platforms are linked by a 16 and 14 inch pipeline, respectively, to the main production complex on Clipper Field, 12 miles to the southeast. Production from the two fields is evacuated through a dedicated 24 inch trunkline to Bacton, 46 miles to the south.
Field stratigraphy A typical stratigraphic section from the initial development area of Barque Field is shown in Figure 2. In addition to group and
GLUYAS,J. G. & H~CHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 663-670.
663
664
M. J. S A R G I N S O N
ee') O
O
O [..
BARQUE FIELD
665
Fig. 2. Barque Field stratigraphic sequence.
formation names, the subdivision of members best suited to seismic and wellsite use is also given. The Lower Permian Rotliegend Group in Sole Pit lies unconformably on Carboniferous Coal Measures and is overlain by a thick Zechstein section consisting of cyclic evaporites and carbonates which vary between 1500 and 2500ft in thickness. Overlying the Zechstein a thin (less than 100ft) Brockelschiefer siltstone forms the basal member of the Lower Triassic Bacton Group, followed successively by three units, the Bunter Shale Formation, its upper Rogenstein Member, and the Bunter Sandstone Formation. The total thickness of the Bacton Group is c. 2000 ft in the Barque area. The Bacton Group is overlain by sediments of the Middle and Upper Triassic Haisborough Group, comprising three evaporite cycles (Rot, Muschelkalk and Keuper) and intervening fine-grained clastics. These cycles total some 2500 ft in thickness and are generally followed by thin Rhaetic sandstones and shales of the Winterton Formation. The succeeding undifferentiated Lower Jurassic sequence is incomplete, though up to 1000ft thick, and consists of fine-grained clastics. Middle and Upper Jurassic and Cretaceous sediments are absent from the Sole Pit structural high. A thin Tertiary-Recent section lies between the seabed and the Lias.
This stratigraphic sequence represents the late Palaeozoic to Tertiary filling of the southern North Sea Basin interrupted by significant episodes of uplift. The basin formed after early Hercynian uplift and erosion of the Carboniferous, and at Barque the Rotliegend is unconformable upon Carboniferous Coal Measures. Subsidence allowed accumulation of continental, predominantly aeolian, sediments followed eventually by a marine transgression and the markedly different cycles of the Late Permian Zechstein sediments (Taylor 1984). Basin fill led to further continental sedimentation in the early Triassic and a later return to marginal and fully marine (evaporitic) cycles (Fisher 1984). Marine clastic sedimentation continued through the Jurassic into the Early Cretaceous with accelerated subsidence in sub-basins such as Sole Pit (Lutz et al. 1975). By the Late Cretaceous the Rotliegend Group had reached its greatest depth of burial, and some local tectonic inversion began (Glennie & Boegner 1981) in response to re-activation of older deep-seated fault systems (van Hoorn 1987). In the Barque area little remains of the post-Triassic sequence as inversion of the Sole Pit high removed most of the Jurassic-Cretaceous sequence. Compaction studies of the Bunter Shale indicate some 5000 ft or more of post-Liassic sediments were removed during this inversion
666
M. J. SARGINSON
(Marie 1975; Glennie et al. 1978). Limited Tertiary sedimentation ended with further uplift associated with the Alpine orogeny.
Geophysics
Seismic interpretation is based on five horizons with well ties provided by synthetic seismograms using sonic, density and well velocity logs. The usual seismic character over the field is shown in Figure 3; the location of this section is shown in Figure 1. The five main mapping horizons are: 9
2D seismic surveys were shot in 1978, 1979 and 1980; these were utilized during field appraisal. A pilot 3D survey was acquired over 15 square miles of southeastern Barque in 1984, and a subsequent survey in 1987 completed 3D coverage of the field. Both 3D surveys have cross-line and inline spacing of 25 m. Earlier seismic suffered both in quality and from uncertain depth conversion, a problem noted by Hornabrook (1975). Processing of the 1987 3D data was completed in mid-1989 and results were incorporated in revised mapping prior to the beginning of development drilling. Imaging of the reservoir is affected by ray bending in the overburden, in particular at the heavily faulted Jurassic/Triassic boundary where there is a large velocity contrast, which results in both poor focusing and lateral positional uncertainty of top reservoir in the post-stack time migrated 3D data. Pre-stack depth migration was carried out on the 1984 survey at the start of the second phase of field development in 1994 (Fig. 1). This improved imaging of the reservoir; results were used to update the field maps and volumetric estimates. The whole Sole Pit area was re-shot in 1999; the new survey was designed to achieve a high fold of stack in the overburden, with the objective of carrying out a full pre-stack depth migration to accurately image the reservoir. Processing is ongoing at the time of writing.
9 9 9 9
Top Triassic, often affected (as shown) by listric faults in the overburden; Top Bunter Sandstone, generally continuous; Top Zechstein, generally continuous; Top Platten Dolomite, strong seismic expression; Top Rotliegend, moderate amplitude, faulted, sometimes obscured by the Platten Dolomite reflector.
Within the Rotliegend, seismic character shows little detail. The base Rotliegend is only occasionally discernible. Minor faults (throw < 100 ft) have been mapped using seismic coherency and dip displays. 3D illumination of the top Rotliegend seismic surface reveals SSW-NNE and W S W - E N E trending lineaments (Fig. 5), which may represent an early formed joint system that was subsequently re-activated. Time to depth conversion has been achieved using a multi-layer velocity model based on migration and well velocity data.
Trap The structural map (Fig. 1) shows that the Barque Field is formed by dip-closure against a N W - S E trending major fault. Seismic data indicate this may have a reverse sense of movement in places. Top
Fig. 3. Seismic dip section across Barque Field (1995 3D Pre-SDM seismic). Line of section shown on Fig. 1.
BARQUE FIELD
667
Fig. 4. Structural section across Barque Field, showing reservoir zonation and FWL (line of section shown on Fig. 1).
Fig. 5. Illluminated top Rotliegend surface from 3D seismic (view from south, 60~ elevation). Arrows indicate lineaments.
reservoir dips to the SW over most of the field. The top seal is formed by the Zechstein evaporites and the tight carbonates immediately above the Rotliegend. The major boundary fault is clearly recognized as sealing where the Rotliegend reservoir is juxtaposed against the Zechstein (see structural cross-section, Fig. 4). To the north of the main boundary fault is a low relief fault dip closure, known as the Barque J area.
Three dimensional illumination of the top Rotliegend seismic surface reveals S S W - N N E and W S W - E N E trending lineaments crossing the field (Fig. 5). These may represent an early formed joint system that was subsequently re-activated. Cataclasis and mineralization along these zones has resulted in intra-reservoir seals; exploration and appraisal well logs indicate at least five different free water levels within the field, ranging between 8570 and 8850 ft TVDss.
668
M.J.
SARGINSON
BARQUE FIELD
Reservoir Hydrocarbons in the Barque Field occur within the Leman Sandstone Formation, which here represents the entire Lower Permian Rotliegend Group and is referred to as the Rotliegend. These sandstones, described as moderately mature quartz arenites (Nagtegaal 1979), were deposited in a continental desert environment (Glennie et al. 1978). Deep burial of the Rotliegend prior to Cimmerian uplift resulted in compaction and advanced diagenesis, which has markedly reduced reservoir permeability. Reservoir quality and diagenesis have been described by Glennie et al. (1978), Nagtegaal (1979), Rossel (1982) and Seeman (1982), the prime cause of permeability reduction being the formation of diagenetic illite as pore-lining and pore-fill. Late-stage diagenesis involving authigenic quartz and Zechstein-derived cements has a less marked but significant effect. Three main reservoir zones are recognized within the Barque Field (Fig. 6). The upper 'A' zone consists predominantly of sabkha sandstones, with thin interbedded aeolian dune, sandsheet, and waterlain sandstones. This unit was deposited in an erg margin/ lake margin environment. Reservoir properties are generally poor; average porosity c. 10%, permeability generally less than 0.1 mD. The structureless Weissliegend (AW) sandstone (Glennie 1984), reworked/homogenized following the Zechstein transgression, lies at the top of the sequence. Towards the base of the 'A' zone are a number of 10-20 ft thick muddy sabkha beds. These are correlatable over large areas (several km), and were deposited during a relatively humid climatic period during which the Silverpit lake expanded and the water table in the Barque area was at or near the surface. The muddy sabkha layers have low porosity and permeability, and may act as a baffle to flow between the 'A' and underlying 'B' zones in areas of the field where there are no open natural fractures. The 'B' zone largely comprises stacked aeolian dune sandstones, thought to have been deposited in an erg interior setting. This unit has the best reservoir properties; porosity reaches 15-20% in thick medium-grained slipface sandstones, with some laminae having permeabilities of tens of mD. Most horizontal development wells to date have targeted the 'B' zone in structurally high areas of the field
669
(Fig. 7). Waterlain sandstones, formed in wadi systems which crossed some areas of the field, occur in the upper part of this layer. These have markedly lower permeability (less than 1 mD) than the dune slipface sandstones, and form unproductive zones where intersected by development wells. The lowermost 'C' zone comprises interbedded aeolian dune, sandsheet, sabkha, and waterlain deposits, deposited in an erg margin setting. This unit shows uniformly low (less than 0.1 mD) permeability, owing to pervasive (predominantly illite) cementation. Both open and cemented natural fractures occur within the Barque Field. Image logs indicate that these are steeply dipping (70-90~ with a NW-SE orientation in the northwest part of the field and NE-SW orientation in the southeast of the field. Open natural fractures occur in the central area of the field, and where intersected by development wells these make a significant contribution to productivity. Conversely, pervasive cemented fractures have a deleterious effect on well deliverability and reservoir connectivity in the west of the field.
Source In the Sole Pit area, the underlying Carboniferous Coal Measures are the acknowledged source for the gas (Lutz et al. 1975), their deep burial leading to maturity and gas generation starting in the Jurassic and continuing at least until the Late Cretaceous uplift. The migration path was directly upward into the overlying Rotliegend. Late Tertiary uplift may have modified fill slightly through re-migration or elevation changes.
Hydrocarbons Well-test data were summarized in an earlier section. Further details of test analyses for wells 48/13a-2 and 48/13a-5 are given by Moore (1989).
I
,o
Fig. 7. Horizontal well targeting Rotliegend 'B' zone. Location shown on Fig. 1. Facies key as in Fig. 6.
670
M. J. SARGINSON
Table 1. Gas composition
Formation water Salinity
Component
%
Methane Ethane Propane Iso-butane N-butane Iso-pentane N-pentane Hexane Heptane+ Nitrogen Carbon dioxide
94.59 2.73 0.49 0.09 0.11 0.04 0.04 0.05 0.10 1.36 0.35
Resistivity
Extensive sampling of reservoir fluids in the Sole Pit area has established the gas c o m p o s i t i o n and expected condensate production. A typical gas analysis from Barque appraisal well 48/13a-5 is given in Table 1. Gas gravity is 0.59 (air-- 1) and the gross calorific value is 1019 B T U / S C F . C o n d e n s a t e p r o d u c t i o n has been between 1 and 1.5 B B L / M M C F . F o r m a t i o n water samples are highly saline (180 000-200 000 p p m equivalent), typical of the Rotliegend in this area. The initial reservoir was hydrostatic; 3850psi at a d a t u m depth of 8200ft TVDss. N o e n c r o a c h m e n t of the water leg is expected t h r o u g h o u t field life. To date there has only been m i n o r water p r o d u c t i o n from two wells; these were in d o w n structure locations and intersected open fractures extending d o w n into the aquifer. The average reservoir temperature is 175~
Reserves Gas recovery is by pressure depletion. Based on 3D seismic and petrophysical data from exploration, appraisal and d e v e l o p m e n t wells, the most likely gas in place estimate for the whole Barque Field is 3020 BCF. M o r e than 50% of this is found within the 'A' zone. The recovery factor has been estimated using a full field simulation model. This is a dual permeability model, incorporating fracture flow, and is history m a t c h e d to p r o d u c t i o n data. The current expectation recoverable reserves for the whole Barque structure are 1366 BCF. Total p r o d u c t i o n at 1/1/99 was 330 BCF. This paper is an update of the paper by Farmer & Hillier in the 1991 edition of United Kingdom Oil and Gas FieMs, and incorporates much of the material from that original paper. The author would like to thank Shell Expro and Esso Exploration and Production UK Ltd for permission to publish this paper. In common with most field descriptive papers it represents largely the work of many people and I am grateful to colleagues for their efforts, assistance and advice, especially with reference to studies of facies, fractures, special core analysis, well test analysis and simulation modelling.
Barque Field data summary Trap Type Depth to crest Free water level Gas column
Dip closure with anticlinal rollover against fault 7000 ft TVDss 8570 8850ft TVDss up to 1600ft
Pay zone Formation Age Gross thickness Porosity Gas saturation Matrix permeability
Leman Sandstone (Rotliegend) Lower Permian 700 800 ft 11.1% average all zones 51% average all zones 0.02-100rod average less than I mD all zones
Hydrocarbons Gas gravity Gas type Condensate yield
0.59 sweet dry gas 1-I .5 BBL/MMSCF
Reservoir conditions Temperature Initial pressure Pressure gradient
Field size Area Gas expansion factor Gas-in-place Recoverable reserves Production First gas Development scheme
160 000 ppm chloride 200 000 ppm sodium chloride equivalent 0.02 ohm m
175~ 3800 3850psi at datum 8200ft TVDss 0.07 psi/ft (gas leg) 0.5 psi/ft (water leg)
9000 acres 228 (SCF/RCF) 3020 BCF (includes Barque 'J' area) 1366 BCF
October 1990 in conjunction with Clipper Field Two normally unmanned platforms, installed 1990 and 1994 17 development wells (+1 producing appraisal) to date 2 further development wells planned in 2000-1 Future infill drilling dependent on well/field performance
References BUTLER, J. B. 1975. The West Sole Gasfield. In: WOODLAND A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1, Geology. Applied Science Publishers, London, 213 219. FISttER, M. J. 1984. Triassic. In: GI,F:NNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 85-101. GLV2~NIE, K. W. 1984. Early Permian-Rotliegend. In: GLI:,NN~E,K. W. (ed.) Introduction to the Petroleum Geology oj" the North Sea. Blackwell Scientific Publications, London, 41-60. GLI':NNIE, K. W. & BOI:C;NI~R,P. L. E. 1981. Sole Pit inversion tectonics. In: ILLJN(;, L. V. & HOI~SON, D. G. (eds) Petroleum Geology of the Continental Shelf oj' North West Europe. Institute of Petroleum, London, 110 120. GLI!NNIE, K. N., MUDI), G. C. & NA(iTEGAAL, P. J. C. 1978. Depositional environment and diagenesis of Permian Sandstones in Leman Bank and Sole Pit areas of the UK southern North Sea. Journal of Geological Society, London, 135, 25-34. HOORN, B. VAN. 1987. Structural evolution, timing and tectonic style of the Sole Pit inversion. Tectonophysics, 137, 239-284. HORNA~ROOK, J. T. 1975. Seismic interpretation of the West Sole gas field. Proceedings of the Bergen North Sea Conference, Norges Geologiske Undersokelse, 121-135. LtJfz, M., KAAtSC~IIE1H~,J. P. H. & WlJliE, D. H. VAN. 1975. Geological factors controlling Rotliegend gas accumulations in the Mid-European Basin. Proceedings of the 9th World Petroleum Congress, 2, 93-103. MARIE, J. P. P. 1975. Rotliegend stratigraphy and diagenesis. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1, Geology. Applied Science Publishers, London, 205-210. MOORE, P. J. R. McD. 1989. Barque and Clipper well test analysis in low permeability fractured gas reservoirs. Proceedings of the 1989 SPE Joint Rocky Mountain Region/Low Permeability Reservoir Symposium, Paper No. SPE 18966. NAGq-EGAAL, P. J. C. 1979. Relationship of facies and reservoir quality in Rotliegendes desert sandstones, southern North Sea region. Journal of Petroleum Geology, 2, 145 158. ROSSEL, N. C. 1982. Clay mineral diagenesis in Rotliegend aeolian sandstones of the southern North Sea. Clay Minerals, 17, 69 77. SEEMAN, U. 1982. Depositional facies, diagenetic clay minerals and reservoir quality of Rotliegend sediments in the southern Permian Basin (North Sea), a review. Clay Minerals, 17, 55 67. TAYLOR, J. C. M. 1984. Late Permian-Zechstein. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 61 83.
The Boulton Field, Block 44/21a, UK North Sea A. M. C O N W A Y 1 & C. V A L V A T N E 2
1 ConocoPhillips, Rubislaw House, Anderson Drive, Aberdeen AB15 6FZ 2 ConocoPhillips, 600 N. Dairy Ashford, Houston, Texas 77079
Abstract: The Boulton Field was discovered in 1984 when gas was tested from the Lower Ketch Unit, Carboniferous Westphalian C/D, in well 44/21-2. Following appraisal drilling in 1990, the Boulton 'B' structure was delineated and a trap confirmed by a combination of up-dip seal against basal Permian shales, and salts and lateral seal against sealing faults and impermeable Westphalian C sediments. A second structure was drilled in the same year, Boulton 'F', with gas discovered in the deeper Murdoch Sand Interval of the Westphalian C/D. The two separate structures collectively form the Boulton Field. Current deliverability from the 'B' structure, Lower Ketch Sands is approximately 100 MMSCFD from a single producer. Developed with a minimal platform facility, the gas is delivered to Theddlethorpe Gas Terminal via offshore compression at the nearby Murdoch Field. The reservoir in Boulton 'B' comprises a series of channel sands deposited in a braided stream complex flowing predominantly from north to south across an Upper Carboniferous alluvial plain. Sandbody connectivity within the complex fluvial architecture of the Westphalian C is a key control on gas production. The Boulton Gas Field lies in U K C S Block 44/21 a, located approximately l l 0 k m off the Lincolnshire coast and l l k m SW of the Murdoch Field in the Carboniferous sector of the Southern North Sea (Fig. 1). Boulton Field owners in the block are ConocoPhillips, as operator (46%), G d F Britain Ltd (44.5%) and Tullow Exploration Ltd (9.5%). Water depth at the field location is 125 ft. The field comprises two structures 'B' and 'F', representing the Carboniferous Westphalian C/D and Murdoch reservoir units, respectively. Gas production commenced on 31 December 1997 with an off-take route from the Boulton minimal facilities platform to the Murdoch platform, ultimately ending at the Theddlethorpe Gas Terminal (TGT). However, production comes entirely from the Boulton 'B' structure. Technical work is currently being undertaken on the development of the Boulton 'F' structure to assess the economic viability of the project with various development options and timings.
History Exploration and appraisal Block 44/21 was originally awarded to Total as part of the 1st UKCS licensing round in 1964. The 44/21-1 well was drilled in 1965 with a primary objective of testing gas from the Triassic Bunter Sands. With no shows, the well was deepened and encountered 345 ft of Carboniferous Westphalian C/D. Located off structure, the well did not encounter hydrocarbons and it was plugged and abandoned as a dry hole. Subsequently relinquished, the block was awarded to BP in 1983 in the 8th Round. Exploratory drilling recommenced in 1984 when the 44/21-2 well encountered gas in Westphalian C/D sands and conglomerates. The interval was tested and yielded 28.9 M M S C F D . Well 44/21-3 was drilled in 1986, northeast of the discovery well, but encountered the Westphalian C/D sands below the gas-water contact. A second Carboniferous prospect was targeted with the 44/21-4 well. Drilled in 1988, the well was located in southeastern part of the block and successfully tested gas in the Westphalian C/D at a rate of 33.0 M M S C F D . In 1989 the 44/21-5 well was drilled to the west of the 44/21-2 discovery, but encountered the Westphalian C/D sands below the gas-water contact. The north and southwest parts of the block were relinquished in 1989 and the remaining licence designated 44/21a. Conoco (UK) Ltd farmed-in to 44/21a in 1990 assuming operatorship and establishing a joint partnership with BP. An accelerated appraisal programme for both the 44/21a discoveries and the adjacent 44/22 Murdoch Field was undertaken to justify economic development of the Carboniferous in this area. Discovery well 44/21a-6 spudded in August 1990, was designed to test a broad Carboniferous structure 6 km E of 44/21-2. Gas was encountered in the Carboniferous Murdoch Sands and the Namurian. Well 44/21a-7
was drilled in December 1990, 500m southwest of the 44/21-3 well, and encountered gas in the Westphalian C/D sands, successfully delineating the Boulton 'B' structure. An extended well test was conducted in the following year and confirmed a high, sustainable flow rate from the Westphalian channel sands. The 44/21a-6 discovery well was appraised in 1993 by the 44/21a-9 and 10 wells, but poor reservoir quality and test results have led to a downgrading of the 'F' structure. With appraisal of the discoveries complete, development options were considered and government approval to develop Boulton granted in 1995.
Development The production from Boulton Field is from the 44/21a-B01/02 well. This well is the only producer in the 'B' structure. Figure 2 illustrates the structural setting of Boulton and the location of the 44/21a-B01 producer within the Westphalian C sands. This high angle (63 ~) development well, drilled in December 1997, was designed as a twin to the 44/21a-7 appraisal well. It was completed with sand screens across the Westphalian C/D reservoir interval.
Structural development and field stratigraphy Three major tectonic events: the Variscan (end Carboniferous), Cimmerian (end Jurassic) and Alpine (Late Tertiary) Orogenies dominated the structural development of the area. Tectonic control on the Westphalian sedimentation appears subtle and indications of syn-sedimentary faulting are illusive. The early Carboniferous rift phase followed by thermal subsidence established a northwest to southeast trending basin into which the Westphalian Coal Measures were deposited. These were overlain by the Westphalian C/D 'Barren beds', so called because they were devoid of coals. Deposited in a fluvial environment with rivers flowing in a general southwesterly direction, the Westphalian C/D comprised three main facies. These were channel sands interpreted to have wide meander belts, levees and crevasse splays. From regional isopach maps over the area it is apparent that a fairly uniform 500 to 700 ft of Westphalian C/D was deposited. The stratigraphic column shown in Figure 3 illustrates the general sequence encountered in the area and the development of thick channel sands that comprise the reservoir in Boulton. Sedimentation ceased during the Variscan Orogeny and the northwest to southeast fault trend was re-activated. Considerable folding and uplift, and subsequent erosion and peneplanation occurred establishing the truncated anticline intra-Carboniferous structure observed today in Block 44/21. Figure 4 a N W - S E cross-section through the field, demonstrates the pervasive nature of the Base Permian unconformity and the formation of the separate Boulton 'B' and 'F' traps.
GLUYAS, J. G. & HICttENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 671-680.
671
672
A. M. CONWAY & C. VALVATNE
Fig. 1. Boulton Field location, illustrating the field's position in the Carboniferous Westphalian. Sedimentation continued almost uninterrupted from end Carboniferous to end Jurassic times (Maynard et al. 1997). The area was then subjected to a period of major inversion accompanied with reactivation of faulting, often in the reverse sense. Deposition resumed in the Lower Cretaceous but was again interrupted by
the predominantly compressive Alpine orogeny. Deep Carboniferous faults were again reactivated, and the Top Carboniferous structure was finally set. These Alpine movements locally mobilized the Permian Zechstein salt section that pillowed in the southeast corner of the block. The 44/21-1 well was drilled just off
BOULTON FIELD
673
54~
54~
Fig. 2. Boulton Field (Block 44/21a). tructural features map illustrates the outline of the production reservoir as a rim around the central, deeper Murdoch closure, Boulton F. The geological cross-section A-A t is shown on Figure 4.
the crest of a salt-induced anticline at Triassic Bunter level, but proved dry.
Geologic model The Upper Carboniferous section in the Boulton Field shows facies representing deposition in the middle of an alluvial plain. The over-
all flow direction for this system was from north to south. The field has two reservoirs of different ages. The deeper reservoir is the Murdoch Sandstone of lower Westphalian B age and forms the reservoir for the 'F' structure. A regional chronostratigraphic framework for the Westphalian C has been developed, resulting in five distinct units. The 'B' structure has a younger reservoir, a sand-prone chronostratigraphic unit of Westphalian C age called the Lower Ketch 2 (see Fig. 3). The Lower Ketch 2 unit represents the primary reservoir
674
A . M . CONWAY & C. VALVATNE
Fig. 3. Boulton Field (Block 44/21a). Schematic stratigraphic column highlighting the production reservoir intervals at Boulton.
BOULTON
FIELD
675
m
~ x
,4
0
0
3 o
0
CO
9
cO
c~
!
c~
!~ii~ I I
(.3 ~S
o
~ i I)!
o
c~
9
8o '-'~ co
.o o
I",-
0 5_, 0 5... !
o
,1"8
o o
o
o
<~
Z o,J
o
,,r-
(000 l.X) 99GA_L q~.doc]
0
676
A . M . CONWAY & C. VALVATNE
unit. The target lithofacies for both 'B' and 'F' reservoirs are fluvial sandbodies, w h i c h have been charged with gas from Westphalian B coals. Figure 4 illustrates the correlation across Boulton highlighting the gas pays in both the Lower Ketch 2 sands and Murdoch sands. The 'F' structure Murdoch sandstones were deposited as regionally extensive fluvial sands and can be subdivided into three main units. The basal fluvial package has an upward fining aspect. Wireline logs and core data suggest the depocentre for this unit lay in the vicinity of well 44/21 a-9 and that channel density decreased to the north and northwest of this well. In all wells, the unit terminates in a lacustrine/channel abandonment facies association, which represents a fieldwide permeability break. This abandonment facies is termed the Murdoch Mid-Shale. A regional study of the Mid-Shale shows a thickening of this unit to the southwest, consistent with the depocentre at this time and more distal setting (McLean & Murray 1996). To the northeast of the study area, more proximal to the source of these channels, this unit thins and in places has been completely eroded out by the unit above. The upper unit consists of a mainly channel prone interval and represents a second phase of clastic fluvial deposition in Block 44/21a. Wireline, core and grain size data suggest the depocentre focused on well 44/21a-6. Although less pronounced than in the basal sequence, the upper unit also has an overall upward fining profile indicated by decreasing grain size and more complex channel geometries. The pebbly conglomeratic channel lag which forms the base to this unit can be seen in most of the wells in the study area, however clast size varies significantly. The Murdoch Sandstone paleovalley, from well and core correlation, extends southeast and was eroded into a humid tropical/ subtropical Westphalian B lower delta plain containing numerous swamps, small lakes and thin 'ribbon' stream channels. In contrast, by Westphalian C times the climate had become drier, and sands were deposited as avulsing, low-sinuosity braided channels on a well-drained upper delta plain. These channels were surrounded by shaley overbank deposits (Ritchie et al. 1998). Unconstrained within a valley, these streams did not rework earlier channel deposits as frequently as the Murdoch Sandstone. However, these channels commonly coalesce vertically and laterally to form sand-rich intervals. The Lower Ketch 2 unit seen in the Boulton 'B' structure represents such a sand concentration.
Geophysics Three-dimensional seismic data was shot and acquired in 1992 and has been fully evaluated and incorporated into the field characterization. From the data set it was apparent that the Base Permian Unconformity was a highly problematic pick and was not used in the interpretation. The closest seismic horizons that envelop the prospective Carboniferous reservoirs that can be interpreted are the Top Rotliegendes and Top Murdoch sand. The Top Rotliegendes event was picked as a trough, being the first good event above the angular unconformity. The Top Murdoch sand, although of variable quality and polarity was picked as a strong white trough at the base of the banded, 80-100 m-thick Westphalian B coal measures (see Fig. 5). A five-layer depth conversion of the overburden was performed to obtain the Top Rotliegendes depth map, which was edited to tie all the well control. Since the Base Permian unconformity is difficult to pick on the seismic data, an isopach map derived from well control was added to the Rotliegendes map to produce the Base Permian (Top Carboniferous) depth map. Over the Boulton 'B' structure an Intra Westphalian B coal marker 90m above the Murdoch Sandstone was identified and interpreted. This pick can be correlated with reliability throughout the survey area and represents the top of the banded, 80-100m thick Westphalian B coal measures. From this event the top and base of the Westphalian C reservoir interval (Lower Ketch 2) were derived. The base of the reservoir seen in 44/21a-7 lies 84m above the Intra Westphalian B event. A 'phantom Base Lower Ketch 2'
horizon was created over the survey area and 'tweaked' to conform to local geological dip. The top Reservoir (Westphalian Lower Ketch 2 layer, Fig. 6) lies 168 m above the Intra Westphalian B event in 44/21a-7. Again a phantom horizon was created and the subsequent time map edited to conform to local dip. Figure 6 across Boulton 'B' illustrates the Top Rotliegendes and Top Murdoch time events and the derived intra Carboniferous horizons. To convert the intra Carboniferous horizons to depth a constant velocity of 14 400 ft/s -1 was applied to the time maps. This constant velocity was found to be a good approximation of the trend between isopach and isochron values for the interval from Top Rotliegendes to Top Murdoch Sandstone.
Trap The Boulton Field is an anticlinal structure that has been partially modified and compartmentalized by northeast and northwest faults (Hakes 1991). The crest of the anticline was eroded by the Base Permian Unconformity, removing the Westphalian C reservoir sands (see Figs 5 & 7). Thus, the gas-bearing portions of the two target reservoirs of the Boulton Field are laterally separated, with the Westphalian C reservoir present around the northwest rim of the Boulton 'B' structure as shown in Figure 7 and the Murdoch Sandstone reservoir located in the 'F' Structure. Gas in the 'B' structure is trapped by a combination of up-dip seal against base Permian shales and salts and side-seal against sealing faults and impermeable Westphalian C sediments. Gas in the 'F' Structure is trapped in an anticlinal structure, with top-seal provided by thick Westphalian B shales.
Reservoir The Murdoch Sand over the Boulton Field is mostly fine-grained. A combination of depth-related compaction and some diagenesis (quartz overgrowth, carbonate grain replacement) have led to moderate porosity's (8-10%) and mostly poor permeabilities (0.51.0 mD). A single exception to this is a 12 ft zone of well-sorted coarse sand in 44/21a-6 that has permeabilities of approximately 100mD. Gas was tested from this well at 22.6 MMSCF/D. Other Murdoch Sandstone tests yielded rates of 0-1 MMSCF/D. The Westphalian C reservoir sands have moderate porosity's (10-12%) and good permeabilities (50-400roD). DST rates of 29 and 63 M M S C F / D have been achieved. Sandbody connectivity within the Westphalian C reservoir is a key control on gas production. However, for the net/gross ratios seen in the Lower Ketch 2 unit (32-42%), connectivity is expected to be in excess of 90%.
Gas-water-contacts
The gas-water contact (GWC) in Boulton 'B' is -12820' TVDss. This is based on good quality RFT data from wells 44/21-2 and 44/21a-7 together with log interpretation (see Fig. 7). In Boulton 'F' the gas-water contact is not well defined. The 44/21a-6 well measured RFT pressures in the gas leg but failed to record data in the aquifer. The Regional aquifer pressure gradient obtained from the 'B' structure was applied and suggests a GWC o f - 1 3 2 0 0 ' TVDss for the 44/21a-6 well. However, uncertainty around the GWC exists with ambiguity over the interpretation of the 44/21 a-9 pressure data and test results that indicate gas-bearing sands as deep as - 1 3 400' TVDss.
Source and seal
The Westphalian A/B, is the principal source rock for the gas in the overlying Westphalian reservoirs. This predominantly shaley coalbearing interval also provides lateral seal for the Westphalian A, Murdoch and Westphalian C sands.
BOULTON
FIELD
677
o
TWT
(Ms)
oLO ('q
I
I
I
~
J
I
I
,.6
&
,
i
oE
c,,r)
I
~
o
r
~Z o
[-o~ i
+_..
2 r
r
::
,e
:
2:
:. : ~:!~
,i!~/:
~ ~
i~
%..~
i%
,ii!!~!: :iii!f
;i!:i
L~]i~i:
;:>
%: i~ '~,~i~i~84 i~!~iii,~i!~
,~ii,, ~i!iii~:~ii~~84
,!i;ii~ !!i~ii ;!i84184 ~,i i?
. . . .
:
,~
:) L::,
m 0
{siN) . L M Z
0
o .~
.,..~
..~
678
A. M. CONWAY & C. VALVATNE
z b
o 9
9
o >
V
a
Z~ 9
c~
g g
N
)
V
o M
?: Z~ o ,d
B O U L T O N FIELD
679
o
o
;:;,,...
. ,,..~
I
3
9
9
..=
[--.
2 o
o
~0.~
9
680
A . M . CONWAY & C. VALVATNE
Gas-in-place and reserves C o n n e c t e d gas-in-place for the Boulton 'B' Field derived from geological interpretation ranges from a low case (P90) 116 B C F to a high case (P10) 315 B C F with a best technical estimate of 206 BCF. These gas-in-place estimates have been closely tied to the results of the 44/21a-7 extended well test (EWT) a n d recent material balance modelling developed for the B o u l t o n Field. The base case model comprises two tanks with a 'leak' between them. The m o d e l is supported by the geological interpretation indicating possible fault separation between the 44/21-2 well in the south a n d the 44/21a-7 well to the north. The material balance estimates for gas-in-place are 160 BCF. Estimated Ultimate Recoverable Reserves range from a low case (P90) o f 74 B C F to a high case (P10) of 228 B C F with 130 B C F Proved. C u m u l a t i v e p r o d u c t i o n from D e c e m b e r 1997 to October 1999 is 43.3 BCF. Daily gas p r o d u c t i o n requirements are currently 39 M M S C F D with a swing factor requiring peak p r o d u c t i o n of 57 M M S C F D . The authors wish to thank ConocoPhillips, GdF Britain Ltd, BP and Tullow Exploration Ltd for permission to publish this paper. The authors have also drawn on the knowledge of colleagues from the Southern North Sea Asset Team.
Boulton B Field data summary Trap Type Depth to crest Lowest closing contour Gas column Pay zone Formation Age Gross thickness (average; range) Net/gross ratio (average; range) Porosity (average; range) Net sand cut-off (permeability 0.1 roD) Hydrocarbon saturation (average) Permeability (average; range)
Tilted fault block 12 400-12 570 ft sub-sea Field full to spill 250-420 ft
Westphalian C Lower Ketch unit Carboniferous 580 It; 550-700 ft 0.37; 0.32-0.42 10%; 8.0-12.0% 5.5% porosity 61% 73 mD; 0.1-1000mD
Hydrocarbons Gas gravity Condensate to gas ratio Formation volume factor
0.65 13.65 STB/MMSCF 295 SCF/RCF
Formation water Salinity Resistivity
200 000 ppm 0.16 ohm m
Reservoir conditions Temperature Initial pressure Pressure gradient in reservoir
240~ @ 12 555ft sub-sea 6490psia @ 12555ft sub-sea 0.17 psi/ft
Field size Gross rock volume Initial gas-in-place Recovery factor Recoverable hydrocarbons
619 000 acre/ft 206 BCF 69% 142 BCF
Production Start-up date Development scheme
Production rate (1999/2000)
31 December 1997 single unmanned satellite well platform linked to a manned central offshore gathering facility at the Murdoch DCQ 39 MMSCF/D
References HAKES, W. G. 1991. Development of Intra-Carboniferous structural styles, United Kingdom Southern Gas Basin. Petroleum Geoscience, 1, 419-443. LEEDER, M. R. 1988. Recent developments in Carboniferous geology: a critical review with implications for the British Isles and NW Europe. Proceedings of Geologists Association, 99(2), 73-100. McLEAN, D. & MURRAY, I. 1996. Subsurface correlation of Carboniferous coal seams and inter-seam sediments using palynology: application to exploring for coalbed methane. In: Coalbed Methane and Coal Geology, Geological Society, London, Special Publications, 109, 315-324. MAYNARD, J. R., HOFMANN, W., DUNAY, R. E., BENTHAM, P. N., DEAN, K. P. t~ WATSON, I. 1997. The Carboniferous of Western Europe: the development of a petroleum system. Petroleum Geoscience, 3, 97-115. RITCHIE, J. S, PILLING, D. & HAYES, S. 1998. Reservoir development, sequence stratigraphy and geological modelling of Westphalian fluvial reservoirs of the Caister C Field, UK Southern North Sea. Petroleum Geoscience, 4, 203-211.
The Camelot Fields, Blocks 53/la, 53/2, UK North Sea R. M. K A R A S E K
& J. R. H U N T
Mobil North Sea Ltd, Grampian House, Union Row, Aberdeen A B I O 1SA, U K
Abstract: The group of gas accumulations known as the Camelot Fields straddle Blocks 53/la and 53/2 of the UK Sector of the Southern North Sea on the southern margin of the Sole Pit Trough. The Camelot North Field was discovered in 1967 and development commenced from the Camelot A platform in 1989 (wells A1 to A5). The Camelot Northeast Field came on-stream from the B platform (53/2-7 well) in 1992. The Cador accumulation, in the north of Block 53/la, was subsequently developed through the A6 horizontal well in 1993. The current estimate of gas initially in place (GIIP) for the field is 280 billion cubic feet. Ultimate recovery factors are expected to be as much as 90% and since more than 80% of the GIIP has already been recovered, the Camelot Fields have proven to be prolific producers. This paper focuses on field history after 1988 and, in particular, on the recent exploratory drilling on the southern field margin beneath the South Leman Graben. In this area depth conversion is a major challenge with large velocity contrasts, low relief structures and thin hydrocarbon columns. Recent well results, following mapping of the new 3D seismic data set, indicate that fault reactivation occurred in late Cretaceous to early Tertiary times. Fault movements associated with this event resulted in trap readjustments and/or gas leakage and have exerted an important additional control on hydrocarbon spill points.
The Camelot Field is the general name of a group of separate gas accumulations located in U K Blocks 53/la and 53/2 in the Southern North Sea and operated by Mobil. The accumulations lie some 30 miles NE of Great Yarmouth and about 9 miles SSW of the Leman gas field (Fig. 1). Water depths in the area are highly variable, ranging from 16 ft (on the crest of 'Smiths Knoll' sandbank) to 154 ft. The Camelot Fields are located in the southern Permian Basin, on the southern margin of the Sole Pit Basin. A major structural element, the South Leman Graben, lies just south of the fields. This graben is the southeastern continuation of the Dowsing Fault Zone and bounding faults have up to 3000 ft of throw. In the Camelot area the Leman Sandstone reservoir of the Lower Permian, Rotliegendes Group (Fig. 2), is up to 800 ft thick and generally of excellent quality. The overlying evaporites of the Zechstein group form the top seal, although these thin and pinch-out southwards over the area. The Camelot Fields themselves are primarily dip and fault-closed, tilted fault blocks. Small, currently non-commercial, accumulations in four-way dip closures and horst structures are also present.
The Camelot 'A' Platform is a six slot, four-legged, generally unmanned, steel platform. Production startup was in October 1989 with wells draining the Camelot North, Central, South and Cador accumulations. Camelot B came on-stream in December 1992 through a single well (53/2-7) draining the Camelot Northeast accumulation. Gas and condensate are exported from Camelot via a 12 inch diameter pipeline to Amoco's Leman facilities. Total recoverable reserves from these accumulations are currently estimated to be 251 billion cubic feet (BCF). Recent exploratory drilling around the producing fields has attempted to find additional gas reserves in order to extend the expected field life beyond the year 2000. The Camelot Fields, including appraisal wells drilled up until 1988, were described by Holmes (1991). At that time, the reservoir character and geometry of the fields themselves were relatively well understood, with the main challenge being to optimally locate and complete the planned development wells. The purpose of this paper is to provide an update to the field history following the successful development drilling campaign. In particular, it focuses on results of recent exploration wells beneath the South Leman Graben where depth conversion and trapping mechanisms are more problematic.
History (post-1989)
Fig. 1. Regional location map of the Camelot Fields in the UK Southern North Sea.
The development wells drilled into the Camelot Fields are summarized in Table 1. Wells A1-A6 are all deviated, drilled from the Camelot A platform, whilst well 53/2-7 was recompleted as a producer from the B platform. The Cador horizontal well was completed as the A6 producer in November 1993. The Camelot development wells are typically perforated in the uppermost 30 ft to maximize the standoff from the gas-water contact (GWC). Since 1988, four exploration wells have been drilled around the producing structures. Wells 53/la-9, 53/2-9 and 5 3 / l a - l l (Fig. 3) were drilled, based on 2D seismic mapping, to establish the extent of the Camelot Southeast accumulation discovered by the 53/2-8/8z wells. The 53/la-9 dry hole, drilled in April 1988, found the top Leman Sandstone at 6386 ft TVDss. Well 53/la-11, which was completed in March 1990, encountered the top Leman Sandstone 5 ft deep to the GWC in the 53/2-8/8z wells. Well 53/2-9, drilled in May 1991, was also wet in the L e m a n at 6272 TVDss, but tested low rates of gas from the Hauptdolomite. Following the mapping of 3D seismic data acquired in 1994, the 53/2-10 well was drilled updip and to the northwest of well 53/2-9 (Fig. 3). The top Leman Sandstone was penetrated at 6202 ft TVDss, with 22 ft of gas pay in a good quality reservoir. The GWC was at 6224ft TVDss but there also appears be about 10ft of density neutron separation indicating the effects of a deeper palaeo gas-water contact (Fig. 4).
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 681-689.
681
682
R . M . KARASEK & J. R. HUNT
Table 1. Camelot Fields development wells with original appraisal wells shown in parenthesis'
Well number
Field area
53/la-A1 (10) 53/la-A2 53/la-A3 53/1 a-A4 53/la-A5 53/la-A6 53/2-B1 (7)
Camelot Camelot Camelot Camelot Camelot Cador Camelot
North South South Central Central NE
T.D. date
Leman ft TVDss
Gas pay TV feet
Jul-88 Jun-89 May-89 Jun-89 Jul-89 Nov-93 Mar-88
6331 6227 6231 6247 6244 6206 6417
90 152 171 154 151 n/a 63
In August 1996, well 53/la-13 drilled a separate horst structure, updip and southwest of the 5 3 / l a - l l well (Fig. 3). The Leman Sandstone was encountered at 5970 ft TVDss, with 65 ft of gross gas pay and a G W C at 6035 ft TVDss (Fig. 5), which is about 200 ft higher than in nearby wells. All the recent exploration wells have drilled the objective Rotliegendes section beneath a major Mesozoic graben system, an extension of the South Leman Graben (Figs 1 & 3). Velocity contrasts across the bounding faults of the graben are significant where Lower Cretaceous and Jurassic rocks are downthrown against higher velocity Triassic sediments (Fig. 6). The velocity contrasts lead to imaging problems and depth conversion uncertainties at the top of the reservoir, typically in the order of +100ft (for example in well 53/la-13 the Top Leman Sandstone was encountered 70 ft higher than was expected). Given hydrocarbon columns averaging about 100 ft in thickness and the low relief on the structures, depth conversion is a major challenge in this area.
Seismic interpretation
Hewett & sa/2-9
"~ Camelot, Leman, Deborah & Dotty "~ Murdoch & Caister
The Camelot 3D seismic survey shot in 1994 was processed to a post stack time migration in early 1995. The survey area covers about 175 square miles and includes a large part of Blocks 52/la and 2 (Fig. 7). The survey was shot with a line spacing of 33 ft in a N - N W direction, perpendicular to the orientation of shallow water tidal shoals. The data have good resolution and frequency content down to the Rotliegendes event (interpreted as a zero crossing from negative to positive) and well to seismic ties are generally good. Imaging of the reservoir is very good except where it is overlain by bounding faults and fill of the Mesozoic graben (Figs 8 & 9). Fault imaging is also generally good and fault mapping was enhanced through the use of Landmark's coherency volume.
Depth conversion
Fig. 2. Generalized stratigraphy showing overburden geology and gasbearing reservoirs
A three layer depth conversion (Seabed to Top Triassic, Triassic to Top Zechstein and Zechstein to Top Rotliegendes) was applied to account for the major lateral velocity variations across the Mesozoic graben. A geostatistical approach (using Landmark's Sigmaview geostatistical software) was used to determine interval velocities directly. In this technique a correlation is sought between interval velocity and interval time or interval midpoint time, at the well locations (Fig. 10). Co-located co-kriging is then used to extrapolate beyond the areas of well control, using seismic interval times for each of the three layers to produce interval velocity grids. This technique is preferred (over kriging for example) since it allows the use of velocities derived from the seismic data to constrain the interpolation between well values. A similar but less rigorous technique, kriging with external drift, has been described by Wolf et al. (1994).
CAMELOT FIELDS
683
Fig. 3. Top Leman depth structure map (from new 3D seismic data) showing recent exploration wells drilled around the Camelot Southeast accumulation.
Excellent time/velocity correlations were established in the upper two intervals (Figs 10a & b). However, determining the interval velocity relationship within the Zechstein group is more problematic. In the Southern North Sea the interval velocity of the Zechstein varies as a function of its carbonate content. Where the Zechstein is thin due to salt withdrawal, velocities are commonly high because of the subsequent concentration of remnant, high velocity carbonates. Where mobile salts have produced a thickened Zechstein the interval velocity is much slower. An evaporite/ dolomite ratio method was applied to account for this variation in evaporite thickness and the mixture of slow and fast rocks
Fig. 4. Well 53/2-10 Leman sandstone interval showing possible palaeo GWC indicated by the density-neutron crossover (hachured).
(Fig. 10c). In this technique, isochrons were calculated for the Zechstein above and below the Plattendolomite and the ratio of the lower to upper Zechstein isochron was calculated. A strong correlation was found between this ratio and gross Zechstein interval velocity. Based on the strength of this correlation, an interval velocity map was created for the Zechstein using a grid of the ratio of seismically derived lower and upper Zechstein isochrons as the secondary guiding parameter. Once the time and velocity relationships were established for the three intervals, correlograms were produced to map the spatial changes of the interval velocities, derived from the wells. A correlation ellipse for each interval was matched to the N W - S E structural trend in the area. Interval velocities were determined by collocated co-kriging using the appropriate time grid (identified by velocity/ time cross plots). Minimal error correction surfaces were then applied to the resultant depth maps to match the well control. To
Fig. 5. Well 53/1a-13 Leman Sandstone interval showing GWC at -6035 ft TVDss, which is about 200 ft higher than in other wells in the Camelot Southeast area.
684
R . M . KARASEK & J. R. HUNT
Fig. 6. North to south structural cross-section through Camelot South and Camelot Southeast. The section shows Triassic section interpreted downthrown to Lower Cretaceous and Upper Jurassic lower velocity sediments (see Fig. 7 for line of section).
assess the uncertainty in the velocity estimation away from the wells, sequential Gaussian (or conditional) simulation was used to produce 50 equally likely velocity maps for each layer. This resulted in 50 depth maps at top reservoir level allowing the uncertainty in depth and G I l P estimation to be assessed. The average of these 50 depth realizations was taken as the best technical depth map for the Camelot Fields.
Trap In the UK southern gas basin the Leman Sandstone reservoirs are commonly filled to their mapped spill point through a combination of dip closure and or fault seal, e.g. Amethyst, Barque, Indefatigable, Rough, Thames, V fields and West Sole (Abbotts 1991). The Zechstein group, in particular the thickly developed evaporite section, forms an excellent regional top seal, and generally provides an
Fig. 7. Outline of 1994 3D seismic survey showing lines of section.
effective lateral seal where the Leman Sandstone is in juxtaposition (e.g. Farmer and Hillier 1991). The role of fault reactivation on gas leakage is less well documented, although migration up faults into the Bunter is known in the Hewett Field (Cooke-Yarborough 1991) and gas remigration during the Tertiary inversion has been suggested by some authors (e.g. Cornford 1984). Prior to the recent drilling in the Camelot area the working model was also that the accumulations were filled to structural spill points and GWCs were primarily controlled by dip closure in the strike direction. However, following the remapping of the 3D seismic data over the Camelot Fields and an analysis of the recent exploration wells, it has become evident that fault reactivation plays an important role in defining both the presence and preserved volume of gas in some of the accumulations (e.g. Knipe 1996). Several lines of evidence exist to support this concept, assuming an adequate supply of gas from the generating kitchen. This seems likely since large fields such as Indefatigable (Pearson et al. 1991) and Leman (Hillier and Williams 1991) are filled near to structural spill point. In the Camelot area, the GWCs are well defined from well log and pressure data in each separate accumulation. From north to south across the area there is a trend of progressively shallower gaswater contacts from the Leman Field in the north at 6700 ft TVDss, to the Camelot Southeast accumulation in the south at 6221ft TVSS (see Fig. 7). This suggests an overall fill and spill mechanism from north to south across the area. However, well 53/la-13 is anomalous to this trend with a G W C about 200 ft higher than in the surrounding wells. Anomalous contacts appear to be confined to anticlinal structures with the downdip limit apparently controlled by the intersection of the closure with boundary (leaking) faults (Fig. 3 wells 53/la-13 and 53/la-3). Also, the overlying Zechstein dolomites are gas bearing in this area (e.g. 53/2-9) suggesting that either the overlying Kupferschiefer shales do not form a perfect seal or that gas leakage from the Leman reservoir occurs where porous or fractured dolomites are juxtaposed in the hanging wall (Fig. 1 la). Spill control by faulting may be most significant in areas where the Werra Anhydrite is thin or absent, as in the Camelot area (Fig. 12). This allows faults of relatively small throw to juxtapose the Leman Sandstone against downthrown permeable Hauptdolomite or Plattendolomite.
CAMELOT FIELDS
685
tO u r
o
Fig. 8. NW-SE dipline through Camelot 'A' and the 53/la-13 well horst block and the South Leman Graben.
-8 C
Fig. 9. NE-SW strike line through Camelot 'A' and 'B' fields.
686
R . M . KARASEK & J. R. HUNT
== .o 8000 >, 7500
I ..... .~........... ~ ............. i .............. i .............. ': ....... .... , ~ , , , ~ = . ; ~ + ~0~4~,.o Way~,.,o~i ........ : ~ ~ ~ ~ ....
Corelation Coefficient = 0.97
I . . . . . 9'ri . . . . . . . . . . . . . . .....
i ..............
.........
r .............
i
'-1. . . . . . . . . . . . . .
i .............
i ........
l,.___o_._~f~____ i .........
i
:
o
:
...........
i
~. . . . . . . . .
" .........
---i ---o- .........
o
7000 E
..... , .........
6500
o
8000
_~:
I22~~:::::::2:2:22 ..... i .......o . ............. i::::22:::::::: .............. i::::::::2::2:: .............. i::::2:2:2 .
p
ssoo
,
.....
'
-
-
r ..............
'
~
~ .............
0.25
........
i ..............
0.5
~ ..............
0.75
1.0
.
.
.
.
.
.
.
.
r .........
i- .........
1,25
Sea Level to Triassic Two W a y Time (secs)
~
I 12000
....... ~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
I
9 o
] . . . . . . . . . ~_
i
!
[
i
l
l
:
:
,o
io
i
i
:
i
'
:
:
:
o~,
i
!
!
ol
(a)
I . . . . . o _ .....
:
!
~ 11000
:o
c
!
i
[
I~1 10000
V(int) = 8715 + 2676 (Interval Mid Point Time) Corelation Coefficient = 0.90
2
0.7
i
i
J
J
0.8
0.9
1.0
1.1
1.2
1.3
Triassic to Zechstein Midpoint Time (see.s)
2ooo0
(b)
.... V(int) = 19276 - 74522 (Upper Z e c h s t e i n I s o c h r o n ) ~ ....... Corelation
Coefficient
...........
18000
: ................
i
o
= O. 88 : ...............
:
...........
:
t
! ...............
i ........
$ ...............
,,ooo
..................
o ...... :
1~o
................
~ ................
i ...............
i .......
15000
................
"I ................
I" ...............
-{ ................
o .......
........ § ....
f ........
f l
! I
i I
i ;
o.o,
0.02
o.os
0.04
Upper Zechstein Interval Time ( s e c s )
Fig. 11. Model showing possible fault control mechanisms on preserved gas columns. (n) Gas is preserved in anticlinal closures only where leakage does not occur into juxtaposed dolomites or up the fault plane (Modified from Knipe 1996). (b) Late stage fault reactivation has resulted in a reduction in reservoir dip, which, within a closed system, has caused the GWC to rise to preserve the gas volume.
l ........
...........
(C)
Fig. 10. Velocity time relationships utilized for depth conversion. (a) See level to top Triassic interval. (b) Top Triassic to Top Zechstein interval. (e) Top Zechstein to top Rotliegendes interval (carbonate/evaporite ratio method).
Structural interpretation of 3D seismic data in the C a m e l o t area indicates that dry holes such as 53/2-4 and 53/2-5, (Fig. 3) are drilled on valid structures and are on the migration pathway. However, the b o u n d i n g fault to these closures appears to penetrate up-section into the Mesozoic overburden. This suggests that gas leakage m a y have occurred up the fault zone into the overlying Bunter Sandstone during gas charge, which p r o b a b l y occurred from the late Jurassic onwards. There is evidence for a b o u t 7000 ft of inversion in the C a m e l o t area. This is shown by the missing section in wells (eroded during uplift), the burial history as indicated by apatite fission track data and the seismic geometries of larger faults and overburden. The inversion is interpreted to be particularly i m p o r t a n t in the southeastern part of the C a m e l o t area where well 53/2-10 has a palaeo G W C . If no gas leakage occurred, then late fault movements (during inversion) m a y have caused a reduction in dip of the
Fig. 12. Werra Anhydrite isochore in the Camelot area.
CAMELOT FIELDS OR
ILD
2
FDC
687
Table 2. Gas initially in place
3 DIPMETER
lOOj
,
,~
20
2000 45
. 9......,
C:.i . . :.; .:. .. .. . . . :
15
CNL
,
~
-.
-~ . . . . .
"/--
~_~ "~
D
..........
t
%
N s CARBONIFEROUS
I
I
Weissliegendes ~
43 32 115 126 -
25 22 70 145 18
Totals
316
280
G a s i n i t i a l l y in p l a c e
Production
l-
~
Northeast North Central South Cador
r"
f
foresets Interdune/ sandsheet
1999 Material Balance GIIP (BCF)
~,
%
1
1988 Annex B GIIP (BCF)
Table 2 compares current estimates of GIIP with pre-production 'Annex-B' values. Given the gentle dip of the fault blocks, small changes to the mapped structure away from well control have a marked affect on the calculated hydrocarbon volumes. Only minor modifications to the pre-production maps are therefore required to account for the differences seen between the initial and current estimates of GIIP.
z La.J -J
Reservoir
toesets Fluvial/wadi
ofcored interval
lOOfeet
Slumped/ deformedstrata
Fig. 13. Leman Sandstone facies 'type section' in the Camelot area.
reservoir and an upward movement of the GWC to preserve the gas volume (Fig. 1lb).
All the accumulations are underlain by water. Given the high permeability of the reservoirs and the absence of significant tight sections in the gas leg, wells were only perforated in the top 20-40 ft of the pay. This achieved a balance between well productivity and standoff from the initial gas-water contact. All wells were completed with permanent downhole gauges. Figure 15 shows the pressure history of Central well A04, which is typical of the Camelot wells. Until 1997, gas was sold under a depletion contract with little if any summer production from the fields. During these periods of low production the reservoir pressures all showed a steady buildup even when all the wells were shut-in for several months. Pressures would normally be expected to stabilize within a few weeks in these small area, high permeability fields if the reservoirs were simple 'tanks' of gas. Since 1997, gas from Camelot has been sold through Mobil's gas marketing arm. To optimize the gas portfolio the Camelot Fields have been produced throughout the year without the former long summer shut-downs. Figure 16 shows the effect of this increase in rate on the relationship between the Pressure to Z factor (P/Z) and cumulative gas production for the Camelot Central Field. The late downward trend exhibited is typical of all the fields and could not occur if the wells were simply draining single 'tanks' of gas. A combination of leaky fault compartments and aquifer influx is thought to explain the observed behaviour in the Camelot Fields of ratedependent P/Z plots.
Reservoir Table 3. Cumulative production to summer 1998 and expected ultimate The Leman Sandstone is very thick in the Camelot area with an average gross thickness of about 800 ft. The recent well information has confirmed that the reservoir in the area is of excellent quality with an average porosity of 19% and permeability of 150roD. The principal diagenetic blocky cements (K-feldspars, ferroan dolomites, anhydrite and quartz) have occluded some porosity but have not seriously impaired permeability. Only minor modifications have been made to the reservoir description of Holmes (1991) and the current zonation scheme is summarized in Figures 13 & 14. The high permeability and high net/gross (typically 1.0 in the hydrocarbon-bearing interval) of the Leman Sandstone may also be significant since there is unlikely to be a lateral fault seal where sand is juxtaposed against sand other than through cataclasis (i.e. poor fault gauge potential).
recovery .from the Camelot reservoirs
Reservoir
Production to 30/06/1998 (BCF)
Percentage of GIIP recovered at 30/06/1998
Ultimate recovery (BCF)
Ultimate percentage of GIIP recovered
Northeast North Central South Cador
17 16 62 117 14
68 73 89 81 78
17 18 65 135 16
68 82 93 93 89
Totals
226
81
251
90
688
R . M . KARASEK & J. R. HUNT
Fig. 14. Leman stratigraphic cross-section across Camelot South showing lateral distribution of aeolian and fluvial dominated facies.
T h e r m a l decay time (TDT) logs have shown a steady rise in the gas-water contacts with time, confirming water influx is influencing reservoir performance. Several wells have recently started to produce formation water, but to date only the Camelot N o r t h e a s t well 53/2-7 (B1) has watered out completely and was a b a n d o n e d in July 1998. The expected ultimate recovery from the Camelot Fields is given in Table 3. A b a n d o n m e n t reservoir pressures of 400 psi have been assumed c o m p a r e d with the initial pressure of 2800psi. with a b a n d o n m e n t expected to occur in 2002. Earlier than predicted water breakt h r o u g h in the remaining water-free wells m a y lower these expected
3000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
ultimate recovery factors somewhat. At the present time no well interventions are planned to increase the life of the field. However, as more than 80% of the G I I P has already been recovered, the C a m e l o t Fields have proven to be prolific producers. The authors wish to thank Mobil North Sea Ltd for permission to publish this paper. The authors have drawn on the knowledge of colleagues from the Southern North Sea Asset Team. In particular we would like to acknowledge geoscientists Geoff Butcher, Emma Jamnezhad, Will Parsons and Jonathan Shearman for their technical contributions and the drafting office for preparing the figures.
40013
...........................................................................
Camelot
Central
2500 7 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
iiiiiiiiiiiii
200O1
,o.:!!!!
~. 2000
1500 1
1000
500,
,
,
,
,
,
,
,
,
,
,
,
,
,
,
,
,
,
,
,
1o Date
Fig. 15. Camelot Central Field - well A04 bottom hole pressure data.
~o
3'o
4'0
5'0 GIIP (BCF)
Fig. 16. Camelot Central Field P/Z plot.
~o
io
8'o
~o
,;o
CAMELOT FIELDS
Camelot Central/South Fields data summary Trap
Type Depth to crest GWC Maximum gas column
Fault terraces, tilted fault blocks 6050 ft TVDss 6232 ft TVDss (South); 6244 ft TVDss (Central) 200 ft
Pay zone
Formation Age Gross thickness Net/gross ratio (average/range) Cut-off for net/gross Porosity (average/range) Hydrocarbon saturation Permeability (average/range) Absolute open flow potential
Leman Sandstone Lower Permian (Rotliegendes Gp) 700-800 ft 1.0/0.98-1.0 8% 19%/15-22% Max 80% 150 mD/5-4500 mD 200 MMSCFD
Hydrocarbons
Gas gravity Condensate yield Gas expansion factor
0.615 relative to air 1.2 BBL/MMSCF 192 SCF/RCF
Formation water
Salinity Resistivity
180 000 ppm 0.025 ohm m at 150~
Reservoir conditions
Temperature Pressure Pressure gradient in reservoir Gas Water
140~ 2800 psi
251 BCF 90% Moderate Water drive
References ABBOTTS, I. L. 1991. United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 385-541. COOKE-YARBOROUGH, P. 1991. The Hewett Field, Blocks 48/28-29-30, 52/ 4a-5a, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 433-442. CORNFORD, C. 1984. Source rocks and hydrocarbons of the North Sea. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 171-204. FARMER, R. T. & HILLIER, A. P. 1991. The Clipper Field, Blocks 48/19a, 48/19c UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 417-423. HILLIER, A. P. & WILLIAMS, B. P. J. 1991. The Leman Field Blocks 49/26, 49/27, 49/28, 53/1,53/2 UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 451-458. HOLMES, A. J. 1991. The Camelot Fields, Blocks 53/la, 53/2, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 401-408. KNIPE, R. 1996. Structural evolution and fault seal analysis of the Camelot Field area (Blocks 53/la and 53/2) Southern North Sea. Rock Deformation Research - Leeds University Report.
0.07 psi/ft 0.49 psi/ft
Field size
Area Gross rock volume Hydrocarbon pore volume
Recoverable gas Recovery factor Drive mechanism
689
2200 acres 219 000 ac-ft. 1450 x 106 ft 3
PEARSON, J. F. S., YOUNGS, R. A. & SMITH,A. 1991. The Indefatigable Field, Blocks 49/18,49/19,49/23,49/24, U K North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume.
Geological Society, London, Memoir, 14, 443-450. WOLFE, O. J., WITHERS, K. D. & BURNAMAN, M. D. 1994. Integration of well and seismic data using Geostatistics. In: YARUS, J. & CHAMBERS,R. (eds) Stochastic Modeling and Geostatistics. American Association of Petroleum Geologists, Computer Applications in Geology, 3, 177-199.
The Clipper Field, Blocks 48]19a, 48[19c, UK North Sea M.
J. S A R G I N S O N
Shell Expro, PO Box 4 Lothing Depot, North Quay, Lowestoft, Suffolk NR32 2TH, UK Present address." Brunei Shell Petroleum Co. Sdn. Bhd., Seria KB3534, Negara Brunei, Darussalam Abstract: The Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the
Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988.24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF. L o c a t e d 40 miles off the N o r f o l k coast in the Sole Pit area o f the s o u t h e r n N o r t h Sea, the C l i p p e r G a s Field lies in water d e p t h s o f 7 0 - 9 0 ft. T h e field is a b r o a d , faulted anticline covering s o m e 12 000 acres, m a i n l y within Block 48/19a (see Fig. 1).
T h e reservoir is the L e m a n S a n d s t o n e F o r m a t i o n ( R o t l i e g e n d G r o u p ) . This consists m a i n l y o f q u a r t z o s e aeolian sandstones. In the crest o f the field the s a n d s t o n e is fully gas-bearing with a m a x i m u m gas c o l u m n o f 1000ft; m o s t gas occurs between 7500 a n d 8 5 0 0 f t
Fig. 1. Top Rotliegend structure map, based on 3D seismic data.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 691-698.
691
692
M. J. SARGINSON
TVDss. The gas is primarily methane with a minor inert gas content and a low condensate yield. Recoverable reserves are currently estimated at 753 BCF. The Clipper Field has been developed in conjunction with the adjacent Barque (Sarginson 2003) and Galleon Fields. First gas production was in October 1990. In common with several Shell/ Esso gas accumulations in the Sole Pit area the field name commemorates vessels from maritime history. The use in this paper of the term Rotliegend (rather than Rotliegendes as used by Rhys 1975) follows that adopted by Glennie (1984). From historic precedent the term Rotliegend is used in this paper for the Leman Sandstone Formation.
History Licence P008 covering blocks 48/19a and 48/20a, was awarded in Round 1. Block 48/19c was awarded as Licence P465 in May 1983, with a one-third relinquishment being made in May 1989. The licences are held jointly by Shell UK Exploration and Production
Fig. 2. Clipper Field stratigraphic sequence.
and Esso Exploration and Production U K Ltd with Shell as operator in each case. The Clipper Field discovery well, 48/19-1, was drilled in 1969 on a seismically defined high as part of the ongoing exploration of the southern North Sea Basin. The well established the presence of a thick gas column; however, limited testing showed the Rotliegend reservoir matrix to be fairly tight, flowing about 0.5 M M S C F D after stimulation by a simple hydraulic fracture. The well was abandoned as a non-commercial gas discovery and further appraisal was held in abeyance as fields of this type did not then appear capable of commercial gas production (Glennie & Boegner 1981). By 1983 industry advances suggested development might be feasible and an evaluation programme commenced that year. The first appraisal well 48/19a-2A, drilled in 1982 and located nearly two miles north of the discovery well, confirmed a 759 ft thick gas-bearing Rotliegend section with significant natural fractures. Extensive testing incorporating acid stimulation yielded a maximum flow rate in excess of 50 M M S C F D (Moore 1989). Two further appraisal wells were drilled in 1984, the 48/1%-4 well confirming poor reservoir quality and flowing little more than
CLIPPER FIELD 7 MMSCFD after acid and hydraulic fracture stimulation. A downflank well, 48/19c-5 tested less than 1 MMSCFD from a restricted column lacking fractures. The sixth and final appraisal well 48/19a-6, was drilled in 1985, testing up to 24 MMSCFD comingled flow from two zones, both having been hydraulic fracture stimulated. In view of the wide range in appraisal well test results and the geological heterogeneity, the initial phase of development targeted the most promising areas of the structure in the north and central part of the field. This first phase of development has now been completed; further infill drilling is still planned in order to maximize ultimate recovery. Development drilling began in September 1988 with six wells drilled through a sub-sea template. A platform was installed in late 1989 over the template and the template wells were tied back. The initial development wells were deviated tangential wells, which were completed with cemented/perforated liners. Hydraulic fracture stimulation was used in wells which did not encounter productive features; open natural fractures or permeable aeolian sandstones. From 1991 onwards horizontal drilling, which increases the chances of intersecting these productive features, has been successfully employed to develop the field. Horizontal wells have been completed using pre-drilled liners. Recent infill drilling (1999), targeting areas left poorly drained by the first phase of development wells, has utilized underbalanced drilling technology. This eliminates formation impairment through drilling fluid invasion, and also enables drilling in depleted areas where conventional drilling would not be feasible because of lost circulation.
693
Field stratigraphy The stratigraphic section over Clipper Field typifies the section found over much of the inverted Sole Pit Basin. A thick PermoTriassic section unconformably overlies eroded Carboniferous sediments and is itself overlain by thin erosional remnants of Jurassic, Cretaceous and Tertiary sediments. The entire sequence represents infilling of a basin whose subsidence began with late Hercynian extension, was interrupted by Mid- and Late Cimmerian tectonism, and terminated with inversion in Late Cretaceous and Mid-Tertiary times. A typical sequence encountered in the central part of the field is given in Figure 2 together with an indication of depth and thickness of the main units recognized as markers in seismic interpretation and drilling. The Carboniferous sediments were deeply eroded following Hercynian uplift and the top most beds in the Sole Pit area are commonly Westphalian Coal Measures (Glennie & Boegner 1981). The overlying Rotliegend is primarily an aeolian quartz sandstone which accumulated during slow basin subsidence during the later part of the early Permian. Marine transgression followed, leading to deposition of the cyclic Zechstein evaporites and carbonates. Basin infill continued in the early Triassic with continental sedimentation of the Bacton Group, followed by a return to marine and marginal marine conditions with cyclic deposition of evaporites of the Haisborough Group, the main halite markers being the Rot, Muschelkalk and Keuper. Little remains of the succeeding marine Jurassic and Lower Cretaceous sequence as a result of Mid- and
Fig. 3. Seismic section across Clipper Field (1992 3D seismic). Line of section shown on Figure 1.
694
M. J. SARGINSON
Late Cimmerian uplift and erosion. However, various estimates have been made as to the thickness of lost section (e.g. Glennie & Boegner 1981) and it is likely that more than 5000 ft were removed in the Sole Pit area. A partial section of Late Cretaceous Chalk is preserved together with an equally thin section of Late Cenozoic clastics (North Sea Group). Further background to the stratigraphy and structural history of the southern North Sea is given by Ziegler (1975) and some details for the Sole Pit area are outlined by Glennie & Boegner (1981) and van Hoorn (1987).
Geophysics Seismic interpretation in the Sole Pit area was initially hampered by the unexpectedly high velocities encountered in the Triassic section. Depth conversion improved when more extensive coverage of well velocity data became available and the effects of burial and compaction were realized. The Clipper Field discovery well was located by early reconnaissance seismic surveys on a structurally high trend between BP's 1965 West Sole Field discovery (Butler 1975; Walmesley 1977) and Shell/Esso's 1966 Leman Field discovery (van Veen 1975). The well was appropriately located off the crest but found formation tops below the Lias to be deeper than expected due to high interval velocities. Field appraisal was based on 2D seismic surveys carried out between 1978 and 1980 using a diamond grid pattern with lines at 500 m spacing. Depth predictions were generally reliable with one notable exception where a flank well came in low due to a higher interval velocity than anticipated. The southern extent of the field was delineated by further 2D lines shot in 1983. In 1986, a 3D seismic survey was acquired over the initial development area of the field, this was used to plan initial development drilling. Further 3D seismic, which covered both the Clipper and Galleon Fields, was acquired in 1992. The current reserves assessment is also based on this survey. Imaging of the reservoir was affected by ray bending in the overburden, in particular at the heavily faulted Jurassic/Triassic boundary where there is a large velocity contrast. This resulted in both poor focussing and lateral positional uncertainty of top reservoir in some areas of the field. The whole Sole Pit area was re-shot in 1999; the new survey was designed to achieve a high fold of stack in the overburden, with the objective of carrying out a full pre-stack depth migration to accurately image the reservoir. Processing is ongoing at the time of writing. Seismic interpretation is based on five horizons with well ties provided by synthetic seismograms using sonic, density and well velocity logs. The usual seismic character over the field is shown in Figure 3; the location of this section is shown on Figure 1. The five main mapping horizons are: 9 9 9 9 9
Top Triassic, often affected by listric faults in the overburden; Top Bunter Sandstone, generally continuous; Top Zechstein, generally continuous; Top Haupt Anhydrite, strong seismic expression; Top Rotliegend, moderate amplitude, faulted, sometimes obscured by base Platten Dolomite reflections.
Within the Rotliegend, seismic character shows little detail. The base Rotliegend is sometimes discernible and a Top Carboniferous map
can be derived though reliability suffers. At reservoir level, faults are generally steeply dipping normal faults reflecting the extensional tectonic environment. Minor faults (throw < 100 ft) have been mapped using seismic coherency and dip displays. 3D illumination of the top Rotliegend seismic surface reveals SSW-NNE and W S W - E N E trending lineaments, which may represent an early formed joint system that was subsequently re-activated.
Trap The Clipper field is one of several NW-trending structural highs in the Sole Pit area. Essentially a broad faulted anticline, the trap has both dip and fault closure. Internal faults may have throws of several hundred feet. The field extent is 9 miles by 3 miles and there is sufficient vertical relief for the Carboniferous section to enter the gas leg, although no net sandstones are recognized below the Rotliegend reservoir. Based on appraisal and development well logs the field wide free water level is estimated to be at 8530 ft TVDSS. The Zechstein Group, comprising mainly halites, anhydrites and tight carbonates, provides excellent top seal for the reservoir as well as lateral seal for gas where the Rotliegend is in juxtaposition (Fig. 4).
Structural history The structural history of the area may be divided into three main phases:
(1)
(2)
(3)
Permian-Early Jurassic subsidence The Rotliegend reservoir sandstones were deposited during a period of thermal subsidence, which commenced in the Middle Permian (Oudemayer & De Jager 1993; Coward 1995). The Solepit Trough was an important depocentre during this period (Cameron et al. 1992). Mid Jurassic-Early Cretaceous faulting A period of uplift was followed by active extension during the Late Jurassic-Early Cretaceous (Late Cimmerian rifting phase - van Hoorn 1987). NW-SE trending faults formed in the Sole Pit area, possibly as a result of dextral transtensional reactivation of a basement trend in this orientation. Late Cretaceous and Tertiary Inversion Onlap of sediments onto the Sole Pit high indicates inversion during the Late Cretaceous (van Hoorn 1987). The NW-SE trending faults were reactivated in a transpressional manner. This phase of inversion is widely regarded as being related to the early Alpine N-S compression (Oudemayer & De Jager 1993). A further phase of inversion, accompanying the Alpine orogeny, occurred during the Oligocene. Fault reactivation in the Sole Pit area is noted by Glennie & Boegner (1981) and also by van Hoorn (1987) who observed that earlier movements may be reversed or modified. Interval velocities and vitrinite reflectance of Carboniferous coals indicate c. 1500 m of uplift and erosion (Alberts & Underhill 1991).
Fig. 4. Structural section across Clipper Field, showing reservoir zonation and FWL (line of section shown on Figure 1).
CLIPPER FIELD Owing to the presence of Zechstein and intra-Triassic salts, which acted as detachment planes, deformation of the overburden was decoupled from that of the Rotliegend and older strata. The top Zechstein and Bunter Sandstone form broad anticlines, with little or no faulting. Overlying this, the upper Triassic Haisborough Group is cut by en-echelon north-south striking normal faults. The formation of these has been attributed to transtensional shear related to dextral strike-slip movements on NW-SE trending basement faults (van Hoorn 1987), and gravitational collapse of the overburden along intra-Triassic salts decollement planes (Walker & Cooper 1987).
Reservoir The Rotliegend reservoir is considered to be Saxonian or late Lower Permian in age, although precise dating has not been obtained from the field. Consisting primarily of aeolian sandstone described by Nagtegaal (1979) as moderately mature quartz arenites, the sandstones are commonly fine-grained with rather low porosity, and very low permeability. Reservoir thickness varies between about 650 and 775 ft with a northward thickening trend. Occasional thin (less than 5 ft) shale beds, found mainly in the lower third of the reservoir are generally discontinuous and detract little from gross reservoir volume, seldom comprising more than 3 % of the section in Clipper Field wells. Detailed correlation within the Rotliegend is imprecise due to the limited extent of individual facies units; however, field-wide correlation of groups of facies allows reliable subdivision of the Rotliegend into three main zones (see Fig. 5). The uppermost 'A' zone consists mainly of dune, interdune and waterlain sandstones, deposited in an erg margin environment. Four subdivisions are recognized in the Clipper field. The structureless Weissliegend (AW) sandstone (Glennie 1984), reworked/homogenized following the Zechstein transgression lies at the top of the sequence. The A1 unit is a heterolithic unit variously composed of waterlain, sandsheet, dune apron/interdune and dune slipface sandstones. The A2 unit consists largely of dune slipface deposits, with subordinate amounts of dune apron, sandsheet, sabkha, and waterlain/water affected sandstones. Slipface units are up to 30' thick. There are localized occurrences of high permeability (up to 20 mD air permeability) streaks within slipface deposits. The A3 unit, at the base of the 'A' zone largely comprises waterlain deposits. It represents a relatively humid period during Rotliegend deposition, when the water table would have been near to the surface. The middle or 'B' zone consists of cross-bedded aeolian dune sandstones of fair to good quality. Individual dune sets are up to 60 ft thick. This unit represents an arid period of maximum erg expansion. The lowest or 'C' zone comprises interbedded dune slipface, dune apron, interdune/sandsheet, and waterlain deposits. The upper boundary of this unit is marked by a waterlain layer. Reservoir quality in the 'C' zone is poor; the sandstones are fine grained with a high authigenic illite content. The facies subdivisions referred to above have been described by Seeman (1982) and Glennie (1984) amongst others. The best reservoir quality is found in the 'B' zone with porosities averaging 11-15%; air permeabilities vary from 0.5-100 roD. The 'A' zone has slightly lower porosity, averaging 10-12% but permeability is considerably lower, 0.1-1 mD with rare thin intervals up to 10 mD. The 'C' zone porosities average 7-9.5% with permeability less than 0.5 mD. Such widely varying porosity permeability relationships for facies groups have been described by Glennie et al. (1978) and Seeman (1982) and are ascribed to depositional mode grainsize, sorting and diagenesis. Reservoir quality is poor as a result of compaction and diagenesis accompanying deep burial in the Sole Pit Trough prior to Late Cretaceous inversion. Authigenic cements, in particular hairy illite, are responsible for the greatest loss of permeability and these effects have been described in general by Marie (1975), and more specifically in the Sole Pit area, by Glennie et al. (1978). Further details on clay mineral diagenesis in the southern North Sea are
695
given by Seeman (1982) and Rossel (1982); many of the features reported have been observed in core from Clipper Field. After permeability is corrected for overburden stress, it becomes apparent that matrix permeability in many parts of the reservoir is so low as to preclude gas flow at economic rates and that only the presence of zones of natural fractures allow high production rates to be achieved. In some areas the cleanest aeolian sandstones contain laminae with permeabilities of up to 100 mD, which also contribute to wellbore inflow. Cores, image logs, and mud losses during drilling indicate that open natural fractures are not present across the entire Clipper structure. Approximately half of the development wells to date have encountered productive natural fractures. Dilational fractures are associated with areas of positive curvature, and with minor intrareservoir faults. The fractures are steeply dipping (70-90 ~ with a predominant N-S orientation. Attempts at seismic based fracture prediction have met with limited success; the field is structurally complex, with relatively poor reservoir imaging. Well test and production data are required to quantify fracture properties.
Source Westphalian Coal Measures directly below the Rotliegend are acknowledged as the source for the gas in the Sole Pit area (Lutz et al. 1975; Glennie 1984). The Coal Measures probably reached maturity during Jurassic time, and continued to generate gas from coals and from organic-rich shales during the Cretaceous. Vitrinite reflectance values greater than 2% are noted in the Sole Pit area, and in spite of truncation and erosion of parts of the Westphalian sequence adequate source volume remains for the known trapped reserves (Cornford 1984). The migration path is considered to be short and direct, as suggested by the low nitrogen content of the gas (see Table 1). Lutz et al. (1975) recognized high nitrogen content as indicative of a long and tortuous path. Mid-Tertiary structural readjustment may have resulted in some re-migration of gas as noted by Cornford (1984).
Hydrocarbons A summary of the discovery and appraisal well test results was given in the history of the field and analyses of tests on the 48/19a-2A and 48/19a-6 appraisal wells are given by Moore (1989). Most appraisal well tests in Clipper Field were carried out in the 'A' zone with the highest flow rates being achieved after acid stimulation of partly cemented fractures in well 48/19a-2A. In less favourable situations, however, even after acid and hydraulic fracture stimulation, 'A' zone intervals have tested less than 1 MMSCFD demonstrating that zone 'A' productivity can be expected to vary greatly in accordance with observed matrix heterogeneity and the presence or absence of natural fractures. Table 1. Separator gas composition (well 48/19a-6) Component
%
Methane Ethane Propane Iso-butane N-butane Iso-pentane N-pentane Hexane Heptane+ Nitrogen Carbon dioxide Helium Hydrogen sulphide
95.76 2.24 0.47 0.07 0.13 0.04 0.03 0.03 0.04 0.71 0.47 0.01 0.00
696
M. J. S A R G I N S O N
o
gg
g
=o
=
i~ i
'
',_L_lJk__]~
~
~I~.
~ I~o~
i~t~ I~ ~
l._..a_~_a._a__L_~.
9?
9 r
,.Q
o >
,.-e, ,,
9 I : i
' ~14~
~7 ,.
::~
i ;t,. -. C~'. " :~.~."
go
~ Q--
-~
~
.)
2 o
ca
ll]__~III
Ill Ii !
'
I ~i I Iza
9 !,I
1 i, :.
L~--.L,-.L--.L-',/ ..........
, .........
.g
\,i,7." ~:.~
d,
..............
,
-,,
I
]
! , ~
!
J ;'
0
@
r ~d
d~
CLIPPER FIELD Matrix in the 'B' zone has better permeability and is m o r e h o m o g e n e o u s ; test intervals m a y flow several million cubic feet of gas per day w i t h o u t stimulation. The 'C' zone has not been tested in this field but experience from adjacent fields indicates productivity will generally be low. D e v e l o p m e n t wells have targetted 'B' zone in crestal parts of the field and the 'A' zone towards the flanks (where the B zone lies in the transition zone or aquifer). Initial rates have r a n g e d between 0 a n d 60 M M S C F D . The most productive wells e n c o u n t e r e d open n a t u r a l fractures. A n analysis of separator gas composition from the Clipper Field appraisal well 48/1%-6 is shown in Table 1. Gas gravity is 0.59 and gross calorific value is 1019 B T U / S C F . C o n d e n s a t e recovery is estimated to be 0.5 B B L / M M C F . F o r m a t i o n water salinity is typically high with a chlorides c o n t e n t of about 160 000 p p m and an equivalent sodium chloride salinity of 2 0 0 0 0 0 p p m or more. F o r m a t i o n water resistivity is 0 . 0 2 o h m m at 175~ The reservoir is n o r m a l l y pressured and no w a t e r - e n c r o a c h m e n t of the gas leg has been observed or is expected during field life.
Matrix permeability Hydrocarbons Gas gravity Gas type Condensate yield Formation water Salinity
Resistivity Reservoir conditions Temperature Initial pressure Pressure gradient
Field size Area Gas expansion factor Gas-in-place Recoverable reserves
697 0.02-100 mD average less than 1 mD all zones 0.59 sweet dry gas 0.5-2 BBL/MMSCF
160 000 ppm chloride 200 000 ppm sodium chloride equivalent 0.02 ohm m
175~ 3850 psi at datum 8200 ft TVDss 0.07 psi/ft (gas leg) 0.5 psi/ft (water leg)
12 000 acres (total field) 228 (SCF/RCF) 1171 BCF (total field) 753 BCF (initial development area)
Reserves The recovery m e c h a n i s m is assumed to be natural depletion. Reserves estimates have been derived from a field simulation m o d e l built using the Top Rotliegend structure map, zone isochores, and iso-porosity maps. Gas saturations were o b t a i n e d f r o m heightsaturation curves constructed from log-derived a n d capillary pressure curves. To allow for uncertainties in p a r a m e t e r s leading to construction of the model, a range of probabilities have been examined and results obtained in terms of expectation values. This full field m o d e l was rebuilt in 1995 to incorporate results of the 1992 3D seismic. The model includes a 2-phase fracture flow subsurface description, which is u p d a t e d with the latest structural, geological, petrophysical and p r o d u c t i o n data. Based on expected a b a n d o n m e n t rates the ultimate recovery is defined as the volumes producible until the year 2040. T h e pre-development estimate of ultimate recovery for Clipper was 558 BCF. This was revised u p w a r d s in 1993, four and a half years after the start of development, following the acquisition of new 3D seismic over the field (leading to a higher estimate of G I I P ) and the successful application of horizontal drilling to improve well performance. The current estimate for initial gas in place is 1171 BCF, with an expectation ultimate recovery of 753 BCF. As of 1.1.99 some 272 B C F (36% of U R ) had been p r o d u c e d from the Clipper field. This paper is an update of the paper by Farmer & Hillier in the 1991 edition of United Kingdom Oil and Gas Fields, and incorporates much of the material from that original paper. The author would like to thank Shell Expro and Esso Exploration and Production UK Ltd for permission to publish this paper. In common with most field descriptive papers it represents largely the work of many people and I am grateful to colleagues for their efforts, assistance and advice, especially with reference to studies of facies, fractures, special core analysis, well test analysis and simulation modelling.
Clipper Field data summary Trap Type Depth to crest Free water level Gas column
Faulted anticline, multiple culminations 7500 ft TVDss 8530 ft TVDss up to 1000ft
Pay zone Formation Age Gross thickness Porosity Gas saturation
Leman Sandstone (Rotliegend) Early Permian 650 to 775 ft 11.1% average all zones 49% average all zones
Production First gas Development scheme
October 1990 30 slot wellhead platform, bridge linked to production platform. 24 development wells to date 1 further development wells planned in 2000-1 Future infill drilling dependent on well/field performance Evacuation to Bacton
References ALBERTS, M. A. & UNDERHILL,J. R. 1991. The effect of Tertiary structuration on Permian gas prospectivity, Cleaver Bank area, Southern North Sea, UK. In: SPENCER,A. M. (ed.) Generation, Accumulation andProduction of Europe's Hydrocarbons. EAPG, Special Publication, 1, 16 I-173. BUTLER, J. B. 1975. The West Sole Gasfield. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1, Geology. Applied Science Publishers, London, 213-219. CAMERON,T. D. J., CROSBY,A., BALSON,P. S., JEFREY,D. H., LOTT,G. K., BULAT, J. & HARRISON, D. 1992. United Kingdom Offkhore Regional Report." the Geology of the Southern North Sea. British Geological Survey, London. CORNFORD, C. 1984. Source Rocks and Hydrocarbons of the North Sea. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 171-204. COWARD, M. P. 1995. Structural and tectonic setting of the Permo-Triassic basins of Northwest Europe. In: BOLDY, S. A. R. (ed.) Permian and Triassic Rifting in Northwest Europe. Geological Society, London, Special Publications, 91, 7-39. FARMER, R. T. & HILLIER, A. P. 1991. The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields': 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 417-423. GLENNIE, K.W. 1984. Early Permian-Rotliegend. In: GLENNIE,K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 41-60. GLENNIE, K. W. & BOEGNER, P. L. E. 1981. Sole Pit Inversion Tectonics. In: ILLING, L. V. & HOBSON, D. G. (eds) Petroleum Geology of the Continental Shelf of North West Europe. Institute of Petroleum, London, 110-120. GLENNIE, K. W., MUDD, G. C. & NAGTEGAAL, P. J. C. 1978. Depositional Environment and Diagenesis of Permian Rotliegendes Sandstones in Leman Bank and Sole Pit areas of the UK Southern North Sea. Journal of Geological Society, London, 135, 25-34. HOORN, B. VAN. 1987. Structural Evolution, Timing and Tectonic Style of the Sole Pit Inversion. Tectonophysics, 137, 239-284.
698
M . J . SARGINSON
LUTZ, M., KAATSCHIETER,J. P. H. & W1JHE,D. H. VAN. 1975. Geological Factors Controlling Rotliegend Gas Accumulations in the Mid-European Basin. Proceedings of the 9th World Petroleum Congress, 2, 93-103. MARIE, J. P. P. 1975. Rotliegend Stratigraphy and Diagenesis. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1. Geology. Applied Science Publishers, London, 205-210. MOORE, P. J. R. McD. 1989. Barque and Clipper - Well Test Analysis in Low Permeability Fractured Gas Reservoirs. In: Proceedings of the 1989 SPE Joint Rock)' Mountain Region~Low Permeability Reservoir Symposium. Paper No. SPE 18966. NAGTEGAAL, P. J. C. 1979. Relationship of Facies and Reservoir Quality in Rotliegendes Desert Sandstones, Southern North Sea Region. Journal of Petroleum Geology, 2, 145 158. OUDEMAYER, B. C. • DE JAGER, J. 1993. Fault reactivation and oblique strike-slip in the southern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1281-1290. RHYS, G. H. 1975. A Proposed Standard Lithostratigraphic Nomenclature for the Southern North Sea. In: WOODLAND, A. W. (ed.) Petroleum and the Continental ShelJ'of Northwest Europe, Volume 1, Geology. Applied Science Publishers, London, 151-162.
ROSSEL, N. C. 1982. Clay Mineral Diagenesis in Rotliegend Aeolian Sandstones of the Southern North Sea. Clay Minerals, 17, 69-77. SARGINSON, M. J. 2003. The Barque Field, Blocks 48/13a, 48/14, UK North Sea. In: GLUYAS, J. & H~CHENS, H. (eds) United Kingdom Oil and Gas Fields: Millennium Commemorative Volume. Geological Society, London, Memoirs, 20, 663-670. SEEMAN, U. 1982. Depositional Facies, Diagenetic Clay Minerals and Quality of Rotliegend Sediments in the Southern Permian Basin (North Sea): A Review. Clay Minerals, 17, 55-67, VEEN, F. R. VAN. 1975. Geology of the Leman Gas Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1. Applied Science, London, 223-231. WALMESLEY, P. J. 1977. Ten Years in the North Sea with BP. Petrole aet Techniques, February 1977, 7-20. WALKER, I. M. & COOPER, W. G. 1987. The structural and stratigraphic evolution of the northeast margin of the Sole Pit basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of Northwest Europe. Geological Society, London, 263-275. Z1EGLER, W. H. 1975. Outline of the Geographical History of the North Sea. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1, Geology. Applied Science Publishers, London, 165-190.
The Corvette Field, Block 49/24, UK Southern North Sea A. P. H I L L I E R
Shell UK Exploration and Production, Lothing Depot, North Quay, Lowestoft, Suffolk NR32 2TH, UK
Abstract: Corvette is a small prolific gas reservoir with reserves of 211 BSCF located on the Indefatigable Shelf in the Southern North Sea. The reservoir is the Permian Rotliegend aeolian sandstone, capped by Zechstein evaporites and sourced from the Carboniferous Coal Measures. The structure is a 'pop up' between the Gawain and Baird Fields. The field was discovered in 1996 and brought on production in 1999, with gas being evacuated via the Leman Field to the Shell/Esso Bacton gas terminal.
The field lies 90 km ENE of the north Norfolk coast in 30 m water depth just to the south of the Indefatigable Field (Fig. 1). It is mainly in the First Round Block 49/24, part of the P007 licence issued to a 50/50 partnership between Shell and Esso with Shell as the operator, but does extend slightly into First Round Block 49/23 part of licence P016 operated by Amoco. The field map based on pre-stack migrated 3D seismic data is shown in Figure 2. Following the discovery of the field Shell acquired the part of the 49/23 block containing the field from the Amoco operated group. The field has therefore been unitized between Shell and Esso for the 49/24 part and Shell for the 49/23 part. The agreed equity split is Shell 56.75%, Esso 43.25%.
History In 1991, exploration well 49/24-18 was drilled on the north flank of a domal structure identified from 2D seismic data to the south of the Indefatigable Field. The well came in deeper than expected and
found the reservoir to be water bearing. A 3D seismic survey over the Gawain Field to the southeast of this well was shot in 1992. It showed that the high mapped from 2D was in fact a very narrow fault bounded pop up structure (Fig. 2) and the original well was seen to be located north of the structures boundary fault. Following detailed mapping of the time migrated 3D data the probability of the structure being gas bearing was so high that an exploration well 49/24-20 was drilled as a deviated well from a potential platform position in 1996 (Fig. 3). The well found 223 ft of Rotliegend sandstone which was fully gas bearing. As planned the well was suspended for future tieback. Development consent was gained for the field based on a development plan incorporating a normally unattended drilling/ production platform with a 20" pipeline to the Shell Esso Leman A complex where the gas will be compressed when needed before export to the Bacton Terminal. The 3D seismic was pre stack depth migrated in 1998 and a new map made, to plan development wells. The platform was installed over the discovery well which was tied back and a second
Fig. 1. Corvette Field location map.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 699-704.
699
700
A.P.
HILLIER
,,_a 9
O
k~
e4
CORVETTE FIELD
during the Alpine orogeny, though this is difficult to prove since the overlying salt accommodates the pop-up block leaving no imprint on the overburden. Corvette lies in line on the same pop-up trend as Baird to the NW and Gawain to the SE. The field has two culminations separated by a saddle and has some minor faulting within the reservoir.
development well drilled to the east lobe of the field in 1998. First gas from the field was in January 1999.
Discovery The original unsuccessful exploration of the Corvette Field was based on 2D seismic where an apparent top Rotliegend seismic time high was mapped as a domal structure. Later the more detailed data from the 3D survey revealed that the structure was a narrow pop up and that the wider spaced 2D data had failed to identify the boundary fault and lack of structure to the north of it. In this area of the southern North sea surrounded by gas fields the definition of a true structural trap virtually guaranteed success and hence the discovery well was drilled as a potential development well.
Stratigraphy The stratigraphy of the field is similar to that of the other fields in the Indefatigable Shelf area such as Sean and Indefatigable, both reported elsewhere in this volume and shown in the crosssection (Fig. 3). Upper Carboniferous purple to red-brown shales and siltstones with minor coals and sandstones, of deltaic origin, occur unconformably beneath the Rotliegend, and constitute the oldest rocks penetrated. The Permian Rotliegend Reservoir, the Leman Sandstone Formation, consists mainly of a series of aeolian sand dunes, with minor amounts of water-laid sediments, and is about 225 ft thick in the field.
Structure Corvette is one of several strike-slip faulted 'pop-up' structures found in the vicinity of the Indefatigable Field. These long but very narrow features lie on a W N W - E S E trend, at around 20 ~ to the main fault trend. They are thought to have formed quite late,
WEST NORTH WEST
]
......
~902~01 I
Bvls55
'
.......
--*~,=
I
......
PLATFORM
701
6V.~609
[
Fig. 3. Corvette Field structural cross-section along wells. No vertical exaggeration.
I
.....
gTS~98 5901;6B I
o~e394
5~1113 I
.......
...... I E A S T I
NORTH EAST
I
702
Fig. 4a. Corvette Field discovery well core, no factures.
A.P. HILLIER
CORVETTE FIELD
Fig. 4b.
703
704
A . P . HILLIER
The Upper Permian Zechstein Evaporite sequence is up to 1300 ft thick. At the base of the Zechstein I Cycle is the thin ubiquitous Kupferschiefer overlain by a thin Zechsteinkalk unit, followed by the Werra Anhydrite. Cycle II starts with Haupt Dolomite followed by the Basal Anhydrite and Stassfurt Halite. The interval from Kupferschiefer to Basal Anhydrite is shown in Figure 3 as the Basal Zechstein. The Cycle III starts with the Platten Dolomite, the Haupt Anhydrite and the Leine Halite. Cycle IV is the Aller Halite. Triassic sedimentation is represented by the Bacton Group starting with the Brockelschiefer Member of the Bunter Shale formation followed by the Main Bunter Shale Member, the Rogenstein Member and finally the Bunter Sandstone. The Bunter sandstone is unconformably overlain by the Lower Cretaceous, Cromer Knoll Formation which is itself overlain by the Upper Cretaceous Chalk. Unconformably above the Cretaceous are some 2000ft of North Sea Group sands and shales.
Trap The pop up structure is composed of Carboniferous, Rotliegend and the basal Zechstein hard rocks below the Stassfurt Halite. Most of the movement is accommodated in the Stassfurt Halite which surrounds the horst block but pinches out at the crest. The top seal for the accumulation is formed by the anhydrites and dolomites together with the Aller and Leine Halite which are complete over the structure. The trap has spillpoints to the N W toward Baird and the SE toward Gawain (Fig. 1). Although the gas-water contact was not penetrated in either Corvette well, pressure gradients taken in the reservoir in the field, and in the aquifer in nearby wells, define a free water level inside the spillpoints showing that the trap is slightly underfilled.
are shown in Figures 4a and 4b. Note the intense small scale fracturing seen in well 49/24-Aly. The fracturing appears to have little effect on the inflow performance of the well and may be related to the proximity to a minor in field fault.
Source The gas is sourced, as in the surrounding fields, from the underlying Carboniferous coals and has a composition as shown in Table 1.
Reserves and production Gas recovery is by pressure depletion. The expectation GIIP for the field is 236 BSCF of which 211 BSCF or 89% is expected to be recovered. There is some evidence from the production history that the two wells are not in complete communication but are separated by a transmissibility barrier assumed to be the faulting in the narrow neck in the field. No further development drilling is currently planned. This paper is a compilation by the author of work by many colleagues in Shell UK Expro whose contribution is hereby acknowledged. Shell UK Exploration and Production, Esso Exploration and Production UK Ltd permitted publication of this paper.
Corvette Field data summary Trap
Type Depth to crest Lowest closing contour Free water level Gas column
faulted pop up 8000 ft 9000 ft 8941 ft 941 ft
Pay zone
Reservoir The reservoir is the aeolian dune sands of the Rotliegend group. In Corvette the reservoir quality is amongst the best seen anywhere in the Southern North sea with average porosity measured in both wells of 20% and average permeability in the range of hundreds of millidarcies. Partial core coverage is available from both wells, the lower part of the first well and the upper part of the second well. The first well was fully cored but the upper part of the core was drilled up and not recovered. Due to the partial recovery the upper part of the second well was cored. Both wells saw well defined aeolian dune sands, both slipface and dune apron, with minor fluvial interbeds. The major difference was in the amount of natural fracturing, the exploration well, 49/24-20, is unfractured whilst the eastern well, 49/24-Aly, is intensely fractured. Representative core photos from the two wells
Methane Ethane Propane Isobutane N-Butane Isopentane N-Pentane Hexane Heptanes plus Nitrogen Carbon dioxide Total
Leman Sandstone Permian 220 ft 100% none applied 20% 85% 400 mD
Hydrocarbons
Gas gravity Gas type Condensate yield
0.59 Sweet Dry 1.05 BBL/MMSCF
Formation water
Salinity Resistivity
200 000 ppm equivalent NaC1 0.018 ohm-m
Reservoir conditions
Table 1. Corvette gas composition Component
Formation Age Gross thickness Net/gross ratio Net sand cut-off Porosity Gas saturation Matrix permeability
Mol. % 94.27 2.16 0.27 0.04 0.06 0.02 0.02 0.02 0.10 2.13 0.91 100.00
Temperature Pressure Pressure gradient
186~ 4083 psia 0.07 psi/ft gas gradient
Field size
Area Gas expansion factor Gas initially in place Drive mechanism Recovery factor Recoverable reserves
795 acres 232 236 BCF Depletion 89% 211 BCF
Production
First gas Development scheme
Jan 1999 Single Unmanned Platform, 2 production wells
The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, UK North Sea C. W. M c C R O N E BP Amoco Exploration, Dyce, Aberdeen AB21 7PB, UK Present address." BP Exploration, Chertsey Road, Sunbury on Thames, Middlesex TW16 7LN, UK
Abstract: Davy, Bessemer, Beaufort and Brown are a series of small to moderate (30-200 BCF) dry gas fields, which span the southeastern corner of the UK Southern North Sea Rotliegend Play fairway. Davy was discovered in 1970; however, it was not until 1989 that Bessemer and subsequently Beaufort in 1991 were drilled. These fields were developed and brought on-stream by Amoco licence groups in 1995/96. More recently the Brown Field was discovered in October 1998 with first gas seven weeks later. The commercial viability of these relatively small accumulations is the result of technical advances across several fronts: 3D seismic imaging, horizontal well technology and minimum offshore facilities. In the Bessemer and Beaufort area, the Rotliegend Leman Sandstone Formation reservoir (250 ft) primarily consists of stacked aeolian dune sandstones of good reservoir quality (porosity 17%, permeability 10 1000mD). However, in the Davy and Brown area there is greater variation in the Rotliegend isopach (300-700 ft) and the nature of facies present e.g., aeolian dune, sabkha and playa lake. The fields are tied back from the Bessemer and Davy mono-tower platforms via 15 km and 43 km pipelines, respectively, to the compression facilities on the Indefatigable 23AT platform.
The Bessemer and Beaufort Fields are located in the centre of the UK Southern North Sea, in Block 49/23 (Fig. 1). They are produced via the Bessemer AMOSS (Amoco Minimum Offshore Support Structure), a normally unmanned installation (NUI), 15 km SW of Indefatigable Field in a water depth of 100 ft. The Bessemer and Beaufort fields are on the margin of the Inde Pediment to the north of the Sole Pit Basin, therefore, the Rotliegend has not been subject to deep burial and is of good reservoir quality. The Davy and Brown Fields are situated in the southeastern corner of the UKCS Rotliegend Play fairway, in blocks 49/30a, 49/30c and 53/5a. Gas production is through the Davy AMOSS, 43 km SE of Indefatigable Field in a water depth of 110 ft. Located on the southern margin of the Permian Basin, rock quality in Davy and Brown is more variable due to facies changes, however, reservoir quality has been preserved due to limited depth of burial. Davy, Bessemer and Beaufort Fields are tilted fault-block traps (Figs 2 & 3) that formed as a result of regional extension and dextral strike-slip movements generating local areas of compression and extension along the regional N W - S E trending fault system. Whereas, Brown is a small N N W - S S E trending horst block located within the graben to the north of Davy Field.
History The exploration acreage covering Blocks 49/23, 49/30 and 53/5 was awarded to Amoco groups as part of the First and Second Offshore Licence Rounds in 1964 and 1965, respectively (Table 1). Block 49/30c was awarded out-of-round in 1997 as P.947. Initial exploration efforts in Block 49/23, during the late 1960s, concentrated on delineating the southern extent of the Indefatigable Field. It was not until 1989 that the Bessemer discovery well 49/23-5 was drilled on a 2D seismic interpretation and tested the flank of the structure; it flowed at 42.6 MMSCFD. The well penetrated a 246ft Rotliegend Leman Sandstone interval, with a 52ft gascolumn and gas-water contact (GWC) at 8696 ft TVDss (Fig. 2). Subsequently, in 1991, the 49/23-7 well tested the en-echelon fault block to the SE of Bessemer. This well was also drilled down flank, encountering a 269ft Leman Sandstone section with a l l0ft gascolumn and a shallower G W C of 8618 ft TVDss, thus establishing Beaufort as a separate structure. The small extension of the Beaufort structure into the Arco Block 49/27 was purchased by the Amoco 49/23 group. Exploration in the Davy area during the late 1960s and early 1970s had mixed results. The early Amoco wells (e.g. 49/30-1 and
Fig. 1. Southern North Sea location map. Gas from Bessemer/Beaufort and Davy/Brown facilities is transported, via 15 km and 43 km pipelines respectively, to the compression platform on the Indefatigable Field prior to export to the Bacton gas terminal. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 705-712
705
706
C . W . McCRONE
Fig. 2. Bessemer and Beaufort Top Rotliegend structure map. The Bessemer and Beaufort Fields are elongate tilted fault blocks developed on the footwalls of a series of sinistral en-echelon faults separated by transfer zones, which form part of a regional NW-SE trending 53/5-1) tested valid structures at the top Rotliegend level but proved to be dry, although the 53/5-1 well did encounter gas within the Plattendolomit. With the benefit of the 3D seismic dataset, acquired in 1994, the early disappointments can now be attributed to late trap timing and lack of effective top and lateral seals. Many of the structures were either created or significantly enhanced during the Alpine orogeny, therefore, post-dating the main phase of gas generation during the late Cretaceous. The Davy discovery well 49/30-2 was drilled in 1970 and encountered 59 ft of pay in a 306 ft Leman Sandstone section with a G W C at 7743 ft TVDss, however, the well only flowed at 6.8 M M S C F D . The two Davy appraisal wells were not drilled until 1989; 53/5a-2 (26 M M S C F D ) confirmed the southerly extension of the field and 53/5a-3 (23 M M S C F D ) established a separate accumulation, SE Davy, with a G W C of 7667 ft TVDss (Fig. 3). In 1998,
Table 1. Davy, Bessemer, Beaufort and Brown acreage licensees Licence
Round
Block
Licensee
Interest
P.016
1
49/23
BP Amoco Exploration plc. BG International Ltd. Amerada Hess Ltd. Enterprise Oil plc.
30.77% 30.77% 23.08% 15.38 %
P.064
2
49/30a & 53/5a
BP Amoco Exploration plc. BG International Ltd. Amerada Hess Ltd.
22.22% 50.00% 27.78%
P.947
OOR
49/30c
BP Amoco Exploration plc. BG International Ltd. Amerada Hess Ltd.
22.22% 50.00% 27.78%
the 49/30a-A5 well was drilled from the Davy AMOSS and tested the Brown exploration prospect to the north of the field; the well encountered 227 ft of pay with a G W C at 8553 ft TVDss. The design specifications for the Davy and Bessemer AMOSS's were identical; they were fabricated, mobilized and installed together thereby maximizing operational synergies and reducing the initial capital costs. The facilities were kept to an absolute minimum to reduce the necessity and frequency of maintenance visits. This had the effect of enhancing safety and reducing operating costs. Davy and Bessemer came on-stream in September 1995, followed shortly thereafter by Beaufort in April 1996. The Brown Field was on production, December 1998, within seven weeks of discovery having obtained all statutory approvals. Following the Amoco (UK) Exploration convention, the fields are named in honour of British scientists, inventors and explorers: Sir Humphry Davy invented the miners' safety helmet, Sir Henry Bessemer developed an inexpensive process for mass producing steel, Sir Francis Beaufort devised an observation scale for measuring winds at sea, and botanist Robert Brown first described the irregular movement of particles now known as Brownian motion.
Stratigraphy The stratigraphy consists of a standard Southern North Sea section, representing continuous subsidence and deposition apart from the regional inversion events of the late Carboniferous, late Jurassic and Tertiary (Fig. 4). In the Bessemer and Beaufort area, there is only minor halokinesis due to the relatively stable nature of the Inde Pediment, and to the south in the Davy area, there is insufficient halite in the thinner Zechstein section.
DAVY, BESSEMER, BEAUFORT AND BROWN FIELDS
707
Fig. 3. Davy and Brown Top Rotliegend structure map. The Davy Field is an elongate tilted fault block bounded on the NE by a regional NW-SE fault with dip closure to the south and west. Brown Field is a small N-S trending fault block situated in the graben between the Davy fault block and the dry horst farther to the north. Underlying the Rotliegend reservoir is a Carboniferous Westphalian A/B section consisting of pro-deltaic shales with occasional deltaic sands and silts deposited during marine regressions. The Beaufort exploration well 49/23-7 penetrated 4800ft of Westphalian section characterized by a low net/gross ratio (e.g. 0.1-0.2) with occasional thin (10-20 ft) sandstones of poor reservoir quality. The Lower Permian Rotliegend Leman Sandstone Formation was deposited on the late Carboniferous Variscan unconformity surface. In the Bessemer and Beaufort area the Rotliegend is primarily composed of stacked aeolian dune sandstones reflecting deposition in a central desert erg environment (George & Berry 1993). However, to the south in the Davy Field sabkha and fluvial units are increasingly common representing a more marginal setting. An effective top seal is provided by the overlying Zechstein, however, this thins from a 2000 ft halite and anhydrite dominated section in the Bessemer/Beaufort area to a 1300 ft carbonate and anhydrite sequence over Davy. Due to the thinning of the Zechstein halites, the Davy Field relies on a Werraanhydrit top seal. A uniform thickness of the Triassic Bacton Group is present, but the overlying Haisborough Group is variably preserved and the Jurassic is completely absent beneath the Base Cretaceous Unconformity as a result of Late Cimmerian tectonism. In the Davy area virtually the entire Haisborough Group has been eroded. A thin Lower Cretaceous sequence of shales and marls grade upwards into the chalk of the Upper Cretaceous. Towards the end of the Cretaceous and into the Tertiary, Alpine tectonism interrupted regional basin subsidence, tilting the Davy structure down to the SE. As a result of this late reactivation, a few faults in the Davy area extend up through the Zechstein and Mesozoic overburden into the Tertiary.
Trap Davy, Bessemer and Beaufort Fields are elongated tilted fault blocks developed on the footwalls of regional N W - S E trending faults (Figs 2 & 3). These structures are 7 km, 8 km and 4.5 km long respectively, bounded to the north and east by the main N W - S E fault system with closure to the south and west provided by structural dip. However, the structural relief (e.g. Davy 450 ft, Bessemer 250ft, Beaufort 220ft) decreases rapidly away from the main bounding faults with large regions of the fields < 100 ft above their respective GWCs. The regional N W - S E trending faults consist of a series of shorter sinistral en-echelon faults separated by transfer zones e.g., the offset between the Bessemer and Beaufort accumulations. The structures are believed to have formed during regional Mesozoic extension combined with limited dextral strike-slip movement that produced local areas Of compression and extension along the regional fault system. In contrast, the Brown Field is a small N-S horst block (2.5km x 0.6km) located in the graben between the Davy fault block to the south and the dry horst block (i.e. 49/30-1, 49/30b-4 and 49/30b-6) farther to the north.
Field development The use of horizontal producers reduced the number of wells required to maximize recovery, therefore, lowered the field development costs and improved the project economics. The locations and lengths of the horizontal wells were optimized based on reservoir
708
C.W. McCRONE 49130 Davy
49/23 Bessemer/ Beaufort
Sira L
~epth 7VDss (FT)
.....
Seismic Marker/ Key Horizon
Seismic Marker/ Key Horizon
'1000"
Top Chalk Top Chalk
'2000"
Base Chalk "3000"
<~::ZlBase Cretaceous
-4000. ~ 1 Base Chalk Base Cretaceous -5000,
Rot Halite
-6000 ~I ~ ~ I Top Zechstein
Brockelschiefer Hauptanhydrit Plattendolomit Werraanhydrit
+ o': I'~
~,~~,o :Z
13_
N
~
@
Hauptanhydrit Plattendolomit Base Stassfurt Halite Werraanhydrit
-7000
Top Rotliegend -8000
Top Rotliegend - 9000
simulations. Near crestal locations, close to and parallel with the main NW-SE bounding faults, were chosen to maximize stand-off from the GWCs, limit water coning and delay water breakthrough. Therefore, the wells were targeted to turn horizontal 40 ft below the top Rotliegend based on drilling and reservoir quality considerations i.e., below the Weissliegend. The 1500 ft well length was chosen after taking into consideration well deliverability, drilling time and possible variations in reservoir quality. The horizontal sections were logged while drilling (MWD gamma-ray and resistivity) and subsequently on completion of the reservoir section a full suite of wireline tools (i.e. gamma-ray, resistivity, density and neutron devices) were conveyed on drill-pipe. Four of the seven Davy and Bessemer/Beaufort wells were also logged by formation micro-imaging tools to determine reservoir facies and thereby predict likely well productivity (Cranfield et al. 1996). The 6-inch hole horizontal reservoir sections were completed with gravel-packed screens. These were the first horizontal wells Amoco had drilled in the UKCS. Critical to the success of the project was the frequent and open communication between the sub-surface team and the drillers during the well planning and operations.
Bessemer and Beaufort Fields. The seismic interpretation of Bessemer and Beaufort for field development was based on the
Fig. 4. Stratigraphy for the Bessemer/Beaufort and Davy Fields. Moving south from Bessemer/Beaufort to the Davy area, on the southern margin of the Permian Basin, the Zechstein thins and changes from a halite and anhydrite dominated sequence to one of anhydrite and carbonate. Higher up the section a variable thickness of Triassic is preserved beneath the Base Cretaceous unconformity with virtually the entire Haisborough Group eroded in the Davy area.
1991/92 Bessemer 3D time-migrated survey. A layer-cake depth conversion method was applied based on the horizons representing significant velocity boundaries: Top Chalk, Base Chalk, Base Cretaceous Unconformity, Top Rot Halite, Top Zechstein, Top Hauptanhydrit, Base Stassfurt Halite and Top Rotliegend. For the Tertiary and Chalk, seismic times rather than sparse well-time data were used to calculate pseudo-interval velocities, however for the Lower Cretaceous and Triassic, well derived interval velocities were applied. Functions relating isopach to isochron were used for the three Zechstein intervals. The development plan for the fields required two horizontal wells in Bessemer and one in Beaufort. Due to the limited choice of target locations and the depth uncertainty (+100ft) on Top Rotliegend, the wells required considerable planning. The initial Bessemer development well (El) located in the centre of the field, came in 89 ft deep at 8564ft TVDss. This resulted in a significant reduction in standoff above the GWC and likely reserves loss due to early water breakthrough. A geophysical re-evaluation concluded that this was a localized depression of the crest of the structure. Directly above the E1 Rotliegend entry point, one Plattendolomit raft had over thrust another, resulting in a velocity pull-up. A decision was made to mill a window in the casing and sidetrack the well to the north, beyond the effects of the pull-up. The 49/23-Elz penetrated the top Rotliegend at 8480ft TVDss having regained elevation above the GWC.
DAVY, BESSEMER, BEAUFORT AND BROWN FIELDS To maintain standoff from the G W C in the narrow high relief northern part of Bessemer a pilot-hole, E2, was drilled to provide a top Rotliegend depth control point. This well was then plugged back and sidetracked horizontally through a N E - S W cross-fault into an up-thrown part of the reservoir. For the Beaufort producer, E3, the entry point for the 4.25 km step-out was chosen close to the 49/23-7 discovery well to provided depth control. The 49/23-E3 horizontal well path was also designed to establish the reserves upside case by drilling towards the main bounding fault where it penetrated an additional gas-bearing fault block.
Davy Field. At the time of field development plan approval the structural interpretation of Davy was based on a 1981 2D seismic survey, reprocessed in 1987/88, with additional infill lines acquired in 1987 and 1989 resulting in a 500-1000 m line spacing. This data set was too sparse for planning the horizontal wells, therefore, Amoco initiated the regional G E C O Q49/53 speculative 3D seismic survey, which was acquired in 1994/95, Phase 1 covering the Davy Field. Conversion from time to depth was accomplished using a layercake method. The interpreted horizons corresponding to significant velocity boundaries: Top Chalk, Base Chalk, Base Cretaceous Unconformity, Brockelschiefer, Hauptanhydrit and Rotliegend. Local well control was used to derive the relationships between layer isopach and isochron. The depth conversion of the Davy Field was controlled along the axis of the structure by the three exploration wells; however, to understand how velocities varied
709
from the crest to the flanks pre-stack depth migration was run on key seismic lines. The four Davy horizontal wells (49/30a-A1 through A4) were drilled along the crest of the structure close to the main N W - S E bounding fault. They were successfully drilled with top reservoir coming in as predicted. Only the 49/30a-A4 well, in the northern part of field, has not performed as predicted as a result of encountering a more extensive fault damage zone.
Brown Field. The entire regional G E C O Q49/53 3D seismic survey has been post-stack depth migrated and was used in the evaluation of the Brown exploration prospect, 3.25 km, to the N of Davy Field. The 49/30a-A5 well, drilled from the Davy AMOSS, targeted the crest of the horst block. It was designed as a pilot-hole to establish the position of the G W C and identify the facies present, in particular any vertical permeability barriers. The information from the pilot-hole was then used to select the optimum depth for the 1200 ft horizontal section.
Reservoir The Rotliegend Leman Sandstone Formation is primarily composed of an aeolian dune sequence with occasional interbedded sabkha and fluvial sandstones in the Bessemer/Beaufort area. To the south in the Davy area, sabkha and fluvial units are more
Fig. 5. Rotliegend Facies. In the centre of the basin the Rotliegend predominantly consists of stacked aeolian dune sequences with only the occasional development of interdune or sabkha facies in the lower Rotliegend (e.g. 49/23-7). On the southern margin of the basin local syndepositional tectonism combined with a marginal erg setting results in a more heterolithic reservoir with smaller dunes interbedded with interdune and sabkha facies. The 53/5a-2 well is atypical of the Davy area due to the presence of the playa lake shales.
710
C.W. McCRONE
common and there is limited development of playa lake facies. Overall the reservoir quality is good and based on well performance data there are no vertical permeability barriers within the fields. The Rotliegend in the Bessemer/Beaufort area is typically 250300 ft thick, representing the gradual thickening of the sandstone off the Inde Pediment. Whereas, the rapid changes in the Rotliegend isopach from 300 ft to 700 ft in the Davy area implies syndepositional tectonic activity. The intercalation of the main facies reflects vertical cyclicity due to long-term fluctuations in the climate, with each drying upward cycle subdivided into a lower 'wet phase' and an upper 'dry phase' (George & Berry 1993). The 'dry phase' is represented by stacked aeolian dune foresets, whereas the 'wet phase' is composed of interdune and sabkha sediments in the Bessemer/Beaufort area and sabkha, fluvial and lacustrine facies around Davy (Fig. 5). Reflecting the difference between central erg and erg margin in the two depositional settings. The main control on reservoir quality is grain size. In all the fields, the best reservoir properties occur in the medium-grained well sorted dune sandstones (e.g. average porosity 18% and permeability 10-1000mD). High permeabilities have been preserved due to the low level of cementation and lack of pore-throat clogging
clays. With the exception of the 20 ft interval immediately beneath the playa lake in 53/5a-2, where a combination of dolomitic cement and illitic clay have reduced porosity to 12% and permeability to <1 roD. The finer grained more poorly sorted sabkha and fluvial sandstones are of poorer rock quality (e.g. average porosity 12% and permeability 0.1-10mD) due to increased cementation and compaction. The Rotliegend is characterized by very high net/gross ratios of 0.95-1.00 based on a net sand cut-off of 8% porosity, as defined from a micro-porosity pore-throat radius (Fig. 6). The damp interdune, sabkha and playa lake units are considered to be nonpay. Only the Davy 53/5a-2 well has a lower net/gross ratio of 0.91 due to the 21ft thick playa lake interval. This shale has not been encountered in any of the other Davy wells and from field production data this unit has not acted as a permeability barrier, therefore, is considered to be of limited lateral extent. In the Davy area, the top 100ft of the Rotliegend is composed of lower fine-grained sub-arkosic dune sandstones, which are characterized by a higher gamma-ray response due to their higher potassium feldspar content (e.g. 9-10%). Although this unit has only slightly lower porosities of 15%, the permeability is dramatically reduced to 5-50 mD.
Fig. 6. Rotliegend Facies porosity/permeability relationship. Descriptions from the cored Davy (53/5a-2 and 53/5a-3) wells indicate that the aeolian dune facies (e.g. foreset, dune-toe and dune-base) have the best reservoir quality. The sabkha and fluvial facies are marginal to non-pay intervals. The permeability in the fine grained higher K-feldspar (9-10%) dune facies encountered in the top 100 ft of the Rotliegend in the Davy area is generally one order of magnitude less than the typical Rotliegend dunes. The dune facies immediately below the playa lake on 53/5a-2 have been subject to extensive diagenetic alteration, reducing their pore-throat size from the macro-mega to the micro range.
Fig. 7. Davy, Bessemer, Beaufort and Brown production data. Davy and Bessemer came on-stream in September 1995, followed by Beaufort in April 1996. The fields are now on decline, however, while on plateau the through put at the Davy and Bessemer/Beaufort facilities was 80 MMSCFD and 75 MMSCFD, respectively. First gas from the Brown Field was in December 1998.
DAVY, BESSEMER, BEAUFORT AND BROWN FIELDS T h e r e is a relatively thin 1 5 - 3 5 f t d e v e l o p m e n t o f m a r i n e r e w o r k e d Weissliegend interval at the t o p o f the Rotliegend. H o w ever, only the t o p 5 ft o f the reservoir is c o m m o n l y d e g r a d e d due to the p r e c i p i t a t i o n o f c e m e n t s by fluids derived f r o m the overlying K u p f e r s c h i e f e r a n d basal Zechstein c a r b o n a t e s a n d evaporates.
Source T h e source o f the gas is the thick sequence o f coals a n d o r g a n i c rich shales o f the C a r b o n i f e r o u s W e s t p h a l i a n A / B section; h o w e v e r , the C a r b o n i f e r o u s t h a t underlies the fields is i m m a t u r e to m a r g i n a l l y m a t u r e for gas generation. T h e m a i n source area is likely to have been the s o u t h e r n e n d o f the Sole Pit Basin where significant gas g e n e r a t i o n started d u r i n g the U p p e r Cretaceous.
711
Reserves and production All the fields are d r y gas reservoirs a n d have essentially the same gas c o m p o s i t i o n , 9 2 % m e t h a n e , with a c o n d e n s a t e / l i q u i d ratio o f < 1 B B L / M M S C F . A l t h o u g h there is h i g h e r n i t r o g e n c o n t e n t ( 4 % ) in the D a v y area c o m p a r e d with B e s s e m e r / B e a u f o r t (2%). First gas f r o m the Davy, B e s s e m e r / B e a u f o r t fields was in 1995/96, h o w e v e r , p r o d u c t i o n is n o w on decline, h a v i n g c o m e off p l a t e a u rates o f 80 M M S C F D a n d 75 M M S C F D , respectively, in 1997/98 (Fig. 7). T h e B r o w n Field c a m e o n s t r e a m in 1998 at a rate o f 50 M M S C F D . T h e reservoir drive m e c h a n i s m is v o l u m e t r i c gas e x p a n s i o n a n d n o water or sand p r o d u c t i o n has been r e c o r d e d todate in a n y o f the h o r i z o n t a l wells. Based on the 3D seismic i n t e r p r e t a t i o n a n d d e v e l o p m e n t well results, the calculated gas initially-in-place figures for Davy,
Davy, Bessemer, Beaufort and Brown Fields data summary Field name
Davy
Bessemer
Beaufort
Brown
unit
Tilted fault block 7300 7743 7743 . . 443 . .
Tilted fault block 8450 8696 8696 . . 246 . .
Tilted fault block 8400 8618 8618
Horst block 8325 8565 8565
ft ft ft ft ft ft
Leman Sandstone Early Permian 300 0.9-1.0 16 (10-24) 30 (1-1000) 70 . .
Leman Sandstone Early Permian 250 0.95-1.0 17 (10-24) 30 (1-1000) 80 . .
Leman Sandstone Early Permian 270 0.95-1.0 17 (10-24) 30 (1-1000) 80
Trap
Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column
218
240
Pay zone
Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Petroleum saturation average (range) Productivity index
Leman Sandstone Early Permian 700 0.95-1.0 16 (10-24) 30 (1-1000) 60
ft % mD % BOPD/psi
Petroleum
Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio Condensate yield Formation volume factor Gas expansion factor
. . 0.6 0.022 . . . <1 . 206
.
. .
. .
0.609 0.023 . .
. . .
~API . 0.609 0.023
0.597 0.022
cp psig psig
<1
BBL/MMSCF
. . .
.
<1 .
.
. <1
.
.
.
228
228
223
SCF/RCF
225 800 0.0194
196 200 0.0185
196 200 0.0185
225 800 0.0 194
NaC1 eq ppm ohm m
1482 2.00E + 05 3562 0.065 190 . 200 87 Volumetric . 175 .
1050 9.40E + 04 4029 0.084 195 . 130 80 Volumetric . 100 .
419 3.40E + 04 4001 0.075 195
370 4.00E + 04 3968 0.067 193
40 80 Volumetric
35 70 Volumetric
acres acre ft psi psi/ft ~F MMBBL BCF %
32
25
1996
1998
25 1
30 1
Formation water
Salinity Resisitivity Field characteristics
Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially-in-place Gas initially-in-place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
.
. .
.
. .
MMBBL BCF MMBBL
Production
Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
1995 . 80 4
.
1995 . 50 2
.
BOPD MMSCFD horizontal producer
712
C.W. McCRONE
Bessemer, Beaufort and Brown are 200 BCF, 130 BCF, 40 BCF and 35BCF, respectively. Both Davy and Brown are essentially unchanged from the field development plans. Whereas Bessemer saw a reduction of 40 BCF due to localized depression of the crest of the structure around the original 49/23-E1 well and Beaufort gained an extra 10 BCF from an additional fault block. During the 1999-2000 contract year BP Amoco groups' average daily sales for Davy, Bessemer/Beaufort and Brown were 40 M M S C F D , 4 5 M M S C F D and 3 0 M M S C F D , respectively, which is equivalent to annual sales quantities of approximately 15 BCF, 16BCF and 10BCF. The cumulative BP Amoco groups' gas production to June 1999 for Davy, Bessemer/Beaufort and Brown represent 76%, 78% and 40% respectively of estimated ultimate recovery. All of the gas and a small volume of associated condensate, with M E G inhibition to hydrate formation, is transported from Davy and Bessemer NUIs, 43 km and 15 km respectively, through 16-inch pipelines to the compression facilities on the BP Amoco operated Indefatigable 49/23AT platform. Here it undergoes separation and metering prior to export to the Bacton Terminal.
The author wishes to thank BP Amoco Exploration and its co-venturers, BG International, Amerada Hess and Enterprise Oil for their permission to publish this paper. Our understanding is based upon many years of subsurface evaluation; therefore, the author acknowledges all those who have previously worked on the fields.
References CRANFIELD, C. B., BREALEY, S. J., MCCRONE, C. W. 8r TINGAS, J. 1996. Davy and Bessemer Rotliegend Fields: Reservoir Characterisation Using Micro-Imaging to Help Integrate Vertical and Horizontal Well Data.
Society of Petroleum Engineers, SPE 36819. GEORGE, G. f. • BERRY, J. K. 1993. A new lithostratigraphy and depositional model for the Upper Rotliegend of the UK Sector of the Southern North Sea. In: NORTh, C. P. & PROSSER, D. J. (eds) Characterization of FluviaI and Aeolian Reservoirs. Geological Society, London, Special Publications, 73, 291 319.
The Gawain Field, Blocks 49/24, 49/29a, UK North Sea R. A. O S B O N l, O. C. W E R N G R E N
2, A. K Y E I 3, D. M A N L E Y 4 & J. S I X 5
ARCO British Ltd, London Square, Cross Lanes, Guildford, Surrey GU1 1UE, UK 1Present address." Santos Ltd, Santos House, 91 King William Street, Adelaide 5000, Australia 2 Present address." BP Exploration Operating Company, Farburn Industrial Estate, Dyce, Aberdeen AB21 7BN, UK 3 Present address. Dome Exploration Consultant Ltd, 46 Downlands Road, Purley, Surrey CR8 4JE, UK 4 Present address." BP Exploration Operating Company, Chertsey Road, Sunbury on Thames, Middlesex TW16 7LN, UK 5 Present address." Chevron Petroleum Technology Co., 4800 Fournace Place, Houston, Texas 77401
Abstract: The Gawain Field is located on the Inde shelf in the Southern North Sea, 85 km NE of the Norfolk coast. Gawain was discovered in 1970 by well 49/29-1 and a total of nine wells have been drilled on the structure. Gas is produced from the Leman Sandstone Formation of Early Permian age. The reservoir section is comprised predominantly of stacked aeolian dune sands possessing excellent poroperm characteristics. The structure is a complex N W S E trending horst block with a common gas-water contact at 8904 ft TVDss. Low structural relief has presented a major challenge to field development, which has utilized extended reach wells to maximize drainage potential. Initial gas-in-place is estimated at 289 BCF with recoverable reserves in the order of 196 BCF. The field came on production in September 1995 via a sub-sea tie back to the Thames infrastructure and has an expected field life of 10 years.
The Gawain Field, located on the Inde shelf, straddles Blocks 49/24 and 49/29a of the U K Southern North Sea, 85 km N E of Bacton and approximately 20kin S of the Indefatigable Field (Fig. 1). Water depths in this area average 110 ft. The Inde shelf represents a N W - S E trending structural horst, separating the Sole Pit Basin to the west from the Broad Fourteens Basin in the east. The Gawain accumulation is approximately 11 km long in a N W - S E direction and covers an area of 11 square kilometres. Total recoverable reserves for the Gawain Field are estimated to be 196 BCF.
History
Exploration and appraisal The P007 licence, of which Block 49/24 is a part, was originally awarded to the Shell/Esso consortium during the First U K Offshore Licensing Round in 1964. Block 49/29 was awarded to Mobil as Licence P105 under the terms and conditions of the Third U K Offshore Licensing Round in 1970. The Gawain discovery well 49/29-1 (Fig. 2) was drilled by Mobil in 1970 and encountered 52ft of good quality, gas bearing Rotliegend Leman Sandstone. Shell drilled appraisal well 49/24-12 the following year, proving the field's northwesterly extension into Block 49/24. This well encountered 70 ft of pay and was interpreted to be in pressure communication with 49/29-1. In the 18 years that followed, little activity occurred in the Gawain area, due in part, to the limitations of the 2D seismic data in accurately defining the structure, but also because horizontal drilling technology was not sufficiently advanced to enable development of such a low relief structure. Mobil returned to Gawain in 1988 in order to appraise the southeastern part of the field with the 48/29a-7 well. The results of this proved encouraging with a 76 ft gas column encountered within excellent quality sands. The well tested gas at a rate of 55 M M S C F D through a 72/64" choke with a well head pressure of 2050 PSIG, demonstrating that commercial production rates could be achieved. In 1990, Shell drilled 49/24-17 (52 ft of gas bearing sands, tested at a rate of 30 M M S C F D with a wellhead pressure of 1747PSIG) proving Gawain's northwesterly extension and followed this by shooting a 3D seismic survey over the field. Based on interpretation of the 3D seismic data, 49/24-19, the final appraisal well, was drilled two years later and found the greatest gas column to date (100 ft of gross pay). In March 1994, A R C O purchased the southern part of Block 49/24 from Shell/Esso. The current Gawain owners are:
% Interest A R C O British Ltd (Operator) Superior Oil (UK) Ltd (a wholly owned subsidiary of Mobil)
50 50
Development Following A R C O ' s acquisition of Block 49/29 in March 1994, a unique joint A R C O Mobil development team was established with the aim of accelerating Gawain's development. Annex B approval was given in October 1994 and the field was subsequently developed using three horizontal sub-sea wells, manifolded and tied back to the Thames infrastructure via a 12" pipeline. This sub-sea development scenario was favoured because Gawain's surface location lies within a deep-water shipping route. The development drilling was carried out by Mobil on behalf of the group and commenced in January 1995 with 49/29a-GO1, situated on the southeastern part of Gawain's structure. This highly deviated well was drilled from Gawain's sub-sea template and achieved a 3516 ft horizontal reservoir section. In plan, it was necessary to drill this well with a highly deviated 'coat hanger' profile (Fig. 2) in order to achieve sufficient stand-off from Gawain's subsea template. This enabled the well to be drilled using a suitable build rate and allowed penetration of the top of the reservoir at the crest of the structure at the required angle of 86 ~ GO1 was successfully completed, producing gas on 29 September 1995 at a rate of 59 M M S C F D . Average reservoir log porosity was 18%. Well 49/29a-GO2 spudded in March 1995 with the aim of draining gas from the southwestern flank of the field. The well required a step-out of 5 km from the template in order to penetrate the Rotliegend target. A key concern was the trade-off between maximizing structural elevation v. reservoir quality (fault damage) as the 49/29-GO2 horizontal section parallels the main Gawain bounding fault (Fig. 2). Over 1000 ft of reservoir section was drilled with porosity and gas saturation averaging 16% and 84%, respectively. In 1995, GO2 came on stream at a rate of 47 M M S C F D . Well 49/29a-GO3 was spudded in the central part of the field in November 1995 and achieved 822 ft of reservoir in two sections, with an average porosity of 18% and water saturation (Sw) of 24% (Fig. 2). GO3 produced first gas in January 1996 at a rate of 17.5 M M S C F D . The three development wells were drilled targeting the structural highs within the field, giving maximum drainage potential and stand-off from the gas-water contact whilst penetrating good reservoir quality sands. The low relief of the field was a major challenge in siting wells, which could only find a column in excess of 100 ft.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 713-722.
713
714
R.A.
OSBON E T AL.
9
O
GAWAIN FIELD
715
Fig. 2. Top Rotliegend depth structure map of the Gawain Field.
Post-development The Gawain sub-sea facilities were designed with the scope for two future wells or groups of wells to be tied into the Gawain subsea manifold. Well 49/24-21Z, drilled early in 1998, proved additional reserves from Gawain's NW-extension. The well encountered a 108 ft gas column whilst pressure analysis indicated that the extension was is in communication with the main field. Although not a horizontal well, the reservoir quality was good enough to complete as a vertical producer once the field came off plateau. In 1998, field remapping, incorporating Gawain's NW extension well results, supported an increase in GIIP from 225 to 289 BCF. Options exist for Gawain's NW extension to be tied back in the future, if required. Further field extension possibilities are currently under review.
Structure
Geophysics During the early exploration phase, structural interpretations of the Gawain Field were based on 2D surveys of various vintages. Between August 1990 and January 1991, Shell acquired a 3D seismic dataset covering 228 square kilometres over Block 49/24, including the extension of the Gawain Field into 49/29a. An acquisition azimuth of 120 ~ was chosen in order to parallel the structural strike at both overburden and reservoir levels. The data has a nominal fold of 30 with an in-line spacing of 25 m and a cross-line interval of 26.7m. Polarity of the data is SEG normal. The Top Rotlie-
gend depth map, interpreted from this dataset, was used in the development drilling programme in 1995. Although the data quality was already good, the dataset was pre-stack time migrated in 1997 to improve the general imaging of seismic reflectors and fault definition. Reflectors are generally well defined therefore seismic interpretation is not the primary source of any uncertainty. These reprocessed data have superior fault definition and form the primary dataset, currently used for the Gawain geological reservoir model. Due to the significant time distortion caused by structural and stratigraphical complexities in the overburden at Gawain, a layer cake depth conversion method has been adopted, historically, to generate field maps. Lateral velocity variations occur in the Mesozoic section due to differential erosion at the Base Cretaceous Unconformity. Further complexities are introduced in the Palaeozoic section where localized thickening of the Stassfurt Halite, at the expense of the faster anhydrite and dolomite sections, depresses the Top Rotliegend over time. This creates uncertainties in depth conversion since these halite pods are difficult to map and hence difficult to allow for. Detailed well velocity analysis and depth conversion work prior to development drilling ensured that all three production wells came within • of that given in the Top Rotliegend map. With an average gas column of approximately 100 ft at Gawain, it was vital to achieve the 80 ft stand-off from gas-water contact required for successful horizontal wells. The following seismic markers were used in the latest depth conversion process (Fig. 3): Top Chalk; Base Chalk; Base Cretaceous Unconformity; Near Top Bunter Sandstone; Top Brockelschiefer; Top Plattendolomit; Near Top Stassfurt/Werra Halite; Base Stassfurt/Werra Halite; Top Rotliegend.
716
R. A. OSBON E T AL.
z
(soes
GAWAIN
FIELD
717
r~ 0 LL
z
Ow o z zo co
a
v _J
< I 0
O< z w ~ o ._1 i - ul .~Wlw w
w -I 0 .-I
l--
O
0
_j 0
z w LU I.~
n
w w, L) 0
z u.l II<
_~o
n 0 I-
~. 0 I-
o Q I-
r
0 mini-
Z
f~ l.u
0. 0 I-
~ ~'i!i!r"~ 84
!!i~i !!i!i !!i!i ~!i!i
i! i!i i! i! i!
!!i!i ! i'i !!i~i i! !!i!i i! !~i!i "! !~i!i i!
tt/3
IaJ _J
< O co
!i!i~i! ! i I io
!~!i!i i! i , i!i! i!i!
! !i!i! ,i! !i!i! !i! ~[![! !ii! ~i ~'i! !i! '!i!i! !i!i!i!i I !i!i!i!ii
.g o
..,.~
w
0
O)
(SSOA1 13) H l d 3 0
9
d ,4
718
R.A. OSBON E T AL.
Fig. 5. Gawain Field generalized stratigraphy.
Local structure
Gawain has a complex structural history resulting from reactivation and tilting of pre-existing fault blocks. The trap itself is a triangular horst block, bound to the east and southwest by N W - S E trending faults (Fig. 2). The Gawain fault block initially developed
during the Late Permian-Late Jurassic extension and was later inverted, with an oblique sense of movement, as a result of the Late Cretaceous-Tertiary inversion. The main bounding faults to the horst structure are high angle and both exhibit net extension. The top Rotliegend structure appears very flat over time, but is somewhat depressed in the central part of the field by the slow
GAWAIN FIELD
719
Fig. 6. Fault juxtaposition diagram along the southwestern bounding fault. velocities of a thickened Stassfurt Halite section (Fig. 3). Depth conversion corrects the effects of this velocity distortion and generates a low relief three-way dip closure against the eastern and southwestern bounding faults (Fig. 2). Crossline 590 (Fig. 3) illustrates the structural style of the field. It demonstrates progressively deeper erosional truncation of the Triassic Haisborough and Bacton Formations by the Base Cretaceous Unconformity towards the eastern flank of the field (Fig. 4). This erosion was followed by a tilting of the basin to the east with depositional thickening of Cretaceous Chalk and Tertiary clastics also to the east. Flattening on the Base Cretaceous Unconformity shows Gawain as a simple steeply-dipping structure, bound on the eastern side by the N W - S E trending fault but no closure against the south bounding fault. The easterly tilt of the Gawain area during the Late Cretaceous enhanced the structural relief on the southern flank of the field, redistributing any trapped gas from the eastern fault to the south bounding fault, which currently traps most of the field's reserves.
Stratigraphy Gawain lies on the southern flank of the Southern North Sea Basin in a narrow zone between the Sole Pit and Broad Fourteens Basins, commonly referred to as the Inde Pediment. The geology is typical of the Southern Gas Basin as indicated by the standardized U K O O A stratigraphic column (Fig. 5). The oldest rocks encountered are the Carboniferous Coal Measures of Westphalian age, comprising a shale, coal, siltstone and sandstone sequence of deltaic origin. Carboniferous evaluations on Gawain are for the most part limited to short penetrations for logging purposes. The Rotliegend Leman Sandstone Formation unconformably overlies the Carboniferous sequence and forms the Gawain reservoir. This predominantly aeolian sand sequence was deposited in an arid desert environment with material derived from the uplifted London-Brabant Massif and the Variscan Mountains to the east. A regional thickening of the Rotliegend towards the SW reflects the increasing influence of the fault controlled Sole Pit depocentre during early Permian times.
Aeolian deposition came to an abrupt end towards the end of the early Permian when the Rotliegend Basin was rapidly transgressed by the Zechstein Sea. At the base of the Zechstein sequence, a thin organic marine shale known as the Kupferschiefer provides an excellent marker bed and indicates the onset of evaporitic marine deposition. The main Zechstein sequence (c. 1600 ft thick) exhibits typical Z I - Z 4 cyclicity. A typical cycle (Richter-Bernburg 1959) reflects an overall increase in basin salinity caused by evaporation following an initial marine incursion. Each cycle commences with the deposition of a limestone (often diagenetically dolomitized) and passes upwards in turn through anhydrite, halite and highly soluble magnesium and potassium salts. Upper cycle Z4 is only partly developed in the Gawain area. Of particular note is the Plattendolomit, which represents a significant drilling hazard in the Gawain area as it commonly contains overpressured gas within halokinetically and structurally derived fractures. The Zechstein evaporites form the regional seal to the underlying Leman Sandstone Formation. The Triassic sequence, conformable with the underlying Zechstein, was deposited in a predominantly non-marine setting. The Bacton Group represents the earliest Triassic deposition in the Gawain area and comprises a lower Brockelschiefer Member of red-brown, anhydritic siltstones at the base of the Bunter Shale Formation. This is overlain by c. 1000 ft of red-brown claystones of the Bunter Shale Formation and c. 800 ft of the Bunter Sandstone Formation. Marine conditions were re-established during the Late Triassic with deposition occurring in sabkha and shallow marine environments. An eroded shale and evaporite sequence of the Haisborough Group is preserved in varying thicknesses across the Gawain Field (Fig. 3). The overlying Jurassic sequence is absent from all the Gawain wells, with mudstones and claystones of the Lower Cretaceous lying unconformably upon the Triassic. The shallow marine, Lower Cretaceous sediments represented by the Speeton Clay (Cromer Knoll Group) were deposited upon the Kimmerian unconformity across the Gawain area as subsidence commenced throughout the Gas Basin. Upper Cretaceous chalk was subsequently deposited in deeper water conditions basin wide, with minor variations in thickness resulting from tectonic and halokinetic activity. Late Cretaceous to Early Tertiary inversion resulting from Alpine tectonism, caused uplift and minor erosion
720
R. A. OSBON E T A L .
Fig. 7. Type core log for the Gawain Field, showing lithofacies & poroperm characteristics of well 49/29a-7.
of the Chalk Group prior to the unconformable deposition of the Paleocene clays. The youngest Tertiary sediments observed in the Gawain area are of Pliocene age.
Trap The structural map (Fig. 2) shows that the Gawain trap comprises a complexly faulted, N W - S E trending horst structure, which plunges towards the NW. This Rotliegend structure is sealed both vertically and laterally by the Zechstein evaporites. While the northeastern bounding fault has throws in excess of 1500 ft, sealing sand against evaporite, the southwestern fault locally juxtaposes sand on sand. Fault plane diagrams demonstrate that Gawain is probably filled to
spill point where the structurally highest sand-on-sand contact exists (Fig. 6). The main horst is divided into several smaller fault blocks by a number of cross cutting N E - S W trending faults, which probably formed in response to Late Cretaceous reactivation of pre-existing faults. These intra-reservoir faults have throws of 50-100 ft, and are unlikely to represent permeability barriers. Similary, gas-water contacts, excellent reservoir quality and pressure analysis suggest that fluid movement between compartments should not prove problematic during the production lifetime of the field. The trap is 11 km long by 4 k m wide and has an areal closure of some 11 square kilometres (2740 acres) as defined by the gas-water contact at 8904ft TVDss. The average gas column is approximately 100 ft.
GAWAIN FIELD
721
POROSITY (%) Fig. 8. Conventional core analysis results grouped by facies for all wells.
Reservoir
Depositional setting The Leman Sandstone Formation comprises continental sediments deposited in a Permian foreland desert basin to the north of the Variscan mountain belt (Glennie 1972). Following Late Carboniferous uplift and erosion, the desert plain inherited a topographic expression, which strongly influenced fluvial activity, draining from the Variscan mountains in the south towards the Silverpit Lake in the north. The geological model for Gawain is that of an aeolian dominated sequence deposited on the Inde shelf, which lay on the southeastern margin of the basin. During the early Permian, this shelf formed a palaeohigh, which explains the relatively thin Rotliegend succession (180-270ft thick) and the lack of fluvial sedimentation within the Gawain reservoir. Cored intervals in wells 49/23-6, 49/24-17, 49/24-1 and 49/29-1 indicate that the Leman Sandstone succession commenced with a phase of aeolian dune deposition interbedded with dry/damp aeolian sandsheets. Ephemeral fluvial activity at this stage is limited to a thin, parallel laminated and diffusely cross-stratified sheet sand unit resting directly on the Permo-Carboniferous unconformity in well 49/24-12. The presence of damp aeolian sheets with adhesion ripples and contorted laminae during this phase of deposition indicates a moist environment, possibly with the water table near surface. A sustained change to a more arid environment followed, with conditions favouring deposition of a thick dune sequence. Dip data from the 49/24-19 well indicate that the dunes were probably not straight crested and that the palaeowind direction was easterly. It is suggested that the dunes were of a compound barchanoid form, which migrated westwards towards the centre of the basin. Individual dune sets are generally small, averaging 10 ft in most cases.
Aeolian deposition came to an abrupt end when the transgression of the Zechstein Sea flooded the desert basin (Glennie & Buller 1983). Reworking of the upper dune sets resulted in homogenization of the aeolian sediments and the development of soft sediment deformation structures. These massive, grey reworked sediments have been cored in wells 49/23-6, 49/29-1, 49/29a-7 and 49/29a-3 and are referred to as the Weissliegend facies. These facies vary in thickness from 2 to 22 ft across Gawain. Detailed analysis of core, wireline and petrographic data has allowed the sub-division of the reservoir into five zones, based predominantly on facies type (Fig. 7). This zonation has formed the basis of Gawain's volumetric calculations.
Porosity types and diagenesis Core analysis demonstrates that reservoir quality at Gawain is good and strongly controlled by facies type, with the main aeolian dune sets showing superior reservoir quality to the dune toesets, sheetsands and the marine reworked facies (Fig. 8). Petro-graphic observations support this conclusion, showing that aeolian dune crossbeds are texturally characterized by a coarser grain size and higher degrees of sorting, resulting in looser grain packing and hence better reservoir properties. The dune crossbed facies are predominantly grain supported, preserving a well connected intergranular porosity. The reworked aeolian facies (Weissliegend) generally has poorer reservoir properties due to homogenization, giving an overall reduction in sorting and the associated increase in packing. Horizontal permeabilities are greatly reduced within the Weissliegend due to the destruction of horizontal laminae and primary sedimentary structures.
722
R . A . OSBON ET AL.
Diagenesis has largely resulted in a net reduction in reservoir quality. Any secondary porosity generation has been offset by the growth of cements occluding pore space and compaction related to burial, further reducing pore volume. Early shallow diagenesis resulted in the dissolution of authigenic feldspar, detrital grains and minor illite. Compaction and grain reorganization resulted in large scale porosity reduction throughout early diagenesis. Late diagenetic phases (pyrite, quartz and dolomite) are related to fracturing in some of the Gawain wells (49/24-17 and 49/29a-3) and are thought to correspond to Cretaceous uplift. Modelling of the burial curve at Gawain suggests that the Rotliegend was never sufficiently buried for significant reservoir degradation by fibrous illite growth, and blocky cements to occur.
Source The main source rock for the Gawain gas is almost certainly the underlying coal and shale sequence of Westphalian age. In the Gawain area, vitrinite reflectance data values at Base Permian level are typically 0.6-0.7% indicating that the Carboniferous coal sequence is largely immature. However, vitrinite reflectance values approaching 2.80% Ro can be mapped along the axis of the Sole Pit Basin, 45 km to the N W (Robert 1980). Back stripping and subsidence modelling suggests peak gas generation in the Sole Pit Basin occurred during Jurassic and Cretaceous times, prior to the Late Cretaceous-Tertiary inversion event. It is likely that gas initially migrated vertically into the Rotliegend via faults, cutting the Westphalian source rock. Lateral migration subsequently occurred in a southeasterly direction from the Sole Pit Basin towards the flanks of the basin, with the Leman Sandstone Formation acting as the main carrier bed. Gas emplacement into the Gawain structure is thought to have occurred at an early stage, preserving reservoir quality through inhibition of diagenetic processes. Tertiary inversion may have been responsible for some late gas re-migration. This re-migration may explain the bleaching effect observed beneath the gaswater contact in one of the Gawain wells, indicating a potentially deeper palaeocontact. The bleaching of gas bearing sands within the Rotliegend is a common observation in the Southern Gas Basin. Reducing conditions are set up within the reservoir when hydrocarbon gas replaces water as the main pore fluid phase. Such conditions cause chemical reduction of hematite, the iron mineral which coats Rotliegend sand grains and gives them their characteristic reddish brown colour.
many colleagues who have worked on the Gawain Field over the past few years; we would like to extend our acknowledgement to all of them for their contribution.
Gawain field data summary Trap
Type Depth to crest Gas-water contact Max closure Pay zone
Formation Age Gross Thickness Net/Gross Porosity Hydrocarbon Saturation Permeability
The authors wish to thank Superior Oil (UK) Ltd for their permission in allowing the publication of this paper. We would also like to acknowledge Superior's significant contribution to the Gawain development drilling programme. This paper has drawn on results and interpretations made by
Leman Sandstone Permian 104-271 ft 1.00 6-27% (Ave 18%) 67-84% 0.1 mD-5 Darcies (average 100mD)
Hydrocarbons
Gas gravity Condensate gravity Condensate yield Gas expansion factor Gas compressibility factor
0.606 51~ 0.98 BBL/MMSCF 227 scf/rcf 0.972
Formation water
Salinity Resistivity
200 000 ppm (NaC1 Eq.) 0.014Ohms @ 194~
Reservoir conditions
Pressure Temperature
4118psia @ 8850ft (ss) 176~ @ 8850 fl (ss)
Field size
Area Recovery factor Reserves
11 sq km (2740 acres) 68% 196 BCF (Gawain) 21 BCF Potential additional reserves (Gawain NW extension)
Production
Start-up date Development scheme Number/type of wells
Development and production The mapped gas-in-place for the Gawain Field is 289 BCF. Based on the three producing wells (GO1, GO2 and GO3), the expected ultimate recovery for Gawain is 68%, giving a recoverable reserve estimation of 196 BCF. P/Z data supports a GIIP of 285-300 BCF, closely matching the mapped volumes. The Gawain production strategy, early in its field life, was to constantly produce from wells GO2 and GO3, using GO1 as a swing well. In order to reduce the risk of water/sand breakthrough and to encourage even reservoir depletion, production currently occurs by swinging all wells on a day by day basis according to demand. The Gawain sub-sea installation mixes the gas from the three producing wells through a common manifold. From there, the gas is transported to the Thames AP platform via a 15.1 km, 12" pipeline, where it is processed and then re-exported through the 90 km, 24" Thames line to the Bacton terminal.
Tilted Horst Block 8600 ft (ss) 8904ft (ss) 304 ft
Production rate Cumulative production Secondary recovery
September 1995 Sub-sea tie back to Thames facilities 6 exploration 3 development [1 on hold] 110 MMSCFGD (Oct 98) 95 BCF (Dec 98) None
References GLENNIE, K. W. 1972. Permian Rotliegend of Northwest Europe interpreted in light of modern desert and sedimentation studies. American Association of Petroleum Geologists, Bulletin, 56, 1048-1071. GLENN~E,K. W. & BULLER,A. J. 1983. The Permian Weissliegend of, N.W. Europe: the partial deformation of aeolian dune sands caused by the Zechstein transgression. Sedimentary Geology, 29, 155-180. RICHTER-BERNBURG, G. 1959. Zur Palaeogeographie der Zechsteins. In: I giacimenti gassiferi dell Europa Occidentale 1. Accad. Nazionale dei Lincei, Rome, 88-99. ROBERT,P. 1980. The optical evolution of kerogen and geothermal histories applied to oil and gas exploration. In: DURAND, B. (ed.) Kerogen." Insoluble Organic Matter From Sedimentary Rocks. Editions Technip, Paris, 340-414.
The Guinevere Field, Block 48/17b, UK North Sea M. L A P P I N 1, D. J. H E N D R Y 2 & I. A. S A I K I A Mobil North Sea Limited, Grampian House, Union Row, Aberdeen ABIO 1SA, UK 1 Present address." Exxon Mobil Exploration Company, 800 Bell Street Rm. 2717C, Houston, Texas 77002, USA 2 Present address." Talisman Energy (UK) Ltd, Talisman House, 163 Holburn Street, Aberdeen ABIO 6BZ, UK
Abstract: The Guinevere Gas Field was discovered in January 1988 by the Mobil-operated well 48/17b-5. The field lies in the UK Sector of the Southern North Sea and occupies Block 48/17b. The field is located within the footwall of the Dowsing Fault Zone on the western flank of the Sole Pit Basin. Guinevere is a cornpressional northwesterly-trendingfault block that comprises Early Permian Leman Sandstone Formation (Rotliegend Group) reservoir, sourced from the Carboniferous below and sealed by Later Permian Zechstein evaporates above. The Guinevere Gas Field is estimated to contain 90 BCF of recoverable gas reserves and was brought on-stream in June 1993 using a single not-normally-manned minimum facilities platform. Field life is predicted to be 13 years. Gas and condensate are evacuated though the Lancelot Area Production System (LAPS) to the onshore Bacton gas terminal in East Anglia.
The Guinevere Gas Field is located 43 miles (70 km) E of the Humber Estuary and 31 miles (50 km) N of the Norfolk Coast, and lies within Block 48/17b (Fig. 1). The field is a N W - S E trending, compressional, anticlinal fault block that is 3.4 miles (5.5 km) long and 1 mile (1.6 kin) wide, and lies in water depths of 88 ft (27 m) (Fig. 2). Guinevere is a modest gas field reservoired by the Leman Sandstone Formation (Permian Rotliegend Group), with an estimated 100 BCF of gas initially-in-place (GIIP). Two production wells, one re-completed vertical and one horizontal, were drilled on the field, which came on-stream in June 1993. The field was named following the 'Arthurian Legend' convention established by Mobil for its Southern North Sea gas fields.
History
Exploration and appraisal Block 48/17 was awarded to Mobil North Sea Limited (100%) as part of Licence P.025 in the first round of licensing in 1964. Following an unsuccessful well, 48/17-1, Block 48/17b was relinquished in 1970. A Mobil-operated group subsequently re-applied for Block 48/17b as part of the Eighth Licensing Round, and were awarded the block in 1983 under License P.463. In November 1991, Superior Oil U K Ltd. (a wholly owned subsidiary of Mobil North Sea Limited) acquired Gas Council (Exploration) Ltd.'s equity. The
Fig. 1. Regional location map including a detailed map of the Lancelot Area Production System (LAPS).
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 723-730.
723
724
M. LAPPIN ET AL.
Fig. 2. Top Rotliegend depth structure map based on 3D seismic data, showing the line of structural-section and seismic lines. current unit participants are: Mobil North Sea Limited (operator) 25.50%; Superior Oil U K Limited 49.50%; E D C (ISE) Limited 18.00%; EDC (Oilex) Limited 7.00%. The Guinevere Field discovery well, 48/17b-5, was drilled in March 1988 on the crest of a small, 2D seismic-defined horst block, as part of Mobil's 'Lancelot Area' exploration and appraisal programme (Fig. 2). The discovery well encountered a 155ft gas column within the Rotliegend Leman Sandstone Formation, established the field gas water contact and tested gas at a maximum flow rate of 35.1 M M S C F D .
Development Reservoir simulation work suggested that field production rates would be severely constrained by production from only the existing 48/17b-5 well. The Guinevere Field development plan was approved in February 1992, and called for the re-completion of the 48/17b-5 discovery and the drilling of a horizontal production well. The suspended 48/17b-5 well (re-designated 48/17b-G1) was reentered in January 1993, and the horizontal 48/17b-G2 well was drilled within the Rotliegend reservoir, to provide commercial
Fig. 3. Guinevere Field minimum facilities platform. deliverability. The G2 well contacted 3523 ft mD of reservoir sandstone and flowed gas at a rate of 37 M M S C F D . Production commenced in June 1993 using a single, 3-slot not-normally-manned minimum facilities platform (Fig. 3). Gas is exported through the Lancelot Area Production System (LAPS) to the Phillips Petroleum gas terminal at Bacton. New onshore dedicated LAPS Gas Compression facilities came on-stream in October 1998 to further enhance recoverable reserves from the Mobil LAPS gas fields.
Stratigraphy The geological succession in the area of the Guinevere Field is typical of the Southern North Sea (Fig. 4). Lower Permian Rotliegend reservoirs of the Leman Sandstone Formation, representing a continental arid environment, mostly out of dune, interdune and fluvial facies (Fig. 5), were deposited unconformably on Carboniferous
Fig. 4. Seismic line (A-A t ) showing the complex overburden sequence overlying the Guinevere Field.
GUINEVERE FIELD strata of a coal-rich Westphalian sequence which forms the source of gas for the entire UK sector of the Southern North Sea (Glennie 1990). Above the Rotliegend section is the Zechstein Supergroup, which is an intercalated series of carbonates and evaporites representing up to five cycles of marine incursion and evaporation (Taylor 1998). This sequence is overlain by the Lower Triassic Bacton Group. The entire Bacton Group is absent in many places in the Southern North Sea including the area overlying most of the Guinevere Field. These 'Lower Triassic Separation Zones' (LTSZ) are proposed to be the result of tectonic events rather than depositional processes (Fig. 6). The Bacton Group is a homogenous sequence, reflected by clastic sandstone and shale deposition in a progradational fluvial-dominated system, within a semi-arid environment (Ketter 1991). The Bunter Sandstone, being the upper member of the Bacton Group, plays a relatively minor role as a reservoir in the UK sector of the Southern North Sea. The Upper Triassic is a series of shales and evaporates still representing semiarid continental conditions (Geiger & Hopping 1968). The interlayering gives the Upper Triassic a highly reflective seismic character in strong contrast to the seismically 'opaque' Bacton Layer. Lying conformably above the Triassic is the Jurassic, a shaledominated sequence representing the onset of marine conditions
Fig. 5. Guinevere Field generalized stratigraphy and Rotliegend reservoir zonation.
725
and rifting associated with an early and abortive attempt of the opening of the proto-Atlantic Ocean (Rhys 1975). Shallow shelf marine conditions persisted through the Chalk of the Cretaceous, which is frequently separated from the Jurassic, across the area by an unconformity. Conformably above, the Tertiary represents gradual subsidence as part of the present North Sea basin.
Structural history The Southern North Sea, being a mature basin, has been wellstudied and built up a very large database including seismic and well data over the years. The rapid growth of 3D seismic data across the basin in recent years has helped fill many o f the gaps in our understanding of the history of the basin. In particular, the compressive features in pre-Zechstein sequences are now clearly identified with the advent of the state-of-the-art 3D seismic imaging techniques such as 3D Pre-Stack Depth Migration. The Guinevere Field lies along the Dowsing Fault Zone (DFZ) on the western flank of the Sole Pit High (SPH). The SPH began as a depositional basin during the Permian and continued to be a sedimentary depocentre until Cretaceous times when a major inversion occurred (van Hoorn 1987; Walker & Cooper 1987).
726
M. LAPPIN E T AL.
Fig. 7. Detailed seismic-section A-A r illustrating the Guinevere Field structural configuration.
Fig. 8. Guinevere Fields structural cross-section through the Rotliegend reservoir showing the field GWC and structural spill point.
Fig. 6. Schematic evolution of the Guinevere Field and Lower Triassic Separation Zones.
An extensional period of tectonics occurred during the Jurassic period causing reactivation of pre-Permian faults which were then further re-activated during the inversion period associated with the Alpine orogeny. Although faulting at Rotliegend level is dominated by an extensional style, many compressional features are apparent from the inversion event as reactivation of an established structural framework and are likely to be transpressional in origin. For the purposes of this description, the generic term of 'compression' will be used. With improved seismic coverage and imaging, many features are now considered to be compressional in nature. The Guinevere Field is an example of a field now interpreted as being a compressional structure although it may have previously been a normal fault bounded horst or graben becoming a positive flower structure during inversion. The Lower Triassic Separation Zones previously discussed are a distinctive feature of the area for which the authors propose the following model. During the Jurassic rifting, the Bacton Group which would have been a relatively homogenous and competent, slab of rock, was faulted, although with no true linkage with the pre-existing fault pattern affecting pre-Zechstein sequences. In subsequent inversion, the faulted layer of Bacton is proposed to have slid under the influence of gravity down a regionally developed
palaeo-slope, facilitated by detachment layers of Upper Permian Zechstein salt below and Upper Triassic Rot Halite salt above, creating steep-sided linear gaps in the Lower Triassic layer. A similar model of thin-skinned gravity tectonics has been proposed for salt-cored folding in the northwestern part of the Southern North Sea by Stewart & Coward (1995). In areas where there was an abundance of Zechstein salt, the LTSZ were invaded by the passive in-fill of salt to form salt walls (Jenyon & Cresswell 1987). In the part of the basin where Guinevere lies there is not a thick layer of potentially mobile salt, so the LTSZ is in-filled by a dramatic collapse of the overburden (Fig. 6). Salt walls and Mesozoic collapsed grabens form endmembers of the response to LTSZ and variations between these end-members are common in the U K Sector of the Southern North Sea (Lappin et al. 1998).
Trap Guinevere Field is an anticlinal feature approximately 3.4 miles (5.5 km) long and 1 mile (1.5 km) wide, bounded by northwesterlytrending reverse faults following the structural alignment of the basin. The southeastern margin is marked by minor cross-faults whilst the northwestern boundary is dip-closed (Fig. 7). The field's gaswater contact (GWC) at 8599ft TVDss is controlled by the structural spill point that is typical of the Southern North Sea fields of the Rotliegend play fairway (Fig. 8). The accumulation is sealed by the evaporates of the Upper Permian Zechstein Supergroup.
GUINEVERE FIELD
Reservoir description and geological model The Leman Sandstone Formation of the Permian Rotliegend Group constitutes the reservoir for the Guinevere Gas Field. The reservoir is 276ft thick in the 48/17b-5 well and maintains a relatively constant thickness across the field. This also applies to the Lancelot and Excalibur Fields where the Rotliegend Leman Sandstone Formation thickness varies from 230ft to a maximum of 304ft, respectively. The small variation in sediment thickness is interpreted to represent deposition on the relatively stable footwall of the Dowsing Fault Zone (DFZ). The dramatic increase in Rotliegend thickness NE of Excalibur to 550 ft in the Mordred and Galahad Fields marks the structural transition from the DFZ into the Sole Pit Basin The Rotliegend sediments of the Guinevere Field are characterized by aeolian dune and fluvial-dominated sequences that were deposited within a regionally extensive arid to semi-arid desert environment, at the western margins of the Permian Sole Pit Basin, lying between the East Midlands Shelf and the southern edge of the Silverpit desert lake complex. In the Guinevere-LancelotExcalibur province, Rotliegend sedimentation reflected the influence of changes in the groundwater table level, which are considered to have been controlled by climatically induced changes in the level of the Silverpit desert lake (Taylor 1996; George & Berry 1997).
727
ranges from poor to moderate, with the dry interdune sands exhibiting the best reservoir parameters, with average porosities of 13% and permeabilities ranging from <1 to 300mD.
Zone E. Regionally, Zone E signals a climatic return to arid desert conditions with a lowering of groundwater table elevation corresponding to the establishment of major aeolian dune fields across the LAPS area. In the Guinevere Field, this sequence is 115 ft thick and comprises of large scale transverse dune sets and crossbedded packages containing both dune top and dune base sands. Dip-meter data indicates the dominant wind direction was SE to NE (Fisher et al. 1994). These sands are generally fine to coarse-grained, clean and well sorted (often bimodal) with an average porosity of 13.9% and an average geometric permeability of 35 mD.
This zone comprises a thin (7 ft) continuous horizon of reworked, structureless fine-grained sandstones that represent the Weissliegend facies, generated by the reworking of Rotliegend dune sands during the Zechstein marine transgression (Glennie & Buller 1983; Glennie 1998). The homogenized and cemented nature of the Weissliegend sandstones generally results in low porosities and permeabilities. Zone F.
Reservoir zonation Reservoir characterization The Guinevere Field Rotliegend reservoir comprises aeolian dune, interdune, ftuvial-wadi sheet-flood and sub-ordinate playa lake facies units (Fisher et al. 1994). Distinct vertical and lateral facies relationships are recognized throughout Mobil's LAPS Rotliegend gas fields (Fig. 5), and represent a series of drying-upward depositional cycles, comparative to those described by George & Berry 1997. Log correlation, core description and petrographical studies have enabled regional sub-division of the Rotliegend reservoir into six zones (Zones A-E) on the basis of lithology and facies association. The two basal zones, A and B, are not present in the Guinevere area, being restricted to the axis of the Sole Pit Basin and representative of the initial in-filling of the pre-existing Carboniferous palaeotopography. A description of the four reservoir zones in the Guinevere Field from the bottom to the top is given below (Fig. 5).
Zone C. This zone represents the lowermost 76 ft of the reservoir, and consists of fluvial facies, dominated by structureless sheet sands and cross-bedded channelized sands, with minor wet interdune sands. The sedimentary succession is interpreted to have been deposited within NE-SW trending ephemeral fluvial-wadi tracts. The sands are generally poorly sorted and argillaceous, with average porosities of 912% and low permeabilities, due to the presence of detrital clays, ranging from < 1 to 100 mD. Along the northeastern flanks of the Guinevere Field, Zone C lies within the water leg.
Zone D. Both regionally and across Guinevere, the facies associations within Zone D are characterized by the influence of high groundwater table evaluation on sedimentation. The zones tends to be extremely heterogeneous, and in the Guinevere area consist of wet and dry interdune horizons, small scale aeolian dune sands and occasional fluvial sheet sands (Fig. 5). The wet interdune intervals are laterally extensive and form a package that can be correlated across the LAPS area gas field, and are considered to represent a climate change-driven rise in groundwater table, corresponding to the southward expansion of the Silverpit desert lake complex (Taylor 1996; George & Berry 1997). The top of Zone D on a regional basis represents a maximum flooding surface, characterized by the dominance of sabkha facies over dry interdune units, and an absence of aeolian dune sands. Reservoir quality
Two wells have been drilled into the Guinevere Field, the discovery well 48/17b-5, which was subsequently re-completed as vertical development well 48/17b-G1, and a horizontal development well 48/17b-G2. The horizontal well was drilled entirely within Zone E in the crestal region of the field, to ensure that the well encountered the best quality sands whilst maintaining a stand-off of at least 75 ft above the Guinevere Field GWC at 8599 ft TDVss. A horizontal section of 3532ft was drilled within the Rotliegend, with the trajectory controlled to exit top reservoir at the toe of the well in order to give additional control point on the top Rotliegend structure (Fisher et al. 1994). Electric wireline logs were run in both the vertical well and the horizontal well. The vertical 48/17b-5 (G1) well encountered a 155ft gross gas column, and proved the field GWC at 8599ftTVDss; this was corroborated by wireline induction and RFT data. Within the gas leg of the vertical well, log interpretation indicates a very high net/gross ratio of 99% using a single net reservoir cut-off criterion of shale >50%, with an average porosity of 13.9% as computed from the Bulk Density Log, and as average water saturation of 35% as computed using the Archie equation with a, m and n exponents of 1.0, 1.83 and 1.79 respectively, derived from special core analysis. The 48/17b-G2 horizontal well targeted Rotliegend Zone E and encountered even higher quality sands, with porosities generally higher and water saturations generally lower than the vertical well. Core was recovered from most of the Rotliegend formation in vertical well 48/17b-5(Gl). Conventional and special core analysis indicate that the gas-bearing sandstones of Unit E comprise good quality aeolian dune base and dune top facies. Core porosities lie in the range of 10 to 17% with an arithmetic average of 13.9%. Core horizontal permeabilities to air lie in the range of 7 to 300 mD with a geometric average of 35 mD. After further correcting for relative permeability effects, this average core-derived permeability is in good agreement with the permeability value of 20 mD derived from well test interpretation on well 48/17b-5. Within the water leg, reservoir quality is more variable with horizontal air permeabilities that range from 0.1 to 300 mD, with a geometric average of 13 mD. These core results incorporate corrections from laboratory measurements at ambient conditions to compaction-corrected values at the effective reservoir overburden stress of 4000 psi, using the following relationships:
728
M. LAPPIN E T AL. 40
Poro8 4000 ---~ 0.932 x POramb PermoB 4000 = - l 0* * [ ( 1.5162*Log Permamb) -- 0.58067] for Permamb in range 0.01 to 10 mD
35
JB 8 w
PermoB 4ooo = 10**[(1.0942*Log Permamb) -- 0.299] for Permamb greater than 10 m D An RMS regression of the compaction-corrected core data indicates the following relationship between core porosity and core permeability: Log PermoB 4000 : ,3.3026 + 0.33536PoroB 4000 (where PoroB 4ooo as a percentage)
30
al
M=
_=E eP
"o .2
lO
I,i.
5
Source
1993
1994
1995
1996
1997
1998
Year
The hydrocarbons of the Guinevere Field are sourced from the Late Carboniferous, Westphalian-age coals of the Conybeare Group (Cameron 1993), which lie directly beneath the Rotliegend. Burial history reconstructions suggest that the Carboniferous coals reach peak gas maturity during the Jurassic to Early Cretaceous, which also corresponds to the maximum depth of burial of the Rotliegend. The Guinevere-Lancelot-Excalibur Field structures were charged during the Middle-Late Cretaceous gas migration phase, and were supplemented by migration and charging that continued through into the Tertiary.
Fig. 9. Guinevere Field historical production rates.
yield based upon allocated sales quantities at the Bacton terminal is 13 stock tank barrels per M M S C F of sales gas, which compare with a condensate/gas ratio measured during drill stem testing of the discovery well 22-b separator barrels per M M S C F of gas. To date, the wells have produced no formation water, with only small quantities of condensate being produced at a rate of around 0.5 separator barrels per M M S C F of gas.
Hydrocarbons The Guinevere Field contains sweet, dry gas. An analysis of the recombined reservoir gas composition is given in Table 1. The composition of the reservoir gas is similar to that of the surrounding LAPS area fields, and shows a general trend of gas composition becoming leaner from the SW to the N E across the LAPS area. The specific gravity of the reservoir gas is 0.710 (relative to air which equals one). The pseudo-critical temperature and pressure of the reservoir gas are 378~ and 658 psia, respectively. The initial reservoir pressure and temperature are 4000psia and 198~ at the datum depth of 8550 ft TVDss. At these initial reservoir conditions, the gas viscosity is 0.0218 cp, the gas deviation factor (z) is 0.9371, and the gas expansion factor is 230 SCF/RCF. The condensate
Table 1. Guinevere recombined reservoir gas composition
Reserves and production Production from the Guinevere Field commenced in June 1993 and by the end of 1998 the field had produced 55 BCF of gas. A historical production rate profile is shown in Figure 9. The evolution in estimates of proved plus probable gas initiallyin-place (GIIP) is shown in Figure 10. At the time of Annex 'B' submission, the GIIP was estimated to be 104 BCF based upon the best-estimate structural map and reservoir properties. Although the method of estimation has since changed to material balance based upon the pressure decline observed in the production wells, the estimated GIIP has remained more or less constant over time and now stands at just over 100 BCF. The p/z plot from which this value was derived is shown in Figure 11. A Havlena-Odeh material balance analysis is also shown in Figure 12. Although this shows an early time response, which is often interpreted to indicate aquifer
(Mol%) 140
Nitrogen Hydrogen sulphide Carbon dioxide Methane Ethane Propane Iso-Butane N-Butane Iso-Pentane N-Pentane Hexanes Heptanes Octanes Nonanes Decanes Undecanes Dodecanes + Total
3.17 0.00 0.59 85.16 5.61 2.01 0.42 0.63 0.28 0.24 0.34 0.45 0.29 0.19 0.14 0.10 0.38 100.00
120
1001
=
so
6o
40
~
--,B'-- Estimated
l
~
gas initially-in-place
Estimated ultimate recoverable
2O 0 Year
Fig. 10. Evolution in GIIP and URR estimates.
resources
]
GUINEVERE FIELD
729
4500 4000 3500 3000 "~
2500
•a.
2000 1500 1000 500 0 0
20
40
60
80
100
Gp (bcf)
Fig. 11. Guinevere Field p/z plot.
120 100
k 80
l i
mmmmm mm []
9
i N
9 .
m~
9
O1
l,IJ ,,-p 60
20
I
I
I
I
10
2O
3O
4O
Gp (bcf)
Fig. 12. Guinevere Field Havlena-Odeh material balance plot.
influx, time-lapse T D T logging has shown that the g a s - w a t e r contact in the vertical well has not moved. This suggests that the field is u n d e r g o i n g simple volumetric pressure depletion, with no active aquifer drive, and that the H a v l e n a - O d e h pressure response in early time tends to underestimate the G I I P being drained. The H a v l e n a - O d e h plot has since stabilized at G I I P level of just over 100 BCF, in close agreement with the p/z plot. The estimated recovery factor for the Guinevere Field has increased from 70% at the time of Annex 'B' approval, to a current estimate of 90%. This increase is due to better-than-expected reservoir properties e n c o u n t e r e d in the horizontal d e v e l o p m e n t well drilled after the A n n e x 'B' was submitted, and to the installation of larger LAPS Gas C o m p r e s s i o n facilities in 1998 than envisaged at the time of A n n e x 'B' submission, which will significantly reduce the field's ultimate reservoir a b a n d o n m e n t pressure. The current estimate of ultimate recoverable resources ( U R R ) stands at 90 BCF. By the end of 1998, some 55 B C F (61% of U R R ) have been produced.
The authors wish to thank the management of Mobil North Sea Limited and EDC Limited for their permission to publish this paper. The authors have drawn on the knowledge and work of colleagues from the Southern North Sea Asset Team, and we extend our appreciation to all of those within Mobil who have previously worked on the LAPS gas fields, without whose efforts this paper would not have been possible.
50
Guinevere Field data summary Trap Type
Depth to crest GWC FWL Datum depth Gas column Pay zone Formation Age Gross thickness Net/gross ratio Average gas saturation Porosity average (range)
Fault bounded horst structure with reverse fault closure to the NE and SW plus dip closure to the NW and SE. 8150 ft TVDss 8599 ft TVDss 8606 ft TVDss (from RFT) 8550 ft TVDss 449 ft
Leman Sandstone (Rotliegend) Early Permian 276ft (gross pay thickness in 48/17b-5 well) 0.99 (net-sand cut-off Vshale > 50%) 64.9% 13.9% (10% to t7%) (compaction-corrected core values 48/17b-5) Permeability average (range) 20 mD from well test interpretation (7 to 300 mD from core) 0.095/0.719 MMSCFD/psi Productivity index (48/t7b-G1 vertical well/48/17b-G2 horizontal well transient PI after 60 hours
730
Hydrocarbons Gas type Gas gravity Gas viscosity Gas expansion factor Condensate yield
Formation water Salinity Resistivity
M. LAPPIN E T AL.
dry gas 0.71 0.0218 cp (at initial reservoir pressure) 230 SCF/RCF 13 STB/MMSCF (from production data. Initial well test indicated 22 BBL/MMSCFD)
159 000 ppm NaC1 equivalent 0.057Ohm.m @ 60~ (equivalent to 0.019 Ohm.m @ 198~
Field characteristics Area Gross rock volume Initial pressure Initial pressure gradient Temperature Gas initially-in-place Recovery factor Drive mechanism Recoverable Gas Recoverable NGL/condensate
1280 acres 121333 acre-ft 4000psia at datum depth of 8550ft TVDss 0.087psi/ft (gas leg) 198~ at datum depth of 8550ft TVDss 100 BCF 90% pressure depletion 90 BCF 1.2 MMBBL
Production First gas Production rate plateau gas Number/type of well
June 1993 30 M M S C F D 1 vertical and 1 horizontal producer
References CAMERON, T. D. J. 1993. Carboniferous and Devonian of the Southern North Sea. In: KNOX, R. W. O.'B. & CORDEY, W. G. (eds) Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. FISHER, W. C., BOND, D. J., SKEITH, G. L., BONNETT, N. & GADGIL, A. G. 1994. Targeting the Guinevere Horizontal Well. A Case Study Involving Geostatistics, Reservoir Description, Reservoir Simulation and Drilling Engineering. European Petroleum Conference, London, 2527 October, SPE paper 28879. GEIGER, M. E. & HOPPING, C. A. 1968. Triassic Stratigraphy of the Southern North Sea Basin. Philosophical Transactions of the Royal Society, London, Series B, 254 (790), 1-36.
GEORGE, G. T. & BERRY, J. K. 1997. Permian (Upper Rotliegend) synsedimentary tectonics, basin development and paleogeography of the southern North Sea. In: ZIEGER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea." Future Potential. Geological Society, London, Special Publications, 123, 31-61. GLENNIE, K. W. 1990. Rotliegend sediment distribution: a result of Late Carboniferous movements. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, LONDON, Special Publications, 55, 127-138. GLENNIE, K. W. 1998. Lower Permian-Rotliegend. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea: Basic Concepts and Recent Advances. 4th Edition. Blackwell Scientific Publications, London, 137-173. GLENNIE, K. W. & BULLER, A. T. 1983. The Permian Weissliegend of NW Europe: the partial deformation of Aeolian dune sands caused by the Zechstein transgression. Sedimentary Geology, 35, 43-81. 1991. Guinevere Field Development, UK North Sea Block 48/17b-Annex B. Volumes 1-3. Unpublished Mobil North Sea Limited Internal Report. JENYON, M. K. & CRESSWELL,P. M. 1987. The southern Zechstein salt basin of the British North Sea, as observed in regional seismic traverses. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of NWEurope. Geological Society, London, 277-292. KETTER, F. J. 1991. The Esmond, Gordon and Forbes fields, Blocks 43/8a, 43/13a, 43/15A, 43/20a, UK North Sea. In: ABBO'rTS, I. L. (ed.) United Kingdom Oil and Gas Fields', 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 425-432. LAPPIN, M., CLUTSON, M. J., DALWOOD, R. E. T. & ANDERSON, A. 1998. The role of Late Permian-Triassic salt in extensional and compressional tectonics of the UK Southern North Sea. Journal oJ Seismic Exploration, 7 (3/4), 407-410. RHYS, G. H. 1975. A proposed standard lithostratigraphic nomenclature for the southern North Sea. In: (ed.) Petroleum and the Continental Shelf of North-west Europe. John Wiley & Sons, New York, 151-163. STEWART, S. m. & COWARD, M. P. 1995. Synthesis of salt tectonics in the southern North Sea. UK Marine and Petroleum Geology, 12(5), 457-475. TAYLOR, B. D. 1996. Unpublished Mobil North Sea Limited Internal Report. TAYLOR, J. C. M. 1998. Upper PermianZechstein. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea." Basic Concepts and Recent Advances. 4th Edition. Blackwell Scientific Publications, London, 174-211. VAN HOORN, B. 1987. Structural evolution, timing and tectonic style of the Sole Pit inversion. Tectonophysics, 137(1-4), 239-284. WALKER, I. M. & COOPER, W. G. 1987. The structural and stratigraphic evolution of the north-east margin of the Sole Pit Basin. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology q f N W Europe. Geological Society, London, 263-275.
The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields P. C O O K E - Y A R B O R O U G H
& E. S M I T H
Phillips Petroleum Company United Kingdom Limited(UK) Ltd, Phillips Quadrant, 35 Guildford Road, Woking, Surrey G U22 7Q T, UK Present address." ConocoPhillips ( UK) Ltd, Rubislaw House, Anderson Drive, Aberdeen AB15 6FZ, UK (e-mail.
[email protected])
Abstract: The Hewett Fields complex, discovered in 1966, is located in the southwestern part of the Southern North Sea Basin. Gas is currently being produced from four horizons: Upper and Lower Bunter sandstones in the Triassic, Rotliegendes sandstones, and Zechstein dolomites in the Permian. Seven fields, containing a total of ten reservoirs, lie within the Hewett Unit and all have a NW-SE orientation. Gas flows, via two 30-inch (0.76m) pipelines, to the ConocoPhillips-operated Bacton terminal, where onshore compression facilities are located. There are also compressors located on two platforms. Over 4 TCF (113 billion cubic metres) of gas has so far been produced in over 30 years of production. Location The Hewett Unit straddles five blocks: 48/28a, 48/29, 48/30, 52/4a and 52/5a and, at its southwestern margin, lies about ten miles (16 kms) NE of the Norfolk coast. Figure 1 shows the distribution of the 10 Hewett Unit hydrocarbon accumulations. Figure 2 is a location map of the Hewett Unit, indicating its position within the Southern Gas Basin. Seven fields, containing a total of ten reservoirs, lie within the Hewett Unit, established in 1969 by the signing of an Unit Agreement between the Phillips and Arpet groups. Current interests in the Hewett Unit Area are as follows: Phillips Petroleum Company United Kingdom Limited (Operator) 18.97%; Agip (UK)
Limited 18.82%; A R C O British Limited 19.85%; Fina Exploration Limited 18.57%; Lasmo North Sea plc 8.53%; Superior Oil (UK) Limited 10.69%; Veba Oil and Gas U K Limited 4.58%. The main Hewett gas field, the largest in the Unit area, comprises three co-extensive reservoirs;, the Upper Bunter sandstone, the Lower Bunter or Hewett sandstone, and the Zechstein carbonates. The field has the shape of a flattened ellipse, aligned N W - S E , has a length of 18 miles (29 km), a maximum width of three miles (5 kin), and lies within all five Unit blocks. The North Hewett gas fields lie in blocks 48/29 and 48/30, to the NE of the main Hewett gas field. Deborah, Big Dotty, Dawn, Della and Delilah are Rotliegendes sandstone (Leman Sandstone)
Fig. 1. Hewett Unit area fields and discoveries. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 731-739.
731
732
P. COOKE-YARBOROUGH & E. SMITH
Fig. 2. Location map of the Hewett Unit. reservoirs, whilst Little Dotty has both Upper Bunter and Rotliegendes sandstone reservoirs. The Hewett Field derives its name from a nearby seabed feature known as the 'Hewett Ledges'. This choice of name is unusual for Phillips-operated fields in the UK North Sea which have been named, in general, after geoscientists' wives or daughters. The designated initial letter for all other prospects and fields in this licensed area have the initial letter 'D', giving rise to the Deborah, Della, Dotty, Dawn and Delilah field names. Hewett is the closest producing field to shore, the southwestern part of the Hewett Unit being approximately 10 miles (16km) from the Norfolk coast in the United Kingdom North Sea Southern Gas Basin, and has an average water depth of approximately 120 ft (37 m).
History and discovery method Licence P.028 (241268 gross acres/97641 hectares), for which Phillips Petroleum Company United Kingdom Limited ('Phillips')
is the operator, contained a total of seven blocks designated 47/4a, 47/5a, 48/10a, 48/30, 49/6a, 49/11a and 52/5a. comprising 241,268 gross acres. Licence P.037 (181 128 gross acres/73 303 hectares), for which Arco British Limited is the operator, was also awarded in the First Round of licensing (1964) and covered blocks 48/1 l a, 48/28a, 48/29 and 49/28. Licence P. 112 (15 394 gross acres/6230 hectares), which covered Block 52/4, was subsequently acquired in 1970 on behalf of the Hewett Unit, for which Phillips is the designated operator. The 48/29-1X Hewett Field discovery well, located on an early Southern North Sea seismic survey (Fig. 2), was drilled by Arpet (now Arco British) in the second half of 1966 and reached total depth (TD) at 7288 ft (2222m) below kelly bushing (RKB) in the Carboniferous. The Upper Bunter sandstone was encountered at 3034ft (925m) RKB and, on a drill stem test of the uppermost 15ft (4.5m), produced gas at the rate of 18.1MMSCFD (510 km 3 d -1). The Lower Bunter, or Hewett, sandstone, encountered at 4178ft (1274m) RKB, flowed gas at the rate of 23.4 MMSCFD
HEWETT FIELDS (660 km 3 d -1) from a 10 ft (3 m) perforated interval. A follow-up well, 48/29-2X, confirmed the continuity of both these two Triassic gas accumulations. It was the drilling of the 52/5-1X well by Phillips, however, some nine miles (14 km) SE of the 48/29-1X well, which gave final confirmation that a field of very significant size had been discovered. By March 1967, a total of seven wells had been drilled along the long axis of the Hewett Field. Subsequently, a further 23 wells have been drilled from three fixed platforms within the Hewett Field: eight each from the 48/29-A and 48/29-B platforms and seven from the 52/5a-A platform. Beneath each platform, the deviated well bores are some 900 ft (274 m) distant horizontally from the centre of the cluster at Upper Bunter sandstone level, and some 1500 ft (457 m) distant in the Hewett, or Lower Bunter, sandstone. In 1968, sales contracts were signed with the then named Gas Council and a 30 inch (0.76 m) trunkline linking the Bacton Plant with the Field Terminal Platform was laid. The Lower Bunter (Hewett) sandstone reservoir of the Hewett Field was put into production on 12 July 1969, less than three years from the spudding of the discovery well. Desulphurisation equipment was installed at Bacton in September 1973 and Upper Bunter sandstone sour gas production from re-completed wells on the 52/5a-A platform commenced shortly thereafter. Onshore compression to maintain the gas supplied to the Gas Council distribution system at 1000 psia (6.9 MPa) has been operational since August 1973. Offshore compression has been installed on the 52/5a and 48/29A (1989) and 52/5a (1995) platforms. The 48/29A compressor was re-wheeled in 1998, as the Lower Bunter reservoir pressure dropped, to enable an additional 12 BCF (340 Mm 3) of reserves to be produced. In March 1993, a new 48/29A quarters platform was commissioned. Exploration of the North of Hewett area followed immediately after the discovery and appraisal of the Hewett Field itself. Three more fields: Big Dotty, Deborah, and Little Dotty, were discovered initially and production from them began in 1976, 1978 and 1979, respectively. Della was discovered in 1987 and began producing in 1988. Dawn Field began producing in 1995 and Delilah in 1998, within a then record time of nine months from discovery.
733
Production from the Zechstein carbonates began in 1986 from the 52/5a-A11 well with gas from the first cycle (Zl) Zechsteinkalk. A second well, 52/5a-A12, and acid 'frac' stimulation of 52/5a-A11, substantially increased gas production from the Zechstein in 1989. These wells were followed by a further four wells drilled from the 52/5-A platform, one from the central 48/29-A platform and three from the northwest 48/29-B platform. One of the 48/29-B platform wells, 48/29-B9, failed to produce at economic rates from the Zechstein. A small underlying Rotliegendes accumulation with an oil rim, however, was penetrated by the well. It produced for two years prior to it 'oiling' out. Currently, nine wells produce from the Zechstein carbonates. Long before fixed platform drilling started in December 1967, however, the Arpet and Phillips Groups had been aware that unitization of their respective interests would do much to assure the efficient and economic development and exploitation of the field. With this end in view, negotiations were initiated in April 1967 and culminated in April 1969 with the signing of a Unit Agreement. The Phillips Group equity was fixed at 54.2% and the Arpet Group equity at 45.8% from these discussions, with no provision being made for re-determination.
Structure The general NW-SE strike of structures in the Hewett Unit area is an inherited Hercynian structural trend, and possibly pre-Caledonian as well. The Dowsing Fault Zone and South Hewett Fault represent the reactivation of actual Hercynian faults. The relatively small, but significant, difference in the trends of the Dowsing Fault Zone and South Hewett Fault represent the orientation of the Hercynian structures at depths from which the Permian and Mesozoic fault systems have developed. The pre-Hercynian Fault System was dominantly extensional until the late Carboniferous. The Hercynian Orogeny caused relative northward movement of the London-Brabant Massif, resulting in right-lateral transpression across the NW-SE trending fault system along the NE margin of the massif. The Dowsing Fault Zone and South Hewett Fault were,
Top Bun~r
Top Zechstein Plattendolomite Top Zechsteinkalk Top Rotliegendes
Fig. 3. Seismic section across the main Hewett field.
734
P. COOKE-YARBOROUGH & E. SMITH
thus, part of an extensional Carboniferous fault system placed in transpression during the Hercynian Orogeny. Minor movements occurred on the Dowsing Fault Zone during the late Permian. The South Hewett Fault and Dowsing Fault Zone, including the North Hewett Fault, underwent extensional/transtensional movement during the late Triassic to the end of the Jurassic. The Hewett anticlinal structure formed during the late Cretaceous and tightened during the Oligocene as a result of reverse movement on the South Hewett Fault. Figure 3 is a seismic section across the main Hewett field. Figure 4 demonstrates the structural configuration of the Hewett Unit fields with a series of schematic cross-sections across the Hewett Unit area.
Stratigraphy Figure 5 shows a generalized stratigraphical section for the Hewett Unit area. During the Westphalian (late Carboniferous), the area occupied a marginal position on an extensive coastal plain that developed to the north of the London-Brabant Massif. With prolonged paralic conditions, very thick coal-bearing sequences were deposited. These sequences contain the source rock that generated the gas found in the Hewett Unit fields. Rotliegendes sedimentation commenced during the early Permian in a desert environment as the uplifted Carboniferous areas were slowly being eroded. The Rotliegendes increases in thickness towards the NE across the Hewett Unit from 450 ft (137 m) to over 700ft (213m). The earliest Rotliegendes sediments consisted of
Fig. 4. Schematic cross-sections across the Hewett Unit area.
fluvial/wadi sands formed by sheet-flood deposits draining off the London-Brabant Massif to the south. These gave way to minor, interbedded intervals of wind-blown sands and eventually dune sands prograded across the entire area. As a result, the upper twothirds of the Rotliegendes consists of thick dune sequences. Within the Hewett area, the top of the Rotliegendes lies at a depth of between 5000ft (152m) and 7000ft (2134m) and slopes NE towards the centre of the Rotliegendes basin. Desert conditions were brought to an abrupt end when the Rotliegendes basin was flooded by marine waters of the Zechstein Sea. The base of the Zechstein is well marked by the Kupferschiefer shale and is overlain within the Hewett Unit area by four carbonate/ evaporite sedimentary cycles, Z l-Z4. Each cycle commences with a phase of marine transgression followed by one of regression and, in general, reflects the influence of an increase in salinity. In the complete case, each cycle would consist of a thin clastic member passing successively upward into limestone, dolomite, anhydrite and halite. This cyclicity is generally well developed within the Hewett Unit area, with the exception that Cycle 4 is present only in a very condensed form. The close of the Permian saw the end of widespread marine sedimentation and a return to the dominantly non-marine depositional environments of the Triassic. At the end of the Zechstein, minor uplift of the London-Brabant Massif followed by erosion led to the local development of the Lower Bunter (Hewett) sandstone within the Brockelshiefer Member. This sandstone is extremely limited in extent and rapidly thins from 200 ft (61 m) thick over the Hewett Field to 20 ft (6 m) thick in the North Hewett fields. The Lower Bunter sandstone is overlain by the Bunter shale, an anhydritic red-brown mudstone with minor, greenish shales deposited in a floodplain environment.
HEWETT FIELDS
735
Fig. 5. Hewett Unit area generalized stratigraphic section.
Fine-grained clastic sedimentation was brought to a halt with the abrupt deposition of the Upper Bunter sandstone, probably initiated by further uplift of the London-Brabant Massif. Thick fluvial channel and sheetflood sands were deposited and basin-wide subsidence results in uniformly increasing thickness to the NE. In the Upper Triassic, marine conditions were re-established with the thin Rot clay being deposited within the area as a basal transgressive unit. During the ensuing period of tectonic stability, Haisborough Group deposition took place in a floodplain environment, alternating with coastal sabkha or shallow marine conditions. Following the Rhaetic transgression, clays and a sand unit derived from the uplifted London-Brabant Massif were deposited. Marine conditions persisted into the Jurassic and sedimentation was essentially continuous from the Lower Jurassic. Thin sands and limestones were deposited in the Middle Jurassic but more stable marine conditions, accompanied by a deepening sea, resumed in the Upper Jurassic. Sedimentation continued in the Upper Jurassic/Lower Cretaceous with the deposition of the Spilsby sand, sourced from a recently uplifted area to the NE of the Sole Pit Axis. With the continuation of passive sedimentation, there commenced a major period of regional
subsidence and marine incursion. For the first time, the L o n d o n Brabant Massif was submerged in the Upper Cretaceous. Over much of the Hewett Unit, chalk is present at the seabed.
Trap The trapping mechanism in the main Hewett Field is entirely structural. Figure 6 shows the top Upper Bunter surface, depicting the shape of the main Hewett Field and the Little Dotty Field faulted anticline. Also shown on this map are outlines of the North Hewett Rotliegendes accumulations. The three co-extensive reservoirs in Hewett are contained in an anticline, which is aligned N W - S E and bounded by faults on its NE and SW flanks. The NW-trending alignment of the structure at all three levels is similar to other productive fields in the Southern North Sea. It is probable that the post-Silurian Caledonian movements in the area of Kent and East Anglia were related to those of the mid-European belt, all of which produced folds with a N W - S E alignment. These younger features may be later manifestations of such an earlier trend. The main
736
P. COOKE-YARBOROUGH & E. SMITH
Fig. 6. Hewett Unit: top Upper Bunter depth map.
folding associated with the Hewett structure occurred contemporaneously with normal faulting in Upper Cretaceous times. In the North of Hewett fields, the key structural events commenced with the development of the NW-trending Dowsing Fault Zone during the Carboniferous with dominant right lateral wrench movement. This was followed by local syndepositional movement along NW-trending faults in the early Permian with subsequent minor NW faulting at the close of the Permian. Initial development of the Big Dotty and Little Dotty structures occurred during the early Triassic in response to movement along the Dowsing Fault Zone. These faulted anticlinal blocks lie at an oblique angle to the wrench zone. Almost certainly the structure was modified during the Cimmerian and Alpine/Sole Pit movements. Major syndepositional faulting in the Jurassic paved the way for the thickness variations seen across the area. Major folding and faulting occurred in the Hewett area during the Sole Pit inversion period and both the Hewett Graben and the Deborah and Della structures were formed at this time. All of the Hewett accumulations are essentially filled down to, or near to, their respective spill points. The Rotliegendes reservoir sands in the North Hewett Fields are generally sealed by both the Zechstein salts and the lower, non-porous limestones of the Zechsteinkalk. However, in the main Hewett Field area nearer to the depositional edge of the palaeo-Zechstein sea, these Zechstein salts are thinner and the Zechsteinkalk has a better developed reservoir quality matrix and fracture permeability. As a result, the main
Hewett Rotliegendes structure is not gas filled, except for a very small accumulation at the top of the structure, which shares the same gas-water contact as the overlying Zeichsteinkalk reservoir. The Rotliegendes and Zechsteinkalk gas accumulations are sealed by overlying and adjacent Zechstein evaporites. The Lower and Upper Bunter sand-stone gas accumulations are sealed, both vertically and laterally, by the overlying Bunter shale and Dowsing Dolomite Formations.
Reservoir Although the Hewett Unit is divided into the 'North Hewett' and 'Hewett' areas from a gas sales contract perspective, geologically the area is divided by the Dowsing Fault which runs NW-SE. The Deborah, Della and Delilah fields are to the NE of the fault, whilst all the other reservoirs are to the SW. The sandstone reservoirs SW of the Dowsing Fault all enjoy very good reservoir properties, porosity of around 20% and permeabilities ranging from several hundred milliDarcies to over one Darcy. In all three productive sands, Upper Bunter, Lower Bunter, and Rotliegendes, aquifer depletion occurs away from the producing reservoirs. Communication/flow has been observed, in all three horizons, around and/or across the North Hewett Fault. This splay, off the Dowsing Fault, has throws of up to 600ft (183m), and separates the Big and Little Dotty reservoirs from the main Hewett Field. This communication is most remarakable, particularly for the
HEWETT FIELDS Lower Bunter sand, which thins to only 30 ft (9 m) northeastwards away from the main Hewett reservoir. This extensive aquifer communication provides the potential for strong aquifer support to both the Upper Bunter and Rotliegendes reservoirs, where the sand thickness is relatively constant across the Unit. The Rotliegendes reservoirs NE of the Dowsing Fault have lower porosities and permeabilities, ranging from about 50mD in the Deborah reservoir to under 10roD in the most northeasterly field, Delilah. These poorer properties are believed to be due to a deeper maximum depth of burial. Furthermore, faults between the reservoirs also appear to be good seals. The Deborah reservoir started production in 1979, but no depletion was observed in the Della Field, drilled in 1987, or in the Delilah Field, drilled in 1997. Aquifer support to these reservoirs is, therefore, likely to be limited. Within the Rotliegendes reservoirs, well tests conducted on the more recent wells, Dawn (48/29-9), Little Dotty (48/30-15z) and Delilah (48/30-16), have indicated a high density of small, subseismic, parallel faults, inferred to be parallel to the main NW-SE faults trends. Perpendicular to these small faults, the permeability is significantly reduced. The well tests also showed very low vertical permeability, which requires both synthetic and antithetic faulting to be present. Such permeability reductions do not seriously affect the productivity of wells drilled in the good quality sandstone SW of the Dowsing Fault. However, in both the Big and Little Dotty reservoirs, which are tilted faulted anticlines adjacent to the Dowsing Fault, the minor faulting has allowed wells drilled away from the Dowsing Fault to water out, whilst areas nearer the main fault remained dry. The successful 48/30-15z well, drilled in 1996 near the Dowsing Fault, found only a 30ft (9m) rise in the gas-water
Fig. 7. Hewett Unit: burial history/gas generation.
737
contact, although the previous Little Dotty Rotliegendes producer, 48/30-9, had watered out in 1986. Pressure data indicates that, every few miles/kilometres, there are probably some barriers in the Rotliegendes, orientated WSW-ENE. Although they are not easily observed seismically, these de keyser lineaments were originally highlighted via ER-Mapper images of 3D seismic horizons. These faults would explain the absence of any pressure communication between the Big and Little Dotty reservoirs. The Zechstein carbonate reservoir has much lower permeability than the underlying Rotliegendes sandstone. Typically, rock matrix porosity is around 6%, with a permeability of around 1 mD. Matrix properties are best in the southeastern part of the field, drained by the 52/5a platform wells. Away from this area, some better quality matrix may still be found but poorer quality matrix becomes more dominant and the continuity of the better quality matrix deteriorates. Throughout the Zechstein reservoir, fracture permeability is important. For example, in the 52/5a area, pressure interference via a fracture network was observed between wells about one mile (1.6 km) apart within about 24 hours. In the north-western 48/29-B area, the fracture network provides most of the connectivity between the more isolated patches of better quality matrix. Unfortunately, when this area is produced, water and oil influx into the fracture network seriously reducing its ability to provide connectivity for gas. For example, the 48/29-B10 well saw an order of magnitude reduction in overall permeability due to the fractures becoming blocked with oil and water. In the 52/5a area, this effect is not seen, due to the better matrix continuity and the fracture network being kept gas filled by imbibition of oil and water matrix.
738
P. C O O K E - Y A R B O R O U G H & E. SMITH
r~
O
O
e~
',,O ~
0
OO I[-~, tr k.O .,~. OO O r C",l k.O
O
t~., ~t"
,,~
17-., ~ OO t"'q
[.--., ~ OO C'q
t"q kid
,'~
O
oo
17"--
h~
rm
=o
O
O", O", ~
0
<
C,,I
O ~.~ r
O o
O", O
I[-.~, 17~,
OO r162 .,.~
~",100
O
"~"
O
OO
<
OO O", C',I
o~:
~
oo
oo
OO
O
oo~ ~
O
O
',.tD
kid
O
=o
O
.4-,
,-..
~oooo .<
,,o
.~-
h~
O O O
O
O OO
r
.'~-~o ~~ O~o ~ oo
~ ~ o
oo
N
~ 9 o~
r
oo
tr
O
~N
O
~t"
o
2
z~
tr ~
~
~
,-.~
r,~
e'~
O
~ r
O oO
O O
O O
w"~ e q OO O C',l
,~
O O
OO O
'~=~
~~
r~
=o O
~
O O O O e q ~,1 ',.ID '~1- O
O
Cxl
,--o
m
O
.,-.~ OO
~~o=
~ <~
o
o
~
~
.~
~
-~
~
~
,--, ~,
HEWETT FIELDS
Hydrocarbon source Based on geological and geochemical data, the late Carboniferous Westphalian Coal Measures are considered to be the primary source of the gas found in the Hewett fields. This has been corroborated by C-isotope studies. It is probable that the initial gas migration period was contemporaneous with gas generation. The burial history of the basin infers initial generation towards the end of the Jurassic, when the gas migrated upwards via faults cutting the Carboniferous. Figure 7 summarizes the timing of the formation of the Hewett Field structures and the generation of the gas which fills them. The major distinction between the gas of the Upper Bunter sandstone reservoir and that of the Lower Bunter sandstone is the presence in the former of hydrogen sulphide. The hydrogen sulphide is most probably derived from the action of sulphate-reducing bacteria on anhydrite in the presence of hydrocarbons, with carbon dioxide and nitrogen liberated as a by-product of this process. The average carbon dioxide and nitrogen content of the Upper Bunter sandstone gas is four times greater than that in the Lower Bunter sandstone. The likeliest source for the anhydrite is in the Triassic Haisborough Group sediments. Faulting has served to bring these beds into juxtaposition with the Upper Bunter sandstone on the north side of the Hewett Field.
Hydrocarbons Fields of the Hewett area contain dry gas, with the Upper and Lower Bunter sands of the main Hewett field having liquid/gas ratios of 4.8 and 3.2 BBL/MMSCF (27 and 18 m3/Mm3), respectively. These two reservoirs contain gas of strikingly different compositions; in addition to the differences in the hydrogen sulphide content, the Upper Bunter contains significantly more nitrogen than the Lower Bunter. In the small 48/29-B Rotliegendes accumulation under the main Hewett Zechstein i:eservoir, a waxy oil rim was encountered. Waxy condensate has also been observed generally from the Zechstein wells, indicating that the waxy oil is present below the whole Zechstein reservoir. The separate fields of Hewett were normally pressured reservoirs prior to production, lying on a water gradient to surface of 0.46psi/ft. The reservoir gas gradient averages 0.07 psi/ft.
739
losses due to water influx. During the late 1980s, there was a significant risk that the entire Upper Bunter reservoir was about to water out. However, after production from the Little Dotty Upper Bunter reservoir, which shares a common aquifer, started in 1986 the water influx slowed and, by 1990, had effectively stopped. Both onshore and offshore compression is being used to maximize depletion of these reservoirs. The reservoir pressure of the Lower Bunter is now <100psia (0.7 MPa), which is only 5% of the initial pressure of 2000psia (13.8 MPa). The smaller reservoirs to the SW of the Dowsing Fault have been more seriously affected by aquifer influx. The Little Dotty Upper Bunter reservoir has now watered out, with an estimated recovery factor of 75%. By the end of the 1980s, both the Big Dotty and Little Dotty Rotliegendes reservoirs had effectively watered out, with only one well, 48/29-C3, in Big Dotty struggling to produce about 12 M M S C F D (340km3d -1) of gas, along with several thousand barrels of water per day. This well continued to produce until the end of 1993. In 1994 and 1996, wells 48/29-C5 and 48/30-15z were drilled to produce undrained gas from Big and Little Dotty fields, respectively. These wells have increased the recovery from these two fields by about 15%, with the 48/30-15z well still producing at over 30 M M S C F D (850km3d-1). Potential still exists, especially in Little Dotty and SE Della, for the recovery of additional undrained reserves from infill drilling. Although Dawn is surrounded by the Big and Little Dotty fields' aquifer, local faulting appears to be restricting the aquifer influx. Both vertical and horizontal permeabilities are reduced by the faulting, reducing the gas-water contact rise near the faults. Northeast of the Dowsing Fault, the reservoir properties of the Rotliegendes aeolian sandstone deteriorate. This is due to a deeper maximum depth of burial. Also, the main N W - S E faulting prevents any pressure communication between the three reservoirs, Deborah, Della and Delilah. The reduction in permeability leads to lower well deliverability, which in turn reduces the potential for very high recovery factors. Current expected recovery factors range from 85-90% for Deborah down to 50% for Delilah. In the absence of infill drilling, recovery is also reduced by the potential for poorly drained fault blocks. However, this poorer rock quality significantly reduces the risk of any significant aquifer influx and hence subsequent loss of reserves. The recovery factor that will be achieved from the low permeability Zechstein carbonate reservoir is estimated to be about 50%. In the better quality, southeastern part of the reservoir a recovery factor approaching 80% may be achieved. However, to the NW and around the margins of the reservoir, gas volmnes are contained in small isolated areas of better quality rock and will not be produced.
Reserves and production The Hewett Field facilities, shown on Figure 1, comprise four production platforms: 52/5a-A, 48/29-A and 48/29-B on the Hewett Field and 48/29-C on Big Dotty, all tied back to a centrally located Field Terminal Platform, 48/29-FTP, with a separate quarters platform, Q. Additionally, there are eight satellite sub-sea wells, four of which are tied back to the 48/29-C platform and four to the 48/29-A platform. Gas flows, via two 30-inch (0.76m) pipelines, to the Phillipsoperated Bacton terminal, where onshore compression facilities are located. Offshore compression equipment was installed during 1989 on the 48/29-A platform and during 1995 on the 52/5a platform. Production from the low pressure wells has also, in the past, been increased by the use of ejectors, which used high pressure gas to lift low pressured wells. The main reservoir parameters are shown in the data summary table. The overall recovery factors from both the main Hewett Triassic Field reservoirs are expected to exceed 90%, with recovery from the Lower Bunter already exceeding 96%. This is due to good to very good permeabilities in their braided fluvial and sheetflood sandstones, with only the Upper Bunter reservoir experiencing
Conclusions For over thirty years since first production in July 1969, the Hewett fields complex has been a prolific gas producer from four reservoirs: Upper and Lower Bunter sandstones in the Triassic, Rotliegendes sandstones and Zechstein dolomites in the Permian. Over 4 TCF of gas has been produced to date. The authors thank ConocoPhillips (UK) Ltd, Agip (UK) Limited, ARCO British Limited, Fina Exploration Limited, LASMO North Sea plc, Superior Oil United Kingdom Limited, and Veba Oil and Gas UK Ltd. for giving permission to publish this paper. The opinions expressed herein are those of the authors and not necessarily those of the Hewett owners.
References COOKE-YARBOROUGH, P. 1991. The Hewett Field, Blocks 48/28-29-30, 52/4a-5a, UK North Sea In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 433-441.
The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea C. W. M c C R O N E l, M. G A I N S K I
& P. J. L U M S D E N
BP Amoco Exploration, Dyce, Aberdeen AB21 7PB, UK 1 Present address." BP Exploration, Chertsey Road, Sunbury on Thames, Middlesex TW16 7LN, UK
Abstract: Indefatigable is a mature dry gas field on the northeastern margin of the UK Southern North Sea Rotliegend Play fairway. The field was discovered, 49/18-1, by the Amoco operated group in 1966 and subsequent appraisal drilling established that the field extended over four blocks (i.e. 49/18, 49/19, 49/23 & 49/24). There have been several phases of development, initial production concentrated on the main horst block with first gas in 1971, followed by the west flank area in 1977/78. Then in 1987/88 the SW and SE Indefatigable satellite accumulations were brought on-stream. The Rotliegend Leman Sandstone Formation reservoir primarily consists of stacked aeolian dune sandstones (150-400 ft) of good reservoir quality (porosity 15%, permeability 100-1000roD). However, the integration of the 1992/93 3D seismic survey, well data, reservoir pressure and production data has lead to a much more complex view of the field with 11 gas-water contacts and 15 reservoir compartments. This has resulted in an upward revision of the gas initially-in-place from 5.2 to 5.6 TCF and recoverable reserves from 4.4 to 4.7 TCF. Current work is focused on maximizing recovery from the various reservoir compartments and accessing this additional potential. Indefatigable Field lies in a water depth of 100 ft in the centre of the Southern North Sea, 90kin from the Bacton gas processing terminal on the East Anglian coast (Fig. 1). The field is on the northeastern margin of the Rotliegend Play fairway and covers an area of 150km 2 extending over four U K C S blocks (i.e. 49/18, 49/19, 49/23 & 49/24). The field is located on the stable Inde Pediment on the northern side of Sole Pit Basin (Fig. 2). The field is composed of a major N W - S E trending horst block (Fig. 3), a series of lower relief fault blocks on the western flank, and several smaller low relief satellite structures (e.g. SW Indefatigable and SE Indefatigable). In addition, the Baird Field, a high relief pop-up structure, was drilled from the Indefatigable 23D platform.
History The exploration acreage was awarded as part of the First Offshore Licence Round in 1964. The BP Amoco group (Table 1) licence, P.016, covers blocks 49/18 and 49/23 whilst the Shell group licence, P.007, covers blocks 49/19 and 49/24. The discovery well 49/18-1, drilled by Amoco in 1966, tested the crest of the main horst block. It encountered a 285 ft Rotliegend Leman Sandstone interval with gas-down-to the Carboniferous and
flowed at 18.8 M M S C F D . Subsequent appraisal drilling of 13 wells, through 1967 to 1970, defined the areal extent of the field (France 1975), including the 49/19-2A well that proved the extension of the field into the Shell operated licence. The field has undergone several phases of development. Initial production (i.e. 18A, 18B, 24J and 24K platforms) concentrated on the main horst block with first gas in September 1971, followed by the development of the west flank area in 1977/78 by the 23C and 24L platforms. The third phase in 1987/88 included the development of the flank areas and the bringing on-stream of the SW and SE Indefatigable satellite accumulations, utilizing smaller Normally Unattended Installations (NUI; i.e. 19M, 24N and 23D). Following the acquisition and interpretation of the Sean/Inde 3D seismic survey in 1992/93, a high relief pop-up structure to the SW of Indefatigable was targeted by the 49/23-D5 exploration well. It discovered the Baird Field in 1993 and tested at rates of 51.6 M M S C F D . There are currently a total of nine BP Amoco and Shell production platforms, from which 67 development wells have been drilled. These wells penetrate the reservoir at low to moderate angles and have perforated liner completions. All the platforms feed into the BP Amoco operated 23AT gas compression platform from which the gas is exported via a 90 kin, 30-inch pipeline to the Bacton Terminal via the Leman Field.
Fig. 1. Southern North Sea location map. Gas from the Indefatigable Field is exported via a 90 km, 30" pipeline to the Bacton gas terminal on the East Anglian coast.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 741-747.
741
742
C.W. McCRONE E T AL.
Table 1.
Indefatigable acreage licensees
Licence Round
Licensee
Interest
P.016
1
BP Amoco Exploration plc. BG International Ltd. Amerada Hess Ltd. Enterprise Oil plc.
30.77% 30.77% 23.08% 15.38%
P.007
1
Shell UK Ltd. Esso Exploration & Production UK Ltd.
50.00% 50.00%
The field is named after the local Indefatigable Banks sea-floor feature. Baird Field is named after John Logie Baird, inventor of the television, and followed the Amoco (UK) Exploration convention of naming fields in honour of British scientists, inventors and explorers.
Stratigraphy
Fig. 2. Rotliegend structural elements and facies map. Indefatigable is located on the relatively stable Inde Pediment. It is on the northern margin of the main erg, shown here at its maximum development during the upper Rotliegend when the structural highs had largely been buried by the dune fields (simplified from George & Berry 1993).
In the Indefatigable area, the stratigraphy consists of a standard Southern North Sea section (Fig. 4) and was described in some detail by Pearson et al. (1991); only a brief review will be presented in this paper. Due to the relatively stable nature of the Inde Pediment, the overburden is essentially undisturbed apart from the regional inversion events of the Late Jurassic and Tertiary. Underlying the Rotliegend reservoir is a Carboniferous Westphalian A/B section consisting of pro-deltaic shales with occasional deltaic sands and silts deposited during marine regressions. The Westphalian section in the nearby 49/23-7 deep test is characterized by a low net/gross sand ratio (e.g. 0.1-0.2) with occasional development of thin 10-20ft sandstones of poor reservoir quality. The majority of early exploration wells and all development wells only tag the top of the Carboniferous. The Lower Permian Rotliegend Leman Sandstone Formation was deposited on the Late Carboniferous Variscan unconformity surface and is primarily composed of stacked aeolian dune sandstones reflecting deposition in a desert erg environment (Fig. 2; George & Berry 1993).
Fig. 3. Indefatigable Field Top Rotliegend structure map. The revised structural interpretation is based on the 1992/93 Sean/inde 3D time-migrated seismic dataset. The field is composed of several structural regions, the main NW-SE trending horst block has up to 1350ft of structural relief and is connected via a saddle to the west flank area of lower relief (500-600 ft) fault blocks. Several low relief satellite structures (i.e. SW Indefatigable and SE Indefatigable and the Baird pop-up structure are also produced from Indefatigable platforms.
743
INDEFATIGABLE FIELD Table 2. Reservoir compartments and gas-water contacts Compartment
GWC TVDss (ft)
Control wells
Baird
8694
inferred
SE Inde
8710
49/24-2
D3 Compartment
8757
D3
D2 Compartment
8795
D2
M3 Compartment
8815
M3
B 10 Compartment
8850
B 10
Inde Main (N & S), Saddle Area
8856
49/18-2, B8
M2 Compartment
8870
M2
B11 Compartment
8874
49/18-3
Inde C North
8914
C2
A4 Compartment
8919
A13, J1025
8967
D4
Inde C West Inde C South Inde C South Centre D1 Compartment
made identifying the main horst block, the west flank area and the satellite structures of SW and SE Indefatigable (Pearson et al. 1991). However, even with this interpretation, several sealing faults had to be invoked in order to explain the four gas-water contacts (GWCs) and a gas-down-to (GDT). The acquisition and interpretation of the Sean/Inde 3D seismic survey, additional well data, reservoir pressure and production data have resulted in a more structurally complex and compartmentalized view of the field. The 3D seismic survey identified several fault trends: NW-SE, E - W and the low throw laterally extensive NNE-SSW. These subdivide the reservoir into 15 compartments excluding Baird (Table 2; Fig. 5).
Geophysics
Fig. 4. Stratigraphic column for the Indefatigable area. An effective top seal is provided by the overlying Zechstein evaporitic sequence, which has a relatively uniform thickness (2000-2500 ft) across the field. It is dominated by halite with the standard basal carbonate sequence and Plattendolomit rafts. However, there is some minor halokinesis in the form of N W - S E trending swells and lows. A complete sequence of the Triassic Bacton Group is preserved, with a uniform thickness of Bunter Shale and Bunter Sandstone across the area. However, the overlying Haisborough Group is variably preserved and the Jurassic is completely absent beneath the Base Cretaceous Unconformity due to the Late Cimmerian tectonism. A thin Lower Cretaceous sequence of shales and marls grade upwards into the Red Chalk and as regional subsidence continued through the Upper Cretaceous a thick chalk sequence blanketed the basin. Towards the end of the Cretaceous and into the Tertiary, Alpine tectonism affected the basin and resulted in a minor adjustment to the Inde Pediment, tilting it down-to the SE. During the remaining Tertiary and Quaternary a sequence of marine clays and sands infilled the basin.
Trap Based on the 2D seismic grid, only a relatively simple structural interpretation, dominated by N W - S E trending faults, could be
The seismic interpretation is based on the Sean/Inde 3D timemigrated seismic survey, which was acquired and processed in 1992/93 and provided a high quality dataset. For the depth conversion, the Top Rotliegend and six shallower events were interpreted throughout the area: Top Chalk, Base Chalk, Base Cretaceous Unconformity, Top Muschelkalk Halite, Top Rot Halite and Top Zechstein. The most appropriate velocity fields were determined for each layer. For the Tertiary and Chalk layers, V0, k velocity functions were used due to increasing velocity with depth as a result of compaction. The five deeper layers were depth converted using gridded interval velocities calculated from the extensive well control. The Rotliegend fault pattern was interpreted on a number of coherency time and horizon slices. These fault picks were then used to assist the interpretation of vertical time-migrated sections. A Top Rotliegend ERMapper display was also used to further refine the reservoir fault pattern. Initial coherency and seismic attribute work suggested good qualitative correlation with reservoir porosity and the presence of gas. Seismic amplitudes of both the Top Rotliegend event and absolute amplitudes extracted from a 40 ms window, approximating the reservoir thickness, showed some degree of correlation with the reservoir compartments. However, further detailed analysis of seismic amplitudes and coherency was unable to establish any quantitative relationships with well derived reservoir parameters (e.g. porosity, water saturation, hydrocarbon-pore-thickness and Rotliegend isopach).
744
C.W. McCRONE ET AL.
Fig. 5. Indefatigable Field reservoir compartments. The integration of the 3D seismic survey, well data, reservoir pressure and production data has lead to a much more structurally complex view of the field with 15 reservoir compartments and 11 gas-water contacts, excluding the Baird Field. However, the vast majority of faults are not total sealing. As reservoir compartments differentially depleted the faults' ability to act as total seals were overcome leading to some communication between compartments.
On a qualitative basis, coherency horizon slices have been key in explaining the lower porosity and poorer performance typically associated with wells drilled through fault damage zones. In the case of D l z (Fig. 6) no faults were identified intersecting the wellbore based on conventional seismic interpretation. The coherency display identified D l z as lying in an area of high disturbance, believed to relate to sub-seismic scale faulting. It also identified 'clean' seismic areas to the west and N W of the well, that could be potential infill locations.
Compartmentalization and gas-water contacts Over the main parts of the field there is gas-down-to the top of the Carboniferous. Out of a field total of 79 wells, only 15 intersect a GWC. Primarily, the GWCs have been picked from wireline log response as many of the key wells pre-date formation pressure measurement tools. The contacts established from wells drilled on the flanks of the field were integrated with bottom-hole pressure data to derive 11 GWCs and 15 reservoir compartments, excluding Baird. In areas of the field where several fault blocks have behaved as a single volume throughout their production history, they have been treated as a single compartment. A G W C of 8856ft TVDss has been assumed for the whole of the main horst block. This is based on the results of the 49/18-2 and B8 wells drilled on the northern dip-closed end of the structure and the common bottom-hole pressure decline profiles of the 18A and 18B platform wells. Minor differences in the G W C s have been honoured where production data has indicated a fault block behaving as a separate compartment. The B10 development well was drilled into a virgin pressured fault block at the northern end of the field and encountered a slightly shallower G W C of 8850 ft TVDss. Although
this difference is small (6 ft) and within the possible errors of the deviation survey, the B10 fault block has a distinct bottom-hole pressure-time decline profile. Due to the phased nature of field development, GWCs have been taken either from the original exploration wells or from development wells that have tested compartments at virgin pressure. A few development wells have twinned early exploration wells and encountered a different GWC. The 49/18-3 exploration well drilled a low relief area on the northwestern flank of the field and encountered a sharp transition zone with a G W C of 8874 ft TVDss. It was twinned 22 years later by B 11, which penetrated a partially depleted reservoir section with a longer transition zone and a deeper contact of 8898 ft TVDss. In these cases the exploration data has been honoured, as they are less susceptible to depth errors compared with highly deviated production wells and are not affected by any production induced changes to the GWC. New well data has lead to a significant change from the previous model with the deepening of the G W C in the western flank area. Previously the 49/18-3 G W C of 8874 ft had been used for this area, however, a deeper G W C of 8967ft TVDss was established by 49/23-D4 and is supported by the 49/23-C11 and 49/24-L1205 G D T of 8932 ft TVDss and 8898 ft TVDss, respectively. The additional well data (i.e. 49/23-D3 and 49/23-D2) also defined SW Indefatigable as two distinct virgin accumulations with GWCs of 8757 ft TVDss and 8795 ft TVDss. However, areas of ambiguity still remain despite the additional data. In the C North compartment, the G W C of 8914ft TVDss is based on a wireline log interpretation of the 49/23-C2 well, however, the deterioration in rock quality towards the base of the Rotliegend in this well may mean that it is in fact a GDT. Also, the 49/23-D5 Baird well did not penetrate a GWC. Therefore, a G W C of 8694 ft TVDss has been inferred from formation pressure measurements made in the gas-column and aquifer gradients taken from neighbouring wells.
INDEFATIGABLE FIELD
745
(a) Top Rotliegend coherency horizon slice
(b) Top Rotliegend Structure in depth (ft) Fig. 6. Application of seismic coherency data for identifying faults and fault damage zones. Coherency time and horizon slices along with ERMapper displays were used to refine the reservoir fault pattern. In particular, the coherency data (a) highlighted areas of high disturbance (dark regions) believed to be sub-seismic scale faulting, which were not identified from the conventional 3D seismic interpretation (b) techniques. This has helped to explain the lower porosity and poorer performance of certain wells (e.g. Dlz) that are now thought to have drilled into fault damage zones. The Indefatigable structure is not filled to spill, probably as a result of regional basin inflection during the Alpine tectonism and the subsequent re-migration of gas.
Sealing faults Apart from one or two exceptions, the faults within the reservoir have not behaved as total seals over field life. The throw on the majority of faults is insufficient to completely offset the Rotliegend, therefore, they retain some sand-to-sand juxtaposition. A recent study by the Rock Deformation Research Group at the University of Leeds indicated that most faults within the Rotliegend are characterized by cataclastic rock flour. The sealing capability of these faults is a function of the grain-size reduction and increased capillary threshold pressure. Except for the N N E - S S W low-throw laterally extensive lineaments, which are typically cemented by fluids from the overlying Zechstein.
Fig. 7. Indefatigable Field reservoir zonation. The Rotliegend Leman Sandstone Formation in the Indefatigable area consist of stacked aeolian dunes of good reservoir quality (e.g. porosity 15%; permeability 10-1000mD). For the purpose of reservoir simulation the Rotliegend has been subdivided into five geological layer. The layer boundaries are based on higher gamma-ray and formation density log responses which correspond to damp interdune or sabkha facies. However, these facies do not act as vertical permeability barriers. When a field has been on production and compartments have become significantly differently depleted, the faults' ability to act as total seals is overcome when the pressure differential exceeds the capillary threshold pressure, leading to some communication between the various compartments. This effect has been observed in Indefatigable Field. Recent mass balance and full field reservoir simulation studies have indicated that to history match well performance, communication is required between compartments that initially had different GWCs.
Reservoir The Rotliegend Leman Sandstone Formation in the Indefatigable area consists of stacked aeolian dunes of good reservoir quality (e.g. porosity 15%, permeability 10-1000mD). Interbedded with
746
C.W. McCRONE E T A L .
the dune sandstones are minor interdune and occasional sabkha deposits. Fluvial facies are rare, however there is evidence of a thin lacustrine system in the southeastern part of the field. The Rotliegend is typically 150-200 ft thick over the horst block and the western flank area, but gradually thickens to 400 ft at the northern end of the field. There is also a substantial and rapid change in Rotliegend thickness between the horst block (150 ft) and the fault terraces on the northeastern margin of the field (350f t). The Indefatigable horst block may have been a significant topographical feature during the Permian. The sandstone is a texturally and chemically mature quartz arenite with little in the way of clay diagenesis. The Rotliegend is characterized by very high net/gross sand ratios of 0.95-1.00. The porosity and permeability cut-offs used to define net sand were based on Winland's empirical relationship (Kolodzie 1980) between porosity, permeability and the pore-throat radius at 35% nonwetting phase saturation. Based on core data, a net sand cut-off of 8% porosity, equivalent to 0.8 m D permeability, was defined by a micro-porosity 0.5 gm pore-throat radius. The handful of wells with low net/gross ratios of 0.5-0.6 either intersect faults or fault damage zones, which are characterized by severely degraded porosity, apart from 49/24-2 and N2 which encounter a playa lake interval. The Rotliegend has been subdivided into five geological layers (Fig. 7) to characterize porosity and permeability variations. The zonation scheme was developed from the limited core data in combination with wireline tool response, principally the gamma-ray and formation density logs. There is no indication from well performance data of any vertical permeability barriers within the sequence. These five geological layers were further sub-divided into a total of 17 layers for the full field reservoir simulation, primarily to control the rate of water influx. The bottom two geological layers, L4 and L5, contain the highest proportion of non-dune facies, in particular non-pay sabkha sediments. However, the dune sandstones that do occur tend to have the best rock quality (e.g. porosities, 20%, permeabilities 100-1000 mD). The sandstones in L5 are occasionally tightly cemented (e.g. 49/23-C2) probably due to the percolation of formation fluids from the underlying Carboniferous. Although, all the layers thick and thin in response to changes in the overall Rotliegend isopach, this is more pronounced in L5. Smaller scale dune, interdune and thinly developed sabkha facies comprise L2 and L3. The dune sandstones have high porosities 15-20% and moderate permeabilities 10-100roD. The boundary between L2 and L3 is interpreted as interdune or occasionally thinly developed sabkha. However, in the southeastern part of the field the boundary occurs at the base of a 20 ft thick playa lake shale unit.
L1 is the uppermost zone within the Rotliegend and consists of thinly interbedded dune and interdune facies with possible reworking towards the top. The rock quality is poorer near the top (e.g. porosity 10%, permeability 10 mD) as a result of either minor reworking and poorer grain sorting or increased cementation from the incursion of formation fluids from the overlying Zechstein carbonates and evaporates. However, there is no evidence of a thick Weissliegend section.
Source The source of the gas is the thick sequence of coals and organic rich shales of the Carboniferous Westphalian A/B section; however, the Carboniferous that underlies the field is only marginally mature for gas generation. The main source area is likely to have been the southern end of the Sole Pit Basin, to the SE of the field, where gas generation started during the Upper Cretaceous.
Reserves and production The integration of the new geoscience interpretation with the production pressure-time data identified wells in communication and those in separate reservoir compartments. Through material balance techniques the degree of communication between compartments was determined. This information was incorporated into the full field simulation and surface network model, for de-bottlenecking and forecasting gas sales. The Indefatigable Field is a volumetric gas expansion reservoir with only a relatively small number of wells exhibiting water production. These wells tend to be located on the flanks of the field and had encountered the gas-water contact when drilled. However, the water influx is minor and gas production is generally unaffected. There is no evidence of an active aquifer. Indefatigable is a dry gas reservoir, 92% methane, with a condensate/liquid ratio of <1 BBL/MMSCF. There is a common gas composition across the field and the satellite structures. Production from Indefatigable is now on decline; the field came off plateau of 8 0 0 - 1 0 0 0 M M S C F D in 1986/87 (Fig. 8). However, the field is forecast to produce through to the expiry of the license in 2010. Based on the BP Amoco field model, the calculated gas initiallyin-place (GIIP) for both sides of the field is 5.6TCF, of which 4.7 T C F is recoverable. This represents a reserve increase of 300 BCF from the 2D seismic evaluation. The recoverable reserve estimate for BP Amoco's side of the field is 3.08 TCF, of which 3.04TCF is sales gas, based on a full field simulation history matched to October 1998.
Fig. 8. Indefatigable Field production by platform. There were several phases of development from the initial production in 1971 through to the installation of the BP Amoco 23D and Shell 19M and 23N platforms in 1987/88. However, production is now on decline; the field came off plateau of 800-1000 MMSCFD in 1986/87. Indefatigable is a dry gas volumetric expansion reservoir with only a few wells producing minor amounts of water.
INDEFATIGABLE FIELD As of the 1999-2000 contract year the BP A m o c o group has average daily sales of 1 1 4 M M S C F D , which gives an a n n u a l sales quantity of approximately 4 2 B C F , a l t h o u g h the field has a m a x i m u m instantaneous capacity of 1 9 0 M M S C F D . Cumulative BP A m o c o g r o u p gas p r o d u c t i o n to June 1999 is 2 . 7 8 T C F representing 90% of estimated ultimate recovery. Gas p r o d u c t i o n is from nine platforms across the field; four on the BP A m o c o side and five on the Shell side. A l t h o u g h the field is jointly operated it is not unitized. All of the gas and a small volume of associated condensate are transported to the BP A m o c o operated 49/23AT compression platform. Here it is c o m m i n g l e d with gas from the Davy, Bessemer, Beaufort and B r o w n fields, prior to export via the 90 km, 30-inch pipeline to the Bacton Gas terminal, where the gas enters the national t r a n s p o r t a t i o n grid. The authors wish to thank BP Amoco Exploration and its c0-venturers, BG International, Amerada Hess and Enterprise Oil for their permission to publish this paper. There have been a great many years of subsurface evaluation, drilling and facility work of which this paper represents a brief summary. The authors acknowledge all who have previously worked on the field, without whose efforts this paper would not have been possible.
Trap Type Depth to crest Lowest closing contour GOC or GWC OWC Gas column Oil column Pay zone Formation Age Gross thickness Net/gross ratio Porosity average (range) Permebility average (range) Petroleum saturation average (range) Productivity index Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas/oil ratio
Condensate yield Formation volume factor Gas expansion factor
228 SCF/RCF
Formation water Salinity Resistivity
196200NaCleqppm 0.0185 ohmm
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially-in-place Gas initially-in-place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate Production Start-up date Production rate plateau oil Production rate plateau gas
Indefatigable Field data summary
structural horst block 7500R 9000fi 8850-8967fi 11 distinct GWCs
Number/type of well
1350fi
References
Leman Sandstone Early Permian 150-400 ft 0.95-1.00 15 (10-24)% 30 (1 1000) mD 70 (60-80)%
-~ API 0.612 0.0232 cp
747 < 1 BBL/MMSCF
38 400acres 4.90E+06acreR 4122psi 0.075psi/fl 195~ 5600BCF 84% Volumetric 4700 BCF 4.5 MMBBL
1971 800-1000 MMCF/D off plateau in 1986/87 56 producers
FRANCE, D. S. 1975. Geology of the Indefatigable Gas Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of N. W. Europe, Volume 1. Applied Science, London, 233-239. GEORGE, G. T. & BERRY, J. K. 1993. A new lithostratigraphy and depositional model for the Upper Rotliegend of the UK Sector of the Southern North Sea. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Fluvial and Aeolian Reservoirs. Geological Society, London, Special Publications, 73, 291-319. KOLODZIE, S. JR. 1980. Analysis of Pore Throat Size and the Use of the Waxman-Smits Equation to Determine OOIP in the Spindle Field, Colorado. Society of Petroleum Engineers, 55th Annual Technical Conference, Paper SPE-9382, 10. PEARSON, J. F. S., YOUNGS, R. A. & SMITH, A. 1991. The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 443-450. ROCK DEFORMATIONRESEARCHGROUP 1997. Structure and Prospectivity of the Rotliegendes Gas Reservoirs in the Central Southern North Sea, UK. University of Leeds, Leeds.
The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea DAVID
E. L A W T O N
& PAUL
P. R O B E R S O N
B H P Billitron Petroleum Ltd, Neathouse Place, London, S W 1 V 1LN, U K
Abstract: The Johnston Field is a dry gas accumulation located within blocks 43/26a and 43/27a of the UK Southern North Sea. The discovery well was drilled in 1990 and after the drilling of one appraisal well in 1991, a development plan was submitted and approved in 1993. Initially two development wells were drilled from a four slot sub-sea template, with commercial production cmnmencing in October 1994. A further horizontal development well was added to the field in 1997. The field has a structural trap, fault bounded to the SW and dip-closed to the north, east and south. This field geometry has been established using high quality 3D seismic data, enhanced by seismic attribute analysis. The sandstone reservoir interval consists of the Early Permian, Lower Leman Sandstone Formation of the Upper Rotliegend Group. This reservoir consists of a series of interbedded aeolian dune, fluvial, and clastic sabkha lithofacies. The quality of the reservoir is variable and is principally controlled by the distribution of the various lithofacies. The top seal and fault bounding side seal are provided by the overlying claystone of the Silverpit Shale Formation and the evaporite dominated Zechstein Supergroup. The field has been developed using a phased development plan, with the acquisition of a 3D seismic survey allowing for the optimized drilling of a high deliverability horizontal well. Current mapped gas initially-in-place estimates for the field are between 360 and 403 BCF, with an estimated recovery factor of between 60 and 75%.
The BHP operated Johnston Gas Field is located in the U K sector of the Southern North Sea in approximately 150 ft (46 m) of water, some 55 miles (88.5km) E of the Yorkshire coastline and only 4.5miles (7.2km) E of the Ravenspurn North Gas Field (Fig. 1). The field trends NW-SE, is approximately 7.5 miles (12km) long, by 1 mile (1.6km) wide, and consists of a structural trap that is fault bounded to the SW. The reservoir consists of sandstone of the Early Permian, Lower Leman Sandstone Formation of the Upper Rotliegend Group. The overlying claystone of the Early Permian, Silverpit Shale Formation and evaporites of the Late Permian, Zechstein Group form the top seal and fault bounded side seal.
History The Johnston Field is located within two U K blocks. These are Block 43/26a (Licence P.380) and Block 43/27a (Licence P.686). Block 43/26a was awarded to a Hamilton Brothers operated group in 1981, as part of the seventh round of U K offshore licensing. In October 1984, well 43/26-1 discovered the neighbouring Ravenspurn North Field (Ketter 1991a). Block 43/27a was awarded to a Hamilton Brothers operated group in 1989 as part of the Eleventh R o u n d of U K offshore licensing. The Johnston Field was discovered in April 1990 by well 43/27-1 which encountered 256ft of gas bearing Lower Leman
Fig. 1. Johnston Field location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 749-759.
749
750
D.E. LAWTON & P. P. ROBERSON
Sandstone Formation reservoir. The well was tested and flowed at 37.6 MMSCF/D, on a 60/64" choke and with a flowing well head pressure (FWHP) of 1766 psig. In 1991 the discovery was appraised by well 43/26a-8, which encountered 368 ft of gas bearing Lower Leman Sandstone Formation, that flowed on test at 46.73 MMSCF/D, with a 72/64" choke and a FWHP of 1619psig. Approval of the field development plan was granted by the UK government in June 1993. Initially two production wells (43/27-J1 and J2) were drilled during 1994 from a sub-sea template and first commercial gas production commenced in October 1994. In 1997 an additional development well, 43/27a-J3, was drilled from the template. This well was completed as a horizontal well from an original vertical pilot hole. The Johnston Unit consists of the following Unit Owners and their respective interests: BHP Petroleum Ltd (Operator) 31.71375%; CalEnergy Gas U K Ltd 22.11300%; Centrica Resources Ltd 3.94350%; Eastern Natural Gas Ltd 5.52825%; Enterprise Oil plc 5.25800%; British Borneo Oil and Gas Ltd 6.31450%; Monument Oil and Gas plc 17.75800%; Petrobras U K Ltd 7.37100%. (Note: since writing this chapter, operatorship and interests of this field have transferred to Consort Resources Ltd.)
r o
...r
o
.m
Seismic Markers
o ro
E t,..
.m --.I
o It.
Corallian
Triton Anhydrite
Geology
Stratigraphy The stratigraphy of the Johnston Field is summarized in Figure 2. Wells in the field area are typically terminated in the Carboniferous strata that underlies the reservoir interval. In the Johnston area, the Carboniferous generally consists of interbedded tight sandstone and claystone of Namurian age (Millstone Grit Formation). Overlying the Carboniferous at a sub-cropping angular unconformity, is the Johnston reservoir sandstone interval. This consists of the Lower Leman Sandstone Formation, which is part of the Early Permian, Upper Rotliegend Group. Regionally, this reservoir interval passes laterally to the north and east into the sealing claystones and siltstones of the upper part of the Upper Rotliegend Group, known as the Silverpit Shale Formation. In the Johnston Field and surrounding area, this reservoir interval consists of sandstones deposited in aeolian, fluvial and clastic sabhka environments. Across the field the reservoir ranges between 162ft and 375 ft thick and is overlain by around 430 ft of claystones and siltstones of the Silverpit Shale Formation. Overlying the Silverpit Shale Formation is the Late Permian, Zechstein Supergroup. This interval is dominated by evaporites which add to the sealing ability of the overburden section. The Zechstein interval can vary in thickness, but is generally around 2400ft thick over the field area and comprises seven sub-groups consisting predominately of halite, but with common anhydrite, dolomite and limestone intervals. The Zechstein Supergroup interval provides the main hazard to drilling within the Southern North Sea. This hazard is primarily from overpressure in dolomite rafts, such as the Plattendolomit Formation. Overlying the Zechstein Supergroup is a thick Triassic sequence. This is divided into the Bacton and Haisborough Groups. The Bacton Group is consistently around 2150 ft thick in the field area and is divided into the Bunter Shale Formation, overlain by the Bunter Sandstone Formation. The Bunter Sandstone Formation forms the reservoir for the now decommissioned Esmond, Forbes and Gordon gas fields (Ketter 1991b), which are located approximately 40 miles (64 km) to the NE of the Johnston Field. The overlying Haisborough Group is around 1800 ft thick and comprises interbedded claystones, halites, and anhydritic and dolomitic claystones. Overlying the Triassic is a Jurassic interval, consisting of the Early Jurassic, Lias Group and the Middle Jurassic, West Sole Group. Whilst the Lias Group consists of calcareous claystones with thin limestone interbeds, the West Sole Group consists of interbedded sandstones, limestones and claystones. From the
.-/---
Bunter Sandstone
,0 . . . . . . . . ,o . . . . . . . .
.
Brockelschiefer
Kupferschiefer
Leman
TD
Fig. 2. Summary of stratigraphy.
JOHNSTON GAS FIELD available 3D seismic data, the Jurassic interval is known to be up to 3000 ft thick in the field area, but is controlled in thickness as a result of significant erosion during the Tertiary; which also removed Cretaceous sediments. Overlying the Jurassic interval is a thin veneer of Quaternary marine sediments.
Geological evolution The Johnston Field area has had a complex geological evolution. Underlying the reservoir interval, the Carboniferous strata were folded and faulted during the compressional phase of the Variscan orogeny; with faults developed in a dominantly N W - S E orientation. By Early Permian times the remaining Variscan topography had largely been peneplained, leading to a Carboniferous sub-crop pattern of varying ages, as is seen today across the Southern North Sea. This erosional terrain, together with the established Variscan fault trends provided a strong influence on the early deposition for the overlying Lower Leman Sandstone Formation, as Early Permian extension and re-activation of existing fault systems caused basin subsidence and allowed space for further sediment accommodation. Following the clastic deposition of the Early Permian, a widespread Late Permian (Zechstein) transgression resulted in the deposition of a thick evaporitic succession, as regional subsidence continued. Subsidence and sediment deposition continued through the Triassic with the development of widespread continental clastic deposits. Towards the end of the Triassic a sea level rise led to the
Fig. 3. Southern North Sea: main structural elements.
751
return of marine conditions, which persisted throughout the Jurassic and into the Cretaceous. Deposition of the Early Cretaceous (Cromer Knoll Group) and the Late Cretaceous (Chalk Group) are known to have taken place over the area. Remnant intervals can be found locally in some offset wells whilst thicker intervals are seen elsewhere in the basin. However, Late Cretaceous to mid-Tertiary inversion associated with the Alpine orogeny resulted in the uplift and removal of the Cretaceous, as well as parts of the Jurassic sequence in the Johnston area.
Source rock The established dry gas source rock for the Southern North Sea is principally the Carboniferous, Westphalian A Westoe Coal Formation (Coal Measures) (Cornford 1990). This coal-rich source rock is known to be abundant and is sufficiently mature to produce large quantities of gas. The Carboniferous seen in the Johnston area is generally Namurian in age, which is older than this source rock. Migration from the source kitchen to the south occurred via the many sandstone carrier beds in the Carboniferous and through the Lower Leman Sandstone Formation (Parsley, 1990). Peak hydrocarbon generation occurred from the Jurassic through to the late Cretaceous, when generation was curtailed by basin inversion.
Structure Regionally, the Johnston Field lies at the northern margin of the Sole Pit Basin (Fig. 3) which is dominated by a N W - S E structural
752
D. E. LAWTON & P. P. ROBERSON
Fig. 4. Top Leman Sandstone Formation depth map.
Fig. 5. Example 3D dip-line across the field.
JOHNSTON GAS FIELD grain that was initiated by dextral shearing during the Variscan orogeny. Extension during the Permian, increased during the Middle Jurassic to Early Cretaceous with the development of 'horst-and-graben' systems. Basin inversion from Late Cretaceous through to mid-Tertiary created areas of uplift and the local erosion of the Cretaceous and parts of the Jurassic. Later periods of repeated fault reactivation, led to many of the predominant NW to SE trending faults being linked with short N-S and E - W faults resulting from oblique-slip. The Johnston Field has a similar trend and structural style of many Southern North Sea fields. The field trends NW-SE. It has a tilted fault structure bounded to the SW by a N W - S E trending fault (Fig. 4) with a vertical throw of up to 1000ft. Dip closure exists to the north and NE. The crest of the field adjacent to the fault is at ( - 1 0 240 ft) TVDss.
Geophysics
753
poor pressure communication with the nearby J1 well. With the benefit of the 3D data, the J2 well is now established to have been placed close to a fault with a minor vertical offset. This fault was not identified on the 2D data. Towards the end of 1995, reduced confidence in the 2D derived structural model, and plans to drill a third development well in 1996, led to the decision to implement a 3D seismic programme. In February 1996, PGS Tensor acquired 195 km 2 of 3D seismic data centred on the Johnston Field. Acquisition consisted of a conventional towed 3000 m 6-streamer array and dual airgun 'flipflop' source arrays. The shooting direction was NW to SE with a subsurface line spacing of 25m (cell length 12.5m). Coverage was 40 fold nominal. The data was processed by PGS in the U K and, following a series of test trials, a final processed product including a radon demultiple, DMO-stack, and post-stack time migration was available by the end of May 1996. The quality and resolution of the 3D dataset was high and fault definition at reservoir level proved far superior to the 2D data.
Seismic database 3D seismic &terpretation There is extensive 2D seismic data coverage over the field area, comprising several vintages. The minimum 2D line spacing is 500m with the majority of data acquired in the NE dip direction, normal to the dominant fault pattern. This bias in line direction led to early concerns that fault aliasing may occur, where apparent long, continuous, sinuous faults are really a series of en echelon faults. In addition, any faulting parallel to the dip direction may have been missed due to inadequate sampling by the few regional control strike lines. The second development well, 43/27-J2, was located near the culmination of the field structure. It was drilled using the 2D data and proved to be disappointing, due to low reservoir quality and
Fig. 6. Top Kupferschiefer Time - colour draped shaded display.
Using the 3D seismic data, an overall improvement in data quality has allowed horizons down to the top reservoir to be interpreted with improved confidence. Six principal horizons were interpreted over the field. These correspond to the Corallian Limestone, Triton Anhydrite Formation, Bunter Sandstone Formation, Brockelschiefer, Kupferschiefer Member and Lower Leman Sandstone Formation (Fig. 2). An example dip-line through the discovery well is shown on Figure 5. The Permian, top Kupferschiefer seismic event, corresponding to the interface between the Zechstein Supergroup and Silverpit Shale Formation, has a distinct acoustic impedance contrast and
754
D. E. LAWTON & P. P. ROBERSON
Fig. 7. Example of regional NE fault. had traditionally been used to map the top of the reservoir below, by the addition of a well-based Silverpit isopach. A colour draped, shaded display of the top Kupferschiefer time event (Fig. 6), clearly demonstrates the prevalent N W - S E fault trend; yet an additional subtle N E - S W trend also emerges. This structural trend is now extensively recognized in the Southern North Sea (e.g. Oudmayer & De Jager 1993, in their study around the Cleaver Bank High). At this stratigraphical level the vertical fault offset is minor, perhaps below seismic resolution, and often only a flexure is noted. Deeper intra-Carboniferous events sometimes do show an offset (Fig. 7). From the present database, it can be demonstrated that this disturbance, adjacent to the well 43/27-1 continues to the SW for at least 15 miles (24 km). A comparison of the maps based on the top Kupferschiefer event generated before and after the 3D seismic (Fig. 8), shows how the fault complexity has evolved, with additional NE and northerly
C.l. 100 It
Fig. 8. Seismic interpretation: 2D v. 3D comparison.
fault trends observed. Also an easterly trend can now be seen to align with a lateral offset of 750 m on the main field boundary fault adjacent to the poorer quality well 43/27-J2.
Depth conversion Many depth conversion methods have been considered for the Johnston Field. They range from deterministic function based and interval velocity applied to a 'layer-cake' scheme, through to geostatistical and stochastical modelling of the velocities derived from the 3D seismic processing. Upper Triassic to Cretaceous faults trending east to NE across the field create fault shadow effects with the 'layer-cake' technique due to abrupt lateral velocity changes across the faults. These faults are listric in nature and 'sole-out' in the Rot Halite Member above
JOHNSTON GAS FIELD the Bunter Sandstone Formation. The top Zechstein event is unfaulted and gently undulating and so provides an ideal control horizon for ensuring the effectiveness of smoothing or resampling methods to remove this velocity artefact. A simplistic approach that considers the post-Zechstein salt as a single layer has proved to be the preferred option. This has resolved the problem of overburden fault imprints and removed the potential accumulation of depth errors derived from a 'layer-cake' technique. Time and subsequent depth interpretations for the preZechstein events often differ significantly. This is due to thickness variations in the dominantly halite Zechstein section, that are subject to a high interval velocity of 14 500 ft s -1 (excluding the anhydrite, dolomite and limestone). On the Johnston Field, the Zechstein salt increases in thickness along the structural dip direction to the NE and also varies along the culmination axis. Where the Zechstein is relatively 'thin', a local 'pull-up' effect in depth occurs. For this area of the Southern North Sea, a simple function correction is usually applied; however, care must be taken if the Zechstein is reduced to <150ms two-way-time (TWT), as the proportion of anhydrite and/or dolomite increases at the expense of the halite. In this instance, a simple function would not be appropriate. Fortunately, around the Johnston Field, the Zechstein isochron is not below 290 ms TWT (approximately 2100 ft).
755
reservoir level is approximately 50 ft. Individual sandstone reservoir intervals are usually <30 ft and are therefore not directly detectable. Mapping the distribution of the top Lower Leman Sandstone Formation RMS amplitude centred on the field (Fig. 9) shows higher amplitudes clustered around the discovery well 43/27-1 and around 43/26a-8, extending to 43/27-J1. The region surrounding well 43/27-J2, the poorer producer, is dominated by lower amplitudes. This direct relationship between well results and seismic amplitude was reflected in modelled well synthetic seismograms. The northern margin of the zone of high amplitudes surrounding 43/27-1 closely matched the mapped GWC from the 3D structural interpretation. The 43/27a-J3 development well was designed to test an up-dip location SE of 43/27-1 and also to evaluate a potential separate field compartment across a N E - S W fault characterized by high amplitudes and shown by the revised structural mapping to be sufficiently elevated above the field GWC. The 43/27a-J3 pilot hole was drilled on prognosis and was side-tracked horizontally into the upper part of the reservoir and extended across the N E - S W fault. This horizontal well path encountered excellent reservoir quality and displayed differential pressure depletion across the fault.
Reservoir
Seismic attributes
Sedimentology
The acoustic impedance characteristics of the Silverpit Shale Formation are remarkably constant over the field area, whereas the underlying Lower Leman Sandstone Formation reservoir demonstrates rapid acoustic impedance variations, related to variations in reservoir quality and gas saturation. As the optimum reservoir and gas zones are found within the upper sand units of the gross interval, it is anticipated that the top Lower Leman Sandstone Formation seismic event will encode these reservoir petrophysical characteristics. Some constraint to this approach should be considered as the critical resolution thickness for this dataset at
A total of 784ft of core has been cut from the reservoir of the Johnston Field wells. In addition, there is a substantial amount of core in offset wells, particularly from the neighbouring Ravenspurn North Field. This core has allowed the development of a detailed depositional model for the Johnston area, which has been incorporated into the established regional model for the Lower Leman Sandstone Formation deposition in the Southern North Sea (e.g. Glennie 1990). The principle reservoir lithofacies in the Johnston area can be classified into four associations: aeolian, fluvial, clastic sabkha and
Fig. 9. Top Leman Sandstone Formation: RMS amplitude map.
756
D . E . LAWTON & P. P. ROBERSON
lacustrine. Overall sediment deposition and rate of deposition was controlled by ongoing subsidence (Glennie 1997), whilst the type of lithofacies deposited reflected subtle changes in climate. These lithofacies variations were developed by the dry and wet phases, leading to the different styles of deposition and sediment preservation (George & Berry 1993, 1997; Howell & Mountney 1997). During dry phases aeolian dunes dominated, but these dunes were also prone to migration and erosion by wind deflation. During the wet phases when the water tables were higher, fluvial and sabkha lithofacies dominate, but deposition was principally preserved. The aeolian associations consist of low angle to horizontal bedded sandstones and high angle bedded sandstones. The low angle to horizontal bedded sandstones are fine to medium grained and well sorted. They represent sand sheets, small dunes and dune bases. The high angle bedded sandstones are fine to coarse-grained, well sorted and exhibit large scale cross stratification with dips ranging between 22 ~ and 34 ~. These high angle bedded sands represent the upper portions of larger preserved dunes. The fluvial associations consist of both structured and massive sandstones. The structured sandstones display planar crossstratification, trough cross beds and low angle laminations, within beds of medium to coarse-grained sandstones. These units often have basal conglomerate lags consisting of both intraformational rip-up mud clasts and less common exotic extraformational clasts. The massive sandstones consist of intervals of fine to mediumgrained sandstones, which display evidence of dewatering, such as dish structures. The sabkha association consists of very fine-grained sandstones to silty sandstones and claystones. They display irregular to wavy bedding of sandy adhesion structures. Nodular anhydrite is often locally developed. The lacustrine association consists of red-brown or green-grey, micaceous claystone; commonly containing dessication cracks. This lithofacies has no reservoir potential and often provides local and field wide permeability barriers. Reservoir quality can be assessed using the large amount of core data. Core analysis data shows that the best quality reservoir sands are the aeolian lithofacies, followed by fluvial and then sabkha lithofacies (Fig. 10). Distribution of reservoir parameters are controlled primarily by the distribution of the lithofacies (principally due to grain size, sorting and detrital clay content), but secondarily by diagenesis due to burial. The development of authigenic illite within pore throats
during deep burial can significantly reduce permeabilities, such as seen on the neighbouring Ravenspurn North Field (Turner et al. 1993) and commonly seen elsewhere in the Southern North Sea (e.g. the Jupiter fields (Leveille et al. 1997). Fortunately, the Johnston reservoir is not believed to have been buried to the same degree and illite is only found in low abundance.
Reservoir zonation
The reservoir zonation for the Johnston Field has been developed using the combined tools of sedimentology, sequence stratigraphy, petrophysics and magnetostratigraphy. Using these techniques, a nine zone reservoir scheme has been established for the field (Fig. 11). Most of the techniques employed are common place, but magnetostratigraphy has only relatively recently become an established stratigraphical technique. Magnetostratigraphy involves the measurement of natural remnant magnetization in sediments and allows the calibration of the stratigraphy by identifying the known magnetic polarity and reversals; as documented from outcrop (Collinson et al. 1967; Tarling 1983; Hailwood 1989). A framework of 13 magnetozones have been established for the Johnston area, which have been integrated with the depositional model. A example cross-section is illustrated in Fig. 12. The reservoir zonation has also been calibrated to include pressure depletion information seen in the repeat formation test (RFT) data from well 42/27a-J3 (caused by early production from wells J1 and J2) and has been supported by the field production performance data, as modelled in reservoir simulation. The lowest zones, 1 and 2, infill the Variscan topography of the underlying Carboniferous strata and are only encountered in certain parts of the field and surrounding area. Zones 3 to 9 are seen in all field wells (with the exception of the J3 horizontal well) and are widespread in all other offset wells. Zone 1 is the basal reservoir zone. This zone represents the main phase of the infilling of the irregular Variscan terrain. It is only seen in wells 43/26a-8 and 43/27-J1, where it varies between 90ft and 108ft thick. Zone 1 consists of predominately structureless fluvial sediments, which were deposited in an alluvial fan environment. The zone is characterized by one magnetozone (M 1). With the exception of the 43/27a-J3 pilot hole (and horizontal sidetrack), Zone 2 is seen in all other field wells and represents the
10000
Facies Identified 0 1000
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4r
9
t
9 o
Aeolian
z~ Sabkha 9
Fluvial
' ~ Playa Lake
100 . . . . . . . . . . . . . . .
d o o ~ o ~ - - -~
.e
9 . . . . . . . . . . . . . . . . .
10
, ~-
i
~
: ", .
-
~
-
9
o
m,
.
.
.
.
.
.
.
.
.
.
. . . . . . . . . . . . . . . .
,o '
~~NilDINNN-9 .
-6 . . . . . . . . . . . .
,
0
9 ~.. m'-- ~ . m
o 9
mm
. , 9~
9
. . . . . . . . . . . . . . . .
9
9
m,
-r
O
_m _ ' ~
7-
......
O~
.
o .
.
,
.
.
.
.
.
.
.
.
.
.
.
.
',0 9 0.01 0
~
,
9
,
l
I
i 5
10
15
HeliumPorosity%
20
Fig. 10. 43/27a-J3 porosity and permeability data by facies association.
JOHNSTON GAS FIELD
757
zone consists predominately of fluvial sandstones interbedded with playa lake siltstone, deposited during a climatic wet phase. This zone is defined by two magnetozones (M6 and M7). Zone 6 has a very uniform thickness and is around 45 ft in all field wells. The base of this zone is marked by another flooding event, which is seen as a thin deposit of playa lake siltstones and claystones. Above this unit the rest of the zones consist of fluvial sheetflood sandstones that are interbedded with aeolian sandstones and represents a drying upward cycle. This zone consists of two magnetozones (M8 and M9). Zone 7 varies in thickness between 9 ft and 25 ft. This zone consists predominantly of structured and massive fluvial sheetflood sandstones, that have been locally reworked as isolated remnant dunes. The base of this zone is marked by a rise in water table and the development of playa lake sediments, marking the onset of the changes leading to the Silverpit lake transgression. This zone is defined by two magnetozones (M10 and M11). Zone 8 varies in thickness between 13 ft and 20 ft. The zone consists of a thin local development of aeolian sandstone interbedded with playa lake siltstone and claystone. This zone is defined by a single magnetozone (M12). Zone 9 varies in thickness between 20ft and 30ft. This zone represents a transition between the Lower Leman Sandstone Formation and the overlying Silverpit Shale Formation. It comprises minor aeolian dune and fluvial sandstones, that have been demonstrated from pressure data to be isolated from the main reservoir units. This zone is defined by a single magnetozone (M13).
Hydrocarbon character The hydrocarbon from the Johnston Field is a dry gas, with a specific gravity of 0.606 and a calorific value of 998 BTU/SCF. Liquid yields are < 5 B B L / M M S C F . A gas-water contact of ( - 1 0 6 4 4 f t ) TVDss has been confirmed by wireline log and R F T data from the field wells, with a gas gradient of 0.08 PSI/ft and a water leg gradient of 0.51 psi/ft.
Reserves
Fig. 11. Johnston Field reservoir zonation.
final infilling of the Variscan terrain. This zone is defined by a single magnetozone (M2) and varies between 19 ft and 38 ft thick. It consists of silty claystone deposited in playa lake margin and sabkha settings, during a climatic wet phase. Zone 3 varies in thickness between 18 ft and 50 ft in the field wells and consists predominately of fluvial sheetflood sandstones, with isolated aeolian sandsheets. This zone consists of two magnetozones (M3 and lower part of M4). Zone 4 varies in thickness between 21 ft and 44 ft as seen in the field wells. It consists predominately of aeolian dune sandstones, deposited in a drier climatic regime. Towards the upper part of this zone there is an increased dominance of fluvial sandstones, interbedded with sabkha siltstone and aeolian sandstones. This upper part represents deposition in progressively wetter climatic conditions and with fluctuations in the water table, giving rise to the preservation of the deposits of this zone. This zone consists of two magnetozones (upper part of M4 and M5). Zone 5 varies in thickness between 28 ft and 47 ft in the field wells. The base of this zone is marked by a major flooding surface, which consists of playa lake silty shales. These shales act as a significant barrier to production within the field. The rest of this
At the time of project sanction gas initially-in-place (GIIP) estimates were between 200 and 270 BCF. Following the completion of the three development wells, the acquisition of the 3D seismic survey and analysis of the production data, the GIIP is now calculated to be between 360 and 403 BCF. The nature of the reservoir's recovery mechanism has not yet been fully established. However, the limited extent of the reservoir to the north and east, and the fault seal to the south and west, suggests that an active aquifer would be limited in size and from the geological model of reduced reservoir quality. To date no evidence of water encroachment has been seen from the production wells. Results of reservoir simulation and history matching indicate that a recovery of between 60% and 75% can be expected. The field is currently expected to be on-plateau until at least the year 2002 and has an economic field life until 2008.
Development plan The Johnston Field has been developed using a four slot sub-sea template, from which three development wells have to date been drilled. This sub-sea template contains the wellheads, the control system and the manifold pipework. It has been designed for minimum maintenance and is enclosed in a protective structure to guard against dropped objects or trawl gear impacts. Gas production from the sub-sea template is transported to the BP Amoco operated Ravenspurn North Central Processing platform via a 12" diameter sub-sea pipeline. Here liquids are removed, the gas is metered and then commingled with Ravenspurn North
758
D. E. L A W T O N & P. P. ROBERSON
9
& b
E
d
JOHNSTON GAS FIELD gas. The R a v e n s p u r n N o r t h Central Processing platform provides hydrate inhibition and pipeline corrosion chemicals to the J o h n s t o n template via a 2" diameter pipeline, which is piggy backed with the gas export pipeline. All control for the J o h n s t o n Field is carried out from the R a v e n s p u r n N o r t h facility. F r o m R a v e n s p u r n N o r t h the gas is exported to the Cleeton platform via a 24" diameter sub-sea pipeline. At the Cleeton platform the c o m b i n e d R a v e n s p u r n N o r t h and J o h n s t o n p r o d u c t i o n is c o m m i n g l e d with Cleeton and R a v e n s p u r n South p r o d u c t i o n , before being transported to the onshore terminal at Dimlington, via a 36" diameter sub-sea pipeline. The authors acknowledge the efforts and achievements of the many individuals from oil companies and consultants that have contributed to the exploration, discovery and development of the Johnston Field. In particular the authors would like to thank Judy Ayers-Morgan, Richard Tomlins, Mark Hazel, Keith Boyle, Ann King, PM Geos and Pole Position for their assistance with the preparation of this paper. Thanks are also given to the internal and external reviewers of this paper. Finally, special thanks are given to the existing Johnston partnership for their permission to publish this paper, whilst recognizing that the views expressed in this paper may not necessarily be those of all partners within the Johnston Unit.
Johnston Field data summary Trap Type Depth to crest Gas-water contact Vertical closure
Tilted Fault Block (-10249/) TVDss (-10 644') TVDss c. 400'
Pay zone Formation Age Thickness (average) Net/gross ratio Porosity (average) Hydrocarbon saturation (average) Permeability (Average)
Lower Leman Sandstone Formation Early Permian 162-37 5ft (280 ft) 100% 7%-17.5% (11%) 50%-85% (75%) 1-800 mD (10 mD)
Hydrocarbons Gas composition
Specific gas gravity Calorific value Gas expansion factor Initial condensate/gas ratio
C1 91.5%, C2 2.4%, N 3.9%, C02 1.1%. 0.606 998 BTU/SCF 240 <5 BBL/MMSCF
Formation water Water gradient Salinity Resistivity Other ions
0.51 psi/ft 175000 ppm 0.017 ohmm at 227~ None
Reservoir conditions Temperature Initial pressure
227~ at (-10 644ft TVDss) 4730 psia at ( - 10 64 4 ft TVDss)
Field size Area Gas initially-in-place Recovery factor Drive mechanism Production First gas Development scheme
4744.5 acres (19.2km 2) 360-403 BCF 60-75% Unconfirmed October 1994 Sub-sea template
Number/type of wells Production rate Cumulative production Secondary recovery method(s)
759 3 (including 1 horizontal) 90 MMSCFD (contract constrained) 67 762 MMSCF (September 1998) None
References COLLINSON, D. W., CREER,K. M. & RUNCORN, S. K. (eds) 1967. Methods in Palaeomagnetism. Elsevier, Amsterdam. CORYFORD, C. 1990. Source rocks and hydrocarbons of the North Sea. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford, 294-361. GEORGE, G. T. & BERRY, J. K. 1993. A new lithostratigraphy and depositional model for the Upper Rotliegend of the UK sector of the Southern North Sea. In: NORTH, C. P. & PROSSER, D. J. (eds) Characterization of Fluvial and Aeolian Reservoirs. Geological Society, London, Special Publications, 73, 295-620. GEORGE, G. T. & BERRY, J. K. 1997. Permian (Upper Rotliegend) synsedimentary tectonics, basin development and paleogeography of the southern North Sea. In: ZIEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 31-61. GLENNIE, K. W. 1990. Lower Permian - Rotliegend. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford, 120-152. GLENNIE, K. W. 1997. Recent advances in understanding the southern North Sea Basin: a summary. In: ZIEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology oJ"the Southern North Sea." Future Potential. Geological Society, London, Special Publications, 123, 17-29. HAILWOOD, E. A. 1989. Magnetostratigraphy. Geological Society, London, Special Report, 19. HOWELL, J. & MOUNTNEY, N. 1997. Climatic cyclicity and accommodation space in arid to semi-arid depositional systems: an example from the Rotliegend Group of the UK southern North Sea. In: ZIEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea." Future Potential. Geological Society, London, Special Publications, 123, 63-86. KETTER, F. J. 1991a. The Ravenspurn North Field, Blocks 42/30, 43/26a, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields'." 25 Year Commemorative Volume. Geological Society, London, Memoirs, 14, 459-467. KETTER, F. J. 1991b. The Esmond, Forbes and Gordon Fields, Blocks 43/8a, 43/13a, 43/15a, 43/20a, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Year Commemorative Volume. Geological Society, London, Memoirs, 14, 425-432. LEVEILLE,G. P., PRIMMER, T. J., DUDLEY, G., ELLIS, D. & ALLINSON,G. J. 1997. Diagenetic controls on reservoir quality in Permian Rotliegendes sandstones, Jupiter Fields area, southern North Sea. In: ZIEGLER,K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea." Future Potential. Geological Society, London, Special Publications, 123, 105-122. OUDMAYER, B. C. • DE JAGER, J. 1993. Fault reactivation and oblique slip in the Southern North Sea. In." PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1281-1290. PARSLEY, A. J. 1990. North Sea Hydrocarbon Plays. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford, 382-384. TARLING, D. H. 1983. Palaeomagnetism: Principles and Applications in Geology. Geophysics and Archaeology. Chapman and Hall, London. TURNER, P., JONES,M., PROSSER, O. J., WILLIAMS,G. U. & SEARL,A. 1993. Structural and sedimentological controls on diagenesis in the Ravenspurn North gas reservoir, U K Southern North Sea. In." PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 771-785.
The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea A. P. H I L L I E R Shell UK Expro, PO Box 4 Lothing Depot, North Quay, Lowestoft, Suffolk NR32 2TH, UK
Abstract: Discovered in 1966 and starting production in 1968, Leman was the second gas field to come into production in the UK sector of the North Sea and is still producing gas today. It is classified as a giant field with an estimated initial gas-in-place of 397 BCM of gas in the aeolian dune sands of the Rotliegend Group. The field extends over five blocks and is being developed by two licence groups with Shell and Amoco (now BP Amoco) being the operators.
This paper is an update of the paper by Hillier & Williams in the 1991 Geological Society Memoir No.14 and repeats much of the information given there.
Location The Leman Field is situated in the southern part of the British sector of the North Sea, some 50 km NE of Bacton on the Norfolk Coast. It is classified as a giant gas field (Carmalt & St John 1986). The Leman Field extends into five licence blocks (UK Blocks 49/26, 49/27, 49/28, 53/1 and 53/2), in which a total of 13 companies had separate interests by virtue of their production licences. These 13 companies are combined into two production groups, Shell/ExxonMobil and the East Leman Unit (ELU), for which Shell and BP/Amoco are the respective operators. The current estimate of ultimate recovery is 360.3 BCM of which 298.8 BCM had been produced by the start of 2000. The field comprises a faulted, elongate periclinal structure oriented N W - S E (Fig. 1) and covers an area of some 390 square kilometres. The field is located at the southern end of the Sole Pit Basin between two major fault zones: The Dowsing/South Hewett faults and the Swarte Bank hinge line. The reservoir comprises the Permian Rotliegend Group Leman Sandstone Formation (550-900 ft thick), capped by the overlying Zechstein evaporites (Fig. 2a) and sourced from the underlying Westphalian Coal Measures.
History In 1959, interest in exploration in the southern North Sea was first generated by the discovery of the giant Groningen Gas Field in the Netherlands. Extrapolation of geological data from this area to the exposures of similar sandstone in Durham, England, led to the belief that the Leman Sandstone would be present beneath the southern North Sea. Shell U K Exploration and Production, acting as operator for a 50/50 joint venture with Esso Exploration and Production U K Ltd in the U K North Sea, took up several First Round licences in 1964. The Leman Field discovery well (49/26-1), the eleventh to be drilled in the U K sector of the North Sea, was spudded on the 17 December 1965 and abandoned on the 18 April 1966 after testing had proved a potentially large gas accumulation. The play concept tested was simple. A seismic survey on a 5 km grid with fourfold coverage had been acquired over Block 49/26 in 1964. The deepest seismic reflection recorded corresponded to the base of the upper salt (Leine Halite Formation) in the Zechstein at which level a very large domal structure 21 by 13 kilometres was mapped; the discovery well was sited on the crest of the dome (Fig. 3). The Permian Rotliegend Leman sandstone reservoir was found at a depth of 5914ft TVDss. The reservoir was 921 ft thick with 804 ft of net gas-bearing sand and a porosity of 14%, above a gaswater contact at 6718 ft TVDss. A production test over the interval 6334-6454ft produced good quality gas at a rate of 0.48 million cubic metres per day through a 9/16 inch choke.
Following the discovery well, fourteen outstep appraisal wells were drilled to delineate the Leman structure. Extensions into adjacent licence block areas were subsequently proven by wells 49/27-1 in September 1966, 49/28-1 in October 1967 and 53/2 in January 1968. Appraisal wells, 49/26-2 to 49/26-5, 49/26-14 and 49/26-25 together with wells 49/27-2 to 5 provide excellent control on the main field, whilst the southern limit is defined by Mobil wells 53/2-1 and -2. The N W flank of the Leman Field was further defined by well 49/26-26 in early 1982 before being developed with fracture stimulated wells from two new platforms. A further horizontal appraisal well 49/26-27 was drilled in 1995 to test the low permeability in the far N W flank. The presence of a Carboniferous field below the Rotliegend field was disproved by well 49/26-28; drilled to a Carboniferous penetration of 4800ft in 1998. Figure 4 shows the locations of the exploration and appraisal wells drilled in the field. The Leman Field, following appraisal drilling, now comprises a total of 192 development wells drilled to date from sixteen platforms. Gas delivery onshore is to Bacton via two 30 inch diameter pipelines, there were originally three pipelines but one was mothballed in 1995.
Structure The southern North Sea Permian sedimentary basin developed over the northern foreland of the Variscan orogenic belt. This mountain belt was created by the northwards movement of Gondwana and its subsequent collision with Laurasia. As a result of these collisional tectonics, the foreland was shortened, uplifted and eroded in the late Carboniferous. The southern North Sea Permian Basin developed on the site of an earlier, Westphalian Basin. By the late Permian, it became a broad feature, some 1500 km long and 500 km wide, parallel to and in front of, the E - W Variscan mountain belt. Sedimentation in the southern North Sea Basin continued into the late Cretaceous. During the Alpine orogenic phase, N W Europe experienced N - S directed compressional forces that re-activated some of the Variscan structural elements. This gave rise to dextral movement along the existing NW-SE-oriented normal faults. As a result, the Cimmerian-Early Tertiary sedimentary basins were inverted, e.g. Sole Pit and West Netherlands Basins (Ziegler 1982). The inversion resulted in erosion of up to 4000 ft of sediments from the area of the Leman Field. From the Eocene onwards, the compressional stress regime relaxed and the North Sea subsided. A continuous, undisturbed stratigraphical sequence was deposited from Miocene to present. The Leman field is located at the southern end of the Sole Pit Basin between two major fault zones; the Dowsing/South Hewett faults and the Swarte Bank Hinge. These are part of a N W - S E trending set of steep normal faults, created during the Variscan orogeny. They were reactivated (with right-lateral strike slip movements) during the Alpine orogeny and were most active during late Cretaceous and early Tertiary (Glennie & Boegner 1981). In 1964, seismic data was acquired over the area on a 5 k m spacing with only fourfold coverage. This grid delineated structural highs at the deepest visible reflector which was within the Zechstein.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 761-770.
761
762
A.P. HILLIER
O O
._1 ~
d,
o
9
~
r
(a)
(b)
GAMMA RAY LOG 0
GROUP
FORMATION
150
F D C LOG BULK DENSITY 2 2 5 2 5 0 gm/cc
LITHO. LOGY
MEMBER
z
0' NORTH SEA
,,, ,.w-TRITON ANHYDRITIC
~
KEUPER HALITE DUDGEON SALIFEROUS
1ooo' /
"iF
HAISBOROUGH LOWER KEUPER
~
UPPER DOWSING ~ MUSCHELKALK HALITE
~ ~
/
"~ ' _
i ~
_
i
/
~ X . ~"~ 2000'
DOWSING DOLOMITIC INTERMEDIATE ROT
/
/
"~';';';';
ii is ii
,< ,<
/ /
,...,..,.......,
:'.'.'.'.'.'."
BUNTER SANDSTONE ROGENSTEIN
BACTON
/
/
/
t
MAIN BUNTER SHALE
4000'
ALLER HALITE
ZECHSTEINIV
I
I
/
~
BUNTER SHALE
/
/
_J..6J/:LSJ:I&.IZF.~~
ZECHSTEINIII
HAUPT ANHYDRITE PLATTEN DOLOMITE STASSFURT HALITE BASAL ANHYDRITE HAUPT DOLOMITE WERRA ANHYDRITE WERRA HALITE LOWER WERRAANHYDRITE ZECHSTEINKALK
ZECHSTEINII ZECHSTEIN ZECHSTEIN I KUPFERSCHIEFER
ROTLIEGENDES
/
3000'
,_%...,..~ ,.....%....,.., ,.........,.... ;.~176 ........ "'"'"'"'""
LEMAN SANDSTONE
5000;
- - ^ ^ ^ 1 i
/
^ ^ ^ ....................
/
/
~
^ ^ ^ ~
/
/ '
.~...:.:.:.
ASAND
~
B SAND
~
C SAND
~
:..,...........~
. . . . . iii:: 9 . . . . . .:.:.., :::: 9
,,m D
COAL MEASURES
.o,
Fig. 2. (a) General lithostratigraphy of the Leman Field. (b) Detailed lithostratigraphy of the Rotliegendes sandstone reservoir sequences.
\\
"53~
//Z, tf-~ //A~
'
"
i ~..r,
!
2~0'
,\ 53o10 '
j
AMOCO 49/27
I
\
'/X /*l| f I C
'
/
I
\ 4s/2s-i~
i}
\X
|
I ~"-..'~
\
\
ooo, GAS/WATER CONTACT \
%
0
2
I_
i
4kin
I
S3oOS'
\ \i~! \ I "__./4/
", '
Fig. 3. Original Top Reservoir map after discovery in 1966 based on 5-km seismic grid interpreted at Base Leine Halite Level. Note contours are in metres sub-sea.
764
A . P . HILLIER
2~
,
E
2~
'
2~
E
'
E 53~I0.00
53~0,00
'
'
N
N
Fig. 4. Leman Field exploration and appraisal well locations. From onshore data the Rotliegend was expected to lie more or less conformably below this reflector. Hence, the discovery well was located on the crest of the seismic time high. Some infill data was acquired after the discovery and the field appraised. A refined structural image of the Leman Field was derived from the seismic surveys acquired in 1980 and 1981 (200 m by 400 m grid over the crest of the structure and 400m over the flank areas). These data, which were the first surveys in which the reservoir could be imaged and directly mapped, were first interpreted in 1983. A 3D seismic survey was shot over the Shell /Esso part of the field in 1992, interpreted and mapped with the 2D over the E L U being tied in. The 3D cover over the ELU part of the field was acquired in 1995 and merged with the earlier 3D data to provide a full field survey. Severe absorption of seismic energy from the Zechstein salts together with acquisition problems due to the shallow water depth in parts of the field led to difficulties in directly mapping the top Reservoir on the 3D data. The current map used for reservoir development (Fig. I) is based on the 3D data, with the fault pattern being derived by use of the seismic attributes (amplitude, dip, azimuth, edge and coherency) in the overlying Haupt Anhydrite/Platten Dolomite and the Rotliegend itself. The following seismic markers were picked and used for depth conversion of the seismic data using a layer-cake model, with seismic velocity maps being derived for each layer based on well inter-sections and well-shoot data. Each depth converted map was tied to well data. Top Top Top Top
R6t Evaporite Br6ckelschiefer Haute Anhydrite/Platten Dolomite Rotliegend.
A seismic line from N W to SE through the platforms is shown as Figure 5 and structural cross-sections both along this line and across it are shown in Figure 6.
Field stratigraphy The general stratigraphical sequence of the Leman Field is well known and illustrated in Figure 2a. Unconformities are present in the sequence between the Carboniferous and Permian, at the base and the top of the Cretaceous. Pre-Carboniferous stratigraphy is unknown from either well penetration or seismic interpretation across the field but Old Red Sandstone facies of the Devonian has been encountered in wells to the north and south of the area. The Westphalian Coal Measures sequence comprises mainly purple-grey mudrocks and sandstones with subordinate coals that sourced the gas. In the U K North Sea the Rotliegend Group is composed of two formations, the Leman Sandstone Formation which is the reservoir and the Silverpit Formation a claystone which is not present in the field area (Rhys 1975). By common usage, the name Rotliegend has been adopted for the Leman Sandstone Formation. The Rotliegend sandstone was deposited on the eroded Carboniferous terrain in a hot, arid environment and is divided into three zones based on depositional environment, waterlain fluvial sands at the base, aeolian in the middle and a reworked aeolian assemblage at the top (Fig. 2b). The source of the fluvial Rotliegend sediment was the London-Brabant Massif, whilst the aeolian dune sands were sourced by denudation of the Variscan Mountains to the east of the field (Glennie et al. 1978). The Zechstein sediments that cap the Rotliegend are composed of four cycles of evaporites. The Stassfurt Halite in cycle II containing interbedded potassium and magnesium salts exhibits considerable variability in thickness as it exhibits plastic flow in accommodating fault movement in the underlying strata. The Zechstein is important as the cap rock for the reservoir. The Triassic sequence of the Leman Field exhibits a continuation of the depositional styles encountered in hot, dry evaporitic settings of hydrologically-closed basins. The basal Triassic unit, the Bacton Group, is divided into two formations. The lower is the Bunter
L E M A N FIELD
765
z~
d~
9
= 9
e..)
I
8CINOO3SI7711AI NI ::IIAill AVM-~
Id
766
A . P . HILLIER
Fig. 6. Leman Field structural cross-sections. Vertical exaggeration x4.
LEMAN FIELD Shale, subdivided into a basal member the Brockelschiefer, a red-brown siltstone and the Main Bunter Claystone, a red-brown claystone, the upper part of which the Rogenstein Member is differentiated by the presence of thin oolitic horizons. The upper formation is the Bunter Sandstone Formation, a red-brown sandstone with claystone interbeds and lenses, and in which circulation is commonly lost while drilling. The Bunter Sandstone commonly displays good reservoir properties but is not charged with gas in the field area. The upper part of the Triassic, the Haisborough Group, consists of an alternating sequence of red and brown claystones with interbedded halite and siltstone. A major marine incursion into the area began in the Rhaetic and is followed by the wholly-marine Jurassic claystones and Cretaceous chalk. Although at one time these marine sequences provided extensive cover, they have been subsequently eroded over the major part of the Leman Field. Undifferentiated Quaternary-Tertiary marine sands and clays occupy the highest stratigraphical position across the field area and comprise some 300 ft or so of sediment directly below the sea bed.
Trap The Leman Field is a single reservoir, dip-closed periclinal trap. The maximum closure is 1100 ft, with the top and lateral seals being formed by the Zechstein cap rock. The gas-water contact for the field is taken as 6700 ft TVDss, equivalent to the spill point of the field. The exact gas-wate r contact is difficult to define due to capillary effects in the reservoir that result in long transition zones between gas and water. The original reservoir pressure of 3020 psi at 6500ft TVDss was slightly above hydrostatic. Recent drilling showed that some of the faulting within the reservoir, whilst not
Fig. 7. Reservoir type log (49/26-25), with field averages for zonal petrophysical parameters.
767
offsetting the reservoir does cause partial compartmentalization on a production time scale with faults breaking down after some differential depletion. The trap was probably initially formed at the time of the Late Cimmerian Inversion of the Sole Pit Basin and has possibly been enlarged by late Cretaceous and Early Tertiary phases of inversion.
Reservoir The depositional setting of the field is interpreted to be the main dune field between the eroding London-Brabant Platform and a major desert lake to the north. In the Leman Field the Rotliegend has been divided into three units based on mode of deposition. From the base upwards these are: wadi, dune and reworked or waterlain sediments (van Veen 1975). These are equivalent to the fluvial, aeolian and 'Weissliegend' of Glennie (1986; Fig. 2b). The entire Rotliegend sandstone contains reservoir quality rock. The aeolian dune sands can be divided into two reservoir zones, 'A' and 'B' on the basis of porosity/permeability relationships. A study of the dune sands shows that the upper part, about 400 ft, is more cemented than the lower part (Arthur et al. 1986). Hence for reservoir simulation work, a threefold zonation of the reservoir was established with the third zone 'C' being composed of the wadi deposits. Porosity and permeability measurements for these zones can be seen in Table 1. These results were derived from core data from 32 wells in the field, which adequately defined the petrophysical parameters. The improvement of reservoir quality from west to east is shown by the averages. Figure 7 shows a type log with average petrophysical parameters for the field.
768
A . P . HILLIER
Table l. Porosity and permeability measurements for zones A, B and C
Block
49/26
49/27
Parameter
Av. Porosity
Av. Av. Permeability Porosity
Av. Permeability
A-sand B-sand C-sand
12.05% 13.54% 9.30%
1.02mD 6.03 mD 0.55mD
2.45mD 15.60 mD 4.67mD
13.70% 15.06% 12.61%
The C zone is of little commercial importance as a reservoir as it is below the gas-water contact over most of the field and has a low porosity due to poor sorting and early cementation exhibited by the sandstones. The B zone consists of stacked grey-green or red-brown, fine to medium-grained aeolian dune sandstones. These sandstones are made up of foreset beds, which have millimetre to centimetre laminae dipping at about 25 -0. Each lamina is itself extremely well sorted; but there is great variation in median grain size from one lamina to the next. This variation causes large changes in permeability (Fig. 8). Each dune consists of a series of foreset beds
SCALE (cm.)
015.5
!t b
o fsA .LE 222'\ .
36~1
0
PoR. JT.~o/o j \ PE,M , , . ,
~
~
\
0, o
~-
O
f
/
d
separated from the preceding dune by poorly sorted, horizontally stratified bottomsets. The B zone sandstones are in general poorly cemented and comprise the best quality reservoir rocks in the field. The zone varies in thickness between 25 ft and 400 ft. The A zone consists of both dune sands and the Weissliegend (Fig. 2b). The A zone is differentiated from the B zone by the increased amount of interstitial cement, particularly grain-coating hematite and illite. The illite, occurring in a fibrous form, tends to have greater effect on the permeability of the rock than would be expected from its effect on the porosity (Stalder 1973). The source of this additional cement is not fully understood but it could be from either a large proportion of unstable silicates transported from the hinterland or a greater proportion of detrial clay derived from the sabkha facies that was present in the Sole Pit area to the north. Cementation within the uppermost Rotliegend is further complicated by the influence of the mineral rich Zechstein pore water (Glennie et al. 1978). The thickness of the A zone varies between 100 ft and 650 ft. The A zone, although volumetrically greater than the other two zones, is a poorer reservoir than the B zone due to this increased cementation. It has been shown that the permeability for a given porosity in the B zone is three to seven times higher than that in the A zone. The porosity in all the Rotliegend zones is intergranular and modified by the diagenetic effects of palaeoburial. As the field was buried unevenly (the N W some 4000 ft and the SE some 3000 ft deeper than the present depth), the diagenetic effects are accordingly uneven across the field. Diagenesis consists of quartz overgrowths, dolomite and fibrous illite deposition in the pore throats (Glennie et al. 1978; Arthur et al. 1986). Fractures, both open and cemented, are visible in virtually all the cored wells in the field. Their contribution to the flow of the wells in the majority of the field is insignificant; but in the N W where the deeper palaeoburial caused more severe diagenetic permeability reduction, they have a measurable effect, raising the productivity of wells by up to 50%. Porosity and permeability varies considerably across the field. Cross-plots of porosity and permeability show an areal variation in the relationship; for given porosity, lower permeability is found in the NW. Porosity permeability cross-plots for two wells, one from the tighter N W and the other from the better reservoir quality in the centre of the field, are shown in Figure 9. The individual samples for a given porosity show a wide variation in permeability. This is due to the depositional environment e.g. wellsorted dune sand lamina with similar porosity. There is, however, a great variation in median grain size and therefore in the permeability. Capillary pressure curves show that there is a very long transition zone above the free water level especially in zones A and C. The pay zone comprises the entire Rotliegend in the most crestal parts of the field and is up to 900 ft thick. However, due to the low general relief of the field some 80% of the gas is contained in the A zone. Barriers to flow within the reservoir are related to faulting and depositional style. Faulting, particularly in the southern and eastern parts of the field, created N W - S E trending compartments. On the other hand wind-deposited dune bottomset beds separate the cross-bedded dune foresets. The bottomset beds, which are finely laminated, poorly sorted and carbonate cemented, are relatively poor reservoir rocks. Their permeabilities are one or even two orders of magnitude lower than those of the better quality dune avalanche foresets. The dune foreset beds have a strongly anisotropic permeability distribution. The permeability along a dune slip-face is much higher than that perpendicular to the slip face. Weber (1987) showed that, by analogy to the Permian de Chelly sandstone in northeastern Arizona, length/width/height ratios of around 200/75/1 can be expected. Given an average cross-bed height of 15 ft, an avalanche set in the Leman Field would be 1000 m long 300 m wide.
Source
Fig. 8. Sketch of core showing rapid permeability variation between adjacent laminae of slip face sands.
The source for the gas in the Leman Field, and indeed for all the other southern North Sea gas fields (Martin & Evans 1988), is
LEMAN FIELD
769
Fig. 9. Porosity-permeability relations for two specimen wells showing the areal variation in the relationship. For well locations, see Figure 4. Regressions lines: red, A-sand, brown, B-sand; blue, C-sand; purple, all data.
the Westphalian Coal Measures, which directly underlie the reservoir. Migration paths are supplied by the sandstones within the Westphalian, which have extensive areas of contact with both the coals and carbonaceous shales that are the actual sources. These sandstones form the conduits from the source at generation time to the reservoir. The reservoir unconformably overlies the Westphalian and hence is a very good hydraulic connection. The time of migration coincided with the time of maximum depth of burial during the Jurassic and Cretaceous. The gas first migrated to the then structurally higher flanks of the Sole Pit Basin. Later, during and after the structural inversion and formation of the trap in the Late Cretaceous, the gas re-migrated back into the field. The fact that the gas remained trapped until the present, demonstrates the efficiency of the seal formed by the Zechstein evaporites. The source has two components, carbonaceous shales with 1% total organic carbon (TOC) and coals with 60% TOC. The kerogen type is II/III-III. The potential yield for the shale is 0.1 MCF/acre ft and for the coal 7.0 MCF/acre ft (Cornford 1986). The source rock has vitrinite reflectance maturation of 1.6 to 2.1.
within the reservoir. This necessitated a wider spread of drainage points to fully develop the reserves. This wider spread of well data together with the reservoir faulting gave a more accurate depth map and hence a better reserves estimate. The reserves published in the 1991 Commemorative Atlas (Hillier & Williams 1991) were based on this mapping. The reduced permeability of the A zone relative to the B zone also allowed noticeable pressure gradients to develop in areas where t h e B zone was below the gas-water contact, thus ineffectively draining some flank areas of the field. The original concept of the field behaving like a gas cylinder, and therefore needing only a limited number of centrally located drainage points to develop was found to be incorrect by the high pressures measured in appraisal well 49/26-26 drilled in 1982. These pressure gradients mean that the use of P/Z plots where average pressure is plotted against production are not valid to estimate connected gas for the field. Gas flow from the flanks of the field means that these plots are not straight lines. The 3D maps of the field gave a better fault and structural interpretation and have been used for updating the volumetric estimates of field reserves.
Hydrocarbons The gas is sweet and lean with 95% methane, very little carbon dioxide and a condensate/gas ratio of only 1 BBL/MMSCF. An analysis is given in Table 2.
Reserves The reserves history of the field is tied very much to the ability to image the field and to define the barriers both real and potential within the field. The earliest reserves estimates were based on maps of top reservoir isochored down from the base of the Leine Halite, and hence reservoir faulting was unrecognized. The early wells were drilled in a radial pattern round the platforms, which reduced the spread of data points for tying the maps. In 1982, the top reservoir was mapped for the first time directly from 2D seismic and reservoir faulting was identified. Although no individual fault in the field has sufficient throw to offset the reservoir, there is evidence that some faults act as baffles
Table 2. Components of the 49/26-1 well Component Methane Ethane Propane Iso-butane N-butane Iso-pentane N-pentane Hexanes Heptanes plus Helium Nitrogen Carbon Dioxide Total Mol. weight
Separator gas mol % 95.05 2.86 0.49 0.08 0.09 0.03 0.02 0.02 0.04 0.02 1.26 0.04 100.00 16.9
770
A . P . HILLIER
T h e field is n o w e s t i m a t e d to have an initial gas-in-place o f 397 B C M a n d an u l t i m a t e recovery o f 360.3 B C M . T h e reserves q u o t e d in 1991 were 392.5 B C M in-place a n d 326.3 B C M recoverable. T h e c h a n g e in gas-in-place figures is d u e to an increase in gross g a s - s a n d v o l u m e derived f r o m the n e w 3D seismic structure m a p , whilst the increase in recovery f a c t o r f r o m 8 3 % to 90.8% is d u e to i m p r o v e d field p e r f o r m a n c e .
Production First gas Development scheme Cumulative production
This paper is an update by one of the authors of the paper published in Memoir 14. Shell UK Exploration and Production, Esso Exploration and Production UK Ltd and the East Leman Unit are thanked for permission to publish this paper. The advice and assistance of numerous colleagues within Shell and the use of much unpublished data on the field from internal reports has greatly eased the job of the author.
References
Leman Field data summary Trap Type Depth to crest Lowest closing contour Free water level Gas column
Faulted Pericline 5850 ft 6700 ft 6700 ft 850 ft
Pay zone Formation Age Gross thickness Net/Gross ratio Net sand cut-off Porosity Gas saturation Matrix permeability
Leman Sandstone Permian 800 ft 100% None Used 12% 59% 0.5-15 mD
Hydrocarbons Gas gravity Gas type Condensate yield
0.585 Sweet Dry 1.0 BBL/MMSCF
Formation water Salinity Resistivity
240 000 ppm 0.026 ohm m @ 125~
Reservoir conditions Temperature Pressure Pressure gradient
125~ 3022 psia initial 0.08 psi/ft
Field size Area Gas expansion factor Gas initially-in-place Drive mechanism Recovery factor Recoverable reserves
253 km 2 210.9 397 BCM Depletion 91% 360 BCM
Aug 1968 multiple wellhead platforms 296 BCM
ARTHUR, T. J., PILLING, D., BUSH, D. & MAACHI, L. 1986. The Leman Sandstone Formation in UK Block 49/28. Sedimentation, diagenesis and burial history. In: BROOKS, J., GOFF, J. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23, 251-266 CARMALT, S. W. & ST. JOHN, B. 1986. Giant Oil and Gas Fields. In: HALBOUTY, M. T. (ed.) Future Petroleum Provinces of the World. American Association of Petroleum Geologists, Memoir, 40, 11-54. CORNFORD, C. 1986. Source rocks and hydrocarbons of the North Sea. In: GLENNIE, K W (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 197-236. GLENNIE, K. W. 1986. Early Permian Rotlegend. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 63-85. GLENNIE, K. W. & BOEGNER, P. L. E. 1981. Sole Pit Inversion Tectonics. ln: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe. Heyden and Son Ltd, London, 110-120. GLENNIE, K. W., MUDD, G. C. & NAGTEGAAL, P. J. C. 1978. Depositional environment and diagenesis of Permian Rotligendes Sandstone in Leman Bank and Sole Pit Areas of the UK southern North Sea. Journal of the Geological Society, London, 135, 25-34. HILUER, A. P. & WILUAMS, B. P. J. 1991. Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea. In: ABBOTTS,I. L. (ed.) United Kingdom Oil and Gas Fields. 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 451-458. MARTIN, J. H. & EVANS, P. F. 1988. Reservoir modelling of marginal Aeolian/Sabkha Sequences, southern North Sea. Society of Petroleum Engineers, 473-486. RHYS, G. H. 1975. A proposed Standard Lithostratigraphic Nomenclature for the Southern North Sea. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe. Applied Science Publishers Ltd, London, 1, 151-163. STALDER, P. J. 1973. Influence of crystallographic habit and aggregate structure of authigenic clay minerals on sandstone permeability. Geologie en Mijnbouw, 52, 217-220. VAN VEEN, F. R. I975. Geology of the Leman Gas Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe. Applied Science Publishers Ltd, London, 223-231. WEBER, K. J. 1987. Computation of initial well productivities in Aeolian Sandstone on the basis of a geological model, Leman Gas Field, UK, In: TILLMAN, R. W. & WEBER, K. J. (eds) Reservoir Sedimentology. Society of Economic Paleontologists and Mineralogists, Special Publication, 40, 333-354. ZIEGLER, P. A. 1982. Geological Atlas of Western and Central Europe. Elsevier, Amsterdam.
The Malory Field, Block 48/12d, UK North Sea R. E. O'BRIEN, M. LAPPIN, F. KOMLOSI & A. L O F T U S Mobil North Sea Ltd., Grampian House, Union Row, Aberdeen ABIO 1SA, UK (an Exxon Mobil subsidiary)
Abstract: The Malory Field straddles blocks 48/12d and 48/12c of the UK Sector of the Southern North Sea on the western margin of the Sole Pit Trough. The field is located within an upthrown part of the Dowsing Fault Zone and was discovered by the Mobil operated well 48/12d-9 in early 1997. The Malory Field is a small fault-bounded horst structure with expected recoverable reserves of 75 BSCF. The reservoir consists of a 249 ft-section of Lower Permian, Rotliegendes Leman Sandstone Formation sandstones, is sourced from the Carboniferous Westphalian Coal Measures below, and is sealed by overlying Upper Permian Zechstein evaporites. Reservoir quality is generally good with an average porosity of 14.7% and core permeabilities (Kh) between 0.2 and 1651mD. This preservation of reservoir quality is attributed to a combination of the structure being located on a broad palaeostructural high, with a lower maximum burial depth than adjacent structures and associated lower compactional porosity loss, the presence of an early hydrocarbon charge and the preferential precipitation of chlorite over illite cements.
The Malory Field is located approximately 70 km N of the Norfolk coast within the Dowsing Fault Zone on the western margin of the Sole Pit Sub-basin, in water depths of 70 ft. The field is located mainly within Block 48/12d with a small southerly extension into Block 48/12c (Fig. 1). The field is a small, northwesterly dipping, fault-bounded horst structure (Fig. 2). The reservoir is the Rotliegendes Leman Sandstone Formation and consists of a mixed aeolian dune and sandy sabkha sequence with relatively minor fluvial sediments. The reservoir was entirely cored and petrophysical, and RFT analysis indicates a full gas column with gas-down-to (GDT) 9269ft TVDss. Analysis of regional aquifer pressures indicates that the field free water level (FWL) is between 9290 and 9450 ft TVDss. The mapped structural spill point is at a depth of 9350 ft TVDss (Fig. 2). Gas composition is similar to that of the nearby Excalibur Field and fits the general trend of gas becoming leaner from SW to NE in fields across the Lancelot Area Production System (LAPS) sector of the U K South-
ern North Sea. The gas consists primarily of methane (92%) with no hydrogen sulphide and 0.72% carbon dioxide. Reserves are estimated to be 75 BSCF and first gas was achieved in October 1998, using a minimum facilities platform (Fig. 3). The field was named according to Mobil's tradition of naming their operated Southern North Sea fields after characters in Arthurian legend. Malory was one of the authors of the adventures of King Arthur.
History Block 48/12d, licence P844, was awarded in the Fourteenth Round of offshore licensing in June 1993. Mobil North Sea Ltd. (MNSL) has a 75% interest in Block 48/12d with EDC (Europe) Ltd. holding the remaining 25%. Block 48/12c was awarded as Licence P461 in the Eighth R o u n d of licensing in May 1989. Mobil North Sea
Fig. 1. Regional location map with detailed map of the Lancelot Area Production System (LAPS) sector of the UK Southern North Sea. GLUYAS, J. G. & H~CHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 771-776.
771
772
R . E . O'BRIEN E T AL. The estimated plateau rate for the field is 45 M M S C F G / D for two years and the current peak production rate is 70 MMSCFG/D. Field life is anticipated to be nine years.
Structure
Fig. 2. Top Rotliegendes depth structure map based on 3D seismic data, showing the line of structural section and seismic Dines.
Ltd. and Superior Oil (UK) Ltd. each hold 42.5% with EDC (ISE) Ltd. and EDC (OILEX) Ltd. holding 10% and 5%, respectively. A field unitization has been agreed with Mobil North Sea Ltd. holding 76% and EDC Ltd. holding the remaining 24%. The Malory Field discovery well, 48/12d-9, was drilled in 1997 on the crest of a small, seismically defined horst block as part of a continued exploitation programme in the LAPS sector of the UK Southern North Sea. The discovery well encountered an entirely gas-bearing, 249 ft reservoir interval, with GDT 9269 ft TVDss. The drill stem test (DST) achieved a rate of 30.6 M M S C F G / D from a 212ft perforated interval with a condensate yield of 2.4STB/ MMSCF. Subsequent test interpretation yielded an average in-situ reservoir permeability of 24 mD. Development plan approval was granted in November 1997 and production commenced in October 1998 from a 4-slot, notnormally-manned minimum facilities platform (Fig. 3). The discovery well, 48/12d-9, is the sole producer and was completed as a mudline tieback.
Fig. 3. Malory minimum facilities platform.
The tectonic history is a complex interaction of basin subsidence from the end of Carboniferous times through to the late Jurassic with a period of active rifting during the Mesozoic. This initial extensional phase is difficult to date precisely, however it is believed to have occurred between the Triassic and late Jurassic. During Cretaceous and Tertiary times, the basin underwent several phases of inversion whereby the Sole Pit sub-basin became the Sole Pit High (Van Hoorn 1987; Walker & Cooper 1987; Glennie 1997). The resulting structural features of the area reflect this series of events and are heavily influenced by related salt tectonics and thin-skinned gravity tectonics (Stewart & Coward 1995; Lappin et al. 1998) From recent burial history and reconstruction work, the Malory feature is thought to have existed as part of a broad palaeostructural high since the Variscan Orogeny. The absence of the lower part of the Rotliegendes sequence (see reservoir section) reflects deposition onto a relict topography related to earlier faulting. In general, the upper Rotliegendes reservoir units and lowermost Zechstein intervals are a consistent thickness across the area, suggesting that by the end of the Rotliegendes depositional period the former structural high was buried. The current offset of the top Rotliegendes is attributed to later movement. Although the exact timing of this movement is difficult to date, due to de-coupling of the structural history by overlying evaporites, regional interpretations would suggest that the structure was reactivated to form a distinctive high during later Mesozoic rifting. Inversion during the Cretaceous and Tertiary resulted in differential uplift of the former Sole Pit Sub-basin, with axial parts forming the locus of uplift and amounts of uplift decreasing towards the basin margins (Glennie 1984). The Malory Field is located on the western margin of the Sole Pit Sub-basin and experienced minimal uplift and erosion during the inversion. In contrast, the area downthrown to the Maiory Field horst block underwent major uplift and associated erosion.
Stratigraphy A relatively conformable sequence of Permian through lower Triassic strata unconformably overlies the relict Carboniferous topography, and is overlain by a sequence of Jurassic and eroded Cretaceous deposits (Fig. 4). The conformable strata represent a coherent stratigraphical wedge (Ziegler 1975) that infilled accommodation space in the Southern Permian Basin. Subsidence of the basin commenced as a result of the Variscan Orogeny and continued into the Cretaceous. This background subsidence was interrupted by late Cimmerian tectonism (Glennie 1984) and terminated with inversion in late Cretaceous and early Tertiary times. The generalized stratigraphy shown in Figure 5 is typical of the sequence found in the partially inverted southwestern margin of the Sole Pit Sub-basin. The oldest sedimentary rocks penetrated in the Malory Field are Westphalian shales, siltstones and sandstones deposited in a deltaic environment. These deposits were uplifted in the Late Carboniferous and deeply eroded in Early Permian times (Glennie & Boegner 1981), resulting in the Westphalian Coal Measures forming the sub-crop to much of the basin. The Lower Permian Rotliegendes unconformably overlies Westphalian claystones and siltstones of the Upper Carboniferous and represents deposition of an aeolian dune and sandy sabkha dominated sequence in a slowly subsiding basin where the rate of subsidence probably exceeded sediment supply (Glennie & Boegner 1981). The Rotliegendes varies in thickness across the area, thickening towards the centre of the Sole Pit Sub-basin. The Upper Permian Zechstein marine transgression flooded the basin,
MALORY FIELD
773
Fig. 5. Generalised stratigraphy showing the relative thickness of overburden geology and a detailed Rotliegendes reservoir section.
Fig. 4. Seismic line (A-A r) showing the conformable overburden sequence. with carbonate deposition restricted to the basin margins, and increasing evaporation resulted in the deposition of gypsum and relatively thick evaporite sequences (Ziegler 1975; Glennie & Boegner 1981). The Zechstein evaporitic sequence is approximately 1600ft thick over the Malory area and provides a regional seal. Zechstein deposition represents a cyclic sedimentation and illustrates the effect of increasing salinity of sea water time linked with the advance and retreat of the Gondwana ice caps (Glennie 1984). Continental siltstones, claystones, and sandstones of the Bacton Group represent the onset of Triassic sedimentation that form the upper part of the conformable clastic wedge described by Ziegler (1975). Overlying these strata is a cyclic sequence of Haisborough Group shales and evaporites that represent a widespread marine transgression and return to marine conditions. The Triassic is overlain by thick Jurassic shales, sandstones and limestones of the Lias, West Sole, Humber and Corallian Groups, and mudstones of the Kimmeridge Clay Formation representing a global highstand of sea level. A minor disconformity occurs at the base of the Lower Cretaceous and directly above this are claystones of the Speeton Clay Formation. The uppermost section is capped by a thin section of Cretaceous Chalk deposited in a tectonically quiet period and partly eroded during late Cretaceous and early Tertiary inversion.
the northern, southern and eastern margins and the structure relies on dip closure to the NW (Fig. 6). Controlling faults are believed to be Variscan in origin and were reactivated during Jurassic rifting. The Zechstein evaporitic sequence seals the accumulation as is normal for Southern North Sea Rotliegendes gas fields.
Trap The Malory Field is a small fault-bounded horst block (Fig. 2). Two northwesterly trending faults bound the accumulation along
Fig. 6. Detailed seismic-section (A-A') illustrating the Malory Field structural configuration.
774
R. E. O'BRIEN E T A L .
Fig. 7. Structural cross-section through the reservoir showing the field hydrocarbon contact and structural spill point.
Displacement along the southern bounding fault varies along its length and in the southwestern portion of the field juxtaposition of reservoir occurs across the fault. Although the structural spill point occurs at 9350 ft TVDss (Fig. 2), the structure requires the fault to be sealing below 9300 ft TVDss. This causes uncertainty in the field reserve estimates as no FWL was encountered in the discovery well, 48/12d-9 (Fig. 7). These uncertainties will be discussed further in the Reserves and Production section.
Reservoir The Lower Permian Rotliegendes Leman Sandstone Formation forms the reservoir in the Malory Field. The geological model for the Leman Sandstone Formation of the Malory Field is that of an aeolian dune and sandy sabkha dominated sequence with occasional fluvial packages, representing deposition in a marginal setting to the Silverpit Lake to the north. These sediments were deposited between the tectonically active Sole Pit Sub-basin to the NE and the relatively stable East Midland Shelf to the SW, on the upthrown flank of the Dowsing Fault Zone. The vertical facies distribution can be subdivided into a series of cycles related to the pulsed expansion of the Silverpit Lake. These cycles can be compared to those identified in the lithological subdivision of George & Berry (1997). During early phases of Rotliegendes sedimentation, fluvial sediments derived from the Variscan Highlands were transported northwards by ephemeral streams (wadis) to the margins of the desert lake (Glennie et al. 1978). The relict Carboniferous topography channelled fluvial facies within depositional lows, while deposition of aeolian dunes and dry interdunes occurred in areas with minimal groundwater influence. The discovery well encountered a thinner Rotliegendes section than prognosed from regional isopach maps. The lowermost units, Zones A and B of the internally developed MNSL Lancelot Area zonation scheme are absent over the Malory Field. This is attributed to the location of the structure on a palaeostructural high. The basal section in well 48/12d-9, Zone C1 (Fig. 5), comprises mainly conglomeratic fluvial and thin aeolian sandsheet deposits with a minor sandy sabkha. This unit progresses upward into a dune dominated sequence with minor dry interdunes, Zone C2, broadly corresponding to a maxima of dune building. Later periods of deposition, Zones D1-4, are interpreted to have occurred in an environment characterized by pulsed expansion of lake margin facies associated with climatic fluctuations. A more cyclic facies distribution is recorded in the evolution from aeolian dune to sandy sabkha sub-environments as facies belts shifted south. Within Zone D there is also a decrease in preserved dune set
size and relative increase in groundwater influenced sabkha facies over dry interdunes. This variation is consistent with deposition occurring in a marginal setting. The top of Zone D (D4) corresponds to a regional lake maxima that can be correlated across much of the Lancelot Area from blocks 48/11 and 48/12 in the north across blocks 48/17 and 48/18, and as far south as Block 48/22. Zone E consists predominantly of a massive fluvial channelfill sequence with a thin aeolian dune remnant package at its base, and represents the final phase of fluvial activity associated with a Lower Permian deterioration in climate and significant downcurrent extension of wadi channels across Block 48/12d. The uppermost section, Zone F consists of massive sands representing reworking of the Lower Permian dune fields by the Zechstein marine transgression. The predominantly fluvial units, Zones C1 and E and mixed sandy sabkha and aeolian units, Zones D1, D2 and D4 exhibit the poorest reservoir quality due to lithology and increased cementation. The predominantly aeolian dune (Zones C2 and D3) and Weissliegendes (F) reservoir units have very good reservoir quality. Average zonal porosities range between 9.4% (Zone C1) and 19.4% (Zone D3) with ambient arithmetic average permeabilities between (Kh) 15.6 (Zone E) and 328 mD (Zone C2). Facies type is the primary control on porosity due to textural characteristics and permeability. Aeolian dune sandstones exhibit the best porosity and permeability (av. ~ 19.8%, Kh 306.8mD). The Weissliegendes of the Malory Field is unusual compared with adjacent fields such as Galahad, Mordred, and Excalibur in that it also displays good reservoir quality (av. ~3~ 17.3%, Kh 52.4mD). The more argillaceous fluvial (av. ~ 11.5%, Kh 42 roD) and sandy sabkha sandstones (av. ~ 11.6%, Kh 0.85 mD) generally display much poorer reservoir quality. Individual sandy sabkha units are not thought to be laterally persistent but may act as baffles to flow. Rotliegendes reservoir quality is impacted by compaction and diagenesis associated with burial. Secondary diagenetic controls on lithology have impacted reservoir quality and resulted in a decrease in porosity and permeability. The main controls in the Malory Field are the precipitation of authigenic cements (particularly dolomite), restricted volumes of quartz and anhydrite, clay precipitation notably chlorite and to a lesser extent fibrous illite, and also compaction related diagenesis. Compared to nearby fields, such as Galahad, Mordred and Excalibur, the Malory Field has anomalously good reservoir quality. Current understanding attributes this to a complex interplay of a number of factors. These include: the presence of a broad palaeostructural high in the area of the Malory structure, early hydrocarbon charge, a lower maximum burial depth than nearby fields with less associated compactional porosity loss, and an abundance of chlorite over illite cements. Leville et al. (1997) identified that preservation of reservoir quality within the Jupiter fields occurs in fault blocks that were structurally high during the main phase of illite growth. Within the Jupiter fields, the main factors contributing to the preservation of reservoir quality in these fault blocks included variations in pore water chemistry, the degree of burial compaction, and in some cases an early hydrocarbon charge. The presence of this palaeostructural high has impacted both reservoir thickness and diagenesis. Equally important is the relative abundance of grain-coating chlorite that is thought to have stabilized the system prevented the authigenesis of large quantities of fibrous illite and helped to preserve reservoir quality. Seeman (1982) and Rossel (1982) have identified the important influence of such diagenetic clay minerals on reservoir quality. The early precipitation of chlorite or a chlorite precursor clay mineral is thought to be related to the high proportion of groundwaterinfluenced facies in the Malory area and associated pore water chemistry. The presence of an early hydrocarbon charge during burial may also have favoured the precipitation of late Fe-rich chlorite in association with flushing of hydrocarbon fluids from Carboniferous source rocks (Leville et al. 1997). Further evidence for the existence of late acidizing fluids is the pale buff-brown to light grey colour of the entire series which is thought to result from reduction of redbed Fe 3+.
MALORY FIELD
Source The acknowledged source for the gas in the Southern Permian Basin is the Late Carboniferous, Westphalian Coal Measures directly beneath the Rotliegendes (Glennie 1984). The source rocks reached maturity for gas during the Jurassic to early Cretaceous and this time period roughly corresponds to the maximum burial depth of the Rotliegendes. The Malory structure is thought to have formed a palaeostructural high and been charged by this early phase of gas migration with charge continuing through to the Tertiary. Bitumen staining within coarser aeolian dune laminae may also be evidence of this early gas charge with an associated oil rim.
Hydrocarbons The Malory Field contains sweet, dry gas. An analysis of the recombined reservoir gas composition from the discovery well, 48/12d-9, is given in Table 1. The composition of the reservoir gas is similar to nearby fields and fits a general trend of gas composition becoming leaner from the SW to N E across the LAPS area. The Malory Field gas is therefore slightly leaner than Excalibur gas and slightly richer than Galahad gas. The Malory Field specific gas gravity is 0.615 (air gravity is 1). As mentioned previously, the discovery well DST achieved a rate of 30.6 M M S C F G / D with a measured condensate gas ratio of 2.4 S T B / M M S C F from a 212 ft perforated interval. This compares with a condensate yield of 0.5 STB/MMSCF during initial production. No formation water was produced during testing and initial production. Only small quantities of water as a result of condensation have been produced at a rate of approx. 0.5 STB/MMSCF. Since well 48/12d-9 did not penetrate the water leg, formation water analysis is not available. The accepted water analysis for the Lancelot area is taken from well 48/17b-3, with an equivalent sodium chloride salinity of 256 690 ppm and a formation water resistivity of 0.057 ohm-m at 190~
Reserves and production Production from the Malory Field commenced in October 1998. The re-completed discovery well, 48/12d-9, is the sole production well and no additional wells are currently planned. A plateau production rate of 45 M M S C F G / D is forecasted for two years, with a current peak production rate of 70 M M S C F G / D . Field life is expected to be nine years. The main uncertainty in estimation of gas initially-in-place (GIIP) is the position of the field FWL. The Malory discovery well, 48/12d-9, encountered a G D T of 9269 ft TVDss. R F T pressure data from the water leg of wells within the Malory area show a range of possible aquifer pressures. Interception of these pressure trends
775
with the pressure gradient in the gas leg of the Malory Field suggests the F W L may be between 9290 ft TVDss and 9450 ft TVDss. The mapped structural spill point of the Malory Field actually occurs at a depth of 9350-ft TVDss, between the predicted F W L range. In order to fully capture this uncertainty in the probabilistic volumetrics, a range of possible F W L depths were used. The current most likely estimate of field GIIP of 99 BSCF is based upon the expected probabilistic value. It is assumed that the main field drive is pressure depletion. Since the location of the F W L and the potential behaviour of the aquifer are unknown, it is not possible to determine at this early stage whether pressure support from the aquifer and water encroachment will be significant. This issue was dealt with in sensitivity studies using a full field simulation model. A full field simulation model, based on the most likely map (Fig. 2), incorporates the distribution of facies in well 48/12d-9 (Fig. 5) and was used to identify the optimum development strategy. The main parameters influencing development decision were the position of the FWL, which strongly influences the estimate of GIIP, the behaviour of the aquifer, internal faults and permeability distribution away from the well. Apart from dealing with subsurface issues, the simulation proved necessary to handle surface constraints due to onshore compression and production from other fields. The simulation work showed that using the existing discovery well as the only producer is the optimum development for the Malory Field due to the high productivity of this well. The well was re-completed for production purposes and only the upper sections of the reservoir were perforated as the simulation showed these zones (Zone F E, D4, D3 & D2) were capable of producing the required rate. Excessive water production, that could cause premature abandonment, is avoided due to sufficient stand-off. Also the comparatively tight zones below the perforated interval should help to avoid water production even in the case of a strong aquifer. However, a modest edge water drive is considered in the reserves estimate. The single vertical well can deplete the reservoir effectively achieving an ultimate recovery of 75 BSCF and a recovery factor of 76%. Gas is evacuated from the Malory Field via a 10" pipeline to the Galahad platform facilities and then via the Mobil operated Lancelot Area Pipeline System (LAPS) to the Bacton gas plant. Shortly after first gas from the Malory Field, the new onshorededicated LAPS Gas Compression facilities became operational. These new facilities will significantly contribute to recoverable reserves from the Malory Field. The authors wish to thank both Mobil North Sea Ltd. and EDC (Europe) Limited, for permission to publish this paper. The authors have also drawn on the knowledge of colleagues from the Southern North Sea Asset Team. The authors would particularly like to acknowledge Dr Louis Macchi of Reservoir Associates International, for his contribution to our understanding of sedimentological and petrographical processes of the Malory area, and also Professor Graham Williams of Keele University for his contributions to our understanding of the structural history.
Table 1. Recombined reservoir gas composition well 48/12d-9 Methane Ethane Propane Iso-Butane N-Butane Iso-Pentane N-Pentane Hexanes Heptanes Octanes Nonanes Decanes Undecanes Dodecanes + Carbon Dioxide Nitrogen Hydrogen Sulphide
91.75% 4.07% 0.88% 0.16% 0.21% 0.05% 0.06% 0.22% 0.08% 0.03% 0.03% 0.02% 0.01% 0.02% 0.72%
1.69% 0.00%
Malory Field data summary Trap
Type
Depth to crest Lowest closing contour GDT FWL Gas column
Fault bounded horst structure with fault closure to the north and south and dip closure to the NW 9020 ft TVDss 9350 ft TVDss 9269 ft TVDss between 9290 and 9450 ft TVDss 249 ft (minimum)
Pay zone
Formation Age Gross thickness Net/gross ratio Net sand cut-off
Leman Sandstone (Rotliegendes) Lower Permian 249 ft 1 no porosity cut-off
776 Vsh Porosity average (range) Matrix permeability
R . E . O'BRIEN E T AL.
Average gas saturation Productivity index
4O% 14.7% 0.2-1651 mD (core Kh) Av. in-situ 24mD 63.3% 269 * e-06 (Mscf/m(p))
Hydrocarbons Gas type Gas gravity Gas viscosity Gas expansion factor Condensate yield
sweet dry gas 0.615 0.0227 cp 234 SCF/RCF 2.4 STB/MMSCF
Formation water Salinity Resistivity
(from 48/17b-3 Lancelot D) 256 690 NaC1 eq. ppm 0.057 ohm m @ 190~
Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Gas initially-in-place Recovery factor Drive mechanism Recoverable gas
397 463 m 2 103 934 acre-ft 4257psia at 9145 ft TVDss 0.078 psi/ft (gas leg) 200~ 99 BSCF 76% pressure depletion 75 BSCF
Production First gas Production rate plateau gas Number/type of well
October 1998 45 M M S C F G / D (current rate 70 MMSCFG/D) one vertical producer
References GEORGE, G. T. & BERRY, J. K. 1997. Permian (Upper Rotliegend) synsedimentary tectonics, basin development and paleogeography of the southern North Sea. In: ZIEGLER, K., TURYER, P. & DAINES, S. R. (eds) Petroleum Geology' of the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 31-61.
GLENNIE, K. W. 1984. Outline of North Sea History and Structural Framework. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 34-77. GLENNIE, K. W. 1997. History of exploration in the southern North Sea. In: ZIEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology' o f the Southern North Sea." Future Potential. Geological Society, London, Special Publications, 123, 5-16. GLENNIE, K. W. & BOEGNER, P. L. E. 1981. Sole Pit Inversion Tectonics. In: ILLING, L. V. & HOBSON, D. G. (eds) Petroleum Geology of the Continental Shelf oJ" North West Europe. Institute of Petroleum, London, 110-120. GLENNIE, K. W., M UDD, G. & NAGTEGAAL, P. J. C. 1978. Depositional environment and diagenesis of Permian Rotliegendes sandstones in Leman Bank and Sole Pit areas of the UK southern North Sea. Journal oJ" the Geological Society, London, 135, 25-34. LAPPIN, M., CLUTSON, M. J., DALWOOD,R. E. T. & ANDERSON,A. 1998. The Role of Late Permian-Triassic salt in extensional and compressional tectonics of the UK Southern North Sea. Journal of Seismic Exploration, 7(3/4), 407-410. LEVILLE, G. P., PRIMMER, T. J., DUDLEY, G., ELLIS, D. & ALLINSON, G. J. 1997. Diagenetic controls on reservoir quality in Permian Rotliegendes sandstones, Jupiter Fields area, southern North Sea. In: ZIEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 105-122. ROSSEL, N. C. 1982. Clay mineral diagenesis in Rotliegend aeolian sandstones of the Southern North Sea. Clay Minerals, 17, 69-77. SEEMAN,U. 1982. Depositional facies, diagenetic clay minerals and reservoir quality of Rotliegend sediments in the Southern Permian Basin (North Sea). Clay Minerals, 17, 55-67. STEWART, S. A. & COWARD, M. P. 1995. Synthesis of salt tectonics in southern North Sea, UK. Marine & Petroleum Geology, 12(5), 457 475. VAN HOORN, B. 1987. Structural evolution, timing and tectonic style of the Sole Pit Inversion. Tectonophysics, 137, 239-284. WALKER, I. M. & COOPER, W. G. 1987. The structural and stratigraphic evolution of the north-east margin of the Sole Pit Basin. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of N W Europe. Geological Society, London, 263-275. ZIEGLER, W. H. 1975. Outline of the Geological History of the North Sea. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf o f North West Europe, Volume 1. Applied Science Publishers, London, 165-190.
The Mercury and Neptune Fields, Blocks 47/9b, 47/4b, 47/5a, 42/29, UK North Sea B. SMITH & V. S T A R C H E R B G Group, Reading, Berkshire R G 6 1PT, U K
Abstract: The Mercury and Neptune Gas Fields, discovered in 1983 and 1985 respectively, are located on the NW margin of the southern North Sea. Both fields have reservoirs in the Permian Lower Leman Sandstone Formation of the Rotliegend Group. The Mercury Field, at Rotliegend level, is an elongate, southerly tilting horst block. It trends NW-SE and is bounded by reverse faults. The Neptune Field, at top reservoir level is a faulted, four-way dip closed structure that is elongated in a NW-SE direction. The combined gas-in-place for the two fields is estimated at 465BCF with recoverable reserves of 368BCF. Development drilling on Mercury commenced in early 1999 and on Neptune it is scheduled to start in Q3 1999. The maximum gas export rate will be 250 MMSCFD with first gas anticipated in November 1999. Location The Mercury and Neptune gas fields are located on the N W margin of the southern North Sea (Permian) gas basin, approximately 45 km from the Easington terminal (Fig. 1). The fields lie within the Sole Pit Basin, although Mercury is located at the western margin while Neptune is located in a more basinal position (Fig. 1).
History The Mercury Field lies within Block 47/9b and BG International operates the block on behalf of the joint venture with Amerada
Hess. The Neptune Field lies within blocks 47/4b, 47/5a and 42/29 with the majority of the field lying in 47/4b. BG International operates the field on behalf of the joint venture with Amerada Hess and BP Amoco. Blocks 47/5a and 42/29 were awarded in the First Licensing Round in September 1964 and blocks 47/4b and 47/9b are Sixth Round awards (in 1979). Four wells were drilled around the Mercury structure before the discovery well, 47/9b-5a, was drilled by Gas Council (Exploration), now BG International, in 1983. Well 47/9b-5a tested at 35 M M S C F D from the 120 ft thick Rotliegend, Leman Sandstone Formation at a depth of 8700 ft TVDss. One appraisal well, 47/9b-6, was drilled by GC (E) in 1984 and flowed at 20 M M S C F D from a thinner
0 ~ 00'
54 ~ IO'N
1~ 00' E
10 24' E 54 ~ IO'N
54 ~ 00' N
54' 00' N
53 ~ 30' N 0 ~ 00'
Kiiometres
1o 00' E
53 ~ 30' N 1o 24' E
30
1 Fig. 1. Mercury and Neptune Fields location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative~Millennium Volume. Geological Society, London, Memoir, 20, 777-787.
777
778
B. SMITH & V. STARCHER
section. The field had been poorly delineated on the old 2D seismic data and was considered uneconomic. It was re-evaluated in 1994, using 3D seismic data, which improved the structural definition. The Neptune Field was discovered in 1985 with the down-dip well, 47/5a-4, which flowed 10 M M S C F D gas from a thin column in the 400ft thick Leman Sandstone Formation at a depth of -9823 ft TVDss. The field was appraised by wells 47/4b-4 and 47/ 4b-5 in 1990.47/4b-4 confirmed a substantial gas column in a more crestal location, but was not tested as a result of salt induced casing collapse. 47/4b-5 was drilled off-structure. The final appraisal well, 47/4b-6, was drilled in 1994 with the benefit of new 3D seismic data and tested at a sand-free rate of 54 M M S C F D . It was suspended as a future producer. A feasibility study undertaken for the area showed the optimum way forward to be the simultaneous development of the Mercury and Neptune Fields. The development of the two fields comprises phase 1 of the ECA development concept. The facilities to be installed included a two-well sub-sea manifold at Mercury, a fourslot wellhead platform at Neptune and a new riser tower located adjacent to the existing BP Amoco Cleeton facilities. These facilities have provision for future developments to be tied-back. The first phase of development drilling commenced on Mercury in early 1999 and on Neptune is scheduled to begin in Q3 1999.
>I
"1n
I
>-r n
>tJ ) if./) I-a
0_1 0
OO
LU
-r I_.1
I>Iv"
<
In-
LU
illtlllll[~ ]-C~I i I i I ] I I I I I I I I
CHALK
CROMER
KNOLL
- 2000
LI.I
HUMBER Structure
"T
r~
Regional setting and tectonic history The Mercury Field is situated on the edge of the East Midlands Shelf, at the western margin of the Sole Pit Basin. The Neptune Field is in a more basinal location at the N W end of the Sole Pit Trough. Both fields lie to the N E of the major N W - S E trending Dowsing Fault Zone (Fig. 1) The basin has been subjected to a number of tectonic events (Glennie & Underhill 1998). The Hercynian orogeny, which occurred in the Late Carboniferous, resulted in the folding and faulting of the Carboniferous along a N W - S E structural grain. Movement was largely strike-slip in response to a N - S stress regime. The main phase of the Sole Pit Basin development occurred in the Permian when crustal extension took place along the N W - S E Variscan trend. This was accommodated by the development of a synthetic (Dowsing Fault Zone) and antithetic (Swarte Bank Fault Zone) fault system. The boundary faults of the Mercury Field are thought to have been formed during this period of tectonic activity. Continued extension produced back-stepped asymmetric half grabens along the Dowsing and Swarte Bank Fault Zones. Following this period of activity, basin subsidence was nearly continuous from the Late Permian until the Late Jurassic. Only local uplift and erosion of fault blocks during the Triassic punctuated it. The mid-Jurassic rifting initiated N W - S E trending normal faults within the Jurassic and Triassic sections. These form the dominant fault trend in both the Mercury and the Neptune fields. Observed cataclastic slip bands in the Neptune Field are postulated to have originated at this time. During the subsequent Cimmerian tectonic event (Late Jurassic), some sub-basins and fault blocks were uplifted. The result was extensive erosion of the Jurassic in this region of the southern North Sea. This tectonically active phase was followed by a period of renewed basin subsidence during the Cretaceous. The final stage in the structural history of this area occurred during the Early Tertiary. This period was characterized by successive periods of uplift, which culminated in a major phase of inversion in the Miocene. The compressive stress regime during this reactivation phase was orientated in a N N E - S S W direction. This was responsible for the observed strike-slip component along some of the major faults and inversion of the Sole Pit Trough area. There is clear evidence that this phase of inversion affected the major faults of the Neptune Field. Inversion is however less obvious in the Mercury Field although a few of the surrounding faults indicate that the Miocene was a time of renewed activity.
i i j i [ i i t = t I
SOLE
WEST
LIAS ~
- 4000
TRITON FlA. ~
HAISBO.
-ROUGH
r~
DUOeEONFM.--H t I t-H I
(
OOWS~F~..![![!
__ _ ~
!!]
I
!!!!
BUNTER ~ S E T FM . . . . . . . . . . . .
BACTON
:. . . . . .
BUNTER ....
5
- 6000
SHALE FM.
~,,,,,,,,,,,
,,,
ZECH-
~
STEIN
Z5
illlllIIIlll 1 I[JI
Z4
:
~
~,
...........
t[ .
.
8000 .
.
, .
....
:/iiiiiiiii!! II11111/[ll
IIlll
u.i
Zl
~
ROTLIEGEND
/-A
A
A
A
S'PIT - - -_ _-__-_ ~_ _ FM. .- . . . . . . . LEMAN ~_r ,-_ S E T FM. " D
i
WESTPHALIAN--
B
o,,,~z III
z
o iXl 11:
12000
A C
m
.
.
.
.
a
' . . . . . . . . . . . .
A
i_-
i !
NAMURIAN
i
. . . . .
i-
v,s . TOURNAISIAN
Fig. 2. Neptune Field (Blocks 47/4b and 47/5a) generalized stratigraphy.
MERCURY AND NEPTUNE FIELDS
Stratigraphy Figure 2 provides the generalized stratigraphy for the area. The oldest rocks penetrated by any of the Mercury and Neptune wells are fluvio-deltaic sands, silts and shales of Carboniferous age. The Hercynian orogenic events resulted in erosion down to the Westphalian A on Neptune and Westphalian B and C on Mercury. The Rotliegend Group within Sole Pit Basin was deposited in a wide range of structural settings, from platform on the East Midlands Shelf (Mercury), through basin-marginal to basinal in the Sole Pit Trough (Neptune). The source of the sediment supply into the basin was the London-Brabant Platform to the south through a series of fluvial tracts. The Lower Leman Sandstone Formation of the Rotliegend Group, the reservoir in both the Mercury and Neptune fields, is composed of mixed aeolian and fluvial deposits. It varies in thickness from up to 400 ft at Neptune to about 100 ft thick at Mercury. The boundary between the Lower Leman Sandstone Formation and the underlying Carboniferous is a major angular unconformity (6~ in the basal Lower Leman Sandstone Formation to 5~ in the uppermost Carboniferous in Neptune well 47/4b-6). The reservoir is overlain by the Silverpit Formation on the Neptune Field but passes directly into the overlying Zechstein Group at Mercury. There is no Upper Leman Sandstone Formation at the top of the Rotliegend Group in either field. The marine transgression, which followed the deposition of the Rotliegend Group, resulted in the cyclic deposition of the Zechstein evaporites and carbonates. The Zechstein Group is over 3000ft thick at Neptune and <600 ft thick at its thinnest over Mercury.
779
The full Zechstein stratigraphy is present over both fields but at Neptune, in different parts of the field, the section has very thick sequences of either the Leine or Stassfurt Halite. The combined thickness of both halite units is, however, fairly constant over the whole Neptune Field (2088-2137 ft). The lowermost part of the Zechstein stratigraphy (Z2 Polyhalite and below) contains several useful markers that are used to predict the top of the reservoir and steer the development wells. The end of the Permian was marked by the return of predominantly non-marine deposition in the Triassic. The Bunter Shale and Bunter Sandstone formations of the Bacton Group overlie the Zechstein Group. These are in turn overlain by the Haisborough Group, which marks the return to marginal marine conditions. The thin Rot Clay Formation represents the basal transgressive deposit after which floodplain deposition resulted in interbedded claystones and evaporites. A major transgression at the end of the Triassic resulted in the deposition of the wholly marine claystones of the Winterton Formation and the overlying Lias. The West Sole and Humber Groups continue a pattern of deepening marine conditions resulting in the deposition of claystones with minor sandstones and siltstones during the Middle Jurassic and claystones with limestones and dolomite during the Late Jurassic. The Upper Jurassic is preserved at both Mercury and Neptune below the Cimmerian unconformity. A return to basin subsidence commenced with the deposition of the Speeton Clay Formation of the Cromer Knoll Group and was followed by the Upper Cretaceous Chalk Group. The thickness of the Chalk Group over Neptune is highly variable, ranging from 700 to 1500 ft. At Mercury, the thickness is more constant at 1700 to 1800 ft, although to the east it thickens off-structure to up to 3300 ft.
Seabed
Base Chalk
Top Haisborough Top Zechstein Time. (msecs)
Fig. 3. Mercury Field composite seismic section.
Top Rotliegend
780
B. SMITH & V. STARCHER
The early Tertiary inversion resulted in uplift and erosion of the Chalk Group. In the Mercury area the chalk subcrops beneath a thin surface veneer of Quaternary sediments. At Neptune, 400-1000 ft of Tertiary and Quaternary sediments overlie the Chalk group and range in age from Paleocene to Recent. The Tertiary overburden at the Neptune Field is complex, resulting in rapid velocity variations. This has caused imaging problems for this field.
Local structure and trap
Mercury. Until 1994, the mapping of the Mercury Field was based upon several vintages of 2D seismic datasets. In 1994, a 3D survey was acquired across Block 47/9b as part of the larger GECO Ouad 47 TQ3D survey. Data quality is good across the main part of the field but deterioration in the imaging of all reflectors occurs toward the SE of the field (Fig. 3). This coincides with the shadow of the Dowsing Fault Zone. The overburden is relatively simple over the main part of the field. The chalk section is dipping to the SW whilst the underlying formations are gently folded. Faulting is minimal in this region. To the NE, in the proximity of the Dowsing Fault Zone, the overburden becomes more disturbed and the degree of faulting in the Triassic increases significantly. Mercury is an elongate, W N W - E S E trending horst block at Top Rotliegend level (Fig. 4). The structure has dimensions of about 8 • 1.5 km. The main bounding faults are reverse faults. The throw on the northern fault is in the region of 3000 ft whilst the throw on the southern bounding fault ranges from near zero in the east to >1000ft in the central section. Along strike the closure is formed by cross faults at both ends of the horst. Internal faulting is minimal. The crest of the structure (-8850 ft TVDss) is mapped toward the NW end of the field and the structure gently dips to the south. The seal is provided by the Zechstein evaporite sequence. Neptune. The Neptune Field was originally mapped on a variety of 2D datasets. A 3D dataset was acquired in 1991 over a 10km 2
Fig. 4. Mercury Field top reservoir structure map.
area centred on the 47/4b gas discovery. The Neptune Field has a structurally complex overburden with large lateral and vertical velocity variations. This results in poor imaging at the top reservoir level. Extensive seismic reprocessing has been undertaken including pre-stack depth migration and post-stack depth migration. The resulting datasets have slightly improved the data resolution but it remains unusually poor due to the overburden (Fig. 5). The overburden of the Neptune Field is dominated by a N W - S E trending Tertiary graben (Fig. 6). This fault-bounded structure shallows to the south and is underlain by a thick chalk layer. The chalk subcrops the surface via major faults to the NE. There is extensive faulting in the overburden that is thought to be related to the Cimmerian tectonic activity. These faults trend predominantly NW-SE. The Zechstein in this region is thick and does not display diapirism. The Neptune Field is a fault bounded N W - S E striking anticline (Fig. 7). The dominant fault trend is NW-SE. It probably formed as an extensional feature during the Late Permian to Late Jurassic with subsequent inversion during the Tertiary. The crest of the structure (-8853 ft TVDss) is located to the NW of the field and the closing contour is -9839 ft TVDss. The field displays a degree of internal faulting which may compartmentalize the reservoir (Fig. 7). The structure is sealed by the overlying Silverpit Shale Formation and ultimately by the Zechstein evaporites.
Reservoir The Lower Leman Sandsone Formation of the Lower Permian Rotliegend Group is the gas-bearing reservoir for both the Mercury and Neptune fields. It is highly variable within the Southern Permian Basin in terms of both lithofacies and thickness. The reservoirs are mixed fluvio-clastic sequences deposited under predominantly arid conditions. The two major controls on the thickness and nature of the reservoir sequences are structural setting (accommodation space) and climatic control (wet or dry cycles). Mercury lies on the East Midlands Shelf and has a thinner reservoir section than Neptune, which is more basinal. The lithofacies types seen in both fields are also very different and they will be discussed separately.
MERCURY AND NEPTUNE FIELDS
Fig. 5. Neptune Field pre-stack depth migrated line.
781
B
B"
47/4b-4
SOUTHWEST
(~
NORTHEAST
2000
F++++++-7-~+++++
++
++
++
+++++
+ ++
++
+ + + +F+
+ ++++
++
++--=F~+
+~'-~
J
[+ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + 4 + + + + + + + + + + + + + + ~ , ~ ~ + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + + ~ + + + + + + + + + ~ + + + + + + + + + + + + + + + + + ~ J + + + + + + + + + + + ~ ~ + + + + + + + ~ + + + + + ~ + + + + + + + + + + + + + + + + + + + + + + + + + + + ~ ~ + + + +++ + + + ++ZechsteinGr~Jp,++ ++ + § + + + + ++~ +++ + ++++ ++ + + +++ + + + + + + + + + + + + d
F i g . 6. G e o s e i s m i c s e c t i o n a c r o s s N e p t u n e
F i g . 7. N e p t u n e
Field.
Field top reservoir structure map.
MERCURY AND NEPTUNE FIELDS
783
o
O
e,D
~2
784
B. SMITH & V. STARCHER
Depositional setting Mercury.
The Mercury accumulation is reservoired in the Lower Leman Sandstone Formation, which is directly overlain by the Upper Permian Zechstein succession. The Silverpit Formation is absent. The reservoir is 110 ft thick in the western part of the field thinning to only 58 ft thick in the east. The thickness variations are believed to be palaeotopographically controlled (Fig. 8). The reservoir is comprised of a complex sequence of aeolian dune, alluvial fan, ephemeral stream and siliclastic sabkha sediments. Climatic aridity is considered the primary control on the depositional sequence. Older, aeolian dune and fluvially reworked dune deposits are known in the wells to the west of the field and represent the early infilling of the Carboniferous topography in the area. These early aeolian sequences are overlain by alluvial fan deposits, that prograde into the western part of the Mercury Field as a function of the decreasing climatic aridity. The Mercury Field reservoir has been subdivided into four reservoir zones (flow units) for modelling purposes (Fig. 8): M4 is the lowermost unit and is present only in the west of the field. It is comprised of reworked aeolian dune deposits becoming predominantly more fluvial towards the top. Dipmeter data is limited but fore-set dips indicate a palaeowind direction from the NE. This is similar to Neptune and conforms to the regional palaeowind direction of this time (Glennie 1982). The M3 unit is comprised of sabkha and sheetflood sandstones in the east passing laterally into fan debris and streamflood deposits in the west. It is generally of poor quality with permeability trends decreasing radially away from the 47/9b-5a well. The M2 unit marks a return to more arid conditions with thin sand-sheets present in the east of the field. Pebbly streamflood deposits predominate towards the west. This unit is of reasonable reservoir quality with a good horizontal permeability in the sandsheets aligned parallel to the basin margin (NW-SE).
Fig. 9. Neptune Field: correlation of reservoir layers.
M1 is the uppermost unit at Mercury and is essentially nonreservoir. It marks a return to wetter conditions with sabkha deposits predominating, overlain by tight (anhydrite cemented) reworked sandstone.
Neptune. The Neptune Field reservoir is situated between two fluvial tracts in a basinal setting. It is characterized by a predominance of aeolian dune deposits and would appear to represent a minor erg. Palaeowinds (and hence sediment transport direction) were from the east. The Leman Sandsone Formation at Neptune is up to 400 ft thick and overlain by the Silverpit Formation. The boundary between the two formations appears to be conformable or a non-angular unconformity. The Leman Sandstone Formation forms part of an erg that extended north into the southern part of the Cleeton Field and was limited to the south by the Outer Silverpit Fault. The reservoir is composed of 85-90% fine to medium-grained aeolian sandstones (mostly grainflow and wind-ripple deposits). These are occasionally interbedded with waterlain deposits of ephemeral stream and sheetflood origin and reworked/fluidized aeolian sandstones. Sedimentological subdivision of the Neptune reservoir has been based on the interpretation of bounding surfaces of various orders. This event-stratigraphical approach helps to provide a better understanding of aeolian bedforms. Of the four hierarchical orders recognized by Kocurek (1988), the most significant are the super bounding surfaces, or supersurfaces (0th order) and 1st order bounding surfaces. The former marks the hiatus in erg development of regional significance, while the latter represent the floors of interdunes to simple dunes and draa. Up to eight units may be recognized in the Neptune reservoir, separated by major bounding surfaces. Each surface represents a hiatus in erg development, which is likely to be climatically controlled and therefore regionally significant. The eight sedimentological units
MERCURY AND NEPTUNE FIELDS are split into seven reservoir layers (flow units) on the basis primarily of permeability. Figure 9 shows this subdivision. N6 is the lowermost unit and represents deposition on the leading edge of the erg, it is comprised of sandsheets and localized sheetflood deposits, overlain by the first of the major dunefield complexes. The lower part of N5 is the second of the major dunefield complexes and it passes up into aeolian sandsheets of wind-ripple lithofacies type. The N4 layer represents the lower part of the third major dunefield complex. The base of the dune sequence is marked by an angular unconformity and is considered to be a super surface. N3 is the upper part of the third major dunefield complex. It is separated from N4 on the basis of permeability variation. N2 is a relatively thin, low permeability layer, which is regionally correlatable. The interval is composed entirely of waterlain sediments deposited during a period of erg deflation. Deposition was from streams/sheetflood centred on/around the 47/4b-6 well. The development wells for Neptune will be drilled and completed above the N2 layer to take advantage of this low permeability barrier to vertical flow which should help to delay water production. The lower part of the N1 layer (Nlb) is comprised of the fourth, and last, of the major dunefield complexes and is overlain by an interval of reworked aeolian sandstones, (Nla) reflecting the onlap of the overlying Silverpit Lake.
Porosity and permeability Mercury. Reservoir quality in the Mercury Field is a function of primary lithofacies. The aeolian deposits and fluvially reworked aeolianites have the highest porosities and permeabilities (M4). Fluvial sands are highly variable depending on grain size and sorting, and the claystones of sabkha and flood-drape origin are tight. In the aeolian facies of the 47/4b-5a well, the core porosity averages 19.4% and the permeability 282mD. In the fluvial facies these drop to 13.9% and 21.3 mD. A PLT run in 47/10-1 just to the SE of the field highlights the importance of aeolian sediments to productivity. Practically all the production (29 MMSCFD) from a 65 ft perforated interval was seen to come from a thin (12 ft) aeolian sandsheet in the M2 layer. The porosity is mainly primary intergranular (average visual estimate is 12%). Secondary porosity comprises dissolution voids (3%). Pore connectivity has been reduced by compactional effects and detrital clays. In some samples a degree of underpacking has been observed. This may be due to an early hydrocarbon charge (bitumen is seen in the Mercury cores) or possibly early carbonate cement (remnant carbonate grains are also seen in some samples). The proximal nature of the depositional system has had an effect on reservoir quality. The Lower Leman Sandstone reservoir contains abundant detrital clay (particularly within the fluvial facies), which is a precursor to the authigenic clays (especially illite). Wells drilled off-structure show a marked reduction in reservoir quality due to increased compaction but also to a greater amount of pore-blocking quartz cement generated by pressure solution. Permeability trends relate to palaeotransport directions, particularly in the sand-sheet horizons (i.e. M2), and can show pronounced horizontal layering. Neptune. Reservoir quality in the Neptune Field is a function of primary lithofacies and depth of burial. Porosities at Neptune are variable, although usually high. The average porosity for the field as a whole is 19% and approximately 25% of the visible porosity has been interpreted to be of secondary (intragranular microporosity) origin. The best reservoir facies are the coarser grained aeolian grainflow units, which are typically found above wind-ripple packages, associated with 1st order surfaces. The principal reservoir intervals are the medium-grained dune complexes of zones N1, N3 and N4. These have layer average porosities as high as 23% and permeabilities as high as 689 mD. Permeabilities however, decrease with
785
depth of burial, as a function of finer grain size but also due to increasing illite abundance. The main reduction in reservoir quality occurs at the top of N5 (a sandsheet), coincident with a change in bed dip. The aeolian deposits beneath the top of N5 are finer-grained and this has been attributed to a climatic control (lower wind strength). The effect appears to be field-wide and the top of N5 and N6 may act as vertical permeability baffles. Only N2, a thin fluvial interval has the capability to act as a local vertical barrier to water flow (Fig. 9). In well 47/4b-6, this has a Kv of <0.05 mD. As the Neptune Field is underlain by water, these zones may be important for delaying aquifer influx. It is planned to complete the three Neptune development wells above the N2 layer for this reason. Authigenic illite has the most important diagenetic effect on reservoir quality. It occurs throughout the reservoir but becomes more abundant and more fibrous with depth. There is a positive correlation between illite abundance and grain-size. Illite is developed preferentially in the larger pores associated with larger grain-size. However because the pores are larger, the illite does not have the profound effect that less illite can have in the finer grained facies. This is particularly noticeable below the top of N5 (as discussed above) where a change to a finer grain-size results in a dramatic reduction in permeability due to the increased effect of the authigenic illite. Cataclastic slip bands have also been seen in core from Neptune where permeabilities can be reduced by two to three orders of magnitude. The bands are developed preferentially in the coarser grained aeolian grain-flow facies due to brittle (rather than flexural slip) deformation and may locally compartmentalize flow.
Pressure relationships Mercury. There is very little pressure data available for the Mercury Field. The free water level (FWL) of -9492 ft TVDss has been determined using selected R F T data from the gas leg of 47/9b-6 and DST p* values for 47/9b-5a and 6. The FWL is also supported by 47/9-2, which clips the SW edge of Mercury and has an interpreted 15ft gas column below a Top Leman of -9472 ft TVDss. Neptune. Available data suggests that Cleeton (8 km NW of Neptune) and Neptune share a common aquifer. Drill stem test (DST) and RFT data suggest different free water levels for the Neptune wells, 47/4b-4 ( - 9 8 3 9 f t TVDss) and 47/4b-6 ( - 9 8 2 1 f t TVDss). This may indicate compartmentalization but may also reflect pressure depletion over time due to production from Cleeton Field. The gas-water contact for 47/4b-6 from log data is interpreted as -9839 ft TVDss, which is 18 ft deeper than that suggested by the RFT data.
Source The source of the gas in the Mercury and Neptune fields is believed to be the Westphalian Coal Measures. The diagenetic history of the Neptune Field (and surrounding wells) has been interpreted to suggest a Late Jurassic phase of gas generation with subsequent remobilization during Tertiary structuration. This interpretation is based on the distribution of illite within the reservoir. Mercury has lower levels of illite than is seen at Neptune and this has been interpreted to suggest an earlier (Cretaceous?) phase of hydrocarbon emplacement.
Reserves and production
Gas-in-place Mercury. The Base Case gas-in-place figure for Mercury is 124 BCF. The reservoir fluid composition is given in Table 1. The
786
B. SMITH & V. STARCHER
Table 1. Composition of the reservoirfluid in Mercury Field
Table 2. Composition of the reservoirfluid in Neptune Field
Component
% Molar
Component
% Molar
N2 CO 2 CH 4 C2 C3 iC4 nC4 iC5 nC5
4.620 0.770 91.220 2.150 0.500 1.100 0.170 0.066 0.002
N2 CO 2
1.680 0.530 92.110 3.920 0.850 0.340 0.130 0.070 0.370
CH4 C2 C3 C4 C5 C6 C7+
fluid contains 91% m e t h a n e and 0.77% c a r b o n dioxide a n d is lean having a condensate/gas ratio of only 6.2 B B L / M M S C F .
Neptune. The Base Case gas-in-place figure for N e p t u n e is 341 B C F with 66% of the in-place h y d r o c a r b o n s being reservoired in the N1 layer. The gas is sweet and lean with 92% methane, 0.5% c a r b o n dioxide and a condensate/gas ratio of only 3.44 B B L / M M S C F . The composition of the reservoir fluid is given in Table 2.
Gas Reserves Mercury. The M e r c u r y Field is to be developed with two high angle/horizontal wells, with drilling having c o m m e n c e d in J a n u a r y 1999. The plateau rate will be 50 M M S C F D . Recoverable reserves of 82 B C F are expected, which will be transported via a sub-sea pipeline to the N e p t u n e Platform to be c o m m i n g l e d with the N e p t u n e gas before being transported to the Easington C a t c h m e n t Area riser alongside the Cleeton facilities. The gas will be processed on Cleeton and exported via the existing pipeline to the D i m l i n g t o n
terminal. The recovery factor for the M e r c u r y Field (66%) is adversely affected by a c o m b i n a t i o n of an elongate structure and relatively thin reservoir (58-110ft).
Neptune. The d e v e l o p m e n t plan for N e p t u n e has three new high angle p r o d u c t i o n wells and re-entry of 47/4b-6 for completion as an additional producer. The wells are designed to have large vertical standoff from the g a s - w a t e r contact and to be completed above the N2 layer, which should act as a local barrier. Recoverable reserves of 286 B C F are expected. The recovery factor for the N e p t u n e Field (84%) is higher than at M e r c u r y due to a m o r e compact structure and thicker reservoir. The plateau rate will be 150 M M S C F D with first gas anticipated in N o v e m b e r 1999. The discovery, appraisal and development of the Neptune and Mercury Fields incorporated the work of many professionals. The efforts of everyone involved in these fields, present or past is recognized and appreciated. The authors would like to thank BG International and its partners Amerada Hess and BP Amoco for giving permission to publish this paper. The views expressed in the paper are the responsibility of the authors and do not necessarily reflect those of the co-venturers.
The Mercury and Neptune Fields data summary Field name
Mercury
Neptune
units
Trap Type Depth to crest Lowest closing contour GWC Gas column
NW-SE trending horst block -8850 -9492 -9492 642
Faulted four way dip closure -8853 -9839 -9839 -986
ft ft ft ft
Pay zone Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Petroleum saturation average (range)
Lower Leman Sandstone Fm Permian 58-110 73-94 12-14 27 91 58-66
Lower Leman Sandstone Fm Permian 366-405 99 17-21 110-140 68-72
ft % % mD %
Petroleum Gas gravity Viscosity Condensate yield Gas expansion factor Formation water Resistivity Field characteristics Area Gross rock volume Initial pressure Pressure gradient
0.612 0.0236 6.2 227.6
0.607 0.0236 3.44 253
0.052
0.056
10.4 8.66 4303 0.074
6.5 10.6 4385 0.08
notes
cp
BBL/MMSCF SCF/RCF
ohm m
at 60~
km 2
BCF psi psi/ft
Gas gradient
MERCURY AND NEPTUNE FIELDS Temperature Gas initially-in-place Recovery factor Drive mechanism Recoverable gas Recoverable NGL/condensate
204 124 66 Edge 82 0.5
176 341 84 Edge 286 1
PRODUCTION Start-up date
Nov 1999
Nov 1999
Production rate plateau gas Number/type of well
50 2 High Angle/Horizontal
200 3 High Angle/Horizontal + 1 vertical
References GLENNIE, K. W. 1982. Early Permian (Rotliegendes) Palaeowinds of the North Sea. Sedimentary Geology, 34, 245-265.
787 ~F BCF % BCF MMBBL
Anticipated at time of paper submission MMSCF/D
GLENNIE, K. W. & UNDERHILL, J. R. 1998. Origin, development and evolution of structural styles. In: GLENNIE, K. W. (ed.) Petroleum Geology of tke Nortk Sea," Basic Concepts and Recent Advances, Blackwell Scientific, Oxford, 42-84. KOCUe,EK, G. 1988. First-order and super bounding surfaces in eolian sequences- Bounding surfaces revisited. Sedimentary' Geology, 56. 193-206.
The Murdoch Gas Field, Block 44/22a, UK Southern North Sea A. M. C O N W A Y 1 & C. V A L V A T N E 2
1 ConocoPhillips, Rubislaw House, Anderson Drive, Aberdeen AB15 6 F Z 2 ConocoPhillips, 600 North Dairy Ashford, Houston, Texas 77079
Abstract: The Murdoch Field was discovered in 1984 when gas was tested from the Murdoch Sandstone of the Westphalian B, Carboniferous in well 44/22-1. The field lies along an elongate NW-SE trending faulted ridge, clearly evident at Top Base Permian structural level. Six exploration and appraisal wells were drilled on the structure prior to commencing a joint development in 1992 with the adjacent Caister Field. The reservoir unit, the Murdoch Sandstone, is interpreted as a low sinuosity fluvial complex of lower Westphalian B age. It is around 120/ thick and was deposited by a large N E S W flowing braided river system in which channels stacked and amalgamated to form the sand package. Production commenced at the beginning of October 1993 making it the first Carboniferous development in the UK North Sea. The maximum deliverability of the field is currently about 180 MMSCFD from six of the eight producers. Developed with a not-normally-manned platform facility, the gas is delivered to the Theddlethorpe Gas Terminal. Heterogeneity in reservoir quality combined with complex structural compartmentalization are the key control mechanisms on gas production in the Murdoch Field.
The Murdoch Gas Field lies in U K C S Block 44/22a located approximately 188kin off the Lincolnshire coast in the Carboniferous sector of the Southern North Sea, in 100 ft water depth (see Fig. 1). Present Murdoch Field owners are ConocoPhillips, as operator (54.5%), Tullow Exploration Ltd (34%) and G d F Britain Ltd (11.5%). Field development consists of a single not-normallymanned platform that is controlled remotely from the Conoco/BPAmoco Gas Terminal at Theddlethorpe. It is being developed with eight production wells, six of which are currently producing. Four of the current producers are sub-horizontal. The produced reservoir fluids are transported by the 26-inch CMS (Caister-Murdoch System) gas pipeline to Theddlethorpe, where the gas is processed and then sold. Production from the field commenced on 2 October 1993. Since then the field has been producing between 80 and 150 M M S C F D . Offshore compression facilities were installed and became operational in 1996. The field is currently in suction mode delivering an annual contract production for the year ending September 1999 of 82.7 M M S C F D and over the 1999/2000 period 8 9 . 4 M M S C F D gas.
History Licence P.451; Block 44/22 was awarded to a Conoco U K Ltd operated group in 1983 as part of the Eighth Round. The subsequent exploration, appraisal and development history is outlined below. Figure 2 illustrates the blocks, development boundaries and well locations for the Murdoch Field and adjacent exploration.
Exploration and appraisal The 44/22-1 Murdoch Field discovery well was drilled in 1984 with the objective of testing both the Permian Rotliegendes and Carboniferous sections. The well tested 2.0 M M S C F D gas from the Carboniferous Westphalian B, Murdoch Sandstone Interval. Appraisal of the large N W - S E trending, faulted inversion feature (Fig. 2) commenced in 1985 with the drilling of 44/22-2, but due to mechanical problems it did not reach its Carboniferous objective. Well 44/22-3, drilled in the same year, was more successful and penetrated 120 ft of the hydrocarbon bearing Westphalian B Murdoch Sand interval N W of the discovery well. The interval was tested and yielded 27.6 M M S C F D gas and 176 BOPD condensate. Encouraged by the results of 44/22-3, appraisal of the Murdoch Field continued through to 1988 with the drilling of the 44/22- 4, 5 and 6 wells. Well 44/22-4 successfully tested the Murdoch Sandstone interval at a rate of 28 M M S C F D gas and 44/22-5 established a gas-water contact in the SE corner of the field. Well 44/22-6 was drilled in the N W segment of the field, chasing deeper Westphalian A distributary channel systems. Unfortunately the sands were tight and the overlying Murdoch Sandstone Interval was water-wet.
The single exploration well and five appraisal wells were all plugged and abandoned. With appraisal complete, a joint development plan with the nearby Caister Field (Block 44/23a) was proposed and approved in 1992.
Development Five pre-production wells were drilled to meet a first gas date of 1 October 1993. The 44/22a-D1 and D3 vertical wells, were perforated in the Murdoch Sandstone interval and overlying Westphalian 'C2' Sands (Fig. 3). Wells 44/22a-D2, D4 and D5 were drilled as sub-horizontal wells with a slotted liner open to the formation in the 'C2' Sands and Murdoch interval. Production commenced on 2 October the 1993 with a field D C Q set at 1 2 0 M M S C F D gas for the first year. Early production indicated some reduction in the field gasin-place estimates due to compartmentalization of the reservoir (Fig. 2). This was to some extent expected as development drilling was suspended after the five wells pending acquisition and interpretation of the 3D seismic dataset. The Murdoch Field was also the first Carboniferous gas field to be developed in the UK, and little in the way of an analogue was available on which to base a reservoir management plan. A revised map based on the 3D seismic dataset and new gas-in-place estimates indicated additional faulted compartments that required new development wells to effectively drain the reservoir. Wells 44/22a-D6 was drilled in 1995 in the N E compartment as a sub-horizontal well with a slotted liner open to the formation in the 'C2' Sands and Murdoch Sandstone interval. From 1995 through 1999, three additional development wells were drilled. Two producing wells were abandoned following mechanical failure due to inferred casing collapse. 44/22a-D2z ceased production in 1996 and the D7 well was drilled in mid-1997 as a replacement gas producer, but mechanical problems prevented a successful completion and the well was abandoned. In the same year D5 also ceased production. Production from D5 was consistently the lowest on Murdoch, and the well had been a candidate for re-drilling since 1996. Well planning began with the concept of drilling a second lateral to improve deliverability, but following the drop in flow rate from D5 early in 1997 this was changed to a side-track replacement. In January 1998, 44/22a-D8 was drilled and successfully flowed 7 0 M M S C F D gas on completion. 44/22a-D9 was planned as a new well to replace production lost following the failure of D2z. D2z did not come back on production after a field shut-in in September 1996. Further diagnostic work indicated that this well also had suffered casing collapse due to movement of the Silverpit salt, evidenced by mechanical obstruction and Silverpit Formation filling the wellbore. 44/22a-D9 was completed on 21 June 1998 after 106 days. Following jetting and clean-up, the well flowed 68 M M S C F D gas on test.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 789-798.
789
790
A.M. CONWAY & C. VALVATNE
Fig. 1. Location of the Murdoch Field in the Southern North Sea. The export pipeline from Murdoch to Theddlethorpe is shown.
Structural development and field stratigraphy Three major tectonic events; the Variscan (end Carboniferous), Cimmerian (end Jurassic) and Alpine (Late Tertiary) Orogenies dominated the structural development of the area. During the Variscan Orogeny, convergence of the Laurasian and Gondawaland supercontinents induced a southward stretching of the foreland basin of the northern plate. This stretching resulted in a period of block faulting along a NW-SE trend that continued
until Dinantian times. The blocks are separated by 'spoon-shaped' faults; the NE flank of Murdoch is an example of one these major down-to-the-south extensional faults and the SW field boundary fault represents separation from the adjacent Caister Block (see Fig. 4). Thereafter the area went into a period of thermal sag as the thinned crust re-equilibrated. Throughout the Namurian and Westphalian, southerly flowing rivers deposited sediments from the Fenno-Scandia highlands, to the north, into the slowly subsiding basin. There followed a late stage compressional pulse of the
MURDOCH GAS FIELD
791
Fig. 2. Structural features map of the Murdoch Field area illustrating the fault compartmentalization of the reservoir. The locations of the seismic section A-A' (Fig. 6) and regional cross-section D-D' (Fig. 7) are shown.
'Variscan Front', which resulted in the N W - S E trending anticlines and basin inversion. The area was further complicated by an element of strike-slip motion followed by erosion and peneplanation, establishing the truncated anticlinal intra-Carboniferous structure observed today in Block 44/22. Sedimentation continued uninterrupted from end Carboniferous to end Jurassic times. A period of major inversion and reactivation of faulting, commonly in the reverse sense, followed this. Deposition resumed in the Lower Cretaceous but was again interrupted by the
predominantly compressive Alpine Orogeny. Carboniferous faults were again reactivated, in a reverse sense, resulting in the present day structural configuration. The Murdoch Sandstone interval has been lithostratigraphically subdivided into three reservoir units: M1, M2 and M3 (see Fig. 3). At the base of the Murdoch Sandstone interval is the finegrained and often tight M1 unit. The sediments are interpreted as silty mouthbar sandstones and are locally eroded by M2 fluvial
792
A. M. C O N W A Y
& C. V A L V A T N E
c~ O3 I--
I I
z
I
O O
-~
2n~
>~ o
mo4
o
2~ ~-~ o~
n,
,.o
~rr
r
o,
moo
A
o
u.i
i
rr
I
b4
v
I
t---
I
Iz LLI
I I I
o
F.-
t.O J
~-i
z
03 o
C c-
o!I
_~
0
c-
z
I
LU
I
I
--
~
LL ~,
~
>,
>o
._
r-
CO 0 ~.) . ~
t-
c-
Q_ E e~
LLco
m
u_
_ -z"_"
>
_=
=
. . . . .
......
9
>
>
z
~0
t-"
~
s~
.~
C
<
C
o
I E
E 2
09
<
~-'1_~
~
>,
.-
I
2
c~
.'=(U
t-"
co
03
0
E
o3
I
i l ii
!:~!~!!:~i!:~il i i i i i i I i
ii!ili{i
:::::::::::::::~::~Ii[ i t I ! I t I ! I I-'~[
-:0,~'.....
~..-.---'~,..--I ~--.~.,
...... ' ~ - -
t1{1{1!1' I:::~.:;!~!;i~::::::: ::~i:~:~":::~/~.&:: :::::::~!;2~',::r?~':'~:,4~:::
euo;spues
I I
9
9
9
!i!iii!i!]!ii
"E';
,-o
i!i!
qooPmlAl
I I-O0
T i'i'i'[ i- "i' i iiiii ~i" ]iii iii i! !{i! I ' 1 " "1" " 1 ' ~ = 1 " 1
s
I I
O
-7
O
4=
O3OO
g
~
~
~
~i ~ I ;> O
n co o~
>-
C~
"l-
-o x~
D-
<
n" CO i
I~
ez
~
O
~Sn-
Z
:~C.
"1-
.o_ 03
~E =o
i
i
o~ co
,
o
rY
~o
ue!leqd~saAA
00
ue!sal!S
ueunuJeN
i
~0 -.=
MURDOCH GAS FIELD sandstones (44/22-3, Fig. 5). Unit M1 has limited reservoir potential across the Murdoch Field. Figure 5 illustrates the high gamma response in these silty sands. In the SE of the field (44/22-5), this unit is overlain by the first true incursion of low-sinuosity fluvial channel fills, the M2 unit, into the Murdoch area. In gross terms, M2 forms an overall fluvial package with several coarsening upward channel sand packages. The main body of the Murdoch Sandstone interval, M2 with the upper and lower limits of each zone generally identified by distinct pebbly sands at the base and channel abandonment facies at the top. These zones are interpreted as major sand units deposited by a high energy braided fluvial channel system. Each zone comprises conglomeratic bands, cross-bedding and fining upward sequences that can exceed 60 ft in thickness. In all wells, M2 terminates in a lacustrine/channel abandonment facies association, which, where present, represents a permeability break. This abandonment facies is regionally termed the Murdoch Mid-Shale and although it is not well developed over the Murdoch Field, in places it is completely eroded out by the M3 above, it thickens to the SW. The M3 upper unit has an overall upward fining profile indicated by decreasing grain size and more complex channel geometries (best demonstrated in the 44/22-5 well, Fig. 5). The pebbly conglomeratic channel lag which forms the base to this unit can be seen in most of the wells in the study area, however clast size varies significantly. The largest clast supported conglomerates are found to the N E of
793
the Murdoch Field, around the McAdam, 44/17-1 area. These are 0.5 cm scale, moderately sorted, sub-rounded mainly quartz clasts. These channel lags are mainly matrix supported.
Geophysics The 3D seismic survey, which covers the Murdoch Field is part of a much larger survey shot over blocks 44/21a, 44/22, 44/23a and 44/28. This was acquired in 1992 but the final migrated volume was not available until June 1994. From well logs a reflection event was tied to the Top Murdoch Sandstone and this event was interpreted across the entire field to produce a Top Murdoch Sandstone time map (see Fig. 6). The same operation was performed for all the overburden horizons: Top Chalk, Red Chalk, Bunter Sandstone, Zechstein and Rotliegendes, used in the depth conversion. Nearby well data was used to determine an interval velocity/mid-point time function for each of these intervals. These functions were applied in a layer-cake depth conversion to produce a Top Rotliegendes depth map. From this an average velocity map to Top Rotliegendes was produced, which was smoothed and edited to tie all wells before recalculating a final Rotliegendes depth map. The Murdoch Sandstone depth
Fig. 4. Top Murdoch Sandstone structure map showing the compartmentalization of the reservoir by faulting tha{ often act as barriers inhibiting production and isolating polygons where the gas-in-place is not recovered. Fault polygons around 44/22-5 are modelled as un-drained.
794
A. M. C O N W A Y & C. V A L V A T N E
. ,,..~ 9
o
o .,,..o
o
.~ ..,,a .i...a
c~
0
0 0 0
8
o cr~ c~ cJ~
9
9 LU OL. Cn
oQ:
E~L
-rT
0
o
"T"
OC
z~
o~ ~
796
A . M . CONWAY & C. VALVATNE
map was obtained by adding a single isopach (interval velocity 14 400 ft s -1) onto this depth map. Editing was performed to tie all wells producing the final Murdoch Field top structure map (Fig. 4). This map incorporates all available well data up to the end of 1996. The two new wells, D8/06 and D9/08, tie the existing map within 30 ft. In 1996, an extensive re-evaluation of the geophysical and geological data available on Murdoch was undertaken. The previous fault geometry was verified and no new faults were recognized. A model was developed for predicting fault sealing, and used to reconcile geologically mapped volumes for initial gas-in-place with volumes indicated by production data.
Trap The Murdoch Field is bounded on three sides by high angle reverse faults and is separated from the adjacent Caister Field in Block 44/23a by a down-to-the SE normal fault (Fig. 2). The trap is provided by up-dip fault seal to the NE, lateral fault seal to the NW and SE and dip closure to the SW. The elevation of the horst block varies from -11 100' TVDss near the central 44/22a-D1 well to - 1 2 6 0 0 ' TVDss west of 44/22-6. There is a moderate amount of intra-field faulting with the largest throws approaching 600'. The faulting appears to have two predominant orientations: N W SE and NE-SW. Figure 7 provides a regional cross-section N W - S E across the Murdoch Field illustrating the trap under the Base Permian Unconformity. The dipping Murdoch Sandstone interval is sealed by a combination of the Silverpit shales and Westphalian B shales that overlie the Murdoch Sandstone. In the SW of the field, the Murdoch Sandstone is truncated out by the Base Permian Unconformity.
Reservoir
Geological model The Murdoch Sandstone is interpreted as a series of Lower Westphalian fluvial channel sands. The reservoir unit ranges in thickness from 90 f to 125' thick and was deposited by a large N E - S W flowing low sinuosity braided river system in which channels stacked and amalgamated to form the sandstone interval (see Fig. 8). The hetero-
geneity in reservoir quality seen in Murdoch is strongly related to the depositional elements of the individual channels within the stacked channel succession: basal channel lags; middle upward fining sandprone sequences; abandonment tops. Best reservoir quality occurs within the middle medium-grained to coarse-grained channel-fill sandstone elements. The coarsest grain size is found in pebbly basal channel lag layers, which have relatively low permeability as a result of their poor grain size sorting. Fine-grained abandonment tops of channel-fills were in most instances eroded by subsequent channels and are therefore rare. During the exploration/appraisal drilling on Murdoch some wells encountered thin sands above the main reservoir in a zone termed the 'C2' Sands (see Fig. 3). The distribution and productivity of these sands was poorly understood and detailed geological (reservoir zonation using log and core data) and reservoir engineering work was undertaken during the development phase to better characterize these sands. These studies showed that the C2 channel sands tend to form isolated anastomosing 'ribbons' rather than amalgamated sheet-like bodies (cf. underlying Murdoch Sandstone interval) and are unlikely to contain large gas volumes but, where intersected, they have been perforated and will contribute some gas to the field. The near-vertical, centrally located wells D1 and D3 (Fig. 2) have excellent deliverability as a result of the large proportion of high-permeability facies and the high average permeability in this central part of the field. Elsewhere in the field, sub-horizontal wells (i.e. wells which cross the entire reservoir at a very high angle) have proved to be a very effective means of improving well deliverability by exposing a much greater reservoir length to the wellbore. The average compaction adjusted core porosity for the Murdoch Sandstone is 10.6%. Permeabilities vary from 5 mD to 400mD with the high permeability streaks associated with the coarse to medium grained sands often found immediately above the conglomeratic pebbly bands. The Murdoch Sandstone interval over the Murdoch Field has a similar, relatively simple, detrital mineralogy that cannot be subdivided or readily distinguished from the overlying and underlying Westphalian sandstones on the basis of the main detrital components. The sandstones are characterized by a lack of detrital feldspar, and classify as quartz arenites and sublithic arenites. Quartz is the dominant detrital component accounting for 70% of the total detritus and 50% of the total rock volume. A diagenetic sequence was initiated early with precipitation of spheroid and rhombic siderite followed by pyrite, minor quartz overgrowths and vermiform
8,000
9,000
10,000
11,000
12,000
13,000
14,000
Fig. 7. Regional geological cross-section across Murdoch Field illustrating the position of the gas-water contact and the faulted geometry of the reservoir sand.
MURDOCH GAS FIELD
797
56o00'N
53~
Fig. 8. Model showing the regional palaeography of the early Westphalian B and Murdoch Sandstone interval. The area was low lying with development of a low sinuosity, braided river system flowing south towards a lake that bordered the London-Brabant massif. The approximate location of Murdoch Field is shown.
kaolinite. Oxidation of earlier-formed iron-bearing minerals to haematite was followed by significant burial related compaction, which destroyed a large amount of the effective porosity. However, during late-burial extensive dissolution of pore filling quartz cement with minor replacement by kaolinite is evident, enhancing the porosity by varying amounts across the field. These porosity variations have their greatest expression in the eastern part of Murdoch. In this area poor productivity, observed in the 44/22-1 and 5 wells, is attributed to an area of greater compaction compared with the centrally located higher performing 44/22-3 and 4 wells. In addition, the central part of the field exhibits greater post Permian burial quartz grain dissolution and benefits from enhanced porosity.
Gas-water contacts The gas-water contact over the Murdoch Field ranges from - 12 120' TVDss to - 1 2 1451 TVDss, with an average - 1 2 125 t TVDss (Fig. 7) used to calculate volumetrics. This is based on good quality R F T data from several wells together with log interpretation (Figure 8 shows the regional - 1 2 125' gas-water contact).
Source and seal The Westphalian A/B, alternatively known as the 'Coal Measures', is the principal source rock for the overlying Westphalian reservoirs. The predominantly shaley coal-bearing interval also provides lateral seal for the Murdoch Sandstone and Westphalian B C2 reservoir sands.
Gas-in-place and reserves The current estimate of gas-in-place is based on the extensive geological and production data review undertaken in 1997 and details are shown in Table 1. Cumulative production from December 1997 to October 1999 is 236BCF. Daily gas production requirements are currently 89.4 M M S C F D with a swing factor requiring peak production of 125.2 MMSCFD. The authors wish to thank both GdF Britain Ltd and BP, for permission to publish this paper. The authors have also drawn on the knowledge of colleagues from the Southern North Sea Asset Team of ConocoPhillips.
798
A . M . CONWAY & C. VALVATNE
Table 1. Murdoch Field- Gas-in-place, estimated recovery and production to October 1999 Polygon
Wells
GIIP (BCF)
1 2 3 4 5
D-01 & D-03 D-02 & D-09 D-04 D-05 & D-08 D-06
106 82 42 80 64
Total
374
Murdoch Field data s u m m a r y Trap Type Depth to crest (Top Murdoch) Lowest closing contour Gas column
Recovery factor 95.6% 94.3% 90.9% 94.2% 87.9%
E U R (BCF) 101.4 77.4 38.2 75.3 56.2
Production Start-up date Development scheme
Production rate (1998/1999) Pay zone Formation
Age Gross thickness (average; range) Net/gross ratio (average; range) Porosity (average; range) Net sand cut-off (permeability 0.1 roD) Hydrocarbon saturation (average) Permeability (average; range)
Westphalian B, Murdoch Sand Interval Carboniferous 118 ft; 56-159 ft 0.94; 0.89-0.98 10.6%; 9.3-13.0% 6.4% porosity 55% 73 mD; 0.1-1000mD
Hydrocarbons Gas gravity Condensate/gas ratio Gas expansion factor
0.673 6.5 BBL/MMMSCF 283 SCF/RCF
Formation water Salinity Resistivity
200 000 ppm 0.064ohm (a: 6 0 T
Reservoir conditions Temperature Initial pressure Pressure gradient in reservoir
235"F @ 11 700 ft sub-sea 6140psia (a~ 11 700ft sub-sea 0.101 psi/ft
Field size Gross rock volume Initial gas-in-place
583 500 acre/ft 478 BCF
84 48 27 40 37
348
Recovery factor Recoverable hydrocarbons Faulted Horst Block 11250 12 600 ft sub-sea Field full to spill 125-875 ft
Production (BCF)
236
93% 348 BCF
October 2nd 1993 Single not-normally-manned platform controlled remotely from the Theddlethorpe Gas Terminal DCQ 82.7MMSCF/D
References AITKEN, J. F. & FLINT, S. S., 1995. The application of high resolution sequence stratigraphy to fluvial systems: a case study from the Upper Carboniferous Breathitt Group, Eastern Kentucky, USA. Sedimentology, 42, 3-30 CORBETT, P., ZHENG, SHI-YI., PINISETTI, M., MESMARI, A. & STEWART, G., 1998. The integration of Geology and Well Testing for Improved Fluvial Reservoir Characterisation. In: SPE International Conference and Exhibition in Beijing, China, Nov 2-6, 1998. HAKES, W. G. 1991. Development of Intra-Carboniferous structural styles, United Kingdom Southern Gas Basin. Petroleum Geoscience, 1, 419-443. LEEDER, M. R. 1988. Recent developments in Carboniferous geology: a critical review with implications for the British Isles and NW Europe. Proceeding of the Geologists Association, 99(2), 73-100. MAYNARD, J. R., HOFMANN, W., DUNAY, R. E., BENTHAM, P. N., DEAN, K. P. & WATSON, I., 1997. The Carboniferous of Western Europe: the development of a petroleum system. Petroleum Geoscience, 3, 97-115. McLEAN, D. & MURRAY, I. 1996. Subsurface correlation of Carboniferous coal seams and inter-seam sediments using palynology: application to exploraing for coalbed methane. In: GAYER, R. & HARRIS, I. (eds) Coalhed Methane and Coal Geology. Geological Society, London, Special Publications, 109, 315-324 RITCmE, J. S., PILLING, D. & HAYES, S. 1998. Reservoir development, sequence stratigraphy and geological modelling of Westphalian fluvial reservoirs of the Caister C Field, UK Southern North Sea. Petroleum Geoscience, 4, 203-211.
The Pickerill Field, Blocks 48/11a, 48/11b, 48/12c, 48/17b, UK North Sea O. C. W E R N G R E N
1'3, D. M A N L E Y 4 & A. P. H E W A R D 2'5
1 A R C O British Ltd, London Square, Cross Lanes, Guildford, Surrey GUI IUE, UK 2 L A S M O PLC, 101 Bishopsgate, London E C 2 M 3XH, UK 3 Present address." B P Exploration Operating Co., Farburn Industrial Estate, Dyce, Aberdeen AB21 7BN, UK 4 Present address: BP Exploration Operating Co., Chertsey Road, Sunbury on Thames, Middlesex T W 1 6 7LN, UK 5 Present address: Petroleum Development Oman, PO Box 81, Muscat 113, Sultanate o f Oman
Abstract: The Pickerill Field is a dry gas accumulation straddling four separate licences in the UK Southern North Sea. Discovered in 1984, 12 appraisal wells were drilled to define the field before Annex B approval in 1989. Subsequently, Pickerill has been developed using 15 high angle wells, a large number of which have been sidetracked reflecting the geological complexity of the accumulation. Pickerill has been in production since August 1992, and has an estimated initial reserves in excess of 500 BCF.
The Pickerill Field extends across Blocks 48/1 la, 48/1 lb, 48/12c and 48/17b of the U K SNS (Fig. 1). Gas production is via two unmanned platforms located 130 km offshore, in 82 ft of water. Gas flows onshore to the Theddlethorpe Gas Terminal where it is processed, compressed and shipped primarily to the Killinghome Power Station. The field was developed and is operated by A R C O British Ltd.
History Pre-discovery Block 48/11 was awarded as a First Round Licence (1964) to the Arpet Group who drilled the 48/11-1 exploration well (1966) and encountered minor gas in the Rotliegend. The well failed to flow to surface and was plugged and abandoned. The 48/11-2 appraisal well, drilled in 1969, was a dry hole. A mandatory 50% relinquishment of the licence took place in 1970 resulting in a loss of 162 km a of the block. The relinquished portion was licensed to the Amoco group who drilled the unsuccessful 48/11-3 well (1977) before relinquishing the acreage once again.
Discovery The Conoco Group were awarded Block 48/1 lb in the eighth round (1983) and drilled the 48/1 lb-4 discovery well in 1984 encountering a 134 ft gross pay interval in the Leman Sandstone but no gas-water contact (Fig. 2). The well tested 4 8 . 8 M M S C F D . The Conoco Group then drilled a Corallian Limestone, West Sole Group and Bunter prospect with 48/11b-5 (1985) but the well was a dry hole. The second gas bearing well was therefore 48/11b-6 (1985), which encountered 109 ft of gross pay, reflecting the thinning of the sandstone towards the west. Again, there was no gas-water contact in the well, although pressure analysis indicated it to be in communication with 48/1 lb-4. The A R C O group then drilled 48/1 la-7 (B1) in 1986 finding 210 ft of gross pay, and no gas-water contact. Pressure analysis indicated that this well was not in communication with the previous discoveries. Separate, but supposedly contiguous, western and eastern accumulations were, therefore, defined for the field. Subsequent wells, 48/1 lb-8 (1986) and 48/1 la-9 (1987), were drilled by the Conoco and A R C O groups, respectively. Both were interpreted to lie in the eastern accumulation. Well 48/11b-10 was drilled by Conoco to appraise the N W corner of the field and found a 110 ft gas column. It flowed gas and proved to be in the western accumulation. Late in 1987, the final appraisal well 48/1 lb-11 was drilled to the north of the field but it only encountered a 26 ft gas column and did not flow to surface. In 1989 the P.460 (Conoco) group relinquished the northern 50% of their part block.
The eastern margin of the Pickerill Field in 48/12b proved elusive for the initial holders of the licence. Both the Conoco Group and the Chieftan Group held and relinquished the acreage before the Gas Council (Exploration) Group licensed the acreage in the Eighth Round. They drilled the 48/12b-4 well (1987), which encountered a 240 ft gas column. Pressure analysis indicated that the well was in communication with appraisal wells, 48/11a-7 and 48/11a-9. Following a number of licence changes, this licence is now held by Mobil and EDC as 48/12c. Mobil proved the most southern extent of Pickerill in 1988 on the 48/17b licence. The 48/17b-7 well hit a fault and had to be sidetracked up-dip where it encountered gas shows in the Leman Sandstone, but did not flow gas to surface on test. Pressure analysis indicated that the well was not in pressure communication with the rest of the field.
Post discovery As development commenced Pickerill was believed to be an accumulation with a gas-water contact in the east of 8938 ft TVDss, proved by well 48/11b-8, and a gas-water contact in the west of 9095 ft TVDss, proved by well 48/11b-10. A densely faulted graben area was thought to separate the eastern and western parts of the field, which also has an 80 psi difference in initial reservoir pressure. This simple model was to be contradicted and disproved by many subsequent well results. Figure 2 shows the location of the exploration, appraisal and development wells. Development drilling started on the Pickerill A platform in 1991 yielding the first surprise for the field. The 48/1 lb-A1 well encountered a 105 ft reservoir section with the base 217 ft above the western gas-water contact and a pressure gradient in line with the 48/1 lb wells. However, it failed to produce any gas on test. Post well analysis indicated that the Rotliegend section was very highly faulted and cemented. This fault and its damage zone was not visible on the 2D seismic data. Even today, modern depth-migrated 3D seismic data does not show the well to be in a heavily faulted area. As a result, the A 1 well was sidetracked to the N W where it found a significantly better quality reservoir. In total eight wells were drilled from the A-platform during the period between May 1991 and M a y 1994. Of these the A2, A4, A5 and A7 wells were drilled without any significant further surprises in the reservoir. However, well A3, drilled to the east of the Platform, found a significantly higher gas-water contact than expected, at 8674 ft TVDss, but only flowed 7.2 M M S C F G D on testing. Up until this point, due to a combination of the thin reservoir column (80-145 ft) and a deep gas-water contact, none of the crestal wells had encountered any water. The well had to be suspended temporarily for fear of water production and to await further seismic definition of the area, post-initial development. In 1997, A R C O reentered this well and drilled one of the first successful multi-lateral wells drilled in the North Sea, 4 8 / l l b - A 3 Y (Bokhari et al. 1997).
GLUYAS, J. G. & HlCHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 799-809.
799
800
O.C. WERNGREN ET/IL.
9 4.,.a
PICKERILL FIELD
801
Fig. 2. Pickerill Field schematic.
Development drilling in the northwestern area of the field was also problematic and the A6 and A8 wells both had to be sidetracked having established either poor reservoirs or a contact in the initial well bore. Drilling from the B platform in the east commenced in November 1992 and concluded in March 1994. Seven wells were drilled, one of which, B3, was sidetracked when it encountered a thin gas column on the flank. Furthermore, well B2 encountered a possible perched gas-water contact at 8725 ft TVDss in an area that had been originally perceived to be the crest of the eastern accumulation (Fenwick 1994). The B6 well, which actually encountered the eastern gaswater contact at 8938 ft TVDss, has never flowed any significant volumes of hydrocarbon and remains a sidetrack option. Returning again to the A platform, Partners drilled 48/1 lb-A9 in 1999. This well was designed to access reserves in a fault block in the centre of the field SE of A1. A gas-water contact of 9095 ft TVDss, the same as that in west Pickerill, was prognosed. Once again the field proved its capacity to surprise, water bearing Leman Sandstone being encountered above both the west and east gaswater contacts and up-dip of gas in A1.
passed over as either totally wet or one in which there were only tens of feet of gas column.
Structure Tectonic history and regional structure Subsequent to late Carboniferous uplift, the Pickerill area saw general basin subsidence through the Permian and into the early Triassic. Rejuvenation of source areas peripheral to the basin may have initiated halokinesis during the Triassic, which increasingly influenced sedimentation (Arthur 1993). The Pickerill structure itself has origins in the Jurassic, when the influence of extension in the central and northern North Sea caused the development of highs and basins such as the Sole Pit Trough in the southern North Sea. This event initiated a regional N W - S E fault system, which dominates Palaeozoic structures today. Late Cretaceous-Tertiary inversion uplifted the Sole Pit Trough and this event affected the Pickerill structure. In the axial region, to the north of Pickerill, inversion removed all Jurassic and some Triassic rocks, whereas at Pickerill erosion removed only the upper part of the Chalk sequence.
Discovery method Local structure By the time the discovery well 48/11b-4 was drilled in 1984, the concepts of regional reservoir development and ubiquitous charge were well advanced. Structure, therefore, remained the primary risk. The latter was addressed through improvement of seismic imaging and an increasing understanding of depth conversion methodology. Given that the Pickerill Field lies on four separate licences, all of which have numerous licencees, it cannot be argued that only one exploration strategy was applied to the area. It was more a case of the requisite mass of hydrocarbon being discovered together with recognition that a joint effort needed to be applied in order for the development to proceed. It is also easy to see with hindsight that if a certain combination of development well locations had been drilled as the initial exploration wells, the area could have been
The structure map (Fig. 3) clearly demonstrates the familiar N W - S E structural grain at Rotliegend level. The central part of the field shows a more N N W - S S E trend, however, which divides the western and eastern parts. The local overburden features a W N W ESE trending graben, parallel to the axis of the field, with a thinned Zechstein section and a 'pulled apart' Bunter sequence (Fig. 4). Figure 4 also demonstrates the inversion of this Mesozoic graben. Until 1990, seismic coverage was done using 2D datasets after which they were superseded by a new, 3D survey. The latter was utilized for the definition of the field for development purposes. In 1997, the 3D survey was pre-stack time migrated and the resulting cube post-stack depth migrated to yield a superior product for
802
O.C. WERNGREN E T A L .
Fig. 3. Top Rotliegend depth structure map.
identification of infill and extension drilling targets. Depth conversion is performed by the layer cake approach, which compensates for the push down over time on the Top Rotliegend reflector, induced by thickened Lower Jurassic and Upper Triassic sections, (cf. Fig. 4).
Stratigraphy The oldest rocks penetrated during drilling of the Pickerill Field are sandstones, siltstones and mudstones of the Carboniferous (Fig. 5). These sediments are thought to be of fluvial-deltaic origin and have been interpreted as channel or overbank crevasse sandstones separated by units of flood-plain or lake mudstones. The Namurian rocks are overlain by mudstones, siltstones, sandstones and coals of Westphalian age. The depositional setting envisaged is that of a delta-top environment cut by distributary channels, which varied from low to high sinuosity and migrated across the area. The Carboniferous section in wells 48/11b-4, 48/11a-7 and 48/12b-4 was interpreted as being gas-bearing from logs although there was no flow on testing. Pressure responses indicated that the sandstones were very tight. Examination of core samples reveals that primary reservoir quality has been greatly reduced by later dia-
genetic events. The most important control on poroperms has been that of quartz cementation, which has reduced porosities and greatly reduced permeabilities. As a result of this, the Carboniferous is not currently viewed as a viable reservoir objective in the Pickerill Field. A lack of continuous seismic reflectors in the Carboniferous also means that it is not possible to map this horizon across the blocks with any confidence. The Rotliegend unconformably overlays the Carboniferous as seen on certain seismic sections, but the regional dip of the Carboniferous can only be inferred. The Permian Rotliegend of the area consists of the Leman Sandstone Formation. This formation lies unconformably on a Carboniferous peneplain surface, which resulted from tilting and erosion during the latter stages of the Hercynian Orogeny. The Leman Sandstone thickens across the area in an easterly direction, varying from 57ft in the 48/1 lb-3 well, to 604ft in the 48/12b-3 well. This reflects the regional eastward thickening towards the Sole Pit Basin axis. In close proximity of the Pickerill Field, the Leman Sandstone penetrated by wells varies in thickness from 109 ft in the 48/1 lb-6 well up to 240 ft in the 48/12b-4 well. The seismic reflector at Top Rotliegend level is the deepest continuously mapable seismic horizon across the Pickerill Field. Immediately overlying the Leman Sandstone Formation is the Kupferschiefer, the basal member of the Zechstein Supergroup.
PICKERILL FIELD
803
I
lkm
I
Base Red Chalk Top Corallian Top Lias Top Triassic Top Bunter Top Zechstein Top Plattendolomit Top Rotliegendes
Fig. 4. SW-NE trending seismic line through Pickerill.
The Kupferschiefer is a dark, silty, bituminous shale varying in thickness in the field wells from 3 to 5 ft and exhibits a distinctive high gamma-ray peak. It marks the onset,of evaporite deposition. The Kupferschiefer is succeeded by the Z1 Zechsteinkalk which varies in thickness from 4 to 18 ft in the field wells. The upper member of the Z 1 evaporitic cycle, the Werraanhydrit, varies in thickness reflecting the basinward thinning of the Z 1 cycle from the evaporitic shelf edge, which lies to the SW of the field. The thickness of the succeeding Z2 cycle varies greatly depending upon the presence or absence of the Stassfurt Halite Member. In wells 48/1 lb-4, 48/1 lb-6, 48/1 lb-8, 48/1 la-9 and 48/17b-7, the Z2 Stassfurt Halite cannot be differentiated from the overlying Z3 and Z4 halites. In contrast to this, the Z2 halite member is 1184 ft and 1355 ft thick, respectively, in wells 48/1 lb-10 and 48/1 lb-3. This is due to the fact that the Zechstein interval above the Z2, and indeed the Triassic, Jurassic and Lower Cretaceous thicknesses above this, are all greatly affected by later tectonic movements and halokinesis. Where present in the field wells, the Z3 Plattendolomit varies in thickness from 192 ft in 48/12b-4 to 297 ft in 48/11-1. Owing to rafting, due to salt flowage or to the effects of faulting, the Plattendolomit is absent in the central part of the field. Drilling of the recent A9 well has shown that the Post Stack Depth Migrated data more accurately reflects the presence or absence of the Plattendolomit, as well as the absolute edge of any raft. The section overlaying the Plattendolomit consists predominately of halites alternating with potassium salts and minor anhydrites. The effects of Post-Zechstein salt flow or of faulting on these Z3 and Z4 Group evaporites have effectively masked any original thickness variations within these sections.
The basal part of the Triassic, the Bacton Group, consists of the continental Bunter Shale Formation and the overlying Bunter Sandstone Formation. It is absent in a large number of wells due to listric faulting. Overlying the Bacton Group is the Haisborough Group which has also been greatly affected by faulting. At the end of the Triassic, deposition of shales of the Lias Group marked the return of marine conditions. The maximum thickness of Lias encountered is 2490 ft in well 48/11 a-9. This well is located towards the centre of the Mesozoic graben and appears to have a complete Lower Jurassic section. In contrast, wells located towards the graben flanks, have been cut by faulting and much of the Lias has been removed, e.g. 48/1 la-11 only has 376 ft of Lias. Here, both the uppermost and lowermost Lower Jurassic sections have been removed by faulting. The Middle Jurassic sequence consists of shales and sandstones of the West Sole Group. The Upper Jurassic is uniform in thickness and consists of mudstones, sandstones and limestones of the Oxford Clay and Corallian Formations succeeded by mudstones and siltstones of the Kimmeridge Clay Formation. Over the field area, the uppermost part of the Upper Jurassic section has been removed by erosion at the Base Cretaceous Unconformity. The Lower Cretaceous is represented by the shallow marine shales of the Speeton Clay Formation and the argillaceous limestones of the Red Chalk Formation. The Upper Cretaceous chalk varies in thickness across the field from 1700 ft to 2500 It, with a general thinning to the NE towards the Sole Pit Basin inversion axis where it is completely removed by erosion. The Upper Cretaceous crops out at the seabed in all the field wells. To the SW, in wells 48/11-2 and 48/11b-5, there are 50 to 60ft of Tertiary sediments interpreted from electric logs.
O. C. WERNGREN ET AL.
804
Trap feet
Trap type
03 D
CHALK
o
uJ O
1000 -
uJ n.. o
I
- - - RED CHALK SPEETON CLAY
I
2000 -
HUMBER
tO u3 03
/
I
I v
WEST SOLE
tr" D ,-j
9
9
9
9
9 t
9
t
v
9
t
t
t
3000
UAS. PENARTI-I z g
~
--(3 03
~
03 <
KEUPER A.
A
MUSCHEL H
A
A
A
A
BBBBBBBBNBBI m
m
m
6
BUNTER SST.
I'-
A
iiiiiiltttlti
.----ROT HALITE5000
8
A
llllllliltlll IlUUmUilllNII
4000 -
KEUPER N
A
m
m
m
9
9
9 6 6
m
9 9
9
9
m
m
m
9 6
m
9 9
9
9
e'
m
9 9
9
9
9
9
The Pickerill Field is a complicated four-way dip and fault closure. It is compartmentalized in west and east areas by a N N W - S S E trending fault zone in the central part of the field. A third compartment in the SE is downthrown by an E - W oriented fault zone. Closure on the SW and SE flanks is provided by faulting, whereas in the N E and NW margins dip closure predominates. Crestal areas in the west, centre and southeast have elevations of 8100 ft TVDss, 8200 ft TVDss and 8850 ft TVDss, respectively. The major reservoir compartments have gas-water contacts at 9095 ft ss (west), 8938 ft ss (east) and 9015 ft ss (southeast). In addition, some less obviously defined compartments occur in the vicinity of wells 48/1 lb-A3 and 48/1 la-B2 with shallower, possibly perched, gas-water contacts (8674 ft TVDss and 8725 ft TVDss, respectively; Fenwick 1994). These wells share a common gas gradient with east Pickerill, but have a water zone which is at about 100psi above the field water zone (Fig. 6). If they are perched contacts, then they would imply that the underlying Carboniferous is impermeable, with the Top Carboniferous structure controlling Rotliegend contacts in isolated areas. Recent analysis indicates that a Carboniferous high underlying the eastern portion of the field is controlling the extent of the perched water. Whereas the field was once perceived to be totally gas bearing, areas can now be defined where the perched contacts are likely to be found. Figure 7 demonstrates the separation between west and east Pickerill and the complex relationship of the gas-water contacts to the structure. The presence of sealing faults may also play a part in the compartmentalization. Wells 48/1 lb-A3 and 48/lla-B2 are in a structurally similar position and are in proximity to fault zones, but these are difficult to reconcile exactly with the extent of the perched contacts. It is believed that the compartment tested by 48/lib-A9 is water-bearing due to a structural configuration illustrated by Fig. 7. The charge derived from the north and west is thought to have displaced water in west Pickerill until the trap was filled down to the elevation of the top Carboniferous saddle (seen in Fig. 7) at the location of well A 1. To the SE of this position, the water is trapped by the Zechstein top seal, Carboniferous bottom seal and, to the east and west, by the bounding faults of the eastern and western parts of the accumulation.
9 9
6
Seal 6000-
BUNTER SHALE 41
--
BROCK. p._.---
LEINE HAL HIAUPT.ANH
~TrFIT~TrM1T III!111111111 IIIIIIIIIIIII I /
PLATF.DOL STASSF. H
7000-llllilllJiill i]lllllll
BASAL ANN
$ ,,, ,,=, 5
9
I
I
"A A X A A'A A X AAAAAAA AAAAAAAA
WERRA A.
~
I Ill
AAAAAA^
FtO'lr LEMAN SS'I ~
I
8000~
CARBONIFEROUS
9 ~
AOA
. . . . .
, v v v v v- -~. CvA vJ ,~ VA
~K~ A 9
Top seal is provided by Zechstein anhydrites and halites. The Zechstein sequence varies considerably across the area due to salt movement. The Hauptdolomit and Plattendolomit have both shown significant overpressure, though interestingly not when they are encountered in the same vertical well bore. Indeed, the Hauptdolomit is more typically overpressured where the Plattendolomit is absent. Pressures in the Hauptdolomit are generally lower than those seen in the Plattendolomit. Within the reservoir itself there is evidence for extremely low permeability cataclasitic and cemented fault damaged zones (enhanced cementation by quartz, anhydrite and dolomites). These zones are capable of sealing gas from water and isolating individual pressure compartments within the field. Analysis of current production data indicates that a number of wells see isolated volumes. Integrated matching of pressure data with the perched water model has given rise to a more accurate prediction of connected volumes.
Reservoir
Fig. 5. Stratigraphic column.
Depositional setting The Pickerill Field produces from the Rotliegend, Leman Sandstone Formation. The depositional setting of the Leman is well
PICKERILL FIELD
O
#
I
4
~
N H O
B
N
'
I
~
9
805
~
4
N
~
9
r
e
~
~
~
D
'
I
4 0 0
/ 0
/
/
/
/
"i 0i I
i~
/ / / . /
"-"
f ,/ I
/
3 ~
.~ "E
n I
8
/
/
/
/
E 0
I
/
/ / /
1
/
I / /
r.,.. i i',,-
V
I
/
/
0
/ ,{
/
t
/ / /
o
/
~/
,
E
1
J~
/
i
/
/
r,.,
/ /
::::I
,,~,,
/
O}
i1 'r,'
==1. m i
o
._o
..
n
0..
E o
j Q) r.
=
om
/
~
"0
I
5,,..
--"
o
I
Q} CD
o
= "-
I
I
~{:}I~l
/ o o ,.o
/ o
~Q =
"0
ggGA.L.
806
O.C.
ET AL.
WERNGREN
a z
_J M,I
ii,,,-
ul 0 n." w u. m z 0 rn rr"
m--
0 0!-~q
A
rn
,,,,t -I
I
n
m
l-
,i,,-,
._1 _.i
m
u.I N m
ID
m
0. Iff)
,D
>
,.-
O~
9
CD
J(J
9
0 0
..J ._1
O
fi) U.
O
r
n
~J
..a e,-
0
o m
"0
=~
0
I--if)
IJJ
...a
. 0~
m
r~
l--
.,-z 9
.~
I
I ~
.........i ..........
N
Z
r,.)
o
..~
PICKERILL FIELD
Fig. 9. Legend. documented as being a semi arid desert basin with sediment source areas to the south, (Glennie 1998). At Pickerill, the following zones are recognized: (1) Weissliegend waterlain sands; (2) a heterogeneous assemblage of aeolian and waterlain sands; (3) aeolian and sabkha deposits; (4) a thin prominent aeolian or waterlain interval; and (5) waterlain sands and conglomerates. Only zones 1-3 are present in west Pickerill, with the most productive intervals occurring in zones 1 and 2. These intervals have similar properties and deplete uniformly. In east and SE Pickerill all five zones normally occur, with significant gas production from zones 3 and 4 (Figs 8-10). The Rotliegend sandstones are feldspathic, lithic arenites, consisting of about 71% framework grains, 9% cements, 8% clays and 12% porosity. The cements are mainly dolomite, quartz and anhydrite, and the clays, illite, illite-smectite, chlorite and kaolinite. There are no major diagenetic differences between west and east Pickerill that can not be accounted for by the differing occurrence of sedimentary facies. There is also no consistent indication of increased diagenesis related to free water levels. However, it is noticeable that wells completed near the gas-water contact produce at much lower rates than those where the best reservoir sands lie more than 200 ft above the gas-water contact. The Weissliegend (zone 1) is most thickly developed in west Pickerill in a trend that runs from 4 8 / l i b - A 2 to 48/llb-A1Z. In several wells in this area, this zone provides a significant contribution to flow (48/lib-A4, 48/lib-A2). Thin grey shales are present at various levels within a number of wells in the Weissliegend and reflect its waterlain character (e.g. 48/11b-4 and 48/1 la-7(B1); Fig. 10). Reservoir properties are best towards its base where medium grained sands occur. Elsewhere in the field, the Weissliegend is generally 20-40 ft, fine grained, and increasingly cemented by dolomite towards its top.
807
Zone 2 in west Pickerill consists predominantly of medium grained aeolian sands which are the main producing horizons in this area. In the NW part of east Pickerill, fine grained aeolian dune deposits occur either as single slipfaces, or stacks of dune aprons and slipfaces (Fig. 10). Reservoir properties improve towards the base of this interval. Further to the SE, waterlain deposits dominate in wells 48/lla-B3, 48/lla-B3Z, 48/lla-B2 and 48/lla-B7, with significantly reduced permeabilities compared with the aeolian sands. Dune deposits are probably in the form of overlapping sets of trough cross bedding, several tens of metres wide, and extending for hundreds of metres downwind to the west and WNW. Waterlain bodies are probably several hundred metres wide and trend SSW-NNE towards the Sole Pit basin. Zone 3 is thin in west Pickerill and dominated by poor quality sabkha deposits resting unconformably on the Carboniferous. To the east, beyond the central N N W - S S E trending fault zone, the zone progressively thickens into a stack of medium grained aeolian sands underlain and separated by laterally extensive sabkhas. The uppermost sabkha forms a distinctive marker and is possibly correlative to one of the muddy sabkhas of the Silverpit Formation (Glennie 1998). The aeolian intervals are probably again trough cross bedded in overlapping sets several tens of metres wide, which extend downwind towards the west. These medium grained aeolian sands form the main reservoirs in east Pickerill. R F T data shows that the relatively tight interbedded sabkhas do not appear to represent significant barriers to vertical crossflow. Zone 4 is absent in west Pickerill, and is absent or not recognisable in a few wells in east Pickerill. The sands are aeolian or waterreworked aeolian ones. Forty percent or more of the gas produced by 48/11a-7 (B1) comes from this thin zone, and it was the most depleted in 48/lla-B7. Repeat PLTs in 48/11a-7 (B1) suggest it is draining gas from a wide area, and from the adjacent poorer quality sabkha and waterlain sediments. Zone 5 is absent in west Pickerill and thickens gently to the east. Tight conglomerates normally comprise 40-60% of this unit, interbedded with waterlain sands. The conglomerates reduce the average reservoir properties for this zone. In the SE of Pickerill, relatively high porosity waterlain and aeolian sands occur, with few conglomerates.
Source The source of hydrocarbons in the Southern Gas Basin is well documented as being derived from the Westphalian Coal Measures in the Sole Pit Trough (Cornford 1998). The Westphalian became mature for gas generation during the Jurassic burial of the Sole Pit, directly north of the field. Whilst any local traps would have been filled during the Jurassic and Cretaceous, the Pickerill structure only realized its current form after Tertiary inversion of the Sole Pit. This event caused remigration, which may in part account for the complex gas-water contact and pressure scenarios seen in the field today.
Development and production Whilst the development of the Pickeri11 Field via two unmanned platforms has been very successful, with hindsight, the placement of the initial high angle wells may not have been optimal. Ten years into production, it is evident that the development wells drain partially sealing compartments, in what are obviously isolated accumulations. With advances in drilling technology and our current understanding of the field, a programme of horizontal wells targeting specific reservoir zones and crossing barriers may ultimately have delivered larger reserves (Bokhari et al. 1997). The NE flank of the field remains undeveloped and this area is the focus of attention for future wells. However, structural elevation, fault compartmentalization and reservoir quality remain risky in a field that has been full of surprises!
808
O. C. WERNGREN E T AL.
Fig. 10. 48/11a-7 well summary of Rotliegendes, Leman Sandstone. A typical East Pickerill well.
The authors would like to acknowledge the current Partners in the field for their constructive support in the development of this complex field. It is recognised that the views expressed in this paper are those of the authors and not necessarily those of the Pickerill owners. Partners are Agip (U.K.) Ltd., ARCO British Limited, Britoil plc, EDC (Europe) Limited, Intrepid Energy North Sea Ltd, Mobil North Sea/Superior Oil (UK), Veba Oil & Gas UK Ltd.
Pickerill Field data summary Trap Type Depth to crest Gas-water contact
Fault dip closure 8100 ft TVDss 9095 ft TVDss west, 8938 ft TVDss east
PICKERILL FIELD Perched contacts Max Closure Pay zone Formation Age Gross thickness Net/gross Porosity Permeability
8674 & 8740 ft TVDss 995 ft
Leman Sandstone Permian 80-250 ft Average 0.9-1 Average 0.12 0.05-10mD (Range 0.01-550 roD)
Hydrocarbons Gas gravity Condensate yield Gas expansion factor
0.61 6.2 BBL/MMSCF 222 scf/rcf
Formation water Resistivity
0.051 ohms @ 60F
Reservoir initial conditions Pressure Temperature Hydrocarbon saturation
3995 Psia @ 8900 ft TVDss 204~ @ 8900 ft TVDss 60%
Field size Area Reserves GIIP
33 sq km (8150 acres) 500 BCF 900 BCF
Production Start-up date Development scheme Number/type of well Production rate Max production rate Cumulative production Secondary recovery
809
August 1992 2 unmanned platforms, high angle/multi-lateral wells 12 exploration 15 development 96 M M S C F D (Oct 98) 210 M M S C F D 339 BCF (Oct 98) None
References ARTHUR, T. J. 1993. Mesozoic structural evolution of the UK Southern North Sea: insights from analysis of fault systems. In: PARKER,J. R. (ed.) Petroleum Geology' of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1269-1279. BOKHARI, S. W., HATCH, A. C., KYEL, A. & WERNGREN, O. C. 1997. Improved recoveries in the Pickerill field from multilateral drilling into tight gas sands. SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 5-8 October, 1997, SPE 38629. CORNFORD, C. 1998. Source rocks and hydrocarbons of the North Sea. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea." Basic Concepts and Recent Advances, 4th ed. Blackwell Science, Oxford, 376 462. FENWICK, D. 1994. Pickerill Field: the evolution of a model for multiple water contacts. Proceedings LPS Seminar, 14 March, 1994, Burlington House, London. GLENN1E, K. W. 1998. Lower Permian-Rotliegend. In: GI~ENNIE, K. W. (ed.) Petroleum Geology o f the North Sea. basic concepts and recent advances, 4th ed. Blackwell Science, Oxford, 137-173.
The Schooner Field, Blocks 44/26a, 43]30a, UK North Sea A. M O S C A R I E L L O Shell U.K. Exploration and Production, Lothing Depot, Commercial Road, Lowestoft NR32 2TH, UK Present address: Shell International Exploration and Production, Volmerleen 8, 2280 AB Rijswijk, The Netherlands (e-mail: a.moscariello @shell. com)
Abstract" The Schooner Field is Shell U.K.'s first Carboniferous gas development in the North Sea. The field was discovered in 1987 by well 44/26-2 and gas production began in October 1996 from four wells. In contrast to the majority of the fields in the Southern North Sea producing from the aeolian Leman Sandstones Formation (Rotliegend), Schooner targets the low net-togross, fluvial Upper Carboniferous Barren Red Measures and Coal Measures formations. The reservoir consists of discrete, low sinuosity fluvio-deltaic channels draining a swampy coastal floodplain evolving upwards into a highly aggrading, low gradient, distal fluvial fan, dominated by braided and anastomosing channels. In Schooner, like other Carboniferous fields, reservoir connectivity is one of the key subsurface uncertainties due both to channel lateral discontinuity and fault compartmentalization. Production data and reservoir properties distribution, together with a new stratigraphical subdivision driven mostly by chemostratigraphic techniques, have been used to reassess the volume of gas-in-place which currently is estimated at 29.98 Gm 3 (1059 BCF).
Location Schooner is Shell UK's first Carboniferous gas reservoir to be developed and is located in the Silver Pit Basin approximately 150km off the South Yorkshire coast (Fig. 1) within Shell/Esso concession Block 44/26a (licence P516) and Eastern Energy/Cal Energy Block 43/30a (licence P689). Shell operates the field on behalf of fixed-equity partners (Shell 43.8%, ExxonMobil 46.55%, T X U Europe Upstream Ltd 4.83% and Cal Energy 4.82%, on November 2000). Licence expiry is 13 June 2021 for P516 and 2025 for P689, with Production Consent until 31 December 2014.
History
sented by the evaporitic lacustrine shale of the Silverpit Formation (Fig. 2), would provide an adequate top seal for gas accumulations within the underlying Carboniferous. Up to 1983, only three dry exploration wells had been drilled. Permian reservoir sands of the Leman Sandstone Formation were predicted to be absent over the area, although a thin basal Leman Sandstone was thought to be present to the south. Carboniferous fluvial and fluvio-deltaic sands formed the prime exploration targets in this region (Fig. 1) whilst structural closures at Triassic Bunter Sandstone level formed a secondary objective. These new concepts, combined with the de-regulation of gas prices in the UK, made the Silver Pit a prime area of industry interest in the 8th, and subsequent, licensing rounds.
Pre-discovery
Discovery
The Silver Pit Basin was largely neglected as an exploration area in the 1960s and 1970s due to the depth and the absence of thick aeolian reservoir facies of the Rotliegend Group, which forms the main gas reservoir in the areas to the south. By the late 1970s it was understood that the Rotliegend Group, which in this area is repre-
Block 44/26a was acquired by Shell/Esso to test a large structural high characterized by a faulted dip closure mapped from seismic at Top Carboniferous beneath the Permian Saalian Unconformity. The discovery well, 44/26-2, drilled in June 1986, found a total of 102 m (335 ft) of gas pay in the Upper Carboniferous Barren Red Measures (BRM) Group and 249 m (816 ft) in the Coal Measures (CM) Group. The well reached a total depth of 13590ft TVDss penetrating the gas-water contact at 13075ft TVDss. Reservoir pressure was measured at 6564psi. The B R M section flowed gas at a rate of 27.8 M M S C F / D at 3220 psi Flowing Tubing Head Pressure. Reserves estimated after the 44/26-2 well were 518BCF. Analysis of the test results showed fairly good well deliverability with good permeability (c. 100mD) for the channel sands and 0.05 mD for the thin, overbank sands. All the tested wells were partially perforated and showed good well productivities. The structure was subsequently appraised by well 44/26-3 in 1987 which tested 10.1 M M S C F / D . Well 44/26-4 in 1988, drilled 2 km to the north of the discovery well within the same structural closure (Fig. 3), was targetted at a deeper middle Coal Measures sand objective (the main reservoir in the Murdoch and Caister fields, 25 km further north) to fulfil the 16000 ft TVDss commitment. The primary objective was found to be tight and water-bearing.
Post-discovery
Fig. 1. Geographical location of the Schooner Field (Silver Pit Basin).
The Schooner Field was covered by a 300 km 2 3D seismic survey in 1988, which was processed during 1989. During 1994, the 3D data set was reprocessed and a reinterpretation and mapping project was conducted in early 1995 in support of the then imminent drilling of the first production wells. Although the reprocessing resulted in improvements, the conclusion was that the data set was inadequate for proper imaging of the subsurface. The data indicated a high
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 811-824.
811
812
A. MOSCARIELLO
(a)
Fig. 2. (a) Stratigraphy of the Silver Pit area over the Schooner Field and (b) summary of chronostratigraphy, depositional and tectonic setting of the Westphalian Barren Red Measures and Coal Measures (compiled from Besly 1990; Leeder & Hardman 1990).
degree of uncertainty associated with fault mapping in the Carboniferous level. This also highlighted the potential high risk of drilling through the Zechstein Group, which is populated with potentially over-pressured Haupt Anhydrite/Platten Dolomite rafts (Fig. 4). A seismic inversion study undertaken in late 1996 highlighted the difficulty in interpreting the intra-reservoir geometries caused by the complex overburden and the poor quality of the original data set. This new study could only provide information of rather limited confidence on reservoir facies distribution. The interbedded gas bearing sands are typically in the order of 30 ft thick and are thus beyond seismic resolution, particularly given the poor dataset. In early 1997 a total of 246 km 2 of new full fold 3D seismic was acquired and pre-stack depth migration was performed. The prestack depth migration (PreSDM) interpretation yielded a improved definition of the reservoir rock volume and fault geometry and distribution throughout the field (compare Fig. 3 with Fig. 5).
The first development drilling phase started in May 1995 from the normally unattended SA platform. The wells were designed with deviations within the reservoir of approximately 50 ~, in order to optimize net pay intersection. Completion strategy (e.g. inflow intervals, tubing size) is determined on the basis of gamma ray (i.e. sand prone intervals) and resistivity log data.
Discovery method Structure The Silver Pit Basin is a loosely defined area situated to the north of the main Rotliegend Group (Permian) gas fields of the late Cimmerian Inde Shelf and the late Cretaceous to Tertiary Sole Pit
SCHOONER FIELD
813
(b)
Fig. 2. (continued) Inversion Zone (Glennie & Boegner 1981; van Hoorn 1987; Corfield et al. 1996). The basin is separated from the offshore Durham Shelf and the Cleveland Basin Inversion Zone to the west by the Dowsing Fault Zone (Fig. 6). The Variscan Mid-North Sea High
Fig. 3. Structural map and cross-section of the Schooner Field reservoir based on 1988 3D seismic survey. GWC, gas-water contact.
defines the northern limit, while the Cimmerian Cleaver Bank High forms the southeastern limit. The Silver Pit Basin developed in an equatorial to subequatorial position north of the then active Devonian to Carboniferous Hercynian orogenic belt. The basin was strongly influenced by this orogen and its northward migration. The area suffered lithospheric extension in late Devonian to mid-Carboniferous times (Corfield et al. 1996). Active fault-bounded half-grabens and tilted fault blocks developed along a dominant N W - S E grain, succeeded in the Upper Carboniferous by a post-rift phase of regional sag, caused by thermal re-equilibration (Leeder & Hardman 1990). This resulted in the creation of two lowland areas separated by the N W - S E trending Murdoch fault system. The Schooner Field lies immediately south of this high (Fig. 6) Variscan tectonism deformed the Upper Carboniferous strata by both folding and faulting along a dominant N W - S E fault trend. Seismostratigraphic interpretation, along with well control, indicate that early-formed basement faults at least intermittently controlled the location of channel belts during the deposition of the Upper Carboniferous. Uplift and subsequent erosion associated with the Saalian Unconformity resulted in a pre-Permian subcrop ranging from Namurian in the west of the basin to Westphalian D (or younger?) Barren Red Measures in the east. However, the limited regional well data make it difficult to determine whether this was a distinct depocentre during Carboniferous times. Since at least the early Permian, the Silver Pit Basin has been a centre of regional subsidence. The effects of uplift associated with the early Cretaceous late Cimmerian tectonic phase were relatively minor in the basin with the result that a thick sequence of overlying Permian to Triassic sediments has been preserved in the area. Late Cimmerian erosion was limited to the removal of the Jurassic and part of the upper Triassic strata. Halokinesis was initiated by these late Cimmerian movements and continued into the early Tertiary. Late Cimmerian reactivation of the Variscan faults, together with Tertiary Alpine wrench movements along N W - S E trending basement fault zones, resulted in the formation of tilted fault blocks at Saalian Unconformity level. These are usually bounded by complex reverse faults and form the principal proven gas-bearing structures in the Silver Pit Basin. Tertiary Alpine tectonic activity has strongly deformed the post-Permian sequence into a series of anticlines and synclines with a dominant N W - S E grain, coincident with the major pre-Zechstein fault trend. Despite local halokinetic effects, the Silver Pit Basin continued to develop as an overall subsiding depocentre into which
814
A. MOSCARIELLO
~
iI iI
Fig. 4. Seismicand geological cross-section over the Schooner Field from the 1997 3D seismic survey. The rafts within the Zechstein Group often consist of over pressured Haupt Anhydrite/Platten Dolomite couplet which have been broken and displaced during tectonic-induced halokinesis. the Upper Cretaceous Chalk and Tertiary sequences thickened slightly. To the west of the basin, fission track analysis has indicated significant Tertiary uplift in two phases (Alberts & Underhill 1991). This has resulted in erosion of the whole Jurassic and most of the Lower Cretaceous sequence. Local structure. The Schooner Field is an elongate N W - S E trending anticlinal closure bounded to the SW by major NNW-SSE highangle transpressional oblique-slip faults (Fig. 6).
The structure is believed to be the result of tectonic inversion of Cimmerian and/or Tertiary age and formed by uplift along a major reverse fault trend that is probably of Hercynian origin. The closure is 16km (10miles) long by 4 k m (2.5miles) wide, with the crest slightly offset to the SW. Within the structural closure, the Carboniferous strata have been deformed into a broad SE plunging anticlinal swell. The main reservoir, the alluvial BRM, forms a southeasterly thickening wedge that is progressively truncated by erosion at the Saalian Unconformity towards the NE over the crest
SCHOONER FIELD
Fig. 5. Structural map of the Schooner Field based on pre-stack depth migration interpretation of the 1997 3D seismic survey. Note the more complex fault pattern compared with Figure 3. of the structure penetrated by the 44/26-4 well (Fig. 5). The main reservoir consists of the fluvial BRM, containing more than 98% of the reserves, with the remainder in the fluvio-deltaic CM. Top seal is provided by the thick Silverpit Formation evaporites and shales that overlie the Saalian Unconformity.
Stratigraphy The stratigraphical succession (Fig. 2) in the Schooner Field area can be summarized as follows:
Fig. 6. Tectonicsetting of the Silver Pit Basin indicating the Schooner Field location. Note the Dogger shelf in the NE that could represent the possible source area of the fluvial systemduring the Upper Carboniferous time period.
815
Carboniferous. The oldest sediments drilled in the Schooner Field belong to the Namurian age fluvio-deltaic Millstone Grit Group, as encountered in the 44/26-4 well (at least 324 ft). These are overlain by a 2900 ft thick fluvio-deltaic and fluvial Westphalian succession that can be subdivided into the CM and BRM. The transition from Westphalian A to late Westphalian B interval shows a gradual decrease in channel size and sand content (down to 5-10% net-togross) with a corresponding decline in reservoir potential. From the late Westphalian B onwards, a gradual increase in sand content is recorded into the Westphalian C which is represented here by Upper Coal Measures (21% net-to-gross) and lower Barren Red Measures Group (28-38% net-to-gross). On seismic sections, the transition from CM into BRM is usually characterized by the increased transparency of the seismic and disappearance of continuous clear seismic reflectors representing the coal bearing intervals in the CM. The main reservoir belongs to the Westphalian C intervals. Data collected by Shell/ExxonMobil during the last ten years suggest that the standard lithostratigraphic scheme (Cameron 1993) does not accurately reflect the relationship of units in the Upper Carboniferous in the Silverpit Basin. Sedimentological, chemostratigraphical, and biostratigraphical investigations indicate that a clear change in depositional environment and therefore reservoir characteristics exists between the formerly defined (Cameron 1993) 'Lower Schooner Formation' (i.e. Coal Measures) and the 'Lower and Upper Ketch Members' (i.e. lower and upper BRM). Moreover, there is evidence of an important erosional event (unconformity) at the base of the Barren Red Measures Group. The lower and upper BRM intervals contrast both in reservoir quality (good in the lower BRM, none in the upper BRM), and provenance. Heavy mineral analyses and zircon age dating (Morton et al. 2001) suggest that the north-northeastern provenance of the lower BRM interval strongly contrasts to the south-southeastern (Brittany?) source area of the upper BRM which can be related to the onshore Halesowen Formation (Westphalian D, English Midlands; Glover et al. 1996; Besly 1998). Palynological analysis in the Silverpit area (McLean 2000) also provide new evidence of a late Westphalian C age for the base of the BRM. Therefore, because of both the contrasting lithological, sedimentological and mineralogical characters between the lower and upper intervals within the BRM and the different depositional environment between the BRM and the underlaying CM, the new Shell's Southern North Sea stratigraphical nomenclature proposes to distinguish the Coal Measures Group from the Barren Red Measures Group. Within the BRM Group, the 'Lower and Upper Ketch Members' (Cameron 1993) are promoted to the Formation rank and named Ketch Formation and Boulton Formation, respectively. The former takes the name from the Ketch Field (wells 44/28-1 and 44/28-2) whereas the latter takes the name from the Boulton Field (well 44/21-3) where the fluvio-lacustrine facies of the upper BRM are well represented. The Coal Measures Group is in turn subdivided in three formations. These are, from bottom upwards: the Caister Formation (Westphalian A), the Westoe Formation (Westphalian B) and the Cleaver Formation (late Westphalian B-early and middle Westphalian C). The terms Schooner Formation, Middle Coal Measures and Lower Coal Measures are thus abandoned (Fig. 2B). The variable thickness of the Westphalian succession is primarily controlled by the Saalian Unconformity, which progressively erodes the Carboniferous succession towards the NE. In the Schooner Field, only the sand-rich Lower Ketch Formation is present. The Coal Measures Group (CM) is only fully penetrated by the 44/26-4 well where it has a thickness of 2900 ft. The measured BRM thickness ranges between 0 and 915 ft depending on the depth reached by the erosional Saalian Unconformity. Sand distribution within the Carboniferous varies vertically probably due to both tectonic and climatically driven basin evolution and subsequent change in sedimentation style (Besly 1987; Stone & Moscariello 1999). Permian. The lower Permian is represented by the Silverpit Formation (Rotliegend Group), which developed in a desert lake as interbedded evaporites and claystones.
816
A. MOSCARIELLO
This is overlain by the Zechstein Group, which in this area displays a variable thickness ranging between 3400 and 5650 ft forming a major elongate salt swell overlying the field. This group includes halites, anhydrite and carbonates. Extensive movement of the salt, coupled with faulting has contributed to the deformation and displacement within the salt of mid-Zechstein couplets of anhydrite and carbonates (i.e. Haupt Anhydrite and Platten Dolomite). These intervals, known as Zechstein 'rafts', form a high acoustic contrast within the salt attenuating and hence disturbing the seismic imaging of the underlying horizons. The rafts, being vertically displaced, are potentially over-pressured and represent a drilling hazard.
Triassic. At the base of the Triassic is the Bacton Group, which consists of about 1500 ft thick succession of reddish-brown floodplain and lacustrine mudstones and fluvial sandstone (Bunter Shale and Bunter Sandstone Formations). The Bacton Group is overlain by the Haisborough Group, represented by marine and subordinate lacustrine evaporites, mudstones and limestones. The Upper Triassic is absent having been eroded during the Lower Cretaceous uplift (Cimmerian Unconformity).
Jurassic.
The entire Jurassic succession is also missing from the
Schooner Field area having been eroded by the Lower Cretaceous age, Cimmerian Unconformity.
Cretaceous. The uppermost Lower Cretaceous is represented by the argillaceous Cromer Knoll Group, which is overlain by the Chalk Group (Upper Cretaceous) consisting of a thick sequence of recrystallized and chert-rich limestones, chalks and marls. This is locally affected by the Oligocene (Pyrenean) Unconformity.
Tertiary-Quaternary. The Tertiary is represented by the 225ft thick North Sea Group, which consists of marine and glacio-marine unconsolidated argillaceous sand, clay and silt.
Trap Trap type and seals As for many of the fields in the Silver Pit Basin, the Schooner Field trap is a complex elongate NW-SE-trending anticlinal closure, formed by a succession of movements (Cretaceous and Tertiary tectonic inversion) along Hercynian trends. Top seal at the Saalian Unconformity level is provided by the thick Silverpit Formation (Rotliegend Group) consisting of desert-lake shales and evaporites.
Faults The Schooner Field is characterized by two very distinct fault generations: (1)
(2)
A series of major NW-SE trending faults with considerable throw. Some of these only show displacement within the Carboniferous, whereas others clearly show displacement all the way up to the Zechstein evaporites, probably due to reactivation at a later stage. Of particular importance is the major NNW-SSE high-angle transpressional oblique-slip fault system, which delineates the northern flank of the steeply dipping block on the SE of the Schooner Field (Figs 5 & 6). A series of N E - S W trending steep faults, which only affect the Carboniferous section. As the BRM is seismically transparent, minor faults are not visible within this zone. However, numerous minor faults are visible in the underlying CM.
The 1997 3D seismic processing has resulted in a revised fault pattern (Fig. 5) where faults have been classified according to orientation, age and throw magnitude. Fault compartmentalization, related to subseismic faulting, is now thought to play a big role in explaining well decline and recovery factors that have not met expectations (see below). Analogue studies (Knipe 1999) suggest that various fault sealing mechanisms (i.e. juxtaposition, clay smear, cataclasis, development of phyllosilicate framework) are acting in this type of reservoir, and sealing potential during field production time is strongly controlled by the reactivation history of each fault. However, the featureless nature of the BRM and the low seismic resolution (25 m at best) make it difficult to directly image the reservoir sand/shale distribution and no direct imaging of lithofacies juxtaposition is possible.
Reservoir Coal Measures Group The Coal Measures Group represents 30% of bulk rock volume of the reservoir (2% of reserves), as only a short sequence of the Middle and Upper Coal Measures (Westphalian B-C) is present above the free water level (FWL) (Fig. 3). As a result of the thin isochore (maximum thickness measured above FWL is approximately 395 ft in 44/26-2 well), the CM has been modelled as a single lithostratigraphic unit (Fig. 7), although biostratigraphic markers (McLean 1995) can be used for further reservoir subdivision. The Middle Coal Measures is partly penetrated by all the wells in the NW part of the field where the BRM is thin or absent.
Sedimentary facies types. The penetrated Coal Measures are characterized by a laterally variable low net/gross ratio distribution ranging between 19 and 22%. The following sedimentary facies have been recognized: Composite low-sinuosity channel fills. These consist of 10-30 ft (3-9 m) thick vertical stacks of 5-15 ft (1.5-4.5 m) thick sand bodies. Typically, these show a vertical grain-size distribution ranging from medium to fine sand. Primary sedimentary structures consist of trough cross-bedded and ripple-laminated sandstones suggesting deposition in low-energy river channels characterized by periodic surges as indicated by the numerous reactivation surfaces. A low, blocky gamma ray (GR) response and clear density/neutron (FDC/CNL) log positive separation characterize this facies. Single low-to-high sinuosity channelfills. These consist of 5-10 ft (1.5-3 m) thick sand bodies formed by fining upward successions of trough cross-bedded and ripple laminated fine to medium sandstone, which are frequently capped by coals or coaly shales. This sediment association suggests deposition in a low energy fluvial environment developed on a very low gradient alluvial plain. Finegrained deposits associated with this sand bodies suggest deposition in calm environment probably as consequence of channel abandonment. The GR response is characterized by a smooth bell shape and again clear FDC/CNL positive separation. Proximal overbank, crevasse splay deposits. These are formed by 2-5 ft (0.6-1.5 m) thick, medium to fine-grained sandstone showing ripple lamination (e.g. climbing ripples) and shale drapes towards the top indicating sequences of rapid deposition followed by settling processes in a temporary flooded interfluvial plain. Bioturbation is common. In logs, this facies has an intermediate GR response and FDC/CNL positive separation. Floodplain deposits. These are represented by distal overbank and lacustrine massive, horizontally or ripple laminated carbonaceous grey and black shales, interbedded with very fine sandstones and siltstones and coal seams. Bioturbation, sideritic concretions and plant fragments are abundant. This facies usually exhibits a spiky, high GR response. Coal seams are typically characterized by a spiky, low FDC signature and FDC/CNL negative separation.
SCHOONER FIELD
817
Fig. 7. Well correlation based on gamma ray logs and chemostratigraphical analyses throughout the Schooner Field. Note the typical gamma ray log signature of low net-to-gross fluvial reservoir characterized by composite and single channels generally showing blocky and bell shapes respectively. FWL, free water level.
Intervals with highest GR signatures (>200 API), ranging from 3 to 40 ft thick, are interpreted as the results of deposition during marine transgression phases. Depositional setting. The depositional environment during the CM accumulation is interpreted to be a waterlogged lower coastal plain cross-cut by fluvio-deltaic meandering rivers (Besly et al. 1993). The area was permanently occupied by swamps and brackishto-freshwater lagoons in which fine-grained sediments and plant material (coal) accumulated. Periodically, marine incursion also occurred, leaving distinct basin-wide shale markers (marine bands). At the top of the succession, the channels have a more braided character (increase in average grain size) probably indicating a shift to a more proximal fluvial style, which is considered as a precursor of the BRM deposition. This would correspond to a rejuvenation of the sediment source areas probably caused by a tectonic uplift of the sediment provenance area (Besly et al. 1993).
Barren Red Measures
Most of the Schooner gas reserves (98%) are contained in the BRM (Lower Ketch Formation), which forms 70% of the gross rock reservoir volume. A reliable stratigraphical subdivision is essential for understanding and modelling facies distribution within this reservoir, and thus for predicting reservoir performance. Stratigraphical subdivision is, however, difficult in the BRM. Due to the intense oxidation of the sediments, traditional biostratigraphical techniques cannot be applied. Therefore, initial stratigraphical subdivision of the reservoir was based on the identification of key gamma ray signatures (corresponding to assumed 'flooding surfaces' related to t e m p o r a r y lacustrine expansions?) and thus peak correlation between wells was performed (Mijnssen 1997). This lithostratigraphical subdivision divided the reservoir into three units: (1) a 300-400 ft thick basal sand-rich unit (BRM A); (2) a middle shale-rich layer (BRM B), approximately 120ft thick; and (3) an upper sand-rich unit (BRM C), variable in thickness depending on
the level of erosion at the Saalian Unconformity (maximum measured thickness 275 ft). Within this lithostratigraphical framework, correlation of sand bodies based on G R responses was then performed between wells (with well spacing 800-2200 metres). The marked variations in channel distribution from the A and C units to the B unit were interpreted, using sequence stratigraphy criteria, as being the result of changes in relative base level (Mijnssen 1997). However, two years of production history did not match the predictions of the existing static and dynamic reservoir models (Stone & Moscariello 1999). Initial inflow rates (average of 45 MMSCF/D, range of 12-80 MMSCF/D) matched reasonably well with predicted rates (45-50 MMSCF/D), but total connected well reserves from early material balance data did not match model forecasts and well decline rates were also much larger than initially predicted. This suggested that the sands were less well connected than assumed in the original reservoir model. Recent analogue data from the Green River Formation of the Uinta Basin, Utah (Keighley et al. 1998, 1999) suggested that sand body width/thickness ratio and lateral connectivity was over estimated and that significant lateral variability in the net sand distribution could be expected over hundreds of metres. The original modelling assumptions were therefore revisited (Stone & Moscariello 1999). The previously assumed channel geometry parameters were revised to obtain a more realistic static model (e.g. the maximum channel width was changed from 4000 m to 1800 m). To re-evaluate the internal stratigraphical zonation of the BRM, a chemostratigraphical correlation technique was chosen to generate a robust stratigraphical framework (Pearce et al. 1999; Stone & Moscariello 1999). Vertical distribution of chemical elements and their relative abundance were analysed for trends and rapid shifts. Pattern matching between wells was used as the basis for correlation. A five-zone subdivision of the BRM (Fig. 7) was constructed based on correlatable geochemical signatures in eight wells. This subdivision has been interpreted as the response to climatically driven changes in weathering cycles in the catchment area and floodplain groundwater conditions. Petrographical data
818
A. MOSCARIELLO
lacustrine and swamp deposits
polygenic composite palaeosols (Pedofacies 2 to 4)
Fig. 8. Core photograph of a typical sedimentary interval in the Barren Red Measures. Massive and fining upwards fine grained sandstones are interbedded with fine-grained floodplain deposits showing palaesols with different degrees of maturity. did not show any considerable change in sediment provenance during the deposition of the BRM.
Sedimentary facies types. The BRM part of the Schooner reservoir is characterized by a low to moderate net/gross reservoir ratio (30% mode) and a high degree of internal, lateral and vertical
reservoir variability (Figs 8 & 9). Based on the classification initially proposed by Mijnssen (1997), the BRM facies can be described as follows: Composite low-sinuosity channel fill. This consist of 12-30ft (4.5-9m) thick vertical stacks of 2-Sft (0.6-2.5m) thick sand bodies characterized by several lithologies: poorly stratified, clastsupported, conglomerates consisting of poorly sorted, sub-angular, fine to medium pebbles and granules; trough cross-bedded sandstones and ripple-laminated medium to coarse sandstones. Often, numerous reactivation surfaces are present. Generally, no obvious grain-size trends are present within the channel fill although sand bodies are often capped by parallel laminated sands and silts (Fig. 9). The sediment composition and sedimentary features of these channel fills suggest deposition in a fluvial environment dominated by competent flows associated with high energy flood events. Massive conglomerate and coarse sand with trough cross-bedding at the base of the channel fill (Fig. 9) are interpreted as the result of migration of large scale bedforms developed in braided stream channel. A blocky G R response (Fig. 9) and a clear F D C / C N L positive separation characterize this facies. Single low-sinuosity channel fill. This genetic unit consists of 8-15 ft (2.5-5 m) thick medium to coarse sandstone packages characterized by trough cross-bedding and ripple-lamination. Usually, this facies shows a fining-upwards sequence resulting in a bell shaped GR response and clear F D C / C N L positive separation. Based on log properties both composite and single channel sediments have been assigned to type I or type II, the former having lower GR and higher log porosity signatures. Proximal overbank deposits crevasse splay deposits. These are formed by 4 - 8 f t (1.2-2.5 m) thick, medium to fine-grained sandstone. Similarly to the ones described for the Coal Measures interval, they are characterized by c. 1-3 ft (30-90 cm) thickfining upward sequences formed by homogeneous, structureless, medium sand at the base passing upwards to ripple lamination (e.g. climbing ripples) and shale drapes at the top. These sequences indicate successive events of rapid deposition followed by settling processes in a temporary flooded interfluvial plain. Bioturbation and root mottling characterize this unit. A spiky GR response (Fig. 9) and a vague F D C / C N L positive separation characterize these units. Floodplain deposits andpalaeosols. These consist of laminated or massive fine-grained sandstones and horizontally laminated mudstones (Figs 8 & 9) accumulated on a distal floodplain where temporary shallow lacustrine environments could develop. The thickest continuous succession of these sediments reaches 60ft
Fig. 9. Schematic facies assemblages characterising the Barren Red Measures reservoir.
SCHOONER FIELD (20 m). Pedogenetic features (i.e. rootlets, bioturbation, mottling, nodules) are very common (Besly & Turner 1983) indicating the presence of vegetation occupying the floodplain. Four types of pedofacies (Fig. 10) have been distinguished according to the degree of palaeosol maturity (Moscariello 2000; Moscariello et al. 2002). Vertical pedofacies distribution usually show 20-45ft (6-15m) thick regular cycles mostly consisting of overbank deposits showing an upward increase in degree of soil maturity. Each cycle usually starts with a channel fill or overbank deposits which do not display pedogenetic features. These typically directly overlay very mature palaeosols belonging to the previous cycle. The vertical repetition of these trends (Fig. 10) indicate a dynamic fluvial system characterized by periodic channel avulsion over the floodplain where intense pedogenetic processes could take place. Lateral distribution and vertical patterns of pedofacies types is used as an indicator of different styles of lateral and vertical aggradation rates. The vertical distribution of pedofacies is also consistent with the chemostratigraphical zonation supporting the use of this technique for reservoir subdivision (Stone & Moscariello 1999). High and spiky GR
response characterizes this genetic unit. Sonic shear-waves respond to the geomechanical properties of the fine-grained which have been pedogenically modified (i.e. peds structure, vertical fracture planes) and can thus be used (Moscariello 2000) to infer pedofacies vertical distribution (Fig. 10) and ultimately to reconstruct channel distribution within the reservoir. Depositional setting. The overall depositional setting of the BRM is interpreted to be fluvial, characterized by braided channels draining a low gradient alluvial plain probably developed in an endorheic basin. Within this system, major low-sinuosity channels developed. Minor single channels formed small subsidiaries flowing between the large channels. Proximal overbank deposits formed adjacent to the main channel areas during flooding events while in the large interfluves only fine-grained deposits were accumulated allowing the development of vegetated soils. Log correlation and isopach mapping indicate that the channels are predominately oriented NE to SW. Moreover, provenance studies using Sm-Nd isotope analyses indicate a source area dominated by Palaeozoic igneous rock
44/26-3
44/26 a -A 1z Core GR (API) Pedofacies 50 150 250 1 2 3 4
819
Thickness (ft) 0 10 20
GR (API) 50 .100
0 12800 -
12800
Core Pedofacies Thickness (ft) 12 3 4 0 10 20
5 12900
"
Reservoir architecture b a s e d on p e d o f a c i e s vertical and lateral distribution 44126-3
12900 "
44/26a-A1z ? ~ .........
5 13000
-
1310o
4
J
"1-
13100
~
- ----N nits !
4-5
4
13200
44/26a-A1z
44/26-3
r- 13300 a
!3._4~
,
--
"
'-3
A
.....
13500
~---"
Z
/ /
Pedofacies cyclo-stratigraphy
100
200
1350013800
13600I 13900 . . . . . . . . . . . . . . . . . . . . . . . . . . .
m palaeosol
D floodplain
Pedofacies Thickness (ft)
G R (API) 0
D channel
1 234
0
10
20
Pedofacies lateral distribution suggests an active avulsing fluvial system during deposition of Units 1-2 and 3. Channel are randomly distributed within floodplain deposits and potentially well connected. On the other hand, Unit 4 and 5 formed during a more stable system where entrenched channel belt developed.
L|
units
~IL,~I~L~
13700"~ 13800-
(
13900
Pedofacies vertical distribution is characterised by high to low aggradation cycles (from Pedofacies 1 to 4). These cycles are typically of a frequency of 4-6 per chemostratigraphic unit.The thickness of each pedofacies type varies vertically, generally showing thinning upwards successions whose base and top correspond to the boundaries of the chemostratigraphical units.
Fig. l& Example of lateral correlation and pedofacies distribution for two wells in the Schooner Field (Upper Ketch Formation, Westphalian C/D). Occurrence and thickness of four types of pedofacies recognized in core are plotted against gamma ray log.
820
A. MOSCARIELLO over time. These are: (1) climatically driven sediment supply to the alluvial plain; (2) climatically controlled fi'equency of catastrophic flood events, and in turn channel avulsion; and (3) the modifications in tectonic regime, which induced changes on alluvial plain evolution and channel distribution. During deposition of Units 1, 2 and 3 a strong and prolonged subsidence during the Late Carboniferous resulted in large amounts of accomodation space occupied by the fluvial plain aggradation. Fluctuation in base level resulted in an alternation of braided river systems formed during relative base level (lacustrine) low stands and meandering river systems, formed during high stands (Besly et al. 1993). During this period, the braided river system constantly avulsed and bifurcated, resulting in a wide range of channel sizes and distribution, the latter being controlled by autocyclic processes related to climate-driven discharge into the basin. During depositions of Units 4 and 5 however, the fluvial channels are temporarily confined in specific areas, forming stacked channel belts up to 6 - 1 0 m (20-30 ft) thick. This is likely to be associated with longer time scale, local (lacustrine ?) relative base level falls which induced minor, short lived incisions, which in turn favoured the formation of composite stacked channels. The changes in the fan topography and overall evolution of the sedimentary basin most likely resulted from a combination of climatic factors (e.g. progressive increase in aridity at the end of the Westphalian D (Besly 1987, 1990) and increase in tectonic activity (subsidence rate, tilting) related to the early Variscan orogenesis (Leeder & Hardman 1990).
Fig. 11. Sm-Nd isotope composition of Barren Red Measures sandstone indicating that a possible source rock could be represented by Palaeozoic igneous rock and Proterozoic gneiss similar in character to the basement of the Norwegian Domain. and with subsidiary Proterozoic gneiss similar in character to the basement of the Norwegian Domain (Fig. 11). This data suggests a source area located to the N - N E of the Silver Pit area, to the east of the Mid North Sea High where plutonic rocks occur (Dogger Shelf, Fig. 6). In detail, the data suggest that two main chemostratigraphical unit assemblages, developed under different sedimentary basinal settings, can be identified on the basis of similarities of net-to-gross, pedofacies, and reservoir properties (porosity, permeability) distribution (Stone & Moscariello 1999). The lower three chemostratigraphical units (1 to 3) can be distinguished from the upper two units (4 and 5) by different internal geometry. This geometry is believed to be directly controlled by the variation of several factors
P o r e types a n d diagenesis
The petrographical composition of the red beds forming the Schooner reservoir rock is the result of early diagenetic and burialrelated processes. Both oxidation and reduction processes acted throughout the early post-depositional and burial time inducing a complicated petrographical assemblage. Early diagenetic assemblages mainly consist of Fe-oxides, authigenic quartz, kaolinite, illite and pyrite. Siderite, heamatite and ankerite commonly form pore-filling cement (Besly et al. 1993). In the BRM sequence, petrographic analyses indicates that porosity is related to feldspar grain dissolution. Kaolinite and illite are associated with partially dissolved feldspars or oversized pores that represent the sites of former feldspar grains. Porous reservoir generation then post dates the development of reddening and is thought to have taken place during deep Mesozoic burial (Besly et al. 1993). Elevated temperatures and aggressive (low pH) formation waters suggested as
Fig. 12. Porosity-permeability crossplot showing the distribution between different facies. The plot shows both core and log-derived data.
821
SCHOONER FIELD Table 1. Reservoir property distribution for each BRM chemostratigraphic unit and CM Reservoir unit
Maximum porosity (%)
Mean porosity (%)
Maximum permeability (mD)
Mean permeability (mD)
Mean net-to-gross
BRM BRM BRM BRM BRM CM
17.8 16.4 18.4 17.9 18.9 20.1
10.8 9.3 12.6 8.27 11.6 6.2
1990 954 2100 520 1895 1000
116 70.8 172.1 90.1 193.4 33.4
0.30 0.28 0.35 0.33 0.38 0.21
5 4 3 2 t
being associated with maturation of organic matter, are the possible cause of this enhanced porosity generation (Cowan 1989).
Porosity and Permeability Reservoir quality in the sandstones of the CM and BRM is generally good to excellent, with an average porosity of 12% and a wide range of permeabilities from 10 to 2100mD. Core analysis indicates that in general the thicker sands, which have the most significant contribution to the total gas volumes, have good reservoir properties. Typically, channel fill facies have mean porosity ranging between 11 and 13% while proximal overbank facies have between 4 and 7%. Core permeability for channel fill ranges between 1 and 1000 mD (air permeability) with an average of about 10 mD. Core permeability are consistent with log-derived permeability calculated using multivariate functions using porosity, gamma ray, volume of shale and calibration to core permeability. Data from nuclear magnetic resonance (NMR) analyses are consistent with the computed permeabilities from logs. For proximal overbank deposits, mean permeability values measured in core and log are also comparable (average of 0.01 mD). Porosity and permeability distribution per facies are shown in Figure 12.
The data from each individual interval showed considerable variation in porosity and even more so in permeability. This is because, within the channel sand bodies, there are a variety of subfacies and grain sizes. Typically, the fine-grained upper parts of the sand body exhibit lower permeabilities than the coarse-grained intervals near the channel bases. The sandstones are, however, embedded in impermeable floodplain mudstones that comprise 65-70% of the stratigraphical section. Consequently, significant concern exists about sand body connectivity and the impact it will have on the recovery of gas. As porosity-permeability characteristics do not vary greatly from unit to unit (Table l), gas inflow performance is primarily controlled by the number of channel sands the wellbore penetrates, and the degree of lateral connectivity of these channels.
Pressure relationships Formation pressures obtained with repeated formation test (RFT) logging tools in the 44/26-2, 44/26-3 and 44/26-4 wells are plotted in Figure 13. All the Schooner Field wells are on the same water and gas line. Formation multi tester (FMT) pressures taken in the BRM sequence in the 44/26-2 well indicate a gas gradient of 0.12 psi/ft. The free water level (FWL) is estimated to be 13 075 ft TVDss (3985 m TVDss). This figure is also indicated by saturations from capillary pressure curves and from resistivity data. To date, despite the high probability of fault compartmentalization, as could suggest the rapid decline of a couple of wells, no indication for different FWLs over the field have been observed.
Source
Fig. 13. Pressure plot for the Schooner Field based on exploration wells 44/26-2, 44/26-3 and 44/26-4.
The source of the gas in the Schooner and Ketch fields are the Namurian and Westphalian coals. The source has two components, carbonaceous shales (c. 1% TOC) and coals (c. 60% TOC). The types of kerogen are II/III-III. The potential yield for the shale is 0.14 MCF/acre-ft and 7.0 MCF/acre-ft for the coal (Cornford 1986). Measured and estimated Vitrinite Reflectance maturities range between 0.8 and 1.1 (%Ro) at the level of the Saalian Unconformity, implying a very extensive gas kitchen at depth within the Carboniferous succession. The current burial depth, the gas kitchen and hydrocarbon charge should still be active, below depth of about 13 000 ft TVDss (3.5 km TVDss). Over much of the area, the presence of the Silverpit Formation and a thick Zechstein salt succession precludes hydrocarbon migration from the Coal Measures into the upper reservoirs such as the Triassic Bunter Sandstone. Migration paths are supplied by the sandstones within the Westphalian BRM and CM, which have extensive areas of contact with both the coals and carbonaceous shales. Source and reservoir sandstone thus lie at the same stratigraphical level. Migration timing coincided with the time of maximum depth of burial during the Jurassic and Cretaceous. The gas first migrated to the structurally higher flanks of the Sole Pit Basin. Later, during and after the structural inversion and formation of the trap in the Late Cretaceous, the gas re-migrated back into the field. The fact
822
A. MOSCARIELLO
Fig. 14. Graph summarising the variation over time of gas initially-in-place (GIIP) and reserve estimates. The most recent estimate was derived from the latest modelling exercise based on re-examination of geological, petrophysical and production data. UR, ultimate recovery; GRV, gross rock volume.
that the gas remained trapped until the present demonstrates the efficiency of the seal formed by the Silverpit Claystone.
Reserves and production Gas-in-place
more than 98% of the gas reserves in Schooner Field. The most likely recovery factor for the B R M is 63.5% while for the CM is only 8.7%. Based on these figures, dynamic reservoir simulation indicates that the overall Schooner Field recovery factor is approximately 58%. The expectation U R (wet) for the current 10 well penetration development concept is predicted to be approximately 17.34 Gm 3 (612 BCF).
The Schooner Field maximum gas column is 1275ft (388 m) with the crest at 11 800 ft TVDss (3596 m TVDss). The B R M contains 88% of the gas-in-place, with the remaining 12% being located in the CM. The Schooner Field expected gas initially-in-place (GIIP) is currently estimated at 29.98 Gm 3 (1059 BCF). Changes in estimated GIIP and ultimate recovery (UR) calculation over the time are summarized in Figure 14. Considerable variations in gross rock volume (GRV) and gas volume estimates resulted from the 1989 first 3D seismic interpretation. A further change in G R V resulted from the 1997 PreSDM interpretation, with an increase of about 35% since publication of the field development plan. The average expected condensate/gas ratio (CGR) over field life is 12 B B L / M M S C F and expectation natural gas liquid (NGL) recoverable is 1.5 M M B B L for the entire field. The reservoir fluid is a wet gas with no in-situ liquids at original conditions. The produced B R M gas stream composition is expected to have about 1.15 mole% of carbon dioxide, 4.18 mole% of nitrogen and C G R at Theddlethorpe (Fig. 1) process conditions of 14.6 STB/MMSCF. No data presently exists for the CM gas. The gas composition is illustrated in Table 2.
Table 2. Gas compositionfrom the Schooner Field Component
Recombined gas (Mol%)
Methane Ethane Propane Iso-butane N-butane Iso-pentane N-pentane Hexanes Heptanes plus Nitrogen Carbon Dioxide H20
83.72 6.24 1.89 0.35 0.41 0.15 0.14 0.33 0.48 4.51 1.16 0.62
Total
100.00
Recovery and connectivity factor Schooner
The recovery mechanism in the Schooner Field is natural depletion. The U R is dictated by two main parameters: (1) the sand volumes connected to the development wells, and (2) abandonment reservoir pressures. Major uncertainties in the geological model and, most importantly, reservoir connectivity make it difficult to provide accurate estimates of recovery factors. The reservoir abandonment pressures are dictated by the Transportation & Processing (T&P) agreement with the Caister-Murdoch System (CMS) owners. On the CMS route compression will be needed when tubing head pressure (THP) falls below 2000 psia. The abandonment T H P is estimated to be 300 psia. Static modelling, based on improved understanding of reservoir complexity and dynamic simulation matching of these models to early production data, resulted in a reassessment of the internal connectivity factor. This is defined as the ratio between the volume of sand connected to the wells and the total volume of net sand in the reservoir. The B R M are the main reservoirs accounting for
P/Z
v. F i e l d
Field
Cumulative
Production
7000
6ooo
.........
5000 N
4000
i
".-.-.A.r : -
3000
2000
i
i
. . . . . . . ~,E,.~. . . . .
1000 o 0
.....................tl
' .................................. ~...................... [.......
- - . ~ : .....
i
' . . . . . . . . . . .| . . . . . . . . . . i i~,
i J
, !
20
40
~" I - . .... ~' J - - ._~.
I ......................... ! ............. + , , I J
. . . . . . . . . . . . . . . . . . . .
60
Cumulative
80
100
Production
120
140
160
(BCF)
Fig. 15. P/Z v. cumulative production for the first Schooner development wells. P, reservoir pressure; Z, real gas factor, which varies between 0.95 and 1.2 depending on reservoir pressure.
SCHOONER FIELD Schooner Field Historical Gas Production to lstApril 1999
Schooner Field Historical Condensate Production to 1st April 1999 120
200 T
U
140
loo I1r
80
(,,9
60
1.2
0.7
z
m m
8o~
120
0.8 ~,
-i
loo o ~
160
1.4
~'
180 4`
6" r
823
8
~
0.6
1
0.5
~= t~ 60 9
~ 0.8
.~
~ 0.6
.>
e-
0.4 o U 0.3 ~_
40
-~
E
9-I U 20
0
0
1997
1998
1999
"~
O U
0.4 0.2 0.2
0.1 U
0
0
1 uue
1997
1998
Years
1999
Years
Fig. 16. Production history graph showing the decline curve which is typical of wells in this type of low net-to-gross, moderately to poorly connected reservoirs.
Production rate
in the CM and BRM also offer potentially high volumes of GIIP but with a low recovery factor. The use of new recovery technologies, such as multilateral wells and under balanced drilling, could unlock these resources.
Gas production began on 1st October 1996 from four wells. To date, seven development wells have been drilled into the Schooner Field reservoir. The first development phase was forecast to start at a peak plateau rate of 130 M M S C F / D from eight wells. However, the current average flow rate is 90 M M S C F / D from 7 wells. After the first three years of production, a marked pressure decline was observed that did not match expectations (Fig. 15). The initial productivity of the wells is some 20% lower than expected based on appraisal well tests and simulation. As a result of the current field performance, a reassessment of the reservoir model is in progress in order to include more realistic representation of the internal reservoir architecture (both structure and channel geometry) and rock properties.
The work described in this paper is based on a number of studies performed by employees of Shell U.K. Exploration and Production, Esso Exploration and Production UK Ltd and various contractors. I am particularly grateful to my colleagues M. Alberts, W. Epping, D. Grant, E. Legius, M. Klingbeil and I. Reid of the Silver Pit Subsurface Team, Southern Gas Supply Group, Lowestoft of Shell U.K. Exploration and Production for their helpful support during the collection of the data. Constructive comments by Bernard Besly, Duncan Mcgregor and Colin North, which improved the quality the manuscript, are gratefully acknowledged. Shell U.K. Exploration and Production, ExxonMobil International Ltd, Cal Energy and TXU Europe Upstream Ltd. are thanked for permission to publish this paper.
Cumulative production
Schooner Field data summary
To date, the Schooner Field has produced 3.9 G m 3 (137.77 BCF) that corresponds to 22% of its initial base case reserves of 17.34 G m 3. The field cumulative production data are summarized in Table 3 and Figure 16. The estimated life time production profile since the first development well was drilled in 1996, is shown in Figure 17.
Trap Type Depth to crest Lowest closing contour GWC OWC Gas column Oil column
Concluding remarks The effective development of the Schooner Field depends primarily on the proper understanding of the geological complexity of the low net-to-gross, BRM fluvial reservoir, which contains 98% of the reserves. A re-examination of geological, petrophysical and production data, integrated with the results from chemostratigraphical, sedimentological and analogue studies, led to the rebuilding of the reservoir model. The new model is felt to be more realistic and reliable for long term production forecasting. However, managing the subsurface uncertainties of reservoir connectivity and structural definition (sub-seismic compartmentalisation), and improving the recovery factor by identifying infill well locations, continue to be the major challenges in this type of reservoir, driving the uptake of new technologies. The lower net-to-gross and tighter reservoir intervals
Table 3. Cumulative production at December 1999
During 1999 Cumulative
0.74 1.59
41.7 137.77
Estimates of Wet Gas Reserves are updated with cumulative production.
Barren Red Measures and Coal Measures
S c h o o n e r Field - Lifetime Production Profile 140 120
t,,t)
o'~"o 100 > <~
o
80
60
~
4o
e-
20
c
N/ASS. Wet Gas (BSCF)
1275 ft
Pay z o n e Formation
<
NGL (MMBBL)
dip closure 11 800 ft 13 075 ft 13 075 ft
o O~ O~
O~ O~
0 0
LO 0 O C~
O0 CD 0 C~
vT0 C~
9~-
~
O
O Cq
O Cq
O Cq
Year
Fig. 17. Lifetime production profile of the Schooner Field.
824 Age Gross thickness (max) Net/gross (range) Porosity average (range) Permeability average (range) Gas saturation average (range) Productivity index Petroleum Oil density Oil type Gas gravity Viscosity Bubble point Dew point Gas-oil ratio Condensate yield Formation volume factor Gas expansion factor Formation water Salinity Resistivity Field characteristics Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially-in-place Gas initially-in-place (wet) Recovery factor Drive mechanism Recoverable oil Recoverable gas (dry) Recoverable NGL/condensate Production Start-up date Production rate plateau oil Production rate plateau gas Number/type of well
A. MOSCARIELLO Westphalian C/D 1275ft 20-38% 10-13 % 30 1000roD 70-85% 0.015 MMSCF/D psi
0.66 0.0277 cp 2930 psig 12 to 15 BBL/MMSCF 0.0036 286.53 SCF/RCF
93 700 NaC1 eq ppm 0.027 ohm m
13 590 acres 5 026 420 acre ft 6475 @ 12 800 ft TVDsspsi 0.11 @ 6475 psi psi/ft 230 + 15~ 1059 BCF 58% natural depletion 612 BCF 7.41 MMBBL
October 1st 1996 130 MCF/D 7 single deviated
References ALBERTa, M. A. & UNDERHILL, J. R. 1991. The effect of Tertiary structuration on Permian gas prospectivity, Cleaver Bank area, Southern North Sea, UK. In: SPENCER, A. M. (ed.) Generation Accumulation and Production of Europe's Hydrocarbons. European Association of Petroleum Geoscientists, Special Publications, 1, 161-173. BESLY, B. M. 1987. Sedimentological evidence for Carboniferous and early Permian palaeoclimates of Europe. Annales GOologiques du Nord., CVI, 131-143. BESLY, B. M. 1998. Carboniferous. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea." Basic Concepts and Recent Advances. Blackwell Science Ltd., Oxford, 104-136. BESLY, B. M. 1990. Carboniferous. In: GLENNIE, K. (ed.) Introduction to the Petroleum Geology' of the North Sea. Blackwell Science, Oxford, 4, 90-119. BESLY, B. M. & TURNER, P. 1983. Origin of red-beds in a moist tropical climate (Etruria Formation, Upper Carboniferous, UK) In: WILSON, R. C. L. (ed.) Residual Deposits. Geological Society, London, Special Publications, 11, 131-147. BESLY, B. M., BURLEY, S. D. & TURNER, P. 1993. The late Carboniferous 'Barren Red Bed' play of the Silver Pit Area, Southern North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe, Proceedings of the 4th Conference. Geological Society, London, 727-740 CAMERON, T. D. J. 1993. Carboniferous and Devonian of the Southern North Sea. In: KNOX, R. W. O'B. & CORDEY, W. G. (eds) Lithostratigraphic
Nomenclature of the U K North Sea. British Geological Survey, Nottingham. CORFIELD, S. M., GAWTHORPE, R. L., GAGE, M., FRASER, A. J. & BESLY, B. M. 1996. Inversion tectonics of the Variscan foreland of the British Isles. Journal of the Geological Society, London, 153, 17-32. CORNFORD, C. 1986. Source Rocks and Hydrocarbons of the North Sea. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 197-236. COWAN, G. 1989. Diagenesis of Upper Carboniferous sandstones: Southern North Sea Basin. In: WHATELY, M. K. G. & PICKERING, K. T. (eds) Deltas: Sites and Traps for Fossil Fuels. Geological Society, London, Special Publications, 41, 57-73. GLENNIE, K. W. & BOEGNER, P. L. E. 1981. Sole Pit Inversion tectonics. In: ILLING, I. P. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of N W Europe. Hayden and Son, London, 110-120. GLOVER, B. W., LENa, M. J. & CHISHOLM,J. I. 1996. A second major fluvial sourceland for the Silesian Pennine Basin of northern England. Journal of the Geological Society, London, 153, 901-906. HOORN, B. VAN 1987 Structural evolution, timing and tectonic style of the Sole Pit Inversion. Tectonophysics, 137, 239-284. KEIGHLEY, D., COLLINS, S., FLINT, S., HOWELL, J., ANDERSSON, D., MOSCARIELLO, A., STONE, G. & O'BEIRNE, A. 1998. Fluvial-channel sandstones in the Eocene Green River Formation (SW Uinta Basin, Utah, USA): geometries, succession and sequence stratigraphic interpretations for a closed, sediment starved, lacustrine basin. British Sedimentology Research Group, 37th Annual Meeting 19-23 December 1998, p. 32. KEIGHLEY, D., FLINT, S., HOWELL, J., MOSCARIELLO,A. & STONE, G. 1999. Application of outcrop analogue studies to predict fluvial sand body connectivity, Schooner and Ketch fields, Southern North Sea. Exploration and Production Newsletter, Special Issue: Geology. Shell International EP 99-7021, 33-28. KNIPE, R. J. 1999. Faulting and Fault Sealing in the Carboniferous of the Silver Pit Basin. Rock Deformation Research Group, University of Leeds. LEEDER, M. R. & HARDMAN, M. 1990. Carboniferous geology of the Southern North Sea Basin and controls on hydrocarbon prospectivity. In: HARDMAN, R. P.F & BROOKS, I. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 87-105. MCLEAN, D. 1995. A palynostratigraphic classification of the Westphalian of the Southern North Sea Carboniferous Basin. In: Stratigraphic advances in the offshore Devonian and Carboniferous rocks, UKCS and adjacent onshore areas. Abstracts, Geological Society, London, 19th January 1995, 20-21. MCLEAN, D. 2000. A palynostratigraphic review of Late Carboniferous sections from wells in the Ketch Field, Southern North Sea. Report for Shell, U.K. Exploration and Production, Lowestoft. MIJNSSEN, F. C. J. 1997. Modelling of sand body connectivity in the Schooner Field. In: ZIEGLER, K., TURNER P. & DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea. Geological Society, London, Special Publications, 123, 169-180. MORTON, A., CLOUE-LONG, J. C. & HALLSWORTH, C. R. 2001. Zircon age and heavy mineral constraints on provenance of North Sea Carboniferous sandstones. Marine and Petroleum Geology, 18, 319-337. MOSCARIELLO, A. 2000. Pedofacies in reservoir modelling of low net-togross, barren fluvial sequences (Schooner Formation, Carboniferous SNS). Proceedings of 62nd EAGE Conference and Technical Exhibition 29 May-2 June 2000 Glasgow, X-10, 4 pp. MOSCARIELLO, A., BESLY, B. M. & MARRIOTT, S. 2002. Reservoir characterisation in low net:gross fluvial red-bed reservoirs, Ketch Formation, Schoone and Ketch Fields, UKSNS. In: Hydrocarbon resources of the Carboniferous, Southern North Sea and surrounding onshore areas. Abstract, Yorkshire Geological Society, University of Sheffield, 13-15th September 2002, 25-26. PEARCE, T. J., BESLY, B. M., WRAY, D. S. & WRIGHT, D. K. 1999. Chemostratigraphy: a method to improve interwell correlation in barren sequences - a case study using onshore Duckmantian/Stephanian sequences (West Midlands, UK). Sedimentary Geology, 124, 197-220. STONE, G. & MOSCARIELLO, A. 1999 Integrated modelling of the Southern North Sea Carboniferous Barren Red Measures using production data, geochemistry and pedofacies cyclicity. Offshore Europe 99, 7-10 September 1999, Aberdeen, Scotland, aPE 56898, 8pp.
The Sean North, Sean South and Sean East Fields, Block 49]25a, UK North Sea A. P. H I L L I E R
Shell UK Exploration and Production, Lothing Depot, North Quay, Lowestoft, Suffolk NR32 2TH, UK
Abstract: Sean North, Sean South and Sean East are small prolific gas fields located on the Indefatigable Shelf in the Southern North Sea. They, like most of the other fields in the area, have a Carboniferous source, a Rotliegend aeolian sandstone reservoir and a Zechstein evaporite cap rock. Sean North and South have been developed to fulfil a peak-shaving role, being produced for only a few days per year in times of high gas demand when they can produce at rates of up to 600 MMSCF/D. East Sean is sold to the direct market. Reserves for the fields are 234 BCF (North), 488 BCF (South) and 127 BCF (East).
This paper is an update of the paper by Hobson & Hillier in the 1991 Geological Society Memoir No. 14 and repeats much of the information given there on Sean North and South and adds data on Sean East (Hobson & Hillier 1991).
Location The three Sean Gas fields North, South and East lie in Block 49/25a about 15 km SE of the Indefatigable Gas Field. They are situated some 100 km N E of the coast of Norfolk in a water depth of 100ft (Fig. 1). The name SEAN is made up from the initial letters of the four partners involved when the discovery wells were drilled: Shell, Esso, Allied Chemical and National Coal Board (ten Have & Hillier 1986). In many respects the Sean Fields are small versions of the Indefatigable Field (Pearson et al. 1991). The reservoir rock is the Permian Rotliegend sandstone, capped by the Zechstein carbonates and evaporites, at about 8400 ft TVDss. The gas-bearing areas are fault and dip-closed, Sean North being some 4 km long by 2 km wide, Sean South is about 8 km long and 3 km wide, and East Sean is 7 km long and 1 km wide.
History The licence, of which Block 49/25a is a part, was awarded in the second round of licensing in 1965 to Allied Chemical and the National Coal Board. Shell and Esso farmed into this by drilling the early wells, and became equal partners with the other two companies. Subsequently, Allied Chemical (Great Britain) Ltd. changed its name to Union Texas Petroleum Ltd., which then sold out to ARCO, the National Coal Board's holding became part of BNOC (later being acquired by Britoil), and now Britoil has been absorbed by BP who have also taken over ARCO. BP is thus the major shareholder with 50%, Shell and Esso having 25% each. Shell is the operator. Well 49/25-1 discovered Sean North in 1969, well 49/25-2 found Sean South in 1970 and Sean East was discovered by well 49/25a-5 in 1983. The discovery wells were sited on seismic time highs. An appraisal well 49/25a-4, was drilled in Sean North in 1982, and an Annex B was submitted to the U K Department of Energy in March 1984 for Sean North and Sean South. One twelve slot wellhead platform (RD) was installed on Sean North and a similar twelve slot wellhead platform (PD) on Sean South. A process platform (PP) was also installed linked to the Sean South well-head platform by a bridge. Five development wells were drilled from each platform
53~
"
N
$3~' 10
"
N
53"0
52~
"
N
"
N
Fig. 1. Location map of Sean Fields relative to Indefatigable and Bacton. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 825-833.
825
826
A.P. HILLIER
during 1985, and the fields were bought on-stream in the 1986-87 contract year. An appraisal well for East Sean 49/25a-6 was drilled in 1986 and found the reservoir water bearing in a position apparently up-dip of the discovery well. Later mapping showed a sealing fault separating the two wells. Wells 49/25a-8 drilled to the SW of the field in 1988 found a few feet of gas sand at the top of the Rotliegend reservoir. Development of East Sean took place in 1994 with two long reach wells being drilled, one from each of the wellhead platforms. The well locations are shown in Figure 2. Gas from the RD platform is evacuated to the PP platform by a 4.7 km long, 20" stainless steel pipeline. The combined gas streams are dehydrated on PP before export to Bacton through a 107km long, 30" pipeline.
and affect pre-Cretaceous formations. Overburden loading during Cretaceous time caused halokinesis in the Zechstein evaporites, generating further faults in the overburden. The major N W - S E faults bounding the Sean area belong to the Viking-Indefatigable system to the SW and to the SE Indefatigable system to the NE. The faults are high angle and sometimes overturned to reverse at Rotliegend level. These major faults extend up to the Zechstein and overlying strata where the sense of throw varies both vertically and laterally, demonstrating the effects of both strike-slip movement and salt flow along the fault planes. Figure 4 shows a seismic section across the fields demonstrating this. Sections from Dutch Block K-l 3 published by Roos & Smits (1983) and from the U K well 49/23-4 published by Glennie (1984) also show this feature.
Structure Field stratigraphy The structure of the fields has been defined from seismic and well data. A 3D seismic survey was shot in 1992-1993 as part of the Greater Inde 3D seismic survey. This was interpreted in 1995. A pre-stack depth migration was carried out in 1997 over Sean South to confirm the extension along the western boundary fault, this data also covered North Sean but excluded East Sean. The following horizons were interpreted on the seismic data: Top Chalk, Base Chalk, Top Triassic, Top Zechstein, Top Haupt Anhydrite, Top Basal Anhydrite, and Top Rotliegend. Representative seismic sections are shown in Figure 3 and structural cross-sections along the same lines can be seen in Figure 4. The structure map enclosed (Fig. 5) is based on the interpretation of the PSDM data for North and South Sean and the time migrated data for East Sean. Three main phases of tectonic activity have affected the SE Indefatigable area in which the fields lie. Hercynian movements gave a dominant N W - S E grain to the pre-Permian formations. In the late Kimmerian phases, Hercynian faults were reactivated
The field stratigraphy, shown in Figure 6 is similar to that of Indefatigable Field. Carboniferous purple to red-brown shales and siltstones with coals and sandstones, of deltaic origin, occur unconformably beneath the Rotliegend, and constitute the oldest rocks penetrated. The Permian Rotliegend Group consists mainly of aeolian sand dunes, with minor amounts of water-laid sediments, and varies in thickness from 200 ft to 265 ft. The Upper Permian Zechstein Evaporite sequence is up to 1300 ft thick. The first three cycles are similar to those seen elsewhere in the Southern North Sea, however, Cycle IV is replaced by a condensed sequence ofinterbedded claystones and minor halites. Triassic sedimentation is marked by the appearance of the Brockelschiefer Member of the Bunter Shale formation of the Bacton Group, a red-brown slightly anhydritic siltstone, mottled with green. This is overlain by the Main Bunter Shale Member of redbrown claystones and capped by the Rogenstein Member with its characteristic ferruginous oolites.
Fig. 2. Sean Fields outline map showing well positions and section lines.
Fig. 3. Representative seismic sections Sean Fields.
828
A.P. HILLIER
Fig. 4. Structural cross-sections along the seismic lines in Figure 3.
Following the late Kimmerian tectonic activity the Jurassic was completely removed by erosion, which also removed the Bunter Sandstone and cut into the underlying Bunter Shale, leaving only 50-300 ft of Triassic sediments. The Lower Cretaceous Cromer Knoll Formation lies unconformably upon the Triassic, It is a grey calcereous clay, with traces of calcereous siltstone, up to 800 ft thick. The succeeding Upper Cretaceous Chalk is 3500-4000 ft thick. Unconformably above the Cretaceous are some 2000 ft of Tertiary and Quaternary deposits, dominated by marine clays, with some sands.
Trap Sean North is a fault, dip-closed anticlinal structure oriented N N W - S S E with the east and south boundaries being faulted, the
west boundary being part fault and part dip-closed, and the northern boundary being dip-closed. Sean South is similarly fault and dip-closed with the east, south and west boundaries being faulted and the north being dip-closed. The western boundary, formed by a major fault, comes up through the overburden and has a 'tongue' of reservoir extending some 5-6 km pulled up along it. Sean East is a simpler structure being fault-closed to the east and dip-closed to the west. Faulting within the fields is limited to a few normal faults with throws of 30-100 ft. The reservoir behaviour of Sean North is that of a simple tank with the well pressure depleting with production. Both Sean South and East Sean deplete on production but the pressures build back up partially when production stops suggesting partial communication between the wells and the rest of the field. Wireline log and pressure data from the wells in the North and South fields show that they initially had the same gas-water contact
SEAN NORTH, SEAN SOUTH AND SEAN EAST FIELDS
829
"10"
1',4
Fig. 5. Sean Fields Top Reservoir structure map basd on 3D seismic. at 8543 ft TVDss and a similar reservoir pressure, with Sean North being some 40 psi lower than Sean South, which is thought to have been depleted through the aquifer from the Indefatigable Field. The reservoir pressure of South Sean is now some 3-400 psi higher than North Sean. The East Sean Field has a shallower contact at 8390 ft TVDss.
Reservoir The reservoir rock of all three fields is Leman Sandstone of the Permian Rotliegend Group. It was deposited under continental desert conditions. The facies recognized are aeolian, wadi, sabkha, and lacustrine, as described by Glennie (1984). The aeolian facies in the form of transverse dunes is dominant in the Sean area. These dunes are perpendicular to the palaeo-wind direction, which was generally from the E-NE. There are cross-bedded, foreset dunes and finely laminated horizontal bottom-sets. Usually thin wadisabkha sediments occur at the base of the sequence, while in the upper part of the sequence interdune sabkha, wadi or lacustrine deposits may be found. These intercalations are usually thin and not laterally extensive. In wells 49/25-1 (Sean North) and 49/25-2 (Sean South), according to data presented by ten Have & Hillier
(1986), the breakdown is approximately, in aggregate, 60% dune, 19% dune-base, and 21% wadi-sabkha for the former well, and 64% dune, 28% dune-base and 8% wadi-sabkha for the latter well. In general, the dune sand units are the thickest. Logs from the three field discovery wells are shown in Figure 7. The reservoir properties are markedly different for the dune, dune-base and wadi-sabkha deposits. The cross-bedded dune sands are fine to medium-grained, clean and well sorted. Locally calcite cementation impairs the reservoir properties. Porosity averages are 21%, and the permeability 650 mD. The entry pressure is very low, and the capillary pressure curve has a long plateau. At 50% wetting-phase saturation the pore throat size is about 11 gm. T h e dune-base sands (bottom-sets) are commonly less well sorted than the dune sands, with a wider grain-size range. Average porosity is 17% and average permeability 166mD. The capillary pressure curve has a short plateau, and the pore throat size at 50% wetting-phase saturation is 2 gm. Nevertheless, the dune-base sands are good reservoir rocks, although calcite cementation is common, reducing the reservoir quality. The wadi and sabkha deposits average 1 1 % porosity and 5 mD permeability. They are poorly sorted and often argillaceous. The capillary pressure curves show a relatively high entry pressure,
830
A.P. HILLIER
GROUP
FORMATION
MEMBER D
",;~"
NORTH SEA
-:--.. --r"
-S
I.I II II I-T-S
CHALK
CROMER KNOLL ~ t"%.1
BUNTER SHALE
BACTON
ZECHSTEIN IV ZECHSTEIN III
ZECHSTEIN
ZECHSTEIN II
ZECHSTEIN I KUPFERs
Fig. 6. Schematic stratigraphic column for Sean Fields. -S, seismically mapped horizon.
ROTLIEGEND
LEMAN SANDSTONE
BUNTER CLAYSTONE BROCKELSCHIEFER ALLER HALITE LEINE HALITE HAUPT ANHYDRITE PLATTEN DOLOMITE STASSFURT HALITE BASAL ANHYDRIT E HAUPT DOLOMITE
-S ~
-
S r ~ ~" " L I
WERRA ANHYDRITE
AA^
I zECHsTEINKALK
~
f
'
S
lii!i!i!i!i
COAL MEASURES
lack a plateau, and have a pore throat diameter of 0.3 lam at 50% wetting-phase saturation. The poor quality sections of reservoir rock (wadi, sabkha and lacustrine deposits), which are found at various levels in the Rotliegend, are thin and not considered to be field-wide permeability barriers. The entire Rotliegend is defined as net sand in all of the production wells, except two in Sean South, in which a thin lacustrine shale interval about 10 ft thick is excluded. Sand production was feared, and selective perforation and preconditioning of the wells was undertaken to prevent excessive sand production. A SANDTEC monitoring system has been installed to detect sand production early, but to date there has been no evidence of excessive sand production.
histories for the Sole Pit Trough, which suggest that gas generation would have taken place during the Jurassic and the Cretaceous. Data published by van Wijhe et al. (1980) indicate that the centre of the Broad Fourteens Basin would have had a main gas generation phase from about mid-Jurassic to mid-Cretaceous. According to Oele et al. (1981) Late Cretaceous inversion raised that sector of the basin out of the depth range needed for gas formation, and shifted the depo-centre to the NE. This event, followed by subsequent sedimentation, led to gas generation taking place beyond that time, in association with a change in the pattern of migration. The very substantial reduction in pressure caused by the uplift during inversion would have released some absorbed gas from coals and dissolved gas from formation water.
Source Reserves The source rock of the gas, the composition of which is given in Table 1, is believed to be the coal-bearing sequence of the Westphalian in the Sole Pit Trough to the west and/or the Broad Fourteens Basin to the east. In the Viking Indefatigable area vitrinite reflectance data show the coals to be immature. However, Cornford (1984) has reported vitrinite reflectance values of > 2 % Ro in both the Sole Pit Trough and in the Broad Fourteens Basin. Glennie & Boegner (1981) generated burial curves based on data derived from sonic logs (Hobson 1960; Marie 1975), other well information and erosion
The initial reserves estimates for the North and South fields based on 2D seismic maps were similar with around 250 BCF gas-inplace. However, with the 3D seismic data being available the long western extension of the South Sean Field was recognized and a considerably larger GIIP was calculated for Sean South. Material balance calculations for the Sean North reservoir agreed with the expectation volumetric value for gas initially-inplace (GIIP). However in Sean South, the volumetric material balance GIIP is higher than the expectation volumetric GIIP, but
SEAN NORTH, SEAN SOUTH AND SEAN EAST FIELDS
Fig. 7. North, South and East Sean Fields discovery well logs.
831
832
A . P . HILLIER Table 1. Gas Composition. Component
Methane Ethane Propane Iso-butane N-butane Iso-pentane ,N-pentane H e~,gnes He~tanes plus Helium Nitrogen Carbon Dioxide Mol. Weight
Reservoir Fluid ( mol % ) Sean East Well 49/25a-5
North Sean Well 49/25a-1
South Sean Well 49/25a- P3 (P01)
90.93 2.982 0.709 0.161 0.189 0.0498 0.0523 0.0646 0.33
92.05 2.94 0.64 0.12 0.13 0.04 0.03 0.03 0.14
91.06 ~ 0.58 0.11 0.13 0.05 0.04 0.06 0.19
3.55 0.978
0.04 3.07 0.76
3.19 1.21
17.58
17.845
17.9
within the calculated uncertainty range. The drive m e c h a n i s m for South Sean includes some water a n d gas, partially shielded by faulting within the reservoir, influx. Sean N o r t h and South n o w have a total ultimate recovery of 722 B C F wet gas, with Sean South being roughly twice the size of Sean N o r t h . East Sean well p e r f o r m a n c e shows some baffling of gas flow to the wells, the volumetric G I I P is used for reserves calculation leading to an ultimate recovery of 127 BCF. The recovery m e c h a n i s m for Sean N o r t h and East appears to be volumetric depletion. In Sean South, the g a s - w a t e r contact is seen to rise in two wells where T D T logs have been run. Plots of P/Z against cumulative p r o d u c t i o n indicate rapid pressure recovery during the s u m m e r shut-in due to water influx and repressurization from the shielded GIIP. The recovery factor for Sean N o r t h is 90%, but Sean South is 80% taking into a c c o u n t expected watering out
of some wells. East Sean has a recovery factor of 89% assuming future compression. The N o r t h a n d South fields are being used as a 'seasonal' or 'peak-shaving' source of gas supply, capable of producing up to 600 M M S C F / D . East Sean gas is sold to the direct market. Compression is expected to be needed at some time in the future for all three fields. Timing for the N o r t h and South Fields in particular is d e p e n d a n t on future offtake levels This is a minor rewrite to include the East Sean Field by one of the authors of the paper in Memoir 14, from which much of the text has been copied. Shell UK Exploration and Production, Esso Exploration and Production UK Ltd, ARCO and BP/Amoco the joint licensees of the field permitted publication of this paper. As in the original paper, the author relied on the work of the many Shell staff who had worked on the field in the past whose contribution is greatly appreciated.
The Sean Fields data summary
North
South
East
Trap Type Depth to crest Lowest closing contour Free water level Gas column
Dip/fault 8280 ft 8550 ft 8543 ft 263 ft
Dip/fault 7800 ft 8550 ft 8543 ft 743 ft
Dip/fault 7960 8400 ft 8390 ft 430 ft
Pay zone Formation Age Gross thickness Net/gross ratio Net sand cut-off Porosity Gas saturation Matrix permeability
Leman Sst. Permian 200-260 ft 95.4% 4% 17.5% 73.5% 130-400 mD
Leman Sst. Permian 240-270 ft 99.9% 4% 17.1% 77.6% 190-420mD
Leman Sst. Permian 300-330 ft 100% 4% 17.0% 75.0% 30-150mD
Hydrocarbons Gas gravity Gas type Condensate yield
0.618 sweet dry 1.74
0.614 sweet dry 1.92
0.617 sweet dry 1.56
Formation water Salinity Resistivity
225 000 ppm 0.017 ohmm
225 000 ppm 0.017 ohmm
225 000 ppm 0.017 ohmm
SEAN NORTH, SEAN SOUTH AND SEAN EAST FIELDS
833
Reservoir conditions Temperature Pressure Pressure gradient
202~ 3945 psia 0.068 psi/ft
192~ 3977 psia 0.068 psi/ft
207~ 3872 psia 0.068 psi/ft
Field size Area Gas expansion factor Gas initially-in-place Drive mechanism Recovery factor Recoverable reserves
1230 acres 218 260 BCF depletion 90% 234 BCF
2420 acres 225 610 BCF depletion/water 80% 488 BCF
1020 acres 220 143 BCF depletion 89% 127 BCF
Production First gas Development scheme
Aug 1986 peak shaving
Aug 1986 peak shaving
Nov 1994 open market
References CORNFORD, C. 1984. Source Rocks and Hydrocarbons in the North Sea. In: GLENNIE, K. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford, 171-204. GLENNIE, K. W. 1984. Early Permian Rotliegend. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, Oxford. GLENNIE, K. W. & BOEGNER, P. L. E. 1981. Sole Pit Inversion Tectonics. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe. Heyden and Son Ltd., London, 110-120. HO~SON, G. D. 1960. Estimation of Relative Maximum Depths of Burial. Journal of the Institute of Petroleum, 46, 89-90. HOBSON, G. D. & HILLIER A. P. 1991. Sean North and South Fields, Block 49/25a, UK North Sea In: UK North Sea. In ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields 25 Years Commemorative Volume. Geological Society, London, Memoirs, 14, 485-490. MARIE, J. P. P. 1975. Rotliegendes Stratigraphy and Diagenesis. In: WOODLAND, A. W. (ed.) Continental Shelf of Northwest Europe, Vol. 1, Geology. Applied Science Publishers Ltd., London, 205-214.
OELE, J. A., HOL, A. C. P. J. • TIEMENS, J. 1981. Some Rotliegend gas fields in K and L Blocks, Netherlands Offshore (1968 1978) - a case history. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe. Heyden and Son Ltd., London, 289-300. PEARSON, J. F. S., YOUNGS, R. A. & SMITH, A. 1991. The Indefatigable Field, Blocks 49/18, 49/19, 49/23,49/24, UK North Sea, In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields 25: Years Commemorative Volume. Geological Society, London, Memoirs, 14, 443-450. Roos, B. M. & SMITS, B. J. 1983. Rotliegend and main Buntsandstein gas fields in Block K/13 - a case history. Geologie en Mijnbouw, 62, 75-82. TEN HAVE, A. & HILLIER, A. P. 1986. Reservoir Geology of the Sean North and South Gas Fields, UK Southern North Sea. In: BROOKS, J., GOFF, J. & VAN HOORN, B. (eds) Habitat ~?f Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23, 267-273. VANWIJHE, D. H., LUTZ, M. r KAASCH1ETER,J. P. H. 1980. The Rotliegend in the Netherlands and its gas Accumulations. Geologie en Mijnbouw, 59, 3-24.
The Trent Gas Field, Block 43/24a, UK North Sea PETER
T. O ' M A R A 1, M A R I L Y N
MERRYWEATHER
2, M A R K
STOCKWELL
3 & MIKE
M. BOWLER 4
A R C O British Ltd, London Square, Cross Lanes, Guildford, Surrey GU1 1UE, UK 1 Present address." Ruhrgas UK Exploration and Production Ltd, New Zealand House, 8th Floor, 80 Haymarket, London SW1 Y 4TE, UK (e-mail."
[email protected]) 2 Present address." Tullow Oil UK Ltd, 5th Floor, 30 Old Burlington Street, London W15 3AR, UK 3 Present address." CalEnergy Gas (UK) Limited, 60 Grays Inn Road, London W C 1 X 8LT, UK 4 BP Exploration Co. Ltd, Chertsey Road, Sunbury on Thames, Middlesex TW16 7LN
Abstract: The Trent gas field lies within the UKCS Southern Gas Basin (Block 43/24a) located 120 km off the Yorkshire coast in average water depths of 160 ft. The accumulation is contained within a NW-SE trending Base Permian closure, which straddles blocks 43/24, 43/23 and 43/25. The Carboniferous subcrop beneath the Base Permian unconformity varies in age from Westphalian A in the east to Namurian in the west. Although the Base Permian closure covers an area of 75 knfl the producible reserves are only located in the central core area of 43/24a. The main reservoir horizon is the Trent Sandstone of Marsdenian age, equivalent to the Chatsworth Grit Sandstone, UK onshore. Additional reservoir zones are within the lowermost Westphalian A. The field has been developed through the application of fracture stimulation of deviated wells.
Westphalian A sandstones of the Caister Coal F o r m a t i o n (Table 1). In 1990, A R C O drilled well 43/24-1 (Fig. 3), which encountered a gasbearing Carboniferous section over 1080 ft thick with a gross reservoir interval of 120 ft. This well tested 34 M M S C F G D from the upper Marsdenian Trent Sandstone, of the Millstone Grit Formation. Well 43/24-2 was drilled in early 1992, 3.5 k m to the SE of 43/24-1, along the crest of the structure and encountered water-bearing Trent Sandstone but a highly permeable Westphalian A distributary channel sandstone in the gas leg. The well tested at 29 M M S C F G D . In mid-1992, the C h e v r o n Block 43/23 group drilled well 43/23-2 at the northwestern end of the structural closure. The well
History Block 43/24 was awarded in 1989, as part of the l l t h R o u n d of Licensing. The Trent Gas Field is located in the N o r t h e r n part of the block (Fig. 1). M a n d a t o r y 50% relinquishment of the southern half of the block was m a d e in July 1997. The current licensees in Block 43/24a are: A R C O British Limited (Operator) 61.25%; Talisman Energy (UK) Limited 20.0%; and Atlantic Richfield Oil & Gas (St James') Limited 18.75%. The Base Permian structure (Fig. 2) was first tested in 1985 by the British Gas well 43/25-1, which flowed at <1 M M S C F G D from
/ /
/ ~ ' r O N
/
"4L. m4.1Nll~
,
,b
i
I
I
i ENGLAND
Fig. 1. Location Map of Trent Gas Field, showing transport route to the Amoco Bacton terminal via the Eagles (ETS) pipeline.
i
0 I
I
I
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 835-849.
835
836
P . T . O'MARA E T A L .
Fig. 2. 43/24-1 well log.
encountered a tight gas-bearing Trent Sandstone section, which failed to flow at measurable rates on test. Early in 1993, well 43/243 was drilled 4 k m to the SE of 43/24-2 and encountered several gas-bearing horizons within the Millstone Grit (Trent Sandstone) and Caister Coal Formations, testing 33 and 1 9 M M S C F G D , respectively. Well 43/24-4, was drilled from the 43/24-1 location in late 1993 into the western flank of the 43/24 structure. It failed to encounter any reservoir quality sandstones within the upper Marsdenian section. In this well an interval of lower Marsdenian age was found to be gas-bearing, but the well was suspended untested. The crosssection along the strike of the Base Permian closure (Fig. 4)
illustrates the position of the exploration/appraisal wells and the distribution of the major stratigraphical units below the Base Permian unconformity. In 1995, Annexe B approval was granted to develop the Trent Field and between June 1995 and October 1996 four development wells were drilled from a platform positioned at the 43/24-1 location. The first development well, 43/24-P1, was a 1.2 km step out to the south of 43/24-1. The well encountered a thick, down-faulted middle to late Westphalian A section (Caister Coal Formation) devoid of reservoir quality sandstones. This was a section not previously encountered on the block. The well was plugged and abandoned in August 1995.
T R E N T GAS FIELD
837
,.s=
-d .2
..o
9
3
9
9
9
9 . ,..., +.,,a
o . ,,...~ c)
E
o
838
P . T . O'MARA E T AL.
Table 1. A summary of Trent Field well results from exploration and development drilling
Well
Year
Test Interval
Flow rate (MMSCFGD)
43/25-1 43/24-1
1985 1990
0.5 35
43/24-2 43/23-2
1992 1992
43/24-3
1993
43/24-4 43/24-P 1 43/24-P2
1993 1995 1995
Westphalian A Distributary Channel Upper and Lower Trent Sandstone combined Westphalian A Distributary Channel Upper and Lower Trent Sandstone combined Westphalian A Distributary Channel Upper and Lower Trent Sandstone combined Untested Untested Lower Trent Sandstone Upper Trent Sandstone
29 0.5 19 31
0.5 33
Note: 43/24-P3 and 43/24-P4z are not included because they are twins of 43/24-2 and 43/24-1, respectively. The second development well 43/24-P2, a 1.4 km step out to the W N W of 43/24-1, encountered a reservoir section of reduced thickness and quality. It tested at 33 M M S C F G D from the Trent Sandstone in October 1995. In light of the results from these first two development wells, the forward drilling programme was modified and the total number of wells reduced from five to four. The 43/24-P3 well twinned the 43/24-2 well at bottom hole location. The development plan had included re-use of the 43/24-1 well but mechanical problems meant that a sidetrack, 43/24-P4z, was required.
Geophysics In 1993, a 320 km 2 proprietary 3D seismic survey was acquired and processed to provide coverage over the entire Base Permian closure,
which extends over blocks 43/23, 43/24 and 43/25. In 1994, the whole seismic volume was post-stack depth migrated to increase seismic resolution and improve fault definition in the pre-Zechstein. Overall the quality of the 3D seismic data is good, which allowed an unambiguous interpretation of the eight overburden horizons mapped down to the Top Rotliegendes. However, data quality in the Carboniferous is variable. Consequently, interpretation of intra-Carboniferous seismic events such as the relatively low amplitude event corresponding to the Top Trent Sandstone and fault delineation, are both problematic (Fig. 5). Where this event is constrained by well control there is a high level of confidence in the interpretation but this is reduced in undrilled fault compartments. Depth structure maps were generated using a vertical layer cake time to depth conversion method with layers defined by the eight interpreted overburden horizons. For the majority of the layers the velocities were calculated using best fit relationships between interval velocity and mid-point depth from surrounding well data. The exceptions to this were the Lower Triassic and the Zechstein layers where a thickness v. two way travel time function was used. Depth conversion sensitivities were performed but showed the Base Permian closure to be a robust structural feature, the size and relief of which did not change significantly when different depth conversion functions were applied. A similar trending but smaller structural closure is mapped at Top Trent Sandstone level (Fig. 6).
Structure Tectonic history
During the late Carboniferous the Southern N o r t h Sea occupied part of an intracratonic foreland area to the north of the Hercynian orogenic front. The main compressional Hercynian structural styles include broad open folds and minor wrench related normal and reverse faults (Hollywood & Whorlow 1993). The faults have two trends; a predominant W N W direction and a NE trend. Within the Trent area these structural trends are clearly evident together with
Fig. 4. Geoseismic cross-section along strike of the trent Field through the exploration amd appraisal wells. Note that the Trent Sandstone lies abiove the GWC only in the vicinity of the 43/23-2 and 43/24-1 wells and is absent i 43/24-4. Zone 2 corresponds to the Westphalian A distributary channel sandstone
T R E N T GAS F I E L D
43/24-P1
43/24-1
Fig. 5. Seismic traverse across the Trent Field structure orientated in a southwest-northeast direction. Position of the line is shown on Figure 6.
Fig. 6. Top Trent Sandstone depth map. Exploration, delineation and development wells are shown at top reservoir location. Contours are in feet.
839
840
P.T. O'MARA E T AL.
E - W orientated normal faults. Reactivation of these faults has occurred during the Triassic, Mesozoic and Tertiary, and often masks the original extent of Hercynian movement. In the late Carboniferous the basin was subjected to Hercynian compression, resulting in basin inversion and erosion, creating a pronounced regional unconformity at the base of the Permian. At least 3000 ft of Upper Carboniferous section was eroded from the Trent area at this time. As a consequence of regional extension within the Hercynian foreland, a new basin developed during the Permian. Within this basin, initial early Permian sediments consist of 1200ft of reddish lacustrine shales and minor interbedded halite (Silverpit Formation, Rotliegendes Group). The late Permian (Zechstein Group) in the Trent area consists of four evaporite-carbonate cycles (ZI to ZIV). The original depositional thickness is unknown but the present day thickness of the interval is highly variable due to halokinesis. In the Trent Field area the Zechstein thickness varies from 800 ft on the crest of the structure up to 3500ft on the northern and southern flanks as demonstrated on the seismic line (Fig. 5). Extensional tectonics in a continental setting throughout the Triassic influenced sedimentation and generated graben areas in which up to 4400ft of Triassic sandstones, shales and halites accumulated. Zechstein halokinesis commenced late in the Triassic and was probably triggered by early fault movements, as demonstrated by the formation of pillow structures in response to sediment loading (Cameron et al. 1992). The Lower Jurassic is represented by 1700ft of Liassic sediments, which conformably overlie the Triassic across Trent. Middle and Upper Jurassic sediments were stripped off at the Base Cretaceous unconformity. Subsidence resumed in the early Cretaceous with the deposition of 100 ft of a condensed mudstone dominated facies, represented by the Cromer Knoll Group, which onlaps the Base Cretaceous unconformity surface. A major global rise in sea level in the late Cretaceous (Haq et al. 1987) led to drowning of the sediment source areas and permitted widespread deposition of the Chalk Group that exceeds 1700 ft in thickness in the Trent Field area. Seismic interpretation suggests that halokinesis was accelerated during Cenomanian times. Many fault movements were reversed within the pre-Zechstein section, due to regional compression of the Hercynian basement by early Alpine orogenic activity. Early Tertiary sedimentation documents a change from the Cretaceous carbonate-dominated sediments to predominantly clastic deposition, which continued into the Miocene. Late Alpine movements in the Oligo-Miocene resulted in the final phase of basin inversion and renewed halokinesis. In Block 43/24, these movements culminated in continued reversal of faults in the preZechstein section. The mid-Tertiary unconformity marks the cessation of these movements and the resumption of subsidence with associated clastic sedimentation. Up to 900ft of Tertiary claystone is present in the Trent wells.
Stratigraphy The field stratigraphy of the Trent area is typical of Quadrant 43 and 44 of the Southern Gas Basin (Fig. 7). The nomenclature used here is from Cameron (1993). A detailed discussion of the Carboniferous stratigraphy is given in O'Mara et al. (1999). In summary, the main producing zones are the upper and lower units of the Trent Sandstone, which is of Marsdenian age within the Carboniferous Millstone Grit Formation. Macrofaunal evidence indicates that the Trent Sandstone is equivalent to the Chatsworth Grit onshore in the UK. Other completed reservoir zones are of basal Westphalian A age.
Trap The regional top seal for the Trent Field gas accumulation are the lacustrine shales of the Silverpit Formation (Fig. 7). These sediments also include discrete basal halite beds (halites A-E) which contribute to the top seal. The Trent Field gas accumulation relies on a large elongate Base Permian closure some 20 km in length, with a closing contour which coincides with the observed G W C in the wells at 11 780 ft TVDss. This closure trends W N W across the northern part of 43/24a, extending westwards into 43/23a and eastwards into 43/25a (Fig. 3). Maximum relief on the Base Permian structure approaches 1200ft and occurs in the area of well 43/24-1. The age of the Carboniferous subcrop beneath the Base Permian unconformity is variable as demonstrated by the strike geoseismic cross-section (Fig. 4) and this factor is key in defining the area of core reserves within the overall Base Permian unconformity closure. The core reserves (Fig. 4) for the Trent Field are located in the vicinity of the 43/24-1 well where the primary reservoir Trent Sandstone is present above the GWC controlled by the Base Permian unconformity closure. Also included in the core reserves area is the 43/24-2 fault block where the Westphalian A distributary channel sandstones are preserved below the Base Permian unconformity but lie above the GWC (Fig. 4). At Top Trent Sandstone a smaller 10 km elongate W N W trending closure is mapped with a closing contour down to the GWC 11 780ft TVDss (Fig. 6). The field is divided into separate compartments by WSW trending, mainly normal faults. The Trent Sandstone seismic reflector is truncated by the Base Permian unconformity to the west of the 43/23-2 well. Although a Trent Sandstone reflector is interpreted at the 43/24-4 location and a sequence of that age was penetrated by the well, the absence of reservoir quality sandstones suggests the presence of an interfluve or channel bypass area (O'Mara et al. 1999) influencing sandstone distribution.
Reservoir Local structure
The Trent Field is located on a positive inversion structure in the pre-Zechstein section. The Base Permian closure is controlled by a series of en-echelon W N W trending faults. Reverse movement on these faults occurred in response to compression during the Alpine orogeny and is responsible for producing the positive inversion feature. W i t h i n t h e Trent structure antithetic faults to the main W N W trend are observed plus a second WSW trend that exhibits generally normal movement. In early interpretations of the Trent structure, the Rotliegendes faulting was linked directly to the faulting at the Base Permian and intra-Carboniferous levels. However ,on the 3D seismic data (Fig. 5) it is apparent that some of these Top Rotliegendes faults do not extend down to the Base Permian or into the Carboniferous but sole out within the basal Permian halites just above the Base Permian unconformity.
The Millstone Grit Formation depositional sequence is dominated by an initial basin and delta slope infill of the pre-existing Dinantian basin-and-block topography. This was followed by repetitive progradation of fluvio-deltaic systems derived from the north and NE and prograding to the south and SW. The upper part of the Millstone Grit is typified by delta top sediments and the lower part of the Caister Coal Formation by lower delta plain sediments. A detailed chronostratigraphic correlation framework constructed from the integration of comparative marine band stratigraphy, lithostratigraphy, sequence stratigraphy and palynostratigraphy is used along with core and log data from Trent and key offset wells to define three key reservoir facies: incised valley fill, distributary channels, and transgressive reworked sandstones (Fig. 8). Marine band stratigraphy has proved to be the key in well correlation over the Trent Field and is supported by macrofaunal evidence in wells 43/24-2, 43/24-3, 43/24-4, 43/24-P1 and 43/24-P2. The Trent Sandstone is effectively bracketed by the occurrence of the Cancelloceras
TRENT GAS FIELD
CHRONOSTR- LITNOLOGY ATIGRAPHY
841
LITHOSTRATIGRAPHY KEY FORMATIONS
PLAYS SEISMIC REFLECTORS
GROUP
O
>R-
~ S ~
O
TOP CHALK
I I I ] I u}
[
O ILl
r
J I J I I I
C~K
I I I I I I I [ I [
BASE RED CI-IALK
a0o.-,
lOP I"R[rON
-ms
HAISBOROUGH
'+'++
-'
@'
, .... . . . .
". ".
".
TOP ROT HALITE
ROT HALITE MEMBER
.~-~ @
SANDSTONE -
. 9 - , ' ~ 9 -. -.
MEMBER
BACTON _ q
TOP ZECHSTEIN PLA'I'I'EN DOLOMITE
++_~
ZECHISTEIM TOP Ro'IrUEGENDES
SILVERPrF
ROTUEGENDES
BASE PERMIAN ~ : r ~ -~ r'.
i
CAISTER COAL
" " -
CONYBEARE
t=::, :-~.~: ~. ~. ~.~- MU.SrO.EG,rr
w.n'E.URSr
Z
Fig. 7. Generalised Trent stratigraphy showing seismic reflectors, key lithostratigraphic and chronostratigraphic units. It also shows the positions of the source, reservoir and seal units.
~
Shale
~
Sandstone
cancellatum marine band above and the Bilingites superbilingue marine band below. It is the occurrence of these two marine bands that suggests that onshore equivalent to both the lower and upper Trent Sandstone is the Chatsworth Grit (Fig. 9). A more detailed discussion of intra-Carboniferous reservoir correlation, Trent Sandstone depositional model, and reservoir characterization is given in O'Mara et al. (1999).
~--~
TOP CARBONIFEROUS
*i
Dolomite
i
BB
Coal
Hamite/Anhydrite
~
Limestone
Petrography The Trent Sandstone is dominated petrographically by monocrystalline quartz (62-78%) with a minor component of polycrystalline quartz (15-20%), which probably originated from igneous and high grade metamorphic rocks, and lower grade metamorphic rocks, respectively.
842
P.T. O'MARA E T A L.
Fig. 8. Well correlation of the Trent Field area showing the lateral continuity of the reservoir units and major marine bands. The section has been flattened on the Cancelloceras cancellatum marine band.
A minor but important constituent is feldspar and predominantly the more stable plagioclase feldspar. It accounts for up to 6% of the rock volume. Potassium feldspar is rare. Primary feldspar content within the Trent Sandstone was higher than it is now, as is commonly thought to be the case in equivalent aged onshore UK sandstones. The majority of the feldspar has been altered in situ to authigenic clay (Fig. 10) or removed, but with some evidence of remnant grains. The degree to which this has taken place is related to the depositional environment and is probably the single most important factor in controlling reservoir properties. In the upper leaf of the Trent Sandstone, marine reworking has removed much of the feldspar and resulted in enhanced maturity and better reservoir quality in this facies (Fig. 11). Westphalian A distributary channel sandstones are petrographically immature, containing a higher detrital clay component
than the Trent Sandstone and consequently have poorer reservoir properties. Mica, almost entirely represented by muscovite, is a common mineral in these lower energy distributary channel sandstones but is noticeably absent in marine reworked facies (Fig 12). When present, it is often partially altered to authigenic clays such as chlorite. Other minor components include heavy minerals and rock fragments.
Diagenesis
The diagenetic sequence observed in Trent Field sandstones is a multi-stage process, which is related to the complex tectonic history (Fig. 13). The majority of cements were deposited over several phases, and precise timing is difficult to discern.
TRENT GAS FIELD
843
Fig. 9. Detailed zonation scheme for the Trent Field area showing the positions of the major reservoir units and marine bands. The most important cements in controlling reservoir quality are authigenic clays. Kaolinite is the predominant authigenic clay and may form up to 20% of the rock volume. This clay is derived from potassium enriched fluids after dissolution of pre-existing K-feldspar grains and occurs as pore-filling booklets. Limited kaolinite pseudo-morphs occur in coarser units and suggest that dissolution of feldspar and re-deposition close by, is more likely than the direct replacement of grains in most facies. The reservoir quality of the coarser-grained facies may be preferentially enhanced by the dissolution of larger feldspar grains, which contribute to the secondary porosity network seen in most of the reservoir quality
sandstones. Conversely, reservoir quality in finer-grained facies has been degraded by kaolinite booklet growth, attributed to a low capacity for pore fluid movement. The remainder of the clay fraction is illite, which is interpreted to have formed after the in situ degradation of muscovite mica, commonly seen within the onshore Namurian sands, although noticeably absent from marine reworked facies. Illite may also form as a late burial fibrous cement that utilizes kaolinite as a substrate around pore margins and forming in alkaline conditions and at high temperatures (Cowan 1989). The presence of such late stage fibrous illite growths has a local detrimental effect on porosity and
844
P . T . O'MARA ET AL.
Fig. 10. Photomicrograph of the Lower Trent Sandstone (IVF) from 43/24-P2 well core at ! 1418 ft TVDss. A moderately sorted medium-grained sublitharenite. Quartz overgrowths (Q) and Kaolinite (K) are both common cement phases. Intergranular porosity is rare but that shown (arrowed) is bridged by strands of illite (I). Also present is minor ferroan dolomite (FD blue stain) overgrowing ferruginous dolomite (D) cement. Porosity is mainly inter-crystalline contained within kaolinite aggregates. Porosity 9%, permeability 0.46 roD.
Fig. 11. Photomicrograph of the Upper Trent Sandstone (TRS) from 43/24-P2 well core at 11330ft TVDss. This is a well-sorted medium-grained quartz arenite. Quartz overgrowths (Q) form localized grain interlocking cement. Intergranular porosity is > 12% and includes a high proportion of secondary pores (2). Porosity 14.5%, permeability 912 mD.
T R E N T GAS FIELD
845
Wii:l,i.: 43/24-2
CORE I)EPT!t: 11719.1 fl
Fig. 12. Photomicrograph of Westphalian A distributary channel sandstone (DC) from the 43/24-2 well core at 11 599 ft TVDss. Moderately sorted, medium-grained quartz arenite with very little feldspar or mica. High visible porosity. Authigenic quartz is the most abundant cement phase with minor siderite and dolomite pore-filling cement. Porosity 12.9%, permeability 205 mD.
Diagenetic Mineral
Kaolinite lllite Quartz No MetreGic
Siderite Haematite
Pyrite Dolomite
MeteGic ,~ater infiltration
::
::
:
M a i n pha~-~ of s e c o n d a r y Dissolution of i e r ~ c ~ Dolor~te a n d m i n o r fetdspar ~ s o l u t i o n : ......... ......................... ;~ 9
:
Calcite Anhydrite / barite Fig. 13. Diagenetic history of a typical Trent Field sandstone.
] ]:
~.:}
i
!
", @~
si
846
P. T. O'MARA ET AL.
permeability. Illite forms from solution in favour of kaolinite but requires a suitable substrate, such as kaolinite booklets and hence its distribution is linked to that of kaolinite. Where kaolinite is post dated by carbonate cements, illite growth is inhibited by a lack of substrates. Quartz is the most common cement comprising an average of 28% of the authigenic component and is the most persistent authigenic phase (Figs 10 & 11). It forms syntaxial overgrowths, the result of multi-stage dissolution and cementation. The main stage is related to early decarboxylation of organic matter, which provided the acidic pore fluids responsible for quartz dissolution, cementation and overgrowth development. The controls on quartz cements are complex, although the more quartzose facies are prone to increased quartz precipitation, a reflection of the increase in quartz grain to grain contacts. The sandstone includes minor pyrite, siderite and carbonate, which are thought to be early near surface phases of cementation and related to pre-Permian burial. Siderite is a product of strongly reducing anoxic conditions. It may be subsequently altered to haematite by meteoric groundwater influx associated with the Variscan uplift. Crushing of labile micas and early quartz cementation would also have occurred at this time. Dolomite cement is locally more abundant than quartz in finergrained sandstones, such as the Westphalian A distributary channels. It is predominantly ferroan dolomite and occurs in the form of rhombic crystals, often in-filling secondary pores, although it may occur with poikilotropic siderite (Fig. 12). The main phase of dolomite precipitation occurred after the main phase of quartz cement and kaolinite growth. Iron-rich pore fluids, expelled from maturing mudrocks, are postulated as the source. In coarser-grained facies the passage of later acidic pore fluids may have dissolved dolomite cements and developed significant levels of secondary porosity. Such events may be linked with the generation of hydrocarbons and attainment of maximum depth of burial during the Cretaceous and continuing into the Tertiary. Relatively minor late stage cements are present in the form of quartz cements, which may enclose pyrobitumen barite cements.
Controls on reservoir quality The fact that most Carboniferous sandstones in the Trent Field are relatively feldspar free is no reflection of their primary depositional composition. The long and complex effects of diagenesis have converted the majority of unstable components into authigenic clays, such as kaolinite and illite. The proportion of K-feldspar would have constituted a significant component of the less mature facies. Reservoir quality ranges from very poor to excellent. It is controlled by pore type, which is in turn influenced by grain size and sediment maturity (both textural and mineralogical) and strongly related to depositional environment. Depositional environment is the most important factor in controlling reservoir quality. The hydraulic energy levels associated with respective environments have been key in determining the texture of the reservoir facies. Facies with coarse and mediumgrained sandstones deposited in incised valleys, marginal marine environments and distributary channels contain the majority of the reservoir quality sandstones. In these facies the variation in reservoir quality arises from the degree of sediment maturity, where the more texturally mature sandstones (that consequently are more mineralogically mature), provide the best reservoir. Unstable minerals, such as detrital clays and feldspar were removed during transportation. Immature sandstones, characteristic of low energy environments, are prone to adverse diagenetic effects such as the development of authigenic clays. The presence of late stage fibrous illite growth has a localized detrimental effect on porosity and permeability, which may to some extent be independent of depositional facies. Illite growth is controlled by the same factors controlling kaolinte distribution but it is inhibited by the presence of late carbonate cement growth.
Reservoir and porosity types Three key reservoir facies are identified and their distribution in the wells is shown in Figure 8. The depositional environments of these facies are illustrated in Figure 14.
Incised valley fills (IVF).
The Lower Trent Sandstone comprises a 50 to 100ft thick multistorey, pebbly, coarse to fine-grained sandstone. It is a fluvial deposit that back-filled an incised valley; the product of high energy, braided channel systems, forming a series of stacked and erosive barforms aligned sub-parallel to the prevailing palaeocurrent (NE-SW). Shale content is low and interbar connectivity appears to be excellent. Reservoir quality is poor to moderate with permeabilities from 0.05 to 19mD and is influenced by grain size and kaolinite content. These sands display good intercrystalline/intergranular pore spaces due to coarser grain size and wider pore throats. Unfortunately, this is mitigated by the presence of abundant kaolinite reflecting the high proportion of depositional feldspar.
Transgressive reworked sandstones (TRS). The Upper Trent Sandstone is predominantly medium-grained, quartzose sandstone. It is interpreted to be part of a transgressive wedge that formed prior to the maximum flooding surface as represented by the Cancellatum marine band. This transgressive wedge is an estuarine/tidal channel complex that formed during the late stage filling of the incised valley. It has the best reservoir characteristics with permeabilities of 0.1 to 1000mD, the feldspar and clay minerals having been removed by tidal reworking. Such cleaning-up of sandstones within the Namurian has been noted in shallow marine environments (Percival 1992). Primary intergranular porosity is best developed (or preserved) in these sands, which is a reflection of abundant early quartz cement preventing framework collapse. Distributary channels (DC). The Westphalian A reservoir zones are medium to fine-grained sandstones deposited in low sinuosity distributary channels. These comprise single storey barforms approximately 30ft thick, constituting strongly linear bodies of limited lateral extent. They have permeabilities ranging from 0.6 to 340 mD. These less mineralogically mature sandstones contain welldeveloped detrital clay and authigenic mineral suites. These account for a pore network dominated by secondary intercrystalline/intergranular pores. The coarser-grained fraction contains the better quality rock where dissolution of early carbonate cements has enhanced porosity by providing an extensive and effective secondary porosity network. In the finer-grained sands this is largely ineffective and moderate porosities are associated with low permeabilities. Porosity/permeability relationships In general there is a rather poor relationship between porosity and permeability as a cross plot reveals (Fig. 15). There is considerable scatter and a significant break in trend at around 8 to 10% porosity. This results from the distribution of the two main porosity types within the reservoir facies. Thus, two samples with very similar porosity can have very different permeabilities. The break in trend corresponds to a change from the low porosity kaolinite rich and lithic sandstones to the higher porosity medium coarse-grained quartzitic sandstones. A different porosity cut off is consequently derived for each reservoir facies.
Source Thermal maturity data for the Trent Field and key offset wells indicate that the Caister Coal and Millstone Grit Formations' source rock facies (coals and carbonaceous mudstones) immediately underlying the Permian have crossed the oil generation
T R E N T GAS F I E L D
~ P O S m O N A J . ENV~ONMENT ,auND DESCRL~N
STP~T'K~I~APHW
-I.1~1.1:1-!~II1 ~ .............
Root=
A!?7
847
SEQUENCE STRAllG RAPId'(
Swm~tp ,,M~mdonme~ Fill
cemu~ mp~=
~.-~
- 250"
Di~rlb~a~ C~nr~l
Trough Crom Bed~ WESTPHIALIAN A DBTRIBUTARY C ~ E L i
I-ighst~nd Syli1~ms Tract Oi~bum~ Moulh Bar ~
~,~
~ | ~
~ r v e d ~ppl~
SUBCRETA,~M
M. Bo
~h~nd
S y ~ m s Trsct
Cl~atnnet
~LLATUM
M,
N T ~ ~
V~
~
T~
Like~
LO~'VER l~Et,&T E
L
~
Systems T ~
N Fig. 14. Summary of depositional environments for the Trent wells based on core. threshold and are between the peak oil and peak gas generation thresholds. Sections containing the source rocks would have reached peak gas maturity from the Cretaceous to the present day depending on their Cretaceous and Tertiary burial histories. Migration routes to the Trent area are short and involve both stratal and cross-stratal migration.
Field development The Trent Field was developed via two deviated wellbores and one vertical hole, which are completed in two separate reservoir inter-
vals. The 43/24-P3 twinned the 43/24-2 well at bottom hole location and is completed in Westphalian A channel sandstones. 43/24-P2 was newly drilled from the Trent Field platform location and is completed within the Trent Sandstone. 43/24-P4z was sidetracked from the original 43/24-1 well and is vertical through the Trent Sandstone reservoir. The Trent platform is not normally manned and is sited at the 44/24-1 location. The produced gas is evacuated via the Eagles (ETS) pipeline to the BP Amoco terminal at Bacton. The Trent Sandstone reservoir is subdivided into a good quality upper unit and poor quality lower unit (Fig. 2). A significant proportion of the reserves are contained within the poor quality lower unit. To enhance the recovery of gas within this lower unit
848
P.T.
O'MARA E T AL.
r162162
m
l
o 0 0
X
I.U
(9
9
E-
.~
15)
Q
Q tS~ Q
(CiUJ) ,~!i!q~aLUJgd Im,uoz!soH
o
TRENT GAS FIELD
849
Trent Field data summary Trap Type (ft TVDss) Gas column (ft) Trent Field Reservoir Zones Pay zone Formation Age Gross thickness (ft) Net/gross ratio Porosity (%) Hydrocarbon saturation (%) Permeability; average (geometric), range (mD)
4 way dip closure 1200 Lower Trent Sandstone Millstone Grit Marsdenian Carboniferous Carboniferous 50-100 0.85 10.3 85 0.3, 0.05-19
Gas water contact 11,780
Upper Trent Sandstone
Westphalian A Sandstone
Millstone Grit Marsdenian Carboniferous
Caister Coal Formation Langsettian
33 0.98 12.8 70 247, 0.1 1000
3O 0.87 ll 6O 38.0, 0.6-340
Hydrocarbons Gas gravity Condensation yield BBL/MMSCF Nitrogen content
0.646 8 3.22
0.646 8 3.22
0.652 8 3.32
Formation water Resistivity ( o h m m @ 60~
0.06
0.06
0.06
Reservoir conditions Temperature (~ Pressure (psi)
233 5500
Field size Area (acres) GIIP (BCF) Recoverable gas (BCF)
3100 111 92
Production Start-up date Nmnber / type of wells
233 5500
240 5605
November 1996 4 exploration and appraisal 3 producers 1 uncompleted development
b o t h the 43/24-P2 a n d 43/24-P4z wells were s t i m u l a t e d by a m e c h a n i c a l fracture t r e a t m e n t . This process i m p r o v e d flow rates a n d c o n n e c t e d v o l u m e to the T r e n t wells. O t h e r f o r m s o f e n h a n c e d recovery techniques such as h o r i z o n t a l wells were d i s c o u n t e d in this reservoir because o f the difficulties o f geosteering within such a laterally variable reservoir. T h e c o n n e c t e d G I I P c o n t a i n e d within the T r e n t Field core d e v e l o p m e n t area is currently e s t i m a t e d to be 111 B C F with recoverable reserves o f 92 B C F . T h e T r e n t Field c a m e o n stream in N o v e m b e r 1996 a n d up to S e p t e m b e r 1999 h a d p r o d u c e d 37.5 B C F . T r e n t Field gas is c u r r e n t l y sold on the s p o t m a r k e t . Thanks to all the members of the Trent and Tyne development team both past and present. Special appreciation is extended to Nick Riley from the British Geological Survey for his evaluation of the Trent macrofauna. Also thanks to Collinson Jones Consulting Ltd for their early Trent reports. Doug Jordan, Sal Bloch, Jim Klein and Chuck Vavra from AIOGC and AEPT are thanked for their petrological, diagenetic and facies descriptions. ARCO British Ltd. and Talisman Energy (UK) Ltd. are thanked for permission to publish.
References CAMERON, T. D. J. 1993. Carboniferous and Devonian of the Southern North Sea (Part 5). In: KNOX, R. W.O'B. & CORDEY, W. G. (eds)
Lithostratigraphic Nomenclature of the UK North Sea. British Geological Survey, Nottingham. CAMERON, T. D. J., CROSBY, A., BALSON, P. S., JEFFERY, D. H., LOTT, G. K., BULAT, J. & HARRISON, D. J. 1992. United Kingdom Offshore Regional Report." the Geology of the southern North Sea. British Geological Survey, Nottingham. COWAN,G. 1989. Diagenesis of Upper Carboniferous Sandstones: Southern North Sea Basin. In" WHATELEY, M. K. G. & PICKERING, K. T. (eds) Deltas: Sites and Traps for Fossil Fuels'. Geological Society, London, Special Publications, 41, 57-73. HAQ, B. U., HARDENBOL, J. & VAIL, P. R. 1987. Chronology of fluctuating sea levels since the Triassic. Science, 235, 1156-1167. HOLLYWOOD, J. M. & WHORLOW, C. V. 1993. Structural development and hydrocarbon occurrence of the Carboniferous in the UK Southern North Sea Basin. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4 ~h Conference. Geological Society, London, 689-696. O'MARA, P. T., MERRYWEATHER, M., STOCKWELL, M. & BOWLER, M. M. 1999. The Trent Gas Field: correlation and reservoir quality within a complex Carboniferous stratigraphy. In: FLEET, A. J. & BOLOY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 809-821. PERCIVAL, C. J. 1992. The Harthope G a n n i s t e r - A transgressive barrierisland to shallow-marine sand-ridge from the Namurian of Northern England. Journal of Sedimentary Petrology, 62, 442-454.
The Tyne Gas Fields, Block 44/18a, UK North Sea P. T. O ' M A R A 1, M. M E R R Y W E A T H E R 2 & D. S. C O O P E R 3 A R C O British Ltd, London Square, Cross Lanes, Guildford, Surrey GU1 1UE, UK 1 Present address." Ruhrgas UK Exploration and Production Ltd, New Zealand House, 8th Floor, 80 Haymarket, London S W 1 4TE, UK (e-mail:
[email protected]) 2 Present address." Tullow Oil UK Ltd, 5th Floor, 30 Old Burlington Street, London W15 3AR, UK 3 Present address." Consultant Geologist, Corner Cottage, Skinners Lane, Ashtead, Surrey KT21 2LY, UK Abstract: The Tyne Fields, operated by ARCO British Limited, are located within UKCS Block 44/18a, situated 180 km off the Yorkshire coast in a water depth of 65 ft. The fields comprise three separate accumulations, each with a different gas-water contact and varying gas compositions, which are known as Tyne North, Tyne South and Tyne West. The three accumulations are combined structural and stratigraphical traps. The reservoir sandstones are of the Lower Ketch member of the Schooner Formation and are Carboniferous Westphalian C/D in age. The fields have been developed through long reach development wells.
Location The Tyne Fields, operated by ARCO British Limited are located within UKCS Block 44/18a (Fig. 1). The block is located in the Silverpit Basin of the Southern North Sea, 180 km off the Yorkshire coast in a water depth of 65ft. ARCO was awarded Block 44/18 in 1987 as part of the 10th Round of Licensing and retained part Block 44/18a after mandatory relinquishment in 1996. The current licensees in the block are: A R C O British Limited 55%; Atlantic Richfield Oil & Gas (St James') Limited 25%; and Talisman Energy (UK) Limited 20%.
History The first field, Tyne South was discovered in 1992 by well 44/18-1 (Fig. 2), which tested the Carboniferous Lower Ketch reservoir at a maximum rate of 5 4 M M S C F D . In 1997 the original hole was twinned at bottom hole location by the development well 44/18aT l z to drain the accumulation.
43
44
Ii,I I
T~YN F-.I /
(
!1 t"
oc.
Tyne North was discovered in 1993 by wells 44/18-2 and 44/18-2z. Wells 44/18-2 tested the Lower Ketch reservoir at a rate of 34 M M S C F D whilst 44/18-2z tested the Upper Ketch reservoir at a rate of 27 MMSCFD. The accumulation is drained via two long reach development wells; 44/18-T3a drilled in 1996 and 44/ 18a-T5 drilled in 1997. They reached measured depths of 21 631 ft and 18 695 ft, respectively. Tyne West was discovered in 1994 by well 44/18-4A, which tested the Lower Ketch reservoir at a rate of 47 MMSCFD. The Tyne Platform is sited at the 44/18-4A well location and Tyne West is drained via a completion of the 44/18-4A well (44/18-T4) and a new deviated development well, 44/18-T2, drilled in 1996. First gas was produced from Tyne West on 7th November 1996, 18 months after Annex B approval.
Stratigraphy Typical Silverpit Basin post-Carboniferous strata are encountered in the Tyne wells. The Permian Silverpit Formation lies unconformably on the Carboniferous and consists of anhydritic mudstones and evaporites grading upward into the Upper Permian, which consists of five Zechstein evaporite cycles. The overlying Triassic sequence comprises red-brown siltstones of the Bunter Shale Formation, arenaceous sands of the Bunter Sandstone Formation, and shales and evaporites of the Haisborough Group. Jurassic rocks have been removed by erosion at the Base Cretaceous unconformity over most of Quadrant 44. However, Jurassic sediments have been encountered in some Tyne exploration wells with a thick Liassic sequence being penetrated in 44/18-T2. The Cretaceous is represented by Lower Cretaceous shales overlain by a thick Chalk section, which is followed by a series of interbedded sands, silts and clays deposited in the Tertiary. Drilling through some of these layers has presented significant operational challenges, most notably: (a)
(b)
(c)
I
o
50 K~
,,
i
Fig. 1. Location map of the Tyne Gas Fields, showing the transport route to the BP Amoco Bacton terminal via the Eagles (ETS) pipeline.
hole stability in the Tertiary mudstones proved to be a problem in the longer reach development wells. It is necessary to maintain a well bore angle of less than 40; mobile salts within the Upper Permian Zechstein Roter Salzton Formation have caused drill-bit sticking and twist-offs as well as production tubing collapse; overpressured Upper Permian Zechstein Plattendolomit Formation rafts have caused drilling kicks. Careful well planning is required to avoid these while drilling.
The Carboniferous nomenclature used here is from Cameron (1993). The Tyne Fields' reservoir is Westphalian C/D in age and lithostratigraphically falls within the lower part of the Ketch member of the Schooner Formation (Fig. 3). The Ketch Member is informally subdivided into a sand-prone Lower Ketch and shale-prone Upper Ketch for reservoir mapping. Well correlation in these largely barren red-beds requires the integration of a variety of techniques. Whole rock chemostratigraphy and enhanced recovery palynology
GLUYAS, J. G. & H[CHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 851-860.
851
852
P.T. O'MARA E T AL.
Fig. 2. Tyne Fields location map illustrating the positions of the accumulations and well locations.
have been applied to correlate the sand-prone packages across the Tyne Fields area. The Lower Ketch unconformably overlies the Westoe Coal Formation (Westphalian B), which comprises a coal-bearing package with the regionally extensive and commercially important Caister Sandstone at its base. The Namurian aged Millstone Grit Formation represent the oldest sediments penetrated in the Tyne area.
Geophysics The initial discovery wells, 44/18-1, 44/18-2 and 2z, were drilled on maps based on 2D seismic data. The Carboniferous section was poorly imaged on the 2D data and the relatively sparse 1 km 2 grid resulted in a degree of uncertainty in the interpretation and alignment of the major fault trends. In 1993, a 3D seismic survey was acquired and processed by Western Geophysical, which improved the overall definition of the Carboniferous section and the delineation of faults, particularly the E - W trending faults. There was also increased confidence in the cross-fault correlation of intraCarboniferous seismic events. The 550 km 2 3D survey has a 12.5-m common depth point interval and covers the whole of Block 44/18, extending into surrounding blocks 44/17, 44/23 and 44/13. The 3D data quality is good except in the area of the N-S oriented Mesozoic Graben and associated Zechstein salt wall (Fig. 2).
Seven key seismic horizons are interpreted to build a structural framework: Top Chalk, Base Chalk, Top Triassic, Top Bunter Sandstone, Top Zechstein, Top Rotliegendes, and Top Caister Sandstone (Fig. 4). These horizons subdivide the section into seven distinct velocity intervals used in the layer-cake depth conversion method. Interval velocity v. mid-point depth functions derived from adjacent wells are applied to the five overburden layers to depth convert to the Top Zechstein. For the Zechstein layer, a thickness v. two-way-time relationship is used and a constant velocity is applied to the Top Rotliegendes-Top Caister interval. This depth conversion methodology has proved robust and the development wells were drilled on prognosis to within 4-50 ft. Trending N-S through Block 44/18 is a Mesozoic graben with a low velocity Jurassic fill and an associated underlying high velocity salt wall. This gives rise to an area where the depth conversion is unreliable due to a combination of poor imaging of the overburden reflectors themselves and uncertainty in layer velocities that should be applied for the fill and flank areas which have undergone inversion. This graben feature affects the mapping of the Tyne West and Tyne North Fields. To overcome this mapping challenge, a geological model is assumed in which the Roltiegendes and Caister dips observed outside the Mesozoic graben poor data zone are extrapolated beneath the graben. The Lower Ketch reservoir at the Tyne Fields is around ( - 1 2 0 0 0 f t ) TVDss. Neither the top nor the base of the Lower Ketch reservoir unit can be easily nor consistently found on the
TYNE GAS FIELDS
853
LEGEND MUDSTONES
~LrrEs SANDS, CONGLOMERAIlT..S
MLIDSTONES, SHIALES COALS
Fig. 3. Stratigraphical column for the Tyne Fields area.
3D seismic data and over much of the area it is not always possible to pick a Base Permian/Top Carboniferous seismic event with confidence. In the display seismic line (Fig. 4) these horizons are essentially picked as form lines. As a consequence, structure maps of the reservoir are generated by applying isopachs to the Top Rotliegendes and Top Caister Sandstone depth surfaces. An isopach for the Silverpit Formation, based upon well data, is added to the Top Rotliegendes surface to produce a Base Permian map. A Westoe Coal Formation isopach, also based on well data, is subtracted from the Top Caister Sandstone pick, and truncated to the Base Permian, to produce a Base Lower Ketch (base reservoir) map. Finally, a Lower Ketch isopach, derived from surrounding wells, is subtracted from the Base Lower Ketch surface and
truncated to the Base Permian, to produce a Top Lower Ketch (top reservoir) map (Fig. 5).
Structure Three main fault trends in the Tyne area are identified from the 3D seismic data. These are oriented E - W (to WSW-ENE), N W - S E and N N W - S S E (Fig. 2). The convergence of these E - W and N N W - S S E fault trends forms the structural component of the trapping mechanism for the Tyne gas accumulations. The E - W trending faults essentially sub-divide Block 44/18 into three
854
P. T. O'MARA ET AL. North - . >
South
Top Chalk
1.0
Base Chalk Top Triassic Base Cret Unc Top Bunter Sst o3
c~ z O oLu
Top Zechstein
co 2.0 z LU I--
Top Rotliegendes ? Base Permian ? Base Lower Ketch Top Caister Sst
3.0 Fig. 4. 3D seismic cross-section A-N from Tyne South to Tyne North illustrating the seismic character of the overburden and the Carboniferous.
separate major fault blocks. Within each of these major fault blocks the intra-Carboniferous dips are fairly uniform, whereas the magnitude and azimuth of the dip varies between each of them. The main phase of movement on the E-W trending faults took place at the end of the Carboniferous with observed throws in the order of 1000 ft. Regional mapping suggests that sediments of the Ketch member were originally widely deposited. However, uplift, folding and faulting associated with the Variscan Orogeny resulted in significant erosion of Upper Carboniferous sediments particularly on the upthrown side of tilted fault blocks controlled by the E-W faults. This produced the present day subcrop pattern at the Base Permian unconformity. Mesozoic extension is evident in the Tyne area and resulted in the formation of the 3km wide graben feature oriented N-S. Development well 44/18-T2 encountered a thick Liassic fill in this graben. The NNW-SSE trending faults, which exhibit equal throw at Rotliegendes and Carboniferous levels, were also generated during the Mesozoic and formed oblique to the E-W extension direction due to pre-existing weaknesses in the Carboniferous structural fabric (Hollywood & Whorlow 1993). During the Alpine Orogeny in the Tertiary, N-S compression caused reverse movement on the older Carboniferous faults, particularly on the major faults oriented E-W. Tertiary compression may also be responsible for generating the broad folds oriented NW-SE mapped at top Rotliegendes and Base Permian. Culminations on these folds at Base Permian can provide some element of structural closure. The Base Permian sub-regional dip over Block 44/18 is approximately two degrees to the SSE. A broad NW-SE trending structural nose is developed in the southern part of Block 44/13 and extends into block 44/18. Within the Tyne North Field, the Carboniferous dip is 10~ to the north and increases to 18~ in the vicinity of the 44/18-2z well. In the Tyne South and Tyne West fields the Carboniferous dips to the east at about 6~. The seismically
mapped structural dip at both Permian and intra-Carboniferous levels is in good agreement with that observed from dip-meter data in the wells.
Trap T r a p type
The trapping mechanisms responsible for the Tyne Fields gas accumulations are complex. Unlike other Carboniferous fields in production, for example Caister and Murdoch, they are not solely related to the Base Permian structure (Bailey et al. 1993; Ritchie & Pratsides 1993; O'Mara et al. 1999). Instead they rely on a combination of Base Permian closure and cross-fault seal, with both Rotliegendes Silverpit and Carboniferous Upper Ketch shales providing seals (Fig. 6).
Sea/s The basal Permian Silverpit shales provide a regional top seal (supra-unconformity seal). They contain a basal conglomeratic lag and overlie the Carboniferous section with a sharp angular unconformity. They also provide lateral seals across NNW-SSE trending faults. The development of a wedge of shale (sub-unconformity seal) between the Lower Ketch reservoir and the basal Permian Silverpit shales adds a stratigraphic sealing element to the accumulations. This shale-rich Upper Ketch unit provides additional seal in both Tyne South and Tyne North. The Upper Ketch also provides crossfault juxtaposition seal across the E-W trending faults that bound Tyne North, Tyne South and Tyne West.
TYNE GAS FIELDS
Fig. 5. Top Lower Ketch depth map.
855
856
P.T. O'MARA ET AL.
Fig. 6. Geoseismic cross-section A-A' illustrating trapping mechanisms for the Tyne South and Tyne North accumulations. The underlying shale-rich Westoe Coal Formation provides lateral seal in crestal areas of Tyne North, where the Lower Ketch has been totally removed by erosion at the Base Permian unconformity.
Tyne South Tyne South has a gas-water contact at ( - 12 339 ft TVDss), which is 180 ft deeper than the closure mapped at Base Permian. It is partly dip-closed and partly fault-bounded to the north where Upper Ketch shales provide both top seal and cross-fault seal. Upper Ketch shales provide additional seal on the dip closure to the east. The field is bounded to the west by a NNW-SSE trending fault and is dip-closed to the south. Shales of the Silverpit Formation, which overlie the B ase Permian unconformity, act as both lateral cross-fault seal and top seal.
Tyne North Tyne North is located on a northerly dipping Carboniferous fault block, which is bounded to the south by an E - W trending fault. The nose of the N W - S E trending fold at base Permian level is mapped, but closure down to the observed gas-water contact at ( - 11 940 ft TVDss) is difficult to establish westwards because of a poor data zone associated with the Mesozoic graben that obscures the western limit of the Tyne North Field. The northerly dipping lower Ketch reservoir is progressively truncated by the southerly dipping base Permian unconformity and is completely eroded at the crest. In the south, the Silverpit Formation shales provide the top seal, whereas in the north, the effectiveness of shales in the upper Ketch to act as top seal is proven by a thin water bearing Rotliegendes sandstone above the gas pay in well 44/18-2z.
unconformity over most of the field. The accumulation is dip-closed to the south with Silverpit Formation shales acting as a top seal. These shales also provide lateral seal across the NNW-SSE trending bounding faults to the east and west, although shales within the Upper Ketch provide additional seal across these faults. Tyne West is bounded to the north by a major E - W trending fault where juxtaposition of the Upper Ketch shales act as a lateral seal.
Reservoir
Depositional setting The reservoir intervals for the Tyne Fields are coarse-grained clastics within the lower part of the Ketch Member (Fig. 7). This interval was deposited in response to a rejuvenation of a sediment source area, increase in slope and increase in accommodation space resulting in an unconfined laterally extensive braidplain (Haszeldine & Anderton 1981; Collinson Jones Consulting 1997). On this braidplain medium- to coarse-grained sands and gravels were deposited as stacked channels up to 100ft thick. The intervening floodplain and sheetflood deposits suggest that the climate was drier than the humid climate prevailing during the deposition of the Westoe Coal Formation. Soil horizons within overbank deposits indicate that both poorly and well-drained environments existed. The Lower Ketch, when fully preserved, consists of 400ft of stacked channel sandstones with a net/gross ratio of 0.5 to 0.7. The sandstones are separated by red- brown, silty claystones less than 40 ft thick. The reservoir comprises fining upward packages with frequent and prominent conglomeratic beds, where pebbles may reach 20 cm in diameter.
Lithofacies Tyne West Tyne West has a gas-water contact at ( - 1 2 228 ft TVDss). The Lower Ketch reservoir is partially truncated by the Base Permian
Two reservoir and two non-reservoir lithofacies associations were consistently recognised in core recovered from both exploration and development wells (Fig. 8).
TYNE GAS FIELDS
857
Fig. 7. 44/18-4A well log.
Lithofacies Association A. Thick, stacked, braided channels, predominantly medium-grained sandstones, with pebbly sandstone and matrix supported extraformational conglomerates distributed throughout. The units have an abrupt transition into overlying and underlying lithologies and demonstrate ~t uniformly low gamma ray signature. Typical bed thickness is up to 3 ft with common erosive lags developed towards the base of sandbodies. These sandstones have good reservoir quality throughout due to the absence of finegrained material.
Lithofacies Association B. Fining upward channel sandstones, thinner and finer grained than Lithofacies Association A. They
comprise pebbly to coarse-grained sandstone overlain by fine to very fine-grained sandstone and thin siltstones. These units have better sorting and more uniform grain size than Lithofacies Association A. The top 2-3 ft represents an abandonment facies of siltstones and suggest that these channel deposits were formed by avulsion on the braidplain.
Lithofacies Association C. Siltstones, very fine grained-sandstones and silty claystones. A wide variation in facies types from sandy overbanks, lacustrine muds to palaeosols is reflected in a ratty gamma ray signature. The sediments are haematitic and have extensive pedogenic alteration in places which is typical of ferruginous
858
P. T . O ' M A R A
G a m m a R a y Profile
*Lithofacies & C o r e Profile F
0
M
I
150
S
Clean Base. Pronounced upward fining.
. ~ t ~ SZm _ ~ F r Sp
e.':.'e.:.e, e.
9 ~ . ~. ~ . e.
,r.
e
f
e.
*-
P
L .
-
~
,,_./ . ~ . _ . . . =9 9 t
9
-
St
~
CE
. ',,.d..x../..u _ . . - ~
.x~,sm CE
- --I
SIII
,~ I
Mpd
-i
Typical sandbody thickness 1-5 ft
Pronounced upward-fining channel fill.
Sandy Braided
Pebbly sandstone: White to reddish grey, fine to coarse, well sorted sandstones. Laminated, cross bedded & massive, with quartz pebbles especially at base. Fining & coarsening upwards co-sets, contacts irregular with Ai & Aii, & sharp with lithofacies association Cii.
Overall blocky. Blocky, stacked channel fills comprising two facies & Minor fining elements of lithofacies association B. upward at top i) Matrix supported conglomerate: Red grey, poorly sorted, angular to maybe present, rounded conglomerate in medium coarse sand matrix. Quartz pebbles minor gamma ray <4cm. Boundaries sharp & irregular. Poorly developed cross beds. spikes corresponc to lags. ii) Clast supported conglomerate: Poorly sorted, sub-angular to subrounded quartz clast conglomerate. Pebbles >6cm. Random to imbricated alignment. Boundaries sharp & irregular with erosive lags. Rare thin bands of poorly iithified pebble openworks with no matrix. High, continuous, slightly ratty.
Interpretation
Thin interbeds of: i) Brown sandstone: Very fine to medium-grained, well sorted parallel & ripple-laminated. Sharp boundaries between co-sets. Rip up clasts. ii) Red mud/siltstone: Red/green to grey, mottled, well laminated to massive. Palaeosols, desiccation cracks & calcrete horizons. Diagenetic bands & pyrite nodules. Sharp, erosive boundaries with Ci, B & Ai.
~CE
_ SFr , x ~ St
:.
~
*Lithofacies
Ratty, thin/ sharply interdigitated.
~, SFb 9 Stm
I
Core Description
C
I I
I I
Gamma Ray Motif
ET AL.
Red grey haematitic mudstone/shale: Sub fissile blocky. Locally churned/rootletted/pedogenic. Planar laminations > 1mm. Bounded between lithofacies association Ci (fine sands). Sharp/planar contacts.
Sheetflood
Low Sinuosity Braided Channel Complex
Overbank, subject to syndepositional reddening
m - massive, h - horizontal laminated, t - trough cross-bedding, r - cross laminated, pd - pedified
F i g . 9. P o r o s i t y v. p e r m e a b i l i t y
plot for the Tyne Fields core data.
B
Fluvial channels on an alluvial plain
A
Major channel fairway on a distal alluvial fanalluvial plain
D
Shallow
Typical sandbody thickness 15-60 ft
CE - extraformational clast supported conglomerate, S - sandstone, SF - fine-grained sandstone, ST - siltstone, M - claystone
Gas Expansion Porosity
Alluvial floodplain
Typical sandbody thickness 10-25 R
Structures:
w i t h i n t h e T y n e F i e l d wells.
C
Channel
Composition:
F i g . 8. L i t h o f a c i e s a s s o c i a t i o n s e n c o u n t e r e d
Lithofacies E n v i r o n m e n t Association Code
lakes and overbank areas on an alluvial floodplain
TYNE GAS FIELDS palaeosols. This association represents floodplain deposits close to the channel margins.
859
secondary intergranular porosity in some instances. Less porous zones relate to bimodal sorting in conglomerates and non-ferroan dolomite and anhydrite cementation. The average core porosity is 11.4% with a maximum of 18%, average gas saturations are 75% and average permeability is around 300 mD with highly permeable units reaching 5000 mD (Fig. 9).
Lithofacies Association D. Thicker red claystone and silty claystone intervals. These intervals probably represent deposition a significant distance from the active channel. They give rise to a consistently high gamma ray signature.
Diagenesis Reservoir quality
The excellent reservoir quality of the Lower Ketch sandstones is a result of the open primary pore network due to a low degree of compaction and the sparse detrital and authigenic clay and mineral cement content. This is a consequence of the high mineralogical maturity of the sandstones at the time of deposition. The principle diagenetic phases are quartz, kaolinite, non-ferroan dolomite and anhydrite. Early diagenesis resulted in the formation of kaolinite clay from the dissolution of feldspars and muscovite, which had an important influence on the distribution of later framework reinforcing quartz cements (Cowan 1989; Vavra 1996). Haematite and non-ferroan dolomite cements are characteristic of sandstones with low permeabilities of < 1 roD. They have been interpreted as the result of oxidizing meteoric water infiltration during the Permian uplift (Cowan 1989). The release of silica compounds from feldspar dissolution during the Jurassic to Cretaceous deep burial resulted in quartz precipitation. Their grain rimming rather than pore blocking nature is probably a result of the limited presence of detrital feldspar. Mudstone rich intraformational conglomerates are more easily deformed due to pore-filling pseudomatrix. Continued feldspar
The reservoir quality of the sandstones varies from good to excellent. The most important parameters governing reservoir quality are the grain size and the sorting. Diagenesis can be an important factor locally. Both porosity and permeability increase with increasing grain size up to the boundary between the coarse and very coarse-grained sandstone classes (Fig. 9). For sandstones with grain sizes greater than very coarse, both porosity and permeability decrease with increasing grain size due to a corresponding decrease in sorting. The coarsest lithologies have a matrix of medium to coarse sand and are bimodal but it is the matrix that provides the porosity and the permeability. Variations in porosity and permeability with grain size are due to sorting and diagenetic effects. In general, the effects of diagenesis show an inverse relationship to grain size and thus are relatively small for the coarser-grained fraction, but more pronounced in the fine-and medium-grained fraction. Porosity types are primary and secondary intergranular macroporosity and micro-porosity associated with kaolinite cements. In general, primary intergranular porosity is the main pore type, although grain and local matrix dissolution may create important
The Tyne Gas Field data summary
Trap Type Gas water contact (ft TVDss) Gas column (ft) Pay zone Formation Age Gross thickness (ft) Net/gross ratio Porosity (%) Water saturation (%) Permeability; average (geometric), range (mD) Hydrocarbons Gas gravity Condensation yield (BBL/MMSCF) Nitrogen content (%) Formation water Resistivity (ohm-m @ 60~
Tyne North
Tyne South
Tyne West
Combined struct/strat 11 940
Combined struct/strat 12 339
Combined struct/strat 12 228
171 Lower Ketch member Carboniferous <400 partly truncated 0.6
11.0 25 35.1, 0.1 5000
240 Lower Ketch member Carboniferous 400 0.7 10.7 24 48.4, 9 450
295 Lower Ketch member Carboniferous <400 partly truncated 0.454-0.67 10.5 17-40 30.6, 0.1-3500
0.65 12
0.65 12
0.65 12
11.3
13.7
8.8
0.057
0.057
0.057
Reservoir conditions Temperature (~ Pressure (psi)
240 6153
242 6393
243 6338
Field area Area (acres) GIIP (BCF) Recoverable gas (BCF)
3920 163 82
1620 61 54
1930 149 105
March 1997 2 exploration 2 extended reach development
Nov 1997 1 exploration 1 extended reach development
Nov 1996 1 exploration 1 vertical, 1 extended reach development
Production Start-up date Number/type of wells
860
P. T. O'MARA ET AL.
dissolution during the middle Cretaceous inversion prompted kaolinite precipitation of a more crystalline morphology. Kaolinite has not affected the interconnectivity of the intergranular macropores. Patchy anhydrite cement is thought to have been deposited as a result of circulating Permian fluids and may be related to the proximity of faults where the Zechstein salts are connected to the Carboniferous section.
Thanks to all the members of the Trent and Tyne development team, both past and present. The support of the original partner, Goal Petroleum, is recognized especially in early Tyne drilling, including most notably John Donato. Special appreciation is extended to Doug Jordan for his detailed core descriptions. Tyne correlation was made possible thanks to the combined efforts of Duncan McLean at Sheffield University and Tim Pearce of Chemostrat Consultants. Jim Klein and Chuck Vavra from AEPT are thanked for their petrological and diagenetic descriptions. ARCO British Ltd. and Talisman Energy (UK) Ltd. are thanked for permission to publish.
Source The Tyne Fields are sourced from the kitchen area of the Silverpit Basin to the south where coals and shales within the Westoe Coal and Caister Coal Formations reached maximum maturity for gas generation during the late Cretaceous and into the Tertiary, prior to Alpine uplift (Ritchie & Pratsides 1993). The on-block maturity of the source rock formations is below the peak gas generating window, hence, migration routes into the structures from the main gas generating basin may have been fairly tortuous. The resultant, somewhat deficient methane charge, may explain the varying nitrogen contents of each of the Tyne accumulations. This ranges from 8% in Tyne West, through 11% in Tyne North and up to 14% in Tyne South.
Field development The Tyne Fields are developed via a single not normally manned platform at the 44/18-4A location and evacuated via a 20" export line (wet) to the A R C O operated Trent Field facility, where the production stream enters the Eagles (ETS) pipeline and is transported to the BP Amoco terminal at Bacton. In addition to the completion of the vertical 44/18-4A well, the Tyne Fields were developed utilizing four long reach wells drilled from a single site to reach the discrete gas accumulations. These long reach wells provide a low angle intersection of several reservoir zones. Reservoir quality is such that stimulation or horizontal wells to improve productivity is not necessary. However, experience of drilling such low angle wells through the Zechstein section has demonstrated the need to double case within the mobile salt section as soon as possible in order to prevent subsequent casing collapse. The total gas-in-place for all three of the Tyne Fields is currently estimated to be 373 BCF. Total production from the Tyne Fields since first gas in November 1996 and up to 30th September 1999 was 63 BCF of gas and 163 000 BBL of condensate. Gas from the Tyne Fields has been de-dedicated and is sold on the spot market at Bacton
References BAILEY,J. B., ARBIN,P., DAFFINOTI,O., GIBSON,P. & RITCHIE,J. S. 1993. Permo-Carboniferous plays of the Silverpit Basin. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 707-715. CAMERON, T. D. J. 1993. Carboniferous and Devonian of the Southern North Sea, Part 5. In: KNOX, R. W. O'B. & CORDEY,W. G. (eds) Lithostratigraphic Nomenclature oJ" the UK North Sea. British Geological Survey, Nottingham. COWAN,G. 1989. Diagenesis of Upper Carboniferous Sandstones: Southern North Sea Basin. In." WHATELEY,M. K. G. & PICKERING,K. T. (eds) Deltas: Sites and Traps for Fossil Fuels. Geological Society, London, Special Publications, 41, 57-73. COLLINSONJONESCONSULTING1997. Stratigraphy and sedimentology of the Westphalian C/D Barren Red Beds in Quadrants 44 and 49 of the Southern North Sea. Proprietary Company Report (unpublished). HASZELDINE, R. S. & ANDERTON, R. 1981. A braidplain facies model for the Westphalian B Coal Measures of north-east England. Nature, 284, 51-53. HOLLYWOOD, J. M. & WHORLOW, C. V. 1993. Structural development and hydrocarbon occurrence of the Carboniferous in the UK Southern North Sea Basin. In: PARKER,J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 689-696. O'MARA, P. T., MERRYWEATHER,M., STOCKWELL,M. & BOWLER,M. M. 1999. The Trent Gas Field: correlation and reservoir quality within a complex Carboniferous stratigraphy. In: FLEET,A. J. & BOLDY,S. A. R. (eds) Petroleum Geology of North West Europe: Proceedings of the 5th Conference. Geological Society, London, 809-821. RITCHIE,J. S. & PRATSIDES,P. 1993. The Caister Fields, Block 44/23a, UK North Sea. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 759-769. VAVRA,C. L. 1996. Pore Level Controls' on Reservoir Quality: North Sea Carboniferous. ARCO internal report (unpublished).
The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea JAMES
COURTIER
l & HUGH
RICHES
ConocoPhillips (UK) Ltd, Rubislaw House, Anderson Drive, Aberdeen AB15 6FZ, UK 1 Present address. ConocoPhillips, Houston, USA Abstract: The Vulcan, Vanguard, North and South Valiant gas fields are collectively known as the V-Fields and lie on the eastern flank of the Sole Pit Basin in the southern sector of the UK North Sea. They are contained within blocks 49/16, 49/21, 48/20a and 48/25b and are operated by Conoco (UK) Ltd. The first field to be discovered was South Valiant, in 1970, and the initial phase of exploration drilling continued until 1983, with the discovery of the North Valiant, Vanguard and Vulcan fields. Prominent faults and dip closures define the limits of the fields and gas is contained within aeolian sands of Early Permian age. The gross average reservoir thickness is approximately 900 ft with porosities ranging from 3-23% and permeabilities varying from 0.1 mD to 2 Darcies in producing zones. The development of the V-Fields consisted of drilling centrally located production wells in each field, targeting higher quality reservoir zones in areas of maximum structural relief. Initial gas-in-place is estimated at 2.6TCF with recoverable reserves of about 1.6TCF. The fields were brought on-stream in October 1988 and currently produce, as of November 1999, up to 260 MMSCFD of gas through the LOGGS complex to the Conoco terminal at Theedlethorpe, Lincolnshire. The V-Fields comprise four separate gas accumulations located approximately 75 miles off the Lincolnshire coast, in the southern sector of the U K N o r t h Sea (Fig. 1). The fields are operated by ConocoPhillips on behalf of BP. The total initial gas-in-place (GIIP) of 2 . 6 T C F is c o n t a i n e d within the L e m a n Sandstone F o r m a tion reservoir below 7200ft sub-sea. 3D seismic data have been acquired across the area, however data quality is still variable. U n c e r t a i n t y in depth conversion due to the complexity of the overburden, being the greatest problem. The fields are n a m e d Vanguard, N o r t h Valiant, South Valiant and Vulcan, following the
'V-Field' c o n v e n t i o n established by C o n o c o for earlier S o u t h e r n N o r t h Sea gas fiields.
Field history Exploration history The S o u t h Valiant Field is c o n t a i n e d within Block 49/21 and has a single satellite p l a t f o r m offtake point (Fig. 2). The field was discovered by the exploratory well 49/21-2 in A u g u s t 1970. A n appraisal
Fig. 1. Location of V-Fields Gas Complex.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 861-870.
861
862
J. COURTIER & H. RICHES
Fig. 2. Simplified structural features outline map at Top Rotliegendes. well was drilled in January 1983 and development drilling began in May 1986. The production satellite was installed in April 1987 and production commenced in August 1983. Six development wells have been drilled to date in the field. The North Valiant Field straddles blocks 49/16 and 48/20a and has two offtake platforms (Fig. 2). The field was discovered by the exploratory well 49/16-2 in October 1970 and then appraised by a single well in May 1972, with two further wells in 1983. Development drilling commenced in May 1986 with the North Valiant jackets and decks being installed in March 1988. Production commenced in August 1988 with seventeen development wells drilled to date. The Vanguard Field lies in Block 49/16 and is produced from a single satellite platform (Fig. 2). The field was discovered by exploratory well 49/16-7z in Novembr 1982 and then appraised by a single well, 49/16-10 in November 1983. Development drilling commenced in May 1986 with the Vanguard jacket and deck being installed in April 1987. Production commenced in August 1988 with seven production wells drilled to date. The Vulcan Field straddles blocks 49/21 and 48/25a and has two offtake platforms (Fig. 2). The field was discovered by explora-
tion well 49/21-6 in March 1983 and then appraised by two further wells, 48/25b-2 and 48/25b-3, in 1984. Development drilling commenced in May 1986 with the Vulcan jackets and decks being installed in April 1987, with production commencing in August 1988. Twenty-one production wells have been drilled in the field to date. In 1994, the separate Vulcan C extension, was discovered 4 km south of the main Vulcan Field by the 49/21-7 well. This was recently developed by drilling an extended reach horizontal well from the RD platform in 1998.
Development history During 1983, Conoco investigated the options for transporting gas to shore from the unexploited reservoirs of the four V-Fields and concluded that the construction of a major new offtake system was justified on the basis of proven reserves. The development plan called for a total of 23 production wells to be drilled through templates at platform jacket locations prior to first gas. The wells provided a contracted peak gas quantity of 551 MMSCF/D during the
V-FIELDS winter of 1988/89, which has now reduced to a peak of approximately 260 M M S C F / D for the 1999/2000 winter. Initial development wells were drilled through the reservoir at deviated angles varying from vertical to 35 ~ from vertical. However with the advent of horizontal well technology, it was recognized that increased production, particularly in heterogeneous or low relief structures, could be achieved through drilling horizontal wells. Prior to 1989, due to reservoir heterogeneity and low structural relief in the North Valiant Field, only four out of 10 production wells effectively contributed to field production. The first horizontal well (49/16-P05) drilled by Conoco UK Ltd targeted this field in an attempt to 'connect' potentially isolated dune sands. Drilled in 1989, P05 pernetrated over 2500 ft of reservoir in the NW area of the field and encountered a series of high quality dune sands, previously unrecognized from the earlier vertical production/exploration wells. This well initially tested in excess of 100 M M S C F / D and demonstrated the importance of horizontal well technology within such a heterogeneous reservoir. To date all seven subsequent wells drilled on the V-Fields have been horizontal, and have helped maximize deliverability from these fields. The last of these was 49/21-R12, drilled as an extended reach step-out from the Vulcan platform, to drain the Vulcan C satellite. The well spudded in February 1995 and reached a total depth of 16 000 ft with a lateral offset of some 12 000 ft from the platform, testing at an initial rate of 77 MMSCF/D.
Structure Regional tectonic history and structural styles of the Southern North Sea are well documented by numerous authors (Glennie & Boegner 1981; Arthur 1983; Glennie 1984, 1990, 1997; van Hoorn 1987; Walker & Cooper 1987; Hooper & More 1995). The V-Fields can be divided into two distinct structural areas within the Sole Pit Basin; a northeastern area comprising Vanguard, North Valiant and South Valiant Fields and a southwestern area including the Vulcan Field (Fig. 2). The northeastern area is characterized by a complex-faulted preZechstein interval, with major axial Mesozoic grabens which are developed in a N W - S E orientation (Fig. 3). The Zechstein section demonstrates an intricate history of halokinesis, which combined with thin-skinned gravity tectonics has directly influenced the development of Mesozoic and Cenozoic structure styles (Hooper & More 1995; Stewart & Coward 1995). The majority of overburden faults utilize various halite detachment surfaces within the Triassic and Zechstein, as a result faults exhibit significant rotation and listric geometries (Fig. 3). Symmetric and asymmetric reactive diapirism are invoked as the fundamental processes which produce the observed overburden structural geometries. The Zechstein section acts as a buffer to tectonic deformation, as planar faults which offset the Leman Sandstone. Formation have a clearly different to those present in the overburden. Principal Rotliegendes faults are oriented NW-SE, displaying normal, vertical and reverse displacements, reflecting the history of different tectonic phases. In contrast, the southwestern area is characterized by a near horizontal, planar bedded overburden section (Figs 4 & 5). This region is situated towards the centre of the Sole Pit inversion axis, consequently a significant Mesozoic section has been eroded leaving a thin Tertiary sequence unconformably overlying Upper Triassic sediments. Rotliegends structure displays an interaction between major E - W oriented faults, which offset key N W - S E features (Fig. 2).
Stratigraphy The geological succession in the V-Fields area (Fig. 6) is typical of the UK Southern North Sea (Ziegler 1975). Quaternary and Tertiary successions of variable thickness are underlain by a Mesozoic succession. Locally the Upper Cretaceous Chalk and only the Lower Jurassic Lias Group, comprising siltstones and shales, remain of
863
the full Jurassic section, with the majoity of Middle and Upper Jurassic and the Lower and Upper Cretaceous sediments having been eroded during the Late Cimmerian. The Lower Jurassic Group rests conformably upon the Upper Triassic, which consists of evaporites, sands and shales, and is underlain by Lower Triassic Bunter sandstones and shales. The Permian Zechstein evaporites consist predominantly of thick halites and anhydrites, with variable thicknesses of limestone and dolomite. This evaporite sequence acts as the seal to the underlying Rotliegendes Leman Sandstone, which forms the gas reservoir in the V-Fields area. The Rotliegendes Group is of Early Permian age and rests unconformably on Carboniferous Westphalian strata (the source of the gas), which were uplifted and gently folded during the Variscan Orogeny (Glennie & Boegner 1981). Rotliegendes deposition commenced in a gently subsidising desert basin, with a N W - S E trending depositional axis, located to the SW of the Valiant trend. The Rotliegendes sediments comprise fluvial sandstones and lacustrine shales overlain by variably developed aeolian sandstone packages. The fluvial sediments were derived from the Carboniferous and Devonian rocks of the London-Brabant Massif to the SW of the V-Fields area, or local structural highs, which had been uplifted during the Variscan Orogeny. The fluvial sediments show a N N E transport pattern away from the massif, but because of the prevailing Early Permian wind, the aeolian sediments, derived from unconsolidated alluvial fan, wadi and floodplain deposits, show a westward transport direction (Pritchard 1991). The depositional environment throughout Rotliegendes time was dominated by fluctuations in the water table caused by variations in the Silverpit Lake to the north of the V Fields' area. Deposition occurred in either aeolian or lacustrine/fluvial dominated environments, depending on whether the water table was respectively deep or shallow. Rotliegendes deposition was terminated by the transgression of the Zechstein Sea which rapidly submerged the desert dunes, disrupting sedimentary structures and establishing conditions favourable for cementation of the uppermost reservoir interval. Differential subsidence ceased during the Zechstein, due to regional tectonic stability, resulting in the deposition of a thick evaporite sequence of progressively shallower cycles. Significant stratigraphic facies thickness variations of the Zechstein can be observed across the V Fields' area. The northeastern area can be considered more basinal in terms of Zechstein deposition, as opposed to the southwestern area of Vulcan and Vulcan C which is interpreted as a carbonate platform. Thicker carbonate sequences and thin halites are developed on the platform area, whereas thinner carbonate units and thicker halites are developed in more basinal settings. Tectonic stability was maintained during the deposition of a uniformly thick Lower Triassic Bunter Shale sequence, but thickening of the overlying Bunter Sandstone to the SW of the area indicates re-establishment of differential subsidence, which continued throughout the Late Triassic. Earliest Zechstein salt movement is believed to have been initiated in the Late Triassic, forming N W - S E linear salt swells over the Valiant and Vanguard trends (Pritchard 1991; Hooper & More 1995). This resulted in active localized depocentres producing variations in sediment thickness and facies with the Upper Triassic. Halokinesis temporarily ceased during the Jurassic and diffeential subsidence continued, with conformable deposition of Lower, Middle and Upper Jurassic sediments (Pritchard 1991). During the late Jurassic and Early Cretaceous, the V Fields' area was uplifted and eroded. Lower Cretaceous and Jurassic sediments and in the Vulcan area, uppermost Triassic sediments, were eroded. A major extensional phase was associated with this initial uplift and resulted in the rejuvenation of reactive diaprisim forming N W - S E oriented linear grabens ithe post-Zechstein overburned. In the case of Vanguard, the graben is asymmetric due to the presence of the underlying salt swell (Fig. 3). A major transgression occurred during the late Upper Cretaceous, resulting in deposition of thick Campanian and Maastrichian Chalk sequences which thin onto structural highs. In addition, salt diapirs began to partially evacuate, further accentuating earlier
864
J.
COURTIER
&
H.
RICHES
I
. ,...~
V-FIELDS
865
~5 ~5
.n:
866
J. C O U R T I E R & H. RICHES ~ee~j 0 0 0
0
0
o o
o o
8
~--
~
C')
0
0
$
8
~ o
~176 o
~176 o
o $
~
U')
~
~-
O0
CD
0
o
o c-
_o >
|
O~
P
LL
0
0
a n~
>
>
o 00 o o
V-FIELDS
Age
Lithology
Tertiary -
/
Recent
Z~=2 ~
Group
(feet)
o
lOO
9
M a j o r i n v e r s i o n of
i
~
~'_~
Inde. H i g h
I
Sonic
Permeability
Porosity
(mD)
140
40
aeservoir
0
Zonation
looo
. ,~--_'~-~-~ - . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sst. Fm.
g ;,)
i
~5
R e g i o n a l Uplit related to Broad Fourteens a n d rifting of west ---- Netherlands B a s i n
Lz-~- ~ --'~-f---~---~~ - ~ - - - ~ -
g- - - ~ - - ~ - - - - -
Neut./Density .o:a . . . . . . . . o..;.~ 1.95 2.95
...............
...........
Lias
I R e s . (~) p,~.. . . . . . . 0.2 20
..................................................................
Broad Fourteens basin,i S o l e Pit Trough and [
/ _ ,
', :~:.
Major inversion main Alpine eventdiapiric rejuvination
~
/ ~
Chalk
Depth
GR API
Major Tectonic Events
867
.
Group
!
.
<.~
-.
.
.
.
.
........................ .. il ..................................................................... !il ..... i. ...................... . . . . . . . . , I
~- ................. $~= -=
ii ~
g -=---
2~
~-:.:.Z:-:-~-:-:.:.:.:.:.:,-' ~ _ ~ _ W i n t e rFro. ton --
Triton Formation
,---=~ ~ - m
:~- i . - -
Silver Pit
_. , ~ , n , . ~ , ~ , . . . . . . . . . [] [] [] [] [] [] [] n []
:
and
Sole Pit Basin
,~
....
fully developed
r:..:
~
F O
-
CO
-
[]
Dudgeon
.
[] .
[]
.
[]
.
.
[] .
[] .
[]
.
[]
[]
.... '
.
[] [] [] [] [] [] O
0
[] []
[] D
D
D
[]
D D [] [] D 0 O D . . . . . . . . . . . . . . . . . .
D
0,
Formation
'~iii' . . . . ......................
Dowsing Formation
D
D
D
D
D
"
~
--~" N
~"
~
~ o
[]
[] 0
D
D
0
D
0
D
D
[]
[] O
0
0
D
0
D
D
D
[]
~
.
.
.
._ . _ .
.
.
.
mO) ~ . ~ :~-
O
ii!:)i '
................
...., ,.,....,.......,....-.......-.-
~,
,.,,,,,,.,,.,,,,,,.,,,,,,....,, ,..,,,.,,,,.,.,.,...,.,.,.,,.,.. Bunter Sst. ~. . . ...--. . . . . :--: . . . . .-.--..--= . . . . . . :=-. : - : .-~. Formation
":-:':.:.:-:.:.:,:.:-:.:.:.:.:-:-:.:-:.: '
:-:.~.:.-T:.X.:-:.~.:-:.X.:: . . . . . . . . . . . . . . . . . . . . , . . / . . . , . . , . . . . . . , , ,
_
_
_
- , . , , 9.............................
..,,,,..,...,................
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. .. .. . . . .. .. .. . . . . . .. .. .. . . . .. .. .
.................
~
...,.,.....,,,,,,,,,,.,,,/,.,,,
.
Bunter Shale Formation
.
.
.
.
.
.
.
.
.
.
.
.
.
.
.
. .
. .
. .
. .
. .
. .
. .
. .
. .
.
.
.
.
.
.
.
.
.
....
. . .
I-'
................ !
%
.
.
\
E diapirism Post Variscan thermal subsidence
l
i. . . .
--
..............................................................................
.
.
.
.
.
.
.
.
.
.
.
.
? Initiation of [] [] o [] [] [] [] [] [] [] [] [] [] [] [] [] ~ [] [] []
Zechstein i ~ / / / / / / / / / / / / / / / " // / Group
i
.....
%
l .......
t::~ ........
'
~
--
~ - -
=z '_
[] [] [] [] [] [] [] [] [] [] [] D
, ,.,,
D
D
-...,,
D
0
O
O
O
-.-.-.-.,....:.-..,,
D
9-
. . . . . . . . . . . . . . . . . . . .
,.....,.....,.....,..........,...
! Leman i Formation
i I !Carboniferous
:--: ...............
-
Sst..:-:.:.:.:-:.:.:.:.:.:.:.'..:.:.:.:.:.:.:, ". .- -. ". :.~. ". . . . .". .". .". .". . ". . ". . ". . ." . ." . .- . ." . ." . .". . .
9--'-'-'--'-'-'-'-'-'-' . ' - - - ' - - .
. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. .. '..'.'.'.'.'.'.' .'.'.'.'.'.'.'.'.'.'.'.'
iiiiiiiiiiiiiiiiiii~iiiiiii .
.
.
.
.
.
.
.
Sole Pit Basin Initiation of m i n o r extension Uplift of Inde. H i g h
. . . .
.
Fig. 6. Generalized stratigraphy in the V Fields.
developed Mesozoic grabens producing Cenozoic depocentres and half-grabens in the immediate NE V Fields' area. Inversion of the Sole Pit anticlinorium occurred in the Late Maastrichtian to Early Paleocene, with some associated erosion of Chalk. Further regional uplift caused by Late Alpine compression was followed by uniform subsidence from the Pliocene through to the present day.
Geophysics Major advances in understanding the V-Fields since Pritchard (1991) have mainly arisen as a result of the advancements in seismic technology such as ocean bottom cable (OBC) seismic acquisition, Pre-stack depth migration and the development of new structural models.
868
J. COURTIER & H. RICHES
3D seismic data were acquired in 1994 across the 49/16 area, including the Vanguard Field, which displayed a great improvement in overall data quality from previous 2D seismic. These data were originally interpreted in 1995-1996 revealing overburden geometries quite unlike those previously mapped from the existing 2D data. Triassic fault patterns and Zechstein fault geometries were interpreted for the first time with a degree of confidence and equally importantly, the intra-Zechstein Plattendolomit rafts (which can be overpressured and hence a drilling hazard) became more easily indentifiable. Significant improvements in seismic imaging by the Vanguard 3D survey and the new opportunities apparent within the survey area prompted the acquisition of a large 3D survey over the remaining V-Fields during 1996. Conventional towed-streamer acquisition was not possible due to extremely shallow water (<3 m in places) and strong tidal currents. This necessitated the acquisition of an ocean bottom cable (OBC) survey. Final time-migration processing was completed in July 1997 and major improvements in data quality from pre-existing 2D data were instantly recognized over all fields. Enhanced data quality over the Vulcan Field allowed the delineation of previously unmapped faults, producing a significantly improved structural interpretation (Fig. 4). Interpreted time-migrated data was depth converted using a variety of methods, including geostatistical and multi-layer-cake techniques. Careful observation of lithology variations and their associated velocity and thickness changes within the Zechstein section is imperative to derive an accurate top Rotliegendes depth map. Latest depth maps have revealed potential in-fill drilling locations within the Vulcan Field and a new development well is currently planned for 2000 to help boost production and extend the field plateau. The OBC 3D data significantly refined the 2D mapping and viability of developing the Vulcan C extension. Furthermore, prospective areas outwith Vulcan have also been identified on the 3D data. Despite improvements recognized in time-migrated 3D data over Vanguard, North Valiant and South Valiant, seismic imaging at top Rotliegendes in more structurally complex areas remains low quality due to the highly complicated overburden structure (Fig. 3). To improve the seismic image in such localities, 3D pre-stack depth migration processing was applied in 1998. A detailed 3D velocity model was built from interpreting the OBC 3D time-migrated volume which was then used to generate a 3D pre-stack depth migrated volume. Data quality shows considerable improvement in the pre-Zechstein section over the 3D time-migrated data. In the post-Zechstein section, faults have been corrrectly positioned and a general improvement in data quality can be observed. Geostatistical and layer-cake depth conversion techniques have been applied and an improvement in the stuctural definition of these fields has been achieved. Previously unmapped faults have been identified, which, when integrated with well production data, help to evaluate future field infill drilling locations. Furthermore, new prospective features have also been identified outwith the main field areas and this potential is under evaluation.
Trap A combination of prominent faults and dip closure define the bounding limits of the fields, with top seal provided by the overlying impermeable Zechstein evaporites. Vulcan and North Valiant demonstrate gas fill beyond structural closure, thus exhibiting an element of Leman sand-on-sand fault seal. Cataclasis along the fault plane where the poor quality Zones A and B are juxtaposed, is attributed as the sealing mechanism (Leeds University internal fault seal report), although this phenomenon does not appear effective when higher quality reservoir units are juxtaposed, such as in Zone C.
North and South Valiant fields The separate Valiant culminations comprise a series of N W - S E oriented upthrown faulted blocks, bounded to the NE by a series of
N W - S E oriented faults and to the SW by a major reactivated fault system. North Valiant Field itself is divided by an E-W sealing fault into two separate blocks with differing gas-water contacts of 8000 ft sub-sea for the southerly block and 8090 ft sub-sea for the northerly block (Fig. 2). South Valiant Field has a gas-water contact at 7964 ft sub-sea and is separated from the North Valiant Field through a series of sealing faults which trend N E - S W and E-W.
Vanguard Field Vanguard Field is contained in a completely faulted NW-SE trending anticline, bounded to the NE and SW by major reactivated faults which converge closing the structure to the NW. The reservoir is filled to spill point and the gas-water contact is at 8450 ft sub-sea (Fig. 2).
Vulcan Field Vulcan Field comprises a series of discrete structural blocks, defined by faults of NW-SE, E - W and E N E - W S W orientations. It is predominantly bounded to the NE by a N W - S E oriented major reactivated hard-linked fault system. To the north and west, faults, and ultimately structural dip, bound the field. To the south, the field is separated from the Vulcan C extension by major E-W sealing fault. Within the field boundaries a moderate degree of compartmentalization is evident through mainly E - W to ENE-WSW faults and a significant fracture zone oriented N N W - S S E dividing the two platform areas. Field production data demonstrates that intraVulcan faults can act as barriers within timescales of field life. Pressure differentials across faults vary depending on the juxtaposition of differing reservoir units. The average gas-water contact is 7650 ft sub-sea, but varies +20' within specific structural blocks (Fig. 2). The Vulcan C satellite is an extension to the Vulcan Field, bounded to the north by a major E-W near vertical sealing fault, with ultimately 3-way dip closure in the other directions (Fig. 5). The gas-water contact is at 7389 ft sub-sea.
Reservoir In the V-Fields area, the Leman Sandstone Formation comprises between 700 and 1000 ft of predominantly aeolian sandtones. These were deposited in an arid desert environment and can be divided petrophysically into four zones, Zones A through D (Fig. 6). These zones correspond closely to four main depositional units possessing characteristic facies assemblages which have had a major influence on reservoir properties. From base to top the zones are:
Zone D The basal zone of the Leman Sandstone Formation comprises a mixed assemblage of facies including fluvial, sandy sabkha, aeolian and lacustrine associations. The vertical and areal distribution of these facies is complex hampering correlation between wells. Layer D is characterized by low porosity and permeability, especially within sabhka and fluvial facies, reflecting the more heterogeneous sorting characteristics of these facies. Porosity averages around 6% and permeabilities are upto 10 mD. Throughout the V Fields, this unit is within the water leg.
Zone C This zone is dominated by a stacked sequence of of aeolian dune and dry aeolian sandstone deposits. These sandstones yield the best reservoir quality in the V-fields area and makes Zone C the optimum target for reservoir production. In general, more than 300 ft of structural closure is required before Zone C can be exploited.
V-FIELDS
Thickness variations in Zone C generally reflect infilling of topography at the base Rotliegendes Group unconformity. Zone C sands are also somewhat difficult to correlate between wells because of variations in dune size and migration patterns. The predominance of aeolian dune and sandsheet facies in Zone C reflects a regional increase in aridity. The porosity range in the dune sands is 15-23% and permeabilities range from 10 mD up to 2 Darcies.
869
erties are similar to those in other Southern North Sea Fields that undoubtedly have the same source. During the Late Cretaceous to Early Tertiary it is likely that the source rock had reached maturity, the trap had been formed and the gas was able to migrate into the reservoir.
Facilities Zone B
The initial Lincolnshire Offshore Gas Gathering System (LOGGS) facilities were installed and commissioned by October 1988. The system comprises six unmanned satellite platforms linked by sub-sea flowlines to a manned central gas gathering station. From the central gas gathering station a 75-mile long, 36" diameter pipeline runs to shore at the Conoco terminal near Theddlethorpe, on the Lincolnshire coast (Fig. 1). The V-Fields unmanned satellite platforms (Fig. 2) are all 10-slot wellhead platforms. The LOGGS complex gathering station initially consisted of an accommodation platform production and North Valiant wellhead platform. Further developments have included installation of a compression platform in 1990 and a riser platform in 1993, to accommodate later development of the Ann, Alison/Viking Kx, Vampire and Jupiter Fields.
This zone comprises interbedded aeolian dune and sandy sabhka deposits. The best reservoir quality is again found in the aeolian dune facies, however due to a finer grain size, it is generally poorer than in Zone C. The sandy sabhka deposits are typically poorly sorted clayrich sandstones and are correspondingly low permeability horizons. Zone B is therefore the most heterogeneous zone, in terms of rock properties, with porosity ranging from 12-15% and permeabilities varying from 0.1 to 10 mD.
Zone A This represents a final expansion of the Rotliegendes erg prior to Zechstein flooding, and comprises aeolian dune facies. The upper part of the zone has been reworked by the Zechstein transgression and is commonly referred to as the Weissliegendes. Generally, this zone possesses poor reservoir properties due to a combination of fine grain size and diagenetic alteration. Up to 100ft of structural elevation exists at the top of Zone A, relative to Zone B, in the V-Fields area, reflecting preserved dune topography. The lower dune sands have porosities ranging from 10-12% and permeabilities from 0.1-1 mD, decreasing in the cemented upper sands to <10% and 0.3 mD respectively.
Reserves Ther estimated ultimate recovery for the V-Fields Gas Complex is approximately 1600BCF gas and 3.35MMBBL Natural Gas liquids and condensate. The production mechanism is one of volumetric depletion with little evidence of acquifer support. Daily gas production requirements were initially 325 M M S C F / D with peak production of 551 M M S C F / D in 1988. This has now declined to 140 MMSCF/D. Figure 7 highlights the annual production profile for the V Fields since first gas in 1988. The authors would like to thank ConocoPhillips and its partners BP for permission to publish this paper. In addition, they would also like to acknowledge the contribution of the large number of ConocoPhillips employees who have been involved over the years in delivering such a successful development.
Source The source for the Rotliegendes hydrocarbons is the underlying Carboniferous Coal Measures (Glennie 1984). Hydrocarbon prop-
Vanguard Total
- 400
N.Valiant Total S.Valiant Total - 350 Vulcan Total
-3oo "
0
1
110
-250 O tO
o
- 200
a.
(5 - 150
////
////,
IIItl
I
88-89
I
89-90
I
I
90-91
91-92
92-93
I
93-94 Contract
Fig. 7. V Fields annual gas production.
year.
IIIII
I
94-95
I
95-96
I
96-97
I
97-98
98-99
~"
870
J. C O U R T I E R & H. RICHES
V-Fields Gas Complex data summary Trap Type Depth to crest Lowest closing contour Hydrocarbon contact Gas column Reservoir Formation Age Gross Thickness (average; range) Net/gross ratio (average; range) Cut off for N/G Porosity (average; range) Hydrocarbon saturation (average) Permeability (average; range)
(Nov 1999) Block faulted 7200-7900 ft sub-sea Fields filled to or close to spill point 7650-8450 ft sub-sea 45O-583 ft
Rotliegendes Group, Leman Sandstone Early Permian 890 ft; 790-990 ft 0.8; 0.6-1.0 Variable 13.5 %; 3-23 % 60% 5.4 mD; 0.1-1950 mD
0.60 1.8 STB/MMSCF 220 SCF/RCF
Formation water Salinity Resistivity
190 000-290 000 ppm 0.017-0.022 ohm m
Reservoir conditions Temperature Pressure, initial Pressure gradient in reservoir
142-177~ 3472 3835psia 0.07 psi/ft
Production Start-up date Development scheme
Cumulative production (November 1999)
DCQ 324.5 M M S C F D Peak production 551 M M S C F D DCQ 140MMSCFD Peak production 256 M M S C F D 906 BCF
References
Hydrocarbons Specific gas gravity Condensate yield Formation volume factor
Field size Area Gross rock volume Initial gas-in-place Recovery factor gas Recoverable hydrocarbons: Gas NGL/condensate
Production rate (1988-1989)
49 square miles 1.1 x 10 t2 cubic ft 2593 BCF 65-77% 1600 BCF 3.35 MMSTB
October 1988 Six unmanned satellite well platforms linked to a manned central offshore gas gathering station
ARTHUR, T. J. 1993. Mesozoic structural evolution of the UK Southern North Sea: insights from analysis of fault patterns. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. Geological Society, London, 1269-1279. GLENME, K. 1984. Outline of North Sea History and Structural Framework. In: GLENME, K. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 34-77. GLENNIE, K. 1990. Rotliegend sediment distribution: a result of late Carboniferous movements. In: HARDMAN, R. F. P. & BROOKES, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 127-138. GLENN~E, K. 1997. History of exploration in the Southern North Sea. In: ZIEGLER, K., TURNER, P. & DMN~S, S. R. (eds) Petroleum Geology of the Southern North Sea." Future Potential. Geological Society, London, Special Publications, 123, 5-16. GLENNIE, K. & BOEGNER, P. L. E. 1981. Sole pit inversion tectonics. In: ILLING, L. V. & HOBSON, D. G. (eds) Petroleum Geology of the Continental Shelf of North Western Europe. Institute of Petroleum, London, 110-120. HOOPER, R. J. & MORE, C. 1995. Evaluation of salt-related overburden structures in the U.K. southern North Sea. In: JACKSON, M. P. A., ROBERTS, R. G. & SNELSON, S. (eds) Salt Tectonics: A Global Perspective. American Association of Petroleum Geologists, Tulsa, Memoir, 65, 251-259. PRITCHARD, M. J. 1991. The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea. In: ABBOTS, I. L. (ed.) United Kingdom Oil and Gas Fields." 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 497-502. STEWART, S. A. & COWARD, M. P. 1995. Synthesis of salt tectonics in the Southern North Sea, UK. Marine & Petroleum Geology, 12(5), 457-475. VAN HOORN, B. 1987. Structural evolution, timing and tectonic style of the Sole Pit inversion. Tectonophysics, 137, 239-284. WALKER, I. M. & COOPER, G. 1987. The structural and stratigraphic evolution of the north-east margin of the Sole Pit Basin. In: BROOKS, J. & GLENNIE, K. (eds) Petroleum Geology of North West Europe. Geological Society, London, 263-275. ZIEGLER, H. 1975. Outline of the Geological History of the North Sea. In: WOODLAND, A. (ed.) Petroleum and the Continental Shelf of North West Europe, Volume 1. Applied Science Publishers, London, 165-190.
The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea HUGH
RICHES
ConocoPhillips (UK) Ltd, Rubislaw House, Anderson Drive, Aberdeen AB15 6FZ, UK
Abstract: First production from the Viking Fields began in 1972 and at its peak a total of 13 platforms produced at rates up to 950 MMSCF/D from 20 wells. This supplied around 10% of the United Kingdom's natural gas requirements, 27 years on, that rate had declined to approximately 40 MMSCF/D. However following an extremely successful infield drilling programme in the mid 1990s, significant volumes of new gas have been discovered and new technology has facilitated the development of accumulations previously considered non-commercial. This has led to three new developments within the Viking area: the Vampire Field on the eastern margin; Kx to the south of the Philips' Alison Field; and four previously non-producing fields, captured within the Phoenix Development. The major change since Morgan (1991) has primarily been the re-negotiation of the gas sales contract and the removal of the Gas Levy in 1992. This provided favourable marketing conditions for the development of additional Viking gas production and initiated an appraisal programme for remaining reserves. This programme, which will be the focus of this paper, began with the acquisition of a 3D seismic survey in 1993 and has concluded in the development of the Viking Extensions in 1998, now known as the Phoenix Development. The Leman Sandstone Formation forms the reservoir and consists of aeolian and fluvial sandstones, which are interbedded in the north of the area with silty shales deposited within a sabkha environment. Hydrocarbons were sourced from the underlying Carboniferous Westphalian coals and carbonaceous shales, and migration into the Rotliegendes Group probably occurred during the Late Cretaceous to Early Tertiary. The average daily production from the original Viking A and B fields and associated satellites had declined to 196 MMSCF/D by March 1989, peaking to over 300 MMSCF/D with seasonal demand. By October 1999, this had further reduced to around 40 MMSCF/D. Production from the Phoenix wells is currently at around 290 MMSCF/D, with further development wells planned. Cumulative production to date is approximately 2880 BCF.
Fig. 1. Location map. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. UnitedKingdom oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 871-880.
871
872
H. RICHES
The Viking complex is located in the Southern North Sea Gas province, in 30 m of water, approximately 140 km E of Lincolnshire (Fig. 1). The area covered by the Viking Gas Field comprises UK Block 49/12a and the northern halves of blocks 49/16 and 49/17. The original complex contained nine developed Rotliegend accumulations (Reservoirs A, B, C, D, E, F, G, Gn & H) which can be subdivided into North and South areas (Fig. 2). North Viking area is some 16 x 3 km and consists of an asymmetric anticline, comprising the Viking A, F, H and Fs reservoirs. The South Viking area is structurally more complex and includes the remaining accumulations. The entire Viking complex contains approximately 3.2 TCF gas-inplace and at its peak supplied about 10% of Britain's natural gas requirements. Rotliegendes aeolian and fluvial sandstones, deposited during the Early Permian, form the reservoir. The field name, Viking, reflects the 'V-Fields' convention established by Conoco (UK) Ltd in the early 1970s for its Southern North Sea gas fields, whilst the name Phoenix, reflects the 'rebirth' of this mature area via a new development.
History The acreage was awarded in September 1964 to the Continental Oil Company as part of the Licensing Round 1. In January 1966, the National Coal Board (succeeded by the British National Oil Corporation and later Britoil plc) farmed-in 50% to the blocks. The licence (P033) is held equally between BP-Amoco and Conoco (UK) Ltd (Operator). The Viking A Field was discovered in March 1969 by well 49/12-2, and the thickness of Rotliegendes Sandstone determined by the early wells on Viking A was a fairly consistent 500 ft (152 m). A gaswater contact (GWC) was established later that year when 49/17-5
Fig. 2. Viking/Phoenix development map.
was drilled into the Viking H Reservoir to the SE. Although the A and H fields have the same initial GWC of 9680 ft (2950 m) sub-sea, pressure tests indicate separate drainage. In 1973, wells 49/12-4 and 49/12-5 proved a down faulted area of Viking A to be gas-bearing (F Reservoir), with a separate GWC of 10 140ft (3091m). These discoveries were developed by a five-platform complex situated over the A Reservoir. The first production well, AD1, was drilled in January 1971. Viking A came onstream in October 1972 and after producing some 1124 BCF ceased production in 1991. Further exploration in the South Viking area, resulted in the discovery of the D Reservoir in 1968 by well 49/17-2. The earlier 49/17-1 well, completed in December 1965, found 40ft (12m) of gas-bearing Rotliegendes Sandstone 9050ft (2758m) sub-sea on the margin of the present Viking C pool. 49/17-3 discovered the B Reservoir to the NW of the C structure, with a separate GWC. Subsequent exploration drilling located C, G and Gn accumulations, all with different GWCs. A total of three main platforms and five unmanned satellite platforms were installed to tap these reserves. The first production well was drilled in October 1972, and Viking B came onstream in August 1973. Renewed exploration, beginning with the acquisition of a 3D seismic survey in 1993, followed up by the successful re-appraisal of the previously un-economic Wx and Fs reservoirs in 1995 has led to the rebirth of this mature area, captured within the Phoenix Development, which came on stream in 1998.
Structure Regional structural styles of the Southern North Sea have been well documented by numerous authors (Glennie & Boegner 1981; Arthur 1993; Glennie 1984, 1990; Hooper & More 1995) and hence
VIKING FIELD
873
o o
Fig. 3. Viking geoseismic section along A-N.
only a general overview as it pertains to this area as described here. The Sole Pit Basin, a locally active depocentre within the more regionally extensive Anglo-Dutch Basin, was initiated during the Early Permian. The Viking Area lies to the NE of the Sole Pit axis in an area of complex Rotliegendes structure, gently pillowed salt and relatively simple overburden (Fig. 3). During the Late Cretaceous and mid Tertiary the basin underwent several phases of inversion (Glennie 1997; van Hoorn 1987; Walker & Cooper 1987), resulting in the formation of many of the present day structural features. Rotliegendes sediments lie unconformably on the partially eroded surface of block-faulted Carboniferous, which had been gently folded during the Variscan Orogeny. The Rotliegendes in the Viking area comprises continental aeolian dune, fluvial, and sabkha deposits, associated with a major erg system developed in Quadrants 48 and 49. The northerly extent of Viking coincides with the northern margin of this erg environment. Further north and NE towards the North German Basin, silts and shales become the dominant Rotliegendes lithology. The Variscan NW-SE structural grain, established in the Carboniferous, persisted throughout the Rotliegendes influencing depositional trends and sedimentary environments. These major lineaments also controlled the block faulting and inversion of the reservoir during subsequent Late Cimmerian tectonism. Two major trends of faulting exist at Rotliegendes level. The dominant trend is NW-SE, along which the F/Fs/Wx/Gn accumulations, and most of the Southern North Sea Fields, are aligned. These faults can persist for several kilometres, and have throws of up to 1300 ft, as between the Viking A structure and F/Fs (Fig. 3). These originally normal faults were prone to reverse reactivation during times of inversion. The more subtle, though locally persistent second trend consists of major lineaments sub-orthogonal to the first, running NNE-SSW. The vertical offset across these lineaments is often small, and sometimes below seismic resolution - indeed they are invariably difficult to define without the benefit of 3D seismic. These lineaments often form narrow, (typically 200 m wide), graben like features with the bounding faults tending to converge at depth into near vertical faults. A third structural grain, that is most apparent in the Fs structure, is oriented ENE-WSW. These are normal
faults with generally small throws, which tend to terminate against the NW-SE trending faults.
Stratigraphy The geological succession present in Viking is typical of the UK Southern North Sea (Ziegler 1975) (Fig. 3). The Viking reservoirs comprise continental deposits of the Lower Permian Rotliegendes Group. The Leman Sandstone Formation dominates the field and passes laterally into the Silverpit Formation of silts and shales to the north. The Rotliegendes sediments lie unconformably on gently folded Carboniferous strata. A large regional Carboniferous anticlinal structure extends NW-SE through blocks 49/16 and 49/17, exposing Westphalian A subcrop along its crest and successive younger Westphalian units on its flanks. Above the Rotliegendes lie the Permian Zechstein evaporites, which vary greatly in lithology and thickness, but provide an effective seal. The Werra, Stassfurt, Leine and Aller Groups, corresponding to Z1, Z2, Z3 and Z4 cycles are all represented in the Viking area. The Zechstein is dominated by mobile halites with interbedded anhydrites and carbonates. The Leine Group, Plattendolomit Formation, occurs extensively over the area, but is discontinuous and frequently rafted out. The Zechstein sequence is overlain by conformable Triassic beds whose succession falls into two major groups: (1) the Bacton Group represents a phase of clastic deposition of sandstones, shales and mudstones; (2) the Haisborough Group is largely a fine-grained clastic and evaporitic sequence. The Triassic is the thickest sequence present and represents a fairly consistent 4000-4500ft (1219-1372m) of sediments. Jurassic siltstones and shales of the Liassic Group overlie the Triassic strata. Isolated occurrences of the Red Chalk Formation of the Lower Cretaceous Cromer Knoll Group are found to the NE of the North Viking monocline. In contrast, Upper Cretaceous Chalk is widespread, overlying the Jurassic sediments along a major unconformity. Variable thicknesses of Quaternary and Tertiary complete the succession in this area.
874
H. R I C H E S
,<
E
o,) 03
(~) q~d~(] o!tus!os
,4
VIKING FIELD
Geophysics One of the key elements that has enabled Conoco and their partners to realize the remaining potential within the Viking area has been through a major re-investment programme that commenced with the acquisition of 3D seismic in 1993, and marks one of the key advancements made since Morgan (1991).
Seismic data The Viking Field was originally discovered using a conventional 2D seismic grid of about 1 km x 89 The first seismic survey (12fold, aquapulse) was shot in 1969 and was not migrated. Since then several surveys have been acquired, culminating in the acquisition of a 3D survey in late 1993. This covered approximately 367 square kilometres over the central portion of the Viking Field in order to more clearly image the Viking Extensions, as they were known at the time. Line orientation was NW-SE, parallel to existing Rotliegendes structural trends and coinciding with operational requirements to take best advantage of ocean tides in the shallow waters. Acquisition ended in February 1994 and processing was completed the following October.
Mapping and depth inversion For purposes of mapping, two gross intervals were evaluated. The overburden, (sea floor to top Zechstein) and the Zechstein itself (Fig. 3). Within the overburden interval, four layers were used for velocity control, whilst in the Zechstein a three layer model was employed. The 3D time migrated image quality is generally good to excellent. However, a combination of 2D ray tracing of selected profiles, and a small map migration project, clearly demonstrated lateral mispositioning errors inherent in the time migrated data. These errors, of up to 360 m, were a result of the inability of the time migration process to take into account ray path bending caused by areas of steep dip and rapid lateral velocity variation within the overburden. It was therefore decided to proceed with a post-stack depth migration of the Viking Area 3D Survey in order to generate a well imaged and more accurately positioned database for the interpretation of the Viking Extensions, namely the F/Fs/Wx/Gn structures. The velocity model built for the map migration project, based on the original depth conversion velocities, was used for the depth migration process. This original velocity model was derived from a five layer depth conversion project that followed the interpretation of the time migrated 3D volume in 1995. Velocity functions were derived for five intervals, Tertiary, Chalk, Jurassic, Triassic and the Zechstein, from the analysis of fifty exploration and production wells drilled within the 3D area. The Zechstein was divided into three units: the Werranhydrit, Plattendolomit, and the remaining 'halite'. The final velocity model was verified by 2D pre-stack depth migration of selected lines across the area. In structurally complex areas, imaging of the Top Rotliegendes surface has been improved significantly by the 3D data (Fig. 4). A key result of these data has been the ability to place in proper context the spatial relationship between neighbouring fault blocks.
Trap The F/Fs structures are comprised of a series of N W - S E trending fault blocks and terraces lying in the hanging wall, and to the SW, of the major fault that controls the Viking A structure (Fig. 3). The Fs structure occupies a secondary footwall associated with an antithetic fault to the Viking A structure and has up to 850 ft of relief. The F structure occupies the site of a former graben immediately adjacent to the Viking A structure and has up to 750 ft of relief. Both structures have been deformed by inversion, resulting in both
875
compressional and preserved extensional internal geometries. Fs is separated by a NNE-SSW trending lineament (with a throw of typically 100 ft) and NW-SE trending fault (with throws between 300 and 700 ft) from the F reservoir. The fault between the Viking A structure and F/Fs completely offsets the Rotliegendes section except at its most northwesterly tip. The bounding faults at the northwesterly limit of the accumulation, (with throws between 100 and 400 ft), are required to be sealing. Dip closure limits the accumulation to the NW, SW and SE. The Wx structure lies to the south of F/Fs and is a N W - S E trending, north-easterly dipping, fault block that is interpreted to be a hanging wall 'pop-up', formed by reverse rejuvenation of a pre-existing normal fault. Up to 1300 ft of relief is mapped. Wx is separated from the Alison Field to the N W by a fault with the northerly lineament trend, with a throw of between 100 and 300 ft. The concave fault that controls part of the north-easterly closure, (the remainder being controlled by structural dip) has throws of up to 1450ft, and is required to seal in order to separate Wx from the dry hole of 49/17-6. Only to the SE does it fully offset the Rotliegendes section. The afore-mentioned reverse fault, seals and separates Wx from Gn (Fig. 3), here again there is insufficient throw to consistently offset the entire Rotliegendes (the throw varies between 400 and 800 ft). The Gn structure is located within the palaeo-footwall terrace, immediately SW of the Wx fault, that now lies downthrown to the latter. This structural interpretation is supported by well data that shows depth of burial induced diagenetic deterioration of reservoir properties in the currently shallower Wx accumulation. Up to 600 ft of relief is seen between the crest of Gn and its gas-water contact. A NNE-SSW trending lineament fault, with throws between 150 and 700 ft, limits the reservoir to the SE. Structural dip controls the accumulation to the SW.
Reservoir The Leman Sandstone Formation of the Permian Rotliegendes Group forms the reservoir of the Viking Gas Fields. The reservoir sediments were deposited in a generally arid, continental environment and comprise' two main facies groups: aeolian, providing the optimum reservoir quality; and locally well-developed fluvial-wadi and lake-margin sabkha fades. The facies associations are interpreted as transitional between the Silverpit sabkha lake to the north and the major dune fields to the SW. The Leman sands thicken regionally to the SW from 430ft (131m) on Viking A to 720ft (220 m) across the South Viking area. Thickening of the Leman Sst Formation across the major faults and comparison of regional geological sections suggests that faulting exerted some control on sedimentation during the Early Permian. Zonation within the Leman Sst. is clearly defined within the North Viking area, (A, H and F/Fs fields), with the thick dune sequences, Zones A, C and E interlayered with the tight impermeable sabkha horizons of Zones B and D. This zonation however becomes less well defined to the south as the sabkha facies significantly reduces in favour of predominantly dry aeolian facies (Fig. 5). In general reservoir quality also improves markedly in this direction, except within the area along the N W - S E trending inverted 'pop-up' feature, within which Alison, Wx, Yx, Lx and Bn are situated (Fig. 2). This extreme degradation in permeability is believed to be due to the Rotliegendes along this trend having been originally buried to much greater depths than neighbouring areas (Fig. 3), prior to subsequent inversion. Air permeabilities of < 1 mD are ubiquitous throughout the reservoir section along this trend, whilst areas immediately adjacent to Wx, such as Gn (Figs 2 & 3) have significantly improved reservoir quality with permeabilities of over 200 mD. Log correlation, core description and petrographical studies permit reservoir zonation into five units (Fig. 6). Zone F: Consisting of fluvial sands with local lake-margin silts and lacustrine shales. The sands are generally poorly sorted and argillaceous, with average porosities in the region of 10-1.5% and
876
H. R I C H E S
Ill |m
r
Z
I
u_
"x e~l
"7 P~
z
.d '3
.~= ;> o
I ,~
F--
9'
z
o
o
~d d0
VIKING FIELD
877
Rotliegendes Zonation Gamma Ray 8.o0
CALIPER
o.oo
GRAPI
IN
18.oo
Depth (feet)
lOO.OO
~,ii~
Density eu
4~.oo 1.95
-~.oo
GM/CC
2.95
.,.;
Restistivity OHM-M ~oo.oo
0.20
OHM'M
i, - " "
,-'.'" %
,,%.
~"
~ ("
<--I
.....
~
_~"
1
[~." [':" ,~i
...............: . - . ~
~
......
\l
~..( .,
....-..." :,. :~:, ... X . . . . . . . . . . . .
.:.:.:.:.:
i!:!:!~::
:k
:::T:::: .....
,,
~ >
ZONE B Lake margin sabkha silts ......~ ...........
?:
ZONE C Dominant fluvial with minor aeolian sands
r
ZONE D Lake margin sabkha silts and fluvial sands
....
: : : : 5 :j' 9:.:.: : , ~ r
. . . . . . . . . . . . . . . . . . . . . . . .
.,
..........
t
f
.'. ".'." t,
.t ~ ~,..,
j
I
,'~ ..........
,~
,
~
.
~
....
.................................
Lake margin sand rich sabkha deposits
--
[
:: ;."
1t~.30
ZONE A
............. \ .................................... ...........................................................
~=, . ::.:,t : : : :: : ~. 9 ....:.:.:,,, ...:;~.
....................................
. ~
::::::::::: .:.:-:.:.:. "i" ~':" i': %...... ..... .'.'.'.'.'
.
=:=:==.
.
:
'
/ I
....
::,
. . I ..~
( : ............. ..%-..-.. :i;:.i:::::: ................................ ~ ......... t :;::
if!:
:
.
~2 " - ' ' - - - ~ "
",~ii J i~]~i
.................................. ~__".;i.!::!.:~!~,.............. ..~!
, , ; :
.
"i'i'i'i'i
,.t
,
Reworked fine grained sands (Weissliegendes)
"7:'X':"
;i"
................................................. . . . . .
.
[']" ]" ]" ['[
%........ i~"~'~"~
~,
I
",
:
"]" [' [' i" i'
.,',',
~'~::!'"
: L
0.00
.'.'.'.'.'.
~ .:;-
;
i
PU
".'.'.'.'." i.~.:.i.i.~
~...~ .^.,...^.~ :::::::::::.:.:.:.:.:.
~
~'.4.~:~: ................................ _ _
~.00
..........
......................................................................................................... ~ ........... .'.' .'.'. . ...... ,'.~ ........
~il.
~=~- ~....:....:.~ ~ . . . . . .
4O.OO
21212121112
";: '~.
~ :~:~
~40.00 U S E C / F T
Reservoir Zonation
ZECHSTEIN
~
~'~...... ~ _ _
Water Saturation
i
.............
'~:
i
Sonic
200.00
'
~i 0'3
Lith.
o.~o
."
::
....
== :
. . . . . I . . . . . " . " . " , " . ", . . ... % ......
ZONE E
Aeolian Dune Sands
. . . . . . . . . . ".'.',',~,
.
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
.
.
.
.
.
.
.
ZONE F Fluvial sands and lake margin sabkha silts
%..
iiiiiiiiiii CARBONIFEROUS
Fig. 6. Phoenix type log - North Viking area.
variable permeabilities, due to the presence of detrital clays, ranging from < 1 mD to 100 mD. Z o n e E: Aeolian dune sediments up to 300ft (191 m) thick. These sands are generally fine to medium grained, clean and well sorted (typically bimodal) with porosities ranging from 15-25% and permeabilities from 5 m D to over 100mD. In both North and South Viking this zone is the most productive unit. Z o n e D: A continuous horizon of lake-margin sabkha silts and fluvial sands overlies the aeolian dune sands and can be correlated across the region. This zone represents a regional climatic change and corresponds to a rise in the groundwater table and a southward expansion of the Silverpit desert lake to the north. Reservoir quality
varies widely from moderate to very poor, with porosities averaging 5-15% and permeabilities <0.2 mD and 10 mD, the unit acting as an effective vertical permeability barrier. Z o n e C: In the North Viking area, this zone comprises mainly fluvial sands with minor aeolian dune deposits in places. Average porosities vary from 8-12%, and permeabilities from 1-100 mD. In other areas, particularly in South Viking, this zone comprises predominantly aeolian deposits with correspondingly better reservoir quality. Z o n e B: Marks a return to lake margin sabkha deposition within the northern area of Viking. Corresponding to a southward expansion of the Silverpit desert lake, albeit less than that seen in
878
H. RICHES
Zone D. Reservoir quality is again very poor, with the unit acting as an effective vertical permeability barrier. Zone A: The zone as a whole comprises a relatively continuous horizon of reworked fine-grained sandstones (Weissliegendes) underlain by lake margin sand rich sabkha sediments. The homogenized and cemented nature of the upper section of Weissliegendes results in low porosities and permeabilities. The thickness of this uppermost unit is highly variable with the Weissliegendes absent in some Viking wells.
tion from these near vertical wells was uneconomical. The goal of the Fs well was to test the viability of gas production from the flank of the structure that was shown to have poor reservoir quality in the FD3 well, which tested at 2.6 MMSCF/D. The well encountered significantly better than expected reservoir properties, with porosities ranging from 11-17% and permeabilities up to 800 roD. The well was subsequently tested at a restricted rate of 53.2 MMSCF/D, with unrestricted estimates of around 100 MMSCF/D.
Viking area reappraisal and renewed growth
Wx. The second well, 49/17-12, was drilled on the Wx structure in October 1994. Although already 'discovered', albeit down-dip, by the 49/17-4 well in 1969, this well encountered low permeability reservoir and tested at uneconomic rates and so the Wx development was not pursued at that time. The 3D seismic interpretation confirmed not only the existence of the primary Wx structure but the addition of a previously poorly imaged reservoir compartment, named Yx (Fig. 2), which was now seen to be an up-dip extension of Wx. The well, drilled at the structural crest encountered one of the thickest gas bearing reservoir sections in the Viking area (835 ft), with no gas-water contact encountered. However, the reservoir exhibited an average permeability of 0.3 mD, and on test the gas rate declined from an initial 14.4 MMSCF/D to 8.8 MMSCF/D in 24 hours. The well was re-entered in April 1995 and a fracture stimulation treatment was performed. Hydraulic fracturing yielded a maximum flow rate of 43 MMSCF/D during an extended cleanup and flow test and illustrated the effectiveness of this stimulation method and ensured that projected reserves of c. 200 BCF could be attained from the Wx structure.
During the early 1970s, when the major Viking reservoirs were undergoing development, only those accumulations that showed significant potential for high sustainable deliverability were brought on stream. Structurally complex areas and structures testing at low gas rates were left undeveloped and remained poorly understood from a reservoir evaluation standpoint. Understanding the structural and reservoir complexities of these undeveloped gas bearing structures has proved to be critical in demonstrating that these prospects could provide viable opportunities for growth. Appraisal by further drilling in conjunction with 3D seismic imaging, applying horizontal technology and adopting a flexible and innovative approach in evaluating remaining gas potential has provided opportunities for realising additional reserves. In addition due to new gas contract terms, low pressure compression also became economically feasible, thus ensuring that recovery of reserves from the old producing reservoirs would continue into the next millennium.
Low pressure compression The installation of low pressure compression on the B platform involved the rewheeling of the existing compressors to create an additional 100 psig drawdown. This has allowed the wells draining reserves from the B, C, D, E, G and H fields to produce beyond their initial predicted life. The additional reserves recovered are predicted total approximately 70 BCF.
Appraisal opportunities In the early 1970s, several exploration wells were drilled into promising structures but tested at low gas rates and consequently were abandoned as un-economic at that time. These accumulations Fs, Jx, Wx and Kx were thus left undeveloped (Fig. 2). Over twenty years after drilling these 'non commercial' Viking Extensions, methods to enhance deliverability using, for example, hydraulic fracturing or horizontal drilling, have proved to be critical in realising their true potential of between 500 and 600 BCF.
Phoenix development The first phase of the Viking re-appraisal programme consisted of the drilling of four new wells, all of which tested at significant gas rates. Jx and Kx successes resulted in stand-alone, with offtake back to the LOGGS platform (Fig. 1). Within the Viking Field area the successful re-appraisal of the non producing Fs and Wx structures, combined with the remaining potential in the F and Gn accumulations led to the rebirth of this mature area and the resultant Phoenix Development.
F/Fs.
The Fs 're-discovery' well, 49/12a-9, was spudded in March 1994 on the SW facing flank of the faulted anticline that contains the A and F reservoirs (Figs 2 & 3), which were abandoned in 1995. The latter had produced 65 BCF of gas up to cessation of production in 1991 from three wells drilled from the A complex. However, the reservoir quality in the wells was poor and continued produc-
Gn. The Gn reservoir was developed and partially depleted, as a satellite to the Viking B Production Facility. Viking Gn is unique amongst the Viking Area reservoirs in that clear aquifer suppor t has been observed through material balance analysis and from the gas-water contact rises observed in the wells. The watering out of the down-dip wells left 'attic' gas in the crest of the structure adjacent to the main fault boundary within Wx (Fig. 4). In order to maximize recovery from this structure, the development has provided an opportunity to drill a horizontal well along the Gn crest to minimize water 'coning' effects and to maximize productivity in order to outrun the encroaching aquifer.
Facilities The Viking Field, including Phoenix, has a total of 11 platforms drawing gas from 15 wells. The Phoenix Development consists of two not-normally-manned six-slot platforms. The F/Fs jacket is positioned at the surface location of the K1 development well (the original 49/12a-9) and the Wx/Gn facility is sited at the surface location of the L1 well (the original 49/17-12) (Fig. 2). Gas from the B Complex and its computer controlled satellites is metered and piped 11 km to the A Platform through a 24-inch diameter pipeline. At the A Complex, the Phoenix and Viking gas co-mingles and enters a 28-inch pipeline which extends 140km to Theddlethorpe (Fig. 1).
Initial gas-in-place (GIIP) and reserves The GIIP for all Viking area producing fields has been estimated at 3835 BCF of which approximately 2930 BCF have been produced (as of Dec. 1999) reflecting a recovery of nearly 77%. The three largest fields eave produced 76% of the total reserves from the A (t124BCF), E (660BCF) and C (545BCF) reservoirs whilst the B, H and G reservoirs have produced an additional 17% and the D, F, Fs, Wx and Gn represent the remaining 7%.
VIKING FIELD
879
"O o 0~
E
E
v
rr r
._o "6 "O O 0_ 0o
Fig. 7. Total Viking production.
Permeability (range) Productivity index
Reserves The Operator's estimate of recoverable gas reserves for the Viking Field (A, B and associated satellites) and Phoenix are 2895 and 507 B C F respectively. The p r o d u c t i o n profile for Viking and Phoenix up to N o v e m b e r 1999 is shown in Figure 7. The author wishes to thank ConocoPhillips UK Ltd and its partner BP for permission to publish this paper. In addition I would like to thank Dr L. Richmond for her editorial comment as well as all the production staff within ConocoPhillips UK Ltd, who have over the years endeavoured to make the Viking area such an outstanding success story.
0.1-100 m D + highly variable 4-110 MSCF/D/psi
Hydrocarbons
Specific gas gravity Calorific value Condensate yield Specific condensate gravity
0.615 10.29 btu/SCF 4-5.5 BBL/MSCF 0.738 (60 ~ API)
Formation water
Salinity Resistivity
220 000 ppm 0.017 ohmm
Reservoir conditions
Viking Field Gas Complex data summary Trap
Type Depth to crest Lowest closing contour Hydrocarbon contact Gas column
Tilted/inverted fault blocks Variable 8000-9000 ft Variable 9000-10 200 ft Variable 9000-10 200 ft Variable (700 ft max. in the Rotliegendes)
Reservoir
Formation Age Gross thickness (range) Sand/shale ratio (range) Net/gross ratio (range) Cut off for N/G Porosity (range) Hydrocarbon saturation
Leman Sandstone Formation Permian 400-700 ft 90:10 50-100% Variable 7-25% 50-60%
Temperature Pressure, initial Pressure gradient in reservoir
170-220~ (65-80~ 4150-4670 psia 0.048-0.085 psi/ft
Field size
Area Gross rock volume Initial gas in place Viking Phoenix Recovery factor Viking Phoenix Recoverable hydrocarbons: Gas Viking Phoenix Condensate Viking Phoenix
2990 BCF 845 BCF 97% 60%
2895 BCF 507 BCF 15.6 MMBBL 3.6 MMBBL
880 Production Start-up date Viking Phoenix Deliverability Viking Phoenix Maximum contractual deliverability Cumulative production (October 1999) Number/type of wells Viking Phoenix Secondary recovery method(s)
H. RICHES
August 1972 November 1998 45 MMSCF/D (31 / 12/99) 200 MMSCF/D (31/21/99) N/A 2880 MMSCF gas
10 producers 5 producers N/A
References ARTHUR, T. J. 1993. Mesozoic structural evolution of the UK Southern North Sea: insights from analysis of fault patterns. In: PARKER, J. R. (ed.) Petroleum Geology of Northwest Europe. Geological Society, London, 1269-1279. HOOPER, R. J. & MORE, C. 1995. Evaluation of salt-related overburden structures in the U.K. Southern North Sea. In: JACKSON, M. P. A., ROBERTS, D. G. & SNELSON, S. (eds) Salt Tectonics." A Global Perspective. American Association of Petroleum Geologists, Tulsa, Memoir, 65, 251-259.
GLENNIE, K. W. 1984. Outline of North Sea History and Structural Framework. In: GLENNIE, K. W. (ed.) Introduction to the Petroleum Geology of the North Sea. Blackwell Scientific Publications, London, 34-77. GLENNIE, K. W. 1990. Rotliegend sediment distribution: a result of late Carboniferous movements. In: HARDMAN,R. F. P. & BROOKES,J. (eds) Tectonic Events Responsible .[or Britain's' Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 127-138. GLENNIE, K. W. 1997. History of exploration in the Southern North Sea. In: ZlEGLER, K., TURNER, P. & DAINES, S. R. (eds) Petroleum Geology o f the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 5-16. GLENNIE, K. W. & BOEGNER,P. L. E. 1981. Sole Pit Inversion Tectonics. In: ILLING, L. V. & HOBSON, D. G. (eds) Petroleum Geology of the Continental Shelf of North West Europe. Institute of Petroleum, London, 110-120. MORGAN, C. T. 1991. The Viking Complex Field, Blocks 49/12a, 49/16, 49/17, UK North Sea. In: ABBOTTS, I. L. (ed.) United Kingdom Oil and Gas Fields: 25 Years Commemorative Volume. Geological Society, London, Memoir, 14, 509-515. WALKER, I. M. & COOPER, W. G. 1987. The structural and stratigraphic evolution of the northeast margin of the Sole Pit Basin. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of N W Europe. Geological Society, London, 263-275. VAN HOORN, B. 1987. Structural evolution, timing and tectonic style of the Sole Pit inversion. Tectonophysics, 137, 239-284. ZIEGLER, W. H. 1975. Outline of the Geological History of the North Sea. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf o[ North West Europe, Volume 1. Applied Science Publishers, London, 165-190.
The Waveney Field, Block 48/17c, UK Southern North Sea D. R. S. B R U C E 1 & P.
REBORA 2
A R C O British Ltd., London Square, Cross Lanes, Guildford, Surrey GU1 1UE, UK 1 Present address." GDF Britain Ltd, 60 Grays Inn Road, London W C 1 X 8 L U 2 Present address." B P Exploration Company Ltd, Chertsey Road, Sunbury on Thames, Middlesex TW16 7 L N
Abstract: The Waveney Field lies entirely within UK block 48/17c in the Southern Gas Basin, approximately 46 km north-east of the Norfolk coast line and to the west of the Mobil's Lancelot and Guinevere Fields. The water depth is approximately 75 ft. The field was discovered in 1996 by the 48/17c-12 well and brought on production in 1998 following a 14 month fast track development program and the drilling of two 2500 ft horizontal wells. The gas field is a low relief northwest trending asymmetrical anticline, with a length of 6 kms, and a maximum width of 2 kms. The crest of the structure is at approximately 7748 ft. TVDSS. The original reserves were 84 bcf. The reservoir predominantly comprises aeolian dune sandstones of the Upper Permian Rotliegend with an average reservoir quality range of 7-10% porosity and 0.1-200mD permeability. The hydrocarbons are sourced from down dip Carboniferous Westphalian Coals.
Location
History
The W a v e n e y Field is located in Block 48/17c, licence PL 780 (Fig. 1), approximately 46 k m N E of the N o r f o l k coast line and 7 k m to the west of the Mobil's Lancelot and Guinevere Fields. The water depth is approximately 75 ft. The licence was a w a r d e d in the U K 12th licensing r o u n d in June 1991 and comprises 82.3 sq. km. A R C O British Ltd. (ABL) currently operates the block with an 86% interest and O r a n j e - N a s s a u Energy as partner with 14% interest.
The first well on this part block was 48/17-1 drilled in 1969 by Mobil. The well penetrated Rotliegend reservoir sandstones but did not e n c o u n t e r h y d r o c a r b o n s . T h e W a v e n e y Field was discovered by the second well in this part block, 48/17c-12 (Fig. 2). This was a c o m m i t m e n t well, drilled to a T D o f 9042ft. R K B into the Carboniferous. The top Rotliegend was e n c o u n t e r e d at 7904ft. R K B . The well discovered 100 ft. of pay in good quality Rotliegend
Fig 1. Structural elements and location map.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields',
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 881-891.
881
882
D.R.S.
B R U C E & P. R E B O R A
d.
o
e4
WAVENEY FIELD
883
unconformity. Regional thermal subsidence during the Early Permian resulted in the deposition of a sequence of continental red beds forming the Rotliegend Leman Sandstone Formation and Silverpit Shales Formation. Flooding of the basin by marine waters during the Late Permian ended the desert conditions and resulted in the deposition of a cyclical sequence of evaporites and carbonate of the Zechstein Supergroup. A return to more continental red bed deposition occurred at the beginning of the Triassic period with only minor influences from shallow marine sedimentation. Marine conditions prevailed in the Jurassic, infilling of the extensional rift-basin commenced in the Triassic. This resulted in the formation of the Sole Pit Trough in the northeast. The post salt sequence contains a major northwest trending graben system extending from Quadrant 41 to the Hewett Shelf, known as the Dowsing Graben System (DOGS) (Coward & Stewart 1995). This Mesozoic graben system which partly overlies the eastern portion of the Waveney Field (Fig. 4) is apparently related to, but detached from the DFZ by the Zechstein evaporites. The DOGS formed by both extension and gravity sliding of the post salt section into the basin, as a result of basement extension on the underlying DFZ (Coward & Stewart 1995). The Waveney structure is interpreted to have initiated by reactivation of Permian faults during the Triassic to Early Cretaceous rift event. Sediments of the Upper Cretaceous were deposited in the post rift thermal sag basin. These include the shallow marine Spilsby Sandstone Formation sourced from the northeast and the Speeton Clay Formation. Further regional subsidence led to the deposition
sandstone and tested at 40.5 MMSCF/D. Subsequent development was strongly influenced by the acquisition and interpretation of 3D seismic. The field was developed during a 14 month fast track program with two horizontal wells completed within the top layers of the reservoir.
Discovery method The original discovery well 48/17c-12 was a commitment well drilled on 1991 vintage 2D seismic data that was interpreted and mapped to show a very low relief structure up dip of the 48/17-1 dry hole.
Geological history The field lies on the SW margin of the Gas Basin, north of the London Brabant Platform and east of the East Midland Shelf. It is separated from the Sole Pit Trough to the NE by the pre-Zechstein Salt Dowsing Fault System (DFZ) (Coward & Stewart 1995). The general stratigraphical column for the area is illustrated in Figure 3. The oldest rocks penetrated in the area are Late Carboniferous in age. These were formed during a period of prolonged fluvial and deltaic deposition in which thick coal-bearing sequences were deposited. Deformation, uplift and erosion during the Variscan orogeny at the end of the Carboniferous formed the Base Permian
STRATIGRAPHY '
'
O LLI
CHALK
DEPTH
LITH. I
I I
,
GROUP
I
I
Iiiii I
I
ft. TVDSS
I I
SEISMIC
PICKS
'.
i
I BASE RED CHALK
CROMER (j
HUMBER
KNOLL GROUP
/ WEST
SOLE GROUP
!~,~
2000
~, h~ ~
....- :':~,~ BASE CRETACEOUS ,.............................TOP CORALLIAN
< rT"
LIAS
GROUP
~L~ I
3003
I
1 s D
TRITON
o~ oO r~
FORMATION
DUDGEON
FORMATION
DOWSING
FORMATION
AA
................................. TOP TRIASSIC
A A A A
~XXXXXXXXXX~
4000
03 s <
s=
i}~{~;~21~{
;~
,
................................ TOP BUNTER SANDSTONE BUNTER
SANDSTONE
...' .. .' .. '...'...' .. ' . ' . ' . " -- 5000
So BUNTER
SHALE 6000
Z3 / Z4 HALITE
-<
=L
~.
N ROTL.
co O
I
PLAI II:NDOLOMIT S T A S S F U R T HALITE BASAL ANHYDRIT HAUPTDOLOMIT
~ X
~
TOP ZECHSTEtN
XX)OCXXXXXX'
'
~
,X"X X k " Z ' X Y ~( • X X X Y6
i/~ ~/ // // z////~ .~.x ~~.x ~ x . ~ , ~ \ ~ 9 / / i / z' ,1, i ,( /,/ ~/ ~ i ~/ /,/ [
TOP PLATrENDOLOMIT 7003
WERRAANHYDRIT LEMAN
SANDSTONE
MILLSTONE
-T-.~___..-~-""'"--'"""-8003
GRIT
O:
UJ
LL m
z O
t~
OL:
< [J
Fig 3. Stratigraphical column.
9003
TOP ROTLIEGEND
884
D.R.S.
B R U C E & P. R E B O R A
z
............................... -r.. ~
.............
"r .
~
+ i m
d +
;i eo
~..t ...............
"i
iI
L +
9
4
w
L~
S
m
1 ! 4...0
.=.
~,
C~
j-
Pq
"-.
~0
@ t~
8
r
ol z
,4
WAVENEY FIELD of the Upper Cretaceous Chalk. The Alpine orogeny during the Early Tertiary uplifted the Sole Pit Trough removing a significant portion of Upper Cretaceous sediments. Compression during this event may have modified the Waveney structure through inversion.
half of Block 48/18c and the eastern quarter of Block 48/17c. The graben is characterised by an anomalously thick low velocity Lower Cretaceous fill. Elsewhere the overburden is generally plane layered and relatively simple. Rollover of the Rotliegend surface occurs towards the south into a west-northwest trending fault. Two culminations occur, one to the east and one to the west of the 48/17c-12 well. Interpreted dip line (Fig. 6) illustrates the very low time relief of the Waveney structure (average Two Way Time structural relief of 20-25 ms). At Top Rotliegend level, three main fault trends have been interpreted from the 3-D data. These are NW, W-NW and an E-W trend. Within the field area, throws on these faults at Rotliegend level are small (40-140 ft). The trap is interpreted to be one of dip closure to the west, north and south and fault closure towards the east. The Upper Permian Zechstein sequence forms the regional top seal to the Rotliegend. Attribute mapping of the Top Rotliegend time interpretation from the 3D volume suggests the Waveney structure may be divided into two or three compartments. The 3D perspective shaded relief mapping shows two subtle fault trends that trend NW-SE (Fig. 7). Shaded relief mapping also clearly shows an east-west linear feature, interpreted to be a fault, between the main 48/17c structure and the 48/22-4 well to the south. Northward throw along this fault diminishes from a maximum of 40ft in the west to apparent negligible throw in the east. However at this eastern end of the fault, the dips of the reservoir in the hanging wall into the fault, are of similar magnitude to those further west, but seismic imaging appears insufficient to resolve the displacement at Top Rotliegend. Closure and separation from the 48/22-4 structure as indicated by different gas-water contacts and pressure regimes is therefore interpreted to be by fault separation. Varying the sun illumination (azimuth and elevation) of shade enhanced images has been particularly useful in highlighting
Geophysics The development well planning was based on interpretation of the Geco-Prakla TQ48 3D data volume acquired in 1996. The 3D survey, shot with a 2.4km cable, provided coverage over blocks 48/17c, 48/22 and 48/18c (Fig. 5). Apart from poor shallow resolution (<200ms) data quality is generally very good down to Top Rotliegend at 1.5 seconds (Fig. 6). The signal to noise ratio within the Carboniferous is poor. Eight key seismic reflectors representing major acoustic interfaces were mapped. These were the Base Red Chalk, Base Cretaceous, Top Corallian, Top Triassic, Top Bunter Sandstone, Top Zechstein, Top Plattendolomit, and Top Rotliegend (Figs 3 & 6). Time to depth conversion of this very low relief structure was achieved with a layer cake depth conversion model. Interval velocities from surrounding wells were used to create velocity functions. Depth residuals were investigated for geographical patterns and subsequently corrected using a contoured correction surface. Structural uncertainties exist primarily from the prediction of velocity variations of the shallow overburden, especally within the DOGS Mesozoic graben system (Figs 4 & 6). The 3D volume and associated attribute mapping enabled a detailed structural interpretation.
Trap Waveney is a NW-SE trending asymmetric anticline (Fig. 2 ) lying in most part, west of the DOGS Mesozoic graben (Fig. 4). This structurally complex graben trends east-west across the western :
885
o2~&':
1~
2,
!
53-<~24'N
9
i
":~
--~-
L1, L/2" 7.1 .
4
.j I
13 5,'~o2,~'N
I'~ i
53~t8'N !
i2
~53Ol8"N
!
O
3
WELLS USED IN GEOLOGICAL MAPPING
J
I e'!B'E
1~
|
4 !
2 mis
Fig 5. Map of 3D seismic coverage.
6 km I
886
D . R . S . BRUCE & P. REBORA
BASE CRETACEOUS TOP CORALLIAN LIMESTONE
TOP TRIASSIC r~ z o u u,! t/) z
TOP BUNTER SST.
!-
TOP ZECHSTEIN TOP PLATTENDOLOMIT TOP ROTLIEGEND
Fig 6. Seismic dip-line across Waveney Gas Field (A A') showing Mesozoic faulting.
directional trends in the 3D data set which were not apparent on the 2D seismic.
Reservoir
Depositional s'etting The depositional model for the Rotliegend in this area, is of an arid to semi-arid desert dominated by aeolian and fluvial depositional processes. Regional mapping of the total Rotliegend isochore shows that over Block 48/17c, the Leman Sandstone thins from 400 ft + to 200-250ft over an apparent regional high, separating the main Sole Pit Trough in the NE from a sub-basin located in blocks 48/21 and 48/22 (Fig. 8). The N-S cross-section (Fig. 9) shows the distinct thickening of the Rotliegend from 48/17b-5 on the high to 48/22-4 in the sub-basin. This palaeo-high extends NW from the 48/17c area into Pickerill in 48/1 lb and is interpreted to be a SE extension of the East Midland Shelf. The early Rotliegend (Zone 1) was a period of rapidly changing environments where both aeolian and fluvial processes formed an interfingering package of sediment. Based on the interpreted facies in the wells, the aeolian sediments appear to be formed dominantly in the south and are not so prevalent in well 48/17b-5. This may indicate the presence of a palaeo-geographical feature between the 48/17c-12 well and
48/17b-5, controlling the distribution of dune sands whilst maintaining a more permanent fluvial environment in 48/17b-5 during early deposition. This was followed by a period of wetter climate when widespread fluvial sediments were deposited across the whole area, forming a distinctive package (Zone 2) that can be correlated in all of the wells. As the climate again became more arid, widespread interdune deposits were developed reducing the fluvial deposits to the occasional ephemeral stream with very minor, small scale, localized aeolian dune fields. With increased aridity, large scale, wide spread dune fields swept across the area depositing a thick sequence 100 ft + of aeolian dune sandstones, which form the main reservoir target in this area, Zone 3. The end of the Rotliegend was marked by the Zechstein transgression which flooded the desert plain reworking the upper section of dune sands to form the Weissliegend facies, Zone 4 before depositing the Kupferschiefer unit, the first fully marine Zechstein deposits.
Reservoir quality The highest porosities and permeabilities are seen in the medium to fine grained, well to bimodally sorted Weissliegend and aeolian dune sandstones, which occur extensively in the upper section of the Rotliegend within Zones 4 and 3 (Fig. 10). The interdune facies show a decrease in reservoir quality primarily due to poorer sorting and a
WAVENEY
FIELD
887
~6
...a ,,._,
E
',e"
...,a
e.:
888
D . R . S . BRUCE & P. REBORA
Fig 8. Gross Rotliegend Isopach. higher clay content. The fluvial sandstones show the poorest quality due to the large variation in grain sizes and very poor sorting. On a regional scale by far the most important factor on reservoir quality is the eastward reduction in porosity due to the effects of burial and compaction followed by inversion within the Dowsing Fault Zone (DFZ) and Sole Pit Basin. However, structurally the Waveney Field lies on the western margin of the DFZ and is less affected than other fields in the vicinity. The mapped average porosities for the gross Rotliegend over Block 48/17c range from 12-14%.
Diagenetic history The majority of the Rotliegend sandstones in this area fall in the sublitharenite to litharenite field, with occasional subarkosic members. The main diagenetic controls on porosity and permeability in order of importance are: ferroan dolomite cements, quartz cements, and authigenic clays (chlorite and illite). The ferroan dolomite cements occur in two main forms, a euhedral rhombic ferroan dolomite cement, which tends to occur in Zone 4 and upper sections of Zone 3, and a more anhedral blocky ferroan dolomite cement. The euhedral rhombic ferroan dolomites generally occupy intergranular pore spaces, locally coalescing to reduce pore throat size, and are seen to be enclosed by later quartz and feldspar overgrowths and authigenic clays. They are interpreted to have formed during the early eogenic stages of diagenesis as a result of the interaction of marine waters and concentrated formation waters during the Zechstein marine transgression.
The anhedral blocky ferroan dolomites occur in both intergranular and secondary dissolution porosity (feldspar dissolution) and tend to enclose authigenic clays and feldspar overgrowths. They are interpreted to form during late stage mesogenesis and may be associated with Late Cretaceous to Early Tertiary inversion (Glennie et al. 1978) The quartz cements generally form euhedral prismatic syntaxial overgrowths to detrital quartz, enclosing grain coating clays and haematite and rhombic dolomites. They are interpreted to have formed during mesogenesis, after the introduction of acid pore waters formed by compaction and dewatering of underlying and interbedded mudrocks. The authigenic clays, particularly illites and chlorites, can regionally form up to 15% of the sandstone composition. Illites occur in two distinct forms, tangential grain coating illite and fibrous illite. It is the fibrous illite that has the greater effect on reservoir quality by bridging pore throats. Chlorites occur as both grain lining and pseudohexagonal honeycomb texture crystals, blocking pore throats and reducing permeability. Both illites and chlorites are formed during early mesogenesis with the introduction of alkaline pore waters.
Source Waveney is thought to be sourced by the Westphalian Coal Measures of the late Carboniferous sediments located to the ENE in the Sole Pit Basin. Peak gas generation occurred during the Middle Jurassic/Early Cretaceous. Migration occurred up faults
W A V E N E Y FIELD
889
o
c)
3
O
Z
"3
o'3
o,,,,i
890
D . R . S . BRUCE & P. REBORA
STRAT~
!?,
~OB
DEPTH
MO
~
GR
I~FStMtESlIJ~tCI'W
iJ
NP~ -15.00 140.00
I 9
F---
ZONE4
---!
~
~
ZONE3
DT
40,~
.......l H|
0.00
SW
t.00
il
0.00
k____a
L
L----
ram,
,*~llmm*, ZONE 2
L__
L_ )
N
iii Fig 10. 48/17c-12 petrophysical interpretation and zonation. that penetrated the Carboniferous and also through Carboniferous and Rotligend sandstones.
Table 1. Composition of co-mingled gas from Waveney wells 48/17c-
12z(W1) and 48/17c-(W2) Waveney Analysis
Hydrocarbons The gas is sweet with 86% methane, 0.6% carbon dioxide and a condensate/gas ratio of around 15BBL/MMSCF. An analysis is given in Table 1.
Exploration and development concepts The Waveney Field came on stream in October 1998 following a 14-month fast track development program. Two highly successful horizontal wells (best in class as per Rushmore Associates 9th Annual European Drilling Performance Review) were drilled, each targeting a 2400 ft section in the top 40 ft of the reservoir. The first development well was drilled re-utilizing the original 48/17c-12 well to drill a short radius high angle well. Due to overpressure in the Hauptdolomit, the horizontal section was kicked off in the Werraanhydrit. Using the Schlumberger 'inform' modeling package to monitor gamma ray, resistivity, neutron, density (porosity) and dip while drilling, the well was geosteered through the upper 40 ft of the reservoir primarily within Zones 4 and 3 (Fig. 2). The second development well was a new drill horizontal well, where again geosteering techniques were used to keep within the better quality reservoir of the upper zones. The wells were plant-constrained at over 70 M M S C F / D each. The surface facility is a Minimal Facilities Platform (MFP) tied into the Lancelot Area Pipeline System (LAPS) via a pipeline tee to the south of Mobil's Lancelot platform. Produced water is removed at the platform and gas is metered prior to entering the LAPS pipeline. Gas and condensate are exported via a 12", 8.2 km pipeline to the sub-sea tee and then via the LAPS pipeline to the onshore Bacton Gas Processing Terminal. Compression for Waveney is provided by an onshore compressor for the LAPS system at Bacton. The Waveney platform is remotely controlled from an onshore
Components Gas Water Nitrogen Carbon dioxide Helium Methane Ethane Propane N-Buane Iso-Butane N-Pentane Iso-Pentane Hexane Heptane Octane Nonane Decane (+) Total
mol% 0.197 2.739 0.593 0.061 86.301 6.073 2.122 0.553 0.170
0.243 0.243 0.270 0.15 ! 0.060 0.041 0.042 100.000
Condensate
mol%
Argon Nitrogen Carbon dioxide Helium Methane Ethane Propane N-Butane Iso-Butane N-Pentane Iso-Pentane Hexane Heptane Octane Nonane Decane Undecane Dodecane Total
0.011 0.240 0.317 0.006 27.113 6.974 5.278 2.667 2.176 2.127 2.251 7.836 9.492 6.001 6.595 5.280 3.946 11.710 100.000
Aromatic fractions N-C6 Benzene Cyclohexane Total
0.618 0.220 0.162 1.000
N-C7 Toluene Methylcyclohexane Total
0.561 0.160 0.279 1.000
Sampled at platform separator; temperature 50.5~ flow rate 84.0 MMSCF/D.
pressure 97.5bar(g);
WAVENEY FIELD
location at the ARCO British Ltd. Great Yarmouth Control Center. Maintenance crews visit at regular intervals. The maintenance philosophy is for m i n i m u m intervention over the life of the field. We would like to thank all the members of the Waveney development team both past and present, who have helped during the life cycle of this project. A special acknowledgment goes to Sandra Vincent for her help in compiling the paper, David Hood for his work on the seismic visualization, Faye Murray for her petroleum engineering contribution, Trevor Hill for his computing expertise and Oonagh Werngren for her continued support throughout the project. Finally we would like to thank both ARCO British Ltd. and Oranje-Nassau Energie B.V. for their permission to publish this paper.
Waveney Field data summary Trap Type Depth to crest Gas-water contact Gas column Pay zone Formation Age Gross thickness Net/gross ratio (av., all zones/range) Net sand cut off Porosity (av. all zones/range) Hydrocarbon saturation (av., all zones) Permeability (average/range)
Roll over anticline, with fault seal to southeast. 7748 ft TVDss 7884 ft TVDss (Log and RFT derived) 136ft
Rotliegend, Leman Sandstone Early Permian 200-250ft 0.98/0.9-1.0 4% porosity equivalent 13% / 7-20% 55% 12 mD/0.1-200 mD
Hydrocarbons Type Gas Condensate yield Gas expansion factor Formation water Salinity Resistivity
891
Gas Gravity 0.68 15 BBL/MMSCF 227 SCF/cu ft 200 000 ppm NaCI equivalent 0.055 @ 60~
Reservoir conditions Temperature Pressure Pressure gradient Gas Water
0.085 psi/ft 0.454 psi/ft
Field data Area Gross rock volume Recoverable gas Drive mechanism
1891.5 acres 119 000 acre/ft 84 BCF Depletion
184 ~ 3655 psia at 7748 ft TVDss
References
COWARD, M. P. & STEWART,S. A. (1995) Synthesis of salt tectonics in the southern North Sea, UK. Marine and Petroleum Geology, 12(5), 457-475 GLENNIE, K. W., MUDD, G. C. • NAGTEGAAL, P. J. C. i978. Depositional environment and diagenesis of Permian Rotliegendes sandstones in Leman Bank and Sole Pit areas of the UK Southern North Sea. Journal of the Geological Society, London, 135, 25-34.
The Windermere Gas Field, Blocks 49/9b, 4 9 / 4 a , U K Southern North Sea R. J. BAILEY 1 & J. E. C L E V E R Wintershall (UK) Ltd, Wimbledon, UK & Wintershall AG, Kassel, Germany 1 Present address." 5 Station Road, Southwell, Nottinghamshire NG25 OET, UK
Abstract: The Windermere Field, in the central area of the Southern North Sea gas province, exploits a variant of the Rotliegend-Leman Sandstone gas play. A thin, basal aeolian sandstone is top-sealed by lacustrine Silverpit Formation. claystones and sourced by the underlying Westphalian Coal Measures. Since the reservoir unit has no mappable seismic expression, trap definition depends on depth mapping the Base Zechstein and adding the appropriate Silverpit Formation isochore. The trap is a simple, uncompartmentalized, anticlinal feature, lying largely within Block 49/9b. The 49/%-2 discovery well (1989) penetrated the crest of the feature and the 49/9b-4 appraisal well (1994-1995) was drilled down-plunge to the SE. Both encountered some 20m of predominantly aeolian-dune sandstone overlying the Base Permian Unconformity. This reservoir flowed dry gas at rates of 0.8-1.0 MMm3/d. The GWC was not penetrated; however RFT pressure projections suggest that it lies at around 3528 m. Stochastic estimates suggested Leman Sandstone GIIP of 2.8 bcm (104 BCF). The field's twowell development is tied back to a minimum facilities platform with export to Den Helder, via the Markham ST-1 platform. On commissioning, in August 1997, the two-wells flowed at 1.8 MMm3/day. By January 1999, 0.682bcm of the originallyestimated 2.3 bcm gas reserve had been produced.
The W i n d e r m e r e Gas Field is located 140 k m N E o f G r e a t Yarm o u t h , in U K S o u t h e r n N o r t h Sea blocks 49/9b a n d 49/4a (Fig. 1). The field lies b e n e a t h a p r o m i n e n t P l e i s t o c e n e - H o l o c e n e channel, the M a r k h a m Hole, where water depths reach 50 m. Unstable seabed conditions associated with this feature necessitated the location of the W i n d e r m e r e drilling and p r o d u c t i o n facilities in shallower waters, some 2 k m to the north. The field lies 7 k m W o f the M a r k h a m Gas Field's ST-1 platform (Fig. 1), which is the site of production control, processing and export facilities.
History The 49/5-2 M a r k h a m Gas Field discovery well (1984) d e m o n strated an effective Rotliegend gas play in this area of the Southern N o r t h Sea, involving a basal P e r m i a n L e m a n Sandstone reservoir, with a lacustrine Silverpit Claystone topseal (Myres et al. 1995). The underlying W e s t p h a l i a n coal measures provided the obvious source for the gas. In 1989, Mobil drilled the 49/9b-2 W i n d e r m e r e discovery well to test the play in a structure west o f M a r k h a m .
Fig. 1. Location map for the Windermere Gas Field. Inset shows regional setting with major tectonic elements mentioned in the text. Note that the dotted delineation of the northern margin of the Cleaver Bank High refers to its palaeotopographical expression at the Base Permian Unconformity. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 893-901.
893
894
R. J. BAILEY & J. E. CLEVER
The well targeted a Base Zechstein structural closure and proved a 22 m thickness of gas-charged, basal, aeolian, Leman Sandstone, beneath the Silverpit Claystone seal. Dry gas was tested at rates up to 1.0 M M m3/d. The BP-operated 49/4a-4 step-out on the adjacent block to the north (Fig. 1) encountered water-bearing basal Leman Sandstone, showing the deterioration in reservoir properties associated with the northward passage into lake margin and lacustrine facies. Minor gas shows in thin sands overlying the main Leman Sandstone unit pointed to its penetration outside structural closure. In 1993, Mobil, Fina and the Coalite Group disposed of their 49/9b licence interests to Wintershall (UK) Ltd. and Brabant Petroleum
plc. (now EDC Europe Ltd.). Sovereign Exploration Ltd. (now CalEnergy Gas) retained its original 20% interest in the licence. The equity interests in the licence (P. 524) in 2000 were Wintershall 60%, EDC Europe 20% and CalEnergy Gas 20%. In 1994, the new licence group, with Sovereign as interim operator, shot additional, high quality 2D seismic across the licence area (Fig. 2), bringing the coverage to 1320 line kilometres, and giving an overall 0.5-1.0km grid. Late in 1994, the group spudded an appraisal well, 49/9b-4, with the aim of testing the Leman Sandstone reservoir in what appeared to be a separate fault compartment in the SE of the mapped closure (Fig. 3). As before, the well was deviated from a location north of the Markham Hole (Fig. 1).
Fig. 2. Seismic profile through the Windermere Gas Field and well 49/9b-W2Z showing horizon picks: BTT, Base Tertiary; BCh, Base Chalk; TZ, Top Zechstein; BZ, Base Zechstein; BPU, Base Permian Unconformity. Note the Carboniferous sub-crop at BPU.
WINDERMERE GAS FIELD
895
Fig. 3. Original Base Zechstein depth structure map based on pre-1996 2D seismic data showing the regional NW-SE structural trend in the Windermere area. Contour interval 25 m.
It encountered severe technical difficulties, resulting in a sidetrack within the Chalk. The side-tracked hole 49/9b-4ST was drilled to total depth (TD) in the Carboniferous and the gas-bearing Leman Sandstone was cored and logged. When a TD logging string became stuck, this hole was plugged-back and a further mechanical side-track, 49/9b-4Z, was drilled closely adjacent to the logged 49/9b-4ST well-bore. The 23m Leman sandstone interval of 49/9b-4Z was then production tested at rates up to 0.8 MMm3/d, confirming GIIP approaching 3.0 bcm. After the testing of 49/9b-4Z, Wintershall (UK) Ltd. assumed the licence operatorship and undertook development planning for the Windermere Field. At this stage, an agreement was negotiated whereby the 49/4a licence group assigned its small equity in the Windermere Field to the 49/9b licence group. The development programme, approved by the DTI in March 1996, involved the re-completion of the Leman gas section of 49/9b4Z for production (49/9b-W1) and the drilling of a new production well, 49/9b-W2, targeted close to the original 49/9b-2 discovery well (Fig. 4). These wells, tied back to the normally-unmanned Windermere platform, currently produce at an aggregate rate of approximately 1.0MMm3/day to Den Helder via the Markham field's export facilities (Fig. 1).
Structure
The Windermere Field is situated on the NE flank of the Cleaver Bank High, a positive feature progressively buried during Late Permian and early Triassic times (Fig. 1 inset; Fig. 6 inset), but rejuvenated by Late Jurassic (Cimmerian) to Early Cretaceous (Austrian) uplift and erosion (Glennie & Underhill 1998; Oakman & Partington 1998). As a consequence of these latter movements in the Windermere area, the Albian marls of the Cromer Knoll Group rest unconformably on the Triassic Bunter Shale (Fig. 5). However, the unconformity is not seismically mappable (Fig. 2); and the argillaceous section combining the Lower Cretaceous and Bunter is treated as one interval, bracketed by the strong reflections at Base Chalk and Top Zechstein (Fig. 2). Since the Cromer Knoll
component appears uniformly thin (c. 20m) in the wells in the Windermere area, the seismically-mapped, c. 100m, variations in the interval isochore probably reflect varying degrees of Jurassic to Early Cretaceous erosion of the Bunter Shale. These variations conform to the pattern of salt-withdrawal and salt swell features in the immediately underlying Zechstein, hence it seems likely that mild halokinesis accompanied the Jurassic to Early Cretaceous uplift and erosion over the Cleaver Bank High. The structure in this area is now dominated by halokinetic features of a later date. The major growth of these high-amplitude, N W - S E Zechstein salt swells (Fig. 2) began in Late Cretaceous (Chalk) times and continued during the Palaeogene, dramatically influencing the Chalk and Tertiary isochores. Though it is probable that the episodes of Zechstein halokinesis were a response to reactivation of lines of weakness in the prePermian, the thick salt layer has maintained clear structural separation between the Mesozoic-Tertiary and the pre-Zechstein of the Windermere area (Fig. 2). In the pre-Zechstein, the key stratigraphical datum is the Base Permian Unconformity (sometimes termed the Variscan or Saalian unconformity), separating the Late Permian Rotliegend continental deposits, including the basal Leman Sandstone reservoir development, from the gently folded and faulted Westphalian source rock succession (Glennie 1998). The Leman Sandstone reservoir has no seismic expression; and the Base Permian Unconformity's seismic reflection is generally weak and impersistent, allowing structure at this level to be mapped directly only in limited areas where a clear sub-crop is evident on the seismic (Fig. 2). However, there is good empirical evidence that the stronger, regionally developed Top Rotliegend/Base Zechstein seismic event, some 200 m shallower in the section (Fig. 2), adequately images structural relief at the Base Permian Unconformity and thus at the level of the Leman Sandstone reservoir. This, then, is the key seismic mapping horizon (see also Myres et al. 1995). Depth mapping of the strong Base Zechstein seismic event in the Windermere area indicates relatively subdued structural relief, largely controlled by an anastomosing pattern of normal faults trending generally NW-SE (Fig. 3). These faults are rooted in
896
R. J. BAILEY & J. E. CLEVER
2o48'E
Fig. 4. Top Leman Sandstone depth structure map of the Windermere Gas Field after incorporation of courtesy 3D seismic data to the northwest of the 49/9b-4ST BHL (R. Youngs, CalEnergy Gas). Contour interval 20m.
the Westphalian and are presumed to record the post-Rotliegend (Cimmerian, Late Cretaceous and Tertiary) reactivations of the Tornquist ('Caledonian/Variscan') structural trends (Glennie & Underhill 1998). However, regional correlation of the Rotliegend, including wells from the Windermere-Markham area, indicates that the interplay between palaeotopography of the unconformity surface and post-Rotliegend fault reactivation can give rise to Base Permian structural relief locally greater than that predicted by the addition of a regional Rotliegend isochore grid to the Base Zechstein depth structure map (see below and Fig. 6). When viewed in its regional structural context, it is clear that the Windermere gas accumulation coincides with a Base Zechstein fault and dip closure, deviating somewhat from the dominant structural trend. It is essentially a broad E S E - W N W anticlinal feature, which, on the 2D seismic, was interpreted as being bounded by a reverse fault along its SSW flank (Fig. 3). However, in 1996, Wintershall received from the 49/4a licence group courtesy 3D seismic data covering the northwestern part of the Windermere Field. Interpretation of this new data, carried out on behalf of the 49/9b group by Rob Youngs of CalEnergy Gas Ltd, gave a detailed picture of the structural configuration of the field's SSW flank. This clearly showed that, for much of its length, the structure at Base
Zechstein was a simple SSW-dipping structural ramp, locally involving normal faulting (Fig. 4). This interpretation more accurately defines the trap structure and has been extended into areas of the field covered only by the 2D seismic (Fig. 4).
Stratigraphy The stratigraphy of the Windermere Field is shown in Figure 5. The oldest sediments penetrated belong to Coal Measures of probable Westphalian 'C' age, consisting of interbedded mudstones, sandstones and coals. Resting unconformably on this section is the basal Rotliegend Leman Sandstone. This 20-25 m aeolian sandstone fines upwards, via an interval of thinly interbedded sabkha sandstones and shales, into the lacustrine mudstone and claystones of the Silverpit Formation (Fig. 5). These two Rotliegend formations are now thought to be of Late Permian (Tartarian) age (Glennie 1998) and attain some 220m in aggregate thickness. They record deposition in a land-locked epeiric basin, formed in response to regional thermal subsidence of the peneplaned and deflated Carboniferous surface, a surface developed during as much as 20 Ma of post-Carboniferous sub-aerial erosion (Glennie 1998).
WINDERMERE GAS FIELD
B
A
GR
897
C 150
Cly
Crse Tertiary Undifferentiated Sands and Clays
LM
~ ]
MMI
Chalk Including Red Chalk / Marl
FRA Bunter Clays, Mudstones Zechstein Evaporites Including K Salts
'1'1'1'1' Iiiiiiiii
Carbonate and Anhydrite
IiIiIiIll Iiiii Iii Iil[lllll
Rotliegend Silverpit Lacustrine Clays
AD 5
'Leman' Aeolian Sandstone
IlIiIiIiI Iiiiiiiii Iiiiiii1[ IiIilll
Carboniferous Westphalian 'C' Sands and Coals
m
I ]
Iiiiiiiii LM
AU 0 TZ 7 7
7 7
7 7
7 7
7 7
-
7
7
Fluvially Reworked Aeolian
AD WAS
Aeolian Dunes Windrippled Aeolian Sandsheet / Zibar
BF
Basal Fluvial
MMU BTT
Mid Miocene Unconformity BaseTertiary
7
7
7 7
7 7
7
7
7
7 7
7
7 7
7
7 7
7
7 7
Fluctuating Lake Margin Sandflat
FRA
7 7
7
7
BZ,' BPU
WAS
9
BPU
AD
BF
E
0 O
E
AU
Albian Unconformity
TZ
Top Zechstein
BZ
Base Zechstein (Kupferschiefer)
IRM
Intra Rotliegend Marker
BPU
Base Permian Unconformity
O O,I
Fig. 5. Stratigraphic column for the Windermere Field. (a) Complete drilled stratigraphy; (b) Rotliegend section with overlaid gamma log curve from 49/9b-W2Z (note Intra-Rotliegend Marker, IRM); (e) Leman Sandstone section with detail from the graphic core log from 49/9b-4ST. Regional log correlation of the Rotliegend (see below and Fig. 6) shows that the Windermere area lies on the northeastern flank of the Cleaver Bank High, then a low-lying promontory extending out into the Silverpit Lake. It separates the WindermereMarkham area and the Dutch Central Graben, on its NE flank, from the Sole Pit Basin, to the SW (Fig 1 inset). Late Permian transtension has been implicated in the formation of this large-scale horst-and-graben configuration within the Southern Permian Basin (Glennie 1998). In more northerly wells on the Cleaver Bank High, lacustrine claystones and halites directly overlie the deflated Carboniferous surface, sometimes with a basal transgressive lag (e.g. 49/8-2A, Fig. 6). In an embayment of the Cleaver Bank High's northeastern flank, in the Windermere-Markham area, the Carboniferous surface is buried by 20-40 m of wind-blown sands and sandy sabkhas which wedge-out southwestwards, against the high, and are overlapped by younger aeolian sand units that bury the peneplained top Carboniferous surface. Within ten kilometres to the north, along this flank of the Cleaver Bank High, the basal aeolian reservoir sands have passed, via sandy sabkha and sand-flat facies, with intercalated lake clays, into the typical lacustrine development of the Silverpit Formation (see Myres et al. 1995, Fig. 9).
The Silverpit Lake's transgression of the Cleaver Bank High was a process driven by subsidence and perhaps by a change in the lake's water budget. It is typical of the resultant southward and southwestward shift of its strandline that lake deposits overlap progressively younger, 20-30 m thick, basal accumulations of windblown sand (Fig. 6). There are two reasons to believe that these sands are both impersistent and diachronous. Firstly, log correlations suggest that the sands locally were drifted against palaeotopographic relief of the Carboniferous surface, leaving intervening deflated rock surfaces, or areas of negligible sand accumulation (e.g. 49/9b-2 to 49/8-2A, Fig. 6). Secondly, these correlations suggest that, as the transgression of the Cleaver Bank High progressed, there were fluctuations in the effectiveness, or sand-saturation, of the aeolian transport system, so that there may have been palaeotopographically-limited intervals within which no basal Permian aeolian sands survive. The regional Kupferschiefer sapropelic shale marker (Fig. 5) is thought to record the catastrophic influx of Permian seawater to the deep, landlocked Silverpit Lake basin, which may have been as much as 250-300m below global sea level (Glennie 1998). An isostatic response to this event may have increased the duration of this first episode of seawater influx, basin starvation and anoxia.
898
R.J.
BAILEY & J. E. C L E V E R
. .....~
92
o
o~
+..a
o~ ~
o
~~ ~
..~
.......,
WINDERMERE GAS FIELD In the Windermere area, as in most of northern U K Quadrant 49, the starved basin Kupferschiefer facies pass up, through a few metres of Zechsteinkalk deep water, dolomitic carbonates, into the anhydritic evaporites ending the first cycle of Zechstein deposition. The subsequent history of the Zechstein basin was characterized by continued subsidence, a lack of terrigenous clastic input, and a sensitive balance between evaporation and the further influx of Permian seawater, possibly through a seepage barrier (Taylor 1998). As many as four further cycles of marine influx/recharge and evaporite accumulation are recognized, typically following the carbonate-anhydrite-halite-bittern (K, Mg) salt sequence of deposition, with carbonates having diminishing influence in the later cycles (Taylor 1998). Three such cycles are recognized in the basinal Windermere area, where halite appears to have been the predominant Zechstein facies (Fig. 5). The current thicknesses of the deposits obviously reflect post-Bunter halokinesis, but at the end of the Permian the local depositional thickness of the Zechstein Group probably exceeded 1000 m (Taylor 1998). The Early Triassic Bunter Shales of the Bacton Group overlie the Zechstein evaporites with no obvious unconformity (Fig. 5). They record an increase in fine clastic input to the now entirely land-locked basin; and there is implied a climatic change in water budget and reversion to distal, playa lake conditions, with marked lateral continuity in facies (Fisher & Mudge 1998). The Bunter Sandstones, the Late Triassic Haisborough Group and the Jurassic and earliest Cretaceous are all absent from the Windermere area. This is attributed to Late Jurassic to Early Cretaceous erosion over the rejuvenated Cleaver Bank High (see above). An argillaceous facies of the Albian Red Chalk (Cromer Knoll Group) covers this unconformity surface and passes up into a thick succession of Late Cretaceous Chalk Group carbonates. Subtle seismic sequence boundaries suggest that growth of the Zechstein salt swells began during later Chalk deposition, but halokinesis had a more marked impact on the stratigraphy in the Palaeogene, which shows major differences in thickness between the crests of the salt swells and the flanking areas of salt withdrawal (Fig. 2). The Windermere wells, drilled from an area of salt withdrawal, are expected to have penetrated a relatively complete development of the Palaeogene (Fig. 5); although the argillaceous marine sediments are not sub-divided. The seismically-defined 'mid-Miocene Unconformity' marked the local cessation of halokinesis. Erosion of the Palaeogene/early Neogene over the crests of the salt swells, was probably associated with regional (Alpine) uplift. This was followed by renewed passive subsidence and the accumulation of several hundred metres of shallow marine and deltaic muds and sands. A richly-glauconitic sand, some 440 m TVDss in the Windermere area, may mark the beginning of this final phase of deposition, which was strongly influenced by Pleistocene glaciation (Fig. 5). Early Pleistocene sediments are deeply incised by melt-water tunnel-valleys developed beneath the grounded Mid Pleistocene ice sheet; and erosion by melt waters during the latest Pleistocene formed Markham's Hole (Fig. 1; see BGS/RGD 1984; Praeg 1996).
Trap Trap definition was first based on 2D seismic time and depth mapping of the Base Zechstein (Wintershall Noordzee, 1996, unpublished report; see Fig. 3). The addition of a gridded Rotliegend isochore was used to create a Base Permian Unconformity depth map. A net sandstone isochore, based on the 49/9b-2, 49/9b-4ST and 49/4a-4 wells, was then subtracted from the Base Permian Unconformity depth map to generate a Top Leman Sandstone depth map. The 1996 top reservoir maps derived in this fashion followed the simple periclinal configuration of the Base Zechstein, with a reverse fault along the southwestern flank of the feature and a normal fault defining the closure to the southeast (Fig. 3). As described above, the merging of the 1994 2D with the 1996 3D courtesy seismic data created a more detailed map at Top
899
Leman Sandstone (Fig. 4). This eliminated the trap's dependence on the SW bounding fault, which was reinterpreted to have a normal geometry. On this updated map, the Windermere trap remains a simple, largely dip-closed periclinal feature, not compartmentalized by faults. The distribution of gas shows in the Leman Sandstone unit and in the thin sandy sabkha units of the lowest Silverpit Claystone Formation suggests that the 1 m transgressive lake clays immediately overlying the aeolian sand reservoir units provide the top seal for the gas accumulation (Fig. 5). The three wells drilled on the field were in near-crestal locations and did not encounter a GWC. On the basis of RFT pressure extrapolations, the GWC is set at approximately 3528 m TVDss; although the results of the 49/4a-4 well, on the field's northern edge, suggest that it may be somewhat deeper. Given the uncertainties that remain in the depth conversion, it seems likely that the field is full to a structural spill between 3552 and 3528 m TVDss and that, as such, Windermere may be spilling towards the shallower gas accumulations encountered by the 49/10b-3 and Markham Field wells.
Reservoir As outlined above, the basal Permian Leman Sandstone reservoir of the Windermere Gas Field accumulated within an embayment of the NE flank of a deeply eroded and deflated palaeo-topographical feature known as the Cleaver Bank High (inset Fig. 6). The Leman unit represents the wind-blown element in a semi-arid depositional system ranging from a southern dune-field, via sandy and muddy lake margin sabkhas to a northern lacustrine/playa facies. There are only minor indications of fluvial processes in the Windermere area. However, in a more regional context, the south to north facies transition, which limits the gas play, suggests that the early Rotliegend deposition system was controlled by the intermittent fluvial sand input from the south, the longer-term action of the prevailing easterly winds in creating dune fields along the lake margin, and the fluctuating, but generally rising level of the Silverpit Lake (Fig. 6; see also George & Berry 1997; Howell & Mountney 1997). Core logs from the 49/9b-4ST well (Macchi 1995) show that the Base Permian Unconformity surface was buried by stacked, dunebedded aeolian sandstone units up to 6 m in individual thickness (Fig. 5). These sandstones constitute the Windermere reservoir. They are well-sorted grainflow deposits, of fine to medium grain size, with the simple bed forms and primary dips associated with the generally westward migration of sinuous-crested transverse dunes. The scale of the stacked units implies that the dunes had amplitudes exceeding 10 m, which would be their minimum contemporary relief relative to the level of the Silverpit Lake, to the north. Their preservation in part reflects the possibly fault-controlled (Glennie and Underhill 1998; Geluk 1999) differential subsidence of the embayment, which would have maintained the relative relief of the Cleaver Bank High, and the resultant potential for sand entrapment against its northeastern flank. Occasional run-off from the bare deflated surface of the Cleaver Bank High may have raised the water table within the otherwise ephemeral dune sand accumulations, assisting in their partial preservation. Evidence for this process is perhaps seen in the highest wind-blown Leman Sandstone units, which show signs of fluvial reworking (Macchi 1995; see Fig. 5). When coupled with an associated rise in the level of the Silverpit Lake, in a regime combining regional subsidence and increasing water budget, this could have ensured the preservation of dune sand units on the scale observed in the Windermere cores. The palaeo-relief of the Cleaver Bank High and the rising relative level of the Silverpit Lake are thus seen as key controls in the accumulation and preservation of the basal, aeolian, Leman Sandstones; while lacustrine transgression provided the topseal. The aeolian grain-flow sands are uniform in texture, though some horizons show very fine (<0.5 mm) grainfall laminae which are clay-enriched and subject to preferential development of dolomite cements. The sandstones are notably feldspar-deficient, quartz
900
R. J. BAILEY & J. E. CLEVER
arenites, with minor amounts of lithic fragments. Evidence of grain dissolution, and large volumes of grain-replacive kaolinite, suggest that the paucity of feldspar is a secondary, diagenetic effect (Macchi 1995). Authigenic carbonates, clay minerals and quartz have halved the 20-30% primary porosities of the aeolian grain-flow sands. Amthor & Okkerman (1998) have studied relative amounts of porosity loss involving early dolomite cements in the equivalent Slochteren Sandstones of the northern Netherlands. They found that much of the porosity loss was groundwater related and occurred at shallow depths of burial. Their evidence clearly shows that a positive relationship existed between the wetness of the depositional environment of the sandstones and the volumes of early pore-filling cements. This is borne out by the data from the Windermere area. Effective porosities for the Leman Sandstone reservoir section (Net/Gross c. 90%) average 13.2% in the 49/9b-2 well and were similar in 49/9b-4ST. Windermere core permeabilities have geometric averages in the range 9 - 1 6 m D (kh, air) and compare well with test-derived values of 12-14mD. The equivalent basal sandstone in the 49/4a-4 well, only 4 km N of Windermere, shows a net/gross of 61% and an average sandstone porosity of only 10.5%. These figures reflect the rapid northward decrease in reservoir quality, corresponding to the relative decline in the volume of aeolian sandstones. They also record the associated increase in the 'wet' sandstone facies that have lower primary porosities and show more pronounced early diagenetic porosity occlusion. None of the wells drilled on the field penetrated the G W C (see above). In the drilled reservoir log-derived gas saturations range from some 83% in 49/9b-2 to 77% in the 20m deeper section penetrated by 49/9b-4ST. These values are consistent with the capillary pressure measurements suggesting G W C at around 3528 mTVDss. The short-term DST performed on the Leman Sandstone reservoir of 49/9b-2 achieved a maximum flow of 0.78 MMm3d (28 M M S C F / D ) through a 44/64" choke. The test on 49/9b-4Z included a 10-day flow period which confirmed the productivity of the reservoir. These tests indicated good reservoir properties; and both wells produced c. 80% methane with some 9.3% non-combustible gases. The pressure data from the extended test on 49/9b-4Z suggested connected Leman Sandstone GIIP of some 2.4bcm (90BCF), a figure comparable to the original stochastic mean GIIP of 2.8 bcm (104BCF) estimated volumetrically from the 2D top reservoir depth map. Subsequent calculations using the revised 3D map remain close to this latter value. Poor quality (<1 mD permeability) Westphalian 'C' sandstones immediately underlie the Leman Sandstones in the 49/9b-2 and 49/9b-4 wells and are known to be gas-bearing. Their subcrop to the Base Permian Unconformity runs W - N W , along the structural axis of the field. These tight fluvial channel sandstones are estimated to contribute a further 0.038bcm (1.4 BCF) to the Windermere GIIP, some of which should be released as the Leman Sandstone reservoir is depleted.
could be drained by two wells. A normally un-manned, Minimum Facilities Platform (MFP) was designed with an 8I' pipeline, linking to the gas export facilities and equipment already in place on the M a r k h a m ST-1 platform, 7 km to the east. The development concept included remote control of Windermere gas production from the Markham J6-A platform's control room (Fig.l). The two-well development entailed extending the mudline casing suspension of 49/9b-4Z back to the M F P and its recompletion as the 49/9b-W1 production well (28/4/97). The new 49/9b-W2 well was drilled and tied back to a second slot on the M F P (16/8/97). This second production well was drilled to a reservoir target close to the 49/9b-2 discovery well's penetration of the Leman Sandstone (Fig. 4). Two spare slots were provided to accommodate additional tie-ins. On the commissioning of the field in August 1997, the combined production of the two Windermere wells was up to 1.8 MMm3/ day (67MMSCF/D), including 100 tonnes condensate per million cubic metres of gas. By January 1999, 0.682 bcm (25 BCF) of the originally-estimated 2.4 bcm (89 BCF) gas reserve had been produced, with a plateau production set at a Daily Contract Quantity of 1.2 MMm3/day (45 MMSCF/D). The authors thank Wintershall A. G. and Windermere partners, CalEnergy Gas Ltd., and EDC Europe Ltd., for permission to publish this paper. Peter Burri, Folke Smulders, Paul Robinson all read and improved the original draft. We would also like to extend our special thanks to all Wintershall Noordzee personel who participated in the development of the Windermere Field. David Lloyd of WIUK prepared the figures. J. D. Strachan is thanked for his careful refereeing of the paper.
W i n d e r m e r e Field data s u m m a r y Trap
Type Depth to crest Lowest closing contour GWC Gas column
Structural 3470 m TVDss 3555 m TVDss c. 3528 m TVDss c. 58m
Pay zone
Formation Age Gross thickness Net/gross ratio Porosity average Permeability average Petroleum saturation average
Leman Sandstone Permian 23m 90% 12-13% 12-14mD (test) 77-83%
Petroleum
Type Gas gravity Dew point Condensate yield (initial) Gas expansion factor
Gas and condensate 0.725 (air = 1) 341 bara 100 tonnes/MMNm 3 252-256 @ normal conditions
Source
The methane gas trapped in the Windermere Field derives from the coals and carbonaceous shales of the underlying Westphalian. In this general area, gas generation is believed to have been ongoing since the Late Cretaceous or Early Tertiary (Myers et al. 1995). However, indications of short-lived Neogene uplift and erosion may point to the gas generation process having ceased in the relatively recent past and re-started during Late MioceneRecent burial.
Development
Given that there was no evidence of fault compartmentalization of the field, it was decided that the Windermere gas accumulation
Formation water
Salinity Resistivity
575 mg/1 2.9155 ohm m @ 25~
Field characteristics
Productive area Gross rock volume Initial pressure Pressure gradient - gas - water Temperature Gas initially-in-place Recovery factor Recoverable reserves Recoverable condensate
8 km 2 123 MMm 3 398 bara 2.034kPa/m 10.622 kPa/m 113~ 2.8 BNm 3 82% 2.3 BNm 3 e. 155.7 Mm 3
W I N D E R M E R E GAS FIELD Production Start-up date Production rate plateau gas Number/type of wells
April 1997 1.2 MMNm3/d 2 producing wells
References AMTHOR, J. E. & OKKERMAN, J. 1998. Influence of early diagenesis on reservoir quality of Rotliegende Sandstones, Northern Netherlands. American Association of Petroleum Geologists, Bulletin, 82, 2246-2265. BGS/RGD 1984. Indefatigable Sheet/Kaartblad, 53~176 Quaternary Geology. British Geological Survey/Rijks Geologische Dienst 1. 250,000 series. FISHER, M. J. & MUDGE, D. C. 1998. Triassic. In: GLENNIE K. W. (ed.) Petroleum Geology of the North Sea, 4th Edition. Blackwell, Oxford, 212-244. GELUK, M. 1999. Late Permian (Zechstein) rifting in the Netherlands: models and implications for petroleum geology. Petroleum Geoscienee, 5, 189-199. GEORGE, G. T. 8r BERRY, J. K. 1997. Permian (Upper Rotliegend) synsedimentary tectonics, basin development and palaeogeography of the southern North Sea. In: ZIEGLER, K., TURNER, P. 8r DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 31-61.
901
GLENNIE, K. W. 1998. Lower Permian-Rotliegend. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea, 4th Edition. Blackwell, Oxford. 137-173. GLENNIE, K. W. & UNDERHILL, J. R. 1998. Origin, Development and Evolution of Structural Styles. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea, 4th edition. Blackwell, Oxford, 42-84. HOWELL, J. & MOUNTNEY, N. 1997. Climatic cyclicity and accommodation space in arid to semi-arid depositional systems : an example from the Rotliegend Group of the UK southern North sea. In: ZIEGLER, K., TURNER, P. 8r DAINES, S. R. (eds) Petroleum Geology of the Southern North Sea: Future Potential. Geological Society, London, Special Publications, 123, 63-86. MACCHI. L. 1995. Summary Report on the Reservoir Geology of the Lower Permian in the SEL Well 49/9b-4, UKCS. Unpublished Report. MYRES, J. C., JONES,A. F. & TOWART, J. M. 1995. The Markham Field: UK Blocks 49/5a and 49/10b, Netherlands Blocks J3b and J6. Petroleum Geoscience, 1, 303-309. OAKMAN, C. D. • PARTINGTON, M. A. 1998. Cretaceous. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea, 4th Edition. Blackwell, Oxford, 294-349. PRAEG, D. 1996. Morphology, Stratigraphy and Genesis of Buried MidPleistocene Tunnel Valleys in the Southern North Sea Basin. PhD thesis, University of Edinburgh. TAYLOR, J. C. M. 1998. Upper Permian-Zechstein. In: GLENNIE, K. W. (ed.) Petroleum Geology of the North Sea, 4th edition. Blackwell, Oxford, 174-21 t.
The Hatfield Moors and Hatfield West Gas (Storage) Fields, South Yorkshire J. W A R D , A. C H A N & B. R A M S A Y Edinburgh Oil & Gas plc., 10 Coates Crescent, Edinburgh E H 3 7AL, UK
Abstract: Hatfield Moors and Hatfield West are two small gas fields with GIIP of 6.1BCF and 2.4 BCF, respectively on adjacent licences PL161-3 and PL162-2, east of Doncaster in South Yorkshire, England, operated and wholly owned by Edinburgh Oil & Gas plc. This paper describes the accidental discovery of the Hatfield Moors Gas Field and its subsequent development and eventual utilization for gas storage, the first such project onshore UK. The nearby Hatfield West Field is also described. The two fields are located on adjacent faulted anticlinal structures in the NW part of the Gainsborough half-graben. The reservoir for both fields is the Westphalian B Oaks Rock sandstone. Reservoir quality is excellent. A gas storage project was agreed with Scottish Power in 1998. Two horizontal wells, Hatfield Moors-5 (1998) and Hatfield Moors-5z (1999) have been drilled for the project by Edinburgh Oil & Gas plc using innovative drilling techniques. Since 1999 gas has been imported from the Transco network and exported from the reservoir according to market demands under the terms of the gas storage contract. In December 1981, the Hatfield Moors-1 exploration well in South Yorkshire, having reached a depth of 1587 ft, blew out from the Westphalian B Oaks Rock sandstone (1434 to 1489 ft) as the drill string was being pulled for a change of bit. Gas ignited and the ensuing blaze destroyed the Boldon T32 rig, fortunately without casualties. An estimated 1 BCF of gas was consumed in the fire before the well was brought completely under control after 38 days. Gas shows had not previously been recorded from Oaks Rock in many coal and several oil boreholes that had already penetrated this shallow formation. Thus, the Hatfield Moors Gas Field was accidentally discovered.
insignificant by comparison with North Sea gas fields, can be very profitable for small companies. The partnership that discovered the Hatfield Moors and Hatfield West Fields comprised Taylor W o o d r o w (operator), Candecca, Marinex, Pict and James Finlay. Taylor Woodrow later became Kelt and then Perenco. BP by acquisition of Candecca joined the licensees in 1987. Edinburgh Oil & Gas plc joined in 1991, eventually becoming the sole licensee (100% interest) in 1995. Licence numbers and boundaries have also altered over the years. The 1999 areas of the production licences PL162-2 (Hatfield Moors) and PL161-3 (Hatfield West) are shown on Figure la.
History
Gas production
In the 1960s following earlier discoveries of Carboniferous oilfields in the East Midlands of England, BP and others extended the search for oil to areas north and west of the Gainsborough and Beckingham Fields in the Gainsborough Trough (Fig. l a). Targets were deltaic sandstones of lower Westphalian A to upper Namurian age found at depths of 3500 to 5500 ft, but no more commercial oil fields were discovered in the north Gainsborough Trough. Gas, which was non-commercial at the time, was discovered at Trumfleet. Unsuccessful wells included Hatfield-1 and Hatfield-2 drilled by BP and the Gas Council in 1966 on a structure east of Doncaster. The Gas Council, however, carried out tests at Hatfield-1, which showed the shallow Oaks Rock sandstone to have excellent reservoir potential for future gas storage. It was to be over thirty years before this potential was developed. In the 1980s Taylor Woodrow Energy Ltd. and partners carried out extensive seismic surveys that resulted in the remapping of much of the subsurface of Yorkshire and Humberside. Hatfield-1 and Hatfield-2 were seen to have been drilled downflank of a structure whose crest lay between the two wells. Taylor Woodrow, by now operator of the Hatfield area, spudded Hatfield Moors-1 at a near crestal location on a close, but separate structure east of Hatfield-1. Plans to test Namurian targets had to be abandoned following the disastrous blowout at the well. It was eventually completed as a gas producer from the Oaks Rock and on testing flowed at over 14 M M C F D . In the next few years four more wells were drilled on the Hatfield structure. Hatfield Moors-2, down dip to the east, was wet. Hatfield Moors-3, located only 40m from Hatfield Moors-l, reached the lower Namurian (TD 6000ft) but after finding only water-wet sands was also completed in the Oaks Rock. Hatfield Moors-4, a deviated, microdrilled well confirmed the lateral extension of the gas-bearing sand to the SW; it was plugged and abandoned. Hatfield West-1 found gas with a higher GWC in a separate closure across a N E - S W fault on the structure. GIIP for Hatfield Moors was estimated to be 6.1 BCF; that for Hatfield West 2.4 BCF. Such accumulations onshore UK, though
Production engineering developments at Hatfield Moors were described by Jones (1988). Production from Hatfield Moors Field
Fig. 1. (a) Regional location map of the Hatfield Moors and Hatfield West gas fields.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 905-91"0.
905
906
J. WARD ET AL.
Fig. 1. (b) Hatfield Moors and Hatfield West gas fields: structure map on Top Oaks Rock.
began modestly in 1986 with limited sales of gas (c. 250 MSCF/D) to a local brickworks. In 1994, the first sales of Hatfield Moors gas by Edinburgh Oil & Gas plc to Scottish Power via the Transco network commenced; the first such deal for a UK onshore field. Meanwhile, Hatfield West gas was sold to the brickworks.
Gas storage In 1996, Edinburgh Oil & Gas plc reached an agreement with Scottish Power to participate in a feasibility project to utilize the partially depleted Hatfield Moors Field for gas storage, as well as continuing gas production. Gas composition (Hatfield Moors) Molecular Composition (Mole Percent) Components Nitrogen Carbon dioxide Hydrocarbons Methane Ethane Propane I-Butane N-Butane I-Pentane N-Pentane Hexanes Heptanes Octanes Nonanes Decanes plus Total
3.99 0.58
88.46 4.34 1.72 0.26 0.36 0.08 0.09 0.06 0.04 0.01 0.01 0.00 100.00
By 1998, Hatfield Moors had produced over 2BCF of gas. Reservoir pressure, estimated to have been about 650 psig prior to the blowout, had decreased to c. 250 psig. Following a contractual agreement with Scottish Power to utilize Hatfield Moors for gas storage, Edinburgh Oil & Gas plc successfully drilled and completed the Hatfield Moors-5 well with a 500ft long horizontal section in the Oaks Rock. This was the first well in the U K onshore designed both for gas injection and production from a partly depleted gas bearing sandstone. The well was drilled from the Hatfield Moors-3 production well which was originally abandoned by setting a cement plug above the Oaks Rock. Having milled a window in the 95" casing at 912ft below ground level in the Magnesian Limestone, a new ~1 v~tt hole was drilled and deviated using conventional drilling techniques to reach a near horizontal angle a few feet above the top of the Oaks Rock. M W D gamma ray was used to identify stratigraphy. A 7" liner was then run and cemented. Drilling continued by means of coiled tubing, M W D gamma ray and underbalanced nitrogen foam. As the reservoir sandstone was penetrated, gas flowed to the surface where it was flared. Hydraulic steering enabled the bit to be maintained at a depth about 10 ft below the top of the Oaks Rock. At that level, M W D gamma ray response and the cuttings returns indicated the sandstone to be of excellent reservoir quality. That level, also some 30 ft above the GWC, was taken to be high enough to avoid water coning when the well would be on production. The horizontal hole section was left barefoot and the new well completed with a larger monobore tubing string than that in the now abandoned Hatfield Moors-3. This larger tubing and the effect of the horizontal section has increased gas deliverability at the well by a factor of eight. A second horizontal section 500 ft in length was drilled by the same methods from the liner shoe in Hatfield Moors-5 in August 1999. This lateral (Hatfield Moors-5z) was steered along a different azimuth to that of the first horizontal section but at a similar depth. Excellent reservoir sandstone was encountered as before. The horizontal reservoir section has also been left barefoot. These two laterals were the first to have been drilled in the U K by means of a
HATFIELD MOORS AND HATFIELD WEST GAS FIELDS combination of coiled tubing and underbalanced nitrogen foam within a partly depleted gas field. Edinburgh Oil & Gas plc and Scottish Power agreed a 25 year contract for the use of the field as a gas store, and injection commenced in September 1999. Gas from the Transco network is carried by a high pressure pipeline some 13 km in length to a compressor station near the Hatfield Moors Field. It is then injected into the Oaks Rock via the Hatfield Moors-5 and -5z wells. Import and export of gas to and from the reservoir takes place according to market demands under the terms of the gas storage agreement.
are the main reservoir targets with almost the only exception being the upper Westphalian B Oaks Rock sandstone of the Hatfield area. In the Namurian, sediments were laid down by prograding deltas that flowed from the north and east across the East Midlands shelf, eventually filling the basins. The post-rift depocentre being to the NW in central England, early Namurian sediments at Hatfield and other outer areas of the Gainsborough half graben were of deep-water facies. Prodelta shales became source rocks. Sandstones, though frequently having oil or gas shows, are almost invariably found to be well-cemented by silica and of generally poor permeability. These sandstones may have reached burial depths of around 8400 ft, the approximate limit for viable reservoir poroperm preservation in Carboniferous channel facies (Fraser et al. 1990). Prospectivity tends to be confined to near the top of the Namurian, where targets are medium to coarsegrained deltaic channel sandstones of the Ashover and Chatsworth Grits or their lateral equivalents, and the Rough Rock immediately below the Westphalian boundary. At Hatfield- 1, Hatfield-2 and Hatfield Moors-3, these sands were wet, whereas to the NW at Trumfleet the Rough Rock and the Ashover Grit equivalent were gas bearing. The only commercial oil found this far north in England has been at the Crosby Warren Oil Field 22 km NNE of Hatfield in an area structurally outwith the Gainsborough half-graben. Some 0.55 MMBBL of oil have been produced (2001) from the Beacon Hill Flags (Ashover Grit equivalent) at that field.
Geological history and petroleum prospectivity of the Hatfield area The Hatfield anticline is located in the north of the Gainsborough Trough, northernmost of the three large half-grabens within the East Midlands oil and gas province (Fig. l a). The Gainsborough, Edale and Widmerpool basins originated in the late Devonian to early Carboniferous by extension and rifting along northwesterly Caledonide fault trends north of the Wales-Brabant Massif. Syn-rift Dinantian limestones, the oldest rocks penetrated by most East Midlands boreholes, are effective economic basement in the province. Post-rift upper Namurian to Westphalian A sandstones
HATFIELD-2
HATFIELD WEST-1
HATFIELD-1
GR
GR
GR
907
HATFIELD MOORS-2
HATFIELD MOORS-3
GR
+
GR
DATUM 1050
9
--
J
,,-, ~'~
'
1100
',
!','_ "~
DEPTH
feet TVDss
'
'I ~-
,,, ,,,
~
[i I
1200
ZXJ Or):~.e
~ - - -
AMB
.- ~ - - - 1300
LL
GWC "I.
.
.
.
9
'i
--
\v~,, ~\ ?
~IK~
-
T+-
i
1400 II
1600
No horizontal scale ~
Sandstone
AMB
Aegiranum marine band
~
Limestone
L. MAG. LS
Lower Magnesian Limestone
~
Dolomite
~
Shale
~
Siltstone
[~-~ Anhydrite
Pre-Permian Unconformity
(i) (ii)
HATFIELD-2
t
HATFIELD
~
HATFIELD-1
,//
#~v
Hatfield West (present day) is structurally higher than Hatfield Moors. Progressive thinning from west to east of the interval from the AMB to base L. Mg Ls indicates Hatfield Moors was previously structurally higher than Hatfield West. (iii) Juxtaposition of the Oaks Rock on either side of the Hatfield Fault may control the position of the Hatfield Moors GWC.
Fig. 2. Hatfield Moors and Hatfield West gas fields: structural correlation cross-section.
908
J. WARD E T AL.
At Hatfield-lA, re-entry of Hatfield-I by Candecca in 1976, a very limited production (< 10 BOPD) was obtained from the Grenoside Sandstone and at Axholrne-1 to the east some minor production was obtained from the Westphalian A Flocton and Lidgett Sandstones. By contrast, at oil fields further to the south, sandstones of comparable age but developed in thick distributary channel facies have provided good oil production. In the NW of the Gainsborough half-graben Westphalian C sandstones rarely have shows and have never produced. The acceptably porous Acton Rock at Hatfield West (Fig. 2) is close to the prePermian unconformity. Any hydrocarbons that had reached this rock may have been lost through inadequate top-seal, cross-fault leakage or by escape into the overlying Permian sandstone. In the late Carboniferous, Variscan compression caused partial inversion of basinal areas, frequently expressed by development or enhancement of hanging wall anticlines. Most of the East Midlands structural traps were formed at that time, though not apparently the Hatfield traps. Pre-Permian erosion removed much of the Westphalian C and D sediments. Seismic and well data indicate near-peneplanation. At Hatfield Moors-5, about 20 ft of reddened claystone is all that separates the Westphalian B from the Permian. Sedimentation resumed in the Permian and continued until the Cretaceous. Several thousand feet of Mesozoic and older strata were eroded following Tertiary uplift. Regional tilting down to the east took place reversing the original westerly dipping trend of the Carboniferous sediments.
Seismic Surface conditions at Hatfield Moors are less than ideal for land seismic acquisition. The site is surrounded by an extensive peat bog and some dense woodland. Between 1981 and 1988, four seismic surveys recorded 85 km of data from dynamite, vibroseis and hydropulse sources. Due to its proximity to the overlying and strongly reflective Permian series, the Oaks Rock gives a poor and laterally inconsistent seismic response. Taylor Woodrow used well and coal borehole data to isochore the interval between the Barnsley Coal, a deeper but more consistent reflector, and the Oaks Rock. This provided a reasonable value for the depth to top Oaks Rock, which could then be mapped. The seismic dataset was reprocessed in 1996 by Edinburgh Oil & Gas plc. Subsequently it was possible to map events at the Top and Bottom of the Oaks Rock. The overall data quality of the seismic is poor and laterally very variable. Consequently, considerable uncertainties remain in the mapping of the Oaks Rock reservoir for both fields.
Trap Hatfield Moors and Hatfield West Gas Fields occupy two culminations separated by the N E - S W Hatfield Fault on the crest of the main Hatfield anticlinal structure located in the hanging wall south of the Askern-Spital Fault (Fig. I b). The Hatfield Anticline has an area of over 20 km 2 but is not nearly filled to spill point; its crest being at about 1300ft and closing contour at 1700ft or deeper. Although the Hatfield structure is of Variscan origin, BP geologists recognized that the crest of this structure originally lay further to the east. It was not until the late Mesozoic or the Tertiary when regional dip was reversed that the Hatfield Moors and Hatfield West traps in the Oaks Rock were formed. Figure 2 shows west to east thinning of the interval from the Aegiranum marine band to base Lower Magnesian Limestone, implying that Hatfield Moors was once higher than Hatfield West. Movement on the Hatfield Fault apparently took place near end Carboniferous times since the 100 ft thick Acton Rock sandstone of Westphalian C age was preserved on the Hatfield West but not the Hatfield Moors side, and the presence of about 35 ft of probable early Permian sandstone at Hatfield West and Hatfield-2 would suggest that some fault movement also occurred post-regional peneplanation in the pre-Permian.
The Hatfield fault appears to control the spill point of the upthrown Hatfield Moors block since the GWC at 1460ft is about level with the mapped top of the Oaks Rock on the downthrown Hatfield West side (Fig. 2). Hatfield Moors is dip-closed in all other directions. The crest of the Hatfield West structural block is higher than Hatfield Moors due to Tertiary uplift and tilting. Closure is fourway dip assisted by faulting to the NW. The GWC at 1349 ft is 111 ft higher than at Hatfield Moors, probably as a result of crossfault leakage. Top seal for both gas fields is the Aegiranum marine band (Top Westphalian B) and the associated non-calcareous mudstones and tight shaly siltstones. Although only a few feet thick the marine band is probably a crucial component in the seal, being laterally extensive, extremely fine-grained and having a high gamma ray response typical of top-sealing shales found in East Midlands oil fields. Lateral seal of Hatfield Moors at the fault may result from juxtaposition of this approximately 50 ft thick shaly interval downfaulted to the west against the Oaks Rock on the upthrown eastern side.
Reservoir The Oaks Rock is the highest stratigraphically occurring sandstone within the Westphalian 'B' sequence. Its top is located some 50 ft below the Aegiranium marine band that marks the boundary with the overlying Westphalian C. The thin Swinton Pottery Coal is found at its base and about three thin seams of the Wheatfield Coal are found within the claystones and shaly sandstones that lie directly above Oaks Rock. Oaks Rock sandstone was cored extensively at Hatfield Moors2, -3 and Hatfield West-1. The sand is light grey and brown, mainly medium-grained with some fine and some coarse to very coarse grains. There is a general trend of grain size coarsening upwards although at Hatfield Moors-2 individual sandstone beds shows fining upward trends. At Hatfield Moors-3 and Hatfield West-1 the sandstone is clean, moderately well sorted, sub-angular to subrounded with up to 10% kaolin matrix and minor carbonate and silica cement. Grains consisting of rock fragments and feldspar are common. Some of the sandstone is micaceous. At Hatfield Moors-2 much carbonaceous material is present as coaly streaks and rippedup coal clasts. All three wells contain thin (6" to 1") channel lag deposits composed of rounded coal clasts and pieces of fossil wood, some heavily water worn, others well-preserved parts of branches. Planar cross-bedding with 20 ~ dips is found at all three locations with some trough cross-bedding at Hatfield Moors-3. Set thickness is mainly between 2 and 4 ft. Climbing ripples are also present in some of the cores. The overall grain size of the Oaks Rock sandstone reservoir indicates that it was deposited by strong currents. This is confirmed by the presence of tabular and trough cross-bed sedimentary structures characteristic of uni-directional, strong currents. However, these structures also occur with slower current climbing ripples and thin, very quite water laminated shale layers. Such a combination is typical of braided stream deposition found in other Upper Carboniferous sandstones in the area (Church & Gawthorpe 1994; Hampson et al. 1996). Individual channel depths can be roughly estimated from the thickness of the cross-bed sets (1 : 2-1 : 6 after Collinson & Thompson 1989) and medium scale sequences (in practice core based reservoir zones). Most cross-bed sets are no more than 2-4 ft thick. Two fining-up sequences (reservoir zones) in Hatfield Moors-2 are 10 ft thick, while an apparently single, coarse-grained sequence in Hatfield West-l, is 30 ft thick. Typically then, internal channels might be <30ft and more generally about 10ft deep. The overall Oaks Rock reservoir thickness is between 86 ft and 46 ft in the cored wells. Outcrop work on the Upper Carboniferous (Aitken et al. 1999; Hampson et al. 1999) suggests that with a channel thickness of approximately 90 ft (30 m), Oaks Rock should have a width of no more than 5 km to 10 kin.
HATFIELD MOORS AND HATFIELD WEST GAS FIELDS
909
Fig. 3. Oaks Rock gross isochore (ft). Palaeocurrent trend to SW (dipmeter data).
The results of reprocessing dipmeter values at Hatfield Moors-2 and -3 enabled a S-SW palaeocurrent to be detected from the crossbedding in those wells. Interpretation of Oaks Rock in the Hatfield area as a fluvial system some 5 to 10 km wide and flowing to the SW is consistent with isochore mapping of the Hatfield Moors and Hatfield West Fields. A fortuitous trend of local thickening occurs along the crests of both structures on a N E - S W alignment. Thinning takes place to the N W and SE (Fig. 3). Reservoir characteristics in the field areas are exceptionally good for a sandstone of Carboniferous age. This is attributable to deposition in a high energy environment. Porosity preservation is likely to be the result of both relatively shallow depth of burial due to the stratigraphic position of Oaks Rock being near the top of Westphalian B and pre-Permian erosion of most of the Westphalian C or younger Carboniferous strata in the pre-Permian. Table 1 shows poroperm values derived from core analysis at Hatfield Moors-2, -3 and Hatfield West-1.
Source rocks and migration Work by both Taylor Woodrow and BP has shown the main source of hydrocarbons in the Gainsborough half-graben to be Early
Namurian pro-delta mudstones. These shales at Hatfield have reached a maturity of 1.3 R0%. In this area source rocks are considered to have reached maturity and generated oil by the end of the Carboniferous. By Late Jurassic-Early Cretaceous times further burial resulted only in expulsion of light oil and gas. Regional isochore mapping by BP geologists showed the Hatfield structure to have been on the western flanks of a large Variscan anticline centred near the Axholme area to the east. Only after easterly tilting in the Tertiary did viable traps appear in Oaks Rock at Hatfield Moors and Hatfield West. Hence, charging of these structures by gas is postulated to have also been in the Tertiary by re-migration from the east.
Reserves The most reliable values for GIIP at Hatfield Moors and Hatfield West are those from production and petroleum engineering data: 6.1 BCF and 2.4 BCF, respectively. Recoverable reserves are estimated to be 4.3 BCF and 1.7 BCF (70%). Estimates of GIIP from geological data are less certain. Poor quality seismic data causes uncertainty in the mapped field areas, and hence total reservoir rock volumes. Nevertheless 'most likely' values similar to those from the petroleum engineering that have been determined.
Table 1. Poroperm data Jor Hatfield Moors and Hatfield West Minimum core porosity (%)
Average core permeability (mD)
Well
Thickness of interval (m)
Average core porosity (%)
Maximum core porosity (%)
Hatfield Moors-2
14.0
16.9
23.2
8.7
Hatfield Moors-3
19.8
21.3
25.6
17.2
248
Hatfield West- 1
13.4 12.2
20.4 16.9
23.9 20.0
12.9 12.9
190.4 13.0
38.4
Maximum core permeability (roD) 685 1100 880 61.0
Minimum core permeability (mD) 0.45 21 0.05 0.45
910
J. WARD E T AL.
Hatfielfl Moors and Hatfielfl West data summary
Hatfield Moors
Hatfield West
Trap Type Depth to crest Gas-water contact Estimated original field pressure
Tilted anticlinal fault block 4-1400 ft TVDss i460 ft TVDss 650 psig
Tilted anticlinal fault block -I-1300 ft TVDss 1349 ft TVDss 600 psig
Pay zone Formation Age Thickness Net/gross Porosity Average gas saturation Permeability
Oaks Rock Sandstone Late Westphalian B 25-90 ft 0.9 17.2-25.6 % 55% 21-1100 mD
Oaks Rock Sandstone Late Westphalian B 25-90 ft 0.9 12.9-23.9 % 55% 0.05-880 mD
Hydrocarbons Gas gravity (Air = 1) Gas type
0.629 Sweet dry gas
0.629 Sweet dry gas
Reserves GIIP Recovery factor Recoverable reserves Drive mechanism
6.1 BCF ?70% 4.27 BCF Pressure depletion
2.4 BCF ?70% 1.68 BCF Pressure depletion
Summary and conclusion Despite its disastrous discovery in 1981, the Hatfield M o o r s gas a c c u m u l a t i o n was successfully d e v e l o p e d as a small o n s h o r e U K gas field. F o l l o w i n g gas d e r e g u l a t i o n in 1994 it b e c a m e the first onshore field to supply gas to the T r a n s c o n e t w o r k . In 1998 h a v i n g p r o d u c e d c. 2.5 B C F o f gas, the partially depleted field was successfully c o n v e r t e d for use as a gas storage facility, the first such project o n s h o r e U K . This was achieved by drilling h o r i z o n t a l wells using i n n o v a t i v e techniques. Hatfield West G a s Field, c u r r e n t l y p r o d u c i n g gas for sale, is n o w being c o n s i d e r e d for use as a gas storage facility. Much of the geological interpretation contained in this paper is based on unpublished work by geologists from companies no longer associated with Hatfield Moors or Hatfield West. These include: P. Spink and F. Gryspeert of Taylor Woodrow Energy Ltd (now Perenco) and K. Beattie, B. C. Mitchener and N. C. Taylor of BP. Recent geological interpretation was made by M. Rider & T. Goodall of Production Geoscience Ltd (PGL). The authors are grateful to M. Storey and R. Steele for refereeing the original draft of this paper.
References AITKEN, J. A., QUIRK, D. G. & GUION, P. D. 1999. Regional correlation of Westphalian sandbodies onshore UK: implications for reservoirs
in the Southern North Sea. In: FLEET, A. J. 8z BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 747-756. CHURCH, K. D. 8g GAWTHORPE, R. L. 1994. High resolution sequence stratigraphy of the late Namurian in the Widmerpool Gulf (East Midlands, UK). Marine and Petroleum Geology, 11(5), 528-544. COLLINSON, J. D. ~; THOMPSON, D. B. 1989. Sedimentary Structures. 2nd Edition. Chapman & Hall, London, 83. FRASER, A. J., NASH, F. F., STEELE, R. P. 8z EBDON, C. C. 1990. A regional assessment of the intra-Carboniferous play of Northern England. In: BROOKS, J. (ed.) Classical Petroleum Provinces'. Geological Society, London, Special Publications, 50, 417-440. HAMPSON, G. J., DAVIES, S. J., ELLIOTT,T., FLINT, S. S. • STOLLHOFEN,H. 1999. Incised valley fill sandstone bodies in Upper Carboniferous fluviodeltaic strata: recognition and reservoir characterisation of Southern North Sea analogues. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 771-788. HAMPSON, G. J., ELLIOTT, T. & FLINT, S. S. 1996. Critical application of high resolution sequence stratigraphic concepts to the Rough Rock Group (Upper Carboniferous) of northern England. In: HOWELL, J. A. & A]TKEN, J. F. (eds) High Resolution Sequence Stratigraphy: Innovations and Applications. Geological Society, London, Special Publications, 104, 221 246. JONES, R. E. 1988. Hatfield Moors - Case History of a Small Onshore Gas Field. Petroleum Review, May 1988.
The Saltfleetby Field, Block L 47/16, Licence PEDL 005, Onshore UK T. H O D G E
Roc Oil (UK) Ltd., High Street, Saxilby, Lincoln LN1 2JQ, UK (e-mail.
[email protected])
Abstract: The Saltfleetby Gas Field is located onshore in East Lincolnshire at the western extent of the Humber Basin, midway between the Southern North Sea gas fields and the established Onshore Oilfields of Welton and Scampton North. Commercial discovery was in 1996, following the re-entry of a 1986 exploration well, confirming the pre-drill belief that the earlier drilling had been mis-appraised. Basic assumptions at the time of drilling the re-entry well suggested a possible 40 BCF gas-in-place in Early Westphalian sandstones. This assessment was based on only a single 2D seismic line, an association with gravity form, and the mud logging information from the earlier exploration well. Full delineation of the field extent following 3D seismic mapping and development drilling has indicated a gas-in-place of 114 BCF. Field development consent was granted in March 1999 and production commenced in December 1999. Initial field production exceeded 50 MMSCFD from four wells and to date (end July 2001) 24 BCF of gas has been produced. Ultimate gas recovery is expected to be 73 BCF proven plus probable reserves. A fifth horizontal well has been drilled in a deeper, Namurian, zone and a sixth well confirmed hydrocarbons in a southern promontory to complete the field development. An 8 km mixed phase export pipeline of 10" diameter exists to the Theddlethorpe processing plant, where gas and condensate is separated. Sharing of Pickerill compression facilities, located at Theddlethorpe were commissioned late in 2001.
Location and history The Saltfleetby Field is located on the East Lincolnshire coast, m i d w a y between the onshore W e l t o n Oilfield and the Southern N o r t h Sea gas fields of A m e t h y s t and Pickerill. (Fig. 1). Saltfleetby lz, the discovery well, was drilled in 1996 as a re-entry and dedicated reappraisal of the Saltfleetby 1 exploration well drilled in 1985. It was assumed that the earlier well had been mis-appraised and that two or three potential gas zones existed.
The early exploration well drilled to and confirmed the presence of D i n a n t i a n carbonates at 2345 m. However, technical evaluation of the well was limited, as wireline logging tools failed to pass deeper than 2195 m. The decision process during the logging of the well is u n k n o w n , but the well was plugged and a b a n d o n e d three days after logging. Evident over the logged p o r t i o n of the hole were frequent coal beds, but with very low associated gas peaks. Deeper in the well, close to the top of the carbonates, were three higher gas peaks. A w o r k i n g knowledge of m u d gas response over coals and reservoir
Fig. 1. Saltfleetby Field location map.
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. UnitedKingdom Oil and Gas Fields,
Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 911-919.
911
912
T. HODGE
in the Welton Field, some 43 km to the east, suggested that the log may be indicating an unevaluated pay zone. Statistically at Welton, mud gas over the reservoir would normally be close to equal that of the highest coal peaks, while at Saltfleetby the deeper gas peaks were 25-70 times higher than those of the coal response. Supporting evidence for an accumulation was limited to the gas shows, a positive drilling break associated with the peaks and an association of a gravity anomaly, conformable with structure along the single N - S 2D seismic line. This was enough of a prompt to submit an application for a licence. PEDL005 was awarded in April 1996. Immediately after the award of the licence, a forward plan was developed. Additional seismic data were discounted, since confirmation of viable hydrocarbon flow rates was the obvious objective. Re-entering the old well and drilling a sidetracked section out of the existing 9~" casing was evaluated as a low cost option. Testing of the re-entry (Saltfleetby lz) provided initial rates of 3.3 M M S C F D gas and 92 BBL/D condensate (BBLCD) from Early Westphalian/ Late Namurian clastics, possibly lateral equivalents of the Sub Alton, Crawshaw and Chatsworth/Ashover Sands of the Peak District.
Fig. 2. Dinantian and Early Namurian geological features.
Two sands with a combined 18 m thickness, the shallower of which was later proven to have a fault cut out of c. 20 m, were tested. Hydrocarbons were sweet with a gas phase CO2 content of 2.1%. Condensate was measured at 61 ~ API and the tested C G R was 29 B B L / M M S C F . Dew point of 3249psig was close to the initial reservoir pressure of 3566 psig, raising concern for deliverability impairment due to formation of condensate banking. Following confirmation of the tested hydrocarbons, a 3D seismic grid of 65 km 2 was acquired to define a location for appraisal drilling and improve the definition of the field potential. Saltfleetby 2 was drilled as an appraisal to the high point of the time structure mapping. The near horizontal reservoir section of this well was tested at 10.02 M M S C F D and 311 BBLCD with 32/64 choke and a W H F P of 2050psig and defined the commercial viability of the field. At this time, gas in place was estimated at 57 BCF, with an expectation of 40 BCF recovery. Further appraisal of the accumulation followed with the sidetracking of the discovery well to provide an optimized completion in a horizontal reservoir section. This tested at 13.4 M M S C F D and 493 BBLCD on a 40/64 choke with a W H F P of 1769 psig. Both
SALTFLEETBY FIELD the Saltfleetby 2 and Saltfleetby lu wells were retained as potential producers. During the Spring and Summer of 1999, after approval of the field development plan, two additional development wells, Salfleetby 3z and Saltfleetby 4, were drilled and the pipeline laid and hooked up. The first of these development wells was preceded by a punch through appraisal of the eastern extent of the field (Saltfleetby 3), resulting in the well penetrating a crestal depth high remote from the central time high indicating an east-west variation in velocity. The punch through was also important in defining the presence of hydrocarbons in deeper Namurian sandstones. The location of the Saltfleetby 3z and 4 wells had been decided by using a seismic inversion and CNL/GR prediction undertaken by Hampson Rusell. Resulting well tests showed 15.6 MMSCFD and 15.9 MMSCFD respectively and 2.3-2.7 mD test permeability. The export pipeline was completed with a challenging 51 river and road crossings, a significant number of which were under drilled, in September 1999. Field production commenced at 52 MMSCFD in December 1999 from the four completed development wells. A fifth well was drilled in September 2000 to target the Namurian sand, which had been confirmed as gas bearing in the Saltfleetby 3 appraisal punch through. This Saltfleetby 5 well was again completed horizontally with a 201 m net sand interval and an initial flow rate of 19.8 MMSCFD and 576 BBLCD. A further 269 m of net Westphalian sand was left behind cemented casing for future recompletion.
Fig. 3. Saltfleetby Field Top Reservoir depth structure map.
913
Total net sand interval in the five producing wells amounts to 1479m of open hole completion and 237m of cased hole completion. To date (end June 2001) 24BCF of gas has been produced, together with 0.48 MMBBL of condensate. Gas-in-place estimate has grown to 114 BCF and there is an expectation of 73 BCF producible reserve, CGR has decreased to 16.5 BBL/MMSCF.
Structure, trap, and seal Licence PEDL005 and the Saltfleetby Field is located at the southwestern edge of the South Humber Basin, an Early Namurian/ Dinantian depocentre initiated by Late Devonian-Early Carboniferous rifting similar to that forming the Gainsborough Trough to the west. To the west and south is a steep rise in basement structure onto the East Midlands Platform and the London Brabant Massif (Fig. 2). The major control on structure formation is primarily Mid Westphalian and to a lesser degree Late Westphalian compression and inversion. The effect of the inversion is particularly evident over the adjacent Keddington Field, but only hinted at in the Saltfleetby structure (Fig. 3), which is a predominantly dip controlled closure. Thermal sag to the east during the Tertiary resulted in a c. 5 degree tilt to the east, was important in redistribution of hydrocarbons, and probably resulted in a significant reduction in the Saltfleetby Field closure. Gas re-migration from the east during this stage may have
914
T. HODGE
been important in gas charging and displacement of earlier liquid hydrocarbons to the west. Westward the Late Carboniferous section maintains its general thickness over the Dinantian shelf carbonates, through Biscathorpe 1 Apleyl and to the Welton Field. Over the westward traverse, the Late Namurian and Early Westphalian reservoirs thin onto structural highs, demonstrated most significantly by Biscathorpe 1 where the potential reservoir interval is only 3 m, compared to the combined 56 m of the Saltfleetby Field. Southward there is considerable thinning of the Carboniferous section onto the London Brabent Massif. There is evidence that the potential reservoir section, as demonstrated by the correlation through Scupholme 1, Saltfleetby 1 and Holton Holgate 1 (Fig. 4), preserves its thickness and onlaps the Dinantian and in places older section. Reservoir quality deteriorates with an increase in distal fine-grained sediment to the south. Significant truncation of late Carboniferous section occurs to the south. It is important to recognize that structural closure at base Permian level is absent over Saltfleetby (Fig. 5), and that seal is obviously provided by Westphalian marine and overbank mudstones, something which is not widely considered feasible in adjacent Southern North Sea play definition.
Reservoir Proven reservoir is comparable with that of the established oilfields of the East Midlands, to the west being Late Namurian to Early Westphalian age Lower delta clastics. The sands are probably lateral equivalents of the Sub Alton, Crawshaw, Chatsworth and Ashover sands of the Peak District, but field nomenclature deliberately
Fig. 4. North-south regional well correlation.
avoids that terminology and breaks the section into reservoir units (Fig. 6). The lateral equivalents may be inferred from the identification of the important correlation markers of the G. amaliae (Norton) and the G. subcrenatum (Pot Clay) marine bands used in the standard nomenclature. Over the Saltfleetby Field, the Late Namurian rests unconformably on carbonates of Dinantian age. Regionally the G. amaliae marine band is seen as the top of the Early Westphalian Deltaics and is regionally utilized as the top of the sand-prone reservoir section. The Saltfleetby 3 well is displayed as a field type log, with virtually full core coverage over the reservoir interval (Fig. 7). Unit 3 sands developed immediately below the marine band are typically found at the flanks of other structures (cf. Welton, Scampton North, Kelstern) suggesting some syn-depositional inversion pulsing and early structural formation. To date Saltfleetby drilling has not proven any hydrocarbon bearing Unit 3 although a distal crevasse is described in the Scupholme 1 well at the northern flank. Unit 2 sands are thought to represent moderately wide channels within a very broad flood plain. Lateral isolation of Unit 2 channels may be expected, the flood plain covers the proven penetrations at Saltfleetby with a reduction in channel thickness and expected persistence to the west. Lateral facies variation and isolation at the western edge of the field may be important in defining upside reserves and a deeper spill to Keddington at the top of the deeper Unit 1 sands. Typically the Unit 2 sands are medium to coarse, but with very rapid lateral transition between wells into channel margin fines. Unit 2 net thickness varies from 0-8 m, and has 491 m of net along hole completion in the producing wells. Average porosity from log and core data is in the range 9-11.5%, net to gross from well data has a wide range of 0.32-0.85 and demonstrates the penetration of channel margin or inter-channel sections by some wells.
SALTFLEETBY FIELD
915
Top Zechstein
Top Rotliegendes Top Carboniferous
Top Reservoir Intra - Reservoir green yellow
Top Dinantian
Fig. 5. East/west seismic section across Saltfleetby Field.
The Unit 1 sands are responsible for 71% of the Saltfleetby Field reserves and are massive coarse to conglomeratic with inferred very large channel system widths. Across Saltfleetby the Unit 1 sands have laterally consistent gross thickness and good connectivity (Fig. 6). Proven well thickness indicates close to 20 m of sand with high net content. The overall environment of deposition is suggested as being a lower delta plain, with rapid infill of palaeotopography by the Unit 1 sands and increasing restriction of channel deposition during the Unit 2 and 3. Initial interpretation of the Saltfleetby lz zonation suggested thinner reservoir sands, but 3D seismic interpretation and correlation with subsequent wells clearly demonstrates a fault cut out of c. 20m. Some 1225 m of net Unit 1 completion is present in the high angle development wells, with an additional 237 m currently isolated behind casing in the Saltfleetby 5 well. Average porosity from log and core data is in the range 9-12%, net to gross from well data is consistent at 0.87-1.0 and reflects the full field distribution of a relatively homogeneous unit. The Namurian sands are separated from the Westphalian reservoirs by the G. subcrenatum marine band. The net reservoir in the Late Namurian at Saltfleetby appears to be provided by distributory and crevasse feeder channels. Cored section of the Namurian indicates that grain size is fine to medium, compared to the coarser Westphalian sands (Fig. 7). Only one well, Saltfleetby 5 is currently completed over the Namurian, and only the Scupholme 1, Saltfleetby lz and Saltfleetby 3 wells provide additional penetration data. The four main development wells, Saltfleetby l u, 2, 3z and 4, were completed horizontally within the Westphalian only. Drill stem test production from the Namurian in Saltfleetby lz was significantly higher than that from the Westphalian; 2.64 M M S C F D compared with 0.3 MMSCFD. Saltfleetby 3 was drilled as a punch through in the east of the field and provided a full cored section of the reservoirs. Core analysis demonstrated thin beds of significantly higher permeability, up to 800 mD in the Namurian than the typical 1-10 mD of the Westphalian sands.
Source Thick organic rich basinal mudstones are present in the Gainsborough Trough and evident in the offshore portion of the Humber
Basin. These are widely accepted as the dominant source of the majority of hydrocarbons in the established oil and gas fields to the west. An association with basin centre Westphalian coals with their wax rich components has also been made in analysis of nearby oils, resulting in a complex multi-source hydrocarbon mix. The current understanding of Saltfleetby as being a gas full to spill structure, with the adjacent Keddington Field to the west having an oil accumulation without a gas column and initially low GOR, indicates the complexity of the hydrocarbon fill.
Seismic database The initial 3D seismic cover for the Saltfteetby Field was 65 km 2 shot in May 1997. This was acquired with an open sparse pattern, with source line spacing of 840 m and receiver spacing of 480 m providing a nominal 10.5 fold. Interpretation of the dataset demonstrated that the structure continued to the absolute eastern extent of the data cover. Later in 1999 an additional 55 km 2 was acquired with similar parameters, the exception being a closer source line spacing of 780 m, providing a nominal 11 fold. The dataset lacks the clarity of fault definition of high fold 2D data in the Humber area, but provides good imaging of the top Dinantian carbonates and therefore the structural form of the base of the reservoir interval. Top reservoir mapping is heavily reliant on well control and time consuming intensive manual picking.
Development and production At the time of field development consent in March 1999, the Saltfleetby Field had two completed and tested horizontal wells (Saltfleetby 2 and lu) in the Westphalian sandstones. Base case development strategy defined the addition of two new horizontal producers at the eastern and western edges of the field. An additional follow up location was indicated in the south of the field. A fifth well, Saltfleetby 5, was added after a year's production to produce from Namurian sands, not considered as part of the original development. The southern location is to be drilled during the third quarter 2001.
916
T. HODGE
Basal Westphalian/Namurian Reservoir Sequence
Siikstone Coal
Base Amaliae Marine Band Unit 3a
Unit 2b Unit 2a
Unit l d
Unit l c
Unit l b Unit l a G. subcrenatum Shale
Namurian C
Namurian B
Namurian A
Dinantian Limestone
Fig. 6. East Lincolnshire generalized stratigraphy and Saltfleetby Reservoir log character.
SALTFLEETBY FIELD
SALTFLEETBY 3-Field Type Section
Fig. 7. Reservoir type section (Saltfleetby 3 near vertical appraisal).
917
918
T. HODGE
Fig. 8. Saltfleetby Field core analysis.
Two separate sites were used for the development, with two wells on each. Facilities on site were minimal, twin high pressure 6" lines linking the A site with the B site, while the B site hosted methanol dosing and the production test seperator. The high pressure site-to-site lines were laid as a consideration for future gas storage usage. Export from the B site is mixed phase, including reintroduced test seperator fluids and gas, via the 10" export line to Theddlethope. A dedicated slug catcher separates liquid and gas before introduction to the main Theddlethorpe process. Compression facilities at Theddlethorpe (originally built for the Pickerill Field) will in late 2001 be used to reduce the operating pressure of the Saltfleetby export line. Production sites are manned 24 hours and telemetry relays information to both the Theddlethorpe Control centre and Roc Oil (UK)'s office. The desire to complete the reservoir section of the development wells barefoot without the significant (compared to total well AFE) cost of screens instigated a sand production study on cored material. Results indicated that sand production from the very competent reservoir sandstone would not occur. Production facilities have continued to monitor for sand production without any reported observations. The sand production study demonstrated up to 16% reduction in permeability with low drawdown, increasing to 25% reduction with maximum drawdown. Staged SEM analysis confirmed that migration of kaolinite fines, blocking pore throats, was to blame for this dramatic reduction in permeability. During production, no significant early stage loss in productivity has been seen in the Saltfleetby wells from the kaolinite fines movement or from the formation of condensate banking. It is believed that either effect occurs immediately after drawdown is induced during well clean up, and the effect is seen as the typical 1.2-5.5 skin factor reported from test analysis. Production from the initial four development wells has exceeded expectation of initial simulation work and the planned introduction of compression facilities has been delayed by a year due to the
maintained wellhead pressures. These wells continue to produce gas and condensate free of water. The Namurian producer Saltfleetby 5 experienced water production and hold up problems after the production of 1.4 BCF gas. Open hole logs identified a zone of fracturing at the proximal end of the horizontal section and subsequent simulation work has conclusively indicated that the source of water entry to the well has to be via fractures. Indicative effect of the fracture productivity is the 18 mD test permeability compared to previous wells of 2.0-4.7 mD. It is anticipated that the Saltfleetby 5 well problem will be remedied by a workover isolating the fracture zone.
The Saltfleetby Field data summary Trap
Type Depth to crest Lowest closing contour GOC or GWC Gas column Oil column
Four way dip closure 2234m 2325m 2325 m 91m 0m
Pay zone
Formation Age Gross thickness Net/gross ratio Porosity average (range) Permeability average (range) Petroleum saturation average range Well productivity (Sandface AOF)
Sub Alton-Ashover Equivalent Late Namuria-Early Westphalian 56m 0.34-0.71 (sand prone interval) 9.5 to 12.5% 1 to 10mD 80% 24-28 MMSCFD
Petroleum
Condensate density Gas gravity
61~ 0.721 sg
SALTFLEETBY FIELD Dew point Process condensate yield Gas expansion factor
3249 psia 23 BBL/MMSCF 225 SCF/RCF
Formation water
Salinity Resistivity
53 500 NaC1 eq ppm 0.085 ohm m
Field characteristics
Area Gross rock volume Initial pressure Pressure gradient Temperature Oil initially-in-place
Gas initially-in-place Recovery factor Drive mechanism Recoverable oil Recoverable gas Recoverable NGL/condensate
919 114 BCF 55 to 71.5% Pressure Depletion n/a MMBBL 63 to 82 BCF 0.84 to 0.98 MMBBL
Production
2857 acres 587 763 acre ft 3566 psia 0.112 psi/ft 183~ n/a MMBBL
Start-up date 15th December 1999 Production rate plateau oil condensate 1450 BOPD Production rate plateau gas 52.2 MCF/D Number/type of wells 5 horizontal
The West Firsby Oilfield, Development Licence 003, Lincolnshire R . J. B A I L E Y
Tullow Oil International Ltd, Dublin, Ireland
Abstract: The West Firsby Oilfield exemplifies the classic east Midlands oil play, sourced by early Namurian pro-deltaic shales.
Stacked fluvio-deltaic sandstone reservoirs of latest Namurian to early Westphalian 'A' age are structured into a Variscan inversion anticline in the hanging wall of the northeastern boundary fault of the Dinantian-Namurian Gainsborough Trough. The Enterprise West Firsby-1 discovery well, drilled on a 'Top Westphalian ' A " seismic depth closure, encountered oil-bearing sandstones at three levels. These are thought to represent the earliest Westphalian 'A' Sub-Alton/Crawshaw distributary channel and mouthbar sandstones (Reservoir Zone [RZ] 1), the stacked fluvial channel sands of the Namurian Rough Rock (RZ2) and an underlying high quality mouth-bar sandstone (RZ3). In the hanging wall setting, these units can be correlated over an area far larger than the West Firsby Field. On acquiring operatorship of the Development Licence (DL 003) in 1991, Tullow Exploration put the WF-1 well into production from RZ2 and 3 disposing of produced water in the earlier-drilled and unsuccessful WF-2 step-out. Between 1992 and 1996, three new production wells (WF-4, -5 and -6) were drilled from the same surface site. The wells principally produce from RZ2 and involve high-angle/horizontal sections in these sandstones, approaching 170 m in length in WF-6. Strong aquifer support, coupled with the injection of produced water into RZ2 of WF-2, promotes early natural flow from such wells at rates up to 800 BOPD, and when this declines jet-pumping can maintain production at rates of several hundred BOPD/well. As of 1st January 1999, the West Firsby Oilfield had produced 0.97 MMBBL of an estimated 13 MMBBL OIIP, maintaining an average annual rate during 1998 of 345 BOPD from four wells. Remaining recoverable reserves are estimated at around 1.03 MMBBL.
..
~.~. PL179b
0 I
SCALE
~, ~
~
~ - *DLI/ N ~GTO " I N"1L~'/~~ " ~%" R "I~ ~ -
COLDHANWORTH l
PL179b
5Km SCAMPTONNORTH
"--~- (/STAINTON 1- i
Fig. 1. The West Firsby Oilfield in its structural setting. 'Contours' are intended to suggest the structure at top Reservoir Zone 2 rather than indicate absolute depths. GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 921-926.
921
922
R.J. BAILEY
The West Firsby Oilfield, near the village of Spridlington, Lincolnshire, was discovered in 1987 by the Enterprise Oil Company's West Firsby (WF) -1 exploration well. The well was drilled on trend with previous oil discoveries in the hanging wall of the Morley-Campsall Fault System (Fig. 1). This fault system, also known as the AskernSpital Fault (Fraser et al. 1990), forms the northeastern flank of the Gainsborough Trough, the grabenal Dinantian-Namurian depocentre that hosts many of the commercial oil fields in northeastern England (Fraser et al. 1990). The drilling target for WF-I was a subtle dip-closed feature mapped at the high amplitude seismic reflector correlated with the Top Westphalian 'A' (Fig. 2). In common with previously discovered fields in Lincolnshire and north Nottinghamshire, the West Firsby trap structure shows pre-Permian (Variscan) roll-over and/or structural inversion against a major growth fault active during the Dinantian and Namurian. The discovery well encountered a stacked series of oil-bearing sandstones in three reservoir zones [RZ] around the level of the Namurian-Westphalian boundary (Fig. 3). Cased-hole drill-stem tests, conducted in the side-tracked WF-1Z hole, flowed oil at up to 750BOPD with 50% water cut, from RZ3 sandstones and at 145 BOPD with no water cut from RZ2. The shallowest oil-bearing sandstones of RZ1 were not tested.
The success of WF-1 prompted the drilling, during 1988, of two deviated appraisal wells from the same surface site. WF-2 stepped out some 600 m to the SE (Fig. 4). Cores and logs confirmed sandstones with oil shows, readily correlated with those tested in WF-1Z. A further, 1200 m, step-out in the same direction, was immediately drilled. The WF-3 well again confirmed the continuity of the three reservoir zones, but drill-stem tests of RZ1 and RZ2 produced only water. The subsequent long-term production tests of the entire RZ2 in WF-2 were also disappointing, producing 95% water, despite indications that the higher unit (2A, Fig.3) was oil-bearing. The WF-3 well was plugged and abandoned; WF-1Z and WF-2 were suspended. In 1991, Tullow Oil acquired from Enterprise Oil a majority interest in the West Firsby Oilfield, (Development Licence DL003) and assumed operatorship, with a view to producing the three proven oil zones in WF-1Z. RZ3 was put on production in July 1991; and production from RZ1 and RZ2 followed during 1992. The subsequent development involved the acquisition of some 25 km of new seismic data, re-processing of the existing seismic, re-mapping of the field, and the drilling of three further production wells in the crestal area of the field. The final interpretation of the West Firsby Oilfield's geometry, combining the seismic data with the results of the new wells, is shown in Figure 4.
NW 500
WF-5
WF-IZ
Offset 100m S
Offset200m N
WF-6
WF-2
SE
--
Top Up. Mg. Lst ~ '
t Nr Top Westphalian ' A ' ~ 1000
- -
I Base Zone 2A Coal ~ J"
l Top Dinantian
m
0
Scale (km)
1 I
Fig. 2. Seismic line TOC 507R, running along the crest of the West Firsby structure (see Fig. 4 for location). Arrows on the section indicate the approximate position of top Reservoir Zone 2. Note the characterless nature of the reservoir interval.
WEST FIRSBY OILFIELD
Stratigraphy
Seismic Markers
Lincs. Lst
Reservoir Zones
923
GR
0
Lias Rhaetic
Top Bunter (Top Sherwood)
Keuper 500
Bunter
Top Up. Mg Lst. Top Carboniferous
Zechstein 1000
Westphalian Coal Measures
Nr Top Westphalian 'A' 1500
Namurian
Fig. 3. The general stratigraphy of the West Firsby Oilfield, showing the reservoir zonation as seen in the WF-1Z discovery well Throughout the development of the field, the equity shares in the work programme and production have been Tullow Exploration Ltd. 53.34% and Edinburgh Oil and Gas plc. 46.66%.
Structure The tectonic history of the West Firsby area reflects the development of the Gainsborough Trough and more particularly of the MorleyCampsall Fault System that formed its northeastern flank (Fig. 1; MCFS, Fig. 4). This fault system developed from lines of weakness in the Caledonian basement during the early rifting phase of the Variscan tectonic cycle (Fraser et al. 1990). It exerted a strong control on Dinantian deposition, separating a carbonate platform, to the NE, from the basinal marine environments of the subsiding Gainsborough Trough, to the southwest. The transition from rifting to post-rift thermal sag occurred towards the end of the Dinantian. During the Namurian and Westphalian, rivers from northeasterly provenance areas flooded the crustal sag developed over the Gains-
borough Trough with the fluvio-deltaic clastics (Fraser et al. 1990). Evidence of continued fault growth is seen during this interval; and local footwall uplift is implied by the absence of the Namurian from areas north and east of West Firsby, where Westphalian 'A' reservoir sandstones may rest directly on a Dinantian limestone surface. Similar unconformable relationships characterise the Welton oilfield, which overlies a basement high to the south of West Firsby; and in this case the Westphalian 'A' Basal Sandstone forms the main oil reservoir (Rothwell & Quin 1987). The Variscan movements were minor in their effects on the Gainsborough Trough, causing mild inversion against the bounding fault system. On seismic lines orthogonal to the Morley-Campsall Fault System, the anticlinal West Firsby structure (Fig. 4) is clearly seen to be truncated at the Base Permian unconformity and thus is Variscan in age. Post-Permian structural development shows reactivation of the Morley-Campsall Fault System, but generally reflects only Mesozoic regional subsidence, peripheral to the Southern North Sea Basin. Widespread uplift during the Tertiary removed much of the passively-accumulated Mesozoic and Cenozoic cover (Fraser et al. 1990).
924
R . J . BAILEY
Fig. 4. The detailed structure of the West Firsby Oilfield as mapped at top RZ2. The approximate limits of the proven oil at this level are indicated by the darker shading. Proven/probable oil in untested compartments on the western flank of the field is indicated by the lighter shading. Note the subtle saddle on the northwest, separating the West Firsby oil pool from the East Glentworth structural nose (cf. Fig. 1). MCFS, Morley-Campsall Fault System. Wells are located on the map at their point of penetration of the reservoir zone. In the case of WF-5 and WF-6 development wells, the azimuths of the horizontal penetrations of RZ2 are indicated.
Definition of the field's structure is problematic, in that the Westphalian 'A' to Namurian reservoir interval generates no readilymapped seismic reflections (Fig. 2); and weak primary events are masked by multiples generated between the top Trias and the high impedance contrast surface at the top Magnesian Limestone. Drilling in the area showed that depth maps of the 'near top Westphalian ' A " seismic horizon, though often effective in identifying areas of closure, did not completely conform to structure at reservoir levels. For this reason, the reservoir interval was scanned for mappable seismic events. The best of these proved to be associated with the coaly shale horizon separating sub-zones 2A and 2B of RZ2 (Figs 2 & 3). Although not a consistent, reliable event (Fig. 2), interpretation of this horizon, when calibrated by reference to the 'near top Westphalian ' A " and top Dinantian seismic markers and other impersistent events corresponding to the reservoir section, could be used to define the field's structure (Fig. 4). Other key horizons, such as Reservoir Zone tops, were mapped by adding or subtracting the appropriate isochores.
Trap Trap definition in the hanging wall anticline at West Firsby is problematical in another sense, in that the oil accumulations appear to be confined to a minor culmination on a larger southeasterly-
plunging structural nose in which the reservoir section rises towards East Glentworth-l, 5 k m to the NW (Fig. 1). Paradoxically, although this up-dip well encountered oil-bearing sandstones in the Westphalian 'B', the clear correlatives of the West Firsby reservoir zones were water-bearing. Tullow's 20 kin 1993 seismic programme was primarily designed to investigate the intervening structural saddle, implied by the results of the West Firsby and East Glentworth wells; but on the latest (1994) seismic interpretation, by S. T. Brown, this remained narrow and subdued in relief (Fig. 4). The new mapping and subsequent wells suggested the importance of faulting in the West Firsby's structural development. The hanging wall anticline is transected by minor, W N W - E S E trending horst and graben features, the orientation of the latter suggesting a right-lateral component of displacement on the Morley-Campsall Fault System (Fig. 4). It is possible that the trap is at least in part dependent on these faults, though their small vertical throws would be expected to result in sand/sand juxtaposition at reservoir levels (Figs 3 & 4). Evidence from formation water chemistry, pressure relationships and saturation gradients within the West Firsby Field suggests that each of the three recognized reservoir zones, and probably each of the individual sub-zones of RZ1 and RZ2 (Fig. 3), represents a separately-sealed oil accumulation, with its own oil-water contact or transition zone (see Reservoir and Exploration & Development Concepts, below). This appears to hold despite the thinness of some
WEST FIRSBY OILFIELD of the intervening mudrocks and coals and the possibilities for crossfault communication within the confines of the field (Fig. 4). It is also evident that that the field is effectively top-sealed by the transgressive shale horizon immediately overlying RZ1.
Stratigraphy All West Firsby wells have been deviated from a site on the southern flank of the pre-Permian anticlinal trap structure (Fig. 4). They first penetrate the Middle Jurassic Lincolnshire Limestone and then drill through an essentially conformable sequence comprising Lias Shales, Triassic Mercia Mudstones and Sherwood (Bunter) Sandstones, and Permian marls and dolomitic limestones (Fig. 3). The wells penetrate the Base Permian unconformity at around 980m TVDss and enter the Westphalian, a thick heterolithic sequence of clastics and coals. Modern drilling practice favours the use of PDC bits in this section, and these tend to reduce cuttings to rock flour, placing the emphasis of lithological interpretation on the M W D gamma logs obtained while drilling. The Westphalian section commences with around 125m of fining-upwards channel sandstones and carbonaceous claystones with rare coals, probably of late Westphalian 'C' age. The underlying Westphalian 'B/C' coal measure section, c. 275 m in thickness, is dated by log correlation with local wells. The section from around 1400 m TVDss is identified as the Westphalian 'A' and includes prominent coal beds correlated with the Deep Hard (1433m TVDss) and Parkgate (1455m TVDss) coal marker horizons. The regionally-developed 'near top Wesphalian ' A " seismic event (Fig. 2) closely corresponds with the stratigraphic boundary, yet the lithological character of the section appears little changed from that of the Westphalian 'B/C'. Two prominent coarsening-upwards cycles, equated with the Kilburn Rock, provide M W D gamma ray log markers used while drilling the production wells to indicate the proximity of the Westphalian 'A' reservoir section (RZ 1). The deeper of these (K2 marker, Fig. 3) shows a particularly sharply-marked transition from crevassesplay or mouthbar sandstones up into high gamma shales. A similarly abrupt transition defines the top of RZ 1 of the West Firsby Oilfield at around 1522 m TVDss (Fig. 3). On the basis of regional litho-/biostratigraphical correlation within the Gainsborough Trough, the Westphalian-Namurian boundary horizon, the S u b c r e n a t u m Marine Band, is placed within the 25 m clay section separating RZ1 and RZ2 (M. Storey, pers. comm., 1992). This dating suggests that RZ1 includes the near basal Westphalian 'A' Crawshaw Sandstone; and that RZ2 represents the stacked channel sandstones of the Namurian Rough Rock (Fig. 3). The West Firsby wells typically reach their total depth in the underlying Namurian shales and sandstones.
Reservoir The general picture emerging from the study of the extensively cored WF-1, -2, and -3 wells is of a deltaic depositional system, fed by braided rivers and prograding southwards and westwards into a poorly-oxygenated, initially marine, basin probably more than 50 m deep. The stacked, braided sands, around 45 m thick in the case of RZ2, evidently occupy channel systems kilometres in width. Distributary mouthbar and crevasse splay sandstones are expected to show lesser sand-body scale and connectivity, but still form units (e.g. in RZ1) that can be correlated several kilometres from the West Firsby Field. The 25-30 m RZ1 is divided into two sub-zones by a 3 m shale and coal interval equated with the Alton Coal (Fig. 3). Sub-zone 1A (15-20 m) consists of three minor, coarsening-upward, distributary mouthbar and channel sandstones, separated by thin shales. None of these medium to coarse sandstones give strong indications of oil saturation and none has contributed significantly to the production from the West Firsby Field.
925
The 10m sub-zone 1B, a proven oil reservoir, is sandwiched between the Alton shale/coal horizon and the underlying Mid Reservoir Shale unit (Fig. 3). The predominant facies is a medium to coarse grained, high-energy, distributary channel sand, and the contact with the Mid Reservoir Shale is erosional - characters consistent with the identification of sub-zone 1B with the Crawshaw Sandstone (Hampson et al. 1997). The unit has has been produced from WF-1, WF-4 and WF-5. It has some of the best reservoir properties in the field, with log porosities in the crestal production wells averaging 15.8% and permeabilities from well test data exceeding 50 mD. Greater textural maturity, coupled with late dissolution of early calcite cements, may explain its relatively good poroperm characteristics. The downward passage from the 20-25 m Mid Reservoir Shale unit into RZ2 is gradual (fining-upward) in WF-1Z and WF-2, and the definition of the zonal top is correspondingly arbitrary (Fig. 3). Its abruptness and the relative thinness of the zone in WF-4 and WF-6 are interpreted to be the result of faults penetrated by these wells (Fig. 4). The three, 10-15m sub-zones recognized within the 45m thick RZ2, each comprise stacked, fining-upward series of medium to coarse grained, distributary channel sandstones and gravel lags. The intervening 2-3 m coaly horizons (Fig. 3) suggest intervals of channel abandonment, which culminate in the upward passage into the Mid Reservoir Shale. Reservoir properties of the RZ2 sandstones are moderate to poor, with average core porosities between 10% and 14%, and permeabilities rarely more than than 20 roD, largely the result of pervasive kaolinitization. As such they are close to the empirical lower limit for producibility of Namurian-Westphalian sandstone reservoirs in conventional wells (Fraser et al. 1990) The final oil-producing unit in the West Firsby Field, the 5-6 m thick RZ3, is separated from the RZ2 channel sandstones by a fieldwide, marine mudstone, some 10 m in thickness (Fig. 3). In contrast to the overlying reservoirs, RZ3 shows a coarsening-upward trend and sharply defined top, thought to mark marine transgression over a high-energy beach or upper shoreface deposit. The reservoir properties of fine to coarse grained sandstones in this zone are remarkable, with permeabilities in excess of 1 D and core porosities in the 15-20% range. Early ferroan dolomite cement is thought to have protected the sandstone from kaolinitization, with the latestage dissolution of the carbonate - possibly associated with early migration of h y d r o c a r b o n s - generating the present poroperm characteristics.
Source The waxy, undersaturated 35 ~API oils that typify the West Firsby Oilfield have not been geochemically typed, but there is little doubt that their source lies in the Namurian organic-rich, pro-delta shales of the Gainsborough Trough. Burial maturation of these source rocks post-dates Variscan trap-formation. Oil migration, limited to the Gainsborough Trough and its immediate environs, was triggered during the slow and protracted Mesozoic burial of this feature, probably in the Cretaceous, and ended by Palaeogene regional uplift (see Fraser et al. 1990).
Exploration and development concepts The WF-1 well, and the subsequent unsuccessful WF-2 and WF-3 step-outs to the SE, established a number of key features of the oil accumulation that were important in the subsequent development. Firstly, over an 80 m interval in WF-1 Z, a stacked series of thin, oilbearing sandstones had been proven, with a well-defined OWC at 1630 m TVDss in the highly-productive RZ3 (Fig. 3). Secondly, the appraisal wells established the required degree of lateral continuity in the three reservoir zones. However, in WF-2, the sandstones of RZ2, though all above the level of the OWC established WF-1Z,
926
R. J. BAILEY
gave disappointing test results, producing 95% water. This indicated that there was no common OWC across the anticlinallystructured reservoir zones. As previously noted, subsequent analysis suggests that each reservoir zone, and possibly each individual subzone recognized in RZ1 and RZ2, should be treated as a discrete oil accumulation. The relatively poor reservoir properties of RZ Subzone 1B suggested an oil-water transition zone beginning at around 1550 m TVDss, while in RZ2 a probably longer transition began in Sub-zone 2A at around 1600 m TVDss (Fig. 4). Field development began in July 1991 with production from the prolific RZ3 of the WF-1Z discovery well. The combination of a deviated well, and high pour-point, waxy crude dictated that artificial lift should be by down-hole jet-pump, rather than the more familiar rod-pumping systems used in the East Midlands. Produced water was disposed-of in WF-2. Rising water cut led to production from RZ3 being suspended early in 1992, and subsequently there was commingled production of oil from RZ2 (sub-zones 2A and 2B) and RZ1 (sub-zone 1B), which has continued at diminishing rates until the present day. Development concepts thereafter focused on accessing the reservoir zones up-dip of WF-1Z, and also on drilling highly deviated 'horizontal' wells through RZ2, with the aim of optimizing production from this relatively poor, but volumetrically important reservoir. The 25 m, or so, Mid Reservoir Shale, permitted the wellbore to be built to the required high angles and allowed 7 ,t casing to be set immediately prior to penetrating RZ2. Below this, the horizontal 6" section of the well was completed open-hole over RZ2. Also, by maintaining deviation angles of 60 degrees, or less, in RZ1, the option to perforate this higher zone through casing was retained. Lessons were learned from problems with the reservoirs' sensitivity to damage and the unexpectedly high water cuts in WF-4, the latter problems possibly associated with a fault extending from the vicinity of the WF-2 injection well (Fig. 4). The subsequent WF-5 and WF-6 development wells were designed to avoid damage (mud weights 8.7 ppg across the reservoir section) and focused on achieving long, 'horizontal' sections in sub-zones 2A and 2B of RZ2 (Figs 3 & 4). In WF-5, the benefits of this approach were immediately evident. RZ2, exposed along 130 m horizontal section of the wellbore, initially produced at 820 BOPD, declining to 330 BOPD over four months. RZ1, on perforation, produced at 710 BOPD, declining to 380 BOPD with a 16% water cut.
WF-6 targeted RZ2 between WF-1 and WF-2 and thus was deliberately located somewhat down-dip of the discovery well. Although a minor fault was encountered, separating the Mid Reservoir Shale from the upthrown RZ2 (Fig. 4), the latter reservoir proved to be at virgin pressure and the 170 m section exposed to the horizontal wellbore produced naturally for over a month, initially at around 450 BOPD. Later jet-pumping increased this to 800 BOPD. Most of the 348BOPD average production from the West Firsby Field during 1998 came from RZ1 and RZ2 in the WF-5 and WF-6 wells. Recoverable reserves under the current four-well production scheme are around 1.6MMBBL (approaching 12% recovery), of which 0.93 M M B B L had been produced by end 1998. The potential to increase this ultimate recovery, from within the body of the field largely rests on improving the recovery of the substantial OIIP of sub-zone 1B, ideally by exploiting the horizontal drilling techniques successfully employed in WF-5 and WF-6. There is also the option to appraise all three reservoir zones in the as yet untested area on the western flank of the field (lighter shading, Fig. 4) The writer would like to thank Tullow Oil plc. and Edinburgh Oil and Gas plc. for permission to publish this paper. Simeon Brown's expert geophysical mapping provided in Figure 4. The writer was part of the field development team led by Mike Dodworth of Troy Petroleum Management Services. Andy King of Troy, and consultant David Lloyd prepared the figures.
References FRASER, A. J., NASH, D. F., STEELE, R. P. & EBDON, C. C. 1990. A regional assessment of the intra-Carboniferous play of Northern England. In: BROOKS, J. (ed.) Classic Petroleum Provinces. Geological Society, London, Special Publications, 50, 417-440. HAMPSON, G. J., ELLrOTT,T. & DAVIES, S. J. 1997. The application of sequence stratigraphy to the Upper Carboniferous fluvio-deltaic strata of onshore UK and Ireland: implications for the Southern North Sea. Journal of the Geological Society, 154, 719-733. ROTHWELL, N. R. & QUIN, P. 1987. The Welton Oilfield. In: BROOKS,J. & GLENNIE, K. W. (eds) Petroleum Geology of North West Europe, Proceedings of the Third Conference. Graham and Trotman, London, 181-190.
The Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey and Sussex, UK Onshore S. T R U E M A N
Star Energy, Humbly Grove Oilfield, Hampshire GU34 5SY, UK Present address: ECL Technology Ltd, Innovation Centre, Exploration Drive, Offshore Technical Park, Bridge of Don, Aberdeen AB23 8932, UK
Abstract: The Weald Basin of SE England is a lozenge shaped accumulation of sediments occuring from Southampton and Winchester in the west to Maidstone and Hastings in the east. It is approximately 150 km long by 60 km wide, covering an area of some 9000 km 2 (Fig. 1). Several commercial oil and gas discoveries have been made, mostly on the flanks of the basin. These fields have been in continous production since the early 1980s. Field size in terms of recoverable hydrocarbons is small, 0.5 to 6 MMBBL of oil is typical. Hydrocarbons are produced primarily from the Middle Jurassic Bathonian Great Oolite at Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth and Horndean fields but also from the Late Oxfordian-Early Kimmeridgian Corallian Sandstone at Palmers Wood; Portland Sandstone at Brockham and Godley Bridge; Corallian Limestone at Bletchingley; Purbeck Sandstones in Albury and Late Triassic Rhaetic calcarenites in Humbly Grove. Cumulative oil production from the basin as a whole is currently 19. I MMSTB.
The structural history of the Wealden District can be divided into three main phases: a pre-Mesozoic period culminating in a platform of folded Palaeozoic rocks, a Mesozoic period of downwarping and sedimentation and thirdly, a period of Tertiary uplift and folding. Palaeozoic rocks underlying the basin were deformed by major N-S compression giving rise to E - W trending thrusts and N W - S E dextral wrench faulting dating from the Late Carboniferous Variscan orogeny (Stoneley 1982). During the Late Triassic and Early Jurassic, N-S oriented crustal extension and subsidence began in the Weald Basin area, with the London Platform to the NE remaining a high area. This crustal extension resulted in extensive E - W trending listric faulting in the Jurassic and Lower Cretaceous, with the majority of faults hading down to the south. A thin deposit of 'Rhaetic' sediments consisting of calcarenites, sandstones and oolitic limestone were deposited in the western area around Humbly Grove, thinning northeastwards towards the London Platform. These sediments preceded a thick sequence (50008500ft) of Jurassic shales, rich in organic matter, limestone and Lower Cretaceous fluviatile sandstones and shales. By the end of the Lower Cretaceous, active subsidence by faulting had ceased, and 1500-2000 ft of Upper Cretaceous clay, sands and chalk were deposited over the region. Throughout the Cretaceous, oil was generated in the more deeply buried Lower Jurassic Liassic shales, with peak generation occuring during the Late Cretaceous and Early Tertiary. The oil then migrated into tilted fault blocks on the basin flanks. Tertiary uplift subsequently raised most Jurassic rocks above the depth required for hydrocarbon generation (Hancock & Mithen 1987). A regional stratigraphical section indicating hydrocarbon producing horizons is given in Figure 2 and a detailed subdivision of the Great Oolite in Figure 3.
Production history The production history of Weald Basin fields is shown in Figure 4. The location of the Fields is shown in Figure 1.
Nature of Great Oolite fields The Great Oolite is the main proven hydrocarbon reservoir in the Weald Basin and is typically 150-200 ft thick, occuring between 3000 and 4000 ft TVDss. The depositional environment, lithology and subdivision has been well documented and described (Sellwood et al. 1985, 1987). It usually consists of quartz-free, oolitic, skeletal and oncolitic limestones with minor and variable amounts of clay. Facies are predominantly of high energy shallow shelf origin with
individual major units of oolitic grainstone being traceable from NE to SW over great distances (Fig. 3). Porosity in the Great Oolite fields is generally moderate to high, around 15-24%. In any well, due to complex diagenetic processes, the highest porosity is not consistently within the same facies or stratigraphical zone. The dominant remnant pore system is based upon microporosity within ooliths and other micritized particles. Interconnectivity is poor and based upon micropathways between cement crystals. Horizons of vadose solution texture (fitted fabric) provide thin (2-3 cm) enhanced 'lenses' of improved permeability, but they can not be correlated between wells confidently. Permeability in the fitted fabric zones are generally < 10 mD. At Humbly Grove and Storrington, much higher permeabilities are preserved. In terms of matrix permeability, fields can thus be divided into two broad categories: high permeability or low permeability (Table 1). The low permeability fields have matrix permeabilities typically 1 mD or less with occasional zones exhibiting fitted fabrics. In the high permeability fields, permeabilities can vary from <0.1 to 2000 mD with a pronounced bimodal distribution. The higher permeability fields have probably received an early charge of hydrocarbons where burial diagenesis was strongly inhibited in the palaeohydrocarbon zone. In exploration terms therefore, early or preTertiary structures are considered most prospective. Evidence of natural fracturing in the Great Oolite is rather scarce, coming predominantly from well test, drilling fluid loss and production data where fluid rates far exceed matrix productivities. Consequently, any attempt to model fracture distribution is compounded by their relative rarity in core material; coarse 2D seismic grids and a general sparsity of data. Given this level of uncertainty, it has been suggested that horizontal wells be turned through 90 degrees for maximum chance of intersecting the primary fracture direction. Reasonable predictions have been made, however, (Stockbridge Field for example) using break out logs to analyse the primary stress direction. Consequently, horizontal wells have been drilled predominantly in a N E - S W direction with some success (average five-fold increase in oil production). It is noted, however, that fractures can also be conduits for water and it is not uncommon for relatively dry oil wells producing at high rates (>1000 BOPD) to suddenly and rapidly produce high water cuts. Oil columns, due to the compexity of the pore systems, are almost entirely within transition zones. The complexity of the reservoir is such that water saturation (Sw) distribution within separate reservoir zones cannot be realistically defined by capillary injection studies. In certains fields (Horndean, Singleton, Stockbridge) it has been shown that no consistent height v. Sw relationships exist either by well or reservoir zone groupings. The position of the oil-water contacts is therefore particularly subjective, and usually based on the level of lowest moveable oil, or producing water-cut at which
GLUYAS,J. G. & HICHENS,H. M. (eds) 2003. United Kingdom Oil and Gas Fields', Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 929-941.
929
HUMBLY GROVE FIELD
Period 0 ;0
Epoch
Lithostrat.
Cenomanina to Campanian
Chalk
Late Albian
Upper Greensand
Mid Albian
Gault Clay
Early Albian Aptian
Lower Greensand
Late Valanginian to Barremian
Wealden
Ryazanian to Early Valanginian
Purbeck
Portlandian
Portland
Lith.
931
Producing Fields
~::==:-
"U m c o9
C)
C O3
_1_1_1_1~ _1_1_1_1_1~
8 4
.. .. .. .. .. . .. .. .. .. .. C "13 73 m
Kimmerdgian
Kimmeridge Clay
Late Oxfordian
Corallian
Early Oxfordian Callovian
Oxford Clay
Bathonian
Kellaways Beds
.
Albury
Brockham,Godley Bridge
r
C
.
Or) O3 0
E3 E] [-m
Cornbrash, For. Marble Great Oolite
r
C ~> O3 O3
O C[-" O O3
m ~ ~
,.,.,...,-,.,..-,-,
...........
~ ~ ~ ~ ..........
Palmers Wood Bletchingley
Humbly Grove, Herriard, Stockbridge, Goodworth, Horndean, Singleton, Storrington
i ~ i i i n i i i i i i
Fullers Earth Bajocian
Inferior Oolite
Toarcian-Aalenian
Upper Lias
Late Pliensbachian
Middle Lias
Early Hettangian Pleinsbachian
Lower Lias
To
i
i
i
i 99 [ e m i R
Penarth Group
TRIASS
Rhaetian(?)
Rhaetic
CARB
Tournaisian
Carb Limestone
I
Humbly Grove
Fig. 2. Regional composite stratigraphical section. wells become uneconomic. Log calculated saturations are regularly used for modelling height saturation relationships, but here also, the interpretation is complicated as the derivation of the cementation exponent 'm' is problematic. Initial overestimation of reserves is common for Great Oolite reservoirs and usually related to an over-optimistic, assumed, recovery factor and/or high STOIIP due to optimistic oil-water contacts. As some fields near the end of their economic life (for primary oil and gas production) actual recovery factors are low, typically 6-10% of the original oil-in-place. Poor recoveries are associated with low permeability reservoir and long transition zones.
Fields have negligible aquifer support and the primary reservoir drive mechanisms is due to reservoir fluid expansion and solution gas drive.
Humbly Grove Location, discovery method and history The Humbly Grove Oilfield is located in Hampshire, 4 km N of Alton on Production License P L l l 6 B .
932
S. TRUEMAN Lithology
Lithostratigraphy
Reserv -oir Zone
m m m m m m m m m m
Cornbrash and Forest Marble Herriard Member
9
m
mm
I
m l l
o. 0. ~-
OJ m
r
o
--~--~)--II!
Hoddington Member
0
Humbly Grove Member
IV V
Hesters Copse Formation
~ . r,.'.',.~
-.-=--##. n .',.'..~.,',.~.
'
Fullers Earth
Seismic surveys, mostly using a Vibroseis source, acquired during the late 1970s and early 1980s allowed identification of pre-Upper Cretaceous structuring not seen at the surface due to the chalk cover. The discovery well, Humbly Grove-1 (HG-X1), was drilled in May 1980 by Carless. Oil and gas was found in the Bathonian, Great Oolite limestones, and later confirmed by further seismic (1980, 1981, 1982) and appraisal drilling (1982) (Fig. 5). Humbly Grove-2 (HG-A1) also discovered gas in a deeper Triassic 'Rhaetic' reservoir, later shown to have an oil leg by Humbly Grove X4. Following Annex B approval, development commenced in 1985. Thirteen deviated wells were drilled from three sites between March 1985 and May 1986, and a gathering centre, pipelines and rail terminal constructed. A second phase of development included two horizontal sidetracks drilled from donor wells (1994, 1995) and a dual-lateral horizontal well completed in 1996. The Original Annex B estimate of reserves totalled 13 MMSTB recoverable (proven + probable) and 3 BCF free gas.
Reservoir The detailed stratigraphy and sedimentology of the reservoir is documented in Sellwood et al 1985. The Great Oolite is divided into three major units that can be correlated field wide (and over much greater distances). The 'Humbly Grove' and 'Herriard' Members (Fig. 3) commence with massive coarsening-up oolitic and pelloidal grainstones. The middle 'Hoddington' Member is an argillaceous, oolitic wackestone and packestone interpreted to have been deposited on an open shelf environment, dominated by terrigenous muds following a rise in sea level. This member is a significant vertical permeability barrier with important implications for reservoir production behaviour. The overlying Cornbrash and Forest Marble has poor reservoir quality but can produce hydrocarbons where naturally fractured. Within the Great Oolite oil leg, the average permeability decreases by two orders of magnitude below 3395 ft and average porosity decreases by only 1.3% (Heasley et al. 2000). Petrographical studies indicate that the transition corresponds to a significant increase in pore filling burial diagenetic cements (ferroan calcite and ferroan dolomite). This is accompanied by a change of the effective pore system from a combination of primary intergranular mesoporosity plus secondary intragranular microporosity (above 3395 ft) to predominant intragranular microporosity (below 3395, Figs 6 & 7). The diagenetic and reservoir heterogeniety at Humbly Grove is attributable to an early episode of oil emplacment and the establishment of a syn-diagenetic oil-water contact at 3395 ft. Burial diagenesis was strongly inhibited in the palaeo-oil leg, but precipitation of ferroan carbonate cements and dissolution enhancement of microporosity was able to continue in the palaeo-aquifer. The field
Fig. 3. Generalized Great Oolite stratigraphic section. consequently preserves a marked vertical heterogeniety irrespective of facies or depositional variability.
Development and production Field estimate of stock tank oil initially-in-place is 43 MMSTB. The current cumulative oil production from the field is 5.7 MMSTB oil and 6 BCF gas. Wells have been in continous production by natural flow and gas lift since 1983. Gas has been used for generation of electricity for site consumption, and the surplus re-injected or vented. Produced water is also re-injected. Surplus gas since February 2001, has been used to power 2 x 5 megawatt turbines and electricity generated for sale directly to the local grid. Later in 2001, well HG-A1 will be recompleted over the Rhaetic gas interval to supplement the power generation scheme. The field has been considered for gas storage and considerable work undertaken on the feasibility of the project (1998-1999). Over the last few years additional work has been delayed due to the government moratorium on gas powered stations. The ban was lifted in October 2000, and work is now again in progress to update the simulation model for gas storage predictions and detailed design. Gas storage has the potential to prolong field life indefinitely and considerably improve oil recovery factors.
Herriard
Location, discovery method and history The Herriard Great Oolite oil accumulation lies within the Humbly Grove Development area and was discovered in June 1983 by the Herriard 1 well. An additional appraisal well, Herriard 2 was drilled in May 1985 but found a separate fault block with poor oil shows and high water saturations. STOIIP is estimated to be 6 MMSTB in the Great Oolite, and cumulative production is 0.34 MMSTB. The field is not currently producing. Table 1. Great Oolite producing fields categorized by matrix permeability
Field
Type
Humbly Grove Storrington Singleton Horndean Stockbridge Goodworth Herriard
High Permeability High Permeability Low Permeability Low Permeability Low Permeability Low Permeability Low Permeability
HUMBLY GROVE FIELD Four wells are currently producing oil from the Great Oolite and three of these horizontal development wells are artificially lifted with jet pumps. Reservoir modelling has highlighted the possibility of untested reserves, below the Hoddington Member. Work is currently underway to assess the feasibility of drilling additional horizontal drainholes.
937
Production and development To date a total of 17 wells have been completed on the field. Stockbridge in terms of size and STOIIP (171MMSTB) is the largest field in the Great Oolite Weald Basin. Cumulative production from the field is currently around 5.5 MMSTB.
Goodworth Albury Location, discovery method and history Location, discovery method and history Original seismic data were acquired between 1979 and 1988 using a mix of vibroseis and hydropulse sources. The Albury Field was discovered by Conoco in 1987 after drilling Albury-1. The field is located to the south of Guildford on the North Downs. No additional wells have been drilled.
Reservoir The Albury reservoir is a relatively thin (21ft) fine-grained glauconitic sandstone, developed within the uppermost part of the Lower Purbeck beds. Petrographic analysis of the sidewall core samples from this unit suggest a shallow marine, possibly offshore bar origin. The distribution of the Albury sand is controlled by the Albury-1 and Bramely-1 wells, which encountered 15ft and 4.5ft respectively. All other information is too distant to be of use in constructing a depositional sand model. Various models have been tested, giving gas-in-place of around 7 BSCF above the elevation of the Albury- 1 well, and up to 22 BSCF if taken down to the structual spill point. Material balance estimates suggest 2-3 BSCF of gas in the drainage area of the well. Structurally, the trap consists of a broad E - W trending inversion anticline in the hanging wall of the Hogs Back fault system.
Production and development The well initially tested gas at 3.7MMSCFD and 4 B O P D (32 ~ API). Gas is used for on-site generation of electricity. The production rate during the first phase of development, was determined by the permissible power export level based on 2 M W of installed generation capacity load using the local 11 kV network. The normal gas consumption of the two units at full load is (2 MW) 580 000 SCFD. The actual consumption is controlled automatically depending upon demand placed by the network. Cumulative production from the field is currently 814.1 MMSCF.
The Goodworth structure is located within Landward License PEDL021 in Hampshire, and is near to Andover in southern England. It was originally identified by Amoco as a satellite of the Stockbridge accumulation in the early 1980s. At that time the prospect lay in PL232 with a 50% Amoco, 50% Ultramar partnership. An exploration well, Goodworth-1, was drilled in early 1987 with a TD of 7005 ft MD (measured depth) and tested oil from the Great Oolite. After an acid fracture stimulation it was nitrogen lifted at rates of 129 BOPD, 37% water cut. A 90 day production test was carried out in the second half of 1987 with an average production of 75 BOPD, 40% water cut. Ultramar abandoned the well in 1990. It is now producing from a single horizontal well from the Great Oolite formation and is 100% owned and operated by Pentex.
Reservoir Structurally, the reservoir zone comprises an E - W trending horst that closes to the west by converging faults. The eastern part of the field is also faulted. The reservoir is very similar to the nearby Stockbridge Field, and is divided into four layers.
Production and development The most likely STOIIP is estimated to be 13.32MMSTB. The main uncertainty, however, is the position of the oil-water contact. The vertical hole has good oil saturations down to the base of Layer 3 and is considered to be oil down to (ODT) 3490 ft TVDss.
Bletchingley Location, discovery method and history
The Stockbridge Field lies onshore U K in licences PL233, PL249 and DL002 which are located north of Winchester, Hampshire. It was discovered by Amoco in 1984.
In 1963 a seismic survey carried out for Esso over the ML18 and ML21 mining licenses near Bletchingley, Surrey indicated the presence of two faulted structures. Between December 1965 and September 1966 four wells were drilled on these structures. Well numbers 1 and 2 were drilled on the eastern structure, and both tested gas from the Corallian Limestone of the Upper Jurassic series. The maximum flow rate achieved was 9.65 MMSCF/D. Well number 3 was drilled on the western faulted structure, and also tested gas but at a lower rate than that obtained in wells 1 and 2. A fourth well drilled between wells 2 and 3 was abandoned as a dry hole, the entire Corallian formation having been cut out by faulting. There is no production from the field currently.
Reservoir
Reservoir
The accumulation is of Middle Jurassic (Dogger) age and the reservoir is contained within the Great Oolite. The structure is a broad E - W elongated dome, separated into two major fault blocks (north and south) by an E - W trending fault. The majority of the producing wells are in the northern block. The reservoir is split into four correlatable layers. Layer 2 has the better reservoir properties.
The Corallian limestone occurs at approximately 3400 ft TVDss in the Bletchingley area and is 130ft thick. It is mostly massive carbonate, occasionally oolitic, reefal in places with vugular and leached intergranular porosity. It is sudivided into four units (1 at top) of which units 1 and 3 contain porous and permeable carbonates and Unit 2 and 4 are tight and shaly with no indications of
Stockbridge Location, discovery method and history
940
S. T R U E M A N
o
~
o,
U
8
on
~
0 .,,-i
c~
r
r'~
I
I
~
~
i
I
~ o
oo
~
,-~
oo
0 . ,...~
~
~.
S"
oo
0
0 i
o
~Z~Z8
~@
l l l I Z
m
oo
0
T 0
0% eq
r
I
r
0
I ooo~
~s c ~9o
oo
~
r
0
9
cq
o@ r o ~,
~
o'~
0 r~
@ @
i
I
9
B, 00
@
~t
CN
oo
0 .,,-~
8
rN
o~
F~
@
~
.~
~~
H U M B L Y GROVE FIELD
oo
-~
o
oo
o~,- o ~ o
o~
oo
on oo o~ o oo
E~ ~ o
on ~'~
0 ~ _
oo oo
oo
o
0
o o~
o o
~
r
~ oo o
9
oo~oooo
941
The Kimmeridge Bay Oilfield, Dorset, UK Onshore J. G. G L U Y A S 1, I. J. E V A N S 2 & D. R I C H A R D S 3
1 Acorn Oil & Gas Ltd, Ash House, Fairfield Avenue, Staines, Middlesex T W 1 8 4 A N 2 B P Exploration, Britannic House, 1 Finsbury Circus, London, U K 3 B P Exploration, Sherwood House, Blackhill Road, Holton Heath Trading Estate, Poole, Dorset, B H 1 6 6LS, U K
Abstract: The Kimmeridge Oilfield is the oldest commercial discovery of petroleum in the Wessex Basin. The field was discovered in 1959. The discovery well was completed for production and that same well continues to produce today, more than forty years after discovery. More than three million barrels of oil have been produced. Oil is trapped in fractured, Middle Jurassic, Cornbrash limestones in an anticline. The anticline is a product of Alpine inversion tectonics. Moreover, the Kimmeridge accumulation is unusual insofar as it is the only inversion structure to contain a commercial quantity of petroleum and the only producing field in the hanging wall of the Purbeck Disturbance.
The Kimmeridge Oilfield lies in Kimmeridge Bay on the south Dorset coast. It is a shallow oil accumulation within a faulted inversion anticline and it lies immediately to the south (downthrown) side of the main Purbeck disturbance, which is the most important structural feature in the area (Underhill & Stoneley 1998). The field was discovered in 1959 and began producing in 1961. It still produces from the same single well at a rate of 100 BOPD and it has produced over three million barrels of oil. The 'nodding donkey' above Kimmeridge Bay is a local landmark (Fig. 1) and Kimmeridge is probably the most visited oilfield in the UK. Until Evans et al. (1998), little had been published on the field other than brief mentions in Brunstrum (1963) and Selley & Stoneley (1987). Here we largely reproduce the Evans et al. (1998) paper. The oil search that led to the discovery of the Kimmeridge Bay oilfield began in earnest in 1935. In December of that year, the first prospecting licences under the 1934 Petroleum Production Act were granted to the D'Arcy Exploration Company. These licences included 2227 square miles in southern England. Armed with their experience of the whale-back anticlines of the Iranian Zagros Province, Lees & Cox (1937) identified the Jurassic as the main target for early exploration in southern England. The first structures to be tested were large anticlines in southern England such as Portsdown, Henfield and Kimmeridge.
The Kimmeridge Bay structure was explored as part of D'Arcy's exploration for those licences awarded in 1935. Astonishingly, exploration wells were drilled over a 35 year period in these licences with the final well being drilled in 1980. The Kimmeridge Field was discovered in 1959 and was developed under a Mining Licence (ML5) granted in 1964. The field still produces under the terms of that licence. Expiry is due in 2014. Between the years 1959 and 2000, six wells were drilled in Kimmeridge Bay (Fig. 2). A few details for each of these wells are given below.
Broadbench-1 The petroleum potential of the Middle Jurassic Corallian limestones (Fig. 3) in the Kimmeridge Anticline was first tested by well Broadbench-1. It was drilled at the western end of Kimmeridge Bay from 1936 to 1937. The well reached the Upper Corallian and found an 'oblique joint in grey sandstone wet with light oil' at 252 m depth in the Sandsfoot Grit. This show was not adequately tested. The main objective, the Lower Jurassic, Bencliff Grit, which is oil impregnated at outcrop near Osmington Mills 10 miles to the west (Miles et al. 1993), was not reached because of mechanical difficulties. Broadbench -1 was plugged and abandoned at 287m in the Osmington Oolite.
Fig. 1. Photograph showing the Kimmeridge-1 well and Kimmeridge Bay. Photograph taken from the central part of Kimmeridge Bay looking NW. Inset picture shows 'nodding donkey' on well head of Kimmeridge-1.
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 943-948.
943
944
J . G . GLUYAS
ET AL.
Fig. 2. Map of Top Cornbrash showing well locations.
Broadbench-2 (Kimmeridge-1) The Corallian was again the main objective of a second well on the Purbeck Anticline. In 1950, an internal D'Arcy report recommended that a well should be drilled to a depth of 760 m to test this target. The well was also designed to investigate a high velocity layer (which is likely to have been the Great Oolite) recorded on a seismic refraction line along the northern flank of the anticline. However, this well was never sanctioned. Further proposals to re-test the Corallian at Broadbench was made in 1953 and again in 1956, the latter date coinciding with a renewed phase of exploration in southern England. The well was finally sanctioned. Broadbench-2 was added to a programme for the Failing M. 1 rig. It was to drill several shallow exploration wells on the Weymouth Anticline. By the end of the 1950s, a tank firing range occupied the highest part of the anticline at Kimmeridge Bay. Consequentially, a site was chosen just outside the firing range on the cliff top in Kimmeridge Bay. The well location was at the same structural elevation as Broadbench-1. Broadbench-2 (renamed to Kimmeridge-1) was drilled during February and March 1959. Core was cut in the Cornbrash Limestone at a depth of 512 metres sub-sea (TVDss). Oil was recorded to have oozed partially leached calcite veins within the core. Substantial mud losses to the formation were experienced at 520 m TVDss. An initial production test yielded oil at a rate of 30 BOPD. Two acid treatments were performed after which the well flowed briefly at 4300 BOPD. Following these tests the well was completed as a production well in the Cornbrash. The original plan had been to test the Oolites and the Lias but penetration of these horizons was postponed until Kimmeridge-3 was drilled.
TVDss but tests could not be performed on this zone. The well was plugged back and perforated within the Cornbrash. After three acid stimulations, oil production from the Cornbrash was measured at 26.5 BOPD with 4.5 BWPD. An oil-water contact was observed at 535.5 m TVDss. The well was used as an observation well until the end of 1992 when a further acid stimulation was performed and the well was then put on production for a short time.
Kimmeridge-2 Kimmeridge-2 was drilled 670m to the east of Kimmeridge-1 in 1960. The well entered the top Cornbrash at 583 m and was terminated within the uppermost Forest Marble. Mud losses occurred within the Corallian, the lowermost Oxford Clay, Kellaways Beds, Cornbrash and Forest Marble, indicating permeable horizons had been penetrated. Tests conducted on sands within the Oxford Clay produced 7.5 barrels of oil in 40.5 hours. After acid treatment, the Cornbrash produced only six gallons of oil. The well was retained as an observation well. Pressure measurements indicate that this part of the Oxford Clay is in communication with the Cornbrash reservoir.
Kimmeridge-4 Kimmeridge-4 was an appraisal well drilled in 1960 in a position 412m N W of Kimmeridge-1 to further appraise the anticlinal trap. The well was terminated at 262 m TVDss owing to a mechanical breakdown and was not tested. No mud losses were experienced. The well was not sufficiently deep to penetrate the Cornbrash reservoir.
Kimmeridge-3 Kimmeridge-5 Kimmeridge-3 was drilled during 1959-1960, before Kimmeridge-2. It was drilled to complete the programme intended for Kimmeridge1, by testing the Great Oolite, Inferior Oolite and Upper Lias, and to further develop the Cornbrash. The well lies 762 m SW of Kimmeridge-1. During drilling, mud losses were encountered at the Top Kellaways Beds and within the Forest Marble. The well was cored through the Cornbrash with heavy mud losses. A test of the Forest Marble (559-575 m TVDss) produced 600 BWPD of water. Tests on deeper formations were either unproductive or produced only water. There were some oil shows within the Bridport Sands around 942 m
Following the discovery and successful appraisal of the Wytch Farm Oilfield (Colter & Havard 1981), which lies only a few miles to the northeast of Kimmeridge Bay, there was renewed interest in the prospectivity of the deeper reservoirs in the area. In 1980 Kimmeridge-5 was drilled as an exploration well to test the deeper potential of the Kimmeridge structure at Sherwood Sandstone level with the Bridport Sands as a secondary target. The well was drilled to the Aylesbeare Group (Permo-Triassic). Weak gas shows and minor fluorescence were recorded throughout the Jurassic. The Sherwood
KIMMERIDGE BAY OILFIELD
945 STRATIGRAPHIC NOMENCLATURI
SUB-ERA, Ma
ERA
I PERIOD EPOCH
LITHOLOGY
UNCONFORMITY-BOU~ LITHOSTRATIGRAPHY MEGASEQUENCES
SUB-PERIOD
0
QUATERNARY ILl -~ PLIOCENE r
zi i i
s
50--
g
m
>.
O N O Z
o: < rr
UJ
uJ
C)
(Not present)
MIOCENE
iii z
OLIGOCENE : .:..-. ,.........,.. .,....... .:,. :~:" ("~::."::~':'" '.
,:~.: .~,-}~ : :
EOCENE
P
Barton F. . . .
tion
:~.:::::~.:l
TERTIARY
: ~ ' " ' " " "~ : ~ ' :~--I Bournemouth & : :: : ,, ! :.'," ~ : ::..',.: ~.,, !:'.." :. r: .:'I BrackleshamG r o u p s -~:: .'.~ :. ' : . ~ : : ' : . ~ : ] (Inc BagshotBeds) --r-"-r-"-r-- ' r - " / London Clay Formation "-r-"-r--'r/ ReadingBeds
PALEOCENE
MEGASEQUENCl
~
SENONIAN CHALK GROUP
UPPER CRETACEOUS
0
1 0 0 --
i :
0
GALLIC
i_,~.:. :
UPPER GREENSAND&
' " ";:-;,.;"'.'~:::. i "):.!
w
GAU LT LOWER GREENSAND "~/'~/'~*/'~/-~J-~-
"~
1 INTRA ALBIAN-
~
JUNCONFORMITIE
~.APTIAN
WEALDEN GROUP
0l 0 N
NEOCOMIAN I"CB ~ ~ .-r- .-r- "-r- "-r-
MALM
150 --
(J3)
U.I
o m
DOGGER (J2)
o0
PURBECK & PORTLAND BEDS
l"-r".-r--~.-r-~.-r-- ~ L
KIMMERIDGE CLAY FM CORALLIAN GROUP OXFORD CLAY FM ~
~ ~
I
r KELLAWAYS, CORNBRASH - I FOREST MARBLE
' ' ~YMBR) INFERIOR OOLITE
U)
< n-
LIAS
) "-r'-
(J1)
"-r'-
-'t--
"-r-
9J B . ~
"..:..: . . . . - . ,
. . . - : . - : : . ...
o.
BRIDPORT SANDS
~
DOWN CLIFF CLAY THORNCOMBE SANDS
(.0
-
- - DOWNCLIFF SANDS
u)
1--r-"-'---r--"~---r--~ --r--
200 --
-i--
"-r--
--r--
'r"i
--r'-
~p~
~--~--A~ -r-A-r~ A--v-A--v-A--v--A I --r--A ~ - - ~ A --r-
O l
or)
TR 3
or)
el,. I-
"-r-"
~
!
ZECHSTEINI
250 - -
'-r-
<
N 0 W
m w a.
SHERWOOD SST GRP
~ --r"-r- "-r- "-r-
300 - -
~
EXMOUTH & DAWLISH BEDS
C~ Z
Fig. 3. Stratigraphy of the Wessex Basin (from Underhill & Stoneley 1998).
Sandstone was encountered 453m deeper than prognosed at 2272.8 m TVDss. The sandstones had weak oil shows but reservoir quality was much poorer than in the Wytch Farm Field.
Structure, trap and seal The dominant structure in the area around the Kimmeridge Bay Oilfield is a tight and structurally complex monoclinal faulted fold known as the Purbeck Disturbance, (Fig. 4). The Purbeck Disturbance marks the northern limit of Alpine tectonics. Specifically, the monocline was created within Cretaceous chalk and younger sediments that overly inverted normal faults that cut the Lower Greensand and older sediments.
,,,O
r.
z=
om >< ;WO
EXETER VOLCANIC SERIES
o "
~
OTTER SST B P
AYLESBEARE MUDSTONEGROUP
uJ
< _i
%-
--I--
Z
0
WHITELIAS
LOWER
MERCIA MUDSTONE GROUP
. ...:., ...... . , . . . . : . . ~ . "~ ~ ' J ~ : ~ : " 1 " - '-'1-" - 1 " - " - r -
~
BLUE LIAS "F
PERMIANCRETACEOUS MEGASEQUENC[
GAB ~
VARISCAN UNCONFORMITY
. '~ z z ~"
=~
'
Highly d e f o r m e d PRE-VARISCAN
(ECONOMIC BASEMENT)
Kimmeridge Bay Field is unique insofar as it is the only commercially viable accumulation known to exist in an inversion structure within the Wessex Basin Basin (Hawkes et al. 1998). The trap at Kimmeridge Bay is only poorly imaged on seismic surveys (Fig. 5). Current opinion suggests that the trap is a simple faulted anticline. The main seal to the Cornbrash reservoir is the overlying Oxford Clay.
Reservoir The main reservoir in the Kimmeridge Field is fractured Cornbrash Limestone. Some reserves may also occur in fractured Oxford Clay.
946
J. G. GLUYAS E T AL.
N
S Kimmeridge-1 ENGLISH
metres 0
~ , ~ , ~ e r ~,<.u i di .,,a e
CHANNEL
-.
Stoborough-1 Purbeck Hills
Clay Fm
10002000-
issG>
Wareham-3
~
metres
- 1000 2000
3000-
3000
4000-
- 40O0
Fig. 4. NS cross-section through Kimmeridge Bay Field showing the nature of the structural inversion, associated faulting in the hanging wall and the Mesozoic extensional, tilted fault blocks in the footwall of the Purbeck fault (from Underhill & Stoneley 1998).
The Cornbrash Limestone is about 20 m thick and is a low porosity (tight), locally fissured limestone. Cores from Kimmeridge-1 and Kimmeridge-3 wells cover almost the entire section. Core analysis data indicate an average porosity of around 1% and virtually zero permeability. Oil staining in core is restricted to the open fractures. It is therefore assumed that production is from an extensive fracture system developed within the Cornbrash and also in the adjacent Kellaways Beds/Oxford Clay and the Forest Marble (productive at Wytch Farm). Abnormally low reservoir pressures characterize the Cornbrash reservoir. These are well below hydrostatic pressure. The initial pressure in Kimmeridge-1 was 400psi at 520m TVDss. This pressure would be expected in a reservoir several hundred metres shal-
lower. Deeper formations are normally pressured. Brunstrum (1963) suggested that oil may have been sealed in the fracture system prior to Miocene folding and that the fissures were physically enlarged during folding leading to reduced pressures. Some such explanation is necessary since there is no history of recent burial that might otherwise explain the pressures.
Source In common with oil from the Wytch Farm and Wareham fields, the oil was sourced from the Lower Lias (Selley & Stoneley 1987). Geochemical analysis of these oils supports this. The Kimmeridge
Fig. 5. Seismic line running NS through the Kimmeridge Field. Well Kimmeridge 2 lies at SP 158.
KIMMERIDGE BAY OILFIELD
947
0,60
0.50
/11
.-~ "0 0.40
E tO
4~ 3
/
0.30
o IX. 0
0,20
'l
/
0,10
\
~'y.,
1/
f,
\
0.00 1955
1960
1965
1970
1975
1980
1985
1990
1995
2000
Year Fig. 6. Graph showing average daily production v. time (from Evans et al. 1998).
0.60
0.50
~u
0.30
/
'
o 'fl_ 0
'\ \ '\
1 0.20
f y~--\
0.10
0.00
0.00
0,50
,00
1.50
2.00
2.50
3,00
3.50
Cumulative Production (mmstb) Fig. 7. Graph showing average daily production v. cumulative production (from Evans et al. 1998).
Bay oil has a significantly lighter gravity (45 ~API) than Wytch Farm oil (35 ~API), which suggests either that it was expelled from more mature source rocks or that some fractionation occurred during migration.
Development and production The production history for the Kimmeridge Bay Field is shown in Figure 6. Production began in 1960 and the rate rose rapidly to
948
J . G . GLUYAS E T A L.
250 BOPD, peaking at 500 BOPD in 1972. Production then declined steadily to reach approximately 100 BOPD in 1986 at which point it stabilized. Production continues at this rate today. Production was initially by natural flow, gas exsolution drive. Artificial lift, in the form of a beam pump ('nodding donkey') was installed in 1964. Water production is minimal, however gas production has increased gradually over time as pressure has declined. The initial rise in production rate from 200BOPD in 1961 to 400 BOPD in 1972 was difficult to explain and led to many theories about the amount of oil at Kimmeridge and its location. By 1975 cumulative production was 1.725 million barrels (Fig. 7) and yet no decline had been seen. Mapping at that time indicated closure over an area of 120-160 acres. The oil column was known to be 47-57 ft thick. Depending on the porosity (including fractures) which they assumed for the Cornbrash, various geologists calculated the area of closure required to contain the cumulative oil produced up to that time. These estimates varied from more than 2500 acres (assuming 1% effective porosity) to 250 acres (assuming 10% porosity). Each estimate of reservoir led to a new theory to explain the disparity between the mapped closure and that calculated from the reservoir behaviour. The most notable theories included: (1) (2)
(3)
(4)
Additional reserves trapped in an unmapped offshore extension to the Kimmeridge Structure at Cornbrash level. The presence of a more porous facies within the Cornbrash, not penetrated by wells but in contact with the producing wells through the fracture system. Supply of the Cornbrash reservoir from a second, deeper reservoir such as the Bridport Sands, possibly by continuing migration along faults The fissure system continues outside the Cornbrash into the Oxford Clay (as shown by Kimmeridge-2) and is extensive enough to contain all of the observed oil.
Some of these were discounted at the time based on available data. For example communication between the Bridport and Cornbrash was considered unlikely given their different pressure characteristics (the Bridport being normally pressured). Subsequent production has shown normal decline behaviour (Fig. 7) suggesting that the reservoir contains a finite reserve. Based on the decline behaviour, the ultimate recoverable reserve is now estimated to be 3.5 million barrels. The increase in gas/oil ratio (GOR) through time is consistent with exsolution gas drive (that is the formation of a natural gas cap through pressure depletion). However, no gas coning is observed in the Kimmeridge-1 well. It has been suggested that the increase in production rate during the early years may have been related to an
increase in the G O R effectively lightening the produced fluids thereby making them easier to lift (a partial natural gas lift). If a gas cap has formed during production, as seems likely, then this must be located outside the Cornbrash itself, probably in the overlying Oxford Clay. Based on cursory examination of the data now available, some combination of an extensive fracture system, extending out of the Cornbrash, possibly higher effective porosities and a larger structure than mapped onshore would seem to provide a plausible explanation of the production behaviour observed at Kimmeridge. If the drive mechanism is assumed to be predominantly exsolution-gas then the recovery factor is likely to be between 15 and 30%. Back-calculation therefore suggests that the stock tank oil initially-in-place (STOIIP) is in the range 10-25 million barrels. Thanks to BP Exploration Operating Company for permission to publish this paper.
References BRUNSTRUM,R. G. W. 1963. Recently Discovered Oilfields in Britain. In: 6th Worm Petroleum Congress. Section 1, Paper 49, 11-20. COLTER, V. S. & HAVARD,D. J. 1981. The Wytch Farm Oil Field, Dorset. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of North-West Europe. Heyden and Son Ltd., London, 494-503. EVANS, I. J., JENKINS, D. & GLUYAS,J. G. 1998. The Kimmeridge Bay oilfield: an enigma demystified. In. UNDERmLL, J. R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publications, 133, 407-413. HAWKES, P. W., FRASER, A. J. & EINCHCOMB,C. C. G. 1998. The tectonostratigraphic development and exploration history of the Weald and Wessex Basins, Southern England. In. UNDERmLL,J. R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publications, 133, 39-66. LEES, G. M. & Cox, P. T. 1937. The geological basis for the present search for oil in Great Britain by the D'Arcy Exploration Company Limited. Quarterly Journal of the Geological Society, 93, 156-194. MILES, J. A., DOWNES,C. J. & COOK, S. E. 1993. The fossil oil seep in Mupe Bay, Dorset: a myth investigated. Marine and Petroleum Geology, 10, 58 70. SELLEY, R. C. & STONELEY, R. C. 1987. Petroleum habitat in south Dorset. In." BROOKS,J. & GLENNIE, K. (eds) Petroleum Geology of Northwest Europe. Geological Society, London, 139-148. UNDERmLL, J. R. & STONELEY,R. 1998. Introduction to the development, evolution and petroleum geology of the Wessex Basin. In: UNDERHILL, J. R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publications, 133, 1-18.
Appendix 1
Trap Type
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft) Gas column (ft) Oil column (ft)
Albury
Andrew
Arbroath
Arkwright
Structural Fault block -2050 GDT -2144
Four way dip closed anticline 6660 7274 7274
Domal antiform
Four way dip closure
8030 8250 8250
8500 8607 8607-8620
614
220
151
Forties Paleocene 330 (260-440) 0.5 (0.3-0.8) 24 (3 30) 80 (1-2000) 55 (25-65)
Forties Paleocene 5O2 0.78 (0.6 0.9) 19 (16-21) 40 (20-50) 51 (25-73)
0.66 38-42 0.43 2670 700 1.456
Pay zone Formation Age Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
Purbeck Sandstone Lower Cretaceous 21 12.5 25.3 1067 84
Forties Formation Palaeocene 1161/653-1539 0.65 0.27/0.10-0.36 700/30-4000 0.85
-
25/5-70
Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
31 0.574 8 150 1.02
37 0.76 1142-1390 300 1.22
0.28 38-42 0.4 1991 490 1.327
Formation water Salinity (ppm NaC1 eq.) Resistivity (ohm m)
80000 0.072@ 89~
55000 0.034
135000 O.023 @245~
55000 0.023 @245~
300
23 000 64 382 3215 96 4196
7712 555 000 3700 245 334
1473 12 600 3700 25O 73
57 Predominantly bottom drive acquifer with peripheral water injection 2545
51 Aquifer drive/gas lift
34 Aquifer drive
170
25
September 1965 520 000
1990 42 000 12 production wells 8 injection wells
1996 8000 2 producers 1 injector well
Reservoir conditions Temperature Pressure (psi) Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
1100 89 2-3 Gas expansion
Recoverable oil (MMBBL) Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
February 1995 500 1
142 well slots 103 wells 59 producers 11 water injectors 72 spares/dead
GLUYAS, J. G. & HICHENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 949-977.
949
950
APPENDIX 1
Armada
Auk
Fleming
Drake
Hawkins
Type
Stratigraphical/structural
Tilted and inverted fault block
4-way closure over salt diapir
Structural
Depth to crest (ft TVDss) Lowest closing contour (ft)
-8500 -9200
-10920 -11322
-9500 -102000
7300 7750
GWC or OWC (ft) Gas column (ft) Oil column (ft)
-9191 700
-11322 400
-10145 650
n/a 0 450
Formation
Maureen Formation
Fulmar Formation
Fulmar Formation
Auk Formation
Age
Paleocene
Upper Jurassic
Upper Jurassic
Rotliegend
Gross thickness (range) (ft)
0-300
450
1000
Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index (BOPD/psi)
0.55 0.18 200 81
0.70 17 5 64
0.85 (0.46-0.92) 19 (11-27) 5 (0.2-125) 55-80
Trap
Pay zone
0.98 22 60 88
1 (vertical well average)
Hydrocarbons
Oil or gas density (~ API) Oil or gas gravity (o API) Viscosity (cp) Bubble point (psig)
0.65
0.67
0.66
0.025
0.033
0.031
38 Solution gas only 0.9 7O0 190 1.54
Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB) Formation water
105 000
Salinity (ppm NaC1 eq.) Resistivity (ohm m)
0.124@60~
0.076 @ 60~
0.07 @ 60~
0.025 @ 205~
53.6 66.6 4092 257@ -900fi
4.7 10.228 6185 293 @ - 11 200 ft
5.5 5544 276 @ -10000ft
1064
472
225
Depletion
Depletion
Depletion
93 28 4067 @ 7600ft TVDss 215 795 133 19 Natural water drive/artificial lift 151
October 1997 (20 000-23 000 Armada total) (450 off-platform Armada total) 5 high angle extended reach
October 1997
October 1997
2 extended reach S-shaped
1 high angle extended reach
Reservoir conditions
Temperature Pressure (psi) Fiehl characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism Recoverable oil or gas (MMBBL)
11.99
Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
January 1976 70 000 peak rate n/a 10 explorative/appraisal 23 deviated development wells/poroduction sidetracks 8 horizontal Sidetracks
UK OIL A N D GAS FIELDS
951
Balmoral
Banff
Barque
Beaufort
No information provided
Four-way dip closure over salt diapir, with side, top and updip seal provided by shaly lithologies -4249 (approximately) -9600 (approximately) Structure is not full to spill -4551 298 (approximately) 3059
Dip closure with anticlinical rollover against fault
Tilted fault block
7000
Up to 16000
8400 8618 8618 8565 240
Leman Sandstone (Rotliegend)
Leman Sandstone
Lower Permian
Early Permian
700-800
270
i
Ekofisk and Tot chalk. Oil is present in overlying Paleocene sands, but this oil is not considered recoverable except to the extent which it drains into the chalk Late Cretaceous (Tor Formation) and Early Paleocene (Danian) (Ekosfisk Formation) Ekofisk and Tor ranging from approximately 1000 ft (300 m) near FWL, thinning to zero at updip edges of raft 69.8 Mean = 20.3 (P90/P10 10-27) 0.1-10 (Chalk) 1-60 (Paleocene) Mean = 62.3
11.1 0.02-100 51
0,95-1.0 17 (10--24)
30 (1-1000) 80
200-300
38-40
0.59
0.609 0.023
196200
0,115 @ 60~ (15.5~
160 000 ppm chloride 200 000 ppm NaC1 equivalent 0.02
77-99~ (25-37~ 2600-3750, depending on reservoir elevation
175~ 3800-3850 at d a t u m 8 2 0 0 ~ TVDss
1000 563 928 acre ft (695 x 106m 3)
9000
419 3.40E= 04 4001 195
3020 (includes barque 'J' area)
4O 8O Volumetric 32
Phase 1: September 1996, Phase 2: January 1999 Up to 60 000
October 1990
1996
2 producers 2 injectors
Two normally unmanned platforms, installed 1990 and 1994 17 development wells (+1 producing appraisal) to date 2 further development wells planned in 2000-1 Future infill drilling dependent on well/field performance
2660 @ GOC 2200 @ OWC @ 180~ (82~ 600-800 1.31
64000
0.0185
304 26 Water injection
25 1
952
Trap Type
APPENDIX 1
Beinn
Beryl
Bessemer
Birch
N o
Structural/stratigraphic
Tilted fault block
-9600 (Beryl A) 10 400 (Beryl B) None (Beryl A) - 1 0 900 to - 1 1 000 (Beryl B) 500 1959
8450
Combination structural/stratigraphic landslide closure 12 868
8696 8696
13 250 13 815 (OWC)
218 -
947
Leman Sandstone
Brae Formation/Brae Conglomerate Late Jurassic
information
provided
Depth to crest (ft TVDss) Lowest closing contour (ft) G W C or OWC (ft) Gas column (ft) Oil column (ft) Pay zone Formation
Age
Middle Jurassic (Bathonian/Callovian) 500 (200-860) 0.85 (0.4-0.99) 17 (10-23) 350 (30-4400) 0.88
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (roD) Petroleum saturation average (range) (%) Production index (BOPD/psi)
947 83 10.5 (0.8-27.7) 94.3 (0.01-4480) 70.2
30 (1-1ooo) 80
5-120
37 (oil) 0.71 (gas)
0.609 0.023
3200-4900 900-1500 1.5-1.7
Formation water Salinity (ppm NaCI eq.) Resistivity (ohm m)
65-75
42-43 0.90 0.14 4225 2648 2.4
196200 0.0185
100000 0.0935
1050 9.40E+ 04 4029 195 -
988 423 343 7462 270 75
130
-
Solution gas and gas cap drive
80 Volumetric
-
-
42 Waterflood 30
July 1976 575
1995
Reservoir conditions Temperature Pressure (psi)
Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
250 0.95-1.0 17 (10-24)
10-100
Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism Recoverable oil (MMBBL)
Early Permian
207~ 4900 ( - 10 500 ft TVDss)
1488 -
-
29 producers 3 gas injection 8 water injection
50 2
14 September 1995 28 000 70 000 1 exploration 3 appraisal 2 development
U K OIL A N D GAS F I E L D S
Bletchingley
Boulton B
953
Brae Central
East
North
Structural faulted dome
Tilted fault block
Structural/stratigraphic
Four-way dip closure
Three-way dip + f a u l t
- 3 3 8 0 South; -3050 North
12400-12570
11 570
12680
11920
- 3 7 5 0 South; -3750 North N o t seen
Field f u l l t o spill
12000 13 426
13735 13735
12475
250-420
1055 1676
Corallian Limestone Upper Jurassic
Westphalian C Lower Ketch unit Carboniferous
131 50 10 <1 48
580 (550-700) 0.37 (0.32-0.42) 10 (8.0-12.0) 73 (0.1-1000) 61
Brae
Brae
Brae
Late Jurassic (Kimmeridgian Early Volgian) 800 (0-1676) 0.6 11.5 100 (1-1000)
Late Jurrasic (KimmeridgianLate Mid-Volgian) 1055 0.85 17 (3.4-28.7) 558 (0.04-8490) 84 (80-95)
Late Jurassic (Kimmeridgian-mid-Volgian) Variable 800-1150 0.85 15 (7-23) 300 (0.3-2000) 85
20-100 (wet gas)
60
39-49 (oil) 0.85 (gas) 0.05-0.11
39-50 (oil) 0.85 (gs) 0.05-0.11
295
4112 1415 1.77
2.2-9.0 1.04 (0.6-0.72 wet gas)
2500-6500 0.00064
2000 000 ppm 0.16
79 000 0.098 @ 60~
45 000 -72 000 0.04616 @ 255~
77 000 0.12 @ 60~
5302
47OO 1600 000 6900 @ 12475TVDss 26O
0.65 33
168
85 000 0.06 @ 120~
240~ @ 12 555 0.17
ft
246~ @ 12600ft TVDss 7057 @ 12 600 ft TVDss
3700 120
619 000 6490psia @ 12555ft -
1800 675 000 -
1-16 Fluid Exp./sol'n gas
206 69 -
20
-
-
31 December 1997
65 75
September 1989 7500
D C Q 39 1 exploration 5 appraisal 10 development (to M a y 1999)
1.32
x
106
7456 254.7 447 2303 80 Gas recycle 242
December 1993 115331 750 1 exploration 5 appraisal 26 development
8O Gas recycle 207
March 1988 81 500 600 1 discovery 6 appraisal 27 development
954
APPENDIX 1
Brent
Brae
Brent Reservoir
West
South
Balder Reservoir
Flugga Reservoir
Structural/stratigraphic
Structural
-5350 -5620 -5516 (16/07a) (GWC) -5433 (16/06a) (GWC) -5650 (16/07a) (OWC) 166 (16/07a)/13 (16/06a) 104 (16/07a)/187 (16/06a)
-5450 -5652 -5500 (16/07a) (GWC) -5652 (16/07a) (OWC)
Unconformity: tilted fault block 8240 9300 8560 (GWC) 9040 (OWE)
50 (16/07a) 152 (16/07a)
320 480
Trap
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft)
Combination structural/stratigraphic 11821 12100 13488
Gas column (ft) Oil column (ft)
1670
Type
Pay zone
Formation Age Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index (BOPD/psi)
Brent Group Middle Jurassic
Brae Upper Jurassic (Kimmeridgian-mid-Volgian) 800 (0-1670) 0.75 11.5 131 (1-2100)
58 87 31.0 7500
72 85 29.2 6000
80
92
92
10-40
350-500
250
3702 1343 1.73
22 5.75 2455-2485 271 1.16
22 3.5 2485 296 1.15
75 000 0.120 @ 60~
600 000 0.138 @ 60~
60 000 0.138 @ 60~
810 (780-850) 21 (16-28) 650 (10-6000)
Hydrocarbons
Oil or gas density (~API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
33-37
(oil) 1.02-1.05 (gas)
-
54.7 (oil), 0.74 (gas) 1.58 1.80
Formation water
Salinity (ppm NaCI eq.) Resistivity (ohmm)
25 000 0.236 @ 77~
Reservoir conditions
Temperature Pressure (psi)
204~ 5785
253~ @ 12740ft TVDss 7128 @ 12740ft TVDss
Field characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
1213 69 936 2525 @ -5620 ft TVDss 145 116 35 (16/07a)/0.34 (16/06a) 31 Water drive
650 46 968 2640 @ -5652 ft TVDss 145 76 5 (16/07a) 31.5 Water drive
36
24
July 1983
20 October 1997 35 000 (first 4 wells only)
20 October 1997 35 000 (first 4 wells only)
2 exploration 6 appraisal 42 development
5 horizontal producers 1 water injector
5 horizontal producers 1 water injector
6OOO 2 750 300
33
Recoverable oil (MMBBL)
30 sq miles
Water injection, gas injection; depressurization 6
Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
November 1976 97 000 866
UK OIL AND GAS FIELDS
955
Brimmond
Britannia
Brown
Camelot
Structure&stratigraphic
Combined stratigraphic/ structural 11800
Horst block
Fault terraces, tilted fault blocks 6050
Statfjord Reservoir
Unconformity: tilted fault block 9000 10 700 9100(GWC) 9690 (OWC)
6365 6460 6460 (OWC)
12760-13 154 (OWC)
83251 8565 8565
6232 (South) (GWC) 6244 (Central) (GWC)
100 590
West 1000, East 1250 0-85
240
200
5O
Statfjord Formation Lower Jurassic/Triassic
Balder Eocene
Britannia Lower Cretaceous (Aptian)
Leman Sandstone Early Permian
850 (800-1000)
3O
23 (16-29) 500 (20-10 000)
33-34
250 (100-600) West 12-30, East 28-58 15 (0-20) (net pay > 10) West 60 (0.l-800), East 30 (0.1-400) (net pay >0.1)
70O 0.95-1.0 16 (10-24)
30 (1.1ooo)
Leman Sandstone Lower Permian (Rotliegend Gp) 700-800 1.0 (0.98-1.0) 8 19 (15-22)
60
80 (max)
0.597 (gas) 0.022
0.615 relative to air
225800 0.0194
180000 0.025@ 150~
1100
60-80 6-9
23.9 53.0 (oil), 0.76 (gas) 5.8 2.17 2.04
106
24OOO 0.270 @ 77~
45 700 0.056
218~ 6020
30 sq miles
17000-100000+ 0.04-0.11
West 129~ East 145~ 5990 at start of production
400-700
61000
2863
140~ 2800
370 4.00E + 04 3968
2200 219000
14.8
Water injection, gas injection; depressurization 6
November 1976 97 000 866
10-15 Aquifer support
Pressure depletion
35 70 Volumetric
1-4
September 1975 520 000 m
2 producers
August 1998 50 8O0 19 gas/condensate producers 22 additional wells planned
1998 30 1 horizontal producer
9O Moderate water drive
956
APPENDIX 1
Captain
Clipper
Corvette
Curlew Curlew B
Trap Type
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft) Gas column (ft) Oil column (ft) Pay zone Formation Age Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
Drape anticline/stratigraphic 'pinch-out
270
Valhall/Wick Sandstone Late Aptian 3OO 0.95 31 (28-34)
7 (1-12) 84 (68-94)
Faulted anticline, multiple culminations 7500 Up to 1000
Faulted pop up
Fault-dip
8000 9000 941
10 550 10 900 10 722 (OWC) -
-
-
172
Leman Sandstone (Rotliegend) Early Permian 650-775
Leman Sandstone Permian 220
-
100 11.1
0.02-100 49
20 400 85
Upper Fulmar Upper Jurassic 53O 87 (85-95) 21 (10-24) 20 (0.001-250) 54 (39 59) 20
19-21 (oil), 0.52 (gas)
0.59
1270 @ 2799 ft TVDss 88-140
-
-
1 . 0 3 - 1 . 0 6
-
-
39 0.82 0.4 3130 1078 1.5
Formation water Salinity (ppm NaC1 eq.) Resistivity (ohm m)
12 000-25 000 0.394 @ 87~
200 000 (160 000 chloride) 0.02
200 000 0.018
200 000 0.014
Reservoir conditions Temperature Pressure (psi)
87~ 1340 @ -2992 ft TVDss
175 3850 @ 8200~ TVDss
186~ 0.07 gas gradient
940O
12000
795
1171
236 89 Depletion
2.60 54438 7298 250 24 25 25 Natural depletion
753
211
6
October 1990
January 1999
November 1997 23 000 25 000 1 horizontal oil producer
Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
1000
20-40 Full voidage replacement, water injection
Recoverable oil (MMBBL) Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
0.59
March 1997 55 OO0-85 000
UK OIL AND GAS FIELDS
Curlew D
Curlew D South
Fault/dip
Fault/dip
10087 10 790 10 644 (GWC) 555
10300 11000 10890 (OWC)
Cyrus
Davy
Deveron
Don
No information provided
Tilted fault block
Rotated fault block/dip 8700 9000 8910 (OWC)
Fault blocks
210
5O0
Brent Group Middle Jurassic 45O
Brent Group Middle Jurassic 42O 20-80 0.16 (0.12-0.28)
7300 7743 7743 443
59O
Fulmar Upper Jurassic 568 82 (43-96) 17 (5-27) 450 (0.001-8000) 72 (50 96)
Fulmar Upper Jurassic 856 67 (40-90) 17 (5-26) 450 (0.001 3500) 51 (50-95)
50
58
44 0.86 0.1
40 0.86 0.2 (initial) 4255 2200 1.9
200000 0.014
200000 0.014
3.87 489011 7319 250 100 340 32 Natural depletion
1.57 99076 7285 252 8 17 25 Natural depletion
Leman Sandstone Early Permian 3OO 0.9-1.0 16 (10-24) 30 (1 1000) 70
24 (16-30) (100-3000) 70
10900 11500 11320-11430
(5-4o) 4-15
38
37-42
1.05@4500psia 617 150 1.133
0.32 0.87 1225-2950 335-944 1.25-1.47
225800 0.0194
13000 0.253
21596 0.314
1482 2.00E+ O5 3562 190
512 50000 4700 22O 54
700 200 000 7240-7350 265 52 (NE), 99 (SW)
28.5 Depletion
14.6 (NE), 8 (SW) Depletion, waterflood
0.6 0.022
2OO 87 Volumetric
15.4
26
February 1998 34 000 115 000 2 vertical gas producers
957
March 2000 20000 40000 1 vertical oil producer
1995 80 4
September 1984 7000
August 1989 10 000
3 platforms 1 producer
1 water injection
958
APPENDIX 1
Douglas
Dunbar
Ellon
Erskine
Type
Structural
No information provided
No information provided
Tilted fault block
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft)
2140
Trap
Gas column (ft) Oil column fit)
2515-2535
-15000 -15000 -15431 300
375
Pay zone
Formation Age
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
Ormskirk Sandstone Triassic
Puffin (Erskine Sandstone) Upper Jurassic
0.90-1.0 Zone I 18, Zone II 13.7 Zone I 2000, Zone II 300
190-250 >95 23 (15-35) 10 (0.01-210) 83 (96-60)
5-30
Hydrocarbons
Oil or gas density (~API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
44
30.5 0.085
285 170 1.075
Formation water
Salinity (ppm NaC1 eq.) Resistivity (ohm m)
270000 0.030@30~
180000 0.016
Reservoir conditions
Temperature Pressure (psi)
30~ 1125 @ 2240ft TVDss
Field characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
6.5 240 000
222700 13938 340
202 500 Water injection
Depletion drive
February 1986
December 1997 25 000 100 2
Recoverable oil (MMBBL) Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
5 exploration/appraisal 11 producers 7 water injectors
UK OIL AND GAS FIELDS
Fergus
Fife
959
Flora
Foinaven
Forties
Four way dip closure anticline 6660 7274 7274 (OWC)
Fife Field
Fife Chalk oil pool
Four-way dip closure
Four-way dip closure
Tilted fault block
Anticline/stratigraphic
8640 8780 8780 (OWC)
8250 8512 8512 (OWC)
Three way dip closure/ diagenetic trap 8000 Variable, oil down to 8150 (OWC)
850O 8745
140 vertical closure
262 vertical closure
150 vertical closure
245
2015 2201 2043, 2085&2113 (GWC) 2201 (OWC) 98 112-158
Fife Sandstone Member Late Jurassic
Fife Sandstone Member Late Jurassic
Tor Formation Upper Cretaceous
440 90 26.5 500 (1-4000) 40
300-500 81 24 (0-31) 50 (1-6000) 40
180-360 45 24.5 (23-27) 0.75 (0-4) 40-60
Flora Sandstone Westphalian C (Carboniferous) to Asselian (Permian) > 1000 Average 85, Vsh 50 21 1-10000 70
29
20
36.4
36.4
36.4
-
24-27
37
1.081
1.081
1.081
8.20
-
-
1.32
490 96 1.108
1.32 490 96 1.108
1.32 490 96 1.108
98 1.129
3.5-4.0 3141 350 1.17
0.76 1142-1390 300 1.22
61 340 0.041
61 340 0.041
61 340 0.041
69 000 0.1002
18 000 0.22
55 000 0.034
-
37 1900 3242 137 1097 244 23 Aquifer and water flood
5650 @ 8500 ft TVDss 223 16.3
5650 @ 8500 ft TVDss 226 132
5650 @ 8500 ft TVDss 226 23
69 Edge water drive
37 Edge water drive/ injection
0
614
Vaila Formation Late Paleocene
Forties Formation Paleocene
250 55 27 (22-30) 800 (500-2000) 80 (70-85)
1161 (653-1539) 0.65 0.27 (0.10-0.36) 700 (30-4000) 0.85
5-40
25 (5-70)
-
250
23 000 64 382 3215 96 4196 57 Predominantly bottom drive aquifer with peripheral water injection 2545
5750 @ 8600ft TVDss 2360 69 19 Aquifer support/water injection
1996 18 000 (peak)
1995 50 000 (peak)
October 1998 30 000
November 1997 8600
September 1975 520 000
1 producer
5 producers 1 injector
2 horizontal producers
15 horizontal producers 6 inclined water injectors 1 gas injector
142 well slots 103 wells 59 producers 11 water injectors 72 spares/dead
960
APPENDIX 1
Fulmar
Gawain
Glamis
Goodworth
Grant
Type
Salt induced eroded anticline
Tilted Horst block
No information provided
No information provided
No information provided
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft)
9900
8600
10 840 (main field), 10 875 (Ribble), 10 590 (Northern)
8904
Trap
Gas column (ft) Oil column (ft)
930
Pay zone
Formation
Age Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
Fulmar Formation Kimmeridge Clay Formation (Ribble Sands) Oxfordian-Kimmeridgian 1200 94 23 (17-28) 500 (10-2000) 79
Leman Sandstone
Permian 104 271 1.00 18 (6-27) 100 (0.1 mD-5 Darcies) 67-84
80
Hydrocarbons
Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
40 0.606 0.42 1800 614 1.43
Formation water
Salinity (ppm NaCI eq.) Resistivity (ohm m)
138 000 0.018 @ 285~
200 000 0.014 @ 194~
Reservoir conditions
176~ @ 8850ft TVDss 4118 @ 8850ft TVDss
Temperature Pressure (psi) Field characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanisms
2825 877 500 5700 @ 10 500 ft TVDss 285 @ l0 500 ft TVDss 822 498 69 Water flood, natural gas lift
Recoverable oil (MMBBL)
567
2740
Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
February 1982 165 103 28 oil wells 13 water injectors 1 gas injector
September 1995 95 110 6 exploration 3 development (1 on hold)
U K O IL A N D GAS F I E L D S
Guinevere
Hamilton N o r t h
Hamilton
Hamish
961
Harding Central
South
Faulted bounded Horst structure with reverse fault closure to the N E and SW plus dip 8150
Structural
Structural
Structural
Structural/stratigraphic
Structural/stratigraphic
2300
2600
7750
5O8O
524O
8599
2910
3166
7962
449
610
466 212
5500 (GOC) 5735 (GWC) 700 235
5489 (GOC) 5682 (GWC) 249 193
Leman Sandstone (Rotliegend)
Ormskirk Sandstone
Ormskirk Sandstone
Piper sands
Balder
Balder
Early Permian 276 0.99 13.9 (10-17) 20 (7-300) 64.9
Triassic
Triassic
(11-19) (300-2100)
(13-17) (240-400)
Upper Jurassic 120 1.000 0.238 1080 0.945
Eocene 0-475 99 35 10000 92
Eocene 0-150 93 34
>1000
>1000
0.095~0.719
89
-
0.65 -
0.67 -
39 1900 613
20 0.57 10 Depth variable 238
-
-
-
1.44
1.11
23 0.57 5 Depth variable 303 1.136
159 000 0.057 @ 60~
300 000 0.039 @ 30~
300 000 0.039 @ 30~
90 990 0.102
43 000 0.103
43 000 0.103
30~ 1404 @ 2600 ft TVDss
30oc 1535 @ 2900ft TVDss
-
1280 121 333 4000 @ 8550ft TVDss 198 @ 8550ft TVDss . . . 100 90 Pressure depletion
15km 2 1 100000 . 627 Natural water drive
8km 2 390000 -
3510 175 7 43 Aquifer drive and water injection
914 107 548 2580 140 236 257 60 Waterflood
731 44 158 2550 140 86 34 53 Waterflood
1.2
-
-
3.8
154
46
June 1993
February 1997
December 1995
February 1990 80 000
April 1996 93 000
December 1996 93 000
30 1 vertical 1 horizontal producer
3 exploration/appraisal 4 gas producers
1 exploration 3 gas producers
1P
7 production 1 gas injection 2 water injection
3 production 0 gas injection 1 water injection
. 0.71 0.0218
.
.
.
230 Natural water drive
.
962
Trap Type Depth to crest (It TVDss) Lowest closing contour (ft) GWC or OWC (ft) Gas column fit) Oil column (ft)
APPENDIX 1
Hatfield Moors
Hatfield West
Heather
Herriard
Tilted anticlinal fault block
Tilted anticlinal fault block
Tilted fault block
+1400
+1300
9450
Structural Tilted fault block ~3265 -3425
1460
1349
No gas cap 1598
160
Brent Group Sandstones Middle Jurassic (Aalenian-Bathonian) 224 (125-370) 0.48 (0-1.0) 14.5 (10-24) 20 (0.1-2000) 41 (8-100)
Great Oolite Middle Jurassic
Pay zone
Formation Age
Oaks Rock Sandstone Late Westphalian B
Oaks Rock Sandstone Late Westphalian B
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
25-9O 0.9 17:2-25.6 21-1100 55
25-9O 0.9 12,9-23.9 0.05-880 55
159 135 16 1 50
0.1-10
Hydrocarbons
Oil or gas density (~API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
0.629
0.629
32-37 c. 0.91 0.4-0.66 1910-3890 450-1280 1.234-1.743
37.5
22000 0.326@60~
85000 0.057
13 947
750
4950-10250 227-242 464
1515-1540
1181 315 1.2
Formation water
Salinity (ppm NaC1 eq.) Resistivity (ohm m) Reservoir conditions
Temperature Pressure (psi) Field characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanisms Recoverable oil (MMBBL)
6.1 ?70 Pressure depletion 4.27
2.4 ?70 Pressure depletion 1.68
6
31 Waterflood 146
Fluid Exp./Sol'n gas
October 1978 38 000
September 1987 15
21 gas-lifted producers 9 water injectors
1
Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
-
U K OIL A N D GAS FIELDS
963
Hewett Main Hewett
Big Dotty
Little Dotty
Upper Bunter
Lower Bunter
Zechsteinkalk
Rotliegendes
Rotliegendes
Upper Bunter
2600
4026
4500
5600
5450
3500
3020 420
4415 389
4883 383
5830 230
4950 500
3666 166
Bunter Sandstone Lower Triassic
Hewett Sandstone Lower Triassic
543 0.96 21.0 500 78
135 0.88 23.0 1000 80
Zechsteinkalk Upper Permian and slope Carbonates 300 0.65 6.5 1 60
Leman Sandstone Lower Permian Aeolian Sandstones 600 0.99 19.0 250 76
Leman Sandstone Lower Permian Aeolian Sandstones 650 0.98 18.8 45O 75
Bunter Sandstone Lower Triassic Alluvial Plain Sandstones 66O 0.95 21.0 35O 76
97
140
148
185
185
111
1362 108 1356
1985 126 2100
2136 130 419
2645 150 296
2746 146 250
1675 116 100
5
13
9
2
1
1
964
APPENDIX 1
Horndean
Hewett (continued) Deborah
Della
Dawn
Deliah
Rotliegendes
Rotliegendes
Rotliegendes
Rotliegendes
Trap Type
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft)
5500
5800
5653
6068
6118
6147
5797
6285
Gas column (ft) Oil column (ft)
618
347
144
217
Pay zone Formation Age
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
Structural Tilted fault block 4100 4337 4337 m
237
Leman Sandstone Lower Permian Aeolian Sandstones 684 0.98 14.2 75 67
Leman Sandstones Lower Permian Aeolian Sandstones 600 0.99 19.5 170 75
Leman Sandstones Lower Permian Aeolian Sandstones 675 0.99 12.7 50 58
Leman Sandstones Lower Permian Aeolian Sandstones 650 0.96 14.6 2 54
Great Oolite Middle Jurassic 28O 130 15 (7-23)
1 (0.1-5) 45 (10-60)
37.3
182
164
187
186
Formation water Salinity (ppm NaC1 eq.) Resistivity (ohm m)
1.65 398 1.135
80 000 0.049
Reservoir conditions Temperature Pressure (psi) Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanisms
. . 2756 145 409 . . .
.
. .
. .
1485 .
2800 143 141 . . .
2354 ! 48 25 . .
.
.
. . .
2837 151 47
1965 140 37
. . Fluid Exp./Sol'n gas
Recoverable oil (MMBBL) Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells 3
November 1987 700 3 4 suspended
UK OIL AND GAS FIELDS
Indefatigable
Humbley Grove
965
Johnston
Ivanhoe Supra
Main
Structural tilted fault block
S t r u c t u r a l t i l t e d f a u l t block
Structural H o r s t block
Structural
Structural
Tilted fault block
-3220 -3680 -3325
-4240
7590 8052 ( O W C )
7590 8052 ( O W C )
(-10249)
105 255
87
7500 9000 8850-8967 (11 distinct G C W s ) 1350 -
462
462
G r e a t Oolite Middle Jurassic
Rhaetic Rhaetian
L e m a n Sandstone
Piper Sands
Piper Sands
20l 160 18 (6-28) 20 (0.1-2000) 60 (15-60)
40 16 12 <1 50
Early Permian 150-400 0.95-1.00 15 (10-24) 30 (1-1000) 79 (60-80)
U p p e r Jurassic 50 0.981 0.226 530 0.867
U p p e r Jurassic 300 0.997 0.229 2200 0.944
L o w e r L e m a n Sandstone Formation Early Permian 280 (162-375) 100 1l (7-17) 10 (1-800) 75 (50-85)
(-10644)
1.48
39
.
0.63 1.15 1589 398 1.173
1.359
.
85000 0.057
.
.
.
0.612 0.0232 -
31 1800 360 1.188
29 1800 360 1.188
0.606 <5 -
196200 0.0185
90990 0.102
90990 0.102
175000 0.017@227~
227~ -10644~ TVDss 4 7 3 0 @ - 1 0 644~ TVDss 2965 1480 120 42 1.95 Fluid E x p . / S o l ' n gas
2000 2012 140 1.1 3.48 Fluid E x p . / S o l ' n gas
38 400 4.90E + 06 4122 195 5600 84 Volumetric
-
-
4.5
June 1984 1400
July 1984 300 500 0
1971 800-1000 56 producers
8
3510 175 34 43 Aquifer drive and water injection 73.3
3510 175 66 64 Aquifer drive a n d water injection 73.3
July 1989 80 000 2P lI
July 1989 80 000 1P lI
4744.5 360-403 60-75 Unconfirmed
O c t o b e r 1994 90 3
966
APPENDIX 1
Kimmeridge
Kingfisher Brae Unit 1
Brae Unit 2
Heather
Structural/stratigraphic
Str uctural/stratigraphic
Structural/stratigraphic
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft)
12600 13125 13 100 (GWC)
12800 13320 13220 (OWC)
1480O 15700 15 700 (GWC)
Gas column (ft) Oil column (ft)
500
Trap
Type
No information provided
900 420
Pay zone
Formation
Brae Unit 1
Brae Unit 2.2
Heather
Age Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
Upper Jurassic 246 0.06-0.86 21 (10-22) 10-800 70-85
Upper Jurassic 286 0.16-0.67 14 (11-15) 10-250 70-85
Middle Jurassic 404 0.14-0.46 13.5 (12-15) 5-20 70-80
2O
l
2O
39-44 0.804 0.03
35-40
43-46
0.27
0.02
3000-4000
2000-2900 2.46
6000-9000
70000 0.034@250~
70000 0.034@250~
70 000 0.034 @ 250~
21 532012 7160 250 104 (total field) 610 (total field) 32 (total field) Natural depletion 33 (total field)
21 313445 7250 250 104 (total field) 610 (total field) 32 (total field) Natural depletion 33 (total field)
12 504 986 11 800 29O 104 (total field) 610 (total field) 32 (total field) Natural depletion 33 (total field)
October 1997 8400 130 5 exploration/appraisal 3 development wells completed
July 1998 8400 130 5 exploration/appraisal 3 development wells completed
August 2000 8400 130 5 exploration/appraisal 3 development wells completed
Hydrocarbons
Oil or gas density (~ API) Oil or gas gravity (o API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB) Formation water
Salinity (ppm NaCi eq.) Resistivity (ohm m) Reservoir conditions
Temperature Pressure (psi) Field characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism Recoverable oil (MMBBL) Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
U K OIL A N D GAS F I E L D S
Leman
Lennox
MacCulloch
Malory
Faulted pericline
Structural
Four-way dip closure over turbidite sandstone mound
585O 670O
2500
6000 6249 -
850
,
3227 (GOC) 3400 (OWE) 760 143
967
Maureen
Fault bounded Horst structure with fault closure to the N and S and dip closure to the N W 9020 9350 -
Maureen (Paleocene)
Mary
4-way dip over salt dome
Updip pinch-out trap
-7950 -8730 -8730 (OWC)
- 10 050 10 750 - 10 646 (OWC)
780
•
249 240
-
r
Upper Balmoral Sandstone of Lista Formation Late Paleocene 175-540 0.4-0.9 28 (24-32) 200-2000 (core Kh) 90
Leman Sandstone (Rotliegend)
Maureen Formation
Hugin Formation
Lower Permian 249 1 4.7 0.2-1651 (core Kh) 63.3
Danian-Thanetian 125-450 0.4-0.7 15-27 10-1500 67
Late Jurassic 10 150 0.8 18-22 5-150 80
50-350
50-300
269 * e-06
15
5-20
32-37 1700-2290 386-424 1.2
0.615 0.0227 -
36 0.7 1786 393 1.29
32
45 1620 650 1.3
240000 0.026@ 125~
280000 0.037@30~
90000 0.0781@25~
125~ 3022
30~ 1620 @ 3257ft TVDss
175~ 2770 @ 6150ffTVDss
253
9 km 2 518000 (gas), 310000 (oil)
3334 205769 2770 @ 6150 ff TVDss 79 200
Leman Sandstone
Ormskirk Sandstone
Permian 800 100 12 0,5-15 59
Triassic 0,9-1.0 11-21 50-10 Darcy
-
-
0.585 -
-
397 91 Depletion 360
August 1968
184 497 Gas injection
February 1996
30-35 Natural aquifer 60-70
August 1997 60 000
256690 0.057@ 190~
20000-40000 _
-
397 463 m 2 103934 4257 @ 9145 ff TVDss 200 99 76 Pressure depletion 75
October 1988
45 4 exploration/appraisal 1 vertical producer 11 pilot and development 6 of which are producers
-
4 exploration/appraisal 7 oil producers 2 gas injectors
(77~
0.7 2060 550 1.33
4100 854000 3792 247 398
355 26600 6262 274 25.0
55 Aquifer 217.4
9 Depletion drive 2.83
968
APPENDIX 1
Mercury
Moira
Montrose
N W - S E trending Horst block -8850 -9492 -9492 (GWC) 642
4-way dip draped over fault block -8850 -8950 -8927 (OWC)
Domal antiform
77
210
Maureen Formation
Forties
Danian-Thanetian
Paleocene
Morag Trap Type
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft) Gas column (ft) Oil column (ft) Pay zone Formation
Strafigraphic -9200 10700 - 1 0 6 0 2 (ODT) 1400
8040 8250 8250 (OWC)
Age
Morag Member, Turbot Anhydrite Formation Permian
Lower Leman Sandstone Formation Permian
Gross thickness (range) (ft) Net/gross ratio (%)
300 0.67
58-110 73-94
0.8
330 (260-440) 0.5 (0.3-0.8)
Porosity average (range) (%) Permeability average (range) (mD)
Matrix 2.6 Fracture
12-14 27-91
17-25 40-400
24 (3-30) 80 (1-2000)
Petroleum saturation average (range) (%) Production index
85
58-66
0.5-25
Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
31.3 0.566 1938 750 1.614
Formation water Salinity (ppm NaCI eq.) Resistivity (ohm m)
0.612 0.0236 -
55
42 0.435 1345 220 1.254
0.631 40 0.32 2348 (West), 2737 (East) 600 (West), 800 (East) 1.467 (West), 1.557 (East)
20000
111000 0.027
0.052
Reservoir conditions Temperature Pressure (psi) Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
1175 19 400 6113 270 5.0 50 Solution gas
10.4 8.66 4303 204 124 66 Edge
3912 245 12.4 34 Aquifer drive
9910 748 000 3744 257 236 41 Aquifer drive/gas lift
Recoverable oil (MMBBL)
2.6
0.5
4.2
98
Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
November 1999 50 2 H i g h angle/horizontal
1976 28000 -
8 producers 6 i~ectors
UK OIL AND GAS FIELDS
969
Morecambe North
Morecambe South
Murdoch
Nelson
Neptune
Faulted roll-over
Tilted fault blocks
Faulted Horst Block
Antiformal
-2950 -4400
-2200 -4050
11 250-12 600 (Top Murdoch) Field full to spill
7192 (22/11-7)
975
1300
125-875
Faulted four way dip closure -8853 -9839 -9839 (GWC) -986
7449-7501 (excluding 22/7a-3) 278
Ormskirk Sandstone St Bees Sandstone Triassic - presumed Scythian (270 Ma) 4000 85-99 (illite free) 55-92 (illite affected) 9-15 (illite affected) 25-180 0.02-1.0 (illite affected) 65 at FW100 at crest 1.25
2.4
0.648
0.64 0.016
Ormskirk Sanstone St Bees Sandstone Triassic
Westphalian B, Murdoch Sand Interval Carboniferous
Paleocene
Lower Leman Sandstone Formation Permian
870-3100 79 (100-60)
118 (56-159) 0.94 (0.89-0.98)
257 (56-459) 0.7 (0.25-0.97)
366-405 99
14 (7-22) 150 (0.3-1000)
10.6 (9.3-13.0) 0.1
23 (15-38) 216 (7-1610)
17-21
75 (92-60)
55
0.673
Forties Sandstone Member
110-140
68-72
40.6
0.607 0.0236
1550-1699@230~ 0.0070
0.0068
270000 0.05@77~
300 000 0.036
1.357
200 000 0.064 @ 60~
235~ @ 11 700 ft TVDss 6140 @ 11 700ft TVDss
0.056
224~ 2480
TVDss
593O 2820000 1800 92
20700 1.8 x 107 1861 91
1290 80 Volumetric depletion
5500 93 Volumetric depletion
478 93
1050
14
348
Basal aqui~r supported by water injection 420-450
October 1994
January 1985
October 1993
February 1994
265 10 production 4 appraisal
1800 34 production 7 appraisal
82.7
583 500 3322
6.5 10.6 4385 176
79O
23 platform producers 4 sub-sea producers 4 water injection
341 84 Edge 286
November 1999 2OO 3 High angle/horizontal + 1 vertical
970
APPENDIX 1
North Cormorant Block III
9230
Pickerill
Pierce
Structural fault and dip closure -2350
Fault dip closure
No information
-2430 East; -2533 West
9095 (West) (GWC) 8938 (East) (GWC)
Block IV
Trap Type
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft)
Palmers Wood
Sectors 1 & 2:10040 Sectors 3A: 9360 Sectors 3B: 9530 Sectors 4A & 5:9800 Sector 4B: 9600
provided
8100
Gas column (ft) Oil column (ft)
0 80 East; 183 West
Pay zone Formation
Corallian Limestone
Leman Sandstone
Age
Upper Jurassic
Permian
,
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
300 0.72 (0.4-1.0) 20 (15-27) +200 (0-2000) -
400 0.69 (0.3-1.0) 20 (16-26) + 100 (0-1000) -
32 16 17.4 (10-22) 5 (0.05-1000) 65 (25-0.70)
80-250 0.9-1 0.12 0.05-10 (0.01-550)
-
-
-
60
Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) F o r m a t i o n volume factor (RB/STB)
36 0.82 (@ Pb) 1040 224 1.191
34.5 0.77 (@ Pb) 1390 311 1.245
37.5 0.942-0.777 2.004 427-764 109-169 -
0.61 -
Formation water Salinity (ppm NaCI eq.) Resistivity (ohm m) Reservoir conditions Temperature Pressure (psi)
-
-
0.051 @ 60~
195~ 210~ 4825 (@8690fl TVDss) 5262 (@9100fl TVDss) -
Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
6900
204~ @ 8900ff TVDss 3 9 9 5 @ 8 9 0 0 f f TVDss
8150
1180 100 11.73 900 Fluid Exp./ Sol'n gas
Recoverable oil (MMBBL) Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
October 1983
August 1992
4
96 12 exploration 15 deVelopment
-
UK OIL AND GAS FIELDS
Rob Roy Supra
7931 (OWC)
Saltfleetby
Schooner
Scott
Four way dip closure
Dip closure
Structural
2234 2325 2325
11800 ,
10400
91
13075
Main
Structural 7550
971
m
7944 (OWC)
13o75: '
13075(GWC)
381
11 895-13792 (OWC)
500-2000
Piper Sands
Piper Sands
Sub Alton-Ashover Equivalent
Barren Red Measures and Coal Measures Grouops
Sgiath and Piper :Formation
Upper Jurassic
Upper Jurassic
Late Namuria-Early Westphalian
Westphalian C/D
100 0.936 0224 520 0.937
220 O.992 0.228 2090 0.955
56 0.34-0.71 9.5-12.5 1-10 80
1275 20-38 10-13 30-100 70-85
Upper iJurassic (Latest Oxfordian to Kimmeridgian) c. 360 0.8 10-22 <0.1-c. 6500 85-97
24-28
0.015
1-50
41
39
3460 1391 1.679
1900 613 1.344
90.990 0.102
90990 0.102
3510 175 42
3510 175 101
56 Aquifer drive and water injection 109,9
67 Aquifer drive and wateri~ection 109.9
July 1989 80O00
July 1989 80000
2P lI
3P 2I
61 0.721
36 0.66 0.0277
0.0036
0.297-0.578@8500psi 1930-3890 578-1398 1.328-1.761 @8500psi
53500 0.085
93700 0.027
110 000 0.027 @ 200~
2857 587763 3566 183
13 590 5026420 6475@ 12800 230 • 15
114 55-71.5 Pressure depletion
1059 58 Natural depletion
8650 3 114000 7879-9320 190-248 946 Associated gas only 46.5 Water flood 441
December 1999 1450 52.2 5 horizontal
October 1996 130 7 single deviated
September 1993 >200 000 13 Scott oil producers 10 Piper oil producers 11 Scott water injectors 7 Piper water injectors 2 Scott/Piper water injectors
972
APPENDIX 1
Singleton
Sean North
South
East
Dip/fault 8280 8550
Dip/fault 7800 8550
Dip/fault 7960 8400
263
743
430
Trap
Type Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft) Gas column (ft) Oil column (ft)
Structural tilted fault block -4050 North; 3950 (South) -4390 North; 4170 South 340 North; 220 South
Pay zone
Formation
Leman Sandstone
Leman Sandstone
Leman Sandstone
Great Oolite
Age
Permian
Permian
Permian
Middle Jurassic
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
200-260 95.4 17.5 130-400 73.5
240-270 99.9 17.1 190-420 77.6
300-330 100 17.0 30-150 75.0
250 180 13 0.5 50
0.618
0.614
0.617
Hydrocarbons
Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
39.15 0.82 11.30 303 1.215
Formation water
Salinity (ppm NaCI eq.) Resistivity (ohm m)
225000 0.017
225 000 0.017
225000 0.017
202~ 3945
192~ 3977
207~ 0.068
1230
2420
1020
26O 90 Depletion
610 8O Depletion/water
143 89 Depletion
August 1986
August 1986
November 1994
150000 0.04
Reservoir conditions
Temperature Pressure (psi) Field characteristics
Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
7900 135000 1852 140 75.26
Solution gas drive
Recoverable oil (MMBBL) Production
Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
December 1990 1000 4
UK OIL AND GAS FIELDS
Staffa
Stat~ord Brent
Dunlin
Stat~ord
Structural/Stratigraphic 2360
Structural/Stratigraphic 2475
Structural/Stratigraphic 2575
4180 4180 (OWC)
2586 (OWC)
2604 (OWC)
2814 (OWC)
145
226
129
239
Tarbert and Ness
Brent Group/Sandstone
Middle Jurassic
Middle Jurassic-Bathonian Bajocian 2OO 0.75 (0.47-0.99) 27 (17-30) 2500 (lOmlO0) -52
Cook Formation (Dunin II)/Sandstone Early Jurassic-Toacian 2O 0.05-0.45 11-22 150 (5-300) -4
Statfjord Formation/ Sandstone Early Jurassic/ Sinemurian-Rhaetian 185 0.6 (0.4-1.0) 22 (20-29) 470 (100-500) -10
c. 2700
c. 1000
c. 2500
1686-1789 1.99
38.4 0.943 0.37@5561 psi 3900 1039 (185) 1.528@5561 psi
36.4 0.943 0.44@5561 psi 3553 825 (147) 1.428@ 5561 psi
39.6 1.0 0.36 @ 5864psi 2900 879.3 (156.6) 1.484 @ 5864psi
0.2645
14000 0.122@77~
0.122 @ 77~
0.128@83~
21000 5.40 5561 @2469mss 192@2469mss 4894 5.030 66 Water drive/WAG
5000 1.162 5561 @2469mss 201 @2469mss 135 0.113 18 Water drive
11000 2.275 5864@2701mss 206@2701mss 1319 1.158 70 Gas/water drive
3249
25
918
3 February 1992 12 000
1979
1994
1979
2 Production
65 OP 18 WI 6 WAG
30P 2 WI
19 OP 2 WI 3 GI 3 WAG 3 WI/GI
Tilted fault block
76 10.4
39-44 0.18-0.21
3.02km 2 143 x 106 7760 @ 4050mTV 276 23-31-34 18 Gas exsolution and aquifer inflow 5.5
13500
973
Stirling
Stockbridge
No information provided
No information provided
974
APPENDIX 1
Storrington
Trap Type
Structural tilted fault block -3780
Strathspey
T-block
Brent Group Reservoir
Banks Group Reservoir
Tiffany
Toni
Structural/Stratigraphy Structural/Stratigraphy
-8900 -9380 -9380 (OWC)
12 520 13 920 (OWC) 1400
11 755 12 932 (OWC) 1177
Depth to crest (ft TVDss) Lowest closing contour (ft) GWC or OWC (ft) Gas column (ft) Oil column (ft)
-3945 165 75
480
Unconformity: tilted fault block -9700 - 10 267 - 10 267 (OWC) 567 -
Pay zone Formation
Great Oolite
Brent Group
Banks Group
Brae
Brae
Age
Middle Jurassic
Middle Jurassic
Lower Jurassic/Triassic
Upper Jurassic
Upper Jurassic
Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index
218 150 13 (6-26) 5 (0.1-2000) 55
800 0.46 20.3 (12.8-30.4) 1045 (10-9750) 0.86 (0.93-0.62)
750 0.44 14.7 (10.4-25.5) 356 (15-8425) 0.82 (0.93-0.71)
1100 58 11 75 66
1000 35 11 150 78
1.22
Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (~ API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
39.04 0.794 0.5 1771 546 1.29
38.9 0.1840 4223 1604 1.879
40-49 1800-7900 2.2
35.6 0.7 0.23 3045 885 1.574
34.8 0.7 0.21 4480 2170 2.198
Formation water Salinity (ppm NaC1 eq.) Resistivity (ohm m)
145 000 0.036 @ 120~
260 000 0.313 @ 60~
240 000 0.3 @ 60~
95 000 0.1 @ 60~
95 000 0.1 @ 60~
740
2581 232 427 5865 @ 9250 ft TVDss 212 @ -9250 101 Solution gas Water flood
1730 243 018 6405 @ 10 182ft TVDss 220 @ - 1 0 182 95 281 0.21 Natural depletion
6.2 5970 7455 275 156 43-47 Water injection
6.8 8700 7000 258 121 40 Water injection
Recoverable oil (MMBBL)
57.7
190
68-75
48
Production Start-up date June 1998 Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/900 D) 4 Number/type of wells
November 1973 39 340 55 7 producers 2 water injectors
May 1994 14 000 127 5 producers
Reservoir conditions Temperature Pressure (psi) Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism
1758 140 12
Fluid Exp./ Sol'n gas
UK OIL AND GAS FIELDS
Thistle
975
Trent
Thelma
SE Thelma Field
Lower Trent Sandstone
Upper Trent Sandstone
Structural/Stratigraphy
Structural/Stratigraphy
Rotated fault block
11780
11900
12 096 (OWC)
12743 (OWC)
850O 9322 9322 (OWC)
316
843
822
Brae
Brent Group
Millstone Grit
Millstone Grit
Upper Jurassic
Brae and Sand Shale Unit Upper Jurassic
Middle Jurassic
Marsdenian Carboniferous
1000 52 13.5 200 70
600 38 12 0-1000 70
<550 20-100 0.24 (0.16-0.30) 40-40000 78 (60-85)
Marsdenian Carboniferous Carboniferous 50-100 O.85 10.3 0.3 (0.05-19) 85
38.5 0.63 0.14 4450 2700 2.58
34.7 0.67 0.22 3300-3600 1200 1.79
38.4 0.85-0.915 (0.92 @ 5000psia)
0.646 -
0.646
95000 0.1 @60~
95000 0.1 @ 60~
13000 0.253@77~
0.06
0.06
220 6060
233 5500
233 5500
3410 910000 6060 @ 9200RTVDss 220 @ 9200~TVDSs 824
3100
4 way dip closure
1200
33 0.98 12.8 70 247 (0.1-1000)
290 1.18 @ 5000 psia
10,2 2660 6655 260 52
10.2 9070 6945 260 194
21 Natural water drive
16 Natural water drive
49 Waterflood
11
30
404
92
February 1978 1 2 4 000
November 1996
60 alots 22 production 7 water injection
4 exploration/appraisal 3 producers 1 uncompleted development
-
111
976
APPENDIX 1
Tyne Westphalian A Sandstone
Tyne North
Trap Type
Tyne South
Tyne West
Combined structural/stratigraphic
Combined structural/stratigraphic
11 940 (GWC) 171
12339 240
Depth to crest (ft TVDss) Lowest closing contour (ft) G W C or OWC (ft) Gas column (ft) Oil column (ft) Pay zone Formation
Age Gross thickness (range) (ft) Net/gross ratio (%) Porosity average (range) (%) Permeability average (range) (mD) Petroleum saturation average (range) (%) Production index Hydrocarbons Oil or gas density (~ API) Oil or gas gravity (o API) Viscosity (cp) Bubble point (psig) Gas/oil ratio (SCF/BBL) Formation volume factor (RB/STB)
Millstone Grit
Caister Coal Formation
Lower Ketch member
Lower Ketch member
Marsdenian Carboniferous 33 0.98 12.8 70 247 (0.1-1000)
Langsettian 30 0.87 11 60 38.0 (0.6-340)
Carboniferous <400 partly truncated 0.6 11.0 35.1 (0.1-5000)
Carboniferous 400 0.7 10.7 48.4 (9-450)
0.646 . . .
0.652 . . . -
0.65
0.65
. . .
. . . -
Formation water Salinity (ppm NaC1 eq.) Resistivity (ohm m)
0.06
0.06
0.057
0.057
Reservoir conditions Temperature Pressure (psi)
233 5500
240 5605
240 6153
242 6393
3920
1620
163
61
March 1997
November 1997
2 exploration 2 extended reach development
1 exploration 1 extended reach development
Field characteristics Area (acres) Gross rock volume (acre ft) Initial pressure (psi) Temperature (~ Oil initially-in-place (MMBBL) Gas initially-in-place (BCF) Recovery factor (%) Drive mechanism Recoverable oil (MMBBL) Production Start-up date Production rate plateau oil (BOPD) Production rate plateau gas (MMSCF/D) Number/type of wells
UK OIL AND GAS FIELDS
977
V-Fields Gas Complex
Viking
Waveney
West Firsby
Windermere
Block faulted
Tilted/invertedfault blocks 8000-9000 9000-10200
Roll over anticline, with fault seal to SE 7748
No information provided
Structural
7200-7900 ft sub-sea Fields filled to or close to spill point
347O 3555
450-583 ft
700 max in the Rotliegendes
7884 (Log and RFT derived) 136
c. 3528 (GWC) c. 58
Rotliegendes Group, Leman Sandstone Early Permian 890 (790 990) 0.8 (0.6-1.0) 13.5 (3-23) 5.4 (0.1-1950) 60
Leman Sandtone Formation
Rotliegend, Leman Sandstone
Leman Sandstone
Permian 400-700 50-100 7-25 0.1-100 +highly variable 50-60
Early Permian 200-250 0.98 (0.9-1.0) 13 (7-20)
Permian 23 90 12-13 12-14 (test) 77-83
12 (0.1-200)
4-100
0.60
0.615
0.68
0.725
190000-290000 0.017-0.022
220000 0.017
200000 0.055@60~
575 2.9155@25~
142-177 3472-3835
170-200~ 4150-4670
1891.5 119000
8 km 2 123 398 113
220
49 1.1 x 1012 3472-3835
4150-4670
2593 65-77
29990 97
2.8 82 Depletion
15.6
October 1988
August 1972
April 1997
2880 10 producers
1.2 2 producers
Appendix 2 Field
AIRTH ALBA
ALBA
ALBURY
ALBURY
ALISON ALWYN N
Authors
MATTINGLY, G. A. & BRETTHAUER, H. H. 1992 The Alba Field: A Middle Eocene deep water channel system in the UK North Sea. In: HALBOUTY, M. f . (ed.) Giant Oil and Gas Fields of the Decade." 1978-1988. American Association of Petroleum Geologists, Memoir 54, 297-306 NEWTON, S. K. & FLANNAGAN, K . P . 1993 The Alba Field: evolution of the depositional model. In: PARKER, R. J. fed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 161-174 BUTLER, M. & PULLAN, C.P. 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 TRUEMAN, S. 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore JOHNSON, A. & EYSSAUTIER, M.
ALWYN N ALWYN S AMETHYST W
INGLIS, I. & GERARD, J.
ANDREW
JOLLEY, J. E.
ANGLIA ANGUS
HALL, S. A.
ANN APLEYHEAD
ARBROATH ARBROATH ARGYLL
ARGYLL ARDMORE ARKWRIGHT
ARKWRIGHT ARMADA AUDREY AUK
AUK AUK BAIRD BALCOMBE
BALMORAL BALMORAL
Year Reference
GARLAND, C. R.
1987 Alwyn North Field and its regional geological context. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe." Proceedings" of the 3rd Conference, 963-978 1991 The Alwyn North Field, Blocks 3/9a, 3/4a, UK North Sea, 21-32 See Dunbar, Ellon & Grant 1991 The Amethyst Field, Blocks 47/8a, 47/9a, 47/13a, 47/14a, 47/15a, UK North Sea, 387-394 2003 The Andrew and Cyrus Fields, Blocks 16/27a and 16/28, UK North Sea
Code
Barbican 93
Memoir 20
Barbican 87
Memoir 14 Memoir 14 Memoir 20
1992 The Angus Field, a subtle trap. In: HARDMAN, R. F. P. fed.) Exploration Britain, Geological Insights for the Next Decade. Geological Society, London, Special Publications, 67, 151-185
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. 8,: BROOKS, J. (eds) Tectonic. Events Responsible for Britain's" Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1991 The Arbroath and Montrose Field, Blocks 22/17, 18, UK North Sea, CRAWFORD, R., LITTLEFAIR, R. W. & 211-217 AFFLECK, L. G. 2003 The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, HOGG, A. J. C. 22/18 and 22/23a, UK North Sea 1975 The Geology of the Argyll Field. In: WOODLAND, A. W. fed.) PENNINGTON, J. J. Petroleum and the Continental Shelf of Northwest Europe, Volume i Geology. Applied Science Publishers, Barking, England, 285-294 1991 The Argyll, Duncan and Innes Fields, Blocks 30/24, 30/25a, UK ROBSON, D. North Sea, 219-226 Renamed from Argyll 2002 1999 Innovation and risk management in a small subsea-tieback: KANTOROWICZ, J. D., ANDREWS, I. J., Arkwright Field, Central North Sea, UK. In: FLEET, A. J. & DHANANI, S., GILLIS, M., JENN1NGS, C., BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: LUMSDEN, G., ORR, G., SIMM, R. W. 8,~ Proceedings' of the 5th Conference. Geological Society, London, WILLIAMS, J. 1125-1134 2003 The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, HOGG, A. J. C. 22/18 and 22/23a, UK North Sea 2003 The Armada development, UK Central North Sea: The Fleming, STUART, I.A. Drake and Hawkins Gas-Condensate Fields FRASER, A. J. & GAWTHORPE, R. L.
BRENNAND, T. P. & VAN gLEN, F . R .
1975 The Auk Oil-Field. In: WOODLAND, A. W. fed.) Petroleum and the Continental Shelf of North West Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 275-284 TREWIN, N. H. & BRAMWELL, M . G . 1991 The Auk Field, Block 30/16, UK North Sea, 227-236 TREWIN, N., FRYBERGER, S. & KREUTZ, H. 2003 The Auk Field, Block 30/16, UK North Sea BUTLER, M. & PUt, LAN, C. P.
TONKIN, P. C. & FRASER, A. R. GAMBARO, M. & CURRIE, M
1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. ~: BROOKS,J. (eds.) Tectonic Events Responsible.for Britain ~ Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 1991 The Balmoral Field, Block 16/21, UK North Sea, 237-244 2003 The Balmoral, Glamis and Stifling Fields, Block 16/21, UK Central North Sea
GLUYAS, J. G. & HICnENS, H. M. (eds) 2003. United Kingdom Oil and Gas Fields, Commemorative Millennium Volume. Geological Society, London, Memoir, 20, 979-994.
Memoir 14 Memoir 20 Barbican 75
Memoir 14
Barbican 99
Memoir 20 Memoir 20
Barbican 75
Memoir 14 Memoir 20
Memoir 14 Memoir 20
979
980
APPENDIX 2
Field
Authors
Year Reference
Code
BANFF
EVANS, N., ROmSON, P. & SYKES, G.
Barbican 99
BANFF
EVANS, N., MACLEOD, J.A., MACMILLAN, N., RORISON, P. & SALVADOR, P. FARMER, R. T. & HJLUER, A . P . SARGINSON, M . J . SARGINSON, M.J. BUTLER, M. & PULLAN, C.P.
1999 Banff Field, UK Central Graben. In: FLEET, A. J. BOLDY, S. A . R . (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 975-990 2003 The Banff Field, Blocks 22/27a, 29/2a, UK North Sea
BARQUE BARQUE BARQUE S BAXTER'S COPSE
BEATRICE
LINSLEY, P. N., POTTER, H. C., MCNAB, G. & RACHER, D.
BEATRICE BEAUFORT
STEVENS, V. M C C R O N EC, . W .
BECKERING BECKINGHAM
FRASER, A. J. & GAWTHORPE, R. L.
BEINN BELVOIR
BREHM, J . A . FRASER, A. J. 8a GAWTHORPE, R . L .
BERYL
ROBERTSON, G.
BERYL BERYL
KNUTSON, C. A. & MUNRO, I. C. KARASEK, R. M., VAUGttN, R. L. & MASUDA, T. T. MCCRONE, C. W.
BESSEMER BIRCH BLADON BLAIR BLENHEIM
HOOK, J., ABHVANI, A. GLUYAS, J. G. & LAWLOR, M.
BLETCHINGLEY
DICKSON, B., WATERHOUSE, M., GOODALL, J. & HOLMES, N. BUTLER, M. & PULLAN, C. P.
BOTHAMSALL
FRASER, A. J. & GAWTHORPE, R. L.
BOULTON BRAE C
CONWAY, A. M. & VALVATNE, C. HARMS, J. C., TACKENBERG, P., PICKLES, E. & POLLOCK, R. E.
BRAE BRAE BRAE BRAE BRAE
C C E N N
TURNER, C. C. & ALLEN, P. J. FLETCHER, K. J. BRANTER, S. R. F. STEPHENSON, M. A. HARMS, J. C., TACKENBERG, P., PICKLES, E. & POLLOCK, R. E.
BRAE N BRAES
BREHM, J. A. HARMS, J. C., TACKENBERG, P., PICKLES, E. & POLLOCK, R. E.
1991 2003 2003 1990
The Barque Field, Blocks 48/13a, 48/14, UK North Sea, 395-400 The Barque Field, Blocks 48/13a, 48/14, UK North Sea The Barque Field, Blocks 48/13a, 48/14, UK North Sea Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. 8r BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 1980 The Beatrice Field, Inner Moray Firth, UK North Sea. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Fields of the Decade: 1968-1978. American Association of Petroleum Geologists, Memoir 30, 117-130 1991 The Beatrice Field, Block 11/30a, UK North Sea 2003 The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, UK North Sea 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The North Brae and Beinn Fields, Block 16/7a, UK North Sea 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas' Reserves. Geological Society, London, Special Publications, 55, 49-86 1993 Beryl Field: geological evolution and reservoir behavior. In:PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe Proeeedings of the 4th Conference. Geological Society, London, 1491 1502 1991 The Beryl Field, Block 9/13, UK North Sea, 33-42 2003 The Beryl Field, Block 9/13, UK North Sea 2003 The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, UK North Sea 2003 The Birch Oil Field, Block 16/12a, UK North Sea
2001 Blenheim Field: the appraisal of a small oil field with a horizontal well. Petroleum Geoscience, 7, 81-95 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371 391 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's' Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Boulton Field, Block 44/21a, UK North Sea 1981 The Brae oilfield area. In: ILUN(;, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 352-357 1991 The Central Brae Field, Block 16/7a, 49-54 2003 The Central Brae Field, Blocks 16/07a, 16/07b, UK North Sea 2003 The East Brae Field, Blocks 16/03a, 16/03b, UK North Sea 1991 The North Brae Field, Block 16/7a, UK North Sea, 43 48 1981 The Brae oilfield area. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 352-357 2003 The North Brae and Beinn Fields, Block 16/7a, UK North Sea 1981 The Brae oilfield area. In: ILLIN6, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 352-357
Memoir 20
Memoir 14 Memoir 20 Memoir 20
Memoir 14 Memoir 20
Memoir 20
Barbican 93
Memoir 14 Memoir 20 Memoir 20 Memoir 20
Memoir 20 Barbican 81
Memoir 14 Memoir 20 Memoir 20 Memoir 14 Barbican 81
Memoir 20 Barbican 81
UK OIL AND GAS FIELDS
981
Field
Authors
Year Reference
Code
BRAE S BRAE S BRAE W
ROBERTS, M. J. FLETCHER, K. J. WRIGHT, S. D.
Memoir 14 Memoir 20 Memoir 20
BRENT
BOWEN, J. M.
BRENT BRENT
STRUIJK, A. P. & GREEN, R. T. JAMES, S., PRONK, D., ABBOTS, F., WARD, V.,VAN DIERENDONCK, A. & STEVENS, D.
BRENT
TAYLOR, S., ALMOND, J., ARNOTT, S., KEMSHELL, D. & TAYLOR, D. FRASER, A. J. ~ GAWTHORPE, R. L.
1991 The South Brae Field, Block 16/7a, UK North Sea, 55-62 2003 The South Brae Field, Blocks 16/07a, 16/07b UK North Sea 2003 The West Brae and Sedgwick Fields, Blocks 16/06a, 16/07a, UK North Sea 1975 The Brent Oil-Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 353-362 1991 The Brent Field, Block 211/29, UK North Sea, 63-72 1999 The Brent Field: improving subsurface characterisation for late field life management. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 1039-1050 2003 The Brent Field, Block 211/29, UK North Sea
BRIGG
BRIMMOND BRITANNIA
BRITANNIA BROCKHAM
BROCKHAM
BROUGHTON
BROWN BRUCE
BUCHAN BUCKLAND BURE
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK CARTER, A. & HEALE, J. North Sea 1999 Britannia Field, UK central North Sea: modelling heterogeneity in JONES, L. S., GARRETT, S. W., unusual deep-water deposits. In: FLEET, A. J. & BOLDV, S. A. R. MACLEOD, M., GUY, M., CONDON, P. J. (eds) Petroleum Geology of Northwest Europe: Proceedings of the i~; NOTMAN, L. 5th Conference. Geological Society, London, 1115-1124 2003 The Britannia Field, Blocks 15/29a, 15/30, 16/26, 16/27a, 16/27b, HILL, P. & PALFREY, A. UK North Sea 1990 Tertiary structures and hydrocarbon entrapment in the Weald BUTLER, M. & PULLAN, C. P. Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible ]'or Britain ~ Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, TRUEMAN, S. Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore 1990 Tectono-stratigraphic development and hydrocarbon habit of the FRASER, A. J. d~; GAWTHORPE, R. L. Carboniferous in northern England. In: HARDMAN, R. F. P. ~: BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves'. Geological Society, London, Special Publications, 55, 49-86 2003 The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, MCCRONE, C. W. 49/30a, 49/30c, 53/5a, UK North Sea 1993 The Bruce Field. ln: PARKER, R. J. (ed.) Petroleum Geology of BECKLY, A., DODD, C. & LOS, A. Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1453-1464 199t The Buchan Field, Blocks 20/5a, 21/la, UK North Sea, 253-260 EDWARDS, C. W. WERNGREN, 0. C.
CADOR CAISTER
KARASEK, R. M. & HUNT, J. R. RITCHIE, J. S. & PRATSIDES, P.
CAISTER
RICHIE, J. S., PILLING, D. & HAYES, S.
CALDER
BLOW, R. A. & HARDMAN, M.
CALOW
FRASER, A. J. & GAWTHORPE, R. L.
CALLISTO CAMELOT CAMELOT CAPTAIN
HOLMES, A. J. KARASEK, R. M. & HUNT, J. R. PINNOCK, S. J. & CLITHEROE, A. R. J.
Barbican 75
Memoir 14 Barbican 99
Memoir 20
Memoir 20 Barbican 99
Memoir 20
Memoir 20
Memoir 20 Barbican 93
Memoir 14
1991 The Thames, Yare and Bure Fields, Block 49/28, U K North Sea, 491-496 2003 The Camelot Fields, Blocks 53/la, 53/2, UK North Sea 1993 The Caister Fields, Block 44/23a, UK North Sea. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 759-770 1998 Reservoir development, sequence stratigraphy and geological modelling of Wesphalian fluvial reservoirs of the Caister C Field, UK, Southern North Sea. Petroleum Geoscience, 4, 193-202 1997 Calder Field appraisal well 110/7a-8. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the Irish Sea and Adjacent Basins. Geological Society, London, Special Publications, 124, 387-398 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49 86
Memoir 14
1991 The Camelot Fields, Blocks 53/la, 53/2, UK North Sea, 401 408 2003 The Camelot Fields, Blocks 53/la, 53/2, UK North Sea 1997 The Captain Field, UK North Sea: appraisal and development of a viscous oil accumulation. Petroleum Geoscience, 4, 305-312
Memoir 14 Memoir 20
Memoir 20 Barbican 93
982
APPENDIX 2
Field
Authors
Year Reference
Code
CAPTAIN
ROSE, P. T . S .
Barbican 99
CAPTAIN
PINNOCK, S. J., CLITHEROE, A. R. J. & ROSE, P. T. S.
1999 Reservoir characterisation in the Captain Field: integration of horizontal and vertical well data. In: FLEET, A. J. & BOLDu S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5 th Conference. Geological Society, London, 1101-1114 2003 The Captain Field, Block 13/22a, UK North Sea
CARNOUSTIE CAUNTON
CAYTHORPE CHANTER CLAIR
FRASER, A. J. & GAWTHORPE, R. L.
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86
SCHMITT, H. R. H. CONEY, D., FYFE, T. B., RETAIL, P. & SMITH, P. J.
1991 The Chanter Field, Block 15/17, UK North Sea, 261-268 1993 Clair appraisal: benefits of a co-operative approach. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1409-1420 1987 Claymore Oil Field. In: BROOKS, J. & GLENME, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference, 835-846 1991 The Claymore Field, Blockl4/19, UK North Sea, 269-278
Memoir 14 Barbican 93
1991 1991 2003 1991 1993
Memoir 14 Memoir 14 Memoir 20 Memoir 14 Barbican 93
CLAYMORE
MAYER, C. E. & HARKER, S. D.
CLAYMORE CLEETON CLIPPER CLIPPER CLYDE CLYDE
HARKER, S. D., GREEN, C. H. & ROMANI, R. S. HEINRICH, R. D. FARMER, R. f . & HILLIER, A. P. SARGINSON,M. J. STEVENS, D. A. & WALLIS, R. J. TURNER, P. J.
COLUMBA B COLUMBA D COLUMBA E CORMORANT N
TAYLOR, D. J. & DIETVORST, J. P. A.
CORMORANT N CORMORANT S
BATER, L. BUDDING, M. C. & INGLIN, H. F.
CORMORANT S
TAYLOR,D. J. & DIETVORST, J. P. A.
CORRINGHAM
FRASER,A. J. & GAWTItORPE, R. L.
CORVETTE CRAWFORD CROPWELL BUTLER
HILLIER, A. P. YALIZ, A. FRASER, A. J. & GAWTHORPE, R. L.
CROSBY W A R R E N FRASER, A. J. & GAWTHORPE, R. L.
CURLEW CYRUS CYRUS DALTON DAUNTLESS
DAVY
Memoir 20
ENEYOK, G. & MAAN, A. MOUND, D. G., ROBERTSON, I. D. & WALLIS, R. J. JOLLEY, J. E.
STEWART, S. A., FRASER, S. I., CARTWRIGHT, J. A., CLARK, J. A. & JOHNSON, H. D. MCCRONE, C. W.
The Cleeton Field, Block 42/29, UK North Sea, 409-416 The Clipper Field, Blocks 48/19a, 48/19c, U K North Sea, 417-424 The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea The Clyde Field, Block 30/17b, UK North Sea, 279-286 Clyde: reappraisal of a producing field. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1503-1512
1991 The Cormorant Field, Blocks 211/21a, 211/26a, UK North Sea, 73-82 2003 The North Cormorant Field, Block 211/21a, U K North Sea 1981 A reservoir geological model of the Brent Sands in Southern Cormorant. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 326-334 1991 The Cormorant Field, Blocks 211/21a, 211/26a, UK North Sea, 73-82 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Corvette Field, Block 49/24, UK Southern North Sea 1991 The Crawford Field, Block 9/28a, UK North Sea, 287-294 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Curlew Field, Block 29/7, UK North Sea 1991 The Cyrus Field, Block16/28, Uk North Sea, 295-300
Barbican 87
Memoir 14
Memoir 14 Memoir 20 Barbican 81
Memoir 14
Memoir 20 Memoir 14
Memoir 20 Memoir 14
2003 The Andrew and Cyrus Fields, Blocks 16/27a, 16/28, UK North Sea
Memoir 20
1999 Controls on Upper Jurassic sediment distribution in the DurwardDauntless area. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 879-896 2003 The Davy, Bessemer, Beaufort and Brown Fields, Blocks 49/23, 49/30a, 49/30c, 53/5a, UK North Sea
Barbican 99
Memoir 20
U K OIL AND GAS FIELDS
983
Field
Authors
Year Reference
Code
DAWN
COOKE-YARBOROUGH, P. & SMITH, E, H.
2003 The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields
Memoir 20
DEBEN DEBORAH
COOKE-YARBOROUGH, P. & SMITH, E . H .
2003 The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields
Memoir 20
DEIDRE DELILIAH
COOKE-YARBOROUGH, P. & SMITH, E . H .
Memoir 20
DELLA
COOKE-YARBOROUGH, P. & SMITH, E.H.
DEVERON DEVERON DON DON
WILLIAMS, R . R . BROWN, A.,M. & MILNE, A . D . MORRISON, D., BENNET, G. G. & BAYAT, M . G . MILNE, A. D. & BROWN, A . M .
2003 The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields 2003 The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields 1991 The Deveron Field, Block 211/18a, UK North Sea, 83-88 2003 The Deveron Field, Block 21 It 18a, UK North Sea 1991 The Don Field, Blocks 211/13a, 211/14, 211/18a, 211/19a, UK North Sea, 89-94 2003 The Don Field, Blocks 211/13a, 211/14, 211/!8a, 211/19a, UK North Sea
DONAN DOTTY, BIG
COOKE-YARBOROUGH, P. & SMITH, E. H,
DOTTY, LITTLE
COOKE-YARBOROUGH,P. & SMITH, E . H .
DOUGLAS
YALIZ, A.
DOUGLAS DRAKE
YALIZ, A. & McKIM, N. STUART, I.A.
DUNBAR
RICHIE, J.S.
DUNCAN
ROBSON, D.
DUNLIN D U N L I N SW DURWARD
BAUMANN, A. & O'CATHAIN, B. STEWART, S. A., FRASER, S.I., CARTWRIGHT, J. A., CLARK, J. A. & JOHNSON, H . D .
2003 The Hewett Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: HeweR, Deborah, Big Dotty, Little Dotty, Della. Dawn and Delilah Fields 2003 The Hewer Fields: Blocks 48/28a, 48/29, 48/30, 52/4a, 52/5a, UK North Sea: Hewett, Deborah, Big Dotty, Little Dotty, Della, Dawn and Delilah Fields 1997 The Douglas Oilfield. In: MEADOWS. N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the Irish Sea and Adjacent Basins, Geological Society, London, Special Publications, 124, 399-416 2003 The Douglas Oil Field, Block 110/13b, East Irish Sea 2003 The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields 2003 The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14 and 3/15, UK North Sea 1991 The Argyll, Duncan and Innes Fields, Blocks 30/24, 30/25a, UK North Sea, 219-226 1991 The Dunlin Field, Blocks 211/23a, 211/24a, UK North Sea, 95-102
Memoir 20
Memoir 14 Memoir 20 Memoir 14 Memoir 20
Memoir 20
Memoir 20
Memoir 20 Memoir 20 Memoir 20 Memoir 14 Memoir 14
1999 Controls on Upper Jurassic sediment distribution in the Durward- Barbican 99 Dauntless area. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 879-896 1993 The Eakring Dukeswood oil field: an unconventional technique for Barbican 93 describing a field's geology. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 1527-1540 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsiblefor Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1999 A subsurface perspectiveon ETAP - an integrated development of Barbican 99 seven Central North Sea fields. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 993-1006 Memoir 14 1991 The Eider Field, Blocks 211/16a, 211/21a, UK North Sea, 103-1 l0 1999 The Elgin and Franklin fields: U K Blocks 22/30c, 22/30b and 29/5b. Barbican 99 In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, t007-1020 Memoir 20 2003 The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14 and 3/15, U K North Sea
EAKRING DUKESWOOD
STOREY, M, W. & NASH, D . F .
EGMANTON
FRASER, A. J. & GAWTHORPE, R. L.
EGRET
POOLER, J. & AMORY, M.
EIDER ELGIN
WENSRICH, M. D., EASTWOOD, K . M . , VAN PANHUYS, C. D. & SMART, J. M. LASOCKI, J., GUEMENE, J.-M., HEDAYATI, A., LEGORJUS, C. & PAGE, W. M.
ELLON
RICHIE, J.S.
ELSWICK EMERALD
STEWART, D. M. & FAULKNER,J. G.
1991 The Emerald Field, Blocks 2/10a, 2/5a, 3/1 lb, UK North Sea, 111-116
Memoir 14
ESKDALE ERSKINE
COWARD, R . N .
2003 The Erskine Field, Block 23/26, UK North Sea
Memoir 20
984
APPENDIX 2
Field
Authors
Year Reference
ESMOND
BIFANI, R,
1986 Esmond gas complex. In: BROOKS,J., GOFF, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in NW Europe. Geological Society, London, Special Publications, 23, 209-221
ESMOND
KETTER, F.J.
ETTRICK
AMIRI-GAROUSSI, K. & TAYLOR, J. M . C .
EVEREST
O'CONNOR, S. J. 8~ WALKER, D.
1991 The Esmond, Forbes and Gordon Fields, Blocks 43/8a, 48/13a, 48/15a, 48/20a,UK North Sea, 425-432 1997 Complex diagenesis in Zechstein dolomites of the Ettrick Field. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference. Geological Society, London, 577-590 1993 Palaeocene reservoirs of the Everest Trend. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 145-160
EXCALIBUR FARLEY'S WOOD
FRASER, A. J. & GAWTHORPE, R.L.
FERGUS FIFE
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. &; BROOKS, J. (eds) Tectonic" Events Responsiblefor Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 SHEPERD, M., MACGREGOR, A., BUSH, K. 2003 The Fife and Fergus Fields, Block 31/26a, UK North Sea & WAKEFIELD,J. CURRIE, S., GOWLAND, S., TAYLOR, A. & 1999 The reservoir development of the Fife Field, In: FLEET, A. J. & WOODWARD, M. BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London,
Code
Memoir 14 Barbican 87
Barbican 93
Memoir 20 Barbican 99
1135-1146
FIFE FISKERTON AIRFIELD FLEMING FLORA
SHEPERD, M., MACGREGOR, A., BUSH, K. 2003 The Fife and Fergus Fields, Block 31/26a, U K North Sea t~ WAKEFIELD,J.
STUART, I. A.
FOINAVEN FORBES
HAYWARD, R. D., MARTIN, C. A. L., HARRISON, D., VAN DORT, G., GUTHRIE, S. ~ PADGET, N. COOPER, M. M., EVANS, A. C., LYNCH, D. J., NEVILLE, G. & NEWLEY, Z. CARRUTH, A. G. BIFANI, R.
FORBES
KETTER, F. J.
FORTH FORTIES
WALMSLEY, P. J.
FORTIES
HILL, P. J. & WooD, G. V.
FORTIES
CARMEN, G. J. & YOUNG, R.
FORTIES FORTIES
WILLS, J. M. CARTER, A. & HEALE, J.
FRANKLIN
LASOCKI, J., GUEMENE, J.-M., HEDAYATI, A., LEGORJUS, C. & PAGE, W. M.
FRIGG
HERITIER, F. E., LOSSEL, P. & WATHNE, E.
FRIGG
HER1T1ER, F. E., LOSSEL, P. & WATHNE, E.
FRIGG
BREWSTER, J.
FULMAR
STOCKBRIDGE, C. P. t~ GRAY, D. I.
FOINAVEN
Memoir 20
2003 The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields 2003 The Flora Field, Blocks 31/26a, 31/26c, UK North Sea
Memoir 20
1999 The Foinaven Field. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 675-682 2003 The Foinaven Field, Blocks 204/19, 204/24a, UK North Sea 1986 Esmond gas complex. In: BROOKS,J., GOFF, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in NW Europe. Geological Society, London, Special Publications, 23, 209-221 1991 The Esmond, Forbes and Gordon Fields, Blocks 43/8a, 48/13a, 48/15a, 48/20a,UK North Sea, 425-432 Renamed to Harding 1975 The Forties Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northewst Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 477-486 1980 Geology of the Forties Field. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Fields of the Decade: 1968-1978. American Association of Petroleum Geologists, Memoir 30, 81-94 1981 Reservoir geology of the Forties oilfield. In: ILLING, L. V. t~ HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe." Proceedings of the 2nd conference. Heyden, London, 371-379 1991 The Forties Field, Blocks 21/10, 22/6a, UK North Sea, 301-308 2003 The Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea 1999 The Elgin and Franklin fields: UK Blocks 22/30c, 22/30b and 29/5b. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 1007-1020 1980 Frigg Field: Large submarin-fan trap in Eocenerocks of the Viking Graben, North Sea. In: HALBOUTY,M. T. (ed.) Giant Oil and Gas Fields of the Decade: 1968-1978. American Association of Petroleum Geologists, Memoir 30, 59-80 1981 The Frigg gas field. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe." Proceedings of the 2nd conference. Heyden, London, 380-391 1991 The Frigg Field, Blocks 10/1, UK North Sea and 25/1, Norwegian North Sea, 117-126 1991 The Fulmar Field, Blocks 30/16, 30/llb, UK North Sea, 309-316
Barbican 99
Memoir 20
Memoir 20
Memoir 14
Barbican 75
Barbican 81
Memoir 14 Memoir 20 Barbican 99
Barbican 81
Memoir 14 Memoir 14
UK OIL AND GAS FIELDS
985
Field
Authors
Year Reference
Code
FULMAR
SPAAK, P., ALMOND, J., SALAHUDIN, S., MOnD SALLEH, Z. & TOSUN, O.
Barbican 99
FULMAR
KUHN, O., SMITH, S. W., VAN NOORT, K. & LOISEAU, B. FRASER, A. J. & GAWTHORPE, R . L .
1999 Fulmar: a mature field revisited. In: FLEET, A. J. & BOLDY, S. A . R . (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 1089-1100 2003 The Fulmar Field, Blocks 30/16, 30/11b, UK North Sea
GAINSBOROUGH
GALAHAD GALLEON GALLEY GANNET A
ARMSTRONG, L., TEN HAVE, A. & JOHNSON, H. D.
GANNET B
ARMSTRONG, L., TEN HAVE, A. & JOHNSON, H. D.
GANNET C
ARMSTRONG, L., TEN Have, A. & JOHNSON, H. D.
GANNET D GANNET E
Memoir 20
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86
1987 The Geology of the Gannet Fields, Central North Sea, UK sector. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 3rd Conference, 533-548 (originally Gannet East) 1987 The Geology of the Gannet Fields, Central North Sea, UK sector. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 3rd Conference, 533-548 (originally Gannet North) 1987 The Geology of the Gannet Fields, Central North Sea, UK sector. In: BROOKS, J. & GLENME, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference, 533-548 (originally Gannet Central)
Barbican 87
Barbican 87
Barbican 87
ARMSTRONG, L., TEN HAVE, A. & JOHNSON, H. D.
1987 The Geology of the Gannet Fields, Central North Sea, UK sector. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference, 533 548 (originally Gannet South)
Barbican 87
2003 The Gawain Field, Blocks 49/24, 49/29a, UK North Sea
Memoir 20
GLAMIS GLAMIS
OSBON, R. A., WERNGREN, O. C., KYEI, A., MANLEY, D. & Six, J. TONK1N, P. C. & FRASER, A. R. GAMBARO, M. & CURRIE, M
Memoir 14 Memoir 20
GLENTWORTH
FRASER, A. J. & GAWTHORPE, R. L.
GLENTWORTH EAST
FRASER, A. J. & GAWTHORPE, R. L.
GODLEY BRIDGE
BUTLER, M. & PULLAN, C. P.
GOODWORTH
BUTLER,M. & PULLAN, C. P.
GORDON
BIFANI, R.
GORDON
KETTER, F. J.
GRANT
RICHIE, J. S.
GUILLEMOT A
ARMSTRONG,L., TEN HAVE, A. & JOHNSON, H. D.
1991 The Glamis Field, Block 16/21a, UK North Sea, 317-322 2003 The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic' Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 1986 Esmond gas complex. In: BROOKS, J., GOFF, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23, 209-221 1991 The Esmond, Forbes and Gordon Fields, Blocks 43/8a, 48/13a, 48/15a, 48/20a,UK North Sea, 425 432 2003 The Dunbar, Ellon and Grant Fields (Alwyn South Area), Blocks 3/8a, 3/9b, 3/13a, 3/14 and 3/15, UK North Sea 1987 The Geology of the Gannet Fields, Central North Sea, U K sector. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference, 533 548 (originally Gannet West) 1987 The Geology of the Gannet Fields, Central North Sea, UK sector. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference, 533-548 (originally Gannet West)
GANNET F GANNET G GANYMEDE GAWAIN
G U I L L E M O T WEST ARMSTRONG, L., TEN HAVE, A. & JOHNSON, H. D.
Memoir 14 Memoir 20 Barbican 87
Barbican 87
986
APPENDIX 2
Field
Authors
Year Reference
Code
GUINEVERE
2003 The Guinevere Field, Block 48/17b, U K North Sea
Memoir 20
HAMILTON N
YALIZ, A. & TAYLOR, P.
HAMISH
CURRIE, S.
HAMISH
HARVEY, M. & CURRIE, S.
HARDING
BECKLEY, A. J., NASH, T., POLLARD, R., BRUCE, C., FREEMAN, P. & PAGE, G. FRASER, A. J. • GAWTHORPE, R. L.
1993 The geology of the Gryphon Oilfield. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 123-134 2003 The Hamilton and Hamilton North Gas Fields, Block 110/15, East Irish Sea 2003 The Hamilton and Hamilton North Gas Fields, Block 110/15, East Irish Sea 1996 The development of the Ivanhoe, Rob Roy and Hamish Fields, Block 15/21A, UK North Sea. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERTICH, D. S. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 329-341 2003 The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea 2003 The Harding Field, Block 9/23b
Barbican 93
HAMILTON
LAPPIN, M., HENDRY, D. J. & SAIKIA, I. A. NEWMAN, M. ST J., REEDER, M. L., WOODRUFF, A. H. W. & HATTON, I. R. YALIZ, A. & TAYLOR, P.
GYRPHON
HARDSTOFT
HATFIELD MOORS
FRASER, A. J. & GAWTHORPE, R. L.
HATFIELD MOORS HATFIELD WEST HAWKINS
WARD, J., CHAN, A. & RAMSEY, B.
HEATHER
GRAY, W. D. T. & BARNES, G.
HEATHER HEATHER HEM HEATH HEMSWELL
PENNY, B. KAY, S.
HERON
POOLER, J. & AMORY, M.
HERRIARD
UNDERHILL, J. R. & STONELEY,R.
HERRIARD
TRUEMAN, S.
HEWETT
CUMMING, A. D. & WYNDHAM,C. L.
HEWETT
COOKE-YARBOROUGH, P.
HEWETT
COOKE-YARBOROUGH, P. 8~; SMITH, E. H.
HIGHLANDER HORNDEAN
WHITEHEAD, M. & PINNOCK, S. J. BUTLER, M. & PULLAN, C. P.
WARD, J., CHAN, A. & RAMSEY, B. STUART, I. A.
FRASER, A. J. & GAWTHORPE, R. L.
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas' Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Hatfield Moors and Hatfield West Gas (storage) Fields, South Yorkshire 2003 The Hatfield Moors and Hatfield West Gas (storage) Fields, South Yorkshire 2003 The Armada development, UK Central North Sea: The Fleming, Drake and Hawkins Gas-Condensate Fields 1981 The Heather Oil Field. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 335-341 1991 The Heather Field, Block 2/5, UK North Sea, 127-134 2003 The Heather Field, Block 2/5, UK North Sea 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1999 A subsurface perspectiveon ETAP - an integrated development of seven Central North Sea fields. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 993-1006 1998 Introduction to the development, evolution and petroleum geology of the Wessex Basin. In: UNDERHILL,J. R. & STONELEY, R. (eds) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publications, 133, 1-18 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore 1975 The Geology and Development of the Hewett Gas-Field. In: WOODLAND,A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 313-326 1991 The Hewett Field, Blocks 48/28-29-30, 52/4a-5a, UK North Sea, 433-442 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, U K Onshore 1991 The Highlander Field, Blockl4/20b, U K North Sea, 323-330 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publication, 55, 371-391
Memoir 20 Memoir 20
Memoir 20 Memoir 20
Memoir 20 Memoir 20 Memoir 20 Barbican 81
Memoir 14 Memoir 20
Barbican 99
Memoir 20
Barbican 75
Memoir 14 Memoir 20
Memoir i4
UK OIL AND GAS FIELDS
987
Field
Authors
Year Reference
Code
HORNDEAN
TRUEMAN, S.
2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore
Memoir 20
HANCOCK, F. R. P. & MITHEN, D. P.
1987 The geology of the Humbley Grove Oilfield, Hampshire, UK, 161-170 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore 1991 The Hutton Field, Blocks 211/28, 211/27, UK North Sea, 135-144 1991 The Northwest Hutton Field, Block 211/27, UK North Sea, 145-152 1993 Hyde: a proposed field developmentin the Southern North Sea using horizontal wells, In: PARKER, R. J. (ed.) Petroleum Geology o f Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1465-1472 1975 Geology of the Indefatigable Gas-Field, In: WOODLAND,A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 233-240 1991 The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea, 443-450 2003 The Indefatigable Field, Blocks 49/18, 49/19, 49/23, 49/24, UK North Sea 1991 The Argyll, Duncan and Innes Fields, Blocks 30/24, 30/25a, UK North Sea, 219-226
Barbican 87
HUDSON HUMBLEY GROVE HUMBLEY GROVE
BUTLER, M. & PULLAN, C. P.
HUMBLEY GROVE
TRUEMAN, S.
HUTTON HUTTON NW HYDE
HAIG, D. B. JOHNES, L. H. & GAUER, M. B. STEELE, R. P., ALLEN, R. M., ALLINSON, G. J. & BOOTH, A. J.
INDEFATIGABLE
FRANCE, D. S.
INDEFATIGABLE
INNES
PEARSON, J. F. S., YOUNGS, R. A. & SMITH, A. MCCRONE, C. W., GAINSKI, M. & LUMSDEN, P. J. ROBSON, D.
IONA IVANHOE
PARKER, R. H.
IVANHOE
CURRIE, S.
IVANHOE JANICE JOANNE JOHNSTON
HARVEY, M. & CURRIE, S.
JUDY
SWARBRICK, R. E., OSBORNE, M. J., YARDLEY, G. S., MACLEOD, G., APLIN, A. C., LARTER, S. R., KNIGHT, I. & AULD, H. A.
INDEFATIGABLE
LAWTON, D. E. & ROBERSON, P. P.
KEDDINGTON KETCH KELHAM
FRASER, A. J. & GAWTHORPE, R. L.
KIMMERIDGE BAY
EVANS, I. J., JENKINS, D. & GLUYAS, J. G.
KIMMERIDGE BAY KINGFISHER KINOULTON
GLUYAS, J. G., EVANS, I. J. & RICHARDS, D. SPENCE, S. & KREUTZ, H. FRASER, A. J. & GAWTHORPE, R. L.
KIRBY MISPERTON KIRKLINGTON
FRASER, A. J. & GAWTHORPE, R. L.
1991 The Iyanhoe and Rob Roy Fields, Block 15/21a-b, UK North Sea, 331-338 1996 The development of the Ivanhoe, Rob Roy and Hamish Fields, Block 15/ 21A, UK North Sea. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERTICH,D. S. (eds) Geology of the Humber Group." Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 329-341 2003 The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea
2003 The Johnston Gas Field, Blocks 43/26a, 43/27a, UK Southern North Sea 2000 Integrated study of the Judy Field (Block 30.7a) - an overpressured Central North Sea oil/gas field. Marine and Petroleum Geology, 17, 993-1010
Memoir 20
Memoir 14 Memoir 14 Barbican 93
Barbican 75
Memoir 14 Memoir 20 Memoir 14
Memoir 14 Barbican 93
Memoir 20
Memoir 20
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England, In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1998 The Kimmeridge Bay Oilfield, an enigma demystified. In: UNDERHmL, J. R. (ed.) Development, Evolution and Petroleum Geology of the Wessex Basin. Geological Society, London, Special Publications, 133, 407-413 2003 The Kimmeridge Bay Oilfield, Dorset, UK Onshore Memoir 20 2003 The Kingfisher Field, Block 16/8a, UK North Sea 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England, In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86
Memoir 20
988
Field
APPENDIX 2
Authors
Year Reference
Code
KITTYWAKE I~ LANCELOT LANGAR LARCH LEMAN
RICHES, H.
2003 The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea
Memoir 20
VAN VEEN, F. R.
Barbican 75
LEMAN
HILL1ER, A. P. & WILLIAMS, B. P. J.
LEMAN
HILLIER, A. P.
LENNOX
HAIG, D. B., PICKERING, S. & PROBERT, R.
LENNOX LEVEN LINNHE LOCKTON LOMER
YALIZ, A. & CHAPMAN, T.
1975 Geology of the Leman Gas-Field. In: WOODLAND,A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 223-232 1991 The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea, 451-458 2003 The Leman Field, Blocks 49/26, 49/27, 49/28, 53/1, 53/2, UK North Sea 1997 The Lennox oil and gas Field. In: MEADOWS,N. S., TRUEBLOOD,S. P., HARDMAN, M. ~; COWAN, G. (eds) Petroleum Geology of the Irish Sea and Adjacent Basins. Geological Society, London, Special Publications, 124, 417-436 2003 The Lennox Oil and Gas Field, Block 110/15, East Irish Sea
LOMOND LONG CLAWSON
LYELL MACCULLOCH MACHAR
MACHAR
MAGNUS
MAGNUS MAGNUS S MALLARD MALORY MALTON MARISHES MARKHAM MARNOCK
MAUREEN MAUREEN MEDWIN MERCURY MERLIN MIDLOTHIAN (D'ARCY) MILLER
BUTLER, M. & PULLAN, C. P.
1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic' Events' Responsible ,for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391
FRASER, A. J. & GAWTHORPE, R. L.
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86
GUNN, C., SALVADOR,P., TOMPKINSON,J. 2003 The MacCulloch, Block 15/24b, UK North Sea ~fr MACLEOD, J. A. 1993 The evolution of a fractured chalk reservoir: Machar Oilfield, UK FOSTER, P. T. & RATTEY, P. R. North Sea. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 1445-1452 1999 A subsurface perspective on ETAP - an integrated development of POOLER, J. & AMORY, M. seven Central North Sea fields. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 993 1006 1981 The geology of the Magnus Oilfieid. In: ILLING, L. V. & HOBSON, DE'ATH, N. G. & SCttUYLEMAN,S. F. G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 342-351 1991 The Magnus Field, Blocks 211/7, 211/12a, UK North Sea, 153 158 SHEPHERD, M.
O'BRIEN, R. E., LAPPIN, M., KOMLOSk F. 2003 The Malory Field, Block 48/12d, UK North Sea ~; LOFTUS, J. A.
MYERS, J. C., JONES, A. F. & TOWART, J. M. POOLER, J. & AMORY, M.
CUTTS, P. L. CttANDLER, P. M. & DICKINSON, B.
1995 The Markham Field: UK Blocks 49/5a and 49/10b, Netherlands Blocks J3b and J6. Petroleum Geoscience, 1, 303-308 1999 A subsurface perspectiveon ETAP an integrated development of seven Central North Sea fields. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 993-1006 1991 The Maureen Field, Block 16/29a, U K North Sea, 347-352 2003 The Maureen Field, Block 16/29a, U K Central North Sea
SMITH, B. & STARCHER, V.
2003 The Mercury and Neptune Fields, Blocks 47/9b, 47/4b, 47/5a, 42/29, UK North Sea
MCCLURE, N. M. & BROWN, A. A.
1992 Miller Field, A subtle Upper Jurassic submarine fan trap in the South Viking Graben, United Kingdom sector, North Sea. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Fields of the Decade: 1978-1988. American Association of Petroleum Geologists, Memoir 54, 307-322
Memoir 14 Memoir 20
Memoir 20
Memoir 20 Barbican 93
Barbican 99
Barbican 81
Memoir 14
Memoir 20
Barbican 99
Memoir 14 Memoir 20 Memoir 20
UK OIL AND GAS FIELDS
989
Field
Authors
Year Reference
Code
MILLER MILLER
ROOKSBY, S. K. GARLAND, C. R.
Memoir 14 Barbican 93
MILLOM
COWAN, G. & BRADNEY, J.
1991 The Miller Field, Block 16/7b, 16/8b, U K North Sea, 159-164 1993 Miller Field: reservoir stratigraphy and its impact on development. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 401-414 1997 Regional diagenetic controls on reservoir properties in the Millom accumulation: implications for field development. In: MEADOWS, N. S., TRUEBLOOD, S. P., HARDMAN, M. & COWAN, G. (eds) Petroleum Geology of the Irish Sea and Adjacent Basins. Geological Society, London, Special Publication, 124, 373-386
MILTON OF BALGONIE MODRED MOIRA MONAN
CHANDLER, P. M. & DICKINSON, B. POOLER, J. & AMORY, M.
Memoir 20 Barbican 99
MONTROSE
FOWLER, C.
MONTROSE
CRAWFORD,R., LITTLEFAIR,R. W. &
MONTROSE
AFFLECK, L. G. HOGG, A. J. C.
MORECAMBE N
EBBERN, J.
MORECAMBE N
BUSHELL, T. P.
2003 The Moira Field, Block 16/2%, UK Central North Sea 1999 A subsurface perspective on ETAP - an integrated development of seven Central North Sea fields. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 993-1006 1975 The Geology of the Montrose Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 467-476 1991 The Arbroath and Montrose Field, Blocks 22/17, 18, UK North Sea, 211-217 2003 The Montrose, Arbroath and Arkwright Fields, Blocks 22/17, 22/18, 22/23a, UK North Sea 1981 The geology of the Morecambe gas field. In: IeLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe." Proceedings of the 2nd conference. Heyden, London, 485-493 1986 Reservoir Geology of the Morecambe Field. In: BROOKS, J., GObF, J. C. & VAN HOORN, B: (eds) Habitat of Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23,
MORECAMBE N
STUART, I. A.
MORECAMBE N
COWAN, G.
MORECAMBE N MORECAMBE S
COWAN, G. & BOYCOTT-BROWN, T. EBBERN, J.
MORECAMBE S
BUSHELL, T. P.
MORECAMBE S
STUART, I. A. & COWAN,G.
MORECAMBE S MUNGO
BASTIN, J. C., BOYCOTT-BROWN, T. E., SIMS, A., & WOODHOUSE, R. POOLER, J. & AMORY, M.
MURCHISON
SIMPSON, R. D. H. & WHITLEY, P. K. J.
MURCHISON MURDOCH NELSON
WARRENDER, J. CONWAY, A. M. & VALVATNE, C. KUNKA, J. M., WILLIAMS,G., CULLEN, B., BOYD-GORST, J., DYER, G. R., GARNHAM, J. A., WARNOCK, A., WARDELL, J., DAVIS, A. & LYNES, P.
Barbican 75
Memoir 14 Memoir 20 Barbican 81
189-208
1993 The geology of the North Morcambe Gas Field, East Irish Sea Basin. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 883-896 1996 The development of the North Morecambe Gas Field, East irish Sea Basin, UK. Petroleum Geoscience, 2, 43-52 2003 The North Morecambe Field, Block 110/2a, East Irish Sea 1981 The geology of the Morecambe gas field. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe: Proceedings of the 2nd conference. Heyden, London, 485-493 1986 Reservoir Geology of the Morecambe Field. In: BROOKS, J., GOFE, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in NW Europe. Geological Society, London, Special Publications, 23,
Barbican 93
Memoir 20 Barbican 81
189-208
NESS NEPTUNE
SMITH, B. & STARCHER,V.
1991 The North Morecambe Field, Block 110/2a,110/3a and 110/8a, U K East Irish Sea 2003 The North Morecambe Field, Block 110/2a, East Irish Sea
Memoir 14
1999 A subsurface perspectiveon ETAP - an integrated development of seven Central North Sea fields. In: FLEET, A. J. & BoeoY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5ih COnference. Geological Society, London, 993-1006 1981 Geological input to reservoir simulation of the Brent Formation. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe. Heyden, London, 310-314 1991 The Murchison Fields, Block 211/19a, U K North Sea, 165-174 2003 The Murdoch Gas Field, Block 44/22a, UK Southern North Sea 2003 The Nelson Field, Blocks 22/11, 22/6a, 22/7, 22/12a, UK North Sea
Barbican 99
2003 The Mercury and Neptune Fields, Blocks 47/9b, 47/4b, 47/5a, 42/29, UK North Sea
Memoir 20
Memoir 20
Barbican 81
Memoir 14 Memoir 20 Memoir 20
990
APPENDIX 2
Field
Authors
Year Reference
NETTLEHAM
FRASER,A. J. & GAWTHORPE, R . L .
NEVIS
DICKSON, A. J., B1NGHAM, G. C., STYLIANIDES, G. C., THOMPSON, H. W. A. & WAY, N. A.
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. 86 BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1999 Application of 3D visualisation and VSP for horizontal well positioning - 9/13a-N1 case history. In: FLEET, A. J. 86 BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1051-1062
NEWSHAM N E W T O N ON TRENT NINIAN
ALBRIGHT, W. A., TURNER, W. L. & WILLIAMSON, K. R.
NINIAN NOOKS F A R M ORION ORWELL OSPREY PALMERS WOOD
VAN VESSEM, E. J. & GAN, T. L.
PALMERS WOOD
TRUEMAN, S.
PELICAN PETRONELLA PHOENIX PICKERILL PIERCE PIPER
ERICKSON, J.W. 86 VAN PANHUYS, C. D. QING SUN, A. 86WRIGHT, V.P.
WADDAMS,P. & CLARK, N. M. RICHES, H. WENGEREN, 0., MANLEY, D. & HEWARD, A. P. BIRCH, P. 86 HAYNES, J. WILLIAMS,J. J., CONNER,D. C. & PETERSON, K. E.
PIPER
MAHER, C. E.
PIPER
MAHER, C. E.
PIPER PIPER
SCHMITT, H. R. H. & GORDON, A. F. HARKER, S. D.
PLUNGAR
FRASER, A. J. & GAWTHORPE, R. L.
PUFFIN
DICKINSON, B.
RAVENSPURN N
KETTER, F. J.
RAVENSPURN S
HEINRICH, R. U.
REMPSTONE
FRASER, A. J. 86 GAWTHORPE, R. L.
RENEE ROB ROY
PARKER, R. H.
1980 Ninian Field, UK Sector, North Sea. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Fields of the Decade." 1968-1978. American Association of Petroleum Geologists, Memoir 30, 173-194 1991 The Ninian Field, Blocks 3/3 and 3/8, UK North Sea
1991 The Osprey Field, Blocks 211/18a, 211/23a, UK North Sea, 183-190 1998 Controls on reservoir quality of an Upper Jurassic reef mound in the Palmers Wood Field are, Weald Basin, Southern England. Am. Ass. Petrol. Geol. Bull., 82, 497-515 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore
Code
Barbican 99
Memoir 14
Memoir 14
Memoir 20
Memoir 14 1991 The Petronella Field, Block 14/20b, UK North Sea, 353-360 2003 The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea Memoir 20 2003 The Pickerell Field, Blocks 48/11a, 48/11b, 48/12c, 48/17b, UK Memoir 20 North Sea 2003 The Pierce Field, Blocks 23/22a, 23/27, UK North Sea Memoir 20 1975 The Piper Oil-Field, UK North Sea. In: WOODLAND, A. W. (ed.) Barbican 75 Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 363 378 1980 Piper Oil Field. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Field~ of the Decade: 1968. American Association of Petroleum Geologists, Memoir 30, 131-172 1981 The Piper Oilfield. In: ILUNG, L. V. & HOBSON, G. D. (eds) Barbican 81 Petroleum Geology of the Continental Shelf of Northwest Europe." Proceedings of the 2nd conference. Heyden, London, 358-370 1991 The Piper Field, Block 15/17, UK North Sea, 361-368 Memoir 14 1998 The Palingenesy of the Piper oil field, UK North Sea. Petroleum Geoscience, 4, 271-286 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. 86 BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1996 The Puffin Field: the appraisal of a complex HP-HT gas condensate Barbican 93 accumulaton. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. 86 MACKERTICH, D. S. (eds) Geology of the Humber Group." Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 299-328 1991 The Ravenspurn North Field, Blocks 42/30, 43/26a, UK North Sea, Memoir 14 459 467 1991 The Ravenspurn South Field, Blocks 42/29, 42/30, 43/26, UK North Memoir 14 Sea, 469-476 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. 86 BROOKS, J. (eds) Tectonic Events Responsible for Britain'6' Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1991 The Ivanhoe and Rob Roy Fields, Block 15/21a-b, UK North Sea, 331-338
Memoir 14
UK OIL AND GAS FIELDS
991
Field
Authors
Year Reference
Code
ROB ROY
CURmE, S.
Barbican 93
ROB ROY
HARVEY, M. & CURRIE, S.
ROSS
SMALLEY, P. C.
ROUGH
GOODCHILD, M. V. & BRYANT, P.
ROUGH
STUART, I. A.
1996 The development of the Ivanhoe, Rob Roy and Hamish Fields, Block 15/21A, UK North Sea. In: HURST, A., JOHNSON, H. D., BURLEY, S. D., CANHAM, A. C. & MACKERTICH, D. S. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 329-341 2003 The Ivanhoe, Rob Roy and Hamish Fields, Block 15/21, UK North Sea 1995 A toolbox for early identification of reservoir compartmentalization. SPE 030533 1986 The geology of the Rough Gas Field. In: BROOKS,J., GOFF, J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23, 223-235 1991 The Rough Gas Storage Field, Blocks 47/3d, 47/8b, UK North Sea, 477-484
RUBIE SALTFLEETBY
HODGE, T.
SALTIRE
CASEY, B. J., ROMANI, R. S. & SCHMITT, R . H .
SCAMPTON
FRASER, A. J. & GAWTHORPE, R. L.
SCAMPTON N
SCAPA SCHIEHALLION
FRASER, A. J. & GAWTHORPE, R. L.
MCGANN, G. J., GREEN, S. C.H., HARKER, S. D. & ROMANI, R. S. LEACH,H. M., HERBERT, N., LOS, A. & SMITH, R . L .
SEAN E
MUSCARIELLO, A. GUSCOTT, S., RUSSELL, K., THICKPENNY, A. & PODDUBIUK, R. HILLIER, A. P.
SEAN N & S
TEN HAVE, A. & HILLIER, A.
SEAN N & S
HOBSON, G. D. & HILLIER, A. P.
SEAN N & S
HILLIER, A. P.
SEDGEWICK
WRIGHT, S. D.
SHEARWATER
SINGLETON
BLEHAUT, J. F., VAN BEEK, F., BILLEAU, C., GAUSE, J. K., KIMMINAU, S., PAARDEKAM,A., RADCLIFFE, N., RADEMAKER,R., STORMS, L., WELSH, B. J. & WITTEMAN, A. BUTLER, M. & PULLAN, C. P.
SINGLETON
TRUEMAN, S.
SKUA
POOLER, J. & AMORY, M.
SCHOONER SCOTT
2003 The Saltfleetby Field, Block L 47/16, Licence PEDL 005, Onshore UK 1993 Appraisal geology of the Saltire Field, Witch Ground Graben, North Sea. In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe." Proceedings of the 4th Conference. Geological Society, London, 507-518 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic' Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 1991 The Scapa Field, Block 14/19, UK North Sea, 369-376
Memoir 20
Memoir 14
Memoir 20 Barbican 93
Memoir 14
1999 The Schiehallion development. In: FLEET, A. J. & BOLDY, S. A . R . (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 683-692 2003 The Schooner Field, Blocks 44/26a, 43/30a, UK North Sea 2003 The Scott Field, Blocks 15/21a, 15/22, UK North Sea
Barbican 99
2003 The Sean North, Sean South and Sean East Fields, Block 49/25a, UK North Sea 1986 Reservoir Geology of the Sean North and South Gas Fields, UK Southern North Sea. In: BROOKS,J., GOFF,J. C. & VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23, 267-273 1991 The Sean North and South Fields, Block 49/25a, UK North Sea, 485-490 2003 The Sean North, Sean South and Sean East Fields, Block 49/25a, UK North Sea 2003 The West Brae & Sedgwick Fields, Blocks 16/6a, 16/7a, UK North Sea 1999 Shearwater prospect development: a high pressure/high temperature challenge. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1021-1028
Memoir 20
1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore 1999 A subsurface perspectiveon ETAP - an integrated development of seven Central North Sea fields. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 993-1006
Memoir 20 Memoir 20
Memoir 14 Memoir 20
Barbican 99
Memoir 20
Barbican 99
992
APPENDIX 2
Field
Authors
Year Reference
Code
SOLAN
HERRIES, R., PODDUBIUK, R. & WILCOCKSON, P.
Barbican 99
SOUTH LEVERTON
FRASER, A. J. & GAWTHORPE, R. L.
STAFFA STAINTON STATFJORD
GLUYAS, J. G. & UNDERHILL, J. R.
1999 Solan, Strathmore and the back basin play, West of Shetland. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 693-712 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Staffa Field, Block 3/8b, UK North Sea
KIRK, R. H.
STIRLING
GIBBONS, K. A., JOURDAN,C. A. & HESTHAMMER, J. GAMBARO, M. & CURRIE, M.
STOCKBRIDGE
BUTLER,M. & PULLAN, C . P .
STOCKBRIDGI~
TRUEMAN,S.
STORRINGTON
BUTLER, M. & PULLAN, C. P.
STORRINGTON
TRUEMAN,S.
STRATHMORE
HERR1ES,R., PODDUBIUK, R. & WILCOCKSON, P.
STRATHSPEY
MAXWELL,G., STANLEY,R. E. & WHITE, D. C. COWARD, R. N., CLARK,N. M. &
STATFJORD
TARTAN
1980 Statfjord Field: A North Sea giant. In: HALBOUTY,M. T. (ed.) Giant Oil and Gas Fields of the Decade: 1968-1978. American Association of Petroleum Geologists, Memoir 30, 95-116 2003 The Statfjord Field, Blocks 33/9, 33/12 Norwegian sector, Blocks 211/24, 211/25 UK sector, Northern North Sea 2003 The Balmoral, Glamis and Stirling Fields, Block 16/21, UK Central North Sea 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore 1990 Tertiary structures and hydrocarbon entrapment in the Weald Basin of southern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 371-391 2003 Humbly Grove, Herriard, Storrington, Singleton, Stockbridge, Goodworth, Horndean, Palmers Wood, Bletchingley and Albury Fields, Hampshire, Surrey, Sussex, UK Onshore 1999 Solan, Strathmore and the back basin play, West of Shetland. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conference. Geological Society, London, 693-712 2003 The Strathspey Field, Block 3/4a, UK North Sea
Memoir 20
Memoir 20 Memoir 20
Memoir 20
Memoir 20
Barbican 99
Memoir 20
1991 The Tartan Field, Block 15/16, UK North Sea, 377 384
Memoir 14
1999 Integrating sequence stratigraphyin field development and reservoir management- the Telford Field. In: FLEET,A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5 th Conference. Geological Society, London, 1075-1088 1991 The Tern Field, Block 210/25a, UK North Sea 191-198
Barbican 99
PINNOCK, S. J. TEAL TEAL S TELFORD
TERN TERN
SYMS, R. M., SAVORY, D. F., WARD, C. J., EBDON, C. C. & GRIFFIN, A. VAN PANIIUYS-SIGLER, M., BAUMAN, A. & HOLLAND, T. C. BLACK, R. C., POELEN, H. J., ROBERTS, M. J. & RODDY, S. E.
THAMES
WERNGREN, 0. C.
THELMA
THISTLE
GAMBARO, M., DONAGEMMA, V. SABLE, G. GAMBARO, M., DONAGEMMA, V. & SABLE, G. HALLETT, D.
THISTLE
WILLIAMS, R. R. & MILNE, A. D.
THISTLE TIFFANY
BROWN, A. M., MILNE, A. D. & KAY, A. KERLOGUE, A., CHERRY, S., DAVIES, H., QUINE, M. & SPOTTI, G.
TIFFANY
GAMBARO, M., DONAGEMMA, V. & SABLE, G.
T H E L M A SE
Memoir 14 Barbican 99
1999 Tern Field development: a marriage of new technologies for business benefit. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 1063-1074 1991 The Thames, Yare and Bure Fields, Block 49/28, UK North Sea, 491-496 2003 The T-Block Fields, Block 16/17, UK North Sea
Memoir 20
2003 The T-Block Fields, Block 16/17, UK North Sea
Memoir 20
1981 Refinement of the Geological Model of the Thistle Field. In: ILLING, L. V. & HOBSON, G. D. (eds) Petroleum Geology of the Continental Shelf of Northwest Europe." Proceedings' of the 2nd conference. Heyden, London, 315 325 1991 The Thistle Field, Blocks 211/18a, 211/19, UK North Sea 199-207 2003 The Thistle Field, Blocks 211/18a, 211/19a, UK North Sea 1995 The Tiffani and Toni oil fields, Upper Jurassic submarine fan reservoirs, South Viking Graben, UK North Sea. Petroleum Geoscience, l, 279-286 2003 The T-Block Fields, Block 16/17, UK North Sea
Barbican 81
Memoir 14
Memoir 14 Memoir 20
Memoir 20
UK OIL AND GAS FIELDS
993
Field
Authors
Year Reference
Code
TONI
KERLOGUE, A., CHERRY, S., DAVIES, H., QU~NE, M. & SPOTTI, G.
TONI
GAMBARO, M., DONAGEMMA, V. 8r SABLE, G. FRASER, A. J. & GAWTHORPE, R. L.
1995 The Tiffani and Toni oil fields, Upper Jurassic submarine fan reservoirs, South Viking Graben, UK North Sea. Petroleum Geoscience, 1,279-286 2003 The T-Block Fields, Block 16/17, UK North Sea
Memoir 20
TORKSEY
TRENT
O'MARA, P. T., MERRYWEATHER, M., STOCKWELL, M. & BOWLER, M. M.
TRENT
O'MARA, P. T., MERRYWEATHER, M., STOCKWELL, M. & BOWLER, M. M.
TRISTAN TRUMFLEET
TYNE N
FRASER, A. J. & GAWTHORPE, R. L.
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49 86 1999 The Trent Gas Field: correlation and reservoir quality within a complex Carboniferous stratigraphy. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe." Proceedings of the 5th Conjerence. Geological Society, London, 809-824 2003 The Trent Gas Field, Block 43/24a, UK North Sea
Barbican 99
Memoir 20
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Tyne Gas Fields, Block 44/18a, UK North Sea
Memoir 20
2003 The Tyne Gas Fields, Block 44/18a, UK North Sea
Memoir 20
2003 The Tyne Gas Fields, Block 44/18a, UK North Sea
Memoir 20 Memoir 14
VALIANT N
O'MARA, P. T., MERRYWEATHER, M. & COOPER, D. S. O'MARA, P. T., MERRYWEATHER, M. & COOPER, D. S. O'MARA, P. T., MERRYWEATHER, M. & COOPER, D. S. PRICHARD, M. J.
VALIANT N VALIANT S
COURTIER, J., & RICHES, H. PRICHARD, M. J.
VALIANT S VAMPIRE VANGUARD
COURTIER, J. & RICHES, H. RICHES, n . PRICHARD, M. J.
VANGUARD VICTOR
COURTIER, J., & RICHES, H. CONWAY, A. M.
VICTOR VICTORY
LAMBERT, R. A. GOODCHILD, M. W., HENRY, K. L., HINKLEY, R. J. & IMBUS, S. W.
VIKING
GRAY, I.
VIKING
GAGE, M.
VIKING
MORGAN, C. P.
VIKING VULCAN
RICHES, H. PRICHARD, M. J.
VULCAN WAREHAM WAVENEY WELLAND NW WELLAND S WELTON
COURTIER, J. • RICHES, H.
1991 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, U K North Sea, 497 502 2003 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, U K North Sea 1991 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, U K North Sea, 497 502 2003 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea 2003 The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea 1991 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea, 497-502 2003 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea 1986 Geology and petrophysiocs of the Victor Field. In: BROOKS, J., GOFF, J. C. ~; VAN HOORN, B. (eds) Habitat of Palaeozoic Gas in N W Europe. Geological Society, London, Special Publications, 23, 237-249 1991 The Victor Field, Blocks 49/17, 49/22, UK North Sea, 503-508 1999 The Victory Gas Field, West of Shetland. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 713 724 1975 Viking Gas-Field. In: WOODLAND, A. W. (ed) Petroleum and the Continental Shelf of Northewst Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 241-248 1980 A review of the Viking Gas Field. In: HALBOUTY, M. T. (ed.) Giant Oil and Gas Fields o f the Decade: 1968-1978. American Association of Petroleum Geologists, Memoir 30, 39-58 1991 The Viking Complex Field, Blocks 49/12a, 49/16, 49/17, UK North Sea, 509-515 2003 The Viking Field, Blocks 49/12a, 49/16, 49/17, UK North Sea 1991 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea, 497-502 2003 The V-Fields, Blocks 49/16, 49/21, 48/20a, 48/25b, UK North Sea
BRUCE, D. R. S. & PEBORA, P.
2003 The Waveney Field, Block 48/17c, UK Southern North Sea
Memoir 20
ROTHWELL, N. R. & QUINN, P.
Barbican 87
WELTON
FRASER, A. J. & GAWTHORPE, R. L.
1987 The Welton Oilfield. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology o f North West Europe: Proceedings of the 3rd Conference, 181-190 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49 86
TYNE S TYNE W
Memoir 20 Memoir 14 Memoir 20 Memoir 20 Memoir 14 Memoir 20
Memoir 14 Barbican 99
Barbican 75
Memoir 14 Memoir 20 Memoir 14 Memoir 20
994
APPENDIX 2
Field
Authors
Year Reference
WENSUM WEST FIRSBY
FRASER, A. J. & GAWTHORPE, R. L.
WEST FIRSBY WEST SOLE
BAILEY,R. J. BUTLER, J. B.
WEST SOLE WHISBY
WINTER, D. A. & KING, B. FRASER, A. J. & GAWTtIORPE, R. L.
WINDERMERE
BAILEY, R. J. & CLEVER, J. E.
WYTCH F A R M
HURST, A. & COLTER, V. S.
WYTCH F A R M
DRANFIELD, P., BEGG, S. H. & CARTER, R. R.
WYTCH F A R M
BOWMAN, M. B. J., MCCLURE, N. M. & WILKINSON, D. W.
WYTCH F A R M
HOGG, A. J. C., EVANS, I. J., HARRISON, P. F., MELING, T., SMITH, G. S., THOMPSON, S. D. & WATTS, G. F. T.
1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. BROOKS, J. (eds) Tectonic" Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The West Firsby Oilfield, Development Licence 003, Lincolnshire 1975 The West Sole Gas Field. In: WOODLAND, A. W. (ed.) Petroleum and the Continental Shelf of Northwest Europe, Volume 1 Geology. Applied Science Publishers, Barking, England, 213-222 1991 The West Sole Field, Block 48/6, Uk North Sea, 517-523 1990 Tectono-stratigraphic development and hydrocarbon habit of the Carboniferous in northern England. In: HARDMAN, R. F. P. & BROOKS, J. (eds) Tectonic Events Responsible for Britain's Oil and Gas Reserves. Geological Society, London, Special Publications, 55, 49-86 2003 The Windermere Gas Field, Blocks 49/9b, 49/4a, UK Southern North Sea 1998 A note on the exploration of the Wytch Farm oilfieid. Petroleum Geoscience, 4, 377-380 1987 Wytch Farm Oilfield: reservoir characterisation of the Triassic Sherwood Sandstone for input to reservoir simulation studies. In: BROOKS, J. & GLENNIE, K. W. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 3rd Conference, 149-160 1993 Wytch Farm oilfield: deterministic reservoir description of the Triassic Sherwood Sandstone, In: PARKER, R. J. (ed.) Petroleum Geology of Northwest Europe." Proceedings" of the 4th Conference. Geological Society, London, 1513-1516 1999 Reservoir management of the Wytch Farm Oil Field, Dorset UK: providing options for growth into later field life. In: FLEET, A. J. & BOLDY, S. A. R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London,
YARE
WERNGREN, 0. C.
Code
Memoir 20 Barbican 75
Memoir 14
Memoir 20
Barbican 87
Barbican 93
Barbican 99
1157-1172
1991 The Thames, Yare and Bure Fields, Block 49/28, UK North Sea, 491 496
Memoir 14
Index
Page numbers in italics refer to Figures and those in Bold refer to Tables Alba Field 12, 49, 979 Albury Field 937, 979 data summary 940-1,949 location 929, 931-2 production history 929-31,932 reservoir 41,937 Alligin Field 122 Altena Group, Lower Jurassic 38 Alwyn North Field 26, 37, 39, 40, 329, 979 Alwyn South Field 40 see Dunbar Field; Ellon Field; Grant Field Amethyst Field 30, 684, 979 Andrew Field 12, 45, 979 data summary 949 discovery 134-5 history 133-4 reserves and production 136 reservoir 48, 135 structure, stratigraphy, trap and source 48, 135 Andrew Formation, Palaeocene Andrew Field 133-6 Cyrus Field 136-7 Balmoral Field 395, 400, 402, 406, 407, 409 Andrew Shale, Palaeocene Andrew Field 135 Angus Field 44, 979 Angus Sandstone, Upper Jurassic 44 Apleyhead Field 979 Arbroath Field 7, 8-9, 10, 979 data summary 615, 949 history 611-12 location 611 reserves and production 612-13, 615 reservoir 612-14 source 614 stratigraphy 612 structure 48, 612 trap 612 Ardmore Field see Argyll Field Argyll Field 25, 32, 979 Arkwright Field 979 data summary 616, 949 history 611-12 location 611 reserves and production 612-13, 615 reservoir 48, 612-14 source 614 stratigraphy 612 structure 48, 612 trap 612 Armada Field 139-51,979 see also Drake Field; Fleming Field; Hawkins Field Atlantic Margin Fields 119-30 Auk Field 32, 979 data summary 496, 950 history 485, 486, 487 hydrocarbons 492 reserves and later development 492-3, 495 reservoirs 491-2, 493-4
stratigraphy 486, 489-90 structure 486, 487-9 trap 490-1 Bacton Group, Triassic Esmond Field 34 Forbes Field 34 Gordon Field 34 Hewett Field 34 Little Dotty Field 34 Balcombe Field 979 Balder Formation, Eocene 49 Brimmond Field 560 Foinaven Field 12 Harding Field 283-5, 286 Nelson Field 619 West Brae Field 224-230 Balmoral Field 979 exploration and development history 395, 398 geophysics 401,403 hydrocarbons 406 location 395, 396 production and reserves 409, 411-2, 411 production facilities and transportation 413 reservoir characteristics 48, 406, 407, 409 stratigraphy and regional setting 48, 397, 400-1,402 trap and source 406 Balmoral Sandstone, Palaeocene MacCulloch Field 453, 455, 458-61 Banff Field 980 data summary 507, 951 history 497, 499, 501 hydrocarbons 505-6 location 497, 498-500 reserves and production 506-7 reservoir 46, 48, 502-3, 505-6 seismic 497, 499 source 505 stratigraphy 501,503 structure 45, 48, 499, 501,502 trap 501-2, 504 Banks Group, Lower Jurassic 37, 38 Strathspey Field 355, 358, 358, 360, 360-3, 365-7 see also Nansen Formation; Statfjord Formation Barque Field 30, 684, 692, 980 data summary 670, 951 geophysics 664, 666, 667 history 663 hydrocarbons 669-70 location 663, 664 reserves 670 reservoir 668, 669 source 669 stratigraphy 663, 665-6 trap 664, 666-7 Barren Red Measures, Carboniferous 27 Schooner Field 811 21
Base Cretaceous Unconformity 148, 154-7, 157, 159, 164, 172-3, 172, 707, 715, 719, 743 Baxter's Copse Field 980 Beatrice Field 21, 38, 39, 41,980 Beaufort Field 980 data summary 711,951 development 707-9 history 705-6, 707 location 705, 706-7 reserves and production 710, 711-12 reservoir 30, 709-11, 709 source 711, stratigraphy 706-7, 708 trap 706, 707-9 Beauly Field 413 Beckering Field 27 Beckingham Field 27, 905, 980 Beinn Field 980 data summary 952 geophysics 207, 208 history 199, 201, 202 location 177, 199, 200 reservoir 43 Belvoir Field 980 Beryl Embayment Group, Middle Jurassic Statfjord Field 157, 157, 160-3 Beryl Field 7, 11-12, 11, 980 data summary 165, 952 hydrocarbons 164 history 154 location 153-4 regional structure and tectonic evolution 155 7, 163 reserves 164, 166 reservoirs 37, 40, 157, 158-63 seismic surveys 154, 155 source 163-4 stratigraphy 157 trap 157 Bessemer Field 30, 981 data summary 711,952 development 707-9 history 705--6, 707 location 705, 706-7 reserves and production 710, 711-12 reservoir 709-11 source 711, stratigraphy 706-7, 708 trap 706, 707-9 Big Dotty Field 986 conclusions 739 data summary 738, 963 history and discovery method 732-3 hydrocarbons 739 hydrocarbon source 737, 739 location 731-2 reserves and production 739 reservoir 736-7 stratigraphy 734-5 structure 733-4 trap 735-6
995
996 Birch Oil Field 980 data summary 180, 952 development method 169, 171 history 167-8, 169-170 location 167, 168 maturation 168, 177-8 reserves and production 168, 173, 176 7, 178-9 reservoir 43, 173, 174 pore types and diagenesis 174-7 source 168, 170, 172, 177 stratigraphy 168, 171-2, 173 structure 168, 169-71, 172 trap 169, 172-4 Bittern Field 48 Bladon Field 48, 48 Blair Field 48, 48, 398 Blake Field 12, 15, 45 Blenheim Field 48, 48, 980 Bletchingley Field 980 data summary 940-1,953 location 929 history 929 reservoir 41,937 8 stratigraphy 931 Bothamsall Field 27, 980 Boulton Field 29, 980 data summary 680, 953 gas-in-place and reserves 680 geophysics 676, 6 7 ~ 8 history 671,673 location 671,672 reservoir 676, 679 structural development and stratigraphy 671 6 trap 676 Brae Field see Central Brae Field; East Brae Field, North Brae Field; South Brae Field; West Brae Field Brae Formation, Upper Jurassic 43 Beinn Field 43, 202, 207, 208 Birch Field 43, 167, 170, 171-2 Central Brae Field 43, 184-7 East Brae Field 43, 192, 193-6 Ehn Field 43 Kingfisher Field 305-13 Larch Field 43 North Brae Field 43, 201-6, 208 Pine Field 43 South Brae Field 43, 212-20 T-Block Fields 43, 369, 371, 374, 375 Brent Field 7, 10-11, 11, 26, 39-40, 981 data summary 249, 954-5 field development 238, 246-9 history 233-6 hydrocarbons 245 location 233, 234-6 reserves and production 245 6 reservoir 239-45 seismic data 236-7 source 245 stratigraphy 238 9 structure 234-6, 237-8 trap 235-6, 239 Brent Group, Middle Jurassic 19, 24 Alwyn North Field 37, 40 Alwyn South Field 40 Brent Field 40, 233-45 Columba Field 40 Deveron Field 40, 253, 254 Don Field 40, 259-261
INDEX Dunbar Field 40, 271-5 Dunlin Field 40 Egret Field 40 Eider Field 40 Ellon Field 40, 265-7, 270-5 Grant Field 40, 265-7, 270-5 Heather Field 40, 292-300 Hudson Field 40 Hutton Field 40 Lyell Field 40 Murchison Field 40 Ness Field 40 Ninian Field 40 North Cormorant Field 40, 315, 318, 321, 322, 323 Osprey Field 40 South Cormorant Field 40 Staffa Field 40, 328, 330-2 Statfjord Field 40, 335, 340, 344, 345, 349 Strathspey Field 40, 355, 358, 358, 360, 362, 364, 365-7 Tern Field 40 Thistle Field 40, 385, 386 9, 390 see also Broom Formation; Etive Formation; Ness Formation; Rannock Formation; Tarbert Formation Bressay Field 48, 49 Bridport Sandstone, Jurassic 6, 38 Brigg Field 981 Brimmond Field 981 data summary 561,955 discovery 558 history 557 8 reserves and production 558, 559 reservoir 48, 558 source 558 stratigraphy 558 structure 48, 558 trap 558 Britannia Field 12, 981 data summary 428, 955 exploration history 415-17 geophysics 418-19, 420-2 location 415 regional structure and tectonic history 415, 417 18 reserves and production 427-8 reservoir 45, 418-19, 421-7 source 415, 427 trap 415, 419-21,422-4 Britannia Sandstone Formation, Lower Cretaceous Britannia Field 421-7 Tiffany Field 371 Brockham Field 41,981 Broom Formation, Middle Jurassic 38 Brora Coal Formation, Middle Jurassic Beatrice Field 41 Broughton Field 981 Brown Field 981 data summary 711,955 development 707-9 history 705-6, 707 location 705, 706-7 reserves and production 710, 711-12 reservoir 30, 709-11 source 711, stratigraphy 706-7, 708 trap 706, 707-9
Bruce Field 39, 40, 46, 981 Buchan Field 25, 981 Buckland Field 40 Bunter Group Fields 31 Bunter Sandston Formation, Triassic Hewett Field 731,736, 738 Bure Field 981 Buzzard Field 44 Cador Field 981 Caister Field 29, 789, 981 Calder Field 981 Caledonian Orogeny 17, 20, 25, 33 Plate Cycle 17 Calder Sandstone Member (Wilmslow Sandstone equivalent) 65 Callovian unconformity 154, 155, 157, 157, 159 Calow Field 981 Camelot Field 981 data summary 689, 955 gas initially in place 687 geophysics depth conversion 682-4, 686 seismic interpretation 682, 684-5 history (post-1989) 681-682, 683-4 location 681,682 production 687-8 reservoir 30, 687, 688 trap 684, 686-7 Captain Field 12, 981-2 data summary 440-1,956 development 434, 438-440 formation water 438 geophysics 437-8 history 432, 433-5 location 431-3, 434 reservoir 45, 438 source and migration 438 stratigraphy 431, 433, 435-7 trap and top seal 432, 438 Captain Sandstone Member, Lower Cretaceous Captain Field 431-40 Caunton Field 982 Central Brae Field 43, 167, 980 data summary 95, 189 geophysics 183 history 183 hydrocarbons 188 reserves 188 reservoir 184-5, 187 source 188 stratigraphy 183 trap 183 4 Central Graben Fields 36, 41-2, 483-659 Central Graben triple junction 17, 20, 41-2, 141 Chalk Group, Cretaceous 38, 45, 46 Brent Field 40 Bruce Field 46 Captain Field 433, 437-8 Ekofisk Field, Norway 10 Pierce Field 647, 657 see also Ekofisk Formation Chanter Field 43, 982 Clair Field 15, 17, 25, 121,982 Claymore Field 12, 12, 30, 44, 982 Cleeton Field 30, 982 Cleveland Basin 22, 32, 34
INDEX climate change 24, 29 Clipper Field 663, 982 data summary 697, 956 geophysics 694, 693 history 692-3 hydrocarbons 695, 697 location 691 2 reserves 697 reservoir 30, 695, 696 source 695 stratigraphy 693-4, 692 structural history 694 5 trap 694 Clyde Field 42, 982 Coal Measures Group, Carboniferous 27 Barque Field 669 Clipper Field 695 Corvette Field 704 Schooner Field 811-17 V-Fields 869 Waveney Field 888, 890 Cold Hanworth Field 27, 982 Collyhurst Sandstone Formation, Permian Douglas Field 63-5, 70 Hamilton Field 78-9, 79, 84 Hamilton North Field 78-9, 79, 84 Lennox Field 87, 89-90, 9 South Morecambe Field 110, 110 Columba Field 40, 982 compactional drape 38, 39, 47 compressional reactivation see inversion Conybeare Group, Carboniferous Guinevere Field 728 Trent Field 835-6,838,841,846, 847, 849 Cook Formation, Lower Jurassic Gullfaks Field, Norway 38 Oseberg Field, Norway 38 Snorre Field, Norway 38 Statfjord Field, Norway 38 Corallian, Upper Jurassic Bletchingley Field 41,931, 937-8 Palmer's Wood Field 41,931, 938 Cormorant Field 11, 26 see also North Cormorant Field; South Cormorant Field Cormorant Formation, Triassic Beryl Field 37, 157-8, 157 Crawford Field 37 Linnhe Field 37 Nevis Field 37 North Cormorant Field 35 Pelican Field 35 Penguin Field 35 South Cormorant Field 35 Tern Field 35 Cornbrash, Middle Jurassic Kimmeridge Bay Field 41,945-6 Corringham Field 27, 982 Corvette Field 982 data summary 704, 956 discovery 701 history 699-701 location 699, 699 reserves and production 704 reservoir 30, 702-3, 704 source 704 stratigraphy 701,704 structure 701 trap 699, 704 Cousland Field 29 Crawford Field 37, 48, 49, 982
Cromarty Field 45 Cromer Knoll Formation, Lower Cretaceous 38, 46 Brent Field 40 Erskine Field 527, 529 see also Captain Sandstone Member; Sola/Rodby Shale; Valhall Formation Cropwell Butler Field 982 Crosby Warren Field 27, 982 Cullin Field 122 Curlew Field 982 data summary 522, 956-7 history 509-10, 511-13 location 509 reservoir 46, 48 sedimentology 516-19, 521 stratigraphy 512, 513, 514, 516 17 structure 48, 510, 513, 514-15 trap 511, 513, 516, 518-19 volumes and production 519-20, 521 Cyrus Field 982 data summary 957 discovery 137 history 136-7 reserves and production 134, 137 reservoir 137 structure, stratigraphy, trap and source 48, 137 Dalton Field 35 Dauntless Field 43, 982 Davy Field 983 data summary 711,957 development 707-9 history 705-6, 707 location 705, 706 7 reserves and production 710, 711 12 reservoir 30, 48, 709-11 source 711, stratigraphy 706-7, 708 trap 706, 707-9 Dawn Field 986 data summary 738, 964 history and discovery method 732-3 hydrocarbons 739 hydrocarbon source 737, 739 location 731-2 reserves and production 739 reservoir 736-7 stratigraphy 734 5 structure 733-4 trap 735-6 Deborah Field 983 data summary 738, 964 history and discovery method 732-3 hydrocarbons 739 hydrocarbon source 737, 739 location 731-2 reserves and production 739 reservoir 736-7 stratigraphy 734-5 structure 733-4 trap 735-6 Delilah Field 986 data summary 738, 964 history and discovery method 732-3 hydrocarbons 739 hydrocarbon source 737, 739 location 731-2 reserves and production 739
997 reservoir 736-7 stratigraphy 734-5 structure 733-4 trap 735-6 Della Field 986 data summary 738, 964 history and discovery method 732-3 hydrocarbons 739 hydrocarbon source 737, 739 location 731-2 reserves and production 739 reservoir 736-7 stratigraphy 734-5 structure 733-4 trap 735-6 depth conversion 7,65, 98-9, 110, 144-5, 148-9, 666, 681-4, 686, 694, 708-9, 715, 743, 754-5, 801,803, 899 Deveron Field 983 data summary 255, 957 discovery 252 fluids 254 geophysics 252, 253-4 history 251-2 location 251,525 reserves 254 5 reservoir 40, 253, 254 stratigraphy 252, 253 structure 252-3 Devonian reservoir deposits Stifling Field 400-1,402, 409, 410 Dierdre Field 736 differential flow 42 doming 19, 24, 38, 47 see also North Sea Dome Don Field 983 data summary 262-3, 957 discovery 260 fluids 261-2 geophysics 260 history 258-60 lesson learned 262 location 257, 258 reserves 262 reservoir 40, 260-1 source 261 stratigraphy 260, 261 trap 260 Donan Field 48, 48 Dotty Fields see Big Dotty Field; Little Dotty Field Douglas Oil Field 983 data summary 74, 958 history 63 hydrocarbon volumes and development plans 72-3, 74 reservoir 35, 66-70 source 70-1, 73 stratigraphy 63-5 structure 64-6, 65 trap 65-6 Drake Field 983 data summary 150, 950 development drilling 148 history 139-41 reserves and production 144, 151 reservoir 148, 149 source and fluid composition 151 stratigraphy and regional setting 141-2 structural geology and seismic considerations 145-8
998 Draupne Formation, Upper Jurassic Statfjord Field 349 drive mechanisms depletion 770, 891 edge 787 electrical submersible pumps 73, 74, 589 fluid expansion 941 gas injection 92, 95, 154, 165, 179, 220, 249, 352, 583, 584, 614-15, 647 gas lift 136, 169, 248, 379, 411-12, 463, 589, 603, 644, 739, 932 gas recycling 196-7, 201,208, 444 jet pumping 926 natural depletion 150, 165, 249, 255, 263, 280, 314, 365, 368, 554, 601, 697, 824 natural water drive 85, 129, 165, 230, 255, 333,379, 450, 463-4, 486, 496, 510, 522, 534-5, 549, 553-4, 601, 609, 614-16, 644-5, 687, 689, 833 pressure depletion 428, 670, 704, 730, 775-6, 910, 919 solution gas 165, 333, 601,941,946 volumetric depletion 105, 117, 832, 869 volumetric gas expansion 711,746-7, 941 water injection 74, 128, 165, 169, 176, 178-9, 183, 188-9, 221,249, 258, 263, 280, 290, 303, 351-2, 367-9, 379, 390, 392, 411,441,450, 480-1, 486, 495-6, 507, 539, 546, 549, 553-4, 563-4, 565, 569, 584, 588, 600, 644 Water-Alternating-Gas injection 166, 188, 220, 349, 351-2 Dunbar Field 983 data summary 280 history and discovery method 265-7, 268-9 regional structure and stratigraphy 265-6, 267-8 reserves and production 277, 279 reservoir 40, 266, 269, 271, 272-76, 277-8 source 266, 269, 276 7, 279 trap 266-7, 268-70, 272 Duncan Field 983 Dunlin Field 40, 98 Dunlin Group, Lower Jurassic 38 Beryl Field 157, 160 Dunbar Field 268 North Cormorant Field Statfjord Field 341,343, 347 Strathspey Field 360, 362, 365 Thistle Field see also Cook Formation Durward Field 43, 983 Eakring Dukeswood Field 27, 983 Eakring Field 5 22, 27 East Brae Field 980 data summary 197, 953 geophysics 194, 195 history 191, 193 hydrocarbons 196 location 191, 192 reserves and production 196 reservoir 43, 195-6 source 196
INDEX stratigraphy 192, 193, 195 structure 193, 194 East Foinaven Field 122 East Glentworth Field 27 East Irish Sea Fields 35, 61-118 East Midland Basin Fields 30, 903-26 East Shetland Basin 38 East Shetland Platform 40 economic indicators, over-reliance on 13 Egmanton Field 27, 983 Egret Field 35, 40, 983 Eider Field 40, 983 Ekofisk Field, Norway 10 Ekofisk Formation, Upper Cretaceous 46 Banff Field 497, 500, 501-4, 505-6 Fife Field 538, 540 Pierce Field 647, 657 Elgin Field 35, 42, 983 Ellon Field 40, 983 data summary 280 history and discovery method 265-7, 268-9 regional structure and stratigraphy 265-6, 267-8 reserves and production 277, 279 reservoir 266, 269, 271, 272-6, 277-8 source 266, 269, 276-7, 279 trap 266-7, 268-70, 272 Elm Field 43, 167 Embla Field 25 Emerald Field 17, 25, 293, 297, 983 Emerald Sand, Mid Jurassic Heather Field 293, 297-8, 299, 300 Erskine Field 983 data summary 534, 958 history 523 4, 525 location 523, 524 reserves and production 534, 535 reservoirs 526, 528, 529-33 source 533 stratigraphy 525-7, 529 structure 524-5, 526 trap 525-6, 529 Esmond Field 34, 984 Etive Formation, Middle Jurassic 38-40 Ettrick Field 32, 984 eustacy 24-5, 29, 37, 42, 45 6 Everest Field 48, 48, 984 Excalibur Field 727, 771, 775 extended-reach drilling 6 extensional basin development Late Jurassic-earliest Cretaceous 19 Permian-Triassic 19 Faeroe-Shetland Basin 24, 48-9 Farley's Wood Field 22, 27, 984 Farsund Formation, Netherlands Flora Field 553 fault scarp degradation 40, 42, 44 Fergus Field 984 data summary 546, 959 history 538-9 location 537, 538 reserves and production 544-7 reservoir 542-4 seismic 539, 540 source 544 stratigraphy 538, 539 structure 540, 541 trap 540, 542
Fife Field 984 data summary 546, 959 history 538-9 location 537, 538 reserves and production 544-7 reservoir 44, 46, 542-4 seismic 539, 540 source 544 stratigraphy 538, 539 structure 540, 541 trap 540, 542 Fife Sandstone, Upper Jurassic 44 Fergus Field 538, 539, 544 Fife Field 538, 539-44, 545 Fiskerton Airport Field 27 Fleming Field 984 data summary 150, 950 development drilling 145 history 139-41 reserves and production 151 reservoir 48, 144-5 source and fluid composition 151 stratigraphy and regional setting 140, 141-2 structural geology and seismic considerations 48, 142-4 Flora Field 30, 984 data summary 554, 959 history 549-50 location 549, 550 regional setting and structural development 550-1 reserves and production 550, 553-4 reservoir 46, 551-3, 554 source 553 stratigraphy 551,552 trap 550, 551,552-3 Flora Sandstone, Upper Carboniferous Flora Field 549, 551-3, 554 Flounder Formation Marls, Late Cretaceous Balmoral Field 406 Foinaven Field 7, 14, 15, 984 data summary 130, 959 history 121-2 location 121 reserves and production 127, 128-9 reservoir 49, 125, 128 source 128 stratigraphy 123, 124 structure 122-4, 125 trap 124-8 see also East Foinaven footwall closures 26, 36, 38-9, 41, 65 collapses 40 uplift 40, 42 Forbes Field 34, 984 Formby Fault 5 Formby Field 5 Forties Field 7, 9-10, 10, 984 data summary 561,959 discovery 558 history 557-8 reserves and production 558, 559 reservoir 48, 558 source 558 stratigraphy 558 structure 48-9, 558 trap 558
INDEX Forties Sandstone Member, Palaeocene 46, 47-8 Andrew Field 48 Arbroath Field 48, 611-12, 614 Arkwright Field 48, 611-12, 614 Balmoral Field 48 Banff Field 48 Bladon Field 48 Blair Field 48 Blenheim Field 48 Brimmond Field 48 Curlew Field 48 Cyrus Field 48 Donan Field 48 Everest Field 48 Fleming Field 48 Forties Field 48, 561 Gannet Field 48 Glamis Field 48 Joanne Field 48 Lomond Field 48 MacCulloch Field 48 Machar Field 48 Maureen Field 48 Moira Field 48 Monan Field 48 Montrose Field 48, 611-12, 614 Mungo Field 48 Nelson Field 13, 47, 48, 617, 619, 621-39 Orion Field 48 Pierce Field 48, 647, 652-5, 657 Sedgewick Field 48 Franklin Field 35, 42, 984 Frigg Field 49, 984 Frigg Sandstone Member, Eocene Alba Field 49 Frigg Field 49 Gryphon Field 49 Harding Field 49, 284-5, 286 Nuggets Fields 49 Frome Clay, Middle Jurassic Wytch Farm Field 41 Fulmar Field 984-5 data summary 584, 960 diagenesis 580 history 563-4, 565-7, 569 lithology and depositional environment 572, 573, 581 location 563, 564 reserves and production 565, 583, 584 reservoir 42, 578-9, 582 porosity and permeability 571, 578, 579-80 zonation and flow units 572, 580-582, 584 sequence stratigraphy 571-2, 574, 576, 577-8 stratigraphy 572, 573-7, 581 structure 566, 568, 569, 570-1 trap mechanisms and hydrocarbons 566, 569, 573 Fulmar Formation, Upper Jurassic Armada development 139, 141, 145, 148-51
Clyde Field 42 Curlew Field 510-14, 516-19, 521 Elgin Field 42 Franklin Field 42 Fulmar Field 42, 563-85 Shearwater Field 42
Gainsborough Field 27, 905, 985 Galahad Field 775 Galleon Field 66, 692 Gannet Fields 35, 43, 48-9, 48, 984 gas monopoly 8 gas storage 905-7, 910, 932 Gawain Field 699, 986 data summary 722, 960 development and production 722 history 713, 715, 715 location 713, 714 reservoir 30, 720, 721-2 source 722 stratigraphy 719-20, 718 structure 715-19 trap 715, 719, 720 Glamis Field 985 exploration and development history 395, 398-400, 401 geophysics 401,404, 406 hydrocarbons 406 location 395, 396 production and reserves 412, 412 facilities and transportation 413 reservoir characteristics 48, 408, 409, 410 stratigraphy and regional setting 397, 400-1,402 trap and source 48, 406 Glamis Sandstone, Upper Jurassic Glamis Field 398, 399, 400-1,402, 408, 409 Glentworth Field 27, 985 Glentworth East Field 985 Godley Bridge Field 985 Gogiarth fault 64, 65, 67, 70, 80, 80 Goldeneye Field 15, 45 Goodworth Field 960, 985 data summary 940-1 location 929, 930 reservoir 41,937 Gordon Field 34, 985 Grant Field 40, 985 data summary 280, 960 history and discovery method 265-7, 268-9 regional structure and stratigraphy 265-6, 267-8 reserves and production 277, 279 reservoir 266, 269, 271, 272-6, 277-8 source 266, 269, 276-7, 279 trap 266-7, 268-70, 272 gravity flows 46 Great Oolite Formation, Middle Jurassic Brockham Field 41 Goodworth Field 41,929-31, 97 Herriard Field 41,929-32 Horndean Field 41,929-31,938-9 Humbley Grove Field 41,929-32, 934-5 Singleton Field 41,929-31,936-7 Stockbridge Field 41,929-31,937 Storrington Field 41,929-31,935-6 Groningen Field, Netherlands 5-6 Gryphon Field 49, 986 Guillemot Field 49, 985 Guinevere Field 986 data summary 729, 961 history 723-4 hydrocarbons 728 location 723
999 reserves and production 728-9 reservoir 30 characterization 727-8 description and geological method 727 zonation 727 source 728 stratigraphy 724-5 structural history 725-6 trap 726 Gullfaks Field, Norway 38 Hamilton fault 64, 80, 80, 84, 90 Hamilton Field 986 data summary 85, 961 diagenetic history 83 history 77, 78 hydrocarbon volumes and development plans 78, 82, 83-5 reservoir 35, 81-3 reservoir fluid parameters 83 source :rock. and hydrocarbon migration 83, 84 stratigraphy 77, 78-9 structure 79-80 trap 79, 80-1 Hamilton North Field 986 data summary 85, 961 diagenetic history 83 history 77, 78 hydrocarbon volumes and development plans 78, 82, 83-5 reservoir 35, 81-3 reservoir fluid parameters 83 source rock and hydrocarbon migration 83, 84 stratigraphy 77, 78-9 structure 79-80 trap 79, 80-1 Hamish Field 986 data summary 450, 961 history 443-4 location 443 reserves and production 444, 447, 448-50 reservoir depositional environments and facies 445 -7 flow unit zonation 447, 448 quality, geological controls on 447 stratigraphy 445, 446 structure 443, 444-5 Haisborough Group, Triassic Hewett Field 735, 735 seal 34 Halibut Horst 45 halokinesis see salt movement Hamish Field 43 hangingwall anticlines 27 hangingwall subsidence 40, 42 hangingwall traps 43-4 Hannay Field 45 Harding Field 986 data summary 290, 961 history 283-4 hydrocarbons and their source 285-7 location 283 reserves and production 286, 287-8, 289 reservoir 49, 285, 289 stratigraphy 284-5, 286
1000 Harding Field (continued) structure 284, 285, 287 trap 285 Hardstoft Field 5 986 Hatfield Moors Field 27, 986 data summary 910, 962 gas production 905-6 gas storage 906-7 geological history 905, 907-8 history 905 location 905 reserves 909 reservoir 908-9 seismic 908 source rock and migration 909 trap 906-7, 908 Hatfield West Field 27, 986 data summary 910, 962 gas production 905-6 gas storage 906-7 geological history 905, 907-8 history 905 location 905 reserves 909 reservoir 908-9 seismic 908 source rock and migration 909 trap 906-7, 908 Hauptdolomite Formation, Permian 32 Hawkins Field 986 data summary 150, 950 development drilling 151 history 139-41 reserves and production 151 reservoir 149, 151 source and fluid composition 151 stratigraphy and regional setting 140, 141-2 structural geology and seismic considerations 148-9 Heather Field 986 data summary 303, 962 history 292, 293 location 291, 292 reserves and production, impact of geoscience projects on 300-2, 303 reservoir 40 quality 299-300 stratigraphy 296-7, 298-9 source 300, 301 structure and trap 292, 293-298 Heather Formation, Upper Jurassic 41, 43 Beryl Field 163-4 Birch Field 177 Captain Field 432-4, 435 Don Field 260, 261 Drake Field 145-8 Dunbar Field 268 Ellon Field 270 Erskine Field 523-9, 533-5 Grant Field 270 Hawkins Field 148 Heather Field 295, 299, 299 Kingfisher Field 305-10, 310-11 Staffa Field 330 Thistle Field 388-9, 389-90 Toni Field 371 Helmswell Field 986 Heron Field 35, 40, 986
INDEX Herriard Field 986 data summary 940-1,962 location 929, 930 production history 929, 931 reservoir 41,937 Hewett Field 7, 986 data summary 738, 963-4 history and discovery method 732-3 hydrocarbons 739 hydrocarbon source 737, 739 location 731-2 reserves and production 739 reservoir 31, 736-7 stratigraphy 734-5 structure 733-4 trap 735-6 Hewett Sandstone, Triassic Hewett Field 731-2, 734, 735 Highlander Field 44, 986 history of exploration 5-16 Holywell Shale Formation, Carboniferous Douglas Field 63, 64, 70-1 Hamilton Field 78, 79, 83 Hamilton North Field 78, 79, 83 Lennox Field 87, 89, 92 South Morecambe Field 113 Horda Platform 40 Horndean Field 986 data summary 940-1,964 location 929, 930 production history 929, 931,932 reservoir 41,937 H P - H T conditions 36, 41, 42 Hudson Field 11, 40 Hugin Formation, Middle Jurassic 38, 40-1
Birch Field 177 Drake Field 146 Mary Field 588-9, 592, 594, 598 North Brae 202 Toni Field 371 Huldra Field, Norway 26 Humber Group, Upper Jurassic 42 Beryl Field 157, 157, 163 Humbley Grove Field 987 data summary 940-1,965 location 929, 931 2 production history 929, 931 reservoir 8, 41,931-2, 932, 934-5 Hutton Field 26, 40, 987 Hutton-Ninian trend 37 Hutton North West Field 987 Hyde Field 30, 987 Iapetus Ocean 17, 25, Iceland hot-spot 21 Indefatigable Field 7-8, 7, 684, 701, 825-6, 987 data summary 747, 965 history 741-2 location 741, 742 reserves and production 746-7 reservoir 30, 745-6 source 746 stratigraphy 742-3 trap 743-5 Inner Moray Firth 21 Innes Field 32, 987 intraplate deformation 19-24
Inverclyde Group (formerly known as the Calciferous Sandstone Series) Cousland Field 29 Midlothian (D'Arcy) Field 29 Milton of Balgonie Field 29 inversion 19 Cenozoic 28, 65 Late Carboniferous-Early Permian 22 see also Westray Inversion Ivanhoe Field 12, 987 data summary 450, 965 history 443-4 location 443 reserves and production 444, 447, 448-50 reservoir 43 depositional environments and facies 445-7 flow unit zonation 447, 448 quality, geological controls on 447 stratigraphy 445, 446 structure 443, 444-5 Joanne Field 46, 48, 48 Johnston Field 29, 987 data summary 759, 965 development plan 757, 759 geology 750-1 geophysics 752, 753-755 history 749-50 hydrocarbon character 757 location 749 reserves 757 reservoir 755-7, 758 source 751 stratigraphy 750-1 structure 751-3 Judy Field 35, 987 Katrine Field 153 Keddington Field 915 Kelham Field 987 Kimmeridge Bay Field 28, 987 development and production 947-8 history 943-5 reservoir 41,945-6 source 946-7 structure, trap and seal 945, 946 Kimmeridge Clay Formation, Jurassic 5-6, 21, 24-6, 43, 46 Andrew Field 135 Arbroath Field 614 Arkwright Field 614 Auk Field 492 Balmoral Field 406 Banff Field 505 Beryl Field 164 Birch Field 171-3, 173, 177-8 Brent Field 245 Brimmond Field 559 Britannia Field 427 Captain Field 438 Central Brae Field 186, 188 Curlew Field 521 Cyrus Field 135 Dauntless Field 43 Don Field 260 Dunbar Field 268, 276-7, 279 Durward Field 43 East Brae Field 192, 194, 195-6
INDEX Ellon Field 270, 276-7, 279 Fergus Field 544 Fife Field 544 Flora Field 553 Forties Field 558 Fulmar Field 563-84 Glamis Field 400, 402, 406, 409 Grant Field 270, 276-7, 279 Harding Field 285, 287 Heather Field 295, 299-300, 299 Kingfisher Field 305, 308, 309-11, 313 Kittiwake Field 43 MacCulloch Field 461 Mary Field 598-9 Maureen Field 598-9 Moira Field 608 Montrose Field 614 Morag Field 598-9 Nelson Field 641 North Brae Field 200, 202, 208 North Cormorant Field 321, 322 Pierce Field 657 Scott Field 478 South Brae Field 212-15, 213-14, 220 Staffa Field 332 Stirling Field 406 Strathspey Field 365 T-Block Fields 371 Thistle Field 388-9, 390 Kimmeridge Sandstone Member, Upper Jurassic 43-4 Buzzard Field 44 Claymore Field 44 Kingfisher Field 44 Miller Field 44 Saltire Field 44 Tartan Field 44 Kingfisher Field 987 data summary 314, 966 history 305-6, 307 hydrocarbons 313 location 305 reserves 313 reservoir 44, 309-10, 311-12 Brae unit 1,311-12, 313 Brae unit 2, 306, 310, 311, 313 Heather 309-10 stratigraphy 307-8, 309-10 structure 306-7, 308-9 trap 306-7, 309, 311 Kinoulton Field 987 Kirby Misperton Field 27, 32 Kirkham Abbey Formation (formerly known as the Middle Magnesian Limestone and equivalent to the Haumtdolomite), Permian Kirby Misperton Field 32 Malton Field 32 Marishes Field 32 Kirklington Field 987 Kittiwake Field 43 Kopervik Formation, Cretaceous Andrew Field 45, 133, 135 Blake Field 45 Brittania Field 45 Cromarty Field 45 Goldeneye Field 45 Hannay Field 45 Kopervik trend 14-15
Kupferscheifer (Marl Slate equivalent), Permian 32 Hewett Field 734 Johnston Field 749-50 Leman Field 763 Sean North, South and East Fields 830 KX Field 988 Kyle Field 46 Lancelot Field 727 Larch Field 43, 171, 177-8 Laurussia 17, 25 Leman Field 7-8, 7, 684, 988 data summary 770, 967 history 761, 763-4 hydrocarbons 769 location 761, 762-3 reserves 769-70 reservoir 30, 767-8, 769 source 768-9 stratigraphy 763, 764, 767 structure 761,764, 765-6 trap 767 Leman Sandstone Formation, Permian 23, 34-5 Amethyst Field 30 Baird Field 701,741-4 Barque Field 30, 663-9 Beaufort Field 30, 705-11 Bessemer Field 30, 705-11 Big Dotty 731,733, 736-9 Brown Field 30, 705-11 Bure Field 31 Caister Field 30 Camelot Field 30, 681-7 Cleeton Field 30 Clipper Field 30, 691-5 Corvette Field 30, 699, 701-4 Davy Field 30, 705-11 Dawn Field 731,733, 736-9 Deborah Field 731,733, 736-9 Delilah Field 731,733, 736-9 Della Field 731,733, 736-9 Gawain Field 30, 713-22 Guineveire Field 30, 723-7 Hyde Field 31 Indefatigable Field 31,741-3 Johnston Field 749-59 Leman Field 30, 761-7 Little Dotty Field 731,733, 736-9 Malory Field 31,771-5 Markham Field 31 Mercury Field 31,778-85 Neptune Field 31,778-85 Pickerill Field 31,799, 801-7 Ravenspurn North and South Fields 31 Rough Field 30-1 Sean North and South Fields 31,825-30 Thames Field 31 V-Fields 31,861-9 Victor Field 31 Viking Field 31,872-8 Waveney Field 31,881-90 Windermere Field 31,893-900 Yare Field 31 Lennox Field 5 988 data summary 95, 967 hydrocarbon volumes and development plans 89, 92-5 history 87, 88-9
1O01 reservoir 35, 89, 90-2 source rock and hydrocarbon migration 92, 93 stratigraphy 87, 89 structure 87-8, 90 trap 88, 90 Lias Formation, Lower Jurassic 5-6, 38 Kimmeridge Bay Field 946 see also Bridport Sandstone licensing, UK 6-8 Lidsey Field 936 Limestone Coal Group, Carboniferous 30 Linnhe Field 37, 40 Lista Formation, Palaeocene 46 Balmoral Field 400, 402 Banff Field 501,503 Fleming Field 142 MacCulloch Field 459 Maureen Field 594 Moira Field 604, 606 see also Balmoral Sandstone Little Dotty Field 986 data summary 738, 963 history and discovery method 732-3 hydrocarbon source 737, 739 hydrocarbons 739 location 731-2 reserves and production 739 reservoir 34, 736-7 stratigraphy 734-5 structure 733-4 trap 735-6 Lockton Field 7 Lomer Field 988 Lomond Field 10, 48, 48 London-Brabant Massif 23, 34 Long Clawson Field 27, 988 Lothian Oil Shales, Carboniferous 29 Loyal Field 122 Lunde Formation, Triassic Alwyn Field 37 Dunbar Field 276, 276 Lyell Field 26, 40 MacCulloch Field 12, 988 data summary 464, 967 history 453, 456-7 hydrocarbons 462-3 location 453, 454-7 reserves and production 463-4 reservoir 48, 458, 460-1,462-4 seismic character 461-2, 465-6 source and migration 461 stratigraphy 455, 458, 460 structure 453, 456, 458 trap 48, 460 Machar Field 46, 48, 48, 988 Magnus Field 44, 988 Malory Field 988 data summary 775-6, 967 history 771-2 hydrocarbons 775 location 771, 772 reserves and production 775 reservoir 30, 774 source 775 stratigraphy 772-3, structure 772 trap 773-4 Malton Field 27, 32
1002 Mandal Formation, Netherlands Flora Field 553 mantle plume 19 see also doming; Iceland hot-spot; North Sea Dome Mariner Field 48 Marishes Field 32 Markham Field 30, 988 Marnock Field 35, 988 Mary Field 988 data summary 601,967-8 history 587-9, 591 location 587 reserves and production 599-600 reservoir 598 source 598-9 stratigraphy 588, 592, 594 structure 589-90, 592, 593 trap 593, 594 Maureen Field 12, 988 data summary 601,967-8 history 587-9, 591, 593 location 587 reserves and production 599-600 reservoir 48, 594-7 source 598-9 stratigraphy 588, 592, 594 structure 589-91,592 trap 594 Maureen Formation, Palaeocene 46 Armada development 139, 141-3, 145 Banff Field 501,503 Maureen Field 587-92, 594-7 Moira Field 603-7 Mercia Mudstone Group 28 Douglas Field 63-6, 69, 70 Hamilton Field 78-9, 81, 84 Hamilton North Field 78-9, 81, 84 Lennox Field 87, 89, 91, 93 North Morecambe Field 109-10, 1 1 0 , 112 South Morecambe Field 97, 97, 100, see also Rossall Halite Mercury Field 988 data summary 786-7, 968 history 777-8 location 777, 777 reserves and production 785-6 reservoir 30, 780, 784-5 source 785 stratigraphy 778, 779-80, 783 structure local structure and trap 779, 780, 783 regional 778, 779 Mid North Sea High 23 Midlothian (D'Arcy) Field 29 Miller Field 44, 988-9 Millom Field 35, 989 Millstone Grit, Carboniferous 5, 25, 27 Trent Field 835-6, 838-46 Milton of Balgonie Field 29 missed fields 12-13, 15 Moira Field 989 data summary 609, 968 history 603-4, 607 location 603 reserves and production 608, 609 reservoir 48, 606-7, 608 source 608 stratigraphy 604, 605 structure 48, 604, 605 trap 606
INDEX Monan Field 48, 48, 989 Montrose Field 10, 989 data summary 614, 968 history 611-12 location 611 reserves and production 612-13, 615 reservoir 48, 612-4 source 614 stratigraphy 612 structure 48, 612 trap 612 Montrose Formation, Palaeocene Forties Field 558 see also Forties Sandstone Member Morag Field 12, 988 data summary 601,967-8 history 587-9, 591, 593 location 587 reserves and production 599-600 reservoir 597-8 source 598-9 stratigraphy 588, 592, 594 structure 589-92, 593 trap 594 Morag Member, Permian Morag Field 588-9, 591-4, 597-8 Moray Firth Fields 42, 393-482 Moray Group, Palaeocene see also Balder Formation Morecambe Field 7, 12-13, 15 see also North Morecambe Field; South Morecambe Field Mungo Field 48, 48, 989 Murchison Field 40, 989 Murdoch Field 29, 33, 989 data summary 798, 969 history 789, 791-2 gas-in-place and reserves 797 gas-water contacts 797 geophysics 793, 795, 796 location 789, 790 reservoir 791-2, 796-7 structural development and stratigraphy 790-3, 794 trap 791, 796 Murdoch Sandstone, Carboniferous Boulton Field 671-6 Murdoch Field 791-7
Namurian, Carboniferous Hatfield Moors Field 909 Hatfield West Field 909 Saltfleetby Field 914 West Firsby Field 925 see also Oaks Rock Sandstone Nansen Formation (now upper part of Banks Group), Lower Jurassic 37-8 Alwyn Field 37 Brent Field 37 Bruce Field 37 Statfjord Field 37 Nelson Field 7, 10, 13, 15, 989 data summary 645, 969 history 47, 617-8, 620 location 617 regional setting 618, 619, 623 reserves and production 620, 642, 644, 645
reservoir 48 Nelson Facies Model 633, 634-7, 638-9 quality, controls on 637, 639, 640 seismic reservoir characterisation and time lapse seismic 639-41,642-3 source rocks and migration 641-2, 644 stratigraphy 47 biostratigraphy and zonation of the Nelson reservoir 619, 623-4, 626 Lista Formation 624, 626, 629-30 Sele Formation of S1 Lower Forties Unit 625, 626-7, 629-30 Sele Formation of $2 Upper Forties Unit 624-5, 627-32, 634 trap 48, 618-9, 621-2 Neptune Field 989 data summary 786-7, 969 history 777-8 location 777, 777 reserves and production 786 reservoir 30, 780, 784-5 source 785 stratigraphy 778, 779-80 structure local structure and trap 779, 780, 781-2 regional 778 Ness Field 40, 153 Ness Formation, Middle Jurassic 38-40 Nettleham Field 27, 990 Nevis Field 37, 40, 153, 990 Ninian Field 26, 40, 329, 990 North Atlantic Ocean opening 17, 21, 49 North Brae Field 177, 980 data summary 208-9, 953 geophysics 208 history 167, 199, 201-2 location 199, 200 reserves 208 reservoir 43 geology 200-1, 204-8 source 208 stratigraphy 201, 202, 203-5 structural history 202, 204 trap 208 North Cormorant Field 982 data summary 325, 970 history 315-8 location 315, 316 reserves and production 322, 324, 325 reservoir 35, 40, 322, 323 source 322 stratigraphy 318, 321 structure 317, 318-20 trap 321 North Kelstern Field 914 North Morecambe Field 989 data summary 105, 969 development plan 102 gas composition 102 geophysics 98-9 history 97 production profile 104 reservoir 35 layering 101, 102 model 100, 101-2 properties depositional controls of 101, 102 diagenetic controls of 97, 101, 102
INDEX stratigraphy 98 structure and contacts 99, 101 test rates 104 well results 103-4 well targeting 102-3 North Sea Dome 41 North Valiant Field 993 data summary 870, 977 facilities 861-2, 869 geophysics 864-5, 867-8 history 861-3 location 861 reserves 869 reservoir 30, 867, 868-9 source 869 stratigraphy 863,864, 867, 867 structure 862, 863, 864, 865, 866 trap 862, 866, 868 Northern Permian Basin 8-9, 19, 23, 30 Nuggets Fields 49 Oaks Rock Sandstone, Carboniferous Hatfield Moors Field 905-9 Hatfield West Field 905-9 Oil Shale Group, Lower Carboniferous 5 Orcadian Basin 21, 25 Orion Field 48, 48 Ormskirk Sandstone Formation (Helsby Sandstone and Sherwood Sandstone equivalent), Triassic Douglas Oil Field 63-75 Hamilton Field 77-86 Hamilton North Field 77-86 Lennox Field 87-96 North Morecambe Field 97-105 South Morecambe Field 107-118 Orrin Formation, Lower Jurassic Beatrice Field 38 Oseberg Field, Norway 38 Osprey Field 40, 990 Otter Bank Sandstone, Triassic Strathmore Field 37 Oxford Clay, Jurassic 5 Kimmeridge Bay Field 945 Palmers Wood Field 990 data summary 940-1,970 location 929, 930 production history 929, 931,932 reservoir 41,938 Pangaea 18 Pelican Field 35 Penguin Field 35 Pentland Formation, Middle Jurassic 40 Beryl Field 40 Bruce Field 40 Buckland Field 40 Curlew Field 521 Drake Field 145 Erskine Field 523-33 Hawkins Field 148 Heron Field 40 Linnhe Field 40 Nevis Field 40 Puffin field 40 Sherwater Field 40 see also Brora Coal Formation; Rattray Volcanics Member Petronella Field 44, 990 Phoenix Development 872, 878-80, 990
Pickerill Field 990 data summary 808-9, 970 development and production 807 history 799, 801 location 799, 800-1 reservoir 30, 804, 806, 807, 808 source 807 stratigraphy 802-3, 804 structure 801-2, 803 trap 804, 805-6 Pierce Field 990 exploration and appraisal history 647, 649-50 geological summary 648-52, hydrocarbon charge 656, 657, 658 location 647, 648 reservoirs 46, 48, 652-5, 657 structure 48 Pine Field 43 Piper Field 12, 12, 43, 990 Piper Formation, Upper Jurassic 13 Chanter Field 43 Hamish Field 43, 443-7 Ivanhoe Field 43, 443-7 Piper Field 43 Renee Field 43 Rob Roy Field 43,443-7 Scott Field 43, 470, 470-8 Telford Field 43 play fairways, U K 43, 50 Carboniferous 25, 27, 29-30 Cretaceous 44-6, 44-5 Devonian 25 Jurassic 37-44 Palaeogene 46-50, 283 Permian 30-2 Pre-Devonian 25 Triassic 32-7 Plungar Field 990 Precambrian production 17 Puffin Field 35, 40, 990 Puffin Formation, Upper Jurassic Erskine Field 523, 527-8, 529, 530, 533 Purbeck Limestone, Lower Cretaceous Albury Field 41,931, 937 Rannoch Formation, Middle Jurassic 38-40 Rattray Volcanics Member 19, 41 Ravenspurn North Field 30, 990 Ravenspurn South Field 30, 990 Rempstone Field 990 Renee Field 43 residual salt analysis 656, 657 Rhaetic, Triassic 38 Humbley Grove Field 932 Rheic Ocean 18, 21 Ribble Sands Member, Upper Jurassic Fulmar Field 563-84 risk minimization 15 Rob Roy Field 12, 990-1 data summary 450, 971 history 443-4 location 443 reserves and production 444, 447, 448-50 reservoir 43 depositional environments and facies 445-7 flow unit zonation 447, 448 quality, geological controls on 447
1003 stratigraphy 445, 446 structure 443, 444-5 Rogaland Group, Eocene Brimmond Field 559 Ross Field 990 Rossall Halite, Triassic Douglas Field 65-6 Hamilton Field 81 Hamilton North Field 81 Lennox Field 90, 90 South Morecambe Field 98 Rot Halite Member, Triassic 34 Rotliegend Group, Permian 30-2 Auk Field 32, 486-95 Argyll Field 32 Camelot Field 681-7 facies 35 Innes Field 32 palaeogeography 23, 34 see also Leman Sandstone Member Rottington Sandstone Member (Chester Pebble Beds equivalent) 63 Rough Field 30-1,684, 990 Rowan Sandstone Member, Upper Jurassic Birch Field 168, 168, 172, 177 Rubie Field 12 salt movement 32, 42 salt withdrawal 31, 42 Saltfleetby Field 27, 991 data summary 918-19, 971 development and production 915, 918 location and history 911-13 reservoir 914-15, 916-17 seismic database 915 source 915 structure, trap and seal 912, 913-14, 915 Saltire Field 44, 991 Scampton Field 27, 914, 991 Scampton North Field 27, 991 Scapa Field 44, 991 Scapa Sandstone Member, Lower Cretaceous 44 Schiehallion Field 14, 15, 49, 49, 121-2, 991 Schooner Field 991 data summary 823-4, 971 history 811-12 location 811 reserves and production 811, 822-3 reservoir 816-21 source 821 stratigraphy 812-13, 815-16 structure 812-15 trap 815, 816 Scott Field 7, 12, 13, 991 data summary 481,971 history 468,469-70 hydrocarbon composition and source 468-71, 473, 478-9 location 467-8, 469 reserves 471, 480, 48I and production history 469, 479-81 reservoir 43 character 468, 475-6, 477-8 interval 468, 473-7 stratigraphy 470, 472 structural evolution 468-70, 471-2 trap 471, 472, 473 sea-level change, global see eustacy
1004 Sean East Field 991 data summary 832-3, 972 history 825-6 location 825 reserves 830, 832 reservoir 829-30, 831 source 830, 832 stratigraphy 826, 828, 830 structure 826, 827-9 trap 828-9 Sean Fields 701 Sean North Field 991 data summary 832-3, 972 history 825-6 location 825 reserves 830, 832 reservoir 30, 829-30, 831 source 830, 832 stratigraphy 826, 828, 830 structure 826, 827-9 trap 828-9 Sean South Field 991 data summary 832-3, 972 history 825-6 location 825 reserves 830, 832 reservoir 30, 829-30, 831 source 830, 832 stratigraphy 826, 828, 830 structure 826, 827-9 trap 828-9 seasonal supply facility (peak shaver) 109, 832-3 secrecy of technical information 15 Sedgwick Field 991 data summary 230 history 223, 224-6 reserves and production 230 reservoir 48, 225, 227-30 source 230 stratigraphy 223, 225, 226-7 trap 48, 226, 227, 228 Sele Formation, Palaeocene Andrew Field 135 Arbroath Field 612 Arkwright Field 612 Forties Field 558 Harding Field 284 Montrose Field 612 Nelson Field 617-39 Pierce Field 649, 653 Blair/West Blair Fields West Brae Field 224-230 see also Forties Sandstone Member Sgiath Formation, Upper Jurassic Scott Field 470, 470-8 Shearwater Field 35, 40, 42, 991 Sherwood Sandstone Group, Triassic Dalton Field 35 Douglas Field 35, 63-66, 74 Hamilton Field 35, 78-80, 84 Hamilton North Field 35, 78-80, 84 Lennox Field 35, 87-8, 89, 93 Millom Field 35 Morecambe Field 13 North Morecambe Field 35, 97-8, 103 South Morecambe Field 35, 107-110, 111 Wareham Field 35 Wytch Farm Field 6 35 see also Ormskirk Sandstone Formation;
INDEX Silverpit Formation, Permian 23, 31, 34-5 Johnston Field 749-50 Neptune Field 778, 779-80, 784 Schooner Field 812, 815 Tyne Field 853, 854, 856 Windermere Field 893 Silverpit Lake 669, 721,727, 757, 863, 875, 899 Silver Pit Basin 811 Singleton Field 991 data summary 940-1,972 location 929, 930 production history 929, 931 reservoir 41,932, 936-7 Skaggerak Formation, Triassic 42 Egret Field 35 Elgin Field 35 Franklin Field 35 Gannet Fields 35 Heron field 35 Judy Field 35 Marnock Field 35 Puffin Field 35 Shearwater Field 35 Skua Field 35 Skiff Field 663 Skua Field 35, 991 Sleipner Formation, Middle Jurassic 38, 41 T-Block Field Smith Bank Formation, Triassic 35, 43 Snorre Field, Norway 35, 38 Sola/Rodby Shale, Lower Cretaceous Captain Field 433, 437 8 Solan Field 121,992 South Arne Field, Denmark 15 South Brae Field 980-1 data summary 221,954 geological history 213, 214-16 geophysics 213, 215 hydrocarbons 220 history 167, 212-13 location 211, 212 reserves 220 reservoir 43, 215-18 correlation 218-20 source rocks 220 stratigraphy 212, 213 trap 211, 214, 215 South Cormorant Field 35, 40, 982 South Leverton Field 992 South Morecambe Field 989 appraisal 109 data summary 117, 969 development 108, 109 geophysics ll0 11,112 history 108 petrophysical evaluation 114-16 reserves and production 117 reservoir 35, 113-14 source rocks 112-13 stratigraphy 107, 109-10 structural history 111-12 South Valiant Field 993 data summary 870, 977 geophysics 864-5, 867-8 facilities 861-2, 869 field history 861-3 location 861 reserves 869
reservoir 30, 867, 868-9 source 869 stratigraphy 863, 864, 867, 867 structure 862, 863, 864-6 trap 862, 866, 868 Southern North Sea Fields 31, 661-901 Southern Permian Basin 19, 23, 30 St Bees Sandstone Formation, Triassic Douglas Field 63-65, 67 Hamilton Field 79, 81 Hamilton North Field 79, 81 Lennox Field 87, 89-90 North Morecambe Field 98, 98, 100, 101 2, 103 South Morecambe Field 109-10, 111, 112-13 Staffa Field 992 data summary 332-3, 97 development and production 332 location and history 327-30 reservoir 40, 330 2 source 332 structure, trap, seal and stratigraphy 328-9, 330 Stainton Field 27 Statfjord Field 12, 38, 39, 40, 992 data summary 351,973 depositional setting and reservoir quality 342-3, 345, 347-9 geophysics 346 history 335-6, 337-9 lithostratigraphic and tectonic framework 335, 338, 339-46 location 335, 336-8 reserves and production 337, 349-52 source 335, 349 structural setting and evolution 335-8, 339 trap 337-8, 346-7 Statfjord Formation (now lower part of Banks Group), Lower Jurassic Alwyn Field 37, 37 Beryl Field 157-60 Brent Field 37, 233-45 Bruce Field 37 Dunbar Field 275-6 Statfjord Field 37, 335, 340, 341,342, 347 Stifling Field 992 exploration and development history 395, 400, 401 geophysics 401,405, 406 hydrocarbons 406 location 395, 396 production and reserves 412, 413 facilities and transportation 413 reservoir characterization 25, 409, 410 stratigraphy and regional setting 397, 401,402 trap and source 405 Stockbridge Field 992 data summary 940-1,974 location 929, 930 production history 929, 931 reservoir 41, 932, 937 Storrington Field 992 data summary 940-1,974 location 929, 930 production history 929, 931 reservoir 41,932, 935-6
INDEX Strathclyde Group (formerly known as the Calciferous Sandstone Series) Cousland Field 29 Midlothian (D'Arcy) Field 29 Milton of Balgonie Field 29 Strathmore Field 33, 37, 121,992 Strathspey Field 40, 992 data summary 368, 973-4 discovery method 356-8, 359 field appraisal 355, 357 field development 355-6 history 355, 357 location 355, 356-8 reserves and production 365-7 source 365 stratigraphy 357, 359-61 trap 358, 362-5, 366 stratigraphic framework 20, 25-59 subsidence history, Atlantic Margin 24 T-block Fields 992 data summary 382, 974-5 geophysics 371,372, 373 history 167, 369 70 location 369 petroleum 374 production and reserves 378-9 oil in place 378, 380 production facilities and transportation 379-81 reservoir 43, 374, 375, 376, 377, 378, 380 source 371 stratigraphy 371 structural setting 370-1 trap 371 see also Toni Field; Thelma Field; Tiffany Field Tarbert Formation, Middle Jurassic 38-40 Tartan Field 12, 44, 992 Tay Sandstone Member, Eocene Gannet Fields 49 Guillemot Fields 49 tectonic framework 17-59 Telford Field 12, 43, 992 Tern Field 35, 40, 992 Tertiary Igneous Province 21 Thames Field 30, 684, 992 Thelma Field 992 data summary 975 Thelma SE Field 992 data summary 975 thermal effects, deformation caused by 17 thermal subsidence 19 Carboniferous 25 Cretaceous-Cenozoic 21, 44, 46 Triassic-Early Jurassic 19, 37 Thistle Field 992 data summary 391-2, 975 field management 390-1 fluids 390 geophysics 385, 389 history 383, 385 location 383, 384 reserves 390, 391 reservoir 40, 389-90 stratigraphy 385, 388-9 structure 385, 386-7
Tiffany Field 992 data summary 974 Toni Field 992-3 data summary 974 Tot Formation, Upper Cretaceous Banff Field 497, 500, 501-4, 505-6 Fife Field 539-44 Nelson Field 641 Torksey Field 993 Tornquist Sea 17, 25, 33 Trent Field 29, 993 data summary 849, 975-6 development 836, 847, 849 geophysics 838, 839 history 835-8 reservoir 840-6, 847-8 source 846-7 stratigraphy 840, 841 structure 838-40 trap 840 Troll Field, Norway 26 Trumfleet Field 993 turbidite deposition 43-5, 49 Tyne North Field 29, 993 data summary 859, 976 field development 860 geophysics 852-3, 854-5 history 851,852 location 851 reservoir 856-60 source 860 stratigraphy 851-2 structure 852, 853-4 trap 854, 856 Tyne South Field 29, 993 data summary 859, 976 field development 860 geophysics 852-3, 854-5 history 851,852 location 851 reservoir 856-60 source 860 stratigraphy 851-2 structure 852, 853-4 trap 854, 856 Tyne West Field 29, 993 data summary 859, 976 field development 860 geophysics 852-3, 854-5 history 851,852 location 851 reservoir 856-60 source 860 stratigraphy 851-2 structure 852, 853-4 trap 854, 856 UK production profile 14, 14-15, 17, 19 Ula Field, Norway 15 V-Fields 684, 861-70 see North Valiant Field; South Valiant Field; Vanguard Field; Vulcan Field Vaila Formation, Palaeocene Foinaven Field 49, 123, 124 Schiehallion Field 49 Valhall Formation, Lower Cretaceous 44 Captain Field 433 Claymore Field 44 Highlander Field 44 Petronella Field 44
1005 Saltire Field 44 Scapa Field 44 Vanguard Field 993 data summary 870, 977 geophysics 864-5, 867-8 facilities 861-2, 869 history 861-3 location 861 reserves 869 reservoir 30, 867, 868-9 source 869 stratigraphy 863,864, 867, 867 structure 862, 863,864-6 trap 862, 866, 868 Varg Field, Norway 142 Variscan deformation 27 Plate Cycle 18-19 Unconformity 27 velocity variations 10 Veselfrikk Field, Norway 26 Victor Field 7 993 Victory Field 45, 121,993 Viking Field 7 993 appraisal opportunities 871-4, 878 data summary 879-80, 977 geophysics 875 facilities 871-2, 878 history 872 initial gas-in-place (GIIP) and reserves 878 location 871, 872 reserves 879 reservoir 30, 872-3, 875-8 stratigraphy 873, 874 structure 872-3 trap 873, 875 Viking Graben Fields 36, 39, 131 Viking Group see Heather Formation; Draupne Formation Vulcan Field 993 data summary 870, 977 geophysics 864-5, 867-8 facilities 861-2, 869 Field history 861-3 location 86l reserves 869 reservoir 30, 867, 868-9 source 869 stratigraphy 863, 864, 867, 867 structure 862, 863, 864-6 trap 862, 866, 868 WAG development see drive mechanisms Wareham Field 35, 38, 946 waste zone Rotliegend 31, 34 Triassic 81, 90 water depth dogma 9-10 Waveney Field 30, 993 exploration and development concepts 882, 890-1 data summary 891,977 discovery method 883 geological history 883-5 geophysics 883-4, 885, 886 history 881-3 hydrocarbons 890 location 881
1006 reservoir 886, 888, 889-90 source 888, 890 trap 882, 884, 885-6, 887 Weald and Wessex Basin Fields 36, 38, 41, 927-48 Weissliegend sandstone, Permian Barque Field 669 Beaufort Field 711 Bessemer Field 711 Brown Field 711 Clipper Field 695 Davy Field 711 Guinevere Field 727 Leman Field 767, 768 Pickerill Field 807 V-Fields 869 Viking Field 877, 878 Waveney Field 886 Well Trade Agreements 10 Welton Field 6 27, 914, 923, 993-4 Werraanhydrit, Permian Davy Field 707, 708 Gawain Field 718, 720 V-Fields 866 Waveney Field 883 West Brae Field 25, 981 data summary 230, 954 history 223, 224-6 reserves and production 230 reservoir 49, 225, 227-30 source 230 stratigraphy 223, 225, 226-7 trap 48, 226, 227, 228 West Firsby Oil Field 27, 994 exploration and development concepts 923-4, 925-6 location and history 921, 922 3, 924 reservoir 923-4, 925 source 925 stratigraphy 922-4, 925 structure 921-2, 923-4 trap 921, 923, 924-5
INDEX West Sole Field 7, 7,663, 684, 694, 994 Westphalian A/B, Carboniferous Beaufort Field 711 Bessemer Field 711 Big Dotty Field 739 Boulton Field 671-80 Brown Field 711 Davy Field 711 Dawn Field 739 Deborah Field 739 Delilah Field 739 Della Field 739 Gawain Field 722 Hatfield Moors Field 908 Hatfield West Field 908 Hewett Field 739 Leman Field 768-9 Little Dotty Field 739 Malory Field 775 Mercury Field 785 Murdoch Field 792, 797 Neptune Field 785 Pickerill Field 807 Saltfleetby Field 915 Schooner Field 821 Sean North, South and East Fields 830 Trent Field 846 Tyne Field 852, 853, 860 West Firsby Field 922, 923, Windermere Field 900 see also Conybeare Group; Murdoch Sandstone Westphalian C/D, Carboniferous Boulton Field 671-80 Saltfleetby Field 914 Tyne Field 851-60 see also Barren Red Measures Westray Inversion 123-4, 124 Whisby Field 994 Wick Formation, Lower Cretaceous Captain Field 45
Widmerpool Gulf 22, 25 Windermere Field 994 data summary 900-1,977 development 893, 896, 900 history 893-5, 896 location 893 reservoir 30, 897-8, 899-900 source 900 stratigraphy 894, 896-9 structure 894, 895-6 trap 896-7, 899 Wytch Farm Field 6 7, 28, 35, 38, 41, 946, 994 Yare Field 30, 994 Yoredale Series, Carboniferous
5
Zechstein Group, Permian 7 32 Auk Field 32, 486, 488, 489-92 Argyll Field 32 Baird Field 743, 743 Barque Field 667 Bessemer Field 707 Beaufort Field 707 Camelot Field 681-5 Clipper Field 692, 693-4 Corvette Field 704 Excalibur Field 727 Guinevere Field 725-6 Hewett Field 31, 731-3 Indefatigable Field 743, 743 Lancelot Field 727 Malory Field 773 Mercury Field 778, 779 Pickerill Field 804 seal 32 Viking Field 873, 877 see also Kupferscheifer; Werraanhydrit; Zechsteinkalk Member Zechsteinkalk Member, Permian Hewett Field 735, 736, 738
Memoir 20 UK Oil and Gas Fields Commemorative Millennium Volume Corrected Appendix Appendix 1 has undergone substantial revision and correction since its original publication, all of which are featured on the CD-ROM (webshop keyword: M20CD). For those customers who have previously purchased the book but do not wish to purchase the CD-ROM the corrected Appendix is available for download at www.geolsoc.org.ulqM20
Geological Society Publishing House Unit 7 Brassrnill Enterprise Centre, BrassmiU Lane, Bath BA1 3JN, UK Tel: +44 (0)1225 445046. Fax: +44 (0)1225 442836. Email:
[email protected] www.geolsoc.org.uk/bookshop Registered charity no. 210161.
United Kingdom Oil and Gas Fields Commemorative Millennium Volume Edited by J. G. Gluyas and H. M. Hichens
Memoir 20 is the most comprehensive reference work on the UK's oil and gas fields available. It updates and substantially extends Memoir 14 (1991), United Kingdom 0il and Gas Fields, one of the Geological Society's best-selling books. This new edition contains updates on many of the ageing giant fields, as well as entries for fields either undiscovered or undeveloped when Memoir 14 was published.
The book is divided into nine parts covering the major petroleum provinces both offshore and onshore United Kingdom, from the Gas Basin in the southern North Sea to the Viking Graben in the northern North Sea, from the Atlantic Frontier to the Irish Sea and from the Wessex Basin to the East Midlands. Each part contains a reference map showing field locations. The introductory chapters reveal the stories behind the major plays and discoveries therein, and their tectonic and stratigraphic framework. There are two appendices: tabulated field data
and a comprehensive list for all of the UK's 300+ oil and gas fields.
Visit our online bookshop: http://bookshop.geolsoc.org.uk Geological Society web site: http://www.geolsoc.org.uk
Front cover illustration:
copyright PESGB, 2 nd Floor, 41-48 Kent House, 87 Regent Street, London WlB 4EH. Tel 0207 494 1933; Fax 0207494 1944; www.pesgb.org.uk
ISBN 1-86239-089-4
I!!UL!Ii!
