The Deliberate Search for the Stratigraphic Trap (Geological Society Special Publication No. 254)

The Deliberate Search for the Stratigraphic Trap

The Geological Society of L o n d o n BOOKS EDITORIAL COMMITTEE Chief Editor: Bob Pankhurst (UK)

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It is recommended that reference to all or part of this book should be made in one of the following ways: ALLEN, M. R., GOFFEY, G. R, MORGAN, R. K. & WALKER, I. M. (eds) 2006. The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254.

CITRON, G. P., MACKAY,J. A. & ROSE, E R. 2006. Appropriate creativity and measurement in the deliberate search for stratigraphic traps. In: ALLEN, M. R., GOFFEY, G. P., MORGAN, R. K. & WALKER, I. M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 27-41.

G E O L O G I C A L SOCIETY SPECIAL PUBLICATION NO. 254

The Deliberate Search for the Stratigraphic Trap

EDITED

BY

M. R. A L L E N Shell UK Ltd. G. P. G O F F E Y Paladin Resources plc, UK R. K. M O R G A N Veritas DGC Ltd., UK and I. M. W A L K E R ConocoPhillips (UK) Ltd.

2006 Published by The Geological Society London

THE GEOLOGICAL SOCIETY

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Contents

ALLEN, M. R., GOFFEY, G. P., MORGAN, R. K. & WALKER,I. M. The deliberate search for the stratigraphic trap: an introduction

1

BINNS, E E. Evaluating subtle stratigraphic traps: prospect to portfolio

7

CITRON, G. P., MACKAY,J. A. & ROSE, P. R. Appropriate creativity and measurement in the deliberate search for stratigraphic traps

27

DONNELLY,N., CAVE, K. R., WELLAND,M. & MENNEER,T. Breast screening, chicken sexing and the search for oil: challenges for visual cognition

43

ALLAN, J. R., SUN, S. Q. & TRICE, R. The deliberate search for stratigraphic and subtle combination traps: where are we now?

57

ATKINSON, C., RENOLDS, M. & HUTAPEA, O. Stratigraphic traps in the Tertiary rift basins of Indonesia: case studies and future potential

105

GOOD, T. J. Identification of stratigraphic traps with subtle seismic amplitude effects in Miocene channel/levee sand systems, NE Gulf of Mexico

127

STOKER,S. J., GRAY,J. C., HALLE,P., ANDREWS,I. J. & CAMERON,T. D. J. The importance of stratigraphic plays in the undiscovered resources of the UK Continental Shelf

153

MILTON-WORSSELL,R. J., STOKER, S. J. & CAVILL,J. E. Lower Cretaceous deep-water sandstone plays in the UK Central Graben

169

MOORE, R. M. & BLIGHT, R. D. The geological exploration techniques applied by BG in evaluation of the Buzzard Field prior to discovery

187

CORCORAN,J. Application of a sealing surface classification for stratigraphic related traps in the UK Central North Sea

207

LOlZOU, N., ANDREWS,I. J., STOKER,S. J. & CAMERON,D. West of Shetland revisited: the search for stratigraphic traps

225

MCINROY, D. B., HITCHEN,K. & STOKER,M. S. Potential Eocene and Oligocene stratigraphic traps of the Rockall Plateau, NE Atlantic Margin

247

GARDINER, A. R. The variability of turbidite sandbody pinchout and its impact on hydrocarbon recovery in stratigraphically trapped fields

267

HURST, A., CARTWRIGHT,J. A., HUUSE, M. & DURANTI, D. Extrusive sandstone (extrudites): a new class of stratigraphic trap?

289

Index

301

The deliberate search for the stratigraphic trap: an introduction MATTHEW

R. A L L E N 1, G R A H A M E G O F F E Y 2, R I C H A R D & I A N M. W A L K E R 4

K. M O R G A N

3

1Shell UK. Ltd. (e-maik matthew.allen@shelLcom) 2paladin Resources plc 3Veritas D G C Ltd. 4ConocoPhillips U.K. Ltd. Abstract: This Special Publication draws upon contributions to a similarly titled conference 'The Deliberate Search for the Stratigraphic Trap - Where Are We Now?' held at the Geological Society in London during 2004. Observations in this introductory paper have been drawn from the authors' experience, talks given at the conference and papers within this volume. Specifically it is noted that by analogy to basins which are perceived to be mature for structural traps, stratigraphic traps can have substantial remaining potential. Additionally, current exploration for stratigraphic traps seems rather restricted to areas where seismic data allow the direct assessment of fluid fill and reservoir development. It is argued that the industry is probably not doing enough to learn from established stratigraphic traps to guide future exploration for such traps. Looking forward, it is suggested that the industry faces two key challenges. Firstly, the use of all available data to assess fluid type and reservoir presence in areas of unfavourable rock physics, and secondly, the development of sufficiently sophisticated predictive models of stratigraphic trap development.

Twenty four years have elapsed since the original A A P G Memoir entitled 'The Deliberate Search for the Subtle Trap' (Halbouty 1982). Since that time, the technologies employed in hydrocarbon exploration have in many respects become extraordinarily sophisticated. Seismic imaging and interpretation tools have seen significant development, wireline logging has substantially improved, digital interpretation and rapid manipulation of vast quantities of data are the norm, and interpretive approaches such as sequence stratigraphy and quantitative analysis of seismic attributes have become prevalent. This Special Publication records a number of the papers given at the conference titled 'The Deliberate Search for the Stratigraphic Trap - Where A r e We Now?', organized by the Petroleum Group of the Geological Society and held in London from May 11 th to 13 th, 2004. The conference posed the question 'Where Are We Now?' in order to examine current industry perceptions of stratigraphic trap exploration and the technologies, tools and philosophy employed in such exploration, given the changing industry environment. It was felt timely to be assessing the current state of exploration for stratigraphic traps given both the increasing exploration maturity of many onshore and shallow water basins, and a subjective perception amongst the convenors

that this maturity was leading to greater emphasis on stratigraphic traps as remaining exploratory targets. Also, the industry has moved into exploration and development in appreciably more challenging and costly environments, in particular the deepwater basins. A developed understanding of stratigraphic trapping arising from deepwater exploration programmes in seismically well-imaged deepwater sediment gravity flow deposits, and the prevalent use of seismic direct hydrocarbon detection techniques in this setting, seemed likely to offer new insights.

H o w do we define stratigraphic traps? In the opening talk of the conference, Binns (2006) references the Levorsen (1966) characterization of oil and gas fields according to three trap dimensions, namely hydrodynamic, structural and stratigraphic. This appears to offer a useful conceptual approach, but as Binns notes, there are a wide variety of unconventional traps such as basin-centred gas accumulations and sand injectites (tturst 2006) which are not readily classified by these attributes. A complementary view is that of Charpentier & Cook (2004), who characterize trapping as a spectrum from discrete 'conventional' traps through to continuous traps, such as basin-centred gas

From: ALLEN,M. R., GOFFEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006.

Stratigraphic Trap. Geological Society, London, Special Publications, 254,1-5. 0305-8719/$15.00. 9 The Geological Society of London 2006.

The DeliberateSearchfor the

M.R. ALLEN ETAL.

2

accumulations. Another approach by Corcoran (2006) uses a seal based classification from Milton & Bertram (1992), whereby stratigraphic traps are characterized as poly seal traps, in which closed contours at the reservoir/seal interface do not exist or do not explain the trap, thus demanding one or more base or lateral seals. Clearly a number of definitions can be employed. We feel that the key concept is the recognition that there is a continuum between a number of end-member trapping mechanisms. Any hydrocarbon accumulation which is less than entirely dependent on structural closure, be it due to some degree of depositional pinchout, facies change, erosional truncation, diagenesis, hydrodynamics, dynamic fluid flow, or other mechanism, is likely to lead to traps with a greater or lesser degree of subtlety and hence is relevant in the context of exploration for non-structural traps.

The current state of the industry In the process of canvassing individuals and companies for papers for this conference, compiling the conference schedule, and through the conference itself, the convenors gained a degree of insight into how the exploration industry currently perceives exploration for stratigraphic traps and how it is behaving in respect of exploration for such traps. These insights can be characterized into a number of themes:

Stratigraphic traps are seen to have the most remaining potential in mature basins. In mature or maturing basins, where all but the smallest or most difficult structural traps have been identified and drilled, stratigraphic traps are often seen as holding the largest remaining prospectivity. For example, Stoker et al. (2006) believe that 50% of the UK's undiscovered resources lie in stratigraphic traps. Perceptions of the maturity of an exploration play may well be misleading if the supporting data are biased towards structural traps. Moore & Blight observed the lack of relevance of play creaming curves in describing play maturity in a Jurassic play in the UK Moray Firth, where structural traps had dominated historic drilling in that play A time lag of stratigraphic trap exploration behind exploration of structural traps was well demonstrated by Atldnson et aL (2006) with reference to the Powder River Basin

(USA). Here, a successful phase of exploration for stratigraphic traps followed earlier phases of exploration for structures based initially on surface geology and subsequently on seismic data. Similar patterns were also demonstrated by Macgregor & Miele (unpublished conference paper), with respect to the UK North Sea and deep-water West Africa. An obvious explanation of this time lag is the typically greater exploratory risk attached to such traps as exploration targets owing to greater difficulty in both accurate trap definition and in assessing sealing potential. Such traps tend only to be drilled once more simple structural traps have been exhausted. Allan et al. (2006) observed that 80% of discovered hydrocarbons in stratigraphic traps reside in North America, an observation attributed by the authors solely to a greater density of drilling in North America.

The majority o f current stratigraphic trap exploration b raking place in Tertiary rift basins and passive margins, driven largely by seismic direct fluid indications. No statistics are available to support this assertion, but it is felt by the authors to be representative of much of current stratigraphic trap exploration. Allan et al. (2006) note how some two thirds of deep-water discoveries in their studied database of fields rely on stratigraphic or combination structural-stratigraphic trapping. Such discoveries are typically based on seismic direct hydrocarbon indications. It is possible that these discoveries may be demonstrating that certain trap types in sediment gravity flow deposits are more common than previously perceived. The updip trapping of coarse clastic reservoirs in marine, lowstand canyons seems to be more prevalent than the authors previously suspected. Such traps were reviewed by Freer et al. in Mauritania and Liu et al. in Cameroon (unpublished conference papers). The Cameroon example was of an initially unpromising monoclinal slope, in which oil had been discovered in Palaeocene age channel thalweg and sheet-like turbidites contained in a 3 to 5 km wide belt and entrapped by up-dip pinchout within the channel. The Mauritanian example stressed the importance of understanding the mechanisms of sand delivery in pinpointing the areas of best reservoir development, but again heavily supported by amplitude analysis.

DELIBERATE SEARCH FOR THE STRATIGRAPHIC TRAP Assisted by outstanding 3D-based seismic imaging, a high level of geophysical sophistication can often be achieved, as demonstrated by Fervari et al. in the use of multi elastic seismic attributes to quantitatively define reservoir properties in the East Nile Delta. This unpublished conference paper showed how, in a gas sand below seismic resolution, careful integration of well and seismic data allowed quantitative prediction of in-place hydrocarbon volumes. Given the very heavy dependence on seismic data in such exploration, the paper by Donnelly et al. (2006) is a ground-breaking review of how geoscientists may be making interpretation of geophysical data more difficult through the use of common display and data search techniques. Using established principles derived from theories of visual cognition, the authors showed how interpretation performance could be improved. Given the great reliance placed by the industry on the use of colour displays to portray spatial variation in seismic attributes, Donnelly et aL's paper represents a unique assessment of the appropriateness of techniques used in a routine fashion by companies and academia. Stratigraphic trap exploration without seismic direct fluid indications is of course still taking place. Atkinson et al. (2006) demonstrate a deliberate and measured search for stratigraphic traps in Tertiary back-arc basins in Indonesia, based on the occurrence of a number of required regional indicators to localize the search for candidate traps. These regional indicators are favourable hydrocarbon charge, basin and reservoir architecture, seal quality and low stratal dips in the trap area. By contrast, Moore & Blight (2006) review a wide range of geological and geophysical techniques which were employed prior to the drilling of a single, seismically mapped stratal wedge which proved to be the North Sea Buzzard Field. These two papers serve to demonstrate that in areas of unfavourable rock physics, there is little substitute for regional and local geological understanding through a play based approach coupled with high quality seismic data.

Geoscientists have far greater enthusiasm for stratigraphic traps than do decision-makers. Perhaps it was ever thus. The authors question whether there is a communication

3

gap between on the one hand the geoscientists, who recognize that in mature basins, stratigraphic traps often offer the largest remaining potential, and on the other hand the decision-makers, who have yet to fully appreciate the advancing maturity of many basins. Alternatively, perhaps decisionmakers are rightly suspicious of perceived high risk stratigraphic traps. Citron et aL (2006) note that explorers are required to serve three main, sometimes conflicting, roles. These roles involve firstly the creative conceptualization and identification of subtle traps, which explorers must then accurately measure, and finally they must communicate the uncertainty and probability aspects associated with their characterization of the opportunity. Citron et al. review the techniques available to allow explorers to fully and accurately characterize stratigraphic prospects, and to clearly convey conclusions to decision-makers.

The industry is probably not learning enough, or attempting to learn enough, from established stratigraphic traps. Whether the techniques of Citron et aL allow decision-makers to overcome suspicions of high risk associated with stratigraphic traps is another matter. In convening the conference, it proved impossible to persuade companies to describe what has been learned from developed fields contained in stratigraphic traps. This is despite the existence in such fields of enviable datasets comprised of many wells, often multiple seismic datasets and a detailed understanding of internal reservoir architecture and limits. We speculate that this is because, at least in NW Europe, developed fields are commonly managed by teams with limited resources or limited briefs, and disconnected from individuals exploring in the same basin. We also question whether sufficient, or sufficiently detailed or appropriate work (e.g. Play based exploration) is routinely undertaken to understand the regional and local setting within which stratigraphic traps may reside. Godo (2006) demonstrated how extremely detailed work to understand every discovery (and failure) in a Miocene deepwater channel/levee system in the NE Gulf of Mexico was valuable in the discovery of a large portion of some 2 trillion cubic feet of gas in an area perceived initially to be one of relative unprospective monoclinal dip.

4

M.R. ALLEN E T A L .

Overall, industry's sophistication in manipulating and employing seismic data in stratigraphic trap exploration is relatively high, particularly where seismic data can assist in fluid identification and in assessment of reservoir distribution and quality. However, it is not clear that geological techniques have reached or aspire to comparable levels of sophistication in terms of understanding and predicting stratigraphic traps. It is possible that techniques have largely been forgotten during the 'amplitude chasing' years and are now having to be relearned. The in-depth understanding of analogue fields and relevant outcrop examples, coupled with deep insights into basin evolution and reservoir deposition that the convenors might have expected to be instrumental in successful exploration for stratigraphic traps were generally not well demonstrated at the conference.

Looking forward... In the future, it seems clear that stratigraphic trap exploration will become increasingly predominant in the worlds' mature and maturing basins. However, the industry must address two major challenges: (1) The use of all available data in a play based approach to develop deep insights which allow explorers to reduce risk on trap (seal), reservoir and charge where seismic data does not lend itself either to the ready differentiation of hydrocarbon from water, or reservoir from non-reservoir. With respect to the UK West of Shetlands basin, Loizou et al. (2006) addressed the limitations of seismic data in areas where the rock characteristics do not lend themselves to ready detection of fluid type. Further improvements in seismic data, but also a much better understanding of the geological building blocks that form hydrocarbon plays, are seen as important elements of exploration in such settings. (2) The development of sophisticated, predictive geological models that guide exploration for stratigraphic traps. The authors believe that the industry needs to adopt a more sophisticated level of geological insight before geoscientists can match their enthusiasm for stratigraphic prospects and leads with a predictive understanding, which demonstrates to decision-makers that exploration funds are being wisely spent. A good understanding of trap analogues, both subsurface and outcrop, the rigorous application of sequence stratigraphic concepts and closer

integration of well and seismic data seem in general to be areas of relatively deficient analysis at the moment. Academia has a major part to play in developing these themes, particularly in developing more sophisticated geological models. Academia and joint industry consortiums can very usefully dissect and understand well-drilled analogue traps to provide improved understanding of trap geometries and place these in an appropriate regional context. Coreoran et al. (2006) show how an understanding of stratigraphic trapping configurations in a basin can assist ongoing exploration. Similarly, Haughton & McCaffrey (unpublished conference paper) demonstrated with reference to outcrop observations and an in-depth understanding of depositional mechanisms, the range in possible style of lateral termination of turbidites against confining slopes. Gardiner (2006) expands upon this and demonstrates how pinchout variability affects reservoir behaviour though the use of reservoir models. The world's readily accessible basins are becoming rather mature for exploration, yet history shows that the challenge of basin maturity can sometimes present an opportunity, where favourable geology leads to the stratigraphic trapping of commercial hydrocarbons. Technology, good science or serendipity can allow the realization that this trapping potential exists. To meet the challenge of successfully exploring for such traps, the authors believe the geology and evolution of a basin needs to be fully unravelled. This is only likely to arise if the exploration effort is sufficiently well resourced in terms of skills, data, technology, funds and time for the rigorous integration of information and creativity to generate such insight.

References ALLAN, J.R., SUN, S.Q. & TRICE, R. 2006. The deliber-

ate search for stratigraphic and subtle combination traps: where are we now? In: ALLEN,M.R., GOFFEY, G.P., MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 57-104. ATKINSON, C.E., RENOLDS, M. & HUTAPEA,0. 2006.

Stratigraphic traps in the Tertiary rift basins of Indonesia: case studies and future potential. In: ALLEN, M.R., GOVEEY, G.E, MORGAN,R.K. & WALKER,I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 105-126.

DELIBERATE SEARCH FOR THE STRATIGRAPHIC TRAP BINNS,P.E. 2006. Evaluating subtle stratigraphic traps: prospect to portfolio. In: ALLEN,M.R., GOFFEY, G.P., MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 7-26. CITRON,G.E, MACKAY,J.A. & ROSE,ER. 2006. Appropriate creativity and measurement in the deliberate search for stratigraphic traps. In: ALLEN, M.R., GOFFEu G.E, MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 27-42. CORCORAN, J. 2006. Application of a sealing surface classification for stratigraphic related traps in the UK Central North Sea. In: ALLEN,M.R., GOFFEY, 6.19., MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 207-224. CHARPENTIER,R.R. & COOK,T. (2004). Conventional and Continuous Accumulations: a Spectrum, Not a Dichotomy. American Association of Petroleum Geologists. Annual Convention, Dallas, Texas. DONNELLY,N., CAVE, K., WELLAND,M. & MENNEER, T. 2006. Breast screening, chicken sexing and the search for oil; challenges for visual cognition. In: ALLEN, M.R., GOFFEY, G.E, MORGAN, R.K. & WALKER,I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 43-56. GARDINER, A.R. 2006. The variability of turbidite sandbody pinchout and its impact on hydrocarbon recovery in stratigraphically trapped fields. In: ALLEN, M.R., GOEFEY, G.P., MORGAN, R.K. & WALKER,I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 267-288.

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GODO, T.J. 2006. Identification of stratigraphic traps with subtle seismic amplitude effects in Miocene channel/levee sand systems, NE Gulf of Mexico. In: ALLEN,M.R., GOFFEY,G.P., MORGAN,R.K. & WALKER,I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 127-153. HALBOUTY, M.T. 1982. (ed.) The Deliberate for the Search Subtle Trap. Memoir 32, American Association of Petroleum Geologists, Tulsa, OK. HURST,A., CARTWRIGHT,J., HUUSE,M. & DURANTI,D. 2006. Extrusive sandstones (extrudites): a new class of stratigraphic trap? In: ALLEN, M.R., GOFFEY, G.P., MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 289-300. LEVORSEN, A. 1966. The Obscure and Subtle Trap. Bulletin American Association of Petroleum Geologists, 50, 10, 2058-2067. LoIzou, N., ANDREWS,I.J., STOKER,S.J. & CAMERON, D. 2006. West of Shetland revisited: the search for stratigraphic traps. In: ALLEN, M.R., GOFFEY, G.P., MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 225-246. MILTON, N.J. & BERTRAM, G.T. 1992. Trap styles, A new classification based on sealing surfaces. The American Association of Petroleum Geologists Bulletin, 76, 983-999. STOKER, S.J., GRAY, J.C., HAILE, P., ANDREWS, I.J. & CAMERON,T.D.J. 2006. The importance of stratigraphic plays in the undiscovered resources of the UK Continental Shelf. In: ALLEN,M.R., GOFFEY, G.E, MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 153-168.

Evaluating subtle stratigraphic traps: prospect to portfolio P. E. B I N N S

Consultant, The Old Farmhouse, Broomlee Mains, West Linton, Edinburgh EH46 7BT, UK (e-mail: [email protected], co. uk) Abstract: A compilation of 85 stratigraphic traps demonstrates the variety of trapping mechanisms and the scope for developing new concepts by matching geological models with features in 3D seismic volumes. However, aspects of quantitative evaluation may discourage exploration. Investors require assurance in the form of probabilistic evaluations of risk and value but information critical to the evaluation of new stratigraphic concepts is likely to be lacking. As estimates of risk and uncertainty vary with information, prospects evaluated with radically different levels of information must be ranked with care. The requirements for quantitative project ranking and portfolio optimization have to be reconciled with the need to 'venture into the unknown'. The character of stratigraphic prospects dictates different evaluation methods from those used to evaluate structural prospects. This, together with the high degree of sensitivity of value to evaluation methodology, can also lead to inconsistencies in ranking. Within the context of a company's overall strategy and risk tolerance, organizational and cultural factors may influence prospect selection. In particular over-emphasis on quantitative methods may not have the intended effect. A common understanding, amongst technical and commercial disciplines and decision makers, of the background to quantification is essential. Factors which encourage the progression of stratigraphic prospects include a dedicated geoscience effort, a separate 'growth' portfolio of new concepts, a formal structure for progressing these and a stable organization.

Stratigraphic traps may contain significant reserves but their seismic responses may be subtle and, if the play concept is new, information critical to the accurate estimation of risk and uncertainty may be lacking. Investors, however, require systems to be in place to realistically evaluate prospects and to produce predictable returns from a portfolio. New stratigraphic concepts are commonly evaluated as high risk and are o u t r a n k e d by structural prospects in competition for funding. This paper attempts to draw together various aspects of stratigraphic trap evaluation and suggests approaches which will result in more stratigraphic prospects being drilled. It draws on a compilation of 85 proven stratigraphic traps in 40 sedimentary basins (Table 1 & Fig. 1). Many of the discoveries have been made when drilling for other objectives ('serendipity'). A very high proportion of the discoveries have been made in North America, suggesting unrealized potential elsewhere. The compilation shows that 'subtlety' is largely due to low gross reservoir thickness; low acoustic impedance contrast does not seem to be a common cause of subtle seismic response. High volumes in subtle stratigraphic traps are thus achieved through areal extent (Fig. 2). Area is the only control on volume which has

the scope to increase it significantly without creating a feature, clearly visible on seismic data. Giant fields such as East Texas (Ultimate Recovery 5.4 billion barrels; Halbouty 1991, 2003) and D a u l e t a b a d - D o n m e z (Ultimate Recovery 27.9 TCF; Clarke & Kleshchev 1992; Halbouty 2003) have proven areas of 534 km 2 and 2503 km 2 respectively. By showing the great variety of stratigraphic trapping mechanisms and their interaction with structural and hydrodynamic controls, the compilation demonstrates the scope for prospect generation based on wellresearched geological models. The basic techniques for evaluating prospects are well established (Newendorp 1975; Mackay 1996; Rose 2001). However, the critical dependence of risk and uncertainty on available inform a t i o n has received less a t t e n t i o n recently, although thoroughly discussed in the past (Knight 1921; Keynes 1936). This aspect is discussed after a review of trends in stratigraphic trap exploration. Special characteristics of stratigraphic traps which pertain to evaluation are discussed next, followed by portfolio aspects. A company's culture and internal communications have a critical impact on evaluation and these are discussed before summarizing approaches likely to lead to the maturation and drilling of more stratigraphic prospects.

From: ALLEN,M. R., GOFFEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 7-26. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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EVALUATING SUBTLE STRATIGRAPHIC TRAPS

11

Fig. 1. Locations of stratigraphic traps in the compilation (Table 1).

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Fig. 2. Ultimate recovery as a function of productive area in forty stratigraphic traps. The relationship indicates that the high volumes in the giant fields are associated with the areal extent of the reservoir. Pecos Slope, which lies below the trend, produces from a fluvial system with inter-channel areas included in the field.

12

R E. BINNS

History and trends In 1936, noting that 'we are facing a declining discovery r a t e . . , and that there is nothing we can do about it', Levorsen (1936) pointed to the potential in stratigraphic traps. This call has been repeated periodically over the years (Levorsen 1966; Halbouty 1969, 1982). However, until the recent discovery of combination traps in deep water, structural traps remained the major source of new reserves. Improved seismic imaging, deep drilling and the opening up of new areas continually generated new prospects. Levorsen (1966) identified three key controls on trapping; structure, stratigraphy and hydrodynamics. He emphasized that most traps are formed by a combination of at least two of these controls. Rittenhouse (1972) produced a hierarchical classification comprising some 64 classes and sub-classes. These pioneers demonstrated the great variety of stratigraphic trapping mechanisms. Since then several types of unconventional accumulation have been discovered and add to the possibilities. Whilst these may not be wholly stratigraphic, they may have a stratigraphic component. Charpentier & Cook (2004) describe an earth model which includes these types of accumulation. They point to the continuous spectrum between conventional, discrete accumulations, at one end, and extensive continuous accumulations with no hydrocarbon-water contacts at the other. The latter include regionally-pervasive, basin-centred gas systems, reviewed by Law (2002), shale-gas systems (Curtis 2002) and coalbed methane systems (Ayers 2002). Other unconventional traps with stratigraphic elements include igneous rocks (Schutter 2003) and injectites (Hurst 2003). Within the last ten years, the discovery of combination traps in deep water offshore West Africa, Egypt, Brazil and the Gulf of Mexico has increased the proportion of giant, stratigraphically trapped accumulation, from 15% of discoveries in the 1970s to over 35% in the 1980s and 1990s (Halbouty 2003). These do, however, have a significant structural component, are amplitude-supported and depositional features are clearly recognizable on 3D seismic. Stoker et al. (2006) analyse the occurrence of stratigraphic traps in the North Sea, showing that 17% of discoveries have a stratigraphic component and 5 % are pure stratigraphic traps. Most stratigraphic and combination traps in the North Sea occur in association with syn- and post-rift plays. The deliberate search for subtle prospects in 3D volumes by matching seismic features with

realistic depositional, diagenetic and hydrodynamic models, is rare. Explorers tend to focus on key horizons. There is, therefore, scope for replacing 'serendipity' with a systematic search and evaluation procedure which is recognized and understood by decision makers.

Risk, uncertainty and information In order to attract investment, geoscientists have to 'translate' their data and judgements into quantitative expressions of risk and monetary value. It is particularly important to understand this process in the case of stratigraphic traps because of the higher risks involved and thus the chance that potentially large accumulations are 'ranked out'. Furthermore risked volumes and values are the basis for portfolio optimization techniques.

Theory

Evaluation of a prospect or portfolio sets out to answer two questions: what is the probability of commercial success? and, given success, what are the likely ranges of volumes and values and their associated probabilities? The questions are answered in the form of risked probability distributions. 'Risk' and 'Uncertainty' in prospect evaluation are defined here as: Risk: the probability that a key element, essential to the formation of a commercial accumulation (e.g. reservoir), is absent. Uncertainty: the range of possible values of some parameter used to calculate volume or value (e.g. porosity): also the ranges of the resulting volumes and values themselves. Probabilities are assigned within a range to form a probability distribution.

Estimates of probability can be made in three ways (for an original discussion see Knight (1921)). 'Classical' probability is concerned with closed systems, which have mutually exclusive outcomes (e.g. dice). Secondly the probability of occurrence of some future event can be estimated from the frequency of its occurrence in the past. Thirdly, probability can be estimated subjectively, based on expert opinion backed up by analogy. The validity of quantifying probabilities on the basis of the subjective judgement of experts has been debated for many years. Referring to situations in which predictions are attempted on very limited information Keynes (1937) states ' . . . there is no scientific basis on

EVALUATING SUBTLE STRATIGRAPHIC TRAPS which to f o r m any calculable probability whatever. We simply do not know'. However, accepting that there has to be some rational basis for decisions, he suggests extrapolation of present conditions and 'conventional judgement' as albeit 'flimsy foundations'. More recently, various "uncertainty orientated methods" have been proposed to handle uncertain inputs (Berleant et al. 2003: B~irdossy & Fodor 2004). A distinction is drawn between: 9 9

'uncertainty described with a distribution function (of which a specific probability value is a special case) and uncertainty described with both a distribution function and error bounds o f some sort (giving, f o r example, dependency bounds~envelopes~p-boxes, confidence intervals, or interval-valued probabilities)'.

Of the methods introduced to handle uncertainties which can not be precisely characterized, Interval Probability Theory (Cui & Blockley 1990; Hall et al. 1998) has been used in exploration but is not common. A p p l i c a t i o n to exploration Risks and uncertainties in exploration are quantified on the basis of the 'Frequency' or 'Subjective' interpretations of probability. The debate about the validity of quantifying probability on the basis of subjective judgement also takes place in exploration and approaches to the quantification of risk and uncertainty range between two extremes. At one extreme, exploration is viewed as a 'venture into the unknown' in which it is impossible to quantify risk and uncertainty; success coming from the quality of a play concept and the persistence with which it is pursued. The explorer may be lucky but, taken to extremes, this approach is likely to result in funds being exhausted by a run of dry holes. At the other extreme is risk aversion and strict financial discipline. Prospect risks and uncertainties are calibrated with adjacent data or analogues. The results are taken at face value, even if they are based on little information. Cutoffs are applied to the resulting economic indicators and any prospect failing to meet these is discarded. As prospect risk is strongly dependent on available information, this extreme attitude, if applied to new concepts, will result in potentially valuable prospects being discarded. Furthermore this approach will direct exploration towards existing plays and away from fresh ideas which could lead to new plays analogues are a mixed blessing.

13

I n f o r m a t i o n a n d n e w p l a y concepts During the development of new plays, information is lacking and estimates of risk and uncertainty are subjective. Contrary to the above view of Keynes, it has been argued that making such subjective estimates is valid because there is no alternative and that quantification of expert opinion is justified. ' . . . the problem involved in using decision analysis has b e e n . . , where do we get all the probabilities . . . ? Risk analysis is certainly the weakest link (at least in the petroleum exploration context) o f the overall decision process . . . But what is our alternative? Ignore risk?' (Newendorp 1975). Rose (2001) supports this view -'Given a logical procedure, knowledgeable explorationists can generate such estimates with surprising consistency, agreeing not only on discovery probability but also on the relative certainty or uncertainty o f the several geological chance factors in a given prospect.' Indeed such estimates are essential, if they are used to compare prospects in proven plays with similar levels of information. They 'translate' and focus geological information and experience into risks and values, which can be communicated to decision makers. However, as the values returned depend on the levels of available information, it is not valid to compare prospects evaluated with different levels of information. This is not comparing like with like and ranking is likely to be seriously in error, particularly in the case of high risk prospects, where differences in the probability of success are only a few percent. Prospects, which have potential but also carry a high risk due to a lack of information, are in danger of being ranked out. The relation between risk and uncertainty, on one hand, and information on the other, must be acknowledged and understood. Prospects within a well-drilled play, in which risks and uncertainties have been calibrated, can be quantitatively evaluated; the probability of a given parameter value being reasonably estimated from the 'relative frequency' with which that value has previously occurred. New concepts, based on limited information, should be treated separately from those in proven plays. Examples Stratigraphic prospects can take very different paths to success, depending on the information available; compare Occidental's Sarah Field (onshore Oman) with Shell's Bonga Field (deep water Nigeria). The Sarah Field is a facies

14

R E. BINNS

change trap (Boote & Mou 2003). Volumes have grown gradually from pre-drilling estimates in 1982 until 2000 (Fig. 3). Before drilling much thought went into the stratigraphic concept but only limited information was available and the prospect carried a high risk and a high level of volumetric uncertainty. The pre-drilling estimate of oil-in-place could only be placed in the range 20-1000 million barrels. This estimate had 'little discriminatory value in comparisons with other competing high-risk ventures. However, at the time the decision was taken to drill Sarah-Ix, the value o f information expected from the well was considered enough to justify its cost' (Boote & Mou 2003). Even after discovery and appraisal, considerable subsurface uncertainty remained. The project was progressed in an iterative fashion with cycles of seismic, drilling and study. Evolving geological models guided operations, the oil price fluctuated considerably and new technologies, probably not envizaged in the exploration phase, were employed as they became available. The postappraisal oil-in-place estimate was based on two alternative geological models, which returned 130-203 and 1090 million barrels. Seventeen years after discovery estimated oil-in-place had firmed to 1077 million barrels. Since discovery estimated recoverable reserves have increased to 380-430 million barrels. Sarah demonstrates

the rewards for recognizing, and persisting with, a stratigraphic concept when information is lacking. Although the first well removed geological risks, substantial volumetric and commercial uncertainties remained. In contrast, the discovery well in Shell's Bonga field was not drilled until a substantial amount of information was available and hydrocarbon indicators had been interpreted (Fig. 4; Ghosh et al. 1998; Chapin et al. 2002a; Skaloud & Cassidy 1999). Evaluation started when the only available data were widely-spaced 2D seismic lines. It was progressed through a regional 2D grid, on which the Bonga feature was recognized. Following this, 3D seismic was acquired, hydrocarbon indicators were interpreted and the discovery well located. Developable reserves are approximately 600 million barrels (Chapin et al. 2002b). The diagram in Figure 5, which is suggested as an aid to discussion, conceptually relates risk and uncertainty to information. A new play concept will lack supporting information, risks will be assigned subjectively and" ,m u. be high. As new information is acquired, risks are either reduced or remain high and at some point a decision to 'drill or drop' will be taken. The initial risks associated with the Nigeria deep water province, being adjacent to a producing delta, are likely to have been lower than those

Fig. 3. Safah Field, onshore Oman, history of hydrocarbon reserves estimates, 1982-2000 (Boote & Mou 2003). At the time Safah-lX was drilled, the trap was not recognizable on seismic. There was considerable volumetric uncertainty, which remained even after appraisal, with two alternative geological models returning 130-203 and 1090 million barrels in-place. Recoverable reserves increased gradually since the start of development, reaching 380-430 million barrels in 2000 as a result of increased knowledge about the reservoir, new technologies and the persistence of the operator.

EVALUATING SUBTLE STRATIGRAPHIC TRAPS

15

Fig. 4. Bonga Field, Deep Water Nigeria, amplitude draped over structure. The discovery well was not drilled until a substantial amount of information was available and hydrocarbon indicators had been interpreted. (OWC, Oil Water Contact.) at Safah and it was subsequently possible to acquire a considerable amount of risk-reducing information before drilling. In contrast the only way to progress the Sarah concept was to drill. In fact the risks of commercial failure remained high until several appraisal wells had been drilled. Conclusions

Estimates of risk and uncertainty naturally change with the amount of information available. When information is lacking, realistic estimates of risk and uncertainty cannot be made. In such situations prospects should not be assigned a high risk and ranked together with prospects in proven plays. Instead, the lack of information should be acknowledged and they should be separated and be subject to special examination. Paths to economic success vary; exploration is an iterative process; persistence and the sensible purchase of new information, including that obtained by drilling, may lead to

success. Equity trading and funding from early production may aid this process.

Evaluating individual stratigraphic traps Overview

Basic evaluation techniques are well-established (Newendorp 1975; Mackay 1996; Rose 2001) and more complex, holistic systems have also been proposed (Peersmann & Floris 1998; Smith & McCardle 1999; Galli et al. 1999; Begg et al. 2001). All assume that any quantitative analysis is made only after the most thorough geological and commercial groundwork. All evaluation techniques attempt to simulate the real world of geology and economics and so the character and geometry of stratigraphic prospects may dictate differences from the approach used to evaluate structural prospects. A stratigraphic trap may be continuous over an area of several hundred square kilometers or may take the form of an extensive complex with

16

R E. BINNS

BONGAMODEL DE-RISKBEFORE DRILLING

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Fig. 5. Conceptual relationship between risk/uncertainty and information for two contrasting stratigraphic prospect histories. In some situations it is possible to acquire information critical to the reduction of risk, before drilling, in other situations success only comes after several wells have been drilled.

separate reservoir c o m p a r t m e n t s (e.g. the Lima-Indiana trend; Keith & Wickstrom 1992). Unusual reservoir/seal combinations such as silicilyte/salt are more common. In discrete stratigraphic accumulations (geomorphic traps and reefs apart) lateral and seat seals replace structural closure as risk factors. If sub-surface water is in motion, hydrodynamic force will be a significant control on trapping (Hubbert 1953). The attitude of h y d r o c a r b o n - w a t e r contacts will be modified and, in extreme cases, hydrocarbons may be trapped by hydrodynamic forces alone (e.g. Elkhorn Ranch Field; DeMis 1992). In extensive traps, with thin reservoirs, transition zones assume a greater importance in estimating volumes. Decisions to progress a stratigraphic prospect, by study, appraisal or by acquiring seismic data, are effectively 'decisions to purchase imperfect information' (Newendorp 1975). Due to their subtle seismic expression, it is more difficult to progress and de-risk stratigraphic prospects. F u r t h e r m o r e their areal extent and long production histories have a negative effect on profitability. Value is less likely to be a linear function of volume due to discontinuities associated with the development costs of areally extensive reservoirs. In stacked sequences dependencies between reservoirs are likely to be lower as they no longer share the common trapping element present in structures.

Estimation of risk Insight can be gained into the relative importance of the geological risk factors associated with stratigraphic traps by viewing the fields in the compilation as prospects in a mature province with 3D seismic. In forty of the fields, enough information is available for a judgement to be made as to the key risk factors. The results of retrospectively assigning risks in this way will obviously be indicative rather than conclusive, but the patterns which emerge are reasonable. The factors for which risks have been defined are: 9 9 9

9

9

Charge: the migration of oil into the trap after the formation of the trap. Reservoir: the presence of a porous and permeable lithology. Top Seal: the presence of an impermeable lithology, stratigraphically overlying the reservoir. Lateral Seal: the presence of an impermeable lithology, stratigraphically adjacent to the reservoir. Seat Seal: the presence of an impermeable lithology, stratigraphically underlying the reservoir.

The frequencies of occurrence of each of these risks in the forty accumulations are shown

EVALUATING SUBTLE STRATIGRAPHIC TRAPS in Figure 6. The risk factors in all the accumulations have been t a k e n together and the frequency of each risk factor is sub-divided according to the number of times that factor occurs in a given accumulation. Reservoir and lateral seals are the most frequent risks. They were judged to be the key risks in accumulations with either one or two key risks. A typical accumulation, with reservoir as the single key risk, is contained in a discrete, thin shallow marine sand or reef encased in a regionally extensive source rock. As the likelihood of the reservoir being more extensive increases, or as hydrodynamic effects are introduced, the then lateral seal becomes a second key risk. Charge and top seal are the risks which occur least frequently, reflecting the presence of regional source rocks and seals. Several accumulations are judged to have four or five key risks. These are fields such as Albion-Scipio (Hurley & Budros 1990), Elk-Poca (Patchen et al. 1992) and Villeperdu (Duval 1992). They are likely to have little or no seismic expression; seals and charge are significant risks. In practice they are likely to have been discovered whilst drilling for other targets. As prospect risk is the product of these individual risk factors, it only takes one factor to have a high risk for the prospect as a whole to be high risk - the prospect is only as strong as its weakest link.

17

Estimation o f volumes The risks and volumes returned by a prospect evaluation may be very sensitive to the statistical model on which it is based. A n updip facieschange trap, for example, can be modelled in two ways (Fig. 7a). A high degree of risk can be assigned to the updip seal, with the assumption that, if this seal is effective, it will hold a substantial column. Alternatively, all risk can be transferred to the uncertainty in the column height. The resulting risks and volume probability distributions (Fig. 7b) are substantially different: the prospect would rank differently and be perceived differently by decision makers. Volume probability distributions are also highly sensitive to small changes in the input parameters (Fig. 8). If very small changes (< 5%) are made to each input parameter, the resulting volume may change by 20-30%. Volume distributions are also sensitive to intra- and interprospect dependencies. Clearly the techniques for combining geological information into a volume probability distribution are essential but can be highly misleading. Consistency is essential when ranking against other prospects but hard to achieve with new concepts. The techniques and sensitivities should therefore be understood by technical and commercial functions, and by decision makers.

Fig. 6. Frequency of key risks in forty stratigraphic accumulations. The risk factors in all the accumulations are taken together. The frequency of each risk factor is counted and sub-divided according to the number of times that risk occurs in a given accumulation. For example, reservoir is judged to be the sole risk in ten accumulations, one of two risks in a further ten and one of three risks in another ten.

18

P.E. BINNS

Fig. 7. Alternative statistical models for hydrocarbon column lengths. An example based on the Bell Creek Field, Montana (McGregor & Biggs 1970). (A) A high degree of risk can be assigned to the updip seal with the assumption that, if this seal is effective, it will hold a substantial column (Model 1). Alternatively, all risk can be transferred to the uncertainty in the column height; hydrocarbons will leak until the pressure is equal to the entry pressure at some critical point (Model 2). Column height uncertainty in this case is described by a probability distribution, tailored to the available geological evidence. In the absence of any information, this may be a uniform distribution. (B) The resulting risks and probability distributions are substantially different. They would rank differently and be perceived differently by decision makers. The irregular shape of the distribution on the left reflects the mapped outline of the Bell Creek Field.

Economic evaluation Progressing a project to c o m m e r c i a l success is an i t e r a t i v e process. A s n e w i n f o r m a t i o n is a c q u i r e d , t h e p r o j e c t is r e - e v a l u a t e d a n d a decision t a k e n as to w h e t h e r to continue. In stratigraphic trap exploration in particular, n e w

i n f o r m a t i o n and the exercise of options to react to it, m a y have a significant effect on value. Several iterations of data acquisition may be necessary before a d e v e l o p m e n t decision can be justified; e v e n then significant uncertainty m a y r e m a i n (e.g. B o o t e & M o u 2003). E x t e r n a l factors such as oil price changes, i n f o r m a t i o n

EVALUATING SUBTLE STRATIGRAPHIC TRAPS

19

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Fig. 8. The effect on a volumetric evaluation of increasing the probability distributions of all input parameters by 4% (based on the model of Fig. 7). Volume probability distributions are highly sensitive to small changes in the input parameters. The mean volume increases by 22%.

from adjacent concessions and new technology may also change value significantly. However, the commonly-used method of project evaluation assumes scenarios which are fixed from exploration through to a b a n d o n m e n t . Cashflows, discounted for the time value of money and the risk-free interest rate are estimated and summed to arrive at a Net Present Value (NPV). The discount rate is sometimes increased as a means of covering risk. This may substantially reduce project value, without the cause being readily apparent. In the simplest approach there are two scenarios, 'success' and 'failure'. A 'risked value' is derived by adding the risked values of each scenario. Other metrics such as Value/Investment ratios may be further derived and used for decision making.

It has been frequently pointed out that this approach does not represent the real world. It underestimates the value inherent in the ability to react to changing results and circumstances (for examples see Table 2). In the real world there are opportunities to limit the downside and to take advantage of opportunities to realise an upside. In practice the results of the N P V approach are often overriden if management sees a strategic value not represented in the NPV. Options Pricing and Real Options Valuation methods have been proposed as a way to put a value on this flexibility (Schwartz & Trigeorgis 2001; D i c k e n s & L o h r e n z 1996; Smith & McCardle 1999; Galli et al. 1999). In particular, R e a l Options Valuation using Decision Tree

Table 2. Examples of flexibility Proactive Flexibility Acquire new data Re-evaluate old wells Divest/acquire equity Make supply contracts Make dry/bottom hole contributions Trade data Hedge price

Reactive Flexibility To oil price change - defer/advance development To an appraisal result - change development model To an uneconomic discovery - re-negotiate terms To an economic discovery - acquire adjacent acreage; drill follow-up prospects To an adjacent downgrade - divest to competitor with ullage of more value to them To adjacent discovery or changes in infra-structure - share facilities To gas becoming economic - develop gas reserves To new technology - apply to improve profitability

20

P.E. BINNS

Analysis, appears attractive in that it offers the possibility of simulating real-world situations in a way that the fixed-scenario, NPV approach does not. Option pricing techniques, analogous to the Black-Scholes method, have been applied to oil projects. Proponents of this approach view a project as a sequence of options. By paying the 'price' of exploration a company buys the'option' to acquire undeveloped reserves: by paying the price of development a company acquires an option to receive a production cashflow. In place of stock price, alternative variables are chosen (e.g. oil price) and alternative statistical models have been proposed to describe the 'volatility' of value. The problems of applying this approach to oil and gas projects have been pointed out (Dickens & Lohrenz 1996; Rose 2001). Whereas it is possible to estimate the variance due to oil price fluctuations, the variance due to other

factors affecting the value of oil and gas assets is impossible to estimate. Decision Tree Analysis (Newendorp 1975; Smith & McCardle 1999) better represents the real world. It models the results of operations and the subsequent possible courses of action, together with possible outcomes of these actions. It thus incorporates the flexibility to react to changing results and circumstances. In exploration for stratigraphic traps, new data may significantly effect value, this approach is likely to return a higher value than the NPV approach (see example, Fig. 9). Apart from representing project value more accurately, there is value in the actual construction of the tree, in that it forces thinking about possible outcomes and alternative reactions to these. It is thus a tool for strategic thinking, providing a c o m m o n ground for discussion between disciplines.

Fig. 9. Comparison of the value returned by Decision Tree Analysis compared with that from a fixed scenario, NPV approach. The figures assume a hypothetical stratigraphic trap discovery, based on the Bell Creek Field (McGregor & Biggs 1970), but in an offshore setting. (A) The tree represents possible courses of action for appraisal and development. Costs underlined; values in light type; probabilities associated with volumetric outcomes as fractions. It is assumed, when alternative course of action are evaluated, that those with lowest value will be discarded and so no negative value is assigned to these branches. (B) Fixed scenario, NPV valuation using the same oil price and discount rate: the mean volume is taken as 100 million barrels. The risked value of $123m is substantially less than that returned by the Decision Tree valuation ($725m) and would still be lower, even if P = 100%.

EVALUATING SUBTLE STRATIGRAPHIC TRAPS

21

The data in the example in Figure 9 are also used to demonstrate the sensitivity of value to discount rate (Fig. 10). At an oil price of $25/barrel value varies from $1739 million at 0% discount rate down to $522 million at a discount rate of 12%.

varying stages of maturity. It is also implied that wells are the single, high-cost activity and result in unambiguous 'success' or 'failure'. In practice significant investments will be made in other activities: in some environments the cost of 3D seismic will exceed that of drilling; an extensive stratigraphic trap will require several wells to prove up. Prospects may not be isolated entities and their economics may be linked to, and interdependent with, the economics of adjacent prospects (Zweidler 2000; Naylor & Spring 2002). Management of an exploration portfolio is a dynamic process, involving the acquisition of information, at the lowest possible cost, on those projects which are judged to have the best chance of maturing into commercial ventures. Every company will have its own objectives, strategy, available capital and levels of risk tolerance, which will be the basis for the progression of projects. Two aspects of portfolio management are particularly relevant to stratigraphic traps: firstly the effect of including high risk prospects on portfolio metrics; secondly the application of portfolio management theory when ranking prospects, whose evaluation is based on radically different levels of information.

Conclusions

Risk mix

The value of a prospect is highly sensitive to evaluation methodology and to small changes in the input parameters. With new plays it is therefore hard to achieve the consistency essential for ranking. This is an additional reason for separating out stratigraphic prospects, based on new concepts. Decisions are naturally improved if all disciplines and decision makers share a common understanding of the geological, engineering and economic background to estimated volumes and values. When valuing a prospect, options to react to future results and events should be taken into account.

An important, and counter-intuitive, aspect of portfolio management is that a portfolio with both high and low risk prospects may be less risky than one with low risk prospects alone (Ball et al. 1998). It follows from this that an individual project can be judged, not only on its own merits, but also on its effect on the portfolio as a whole. There are well-established techniques for achieving a specified balance between risk and reward in the portfolio as a whole. The 'Efficient Frontier' technique, for example, (Ball et al. 1998; Rose 2001) optimizes a portfolio given desired levels of risk and reward. To show the effects of high risk/high reward prospects on a portfolio, numerical modelling has been carried out to compare two, 50prospect portfolios (Fig. lla). The volume probability distributions for all the prospects have been added stochastically to produce a probability distribution for each portfolio as a whole. As predicted by the Central Limit Theorem, given a sufficient number of input distributions, the resulting distributions approach a normal distribution (Fig. llb). This is clearly the case with the lower risk portfolio. In the case of the higher risk portfolio, the distribution remains skewed. The most likely total volumes to be

Fig. 10. The relative sensitivity of an evaluation to oil price and discount, using the same model as in Figures 7-9. Sensitivity to the discount rate increases with increasing oil price.

Portfolio aspects Overview

The term 'portfolio' is used both loosely to describe an inventory of potential projects and specifically to describe a set of projects, which can be ranked on some metric, or analysed together as a group. Quantitative portfolio management theory assumes that portfolio optimization will be followed by a single project execution phase. In practice, because exploration involves repeated cycles of acquiring information, a portfolio will include projects at

22

P.E. B I N N S

EVALUATING SUBTLE STRATIGRAPHIC TRAPS found by drilling each portfolio are similar but the higher risk portfolio offers the chance of significantly higher volumes and is to be preferred.

Ranking and allocation of capital A practical difficulty in applying theory arises when project evaluations are founded on varying levels of information. If the results are taken at face value then high risk/high reward prospects m a y be r a n k e d out. Stratigraphic prospects are particularly vulnerable to being discarded in this way because the risks may not be understood by decision makers, although the problem is often intuitively recognized and numerical results overridden. In addition to technical results, political, commercial and resourcing factors have to be taken into consideration in project selection. Such circumstances call for ongoing balancing of all factors, quantifiable and unquantifiable. Given these realities a more realistic approach would be to work with two separate portfolios: (1) A portfolio of 'growth options' - prospects which lack sufficient information to properly quantify risk and uncertainty. (2) A portfolio of prospects in established plays, with values based on objective, calibrated estimates. In both cases, when allocating capital, decision makers will consider the range of technical, commercial, political and environmental aspects. In the case of the growth portfolio less weight will be placed on volume and economic metrics; the objective will rather be to thoroughly understand the relative merits of all aspects of the projects: inevitably the final decision will be a value judgement. In the case of a potentially high value stratigraphic prospect, such as Safah, this would be the most reasonable course of action. More weight will be given to the metrics in the second portfolio.

23

Organization, culture and communication A n exploration company works within the context of a country's fiscal regime and the company's partnership arrangements. A n exploration team works within the context of its company's objectives, strategy, financial resources and attitude to risk. Its work is therefore influenced by organizational and cultural factors, which will affect the progression of stratigraphic projects.

Setting and achieving objectives Corporate objectives are naturally expressed in financial terms, but the way they are cascaded down and translated into technical objectives may affect their chance of success. Paradoxically, over-emphasis on quantitative methods in an attempt to ensure financial discipline and profitability may have the opposite effect if new concepts are involved. Awareness of lack of information, and focus on short term financial indicators are likely to make decision makers reject proposals to progress new concepts, even if these hold the promise of growth. Another effect of over-emphasis on quantitative methods in the absence of information arises because those competing for capital can produce overoptimistic estimates, whilst still honouring available data. The performance of an exploration department, whose job it is to produce new concepts, cannot be controlled and predicted through quantitative portfolio management. A more subtle, and longer term, effect of an excessive focus on financial ends rather than technical means, is that the contribution of geoscientists is underestimated at a time when the intellectual demands of combining seismic and geological models has never been higher. Morale is lowered and high calibre staff discouraged from joining the industry. This is not to decry quantitative techniques, which are essential for translating technical information into value. Given a sufficient number of projects, and evaluations based on objectively-derived estimates in proven plays,

Fig. 11. Comparison of two, 50-prospect portfolios based on numerical portfolio modelling with a 5000-cycle Monte Carlo simulation. (A) Number of prospects in each 'Probability of Success' class. The 'high risk' portfolio includes nine prospects with Probabilities of Success of 10% or 20%. In the 'low risk' portfolio these are replaced by prospects with Probabilities of Success of 50% and higher. Each prospect is represented by a lognormal distribution: mean volumes increase from 12-18 million barrels for the lowest risk prospects, up to 210-425 million barrels for the higher risk prospects. The portfolios are therefore diverse, both in risk and volume. (B) Comparison of the summed probability distributions (each distribution is risked). As predicted by the Central Limit Theorem, the resulting distributions approach normal distributions, but the low risk portfolio is much closer. The most likely volumes to be returned by drilling these portfolios are virtually the same but the higher risk portfolio is to be preferred as it gives the chance of an upside.

24

E E. BINNS

reasonable predictions may be possible. However, in frontier and new concept exploration lack of information must be taken into account. Inevitably, a element of pure chance will always remain: 'Businessmen play a mixed game of skill and chance.... I f human nature felt no temptation to take a chance, no satisfaction (profit apart) in constructing . . . a mine, there might not be much investment as a result of cold calculation' (Keynes 1936). Openness to n e w technical concepts Even if a company accepts high risk exploration, time and funding to progress stratigraphic prospects may not be forthcoming because the concepts are not understood by decision makers. Development of stratigraphic plays involves searching the whole 3D seismic volume and the creation of new geological models. In contrast to structural concepts, which are generally expressed as obvious features on seismic data, stratigraphic concepts are seismically subtle and rely substantially on the integration of geological reasoning with detailed, 'event level' seismic interpretation. Stability and technical f o c u s The development of stratigraphic concepts takes time and requires long-term technical focus. Flexibility is required to respond to results. An organization which is frequently changing its structure and objectives will not have the persistence necessary for success. Communication Underpinning all these factors is the need for balance and communication between technical disciplines, commercial disciplines and decision makers. Ideally, processes and systems should be transparent and their limitations and sensitivities understood by all disciplines. In addition the human biases in decision making under risk should also be understood. (Kahnemann & Tversky 2000). It is critical that all disciplines involved in capital allocation share a common understanding of new play concepts and are willing to share responsibility for what is, inevitably, a value judgment. Clearly in a large multinational it is not possible for a central planning unit to focus in detail on all prospects. It is possible though to focus on the relatively small number of projects in the high risk/low information category. A company with a smaller portfolio does not have the advantage of a large, diversified portfolio to reduce risk but is

perhaps in a better position to examine new concepts in depth.

Conclusions - progressing subtle stratigraphic traps Given that high risk projects fit a company's strategy, what is required to enable more subtle stratigraphic prospects to be progressed? (1) Resource and encourage a dedicated geoscience effort to match subtle features in the 3D seismic volume with depositional, diagenetic and hydrodynamic models. Recognize that play concepts must be geologically sound and that this involves intensive work. The corollary to this is that geoscientists are given a thorough grounding in sedimentary geology and the characteristics of stratigraphic and combination traps and their subtle seismic expression. (2) A separate 'Portfolio of Growth Options'. Recognize that risk ~,nu-J uncertainty are dependent on available information and set aside a portion of the exploration budget to fund the progression of subtle prospects, whose high risk is due to lack of information. Part of this budget may be needed for high capital expenditure on seismic and drilling. De-risking without drilling can only be taken so far but there are also opportunities through the re-evaluation of existing wells. If drilling alone is required to progress prospects opportunities may be better pursued onshore. The dynamic and constantly-changing nature of the evaluation process must be recognized. There must be a willingness to invest in information and to constantly re-evaluate opportunities as new information comes in. (3) A formal and rigorous system for progressing and evaluating prospects. There is clearly scope for replacing 'serendipity' with systematic search and evaluation procedures which are recognized and understood by decision makers. Ideally a system should serve as a focus for discussion between geoscientists, the commercial function and decision makers, helping to raise the level of debate. It should be as much a strategy tool as an evaluation tool and should be transparent and not include complex 'black boxes'. All involved need to understand the process of 'translating' geological information into risks and values and to understand the limitations to estimating risk in the absence

EVALUATING SUBTLE STRATIGRAPHIC TRAPS of i n f o r m a t i o n . T h e s y s t e m s h o u l d h a v e e n o u g h r i g o u r to be r e s p e c t e d by investors c o n c e r n e d a b o u t o v e r e s t i m a t i o n . Excessive emphasis on financial indicators is to be a v o i d e d a n d all aspects of a project should be addressed. (4) The organization and evaluation systems should be stable over sufficient time to allow statistical effects to w o r k and lookback experience to take effect. F r e q u e n t reo r g a n i z a t i o n s p r e v e n t this a n d d i v e r t attention a w a y f r o m the technical process. I would like to thank GeoArabia for permission to reproduce Figure 3 and D. Boote for a discussion on the Safah paper and for supplying the original Figure. Shell Nigeria Exploration and Production Company and its partners gave permission to reproduce Figure 4. I would also like to thank the reviewers, J. Craig and A. Law, for their comments.

References AYERS, W.B. 2002. Coalbed Gas Systems, Resources, and Production and a Review of Contrasting Cases from the San Juan and Powder River Basins. Bulletin American Association of Petroleum Geologists, 86, 1853-1890. BALL, B., SAVAGE, S. &; WARNER, T. 1998. Portfolio Thinking: A View from the Top. In: Integration of Geologic Models for Understanding Risk in the Gulf of Mexico, American Association of Petroleum Geologists Hedberg Research Conference. BARDOSSY, G. & FODOR, J. 2004. Evaluation of Uncertainties and Risks in Geology. Springer-Verlag, Berlin. BEAUMONT, E.A. &; FOSTER, N.H. 1990. Stratigraphic Traps I. American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields. BEGG, S.H., BRATVOLD,R.B. & CAMPBELL,J.M. 2001. Improving Investment Decisions Using a Stochastic Integrated Asset Model. Society of Petroleum Engineers, Annual Technical Conference, New Orleans (SPE71414). BERLEANT,D., CHEONG,M., CHU, C. GUAN,Y. KAMAL, A. FERSON, S. & PETERS, J.E 2003. Dependable Handling of Uncertainty. Reliable Computing, 9, 1-12. BOOTE, D.R.D. & Mou, D. 2003. Sarah Field, Oman: Retrospective of a New-concept Exploration Play. GeoArabia, 8, 367--430. CHAPIN, M., BRENTJENS, E. & BLAAUW, M. 2002a. Integrated Seismic and Subsurface Characterisation of Bonga Field, Offshore Nigeria. The Leading Edge, 21, 1101-1131. CHAPIN, M., HINCHEY, J., BLAAUW,M. & VARLEY, C. 2002b. Bonga Field Development, Offshore Nigeria - a Deepwater Giant. Bulletin American Association of Petroleum Geologists', 86, 13. CHARPENTIER,R.R. & COOK,T. 2004. Conventional and Continuous Accumulations: a Spectrum, Not

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a Dichotomy. American Association of Petroleum Geologists. Annual Convention, Dallas, Texas. CLARKE, J.W. & KLESHCHEV, K. 1992. DauletabadDonmez Field - Commonwealth of Independent States (Former USSR). In: FOSTER, N.H. & BEAUMONT, E. (eds) Stratigraphic Traps IlL American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, 285-300. CuI, W. & BLOCKLEY,D.I. 1990. Interval Probability Theory for Evidential Support. International Journal of Intelligent Systems, 5, 183-192. CURTIS, J.B. 2002. Fractured Shale-gas Systems. Bulletin American Association of Petroleum Geologists, 86, 1921-1938. DEMIs, W.D. 1992. Elkhorn Ranch Field - U.S.A. Williston Basin, North Dakota. In: FOSTER, N.H. & BEAUMONT,E.A. (eds) Stratigraphic Traps IlL American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, 369-388. DICKENS,R.N. & LOHRENZ,J. 1996. Evaluating Oil and Gas Assets: Option Pricing Methods Prove No Panacea. Journal of Financial and Strategic Decisions, 9, 11-19. DUVAL, B.C. 1992. Villeperdu Field. In: HALBOUTY, M.T. (ed.) Giant Oil and Gas Fields of the Decade. American Association of Petroleum Geologists, Memoir 54, 251-263. FOSTER, N.H. & BEAUMONT,E.A. 1991. Stratigraphic Traps IL American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields. FOSTER, N.H. & BEAUMONT,E.A. 1992. Stratigraphic Traps III. American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields. GALLI, A.G., ARMSTRONG, M. & JEHL, B. 1999. Comparison of Three Methods for Evaluating Oil Projects. Journal of Petroleum Technology, October, 44-49. GHOSH, D., BLUM, M., ADESANYA, S. & TIJHOF, H. 1998. Impact of 3D and AVO Technology to Exploration Efforts in Deepwater Nigeria. Bulletin American Association of Petroleum Geologists, 82, 1917. HALBOUTY, M.T. 1969. Rationale for Deliberate Pursuit of Stratigraphic, Unconformity and Paleogeomorphic Traps. Bulletin American Association of Petroleum Geologists, 53, 3-29. HALBOUTY, M.T. 1970. Geology of Giant Petroleum Fields. American Association of Petroleum Geologists, Memoir 14. HALBOUTY,M.T. 1980. Giant Oil and Gas Fields of the Decade: 1968-1978. American Association of Petroleum Geologists, Memoir 30. HALBOUTY, M.T. 1982. The time is now for all explorationists to purposefully search for the subtle trap. In: HALBOUTY,M.T. (ed.) The Deliberate for the Search Subtle Trap. American Association of Petroleum Geologists, Memoir 32, 1-10. HALBOUTY,M.T. 1991. East Texas Field - U.S.A. East Texas Basin, Texas. In: FOSTER, N.H. &

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BEAUMONT, E.A. (eds) Stratigraphic Traps IL American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, 189-203. HALBOUTY,M.T. 2003. Giant Oil and Gas Fields of the Decade 1990-1999. American Association of Petroleum Geologists, Memoir 78. HALL, J.W., BLOCKLEY,D.I. & DAVIS,J.P. 1998. Uncertain Inference Using Interval Probability Theory. International Journal of Approximate Reasoning, 19, 247-264. HUBBERT, M.K. 1953. Entrapment of Petroleum Under Hydrodynamic Conditions. Bulletin American Association of Petroleum Geologists, 37, 1954-2026. HURLEY, N.E & BtJDROS, R. 1990. Albion-Scipio and Stoney Point Fields - U.S.A. In: FOSTER, N.H. & BEAUMONT, E.A. (eds) Stratigraphic Traps L American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, 1-37. HURST, A. 2003. Sand Injectites: an emerging play or something to be avoided. 6th Petroleum Geology Conference, North West Europe and Global Perspectives, London. KEYNES,J.M. 1936. The General Theory of Employment, Interest and Money. In: The Collected Writings of John Maynard Keynes. The Royal Economic Society 1973, MacMillan Press Ltd., London. KEYNES,J.M. 1937. The General Theory of Employment. The Quarterly Journal of Economics, 51, 209-223. KEITH, B.D. & WICKSTROM,L.H. 1992. Lima-Indiana Trend - U.S.A. Cincinnati and Findlay Arches, Ohio and Indiana. In: FOSTER, N.H. & BEAUMONT, E.A. (eds) Stratigraphic Traps III. American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, 347-365. KAHNEMAN,D. & TVERSKY,A. 2000. Choices, Values and Frames. Russell Sage Foundation and Cambridge University Press, New York and Cambridge. KNIGHT, EH. 1921. Risk, Uncertainty and Profit. 7th Edn, reprinted 1948. The London School of Economics and Political Science. LAW, B.E. 2002. Basin-centred Gas Systems. Bulletin American Association of Petroleum Geologists, 86, 1891-1919. LEVORSEN,A.I. 1936. Stratigraphic Versus Structural Accumulation. Bulletin American Association of Petroleum Geologists, 20, 521-530. LEVORSEN, A. 1966. The Obscure and Subtle Trap. Bulletin American Association of Petroleum Geologists, 50, 2058-2067. MACKAY, J.A. 1996. Risk Management in International Ventures: Ideas from a Hedberg Conference. Bulletin American Association of Petroleum Geologists, 80, 1845-1849. MCGREGOR, A.A. & BIGGS, C.A. 1970. Bell Creek

Field, Montana: a Rich Stratigraphic Trap. In: HALBOUTY, M.T. (ed.) Geology of Giant Petroleum Fields, American Association of Petroleum Geologists, Memoir 14. NAYLOR, M.A. & SPRING, L.Y. 2002. Exploration Strategy Development and Performance Management: a Portfolio-based Approach. The Leading Edge, 21, 159-167. NEWENDORP, ED. 1975. Decision Analysis for Petroleum Exploration. Petroleum Publishing Company, Tulsa, Oklahoma. PATCHEN, D.C., BRUNER, K.R. & HEALD,M.T. 1992. Elk-Poca Field - U.S.A. Appalachian Basin, West Virginia. In: Foster, N.H. & BEAUMONT, E.A. (eds) Stratigraphic Traps IlL American Association of Petroleum Geologists Treatise of Petroleum Geology, Atlas of Oil and Gas Fields, 207-230. PEERSMANN,M.R.H.E. & FLORIS, EJ.T. 1998. E & P Decision Support Systems for Asset Management. In: Integration of Geologic Models for Understanding Risk in the Gulf of Mexico. American Association of Petroleum Geologists Hedberg Research Conference. RITrENHOUSE, G. 1972. Stratigraphic-Trap Classification. American Association of Petroleum Geologists, Memoir 16, 18-32. ROSE, ER. 2001. Risk Analysis and Management of Petroleum Exploration Ventures. American Association of Petroleum Geologists, Methods in Exploration Series, No 12. SKALOUD,D.K. & CASSIDV,E 1999. Exploration of the Bonga and Ngolo Features in the Deepwater Nigeria. Bulletin American Association of Petroleum Geologists, 80, 1340. SCHWARTZ,E.S. & TRIGEORGIS,L. 2001. Real Options and Investment Under Uncertainty. The MIT Press, London, England. SCI-IUTrER, S.R. 2003. Hydrocarbon Occurrence and Exploration in and Around Igneous Rocks. In: PETFORD,N. & MCCAFFREY,K.J.W. (eds) Hydrocarbons in Crystalline Rocks. Geological Society, London, Special Publications, 214, 7-33. SMITH, J.E. & MCCARDLE, K.E 1999. Options in the Real World: Lessons Learned in Evaluating Oil and Gas Investments. Operations Research, 47, 1-15. STOKER, S.J., HAILE, P., GRAY, J.C., ANDREWS,I.J. & CAMERON,T.D.J. 2006. The importance of stratigraphic plays in the undiscovered resources of the UK Continental Shelf. In: ALLEN,M.R., GOFFEY, G.E, MORGAN, R.K. & WALKER,I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 153-168. ZWEIDLER, D.C. 2000. Geological Models, Development Scenarios and Portfolio Management: an Integrated Approach to Opportunity Evaluation. Bulletin American Association of Petroleum Geologists, 84, No. 13 (supplement).

Appropriate creativity and measurement in the deliberate search for stratigraphic traps G. P. C I T R O N 1, J. A . M A C K A Y

1 & R R. ROSE 2

1Rose & Associates, LLP, 4203 Yoakum Blvd., Suite 320, Houston, T X 77006 USA (e-mail: garycitron@roseassoc, corn) 2Rose & Associates, LLP, 3405 Glenview Avenue, Austin, T X 78703 USA Abstract: Global exploration over the past decade has been characterized by fewer large fields discovered relative to the previous decades, while the commercial success rate has remained constant at about 25%. Amidst the shrinking resource base, demand remains robust, thus signifying the clear need for enhanced efficiency in the deliberate search for stratigraphic traps. Recent analyst reports substantiate the need for a re-invigorated exploration role to profitably replace production, rather than an over-reliance on acquisitions. To meet this need, explorers are required to serve three main roles which, at times, may conflict with each other. First, they must be creative, to conceptualize and envision subtle traps. Second, they must measure them in a responsible, professional fashion for the benefit of the shareholders. Third, they must communicate the uncertainty and probability aspects associated with their characterization of the opportunity in a clear fashion to facilitate more informed decision-making and more predictive portfolio management. We attempt to facilitate and enhance the renewal of the exploration role with lessons we have learned from the fields of systematic risk analysis of geologic trends, also known as play analysis, lessons from economics and risk aversion, and lessons from the analysis of complex traps. Having observed firsthand how leading E&P companies are conducting their global exploration programs, we want to begin by reviewing some key aspects of creativity and measurement needed for 'new-play' exploration and, in particular, how it applies to the search for stratigraphic traps. Starting with some background perspective on the exploration business, we focus on the importance and subsequent reaffirmation of the exploration role, and conclude with a number of lessons, or insights, to take away that we hope will inspire and assist in their deliberate searches for stratigraphic traps. These insights represent best practices we have observed in client companies, on creativity and opportunity-measurement in the pursuit of viable, profitable exploration opportunities. Our information regarding the status of exploration comes courtesy of some global databases and some recently published analyst reports. These published reports support our contention that the exploration role needs to continue its renewal, and contribute more significantly to profitable production replacement relative to property acquisitions. The path towards profitable production replacement often begins with the creativity provided by the exploration team associated with evaluating or generating new play concepts. Creativity at the regional level benefits by approaching subtle trap exploration through probabilistic play analysis. In this context, regional geological analyses can better pinpoint the critical elements, and systematically search for the footprint of active migration pathways provided by hydrocarbon shows. Explorers should take full advantage of thought-experiments that pose both outlandishly successful and embarrassingly meagre results (including failure) to promote characterization of the full range of outcomes consistent with the inherent uncertainty, and the likelihood of achieving various success states. These regional efforts can then be integrated with the appropriate discount rate for a company's economic valuation system. We also share some lessons learned regarding the business realities of a company's dry hole tolerance to better plan for interim learnings and exit strategies. Similar considerations and open discussion of a company's risk tolerance can lead to more appropriate diversification in the critical plays needed to achieve a business plan. We also review chance-dependency issues among prospects and leads in plays. In particular, we note that measurement of subtle traps often requires special attention to the geological phenomena that indicate internal parameter dependencies and changes in the probability profile that need to be perceived, calculated and communicated for complete characterization of given opportunities. The more consistency and calibration that is achieved in prospect characterizations, the more predictable a company's portfolio will become.

From: ALLEN,M. R., GOFFEY, G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 27-41. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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G. E CITRON ETAL.

Status of exploration Supply Over the last century, discovered resources (Fig. 1) steadily climbed through the decade of the 1960s, and then began an even more precipitous fall as increasing technology and process applications struggled against the backdrop of decreasing exploration opportunities. Note that the decline in ultimately recoverable reserves continued in the 1990s decade, even though very substantial areas for international exploration became available, with the end of the Cold War, and through deepwater development technologies. As the industry applied improved technology, however, the commercial success rate for the last 4 decades did not vary much from around 25% as the industry apparently sorted through a relatively limited set of opportunities. In our current decade, though, with increased focus on seismic amplitude related prospects, the commercial success rates appear to be higher, at about 40% (Pete Stark, IHS, pets.

comm.). As we look at the sizes of discoveries across the last 4 decades (Fig. 2), we clearly see a decline in the number of 'elephants' (> 500 M M B O E (Millions of barrels of oil equivalent)) discovered. However, there still appear to be a healthy proportion of moderately-sized discoveries being made. In the 1980s and 1990s about 35% of the 'elephants' were stratigraphically trapped, up from about 15% in the 1960s and 1970s (Binns 2006).

The median (P50 value) field size remained fairly constant since the 1950s at about 5 MMBOE, while the mean (average) size of fields discovered dropped precipitously from the heyday of the 1960s, but shows an encouraging upturn in the last decade to about 60 M M B O E (Fig. 3). Note also that the number of giant discoveries - those of a billion barrels or more - peaked in the 1960s, and has been declining steadily to about the same levels as we saw in the 1920s and 1930s.

Demand Yet amidst the decline in petroleum resources discovered, the demand for world energy (Fig. 4) is forecast to rise continually into the 22nd century, with oil and natural gas probably filling more than 50% of that demand over the next few decades. This strong world demand for crude oil and natural gas should likely continue as far ahead as we foresee. In fact, you might say that petroleum geoscientists, engineers and managers are 'buying time' for alternate energy sources to come on stream. If there is an extended supply shortfall, the negative consequences to the world economy and geopolitical stability are sobering indeed.

Challenge Thus, the stage is set. Amidst a declining resource base and robust onward demand, our capital, creativity and

Fig. 1. Discovered resources by decade (courtesy IHS). (BBOE, Billions of barrels of oil equivalent.)

APPROPRIATE CREATIVITY AND MEASUREMENT

29

Fig. 2. Histogram of discovery size by decade (courtesy IHS).

Global Field Sizes and Numbers

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30

G.P. CITRON E T A L .

Fig. 4. Global energy demand is forecast to increase steadily, with about half needed to be supplied by oil and natural gas (from Edwards 1997).

ability are challenged to convert ideas to profitable oil and gas production. In meeting this challenge, exploration is buying precious time for the development of alternative sources. We have the capital and the ability. The main questions are: 9 9

Can we mobilize the creativity and the will to do so? Can we explore and discover efficiently?

Conferences such as this one are important generators of ideas, creative inspiration, and motivation for our business of exploration. Think of that business as a series of decisions under (hopefully) decreasing uncertainty, designed to profitably grow a company's reserve base. To make the best decisions, we need to clarify the exploration role.

Reaffirmation of the exploration role There is a growing reaffirmation t h a t exploration is clearly one of the crucial functions required to meet the challenges ahead. Let's take a look at how recent business performance indicates that reinvestment in exploration is vital to the health of our industry.

Wood Mackenzie (2003) and Deutsche Bank (2003) recently collaborated to report on the business performance of companies' exploration and acquisition efforts over the threeyear period 2000-2002. Figure 5 plots profitable production replacement by exploration discoveries (x axis, 'organic') against annualized replacement of production via profitable acquisition (y axis) during the three-year period. The bold vertical and horizontal lines indicate 100% production replacement by organic exploration or acquisition, respectively. For example, company A replaced about 150% of its annualized production during 2000-2002 from acquisitions, but only about 30% via organic exploration in 2002. On the other hand, two companies plotted adjacently (B) replaced about 60% of their production through acquisitions, and about 120% through organic exploration. Of the 11 companies shown, three failed to replace production by either route. Only one company replaced production via acquisition. However, seven companies replaced production through organic exploration. This signals the need for more companies to renew their exploration efforts.

APPROPRIATE CREATIVITY AND MEASUREMENT

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Fig. 5. Production replacement by exploration versus production replacement by the 2000-2002 annualized acquisition efforts for 11 major oil companies (from Deutsche Bank AG 2003).

As Wood Mackenzie (2003) notes, spending more on acquisitions may not be the answer to the call for increased earnings year after year, especially with oil prices now near a 15-year high. There appears to be a limit on the viability of profitable acquisition-dominated strategies. JPMorgan (2003) shares this concern (Fig. 6). The mid-capitalization companies they routinely follow that have dominant acquisition-led strategies showed that their valuecreation rarely outpaces their cost of capital (which we infer to be about nine percent). Marko (2000), in a wake-up call report, expressed concern that the industry has so overfocused on cost cutting that value-creation may have now become a lost art. As flattering (or perhaps as ominous) as it sounds, sustained exploration - that is, building petroleum resource growth at a profit- has been a major contributor to the improving standard of living of most of the world during the 20th century. According to past A A P G President Ray Thomasson: 'Industry is recognizing that in order to grow, they need to re-focus on exploration.' For this endeavor to be successful,

profitable and sustained, we need to practice three key exploration values: creativity, measurement, and respect for the investor. Here is how those values translate to the roles we accept as E&P professionals: First, we need to be creative in generating the new exploration concepts and opportunities, involving pattern recognition, perceptive geoscience and informed intuition. Those are mostly right-side brain functions. Second, but simultaneously, we must practice responsible measurement and preservation of our estimates for effective portfolio management and the long-term benefit of our shareholders. These tasks are generally considered to be left-brain functions. There is a healthy dilemma created by the first two roles. It's hard to have the left and right side of the brain simultaneously work in concert. This is one reason why many companies have chosen to engage prospect review teams at the portfolio level. These teams are chartered to provide feedback, mentoring and suggestions on measurement techniques (reality checks, appropriate analogs, techniques applied by other teams, failure-mode analyses) and post-audit reviews based on the creative work presented.

32

G.P. CITRON ETAL.

Value Creation 10

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Fig. 6. Annualized shareholder value creation for large independent oil companies. The y-axis is defined as current share price percentage above (or below) the 5 year volume weighted daily average price, reported on a compound annual growth rate (CAGR) basis (from JP Morgan 2003).

Third, in order to have informed decisionmaking and clear portfolio processes to deliver on our promises, we need to demonstrate better communication to our decision-makers and leadership of both the creative and measurement aspects of our work.

Lessons learned We have a few lessons, or insights that may help in this regard. We review these insights in the hope that they make work more interesting and productive. They come from the fields of play analysis, economics and risk aversion, and complex trap analysis. W h y play analysis? Play analysis is the consistent, systematic fullcycle economic evaluation of groups of genetically-related leads, prospects and producing fields in a geological trend. Plays can be objectively assessed for reserves, chance of success and net present value, just as prospects. While incredibly valuable in helping companies differentiate better from lesser plays, there has been,

in the past, an alarming lack of discipline in applying this type of analysis. Because of this lack of discipline, almost every major company has its share of horror stories. For example, in one large company, the chairman once thought out loud in his conference room, 'Wouldn't it be nice if we owned acreage on the Arabian Peninsula?' While only brainstorming to generate discussion, his words were misinterpreted as a directive. Within weeks, this company had its best negotiators in the capitols of Oman and Yemen doing what they do best: negotiating concession terms! As a result of the reversal and distortion of the exploration work process, they returned with very favorable terms on largely nonprospective acreage - as well as long-term commitments that set this company's profitmaking potential back several years! Most seasoned explorationists can relate analogous disastrous play campaigns that arose from superficial, poorly sequenced analysis or misplaced incentives. Because of the lack of a valid play-analysis process, many companies have suffered from poor return on invested time and money; missed opportunities to participate

APPROPRIATE CREATIVITY AND MEASUREMENT in good plays, typically because of the lack of a comprehensive comparative analysis; and the advantage gained by competition by not having you as a competitor in those better plays, thus solidifying their position as preferred partner by the host countries for repeat business.

Selecting plays is a key exploration decision Not surprisingly then, selecting 'plays to pursue' is the key exploration decision - not 'which prospect to drill.' Figure 7 shows rough estimates provided by Conoco in the mid 1990s, and plotted on a logscale, of the capital necessary to detail a prospect with seismic data, drill various types of prospects, and properly execute exploration of a new play (shooting seismic programs, concession costs, overhead, drilling, etc). The vast of amount of money, time and staff potentially committed means that plays deserve rigorous analysis, hopefully tied to company strategy. We note that companies with sustained good exploration performance tend to manifest the key attributes of broad-gauge geological basin and trend analysis, in other words, distinctive use of play analysis. By this, we mean integration of regional data, and interpretations of those data that are tied to the risk elements of the petroleum system. Skilled play analysts utilize recent discovery data, arrayed as field size distributions, as a predictive tool. Furthermore, they are able to translate the engineering

33

efforts necessary to explore the trend into a coherent economic evaluation of the trend. Disciplined estimation of costs, timing, and prices means that plays that they undertake have a high probability of performing much as anticipated. Skilful estimation of uncertain parameters is equally as important for engineers as it is for geoscientists!

Binomial probability in the petroleum system A powerful take-away from play analysis is the communication that arises in determining how many consecutive dry holes your company would tolerate in exploring a play before abandoning that effort. That number of trials is referred to as the dry hole tolerance (DHT). As a company is willing to accommodate more chances (and test the independent factors) to drill a discovery that covers sunk and pointforward costs (i.e. an economic discovery), the probability of achieving that threshold actually increases, but can never exceed the probability that the play actually exists (e.g. the play chance). There are, of course, limits to this formula as previous company forecasts of prospect success rates (PSR) less than 20% have rarely been proven to be calibrated (Citron et al. 2002). Thus, in cases where the PSR is less than 20%, a company should always ask 'has this population of prospects in our last few years' portfolios actually delivered a success rate of

Fig. 7. Range of monetary investment needed to properly define a prospect from a seismic program, drill a prospect and properly explore a Play. Note that the x-axis is logarithmic.

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about 10% (the mid-point of the 0-20% range)?' This communication is designed to generate a key metric in play analysis, the program Pe (Fig. 8), defined as the probability that your exploration program will yield at least one full-cycle economic discovery after a certain number of trials, specified by the D H T (and also referred to as the dry hole program). Because of the success and failure probabilities contained in the formula, the equation falls within the family of binomial probability expresssions. Play chance is the chance the play exists, dealing largely with dependent chance factors that may be shared by all prospects in the play. Prospect success rate (PSR) deals with the prospect-specific characteristics in the play, and represents the percent of prospects in the play that would yield discoveries that would flow hydrocarbons, given that the play actually does exist. The diagonal line on the cumulative log-probability graph in Figure 8 represents the forecast rcsourcc . , ~ . u size distribution (FSD) for the play, and the m i n i m u m economic field size (MEFS) needed that would generate a PV > O, when fully burdened by the costs associated with the discovery well (such as seismic surveys, overhead, and concession costs). The projection of the MEFS from the FSD to the cumulative

ETAL.

probability y-axis determines the PMEFS, or the percent of that FSD that would be considered 'economic' in a full-cycle sense. This portion of the FSD is used to generate the success case value distribution of a play. Note how Program Pe has the D H T as an exponent, which dictates that this n u m b e r contributes a strong influence in the calculation. Indeed, this represents a powerful communication tool that can help your m a n a g e m e n t appreciate how many trials are appropriate in your play. Continually remind your staff that play exploration should be leveraging and updating the play analysis with the geotechnical learnings that arise from drilling within the 'dry hole program.' Let's use a simple example illustrated in Figure 9. When we graph the Program Pe versus the DHT, with the Play Chance at 0.6 and the PSR at 0.2, we note two points on the lowest curve. First, we can communicate to decision makers the dramatic increase in program Pe from 11% to 28% - with just a small increase in DHT, say between 2 a^-. u"~6. W e al~u ~'- ^ note that the curve becomes asymptotic to the play chance since the program Pe can never exceed the chance that play actually exists. Perhaps with some effort in studying a shared element indicated by hydrocarbon shows in this play, we might either c o n d e m n the play, or

Fig. 8. The program Pe relates the probability that a play will yield a full-cycle economic discovery after a prescribed number of independent trials. Play chance, prospect success rate (PSR), the number of dry holes tolerated (DHT), and the probability location of the minimum economic field size (MEFS) are required inputs. The MEFS is posted as a vertical line on the forecast field size distribution (FSD) for the play, and is read off the y-axis as the Pmefs.

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Fig. 9. Program Pe versus the number of dry holes tolerated, illustrating the benefit of sequential learning in a

play.

improve play chance, thereby demonstrating enhancement to the program Pe (as represented by the middle curve), well before we address notoriously prospect-specific factors such as reservoir, closure, or containment. Then, after perhaps some consideration of the independent (or local) aspects in the play, such as improvements forecast from anticipated seismic resolution for the trend, it is possible to drive the program Pe even higher. Unlike prospect analysis, in which all probabilities record a 'snapshot in time' - the knowledge that justified the decision to drill - there is a temporal aspect to play analysis. It is important to note that, with each additional item of significant new data, chance of success and reserves potential can be expected to change. While every trend is unique, at each step, the exploration process typically requires a series of decisions: 'Shall we add or reduce our equity position in the play area?' and/or 'Shall we acquire additional information?' Note how conducive this type of analysis is to examining exit strategies.

'Power of thought' exercises There is a figure in American folklore known as Rip Van Winkle, an early Dutch homesteader in the Catskill Mountains, who in the 1770s fell asleep for 20 years. When he awoke, with flowing white hair and long scraggly beard, he was amazed at all the changes he observed. Ed Capen utilized this concept when he introduced power-of-thought exercises to Arco and the industry. Imagine trying this approach with your Play scenario: It's 20 years hence, and you are flying over the Play fairway you analysed, amazed by the mature development of producing infrastructure - well heads, tank batteries, flow lines, equipment yards - built to accommodate the fabulous success of your play. With such a thought-provoking scenario, ask your team: 'What elements of the geology or geotechnology were operative to contribute to that SUCCESS?'

Now, turn the situation around; go through a contrasting scenario of abject failure. Ask the team to explain the catastrophic outcome as well. Can they imagine these extreme

G.P. CITRON ETAL.

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outcomes? If so, where do they fit into their probabilistic assessment? Are their probabilistic envelopes wide enough? Are yours? Also remember to place your patternrecognition skills, as well as your analytical thinking, to work on the analysis of often subtle oil or gas shows, which, in effect, represent the footprint, or migration pathways, of hydrocarbons moving in the host rocks of the play. This is always a great starting point to help analyse the petroleum system, paying attention to the kitchen, and its exit routes to obvious or subtle traps.

Balanced risk behaviour Play analysis helps companies get things about right, so that stupid mistakes can be avoided. A balanced approach has best served companies to profitably grow (Fig. 10), since it tends to avoid overly passive or simplistically aggressive approaches. Overly passive behaviour can 'bleed' and diffuse a company's efforts. In this mode, very few people are assigned to cultivate new trends, those people that are assigned to regional efforts typically have too many trends to examine, and the review of such efforts tend to be micromanaged. As a result, few commitments are made, resulting largely in the loss of valuable staff time. At the other end of the spectrum, we see 'make or break' risk-seeking behaviour. In this

mode, there tends to be an over-reliance on too few trends, possibly overstaffed, with very few pre-determined milestones or management reviews. Unfortunately with this attribute combination, there is little attention to an appropriate dry hole tolerance and a tendency towards over-commitments without substantive learning. Play analysis, when conducted with distinction, is balanced, and offers the greatest probability for profitable growth. There is a concerted effort to evaluate a number of plays in a reasonable time frame that can potentially contribute to the company's goals. Reviews are timely and commitments are phased and commensurate with the company's stated risk tolerance. Rather than becoming repeated victims of the same old mistakes, companies with a balanced approach to play analysis capitalize on information archival and integrate company learnings to determine which trends need to be expanded and which plays need to be exited.

Economics and risk aversion In Figure 10 we reference overly risk-averse and risk-seeking behavior in play analysis. Understanding risk aversion leads to better management of the needed capital exposure, the determination of the appropriate discount rate for your company, and ways to diversify company portfolios with appropriate interest in joint ventures.

Characteristics of Different Risk Behaviours Passive Balanced Aggressive One on all (watch and wait)

Basket of selected opportunities

All on one

No commitment (each step contingent)

Commitment in phases optimized # of tries

Commitment to as many tries as it takes

Review/decision at each step

Review/decision at each phase

No review

Minimize cost to fail

Minimize cost to succeed (plan to win)

Minimize tries (spend to win)

(plan to fail)

Fig. 10. Balanced risk behaviour, as compared to risk-averse behaviour in the left column and risk-seeking behaviour in the right column, seeks to grow a company at a sustainable rate.

APPROPRIATE CREATIVITY AND MEASUREMENT Whenever possible, always select the lowest possible discount rate for your company. While this number is usually pre-determined by the CFO's office, rather than the E&P senior VP, be aware that discount rates that exceed a company's average weighted cost of capital actually discriminate against the exploration needed to grow a company because they disproportionately jeopardize the value of 'out-year' cash flows. High discount rates are the enemy of successful play analysis. Elevated discount rates are not an acceptable proxy for risk which is properly handled via expected value, portfolio diversification, and risk-aversion methodologies. The under-utilized field of risk aversion teaches us that there are ways to determine, for every venture, the appropriate equity position to target for your company, depending upon c o m p a n y budget. Believe it or not, this is superior to the 'feels about right' determination that often occurs in high level m a n a g e m e n t decisions and negotiations. The optimum working interest (OWI) is that share in a venture which maximizes the riskadjusted value of that opportunity (Fig. 11). As you can see from the formula, there is nothing exotic about the inputs, except for a company's risk tolerance (RT). This number, reported in millions of currency units is typically closely related to a company's exploration budget. To get an idea of your

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company's RT, imagine that anticipated capital cost at which your management says, 'Let's get a partner for this, it's too risky for us at 100%.' For many risk-balanced companies, RT turns out to be roughly a fifth of their annual exploration budget. C o m p l e x trap analysis: d e p e n d e n c y a n d variance Our last set of insights comes from analysis of complex prospects, where we focus on geological p h e n o m e n a that could create dependency between prospect areal extent and reservoir thickness. Imagine a stratigraphic trap in cross-section, perhaps with a slight roll-over near the structural high point (Fig. 12). Here, the exploration team can make a clear case that, as the prospect area increases, the effective net reservoir thickness almost certainly increases as well. If each dimension increases proportionately, we say that reservoir thickness is to some degree dependent upon area. Let's examine the impact on the reserves distribution. First, let's examine the input distributions of area and net reservoir thickness (Fig. 13), and note that the P10/P90 ratio of each is 10. Multiplying these input distributions gives us an impression of the reserves potential (Fig. 14). Dependence always increases the variance, or dispersion of the product output distribution,

Fig. 11. Graph of risk adjusted value (RAV) versus working interest for a venture. RAV is the chance weighted value for an opportunity discounted by a company's or decision maker's utility, or risk aversion. RAV = -RT*In[Pc*e(-ewRT) + (1--Pc)*e(C/RT)]where RT = company's risk tolerance, in millions of dollars; PV = net present value of the opportunity, in millions of dollars; Pc = probability of commercial success (decimal), c = cost of the opportunity, in millions of dollars (from MacKay 1995).

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Fig. 12. Cross-section of a hypothetical stratigraphic trap, with areal extent and thickness axes.

relative to the same calculation without any dependence in the system. In the case where the thickness distribution is totally independent of the area distribution, the resulting product (labelled 0% dependent) has a P10 of about 50 000. In the case where the thickness distribution is totally dependent on the prospect area distribution, the resulting product has a P10 of 100 000, and is shown by the line with the greater slope. On each, the circle represents the average or mean (often referred to as the expectation) of each line. The mean in the dependent case is more than twice as great as the mean of the i n d e p e n d e n t case, which arises from the

increased dispersion expressed here with the flatter slope. In other words, in the totally dependent case, your computer software takes the P10 of the thickness and forces it to be multiplied by the P10 of the area and places the product at the P10 of the output distribution. In the independent case, you never know, a priori, what percentile of the thickness can be matched with the P10 area. Mathematically, in the independent case, the product of two P10 values falls at about the P4 of the product, leaving little room for higher upsides or lower downsides. Any specified partial dependency between area and thickness would result in a product distribution line with the same median, falling somewhere between the lines representing the ends of the dependency spectrum (total or zero dependence). Dependence always increases the variance, or dispersion, of the product output distribution, often dramatically, relative to the same calculation without any dependence in the system. Thus, we need to clearly articulate the geological p h e n o m e n a to properly characterize the reserves distribution.

Complex trap analysis: when chance elements change with prospect scope Our last insight concerns the chance assessment of this stratigraphic trap as we investigate how large it can be (Fig. 12). Let's assume that the reserves associated with the small four-way

Fig. 13. Plot of the thickness and area distributions of stratigraphic trap in Figure 12, plotted on a cumulative log-probability graph.

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Fig. 14. Distribution of the area x thickness product, considering both 100% dependence and 0% dependence between the input distributions. Note how the slope and mean of the dependent case are greater than the independent case. closure falls short of the current commercial threshold. Moreover, the chance elements change with the scope of the prospect. In this case, as the prospect gets bigger, we are concerned that another nearby sand body may shingle onto the prospect, creating a possible seal breach. If the chance elements change across the full range of prospect outcomes, as they do here (larger outcomes have a decreased probability of appropriately sealing next to the adjacent sand body), we need to account for the overall chance of the entire prospect. Perhaps the clearest way to demonstrate this approach is with a decision tree. Here (Fig. 15), the analyst has illustrated the chance factors associated with the small (P90), median (P50) and large (P10) reserves outcomes. The chance factors in each row are multiplied to represent the percent probability (in bold print) of meeting or exceeding the reserves sizes of P90, P50 and P10, respectively. The reserves values are shown in the white cells beneath the MMBOE label. The product of the lower row of chance numbers (with shaded background) represent the traditional, base case probability of geological success, where the reservoir and closure chance factors are typically assigned to meeting the P90 of the

average net pay and productive area distributions, respectively. In other words, to better characterize the chance of this complex prospect, we take the specific, representative size outcomes, chanceweight those values, and add them up to generate the prospect's Expected Mean Reserves (EMz), shown on the far right column. In this example, the EMz is 6.80 MMBOE. The specific non chance-weighted (i.e. success case) reserves outcomes cannot be added. Rather, the mean of this reserves distribution can be calculated via Swanson's approximation (Mz). Swanson's approximation adds 0.3 • P90 reserves plus 0.4 x P50 reserves plus 0.3 x P10 reserves, in this case yielding a mean of 34.30 MMBOE. The size-weighted chance for a complex prospect (Pg) is represented by ratio of the EMz to the Mz, or EMz / Mz, which here is 20%. This percentage approximates the proper chanceweighting of the success case value in any expected monetary value calculation. When chance elements change with the scope of the prospect, the probability numbers need to reflect that change, to properly characterize the opportunity in relation to other projects considered for inclusion in the portfolio, and for proper prediction of portfolio outcomes.

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Fig. 15. Decision tree approach to demonstrate the chance of achieving successively larger outcomes for the stratigraphic trap introduced in Figure 12. The size-weighted chance is the sum of the chance weighted outcomes, EMz (here 6.80 MMBOE), divided by the Swanson's mean (here 34.30 MMBOE), defined as 0.3 (PIO + P90) + 0.4(P50). Condusion

We believe creativity, m e a s u r e m e n t and communication are three attributes needed in the deliberate search for stratigraphic traps. We have learned a number of lessons to cultivate these attributes, and note that they admirably serve the i m p o r t a n t function of exploration: 9

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Execution of a play is all about learning. Be sure to engage in a balanced approach that includes thought experiments, and recognize as early as possible the footprints of hydrocarbon migration established by the geographic and stratigraphic distribution of hydrocarbon shows. In play analysis, your dry hole tolerance strongly influences the probability your initial program will yield an economic discovery. Low corporate discount rates encourage new-play exploration. Determine the optimal working interest to appropriately diversify your efforts across several plays.

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Geological phenomena that create dependency always disperse the reserves outcomes such that greater dependency increases the mean of the reserves distribution. Understand and communicate the impact of stated dependencies. W h e n faced with prospects where the chance elements change across the scope of reserves sizes, a decision tree approach can help to clarify and communicate the complexity. In such cases, a size-weighted chance is a more appropriate probability weighting of the success case value in an expected monetary value calculation.

We hope these insights serve your roles of creativity, measurement and communication in the deliberate search for the stratigraphic trap. We wish you every success towards that end. References

BINNS, P. 2006. Evaluating subtle stratigraphic traps: prospect to portfolio. In: ALLEN,M.R., GOFFEY, G.P., MORGAN, R.K. & WALKER, I.M. (eds) Deliberate Search for the Stratigraphic Trap.

APPROPRIATE CREATIVITY AND MEASUREMENT Geological Society, London, Special Publications,

254, 7-26. CITRON,G.E, COOK,D.M. & ROSE,ER. 2002. Performance Tracking as a Portfolio Management Learning Tool. AAPG 2002 Annual Meeting, March 10-13, 2002, eposter, pg. A32. DEUTSCHE BANK. 2003. Global Oils: Sustainability Costs Money (Part 1: Analysis), Global Equity Research report. EDWARDS,J.D. 1997. Crude oil and alternative energy production forecasts for the twenty- first century: the end of the hydrocarbon era. AAPG Bulletin, 81, 1292-1305.

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JPMORGAN. 2003. Long-Term E&P Value Creation. North American Equity Research report (September 4, 2003), 10 pp. MACKAY, J.A. 1995. Utilizing Risk Tolerance to Optimize Working Interest. SPE paper 30043, HEE Symposium, Dallas, 103-109. MARKO,W.A. 2000. 2000 Global Competitive Assessment. SPE paper 62886. WOOD MACKENZIE. 2003. Value Creation Through Acquisitions. Horizons Energy Issue 14, October 2003.

Breast screening, chicken sexing and the search for oil: challenges for visual cognition N. D O N N E L L Y 1, K. R. C A V E 2, M. W E L L A N D 3 & T. M E N N E E R 1

1Centre for Visual Cognition, School of Psychology, University of Southampton, UK (e-maik n. [email protected], uk) 2Department of Psychology, University of Massachusetts, USA 30rogen Limited, 175 Southwark Bridge Road, London SE10ED, UK Abstract: Interpretation of images of the Earth's subsurface is a process whereby humans perceive and categorize visual features derived from seismic data. The seismic data are presented in the form of vertical slices showing points of change in some variable being measured (e.g. acoustic impedance) and horizontal slices showing surfaces interpolated between values at a particular time or horizon across multiple vertical slices. These images are usually highly complex and their nature has been determined largely by the technical capabilities of the hardware and software of the imaging technology. Because of these constraints, we argue, images do not convey information as readily as they could. We believe that these images could be more informative if they were constructed and tailored with known properties of the human visual system. Furthermore, little or no consideration has been given to the training and selection for image interpretation vis-h-vis the fundamental psychological skills that distinguish good from poor interpreters. In this paper we argue that tailoring images to the human visual system and developing working practices that eliminate biases will improve the detection of subtle features related to hydrocarbon traps. Furthermore, establishing training procedures that enhance the visual system's ability to detect and encode hydrocarbon traps, and creating selection procedures that select individuals with excellent visual imagery skills will also facilitate performance.

The apparently effortless act of seeing and interpreting information coming into our eyes hides a fact. Visual processing is one of the most complex tasks achieved by humans. Large areas of our brains are devoted to the task of processing visual information so that we can see and comprehend the visual world about us. Our visual skills include not only recognition, but also the guidance of actions and the creation and manipulation of visual images. In forming visual images and the mental tools for their manipulation, we create the basis for visual problem solving. The goal of this paper is to understand the processes involved in image interpretation for hydrocarbon deposits, given the basic visual data presented to image interpreters using imaging (for example seismic i n t e r p r e t a t i o n ) software. This understanding will be framed using basic principles of the human visual system that have been gleaned from many years of psychological experimentation. In exploring the problems of image interpretation, we will examine two related issues. First, why is the process of image interpretation so hard given the image data available? Second, how might image interpretation be improved? In bringing together the two

disparate areas of visual cognition and image interpretation for hydrocarbons, we accept at the outset that the treatment of both will be simplistic. Nevertheless, by showing how image interpretation might be advanced by greater consideration of the nature of h u m a n visual processing, we will demonstrate how technical advances in imaging need to be tuned to the humans interpreting the images. We contend that it is possible to improve the accuracy, reliability and speed of image interpreters by considering the visuo-cognitive elements of the job they perform. To our knowledge, nobody has made such an attempt to do so previously, and so this paper is the first attempt to understand issues of visual cognition in respect of image interpretation in geophysics.

Why is image interpretation so hard? In the search for h y d r o c a r b o n deposits, the primary data are derived from the collation and processing of artificially-generated acoustic waves that have been reflected by inhomogeneities in rocks below the Earth's surface (Brown 1999). Vertical and lateral changes in the properties of the rocks and the fluids

From:ALLEN,M. R., GOFFEY,G. E, MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the StratigraphicTrap.Geological Society, London, Special Publications, 254, 43-55. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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contained within them influence the character of the reflected seismic energy; these changes are displayed through colour transitions and variations in the image. Image interpretation is typically based on two different image types, vertical profiles and horizontal or 'topographic' surfaces (representing slices through the 3dimensional seismic data volume.) Vertical slices typically contain more or less continuous coloured lines of high spatial frequency representing boundaries of change in subsurface acoustic properties as recorded in the seismic data. Horizontal surface images (e.g. time and horizon slices, maps) contain coloured regions of common data values (amplitude, travel-time, etc.) that vary irregularly over space. Crudely speaking, the vertical images enable the detection of geological features (faults, folds, stratigraphic discontinuities and so on) that have diagnostic spatial properties (Selley 1998). In addition, the patterns of seismic reflections surrounding these spatial features provide significant information through the spatial relationships, positions of lines, or discontinuous bands displayed in different colours. Increasingly, interpretation requires identification of extremely subtle geological relationships imaged through equally subtle, and ambiguous, changes in the seismic data. There is, however, no simple visual process that will allow detection of these subtleties. In order for humans to detect and classify significant features of the types linked to the presence of hydrocarbon traps, they must construct specialized visual routines (Ullman 1985). These routines will perform basic search and analyses of images. We begin by describing some of the properties of these routines.

Searching for targets Interpreting a seismic image is to some important degree a visual search task. Visual search has been a popular topic within experimental psychology, and this work has led to a distinction between search for a target that is defined by a single feature, and search for targets defined by conjunctions of features (Treisman & Gelade 1980). Features are simple visual properties, such as orientations, colours, etc., whereas conjunctions are combinations of these basic features; for example, lines that are both red and horizontal. A long series of carefully constructed experiments in visual search have been conducted to uncover the psychological processes associated with detecting features versus conjunctions. In the most widely used visual search paradigm, participants are asked

to report as quickly as possible whether a specific target has been presented amongst a set of distractors. Two things are manipulated in this type of experiment: the relationship between the target and distractors, and the number of distractors. The evidence shows that if the target can be readily discriminated from distractors on the basis of at least one feature, then search for the target is fast and the speed of target detection increases little with the number of distractors (Treisman 1986; see Fig. la). In contrast, if targets and distractors can only be differentiated by conjoining features (see Fig. lb) then the time necessary for target detection increases with the number of distractors. One conclusion drawn from these experiments is that the presence of a simple feature is detected across the visual field without visual attention, and that visual attention is required to detect conjunctions of features. However, visual attention is limited in the sense that it cannot be applied to the whole visual field simultaneously. The requirement to use attention to detect conjunctions of features places a fundamental restriction on all complex visual tasks, because spatial attention can only be allocated to a limited number of locations at a time and takes a finite time to move to other spatial locations (Cave & Bichot 1999). Consequently, perceiving conjunctions of features takes time and requires active exploration of the visual field. The kinds of structures being searched for by image interpreters in vertical images are conjunctions of features. With respect to the search for hydrocarbons, we can understand part of the problem faced by image interpreters as resulting from the need to move visual attention around images in order to detect conjunctions of features that might indicate important subsurface relationships.

Colour categorization Considering only the basic properties of these vertical images and how they must be encoded by the human visual system does not, however, come close to providing a full understanding of why these images are visually so difficult to interpret. A further reason why vertical images are so difficult to interpret relates to the arbitrary use of colour in images (for some discussion of how colour should be used, see Brown 1999, Chapter 2.). By arbitrary, we do not mean that colour is applied without reference to a colour scale, or that some thought has not been given by designers into the colour scales themselves (Ware 1988). However, colour perception is a complex issue and scales should

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Fig. 2. Colour (Hue) is a linear construct but is perceived in a non-linear fashion such that colour categories are perceived with points of transition between categories. The graph at the top of the figure illustrates the difference (in frequency) required between two colours before they are perceived as being different. Note how the ease of discrimination changes within and across categories. Reprinted with permission, Clark University Press.

Fig. 1. Example displays of visual search experiments designed to show how targets defined as a simple feature difference relative to distractors 'pop-out' without attention (a), while targets defined as a conjunction of basic features require attention (b). (a) the target (black horizontal bar) is detected as easily in the top and bottom panels whereas this is not the case in (b) (light grey vertical bar). be designed with full consideration to all issues of perceived similarity and dissimilarity of the colours they contain. A cursory understanding of how humans encode colour i n f o r m a t i o n demonstrates why this is so problematic. For the m o m e n t we will satisfy ourselves with demonstrating a single point: while colour is a continuous variable with the visible wavelengths stretching from around 300 to 700 nm, it is perceived in distinct categories (red, green, blue, yellow etc) separated by apparent boundaries. Furthermore, two colours that are separated by, for example, 10 nm will be easily discriminated if there is a colour boundary between them, but very difficult to discriminate if they are both within the same colour category (Fig. 2). In other words, the discriminability of pairs of colours is not a linear function of the difference

in their wavelengths, even for typical viewers with perfectly n o r m a l colour vision. Hence, colour scales that do not take account of this basic fact, for example seismic workstation colour scales, risk making some differences imperceptible when other differences of equal magnitude are clearly perceptible (for a further discussion of this point, see Della Ventura & Schettini 1993). For this reason, the unprincipled use of colour adds visual noise to images that, even without that noise, would be difficult to interpret. With respect to horizontal surface images, the issues are somewhat different. These images are used to reveal the spatial extent of geological systems whose presence has been identified initially in vertical profiles. The issues relating to these images are primarily to do with determining a story through which all aspects of the image fit within a geologically consistent account. We will turn to this shortly, but before doing so, a further impact of colour categorization on performance needs to be described. The horizontal surface images typically used by image interpreters demonstrate an invidious aspect of the failure to appreciate the effects of colour category boundaries. The problem we refer to is the inappropriate segmentation of images into figure and ground.

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Whenever humans perceive an object (figure) it appears in some context (ground; see Fig. 3). We perceive only the figure as having shape, whereas the 'hole' in the ground covered by the figure is 'shapeless'. A n o t h e r important fact is that only a single object, or group of related objects, can be perceived as figure at any one moment in time. Finally the boundary distinguishing figure from ground is of particular interest to the visual system, as it represents the limit to the spread of attention at any particular moment. Putting these facts together, we can state that attention acts as if it spreads across the surface of objects to define its shape and extent, being delimited by the perceived edges of figures. When imaging surfaces to establish topography, one thing that should be avoided is the arbitrary segmentation of images by boundaries that do not reflect large differences in the real topographical data. Unfortunately, the wrong choice of colour scale for an image can lead to the perception of sharp boundaries where they do not belong. A n example of this effect is shown in Figure 4. In studying this image, note how attention is drawn to the red, blue and white regions sequentially, and how difficult it is to see these regions as being part of the single

continuous surface that the data, in reality, represent. Furthermore, note how difficult it is to discriminate within the blue, red and white regions, and how easy it is in contrast to discriminate between blue and red or between red and white regions. The difference between two points that are shown as two different shades of red may be just as great as the difference between a red point and a blue point, but the colour scale attaches much more salience and importance to the red/blue difference. By using the red-blue-white cotour scale, the continuous surface described by the data has been transformed into a surface of multiple figures and grounds in the image, making it difficult to visualize what the original data must have been. The location of real boundaries is critical to understanding the architecture and history of a geological system; the introduction of artificial boundaries through artefacts of colour coding has the potential to bias or distort the interpretation process.

Fig. 3. The Rubin's face/vase figures demonstrate how we cannot perceive the two faces at the same time as the vase.

Fig. 4. Example of an image of a continuous surface coded to create segmented regions that do not exist in the data. (Courtesy Amerada Hess)

The influence of top-down knowledge on perception It has long been known that experience and expectancies influence image interpretation, most obviously in the viewer deciding where to move their eyes next. However the influence of top-down knowledge on the visual routines used in image interpretation is much more pervasive. This can be demonstrated using pictures that

VISUAL COGNITION AND IMAGE INTERPRETATION can be interpreted in two different ways. The ambiguity in some of these stimuli is created by visual noise, while in other cases the interpretation can be changed by changing figure-ground assignment. A particularly good example of this is seen in the Salvador Dali picture presented in Figure 5. This figure can be interpreted in two ways. At first, the viewer will probably interpret it as a scene with various women and men set amongst a pair of arches. Under the second interpretation, the outer parts of the figure are similar to the first, but there is a large face set into the right hand arch. The assignment of what is figure and ground serves to determine whether the face (a 'Bust of Voltaire') is detected in the image or not. The fact that figure can emerge from ground is an interesting p h e n o m e n o n in its own right. However, it is a second aspect of this effect that is of primary interest in the current context. Having detected the 'Bust of Voltaire' in the image, now try to interpret the scene as if it is not there, i.e. as if the face was not seen when first viewing the image. It is difficult, if not impossible, to know that the 'Bust of Voltaire' is in the image but to treat the elements of the face as belonging to different people and so to not see Voltaire. The point of this demonstration is to show that one cannot readily let go of hypotheses, once formed, concerning the perceptual organization of a scene; 'unlearning' is virtually impossible. Therefore, when interpreting ambiguous images, one must avoid being drawn towards

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interpretations of scenes based on hypotheses that c a n n o t be supported by real features present in images. Of course, it might be supposed that the ability of expectations to change image interpretation only arises in the context of situations designed to play perceptual tricks. Unfortunately this is not the case, as illustrated by a case from radiology. Berlin (2000) reports on a radiologist convicted in court for negligence for missing a visually-identifiable tumour on a chest x-ray. The accusation was based on the fact that a patient was diagnosed with a lung tumour three years after having a chest x-ray. When the patient's lawyers showed the original chest xrays to a number of 'expert' radiologists and asked the question 'do you see the tumour?', they confirmed that the tumour was present and visible. These experts had the benefit of knowing about the tumour's presence before ever viewing the image, and thus were not able to view the image with the uninformed mindset of the original radiologist when he first examined the image. The experts' judgments could reflect a bias from hindsight. That is to say that the clarity of the tumour in the original chest x-ray became more striking in the context of the subsequent x-ray taken three-years later. Hindsight of this sort could potentially bias observers to indicate the presence of a target on the basis of minimal evidence. One would expect this response bias to raise the number of correct detections ('hits') while also raising the

Fig. 5. The 'Bust of Voltaire' by Salvador Dali. Original is in colour. Reprinted with permission.

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number of times that a target is reported without actually being present ('false alarms'). Recent studies, however, suggest that in some circumstances hindsight may increase the accuracy of perception without increasing the number of errors. In a study of medical students detecting visual features relevant for determining diagnoses, Brooks et al. (2000) showed participants images of patients whose diseases left marks or discoloration of the skin. The task was twofold: first, to report the number of clinically-relevant visual features present in each image, and second to report which of a list of six pre-specified features were present in each image. The list of six features composed two features that were present, two that might have been present given the condition but were not, and two features not present and unrelated to the correct diagnoses. Brooks et al. (2000) split participants into three groups. Group I was told the correct diagnoses, Group 2 was given five possible diagnoses, and Group 3 was given no information at all. The results of the experiment showed that having diagnoses in mind influenced the total number of clinically relevant features reported. Furthermore, the certainty of diagnoses increased the reporting of clinically-relevant visual features that were actually present, but did not increase the reporting of potential features that might have been present but were not actually shown. In other words, knowing the diagnosis increased the sensitivity of perception without also increasing any response biases. Apparently, some types of knowledge can influence the ratio of signal to noise in image interpretation. A study by Sowdon et al. (2000) confirms the basic finding that experience influences basic perceptual sensitivity. In their experiment they took radiographers with experience interpreting mammograms (breast x-rays), and compared their ability to discriminate subtle differences in shades of grey in pairs of dots presented on xray film (though not in the context of mammograms). Note here that these radiographers have spent many years studying grey-scale images for abnormalities indicated by changes in value along a grey-scale. The radiographers demonstrated much more sensitivity to subtle differences in shades of grey than a control sample of younger adults. The fact that a correct hypothesis can influence the signal-to-noise ratio of perception is a real asset if the working hypothesis is correct. But what happens when interpretation proceeds under an incorrect hypothesis? One might suppose that hypotheses are commonly formed prematurely in the process of seismic image

interpretation, and potentially valid alternative geological models discarded early on, or, more likely, never identified. Furthermore, this issue is exacerbated by the typical nature of conversations between interpreters: 'you see this incised channel here?' is a more common form of question than 'what do you make of this feature?' Assuming that the working hypotheses are based on some perceptual evidence available in images, then those features consistent with the hypothesis will be amplified relative to those that are inconsistent with the hypothesis. Obviously, the impact of this adjustment in features will be to further bias interpretation along the lines of the initial incorrect hypothesis. In summary, the images being interpreted in the search for hydrocarbons tax basic human visual processing systems. One set of difficulties arise because 'targets' in vertical slice images are conjunctions of colour and form that require focal attention to encode. Another set of difficulties are introduced by inappropriate segmentation from the colour scales applied to horizontal or 'topographic' images. Finally, the working practices of image interpreters leads to geological stories being created which, whether right or wrong, accentuate some features over others. The manipulation of basic sensory signals is good if working hypotheses are correct, but extremely damaging if they are incorrect.

Improving image interpretation The issues outlined above do, we contend, lead to the task of image interpretation being even more difficult, and less objective, than it might otherwise be. In this section we propose a number of modifications to aspects of the image interpretation process. We make no claim that the issues discussed represent an exhaustive list or that the conclusions reached are necessarily correct. It is our contention, however, that these issues should be examined and that a good case exists for their consideration in a review of how image interpretation is conducted. Image construction

Important information can be obscured in vertical and horizontal image slices because the colours used to encode the data have not been carefully chosen. A colour scale for displaying values on a continuous variable (e.g. time, depth, amplitude etc.) should be designed so that equally perceptible differences in colour correspond to equal differences in the data, irrespective of the ranges of the scale being

VISUAL COGNITION AND IMAGE INTERPRETATION compared. In principle this is easy to achieve, and colour spaces have been defined which attempt to rectify for the non-linearity of human colour vision so that perceived differences between colours map onto the distance between colours in some metrical space. Examples of these colour spaces are the Munsell color set (Munsell 1929) and C I E L A B space (see CIE 2004). As long as monitors are properly calibrated, these colour spaces might form the basis of colour scales that are calibrated for the non-linearity in h u m a n colour perception (Della Ventura & Schettini 1993; Ware 1988).

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However, b o t h the Munsell color set and C I E L A B are not especially good at accounting for human colour perception across some types of images, especially those in which colours appear in high spatial frequency patterns. Perceived saturation is generally reduced as spatial frequency increases, and this reduction is not equal for all colours, as studies from our laboratory have shown (Fig. 6). Furthermore, human colour perception is influenced by other contextual effects such as the set of colours actually shown in any specific image (Fig. 7; see Robertson 1988). In summary, we cannot just

Fig. 6. Data from two conditions of an experiment run in the University of Southampton laboratory in which participants were asked to judge the similarity of pairs of colours, taken from a set of forty colours. The spatial frequency of images was varied and multi-dimensional scaling used to construct a 2-dimensional solution shown in the polar graph for each condition. Note how the shape of the curves differ across spatial frequency, with the spatial frequency being 4 cycles per degree in high spatial frequency condition (Graph A) but varying between 0.5 to 2 cycles per degree in the low spatial frequency condition (Graph B). These data show that spatial frequency influences colour similarity (and hence discrimination) judgements. Moreover the impact of spatial frequency is not the same on red-green and blue-yellow axes.

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N. DONNELLY E T A L . place using a correctly-calibrated workstation monitor. In the 'rainbow' image shown in Figure 8a, note how (1) attention is drawn to sub-regions of the image without regard to data values but to colours, (2) gradual changes in data values appear as categorical shifts in colours, (3) a sense of topographic variability is present despite continuous changes in data values, (4) some subtle changes in data values are transformed into categorical shifts so that the reality of the subtle changes is lost.

Fig. 7. Example of how colour context can affect perceived colour. The Figure contains only two colours. assume that it is possible to take a standard colour space and use it to create psychologically unbiased coiour scales that will suit all situations. We have been conducting experiments on human colour perception to collect the data necessary to create psychologically unbiased colour scales suitable for use in the kinds of images generated from seismic data. In these experiments, we establish similarity matrices for sets of colours that are frequently used in colour bars and presented in situations designed to replicate those in which they appear in geophysical images. These data are then analysed using multi-dimensional scaling to form a representation of how similar/dissimilar colours are from each other. These data can then be used, along with methods of interpolating between measured data points, to construct colour scales that have a number of desirable properties. First, equal perceptual differences equate to equal differences in whatever value is being represented in images. Second, they do not contain artificially-created distinct colour boundaries: points of segmentation will only occur in images when justified by the data. We are only at the beginning of understanding how the colour similarity data might assist image interpretation but some examples of images coded in traditional colour scales and the same images coded using psychologically unbiased colour bars are shown in Figure 8a-d. Figures 8a and 8c are coded using a traditional colour bar taken from an industry standard package. Figures 8b and 8d are coded using colour bars derived from psychological colour space experiments. It should be noted that proper inspection of such images should take

In contrast, the same data represented in Figure 8b appear as a continuous but changing surface where subtleties in the data are preserved and attention is free to explore the surface unbiased by the influence of the choice of colour scale. It is recognized that an initial inspection of Figure 8b may create a sense of 'discomfort' in a viewer accustomed to the more traditional appearance of the image (Fig. 8a); however, if this can be overcome, the ability of the visual system to discriminate subtle colour changes in the coding in this image enables detection of subtle features in the data represented. In Figure 8c note how the metrical values representing intensity are lost in the traditional image but can be interpreted in Figure 8d. It should also be noted that, as with the 'discomfort' factor recognized above, the initial reaction to Figure 8d might be that data variations visible in Figure 8c are not so readily discernible; arguably, closer inspection and familiarization with the image reveal that this is not the case. Of course, there are many different kinds of data imaged in the process of seismic interpretation, and some displays rely more than others on establishing subtleties in colour space. It is intended that colour coding experiments will be conducted on a variety of display types (for example, seismic attributes, seismic facies maps) that would appear to be particularly sensitive to colour coding. We contend that the proper imaging of at least some types of data will be facilitated by ensuring the colours presented in images are calibrated to the human visual system. In this section we have discussed the role of colour in improving image interpretation, and we have done so partly grounded in our own studies. However, we believe other aspects of the interpretation process are open to investigation and improvement although, as yet, we have not studied them in detail. In the final two sections we provide some introductory remarks

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Fig. 8. Examples of 'surface' images coded using a traditional colour scheme (a) and a colour scheme derived from psychological colour space (b). Examples of vertical profile images coded using a standard colour scheme (c) and a colour scheme derived from psychological colour space (d). Note that precise reproduction of images on monitors and in print is dependant on calibration of devices. on these issues, while acknowledging that they await full investigation.

Training and expertise Image interpreters are highly-trained individuals who bring substantial experience to the process of interpretation. We have yet to discuss how this experience might moderate the task of image interpretation, given the images being interpreted and the architecture of the human visual system. Two issues are of interest in this regard. First, given that detection of relevant features is reliant on having knowledge of the characteristics of such features, can knowledge be imparted to trainees more quickly and with

greater impact than at present so that they produce more accurate interpretations earlier in their careers? Second, can training influence the speed and accuracy of the detection of conjunction targets in crowded visual fields, as found when subtle geological relationships are displayed in vertical profile images? Currently, little consideration is given to how new interpreters can be most effectively trained. Beyond the basics, learning how to interpret images, is in large part implicit. This raises the question of how efficient and objective this implicit learning is and whether it might be improved by explicit training. An extreme example from a different type of visual discrimination serves to illustrate the point. Until the

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late 1920s, sexing day old chicks was considered an impossible task as sex-specific characteristics do not emerge in chickens until around one month. However, there is an incentive to identify male chicks early, as they are of no economic value and eat vast amounts of food before reaching one month old. In short, early chicken sexing is of value because it allows male chicks to be identified and destroyed. In the late 1920s a Japanese delegation visiting the US demonstrated a technique for sexing day-old chickens. Many of the details of the technique are of no interest to geophysicists, but in 1930s America they caused such a stir that chicken sexing schools began to develop, whose sole reason for existence was to train chicken sexers. It is commonly accepted that after training it takes chicken sexers two to three years to reach the full extent of their skills. In the normal course of events, chicken sexers operate with high accuracy, but some chickens are very difficult to categorize. Two perceptual psychologists (Biederman & Shiffrar 1987) tested some of these chicken scxcrs, who had a lifetime experience of sexing chickens, on eighteen cases known to be extremely difficult to categorize; they performed at a level of 72% correct. Biederman & Shiffrar noted that the sex of chickens in these images could be classified according to a very simple perceptual principle called the minima rule, and wrote a one-page description of how the minima rule could be used to discriminate the sex of day-old chickens. They then took two groups of na'fve participants and asked them to distinguish male from female chickens. Both groups attempted the task without instruction and scored around 60%. After this, one group was shown the instructions, taking around 1 minute to read them, and then reclassified the images, scoring 84% correct. The second group repeated the classification task without instruction and scored 54%. Therefore, this experiment demonstrated that if a simple visual rule can be used to define targets, brief explicit instructions can lead to superior performance compared to many years of implicit learning based on instances. The chicken sexing example demonstrates that visual discrimination tasks that might be considered to be the fruits of distilled knowledge can in some cases rely on simple visual features that distinguish targets from distractors. For these tasks, relative novices can achieve excellent performance with the right type of training on detecting the key features. In the search for hydrocarbons, of course, it may or may not be possible to identify simple visual

features that distinguish targets from distractors. Nevertheless, it raises the possibility of a role for training via explicit identification Of basic image features that map onto those whose presence is readily detected by the human visual system. It also emphasizes the importance of understanding 'proven' examples of the features being sought in order to try to define relevant visual features, before embarking on the data search itself. Other experiments show that search for some targets, while initially difficult, can improve qualitatively with practice. Repeated exposure to specific stimuli can lead to the development of special skills for finding a particular target. However, efficient search only develops when the task is consistent enough to allow a particular type of practice. For example, Schneider & Shiffrin (1977) used letter and digit displays to investigate changes in the speed of search for targets with practice as a function of whether the items (targets and distractors) were drawn from the same or different categories (letters ~ digits). Their results showed that if highly familiar items (letters and digits) were reliably separated into target and distractor items, then efficient search eventually developed. In contrast, if targets could be either letters or digits, then the search remained relatively inefficient. These data suggest that if some kinds of items are always search targets, while other kinds of items are consistently distractors, then visual search can become very efficient. Whether the search for hydrocarbon traps might similarly be enhanced through training is another question to be answered by research. The chicken sexing example described above serves to illustrate how categorization of image features can be improved by providing clear explicit instructions. Despite our comments regarding how basic image features might, with experience, come to be detected efficiently, it is apparent that the search for traps containing hydrocarbons is more complex than chicken sexing, and if performance is to be improved from current levels, a more carefully designed training procedure will probably be necessary. One complication comes from the wide variation across different exemplars in any given class of geological formations. No two geological features are identical, and their rendition in seismic data is ambiguous and dependent on a multitude of factors; the seismic method remains a crude tool, often incapable of imaging geological features of the scale and subtlety that is desired, yet at the same time giving the appearance of doing so. Traditionally learning of visually confusing items has employed simple

VISUAL COGNITION AND IMAGE INTERPRETATION prototypes; for example, in wartime aircraft identification or bird-watching. These training programmes are based on the assumption that once trainees have learned to make easy discriminations, they will be better able to learn the more difficult discriminations. The alternative is to start from the beginning with practice at difficult discriminations. Under this approach, trainees would practice with real instances of difficult or ambiguous seismic geometries from the very start. The issue is exactly the same as that faced by those training X-ray baggage interpreters who must identify threatening items without knowing the exact form and orientation of any threat item. In fact this issue has only just begun to receive the attention it deserves and so it is hard to give a simple recommendation. However, studies with X-ray stimuli in our own laboratory show little advantage of starting training with highly discriminable exemplars, and suggest that better outcomes are reached if difficult exemplars are shown in training from the beginning. We would argue that exactly the same is true in the interpretation of geophysical data, and that training of novices should be based on difficult exemplars, as these will eventually allow generalized representations of target features to develop despite being difficult to learn at the outset.

Mental imagery The final issue we consider in improving interpretation of geological images is visual imagery. Image interpreters often begin their process of analysis by working with sequences of 2-dimensional images which represent slices through the 3-dimensional data volume. Interpolation across these vertical slices is used to create surfaces. The representations formed in the minds of interpreters are, however, 3dimensional, with visual imagery skills used to relate image features in one slice to those in another. Only through visual imagery can one begin to understand the 3-dimensional structure intended to be communicated by successive 2dimensional slices. Visual imagery is, therefore, fundamental to the process of image interpretation. Studies of mental imagery in humans have a long history, and it is worthwhile reviewing some classic experiments to reveal some fascinating insights into the hidden world of visual imagery. In one task, participants were given two similar objects and asked to judge whether the two objects were the same or different (Shephard & Metzler 1971). Figure 9 illustrates conditions from an experiment which reveals a

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surprising pattern in the time necessary to compare the two shapes. Specifically, there is a linear relationship between response time (RT) and angular difference between images. It is as if one object is being mentally rotated to the orientation of the other object before making a decision. The speed of rotation of the mental image is apparently constant; i.e. it takes time to change orientation in mental space with time being scaled linearly by change in orientation as in the physical world. The fact that visual imagery obeys lawful rules of the physical world turns out to be true across a number of different types of experiments. For example, Kosslyn et al. (1978) asked participants to learn a map containing seven named locations. Once they were confident they had learnt the map, they were then told to imagine the map and focus on a specific location. They were then instructed to imagine a spot moving from that location to some other location named by the experimenter and then to press a response button. The crucial result was that the time to respond was scaled by the physical distance travelled by the imagined spot. These studies form part of a voluminous literature. Taken as a whole, these experiments indicate that visual imagery is not a single undifferentiated skill, but has separable components relating to broad categories that we might call image generation, manipulation and storage. Furthermore, it is apparent that there are individual differences in the component imagery skills (Kosslyn et al. 1984). This research raises the intriguing possibility that the use of imagery skills in solving the problem of image interpretation might be used to enhance performance either by selecting interpreters who will be good at the task via some form of psychometric testing, or by training interpreters to enhance specific imagery skill components that are less well developed than others. Both of these proposals are untested at the present, but deserve attention in the near future.

Summary In this paper we have investigated the human dimension to image interpretation. Given the images available, interpretation is difficult because the necessary discriminations challenge the abilities of human visual processing mechanisms. Critical features do not automatically signal their presence and so risk being missed. Furthermore the arbitrary use of colour in colour scales creates two distinct problems. First, images contain segmentation cues where colours abut each other. The segmentation cues

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N. DONNELLY ETAL. colour space and the difference between data values on whatever dimension is being imaged. This arbitrary mapping makes it impossible to understand values in images without explicit reference to colour bars, and this makes interpretation unnecessarily complicated. Both of these problems in using colour for data coding can be solved by using colour bars derived in psychological colour space. The p e r f o r m a n c e of image interpreters should be improved if training is provided in which features to be searched for are made explicit. The exemplars used for this training should reflect the full complexity normally found in geological images, and should not be artificially simplified. Furthermore, trained interpreters should conduct their interpretation for as long as possible in a 'hypothesis free' state. Of course, interpreters will be bound to be driven by contextual knowledge of previous successes etc. However, each interpreter should approach a new image without any suggestion or biasing from other interpreters. The expect,at; . . . . . . . t~r] hy th,~,,o,, . . . . .~"~b~, . . . . . "~o---',,~t;'~'~will change perceptual signal-to-noise ratios, blocking the likelihood of discrepant findings being reported and different (equally valid) interpretations being made. Finally, we raised the prospect that not all are born to interpret, and that differences in visual imagery skills might be used to select good from poor interpreters. The authors would like to acknowledge the help given by all at Ikon Science in the preparation aspects of this paper.

References

Fig. 9. Example of three images in a visual imagery study. Are the images in a--e the same? In experiments of this type, reaction times to make decisions about the sameness or difference of figures increase linearly with the angular difference between pairs of figures. So, deciding a and b are the same takes proportionately less time than deciding a and r are the same. The results hold whether rotations are made in 2- or 3-dimensions. attract attention to locations that are likely to be of no greater real interest than others that arbitrarily lack such cues. Second, the arbitrary nature of colour bars means that there is no relationship b e t w e e n perceived distance in

BERLIN, L. 2000. Malpractice issues in radiology: Hindsight bias. American Journal of Radiology, 175, 601. B1EDERMAN, I. & SHIEFRAR,M.M. 1987. Sexing dayold chicks: A case study and expert systems analysis of a difficult perceptual learning task. Journal of Experimental Psychology: Learning, Memory and Cognition, 13, 640-645. BROOKS,L.R., LEBLANC,V.R. & NORMAN,G.R. 2000. On the difficulties of noticing obvious features in patient appearance. Psychological Science, 11, 112-117. BROWN A.R. 1999. Interpretation of ThreeDimensional Seismic Data. 5th edn. American Association of Petroleum Geologists, Memoir 42, Tulsa, Okla. CAVE, K.R. & BICHOT,N.E 1999. Visuo-spatial attention: Beyond a spotlight model. Psychonomic Bulletin and Review, 6, 204-223. CIE. 2004. Colorimetry. CIE Publication No. 15, 3rd Edn. Commission Internationale de LEclairage, Vienna.

VISUAL COGNITION AND IMAGE INTERPRETATION DELLA VENTURA,A. & SCHETI'INI,R. 1993. Computer aided color coding. In: THALMANN, N.M. & THALMANN, D. (eds) Communication with Virtual Worlds. Tokyo, Hong Kong, Springer-Verlag, 62-75. KOSSLYN,S.M., BALL,T.M. & REISER, B.J. 1978. Visual images preserve metric spatial information: Evidence from studies of image scanning. Journal

of Experimental Psychology: Human Perception and Performance, 4, 47-60. KOSSLYN, S.M., BRUNN, J., CAVE, K.R. & WALLACH, R.W. 1984. Individual differences in mental imagery abilities: A computational analysis. Cognition, 18, 195-243. MUNSELL, A.H. 1929. The Munsell Book of Colour. Munsell Color Company, Inc., Baltimore, Maryland. ROBERTSON, EH. 1988. Visualizing color gamuts: A user interface for effective use of perceptual colour spaces in data displays. IEEE Computer Graphics and Applications, 8, 50-64. SCHNEIDER,W. & SHIFFRIN,R.M. 1977. Controlled and automatic human information processing: 1. Detection, search, and attention. Psychological Review, 84, 1-66.

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SELLEY, R.C. 1998. Elements of Petroleum Geology. Academic Press, San Diego. SHEPHARD, R.N. & METZLER,J. 1971. Mental rotation of three-dimensional objects. Science, 171, 701-703. SOWDON, ET., DAVIES, I.R.L & ROLING, P. 2000. Perceptual learning of the detection of features in X-ray images: A functional role for improvements in adults' visual sensitivity. Journal of

Experimental Psychology: Human Perception and Performance, 26, 379-390. TREISMAN, A. 1986. Features and objects: The fourteenth Bartlett memorial lecture. Quarterly Journal of Experimental Psychology, 40A, 201-237. TREISMAN,A. & GELADE, G. 1980. A feature integration theory of attention. Cognitive Psychology, 12, 97-136. ULLMAN, S. 1985. Visual routines. Cognition, 18, 97-159. WARE, C. 1988. Color Sequences for Univariate Maps: Theory, Experiments and Principles. IEEE Computer Graphics and Applications, 8, 41-49.

The deliberate search for stratigraphic and subtle combination traps: where are we now? J. R. A L L A N 1, S. Q. S U N 2 & R. T R I C E 2

1C&C Reservoirs, Inc., 1038 East Bastanchury Road, #183, Fullerton, CA 92835, USA (e-mail: Jack.Allan@ccreservoirs. corn) 2C&C Reservoirs Ltd., Arcadia House, 15 Forlease Road, Maidenhead, Berkshire SL6 1RX, UK Abstract: Stratigraphic and subtle combination traps have a well-documented track record

as significant producing hydrocarbon resources. The majority of these success cases come from onshore USA where unprecedented drilling densities combined with a long history of hydrocarbon exploration provide a large portfolio of stratigraphic and subtle combination traps. By comparing USA-based examples with other global cases it is evident that numerous basins still have the potential for exploration success associated with these traps. This paper attempts to raise the awareness of the exploration potential of stratigraphic and subtle combination traps through four approaches. Firstly, a summary of key global statistics related to stratigraphic and subtle combination traps is provided with the intention of demonstrating that they have historically represented a key hydrocarbon resource. Secondly, a classification scheme is introduced and acts as a reference for the observations and case studies presented. The third component of this paper is to present a range of case studies, which serve to demonstrate the exploration history behind successful discoveries associated with stratigraphic and subtle combination traps. The final component is to consider the general exploration history and from this long experience highlight the key techniques necessary for the development of a successful exploration strategy.

In structural traps, closure is created by folding and faulting, while in stratigraphic traps, closure is created by stratigraphic, lithologic or hydrodynamic variations. Most stratigraphic traps are subtle, in that detection is problematical and lateral closure is difficult to prove. Some stratigraphic traps, most noticeably organic buildups (reefs and mounds) and buried hills, have fourway dip closure, are generally easy to image on seismic, and are therefore not subtle. These are not discussed in this paper. Combination traps contain elements of both structural and stratigraphic entrapment (Levorson 1954). Combination traps that occur on or near the crests of four-way structural closures are not subtle and are also not considered in this paper. Most were misidentified as structural prospects and discovered by drilling the structural crests. However, stratigraphic trapping mechanisms may combine with open structural noses and small anticlinal closures to produce subtle combination traps. O p e n structural noses provide the lateral structural seals to subtle combination traps, which are sealed up-dip by lateral depositional or onlap pinchout, subcrop trucation, or diagenetic cementation of reservoirs. Depositional pinchout of reservoirs on the flanks of small anticlinal closures can create

subtle combination traps with hydrocarbon columns far larger than could be predicted from the size of the closure. Subtle combination traps of this sort are considered along with pure stratigraphic traps in the discussions that follow. In a broad sense, stratigraphic and subtle combination traps include: (1) Traps that lack obvious four-way closure and would not have been discovered using exploration strategies designed for structural traps. (2) Traps which, if associated with a major structure, occur in an unexpected place (e.g. in a down-flank location). Building on these definitions we consider stratigraphic straps to be those traps arising from the processes of: (a) deposition, (b) erosion, (c) intrusion, (d) diagenesis, and, (e) fluid variation. Although most types of stratigraphic and subtle combination trap have been known for decades they represent an underexplored resource in comparison to structural traps. The challenges that they present to the explorationist can be summarized as detection and quantification. In the context of detection, stratigraphic and subtle combination traps can be harder to find than

From:ALLEN,M. R., GOFFEu G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 57-103. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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structural traps since they are more difficult to image seismically. From the quantification perspective, once identified, they are more difficult to assess with respect to their closure risk, seal integrity, potential hydrocarbon column, and hydrocarbon reserves. The combination of these challenges adds to the difficulty of selling the concept of exploring for stratigraphic and subtle combination traps to management and investors. Despite these challenges, the opportunity presented by stratigraphic and subtle combination traps is significant. An insight into this global exploration potential can be gained by reference to Figure 1 and Figure 2, which are based on a review of 174 fields worldwide that are associated with stratigraphic and subtle combination traps as portrayed in Figure 3. Figure 1 includes the in-place hydrocarbons for the combination structural-stratigraphic accumulation of Prudhoe Bay ( > 1 2 B B O (Billion barrels of oil)), the stratigraphic trap of East Texas field (6 BBO), and the huge Hugoton accumulation, which is the largest US gas field (27 TCFG (Trillion Cubic Feet of Gas)). Figure 2 demonstrates that hydrocarbon column height may attain values in excess of 2000 ft. Such summary figures are important tools in challenging the common perception that stratigraphic and subtle combination traps are

associated only with small accumulations with limited hydrocarbon columns. Figure 3 shows the global distribution of stratigraphic and subtle combination traps that form the basis of this paper. It can be clearly seen from this Figure that the bulk of stratigraphic and subtle combination traps reside in North America. However, from the perspective of trapping mechanism potential there is nothing geologically unique about North America. The disproportionate number of stratigraphic and subtle combination traps is attributed to the extremely high drilling density, which has resulted from an extensive and long lived US domestic oil industry. From these observations it is clear that significant opportunity must exist in basins outside North America. This statement can be further appreciated by recognizing that it is within mature basins that stratigraphic and subtle combination traps represent real exploration opportunities. This opportunity arises in mature areas as most structural traps have been drilled, an infrastructure exists, and a knowledge base has been accumulated, from which cieative exploration ideas can be generated. A further important consideration is that, as part of the research for this paper, an analysis of 119 global deepwater discoveries showed that two-thirds of these are stratigraphic and subtle combination traps. In order to further develop the concepts, the

Fig. 1. In-place hydrocarbon volume distribution for the stratigraphic and subtle combination traps examined in this paper. Only traps for which reliable data were available are shown.

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Fig. 2. Total hydrocarbon column height (oil and gas) distribution for stratigraphic and subtle combination traps examined in this paper. Only traps for which reliable data were available are shown.

Fig. 3. Global distributions of the studied 174 stratigraphic and subtle combination traps examined in this paper. following section is intended to summarize prior trap definitions and introduce the definitions applied by the authors of this paper in assessing the exploration potential of stratigraphic and subtle combination traps.

Classification of stratigraphic traps Previous classifications A trap is a geometric configuration of permeable reservoir and less permeable seal rocks which,

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when combined with favourable physical and chemical properties of subsurface fluids, can allow hydrocarbons to accumulate (Vincelette et al. 1999). The trap is limited by several intersecting surfaces, which include boundaries between solids (e.g. reservoir and seal) and boundaries between fluids (e.g. oil-water and gas-water contacts). The geometric configuration of these boundary surfaces defines the trap. The petroleum trap concept originated in 1844, when William Logan recognized that oil seeps in the Gaspe region of eastern Canada were associated with anticlines. However, it was not until 1885 that the application of the trap concept to petroleum exploration began, when I.C. White stated the anticlinal theory of oil accumulation in print and others began to use the idea to look for oil in surface anticlines (Levorsen 1941, 1954). Since then the concept of trap and trapping mechanisms has evolved (Clapp 1929; McCotlough 1934; Wilhelm 1945; Levorsen 1954; Rittenhouse 1972; North 1985; Biddle & Wielchowsky 1994; Vincelette et al. 1999). It was not ,,.,~1 l o ~ ~r,,~ tevorsen drew special attention to stratigraphic traps. The concept of stratigraphic traps was built on by Sanders (1943) who described several types of structural-stratigraphic combination trap. The next decade saw the development of two seminal trap classifications. Wilhelm (1945) divided petroleum reservoirs into five major categories and Levorsen (1954) integrated the work of many of his predecessors into a simple yet elegant classification scheme. Leverson's scheme has influenced geological thinking up to the present day as most modern trap classifications recognize Levorson's categories. The key to Levorsen's classification is that he defined two trapping end-members: structural traps, in which closure is created by local deformation (folding and faulting) and stratigraphic traps, in which closure is created by stratigraphic, lithologic or hydrodynamic variations (e.g. facies change, depositional pinchout, unconformities, diagenetic changes). Between these two endmembers lie a continuum of combination traps, in which both structural and stratigraphic elements are necessary for hydrocarbon entrapment. Levorsen further divided stratigraphic traps into primary (depositional) traps, secondary (unconformity) traps, and fluid (hydrodynamic) traps. A later, more comprehensive attempt at classifying stratigraphic traps was undertaken by Rittenhouse (1972). uxxLxx

a_3Ju

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Table 1. Organization o f major subdivisions (systems and regimes) in the trap classification o f Vincelette et al. (1999) Structural trap system

Stratigraphic trap system

Fluidic trap system

Fold regime Fault regime Fracture regime Depositional regime Erosional regime Diagenetic regime Pressure regime Temperature regime Fluid-composition regime

Vincelette et al. (1999) developed a classification that combines Levorsen's ideas with the organizational structure of the biological classification scheme, which subdivides all life on Earth into kingdoms, phyla, classes, orders, genuses, and species (Curtis 1983). Employing this approach, structural, stratigraphic and . . . . . . . . . . r, ~ , ~ m s are ~u~,dv~lu,~d into three trap regimes (Table 1), which are further subdivided into classes and families based on geological processes, trap geometry and composition and genesis of the traps. Combination traps of any sort can be described simply by combining elements from the various categories. Although complicated, Vincelette et al.'s classification scheme enjoys the advantage of a logical yet flexible structure.

Classification applied in this paper In this paper, we apply a classification scheme for stratigraphic and fluidic traps that is modified from Vincelette et al. (1999). A few major differences between this classification and Vincelette et al.'s (Table 1) classifications are apparent. Specifically we combine stratigraphic and fluidic traps into one system. We also include fracture traps, which lack structural expression, as part of the diagenetic regime of the stratigraphic-fluidic trap system rather than part of the structural trap system. Traps produced by fracturing occur where oil or gas are entrapped in fractures in low permeability lithologies such as shale, chalk, chert or coal. They should not be confused with fractured reservoirs within structural or stratigraphic traps. These concepts are summarized in Figure 4, which provides an overview of the trapping

Fig. 4. Stratigraphic trap classification as applied in this paper. Combination traps can be described by combining any of the stratigraphic or fluidic elements here with various structural elements.

S T R A T I G R A P H I C A N D SUBTLE COMBINATION TRAPS

61

62

J.R. ALLAN E T A L .

system, regime, class and family as well as schematic cross-sections of each trap type. As in Vincelette e t a l . ' s classification, combination structural-stratigraphic traps can be described by combining structural elements with any of the stratigraphic or fluidic elements shown in Figure 4.

History of strafigraphic and subtle combination trap exploration The 174 stratigraphic and subtle combination traps in this report were discovered between 1885 and 1996. This section represents an attempt to summarize this history and from that summary distill some key learning points that can be used to better focus exploration efforts. Between 1885 and 1929 only 12 stratigraphic and subtle combination traps where discovered (Fig. 5). All were found in North America and Latin America and were very shallow and quite large (Figs 6 & 7). They were discovered using surface geological mapping, by drilling adjacent to oil or gas seeps, or by accident while drilling for other objectives (Fig. 8). It must, of course, be born in mind that the stratigraphic trap concept had not yet been developed at that time. Thirteen of the studied traps were discovered during the 1930s (Fig. 6). Once again, all were in North America and Latin America and most were very large (Fig. 7). During the 1940s 15 of the studied traps were discovered, again, all in North America and Latin America (Fig. 6). Smaller traps (Fig. 7) were found at greater depths, as seismic and subsurface geology began to be used more frequently (Fig. 8). However, more than half of the traps were found by accident, indicating that a systematic search for stratigraphic and subtle combination traps had not yet begun. In fact it was not until the 1950s that a boom in the deliberate search for stratigraphic and subtle combination traps occurred (Figs 5 & 6). During this decade 36 were discovered, however, the average trap size was noticeably smaller than in most previous decades (Fig. 7). This boom was the result of a wide variety of techniques (Fig. 8), being applied intentionally to search for lateral facies-change, lateral depositional pinchout, and channel-/valley-fill traps in the foreland basins of North America. Exploration activity remained high in the 1960s, with 32 discoveries, as North American foreland basin exploration continued at a rapid pace. Cretaceous valley-fill traps in the Rocky Mountain basins emerged as an important play

at this time. Most discoveries occurred at depths of 5000-10 000 ft and, although the average trap size was about the same as in the 1950s, several large accumulations were discovered (Fig. 7). It was during the 1960s that for the first time, discoveries were made in Asia and Australasia (Fig. 6) and exploration for stratigraphic and subtle combination traps moved offshore, with discoveries made at Arenque in Mexico and Halibut-Cobia in Australia. The 1970s was another active decade. Thirtysix discoveries were made using a wide variety of exploration techniques (Figs 5 & 7). The search for stratigraphic and subtle combination traps finally went worldwide, with discoveries in Brazil, the North Sea, Libya, Central Asia, India, China and Australia (Fig. 6). It was during this time that basin-centre gas and coal bed methane plays first came to the world's attention. Although the trap-size distribution remained about the same as in the 1960s (Fig. 7), deeper discoveries became more abundant. Another interesting trend was that offshore exploration for .tUlt, . . . '-:-~: . . . .buau~ldr, . . . : . . . . l":lUlt~ lll~, and subtle combination traps became active in the North Sea during the 1970s (Fig. 6). The number of stratigraphic and subtle combination traps discovered in the 1980s and 1990s is lower than that in each of the previous three decades (Fig. 5). In part, this reflects a decrease in North American onshore exploration activity as the price of oil plummeted in the mid-1980s and stratigraphic and subtle combination trap plays in Rocky Mountain foreland basins reached maturity. However, the apparently small number of traps discovered in the 1990s is largely an artifact of the data used in research for this paper, which relies on released data as its source material. The authors are aware that there have been hundreds of stratigraphic and subtle combination trap discoveries in offshore Brazil, Gulf of Mexico, U K North Sea and offshore West Africa. However, as information from these fields remains largely proprietary, their inclusion in research for this paper was not possible. During the 1980s and 1990s, the locus of exploration activity for stratigraphic and subtle combination traps moved from North America to offshore Brazil, offshore West Africa, the North Sea and onshore and offshore Asia. Fewer than half of the traps discovered since 1980 were located in North America. More than half of the discoveries were offshore turbidite traps, principally in the North Sea, the Atlantic margins of Africa and South America, and the US Gulf of Mexico. The trap-size distribution remained unchanged from the 1970s (Fig. 7).

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS

63

Fig. 5. Frequency of onshore and offshore stratigraphic and subtle combination trap discoveries plotted against year of discovery. The small number of discoveries shown for the 1990's reflects the fact that much of the data for recent discoveries remains proprietary and could not be included in this paper.

Seismic eclipsed all other exploration techniques (Fig. 8) as 3D seismic became a routine exploration tool and amplitude, attribute, AVO (Amplitude variation with off-set) and D H I (Direct hydrocarbon indicator) analyses came into general use offshore. During the 110 years of exploration for stratigraphic and subtle combination traps, a wide variety of techniques was used to make the discoveries. Seismic was involved in only 33 % of the discoveries with 87% of the traps being located onshore (Fig. 5). Active exploration for stratigraphic and subtle combination traps moved into deepwater areas, where costs are higher and risks are greater, at about the same time that 3D seismic became available. As a result, 95% of the offshore discoveries were made using seismic or seismic in conjunction with other techniques (Fig. 8).

Case studies The understanding and application of classification schemes aids in the exploration for stratigraphic and subtle combination traps and knowledge of past exploration approaches allows us to learn from our successes and failures. However, it is also important to consider analogue fields, which can be used to provide benchmarks for geological thinking and

to provide the creative seed for new exploration opportunities. With this objective in mind the following section provides case studies, which can be used as analogue material in the exploration for stratigraphic and subtle combination traps. Five case studies are presented. These cover a diverse selection of discoveries, which have been made by, (a) accident, (b) step-out drilling, (c) facies mapping, (d) change in play concept, and (e) seismic anomaly. By comparing and contrasting these case studies it is possible to examine some of the key elements necessary to successfully explore for stratigraphic and subtle combination traps.

East Texas Field The East Texas Field is located on the flank of the Sabine High in the east of the East Texas Basin, U S A (Figs 9 & 10). It has a STOIIP (Stock tank oil initially in-place) of 7326 MMBO (Million barrels of oil) with ultimate recoverable reserves estimated at 5992 MMBO. The East Texas Field is a classic stratigraphic trap, consisting of a very gently dipping erosionally truncated wedge situated between two unconformities (Fig. 11). The field is unfaulted and the reservoirs consist mainly of high-permeability, strand-plain and beach-ridge sandstones deposited in a wave-dominated

64

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Fig. 6. Number of stratigraphic and subtle combination traps discovered by decade for: (a) North America; (b) Latin America; (c) Europe.

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS

65

Fig. 6. (cont.) Number of stratigraphic and subtle combination traps discovered by decade for: (d) Africa; (e) Asia; (f) Australia.

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Fig. 7. Year of discovery versus original in place oil and gas volumes for stratigraphic and subtle combination traps. delta. The field was discovered in October 1930 and within eight months was producing at a peak rate of 900 000 BOPD (Barrels of oil per day) from 1500 wells. To date, more than 33 000 wells have been drilled on this accumulation. By the late 1920s the area to the east of Dallas, east Texas, was widely regarded within the oil industry as unprospective. A total of 24 wildcats had been drilled in Rusk County and Gregg County and all had been dry. The East Texas Field was discovered by accident. An amateur geologist, Dr A. D. Lloyd, recommended the drilling location to a promoter, Columbus Joiner, on an apparently misconceived geological model. Joiner drilled his first exploration well (Joiner Bradford No. 1) in Rusk County, in the SE of the eventual field area, but the well was abandoned as a result of mechanical and financial difficulties. Undeterred, Joiner drilled his second well only 100 ft from the first, but once again the well was junked and abandoned, although encouragement was drawn from an oil show. The discovery well (Joiner Bradford No. 3), was drilled in October 1930 only 300 ft south of the original well, and tested 300 BOPD (Minor & Hanna 1933). During the next six months, other operators drilled three more wildcats, which tested at rates of up to 10 000 BOPD. However, these wells were up to 15 miles from the discovery and initially it was not clear that they had all pene-

trated the same pool. An oil bonanza was nonetheless certain and impoverished local landowners and speculators bought up acreage and began to drill at an unprecedented rate. By end-May 1931, approximately 3000 wells had been drilled, and 500 000 B O P D were being produced from 1000 completions. As production reached some 900 000 B O P D in August 1931, the East Texas Field was recognized as the largest field in the USA, if not the world. The East Texas Field is approximately 67 km long and 8 km wide and covers an area of 528 km 2 (Fig. 9). The reservoir is contained in a regional subcrop trap in the Upper Cretaceous Woodbine Formation. The Woodbine Formation thins up-dip onto the flanks of the Sabine Uplift and truncates against the base-Austin Chalk unconformity (Fig. 10). The oil is trapped in an unconformity wedge-out with the reservoir occurring between the top-Washita Group unconformity and the Upper Cretaceous baseAustin Chalk unconformity (Fig. 11). The unconformities probably resulted from uplift of the Sabine Uplift. An alternative interpretation of the upper surface of the reservoir was presented by Gussow (1972, 1973), who argued that the up-dip pinch out is not erosional, but reflects depositional thinning and onlap onto the Sabine High. This latter interpretation is not widely accepted and hence the erosional truncation model is the preferred model in this

STRATIGRAPHIC A N D SUBTLE COMBINATION TRAPS

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Fig. 9. Gross isopach map of the Woodbine Sandstone in the East Texas Basin, USA. Note cross section depicted in Figure 10 (after Halbouty 1991; AAPG 9 1991, reprinted by permission of the AAPG, whose permission is required for further use). summary. The top of the reservoir dips to the west at <1 ~ and the oil accumulation is entirely dip-closed in the north, west and SW. In the far south of the field there is a small structural saddle, with an isolated gas accumulation developed to the south of this (Gussow 1972). The East Texas Field represents a significant oil accumulation and is an excellent analogue for stratigraphic traps associated with an unconformity subcrop wedge. The discovery can be described as an accident as the play type was unknown at time the of drilling. However such accidents are not unique in the discovery of subtle combination and stratigraphic traps as demonstrated by the following case study, a c a r b o n a t e example from a n o t h e r mature onshore area. What these two examples demonstrate is that explorationists should always be challenging the current geological paradigm, as oil is not necessarily where it was expected, but where it was found!

Jay Field The Jay Field is located along the eastern part of the Upper Jurassic Smackover trend, which extends from eastern Texas to western Florida (Fig. 12). The Jay Field is an example of a subtle c o m b i n a t i o n trap formed by lateral facies change on the nose of a rollover anticline (Fig. 13). It was the lack of obvious structural closure that caused the late discovery of the Jay Field (in 1970). However, despite the absence of any prominent structural closure, the Jay Field is the largest of the Smackover fields with STOIIP of 728 MMBO. Production is from dolomitized peloidal packstones and mixed peloidal-oolitic grainstones. The carbonates making up the reservoir are highly stratified and have laterally variable porosity distribution. Exploration for the Upper Jurassic Smackover Formation was initially concentrated in southern Arkansas and n o r t h e r n Louisiana

STRATIGRAPHIC A N D SUBTLE COMBINATION TRAPS

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southern Alabama when the Norphlet sand, lying just below the Smackover, was found to be gas bearing. In 1970 an appraisal well (Exxon St. Regis No. 1) was drilled to target an apparent four-way dip closure south of the Flomaton Gas Field. Instead of penetrating gas-bearing Norphlet sand, the well penetrated 156 ft of oilbearing dolomite in the Smackover Formation. The well was completed for 1762 BOPD with 3450 psi flowing tubing-head pressure and was the discovery well for Jay Field. The well was actually located on the crest of a structural nose extending south from the Flomaton gas field. Within three months a second confirmation well discovered the Alabama part of the Jay Field, designated as the Little Escambia Creek (LEC) Field. By the end of 1970 five wells had been completed in the Jay-LEC fields. Production at the Jay-LEC fields was initiated in December 1970 at 2000 BOPD. Within the broader arcuate distribution of the Smackover ramp carbonates around the Jurassic rim of the Gulf of Mexico, the Jay Field occurs in the Conecuh embayment between the Conecuh ridge and the Pensacola arch (Fig. 12). Ottmann et al. (1973) interpreted these ridges to be Appalachian structural features which in part

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS

71

Fig. 12. Palaeogeographic map showing the depositional setting of the Jay trend area, USA during the Late Jurassic (Oxfordian) (after Bliefnick & Mariotti 1988) 9 SEPM, Society for Sedimentary Geology.

influenced Smackover deposition, particularly by channelling tidal currents across the Jay Field area. The structural portion of the Jay Field trap is on the nose of a rollover anticline along the downthrown side of the extensional Pickens-Gilbertown fault system (Ottmann et al. 1973; Sigsby 1976). The Smackover is not completely sealed by structural closure, as can be seen in Figure 13a, and the up-dip trap is formed by a facies change to dense lime mudstones (Fig. 13b). The field has a productive area of 14 415 acres. Although there is only 100 ft of structural relief on the Jay nose above the saddle separating it from the large Flomaton

structure adjacent to the north, the trap supports an oil column of 420 ft, indicating entrapment in a subtle combination trap (Fig. 13). The Jay field is an example of a major hydrocarbon trap, which was unexpectedly discovered within a mature area. A combination of subtle structural features and facies variation make the Jay field an important example. The Jay and East Texas examples can both be described as accidental discoveries. In fact many stratigraphic and subtle combination traps successes are due to luck. However, the following example runs contrary and provides

72

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STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS an excellent example of where geological due diligence paid off. Ansai Field

The Ansai Field is an example of a stratigraphic trap discovered through detailed facies mapping. It is located in the central part of the Ordos Basin, north-central China (Fig. 14) and was discovered and brought on stream in 1983. Cumulative production for the field as of end2000 was 57MMBO. With a STOIIP of 1810 MMBO, the Ansai Field is the largest field in the Ordos Basin, having ultimate recoverable reserves of 330 MMBO. Oil production is from lacustrine deposits of the Upper Triassic Yanchang Formation. The formation is a selfcontained petroleum system in which relatively deep lacustrine shales provide the source rocks, deltaic sandstones form the reservoirs and lacustrine and interdistributary mudstones provide top and lateral seals. Oil is trapped predominantly in stratigraphic traps, which occur in five separate pools. Reservoirs are located in delta-front mouth-bar, delta-front and delta-plain distributary-channel sandstones, with the majority of the reserves occurring in the mouth-bar sandstones of the Chang-6 reservoir unit (Fig. 15). Oil seeps in the Ordos Basin had been found and used by the ancient Chinese as early as the Song Dynasty (c. 1000 AD). Modern exploration activities began in the late 19th century and the first field in China (the Yanchang Field) was discovered in 1907, with oil flowing from the U p p e r Triassic Yanchang Formation (Yang 1992). Extensive exploration began in 1950 with regional geological and geophysical surveys. Between 1950 and 1957, a total of 96 wildcat wells were drilled and a number of oil shows were discovered in the Triassic Yanchang Formation. By the mid-1960s, it was realized that good source rocks exist in the southern Ordos Basin, as evidenced by 215 oil seeps and 253 oil shows. A variety of trap types, including anticlinal and lithological traps, were also identified. Extensive drilling was therefore carried out in the southern and western parts of the basin leading to the discovery of the Lizhuangzi, Majiatan and Liujiazhuang fields (Fig. 14). Encouraged by these discoveries, large scale drilling, assisted by seismic surveys, led to

73

further discoveries in the southwestern part of the basin. By 1978, exploration for the Yanchang Formation reservoirs had come to a halt. As part of an effort to replace Ordos basin reserves, a series of basinal petroleum evaluation studies were carried out in the early 1980s, focusing on the Upper Triassic Yanchang Formation. The studies indicated that the Yanchang Formation lacustrine system not only provided prolific source rocks, but deltaic sandstones in the east and sub-lacustrine fan sandstones in the west represented potentially good reservoirs. The Ansai area, lying at the centre of the Triassic lacustrine delta, was selected as the first target. In 1983, the first six wildcats were drilled into the main sand body of the Ansai Delta; three encountered commercial oil flows. An appraisal program followed, comprising 74.1 km of seismic data and 37 appraisal wells, ten of which encountered commercial flow. In 1985, 46 more wells were drilled. This drilling program not only broadly delineated the field area, but also established the regional depositional framework. It was found that the Ansai Delta contained three main reservoir units: (1) a shallow reservoir (Chang-2) consisting of delta-plain distributary channel sand bodies; (2) a middle reservoir (Chang-(4+5)) consisting of delta-plain and delta-front distributary channel deposits; and (3) a deep reservoir (Chang-6) consisting of delta-front mouth-bar sands (Fig. 11). Trapping is stratigraphic and related to lateral depositional pinchout and lateral facies change. Between 1986 and 1988, 38 more appraisal wells were drilled, and by the end of 1988, the field was almost completely delineated. A total of five oil-bearing blocks (Fig. 16) were confirmed with an overall oil-bearing area of 206 km 2 and a STOIIP of 780 MMBO (Ling & Li 1997; Qiu & Gong 1999). The Ansai Field case study demonstrates the successful search and discovery for stratigraphic traps based on a sound understanding of the local and regional geology. This geologically focused approach to exploration is expanded on in the following example, where both geological and strategic business efforts culminated in the discovery of a subtle combination trap containing a major oil reserve.

Fig. 13. Structural contour maps of the Smackover Formation: (a) Jay trend area with distribution of fields (Bliefnick & Mariotti 1988) 9 SEPM, Society for Sedimentary Geology; and (b) Jay-LEC fields. Jay Field is a subtle combination trap formed by updip lateral facies change on the nose of a rollover anticline (Ottmann et al. 1973).

74

J.R. ALLAN ETAL.

Fig. 14. Map of the Ordos Basin, China, showing the main structural elements and location of Ansai and other nearby oil and gas fields (Yang 1992).

Nelson Field The Nelson field is an oil field with potential that was realized only through the development of a new play concept. The structure on which Nelson is located is a low-relief anticline with

four-way dip closure. However, it was only after Enterprise Oil combined modern and ancient analogues with a detailed appreciation of local geology, that its potential was appreciated. This lay not in the structural closure alone, but in localized stratigraphic traps developed upon it.

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STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS The key intellectual leap was to recognize that sand-prone deepwater channels could be recognized on reflection seismic. The Nelson Field therefore represents an excellent example of a channel-fill subtle combination trap discovered in a mature area only after the development and application of new thinking. The Nelson Field is located in the Central North Sea next to BP's Forties Field and occurs half in UK Block 22/6a and half in Block 22/11 (Fig. 17). It has over 500 MMB of recoverable oil reserves, located in Palaeocene sands of the Forties Formation. The Nelson Field was found some 20 years after the Nelson structure was first drilled. In the early years, the Late Palaeocene Forties Sands were not the main objective. In fact the first well on the block encountered them in an unfavorable facies whilst drilling to deeper targets. It was not recognized for some time that there was a sharp lithological contrast between the massive turbidite sands within the channels of the Forties submarine fan and the fine-grained, thinly-bedded inter-channel facies. The Nelson Field was 'rediscovered' in 1988 by Enterprise and appraised by a total of thirteen wells, drilled both by Enterprise in Block 22/11 and by Shell/Esso in the adjacent Block 22/6a. The Upper Forties reservoir proved to be complex, with at least three separate channel developments. The decision to develop the field was taken in the late 1980s, and it was brought on stream in the early part of 1994. Both blocks were awarded as part of the UK Second Licensing Round in 1965: Block 22/6 went to Shell/Esso, while Block 22/11 to the south was obtained by Gulf (100%). Early seismic had revealed the presence of a shallow, low relief anticline, but the stratigraphy at that time was virtually unknown (Whyatt et aL 1991, 1992b). Shell/Esso and Gulf contributed jointly to the cost of the first well, 22/11-1, which was drilled at a location right in the centre of the structure. The well reached the Permian Rotliegendes Formation at a TD of 10 846 ft, but the best oil shows were encountered within the Lower Tertiary section, where a series of thinly bedded sandstones were interpreted to be oil bearing. However, an open-hole test failed to produce more than minor traces of oil, so the well was abandoned as dry. Gulf then farmed out part of its equity to the National Coal

77

Board, which later passed it over to Britoil. Conoco farmed into Block 22/11 in 1972 and drilled a well (22/11-2) just south of the then recently discovered Forties Field. The Conoco well only encountered minor oil shows in the Palaeocene Forties sands. Conoco's second well, 22/11-3, located in the west of the block and drilled in 1983 (Figs 17 & 18), was even less successful. This was no doubt instrumental in convincing the three partners in the block, Conoco, Britoil and Chevron (ex-Gulf equity), to allow Enterprise to farm-in with an equity level of 30%, in 1985. Enterprise's obligatory farm-in well, 22/11-4, drilled in 1986 in the southwestern part of the block, was not successful, and this turned out to be the last straw for the original partners, for they agreed to concede all their equity in the block to Enterprise. Before the ink was dry on these 1987 agreements, Enterprise had spudded two wells, 22/11-5 and 22/11-6 (Fig. 18) from a sub-sea template, centrally placed near the original 22/11-1 well. The wells targeted seismically defined sand-prone turbidite channels (Fig. 19). These were defined by a combination of isochore mapping, seismic facies calibrated with core data from local fields, and application of seismic analogues from present day submarine fans (Whyatt et al. 1992a, b). Both wells were completed and tested early in 1988 at rates of 6720BOPD and 1 0 2 2 4 B O P D respectively, proving the existence of good quality sands and commercial volumes of oil. Shell/Esso confirmed the extension of the Nelson Field in Block 22/6 shortly afterwards and this was followed by a further three appraisal wells in each block. It was decided to develop the field jointly, with Shell/Esso being responsible for platform design, construction and installation and Enterprise undertaking the pre-drilling of ten sub sea production wells (Watt 1993). The Nelson Field was put on stream in February 1994, from which date, operatorship of the field was passed over to Enterprise. The Nelson Field represents a classic successful case of applying a change in play concept. Whilst it is clear that the Nelson structure was a large seismically defined feature it was not the application of routine thinking that resulted in a commercial discovery but the appreciation that stratigraphic targets could be identified on

Fig. 16. Structural contour map, top Chang 6 reservoir, Ansai Field. Oil is trapped predominantly in stratigraphic traps, which occur in five separate pools. Reservoirs are located in delta-front, delta-front mouth-bar, and delta-plain distributary-channel sandstones (Anon. 1991). The insets are NE-SW cross-sections through the Pingqiao (AA') and Wangyao (BB') blocks.

78

J.R. ALLAN E T A L .

Fig. 17. Regional structure map illustrating the position of the Nelson Field, North Sea, with respect to the Forties Montrose High and other fields with the same reservoir. Channels in the Upper Forties Sand member are shown in brown (Whyatt et al. 1992b 9 Springer Verlag). the structure using seismic. C o n s e q u e n t l y several decades were to elapse after the drilling of this first well before the half-billion barrel Nelson Field was confirmed on the originally drilled structure. The next case study expands

on the application of seismic techniques to explore for stratigraphic and subtle combination traps by highlighting an example where seismic anomalies were used to image an offshore subtle combination trap.

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STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS Bullwinkle

Field

The Bullwinkle Field lies in Green Canyon Blocks 65, 108 and 109 in the Northern Gulf of Mexico Basin, USA (Fig. 20). Oil and gas are entrapped by onlap pinchout of Pliocene turbidite sandstones onto structural-flank unconformities on the western and northern margins of the Bullwinkle salt-withdrawal minibasin and onto a salt high in the southwestern part of the field (Figs 21 & 22). Post-depositional diapiric salt movement created the current structural configuration (O'Connell et al. 1993). The field was discovered in 1983 and began production in 1991. It contains 190 MMBO and 600 BCFG (Billion cubic feet of gas) in-place. The medium to light oils are contained in multiple Pliocene sandstone reservoirs, with >90% of the reserves in the J Sands, the most important of which is the J2 unit. The J Sands are amalgamated channel and sheet sand turbidites that have excellent reservoir properties with permeabilities up to 2700 mD. The J Sand interval contains four main reservoir sandstones that are divided by shales deposited as debris flows/slumps, which form baffles and barriers to fluid flow. The sands share a common aquifer, which is the principal production drive mechanism, supported by solution-gas drive and gas-cap expansion. The first exploration phase in the Northern Gulf of Mexico Basin in the first two decades of the 20th century was essentially based on drilling over seeps and on surface structures. The second phase up to the 1940s included the first extensive application of geophysical technology and resulted in 21 giant discoveries, most of which were associated with salt structures, salt-cored anticlines, or fault-controlled anticlines in the Louisiana and Texas Coastal Plain. During the late 1940s exploration moved into shallow-water offshore Louisiana and involved exploration for salt-related structural traps analogous to the earlier onshore Texas and Louisiana discoveries (Lore 1994; Bacigalupi et al. 1998). Discoveries in the Plio-Pleistocene slope trend began in the 1960s and have continued until the present day. After the 1970s, exploration focused on deeper water offshore structures. Miocene-Pleistocene slope turbidite sands deposited in salt mini-basins are the main reservoirs in this region and seismic amplitude anomalies are used to determine their fluid

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content (Nehring 1991; Ward et al. 2002). Predrill correlation of seismic amplitudes and geometry to reservoir presence and quantification of AVO anomalies for fluid fill, play an essential role in identifying successful stratigraphic traps in the region. The Bullwinkle Field was discovered by Shell in 1983. The discovery well, GC65-1, targeted a large 2D seismic amplitude anomaly at the Plio- Pleistocene level, close to the northern margin of a salt-withdrawal mini-basin known as the Bullwinkle Basin (Fig. 22). The well confirmed the predrilling model of turbidite sandstones along a proven turbidite fairway (Holman & Robertson 1994). A total of four appraisal wells and four sidetracks were drilled in adjacent Green Canyon Blocks 108,109 and 110 to evaluate and delineate the reservoirs (Sterling et al. 1989). The first 3D seismic data were acquired in 1984 in conjunction with the drilling of three of the appraisal wells. Since the first 3D dataset was deemed to be inadequate, two additional, orthogonal 3D seismic surveys, comprising 7200 km 2, were acquired in 1988. Comparisons of the two surveys showed that data acquisition oriented in a strike direction to the salt face yielded a superior sediment image, particularly near overhung salt. The improved imaging of the pay zones increased reserves estimates by 20% and reduced the number of planned development wells from 30 to 20 (O'Connell et aL 1993). The Bullwinkle Field covers 7 km 2 (1730 ac). Light oil and gas occur in multiple Pliocene sandstone reservoirs, each with separate fluid contacts. The bulk of the reserves (>90%) are contained in the J Sand unit, in particular the J2 Sand, which has an estimated hydrocarbon column height of 1500-1600 ft (Holman & Robertson 1994; Westrich et aL 1995). The J Sands are sealed laterally and vertically by bathyal shales. On the basis of PVT analyses of the fluids, the structure at the J2 Sand level is considered to consist of two reservoir compartments separated by a stratigraphic permeability barrier.

Summary data for 174 stratigraphic and subtle combination traps The five case studies discussed above are a small part of a wide spectrum of stratigraphic and

Fig. 19. ENE-WSW seismic line CNST-82-3 crossing the Nelson Field through the first well location on the block, 22/11-1. Nelson Field is a channel-fill subtle combination trap formed by lateral deposition pinchout of sand-filled channels on a low-relief anticline. The well is located between two prominent Upper Forties channels, shown by local thickening (Whyatt et al. 1992b 9 Springer Verlag).

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Fig. 21. WNW-ESE 3D seismic cross-sections across the Bullwinkle Field (O'Connell et al. 1993). Hydrocarbon related seismic amplitude anomalies are shown in brackets, with the limits of the J Sand amplitude anomaly arrowed,

Fig. 20. Hydrocarbon occurrence in the Green Canyon Block and the location of the Bullwinkle Field (Weimer et al. 1998; A A P G 9 1998, reprinted by permission of the AAPG, whose permission is required for further use).

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Fig. 22. Early NW-SE 2D seismic cross-section over the Bullwinkle Field, showing northwestward onlap of Upper Pliocene section and pinchout of the 'J' Sand onto the basin-margin unconformity (Holman & Robertson 1994) 9 SEPM, Society for Sedimentary Geology. The penetrations of well GC 109 and its sidetrack are also shown.

subtle combination trapping mechanisms in our much larger study of 174 fields, which together contain over 2009 BBOE. The range of trapping mechanisms is summarized in Figure 23, which illustrates the diversity of stratigraphic and subtle combination traps discovered since 1885. From the case studies and exploration history review, it is apparent that the successful exploration for stratigraphic and subtle combination traps requires a more intimate knowledge of the geological history and stratigraphic relationships within a basin than exploration for structural traps. As an aid to achieving a successful exploration strategy, several key considerations relevant to stratigraphic and subtle combination traps are noted. These considerations are intended to act as a framework to help develop robust exploration strategies and consist of the following non-sequential steps, (a) establish basin setting, (b) establish probable trapping mechanism, (c) estimate the trap size probability distribution.

Basin setting By far the greatest number (95) and largest percentage (55%) of stratigraphic and subtle combination traps occur in foreland basins (Fig. 24). Intracratonic, rift and passive margin basins place a distant second, third and fourth. Each of the remaining six structural settings accounts for no more than 4% of the traps. Intrashelf basins on passive margins and delta/salt mini-basins (located on the US Gulf of Mexico continental slope) both occur within larger passive margin structural settings. When traps located within intrashelf basins and delta/salt mini-basins are grouped with passive margin traps, they still account for only 13% of the stratigraphic and subtle combination traps in this report. This, of course, is due in part to the difficulty in obtaining proprietary data on recent deepwater discoveries, many of which occur in passivemargin settings. Foreland basins contain the greatest number

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS

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Fig. 23. Distribution of principal trap categories for stratigraphic and subtle combination traps. of stratigraphic and subtle combination traps and the largest in-place volumes and recoverable reserves. However, large reserves do not always correspond to a large number of traps in other

structural settings. For example, wrench, salt and intrashelf basins contain larger in-place volumes and recoverable reserves than intracratonic basins, even though they possess far fewer traps

Fig. 24. Distribution of stratigraphic and subtle combination traps by the main structural settings of the basins in which they are located. About 55 % of the traps occur in foreland basin settings.

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Fig. 25. (a) Distribution of original in-place oil and gas volumes in stratigraphic and subtle combination traps amongst main structural settings. (b) Distribution of ultimate recoverable oil and gas reserves in stratigraphic and subtle combination traps amongst main structural settings. Foreland basins contain the greatest number of stratigraphic traps and the largest in-place and recoverable volumes.

(compare Figs 25a & b to Fig. 24). This is because wrench, salt and intrashelf basins each contain a multi-billion barrel field (Kern River Field in the San Joaquin wrench basin, Marlim

Field in the Campos salt basin, and East Texas Field in the East Texas intrashelf basin), while no fields of this size occur in intracratonic basins.

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Trapping mechanism

Trap sizes

Whilst such statistics are interesting in their own right it is perhaps more useful to look at accumulation volumes in light of the trapping mechanism (Fig. 4). From the studied data it is evident that nearly 40% of the unconformity-truncation and onlap traps have recoverable reserves >600 MMBOE (Million barrels of oil equivalent) (Fig. 26d). In contrast, 93 % of the channelfill and valley-fill traps have recoverable reserves of <400 MMBOE (Fig. 260. Subcrop and onlap traps tend to be large because they produce from laterally continuous reservoirs with large productive areas. Individual channel-fill and valley-fill traps tend to be small because they produce from discontinuous fluvial and estuarine sands. However, reserves in a channel-fill or valley-fill play can be quite large because the traps are generally clustered in trends that consist of many small to medium-sized fields. Proportionally, many more lateral depositional pinchout traps have recoverable reserves of >200 M M B O E than do lateral facies change traps (compare Fig. 26b & h). Most of the lateral depositional pinchout traps in the 200-500 MMBOE size range are clastic delta and turbidite fan-lobe traps that produce from numerous reservoir sands. The many productive intervals in each trap explain their larger size compared to lateral facies change traps, which tend to produce from fewer zones. Fracture traps tend to be regional in scale. Because of their large productive areas, many contain large recoverable reserves (Fig. 261). Finally, different trapping mechanisms within the same trap regime may result in very different reserves distributions. Hydrodynamic and basin-centre gas accumulations are both fluidic traps. However, hydrodynamic traps, which are local in scale, tend to have limited productive areas, low net pay, and small reserves, while basin-centre gas traps, which are regional in scale, generally contain huge reserves (Fig. 27b). A few trapping mechanisms are responsible for a disproportionate amount of the in-place volumes and recoverable reserves found in stratigraphic and subtle combination traps. Lateral depositional pinchout traps are the most abundant trap type and as a group contain the largest in-place volumes (Fig. 27a). Subcrop and onlap traps, although far fewer in number, are much larger in size and contain the largest recoverable reserves (Fig. 27b). Six of the subcrop traps and four of the onlap traps have ultimate recoverable reserves >1 BBOE. Basin-centre gas and coal bed methane traps are regional traps with huge productive areas and also have large reserves (Fig. 27b).

Major oil companies have, in recent years, targeted their exploration efforts to locate 'elephants' as it is only through their discovery that the promised company growth can be realized. Medium-sized oil companies and independents can of course afford the luxury of exploring for smaller accumulations as the net growth from a medium or even small find is significant. In considering stratigraphic and subtle combination traps as potential targets for companies of any size, it is worth remembering that, like structural traps, stratigraphic and subtle combination traps can occur as single accumulations (e.g. East Texas, Nelson and Jay fields) or they can occur in trends and clusters, which add up to significant volumes (e.g. Ansai Field). From analysis of the data included for this paper it can be demonstrated that stratigraphic and subtle combination traps are associated with a wide range of trap sizes as depicted in Figures 26 and 27. Thirty-six of the stratigraphic and subtle combination traps have original inplace oil and gas volumes >1 BBOE. Ninetyone traps have original in-place oil and gas volumes <1 BBOE. Twenty-five traps have ultimate recoverable reserves >1 BBOE. However the modal frequency occurs in the field-size range of 50-300 MMBOE. It is worth reflecting that amongst all these statistics the largest conventional oil field is Prudhoe Bay Field, USA, a regional subcrop trap with an original in-place volume of 30.8 B B O and ultimate recoverable reserves of 12.3 BBO.

Heavy oil traps Light oils are obviously attractive and it is not worth expanding on them from the perspective of stratigraphic and subtle combination trapping mechanisms. What is worth further consideration is heavy oils and gas, as these fluids are often associated with stratigraphic and fluidic trapping mechanisms, which have large areal distributions and contain large volumes. They are often not given appropriate focus due to their classification as 'unconventional'. Heavy oil, often dismissed because of low value per barrel, can be present in large volumes in stratigraphic and subtle combination traps. For example, the largest heavy oil field is the Athabasca Oil Sands, Canada, a lateral depositional pinchout trap which contains an in-place volume of 902 BBO of heavy oil and tar. Its ultimate recoverable reserve is as yet unknown. Cerro Negro and Machete, two producing areas

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Fig. 27. Distribution of hydrocarbon volumes in stratigraphic and subtle combination traps shown by main trapping mechanism; (a) in-place volumes; and (b) ultimate recoverable reserves. Regional subcrop and onlap traps, although far fewer in number than lateral pinchout traps, are much larger and contain greater recoverable reserves.

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J.R. ALLAN E T A L .

which produce from onlap traps in the Orinoco Heavy Oil Belt, Venezuela, have the largest recoverable oil reserves, estimated at 25.6 and 20.0 BBO respectively. The potential of discovering volumes of such magnitude is a powerful argument for targeting stratigraphically trapped heavy oil or tar accumulations, particularly in today's economic climate where heavy hydrocarbons are economically recoverable due to improved technology (Alberta Energy and Utilities Board 2000). Gas and condensate traps

Gas and condensate are also important from the perspective of stratigraphic and subtle combination traps, as they are associated with basincentre gas and coal bed methane accumulations, both of which have been proven to contain significant volumes of in-place hydrocarbons (Fig. 27a & b). Many of these traps contain huge reserves, as exemplified by the ElmworthWapiti basin-centre gas trap in Canada (800 TCFG in-place, 20 TCFG recoverable) and the Bowen Basin coal bed methane trap in Australia (>60 TCFG in-place). Basin-centre gas accumulations may result from hydrostatic entrapment caused by lateral capillary pressure changes from gas-saturated clean sandstones down-dip into water-wet shalier sandstones updip (Elmworth-Wapati and Blanco Mesaverde fields, North America), by hydrodynamic entrapment on the flank of a regional high (Dauletabad-Donmez Field, Turkmenistan), or by a combination of the two (Hoadley Field, Canada). The current economics of world hydrocarbon resources make gas an increasingly valuable commodity, as quoted from the Petroleum Technology Transfer Council's Year 2000 Symposium on Basin-Centred Gas: 'It is becoming critical that the US. industry more fully develops the Nation's large "unconventional" gas resources. A t present about 15% o f the US. total gas production is from "unconventional" basin-centred (synclinal) gas resources. Basin-centred gas production is in its infancy, but will increase as more explorationists become aware o f this enormous gas resource. More effective exploration and exploitation strategies will be necessary in the near future to meet the increasing emphasis on this resource'.

Whilst there are clear analogues for reviewing stratigraphic and subtle combination trapping mechanisms from the perspective of basin setting, trapping mechanism and trap size the successful exploration for such plays requires not only an understanding of relevant analogues but also the application of appropri-

ate geoscience techniques. Techniques relevant to the exploration for these traps are outlined in the following section.

Exploration techniques Whilst numerous successful discoveries of stratigraphic and subtle combination traps can be documented, it is important to note that dry hole risk is greater than in structural traps. This situation arises from difficulties in locating updip depositional pinchouts or facies-change seals, particularly if deterioration in reservoir quality has created a large waste zone at the pinchout. Consequently, several dry holes are usually drilled prior to a discovery. Additional costs and risks are incurred through the necessity of drilling numerous appraisal wells to locate lateral seals and to establish the size and commercial viability of a trap. Failure to recognize a stratigraphic or subtle combination trap must also be considered a significant exploration risk. Several large accumulations included in this study (e.g. Nelson, Miller, Harding, Gryphon fields in the North Sea, Upper Valley Field in the USA) were discovered by the second or third leaseholder on relinquished acreage because the original leaseholder failed to recognize the trap. Most of these missed opportunities were caused by one or more of the following reasons: (1) Poor seismic resolution, which made it difficult to identify the updip or lateral seals to a trap and prove closure. As a result, the prospect was considered too risky to drill. (2) Encountering a thin pay zone, failing to recognize that it covered a large productive area and dismissing the prospect as noncommercial. (3) Misinterpreting a large combination trap as a small structural closure because of failure to recognize a stratigraphic component to entrapment. (4) Failure to recognize a stratigraphic or subtle combination trap because of unfamiliarity with unconventional trapping mechanisms (e.g. basin-centre gas, subtle fracture, hydrodynamic traps). These often occur in unexpected locations (e.g. in basincentre synclines or down-flank on large structures) and sometimes have unusual well-log responses. Although stratigraphic and subtle combination traps carry a few more risks than structural traps, by using the exploration techniques most appropriate for each trap type, many of these risks can be minimized. Whilst a detailed

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS analysis of all available geoscience techniques that have application to the exploration for stratigraphic and subtle combination traps is beyond the scope of this paper it is worth noting some of the key geological, geophysical and geochemical techniques. Geological techniques

Arguably the most important starting point in exploring for stratigraphic and subtle combination traps is a detailed sequence stratigraphic framework. A comprehensive discussion of sequence stratigraphic principles and techniques is beyond the scope of this paper and the reader is referred to excellent publications by Bally (1987); Mitchum et al. (1977); Payton (1977); Sarg (1988); Vail (1987); Van Wagoner et aL (1988, 1990) and Weimer & Posamentier (1993). An excellent five-step approach to stratigraphic trap exploration, which relies heavily on sequence stratigraphic analysis, is described by Dolson et al. (1999). In summary these stages include: (1) Using seismic and log cross-sections, identify all unconformities in a basin or area of interest, subdivide the sedimentary section into genetically related sequences, and construct a sequence stratigraphic framework. Identify all maximum flooding surfaces, condensed sections and transgressive surfaces within each sequence. The locations of stratigraphic and subtle combination traps are generally controlled by third-, fourth- and fifth-order sequences. Third-order sequences represent major sea-level cycles and consist of highstand systems tracts (HST), transgressive systems tracts (TST) and lowstand systems tracts (LST). Different types of stratigraphic and subtle combination trap are found within each systems tract (Fig. 28). (2) Interpret seismic facies within each sequence, using reflection-pattern geometries and calibrate the reflection patterns to lithology using well data (Mitchum et al. 1977; Brown 1999). (3) Using seismic, lithologic, biostratigraphic, chronostratigraphic and palaeoenvironmental data, construct facies maps and cross-sections for all areas of interest. A good sequence stratigraphic framework is essential, because it provides the means for constructing palaeogeographic maps of facies belts at precisely defined intervals of time. (4) Within each sequence stratigraphic framework, use the facies maps and cross-

(5)

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sections that have been constructed to identify those sequences that appear most likely to contain good reservoirs and viable seals. Within each of these sequences, identify and map the shoreline trends, shelf breaks, regional facies transitions, and local unconformities. Different trap types will be associated with each feature. Using analogue traps as a guide, examine each of these features for evidence of stratigraphic and subtle trapping configurations using the maps, cross-sections and seismic data.

Although the optimal exploration strategy for each trap type described in this paper (Fig. 4) is somewhat different, similar strategies often apply to traps located in the same systems tract or in similar palaeogeographic settings. For example, although trapping configurations may be quite different, the same basic approach is used to search for lateral depositional pinchout and channel-/valley-fill traps that occur in marginal marine and continental settings. Turbidite lateral depositional pinchout traps, turbidite channel-/canyon-fill traps, and carbonate debris-flow traps belong to different trap categories. However, because all occur in the same palaeogeographic setting (the outer shelf and slope), exploration strategies for these three trap types have many similarities. In contrast exploration for subcrop and onlap traps, which are both associated with unconformities, involves a set of exploration approaches that differ from those for depositional pinchout traps. Delineation and development approaches and strategies differ for combination traps as opposed to pure stratigraphic traps. Structure maps are useful for evaluating spill points and estimating locations of hydrocarbon-water contacts in combination traps, particularly those located on structural noses. However, they provide little useful information for evaluating pure stratigraphic traps. 3D seismic technology now offers the potential to define stratigraphic traps (see the following section). Before 3D seismic was available, depositional pinchout, lateral facies change, channel-/valley-fill, subcrop and onlap traps were delineated by first drilling step-out wells up-dip and down-dip. Analogue fields, particularly earlier discoveries in the same play, were often used to predict trap geometry and guide step-out drilling. Analogues are particularly useful when the trap has an unusual geometry, such as the narrow, elongate shapes characteristic of incised shoreface and barrier island lateral depositional pinchout traps, channel- and valley-fill traps and

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Fig. 28. Schematic cross-section illustrating typical locations of stratigraphic and subtle combination traps within a third order sequence. Different types of stratigraphic and subtle combination trap are found within different systems tracts (Baum & Vail 1988; Sarg 1988; Dolson et al. 1999) 9 SEPM, Society for Sedimentary Geology. dolomitization/dissolution traps. Careful welllog analysis is of the utmost importance. The sequential log analysis approach described in Rider (1996) can be used along with image logs to define key unconformity surfaces and to aid in delineating facies geometries. Accurate log evaluation is also important when evaluating tight sands in basin-centre gas traps to determine whether they will be capable of commercial flow (Shanley et al. 2004). Special

maps and cross-sections may be required to evaluate certain reservoir types. For example, a potentiometric map is the best tool for predicting the direction in which an oil accumulation has been displaced by hydrodynamic flow in an aquifer. Maps of bulk permeability calculated from log porosity-permeability transform equations are helpful for identifying fractured high-productivity 'sweet spots' in basin-centre gas traps and subtle fracture traps, but only

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS really have true value when integrated with dynamic data, which is a significant limitation when historic data are unavailable.

Geophysical techniques 3D seismic technology has changed the way in which stratigraphic and subtle combination traps are delineated and developed, dramatically lowering dry-hole risk and enhancing the effectiveness of well placement. It is particularly effective for imaging and delineating young, poorly consolidated siliciclastic reservoirs with high porosity and sandstones that pinch out into shale, since the pronounced acoustic impedance contrast between sandstone and shale allows the edges of reservoirs to be precisely defined. Seismic reflection amplitude is now used to accurately map the wedge-out edges of porous reservoirs in stratigraphic traps, which previously had been difficult or impossible to detect. Amplitude-derived attributes and acoustic impedance contrasts can, when calibrated to core and well logs, be used to map rock properties within reservoirs. Examples that illustrate the application of these techniques to delineation and development of stratigraphic and subtle combination traps are presented in the following section. For a more exhaustive treatment of 3D seismic interpretation techniques, the reader is referred to Brown (1999). Amplitude displays of 3D seismic data are extremely useful for identifying locations of reservoir pinchouts and estimating reservoir thickness and quality. Seismic reflectors dim as a reservoir thins and disappear at the pinchout edge, providing a means for precisely determining the positions of up-dip and lateral pinchout seals. This greatly diminishes the risk of drilling dry holes along the edges of stratigraphic and subtle combination traps. The amplitude of a seismic bright spot generally becomes higher with increase in N/G ratio, porosity, or hydrocarbon saturation. Horizon-slice maps can be used to display this lateral variation in seismic amplitude within a reservoir. Once seismic amplitude has been calibrated to well data (Fig. 29a), seismic amplitude maps can be used to identify areas with the best porosity (Fig. 29b) or highest N/G ratio (Fig. 30). Using this information, development wells can be sited to target areas of highest reservoir quality thus maximizing flow rate and ultimate recovery. It is now possible to define the spatial distribution of amplitude anomalies so accurately that they can be used to plan trajectories of horizontal wells. Because of the acoustic impedance contrast between sandstone reservoirs and enveloping

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siltstone and shale seals, seismic lithologic velocity modeling can be used to precisely define the boundaries of lateral depositional pinchout, onlap pinchout, and channel-/valleyfill traps. Seismic AVO modelling (amplitude variation with offset) can be used to identify oiland gas-bearing reservoirs, image facies changes in carbonates, and map net pay in sandstone traps. Stacking patterns of seismic reflectors are now regularly used to decipher the internal geometry of reservoir sand bodies, which gives geologists and geophysicists the ability to identify and map depositional facies using seismic data. Once the reservoir distribution has been mapped from seismic amplitude, acoustic properties can be correlated to rock properties and used to create maps of important reservoir parameters. Fractured 'sweet spots' within reservoirs can often be identified through the use of 3-component seismic data or by break-up of seismic reflectors. An example of this phenomenon can be seen in Figure 31. In highporosity, poorly consolidated reservoirs, direct hydrocarbon indicators (DHIs) can often be used to identify hydrocarbon-water contacts. Hydrocarbon accumulations may appear as bright or dim spots that terminate at hydrocarbon-water contacts, while fluid contacts may appear as flat spots on seismic profiles. The ability to directly detect and map fluid contacts seismically lowers down dip dry hole risk during delineation drilling and allows trap size to be appraised using fewer wells. Recently, 4D seismic has come into use as successive time lapse 3D seismic surveys have been utilized to monitor steam flow and sweep efficiency in reservoirs undergoing steam flood tertiary recovery. This new 3D seismic technique will be of particular importance in the exploitation of the world's heavy oil accumulations, which occur mostly in stratigraphic and subtle combination traps. Although 3D seismic technology has significantly lowered delineation and development risk in stratigraphic and subtle combination traps, it does not work equally well for all trap and reservoir types. 3D seismic is very effective for imaging poorly consolidated siliciclastic reservoirs and sandstones that pinch out into shale. It is therefore most successful in evaluating lateral depositional pinchout, channel-/ valley-fill, and subcrop/onlap traps. 3D seismic is less effective in imaging well-indurated sandstone reservoirs, carbonate facies-change traps, traps in which the lithologic contrast between reservoir and seal is gradational and thin reservoirs that are below seismic resolution. Furthermore, unless DHIs are present, seismic can only

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Fig. 30. Seismic amplitude map demonstrating high amplitude related to high net/gross ratio from the Halibut Cobia Field, a regional subcrop trap in Australia (Hinton et al. 1994). tell the explorationist that a trap is present, not indicate whether it is filled with hydrocarbons. Thus, other techniques must be integrated with seismic in order to delineate the boundaries of many types of stratigraphic and subtle combination trap. Some of the greatest advances may yet come from i m p r o v e m e n t s in seismic interpretation techniques gained by matching features on seismic data with known geological analogues.

Geochemical techniques

Surface geochemical analysis, an emerging technology that in the past was used mainly for exploration purposes, also holds great promise for delineating stratigraphic and subtle combination traps. W h e n used correctly, surface geochemical analysis has dramatically increased the success rate and decreased dry hole risk in hundreds of d o c u m e n t e d cases around the

Fig. 29. (a) Cross-plot calibrating seismic amplitude to porosity using average porosity data from logs, Cretaceous Kharaib limestone reservoir, Idd AI-Shargi North Dome Field, a lateral facies change combination trap in Qatar. (b) Structure contour map, top Kharaib B limestone. The porosity cutoff of 26% corresponds to a permeability of 2 mD. Potentially productive areas with average porosity >26 % and tight areas with average porosity <26% have been mapped using seismic amplitude variation tied to log porosity (Rubbens et al. 1983) 9 SPE.

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Fig. 31. An example of seismic response to fractures. Circled areas highlight seismic reflector break up corresponding to areas of more intense fracturing. The seismic section is a SE-NW profile through the Austin Chalk of the Giddings Field, a subtle fracture trap in Texas USA. Although seismic played no role in the original discovery, it has since become important in identifying well-fractured sweet-spots during development drilling (Kuich 1989).

world (Shumacher 2002). Surface geochemical anomalies result when oil or gas migrate to the Earth's surface, creating a hydrocarbon seep. Macroseeps are visible oil and gas seeps, while microseeps are detectable by chemical analyses that reveal hydrocarbons in soils, sediments or water. Seeps can be identified by direct techniques, which detect minute quantities of migrated hydrocarbons that occur in the pores

of soil or near surface sediment, or by indirect techniques, which detect changes to soil, sediment or vegetation caused by hydrocarbon seepage (Schumacher 1999). Macroseeps and microseeps provide evidence for the presence of an active petroleum system and, when integrated with seismic and subsurface geological data, can be used to determine the location and boundaries of hydrocarbon accumulations. A n

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS example of this can be seen in Figure 32, which demonstrates how geochemical data and seismic data when integrated proved to be an extremely powerful exploration technique. Hydrocarbon seepage creates many different kinds of detectable anomalies at the Earth's surface (Table 2). The anomalies and the methods used to detect them are myriad and differ for onshore and offshore locations. A comprehensive tutorial on surface geochemical techniques is beyond the scope of this paper. For detailed discussions of types of anomalies, analytical techniques used to detect them, sampling methods and interpretation strategies, the reader is referred to Tedesco (1995); Schumacher & Abrams (1996); Schumacher (1999); and Schumacher & Le Schack (2002). As with all analytical approaches, some geochemical techniques yield better results than others in any given situation. Thus, whenever possible, it is wise to apply multiple methods in order to find the ones that are most effective for solving the problem at hand. Surface geochemistry is most effective for delineating reservoirs when hydrocarbon migration is vertical, in which case sharp lateral changes in concentra-

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tion are often observed at the edges of hydrocarbon-charged traps. When there is a strong lateral component to seepage, geochemical anomalies may be displaced and interpretation of the data will be more complicated. Analogues are used extensively in surface geochemical studies. Patterns in surface geochemical data collected above well-understood accumulations are commonly used as templates for interpreting data collected above traps that are poorly defined Tedesco (1995). Surface geochemical techniques have been used successfully in trap delineation to identify productive limits, favorable infill and step-out drilling locations, bypassed pay zones and un-drained reservoir compartments. Surface geochemical surveys are particularly effective at reducing dry hole risk by identifying the edges of reservoirs in traps with poor seismic expression and differentiating between hydrocarbon-bearing and water-wet reservoir compartments. When integrated with seismic data, surface geochemical data can be used to delineate stratigraphic and subtle combination traps that are difficult to image on seismic, provide data on the distribution of hydrocarbon-bearing reservoirs between

Fig. 32. (a) A seismic amplitude anomaly associated with a lateral depositional pinchout trap was confirmed as hydrocarbon-bearing by a soil gas survey that revealed a surface geochemical anomaly at the same location (CDP 1070). A second geochemical anomaly, not associated with any recognizable seismic signature can be seen at CDP 1096. (b) Reprocessing the seismic data revealed a velocity anomaly at CDP 1096. The seismic anomalies at CDP 1070 and 1096 were drilled and completed as commercial producers (Rice 1989). The above data is from a lateral pinchout trap in the Upper Cretaceous Escondido Formation, Texas, USA.

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Table2.

J.R. ALLAN E T A L . Types o f geochemical anomaly associated with hydrocarbon seepage (Schumacher 1999)

9 Anomalous hydrocarbon concentrations in sediment, soil, water, and even the atmosphere 9 Microbiological anomalies and the formation of paraffin dirt 9 Anomalous nonhydrocarbon gases such as helium and radon 9 Mineralogical changes such as the formation of calcite, pyrite, uranium, elemental sulphur, and certain magnetic iron oxides and sulphides 9 Clay mineral alterations 9 Radiation anomalies 9 Geothermal and hydrologic anomalies 9 Bleaching of red beds 9 Geobotanical anomalies 9 Altered acoustic, electrical, and magnetic properties of soils and sediments

seismic lines, and differentiate between seismic amplitude and attribute anomalies that are hydrocarbon bearing and those that are not.

Summary The following discussion summarizes the key insights gained from study of the 174 stratigraphic and subtle combination traps described in this paper. Whilst the authors recognize there are limitations to the data, they believe that the underlying conclusions are relevant to exploration for these traps. The first key point gained from this study is that both new and missed opportunities exist within mature exploration areas. Stratigraphic and subtle combination trap plays remain a significant opportunity, as in most basins, structural traps are discovered first because they are easier to identify and evaluate. After a period of focused exploration and appraisal drilling, most of the large structural traps will have been found. However, as large structural prospects become scarce, a second round of discoveries, consisting of smaller structural traps and stratigraphic and c o m b i n a t i o n traps, c o m m o n l y occurs. These traps carry higher risks and are not drilled until after the lower risk, large four-way structural closures have all been tested. In fact, less obvious traps can go unrecognized during the early stages of basin exploration, putting operators in the embarrassing position of relinquishing acreage that later proves to contain large reserves. The key to avoiding embarrassment and to detecting and correctly evaluating stratigraphic and subtle combination trap prospects is for explorationists to focus on the proper integration of seismic data, field and outcrop analogues, and sequence stratigraphic principles, such that they are able to develop and test conceptual geological models. The rewards of such focus can be seen in the last decade's exploration successes in the search for turbidite reservoirs in

the deepwater basins of the Gulf of Mexico and the Atlantic margins of South America and Africa, where large stratigraphic and subtle c o m b i n a t i o n traps have been found interspersed among structural traps (Pettingill 1998a, b). However, concentrating solely on deep-water facies is insufficient; it is the thorough understanding of all stratigraphic and subtle combination trapping mechanisms that will provide the necessary insight for creative and successful exploration. Such an understanding requires data, effort and experience, all three of which may not be achievable for a given region, play-type, or business cycle. In such circumstances, it is worth reflecting on the following statement, which presents a very reasonable starting point for locating commercial h y d r o c a r b o n accumulations in stratigraphic and subtle combination traps: 'We usually find oil in new places with old ideas. Sometimes, also, we find oil in an old place with a new idea, but we seldom find much oil in an old place with an old idea'. - Park Dickey, 1958.

The second key point is that many opportunities for stratigraphic and subtle combination traps are clearly present, particularly outside of North America. These traps have received more attention in North America than elsewhere in the world. About 76% of the world's discovered stratigraphic and subtle combination traps are located in the USA and Canada. This is simply because many more wells have been drilled in North America than in comparable global areas and because there has been a concerted exploration focus in the USA on stratigraphic and subtle c o m b i n a t i o n traps. It is therefore probable that there are many excellent stratigraphic plays elsewhere in the world. The final key point is that both conventional and unconventional reservoirs associated with stratigraphic and subtle combination traps often contain extremely large reserve volumes.

STRATIGRAPHIC AND SUBTLE COMBINATION TRAPS Unconventional examples include the world's largest heavy oil deposits, located at Athabasca, Lloydminster, Peace River and G r o s m o n t in Canada and in the Orinoco Heavy Oil Belt of Venezuela (e.g. Cerro Negro, Machete fields), all of which are onlap, subcrop, lateral depositional pinchout, or channel-fill stratigraphic and subtle combination traps. Basin-centre gas traps, which are regional-scale stratigraphic traps, have become important sources of gas in North America in the past two decades. Many giant c o n v e n t i o n a l oil and gas accumulations are stratigraphic and subtle c o m b i n a t i o n traps, including the Prudhoe Bay and East Texas fields in the USA, which are subcrop combination traps with recoverable reserves of >12 B B O E and nearly 6 B B O E , respectively. E v e n small to medium-sized stratigraphic traps can form large accumulations w h e n hundreds of similar traps occur together in a regional trend or play, such as the U p p e r Mannville fluvio-estuarine channel#valley-fill play in Western Canada, which comprises dozens of fields and hundreds of traps with r e c o v e r a b l e reserves of c. 1.6 B B O E (Jackson 1984). Stratigraphic and subtle c o m b i n a t i o n traps r e p r e s e n t a great, u n d e r e x p l o i t e d opportunity, for those who know where to look. The authors would like to acknowledge C&C Reservoirs, Ltd., which has granted permission for the authors to use data from their 'Global Fields Digital Analogs Knowledge System' to support the findings of this paper. The authors also wish to thank EL. Binns and an anonymous reviewer for their insightful reviews of the manuscript.

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Stratigraphic traps in the Tertiary rift basins of Indonesia: case studies and future potential CHRISTOPHER

A T K I N S O N 1, M I C H A E L

RENOLDS 1 & OSKAR HUTAPEA 2

1Serica Energy Corporation, Singapore (e-mail: [email protected]) 2pT Medco Energi, Jakarta, Indonesia Abstract: Stratigraphic traps are often regarded as one of the most risky exploration

targets and are frequently the most difficult trap type to secure management support for drilling. This is despite their frequent occurrence in many basins, in particular the mature onshore basins of North America. The critical factors required for the development of stratigraphic traps are the presence of a fully charged petroleum system, favourable basin and reservoir architectures, low dips in the accumulation zone and good seal integrity. These factors commonly occur in the Palaeogene rift basins of Indonesia and consequently, since the early 1990s stratigraphic traps have often accounted for the majority of recently discovered fields. The Palaeogene rifts of Indonesia are prone to the stratigraphic trapping of hydrocarbons simply because they possess an almost perfect petroleum system in which traps of this type can form. Every rift has a similar history beginning with a syn-rift phase, which primarily provides source rocks of various types as well as reservoir sandstones. This is followed by a thermal sag phase ('early post-rift') where better quality reservoir sandstones and sometimes reef carbonates are found. The ensuing transgressive phase ('late post rift') guarantees a marine shale regional seal. This seal is most impressive at the Minas Field in Central Sumatra where 6 billion barrels of oil are trapped at only 600 metres depth with no surface oil seeps. The various late Tertiary 'orogenic' phases trigger migration of hydrocarbons generally up the flanks of the rifts as well as creating structures at shallower levels. Sometimes this structural activity is so intense that the regional seal is breached causing hydrocarbons to migrate into these shallower structures where major accumulations have been found. However, where the seal is not breached the hydrocarbons must still be trapped below it on the flanks of the rift. The giant Widuri and Kaji Semoga fields are perfect case history examples. There is no doubt that in Indonesia the 'easy oil' has already been found in large 4-way dip closures or classic Sunda Fold inversion structures. However, it is contended that there is still a huge potential for finding large reserves in stratigraphic traps in basins with the right characteristics. In this context, two largely unexplored basins within the Asahan Offshore PSC, North Sumatra and the Biliton PSC, West Java are discussed. Both these areas exhibit all the ingredients required for successful stratigraphic trap discoveries but both remain at the present day undrilled for this play type.

It is c o m m o n knowledge that most exploration prospects drilled in the international oil and gas business consist of obvious features such as folds, fault blocks, salt domes, well defined reefs or, in m o r e recent times, undisputed seismic anomalies with clear direct hydrocarbon indications ('DHI's'). A subtle trap is any less obvious trap which is more difficult to convince management or partners to drill, such as a stratigraphic trap, unconformity trap, low relief structure, or any trap involving a combination of structural and stratigraphic factors. To this day, without support from DHI's, such traps appear nigh on impossible to receive approval to drill, although the recent Buzzard discovery in the Central

North Sea is an important exception to this rule. Such traps are c o m m o n l y p u r s u e d in the mature, onshore areas of the U n i t e d States and Canada, but have b e e n avoided in international exploration, in spite of the increasing maturity of some basins. Low cost, onshore drilling in the safe political environment of North America has u n d o u b t e d l y contributed significantly to this situation. It is our opinion that there is huge remaining potential for finding stratigraphically t r a p p e d reserves of h y d r o c a r b o n s in most mature basins throughout the world however this study concentrates on the Palaeogene rift basins of Indonesia where most of our collective experience has been gained.

From: ALLEN,M. R., GOFFEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The Deliberate Searchfor the

Stratigraphic Trap. Geological Society, London, Special Publications, 254,105-126. 0305-8719/$15.00. 9 The Geological Society of London 2006.

C. ATKINSON ETAL.

106

Exploration for stratigraphic traps The exploration cycle Many mature basins have had a similar past exploration history which can be divided into three phases: Phase I: Drilling of surface anticlines Phase II: Drilling of seismic prospects (2D & 3D defined) Phase III: Drilling of subtle/stratigraphic traps (especially with 3D seismic) The relative importance of these phases varies from basin to basin. Offshore areas had no era of surface geological exploration, while some complex fold belts were virtually completely delineated by surface work. A n important point must be made regarding these phases - while field size tends to decrease from large to small during one phase, it usually increases when the next phase begins (Fig. 1). This is only natural, given the risks of the exploration business. E x p l o r a t i o n programmes following a certain play type start with the largest features and pursue progressively smaller targets. Companies tend to stick with a proven play type until it is no longer economically viable, at which point something new is tried. Large quantities of oil and gas continue to be found in mature basins. A n interesting study completed by Amoco (pers. comm.) revealed that approximately 80% of the oil found worldwide between 1980 and 1990 was in well understood, mature basins, rather than in the on-trend, or frontier basins (Fig. 2). This was

> n :> t c ~ h O ZLI N

~ Stratigraphlc Traps ~ 3D Seismic ~ PHASE III & Geological PHASEII ~ C. . . . pt 2D & 3D Seismic ~

kStruct .... PHASE I ~

sU"~u s

~

,

\

~0 TIME

(YEARS)

Fig. 1. Phases of exploration within a typical mature hydrocarbon bearing basin. Note the tendency for discovery sizes within each phase to decrease through time until a new phase is adopted.

Fig. 2. Basin type location of discovered hydrocarbons in the decade 1980-1990 (Amoco Production Company, pers. comm.).

seen to be attributed to the successful drilling of subtler structural/stratigraphic and pure stratigraphic traps in basins with well defined petroleum systems. The three cycles of exploration are clearly evident in most of the large onshore basins of North America. For example in the Powder River Basin, in NE Wyoming, USA oil was first found in the late 1800s. The early prospects were obvious surface structures known as 'sheepherder anticlines' because geologists located them simply by describing what they were looking for to the local sheepherders. Through 1930, the oil companies drilled progressively smaller features until no more viable prospects existed. Only one stratigraphic trap was found during this period, in a channel sandstone reservoir, near to a surface oil seep. With the development of seismic techniques, the Powder River Basin saw a resurgence of activity. On the deformed flanks of the basin, many more structural traps were drilled with success whereas in the central part of the basin seismic data revealed only homoclinal dip and little drilling was conducted. One more stratigraphic trap was found on the flank of a structural prospect but by 1960 all the seismic structural anomalies were drilled and the basin was largely dormant once again. In 1967, Bell Creek, a large stratigraphically trapped oil field was found in the central portion of the basin. The field was found in an area of homoclinal dip by an operator with the conviction to chase a stratigraphic concept. By 1980, the entire central portion of the basin was developed, with over 100 stratigraphic traps discovered. Somewhat ironically, the Hartzog Draw Field, discovered in 1975, is a 250 million barrel field which was found after nearly 100 years of exploration in the basin. It is a common theme in the discovery of subtle or stratigraphic traps that many have been drilled by accident. In many cases

STRATIGRAPHIC TRAPS IN INDONESIA prospects were drilled which would have been economic if they resulted in a small discovery. However, when the discoveries were appraised and developed they resulted in larger than expected fields, mainly due to important stratigraphic components in the trap set-up. If a strategy can be developed to maximize this upside potential, the drilling of subtle/stratigraphic traps becomes much easier to justify. Also, the example of the Powder River Basin, demonstrates that vast areas with high economic potential can be missed if one assumes that stratigraphic traps will be found as accidental by-products while drilling for pure structural closures. Clearly, in order to find stratigraphic traps you must pursue an exploration strategy which believes that they will exist.

The petroleum system approach Many structurally defined prospects consist of a very well documented closure with a speculative source. Historically in the exploration business these features have been fairly easy to get drilled because it is usually possible to devise a plausible scenario of source and migration to justify the risk. The fact that a large proportion

107

of the structural closures drilled worldwide are not charged by hydrocarbons demonstrates that source and migration should be considered a major concern. This approach to ranking generative basins on the basis of their charge or 'petroleum system' was first devised by Demaison (1984) and expanded upon by Demaison & Huizinga (1991). In Indonesia the recognition of a functioning petroleum system is key since migration distances from kitchen to trap are always relatively short (<40 km). In most mature basins, the source and migration are fairly well understood risk elements. Reducing this risk to near to zero suggests that all trapping configurations in the migration path should be considered prospective. In summary, it should be remembered that the only difference between a prospect with known source and a speculative trap, and a prospect with known trap and a speculative source is that the latter have historically been easier to sell to exploration management. Figure 3 illustrates this phenomenon using the example of an idealized rift basin petroleum system (Magoon 1988). Note that depending upon the mapped extent of the petroleum system 4-way dip closures maybe dry whereas significant stratigraphic accumulations could

Prospect "A" (a Structure) will be a dry hole Prospect "B" (a Stratigraphic Trap) will be a discovery Prospect "C" (a Structure) will be a basement show or in some cases a discovery Fig. 3. Idealized rift basin petroleum system (after Magoon 1988). Note how structural traps outside the limit of the petroleum system are not likely to be discoveries and yet stratigraphic pinchouts within it may well be.

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C. ATKINSON ETAL.

Table 1. Recent subtle/stratigraphic traps discovered in Indonesia. M = metres, MMBO(E) = millions of barrels of oil or oil equivalent Company block First production (cycle I or II)

Cycle III discoveries

Trap type

Comment

Total Mahakam

1972

SISI, NW PECIKO, NUMBI 1 9 9 2

Subtle structure, hydrodynamic, stratigraphic trap

PECIKO (7+ TCF) largest gas field in block

Maxus SE Sumatra

1970

INTAN 1987 WIDURI 1 9 8 8

Subtle structure, stratigraphic trap

WIDURI (500 MMBO) largest field in block

Conoco Natuna

1974

BELIDA 1989

Broad subtle structure, stratigraphic trap

BELIDA (370 MMBOE) largest field in block

Hudbay Malacca Strait

1979

KURAU 1986

Very subtle structure (8 ms rollover)

KURAU (62 MMBOE) largest field in block

Exspan South Sumatra

1900s

KAJI-SEMOGA 1996

Stratigraphic trap

KAJI-SEMOGA (300 MMBOE) largest field in block

exist. In the case of many of the recent major h y d r o c a r b o n discoveries made in Indonesia virtually all are located in areas of proven source and look extremely unimpressive structurally on seismic data (see Table 1). Critical factors f o r successful stratigraphic trap exploration Mainly due to the reasons discussed above most exploration managers still regard the stratigraphic trap as a risky undertaking even when defined on 3D seismic. The tight subsurface control desired to locate the prospect, as seen in North America, is usually absent, and without the definition of 3D and in most cases the support of DHI's most seismic data can still only approximate a location. In an effort to reduce the risk on stratigraphic traps one should first examine the factors which are considered critical to their success. It is our experience that these factors are as follows: 9 9

9 9

Fully or overcharged petroleum system; Favourable basin and reservoir architecture promoting the development of discontinuous clastic (paralic/deltaic) or carbonate (reef) facies; Optimum dip angle in the accumulation zone of the trap; Good top, base and lateral seals.

Of these factors we consider two; seal and trap dip, to be relatively easy to risk and thus

assess whether or not a stratigraphic trap should be considered worthy of drilling. In a worldwide survey of stratigraphic traps the one common factor is that 80% occur in areas with regional dips of 0.4 to 2.7 degrees. In our independent review of several major stratigraphic traps, the median dip was only 0.9 degrees (Table 2). This is an extremely important point. The reason for this limited range of dips is simple geometry. Seals in typical stratigraphic traps are usually shales and siltsones. They are thus generally only capable of holding relatively small columns of hydrocarbons (<100 m). Many major stratigraphic traps have columns of 50 m or less. Outstanding traps may hold back columns of 300 m, but longer columns usually require unconventional seals such as evaporites, tar plugs, overpressured environments or regions with strong subsurface hydrodynamic flows. Figure 4 illustrates graphically the effect of dip on a stratigraphic accumulation. A seal which can hold a 50 m oil column will trap an accumulation 5.7 km wide in dips of 0.5 degrees. This same seal will only trap an accumulation i km wide in 3 degrees of dip and 280 m wide in 10 degrees of dip. Given this relationship, migration can explain why most stratigraphic traps occur between 0.4 and 2.7 degrees. In dips steeper than 2.7 degrees, buoyancy forces tend to be greater than capillary forces given the greater chance of thicker hydrocarbon columns and hydrocarbons tend to migrate through, leaving non commercial shows ('residual

109

S T R A T I G R A P H I C TRAPS IN I N D O N E S I A Table 2. Dip angle o f the trap in several major worldwide stratigraphic accumulations Field Stanley Pembina Pecos Slope Rubiales Bell Creek East Texas Widuri Hartzog Draw Red Wash Chicontepec Glenrock Patrick Draw Quiriquire Cottonwood

Location USA Canada USA Colombia USA USA Indonesia USA USA Mexico USA USA Venezuela USA

Anadarko Basin W. Canada Foreland Basin Permian Basin Llanos Basin Powder River Basin East Texas Basin Sunda Basin Powder River Basin Uinta Basin Tampico Basin Powder River Basin Green River Basin E. Venezuela Basin Big Horn Basin

Dip

Column

Reserves

0.5 ~ 0.5 ~ 0.7 ~ 0.8 ~ 0.8 ~ 0.9 ~ 0.9 ~ 1.1 ~ 1.4 ~ 2.3 ~ 2.7 ~ 3.6 ~ 4.0 ~ 9.6 ~

90 M 265 M 275 M 100 M 90 M 335 M 50 M 35 M 120 M Multiple Pays 300 M 275 M 610 M 1300 M

600 MBO 1900 MBO 750 BCFG 400 MBO 150 MBO 6000 MBO 400 MBO 250 MBO 157 M B O E 12 000 MBO 80 MBO 60 MBO ? 900 M B O E 70 MBO ?

M = metres, M M B O ( E ) = millions o f barrels ofoil or oil equivalent, BCFG = billions o f cubic feet o f gas

h y d r o c a r b o n s ' ) t r a p p e d d o w n - d i p of t h e seals. I n f l a t t e r dips, g i v e n f a v o u r a b l e s t r a t i g r a p h y , m o s t h y d r o c a r b o n s are a l r e a d y t r a p p e d basinward. Generally, h y d r o c a r b o n s n e e d a r e s e r v o i r dip s t e e p e r t h a n 0.4 d e g r e e s to d e v e l o p t h e b u o y a n c y f o r c e r e q u i r e d to m i g r a t e t h r o u g h t h e less p e r m e a b l e z o n e s w i t h i n t h e reservoirs.

When reviewing internally generated p r o s p e c t s or f a r m - o u t p r o p o s a l s it is a p p a r e n t t h a t m a n y s t r a t i g r a p h i c traps are m a p p e d w i t h dips at t h e t r a p level in t h e 5 - 1 0 d e g r e e s range. U n l e s s s u p p o r t e d b y u n c o n v e n t i o n a l seal lithologies t h e n t h e a p p l i c a t i o n of t h e p r i n c i p l e discussed above allows easy p r e l i m i n a r y

Fig. 4. Effect of trap dip On the extent of a stratigraphic accumulation with a 50 m hydrocarbon column height. M = metres, KM = kilometres.

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C. ATKINSON E T A L .

screening of these prospects out of the exploration portfolio. Seal extent and capacity, together known as 'seal integrity', are a key aspect to be considered in the exploration for viable stratigraphic traps. Without an effective top, side and bottom seal the chances of having stratigraphically trapped hydrocarbons are very rare. This can be illustrated by way of an example from the Ardjuna basin which is a Palaeogene rift basin located in the offshore NW Java area of Indonesia (Kaldi & Atkinson 1997; Noble et al. 1997). In this example a series of potential sealing lithologies within the late syn-rift/early post-rift Talang A k a r Formation were sampled and mercury injection capillarity analyses conducted to measure their actual sealing capacity (Fig. 5). In addition, the thickness and lateral extents of the various seal types were either measured from borehole and seismic data or quantified according to comparisons to known outcrop analogues

(Fig. 5). It can be seen from this example that the best sealing capacities occur in the more marine influenced shales ('delta front shales') and carbonates. This is purely a result of grain size (delta front shales are true claystones rather than siltstones) and cementation (presence of carbonate cements occludes porosity). Although both seal lithologies are often very extensive the tendency for the carbonate facies to undergo brittle fracturing upon deformation reduces their true seal integrity. Consequently, it is the extensive, marine shales which define the best seals within the Arjuna basin and virtually all other Palaeogene rift basins in Indonesia. Once again, when risking any presented stratigraphic trap prospect it is our experience that most require favourable sealing lithologies often with a link to a particular environment of deposition (e.g. marine shales, tuffaceous shales) and without such evidence they should be regarded as much higher risk.

Fig. 5. Measured hydrocarbon column heights and sealing capacities of Talang Akar Formation seal facies, Ardjuna Basin, offshore Java, Indonesia. Note preferential enrichment of non-indigenous hydrocarbons in the poorer quality delta plain shale seal lithologies implying that these seals often leak above reservoirs. From Noble et al. 1997.

STRATIGRAPHIC TRAPS IN INDONESIA

Strategy for stratigraphic exploration in the Palaeogene rifts of Indonesia Exploration in the Palaeogene rifts of Indonesia historically has had a structural bias - exploration consisted of drilling structures in order of descending size. As a better understanding of the regional geology was achieved, operators started preferentially to drill certain types of structure~ i.e. drapes rather than 'Sunda fold' inversions. Despite a steady supply of drillable structural traps most wildcats in or close to the Palaeogene rift basins of Indonesia in the last ten years have either been dry or discovered only limited reserves. This is not to say that discoveries have not been made in these basins because they have and the majority have been made in subtle/stratigraphic traps often many years after exploration first commenced (see Table 1). The reason why the Palaeogene rifts continue to be successful exploration areas is largely because of their world class petroleum systems and the presence of excellent quality source rocks (Fig. 6). Unlike the cratonic basins of North America, the source kitchens in the Palaeogene rifts of Indonesia are localized in the rift deeps, and migration distances to successful traps tend to be less than 40 km. For this reason, our experience advocates an exploration strategy based on charge and distance within the rifts and not necessarily the presence of drillable structures. In evaluating any area of western Indonesia, the first step is to locate the Palaeogene rifts. Often they are obvious, but on old vintage seismic data or under difficult seismic conditions, they may have to be inferred. Rifts can be inferred by locating the prominent seismic marker of the first marine sediments in the post rift lower Miocene succession (Figs 6 & 7a). Frequently this marine unit is marked by a high amplitude event representing transgressive carbonates such as the Batu Raja Limestone or equivalents in Sumatra and Java. If a deep rift exists below the Miocene marker, the marker will never be flat on seismic data. It will either sag due to differential compaction or bow up due to later structural inversion. Frequently, the relative depths to crystalline basement can be estimated by the amount of sag or inversion. Once the rifts are located it may be possible to directly detect source facies on seismic. Some of the major source rocks of the rifts, such as lacustrine shales or coals, stand out as parallel, high amplitude, low frequency reflections (Fig. 7b). Rifts with divergent, weak reflections may

111

be filled by coarse grained clastics and barren of source rock. When rifts and source have been established, migration paths need to be considered. Maturity in most Indonesian Palaeogene rifts is usually reached at a depth of around 2500-2750 m or between 2.0-3.0 seconds two-way travel-time depending on heat flow. Migration tends to be late, bed parallel, and less than 40 km in distance from the kitchen area. Hydrocarbons tend to migrate away from the main bounding fault of the rift, up the ramp of the hanging wall block into traps located on the shallow dipping rift margins. The extent of potential reservoirs can be found by identifying the early Miocene marine shale. This shale forms the most important regional seal throughout the western half of Indonesia (Fig. 8). Most hydrocarbons are trapped in the reservoirs below these shales e.g. Talang Akar Formation and Batu Raja Formations of South Sumatra and West Java; the Sihapas Formation of Central Sumatra. If this marine shale rests on basement, the prospect invariably lacks reservoir unless favourable lithologies exist in the basement e.g. weathered granites of the Palembang basin, South Sumatra; the Permo-Triassic Ratburi Limestone of North Sumatra and Thailand. Thus if any type of trap can be identified in the migration path from a rift, down-dip of where the early Miocene shale rests on basement, the area has merit (see Fig. 8). Stratigraphic traps are likely in this area, although it is important to bear in mind the requirement for low trap dip as discussed previously. It is our conviction that by adopting this recipe in the exploration of the Palaeogene rift basins of Indonesia that the risks associated with drilling stratigraphic plays will be greatly reduced.

Case studies and undrilled potential In Indonesia a similar pattern of the exploration cycle discussed above is starting to emerge. In the late 1890s through 1930s early exploration efforts found most of the significant onshore structures in Sumatra, Java and Kalimantan using surface mapping techniques often linked to the presence of active oil seeps. Later, from the 1930s onwards, seismic surveys revitalized the industry with the discovery of offshore fields as well as additional onshore fields, including the giant Minas field (6 billion barrels) of onshore Central Sumatra. In more recent times many basins have had a resurgence in exploration fueled by the discovery of

112

C. A T K I N S O N E T A L .

STRATIGRAPHIC TRAPS IN INDONESIA stratigraphically trapped h y d r o c a r b o n s (see Table 1). More importantly, these discoveries often comprise the largest field on the block and were made 15-20 years after exploration first commenced. Clearly, the exploration for subtle/stratigraphic traps can still be successful in Indonesia if risk is correctly addressed and a focused approach adopted. In order to illustrate this concept two case studies and two areas of currently unexplored potential will be discussed.

Case study: Widuri Field, Asri basin, offshore Sumatra The Widuri Field of the Asri basin, offshore South Sumatra (Fig. 9) was discovered in 1988 after the drilling of ten completely dry holes in the basin (Wight et al. 1997). The Asri basin was regarded as lacking source rocks, was too shallow for generation, had a low geothermal gradient and had no more structures to drill. On this basis one of the largest multinational oil companies in the world exited the block just before the drilling of the Intan-1 well in late 1987. This well targeted one of the last remaining structural closures in the block, a small, fault dependent basement bump at the up-dip basin margin. As documented by Wight et al. (1997) this well was only drilled by the dogged persistence of a single explorationist who had just been responsible for the drilling of several of the previous ten dry holes! The well encountered a 23 m oil column in the Talang Akar Formation and led to the drilling of the Widuri-1 well in 1988 on a much smaller faulted basement structure. This well was also a success but even more so since it confirmed the presence of a major stratigraphic component to the Talang Akar trap whereby the deltaic sandstones shaled out to the NW (Fig. 10). Interestingly, the Saleha-1 dry hole (part of the original ten well programme) was drilled down-dip of the later Intan discovery and the well is unique in that it contained no Talang A k a r sandstones but now occurs within the extent of the Widuri trap (Wight et aL 1997). In hindsight, it represents the up-dip shaley seal to the Widuri accumulation. Reference to Figure 10 reveals that it is now easy to distinguish on seismic the low velocity lacustrine source rock in the deepest portion of the depression. Migration from this source

113

follows the dip of the strata to the NW up the hanging wall of the rift. Oil has migrated from steep dips in the deeper part of the Asri rift to dips of less than 1 degree in younger strata on the flank of the basin (Fig. 10). Over five hundred million barrels are trapped in this area of low dip, some in minor fault closures, but most in the stratigraphic and combination trap of the giant Widuri Field. Together the IntanWiduri complex represents the second largest discovery made in the block some 20 years after it was first explored (Wight et al. 1997; Carter 2003).

Case study: Ka]i Semoga, Rimau Block, onshore south Sumatra The Kaji Semoga field lies in the Rimau Block of south Sumatra (Fig. 11) and it represents a classic case of major company 'tunnel vision'. Standard Vacuum Oil C o m p a n y ('Stanvac'), which was a survivor of the Standard Oil empire and a combination of two oil majors, Mobil and Exxon, held large tracts of acreage in south Sumatra for some 30 years, from 1963 to 1995. The company had, what turned out to be the Kaji Semoga 'prospect' on their books with a 2% chance of finding 3 million barrels of oil in a structural trap above a small basement closure (Fig. 12). No thought was given to the stratigraphic potential of the well established Batu Raja reef play. In December 1995 PT Exspan Nusantara (a forerunner of PT Medco Energi) a new startup I n d o n e s i a n exploration and p r o d u c t i o n c o m p a n y purchased the Stanvac entity. In January 1996 the Exspan management approved the drilling of three separate prospects in the block: Kaji, Semoga and Sembada (Hutapea 1998). This decision was based purely upon a financial argument that since all three prospects were quite shallow the cost of drilling each one was low and was roughly equivalent to the drilling of a single deep well further out into the basin. Furthermore, because they were a low cost operator it was felt that even though the reserve targets in each prospect were small they would still be able to u n d e r t a k e the d e v e l o p m e n t of the proposed small reserves on a cost effective basis (Hutapea 1998). Consequently, the wells were approved for drilling which commenced in June 1996. The Semoga 1 well was drilled first and

Fig. 6. Idealized cross-sectional model of an Indonesian Palaeogene rift basin. The geological history of the basin fill involving a transition from restricted, non-marine lacustrine environments (source) to more extensive paralic/deltaic to marine environments (reservoir) promotes the development of an excellent petroleum system.

114

C. ATKINSON E T A L .

STRATIGRAPHIC TRAPS IN INDONESIA

115

Fig. 8. Hydrocarbon accumulation model for a typical Indonesian Palaeogene rift basin. Locations on the shallower dipping, hanging wall margin are often the sites for the presence of subtle/stratigraphic traps.

encountered just 2 metres of Batu Raja Formation pay which tested at 3 million cubic feet of gas per day and 9 barrels of oil per day. Unperturbed by this and because Exspan had already decided to drill the next well irrespective of the outcome of the first, the Kaji 1 well was drilled in July 1996. Luck changed and they encountered 37 m of high porosity reefal pay in the Batu Raja Formation which tested at 525 barrels of oil per day. Finally, the Sebada-1 well was drilled in August 1996. This well encountered 33 m of Batu Raja Formation pay which tested at 1130 barrels of oil per day. U p o n drilling of the three wells it became apparent that what they had encountered was not a series of small structural oil pools but a significant partial stratigraphic trap off the flanks of the basement high (Figs 13 & 14). Total oil column height in the field is around 80 m and the areal extent of the field is currently some 15 km 2 (Hutapea 2002). The field is currently producing around 10 000 barrels of oil/day and has reserves of around 250-300 million barrels.

Unexplored potential." Asahan Offshore, North Sumatra The A s a h a n Offshore P r o d u c t i o n Sharing Contract (PSC) lies in the North Sumatra basin (Fig. 15). This basin which covers an area of 56 000 km 2 is one of Indonesia's most prolific petroleum provinces with in-place reserves in excess of 25 trillion cubic feet of gas and i billion barrels of oil. The basin comprises a number of sub-basins separated by intervening basement highs which together represent a series of n o r t h - s o u t h trending Palaeogene rifts. In contrast to the remainder of Sumatra, the North Sumatra Basin is relatively lightly drilled, especially offshore where less than 50 exploration wells have been drilled since 1970. The Asahan Offshore PSC lies in the southeastern part of the North Sumatra basin, in water depths less than 50 m (Fig. 15). The PSC includes parts of the n o r t h - s o u t h trending Pakol and Glagah sub-basins, Pakol and Glagah Horsts and the western flank of the Asahan Arch.

Fig. 7. Seismic expression and recognition of typical Indonesian Palaeogene rift basins. (a) sag in post-rift section (Oligo-Miocene), Biliton basin, refer to Figures 17 and 18 for line location; (b) basin centre, onlapping, low frequency reflectors as indicators of source rocks, North Seribu Trough, offshore Java (from Pramono et al. 1990).

116

C. ATKINSON ETAL.

Fig. 9. Location of the Widuri Field, Asri basin, offshore South Sumatra (from Carter 2003). Location of seismic line illustrated in Figure 10 indicated.

Exploration to date has proved the existence of a working petroleum system. A dense grid of existing 2D seismic defines excellent Palaeogene rift basin geometries and the Glagah-1 well drilled in 1985 proved that this large, deep rift is an active source kitchen with a good charge (Fig. 15). Hydrocarbons have migrated up the hanging wall ramp of the rift from this kitchen and some have managed to migrate to the basement high at Glagah, where insufficient reservoir is present for a commercial accumulation despite flowing oil at rates in excess of 2000 barrels per day. The seismic line shown in Figure 16 shows that the present day structure is still that of an undisturbed half-graben rift very reminiscent to the Asri basin in the Widuri case study (compare to Fig. 10). On the basis of the Palaeogene rift model discussed earlier better reservoirs should be present down-dip from the Glagah-1 well (Fig. 15). Syn-rift clastic sediments can be recognized on seismic data down-dip of the Glagah well, pinching out between the early Miocene, postrift transgressive deposits and the basement. These reservoir rocks are on the migration path from the rift to the Glagah location. Adopting the concepts developed in this paper there appears to be a very good chance that an

accumulation could exist at the pinchout of these syn-rift clastics. Although there are undoubtedly remaining subtle structural traps remaining in the PSC, there is huge potential for finding stratigraphically trapped reserves in the block. The key ingredients which have been discussed earlier are clearly present; deep overcharged rift, obvious sag, working kitchen, shallow dips and a migration distance of less than 40 km.

Unexplored potentiak Biliton PSC, West Java Sea The Biliton Basin is an example of one of Indonesia's true unexplored Palaeogene rift basins. It represents one of a series of Palaeogene basins (Palembang, Sunda, North Seribu, Asri, Ardjuna, Zaitun, Vera, etc.) located on the SE margin of the Sunda craton that originated during a major Eocene-Oligocene period of extension and later Miocene sag. The prolific oil producing basins of Ardjuna, Sunda and Asri lie approximately 200 km to the SW and west (Fig. 16). Overall the depression forming the Biliton basin extends for over 60 000 km 2 with an

S T R A T I G R A P H I C TRAPS IN I N D O N E S I A

117

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118

C. ATKINSON E T A L .

Fig. 11. Location of the Kaji Semoga Field, Palembang Basin, onshore South Sumatra.

Fig. 12. Pre-drill structure map of top Batu Raja Formation illustrating presence of three, small, independent Kaji, Semoga and Sembada closures. Contour interval = 100 ft (33 m).

STRATIGRAPHIC TRAPS IN INDONESIA

119

Fig. 13. Current structure map of top Batu Raja Formation revealing the presence of two separate hydrocarbon accumulations defined by two independent oil:water contacts. Location of seismic line 1588-90 seen in Figure 14 is indicated.

average water depth of 40 m. The current Biliton PSC lies within this depression and occupies an area of approximately 6500 km 2 (Fig. 17). Recently acquired high resolution 2D seismic data reveals the presence of two, largely north-south oriented, Palaeogene rift basins (Fig. 18). The dominant one lies in the west adjacent to the Parang G-1 well and trends approximately north-south to NE-SW. The other has a similar trend but lies approximately 50 km to the east. The western rift is of similar size (approximately 400 km 2) and orientation as the nearby Asri basin. Seismic indicates more than 2.5 seconds two-way time of sedimentary section in the main western rift representing a likely depth to basement in excess of 3900 m (Fig. 18). Formerly Amoco and then later BP evaluated the current area of the PSC. BP in 1991 did not take up the opportunity of converting the area into a PSC and exited despite the results of their Airborne Laser Fluorescence (ALF) survey and subsequent seabed coring program which

indicated the presence of migrated hydrocarbons (Thompson et al. 1991). The sea-bed recovered hydrocarbons were typed geochemically to lacustrine source rocks rich in algal material similar to those in the nearby Asri and Sunda basins. The newly acquired 2D seismic is very revealing. Whereas on the old data where basement definition was poor the new data is of excellent quality and clearly indicates a good basement reflector and, more importantly, the presence of onlapping, low frequency events in the deeper parts of the western rift (see Fig. 7a). Up-dip to the east, away from the kitchen, the gentle dip at basement level sets not only the correct configurations for stratigraphic trapping but also the chances for fault enhanced, low relief structures. Despite the new 2D seismic data being largely a reconnaissance survey all the basic ingredients for a classic rift play in an unexplored basin exist and the close similarity to the prolific oil producing Asri basin is remarkable (compare Figs 18 & 10).

120

C. ATKINSON E T A L .

Fig. 14. West to east seismic line 1588-90 across the Kaji-Semoga Field. (a) uninterpreted and with original interpretation, (b) same line datumized within Gumai Formation and with current interpretation. Location of line indicated on Figure 13.

S T R A T I G R A P H I C TRAPS IN I N D O N E S I A

121

122

C. ATKINSON E T A L .

Fig. 15. Location of the Asahan Offshore PSC, North Sumatra, Indonesia. Location of seismic line 81-1114 seen in Figure 16 is indicated.

Fig. 16. West-east seismic line (annotated) across the Asahan Offshore PSC from the Pakol High to the Glagah-1 discovery well. Location of line indicated on Figure 15. bcpd = barrels of condensate per day, Mcf/d = millions of cubic feet per day of gas.

S T R A T I G R A P H I C TRAPS IN I N D O N E S I A

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Conclusions (1) Subtle or stratigraphic traps are generally discovered in mature basins at the late stage of the exploration cycle. (2) Historically subtle or stratigraphic traps have been difficult to get drilled because they are perceived as being high risk. (3) It is suggested that subtle or stratigraphic traps should be abundant in fully to overcharged petroleum systems with favourable basin/reservoir architecture, low dips at the trap level (>0.5 but <3 degrees) and the presence of effective top, base and lateral seals. (4) The above factors epitomize the Palaeogene rift basins of Indonesia. Consequently subtle/stratigraphic traps commonly exist where they have represented some of the largest hydrocarbon accumulations discovered in recent time. Exploration to

date has shown that these rifts contain a unique geological make up which favours the existence of a charge dominated petroleum system. It can be demonstrated in many rifts that the early Miocene transgressive system has sealed the generated hydrocarbons within a relatively small area either within the rift or within 40 km of its centre. Prior exploration has focused generally on structures near these source kitchens, particularly the large structures formed during later Miocene and Plio-Pleistocene inversion. Many rifts, however, remained tectonically quiescent during these periods of later tectonism and the present day structure is still that of an undisturbed halfgraben. The lack of structures has no bearing whatsoever on whether or not hydrocarbons were generated. Hydrocarbons generated in an undeformed rift will still migrate up-dip along the ramp of

STRATIGRAPHIC TRAPS IN INDONESIA

125

Fig. 18. Map of top Basement within the Biliton PSC based upon the new 2D seismic grid. Note the presence of two north-south trending Palaeogene rifts and the location of the area of pronounced onlapping reflectors seen in Figure 7a which lies within the basement embayment updip of the western rift depocentre.

the hanging wall block until they reach the effective seals within the early Miocene transgressive deposits where they become trapped in subtle structures or in gently dipping stratigraphic pinchouts. (5) By comparison to existing case studies it is considered that there are m a n y Palaeogene rift basins in Indonesia which contain excellent stratigraphic trap potential but which remain to date totally unexplored for this type of play. (6) The role of serendipity in the discovery of major stratigraphic traps can never be underestimated. However, there are many cases where stratigraphic traps have been intentionally drilled from the outset by a determined operator and been successful. The key for any explorationist to have any prospect drilled is a combination of the merits of potential reward versus perceived risk. Therefore, unless a clear strategy involving risk reduction is developed to explore for stratigraphic traps they will remain undrilled despite the fact that in some basins they r e m a i n the last true opportunity for significant reserve addition.

The authors would like to thank D. Carter, H. Rashid and A. Wong for help in the production of this paper. We would also like to acknowledge the supporting roles of Serica Energy Corporation and PT Medco Energi and finally the permission of Minyak dan Gas Bumi (MIGAS) and Badan Pelaksana Kegiatan Usaha Hulu Minyak dan Gas Bumi (BPMIGAS) to publish the material presented.

References CARTER, D. 2003. 3-D Seismic geomorphology: Insights into fluvial reservoir deposition and performance, Widuri field, Java Sea. American Association of Petroleum Geologists Bulletin, 87, 909-934. DEMAISON,G. 1984. The Generative Basin Concept. In: DEMAISON,G. & MURRIS,R.J. (eds) Petroleum geochemistry and basin analysis. The American Association of Petroleum Geologists, Tulsa, Oklahoma, Memoir 35, 1-14. DEMAISON, G. & HUIZINGA,B. 1991. Genetic Classification of Petroleum Systems. American Association of Petroleum Geologists Bulletin, 75, 1626-1643. HUTAPEA, O. 1998. The Semoga-Kaji discoveries: Large Stratigraphic Batu Raja oil fields in South Sumatra. Proceedings of the Indonesian

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Petroleum Association Annual Convention, May 1998, 313-326. HUTAPEA,O. 2002. What makes Karl Semoga Field so big? Giant Field and New Exploration Concepts Seminar, Indonesian Association of Petroleum Geologists One Day Seminar, Abstract. KALDI, J. & ATKINSON, C. 1997. Evaluation of seal potential: Example from the Talang Akar Formation, offshore northwest Java, Indonesia. In: SURDAM,R.C. (ed.) Seals, traps and the Petroleum System. American Association of Petroleum Geologists, Tulsa, Oklahoma, Memoir 67, 85-101. MAGOON, L.B. 1988. The Petroleum System - A Classification Scheme for Research, Exploration, and Resource Assessment. In: MAGOON, L.B. (ed.) Petroleum Systems of the United States. U.S. Geological Survey Bulletin, 1870, 2-15. NOBLE, R., KALDI,J. & ATKINSON,C. 1997. Oil Saturation in Shales: Applications in Seal Evaluation. In: SURDAM,R.C. (ed.) Seals, traps and the Petro-

leum System. American Association of Petroleum Geologists, Tulsa, Oklahoma, Memoir 67, 13-29. PRAMONO, H., Wu, C. & NOBLE, R. 1990. A new oil kitchen and petroleum bearing sub-basin in the offshore northwest Java area. Proceedings of the Indonesian Petroleum Association, Annual Convention October 1990, 253-278. THOMPSON, M., REMINGTON, C., PURMONO, J. & MACGREGOR,D. 1991. Detection of liquid hydrocarbon seepage in Indonesian Offshore Frontier basins using ALF. Proceedings of the Indonesian Petroleum Association, Annual Convention October 1991, 663-689. WIGHT, A., FRIESTAD, H., ANDERSON,J., WICAKSONO, P. & REMINGTON,C.H. 1997. Exploration History of the offshore Southeast Sumatra PSC, Java Sea, Indonesia. In: FRASER, A.J., MATTHEWS, S.J. & MURPHY, R.W. (eds) Petroleum Geology of Southeast Asia. Geological Society, London, Special Publications, 126, 121-142.

Identification of stratigraphic traps with subtle seismic amplitude effects in Miocene channel/levee sand systems, NE Gulf of Mexico THEODORE

J. G O D O

Shell Exploration and Production Company, Houston, Texas, USA (e-mail: ted.godo@shelL com) Abstract: Stratigraphic traps created and preserved on the unconfined slope of the ancestral Mississippi submarine fan in the northeastern Gulf of Mexico have been found to contain substantial and profitable hydrocarbon reserves. Nearly 2 trillion cubic feet of gas (350 million barrels of oil equivalent) have been produced in the last 13 years in less than 1400 feet (425 m) of water. Drilling results have yielded 31 fields from 45 drilled prospects for a success rate of 69%. The main phase of exploration lasted eight years. The first 3D survey in 1994 sparked a major increase in drilling and success rates until the last field was discovered in 2001. This play has now essentially been exhausted of sizeable opportunities. The underlying Mesozoic section sources hydrocarbons to the play for middle Miocene slope sands. The unconfined (non mini-basin) slope sands are turbidites and debris flows that were deposited between 5 and 25 miles (8 and 40 km) from their coeval shelf margins. Stratigraphic traps in this environment are created at the margins of the levees as they interfinger with slope shales. Additional geometric modifications of the stratigraphic traps result from post-depositional erosion or 'cannibalization'. The erosion left 'monadnocks', or remnant patches of porous sands, that are encased in low permeability shales. Turbidite channel/levee deposits are the dominant reservoir fades in these 'patches'; however, they may consist of channel, levee, or debris flow facies. Detailed mapping of these dominantly gas charged erosional remnants shows little to no fit of seismic amplitude effects to structure and the hydrocarbon accumulations often appear as amplitude anomalies 'floating in space'. This work was done to provide an analogue study, as well as to document any remaining prospects that were initially overlooked. Almost every discovery and dry hole in the trend was interpreted and included in this study. Integrating the well control into the geological model by using detailed seismic stratigraphy, whole core description, dipmeter logs, seismic to well tie synthetics, Gassmann fluid substitution and AvO analysis, provided the necessary insight to prosecute this play. Within the play area, seismic velocities of sands and shales are very similar. As a consequence of this, seismic reflections are generally weak and, due to the stratigraphic variability, they are discontinuous. Hence, standard sequence stratigraphic mapping techniques alone are not enough to define these subtle traps. The key to successful exploration is a complete understanding of the rock properties. All of the fields examined displayed subtle amplitude anomalies associated with the presence of hydrocarbons. The ability to understand and quantify both the amplitude is essential to increasing the probability of success in this play.

D u r i n g the 1980s, exploration in the northeastern Gulf of Mexico focused on the search for h y d r o c a r b o n s in U p p e r M i o c e n e and Pliocene deltaic sands t r a p p e d in c o n v e n t i o n a l b r o a d rollover anticlines associated with down-to-thebasin growth faults and o n t h e flanks of diapiric salt domes. E x p l o r a t i o n was b a s e d o n 2D seismic data. These oil and gas bearing sands are h y d r o - p r e s s u r e d and s h o w seismic a m p l i t u d e a n o m a l i e s with a ' d o w n - d i p shut-off' that is c o n f o r m a b l e with a structure contour. This play was in a m a t u r e phase of d e v e l o p m e n t . Lying b e n e a t h this play, in t h e m i d d l e to u p p e r Miocene, was a n e w and relatively u n c o n v e n -

tional play for h y d r o c a r b o n s stratigraphically t r a p p e d in d e e p - w a t e r sands (or STDWS play). A few k e y wells existed during this t i m e that p r o v e d the p r e s e n c e of these d e e p - w a t e r sands. This p a p e r characterizes the k e y attributes of the d e e p stratigraphic play, and traces the interplay of t e c h n o l o g y and drilling results during various phases of the evolution and exploitation of the play.

Stratigraphic framework T h e s t r a t i g r a p h i c c o l u m n , d e f i n e d by t h e d e e p e s t well p e n e t r a t i o n s in t h e study area,

From: ALLEN,M. R., GOFVEY,G. P., MORGAN,R. K. & WALKER,1. M. (eds) 2006. The Deliberate Searchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254,127-151. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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extends from the Lower Cretaceous to the Recent (Quaternary). During the Lower Cretaceous, the Gulf of Mexico was tectonically stable except for general subsidence in the centre of the basin. Shallow water covered the shelf while aggradational 'reef' carbonates built up at the shelf slope break forming a marked bathymetric rise that encircled the early Gulf of Mexico basin (Fig. 1). In the study area, this carbonate shelf edge, or reef, reached a relief of nearly 5000 ft from the toe of slope to the reef crest and the slope was inclined at approximately 11 degrees (Fig. 2). This bathymetric rise is higher and steeper than in most other areas around the Gulf of Mexico due to the rather unique vertical stacking of reef margins from the Lower Aptian through the mid Cenomanian. During the U p p e r Cretaceous, a general oceanic highstand prevailed. Chalk, marls and

some terrigenous input comprise the dominant lithologies. There is generally a disconformity between the Upper and Lower Cretaceous. In places, Upper Cretaceous overlies Lower Cretaceous carbonates, which represents a time gap of some 30 million years. Smaller time gaps are documented along this disconformity in the NW portion of this study area. The Cretaceous-Tertiary boundary is marked by an erosional unconformity. Basal Tertiary sediments of Paleocene to Lower Miocene age overlap and fill small erosional depressions in the Cretaceous resulting in time gaps varying from 20-60 million years. The Early Tertiary sediments are relatively thin in the study area. The sedimentation rates were very low as the main depocentre during this time was located far to the west, in west central Louisiana and east Texas (Galloway et al. 2000).

Pig. 1. A generalized lithologic map during the lower Cretaceous when a prominent carbonate shelf margin encircled the early forming Gulf of Mexico. Within this study, this shelf margin was a significant palaeo-high.

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Fig. 2. The Cretaceous shelf margin was onlapped from the early Tertiary through the upper Miocene. The six major sequence boundaries, which contain the reservoir rocks for the play, were all influenced by the presence of the palaeo-high as the flows either onlap or were confined laterally by the high. In the study area, the Paleocene is distinctive in its red coloured shale with a thickness range from 50-300 ft. The Eocene and Oligocene are both commonly comprised of deep-water chalk or marl up to 600 ft thick for the Eocene and 200 ft for the Oligocene. The Lower Miocene sediments continue to onlap the relict Lower Cretaceous bathymetric high (Fig. 2). Lithologically, the Lower Miocene is very shaley with patchy, thin carbonates or marls deposited in a deep-water environment. A widespread unconformity marks the top of the Lower Miocene. This unconformity is particularly evident along the maximum height of the

bathymetric rise and the adjacent shelf area to the north (Smith 1991). Commonly, along the unconformity, the overlying middle Miocene fauna, Cibicides Opima, overlies the Oligocene chalk while the Lower Miocene section is missing entirely. The Middle Miocene saw a shift in the clastic depocentre to the east, into the study area, and sedimentation rates increased significantly, especially between 10 and 15 million years ago. The basin filled quickly as sands and shales prograded across the study area from NW to SE, sub parallel to the Lower Cretaceous bathymetric high (Fig. 3). Sediments were delivered into deep water from this

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advancing delta during the six major lowstands in the upper middle Miocene. Rapid sedimentation rates resulted in a complex system of scouring and filling whereby stratigraphic traps formed in the STDWS play. Benthic and planktonic foraminifera as well as calcareous nannofossils, as defined by Styzen (1996), define the six-lowstand intervals (Fig. 4). In this report, the lowstands are defined as the units below the capping 'flooding horizon'. The lowstand sands are named after the age (in million years) of the underlying maximum flooding event. In the study area, the '14.35' lowstand sequence was deposited in the deepest palaeo water depth of the five sequences, estimated at greater than 600 ft based on palaeontologic examinations. The relief on the relict Cretaceous palaeo-high suggests water depths of a few thousand feet during this time. As the deep-water sediments filled in the basin, water depths lessened with

time during the upper middle Miocene, such that the youngest '10.75' lowstand event was deposited in water depths of 500 ft or less basinwards of the shelf/slope break.

Structural setting and hydrocarbon charge A generalized structure map for the play can be characterized as faulted monoclinal dip that deepens to the SW portion of the play area (Fig. 5). This play undoubtedly extends to the SW of the outline, but it will be difficult to identify prospects there due to loss of amplitude support with burial depth, increasing the exploration risk. Objective depths from the shallowest '10.75' sequence to the deepest '14.35' sequence range from 6100 to 16 000 ft. Present day water depth is less than 450 ft. Objective sands are all soft to mildly geopressured with gradients between 0.55 and 0.75 psi/ft, and the base of

Fig. 3. Dip profile illustrating Miocene progradation from NW to SE, which filled the basin. The wells are field discoveries in the STDWS play The turbidite/debris flow reservoirs shown in this figure were deposited near the toe-of-slope or base of the prograding delta front.

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Fig. 4. Presented here are the six lowstands that contain the deep-water reservoirs in the study area that range between 14.35 and 10.75 Million years before present (MMYBP). The maximum flooding surface or top of the highstand systems tract (HST) defines the 'age' of the reservoir sands. hydropressure generally follows the base of the deltaic section. Reservoir temperatures of the objective section lie between 185 and 290 degrees Fahrenheit. Stratigraphic traps in the STDWS play are positioned regionally on monoclinal dip to the south and SW with down-to-the-basin faults providing some of the trapping elements, as well as providing access to a thermal Mesozoic charge (Figs 2 & 5). Source rocks in the Mesozoic are found in the Turonian (midCenomanian), Tithonian through Neocomian (Upper Jurassic through Lower Cretaceous) and Oxfordian (Upper Jurassic) (Cole et al. 2001). All three of the source rock intervals are observed immediately north of the play area. These Mesozoic sediments plunge sharply beneath the play area along the palaeobathymetric high. At a depth below the play area the source rocks enter a 'cooking pot' where oil and gas expulsion and migration occurs. The down-to-the-basin faults appear to

cut source rocks in the 'cooking pot' and allow for vertical migration of hydrocarbons into the Miocene and younger formations. For example, at Pabst Field (Fig. 5), the Miocene reservoirs contain thermogenic gas resulting from thermal cracking of crude oil at depth and then vertical migration in discrete pulses (Sassen & Decker 2000). The dominant type of hydrocarbons in the STDWS play is gas with some oil in the form of condensate. The hydrocarbon mix as a percentage of oil and gas at the surface average 14% oil and can be as low as 0.05% (in three fields) or as high as 41%. Some of the gas may have a biogenic contribution. Immediately north of the study area, the Miocene fields are made up primarily of biogenic gas (Mink 1988).

Reservoir rock The reservoir quality for all of the Miocene objectives is very good. Porosities range from 24 to over 30% with permeabilities of several

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Fig. 5. Regional structure map on the 11.10 MMYBP sand shows the stratigraphic traps on monoclinal dip. The faulting provides both access to Mesozoic charge and part of the trapping element to some of the fields.

hundred millidarcies to over a darcy. The netto-gross in the thin-bedded reservoirs varies from 20-60%, averaging between 30 and 50%. Thicker bedded reservoirs have similar porosity and permeability as thin-bedded sands but have net-to-gross ranges between 40 and 85%. For the purposes of this paper, thin-bedded reservoirs comprise individual sand beds less than 3 fl (as thin as micro laminations) thick, while thick-bedded reservoirs comprise sand beds greater than three feet thick. Three feet was chosen as the discriminant as that corresponds to the highest resolution for conventional logging tools. On standard log evaluations, many of these reservoirs appear as silty sections with low resistivity (high water saturations) and low net to gross. Thin-bedded reservoirs are best resolved with 'high-resolution' logging tools such as FMI, SHDT, BHTV and NMR (Akkurt 1997; Rollins 8,: Shew 1993) (Figs 6 & 7). In the objective sections, it is common to find both thin and thick-bedded sand sequences stacked vertically during lowstand intervals. Based on cores, dipmeter and imaging logs, dip measurements in thick-bedded sands are highly variable 'stratigraphic' dips that are much steeper than and comprise differing dip

directions from the semi- regional dip (Fig. 7). This is due primarily to amalgamation (channels and scours) surfaces within channel fill sands. The channel fill interpretation is further supported by the classic 'bell-shaped' log motifs or a thinning-upward profile (Serra & Sulpice 1975). Channel-fill sands generally have a high net-to-gross ratio (up to 85%), although fluid migration is often tortuous due to internal baffles and barriers such as amalgamation surfaces (Kendrick 2000; Bramlett & Craig 2002). Channel-fill sands show rapid thickness changes as they comprise multiple, partially stacked, and laterally accreting sands deposited within a pre-existing scour depression (Kendrick 2000). Thicker beds are found as isolated beds with sharp bed contacts with surrounding shale, amalgamated with other thick beds, or overlain by gradually thinning beds toward the top of the sequence. In this type of sequence, generally the top two thirds contains thin beds with bed thickness decreasing to millimetre scale (Fig. 6). These thin beds were the last beds to be deposited as the sediment cloud of the turbidite flow settled to the sea-floor. On amplitude maps, these 'thinning-upward' sequences are expressed as a

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Fig. 6. Logs, core and thin sections are used to describe the thin-bedded character of a levee fades. The model cross-sectional drawing at the bottom left describes the interpretation of what the conventional log found from the well. The FMI log (centre) is a example from a 6 ft logged section from the levee facies. The sidewall and thin sections pictures show more detail at the lamination scale.

Fig. 7. Dipmeter logs can be used to determine facies differences between a channel and levee. Consistently low dips characterize levee beds whereas 'wide ranging' dips and dip direction indicate multiple scours and amalgamation surfaces in channel facies. The FMI dipmeter calibrated to the image clearly shows this relationship of the two facies. Once calibrated with an FMI log, a similar interpretation can be made using a conventional wireline dipmeter (right).

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m e a n d e r i n g shape with a well-defined lowamplitude central channel, flanked by wider belts of high amplitudes representing thinb e d d e d levee deposit (Fig. 8). On vertical seismic sections, this central channel, flanked by the amplitude anomalies, results in what have been referred to as a 'gull-wing' seismic signature (Shew et al. 1993) (Figs 6 & 8). While the channel-levee system is dominated by the extensive levee facies on either side of the central channel, there are other minor sands with a different origin associated with this system. These minor sands include subordinate channels caused by breaks in the levee and associated splay sands or sheet sands. Levee sands are composed of very fine sands and silts that contain ripple bedding, pinch and swell structures with some convolute bedding and very minor bioturbation. G r a d e d beds, sometimes only seen in thin section, indicate that the deposits are true turbidity currentderived deposits and not b o t t o m - r e w o r k e d sediments (Shew et aL 1993). These thin beds, deposited as the turbid sediment cloud dissipated, have a large lateral extent with

individual beds having excellent lateral continuity. Reservoir connectivity appears to be in the thousands of acres in the absence of faulting (Clemenceau & Colbert 1999). At the RamPowell field, single wells in the '11.10' sequence have drained hydrocarbons over 4000 acres, based on material balance estimates (Bramlett & Craig 2002). The channel axis separating the levee flanks is commonly shale filled. There may be some sand 'lag' deposited in the bottom of the channel, but it still acts as a barrier to flow from one levee flank to the other. At the Tahoe field, both levee flanks produce hydrocarbons but do not communicate hydraulically across the channel. Hydrocarbons in each levee on either side of the channel frequently exhibit different hydrocarbon geochemistry and have different fluid contacts (Kendrick 2000).

Miocene depositional model Significant sediment input occurred during the middle to upper Miocene as deltas prograded from the NW to SF, into the deep-water basin adjacent to and parallel with the relict

Fig. 8. This example is a flattened timeslice through an area where a meandering channel levee was confirmed by wells. The red areas are the lowest impedance followed by the orange and grey. Black areas have the highest impedance. The seismic line at the bottom is displayed as integrated trace data (RFC with a 90 degree phase roll. This display matches a gamma ray response where the zero crossings are bed boundaries and the thickness of the low impedance (left kicking trace) corresponds to the thickness of the levee sand. Note that the channel is interpreted to be within the blue meandering line. The impedance is medium to somewhat high, indicating that the channel is probably shale filled.

IDENTIFICATION OF STRATIGRAPHIC TRAPS Cretaceous shelf margin (Fig. 9). During this progradation, six prominent lowstands in the middle Miocene brought significant amounts of sands via debris and turbidite flows into the basin. Objective reservoir sands are present in all of the lowstand intervals. The lowstands are dated at 14.35, 13.80, 13.05, 12.20,11.10, and 10.75 million years ago. During these lowstands, sediments were introduced into the basin as unconfined flows. In this paper, an unconfined flow refers to a turbidite or debris flow that moved downslope, unimpeded by 'filling and spilling' into salt-bounded mini-basins typical of the central Gulf of Mexico (Winker 1996; Toniolo 2003). The only 'confinement' of flows into the NE Gulf of Mexico was lateral containment by the steep bathymetric rise of the relict Cretaceous shelf margin. Most of the flows simply m e a n d e r e d down a gentle slope. Turbidite flows beyond 25 miles down-dip from the coeval shelf margins show strong evidence

Fig. 9.

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of meandering channels with levees built along the channel margins.

Stratigraphic traps Stratigraphic traps in the study area are genetically classified as constructional or destructional. A n example of a constructional stratigraphic trap would be a channel-levee complex meandering downslope over prodelta or bathyal shales that construct an organized depositional tract of predictably changing lithofacies. Specific facies in this depositional tract are levee deposits with associated crevasse splays, which flank a m e a n d e r i n g channel, commonly shale-filled. The levee facies often formed p a l a e o - b a t h y m e t r i c highs of a 'gullwing' shape in cross-section (Fig. 8). A n o t h e r type of constructional stratigraphic trap is an onlap trap. During the middle to upper Miocene, there was continuous onlap of

The illustration is a conceptual model for deep-water sand dispersal into the study area. Sediment input came mainly from the NW as the ancestral Mississippi delta prograded into the basin. The direction of progradation was to the southeast and paralleled the ancestral Cretaceous Shelf margin. The shelf margin remained a significant seafloor palaeo-high throughout most of the Miocene. Smaller deltas sourced from the north occasionally spilled over the edge of the palaeo-high before turning SW into the deeper part of the basin. Because the palaeo-high had an steep slope into the basin, shales occasionally slumped into the basin disrupting the sediment supply from the NW.

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sediments against the large relief, palaeobathymetric carbonate high. Destructional stratigraphic traps are 'modifications' of constructive traps and are the most common traps in the study area. Destructional stratigraphic traps are created when flows scour away earlier sand deposits, leaving b e h i n d isolated sand 'patches'. The scouring action, which modifies a depositional tract (e.g. channel-levee complex), creates lateral facies changes that are not predictable because they are related to different depositional system tracts. Only part(s) of the original depositional system tract is preserved. The recognition of these 'remnants' of reservoir sand is critical because the geometry of the r e m n a n t can greatly differ from the original deposit (Martinsen 2003). Martinsen defined 'depositional

remnants' as a 'sedimentary deposit that is only part of an original depositional system preserved after subsequent, but commonly penecontemporaneous, erosion'. Reasons for the a b u n d a n c e of these destructional stratigraphic traps in the study area are the proximity to the sediment entry points and the lower rate of subsidence on the slope margin relative to the basin. In general, larger areas of remnant sands are found further down-dip in the basin. For example, extending the map of the 10.75 million year remnant sand down-dip out of the study area reveals a wide facies belt that can be more easily recognizable as a channel levee system (Fig. 10). W h e n multiple alternating cycles of deposition and erosion occur (especially in up-dip locations), the result is a seemingly chaotic agglomeration of small sand bodies with

Fig. 10. This map is an amplitude map of the 10.75 million years sand. From the map it appears that this sand was deposited in a channel-levee system. The study area is at the northern most area of this map (dashed box). Within the study area, depositional systems like these are not evident through mapping because post depositional erosion has left only remnants of sand to be preserved from this delivery system.

IDENTIFICATION OF STRATIGRAPHIC TRAPS poor connectivity: a plethora of stratigraphic traps. The stratigraphic traps in the study area are almost always fully hydrocarbon charged, with little of the sand extending into a water leg. As a result, the reservoirs are essentially all produced by depletion drive. Typically, the reservoir sand only extends over a h u n d r e d acres to a few thousand acres. Those fields that are located more basinward have more extensive reservoirs as these were less subject to multiple post-depositional periods of erosion. These more extensive sand bodies do have water legs and produce at least a partially by water-drive. Figure 11 (acoustic impedance data - see 'Geophysical Play Characteristics' section) shows two stacked seismic anomalies. The lower a n o m a l y represents a channel-levee depositional system and shows a typical 'gull-wing' image (Shew et al. 1993). The central channel is most likely shale filled with only a basal sand lag. Seismic traces in the channel show neutral

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impedance, typical of shale in the area. The solid filled traces have low impedance and represent hydrocarbon filled sand as confirmed by the well penetration. The upper seismic anomaly has a central low flanked by seismic reflections that thin away from the centre. This shape is indicative of a broad, fiat scour that eroded into the left levee flank of the channel-levee system. The broad scour was sand-filled and then also charged by hydrocarbons. The gamma ray curve from the discovery well supports the interpretation from seismic as the levee portion of the log has a thinning-upward pattern while the scour channel has a blocky shape with sharp contacts above and below the sand. Examples of shale filled, low relief scours can also be found as a lateral seal in some stratigraphic traps (Fig. 12). H y d r o c a r b o n - f i l l e d remnants sands are shown as red events in the seismic examples of Figure 12. Shales and silts are grey to pale-yellow in the display. There is a large ratio of the scour width to scour depths. Widths of scours can be from 5000 to 15 000 ft

Fig. 11. An erosionally modified trap. The two amplitude anomalies in the upper right display appear to merge together over a small area. This area was penetrated by a well and found two genetically different gas-filled sands. The lower sand had a classic log motif of a thinning upward levee deposit. It seismically tied to an amplitude that has a 'gull-wing' shape indicative of a channel-levee system. The upper sand has sharp contacts next to a shale base line curve. The seismic anomaly that this sand ties to has a thick centre to the amplitude and thins away in both directions. The log and seismic anomaly shapes both support a sand-filled scour interpretation. The upper sand-filled scour had cut down into and removed part of the older levee deposit modifying the trap.

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Fig. 12. This is an example of how mapping the terminations of the amplitude anomalies (red on seismic) can lead to an interpretation of defining the stratigraphic trap. Without this identification, these amplitude anomalies are seemingly randomly placed. The blue line on the seismic displays show the base of scours which cut into the sand and removed parts of the potential reservoir section and because the scour is shale-filled, a destruct ional or modified stratigraphic trap is created. while the scour d e p t h is on the o r d e r of a few h u n d r e d feet. S o m e of t h e flows p r o d u c i n g scours a r e c o m p o s e d m a i n l y of r e m o b i l i z e d p r o d e l t a

shales, w h i c h s l u m p e d off the o v e r - s t e e p e n e d e d g e of the relict C r e t a c e o u s shelf edge. Such shale-filled scours act as the lateral seals in the ' B u d ' field (Figs 9 & 13). H e r e the shale slumps

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Fig. 13. Shale slump features appear to have periodically moved downslope to the south off the steep palaeo-high. If a flow system moving along the base of the palaeo-high had deposited sands prior to the slump, then the slump often cut across the sands and removed them by scouring to a base level below the sands. Since the slump mainly consisted of prodelta shales with no sand deliver system, the scour was shale filled and acted as a trapping element for hydrocarbons. cut across the SE trending channel-levee systems, thus isolating part of the long longitudinal levee sand belt and creating a smaller stratigraphic trap.

W h e n multiple stacked cycles of deposition and erosion occur, reconstruction of original geometries and lithologic patterns is nearly impossible, as they have been modified beyond

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recognition. The 'Pabst' field is a series of stacked stratigraphic traps, characterized by multiple periods of deposition and scouring. Evidence for this can be seen in several wells separated by only a few thousand feet (Fig. 14). Stratigraphic traps are formed in this setting where shale filled scours act as seals. With so much scouring after each pulse of sand deposition, pattern recognition of a discrete depositional unit in map view is impossible (Fig. 15). For example, hydrocarbon filled channel-levee sands form irregular shaped 'blobs' expressed as amplitude anomalies without recognizable shape or pattern. What presumably was a long continuous and narrow meandering belt now appears as a series of amplitudes 'floating' on regional dip (Fig. 16). Most of the deep-water flows were sourced from the NW. A few of the flows came into the basin from smaller deltas originating north of the play area (Smith 1991). Some of the deltaic

pulses of sedimentation spilled over the edge of the palaeo-high into the deep basin. As a channel cut into the escarpment edge, it scoured into the older carbonate/marls. The first prospect drilled by Shell in the STDWS play (Prospect Michelob) targeted a 'bright spot' seismic anomaly which filled one such scour cut into the palaeo-high (Figs 9 & 17). The amplitude map in Figure 17 shows a 'protrusion' of the amplitude anomaly to the north, representing a notch of Miocene sand that filled the scour. The sediment in this channel cut was carried as a debris flow into the basin. Cores from the Shell wildcat well show this sand to be poorly sorted with rip-up shale clasts and even a couple of five to six inch diameter carbonate mud clasts (Fig. 17). The wildcat well found residual gas in the amplitude, which presumably leaked up-dip along the channel cut. Trap failure is likely due to the low sealing capacity of the underlying carbonate/marl and there is no dip reversal to

Fig. 14. Note the complex interaction of channel levee sands and sand-filled scours. Additional mapping complications arise due to sands, which flip polarity when hydrocarbons are present (from Pabst Field).

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Fig. 15. Seismic amplitudes from Pabst field, which appear as isolated amplitude 'blobs' on regional dip. help the trap. Interestingly enough, another operator drilled a second well up-dip on Prospect Michelob and also found residual gas in the same sand. In Figure 17, the amplitude extension to the SE represents the path of the debris flow as it reached the basin axis and

turned SE towards the deeper basin centre. A late east-west trending fault (white area) cut and displaced the sand to form the lateral seal for the MP 225 field discovered in 1995 (Fingleton & Zinni 1999).

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Fig. 16. Seismic amplitudes 'floating' on regional monoclinal dip. This prospect had a very low chance for success prior to well and seismic calibrations and an understanding of the trap styles in this play.

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Fig. 17. Prospect Michelob - An example of a debris flow facies and a failed onlap trap due to 'seat-seal' failure up-dip.

Geophysical play characteristics All seismic interpretations are based on pseudo acoustic impedance data (integrated reflectivity data with a 90 degree phase shift). On this type of display, the seismic trace matches directly with well logs. Zero crossings of the seismic trace correlate with bed boundaries on logs. For example, a 'soft' or left kicking, seismic trace would tie directly with an interval of 'low impedance' sand. A detailed example of this seismic to log tie is shown in Figure 11. Most of the objective sands are acoustically low to medium impedance sands primarily due to low degrees of burial. Further burial and heating would result in excessively high impedance sands which would not produce conventional amplitude anomalies or 'bright spots' if gas charged. Because of the high risks in exploring for stratigraphic traps, amplitude bright spots are needed to help define the trap and increase the chance of finding trapped hydrocarbons. The transition from low impedance to high

impedance for 'wet' sands generally occurs over a depth range between 2500 and 7500 ft. Near the SW edge of the play boundary, the basin continues to deepen in that direction and the objective upper and middle Miocene sands enter a seismic regime where all of the sands are very high impedance and no conventional amplitude anomalies are expected. A crosssection in (Fig. 18), illustrates the relationship between stratigraphy, depth, and impedance regimes. The accompanying seismic section is shown in Figure 19. Conventional amplitude anomalies are found in all three impedance regimes due to the high gas content of the hydrocarbons and good porosity (23%) present even in the high impedance sands. The high impedance sands become low impedance with hydrocarbon fill (or 'flip' polarity). Identification of the elements to stratigraphic traps and the extent of the reservoir in the water leg becomes more of a challenge when seismic phase changes take place with the introduction of gas (Fig. 20). Low impedance 'wet' sands do not change phase with gas fill and both the gas

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Fig. 18. Structural 'dip' section indicating with horizontal bands, the zones of similar rock properties that yield similar seismic responses to sands. and water legs can be mapped on seismic. For seismically invisible as well as hard sands, the extension of the sand into the water leg can often not be mapped with confidence, and it may not be possible to distinguish brine-filled sand from shale. Examples of such polarity reversals have also been reported at the 'Chinook' field (Butler & Towe 2001). Three examples of the different sand impedance regimes are shown in Figures 21, 22, and 23. Finally, to illustrate the challenge of interpreting depositional and erosional processes is when combined with seismic phase changes associated with gas filled sands; refer back to the Pabst Field shown in Figure 14. Carefully note the trapping complexities of 'interbedded' wet and gas filled sands.

Play history Lease sale in the Gulf of Mexico prior to 1983 was by nomination of individual Outer Continental Shelf (OCS) blocks 3 miles2 in area. This tended to cause exploration to be rather reactive in evaluating exploration potential in blocks nominated by other companies. The first area-wide lease sale in the Gulf was held in 1983 in which all unleased blocks were offered for bidding: no nominations. This change helped to

focus exploration efforts on regional plays rather than on individual prospects. In anticipation of the 1983 lease sale, a team was assigned to the greater Main Pass protraction area in order to establish a dominant lease position in a play with scope for large hydrocarbon volumes. In this particular study area, very limited opportunities remained in the established deltaic structural play. What remained could be geologically characterized as faulted monoclinal regional dip with onlapping geometries to the north against a large palaeo-high (relict Cretaceous shelf margin). The stratigraphy in this setting was predicted to comprise middle Miocene deep-water sediments based on sparse well control. The team observed that there were abundant Miocene oil shows in a few good reservoir quality sands from the key well penetrations. With two of the three key ingredients observed, the remaining ingredient, trap, was needed. Although none of the key wells penetrated a good bright spot in the STDWS play prior to 1985, it was observed that the Miocene section in the study area did contain several untested moderate to good quality 'bright spots', from which it could be inferred that hydrocarbons and therefore traps were present. At the time, Shell had an established

IDENTIFICATION OF STRATIGRAPHIC TRAPS

145

Fig. 19. Actual seismic line of the 'area of interest' shown in Figure 18. record of bright spot technology, developed throughout the 1970's and beyond (Proubasta 2000). In the 1984 lease sale, Shell bid on, and won eleven of these 'bright spot' supported prospects that required a significant stratigraphic trap component to work for prospect success. Shell's first well, Prospect Michelob, found residual gas in a debris flow sand (Fig. 17). The second well (Bud, Fig. 13) drilled another 'bright spot' that onlapped the palaeo-high. The 'Bud' discovery well was drilled updip from a 1973 (Chevron) well that had targeted a deeper Cretaceous carbonate reservoir but found thin pay in a Miocene sand at the edge of a 'bright spot'. This well was drilled in 1973 and was thought to be non-economic due to the low resistivity readings and a gamma-ray log that indicated a low net-to-gross for the sand. However, in 1985, careful petrophysical reinterpretation of this thin-bedded pay sand showed that it correlated to an amplitude anomaly on seismic. By drilling up-dip in a welldeveloped part of the amplitude anomaly, Shell found gas pay filled to base in a blocky logshaped channel sand and had 'officially' made the first discovery in the STDWS play. The first development well targeted a less pronounced development of the 'Bud' amplitude anomaly and found thin microlaminated sands with a low

resistivity profile and a gamma ray profile that appeared to indicate low net to gross. In spite of the hydrocarbons discovery, enthusiasm for the play was dampened by the fact that great uncertainty remained on whether the thin-bedded turbidite levee sands would deliver hydrocarbons at economic flow rates and could be drained effectively. In 1990, a decision was made to 'farm out' the remaining undrilled prospects and keep a small interest. Four reasons were given at the time for this decision: low volume potential, high risk stratigraphic traps with poor amplitude fit-tostructure, amplitudes were inexplicable because they dimmed and brightened 'haphazardly', and the lack of seismic calibration to net pay thickness. The inability of the seismic to de-risk the play was due to, first, the fact that the seismic amplitudes could be identified on a few 2D seismic lines since the dimensions of the prospects generally were smaller than the 2D seismic grid spacing coverage. As a consequence, the amplitudes appeared in map view to have 'ragged edges' and the amplitude anomaly usually did not precisely conform to structural contours. However, two of the undrilled prospects were immediately acquired from Shell and drilled in 1991, resulting in the discovery of the 'Pabst' and 'Busch' fields (Fig. 5).

146

T.J. GODO

Fig. 20. Seismic 'phase' change with the introduction of gas.

Fig. 21. Seismic example of 'soft' sands that are both 'wet' and have gas pay. For location map inset see Figure 9.

IDENTIFICATION

OF STRATIGRAPHIC

TRAPS

147

~

Y, .9

.,..q

e,i eq

148

T.J. G O D O

IDENTIFICATION OF STRATIGRAPHIC TRAPS By the end of 1993, the STDWS play had a total of four discoveries out of ten prospects tested for a success rate of 40% (Fig. 24). All of these prospects were mapped on 2D seismic data. By 1994, Shell had access to production data from Bud field and the well data from the other discoveries. In addition, encouraging production data from other thin-bedded turbidite levee sands were available and used as analogues for this play. A resurgence of interest in the play resulted, and Shell worked with a seismic vendor to acquire a regional 3D survey in the study area. This data was also made available to the industry. Over the next eight years, 27 new fields were discovered out of a total 35drilled prospects thus increasing the cumulative

149

success rate in this play to 69% (Fig. 24). The main cause of failure was residual gas. Only one prospect failed due to lack of reservoir. All of the discoveries were commercial successes. The average field size is 75 B C F (Billion Cubic Feet) of recoverable gas or an equivalent oil volume. The largest field has a recoverable volume of over 300 BCF. The total play volume discovered to date is 350 M M B O E (Million Barrels of Oil Equivalent) with no significant discoveries made in the last 3 years (Fig. 25). The play was 'creamed' within 8 years after acquisition of the regional 3D seismic survey. A volume threshold for commerciality was low because prospects were located in shallow water with existing n e a r b y infrastructure. E c o n o m i c thresholds

Fig. 24. 1993 and 2001 maps of the study area showing the wells that were discoveries and dry holes at that time.

Fig. 23. Seismic example of a 'hard' sand when 'wet' and with gas pay.

T. J. G O D O

150

'94 4

8 Years

10-

400

9~o

8-

350 5m 300 ~

76

'01

250

"

5"

200 ,~

4 "

150 E. loo

50

=~

"ill [] # of fields start on prod.

Year

Fig. 25. Histogram showing the discoveries and dry hole through time as well as the cumulative volume curve that resulted from the stratigraphically trapped deep-water sands play (STDWS play).

were further lowered after the 3D survey, as this allowed for more precise placement of wells for better drainage, and the drilling of horizontal wells, thus facilitating 'fastrack' prospect d e v e l o p m e n t and platform construction (Fingleton & Zinni 1999). Conclusions

During the middle to upper Miocene in the northeastern Gulf of Mexico, unconfined deepwater turbidites, debris flows and slump shales produced complex stratigraphic traps by the interaction of penecontemporaneous constructional and destructional processes. Constructional processes produced stratigraphic traps as sands were deposited along the path of the turbidite flow in a meandering channel with flanking levee deposits of sand. Basinal shales seal the levees laterally. Destructional traps are modifications of constructional traps caused by p e n e c o n t e m p o r a n e o u s flow(s), cross-cutting earlier flow deposits and thus creating lateral lithologic change on a new orientation. R e p e a t e d occurrences of crosscutting deepwater flows can almost entirely remove previously deposited sands, rendering recognition of these systems unlikely, as based on seismic patterns or geometries. Occurrences of multiple crosscutting flows are located updip on the slope, near the sediment entry points. Hydrocarbon traps found in the up-dip part of the basin (i.e. this study area) are as a result, smaller in comparison to stratigraphic traps formed by

downdip. Nearly 2 trillion cubic feet of gas (350 M M B O E ) have been produced in the last 13 years from the study area. The average field size is 75 BCF of recoverable gas or equivalent oil volumes. The largest field has a recoverable volume of 300 BCE Drilling over the last 13 years has yielded 31 fields out of 45 prospects for a success rate of 69%. A critical, industry available, 3D survey began to be used in 1994. Ninety percent of the discoveries were made within eight years after the 3D became available, essentially creaming the play. Full acknowledgement is due to Shell Exploration and Production Company for supporting this work and allowing this publication. A grateful acknowledgement is due to Veritas D G C Inc. for the permission to use seismic examples presented in this paper. Also a great debt is owed to my friend and coworker Robert Foster, who geophysically supported me during the study. I would further like to acknowledge my supervisors B. Hewett, R. Watson, P. Brit-

tingham, J. Shepard, and L. Gaarenstroom for their coaching and support over the 10-year period of this work. A host of co-workers from our research lab in Houston and operational units based in The Hague are due special thanks for the excellent technical challenge. A final thanks goes to my wife and family for their support and indulgence during the writing of this article. References

AKKURT, R., MOORE, M.A. & FREEMAN, J.J. 1997. Impact of NMR in the development of a deepwater turbidite field. Transactions of the SPWLA

IDENTIFICATION OF STRATIGRAPHIC TRAPS (Society of Professional Well Log Analysts) Thirty-Eighth Annual Logging Symposium, June 15-18, 1997" Houston, Tex., Society of Professional Well Log Analysts, Paper SS. BRAMLETF,K.W. & CRAIG,P.A. 2002. Core Characterization of Slope-Channel and Channel-Levee Reservoirs. in Ram Powell Field, Gulf of Mexico. In: WEIMER, P., SWEET, M., SULLIVAN, M., KENDRICK, J., PYLES, D. & DONOVAN,A. (eds) Deep-Water Core Workshop, Northern Gulf of Mexico. GCS and SEPM Foundation Conference, 10 March, 2002. BUTLER,C.E. & TOWE,S.K. 2001. Chinook Held. Main Pass 283 and Viosca Knoll 734: A case study. AAPG Bulletin, 85, No. 13 (supplement). COLE, G.A., YU, A., PEEL, E, REQUEJO,R., DEVAY,J., BROOKS, J., BERNARD, B., ZUMI, J. & BROWN,S. 2001. Constraining source and charge risk in deepwater areas. World Oil, 22, 69-77. CLEMENCEAU,G. & COLBERT,J. 1999. Levee-overbank turbidite production from Ram/Powell Field, Deepwater Gulf of Mexico. AAPG Bulletin, 83, 1296-1346. FINGLETON, G.W. & ZINNI, E. 1999. 3-D impact on exploration success, Main Pass South and East Area, Gulf of Mexico. The Leading Edge, 18, 200-205. GALLOWAY, W.E., GANEY-CURRY, EL., LI, X. & BUFFLER, R.T. 2000. Cenozoic Depositional History of the Gulf of Mexico Basin. AAPG Bulletin, 84, 1743-1774. KENDRICK,J.W. 2000. Turbidite reservoir architecture in the northern Gulf of Mexico deepater:insights from the development of Auger, Tahoe, and Ram/Powell Fields. In: WEIMER, P., SLATT,R.M., BOUMA,A.H., LAWRENCE,D.T., COLEMANJR., J., STYZEN, M. & NELSON, H. (eds) Deep-Water Reservoirs of the World. 20th Annual Gulf Coast Society Sedimentary Geology(SEPM) Foundation Bob E Perkins Research Conference, Houston, Dec. 3-6, 450-468. MARTINSEN,R.S. 2003. Depositional remnants, part 1: Common components of the stratigraphic record with important implications for hydrocarbon exploration and production. AAPG Bulletin, 87, 1869-1882. MINK, R.M. 1988. Regional geologic framework and petroleum geology of Miocene strata of Alabama

151

coastal waters area and adjacent Federal waters area. State Oil and Gas Board Report 16. PROUBASTA, D. 2000. Interview with Mike Forrest, 'father of bright spots' and 'oil finder' at Shell Oil. The Leading Edge, 19, 1184-1186. ROLLINS, D.R. & SHEW, R.D. 1993. Geological and Petrophysical Properties of Thinly-Bedded Turbidite Deposits, Eastern Gulf of Mexico. AAPG Bulletin, 77, 177. SASSEN, R. • DECKER, C.L. 2000. Preliminary geochemical insight into Pabst Field oils and gases. Integrated Reservoir Investigations Group, Semi-Annual Meeting, 21 June 2000, Reed Arena, Texas A&M University. SERRA, O. & SULPICE, L. 1975. Sedimentological analysis of shale-sand series from well logs. Transactions of the SPWLA 16th Annual Logging Symposium, paper W. SHEW,R.D., ROLLINS,D.R., TILLER,G.M., HACKBARTH, C.J. & WHITE, C.D. 1993. Characterization and modeling of thin-bedded turbidite deposits from the Gulf of Mexico using detailed subsurface and analog data. In: WEIMER, P., BOUMA, A.H. & PERKINS, B.E (eds) Submarine fans and turbidite systems - sequence stratigraphy, reservoir architecture, and production characteristics. GCAGS Fifteenth Annual Research Conference, 327-334. SMITH, C.C. 1991. Foraminiferal biostratigraphic framework, paleo-environments, rates of sedimentation, and geologic history of the subsurface Miocene in southern Alabama and adjacent state and federal waters. Geological Survey of Alabama, USA, Bulletin 138. STVZEN, M.J. 1996. A Chart in Two Sheets of the Late Cenozoic Chronostratigraphy of the Gulf of Mexico. AAPG Annual Convention May 11-14, 2003 Salt Lake City, Utah, Gulf Coast Section of SEPM Foundation Publication, Houston, Texas. TONIOLO, H. 2003. Depositional Turbidity Currents in Diapiric Minibasin on the Continental Slope: Theory, Experiments and Numerical Simulation. AAPG Annual Convention. WINKER, C.D. 1996. High-resolution seismic stratigraphy of a late Pleistocene submarine fan ponded by salt-withdrawal mini-basins on the Gulf of Mexico continental slope. Proceedings of the 28th annual Offshore Technology Conference, 619-628.

The importance of stratigraphic plays in the undiscovered resources of the UK Continental Shelf S. J. S T O K E R 1, J. C. G R A Y 2, E H A I L E 2, I. J. A N D R E W S

1 & T. D. J. C A M E R O N

1

1British Geological Survey, Gilmerton Core Store, 376 Gilmerton Road, Edinburgh EH17 7QS, UK (e-mail: s#[email protected]) 2Department of Trade and Industry, Energy Resources and Development Unit, 1 Victoria Street, London S W I H OET Abstract: This paper analyses the statistics of existing United Kingdom Continental Shelf (UKCS) fields and discoveries as a means of assessing which plays are likely to contain the greatest untapped potential for stratigraphic traps. Current Department of Trade and Industry (DTI) estimates put the maximum discovered ultimate recovery of the UK at 50 billion (x 109) barrels of oil equivalent (BBOE); estimated technically recoverable undiscovered resources are between 4.1 to 21.3 BBOE, based on a prospect mapping approach. As of end 2003, 82% of the oil and gas fields and discoveries on the UKCS have been found in structural traps; 12% have been found in combination structural/stratigraphic traps and only 6% in stratigraphic traps. The majority of stratigraphic traps and combination traps occur in association with syn-rift (Upper Jurassic) and post-rift deep-water plays. There has been relatively little direct exploration for stratigraphic traps until recently, and a number of the major discoveries in stratigraphic traps were found by chance. Few substantial untested structural traps remain in the UK North Sea except at considerable depth with associated risks. We estimate that perhaps 50% of the UKCS undiscovered resources are located in stratigraphic or combination traps, principally within syn- and postrift deep-water sandstone plays.

The DTI publishes annual statistics of the U K ' s discovered, produced and remaining recoverable reserves (ultimate recovery), accompanied by estimates of the UK's technically recoverable undiscovered resources (on the basis of current technology). A t the end of 2003, the ultimate recovery from the UK's discovered reserves in both offshore and onshore fields was predicted to be 50 B B O E (DTI 2004a), more than 99% of which is located in offshore basins (Fig. 1). C u r r e n t D T I estimates of the undiscovered technically recoverable resources on the U K C S range between 4.1-8.9-21.3 B B O E , and are based on a predominantly prospect mapping approach of k n o w n plays; estimates derived from statistical assessments support these figures (Stoker et al. 2004). The DTI's complete database of 660 offshore fields and technical discoveries (as of end 2003) has been used to construct discovery curve and accumulation size distribution charts. This database was derived from the DTI's listing of offshore producing, ceased production and approved fields, plus unpublished data from discoveries for which there are no current plans for development (Potential Additional Reserves (PARs)). We have used hydrocarbon volumes originally in place, to negate the effects of variable recovery factors and the n e e d to

Fig. 1. Major basins of the United Kingdom Continental Shelf.

From: ALLEN,M. R., GOrTEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The Deliberate Searchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254,153-167. 0305-8719/$15.00. 9 The Geological Society of London 2006.

154

S.J. STOKER E T A L .

consider reserves growth. The accumulation size classes are those used by the US Geological Survey (United States Geological Survey 1995). Discovery curves, or pseudo-creaming curves, offer a visual image of the exploration maturity of an area or play. Data for the UKCS exhibit a maturing signature, where the annual discovery size is generally declining, but significant discoveries are still being made (Fig. 2a). A notable resurgence in 2001 was due to the discovery of the Buzzard oil field, which has an estimated 800-1100 million ( x 106) barrels of oil (MMBO) in place (Dor6 & Robbins 2005). One means of quantifying the exploration success of an area is by the number of discoveries made per exploration well. Between 1965-2003, the average technical (fields and PARs) success rate was 31.1% (Fig. 2b), and despite a low level of exploration over the last five years, the average technical success rate for 1999-2003 was a striking 45.4%. Trap type has been determined for DTI's database of offshore fields and technical discoveries, and the majority (82% by numbers; 75% by volume) of the oil and gas fields and discoveries found by end 2003 on the UKCS are located in structural traps (Fig. 2c-d). Only 6% (5% by volume) have been found in stratigraphic traps, and 12% (20% by volume) occur in combination structural/stratigraphic traps.

As a result of 39 years of exploration activity, the majority of the structural traps have been tested in the U K North Sea. Remaining substantial structural traps in the UK North Sea are likely to lie at considerable depth, such that reservoir quality, high-pressure and hightemperature risks render them more challenging to exploration, taking into account current technology and economic considerations. There has been relatively little direct exploration for stratigraphic traps on the UKCS. Several unexpected major discoveries have been made in stratigraphic and combination traps whilst drilling to deeper, structural targets (e.g. Britannia, Scapa, Alba). Difficulty in recognizing these on seismic data is a major factor in the higher level of risk and uncertainty associated with stratigraphic traps. Sophisticated seismic data analysis, in particular amplitudeversus-offset (AVO) techniques, has proved highly valuable at the development stage, but has not always been reliable in exploration, particularly in the West of Shetland area (Loizou et al. 2006). The Buzzard Field, an Upper Jurassic stratigraphic pinchout/dip trap discovered in 2001, is an outstanding success story credited to application of traditional methods of seismic interpretation, leading to the development of a strong conceptual model (Dor6 & Robbins 2005).

Fig. 2. (a) Discovery curve and discovery history histogram for UKCS fields and discoveries. (b) Number of exploration wells drilled on the UKCS per year and drilling success rate (percentage of offshore exploration wells that have proved technical successes). (e) Proportion of 660 UKCS fields and discoveries in structural, stratigraphic and combination traps. (d) Proportion of UKCS in-place discovered volumes in structural, stratigraphic and combination traps.

IMPORTANCE OF STRATIGRAPHIC PLAYS, UKCS Plotting separate accumulation size distributions for the existing U K C S discoveries located within structural traps and within stratigraphic or combination traps lends supporting evidence to the premise that most of the structural traps have already been discovered. Natural populations of hydrocarbons are widely believed to conform to either a lognormal or a fractal (or power-law) distribution ( U S G S 1995); debate is still ongoing as to which is the most appropriate ( A t t a n a s i & C h a r p e n t i e r 2002). The size distribution of those discoveries located in structural traps has a distinctly lognormal shape suggestive of a mature population, whilst that for stratigraphic and combination traps is rather irregular, indicating an immature or incomplete population (Fig. 3). Whichever distribution is preferred, lognormal or ffactal, there is clearly scope for significant numbers of stratigraphic and combination traps to be discovered, including large fields of 512-1024 million (• 106) barrels oil equivalent ( M M B O E ) in place, and perhaps also fields greater than 2048 M M B O E in place (Fig. 3).

155

Fig. 3. Size distribution chart for UKCS structural and stratigraphic/combination fields and discoveries. The 660 fields and discoveries (including technical discoveries, or PARs) found on the U K C S by end 2003 have been assigned to 43 specific plays. These have been simplified into 15 play groups to determine the relative importance of play type in existing and undiscovered resources (Table 1). Comparison of the total hydrocarbon

Table 1. Breakdown of UKCS known and undiscovered resources by play (modified after Munns et al. 2005) Play group*

Estimate of total hydrocarbon resource at end 2003 (x 106 BOE initially in place) t

%

Estimated Estimated percentage of percentage of total yet-to- total yet-to-find find at end in stratigraphic 2003 in each and combination play group traps

POST-RIFT Pliocene sandstones Palaeogene deltaic sandstones Palaeogene deep-water sandstones Upper Cretaceous carbonates Lower Cretaceous deep-water sandstones

29 1838 23 587 1213

<0.1 1.7 22.2 1.1

0 2 22 5

3668

3.5

12

SYN-RIFT

10 041

9.5

22

11 076

10.4

24 917

23.5

3

5881 3381 880 12 631 6319 575 5

5.5 3.2 0.8 11.9 6.0 0.5 <0.1

8 1 1 7 8 1 0

PRE-RIF-F

Upper Jurassic deep-water sandstones Upper Jurassic shallow-marine/deltaic sandstones Middle Jurassic shallow-marine/deltaic sandstones Upper Triassic to Lower Jurassic sandstones Lower Triassic fluvial sandstones Upper Permian carbonates Lower Permian aeolian sandstones Carboniferous sandstones Devonian sandstones Basement Total

106,041

* Play groups are condensed from a list of 43 UKCS plays t All discovered resources and PARs are included

33

17

55

156

S.J. STOKER E T A L .

volume in known fields and discoveries emphasizes the historical and current importance of the Middle and Upper Jurassic, Palaeogene and Lower Permian plays (Table 1). A variety of data sources and methods (e.g. mapped prospect inventory, statistical evaluations and regional knowledge) have been employed to estimate the proportion of undiscovered resources that may be expected in each play group. Due to the large number of uncertainties involved, these estimates should only be regarded as a guide to the relative significance of each play, and they should be considered in conjunction with the UKCS undiscovered resource range published by the DTI (2004a). Further simplification of the DTI's UKCS fields and discovery database into 7 gross play groups shows that the majority of stratigraphic and combination traps occur in association with Upper Jurassic syn-rift and Cretaceous to Palaeogene post-rift plays (Fig. 4).

Pre-rift stratigraphic potential More than 50% of the discovered resources of the UKCS are hosted within pre-rift reservoirs (Table 1). Analysis of the existing UKCS fields and discoveries shows that there are no purely stratigraphic traps in pre-rift reservoirs, and only 3% of the traps are combined structural/stratigraphic. The proportions of combination traps found within the Palaeozoic, Lower Jurassic-Triassic and Middle Jurassic play groups are 2%, 4% and 3% respectively (Fig. 4). Stratigraphic entrapment is relatively rare in Middle Jurassic and older strata, because of the sheet-like geometry and basin-wide distribution of many of the pre-rift reservoirs. Combination traps in the pre-rift plays generally involve major erosional truncation (e.g. Auk Field; Trewin et al. 2003). Carboniferous

Carboniferous plays comprise 6% of the UKCS known resources (Table 1), and are mostly concentrated in the Southern North Sea Gas Basin (Fig. 1). Discovery curve data for the Carboniferous indicate that this play group is rather immature (Fig. 5a), and Carboniferous plays are estimated to constitute around 8% of the UKCS undiscovered resources (Table 1). Although the majority of the existing Southern Gas Basin Carboniferous discoveries occur within structural traps, many are complicated by significant dip, and by erosional truncation beneath a regional base Permian unconformity. There is significant future potential for Carboniferous stratigraphic traps. For example,

Fig. 4. Proportion of UKCS fields and discoveries in structural, stratigraphic and combination traps for the grouped pre-, syn- and post-rift plays. See Fig. 2 for key to trap type.

largely untested potential remains for exploration of Carboniferous fluvio-deltaic sandstone reservoirs in those sub-Permian truncation traps where there is no structural closure at base Permian level, but where a Carboniferous intraformational seal provides critical lateral closure. Intraformational sealing intervals are common at three levels within the Upper Carboniferous: (i)

an upper, shale-prone part of the Westphalian C-D Ketch Member forms a local seal to underlying Ketch Member sandstone and conglomerate reservoirs, (ii) the Westphalian B Westoe Coal Formation offers a regional seal to the basal Westphalian B Caister Sandstone unit, and (iii) thick basal Kinderscoutian basinal shales locally provide a seal to late Alportian sandstone reservoirs (Cameron et al. 2005; Fig. 6a).

IMPORTANCE OF STRATIGRAPHIC PLAYS, UKCS

157

Fig. 5. Discovery curves and discovery history histograms for selected UKCS pre-rift play groups. (a) Carboniferous. (b) Lower Permian. (e) Triassic gas province plays. (d) Triassic to Lower Jurassic oil province plays. (e) Middle Jurassic. Note different vertical scales.

Permian Lower Permian plays make up 11.9% of the U K C S known resources (Table 1), much of which are located in the Southern North Sea Gas Basin (Fig. 1). This play group is relatively mature, although its discovery curve shows that a steady increase in cumulative volumes has been maintained over the last decade (Fig. 5b). The principal reservoir in the Southern Gas Basin, the Lower Permian Leman Sandstone Formation, comprises aeolian and localized fluvial sandstones. Recent exploration on the play has been targeted at small structures adjacent to existing fields and infrastructure. Its existing gas discoveries are located almost exclusively within structural traps because of

the broadly sheet-like, nearly basin-wide development of the Leman Sandstone Formation. The R a v e n s p u r n North Field on the northern margin of the fairway is a key exception, comprising a combined structural and stratigraphic trap (Ketter 1991). On this margin of the Lower Permian fairway, a good reservoir quality aeolian dune facies interdigitates with sabkha facies and lacustrine shales of the Silverpit Formation. This sets up the potential for significant stratigraphic traps, particularly where aeolian sand distribution is related to palaeotopography (Fig. 6b). Lower Permian plays are estimated to comprise 7% of the UKCS yet-to-find resources (Table 1). U p p e r Permian carbonate plays constitute less than 1% of the UKCS existing resources

158

S.J. STOKER E T A L .

Fig. 6. Examples of pre-rift stratigraphic entrapment from the Southern North Sea Gas Basin (a) Geoseismic section showing Carboniferous erosional truncation traps. (b) Schematic diagram illustrating a mechanism for development of combination traps in the Lower Permian.

(Table 1). There is potential for the development of stratigraphic traps due to facies change, e.g. reefs and oolite or oncolite shoals within shelf-edge barrier zones of the Zechsteinkalk and Hauptdolomit around the margins of the Southern Permian Basin, especially the largely untested northern margin. Poor reservoir quality, as found in well tests of Upper Permian carbonates along the southern margin of the UK Southern Permian Basin, is commonly perceived to be a deterrent to economic viability in the UK sector. However, Taylor (1998) suggested that the most prospective parts of Upper Permian carbonate shelf facies have yet to be drilled. Triassic to L o w e r J u r a s s i c

Almost 9% of the discovered resources of the UKCS are found in Triassic to Lower Jurassic sandstones (Table 1). Discovery curve data for the Triassic southern gas province play group (including the Bunter, Hewett and Sherwood fluvial sandstone plays) and the Triassic-Lower Jurassic northern oil province play group (including the Skagerrak, Cormorant and Statfjord predominantly fluvial sandstone plays) appear rather mature (Fig. 5c-d). The Bunter and Hewett sandstone plays of the Southern North Sea Gas Basin are almost exclusively simple anticlinal structural traps resulting from halokinesis in the underlying Permian Zechstein Group. Most of those remaining undrilled structural traps have no perceived migration

route for gas from the Carboniferous coal measures source rock, and no DHI. Most of the potential for undiscovered gas resources in the south lies in the Sherwood Sandstone play of the Irish Sea and Celtic Sea basins (Fig, 1). In the oil province, there is significant remaining potential for structural traps at depth in the Central Graben and Viking Graben, within a high-pressure high-temperature province. Along the western margin of the Central Graben, Triassic sandstones of the Skagerrak Formation have a limited distribution related to the presence of palaeovalleys formed above dissolving Upper Permian (Zechstein) salt diapirs (Stewart & Clark 1999). A number of undrilled combination structural/stratigraphic traps have been identified within this play (DTI 2004b, prospects 20/30, 21/22A-D & 28/2), similar to that of the Kittiwake Field (Glennie & Armstrong 1991) where the Skagerrak sandstones form a secondary reservoir. Angular unconformity traps offer additional potential for undiscovered reserves. At the Strathmore Field, West of Shetland, oil reservoired in dipping, truncated Triassic Otter Bank Formation fluvial sandstones on the flank of the East Solan Basin is sealed by supra-unconformity Upper Jurassic Kimmeridge Clay Formation mudstones (Herries et al. 1999). Triassic to Lower Jurassic plays, principally oil province play groups, are estimated to contain around 9% of the undiscovered resources of the UKCS (Table 1).

IMPORTANCE OF STRATIGRAPHIC PLAYS,UKCS Middle Jurassic

The most important pre-rift play group in the UKCS existing fields and discoveries database is the Middle Jurassic. It comprises shallow marine to deltaic sandstone plays, including the worldclass Brent play of the East Shetland Basin (Fig. 1), and makes up 23.5% of the known resources on the UKCS (Table 1). Structural traps predominate in the form of large rotated fault blocks generated during Late Jurassic rifting. Locally, substantial erosion of footwall crests has produced combination traps where the truncated reservoir sandstones are sealed by supra-unconformity Cretaceous mudstones (e.g. Beryl Field; Karasek et al. 2003). Complex crestal slumping and fault scarp degradation commonly occur in the East Shetland Basin (Fig. 1; e.g. Brent Field; McLeod & Underhill 1999), and such structural zones have the potential to add significant volumes to existing field reserves. The Middle Jurassic play group is mature, as illustrated by its discovery curve (Fig. 5e), and it is estimated that only around 3 % of the undiscovered resources of the UKCS are hosted in Middle Jurassic reservoirs (Table 1). Remaining stratigraphic potential is likely to be almost entirely within untested erosional truncation traps.

Syn-rifl stratigraphic potential Upper Jurassic syn-rift reservoirs include both shallow-marine sandstones and deep-water mass-flow deposits, and these hold almost 20% of the UKCS known resources (Table 1). Discoveries in shallow-marine sandstones such as the Piper and Fulmar Formations are mostly located in structural traps (e.g. Piper and Fulmar fields; Schmitt & Gordon 1991; Kuhn et al. 2003), and there is only limited potential for further stratigraphic discoveries in syn-rift shallow-marine reservoirs. Along the western margin of the Central Graben, shallow-water sandstones of the Fulmar Formation have a limited distribution within shallow-marine embayments formed above dissolving Upper Permian (Zechstein) salt diapirs (Stewart & Clark 1999). Applying this Kittiwake Field play concept, a number of undrilled combination structural/stratigraphic traps have been identified on the West Central Shelf (DTI 2004b, prospects 20/30, 21/22A-D & 28/2). The geometry and lateral distribution of Upper Jurassic syn-rift deep-water mass-flow deposits are highly conducive to full or partial stratigraphic entrapment, since they are interbedded with mudstones of the Kimmeridge

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Clay Formation, an excellent seal, and a worldclass source rock that has generated much of the oil in the North Sea. Of the existing fields and discoveries with syn-rift reservoirs, 24% are located in stratigraphic and combination traps (Fig. 4). Taking into account only deep-water syn-rift reservoirs, the proportion of fields and discoveries in both stratigraphic and combination traps is 48 %. Discovery curve data indicate that the Upper Jurassic deep-water play is not yet mature (Fig. 7). Despite the profile flattening during the 1990's, discoveries made in the last three years, including the giant Buzzard Field in 2001, show a rejuvenation of the play. Most of the syn-rift deep-water sandstone combination traps were initially drilled as structural traps (e.g. South Brae; Fletcher 2003), but subsequently proved to be larger than pre-drill prognosis, due to closure enhancement by an element of stratigraphic pinchout. The Braetrend fields in the South Viking Graben illustrate the considerable success of the hanging wall combination trap type, but remaining untested traps of this type are unlikely to have a significant structural component and will therefore be more difficult to identify. Many of the Upper Jurassic deep-water sandstone reservoirs that occur within entirely stratigraphic pinchout traps are located above the flanks of an underlying structural trap, and were discovered through serendipity (e.g. Hot Lens reservoirs at Tartan and Highlander fields; Coward et al. 1991; Whitehead & Pinnock 1991). At those fields, the Hot Lens sands were preferentially deposited within and thicken into topographic lows, which developed in response to fault block rotation in the initial stages of the rift phase. Encasing mudstones of the Kimmeridge Clay Formation provide the seal to the trap. Traps formed by a combination of dip closure and stratigraphic pinchout may occur in both intra-basin and basin-margin settings. Typically, such traps are subtle and may not be directly recognized on seismic data, thus requiring the development of a robust conceptual model. On the southern margin of the Moray Firth rift basins (Fig. 1), the giant Buzzard Field represents the first major discovery in a basin-margin pinchout play (Dor6 & Robbins 2005). With estimated in-place resources of 800-1100 MMBO, Buzzard is the largest oil discovery to be made in the North Sea since 1984, and its size clearly establishes that those more subtle, complex traps remaining to be found are not necessarily smaller than existing structural traps.

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Fig. 7. (a) Discovery curve and discovery history histogram for UKCS syn-rift plays (Upper Jurassic). (b) Discovery curve and discovery history histogram for Upper Jurassic deep-water plays. Note different vertical scale. (c) Example of an Upper Jurassic deep-water sandstone stratigraphic pinchout trap with amplitude anomaly (seismic data courtesy of Fugro Multi Client Services). (d) Location of Upper Jurassic lead.

Recognition of wedging units, mounded intervals and amplitude anomalies within the basinal syn-rift sequence may lead to the identification of a prospect. An example of an undrilled intrabasinal prospect in the Smith Bank Graben (Moray Firth) is illustrated in Figure 7c, and comprises up-dip pinchout of an intraKimmeridgian wedging unit that is highlighted by the presence of a discrete amplitude anomaly (DTI 2004b, Prospect 12/23). We estimate that around 30% of the UKCS undiscovered resources are located within syn-rift plays, predominantly in deep-water sandstone reservoirs (Table 1).

Post-rift stratigraphic potential UKCS fields and discoveries within post-rift reservoirs contain the largest proportion of stratigraphic and combination traps (51% overall). The greatest ratio of stratigraphic and

combination to structural traps is recorded from the reservoirs of Early Cretaceous age (Fig. 4). Lower Cretaceous

Approximately 3.5% of the UKCS known resources are located within Lower Cretaceous reservoirs. The discovery curve for this play group shows a major resurgence during 1996-1997 when the Goldeneye and Blake fields were discovered (Fig. 8a). Although a broadly post-rift style basin development was established early in the Cretaceous, deep-water sandstones continued to be deposited in response to local extensional faulting and inversion (Copestake et al. 2003). Seventy-five percent of UKCS Lower Cretaceous fields and discoveries occur in combination or stratigraphic traps (Fig. 4). The chance discovery of the Lower Cretaceous

IMPORTANCE OF STRATIGRAPHIC PLAYS,UKCS

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Fig. 8. Discovery curves and discovery history histograms for selected UKCS post-rift play groups. (a) Lower Cretaceous. (b) Upper Cretaceous. (e) Palaeogene. Note different vertical scales.

Scapa Field within a syncline during appraisal drilling of the underlying Upper Jurassic Claymore Field (McGann et al. 1991) highlights the importance of exploring within synsedimentary lows or synclines. This trap type is not typically targeted in the early phase of exploration in a basin, but becomes more important as the basin matures. Discoveries within the Lower Cretaceous play are so far almost exclusively limited to the Moray Firth area of the Central North Sea (Fig. 1) between Captain Field in the west and Britannia Field in the east. The distribution of Lower Cretaceous sandstones is quite well constrained within the most heavily drilled parts of the Moray Firth, but is poorly defined where wells are sparse, such as along the southern margin of the Moray Firth. Significant undrilled potential on this play exists within the Central Graben to the south (Milton-Worssell et al. 2006; Morgan & Went 2003), the Viking Graben to the north (Oakman 2005), and in the West of Shetland area (DTI 2004b). The Lower Cretaceous depocentres of the Central Graben are largely undrilled, yet offer the potential for significant deep-water sandstone developments (Milton-Worssell et al. 2006). Imaging of Lower Cretaceous sandstones is commonly poor using

conventional seismic data (Law et al. 2000; Garrett et al. 2000). However, recent studies of 3D seismic data acquired with a long-offset (6 km) in the UK Central Graben have shown that anomalous AVO effects can be recognized within channel-like palaeo-lows and within lobate, fan-like bodies, which can be correlated to the possible presence of sandstones (Morgan et al. 2002; Morgan & Went 2003). In the West of Shetland area, Lower Cretaceous marginal to shallow-marine sandstones contain gas in the undeveloped Victory Field within a fault-controlled structural trap (Goodchild et al. 1999). Stratigraphic trap potential has been identified to the SW in the East Solan Basin (DTI 2004b). For example, an isopach map of a basal unit mapped on seismic data within the Lower Cretaceous has a lobate form, with a clear channel-like thick extending off the Otter Bank Fault on the eastern margin of the basin (Fig. 9a). It is interpreted as a basin-floor fan unit, and it contains internal units which onlap the western margin of the East Solan Basin (Fig. 9b). Due to the significant untapped potential of its deep-water sandstone plays in the Central Graben, Viking Graben and West of Shetland, Lower Cretaceous plays are estimated to

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Fig. 9. Stratigraphic prospect within Lower Cretaceous deep-water sandstone play, East Solan Basin (after DTI 2004b). (a) Isopach map of deep-water fan unit showing fan geometry. (b) Seismic section across the prospect. contain 12% of the U K C S undiscovered resources (Table 1), much of which are likely to be at least partially stratigraphically trapped.

Upper Cretaceous A p p r o x i m a t e l y 1% of the UKCS known resources are hosted within the Upper Cretaceous Chalk, but its reservoirs are estimated to contain perhaps 5% of the UKCS undiscovered

resources (Table 1). The stepped appearance of the Upper Cretaceous discovery curve (Fig. 8b) is suggestive of play immaturity. Until recently, all of the UKCS Upper Cretaceous Chalk fields were believed to be structural traps (Johnson & Fisher 1998). Twenty-five percent of UKCS Upper Cretaceous Chalk fields are now known to have an element of non-structural trapping (Fig. 4). Dipping oil-water contacts due to postcharge tilting indicate partial stratigraphic

IMPORTANCE OF STRATIGRAPHIC PLAYS, UKCS entrapment in the Chalk at the Joanne, Fife and Flora fields (Megson & Hardman 2001). Traps of this type are formed by a combination of post-emplacement structuration and either very low lateral permeability preventing remigration, or hydrodynamic controls. The Danish Halfdan Field is an unusual stratigraphic trap, designated a migration trap by Megson & Hardman (2001), where the body of oil in the Chalk reservoir is part way along its migration pathway. Recognition of subtle, non-structural traps within the Upper Cretaceous requires the determination of migration entry points into the Chalk, estimation of maximum possible migration distance within the Chalk from the entry points, and preparation of palaeostructure maps relating to time(s) of oil emplacement (Megson & Hardman 2001). It also requires a thorough understanding of overpressure and hydrodynamics within the Chalk (Caillet et al. 1997). There has been little exploration on this play in recent years, with the notable exception of Maersk's drilling on the Harrier Shallow Chalk prospect in block 30/6 (Platts 2004). Our improved understanding of the unusual trapping mechanisms that are possible in the Chalk play offers hope for future exploration opportunities. Palaeogene

Almost a quarter of the known resources of the UKCS are located within Palaeogene reservoirs (Table 1). Despite the maturing profile of their discovery curve (Fig. 8c), we estimate that a similar proportion of the UKCS undiscovered resources is likely to be contained within Palaeogene plays (Table 1). The Brenda, Brenda West and Brenda East oil discoveries made since 2002 within Palaeogene stratigraphic traps are a testament to the continuing success of this play group. The majority of Palaeogene reservoirs are deep-water sandstones whose geometry and lateral distribution is predisposed towards stratigraphic entrapment. Hence, half of all UKCS Palaeogene hydrocarbon discoveries occur in traps with full or partial stratigraphic entrapment (Fig. 4). For example, pinchout traps can occur where Palaeogene sandstones onlap onto the flanks of basin margin or intrabasinal highs (e.g. Everest Field; O'Connor & Walker 1993). Palaeogeomorphic traps are commonly developed within both the deep-water and fluvio-deltaic Palaeogene facies. In these, detached lobes of mass-flow sandstones may exhibit four-way dip closure resulting from a combination of primary sedimentary mounding and subsequent differential post-

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depositional compaction of the encasing mudstones (e.g. Frigg Field; Brewster 1991). Other stratigraphic traps in basin-marginal late Palaeocene-early Eocene deltaic deposits include incised valley fill mounds with compactional drape, sometimes enhanced by delta-top palaeo-relief (Underhill 2001). Sophisticated seismic techniques appear to work well on Palaeogene reservoirs in the UK North Sea. For example, the trapping mechanism and geometry of the Alba Field, a stratigraphic trap of Eocene age found by serendipity during drilling to a deeper objective, has been elucidated by the use of 3D shearwave volume processing of data collected using sea bottom seismic cables (Jones et al. 2003). The Arbroath and Montrose fields in the UK Central Graben are both simple, four-way dip closures of Palaeocene reservoirs. Seismic attribute analysis has revealed that the main Forties Sandstone reservoir in both these fields is highly channelized, and AVO techniques have been used successfully to determine the distribution of oil versus water (Ahmadi et al. 2003). However, in the West of Shetland area (Fig. 1), the use of AVO as a hydrocarbon predictor in Palaeogene plays has been less successful (Loizou et al. 2006). Thirty-nine wells West of Shetland drilled Palaeocene targets with an amplitude or AVO anomaly and of these, 30 wells failed to find significant hydrocarbons. For instance, to the NW of the Foinaven Field, the Assynt prospect was proved dry by well 204/18-1. This prospect had been mapped on the basis of a strong AVO response, interpreted by the well operators to mark the presence of oil within a Palaeocene stratigraphic trap. The Assynt prospect contained neither an up-dip stratigraphic seal nor fault seals to create a robust trap. The reason for the AVO response at many failed prospects is poorly understood, but many may be related to changes in lithology (Loizou et al. 2006). There is clearly a need to define future West of Shetland prospects on the basis of a sound geological model and careful structural mapping, in addition to support from geophysical techniques. In the North Sea Eocene deep-water sandstone play, almost all of the fields and discoveries occur in stratigraphic or combination traps. Mounded geometries are common within palaeogeomorphic traps. For instance, the Frigg and Guillemot fields are characterized by palaeogeomorphic four-way dip closure (Brewster 1991; Jones et al. 2003). Where no four-way dip closure occurs, other mounded sandstones may require isopach mapping in order to delineate potential prospects, for

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Fig. 10. Stratigraphic prospect within the Eocene deep-water sandstone play, Central North Sea (after DTI 2003). The lead is defined by a mounded thick of channel and fan lobe sandstones within the Tay Formation.

example, a Tay Formation prospect located in the UK Central North Sea (Fig. 10). This prospect requires up-dip stratigraphic pinchout within its feeder channel. Remobilized, or injected, channel sands constitute a locally important Eocene deep-water sandstone play that was first realized at the discovery of the Alba Field during appraisal drilling on the underlying Britannia Field (Jones et al. 2003). The Alba reservoir proved difficult to resolve on conventional seismic data, but was clearly distinguished using multicomponent pressure and shear-wave seismic data acquired through sea-bottom seismic cables (Jones et al. 2003). Amplitude extraction maps have proved a valuable aid to play delineation across the Tay fan play in the Central North Sea (Jones et al. 2003, p. 275, fig. 15.10). Such sophisticated techniques are likely to be required for future exploration of this sand injectite play. In the West of Shetland area (Fig. 1), the Eocene deep-water sandstone fairway covers a substantial area, but it is only lightly explored. High amplitudes on seismic data, mounded topography, and considerable internal complex-

ity characterize the Eocene fans in this fairway (Munns et al. 2005, fig. 16). Although critical exploration of this play will concentrate on the large undrilled four-way dip closures, stratigraphic trapping potential is high. Intruded sand bodies of probable Eocene age have been identified from 'V-bright' anomalies on seismic data in the West of Shetland area, where they are thought to have acted as conduits for upward migration of gas, oil or formation water that triggered mud diapirism within the Pliocene to Recent section (Johnson et al. 2004). Similar sand injectites occurring elsewhere in the West of Shetland area may offer significant stratigraphic trap potential.

Summary Eighty-one percent of existing UKCS fields and discoveries are located within structural traps, 6% occur within purely stratigraphic traps, and 12% lie within combination structural/stratigraphic traps. The majority of discoveries in stratigraphic and combination traps occur in association with

IMPORTANCE OF STRATIGRAPHIC PLAYS, UKCS syn-rift (Upper Jurassic) and post-rift plays. Proportions of stratigraphic and combination traps within pre-rift, syn-rift and post-rift plays average 3%, 24% and 51% respectively. Lower Cretaceous fields and discoveries, almost exclusively in deep-water sandstone plays, demonstrate the highest proportion of stratigraphic entrapment of all, with 75% located within stratigraphic and combination traps. This is closely followed by Palaeogene deep-water plays at 50%, and Upper Jurassic deep-water plays at 48% of such traps. The discovery curve for the entire UKCS has a maturing signature. However, discovery curves for individual play groups suggest significant remaining potential, especially in the Carboniferous, Lower Permian, Upper Jurassic, Lower Cretaceous, Upper Cretaceous and Palaeogene plays. Exploration success expressed as a percentage of discoveries per exploration well is 31.1% for the period 1965 to 2003. Despite low levels of exploration, recent years have yielded even higher success levels, with an all time high in 1999 of 56.3%, and an average for 1999-2003 of 45.4%. This is a testament to more focused exploration through increased use of sophisticated technologies and more rigorous prospect risking, and it gives grounds for optimism that there will be many exploration successes in future years. Plotting the UKCS discovered data on a size distribution chart shows that the structural traps give rise to a rather mature, lognormal-type distribution, whereas the stratigraphic and combination traps describe a more irregular distribution that is indicative of significant undiscovered resources potential. Many of the major discoveries in stratigraphic traps were found by chance during drilling of deeper structural targets, since there has been relatively little direct exploration for stratigraphic plays to date. However, exploration on the UKCS has moved into a new era of primarily searching for high risk, high yield subtle stratigraphic plays within both stratigraphic and combination traps. Deep-water sandstone stratigraphic plays within the syn- and post-rift sequences offer the greatest potential for substantial new resources. Of the forecast 4.1 to 21.3 BBOE technically recoverable UKCS yetto-find (DTI 2004a), we estimate that at least 50% is located within stratigraphic traps: Approximately 5% of undiscovered resources are anticipated to be located within stratigraphically-trapped pre-rift reservoirs, primarily Carboniferous and Lower Permian in age.

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A further 17% is estimated to lie within syn-rift stratigraphic traps in Upper Jurassic deep-water plays. The largest proportion (33%) of undiscovered resources are believed to be hosted within stratigraphically-trapped post-rift reservoirs, predominantly in Palaeogene and Lower Cretaceous deep-water reservoirs. Successful exploration for such targets will rely on well-grounded conceptual models for reservoir and seal distribution enabling robust prediction of trap configuration, and wellconstrained use of data and techniques such as long offset seismic data acquisition and AVO analysis where appropriate to map trap geometry and determine optimum drilling locations. This paper is published with the permission of the Executive Director, British Geological Survey (NERC), and the Director of Licensing and Consents Unit, Department of Trade and Industry. The authors are grateful to an anonymous referee for useful comments.

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Proceedings o f the 5 th Conference, Geological Society, London, 179-200. STOKER, S.J., GRAY,J.C. & HAILE, P. 2004. Estimation o f UKCS undiscovered resources: prospect mapping vs. statistical assessment, http://www. og.dti.gov.uk/Ukpromote/presentations.htm TAYLOR,J.C.M. 1998. Upper Permian - Zechstein. In: GLENNIE, K.W. (ed.) Petroleum Geology o f the North Sea: basic concepts and recent advances. 4th edn, Blackwell Science Ltd, Oxford, 174-211. TREWlN, 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, 485-498. UNDERHILL, J.R. 2001. Controls on the genesis and prospectivity of Palaeogene palaeogeomorphic traps, East Shetland Platform, UK North Sea. Marine and Petroleum Geology, 18, 259-281. UNITED STATES GEOLOGICAL SURVEY. 1995. A new approach to estimating hydrocarbon resources. U.S. Geological Survey Energy Resource Surveys Program Fact Sheet, January 1995. http://www.energy.usgs.gov/factsheets/HydroRes/ estimat.html. WHITEHEAD,M. & PINNOCK,S.J. 1991. The Highlander Field, Block 14/20b, UK North Sea. In" ABBOTrS, I.L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume, Geological Society, London, Memoirs, 14, 323-329.

Lower Cretaceous deep-water sandstone plays in the UK Central Graben R. J. M I L T O N - W O R S S E L L 1, S. J. S T O K E R 2 & J. E. C A V I L L 3

1Department of Trade and Industry, Energy Resources and Development Unit, 1 Victoria Street, London S W 1 H OET, UK (e-mail: [email protected]) 2British Geological Survey, Gilmerton Core Store, 376 Gilmerton Road, Edinburgh EH17 7QS, UK 3British Geological Survey, Murchison House, West Mains Road, Edinburgh EH9 3LA, UK Abstract: Up to the present, exploration of the UK Lower Cretaceous deep-water sandstone play has been confined largely to the Moray Firth basins. The Lower Cretaceous of the Central Graben area has been modelled previously as predominantly shale-prone, and hence unattractive to exploration. There is a growing realization that this may not be the case. Since seismic imaging of Lower Cretaceous sandstones is known to be poor whether hydrocarbon-bearing or water-wet, a robust depositional model must be constructed from well and regional geological data in order to predict sandstone distribution and geometry, and hence to aid identification of potential hydrocarbon traps. Of the hundreds of wells drilled in the Central Graben area that targeted deeper Jurassic-Triassic reservoirs, virtually all have been located on the flanks of the graben, or on intra-graben highs. However, 71 of these wells have proved sandstones or traces of sandstone within the Lower Cretaceous, giving grounds for optimism that more substantial deep-water sandstone developments may be present within the graben depocentres. Twenty-six leads have been identified within these depocentres; most of these are located within stratigraphic traps in interpreted detached basin floor fans. This paper aims to highlight the exploration potential of Lower Cretaceous deep-water sandstones within the UK Central Graben, to the SE of the established Lower Cretaceous fairways. In order to achieve this objective we (1) i n t e r p r e t e d conventional 3D seismic surveys, with 3-6 km offsets, covering an area of 22 135 km 2 (Fig. 1) to provide a regional framework for the study. (2) This was combined with a review and reevaluation of the Lower Cretaceous sections in all exploration and appraisal wells (plus some development wells) within UK Quadrants 21-23 and 28-31. (3) These data were then appraised in the context of the palaeogeographic development of the UK Central Graben and used as a basis for the prediction of potential leads. Currently, Lower Cretaceous fields and discoveries of the United Kingdom Continental Shelf (UKCS) are almost exclusively limited to deep-water sandstone reservoirs in the Moray Firth area of the UK Central North Sea (Fig. 1). By 2004, 22 fields and significant discoveries had been made in the Moray Firth area, extending from the Captain Field in the west to the

Britannia Field in the east (Fig. 1). Some of the most important Lower Cretaceous fields were discovered t h r o u g h serendipity (e.g. Scapa, Britannia and Highlander) whilst drilling for deeper Jurassic targets. The Scapa Field is located within a syncline (McGann et aL 1991), and as such it underlines the importance of exploring within s y n - s e d i m e n t a r y lows or synclines. Seventy-five percent of Lower Cretaceous fields and discoveries on the UKCS are located within purely stratigraphic or combination structural/stratigraphic traps, and this sets a clear benchmark for the trap types we can anticipate for future exploration. Imaging of Lower Cretaceous sandstones is known to be generally poor using conventional seismic data (Law et aL 2000; Garrett et al. 2000), except in the Inner Moray Firth area (Fig. 1) where Upper Cretaceous Chalk and Tertiary sediments are absent (Argent et al. 2000). Therefore, across much of the Lower Cretaceous fairway, a sound depositional model must be constructed from well data and basin analysis in order to predict sandstone distribution, and hence to aid identification of potential stratigraphic traps. Recent studies of 3D seismic data with a long-offset (6 km) in the UK Central Graben have shown that anomalous amplitudeversus-offset (AVO) effects can be recognized

From: ALLEN,M. R., GOFFEY,G. E, MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254,169-186. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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Fig. 1. Late Jurassic-Early Cretaceous structural framework of the UK central North Sea, location of Lower Cretaceous fields and discoveries, and extent of seismic dataset used (SVG -- South Viking Graben, NBG = North Buchan Graben, FB = Fisher Bank Basin, JH = Jaeren High, FMH -- Forties-Montrose High, ECG = East Central Graben, Jo = Josephine High, WG = Witch Ground Graben, SHB -- South Halibut Basin).

within channel-like palaeo-lows and within lobate, fan-like bodies, which can be correlated to the possible presence of sandstones (Morgan et al. 2002; Morgan & Went 2004).

Established Lower Cretaceous plays The Lower Cretaceous Cromer Knoll Group of the UK Central North Sea contains three principal sandstones: the Wick Sandstone Formation in the Inner Moray Firth (comprising the Punt, Coracle and Captain sandstone members), and both the Scapa Sandstone M e m b e r (Valhall Formation) and the Britannia Sandstone Formation in the Outer Moray Firth (Fig. 2; Johnson & Lott 1993). Additional sandstone members occur in the Outer Moray Firth within the mudstones and carbonates of the Valhall F o r m a t i o n (e.g. Sloop and Yawl Sandstone members). All of these sandstones are deep-

water mass flow deposits whose distribution is relatively well known across the Moray Firth area. They were deposited in response to local Early Cretaceous extensional faulting and inversion, probably under a strike-slip tectonic regime within an overall post-rift setting (Copestake et aL 2003). The Lower Cretaceous plays are divided in this paper into two plays: Latest RyazanianBarremian and Aptian-Albian. The Fischschiefer Bed (Fig. 2) is a regionally developed organic-rich mudstone with phosphatic fish debris (Ainsworth et al. 2000), generally characterized by a higher gamma and sonic response. It is one of the few regionally correlatable marker beds within the Lower Cretaceous (Figs 2 & 3). The Fischschiefer Bed represents a major flooding event during the early Aptian, and this horizon has been used as a proxy for the boundary between the two plays

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Fig. 2. Stratigraphic summary chart of the UK Central North Sea Lower Cretaceous (chronostratigraphy and sequence stratigraphy after Copestake et al. 2003), also showing occurrence of hydrocarbons.

since it is stratigraphically very close to the B a r r e m i a n - A p t i a n boundary. The A p t i a n Albian play was informally referred to as the Kopervik play by Law et al. (2000), but Oakman (2005) employed the term Aptian play. Copestake et al. (2003) defined two proven deepmarine sandstone plays within the U K Lower Cretaceous; K12-K32 sequences (Scapa Sandstone Formation) and K40-K50 sequences (Britannia Sandstone Formation, Captain, Sloop and Skiff sandstone members). In the Norwegian sector, deep-marine sandstones also occur in the K55 sequence (Agat Formation; Copestake et al. 2003, Fig. 12.14). Following the stratigraphic scheme of Copestake et al. (2003), the Latest Ryazanian-Barremian play spans sequences K10-K30, and the Aptian-Albian play includes sequences K40, K45 and K50 (Fig. 2). Biostratigraphic reassessment was carried out for us on a limited number of key wells containing evidence of sandstone developments within the Lower Cretaceous of the Central Graben area; there was not scope within this study for a more comprehensive

biostratigraphic and sequence stratigraphic evaluation. Potentially significant sandstone developments in the UK Central Graben are indicated on Fig. 2, and are based upon trace and minor sandstone occurrences as determined from well data. The distribution of Lower Cretaceous sandstones is quite well constrained within the most heavily drilled parts of the Moray Firth area, but it is poorly constrained where wells are sparse, such as along the southern margin of the Moray Firth and within the largely undrilled depocentres of the Central Graben. Latest Ryazanian-Barremian

play

Deep-marine sandstones of the Latest Ryazanian-Barremian play of the U K Central North Sea comprise the Punt and Coracle members of the Wick Sandstone Formation, and the Scapa Sandstone and Yawl Sandstone members of the Valhall Formation (Fig. 2; Johnson & Lott 1993). These sandstones were deposited in the Inner and Outer Moray Firth

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Fig. 3. Seismic section across the West Central Graben showing the Fischschiefer horizon. Seismic data courtesy of Veritas DGC. basins, derived from the Shetland Platform to the NW, the Scottish Highlands to the west, and locally off the Halibut Horst (Fig. 4). The sandstones were predominantly developed in hanging-wall slope-apron fans; however, incised narrow linear channel complexes have been identified in the Inner Moray Firth, extending from shoreface to basin, as an integral part of a mini-basin fill and spill process (Argent et al. 2000). Localized mass flow sandstones of Late Barremian (to early Aptian) age sourced from the Fladen Ground Spur have been recognized from a small number of Britannia Field wells in blocks 15/30 and 16/26 (Ainsworth et al. 2000). These sandstones have been assigned to the Lapworth Member Unit A of the Britannia Sandstone Formation, and are described by Ainsworth et al. (2000) as lateral equivalents of the Yawl Sandstone Member. However, Copestake et al. (2003) suggested that the Lapworth Member Unit A may be entirely Early Aptian in age, and it would therefore belong to the Aptian-Albian play. Lower Cretaceous shallow-water shelf sandstones were found in Quadrant 29 south on the West Central Platform through exploration drilling between 1967-1976; these sandstones were formally designated the Devil's Hole Sandstone Member by Johnson & Lott (1993) (Fig. 4). Throughout the Latest RyazanianBarremian time period, the palaeo-coastline

was receding across the West Central Platform to an approximate position close to the present day coastline (Fig. 4). This was effectively a continuation of the Late Jurassic Fulmar transgression, and this scenario suggests that there is potential for localized development of shallow marine sandstones across the entire West Central Platform. A significant development of latest Ryazanian to Early Valanginian (K12 sequence) deep marine sandstones was recognized in Quadrant 30 by Copestake et al. (2003) directly to the NE of the Devil's Hole shallow marine sandstones within the Central Graben, but separated from them by the Auk High (Fig. 4). Interestingly, Copestake et al. (2003) also hinted at other possible latest Ryazanian to Early Valanginian (K12 sequence) sandstone bodies in the Central Graben, and indicated the potential for local derivation of sandstones from the FortiesMontrose High (Fig. 4). Aptian-Albian

play

The Captain Sandstone Member of the Wick Sandstone Formation and the Britannia Sandstone Formation are the principal reservoirs of the A p t i a n - A l b i a n play of the UK Central North Sea (Fig. 2). The Sloop Sandstone Member of the Valhall Formation provides a localized additional reservoir at the Saltire Field

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Fig. 4. Distribution of sandstones and hydrocarbon fields within the Latest Ryazanian-Barremian play of the UK Central North Sea (modified after Copestake et al. 2003) (HH = Halibut Horst, FGS = Fladen Ground Spur, FMH = Forties-Montrose High, AH = Auk High, WCG = West Central Graben, ECG = East Central Graben). in block 15/17 (Fig. 2; Johnson & Lott 1993; Casey & Romani 1992). The basal unit (Lapworth Member Unit A) of the Britannia Sandstone Formation sits beneath the Fischschiefer Bed (Fig. 2) and was determined to be Late Barremian-Early Aptian in age by Ainsworth et al. (2000). However, Copestake et al. (2003) argued that an Early Aptian age is more likely on the basis that the sandstones are sharp-based and appear to be erosive, and Barremian palynomorphs only occur beneath the Lapworth Member Unit A in the reference well. These are the only proven sandstones within the Aptian-Albian play that lie beneath the Fischschiefer Bed, our proxy horizon on seismic data for the boundary between the

Latest Ryazanian-Barremian and A p t i a n Albian plays. The A p t i a n - A l b i a n palaeogeography is broadly similar to the Latest RyazanianBarremian, with major sediment input from the Shetland Platform to the NW (Fig. 5). In addition to slope-apron type filling of the proximal depocentres, a long distance transport route developed through a narrow channel belt from the Captain Field area, extending south of the Halibut Horst, and into the South Buchan Basin. The Britannia Sandstone Formation is a complex series of overlapping slope-apron fans that result from multiple sediment entry points into the Witch Ground and Fisher Bank basins from the Fladen Ground Spur source area to the

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Fig. 5. Distribution of sandstones and hydrocarbon fields within the Aptian-Albian play of the UK Central North Sea as identified in 2003 (after Copestake et al. 2003) and by Oakman (2005) (HH = Halibut Horst, FGS = Fladen Ground Spur, FMH = Forties-Montrose High, AH = Auk High, SBB = South Buchan Basin, FBB = Fisher Bank Basin, WGG = Witch Ground Graben, WCG = West Central Graben, ECG = East Central Graben. north and from additional clastic input from the SW (Copestake et aL 2003). O a k m a n (2005) suggests that the A p t i a n Albian sandstone play is more areally extensive than mapped by Copestake et al. (2003). In particular, O a k m a n (2005) interprets the presence of linear sandstone bodies that track northeastwards across Quadrants 19 and 20 and merge with the sandstones derived from the N W along the northern boundary of Quadrant 20, and in the north of Quadrant 21 (Fig. 5; see fig. 10 of O a k m a n 2005), suggesting a sediment input from an additional southwesterly source. In the n o r t h e a s t e r n part of Q u a d r a n t 29, south of the established A p t i a n - A l b i a n play, one small body of deep marine sandstones has

been recognized within the Early A p t i a n - E a r l y A l b i a n (K40-K50) depositional sequence in Central Graben (Copestake et aL 2003; Fig. 5).

Lower Cretaceous sandstones in the U K Central Graben All exploration and appraisal wells in the U K Central Graben study area were reviewed and assessed with respect to the presence or absence of Lower Cretaceous sediments, in particular sandstones in the present study. A total of 663 released wells (as of end 2003) p e n e t r a t e d Lower Cretaceous or older strata, of which 504 were found to have drilled Lower Cretaceous

LOWER CRETACEOUS DEEP-WATER SANDSTONE PLAYS beds and 159 proved Lower Cretaceous beds to be absent (Fig. 6). A further 400 released Central Graben area wells reached total depth (TD) above the Lower Cretaceous section. Ninety-eight wells found traces or significant developments of sandstones within the Lower Cretaceous (Fig. 6). Seventy-one of these wells are located outside the established A p t i a n Albian and Latest R y a z a n i a n - B a r r e m i a n plays, that is, in an area previously deemed to be almost entirely mud-prone, and six of these record gas or oil shows (Fig. 6; Table 1). Comparison of the isochron map of the Lower Cretaceous, derived from seismic interpretation,

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with the distribution of Lower Cretaceous well penetrations shows that only two of the 504 wells to have drilled the Lower Cretaceous were located within a depocentre. In the north of the study area, well 21/lb-17 was drilled close to the axis of the South Buchan Basin, a narrow halfgraben to the south of the Buchan Ridge (Figs 6 & 1), and proved 1217 m (3993 ft) of Lower Cretaceous mudstones. In the West Central Graben, well 29/lc-4 recorded the thickest Lower Cretaceous well penetration in the U K Central North Sea of 1940 m (6366 ft). Both of these wells are, however, marine m u d s t o n e dominated with no traces of sandstone, and they

Fig. 6. Lower Cretaceous well penetrations in the UK Central Graben area, also showing the isochron of the Lower Cretaceous interval. Note that the zero limit of the isochron is the limit of seismic resolution of the Lower Cretaceous, not the absolute limit of the Lower Cretaceous.

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Table 1. Hydrocarbon shows within Lower Cretaceous sandstones of the UK Central Graben area, i.e. outside the established Lower Cretaceous fairways

Well 21/6-1 21/15a-2 21/15a-6 21/20a-1 22/11-4 29/2b-5

Details of shows Oil show within Late Ryazanian (trace sandstone) Gas shows within Aptian sandstone (10 m/32 ft gross) at the top of the Lower Cretaceous interval (Fig. 8) Oil and gas shows within ?Late Ryazanian-Valanginian (5.5 m/18 ft gross, 7 thin beds) Gas shows within probable Aptian sandstone (5.2 m/17 ft gross, thin beds) Gas shows within Aptian (1.5 m/5 ft sandstone) Gas shows within Aptian thin beds (2.4 m/8 ft gross)

clearly demonstrate that Lower Cretaceous deep-marine sandstones are necessarily likely to be developed in all of the major depocentres in the study area. Interestingly, three wells drilled on the Auk High (Figs 5 & 6) found Lower Cretaceous basalt conglomerates, and a number of wells within the Central Graben recorded tufts within the Lower Cretaceous. Tufts have been recorded in the condensed claystones marking the bases of sequences K45 and K50 in the UK and Norwegian Central North sea (Copestake 2003). These occurrences will be discussed further below. Latest Ryazanian-Barremian

play

A total of 60 wells in the study area of the Central North Sea found sandstone in the Latest Ryazanian-Barremian interval, of which 26 wells have sandstone beds in excess of 3 m (10 ft) thick, and 34 wells have less significant sandstone developments (Fig. 7). Most of these sandstones are in the Central Graben, and are thus likely to be deep-water mass flow deposits; shallow marine sandstones are restricted to patchy occurrences on the West Central Platform (e.g. Devil's Hole Sandstone Member, Fig. 4). Substantial thicknesses of Latest RyazanianBarremian deep-marine sandstones have yet to be proved in the UK Central Graben area. Most of the recorded minor sandstone developments occur predominantly within a basal unit of Late Ryazanian-Valanginian age, and are therefore likely to belong to the K12-K14 sequences of Copestake et aL (2003). They comprise beds up to 10 m thick, e.g. well 22/19a-3 (Fig. 8), but are commonly less than 3 m thick, e.g. 30/11b-1 (Fig. 8). Such minor sandstone occurrences are quite widely distributed across the Central Graben area. Hydrocarbon shows are recorded from two wells containing Late Ryazanian-Barremian

sandstones (Table 1); in 21/6-1 located within the South Buchan Basin, and in 21/15a-6 located within the West Central Graben immediately to the west of the Forties-Montrose High (Fig. 6). All other occurrences of Late RyazanianBarremian sandstones in the Central Graben area are water wet. A basalt flow found on the Auk High during appraisal drilling of the Auk Field has been dated as Hauterivian (Trewin & Bramwel11991; Trewin et al. 2003; Fig. 7); erosion of these basalts yielded Lower Cretaceous conglomerates (discussed below). Tufts occur within Lower Cretaceous mudstones in some wells in the Central North Sea e.g. 22/5-1A (Hauterivian) and 21/10-7 (age uncertain), and these may be related to the igneous activity on the Auk High. Onshore UK, Barremian age tufts are found in the Speeton Clay, and are thought to be derived from a buried source in the Southern North Sea (Knox & Fletcher 1978). Sandstones within the Lower Cretaceous cannot be imaged directly with conventional seismic data due to the low acoustic impedance contrast between the sandstones and overlying shales (Garrett et al. 2000; Law et al. 2000). However, possible sandstone bodies in the Latest Ryazanian-Barremian play can be postulated through geological modelling, utilizing the isochron map for the base Cretaceous to Fischschiefer interval in combination with well data, and assessment of basin margin and intrabasinal sediment source areas (Fig. 7). The areas of deep-water mass-flow sandstones postulated within the UK Central Graben and illustrated in Fig. 7 are highly speculative, and require fuller investigation with more advanced seismic techniques. The eastern margin of the West Central Shelf was emergent at the Auk High during at least part of the Late Ryazanian-Barremian, and along strike as far as Quadrant 28 north, and Quadrant 30 south (Fig. 7), forming a potentially substantial sediment source area complicated by

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Fig. 7. Well penetrations of sandstone and postulated sandstone developments within the Latest Ryazanian-Barremian, also showing isochron maps of the near equivalent seismic interval base Cretaceous to Fischschiefer. Note that the zero limit of the isochron is the limit of seismic resolution of the interval, not its absolute limit. (JH -- Jaeren High, FMH = Forties-Montrose High, Jo = Josephine High, AH -- Auk High, SBB = South Buchan Basin, FBB = Fisher Bank Basin, MT = Marnock Terrace).

the eruption of basalts locally on the high during the Hauterivian (Trewin & Bramwell 1991; Trewin et al. 2003). The Forties-Montrose and Josephine highs may have been emergent also, along with parts of the Jaeren High (Fig. 7). In addition, a smaller intra-basin high located in the

southwestern part of Quadrant 22 is interpreted to have b e e n emergent, and to have b e e n a potential clastic sediment source. During Latest R y a z a n i a n - B a r r e m i a n times, the palaeocoastline r e c e d e d westwards approximately 100 k m across the West Central Shelf (Fig. 4).

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Fig. 8. Selected well penetrations of Lower Cretaceous sandstones in the UK Central Graben. See Figures 7 & 10 for location of wells.

Coarse clastics derived from the UK landmass, or from the shelf itself, may have been deposited as shallow-marine sandstones (Figs 4 & 7), or may possibly have fed northeastwards across Quadrants 20 and 21 into the South Buchan Basin or West Central Graben. The Latest Ryazanian to Barremian basins of the Central Graben are largely separated from those of the Outer Moray Firth to the north by E - W to SW-NE trending highs across Quadrants 21 and 22 (Figs 7 & 9) which may have formed barriers to clastic sediment input. The Marnock Terrace, which forms a SW-NE trending structural high connecting the FortiesMontrose High to the Jaeren High, separates the East Central Graben to the south from the Fisher Bank Basin to the north (Fig. 9, Line A). Very thin (sub-seismic resolution) developments of poorly dated Lower Cretaceous beds have been proved locally by wells on this high. The western arm of the Forties-Montrose High forms an E - W trending structural high that partially separates the West Central Graben to the south from the South Buchan Basin to the north (Fig. 7; Fig. 9, Line B). This high may have formed an almost complete barrier during the Latest Ryazanian-Barremian. Thus, Latest Ryazanian-Barremian mass-flow sediments within the Central Graben are likely to be entirely separate from those proven within the Outer Moray Firth area.

A p t i a n - A l b i a n play A total of 48 wells in the UK Central Graben study area found sandstones in the AptianAlbian interval, 23 of which are located in the north within the established A p t i a n - A l b i a n play. Of the remaining 25 wells outside the proven play fairway, 9 contain sandstone beds in excess of 3 m thick, 13 contain less significant sandstone developments, and 3 found conglomerates with basalt clasts on the Auk High (Fig. 10) that Trewin & Bramwell (1991) and Trewin et al. (2003) have determined to be of Aptian-Albian age. These conglomerates are interpreted to have been derived from a Hauterivian basalt flow of localized extent on the Auk High (Trewin & Bramwel11991; Trewin et al. 2003). There are fewer well penetrations to date of Aptian-Albian deep marine sandstones than of the older Lower Cretaceous sandstones in the Central Graben; however, those Aptian-Albian sandstones found are geographically widely spread across the Central Graben area (Fig. 10). Example sections from wells 21/15a-2 and 29/5a-5 are illustrated in Figure 8. Drilled in 1981, well 21/15a-2 penetrated 10 m gross sandstone of probable Aptian age with gas shows, and the 1985 well 29/5a-5 proved 6 m gross Aptian-Albian sandstone. Seismic imaging of Aptian-Albian sandstones is known to be poor due to the low acoustic impedance contrast between them and the

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Fig. 9. Regional geoseismic lines showing the structural highs separating the Lower Cretaceous of the East Central Graben and West Central Graben from the Fisher Bank and South Buchan basins respectively. Location of lines shown on Figure. 7.

overlying shales; multiples generated from within intra-Upper Cretaceous intervals are also widely problematic (Garrett et al. 2000; Law et al. 2000). Hence, the potential for unidentified sandstone bodies has been assessed through basin analysis, utilising an isochron map for the Fischschiefer to top Lower Cretaceous interval in combination with well data, and evaluation of basin margin and intra-basinal sediment source areas (Fig. 10). The areas postulated for A p t i a n - A l b i a n deep-water mass-flow sandstones within the UK Central Graben as illustrated in Figure 10 are highly speculative, and require comprehensive investigation with more advanced seismic techniques than are available to us. During the Aptian-Albian, only two small areas on the eastern margin of the West Central Platform are likely to have been emergent (Fig. 10) and potentially supplying coarse clastics to the West Central Graben. The FortiesMontrose and Josephine highs are thought to have remained emergent, along with the northwestern part of the Jaeren High (Fig. 10). During Aptian-Albian times, the palaeo-coast-

line receded westwards approximately 50 km across the West Central Platform to a position west of the current coastline (compare Figs 4 & 5). Coarse clastics derived from the U K landmass may have been deposited locally as shallow shelf sandstones on the West Central Platform. Very long transport routes would be required for any such sandstones to have fed across the platform into the West Central Graben. The barrier highs interpreted across Quadrants 21 and 22 (Figs 9 & 10) that separated the Latest R y a z a n i a n - B a r r e m i a n basins of the Central Graben from those of the Outer Moray Firth are likely to have remained significant during A p t i a n - A l b i a n times. The A p t i a n Albian interval is less than 50 ms two-way time thick across the Marnock Terrace barrier in Quadrant 22 (Fig. 10). Although the western arm of the Forties-Montrose High crossing Quadrant 21 may have been completely flooded during A p t i a n - A l b i a n times, it still caused significant thinning of the A p t i a n - A l b i a n section here. The possibility of contiguous Aptian-Albian mass-flow sandstones extending

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Fig. 10.

Well penetrations of sandstone and postulated sandstone developments within the Aptian-Albian, also showing isochron map of the near equivalent seismic interval Fischschiefer to top Lower Cretaceous. Note that the zero limit of the isochron is the limit of seismic resolution of the interval, not its absolute limit. (JH = Jaeren High, FMH = Forties-Montrose High, Jo = Josephine High, A H = Auk High, SBB = South Buchan Basin, FBB = Fisher Bank Basin, MT = Marnock Terrace).

f r o m t h e e s t a b l i s h e d f a i r w a y in t h e O u t e r M o r a y F i r t h (i.e. t h e n o r t h e r n p a r t s of Q u a d r a n t s 21 a n d 22) passing s o u t h w a r d i n t o t h e E a s t C e n t r a l G r a b e n or t h e W e s t C e n t r a l G r a b e n is c o n s i d e r e d to be r e m o t e .

Future exploration opportunities Initial s t u d i e s h a v e i d e n t i f i e d 26 leads f r o m o u r analysis of L o w e r C r e t a c e o u s d e e p - w a t e r sands t o n e d i s t r i b u t i o n in t h e U K C e n t r a l G r a b e n , all

LOWER CRETACEOUS DEEP-WATER SANDSTONE PLAYS of which have a strong stratigraphic component. The mapping was carried out to 'prospect lead' rather than 'drillable prospect' status.

Trapping styles The leads identified fall into three trap types:

(1) hanging wall fans located adjacent to active or residual fault scarps (Latest Ryazanian-Barremian leads only); (2) on-slope, ponded mini-basin fill (Latest Ryazanian-Barremian leads only); and (3) detached basin floor fans (Latest Ryazanian-Barremian and Aptian-Albian leads).

Hanging wall fans. Potential exists for slope to basinal fans to occur within the hanging walls of active or residual Late Jurassic fault scarps within the UK Central Graben. The potential for fan development is greatest where an adjacent high is interpreted to have been emergent and generating source clastics. Two Latest Ryazanian-Barremian leads of this type have been mapped on either side of an intrabasinal high within relatively minor hangingwall basins in the West Central Graben (Fig. 11). Regional tilting up to the west provides the optimum trap configuration of up-dip stratigraphic pinchout, and avoids the potentially problematic issue of lateral seal risk where these postulated Lower Cretaceous sandstones may

181

be in cross-fault contact eastwards with Jurassic to Triassic sandstones of the footwall. Stacked leads within the West Central Graben (Fig. 12), in which postulated sandstones within the Latest Ryazanian-Barremian play are located within hanging wall slopeapron fans. These leads rely upon up-dip stratigraphic pinchout of the postulated reservoir sandstones to the west at the interpreted distal limit of the sandstone bodies. A total of 9 leads have been mapped within hanging wall fan traps, all of which lie within the Latest Ryazanian-Barremian sequence.

On-slope, ponded mini-basin fill. Basin fill and spill processes were recognized by Argent et al. (2000) within the Late Ryazanian-Valanginian Punt Sandstone Member (K10 sequence, Copestake et al. 2003) of the Inner Moray Firth, whereby sand-rich sediments accumulated within the first basin encountered, and only spread to neighbouring basins once the first basin was filled to spill point, from when the feeder channel was able to incise and cross interbasinal highs. Several mini-basins have been identified on the margins of the UK Central Graben, within which the Latest RyazanianBarremian sequence is isolated from the main basin in the graben, but the A p t i a n - A l b i a n sequence continues across the intervening high. The smaller lead on the western side of Figure 13 comprises the ponded fill of a basin-margin mini-basin, and may have bottom and lateral

Fig. 11. Seismic section across the West Central Graben showing hanging wall fan leads within the Latest Ryazanian-Barremian play. Seismic data courtesy of PGS MegaSurveys.

182

R. MILTON-WORSSELL ETAL.

Fig. 12. Seismic section across the West Central Graben showing stacked Latest Ryazanian-Barremian hanging wall fan leads, and an Aptian-Albian detached basin floor fan lead. Seismic data courtesy of PGS MegaSurveys.

seal risk if the pre-Cretaceous section comprises Jurassic or Triassic sandstones. Two Latest Ryazanian-Barremian leads have been recognized within this trap type. Detached basin floor fans. In the established Lower Cretaceous fairway of the Moray Firth basins, detached basin slope to basin floor channel and fan-lobe sands are recognized as the most important play type, especially within the Aptian-Albian play (Oakman 2005). In the UK Central Graben, the majority of the mapped leads (57%) are located within detached basin floor fans, with either full stratigraphic pinchout trapping, or combination stratigraphic pinchout and down-dip closure trapping. Detached basin floor fan traps characterize all 7 of the Aptian-Albian leads recognized in this study. Eight Latest Ryazanian-Barremian detached basin floor fan leads have also been identified. An example of a potential detached basinfloor fan within the Aptian-Albian play is illustrated in Figure 12. This lead relies upon up-dip stratigraphic pinchout of the postulated reservoir sandstones to the west, at the interpreted distal limit of the sandstone body. In contrast, a lead based upon an interpreted detached basinfloor fan sandstone body within the Latest Ryazanian-Barremian play in the East Central Graben is shown in Figure 13. This lead requires

up-dip stratigraphic pinchout at the proximal end of the fan. Reservoir This initial study has reviewed data from 663 wells of which 71 found sandstones or traces of sandstones within the Lower Cretaceous interval in areas outside the established fairways. None of these 71 wells were targeted at the Lower Cretaceous, and they were not drilled at optimum locations for thick deepwater sandstones. The thin sandstone beds and sandstone traces that have been encountered are interpreted to represent distal equivalents of more substantial sand bodies which we interpret within the Lower Cretaceous depocentres. The characteristics of established Lower Cretaceous reservoirs in the Moray Firth area are summarized below. Analogous sandstones are anticipated within the UK Central Graben Lower Cretaceous depocentres. Locally significant heterogeneity has been recorded from some reservoirs within both the Latest Ryazanian-Barremian and A p t i a n Albian plays in the Outer Moray Firth, e.g. Scapa Sandstone Member at Scapa Field (McGann et al. 1991) and Britannia Sandstone Formation at Britannia Field (Jones et al. 1999; Blackbourn & Thomson 2000). Mixed high-density turbidites

LOWER CRETACEOUS DEEP-WATER SANDSTONE PLAYS

183

Fig. 13. Seismic section across the East Central Graben showing on-slope, ponded mini-basin fill and detached basin floor fan leads within the Latest Ryazanian-Barremian play. Seismic data courtesy of PGS MegaSurveys.

and slurry flow sandstones are characterized by porosities of around 15 % and permeabilities of 0.1-500 mD at the Britannia Field, where reservoir depth is between 3600-4000 m (Copestake et al. 2003). The unusual slurry flow sandstone facies of the Britannia Sandstone Formation may be unique to the Britannia Field area, since the sandstones were sourced in part from altered volcanic rocks of the Forties Volcanic Province (Blackbourn & Thomson 2000). Higher porosities and permeabilities (25-30% and 100-1000 mD) have been recorded from Aptian sandstones within the South Halibut Basin (Law et al. 2000; Rose et aL 2000). At the Scapa Field, the Scapa Sandstone Member reservoir (Early Valanginian-Late Hauterivian) has recorded porosities of 16.6-24.4% and an average permeability of 390 mD (maximum 2338 mD), although reservoir depth at Scapa Field is a relatively shallow 2300-2700 m (McGann et aL 1991). Reservoir depth within the mapped leads in the UK Central Graben is in the range 3350-5850 m; the deeper-buried leads fall within the high-pressure-hightemperature (HPHT) overprint. Within the Central Graben H P H T area, excess fluid pressures exert an important additional influence on reservoir properties, such that higher porosities are retained at depth compared to normally pressured reservoirs (Moss et al. 2003). Erosion of localized Hauterivian basalts has

resulted in the deposition of basalt-clast conglomerates on the Auk High. Material derived from these eroded basalts in the West Central Graben may have mixed with sands derived from erosion of Lower Permian Rotliegend sandstones also exposed on the Auk High. Resulting mass-flow deposits here may have poorer reservoir quality than other Lower Cretaceous sandstones due to diagenetic alteration of the volcanic material to clay minerals. Seal and charge

Claystones of the Valhall and Carrack formations are likely to offer good intraformational seals for the Lower Cretaceous deep-water sandstones. Within the established plays, condensed claystones at sequence boundaries can act as seals to underlying reservoirs e.g K34 condensed claystones seal the Scapa Sandstone Member at the Scapa and Claymore fields, and K50/K55 condensed claystones seal underlying Captain Sandstone Member and Britannia Sandstone Formation reservoirs at several fields (Copestake et al. 2003; Fig. 2). An element of seal risk is anticipated where the Lower Cretaceous reservoir sandstones require a bottom seal or lateral fault seal from Jurassic to Triassic beds. Mature Upper Jurassic Kimmeridge Clay Formation source rocks underlie much of the

184

R. MILTON-WORSSELL E T A L .

UK Central Graben. Numerous oil, gas and condensate fields and discoveries within and along the margins of the Central Graben attest to the efficacy of this world-class source rock. The Lower Cretaceous leads identified in this study are all located within major depocentres. They all lie directly above mature Kimmeridge Clay Formation, such that migration routes are likely to be short and direct. Lower Cretaceous mudstones may offer limited additional source rock potential. Copestake et al. (2003) note that Fischschiefer mudstones, although thin (3-15 m), could yield significant volumes of hydrocarbons where thermal maturity has been achieved. Jensen & Buchardt (1987) reported total organic carbon contents of up to 12.7% from the Sola Formation in the Danish North Sea, and noted that the organic matter is oil prone to gas prone, of mixed marine and terrigenous origin. In the MOre Basin, the discovery of oil in the Ellida structure prompted a review of potential oil source rocks in the basin (Riis et al. 2004), and /'~pUdll

tO

~llUllldllldll

i:lllU

~dl

ly

P90-P50-P10). The spread of unrisked resource volumes across the various trap types identified within the Latest R y a z a n i a n - B a r r e m i a n and A p t i a n - A l b i a n plays are detailed below: 9

9

9

9

I Ul Ollldll

mudstones were found to have a high organic content. Well 6204/11-2, located on the margin of the MOre Basin, found units with a TOC of 2% and Hydrogen Index of around 200 within the Aptian to Early Turonian interval. Lower Cretaceous potential source rocks in the Central Graben are likely to be mature for oil generation within the deepest parts of the graben since the top of the underlying Upper Jurassic Kimmeridge Clay Formation is generally late mature for oil generation within the graben axial areas (Kubala et al. 2003). Resource volumes

From the 26 leads that have been identified within the Lower Cretaceous plays in the U K Central Graben, the chance of success estimated for all mapped leads is based on an evaluation of risks associated with both presence and effectiveness of reservoir, source, trap and seal. Risk factors for the Lower Cretaceous leads as a whole are primarily with respect to reservoir presence, but also in terms of trap definition since the predicted sandstone bodies and their geometry cannot be imaged directly on the conventional seismic data available to us. At the end of October 2004, the unrisked recoverable resource volumes for leads within the Lower Cretaceous plays in the UK Central Graben having a chance of success greater than 5 % were calculated by Monte Carlo simulation to be 3.1-6.6-12.3 • 109 barrels of oil equivalent ( B O E ) (Lower, Central and Upper case, or

Seven A p t i a n - A l b i a n leads are recognized within the detached basin floor fan play, and each has been determined to have a chance of success of more than 5%. The total of the unrisked recoverable resource volumes in these 7 leads is 2.5-5.2-9.7 x 109 BOE. Eight leads are seen within Latest Ryazanian-Barremian detached basin floor fan traps, two of which have a chance of success of more than 5 %. The total of the unrisked recoverable resource volumes in these 2 leads is 0.6-1.3-2.3 • 109 BOE. Two Latest R y a z a n i a n - B a r r e m i a n leads are recognized within on-slope, p o n d e d mini basin fill traps, both of which have a chance of success of less than 5 %. Nine Latest R y a z a n i a n - B a r r e m i a n leads are seen w,um, ,,a,,~,,~ win, fan traps; on one falls above the 5% chance of success threshold, and it has unrisked recoverable resource volumes of 0.08-0.17-0.31 • 109 BOE.

Conclusions A regional appraisal of the Lower Cretaceous strata in the UK Central Graben area provides grounds to support the possibility that deepwater sandstones could be important exploration targets in the future. In particular: 9

9

The Lower Cretaceous depocentres of the Central Graben are largely untested. Only 2 of the 504 wells that penetrated the Lower Cretaceous within the study area were located within a Lower Cretaceous depocentre. However, 98 of the wells found traces or significant developments of sandstone within the Lower Cretaceous. Seventy-one of these wells are located within the UK Central Graben area, but outside the established Lower Cretaceous fairways, and 6 of these recorded hydrocarbon shows. Seismic mapping suggests that E - W and S W - N E trending palaeohighs probably largely separated the Central Graben basins from the South Buchan and Fisher Bank basins to the north during the Early Cretaceous. Consequently, the Lower Cretaceous sandstone plays within the Central Graben are likely to have been

LOWER CRETACEOUS DEEP-WATER SANDSTONE PLAYS

*

-

*

*

entirely separate from the established fairways of the Outer Moray Firth. Integration of the regional well data with isochron maps for the pre- and postFischschiefer intervals of the Lower Cretaceous, and evaluation of basin margin and intra-basinal s e d i m e n t source areas has enabled the d e v e l o p m e n t of models for postulated Latest R y a z a n i a n - B a r r e m i a n and A p t i a n - A l b i a n deep-water sandstone distribution in the U K Central G r a b e n area. Predicted sandstone developments in both the Latest R y a z a n i a n - B a r r e m i a n and A p t i a n - A l b i a n plays are p r e d o m i n a n t l y detached slope-apron or basin-floor fans. They are most likely to have been derived from local sediment sources around the margins of the Central Graben. The potential for d e v e l o p m e n t of narrow, linear channel belts such as those identified in the Inner Moray Firth and South Halibut Basin is believed to be low. The potential for stratigraphic entrapment of hydrocarbons within postulated detached deep-water sandstones in the depocentres of the East Central Graben and West Central Graben is high. Example leads are relatively high risk, primarily in terms of reservoir presence, but also in terms of trap definition since the predicted sandstone bodies and their lateral distribution cannot be discerned on seismic data. More extensive evaluation using advanced seismic techniques is required to firm up these and similar leads. Twenty-six leads have been identified in this study. The leads are quite deeply buried (3350-5850 m), and are located within, or on the flanks of, deep graben where effects of overpressure are likely to be seen. At the end of O c t o b e r 2004, the total of the unrisked recoverable resource volumes for leads within the U K Central Graben having a chance of success greater than 5% was estimated to be 3.1-6.6-12.3 • 109 B O E (P90-P50-PlO).

This paper is published with the permission of the Director of Licensing and Consents Unit, Department of Trade and Industry (DTI), and the Executive Director, British Geological Survey (NERC). The views expressed in the paper are the views of the authors, and not necessarily those of the DTI. The authors gratefully acknowledge permission to publish seismic data owned by PGS Geophysical and Veritas DGC. P. Copestake of Merlin Energy Resources Ltd and J. Argent of Paladin Resources plc are thanked for their constructive reviews.

185

References AINSWORTH, N.R., 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. ARGENT,J.D., STEWART,S.A. & UNDERHILL,J.R. 2000. Controls on the Lower Cretaceous Punt Sandstone Member, a massive deep-water clastic deposystem, Inner Moray Firth, UK North Sea. Petroleum Geoscience, 6, 275-285. BLACKBOURN,G.A. & THOMSON,M.E. 2000. Britannia Field, UK North Sea: petrographic constraints on Lower Cretaceous provenance, facies and the origin of slurry-flow deposits. Petroleum Geoscience, 6, 329-343. CASEY, B.J. & ROMANI,R.S. 1992. Reservoir geology of the Saltire Field, Witch Ground Graben, North Sea. Bulletin des Centres de Recherchers Exploration-Production Elf Aquitaine, 16, 235-251. COPESTAKE, P. 2003. Appendix A. Lower Cretaceous regional depositional sequences. In: EVANS, D., GRAHAM, C., ARMOUR,A. & BATHURST,P. (eds) The Millennium Atlas: petroleum geology of the central and northern North Sea. Geological Society, London, 359-366. COPESTAKE, P., SIMS, A.E, CRITrENDEN, S., HAMAR, G.P., INESON,J.R., ROSE, P.T. & TRINGHAM,M.E 2003. Lower Cretaceous. In: EVANS,D., GRAHAM, C., ARMOUR,A. & BATHURST,P. (eds) The Millennium Atlas: petroleum geology of the central and northern North Sea. Geological Society, London, 191-211. GARRETT, S.W., ATHERTON, T. & HURST, A. 2000. Lower Cretaceous deep-water sandstone reservoirs of the UK Central North Sea. Petroleum Geoscience, 6, 231-240. JENSEN,T.E & BUCHARDT,B. 1987. Sedimentology and geochemistry of the organic carbon-rich Lower Cretaceous Sola Formation (Barremian-Albian), Danish North Sea. In: BROOKS,J. & GLENNIE,K. (eds) Petroleum Geology of North West Europe. Graham & Trotman, London, 431-440. JOHNSON,H. & Lcrrr, 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, 1-169. JONES, L.S., GARRET]', S.W., MACLEOD,M., GuY, M., CONDON,P.J. & NOTMAN,L. 1999. Britannia Held, 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 5th Conference, Geological Society, London, 1115-1125. KNOX, R.W. O'B. & FLETCHER,B.N. 1978. Bentonites in the Lower D Beds (Ryazanian) of the Speeton Clay of Yorkshire. Proceedings of the Yorkshire Geological Society, 42, 21-27. KUBALA, M., BASTOW,M., THOMPSON,S., SCOTCHMAN, I. & OYGARD,K. 2003. Geothermal regime, petroleum generation and migration. In: EVANS, D., GRAHAM, C., ARMOUR,A. & BATHURST,P. (eds) The Millennium Atlas: petroleum geology of the

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central and northern North Sea. Geological Society, London, 289-315. 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. MCGANN, G.J., GREEN, S.C.H., HARKER, S.D. & ROMANI, R.S. 1991. The Scapa Field, Block 14/19, UK North Sea. In: ABBOTrS, I.L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume, Geological Society, London, Memoirs, 14, 369-376. MORGAN, R. & WENT, D. 2004. The Seismic Characterisation o f Lithology using AVO: A Window onto Lower Cretaceous Sands and their Trapping Potential in the Central Graben. Abstracts, The Deliberate Search for the Stratigraphic Trap where are we now? Geological Society, London. MORGAN, R., TOOTHILL, S. & FOGG, A. 2002. What remains to be found in the Central Graben, North Sea? A role for long(er) offset seismic data. Abstracts CD-ROM, PETEX 2002. Moss, B., BARSON, n., RAKHIT, K., DENNIS, H. & SWARBRICK,R. 2003. Formation pore pressures and formation waters. In: EVANS,D., GRAHAM,C., ARMOUR, A. & BATHURST, P. (eds) The Millennium Atlas: petroleum geology o f the central and northern North Sea. Geological Society, London, 317-329.

OAKMAN, C.D. 2005. The Early Cretaceous Aptian Play of the Central and Northern North Sea Atlantean drainage models and enhanced hydrocarbon potential. In: DORg, A.G. & MINING, B. (eds) Petroleum Geology: North-West Europe and Global perspectives - Proceedings o f the 6th Petroleum Geology Conference, Geological Society, London, 187-198. RIIS, E, MAGNUS, C. & WILLIAMS, R.W. 2004. Oil potential in the deep-water MOre Basin, Norwegian Sea. Abstracts CD-ROM, PETEX 2004. ROSE, ETS., 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. TREWIN, N.H. & BRAMWELL, M.G. 1991. The Auk Field, Block 30/16, UK North Sea. In: ABBOTrS, 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, 485-498.

The geological exploration techniques applied by BG in evaluation of the Buzzard Field prior to discovery RICHARD

M. M O O R E

& RICHARD

D. B L I G H T

BG Group, 100, Thames Valley Park Drive, Reading RG6 1PT, UK (e-mail." richard, moore@bg-group, com) Abstract: Substantial technical studies were undertaken by BG in the exploration effort

which preceded the discovery of the Buzzard oil field. These studies were of value in forming BG's perception of prospect risk and reward and confirming the company's commitment to drill the prospect. Studies ranged from standard evaluation techniques to application of cutting edge technology of the time to innovative applications of software to address specific uncertainties or risks. BG perceived the prospect to be of moderate to high value, with a substantial upside reward, and since acquisition of 3D seismic to have moderate risk. This perception derived from several factors that may be peculiar to this particular prospect: 9 an existing well with an oil accumulation, located down dip, proving a migration path from oil mature source and the presence of thick sandstone units of excellent reservoir quality, logged and cored 9 tectonic tilting had both accentuated trap relief significantly increasing trap volume, and aided migration direction 9 the abundance of offset well data allowing an understanding of basin history and a robust geological model Furthermore the BG evaluation benefited from: * involvement of in-house specialists in sedimentology, basin analysis and geophysical modelling * application of the findings of research projects at Edinburgh and Leeds Universities in the fields of Moray Firth structural development and Turbidite Sedimentation respectively

This historical account of technical work undertaken in the evaluation of a stratigraphic trap concerns the South H a l i b u t basin and West Buchan graben of the Moray Firth, offshore U K (Fig. 1), and the evaluation of a prospect which was to become the Buzzard field. The play involves U p p e r Jurassic turbidite sandstone reservoir with age-equivalent oil mature source rock. In the context of stratigraphic traps, the accumulation can be considered to be hosted in base of slope sandstones (Dor6 & Robbins 2005) in a deep-marine depositional environment. Specifically, the reservoir comprises syn-rifl sandstone units within the Kimmeridge Clay Formation deposited by deep marine gravitational flows. The trap (Figs 2, 3a & b) involves the proximal pinchout of sandstone units against the incident slope at the western end of the West Buchan Graben, plus lateral onlaps to intra-basinal, fault-related bathymetry. In places lateral seal is provided by faults. Top and lateral seals are provided by Kimmeridge Clay Forma-

tion shales and base seal by the underlying Kimmeridge Clay and H e a t h e r F o r m a t i o n shales. Oil charge is derived from the K i m m e r i d g e Clay Formation, an oil-prone source rock, which is mature further east in the basin, towards the Ettrick Field. The types of data available and the techniques used through successive stages of exploration are described: from regional evaluation to prospect specific evaluation, through licence award to the technical justification for the drilling of an exploration well (Table 1). The paper presents no information from the discovery well, 20/6-3, or from field appraisal, hence does not describe a current view of the Buzzard field. For this the reader is referred to Dor6 & Robbins (2005). The work described was conducted between 1994 and 2001, a period when both evaluation technologies and presentation tools passed from the era of working on paper through the digital revolution. As a result illustrations of the early studies have proved difficult to source.

From: ALLEN,M. R., GOFFEY,G. R, MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254,187-205. 0305-8719/$15.00. 9 The Geological Society of London 2006.

188

R I C H A R D M. M O O R E & R I C H A R D D. B L I G H T

Fig. 1. Locations of the area of regional evaluation of 1994, the principal discoveries at the time, and the subsequent Buzzard field in the Moray Firth, offshore UK.

Fig. 2. Trap summary map with depth structure of top reservoir pick (Top Ettrick C Sandstone) derived from 2D seismic interpretation, February 1995. Contour interval 100 ft, contour range 7100-10100 ft.

BG PRE-DISCOVERY EVALUATION OF B U Z Z A R D FIELD

189

Fig. 3. Seismic lines from 3D seismic survey of 1995 illustrating the trapping concept. (a) Trace 1902 in the dip direction, W-E, with inset line location map. (b) Line 1618 in the strike direction, N-S.

190

Table1. A

RICHARD M. MOORE & RICHARD D. BLIGHT summary of successive technical evaluations with the key data and studies available to each

Evaluation 1994 regional screening Data added

Studies added

1995 pre-licence application

abundant well data including close offset well 2D seismic

2000

3D seismic

regional seismic interpretation

formation pressure analysis charge volume evaluation

well data evaluation stratigraphic modelling

core viewing

Concentrating on subsurface evaluation techniques, we document the work u~u~ t~kcn b-yBG to generate, describe and defend the prospect. Since BG was a non-operating partner, the exploration team could address additional issues to the work commonly performed by an operator on behalf of a licence group. The partner companies shared their evaluations at appropriate times. The work flows presented are not considered to be a guarantee for success, to be applicable in evaluating all stratigraphic traps, or to be techniques that the company would repeat in the light of modern technologies. This prospect evaluation is an interesting case study of exploration for a stratigraphic trap since a large number of companies carried out their own evaluations either as licence participants or farm-in candidates, and most decided not to participate in the discovery well. Whether this course of action derived from different technical approaches and conclusions, or whether other factors drove the decisions, will be known only to those companies. As the evaluation matured, BG consistently considered the prospect to have a wide range of possible reserves and a moderate to high value with a large upside. Since the acquisition of 3D seismic, the risk was consistently considered to be moderate. Progression of activity on the prospect was influenced by commercial factors, the fascinating account of which is sadly beyond the scope of this paper. As the commercial drivers changed, the strength of the technical case supporting the prospect's most likely geological model and risked value, above non-technical factors, determined the path taken by BG. ~ 1 7 6

1998

..i

_ _ a -

.

.

.

core palaeo-magnetic study seismic attributes & GDI depositional bathymetry evaluation

2001 pre-discovery Reprocessed 3D seismic

outcrop analogue research

picking intra-reservoir units & facies

Exploration premise

.

In 1994 BG held a strong acreage position in the Moray Firth, benefiting from several 14th Round licence awards. The company considered the area to have abundant exploration potential. At the time discoveries in the region were few and included the Beatrice, Captain, Ross and Ettrick Fields (Fig. 1). For the area of the South Halibut basin and West Buchan graben, the exploration team recognized that almost all drilling had been on structural highs, with wells commonly having oil shows but from thin Jurassic successions with thin-bedded reservoirs of poor quality. The premise was that the basin depo-centres could contain thick successions of thick bedded, reservoir-quality turbidite sandstones, coincident with oil mature source rock. The thick sandstones and short oil column (about 10 ft thick) of well 20/6-2 (Fig. 2) supported this premise. This well had targeted Upper Jurassic submarine fan sandstones at a location with a small structural closure at top Jurassic level and a potential large stratigraphic trap within the Ryazanian to Kimmeridgian interval (Well 20/6-2 Completion Report, UKCS Well Records, HMSO London 1992).

Exploration techniques employed by project stage Project stage: pre-licence application, 1994-5

In the quest for acreage acquisition in future licensing rounds, BG commenced in 1994 a regional evaluation of an area spanning parts of

BG PRE-DISCOVERY EVALUATION OF BUZZARD FIELD the South Halibut basin and West Buchan graben (Fig. 1). With formation of a bidding group prior to the 16th Round, BG took responsibility for evaluating open acreage in the East of this area and Amoco in the West, including the area of the prospect which would become Buzzard. BG's prospect-specific studies therefore augmented those of the operator. Regional 2D seismic evaluation. Using 2D seismic lines of various regional surveys, augmented during the course of the evaluation by traded seismic lines, the Base Cretaceous surface and Mid-Cimmerian unconformity surface (Fig. 4) were mapped. The resulting Jurassic isochore (Fig. 5), displayed with Base Cretaceous structure contours overlain, illustrated the size and shape of Upper Jurassic depo-centres and allowed inferences of basin controls and sediment transport pathways to be made. The evaluation (Figs 2 & 5) illustrated that the stratigraphic potential up dip of well 20/6-2 remained untested, with the short oil column being trapped by a small isolated structural closure at the well location. Regional well data evaluation. Of concern was

the distribution of sandstone units within the resulting Jurassic isochore. These were unresolvable with the available seismic data yet

191

proven by widespread drilling. A study was initiated to combine well data with the seismicderived isochore to indicate areas of potential stratigraphic traps. The first part of the study aimed to illustrate the regional basin history and commenced with compilation of thickness and lithology data from wells onto copies of a paper regional base map showing well locations and major fault trends. A map was generated for each major stratigraphic unit from the Devonian upwards. All wells and biostratigraphy reports available to the company were evaluated. Each map showed well stick plots for the respective stratigraphic unit recording subcrop unit, thickness, overlying unit, dominant lithology and the nature of bounding surfaces (conformable or erosional). Lithology and thickness variations were hand contoured between well data points, illustrating inferred provenance, volume and texture of sediment detritus and distribution of depositional environments. Other products included a subcrop map and a map of onlapping units for the base Jurassic surface and other areally extensive unconformities. The age of each erosional episode could then be deduced from the correlative conformable succession. Topography of the erosion surface was implied by the areal extents of successive transgressive units. These maps existed as working copies only.

Fig. 4. Stratigraphic scheme used in 1994 for stratigraphic modelling of component units of the regional Upper Jurassic isochore, with comparison to the genetic sequences of Carruthers et aL (1996) and Partington et aL (1993).

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Fig. 5. Juxtaposed maps of two-way time isochore for the Jurassic of the West Buchan Graben, and structure in two-way time of the Base Cretaceous surface. This juxtaposition of contour maps, using colour fill for the thickness contours, allowed comparison of isochron thicks with structural relief. This map display comes from the evaluation of 1994, based on 2D seismic. The second part of the study considered the Upper Jurassic succession in greater detail. Well picks followed a simple stratigraphic scheme (Fig. 4). Based on the scheme of Geostrat (Price et al. 1993; Carruthers et al. 1996, fig. 2), 3 principal maximum flooding surfaces subdivided the Kimmeridge Clay Formation (Kimmeridgian to Early Ryazanian) into 4 sequences, A, B, C and D. Although it was recognized that the succession could contain more numerous sequences (e.g Partington et al. 1993), this simplified scheme was considered adequate for the scale of analysis. Wells tied by seismic lines allowed identification of the surfaces picked on seismic. During this study, the Landmark OpenWorks suite for subsurface evaluation was introduced within the company. This allowed creation of digital data bases of well logs and picks, without a legacy of stratigraphic nomenclature inherited from earlier BG evaluations of the wells concerned. Picks were made through the Upper Jurassic succession of each well following the stratigraphic scheme (Fig. 4) constrained by biostratigraphical data. The digital data base allowed rapid calculation of thickness and sandstone proportion for each stratigraphic unit

within the Kimmeridge Clay Formation (Fig. 4) in every well. Regional stratigraphic modelling. Mapping of stratigraphic units away from well control was achieved by geometrical construction, constrained by just two surfaces mapped from seismic (Base Cretaceous and Mid-Cimmerian). The intent was to define the distribution of each sandstone unit, its pinchout edge relative to structure, hence identify potential stratigraphic traps. Using Landmark's ZmapPlus for gridding, a model-driven work flow was created to generate depth grids for each maximum flooding surface and for the tops and bases of each sandstone unit in accordance with accepted concepts of basin dynamics and sequence stratigraphy. The Heather Formation was treated as prerift, and the Kimmeridge Clay Formation and component sandstone members were treated as syn-rift. Experience of Upper Jurassic successions in the North Sea recognized (a) a mutually exclusive nature for sandstone preservation in contemporaneous shallow-marine and deepmarine environments, and (b) potential for thick

BG PRE-DISCOVERY EVALUATION OF BUZZARD FIELD turbidite sandstone units outwith a lowstand systems tract. The work flow added the Heather Formation isochore (gridded from well data) to the base Jurassic surface. The remaining isochore was split by the 3 maximum flooding surfaces in the proportion of the thicknesses seen at wells. The thicknesses of shale units between each sandstone member and the preceding and succeeding maximum flooding surface were added or subtracted as appropriate from the relevant maximum flooding surface grid to generate top and base grids for each sandstone unit. Pinchout edges were defined where grids intersected. The methodology honoured all well picks and predicted the pinchout edges for each sandstone unit. Potential stratigraphic traps could be identified by recognition of depth contours of the top surface of each sandstone unit closed against the respective pinchout edge (for example compare Fig. 6a, b). Whilst the exploration premise held generally, in detail it was recognized that there was not a direct correlation between the thickness of the sequence isochore and that of component sandstone units. Automated mapping of depositional environments was not attempted and a hand-drawn approach was followed. Guided by the isopach map for each sandstone unit (Fig. 6b), the corresponding net/gross ratio posted at each well location, the log character, and the bathymetry inferred from the isopach map between successive maximum flooding surfaces, a depositional environment map was created for each successive deep-marine sediment distribution system. The findings of university research projects were applied in this evaluation, specifically in consideration of deepmarine sedimentary processes and deposit distributions and tectonic controls on sediment transport from the evaluation of the structural evolution of the Moray Firth. Products of the study were thickness maps, top and base structure maps and sandstone depositional facies maps for the 4 sandstone units (A, B, C and D) of the Ettrick Sandstone Member, Kimmeridge Clay Formation (Fig. 4). These maps allowed identification of stratigraphic traps within the Upper Jurassic basin fill: their position, area, relief, volume and likely depositional facies. In the area of the future Buzzard prospect this model approach, steered by sandstone thicknesses for well 20/6-2, suggested a change from onlap (A to B) to offlap (B to C to D) in the distribution of successive sandstone units within an overall onlapping shale succession of the Kimmeridge Clay Formation. The maps were used to derive

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scoping volumetrics. For internal company approval to bid for acreage, however, volumetric estimates were based on a top reservoir map and pinchout edge picked from 2D seismic (Fig. 2). In conducting these regional studies the project geologist gained a detailed knowledge of all available well data. A valuable implicit factor of the above approach is the personal understanding gained of the controls and factors influencing the depositional models. The value of the time invested in gaining such knowledge and understanding was recouped in subsequent years since the geologist remained involved with the evaluation team until after the field discovery.

Formation pressure analysis. In order to identify pressure seals within the stratigraphy, the degree of overpressure and its distribution vertically and laterally, a compilation was made of formation pressure measurements. The composite logs and end-of-well reports of all released wells and wells to which BG had access through ownership or trade were consulted. Where direct formation pressure measurements were absent, drilling mud weights and well site pressure analyses were considered. Data were plotted using a PC-hosted spreadsheet to produce charts of pressure versus sub-sea depth, annotated by hand for well, formation and calculated pressure gradients. Results showed that the sandstone units of the Kimmeridge Clay Formation were over pressured, with increasing overpressure in successively deeper sandstone units, and the maximum flooding surfaces picked to separate the sandstone units A, B, C and D were commonly pressure seals. Though lacking formation pressures, well 20/6-2 drilling history supported an abnormal pressure regime. A slightly over pressured formation pressure gradient had been interpreted from mud logging, based on drilling exponents and occurrences of trip gases. From these data it was inferred that a potential stratigraphic trap updip of well 20/6-2 could not be dismissed on the grounds of the aquifer being at normal hydrostatic pressure. Analysis showed there was negligible risk for potential top seal failure of the prospect due to excess pressure of a hydrocarbon column above an over pressured aquifer. Charge volume evaluation. The large size of the trap led to speculation that it would be under filled if the source basin had been insufficiently large or mature to expel the oil volumes

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a

Fig. 6. O u t p u t from regional stratigraphic modelling undertaken in 1994 for the C sandstone unit (a) top structure in depth, contour interval 400 ft, contour range 6800-13600 ft, and (b) isochore, contour interval 50 ft, contour range 0-1400 ft.

BG PRE-DISCOVERY EVALUATION OF BUZZARD FIELD required to fill the trap, or if the preferred migration route had been unfavourable. The operator of the bidding group undertook a migration modelling exercise to address this issue. To augment these results, BG undertook its own evaluation of charge volumes expelled from the West Buchan Graben. The evaluation pre-dated BG's capability to perform advanced basin modelling, and an innovative application was made of software usually used for Monte Carlo reserves assessment. Uncertainty distributions were entered for the source rock volume (calculated from regional surface grids derived from seismic interpretation) and for oil generation and expulsion parameters, the proportion of expelled oil migrating in a favourable direction (based on BG's view of the operator's migration modelling on mapped surfaces within the Kimmeridge Clay Formation), and migration losses. The output was a probability distribution for oil volume charging the trap, which was greater then trap volume. Timing of oil migration with respect to trap accentuation was considered favourable. In conclusion charge constraint was not considered a major risk.

Core viewing. BG had custody of cores from well 20/6-2. A core viewing was held for the bidding group participants during 16th Round evaluations, which proved valuable in fuelling enthusiasm for the Upper Jurassic prospectivity, thanks to the excellent reservoir quality. The bidding group, in which BG held 25% equity, submitted an application for the relevant open acreage offered in the 16th Round of Licensing. Project stage: post licence award 1995-2000 An exploration licence, E928 comprising blocks 19/5 and 20/1 and covering the north of the prospect, was awarded in 1995. Blocks 19/10 and 20/6, though nominated for 16th Round inclusion, were not available for bidding. A 3D seismic survey over the full extent of the prospect was acquired in the same year. Technical work concentrated on moving the prospect evaluation forward to a 'ready to drill' status.

3D seismic interpretation. The quality of the 3D seismic data suffered from numerous multiples, especially within the prospective section, as described by Dor6 & Robbins (2006). Well ties identified a near top reservoir pick corresponding to the intra-reservoir Aire maximum flooding surface (MFS) (Fig. 4) and this was mapped, although data quality limited the confidence of the pick away from well control.

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Despite this difficulty, the onlap of the pick onto the faulted surface of the mid-Cimmerian unconformity was mapped (Fig. 3a). The map of the Aire MFS derived from this data set was the basis for measuring the gross rock volume (GRV) of the prospect at this time. Multiple movement histories of faults extending into the Lower Cretaceous could be demonstrated (Fig. 3b). A judgement was made for the most likely degree of trap fill by considering depths where additional potential trap leakage points were introduced by faulting. Of concern was the lithology within the trapped GRV, and uncertainty in how representative was the reservoir of well 20/6-2. The interpretation focussed on understanding the sediment transport system using diverse approaches, described below.

Core palaeomagnetic study. Coremagnetics, a company providing palaeomagnetic services, was contracted by the licence group to perform a core palaeomagnetic study with the aim of reorienting core samples and identifying grain fabric preferred orientations. The core of well 20/6-2 provided an opportunity to address local sand transport direction from grain fabric orientation. The core displayed a number of features suggesting deposition or remobilisation on a submarine slope. The control acting on the slope and its orientation were uncertain: the slope could have been fault related or a result of channel-bank collapse. In sampling the core, remobilised beds were avoided and any analysed samples with excessively steep grain fabrics were inferred to have undergone postdepositional fluidisation whilst dewatering thus they were removed from the results. Seismic

attributes and GDI. Geologically Driven Integration (GDI) is a technique for neural network classification of seismic facies. Its application to this prospect was an early trial of an emerging technology. By considering a time window of interest, in this case from zero to 48 milliseconds below the seismic pick for the Aire MFS, analysis was performed of (a) seismic waveform (8 classes), and (b) seismic attributes (6 classes) using unsupervised training of the neural network. The areal distribution of classes is displayed in map form (Fig. 7a). In this case the GDI waveform and attribute class maps showed common features relating to: 9 9 9

thinning of the isochore towards the up-dip pinchout edge data quality positions of faults

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Fig. 7. 1998 evaluation: (a) GDI seismic facies classification map, with colours corresponding to discrete seismic classes, (b) seismic attribute map for dominant frequency. Displays of intervalled seismic attributes in map form inspired interpretation of sedimentological features, e.g. sandstone sheets in (a) or sandstone restricted to channel fills in (b). The latter interpretation is illustrated by (e), the base reservoir map for the channel fill sandstone model, contour interval 100 ft, contour range 6600-9900 ft.

The G D I waveform class and attribute class maps, and maps of any individual seismic attribute, can be compared with the expected geometries of geological bodies in alternative sandstone distribution models. The study noted the absence of channel-like features on the class maps and concluded this could indicate either that a sheet-sandstone distribution was applicable or that issues of data quality, pick uncertainty and analysis across too wide a window could negate a geological interpretation. The class maps were used to support a sheet sandstone distribution in the prospect predominantly to the north of the prominent east-west fault (class coloured orange in Fig. 7a). A map of a single seismic attribute, d o m i n a n t frequency, was used to support an alternative model of sandstone distribution confined to channel fills (Fig. 7b, 7c).

Depositional bathymetry evaluation through structural, flexural and decompactional restoration. Using grids interpreted from the

3D seismic, the stratigraphy was back-stripped in order to predict basin geometry and sediment transport pathways at the time of sandstone deposition. Fault displacements were studied to infer which faults were post-depositional and which had syn-depositional fault scarps or faultrelated surface slopes. The calculated b a t h y m e t r y confirmed the sandstone depositional e n v i r o n m e n t s to be turbidite related, and indicated an evolving depositional slope with west to east axial transport direction for sand into the basin. A zone of non-depositional by-pass (Fig. 8) was inferred between the position on seismic of onlap of the Aire MFS onto the mid-Cimmerian unconformity and the loci of onset of sand deposition at the calculated base of slope. The result of the study is summarized as a risk map on sandstone presence (Fig. 8) based on the interpretation of syn-depositional, intra-basinal topography. It was used to support a model of laterally extensive depositional lobes separated by hemipelagic drapes. For prospect volumetrics

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Fig. 8. Risk map for sandstone presence from depositional bathymetry restoration modelling, 1998.

this favoured the sheet sandstone model of large GRV with relatively low net/gross. The findings of this study combined with those of the more ambiguous GDI study, shifted BG's view of the two alternative sandstone distribution models towards the sheet distribution. A significant increase to the most likely potential reserves resulted, sufficient to change the optimum development scenario used in economic analysis from a floating production storage and offloading (FPSO) system to a platform with pipeline export (described later).

Project stage: well planning, 2000-2001 The P.928 partnership was unsuccessful in its 18th Round bid for blocks 19/10 and 20/6 and BG held no equity in the exploration licence, P.986, awarded in 1998 covering the southern portion of the prospect. Each company holding equity in the prospect had to consider its options and commercial activity gained pace during 2000 as the ultimate deadline for drilling the commitment well of the P.928 licence approached.

3D reprocessing. In the summer of 2000, the operator of licence P.986 contracted Veritas to

perform a reprocessing of the 3D seismic data with a key aim of reducing the multiples. Multiple attenuation was successfully achieved, though at the expense of primary energy, with localized adverse affect in the reservoir section. The new 3D volume showed abundant minor faulting of the reservoir section and the improved resolution allowed picking base reservoir and intra-reservoir surfaces for the first time.

Seismic interpretation. The

focus of the interpretation became definition of the optimum location for the exploration well. Concerns remained with the seismic data and interpretation, in particular the change in wavelet character (phase) below the Base Cretaceous surface, correlation of picks across faults, and changes in reservoir thickness and facies through interaction with topography. Of benefit to the evaluation was the technique of flattening seismic sections on a nominal pseudohorizontal surface, in this case the Base Cretaceous surface was used (Fig. 9 a, b). Although focus had shifted to the reprocessed data set, comparison was frequently made with the original data in evaluating problematic areas. Seismic characteristics compatible with

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Fig. 9. An example of the creation of pseudo-bathymetry to assist in picking sandstone units by flattening a seismic section on the Base Cretaceous surface; (a) tie line from reprocessed 3D seismic survey between wells 20/6-2 and 20/6-3, with pre-drill interpretation, (b) same line flattened on base Cretaceous surface.

differential c o m p a c t i o n were used to gauge confidence in the presence of sandstone lithology at alternative candidate well locations. For example isochore thicks with an elongate area and positive relief on the upper surface were inferred to contain s a n d s t o n e in p r o b a b l e

channel-fills (Fig. 10 a, b) within the overall sheet system.

Application of outcrop analogue and research findings. Views of the most appropriate outcrop analogue differed b e t w e e n licence partners. B G

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was familiar with the A n n o t Sandstone, of the French Maritime Alps, through sponsorship of the Turbidites Research G r o u p at Leeds University. Features of this outcrop analogue applied in the interpretation of the seismic data and the geological model included the onlap relationships, both proximal and lateral, the channel fill geometries and the proximal to distal facies variations.

Well location selection criteria. BG considered the choice of well location to be crucial in order to prove an unambiguous test of the prospect. Earlier exploration wells in the Moray Firth had been drilled sub-optimally in relation to stratigraphic traps, for example: the significance of the thin interval of gas-bearing Aptian sandstones in the 1981 well 13/24-1 was unrecognized at the time of drilling, but subsequently the well was inferred to be near the stratigraphic pinchout of what was later to be defined as the Blake oil field; the location of 1986 well 20/6-2 had been compromised by the desire to drill on o '-";"or structural closure in ad . . . . . . . to testing the stratigraphic trap potential of the Upper Jurassic succession. In either case, a few hundreds of metres difference in well location might have led to discoveries which would have significantly accelerated industry activity in the Moray Firth. Experience shows that re-evaluation with the added benefit of information from unsuccessful wells can better define stratigraphic targets leading to future success. Criteria considered significant in the choice of potential well locations were: 9

* 9 9 9

9 9

the seismic character of the top reservoir pick should be comparable with that of the thick reservoir sandstones seen in the offset well 20/6-2 the ease of extending picks away from the target location the location should be relatively unfaulted at reservoir level the reservoir thickness should be substantial compactional geometries should be consistent with sandstone lithology at the well location sufficient distance from the zone of uncertainty on reservoir pinchout attic reserves volume should be subcommercial in the event of an unsuccessful well

above a closing contour independent of the northern lateral bounding fault, thus not reliant on an additional possible fault seal c o m p o n e n t to trap risk as well as top, lateral and base stratigraphic seals (Fig. 10) In the spring of 2001 well 20/6-3 was drilled and discovered the Buzzard Field, encountering a full oil column. A well test was conducted and a sidetrack, to establish the oil-water contact, followed.

Discussion

Evolution o f the geological model as data, resolution and studies increased The sandstone pinchout geometries in the prospect were modelled in different ways during the course of the evaluation (Fig. 11). In 1994 the sandstone units (A, B, C and D) were modelled as onlap (A to B) then ofttap (B to C to D). In 1998 a constant hinge line was muu~llcu with sandstones ~. ,. . .D. . anu C thinning to zero at the same line. At end 2000 successive onlaps from A to B to C were imaged. The seismic data coverage improved from the grid of 2D regional lines to the original 3D (processed with offset well calibration), and resolution improved with the reprocessed 3D (multiple attenuation). A n increasing number of features of the subsurface model were imaged on successive seismic data sets and as a consequence the techniques used in the interpretation evolved. With the 2D seismic data the top reservoir was mapped and the base reservoir and GRV were modelled. The prospect was considered to be high risk. Using the original 3D seismic data, the prospect was evaluated as moderate risk. Seismic attributes were used to support end-member sandstone distribution models within the trap. A top surface was picked and base reservoir and the GRV were modelled using a wedge of reservoir from a common pinchout line thickening to the down dip well, 20/6-2. Once the re-processed 3D seismic was available both top and base reservoir were mapped to give the GRV. The pinchouts of separate sandstone units, in an overall on-lapping geometry, could be mapped (Fig. 10b). The variability in reflection strength and character were used to infer reservoir facies changes.

Fig. 10. Maps from the evaluation prior to drilling, November 2000. (a) Depth structure map on top Ettrick C Sandstone, contour interval 50 ft, contour range 7700-9900 ft, and (b) map of sandstone isochore (sandstone units A, B & C) with depth structure overlain, depth contour interval 100 ft, depth contour range 7400-9700 ft, thickness range 0-550 ft approximately. Black squares in (a) show locations considered for well 20/6-3.

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E

B A

C

B A

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Fig. 11. Diagrammatic cross-sections of the Upper Jurassic succession, illustrating the differing pinchout geometries of successive sandstone units inherent in the stratigraphic modelling approaches used in 1994,1998 and end 2000.

It is interesting to consider at what stage the degree of confidence reached a sufficient level to mobilize a drilling rig, how many of the well locations considered throughout the evaluation would have been successful, and the influence this experience might have on future similar evaluations. The experience of the Buzzard evaluation shows: the 2D map, with the benefit of close offset well calibration, was sufficiently near to the pre-drill map that a well targeted at a wholly stratigraphic target would have been successful (Figs 2 & 10). The trap risk was considered too great by BG to consider drilling based on this data set. well 20/6-2 and, in the case of the Blake field, well 13/24-1 missed significant discoveries by drilling marginally to stratigraphic traps. Evaluations in both cases were based on 2D seismic data, though without the benefit of nearby well calibration. In the case of well 20/6-2 the location resulted from a compromise of target objectives.

9

9

*

9

the well location considered from the original 3D would have resulted in a discovery. all well locations considered from the reprocessed 3D would have resulted in discoveries (Fig. 10). the interpretation of the reprocessed 3D data adequately identified the sweet spots of the prospect (Fig. 10), penetrated by discovery well 20/6-3, its sidetrack and initial appraisal well bores. The discovery well was placed such that an early appreciation of the field reserves was achieved, with benefits for appraisal and development planning

In summary, it is our technical view that the confidence derived from a 3D interpretation is required before drilling an exploration well targeting a stratigraphic prospect, and that a 3D seismic survey is essential to determine the well location. BG's view of the prospect's risk changed from high to moderate following 3D acquisition.

BG PRE-DISCOVERY EVALUATION OF BUZZARD FIELD

Risk perception Since the acquisition of 3D seismic data BG no longer perceived the risk on the prospect to be high. Furthermore, the moderate risk value assigned at that time was not significantly changed even as improvements in seismic resolution were realised. This resulted from: 9 9 9

key information being available from the start of the evaluation, i.e. down dip well 20/6-2 with proven reservoir and oil. the trap concept of pinchout of the Upper Jurassic basin fill in an up dip direction being displayed on all seismic data sets. the 3D seismic suffering data quality issues.

Key risks and mitigating studies

addressed with back-stripping and decompaction modelling to determine bathymetry at deposition and allow inference of sand transport paths and distribution; addressed with seismic attribute analysis. The simultaneous occurrence of factors which contributed to the pre-drill perception of moderate risk could be considered to be unique to this prospect. Such factors are: 9

9

The technical studies used to address the key risks are summarized below. 9

9

9

9

Charge volume (source effectiveness) o addressed through Monte Carlo assessment of oil volumes generated from a source rock GRV and the proportion migrated in the direction of the prospect. Nowadays BG would address this with basin modelling in 1D wells and pseudo-wells, 2D sections or 3D surfaces as appropriate. Base seal (trap effectiveness) o addressed using outcrop analogues and models of deep marine environments with onlap onto mud-draped slopes; a remnant risk was recognized if feeder channels had (1) existed, (2) been sandstone filled and (3) cut to a permeable lithology in the subcrop. Definition of trapping elements (trap presence and effectiveness) o for the pinchout trap element there was a risk in accurately defining the position of the pinchout o resolution was insufficient to define whether the oil fill of the prospect in the upside case would rely on fault seal or whether slumped units and mud drapes on active fault scarps bounding the sand deposits would be sufficient to negate this trapping element o there was uncertainty on the depth of the deepest intersection of lateral seals with dip closure hence definition of the spilling contour, although the down-dip well provided a maximum limit. Sandstone facies distribution (reservoir presence)

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9

an existing down dip well with an oil accumulation proving a migration path from oil mature source and presence of thick sandstone units of excellent reservoir quality, logged and cored the target petroleum system having intercalated potential reservoir rock and potential source rock thus favouring dip parallel migration tectonic tilting (Dor6 & Robbins 2005, fig. 8) that had both accentuated trap relief, significantly increasing trap volume, and aided migration direction the abundance of offset well data allowing an understanding of basin history and a robust geological model

Although having a minimal impact on the output of the risk assessment, the value added by the technical studies was significant in increasing the perception of the mid case reserves, hence the perceived value of the success case outcome (discussed below). Supported by the study results, the confidence with which the technical team presented its evaluation of risk and potential reward was sufficient to convince the company to improve its equity position and invest in the exploration well.

Factors influencing BG's commitment to explore this prospect With the benefit of hindsight some factors can be identified which helped steer BG's course. BG undertook substantial technical work as a non-operating partner and addressed key concerns with appropriate technologies, both proven and emerging. The technical approach involved working all the data available, recognizing data quality issues and working around them. The skills of in-house specialists (deep marine sedimentologist, basin analyst, geophysical modeller) were called upon to target specific issues at appropriate times. There was

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sufficient continuity of staff through company re-organizations to defend the prospect when challenged at technical audits. There was no attempt to predict the likelihood of success or field reserve size based on so-called 'creaming curves' for the region. The company's internal procedures not only challenged the evaluation frequently, but were used to support an increase in prospect value when justified by the technical case. The stratigraphic nature of the prospect was not considered to be a special case or to warrant any preconception of prospect risk. The company's prospect evaluation procedures were followed as for any prospect. The significant increase in predicted reserves occurred early in 2000 when a technical case was presented to increase the perceived mid case oil-in-place above the threshold that would allow a 'platform and pipeline export' development concept to become economically attractive. Results of economic analysis of this development concept surpassed all internal economic hurdles, which could not be achieved for an FPSO development option. Other factors which influenced the economic assessment were: high productivity wells, relatively shallow water, relatively shallow target, and well cost forecasts based on straightforward drilling in a geological succession well known to BG through its Blake development. This 'wholeprospect' economic evaluation demonstrated a potential high value and fuelled the company's desire to gain equity in licence P.986 and drill the prospect.

Conclusions

(1)

The pre-discovery evaluation benefited from: 9 a close offset well demonstrating oil and sandstone presence which helped reduce reservoir and migration risk elements 9 an understanding of basin history based on abundant regional well data 9 adopting a point forward view which recognized the positive implications of unsuccessful wells 9 following an evaluation procedure as for any prospect without any preconception of risk due to the stratigraphic nature of the trap 9 application of research findings of joint industry projects at Edinburgh and Leeds universities in the fields of subsidence history and turbidite sedimentology respectively.

(2)

The prospect benefited from tectonic tilting in the Tertiary which amplified trap volume and aided migration, further improved by the interbedded nature of reservoir and source rocks. (3) The limits of stratigraphic traps in the deep-marine sedimentary environment which commonly have a subtle expression and poor definition on seismic can be constrained by techniques which: 9 address topographical controls on trap extent, both fault-bound and slopebound 9 address depositional controls on reservoir pinchout position 9 reconstruct topography through backstripping 9 predict position of change in slope hence the potential position and geometry of the pinchout edge. (4) The techniques that BG applied were largely 'modelling' exercises, hence value comes from the understanding gained during the btuuy a~ mutsii as from the 'result'. Value from the studies was optimized through continuity of team members. (5) Specialists in a variety of fields, sedimentology, basin analysis and geophysical modelling, brought their expertise to bear on the evaluation. (6) Key points in the evaluation history were an increase in mid case reserve and an improvement in chance of success as a result of data acquired and studies undertaken. (7) Creaming curves were not used in assessing the prospect, since they describe historical data and, in our view, the value of forward extrapolation is questionable. (8) Criteria were defined for the exploration well location to meet in order to determine unambiguously the presence or otherwise of the target hydrocarbon accumulation. (9) In this case study, the prospect was not drilled until the data set comprised the following key elements: reprocessed 3D, down-dip well, abundance of wells in the basin. Appraisal drilling has shown that the maps throughout the evaluation were sufficiently accurate to define a prospect area within which virtually any well location would have resulted in a discovery. (10) Field appraisal data has confirmed that the technical analysis prior to the discovery well was sufficiently advanced to target that well into one of the several sweet spot areas in the field. ~!_

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BG PRE-DISCOVERY EVALUATION OF BUZZARD FIELD The authors acknowledge BG Group for granting permission to publish and all BG staff past and present who worked on the project, in particular those whose work is presented here: S. Lynch, R Nadin, I. Campbell, T. Boycott-Brown and N. Percival. We acknowledge joint industry projects conducted by Edinburgh University and the Turbidites Research Group at Leeds University, the results of which were incorporated in our evaluation. We thank the Buzzard field operator and partners for permission to publish seismic data and for the lively debate at pre-discovery technical meetings where BG presented its technical work. The manuscript benefited from reviews by J. Ford and A. Sims and the editorial comments of G. Goffey, for which we are grateful.

References CARRUTHERS, A., McKm, T., PRICE, J., DYER, R., WILLIAMS, G. & WATSON,P. 1996. The application of sequence stratigraphy to the understanding of Late Jurassic turbidite plays in the Central North Sea, UKCS. In: HURST, A., JOHNSON, H.D., BURLEY, S.D., CANHAM, A.C. & MACKERTICH,

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D.S. (eds) Geology of the Humber Group: Central Graben and Moray Firth, UKCS. Geological Society, London, Special Publications, 114, 29-45. DORE, G. & ROBBINS,J. 2005. The Buzzard Field. In: DORE, A.G. & VINING, B.A. (eds) Petroleum Geology of Northwest Europe and Global Perspectives: Proceedings of the 6th Conference. The Geological Society, London, 241-252. PARTINGTON, M.A., COPESTAKE, P., MITCHENER, B.C. & UNDERHILL, J.R. 1993. Biostratigraphic calibration of genetic stratigraphic sequences in the Jurassic-lowermost Cretaceous (Hettangian to Ryazanian) 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. PRICE, J., DYER, R., GOODALL,I., MACKIE,T., WATSON, P. & WILLIAMS,G. 1993. Effective stratigraphical subdivision of the Humber Group and the Late Jurassic evolution of the UK Central Graben. In: PARKER, J.R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 443-458.

Application of a sealing surface classification for stratigraphic related traps in the UK Central North Sea JOEL CORCORAN

Imperial College o f Science, Technology and Medicine, Prince Consort Road, London SW7 2BB, UK now at: Paladin Resources, Kinnaird House, 1 Pall Mall East, London SW1 Y SPR, UK (e-mail: joel [email protected], uk) Abstract: Traps can be categorized by defining the relationship of the seals with respect to the reservoir/seal bounding surface(s). Two major subdivisions provide the foundation of the classification; one-seal traps are structures which possess closed contours at the reservoir/seal interface, whereas poly-seal traps are those where closed contours at the reservoir/seal(s) interface do not exist or are inadequate to entirely close the trap on a single sealing surface; thus implicating the requirement of one or more base and/or lateral seals. The nature (conformable, unconformable, tectonic, facies change, waste zone) and combination of the seals essential to contain the hydrocarbon pool with respect to the one-seal and poly-seal distinction allow for further subdivisions of each of these classes. This publication catalogues a variety of Lower Cretaceous, Upper Jurassic and Tertiary stratigraphic related traps (stratigraphic and combination) from the Central North Sea with respect to fourteen applicable sealing-surface classes. The paper also provides a source for identifying and categorizing prospective stratigraphic related traps in accordance with documented field examples from the Central North Sea. In addition, the author demonstrates the scheme as a first-pass exploration tool to rank future portfolios of stratigraphically trapped prospects with respect to the trapping integrity/reliabilityof the sealing surface(s).

The mature p e t r o l e u m province of the U K Central North Sea (CNS) is witnessing a shift towards targeting stratigraphically related traps; induced by the ever decreasing number of substantial structural closures and recent sizeable stratigraphic trap successes (e.g. Buzzard (Dor6 2002); B r e n d a (Jones et al. 2004). However, previous to this publication, no published work has looked specifically at the range of trap types within the CNS that rely on a stratigraphic closure element. This p a p e r attempts to address this gap in current understanding by compiling a useable classification scheme that documents the range of stratigraphic trapping mechanisms within this region. In addition, the classification system provides an aid to risking seal efficiency from the stand point of reservoir-seal b o u n d i n g surface relationships.

In order to develop prospects and mitigate risk it is vital to u n d e r s t a n d stratigraphic trapping mechanisms in existing fields. This paper concentrates on reviewing and classifying some of the proven Tertiary, Lower Cretaceous and Upper Jurassic stratigraphic and combination (structural/stratigraphic) trapping mechanisms in UK Quads 13, 14,15,16, 20, 21 and 22 (Figs 1 & 2). In this study we have utilized the concepts and models adopted in Milton & Bertram's (1992) sealing surface classification and applied the scheme solely to stratigraphic and structural/stratigraphic traps. A n improved understanding and recognition of the significance of stratigraphic related traps since the publication of the original paper has necessitated the construction of several new/revised seal-surface models, these will be discussed and illustrated later in the paper.

Background Of the 4-25 billion barrels of oil equivalent predicted yet to find in the UK continental shelf up to 75 % is estimated to be potentially located within stratigraphic traps (Munns & Stocker 2003).

Classification schemes A trap classification scheme can help to improve trap descriptions, aid comparisons between traps and assist in grouping trap examples. Current classifications are not specific to

From: ALLEN,M. R., GOFFEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 207-223. 0305-8719/$15.00. 9 The Geological Society of London 2006.

208

JOEL CORCORAN

Fig. 1. Location map of CNS study area, fields discussed in text and tables are highlighted.

stratigraphic traps and are based on three main approaches; A primary 'genetic' distinction relies on determining the controlling factors of trap formation in terms of two end-members; stratig r a p h i c i.e. major closure control induced through lithology/stratigraphy variation and geometry or s t r u c t u r a l where deformation and geometrical modification is the chief control on the trapping configuration. Those traps falling between these two end-members can be termed structural/stratigraphic traps. A second approach, utilized by Rittenhouse (1972) and Halbouty (1982) and summarized by Biddle & Wielchowsky (1994) utilizes sub-

divisions for the structural to stratigraphic trap continuum based on overall trap relationships with unconformities, post-depositional alteration or primary depositional events (Biddle & Wielchowsky 1994). A major shortfall concerning this method is an incorrect emphasis on closure mechanisms with limited consideration of onlaps and pinchouts. Neither Rittenhouse's (1972) nor Halbouty's (1982) classification benefited from definition using modern 3D seismic and both schemes created a restrictively large number of sub-classes (Rittenhouse 1972). In addition to these shortcomings structural/stratigraphic traps were under represented.

Fig. 2. Simplified lithostratigraphic and sequence stratigraphic chart for the CNS study area, highlighting reservoir/seal extent and distribution. After Fraser et al. 2003, Copestake et al. 2003 and Ahmadi et al. 2003. Jurassic sequence stratigraphy after Partington et al. 1993, Lower Cretaceous sequences are from the Millennium atlas convention (Copestake et al. 2003) and the Tertiary follow Dixon & Pearce (1995).

SEALING SURFACE CLASSIFICATION

209

210

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The third scheme constructed by Milton & Bertram (1992) considers the relationship of the trapping seal(s) to the reservoir interfaces(s) and has been adopted by this paper.

One-seal traps One-seal traps are structures defined by closed contours at the base of the sealing sequence (Figs 3-5). Common examples include sedimentary and compaction mounds, antiformal drape

A sealing surface classification (Milton & Bertam 1992) Milton & Bertram's (1992) classification considers the fundamental trapping mechanism and is further sub-divided according to sealing surface relationship and associations. In this scheme, to define the trapping mechanism, one is required to list the nature and relationship of the surfaces and rock lithologies required to seal the hydrocarbons. A discrimination between traps that require only a top sealing surface (one-seal traps) and those that require a lateral or/and base seal completes the classification (poly-seal). The motivation behind Milton & Bertram's classification (1992) lies in the desire to have a categorization which assesses trap integrity. Their conclusion was that a scheme based on the relationship of surfaces that contain the hydrocarbons (i.e. seals) would give insights into the sealing efficiencies of traps, whilst providing trap definition. The capacity of a trap to impede the migration of hydrocarbons is determined by the sealing efficiencies of three types of sealing surface; (1) Stratigraphic surfaces; these are either bedding or erosional contacts. In terms of the sealing surface distinction, stratigraphic surfaces are parallel and thus conformable with the reservoir/seal interface or angled to the interface and unconformable. This distinction is vital when considering seal risk since an unconformable surface in contact with the reservoir/seal interface offers potential routes for migration along the bedding planes. Furthermore an unconformable seal has the potential to place multiple lithologies of differing sealing efficiencies in contact with the reservoir rock, complicating risking. (2) Tectonic surfaces; here the reservoir is juxtaposed against strata which has moved post reservoir deposition. Examples of tectonic surfaces include fault planes and salt bodies. (3) Facies/waste zones; poorly defined regions where reservoir quality degrades to nonreservoir (sealing) due to facies change or post depositional diagenesis.

Fig. 3. (U) Truncation enveloped antiform, (U) Truncation enveloped antiform, (U) Unconformable top seal, Single seal.

Fig. 4. (U(C)T) Footwall related, variable truncated top seal trap, (U(C)T) Footwall related, variable truncated top seal, (U(C)) Unconformable top seal with less critical conformable seal, (T) Part of top seal potentially fault, Single seal.

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Fig. 5. (C) Sedimentary mounding enhanced by differential compaction trap, (C) Sedimentary mounding enhanced by differential compaction, (C) Dip closed with conformable to seal, Single Seal (Milton & Bertram 1992). structures and upthrown fault closures that lack a basal seal requirement e.g. the Piper field (Fraser et aL 2003). In the latter the sealing surface includes both the fault plane and crestal stratigraphic surface.

Poly-seal traps Where closed contours at the reservoir/seal interface do not exist or are insufficient to completely close the trap along one 'sealing' horizon, an additional lateral or basal sealing surface is required to provide a 'poly-seal' trap closure (Figs 6-16). Pinchouts, onlaps, down thrown fault closures, scoured channels and upthrown fault closures that require a basal seal are all traps that require sealing along more than one surface. An important distinction, and key risk, between one-seal and poly-seal traps is the requirement of a join line; this is where top and basal/side seal link. Poly-seal and one-seal traps can be further sub-divided according to the nature of their sealing surfaces (and their sealing lithology if applicable). The surfaces required to trap the hydrocarbons are either; conformable (C), unconformable (U), defined by a facies change (F) or tectonic (T). Usefully, Milton & Bertram's (1992) classification is tailored towards risk evaluation in prospects. Take for example the comparison of

211

Fig. 6. (U/T) Downthrown fault closure with truncation trap, (U/T) Downthrown fault closure with truncation, (U) Unconformable top seal, (T) Tectonic (fault) side/bottom seal, Poly-seal.

a conformable and unconformable seal. For an unconformable seal, a comparatively high risk is implicated since multiple lithologies are potentially brought into contact with the reservoir/seal interface. Similarly for a poly-seal trap to be successful multiple independent seals require considering, and with this the multiplication of numerous seal risks (Milton & Bertram 1992). A number of illustrative models have been constructed to illustrate the range of stratigraphic and combination structural/stratigraphic traps in the study area. It is worth noting that in practice a field may have a number of stratigraphic trapping mechanisms in place, thus requiring more then one model to define the trap (e.g. Brae South, Table 2). All models are described with reference to the sealing surface classification described above. Tables 1, 2 and 3 relate the classification scheme to field examples. Stratigraphic related fields and discoveries included in the tables are not exhaustive. All have been interpreted to have at least one of the three following elements (1) A stratigraphic closure surface at the reservoir/seal interface within the closure of the hydrocarbon pool, (2) A trapping mechanism induced through a deviation in lithology, (3) A trapping geometry that is chiefly depositional in origin. References where appropriate have been provided.

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I3, Salt induced truncation antiform (Fig. 3) One-seal trap with an unconformable top seal. The basal seal is not significant to the trapping mechanism. Pinchout and/or truncation of the reservoir in the lateral sense may be locally important. Examples include Kittiwake (Glennie & Armstrong 1991)

U(C)T, Footwall trap with unconformable/ conformable top seal (Fig. 4) Footwall related poly-seal trap with a variable truncated top seal. A conformable partial seal is not critical to the trap success although may aid pooling additional upside. Note that the lateral fault seal is required where the subcrop edge branchline cuts the fault. Examples include Saltire (Casey et al. 1993), Petronella (Sgiath & Piper Sandstone) (Waddams & Clark 1991) and the Piper F i e l d s (Schmitt & Gordon 1991; Maher 1981).

Fig. 7. (U/U) Truncation enveloped onlap trap, (U/U) Truncation enveloped onlap, (U) Unconformable top seal, (U) Unconformable bottom seal, Polyseal.

C, Compaction anticline (Fig. 5) Four-way dip closure induced through differential compaction. The closure mechanism is chiefly structural, however the geometry is a result of differential compaction imparted by stratigraphy and depositional set-up. Examples include West Brae.

U/T, Downthrown fault closure with truncation trap (Fig. 6) Poly-seal trap with an unconformable top seal and fault bounded side/bottom seal. Examples include the Saltire field (Casey et al. 1993), Galley (Moseley 1999) and Petronella field (Waddams & Clarke 1991).

U/U, Truncation enveloped 'onlap' trap (Fig. 7) Poly-seal trap with an unconformable top and bottom seal. The geometry is such that an apparent onlap/pinchout against the elevated basal/side seal may be evident on seismic; though the onlapping nature of the side and basal seals would give evidence of erosional nature of the reservoir package. Examples include the Piper sandstone reservoirs of the Highlander field (Whitehead & Pinnock 1991).

C/C, Onlap trap (Fig. 8) Poly-seal onlap trap with conformable top and bottom seal required for closure.

Fig. 8. (C/C) Onlap with conformable top and bottom seal trap, (C/C) Onlap with conformable top and bottom seal (conformable in terms that, only one bedding surface in contact with bottom and top reservoir respectively), (C) Conformable top seal, (C) Conformable base seal, Poly-seal (two independent risks).

U/C, Subcrop trap (Fig. 9) Poly-seal trap with the reservoir subcropping beneath an unconformable top seal. The basal seal remains conformable e.g. local regions of Captain field (Rose et al. 2000).

218

JOEL CORCORAN It is worth noting the subtle differences between the C/C onlap trap (Fig. 8) and the C/U onlap trap (Fig. 10). In the former trap the basal seal has only one bedding plane in contact with the base of the reservoir. This could prove a key component in risking the Lower Cretaceous prospects in the outer Moray Firth. Here a thin drape of Kimmeridge Clay is occasionally sufficient enough to blanket the palaeotopography such as to remove the reservoir from an otherwise high risk unconformable basal seal.

U(C)/TC, Footwall trap with unconformable/conformable top seal (Fig. 11)

Fig. 9. (U/C) Truncation Trap, (U/C) Truncation trap (below), (U) Unconformable top seal, (C) Conformable bottom seal, Poly-seal (Milton & Bertram 1992).

C/U, Onlap trap (Fig. 10) Poly-seal trap created by onlap onto an eroded high. The basal seal is unconformable in comparison to the top seal. A key risk is the potential for hydrocarbon re-migration from the reservoir through the unconformable basal seal sequence via the bedding planes or along permeable beds.

Poly-seal footwall trap with variable truncated top seal. The conformable seal is not critical to trap success although may aid pooling additional upside. The extent of the stratigraphic component of the trap is often minimal in areal extent but critical to trap success in crestal regions. A basal seal is required when the reservoir pool does not extend into fault plane as illustrated in Fig. 11. Examples include local regions of the Rob Roy (Parker 1991; Fraser et al. 2003), Scott (Fraser et al. 2003) and Piper fields (Schmitt & Gordon 1991; Maher 1981).

Fig. 11. (U(C)/I'C) Footwall related, variable Fig. 10. (C/U) Truncation Trap (above), (C/U) Truncation trap (above), (C) Conformable top seal, (U) Unconformable bottom seal, Poly-seal (Milton & Bertram 1992).

truncated top seal with basal seal trap, (U(C)/TC) Footwall related, variable truncated top seal with basal seal, (U(C)) Unconformable top seal with less critical conformable seal, (C) Conformable bottom seal, part of bottom/lateral seal potentially fault induced, Poly-seal.

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219

U/U, Differentially compacted channel trap (Fig. 12) An example of this trap is the Alba field. Here the top reservoir is distinguished by the differentially compacted base Oligocene unconformity. The basal seal is also unconformable resulting from rapidly infilled channel incision. In the case of Alba the presence of injectites introduce a high risk element to the seal risk since multiple top seal surfaces will interact with an otherwise low risk structurally closed top reservoir. The severity of risk will be dependent on the thickness and lithology of the sealing sequences. Injectite structures are post depositional and complicate trap classification as they fall into neither of the generic stratigraphic or structural schemes.

C/U, Mounded channel trap (Fig. 13) These are predominantly structural traps with a single low risk seal at the top reservoir (NB. top seal closure mechanism analogous to 'C, compaction anticline', Fig. 5). Additional stratigraphic upside and the polyseal trapping mechanism is presented by the basal erosional surface. The trapping mechanism in the one-seal (i.e. top reservoir) case is clearly structural if closed uniquely by closed contours. However the overall geometry is both depositionally and compactionally induced resulting in a structural/stratigraphic classification. In addition a further stratigraphic element is implicated when a basal seal is required e.g. The MacCuUoch field (Gunn et al. 2003).

Fig. 12. (U/U) Differentially compacted 'channel' with unconformable top and base seal trap, (U/U) Unconformable top and bottom seal, (U) Unconformable top seal, (U) Unconformable base seal, Poly-seal.

C/F, Mounded channel trap (Fig. 14) A poly-seal trap with a conformable top seal over a structural 'mound' and lateral seal(s) provided by facies change into non reservoir channel flank/overbank deposits. A possible example is the Brenda discovery (inferred from Jones et al. 2004).

C/CF, Marine pinchout trap (Fig. 15) Two independent seals are required (base and top) to create this trap. Both are conformable with the reservoir bounding surfaces. It is likely that both seals will be of similar, if not identical lithology. In this case top and bottom seal will carry the same risk (Milton & Bertram 1992). This poly-seal category is the most prolific stratigraphic closure mechanism identified within the

Fig. 13. (C/U) Erosive mound trap, (C/U) Erosive base mound, (C) Conformable top seal, (U) Unconformable bottom seal, Poly-seal. study region (Tables 1-3), example include closure within the Britannia (Oakman & Partington 1998), Everest and Fleming fields (O'Connor & Walter 1993).

220

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Fig. 14. (C/F) Channel with flank facies closure trap, (C) Sedimentary mounding enhanced by differential compaction, (F) Facies change induced by non reservoir/sealing levees, Poly Seal.

Fig. 16. (C/F) Facies change/waste zone traps, (C) Conformable top seal, (F) Facies change, Poly-Seal (modified after Milton & Bertram 1992).

moving proximal to the fault scarp e.g. Brae fields (Fraser et al. 2003; Harms et al. 1981).

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Fig. 15. (CICF) Pinchout/Shale out traps, (C) Conformable top seal, (CF) Conformable base seal with facies change, Poly-Seal (Milton & Bertram 1992).

C/F, Depositional facies change/Waste zone trap (Fig. 16) A poly-seal trap with closure provided by a conformable top seal along a single surface and a lateral seal occurring over a waste zone created by a degradation in reservoir quality;

Table 4 describes in qualitative terms the relative risking of the trapping models illustrated in this paper. A risk value of high to low has been applied to each of the models described in addition to a brief comment on the justification behind the risk rank. For the purpose of this illustration we are concerned only with the geometrical nature of the sealing surface with respect to the reservoir bounding surfaces, remaining purposely generic. Lithologies and properties of the seals have been neglected, although clearly the nature and combination of the seal lithology associations will have a strong control on sealing efficiency, providing an additional insight into sealing integrity when considered in relation to trapping mechanism.

Conclusions The sealing-surface classification concept and scheme initially proposed by Milton & Bertram (1992) provides a suitable framework for describing proven hydrocarbon accumulations which can be applied to similar un-drilled traps. Furthermore by considering the nature and

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g e o m e t r y of the sealing surface in relation to the reservoir/seal interfaces an assessment of risk is possible. Such a s c h e m e warrants revisiting as a useful tool for the c o n t i n u e d successful exploration for stratigraphic and stratigraphic-related traps in similar extensional settings. Thanks to Milton and Bertram for compiling the original scheme and concepts upon which this publication is based. Gratitude is extended to J. Argent and C. Oakman for their useful review and contributions which have greatly improved this manuscript. The paper represents work that contributed partly towards an MSc thesis on the 'Significance of Stratigraphic Trapping in the Britannia Satellites and Beyond, UK CNS' carried out over the summer of 2003 in fulfilment of the requirements for the MSc in Petroleum Geoscience (Imperial College, London). Mentorship by T. Evans (Imperial College) and ConocoPhillips UK individuals is gratefully acknowledged. Final thanks to S. Emberson for aid with references.

References AHMADI, Z.M., SAWYERS, M., KENYON-ROBERTS, S., STANWORTH,C.W., KUGLER, K.A., KRISTENSEN,J. & FUGELL1,E.M.G. 2003. Paleocene. In: EVANS, D., GRAHAM, C., ARMOUR, A. & BATHURST, P. (eds) The millennium atlas, petroleum geology of the central and northern North Sea, Geological Society, London, 235-260. 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.W. (eds) Petroleum Geology of North West Europe, Graham and Trotman, London, 533-548. BIDDLE, K.T. ~: WE1LCHOWSKY, C.C. 1994. Hydrocarbon Traps. In: MAGOON, L.B. & Dow, W.G. (eds) The petroleum system-from source to trap, American Association of Petroleum Geologists, Memoir 60, 219-235. 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 of London, 507-517. COPESTAKE, P., SIMS, A.E. CRITrENDEN, S., HAMAR, G.R, INESON,J.R., ROSE, RT. & TRINGHAM, M.E. 2003. Lower Cretaceous. In: EVANS,D., GRAHAM, C.,ARMOUR, A. & BATHURST,R (eds) The Millennium Atlas: Petroleum geology of the Central and Northern North Sea, Geological Society of London, 191-212. 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, Memoir, 14, 377-384. DIXON, R.J. & PEARCE, J. 1995. Tertiary sequence stratigraphy and play fairway definition, Bruce-

Beryl Embayment, Quadrant 9, UKCS. In: STEEL, R.J., FELT, V.L., JOHANNSSEN,E.P. & MATHHIEU, C. (eds) Sequence stratigraphy on the Northwest European margin. Geological Society, London, Special Publications, 94, 443-469. DORE, G. 2002. The Buzzard Field - A n overlooked North Sea giant, PETEX 2002 Exploration Session, Extended abstracts: PETEX 2002 CD-Rom, mk:@Store:D:\petex 2002.chm: /file0022.htm. FLETCHER, K.J. 2003. The South Brae Field, Blocks 16/07a,16/07b, UK North Sea. In: GLUYAS,J.G. & HICHENS, H.M. (ed.) United Kingdom oil and gas fields, commemorative millennium volume, Geological Society, London, Memoir 20, 211-221. FRASER, S.I., ROBINSON,A.M., JOHNSON,H.D., UNDERHILL, J.R., KADOLSKY, D.G.A., CONNELL, R., JOHANNESSEN, P & RAVNAS, R. 2003. Upper Jurassic. In: EVANS,D., GRAHAM,C., ARMOUR,A. & BATHURST, E (eds) The Millennium Atlas: Petroleum geology of the Central and Northern North Sea, Geological Society, London, 157-190. GAMBARO, M. & DONAGEMMA,V. 2003. The T-Block Fields, Block 16/17, UK North Sea. In: GLUYAS, J.G. & HICHENS, H.M. (ed.) United Kingdom oil and gas fields, commemorative millennium volume, Geological Society, London, Memoir 20, 369-382. 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. 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, Memoir 14, 339-345. GLUYAS, J. 2001. Upper Jurassic play fairways of the south Viking graben, Gluyas Petroleum Geoscience (commissioned for ConocoPhillips). GUNN, C., MACLEOD,J.A., SALVADORP. & 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, Memoir 20, 453-466. GUSCOTT, S., RUSSEL, K., THICKPENNY,A. & PODDUBIUK, R. 2003. The Scott Field, Block 15/21a, 15/22, UK North Sea. In: GLUYAS, J.G. & HICHENS, H.M. (ed.) United Kingdom oil and gas fields, commemorative millennium volume, Geological Society, London, Memoir 20, 467-482. HALBOUTY,M.T. (ed.) 1982. The deliberate search for the subtle trap, American Association of Petroleum Geologists, Memoir 32. HARMS, J.C., TAKENBERG,E, PICKLES, E. & POLLOCK, R.E. 1981. The Brae Oilfield area. In: ILLING,L.V. & HOBSON, G.D. (eds) Petroleum geology of the continental shelf of North-West Europe, Institute of Petroleum, London, 352-357. HARKER, S.D., GREEN, S.C.H. & ROMANI, R.S. 1991. The Claymore Field, Block 14/19, UK North Sea.

SEALING SURFACE CLASSIFICATION In: ABBOTFS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 269-278. JONES, E., JONES, B., EBDON, C., EWEN, D., MILNER, P., PLUNKETT, J., HUDSON, G. & SLATER, R 2003. Eocene. In: EVANS,D., GRAHAM,C., ARMOUR,A. & BATHURST,P. (eds) The millennium atlas, petroleum geology of the central and northern North Sea, Geological Society, London, 261-277. JONES, I.E, CHRISTENSEN,R., HAYNES,J., FARAGHER,J., NOVIANTI,I. & MORRIS, H. 2004. The Brenda field development: a multi-disciplinary approach, E A G E First Break, 22, 85-91. OAKMAN,C.D. 8~;PARTINGTON,M.A. 1998. Cretaceous. In: GLENNIE,K.W. (ed.) Petroleum geology of the North Sea, basic concepts and recent advances, 4th edn, Blackwell Scientific, Oxford, 294-349. O'CONNOR, S.J. & WALKER,D. 1993. Paleocene reservoir of the Everest trend. In: PARKER, J.R. (ed.) Petroleum geology of northwest Europe: proceedings of the 4th conference, Geological Society, London, 145-160. 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, Institute of Petroleum, London, 358-370. MCGANN, G.J., GREEN, S.C.H., HARKER, S.D. & ROMANI, R.S. 1991. The Scapa Field, Block 14/19, UK North Sea. In: ABBOTrS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 369-376. MILTON,N.J. & BERTRAM,G.T. 1992. Trap styles, A new classification based on sealing surfaces, The American Association of Petroleum Geologists Bulletin, 76, 983-999. MOSELEY, B.A. 1999. Downthrown closures of the Outer Moray Firth. In: FLEET, A.J. & BOLDY, S.A.R. (eds) Petroleum geology of Northwest Europe: Proceedings of the 5 th Conference, Geological Society, London, 861-878. MUNNS, J. & STOKER, S. 2003. UKCS: The future is stratigraphic!, Sharp IOR Newsletter, 2003, http://ior.rml.co.uk/issue5/articles/DTI_strat plays/ strat_plays.htm. NEWTON,S.K. & FLANAGAN,K.E 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, 161-171. OAKMAN,C.D. & PARTINGTON,M.A. 1998. Cretaceous. In: GLENNIE,K.W. (ed.) Petroleum geology of the North Sea: Basin concepts and recent advances, Blackwell Science, Oxford, 249-349. PARKER, R.H. 1991. The Ivanhoe and Rob Roy Fields, Blocks 15/21a-b, UK North Sea. In: ABBOTTS,I.L. (ed.) United Kingdom Oil and Gas Fields, 25 Years Commemorative Volume, Geological Society, Memoir 14, 331-338.

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PARTINGTON, M.A., COPESTAKE, P., MITCHENER, B.C. UNDERHILL, J.R. 1993. Biostratigraphic calibration of genetic stratigraphic sequences in the Jurassic-lowermost Cretaceous (Hettangian to Ryazanian) 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. RITTENHOUSE, G. 1972. Stratigraphic-trap classification. In: KING, R.E. (ed.) Stratigraphic oil and gas fields - classification, exploration methods and case histories, American Association of Petroleum Geologists Memoir 16, SEG Special Publication, 10, 14-28. ROOKSBURY,S.K. 1991. The Miller Field, Blocks 16/7B, 16/8B, UK North Sea. In: ABBOTrS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 159-164. ROSE, RT.S., MANIGHETrl,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, 255-264. SCHMITT, H.R. & GORDON, A.E 1991. The Piper Field, Block 15/17,UK North Sea. In: ABBOTrS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 361-368. 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, Memoir 14, 43-48. TURNER, C.C. ~; ALLEN, P.J. 1991. The Central Brae Field, Block 16/7a, UK Field North Sea. In: ABBOTrS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 49-54. WADDAMS, E ~; CLARK, N.M. 1991. The Petronella Field, Block 14/20b, UK North Sea. In: ABBOrrS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 353-360. WHITEHEAD,M. & PINNOCK, S.J. 1991. The Highlander Field, Block 14/20, UK North Sea. In: ABBOTTS, I.L. (ed.) United Kingdom oil and gas fields, 25 years commemorative volume, Geological Society, London, Memoir 14, 323-329. WRIGHT, S. 2003, The West Brae and Sedgewick Fields, Blocks 16/06a,16/07a,UK North Sea. In: GLUYAS, J.G. & HICHENS, H.M. (ed.) United Kingdom oil and gas fields, commemorative millennium volume, Geological Society, London, Memoir 20, 223-231.

West of Shetland revisited: the search for stratigraphic traps N. L O I Z O U 1, I. J. A N D R E W S 2, S. J. S T O K E R 2 & D. C A M E R O N 2

1Department of Trade and Industry, 1 Victoria Street, London S W 1 H OET, UK (e-mail: [email protected], uk) 2British Geological Survey, D TI Core Store, 376 Gilmerton Road, Edinburgh EH17 7QS, UK Abstract: The West of Shetland area has scope for the stratigraphic entrapment of hydrocarbons at various Jurassic to Palaeogene stratigraphic levels. Mapping and identification of such traps requires a fundamental understanding of the regional geology, the study of analogues and source kitchens, and a thorough approach to trap validation. Since 1982, 47 exploration wells have been positioned on Paleocene prospects with a significant stratigraphic component, but few have found hydrocarbons - many failing as a result of poor trap definition and overconfidence in the predictive use of amplitude anomalies. Hydrocarbon sourcing of many of the failed prospects was also poorly constrained. Few amplitude-related stratigraphic features could be tied with confidence to a viable source kitchen. The presence of a regional seal is a prerequisite ingredient for a successful Paleocene play. Many remaining undrilled, subtle prospects rely on a stratigraphic trapping component, and high-quality 3D seismic data are seen as an essential search tool. Examples of undrilled prospects are presented from the Paleocene of the northern Faroe-Shetland Basin and the Mesozoic of the East Solan Basin and Corona Ridge.

Between 1972 and 2003, 138 exploration wells were drilled in the West of Shetland area, U K Continental Shelf (UKCS) (Fig. 1), with an overall technical success rate of about 1 in 6 (Loizou 2003b). Unlike in the North Sea, where most wells have had structural targets, 47 exploration wells drilled West of Shetland are recognized to have targeted Paleocene traps with a significant stratigraphic component. For these wells, the success rate has been better than 1 in5. A prerequisite for a true stratigraphic trap is a porous and permeable reservoir, which passes laterally on one or more sides into a non-permeable rock by facies changes or pinchout. A classic regional setting for such a trap involves lateral pinchout of a sand facies at the margin of channel deposition. Pure stratigraphic traps are relatively rare, as some degree of structural closure is often evident. The angle of dip of the reservoir relative to the overlying top seal is an important factor in the trapping of significant hydrocarbons (Allan et al. 2006). The successful traps in the Foinaven, Schiehallion and Laggan fields (Fig. 1) have their reservoirs dipping up to 7 degrees steeper than their top seals. Using the exploration techniques available in the past, stratigraphic traps have proved extremely difficult to predict. Historically, most stratigraphic traps on the UKCS have been found serendipitously while drilling structural objectives. By analysing the results of the 47 Paleocene targeted wells, we can obtain a better

understanding of why the success rates for this play appear to have been relatively poor so far. The key question is, by using hindsight, how many wells can be said to have actually drilled valid traps? Furthermore, what is the success rate for wells drilled on valid stratigraphic traps? Can this lead to better expectation for the future? With on-going improvements in seismic technology, and a better u n d e r s t a n d i n g of what represents a valid stratigraphic trap, greater volumes of stratigraphically-trapped hydrocarbons will undoubtedly be discovered West of Shetland. This analysis uncovers some promising areas where the ingredients for potentially successful stratigraphic traps appear to come together.

Key elements for a Paleocene stratigraphic trap, West of Shetland

Trap definition The most important prospect-specific success factor is the presence of a reliable trap model (Loizou 2003a), in particular requiring the accurate prediction of the pinchout of reservoir sands. The ingredients that produce a good stratigraphic trap include the clear identification of reservoir, seal and source. When all these combine favourably with good quality seismic and other key data, then they produce a robust trap model with the optimum chance of success.

From: ALLEN,M. R., GOFFEV,G. R, MORGAN,R. K. & WALKER,I. M. (eds) 2006. The Deliberate Searchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 225-245. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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Fig. 1. Structural elements and main Paleocene depocentres, West of Shetland. The 47 wells used in the analysis of stratigraphic traps are shown in either blue (failure) or red (success). Figure 2 shows a simplified stratigraphic trap model for the Flett Sub-basin. Significant advances in 3D seismic technology in the 1990s have improved trap definition. However, trap definition could be further improved by enhanced processing techniques or the availability of new, purpose-designed, 'high resolution' 3D seismic data. There are, for example, potential sandstone reservoirs beneath the Paleocene T35-T36 regional seal (Ebdon et aL 1995; Fig. 3) that are almost sub-parallel to or have a low angle of dip relative to the seal, but these are difficult to interpret using early to mid 1990s 3D lower-resolution seismic data. Improved, high-resolution 3D seismic datasets should enable a more precise pinchout edge to be interpreted for these sandstone units.

Fig. 2. Simplified model of a West of Shetland stratigraphic trap in Vaila Formation sandstones.

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Reservoir presence In the early stages of West of Shetland exploration, when well control was limited, the first major challenge was to predict sandstone distribution (geographically and vertically) within the Paleocene Faroe-Shetland Basin. Now, with a portfolio of 138 wells (of which 129 have been released by 2004) and several regional studies (published and proprietary), the risk associated with this element of the trap is much reduced (e.g. Ebdon et al. 1995; Mudge & Bujak 2001). The Paleocene Vaila play in the Faroe-Shetland Basin consists predominantly of turbidite sandstone reservoirs in combination structural/ stratigraphic traps. All discovered Paleocene pools have been found in slope turbidites derived from the Scottish hinterland. R e s e r v o i r quality Good quality reservoir sandstones occur in many of the Paleocene sequences in the West of Shetland area. In the Flett Sub-basin, porosities range from less than 10% to greater than 30%, and permeabilities from 0.1 mD to 2 D (Fig. 4). Although there is an overall reduction of reservoir quality with depth of burial, certain sandstone units have retained high porosities (>20%) and permeabilities (10-100 mD) at burial depths below 3 km (Sullivan et al. 1999). Sandstones in the Paleocene T35 Vaila Formation in Laggan Field wells 206/1-2 and -3 have porosity and permeability preservation (or enhancement) at depth (Fig. 4). Although showing the same composition as the older sandstones here, the T35 sandstones are much better sorted, with ubiquitous chlorite grain coating (Sullivan et al. 1999). The presence of this coating appears to have prevented further quartz diagenesis and led to locally preserved, anomalously high porosities. In the adjacent Torridon area, wells 206/2-1 and 214/27-3 have poorer quality T35 sandstones, which are devoid of chlorite. Furthermore, between 150-200 m of tight, non-reservoir quality T25-T28 Lower Vaila Formation sandstones were also penetrated by these wells. The prediction of areas where reservoir quality is best preserved is a major challenge for continuing exploration, particularly in the deeper parts of the Faroe-Shetland Basin. Using the Laggan case, there is a strong relationship between high porosities and high seismic amplitudes; therefore true amplitude preservation is certainly an important element for predicting reservoir quality prior to drilling here.

Fig. 3. Summary of mid-Paleocene stratigraphy, West of Shetland, showing the Kettla Tuff Member and the regional seal.

Fig. 4. Simplified porosity-depth trends in Paleocene sands, West of Shetland (modified after Lamers & Carmichae11999).

Seal p r e s e n c e a n d effectiveness In the Flett Sub-basin, shales within the T35-T36 Vaila Formation sequence combine with the overlying Kettla Tuff Member to form an effective, basin-wide pressure seal (Lamers & Carmichael 1999). The Kettla Tuff is typically 10-50 m thick, while the underlying shales add up to a further 200 m to seal thickness (Fig. 5). A seal of equivalent age is also present in the Foinaven Sub-basin, but by and large it is less well defined there and much thinner (Fig. 3).

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The distribution of hydrocarbons within the Vaila Formation sandstones strongly relates to the extent of the T35-T36 regional seal. In general, an increase in aquifer pressure of 350-650 psi can be observed across the T31-T35 sequence over most of the Flett Sub-basin as in well 214/27-2 (Fig. 6). However, in both the 205/14-1 and -2 wells, where the Kettla Tuff is absent, the Paleocene sequence was normally pressured. The composition of the Kettla Tuff Member varies across the area, and S. Linnard (pers. comm.) interprets it as an influx of basalt outwash material rather than an airfall deposit. The gamma and velocity log responses for the Kettla Tuff are typified by well 206/1-3 (Fig. 5), whereas on the composite log section for well 205/9-1 (Fig. 7) the same sequence is partially described as 'coarse sandstone'. A map illustrating the extent of the Kettla Tuff (Fig. 8) has been constructed as a proxy for the T35-T36 regional pressure seal, and superimposed onto the underlying T34-T35 sand play fairway as an aid to understanding whether the . . .~. . . . .a va.u 1;a ..at,. ... we !!s were o pti mfi !!yl~. . ~. . . a .~u

Fig. 5. Summary of log responses and stratigraphy for the T35-T36 interval in the Laggan 206/1-3 appraisal well.

Fig. 6. Formation pressure data from well 214/27-2 in the Flett Sub-basin, providing an example of the raolnnnl

T'~lq n r a ~ ] l r ~

~onl

Fig. 7. Summary of log responses and stratigraphy for the T35-T36 interval in the 205/9-1 well.

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Fig. 8. Interpreted limits of the area with potential stratigraphic T34-T36 prospectivity. Pale shading colour key as in Figure 1. The map demonstrates that there is indeed a strong relationship between the extent of this seal and of hydrocarbon occurrences in the Faroe-Shetland Basin. However, this is only one stage in predicting the location of subtle hydrocarbon accumulations below that regional seal.

Source rocks and charge The UK Atlantic Margin is part of a passive continental margin that formed as a result of multiphase extension. This extension generated a complex assortment of rift basins during the Mesozoic and Tertiary. Because source rocks have been encountered in only a few of the wells, identifying and extensively mapping the

source rocks on seismic data remains problematic. As a result there have been no realistic estimates of the volumes of hydrocarbons generated and expelled in the area prior to the rifting phase. Nonetheless, the presence of source rocks is not a key geological constraint for the West of Shetland area. The Foinaven Sub-basin is underlain by source rocks of both Middle and Late Jurassic age (Fig. 9). Well data and geochemical modelling suggest that the pre-Tertiary strata initially reservoired oil and gas, but these traps were subsequently breached by later overpressuring caused by rapid burial in the Tertiary. Fields such as Foinaven and Schiehallion, which directly overlie pre-Tertiary fault blocks and lie

230

N. LOIZOU ETAL.

Fig. 9. Geological cross-section across the Foinaven and Flett Sub-basins. This section highlights the importance of the Westray Ridge and Westray Inversion in providing the regional charge/migration focus for the Quadrant 204 Paleocene oil accumulations. The prevalence of gas in the Flett Sub-basin is attributed in part to the presence of a thick Late Cretaceous basin, which developed above the Upper Jurassic source rock interval NE of the Westray Transfer Zone. Location of cross-section on Figure 8. Modified after Lamers & Carmichael (1999). on an inversion anticline, received multiple phases of charge (Iliffe et al. 1999). In the Flett Sub-basin there are only three notable Paleocene gas discoveries - 206/1-2 (Laggan), 214/27-1 (Torridon) and 214/30-1 (Laxford) mainly because a large number of wells have been positioned on invalid traps (Fig. 8). Since the work of Lamers & Carmichael in 1999, the understanding of source rock distribution and pre-Tertiary burial history still remain somewhat speculative. However, based on a number of wells that also encountered 'minor' gas shows within the Vaila Formation (Fig. 10), gas charge in the Flett Sub-basin appears to be persistent.

Direct hydrocarbon indicators (DHIs), amplitude anomalies (AAs), amplitude variations with offset (AVOs) and related geophysical features Given that true stratigraphic traps have little or no structural control, the location of drilling targets that contain convincingly predicted hydrocarbons has relied heavily on additional geophysical techniques, such as DHIs, flat spots,

AAs and AVO technology. AVO technology was introduced in the 1980s and became a primary c o m p o n e n t of seismic exploration West of Shetland throughout the 1990s until the present. Considerable financial investment has been put into AVO studies, and there has been much confidence in its ability to detect the presence of hydrocarbons in reservoirs (or at least to reduce prospect risk). A number of wells were drilled mainly on geophysical anomalies (Table 1). The AVO studies to date indicate that conventional D H I anomalies (soft amplitude anomalies conforming with structure) should be represented in typical hydrocarbon-bearing sands above 2000 m sub-sea-bed (Smallwood & Kirk 2005). Their detection should reduce the level of risk of any shallower prospect. The same studies suggest that D H I anomalies should not be expected below 2500 m (sub-sea-bed) in typical oil-bearing sandstones, or below 2700 m (sub-sea-bed) in typical gas-bearing sandstones. When so-called D H I anomalies are seen at depths of less than 2700 m, it could indicate particularly favourable conditions (e.g. anomalously high porosity reservoir as in the Laggan gas accumulation, the presence of gas, very good signal-to-noise ratio data, or very uniform rock

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Fig. 10. Flett Sub-basin hydrocarbon occurrence. Key: red = tested gas, yellow = gas shows, orange = interpreted gas, blue -- water-bearing, green = sand absent or not penetrated. properties), or it could indicate secondary effects associated with the presence of hydrocarbons (e.g. cementation contrasts near the hydrocarbon-water contact). In these circumstances of seismically invisible pay, the trap must be very well defined, as the level of risk will be much higher than for amplitude-supported targets. Amplitude anomalies are influenced by other factors, such as lithology, porosity, anisotropy, and also fluids. It would be incorrect to infer a direct link between amplitude anomalies and the presence of hydrocarbons.

Post-drill analysis of 47 West of Shetland wells A total of 44 exploration and three appraisal wells West of Shetland are considered to have targeted Paleocene traps with a significant stratigraphic component (Fig. 1, Table 1). In this postdrill analysis, wells were classed as a success if significant volumes of hydrocarbons were discovered. The description 'success' is defined here as a h y d r o c a r b o n accumulation that if tested would flow to surface. It does not necessarily indicate the commercial potential of the discovery. Analysis shows that all of the successful wells are located close to or at the basin margins, with seven discoveries located in the Foinaven Sub-basin (Foinaven, SE Foinaven, Schiehallion, Loyal, Alligin, Cuillin and Arkle) and a further three located in the Flett Sub-basin (Laggan, Torridon and 214/30-1). The Flett SubBasin discoveries all lie immediately west of the Flett Ridge (Fig. 1). Most of these discoveries have a northwesterly structural dip and are sealed up-dip by an E - W or N E - S W fault in combination with stratigraphic pinchout of the Vaila Sandstones.

The post-drill analysis of the failed wells forms the basis of this study (Table 1). Each well has been assessed in terms of the key stratigraphic trap elements (i.e. trap, reservoir, seal and charge). The key reason for most failures in both the Foinaven and Flett Sub-basins has been poor trap definition. However, many wells failed on a combination of geologic components (trap, reservoir, seal, and source). For this analysis, if the trap constituted more than 50% towards the well failing to find hydrocarbons then trap is assigned as the key element for failure. The majority of wells (84%) are deduced to have failed as a result of a poorly defined trap; 8% of the wells failed as a result of thin or absent reservoir, and 8% failed due to the seal being either thin or absent. Intriguingly, none of the wells specifically failed as a result of source rock absence. However, many poorly defined traps could also have failed due to lack of migration. Lamers & Carmichael (1999) published a similar analysis of the Foinaven Sub-basin wells, in which they showed the primary reasons for failure were 74% trap, 13% reservoir and 13% charge. Of the 37 failed wells, around 73 % were positioned too far up-dip to trap hydrocarbons, and about 27% were positioned down-dip of any trapping potential (Fig. 2). Quite surprisingly, none of the failed wells are considered to have tested what constitutes a valid stratigraphic trap (Fig. 8). A p p r o x i m a t e l y 39 wells were positioned on an amplitude or AVO a n o m a l y (Table 1). Of these, nine encountered notable hydrocarbons. Following post-mortem studies, the majority of the 30 wells that failed to find h y d r o c a r b o n s could be shown to r e p r e s e n t poorly u n d e r s t o o d amplitude anomalies (various lithologies including igneous), AVO artefacts and spurious DHIs (which also include

N. L O I Z O U E T A L .

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Table 1. Post-drill analysis of west of Shetland wells, which targeted Paleocene, traps with a significant stratigraphic component Well number

204/14-2 204/18-1 204/19-2 204/19-3 A 204/19-5 204/19-6 (Appr) 204/20-1 204/20-3 204/20-4 (Appr) 204/22-2 204/24-2Z (Appr) 204/25-1 204/25b-4 204/25b-5 204/26-1A 204/27a-1 205/8-1 205/9-1 205/10-2B 205/10-3 205/10-4 205/10-5A 205/12-1 205/14-1 205/14-2 205/14-3 205/17a-1 205/17b-2 206/1-1A 206/1-2 208/15-2 208/17-1 208/17-2 208/19-1 208/21-1 208/22-1 208/23-1 208/24-1A 208/27-2 214/24-1 214/27-1 214/27-2 214/27a-3 214/27a-4 214/28-1 214/29-1 214/30-1

Year

1998 2001 1991 1994 1995 1995 1993 1994 1995 1994 1992 1991 1995 1995 1995 1990 1996 1989 1984 1985 1997 1997 1995 1990 1996 1997 1995 1995 1985 1986 1995 1985 1995 1983 1985 1986 1983 1986 1982 1998 1985 1986 1997 2000 1984 1985 1984

Amplitude anomaly on 2D or 3D seismic

Success (with name) or failure

3D 3D 2d 3D 3D 3D 2d 3D 3D 3D 2d 2d 3D 3D 3D 2d 2d 2d

Failure Failure Arkle Cuillin Failure Alligin Schiehallion Loyal Failure Failure Foinaven Failure Failure SE Foinaven Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Laggan Failure Failure Failure Failure Failure Failure Failure Failure Failure Failure Torridon Failure Failure Failure Failure Failure Laxford

2d 3D 3D 3D 2d 3D 3D 3D 3D 2d 2d 3D 2d 3D 2d 2d 2d 3D 2d 2d 3D 3D

Reason for failure (key reason = X) Trap

multiples). A large n u m b e r of failed wells w e r e p o s i t i o n e d o n i n t e r p r e t e d A V O or high amplit u d e f e a t u r e s b e l i e v e d to c o i n c i d e with t h e t e r m i n a t i o n or up-dip l i m i t / p i n c h o u t e d g e of a s a n d s t o n e interval. F u r t h e r m o r e , w o r k c a r r i e d out by most c o m p a n i e s on these features

Reservoir

Seal

Charge

X X

X

X X X X X X X X x X X X X

x X X

x x x

X

x x x

X

x

X X

x

X X X X X X X X X X X X X X X

x X x x x

x

i m p l i e d that a h y d r o c a r b o n a c c u m u l a t i o n was p r e s e n t . For a n u m b e r of failed cases, the cause o f t h e A V O or high a m p l i t u d e f e a t u r e s was misinterpreted. C o m p l i c a t i o n s in A V O r e s p o n s e d u e to overlying c o n d e n s e d sections or variations in r o c k

STRATIGRAPHIC TRAPS, WEST OF SHETLAND property can significantly reduce or even destroy AVO responses. For example, Margesson & Sondergeld (1999) deduced that dry well 208/17-2 had drilled a manifestation of anisotropy and not a predicted hydrocarbonsrelated AVO anomaly. Hence AVO studies cannot be used as the only key measure of prospect risk, but they must be combined with other techniques. Foinaven displays a classic and easily understood Class 3 AVO response (E. Liu, pers. comm.), which, if seen within an exploration prospect, would be significant in reducing prospect risk. Foinaven is also an excellent example of a soft/negative acoustic response that increases with offset angle. However, in other cases in which hard shales overlay hard sands, the far offset is usually a negative response that actually dims with offset. Whilst explorationists normally appreciate the presence of higher porosity reservoirs, the downside for the Flett Sub-basin is that seismic anomalies generated by normal porosity sandstone containing hydrocarbons are indistinguishable from anomalously high porosity sandstone that is brine-filled. No pattern has yet been detected either in the geographical or stratigraphical distribution that would allow significant risk reduction of this 'False D H I ' phenomenon in the Flett Sub-basin. It is therefore difficult to separate out amplitudes associated with gas from those related to high porosities. In the right structural/stratigraphic context the A V O / D H I approach can be powerful, even without much geophysical understanding. Unfortunately, the majority of the failed well prognoses were more heavily influenced by geophysics-based deductions than by actual geology. There has been a proliferation of AVO analyses with too little focus on determining how the AVO anomaly is located with respect to receiving and trapping hydrocarbons. AVO methods can in certain cases add reliable constraints to quantitative reservoir characterization if underlying concepts and how to apply the technology is understood. Much of the AVO work was carried out on 3D seismic datasets that had angle offsets of up to 35 ~ (realistically reliable for AVO analysis to a sub-sea depth of approximately 2.1 km), which are not ideal for robust AVO studies. At least 75 % of the drilled AVO anomalies were at depths greater than 2.1 km subsea. For increased accuracy and confidence in AVO analysis, there is a need to acquire seismic data with offsets longer than 5 km. Despite the pitfalls, the use of AVO/DHI has been fairly widespread West of Shetland since the early 1990s. The optimal setting for the technique is for gas detection in shallow, porous,

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poorly consolidated clastic rocks of Eocene and Paleocene age. A good example where AVO has worked effectively is the Foinaven area, mainly because the burial depth here for the T31-T35 reservoir sandstones is generally less than 2500 m below sea-bed.

Examples of successful Paleocene stratigraphic traps It is significant to note that all the wells that have encountered hydrocarbons are associated with amplitude anomalies that, at least partly, conform to structure, e.g. Foinaven (Lamers & Carmichael 1999).

Foinaven Oil Field (discovery well 204/24a-2) The Foinaven/Schiehallion geological setting is unique in terms of hydrocarbon charge history, reservoir quality and trapping style (Figs 9 & 11). All the traps in the Foinaven Sub-basin are combined structural/stratigraphic traps (Cooper et al. 1999; Leach et al. 1999). The Vaila T35-T36 sequence, which includes the Kettla Tuff, provides an effective top seal across the subbasin, and all the significant discoveries have been made in the T31-T35 fairway directly underlying it. The hydrocarbon-saturated sandstones generate strong seismic amplitude anomalies, which help to define the extent of the traps (Lamers & Carmichael 1999), and hence the trapping mechanism, with a high degree of confidence (Fig. 12). On the seismic line through the 204/24a-2 discovery well, all the reservoir sandstones appear to pinchout in a similar position, but this is not generally true moving away from this location. As with all depositional systems, there is, of course, a structural control on the extent of the sands, which changes through time.

Laggan Gas Field (discovery well 206/1-2) Located in block 206/la within the Flett Subbasin, the Laggan gas accumulation represents an unusual example of a stratigraphic trap. Laggan was discovered in 1986 by well 206/1-2 (positioned on 2D seismic data), which encountered pay in T35 Vaila Formation sandstones. Ten years later, appraisal well 206/1-3 also found gas within the same reservoir sandstones 4 km to the SW. During 2004, Total drilled two successful appraisal wells (206/la-4A and 206/la-4Z) to further evaluate the potential Laggan gas accumulation. The 206/la-4Z well

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Fig. 11. Geoseismic section showing the position of the 204/18-1 Assynt prospect well (poor trap) and the up-dip Foinaven area 204/19-3A Cuillin well (good trap). Location of section shown on Figure 8.

tnc UlO-UqOl l J J l J t tu~ U I C ~aggan ~,~ accumulation is interpreted to be a pinchout of T35 Vaila Formation sandstones almost against a NE-trending set of growth faults (Figs 13 & 14). The faults appear to have influenced the geometry of sandstone deposition. Not surprisingly, the high amplitudes displayed on seismic data represent the extent of the high porosity sandstones, which terminate quite close to the west of the growth faults. Although a gas-water contact was established by well 206/1-3, giving the down-dip limits of the Laggan accumulation, the high amplitudes associated with the sands extend beyond the gas-water contact. This suggests that the amplitudes at least partly indicate the extent of high porosity sands, and not exclusively the occurrence of gas.

Examples of poorly defined traps and lack of reservoir

Fig. 12. (a) 3D seismic line through the Foinaven 204/24-2A discovery showing that hydrocarbonsaturated sands generate a strong seismic amplitude (coloured inversion of full stack in depth) courtesy of BP, (b) Geoseismic interpretation. Note that in other areas of the Foinaven Field, T35-T36 sandstones also contain hydrocarbons. tested at a rate of approximately 36 mmscfd, whilst the original discovery well flowed at 25 mmscfd.

The analysis of prospect failures highlights the inadequacy of trap definition in many cases. Two examples are presented below. Q u a d r a n t 205 N o r t h

In the southern Flett Sub-basin, wells 205/8-1, 205/9-1, 205/14-2 and 205/14-3 (Figs 7 & 15) were drilled on amplitude/AVO features predicted, pre-drill, to indicate the presence of hydrocarbons, but all of these features turned out to be lithology-related. Wells 205/8-1 and 205/9-1 were positioned using 2D data, while the

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Fig. 13. Amplitude and structure map over the Laggan gas discovery area, block 206/la. The highlighted area shows Total's current interpretation of sand extension. Courtesy of Total.

Fig. 14. Example 3D seismic line across the Laggan appraisal well 206/1-3.3D seismic line courtesy of Total. Location of section on Figure 13.

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Fig. 15. Geoseismic section through dry wells 205/9-1,205/8-1,205/14-3 and 205/14-2. Location of cross-section on Figure 8.

other two wells were located on the basis of 3D seismic data. Importantly, none of these wells were situated on what can in hindsight be described as a valid robust trap. There has been some ambiguity in the well correlations in the area, particularly of the T35-T36 sequence between 205/9-1 and 205/14-3. Well 205/9-1 encountered 425 m of good quality Paleocene Vaila T35-T36 Formation sandstones, whereas, well 205/8-1, located 8.5 km up-dip of this well only encountered 27 m of Vaila T35 sandstones. Well 205/8-1 is reported to have 'dubious minor oil shows' within the T36 and T38 sands (Smallwood et al. 2004). Further up-dip, well 205/14-3 failed to encounter any Vaila T35-T36 sandstones beneath what is described on the composite log as the Kettla Member. The lowermost 15-18 m of this 'Kettla' interval represents a tight sequence, which is considered as part of the regional seal. Interestingly, the T34-T35 Vaila Formation in the 205/91 well is overpressured by 363 psi (Lamers & Carmichael 1999), and the 205/8-1 well is also mildly overpressured beneath the regional T36 pressure seal. Well 205/14-3 had several RFTs taken from a 'sandstone unit' within the T36 Kettla Member interval, which not surprisingly indicate normal pressure. Intriguingly, the pinchout of the T35 Vaila Sandstones is inferred to be approximately 2 to 3 km down-dip of the 205/14-3 well. In contrast, the 205/14-2 (also 205/14-1) well, which lies beyond the regional pressure seal, is normally pressured. All four wells shown in

Figure 15 failed to locate hydrocarbons, but more importantly, none are positioned on a valid trap. Well 205/14-2 was unwisely located 3.5 km from and marginally up-dip of 205/14-1 and drilled the same play but on a brighter amplitude feature created by 'lithology tuning' (Smallwood et al. 2004). Not surprisingly, both wells were dry as, realistically, supplying these localized sands with hydrocarbons would be virtually impossible; vertical migration through more than 2500 m of underlying Cretaceous mudstones would be required. Additionally, they are cut off from the more likely migration of the main Vaila sandstone fairway encountered down-dip.

The A s s y n t prospect (well 204/18-1) The Assynt prospect in the Foinaven Sub-basin was largely based on amplitude analysis and was proven dry by well 204/18-1 in 2001. Pre-drill, the Assynt prospect was interpreted as comprising stacked sandstone intervals in the Upper and Lower T35 Sequence deposited as slope turbidites in three main channels orientated N-S, parallel to the structural dip (Fig. 16). The prospect was interpreted to be a direct fairway analogue to discoveries such as Foinaven. Compared to Foinaven, however, there was no evidence of true amplitude conformance with depth. The predominantly stratigraphic nature of the Assynt prospect relied heavily on the definition of a sealing mechanism. At the Foinaven and Schiehallion Fields, the existence of a thick

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Fig. 16. (a) Example 3D seismic line through the 204/18-1 Assynt well. Seismic courtesy of Veritas DGC. (b) Assynt amplitude anomaly map (red/yellow = high amplitude; blue/purple = low amplitude). (e) Contours in depth (m) to top Assynt amplitude anomaly.

and dominantly mud-prone T35 lowstand wedge provides a ubiquitous top seal. The location of Assynt suggested that it is downslope of, or even within the basinward equivalent of, this package. The T36 sequence would thus be required to provide the ultimate top seal to the Assynt prospect. Post-drill AVO analysis (E. Liu, BGS, pers. comm.) of the Assynt amplitude anomaly shows a fundamental difference to the operator's AVO analysis, which pre-drill suggested the presence

of hydrocarbons (Class 3 type AVO). On the near and mid offset stacks (375-2241 m) the Assynt amplitudes are quite strong; however, on the far offsets (2241-3174 m) the amplitudes are much weaker. The AVO and various attribute analyses conclusively show no evidence of hydrocarbon presence. More significantly, postdrill analysis of the Assynt amplitude anomaly identifies it as a Class 1 type AVO. In a geologic/geomorphologic context, the strong amplitudes are mainly confined to channels that

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show evidence for incision into the underlying strata. They are thought to record a significant contrast in rock properties between the highporosity channel fill and the surrounding sediments, but without supporting geological evidence this should not have been interpreted as conclusive proof of hydrocarbon charge in the prospect. Comparison of the regional setting of the Assynt prospect to the nearby Foinaven Field (Fig. 11) reveals a fundamental problem for the validity of the trap. Essentially, there is very limited scope for stratigraphic trapping potential. In order to trap the sizeable reserves that were anticipated for the Assynt amplitude anomaly, a significant sealing fault would have been required to prevent migration up-dip from Assynt along T34-T36 sandstones and siltstones directly into the Foinaven Field area. Furthermore, the sourcing for the Assynt prospect is less straightforward than at Foinaven, where large basin-marginal faults also provide a direct migration route from the underlying Middle to Upper J . . . . . . ;. . . . . . . . rocks (Figs 9 & 11).

basin-bounding faults, such as that defining the north-west of the Flett Ridge, acted as a focus for migrating hydrocarbons. Generally, the seal for all of the identified traps requires the pinchout reservoir sandstone to be encased in mudstone. The overlying Kettla Tuff and T35-T36 mudstones provide a regional seal to many oil and gas accumulations in the Faroe-Shetland Basin (e.g. Foinaven Field and Laggan gas accumulation). The nature of the underlying strata is less certain, but these are required to provide a bottom seal to prevent leakage up-dip of any mapped prospect to the SE. The quality of the bottom seal is thus the principal risk for this type of play. As previously discussed, the Paleocene regional seal causes the underlying succession to be overpressured by up to 650 psi above the hydrostatic gradient (Fig. 6). By and large, the seal thins gradually towards the SE onto the Flett Ridge; it also thins and onlaps the Corona Ridge to the NW of the basin. Analysis suggests that where the Kettla Tuff ~ - ;~ ~'" ~ , ~ is present, ,,,~'1,1~'r,ho~,,.l~ . . . . . . and Upper Cretaceous sediments below are likely to be overpressured. Overpressured rocks are prone to hydro-fracturing, providing potential

Identification of new stratigraphic concepts There can be little doubt that stratigraphic traps remain an attractive proposition West of Shetland, but finding and de-risking such traps requires improved, high quality, targeted 3D seismic data and a more comprehensive understanding of the local geology and rock physics. The examples reviewed below are based on the interpretation of mid-1990s 3D seismic data, which were less than optimally acquired to aid identification of subtle stratigraphic traps.

Paleocene stratigraphic traps A study area comprising fifteen UK blocks within the Flett Sub-basin was evaluated to investigate the potential for Vaila Formation sandstone stratigraphic plays beneath a regional intra-Paleocene unconformity. An example of an undrilled Vaila pinchout prospect is located on block 214/25 (Figs 17 & 18) and is described in more detail elsewhere (DT12004). Significant gas discoveries were noted in wells 206/1-2 and 214/27-1, and gas shows in several wells (Fig. 10) indicate that there is a strong likelihood of further gas accumulations in the Flett Subbasin. The majority of these gas indications lie on or immediately west of the Flett Ridge (Fig. 1). It appears that this Ridge and large

Fig. 17. Example of a potential untested Paleocene stratigraphic trap, located in block 214/25 in the Flett Sub-basin. Depths are in feet to a Paleocene intraVaila Formation event. The subcrop of this event beneath the regional seal has defined the limit of the prospect.

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Fig. 18. 3D seismic line showing a potential untested stratigraphic trap beneath the T36 regional seal in block 214/25. The target trap is defined by the pinchout up-dip of a Paleocene intra-Vaila Formation reservoir unit beneath the regional seal. Location of section shown on Figure 17. Released Shell seismic data, available from PGS Geophysical.

pathways for vertical migration from Jurassic source rocks into the sub-Kettla sandstone bodies. In this scenario, there may be no need for significant faults to be present. In the Flett Sub-basin study area, the NW trending Clair Transfer Zone (Rumph et al. 1993) could also have acted as a migration conduit. A good example is the 214/27-1 gas discovery, which confirms that migration of gas into closures distant from the Flett Ridge can take place. Individual gas accumulations, such as those in the lower Vaila Formation T25 sands in well 214/27-1, have been effectively sealed by intraformational claystones (Fig. 9), in this case forming a four-way closure over a NE trending shale diapir. Where prospects rely wholly or partly on stratigraphic trapping, the risk of

leakage through seismically unresolved sands is always present (even with high resolution 3D seismic data). Whilst only a few valid combination structural/stratigraphic traps have been drilled, the success rate of more than 50% for these has been relatively high. In the Flett Sub-basin, reservoir sandstones can occur throughout the Paleocene section. Their presence is not a critical factor for the study area, as reservoir is generally well calibrated and proven in nearby wells. The Upper Vaila F o r m a t i o n is relatively sand-prone in nearby wells, with up to 100 m of net sandstones. The anticipated reservoir depths for the Vaila sequence in the study area range from 2100 m to about 3200 m. Based on well control for this interval, the porosities are expected to range

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from 10-25% depending on the burial depth (Fig. 4). Not surprisingly, all reservoirs containing gas shows and significant reserves occur below the Kettla Tuff. These reservoirs range from lower Vaila Formation T22 sandstones that form the reservoir in the Torridon discovery well (214/27-1) to younger Vaila Formation T28-T35 sands that partly form the reservoir in the previously discussed Laggan discovery. Geochemical and well data indicate that the chief source rocks in the Faroe-Shetland Basin are Jurassic in age (Iliffe et al. 1999). These source rocks are predicted to be over-mature for oil generation in this part of the Faroe-Shetland Basin. They have generated gas, e.g. in the nearby Laggan discovery to the south, but cannot be readily mapped on seismic data. What is particularly interesting is that all the identified leads (not presented in this paper) are near down-dip faults, which have also served as conduits for the hydrocarbons.

Cretaceous stratigraphic traps The likelihood of finding commercial hydrocarbon accumulations within the Cretaceous interval relies heavily on identifying and accurately defining significant traps and good reservoir quality sandstones. Generally, three types of Cretaceous traps are recognized: 4-way dipclosed structures, fault-bounded three-way dip closures, and stratigraphic pinchouts. Unfortunately, there are no available analogues for Cretaceous stratigraphic pinchout traps, as none have been drilled West of Shetland. Nonetheless, potential does exist for Turonian Commodore Formation stratigraphic plays within the Faroe-Shetland Basin, with the main risks being reservoir presence and effectiveness. An example of a stratigraphic trap has been mapped immediately west of the Corona Ridge (DTI 2004), located on block 213/20 and adjacent blocks (Figs 19 & 20). This trap is interpreted to comprise basin-floor sandstones encased within basinal mudstones. The predicted reservoir sandstones are within a wedging unit towards the base of the Upper Cretaceous Shetland Group. Turonian sandstones are present in both of the nearest wells, 214/9-1 and 213/23-1, but it is not known whether these were derived ultimately from Greenland to the NW or from the UK landmass to the SE. The hydrocarbon source is expected to be mature Upper Jurassic Kimmeridge Clay Formation mudstones, which are predicted from seismic interpretation to occur down-dip to the NE. Overall, the structural configuration is conducive to hydrocarbon migration and

Fig. 19. Example of a potential untested Upper Cretaceous stratigraphic trap, west of the Corona Ridge and located mainly in block 213/20. Amplitude extraction map from the top of the Upper Cretaceous wedge, superimposed on depth contours (ft). High amplitude = blue/green, low amplitude -orange/brown; contour interval = 250 ft.

focusing towards the Corona Ridge. Top seal is provided by thick Upper Cretaceous (Shetland Group) mudstones. The nature of the up-dip fault seal is uncertain, but the presence of reservoir remains the principal risk for this prospect. Interestingly, there is a strong amplitude anomaly at the up-dip culmination of the mapped prospect, possibly implying the presence of gas, and providing a degree of confidence in the validity of the trap. Furthermore, there is a brightening of amplitudes above in the Eocene Balder Formation (Fig. 20), which could signify further evidence of an active hydrocarbon system. However, there are no obvious gas chimneys on the seismic data to suggest that the vertical seals above the Turonian target reservoir have been breached, either by fracturing associated with an episode of Oligocene inversion, or by capillary failure. The depth of the prospect (5360 m) is fairly significant in terms of reservoir quality. The 204/19-1 well penetrated an Upper Cretaceous reservoir with porosities ranging from 11-21% at 4000 m depth. With normal burial conditions, porosities ranging

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Fig. 20. Interpretation of 3D seismic line showing an example of a potential untested Cretaceous stratigraphic trap west of the Corona Ridge and mainly located in block 213/20. AA = amplitude anomaly. Location of seismic line on Figure 19. Seismic data courtesy of PGS Geophysical.

between 8-15% are expected for the 213/20 prospect. However, overpressuring is possible in this deep part of the basin that may have preserved better-quality porosity and permeability. Two further basin-floor fan prospects have been identified from seismic interpretation in a shallower depth setting (DTI 2004) within the Lower Cretaceous strata of the East Solan Basin (Figs 21 & 22). An upper fan unit is interpreted to be sourced from the Rona Ridge to the NW (Fig. 1), as suggested by the thickness distribution of the fan, and evidence of downcutting on the seismic data. Interestingly, the fan geometry is closely matched with low RMS amplitudes for this 'upper fan' interval (Fig. 21); a similar response is observed for the Upper Jurassic reservoir interval at the Solan oil discovery on the SW flank of the basin. Not surprisingly, because of the up-dip slope setting in the area, there are no Lower Cretaceous sandstones encountered within the Solan Field

wells. A lower and slightly deeper basin floor fan unit is also interpreted. The potential reservoirs in both fans are anticipated to be locally sourced from the Kimmeridge Clay Formation, with the principal risk being their lateral pinchout seal.

Potential Jurassic Stratigraphic Traps Overlying the eastern portion of the Strathmore Lower Triassic oil accumulation in block 205/26a (Fig. 1) is the oil-bearing basin-floor Solan Sandstone that sits within the Upper Jurassic Kimmeridge Clay Formation; the latter thickens and dips northeastward into the East Solan Basin. At the Solan Field (Figs 21 & 22), the Solan Sandstone forms a stratigraphic trap, onlapping and pinching out southwestwards against an intrabasinal high created by the Judd Transfer Zone, which separates the East Solan Basin from the South and West Solan Basins (Fig. 1; Herries et al. 1999). The oil in both the Strathmore and Solan

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Fig. 21. RMS amplitude map for a Lower Cretaceous 'upper fan' interval showing the Solan Field and Lower Cretaceous 'upper fan' prospect in the East Solan Basin (low amplitude = red/yellow, low amplitude = green/blue). Faults are shown in red. accumulations was generated in the East Solan Basin from the Kimmeridge Clay Formation. B o t h accumulations have similar oil-water contacts, and both share a heterogeneous oil

column that becomes richer in asphaltine with depth, possibly reflecting two h y d r o c a r b o n charges. The Solan Field forms a self-sourcing, self-sealing U p p e r Jurassic accumulation (Herries et al. 1999). Reservoir extent and prospectivity is predicted elsewhere in the East Solan Basin from the total Late Jurassic isochron. A potential Solan analogue prospect is interpreted in adjacent, unlicensed acreage (Figs 23 & 24). However, exploration for potential Solan analogues requires the presence of thick, Late Jurassic section as a possible indication that the thickening relates to the presence of Solan Sandstone. A combination structural/stratigraphic closure has been mapped at top Upper Jurassic level at the northeastern corner of the East Solan Basin in open block 205/27 (Figs 23 & 24; DTI 2004). The reservoir is prognosed to be composed of basin-floor fan sandstones of the Solan Sandstone. The wells in the Solan Field have encountered up to 30 m of reservoir, which is difficult to resolve on seismic data through normal interpretation. However, RMS amplitude extraction of the Upper Jurassic interval (Fig. 23) reveals an area of low amplitudes crossing the East Solan Basin that, by analogy

Fig. 22. 3D seismic line showing a basin-floor, Lower Cretaceous stratigraphic trap in block 205/27 in the East Solan Basin. Location of seismic line on Figure 21. Released BP seismic data.

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Fig. 23. (a) Two-way time map to top Upper Jurassic, showing the Solan Field and an undrilled Jurassic prospect in the East Solan Basin (shallow depth = yellow/red/green). (b) RMS amplitude map for the Upper Jurassic interval (low amplitude = red/yellow, high amplitude = blue/purple).

Fig. 24. 3D seismic line across an Upper Jurassic, Solan analogue prospect in the East Solan Basin. Location of seismic line on Figure 23a. Released BP seismic data.

with a comparable response at the Solan Field, is interpreted to indicate the presence of the Solan Sandstone. Interestingly, well 205/27-2, located 2 k m from

the identified prospect (Fig. 23), encountered a 10 m-thick basal U p p e r Jurassic sandstone with minor oil shows that was incorrectly ascribed to the Solan S a n d s t o n e on the c o m p o s i t e log.

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Instead, this unit is the R o n a Sandstone of probable shelfal origin, which typically has relatively poor reservoir quality. In contrast to the Solan Field and the prospect, the area around this well has high RMS amplitudes.

Conclusions The analysis of 37 failed wells shows that 84% were located on unreliable traps. Not surprisingly, those wells located on more reliable, robust structures achieved a higher success rate of approximately 60%. Therefore, the sound mapping of a valid trap is viewed as the key component to increasing exploration success West of Shetland. A key observation from the analysis of the wells indicates that many were not optimally positioned to test a valid stratigraphic trap. With this in mind, exploring for valid stratigraphic structures requires a great deal more care and an improved understanding of specific trap ingredients than are necessary to generate a successful structural trap. So what makes a valid hydrocarbon trap? A valid trap can be defined as a robust structural closure or a combination structural/stratigraphic or purely stratigraphic feature that can be m a p p e d with high confidence utilising good quality seismic and other key data. Without doubt, many of the failed Paleocene wells record a general lack of understanding of the occurrence of sandstone pinchout plays relative to the basinal setting and regional seal. The majority of the 37 unsuccessful wells failed to find hydrocarbons because there was no valid trap. Bearing this in mind, correctly identifying and confidently mapping robust stratigraphic traps should result in a much improved success rate. Evaluation of proven examples of successful P a l e o c e n e traps like Foinaven and Laggan, which have a strong stratigraphic component, can add to the understanding of why a large n u m b e r of stratigraphic wells have failed. A fundamental awareness of the key ingredients that constitute a successful stratigraphic trap will contribute to the success of future exploration. Utilizing the appropriate data, robust stratigraphic traps in Paleocene and older successions can be successfully mapped with a high degree of confidence. If all the ingredients that contribute to the making of a stratigraphic trap are present, then future exploration should be viewed more optimistically. The senior author (NL) would like to thank BP and Shell for giving permission to publish NL's postmortem analysis of the Assynt prospect. The authors

gratefully acknowledge Total for provision of the amplitude map and seismic line across the Laggan discovery. This paper is published with the permission of the Director of Oil and Gas Licensing and Exploration, Department of Trade and Industry and the Executive Director, British Geological Survey (NERC). The views expressed in this paper are mainly the opinions of the authors and are not necessarily those of the DTI.

References ALLAN, J., ROSEWAY,J. & SUN, S.Q. 2006. Evaluating risk factors and exploration/development strategies in stratigraphic and subtle traps. In: ALLEN, M.R., GOFFEY, G.E, MORGAN, R.K. & WALKER, I.M. (eds) The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 57-104. 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 ~.)UblK;Ly,bUIIUUII, U/ J--UOZ~. DEPARTMENT OF TRADE AND INDUSTRY.2004. Promote

United Kingdom 2004: Petroleum potential of the United Kingdom Continental Shelf. CD-ROM. 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. In: 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. 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. ILIFFE, J.E., ROBERTSON,A.G., WARD, G.H.E, WYNN, C., PEAD, S.D.M. & CAMERON, N. 1999. The importance of fluid pressures and migration to the hydrocarbon prospectivity of the FaeroeShetland White Zone. In: FLEET,A J. & BOLDY, S.A.R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 601-611. 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, 645-659. 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.

STRATIGRAPHIC TRAPS, WEST OF SHETLAND LoIzou, N. 2003a. Post-well analysis of exploration drilling on UK Atlantic Margin provides clues to success. First Break, 21, 45-49. LoIzou, N. 2003b. Exploring for reliable, robust traps is a key factor to future success along the UK Atlantic Margin. AAPG International Conference & Exhibition, Extended Abstracts with Program. MARGESSON, R.W. t~z SONDERGELD, C.H. 1999. Anisotropy and amplitude versus offset: a case history from the West of Shetlands. In: FLEET,A.J. & BOLDY, S.A.R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 634-643. 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. RUMPH, B., REAVES,C.M., ORANGE,V.G. & ROBINSON, D.L. 1993. Structuring and transfer zones in the Faeroe Basin in a regional tectonic context. In"

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PARKER, J.R. (ed.) Petroleum Geology of Northwest Europe: Proceedings of the 4th Conference. Geological Society, London, 999-1009. SMALLWOOD, J.R., KIRK, W.J. & PRESCOTt, D. 2004. Alternatives in Paleocene exploration West of Shetland: a case study. Scottish Journal of Geology, 40, 131-143. SMALLWOOD,J.R. • KIRK, W.J. 2005. Paleocene exploration in the Faroe-Shetland Channel: disappointments and discoveries. In: DORI~,A.G. & VINING, B. (eds) Petroleum Geology: North-West Europe and Global Perspectives: Proceedings of the 6th Petroleum Geology Conference, Geological Society, London, 977-991. SULLIVAN,M., COOMBES,Z., IMBERT,P. t~zAHAMDACHDEMARS, C. 1999. Reservoir quality and petrophysical evolution of Paleocene sandstones in the West of Shetland area. In: FLEET,A.J. & BOLDY, S.A.R. (eds) Petroleum Geology of Northwest Europe: Proceedings of the 5th Conference. Geological Society, London, 627-633.

Potential Eocene and Oligocene stratigraphic traps of the Rockall Plateau, NE Atlantic Margin D. B. M C I N R O Y , K. H I T C H E N

& M. S. S T O K E R

British Geological Survey, Murchison House, West Mains Road, Edinburgh EH9 3LA, UK (e-mail: [email protected], uk) Abstract: Following thermal uplift during the late Paleocene to early Eocene, the denudation of the subaerial hinterland provided a massive sediment supply that led to the development of a number of large, prograding sedimentary wedge systems flanking the Hatton and Rockall basins. Regional seismic data mapping and borehole data indicate that the wedges are Eocene in age and have a high percentage of coarse clastic material typical of highenergy, fluvial or near-shore marine environments. The prograding wedges have been mapped and can be viewed as large, clastic fairways within which trapping at a number of scales exists. Seismic interpretation suggests that the wedges are present at various stratigraphic levels within the Eocene and are locally separated by unconformities. However, all pre-date the margin-wide late Eocene unconformity (C30), which resulted in subsidence and deepening of the Rockall and Hatton basins. A marine transgression inundated most former land areas, and a marked change occurred in basinal facies; a change from fluvial/near-shore clastic sedimentation to deep-water mud and ooze deposition influenced by bottom-currents. These conditions persisted throughout most of the Oligocene and Neogene and hence provided a seal for potential hydrocarbon-bearing sand-prone Eocene reservoirs internal to the wedge-systems. Additional sealing potential may be provided by shale layers internal to the wedges. Buried Eocene pinchout lobes, submarine fans at the base of basalt scarp faces and Oligocene slump deposits also provide potential trapping mechanisms. High, and probably unacceptable, risks include biodegradation and poor seal development due to the typically shallow depth of burial of the wedges. However, the majority of the wedges should be treated as analogues, with some of the deeper examples providing some scope for consideration as exploration targets. The scale of the prograding wedge play fairway is massive, with volumes measured in tens of cubic kilometres.

Cenozoic post-rift sands are currently important targets for h y d r o c a r b o n exploration in the Atlantic Margin region of the United Kingdom Continental Shelf (UKCS). These targets have become more attractive as the U K sector of the North Sea oil province matures, and opportunities to discover large accumulations of oil and gas there decrease. Exploration of older and deeper plays is hindered by the presence of extensive Iceland hot-spot-related late Paleocene/early Eocene volcanics, which obscure the pre- and syn-rift geology on seismic records across large parts of the margin. Consequently shallower, and often subtle, stratigraphic traps have become favoured exploration targets in the A t l a n t i c Margin region. P a l e o c e n e and Eocene basin-floor-fan reservoirs are the principle target around the proven Foinaven and Schiehallion fields in the Faroe-Shetland Basin, and are potentially sealed by lowstand and highstand mudstones (Brooks et al. 2001). Currently attractive hydrocarbon targets in the Rockall and H a t t o n basins are Paleocene-Eocene postrift plays, in addition to Mesozoic tilted faultblock plays. In this paper we present examples

of potential stratigraphic traps identified in the H a t t o n - R o c k a l l area. The H a t t o n - R o c k a l l area is situated in the N E Atlantic Ocean between 450 and 1000 km west of the Scottish mainland (Fig. 1), and is comprised of the R o c k a l l P l a t e a u and the Rockall Trough bathymetric features. The crust underlying the area is continental, and is highly a t t e n u a t e d across the Mesozoic H a t t o n and Rockall basins. Thicker crust exists beneath the intervening H a t t o n and Rockall highs and at the inner continental shelf, while other highs are formed by several C r e t a c e o u s and Paleocene igneous centres. This configuration of basins and highs reflects the rifting and m a g m a t i s m t h a t occurred in the H a t t o n - R o c k a l l area throughout the Palaeozoic, Mesozoic and early Cenozoic, which ultimately led to the separation of Greenland and Europe along an axis further to the west in the early Eocene. Seaward dipping reflectors (SDRs) in the basalt sequence on the western flank of H a t t o n High sit above the approximate location of the continental margin. West of the S D R sequence, the crust thins to n o r m a l

From: ALLEN,M. R., GOFFEY,G. R, MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 247-266. 0305-8719/$15.00. 9 The Geological Society of London 2006.

248

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POTENTIAL TRAPS OF THE ROCKALL PLATEAU oceanic thicknesses and exhibits typical oceanic magnetic anomalies. The majority of the traps discussed in this paper are internal to prograding sediment wedges of Eocene age that have been identified on the margins of structural highs in and around the Hatton-Rockall area (Fig. 1). In this study, a prograding sedimentary wedge is considered to be a shallow-marine body of prograding clinoforms formed by the coalescence of a number of fan complexes fed by adjacent numerous small-scale sediment input points. The wedges are not major fans fed by a single, significant point source. Additionally, the term 'prograding sedimentary wedge' is applied to the coarse grained, marginal component of what are often larger depositional systems with muddier distal components. Where these systems are situated on the margins of structural highs (basement highs or igneous centres), their distal components have often collapsed into the basin, leaving their marginal components, or their prograding sedimentary wedges, perched and isolated above the basin. Other stratigraphic traps identified are submarine fans at the base of basalt scarp faces (base-scarp fans), up-dip pinchout lobes (also common to the prograding wedge play) and mass-flow slump deposits. The tectonostratigraphic setting, geometry and potential hydrocarbon prospectivity of these traps are the focus of this paper.

Dataset The Rockall Consortium (see acknowledgements for members) and BGS offshore mapping 2D seismic datasets were used to identify and map the prograding sequences on the slopes of the main structural highs in the Hatton-Rockall area. The Rockall Consortium 2D seismic dataset contains 14 900 km of high resolution and conventional seismic data shot by the BGS and other contractors for the Rockall Consortium in 1992, 1993, 1998 and 2000, plus 1700 km of conventional 2D seismic data acquired from Mobil (1989 vintage) and GEUS (1990 vintage), and is shown in Figure 1. The BGS offshore mapping dataset includes 2700 km of new data shot across the north Rockall Basin and north Hatton Bank in 2002. The prograding wedges have been sampled throughout the Hatton-Rockall area by BGS boreholes, BGS short sea-bed cores, DSDP (Deep Sea Drilling Program) boreholes (two of which are situated outside the extent of the BGS offshore seismic grid) and commercial wells, the location of which are shown in

249

Figure 1. Collapsed and distal components of the same depositional systems have also been sampled, although it is the coarse-grained and porous marginal prograding wedges that are the focus of this study. Table 1 summarizes the sampling of the Eocene prograding sedimentary wedges, and includes sample points of collapsed and distal components of the prograding system. Although lying outside the extent of the seismic grid, DSDP boreholes 405 and 406 have been included in Table 1 as they penetrated an Eocene prograding wedge on the southern flank of Edoras Bank on the SW Rockall Plateau.

Regional context Tectonostratigraphy o f the Rockall and Hatton basins Four Cenozoic post-basalt tectonostratigraphic intervals (megasequences) bounded by four regionally significant seismic reflectors have been identified within the Rockall Basin (Stoker et al. 2001; McDonnell & Shannon 2001; Stoker et al. 2005) and the neighbouring Porcupine Basin (McDonnell & Shannon 2001). The four megasequences in ascending stratigraphical order are RPd, RPc, RPb and RPa, each bound at their base by regional seismic reflectors C40, C30, C20 and C10 respectively (Fig. 2). Reflector C40 marks the base of megasequence RPd, and is an early Paleocene event which represents the top of the Cenomanian to Danian chalk succession in the Porcupine Basin. In the Rockall Basin, C40 is a continuous high amplitude reflection onlapped locally by less continuous reflections within the RPd megasequence (Figures 8-14). The RPd megasequence, of early Paleocene to late Eocene age, is bounded by C40 at its base and C30 at its top, and contains a tuffaceous muddominated Paleocene succession locally overlain by sandy Eocene intervals. These intervals are the prograding sedimentary wedges considered in this paper, which are only preserved within the Paleocene-Eocene RPd megasequence. Reflector C30 marks the top of the RPd and the base of the RPc megasequences, and is late Eocene in age. At the margins of the basin and adjacent to intrabasinal seamounts, C30 is a prominent angular unconformity and is expressed as a high amplitude reflection. This important reflector marks the rapid change in depositional style within the Rockall Basin in the late Eocene when rapid subsidence created the present day deep-water

250

D.B. MCINROY ETAL.

Table 1. Sample summary of the Eocene prograding sedimentary wedges within the Rockall Basin. Samples located in Figure 3 Sample site

Location

Prograding wedge

E Rockall Bank

Eocene sandstone

Prograding wedge

N Rockall Bank SE George Bligh Bank

Mid-Eocene sandstone Eocene sandstone overlain by Eocene limestone Mid-Eocene sandstone Mid-Eocene sandstone Terminated in Early Eocene detrital claystone at 407 mbsb Terminated in Middle-Eocene detrital claystone at 831.5 mbsb

Prograding wedge Prograding wedge

Eocene sandstone overlain by Eocene mudstone Early Eocene mudstone

Collapsed wedge

Early Eocene mudstone, mid-Eocene sandstone

Collapsed wedge

Early and mid-Eocene mudstone

Distal wedge

Eocene marls and mudstone Lower/Mid-Eocene mudstone and sandstone overlain by Mid-Eocene marls Eocene marls and limestone Lower Eocene sandstone and mudstone overlain by Mid-Eocene marls

Distal wedge Collapsed wedge

E Rockall Bank

BGS Borehole 94/3

E Rockall Bank

BGS Borehole 90/6 BGS Borehole 88/10 DSDP Borehole 405

Hebridean Margin Hebridean Margin SW Rockall Plateau

DSDP Borehole 406

SW Rockall Plateau

W Rockall Basin (E of Rockall Bank) BGS short sea bed core W Rockall Basin (E of Rockall Bank) 57-13/63,64,65 BGS short sea bed cores W Rockall Basin (N of Rockall Bank 58-14/29,30 and SE of George 58-14/54 Bligh Bank) BGS short sea bed cores 58-14/10,43 W Rockall basin 58-14/34 (SE of George Bligh 58-14/44,45 Bank) 58-14/53 Well 163/6-1 N Rockall Basin Well 164/25-1 Hebrides Slope

BGS Borehole 94/1

Well 164/25-2 Well 132/15-1

Component

Eocene sandstone, gravel and conglomerate Predominantly sandstone with gravel, conglomerate and volcaniclastic sandstone. Log summary given in Fig. 6.

BGS Borehole 94/2

BGS short seabed cores 57-13/77 57-14/43 BGS Borehole 94/6 BGS Borehole 94/7

Lithology

Hebrides Slope Hebrides Slope

basin (Stoker et al. 2005), thus m a r k i n g a change from fluvial/near-shore clastic sedimentation to deep-water m u d and ooze deposition influenced by bottom-currents. Post C30, the r e m a i n i n g Cenozoic succession consists of three megasequences: RPc (of Late Eocene to Early Miocene age), RPb (of Early Miocene to Early Pliocene age) and RPa (of Early Pliocene to H o l o c e n e age). These three megasequences and the intervening unconformities, C20 (Early Miocene) and C10 (Early Pliocene), preserve a record of shifts in sedimentation patterns and p a l a e o c e a n o g r a p h i c circulation that have occurred within the Rockall Basin in response to N e o g e n e tectonics, including (i) Early to

Prograding wedge

Prograding wedge Prograding wedge Prograding wedge Prograding wedge

Distal wedge

Collapsed wedge Distal wedge

M i d - M i o c e n e c o m p r e s s i o n and (ii) Early Pliocene epeirogenic m o v e m e n t s (Stoker et al. 2005). This paper focuses on the predominantly clastic sedimentation that occurred pre-C30. The Cenozoic stratigraphic terminology established for the Rockall and Porcupine basins may be applied to the H a t t o n Basin. A c o m m o n history of Cenozoic basin d e v e l o p m e n t has previously been proposed for the Rockall and Hatton basins (Roberts 1975; Stoker 1997), and is consistent with the results of this study, which suggests that the megasequences and unconformities identified on seismic data in the Hatton Basin display the same geometries, relationships and seismic character as those recognized in the

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Fig. 2. Stratigraphic nomenclature (megasequences and key reflectors) for the middle to upper Cenozoic succession in the Rockall and Porcupine Basins, based mainly on Stoker et al. (2005). For North Sea context, the sequence stratigraphy for the Late Paleocene and Eocene is given, after Mudge & Bujack (1994). Grey lithology: predominantly deep marine mudstone and ooze; yellow lithology: sands, gravels and conglomerates; red lithology: basalt complex. (R) reservoir; (S) seal. (1) as cored in BGS borehole 94/4 (Fig. 14); (2) as cored by BGS borehole 94/3 (Fig. 5). Timescale after Berggren et al. (1995).

Rockall Basin (Hitchen 2004). It should be noted that the Rockall High prevents direct correlation of reflectors from the Rockall Basin into the Hatton Basin; therefore, the Rockall Basin Cenozoic stratigraphic terminology has been tentatively applied to the Hatton Basin (e.g. ?C30 in the Hatton Basin is proposed to be the equivalent of C30 in the Rockall Basin etc.). However, the validity of applying the Rockall Basin scheme to the Hatton Basin is supported by D S D P boreholes 116 and 117, and O D P (Ocean Drilling Program) borehole 982 (a redrill of 116 at approximately the same location), which tested the Cenozoic succession in the Hatton Basin. The results from these boreholes

support the proposed correlation of the C10 and C30 reflectors. Borehole 116 terminated at 854 m below sea-bed in upper Eocene (NP19) limestones (Laughton et al. 1972; Berggren & Schnitker 1983) at about the level of the ?C30 reflector (Stoker e t aL 2001). Borehole 982 reached only 614.9m below sea-bed. In borehole 117, a marked downward change from Oligocene cherty limestones to Lower Eocene clays at approximately 150 m depth corresponds to the ?C30 reflector. The intra-Early Pliocene age for the ?C10 reflector is corroborated by boreholes 116 and 982, in which the ?C10 reflector was penetrated at approximately 120 m and 110 m below sea-bed respectively. These depths

252

D.B. MCINROY E T A L .

are within intervals designated as Early Pliocene in borehole 116 (Laughton et al. 1972) and borehole 982 (Jansen et al. 1996). The arrangement of megasequences and their dividing reflectors ?C10 and ?C30 is consistent with Palaeogene development of the southern margin of the Rockall Plateau (Bull & Masson 1996) and the Porcupine region, west of Ireland (McDonnell & Shannon 2001). Palaeogene palaeogeography

Two palaeogeographic maps (Figs 3 & 4) were compiled for the Hatton-Rockall area using well, borehole and short sea-bed core data from the BGS, industry, the Deep Sea Drilling Program (DSDP), the Ocean Drilling Program (ODP), the Irish Petroleum Infrastructure Programme (PIP) and universities. Rock types and seismic facies encountered in specific stratigraphic intervals were used to estimate the palaeobathymetry and type of environment that prevailed during that interval. Late Paleocene to Early Eocene. During the late Paleocene to early Eocene, volcanic activity associated with the opening of the North Atlantic Ocean and the Iceland hot spot resulted in extensive basalt lava flows covering most of the Hatton-Rockall area. Extrusive volcanic activity probably initiated as submarine eruptions, and a subsequent relative sea-level fall allowed volcanic centres and fissures to distribute basaltic lava flows subaerially over large areas. Epeirogenic uplift during the Paleocene may have been driven by a combination of transient dynamic support from abnormally hot mantle beneath the lithosphere and permanent uplift related to injection of melt into and beneath the crust (sills and underplating), both related to the Iceland hot spot (Clift & Turner 1998; Jones et al. 2001, 2002). Laterally continuous basalt scarps imaged on the seismic data are interpreted as palaeoshorelines, where the subaerial lava flows froze on contact with the sea-water and which would have formed rugged scarp faces of explosively-brecciated and pillowed basalt (Planke et al. 2000). An early Eocene sea-level rise is indicated by basalt scarp faces on Hatton Bank and Darwin igneous centre, as they are observed to step back from the basin as they become younger. Basalt scarp faces at various stratigraphical levels are not ubiquitous throughout the region, and deductions made about palaeo-sea-levels in any one area may not be applicable to the Hatton-Rockall region as a whole. However, in this study it is assumed that uplift was initiated

sometime in the Paleocene and that by early Eocene time, during the last phases of volcanic activity, the area was subsiding. This sequence of events is similar to those recorded in the Paleocene-Eocene sedimentary rocks of the North Sea (Milton et al. 1990; Neal 1996), thought to be caused by the inflation and deflation of the initiating Iceland plume swell (Nadin et al. 1995). Throughout the late Paleocene and early Eocene, sediments would have been generally supplied to the Hatton and Rockall basins from the exposed volcanic landscape. Repeated outpourings of lava would have continually mantled the deposits of previously eroded volcanic material, and the volcanMastic sediments would have frequently become interbedded with the lava flows. Identifying these deposits on seismic records is therefore difficult as the overlying basalt flows obscure the underlying geology. For this reason, the Paleocene interval is not dealt with in this paper, although it is acknowledged that it is probably the most iJiu~pective L. I.:.; I.I .U.L.U.I.~ . . . .I I.I .L .~ .; I.V.i .' I .I . 111 t l l l U re gion. It was not until volcanic activity had waned significantly or ceased altogether in the early Eocene that prograding wedges were deposited with no overlying basalt flows, and so are clearly visible on seismic records. Late Eocene (Fig. 3). Subaerial volcanic activity diminished across the Hatton-Rockall region during the early Eocene, as sea-floor spreading commenced along the newly-formed plate boundary west of Hatton Bank. Volcaniclastic material entered the Hatton and Rockall basins from still-exposed volcanic landscapes via prograding sequences of sand, gravel and conglomerate (Fig. 3). Table 1 summarizes the BGS boreholes and short sea-bed cores that have proven Eocene sandstones and conglomerates on the eastern flank of Rockall Bank and on the SE flank of George Bligh Bank. The prograding wedges are preserved at various stratigraphic levels within the Eocene, but are always below the regional intra-late Eocene ?C30 event. On the eastern flank of Hatton Bank, three prograding sequences have been identified which describe a retrogradational stacking pattern. This indicates that, overall, sea-level rose relative to Hatton Bank as the bank, and Hatton Basin, subsided during the Eocene. The transgression may have involved three still-stands, which allowed the sediments being supplied from the Hatton hinterland to build the three observed wedges in the accommodation space provided by the sea-level rise. A similar, but not identical,

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Fig. 4. Palaeogeographic map of the Hatton-Rockall study area for post-Late Eocene C30 event. (BBB) Bill Bailey's Bank, (GBB) George Bligh Bank, (LB) Lousy Bank, (RB) Rosemary Bank, (WTR) WyvilleThomson Ridge. configuration is preserved between the Swithin igneous centre (prograding wedge 5, Fig. 1) and Rockall Bank. Here, an older sequence has been observed prograding westwards from Rockall Bank, and a slightly younger sequence prograding eastwards from the Swithin igneous centre. This suggests that at some time during the Eocene, the drainage pattern on Rockall Bank changed such that it favoured sediment transport away from the western flank of the bank, while a sediment source was initiated on Swithin and progradation commenced eastwards. A possible cause for this change could be the eastwards tilting of the Rockall Bank and the gentle uplift of the Swithin igneous centre, which appears deeply eroded on seismic records. Mudge & Jones (2004) document short duration (< 1 Ma) sea-level fluctuations superimposed on the Paleocene-Eocene transgression cycle in the North Sea. Similar cycles may have affected the UK Atlantic Margin, and the stacking patterns of some of the wedges may be a record of this. However, the ages of the wedges are poorly constrained, making it difficult to date the significant boundaries of the wedge systems. Prograding wedges similar to those described above have been documented from the SW Rockall Plateau. Bull & Masson (1996) describe an early to mid-Eocene sediment wedge prograding out from Edoras Bank. The top of

the wedge is defined by their Reflector III (late Eocene and equivalent to ?C30), which correlates with a hiatus between the late and midEocene at DSDP borehole 405 and a hiatus between the early Pliocene and mid-Eocene at DSDP borehole 406. As with some of the prograding wedges described in this study, the prograding wedge of Bull & Masson (1996) downlaps onto the top of the Paleocene basalt surface (their Reflector IV) and thins out into the basinal area where the top of the wedge (?C30) eventually becomes conformable with the overlying and underlying sediments. In contrast, DSDP boreholes 405 and 406 sampled detrital claystones in the prograding wedge (Roberts et al. 1979) as opposed to the much coarser sands, gravel and conglomerates sampled by the BGS boreholes 94/3 and 94/7 on east Rockall Bank and SE George Bligh Bank respectively. This may simply be a material supply issue, although it does have serious implications for the trapping potential of the other, as yet unsampled, wedges throughout the Hatton-Rockall region. Post-Late Eocene C30 event (Fig. 4). In late

Eocene time, rapid, strongly differential subsidence resulted in kilometre-scale deepening of the Rockall and Hatton basins with respect to Rockall Bank and the UK continental shelf,

POTENTIAL TRAPS OF THE ROCKALL PLATEAU which culminated in sediment-starved deepwater troughs (Stoker et al. 2005). The subsidence may have occurred in response to upper mantle circulation, as a loss of dynamic support through the abandonment of an upwelling (Stoker et al. 2005). As a consequence of the Late Eocene subsidence, the previously exposed and eroding volcanic landscape was transgressed, shutting off the sediment supply to the prograding wedges and the top seal (Fig. 4), resulting in thin overburden over many of the wedges. Around the Hatton Basin, Eocene prograding wedges are locally preserved, either buried beneath deeper-water Neogene strata or still exposed at sea bed. The ?C30 event marks a significant change in depositional style from shallow water, near-shore clastic progradation and downslope deposition to fully marine oozes and clays deposited and re-distributed by bottom currents (Stoker et al. 2001).

Potential stratigraphic traps Prograding wedges Figure 1 shows the location of the fourteen prograding wedges mapped over the extent of the 2D seismic dataset used. The locations of the up-dip pinchout (Fig. 12), scarp fan (Fig. 13) and mass-flow slump deposit (Fig. 14) are also shown. The distribution of prograding units is that of coalesced sand and gravel fans shed from the highs that fringe the Hatton and Rockall basins. Geometrical properties of the prograding sedimentary wedges are summarized in

255

Table 2. Descriptions and seismic examples of five of the prograding sedimentary wedges are given below (wedges 1, 3, 5, 8 and 9). Wedges 1 and 3 were chosen because they have been sampled by the majority of boreholes and short cores that penetrated the Eocene succession; 5,8 and 9 were chosen on the basis that they are well imaged on seismic data and best demonstrate the varied geometries and geologic settings of the wedges.

G e o m e t r y and lithology Wedge 1 (Boreholes 94/2 and 94/3, east margin of Rockall Bank). BGS Borehole 94/3 penetrated the prograding wedge preserved on the eastern margin of Rockall Bank (Fig. 5). On seismic data, the wedge appears as a series of low to moderate amplitude reflections dipping away from Rockall Bank with dips greater than the general dip of the top basalt surface. Unconformities within the wedge are of slightly higher amplitude than the internal reflectors (Fig. 5), and have been confirmed by Borehole 94/3 at depths of 34.35 m and 135.94 m below sea bed (bsb) (Fig. 6). The wedge has an area of approximately 1600 km 2, although its extent has been limited by its position above a major basinbounding fault of the Rockall Basin and associated scarp face; as a result the distal portion of the wedge would have tended to become unstable and periodically collapsed into the Rockall Basin as slump deposits. Borehole 94/3, drilled to 209.65 mbsb, encountered an Eocene sequence of mainly sand, gravel and conglomerate interbedded with mud, a thick tuff layer and

Table 2. Summary of the geometricalproperties of the prograding sedimentary wedges identified in the Hatton-Rockall study area. Wedges located on Figure I Prograding wedge

Water depth (m)

1 2 3

300 300 530

4 5 6 7 8 9 10 11 12

530 600 550 1100 870 1200 770 860 1730

13 14

200 590

Area (km2)

Volume (km3)

Av. thickness (m)

Depth to top wedge (mbsb)

1599 131 82 At sea-bed 667 56 84 At sea-bed Not enough seismic coverage to estimate areas, volumes and average thicknesses 214 14 65 200 573 20 35 145 807 74 92 210 1916 61 32 At sea-bed 569 39 69 At sea-bed 1283 68 53 370 845 56 66 125 3273 206 63 At sea-bed Not enough seismic coverage to estimate areas, volumes and average thicknesses

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D.B. MCINROY E T A L .

Fig. 5. Illustrative sections through the prograding sedimentary wedge on the eastern margin of Rockall High. See Figure 6 for log of borehole 94/3.

POTENTIAL TRAPS OF THE ROCKALL PLATEAU

257

Fig. 6. Lithostratigraphic log of BGS Borehole 94/3, which continuously cored a prograding sedimentary wedge on the eastern flank of Rockall High. Nannoplankton zonation scheme (NP) of Martini (1971) is used. a single lava flow. The Eocene succession is underlain by submarine basalt and overlain by a veneer of Pleistocene to Holocene sediments (Fig. 6). The post-basalt section can be divided into upper, middle and lower packages, each separated by an unconformity, evident from the seismic data and n a n n o p l a n k t o n biostratigraphy. Together, the three packages define a

sediment wedge of latest Paleocene-middleE o c e n e age. Organic and shell debris were found within the sandstones in all three packages, an example of which is shown in Figure 7, where shelly bands are clearly observed within a sandstone core recovered from the lower package in B o r e h o l e 94/3. Visible porosity within the sands is high, as

258

D.B. MCINROY ETAL.

Fig. 7. (a) Photograph of coarse-grained sandstone unit recovered by BGS Borehole 94/3 from 140.62 m depth. (b) Thin section of coarse-grained sandstone unit recovered by BGS Borehole 94/3 from 136.14 m depth. Most of the grains are lithic fragments of basic volcanic material, with feldspar crystals evident within some grains. Minor amounts of quartz are also present. Blue colour represents porosity. illustrated by the thin section of a lower package sandstone in Figure 7, but has not been quantitatively measured.

Wedge 3 (Borehole 94/7 SE margin of George Bligh Bank). BGS borehole 94/7 penetrated a prograding wedge preserved on the southeast margin of George Bligh Bank (Fig. 8). On seismic data, the form of the wedge is defined by the top basalt reflector and the sea bed.

Internal reflections, although weak, show a consistent dip away from the top of the bank towards the Rockall Basin. The wedge is 26 km wide on the seismic section and, at its thickest point, is estimated to be 200 m thick. As is the case with the wedge preserved on Rockall Bank (Wedge 1), the width of the wedge has most probably been limited by the steep drop of the basalt surface that defines the extent of the bank. The wedge is overlain by a thin veneer of

POTENTIAL TRAPS OF THE ROCKALL PLATEAU P l e i s t o c e n e - H o l o c e n e sediments. B o r e h o l e 94/7, projected onto the seismic section (Fig. 8), recovered middle E o c e n e bioclastic, porous, carbonate-rich sandstone with shelly fragments overlying a basal sandy gravel layer, in turn overlying Paleocene basalt.

Wedge 5. BGS seismic line 00/01-1 imaged a sediment wedge prograding away from the Swithin igneous centre into the small depocentre between the Swithin and Rockall Bank

259

(Fig. 9). The wedge is identified from low-angle internal reflections of low to moderate amplitude consistently dipping away from the Swithin igneous centre. The wedge has an area of 573 km 2. It extends 17 km from the Swithin centre and at its thickest point is estimated to be 85 m thick on the seismic section (Fig. 9).

Wedge 8. BGS seismic line 00/01-5 imaged a sediment wedge prograding away from Sandarro igneous centre (Fig. 10). I n t e r n a l

Fig. 8. Illustrative seismic line BGS92/01-38 across a prograding sedimentary wedge on SE George Bligh Bank. See Figure 1 for location.

Fig. 9. Illustrative seismic line BGS00/01-01 across a prograding sedimentary wedge to the SE of Swithin igneous centre. See Figure 1 for location. Top and base of wedge indicated by black picks.

Fig. 10. Illustrative seismic line BGS00/01-05 across a prograding sedimentary wedge to the east of Sandarro igneous centre. See Figure 1 for location.

260

D.B. MCINROY ETAL.

reflectors are weak, but, where apparent, dip away from Sandarro. The wedge is preserved at the sea bed, having been submerged at the end of the Eocene and kept clear of subsequent mud deposition by bottom current activity. The wedge appears to overlie a thin succession of post-lava sediments. The area of the wedge is 569 km 2. The wedge is at least 11 km wide and at its thickest point estimated to be 140 m thick on the seismic section (Fig. 10).

Wedge 9. BGS seismic line 00/01-45 imaged a sediment wedge prograding away from the Lyonesse igneous centre (Fig. 11). Internal reflections are strong, and dearly prograde away from Lyonesse towards the Hatton Basin. The wedge has an area of 1283 km 2. The wedge is 5.5 km wide and at its thickest point estimated to be 200 m thick on the seismic section (Fig. 11). The width of the wedge is again limited by the steeply sloping edge of the Lyonesse igneous centre.

Other stratigraphic traps Up-dip pinchout lobes BGS seismic line 00/01-56 imaged an up-dip pinchout of the Eocene sequence. The pinchout is preserved below the bathymetric channel separating the Rockall and George Bligh Banks (Fig. 12). This sequence of reflectors display a mounded geometry rather than a basinward dip. The mounded pinching-out geometry of the

probable Eocene sequence at this location may represent a unique example of material that was derived from prograding wedges perched high on George Bligh and Rockall banks, and subsequently reworked in the channel between the two banks. Towards the up-dip pinchout, there are a number of amplitude anomalies within the Eocene succession and the amplitude of the reflectors diminishes down-dip towards the west. This change in amplitude may have two explanations. The first is that trapped hydrocarbons are causing the amplitude anomalies in the east of the section, whereas in the west of the section the hydrocarbons have migrated to the surface via the obvious accommodation faulting affecting the post-Eocene succession. The second explanation is that the accommodation faulting caused dispersal of the seismic energy and as a consequence all reflectors below the faulting appear weaker. The second explanation is the more likely, as the top of the pinchout is at 425 m depth below sea bed, and as a trap would be open to biodegradation and have poor ~L, a J

ulL~llty.

Submarine fan at base of basalt scarp (below Wedge 9) BGS seismic line 93/02-C imaged an Eocene scarp fan preserved at the base of a basalt scarp (Fig. 13). This unit lies at a depth of 1300 m below sea bed at the base of the steep basalt slope marking the extent of the Lyonesse

Fig. 11. Illustrative seismic line BGS00/01-45 across a prograding sedimentary wedge to the SE of the Lyonesse igneous centre. See Figure 1 for location.

POTENTIAL TRAPS OF THE ROCKALL PLATEAU

261

Fig. 12. Illustrative seismic line BGS00/01-56 across an up-dip Eocene pinchout structure to the north of the Rockall High. See Figure 1 for location.

Fig. 13, Illustrative seismic line BGS93/02-C across a base of basalt scarp fan to the SE of the Lyonesse igneous centre. See Figure 1 for location.

igneous centre. It is suggested that such fans might occur at the bases of the basalt slopes elsewhere over the H a t t o n - R o c k a l l region. The top of the fan is observed rising to terminate against the steeply-dipping top basalt surface, while towards the basin the top fan surface becomes conformable with the basin fill. A variation in amplitude is observed within the fan.

Next to the scarp, amplitudes are higher than on the correlative reflectors further away from the scarp. This may reflect a heterogeneity in the sediment character of the fan sediments near the scarp, which are speculated to be a stack of sands, gravels and muds as opposed to homogeneous, mud prone, sediments further from the scarp.

262

D.B. MCINROY ETAL.

Upper Oligocene mass f l o w deposits A possible post-Eocene stratigraphic trap analogue has been identified on the eastern margin of Rockall Bank in the form of an upper Oligocene mass-flow slump deposit (Fig. 14). The slump deposit is currently preserved at the sea bed below Rockall Bank, having been derived from the top of Rockall Bank and redeposited as a fan on the NW flank of the basin. BGS Borehole 94/4 terminated at 59 mbsb after penetrating upper Oligocene, porous, bioclastic sandstones containing scattered terrigenous components, the upper 25 m having been reworked during the Neogene. The age of the deposit is constrained by 87Sr/86Sr age dating (Darbyshire 2001). The Oligocene sands have a very high porosity, evident in a core sample and thin section of sandstones recovered from the borehole (Fig. 14).

Hydrocarbon prospectivity Source rock The timing of rift phases within the Hatton and Rockall basins is under debate, and is critical to the source rock potential of the two basins. Obviously, if there has been no pre-Cretaceous rifting in the Hatton and Rockall basins then there is limited potential for Jurassic source rocks. It is therefore necessary for Cretaceous and Cenozoic marine mudstones to be mature if a working petroleum system is to be present. On the other hand, some authors suggest that a preCretaceous rift basin underlies the present day Rockall Basin, based on crustal reconstructions of the North Atlantic region (e.g. Cole & Peachey 1999; Nadin et al. 1999; Butterworth et al. 1999). Other evidence for pre-Cretaceous rifting in the Rockall Basin comes from structural modelling across the Irish Rockall Basin (Walsh et al. 1999), identification of deep NNEtrending structural trends (Waddams & Cordingley 1999), backstripping modelling (Shannon et al. 1999), rifting patterns in the adjacent Erris Basin (Dancer et al. 1999) and seismic and potential field data analysis (Corfield et al. 1999). If pre-Cretaceous rifling in the Rockall Basin did occur, then Jurassic source rocks may be distributed within sub-basins in the Rockall Basin. Maturity modelling by Nolan et al. (1999) indicates that the upper part of the preCretaceous section in the NE Irish Rockall Basin area is currently within the mid- to late oil window. No basin-wide source rock has yet been proven in the Rockall and Hatton basins. However, the recent Dooish discovery NW of the Erris Ridge within the eastern margin of the

Rockall Basin, occasional gas chimneys and seep data (Hitchen 2004) suggest that working source rocks exist in some parts of the Hatton and Rockall basins.

Reservoir (Late Eocene prograding wedges) Figure 2 summarizes the stratigraphic occurrences of the traps identified in this study. The prospectivity of the prograding wedges, stratigraphic pinchouts, scarp fans and slump deposits is low. These features are perhaps best viewed as analogues for more deeply buried potential traps in other areas of the Atlantic Margin. Low prospectivity is mainly due to their shallow depth of burial where poor seal integrity and biodegradation are two major risks. Biodegradation will occur in oils that are expelled from source rocks at temperatures of 100-150 ~ then migrate to reservoirs cooler than 65 ~ (Connan 1984). Assuming a geothermal g r n d l o n t a f " ~ o(', km.1 and a sea bed temperature of 5 ~ the 65 ~ isotherm will be at a depth of 1700 m below sea bed. This is 400 m deeper than the deepest stratigraphic trap (the base of basalt scarp fan) presented in this study. Therefore, oil present in any of the traps will have undergone biodegradation. A mixture of fresh oil and biodegraded oil may be present in some of the deeper traps if fresh oil is assumed to be continually entering the traps. A presentday source kitchen would satisfy this requirement if viable migration paths to the traps from the kitchen areas are present, although sealing faults would be a large risk to charge. The argument for any of the prograding wedges being viable stratigraphic traps in their current situation is extremely weak. However, the wedges, fans, pinchouts and slumps identified serve as analogues for comparison, and do have some favourable reservoir characteristics such as high porosity and permeability, as well as large volumes in the coalesced prograding units. Visual porosity in thin sections of Eocene and Oligocene sands from BGS boreholes 94/3 and 94/4 (Figs 5 & 14) is high. However, in wedges or slump deposits that have been buried deeper, porosity will have been lost through compaction and the diagenesis of the feldspar-rich volcanic mineralogy to clay. Porosities of early Cenozoic sands have been measured elsewhere in the Rockall region. Well 154/3-1 on the Hebridean shelf encountered Eocene sands with an overall sonic log-derived porosity of 29%. Also on the Hebridean shelf, well 164/25-1 encountered Paleocene sands with an overall porosity of

POTENTIAL TRAPS OF THE ROCKALL PLATEAU

(c)

263

(d)

Borehole 94/4 31.32 m

Fig. 14. (a) Map based on Central Rockall Basin Solid Geology 1:500,000 Offshore Map Sheet (Stoker 2002). (b) Illustrative seismic line BGS92/01-46 across an Oligocene mass-flow slump deposit to the NE of the Rockall High. (e) Photograph of bioclastic sandstone core recovered from BGS Borehole 94/4 from 31.45 to 31.54 mbsb depth. (d) Thin section of bioclastic sandstone recovered from 31.32 mbsb depth. Grains are predominantly broken shell fragments. Blue colour indicates porosity.

264

D.B. MCINROY E T A L .

Table 3. Summary o f hypothetical recovery from traps internal to the prograding sedimentary wedges based on stated assumptions on net to gross, porosity and recovery Prograding wedge play fairway

1 2 4 5 6 7 8 9 10 11

Total volume of wedge (km3)

Volume of potential sandy reservoir assuming net:gross of 20% (km3)

Volume of potential pore space assuming porosity of 20% (km3)

Corresponding volume of trapped oili (Bbl • 106)

Potential reserves assuming 20% recovery (Bbl x 106)

131 56 14 20 74 61 39 68 56 206

26.2 11.2 2.8 4 14.8 12.2 7.8 13.6 11.2 41.2

5.24 2.24 0.56 0.80 2.96 2.44 1.56 2.72 2.24 8.24

16479 7044 1761 2516 9309 7673 4906 8554 7044 25914

3296 1409 352 503 1862 1535 981 1710 1408 5182

1When estimating volumes of potentially trapped oil, the porous space has been assumed to be half filled to approximate the fact that potential traps are internal to the wedges, and will be of smaller volume than the total gross rock volume.

22%. Well 164/25-2 e n c o u n t e r e d Oligocene sands with an overall sonic log-derived porosity of 14%, and a net to gross ratio of 0.7. Table 3 summarizes the hypothetical volumes of oil that could be extracted from traps internal to 11 of the wedges identified. It is speculated that the wedge fairways could contain a number of potential traps. Therefore, to account for this, the porous space has been assumed to be half filled to approximate the fact that potential traps are internal to the wedges and will be of smaller volume than the total gross rock volume. Seal

Potential seal rocks capping the E o c e n e prograding wedges are the basinal mudstones deposited in the H a t t o n and Rockall basins after the C30 drowning event (Fig. 2). This obviously does not apply to the very shallowest wedges preserved at higher levels where they outcrop at the sea bed (e.g. Figs 5 & 10). The typical depth of burial of the wedges is only a few hundred metres below sea bed and the deepest unit identified, a submarine fan at the base of a basalt scarp, occurs at 1300 m (Fig. 13). This may be too shallow for efficient seals to develop due to the lack of compaction. Shales internal to the wedges (like those recovered by BGS b o r e h o l e 94/3, Fig. 6) may provide additional sealing potential (Fig. 2).

Conclusions (1) The post-rift development of the HattonRockall area has resulted in several potential stratigraphic traps, including prograding sedimentary wedges, basalt scarp-base fans, up-dip pinchouts and massflow slump deposits. (2) Lithological information indicates a coarse clastic component to many of the wedges and mass-flow slump deposits, which commonly contain gravel and conglomerate in addition to sandstone. (3) Late Eocene differential subsidence caused a change in the sedimentary and oceanographic regime from shallow-water, nearshore clastic progradation and downslope deposition to fully marine ooze and clay deposition susceptible to re-distribution by bottom currents. Seal potential is provided by these deep-water clay deposits, although seal integrity is an issue at the shallow depths considered in this paper. (4) The h y d r o c a r b o n potential of the prograding wedges is low, and they are best viewed as analogues. This is mainly due to their shallow depth of burial (less than 1500 m), in which the biodegradation of hydrocarbons and seal integrity risks become high, and probably commercially unacceptable. (5) There is limited scope for working seals above some of the deeper wedges and scarp

POTENTIAL TRAPS OF THE ROCKALL PLATEAU base fans. Visible porosity is high in the s a n d s t o n e cores r e c o v e r e d from the prograding wedge preserved on the eastern flank of the Rockall Bank. Additionally, the scale of the prograding wedges is massive (typically 60 km3). These are favourable reservoir characteristics which may be shared by other, more deeply buried sedim e n t a r y wedges in the H a t t o n - R o c k a l l area and along the n o r t h e a s t Atlantic Margin. We wish to thank the past and present members of the Rockall Consortium for permission to use seismic and borehole data acquired during their membership. Present members: Chevron, DTi, ENI, Shell, Statoil. Past members: Agip, Amerada Hess, Arco, BP, Conoco, Elf, Enterprise, Esso, Exxon-Mobil, Philips, Total-Fina-Elf, Texaco. We also thank E Darbyshire (NERC Isotope Geosciences Laboratory) for the Sr isotope study of a sample from BGS borehole 94/4, and S. Archer (University of Aberdeen) for reviewer's comments. This paper is published with the permission of the Executive Director of the British Geological Survey (NERC).

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The variability of turbidite sandbody pinchout and its impact on hydrocarbon recovery in stratigraphically trapped fields ANDY

R. GARDINER

Institute o f Petroleum Engineering, Heriot-Watt University, Edinburgh EH14 4AS, UK (e-mail: andy.gardiner@pet, hw. ac. uk) Abstract: Stratigraphic trapping is an important component of many hydrocarbon fields reservoired in deep-water, turbidite deposits. The trapping may occur at channel margins, onlap surfaces and when turbidite sandbodies exhibit lateral variations in sand quality and/or bed thickness. The range of geometries occurring at these sandbody terminations has been the subject of detailed previous research and a number of classification schemes have been proposed. A single classification scheme, based only on the geometry of the sandbody and individual sandstone beds, is proposed here. The different geometries of sandbody termination or pinchout will have an impact on both the static and dynamic behaviour of hydrocarbon reservoirs. Dynamic simulation of a range of models of sandbody pinchout by onlap indicates that the recovery factor of stratigraphically trapped fields will be influenced by a range of geological and engineering parameters. Producing wells positioned too far from the sandbody termination run the risk of leaving behind significant volumes of up-dip oil. If wells are moved closer to the sandbody termination, they may intersect the onlap surface, and so not penetrate the lowest sandstone beds. In systems with a low effective vertical permeability, oil from these lower beds may not be efficiently produced. In this case, the optimum well location, in terms of recovery factor, is close to the initiation of onlap. Unfortunately, this position may be difficult to identify in the subsurface without the drilling of many appraisal wells. Variation in a range of parameters has been modelled, in order to examine their impact on hydrocarbon recovery. For layered sand/shale successions, with low effective vertical permeability, the initiation of onlap, and therefore the optimum well location, moves further from the onlap termination as the angle of onlap decreases. The maximum recovery factor is also lower for the lower onlap dips, as a greater volume of the reservoir lies updip of the producer at its optimum location. If individual sandstone beds thin towards the onlap, the volume of oil which might be left up-dip of producing wells is reduced, so that the risk in placing a well away from the sandbody termination is lower. The degree of trapping of hydrocarbons in the lower layers, as the producing well location moves onto the onlap surface, depends on the effective vertical permeability of the sandbody. If the vertical permeability is zero (as would be the case for a perfectly layered system with continuous sealing shales) no oil will be produced from the lower layers. As the vertical permeability is increased, fluids are able to flow vertically from these beds into higher beds and thence to the producer. The trapping potential is significantly reduced for kv:kh ratios of 2 x 10-5 or more, which is equivalent to an effective kv of 0.01 mD for a kh of 500 mD. In layered turbidites, this effective kv could be produced by 2 m thick sandstone beds, with a kv of 400 mD, interbedded with thin, non-sealing siltstones or silty shales, with permeabilities of the order of 10-4 mD. In practice, the effective kv:kh ratio of interbedded turbidite sandstones and shales is greatly influenced by the local erosion of the shales. Flow simulation through models representing various proportions of shale removal indicates that significant trapping of hydrocarbons in the lower layers may occur for proportions of shale removal below 15 %. Above this value of shale removal, little trapping occurs, as fluids are able to move sufficiently easily between the individual sandstone layers. These results suggest that the risk of reduced hydrocarbon recovery, as producing wells are moved closer to the onlap termination, are significant only in the case of well-layered reservoirs with low proportions of shale removal and sand-bed amalgamation. Examination of available core should enable the proportion of bed amalgamation, and therefore the risk of reduced recovery, to be evaluated for a stratigraphically trapped reservoir of this type.

In r e c e n t years, as m a n y p e t r o l e u m p r o v i n c e s h a v e r e a c h e d m a t u r i t y a n d m a n y of t h e seismically a p p a r e n t s t r u c t u r a l t r a p s h a v e b e e n drilled, t h e s e a r c h for s t r a t i g r a p h i c t r a p s has

b e c o m e m o r e i m p o r t a n t . A s is d i s c u s s e d in m a n y p a p e r s in this v o l u m e , s t r a t i g r a p h i c t r a p s c a n t a k e m a n y forms. T h e m o s t o b v i o u s a r e d u e to lateral v a r i a t i o n s in lithology, as o c c u r s in t h e

From: ALLEN,M. R., GOFFEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The Deliberate Searchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 267-287. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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case of sandbody pinchouts, but traps can also be formed by lateral variations in facies or diagenesis. This paper is concerned only with the case of sandbody pinchouts. Sandbody pinchouts can occur by a variety of mechanisms and in a range of clastic depositional environments, but are particularly common in turbidite successions. Turbidite successions are generally layered, and sandstone packages show variable degrees of shale preservation between individual sandstone beds. The packages can commonly be observed to pinchout within or against a shale/mudstone succession, forming the ideal conditions for a stratigraphic trap. Stratigraphically trapped turbidites form important play types in many parts of the world, including the Tertiary of the North Sea and the Gulf of Mexico (e.g. Newman et al. 1993; O'Connor & Walker 1993; Mahaffie 1994; McGee et al. 1994) and the importance of this type of play has long been recognized (Pettingill 1997, 1998). In this paper, the variable geometry of turbidite sandbody pinchout is d i ~ e n ~ d and a geometric classification scheme suggested. The impact of some of the geometrical variations on reservoir behaviour is then addressed by building generic models of selected geometries and simulating two-phase fluid flow through the models.

Variability of sandbody pinchouts As discussed above, sandbody pinchouts occur in a range of depositional environments and can take a variety of forms (Fig. 1). Pinchout may occur when a sandbody onlaps an existing surface. This occurs at channel margins, in which case the pre-existing surface is erosive, or, in the case of many turbidite sandbodies, when sands are deposited against submarine topography. In the following paragraphs, turbidite onlaps are discussed in more detail, although some of the geometrical comments may also apply to other depositional settings. In the case of turbidite sandbody onlap against an existing surface, individual sand beds may maintain their thickness as they approach the onlap surface. In this case, the thickness of the sandstone package will decrease at the onlap, but the net-to-gross ratio will remain constant (it should be noted that, in this paper, the term 'net-to-gross ratio' is used for the ratio of sandstone thickness to interval thickness; no sandstone porosity cut-off is applied). This geometry is seen at several of the onlaps of Gr~s d'Annot sandstone packages at Chalufy, SW France (e.g. Smith & Joseph 2004).

In the simplest case, individual beds terminate suddenly against the onlap surface, producing a 'clean' onlap surface. In other cases, the sand bed may thin at the onlap surface, but continue up the surface for some distance (e.g. McCaffrey & Kneller 2001; Smith & Joseph 2004), often with a thickness of only a few cms (Fig. ld, e). In addition, suspended mud associated with the turbidity current may drape the onlap surface. Deposition of mud, silt and sand on the onlap surface means that the surface itself accretes vertically and laterally with time and that later sand beds overlie slightly earlier turbidite deposits and associated fines, rather than the original surface. The mechanisms and geometries of such onlaps are discussed i n detail in Smith & Joseph (2004). In addition to bed pinchout at the onlap surface, individual sandstone beds may thin out as they approach the onlap (McCaffrey & Kneller 2001; Satur et al. 2005). In this case, the net-to-gross ratio of the sand package will decrease as the onlap surface is approached. More r. .n. r. .o l v a , i n c l l v l c h m l ~ a n c l ~ t c ~ n o beds may thicken close to the onlap and may locally erode into the underlying mudstone and sandstone (McCaffrey & Kneller 2001; Fig. ld, Type B). In all of the previous discussion, the presence of the pre-existing topography had an influence on the behaviour of the turbidity currents and therefore on the sand-body distribution. Where significant topography is absent, turbidity currents will tend to vary spacially in energy and therefore their ability to transport and deposit sand. Individual turbidite sandstones will therefore tend to be thinner downcurrent (e.g. Amy et aL 2000; Remacha et al. 2006) and also to thin towards their lateral margins. Repeated turbidity currents in the same area can therefore produce a sediment package in which both the package itself and the individual beds within it will thin towards its margins. .

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Outcrop studies of turbidite onlaps In the last 20 years, many outcrop studies have examined the nature of turbidite sandbody pinchouts (e.g. Apps 1987; Haughton 1994a, b; Zelt & Rossen 1994; Johnson et al. 2001). In the case of onlaps, the impact on turbidity current behaviour (and therefore on the nature of turbidite sandbodies) of the relationship between the palaeocurrent direction and the slope orientation and dip has been examined by many workers and compared with the results of theoretical and experimental studies (e.g. Pantin & Leeder 1987; Muck & Underwood 1990; A m y et al. 2004). Variations in bed

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Fig. 1. Examples of classifications of sandbody terminations. (a) after Hurst et al. 1999; (b) after Sinclair 2000; (c) after Prather et al. 2000; (d) after McCaffrey & Kneller 2001; (e) after Smith & Joseph 2004. thickness and facies with increased distance from the onlap surface have been identified and attributed to variations in turbidity current behaviour (e.g. Sinclair 1994; Haughton 1994a, b; McCaffrey & Kneller 2001). Some of these lateral variations in facies and thickness may be reflected in vertical trends within the onlapping sandstone package (e.g. Sinclair 1994; McCaffrey & Kneller 2001) and attempts have been made to use such trends to estimate the distance from the onlap. These detailed sedimentological studies are of great value, as they not only increase our understanding of the processes occurring at sandbody terminations, but also indicate the range of geometries which may occur. In this study, we are interested mainly in the sandbody geometry, from a reservoir engineering point of view, rather than the details of facies or sedimentary processes.

Classification of pinchouts and onlaps Several of these studies of sandbody pinchouts have used either formal or informal classifications of pinchout geometry, but there is no consistency between the schemes (Fig. 1). Some classification schemes have used simply geometric criteria, whilst others have included more detailed process sedimentology. From a reservoir engineering point of view, it is mainly the geometry which is of interest. It will be useful,

therefore, to establish a consistent classification of pinchout geometry before addressing the engineering issues. A geometrically-based classification scheme for onlaps and pinchouts is the subject of current work (Gardiner in prep.) and is shown on Figure 2. As far as possible, this classification is descriptive, without any implications as to the origin of the pinchout. It should be noted, however, that there is a continuum of geometries and that similar geometries can be formed by different processes. Rather than using numerical or alphabetic classes (which can be easily forgotten or confused), the different geometries are given descriptive names, and alphabetic codes based on these names. The first three geometries reflect relatively rapid thinning of the sandbody, resulting in a more-or-less sharp contact. They occur most commonly when the sandbody onlaps an existing surface (e.g. channel margin or basinfloor topography). Simple onlap (Os) occurs when the sandbody pinches out sharply against an existing surface (Fig. 2a). The sandbody may be either massive or bedded, but there is little thinning of individual sandstone beds before the onlap surface is reached. This geometry is equivalent to Hurst e t a/.'s infill, Sinclair's Type 1 and 2 onlap, Prather e t a l . ' s 'massive' and 'onlap' and Smith & Joseph's 'abrupt onlap'. Draping onlap (Od) occurs when individual

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Fig. 2. Examples- of sandbody pinchout geometry. (a--d) show a range of possible geometries when a sandstone body onlaps an existing surface. (e--i) are examples of 'feather edge pinchout', in which individual beds pinchout in a consistent direction, without the need for a pre-existing surface. Note that the geometries shown in e and i may also occur at onlaps against an existing surface. sandstone beds extend some distance up the onlap surface (Fig. 2b). This may be accompanied by deposition of finer sediment higher up the onlap, causing the onlap surface to build upwards with time. This geometry is essentially

the same as Sinclair's type 3, McCaffrey & Kneller's Type A and Smith & Joseph's Class 2 (aggradational onlap). Onlap with bed thickening (Ot) is characterized by individual beds thickening close to the

TURBIDITE SANDBODY PINCHOUT onlap surface. Beds may extend some distance up the confining slope and may also show more evidence of basal erosion (Fig. 2c; McCaffrey & Kneller's type B). Draping offlap (Oo). In rare cases of draping onlap, later sandstone beds may terminate increasingly further from the onlap surface (Fig. 2d), leading to an offlap geometry. In all of the geometries described above, the top of the sandbody extends further than its base, which will normally be the case when the sandbody terminates against an existing surface. The remaining geometries involve the thinning of individual sandstone beds and so produce a less sharp sandbody termination. They may therefore be referred to as featheredge pinchouts. In the first four cases, individual sandbodies are essentially horizontal. This occurs when the thinning of sandstone beds is accompanied by a thickening of mudstone. The four cases are differentiated by the position of the termination of the individual sandstone beds. Advancing pinchout (Pa) occurs when each successive bed extends further than the underlying bed (Fig. 2e). This geometry occurs at onlaps when individual sand beds thin towards the onlap surface, but might also be expected to form during the advance of a submarine fan lobe. Retreating pinchout (Pr) occurs when each successive bed extends less far than the previous bed (Fig. 2f). This may occur during lobe retreat. Symmetrical pinchout (Ps) consists of a sandstone package with advancing pinchout geometry at its base and retreating pinchout at its top (Fig. 2g). It is likely to occur during the advance and later retreat of a fan lobe or when a lobe sweeps laterally over an area of sea-floor. For completeness, it is also useful to include the case in which all sandstone beds terminate at approximately the same lateral position (Fig. 2h). The termination of the sandbody will form an approximately vertical surface, and the pinchout can therefore be described as vertical pinchout (Pv). In all of the above cases of feather-edge pinchout, individual sandstone beds are horizontal and parallel. However, if the thickness of the mudstone beds between the sandstones does not change laterally, or the mudstones thin in the same direction as the sandstones, the sandstone beds will have a convergent form (Fig. 2i). Most sandstone packages which exhibit significant thinning of individual sandstone beds are likely to exhibit some degree of convergence. The first four feather-edge pinchout geometries should therefore be treated as relatively rarely-

271

occurring end-members. Each of these forms can occur with convergence, and can be given the codes Pac, Prc, Psc and Pvc. The convergent and thin-bed geometries of Prather et al. 2000 (Fig. lc) have the geometry of 'advancing pinchout with convergence' (Pac) or 'vertical pinchout with convergence' (Pvc).

Modelling of dynamic behaviour of stratigraphic traps formed by sandbody pinchout All of the pinchout geometries described above may form single or multiple stratigraphic traps if top and base seal are present. The main objective of this paper is to examine the impact of some of the different geometries on dynamic reservoir behaviour. Amongst the variables which may have an impact on reservoir behaviour are the slope of the onlap/pinchout surface, the thinning of individual beds, lateral variation of reservoir quality within individual beds, the effective kv/kh ratio and the location of producing wells with respect to the initiation of onlap or pinchout. In this study, the geometries which will be studied are the simple onlap (Os) and advancing pinchout (Pa) and the main issues which will be addressed are the onlap dip, the thinning of beds, the variation of kv/kh ratio and the well location. Individual sandstone beds are assumed to have uniform properties. In the discussion of the models in the following sections, various terms are used to describe the different elements of sandbody pinchouts. These are defined in Figure 3.

Modelling issues The design of models for dynamic simulation studies always includes a degree of compromise between the resolution of the model and the number of active cells. High-resolution geological models often contain several million cells, but it is impractical to attempt flow simulation through models of this size. In general, simulation models are restricted to several hundred thousand cells. For full-field simulation models, this requires the cell to be tens of metres (or more) in the two horizontal directions and metres in the vertical direction. Additional constraints on the models are produced by the need to avoid, as far as possible, high aspect ratios in the cells, which may cause numerical dispersion in the simulator software. The cells in these 3D models may be too coarse to capture the geological heterogeneity

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Fig. 3. Definition of the components of an onlap, as used in this paper. Angle 0 is the onlap angle.

and may have to be populated with 'upscaled' average properties. In this study, which is concerned with the impact of geological heterogeneity on fluid flow, such upscaling would be inappropriate, as the fine-scaled heterogeneities would be lost. One way of maintaining a small cell size in simulation models is to build 2D models, consisting of only one cell in one of the horizontal directions. This approach has clearly limited applicability in the case of geological systems with pronounced variation in all three . . _._I_ ~ J~ __ directions. However, in tile. . ca~e of Lturoiu~tes, sheet-like geometries are relatively common. In the current study, the main variation in sand and shale thickness is likely to occur in the direction of onlap; lateral variations parallel to the strike of the onlap surface are likely to be less pronounced. In addition to possible geological limitations, 2D models cannot capture 3D fluid flow. For example, if a vertical injector-producer pair is modelled in 2D, little flow is likely to occur in those parts of the model beyond the wells. It may therefore be appropriate to compare the results of 2D and 3D simulations before embarking on a large programme of 2D simulations.

Model design To assess the applicability of 2D simulation in this case, an initial pilot study, using coarse 2D and 3D models, was undertaken. The coarse models represent a sandbody 25 m thick, onlapping against a surface dipping at 10.6 ~ and extending 600 m away from the onlap. The cells are 4 m • 4 m (horizontally) • 0.5 m (vertically). The 2D model is, therefore, 4 m wide. The three 3D models contain 11, 31 and 51 cells in the direction parallel to the onlap, and are therefore 44 m, 124 m and 204 m wide. The largest of these models contain 382 500 cells. The 3D models were produced by duplicating the 2D geometry in the third dimension. This means that the models show no geological variation in that direction, although their 3D nature allows more realistic flow towards the produc-

ing well. The aim of these simulations was to compare the results from 2D and 3D models and to assess the validity of results from the 2D models. In some simulation runs, the sandbody was given a structural dip, away from the onlap, of approximately 10 ~ so that an oil-water contact (OWC) could be added to the down-dip end of the model and the model simulated using a natural aquifer drive (see Fig. 8). The coarse models, because of the limitation of cell numbers in the 3D models, were relaUvely S l l l d l l , eXtelIUlllg umy 1 1 1 from the onlap. The coarse cell size meant that geological subtleties, such as variations in bed thickness, were hard to model. To address this, larger 2D models were built. In these models, the sandbody is 20 m thick, consisting of ten 2 m beds, and extends 1000 m away from the onlap. Cells are 1 m by 0.25 m and the models contain 100 000 cells in total (66 000 active cells). The sandbody was given a structural dip away from the onlap, with an OWC at the down-dip end of the models, and the models were simulated using a natural aquifer drive. Despite the larger size of these models, a relatively high structural dip (approximately 6 ~) was still required to move the OWC sufficiently far away from the onlap surface. To address this, larger models were built, extending 2000 m from the onlap and with a dip of 3 ~ Unfortunately, the larger size required a coarsening of the cells to 1 m by 1 m (120 000 cells in total, with 38 536 active cells) to avoid excessive simulation run-times. With the higher resolution 2D models, it was possible to model a number of geological variables, including the dip of the onlap surface, thinning of individual sandstone beds and erosion of intervening shales. z'~

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Applicability of the models to the real world In the intermediate and large 2D models, onlap dips of between 2 ~ and 14 ~ were modelled.

TURBIDITE SANDBODY PINCHOUT These models reflect onlap dip values commonly seen at outcrop. The turbidite formation which is probably best known for onlaps is the A n n o t Sandstone (Gr6s d ' A n n o t ) of SE France (Joseph & Lomas 2004). The formation onlaps pre-existing slopes on the underlying marl formation and onlap dips of 10 ~ or more are common. In the most spectacular onlap outcrop, at Chalufy, the dips vary from approximately 5 ~ to 12 ~ (e.g. Smith & Joseph 2004; Puigdefhbregas et al. 2004) but can exceptionally reach 20 ~ (Sinclair 1994). The intermediate and large 2D models have structural dips, away from the onlap, of approximately 6 ~ and 3 ~. These dips are slightly higher than those which occur in many stratigraphically trapped fields (e.g. approximately 2 ~ in the Tartan Field; Coward et al. 1991), but dips of this magnitude and greater can be found in North Sea turbidite fields such as Highlander (approximately 6~ Whitehead & Pinnock 1991) and Scapa (approximately 7 ~ and 19 ~ on the two flanks of the field (McGann et al. 1991). In the scenario modelled by the larger 2D models, with the OWC approximately 1 km and 2 km from the onlap, producing wells would access significant volumes of hydrocarbons. These models are 2D but, if they are considered as part of a 3D field, with wells placed every 500 m along the onlap, each well would access 8 million barrels of oil in place for the 1 km model and 17 million barrels for the 2 km model (for a porosity of 20% and initial water saturation of 0.2). These values suggest that the models represent an economically valid scenario.

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P i l o t study, u s i n g c o a r s e m o d e l s The coarse models consist of a sandstone package 25 m thick, containing 10 sandstone beds, each 2 m thick, separated by 0.5 m 'shales' (Fig. 4). The sandstone package onlaps a surface dipping at 10.6 ~. The 'shales' in these coarse models are laterally continuous and are assumed to have zero permeability. O t h e r geometric and petrophysical parameters of the models are shown in Table 1. The models were built in Excel and input to Schlumberger's Eclipse simulation software. The initial 2D model was placed horizontally, with its top at a depth of 2450 m. The oil-water contact was put at a depth of 3000 m, so that the e n t i r e thickness of the sandbody was within the oil leg. Two-phase flow was simulated by injecting water through a vertical well on the left of the model and producing fluids through a vertical producer, which could be moved to different positions in the model (Fig. 4). The relative permeability curves used were generic curves appropriate for clean, porous sandstones with high permeabilities (Fig. 5). In order to test the validity of the 2D model, three 3D models were built. In all of these, the sandbody geometry of the 2D model was extended into the third dimension (y dimension in Eclipse). In the models, the thickness of the beds does not vary in the third dimension. Whilst, in reality, there is likely to be some variability of bed thickness along the onlap, it is likely to be much less pronounced than in the direction away from the onlap.

Fig. 4. Definition of the 2D Eclipse models for the pilot study. Note that the model shows significant vertical exaggeration. See text for definition of the 3D models and the larger 2D models.

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Table 1. Geometrical and petrophysical parameters for the model used in the pilot study Size of model (vertical slice)

600 m • 25 m 10.6~ 2m 0.5 m 25 m 4m 0.5 m 150 1, 11 31 and 51 50 600m • 25m • 4m 600m x 25m • 44m 600m x 25 m x 124m 600 m • 25 m x 204 m 7500 82 500 232 500 382 500 20% 500 mD 400 mD 0 mD and 0.1 mD

Onlap dip Sand bed thickness Shale bed thickness Sandbody thickness Cell size (horizontal) Cell size (vertical) Cells in model - x -y --Z

Total size of model

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3Dll - 3D31 - 3D51 Total number of cells (2D) Total number of cells (3Dll) Total number of cells (3D31) Total number of cells (3D51) Sandstone porosity Sandstone kh Sandstone kv 'Shale' permeability (kv = kh) -

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Fig. 5. Relative permeability curves used in the flow simulation study. These curves are appropriate for clean, porous sandstones with high permeability.

The 3D models contain 11, 31 and 51 cells in the y direction, giving plan areas of 600 m by 44 m, 600 m by 124 m and 600 m by 204 m. To give these models more geological and engineering reality, the sandbody was also tilted away from the onlap and an oil water contact and natural aquifer were a d d e d (Fig. 8). To avoid the aquifer encroaching too close to the producer, the sandbody was given a dip of 9.8 ~ This is higher than the dip in the majority of stratigraphically trapped turbidite fields (see above), but was felt to be acceptable for the purposes of this pilot study. Lower dips were m o d e l l e d later, using higher-resolution 2D models (see below).

The depth to the top of the inclined coarse models was maintained at 2450 m at the right hand side but, because of the bedding dip, the left side of the model was now at 2554 m. The oil-water contact was placed at 2550 m and the aquifer was modelled numerically in Eclipse (a single, very high volume water-bearing cell is attached to all the cells in the first column(s) on the left). In order to be able to compare the results from 3D and 2D models, a 2D version of the tilted 3D models was produced. The simulation of fluid flow through these models was controlled by fluid production rate in the producing well. The production rate was chosen so that the fluid saturation front moved through the model with a velocity of less than 1 m/day, which is consistent with migration rates far from the well-bore in typical fields.

Results o f the coarse m o d e l simulation For a given simulation, the fluid production rates, cumulative fluid volume, reservoir and b o r e h o l e pressure and fluid saturation are recorded for each time step, in addition to other reservoir data. Using Eclipse's 'Flowviz' module, the simulation run can be visualized as a movie. For studies such as this, the change of fluid saturation with time is one of the most useful parameters to observe with Flowviz (see Figs 7, 8, 10 & 14). The numerical output can be combined in various ways in order to assess the behaviour of

TURBIDITE SANDBODY PINCHOUT the model. The recovery factor (calculated as total volume of oil produced, divided by the volume of moveable oil in the reservoir) is a useful measure of sweep efficiency (Fig. 6). Note that this recovery factor will be significantly higher than the recovery factor based on oil in place (Fig. 6b). Despite this, it is considered to be a useful measure of sweep efficiency, as it does not depend on the residual oil saturation. In the following discussion of the results, the producing well water cut is also t a k e n into account. Water cut is one of the main parameters which control the economics of a well. The acceptable maximum water cut for a given well or field will depend on the water handling facilities available, but will also be influenced by environmental regulations and economics. Because the maximum economic water cut will vary depending on local conditions, the recovery factor for different water cuts has been calculated in this study (Fig. 7a). For the simple onlap model, it can be seen that, for wells situated to the left of the initiation of onlap, the area to the left of the well is efficiently swept (Fig. 7c), but significant volumes of oil remain in the area nearer the onlap. This leads to a low recovery factor. As the well is moved towards the onlap, the volume of oil produced increases. However, when the well moves onto the onlap surface, the low perme-

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ability of the 'shales' leads to trapping of oil in the lower sandstone beds (Fig. 7d). The impact of well position on oil recovery can be examined by plotting the recovery factor for each well position, for a range of different water cuts (Fig. 7a). The recovery factor can be seen to increase linearly towards the onlap but, soon after the onlap is reached, the oil recovery begins to decrease rapidly. For a perfectly layered reservoir, with sealing shales, maximum oil recovery occurs approximately at the initiation of onlap (Fig. 7a). As the well is moved onto the onlap, the recovery decreases rapidly, such that, 90 m onto the onlap, it is less than 50% of the maximum value.

Comparison o f results from 2D and 3D models Although 2D models can be very valuable in quick-look pilot studies, there are always uncertainties over their validity. For example, in this case, it is not clear whether the poor sweep efficiency to the right of the producing well in the 2D model is due to the fact that the 2D nature of the model largely prevents injected water from reaching the up-dip parts of the onlap to displace the oil there. Comparison of the results of the 3D models and the tilted 2D model shows that, for models with continuous

Fig. 6. Results from Eclipse simulation of flow through the coarse 2D model. Results from several producing wells near the start of onlap are shown (distances are measured from the left hand side of the model). (a) Fluid production rates vs. time. Note that oil production rate decreases rapidly after water breakthrough and that the time to breakthrough increases as the producing well is moved to the right. (b) Oil recovery factor vs. time: The lower curves show the ratio of produced oil to total oil in place, whilst the upper curves show the ratio of produced oil to mobile oil. The proportion of oil which is mobile is controlled by the end-points of the relative permeability curves (Fig. 5).

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Fig. 7. (a) oil recovery (as a fraction of mobile oil) for different well positions and water cuts. Total oil production increases as the producer approaches the onlap (see onlap geometry in (b), then decreases rapidly. The low recovery from wells to the left of the onlap initiation is due to un-swept oil adjacent to the onlap (r The rapid decrease after the well position moves onto the onlap surface is due to oil trapped in the lower layers (d). (e) shows the reduced trapping which occurs if there is some connectivity between adjacent sandstone beds. These results are from the un-tilted 2D model. On (r to (e), the position of the producing well is shown by 'P'. Blue colours represent water and red colours indicate oil.

shales, the recovery factor curves have a similar shape in all four cases (Fig. 9a). It can be seen that, in each case, the optimum well position, in terms of recovery factor, is a p p r o x i m a t e l y 10-35 m onto the onlap. The recovery factor is slightly higher for the 3D models, which reflects the fact that the water front was able to advance beyond the well on the flanks of the 3D models, displacing more oil towards the well (see saturation on the top of the m o d e l on Fig. 8). Despite this, the similarity of the recovery factor curves from the four models suggests that the 2D model is sufficient to indicate the behaviour of a 3D model, at least in qualitative terms. In dynamic simulation, the cell sizes of a model (in this case 4 m by 4 m by 0.5 m) control the thickness of beds which can be modelled. More geological detail and more realistic

models are only possible if the cell sizes are reduced. Unfortunately, this leads to an increase in the number of cells in the model, and therefore in simulation run-time. This is illustrated by the simulation run-times for the different models (Table 2). The relatively long run times of the 150 by 50 by 51 cell models means that it would be difficult to run large numbers of significantly larger models (in terms of total cell numbers) in an acceptable time-frame. In many geological systems, this might be an insurmountable problem, due to the variation of geological parameters in all three dimensions. However, in this case, there is likely to be relatively little variation in bed thickness and geometry in the direction parallel to the strike of the onlap surface. This fact, together with the similarity of results from the 2D and 3D coarse models, suggests that it is valid to run 2D models to

TURBIDITE SANDBODY PINCHOUT e x a m i n e the impact geometry in this case.

277 of varying p i n c h o u t

Higher resolution 2D models

Fig. 8. Tilted 3D model, with 31 cells in the y direction. The sandbody is given a dip of approximately 10~ away from the onlap surface and an oil-water contact (OWC) is placed just above the depth of the top-left edge of the model. The dip of the sandbody is higher than that found in most stratigraphically trapped fields but, with a model of this size, a lower dip would allow the OWC to approach too close to the onlap. The colours indicate the fluid saturation when the water cut in the well has exceeded 95 %. The well in this case is placed 25 cells (100 m) from the onlap termination, or 9 cells (36 m) onto the onlap. Note that the oil saturation scale is from 0 to 80%.

In many high net-to-gross turbidite sandbodies, the fines b e t w e e n individual turbidite sandstones are commonly less than 0.5 m thick. The m i n i m u m thickness of the shale beds in the initial models (0.5 m) is therefore thicker than might be desired. In dynamic modelling, in order to avoid numerical problems, sandstone layers should ideally be several cells thick, so it is difficult to m o d e l individual beds with fewer than 2 or 3 cells in the vertical direction and more may be required w h e n the beds are nonhorizontal. For the remainder of this study, it was therefore decided to use higher-resolution 2D models, to enable finer geological detail to be modelled. The high-resolution 2D model used is 1000 m horizontally by 25 m vertically, with cells 1 m by 0.25 m. The modelled sandbody is 20 m thick, consisting of 80 cells in the z direction, and is tilted away from the onlap at a lower angle than the coarse models, namely 5.9 ~ (Fig. 10). The sandbody does not contain explicitly-modelled shale layers; instead, shales are m o d e l l e d in

Fig. 9. Comparison of results from 2D and 3D models. The curves show oil recovery factor for a water cut of 85%. All three models show that recovery peaks close to the initiation of onlap, and then decreases rapidly The similarity of the curves suggests that the 2D model can be used, at least qualitatively, to assess the behaviour of a 3D system.

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A. GARDINER

Table 2. Model sizes and run times for the 2D and 3D coarse models and the higher resolution 2D models Model

Dimensions (m) x

y

Cell sizes (m)

No. of cells

z

x

y

z

x

y

Total cells

Total active cells

Average run-time

z

2D

600

4

25

4

4

0.5

150

1

50

7500

3D(11)

600

44

25

4

4

0.5

150

11

50

82 500

3D(31)

600

124

25

4

4

0.5

150

31

50

232 500

232 500 1.5-2hrs

3D(51)

600

204

25

4

4

0.5

150

51

50

382 500

382 500

2D(high res.)

1000

10

25

1

10

0.25

1000

1

100

100 000

66 000 1.5-5 hrs

2D(mod res.)

2000

10

25

1

10

1

2000

1

25

50 000

38 536 20-30 min

Eclipse as transmissibility multipliers, w h i c h limit the vertical flow b e t w e e n cells (see later discussion and Figs 13 & 14). The advantages of shales thinner than the vertical cell resolution of the m o d e l can be e x a m i n e d , and the p r o p o r t i o n of p r e s e r v e d shale can be m o d i f i e d w i t h o u t changing the net-to-gross ratio of the model. Using the high-resolution model, a n u m b e r of issues was examined. These include the dip of

Fig. 10. Examples of high-resolution, tilted 2D models. These larger models extend 1000 m from left to right and are inclined at 6 ~ The OWC is at 2550 m and edge aquifer drive is simulated by the addition of a 'numerical aquifer' in Eclipse. (a) shows a 'sand tank' model with a kh of 500 mD and kv of 0.1 mD (kv:kh ratio of 0.0002). The water cut at the well (at 950 m) has reached 90%, with significant volumes of oil left in the lower beds. (b) shows a geologically more realistic model, with 10% shale removal. The advance of the water front is much less regular, reflecting the randomly positioned 'holes' in the modelled shales (see also Fig. 14d). Well position is at 925 m and water cut is 85 %.

7500

i min

82 500 20-25 min

2-3hrs

the onlap surface, the effective kv:kh ratio, the p r o p o r t i o n of p r e s e r v e d shales and the thinning of i n d i v i d u a l s a n d s t o n e beds. As discussed ................................. s should be t r e a t e d as q u a l i t a t i v e or s e m i - q u a n t i t a t i v e . D e s p i t e this limitation, it is felt that the results of the simulations will provide useful insights into the reservoir b e h a v i o u r of onlap stratigraphic traps and will indicate the parameters which n e e d to be c o n s i d e r e d w h e n appraising such reservoirs. To address the impact of the structural dip of the s a n d b o d y on reservoir behaviour, a m o d e l with a dip of 3 ~ was built. To p r e v e n t the O W C e n c r o a c h i n g too close to the onlap, this m o d e l was e x t e n d e d 2000 m f r o m the onlap. Initial m o d e l s h a d the same cell sizes as t h e highr e s o l u t i o n 1000 m m o d e l , but excessive runtimes r e q u i r e d a coarsening of the cells (see Table 3 for cell sizes). B e c a u s e of the coarser cells in the largest (2000 m) models, t h e y w e r e used only to examine w h e t h e r structural dip has a significant i m p a c t o n r e s e r v o i r b e h a v i o u r ; the h i g h e r resolution 1000 m m o d e l s were used to examine the impact of other variables, and it is results from these m o d e l s which are discussed below. I m p a c t o f o n l a p dip Models with onlap dips of 2 ~ 4 ~ 6 ~ 8 ~ 10 ~ and 14 ~ w e r e m o d e l l e d . As discussed above, these angles are within the r a n g e of onlap angles observed at outcrop. Because of the structural dip of the s a n d b o d y (in this case 6~ the onlap surface will dip at a steeper angle in the m o d e l (for example, the 10 ~ onlap will dip at 16~ In the discussions which follow, the original dip of

TURBIDITE SANDBODY PINCHOUT

279

Table 3. Parametersof the higher resolution2D models

Dimensions of model Sandbody thickness Cell dimensions

High resolution

Moderate resolution

1000 m 25 m 20 m lm 0.25 m 5.9 ~ 2550 m

2000 m 25 m 20 m lm Im 3~ 2550 m

horizontal vertical horizontal vertical

Dip of sandbody Oil-Water Contact

the onlap surface, relative to the bedding of the sandbody, is used. In these high-resolution models, the 20 m sandbody was divided by continuous transmissibility multipliers (of value 0) into 10 beds each 2 m thick. The effective vertical permeability of the sandbody is therefore zero. Figure 11 shows the variation in recovery factor with well position for the different onlap dip angles. In all cases, the recovery increases linearly towards the onlap surface, but begins to decrease rapidly soon after the onlap is reached. The point at which the recovery factor reaches a m a x i m u m is further away from the onlap

termination for lower dips, so that a greater volume of hydrocarbons is left up-dip of the well in these cases. The maximum oil recovery (as a proportion of mobile oil) is 78% for an onlap dip of 14 ~ but decreases to 68% for a dip of 4 ~

Impact o f effective kv/kh ratio As shown by Figure 7, the decrease in recovery factor when the producing well is on the onlap surface is due to trapping in the lower sandstone beds, and will therefore be influenced by the effective kv:kh ratio. To examine this, a n u m b e r of simulations were u n d e r t a k e n with constant

Fig. 11. Comparison of results for different onlap dips. The curves show the recovery factor (as a fraction of mobile oil) achieved when the water cut reaches 90%. As the onlap dip decreases, the optimum well position moves to the left, away from the onlap termination, and the maximum recovery factor decreases. This is due to the lower dips producing a greater separation of the onlap initiation and the onlap termination and, therefore, a larger volume of oil up-dip of the optimum well position.

280

A. GARDINER

onlap dips (10 ~ and variable kv:kh ratios. In these simulations, the 20 m thick sandbody was assumed to be a 'sand tank', with a horizontal permeability of 500 mD and variable vertical permeabilities. The results of one of the simulations are shown in Figure 10a. The vertical permeabilities used and the resultant kv/kh ratios are shown in Table 4. In reality, rather than being 100% sandstone, most onlapping sandbodies are composed of interbedded sandstones and fines. If the fines are continuous sealing shales, with permeabilities close to zero, there will be no vertical flow b e t w e e n sandstone beds. However, in m a n y turbidite systems, the fines are quite silty, so may have measurable permeability. It may be instructive to examine what values of 'shale' permeability would produce the effective kv:kh ratios modelled here. The permeabilities required will depend on the thickness of the 'shale' beds. Table 4 shows the permeabilities required, for 'shale' beds 5 cm and 10 cm thick, in order to produce the effective kv:kh ratios - , tA. ~ t.v ~ , 11 11 ,~.r ~ ~At here. 19-1.1~ ,k.P Figure 12 shows the results of the simulations. For models with kv greater than 0.1 m D (for a kh of 500 m D ) the r e c o v e r y factor continues to rise as the onlap termination is approached, indicating that no significant volumes of hydrocarbons were trapped in the lower layers. Models with kv of 0.01 mD show a decrease of recovery factor which begins some distance after the initiation of onlap is reached. Those models with kv values below 0.001 m D do not show a significant difference from the models with zero vertical permeability, indicating significant trapping in the lower layers.

In reality, the low vertical permeability in turbidite reservoir sandbodies is likely to be the result of thin shale or siltstone beds with low permeability. As Table 4 shows, 5 cm shales with a permeability of 2.4 x 10-5 (or 10 cm shales with permeabilities of 4.5 x 10-s), w h e n interbedded with 2 m sandstone beds with kv of 400 mD, would produce the same effective kv/kh ratio as a uniform kv of 0.001 mD, indicating that these values of 'shale' permeability would act as effective barriers to vertical flow in this situation. Impact of shale erosion

In practise, the effective kv:kh ratio of interbedded turbidite sandstones and shales is influenced by the degree of shale removal (e.g. Stephen et aL 2001). In order to model this, the values assigned to the transmissibility multipliers between the 2 m sandstone beds were modified. Transmissibility values of 0 represent shales with a kv of 0 mD, whilst local erosion of ~,,,~ ~..a,,~ can be ,,,,.,u,.,,,~u ~,y a -,u,~.r,-~.- of 1. Different proportions of multipliers of 0 and 1 along a row of cells in the simulation model therefore represent variations in shale erosion (Fig. 13). To build the multiplier layers, an in-house code was used to generate a 3D model of alternating sandstones and 'shales', represented by continuous layers of 0 transmissibility. Circular holes in the shales are then simulated by replacing circular distributions of cells by multipliers of 1. The size distribution of these 'holes', and the proportion of 'shale erosion' in a layer, can be defined to give different distributions of shales and amalgamation surfaces. When the 3D model

Table 4. Permeabilities needed for continuous 5 cm and 10 cm 'shales', to produce the modelled kv:kh ratios Permeability values for 'sand tank' model

Equivalent permeability values required for a bedded sandstone/shale succession

kh (mD)

kv (mD)

Effective kv/kh ratio

Sand kh (2 m beds) (mD)

Sand kv (2 m beds) (mD)

Shale perm. kh = kv) for 5 cm shale (mD)

Shale perm. kh = kv) for 10 cm shale (mD)

500 500 500 500 500 500 500 500 500

0 0.0001 0.001 0.01 0.1 0.5 1 10 100

0 2 x 10~ 2 x 10-6 2 x 10-5 0.0002 0.001 0.002 0.02 0.2

500 500 500 500 500 500 500 500 500

400 400 400 400 400 400 400 400 400

0 0.0000024 0.000024 0.00024 0.0024 0.012 0.024 0.24 3.1

0 0.0000045 0.000045 0.00045 0.0045 0.023 0.045 0.46 5.9

TURBIDITE SANDBODY PINCHOUT

281

Fig. 12. Comparison of results for different values of kv:kh ratio. The curves show the recovery factor (as a fraction of mobile oil) achieved when the water cut reaches 90%. Models with low values of kv:kh behave like the perfectly layered sandstone/shale but as the kv (and therefore kv:kh ratio) increases, the degree of trapping in the lower sand beds decreases and the recovery factor therefore continues to increase as the wells move towards the onlap termination.

Fig. 13. Illustration of the use of transmissibility multipliers to mimic shale barriers. The layered model (a) consists of sandstone beds with 4 rows of grid cells, separated by shale consisting of a single layer of cells. The net-to-gross ratio (NTG) of the model is, therefore, 80%. Localized erosion of the shale layers can be modelled by replacing selected shale cells by sandstone (b). Unfortunately, this will also change the NTG of the model. In this case, removal of half of the shale cells increases NTG to 90%. To avoid this unwanted change, barriers to flow can be modelled in Eclipse as transmissibility multipliers between adjacent cells (r Multipliers with a value of 0 mimic totally impermeable barriers, whilst multipliers of 1 allow normal flow between cells. has been built, a single vertical slice is extracted for use in the 2D simulation (Fig. 14a--c). For the purposes of simulation, proportions of shale erosion of 0%, 5%, 10%, 15%, 20% and

25% were modelled, using the same m o d e l geometry as before (Fig. 14a--c). For proportions of shale removal of 20% and above, there is little decrease in recovery factor as the onlap

282

A. GARDINER

Fig. 14. Models with different percentages of shale removal (a-c). (d) shows the fluid saturation plot for part of a shale erosion model, demonstrating the impact of the irregular shale distribution on the fluid front. termination is approached (Fig. 15). However, for values of shale removal below this, the recovery factor decreases for wells which intersect the onlap. Figure 15 indicates that the impact on recovery factor occurs later, and is less significant, as the p r o p o r t i o n of shale erosion increases. For example, for shale removal of 15% and above, the decrease in recovery factor only begins close to the onlap termination.

Impact of thinning of sandstone beds To examine the impact of individual sandstone beds thinning as they approach the onlap, models were built in which the sandstone beds thinned at rates of I in 8,1 in 16, 1 in 36, 1 in 48 and 1 in 96. This corresponds to beds which maintain a uniform thickness of 2 m before thinning in the last 16 to 192 m. Where the sandstone beds were in contact, they were separated by transmissibility multipliers of 0. These models were c o m p a r e d with the layered model with no thinning, and the results are shown on Figure 16. It can be seen that the

curves are very similar, showing the same optimum well location. The models with more gradual pinchout have higher recovery factors for all well positions, which reflects the fact that less oil is left in the thin beds up-dip of the well.

Impact of structural dip As discussed above, the structural dips of the coarse models and the high-resolution 2D models are higher than the dips of many stratigraphically trapped fields. To assess whether the dip has a significant impact on dynamic reservoir behaviour, moderate resolution models, with a dip of 3 ~ were built, and the results of simulations through these models compared with results from the more steeply dipping highresolution models. As stated above, these models were only used to assess a limited range of variables, including onlap dip and the degree of shale erosion. The results indicate that the s a m e trends occur for dips of 3 ~ as dip for dips of 6 ~ (compare Fig. 17 with Fig. 11 and Fig. 18 with Fig. 15). This suggests that variation in structural dip within

TURBIDITE SANDBODY PINCHOUT

283

Fig. 15. Results for different proportions of eroded shale. The curves show the recovery factor (as a fraction of mobile oil) for a water cut of 90%. Note that the recovery factor decreases as the producer moves onto the onlap for shale removal proportions of less than 15% or less but, when 15% or more of shale is removed, the recovery factor continues to increase, due to reduced trapping in the lower layers.

Fig. 16. (a) Results for different rates of thinning of individual sandstone beds. The curves show the recovery factor (as a fraction of mobile oil) for a water cut of 90%. The recovery factor is higher when individual beds pinch out towards the onlap, as the reduction in net sand reduces the volume of oil which might be left updip of the producer. (b) shows the model with bed pinchout of i in 96.

284

A. G A R D I N E R

Fig. 17. Comparison of results for different onlap dips, for the intermediate resolution models with 3 ~ dips. The curves show the recovery factor (as a fraction of mobile oil) achieved when the water cut reaches 90%. As the onlap dip decreases, the optimum well position moves to the left, away from the onlap termination, and the maximum recovery factor decreases. This trend is essentially similar to the results for models with 6 ~ dips (Fig. 11).

Fig. 18. Results for different proportions of eroded shale for the intermediate resolution models with 3 ~ dips. The curves show the recovery factor (as a fraction of mobile oil) for a water cut of 90%. Note that the recovery factor decreases as the producer moves onto the onlap for shale removal proportions of 15% or less but, when 20% or more of shale is removed, the recovery factor continues to increase, due to reduced trapping in the lower layers. These results are similar to those for models with dips of 6 ~ (see Fig. 15). Note that only the right hand end of the model (from 1400 m to 2000 m) is shown.

TURBIDITE SANDBODY PINCHOUT the range modelled (greater than 3 ~) does not have a significant impact on dynamic behaviour, at least for the geological and petrophysical parameters examined here.

Discussion and conclusions The results of the simulations indicate that the position of producing wells near sandbody pinchouts has a significant impact on the recovery factor. In the case of reservoir sandbodies with low effective vertical permeability, there will be significant trapping of hydrocarbons in the lower sandstone layers as the well position is moved closer to the onlap termination. This trapping is reduced if the well is moved further away from the onlap termination. Unfortunately, this may lead to hydrocarbons being left up-dip of the well. The various simulations indicate that the optimal well position is close to the point of initiation of onlap. However, it may be very difficult to identify this point accurately on seismic data. Because of this uncertainty, it is useful to be able to assess the relative risks of moving the well towards or away from the onlap. Moving the producer away from the onlap, as identified by seismic, reduces the risk of significant volumes of hydrocarbons being trapped in the lower layers, but may leave more hydrocarbons updip. The potential volume of un-swept up-dip oil is greater when the onlap dip is low, due to the greater lateral separation of the onlap initiation and onlap termination. For a given onlap dip, the volume of oil which may be left up-dip of a producer is lower if the individual sandstone beds thin towards the onlap. Moving the well closer to the onlap termination reduces the volume of up-dip hydrocarbons, but may allow trapping in lower layers. The degree of trapping of hydrocarbons in the lower layers depends on the effective kv:kh ratio of the sandbody. In layered turbidite systems, this will be influenced by the permeability of the 'shale' and the proportion of shale preserved between adjacent sandstone beds. If the fines have permeabilities of 10-5 mD or less, they are likely to inhibit vertical flow in the systems modelled here, but silty shales with higher permeabilities may allow vertical flow and so reduce trapping in the lower layers. In the case of shale erosion, the 2D results indicate that, for shale erosion percentages above 15%, fluids are able to flow vertically between adjacent beds, so reducing the tendency for trapping. However, for lower values of shale erosion, significant trapping can occur. This suggests that the risk of reduced recovery for

285

wells on the onlap surface is negligible for high degrees of shale erosion, but becomes important when more shale is preserved. Initial results from 3D simulations (not r e p o r t e d here) suggest that values of shale erosion somewhat below 15% may also allow significant vertical communication. Clearly, it is impossible to measure the areal percentage of shale removal in the subsurface. However, if core is available, the p r o p o r t i o n of sand-on-sand contacts at turbidite bed bases will be a proxy for this value (Stephen et aL 2001). Careful examination of the core may therefore allow the risk of trapping in lower sandstone layers to be assessed. In cases where this risk is high, more effort may be put into an accurate identification of the position of the onlap, or steps may be taken to minimize the impact of poor well placement (e.g. by planning for intelligent well completion or sidetracking). The author is indebted to many colleagues at HeriotWatt for general discussions about the issues involved in this paper. In particular, thanks are due to S. Neal, who ran many new simulations between the Geological Society conference in May 2004 and the submission of the final typescript. E. MacKay offered invaluable advice and problem-solving help on all Eclipse issues. J.-M. Questiaux gave constructive comments on an earlier version of the paper. We thank Schlumberger-Geoquest for the provision of the Eclipse software suite to the Institute, without which this study would have been impossible. The paper benefited from incisive reviews by K. Milne and T. McKie.

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Petroleum Geology of Northwest Europe: Proceedings of the 4th conference. Volume 1, The Geological Society, London, 145-160. PANrIN, H.M. & LEEDER, M.R. 1987. Reverse flow in turbidity currents: the role of internal solitons. Sedimentology, 34, 1143-1155. PETrINGILL,H.S. 1997. A historical look at world-wide turbidite production: the importance of stratigraphic traps in predicting play reserves (abs), AAPG Bulletin 81, 1403-1404. PETrINGILL, H.S. 1998. World turbidites: 1. turbidite plays' immaturity means big potential remains. Oil and Gas Journal, 96, 106-112. PRATHER, B.E., KELLER, LB. & CHAPIN, M.A. 2000. Hierarchy of deep-water elements with reference to seismic resolution: implications for reservoir prediction and modelling, GCSSEPM Foundation 20 th Annual Research Conference. Deep-Water Reservoirs of the World, December 3-6 2000, 817-835. PUIGDEFABREGAS, C., GJELBERG, J. ~: VAKSDAL, M. 2004. The Gr6s d'Annot in the Annot syncline: outer basin-margin onlap and associated softsediment deformation. In: JOSEPH, P. & LOMAS, S.A. (eds) Deep-Water Sedimentation in the Alpine Basin of SE France: New perspectives on the Gr~s d'Annot and related systems. Geological Society, London, Special Publications, 221, 367-388. REMACHA, E., FERNANDEZ,L.R & MAESTRO,E. 2005. The transition between sheet-like lobes and basin plain. Journal of Sedimentary Research, 75, 798-819. SATUR, N., KEELING, G., CRONIN, B.T., HURST, A. & G~RBOZ, K. 2005. Sedimentary architecture of a canyon-style fairway feeding a deep-water clastic system, the Miocene Cing0z Formation, southern Turkey: significance for reservoir characterisation and modelling. Sedimentary Geology, 173, 91-119. SINCLAm, H.D. 1994. The influence of lateral basinal slopes on turbidite sedimentation in the Annot sandstones of SE France. Journal of Sedimentary Research, 64, 42-54. SINCLAIR, H.D. 2000. Delta-fed turbidites infilling topographically complex basins: a new depositional model for the Annot Sandstones, SE France. Journal of Sedimentary Research, 70, 504-519. SMITH, R. & JOSEPH, P. 2004. Onlap stratal architectures in the Gr~s d'Annot: geometrical models and controlling factors. In: JOSEPH, P. & LOMAS, S.A. (eds) Deep-Water Sedimentation in the Alpine Basin of SE France: New perspectives on the Gr~s d'Annot and related systems. Geological Society, London, Special Publications, 221, 389-400. STEPHEN, K.D., CLARK, J.D. & GARDINER,A.R. 2001. Outcrop-based stochastic modelling of turbidite amalgamation and its effects on hydrocarbon recovery. Petroleum Geoscience, 7, 163-172. WHITEHEAD,M. & PINNOCK,S.J. 1991. The Highlander Field, Block 14/20b, UK North Sea. In: ABBOTTS, I.E. (ed.) United Kingdom Oil and Gas Fields, 25

TURBIDITE SANDBODY PINCHOUT years Commemorative Volume, Geological Society, London, Memoir 14, 323-329. ZELT, E & ROSSEN,C. 1995. Geometry and continuity of deep-water sandstones and siltstones of the Brushy Canyon Formation (Permian), Delaware

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Mountains, Texas. In: PICKERING,K.T., HISCOTT, R.N., KENYON,N.H., RIccI LUCCH~,E & SMITH, R.D.A. (eds) Atlas o f deep water environments: Architectural styles in turbidite systems, Chapman and Hall, London, 167-183.

Extrusive sandstones (extrudites): a new class of stratigraphic trap? ANDREW

H U R S T 1, J O S E P H A. C A R T W R I G H T

2, M A D S H U U S E 2

& DAVIDE DURANTP

aUniversity of Aberdeen, Department of Geology & Petroleum Geology, Kings College, Aberdeen AB24 9UE, UK (e-mail: [email protected]) 23DLab, School of Earth, Ocean and Planetary Sciences, Cardiff University, Main Building, Park Place, Cardiff CFIO 3YE, Wales, UK (email." joe@ocean, cf.ac, uk, m. huuse@earth, cfac. uk, www.3dlab, org. uk) Abstract: Extrusive sandstone bodies are identified as entirely stratigraphic traps associated with sand injectites. They may be difficult to recognize but have four-way dip closure and are invariably connected through underlying lower permeability strata to parent sandbodies by sandstone dykes or transgressive sills that belong to sand injectite complexes. Extrusive sandstones (extrudites) constitute an immature exploration target, which is largely untested by deliberate exploration wells. Using seismic data alone, the distinction between extrudites and intrusive sills, and between extrudites and depositional sands, may be problematic. Sedimentological criteria may make differentiation possible when core is available. Extrudites are likely to have been drilled and misinterpreted as conventional deep-water turbidites within deep-water systems affected by sand injection.

Recent mapping of sand injectite systems in the North Sea and the Faeroe-Shetland Basin using 3D seismic data calibrated with exploration and production wells has provided strong evidence that substantial quantities of sand were extruded onto or near the p e n e c o n t e m p o r a n e o u s seafloor in the course of the overall intrusive event (Huuse et al. 2004, 2005; Shoulders & Cartwright 2004). These sand units appear to be locally transported from the extrusive vent sites, and thus mimic the characteristics of depositional sands in many respects, except that they may have a patchy areal distribution and are difficult to place in an overall depositional context. The sandbodies form entirely stratigraphic traps with four-way dip closure. The possibility that major sandbodies could have an allochthonous origin as extrusive bodies fed by underlying sandstone intrusions raises many interesting questions about the prospectivity and identification of such bodies. Not least is the question of scale: how large a sandbody can potentially be formed during an extrusion episode? Outcrop data describing extrusive sands (extrudites) are sparse and largely restricted to descriptions of sand (and silt) volcanoes in ancient systems and sand volcanoes and associated sand sheets (blows) in modern (terrestrial) systems (Obermeier 1989; Gallo & Woods 2004). One exception to this are extrusive sands adjacent to large intrusive sand complexes in Miocene mudstones between the San Gregorio and San Andreas faults near Santa Cruz where

individual extrudites may be up to 3 m thick (Boehm & Moore 2002). Closer examination of these outcrops reveals that there are several extrudite units that form a stacked series of laterally extensive sands, which are currently tar saturated. Another extrudite is recognized in a Late Permain aeolian setting where sand extruded into an ephemeral lake in an inter-dune area as a consequence of mass wasting of a dune field during a period of increasing precipitation and rising humidity (Glennie & Hurst 2006). Because sand injectites, forming intrusive traps (Hurst et al. 2005) are increasingly recognised in petroliferous basins, in particular in association with deep-water clastic reservoirs (Jolley 8,: Lonergan 2002), we believe that the possible occurrence of extrudites associated with the injectites should be considered, both in terms of a reservoir geometry that may contain incremental reserves, and if sufficiently large as discrete traps. Here, we aim to provide some preliminary criteria for differentiating between extrudites, injectites and depositional sandbodies as we believe that extrudites are more c o m m o n than currently perceived, that they may have been drilled and misidentified as depositional units, and that they may contain significant reserves.

Extrusive s a n d s t o n e s The simplest and best-known examples of extrusive sands (extrudites) are sand volcanoes

From: ALLEN,M. R., GOFFEY,G. R, MORGAN,R. K. & WALKER,I. M. (eds) 2006. The DeliberateSearchfor the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 289-300. 0305-8719/$15.00. 9 The Geological Society of London 2006.

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A. HURST E T A L .

(Fig. 1). Sand volcanoes are infrequently preserved in the geological record (e.g. Gill & Kuenen 1957; Leeder 1999) and are usually less than 2 m in diameter, and when preserved they are typically highly symmetrical. A l t h o u g h arguably most commonly preserved in deepwater environments (Jolley & Lonergan 2002) sand volcanoes are preserved in other depositional environments, for example aeolian (Netoff 2002; G l e n n i e & Hurst, 2006). In m o d e r n terrestrial environments sand volcanoes are common in areas of active seismicity where they sometimes merge into laterally extensive, but patchy, sand sheets (Obermeier 1989, figures 14-18). In m o d e r n subaqueous environments formation of sand volcanoes is commonly observed, for example in tidal flat environments, but their preservation potential is poor. As individual sand volcanoes are small features they are of no interest as reservoirs, but extensive sand volcano fields fed by numerous fissures may be of sufficient volume to warrant interest. Sand volcanoes form above "~,,,l~, wh .... represent breach points through low permeability (seal) lithologies and sometimes form in close proximity, sometimes oriented along, underlying fault planes (Leeder 1999, figure 12.1). Often sand volcanoes have an apparently random distribution within a general area in which they are common (Gill & Kuenen 1957; Obermeier 1989). Where extrusion of sand has been volumetrically sufficient and the vents are closely spaced, sand volcanoes merge to form sand sheets (e.g. Obermeier 1989; Netoff 2002).

Seismic evidence If extruded sandbodies are to represent potential drilling targets, they need to be resolvable on seismic data. They need to be fed by sand intrusions whose size and whose parent sandbodies are sufficiently large to give a reasonable probability for a high sand flux to the surface, and to allow hydrocarbon migration into the extruded reservoir some time after burial. By analogy with outcrop and modern day sand sheets it seems unlikely that individual extruded sands are likely to exceed c. 5 m. If they form stacked series of extrusions, as in the Santa Cruz area, sand-dominated intervals with gross thickness in excess of 10 m may occur. To our knowledge the only records of possible extrudites identified on seismic data are by our research group (Huuse et al. 2004, 2005; Shoulders & Cartwright 2004; Hurst et al. 2005). Well data to confirm the reservoir quality of these extrudites is sparse, but in at least one case the sparse well data that exist are encouraging (Huuse et al. 2005).

Fig. 1. A sand volcano from the Ross Formation (Carboniferous), County Clare. This locality was first described by Gill & Kuenen (1957) and has tens of similar sand volcanoes developed on an extensive wave-cut platform. The sand extrusion occurred in a deep-marine setting. Grain size is very fine sand. Flow structures are seen along the dip of cone away from a well-defined crater. The hammer is approximately 0.35 m long (photograph courtesy of Rene Jonk). As sand extrusions are genetically related to sand injectites the identification of the discordant geometries formed by injectites is the first step toward identifying where possible extrudites may occur. A number of potential extrudite geometries are known from interpretation of seismic data (Figs 2, 3, 4 & 5). Discrete sheet-like bodies fed by one or several dykes/sills were identified following a deliberate search for sub-circular features in areas where sand injections were present in lower intervals (Fig. 2); although well data confirm the presence of sand in this interval core data are not available. Similar bedding-parallel features formed at the tips of multiple conical sandstone intrusions are known to contain sand and are strong candidates for sea-floor extrusions of sand (Figs 3 & 4). Sea-floor (or bedding) -parallel extensions of inclined sills or low-angle dykes (Fig. 5) are commonly associated with deep-water clastic reservoirs and are known to contain sand (MacLeod et al. 1999; Duranti et al. 2002; Huuse et al. 2004) and have been known since the mid1990s (Lawrence et al. 1999). A n e c d o t a l evidence and the results of recent drilling (de Boer et al. 2006) suggest that these features may in fact be relatively low net/gross and probably represent shallow subsurface intrusions (sills) rather than sea-floor extrusions as previously inferred by Jolley & Lonergan (2002).

Trap geometry Extrudite geometry is a function of the volume of sand extruded, the topography of the

EXTRUSIVE SANDSTONES (EXTRUDITES)

Fig. 2. A possible extruded sand sheet from the Eocene, UK Outer Moray Firth. The feature forms bedding parallel hard reflectors (arrowed), which are fed by a feeder dyke (D). To the left of the dyke a small fault displacement disrupts the inferred sand extrusion. A well penetration out of the plane of section indicates that the interval is sand prone (modified from Hurst et al. 2005). sea-floor, and the number and geometry of active vents. Surface extrusions of sand have four-way

291

dip closure and have one or more dykes feeding them from below (Fig. 6), which may also have a hydrocarbon charge. As already noted, extrudites may emanate from point (volcanoes) or fracture vents. The presence of sand injectite systems below extrudite sand sheets, and the stratigraphically isolated nature of extrudites is key evidence that allows their discrimination from depositional mounds, which are not fed by injectites and usually can be traced back to contemporaneous, depositional feeder systems. Extruded sands thin and dip away from vents typically forming stacked and interfingering low-angle laminae or thin beds. Sub-circular bodies that thin away from points, and areas, of extrusion seem to be the most likely geometries to form with the main potential for modification of the p l a n f o r m geometry (assuming that erosion of the sand does not occur) being the shape and topography of the surface onto which extrusion occurs, and any subsequent remobilization during burial.

Fig. 3. Converted-wave seismic profile from Chestnut Field (Outer Moray Firth) showing a possible extrudite reservoir underlain by lower Eocene mudstones crosscut by conical intrusions. Location of profile A - A ' is shown together with the calibration of high amplitudes to tens of metres thick sandstones in the boreholes (data courtesy of WesternGeco, figure compiled from Huuse et al. 2005).

292

A. HURST E T A L .

Fig. 4. 3D visualization of conical intrusions (lower Eocene) and Alba/Chestnut reservoirs (mid-upper Eocene) in UK Block 22/2 (Outer Moray Firth) (from Huuse et al. 2005).

Outcrop data Sand sheets are the extrudites of relevance to hydrocarbon reservoirs, although the presence of sand volcanoes may give local enhancement of the vertical permeability of seal lithologies. Modern sand sheets on the floodplain of the Mississippi Valley may reach approximately 2 km 2 and merge with similar deposits over areas of 10s of km 2 ( O b e r m e i e r 1989). We estimate that this possibly represents a volume of extruded sand of the order of 105-107 m 3. In seismically-active areas extrudites form as a response to the seismicity and, as recorded in

the Santa Cruz area, stacked sand extrusions are preserved that are likely to record periods of sand extrusion related to seismicity along the San A n d r e a s and San Gregorio fault zones (Thompson et al. 1999; Boehm & Moore 2002; Hurst 2004; Thompson et al. 2006). Not all extrudites are associated with seismicity and may form single discrete units (e.g. the Hopeman example formed during a period of masswasting of aeolian dunes triggered by increased humidity). Modern examples of terrestrial sand sheets (Obermeier 1998; Leeder 1999; Gallo & Woods 2004) show, or assume that sand is vented from

Fig. 5. A possible sea-floor extrusion/shallow sill in the Hamsun prospect (Eocene), Norway Block 24/7 linked to high-angle (c. 25-30 ~ dip) transgressive sill/low-angle dyke (modified from Huuse et al. 2004). (a) Top right Sandstone reservoir outlined by a wing-like discordant anomaly. The anomaly crosscuts approximately 200-250 m of mudstone-prone Balder and Frigg formations before becoming bedding concordant, possibly representing an extruded sandstone sheet. (b) Bottom right Plan view of the feature in a. Top Balder (grey) and the top of the anomalous amplitudes (interpreted as sandstone, colour range c. 2000-1750 ms TWT). The concordant, possibly extrusive part at the upper tip off the wing-like intrusion is indicated by the red colour. Note the similarity with saucer-shaped igneous intrusions. This feature has recently been drilled by the Marathon/Lundin partnership and a >100 m hydrocarbon column is proven (De Boer et al. 2006).

EXTRUSIVE SANDSTONES (EXTRUDITES)

293

294

A. HURST E T A L .

sea-floor

Fig. 6. Extrudite trap geometry. In the simplest form an extruded sand has a single low-angle conical geometry and is fed by a single feeder dyke (for example, a sand volcano, Fig. 1). A depression is commonly preserved above the vent that will be inundated by later extrusions if they occur. If fed by a fracture vent an elongate, crudely elliptical geometry will form (dependent on sea-floor topography), which is elongate in the direction of the fracture; such extrudites are fed by multiple vents (Fig. 7).

point sources (volcanoes). In contrast both ancient examples show that sand sheets emanate from fracture vents (Fig. 7). In the Californian example (Hurst 2004) one can see that the sand sheets are formed by amalgamations t,t - ~ smanel ..... "--- extrusions (Fig. 8), however the plan-view geometry of the extrusions is not visible. We assume that the fracture vents form elongate, crudely elliptical, rather than approximately conical extrusive mounds. In the much smaller aeolian Hopeman sandstone example plan-view exposure reveals that fracture vents and (one at least) point source vent may have coexisted (Glennie & Hurst 2006). The margins of the extrusions are sharp against the underlying strata although the underlying strata may be highly disrupted adjacent to vents (Fig. 9a). Transitional extruded sand-underburden relationships are not observed, both because they tend not to contain significant fine-grained material and, because they are deposited rapidly. In common with other components of sand injectites extruded sands tend to be fine to medium grained and moderately well sorted (coarser and finer grains are less easily fluidized, Lowe 1975). Exceptions to this generalization undoubtedly occur. Where clasts of sea-floor (or other seal) lithologies are reworked into the extruded sands reservoir quality is degraded. In Figure 9b mudstone clasts have been transported several metres upward from the seafloor. Distribution of mudstone clasts is irregular but associated with breach points in the underlying seal lithology. Bioturbation and sedimentary lamination will affect the extruded sand reservoir quality in a similar way to other sandbodies. Preservation of extrudites depends on the post-extrusional processes to which the sand is

subjected. Ideally to have a high probability of preservation in sub-aqueous environments the sediment surface must lie below storm wavebase and be unaffected by tidal currents. All extrudites have potential as hydrocarbon traps when overlain by a seal lithology. Individual extrudites in the Californian example (Figs 7a,b, 8 & 9) vary in thickness up to approximately 5 m, have locally strongly discordant bases (including rip-up clasts) and are exposed over a N W - S E section of more than 1.5 km. Assuming a circular plan-geometry and constant thickness of 5m this would be equivalent to a reservoir unit in the range of 2-3 • 106 m 3. When the base is less disrupted it is typically bioturbated. A2part from burrowing, the top surface is low gradient and conformably overlain by siliceous mudstones of the Santa Cruz Mudstone Member. The siliceous mudstone has acted as a seal for hydrocarbon migration and has trapped hydrocarbons as evidenced by the present-day tar-saturation.

Discussion A summary of some key characteristics of extrudites, injectites and depositional sandbodies emphasises the differences between them, although on seismic data the difference may be subtle (Table 1). E x t r u s i v e vs. i n t r u s i v e s a n d s t o n e s

Extrusive sands and bedding-parallel sills may appear similar on seismic data. Both may be part of larger sand injectite complexes and fed by deeper dykes and sills. Extrusive sands occur within the stratigraphic framework, as do all stratigraphic traps (Rittenhouse 1972) whereas intrusive sands, even when close to bedding parallel, will at some point show discordance with bedding along their upper and lower margins. Sometimes the discordance will be below the resolution of seismic data. If the extrusive units are sufficiently thick, subsequent sediments may form onlapping reflectors, which would not be associated with intrusive sandbodies. Onlapping relationships may not be preserved where the background sedimentation rate is sufficiently high and the upper parts of extrudites grade up into muds (mudstones), a gradation made more transitional by bioturbation (e.g. at the Majors Creek Beach locality, Fig. 9b). Extrudites have locally irregular bases (caused by disruption of the sea-floor during sand extrusion, but generally concordant tops. Sedimentary structures may be common and

EXTRUSIVE SANDSTONES (EXTRUDITES)

Fig. 7. Evidence for elongate, planar dykes that formed fracture vents rather than point source vents, feeding sand extrudites. (a) An approximately vertical vent and an overlying extrudite from the Miocene Santa Cruz Mudstone, California. The vent is filled with medium grained sand and entirely tar saturated (post extrusion). Low-angle laminae and beds are present in the extrudite as are cm-scale burrows; the mudstones underlying the extrudite are burrowed. The vent is elongate and can be traced > 5 m laterally to the adjacent cliff (see b). Scale is 0.3 m. (b) Top right Exposure on the wave-cut platform between the exposure in a and the main cliff. A network of sand-filled fractures, now tar saturated, forms elongate fracture vents that feed the overlying sand extrusion. A crudely orthogonal pattern of dykes, c. NE/NNE-SW/SSW (light grey) and c. N/NNW-S/SSE (black) feed the lower and upper extradites, respectively in the composite extrudite (shown in Fig. 9b). Scale bar (tape) is 0.3 m. (e) Bottom right A sandstone dyke feeding a 0.25--0.3 m thick sand extrusion in the aeolian Hopeman Sandstone (Late Permian). The dyke is planar and extends into the laminated sandstones within the field of view. The measuring tape is 0.4 m long (modified from Glennie & Hurst 2006).

diverse in extrudites, while intrusive sandstones may display discordant tops and bases and internal deformation bands (Purvis et al. 2002; Jonk et al. 2003), shale-clast breccias, microscale conjugate fault sets (Huuse et al. 2005), and margin-parallel (shale) clast alignment (Duranti & Hurst 2004). Intrusive sands are very unlikely

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to have any trace of b i o t u r b a t i o n w h e r e a s bioturbation is c o m m o n in extrusive sands. Extrudites provide potentially valuable stratigraphic correlation surfaces within sand injectite systems, which otherwise have discordant relationships with biozones. The chrono- and event-stratigraphic significance of extrudites has, however, not b e e n investigated in any detail. Their value as stratigraphic markers is likely to be enhanced in subsurface studies as their bedding-parallel lithological character is likely to form impedance contrasts that will be imaged by seismic data (the background for Fig. 2). If core or borehole images are available the presence of small intrusive bodies above

296

A. HURST ETAL.

Fig. 8. Interfingering packages of low-angle laminae and beds that have stacked together to form an approximately 1 m thick sand extrudite (Miocene, Majors Creek Beach, Santa Cruz, California). Each package represents a period of flow from a vent in the palaeo-sea-floor. At the base a thin sub-parallel sill feeds the extrudite and local detachment of fiat mudstone clasts occurs. The top of the unit is bioturbated so forming a gradual transition into the overlying Santa Cruz Mudstone Member). All the sands are tar saturated.

approximately bedding-concordant sills provides strong evidence for a non-extrudite origin (Fig. 10), unless these formed during a later phase of sediment remobilization (cf. Huuse et al. 2005).

E x t r u s i v e vs. ' n o r m a l ' d e p o s i t i o n a l sandstones Both on seismic and at outcrop the association between sand injectites in the underlying section and extrudites is critical (Table 1). It is feasible that depositional sands erosionally truncate and overlie sand injectites but typically the presence of sandstone dykes and sills below a sandbody will be a record of a genetic relationship. If the disruption of the underlying strata is substantial this may be revealed on seismic and is certainly visible at outcrop. In core it is highly likely that extrudites have been and will

continue to be confused with 'normal' depositional sandstones as both may contain sedimentary structures; the current paucity of core data from known extrudites limits this comparison. Low-angle lamination and/or bedding in extrudites (Figs 7a, 8 & 9b) may be confused with tabular cross-bedding. Lamination and bedding in extrudites is unlikely to approach unidirectional because of the radial or crudely elliptical flow around point and fracture vents, respectively. It is quite possible that extrudites have already been cored but misinterpreted as dunescale cross-bedding. Deep-marine and alluvial environments are those in which extrusive sandbodies are known to occur. Extrudite sandbodies in terrestrial environments are best k n o w n from recent examples (e.g. Obermeier 1998; Leeder 1999; Gallo & Woods 2004) with limited documentation of ancient examples (Netoff 2002; Chan et al. 2006). Deep-marine examples of extrusive

EXTRUSIVE SANDSTONES (EXTRUDITES)

Fig. 9. (a) An example of highly disrupted strata underlying a sandstone extrusion on Majors Creek Beach (Santa Cruz). The extruded sand varies in thickness dramatically to the left (NE), probably associated with proximity to vents in the sea-floor. Below the extrudite, and in particular in the right field of view, the underburden Santa Cruz Mudstone is brecciated and intruded by a complex series of sandstone dykes and sills (all tar saturated). (b) An extruded sand sheet in the Santa Cruz Mudstone (Miocene, California). The sand is medium grained and tar saturated. The base of the sand sheet is irregular (> 1 m relief in places) and fed by numerous sandstone dykes that cut through the fractured, porcellanous mudstone. Large (some >2 m length) rafts of mudstone (M) are common. The upper surface has a very gentle slope and is conformably overlain by mudstone of the Santa Cruz Mudstone Member (Thompson et al. 1999). Cross bedding and burrows are common in the upper part of the sand sheet.

sandstone bodies are represented in the rock record by sand volcanoes (Gill & Kuenen 1957; Jonk et al. 2006) and submarine extrusive sand sheets ( B o e h m & M o o r e 2002). Given the limited knowledge of intrusive traps, particu-

297

larly on a global basis, it is quite likely that extrusive sandbodies that are associated with them have been encountered but not recognized as of extrusive origin. We are unaware of exploration wells that have deliberately targeted the extrudite stratigraphic elements of intrusive traps. Development drilling on fields known to be affected by sand injection may have drilled through sandrich units that extruded onto a palaeo-sea-ttoor but, although candidate sandbodies exist (Figs 2, 3, 4 & 5), none are proven. As such the prospectivity and reserve potential of extrusive sandbodies is untested. F r o m the dimensions of known extruded sandbodies it is probably rare that isolated extrusive sandbodies will reservoir major reserves, but they are likely to be interesting secondary targets when exploring in areas associated with intrusive traps, or where they merge laterally with similar features (cf. Obermeier 1989, figures 14 to 18). In the Santa Cruz area the extrudites have a large areal extent and have been quarried for their tar. Estimates of gross rock volume of large extrudite bodies may be of the order of 105-108 m 3, equivalent to a possible pore volume of these often poorly cemented sandstones of the order of 105-108 barrels.

Conclusions Extrudite sand sheets are entirely stratigraphic traps associated with sand injectites and intrusive traps. Extrudites have four-way dip closure and typically overlie and underlie lower permeability strata. A l t h o u g h sand injectites are increasingly recognized, particularly in deep-water systems, they are a new play in terms of hydrocarbon prospectivity beyond the N o r t h Sea. As extrudites are even less widely

A. HURST E T A L .

298

Table 1. Guidance for differentiation between extrudites, sills and depositional sands

Seismic Injectite association Max thickness individual group Boundaries top . base Internal structures

Bioturbation Connectivity with underlying units

Extrudites

Sills

Depositional (mounds)

bedding parallel

bedding parallel (+ local discordance)

mounded

yes

yes

yes

<5 m 5-15 m

15-20 m >30 m

>20 m

concordant (graded) concordant

discordant discordant

concordant (graded) concordant &/or erosional

(i) low-angle lamination/bedding (ii) soft sedimentary deformation (iii) cross bedding

(i) deformation bands (ii) margin-parallel clast alignment (iii) conjugate micro-faults

diverse

common

unknown

present

highly connected porous networks

highly connected porous networks

rarely connected

(a)

(b)

Fig. 10. Cross-sections of possible (a) sill and (b) extrudite geometries that demonstrate the overall similar macro-scale geometry but fundamentally different relationships with adjacent strata. (a) is bedding parallel but has a series of small intrusions above the main sill and has similarities to the geometry inferred in Figure 5. In (b) the extrudite is bedding parallel but shallower intrusions are not present. The sand body has macro-scale similarities to Figure 2 and internal characteristics similar to Figures 8 & 9b. recognized than injectites their d o c u m e n t a t i o n is presently very sparse. However, we believe that they will be recognized m o r e commonly in

the future as the awareness of 'unconventional' s a n d s t o n e occurrences grows in the E & P community. I n d e e d we think that the main reason why extrudites are so rarely characterized is that they have been misinterpreted as depositional units in some subsurface studies. Examination of analogue data suggests that extrudites h a v e uniformly high reservoir quality except for where mudstone clasts are present. Extrusive sand sheets are fed by sand injectite systems, which provide potential pathways for h y d r o c a r b o n migration and aquifer support, and they should thus be an attractive and straight-forward play type, once it is realized that their occurrence cannot be predicted using paleogeographic maps for the stratigraphic interval in which they are located. Some of this work was supported by the sponsors of the Injected Sands Research Consortium, ChevronTexaco UK, Enterprise Oil Norway, Kerr McGee UK, Norsk Hydro, Shell UK, Statoil and TotalFinaElf, to whom we are grateful. Review comments by L. Richmond and R. Fitzsimmons were most helpful. Seismic and well data from the Chestnut Field were kindly provided by WesternGeco. JAC and MH acknowledge the generous software support to the 3DLab at Cardiff University by Schlumberger Information Solutions.

EXTRUSIVE SANDSTONES (EXTRUDITES)

References BOEHM, A. & MOORE, J.C. 2002. Fluidized sandstone intrusions as an indicator of paleostress orientation, Santa Cruz, California. Geofluids, 2, 147-161. CHAN, M., NETOFF, D., BLAKEY, R., KOCUREK, G. & ALVAREZ,W. 2006. Syndepositional deformation structures associated with Jurassic eolian deposits; Examples from the Colorado Plateau. In: HURST, A. & CARTWRIGHT, J.A. (eds) Sand Injectites: Implications for Hydrocarbon Exploration and Production. American Association of Petroleum Geologists, Memoir 87, Tulsa, Oklahoma, in press. DE BOER, W., RAWLINSON, P. & HURST, A. 2006. Successful exploration of a sand injectite complex: Hamsun prospect, Norway Block 24/9. In: HURST, A. & CARTWRIGHT, J.A. (eds) Sand Injectites: Implications for Hydrocarbon Exploration and Production. American Association of Petroleum Geologists, Memoir 87, Tulsa, Oklahoma, in press. DURANTI,D. & HURST,A. 2004. Fluidisation and injection in the deep-water sandstones of the Eocene Alba Formation (UK North Sea). Sedimentology, 51, 503-531. DURANTI, D., HURST, A., BELL, C. & GROVES, S. 2002. Injected and remobilised sands of the Alba Field (UKCS): sedimentary facies characteristics and wireline log responses. Petroleum Geoscience, 8, 99-107. GALLO, E & WOODS, A.W. 2004. On steady homogeneous sand-water flows in a vertical conduit. Sedimentology, 51, 195-210. GILL, W.D. & KUENEN,P.H. 1957. Sand Volcanoes on slumps in the Carboniferous of County Clare, Ireland. Quarterly Journal of the Geological Society of London, 113, 441460. GLENNIE, K.W. & HURST, A. 2006. Fluidisation and associated soft-sediment deformation in eolian sandstones: Hopeman Sandstone (Permian), Scotland, and Rotliegend, North Sea. In: HURST, A. & CARTWRIGHT, J.A. (eds) Sand Injectites: Implications for Hydrocarbon Exploration and Production. American Association of Petroleum Geologists Memoir 87, Tulsa, Oklahoma, in press. HURST, A. 2004. Sedimentology of seafloor sand extrusions: an example from the Miocene of central California. British Sedimentological Research Group Annual General Meeting, Manchester, 19th-21 st December, Abstract. HURST, A., CARTWRIGHT, J.A., DURANTI, D., HUUSE, M. & NELSON, M. 2005. Sand injectites: an emerging global play in deep-water clastic environments. In: DORE, A. & MINING,B. (eds) 6th Petroleum Geology Conference: North West Europe & Global Perspectives, Geological Society, London, 133-144. HUUSE, M., DURANTI,D., STEINSLAND,N., GUARGENA, C., PRAT, P, HOLM, K., CARTWRIGHT, J.A. & HURST, A. 2004. Seismic characteristics of largescale remobilised and injected sand bodies in the Paleogene of the South Viking Graben (North

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Sea): steep-sided mounds, wings and Vs. In: DAVIES, R.J., CARTWRIGHT, J.A., STEWART, S.A., LAPPIN, M. & UNDERHILL,J.R. (eds) 3-D Seismic Technology: Application to the exploration of sedimentary basins. Geological Society, London, Memoir, 29, 263-277. HUUSE, M., CARTWRIGHT, J., GRAS, R. & HURST, A. 2005. Km-scale sandstone intrusions in the Eocene of the Outer Moray Firth (UK North Sea): migration paths, reservoirs, and potential drilling hazards. In: DORI~, A.G. & MINING, B. (eds) Petroleum Geology: North-West Europe and Global Perspectives - Proceedings of the 6th Petroleum Geology Conference, Geological Society, London, 1577-1594. JOLLEu J.H.R. & LONERGAN, L. 2002. Mechanisms and control on the formation of sand intrusions. Journal of the Geological Society, 159, 605~17. JONK, R., DURANTI, D., PARNELL, J., HURST, A. & FALLICK,A.E. 2003. The structural and diagenetic evolution of injected sandstones: examples from the Kimmeridgian of NE Scotland. Journal of the Geological Society, 160, 881-894. JONK, R., CRONIN,B.T. & HURST,A. 2006. Sand extrusion at the sediment-water interface: sand volcanoes from the Namurian of County Clare, Ireland. In: HURST,A. & CARTWRIGHT,J.A. (eds) Sand Injectites: Implications for Hydrocarbon Exploration and Production. American Association of Petroleum Geologists Memoir 87, Tulsa, Oklahoma, in press. LAWRENCE, D.A., SANCAR, B. & MOLYYEUX,S. 1999. Large-scale elastic intrusion in the Tertiary of Block 24/9, Norwegian North Sea: origin, timing and implications for reservoir continuity. American Association of Petroleum Geologists Bulletin, 83, 1324. LEEDER, M.R. 1999. Sedimentology and sedimentary basins: from turbulence to tectonics. Blackwell Science, Oxford. LOWE, D.R. 1975. Water escape in coarse-grained sediments. Sedimentology, 22, 157-204. MACLEOD, M.K., HANSON, R.A., BELL, C.R. & McHuGO, S. 1999. The Alba Field ocean bottom cable seismic survey: Impact on development. The Leading Edge, 18, 1306-1312. NETOFF, O. 2002. Seismogenically induced fluidization of Jurassic erg sands, south-central Utah. Sedimentology, 49, 65-80. OBERMEIER, S. 1989. The New Madrid earthquakes: an engineering-geologic interpretation of relict liquefaction features. US Geological Survey Professional Paper 1336-B. PURVIS, K., KAO, J., FLANAGAN,K., HENDERSON,J. & DURAYrI, D. 2002. Complex reservoir geometries in a deep-water clastic sequence, Gryphon Field UKCS: injection structures, geological modelling and reservoir simulation. Marine and Petroleum Geology, 19, 161-179. RITTENHOUSE, G. 1972. Stratigraphic trap classification. In: KING, R.E. (ed.) Stratigraphic oil and gas fields - classification, exploration methods and case histories. American Association of Petroleum Geologists, Memoir 16, Tulsa, Oklahoma, 14-28.

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SHOULDERS,S.J. & CARTWRIGHT,J.A. 2004. Constraining the depth and timing of large-scale conical sandstone intrusions. Geology, 32, 661-664. THOMPSON,B.J., GARRISON,R.E. & MOORE, C.J. 1999. A late Cenozoic sandstone intrusion west of Santa Cruz, California: fluidised flow of water and hydrocarbon-saturated sediments. In: GARRISON, R.E., AIELLO, I.W. & MOORE, C.J. (eds) Late Cenozoic fluid seeps and tectonics along the San Gregorio fault zone in the Monterey Bay region,

California. American Association of Petroleum Geologists Pacific Section, Volume and Guidebook GB-76, Tulsa, Oklahoma, 53-74. THOMPSON, B.J., GARRISON,R.E. & MOORE, C.J. 2006. A giant Miocene sandstone injectite near Santa Cruz, California. In: HURST, A. & CARTWRIGHT, J.A. (eds) Sand Injectites: Implications for Hydrocarbon Exploration and Production. American Association of Petroleum Geologists Memoir 57, Tulsa, Oklahoma, in press.

Index Page numbers in italic indicate figures, those in bold denote tables.

accidental discovery 68, 71 see also serendipity Alba Field, UKCS 163,164, 212, 219, 292 analysis, post-drill 232 Ansai Field, China 73, 74, 75, 76, 87 Aptian-Albian play 172-174,174, 178-184 Arbroath Field, UKCS 163 Ardjuna Basin, Indonesia 110 Asahan Offshore, Indonesia 115-116,122,123 Asri Basin, Indonesia 116,117, 119 Assynt prospect, UKCS 234, 236-238 Athabasca Oil Sands, Canada 87 Auk Field/High, UKCS 176,178,183 Australia 92 back-stripping 203 basalt 176-178,183,252, 253,260, 263 basin setting for stratigraphic traps 84-86 bathymetry 197-198,199, 203,251 Beatrice Field, UKCS 190 Bell Creek Field, Wyoming 106 Biliton PSC, Indonesia 116,119,124,125 biodegradation 263 Blake Field 200, 202 Bonga Field, Nigeria 13-14,15 Bowen Basin, Australia 92 Brae Field, UKCS 212, 214, 215, 217 Brenda Field, UKCS 163,212, 219 Britannia Field, UKCS 172, 182, 183,213,219 Buchan Basin, South 173,175,176,177,179,180, 184 Bud Field, Gulf of Mexico 138,145 Bullwinkle Field, case study 81, 82, 83, 84 burial 227,229, 230, 263 Buzzard Field, UKCS 154,159,187-204,215 Canada 8, 9, 87, 92,100,101 Captain Field, UKCS 173,190 carbonate facies 68, 95,128, 158 Carboniferous play, UKCS 156, 165 case histories Bullwinkle Field 81, 82, 83, 84 Buzzard Field, UKCS 187-206 deep water sands 144-150 East Texas Field 63, 66, 68-70, 87 Indonesia 111-124 Jay Field 68, 70, 71, 72, 87 Central Limit Theorem 21-22 Central North Sea 207-222 trap classification 181-183 Central North Sea Graben, UKCS 158,159, 161,163, 164 Cretaceous plays in 169-185 chalk play, UKCS 162-163 Chalufy, France 268,273 channel/levee sand system, Gulf of Mexico 127-150

channel-fill reserves 87, 89, 93 channel-fill sandstone 197, 199-200, 238 Chanter Field, UKCS 215 charge volume 203, 229-230 evaluation of 193-195 Chestnut Field, UKCS 212, 291,292 China 73, 74, 75, 76, 87 Cimmerian unconformity 191,192, 195, 197 classification of traps in Central North Sea Graben 181-183 combination trap 24, 61 deep-water sand 135-141 stratigraphic 59-62 Claymore Field, UKCS 161,213, 216 coal bed methane 87, 92 colour categorization 4446, 48, 5/ column height 18,108,110 combination trap, classification 24, 61 communication, technical-commercial24, 32, 40 compaction 199,217,219 constructional trap 135,143,150 creaming curves 203 Cretaceous play, UKCS 160-163,165,178-180 Central North Sea Graben 169-185 see also Ryazanian-Barremian Cretaceous trap 240-241 Decision Tree Analysis 19-20, 39, 40 decompaction 203 deep-water sand 134-135, 159,160, 162, 163,164, 165 plays 127-150,169-185 seismic interpretation 143-144,145 Denmark, Halfdan Field, 163 depositional model 134-135, 192-193 destructional trap 135-143, 145,150 diagenetic trap 90 dip 108,109, 113,130, 133,144, 225 in extrudites 289,291,298 impact on oil recovery 279, 280, 282, 284, 285 discount rate 21, 37, 40 dry hole risk 33, 34, 35, 40, 92, 97, 99 dynamic behaviour modelling 271-285 East Central Graben, UKCS 179, 183 East Solan Basin UKCS 161,162 East Texas Field, case study 63, 66, 68, 69, 70, 86, 87 Efficient Frontier Technique 21 Elmworth-Wapiti trap, Canada 92 energy-demand forecast 30 Enoch Field, UKCS 212 Eocene 164, 240, 247-265,291, 292,293 subsidence 250, 253,263 Ettrick Field, UKCS 190 evaluating prospects 7-25,202-204

From: ALLEN,M. R., GOFFEY,G. P., MORGAN,R. K. & WALKER,I. M. (eds) 2006. The Deliberate Search for the Stratigraphic Trap. Geological Society, London, Special Publications, 254, 301-304. 0305-8719/$15.00. 9 The Geological Society of London 2006.

302 evaluation of technology 187,190, 190-200 evaluation of well data 191,231 Everest Field, UKCS 212, 219 exploration 27-40,106-111,180-185 and investment 31-33, 37 for stratigraphic traps 1-4, 28-33 exploration history 77, 81, 84,106 exploration industry, review of 2-4 exploration techniques 92-100, 187-204 extrusive sandstone (extrudite) 289-298 failure 231-232, 234, 236-238, 244 fan 164,173,190, 248 basin floor 161,241,242, 247,263 detached basin floor 182,184, 185 hanging-wall trap 181,184 Faroe-Shetland Basin 225-244, 247,289 field size 7,11, 37-39,106 Fife Field, UKCS 163 Foinaven Field UKCS 163,225,227-238,244 Fischschiefer Bed 170,171,173,176,177,180 Fisher Bank Basin 173,177, 184 Fleming Field, UKCS 212, 219 Flett Sub-basin, UKCS 226-233,238, 239 Flora Field, UKCS 163 fluid identification 4 fluvial sandstone plays 158,163 foreland basin 84, 86 Forties Field, UKCS 163 Forties Volcanic Province 183 fracture trap 87, 90 fractures in seismic response 98 France 268,273 Frigg Field, UKCS 163 Galley Field, UKCS 214 Gannet Field, UKCS 212 gas and condensate trap 92 gas show 175-176,178,233-234, 238, 239, 240 geochemical techniques 97-100 Geologically Driven Integration 195,196, 197 Giddings Field, USA 98 Guillemot Field, UKCS 163,212 Gulf of Mexico 100, 127-151,268 gull-wing 133, 134, 135,137 Halfdan Field, Denmark 163 Halibut Field, South, UKCS 183,185,187, 190 Hartzog Draw Field, Wyoming 106 Hatton-Rockall, UKCS 247-265 heavy oil trap 87, 92, 95 Highlander Field, UKCS 159,213 hydrocarbon indicator anomalies 15, 230-233 hydrocarbon reserves 14 Iceland hot spot 251-252 Idd A1-Shargi Field, Qatar 96 igneous rocks 176-178,183 image interpretation 43-54 Indonesia 10,105-126 injectite 164, 219,289-298 Interval Probability Theory 13 Irish Sea Basin 158

INDEX Jay Field, UKCS 68, 70, 71, 72, 87 Joanne Field, UKCS 163 Jurassic play, UKCS 158-159,165,241-244 Kaji Semoga, Indonesia 113,118,119,120-121 Kimmeridge Clay seal 159, 218 Kimmeridge Clay source rock 183-184 West of Shetland 240, 241,242 Buzzard Field 187, 192,193 Kingfisher Field, UKCS 215 Kittiwake Field, UKCS 158,159,214, 217 Laggan Field, UKCS 225,228, 233-234,235, 244 lithologies of stratigraphic traps reviewed 8--10 Lyonesse Field, UKCS 259, 260 MacCulloch Field, UKCS 212, 219 mass flow deposits 2,176,179,248,254, 260-262, 263 sandstone in hydrocarbon fields 173,174 Mexico 10 Michelob Field, Gulf of Mexico 140,141, 143,145 Miller Field, UKCS 215 Minas field, Indonesia 111 Miocene 111,251 Miocene extrudites 292-296 model design 271-272,272, 273, 274 modelling, impact of shale erosion 280-282, 283 Montrose Field, UKCS 163 Moray Firth 160,161,181,182,185,187 mud fan, Mississippi 127-150 Nelson Field, UKCS 74, 78, 79, 80, 87 subtle combination trap 77 Neogene tectonics 251 North Sea 153, 159,252, 253 see also Central North Sea Norway Block 24/7 293 oil and gas 101,175-176, 190 oil recovery 275-279, 281, 282-285 oil seeps 73, 98-99,100, 106, 111 Oligocene inversion 240 Oligocene traps, Rockall Plateau 247-265 pinchouts 225,232, 234,239, 240 Oman 10, 13,14, 15 onlap 200, 208,218, 268-269 model 272, 273, 274, 275 trap 135, 88 onlap dip, impact on oil recovery 279-280, 282, 284, 285 Orinoco Heavy Oil Belt, Venezuela 92 Pabst Field, Gulf of Mexico 140,141, 142, 145 Palaeogene 164, 165,251-254 palaeogeography, Rockall-Hatton 251-254 palaeomagnetic study, Buzzard Field 195 Paleocene prospect 225-245 passive margin basin 2-3, 84 permeability 227,274, 280, 285 Permian play 157,165 petroleum-system approach 107-108, 111 and rift basins 107-108,112, 116, 124 Petronella Field, UKCS 216, 217

INDEX Pilot Field, UKCS 212 pinchout 107,159,160, 163,182,208, 220 Buzzard Field 187, 193,195,200, 202 Rockall Platform 225,232, 234, 239, 240, 259-260 trap 87, 88, 93, 95, 99 turbidite sandbody 267-285 pinchout and onlap 271-285 classification of 269-271 Piper Field, UKCS 216, 217 play analysis 32-36 see also risk play groups, UKCS 155, 156 play history, deep-water sands 130-132, 144-150 play in rift basins 156-165 Pliocene uplift 251 polarity reversal 140, 143-144 ponded fill 181-182, 184 porosity 96, 131-132, 227, 256 visible 256, 262,263 Powder River Basin, Wyoming 106,107 pressure analysis, Buzzard Field 193,228 probability 33, 34, 35, 38-39, 40 and risk 12-13,18,19, 22 profitable production 30-31 prograding wedge 253-255, 256, 259 prospectivity 262-263 prospect evaluation 7-25, 31 Prudhoe Bay Field, USA 87,101 Qatar 96 Quadrant 205, UKCS 236-238 reserves, recoverable 85, 86, 88, 89, 90, 91 reservoir 161,171-180,182-183,227, 247 in beach sandstone 63, 68, 73, 77 sands 131-135,137 in turbidite 15,100,130,135,187,190 resources discovered 28, 29 rift basin 84,105-125 risk 124,165,185,200, 202-203,220, 231 analysis 12-23, 31,211 behaviour 36-37 dry hole 92, 97, 99 estimation of 7,16-17, 18, 100, 108 RMS amplitude 241-242, 244 Rob Roy Field, UKCS 216 Rockall Plateau 247-265 Ross Field, UKCS 190 Ryazanian-Barremian play 171-173, 175-177, 181-184 Safah Field, Oman 13,14, 15 salt 81, 85, 86,159, 212 Saltire Field, UKCS 172, 213, 215, 217 sand injectite 164,219,289-298 sand volcano 289-290, 292, 297 Sandarro igneous centre 258 sandbody pinchout and onlap 269, 270-285 sandstone, extrusive 289-298 sandstone (beach ridge) reservoir 63, 68, 73, 77 Santa Cruz 289,290, 292, 294-296, 29& Scapa Field, UKCS 161,169,182,183,213 Schiehallion Field, UKCS 225,229 Scott Field, UKCS 216

303

seal 108,110,159,183-184, 203,263 Kettla Tuff 227-228, 233,236, 238 one-seal 210-211 poly-sea1211-220 sealing surface classification 207-222 in Tertiary fields 212-216 sealing surface and risk evaluation 16,18, 221 seismic 3D data 169,170,189, 195,200, 202 trap definition 226,238,239, 241-243 seismic amplitude anomaly 83, 84, 99, 140, 260 West of Shetland 230-236, 240 seismic amplitude maps 136-138, 141, 142 seismic amplitude variations with offset 230-234, 237 seismic data 44, 50,125, 248-249 and colour choice 44, 45, 46, 48-50, 51 seismic interpretation 191 Buzzard Field 198-200 deep-water sands 143-144,145 seismic interpretation and visual cognition 43-55 seismic interpreters, training for 51-54 seismic profiles 3D Corona Ridge 241 3D Solan Basin 242, 243 3D trap concept 189 Assynt, UKCS 237 basalt scarps 260 Buzzard Field 199 channel sandstone 134 extrudite 291, 292, 293 George Bligh Bank, UKCS 258 igneous centres 258 Laggan 235 Lyonesse 259 mass slump deposit 261 pinchout structure 99, 259 rift basin 114,117, 120-123 West Central Graben 172 wet sand with gas pay 146-150 seismic techniques, 3D, 4D 95-97 sequence stratigraphy 93, 94, 95,129-131 Central North Sea 209 serendipity 7,12, 24,125,159,163,169 accidental discovery 68, 71,165 shale erosion, in modelling 280-282,283 Solan Field, UKCS 241,242, 243, 244 Southern North Sea Gas Basin 157,158 statistics on discoveries, UKCS 153-156, 157, 160, 161, 165 on stratigraphic traps 64, 65, 66, 67 Strathmore Field, UKCS 158 stratigraphic trap classification 61 defined 1-2, 57 and extrudites 289-298 location 11 review 4, 8-10 statistics 64, 65, 66, 67 summary data 81-92 stratigraphic modelling 192-193,194 stratigraphy Buzzard Field 191 Central North Sea Graben 171 Paleocene 227

304 Rockall Basin 249-254 see also sequence stratigraphy subtle combination trap 57-103 Swithin igneous centre, UKCS 253,258 syn-rift play, UKCS 159-160,165 targets, search for 44, 48 Tartan Field, UKCS 159,215-216, 273 T-block Field, UKCS 214 Teal Field, UKCS 216 technology evaluation 187,190-200 tectonostratigraphy, Rockall-Hatton 249-254 Tertiary, rift and passive margin basins 2-3 transmissibility 280-281 trap 12, 85, 87, 88, 89 analysis 7,11, 37-38, 39 classification 207-222 definition 225-226 exploration history 62-63 global distribution 59 seal 210-220 see also under seal trap, Eocene 247-265 trap, subtle combination 57-103, 81-92 trap, volume distribution 58 trapping mechanism 8--10, 87, 91, 92,221 Tree Field, UKCS 214

INDEX Triassic play, UKCS 158-159 turbidite pinchout, onlap surface 268-269 turbidite reservoir 15,100,130, 135,187,190 UK Continental Shelf 153, 153-167 statistics on discoveries 153-156, 157,160,161, 165 Vaila play, UKCS 226-230, 233,234, 236,238,239 Venezuela 8, 92,101 Victory Field, UKCS 161 Viking Graben, North Sea 158,150 visual cognition 43-55 visual images 46, 47, 54, 292 volume of resource 85, 86, 87, 88-91, 184, 262 well data, evaluation 191,231 well location selection 200 well position and oil recovery 275-277, 278,285 wells, Central North Sea Graben 175, 177,178, 180 West Buchan Graben 187,192, 290 West Central Graben 179, 181 West of Shetland 161,163,164,225-245 Widuri Field, Indonesia 116, 117, 119 Witch Ground Basin 173 wrench basin 85, 86 Wyoming 106,107

The Deliberate Search for the Stratigraphic Trap Edited by M. R. Allen, G. R Goffey, R. K. Morgan and I. M. Walker \

"

Twenty-four years have elapsed since the publication of Halbouty's AAPG Memoir of 1982, The Deliberate Search for the Subtle Trap. Since then, the technologies employed in hydrocarbon exploration have become extraordinarily sophisticated, yet current exploration for stratigraphic traps is to some extent restricted to areas where seismic data simplifies exploration by allowing direct inference of fluid fill and reservoir development. This Special Publication draws upon contributions that examine current industry perceptions of stratigraphic trap exploration and the technologies, tools and philosophies employed in such exploration, given the changing industry environment. iP,

This book contains a collection of papers examining a number of themes related to exploration for stratigraphic traps, rangi~qg from play and risk assessment, through regional assessments of stratigraphic trapping potential, specific exploration programmes targeted at stratigraphic traps to specific working traps and plays where stratigraphic trapping is prevalent. Visit our online bookshop: http://www.geolsoc.org.uk/bookshop Geological Society web site: http://www.geolsoc.org.uk

Cover illustration: AVO-basedseismicinversion showing reservoircomplexity in a deep water channel offshore Nigeria. Image supplied by R. K. Morgan (VeritasDGC Limited)