ORIGINAND PREDICTIONOF ABNORMALFORMATION PRESSURES
Volumes 1-5, 7, 10, 11, 13, 14, 16, 17, 21, 22, 23-27, 29, 31 are out of print.
6 8 9 12 15a 15b 18a 18b 19a 19b 20 28 30 32 33 34 35 36 37 38 39
Fundamentals of Numerical Reservoir Simulation Fundamentals of Reservoir Engineering Compaction and Fluid Migration Fundamentals of Fractured Reservoir Engineering Fundamentals of Well-log Interpretation, 1. The acquisition of logging data Fundamentals of Well-log Interpretation, 2. The interpretation of logging data Production and Transport of Oil and Gas, A. Flow mechanics and production Production and Transport of Oil and Gas, B. Gathering and Transport Surface Operations in Petroleum Production, I Surface Operations in Petroleum Production, II Geology in Petroleum Production Well Cementing Carbonate Reservoir Characterization: A Geologic-Engineering Analysis, Part I Fluid Mechanics for Petroleum Engineers Petroleum Related Rock Mechanics A Practical Companion to Reservoir Stimulation Hydrocarbon Migration Systems Analysis The Practice of Reservoir Engineering Thermal Properties and Temperature related Behavior of Rock/fluid Systems Studies in Abnormal Pressures Microbial Enhancement of Oil Recovery- Recent Advances - Proceedings of the 1992 International Conference on Microbial Enhanced Oil Recovery 40a Asphaltenes and Asphalts, I 40b Asphaltenes and Asphalts, II 41 Subsidence due to Fluid Withdrawal 42 Casing Design - Theory and Practice 43 Tracers in the Oil Field 44 Carbonate Reservoir Characterization: A Geologic-Engineering Analysis, Part II 45 Thermal Modeling of Petroleum Generation: Theory and Applications 46 Hydrocarbon Exploration and Production 47 PVT and Phase Behaviour of Petroleum Reservoir Fluids 48 Applied Geothermics for Petroleum Engineers 49 Integrated Flow Modeling 50 Origin and Prediction of Abnormal Formation Pressures
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ORIGINANDPREDICTIONOF ABNORMALFORMATION PRESSURES G.V. CHILINGAR Professor of Civil and Petroleum Engineering, University of Southern California, Los Angeles, CA 90089-2531, USA V.A. SEREBRYAKOV DCD, Inc., Coulter Lane, Gillette, WY 82 716, USA J.O. ROBERTSON, Jr. Earth Engineering, Inc., 4244 Live Oak Street, Cudahy, CA 90201, USA
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DEDICATION This book is dedicated to His Royal Highness Prince Abdullah bin Abdulaziz, Crown Prince and Deputy Prime Minister, and Head of The National Guard of Kingdom of Saudi Arabia for his relentless support of all branches of engineering and sciences in order to improve the well-being of mankind.
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Vll
PREFACE
This book's 1 goal is to provide the geologists and engineers working in the petroleum industry with the latest knowledge on subsurface abnormally-pressured systems associated with hydrocarbon accumulations. Abnormally high- or low-pressured zones are succinctly defined as having a pore pressure gradient trend deviating from the normal hydrostatic pressure gradient over a given depth range. Drs. G.V. Chilingar, V. Serebryakov and J.O, Robertson have brought together a team of experts who have methodically scrutinized recent scientific and engineering developments concerning the global distribution, origins and predictions of abnormallypressured environments. The contributors have many years of collective experience as geologists, geochemists, geophysicists and petroleum engineers in studying, strategizing, detecting and coping with different kinds of pressure environments and subsurface mass transport-pressure phenomena. Their findings are based upon critical inquiry into the scientific details behind the proposed ideas and concepts of this phenomenon. They present an account of the nature of mass transport processes associated with such pressure systems and their accompanying patterns of geochemical and mineralogical changes. As petroleum engineer and geologist, I am convinced that their approach is definitely a worthwhile effort, even if many of the relationships that have been formulated and presented in the technical literature about the framework of these pressure systems are still of an observational and empirical nature. Exploration for large oil and gas accumulations is taking the industry into the offshore deep-water environments on the outer continental shelf. Abnormally-high formation pressures are ubiquitous in 'geologically' recent pelitic sedimentary environments, and their overpressure magnitude must be by necessity identified prior to drilling and completing a well. The subsurface pressure regime is hostile. Seismic detection and prior knowledge on subsurface pressure conditions are prerequisites in promoting safe drilling and development operations. Certainly, caution mitigates the risk of having costly pressure surges and blowouts, disruption of the company's unrealized cash stream, and occurrence of potential injury and loss of life to those individuals who are involved in well construction. Pressure prediction is the main technology focus in the majority of the book's chapters. Though the topic of abnormally-pressured zones is rooted in the preceding century, the application of thermodynamics to the physicochemical problem is just now being explored. Recent publications are helping to recast our opinions on the origin and maintenance of abnormal pressure zones and the resulting physical and chemical artifacts. 1This book is contribution No. 15 of the Rudolf W. Gunnerman Energy and Environment laboratory, University of Southern California, Los Angeles, California
viii The patterns of fluid flow powered by compaction disequilibrium or tectonic stress conditions, presence of salt beds and higher than normal geothermal temperatures create changes in the salinity of the pore water and its content of dissolved gases that flow out of and through the sediment/rock pore space. These processes determine the subsurface pressure regime, its integrity and stratigraphic distribution, and diagenetic/catagenetic alteration. The nature of abnormal pressure zones fluctuates over geologic time, and diagenetic/catagenetic history is manifested in the aqueous geochemistry and corresponding changes in the associated mineralogy especially clay mineralogy. Discussion on the lack of smectite to illite transformation in the Caspian Basin is enlightening. The book is offered in the hope that our knowledge will provide a new foundation for bringing about improved field performance, initiating innovative field and laboratory research, and nurturing analytical dialogue among the geoscientists and engineers. In addition to the customary topics discussed, there are two chapters that address other associated issues. One important ancillary topic is production-induced surface subsidence. Subsidence is the result of abnormally-low formation pressures owing to the production of fluids. The influx of shale water into the depleting hydrocarbon-producing zones results in shale compaction. The other chapter explores the use of analytical model studies, which complete the abnormal pressure picture by adding insight into likely pressure prediction strategies. In conclusion, this book is a welcome addition to the petroleum literature. H.H. Rieke Lafayette, LA, USA
1x
LIST OF CONTRIBUTORS
E AMINZADEH
President d G B - USA & FACT, 14019 SW FWY, Suite 301-230, Sugarland, TX 77478, USA
L.A. BURYAKOVS KY
5001 Woodway Dr., Apt. No. 702, Houston, TX 77056-1718, USA
G.V. CHILINGAR
University of Southern California, 101 So. Windsor Blvd., Los Angeles, CA 90004, USA
R.D. DJEVANSHIR
Institute of Deep Oil and Gas Deposits, Azerbaijan Academy of Sciences, Baku, Azerbaijan
E.C. DONALDSON
Consultant, Rt2, EO. Box 53, Wynnewood, OK 73098, USA
W.H. FERTL
Deceased
M.V. GORFUNKEL
Consultant, 676 Rain Tree Circle, Coppell, TX 75019, USA
A.E. GUREVICH
Consultant, 119 Avonlea Dr., The Woodlands, TX 77382-1058, USA
R. ISLAM
Professor and Killam Chair in Oil and Gas, Faculty of Engineering, Dalhousie University, E O. Box 1000, Halifax, Nova Scotia, Canada B3J2X4
S.A. KATZ
Consultant, 12250 S. Kirkwood Road, No. 1625, Stafford, TX 77477, USA
L. KHILYUK
Consultant, Russian Academy of Natural Sciences, U.S.A. Branch, 101 So. Windsor Blvd., Los Angeles, CA 90004, USA
H.H. RIEKE
Chairman, Petroleum Engineering Dept., USL, EO. Box 44683, Lafayette, LA 70504-4691, USA
J.0. ROBERTSON JR.
President Earth Engineering, Inc., 4244 Live Oak St., Cudahy, CA 90201, USA
V.A. SEREBRYAKOV
Consultant, 118 Mesa Dr., Gillette, WY 82716, USA
V.I. ZILBERMAN
Russian Academy of Natural Sciences, U.S.A. Branch, 101 So. Windsor Blvd., Los Angeles, CA 90004, USA
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x1
CONTENTS
Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . List of Contributors
Chapter 1
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
INTRODUCTION
TO ABNORMALLY
PRESSURED
vii ix
FORMATIONS
E.C. D o n a l d s o n , G.V. C h i l i n g a r , J.O. R o b e r t s o n Jr. a n d V. S e r e b r y a k o v . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1
Abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
Introduction
1
Subpressures
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
Surpressures
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
2
O r i g i n o f vertical b a r r i e r s r e s u l t i n g in a b n o r m a l f o r m a t i o n p r e s s u r e s
. . . . . . . . . . . . . . . . . .
3
Undercompaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4
Tectonic compression
4
Faulting
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6
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7
Diapirism
Geothermal temperature
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
P h a s e c h a n g e s that p r o d u c e a b n o r m a l p r e s s u r e s
. . . . . . . . . . . . . . . . . . . . . . . . . . .
O s m o s i s as a f a c t o r for g e n e r a t i o n o f a b n o r m a l p r e s s u r e S a l i n i t y o f interstitial w a t e r
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8 10 11 12
R e s e r v o i r e n g i n e e r i n g c o n c e p t s in a b n o r m a l p r e s s u r e e n v i r o n m e n t s . . . . . . . . . . . . . . . . . . .
13
E c o n o m i c s in o v e r p r e s s u r e e n v i r o n m e n t s
14
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
16
Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
17
Chapter 2
ORIGIN OF ABNORMAL
FORMATION
PRESSURES
G.V. C h i l i n g a r , J.O. R o b e r t s o n Jr. a n d H . H . R i e k e III Introduction
. . . . . . . . . . . . . . . . . . . . . .
Definitions
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Compaction process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrostatic pressure
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
F o r m a t i o n or interstitial fluid p r e s s u r e
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Sediment consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S t a t e o f stress in c o m p a c t i n g shales
21 21 21 24 24 24 25
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
29
R e s o l u t i o n o f the total stress field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
30
H y d r o s t a t i c stress state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
31
D e v i a t o r i c stress state
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31
Total stress t e n s o r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
32
Spring models of compaction
33
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Hooke's law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Load transfer
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Porosity-density variations with depth
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Compaction models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Athy's compaction model
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Hedberg's compaction model Weller's compaction model
36 37 42 43 44
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44
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
46
Xll
CONTENTS
Powers' compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Teodorovich and Chernov's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . Burst's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Beall's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overton and Zanier's compaction model . . . . . . . . . . . . . . . . . . . . . . Creation and maintenance of abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M e c h a n i s m s generating abnormal formation pressures . . . . . . . . . . . . . . . . . . . . . . . . . . Undercompaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tectonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth faults . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Transference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of temperature increase on formation pressure (aquathermal pressuring) Decomposition of organic matter . . . . . . . . . . . . . . . . . . . . . . . . . . Gas migration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Osmosis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Density contrast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
. . . . . . . . . . . . . . . . . . . . . . . . .......... . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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47 49 49 49 51 51 55 55 56 57 57 57 59 59 63 63 64 64
Chapter 3
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS A. Gurevich, G.V. Chilingar, J.O. Robertson and E A m i n z a d e h . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Factors causing fluid flow and pressure distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . Factors of fluid flow and pressure distribution and changes . . . . . . . . . . . . . . . . . . . . . Free convection of ground fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forced convection of ground fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Role and distribution of formation permeability . . . . . . . . . . . . . . . . . . . . . . . . . . . Presentation of pressure as the additive sum of two components . . . . . . . . . . . . . . . . . . . . . S o m e major factors of underground fluid forced convection and characteristics for correlation Compaction of granular sediments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . U p w a r d fluid migration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Correlation between porosity and pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Methods used in Azerbaijan to determine abnormal pressures . . . . . . . . . . . . . . . . . . . . Distributions of abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . Definitions of terms as used in this chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chapter 4
Introduction
. . . .
69 69 70 70 71 72 74 75 78 78 80 81 85 85 93 93 94
SMECTITE-ILLITE TRANSFORMATIONS DURING DIAGENESIS AND C A T A G E N E S I S AS R E L A T E D TO O V E R P R E S S U R E S L.A. Buryakovsky, R.D. Djevanshir, G.V. Chilingar, H.H. Rieke III and J.O. Robertson, Jr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
97 97
Burst's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of abnormally high formation pressure . . . . . . . . . . . . . . . . . Clay-mineral transformation . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of thermobaric conditions . . . . . . . . . . . . . . . . . . . . . . . . Effect of hydrochemical factors . . . . . . . . . . . . . . . . . . . . . . . . Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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99
100 105
110 113
116 120 121 121
CONTENTS
Xlll
Chapter 5
M E T H O D S OF ESTIMATING AND P R E D I C T I N G A B N O R M A L F O R M A T I O N PRESSURES G.V. Chilingar, V.A. Serebryakov, S.A. Katz and J.O. Robertson Jr. . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prediction of a b n o r m a l l y high pressure in regions with n o n e q u i l i b r i u m c o m p a c t i o n . . . . . . . . . . A b n o r m a l pressure due to temperature variations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimation and prediction of a b n o r m a l l y low pressures in basins in permafrost regions . . . . . . . . Formation pressure in regions with u p t h r o w n and d o w n t h r o w n blocks (uplift and subsidence of sedimentary rocks) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Calculation of a b n o r m a l pore pressure during drilling . . . . . . . . . . . . . . . . . . . . . . . . . . Method of equivalent depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Method of n o r m a l c o m p a c t i o n trend . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Method of c o m p r e s s i o n a l curves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Radioactivity study of zones with a b n o r m a l l y high formation pressure . . . . . . . . . . . . . . . . . Pulsed neutron capture logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantitative pressure evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technique A: empirical calibration charts . . . . . . . . . . . . . . . . . . . . . . . . . . . . M e t h o d B: equivalent depth m e t h o d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale water influx - - driving m e c h a n i s m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Various geophysical well logging methods - - a s u m m a r y . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
123 123 126 130 130 131 134 135 136 137 140 141 145 145 146 146 147 148
148
Chapter 6
DRILLING PARAMETERS W.H. Fertl, G.V. Chilingar and J.O. Robertson Jr. . . . . . . . . . . . . . . . . . . . . Drilling rate (penetration) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . N o r m a l i z e d rate of penetration (d-exponent) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of drilling hydraulics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of drill bits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overbalance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling rate equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Porosity and f o r m a t i o n pressure logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . L o g g i n g while drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Torque . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drag . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling m u d p a r a m e t e r s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M u d - g a s cutting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flowline specific w e i g h t of drilling fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure kicks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flowline t e m p e r a t u r e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Resistivity, chloride ion content, and other methods . . . . . . . . . . . . . . . . . . . . . . . . . Pit level and total pit v o l u m e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hole fill-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M u d flow rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale cuttings parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale bulk specific w e i g h t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Volume of shale cuttings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shape and size of shale cuttings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other pressure indicator methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling concepts in overpressured environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
151 151 151 153 155 156 156 157 159 159 160 160 160 160 161
161 162 163 163 163 163 163 164 164 164 165 165 165
XIV
CONTENTS
Chapter 7
S E I S M I C M E T H O D S OF P R E S S U R E P R E D I C T I O N F. A m i n z a d e h , G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prediction of abnormal pressure f r o m geophysical data . . . . . . . . . . . . . . . . . . . . . . . . . . Empirical relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eaton's exponent of pore pressure determination from sonic data . . . . . . . . . . . . . . . . . . E a t o n ' s exponent for pore pressure determination f r o m resistivity logs . . . . . . . . . . . . . . . Eaton's fracture pressure gradient equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dutta's m e t h o d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fillippone f o r m u l a . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Modified Fillippone f o r m u l a . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Practical applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Caspian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AVO effects of overpressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Real time pressure analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lithology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E m p i r i c a l relationships based on laboratory m e a s u r e m e n t s . . . . . . . . . . . . . . . . . . . . . Velocity and acoustic i m p e d a n c e inversion of seismic data . . . . . . . . . . . . . . . . . . . . . Pore pressure and seismic amplitude versus offset (AVO) . . . . . . . . . . . . . . . . . . . . . . Pore pressure estimation from seismic velocities . . . . . . . . . . . . . . . . . . . . . . . . . . . D e e p - w a t e r prospects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M a p p i n g reservoir fluid m o v e m e n t and d y n a m i c changes of reservoir pressure using time lapse (4-D seismic) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimation of sonic velocity from resistivity logs . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
169 169 169 170 170 171 171 172 172 172 173 173 175 175 176 177 178 179 179 183 186 187 188
Chapter 8
TECTONICS AND OVERPRESSURED FORMATIONS G.V. Chilingar, W. Fertl, H. Rieke and J.O. Robertson Jr . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Faulting as a cause of overpressured formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale diapirism (mud lumps, m u d volcanoes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prediction of tectonically caused overpressures by using resistivity and density measurements of associated shales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin and distribution of overpressures in carbonate reservoirs . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
191 191
191 198 200 200 205 206
Chapter 9
P R E D I C T I O N O F A B N O R M A L L Y H I G H P R E S S U R E S IN P E T R O L I F E R O U S SALT-BEARING SECTIONS V.I. Zilberman, V.A. Serebryakov, M.V. Gorfunkel, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Indicators of approaching the overpressured zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . Locating the areal positions of A H F P zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantitative A H F P forecast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
209 209 211 213 217 220 220
Chapter 10
P O R E WATER C O M P A C T I O N C H E M I S T R Y AS R E L A T E D T O O V E R P R E S S U R E S H.H. Rieke, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . O v e r v i e w and constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . T h e r m o d y n a m i c and reaction models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Evolution of seawater into pore water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
223 223 224 225 227
(SUIN 1 L N I ~ i
X V
Reliability of water sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . P a l m e r and Sulin water classifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . P a l m e r ' s classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sulin's classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C h e m i c a l composition of subsurface brines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Salinity variations in c o m p a c t i n g sandstones and associated shales . . . . . . . . . . . . . . . . . Field case studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . H a c k b e r r y and M a n c h e s t e r fields, Louisiana, U . S . A . . . . . . . . . . . . . . . . . . . . . . . Global reconnaissance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bengal and Kutch basins, India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Songliao Basin, China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Caspian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Laboratory experiments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Early laboratory experiments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of rate of loading (experiments) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Smectite to illite transformation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E x p e r i m e n t s involving mixtures of oil and seawater . . . . . . . . . . . . . . . . . . . . . . . . . Fluid chemistry c o m p a c t i o n models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . N o n - t h e r m o d y n a m i c approaches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Warner's double-layer model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kotova and Pavlov's empirical m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pol'ster's capillary m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . T h e r m o d y n a m i c approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bolt's pressure filtrate m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A p p e l o ' s D o n n a n equilibrium model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S m i t h ' s Gibbs e q u i l i b r i u m m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Isotope studies of interstitial fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geological observations and evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Isotope studies of shales in the G u l f Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . S u m m a r y and conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
229 233 233 234 235 236 238 240 243 245 248 250 251 251 261 264 270 272 273 273 275 276 277 277 279 281 282 282 283 285 288
Chapter 11
ABNORMALLY LOW FORMATION PRESSURES V.A. Serebryakov, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimation of the effects of temperature change and erosion on pore pressure . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chapter 12
. . . . . . . . . . . . . . . .
295 295 296 300 308 308
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES M.R. Islam, L. Khilyuk, G.V. Chilingar, S. Katz, J.O. Robertson Jr., A. Gurevich, E A m i n z a d e h and L. B u r y a k o v s k y . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 M e t h o d o l o g y of simulation of d y n a m i c systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312 Analytical approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312 Analytical models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 314 Simulation of pore-fluid (formation) pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316 N u m e r i c a l models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 Tectonic and lithological m o d e l i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 322 N u m e r i c a l criterion and sensitivity analysis for t i m e - d e p e n d e n t formation pressure in a sealed layer . 327 M o d e l i n g of m e a n value for t i m e - d e p e n d e n t formation pressure . . . . . . . . . . . . . . . . . . 329 F o r m a t i o n pressure in the case of constant fluid flow t h r o u g h the lower b o u n d a r y of the f o r m a t i o n . . 331 Criterion for the type of t i m e - d e p e n d e n t variation of formation pressure . . . . . . . . . . . . . . 333
xvi
CONTENTS
B o x - t y p e fluid flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sensitivity analysis for the m e a n value of the formation pressure in the sealed p e r m e a b l e layer Criterion B / A and relaxation coefficient for the Western K u b a n region in the southern part of Russia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E x a m p l e s of formation pressure d e v e l o p m e n t . . . . . . . . . . . . . . . . . . . . . . . . . . . . Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Identification of conductivity function for p e t r o l e u m reservoirs . . . . . . . . . . . . . . . . . . . . . Basic m a t h e m a t i c a l m o d e l of the pressure distribution in petroleum reservoirs . . . . . . . . . . Indirect evaluation of the conductivity function . . . . . . . . . . . . . . . . . . . . . . . . . . . Determination of the piezoconductivity coefficient layer by layer . . . . . . . . . . . . . . . . . . Model e x a m p l e of determining the conductivity function . . . . . . . . . . . . . . . . . . . . . . Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F r a m e w o r k of a c o m p r e h e n s i v e model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overpressurization due to rapid loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shear deformations aided by overpressures . . . . . . . . . . . . . . . . . . . . . . . . . . . Fluid generation at depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . N o m e n c l a t u r e used in this chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chapter 13
.
333 334 336 337 338 339 340 341 342 343 344 344 344 346 347 348 348 348 349
Introduction . C o m p a c t i o n of Conclusions . Bibliography .
INTERRELATIONSHIP AMONG FLUID PRODUCTION, SUBSIDENCE RESERVOIR PRESSURE V.A. Serebryakov, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
AND
. . . .
353 353 353 358 358
A u t h o r Index
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
361
Subject Index
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
369
. . . .
. . . .
Chapter 1
INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. and V. SEREBRYAKOV
INTRODUCTION There are wide variations in the subsurface formation fluid pressures due to a variety of hydraulic and tectonic phenomena. Variations of interstitial fluid pressure from the hydrostatic pressure of the subsurface fluids are labeled as abnormal formation pressure. The hydrostatic pressure is equal to the vertical height of a column of water extending from the surface to the formation of interest: Ph -- Vw X h
(1-1)
where Ph is the hydrostatic pressure in lb/ft 2, Vw is the specific weight of water in lb/ft 3, and h is the height of the column of water, in ft. The hydrostatic pressure gradient, Gh, in psi/ft, is equal to: Gh =
Vw 144
(1-2)
If the specific weight of water is 62.4 lb/ft 3, the Gh -- 0.433 psi/ft (0.10 kg cm -2 m - l ) . The specific weight of water is a function of the salinity of the water, temperature, and content of dissolved gases. Therefore, there is a general variation in the hydrostatic pressure gradient at different locations and the average estimated hydrostatic pressure gradient is usually taken as 0.465 psi/ft (0.074 kg cm -2 m - l ) ; this corresponds to water with a salinity of 80,000 parts per million (ppm) of sodium chloride at 77~ (25~ (Dickinson, 1953). In the presence of a normal hydrostatic pressure gradient, there is fluid communication (vertical) between the formations. The coexistence of normal and abnormal formation pressures in the same geologic environment can occur if one or more of the formations are impermeable to the vertical hydraulic communication. The average total overburden (lithostatic) pressure gradient resulting from the combined pressure of the rocks (grain-to-grain or rock matrix stress) and their interstitial fluids are taken as 1.0 psi/ft (0.231 kg cm -2 m-l): Pob -- Pe + Pp
(1-3)
where Pob is the total overburden (lithostatic) pressure which increases with depth, Pe is the stress exerted through the grain-to-grain contacts, and pp is the pressure of the fluids present in the pore spaces of the rocks. The hydrostatic, fluid pressure gradient cannot exceed the pressure gradient of the total overburden load. Thus, any reservoir with a hydrostatic gradient between 0.465 and 1.0 psi/ft is considered to have an abnormally high pressure. Actually, as pointed out by Swarbrick and Osborne (1998), when the
2
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
porosity of sediments is high (60-70%), the lithostatic pressure gradient is 0.7 psi/ft. Only at a depth of about 1.0 km, this variable is about 1.0 psi/ft. There are many factors that cause abnormal formation pressures, which may be either less than, or greater than, the pressure resulting from the normal hydrostatic pressure gradient of the region.
ABNORMAL PRESSURES
Subpressures In the accumulated experience of the petroleum industry in exploration wells, abnormally low formation pressures (subpressures or ALFPs) have been encountered far less than the surpressures (abnormally high formation pressures). In the United States, ALFPs have been found in Arkansas, some areas of the Appalachian Mountains, the eastern Colorado plateau and the Oklahoma-Texas panhandle areas. Other locations of subnormal formation pressures are in central Alberta in Canada, in the Siberian oilfields of Russia, and the arid regions of the Middle East. Many subnormal formation pressures have been artificially induced by production of hydrocarbons and water from subsurface reservoirs, which reduces the formation pore pressure of isolated reservoirs where a sufficient influx of water does not exist to compensate for the fluids that are withdrawn. In many cases, this reduction of formation pressure leads to surface subsidence, which in some cases has resulted in the destructive damage to surface structures. Examples of subsidence due to fluid withdrawal have taken place in: the Po Delta of Italy; the Bolivar Coast of Lake Maracaibo, Venezuela; Galveston Bay, Texas; Long Beach, California; Japan; Taiwan; and other areas (Chilingarian et al., 1995). The Granite Wash oil-producing formation near Amarillo, Texas, exhibited a formation pressure of almost one half of the expected normal hydrostatic pressure. Levorsen (1967) stated that a possible reason may be the fact that the Granite Wash Formation outcrops in Oklahoma east of the Wichita Mountains at an elevation which is about 1000 ft (305 m) lower than the surface elevation at the producing field in Texas. Subnormal pressures in the semi-arid areas of the Middle East occur because the water table is exceedingly deep (several thousand feet in some cases) and the hydrostatic gradient begins at the water table depth.
Surpressures Formations containing fluids with abnormally high formation pressures (AHFPs) have been encountered in all of the continents of the world where exploratory drilling for hydrocarbons has been conducted. Hunt has noted that AHFPs are present in around 180 basins around the globe. According to Law and Spencer (1998), in the US Gulf Coast region, for example, there are at least seven stratigraphic units, ranging in age from Jurassic to Recent, that are abnormally pressured. These fluid reservoirs are isolated environments or at least the fluid flow out of the reservoirs is restricted, and the total overburden load is partially supported by the
3
INTRODUCTION TO ABNORMALLYPRESSURED FORMATIONS
pore fluids. These AHFPs can only exist if the formation is separated by impermeable barriers that contain the pressure in the reservoir. The origins of these barriers may be physical, chemical, or a combination of both (Louden, 1972). There are a multitude of origins for AHFPs among which are (1) compaction, (2) tectonic compression, (3) faulting, (4) diapirism, (5) unusually high geothermal temperature gradients, (6) phase changes of minerals, (7) hydrocarbon (oil and gas) generation, (8) upward migration of hydrocarbon gases along faults, and (9) osmosis. Formation of a fluid seal (caprock) in the subsurface and development of the zone of abnormally high pore pressure is a highly complex mechanism. All of the mechanisms listed above, in any combination, with the passage of geologic time work together to cause the changes in the physicochemical environment (Fertl, 1976).
ORIGIN OF VERTICAL BARRIERS RESULTING IN ABNORMAL FORMATION PRESSURES
Fig. l-1 shows the approximate average subsurface pressure gradient. The rate of sedimentation and compaction and the density of the rock determine the overburden pressure gradient. As indicated in Fig. 1-1, the hydrostatic pressure gradient is 10.5 kPa/m (0.454 psi/ft), and at the other extreme, the lithostatic gradient is about 22.6 kPa/m (1.0
Hydrostatic gradient 10.5 kPa/m ( 0 . 4 5 4 p s i / f t )
\ A
6
!
o m
x
FLU UJ 9
~9
Lithostatic gradient 22.6 kPa/m (I.0 p s i / f t )
a
3
~,~
v
Geopressured zone "~~0.3 kPa/m (0.9 psi/ft}
\
IJ.
-r"
I-Q. LU "12
-. %
, 16
20
- 0 I 0
I 2
I 4
\
\ "\ \
9
\
%
40 60 80 PRESSURE (mPo) I I I i 6 8 I0 12
I00 I 14
120 I 16
I 18
PRESSURE (PSI x 10 - 3 ) Fig. 1-l. Approximate average subsurface pressure gradient in a geopressured zone.
4
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
psi/ft). In the geopressured reservoirs of the Gulf Coast region of the United States, at a depths greater than 3000 m, the pressure gradient increases to about 20.3 kPa/m (0.9 psi/ft). Hence, fluids in the geopressured zones can exhibit pressures greater than 68 MPa (about 10,000 psi). The formation with normal pressure gradient and the geopressured zone above can coexist only if they are separated by barriers that are impermeable to the vertical movement of fluids over millions of years of geologic time. The pressure seals (caprocks) above the geopressured zones are impermeable to the flow of fluids.
Undercompaction Undercompaction of the sediments can occur during rapid sedimentation and burial of sediments containing a large quantity of clay minerals (Rubey and Hubbert, 1959; Wilson et al., 1977). The complete expulsion of water does not occur, leaving the sediments as a loosely bound system of swollen clay particles with interlayer water. Where rapid deposition involves large quantities of clays, the sand bodies can be surrounded by clays, and if the loading rate of sediments is high, the permeability will decrease rapidly. Consequently, the pore fluids are prevented from escaping vertically through the overlying argillaceous sediments. Support of the overburden load is then transferred to the interstitial fluids and the formation becomes abnormally pressured because the fluids are subjected to the load of the newly deposited sediments. Thus fluids support a greater portion of the total overburden load (see Eq. 1-3). If the rate of migration of water from the formation undergoing sedimentation is equal to the rate of sedimentation, the excess fluid pressure created by the increasing loading will be dissipated and hydrostatic pressure will be maintained at all depths as the compaction of sediments takes place (Johnson and Bredeson, 1971).
Tectonic compression Lateral compression can occur in orogenic belts resulting in development of abnormally high pore pressures. Cretaceous mudstones of northern Wyoming (USA) have been deformed by lateral compression, which has decreased the formation porosity with consequent fluid expulsion through permeable beds or increase of formation pressure within the sealed zones (Rubey and Hubbert, 1959). Fluid pressure almost equal to the overburden pressure was encountered during the initial drilling of the Ventura Field (California). The presence of these faulted and folded zones suggests that lateral tectonic stresses are responsible for some of the surpressures that were encountered (Watts, 1948). Anderson (1927) reported that abnormally high formation pressures were encountered on the Potwar Plateau of West Pakistan just south of a folding zone in the foothills of the Himalaya Mountains; high fluid pressures were also associated with folding in the Khaur Field of West Pakistan (Keep and Ward, 1934). As a result of the compressive forces, water from shales can be squeezed into the associated reservoir rocks (sandstones or carbonates), giving rise to overpressures (see Chapter 8). A cubic element in the subsurface has nine stress components acting on it: three principal, normal stresses, cri, acting on the planes normal to the major axes and six
INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS
Z
~z
l I
*
~Y
~z
/
a~z
Fig. 1-2. Stress notation in a cubic argillaceous rock slice. Stress notation of the normal component of stress, a2, on the plane normal to the z-axis, rzx and rzy refer to the shear stress components in the plane normal to the z-axis and acting in the x- and y-directions, respectively, crz + ( O a z ) / ( O z ) d z is the incremental change in vertical stress through the free body. (Modified after Rieke and Chilingarian, 1974, fig. 52, p. 93.)
tangential (shear) stresses, ri, that act on each face of the cube normal to the major axes (Eq. 1-4, and Fig. 1-2). The tensor (S) of the nine stresses may be represented by the following equation:
I 0"x "Cxy "Cxz S ~ Tyx Oy "gyz
(1-4)
L'Czx 72zy O"z If compression is produced by tectonic horizontal compressive stresses, such as folding, the greatest principal stress is horizontal ( ~ ) , and the least principal stress is vertical (~z), which is equal to the overburden load per unit area (Pob). The greatest and least effective stresses m a y be expressed as follows: P e x - - Ox - - p p
(1-5)
Pez -- ~
(1-6)
-- Pp
6
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
where pp is the pore fluid pressure. If the overburden pressure (~rz) is fixed, and the effective horizontal stress, Pex, increases more rapidly than the pore pressure is dissipated from the formation by leakage, the pore pressure will increase until it reaches a maximum value equal to the overburden pressure (pp = O-z). Then, Pez will be equal to zero, and crx will increase toward the failure stress of the rock. At this condition, the superincumbent material can be moved tangentially with negligible resistance. Approach to this condition depends on the relative rates of the opposing processes: (1) the rate of the lateral deformation stress (crx) and (2) the rate of pressure dissipation by fluid leakage. According to Hubbert and Rubey (1959), the application of orogenic stresses is more effective in promoting the conditions of surpressures than sedimentary loading in tectonically quiescent geosynclines. Thus, if the rate of increase of applied orogenic stresses is more rapid than the pore fluid pressure dissipation (through leakage of the fluid), only the presence of stronger rocks can prevent pp from becoming equal to ~rz.
Faulting Some high-pressure zones in the Louisiana and Texas Gulf Coast region of the United States apparently originate from the pattern of block faulting accompanied by contemporaneous sedimentation and compaction. The process creates lateral seals that, together with a layer of thick shale overlying the surpressure zones, prevent the loss of pore fluids from the sediments during compaction and other diagenetic processes. Resistance to the flow of water through the clay is a function of decreasing porosity and permeability of the clay as compaction progresses. The hydraulic permeability of clay is negligible in the geopressured environments. The clay beds have overlain abnormally pressured formations for millions of years without the release of the pressure by fluid flow across the clay/shale beds. Apparently when the beds of clay are compacted, a stage is reached when the porosity and permeability are so low that the vertical flow of fluids is completely restricted. According to Dickey et al. (1968) the 'growth faults' of the Gulf Coast exhibit the characteristics of slump-type landslides and in many cases may indeed be due to old slides that were later buried by sedimentation. The units are thicker on the downthrown side of the growth faults than they are on the upthrown side, probably because during sedimentation there was continuous movement along the fault planes. During compaction of the sediments while sedimentation was taking place, fluids in the pores of the sediments normally travel vertically upward. As compaction progressed, the vertical permeability of argillaceous sediments decreased rapidly and as burial continued the pore pressure increased due to the mass of the overburden sediments and temperature increase. The abnormally high formation pressures are commonly found at depths beginning at about 10,000 ft (3000 m). Continued sedimentation can cause a shear zone to develop by overloading the undercompacted shale. Expulsion of the water is accompanied by subsidence of blocks of sediments. Thus, the contemporaneous faults of the Gulf Coast Basin (USA) are characterized by the cycle of deposition, expulsion of water, subsidence of blocks of sediments, and temperature increase.
INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS
7
Abnormally high formation pressures are also encountered in the Niger Delta in Nigeria, Africa. This delta is characterized by growth faults caused by gravity creating zones of high pressure overlain by thick shale beds. There is no doubt that several other mechanisms were active as supplementary pressure generators during the origin of the high pressures found in zones where growth faults predominate, and also in the maintenance of the high pressures after their generation. Although several mechanisms may have made their contributions, gravitational loading and tectonic compression probably exerted the greatest influence on pore pressures and hydrocarbon/water migration. Therefore, knowledge of the vertical and lateral orogenic stresses in the depositional basins is of major importance for interpreting the abnormal fluid pressure environments and anticipating the location of oil and gas reservoirs associated with the abnormally high pressures. The analysis of fluid-rock stress conditions has many other applications: earthquake prediction, hydraulic fracturing, compaction of rocks during their geological history, and the deformation of rocks in subsiding formations. The same theoretical basis applies for the solution of deformational problems by earthquakes and hydraulic effects that dissipate tectonic stresses through small earthquakes; and deformations caused by oil, gas, and water production. There is the curious generation of earthquakes up to magnitude 5 created near Denver, Colorado, USA, by the injection of waste fluids into the fractured gneiss using a 3700-m deep well. The increase of subsurface pressure disturbed the fluid-rock stress equilibrium and promoted sudden slippage along fracture planes (faults), some with very deep epicenters up to 5500 m deep (Evans, 1966).
Diapirism The Jurassic age Louann Salt underlying deep sediments of Louisiana and Texas in the United States was thinned by diapiric flow during the period of rapid sedimentation that began with the uplift of the Rocky Mountains at the beginning of the Cenozoic era. Salt was squeezed gulf-ward by sand and clay deposits forming domes and ridges, with some diapirs rising through the entire thickness of the overlying deposits. As the depth of burial continued, the increases in temperature induced dehydration of the clays within the buried zone and contributed to the shearing stresses. The salt became ductile and flowed like a viscous plastic under pressure and at elevated temperatures, such as those encountered in deep subsurface formations: 93~ (approximately 200~ at 3700 m (12,000 ft). The low density and strength of salt readily allowed development of domes when the density of overlying sediments exceeded the salt density. Salt was pushed upward penetrating the overlying sedimentary structures and acquiring a sheath of pliable clays, or shales, around parts of the salt diapir. The term sheath refers to the predominantly shale material which is out of place between the salt stock and the younger sedimentary rocks. The sheaths originate from folding of the clay bed and deposits of younger sediments against the dome, or from faulting of the clay bed which is then pressed into its position between the salt dome and the flanking sediments (Fig. 1-3). Structural features generally associated with salt domes, such as the configuration of the sheath, indications of uplift, subsidence at the surface, and development of rim synclines, are a consequence of the physical properties of
8
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
Basinward
D, ~ :
~ ~ . . . . . ,
...............
.:...,...,~:
. .,.:..
......
Sand
~,.... . . . . . . . . . . . .
.......
..............
Salt
~~~ABNORMAL~
Fig. 1-3. Schematic section through a piercement salt dome showing modification of abnormal pressure surface. (Modified after Harkins and Baugher, 1969, p. 964. Courtesy of the Society of Petroleum Engineers.)
salt and the overlying sediments (Johnson and Bredeson, 1971). In Fig. 1-3, the steep boundary demarcation of the abnormally pressured lower zone reflects earlier (before development of the salt dome) topography associated with the uplift of the region. Harkins and Baugher (1969) illustrated the abnormal pressures associated with the sheath in Fig. 1-3. A well drilled into Formation C would encounter high pressures in the Formation D rocks. The sheath deposits are out of place, having been dragged into their present position by the dome. Growth of salt domes in the Gulf Coast region of the United States was contemporaneous with the sedimentation (see Fig. 1-4). Deep shale beds also undergo plastic flow when subjected to high overburden pressures, forming diapiric masses with the same characteristics as those of salt beds (low bulk density, high pressure gradients, and low electrical resistivity) (Gilreath, 1968). This condition probably occurs when low-density, low-permeability formations are rapidly loaded by sediments; this occurs in major river deltas such as the Niger, Nile, Mississippi, Amazon, etc. where shales are rapidly loaded by sands (Murray, 1961). Geothermal temperature Another contributor to the fluid pressure is the temperature increase that occurs within the geopressured zone. The overlying, normally pressured, sediments that are compacted possess a lower thermal conductivity and act as a 'blanket', decreasing the transfer of heat from the deep mantle. A leak-proof permeability seal is required in order to have a closed system, and the heat trapped by the blanket effect above the geopressured zone produces an abnormally high temperature in the formation. This contributes another incremental pressure increase to the fluid (Kreitler and Gustavson, 1976). The approximate subsurface temperature gradients are illustrated in Fig. 1-5. The temperature gradient increases from the normal gradient of 18.2~ (1.0~ ft) to about 30~ (1.7~ ft) in the geopressured zone at a depth of about 3000 m.
9
INTRODUCTION TO ABNORMALLYPRESSURED FORMATIONS
Hence, water in the geopressured zone can be expected to have a temperature of 152~ (305~ Several factors affect the heat flux in subsurface formations: (1) the prevailing temperature of the zone; (2) the specific heats of the matrix and fluids; (3) the porosity and permeability of the sedimentary layers; (4) the density and thermal expansion of the rock and fluids; and (5) the chemical composition of the rocks and fluids (Donaldson, 1980). The geopressured zones along the Gulf Coast region (USA) generally occur at depths below 2500 m and require special drilling technology whenever these zones are to be penetrated. These zones usually contain a considerable amount of methane that is frequently separated and recovered when the geopressured formations are penetrated (Harkins and Baugher, 1969). Dickinson (1951) made a thorough study of the geologic aspects of the high fluid pressures in the Tertiary Basin of the U.S. Gulf Coast region. The high-pressured zones occur most frequently in isolated Miocene and Pliocene sand beds surrounded by thick shale sections located below the main deltaic sand series. The high fluid pressures appear to be independent of the depth or geologic age of the formations. Where sedimentation has been rapid, the thick accumulation of shales and mudstones having low permeability (< 10 -7 D) have retarded the expulsion of water and hydrocarbons. The trapped pore fluids bear a portion of the overburden load that would normally be supported by the grain-to-grain contacts. In the geopressured/geothermal zones (at depths greater than 3000 m) with pressure and temperature of about 70 MPa (10,000 psi) and 152~ respectively, the solubility of methane in water is about 0.058 mole fraction (40 ft3/bbl). The actual gas production from several zones, however, exhibits an approximate saturation of 0.029 mole fraction
Plain
Shelf Top of geopressured zone
Sand and shale sequence---
Louann salt Sandstone Granite Fig. 1-4. Top of geopressured zone in the Gulf Coast of the U.S. in relation to salt domes (Louann Salt).
10
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
(20 ft3/bbl) (Kharaka et al., 1977). Organic matter which is a substantial part of freshly deposited muds decomposes during diagenesis as a result of biochemical and thermochemical processes. The resulting methane gas which is released during the transformations can create, or accentuate, the overpressured, undercompacted, state of the compacting mud sediments in two ways: (a) by building up additional pore pressure; and (b) by further impeding the expulsion of interstitial pore water through the development of a second gas-fluid phase. Gas bubbles dispersed in water reduce the permeability of the rock to either phase (Chilingarian et al., 1995). The mechanism of temperature increase (aquathermal expansion) as a possible cause of overpressures has been questioned by several authors (e.g., see Swarbrick and Osborne, 1998). The main objection is the absence of practically impermeable seals. Phase changes that produce abnormal pressures Berner (1980) described two phases in early diagenesis. The first one consisted of two stages: (1) the initial stage which is regulated by the chemistry of water; and (2) the early burial stage which is controlled by the entrapped pore water that is chemically modified by bacteria and bioturbation of surface organisms. During the initial stage, the clay minerals undergo a gradual change of their ionic exchange capacity, and
Normal thermal gradient 1 8 . 2 ~ (I.O~ ft.) 6
.-. if3 i c)
x IuJ bJ
9
Geothermal
,,=, a
-rl-o. w ol2
zone
/~30.OOC/km (I.7~
ft.)
\ 16
-
50
I
0
,
I
I00
I00 TEMPERATURE
~
I
200
TEMPERATURE
\
\
\
\
150 ~
I
I
300
2_00
I
~
Fig. 1-5. Approximate average subsurface temperature gradients.
INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS
11
bioturbation creates a well-oxidized depositional environment. The early burial state is recognized as a reducing zone where anaerobic bacteria are dominant. Rieke (1972) presented a discussion of the transformation of clay minerals from field observation and laboratory experiments. During sedimentation, montmorillonite clay adsorbs water into its three-dimensional lattice structure that is later released into the pores of the surrounding porous media during compaction and burial. The transformation of montmorillonite clay to illite occurs between 80 ~ and 120~ releasing an amount of water equal to one half of its volume (Powers, 1967). This infusion of water leads to further undercompaction in the geopressured zone. When the fluid pressure exceeds the lithostatic pressure, the faults act as valves for discharge of fluids upward into the hydro-pressured aquifers overlying the zone. As the formation pressure declines, the valves close until the pressure once more exceeds the lithostatic pressure (Jones, 1975; Bebout, 1976). Various investigators have shown that during compaction accompanied by deep burial, a diagenetic conversion of montmorillonite to illite, and also kaolinite to chlorite, occurs with increasing depth as the subsurface temperature increases. Progressive modification of the structure of montmorillonite with its eventual disappearance was observed with increasing burial depth in the Wilcox Formation of the Gulf Coast (USA). Burst (1969) proposed that the disappearance of montmorillonite in the sediments was caused by conversion to illite as Mg 2+ cation was substituted in the silicate lattice structure for A13+ ion, accompanied by fixation of the interlayer potassium. Powers (1959) and Weaver (1961) have also reported on the lack of non-interlayered montmorillonite in deeply buried sediments. The gradual change of montmorillonite clay to illite and kaolinite to chlorite has been investigated by many authors: Fuchtbauer and Goldschmidt (1963), Dunoyer de Segonzac (1964), Perry and Hower (1970), Van Moort (1971) and others. The fact remains, however, that smectite-to-illite transformation during diagenesis and catagenesis does not occur in many overpressured environments (see Chapter 4). Osmosis as a factor for generation of abnormal pressure Osmotic pressure occurs when two solutions having different ionic concentrations are separated by a semipermeable membrane that will allow the solvent to pass through by diffusion from the more dilute side to the more concentrated side of the membrane. The osmotic flow will continue until the chemical potential of diffusion is equal on both sides of the membrane; thus, the pressure increase occurs if the solvent moving into the more concentrated solution enters a closed compartment (Fig. 1-6). McKelvey and Milne (1962) measured the osmotic pressure of 1 N sodium chloride solution versus distilled water across plugs (0.26-0.51 cm in thickness) of bentonite. The pressure was 695 psi (4.8 KPa): 95% of the theoretical value. Probably the natural clay/shale beds will act only as imperfect semipermeable membranes because of the presence of fractures and large pores, which may be too large or too weakly charged to restrict the movement of salt. Thus, the generated osmotic pressure will be less than the theoretical one on the basis of salinity differences across them.
1~
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
Zone of decreasing pore pressure
Zone of increasing pore pressure
H20 - - - - - - - ~ I i i~iiliii!iiiiiEi ili iiiii.iiiiiiiiiiii~lH20 i.._
H20 ~
H20
0 ..-.
e"
9
'*-
N),.,,-
"" 0
-4,.,,.
N~O ~
H~O
~
H20 ~
H20
~
H~O ~
H~O
~
H20
H20
O
(I)
rO
N
.0 o NI,,,,-
O
H20 "'~iiHiiiiiiiiiiii!iiiiiiiiiiiii~iiii
iii iiii iiil H20
(]) tO
N
'' i,,
Fig. 1-6. Schematic diagram of osmotic flow through semipermeable clay membrane (without fractures).
The pressure will be abnormally high in the water influx side of the membrane, and the water will contain a considerably lower concentration of electrolytes. Formations with a large lateral continuity and high permeability would probably dissipate the osmotically induced high pressure, whereas the formations which are surrounded by rocks having low transmissibility would exhibit higher pressure. Young and Low (1965) conducted experiments that illustrated the behavior and effectiveness of argillaceous sediments as semipermeable membranes (Hanshaw and Zen, 1965). Lomba et al. (2000) discussed a model for calculation of transient pressure profiles and solute diffusion through low-permeability shales applied to the calculation of pore pressures near a wellbore. They found that the osmotic potential contributes to the generation of a high hydraulic pressure gradient near the wellbore that controls the flow of water from the formation. Swarbrick and Osborne (1998), on the other hand, calculated that in the North Sea rocks, an osmotic pressure of only about 3 MPa (435 psi) can be generated even with salinity contrasts as high as 35 wt% NaC1 equivalent. They also stated that if shale contains microfactures, osmosis is impossible. Thus, this possible mechanism for creating overpressures should be thoroughly investigated.
Salinity of interstitial water Often on approaching formations with abnormally high pressure, there is a freshening of interstitial water (e.g., see Rieke and Chilingarian, 1974). Yet, the reasons for this
INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS
13
decrease in salinity of water are not clear. In analyzing this problem, one should consider the following established facts. (1) Water in shales is much fresher than that in associated sands and sandstones (Schmidt, 1973; Chilingar and Rieke, 1976). (2) Influx of fresher shale water into the associated sandstone reservoirs results in freshening of produced water as production of oil and water progresses (Rieke and Chilingarian, 1976; Chilingarian et al., 1994). (3) Salinity of water in well-compacted shales is lower than that in associated undercompacted shales, but still remains lower than those in associated sands and sandstones (Chilingar and Rieke, 1976). (4) In thick sand-shale sequences, with overpressured formations, the salinity of interstitial water in shales and sandstones often decreases with depth (Rieke and Chilingarian, 1976). (5) Water in the center of shale capillaries is more saline than water adjacent to the capillary walls (Rieke and Chilingarian, 1974). (6) There is good correlation between the salinity of interstitial water in shales and sonic data, which is used for prediction of abnormal formation pressure (Vorabutr et al., 1986). On considering the above-established facts, one may consider the following suggestions: (1) In thick shale sequences, as compaction water moves up, it becomes more saline. Thus, in undercompacted sediments, the salinity of formation waters may decrease with increasing depth. Also, the more-compacted shales below will contain fresher water than less-compacted shales above. (2) In interbedded sands and shales, the variation of salinity with depth is not clear (see Kucheruk and Shenderey, 1975) and considerable field and laboratory research work is required to elucidate the problem.
RESERVOIR E N G I N E E R I N G CONCEPTS IN A B N O R M A L P R E S S U R E E N V I R O N M E N T S
Much attention has been focused on the analysis of hydrocarbon reserves, reservoir behavior, and possible mechanisms important to the production from abnormally high-pressured reservoir rocks. Frequently, overpressured gas reservoirs do not behave as volumetric reservoirs which complicate gas-in-place estimates. For years it has been observed that the production curves in many gas reservoirs show a rapid decline in the early-life history after which they flatten out (Fig. 1-7). The reader is also referred to the classical book of Poston and Berg (1997) on overpressured gas reservoirs. The following characterize overpressured reservoirs: (1) water influx from the shales into adjacent pay sands (i.e., shale water influx) (Wallace, 1969); (2) rock compressibility and rock failure (Harville and Hawkins, 1969); (3) water influx into the reservoirs from limited aquifers.
14
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
True gas-in-place
estimate
.o a
=IN==
Erroneous
gas-in-place estimate i i g i
",,,,i
i
2
i i i
9
Cum. gas producti( )n
li~
Overestimate
Fig. 1-7. Typical p/z versus cumulative production behavior for an overpressured gas reservoir in sand-shale sequence. (Modified after Fertl and Chilingarian, 1977, fig. 4, p. 35.)
.E Q. (1) "4--
N \\
\i~.~
~
1
x'" 2 "~3
Time risk, cost Fig. 1-8. Generalized trends of key drilling factors in hydrostatic and overpressured environments: 1 = hydrostatic pressures" 2 = overpressures; and 3 = severe overpressures. (Modified after Fertl and Chilingarian, 1987, fig. 13, p. 37.)
E C O N O M I C S IN O V E R P R E S S U R E E N V I R O N M E N T S
Exploration in normal-pressure environments generally shows predictable trends for time, cost, and risk. Presence of abnormal pressures, especially superpressures, however, is a very critical factor. Time, cost and risks can increase drastically, greatly affecting the profit. This is clearly shown in Fig. 1-8. Based upon the shale resistivity ratio method (Fig. 1-9) and regardless of measured formation pressure gradients, the following conclusions were drawn by Timko and Fertl (1971) and Fertl and Chilingarian (1976) for the shale-sand sequences (but not massive carbonate sections).
INTRODUCTION
TO ABNORMALLY
PRESSURED
FORMATIONS
15
D O
~
._~ 2 o C
,I,,,9
r-
U'O
OVERPRESSURE
.
d-
~~.
/ ~
r',,,"
13 No. MW
,,p.z\
COMMERCIAL OIL/GAS FIELDS
\
t
NO
-
A
. 6\- -
",-,99~
SMALL RESERVOIRS
~r
=
MAJORITY GULF COAST FIELDS
.~ \
/
oo~e~o,~ ~
3.s NORMAL
B m ~ oS
\
i
-'~ \ Rsh
RESERVOIRS
TOP SUPER
\
F~
_ 3 O ~ m -(3 ,,,.. ~ > -4
PRESSURE
\
~
~
r-
, ,,,., ,,.
iiiiiiiii
Shoff normal resistivity, log Rsh Fig. 1-9. Statistical relationship of hydrocarbon distribution to shale resistivity profile based on short normal curve in Tertiary clastic sequence, U.S. Gulf Coast area. (Modified after Timko and Fertl, 1971. Courtesy of the Society of Petroleum Engineers. In Fertl and Chilingarian, 1987, fig. 11, p. 36.)
(1) Most commercial oil sands exhibit shale resistivity ratios (ratio of normal Rsh to observed Rsh) less than 1.6 in adjacent shales and can generally be reached without an expensive string of protection pipe. (2) Most commercial gas-sand reservoirs exhibit ratios of about 3.0 and less. These wells can have extremely high measured pressure gradients. (3) Wells with ratios of 3.0 to 3.5 can be commercially gas productive and generally will produce as one- or two-well reservoirs. (4) No commercial production is found when the shale resistivity ratio reaches and/or exceeds 3.5, no mater what the actual pressure gradient is. These wells are often highly productive initially and are characterized by extremely fast pressure depletion. Of course, this can also be due to plastic deformation (irreversible compaction) in undercompacted rocks with increasing effective stress soon after production commences. According to Belonin and Slavin (1998), most of the overpressured production in Russia occurs at an abnormality coefficient, Ka, of less than 1.8 (Ka is measured pore pressure, Ppa :hydrostatic pressure, Ph; 0.45 psi/ft (10.2 kPa/m) was assumed for the hydrostatic gradient). Leach (1993) stated that pressure gradients equal to or in excess
16
E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV
of 0.85 psi/ft (19.6 kPa/m) exceed the FPGs of most sandstone reservoirs. Thus, if hydrocarbons are present initially, they probably would have escaped through fractures. (For a detailed discussion see Law and Spencer, 1998.) The writers, however, would like to point out that well testing is a sword of two edges in overpressured formations. As soon as some fluids are produced, the effective pressure increases to a critical limit and closes down the pores (irreversible compaction). Thus many overpressured reservoirs have been condemned in the belief that the reservoir cannot produce fluids (see Belonin et al., 2002).
SUMMARY
Abnormal subsurface formation pressures are encountered throughout the world and are produced by many different causes that may be physical, chemical, or a combination of the two. Many reasons for the formation of subsurface abnormal fluid pressures have been postulated and discovered. There is some disagreement among engineers and geologists regarding some of the mechanisms that have been proposed for the origin of abnormal pressures; however, developments in drilling, seismic technology and well-logging are resolving many of the disputes. This book presents analyses of the theories for the creation and maintenance of abnormal fluid pressures in sedimentary rock environments and their prediction. Clark (1961) coined the term 'tectonic overpressure' during his discussion of tectonic compression. Dickey et al. (1968) developed theories based on faulting. Rieke and Chilingarian (1974), Magara (1975) and Plumley (1980) discussed compaction as a 'disequilibrium mechanism' causing abnormal fluid pressures. According to Gilreath (1968) and Johnson and Bredeson (1971), diapirism of salt and shale was responsible for the creation of some abnormal pressure environments. The influence of abnormal formation temperature on the maintenance of abnormally high fluid pressures (especially along the Gulf Coast of the United States) was discussed by several authors: Harkins and Baugher (1969), Kharaka et al. (1977), Donaldson (1980), and others. Phase changes of minerals during diagenesis and catagenesis was investigated by Powers (1967) and Hanshaw and Bredehoeft (1968). Osmotic pressures were investigated by McKelvey and Milne (1962), Hanshaw and Zen (1965), Swarbrick and Osborne (1998), and others. The two mechanisms of formation of overpressures which have been underestimated in the past are (1) hydrocarbon (both liquid and gas) generation (e.g., Hunt et al., 1998), and (2) upward gas migration along faults from lower to upper horizons, resulting in the overpressures in the upper horizons (Khilyuk et al., 2000). (See Chapter 2.) The chapters that follow are devoted to more detailed analyses of the origins of abnormal subsurface pressures, their prediction and distribution, the effects of diagenetic and catagenetic changes, and mathematical models.
INTRODUCTIONTO ABNORMALLYPRESSURED FORMATIONS
]7
BIBLIOGRAPHY Anderson, R.V.V., 1927. Tertiary stratigraphy and orogeny of the northern Punjab. Geol. Soc. Am. Bull., 38: 665-720. Bebout, D.G., 1976. Subsurface techniques for locating and evaluating geopressured-geothermal reservoirs along the Texas Gulf Coast. Proc. 2nd Geopressured/Geothermal Energy Conf., II, pp. 1-16. Belonin, M.D. and Slavin, W.I., 1998. Abnormally-high formation pressures in petroleum regions of Russia and other countries of the Commonwealth of Independent States (CIS). Am. Assoc. Pet. Geol. Mem., 70: 115-121. Belonin, M.D., Slavin, V.I., Smirnova, E.M., Chilingar, G.V. and Robertson, J.O. Jr., 2002. Exploration in oil and gas fields with abnormally-high formation pressures (AHFP). Energy Sources. (in press). Berner, R.A., 1980. Early Diagenesis: A Theoretical Approach. Princeton University Press, Princeton, NJ, 241 pp. Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. Am. Assoc. Pet. Geol., 53(1): 73-93. Chilingar, G.V. and Rieke, H.H. III, 1976. Chemistry of interstitial solutions in undercompacted (overpressured) versus well-compacted shales. Proc. Int. Clay Conf. 1975, Mexico City. Applied Publishers Ltd., Wilmette, IL, pp. 673-678. Chilingarian, G.V., Rieke, H.H. and Kazi, A., 1994. Chemistry of pore water. In: W.E. Fertl, R.E. Chapman and R.F. Holtz (Eds.), Studies in Abnormal Pressures. Developments in Petroleum Science 38, Elsevier, Amsterdam, pp. 107-153. Chilingarian, G.V., Donaldson, E.C. and Yen, T.E, 1995. Subsidence Due to Fluid Withdrawal. Developments in Petroleum Science 41, Elsevier, Amsterdam, 498 pp. Chilingar, G.V., Eremenko, N.A. and Ar'ye, A.G., 1997. Anomalously high pressures in natural geofluiddynamic systems. Geol. Oil Gas, 5: 19-27. Clark Jr., S.E, 1961. A redetermination of equilibrium relations between kyanite and sellimanite. Am. J. Sci., 259:641-650. Dickey, EA., Shiram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160:609-615. Dickinson, G., 1951. Geological aspects of abnormal reservoir pressures in Gulf Coast region of Louisiana, U.S.A. Proc. 3rd World Petrol. Congr., 1: 1-17. Dickinson, G., 1953. Reservoir pressures in Gulf Coast, Louisiana. Bull. Am. Assoc. Pet. Geol., 37: 410-432. Donaldson, E.C., 1980. Underground disposal of brines from geopressured reservoirs. Proc. 73rd Annu. Meet., Am. Inst. Chem. Eng., 30 pp. Dunoyer de Segonzac, G., 1964. Les argiles du Cr6tac6 Sup6rieur dans le bassin de Douala (Cameroun): Problbmes de diagenbse. Bull. Serv. Carte Geol. Alsace-Lorraine, 17(4): 287-310. Evans, D.M., 1966. The Denver area earthquakes and the Rocky Mountain Arsenal disposal well. Mt. Geol., 3(1): 23-36. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Fertl, W.H. and Chilingarian, G.V., 1976. Importance of abnormal formation pressure to the oil industry. SPE 5946, Soc. Pet. Eng. AIME, Amsterdam, April 7-9. Fertl, W.H. and Chilingarian, G.V., 1977. Importance of abnormal formation pressures to the oil industry. Paper SPE 5946 presented at the Spring Meeting of the European Societ of Petroleum Engineers of AIME, Amsterdam; also J. Pet. Technol., 29(4): 347-354. Fertl, W.H. and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1(1): 23-38. Fuchtbauer, H. and Goldschmidt, H., 1963. Beobachtungen zur Tonmineral Diagenese. Proc. 1st Int. Congr. Clays, Stockholm, pp. 99-111. Gilreath, J.A., 1968. Electric-log characteristics of diapiric shale. Am. Assoc. Pet. Geol. Mem., 8: 137-144. Glasstone, S., 1946. Textbook of Physical Chemistry. Van Nostrand, New York, 1320 pp. Hanshaw, B.B. and Bredehoeft, J.D., 1968. On the maintenance of anomalous fluid pressures, II. Source layer at depth. Geol. Soc. Am. Bull., 79:1107-1122. Hanshaw, B.B. and Zen, E., 1965. Osmotic equilibrium and overthrust faulting. Geol. Soc. Am. Bull., 76: 1379-1386.
18
E.C. DONALDSON,G.V. CHILINGAR,J.O. ROBERTSONJR. AND V. SEREBRYAKOV
Harkins, K.L. and Baugher III, J.W., 1969. Geological significance of abnormal formation pressures. J. Pet. Technol., 21 (8): 961-966. Harville, D.W. and Hawkins, M.E, 1969. Rock compressibility and failure as reservoir mechanism in geopressured gas reservoirs. J. Pet. Technol., 21: 1528-1530. Hubbert, M.K. and Rubey, W.W., 1959. Role of fluid pressure in mechanics of overthrust faulting. I. Mechanics of fluid-filled porous solids and its applications to overthrust faulting. Geol. Soc. Am. Bull., 70(2): 167-206. Hunt, J.M., 1990. Generation and migration of petroleum from abnormally pressured compartments. Am. Assoc. Pet. Geol. Bull., 74: 1-12. Hunt, J.M., Whelan, J.K., Eglinton, L.B. and Cathless III, L.M., 1994. Gas generation - - a major cause of deep Gulf Coast overpressures. Oil Gas J., Jul. 18, pp. 59-63. Hunt, J.M., Whelan, J.K., Eglinton, L.B. and Cathless III, L.M., 1998. Relation of shale porosities, gas generation, and compaction to deep overpressures in the U.S. Gulf Coast. Am. Assoc. Pet. Geol. Mem., 70: 84-104. Johnson, H.A. and Bredeson, D.H., 1971. Structural development of some shallow salt domes in Louisiana Miocene productive belt. Am. Assoc. Pet. Geol. Bull., 55(2): 204-226. Jones, EH., 1975. Geothermal and hydrocarbon regimes, Northern Gulf of Mexico Basin. Proc. 1st Geopressured/Geothermal Energy Conf., V (Part 3), pp. 15-39. Keep, C.E. and Ward, H.L., 1934. Drilling against high rock pressures with particular reference to operation conducted in the Khaur field, Punjab. J. Inst. Pet. Technol., 20: 990-1013. Kharaka, Y.K., Callender, E. and Carothers, W.W., 1977. Geochemistry of waters in the geopressured zone from coastal Louisiana: implications for the geothermal development. 3rd Geopressured/Geothermal Energy Conf., Univ. Southwestern Louisiana, Lafayette, LA, Nov. 16-18, 1: GI- 121-165. Khilyuk, L.E, Chilingar, G.V., Endres, B. and Robertson, J.O. Jr., 2000. Gas Migration - - Events Preceding Earthquakes. Gulf Publ. Co., Houston, TX, 389 pp. Kreitler, C.W. and Gustavson, T.C., 1976. Geothermal resources of the Texas Gulf Coast: environmental concerns arising from the production and disposal of geothermal waters. Proc. 2nd Geopressured/Geothermal Energy Conf., V (Part 3), 1- 14. Kucheruk, E.V. and Shenderey, L.P., 1975. Present-Day Understanding of Nature of Anomalously-High Formation Pressures. V. 6, VINITI, Moscow, 165 pp. Law, B.E. and Spencer, C.W., 1998. Abnormal pressures in hydrocarbon environments. Am. Assoc. Pet. Geol. Mem., 70:1-11. Leach, W.G., 1993. Fluid migration, hydrocarbon concentration in South Louisiana Tertiary sediments. Oil Gas J., Mar. 1, pp. 71-74. Levorsen, A.T., 1967. Geology of Petroleum. Freeman, San Francisco, CA, 724 pp. Lomba, R.ET., Chenevert, M.E. and Sharma, M.M., 2000. The role of osmotic effects in fluid flow through shales. J. Pet. Sci. Eng., 25(I-2): 25-35. Louden, L.R., 1972. Origin and maintenance of abnormal pressures. SPE 3843, 3rd Symp. Abnormal Subsurface Pore Pressure. Magara, K., 1974. Compaction, ion filtration, and osmosis in shale and their significance in primary migration. Bull. Am. Assoc. Pet. Geol., 58: 283-290. McKelvey, J.G. and Milne, I.H., 1962. Flow of salt solutions through compacted clay. Clays Clay Miner., 9: 248-259. Murray, G.E., 1961. Geology <~'the Atlantic and Gulf Coastal Province of North America. Harper Brothers, New York, 692 pp. Perry, E. and Hower, J., 1970. Burial diagenesis in Gulf Coast pelitic sediments. Clays Clay Miner., 18: 165-177. Plumley, W.J., 1980. Abnormally high fluid pressure survey of some basic principles. Am. Assoc. Petrol. Geol. Bull., 64:414-430. Poston, S.W. and Berg, R.R., 1997. Overpressured Gas Reservoirs. Society of Petroleum Engineers, Richardson, TX, 138 pp. Powers, M.C., 1959. Adjustments of clay to chemical change and the concept of the equivalent level. Clays Clay Miner., 2: 309-326.
INTRODUCTION TO ABNORMALLYPRESSURED FORMATIONS
19
Powers, M.C., 1967. Fluid release mechanisms in compacting marine mudrocks and their importance in oil exploration. Am. Assoc. Pet. Geol. Bull., 51: 1240-1254. Rieke III, H.H., 1972. Mineralogy of montmorillonite under elevated temperature and pressure. 3rd Symp. Abnormal Subsurface Pore Pressure. Soc. Pet. Eng. Meet., Baton Rouge, LA, pp. 89-109. Rieke III, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Elsevier, Amsterdam, 424 pp. Rieke, H.H. III and Chilingarian G.V., 1976. Compaction of argillaceous sediments. In: W.H. Fertl (Ed.), 1976, Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Rubey, W.W. and Hubbert, M.K., 1959. Role of fluid pressure in mechanics of overthrust faulting, II. Overthrust belt in geosynclinal area of western Wyoming in light of fluid- pressure hypothesis. Geol. Soc. Am. Bull., 70(2): 167-206. Schmidt, O.W., 1973. Interstitial water composition and geochemistry of deep Gulf Coast shales and sandstones. Bull. Am. Assoc. Pet. Geol., 57(2): 321-337. Swarbrick, R.E. and Osborne, M.J., 1998. Mechanisms that generate abnormal pressures: an overview. Am. Assoc. Pet. Geol. Mem., 70: 13-34. Timko, D.J. and Fertl, W.H., 1971. Relationship between hydrocarbon accumulation and geopressure and its economic significance. J. Pet. Technol., 223(8): 923-931. Van Moort, J.C., 1971. A comparative study of the diagenetic alteration of clay minerals in Mesozoic shales from Papua, New Guinea, and in Tertiary shales from Louisiana, USA. Clays Clay Miner., 19(1): 1-20. Vorabutr, P.A., Almubarak, N., Razavi, J., Mohseni, A.A., Chilingarian, G.V. and Yen, T.F., 1986. Prediction of abnormal formation pressures from salinity of solutions obtained on leaching shale cuttings. Energy Sources, 8(2/3): 289-290. Wallace, W.E., 1969. Water production from abnormally pressured gas reservoirs in South Louisiana. J. Pet. Technol., 21: 969-983. Watts, E.V., 1948. Some aspects of high pressures in the D-7 zone of the Ventura Avenue field. Am. Inst. Min. Metall. Eng., 174: 191-200. Weaver, C.E., 1961. Clay mineralogy of the late Cretaceous rocks of the Washakie Basin. Wyo. Geol. Assoc. Guidebook, 16th Field Conf., pp. 148-154. Wilson, J.S., Hamilton, J.R., Manning, J.A. and Muehlberg, EE., 1977. Environmental Assessment of Geopressured Waters and Their Projected Use. EPA-600/7-77-039, National Technical Information Service, Springfield, VA 22161, 85 pp. Young, A. and Low, EE, 1965. Osmosis in argillaceous rocks. Bull. Am. Assoc. Pet. Geol., 47(7): 10041008.
This Page Intentionally Left Blank
21
Chapter 2
ORIGIN OF A B N O R M A L FORMATION PRESSURES G.V. CHILINGAR, J.O. ROBERTSON JR. and H.H. RIEKE III
INTRODUCTION
Interstitial (intergranular or formation) fluid pressures, either above or below the hydrostatic pressure, occur around the world under a wide range of geological conditions. Any pressure that is either above or below the hydrostatic pressure is referred to as an abnormal formation pressure. Pressures above the hydrostatic pressure are often referred to as abnormally high (AHFP) or surpressures. Pressures below the hydrostatic pressure may be referred to as either abnormally low (ALFP) or subpressures. The object of early formation analysis of abnormally pressured zones was primarily to predict and identify these zones prior to drilling into them. This need for prior knowledge was motivated by the economic losses that were often experienced by suddenly drilling into an unrecognized abnormally pressured region. Attention must be paid to pore fluid and rock stresses in sedimentary sequences, because the knowledge of vertical and lateral stress patterns in a depositional basin is helpful in evaluating its history and development. A thorough quantitative understanding of compaction mechanics, the relationship between the total overburden stress, effective stress, and pore stress (pressure) in fine-grained clastics is required to recognize the potential development of abnormally high pressured formations. Possible origins of abnormally pressured formations are presented in Table 2-1 (surpressured) and Table 2-2 (subpressured). Throughout the world, literature is filled with examples of abnormally high pressured formations, recorded at depths of a few hundred feet to that greater than 20,000 ft. As shown in Table 2-1, the processes often responsible for the generation of abnormally high formation pressures (AHFP) can be grouped into three categories: (1) changes in the rock pore volume, (2) changes in the fluid volume within the pores, and (3) changes in the fluid head. All three of these mechanisms require changes that occur faster than the formation is able to drain-off the excess pressure.
Definitions The following terms (definitions) are used in this chapter (loads, stresses and pressures). Stress: the total pressure (force per unit area, a) acting at a point. Effective stress, ~c: that part of the load (force per unit area) that is not counteracted by other forces and is available to cause compaction. Hydrostatic gradient, Gh: the pressure exerted by a column of water per unit of depth. Hydrostatic pressure, Ph: the pressure exerted at the bottom of a water column or at a
22
G.V. CHILINGAR,J.O. ROBERTSONJR. AND H.H. RIEKE III
TABLE 2-1 Types of mechanisms responsible for generating abnormally high formation pressures (AHFP) Type of changes
Changes in the rock pore volume Vertical loading (undercompaction)
Lateral tectonic loading
Secondary cementation
Description of process
Rate of sedimentation and deposition. High depositional rates in clastic sequences and high shale/sand ratios (undercompaction). Massive areal rock salt deposition. Presence of impermeable salt (NaC1) beds. For example, massive salt deposits in U.S.A., Russia, North Africa, Middle East, North Germany, etc. Paleopressures. Sealed-off reservoir rocks experiencing a depth change due to either uplifting or erosion. Tectonic activities. Local and regional faulting, folding, lateral sliding and slipping; squeezing caused by down-dropping of fault blocks; diapiric salt, sand, or shale movements; earthquakes; etc. The pore volume is reduced by horizontal tectonic compression of rock. Cementation. Calcium sulphates, sodium chloride, dolomite, siderite, calcite, silica, etc., may act as sealing barriers ('pressure caps'), and directly cause increased pore pressure by decreasing pore space due to crystal growth within closed reservoirs (e.g., NaC1 in Markovo oil pool in the Osinskiy Series, Russia).
Changes in the volume of interstitial fluids Temperature change Thermodynamic effects. Formation temperature increase causes (aquathermal expansion) expansion of fluids with consequent increase in the fluid pressure. Mineral transformation Diagenetic and catagenetic processes. Postdepositional alterations (release of bound water): (1) montmorillonite and mixed-layer clays altered to illites (smectite dehydration); (2) gypsum to anhydrite dehydration. Hydrocarbon generation Conversion of organic material/kerogen to petroleum. Generation of oil and gas from kerogen (maturation) results in a significant increase in pore volume. Decomposition of Breakdown of hydrocarbons. About 2- to 3-fold volume increase hydrocarbons (thermogenic) caused by breakdown of hydrocarbon long-chained molecules into shorter-chained molecules. Such reactions generally occur at depths below 2 to 4 km and temperatures greater than 70 ~ to 120~ Thermal cracking of organic molecules is initiated at temperatures of 120~ to 140~ depending upon the depth of sediments. At temperatures greater than 180~ almost all the hydrocarbons are converted to methane. Migration of fluids Gas migration. Upward migration of hydrocarbon gases from lower to upper horizons along faults. This can result in overpressuring of upper horizons. Changes in fluid pressure (hydraulic head); movement of fluids Osmosis Osmosis. Contrasts in the brine concentration of formation fluids can induce the transfer of fluids across a semipermeable membrane. On regional basis, e.g., San Juan Basin, New Mexico, Western Sedimentary Basin, Canada, San Joachim Valley, California. US.A. Gulf Coast, and Paradox Permian Basin, !llinoi% U.,~I.A. Fluid pressure head Piezometric fluid level. Effect of regional potentiometric surface, e.g., artesian water system. Examples would include the Artesian Basin, Florida, U.S.A., Great Artesian Basin, Australia, and North Dakota Basin, U.S.A. Structure of permeable reservoir. Pressure transmission to shallower part of reservoir. Large anticlines, steeply dipping beds, etc.
ORIGIN OF ABNORMAL FORMATION PRESSURES
23
TABLE 2-1 (continued) Type of changes
Description of process
Oilfield production operations
Repressuring of reservoir rocks. Can occur as a result of massive fluid
Permafrost environment
Differences in specific weights
injection or fluid influx into the formation, i.e., massive water injection programs (secondary recovery). Pressure increase may occur across faults, or behind casing. Formation of frost heaves (pingos). Permafrost encroachment: trapping of unfrozen zone in practically closed system. Freeze-back pressures around shut-in arctic wells. Gas hydrate reservoirs (e.g., Mackenzie Delta, Canada). Density difference. Difference between the weight of a gas column and that of a fluid (oil or water) column.
TABLE 2-2 Types of mechanisms responsible for generating abnormally low formation pressures (ALFP) Type of changes
Description of process
Changes in the rock pore volume Rock dilatancy
Increase in pore volume. During erosion of a shallow-buried, clay-rich
Tectonic movements
Local and regional faulting, earthquakes, etc. With increase in tension
Increase in pore volume
Dissolution of cementing material. Dissolution of cementing materials
lithology, dilation of the pores can occur. of the formation, the pore volume may increase. such as CaCO3 can increase the pore volume.
Changes in the volume of interstitial fluids Thermodynamic effects. Cooling of the formation (e.g., due to uplift or
Temperature change
erosion) can cause the contraction of fluids and, thus, decrease the fluid pressure.
Changes in fluid pressure (hydraulic head); movement of fluids Osmosis. Contrasts in the brine concentration of formation fluids can
Osmosis
Production of fluids (gas, oil and/or water)
Migration of gases
Groundwater movement
result in the transfer of fluids across a semipermeable membrane. This can result in a loss of fluids across a semipermeable membrane with a resultant drop in the fluid pressure, in the upstream side of the system. Depressuring of reservoir rocks. Can occur as a result of massive fluid production from the formation that is not replaced by an influx of fluids from the adjoining formations, i.e., massive water depletion of producing formations. Gas migration. During uplift, gas is often able to come out of solution as the temperature and confining pressure are reduced. The freed gas may then escape toward the surface by diffusion or along faults, reducing the pore pressure of the rock. Fluid movement. Difference between the permeabilities of discharge and recharge areas, as more fluids are leaving the system than entering it.
24
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
certain depth [Ph, lb/ft 2 = (depth, D, ft) x (specific weight, gw, lb/ft3)]. Lithostatic (or geostatic)gradient, GI: the total pressure exerted by the overburden (rocks plus interstitial fluids) per unit of depth. Lithostatic (or geostatic)pressure, Pl: the pressure exerted by the total weight of the rocks and the interstitial fluids at a particular depth. Skeletal loading: that portion of the lithostatic pressure borne by the framework of solids (rock) of the porous media. This pressure is often referred to as the effective pressure, Pe or O-e.
COMPACTION
PROCESS
Several mechanisms responsible for generating abnormal pressures (Tables 2-1 and 2-2) are related to the changes in rock pore volume. This is particularly true in the case of relatively young basins that are buried from 1.0 to 2.0 km (Swarbrick and Osborne, 1998) and that had been rapidly deposited, or in those older basins with thick sections of fine-grained sediments. The increase in pore pressure results from the fact that the interstitial solution cannot escape quickly enough from the shrinking rock structure.
Hydrostatic pressure The hydrostatic pressure, Ph is defined as the pressure exerted at the bottom of a vertical column of water (Fig. 2-1) extending from the surface: Ph -- YwD = 0.433D
(2-1)
and where ),'w is the specific weight of water, and D is the length of the column of water. The pressure gradient of pure water is equal to 0.433 psi/ft. The specific weight of a fluid is a function of the quantity of dissolved solids (salinity), water temperature and volume of dissolved gases. Fig. 2-2 demonstrates the effect of total dissolved solids on the specific weight of the fluid. As the salinity increases (content of dissolved solids), the specific weight also increases. Fig. 2-3 illustrates the effect of dissolved gas, pressure and temperature on the compressibility and pressure gradient of water.
Formation or interstitial fluid pressure Formation (interstitial pore fluid) pressure deviating from the hydrostatic pressure, Ph, at any depth, D, is identified as abnormal formation pressure. Several examples of geopressure gradients are shown in Fig. 2-4. As discussed by Watts (1948), isolated abnormally high formation pressures (AHFP) may be found in the Ventura Field, California, as a result of thrusting. High pressures in formations associated with salt domes along the Gulf Coast of Texas and Louisiana are often attributed to faulting and diastrophism accompanying intrusion of the salt domes. A typical formation water gradient in this area is about 0.465 psi/ft (0.074 kg cm -2 m-l), which corresponds to
ORIGIN
OF
ABNORMAL
FORMATION
25
PRESSURES
0 psig
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. . . . . . . .
2.6 psig
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~
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4.333 psig 2 3 4 5 Pressure, Ph, psig
Fig. 2-1. Pressure versus depth for a 0.433 psi/ft gradient (pure water). (Modified after Brown, 1967, fig. 3.11, p. 28; in Khillyuk et al., 2000, fig. 18-1, p. 269.) water with the salinity of 80,000 parts per million (ppm) of sodium chloride at 77~ (25~
Sediment consolidation The forces acting on a unit of sediment control its compaction. Terzaghi and Peck (1948) were early pioneers in the study of compaction; however, the geologic applications of the theory of compaction of fine-grained clastic sediments was first elucidated by Hubbert and Rubey (1959). In nature, the load acting on a unit of sediment is carried by the (1) skeletal framework and (2) the interstitial fluid in the pores. The total stress at any point consists of the sum of two stress components: the skeletal (intergranular) stress and the pore-fluid stress. The term effective pressure, Pe, is used to designate the difference between the total overburden pressure (geostatic or lithostatic) and the pore pressure,
26
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
73 2~
72
S
71
-~
70
~a 69 68
--
67 .-~
66 65
,,,,~
64
r~
= "t=
63
62
0
2
4
6
8
10 12 14 16 18 20 22 24 26
Total dissolved salts, % Fig. 2-2. Density of brines as a function of total dissolved solids (TDS). (Modified after Frick, 1962, fig. 22.21, p. 22.24.) pp. If the vertical permeability of sediment allows the pore fluid to move out as the load is increased, then the pressure (stress) distribution in pore fluids is the same as that of a continuous column of water extending to the water-table surface (hydrostatic pressure). Inasmuch as the mineral grains (skeletal structure) support a load equal to the weight of the overlying water and grains minus the weight transferred to the water by the grains (buoyant force), then the force responsible for compaction, Fe, is equal to: Fe = F t - Fb
(2-2)
where Fe is the effective grain-to-grain force on the horizontal surface, A, Fb is buoyant force, and Ft is total overburden load. The total overburden force, Ft is equal to:
ft = fo + W~ + Wf-
(2-3)
where Fo is outside (external) force exerted on the body of the sediment under consideration. W~ is weight of solids: l'{/s --- g s ( l
- - ~ ) Vb
(2-4)
where ?,~ is the specific weight of solids, 4~ is the fractional volumetric porosity, and Vb is the bulk volume of sediment. Wf = weight of interstitial fluids: Wf = yfq9gb where ?,f is the specific weight of fluids.
(2-5)
27
ORIGIN OF ABNORMAL FORMATION PRESSURES 0.013 0.012 0.011 ~:~
0.010
I
0,009
a;
f1"
'~ 0.008 0,007 ~..T..: 0.006
>:
o~
0,005 0.004
~
i=~ 0.003 0
!: 0
0.002 0.001 0.000
0
1000
2000
3000
4000
5000
6000
Pressure, p, psia Fig. 2-3. Difference between the formation volume factor of gas-saturated pure water and that of pure water at various temperatures. Correction for the formation volume factor (EV.F.) is F.g-F.gas saturatedpurewater F.V.F.purewater. (Modified after Frick, 1962, fig. 22.16, p. 22.21.) F.V.F. = volume occupied at reservoir
conditions divided by the volume occupied at standard conditions at the surface (60~ and 1 atm pressure).
If the buoyant force Fb is equal to the weight of fluid displaced by the grains Fb -- Wb
--
~fgb(l
--
~b)
(2-6)
and inasmuch as
Vb--A.D
(2-7)
where A is the total cross-sectional surface area and D is the depth, and the pore pressure, pp: pp -- yfD
(2-8)
Fb -- p p . A (1 - ~b)
(2-9)
then:
Eq. 2-9, derived by Rieke and Chilingarian (1974), is in close agreement with the view of Terzaghi (1926) that the uplift force, due to pore pressure, is proportional to the surface porosity (also see Laubscher, 1960). Surface or boundary porosity is the ratio of the pore area to the gross area, along the surface, A. It can also be shown that surface porosity on a plane surface is the same as volumetric porosity. Hubbert and Rubey
28
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
,,4,,,-,
4000
' \~e
(1) 11)
.ff O. (1) 1=1
"~ x,~4 o
\ \ '~ "~_ ~ ~ "
8000
9
California - Ventura Field pressuresnear crest
~....\ b . . \ Q
.
~
\ \
~
_,ro~\
w
~ ~
~ Ventura Field ,0 ~ D-7 Zone
,,
"~,
12,000
\
\
Wyoming Church Buttes
Texas -- Louisiana Gulf~oast Fields
'\
\
\
\ 0
4000
8000
Pressure, psi
12000
16000
Fig. 2-4. Relationship between the formation fluid pressure and depth in several abnormally pressured pools. Specific weight of water = 62.4 lb/ft 3 (+144 in2/ft 2 = 0.433 psi/ft). (Redrawn from Watts, 1948, fig. 2, p. 194; in Rieke and Chilingarian, 1974, fig. 10, p. 26.)
(1959; also see Hubbert and Rubey, 1960), however, showed that the pore pressure, pp, is common to both the water and the clay and acts over the whole of any surface passed through the porous solid, with the surface porosity being in no way involved (see experimental results of Rieke and Chilingarian, 1974, p. 6). On assuming that all pores are filled with water, at a depth, D, the total overburden pressure, pt, resulting from the weight of overlying water and solids can be expressed by the following equation: Pt-
[y~(1 -4>) + y'wr
(2-10)
where Vs is specific weight of the sediment grains (lb/ft3), 05 is fractional porosity, and Vw is specific weight of water (lb/ft3). Inasmuch as the effective pressure (grain-to-grain stress), Pe, is equal to the difference between the total overburden pressure and the pore pressure [Pe - Pt - Pp], and pore pressure at a depth D is equal to VwD, then: Pe -- [ys(1 --q~) + Ywq~- yw]D
(2-11)
Pe -- D[(1 - ~ b ) ( y s - Yw)]
(2-12)
or:
Brandt (1955) introduced an 85% correction factor (n) into the pp term to take into account the "fact that the internal fluid pressure does not wholly react against
ORIGIN OF ABNORMAL FORMATION PRESSURES
29
the e x t e r n a l p r e s s u r e " . According to him, this factor, n, is structure dependent and, therefore, is not the same for all sediments: Pe = Pt - npp
(2-13)
Rieke and Chilingarian (1974, p. 6), however, showed that n is equal to one. Accumulation of additional sediments upon the older sediments will cause a gradual change in the vertical stress throughout the sediment column. The matrix pressure is redistributed by the grains squeezing closer together so that they bear more load. Many authors (Hubbert and Rubey, 1959; Hottman and Johnson, 1965; Powers, 1967; and others) have stated that for thick shale sequences having low permeability, compaction is a slow process and the fluid must support the additional load. This creates abnormally high pore-fluid pressures, which must be balanced by a corresponding decrease in the shale matrix pressure, because the total weight of overlying rock and water to be supported is practically the same.
STATE OF STRESS IN C O M P A C T I N G S H A L E S
The lithostatic pressure (overburden weight) is probably equal to the vertical normal component of the stress. There is the possibility, however, that the normal stress at a point in a shale body undergoing compaction at some depth is equal to the overburden weight per unit area plus contributions from the vertical shear components of stress (r). A total stress field in such a sedimentary body can be specified in terms of its normal and tangential stress components across a given plane surface (Fig. 1-2) (see Rogers, 1964, p. 25): f x - - {Crx-Cxy-Cxz}AyAz
Fy = {72yxGy'gyz} A x A z
(2-14)
F z = {rzxrzyCrz}AxAy
where Fx, Fy, and Fz are the forces in the x-, y-, and z-directions. It should be noted that the pressure (load per unit area) has the dimensions of stress (e.g., psf or psi). The surface forces are measured in units of force per unit area, whereas the body forces are measured in units of force per unit volume. Examples of these would be specific weight and pressure. In the case of a normal stress as expressed in Eq. 2-14, the subscript refers to the direction (axis) normal to the plane on which the stress acts. In the case of shear stresses, the first subscript denotes the axis perpendicular to the plane in which the stress acts, whereas the second subscript denotes the direction in which the stress acts. It is important to note that one must be consistent in considering either (1) all forces acting on the system or (2) all forces acting outward from the system. If Ft is the normal component of the total force exerted on the element, and Ftt is the tangential component of the force, then for any change in Ft or Ftt, owing to additional overburden weight, there will be a corresponding change in the shear and tangential
30
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
stresses" Acr--
AFt A
At--
(2-15)
AFtt
A
Resolution o f the total stress field
The stress tensor for a porous, homogeneous, isotropic shale body can be written in the conventional way:
S ~
crx
"gxy
rxz
ry x
Cry
12yz
72zx
Tzy
Oz.
(2-16)
where S signifies the symmetrical tensor of the total stress; cri and rij represent the normal and shear forces, respectively, acting on the faces of a unit of an argillaceous sediment. Next, one can take moments about point O (Fig. 1-2). The tangential stress, r~y, multiplied by the area in which it acts, gives the force rxydzdy, and this times dx, gives a clockwise moment about O. The stress, ryx, times the area gives r,.xdxdz, and the latter times dy results in a counterclockwise moment r y x d x d z d y . At equilibrium, the two moments balance each other: rxydzdydx - ryxdxdzdy
(2-17)
rxy -- ryx
(2-18)
or
Then it follows that rx: - r:x
(2-19)
ryz - rzy
(2-20)
and
The total stress array for a point in a cylindrical body under compaction can be expressed in cylindrical coordinates r, 0, and z"
S ~
crr
TrO
Trz
"fOr
crO
gOz
Tzr
"gzO
crz
(2-21)
The total stress tensor can be decomposed into two distinct parts for a body of sediment in equilibrium: (1) hydrostatic stress; and (2) deviatoric stress.
31
ORIGIN OF ABNORMALFORMATIONPRESSURES H y d r o s t a t i c stress s t a t e
The component attributable to the interstitial fluid is the hydrostatic stress (pressure), O-w, which can be regarded as being continuous throughout the medium. The normal and shear stress components are given by:
P --
O-wx
72wxy "Cwxz
"Cwyx
O-wy
rwyz
rwzx
"gwzy
Crwz
(2-22)
where P is the hydrostatic tensor. It can be assumed that under hydrostatic conditions no shearing stresses exist in the interstitial fluid. By definition, a fluid is a substance that cannot sustain tangential or shear forces when in static equilibrium. This may not hold true for adsorbed water because of its probable quasi-crystalline nature. Hubbert and Rubey (1959, p. 138) noted that if a viscous fluid occupies the pore space, there are then microscopic shear stresses, which are expended locally against the fluid-solid boundaries. Thus, their only macroscopic effect is to transmit to the solid skeleton by viscous coupling whatever net impelling force may be applied to the interstitial fluid. In any stress system with the principal stresses, O-~,O-y, and crz, one can determine the local mean value for the hydrostatic stress, 6w, as: 1
(2-23)
6w -- 5(o-wx .qt_O-wy + O-wz)
Now, the hydrostatic stress tensor, P, can be represented by
P ----
-iw
0 6w
0 0
0
~w
(2-24)
and P - - 5 1 (36w) -- 6w
(2-25)
The above expression represents the hydrostatic pressure of a fluid whether it is flowing or is stationary in the porous system of the shale. Note that O-wx -- O-wy = O-wz - 6w, and that the hydrostatic portion of the total stress system causes only volume changes in the deformed material. D e v i a t o r i c stress state
The second component is known as the stress deviator from the hydrostatic state. It is expressed as the difference between total stress and the hydrostatic stress, which resists deformation:
D --
(O-x -- O-wx )
75xy
"Cxz
ryx
(o-y -- O-wy)
ryz
rzx
rzy
(O-z -- O-wz)
(2-26)
32
G.V. CHILINGAR,J.O. ROBERTSONJR. AND H.H. RIEKEIII
where D is the deviatoric portion of the total stress tensor. The effect of the deviator stress is to produce a distortion, which is elastic or plastic in nature and is introduced into the shale body. Total stress tensor
If the sediment body is not in equilibrium, the second component will not be a symmetric tensor for "gxy ~ "gyx. Ramsay (1967, p. 282) subdivided the asymmetric tensor into symmetric and skew-symmetric parts. The hydrostatic stress component is the same as in Eq. 2-23. The second symmetrical part is the deviatoric stress component which can be expressed as follows:
D --
(O'x --O'w)
"~l ( 72x y -+- "Cy x )
1 ~('gxy + "gyx) 1 ~ ( "gx z + "gz x )
(Oy - ~w) 1 "~ ( 72y z + 7Jay)
-~l(r~z + rz~) 1 ~("gyz 'Jl- "gzy)
(2-27)
( O'z - - O ' w )
The skew-symmetric part is termed the disequilibrium component, which causes the shale to undergo a rotation in space and is expressed as:
l ~('rxy + ryx)
0
R =
l(r~ + r~)
1
(2-28)
! (r~,:. + r:..~,)
1 ~(r:.~ + r~:.)
1 ~(r:.y + ry:.)
0
where R is the disequilibrium component. Such a stress state would be anticipated if tectonic forces were acting on the shale mass in a basin within a geosyncline. The total stress tensor for a shale body not in equilibrium is expressed as the sum of the above-described parts: S= P+D+R
(2-29)
Namely, the total stress = hydrostatic stress + deviatoric stress + disequilibrium component. Each one of the three components making up the state of stress is directly related to the respective component of the strain tensor. The hydrostatic portion of the stress system causes changes in volume, the deviatoric stress components cause distortion, and the disequilibrium components cause the material to undergo rotation in space (Ramsay, 1967). Lo (1969) demonstrated that the pore pressure induced by shear may be expressed as a sole function of the major principal strain. According to him, the only unambiguous and correct principle of superposition of pore pressure is to consider an isotropic stress system and a deviatoric stress system, namely, m
ACrl
0
0
0
Act 2
0
0
0
AO-3
--
Act3
0
0
0
Act 3
0
0
0
AO"3
(ACrl -- Act3) +
0 0
0
0
( A o 2 -- / k o 3) 0 0
0
(2-30)
33
ORIGIN OF ABNORMAL FORMATION PRESSURES
where crl is the total major stress, ~r2 is the total intermediate stress and or3 is the total m i n o r stress. According to Lo (1969), the physical justification for Eq. 2-30 lies in the fact that under ambient stress, the induced pore pressure corresponds almost exactly to the applied pressure, because the compressibility of the pore water and argillaceous sediment grains are m u c h lower than that of the sediment structure. M o s t of the pore-pressure equations presented in literature give almost identical results providing they are properly used. For further detailed discussion see Rieke and Chilingarian (1974).
Spring models of compaction The concept of the s h a l e - c o m p a c t i o n process can be best explained by a m e c h a n i c a l m o d e l which is c o m p o s e d of a perforated, round metal plate and the enclosing cylinder which contains a metal spring and water (Fig. 2-5). In this analogy, the spring represents the compressible clay particles, the water represents the fluid in the pore space, and the size of the perforations in the metal plate determines the permeability. Using this model, well-saturated clay can be treated mathematically, as a two-phase continuum. The hydrated clay is envisioned as clean clay plates in m e c h a n i c a l contact
A
Overburden P r e s s u r e
0 psig =
B
Overburden Pressure
25 psig 9
C
D
Overburden Pressure
25 psig
Overburden Pressure
25 psig
Perforated plate / /
Manometer
/ t.t or'= 0 p s i g ~w = 0 psig )~ = i n f i n i t y
~'= 0psig crw = 25 psig
or'= 3 p s i g ~ = 22 psig
~'= 25psig crw = 0 psig
~L
)~
X
=
I
-
0.875
=
0
Fig. 2-5. Compaction analogy using a spring and perforated plate, o-t is the effective (intergranular) stress, ~w is the pore-water stress and X is the ratio of the pore-water stress to the overburden stress on the system (c~t and Crw are in psig). (Case A) Initial conditions; tightly fitted, frictionless metal plate seals the water in the cylinder. There is no overburden load on the system and perforations of plate are sealed. (Case B) A 25-psig load is imposed on the model. This load is entirely carried by the water. Perforations in the plate are sealed. (Case C) The fluid is allowed to flow out through the perforations. The plate descends as the fluid escapes. The spring carries a portion of the load. (Case D) The spring now carries the entire 25 psig load. The system is in equilibrium and there is no water outflow. (Modified after Taylor, 1948; in Rieke and Chilingarian, 1974, fig. 49, p. 90.)
34
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
with each other and the fluid wetting the clay-particle surfaces and filling the pore space between the particles. If the mechanical model were sealed in such a manner that no fluid could escape through the plate, then the total applied pressure to the system would be carried by the fluid and none by the spring (Fig. 2-5B). The compressibility of the spring is assumed to be so great that the strains produced in the fluid and in the cylinder walls are negligible in comparison (Taylor, 1948, p. 223). Fig. 2-5C shows that if the fluid is allowed to escape through the perforations, then the overburden pressure is carried both by the spring and the fluid. As the fluid escapes, the plate sinks lower and lower, compressing the metal spring. The length of time required for the spring to pass from one state of compaction to the next depends on how rapidly the water escapes; this is determined by the size of the perforations in the plate. Equilibrium is reached at a point where none of the overburden stress is borne by the fluid (Fig. 2-5D); however, any additional applied loads cause the plate to compact the spring still further, expelling additional fluid. In this manner the clay layers are thought to be compacted under the weight of the overlying sediments. In the spring analogy of the compaction, the following relationship (static equilibrium) must exist at any particular time: Ft = Fs + Fw
(2-31)
where Ft is the total overburden force applied to the system, Fs is the force carried by the spring, and Fw is the force applied to the fluid. If these forces are divided by the total cross-sectional area, A, of the enclosing cylinder, then: Pt or o- =
Ft/A
(2-32)
lS~/A
(2-33)
pp or aw = Fw/A
(2-34)
Pe or o r ' =
where pt or cr is the total stress applied to the system, Pe or a ' is the effective stress, and pp or crw is the pore-water pressure. Thus, Eq. 2-31 can be rewritten as: cr = o-' + aw
(2-35)
As expressed in Eq. 2-35, the total stress, or, normal to any plane in the skeletal structure consists of two components: (1) the pore fluid pressure, Crw; and (2) the effective stress component, or', which is 'effectively' carried by the skeletal structure. The spring analogy fails to agree with the actual compaction of clay in that the pressure conditions are not the same throughout the thickness of the clay mass as they are in the cylinder. In compacting saturated clay at a given pressure, the water pressure at its surface is atmospheric (0 psig), whereas at short distances inside the clay sample the water pressure is equal to o- - or'. Fig. 2-6 illustrates a void space surrounded by a shale matrix. In this figure, the total weight of the overburden, which acts downward, and the vertical and horizontal portions of the effective stress are shown. The high fluid-pressure gradient at the clay's surface is caused by the rapid expulsion of the fluid from the pores near the surface. Under a constant overburden pressure, the water pressure decreases with time, whereas the intergranular pressure increases.
35
ORIGIN OF ABNORMAL FORMATION PRESSURES
!
O" v
i
O" H + O'w
t
]~
.= O"w
~W
0"
CYx
(5" z
Fig. 2-6. Stress state in a shale. Schematic of the stress state in a shale body underground, where crv' is the effective (intergranular) stress in the vertical direction, cr~ is the horizontal effective stress, Ow is the pore water stress and crz is the total vertical stress component. The total horizontal stress component in the x-direction Crx is equal to cr~ + ~r~. (Modified after Rieke and Chilingarian, 1974, fig. 50, p. 92.)
A useful expression in studying compaction is the ratio of the fluid stress to the total stress, )~ (see Hottman and Johnson, 1965): )~ --
Ow cr
=
pp Pt
(2-36)
W h e n stress is initially applied to the closed system, )~ has a value of 1 and the system is overpressured. At final compaction equilibrium, when the load is carried entirely by the skeletal structure (grains; spring), )~ is equal to 0. An example of the use of )~ is demonstrated in Figs. 2-5 and 2-7. At the final stages of compaction equilibrium, the applied load is supported jointly by the skeletal structure and intergranular water (hydrostatic) and the value of )~ is approximately equal to the normal pressure gradient, i.e., 0.465. This value is typical of the normal pressure gradient on the U.S. Gulf Coast (~0.465 psi/ft). The lithostatic (geostatic or overburden) pressure gradient is considered to be about 1.0 psi/ft (0.231 kg cm -2 m -1) of depth. As discussed earlier, the hydrostatic pressure will vary from locality to locality dependent upon the specific weight of the water (salinity).
36
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
S S
S
P ; : : ,,<:
............
,. . . .
. .:
6
Stage A ~=1
L<
Stage B
1 >0.465
Stage C
~.=0.465
Perforated Plates Water Fig. 2-7. Schematic representation of clay compaction, o- - grain-to-grain bearing strength, S = axial c o m p o n e n t of total stress (overburden pressure), and p = fluid pressure, o- = S - p. (Stage A) Overpressure system. (Stage B) Water is allowed to escape; springs carry part of the applied load. (Stage C) Compaction equilibrium; load is supported jointly by the springs and the water pressure, which is simply hydrostatic. )~ = P p / P t = p / S . (Modified after Terzaghi and Peck, 1948; in Hottman and Johnson, 1965, p. 718. In Rieke and Chilingarian, 1974, fig. 5 I, p. 93.)
Another useful ratio of the effective intergranular stress to the total stress can be used, which is expressed by the symbol X" O-t
X --
(2-37)
(7
Hooke's law Commonly, the overburden weight of sediments (force) creates the major stress, o-z, which acts in a vertical direction. The lateral stresses, ox and ~r.v, lie in a horizontal plane in all directions as a lateral restraining force. According to Hooke's law, the horizontal strain (ex) can be expressed as follows" ex =
O"x
O-v
O-z
v--:- - v - (2-38) E E E where e,, is horizontal strain, a~, a>,, a: are effective stresses along x and y (horizontal) and z (vertical) axes, E is Young's modulus, and v is Poisson's ratio. Inasmuch as e~ is essentially equal to zero and the lateral stress a , is equal to the lateral stress ay for rocks in compression, then" v o x - - O-y - - o-h - - ~ o -
(1 -
v)
z
(2-39)
ORIGIN OF ABNORMAL FORMATION PRESSURES
37
where Crh is horizontal stress in general. On assuming a Poisson ratio, v, of 0.18 to 0.27 for consolidated sedimentary rocks, the horizontal compressive stress would range from 0.22 to 0.37 psi/ft of depth. According to Harrison et al. (1954), for soft shales and unconsolidated sands found in the Gulf Coast of Texas and Louisiana, which can be considered to be in a plastic state of stress, the horizontal stresses are in excess of 0.37 psi/ft of depth. Faulting can occur in cemented rocks at stresses that will only cause plastic deformation in uncemented rocks. The effective pressure, Pe, may be either increased or decreased by the presence of vertical dynamic flow and resulting fluid drag pressure on the grains, depending upon the flow direction. An example of this would be quicksand, a case where intergranular loading has been reduced to nearly zero by upward water seepage resulting in zero bearing strength in the skeletal structure. L o a d transfer
The overburden (lithostatic) pressure, Pt, is equal to: Pt = Pbg Z
(2-40)
which for all practical purposes, is the pressure exerted at any depth by the weight of overlying sediments and fluids. The density term in this equation is the bulk density of fluid-saturated rocks. If Pb is known, the pressure-depth relationships can be established in a particular area. Hubbert and Rubey (1959, p. 129) stated that within depths of 1 or 2 km, the pressure of the water as a function of depth, D, can be closely approximated by the equation: Ph = p w g D = ywD
(2-41)
where Ph is the hydrostatic pressure of a column of water extending from the surface of the ground to a depth of D, Pw is the density of the water, g is the acceleration of gravity, and Yw is the specific weight of water. Along the Gulf Coast, the fluid-pressure gradient is about 0.465 psi for each foot of depth. This represents a hydrostatic pressure gradient for brine having a specific weight, yw, of 67 lb/ft 3. The corresponding shale matrix pressure is 0.535 psi/ft, if one assumes a total lithostatic pressure gradient of 1 psi/ft. Frederick (1967) presented several examples of the relationship between the bottom hole fluid pressure and depth for areas with abnormal pressures. Hubbert and Rubey (1959, p. 155) noted a lithostatic pressure as high as 1.06 psi/ft occurring in the Khaur Field in Pakistan. Levorsen (1958, p. 386) reported that the average gradient of oilfield brines is approximately 0.450 psi/ft. Deviations are in part due to the varying salt concentrations in the brines. Table 2-3 gives the specific gravity and pressure gradients of various fluids that might occur in a sand-shale sequence. Fig. 2-8 demonstrates the pressure versus depth relationship for various brines. AHFPs can form when a portion of the effective stress, ~e, normally assumed by skeletal structure is transferred to the intergranular water. For example, when increasing the weight of the overlying sediments by continued burial, Fz, at a rate faster than the intergranular water can escape from the sediment, the percentage of the lithostatic
38
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
TABLE 2-3 Pressure gradient and specific gravity data for various fluidsa,b Type of fluid
Specific gravity
Specific weight (lb/ft 3)
Pressure gradient (psi/ft)
Crude oil (40~ Fresh water, TDS = 0 mg/1 Seawater, TDS = 35,000 mg/l Brine, TDS = 100,000 mg/1 Brine, TDS = 200,000 mg/1
0.8285 1.000 1.0256 1.0730 1.1285
51.69 62.4 63.99 66.95 70.42
0.359 0.433 0.444 0.465 0.489
TDS -- total dissolved solids. a Levorsen (1958, p. 663) pointed out that the pressure gradient averages approximately 0.0043 psi/ft per specific gravity increase of 0.01. b After Rieke and Chilingarian (1974), table XI, p. 104.
pressure exerted on the skeletal structure decreases as the percentage of load exerted on the intergranular fluid increases, which in turn increases the fluid pressure. If this increased fluid pressure is dissipated by the flow of water from the sediment, the excess load is transferred to the skeletal structure. As the grains become more tightly packed and the pore space is reduced, however, the permeability of the sediment is reduced and the intergranular water cannot be removed rapidly by forced flow to other regions. The fluid pressures increase to successively higher levels because of the inability of the excess fluid to be expelled. Under many geologic settings, the overburden loads are not equal and the interstitial fluid pressures are not hydrostatic. A thorough understanding of the loading processes and load transfer from the pore fluids to the skeletal framework of the sands is thus important. Compaction of sediments can occur as a direct result of loading or a change in loading. An imbalance of forces then occurs between the applied load and the ability of skeletal framework to resist this load. The magnitudes of the changes in loading, which cause compaction of the framework, are presented in Fig. 2-9. On assuming that the strata consist of sands and shales, and that all pores contain fluid, Curve 1 represents the hydrostatic gradient, i.e., the pressure, owing to fluid column, exerted per unit depth. Curve 3 shows the overburden (lithostatic) pressure gradient. The effective unit load on the sand grains, i.e., the intergranular pressure, is represented by Curve 2. The latter pressure gradient is equal to the difference between the gradient of Curve 3 and that of Curve 1. Fig. 2-9 is a graphical representation of Eqs. 2-10 and 2-11. Over geologic time, it would be extremely rare for any deposit not to undergo many overburden load changes. Two such cases are illustrated in Fig. 2-9 (Allen and Chilingarian, 1975). Case 1. If the fluid level is lowered in an unconfined aquifer (i.e., no caprock, and fluid is present as a continuous phase to the surface) to a depth of 500 ft below surface (assuming no residual capillary water), the hydrostatic pressure shifts to zero at that point (Curve la); the geostatic and intergranular pressure gradients become identical down to a depth of 500 ft (Curves 2a and 3a). The intergranular pressure would
39
ORIGIN OF ABNORMAL FORMATION PRESSURES
0
0
2000
4000
6000
8000
I0,000
\
"~,//I///I/I/I/////I/,
12,000
14,000
6000
N,--
8000
LLI 10,000
12,000
14,000
~6,OOOl--
I
\
\
~OOO
Fig. 2-8. Hydrostatic and lithostatic pressure gradients. The dashed area indicates the region for reservoirs having abnormally high formation pressures (AHFP). (Modified after Rieke and Chilingarian, 1974, fig. 53, p. 105.) Pressures shown on top are in psi.
increase owing to the loss of the supporting hydrostatic pressure (from Curves 2 to 2a), whereas the total overburden weight is reduced because of loss of weight of water fraction (from Curves 3 to 3a). At a depth of 500 ft, each one would assume a normal pressure gradient (Curves 2b and 3b) owing to the presence of pore fluid from that point downward. Case 2. It is assumed that the entire section is water saturated, but that the hydrostatic pressure in the confined aquifer (i.e., impermeable caprock is present above the aquifer) at a depth of 1500 ft has been reduced to zero by pumping (Curve lb). Inasmuch as the pores are all saturated with water, the hydrostatic pressure can be zero only at that
40
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
PRESSURE, psi
0
500
0.[ ~\
I 25
I~\
I
\\ ' ~
/
I
1000
l 50
I
Kg/Sq cm
1500 IIli~
I 75
I 1O0
0.77 psi/ftor O.18 kg/sqcm/m
500' = '" "-~ , k " '~, '~,Xx\ |\ \\ \ \ \ ~.200m ~\ ~ \ \ \
Totaloverburdenpressuregradient~' I,'/70.91psi/ftorO.21kg/sqcm/m / /
~ \ ~\\~ \ \~.X\/ Unconfined& ~ \ ~_\'~ \ \\\\\ unconsolidated ! ~\ ~,..'\'~ \ ', X_ Aquifer ,ooo,: \ ",), E
, Nydrostatic pressure gradient~ ~ 0.43psi/ftorO.I kg/sqcm/m \~,
'/ /
OOm "
15oo',
\
s,,,\ ~ V'.~. ~_~\,, \~'~
,,,
_~ ImpermeableCaprock"xX.
;_ /' , '~
Confined \ & '\\ '~'\\ \'~ 0.4_8 ,ntergranulal Prissuregardeint p~si/f)or O.11 kg/sqcm/m ~\\unconsolidated '\ ~ ~""---~~ aquifer ~ ~ '~ '~ t~,
2000, _60~3 r
~
/
Curve 2c
Fig. 2-9. Hydrostatic, geostatic and skeletal load changes as influenced by changes in fluid levels and pressure in unconfined and confined aquifers. Curves 1, la, lb -- hydrostatic pressure gradient; curves 2, 2a, 2b, 2c -- intergranular pressure gradient; curves 3, 3a, 3b -- total overburden pressure (geostatic) gradient. Sp. gr. solids -- 2.7; sp. gr. water - 1; porosity, 4) = 35%. (Modified after Allen and Chilingarian, 1975, fig. 2, p. 50.)
point and will increase with depth, at a normal hydrostatic gradient; therefore, Curve l b is parallel to Curve 1. The skeletal structure at a depth of 1500 ft assumes the full overburden load, and the intergranular gradient shifts from Curve 2 to Curve 2c, because of the loss of hydrostatic pressure support. Fig. 2-10 illustrates the changes in skeletal loading if the pore pressure at the top of the confined zone at 1500 ft is raised to become equal to the lithostatic (geostatic) pressure. The hydrostatic pressure gradient (Curve 1) would become equal to the geostatic gradient (Curve 3) at 1500 ft (Curve 1 shifts to Curve la) and the intergranular pressure (Curve 2) is reduced to zero (Curve 2 shifts to Curve 2a). The entire weight of
41
ORIGIN OF ABNORMAL FORMATIONPRESSURES
0
500
"
I \',\,\\
100o
] 500
KG/CM2 I
500
Q -1- 1000 I-ILl
c~ \\\\\
1500
I
i
ii
-
~.k~-,~ IMPERMEABLECAPROCK -~\\\
2000 Ib 600 m Fig. 2-10. Hydrostatic, geostatic and skeletal load changes under abnormally high formation pressure (AHFP) conditions. Curves 1, la = hydrostatic pressure gradient; curves 2, 2a = intergranular pressure gradient; curve 3 = the total overburden (geostatic) pressure gradient. Sp. gr. of solids = 2.7, sp. gr. of water = 1, and porosity, 4) = 35%. (Modified after Allen and Chilingarian, 1975, fig. 3, p. 51.)
the overburden is now exerted on the intergranular pore fluid at the top of confined zone. With increasing depth below 1500 ft, some of this load will be transferred from the pore fluids to the skeletal structure. This is illustrated by the fact that the slope of Curve 1a is steeper than that of Curve 3 and that Curve 2a is parallel to Curve 2. The bulk specific gravities of undercompacted, abnormally high pressure formations are lower than those of well-compacted rocks having similar lithologies. This is demonstrated by examination of cores from the boreholes and by logging. AHFPs off the coast of California, where the pressure gradient at a depth of about 9000 ft approaches geostatic gradient, are presented in Fig. 2-11. Various well log parameters, reflecting rock bulk specific gravity (commonly called bulk density) and fluid content, show the presence of overpressured zones.
42
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
2000
4000
q
Rincon -Dos Cuadros pressure gradient
c-
C~. 6000
a 8000
10,000
....... 0
O0
2000
200
~90
4000
400
500~
6000
600
8000
\ 7 0 0 kg/cm 2 10,000
Pressure, psi Fig. 2-11. Variation in pressure gradient with depth in Rincon-Dos Cuadros, California, USA, abnormally high formation pressure (AHFP). (Modified after McCulloh, 1965, fig. 11, p. 38.)
Porosity-density variations with depth A series of curves showing variation in porosity and density of plastic sedimentary rocks with increasing geostatic loading are presented in Fig. 2-12. Ozerskaya (1965) presented the following equation for the variation in rock porosity with increasing geostatic pressure: ~b = ~bmaxe-0"45D
(2-42)
where ~bmax is the maximum initial porosity of argillaceous sediments, which is commonly considered to be equal to 60%, and D is the depth of burial. The 60% value is a good average for deltaic and marine clays; however, 4~maxmay be significantly different for continental, lacustrine, deep-ocean, and other types of clays. The formula relating fractional porosity, 05, bulk density, Pb, and mineralogic density, Ps, can be presented as follows: Pb = p~(1 -- 4>)
(2-43)
Consequently, Pb = ps(1
- ~bmaxe -0"45D)
(2-44)
In Fig. 2-12 the density of mineral grains was assumed to be equal to 2.7 g/cm 3. It was assumed that the initial maximum porosity of the clayey sediment was equal to 60%. If the values read from Fig. 2-12 indicate a lower initial porosity, there are several possible
43
ORIGIN OF ABNORMAL FORMATION PRESSURES
POROSITY (~), % 60
50
40
30
20
10
o
0,1
5C 0.5
E
4,5
1.0
c~
30
"1-
2~
0_
LJJ
20
c~ 5.0
10.0
] .1
1.5
1.9
DENSITY (pJ,
2.3
2.7
g/cm
Fig. 2-12. Interrelationship among the bulk density, porosity and depth of burial (lithostatic load) for argillaceous sediments. 4) = q~maxe-0"45D; jOb -- ps(1 --q~maxe-045D); Ps = 2.7. The numbers des gnate the values of initial porosity (4~max) from 60 to 5%. The same numbers shown on the first curve to the left, correspond to the curves with different initial porosity, shifted along the depth scale to the 60% curve. (Modified after Ozerskaya, 1965; also see Avchyan and Ozerskaya, 1968, fig. 2, p. 139; in Rieke and Chilingarian, 1974, fig. 54, p. 106.)
explanations: (1) part of the overburden load was removed by erosion; (2) uplift of the region; (3) geotectonic forces caused excess compaction; (4) subsequent cementation and filling of pores; (5) presence of sand and carbonate fractions; (6) wrong initial porosity assumption.
COMPACTION MODEL5
The pore volume of clastic sediments and rocks decreases with increasing depth. This decrease in porosity is a convenient measure of the amount of compaction undergone by
44
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
argillaceous sediment since deposition. There is a problem in evaluating the effects of depositional rates and geologic age in developing a simple sediment compaction model. Nevertheless, empirical data suggest that the effect of age and depositional rates are commonly predictable. Although the effect of temperature on formations is difficult to evaluate, experiments by Warner (1964, pp. 50-79) suggest that at temperatures less than 200~ temperature may not have a significant effect (other than in accelerating compaction rates). Most compaction models utilize clay minerals of an idealized size and shape, which are influenced by mechanical rearrangement during burial. The following theories, presented in chronological order, are intended to enable the reader to better visualize the interrelationship among pressure, porosity reduction, and interstitial fluid release in argillaceous sediments. A comparison of the relationship between the porosity and depth of burial is shown for several regions in Fig. 2-13.
Athy's compaction model According to Athy (1930a) compaction represents a simple process of squeezing out the interstitial fluids and thereby reducing the porosity. In relatively pure shales a definite relationship exists between porosity and depth of burial (Fig. 2-14). After a sediment has been deposited and buried, the pore volume may be modified by: (1) deformation and granulation of the mineral grains; (2) cementation; (3) solution; (4) recrystallization; and (5) squeezing together of the grains. The continued application of overburden or tectonic stress is the mechanism by which porosity is reduced and bulk density is increased further. Athy (1930b) pointed out that the amount of compaction is not directly proportional either to reduction of pore volume or to increase in bulk density because of the above-mentioned processes.
Hedberg's compaction model Hedberg (1936) stated that because of the numerous processes involved in compaction, it is not possible to express satisfactorily pressure-porosity relationships for clays and shales throughout the entire depth range by any one simple equation. Hedberg (1936) determined the porosities of shale core samples taken from Venezuelan wells from depths of 291 ft to 6175 ft. An analysis of these data, led Hedberg (1936) to propose a compaction process consisting of three distinct stages. The first stage consists mainly of the mechanical rearrangement and dewatering of the clayey mass in the pressure interval from zero to 800 psi. During this period of dewatering, there is a rapid decrease in porosity for small increments of additional overburden pressure. Expulsion of free water and mechanical particle rearrangement are dominant in the porosity range from 90% to 75%. Some adsorbed water is also lost during this stage. Between a porosity of 75% and 35%, adsorbed water is expelled from the sediment. Mechanical deformation of the clay structure occurs below a porosity of 35% where the clay particles come in closer contact with each other. As a result, there is a greater resistance to further reduction in porosity. According to Hamilton (1959, p. 1407), the
ORIGIN OF ABNORMAL FORMATION PRESSURES
45
|
1
J
jS 5o00
,-l-,Wl--,
'!'
q .C:
l o,ooo
'
C}. (I) C~
,
/~
/
1
r
I
i
,o
15,000
20,000
.........
i 0
, 20
,,
i
40
60
Porosity (~). % Fig. 2-13. Various compaction models showing the relationship between porosity and depth of burial for shales and argillaceous sediments. 1 --- Proshlyakov (1960); 2 = Meade (1966); 3 = Athy (1930a); 4 = Hosoi (1963a,b); 5 = Hedberg (1936); 6 = Dickinson (1953); 7 = Magara (1968); 8 = Weller (1959); 9 = Ham (1966); 10 = Foster and Whalen (1966). (Modified after Rieke and Chilingarian, 1974, fig. 17, p.42.)
transition from clay to shale likely occurs at about 35% porosity, because the chemical changes and cementation between the grains impart rigidity to the skeletal structure. There is also some recrystallization of the clay particles during this stage (Hedberg, 1936). Recrystallization stage is the third and final stage with porosities less than 10%. The main compaction mechanism during this stage is recrystallization under high pressures. Reduction of the pore volume occurs slowly and only with large pressure increments. The larger crystals may grow at the expense of the smaller ones, and a gradual transition may occur from a shale to a slate and then to phyllite.
46
G.V. CHILINGAR,J.O. ROBERTSONJR. AND H.H. RIEKE III
2.6
A
,
..'-(
..
..
.
,~...>7.
..#/.,~?:.'
,.....:
.
.
.
.
9
: .
2.4
E
O
C d~ L3
2.2
2.0
1.8 /
1.6 I
/
/
/
!
!
/
/
/
/
/
/
/
I
i
1.4
I
I
I
i
,
1000
I
I
3000
i
i
Depth at Garber (O), It ~
5o
--O-
.,~
4o
o
30
w
i
I 5000
\
'
% %
B
% % % % % %
O
IX. C
20
O O
l0
.=u. .@,m
E O
i1_
0
I
0
i
l
2000
i
4000
Depth (O), ft
i
i
6000
Fig. 2-14. (A) Relationship between the dry bulk density and depth for Oklahoma (USA) shales. (B) Relationship between the porosity and depth for Oklahoma (USA) shales. (Modified after Athy, 1930a, figs. 2 and 3, pp. 12-13; in Rieke and Chilingarian, 1974, fig. 14, p. 37. Courtesy of Am. Assoc. Pet. Geol.)
Weller's compaction model Wello," cloCaa described a compaction process ,,or,, ~imil,r to the one proposed by
Ilcdbci~; (lPJo). ,Vcllt~i'a cuJ,Jpuaitc pu~uaity-dvpm cmvc ~llu'~vnin Fig. 2-i5 lcplcSClitS an equilibrium condition in a continuous column of ordinary mud and shale. This curve is based on Terzaghi's, Athy's, and Hedberg's data. The porosity-depth relationships can be distorted by the occurrence of carbonates and sands in shales and by abnormally
47
ORIGIN OF ABNORMALFORMATIONPRESSURES 1.8
5.4
12.8
01
20.0
27.2
34.6
41.8
49.1
. . . .
"-~~2.0
9
"8 3.0
~
4.0
/
- .
! 5.0 98
196
392
588
784
980
1176
Pressure, N/m 2 Fig. 2-15. Interrelationship among porosity, depth of burial and overburden pressure. N = unit of force (Newton) = 102 g-force = 105 dyn. (Modified after Weller and Vassoevich, in Kartsev et al., 1969; in Rieke and Chilingarian, 1974, fig. 18, p. 43.)
overpressured zones. In addition, application of laboratory soil-compression tests to buried sediments presents some problems. Weller (1959) proposed a compaction process starting with a mud at the surface having a porosity between 85% and 45%. As the overburden pressure increases owing to sedimentation, the interstitial fluids are expelled from the pore space (porosity ranges from 45% to 10%). As a result, there is rearrangement of the mineral grains and development of closer packing. Compaction in this stage is related to yielding of the clay minerals between the more resistant grains. Weller theorized that at about 10% porosity, the non-clay mineral grains are in contact with each other, and the clays are being squeezed into the void space. Further compaction (porosity < 10%) requires deformation and crushing of the grains.
Powers' compaction model Powers (1967) presented a shale fluid-release theory based on changes in clay minerals and bulk properties with depth in argillaceous sediments. His theory assumes that mineralogical transformation of montmorillonite to illite occurs during deep burial, with the consequent release of large volumes of bound water from montmorillonite surfaces to interparticle areas where it becomes interstitial water. In the case of marine montmorillonitic sediments buried to a few hundred feet, a balance is reached between the water retained in the sediment and the water-retaining
48
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
~ MONTMORILLONrrE BEFORE DIAGENE$1S
AFTER DIAGENESIS TO ILLITE
O ~
"r~
0 0
VOLUME
o.
"o d, l r
LOST
AFTER DIAGENESIS 8= COMPACTION
~
UNIT LAYER OF CLAY WATER CLAY PARTICLE (AS
NUMBEREO)
Fig. 2-16. Effect of clay diagenesis on compaction of mudrocks, on assuming that the same number of particles, crystal aggregates, and unit layers of clay occur in each compaction stage shown. (A) No effective porosity or permeability; practically all water is bound water. (B) Most bound water becomes free water; consequently, effective porosity and permeability are greatly increased. (C) Free water squeezed out; effective porosity, permeability, and original volume are greatly reduced. (Modified after Powers, 1967, fig. 1, p. 1242; in Rieke and Chilingarian, 1974, fig. 57, p. 110. Courtesy of Am. Assoc. Pet. Geol.)
properties of montmorillonite (Powers, 1967, p. 1244). Further increase in overburden stress alone, resulting from deeper burial of the mud is ineffective in squeezing the remaining water out of the plastic sediment. At burial depths greater than 1500 to 3000 ft, most of the water exists as water of hydration and is stacked at least four monomolecular layers thick between the unit layers of montmorillonite. Only a small amount of oriented water occurs between the crystals and particles at depths of about 3000 to 6000 ft (Fig. 2-16A). At burial depths below about 6000 ft, montmorillonite is altered to illite and the bound water is desorbed and becomes free pore water (Fig. 2-16B). This causes a decrease in clay-particle size with a corresponding increase in the porosity and permeability at burial depths of 6000 to 9000 ft. Below a depth of
ORIGIN OF A B N O R M A L FORMATION PRESSURES
49
9000 to 10,000 ft, the water released from the clay is compacted until a new balance is established corresponding to the water-retaining properties of the illitic alteration product (Fig. 2-16C). The relationships among water expulsion, type of clay mineral, and depth of burial are illustrated in Fig. 2-17, for both expanding and non-expanding clay deposits (Powers, 1967, p. 1245). The water-escape curves are diagnostic of the porosity, permeability, and bulk density of compacting argillaceous sediments. Powers stated that the compaction history of mudrocks depends largely on their original clay composition and the diagenesis and catagenesis, which they undergo after burial.
Teodorovich and Chernov's compaction model Teodorovich and Chernov (1968) suggested the following stages in the compaction of productive Apsheron horizons in Azerbaijan. (1) The first stage occurs at burial depths of 0 to 8-10 m where there is a rapid compaction. Porosity in clays decreases from 66% to 40%, whereas that of sandstonessiltstones decreases from 56% to 40%. Large amounts of water are squeezed out during this stage (sedimentogenesis and early diagenesis). (2) During the second stage there was a rapid decrease in the compaction rate in the intervals from 8-10 m to 1200-1400 m. During this stage, porosities of the shales and sandstones-siltstones decrease to about 20%. (3) The third stage (burial to a depth of 1400-6000 m) is characterized by slow compaction. The absolute porosity of sandstones-siltstones at a depth of 6000 m decreases to approximately 15-16%, whereas that of shales to 7-8%.
Burst's compaction model Burst (1969) proposed a compaction model based on a three-stage dehydration sequence and the transformation of montmorillonite clay to mixed-layer varieties. A description of this model appears in Chapter 4.
Beall's compaction model A. Beall (personal communication, 1970), proposed a simple model for consolidation of clastic muds, based on the data from offshore well core samples, Louisiana, the JOIDES Deep Sea Drilling Project, and from high-pressure experiments on marine muds. The initial stage of compaction (down to a depth of approximately 3300 ft) primarily involves expulsion of fluids by mechanical processes as in the other proposed theories. Approximately 50% of total consolidation is reached at a very shallow depth. The average calculated pore throat diameters during the first stage are around 6~. During the second stage (at depths of 3300 to approx. 8000 ft) about 75% of total compaction is complete, and pore throat widths in the clays approach 1 *. The fluid pressures remain hydrostatic. During the third-stage of compaction there is an extremely slow decrease of porosity with depth, and pore throat diameters are generally less than
REMARKS
SEVERAL MONOLAYERS OF UYOROGEN BONDED WATER HELD IN INTERLAYER POSITION IN MONTMORlLLONlTE CANNOT BE SQUEEZED W T BY COMPACTION PRESSURES. AS MONTMORlLLONlTE ALTERS TO ILLITE. WATER THAT I S HYDROGEN BONDED BETWEEN UNIT LAYERS IS DESOReEO ANOTRANSFERRED AS FREE WATER TO INTERPARTICLE POSITIONS. OVERBURDEN
MOST HYDROCARBONS FORYEO OR MADE AVAILABLE N THIS ZONE BUT NO
HYDROCARBONS
NO-UONTMORILLONITE LEVEL (USUALLY ABOUT 9,000 TO 10.000 FEET)
1-1 m i
WATER-ESCAPE
CURVE
MONTMORILLONITE
1-1
ILLlTE
m y
ILLITE
MIXED
LAYER
AND KAOLINITE
Fig. 2-17, Compaction history of various clays when deposited in marine environments and its probable relation to release of hydrocarbons from mudrocks. (Modified after Powers, 1967, fig. 3, p. 1245; in Rieke and Chilingarian, 1974, fig. 58, p. 111. Courtesy of Am. Assoc. Pet. Geol.)
ORIGIN OF ABNORMAL FORMATION PRESSURES
51
1 ,~. According to Beall, NaC1 filtration could probably take place during the third stage, resulting in the expulsion of progressively less saline fluids to associated permeable sands, if the latter are present. In Beall's model, overburden pressure between 8000 and 12,500 psi would be required to initiate NaC1 filtration in marine muds. In the absence of permeable sands, the excess fluid pressure may be generated during the third stage. Overton and Zanier's compaction model
Overton and Zanier (1970) proposed a similar model to that of A. Beall with four zones having different water types: (1) depths less than 3000 ft m fresh water; (2) depths of 3000-10,000 ft m depending on the temperature, exponentially increasing salinities; (3) depths greater than 10,000 f t - decreasing salinities to the depth of greatest pressure gradients; (4) depths greater than 15,000 ft ~ increasing salinities with decreasing water fractions; physicochemical changes in shales occur in this indistinct zone. Overton and Zanier (1970) noted that for the Gulf Coast (USA), sands and shales are difficult to distinguish on SP (self-potential electric log) curves at depths less than 3000 ft, due to similarity of the waters in them. Water expelled from this interval is loose (free) water, which constitutes 30% to 70% of the rocks. At a critical compaction depth (depth around and usually less than 3200 ft), shales and sands become readily distinguishable on the SP curve. In zone 2, fresher water is held in the more-ordered or crystalline layer next to the clay, whereas saline water is forced into an equilibrium position in an outer layer (large pores in the shale and in the nearest sand). As the crystallinity of water increases, ions are expelled into a less-ordered or more fluid layer. Below a depth of 10,000 ft, shales remineralize (Overton and Zanier, 1970) and associated sandstones contain fresher waters. The beginning of zone 3 is readily apparent on the SP curve. The water freshening is probably due to the expulsion of (1) the last layers of dense, fresh water from shales into sands, and/or (2) water of hydration resulting from montmorillonite-to-illite alteration. For further details on compaction of argillaceous sediments, see Rieke and Chilingarian (!974).
CREATION A N D M A I N T E N A N C E OF A B N O R M A L P R E S S U R E S
Hanshaw and Bredehoeft (1968, p. 1117) suggested a hydrologic model in which there is a constant flux of water flowing from the compacting sediments. They examined the rate of fluid production as a result of mineral dehydration and conversion from a quantitative viewpoint. The creation of excess pore pressure in the formation and its maintenance with time is a boundary value problem expressed as: OZh' Oz 2
=
Ss Oh' K Ot
(2-45)
52
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
1.0
1.0
0.9 0.8
0.8
0.7
t~ 4::
0.6
0.6
0.5 0.4
0.4
0.3 0.2
0.2
z/i :0.1 01111 10 .3
I 04
I 0 "2
10 I
I
I0
Kt/Ss12
Fig. 2-18. Dimensionless graph of the excess-head pressure distribution for a finite layer with a constant flux at one boundary. Specific storage, Ss = volume of water taken into storage, or discharged per unit volume, per unit change in head. (Modified after Hanshaw and Bredehoeft, 1968, fig. 9, p. 1118; in Rieke and Chilingarian, 1974, fig. 177, p. 331. Courtesy of the Geol. Soc. Am. Bull.)
for the conditions of 0 < z < 1
h'(z, 0) -
0
att - 0
h'(O, t) - 0
att > 0
ah' = 0z z=t
qo K
att > 0
where h' is the excess head, z is the vertical coordinate, S~ is the specific storage, K is the hydraulic conductivity, t is the time, l is the thickness of sediments, and qo is the flow into or out of the confining layer per unit area. The vertical dimension is defined at the source layer as z -- 1 (Hanshaw and Bredehoeft, 1968, p. 1118). The solution to this problem is taken by analogy from conduction of heat in solids (Carslaw and Jaeger, 1959, p. 113) as"
h'K_z qol -- 1
8 L (-1) n 7/-2 (2n + 1----~exp ,,=0
[-(2n+l)27r2Kt] 4S~12
[(2n + 1)7rz] sin
21
(2-46)
Fig. 2-18 is a graphical solution of Eq. 2-46 presented by Hanshaw and Bredehoeft (1968, p. 1118). The finite zone (Fig. 2-18) behaves as an infinite medium until the effect reaches the outer boundary. Hanshaw and Bredehoeft (1968, p. 1118) simplified the problem for time before the change in head reaches the outer boundary by considering the head
53
ORIGIN OF ABNORMAL FORMATION PRESSURES 10
%
O"
10 -1
10-2 10 -1
1
10
100
z/fKt/Ss} 1/2 Fig. 2-19. Dimensionless graph of excess-head pressure distribution in a semi-infinite medium with constant flux at the boundary. (Modified after Hanshaw and Bredehoeft, 1968, fig. 10, p. 1119; in Rieke and Chilingarian, 1974, fig. 178, p. 332. Courtesy of the Geol. Soc. Am. Bull.)
distribution in a semi-infinite medium: 02h '
Ss Oh'
Oz 2
K Ot
(2-47)
where 0 < z _< ec h'(z, 0) - 0 h'(oc, 0) - 0
at t - - 0 att>0
Ohl
qo
Oz z=0
K
att>0
It is necessary to define z = 0 at the boundary of the media, which for the core of a semi-finite m e d i u m is at the source layer. By analogy, the solution is obtained from Carslaw and Jaeger (1959, p. 75):
Ssz~2 exp
-qoz
~
-Ssz2 4Kt
erf
~ 2
- 1
(2-48)
/Kt
A graphical solution to Eq. 2-48 is presented in Fig. 2-19. The head at the surface,
54
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III 10
-1
10
.2
10
.3
o
O" E:
lo-4t 10
l
-7
10 .6
10 .5
10 .4
10 .3
I I i I li:
10 .2
ktlSs 12
Fig. 2-20. Dimensionless graph of excess-head variation for small values of time at a surface of constant flux (z/1 = 1). The solution is the same for either the semi-infinite or finite medium. (Modified after Hanshaw and Bredehoeft, 1968, fig. I1, p. 1119; in Rieke and Chilingarian, 1974, fig. 179, p. 332. Courtesy of the Geol. Soc. Am. Bull.)
z = 0, was given by Carslaw and Jaeger (1959, p. 75) as:
h'K = 2 / K t qo
(2-49)
V Jr S~
For small intervals of time, Eq. 2-49 gives the same results as Eq. 2-45 for the finite layer that is evaluated at the surface of constant flux (z/l = 1) (Hanshaw and Bredehoeft, 1968). Excess head at the surface of constant flux is presented in Fig. 2-20 for very small amounts of time by solving Eq. 2-45. Hanshaw and Bredehoeft (1968, p. 1119) used Figs. 2-19 and 2-20 to compute the pressure, for a source bed at 1200 m depth, overlain and underlain by beds of low hydraulic conductivity. The conductivities of 10 -12 cm/s and 10 -l~ cm/s were both used. They reported that the results obtained are extremely sensitive to hydraulic conductivities and flow rates. Assuming a burial rate of 500 m/106 years, the phase transition period (time during which fluid will be produced) for a 15-m-thick bed is about 30,000 years; upward or downward flow will be 3.85 x 10 -~~ cm/s. At a hydraulic conductivity of 10 -12 cm/s, Hanshaw and Bredehoeft (1968) calculated that it is possible for the fluid pressure to approach the lithostatic load. As the fluid pressure increases, it will also decrease the reaction rate and, therefore, decrease the fluid flux at low values of the hydraulic conductivity. If the hydraulic conductivity is increased to 10 -1~ cm/s, there will be an insufficient quantity of fluid produced to create pressures much in excess of the hydrostatic pressure. The important variables are the burial rate, thickness of the
ORIGIN OF ABNORMAL FORMATION PRESSURES
55
gypsum bed, and hydraulic conductivity of the confining layer. The gypsum-dehydration mechanism in compacting sediments will produce high fluid pressures only if all the above variables are within certain definable limits. This is also true for the montmorillonite-dehydration model: Hanshaw and Bredehoeft (1968, p. 1117) assumed that if each cubic centimeter of sediment contains 2 g of montmorillonite, then dehydration of montmorillonite will produce 0.33 g/cm 3 of H20. Enthalpy data from Sudo et al. (1967) indicate that 178 cal/cm 3 is required to release the interlayer water. Employing the following assumed values of 10 -6 cal cm -2 s -1 for a heat flow rate and 1.6 x 10 -9 cm/s as a burial rate, 6.3 x 101~ s would be required to increase the depth by 1 cm. In that time, 630 cal/cm 2 would be available from the usual flow of heat found in the Earth. There would be more than enough heat available for the dehydration reaction to proceed (Hanshaw and Bredehoeft, 1968). Interlayer water would be released at the rate of 5.1 x 10 -1~ cm/s. In the phase transition of gypsum, the reaction went from a solid to a solid plus water; however, in the dehydration of montmorillonite the dense water expands. Not all of the water is moved from the reaction site. If one assumes that all interlayer water has a density of 1.4 g/cm 3 (Martin, 1962), expansion, upon release to water having a normal density of 1 g/cm 3, will result in an increase in specific volume (reciprocal of density) of 28.5%. Hanshaw and Bredehoeft (1968, p. 1117) calculated that the total flow (qo) upward or downward will be equal to 0.285 x 0.5 x 5.1 x 10 -1~ or 7.3 x 10 -11 cm/s. In this case, a conductivity of 10 -12 cm/s and about 106 years would be required to approach lithostatic pressure on the fluid. In an actively subsiding basin such as the Gulf Coast Basin, this mechanism could provide a significant increase in pore pressure if the amount of montmorillonite is high and the permeability is low.
MECHANISMS GENERATING ABNORMAL FORMATION PRESSURES
The mechanisms responsible for generating abnormal pressures can be classified into three categories (see Tables 2-1 and 2-2), as indicated previously. (1) Changes in rock pore volume: (a) vertical loading (undercompaction); (b) lateral tectonic loading; (c) secondary cementation. (2) Changes in the volume of interstitial fluids: (a) temperature change; (b) mineral transformations; (c) hydrocarbon generation; (d) thermogenic decomposition of hydrocarbons; (e) migration of fluids (mainly gas). (3) Changes in fluid pressure (hydraulic head) and movement of fluids: (a) osmosis; (b) fluid pressure head; (c) oilfield operations; (d) permafrost environment; (e) differences in specific weights (e.g., between gas and oil).
Undercompaction Undercompaction of sediments can occur during rapid sedimentation and burial of sediments containing a large quantity of clay minerals (Rubey and Hubbert, 1959; Wilson et al., 1977). Thus, the complete expulsion of water from the sediments does not occur, and sediments are left as a loosely bound system of swollen clay particles with
56
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
interlayered water. According to Harkins and Baugher (1969), in order for abnormal pressures to develop, the shales must be over 200 ft in thickness. Continued sedimentary deposition can result in a shear zone developed by overloading the undercompacted shale. Expulsion of water from these sediments is accompanied by the subsidence of blocks of sediments. Many contemporaneous faults found in the Gulf Coast Basin (USA) exhibit the following cycles: (1) deposition, (2) expulsion of water, (3) subsidence of blocks of sediments, and (4) temperature increase. (Also see Chapter 1.) Tectonics
Tectonic activity may be the cause of AHFPs, including local and regional faulting, folding, lateral sliding and slipping, squeezing resulting from down-dropping of fault blocks, diapiric salt/shale movements, and earthquakes. In their classical book, Poston and Berg (1997) stated that some of the earliest recorded AHFPs were reported from areas where recent tectonic activity caused the principal normal stress to be horizontal. Transfer of tectonic stress to the fluids can result in overpressures, as exemplified by the Ventura oilfield of California (USA). Fig. 2-21 illustrates the effect of tectonic activity on oilfield pressures. Other pertinent references appear in Chapter 8.
%
%
",,
Khaur
o o o \ Ventura \
Q.
"-'~\
s
,
\
o~k, Chia-Surkh 'O~, . ,, e -, ~ ~ - Qum
10
\
G~
"G, \
12 0
2
4
6
8
10
12
Pressure, 1,000 psig Fig. 2-21. Overpressures recorded in wells drilled in or near active tectonic belts of compressional loading and faulting. (Modified after Hubbert and Rubey, 1959, p. 115.)
ORIGIN OF ABNORMAL FORMATION PRESSURES
57
Growth faults According to Dickey et al. (1968), high-pressure zones in the Louisiana and Texas Gulf Coast region of the United States are related to the particular patterns of block faulting accompanied by contemporaneous sedimentation and compaction. This creates lateral seals that, together with a layer of thick shale overlying the surpressure zones, prevent the loss of pore fluids from the sediments during compaction and diagenesis. Resistance to the flow of water through the clay is a function of decreasing porosity and permeability of the clays as compaction progresses. The hydraulic permeability of clay is negligible in the geopressured environments. The clay beds have overlain abnormally pressured formations for millions of years without the release of the pressure by fluid flow across the clay/shale beds. When clays are compacted, a stage is reached where the porosity and permeability are so low that the flow of water is completely restricted. According to Dickey et al. (1968) the growth faults of the Gulf Coast exhibit the characteristics of slump-type landslides, which in many cases may be due to old slides that were later buried by sedimentation. The stratigraphic units are thicker on the downthrown side of the growth faults than they are on the upthrown side, because during sedimentation there was continuous movement along the fault planes. As compaction of sediments progresses, the vertical permeability of argillaceous sediments decreases rapidly. As burial continues, the pore pressure is increased by the mass of the additional overburden of sediments and temperature increase. In general, abnormally high pressures are found at depths of 10,000 to 11,000 ft. Abnormally high formation pressures are encountered in the Niger Delta area in Nigeria, Africa, where the subsurface structure of the delta is characterized by growth faults with associated rollover structures, which are caused by gravity (Hospers, 1971). (Also see Chapter 1 on Growth Faults.)
Transference Redistribution of excess pore pressure in the subsurface is referred to as transference (Swarbrick and Osborne, 1998). It is not a primary mechanism in itself for creating overpressures, but transference may exert a strong influence on many of the pore pressure profiles seen in the subsurface, and may mask recognition of the underlying causal mechanism.
Effect of temperature increase on formation pressure (aquathermal pressuring) Jones (1969, p. 804) pointed out that abrupt changes in temperatures over short depth ranges are hydrologically critical to the geopressured regime, because the movement of water is the most important factor in sustaining terrestrial heat flow in the sedimentary basins. Conventional maps of geothermal conditions, however, tend to obscure, rather than to identify, abrupt changes in temperature. An increase in the geothermal temperature, as the compacting sediments are subsiding in the basin, causes the pore fluids (gas, oil and water) to expand more than the enclosing rocks. Such an expansion would create abnormal fluid pressures in the rocks. There are three modes of heat transport through fluid-saturated sediments: (1) convective flow of interstitial fluids,
58
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
(2) conduction through mineral grains and interstitial fluids, and (3) radiation. Jones (1969, p. 807) listed several factors that have a direct beating on the heat flux in sediments: (1) thermal conductivity and composition of (a) the mineral grains that form the rock matrix and (b) interstitial fluids; (2) specific heat of the pore fluids and solids; (3) porosity and pore distribution in the shales and sands; (4) density, viscosity and thermal expansion of the pore fluids; (5) thermal expansion of solids; (6) absolute temperature. Lewis and Rose (1970) and Jones (1969) observed that in the Gulf Coast region the overpressured zones have abnormal temperature gradients. Jones (1969, p. 804) found no relationship between the average geothermal gradient and pressure/depth ratio (geostatic ratio) in the Gulf Coast Tertiary sediments after studying 175 south Louisiana overpressured reservoirs above a depth of l 1,000 ft. Nevertheless, the occurrence of abnormal pressures is commonly associated with a sharp increase in the geothermal gradient in the sealing clay member of the reservoir (C.E. Hottman, personal communication, 1966; in Jones, 1969, p. 804). According to Lewis and Rose (1970), the abnormally pressured shale zones constitute thermal barriers, because they are undercompacted and have high porosity compared to the adjoining sediments. Reduction in the upward flow of water in these zones greatly reduces the rate of upward flow of heat and, consequently, the overpressured zones become heat storage areas. In addition, the insulating effect of water is three times greater than that of the shale matrix. The larger the amounts of fluid stored in the overpressured shales, the greater is the insulating value of the zone. Whenever there is an insulating layer in the Earth's crust there can be a buildup of heat beneath this layer. Thus, the geothermal gradient is steepest in the portion of the beds above a permeable reservoir. Jones (1969, p. 805) reported gradients as high as 6~ ft in such settings. The steepness of the geothermal gradient varies inversely with the thickness of unconsolidated sediments in the structural basins (Jones, 1969, p. 807). Geothermal gradients are large in the undercompacted shales overlying the reservoir sands and are very much reduced in the aquifers. The thermal conductivity of sediments varies inversely with the geothermal gradient, if the geothermal flux is uniform over broad areas. Langseth (1965) stated that the thermal conductivity of clay varies inversely with its water content, and Zierfuss and van der Vliet (1956) discovered that the thermal conductivity of sand increases with porosity owing to the occurrence of convective heat transport in the wider pores. As pointed out by Bogomolov (1967), water plays a major role in the redistribution and subtraction of heat in the geothermal field of the Earth's sediments. Jones (1969) stated that convective and conductive heat flow is important in the low-temperature range above depths of 10,000 ft in the northern Gulf of Mexico Basin. Water temperatures in this area are greater than 250~ at depths ranging from 10,000 to 14,000 ft (Jones, 1969). Lewis and Rose (1970) showed a range in average geothermal gradients from 1.6~ to 2.2~ ft for the Texas Gulf Coast.
ORIGIN OF ABNORMAL FORMATION PRESSURES
59
Perhaps the most obvious feature of the geothermal-gradient maps of the northern Gulf Coast Basin is its conformity with the structural map. Elongate areas, beneath which the geothermal gradient is lowest, overlie the axis of the depositional basin (Gulf Coast geosyncline). Sediments which overlie the deepest portion of the Gulf Coast geosyncline would appear, then, to possess the highest thermal conductivity. Jones (1969, p. 807) stated that if they do not, then they must form a thermal sink and are now storing heat energy received from below; their temperature must inevitably rise. The endothermic diagenetic processes occurring in these argillaceous sediments, such as the dehydration of montmorillonite, require the addition of heat and, thus, reduce the amount of heat flux to the overlying sediments. Jones (1969, p. 808) concluded that, by checking the upward flow of water from the saturated sediments beneath the shales, the sealing clay beds have caused a reduction of the geothermal flux above and overheating of the undercompacted sediments below. When the interstitial fluids cannot escape the sediment, subsurface temperature changes can result in changes in pore pressure, especially if gas is present in the interstitial fluid. As sediments and pore fluids are buried deeper during sedimentation, the temperature rises and if the fluid cannot escape, the fluid density would decrease and volume will increase. If the fluid cannot escape, the effective pressure (grain-to-grain stress) decreases and the pore pressure increases; thus, the interstitial fluids support more of the overburden pressure (see Poston and Berg, 1997, pp. 13-16). Calculation of pressure abnormality due to changes in temperature is presented in Chapter 5.
Decomposition of organic matter Organic matter (or kerogen), which constitutes a substantial part of freshly deposited muds, converts to liquid and gaseous hydrocarbons during diagenesis and catagenesis. The resulting fluids released during these transformations can create, or accentuate, the overpressured, undercompacted, state of the compacting clay sediments: (a) by increasing the pore pressure; and (b) by further impeding the expulsion of interstitial pore water through the development of a second gas-fluid phase. Methane bubbles dispersed in water reduce the permeability of the rock to either phase (Chilingarian et al., 1995).
Gas migration As mentioned in Chapter 1, one mechanism which is responsible for the formation of abnormal pressures and yet not fully recognized is the migration of hydrocarbons (mostly gas) from the lower to upper horizons along faults. One such example is presented here. Larichev and Timurziev (1987) studied petroleum geology of pre-Jurassic formations in the Mangyshlyak Peninsula on the eastern shore of the Caspian Sea in relation to the neotectonic movements (Fig. 2-22). One of the tectonic characteristics that they investigated was the gradient of the amplitudes of recent vertical movement defined as the amplitude per unit horizontal distance. First, the map of recent vertical
60
G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III
Gradient of movement amplitude, m/km I
...: 9 ..:.~
"".'"':7 9.'..I~-
0
9
9
4
8
12
is
20-a2
~
..~ o'.. 9' , ; .'..... o. 9 .';.o
<~..
~
9'.'].-.;..:?;-
,6[
.
}.~
-,..~
.
12 8
'-
0
114
9
0 0.9
~ (--,.-
1.0
1.1
1.2
1.3
9
1.4
Formation pressure Hydrostatic pressure Fig. 2-22. Correlation between the gradient (m/kin) of Recent vertical tectonic movements and pressure abnormality; pre-Jurassic formations in the Mangyshlyak Peninsula, west coast of the Caspian Sea, Kazakhstan. (Modified after Larichev and Timurziev, 1987; in Gurevich and Chilingarian, 1997, fig. 7, p. 328.)
movements was developed. Then differences in amplitudes per unit horizontal distance was calculated and a map of these gradients was developed (Fig. 2-22). This gradient is a measure of recent tectonic movements that are indicative of the tectonic stress and, thus of the fracturing induced by this stress. Larichev and Timurziev showed that pressure abnormality (the ratio of formation pressure to hydrostatic pressure, p/ph) correlated well with this gradient and with the set of processes caused by, and associated with, neotectonic activity (Fig. 2-22). (Also see Gurevich and Chilingarian, 1997.) Pressure abnormalities in these formations were definitely caused by vertical migration of hydrocarbon fluids, mostly gas, and fresher water from underlying formations. This is evidenced by the correlations between (1) the thickness of gas-saturated rocks and distance from recent faults, and (2) water salinity and pressure abnormality (Fig. 2-23). Moreover, oil and gas were encountered only within extension zones
61
ORIGIN OF ABNORMAL FORMATIONPRESSURES
~
15
QC
,Xx\o xxx\
\
\
\~, ,x~l!x,\ x x~xx
-
[ if)
w Z
xx~O
s
o 3
I
9 x
x
x..x X-~X ~ X x x -'~.._ X
xx - " " ' ~x__
-r
~
0
!
I
i
I
t
I
0.5
1.0
1.5
2.0
2.5
3.0
DISTANCE FROM FAULT, KM I00 j
80
B
(..9
e 13
~2
~ .60
2o ,,
_.1
4O
17'
W
I-. ~
14
0 22
20 012
0.9
i
I
0.9'5
1.0
! i.05
O9
I I.i
! 1.15
I 1.2
_FORmAl" tON PRESSURE HYDROSTATIC PRE SSURE Fig. 2-23. Correlations between the thickness of gas-filled rocks and distance from the fault (A), and between the pressure abnormality and water salinity (B) for pre-Jurassic formations of the North Rakushechnoye field, Mangyshlyak Peninsula, west coast of the Caspian Sea, Kazakhstan. (Modified after Larichev and Timurziev, 1987; in Gurevich and Chilingarian, 1997, fig. 8, p. 328.)
(Fig. 2-24). Thus, fluids were collected at the roots of the fault and transferred (injected) upward through the fault into formations within the fractured zone. The pressure distribution, therefore, is controlled by these injection scenarios. To predict a pressure abnormality of this type, approaches that are different from the current ones should be used. A combination of various geophysical methods with geologic studies can be recommended for a case like this.
L
Fig. 2-24. Zones of tectonic extension and oil and gas occurrence, Oymasha oil field, Mangyshlyak Peninsula, west coast of the Caspian Sea, Kazakhstan. I = isolines of the relief of the top of 'A' bed, mid-Triassic; 2 = lines of equal water salinity, g/l; 3 = isolines of pore-pressure/hydrostatic-pressureratios; 4 = Recent extension zones; 5 = faults according to seismic data; 6 = wells (a = economic, b = uneconomic, c = no hydrocarbons). (Modified after Larichev and Timurziev, 1987; in Gurevich and Chilingarian, 1997, fig. 9, p. 329.)
O
m 7:
rn
63
ORIGIN OF ABNORMAL FORMATION PRESSURES
Osmosis Glasstone (1946) described osmosis as a spontaneous flow of water from a m o r e dilute to a m o r e concentrated solution, w h e n the two are separated from each other by a suitable m e m b r a n e (see Fig. 1-6). A c c o r d i n g to Jones (1969), the pressure difference across a clay bed could e x c e e d 3500 psi (246 k g / c m 2 ) . Thus, stepwise increments of osmotic pressure through a series of i n t e r b e d d e d sands and clays could (as a multistage p u m p ) produce A H F P s . S o m e experts, e.g., Poston and Berg (1997) and Swarbrick and O s b o r n e (1998), however, believe that the osmotic p h e n o m e n o n would not greatly contribute to higher levels of overpressures. Thus, further research work (both field and laboratory) is necessary to reach definite conclusions.
Density contrast Differences b e t w e e n the density of h y d r o c a r b o n s (oil a n d / o r gas) and that of water in a reservoir can create an overpressure (Fig. 2-25). Obviously in the case of gas, the overpressure will be m o r e pronounced.
Po,: P.i + (15--l$o)(Zl-z')
zl
9,
Z2
,:.:,!i:
,,
i,71-w-~iE~-kll,$ Fig. 2-25. Cross-sectional view of an anticlinal reservoir sandwiched between two impervious shale bodies, showing abnormal pressures in hydrocarbon accumulation in hydrostatic water environment. Yo = specific weight of oil (e.g., in lb/ft3); Yw - specific weight of water (e.g., in lb/ft3); z = elevation (e.g., in ft); p = pressure (e.g., in lb/ft2); overpressure (Ap = (Pol - Pwl) = (Yw - Vo)(Z2 - zl)] in lb/ft 2. (Modified after Hubbert and Rubey, 1959, p. 150; and Gretener, 1969, p. 267; in Rieke and Chilingarian, 1974, fig. 264, p. 310.)
64
G.V. CHILINGAR,J.O. ROBERTSONJR. AND H.H. RIEKEIII
CONCLUSIONS
Abnormal subsurface formation pressures are encountered throughout the world and are produced by a variety of different mechanisms, which may be physical, chemical, or a combination of the two. In many cases, the pressure increase is due to the inability of water to escape from the compacting sediment. Thus, the interstitial water must carry an additional load. There are disagreements among investigators regarding some of the mechanisms that could explain the origin of abnormal pressures. Recent developments in drilling, seismics and well-logging are helping to resolve many of the disputed mechanisms.
BIBLIOGRAPHY Allen, D.R. and Chilingarian, G.V., 1975. Mechanics of sand compaction. In: G.V. Chilingarian and K.H. Wolf (Eds.), Compaction of Coarse-Grained Sediments, I. Elsevier, Amsterdam, pp. 43-77. Anderson, R.V.V., 1927. Tertiary stratigraphy and orogeny of the northern Punjab. Geol. Soc. Am. Bull., 38: 665-720. Athy, L.F., 1930a. Density, porosity and compaction of sedimentary rocks. Bull. Am. Assoc. Pet. Geol., 14(1): 1-24. Athy, L.F., 1930b. Compaction and oil migration. Bull. Am. Assoc. Pet. Geol., 14(1): 25-35. Avchyan, G.M. and Ozerskaya, M.L., 1968. Regularity in consolidation of sedimentary rocks with depth. Izv. Akad. Nauk. Ser. Geol., 2 : 1 3 7 - !41. Bebout, D.G., 1976. Subsurface techniques for locating and evaluating geopressured-geothermal reservoirs along the Texas Gulf Coast. Proc. 2nd Geopressured/Geothermal Energy Conf, The University of Texas, Austin, Feb. 23-25, II, pp. I-16. Berner, R.A., 1980. Early Diagenesis: A Theoretical Approach. Princeton University Press, Princeton, NJ, 241 pp. Bogomolov, Y.G., 1967. Geotemperature regime. Bull. Int. Assoc. Sci. Hydrol., 4: 86-91. Brandt, H., 1955. A study of the speed of sound in porous granular media. Trans. Am. Soc. Mech. Engr., 77: 479-485. Brown, K.E., 1967. Gas Lift Theory and Practice. The Petroleum Publishing Co., Tulsa, OK, 924 pp. Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Am. Assoc. Pet. Geol., Bull., 53(1): 73-93. Carslaw, H.S. and Jaeger, J.C., 1959. Conduction of Heat in Solids, 2nd ed. Oxford Univ. Press, London, 510 pp. Chilingarian, G.V., Donaldson, E.C. and Yen, T.E, 1995. Subsidence Due to Fluid Withdrawal. Developments in Petroleum Science 41, Elsevier, Amsterdam, 498 pp. Clark Jr., S.E, 1961. A redetermination of equilibrium relations between kyanite and sillimanite. Am. J. Sci., 259:641-650. Dickey, P.A., Shiram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160:609-615. Dickinson, G., 1953. Reservoir pressures in Gulf Coast, Louisiana. Am. Assoc. Pet. Geol., Bull., 37: 410432. Donaldson, E.C., 1980. Underground disposal of brines from geopressured reservoirs. Proc. 73rd Annu. Meet., Am. Inst. Chem. Eng., Washington, DC, Nov., 30 pp. Dunoyer de Segonzac, G., 1964. Les argiles du Cr6tac6 Sup6rieur dans de bassin de Douala (Cameroun): Problbmes de diagenbse. Bull. Serv. Carte Geol. Alsace-Lorraine, 17(4): 287-310. Evans, D.M., 1966. The Denver area earthquakes and the Rocky Mountain Arsenal disposal well. Mt. Geol., 3(1): 23-36. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp.
ORIGIN OF ABNORMALFORMATIONPRESSURES
65
Foster, J.B. and Whalen, H.E., 1966. Estimation of formation pressures from electrical surveys, offshore Louisiana. J. Pet. Technol., 18(2): 165-171. Frederick, W.S., 1967. Planning a must in abnormally pressured areas. World Oil, 164(3): 74-77. Frick, T.C., 1962. Petroleum Production Handbook, Volume 2. Society of Petroleum Engineers of AIME, Dallas, TX, 1000 pp. Fuchtbauer, H. and Goldschmidt, H., 1963. Beobachtungen zur tonmineral diagenese. Proc. 1st Int. Congr. Clays, Stockholm, pp. 99-111. Gilreath, J.A., 1968. Electric-log characteristics of diapiric shale. Am. Assoc. Pet. Geol. Mem., 8: 137-144. Glasstone, S., 1946. Textbook of Physical Chemistry. Van Nostrand Co., New York, NY, 1320 pp. Gretener, EE., 1969. Fluid pressure in porous media - - its importance in geology, A review. Bull. Can. Pet. Geol., 17(3): 245-255. Gurevich, A.E. and Chilingarian, G.V., 1997. Notes on the origin of formation fluid pressure: well-logging methods aspect. J. Pet. Sci. Eng., 17: 321-330. Ham, H.H., 1966. New charts help estimate formation pressures. Oil Gas J., 64(51): 58-63. Hamilton, E.L., 1959. Thickness and consolidation of deep-sea sediments. Geol. Soc. Am. Bull., 70: 13991424. Hanshaw, B.B. and Bredehoeft, J.D., 1968. On the maintenance of anomalous fluid pressures, II. Source layer at depth. Geol. Soc. Am. Bull., 79:1107-1122. Hanshaw, B.B. and Zen, E., 1965. Osmotic equilibrium and overthrust faulting. Geol. Soc. Am. Bull., 76: 1379-1386. Harkins, K.L. and Baugher III, J.W., 1969. Geological significance of abnormal formation pressures. J. Pet. Technol., 21(8): 961-966. Harrison, E., Kieschnick Jr., W.J. and McGuire, W.J., 1954. The mechanics of fracture induction and extension. Trans. Am. Inst. Min. Metall. Eng., 201: 254-255. Hedberg, H.D., 1936. Gravitational compaction of clays and shales. Am. J. Sci. (5th Sen), 31(184): 241-287. Hosoi, H., 1963a. First migration of petroleum in Akita and Yamagata Prefectures, 1. Jpn. Assoc. Mineral., Petrol., Econ. Geol. J., 49(2): 43-55. Hosoi, H., 1963b. First migration of petroleum in Akita and Yamagata Prefectures, 2. Jpn. Assoc. Mineral., Petrol., Econ. Geol. J., 49(3): 101-114. Hospers, J., 1971. The geology of the Niger delta area. Inst. Geol. Sci., London, Rep., 70: 121-142. Hottman, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., 16(6): 717-722. Hubbert, M.K. and Rubey, W.W., 1959. Role of fluid pressure in mechanics of overthrust faulting. I. Mechanics of fluid-filled porous solids and its applications to overthrust faulting. Geol. Soc. Am. Bull., 70(2): 167-206. Hubbert, M.K. and Rubey, W.W., 1960. Role of fluid pressure in mechanics of overthrust faulting, a reply to discussion by H.E Laubscher. Geol. Soc. Am. Bull., 71: 617-628. Johnson, H.A. and Bredeson, D.H., 1971. Structural development of some shallow salt domes in Louisiana Miocene productive belt. Am. Assoc. Pet. Geol., Bull., 55(2): 204-226. Jones, EH., 1969. Hydrodynamics of geopressure in the northern Gulf of Mexico basin. J. Pet. Technol., 21(7): 803-810. Jones, EH., 1975. Geothermal and hydrocarbon regimes, Northern Gulf of Mexico Basin. In: Proc. 1st Geopressured/Geothermal Energy Conf., University of Texas, Austin, Feb. 23-25, V (Part 3), pp. 15-39. Kartsev, A.A., Vagin, S.B. and Baskov, E.A., 1969. Paleohydrogeology. Nedra, Moscow, 150 pp. Keep, C.E. and Ward, H.L., 1934. Drilling against high rock pressures with particular reference to operation conducted in the Khaur field, Punjab. J. Inst. Pet. Technol., 20: 990-1013. Kharaka, Y.K., Callender, E. and Carothers, W.W., 1977. Geochemistry of waters in the geopressured zone from coastal Louisiana: Implications for the geothermal development. In: 3rd Geopressured/Geothermal Energy Conf., University of Southwestern Louisiana, Lafayette, LA, Nov. 16-18, 1, pp. GI-121-GI-165. Khilyuk, L.E, Chilingar, G.V., Robertson, J.O. Jr. and Endres, B., 2000. Gas Migration~Events Preceding Earthquakes. Gulf Publ. Co., Houston, TX, 389 pp. Kreitler, C.W. and Gustavson, T.C., 1976. Geothermal resources of the Texas Gulf Coast: Environmental concerns arising from the production and disposal of geothermal waters. In: Proc. 2nd Geopressured/Geothermal Energy Conf., University of Texas, Feb. 23-25, v. V (Part 3), pp. 1-14.
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Langseth, M.G., 1965. Techniques of measuring heat flow through the ocean floor. Geophys. Monogr., 8: 58-77. Larichev, V.I. and Timurziev, A.J., 1987. Pre-Jurassic complex of Mangyshlyak. In: A.E. Gurevich et al. (Eds.), Formation Fluid Pressure. Nedra, Leningrad, pp. 64-71. Laubscher, H.E, 1960. Role of fluid pressure in mechanics of overthrust faulting: discussion. Geol. Soc. Am. Bull., 71: 611-616. Levorsen, A.T., 1958. Geology of Petroleum. Freeman, San Francisco, CA, 703 pp. Lewis, C.R. and Rose, S.C., 1970. A theory relating high temperatures and overpressures. J. Pet. Technol., 22(1): 11-16. Lo, K.Y., 1969. The pore pressure-strain relationship of normally consolidated undisturbed clays, I. Theoretical considerations. Can. Geotech. J., 6(4): 383-394. Lomba, R.ET., Chenevert, M.E. and Sharma, M.M., 2000. The role of osmotic effects in fluid flow through shales. J. Pet. Sci. Eng., 25(1-2): 25-35. Louden, L.R., 1972. Origin and maintenance of abnormal pressures. In: 3rd Symp. on Abnormal Subsurface Pore Pressure, SPE 3843. Louisiana State University, Baton Rouge, LA, May. Magara, K., 1968. Compaction and migration of fluids in Miocene mudstone, Nagaoka Plain, Japan. Bull. Am. Assoc. Pet. Geol., 52(12): 2466-2501. Martin, R.T., 1962. Adsorbed water on clay: A review. Proc. Natl. Conf. Clays and Clay Minerals, 9 (1960): 28-70. McCulloh, T.H., 1965. A confirmation by gravity measurements of an underground density profile based on core densities. Geophysics, 30(6): 1108-1132. McKelvey, J.G. and Milne, I.H., 1962. Flow of salt solutions through compacted clay. Clays Clay Miner., 9: 248-259. Meade, R.H., 1966. Factors influencing the early stages of compaction of clays and sands review. J. Sediment. Petrol., 36:1085-1101. Murray, G.E., 1961. Geology of the Atlantic and Gulf Coastal Province of North America. Harper Brothers, New York, NY, 692 pp. Overton, H.L. and Zanier, A.M., 1970. Hydratable shales and the salinity high enigma. Soc. Pet. Eng., Am. Inst. Min. Metall. Eng. 45th Annu. Fall Meet., Houston, TX, Pap. 2989, 9 pp. Ozerskaya, M.L., 1965. Influence of structural factors on density and elastic properties of sedimentary rocks. Izv. Akad. Nauk. S.S.S.R., Ser. Phys. Earth, 1: 103-108. Perry, E. and Hower, J., 1970. Burial diagenesis in Gulf Coast pelitic sediments. Clays Clay Miner., 18: 165-177. Poston, S.W. and Berg, R.R., 1997. Overpressured Gas Reservoirs. SPE, Richardson, TX, 138 pp. Powers, M.C., 1959. Adjustments of clay to chemical change and the concept of the equivalent level. Clays Clay Miner., 2: 309-326. Powers, M.C., 1967. Fluid release mechanisms in compacting marine mudrocks and their importance in oil exploration. Bull. Am. Assoc. Pet. Geol., 51: 1240-1254. Proshlyakov, B.K., 1960. Reservoir properties of rocks as a function of their depth and lithology. Geol. Nefti Gaza, 12: 24-29. Ramsay, J.G., 1967. Folding and Fracturing of Rocks. McGraw-Hill, New York, NY, 568 pp. Rieke, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Elsevier, New York, NY, 424 pp. Rieke, H.H. III, 1972. Mineralogy of montmorillonite under elevated temperature and pressure. In: 3rd Symp. Abnormal Subsurface Pore Pressure. Soc. Pet. Eng. Meet., Louisiana State University, Baton Rouge, LA, pp. 89-109. Rogers, G.L., 1964. Mechanics of Solids. Wiley, New York, NY, 250 pp. Rubey, W.W. and Hubbert, M.K., 1959. Role of fluid pressure in mechanics of overthrust faulting, II. Overthrust belt in geosynclinal area of western Wyoming in light of fluid-pressure hypothesis. Geol. Soc. Am. Bull., 70(2): 167-206. Sudo, T., Shimoda, S., Nishigaki, S. and Aoki, M., 1967. Energy changes in dehydration processes of clay minerals. Clay Miner. Bull., 7: 33-42. Swarbrick, E. and Osborne, M.J., 1998. Mechanisms that generate abnormal pressures: an overview. Am. Assoc. Pet. Geol. Mem., 70: 13-34.
ORIGIN OF ABNORMALFORMATIONPRESSURES
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Taylor, D.W., 1948. Fundamentals of Soil Mechanics. Wiley, New York, NY, 700 pp. Teodorovich, G.I. and Chernov, A.A., 1968. Character of changes with depth in productive deposits of Apsheron oil-gas-bearing region. Sov. Geol., 4: 83-93. Terzaghi, K., 1926. Simplified soil tests for subgrades and their physical significance. Public Roads, 7: 153-162. Terzaghi, K. and Peck, R.B., 1948. Soil Mechanics in Engineering Practice. Wiley, New York, NY, 566 pp. Van Moort, J.C., 1971. A comparative study of the diagenetic alteration of clay minerals in Mesozoic shales from Papua, New Guinea, and in Tertiary shales from Louisiana, USA. Clays Clay Miner., 19(1): 1-20. Warner, D.L., 1964. An Analysis of the Influence of Physical-Chemical Factors Upon the Consolidation of Fine-Grained Elastic Sediments. Thesis, Univ. California, Berkeley, CA, 136 pp. Watts, E.V., 1948. Some aspects of high pressures in the D-7 zone of the Ventura Avenue field. Am. Inst. Min. Metall. Eng., 174: 191-200. Weaver, C.E., 1961. Clay mineralogy of the late Cretaceous rocks of the Washakie Basin. Wyoming Geol. Assoc. Guideb., 16th Field Conf., pp. 148-154. Weller, EA., 1959. Compaction of sediments. Am. Assoc. Pet. Geol., Bull., 43: 273-310. Wilson, J.S., Hamilton, J.R., Manning, J.A. and Muehlberg, EE., 1977. Environmental Assessment of Geopressured Waters and Their Projected Use. EPA-600/7-77-039, National Technical Information Service, Springfield, VA, 85 pp. Young, A. and Low, EF., 1965. Osmosis in argillaceous rocks. Am. Assoc. Pet. Geol., Bull., 47(7): 10041008. Zierfuss, H. and van der Vliet, G., 1956. Laboratory measurements of heat conductivity of sedimentary rocks. Bull. Am. Assoc. Pet. Geol., 10: 2475-2488.
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Chapter 3
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON and E AMINZADEH
INTRODUCTION
Although the study of formation pressures has a history of more than 50 years, still not all aspects and phenomena are investigated thoroughly enough and taken into account while studying many oilfields. For example, pressure increase caused by vertical gas migration and liquid-gas redistribution may be a major factor during periods of intense gas generation and migration. Compaction of clays depends not only on the overburden or/and geodynamic loading but also on reduction in strength and on temperature change. A better understanding of natural phenomena allows extending the scope of pressure prediction methods. It is useful to emphasize that almost all mechanisms that produce pressure deviation from the hydrostatic one were well known some 50 and more years ago in physics, soil mechanics, geochemistry, etc. Regretfully, the knowledge that lies beyond the immediate scope of traditional petroleum geology, has not been used fully enough. Pressure distribution and abnormality are caused by both gravitationally non-equilibrium distribution of fluid density (free convection) and changes in fluid compression (forced convection), that are generated and influenced by different factors. Therefore, to achieve better correlation, pressure may be divided, with a reasonable accuracy, into the free convection and forced convection components and each component may be separately correlated with corresponding factors. Sets of characteristics, separately presenting ability of fluid-filled rock to change pressure under external influence, the external influence itself, and permeability, should be used for correlation. In general, reliability of pressure prediction methods, including geophysical methods, is still not high. In subduction and orogeny regions (Kucheruk and Lustig, 1986) or where vertical fluid migration is intensive, an error in pressure determination may be high. For example, in Azerbaijan, where vertical migration of fluids is very active and pressure distribution differs from that which would be produced by compaction processes only, well-log methods do not guarantee reliable results (Melik-Pashaev et al., 1983). Carstens (1980) showed, using empirical data, that high shale porosity does not necessarily coincide with pressure abnormality. Carstens and Dypvik (1981) indicated that clays in the abnormal pressure zone of geological section (about 13,000 ft and deeper) in the Viking graben (North Sea) are well consolidated, although pore pressures reach 0.8 of the overburden. Carstens (1980) emphasized that under such circumstances usual abnormality indicators (higher sonic transit time, lower electric resistivity, low mechanical strength of formations and the d-exponent factor) may be misleading and
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A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
cannot be used for pressure detection. Therefore, new approaches, that can form a basis for new and more reliable methods for different geological environments are necessary. They can only be developed by more thorough and detailed in-depth analysis of causal relations between pressure distribution and the complete set of geological, physical, and physicochemical factors. Such an analysis can lead to new mathematical and other formal methods for establishing quantitative relations between parameters of pressure distribution and geological environment. A new approach to the empirical study of non-hydrostatic pressure and pressure-changing mechanisms in fields and regions was suggested by Gurevich et al. (1987). The essence of this approach is in dividing the pressure value into the free convection and forced convection components and correlating these components separately with those geologic parameters and factors that cause each component. Such statistical analysis of the already existing field data will provide better basis for predrilling pressure prediction. At the same time it will be helpful to classify the geologic patterns of regions and formations to develop separate techniques for determination of pressure from combinations of drilling and geophysical data. The additive pressure components and geologic and physical characteristics and parameters that correspond to them separately can make a reliable basis for pressure prediction and detection expert systems, a powerful tool in the oil and gas exploration (Aminzadeh, 1991). This approach of pressure subdivision into two physically different components was radically new but the work was discontinued and the writers had no possibility to apply this approach. The authors of this chapter continue this line of research. The purpose of this chapter is to summarize concisely current understanding of pressure distribution origin, to indicate areas that have not been fully studied and that have, therefore, a potential for new practical development, and to outline a possible new approach to the solution of the abnormal and subnormal pressure problem.
FACTORS C A U S I N G F L U I D F L O W A N D P R E S S U R E D I S T R I B U T I O N S
Flow of underground fluids (water, oil, and gas) and distribution of their pressures are just two sides of the same coin and must be considered together. Distributions of fluid flow and pressure are determined by a superposition of distributions of (1) factors causing fluid flow and (2) permeability of rocks.
Factors of fluid flow and pressure distribution and changes Factors of fluid flow and pressure may be divided into two separate groups: (1) those that cause free convection, and (2) those that cause forced convection. This division is natural from the point of view of physics. Abnormal and subnormal pressures are caused only by the forced convection factors in flat countries and by both free and forced convection factors in areas with broken ground relief, especially in intermontane areas. It may be of no importance for mathematical simulation of flow and pressure distribution. But it is important, even crucial sometimes, for statistical analysis of relations between distributions of pressure and geologic parameters and characteristics,
71
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
Crest H o r i z o n t a l Lines
Pressure Isobars 1 -- Zone of lower than hydrostatic pressures 2 -- Zone of higher than hydrostatic pressures
River
Fig. 3-1. Pressure distribution in the case of free convection basin water flow caused by non-horizontal water table. (Modified after Gurevich et al., 1994, fig. 1, p. 69.)
because free and forced convection and pressure distributions associated with them, are caused by different factors and should be correlated with different parameters. Geological factors are nearly always combinations of physical and chemical factors. To avoid confusion it is more convenient to follow the cause-and-effect picture of natural phenomena and processes and, therefore, to list all factors from a viewpoint of physics and physical chemistry. A list of theoretically possible pressure generating and pressure changing mechanisms is presented below.
Free convection of ground fluids Free convection of ground fluids is caused by non-uniformity of fluid density unstable in the gravitational field. It is convenient, from a geological and physical point of view, to identify different cases of such non-uniformity as follows: (1) non-horizontal groundwater table - - the boundary between water and air that generally follows the relief of the Earth's surface; (2) vertically and horizontally non-uniform water density distribution owing to the salinity and temperature non-uniformities; (3) inclusions of oil and gas - - from bubbles to pools in s i z e - in water-saturated formations. The first factor can cause subnormal pressures below elevated (recharge) areas and abnormal pressures below low (discharge) areas (Fig. 3-1). In intermontane areas deviation from hydrostatic pressure may reach up to 30-50%. In flat areas fluid pressure distribution caused by non-horizontal relief and water table is rather close to hydrostatic. Non-uniformity of water density generally causes only minor deviations from hydrostatic pressures. But oil and especially gas pools in traps of considerable height can cause noticeable to very high abnormal pressures.
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A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
Forced convection of ground fluids The forced convection is caused by any factor or combination of factors that change compression of fluids as a result of changes in volumes of rock solids, interparticle voids, and fluids themselves. These processes act locally, producing pressure deviations directly in the volume where they are manifested. Then these deviations are transmitted to the neighboring volumes of fluid-saturated rocks by piezoconductivity by means of mass transfer. A list of physical and physicochemical processes known today (and actually long ago) that can theoretically cause a forced convection, may be presented as follows (Gurevich et al., 1987). (1) Mechanical deformations of rocks with a change in porosity and, thereby, a change in the fluid pressure: (a) Elastic compression (or expansion) of the grains and of the entire rock frame with increasing (or decreasing) overburden load. (b) Irreversible decrease in porosity of granular sedimentary rocks due to addition of overburden or reduction in fluid formation pressure or/and a reduction in the rock frame strength. The strength of the rock frame is influenced by the following: (1) diffusion of dislocations in crystal structure, which favors slow slippage of grains relative to each other; (2) pulsating (alternating) temperature changes which create non-uniform stresses in an inhomogeneous frame and tend to rupture bonds between grains; (3) seismic-type vibrations which reduce the force of friction upon passage of the tension phase of the seismic wave; (4) steady tangential and especially alternating geodynamic stresses; (5) alternating stresses from lunar and solar tides; and so on. As the end result, the rate of irreversible compaction sometimes may reach the maximum not at the maximum rate of overburden increase, but rather in periods of fast uplift when impact on the frame is intensified and the strength of the rock frame is reduced, though overburden load may remain constant or even decrease. (c) Geodynamic stresses (compression and tension) that arise during periods of active tectonic movements and act on the volume of void space. Effects on intergranular capacity are usually insignificant, but fracture capacity, due to high compressibility of fractures, is strongly affected. (d) Flow of salt (plastic deformation) under the influence of overburden and geodynamic load, into the void space of intersalt porous rocks. The salt flow rate will be increased by vibration. This process constantly tends to equalize the pore fluid pressure in these porous rocks and the stress in the salt. (2) Influence of mass transfer fluxes: (a) Passage of fluxes of fluids through barogeochemical and thermogeochemical barriers, leading to dissolution or precipitation of solids from solution, and to mixing or differentiation of fluids. Dissolution of a certain component of rocks in a fluid moving through the rocks in the direction of increasing solubility of this component usually leads to a decrease in the total volume and a reduction in pressure. Precipitation of the substance during fluid movement in the direction of a decreasing solubility below the actual concentration of this component leads to an increase in pressure.
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
73
(b) Piezo-convection effect. In the convective rise of gas, changing places with the liquid that it displaces, the gas enters a region of lower pressure, whereas the liquid enters a region of higher pressure. But because of the great difference in their compressibilities (and the lower the pressure, the greater this difference), the expansion of gas must be much greater than the compression of the liquid that has arrived at the former site of gas. If the volume in fluid-saturated rocks in which this convective redistribution of fluids takes place is poorly permeable or, especially, if it is surrounded by poorly permeable rocks, the outflow of fluid compensating this difference in new volumes will proceed very slowly. Therefore, a significant (local) increase in pressure will arise, by means of which, through additional compression of both liquid and gas, the greater expansion of the gas will be compensated, thus preserving the overall balance of volume. This effect will be the greatest in vertically fractured zones in poorly permeable rock formations. (3) Effects of temperature change: (a) Thermoelastic effect. Inasmuch as the coefficient of thermal expansion is greater for fluids than for rock and, therefore, for the pore space, an increase in temperature will increase the pressure, and a drop in temperature will lower the pressure. (b) Changes in the state of aggregation, i.e., ice/water and water/vapor phase transitions as the temperature passes through a critical point. Also included here is the transition of bound water to free water as the temperature is raised (with an increase in pressure), as well as the reverse transition of free water into bound water when temperature is lowered (with a decrease in pressure). (c) Precipitation of salts from saturated solutions, when the temperature is lowered and the salt solubility is reduced, generally leads to a decrease in pore volume and an increase in pressure. Dissolution of salts, when temperature is raised, usually leads to an increase in the pore volume and a drop in pressure. (d) Generation of oil and gas by thermocatalytic transformation of organic matter and the decomposition of carbonates to form carbon dioxide (in quantities greater than the quantities that can be dissolved in the pore water), accompanied by the formation of new fluid and an increase in pressure. (e) Dehydration of minerals. Transformation of montmorillonite to illite, gypsum to anhydrite, and analogous transformations of other minerals lead to increases in pressure. (4) Chemical transformations of substances that are not initiated by temperature increase, such as radiochemical decomposition of water and hydrocarbon molecules, thermochemical decomposition of hydrocarbon molecules, synthesis of molecules of resins and asphaltenes, and dolomitization of limestone. These phenomena have not been yet evaluated rigorously in terms of the overall change in the volume of the system and its impact on pressure. This, in brief, is the list of basic thermodynamic phenomena (physical, physicochemical, and chemical in character) leading to changes in the specific amount and degree of compression of a fluid in the intergranular space of rocks. It must be emphasized that even though the nature of these mechanisms and individual processes and their qualitative patterns are rather clear in most cases, it may still be extremely difficult to
74
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH . . . . . . . . . . .' .
7. Flow
.
.
.
.
" Ko
Flow
.
Fig. 3-2. Two extreme cases of beds orientation with respect to fluid flow direction. (Modified after Gurevich et al., 1994, fig. 2, p. 69.)
obtain any direct quantitative evaluations of their manifestation and their influence on fluid pressure and fluxes in nature. The list presented above does not include such rather 'exotic' mechanisms as pressure increase due to osmotic processes. For such a process to be operative, water with higher salinity must be located in a sand lens among clays surrounded by low-salinity water, and the permeability of the clay must be zero. Clearly, such situations are rather exotic and do not play any role in regional processes. It is useful to notice that the role of each of the mechanisms listed above is determined by the rate at which the process takes place and the rate at which pressure change is dissipated.
Role and distribution of formation permeability Permeability is a tensor value and depends on space distribution of lithologic heterogeneity. There are two extreme cases of distribution of lithologic bodies relative to the direction of fluid flow: alternating layers of different permeability lie (1) parallel and (2) perpendicular to the flow direction (Fig. 3-2). In the first case the average permeability k~ of the formation for the flow will be:
Hi
-
k,i-y
(3-1)
where kli and Hi are lateral permeability and thickness of the layer i, H is the total thickness of the formation. In the second case, the average permeability k2 will be: k2 - -
~H' Hil/k2i
(3-2)
where H' is the length of the formation (in the direction of flow) along which permeability of rocks is being averaged, H i' is the thickness of layer i, and k2i is the permeability of this layer along the flow line. Gurevich (1972) analyzed the problem of averaging permeability of geological formations for block sizes up to a sedimentary basin. It was shown that regional deep formation water flow velocities, calculated on the basis of regional permeability averaged as the arithmetic average from permeability values measured in wells in oil and gas fields, are in contradiction with hydrogeochemical zonality of groundwater. Calculated (arithmetically averaged permeability values) velocities are at least two or three orders of magnitude higher than it is possible at the existing geochemical zonality. The method of averaging permeability may be the only cause of this discrepancy.
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
']
Due to the heterogeneity of formations, in the majority of regions, permeability distribution on the regional scale is much nearer to case (2) than case (1). One of the causes of such lateral heterogeneity is facies change: it is well known, for example, that at the top of anticlinal structure, formed simultaneously with sedimentation, sand content is the highest and decreases with distance from the top of structure. Beyond the anticline, clays may dominate. Thus, permeability in the center of anticlinal structure may be several orders of magnitude higher than that beyond its boundaries. Still another cause of low regional average permeability is the presence of faults impermeable or poorly permeable across their planes. In many regions hydrodynamic environments and hydrogeochemical zonality are distinctly broken by faults into separate blocks. Antonellini and Aydin (1994) thoroughly investigated porosity and permeability distribution in fault zones. They stated that in porous sandstones "deformation bands have porosity about one order of magnitude lower than the surrounding host rock and, on average, a permeability three orders of magnitude less than the surrounding host rock. The wall rock in proximity to slip planes can have permeabilities more than seven orders of magnitude less than the pristine sandstone". They also stated that capillary pressure within deformation bands is estimated to be 10-100 times larger than that in the surrounding host rock, and concluded that as a result of all this, "deformation bands and slip planes can substantially modify fluid flow properties of a reservoir and have potential sealing capabilities with respect to a non-wetting phase". It is also true for the wetting phase water. Therefore, the lateral permeability of formations for a long-distance flow may be orders of magnitude less than it is often assumed and, thus, regional lateral flow of underground water and migrating hydrocarbons may be, at least, highly limited. At the same time, vertical permeability regionally and during geological time is much higher than that measured from cores. In some areas with rather consolidated rocks, a kind of honeycomb pattern of hydrodynamic environment was observed. Vertical permeability formed by fractures depends strongly on tectonic and other rock-deforming activities. For example, it was observed that moon earth-tides noticeably affect the width and permeability of fractures and cause cyclicity in the yield of springs from fractured rocks. Tectonic activity is a cyclical process and vertical permeability of formation reaches its peak value at peaks of tectonic deformation. These periods, however short they could be, can provide the major portion of vertical fluid migration that pulsates together with tectonic pulsations. For the origin and maintenance of abnormal pressure, the existence of poorly permeable and sufficiently thick formations above the zone, where factors of the forced convection act, is the most important feature of permeability distribution.
PRESENTATION OF P R E S S U R E AS THE A D D I T I V E SUM OF TWO C O M P O N E N T S
It is obvious from the above that free and forced convection and, accordingly, their individual contributions to pressure distribution are caused by two specific groups of factors, different both physically and geologically. To obtain a correct statistical correlation between the pressure and various physical and geological parameters and
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A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
characteristics, pressure should be divided into free and forced convection components each of which can be correlated with proper parameters causing them. Free convection pressure distribution for underground water flow, in the absence of forced convection factors, can be easily done with reasonable approximation by mathematical simulation. Water table position can be determined with a substantial precision. Permeability distribution can also be assumed to be close enough to the actual one. As a result, an error in simulated pressure distribution will be mostly within a range of 1-2 kg/cm 2 and less. It is not possible to calculate forced convection pressure distribution because many values are unknown. The only way to evaluate forced convection contribution to the total pressure value would be to subtract the free convection pressure component from the total pressure value. This can be done only if the free and forced convection pressure components can be considered additive. This is possible to do precisely if fluid and solid are assumed to be incompressible (Gurevich, 1972) or with a reasonably small error for most natural environments. It is necessary to examine conditions under which the total pressure can be divided into a sum of free and forced convection components with acceptable approximation. Water constitutes more than 95 to 99% of fluid filling rock pore space. Thus, it is possible to use equations for water only, for simplicity. Assuming that Darcy's law is valid for water flow, the boundary problem for pressure p distribution in a basin, formulated in general (ignoring changes in rock volume and, thus, in coordinates tied to it) is: div
#
Ot
p(F1) = 0 ( - V p + pg)n
(3-4) =
kI.t(l-"2)
(3-5)
where p is the water density, K is the permeability tensor, # is the water viscosity, g is acceleration of gravity vector, n is a normal to the boundary surface, ~b is the rock porosity, t is the time, G is the intensity of source or sink of water, F1 is the upper boundary (the water table), F 2 is the side and bottom boundary, and qJ(F2) is a prescribed function. The first term in Eq. 3-1, the flow changes, can be presented as a sum of two flows for two additive components of pressure. Boundary conditions also can be divided into two sets for these additive boundary problems. It is obvious that whether or not this problem for pressure p can be presented as a sum of two problems for the free and forced convection depends only on whether fluid and rock compression determined by the total pressure can be presented as a sum. Two cases may be considered: (a) the fluid flow volume can be divided into two separate volumes where free and forced convection occur separately, and (b) the actual flow combines free and forced convection components. The first case is the simplest one: a poorly permeable clayey or salt formation divides the geologic section into two hydraulic sections. The fluid dynamics in the upper section depends mostly on the water-table relief and, often negligibly, on heterogeneity
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
'[']
of fluid density. Thus, fluid flow in this section is presented only by free convection. The influence of water table in the lower section is negligible due to the sealing action of the poorly permeable formation and fluid flow is determined completely by the processes that change the volumetric ratio of fluid and pore space volumes. Thus, only forced convection occurs in the lower section (local fluid flows within this stage can be considered, at a certain scale, as one of mechanisms of volume changes). This situation can easily be described by two boundary problems. Pressure distribution in the upper stage can be described by the following boundary problem:
div lPK(-vp +
--0
p (1-'1) = 0
[-
(3-6) (3-7)
]
7 ( - V p + pg) (r2) - 0
(3-8)
Equations describing density and viscosity distributions, their dependence on temperature and pressure, etc. may or should be added when necessary. Pressure, p, is the fluid pressure above the atmospheric one; thus, pressure is zero at the upper boundary (water table). There is no flow through the side and bottom boundaries: flow into the upper section from the lower one is negligible compared to the flow in the upper section. Solution of the above system (Eqs. 3-6, 3-7, 3-8) gives a function p(F2) for pressures at the lower boundary of the upper section, i.e., the upper boundary of the lower section. Then the forced convection pressure component p* can be calculated as follows: P* = Pac -- (P -k- 7'h)
(3-9)
where Y is the fluid specific weight and h is the vertical depth of the point with pressure Pac; h is measured from the boundary surface F2. This is the p* value that should be correlated with parameters which determine the forced convection. The error of such a procedure of discriminating the forced convection component of pressure can be established for each particular case by mathematical simulation. Generally, it will rarely exceed about 25 to 30 psi. Values of p* lower than the error should not be taken into account. For abnormalities with p* higher than 100 psi and more such an accuracy is excellent, and correlation will be pure from physics and geology viewpoints (free from influence of irrelevant factors) and highly reliable. The second case is the situation when poorly permeable formations dominate in the whole section. Here, the boundary problem for the free convection should be solved for the total segment of depth and resulting pressure distribution subtracted from the actual pressure distribution. The difference p* may be assumed to be the forced convection pressure component with approximately the same precision as in the previous case. When a more definite evaluation is necessary, the error should be established by simulation. Evaluation of the error of approximation of an actual formation fluid pressure by the sum of these two components for different geologic situations is a subject of a special thorough analysis.
~]8
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
It is obvious that for flat areas or, more precisely, for areas with a nearly flat water table, p* can be obtained just by subtraction of hydrostatic pressure from the actually measured pressures.
S O M E M A J O R FACTORS OF U N D E R G R O U N D F L U I D F O R C E D C O N V E C T I O N AND C H A R A C T E R I S T I C S FOR C O R R E L A T I O N
Characteristics and parameters for correlation with the forced convection component of formation pressure should be selected on the basis of thorough causal analysis of each phenomenon and its impact on pressure changes. It is convenient in many cases to select separately characteristics (1) of rock properties that provide a possibility of compression and pressure change resulting from an external influence, and (2) of such an influence. For example, porosity characterizes the ability of pore space to be reduced under the impact of external influence, and overburden weight is such an influence. Pressure increase is a superposition of (1) a rock ability to respond to external influence, (2) external influence, and (3) permeability. The first two characterize the pressure increase and the third one characterizes pressure dissipation. There is a possibility, using characteristics of these three types, to form a kind of generalized parameter similar to the similitude criterion and correlate it with the forced convection pressure component. This possibility should be thoroughly explored and tested on some regional data. A preliminary analysis of several major factors is given below.
Compaction (~'granular sediments Compaction of granular sediments is a complex process strongly dependent on the intensity of external influences (Athy, 1930; Hedberg, 1936; Dickinson, 1953; Weller, 1959; Mukhin, 1965; Rieke and Chilingarian, 1974; Chilingarian and Wolf, 1975, 1976; Gurevich, 1980; and many others). It has two major mechanical components (Gurevich, 1980): (1) compaction due to increase in the effective stress, and (2) compaction due to changes in sand matrix strength caused by external influences at a constant or decreasing effective stress. Alternating stress and temperature changes and especially vibrations weaken bonds between grains and help their rearrangement at points of highest stress. The third component is a physicochemical one: filling of pore space with secondary minerals. The relative role of each one of these three contributions to porosity reduction varies with the type of geologic formation, intensity of tectonic deformation, and geochemical processes including migration of mineral solutions. It is obvious that porosity and permeability of a sediment change in time quite unevenly. Three of the above-mentioned components of consolidation pertain to sands. Compaction of clays involves both of the mentioned mechanical components and, to a lesser degree, the geochemical, but is more complicated because other processes are also involved. Clay minerals, especially montmorillonite, have large quantities of water. This water partially is represented by bound water adsorbed on the surfaces of clay minerals and contained in-between aluminosilicate layers. The density of bound water is approximately equal to up to 1.4 g/cm 3 immediately near the clay mineral surface.
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
79
Bound and interlayer water is in dynamic equilibrium with solid matter of minerals; therefore, this equilibrium and, thus, compaction of clay are temperature dependent. With increasing temperature, the energy of Brownian oscillations of water molecules increases and exceeds the energy of bonds. Thus, with an increase in temperature, layer after layer of adsorbed water transforms to free water and becomes capable of flowing through pore space in the direction of lower fluid potential. Transformation of the bound water into free water occurs with an increase in volume due to the density difference. For each particular clay bed a major increase in temperature may occur not while it is being buried and the sediment load is increasing, but in the course of a regression period when temperature rises due to higher heat flow and, often, vertical migration of fluid. This may be especially true in the case of fast sedimentation when thick sediments are accumulated and buried. The rate of heating these sediments is lower than the rate of sedimentation and burial; thus, rocks are much cooler here than at the same depth in stable areas: the geothermal gradient may be just half of that in the stable areas. When sedimentation stops, formations continue to warm and temperature isotherms rise up the geologic section. During this period, compaction can continue due to temperature increase even if load of sediments decreases due to erosion. Changes in shale porosity are also due to the transformation of clay with loss of water, such as transformation of montmorillonite to illite. This process depends on temperature increase and availability of an additional amount of potassium. It takes a long time and its rate is different in geologically different environments. As a result, montmorillonite ceases to exist at different depth and temperature in different regions. In tectonically stable regions with older formations the lower boundary of montmorillonite presence may be about 2000+ m, but in regions of recent and very fast sedimentation like Azerbaijan it may be deeper than 5000 m. The combination of load and temperature enhances and changes the process of deformation of clay. Compaction caused by loading applied at different rates produces different final porosity in samples of equal initial porosity. Temperature increase and 'melting' of bound water causes appearance of 'dry' contacts between individual mineral grains that strongly impedes further compaction. The above discussion indicates that the compaction process includes several relatively independent components and cannot be reduced to Terzaghi's model and equivalent depth concept. A single simple model common for all formations and regions cannot describe it. In the areas of recent continuous sediment accumulation, burial and compaction, a correlation between porosity and pressure can be expected and is actually observed. This correlation may be due to both pressure distribution changed by compaction and the hydraulic resistance of rocks to the upward water flow, which dissipates the excess pressure. Utilization of the following characteristics can be suggested: (1) For the permeability and total hydraulic resistance: total thickness and clay/sand ratio. (2) For the rock capability to produce pressure increase: porosity, vitrinite reflectance (as an indirect indicator of consolidation and, thus, mechanical strength), and the expandable minerals content in the total clay minerals content. (3) For the external influence causing compaction: overburden, rate of subsidence,
80
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
amplitude and frequency of the subsidence-uplift oscillations, and rate of temperature increase. Generally, in areas where subsidence and sediment accumulation occurred prior to the Cretaceous period and was followed by an uplift or stabilization, clays are consolidated and processes other than compaction play major roles in abnormal pressure generation and maintenance. No correlation between pressure and porosity or other compaction parameters can be expected in such formations and areas. In some areas where clays are within or interbedded with carbonate formations a reverse correlation was observed (Fertl and Chilingarian, 1989; Chilingarian et al., 1992).
Upwardfluid migration In areas where there are lithological 'windows' in seals and/or where faults and fractured zones are present, vertical migration can play a very important and sometimes major role in the origin and maintenance of abnormal pressures. Vertical migration of fluids can create pressure abnormality by several mechanisms. Good local vertical connection between two or several beds within a structural trap can create a high oil or gas pool (piercing several formations) and, thus, a high pressure at the top of the pool. This, actually excessive hydrostatic pressure can exceed the geostatic one in shallow traps. Such cases were encountered in Azerbaijan, California and other intensively faulted regions. Bourgoyne (1994) emphasized the danger of these shallow high-pressure pools. Vertical and subvertical columns of gas migrating through formations are encountered in regions of active recent or current tectonic activity and currently continuing vertical migration of hydrocarbons. In such cases, abnormality may even decrease upwards due to dissipation of pressure caused by penetration of gas laterally from the column into permeable beds. Pressure typically decreases laterally from the column outward. Vertical migration and pressure distribution of this kind mostly occur in consolidated deeper formations with reduced lateral permeability and increased capacity to form fractures. Upward gas migration along the high-permeability fractured zones can greatly increase pressure by the piezo-convective effect. In some cases of localized zones of upward gas migration, this effect may make a major contribution. Origin of abnormality in areas of intensive upward fluid migration is a combination of a free convection (hydrostatic including) component and a forced convection component. The whole geologic section down to and often including basement rocks is undergoing mechanical deformations and geochemical transformations, including oil and gas generation. This increases compression of fluids and, therefore, pressure. Faults and fractured zones provide paths for mostly localized upward fluid migration within the whole thickness of a sedimentary basin. It is difficult and most often impossible to determine what factor of free and forced convection contributed most heavily in an observed pressure distribution. On one hand, fluid is compressed and being 'squeezed' from its previous position along the direction of decreasing potential. On the other hand, distribution of pressure in the column of migrating upward fluid always has a hydrostatic component depending on fluid density.
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
81
Pressure distribution caused by an upward fluid migration in areas with multiple faults may vary laterally very significantly and is less predictable especially in the early stages of exploration. Some tectonic blocks can have a very high pressure, whereas the pressure in adjacent blocks may be much lower due to the difference in the vertical connections with the source of high pressure. Taking into account insufficient information on geology and pressure distribution in such areas at the exploration stage, it may be advantageous to use some average values of pressure for correlation with geologic and physical parameters. The following characteristics may be recommended for correlation. (1) For rock and fluid capability to produce an increase in pressure: thickness of sedimentary basin, degree of consolidation and transformation of sedimentary and basement rocks, and presence and relative proportion of source rocks. (2) For external influence: temperature gradient and rate of its increase with depth, length and frequency of linear faults, and gradient of neo- and recent tectonic differential movements.
Correlation between porosity and pressure Next, one should discuss the correlation between porosity and pressure distributions. Such a correlation may have a cause-and-effect nature even if pressure deviations from the free convection pressure distribution were caused by the compaction only and there was no fluid flow. From the hydrodynamics viewpoint, pressure distribution in a fluid seeping through a rock formation will depend on the permeability distribution. In a case of steady flow, i.e., when there are no changes in time, a certain local correlation will exist between pressure and permeability along the fluid flow path. In a case of active processes, for example, compaction and upward fluid migration, these distributions may be more complex, but still some correlation between permeability and pressure distributions in poorly permeable rock formations may still exist. As there is a correlation between permeability and porosity (if lithology is uniform) and correlation between permeability and pressure distributions, there is a correlation between pressure and porosity distributions. For example, if a high-porosity formation lies on a low-porosity formation and is overlain by another low-porosity formation covered by sands up to the surface, high pressure may be present in the high-porosity formation, lower poorporosity formation, and abnormal pressure in the upper poor-porosity formation will decrease upward to the hydrostatic one at the boundary between the upper poor-porosity formation and sands. Definitely, as pressure decreases, porosity increases upward in each formation. Thus, a certain correlation may always be found between the two. The above-presented theoretical analysis is next applied to a regional pressure distribution in Azerbaijan, in the South Caspian Basin. Researchers of this region believe that pressures here fully correlate with porosity and, thus, almost completely base pressure evaluations on well logging data. As discussed above, hydrodynamic theory indicates that pressure distribution should heavily depend on the permeability distribution and that a correlation between porosity and pressure may exist or not. Carstens and Dypvik (1981) showed this very convincingly using empirical data. If such a correlation exists, it is an indirect correlation mostly based on correlation between
82
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
permeability and porosity. The writers approached the pressure distribution data in the South Caspian Basin using this concept. Beginning with the geological setting of the region, the South Caspian Basin was formed mostly during the Early and Middle Pliocene. The total thickness of sedimentary rocks reaches 22,000 m (72,131 ft) in the deepest part of the basement surface. Major oil, condensate and gas reserves are present in the shale-sand sequences (Productive Formation) of Middle Miocene. The thickness of this formation is up to 4000-4500 m (13,115-14,754 ft) (Ali-Zadeh et al., 1985). Basic anticlinal structural elements were developed during the Middle Pliocene when intense tectonic activity took place. The next peak of tectonic activity, which occurred during the second half of the Quaternary, completed tectonic development of regional and local geological structures, formed most faults, and strongly enhanced the mud volcano activity. Tectonically most active areas were the Apsheron Peninsula, Apsheron Archipelago and Sub-Kura region (see Buryakovsky et al., 2001). The Mesozoic-Miocene tectonic stage has produced mostly sub-latitudinally oriented structures, whereas structures of the Oligocene-Quaternary stage are sub-longitudinally oriented. Mesozoic to Oligocene-Miocene deposits are represented mostly by flysch and finer marine molasses. For Pliocene to Quaternary rocks, coarser, mostly continental, molasses are typical. Marine formations constitute 80 to 90% of the whole sedimentary section of the region. Owing to the very rapid Oligocene-Quaternary sedimentation (that began in Pontian time) and thick shales with low thermal conductivity, the geothermal gradient in the Azerbaijan part of the South Caspian Basin is as low as 16-18~ This helps to preserve the sealing properties of the shales. For example, formation temperatures in the Baku Archipelago fields are 110 to 115~ with a high content of montmorillonite at depths of about 6000 m. The least compacted shales are encountered in the Middle Pliocene Productive Formation in the Lower Kura Depression and Baku Archipelago (Kheirov et al., 1990). Porosities of shales in a vertical geologic section vary appreciably due to variations in lithology: it is actually impossible to find lithologically identical rocks even within the same horizon (Kheirov et al., 1990). Although the density of rocks increases with depth, poorly consolidated highly permeable sands can be encountered at depths of 5 to 6 km and more. It is believed that despite some consolidation, shales retain their plasticity and good sealing property even at depths of more than 5-6 km (Mekhtiev et al., 1988) owing to their mineral composition. The montmorillonite content varies widely laterally and in vertical sections, but mostly remains within the range of 20% to 60% (Buryakovsky and Djevanshir, 1985; Asadov et al., 1988; Bunyatov and lmanov, 1989; Kheirov et al., 1990). X-ray analysis and electron micrographs (SEM) of shales show definitely that the rather stable content of montmorillonite in the Baku Archipelago fields is caused by the dominance of secondary montmorillonite formation over its destruction down to depths of at least 6200 m (20,328 ft) (Buryakovsky et al., 1986). Very intensive Quaternary tectonic stresses and movements greatly affected the shale physical properties: many shales, strongly deformed by tectonic and diapir movements, are not cohesive enough and, thus, are very unstable in the boreholes, i.e., large
83
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
_~_2.._ o
~
o
8~ _
o
Caspian
s
Sea
"
+l_t_! !ol
Fig. 3-3. Distribution of mud volcanoes in Azerbaijan. (Modified after Melik-Pashaev et al., 1983. Editors of the map: A.A. Ali-Zadeh, E.M. Shekinskiy and A.A. Yakubov.) 1 = faults separating large structural elements; 2 = faults important for mud volcanism; 3 = smaller faults; 4 = large, periodically erupting mud volcanoes; 5 = buried mud volcanoes inactive for 100 years and more; 6 -- all other mud volcanoes; 7 = oil and gas fields. (In Gurevich and Chilingar, 1995, fig. 1, p. 126.)
fragments of shale fall down from the borehole walls (Melik-Pashaev et al., 1983). Instability of some shale is caused by its lithology. For example, Lower Pliocene (Pontian) shales have gypsum inclusions. They easily soak in water and separate into small laminae that fall down from the borehole walls. Faults are numerous in the area. In the Apsheron zone nearly all anticlinal structures are cut by faults. Longitudinal faults, that have amplitudes of several hundred to 2000 m (6557 ft), are especially important. Such faults contribute strongly to the formation of mud volcano channels. Yakubov et al. (1971) showed that longitudinal faults in the southwestern Caucasus cut not only the Pliocene formations but also the MiocenePaleogene and Mesozoic ones. This provides a possibility for mud volcanoes to have deep roots into the Mesozoic formations. Active and buried mud volcanoes are widespread over the territory of the South Caspian Basin. Active mud volcanoes are well known in Azerbaijan in the Apsheron, Kobystan and Kura regions, and in the Apsheron and Baku Archipelagos. Mud volcanoes are situated on the axes of anticlinal structures (Fig. 3-3), but not necessarily on the anticlinal crests (Melik-Pashaev et al., 1983). Yakubov et al. (1971) described more than 220 mud volcanoes and their numerous gryphons and salses in the Azerbaijan. In SW Kobystan alone, there are more than 650 active gryphons and salses that emanate an average of 500 m 3 of gas per day each. Many mud volcanoes are buried and their fluids cannot reach the Earth's surface.
84
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH #92
Sea level
A
#75
t
#41
#79
#63
\
,,i~
Q
N2aP ~~~~--" ~ - - - .
~.
5,01~9"m ,. (16,426 ft) 5,260 m ~ j ( 1 7 , 2 4 6 ft)
4,7 !0 m~ 4,80 (15,475 ft) (15,754 ft)
"~ ~
2
N2ak
VII
~" VIII
!/I
Fig. 3-4. Bulla Island geologic section: 1 = mud volcano breccia; 2 -- faults. (Modified after Melik-Pashaev et al., 1983. In Gurevich and Chilingar, 1995, fig. 2, p. 127.)
Activity of mud volcanoes clearly shows the scale of the vertical upward fluid (gas and water mostly) migration. Faults constitute another important avenue for vertical fluid migration (Fig. 3-4). Oil and gas generation and vertical upward migration, tectonic movements forming faults, and deformation of plastic shales forming diapirs and mud volcanoes have been considered to be part of an integral process as early as 1934 by I.M. Gubkin (in Melik-Pashaev et al., 1983). This process still continues now. Tectonic movements cause strong earthquakes in the region. Mud volcanoes erupt periodically, transferring large volumes of water and gas to the surface and atmosphere, and also to the subsurface strata. Melik-Pashaev et al. (1983), for instance, believe that the abnormal pressure in the Bakhar oil field formations is partially caused by mud volcano activity: a big subsea mud volcano nearby erupts fiercely at time intervals of 1-2 years to 16-17 years. One of the evidences of the upward fluid migration can be seen in the Oil Stones field. The oil composition in this field is more or less uniform with a slight tendency of increasing density toward the oil-water contact. But, at the pool's edge, a light oil appears which is quite alien for this group of fields (Samedov, 1959).
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
85
The distance of vertical migration can be judged by the lithology and age of rocks brought by the mud volcanoes to the surface. Large fragments of Cretaceous limestones and marls are present in the deposits of many mud volcanoes such as Lokbatan, Otman-Bozdag, etc. (Melik-Pashaev et al., 1983). Sediments in the South Caspian Basin have been accumulated at a very high rate of 1.3 km per million years (Djevanshir, 1987). With shales being predominant in the geologic section, compaction makes a major contribution to the distribution of formation pressures. Presence of thick, highly permeable sand formations, exposed by subsequent erosion in some places, and vertical migration of fluids, discharged from deeper formations to the surface or to the overlying formations allows a rapid redistribution of pressures. This may be the cause of a specific distribution of pressures, e.g., pore pressures in thick shales noticeably exceed those in the permeable formations. Methods used in Azerbaijan to determine abnormal pressures
Authors who have studied abnormal pressures in Azerbaijan distinguished three different pore pressures: (1) abnormal pore pressures in the permeable formations (APPF); (2) abnormal pore pressures in shales (APPS); (3) abnormal pore pressures in thin permeable sand lenses in shales (APTL). In each case, different measurement methods were used. APPF were mostly measured by wellbore pressure gauges. APPS were measured indirectly by calculation using well-logging data. APTL were assumed to be equal to pressures in the surrounding shales. Calculated values of pressures in shales were compared with pressures exerted by the weight of the drilling mud column having a density necessary to maintain wellbore wall stability or that corresponding to the beginning of gas penetration into the mud. Judging from the texts of the reviewed papers, the static pressure of the drilling mud column (depth times specific weight) was used. No special estimates of the pressure evaluation precision were presented. Deformations of wellbore walls in wells intersecting shales are considered, by almost all authors, to be a result of abnormal pressure impact. Distributions of abnormal pressures Pressure abnormality in the region continuously increases from NE to SW, from Apsheron Peninsula and Apsheron Archipelago toward the Kura Depression (Buryakovsky et al., 1986). Fig. 3-5 shows changes in the vertical abnormality distribution in this direction. Table 3-1 illustrates abnormality distribution in the oil and gas fields of Apsheron and Baku Archipelagos and South Apsheron offshore zone. According to Durmishian (1972), deeply buried Miocene-Paleogene rocks exhibit considerable overpressures everywhere except near their outcrops. The upper part of the Productive Formation of Middle Pliocene age, devoid of oil and gas, has no or very mild pressure abnormalities. The middle part has widely distributed but mostly moderate abnormalities. The lower part of the Productive Formation has high abnormal pressures all over the area. Laterally, as all authors indicate, pressure abnormality increases with the increase in depth and shale content of rocks.
TABLE 3- 1 Statistics of abnormally high pore pressures in shales (APPS) determination for the fields of Apsheron and Baku Archipelagos and South-Apsheron offshore zone (after Buryakovsky et al., 1986) Oil and gas fields
Zhiloy Island, Oil Stones, Apsheron Bank Peschanyy-Sea Southern, Southern-2 Bakhar Sangachaly-Sea-Duvannyy-Sea-Bulla Island Khamamdag-Sea, Garasu, Sangi-Mugan, Persiyanin Bank Sangachaly-Sea-Duvannyy-Sea-Bulla Island. Khamamdag-Sea, Persiyanin Bank Bulla-Sea
Number of determinations
Pressure gradient (MPa/m)
>
Standard deviation, o, MPa/m
0
z
average
median
modal
353 35 74 232 600 39 1 99 1
0.0136 0.0132 0.0156 0.0 166 0.0171 0.0 176 0.0 173
0.0135 0.0132 0.0153 0.0 165 0.0176 0.0181 0.01 78
0.0135 0.0 135 0.0 145 0.01 65 0.0185 0.0185 0.0 185
0.00168 0.00155 0.00150 0.00156 0.00202 0.00223 0.00210
646
0.0182
0.0184
0.0185
0.001 11
2m
< 5 P 5 o
-II
50 > 7
6 ia
$2m
2
2:
> Z u 3 >
sz
N
> 0
E
87
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
Pressure gradient, MPa/m (psi/ft) t3.010 (0.0431)
0.015 (0.065)
500 (1,639) 1,000 (3,279) 1,500 (4,918) 2,000 (6,557', l::::
2,500
.ff
(s,197)
~. a9
3,000 (9,836~ 3,500 (11,475) 4,000 (13,115) 4,500 (14,75:13 5,000 (16,39.31)
Fig. 3-5. Average pressure gradients at the Southern [Yuzhnaya] (1), Sangachaly-Duvannyy-Sea-Bulla Island fields (2) and Sub-Kura Depression (3). (Modified after Buryakovskyet al., 1986. In Gurevich and Chilingar, 1995, fig. 3, p. 129.)
Apsheron petroleum zone has locally some noticeable abnormalities (Oil Stones, Mud Cone, Zhiloy Island, Makarov Bank and other oil fields in the Apsheron Archipelago and Lokbatan-Karadag in the southwestern part of the Apsheron Peninsula). Abnormalities in the upper and middle parts of the Productive Formation in this zone exist mostly within the boundaries of oil and gas pools. Beyond these boundaries pressure is mostly hydrostatic. Shales with abnormal (calculated) pressure in the Apsheron Archipelago are first encountered at a depth as shallow as 480 m (1574 ft) in the Peschanyy field in the lower part of the Apsheron Formation (Yusuf-Zadeh et al., 1979). The pore pressure gradient reaches 0.0158 MPa/m in the Akchagyl Formation and changes discontinuously with depth. For example, pressure gradients in the Lower Surakhan shales are normal. Reservoir pressures in the Apsheron Archipelago are about normal. Abnormal pressures
88
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
Pore Pressure, MPa (psi) 50 (712)
100 (1,423)
1,000 (3,279)
11"1
2,000 (6,557)
3,000 L__ (9,836)
g 4,000 ~"(13,115)
a 5,000 (16,393)
6,000 (19,672)
A
Fig. 3-6. Pore pressures in shales (1) and sand reservoirs (2) in oil and gas fields along the Khamamdag-Sea-Karasu-Sangi-Mugan-Persiyanin Bank trend. A = hydrostatic pressure gradient. (Modified after Buryakovsky et al., 1986. In Gurevich and Chilingar, 1995, fig. 4, p. 130.)
in the Baku Archipelago and especially in the Kura region are much higher and are widespread. Abnormality at shallower depths (about less than 1500 m, i.e., above the Productive Formation) in the Baku Archipelago is mostly due to vertical migration of fluids from the deeper formations through deep faults and active and buried mud volcanoes. The idea of a deep source of abnormality is strongly supported by the fact that abnormal pressures in the Bulla-Sea field were encountered only in wells situated near longitudinal deep faults (Khalilov et al., 1988). At the same time, in the much deeper sediments of the Productive Formation, abnormality decreases near such faults (Yusuf-Zadeh et al., 1979). A mud volcano in this field is buried below the Akchagyl Formation. Roots of mud volcanoes in the Baku Archipelago reach Paleogene-Miocene sediments. Pressures are the highest in the Kura region. Pressure gradients reach 0.0226 MPa/m in the northeastern slope of the Kyurovdag anticline (Kasumov et al., 1976). The difference between the measured pressures in sand reservoirs and calculated pressures in shales reaches up to 40 MPa in both the Kura region and Baku Archipelago (Fig. 3-6). Calculated abnormalities are rather high even in thin (1 to 2 m) shale beds (Buryakovsky et al., 1986) and increase with shale bed thickness (Fig. 3-7). The abnormality level in such beds decreases with time upon production (Table 3-2).
89
ORIGIN OF FORMATIONFLUID PRESSURE DISTRIBUTIONS
TABLE 3-2 Effect of length of time after the beginning of production on calculated a pressures in shales (after Buryakovsky et al., 1986) Oil and gas fields
Sangachaly-Sea-DuvannyySea-Bulla Island
Bulla-Sea
Well No.
Well-logging date
43
12/09/65
62
03/02/67
135
08/01/68
147 191
09/03/70 04/05/73
197
03/07/74
537
10/08/75
18
06/11/73
9
10/26/74
23
07/10/74
a On the basis of well logging data.
Formation depth (m)
Thickness (m)
Pressure gradient (MPa/m)
4570 4610 4620 4440 4480 4100 4110 4125 4045 4555 4580 4595 4525 4550 4620 4760 4620 4650 4670 4713 4715 4730 4740 4800 4745 4767 4770 4775 4795 4810 4840 4850 4660 4670 4685 4690 4715 4720 4735
3 1.5 1 1 1 1 3 1 1 1 2 1 2 1 2 4 6 2 2 1.5 1 3 1 4 3 1.5 1.5 1 1.5 1 1 2 4 2 1.5 2.5 1 2 1
0.0190 0.0188 0.0186 0.0189 0.0190 0.0174 0.0175 0.0173 0.0166 0.0169 0.0170 0.0164 0.0169 0.0164 0.0167 0.0180 0.0185 0.0177 0.0178 0.0176 0.0176 0.0171 0.0173 0.0183 0.0176 0.0172 0.0173 0.0170 0.0172 0.0168 0.0170 0.0173 0.0174 0.0169 0.0169 0.0170 0.0174 0.0174 0.0163
90
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
0.020 ~..'- (0.087) 6 5 4
2 .~7 r
"0
t9 o~ IX. 0.010
(0.043)
I
,
4 (13)
8 (26)
Thickness of Shales, m (ft) Fig. 3-7. Pore pressure gradients in shales vs. thickness of shale beds: 1 -- Zhiloy Island; 2 -- Oil Stones; 3 = Bakhar; 4 = S a n g a c h a l y - S e a - D u v a n n y y - S e a - B u l l a Island; 5 = Bulla-Sea; 6 = K h a m a m d a g - S e a - K a r a s u Sangi-Mugan-Persiyanin-Bank. (Modified after Buryakovsky et al., 1986. In Gurevich and Chilingar, 1995, fig. 5, p. 133.)
The writers analyzed the reviewed data on pressure distribution in Azerbaijan. They tried to determine (1) whether or not current theories of the pressure abnormality distribution in Azerbaijan are complete enough, and (2) whether or not the pressure measurement methods are fully reliable. Although up to now a considerable amount of research work has been done on abnormal pressures in Azerbaijan, not all aspects were exhaustively studied. The analysis conducted by the writers suggested some new areas and directions of possible research work that can be done by the oil companies to increase drilling and production efficiency in Azerbaijan. (1) Most authors who studied the Azerbaijan overpressures believe that compaction of sediments is the totally dominant cause of pressure abnormality and, therefore, there should be a close relation between pressure and porosity abnormalities. This concept is not convincing from the viewpoint of an analysis of the nature of geological processes. It also contradicts the well-known fact that many very shallow fields had initial pressures higher than the overburden pressure (Anikiev, 1964). This cannot be explained by compaction only and recognition of a contribution of vertical migration of hydrocarbons to pressure abnormality in these fields is unavoidable. (2) Deformation of wellbore walls is considered to be mostly the result of shale plasticity combined with the impact of pressure abnormality. This may not be completely true.
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
91
In the reviewed publications, there were no special analysis and experimental confirmation of the plasticity of shales at deep horizons. The conclusions on plasticity seem to have been made indirectly on the basis of observed deformations of walls in the wellbore. It is not apparent that shales at temperatures above 100~ can be plastic, because at such temperatures mineral grain surfaces have no or almost no bound water, which could reduce dramatically the grain-to-grain friction. Deformational behavior of shales in the geologic section of the Azerbaijan formations with abnormal pressures should be studied thoroughly. Possibly, one can stabilize these shales by means of special formulation of drilling muds and, thus, reduce the required mud density. Also possibility of using direct electric current (DC), in conjunction with various chemicals, for electrochemical stabilization of heaving and sloughing shales should be thoroughly investigated (see Chilingarian, 1991, p. 293). It is always better to drill at the lowest possible wellbore pressure to achieve a higher penetration rate. For geologic sections where shales with higher pressures are interbedded with reservoir sands with significantly lower pressures this may be crucial. Therefore, it is necessary to separately evaluate contributions of shale plasticity and pressure abnormality to the deformation of wellbore walls. In the case of high shale plasticity, special composition of drilling mud may be used instead of a higher mud density. This can provide a significant increase in the penetration rate and, therefore, reduce costs. In a well that is being drilled through shales, with clays still retaining colloidal properties and maintaining thixotropy, there is a possibility that vibrations of the drilling tools and tubing may also contribute to fluidization of shales in the wellbore walls. In some wells, although the drilling mud weight was less than that calculated to be necessary to balance the pore pressure in shales, no problems were encountered. In the reviewed papers no analysis has been presented of the difference between shales with and without problems. The properties of shales and the drilling procedures in both cases should be thoroughly investigated. The emphasis should be on the relative roles of (a) pressure abnormality, that causes or increases plasticity or other deformational properties of shale, and (b) shale plasticity and other properties indigenous to the shale itself. It is important to determine the relative contributions to deformation of shales made by (a) the abnormal water and gas pressure in shale and (b) the plasticity of the shale itself at different mineral compositions and temperatures. The effect of temperature on the amount of bound water and, thus, the rheology of shales in the upper part of the geologic section (temperature below 40-50~ also should be investigated. (3) In the reviewed papers there were no thorough analyses and direct estimations of the precision of pressure determination by well-logging data. Whether or not calculated pressures are always or usually close enough to the actual values is not clear. During the geologic history, pressure abnormalities in shales and permeable formations can increase after some decline. In such a case, a definite relation between the pressure and porosity will cease to exist. Vertical fluid migration and increase in the oil and, especially, gas column heights can raise the pressure. Excess pressures due to the fluid column height also could reverse the pressure change trend. Vertical paths for the upward fluid migration and pressure redistribution (i.e., currently active and buried mud volcanoes, fractured zones, and faults) are numerous
92
A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH
in Azerbaijan. Upward migrating fluids, especially gas, can significantly increase pressure in the beds they intrude. As a result, the effective stress (total overburden stress minus the fluid pore pressure) is reduced, whereas porosity remains the same. Under such circumstances, well-logging methods may provide incorrect pressure values. Therefore, the effects of pressure increase, caused by vertical fluid migration, should be recognized and current pressure detection methods should be improved or, in some cases, substituted by other methods for such zones. Excess pressure, caused by the fluid column height, can also invalidate usage of (1) standard porosity/pressure relations, and (2) well-logging pressure determination methods in shales lying above such pools. To confirm their validity, investigators compared calculated pressures in shales with 'equilibrium' drilling mud pressures. Abnormal pressure gradients were mostly calculated from the weight of mud columns; therefore, pressure drops due to mud movement were not taken into account, although the head loss due to the friction is appreciable in most cases. In some papers, reference was made to a 'static mud pressure', which does not provide the necessary accuracy of pressure evaluation during drilling or a trip. Wellbore wall deformations also cannot be considered an ideal reference point. Plasticity of shales depends on (a) mineral composition, (b) amount and nature of bound water, and (c) the amount of 'dry' contacts and crystal bonds. Although the pressure excess over the hydrostatic pressure contributes to the plasticity of shales, it is neither the primary nor the only cause of plasticity. If wellbore pressure is lower than the pressure in shales saturated with gas, expansion of gas will contribute to heaving and sloughing of shale into the wellbore. But in the case of high plasticity, shale can flow into the wellbore, even without the presence of abnormal fluid pressure, just under the geostatic pressure of the overburden. Under such circumstances the 'equilibrium' pressure of the drilling mud cannot be used to confirm calculated pressures in shales and, thus, the validity of well-logging methods. Calculation from well-logs show pressure gradients of 0.015-0.018 MPa/m in very thin shale beds. It is not convincing that shale beds of about 1 to 6 m in thickness can sustain a pressure excess above that in the adjacent sand beds for a geological period of time. There is a real possibility that pressure in such shales, calculated from well-log measurements, was overestimated because of lithological changes in the shale from the external boundary of a layer to its center caused by normal cyclicity in sedimentation: sand content increases and porosity decreases from the center outward. Calculated pore pressure values decrease with time since the beginning of production (fluid withdrawal). If they respond to an additional pressure difference during such a short period of time, how could they maintain the pressure in geological time with a very significant difference between the shale and sand pore pressures? (4) In the Azerbaijan fields, calculated/measured pressures in shales are higher than pressures in the sandstone reservoirs. This is only possible if the reservoirs have a lateral conductivity high enough to discharge the excess volume of fluids to the surface or into shallow aquifers. Therefore, for data reliability evaluation and better pressure prediction, this conductivity and total regional and local hydrodynamic scenarios should be analyzed for each reservoir much more thoroughly than it was done previously.
ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS
93
DEFINITIONS OF TERMS AS USED IN THIS C H A P T E R
Hydrostatic (or normal)pressure: a pressure in a formation equal to the weight of the actual column of water from the measurement point to the surface or to the reference plane at an average elevation of the relief of area under consideration. The latter is much more convenient in many cases (Gurevich et al., 1987). Inasmuch as the groundwater table is nearly always not horizontal, the hydrostatic formation pressure is an ideal one. It always differs from the actual pressure and is used as a reference value only. The hydrostatic pressure gradient is obtained from the specific weight of fluid and, therefore, varies with depth according to the actual fluid density distribution. Abnormal pressure: a pressure that noticeably exceeds the hydrostatic one. Subnormal pressure: a pressure that is noticeably lower than the hydrostatic one. Free convection of a fluid: a flow of fluids caused only by non-equilibrium (in the field of gravity) distribution of their densities. Forced convection of afluid: a flow of fluids caused only by changes in fluid compression. Pressure prediction: indirect determination of pressure before penetrating the reservoir by a well and measuring reservoir characteristics. Pressure detection (indirect determination): indirect determination of pressure from values of other reservoir characteristics measured in a well penetrating the reservoir.
CONCLUSIONS
The major conclusions can be summarized as follows. (1) The authors recommend using their approach to a statistical correlation of pressure abnormality with geologic and physical characteristics: to subdivide pressure value into free and forced convection components and to correlate them with the factors that actually cause pressure increases. (2) A complete list of factors that cause the forced convection of fluids includes some important elements not mentioned previously by many investigators. They include: the piezo-convection effect, a major factor in areas and periods of intensive gas generation and migration; dependence of sand and clay compaction on both compacting force and reduction of rock matrix strength; and clay compaction caused by temperature increase. (3) Sets of geologic and physical parameters that can be correlated with pressure increase are recommended for the cases of compaction and upward fluid migration domination. These parameters present separately the ability of fluid-filled rock to change pressure under an external influence, the external influence itself, and permeability of formations.
94
A. GUREVICH, G.V. CHILINGAR,J.O. ROBERTSONAND E AMINZADEH
BIBLIOGRAPHY Abasov, M.T. (Ed.), 1991. Theory and Practice of Geologic-Geophysical Explorations and Production of the Offshore Oil and Gas Fields. Elm Publ., Baku, 428 pp. Ali-Zadeh, A.A., Salaev, S.T. and Aliev, A.I., 1985. Scientific Evaluation of Oil and Gas Prospects in Azerbaijan and South Caspian Zone and Direction of Exploration. Elm Publ., Baku, 252 pp. Aminzadeh, E, 1991. Where are we now and where are we going? In: E Aminzadeh and M. Simaan (Eds.), Expert Systems in Exploration. Soc. Explor. Geophys., Tulsa, OK, pp. 3-32. Anikiev, K.A., 1964. Abnormally High Reservoir Pressures in Oil and Gas Fields. Nedra Publ., Leningrad, 167 pp. Antonellini, M. and Aydin, A., 1994. Effect of faulting on fluid flow in porous sandstones: petrophysical properties. Am. Assoc. Pet. Geol. Bull., 3: 355-377. Asadov, M.N., Kheirov, M.B. and Azizova, Sh.A., 1988. Clays and clay minerals of South-Caspian Basin Middle Pliocene sediments. Azerbaijan Oil Business, 3: 9-14. Athy, L.E, 1930. Density, porosity and compaction of sedimentary rocks. Am. Assoc. Pet. Geol. Bull., 14: 1-24. Bourgoyne, A.T. Jr., 1994. Shallow abnormal pressure hazards. In: W.H. Fertl, R.E. Chapman and R.E Hotz (Eds.), Studies in Abnormal Pressures. Elsevier, Amsterdam, pp. 281-317. Bunyatov, J.B. and Imanov, A.D., 1989. Influence of clay minerals on sealing properties of caprocks in Apsheron-Pribalkhan tectonic zone. Azerbaijan Oil Business, 7: 5-9. Buryakovsky, A.A. and Djevanshir, R.D., 1985. Pore space structure of Cenozoic clays in Azerbaijan in relation to abnormal pressures in them. Lithol. Mineral., 1: 96-105. Buryakovsky, A.A., Djevanshir, R.D. and Aliyarov, R.Yu., 1986. Geophysical Methods of Geofluidal Pressure Exploration. Elm Publ., Baku, 81 pp. Buryakovsky, A.A., Chilingar, G.V. and Aminzadeh, E, 2001. Petroleum Geology of South Caspian Basin. Heinemann-Butterworth, Woburn, MA, 442 pp. Carstens, H., 1980. Abnormal Formation Pressure Detection: Limitations to the 'Porosity Tools'. Preprint, Norwegian Petroleum Society Seminar, Stavanger, April 17-18. Carstens, H. and Dypvik, H., 1981. Abnormal formation pressure and shale porosity. Am. Assoc. Pet. Geol. Bull., 2: 344-350. Chilingarian, G.V., 1991. Experimental results on the influence of electric fields on the migration of oil, ionic species and water in porous media, by F. Lancelot, H. Londiche and G. de Marsily - - Discussion. J. Pet. Sci. Eng., 5(3): 293-295. Chilingarian, G.V. and Wolf, K.H. (Eds.), 1975. Compaction of Coarse-Grained Sediments, I. Elsevier, Amsterdam, 552 pp. Chilingarian, G.V. and Wolf, K.H. (Eds.), 1976. Compaction of Coarse-Grained Sediments, II. Elsevier, Amsterdam, 808 pp. Chilingarian, G.V., Mazzullo, S.J. and Rieke, H.H., 1992. Carbonate Reservoir Characterization: A Geologic-Engineering Analysis, Part 1. Elsevier, Amsterdam, pp. 1-35. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast, Louisiana. Am. Assoc. Pet. Geol. Bull., 37: 410-432. Djevanshir, R.D., 1987. Relationships between clay minerals, low temperatures, high pore pressures, and oil and gas reservoirs at great depths in the Baku Archipelago, U.S.S.R.J. Pet. Sci. and Eng., 1: 155-162. Dobrynin, V.M. and Serebryakov, V.A., 1978. Abnormally High Formation Pressures Prediction Methods. Nedra, Moscow, 232 pp. Durmishian, A.G., 1972. On the abnormal pressures role in the formation of tectonic structures and deposits of oil and gas in the South Caspian Depression. Proc. USSR Acad. Sci., Ser. Geol., 5: 114-125. Dutta, N.C. and Franklin, K.L. (Eds.), 1987. Geopressure. Soc. Expl. Geophys., Ser., 7, 365 pp. Eaton, B.A., 1969. Fracture gradient prediction and its application in oilfield operations. J. Pet. Technol., 21(10): 1353-1369. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Fertl, W.H. and Chilingarian, G.V., 1989. Prediction of tectonically-caused overpressures by using resistivity and density measurements of associated shales. J. Pet. Sci. Eng., 1(1): 203-208.
ORIGIN OF FORMATIONFLUID PRESSURE DISTRIBUTIONS
95
Fertl, W.H., Chapman, R.E. and Hotz, R.E (Eds.), 1994. Studies in Abnormal Pressures. Elsevier, Amsterdam, 454 pp. Forbes, EL., Ungerer, E and Mudford, B.S., 1992. A two-dimensional model of overpressure development and gas accumulation in Venture field, Eastern Canada. Am. Assoc. Pet. Geol. Bull., 3: 318-338. Gurevich, A.E., 1972. Regional dynamics of groundwater. In: A.E. Gurevich, L.N. Kapchenko and N.M. Kruglikov (Eds.), Theoretical Principles of Petroleum Hydrogeology. Nedra, Leningrad, pp. 5-112. Gurevich, A.E., 1980. Handbook of Groundwater Motion Exploration. Nedra, Leningrad, 216 pp. Gurevich, A.E. and Chilingar, G.V., 1995. Abnormal pressures in Azerbaijan: A brief critical review and recommendations. J. Pet. Sci. Eng., 13(2): 125-135. Gurevich, A.E., Batygina, N.B., Kraichik, M.S. et al., 1987. Formation Fluid Pressure. Nedra, Leningrad, 223 pp. Gurevich, A.E., Chilingar, G.V. and Aminzadeh, E, 1994. Origin of the formation fluid pressure distribution and ways of improving pressure prediction methods. J. Pet. Sci. Eng., 12: 67-77. Hedberg, H.D., 1936. Gravitational compaction of clays and shales. Am. J. Sci., 31:241-287. Hottman, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., 17: 717-723. Hubbert, M.K. and Ruby, W.W., 1959. Role of fluid pressure in mechanics of overthrust faulting, I. Mechanics of fluid-filled porous solids and its application to overthrust faulting. Geol. Soc. Am. Bull., 70: 115-166. Jorden, J.R. and Shirley, O.J., 1966. Application of drilling performance data to overpressure detection. J. Pet. Technol., 11: 1387-1394. Kasumov, K.A., Dergunov, E.N. and Aleksandrov, B.L., 1976. Abnormal pressure origin in sections of Kyurovdag and Karabagly fields of Prikurinskaya Lowland. Geol. Oil Gas, 8: 39-43. Khalilov, N.Yu., Kerimov, A.N., Omarov, A.K. et al., 1988. On the origin of shallow epigenetic abnormal pressures in the Bulla-Sea field. Proc. VUZ, Oil and Gas, 7: 8-13. Kheirov, M.B., Davidbekova, E.A. and Djavadov, Ya.J., 1990. Reservoir and Sealing Rocks of Azerbaijan Mesozoic-Cenozoic Sediments. Reservoir Rocks at Greater Depths. Moscow, pp. 155-162. Kucheruk, E.V. and Lustig, T.E., 1986. Abnormal Formation Pressures Prediction and Estimation Based on Geophysical Data. VINITI, Moscow, 128 pp. Mekhtiev, Sh.E et al., 1988. Role of caprock permeability for oil and gas in formation and preservation of pools of hydrocarbons in the west slope of the South Caspian Basin. In: Geology, Exploration and Development of Oil and Gas Fields in Offshore Caspian Sea, pp. 57-62. Melik-Pashaev, V.S., Khalimov, E.M. and Seregina, V.N., 1983. Abnormally High Formation Pressures in Oil and Gas Fields. Nedra, Moscow, 181 pp. Mukhin, Yu.V., 1965. Clayey Sediments Compaction Processes. Nedra, Moscow, 200 pp. Powers, M.C., 1967. Fluid-release mechanisms in compacting marine mudrocks and their importance in oil exploration. Am. Assoc. Pet. Geol. Bull., 51: 1240-1254. Rieke III, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Elsevier, Amsterdam, 424 pp. Ruby, W.W. and Hubbert, M.K., 1959. Role of fluid pressure in mechanics of overthrust faulting, II. Overthrust belt in geosynclinal area of western Wyoming in light of fluid pressure hypothesis. Geol. Soc. Am. Bull., 70: 167-206. Samedov, EI., 1959. Oil Stones Field. Azerneshr Publ., Baku, 171 pp. Tkhostov, B.A., 1960. Initial Formation Pressures in Oil and Gas Reservoirs. Gostoptekhizdat, Moscow, 252 pp. Tkhostov, B.A., 1966. Initial Formation Pressures and Geohydrodynamic Systems. Nedra, Moscow, 268 pp. Weller, J.M., 1959. Compaction of sediments. Am. Assoc. Pet. Geol. Bull., 2: 273-310. Whittaker, A. (Ed.), 1985. Theory and Evaluation of Formation Pressures. IHRD Corp., Boston, 231 pp. Yakubov, A.A., Alizadeh, A.A. and Zeinalov, M.M., 1971. Mud Volcanoes of the Azerbaijan Republic (Atlas). Azerbaijan Acad. Sci. Publ., Baku, 201 pp. Yusuf-Zadeh, Kh.B., Dergunov, E.N. and Aliyarov R.Yu., 1979. Results of Exploration and Prediction of Abnormal Pressures by Well-logging Methods in the Offshore Fields of Azerbaijan. Review Information, Ser. Oil-Gas Geol. and Geophys. VNIIOENG, Moscow, 49 pp. Zamora, M., 1972. Slide rule correlation aids d-exponent use. Oil Gas J., 70(51): 68-72.
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Chapter 4
S M E C T I T E - I L L I T E TRANSFORMATIONS DURING DIAGENESIS AND CATAGENESIS AS RELATED TO OVERPRESSURES
L.A. BURYAKOVSKY,R.D. DJEVANSHIR,G.V. CHILINGAR,H.H. RIEKE III and J.O. ROBERTSON,JR.
INTRODUCTION In general, the properties of argillaceous rocks and the fluids contained in them are important indicators of future trends in the processes of postsedimentary transformations. The clay minerals, which compose argillaceous rocks, are sensitive to the formation pressure and temperature (thermobaric factors). The interstitial fluids (water, oil and gas) in shales also influence the degree and character of diagenetic 1 and catagenetic 2 transformations of clays. Of special interest are the young sedimentary basins, which are characterized by the presence of thick, rapidly accumulated sand/shale sequences. A vivid example is the South Caspian Basin (Buryakovsky et al., 2001), which is distinguished by a diverse and rather unique association of parameters: (1) an exceptionally high rate of sediment accumulation (up to 1.3 km m -1 yr-1); (2) a very thick (up to 25 km) accumulation of sediments with those of Quaternary-Pliocene age accounting for up to 10 km (sand-silt-shale); (3) abnormally high pore pressure in shales [average factor of abnormality ranges up to 1.8 (abnormality factor Ka = Pa/Pn, where Pa is the abnormally high pressure and Pn is the normal hydrostatic pressure)]; (4) low heat flow and low formation temperature (at depths in the order of 6 km the temperature is approximately 105~176 (5) an inverted character of the hydrochemical profile (the chemistry of water changes with depth from calcium chloride and magnesium chloride to sodium bicarbonate type, i.e., freshening of water with depth); and (6) wide development of mud volcanism. Argillaceous rocks make up 50-95% of the section and play a key role in determining the mineralogical, lithologic, geochemical, and thermobaric characteristics of the basin (Buryakovsky, 1974, 1993a,b,c,d). Cenozoic shales are widespread in the Azerbaijan and South Caspian Basin. Paleogene and Neogene argillaceous rock cores were recovered from deep onshore and offshore wells, exploratory and hydrocarbon producing wells, as well as the welllogging and field development data, in order to appraise the origin and history of abnormally high formation pressure in this area. 1Diagenesis includes all physical, chemical and biochemical processes, which occur in sediments after sedimentation and through lithification at near-surface temperature and pressure. 2 Catagenesis comprises all physical and chemical processes which occur in sedimentary rocks at high temperatures and pressures after lithification and up to metamorphism.
98
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
TABLE 4-1 Variation in montmorillonite/kaolinite and montmorillonite/chlorite ratios with depth (data obtained from N. Batachariya, in Eremenko and Neruchev, 1968) Depth
Montmorillonite/kaolinite ratio
Montmorillonite/chlorite ratio
1.0 to 0.4 0.4 to 0.1 0
Chlorites absent 0.7 to 3.3 and higher 0
(m) 1200 to 1500 1500 to 1650 >1650
2
Pressure, kg/cm IO0 !
200
300
!
I
400
800
E c'-
1200
11
8 6e ~ 7
~.4 e2
1600
-4,,,-
~=
2000
%
2400 2800
,CI 3200 Fig. 4-1. Variation of formation pressure with depth in Cambay Basin, India. 1-3 = Calol" 4 - 8 -- Navagam; 9 = Cambay; 10, 11 - Ankleshvar; 12 = Cosamba. (Modified after Eremenko and Neruchev, 1968, fig. 2, p. 8.)
According to Rieke and Chilingarian (1974), the AHFP in argillaceous sequences is often attributed to montmorillonite dehydration as it is altered to hydromica (illite). For example, according to N. Batacharya (in Eremenko and Neruchev, 1968, p. 8), in the Cambay Basin of India, where the geothermal gradient reaches 6.5~ m (about twice as high as those in the Volga-Ural region and West Siberia in Russia: 2.5 and 3.3~ m, respectively) montmorillonite disappears at depths of 1412 to 1500 m (see Table 4-1). Abnormal formation pressures in the Cambay Basin are presented in
99
SMECTITE-ILLITE TRANSFORMATIONS
%
2000
20 40 60
20 40 60
,,
'
9
'ca
c ;l ..
oo
o 9
E
3000
i
Cc)
9"
ea
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20 40 60
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II
i
i
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i
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;
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9
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9 9
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e 9
o
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9
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e 9
eee
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,
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e 9
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9
eJ
o
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9
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"~ e9
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Fig. 4-2. Contents of various clay minerals in the Productive Unit of the Baku Archipelago: (a) montmorillonite, (b) hydromica, (c) kaolinite, (d) chlorite, and (e) mixed-layered minerals. (Modified after Buryakovsky et al., 1995, fig. 4, p. 206.)
Fig. 4-1. On the other hand, field data in the South Caspian region, as discussed in this chapter, shows that a practically unaltered montmorillonite is present in the Baku Archipelago deposits at depths down to 6 km, i.e., throughout the entire drilled section (Fig. 4-2). This suggests a subordinate role of montmorillonite dehydration in the total process of AHFP development.
BURST'S COMPACTION MODEL A compaction model based on a three-stage dehydration sequence and the transformation of montmorillonite clay to mixed-layer varieties was proposed by Burst (1969). The initial dehydration stage is essentially completed in the first few thousand feet of burial as the interstitial water content is reduced to approximately 30% (20-25% interlayer water and 5-10% residual pore water) (Fig. 4-3). During the second stage, the argillaceous sediment is in a state of quasi-equilibrium as it continues to absorb geothermal heat. Pressure is relatively ineffective as a dehydrating agent because of the increased density of the interlayer water packet. As soon as the heat accumulation is sufficient to mobilize the interlayer water, one of the two remaining interlayers of bound water (statistically averaged) is discharged into the bulk system. Burst (1969, p. 80) stated that the amount of water in movement should constitute 10-15% of the compacted bulk volume. During the third stage, the final water increment, having approximately capillary water density, gradually is forced out of the clay mineral lattice and voids as sediment temperature increases. Burst's dehydration-compaction model was discussed by Rieke and Chilingarian (1974).
] 00
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR Recent density
burial =
1.32
~
-v
Pore w a t e r
~
~
~
Interlayer
water
[-:.~--'--2"1
Swelling c l a y solids
t
"~""~'~~
I
~
~
~
~
~
After
l ~ ~
....
_
..... s,ooe,
~
20-/,, ~
- ...... ~ -----
_
.p
N o n - c l a y solids
I st
dehydration density = 1.96 L_ . . . . . ;;, ~ ..
~:.'zT~.:T:.l
c l a y solids
Non-swelling
x~
"-..
"" -.-.
After 2 n d dehydration
dens ity = 2. 28
"- - ~ ~ V o ~ - - . .
/
........ s,ooe,,
Aft e r. 3r.cl
~.
~:4 ............ 9........ ~ ........................... ;;:~.
"I"
dehvaraTion .
.
.
.
.
.
.
.
.
:~~IU:~i~C."~.~.~ ..-~ ..................... ........
s,ooe,,,
Fig. 4-3. Marine shale bulk composition during dehydration. (Modified after Burst, 1969, fig. 6. p. 81.)
ORIGIN OF ABNORMALLYHIGH FORMATIONPRESSURE Abnormally high formation (pore) pressure (AHFP) in reservoirs is known to be caused by several diverse factors. Buryakovsky et al. (1995) suggested that the most probable mechanism for development of AHFP, in regions with thick terrigenous sedimentary rocks (sand/shale sequence), is rapid sedimentation and gravitational
SMECTITE-ILLITETRANSFORMATIONS
101
E
Q
c-
Akchagyiian to A p s h e r o n i a n Quaternary Deposits
I0
20
30
40
50
i
i
I
;
i
70
60 I
80
90
I
I
1200
-
2000
-
2800
-
3600
-
4400
-
5200
-
r .m
> t~
I
400
E .mO .m
MPa
100
F•
Shales
r ~
Reservoir Rock
(1) (3. o. or (1) :3 o" (!) r
(1) > o :3 "(3
o
IX.
VII Horizon
~ 6000
-
.
~
.,,~
Fig. 4-4. Pore fluid pressure gradient, ~ (in MPa/m) in shales and in reservoir rocks in the Baku Archipelago. (Modified after Buryakovsky et al., 1995, fig. 2, p. 205.)
compaction. This leads to significant underconsolidation (undercompaction) of rocks and to development of AHFE In this process, abnormal pressures in reservoir rocks are caused by those in shales and approach each other only in moderately thick beds. The regionally developed reservoirs have a better pressure distribution than that in shales; consequently, their pore pressure is usually lower than that in the enclosing shales (Fig. 4-4). In the South Caspian Basin, the drilled Pliocene terrigenous section is 6.5 km thick, with AHFP unevenly distributed, both vertically and laterally. Presence and intensity of AHFP are determined by lithofacies of the oil- and gas-beating rocks, tectonics (uplifts), feasibility of underground water discharge and other factors. The highest clay content (up to 95%) has been observed in the Productive Unit of the Baku Archipelago. An important regional feature is the very high porosity of argillaceous rocks, much higher than those at similar depths in other areas of the world (Buryakovsky et al., 1982, 1986, 1995; Dzhevanshir et al., 1986). Porosity of Pliocene shales in Azerbaijan at depths of
102
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
Porosity, IE
0.001 o
2 I
3 4 56 I
I
I
0.01
I I I II
2 I
3 4 56 I
[
I
I II
0.1 II
2
3
,,,,.
:::I::: 7
i
.,,,..
"-
2000
0
,2 ~
6, 'S
r,,
r
400C
6000
Fig. 4-5. Relationship between porosity (r %) and depth of burial (H, m) (Weller, 1959); 2 = Mesozoic (Proshlyakov, 1960, and Dobrynin, 1970); 3 (Vassoyevich and Bronovitskiy, 1962); 4 - 6 -- Middle Pliocene (Durmishyan, Archipelago; 5 = South Apsheron Offshore Zone; 6 -- Baku Archipelago (Modified after Buryakovsky et al., 1995, fig. 3, p. 206.)
for shales. 1 - Devonian = Oligocene to Miocene 1973a,b) (4 - Apsheron and Lower Kura region).
4.0-5.5 km is several times higher than in consolidated shales present in other regions (Fig. 4-5). Such a difference is due to geological age, relative contents of clay and sand, temperature and other factors. The abnormally high porosity of Apsheron Archipelago shales is primarily a result of slower rate of compaction as compared to the subsidence rate, due to the slow pore water removal from the compacting argillaceous rocks during rapid sedimentation rate. This process was critical in the development of AHFP in the South Caspian Basin. Numerous initial formation pressure measurements in reservoir rocks and wireline logging determination of pore pressure in argillaceous rocks reveal a pattern of AHFP distribution throughout the section at the northwest flank of the South Caspian Basin (Table 4-2). The average gradients of initial formation pressures in the reservoir rocks, r/res, and of pore pressures in shales, rich, at the investigated depths, are (in MPa/m): 0.0106 and 0.0120 for the Apsheron Archipelago; 0.0119 and 0.0145 for the South Apsheron Offshore Zone; and 0.0138 and 0.0182 for the Baku Archipelago and Lower Kura region. A substantial difference between the initial formation pressures in reservoir rocks and pore pressures in shales (by a factor of over 1.5) exists in the Baku Archipelago, where the average thickness of shales, hsh, is particularly higher than in the other regions of Azerbaijan. Generally, AHFP rises with the relative content of shales, Xsh, throughout the section (Table 4-2) and within the reservoir (Fig. 4-6). The highest shale pore pressures are associated with shale sequences in the Baku Archipelago
9
e~0
9
r
9
,
.. +..a
9
o~
Apsheron Archipelago
South Apsheron Offshore Zone
Baku Archipelago and Lower Kura region Vies
(MPa/m)
(MPa/m)
50 40 30 20
12 8 5 3
0.0122 0.0125 0.0120 0.01 10
0.01 I6 0.0108 0.0100 0.0098
250 235
15 12 10 8
0.0137 0.0146 0.0149 0.0 148
0.0 124 0.0119 0.0116 0.01 16
900 725 460 350
21 18 16 13
O ~
O
O
~
oO
0.0135 0.0137 0.0 140 0.0142 O
~ o ~ o
~
~
q'~ ~
O
O
~
I50
r
185
0.0167 0.0179 0.0187 0.0 193
o ~ o ~
qsh
(%)
~
'$%h
(m)
r
hsh
(MPa/m)
O
Dies
(MPa/m)
O
l)$h
(%)
O
d%h
(m)
o ~ o
hsh
(MPa/m)
tt~
rlres
(MPa/m)
oO
O
O q'~
%h
(%)
O q'~ q'~ O Ig') r162 oO Ig'3 r r ,---~ ,---~
~
dJsh
(m)
~
O ~ r162 "r
h h
~.C~ oO
O O
~ r
2000 3000 4000 5000
,.azZ
(m)
~<
9
Depth
.,-.~
Variation with depth (m) of average thickness of shales, h5h, shale porosity, &,, pore pressure gradient in shale, qd,, and pore pressure gradient in reservoir rock, vies, in the Apsheron Archipelago, the South Apsheron Offshore Zone and the Baku Archipelago and Lower Kura region (after Buryakovsky et al., 1995, table 1, p. 207)
SMECTITE-ILLITE TRANSFORMATIONS
TABLE 4-2
103
104
L.A. BURYAKOVSKY,R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
0.01
/ /
E o
a.
00 ' 16
-
/ 6
5
4
/
o 0.014
/ 0.012 J
J
0.010
-
1
1
1
0
20
40
60
80
Xsh, % Fig. 4-6. Pore pressure gradient (r/, MPa/m) as a function of clay content (X~h, %). 1-3 -- argillaceous rocks (1, 2 and 3: lII, IV and V sedimentary rhythms); 4 = aquifers; 5 = oil-bearing sandstones; 6 gas-bearing sandstones and siltstones. (Modified after Buryakovsky et al., 1995, fig. 5, p. 207.)
and Lower Kura region with their extraordinarily high porosity, ~sh, owing to rapid sedimentation and slow compaction. The formation of abnormal pore pressures in the shales of Azerbaijan has been experimentally demonstrated by elastic compression of hermetically isolated cores of Cenozoic shales. Fig. 4-7 shows that pressure in the core rises with the external pressure and then decreases as the confining pressure decreases, but always remaining higher than in the case of increasing load, evidently as a result of residual (irreversible) deformation of the rock. Abnormally high pressures in the argillaceous sequences may substantially affect geological processes at depth. It appears that they have played an important part in folding, clay diapirism, mud volcanism and earthquakes. Models of these phenomena are described by Coulomb's law and by rheological models of various theoretical bodies. According to Coulomb's law, resistance to shearing in shales is the first power function of normal compressive stress. As the abnormal pore pressure in shales increases, the intergranular stress (effective stress) decreases, down to very low values under certain conditions. Resistance to shearing determined by friction decreases correspondingly. This leads to an intergranular sliding and facilitates to a considerable degree the devel-
105
SMECTITE-ILLITE TRANSFORMATIONS
0 D_
~176
_
50
.g !._
30
I:1. (J,)
lO
0
I 30
I0
I 50
External Pressure
I 70
I 90
MPa
Fig. 4-7. Experimentally determined relationship between the pore pressure (Ppor, MPa) in an argillaceous rock core and the external (total overburden, confining) pressure (or, MPa). (Modified after Buryakovsky et al., 1995, fig. 6, p. 207.)
opment of shearing. In such instances, plastic argillaceous sequences can become quite mobile under high shale pore pressure and are displaced. Depending on the geological environment and duration, this process may lead to the development of folds, diapirs, mud volcanoes, and earthquakes. In Azerbaijan, such geologic set-up is quite typical of thick Paleogene to Miocene argillaceous sequences with extremely high, quasi-geostatic values of AHFP, with shale pore pressure gradients of 0.020-0.023 MPa/m. The undercompacted character of Cenozoic shales in Azerbaijan implies that their sealing properties are determined mainly by their AHFP and still continuing squeezing out of pore water. The progressively rising capillary pressures, as the pore channel diameters decrease, determine the sealing properties of argillaceous rocks.
CLAY-MINERAL TRANSFORMATION
Pliocene shales and argillaceous rocks were studied at depths of 1400 to 6000 m at various locations of the Apsheron Peninsula and Apsheron Archipelago, South Apsheron Offshore Zone, Baku Archipelago and Lower Kura region (Buryakovsky and Dzhevanshir, 1985, 1986; Buryakovsky et al., 1988). The pelitic fraction of argillaceous rocks, i.e., the fraction with a particle size of less than 0.01 mm, accounts for 51-83% (average of 69%) of the total rock mass. The sand fraction of argillaceous rocks accounts for 1.5% on the average; the content of the silt fraction in these rocks ranges from 11 to 50% (average of 21%); and the average content of the carbonate cement is 10%. At a depth of 2000-6000 m, the porosity of normally consolidated argillaceous rocks fluctuates within the 12-3% range, whereas the porosity range for the unconsolidated rocks is 28-10%. The corresponding permeability ranges are (7.5-0.36) x 10 -7 mD and (230-6.2) x 10 -7 mD.
106
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
With increasing depth, the pore size of shales progressively decreases according to the following equation: dMe --
4.6e -~
(4-1)
where dMe is the median pore size (in lxm); and H is the depth (in km). Most of the clay minerals in the Productive Unit of Middle Pliocene age belong to the montmorillonite and hydromica groups. The kaolinite content varies from 15 to 20%, chlorite from 5 to 10%, and mixed-layered minerals, from traces up to 5%. The X-ray analysis showed the variations in clay mineral contents with depth, with no clear-cut regularity. Montmorillonite is present in large amounts (40% on the average, reaching 75% in individual samples) throughout the Productive Unit. This means that there has been no obvious transformation of montmorillonite to hydromica in these clays, at least down to a depth of 6200 m. Table 4-3 (with regard to the depth of occurrence) and Tables 4-4 and 4-5 (with regard to the location) present data on montmorillonite, hydromica and other clay mineral contents in sedimentary rocks of the Apsheron Archipelago (Neftyanye Kamni-2, Gryazevaya Sopka, Banka Yuzhnaya-2 and Gyuneshli offshore areas), the South Apsheron Offshore Zone (Bakhar oil and gas field), the Baku Archipelago (Sangachaly-mor6, Duvanny-mor6, Bulla Island, Bulla-mor6, Alyaty-mor6, Khamamdag-mor6, Garasu, Sangi-Mugan, and Kamen Persiyanina offshore areas), and the Lower Kura region (Kyurovdag and Karabagly onshore areas) (see Buryakovsky et al., 2001). Oligocene through Miocene shales of the Muradkhanly oil field (Middle Kura Trough) have been studied onshore. The cores of Chokrak rocks were studied from a depth of 2825-2830 m: montmorillonite and mixed-layered clay, with chlorite, hydromica and volcanic ash. Organic matter is represented by skeletons of marine microorganisms (coccoliths). The rock is fairly loose and unconsolidated. The Maikop rocks have been studied on cores taken from depths of 3080-3085 m and 3287-3292 m. These rocks of marine origin contain montmorillonite clay with some ash. The ash (volcanic glass) is often altered to montmorillonite. Broken grains of pyroxenes and amphiboles with a typical cleavage are locally present. Montmorillonite, chlorite and mixed-layered clays are widespread. The observed distribution of clay minerals is due to different sources of clastic material brought to the separate portions of sediment accumulation basin, the predominantly allothigenic origin of clay minerals, and the variations in the rate of sedimentation. The Russian Platform, the Kilyazi-Krasnovodsk Zone of uplift, and islands, which existed north of the Apsheron Peninsula and Archipelago, as well as the southeastern slope of the Greater Caucasus served as the primary source regions for clastic material for the Apsheron Peninsula and the adjacent Caspian Sea. The more ancient (MesozoicPaleogene) magmatic and sedimentary rocks of the mountain massifs of the Greater and Lesser Caucasus and Talysh Mountains served as the primary source of sediments for the Lower Kura region and the Baku Archipelago. Montmorillonite and hydromica-montmorillonite minerals may be transformed to hydromicas during diagenesis and catagenesis, as has been described for almost all major sedimentation basins throughout the world. These changes in clay minerals during catagenesis are most probable (not simply possible, as in diagenesis), due to the
SMECTITE-ILLITE
Contents of various clay minerals in the Apsheron Archipelago oilfields, variation with depth of porosity (&,), are shown in parentheses (after Buryakovsky et al., 1995, table 2, p. 208)
permeability
and pore size; average values
Depth range
Clay-mineral content (%)
(m)
Montmorillonite
Hydromica
Kaolinite
Chlorite
Mixed-layer
1000-2000
10-45 (32.5)
35-65 (43.5)
15-20
5-10 (6.5)
Traces
(1 7.5)
1.7-3.9 (2.7)
2000-3000
35-70 (45.0)
20-40 (35.0)
0-15 (13.0)
0-10 (7.0)
Traces
1.3-3.1 (2.1)
30004000
15-50 (36.0)
30-60 (42.0)
5-20 (7.0)
5-15 (7.0)
1.0-2.5 (1.6)
4000-5000
15-70 (40.0)
10-60 (38.0)
0-20 (12.5)
0-10 (5.5)
0.7-2.0 (1.3)
5000-6000
5-65 (39.0)
20-65 (39.0)
0-30 (15.5)
0-15
0.5-1.5 (0.8)
5-70 (36.0)
20-60 (37.5)
10-25 (15.5)
0-10 (4.0)
More than 6000 m
Porosity
(k\h)
(5.0)
Permeability mD)
TRANSFORMATIONS
TABLE 4-3
Pore size (wm)
107
108
L.A. BURYAKOVSKY,R.D. DJEVANSHIR,G.V. CHILINGAR,H.H. RIEKE III AND J.O. ROBERTSON,JR.
TABLE 4-4 Variation of the geothermal gradient and pore pressure gradient in sedimentary rocks with depth (average values are shown in parentheses) (after Buryakovsky et al., 1995, table 3, p. 210) Depth range (m)
Pore pressure gradient (MPa/m)
Geothermal gradient (~
1000-2000
0.012-0.020 (0.016)
10-15 (12)
2000-3000
0.013-0.021 (0.017)
10-12 (11)
30004000
0.014-0.022 (0.018)
8-11 (10)
4000-5000
0.015-0.023 (0.019)
15-19 (17)
5000-6000
0.015-0.023 (0.019)
21-21 (22)
More than 6000
0.016-0.024
15-25
(O.O2O)
(2O)
rise in temperature and pressure as the sediments are buried. Consequently, during late catagenesis, the clay-mineral assemblage consists of two components (hydromica and chlorite), no matter what was the initial composition. On the other hand, virtually unaltered montmorillonite has been observed at great depths and in large amounts (Kheirov, 1979). Kheirov explained the almost unaltered montmorillonite found at a depth of 6026 m in the Pliocene beds of the Baku Archipelago as due to specific sedimentation conditions, the composition of the initial material and the effects of abnormally low temperature, i.e., these sediments lie in the early diagenetic zone. Possibly a lack of potassium in interstitial solutions has also played an important role. Of great importance is the study of regularities in the distribution of clay minerals over the entire section, the identification of basic factors influencing the transformation of montmorillonite to illite, and the prediction of catagenetic changes at greater depths not yet reached by boreholes. It is important to note that the results do not always allow one to judge correctly the origin of clay minerals, i.e., whether they are primary or secondary throughout the depth range. For example, Millot (1949) noted that the montmorillonite formed in the final stage of hydromica degradation does not differ very greatly from true montmorillonite, the X-ray characteristics being the same. Of interest are the photomicrographs of freshly broken surfaces of shales and argillaceous rocks of the Productive Unit of the Baku Archipelago (depths of 14005200 m) recorded with a scanning electron microscope (SEM). The surfaces were examined in sections parallel, perpendicular and oblique to the bedding. The mineral compositions of these rocks are on the whole the same throughout the depth range. The main clay minerals are hydromica and montmorillonite, with subordinate amounts of
TABLE 4-5 Contents of various clay minerals, pore pressure gradient in shales, and geothermal gradient in the various oil and gas fields of Azerbaijan and the South Caspian Basin (average values are shown in parentheses) (after Buryakovsky et al., 1995, table 4, p. 210) Clay mineral content (%)
Area
Pore pressure gradient
Geothermal gradient C'CIkm)
Montmorillonite
Hydromica
Kaolinite
Chlorite
Mixed-layer
(MPa/m)
Gryazevaya Sopka
10-35 (24)
45-60 (51)
20
Trace-5 (3.8)
Trace
0.0135
Gyuneshli
40
40
15-20 (17.5)
Trace
Trace-5 (2.5)
0.0146
5-60 (41)
10-35 (24)
10-35 (24)
Trace-15 (6)
Trace-5 (1)
0.0171
30-75 (49)
10-45 (28)
10-15 (12.5)
Trace-10 (5)
Trace
0.0176
40-75 (53)
10-53 (23)
Trace-20 (12)
Trace- 15 (10)
Bibieibat
Bakhar Sangachaly-Duvanny-Bulla
Kyurovdag, Karabagly
Island
0.0176
16.0
110
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
kaolinite and chlorite. The rocks have a honeycomb-like texture, which is clearly seen in oblique sections. The SEM results indicate that there are both 'forward' and 'reverse' clay-mineral transformations, which occur simultaneously as the rocks are buried. The cores from depths of 1400-1800 m show only very slight changes in the clay minerals, although one can identify damaged sublayers (twisting) at the edges, as well as secondary pores and cracking in some hydromica grains. There are also microcavities produced by secondary (diagenetic) processes. Cores from depths greater than 4000 m show more signs of transformation. Hydromica and montmorillonite predominate, with the montmorillonite being both primary and secondary. The latter occurs in the interstices between the hydromica grains and at their edges and cracks. The primary montmorillonite is disrupted or twisted at the edges and the secondary pores are present. These Pliocene beds thus show degradation not only of the primary montmorillonite but also of the hydromicas, which change to montmorillonite. This paradoxical observation is probably largely responsible for the retention of the same ratio of hydromica to montmorillonite at depth. Transformation of clay minerals during catagenesis is a complicated process, proceeding over a long period of geologic time under the influence of interrelated and interdependent natural factors. It is extremely difficult to recognize the effect of each of these factors, i.e., to give a quantitative estimate of their degree of influence. One of the paths toward the solution of this problem is the utilization of data from the detailed study of the composition and structural features of clay minerals, with inclusion of the complex of contemporary methods of mineralogical investigation, performed on a representative sample of clays from the studied stratigraphic section. The effect of thermobaric and hydrochemical factors on the postsedimentary (diagenetic and catagenetic) alteration of Pliocene clays in this region should be studied using the data on chemical analyses of formation waters, formation temperatures and pore pressures in clays determined by logging methods.
EFFECT OF THERMOBARIC CONDITIONS
The abnormally low temperatures might be responsible for the absence of clear-cut clay-mineral transformation. It has been shown by Khitarov and Pugin (1966) and Magara (1968) that temperature is a basic factor influencing montmorillonite degradation. Also of interest is the effect of hydromica degradation on the geothermal characteristics. Inasmuch as the clay hydration is exothermic, there may be elevated gradients in the depth ranges where the hydromicas are degraded under otherwise equal conditions. Temperature measurements in deep wells in the South Caspian Basin areas and onshore of Azerbaijan are of interest. In studied section, the average geothermal gradient is approximately 16~ and the temperature at a depth of about 6 km does not exceed 110~ A characteristic feature is that the gradient becomes lower at a depth of approximately 3-4 km (Table 4-4). The increased gradient at a depth below approximately 4 km may be related to hydromica degradation, which releases heat. At this depth, the degradation rate exceeds
SMECTITE-ILLITETRANSFORMATIONS
1 11
(A)
(B)
~,~ 60
~--- 40
~
O
J
E
cO
9
20
r
,.I,--
~
14
I
I
I
18
22
26
Geothermal Gradient (G), ~
0.012
[ 0.014
I 0.016
t 0.018
I
Pore Pressure Gradient (qpor), MPa/m
Fig. 4-8. Dependence of montmorillonite content (M, %) on the (A) geothermal gradient and (B) the pore pressure gradient in shales. (Modified after Buryakovsky et al., 1995, fig. 7, p. 211.)
some limit, which causes hydration to predominate over dehydration. Attention should be given, therefore, to the effects of temperature on diagenetic and catagenetic processes. A temperature increase accelerates the process of montmorillonite degradation, which, in turn, favors its catagenetic transformation into non-swelling minerals (hydromica and chlorite). Consequently, sections with a high geothermal gradient should be characterized by small montmorillonite content. On the other hand, inasmuch as a temperature decrease retards the process of montmorillonite degradation, sections with low geothermal gradient should be characterized by high montmorillonite content. Table 4-5 and Fig. 4-8A demonstrate the dependence of montmorillonite content on the geothermal gradient in shales of the South Caspian Basin. The greatest montmorillonite content is found in the shales of the Baku Archipelago and Lower Kura region, which is characterized by a low geothermal gradient (16~ The Apsheron Peninsula and the adjacent offshore areas, having a higher geothermal gradient (24.028.5~ are characterized by lower montmorillonite contents. The low temperature apparently does not favor the transformation of montmorillonite to hydromica, which reduces the montmorillonite degradation rate. Under otherwise equal conditions, the transformation should increase with depth, which means that some additional factors must be influencing the transformation. Inasmuch as the transformation of montmorillonite into hydromica proceeds with the removal of interlayer water, conditions at which desorbed water leaves the pore space without hindrance will be favorable for the development of this process. Every factor opposing the withdrawal of fluids from the interlayer space of clays, therefore, may lead to slowing down or cessation of the reaction of transformation of montmorillonite into hydromica or chlorite. Possibly, such a factor is the abnormally high pressure, which occurs virtually throughout the section. The pressure gradients in the pores of shales at 1000-6000 m are based on more than 2000 determinations and range from 0.012 to 0.024 MPa/m, with a mean of 0.018 MPa/m (see Fig. 4-4 and Table 4-4).
] ]2
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
E:L "13 N t,f)
~) !,---o
~~
2
E
O
~
"13
I
I
2
4
Depth (H), km Fig. 4-9. Variation of median pore size (dMe, ~tm) in shales of the Baku Archipelago with depth (H, km). (Modified after Buryakovskyet al., 1995, fig. 8, p. 212.)
The dependence of the montmorillonite content on the pore pressure gradient in shales is shown in Fig. 4-8B (also see Table 4-5). There is a close correlation between these two parameters. In the regions of the Baku Archipelago and Lower Kura region, characterized by intense development of AHFP (pore pressure gradients in shales of 0.018-0.019 MPa/m), the montmorillonite content in shales in the section reaches an average of 53%. In regions with moderate development of AHFP (Apsheron Archipelago and the South Apsheron Offshore Zone), the montmorillonite content decreases to 17%. There is no adequate discussion in the literature on the role of pore pressure in shales on clay-mineral diagenesis and catagenesis. It can be shown theoretically that rising pressures reduce the dehydration rates. The production of hydromica in clays, therefore, involves an increase in the free water volume by the release of bound water, which is denser than free water. A factor opposing this volume increase (such as high pore pressure in shales) will reduce the dehydration rate. On the other hand, AHFP can lead to hydromicas degrading to secondary montmorillonite by the absorption of water. Under such conditions, reduced grain size of the clay minerals favors degradation of hydromica, which occurs in this section, as shown by the relationship between the pore size and depth (Table 4-3 and Fig. 4-9; pore sizes were determined from SEM data). The writers propose the following scheme for the relationship between clay-mineral transformation and the thermobaric conditions. In a basin where the subsidence rate is equal to the accumulation rate, the depth at which diagenetic transformation (desorption of water) begins remains stable and is largely determined by the geothermal gradient. Inasmuch as the desorbed water has a greater volume than the interlayer water, abnormally high pressures may develop if the water cannot escape. Under some conditions, the rising pore pressure
SMECTITE-ILLITETRANSFORMATIONS
1 13
in shales may reduce the montmorillonite dehydration rate and release of water. The result will be similar to that from a low geothermal gradient, i.e., reduction in the rate of hydromica formation with depth. Under favorable conditions, the hydromicas may also be hydrated; this is accompanied by a release of heat and leads to their transformation to a secondary montmorillonite. The relative magnitudes of desorption of water and hydromica hydration may determine the rate of development of anomalous pressure. The sedimentation rate and sediment sources do not remain constant with time; some zones may differ in the dehydration rate because of changes in the sedimentation rate or type of sedimentary material. Transitions from a zone with normal pressures and normal dehydration rate to an AHFP zone may indicate either diagenetic and catagenetic processes, or a lag in the development of diagenetic and catagenetic processes. The montmorillonite content may remain the same or even increase with depth, but this does not necessarily mean that the process of dehydration of montmorillonite to hydromica is replaced by the hydromica hydration, although this is possible. Instead, it could mean that dehydration process in the AHFP zones is slow; therefore, these zones may be characterized by higher montmorillonite contents than those in younger zones of normal shale pore pressure.
EFFECT OF HYDROCHEMICAL FACTORS
The hydrochemical environment in a basin of sedimentation has a significant influence on the intensity of postsedimentary transformation. First it is important, therefore, to ascertain the nature of the hydrochemical regime observed in the Cenozoic complex of the South Caspian Basin, namely: whether it is a consequence of diagenetic and catagenetic processes in shales and the transformation of clay minerals, or it is formed predominantly as a result of the action of other factors. In this connection, the problem presenting the greatest interest is the origin of the inverted hydrochemical profile in the section of the South Caspian Basin, i.e., replacement of deep calcium chloride waters by little-mineralized sodium bicarbonate waters. Numerous data from laboratory analyses and field observations indicate a decrease in the mineralization of pore waters in sands with depth. Replacement of calcium chloride water by alkali sodium bicarbonate water is characteristic for the AHFP zones in the South Caspian Basin areas (Buryakovsky, 1974). Analogous data on the decrease of formation water salinity with increasing pressure have also been noted in the Gulf of Mexico (Fertl, 1976). According to Chilingar (1957) the relationship between the chemical composition of the Apsheron Peninsula waters and the stratigraphic depth is subject to the following rules. (1) The mineralization of water decreases with stratigraphic depth (also see Rieke and Chilingarian, 1974, pp. 265-269; Samedov and Buryakovsky, 1966). (2) CI-, Ca 2+, and Mg 2+ ions decrease with depth. (3) (Na + + K +) and (HCO~- + CO 2- + H. K-) ions gradually increase with depth. (4) The transition from hard to alkaline waters occurs at maximum concentration, not exceeding 0.1 g-equ per 100 g of water (5-6.5~ As a rule, the waters are hard at concentrations above 0.1 g-equ. (5) The HCO~- content
114
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
(in g-equ) does not exceed the C1- content. (6) Usually, the waters do not contain the SO 2- anion (A/ < $1). If present, however, its concentration does not exceed 0.0004 g-equ per 100 g of water. Mekhtiev (1956, in Rieke and Chilingarian, 1974, p. 265) also showed that in the Azerbaijan oil fields mineralization of waters is decreasing with stratigraphic depth and calcium chloride waters rC1- - rNa + >1 rMg 2+ where r is percent equivalent, are gradually replaced by bicarbonate waters rNa + - rC1rSO z-
>1
For magnesium chloride type of water rC1- - rNa + <1 rMg 2+ For details on classification of waters, see Chilingar (1956, 1957, 1958), Samedov and Buryakovsky (1966), and Buryakovsky (1974). The appearance of hydrochemical inversion in this section of the South Caspian Basin sediments may be explained by a genetic connection of the hydrochemical regime with the development of abnormally high pore pressures in shales. As shown by data presented in Table 4-5, the most intense AHFP development is characteristic for the Baku Archipelago and Lower Kura regions, where the water is primarily of the sodium bicarbonate type. Pore water chemistry is determined by the compaction processes in argillaceous rocks and the squeezing out of pore water (see Chilingarian et al., 1994). In turn, hydrochemical factors influence the processes of diagenetic and catagenetic transformation of clay minerals. Fig. 4-10 shows the dependence of montmorillonite content on the total salinity of the formation water for the two types of pore solutions in sands which are characteristic for the South Caspian Basin: calcium chloride and sodium bicarbonate. As shown, a direct relation exists for the sodium bicarbonate water, i.e., with decreasing water salinity, the conditions for preservation of montmorillonite are improved and its content in the clays is increased. Increase in the total salinity of water is caused by the increase in the content of carbonate and bicarbonate salts of alkali-earth metals. Sodium bicarbonate type waters are present in the Baku Archipelago and the Lower Kura region, as well as in the rocks from the lower division of the Productive Unit of the Apsheron Peninsula and adjacent offshore area, i.e., sections in which the argillaceous rocks are characterized by increased montmorillonite content. There is an inverse relationship between the montmorillonite content and the presence of calcium chloride type waters. The chloride content, in particular sylvite (KC1), increases with increasing water salinity. As shown, the alkali medium is favorable for the formation and preservation of montmorillonite. This was also confirmed by the results of computer geochemical simulation (Buryakovsky et al., 1990). A program RAMIN in PL-1 language was utilized, which is similar to the geochemical model proposed by Kharaka and Barnes (1973). The program RAMIN makes it
SMECTITE-ILLITE
1 15
TRANSFORMATIONS
0
2
o ~
0
6O
,e-C" 0 o
~9 0 .~-.
40
0
E
.I,-. C" O
20
10
Interstitial Water Salinity (S), g/I Sodium bicarbonate 1
30
Calcium chloride 2
Fig. 4-10. Relationship between the montmorillonite content (M, %), and the interstitial water salinity (S, g/l). 1 = sodium bicarbonate; 2 = calcium chloride. (Modified after Buryakovsky et al., 1995, fig. 9, p. 213.)
possible to simulate the equilibrium distribution of a majority of elements present in the pore solutions at temperatures up to 350~ on the basis of data on the chemical composition of formation water, temperature, pH and Eh. For the determination of the possibility of dissolution or precipitation of one or another mineral, calculation of A G values (Gibbs' free energy difference) is included in the program. The results of the chemical analyses of formation water in two wells (No. 96 and No. 521) of the VII Horizon of the Sangachaly-mor6-Duvanny-mor6-Bulla-island oilfield served as initial data for computer-based simulation (Table 4-6). Average depth of burial and formation temperature for the two wells are: well No. 9 6 : - 3 0 9 1 m, +80~ well No. 5 2 1 : - 4 3 2 0 m, +97~ The pH value for the studied conditions averaged 7.0-7.5. Table 4-7 gives the results of the determination of the Gibbs' free energy difference A G for various clay minerals. As shown, within the pH interval of 6 to 8, in most cases the A G values for minerals of the montmorillonite and kaolinite groups exceed zero. This indicates a possibility of their authigenic origin. The values of A G for
116
L.A. BURYAKOVSKY,R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
TABLE 4-6
Chemical analyses of formation waters in wells No. 96 and No. 521 of the VII Horizon of the Sangachalymor6-Duvanny-mor6-Bulla-mor6 oil and gas condensate field (after Buryakovsky et al., 1995, table 5, p. 214)
Anions
Concentration
Cations
(mg/1) C18042 HCO 3 CO32 RCOO-
Concentration (mg/l)
709.0 211.2 195.2 36.0 17.7
Ca 2+ Mg 2+ Na + + K + A13+ SiO2
8.02 2.44 618.7 <0.1 70.0
TABLE 4-7
Gibbs free energy difference (AG) for various clay minerals at different pH (modified after Buryakovsky et al., 1995, table 6, p. 214)
Mineral
Well No. 96:
Ca-montmorillonite K-montmorillonite Na-montmorillonite Kaolinite Well No. 521:
Ca-montmorillonite K-montmorillonite Na-montmorillonite Kaolinite
AG pH = 6
pH -- 7
pH -- 8
7.34 6.97 7.44 7.38 5.91
5.46 5.08 5.55 5.49 3.84
1.99 1.60 2.08 2.01 0.48
6.14 5.61 5.94 6.21 4.72
3.20 2.67 3.00 3.27 1.37
-0.52 - 1.07 -0.72 -0.47 - 1.84
hydromica are always less than zero, which indicates the possibility of its precipitation from solution. Thus, the geochemical environment at great depths in the deposits of the South Caspian Basin not only assists in the preservation of allothigenic montmorillonite, but also possibly allows the transformation of hydromica into montmorillonite, with formation of secondary montmorillonite.
DISCUSSION
According to the data cited above, a rather close relation exists between the various clay-mineral contents and the thermobaric and hydrochemical characteristics of the section in the South Caspian Basin and onshore of Azerbaijan. It is evident that all these parameters interact, and the stability of montmorillonite at great depths depends mainly on them. Moreover, in the section of Baku Archipelago at depths greater than 4 to 5 km,
l 17
SMECTITE-ILLITETRANSFORMATIONS TABLE 4-8
Statistical analysis of particle sizes of primary and secondary montmorillonite at two different magnifications: x 1000 and x3000 (after Buryakovsky et al., 1995, table 7, p. 214) Magnification
Particle size (~m) limits
median
average
standard deviation (~m)
coefficient of variation (%)
asymmetry
1.9 1.5
2.6 1.9
3.3 2.1
127 122
0.58 0.53
2.0 1.6
2.7 1.9
2.9 2.2
107 116
0.7 0.52
Primary montmorillonite 1000 3000
0.9-11.2 0.5-5.1
Secondary montmorillonite 1000 3000
0.9-6.5 0.6-4.8
the formation of secondary montmorillonite from hydromicas was observed using the scanning electron microscope (SEM). Such a phenomenon is explained by the influence of relatively low temperatures, abnormally high pore pressures in shales, and the alkali composition of pore water. Numerical characteristics of the particle sizes (or more likely aggregate accumulations) of primary and secondary montmorillonite at great depths were established. An estimate was achieved by means of a corresponding quantitative analysis of SEM data. The authors of this chapter utilized photomicrographs of surfaces cut (parallel to bedding) from a shale sample from a depth interval of 5128-5132 m in the Bulla-mor6 gas-condensate/oil field. The relations between primary and secondary montmorillonite were observed clearly using magnifications of 1000 and 3000. Statistical analyses of the data on particle sizes for primary and secondary montmorillonite are presented in Table 4-8. As shown, the particle sizes for primary montmorillonite are within the 0.5-11.2-~m limits, whereas the size of secondary montmorillonite ranges from 0.6 to 6.5 [~m. The average particle sizes of the primary and secondary montmorillonite roughly coincide. Some differences were observed using photomicrographs with magnifications of 1000 and 3000, because with a magnification of 3000 it is possible to observe a greater number of smaller particles. This, naturally, yields a somewhat smaller average value of the clay particle sizes. As shown in Table 4-8 and Fig. 4-11, the distributions of particle sizes are rightasymmetric, close to log normal law. In all four cases, the average values of the particle sizes exceed the median by 0.3-0.7 Ixm. It is significant that sizes of the montmorillonite particles are close to those of the pores, as established by SEM data. Utilizing the data obtained, Buryakovsky et al. (1995) estimated the primary and secondary montmorillonite contents (Table 4-9). On average, the total montmorillonite content (percent of the total area of photomicrographs) reached 19.2% (13.2% primary and 6% secondary). The secondary montmorillonite fraction constituted an average of 31.5% of the total montmorillonite content. This indicates a rather high intensity of secondary montmorillonite formation from hydromica at great depths.
] ]8
L.A. BURYAKOVSKY,R.D. DJEVANSHIR,G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
7
(a)
~ , 0.3
8
C
~
o.2
Um (b
u_
.-->
0.1 i
0
rv
i
o
1.8 2.5 3.1 3.6 4.0
$, o.3 e
0
0.2
O.l
-
(I)
rv 4.4 4.8
Particle Size (d), l~m
8
(b)
~0.3
0
0
1.8 2.5 3.1 3.6 4,0
Z
('
4,4 4.8
Particle Size (d), ~m
,, 0.3
(c)
(d)
O.2
~"
i..i..
0.2
u_
O.1
0
l- -tl r--i
1.3 1.9 2.3
3.0
I
~
[--~ F l 3.7
Particle Size (d), ~m
5.1
""
0.1
o
-
[-I-I
F-~l F--l ~
1.3 1.9 2.3 2.7 3.0 3.8
Particle Size (d), ~m
Fig. 4-11. Histograms of the distribution of particle sizes for primary (a, c) and secondary (b, d) montmorillonite (Bulla-mor6 field; depth interval of 5128 to 5132 m). [(a, b) x 1000], [(c, d) x 3000] is the relative frequency. (Modified after Buryakovsky et al., 1995, fig. 10, p. 215.)
The postsedimentary (diagenetic and catagenetic) transformation of Middle Pliocene shales of the South Caspian Basin is characterized by retardation of the process of transformation of montmorillonite into hydromica or chlorite at great depths, and the replacement of this process by the process of transformation of hydromica into swelling minerals of the montmorillonite group. These processes are closely related to the lower geothermal gradient and increasing pressure at depth. The inverted hydrochemical profile of these deposits is possibly a consequence of the relationship between the transformation of clay minerals and thermobaric conditions at depth, as pore solutions could distil in the process of clay sediment compaction. On the basis of compaction experiments, Rieke and Chilingarian (1974) suggested that compaction fluids become saltier as they move upwards through clays. An important question is: what is the depth limit for the preservation of montmorillonite under given thermobaric conditions? Khitarov and Pugin (1966) estimated the depth of occurrence for montmorillonite under various conditions. For example, when the geothermal gradient changes from 40 to 10~ the limiting depth of occurrence
SMECTITE-ILLITETRANSFORMATIONS
1 19
TABLE 4-9 Relative proportions of primary and secondary montmorillonites (in %) using different magnifications (after Buryakovsky et al., 1995, table 8, p. 215) Photomicrograph
Magnification
number
Montmorillonite content (%)
Total content
primary
(%)
secondary
Portion of secondary montmorillonite
(%) 1 2 4 5
3000 1000 3000 1000
14.5 13.5 10.5 14.3
7.1 6.5 5.4 5.2
21.6 20.0 15.9 19.5
32.9 32.5 34.0 26.7
for montmorillonite changes from 3 to 16 km. Inasmuch as the average geothermal gradient in the Baku Archipelago is 16~ the limiting depth may be 8-9 kin. On the basis of the data obtained by Khitarov and Pugin (1966), Buryakovsky et al. (1995) suggested the following equation relating the depth of montmorillonite occurrence H in km to the geothermal gradient G in ~ H - 261G -123
(4-2)
Stratigraphic sections with abnormally high pore pressures may, however, have even greater limiting depths. Inasmuch as there is a linear relationship between pressure and depth, the equation for the limiting depth Hlim, can be presented as follows" nlim-
2 6 1 K a G -123
(4-3)
where Ka is a dimensionless factor to account for the pore-pressure anomaly (ratio of the actual (or predicted) pore pressure to the hydrostatic pressure). Predicting clay-mineral transformations in the Caspian Sea region at depths > 6.5 km is of great importance. Data derived from extrapolation and from physical and mathematical simulation (Buryakovsky et al., 1982) indicate that conditions at depths of 9 km or more in the South Caspian Basin do not favor catagenesis of argillaceous rocks. As shown by Buryakovsky et al. (1982), the porosity of shales at depths of more than 9 km can be as high as 10%, which means that there are abnormally high pore pressures of gravity-filtration origin. Using Eq. 4-3, at G -- 16~ and Ka = 1.8, the limiting depths are found to be 15-17 km in the center of the basin. This indicates that the shales retain their sealing properties, whereas the reservoir rocks have rather high porosity (the predicted porosity at a depth of 9 km is on the average 7-9%, whereas the permeability is 1.5 to 11 mD. The presence of abnormally high pressures and relatively low temperatures indicate that hydrocarbons may be present; thus, it is likely that the South Caspian Basin may have commercial accumulations of oil and gas at depths of 9 km or deeper.
120
L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.
SUMMARY
For the South Caspian Basin the findings of Buryakovsky et al. (1995) can be summarized as follows. (1) Regionally developed abnormally high formation pressures were encountered onshore of Azerbaijan and offshore of the South Caspian Basin. The pore pressure in the argillaceous rocks is higher than that in the reservoir rocks. (2) Paleogene to Neogene shales and argillaceous rocks, widespread in the geologic section of Azerbaijan and the South Caspian Basin, consist of montmorillonite (smectites), hydromica (illite) and mixed-layered minerals. Onshore, the Oligocene to Miocene argillaceous rocks (shales, mudstones, etc.) are higher in volcanic ash content owing to their proximity to the Lesser Caucasus, than the Pliocene argillaceous rocks formed in the South Caspian Basin. The most characteristic feature of Tertiary argillaceous rocks in Azerbaijan and the South Caspian Basin is their undercompaction and the presence of pores of various sizes, measured by SEM. Their open porosity (effective porosity as used in USA) ranges from 3 to 20%. (3) The incomplete compaction of such argillaceous rocks, even at depths down to 6.5 km, is explained by the comparatively young age, a high sedimentation rate (up to 1 km per one million years), their great thickness, and incomplete squeezing-out of pore water. Such argillaceous rocks have high pore pressures, often higher by a factor of 1.5 (and more) than hydrostatic pressure, and constitute good seals for oil and gas accumulations. (4) The montmorillonite content of the Baku Archipelago shales is constant down to depths of 6.5 km because the formation of secondary montmorillonite from hydromicas predominates over the transformation of primary montmorillonite. An increase in temperature causes the dehydration of montmorillonite to hydromica, but abnormally high pore pressures in shales hinder the dehydration and favor the transformation of hydromicas to secondary montmorillonite, which produces heat. This is particularly characteristic of young basins with rapidly accumulated thick series of argillaceous sediments. (5) A formula was proposed for the limiting depth at which montmorillonite can occur for any specific thermobaric conditions and, particularly, when the actual pore pressure differs from the normal hydrostatic one. In the stratigraphic section of the South Caspian Basin, the predicted limiting depth ranges from 15 to 17 km. (6) The sealing properties of argillaceous rocks at depths greater than 6.5 km probably persist, because of the presence of large amounts of montmorillonite. If accompanied by (1) good reservoir rock properties, (2) abnormally high pore pressures in shales and sandstones, and (3) relatively low formation temperatures (which allow hydrocarbons to persist), the writers suggest that the South Caspian Basin may contain commercial oil and gas accumulations at depths of 9 km and deeper. (7) Development of abnormally high pore pressures may lead to lateral rock density variation and, under certain geologic conditions, to folding, clay diapirism, mud volcanism, and earthquakes.
SMECTITE-ILLITETRANSFORMATIONS
121
CONCLUSIONS In c o n c l u s i o n , one m a y state that the m o n t m o r i l l o n i t e - i l l i t e t r a n s f o r m a t i o n m a y contribute to or l e a d to a b n o r m a l l y h i g h f o r m a t i o n pressures. In m a n y cases, h o w e v e r , due to lack of p o t a s s i u m ions in the interstitial solutions, low g e o t h e r m a l gradi ent s, etc., this m a y not be the case. T h e m o n t m o r i l l o n i t e / i l l i t e ratio, h o w e v e r , s h o u l d be m e a s u r e d and u s e d in c o n j u n c tion with o t h e r p r e d i c t i v e t e c h n i q u e s in t h i c k s a n d - s h a l e s e q u e n c e s .
BIBLIOGRAPHY Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. Am. Assoc. Pet. Geol., 53(1): 73-93. Buryakovsky, L.A., 1974. Distribution patterns of oil and gas deposits within the Apsheron Archipelago. Int. Geol. Rev., 16(7): 749-758. Buryakovsky, L.A., 1993a. Outline of general and petroleum geology in Azerbaijan and the South Caspian Basin, Part 1. Houston Geol. Soc. Bull., 35(6): 16-33. Buryakovsky, L.A., 1993b. Outline of general and petroleum geology in Azerbaijan and the South Caspian Basin, Part 2. Houston Geol. Soc. Bull., 35(6): 43-47. Buryakovsky, L.A., 1993c. Offshore oil and gas fields in Azerbaijan: History and description, Part 1. Houston Geol. Soc. Bull., 35(10): 12-17. Buryakovsky, L.A., 1993d. Offshore oil and gas fields in Azerbaijan: History and description, Part 2. Houston Geol. Soc. Bull., 36(3): 23-27. Buryakovsky, L.A., and Chilingarian, G.V., 1991. Time factor in mathematical models of geologic and technical processes. J. Pet. Sci. Eng., 6(4): 341-347. Buryakovsky, L.A., and Dzhevanshir, R.D., 1985. Structure of pore space in Cenozoic argillaceous rocks of Azerbaijan in connection with development in them of abnormally high pore pressure. Lithol. Miner. Resour., 20(1): 83-91. Buryakovsky, L.A., and Dzhevanshir, R.D., 1986. Interaction of clay-mineral transformation with thermobaric conditions at depth. Geochem. Int., 23(8): 99-106. Buryakovsky, L.A., Dzhafarov, I.S., and Dzhevanshir, R.D., 1982. Prediction of Physical Properties of Oil and Gas Reservoir and Cap Rocks. Nedra, Moscow, 200 pp. (in Russian). Buryakovsky, L.A., Dzhevanshir, R.D., and Aliyarov, R.Yu., 1986. Well Logging Methods for Geofluidal Pressure Study. Baku, Elm, 148 pp. (in Russian). Buryakovsky, L.A., Dzhevanshir, R.D., Kheirov, M.B., and Aliyarov, R.Yu., 1988. Post- sedimentary transformations of Middle Pliocene clays of the South Caspian Basin. Lithol. Miner. Resour., 23(1): 68-77. Buryakovsky, L.A., Dzhevanshir, R.D., and Tagiev, S.O., 1990. Computer simulation for chemical interaction processes of rocks and pore waters. Proc. III Symp. Mining Chemistry, pp. 61-65. Buryakovsky, L.A., Djevanshir, R.D., and Chilingar, G.V., 1995. Abnormally high formation pressures in Azerbaijan and the South Caspian Basin (as related to smectite-illite transformations during diagenesis and catagenesis. J. Pet. Sci. Eng., 13:203-218. Buryakovsky, L.A., Chilingar, G. V., and Aminzadeh, E, 2001. Petroleum Geology of South Caspian Basin. Gulf Publ. Co., Houston, TX, 442 pp. Chilingar, G.V., 1956. Durov's classification of natural waters and chemical composition of atmospheric precipitation in USSR. Trans. Am. Geophys. Union, 37(2): 193-196. Chilingar, G.V., 1957. Soviet methods of reporting and displaying results of chemical analysis of natural waters and methods of recognizing oil-field waters. Trans. Am. Geophys. Union, 38(2): 219-221. Chilingar, G.V., 1958. Chemical composition of oil-field waters from Apsheron Peninsula, Azerbaidzhan, SSR.,Geochim. Cosmochim. Acta, 14: 168-172.
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Chilingarian, G.V., Rieke, H.H., and Kazi, A., 1994. Chemistry of pore waters. In: W.H. Fertl, R.E.,Chapman and R.E Hotz (Eds.), Studies in Abnormal Pressure. Elsevier, Amsterdam, pp. 107-153. Dobrynin, V., 1970. Deformation and Physical Properties Change in the Oil and Gas Reservoir Rocks. Nedra, Moscow, 239 pp. Durmishian, A.G., 1973a. Role of anomalously high formation pressures (AHFP) in the development of traps for accumulation of oil and gas in Southern Caspian Basin. Int. Geol. Rev., 15:(5) 508-516. Durmishian, A.G., 1973b. Towards question of consolidation of clayey rocks. Izv. Akad. Nauk. SSSR, Ser. Geol., (8) 85-89. Dzhevanshir, R.D., Buryakovsky, L.A., and Chilingarian, G.V., 1986. Simple quantitative evaluation of porosity of argillaceous sediments at various depths of burial. Sediment. Geol., 46: 169-175. Eremenko, N.A., and Neruchev, S.G., 1968. Primary migration in the process of burial and lithogenesis of sediments. Geol. Oil Gas, 9: 5-8. Fertl, W.H., 1976. Abnormal Formation Pressures, Implications to Exploration, Drilling, and Production of Oil and Gas Resources. Developments in Petroleum Science, 2. Elsevier, Amsterdam, 385 pp. Fertl, W.H., and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1: 23-28. Kharaka, J.K., and Barnes, H., 1973. Solmineq-solution-mineral equilibrium computation. USGS Comput. Cont., Natl. Tech. Inf. Rep., PB-215-583. Kheirov, M.B., 1979. The effect of depth of sedimentary rocks on transformation of clay minerals. Izv. Akad. Nauk SSSR, Ser. Geol., 8:144-151 (in Russian). Khitarov, N.L., and Pugin, V.A., 1966. Montmorillonite under conditions of increased temperature and pressure. Geokhimiya, 7:790-795 (in Russian). Larsen, G., and Chilingar, G.V., 1979. Diagenesis in Sediments and Sedimentary Rocks. Developments in Sedimentology, 25A. Elsevier, Amsterdam, 579 pp. Magara, K., 1968. Compaction and migration of fluids in Miocene mudstone, Nagaoka Plain, Japan. Bull. Am. Assoc. Pet. Geol., 52(12): 2466-2501. Millot, J., 1949. Relations entre la constitution et al gen6se des roches s6dimentaires argileuses. ThOse Sci. Nancy et G~ol. Appl. Prospec. Min., 2(2-4): 1-352. Proshlyakov, B.K., 1960. Reservoir properties of rocks as a function of their depth and lithology. Geol. Nefti Gaza, 12: 24-29. Rieke, H.H. III, and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Developments in Sedimentology, 16. Elsevier, Amsterdam, 424 pp. Samedov, EL., and Buryakovsky, L.A., 1966. Oil-field Hydrogeology in the Apsheron Aiz'hipelago. Azerneshr, Baku, 228 pp. (in Russian). Vassoevich, M., 1960. Experiment in constructing typical gravitational compaction curve of clayey deposits. Nov. Neft. Tekh., Geol. Ser. (News Pet. Tech., Geol.), 4: 11-15. Vassoevich, M., Bronovitskiy, A.V., 1962. Towards studying density and porosity of sedimentary rocks. Trudy VNIGRI Gostoptekhizdat, 190: 478-484. Weller, J.M., 1959. Compaction of sediments. Bull. Am. Assoc. Pet. Geol., 43(2): 273-310.
123
Chapter 5
M E T H O D S OF ESTIMATING AND P R E D I C T I N G A B N O R M A L F O R M A T I O N PRESSURES G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ and J.O. ROBERTSON JR.
INTRODUCTION
Most of the pressure detection techniques described in the literature are based mainly on the observation that many overpressured rocks are associated with undercompacted shales. The greater the undercompaction, the higher the porosity, and the greater the percentage of the load carried by the intergranular fluid. Undercompaction and decompaction often result in the creation of higher porosity in comparison with a normal compaction trend. Weller (1959) and Vassoevich (1960) noted that shales can be used as a geologic manometer. They found interrelationships among the degree of compaction, shale porosity, and overburden and formation pressures. There are different shale porosity versus depth curves for various lithologic cross-sections and different basins. The normal compaction trend must be known to estimate the correct abnormal pressure for (1) each basin, (2) each oil and gas field, and maybe (3) each well (see Rieke and Chilingarian, 1974). A major problem when drilling new wells in an abnormally pressured area is that of identifying an abnormally pressured formation prior to drilling into it. Drilling unexpectedly into an abnormally pressured formation (AHFP) can result in costly drilling expenses. These costs can be avoided through the observation of a combination of several formation-pressure indicators. These include surface and borehole seismic, drilling, and well logging data. Although several such indicators should be monitored at the wellsite, not all data are usable or necessarily required in any one drilling operation. Drilling operations in overpressured environments should incorporate the following steps: (1) planning the w e l l - gathering and interpretation of all known information of the region in which the well is to be drilled; (2) preparation of a preliminary drilling program with educated guesses about the potential of encountering abnormally pressured formations; and (3) review and revision of the drilling program as the well is being drilled. One should always have contingency plans prepared if an abnormally high pressured formation is encountered so that all decisions can be made quickly. It should be remembered that drilling operations, drilling fluids (muds), and casing constitute major costs in a drilling program. Also, a review of the regional fracture pressure gradient, as well as the pore-pressure variations, should be estimated prior to drilling and continuously monitored while drilling the well in order to design an effective and economical drilling mud program. Sometimes, a well can be lost due to a blowout if an AHFP is unexpectedly encountered.
124
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
The concept of the process of rock compaction is a fundamental part of many prediction methods (Serebryakov and Chilingar, 1994). In basins with well-compacted rocks, the influence of temperature on the formation pressure is an important factor. Tectonically caused abnormal pressures (overcompaction) caused by squeezing of water from shales into associated sandstones are discussed in Chapter 8. Some of the most reliable quantitative overpressure detection and evaluation techniques are based on geophysical wireline logging methods. These methods, however, are usually after-the-fact techniques, i.e., the wellbore is drilled prior to logging. Many short logging runs are frequently necessary, if the logging-while-drilling is not used. Logs that can detect abnormally high formation pressures have been discussed in detail by Fertl (1976, pp. 177-230). Wireline formation testers, which record several pressures over the entire length of the uncased borehole, are being used. Measurements from these testers can be used to 'calibrate' other drilling and/or log-derived pressures. Cased-hole wireline formation testers are also available to calibrate logging data. Applications of good surface seismic data allow: (1) determination of interval velocity; (2) the study of lithologic and stratigraphic variations in geologic sections; (3) estimation of geologic age and/or average geothermal gradients; (4) the study of the effects of lateral folding pressure on a regional scale; (5) detection of hydrocarbon presence, especially gas, at shallow depths (i.e., the bright spot technique); (6) detection of natural and/or artificially caused hydrocarbon seepages from the ocean floor; (7) investigation of the ocean floor and sub-bottom properties (buried ancient glacial channels, sediment stability, and mud lumps) for proper planning of offshore drilling and production operations; and (8) detection of the presence and top of abnormally pressured formations and determination of the magnitude of pressure. Drilling parameters and logging-while-drilling methods provide instantaneous information. Drilling mud parameters and shale cutting analysis are an excellent source of information as these data can be compiled during drilling. The latter data, however, are delayed by the time required for circulation and sample return (see Table 5-1). Interpretation of recorded data is not always straightforward. Accuracy depends on geologic factors, borehole environment, sample selection at certain depth increments, and plotting techniques (Table 5-2). Digital recording systems can yield borehole seismic recordings at the wellsite. Behavior of the borehole wall in response to sound energy from a surface source can be detected by a three-component geophone tool and recorded. Table 5-3 lists several interpretive product lines related to borehole seismic technology. An approach that does not rely on the concept of rock compaction is the methodology of detection of abnormally pressured zones based on the concentration of radioactive isotope 4~ With the exception of the SP-curve data, all parameters which are recorded in shales are plotted versus depth. Trendlines are then established for normal compaction. Interpretation of the logs depends on the magnitude of the departure from the normal trend, due to the divergence of formation pressure from the normal hydrostatic pressure at a specific depth. Application of these methods, however, is not always simple and straightforward.
TABLE 5-1 Drilling and well logging overpressure detection and evaluation techniques (after Fertl and Chilingarian, 1987, table 11, 8. p. 28)
> z
0 -0
Techniques
Variables
Drilling parameters (instantaneous)
Drilling rate, torque, drag, hole fill-up (reaming), modified d-exponent, analytical drilling model concepts.
Logging-while-drilling (instantaneous or semi-instantaneous)
Electrical and acoustic-type transmission concepts (using cables, drillstring, or mud system); analysis of drillstring vibrations; downhole gas detection tool.
Drilling mud parameters (while drilling, but delayed by circulation lag-time)
Mud weight, gas content, temperature, flow rate, hole fill-up, pit level and total pit volume, salinity (resistivity, conductivity), well kicks.
Drill cutting analysis (while drilling, but delayed by time required for sample return)
Density, shape, size, color, volume over shale shaker, moisture content, 'lithofunction' plots, and shale factor (cation exchange capacity) of cuttings. Cutting slurry and/or filtrate: resistivity, color, pH and redox potential, bicarbonate content, specific anion and cation concentrations, and filtration rate.
Well logging parameters
Electrical surveys: resistivity, conductivity, salinity, shale formation factor. Acoustic (sonic) surveys: interval transit time and wavetrain presentations (VDL, signature log, etc.). Bulk density surveys: density log, downhole gravity meter. Hydrogen index (neutron-type logs). Thermal neutron capture cross-section (pulsed neutron logging). Nuclear magnetic resonance. Gamma-ray spectral analysis logs.
- geophysical
well logs
z m E!
2 Pn
$ Z
Bs $
2 u
5 ?(
;a
C,
c"z
126
G.V. CHILINGAR,V.A. SEREBRYAKOV,S.A. KATZAND J.O. ROBERTSONJR.
TABLE 5-2 Parameters affecting practical information pressure evaluation techniques (after Fertl and Chilingarian, 1987, table III, p. 29)
Geologic factors Geologic age changes. Compaction effects on regional (basin edge versus basin center) and local scale, and differential compaction across structures. Sand/shale ratio in clastic sediments. Lithology effects: pure shales (soft, hard); limey and silty shales; bentonitic markers; gas-bearing ('shale gas'), organic-rich, bituminous shales; types and amounts of clay minerals in shales (depending on depositional environment and/or diagenesis). Heavy minerals (siderite, pyrite, mica, etc.). Drastic formation water salinity variations in subsurface. High geothermal gradients. Stratigraphic and tectonic features (acting as overpressure continuities or barriers), including unconformities, pinchouts, and faults; proximity to large salt masses, mud volcanoes, geothermal 'hot' spots, etc. Steep, thin, overturned beds. Pore pressure gradients within single thick shale interval. Borehole environment Borehole size, shape, and deviation. Shale alteration and hydration (exposure time of open hole to drilling mud). Type of drilling mud (freshwater, saltwater, oil-base). Type and amount of weighting material (barite, etc.) and/or lost circulation material (mica, etc.). Degree of 'gas cutting' in mud. Drilling conditions Hole size, shape, and deviation. Mud programs and mud hydraulics (circulation rate). Rotary speed. Bit type (button, diamond, insert, etc.). Bit weight to bit diameter ratio. Bit wear (sharp, new bits versus dull, old bits). Degree of overbalance. Floater ('heave' action) versus fixed on- or offshore rig. Sample selection Type and size of sample (avoid sand, cavings, recirculated shales). Sampling technique. Sampling frequency. Analysis methods: for example, cutting density-variable density column, multiple-density solution technique (float and sink method), mercury pump technique, mud balance technique. Proper calibration is of utmost importance. Geophysical well logging Different basic measuring principles (shales are anisotropic). Sonde spacing. Depth of tool investigations. Temperature ratings. Proper tool calibration. Tool malfunction (overlapping repeats or returns). Parameter plotting techniques Interval (or sample) selection. Sampling frequency. Linear, logarithmic plots. Plot comparable data (not compatible are bulk density from logs versus cuttings, and short normal versus induction log resistivities). Proper selection of 'normal' compaction trendlines (discrepancies become enhanced with increasing depth of wells). Use all information available. Experienced, properly trained personnel is a must.
PREDICTION OF ABNORMALLY HIGH PRESSURE IN REGIONS WITH NONEQUILIBRIUM COMPACTION
Dobrynin and Serebryakov (1978) studied present-day pressures of formations in the West-Kuban Depression, South Caspian Basin, Fergana Basin and other petroliferous regions of the former USSR. They also estimated (theoretical) the possible lifetime (duration) of abnormally high pressure in oil and gas accumulations. The present-day values of pore pressure in the shale seals (caprocks) and the formation pressure in associated reservoir rocks in regions with nonequilibrium compaction depends on (1) the permeability of the seals, (2) the lithology of the geologic section, (3)
127
METHODS OF ESTIMATINGAND PREDICTING ABNORMAL FORMATIONPRESSURES TABLE 5-3 Borehole seismic techniques (after Fertl and Chilingarian, 1987, table IV, p. 30)
Synthetic seismogram Detailed correlation information between well log data and recorded seismograms. Transformation of acoustic and density log data into a seismic trace format for direct comparison with surface or borehole seismic recordings.
Velocity survey Precise tie between seismic reflection travel times and known depths within a well. Useful for identifying events on surface seismic displays corresponding to specific geologic formation boundaries.
Acoustic calibration Velocity survey results adjust acoustic log values into the domain of macroscopic seismic measurements, so that synthetic seismograms derived from acoustic logs will accurately match field near-surface structures.
Offset VSP Enhanced resolution of the VSP technique achieved laterally away from the borehole. Converted wave modes deduce additional lithologic properties.
Predicted acoustic log Inversion of seismic trace data. Prediction of rock conditions, such as overpressure zones or porosity zones, below the drill bit. The required velocity trend at the well location is derived from a combination of acoustic log data, seismic velocity survey, and surface seismic velocity analysis results.
Salt proximity survey Specialized format of vertical seismic profile. Determines shape of a salt dome flank. Instead of using reflected waves, this technique depends on observing the direct arrival time of waves that travel through the salt dome. This configuration solves the structural interpretation problem that has always been very difficult when using only surface seismic measurements.
the rate of sedimentation (mainly during Pliocene-Quaternary time), and (4) tectonic movements of the Earth's crust. Assuming that filtration of water through the seals obeys Darcy's law, the following equations can be obtained: If R > Rcr:
Ka = Pa Pn
= 1+
Ahs 9~.C~b 9( R - Rcr)] (kw/#s) gpwh
(5-1)
If R _< Rcr: Ka -- 1
where Ka is the coefficient of abnormal pressure (i.e., the ratio of abnormal pressure, pa, to the normal hydrostatic pressure, p,, at the same depth h, kw is the permeability of the seal to water; Ahs is the thickness of the seal, #s is the viscosity of water, )~ is the coefficient showing what portion of the total water is expelled from the rocks through the seals by vertical filtration, C is the consolidation coefficient of the rocks, q~ is the porosity, g is the gravitational acceleration, Pw is the average density of water, R is the sedimentation rate (e.g., during the Pliocene-Quaternary), and Rcr is the critical sedimentation rate.
128
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
10.0
8.0 5.0
~
3.0
<~
1.0
~
0.8
II
O.5
~
0.3
0
121 0.1
1000
3000
i
Depth (h), m
'1 * 121 *1 31 ~ I 41,151-! Fig. 5-1. Relationship between the sealing potential of shales, characterized by the factor k~ and depth (h) of the seal (caprock) in m. Age of the deposit at the base of the seal being studied: 1 = Miocene; 2 Oligocene; 3 = Eocene; 4 -- Upper Cretaceous; and 5 = Lower Cretaceous. (Modified after Dobrynin and Serebryakov, 1989, fig. 41, p. 93.) The term Ah~ I --
(kw/~Z,)
(5-2)
in Eq. 5-1 is related to the isolating ability of the seal and depends on its thickness and permeability (Fig. 5-1). The next part of Eq. 5-1" L --
zcq~ gpwh
(5-3)
m o s t l y reflects the lithology of the geological section and the depth of burial. The last part of Eq. 5-1" S-
R-
Rcr
(5-4)
129
METHODS OF ESTIMATINGAND PREDICTINGABNORMALFORMATIONPRESSURES 5000 m 2.4
5500 m
"
ouuu 2.2
- -
2.0
- -
f
m
4500 m
~ej
4000 m
.=,..
0
E
1.8
--
0r <
1.6
3500 m
--
0 r
3000 m
0 (1) 0
0
1.4
I
2000 m
1.2 ,
0
20
I
!
I
I
I
I
40
60
80
1oo
120
140
Rate of Sedimentation (R), meters per million years Fig. 5-2. Relationship between the coefficient of abnormally high formation pressure (AHFP) in shales, Ka, and the rate of sedimentation (m/million years) during Pliocene-Quaternary time at different depths, h (m). Values are shown on curves. (Modified after Dobrynin and Serebryakov, 1989, fig. 42, p. 93.)
shows the rate of sedimentation, which in many cases determines the creation of abnormally high pressure. Using the data from wells drilled in the West Kuban Depression (Azov-Kuban petroleum basin), the sealing ability of caprocks can be estimated (Eq. 5-2). The coefficient of abnormally high pressure can be calculated using Fig. 5-1 and Eq. 5-1 as a function of the sedimentation rate, R (Eq. 5-4) and the depth of burial of these rocks. Examples of calculated coefficients of abnormally high pressures presented as a function of sedimentation rate, R, during the Pliocene-Quaternary time are shown in Fig. 5-2. Using this type of calculation, it is possible to predict not only the present-day values of pressure, but also to explore paleopressure compartmentalization in order to help understand hydrocarbon migration and accumulation. This method of calculating abnormal pressure based on the use of Eqs. 5-1 through 5-4, was used in several regions including the West Kuban Depression and Turkmenistan Basin with good results.
130
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
A B N O R M A L P R E S S U R E D U E TO T E M P E R A T U R E VARIATIONS
In the creation of abnormally high pressures, temperature does not play an appreciable role in the case of nonequilibrium in undercompacted rocks. Temperature does play a significant role in the case of well-compacted rocks, because the probability of creating abnormally high pressure in compacted isolated rocks is significantly higher as a result of the temperature change of the rock and its interstitial fluids. The change of the formation pressure as a direct result of temperature variations, ApT, may be expressed by the following equation: Ofw m ly s
APT = r
+ r
9A T
(5-5)
- r
where O~s and Otw are respectively coefficients of thermal expansion of solids (minerals) and water; tip, flw and fls are respectively the coefficients of compressibility of pore volume, water and skeletal structure for the rock and A T is the temperature change. Inasmuch as: Olw -r ors
(5-6)
the thermal expansion of pore water cannot be compensated for by the deformation of pore space. A change in temperature will lead to variations in the formation pressure. It follows from Eq. 5-5 that if: tip .qt_ /~w ~> /~s
(5-7)
then an increase in temperature (A T > 0) will cause an increase in formation pressure.
E S T I M A T I O N A N D P R E D I C T I O N OF A B N O R M A L L Y L O W P R E S S U R E S IN BASINS IN PERMAFROST REGIONS
The creation of abnormally low pressure in formations in regions of permafrost is due to the following: (1) a decrease in the hydrostatic level of formation water due to permafrost; (2) deformation of the rocks and interstitial fluids due to increase of overburden (weight of ice); and (3) a decrease in rock volume and interstitial fluids due to a decrease in temperature (cooling). In compacted rocks, change of pore pressure can be estimated as follows (Dobrynin and Serebryakov, 1989): Ap-
Aa + Apv
(5-8)
where ApT is the temperature-related term defined by Eq. 5-5, Ao- is the change in the average normal stress due to the formation of permafrost zone with thickness hi. It is defined by the following equation: l+v (5-9) 3(1 - v ) where v is Poisson's ratio, Pi is the density of ice, and hi is the thickness of the permafrost. Ao" = ~ g l o i h i
131
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES
For geological cross-sections with compacted carbonate rocks, usually: tip + flw >> fls
(5-10)
Otw >> ors
(5-11)
and:
Thus, the following equation for estimating the pore pressure in cross-sections with permafrost and without permafrost can be derived:
[
(
Pa = P n - A p =
gPw
(h -
hst) -
1+
v
3(1 - v)
)(
tip
)() ](ow)
tip + flw
Pi
Pw
hi
AT
tiP + / %
(5-12)
where hst is the depth of the static water level. The first term in Eq. 5-12: H
=
gpw(h
-
hst)
represents the normal hydrostatic pressure, whereas the second term in Eq. 5-12: O
-- gPw
(lqt-l) ) ( ~P ) (P-~w)hi 3(1 - v)
/~p -+- flw
indicates deformation of the rocks and fluids due to increase in the mass of ice. The last and most important term in Eq. 5-12: V--
(ow) /~P -nt- flw
AT
represents the pore pressure component caused by volume changes in rocks and especially in interstitial fluids due to decreasing temperature (cooling). Fig. 5-3 shows the graph for estimating the pore pressure in the Nepsko-Botuobin anticline (eastern Siberia) based on Eq. 5-1. Using this equation, an estimated abnormally low pressure was calculated in more than 40 wells in 23 oilfields, and then compared to data obtained from field tests. The margin of error was usually not more than 4-5%. Abnormally high pressure (10-20% higher than the normal hydrostatic pressure) was present in one formation of this region (Osinskiy Horizon). But the origin of this pressure appears to be related to the decrease in pore volume due to salt deposition in pores and salt injection into the highly fractured zones.
FORMATION PRESSURE IN REGIONS WITH UPTHROWN AND DOWNTHROWN BLOCKS (UPLIFT AND SUBSIDENCE OF SEDIMENTARY ROCKS)
Some tectonic processes in the Earth's crust create abnormal pressure. Most likely, these processes involve multiple changes in the overburden, temperature, and squeezing out of water from shales into associated sandstones. A change in the overburden creates volumetric changes (increase or decrease in pore volume), whereas a change
132
G.V. CHILINGAR,V.A. SEREBRYAKOV,S.A. KATZAND J.O. ROBERTSONJR.
Pore Pressure (pp), MPa 10
20
30
0
600
600
10
20
30
'
qF]
'
2Vzz:1 1200
A)
CB)
1200
r \\
~8oo
1800
a \
2600
2600
\ \
Fig. 5-3. Curves for estimating pore pressure in the formations of the Nepsko-Botuobin anticline in East Siberia. (A) Areas with permafrost and average geothermal gradient (G2) of 0.8~ m. (B) Areas devoid of permafrost. Figures on curves represent geothermal gradient: 1 = normal hydrostatic pressure gradient; 2 -- calculated using the following equation: Pa = g p w ( h --
O/w 0.8hi) -- ~ [ T o . I tip "t- ~w
-F ( G I - G 2 ) h 4-
G2hi]
where tSw is the average density of formation water at depth h; hi is the thickness of the permafrost; G1 and G2 are geothermal gradients respectively before and after cooling; T0,1 is yearly average temperature of the Earth's surface prior to cooling; /4p is coefficient of pore compressibility and flw is coefficient of compressibility of pore water; and oe,,, is coefficient of thermal expansion of pore water. Assumptions for dense carbonate rocks: /4p ~ flw; tip + flw >> fl~ (/4~ is compressibility of solid mineral grains of rocks); C~w >> c~ (c~ is coefficient of thermal expansion of solid mineral grains composing the rocks); Poisson's ratio, v = 0.25; and Pi/lSw ,~ 0.75 (,oi is average density of ice). (Modified after Dobrynin and Serebryakov, 1989, fig. 51, p. 108.)
in temperature creates volume changes in the rock's skeletal structure and interstitial fluids. These processes operate only in sedimentary basins with aquifer systems; they do not operate in infiltration water systems. The following equation can be used for the estimation of abnormal pressure in regions with uplift plus erosion, or subsidence plus sedimentation (Dobrynin and Serebryakov, 1989): pa = Pn 4- A p
gpw(h
( I + V ) hst) +
3(1 - v)
(tip)gprAh_4_ /~p --~ flw
~C~w /~p + / 3 w A T
(5-13)
where parameters are the same as in Eqs. 5-5, 5-8, 5-9 and 5-10; Ah is the amplitude of subsidence or uplift and Pr is the average density of new deposits after subsidence and sedimentation. After the first and second parts of Eq. 5-13, it is necessary to use a minus sign in the case of uplift and erosion and a plus sign in the case of subsidence plus sedimentation.
133
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES
Pore Pressure (Pc,), MPa
Pore Pressure (p,:,), Mpa
(B)
(AI
~
0
E .,c
0..
4000
L3
i
40 ,,,
80
I
1
0
40
80
k
\\\ oo oo
I
,;oo2.oo oo..
..
Pore Pressure (Pc,l, MPa 0
40
(c)
80
I[.. -1 21"-..I 31~ 4000
a
'
\\
,,,,,
Fig. 5-4. Theoretical dependence of anomalous pressures in rocks with hydraulically closed pores on magnitude (amplitude) of downthrust (subsidence) and upthrust (uplift) of blocks. Figures on the curves for (A) and (B) represent amplitude of downthrust of blocks in m; for (C), amplitude of upthrust blocks in m. 1 = Normal hydrostatic pressure; 2 = geostatic (total overburden) pressure; and 3 = theoretical curves for pressure in hydraulically closed pores. Geothermal gradients: (A) and (B): 3 x 10-2~ (C): 4 x 10-2~ (Modified after Dobrynin and Serebryakov, 1989, fig. 26, p. 61.)
Cross-plots for estimating the abnormally high pressure in regions with downthrown blocks (subsidence) are presented in Fig. 5-4A,B, whereas for the estimation of abnormally low pressure in regions with uplift and erosion, Fig. 5-4C can be used. An estimate of the pressure in the D n i e p r - D o n e t z (Ukraine) and Middle Kura (Georgia) basins can be made. In Georgia, an abnormally low pressure was estimated in Eocene deposits at depths of 2 0 0 0 - 3 0 0 0 m. The amplitude of the compressional thrust is 800 m. According to Fig. 5-4, coefficients of abnormal pressure range from 0.7 to 0.9. In the Shebelin gas field (Ukraine), abnormally high pressures are related to strike-slip faulting with displacements of 1000 m. Using Fig. 5-4, at a depth below 5400 m, the coefficient of abnormal pressure is 1.5. It should be noted that the methods described lack precision and should only be used as a preliminary pressure prediction prior to drilling. More precise methods of calculating abnormal pore pressures are utilized during drilling, using well log and drilling data.
134
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
(A) Abnormally-High Pressure Log r
Log p
Log R
Log Ln,
Log In~,
...... --
Log A,~ .....
n
L .......
"1~
"t
me
s|. "I,
:1, im
(B) Abnormally-Low Pressure Log
Log p ,,,,
9 ,
Log R .
.
.
.
.
.
.
.
.
Log I~,~ t .
.
.
.
.
.
Log In~
Log Az
.
~. 9
~
;.;.-
Fig. 5-5. Well-log responses in zones of (A) abnormally high and (B) abnormally low pressures. 1 = Abnormally high formation pressure (AHFP) in reservoir rock; 2 = shales; 3 = limestone; 4 -sandstone; and 5 = abnormally high and abnormally low pressures in shales. (Modified after Dobrynin and Serebryakov, 1989, fig. 54, p. 112.)
C A L C U L A T I O N OF A B N O R M A L PORE PRESSURE DURING DRILLING
In normally pressured zones, all log responses related to porosity, when plotted on a semilogarithmic paper, form straight lines (i.e., the vertical axis is log (x), where x is a geophysical parameter such as resistivity, sonic travel time, density, and gamma-ray and neutron log responses). In zones of abnormally high and abnormally low pressures, however, the magnitudes of the responses change significantly (Fig. 5-5). Abnormal pressure, therefore, can be detected on wireline logs (also logging while drilling).
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES
135
>, 0 0 t-
Resistivity 20
20
R
i
R
CB)
h
Fig. 5-6. Determination of abnormally high (A) and abnormally low (B) pressures using the method of equivalent depth. 1 -- Shale; 2 = sandstone; 3 = reservoir rock with anomalous pressures; 4 =
abnormal-pressure zone (pore pressure in shale); and 5 = crossed zone = zone not penetrated by drilling. h is the depth of investigation and he the equivalent depth (see Eq. 5-17). (Modified after Dobrynin and Serebryakov, 1989, fig. 55, p. 113.)
There are many methods for estimating and predicting abnormal pressure during drilling. Most methods are empirical dependencies between the pore pressure and log responses. There are three well-known analytical methods: (1) the method of equivalent depth (Foster and Whalen, 1966), (2) the method of normal compaction trend (Dobrynin and Serebryakov, 1978), and (3) the method of compressional curves (Dobrynin et al., 1982).
Method of equivalent depth The method of equivalent depth (Fig. 5-6) is based on the assumption that the same shale with equal physical properties at different depths will have equal effective stress (total overburden load, or, minus the pore pressure, pp)" ((7 -- P p ) l - - (0- - - P p ) 2
(5-14)
136
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
Using the above equation and the equations for the estimation of overburden pressure: (5-15)
~y -- gprh
and of pore pressure: (5-16)
pp = gpwh
it is possible to obtain an equation for the estimation of abnormally high pressure, ph (Alexandrov, 1987): ph
--
gphh
--
g(phre
--
he )he Pw
( 5 - 1 7 )
where prh and/9 he a r e the average densities of rocks at the estimated depth h and at the equivalent depth he, respectively, and phweis the average density of pore fluids to depth he. It is necessary to correct all parameter values for temperature, especially when the resistivity data are used as a geophysical property to identify equivalent depths. Method of normal compaction trend
In the method of normal compaction trend, the same assumptions are used as in the equivalent depth method, i.e., lithologically identical rocks with equal values of physical properties at different depths have the same effective stress. The normal compaction trend is dependent on the variation of rock properties with depth of burial at normal hydrostatic pressure. These properties can be determined using well-log data, drilling data, core analysis data, etc. In particular, the physical properties of shales depend primarily upon the degree of compaction. In nature, an exponential relationship exists between the depth of burial and porosity, density, or resistivity of normally compacted rocks (Fig. 5-7). When displayed on semilogarithmic plots, these exponential dependencies are shown by straight lines. Deviations from the straight lines indicate the upper boundary (top) of abnormal-pressure zones. For estimating abnormal pressure, Pa, the following equation can be used (Dobrynin and Serebryakov, 1978): P, -- Pn +
g(Pr - Pw) Ah log(xn/Xa) log(x2/xl ) + 0.435c~(x)GAh
(5-18)
where Pn is the normal hydrostatic pressure; Pr is the average density of rocks; Pw is the average density of water; or(x) is the temperature coefficient for each physical property; x2 and x~ are values of a certain geophysical parameter at depths h2 and hi; G is the geothermal gradient for the interval (hi - h2); Ah = (h2 - hi); and Xn and Xa are the values of a certain geophysical parameter used for the estimation of abnormal pressure within the normal compaction trend and within the zone of abnormal pore pressure. In the framework of this approach, it is not necessary to correct the values of geophysical parameters for temperature effects, because the temperature coefficient and geothermal gradient are included in Eq. 5-18. Using this equation, it is possible to estimate abnormally high and abnormally low pressures. In the case of abnormally high pressure, the second term in Eq. 5-18 is positive, whereas it is negative in the case of abnormally low pressure.
137
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES
Log X B\ A
hi aZZ r
i\\
h2
I
S
J
2o 2~ Fig. 5-7. Correction of normal compaction curve to temperature T1 at depth hi. Abnormally high pressure zone in shale is dashed; solid line above h2 is normal compaction trend, AAt; dashed line above h2 is normal compaction curve corrected to temperature Tt at depth h 1 (BB ~ trend); 2a is the trend in abnormally pressured zone without correction to temperature T1; 2b is the trend in the abnormally pressured zone with correction to temperature T1. (Modified after Dobrynin and Serebryakov, 1989, fig. 56, p. 115.)
The method of normal compaction trend was used in hundreds of wells in various basins. It was also used for interpreting seismic data in studying the possibility of predicting anomalously high pressure intervals in the sand-shale sequences of the West Kuban Depression, Russia (Dobrynin et al., 1979).
Method of compressional curves The method of compressional curves has also been used in estimating abnormally high and abnormally low pressures for a very large number of wells. This method is based on the use of compressional curves of regularly compacted rocks, the shape of which depends on the difference between the overburden pressure and pore fluid pressure. A compressional curve is defined as a plot of several physical rock properties, which characterize the compaction of rock, versus effective stress (effective stress is the difference between the total overburden pressure and the pore pressure). Compressional curves (semilogarithmic plots of rock properties versus depth) are more useful for estimating the abnormal pressure than the normal compaction trend,
138
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
Log X
m
E t-
O
N
1
3
r > 0 I.Li
E
o .Q
2
,< o o
N
l
Fig. 5-8. Schematic showing the dependence of the physical properties of shales on the effective pressure Pe (Pe -- o" -- pp): 1 = depth hi" 2 = depth h z" 3 = depth h. (Modified after Dobrynin and Serebryakov, 1989, fig. 57, p. 119.)
because they are continuous through the zones of both normal and abnormal pressure. Thus, all values of a geophysical p a r a m e t e r in the zones of normal hydrostatic pressure and abnormal pressure lie on a straight line (Fig. 5-8), because the physical properties do not depend on depth, but rather on the effective stress (0" - pp). The general equation for estimating the abnormal pressure using this m e t h o d is: Pa - 0" -
log(x) -t- [0.435ot(x)(h - h i ) G ] - mx
(5-19)
?/x
where x is the value of a certain geophysical parameter at a depth of pressure estimation; mx and n~ are the y-intercept and slope of the compressional curve, respectively; or(x) is the temperature coefficient for each geophysical p a r a m e t e r used (plus or minus sign is used depending on the physical property of the rock); and G is the geothermal gradient for the depth interval (h - hI). The parameters m~, and n~ are defined by the following equations: nx =
l o g ( x z / x l ) • ot(x)(h2 - h l ) ( G / 2 . 3 ) (0"2 -- P2) -- (0"1 -- P l )
(5-20)
M E T H O D S OF E S T I M A T I N G A N D P R E D I C T I N G A B N O R M A L F O R M A T I O N P R E S S U R E S
139
n x (slope) .05~ -.o56 .----'.05
.054
-
-----'----'.04 .033o ,035
.029
9 , .025
~.0~
.033
. . . .
.04
~5~
[intercept]
\ .I ~
"35 9
9
e'[4
9
~
-.01~~
20211,/
/
q,. -.22
Fig. 5-9. Schematic maps of nx (slope) and mx (intercept) of compressional curve in West Kuban Depression. (Modified after Dobrynin and Serebryakov, 1989, fig. 85, pp. 180-181.)
mx
-
log(xl)(o-2 - P2) (o-2 - P2) - (o-1 - Pl) (5-21) log(x2) • ol(x)(h2 --
hI)(G/2.3)(o-I
(o-2 -- P2) -- (o-1
-
Pl)
Pl)
Maps of these parameters may be useful for the prediction of abnormal formation pressure during drilling of new fields. As an example, schematic maps of mx, and nx in the West Kuban Depression are presented in Fig. 5-9. The mx is the value of a physical property of the formation near the surface (at the beginning of the compressional curve), where the effective stress is equal to zero.
140
G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.
Another advantage of the compressional curves method is that it enables the estimation of thickness of eroded deposits and also the detection of unconformities (Serebryakov and Chilingar, 1994).
RADIOACTIVITY STUDY OF ZONES WITH A B N O R M A L L Y HIGH FORMATION PRESSURE
Zoeller (1984) and Starostin (1985) discovered a gamma-ray phenomenon (decreasing radioactivity) in zones of abnormally high pressure. They attributed this phenomenon to a high porosity in zones of abnormally high pressure. Upon extensive research, however, Serebryakov et al. (1995) noted that the decrease in radioactivity is not related to the change in porosity, because this phenomenon can be found only in basins with nonequilibrium compaction and only in overpressured zones. Radioactivity of sedimentary rocks primarily depends upon the presence of uranium, thorium and potassium. Starostin (1985) examined 166 core samples of shale both in the zones of abnormally high pressure and zones of normal hydrostatic pressure. He found that the contents of uranium and thorium are not different in the normally pressured and abnormally high pressured zones. In addition, U and Th are not sufficiently soluble. In the opinion of Serebryakov et al. (1995), the most important indicator is the radioactive isotope of K: (4~ The potassium ion has a negative hydration in water (Blokh, 1969), i.e., water molecules become more mobile in the vicinity of potassium ions than they do in pure water. According to the principle of Le Chatelier, there is a mobile balance between interstitial solutions and the solid phase. An increase in pore pressure leads to the disruption of mobile balance and, as a result, ions which can decrease the pressure (potassium ions) of the solution move into filtrating water. Water molecules become more mobile in the presence of potassium ions than in pure water (negative hydration) and migrate more easily, removing potassium ions. This leads to a decrease in concentration of 4~ ions in the shales of abnormally high pressured zones. It is interesting to note that mud (drilling fluid) engineers are quite familiar with potassium-based muds which inhibit clay swelling and hydration and, consequently, prevent heaving and sloughing of shales (Chilingarian and Vorabutr, 1981). The removal of potassium ions from abnormally pressured zones prevents the transformation of montmorillonites to illites, which requires potassium ions to complete the reaction. In addition, there is a conversion of illites to montmorillonites (reverse reaction). Both phenomena (in addition to overpressure) contribute to the greater potential of shales to swell because montmorillonites swell more than illites (Rieke and Chilingarian, 1974). The results of radioactivity studies of natural shales in the Kharasavey oilfield (northwestern Siberia) are presented in Table 5-4 and Fig. 5-10. The total radioactivity and the radioactivity of 4~ were obtained from gamma-ray logs and by measuring the radioactivity of 4~ in the core samples. Thus, it appears possible to use the natural shale radioactivity to locate the abnormally high pressured zones in basins with nonequilibrium compaction (origin of abnormal pressure) and where pore pressure is abnormal.
141
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES
TABLE 5-4 Depth of wells, porosity, 4~ radioactivity (imp/min cm3), and total natural radioactivity (Iz, imp/min cm3) in the Kharasavey oilfield (after Dobrynin and Serebryakov, 1989, table 5, p. 88) Well No.
Depth, h (m)
Porosity, 4~ (%)
Radioactivity of 4~ (imp/min cm3)
Total radioactivity (imp/min cm3)
17 9 11 6 3 4 11 16 6 8 9 11 9 16 2 2 2
1812 1858 1504 1415 2068 2201 1508 1820 1417 2237 1528 2511 1530 802 1515 1469 1478
10.6 10.5 16.4 15.4 10.0 10.4 15.0 10.1 14.6 9.0 14.0 8.5 11.0 24.8 11.7 12.8 15.5
3.39 3.27 2.79 2.90 3.15 3.19 2.87 3.21 2.94 2.88 2.58 2.97 2.56 2.26 2.71 3.21 2.76
4.74 4.40 4.00 4.13 4.39 4.27 4.11 4.47 4.14 4.02 3.66 4.29 3.66 3.18 3.80 4.54 3.92
This method can possibly also be used for the paleoreconstruction of a hydrodynamic scenario in the geologic cross-sections based on the 4~ content, because shale can ' r e m e m b e r ' the existence of overpressures in the past in a particular zone (decreasing 4~ content).
PULSED NEUTRON CAPTURE LOGS Pulsed neutron capture (PNC) logging devices have been highly successful in distinguishing between formation waters and hydrocarbons and also in detecting formations that have an abnormally high pressure. These PNC logging devices measure the macroscopic cross-section, Sigma ( r ) , for t h e ~ a l neutron capture in the borehole environment. They have been used to examine formation waters behind casing and monitor production and depletion behavior of hydrocarbon reservoirs. Pulsed neutron capture (PNC) logging was initially developed to measure the parameter Sigma (27) (Youmans et al., 1964). This macroscopic cross-section of the absorption of thermal neutrons, I7, is a basic physical parameter of the formation surrounding the logging instrument. As such, the Z - v a l u e is a function of the chemical composition of the rocks and the amount, type, and composition of the fluids present in the pore space. Inasmuch as the Z - v a l u e s in shale formations can be determined by observing the thermal neutron die-away in the formation, following a burst of neutrons from a
142
G.V. CHILINGAR,V.A. SEREBRYAKOV,S.A. KATZAND J.O. ROBERTSONJR.
Resistivity 2
500
I
5 l
I I
]0
2O
I
I
30 I
'
Total Radioactivity 3 4 5 I
I
I
Radioactivity of 4~ 2 3 4 I
I
I
Q
1000
E w
t-"
,4,.=-
o. (D
1500
2000
o;Ao
o ~,1"r
O o
O 9 1 499
e'~, O
"li Fig. 5-10. Resistivity (p, ohmm) total radioactivity (lr~, imp/mincm3), and radioactivity of 4~ versus depth (m) in shales in the abnormally high formation pressured (AHFP) Kharasavey oilfield, northwestern Siberia. (Modified after Dobrynin and Serebryakov, 1989, fig. 40, p. 88.)
pulsed neutron generator, the Z'-measurement is made by analyzing the time rate of decay of the thermal neutron population. The E-values in shale formations decrease in a regular fashion with depth in normally compacted clastic sequences. Abnormal formation pressures are, however, flagged by divergence from this normal Z-trend (Fertl and Chilingarian, 1987). Although this absorption cross-section is a nuclear measurement, the recorded log response is similar in appearance to the induction log. As a result, the r-measurement can be used in many geological applications in cased holes previously available only from the open-hole resistivity logs. Fig. 5-11 shows a useful application of PNC logs for quantitative formation pressure evaluation (Fertl and Timko, 1970). Shale resistivity (R~h) versus depth for a well drilled in Louisiana in 1946 is shown in Fig. 5-11A. All reservoir sands below 8200 ft have been productive for at least 25 years. This particular well produced from the Klump Series. After a casing collapse below 8100 ft, the plan called for placing the well back on production by recompleting it in the Homeseekers 'A' sand at a depth of 9060 ft
Tepetate, LA 7,000-
-
1946
(A1
.I.I
Original Shale Pressure 1946 (Short Normal)
x---x
' a
Shale Pressure 1966 (Sigma Curve)
Original Mud Weight
IOrtego A
t
*
.-
9.7 Iblgal
,8.000 -
A
5:
Y
c t
G
Q a,
= HomeseekenA I Homeseeken B
13
=
-
=
Kick off Point
0.53(10.2Ib/gal)
12.8 lWgal
14.0Iblgal 14.3 Iblgal Homeseeken C 14.8 lbigal Homeseeken 0 14.9 Iblgal
- Twedel
17.3 Iblgal 17.6 Iblgal
10.2Ib/gal MW-Maximu needed to redrill well
0.3
0.5
1 .O
2.0
Shale Resistivity, R,
20
30
40 50
Sigma Shale, C,
Formation Pressure, 1000 psi
Fig. 5-1 1. PNC log used in quantitative formation pressure evaluation. (After Fertl and Timko, 1970.) (A) Shale resistivity plot in Tepetate field well, Louisiana, drilled in 1946. (B) Sigma shale plot in the same well (cased) based on PNC log run in 1966. (C) Original shale pressure from short normal log (1946) and depleted shale pressures from Sigma curve (1966). (Modified after Fertl and Chilingarian, 1987, fig. 4, p. 32.)
144
G.V. CHILINGAR, V.A. SEREBRYAKOV,S.A. KATZ AND J.O. ROBERTSON JR.
6000
6000
-4===
8000 c~
Q)
r~ m
c~
0
!
-
.~_.. 7000 -
7000 -
8000
9000 ~ 9-5/8" casing ~ ' ~ I0,000 -
~:-
II
~
II
:~
Ib/gal
-
9000 [9"5/8" casin~ ----~
l l l
I0'000-
12.5 16.5 -
l
11,000 -
(D
7" casing
12,000
~~'~
i
12,000
15,000 0.1
" casi
13,000 -
13,000 14,000
t t
i
~5" casing
1
i
Shale Resistivity,
t
16.4 t
"oa'ng
17.6 -
14,000 - - 15,000 2 60
I 50
17.9
I
40
J
30
J, ,
20
-
I
10
Sigma Shale, Ysh
0
Fig. 5-12. Plots of a shale resistivity and Z-shale values versus the true vertical depth, which define the overpressure environment in offshore U.S. Gulf Coast well. (Modified after Taneja and Carroll, 1985.)
by side-tracking the original well above the casing restriction and redrilling to this target. The mud weight required to safely drill this well initially in 1946 to the Homeseekers 'A' target zone was approximately 14.0 lb/gal, because both the sands and shales contained overpressures equivalent to this specific weight of drilling mud. Due to production-related pressure depletion over the years, however, most of the sands had exhibited pressure gradients throughout this oilfield considerably less than hydrostatic. Thus, it was known that the interval to be redrilled would not sustain nor require the high mud weights used to drill the original well. The PNC log was run in the old cased wellbore to evaluate present pressure conditions. Fig. 5-11B presents the Z-trend versus depth to a depth of 9110 ft. The maximum mud weight determined to reach the Homeseekers 'A' sands was 10.2 lb/gal. Fig. 5-11C clearly shows the change in shale pressure due to pressure depletion of the sands. The well was side-tracked at 8120 ft, and redrilled to 9215 ft without difficulty. A mud weight of 10.4 lb/gal was required for redrilling the well rather than the mud weight (MW) of 14.3 lb/gal used for the original drilling fluid. Plots of shale resistivity and Z-shale values versus true vertical depth (Fig. 5-12), were used to define the overpressure environment for 18 offshore Gulf Coast wells in 12 fields to establish the generalized compaction trend (Taneja and Carroll, 1985). The
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES
I I I I I
D
E
0 t-.
o D 0 0 .Q
o
0
,.,...
D !
r,,q
9
/ 2 / /
/
I
,
/
"1- ~ ._
I
/"
~-
~
z
I ,~.~
/..,
I J
I I
I/I
] 45
9
/
/ /
/
/
J
/
/
r .......
//, .
/
9
"/
GH
GO
"~
Formation FPG, psi/ft Equivalent Mud Weight, Ib/gal
Fig. 5-13. Empirical relationship between ZT-shale ratio (Esh(observed)/Xsh(normal)) and reservoir fluid pressure gradient (FPG and equivalent mud weight requirements). GH is hydrostatic pressure gradient; Go is overburden pressure gradient; 1, 2, 3 -- empirical calibration trends established for different areas; dots represent data points obtained in a given area to establish calibration trend. (Modified after Fertl and Chilingarian, 1987, fig. 6, p. 33.)
data were replotted by Fertl and Chilingarian (1987) to highlight the similarities in the normal and overpressure environments. Quantitative pressure evaluation
Two quantitative techniques are available for using PNC logs to locate and evaluate overpressures. Technique A: empirical calibration charts
(1) Plot r - s h a l e values (either on a logarithmic or linear scale) versus depth and establish the normal compaction trendline. (2) Top of the overpressure zone is at a depth where the plotted r - v a l u e starts to diverge from the normal trend. (3) Determine the formation pressure at a specific depth as follows: (a) divergence of observed ,V-shale value from the extrapolated (normal trendline) value determines the ~7-ratio (observed Xsh/normal ZTsh); (b) from Fig. 5-13, the formation fluid pressure gradient (FPG) and equivalent mud weight corresponding to the E-ratio are found.
146
G.V. CHILINGAR, V.A. SEREBRYAKOV,S.A. KATZ AND J.O. ROBERTSON JR.
DE
ql-. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
B
i ~
cO.
PressureTop
a
DA
A
E-Shale Parameter Fig. 5-14. Schematic illustrating the equivalent depth method. (Modified after Fertl and Chilingarian, 1987, fig. 7, p. 33.)
(4) The FPG value is multiplied by the subject depth, i.e., true vertical depth, to obtain the formation pressure.
Method B: equivalent depth method The equivalent depth method is based on a mathematical relationship, which is valid for all logging parameters and includes the following steps. (1) Plot S-shale values and establish the normal compaction trendline. (2) Determine the formation pressure such as (Fig. 5-14): pf-
Go.
DA
--
D E ( G o - GH)
- - DA - - 0 . 5 3 5 D E
(5-22)
where pt is formation pore pressure in psi, DA is depth of interest in overpressured interval in ft, DE is normal, equivalent depth in ft, corresponding to DA, GIj is hydrostatic pressure gradient in psi/ft, and G0 is overburden pressure gradient in psi/ft.
SHALE WATER I N F L U X -
DRIVING MECHANISM
The influx of overpressured shale water into the associated reservoir sands has been discussed by many authors (e.g., see Rieke and Chilingarian, 1974, pp. 270-272). Mathematical model studies suggest a varying pore pressure gradient in overpressured shale sections, with the highest excess pressure being located near the center of massive shales. Less excessive pressure is found in the vicinity of permeable zones, such as sands and sandstones. This concept is supported by field observations of Fertl and Chilingarian (1987): freshening of produced water with time in thick sand-shale sequences due to the influx of fresher shale water into the sands.
147
METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATIONPRESSURES
IES 1964 I
NLL 1967 |
NLL 1968
40
30
20
i
i
,
40
30
20
J
Fig. 5-15. PNC logs run several years following the completion of a high-pressured Louisiana well, which showed effects of pressure depletion. (After Fertl and Timko, 1970.) The increase in E-values in the pay section is due to increased water saturations caused by production. The 2S decrease in shale A apparently was caused by increased compaction and decreased porosity. A represents shale adjacent to permeable sand, and B, shale distant to the permeable sand.
Shale water depletion was diagnosed over comparatively short periods of time in an overpressured south Louisiana well (Fig. 5-15). Two PNC logs had been run a year apart to monitor hydrocarbon saturation changes in the pay zone which was being produced in several adjacent wells. The r - v a l u e changes in the pay sand were caused by the increase in water saturation. There were also changes in the adjacent shales. Zone A, the shale next to the pay, showed a marked Z-decrease as a result of increased compaction and porosity decrease. This suggests the influx of shale water into the sand. In Zone B, the portion of the shale some distance from the permeable sand shows considerably less, if any, variations in S-value as a result of pressure drawdown (Fertl and Timko, 1970).
VARIOUS GEOPHYSICAL W E L L LOGGING METHODS - - A SUMMARY
Various well logging methods significantly aid engineering planning even though short, multiple intervals may have to be logged. Several types of logs measuring electric, acoustic, and nuclear properties of formations can be used. These parameters are plotted versus depth and trendlines are then established for normal compaction. Interpreting such plots depends on their departure from the normal trend. The equivalent depth method (Fertl, 1976) and/or empirical calibration charts can be used in quantitative pressure evaluations for a specific formation, area, or geologic region. Possible pitfalls and constraints to fully utilize the potential of well logs must be recognized (see Table 5-2). Vertical formation pressure profiles obtained from the wireline multiple formation pressure tester is an important tool for improved determination of reservoir pressure and fluid distribution (Gunter and Moore, 1986). These wireline testers can record an
148
G.V. CHILINGAR,V.A. SEREBRYAKOV,S.A. KATZAND J.O. ROBERTSONJR.
unlimited number of precise and accurate pressure measurements during a single trip into the borehole. Applications include: (1) the analysis of naturally fractured reservoirs; (2) pulse testing techniques to establish reservoir continuity; (3) qualitative estimation of permeability in low-permeability formations; (4) reservoir management in producing fields; (5) detection of fluid interfaces from vertical pressure profiles; and (6) verification (calibration) of other overpressure indicators.
CONCLUSIONS
Two groups of quantitative methods for the analysis and prediction of abnormally high and abnormally low formation pressure zones were described. The methods of the first group are based on general geologic and tectonic information and may be used prior to drilling. The methods of the second group are based on the use of geological, geophysical and drilling-related information accumulated in the process of drilling. Using equations of a general form, zones of abnormal pressure can be located using resistivity, density, sonic time travel, gamma-rays and neutron-gamma logs. In these methods, almost all log responses, except radioactivity in the abnormally high pressured zones, are related to porosity. A decrease in natural radioactivity in the abnormally high pressured zones is related to a decrease in 4~ content in the regions with nonequilibrium compaction. The following conclusions have been reached by Fertl and Chilingarian (1987): (1) Industry-wide experience shows that costly misinterpretations are best avoided by studying a combination of several pressure indicators. Not all of them, however, can always be used or are necessarily needed in any one drilling application. (2) Pulsed neutron capture (PNC) logs can be used to detect and quantitatively evaluate the overpressure environments. (3) Empirical correlations between r - s h a l e values as a function of the true vertical depth and magnitude of formation fluid pressure gradients and/or equivalent mud weight requirements can be established for a given geological area. (4) Provided Z-derived normal compaction trendlines can be easily derived, the equivalent depth method allows reliable quantitative formation pressure estimates. (5) PNC logs allow the monitoring of short- and long-term pressure depletion of, and concurrent shale water influx into, hydrocarbon-bearing reservoirs.
BIBLIOGRAPHY Alexandrov, B., 1987. Abnormally High Formation Pressures in Oil and Gas Basins. Nedra, Moscow, 215 PP. Blokh, A., 1969. Water Structure and Geological Processes. Nedra, Moscow, 216 pp. Chilingarian, G.V. and Vorabutr, P., 1981. Drilling and Drilling Fluids. Developments in Petroleum Science, 11. Elsevier, Amsterdam, 767 pp. Daniel, W.L. and Fertl, W.H., 1984. Logging high-angle, long-reach boreholes. Oil Gas J., Dec.: 103-108. Dellinger, T.B., Graveley, W., Tolle, G.C. and Sexton, T.H., 1983. Field testing to extend reach of directional wells. Oil Gas Eur. Mag., 9(2): 14-16.
METHODS OF ESTIMATINGAND PREDICTINGABNORMALFORMATIONPRESSURES
149
Dobrynin, V. and Serebryakov, V.A., 1978. Methods for Prediction of Abnormally-High Formation Pressure. Nedra, Moscow, 231 pp. Dobrynin, V. and Serebryakov, V.A., 1989. Geological-Geophysical Methods for Prediction of Pressure Anomalies. Nedra, Moscow, 288 pp. Dobrynin, V., Rapoport, M. and Serebryakov, V.A., 1979. Prediction of anomalously-high interval pressures from seismic data. Int. Geol. Rev., 21(5). Dobrynin, V., Serebryakov, V. and Srebrodol'skiy, A., 1982. Determination of abnormally-high formation pressure in shale using the method of compressional curves. Geol. Nefti Gaza, 5: 25-28. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 385 pp. Fertl, W.H. and Chilingarian, G.V., 1977. Importance of abnormal formation pressures to the oil industry. Paper SPE 5946 presented at the Spring Meeting of the European Society of Petroleum Engineers of AIME, Amsterdam; also J. Pet. Technol., 29(4): 347-354. Fertl, W.H. and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1(1): 23-38. Fertl, W.H. and Sahay, B., 1984. Occurrence of high-pressure formations on and off India. Oil Gas J., 82(32): 81-86. Fertl, W.H. and Timko, D.J., 1970. How abnormal pressure detection techniques are applied. Oil Gas J., 68(2): 62-71. Fertl, W.H. and Timko, D.J., 1971. Parameters for identification of overpressure formations. Paper SPE 3223 presented at the 5th Conference on Drilling and Rock Mechanics, Society of Petroleum Engineers of AIME, Univ. Texas, Austin, TX. Foster, J.B. and Whalen, H.E., 1966. Estimation of formation pressures from electrical survey offshore Louisiana. J. Pet. Technol., 18(2): 166-171. Gunter, J.M. and Moore, C.V., 1986. Improved use of wireline testers for reservoir evaluation. Paper SPE 14063 presented at the International Meeting of Petroleum Engineers, Beijing, March 17-20, 1986. Hottman, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., 17: 717-725. Nyein, R.K., MacLean, L. and Warris, B.J., 1977. Occurrence, prediction and control of geopressures on the northwest shelf of Australia. Aust. Pet. Explor. Assoc., 17(1): 64-72. Randall, R.R., Fertl, W.H. and Hopkinson, E.C., 1983. Time derived Sigma for pulsed neutron capture logging. J. Pet. Technol., 35(6): 1187-1191. Randall, R.R., Lawrence, T.D., Frost, E. and Fertl, W.H., 1985. PDK-100 log examples in the Gulf Coast. Trans., SPWLA, Paper XX. Rieke, H.H., III and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Developments in Sedimentology, 16. Elsevier, Amsterdam, 424 pp. Schaar, G., 1985. The occurrence of hydrocarbons in overpressured reservoirs of the Baram Delta, offshore Sarawak, Malaysia. Proc. Indonesian Pet. Assoc., Fifth Annu. Convention, June, pp. 163-169. Schultz, W.E., Smith, H.D., Verbout, J.L., Bridges, J.R. and Garcia, G.H., 1983. Experimental basis for a new borehole corrected pulsed neutron capture logging system (TMD). Trans., SPWLA, Paper DD. Serebryakov, V. and Chilingar, G., 1994. Investigation of underpressured reservoirs in the Powder River Basin, Wyoming and Montana. J. Pet. Sci. Eng., 11: 249-259. Serebryakov, V., Chilingar, G.V. and Katz, S.A., 1995. Methods of estimating and predicting abnormal formation pressures. J. Pet. Sci. Eng., 13(2): 113-123. Serpas, C.J., Wichmann, EA., Fertl, W.H., DeVries, M.R. and Randall, R.R., 1977. The dual detector neutron lifetime log - - theory and practical applications. Trans., SPWLA, Paper CC. Smith, S.W., 1978. The use and validity of pulsed neutron surveys in current drilling tests. Trans., SPWLA, Paper H. Starostin, V., 1985. Estimation and Prediction of Abnormally High Formation (Pore) Pressure Using Geological-Geophysical data in the Dniepr-Donets Depression. Ph.D. thesis, MINKhiGP, Moscow. Taneja, EK. and Carroll, J.E, 1985. Abnormal pressure detection using a pulsed neutron log. Trans., SPWLA, Paper MM. Timko, D.J. and Fertl, W.H., 1971. Relationship between hydrocarbon accumulation and geopressure and its economic significance. J. Pet. Technol., 23(8): 923-931.
150
G.V. CHILINGAR,V.A. SEREBRYAKOV,S.A. KATZAND J.O. ROBERTSONJR.
Vassoevich, M., 1960. Experiment to build typical gravitational curve of the shale deposits compaction. Nov. Neft. Tekh., 4: 11-15. Wahl, J.S., Nelligan, W.B., Frentrop, A.H., Johnston, C.W. and Schwartz, R.J., 1970. The thermal neutron decay time log. J. Pet. Technol., 22(12): 365-380. Weller, J.M., 1959. Compaction of sediments. Bull. Am. Assoc. Pet. Geol., 43(2): 273-310. Youmans, A.H., Hopkinson, E.C., Bergan, R.A. and Oshry, H.I., 1964. Neutron lifetime log, a new nuclear log. J. Pet. Technol., 16(3): 319-329. Zoeller, W., 1984. Determine pore pressures from MWD gamma ray logs. World Oil, 3: 97-102.
151
Chapter 6
DRILLING PARAMETERS
W.H. FERTL, G.V. CHILINGARand J.O. ROBERTSONJR.
DRILLING RATE (PENETRATION) Drilling rate is a function of weight on the bit, rotary speed, bit type and size, hydraulics, bottom-hole cleaning properties of drilling fluid, and formation characteristics. Under controlled conditions of constant bit weight, rotary speed, bit type, and hydraulics, the drilling rate in shales decreases uniformly with depth. This is due to increase in degree of compaction of shales with depth; however, in pressure transition zones and highly overpressured zones the penetration rate often increases. Slower penetration rate is frequently observed in the sealing pressure barrier (caprock) overlying this transition zone. Any other major lithological changes in the shales (silty and/or limey shales, mudstones, etc.) will also cause penetration rate variations. Penetration rate should be plotted at proper depth increments (5- to 10-ft increments in slow-drilling formations or in 30- to 50-ft increments in fast-drilling intervals). Plotting such data points, however, should not lag too much behind the total drilling depth (not more than twice the plotted depth increment behind the total well depth reached by the bit). Drilling rate recorders automatically plot rate in feet per hour versus depth. Simple rules of thumb, such as the one proposed by Forgotson (1969) that a twofold penetration rate increase indicates the onset of overpressures, do not always apply. For example, an increase in mud weight to 12 lb/gal upon encountering the transition zone, may partially mask any further pressure increase with depth. It is also of interest to note that the first unit of mud weight (lb/gal) in excess of formation pore pressure will reduce the drilling rate more than each subsequent unit of mud weight (lb/gal) increase (Moore, 1974). Complications may also arise during bit drilling, which may mask any penetration rate change due to overpressure. Penetration rate may even decrease due to fluctuating rotary torque and erratic action of the drill bit on the bottom of the borehole.
Normalized rate of penetration (d-exponent) Inasmuch as it is not always possible and/or feasible to maintain the bit weight and rotary speed constant, the concept of the d-exponent was developed by Jorden and Shirley (1966). Data required to calculate the d-exponent, a dimensionless number, are the penetration rate (R, in ft/h), bit size (diameter D, in inches), weight on bit (W, in
152 0.9 ,,C,.811,0
d~
v 1;5 2.
1.
odc t.5
2.0
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i
i
11
10
I
A
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Illll((lllli) \
...
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i
-
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dc dr. I8i'tn~.
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSON JR.
II
B
C
11'111111~111 _'1 D
Fig. 6-1. Plotting the dc-exponent on a logarithmic scale using the mud weight overlay technique in South Texas (A,D), South Louisiana (B) and Oklahoma (C). (After Zamora, 1972, fig. 2, p. 70. In Chilingarian and Vorabutr, 1981, fig. 16-5, p. 588.) Note effect of bit size change (from 8 1/2 inches to 6 1/2 inches) on normal trendline in the South Texas well (D). Trendlines represent constant mud specific weights. (Courtesy of Oil and Gas Journal.)
lb), and rotary speed (N, in rpm):
log(R/6ON) d - log(12W/lO6D)
(6-1)
Basically, plots of d-exponent versus depth show a decreasing trend with depth. In transition zones and overpressured environments, in many cases the calculated values diverge from the normal trend to lower than normal values. Quantitative pressure evaluation can then be made on using the equivalent depth method (Fertl, 1976, p. 123) or specially constructed, transparent overlay of parallel, equivalent mud weight lines for the specific depth scale used for the d-exponent (see Fig. 6-1). The values of the d-exponent are affected by any change in the basic input parameters in Eq. 6-1. Furthermore, it is often difficult to establish reasonable values for bit weight in soft formations. Any major lithologic change in the shale section (e.g., limey or silty shales, mudstones, and marls) will also affect the d-exponent. The same is true in poorly maintained drilling fluid systems and for drastic changes in mud weight. Inasmuch as Eq. 6-1 ignores the direct effect of mud weight on drilling rate, a modification of the d-exponent has been proposed by Harper (1969) to normalize the d-exponent for the effective mud weight as follows: MW1 dc -- d . MW2 (6-2) where dc is modified (corrected) d-exponent, MW1 is normal mud weight, and MW2 is actual mud weight used.
0[
DRILLINGPARAMETERS
153 A
o4[
B \
o
..ff e,-
12'
I
1.O
I
f
2.0
d- exponent
'
I
3,0
0,5
I
I
t
1.O
I
2,5
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Fig. 6-2. Comparison plots of depth versus d-exponent and de-exponent in the same well. Protective casing seat is at a depth of 8700 ft. Note that the de-exponent more clearly defines the overpressured zone. (Modified after Fertl, 1976, fig. 4-6, p. 125. In Chilingarian and Vorabutr, 1981, fig. 16-2, p. 586; Courtesy of Oil and Gas Journal.)
Consequently, de-plots represent a substantial improvement over d-plots because mud weight effects are considered (Figs. 6-2-6-4). They are used by the industry worldwide, both on- and offshore. Quantitative pressure methods include (1) the equivalent depth method, (2) transparent overlays of parallel equivalent trend lines for mud weight or pore fluid pressures (Fig. 6-1), or (3) a specially designed de-slide rule. Drilling information is normally used in elastic sediments for calculating the de-exponent. In several areas, in drilling through mixed lithologies (i.e., sands, shales, limestones, and dolomites) such computations often give good results. Frequency of calculating the d~-exponent depends on how fast formations are being drilled. Usually, the d~-exponent is determined for every 10 ft of increment in depth. In fast drilling areas, 25-, 50-, or even 100-ft depth increments may be adequate, whereas in slow-drilling areas, i.e., hard-rock intervals, 5-ft depth intervals may become necessary. The mathematical relationships shown in Eqs. 6-1 and 6-2 clearly indicate the effects of drilling variables on d~-values. Effects of hydraulics, weight on bit, bit size and type, and overbalance in the case of drilling through soft, elastic formations are discussed below.
Effect of drilling hydraulics The equations for d- and de-exponents are based on the assumption that drill cuttings are being effectively removed. In most wells drilled in the mid 1960s, transition zones were encountered at moderate depths, i.e., 8000 ft or slightly deeper, and hydraulics programs were usually adequate. Minor fluctuations in circulation rate did not significantly affect the penetration rate.
154
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSONJR. -6
"0 a)
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-
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-
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-
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9
I
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I
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D I I
0.5
I
10
I
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I
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ACTUAL MUD WEIGHT, Ib/gal Fig. 6-3. Comparison of plots of depth versus d-exponent and de-exponent based on drill bit data, Louisiana well, U.S.A. (Modified after Fontenot and Berry, 1975, fig. 3, p. 127. In Chilingarian and Vorabutr, 1981, fig. 16-3, p. 587" Courtesy of Oil and Gas Journal.)
Drilling in areas where overpressured zones are encountered in shallow, unconsolidated elastic formations, indicates the increased importance of proper hydraulics programs in achieving effective penetration rates in these soft formations. The latter are drilled utilizing a combination of tooth cutting and jetting action. As a result, increased jetting action will increase penetration rate which, in turn, will result in decreasing values of the de-exponent. This gives an appearance of a non-existent transition zone. Furthermore, maintaining a constant circulating rate when a transition zone is anticipated in unconsolidated sediments will minimize effects of hydraulics. Transition zones at depths as shallow as 1500 ft have been successfully defined by .~ontrolled drilling conditions (i.e., maintaining constant bit weight, rotary speed, mud weight, and circulation rate). The fast penetration rate may be measured even by timing with a stop watch the drill joints lowered during drilling.
DRILLING PARAMETERS
155 m 0
E : Or-
8
-
O
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~-
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00 9.2 9
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oA
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I
0.5
i
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I
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I
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Fig. 6-4. Comparison of plots of depth versus d-exponent and dc-exponent based on drilling data averaged over 50-ft intervals; Louisiana well, U.S.A. (After Fontenot and Berry, 1975, fig. 6, p. 129. In Chilingarian and Vorabutr, 1981, fig. 16-4, p. 588; Courtesy of Oil and Gas Journal.)
Effect of drill bits When button and diamond bits are used instead of standard rock bits, an empirical correction is required, i.e., a 1-inch reduction in the bit diameter is used in calculations. Reliability of this concept in actual field applications, however, is debatable. There is a decrease in dc-values when a button or diamond bit is used. It should be assumed that, at the point of a bit change, the first shale layer drilled with the button or diamond bit has the same pore pressure as the last shale layer drilled with a rock bit. Hence, a shift of the normal compaction trend line in the de-versus-depth plot is required to account for the change in bit type. This shift is similar to the one required due to the change in bit size. The effect of bit size change is shown in Fig. 6-1. Consequently, trendline shifts become necessary when the (weight-on-bit)/(bit size) ratio is significantly changed, regardless of the type of the bit.
156
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSON JR.
Bit wear will cause a decrease in penetration rate and, thus, an increase in the dc-exponent. Consequently, dull bits can mask the presence of a transition zone. Consideration of bit wear in graphical and computerized techniques will eliminate this limitation. An alternative solution is to study the offset well data and previous bit performance in order to determine when to pull a bit prior to drilling through transition zones. Although this approach may result in an additional trip, it will greatly reduce the hazards of a well kick and time required to kill it, or even of a blowout, should the downhole mechanical problems occur.
Overbalance The dc-exponent is also affected by the difference between hydrostatic pressure of the mud column and formation pressure (i.e., amount of overbalance). A linear, instead of the required hyperbolic, correction will introduce a serious error into calculations with increasing overbalance. In other words, arbitrary and 'emotional' mud weight increases should be avoided. Knowledge of formation pressure while drilling is important for achieving safe and economic operations and in the selection of proper casing seats. The dc-exponent, supplemented with several other pressure indicators, provides the drilling engineer with the required information for making proper decisions.
D R I L L I N G RATE E Q U A T I O N S
The application of proper drilling rate equations in order to establish correlations between the formation and borehole pressures requires instrumentation at the rig site to record simultaneously several drilling parameters. For example, a general equation for penetration rate in shales has been developed by Combs (1968) using data from six Louisiana wells in a regression-type analysis. Combs' correlation shows that penetration rate (R) is proportional to the weight on the bit (W), rotary speed (N), and bit hydraulics, each raised to a fixed power:
R - Ro ~
-~
31~D,
f (Po)f (T)
(6-3)
where Dh is borehole diameter (inches), Dn is bit nozzle diameter (inches), f is function and n3 is weight, speed and hydraulics exponents, respectively; Combs' recommendations: nl - 1.0, n2 = 0 . 6 , n3 -- 3; N is rotary speed (rpm), Q is flow rate (gal/min), Pa is differential pressure (lb gal -l 1000 ft-I), R is penetration rate (ft/h), R0 is shale drillability with sharp bit at zero differential pressure (ft/h), T is bit wear index-equivalent rotating index, and W is weight on bit (in 1000 lb). According to Combs (1968), penetration can be predicted from Eq. 6-3 with a standard deviation of approximately 30%, whereas pore pressure can be predicted with a standard deviation of about 1.0 lb/gal equivalent pore pressure. In connection with computerized drilling control, Young (1968) expressed penetration of, n l, n2
DRILLINGPARAMETERS
157
rate as follows:
R=GNm(W-Wf)K
(6-4)
where a reciprocal drilling constant (K), the weight intercept value (Wf), and the bit rotary speed exponent (m) are determined by a five-spot drilling test. G is a function of the normalized bit tooth height. Drilling performance optimization and identification of overpressured formations have been also investigated by Wardlaw (1969). Several other empirical equations for drilling rate determination have been developed by different investigators. Consequently, field data from (1) previously drilled adjacent wells, and/or (2) feedback data from short-interval testing in the subject well are usually needed in order to determine input parameters. Unfortunately, drilling rates change with lithologic variations, even though the pressure gradient remains constant. Deviated holes, severe dog legs, drilling from floating vessels, and frequently occurring water-sensitive and sloughing shales can make these indicators questionable. Development of fully automated pressure-detection techniques is difficult, except for local geographic areas where the lithology is well known. Other pressure indicators, such as chemistry of produced water, drilling mud properties, density of formation cuttings, and wireline and related tools must still be used meticulously.
POROSITY AND FORMATIONPRESSURELOGS Several models establish the relationship between the formation characteristics and drilling parameters, and provide an early indication of formation type and porosity and pore pressure variations (Zoeller, 1970; Boone, 1972). Several service companies have made similar 'data units' commercially available, and many oil companies and drilling contractors have developed their own drilling program models. For example, a field example of formation porosity and pressure logs in an offshore Louisiana wildcat (U.S.A.) is shown in Fig. 6-5 (Fertl, 1976, p. 131). There is a 9g5 inch casing seat at a depth of 14,401 ft, which is followed by a fast pressure increase over the next 600 ft. Bourgoyne (1971) proposed a general equation relating various controllable drilling variables and drilling performance, which can be expressed as follows:
R = K . f l ( W / D ) , f2(N)- f 3 ( H ) , f4(Ap)
(6-5)
where R is rate of penetration (ROP); K is drillability constant or normalized ROP; fl (W/D) is a function describing the effect of bit weight, W, per inch of bit diameter, D, on ROP; fz(N) is a function defining the effect of rotary speed, N, on ROP; f3(H) is a function defining the effect of tooth dullness, H, on ROP; and f4(Ap) is a function defining the effect of the differential pressure across the hole, A p, on ROE Normalized penetration rate, K, is related to the bulk density by the following
15 8
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSONJR.
5o
Porosity, %
|,,
Pore Pressure, "A" Exponent, o~8 Ib/gal 8 ~ 8 Ib/gal a J
I
I
g__
Bit
#27
~
Bit
I
#28 #29
9%i0.
Bit
t
Bit
#31
o o c)
Fig. 6-5. Field example of formation porosity and pore pressure logs in an offshore Louisiana wildcat well, U.S.A. The curve on the right ('A' exponent) gives the value for pore pressure taking porosity and lithology variations into account. Solid circles represent actual mud weight in borehole. (After Fertl, 1976, fig. 4-10, p. 131. In Chilingarian and Vorabutr, 1981, fig. 16-6, p. 592.)
equation: Pb--2.65--1 65(Sg+l~ 9
Sg
(6-6)
where Pb is bulk density in g/cm 3, and Sg is rock strength parameter (e.g., a value of 5.2 in the U.S. Gulf Coast area). These bulk density values are then converted to formation pseudo-porosity, which closely agrees with the calculated porosity from geophysical well logs, such as a density log. Bourgoyne (1971) developed a graphical approach for these concepts for wellsites without digital facilities.
DRILLINGPARAMETERS
159
Belotti and Gerard (1976) discussed a similar system, which was developed in Europe and was successfully tested in more than 40 wells. The system consisted of a set of sensors which acquire necessary information and transmit it to an on-site data unit, where the information is scaled, displayed, recorded and processed by the mini-computer. Storage on magnetic tape cassettes allowed playback of magnitude of overpressure, porosity, and geologic information at desired depth intervals for comparative studies with other individual pressure indicators, such as well logs. Herbert and Young (1972), using historical field data from several Louisiana Gulf Coast wells, developed equations based on regression analysis for predicting pore pressures. When the results of this analysis are applied to drilling data, the transition from normal pore pressures to overpressures can be predicted. This, however, can be done only on a geographically-regional basis. Correlations between the well log data and rock drillability have been developed by Gstalder and Raynal (1966) and E1-Hadidi (1970). Acoustic transit time data from geophysical well logs can be used to predict rock drillability, provided the lithology is known. The basic concepts of the SNAP log (Lutze et al., 1972) apply the vibrations from the tricone bit, as measured at the Kelly, to give an instantaneous log of the formation characteristics while it is being drilled.
LOGGING WHILE DRILLING Methods have been developed for recording the formation, mud, and bit data at the bottom of the borehole, and then transmitting these data to the surface. The great need for the development of additional energy resources and ever-increasing costs of drilling and exploration, created an incentive for developing methods providing downhole real-time measurements. Proposed methods and granted patents are numerous. Logging-while-drilling measurement systems essentially perform only two basic functions: (1) recording of the desired parameters at the bottom of the wellbore, and (2) data transmission to the surface. Downhole measurements comprise: (1) well control information, (2) directional drilling control, (3) drilling optimization, and (4) formation evaluation. Many different logging-while-drilling systems have been developed. Basically, there are four different types of data telemetry: (1) mud-pressure pulses, (2) insulated conductor or cable, (3) electromagnetic methods, and (4) acoustic methods.
TORQUE Torque variations are continually monitored at the drilling rigs. Torque usually increases gradually with depth due to increased wall-to-wall contact of drillpipe and wellbore. In the presence of underbalance (i.e., negative differential pressure), overpressured shales tend to flow or heave into the borehole. Hence, a drastic increase in torque may serve as an additional pressure indicator.
160
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSON JR.
DRAG
Drag is defined as the excess in hook load over the free handling load. Drastic increase in drag may signal the presence of an overpressured formation. In the presence of a gradual pore pressure increase, however, as in very long transition zones or in the case of drilling from floating vessels, this pressure indicator becomes questionable. Furthermore, increase in drag may be caused by bit balling, severe dog legs, deviated holes, differential sticking, and extra volume of cuttings influx into the wellbore while drilling through transition zones.
DRILLING MUD PARAMETERS
Mud-gas cutting Mud logging aids in formation evaluation and detection of overpressured zones. As early as 1945, the use of mud-gas logging was recommended as an overpressure indicator and as a warning of impending blowouts (Pixler, 1945). Similarly, Rochon (1968) proposed mud-gas anomalies as an aid in controlling drilling mud hydrostatic head-pore pressure relationships. If formation permeabilities are extremely low, the degree of gas cutting can be roughly correlated with the amount of underbalance (Goldsmith, 1972). Generally speaking, however, mud-gas cutting may or may not be directly related to the increased formation pressures, because it is greatly affected by the geological environment penetrated and the drilling techniques used in the subject well (Fertl, 1973; Daw et al., 1977). Several factors which may affect mud-gas logs and, thus, complicate their use for pressure detection include (Fertl, 1973): (1) potential pay zones, (2) connection gas, (3) Kelly air, (4) downtime, (5) gas composition, (6) presence of lignite and (7) coal seams, (8) degradation of mud additives, (9) gas flushing, (10) volcanic material, (11) deep-seated mud volcanoes, (12) faults, (13) shale gas, (14) thermodynamic processes, and (15) recycled gas. Equipment for gas detection and analysis of gas is readily available.
Flowline specific weight of drilling fluids Reduction in the specific weight of the drilling fluid at the mud flowline can be used as an additional indicator for gas cutting and the possible presence of overpressured formations. Consequently, continuous mud weight indicators have become an integral part of many on-site data collection and analysis units. Issenmann and Lucon (1971) discussed a continuous mud weight recorder, which basically consists of a constant-height column through which mud from the wellhead outlet is circulated by a special pump at a constant flow rate. The weight of the mud is measured by a pressure gauge located at the bottom of the column and then transmitted to a recorder. Another high-resolution drilling fluid monitor system, which consists of pressure and density sensors, has been developed by Goddard et al. (1973). The measurements are
DRILLINGPARAMETERS
161
based on the principle that the degree of absorption of gamma rays by a material is a function of the density of that material. With proper calibration, radioactive densometers provide density measurements with an accuracy of +0.1 lb/gal for muds in the 7-20 lb/gal specific weight range. Pressure kicks
Balanced drilling techniques require a very narrow margin between the effective pressure control and threatened blowout. Differential pressures are frequently reduced considerably below 500 psi. Improper pressure balance, therefore, may cause well kicks, which can be a direct indication of the presence of overpressured formations. Whereas pressure kicks have occurred at pressure differentials as high as 9 lb/gal, the control of most kicks requires less than 2 lb/gal mud weight increase. Pressure kicks in high-pressure wells are influenced by the following factors: (1) difference between pressure due to the hydrostatic mud-column weight and formation pressure; (2) thermodynamic behavior of the gas; (3) interaction of gas with drilling fluids (especially oil-base); (4) downhole pressures and temperatures; and (5) time required for the circulation of mud (which is a function of depth) and recording of the transmitted pressures. Further considerations include: (a) well location, including onshore and offshore remote areas; (b) deep-water drilling; and (c) pressure kicks associated with drilling shallow surface holes and zones below the protection pipe. Excellent discussions and detailed reviews of well control methods are available in the literature. The articles by O'Brien and Goins (1960), Goins and O'Brien (1962), Goins (1968, 1969), Rehm (1969), Moore (1974), West (1976), Bourgoyne (1976), Nance (1977) and Adams (1977) are notable examples. In general, however, proper pressure control requires installation of blowout preventor valves, adjustable surface chokes, accurate and reliable pressure reading equipment, gas separators, and drilling and mud analysis equipment. In addition, the presence of trained rig personnel, with a sound understanding of the basic concepts involved and having a planned control program to meet any emergency, is of utmost importance. Flowline temperature
In a pressure transition zone, the formation pressure increases with depth at a rate above the normal one. The same appears to hold true for the rate of formation temperature increase with depth. Inasmuch as heat conductivity varies with rock and fluid characteristics of subsurface formations, overpressured, high-porosity shales act as 'thermal barriers', thereby locally increasing the geothermal gradient (Jones, 1968; Fertl and Timko, 1970). Lewis and Rose (1970) proposed a mathematical model relating overpressures and high formation temperatures, which is based upon basic heat flow considerations (Guyod, 1946). Changes in flowline temperature gradients of up to 10~ ft have been observed prior to and/or when entering overpressured intervals. This pressure indicator, however, is also affected by the lithology, circulation and penetration rates, tripping the drillstring for bit change, long risers in deep-water drilling, and drilling through permafrost
162
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSONJR.
2
-
4
-
i
AHFP top fro
6
0 0 0
8
r
lo
~-~
sonic log ~
i
c~
~, 12
-
Max. temp.
mud 14
weight
Q~
= 7 3 7 0 psi
i1~
= 14.7 Ib/gal
Kick
-
mud
weight
from
11.3 to 14.5 Ib/gal
ranged
16
18
= 167~
P = 17,000 x 0.433 G = 0.767
I
t 40
,
I I,i 60 80 100
Ats~, l~sec/ft
,
I 100
I iI
i~ Equivalent temperature for i. normal conditions at 1 7,000 ft. d I 200
I 300
Temperature, ~
, 2
,
I 4
.
t 6
.
I 8
. .I 1/0
Formation Pressure, 1000 psi
Fig. 6-6. Use of quantitative pressure evaluation using flowline temperature data in a Texas wildcat, U.S.A. For comparison, an acoustic plot and pore pressure variations with depth are presented. Casing seats are also shown. G = geostatic pressure gradient in psi/ft; A H F P = abnormal formation pressure; and M W = specific weight of drilling mud in lb/gal. (After Fertl, 1976, fig. 4-10, p. 131. In Chilingarian and Vorabutr, 1981, fig. 16-7, p. 596).
intervals. Thus, certain precautions and refinements are required in use and interpretation of temperature gradients (Wilson and Bush, 1973) when plotting flowline temperatures, including (1) use of temperature readings (points) of each drill bit run, (2) replotting segments of individual bit runs end-to-end without regard to actual temperature values, and (3) use of inlet and outlet flowline temperatures. The possible application of the flowline temperature data as a semiquantitative pressure indicator in a Texas wildcat has been illustrated by Fertl (1976, pp. 146-147). Fig. 6-6 shows a similar, or at least complementary, evaluation of both acoustic log and flowline temperature data in this well. Resistivity, chloride ion content, and other methods
Relationship between the salinity of formation waters and formation pressure variations in consolidated and unconsolidated rocks has been discussed by Chilingarian and Rieke (1968), Chilingar et al. (1969), Overton and Timko (1969), and Fertl and Timko
DRILLINGPARAMETERS
163
(1970). The increase or decrease in the chloride content of the drilling mud between the inlet and outlet of the mud stream can be related to the drilling and pressure conditions. In addition, the drilling rig data gathering units enable measuring and recording both inlet and flowline drilling fluid resistivities. Other techniques, such as variations in the contents of specific ions, redox and pH measurements on the drilling mud stream, and various physical and chemical analyses of drill cuttings, have been investigated by Fertl and Timko (1973a,b).
Pit level and total pit volume Pit level indicators, which monitor variations in the total mud volume, may show mud-volume reduction caused by lost circulation or increase in mud volume due to the fluid entry into the wellbore as a result of unexpected high formation pressures. An ultrasonic equipment exists to measure accurately drilling fluid levels in mud tanks without having any contact with the mud (Dupin de Saint Cyr, 1973). Hence, this method is particularly effective on floating, deep-water offshore drilling figs.
Hole fill-up If the drillstring is pulled, the mud volume needed to fill the borehole should be equal to the displaced pipe volume. Keeping the hole full is especially critical at the time when drill collars are pulled, because on pulling the same length of collars as that of the drillpipe, the level of drilling mud in the borehole will fall four to five times as fast. Furthermore, if salt water, oil, or gas from the formation enters the well, the mud volume required to fill the borehole will be less than the displaced volume of the pipe pulled out. Consequently, this gives the first indication of a pressure kick. Measurement of mud volume used to fill the borehole can be checked from changes in the pit mud level.
Mud flow rate Flow rate measurements are superior to pit level checks, because even small flows can be detected before they become sufficiently large to show on any pit level measuring device. More time is available, therefore, to take proper control measures.
SHALE CUTTINGS PARAMETERS
Shale bulk specific weight Bulk specific weight of drill cuttings usually increases with depth. Measurement techniques include (1) the high-pressure mercury pump technique, (2) the fluid density gradient column, and (3) the mud balance method. Care must be taken in selecting and preparing the drill cuttings for analysis. Multiple cuttings samples have to be tested due to the variance in sample data. The average bulk specific weight value, for a given depth,
164
W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSON JR.
is then plotted on a linear or logarithmic scale versus borehole depth, thus establishing normal compaction trend lines. Inasmuch as shale porosity commonly increases in overpressured zones, any decrease in bulk specific weight may indicate the presence of overpressured environments. Quantitative pressure evaluation is then possible by the equivalent depth method (Fertl, 1976) or from empirical curves established for a given area (Boatman, 1967). Major limitations are (1) examination of cavings and/or recirculated cuttings which constitute the contaminating part of drill cuttings being investigated, and (2) limited care taken by rigsite personnel to collect and analyze samples. Several other factors, which may greatly affect the measured bulk specific weight values of drill cuttings, include: (1) presence of shale gas which decreases the apparent bulk specific weight values; (2) presence of organic-rich shales, which results in lower bulk specific weight values; (3) lithologic variations, e.g., presence of silty or sandy shales, mudstones, and marls; variation in carbonate content of shales also affects bulk specific weight; (4) presence of heavy minerals, such as pyrite (Permian Basin, U.S.A.; offshore Cameroon, Africa; South China Sea area), siderite (South China Sea area; Mackenzie Delta, Canada), and mica (biotite and muscovite; North Sea area), will increase the bulk specific weight values; (5) age boundaries, unconformities, differential compaction, structural effects, and position within the clastic basin may affect the normal compaction trendline (Fertl, 1977).
Shale factor The shale factor can be successfully measured by the methylene blue test (Nevins and Weintritt, 1967). This shale formation factor method (Gill, 1968; Mondshine, 1969; Gill and Weintritt, 1970) may be equated with the cation exchange capacity (CEC) of solids carried by the drilling fluid out of the wellbore. This CEC value, in turn, can be related to the water-holding capacity of drill cuttings or montmorillonite content. The shale factor also appears to be a supplementary and useful indicator for the detection of impermeable pressure seals (caprocks) on top of the overpressured zones.
Volume of shale cuttings During drilling, entry into overpressured environments is characterized by an increase in the penetration rate, which gives rise to an increase in volume of cuttings over the shale shaker.
Shape and size of shale cuttings In pressure transition zones, the shape of drill cuttings is angular and sharp, rather than rounded as found in normal, hydrostatic pressure environments. Furthermore, cuttings from high-pressure formations are unusually large and splintery in appearance.
DRILLINGPARAMETERS
165
OTHER PRESSURE INDICATOR METHODS Several unconventional methods for detecting overpressured formations and, possibly, even predicting transition zones ahead of the drill bit have been investigated in detail by Fertl and Timko (1973a,b). These m e t h o d s include: (1) shale cuttings resistivity, (2) filtration rate of shale slurry; (3) filtrate (shale water) color; (4) shale cuttings moisture index; (5) litho-function plots; (6) bicarbonate content of shale slurry filtrate; (7) redox and pH potential m e a s u r e m e n t s ; (8) distribution of specific ions in shale slurry filtrates.
DRILLING CONCEPTS IN OVERPRESSURED ENVIRONMENTS M a x i m u m well control and m i n i m u m cost are key factors in present-day drilling operations. To achieve this, a basic understanding of two key formation pressures, i.e., formation pore pressure and fracture pressure, is a prerequisite. This aspect has been discussed in detail by Chilingarian and Vorabutr (1981).
BIBLIOGRAPHY Adams, N., 1977. Deep waters pose unique well kick problems. Pet. Eng., 49(5): 25-36. Belotti, E and Gerard, R.E., 1976. Instantaneous log indicates porosity and pore pressure. World Oil, 183(5): 90-94. Boatman, W.A., 1967. Shale density key to safer, faster drilling. World Oil, 165(2): 69-74; also J. Pet. Technol., 19: 1423-1431. Boone, D.E., 1972. Porosity and pressure log performs well in the North Sea. Pet. Eng., 48(5): 122-218. Bourgoyne, A.T., 1971. A graphical approach to kick severity calculations. Pet. Eng., 48(9): 22-28. Bourgoyne, A.T., 1976. Drilling strength analysis in evaporites. Pet. Eng., 48(9): 22-28. Chilingarian, G.V. and Rieke III, H.H., 1968. Data on consolidation of fine-grained sediments. J. Sediment. Petrol., 38(3): 811-816. Chilingarian, G.V. and Vorabutr, E, 1981. Drilling and Drilling Fluids. Developments in Petroleum Science, 11, Elsevier, Amsterdam, 767 pp. Chilingar, G.V., Rieke III, H.H., Sawabini, S.T. and Ershaghi, I., 1969. Chemistry of Interstitial Solutions in Shales Versus that in Associated Sandstones. 44th Annu. Fall Meet., Soc. Pet. Eng., AIME, Denver, CO, SPE 2527, 18 pp. Combs, G.E, 1968. Prediction of Pore Pressure from Penetration Rate. 43rd Annu. Fall Meet., Soc. Pet. Eng., AIME, Houston, TX, SPE 2162, 16 pp. Daw, R.N., Myers, D.L. and Mercer, R.F., 1977. Mud gas logs help predict mud pit levels on floaters. World Oil, 177(7): 57-58. Dupin de Saint Cyr, E, 1973. Ultrasonic device monitors mud pit levels on floaters. World Oil, 177(7): 57-58. E1-Hadidi, S., 1970. Use of Well Logging Data for Predicting of Rock Drillability. M.S. Thesis, Univ. California, Berkeley, CA, 90 pp. Fertl, W.H., 1973. What to remember when interpretating mud-gas cutting. World Oil, 177(4): 67-72. Fertl, W.H., 1976. Abnormal Formation Pressures, Implications to Exploration, Drilling and Production of Oil and Gas Resources. Elsevier, Amsterdam, 382 pp. Fertl, W.H., 1977. Shale density studies and their application. In: G.D. Hobson (Ed.), Developments in Petroleum Geology. Applied Science Publishers, Barking, Essex, pp. 293-327. Fertl, W.H. and Timko, D.J., 1970. How abnormal pressure detection techniques are applied. Oil Gas J., 68(2): 62-71.
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Fertl, W.H. and Timko, D.J., 1973a. How downhole temperatures, pressures affect drilling, Part 9. World Oil, 176(2): 47-51. Fertl, W.H. and Timko, D.J., 1973b. How downhole temperatures, pressures affect drilling, Part 10. World Oil, 176(4): 62-66. Forgotson, J.M., 1969. Indication of proximity of high pressure fluid reservoir, Lousiaa and Texas Gulf Coast. Bull. Am. Assoc. Pet. Geol., 53: 171-173. Gill, J.A., 1968. Applied drilling technology, an engineered package for pressure detection and control. Drilling Contractor, Mar/Apr: 128-140. Gill, J.A. and Weintritt, D.J., 1970. Shale Factor: a Diagnostic Tool for Formation Logging. 1lth Prof. Well Log Analysts Symp., Los Angeles, CA, 11 pp. Goddard, R.D., Guest, R.J. and Anderson, T.O., 1973. High resolution fluid measurements improve drilling. Drilling Contractor, Mar/Apr: 55-64. Goins, W.C., 1968. Guidelines for blowout prevention. World Oil, 167(4): 88-106. Goins, W.C., 1969. Blowout Prevention. Gulf Publ. Co., Houston, TX, 260 pp. Goins, W.C. and O'Brien, T.B., 1962. How to detect and control threatened blowouts. Oil Gas J., 60(42): 143-151. Goldsmith, R.C., 1972. Why gas-cut mud is not always a serious problem. World Oil, 175(5): 51-54. Gstalder, S. and Raynal, J., 1966. Measurement of some mechanical properties of rocks and their relationship to rock drillability. Trans. AIME, 237:991-996. Guyod, H., 1946. Temperature well logging. Oil Weekly, 28: 35-47. Harper, D., 1969. New Findings from Overpressured Detection Curves in Tectonically Stressed Beds. 40th Reg. Meet., Soc. Pet. Eng., AIME, Los Angeles, CA, 2781, 9 pp. Herbert, W.E. and Young, ES., 1972. Estimation of formation pressure with regression models of drilling rate. J. Pet. Technol., 24: 9-15. Issenmann, O. and Lucon, C., 1971. Present state of gas-logging techniques with use of a continuous mud weight indicator. J. Can. Pet. Technol., 12: 9- I 1. Jones, EH., 1968. Hydrodynamics of Geopressures in the Northern Gulf of Mexico Basin. 43rd Fall Meet. Soc. Pet. Eng. AIME, Houston, TX, 2207, 15 pp. Jorden, J.R. and Shirley, O.J., 1966. Application of drilling performance data to overpressured detection. J. Pet. Technol., 18:1387-1394. Lewis, C.R. and Rose, S.C., 1970. A theory relating high temperatures and overpressures. J. Pet. Technol., 22:11-16. Lutze, J., Raynard, M., Gstalder, S., Quic-aud, C., Raynal, J. and Muckleroy, J.A., 1972. Instantaneous logging based on a dynamic theory of drilling. J. Pet. Technol., 24: 750-758. Mondshine, T.C., 1969. New technique determines oil-mud salinity needs in shale drilling. Oil Gas J., 67(28): 70-75. Moore, EL., 1974. Drilling Practices Manual. The Petroleum Publ. Co., Tulsa, OK, 448 pp. Nance, G., 1977. How to calculate maximum surface pressure for floating drilling. Oil Gas J., 49(1): 46-54. Nevins, M.J. and Weintritt, D.J., 1967. Determination of cation-exchange capacity by methylene blue adsorption. Bull. Am. Ceram. Soc., 46: 587-592. O'Brien, T.B. and Goins, W.C., 1960. The mechanics of blowouts and how to control them. API Drill Prod. Prac., 27: 41-55. Overton, H.L. and Timko, D.J., 1969. The salinity principle, a tectonic stress indicator in marine sands. Log Anal., 10(6): 34-43. Pixler, B.O., 1945. Some Recent Developments in Mud Analysis Logging. Fall Meet. Soc. Pet. Eng., AIME, Houston, TX, Oct. SPE 2036, 8 pp. Rehm, W.A., 1969. Pressure control in drilling. Oil Gas J., 67(31)-68(7). Rochon, R.W., 1968. The Effect of Mud Weight in Mud Logging Gas Anomalies. Monarch Logging Co., San Antonio, TX, 12 pp. Wardlaw, H.W.R., 1969. Drilling Performance Optimization and Identification of Overpressure Formations. 4th Conf. Drilling and Rock Mechanics, Soc. Pet. Eng., AIME, University of Texas, Austin, TX, 2388, 12 PP. West, E.R., 1976. Hydraulic control of deep well blowouts. Pet. Eng., 48(5): 68-81.
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Wilson, G.J. and Bush, R.E., 1973. Pressure prediction with flow line temperature gradient. J. Pet. Technol., 25: 135-142. Young, ES., 1968. Computerized Drilling Control. 43rd Fall Meeting, Soc. Pet. Eng., AIME, Houston, TX, SPE 2241, 12 pp. Zoeller, W.A., 1970. The Drilling Porosity Log. 45th Fall Meet., Soc. Pet. Eng., AIME, Houston TX, Oct., SPE 3066, 10 pp.
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Chapter 7
SEISMIC METHODS OF PRESSURE PREDICTION
E AMINZADEH, G.V. CHILINGAR and J.O. ROBERTSONJR.
INTRODUCTION Geophysical methods, in conjunction with other tools, can provide the means to predict reservoir pressure in many cases. Overpressured shales can act as good reservoir seals, but can also cause drilling difficulties, particularly in maintaining an adequate safety margin for the drilling mud weight. Geophysical techniques are based on the impact of reservoir pressure on the seismic velocities (primarily compressional waves). Many studies have demonstrated the effectiveness of geophysical methods for pore pressure prediction. One of the first of such studies was reported by Pennebaker (1968). Subsequently, the Society of Exploration Geophysicists published Geopressure (Dutta, 1987) that included major geophysics-related methods for overpressure prediction. With the advent of 3-D seismic and, more recently, four components and 4-D seismic, it has become possible to make pressure predictions that are more reliable and create three-dimensional pressure profiles. In general, the seismic reflections are functions of acoustic impedance (velocity times density) and are influenced by reservoir pressure. On the other hand, the type of reservoir fluid impacts sonic velocities. Shear waves and compressional waves respond differently to various reservoir fluids (and lithology) as well as reservoir pressure. These phenomena offer the following two practical applications: (1) prediction of abnormal pressure from seismic velocities before drilling; (2) mapping reservoir fluid movement and dynamic changes of reservoir pressure using time lapse (4-D seismic).
PREDICTION OF ABNORMAL PRESSURE FROM GEOPHYSICALDATA Most of the methods of predicting reservoir overpressures utilize the following phenomena: (1) lower bulk densities (thus lower seismic velocity); (2) higher porosity; (3) lower stress; (4) higher reservoir temperature. Table 7-1 shows how specific types of measurement at different stages of well development are employed to predict reservoir pressure using geophysical data. There are two major categories of approaches for predicting pore pressure and effective stress. They are based either on empirical relationships derived from statistical data and case histories or on laboratory measurements and rock physics models. In general, most methods use the seismically derived velocities as a basis for prediction. Some of the earlier work on the subject has been reported by Dutta (1987) and Fertl et al. (1994). The sonic velocities are calibrated against velocities derived from sonic
170
E AMINZADEH,G.V. CHILINGARAND J.O. ROBERTSONJR.
TABLE 7-1 Geopressure prediction techniques (adapted from Dutta, 1987) Development stage
Source of data
Pressure indicator
Prior to drilling
Surface geophysical methods (gravity and 2-D, 3-D, 3-C and seismic)
P- and S-wave velocity, density, porosity
During drilling
Drilling parameters
Penetration rate, logging MWD, seismic while drilling Mud gas cuttings, pressure kicks, flow-line temperature, pit-level, total pit volume, hole fillup, mudflow rate Bulk density, shale formation factor, volume, shape, size, % shale Drilling data
Drilling mud parameters
Shale cutting parameters Correlation between new and existing wells After drilling
Surface and subsurface geophysical data (VSP, Cross-well, 4D, 3C) Petrophysical data
P- and S-wave velocity, density, porosity, downhole gravity Sonic, resistivity, density, neutron
During testing and completion
Monitoring pore pressure variations in short zones
Repeat formation tester, drillstem test, pressure bombs, 4-D seismic
logs and petrophysical measurements. Under a normal pressure regime in the absence of hydrocarbon saturation, one would anticipate the sonic velocity to increase with depth. Any major deviation from this may be attributed to abnormal pressure or other anomalies (such as saturation with gas). How one can distinguish between these different situations is presented here. Formation pressure that deviates from hydrostatic pressure at a similar depth is considered as an abnormal pressure. Abnormal pressures are indicated by significant changes in the sonic velocity with depth. These changes of course can have different origins, such as lithology, hydrocarbon saturation, formation temperature and, finally, formation pressure. The main objective of earlier work on the use of seismic velocities for overpressure prediction concentrated on identifying sonic velocity changes without isolating the reasons for such changes (e.g., see Eaton, 1972).
EMPIRICAL RELATIONSHIPS
Many empirical formulas are based on case studies and real data which have been developed for overpressure prediction. The following are some well known relationships frequently used in the oil industry: Eaton's exponent of pore pressure determination from sonic data
Eaton's original formula (Eaton, 1972) uses the exponent relationship between pore pressure and several parameters. It does not differentiate between different lithologies or
SEISMIC METHODS OF PRESSURE PREDICTION
171
depth: Pp -- Po -- (Po -- Ph)
~o
(7-1)
where pp is the predicted pore pressure, Ph is the normal hydrostatic pressure, Atn is the normal shale travel time, Ato is the observed shale travel time, and N is an experimental coefficient. This method of predicting pore pressure is based upon the assumption of sediment compaction; thus, it is appropriate in sand-shale sequences only. The exponential coefficient, N, is determined for different regions (geological basins) and for offset wells. A typical N value in the Gulf of Mexico is 3.
Eaton's exponent for pore pressure determination from resistivity logs Eaton's transient time equation can also be expressed in terms of resistivities: Pp -- Po -- (Po -- Ph)
Rn
(7-2)
where Ro is the observed shale resistivity and Rn is the resistivity of normally compacted shale. The exponent M is usually chosen to be 1.2 for the Gulf of Mexico.
Eaton's fracture pressure gradient equation In Eqs. 7-1 and 7-2, the overburden pressure is critical to the accuracy of prediction of overpressures. In vertical wells, the fracture pressure is related to the overburden pressure, horizontal stress and pore pressure. To fracture a formation would require a drilling mud weight pressure at least equal to the formation pressure. Any additional required pressure must be related to overcoming the horizontal stress and/or the cohesive strength of the rock matrix. Eaton's fracture gradient equation (Eaton and Eaton, 1977) is based on the equation developed by Mathews and Kelly (1967) to calculate the fracture pressure: p f = p p nL
K (Po
-
Pp)
(7-3)
where pf is the fracture pressure, and K is the coefficient describing horizontal stress/vertical stress. Eaton used the following expression in terms of the empirical depth-dependent Poisson's ratio, v, to calculate K: v
K =
(7-4) 1--v
From the data collected worldwide by Eaton, he was able to generate depth-dependent heuristic equations for v. This was done through a multi-segmented regression analysis of the empirical relationship between v and the depth below the mud line in feet (d and d2). For deep water, the fit was reasonable in many cases. The following are expressions for v: Vl = (-6.0893 x 10-9d 2) -k- (8.0214 x i0-5)d + 0.2007, for d < 4100 ft
(7-5)
172
F. AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR. 1)2 =
( - 1 . 8 8 2 x 10-1~ 2) -+- (7.2947 • 10-6)d + 0.4267,
for d > 5000 ft (7-6)
l) 3 = l) 1 --[- (d
- 4100)
5000 ~' - 41 O0~:
, for 4100 ft > d > 5000 ft (7-7) 900 Substituting v from Eqs. 7-5 to 7-7 in Eq. 7-4, one can derive a value for K for inclusion in Eq. 7-3.
Dutta's method Dutta (1988, 2002) expressed effective stress as a function of temperature, shale void ratio, and diagenetic integral depending on the time and temperature.
Fillippone formula Fillippone (1982) developed the following formula: Poverburden (Vp-grain pp-
Vp-inst)
(7-8a)
Vp_grain- Wp_fluid
where Wp-grain is the velocity when the porosity goes to zero (approximated to matrix velocity of the rock), Vp-nuid is the velocity when rigidity goes to zero (approximated to pore fluid velocity), and Wp-inst is the instantaneous velocity. The Po in the above equation is calculated from the following equation
Po (D) = PhP D
(7-8b)
where hydrostatic gradient is equal to 0.465 psi/ft, fluid density is 1.073 g/cm 3, p is the density, and D is the depth. Eq. 7-8 is valid only in certain areas. When it is applied to other areas, errors are usually over 10% (Fillippone, 1982).
Modified Fillippone formula In 1982, Fillippone presented a modified formula (Fillippone, 1982): Poverburden (Vp-grain -- Vp-inst)
pp = C Vp-~n~t C Vp-inst
V - r in- Vp-uid
(7-9)
may be calibrated by well log data. In some areas,
C Vp-inst = 0 . 1 8 6 7 7 e ~176176176....
(7-10)
If density logs are not available, for OBG calculation in Eqs. 7-1, 7-2 and 7-3, one has to use synthetically derived densities. One conventional method is to use the well-known Gardner equation (Gardner et al., 1974): p = 0.23 V ~
(7-11)
where V is the interval velocity. Another empirical relationship to develop the rock density curves has been reported by Traugott (1997). It is also known as the Amoco
SEISMIC METHODS OF PRESSURE PREDICTION
173
Generalized Gulf Coast density. Density (p) is a function of depth (d), water depth (w) and air-gap (a):
(d-w-a) p -- 16.3 +
~
3125
(7-12)
Kenda et al. (1999) observed that the Gardner equation tends to underestimate density values, especially for older rocks. Traugott's (1997) method was considered more reliable for older rocks. Density can also be derived from other logs using neural networks when at least one of the wells has density information to be used for training (see Nikravesh and Aminzadeh for several examples of such neural networks and fuzzy logic-based method). As shown in Fig. 7-1, SP and resistivity logs can be used to predict synthetic density logs.
PRACTICAL APPLICATIONS
In recent years, the petroleum industry has increased exploration and production operations in overpressured areas. In drilling, the weight of the drilling mud should be at least 1 pound per gallon (ppg) greater than the formation pore pressure. Pore and fracture pressure prediction can assist the drilling engineers to design an effective casing program. If the difference between the fracture and pore pressure is less than 1 ppg, drilling can be very difficult. Accurate estimation of overburden and effective pressures can help control drilling costs. Several practical applications, each highlighting one or more aspects of pressure prediction and related issues, are presented here.
South Caspian Basin Lee et al. (1999) determined overpressure as a function of porosity and water depth. Overburden pressure is the total vertical stress exerted by the weight of the overlying rocks and the interstitial fluids. Fracture pressure is the stress necessary to fracture a formation; it is a function of overburden pressure, horizontal stress, and the pore pressure. Overburden pressure can be obtained using the following equation:
Po -- C
low
pwdw + C
loOS
{pg(1 - ~b(h)) 4- pfqb(h)dh}
(7-13)
where r is the porosity, h is the vertical depth, C is the constant coefficient, Ds is the sediment thickness, Dw is the water depth, Pw is the density of water saturated sand, pg is the density of grains, and pf is the density of interstitial fluid. Eq. 7-13 relates the overburden pressure to the height of the water column and the lithostatic column. The first integral term varies relative to the seafloor. The density can be obtained from bulk density log measurements. If direct density measurements are not available, they can be estimated from other wells or seismic data (e.g., Gardner's Eq. 7-11 or the neural network method of Nikravesh and Aminzadeh, 2001). There are a number of ways to predict pore pressure from drilling mud weights, resistivity, conductivity, and sonic and seismic interval velocity. In exploration areas
174
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.
with seismic shadow zones, where very little or no pressure information is available, the interval velocity method can be used. Eq. 7-1 presents one such approach. Eaton's method enables prediction of pore pressure assuming compaction and is applicable only in sand-shale sequences. In Eq. 7-1, the knowledge of the overburden pressure is critical to the accuracy of pore pressure determination. In vertical wells fracture pressure is determined by the overburden pressure, horizontal stress, and the pore pressure. Fracturing a formation would require a mud weight pressure at least equal to the formation pressure. Any additional pressure required is related to overcoming the horizontal stress and the cohesive strength of the rock matrix. In this situation the fracture pressure equation (Eq. 7-3) of Mathews and Kelly (1967) can be used. As described earlier, more accurate fracture pressure can be obtained by use of Poisson's ratio (Eq. 7-4). The solution of the latter equation requires knowledge of shear wave and compressional wave velocities. Eaton and Eaton (1977) provided empirical depth-dependent relationships such as those given in Eqs. 7-5, 7-6, and 7-7. These empirical relationships may vary for different geographic areas. Historically, seismic stacking velocities, converted to depth domain interval velocities using the Dix equation, were used for pressure prediction. Pressure prediction from the Dix equation velocities can be in error when lateral velocity variations and dipping structures exist, and can become unstable when the stacking velocity decreases. These problems can occur in overpressured areas. Lee et al. (1999) corrected these problems by increasing the accuracy of the interval velocity measurement. This was accomplished by the use of tomographic inversion to yield more accurate lateral interval velocities in the depth domain. This technique allowed the integration of pressure prediction, AVO indicators, and reservoir depth imaging. The color-coded geopressure was then overlain on seismic depth sections to indicate variations in the geopressure distribution. Additionally, reservoir boundary mapping can be enhanced by overlaying color-coded geopressure distribution charts on AVO sections. Use of the tomographic inversion yields more accurate velocities both laterally and with depth. The final interval velocity model from the tomographic inversion was used to make the pore and fracture pressure predictions. The sediment compaction trend was determined by analyzing two seismic events, one shallow and one deeper. Based on the derived interval velocities and well information, the normal compaction trend was adjusted to allow the calculated pore pressure to match the actual pressure at the well location. Pore and fracture pressures were estimated from interval velocities through the low-amplitude zone, as well as deeper in the section. The geopressure estimation was then overlain on the depth migration sections providing a useful reservoir interpretation tool. Fig. 7-2 (Lee et al., 1999) is a depth domain pore pressure distribution. The pore pressure distribution shows that the pressure remains hydrostatic to a depth of 2500 m. The pressure then starts to increase with depth and reaches 10 ppg at a depth of 2800 m. In Fig. 7-2, the lighter shading with a pressure of 10 ppg represents the top of an overpressure zone. The fracture pressure was calculated using Eqs. 7-5 to 7-7 and the results were plotted in Fig. 7-3. As shown, the fracture pressure distribution in the low-amplitude zone also increases with depth. At a depth of 2800 m from the top of the overpressured zone, the fracture pressure reaches 15 ppg (equivalent mud weight). A differential pressure between the fracture pressure and
SEISMIC METHODS OF PRESSURE PREDICTION
175
the pore pressure was calculated to detect the mud circulation. If the differential pressure is less than 1 ppg, drilling can be very difficult. Fig. 7-4 shows the differential pressure distribution of the fracture and pore pressures. The differential pressure ranges from 1 to 6 ppg. These results indicate that the drilling mud circulation should be smooth in the studied low-amplitude zone.
AVO effects of overpressure Pigott and Tadepali (1996) used elastic amplitude variation with the pre-stack seismic AVO data, and a three conjugate layer, iterative least-square minimization inversion technique to determine Young's modulus. Compared with the derived statistical models of laboratory-measured elastic rock properties of Young's modulus determinations enable prediction of the in-situ reservoir porosities and differential pressures, which were within 5 porosity percent and 400 psi (2.75 MPa) of the borehole measurements, respectively. They relied on the results of Pigott et al. (1988a,b), which suggest that Young's modulus can be dynamically determined from the inversion of AVO data and that, in principle, the in-situ reservoir pressures and porosities could be seismically quantified. Pigott and Tadepali (1996) procedure consists of: (1) developing a statistical model which describes differential pressure and porosity in elastic sedimentary rocks as a function of Young's Modulus; and (2) determination of the porosity and differential pressure using AVO inversion and the derived Young's modulus. Statistical analysis of the experimental laboratory data of differential pressure, compressional wave velocity, shear wave velocity, and density for dry gas sands have been compiled in earlier publications. The statistically best-fit non-linear least-square equations expressed in the form consistent with the earlier theoretical derivations of Young's modulus (E) as a function of strain, are of two types: (1) a primary equation expressing porosity as a dependent variable of Young's modulus, and (2) a secondary equation, which expresses differential pressure as a dependent variable of both porosity and Young's modulus. These equations are: q5 = 0.2423 - 0.10276 log e E
(7-14)
loge Pd = A + B ~b + C E
(7-15)
where 4~ is the % porosity, E is Young's modulus, Pd is the differential pressure and A, B, and C are constants. Based on the statistical analysis of real data, values of these constants and respective different ranges of porosity are presented in Table 7-2. The last column is the standard deviation of the estimates in each range. Thus, the porosity and reservoir pressure can be obtained for elastic sedimentary rocks using Eqs. 7-14 and 7-15 along with seismic data.
Real time pressure analysis With the introduction of measurement while drilling (MWD) logging techniques, the prediction of abnormal pressure has become more efficient, leading to considerable
176
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.
T A B L E 7-2 Statistically derived coefficients of differential pressure equation (Eq. 7-15) Porosity 0 10 20 30
< < < <
~b < ~b < ~b < ~b <
10% 20% 30% 40%
A
B
C
r2
- 1.5041 8.8478 -12.4646 351.824
0.6725 1.919 2.2884 -908.7610
24.9081 -61.6463 44.6589 -32.545
0.648 0.967 0.876 0.992
saving in drilling cost and time. Desbrandes and Clayton (1994) suggested use of log measurements while drilling to predict formation pressures. Kenda et al. (1999), used three case histories from the Gulf of Mexico to demonstrate a reduction in drilling costs using real time geopressure analysis. Some of their conclusions are the following. (1) Site-specific real time pore pressure analysis using MWD can help optimize mud weight, drilling hydraulics and casing programs. (2) There are many possible mechanisms for the presence of overpressured conditions, some of which are not detectable either by MWD logging measurements or seismic. The more common (undercompaction) condition, however, can be detected in most cases.
(3) Readjustment of the normal compaction trend line on the basis of a pressure kick can be wrong if the overpressure was not caused by undercompaction. A better understanding of the geology and reservoir fluids may be necessary. Seismic while drilling (SWD) logging techniques are also available. The use of SWD in conjunction with MWD logging can further fine-tune the current prediction methods of overpressure. SWD can help determine interval velocities more accurately which, in turn, can determine the pressure profile. Neil et al. (1993) have shown that SWD-based seismic imaging methods can help direct drilling paths. A side benefit of this method is to use the migration velocities (used for depth imaging) for pressure prediction as well.
Lithology As discussed earlier, the empirical relationships between velocity and pressure have been modified to account for different lithologies, which play an important role in determining pressures. 'Normal compaction' velocity trend curves must incorporate the impact of lithology on velocity. As shown in Fig. 7-5, the normal velocity trend curves are impacted by lithology and geologic scenarios. Thus without careful examination of the reason for changes in the velocity trend, overpressure predictions can be erroneous. Katz et al. (1994) demonstrated a method to simultaneously predict pressure and lithology in interbedded sand-shale sequences. This method is based on the assumption that several depth-dependent pressure and lithology curves can be expressed in terms of summation of three components: (1) a smooth component slowly changing with depth (related to the actual variation in formation pressure); (2) a fast changing component (related to changes in lithology); (3) a random component that is not correlated with 1 or 2.
177
SEISMIC METHODS OF PRESSURE PREDICTION Training Data set; Blue: Actual, Red: Prediction 0.5
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.
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.
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0.5 ......................9.............. 9 . . . . . . ,
,
-
o
0
20
40
....................................... 0.5
60
80
100
0
20
40
60
80
100
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The models for pressure and lithology prediction are built as bi linear functions of variables from the estimated curves from groups 1 and 2
Empirical relationships based on laboratory measurements In addition to the empirical relationships derived from the field data (seismic and other logs), attempts have been made to establish relationships based on laboratory measurements. Conceptually, the following types of relationships should exist:
Vp - A @ , s h , T, Pe)
(7-16)
Vs -- fz(~b, sh, T, Pe)
(7-17)
where 4~ is the porosity, sh is the clay content (%), T is the temperature and Pe is the effective stress. Using Eqs. 7-16 and 7-17, it is possible to derive the effective stress formula: Pe -- fz(Vp, Vs, ~b, sh, T)
(7-18)
178
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.
Fig. 7-6 shows schematic curves demonstrating the differences of compressional and shear wave velocity profiles for the gas-saturated overpressured zones. Extensive efforts in different petrophysical laboratories (including those at Stanford's SRB) have been made to derive explicit relationships for Eqs. 7-16 and 7-17. Eberhart-Phillips et al. (1989), among others, have used laboratory measurements to derive empirical relationships between the sonic velocity (both compressional and shear waves) and effective pressure, porosity and clay content. The following two are examples of such a relationship: Vp - -
5.77 - 6.94q~ - 1.73sh ~ + 0.446(pe - e -167pe)
Vp - 3.70 - 4.94~b - 1.57sh ~ + 0.361 (Pe
-
e-167pe)
(7-19) (7-20)
Inasmuch as there is no temperature dependency, Pe can be obtained by combining Eqs. 7-19 and 7-20. Based on laboratory results, Yilmaz et al. (1994) developed other empirical relationships between pore pressure and permeability in fractured rocks. Previously, Brace et al. (1968) showed that permeability decreases as confining pressure increases. Yilmaz et al. (1994) observed that permeability is impacted more dramatically as a result of pore pressure changes. Permeability is roughly proportional to the square of the change in fracture width which, in turn, is proportional to the applied pore pressure.
Velocity and acoustic impedance inversion of seismic data Dutta and Ray (1997) used the velocity and acoustic impedance inversion of seismic data to obtain geopressure. They used an integrated geological and geophysical technique for pressure prediction. Their technique has two major components: (1) a rock property model that links effective stress, temperature and lithology to velocity, and (2) a subsurface image based upon high-resolution velocity analysis of seismic data. The rock property transform is generated from an extensive database. The transform is model-based and considers the major causes of overpressure mechanisms, e.g., undercompaction, clay dehydration and charging of fluids in dipping permeable beds. The model does not require either a local calibration or a normal trend analysis of Hottmam and Johnson (1965), Eaton (1972) or Pennebaker (1968). It predicts effective stress directly, which is the most fundamental quantity for pressure prediction. The overburden pressure is estimated from a relation between velocity and density. This technique is critically dependent on velocity, which is derived from seismic data in two different ways: (1) normal move-out relation (low frequency) and (2) seismic amplitudes (high frequency). First, interval velocities are obtained at closely spaced CDP locations from seismic stacking velocities via Dix's inversion, after processing the data (e.g., pre-stack migration and DMO) and applying geologic constraints through horizon consistent velocity analysis. Next, acoustic impedance (product of velocity and density) is generated from trace integration after seismic waveform analysis. These impedances are calibrated using the RMS scaling method, where RMS levels are determined for a time-window from field and synthetic seismic data (calculated at analog wells). Using these RMS values, seismic data are scaled to ensure that seismic impedances are tied to
SEISMIC METHODS OF PRESSURE PREDICTION
179
well impedances. Extensive testing proved that this scalar, which varies to some extent with space and time, can be effectively used to generate absolute acoustic impedances from consistently processed seismic data. Velocity information is then extracted from the impedances using the velocity-density transformation. Pore pressure and seismic amplitude versus offset (AVO) As discussed previously, the amplitude of the seismic reflection is influenced by the reservoir pressure. Moreover, reservoir fluids also affect the seismic velocities. The shear and compressional waves respond differently to reservoir fluids (and lithology), as well as to the reservoir pressure. These facts offer the opportunity to predict pressure and fluid content using seismic velocities. Other challenges include distinguishing between the presence of overpressure and gas saturation from seismic response. Some laboratory tests have been helpful in this regard (for example, see Fig. 7-6). Lindsay and Towner (2001) demonstrated how to improve predictions. Rock properties and amplitude versus offset modeling help to understand the frequently ambiguous amplitude and AVO signatures found in seismic data. The aim is to understand the elastic reservoir properties and their dependence upon pore fluids. Inasmuch as the seismic reflectivity data are a measurement of changes in the elastic rock properties across interfaces, the elastic properties of the sealing caprock are as important to the reflectivity solution as those of the reservoir. Pore pressure has a greater influence on the elastic properties of shale than it has on the properties of sands and sandstones because of the influence of adsorbed water on the clay particles. Inasmuch as the pore pressure could be related to shale dewatering, at least in Tertiary sand-shale sequences, the amount of adsorded water correlates with pressure. Pore pressure, therefore, becomes a critical parameter in the rock property and reflectivity models because of its disproportionate influence on the shale caprock. Fig. 7-7 shows that essentially identical reservoir sands with similar fluids may have dramatically different amplitudes and AVO signatures simply because of their pore pressure. In sand-shale sequences, the elastic properties of rocks vary as a function of the pore pressure. The properties of shales vary more as a function of pressure than do the sands. Consequently, in order to generate high-precision rock property and reflectivity models, the influence of pore pressure on the reservoir rock and shale seal (caprock) must be included. An independent estimate of pore pressure is required when models are made for prospects away from the well control. Fortunately, there is a strong correlation between the pore pressure and seismically derived interval velocity (Fig. 7-8). Additionally, this velocity is presented in three dimensions. Pore pressure estimation from seismic velocities The pore pressure calculated from 3-D prestack depth migration velocities was used successfully in the Gulf of Mexico subsalt trend. Various papers have been published on this topic showing the usefulness of implementing pore pressure prediction in a 3-D volume. In all cases, pore pressure is estimated by measuring the deviation of
] 80
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSONJR. P.(PPg) ...
=nn
Pore Pressure Images
Fig. 7-2. The pore pressure distribution in low-amplitude zone shows the pressure increases with depth. The lighter shading represents a pressure of 10 ppg. (Modified after Lee et al., 1999.) P""u~' (PPg) m8
~^^
Fracture Pessure Images . . . . . .
Fig. 7-3. The fracture pressure distribution in low-amplitude zone shows the increases with depth. (Modified after Lee et al., 1999.)
181
SEISMIC METHODS OF PRESSURE PREDICTION Pressure
(ppg)
Fracture Pressure - Pore pressure
500
lEO
0.75
1000
1.5 2.25
1500
3
2000
3.75 4.5
2500
5.25 3000
6
3500
4000
4500
Fig. 7-4. The range of differential pressure (fracture pressure minus pore pressure) between 1 and 6 ppg. (Modified after Lee et al., 1999.)
orma, oomoaot,on tren
-Unc~
0 0 0
sands
i'
12
f'~
s a, s
nesville salt
16 Carbonate and salt
tren~l:~~~k
20 Possible top Norphlet sand ~ . . . ~
I 24
6
I
i
!
I
t
I
i
8
10
12
14
16
18
20
Interval velocity, 1000 ft/sec
Fig. 7-5. Intercept velocity analysis for a south Mississippi prospect demonstrating the impact of lithology change on the velocity trend. (Modified after Reynolds, 1970.)
182
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.
v- p
A
V
urated zone
v- p
B
v
sured zone
Fig. 7-6. Schematic curves demonstrating differences of Vp and Vs velocity profiles for (A) gas-saturated zone and (B) overpressured zone.
observed velocity from the model velocity function representing the normal-compaction pressure trend (Fig. 7-9). The 3-D pore pressure volume is integrated into the seismic interpretation workstation in seismic trace format. Spatial variations in pressure are measured along interpreted horizons, thereby creating maps of pore pressure at prospective horizons. This information is then used to refine the rock property and reflectivity models lending understanding to seismic amplitude and AVO response maps. The pore pressure prediction algorithm relates pressure to interval velocity. Similarly, the equations can be written in reverse with average shale velocity being predicted from pore pressure. The function relating the brine sand velocity to pore pressure is also found. Classical fluid substitution modeling and the 3-D pore pressure volume then become independent variables in the perturbation of the elastic properties found at one well location to those in a prospective well location. Table 7-3 shows the elastic properties measured at a control well located in the Shabwa Basin of central Yemen within the 3-D seismic survey area. Pore pressure encountered at this location in the Jurassic Alif sand is about 3000 psi (14.7 lb/gal mud-weight-equivalent). Studies of multiple wells in the area allow for the computation of velocity-to-pressure systematics. Using these trends, the elastic properties are perturbed to new values representing those that should be found in the new areas of the
TABLE 7-3 Elastic properties of shale and sand at the control well location Shale Vp Shale Vs Shale density, ,Ob
3350 m/s 1550 m/s 2.5 g/cm3
Sand Vp Sand Vs Sand density, Pb
3733 m/s 2347 m/s 2.3 g/cm3
183
SEISMIC METHODS OF PRESSURE PREDICTION TABLE 7-4 Modeled and measured elastic properties of sand and shale at the prospect Modeled Shale Vp Shale Vs Shale density, Pb
2500 m/s 1000 m/s 2.2 g/cm 3
Sand Vp Sand Vs Sand density, Pb
3400 m/s 1800 m/s 2.3 g/cm 3
Measured Shale Vp Shale Vs Shale density, Pb
2400 m/s 915 m/s 2.3 g/cm 3
Sand Vp Sand Vs Sand density, Pb
3350 m/s 1680 m/s 2.3 g/cm 3
basin, away from the control well. One of the two new exploratory wells drilled in this area encountered Alif sands at an approximate pressure of 4300 psi (16.9 lb/gal). The second well drilled the equivalent sands in a different area with a mud weight equivalent to 2500 psi. The pore pressure prediction was in error by 10% in both cases. Typical precision is about one pound per gallon. Table 7-4 presents a comparison of the predicted elastic properties at one of these exploratory wells versus the observed properties. This table shows the improvement in the precision of the prediction of the elastic properties used for input to reflectivity models. Of much greater importance is the influence of the correct reflectivity models on the risk analysis of the seismic amplitude and AVO analyses of the prospect. These models illustrate that the mild positive AVO signature found at the control well should not be expected at the new prospect. In fact, a strong negative AVO anomaly might be expected in certain porous vs. nonporous scenarios in hydrocarbon-filled sands or sands with pores occluded by salt (Fig. 7-10). This was not the response predicted by the models without including the pore pressure analysis.
Deep-water prospects In recent years, exploration and production has been rapidly expanding into deepwater plays. In a geopressure system, the weight of a large water layer significantly impacts the sedimentary column. A thick water column changes the overburden and fracture pressures as well as the pressure differential between the formation fracture and pore pressures. Lee et al. (1997) illustrated this in a model study using sonic log velocities to compare the pressure system for shallow-, medium-, and deep-water models. If the difference between the fracture and pore pressures are less than 1 lb/gallon (ppg), drilling complexities can arise. It is, therefore, very important to obtain accurate pore pressure and fracture pressure for 'deep-water plays' in order to properly design the drilling program. In a vertical well, fracture pressure is related to the overburden pressure, horizontal stress, and the formation pressure. The fracture pressure is equal to the formation pressure plus the horizontal stress and the cohesive strength of the rock matrix. In deep-water, fracture pressure and overburden pressure will move closer to that of the pore pressure. If the difference between the fracture pressure and pore pressure is less
184
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSONJR.
Control Well Area
q
Prospect Area
t,
....
Fig. 7-7. AVO strength maps in control well and prospect area. (Modified after Lindsay and Towner, 2001.)
2,8 o
C)')
O
2,7
(b ~
2,6
-.t--
c-"
-,t--
~ c-"
2,5
i-.--
2.4
-0,4
-0,2
0,0
0,2
0,4
0,6
0,8
Depth [Iog,0] Fig. 7-8. Cross-plot and regression analysis for transient time (inverse velocity) and depth. (Modified after Lindsay and Towner, 2001.)
than 1 ppg, mud circulation can be very difficult. Likewise, deeper water will affect the pressure gradient. If the pressure gradient is greater than 0.80, drilling is very difficult. Lee et al. (1997) compared the difference in fracture pressure among the wells in shallow (50 m water depth), medium (100 m water depth) and deep (>2000 m water depth) water. Input sonic velocities were taken from an offshore sonic log. The
185
SEISMIC METHODS OF PRESSURE PREDICTION
dt, lasec/m (log ~0)
o r -
_9 o
E
xi
13. (D Observed Profile
Pressure g r a d i e n t
Fig. 7-9. Calculation of pore pressure by determining the intercept of the observed pressure profile and the trend lines for the normal pressure. (Modified after Lindsay and Towner, 2001.) 0.20 0.15 0.I0
d.) "t3
0.05
Incidence angle
0.00
.i
Q.
E <
-0.05 -0.10
AVO at control well
m0.15
0.20
Fig. 7-10. AVO models at the prospect for different rock property models.
deep-water model showed that the pore and fracture pressures were very close. To calculate the fracture pressure, one needs the horizontal stress which may be determined using Poison's ratio (Eq. 7-4). Based upon empirical information (Eqs. 7-5 through 7-7), a Poisson's ratio was chosen that started with 0.4 at the sea bottom and ended with 0.25 at a depth of approximately 4000 m. For the shallow-water model, the fracture pressure
186
E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.
is 4.0 ppg higher than the pore pressure at some locations. At the same locations, the difference between the fracture and pore pressure was 2.5 ppg for the medium-depth water. The pore and fracture pressures differed by 1.5 ppg for the very deep water. The results show that as the water depth increased the difference between the fracture and pore pressures decreased. In a second model study, Lee et al. (1997) lowered a sonic log to the fixed depth levels of 2000 and 3000 m, to analyze pressure gradients. They replaced the sediments by adding water columns of 50, 1000, and 2000 m. They also assumed that the sediments from the water bottom to the top of the sonic log were homogeneous. The second model differed from the first model by the position of the sonic log. The sonic log was located exactly below the water bottom for the first model, whereas for the second model, the log was located at a fixed depth. Using this model, they calculated the pressure gradients for each water column. The pressure gradient, ~, was calculated from the following equation: ~. -
PP
(7-21)
(Zo - Zw) + 0.465Zw where, pp is the pore pressure and Zo and Zw are the pressure observation depth and water depth, respectively.
Mapping reservoir fluid movement and dynamic changes of reservoir pressure using time lapse (4-D seismic) Time lapse (4-D) seismic data has been proven useful for accurate dynamic reservoir characterization. As Tufa and Aminzadeh (1999) stated, to achieve accuracy and to ensure that all available information at any given time is incorporated in the reservoir model, reservoir characterization must be dynamic. To achieve this goal, one starts with a simple model of the reservoir. As new well log, petrophysical, seismic, and production data become available, the reservoir model must be updated to reflect the changes in the reservoir, and for the model to be more detailed and representative. Both static reservoir properties (such as porosity, permeability and facies type) and dynamic reservoir properties (such as pressure, saturation of fluids, and temperature) must be updated as more field data become available. Characterizing a reservoir by updating both static and dynamic reservoir properties during the life of the field is referred to as dynamic reservoir characterization. Reservoir pressure is lowered by fluid production, whereas gas injection or water flooding increases the reservoir pressure. Such changes affect bulk density and seismic velocity of the reservoir layers which, in turn, affect the travel time and amplitude of seismic waves propagating through the reservoir rocks. Usually the amplitude variations are more apparent than the travel changes in 4-D seismic surveys; however, these variations must be of sufficient size to represent a difference between the base seismic survey and the follow-up surveys. Forward modeling using laboratory data is generally utilized to estimate the expected changes in seismic amplitudes. The effect of fluids on reservoir rock velocity is more pronounced than that on the density. The introduction of gas into a liquid-filled rock
SEISMIC METHODS OF PRESSURE PREDICTION
187
(as the pressure is decreased) results in a decrease in seismic velocity which, in turn, decreases the acoustic impedance. The decrease in acoustic impedance alters the reflection coefficient and the seismic amplitude at the reservoir interface. As water is injected into the reservoir, pressure builds up and free gas is pushed back into solution in the oil. A large impedance contrast is observed between the area where there is a free gas with the oil and where there is oil with redissolved gas. This will generate a profound seismic amplitude variation between the two areas.
Estimation of sonic velocity from resistivity logs The sonic velocity of formations obtained by acoustic logs is necessary in solving many problems arising during exploration. This information is often lacking, however, because sonic logs are sometimes obtained only in the productive portions of the formation. Thus, it is necessary to estimate the sonic velocity on the basis of other logging data. This is especially critical for shales, because even if the sonic logs are available, they are very hard to interpret in badly washed-out beds. One of the methods in solving this problem is using the correlations between the sonic velocity and other logging data (electrical, gamma-ray, neutron, etc.). In some regions, this approach gives positive results. For example, for various lithologies in west Siberia, Bazylev (1987) obtained a system of equations relating longitudinal and transverse wave velocities to the parameters of neutron gamma-ray or thermal neutron logs. These equations are characterized by sufficiently high correlation coefficients ranging from 0.74 to 0.97, with mean-squares error of sonic velocity estimation of 50-150 m/s. However, development of one- or multidimensional equations for accurate estimation of sonic velocity is not always possible. In normally compacted formations with hydrostatic pressure, sonic velocity can be estimated from the velocity vs. depth relationships [V -- f ( D ) ] obtained for certain lithologies (and regions) (Kerimov, 1987; Averbukh, 1988). This method, however, is not applicable to overpressured formations. Kerimov et al. (1996) proposed a method for estimating (1) the sonic velocity, Va, in abnormally pressured shales using resistivity logs and, thus, (2) shale bulk density. Analysis of the well-log data for productive strata in Azerbaijan showed that there is a poor correlation between the sonic velocities and other well-log data, such as resistivity, SP, neutron and gamma-ray. Introducing the normal trend for sonic velocity Va and resistivity Pn allowed these authors to express sonic velocity (and, therefore, the bulk density of the shale) as a nonlinear function of resistivity with good correlation between the normalized velocity and normalized resistivity. The best-fit regression equation is of the following form:
where Pa and Pn are the resistivities of abnormally-pressured and normally-compacted shales, respectively.
188
E AMINZADEH,G.V. CHILINGARAND J.O. ROBERTSONJR.
(1)
1.0-
0 0 d~
..,.,_
> r r
0.75Q
0 0 0 O
o.--
9
~
9
00
0.5-
=1===
ry
-
I
0.25
I
0.5
l
0.75
I
1.0
Ratio of resistivities, pip~ Fig. 7-1 I. Relationship between ratio of sonic velocities Va/Vn and the ratio of resistivities Pa/Pn in shales. Va and Vn are sonic velocities in abnormally-pressured and normally-compacted shales, and Pa and Pn are resistivities of abnormally-pressured and normally-compacted shales. (After Kerimov et al., 1996.)
The coefficient of correlation between the parameters V (Va/V.) and/5 ((Pa/Pn)) is 0.87 and the mean-squared estimation error for Va is 190 m/s. The average relative error of velocity estimation is 6%, ranging from zero to a maximum of 14%. Thus, Va can be estimated from the Pa/P. ratio and the Vn obtained from the normal compaction trend in the area studied. The relationship between the ratios Va/V, and pa/p. is presented in Fig. 7-11.
BIBLIOGRAPHY Averbukh, A.G., 1988. Study of Composition and Properties of Rocks During Seismic Exploration. Nedra, Moscow, 216 pp. Bazylev, A.P., 1987. Estimation of sonic velocities on the basis of geophysical investigations of boreholes in Western Siberia. In: Investigations on the Basis of Multi-Wave Seismic Exploration. Tr. Inst. Geol. Geofis. Akad Nauk SSSR, Novosibirsk, pp. 109-140. Brace, W.F., Waish, J.B. and Frangos, W.T., 1968. Permeability of granite under high pressure. J. Geophys. Res., 95: 19279-19298. Desbrandes, R. and Clayton, R., 1994. Measurements while drilling. In: W.H. Fertl, R.E. Chapman and R.E Hotz (Eds.), Studies in Abnormal Pressure. Elsevier, Amsterdam, pp. 251-279. Dutta, N.C., 1986. Shale compaction, burial diagenesis, and geopressures: a dynamic model, solution and some results. In: J. Burrus (Ed.), Thermal Modeling in Sedimentary Basins, 1st IPF Exploration Research Conf. Proc., Caracas, June 3-7, 1985. Dutta, N.C., 1987. Geopressure. Soc. Pet. Eng., Geophys. Reprint Ser. No. 7. Dutta, N.C., 2002. Deepwater geohazard prediction using prestack inversion of large offset P-wave data and rock model. Leading Edge Geophys., 21(2): 193-198. Dutta, N.C. and Ray, A., 1997. Image of geopressured rocks using velocity and acoustic impedance inversion
SEISMIC METHODS OF PRESSURE PREDICTION
189
of seismic data. Technical Program, Expanded Abstracts, Society of Exploration Geophysicists, 2, pp. 929-1030. Eaton, B.A., 1972. Graphical method predicts geopressure worldwide. World Oil, June, pp. 51-56. Eaton, B.A. and Eaton, T.L., 1977. Fracture gradient prediction for the new generation. World Oil, June, 93-100. Eberhart-Phillips, D., Han, D.-H. and Zoback, M.D., 1989. Empirical relationships among seismic velocity, effective pressure, porosity, and clay content in sandstone. Geophysics, 54(1): 82-89. Fertl, W.H., Chapman, R.E. and Holz, R.F., 1994. Studies in Abnormal Pressure. Elsevier, Amsterdam, pp. 251-2790. Fillippone, W.R., 1982. Estimation of formation parameters and the prediction of overpressure from seismic data. Presented at the SEG Research Symp. Geopressure Studies, Dallas, TX, Paper R1.4, Oct. 17-21. Gardner, G.H.E, Gardner, L.W. and Gregory, A.R., 1974. Formation velocity and density - - the diagnostic basis for stratigraphic traps. Geophysics, 39(6): 2085-2095. Gurevich, A.E., Chilingar, G.V. and Aminzadeh, F., 1994. Origin of the formation fluid pressure distribution and ways of improving pressure prediction methods. J. Pet. Sci. Eng., 12: 67-77. Hottman, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., 16(6): 717-722. Ivakhnenko, A.G., Zaychenko, Yu, R and Dimitrov, V.D., 1976. Making Decisions on the Basis of Self-Organization. Soviet Radio, Moscow, 280 pp. Katz, S., Chilingarian, G.V., Aminzadeh, F., Khilyuk, L.A. and Gurevich, A.E., 1994. Bi- linear models for simultaneous estimation of formation pressure and lithological characteristics in interbedded sands and shales. J. Pet. Sci. Eng., 12: 37-48. Kenda, W.R, Hobart, S. and Doyle, EE., 1999. Real-time geo-pressure analysis reduces drilling cost. Oil Gas J., March 1. Kerimov, K.M., 1987. Prognosis of oil- and gas-bearing deposits using methods of exploration geophysics. In: K.M. Kerimov (Ed.), Symp. Sci. Papers of Southern VNII Geof Baku, 105 pp. Kerimov, K.M., Chilingar, G.V. and Katz, S.A., 1996. Estimation of sonic velocity in shales in abnormally pressured formation from resistivity data. J. Pet. Sci. Eng., 15: 375-377. Khilyuk, L., Katz, S., Chilingarian, G.V., Aminzadeh, E and Gurevich, A., 1994. Numerical criterion and sensitivity analysis for time-dependent formation pressure in a sealed layer. J. Pet. Sci. Eng., 12: 137-145. Lee, S., Reilly, J., Lowe, R. and Brodie, S., 1997. Accurate pore pressure and fracture pressure predictions using seismic velocities - - an aid to deep water exploration and drilling design. Annu. Meet. Tech. Prog., Expanded Abstracts, Society of Exploration Geophysicists, Tulsa, OK, 2, pp. 2013-2016. Lee, S., Shaw, J., Ho, R., Burger, J., Singh, S. and Troyer, B., 1999. Illuminating the shadows: tomography, attenuation and pore pressure processing in the South Caspian Sea. J. Pet. Sci. Eng., 24: 1-12. Lindsay, R.O. and Towner, B., 2001. Pore pressure influence on rock property and reflectivity modeling. Leading Edge Geophys., 20(2): 184-187. Mathews, W.R. and Kelly, J., 1967. How to predict formation pressure and fracture gradient. Oil Gas J., 65(8): 92-106. Neil, W.M., Aminzadeh, F., Sarem, A.M.S. and Quintana, J.M., 1993. Guided Oscillatory Well Path Drilling by Seismic Imaging. U.S. Patent Number 5,242,025. Nikravesh, M. and Aminzadeh, F., 2001. Mining and fusion of petroleum data with fuzzy logic and neural network agents. J. Pet. Sci. Eng., 29: 221-238. Pennebaker, E.S. Jr., 1968. Seismic data depth magnitude of abnormal pressures. World Oil, June, pp. 73-77. Pigott, J.D. and Tadepali, S.V., 1996. Direct Determination of Elastic Reservoir Porosity and Pressure from AVO Inversion. Annu. Meet. Tech. Prog., Expanded Abstracts. Society of Exploration Geophysicists, Tulsa, OK. Pigott, J.D., Shrestha, R.K. and Warwick, R.A., 1988a. Direct determination of carbonate reservoir porosity and pressure from AVO inversion. Soc. Explor. Geophys. 60th Annu. Int. Meet., 2:1533-1536. Pigott, J.D., Shrestha, R.K. and -Warwick, R.A., 1988b. Young's Modulus from AVO inversion. Soc. Explor. Geophys. 59th Annu. Int. Meet., 2:832-835. Rector, J.W. III and Marion, B.R, 1989. Extending VSP to 3-D and MWD: using the drill bit as a downhole seismic source. Oil Gas J., 19: 55-58.
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Reynolds, E.B., 1970. Predicting overpressured zones with seismic data. World Oil, 171(10): 78-82. Traugott, M., 1997. Pore fracture pressure determination in deep waters. World Oil, Deep Water Special Suppl., 8:68-70. Tura, A. and Aminzadeh, F., 1999. Dynamic reservoir characterization and seismically constrained production optimization: An overview. Soc. Expl. Geophys. 69th Annu. Meet., Calgary, Canada, Research
Workshop on Dynamic Reservoir Characterization and Seismically Constrained Production Optimization. Yilmaz, O., Nolen-Hoeksema, R.C. and Nur, A., 1994. Pore pressure profiles in fractured and compacted rocks. Geophys. Prospecting, 42:693-714.
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Chapter 8
TECTONICS AND OVERPRESSURED FORMATIONS G.V. CHILINGAR, W. FERTL, H. RIEKE and J.O. ROBERTSON JR.
INTRODUCTION
Abnormally high pore fluid pressures may result from local and regional tectonics. The movement of the Earth's crustal plates, faulting, folding, lateral sliding and slipping, squeezing caused by downdropping of fault blocks, diapiric salt and/or shale movements, earthquakes, etc. can affect formation pore pressures. Due to the movement of sedimentary rocks after lithification, changes can occur in the skeletal rock structure and interstitial fluids. A fault may vertically displace a fluid-bearing layer and either create new conduits for the migration of fluids giving rise to pressure changes or create up-dip barriers giving rise to isolation of fluids and preservation of the original pressure at the time of tectonic movement. Sahay (1994) noted that this barrier may be created by either the fault itself or by bringing the impermeable layer in contact with the permeable layer up-dip. In strongly folded formations there is a reduction in pore volume (due to compression) along with an attenuation of competent layers (in limbs) and accumulation in the cores of anticlinal folds. An additional rupturing of layers of formations also takes place due to squeezing of and stretching of the skeletal rock structure beyond its elastic limit. Thus, there is a development of high fluid pressure in isolated blocks. According to Sahay (1999), in the Surnimastagarh anticline of Jammu, India (Siwalik Belt), overpressures up to 2.38 times hydrostatic have been encountered during drilling. In the outer folded belt of the Assam-Arakan system, pressures 1.8 to 2 times the hydrostatic have been encountered while drilling at the Masimpur area of Assam. In the Balh well of Punjab (Himalayan Foothills), the formation pressure encountered was 2.14 times the hydrostatic. For details on abnormal pressures in India apparently caused by tectonic activity, one can consult Sahay and Fertl (1988).
FAULTING AS A CAUSE OF OVERPRESSURED FORMATIONS
Dickinson (1953), Murray (1961), Carver (1968), Classen (1968), Dickey et al. (1968), Meyers (1968), Harkins and Baugher (1969), Jones (1969), and Fowler (1970) stressed the importance of various types of faults in developing the abnormal-pressure environments. Fig. 8-1 illustrates abnormal pressures as related to faults, whereas Fig. 8-2 is a schematic diagram showing the stratigraphic rise of abnormal pressure as related to prograding sedimentation modified by growth fault.
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Dickey et al. (1968) offered an explanation of how abnormally high formation pressures originated in the Gulf Coast sediments. According to Dickey et al., in southwestern Louisiana, the pattern of abnormally high pressure zones appears to be related to the patterns of faulting contemporaneous with sedimentation and compaction. The process creating these faults (growth faults) prevents the expulsion of water from the pores of argillaceous sediments during compaction and diagenesis. The abnormally high pore pressures might have facilitated sliding and slumping of the sediments at the edge of continental shelf. Dickey et al. (1968) noted that growth faults have many of the characteristics associated with slump-type landslides and that they may indeed be the result of old slides that have ceased their activity and were later buried by sedimentation.
193
TECTONICS AND OVERPRESSURED FORMATIONS
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The role of growth faults in the structural deformation of geo-pressured sediments has also been described by Ocamb (1961) and Thorsen (1963). The Oligocene and Miocene sediments in southwestern Louisiana consist of three facies: (1) continental and deltaic facies consisting of massive sands; (2) neritic facies composed of alternating sands and shales; and (3) shale facies consisting of argillaceous sediments deposited on the outer shelf and slope. Shallow water and continental sediments overlap the marine sequence deposited earlier in deeper water (Dickey et al., 1968). Abnormally high pressures are first encountered in the neritic facies directly beneath the base of the more massive and continuous deltaic sands. Harkins and Baugher (1969) stated that in order for abnormally high pressures to develop, the shales usually must be over 200 ft in thickness. The intertonguing sand-shale facies forms down-slope from the deltaic facies and, therefore, as a prograding sequence, tends to rise stratigraphically in a basinward direction (Harkins and Baugher, 1969). The stratigraphic units thicken seaward. The geologic structure associated with this sedimentation pattern is dominated by growth faults lying roughly parallel to the coast between salt domes (Fig. 8-3). Embayments are areas where salt domes are scarce and growth faulting has caused some stratigraphic units to be abnormally thick. Abnormal pressures are usually found at depths of 10,000-11,000 ft. Dickey et al. (1968) pointed out that the stratigraphic units are thicker on the downthrown side of the growth faults than they are on the upthrown side (Fig. 8-4). Their explanation for this thickening of the sediments is that movement along the fault plane was continuous during sedimentation. The fault planes cut the seafloor while sediments were being swept over it, so that the downthrown block was covered with a thicker layer of sediment. As shown in Fig. 8-4, grabens also commonly occur. Abnormal pressures are associated with this structure-facies relationship and rise
194
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stratigraphically in a basinward direction, being modified by growth faulting (Harkins and Baugher, 1969). In explaining the relationship between abnormally high fluid pressures and growth faulting, Dickey et al. (1968) proposed that during compaction, pore fluids in the marine sediments migrate vertically upward towards the seafloor at a constant rate. As compaction progresses, the vertical permeability of the argillaceous sediments decreases rapidly, forcing the interstitial fluids to travel parallel to the bedding planes. If growth faulting occurs while abundant water is still present in the shales, the routes of up-dip fluid migration parallel to the bedding would be shut off by the fault plane. Pressure buildup tests in producing oil and gas wells have shown that faults, which cut reservoirs, form pressure discontinuities and are seals to fluid movement. As a result of cutoff because of faulting, the fluid has to sustain a heavier overburden load as sedimentation proceeds. Whenever the growth faulting occurred after most of the water had been expelled and the shales were already compacted, the abnormal pressures were observed to be much lower, or pressures were normal. Dickey et al. (1968) also pointed out that inasmuch as growth faults often have dip angles of less than 50 ~ wells frequently cross fault planes. It is possible for a well to encounter the abnormal-pressure zone and then, after crossing a fault plane, to enter a different fault block where pressures are normal.
195
TECTONICS AND OVERPRESSURED FORMATIONS
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Contemporaneous faults are those whose movements occur during sedimentation (Hardin and Hardin, 1961). There can be several causes for regional contemporaneous faults (Carver, 1968), the most significant of which are basement tectonics, deep salt or shale movement, slump across flexures, slump at the shelf edge, differential compaction, response to crustal loading, or a combination of these factors. Bishop (1973) studied this type of faults in North Louisiana and South Arkansas and concluded that Jurassic contemporaneous faults generally parallel regional structural and depositional strike and tend to be slightly younger basinward (south). Most of these faults appear to be downthrown toward the basin. Beds on downthrown sides are greatly thickened and throws increase with depth. Correlation of individual units is very difficult to impossible. Because the downthrown blocks are tilted, sediments are thickest adjacent to the fault. The fault planes appear to be curved, and although having a high angle (60-70 ~ near the top, they may flatten with depth. As a result of this flattening, together with towage of underlying Jurassic salt away from downthrown blocks, faults are not known to extend below the salt. "They do not cut beds younger than Jurassic and die out upward in a conformable section" (Bishop, 1973). Bruce (1973) summarized the mechanism for development of regional contemporaneous faults corresponding to overpressured shales and related sediment deformation as follows: "Regional contemporaneous faults of the Texas coastal area are formed on the seaward flanks of deeply buried linear shale masses characterized by low bulk density and high fluid pressure." According to him, the seismic data show that these
196
G.V. CHILINGAR, W. FERTL, H. RIEKE AND J.O. ROBERTSON JR.
masses, commonly tens of miles in length, have been observed to range up to 25 miles (40.23 km) in width and 10,000 ft (3048 m) vertically. Aligned subparallel with the coast, these features represent residual masses of undercompacted sediment between sandstone/shale depoaxes in which greater compaction has occurred. "Most regional contemporaneous fault systems in the Texas coastal area consist of comparatively simple down-to-basin faults that formed during times of shoreline regression, when periods of fault development were relatively short" (Bruce, 1973). Cross-sectional view shows that these faults flatten and converge at depth to planes related to fluid pressure and form the seaward flanks of underlying shale masses. Faults, which formed during regressive phases of deposition, "developed primarily as a result of differential compaction of adjacent sedimentary masses." They die out at depth near the depoaxes of the sandstone/shale sections (Bruce, 1973). Gravitational faults developed where the subsidence exceeded the rate of deposition and a basinward seafloor inclination was established in the area of deposition. Postdepositional faults are common on the landward flanks of deeply buried linear shale masses. Many of these faults dip seaward and intersect the underlying low-density shale at relatively steep angles (Bruce, 1973). Bruce (1973) supported the concept of regional contemporaneous fault development through sedimentary processes where thick masses of shale are present and where deep-seated tectonic effects are minimal. A schematic dip section through the Rio Grande Embayment, illustrating strata thickening across growth faults (Murray, 1961), is shown in Fig. 8-5. Three basic types of such regional contemporaneous faults (Bruce, 1973) are presented in Fig. 8-6, with differentiation based on the rates of deposition of sandy sediments upon unconsolidated clay surfaces. According to Bruce (1973), (1) two of these types are considered to be associated with seafloors which were relatively flat at the time of deposition, and (2) the third type appears to be formed in areas of slope environments where seafloor subsidence exceeded the rate of deposition. The first example (Fig. 8-6a) represents faults formed during a regressive sequence of deposition (progradation locally), when the amount of sediment available for deposition was greater than the space available for accumulation. Under these conditions each successive depoaxis was formed seaward from that of the adjacent underlying unit. Antiregional dip, developed adjacent to the downthrown sides of these faults, varies in relation to the amount of sediment deposited. In areas where 'still-stand depositional conditions' prevailed, the rate of faulting was sufficient to accommodate all incoming sediments (Fig. 8-6b). In these areas, a strong antiregional dip developed that increased with depth and time. "Contemporaneous faults, formed during still-stand and regressive phases of deposition, are common in southern Texas and are considered to have developed primarily through differential compaction associated with relatively flat seafloors" (Bruce, 1973). Faults formed during transgressive phases of deposition are less common than the other two types in southern Texas (Bruce, 1973). They occur when subsidence exceeds the rate of deposition (Fig. 8-6c). The seafloor is considered to have been inclined basinward at an angle related to the rate of subsidence. "The primary cause of seafloor
197
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198
G.V. CHILINGAR, W. FERTL, H. RIEKE AND J.O. ROBERTSON JR.
subsidence and tilting was not dependent on differential compaction and differential loading, as described for faults formed during regressive and still-stand phases of deposition. Instead it was controlled by forces below or outside the area of deposition. These forces may owe their origin to either salt movement or basement tectonics." Some manifestations of contemporaneous faulting can be explained when seafloor inclination and basinward formational dips are compared with rates of deposition. Gravity-slide faults are the most significant of these. "Many of them become bedding-plane types at depth" (Bruce, 1973). According to Hospers (1971), the Niger Delta area in Nigeria, Africa, has a clay-shale base of considerable thickness. The subsurface structure of this delta is characterized by typical growth faults with associated rollover structures, which are interpreted as being caused by gravity. Overpressures are encountered in the delta area. Roberts (1972) developed several tectonic concepts based upon the pore fluid pressure hypothesis of Hubbert and Rubey (1959). According to him, overthrusts cannot develop unless the thrust sheet is underlain by a weaker layer or unless abnormal pore fluid pressures are restricted to this layer. The conditions of failure implied by the Hubbert-Rubey hypothesis indicate that both requirements are met if the ready ingress or egress of pore fluid is prevented during impending shear failure. Under these circumstances, sediments capable of further compaction undergo an increase in formation pressure so that the effective value of ~ (i.e., pore pressure: total overburden pressure ratio) at failure is unity. This type of behavior is typical of shale horizons, which act as the locus of overthrust faults. Dilation hardening affects the intervening sandstone or limestone horizons, which in turn form the overthrust sheets. Once shear failure is initiated, movement is essentially frictionless as long as excess pore pressures (overpressures) are maintained (Roberts, 1972).
S H A L E DIAPIRISM (MUD LUMPS, MUD V O L C A N O E S )
Fertl (1976) noted that conditions necessary for diapirism are a density inversion including a material of low shear strength. This may be produced when a low-permeability formation is rapidly loaded and depocenters are rapidly shifted (Gretener, 1969). Such conditions are found in delta areas of major rivers, such as the Mississippi, Niger, Nile, Danube, and Amazon. Mud lumps (small shale diapirs) are formed by shales having high water content (high porosity) and low shear strength that have been rapidly loaded by sands (Morgan, 1952; Murray, 1961). On a small scale, diapirism produces mud lumps, whereas on a large scale mud volcanoes are formed. Mud volcanoes represent an overpressure phenomenon caused by an intrusion at depth of mud and/or a mixture of mud and solid rocks (Fig. 8-7). It is necessary to distinguish material that has been extruded over the ground surface from material that has been intruded diapirically (now exposed as a result of erosion of the older enveloping rock). Suter (1960) has called both "diapiric rocks" and assigned the term "sedimentary volcanism", as did Kugler (1933, 1938), to emphasize the non-igneous nature of the phenomenon. One must also distinguish between (1) accretionary cones of gently extruded mud accompanied by gas and water, and (2) gas
199
TECTONICS AND OVERPRESSURED FORMATIONS
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seepages accompanied by more or less muddy water but lacking mud cones (Ridd, 1970). As pointed out by Handin et al. (1963), rapid Tertiary and/or Late Cretaceous sedimentation is associated with mud volcanoes. In addition, pore fluid pressures are abnormally high. For example, pressure gradients of 0.9 psi/ft (0.208 kg cm -2 m -1) have been reported around mud volcanoes on Apsheron Peninsula in Azerbaijan (see Buryakovsky et al., 2001). A rock with pore fluid pressure gradient equal to or exceeding 0.80 psi/ft (0.185 kg cm -2 m -1) may become dilatant during structural deformation (Handin et al., 1963). Fertl (1976) noted that it is unusual in geology to find a phenomenon associated only with rocks of one particular age; however, geologic time is a factor in the escape of abnormally high pore fluid pressures (Ridd, 1970). Mud volcanoes may have erupted in the geologic past. For example, Shelton (1967) discussed diapirism in the Mississippian/Pennsylvanian Springer Group in Oklahoma, formed when the shale was in an overpressured and undercompacted state. Quiescent mud volcano activity is also due to abnormal fluid pressure. Instead of gradual pressure buildup until eruption, mud gently escapes to the surface through fractures. If this bleeding-off of pressure is insufficient, eruption can occur (Ridd, 1970). Kugler (1933, 1938), Wilson and Birchwood (1965), and Gorkun and Siryk (1967) have suggested that subsurface gas under pressure is the driving mechanism responsible for mud volcanoes with some exceptions (Richard, 1945). Gansser (1960) listed several criteria, which mud volcanoes have in common. (1) Mud volcanoes are usually associated with Tertiary (and Upper Cretaceous) sedimentary strata. (2) The sedimentary strata are usually of marine origin.
200
G.V. CHILINGAR, W. FERTL, H. RIEKE AND J.O. ROBERTSON JR.
(3) (4) (5) (6)
Plastic, pelitic beds predominate. Gas and connate salt water are always present. The plastic beds are overlain by more competent deposits. Broad synclines are separated by sharp anticlines in which the deeper plastic sediments push upward. (7) Most eruptive centers consist of several volcanic cones. (8) Shallow and steep-sided cones can be present together. (9) Increasing stress mobilizes the plastic clay in the core with salt water, gas, and, in many cases, oil. The resulting mud is pressed upward in a magma-like fashion and, if the equilibrium of the surface is disturbed, it erupts and forms a mud volcano. (10) The eruptions can be periodic, but commonly are irregular. Many large eruptions have occurred after long periods of quiescence. (11) Small and large rock fragments are commonly present with the mud, usually originating from older formations. (12) Diapiric zones with mud volcanoes generally coincide with areas of negative gravity anomaly. (13) The life of an individual eruptive center is usually short. Yakubov et al. (1973) illustrated the magnitude of forces, sometimes associated with erupting mud volcanoes. "After 13 years of no activity, the largest mud volcano of Loktaban erupted in Azerbaijan for almost 6 hours. During the eruption, the volcano discharged 125,000 m 3 of breccia in the shape of two huge tongues, each about 200 m long and 60 m wide. During the eruption, gas flames ( 1000-1200~ reached 500 m into the sky."
P R E D I C T I O N OF T E C T O N I C A L L Y CAUSED O V E R P R E S S U R E S BY USING RESISTIVITY A N D D E N S I T Y M E A S U R E M E N T S O F ASSOCIATED S H A L E S
Predicting abnormally high formation pressures (AHFP) in carbonates caused by tectonic activity is a very challenging problem. In the presence of thick shale sequences, low porosities, high resistivities, and high bulk densities of shales are characteristic features. The reason is simple: the greater the overcompaction (due to tectonic movement), the greater is the amount of water squeezed from shales into the associated reservoirs, which results in overpressuring. One such example is presented here.
O R I G I N AND D I S T R I B U T I O N OF O V E R P R E S S U R E S IN C A R B O N A T E RESERVOIRS
Many exploration wells drilled in the Pripyatskiy Deep, located in the Byelorussia, have encountered overpressured formations (Fig. 8-8). Zavgorodniy and Pakhol'chuk (1985) have investigated the nature and both lateral and vertical distribution of formation pressure in this area. The change with depth of electric resistivity in the Buregskiy shales, porosity variations, and the ratio of Pres (measured reservoir pressure) to Pahyd (assumed hydrostatic pressure) for the intersalt and subsalt carbonates in the northern Pripyatskiy
Fig. 8-8. Northern Pripyatskiy Deep. Prospects and fields with the overpressures: a = deep-seated faults bounding the Pripyatskiy Deep; b = subsurface and seismic faults; c = boundary of the Vasilevichskiy intersalt depression; d = isopachs of the Buregskiy horizon; e = wells. Prospects with overpressure in carbonate formations: f = subsalt; g = intersalt; h = numerator indicates the prospect or field number (I = Dneprovskaya; 2 = Vetkhinskaya; 3 = Krasnosel'skaya; 4 = Barsukovskaya; 5 = South Rechitskaya; 6 = Malodushinskaya; 7 = Demikhovskaya; 8 = East Pervomayskaya; 9 = Pervomayskaya; 10 = South Tishkovskaya; I 1 = South Ostashkovichskaya; 12 = Zolotukhinskaya; 1 3 = Pritokskaya; 14 = Rudnitskaya; 15 = South Domanovichskaya; 16 = South Sosnovskaya; 1 7 = Vishanskaya; I 8 = Sudovitskaya; 1 9 = Malynskaya; 20 = Glusskaya; and 21 = East Drozdovskaya); denominator shows the reservoir pressure. (Modified after Zavgorodniy and Pakhol'chuk, 1985, fig. 2.)
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I ~
,'
J
-v*1 J . . .,~ 0 . 3 %
O0
l
.'1 , J r
3~176176 Io~ ~.-! . . . . . . . . . .
~
I
I I
~-I
i 01~-+- /22%
4000
I
"~''1 ;ikT 6
'
2,oo rlI+I
el
"I'. I ,115
~
2000 tl
9 -
60 Rm, ohm'm
/
II
s
i
1500 I~"
Pres/Pah
1.0 I.I 1.2 1.3 1.4
w
1.
I
It.I 2 ,1~ Z I,~I/# I
1,3
,~ I : , ~ 's
' 15
,"J',
,I
Fig. 8-9. Variation with depth of (/) electric resistivity of the Buregskiy shales, (II) porosity, and (III) Pres/Pahyd ratio for the subsalt carbonates of the northern structural-tectonic zone in the Pripyatskiy Deep. Prospects with overpressure: 1 = Dneprovskaya; 2 = Vetkhinskaya; 3 -- Krasnosel'skaya; 4 = Barsukovskaya; 5 -- South Rechitskaya; 6 - Malodushinskaya; 7 = Demikhovskaya; 8 -- East Pervomayskaya; 9 -- Pervomayskaya; 10 -- South Ostashkovichskaya; / / = Rudninskaya; 12 = Vishanskaya; 13 = Sudovitskaya; 14 = Malynskaya; 15 -- Glusskaya; and 16 = East Drozdovskaya. (Modified after Zavgorodniy and Pakhol'chuk, 1985, fig. 3.)
Deep are illustrated in Fig. 8-9. Additional detailed information on overpressures is listed in Table 8-1. The standard average deviation of measured formation pressures (Pr~) from Curve III in Fig. 8-9 equals +0.03. According to Zavgorodniy and Pakhol'chuk (1985), two "stabilized P r e s / P a h y d regimes" have been encountered in the region" the first one occurs at 3000 m with a Pres/Pahyd ratio close to 1.14, whereas the second one starts at 3500 m with the pressure ratio asymptotically approaching the value of 1.18 (Fig. 8-9, Curve III). (Pahyd = assumed hydrostatic pressure.)
TABLE 8-1
1
rn 0
Some data on overpressured formations of the northern Pripyatskiy Deep (after Zavgorodniy and Pakhol'chuk, 1985, table I) Prospect
Well
Horizon
Depth (m)
Saturation type
Semiluksky
3450
Oil
4
Depth to O/W contact (m)
Initial reservoir pressure (MPa)
pie,/prhyd
phyd/pahyd
Abnormality
3535
44.4
1.28
1.18
0.10
(1 1 3
3535 3910
38.0 59.5
1.34 1.58
1.24 1.18
0.10 0.40
-
3910
57.7
1.51
1.18
0.33
-
1.51 1.44 1.29
1.18 1.24 1.14
0.33 0.20 0.15
L%d?%L
,Je~c/,Jd,~d
209
Dneprovskaya Vetkhinskaya
8 4
Zadonsky Voronezhsky
2845 3770
Water Oil
Vetkhinskaya
4
Semiluksky
3800
Oil
Krasnoselskaya Krasnoselskaya Barsukovskaya
210 206 9
Semiluksky Zadonsky Semiluksky
4477 2909 3000
Water Gas-condensate Oil
3852
67.6 42.0 38.6
Barsukovskaya
9
Voronezhsky
3031
Oil
3790
423
1.40
1.14
0.26
22 O 070
South Rechitskaya Malodushinskaya
I04 32
Semiluksky Voronezhsky
4770 3622
Water Oil
-
71.6 45.8
1.SO 1.26
1.18 1.18
0.32 0.08
-
3768
Demekhovskaya East Pervomayskaya
20 1 9
Semiluksky Semiluksky
3233 4188
Water Oil
42.0 52.3
1.30 1.25
1.14 1.18
0.16 0.07
-
Pervomayskaya South Tishkovskaya South Ostashkovichskaya South Ostashkovichskaya Zolotukhinskaya
21 121 18 108 13
Voronezhsky Zadonsky Zadonsky Semiluksky Zadonsky
4506 4243 4844 4604 1900
Oil Water Oil Water Oil
1.28 1.41 1.41 1.28 1.40
1.18 1.24 1.24 1.18 1.08
0.10 0.17 0.17 0.10 0.32
-
2275
57.6 59.9 54.6 59.0 26.6
2740 3664
Water Water
-
44.0 48.6
1.60 1.32
1.24 1.18
0.36 0.14
3 38
Zadonsky Sargaevsky + Pashiysky Zadonsky Zadonsky
3260 3685
Water Oil
-
43.5 52.4
1.33 1.42
I .24 1.24
0.09 0.18
Vishanskaya
9
Voronezhsky
2737
Oil
3001
32.5
1.19
1.12
0.07
Sudovitskaya Malynskaya Glusskaya
3 6 4
4479 3235 2083
Oil Water Water
-
1.24 1.25 1.25
1.18 1.14 1.10
0.06 0.11 0.15
-
-
55.6 40.4 26.1
East Drozdovskaya
1
Voronezhsky Semiluksky Voronezhsky + Semiluksky Voronerhsky + Semiluksky
1877
Water
-
21.8
1.16
1.08
0.08
-
Pritokskaya Rudninskaya South Domanovichskaya South Sosnovskaya
5 4
p,, = reservoir pressure; pahyd= assumed hydrostatic pressure; p,,, = excess pressure.
-
-
4386 -
3855 -
-
-
-
> z
Dneprovskaya
+ oil
2g
1 ) 8 I I 021 IZ -
0.032
-
0
9m F ia
m
V]
z
ia
m
-
049
11 1 6
11 9
m
1 0
5
5 5
14
(1 (134
-
15
0080 -
-
--1.8 0 050 12
0 044
-
h)
S
204
G.V. CHILINGAR, W. FERTL, H. RIEKE AND J.O. ROBERTSON JR.
By definition, abnormal formation pressures (i.e., overpressures) are characterized by conditions where the Pres/Pahyd ratio by more than twice exceeds the standard deviation value. In other words: while below 3000 m the anomalous values approach 20%, the excess anomalous deviation below 3500 m ranges from 20% to 40% (e.g., Vetkhinskaya, Krasnosel'skaya, Barsukovskaya, and South Rechitskaya fields). Only in three oil fields slight overpressures (<15%) were encountered above a depth of 3000 m. Similar observations have been made for the intersalt sediments by Zavgorodniy and Poroshin (1981). Whereas magnitude and frequency of overpressures in the subsalt sedimentary section increase in an easterly direction, abnormal formation pressures in the intersalt complex are only encountered within the southeastern portion of the area, i.e., in wells drilled along the periphery and the central portion of the Vasilevichskaya Depression (Fig. 8-8). The compilation of subsurface pressure data in Table 8-1 in several fields and wildcat wells, located within the northern structural-tectonic zone of the Pripyatskiy Deep, allows the following observations: (1) overpressures are mainly encountered below the depth of 3000 m; (2) formation pressures increase with depth and exceed hydrostatic pressures by 30 to 40% between 3500 and 5000 m; (3) these overpressures occur in oil-bearing as well as water-bearing rocks with no significant pressure differentials being observed across oil-water contacts. It is postulated that compaction of the Buregskiy shales expelled shale water primarily into the good Semilukskiy carbonate reservoirs and only to a very small extent into the marginal Voronezhskiy reservoirs. Potential reservoir rocks within the intersalt complex, on the other hand, are invaded by the 'compaction' waters from shales and marls only in the areas of major subsidence. Zavgorodniy and Pakhol'chuk (1985) refer in particular to the Vasilevichskaya Depression with depth to the intersalt complex in excess of 5 km. Depth and thickness of shales, presence of adjacent permeable reservoir rocks, extent of the hydrodynamic isolation (i.e., sealing) of reservoir rocks, the tectonic history, etc., all are major factors in the origin, distribution, and magnitude of overpressures. Variations of electric resistivity (p, ohm m) with depth as observed in the Buregskiy shales were studied by Zavgorodniy and Pakhol'chuk (1985) to investigate the degree of shale compaction (Fig. 8-9). The Buregskiy shales have been encountered over a wide depth range, i.e., from 1249 m in well Novodubrovskaya No. 1 to 5080 m in well Svetlogorskaya No. 1 with a corresponding significant resistivity change from 2.2 to 129 ohm m. Core samples above 4100 m clearly showed the Buregskiy interval to be composed of shales (e.g., wells Nos. 1, 23, and 26 in the Ozershchinskaya field; and well No. 8 in the Barsukovskaya field), or a combination of shales and mudstones (e.g., well No. 18 in the Ozershchinskaya field; and wells Nos. 15, 22, 25, 28, and 34 in the Barsukovskaya field). At and below 4100 m, the horizon is composed predominantly of mudstones (e.g., wells Nos. 9, 10, 11, 16 in the East Pervomayskaya field). These lithological alterations are the result of diagenetic and catagenetic processes accompanied by the expulsion of pore water which then entered adjacent Semilukskiy and Voronezhskiy reservoir rocks.
TECTONICS AND OVERPRESSURED FORMATIONS
205
Based on the mathematical model proposed by Anikiev (1971), porosity values for the shales at different depths can be estimated as follows: 4~ - 4~(1.0 - 0.25/3D)
(8-1)
where ~bsh D is the shale porosity value at depth D" qS~his the shale porosity at the surface (~35%); and r is the irreversible rock compaction factor (/~ -- 27 • 10 -5 MPa-1). For example, the amount of shale water (0.13 m 3) expelled at 3000 m, where porosity decreased by 13%, is well over the capacity of the regionally developed Semilukskiy reservoirs. That is why the pore water expelled from the Buregskiy shales was sufficient to create overpressure conditions in both the Semilukskiy and Voronezhskiy reservoir sequences, provided these reservoirs were hydraulically sealed (Zavgorodniy and Pakhol'chuk, 1985). As pointed out by Zavgorodniy and Pakhol'chuk (1985), the areal distribution of the overpressures is related to the thickness of the Buregskiy shale (Fig. 8-8; Table 8-1). The highest overpressures (i.e., with an abnormalityfactor of 0.2-0.4; see Table 8-1) are in the easterly portion of the northern structural-tectonic zone where the Buregskiy shale thickness is between 40 and 60 m (e.g., South Rechitskaya and Krasnosel'skaya fields), whereas to the west the shale thins out to 5-10 m with a corresponding decrease in the abnormality factor in the range of 0.06-0.14. East of Barsukovskaya and Vetkhinskaya, oil fields with several promising subsalt structures have been defined with an anticipated overpressure abnormality factor as high as 0.3-0.4. Basically these potential reservoir rocks occur in deeply buried and hydraulically sealed fault blocks. On the other hand, no significant overpressures are anticipated within the subsalt sedimentary complex in the highly faulted part of the central structural-tectonic zone of the Pripyatskiy Deep.
CONCLUSIONS
The following generalized conclusions as to the overpressure environments in the Pripyatskiy Deep were made by Zavgorodniy and Pakhol' chuk (1985). (1) Overpressured rocks do not occur above 3000 m. (2) Below 3000 m, overpressures may exceed hydrostatic pressure by as much as 40%. They are caused by 'compaction' water from shales and marls which entered the carbonate reservoirs. (3) Overpressures in the subsalt Semilukskiy and Voronezhskiy carbonates are controlled by the thickness of associated Buregskiy shales and the degree of hydrodynamic sealing of the carbonate reservoirs. Highest overpressures are most likely in the eastern region of the Pripyatskiy Deep where the thickness of Buregskiy shales is maximum (30-60 m). (4) Intersalt rocks exhibit significant overpressures only within the Vasilevichskiy Depression, i.e., the deepest portion of the Pripyatskiy Deep. Elsewhere, such overpressures are only encountered locally and are insignificant. (5) Overpressures occur only in the presence of good sealing of reservoirs. In the opinion of the writers, the greater the degree of overcompaction in shales, mudstones and/or marls due to the tectonic activity, the greater is the overpressure
206
G.V. CHILINGAR,W. FERTL, H. RIEKE AND J.O. ROBERTSONJR.
owing to the greater volume of water squeezed from the shales, mudstones, and/or marls into the associated reservoir rocks. This suggests the following predictive techniques: (1) increase in the resistivity of shales; (2) decrease in the acoustic travel time of shales; (3) increase in the bulk density of shales; and (4) decrease in the pulsed neutron capture cross-section of shales (Fertl and Chilingarian, 1989). Considerable amounts of research work, however, still remain to be done in this area.
BIBLIOGRAPHY Anikiev, K.A., 1971. Prognostication of the Super-high Reservoir Pressure and Improvements in Deep Oil and Gas Drilling. Nedra, Leningrad. Bishop, W.E, 1973. Late Jurassic contemporaneous faults in North Louisiana and South Arkansas. Bull. Am. Assoc. Pet. Geol., 57: 858-877. Bruce, C.H., 1973. Pressured shale and related sediment deformation mechanism for development of regional contemporaneous faults. Bull. Am. Assoc. Pet. Geol., 57: 878-886. Buryakovsky, L.A., Chilingar, G.V. and Aminzadeh, E, 2001. Petroleum Geology of the South Caspian Basin. Gulf Prof. Publ., Boston, MA, 442 pp. Carstens, H., 1980. Abnormal Formation Pressure Detection: Limitations to the 'Porosity Tools'. Norwegian Petroleum Society Seminar, Stavanger (preprint). Carstens, H. and Dypvik, H., 1981. Abnormal formation pressure and shale porosity. Bull. Am. Assoc. Pet. Geol., 2: 344-350. Carver, R.E., 1968. Differential compaction as a cause of regional contemporaneous faults. Bull. Am. Assoc. Pet. Geol., 52: 414-419. Castro, G., 1987. On the behavior of soils during earthquakes liquefaction. In: A.S. Cakmak (Ed.), Soil Dynamics and Liquefaction. Developments in Geotechnical Engineering. Elsevier, Amsterdam. Classen, J.S., 1968. Formation pressure-production relationship, Lake Mongoulois Field. SPE 2206, 43rd AIME Fall Meet., Houston, TX, Sept. Dickey, EA., Shriram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160:608-6 ! 5. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana. Bull. Am. Assoc. Pet. Geol., 37: 410-432. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Fertl, W.H. and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1(1): 23-38. Fertl, W.H. and Chilingarian, G.V., 1989. Prediction of tectonically caused overpressures by using resistivity and density measurements of associated shales. J. Pet. Sci. Eng., 3(3): 203-208. Fowler Jr., W.A., 1970. Pressure, hydrocarbon accumulation and salinities Chocolate Bayou field, Brazoria County, Texas. J. Pet. Technol., 22: 411-432. Gansser, A., 1960. Ueber Schlammvulkane und Salzdome. Naturforsch. Ges. Zuerich Viertelsjahrssch., 105: 1-46.
Gorkun, V.N. and Siryk, L.M., 1967. Calculation of depth and volume of released gas during the eruption of mud volcanoes in southern Sakhalin. Geol. Geofiz., 2: 30-42. Gretener, EE., 1969. Fluid pressure in porous m e d i a - its importance in geology: a review. Bull. Can. Pet. Geol., 17: 255-295. Gurevich, A.E., 1980. Handbook of Groundwater Motion Exploration. Nedra, Leningrad, 216 pp. Gurevich, A.E., 1984. A new possible mechanism of hydrocarbon migration. Abstr. 27th Int. Geol. Congr., Moscow, 7, pp. 49-50. Gurevich, A.E. et al., 1987. Formation Fluid Pressure. Nedra, Leningrad, 223 pp. Gurevich, A.E., Chilingar, G.V. and Aminzadeh, E, 1994. Origin of the formation fluid pressure and ways of improving prediction methods. J. Pet. Sci. Eng., 12: 67-77.
TECTONICS AND OVERPRESSUREDFORMATIONS
207
Handin, J., Hager, R.V., Friedman, M. and Feather, J.N., 1963. Experimental deformation of sedimentary rocks under confining pressure - - pore pressure tests. Bull. Am. Assoc. Pet. Geol., 47: 717-755. Hardin, ER. and Hardin, G.C., 1961. Contemporaneous normal faults of Gulf Coast and their relation to flexures. Bull. Am. Assoc. Pet. Geol., 45: 239-248. Harkins, K.L. and Baugher III, J.W., 1969. Geological significance of abnormal formation pressures. J. Pet. Technol., 21(8): 961-966. Hospers, J., 1971. The geology of the Niger delta area. Inst. Geol. Sci., London, Rep., 70: 121-142. Hubbert, M.K., 1940. Theory of ground-water motion. J. Geol., 48(8): 785-944. Hubbert, M.K. and Rubey, W.W., 1959. Role of fluid pressure in mechanics of overthrust faulting, 1. Mechanics of fluid filled porous solids and its application to overthrust faulting. Geol. Soc. Am. Bull., 70: 115-166. Jones, EH., 1969. Hydrology of Neogene deposits in the northern Gulf of Mexico Basin, LA. Water Resour. Res. Inst., Bull., GT-2, Louisiana State Univ., Baton Rouge, LA, 105 pp. Kalinko, M.K., 1967. Mud volcanoes as a source of information on the composition of hydrocarbons, their quantity, and conditions of occurrence. Sov. Geol., 7: 86-96. Kugler, H.G., 1933. Contribution to the knowledge of sedimentary volcanism in Trinidad. Inst. Pet. J., 19: 743-760. Kugler, H.G., 1938. Nature and significance of sedimentary volcanism. In: The Science of Petroleum, Vol. 1. Oxford Univ. Press, London, pp. 297-299. Leftwich, J.T. and Engelder, T., 1994. The characteristics of geopressure profiles in the Gulf of Mexico. Bull. Am. Assoc. Pet. Geol. Mem., 61: 119-129. Melik-Pashaev, V.S., Khalimov, E.M. and Seregina, V.N., 1983. Abnormally High Formation Pressures in Oil and Gas Fields. Nedra, Moscow, 181 pp. Meschan, S.R., 1978. Initial and Long-term Strength of Clayey. Soils. Nedra, Moscow, 207 pp. Meyers, J.D., 1968. Differential pressures: a trapping mechanism in Gulf Coast oil and gas fields. Trans. Gulf Coast Assoc. Geol. Soc., 18: 56-80. Morgan, J.E, 1952. Mud lumps at the mouth of the Mississippi River. In: J.W. Johnson et al. (Eds.), Coastal Engineering. Eng. Foundation, Univ. of California Press, Los Angeles, CA, pp. 130-144. Murray, G.E., 1961. Geology of the Atlantic and Gulf Coastal Province of North America. Harper and Brothers, New York, NY, 692 pp. Ocamb, R.D., 1961. Growth faults of South Louisiana. Trans. Gulf Coast Assoc. Geol. Soc., 11: 139-182. Richard, J.J., 1945. The mud volcanoes of Moa near Tanga. Tanganyika Notes Rec., 19: 3-8. Ridd, M.E, 1970. Mud volcanoes in New Zealand. Bull. Am. Assoc. Pet. Geol., 54: 601-616. Rieke, H.H. III and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Elsevier, Amsterdam, 424 pp. Roberts, J.L., 1972. The mechanism of overthrust faulting: a critical review. Proc. 29th Int. Geol. Congr., Montreal, QC, Section 3, pp. 593-598. Rubey, W.W. and Hubbert, M.K., 1959. Role of fluid pressure in mechanics of overthrust faulting. 2. Overthrust belt in geosynctinal area of western Wyoming in light of fluid pressure hypothesis. Geol. Soc. Am. Bull., 70: 167-206. Sahay, B., 1994. Petroleum Exploration and Exploitation Practices. Allied Publ. Ltd, New Delhi, 647 pp. Sahay, B., 1999. Pressure Regimes in Oil and Gas Exploration. Allied Publ. Ltd, New Delhi, 460 pp. Sahay, B. and Fertl, W.H., 1988. Origin and Evaluation of Formation Pressures. Allied Publ. Ltd, New Delhi, 292 pp. Shelton, J.W., 1967. Deformational pattern in the Springer Group of southeastern Oklahoma. Geol. Soc. Am., South Cent. Sec., Annu. Meet. Progr., Norman, OK, p. 25. Silver, M.L. and Seed, H.B., 1971. Volume changes in sands during cyclic load. J. Soil Mech. Found. Div. Proc. Am. Soc. Civ. Eng., 97(SM9): 1171-1182. Suter, H.H., 1960. The General and Economic Geology of Trinidad. H.M. Stationary Office, London, 145 pP. Tdth, J., 1962. A theory of groundwater motion in small drainage basins in Central Alberta, Canada. J. Geophys. Res., 67(11): 4375-4387. Thorsen, C.E., 1963. Age of growth faulting in southeast Louisiana. Trans. Gulf Coast Assoc. Geol. Soc., 13: 103-110.
208
G.V. CHILINGAR,W. FERTL, H. RIEKE AND J.O. ROBERTSONJR.
Whittaker, A. (Ed.), 1985. Theory and Evaluation of Formation Pressures. Int. Human Res. Dev. Corp., Boston, MA, 231 pp. Wilson, C.C. and Birchwood, K.M., 1965. The Trinidad sand volcano island of 1964. Proc. Geol. Soc. London, 1626: 169-174. Yakubov, A.A., Ali-Zade, A.A. and Kastryulin, N.S., 1973. A new eruption of Lokbatan mud volcano. Azerb. Neft. Khoz., 3: 5-7. Youd, T.L., 1972. Compaction of sands by repeating straining. J. Soil Mech. Found. Div. Proc. Am. Soc. Civ. Eng., 98(SM7): 709-725. Zavgorodniy, A.L. and Pakhol'chuk, A.A., 1985. The distribution and nature of the overpressure in carbonate reservoirs of the Pripyatskiy Deep. Geol. Nefti Gaza (Geol. Oil Gas), II: 51-56. Zavgorodniy, A.L. and Poroshin, V.D., 1981. Overpressures in oil-gas accumulation zones of the Pripyatskiy Deep. In: Problems of Methodology and Some Results of Oil Exploration in the Pripyatskiy Deep. Minsk, pp. 107-110. Zkhus, I.D. and Bakhtin, V.V., 1979. Lithogenetic Transformations of Shales in the Abnormally High-Pressured Zones. Nauka, Moscow, 139 pp.
209
Chapter 9
PREDICTION OF ABNORMALLY HIGH PRESSURES IN PETROLIFEROUS SALT-BEARING SECTIONS V.I. ZILBERMAN, V.A. SEREBRYAKOV, M.V. GORFUNKEL, G.V. CHILINGAR and J.O. ROBERTSON JR.
INTRODUCTION
Thick salt-bearing sequences form sealing complexes in many oil regions around the globe. Serving as seals, these complexes often include oil, gas and brine accumulations with abnormally high formation pressure (AHFP). Forecasting AHFP in evaporites is difficult. The reason for that is the absence in the evaporites of transition zones, which are typical for clastic seals (Dobrynin and Serebryakov, 1989). Consequently, in evaporite sequences there are no indications of approaching the overpressured intervals (such indicators are common in clastic sequences). Logging techniques in this type of section are not applicable. Reservoir pressure within these formations changes abruptly, with no gradual transition. Fluid accumulations in evaporites are sporadically developed over the area and are mostly associated with zones of weakness due to salt intrusion (fracturing, development of sand lenses, etc.). Even an increase in drilling rate is not always diagnostic in the evaporite sequences. Overpressured fluid accumulations are usually encountered immediately underneath the salt section, which is drilled easily and at a high rate. It is very difficult in such an environment to observe an increase in drilling rate caused by a decrease in rock strength (zones of fracturing) or by a decrease in differential pressure between the borehole and the reservoir. The situation is often further obscured due to the intentional decrease in drilling rate in salt sections with the purpose of eliminating the borehole deviation. In evaporites, especially in salt-beating sections, it is much more difficult to detect a temperature increase on approaching the AHFP than it is in clastic sections. Another complicating factor in evaporite seals is their non-uniform gas-saturation, which is not the case in the clastic seals. Brine shows are commonly associated with the overpressured zones in evaporites. Substantial brine shows are common in geologically young, Mesozoic and Cenozoic, salt-bearing sections. Older Paleozoic sediments, with more compacted and catagenetically altered rocks, display oil and gas shows accompanied with much less intense brine shows. The southeastern Dnepr-Donets Basin in the Ukraine (see Fig. 9-1) is an example of a region where the Lower Permian evaporites form a regional seal for a gas-beating section. Little knowledge of the gas-occurrence conditions within this region and a lack of overpressure forecast methodology here have resulted in numerous gas shows, kicks and blow-outs (Zilberman, 1972; Zilberman and Zilberman, 1978). Dangerous
.
,
- 1 1
.
\
,,
1
EXPLANATION
Fig. 9-1. Location of Dnepr-Donets Basin, Carpathian Basin and North Black Sea-Crimean Region in the Ukraine. Principal oil and gas fields are shown. (Modified after Polutranko, 1998, fig. 1, p. 182. Courtesy of the American Association of Petroleum Geologists.)
PREDICTION OF ABNORMALLY HIGH PRESSURES IN PETROLIFEROUS SALT-BEARING SECTIONS
211
complications with AHFP-associated brine shows have occurred while drilling the salt-anhydrite sequence in the Bukhara-Khiva region of Uzbekistan (Kushnirov et al., 1972). Similar complications have occurred in West Uzbekistan, East Turkmenistan, Tadzhikistan, over the Astrakhan Arch in Russia and in some other regions.
INDICATORS OF APPROACHING THE O V E R P R E S S U R E D ZONES
The absence of transition zones sealing the high-pressure hydrocarbon accumulations in evaporite sequences makes the forecasting of AHFP very difficult. This makes the development of precursor indicators for AHFP very important. An interesting example may be found among the gas condensate fields in the central graben of the Dnepr-Donets Basin (southeastern Ukraine). The Permian and Upper Carboniferous section there includes commercial gas accumulations and an evaporite sequence (Lower Permian Bakhmut Series), which is a regional seal. These gas-condensate fields are located within a complex geologic environment, with a massive accumulation height of up to 1500 m, total gas-saturated column of up to 1800 m, reservoir pressure of up to 40 MPa, and abnormality coefficient (Pa/Ph, where Pa is the abnormally high pressure and ph is the normal hydrostatic pressure) of up to 1.9. The sealing evaporite sequence includes 'high-pressured-low-volume' and 'high-pressured-low-permeability' local gas accumulations (Melik-Pashayev, 1973). These small accumulations (Zone II, Fig. 9-5) are satellites of the massive-bedded large gas accumulations (Zone I) and sometimes lie 500 to 600 m above them. AHFP zones in the sealing sequence are associated mostly with faults and the crestal portions of the accumulation structures, which experience the greatest excess gas pressure. It was found that the AHFP occurs mostly within the structural elements that experienced the most active neotectonic evolution. Evaporite sequences have better sealing capacity than clastic sequences. As a result, predictive precursors of the AHFP begin to appear closer to the accumulations. For instance, an indication of the approach to the massive gas condensate accumulation in the Shebelinka Field is a drastic decrease in drilling rate in a very firm anhydrite bed, 4 to 12 m thick. This bed is a part of the Svyatogor Rhythm underneath the salt, and serves as a seal for the massive gas accumulation (Fig. 9-2). It is a lithologic barrier similar to clayey seals established over many accumulations in thick sand-shale sequences (Anikiyev, 1971; Durmishyan, 1973). The hard anhydrite bed is the upper limit for small high-pressured gas accumulations and of decompacted clays (as a result of elevated pore pressure and decrease in effective stress). The only gas occurrence above that bed is found in well No. 80 located within a fractured zone over an uplifted fault-block of the Shebelinka anticline. This well penetrated the gas accumulation 50 m above the main accumulation of gas. A plastic clay (greenish-gray and brown) is encountered in the Shebelinka Field directly above the lithologic barrier. This clay is observed in the drilling mud returns as a bubbly flaky mass with a pronounced smell of condensate. The drillers caI1 it 'gas clay'. Fig. 9-2 shows the lithologic barrier and 'gas clay' for a typical stratigraphic section of the Svyatogor Rhythm of the Shebelinka Field. The 'gas clay' appearance in the circulating mud is a signal to prepare to drill into the massive overpressured gas
212
V.I. ZILBERMAN, V.A. SEREBRYAKOV,M.V. GORFUNKEL, G.V. CHILINGAR AND J.O. ROBERTSONJR.
,_ lz
O s:~ "'--0~ -1-- c~ _
155o
a)>"
ResistivityLog
O r'O "~
M2AO.25B
L LI'L hLl" L. t. L L I. L L, L, L, e. ~,
~
Drilling Rate
Ohm-m i
5
10
15
I
I
I
20
Mud Log min/m
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accumulation with AHFP. The drilling rate increases upon entering the 'gas clay', which ranges from 3 to 10 m in thickness. The gas-clay and lithologic barrier are present in the other fields adjacent to the Shebelinka Field (Efremov, Melikhov, Medvedov and
PREDICTION OF ABNORMALLY HIGH PRESSURES IN PETROLIFEROUS SALT-BEARING SECTIONS
213
Kagichev fields) and in other regions where gas-condensate accumulations, similar to those of the southeastern Dnepr-Donets Basin, are sealed with evaporites. Gas shows in the upper portion of the Philippov Horizon (directly underneath a thick salt sequence) are an indication of approaching the AHFP in the Orenburg Field (Meshcheryakov et al., 1966). The scattered nature of the local gas accumulations in the Orenburg Field sealing sequence is believed to indicate their association with fractured zones. These fractures are associated with faults used by gas to migrate up from the major hydrocarbon accumulation.
LOCATING THE A R E A L POSITIONS OF AHFP ZONES
Evaporite sequences possess very peculiar physicochemical properties; therefore, all indirect techniques should be utilized in the AHFP forecast that could help establish patterns of geologic evolution of regional or local structures and associated hydrocarbon accumulations. Possible ways to forecast AHFP in the Paleozoic salt-bearing sequence of the Dnepr-Donets Basin (DDB) are as follows. Two salt-beating formations, a Lower Permian and a Devonian, are developed in the DDB. The Lower Permian evaporites are encountered at a depth of 1000 to 2000 m and are 500 to 1500 m thick. They form a seal for large gas accumulations, but also contain small overpressured gas accumulations. The Devonian salt deposits, which are found at a depth ranging from 3500 to 4000 m in the northwestern part of the region, are too deep to be reached by drilling in the central and southeastern parts of the region. The gas reserves controlled by the Lower Permian salt seals and by the buried Paleozoic highs with Devonian salt plugs are concentrated within the southeastern DDB. The Devonian salt domes pierced the overlying Carboniferous rocks along the large faults mainly over the peripheral areas of the anticlines. The portion of the sediment cover where piercement had occurred are fractured (Fig. 9-3, III). These zones are called 'zones of weakness'. Such structurally weakened areas are present around each salt plug, i.e., within each salt plug-associated structure. Gas accumulations in the sealing salt sequence in a number of the southeastern DDB gas fields are spatially associated with the salt plugs (among such fields are the West Krestishchenskoye, Efremov, Melikhov, Medvedov and Kagichev). A study of the available logs and drilling information demonstrates a clear correlation between the AHFP manifestations in the Lower Permian evaporites and the structurally weakened near-plug areas. Faults, which are very common here, have served as conduits for gas overflows up from the sub-salt (under-salt) deposits (Zone I, Fig. 9-5). This resulted in the formation of AHFP within the salt seals. An inference is that the identification of a zone of weakness makes a forecast of possible AHFP zones possible. Currently, available techniques for the identification of overpressured zone are based on well logs obtained in the process of drilling (MWD). This means that an AHFP zone is discovered vertically; usually, its areal extent remains unknown. This prevents undertaking of protective measures in the nearby wells drilled subsequently. As a result, AHFP may be encountered unexpectedly at different stages of oilfield exploration and development.
214
v.I. ZILBERMAN, V.A. SEREBRYAKOV,M.V. GORFUNKEL, G.V. CHILINGAR AND J.O. ROBERTSONJR.
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PREDICTION OF ABNORMALLY HIGH PRESSURES IN PETROLIFEROUS SALT-BEARING SECTIONS
215
Delineation of an AHFP zone in evaporites, as a zone of tectonic weakness, is a direct method of preventing complications at the stage of designing the drilling plan. An attempt to forecast overpressured brine shows in relatively young deposits by locating fractured zones in salt-bearing sequences (which also represent zones of tectonic weakness) was successful. The fractured zones in that case were identified from seismic data. Satisfactory results are obtained when the evaporite sequence is not deformed by salt diapirs (Melik-Pashayev, 1973). A problem with delineating the development of weakness zones with seismic data in the DDB is that the correlation of reflection and refraction waves disintegrates on approaching salt plugs. The salt plugs proper are areas of the total loss of correlation. Only an approximate position of the salt plug and a general outline of an area where correlation is lost is provided by the seismic data. For the delineation of AHFP zones in such cases it is proposed to use the established pattern in the thickness changes of the post-salt (above salt) rocks where the so-called indicator sequences are present. Zilberman et al. (2000) stated that for some periods in the geologic evolution, the rate of subsidence of the tectonic weakness zones was faster than the rate of regional subsidence. This resulted in a greater thickness of accumulated sediments, which was more pronounced each time when the sign of tectonic movement changed. These were exactly the time intervals when the indicator sequences accumulated; their thicknesses above the zones of weakness are 1.5 to 3 times that of the background thickness (Fig. 9-4). Among the indicator sequences in the Dnepr-Donets Basin are the Upper Permian Shebelinsk Formation, and Lower Jurassic, Lower and Upper Cretaceous, Paleogene and Neogene deposits (Zilberman and Chernyakov, 1981). Thus, the AHFP zones can be delineated with the help of indicator sequences, which exhibit variation in thickness: greater thickness in the tectonic weakness zones above salt plugs as compared to the thickness of the same deposits away from the salt plugs and weakness zones. Zones of weakness represent the most mobile foci so that the associated indicator sequences are the thickest. The proposed technique by Zilberman and Chernyakov (1979) enables one to delineate an AHFP zone using the thickness of a geologic section up to 1000 m above the possible AHFP interval. This technique also makes it possible to forecast a prospect based only on core drilling. Each subsequent well drilled over the prospect substantially improves the information and hence the reliability of the forecast. An example of this would be the isopach map of Fig. 9-3 for the Lower and Middle (Bajocian) Jurassic sediments near the salt plug of the West Krestishchenskoye gas-condensate field. The 100-m isopach map presented in this figure delineates an AHFP zone. Not only does an application of this technique provide an opportunity to delineate the AHFP zones in the section and areally, but it also provides forecasting at the design stage and during drilling. In addition, it enables a better casing string design and drilling program to take into account otherwise unexpected pressure surges. The well location relative to a danger zone is fine-tuned as indicator sequences are penetrated and their thicknesses are measured. This technique is based on the analysis of available geologic information and does not require substantial additional funds. There is, however, a weakness in this technique, because of an intrinsic weakness in the appraisal and development of the salt plug-trapped hydrocarbon accumulations.
216
V.I. ZILBERMAN,V.A. SEREBRYAKOV,M.V. GORFUNKEL,G.V. CHILINGARAND J.O. ROBERTSONJR.
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The weakness lies in the delineation of the salt plug, which is the boundary between the accumulation and the AHFP zone. As mentioned above, the seismic survey is not capable to accurately delineate the salt plugs. Errors in locating the boundaries result in poor well locations. As an example, in Western Krestischensk gas condensate accumulation, five appraisal wells and one development well have been drilled without
PREDICTION OF ABNORMALLY HIGH PRESSURES IN PETROLIFEROUS SALT-BEARING SECTIONS
217
leaving the salt plug, which is trapping a massive gas accumulation. A great number of unfavorably located wells exit the salt plug below the gas-water contact (GWC) or penetrate only the lowermost portion of the productive horizons. For a reliable AHFP zone forecast in evaporites it is necessary to accurately delineate the boundaries of salt plugs. Zilberman et al. (2000) proposed to utilize the thickness of sediments synchronous with the formation of the salt overhang as a reference thickness. The vertical cross-section of a salt plug resembles a mushroom. A salt plug has (1) a 'stem', formed due to piercing the overlying sediments along the faults by Devonian salt, and (2) a 'cap' comprising the overhanging fragments that remain after regional and local erosion events. Salt plug overhangs are indications of synchronous evolution of the salt bodies and of the sediment cover portion subsequent to the salt break-through (Fig. 9-3). In the Dnepr-Don Basin, for instance, after the first portions of the Devonian salt reached the surface or the seafloor during the Carboniferous, they were destroyed. Some traces of the event are preserved, in the form of peculiar sediments composed of the Devonian clastic and igneous rock fragments called deluvial talus. This talus indicates that the salt was dissolving faster than it was fed through the salt-supplying channel (the stem). The process continued through early Permian time when the volume of salt deposits in the sedimentary basin increased. This resulted in the prevalence of salt supply compared to its destruction. Salt overhangs began to form around the salt stems. As the distance to the stem increases, the overhangs lie over younger Lower Permian sediments and gradually pinch out. After a regional erosion, the Upper Permian sediments overlie the Lower Permian deposits with the included upper portions of the salt plugs. Thus, the sediments from the Svyatogor Rhythm through the base of the Lower Permian accumulated simultaneously with the overhang development. The thickness of this interval is assumed to indicate a standard of the maximum overhang thickness (Fig. 9-3). The location where the salt thickness is greater than the standard one is the salt plug proper. Seismic surveys delineate the areal extent of the plug and several vertical cross-sections. Thus, one can identify points (locations) with the standard thickness. The required outline is obtained by connecting these points (Zilberman et al., 1971). Applications of this technique in the DDB gave favorable results for a preliminary and operational AHFP forecast.
QUANTITATIVE AHFP F O R E C A S T
Analysis of the thickness of the indicator sequences and of sediments synchronous with the salt overhang development provides a way to derive a qualitative reservoir pressure distribution and an areal outline of the AHFP zones. This, however, is insufficient to prevent dangerous pressure surges (kicks) while drilling. What is needed is to determine dangerous intervals in the section as well as the magnitude of expected overpressures. As an example, overpressured gas accumulations in the Bakhmut evaporite series of the DDB are associated with clastic and carbonate components of the rhythms. Such gas accumulations are most common in the Podbryantsev Formation. The quantitative AHFP forecast in the evaporite sealing sequences is best analyzed using pore pressure in the reservoirs sealed by these sequences.
218
V.I. ZILBERMAN, V.A. SEREBRYAKOV, M.V. GORFUNKEL, G.V. CHILINGAR AND J.O. ROBERTSON JR.
Vertical gas migration has played a leading role in the formation of overpressured gas accumulations (secondary traps) in the evaporite seals. The recognition of this fact is a starting point of the AHFP quantitative forecast. A substantiation of this theory is found in the large DDB fields with massive gas-condensate accumulations of significant vertical extent. The following zones may be identified between GWC and the top of the accumulation: (1) zone of overpressure (pressure greater than the hydrostatic) caused by the height of the accumulation and the density difference between the reservoir water and gas; (2) zone of overpressure; (3) zone of normal hydrostatic pressure. These three zones are respectively associated with the sub-salt, salt and post-salt deposits (Fig. 9-5). Thus, in Fig. 9-5, Px -- (P + q Ah), where P x - - AHFP in the evaporite sealing sequence at point x (Zone II), p -- initial gas pressure in the massive gas reservoir (Zone I), Ah = depth difference between the gas-water contact (GWC) of the reservoir and point x, and q - initial reservoir pressure gradient in massive accumulation (Zone I). The pressure in Zones I and III (Fig. 9-5) increases with depth due to the weight of reservoir fluid column (gas or water). There is no regularity in the overpressure changes within Zone II. Apparently, high-pressure gas accumulations in the sealing sequence (secondary traps, Zone II) have been derived from the massive accumulations of the lower zone (Zone I), as a result of vertical gas migration. They could not have formed independently from the massive accumulation located underneath, or simultaneously with it. During the vertical gas migration, the major reservoir trap (Zone I) is filled up first. Then, the gas breaks through (probably along faults) into the sealing sequence filling up secondary reservoir traps (lenses) in the sealing evaporites (Zone II) along the way. Some evidences of vertical gas migration include the following. (1) Association of the AHFP with fault zones, especially those adjacent to the salt plugs and to the areas above the crests of massive accumulations. (2) Almost identical gas composition in the massive accumulations (Zone I, Fig. 9-5) and in the accompanying secondary traps in the sealing evaporite sequences (Zone II, Fig. 9-5). (3) Association of the AHFP with local, isolated reservoirs with no reservoir water. (4) Absence of any data suggesting that hydrocarbon generation occurred in situ within the evaporite sequence. (5) The deepest penetration of gas into the sealing evaporite sequence occurs over the highest portions of the anticlines, where the height of massive accumulations and, hence, reservoir pressure are maximum. Thus, thick massive accumulations have caused surplus gas pressure in the lower zone (Zone l, Fig. 9-5) and the gas penetration into the overlying low-permeability rocks (Zone II, Fig. 9-5). In the sealing evaporite sequences (Zone II), the overpressured gas accumulations occur in the fractured (due to tectonic movements) and/or cavernous zones, and in the sand lenses. The evaporite sequence occupies an intermediate position in the aforementioned vertical zonation. It serves as a transition between the overpressures and the normal hydrostatic pressure. Thus, the pressure in that sequence is within a range whose upper limit is set by the pressure at the top of the massive accumulations (Zone I), whereas the lower limit is determined by the hydrostatic pressure at the base of the upper zone (Zone IID.
219
PREDICTION OF ABNORMALLY HIGH PRESSURES IN PETROLIFEROUS SALT-BEARING SECTIONS
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Fig. 9-5. A conceptual diagram showing the quantitative AHFP forecast in the sealing sequence from pressure in the massive accumulation. (Modified after Zilberman et al., 2000, fig. 5, p. 26.)
Pressure loss in the middle zone may have been caused by the resistance of rocks to gas movement in a heterogeneous, low-permeability medium (according the laws of gas effusion and diffusion: Darcy's, Fick's, Henry's and Urey's laws). (Also see Gurevich et al., 1993 for detailed analysis of gas migration.) The head loss due to friction 1 will be l h L f = f(1/d)(Vf/2g), where f is friction factor, 1 is length of fracture, d is equivalent diameter of fracture cross-section, g is gravity acceleration, and V is velocity of fluid flow.
220
V.I. ZILBERMAN,V.A. SEREBRYAKOV,M.V. GORFUNKEL, G.V. CHILINGARAND J.O. ROBERTSONJR.
lower in the case of gas migration along faults and fractures. Conductivity of faults and fractures may have increased during the periods of neo-tectonic activity. Thus, the reservoir pressure can be extrapolated from the sub-salt productive formations into the overlying sealing sequences (Fig. 9-5). A model of the massive gas accumulation and local gas accumulations (secondary traps) in the sealing sequences recombines the two into a single reservoir system, where the pressure changes with depth according to the weight of the gas column (Fig. 9-5). This model can be used to forecast AHFE The AHFP prediction technique based on the above model and on the forecast outline as shown in Fig. 9-5 has been used since 1975. Its efficiency was proven in 62 wells drilled through the evaporite sequence in the Melikhov, Medvedov and Krestishchenskoye fields of the DDB (Ukraine). Prior to the application of this technique, serious problems (gas shows, blow-outs and open gushers) arose in these fields. As a result of these complications, three wells did not reach their intended depth and four wells were abandoned for mechanical reasons. In addition to the above-described method, one should keep in mind the findings of Fertl and Chilingarian (1987) that in predicting overpressures caused by tectonic activity, the following predictive techniques can be used in the presence of shales: (1) increase in the resistivity of shales on approaching AHFP; (2) decrease in the acoustic interval transit time (Us ft -1 ) in shales; (3) increase in the bulk density of shales; and (4) decrease in the pulsed neutron capture cross-section of shales, etc. The reverse is true in the case of undercompacted shales in thick sand-shale sequences.
CONCLUSIONS
In the case of AHFPs in the evaporite sequences, it is necessary to: (1) prepare a good salt-plug outline at an early exploration stage; (2) outline the AHFP zones; (3) avoid drilling expensive wells outside the GWC; (4) determine the boundaries between the salt bodies and the hydrocarbon accumulations and delineate AHFP zones using computer models; (5) quantitatively determine AHFPs; (6) study the resistivity and density of associated shales (Fertl and Chilingarian, 1989).
BIBLIOGRAPHY Anikiyev, K.A., 1971. Forecast of Abnormally High Reservoir Pressure and Improvement of Oil and Gas Drilling. Nedra, Leningrad, 167 pp. Dobrynin, V.M. and Serebryakov, V.A., 1989. Geological and Geophysical Techniques of Forecasting Abnormally High Reservoir Pressure. Nedra, Moscow, 287 pp. Durmishyan, A.G., 1973. On syngenetic and epigenetic nature of abnormally high reservoir pressure (AHRP) in the subsurface. Neftegazov. Geol. Geofiz., 3: 50-53.
PREDICTION OF ABNORMALLYHIGH PRESSURES IN PETROLIFEROUSSALT-BEARINGSECTIONS
221
Fertl, W. and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1: 23-28. Fertl, W.H. and Chilingarian, G.V., 1989. Prediction of tectonically-caused overpressures by using resistivity and density measurements of associated shales. J. Pet. Sci. Eng., 3: 203-208. Gurevich, A.E., Endres, B.L., Robertson Jr., S.D. and Chilingar, G.V., 1993. Gas migration from oil and gas fields and associated hazards. J. Pet. Sci. Eng., 9: 223-238. Kushnirov, I.V. and Pashkovsky, V.N. et al., 1972. Brine show forecast in the Bukhara-Khiva region. In: Geology of Oil and Gas Fields of the Western and Southern Uzbekistan, Tashkent, pp. 118-132. Melik-Pashayev, V.S., 1973. On the nature of abnormally high reservoir pressure in the Jurassic of the Salim Field. Geol. Nefti Gaza, 7: 25-28. Meshcheryakov, Yu.L., Romanovsky, Yu.E. et al., 1966. Gas-occurrence fine-tuning in the Philippov Horizon, Orenburg Swell. In: Geology and Exploration of Gas and Condensate Fields. VNIIE Gazprom, Moscow, 9: 39-42. Polutranko, A.J., 1998. Causes of formation and distribution of abnormally-high formation pressure in petroleum basins of the Ukraine. In: B.E. Law, G.E Ulmishek and V.I. Slavin (Eds.), Abnormal Pressures in Hydrocarbon Environments. Am. Assoc. Pet. Geol., Mem. 70:240 pp. Zilberman, V.I., 1972. Indications of the approach to horizons with abnormally high reservoir pressure while drilling. Neft. Khoz., 6: 12-14. Zilberman, V.I. and Chernyakov, A.M., 1979. A Technique of Delineating the AHRP Zones. USSR Patent 697698, International Class E21 B43/114. Zilberman, V.I. and Chernyakov, A.M., 1981. Forecasting and outlining AHRP zones in thick evaporite sediments at the design and drilling stage. In: Drilling of Gas and Offshore Oil Wells. VNIIE Gazprom, Moscow, 5: 1-10. Zilberman, V.I. and Zilberman, L.V., 1978. A quantitative AHRP forecast within the gas invasion outline in the Melikhov Field. Geol. Nefti Gaza, 9: 69-73. Zilberman, V.I., Chervanev, I.G., Chernyakov, A.M. and Ulyanov, M.G., 1971. A Technique of Delineating the Salt Plugs. USSR Patent 872744, International Class E21 B40/00. Zilberman, V.I., Serebryakov, V.A., Gorfunkel, M.V. and Chilingar, G.V., 2000. Prediction of abnormallyhigh formation pressures (AHFP) in petroliferous salt-bearing sections. J. Pet. Sci. Eng., 29(1): 1727.
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223
Chapter 10
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
H.H. RIEKE, G.V. CHILINGARand J.O. ROBERTSONJR.
INTRODUCTION Much has been written in the petroleum geology literature on the geochemical evolution of pore liquids and gases associated with fluid flow systems in recent and ancient sedimentary basins. The dialogues include observations about the origin of interstitial fluids, measurements of the active chemical diagenetic processes, and resulting mass-transport properties, which arise during the development of sedimentary basins. Effects of thermal and chemical factors and the dynamic transfer of fluids within the basins leave imprints on the pore-fluid chemistry and generation of abnormally high (AHFP) or abnormally low formation pressures (ALFP). It is the purpose of this chapter to present and validate a hypothetical model that explains the differences between the salinities of pore water in sandstones and shales in the gravitationally compacted sedimentary basins of Tertiary age. The explanation presented here is based on two diverse, relative scales of r e s o l u t i o n - microscopic (10 -2 to 10 -4 m) and gigascopic (> 105 m). The gigascopic scale presents evidence from field observations, whereas the microscopic scale focuses on laboratory experiments that dealt with the chemistry of fluids in the pore space. Mathematical and conceptual models are presented and discussed, which support these observations. Additionally, the relevance of the isotopic character of shale pore water is evaluated for this environment. The all-inclusive premise is that the pore-water salinities in shales are lower than those in associated sandstones in compacting sedimentary basins. A corollary to our premise is that the salinities of solutions 'squeezed out' during compaction are a function of the overburden pressure, temperature, and rate of compaction. The salinities of solutions expelled out of pelitic sediments decrease with increasing depth in young basins having a high sedimentation rate and, therefore, a high sediment compaction rate. In basins with low sedimentation rates, the compaction rates are low and the pore-water salinities increase with increasing depth. AHFP zones are normally absent in these basins. A majority of previous investigations focused on placing the observed single-phase fluid flow systems and their geological outcomes into four general categories: after sedimentation, during burial, during tectonic deformation, and during uplift and erosion. These four categories define the accepted, customary steps in sedimentary basin filling and evolution. The following references on pore-fluid chemistry and fluid flow provide a background to the above four categories. Goldberg et al. (1971), Manheim (1976), Sayles (1979), and Gieskes et al. (1990) presented chemical analysis of sea, bottom, and pore waters
224
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
after sedimentation. Kryukov and Zhuchkova (1963) and Sayles and Manheim (1975) reported on the chemistry of fluids during burial. Ancillary experimental compaction studies of peat and the mobilization of major inorganic ions were reported by Bailey et al. (2000) on three different naturally occurring peats, i.e., Cladium, Rhizophora, and Cyrilla. Berry (1959, 1973), Stephenson et al. (1994), Kouznetsov et al. (1994), Chilingar et al. (1996), and Khilyuk et al. (2000) relate pore-fluid chemistry and the movement of fluids to tectonic activity. Cannon and Craze (1938) stated that uplift and erosion are not the probable causes of abnormally high pressures in the U.S. Gulf Coast Basin. Rowaik (1975), Magara (1978), and Luo and Vasseur (1995), however, pointed out that uplift and erosion are important factors in the evolution of pore pressures in such environments. Subnormal pressures can be created by uplift and erosion through the reduction of temperature, which causes shrinkage of the fluids and porosity rebound. This can create a differential pressure in the overall hydrodynamics of the uplifted sediments. Dobrynin and Serebryakov (1989) attributed the occurrence of abnormally low pressures located in the Nepsko-Botuobin anticline in eastern Siberia to changes in the surface temperatures of the Earth during geologic times. There are three commonly accepted practical classifications of pore waters based on their chemistry and the geochemical interpretation of the results: 9 Palmer (1911) m American 9 Sulin (1946) m Russian 9 Schoeller (1955) m French Collins (1975) gave an excellent review of the water analysis procedures and resulting interpretations from the above classification schemes for the Gulf Coast and mid-continent reservoir pore waters. The present-day understanding on how these pore waters originate, what affects their chemical compositions, and how fluids migrate are presented and debated in this chapter. Arguments and perspectives, both pro and con, are presented to facilitate examining the role of pore-water chemistry in excessive-pressured zones.
OVERVIEW AND CONSTRAINTS
The chemical composition of pore waters in abnormally high pressure zones in sedimentary basins often differs from the composition of the pore waters in associated normally pressured formations. This is especially true for subsiding immature Tertiary and young Quaternary sedimentary basins with high sedimentation rates and thick shale components. Chilingarian et al. (1994) pointed out that overburden pressures on sediments in these basins may reach as high as 45,000 psi (about 300 MPa). This results in a strong driving force for the migration of excess pore waters during gravitational compaction when large amounts of interstitial water are squeezed out of argillaceous sediments and are expelled into the associated permeable beds. Since the mid-1950s, there has been a steady progress toward comprehending how subsurface pore fluids have evolved under gravitational compaction conditions, and the differences in pore-water chemistry between normally compacted and under-compacted sediments.
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
225
The theories explaining the cause of these high-pressure zones were discussed in the previous chapters and among others by Chilingarian and Rieke (1976). A symposium convened at the University of Kansas presented a broad summary on the geochemistry of subsurface brines and their evolution in geologically mature sedimentary basins (Angino and Billings, 1969). In 1990, an interdisciplinary conference was held in England that reported on and reviewed microscopic-scale interactions of aqueous pore fluids with clay minerals in surface and subsurface environments and contains valuable ancillary information on the compaction chemistry of pore water (Manning et al., 1993). The proceedings focused on the mineralogical reactions that take place, such as authigenic formation of clay minerals, diagenesis of mudrocks in the North Sea, diagenetic pore-fluid evolution, and the importance of chemistry of pore fluids to the petroleum engineering and geological concerns with the mechanisms of overpressuring. Hobson (1954) presented the macroscopic concept of fluid pressure systems to be either open or closed in explaining the origin of abnormal formation pressures. He proposed that an idealized closed system is one in which fluid pressures do not dissipate readily over geologic time, whereas in an open system excess pore pressures decrease with time. This concept can be extended to include the geochemical fluid reactions within such pressure system models. To be academically precise, however, a subsurface fluid system should be categorized from a thermodynamic viewpoint.
Thermodynamic and reaction models A synopsis of thermodynamic models is in order so that laboratory experimental and field results can be properly interpreted. The thermodynamic approach includes the fluid system's state variables such as pressure, volume and temperature, its time-dependency processes, and physical boundaries of the system. All these factors must be considered with respect to geologic time and space. A brief discussion is presented here on the validity of applying this concept. Subsurface fluid flow systems can be described using the following thermodynamic models. An open system is defined as one that allows the free flow of both mass and energy across its boundaries, whereas a closed system allows only the outflow of energy but not the mass. An isolated system would exhibit neither flow of mass nor energy from its boundaries. The adiabatic fluid system by definition is closed to mass flow but open to the flow of energy except for heat (there is no exchange of heat with the adjacent bounding systems). Under this classification, a leaky fluid flow system is an open system that only allows a very slow release of mass and energy across its boundaries over geologic time. The state of these systems depends on the type of system and the time dependency of the diagenetic processes. The writers realize that with geologic time all closed and isolated systems will eventually leak. Giles (1997) posed the following question. Is the application of thermodynamic classification with respect to diagenesis pointless? His argument is that all burial systems leak and consequently do not restrain the pore water and their total dissolved solids. Diffusion will drive mass transfer of ions across the boundary of a 'closed system'. His point raises several issues. At what scale is one going to examine the reaction chemistry of pore waters? Scaling is very important with respect to the level of
226
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
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discussion about mechanisms taking place. Fig. 10-1 presents a schematic of the scaling phenomena as applied to a sedimentary environment. How long does it take for an over-pressured system to dissipate? What are some of the other phenomena impacting the chemistry of pore waters and do they mask the whole fundamental process of migration and retention by gravitational compaction? Giles (1997) is certainly correct in stating that certain conditions will open avenues of migration for some of the components and not to others, depending on the conditions within the sedimentary system. Buryakovsky et al. (1994) discussed the relation of the abnormally high formation pressures in the South Caspian Basin to undercompaction of the very thick (up to 25 kin) accumulation of Quaternary-Pliocene sediments and the retardation of the smectite to illite conversion process in shales at depths down to 6 km. The origin of abnormally high pressure in argillaceous sequences is often attributed to smectite dehydration as it is altered to illite. Field data from the Baku Archipelago shale sequence, however, show that smectite remains practically unaltered down to a depth of 6 km. Also in Azerbaijan, the undercompacted character of the Cenozoic shales implies that their sealing properties are determined mainly by their abnormally high formation
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
227
pressures and the compaction process is still continuing to squeeze out pore water (Buryakovsky et al., 1994). All of the South Caspian Basin field evidence indicates that at the present time, pressure systems are not actively leaking or open. Factors opposing the withdrawal of fluids from the interlayer space of clays in these sediments is probably slowing down or halting the smectite transformation into mixed-layer and illitic clays. In conjunction with the low heat flow and low formation temperatures (105-110~ at 6 km), the compaction process is retarded and these factors contribute to the maintenance of isolated fluid system. For an isolated system, equilibrium must exist between the pore-fluid constituents and the surrounding minerals. If the system is geologically leaky, then the chemical equilibrium will change with time. Thus a thermodynamic viewpoint is sufficient in explaining the large-scale phenomena. The emphasis of discussion in this chapter is primarily on the expulsion chemistry of pore water by compaction. Ancillary processes are briefly discussed, if they have an effect on the pore-water chemistry. The main thrust of discussion is to clarify and substantiate what could be important to petroleum exploration and recovery operations. Key component to such an understanding is the integration of available laboratory-simulated compaction data with field measured data and modified as evidenced by structural and thermodynamic imprints. Evolution of seawater into pore water
Sedimentary basins on the average contain about 20% pore water by volume. This pore water at depth is hot and saline, and frequently occurs under high pressures. Some low-salinity waters, however, are often associated with abnormally high fluid pressure zones. It must be pointed out that interstitial waters are mobile and are the agents by which chemical constituents are transferred from one place to another. Most of the dissolved constituents present in the waters trapped during sedimentation are squeezed out during the initial stages of compaction. It is of interest to briefly review the historical development time line of the theories of subsurface fluid origins. Washburne (1914) thought that the pore water contained in sediments is not just buried seawater, but subsequent studies have shown that pore waters in marine Tertiary sediments are essentially remnants of seawater entrapped with the sediments during deposition (Chave, 1960; Manheim, 1976; Sayles, 1979). Degens et al. (1964) analyzed the oxygen isotope composition of a number of pore waters ranging in geologic age from the Cambrian to the Tertiary, and reported that the ~180 values of the highly saline oilfield brines do not deviate appreciably from the 3180 values of present-day seawater. Later studies by Sayles and Manheim (1975) have shown that in all but the most slowly deposited sediments, pore water exhibits changes in its composition during burial. The rate at which pore water is expelled from argillaceous sediments depends not only on the overburden pressure and the physical and chemical properties of the contained fluids, but also on the texture, structure, and mineral composition of the sediments. Table 10-1 shows chemical changes of pore water held in marine sediments with respect to the rate of sedimentation and depth of burial. Results from the Deep Sea Drilling Project showed that biogenic sediments and pelagic clays undergoing a rate of
228
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.
TABLE 10-1 Chemical composition of seawater, bottom water, and average concentrations of pore water squeezed out from ocean sediments expressed in g/kg Ions
Seawater Normal
Na + K+ Ca 2+ Mg 2+ C1SO 2HCO 3
10.5 0.4 0.4 1.3 19.1 2.7 0.17
Ocean sediments Red Sea
11.8 0.43 0.46 1.42 21.4 3.06 0.15
Terrigenous clay
Pelagic clay
Hemipelagic
Red Sea
(>3 cm/10 yr)
(< 1 cm/10 yr)
bottom water
burial depth 223-243 m
marl, burial depth 82 m
10.80 0.30 0.40 1.08 19.4 1.05 0.45
10.80 0.38 0.42 1.25 19.5 2.45 0.20
10.8 0.38 0.41 1.26 19.2 2.7 -
11.1 0.52 0.41 1.18 19.5 2.7 -
28.7 0.22 0.98 0.84 46.1 3.57 0.15
Data for normal seawater from Goldberg et al. (1971); all other data modified after Manheim (1976). In Chilingarian et al., 1994, table 5-1, p. 108.
deposition at < 1 cm/1000 years were the only sediments which exhibited low chemical reactions with the contained pore waters. At shallow burial depths there is not much change in the pore-water chemistry except when influenced by underlying salt beds. An example of salt bed influences is illustrated by the chemical composition of the pore water extracted from Red Sea marl (Table 10-1). One way of visualizing the changes in pore-water chemistry is presented in Fig. 10-2. This lumped-parameter analysis illustrates the change in chemistry of oilfield waters with depth in eight sedimentary basins representing ten different formations. Similar types of pore-water patterns were shown by Hanor (1987a), using data from Graf et al. (1966) for the Paleozoic Illinois Basin (U.S.A.). Pore-fluid diagenesis is the term that was used to denote these changes. Sayles and Manheim (1975) stated that reactions undetectable in the solid components have a large and readily measurable effect upon the pore waters. The geodynamic aspect of the origin of sedimentary basins has a direct influence on the diagenetic changes that pore waters undergo after deposition. Sedimentary basins develop in different tectonic settings as shown in Fig. 10-3. The mechanisms involved in their formation are probably as poorly understood as the diagenesis of their pore fluids. The writers use this basin classification system to tag each basin and field example given in this chapter. Contradictions in the geochemical pore-water data from various basins can be explained by the basin's type and its degree of geologic maturity. In this chapter, the term delta basin is used to describe those Tertiary to Recent young depositional sites where present-day deposition is still taking place. A good example in the United States is the Mississippi delta basin, which is adjacent to, and is considered a part of, the Gulf Coast crustal collision zone-closed convergent plate margin age basin. These basins can be described as being immature and forming along the continental margins, versus those mature basins which are geologically older and now exist directly
229
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Reliability of water sampling Most petroleum geologists and engineers have ignored the properties of pore fluids associated with the less permeable shales in compacting basins. One reason for this oversight is that the shale permeabilities are so low that the exposed shale intervals in oil wells rarely produced pore water in measurable quantities. Another reason is that such studies always had a low priority until the later 1960s when abnormally high fluid pressures were intensely investigated by the petroleum industry. The water produced
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232
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
from oil and gas wells is p r o b a b l y not representative of the interstitial water owing to contamination, dilution by c o n d e n s e d water vapor, q u e s t i o n a b l e fluid sampling, preservation, and laboratory analytical procedures. Water p r o d u c e d with the oil can represent a mixture from different production horizons in the case of c o m m i n g l e d production or as a result of poor c e m e n t job or leaky casings. During the c e m e n t i n g of casing into place in a well, the filtrate f r o m the c e m e n t slurry can p e n e t r a t e the p e r m e a b l e sandy zones and c o n t a m i n a t e the pore water. H y d r a u l i c fracturing fluids can also c o n t a m i n a t e reservoir waters. In some cases it takes m o r e than three m o n t h s for the fracturing fluids to be p r o d u c e d back after fracture stimulation treatment. It is prudent to view with caution pore-water c h e m i s t r y results r e p o r t e d in the literature that are based entirely on p r o d u c e d water sampled at the wellhead. T h e s e are just some o f the p r o b l e m s e n c o u n t e r e d by investigators looking at p o r e - w a t e r chemistry. With respect to u n c o n s o l i d a t e d s e d i m e n t samples, the handling of the samples can be critical in obtaining accurate analytical results. Problems include changes in t e m p e r a t u r e and pressure, c o n t a m i n a t i o n by b o t t o m water and seawater as the cores are retrieved. F u r t h e r changes can take place owing to evaporation, oxidation, and the type of e q u i p m e n t and supplies used in extracting and storing the sample, and the m a g n i t u d e of the pressure at which the pore water is s q u e e z e d out of the s e d i m e n t sample. M a n g e l s d o r f et al. (1969) first d e m o n s t r a t e d that t e m p e r a t u r e changes alter i o n - e x c h a n g e equilibria and bring about changes in p o r e - w a t e r chemistry. Bischoff et al.
Fig. 10-3. It is important to have a sense for the relationships among pore-water chemistry, petroleum basin types and the origin of the abnormal fluid pressures. Klemme's (1984) petroleum basin classification with cross-sections showing idealized basin profiles, basin parameters, stratigraphy and structures are used to proffer some generalizations about what kind of water chemistry might occur in these basin types. Basin examples given for Kiemme's (1984) basin types are the following. Basin Type I (U.S./Canada Williston) has abnormal pressures due to hydrocarbon generation rather than compaction. Basin flushing by water has influenced the water chemistry. Basin Type IIA (U.S. Wind River) has basin-centered abnormal fluid pressure zones. Well-logs show that resistivity increases in the more thermally mature rocks. Water chemistry is modified by coalbeds and artesian flow into the basin. Most of these reservoirs in this type of basin are gas and have water-free production. Basin Type IIC (U.S. Gulf Coast) and IV (Mississippi Delta) exhibit compaction water chemistry associated with regressive sedimentary sequences, growth faults, mud volcanoes, and smectite to illite clay mineral transformation. Rift basins offer a more complex picture. Basin Type IliA (North Sea Viking Graben) basins illustrate that two distinct abnormal pressure zones can exist. One pressure zone is above another below the characteristic (unconformity/disconformity) zone which tends to occur in this type of basin. The abnormal pressure zones are basin-centered making the water chemistry profile complex. Type IIIB (South Sumatra, U.S. Ventura, Maracaibo) basins have a broad range of imposed stress conditions that commingle the effects of local and major tectonic forces and gravitational compaction on the water chemistry. Usually the water chemistry shows a salinity decrease with depth but can change areally and vertically over the section and in individual structures. Basin Type IIIC (Australia's North West Shelf) having abnormal formation pressures which depend upon the rate and type of sedimentation. Water chemistry is a mixed bag. Basin Type IV are forearc basins (Sacramento, U.S.) which has a mixed history, of tectonism, compaction and basin flushing. Major deviations from compaction water chemistry expectations can be attributed to dehydration in the change from gypsum to anhydrite in evaporitic sequences, coalification, and lack of argillaceous sediments. (After Klemme, 1983, fig. 3, p. 170; reprinted with the permission of the Oil and Gas Journal.)
PORE WATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES
233
TABLE 10-2 An overview of proposed mechanisms to account for the origin of chemical differences in subsurface pore waters (after Chilingarian et al., 1994, table 5-2, p. 111) Reference
Mechanism(s)
Washburne (1914) Richardson (1917) White (1957) Berry (1959) Chave (1960) Von Engelhardt and Gaida (1963) Bredehoeft et al. (1963) Powers (1967) Serruya et al. (1967) Mangelsdorf et al. (1969) Hitchon et al. (1971)
Subsurface evaporation and juvenile water additions. Leaching of disseminated salt and salt diffusion from salt bed. Burial diagenesis of seawater. Chemical osmosis. Trapped remnants of seawater moved by sediment compaction. Ion exchange capacity of clays under compaction. Membrane filtration by clays. Alteration of smectite to illite during deep burial. Electrical potentials (electrodiagenesis). Molecular settling. Trapped pore water diluted by fresh water recharge and concentration by clay membrane filtration. Interaction between sediments and water contained in their pore spaces. Infiltration of subaerial brine. Salt related brines diluted by mixing with seawater. Thermohaline overturn of pore water.
Sayles and Manheim (1975) Carpenter (1978) Stoessell and Moore (1983) Hanor (1987b)
(1970) confirmed these effects. Sayles and Manheim (1975) stated that temperature is the most single significant factor affecting the composition of pore waters. With respect to laboratory-simulated compaction studies, problems arise from (1) the magnitude of pressure used to squeeze out the pore water (chemistry of water changes with pressure), (2) analytical techniques involving minute amounts of squeezed-out pore waters, (3) specimen preparation, and (4) contamination involved in collecting the pore water. Palmer and Sulin water classifications A concise discussion of Palmer and Sulin's water classification methodologies is in order so the reader can quickly comprehend the meaning, formulate relationships, and categorize subsurface water chemistry results based on these classification schemes. Both schemes could be useful in making comparisons with published subsurface water analysis data. The foundation for such analytical schemes is the composition of the seawater system, i.e., contents of (Na +, K +, Ca 2+, Mg 2+, CI-, SO 2-, and CO 2-) in H20. Schoeller's system for the most part addresses petroleum-reservoir waters and the reader is referred to Schoeller (1955) and Collins (1975) for details. Palmer's classification Palmer (1911) devised his water classification system based on the chemical salinity (salts of strong acids) and alkalinity (salts of weak acids). Briefly, the concept of the chemical salinity is that all cations (positive ions) and certain anions (negative ions), such as chloride, sulfate, and nitrate, can cause salinity. Alkalinity depends on the
234
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
free alkaline bases, which is a result of the hydrolytic action of water on dissolved weak acid salts. Dissolved ions in water are divided into three groups: (1) soluble alkalies (sodium, potassium, lithium); (2) meagerly soluble alkaline earths (magnesium, calcium, strontium, barium); and (3) hydrogen, whose salts are acids and cause acidity (Collins, 1975). Palmer's classification system uses the sum of the reacting values (capacity for reaction) of the individual ionic species in each group to define five classes based on five special properties of water. Reacting values are calculated in percent by summing the milliequivalents of all the ions, then dividing the mequiv of a given ion by the sum of the total mequiv and multiplying by 100. The predominance of reacting values in each group is the basis for the special properties, which are: 9 Primary salinity (alkali salinity), which does not exceed twice the sum of the reacting values of the alkali radicals. 9 Secondary salinity (permanent hardness) is defined as the excess of any salinity over primary salinity and does not exceed twice the sum of the reacting values of the alkaline earth group radicals. 9 Tertiary salinity (acidity) is any excess of salinity over primary and secondary salinity. 9 Primary alkalinity (permanent alkalinity) is any excess of twice the sum of the reacting values of the alkalies over salinity. 9 Secondary alkalinity (permanent alkalinity) is the excess of twice the sum of the reacting values of the alkaline earth group radicals over secondary salinity. The Palmer classification system has some shortcomings, such as the grouping of some of the constituents together that are not closely related chemically, and it does not consider ionic concentrations of saturation conditions related to sulfate or bicarbonate. (For additional details see Collins, 1975.)
Sulin's classification Sulin (1946) devised a classification system based upon various combinations of dissolved salts in water and tied it to the environmental origin of the water. The sulfatesodium water groups are indicative of terrestrial conditions, bicarbonate-sodium water groups represent continental conditions, chloride-magnesium water groups form under marine conditions, and the chloride-calcium groups are related to deep subsurface conditions. The water classification scheme of Sulin consists of: (1) genetic water types established by value of the Na/CI ratio; (2) chemical types using values of the ratios of (Na-C1)/SO4 and (CI-Na)/Mg; (3) groups subdivided based on Palmer's characteristics as determined by the classes; (4) classes depending on Palmer's salinity or alkalinity values; and (5) subgroups established using the Ca/Mg and SO4/C1 ratios. Sulin considered sodium as the sum of Na, Li, K ions, and chlorides as the sum of C1, Br, and I. The classification system is completed by determining the sum of the milligram equivalents per 100 g of water (indicator of water mineralization). The Sulin's class subdivision scheme employs the distinction of whether or not sodium bicarbonate is present. In the sulfate-sodium, chloride-magnesium, and chloride-calcium water types there is no sodium bicarbonate present.
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
235
(1) Bicarbonate-sodium type (a) Class At: primary alkalinity predominates (alkali carbonates and bicarbonates). (b) Class A2: secondary alkalinity predominates (alkaline earth carbonates and bicarbonates). (c) Class St: primary salinity predominates (alkali chlorides and sulfates). (2) Sulfate-sodium, chloride-magnesium, and chloride-calcium types (a) Class A2: secondary alkalinity predominates (alkaline earth carbonates and bicarbonates). (b) Class St: primary salinity predominates (alkali sulfates and chlorides). (c) Class $2: secondary salinity predominates (alkaline earth sulfates and chlorides).
C H E M I C A L C O M P O S I T I O N OF S U B S U R F A C E B R I N E S
Petroleum engineers, geochemists, hydrologists, well-log analysts, sedimentologists, and water chemists all have an interest in classifying water based on its chemical composition, physical properties, origin, or association with diagenetic processes. Collins (1975) discussed his compilation of chemical and physical analysis of oilfield brines occurring in various formations and producing oil and gas reservoirs in the U.S. Geochemists such as Ortoleva (1994), Bethke (1996) and Giles (1997) approach the problem by employing different strategies. Ortoleva looked at the geochemical self-organization in overpressuring and compartmentalization in sediments. Giles focused on the resolution of geochemistry theory with basin modeling aspects. Bethke's methodology is concerned with the analyses of open and closed fluid systems using computational geochemical reaction modeling. His reaction model considers the transfer of mass and heat in and out of a system having an aqueous fluid and one or more minerals, and can accommodate a buffer (an external gas reservoir) in order to calculate the system's equilibrium state. The reaction path is determined by the course the equilibrium state takes as it responds to changes in composition and temperature. Changes in the equilibrium system are audited, thereby monitoring the reactants (minerals and fluids) influence on the system composition. How does this fit in with the present research trend on the fluid chemistry relationships in compacting pelitic sediments? Hunt et al. (1998) believe that the cessation of compaction does not appear to be related to overpressuring, but is a phenomenon that occurs with hydrostatic-pressured shales. This means that the two-stage, linear compaction is a normal compaction trend (see section on Field Case Studies). At depths where compaction no longer occurs, gas generation seems to be the major cause of overpressures. Now we have all the reaction modeling ingredients (seawater, smectite, smectite/illite mixed interlayer clays, and illite, and a gas reservoir) needed to explore Hunts et al.'s premise, and to see if their model matches field results. This could confirm whether or not the pore waters in shales should be fresher than those in associated sandstones, and confirm the origin of the fresh water in the overpressure zones. The alternative to Hunt et al.'s hypothesis is the study by Burrus (1998) on stress-porosity, using the TEMISPACK finite volume model, showing that compaction disequilibrium is the dominant cause of overpressures.
236
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
Pore waters can be classified based on their origin as (1) syngenetic (formed at the same time as the enclosing rocks), and (2) epigenetic (owing their origin to subsequent infiltration of meteoric and other waters into already formed rocks). The main processes, which alter the chemistry of buried waters, are: (1) physical (gravitational compaction); (2) chemical (reactions involving minerals, organic matter and interstitial solutions); (3) physicochemical (filtration through charged-net clay membranes, adsorption and base exchange); (4) electrochemical; and (5) biochemical. Data provided by Hanor (1981) illustrate that the geochemical properties of fluids being expelled from recently deposited sediments of the Mississippi River delta undergo a compositional change. He attributes these changes to early diagenetic processes of bacterial respiration, mineral precipitation, and possible fractionation due to the presence of clays having high exchange capacity. Changes in the concentration of pore-water fluids during the process of compaction, as reported by different investigators and presented in the following section, are based on field and laboratory data. Conceptual models relating the results to gravitational compaction and the generation of overpressures are also presented. Salinity variations in compacting sandstones and associated shales Much of the available data on the composition of oilfield brines pertains to water from permeable formations and only in a few instances are data on the composition of pore water from associated shale beds are reported in the literature. De Sitter (1947) noted that the salinity of formation waters in sandstones varies from that of fresh water to ten times the salinity of seawater. The distribution of salinity of pore water present in the young geosynclinal sediments (recent deposition in the crustal collision zone-closed convergent plate margin) along the U.S. Gulf Coast is well documented by a number of investigators. Timm and Maricelli (1953, p. 394) stated that high salinities up to 4.5 times that of normal seawater characterize the pore waters in Miocene/Pliocene sediments. Where the relative quantity of shale is large and the degree of compaction is high, pore waters have salinities as low as one-half that of normal seawater. Fig. 10-4 illustrates their concept that the formation waters in downdip, interfingering, marine sandstone members, have lower salinities than that of seawater. These sandstones have proportionately less volume than the associated massive shales. More massive sands updip have salinities greater than that of seawater, because of lack of influx of fresher waters from shales. Myers (1963) studied the chemical properties of formation waters, down to a depth of 12,400 ft (3780 m), in four producing oil wells in Matagorda County, Texas. Salinities of pore waters ranging from 5000 ppm to 12,500 ppm were found below 10,000 ft (3048 m) in each of the four wells, as compared to salinities of about 70,000 ppm above that depth. Myers commented that in the deeper section the proportion of massive shale is large and the sands are near their downdip limits. These results were in close accord with those of Timm and Maricelli (1953). Kharaka et al.'s (1977) study of the geochemistry of geopressured geothermal waters from the Frio Clay in the Texas Gulf Coast indicated that the salinity (total dissolved solids) of water in the geopressured zone ranged from 20,000 to 70,000 mg/1. Water
237
PORE WATERCOMPACTIONCHEMISTRY AS RELATEDTO OVERPRESSURES
Sea Level
,-':.:!~!:-!:i!". ;'!"--':-').':.''.~:."..".~::."::.)).~i...:.
::-'.;.:.::..:.-.'..:: ::...:.;::;:..:.........:.....'..-...:.:.:-:.;...
'.-'-?'-~":..':.. "'"-"';::."-.....
" " #:."::..-"-".'i!i:!'i'~':':.:"-):'."." :.,
oa
9 00
"'-"?'-':-."::. ".';?:~ '~o~
Fig. 10-4. An idealized cross-section of some sands and shales in the offshore subsurface of southwest Louisiana illustrating salinity relationships. (Modified after Timm and Maricelli, 1953, pp. 396, 397 and 408; in Rieke and Chilingarian, 1974, fig. 146, p. 271.)
samples from many gas wells, on the other hand, yield much lower salinities. Kharaka et al. (1977) believed that these samples are not representative of the true formation waters' salinity owing to the dilution of the condensed water produced with the natural gas. Their study shows that the salinity in the geopressured zone is generally, but not always lower, than salinities in the normally pressured zone. Dickey et al. (1972) reported that formation waters from four wells in southwestern Louisiana showed almost normal concentrations of total dissolved solids in the geopressured zone for those depths of burial. The findings of Fowler (1968) suggest that the salinity of water in undercompacted shales in the Chocolate Bayou Field, Brazoria County, Texas, is higher than in the well-compacted ones. A definite correlation between the high salinity of interstitial fluids and abnormally high pressures was found to exist. This is possibly due to the fact that undercompacted shales did not have a chance to contribute their fresher water to the associated sandstones. Fowler (1968) also studied the variation in salinity of produced water with time. The typical pattern is one of decreasing salinity with time, and the freshest water is found in sands receiving most of this water from associated shales. Plummer and Sargent (1931) and Elliott (1953) also studied the variability of pore waters from specific zones in wells taken over a 1- to 48-month time period. They found that there was no definite trend of ion concentration with time. Chave (1960, p. 359) reported that the percentage difference in the concentration of a given ion could vary from less than 1% to as much as 168%. Chave commented that the reasons for the differences between resampling by Plummer and Sargent (1931) and Elliott (1953) were not clear. He suggested that they could represent the natural
238
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
chemical difference of waters in a given local stratigraphic zone or the samples were contaminated. In the opinion of the writers, any chemical analyses of pore waters should be checked by charge balance criteria. The total milliequivalents per liter of cations and anions must be equal to each other within 5 to 10%. In order to perform this check, the analysis must be made for all the major cations and anions present in the sample. Morton and Land (1987a) pointed out that abnormally high pressured Oligocene Frio sandstones in Texas contain waters having salinities ranging from around 8000 to more than 250,000 mg/1 (total dissolved solids). The high values could be due to the dissolution of diapiric salt. Low salinities are attributed to pore-water dilution by water released from the transformation of smectite clay to illite (hydromica), i.e., by mineral dehydration reactions. Manheim and Bischoff (1969) were the first to suggest the increase of pore-water salinity with depth in relationship to diapiric salt structures in the Gulf Coast. Pore waters were analyzed from six boreholes drilled offshore in the Gulf of Mexico. Pore-water samples from the drillholes near diapiric structures showed systematic increases in salinity with depth. The salinity showed little change with depth in those boreholes drilled away from the diapiric structures. Manheim and Bischoff (1969) suggested that salt diffusion from underlying salt structures were the cause of this increase in salinity. The mass transport of highly saline waters in sedimentary basins will have a strong impact on the transport of hydrocarbons, ore fluids, heat, and diagenetically reactive dissolved constituents. Hanor (1987b, 1999) discussed the concept of thermohaline overturns and the resulting mass transfer of pore water in southeastern Louisiana. He proposed that there are three major types of subsurface flow regimes in this area. The uppermost (shallowest) consists of topographically driven, fresh-water systems (ground water). A thermohaline system can exist at an intermediate depth where salt diapirs are present. The deepest zone is the regional overpressured regime. The salinity (total dissolved solids) overprint on the intermediate zone's pore-water chemistry is a direct result of the presence of salt, and the induced fluid circulation is driven in part by fluid density inversions resulting from spatial variations in salinity and temperature. This chemical overprint could be expected to exist in other young basins where salt beds and diapirism are present. Capuano (1990) simply stated that compaction-driven flow dominates in the abnormally high pressured sediments, whereas gravity-driven or thermal-density-driven flow dominates in normally pressured sediments. Field case studies
The importance of knowing that the pore-water concentrations are lower in shales than in associated sandstones was pointed out by Chilingar et al. (1969). Erroneous interpretation of well logs may result if it is assumed that the salinity of pore waters in sandstones and associated shales are the same. In order to determine the water saturation, Sw, in well log analyses, it is necessary to know Rw (resistivity of the pore water in the formation being evaluated). Under favorable conditions, the latter can be determined on using the SP curve. This approach, however, is not practical in many cases owing to the properties of some drilling fluids and other variables that can cause
239
PORE WATERCOMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES 3600
9940
T
o,,
I
9980
l
3800
I
9960
I-Q. IJJ a
(B)
(A)
SHALE
i
" r 4OOO I-Q. IJJ C~
e,,~o,,==,
p,p.m. RANGE IN ":..
SAND
4200
l
to,ooo
i
SAND
I SHALE
10,020 I0
20
4400 30
CHLORINITY, p.lam,x I0 a
40
30
50
70
90
I10
CHLORINITY, Rl~m.,x I0 a
Fig. 10-5. Chlorine ion concentration in shales and sands versus depth. (Modified after Fertl and Timko, 1970, fig. 4, p. 15" based upon data by Hedberg, 1967.)
wellbore contamination. The best method, which has been practiced for many years, is the analysis of formation water collected from a permeable zone or the use of the petroleum industry's compiled water atlases. Once the water salinity is determined in an area, Rw is calculated for any subsurface zone by making only a temperature correction (Arps, 1953). Another approach to find Rw in sandstones involves the use of log-derived values of adjacent shales. It was proposed by Overton and Timko (1969) to plot salinity variations as calculated from the SP curve for abnormal formation pressure detection work. Their simple relationship, so-called salinity principle, between the salinity of clean sands, Cw, and the porosity of adjacent shales, 4~sh,is expressed as C w x (~sh - -
constant
(10-1)
The assumption is that the formation water salinity is in equilibrium between sands and shales and that it will vary inversely with the porosity of adjacent shales. In most instances it is generally accepted that shale porosity decreases with increasing depth, whereas formation water salinity tends to increase with depth. AHFP environments cause divergence from such normal trends. Shale porosity is shown to increase or remains constant in these overpressured zones, which in turn suggests a decrease of constant value in the formation water salinity as calculated by Eq. 10-1. Any decreasing trend in the water salinity as indicated by the SP curve would indicate possible abnormal fluid pressures. Fig. 10-5 is an example illustrating the relationship between shale resistivity values derived from sidewall cores and those obtained from the SP curve in clean sands (Fertl and Timko, 1970). It should be stressed that the shale pore waters are less saline than those in the associated clean sandstones. The validity of Overton and Timko's empirical relationship is questioned based on their assumption that the pore water in shale and clean sand is in chemical equilibrium
240
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
(G.V. Chilingar, personal communication, in Fertl, 1976, p. 190). This is a valid observation by Chilingar as demonstrated by the plot of salinity values for log and laboratory results in Fig. 10-5. Hermanrud et al. (1998, 1999) raised additional doubt by expanding the question to include other well logging data used to establish such trends. They evaluated sonic, resistivity, neutron, and density well-log data from 80 wells on the Norwegian continental shelf in the North Sea to show that there is no clear correlation between the well-log response (abnormally high porosity) and interpreted fluid pressure. They did not find a depth in these wells below which porosity ceases to decrease (overpressure indicator); therefore, undercompaction in these shales associated with the dominating clastic sediments was not demonstrated. In the offshore, Atlantic Haltenbanken area of Norway, however, both the resistivity and sonic logs responded to high fluid pressures present in the Jurassic intra-reservoir shales of the Ror and Not formations. The shales separate reservoir sandstones deposited in deltaic and shallow marine environments. Hermanrud et al. (1998) suggested that the well logging tools were responding to textural changes in the shales or microfracturing rather than elevated porosity induced by the overpressuring of the heterogeneous shales. One can raise the following question, however: was their choice of formation water resistivity and matrix transit time values used for evaluating the 'Not Formation' high-pressure regimes correct? These values were determined using an average porosity for a low-pressure reference well in the Not Formation, rather than using actual chemical measurements. Would there have been a more precise demarcation of the porosity-depth relationship if fluid samples were used? Burrus (1998) noted that the conversion of log measurements in shales into porosity values is not straightforward. Density logs are sensitive to changes in lithology, neutron logs are sensitive to changes in mineralogy, and the sonic logs are not linearly related to porosities. The above brief discussion raises concern about the present trend in the literature to place specific well data from wide areas into a lumped-parameter evaluation plot. Well-log interpretation techniques should be performed in conjunction with water analysis of in-situ formation test fluid samples and from the cores of shales and their associated sandstones. Such analyses should be carried out on a well-by-well basis rather than making the assumption that the hydrochemical facies hold from one well to the other.
Hackberry and Manchester fields, Louisiana, U.S.A. Schmidt (1973) performed an important field case study. He analyzed the pore waters of both shales and sandstones from the Manchester and Hackberry fields in the south Louisiana Gulf Coast Basin by determining the concentration of various cations and anions together with base-exchange capacity, type of exchangeable cations, and mineral composition of the clays. Similar data from sandstones, in the A-5 Farmers Land and Canal well in the Manchester Field, were calculated by Schmidt (1973) using the spontaneous potential (SP) electric log curve. Sandstone salinity values are based on 56 water sample analyses for major cations and anions. The sampling was from normally pressured producing zones in the Hackberry Field, and highly pressured zone in the Manchester Field.
PORE
WATER COMPACTION
CHEMISTRY
AS RELATED
Concentration, 0
0 ' .
'
4 ' I '
8 ' I '
'
~-----10,000 mg/I "'""........
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_
/
/
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.
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.......
R"
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/
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F
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2000
-
3000
-
4000
-
5000
-
6000
-
7000
-
8000
-
9000
o- .... :":::~2~ ~ / ." / :" ~
~ berry SS Field
.,_.
.ff
,
l
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-
-..,n-- H C O ~
Note abrupt change between normally pressured Hackberry sandstone and high pressured Hackberry ( M a n c h e s t e r Field) sandstone
-
l
0,000
-
l
1,000
~
- 12,000
"
'~ 4000
....... CI
1 0 0 0
~ .....
,
~ r
9
...... TDS
o:-.:',,a
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:" ;W ._ 9
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24 l '
. . . . . . .o+
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20 I ....
~
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2000
3000
'
91
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.!
'
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_
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x 10,000
--
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E .ff
mg/I
12 16 ' I ' ' ' I '
....
-
1000
'
241
TO OVERPRESSURES
~'"o.
r~..... :'.':o~Hackberry SS Field
- 13,000 - 14,000
i
11
, Manchester I SS r l l dlel l
1111~1
" " I
I I
I
Fig. 10-6. Changes in concentration of pore waters within sandstones and shale beds in the Hackberry and Manchester fields, Louisiana (U.S.A.). The concentrations of HCO~-, SO]-, Ca2+, Mg2+, and, K+ in sandstones are less than 10,000 mg/1 and are not shown. (This figure is based on data from Schmidt's (1975) tables 1 and 2, pp. 332-337. (Modified after Chilingarian et al., 1994, fig. 5-4, p. 116.) Additionally, sidewall cores from shales in well A-5 were leached and analyzed for major dissolved constituents. Schmidt's study showed that the compositions of pore water in shales and those in sandstones are different. His data on sandstone and shale pore-water chemistry (as given in his tables 1 and 2, respectively), have been plotted as lumped parameters in Fig. 10-6. The data reveal changes in the concentration of pore water with depth in the sandstones and shales. It should be noted that the sandstone pore-water data from the Manchester Field is only for the high-pressure zone, which lies between 11,200 ft (3400 m) and 12,900 ft (3800 m). The data from the shale sidewall cores were taken at intervals of every 500 ft (152 m) between depths of 3000 ft (914 m) and 14,000 ft (4257 m) to include normal- and high-pressure zones in the Manchester Field. There is an abrupt decrease in the concentration of various ions in the high-pressure Manchester Field. Fig. 10-6 illustrates that there is a significant difference between the
242
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
total dissolved solids concentrations in waters from the normally pressured sandstones and the abnormally pressured sandstones in the Hackberry Field. Concentration values range from 600 to 225,000 mg/1 in the normally pressured sandstones and from 16,000 to 49,000 mg/1 in the abnormally high-pressured sandstones. Changes in the concentrations of chloride and sodium follow the same trend as that of the total dissolved solids (C1- > Na+). The concentrations of the HCO 3, SO 2-, Ca 2+, Mg 2+, and K + in interstitial waters in sandstones are so small as compared to the concentration of other major constituents at the scale used in Fig. 10-6, that values less than 10,000 mg/1 are not plotted in the diagram. The salinity of the water in shales is lower than that in the adjacent normally pressured sandstones. The concentrations, however, were found to be more similar in the AHFP zone. It was shown that in shale pore water, the ionic concentration order is generally SO 2- > Na + > HCO 3 > CI-, whereas water in normally pressured sandstones has an opposite concentration order (Fig. 10-6). The concentrations of the Ca 2+, Mg 2+, and K + show very little variations and plot in the band mentioned above. In all cases, the salinities of pore waters in shales were found to be considerably lower than those in associated sandstones. Rieke et al. (1964) were first to point out the difference in salinity between the shale and the associated sandstone (also see Chilingar and Rieke, 1976). Osmaston (1975) in his discussion of Schmidt's (1973) field study pointed out that there are some discrepancies in Schmidt's porosity and density values. The fundamental expression showing the relationship between fractional porosity, 4~, bulk dry weight density, Pa, and grain density, pg (which was assumed to be a constant, 2.65 g/cm 3) is: Pd =
,Og(1 - - q~)
(10-2)
These porosity or density values were used to calculate the concentration of dissolved constituents in the pore water. The constituents were extracted by leaching the sidewall cores of shales. The correction factors suggested by Osmaston (1975), by which the concentration of each constituent needed to be multiplied, ranged from 0.81 to 2.19 with an average of 1.12. Apparently, the average correction factor is too insignificant to alter the main trend of change in Schmidt's concentration of dissolved constituents with depth. It is well known that the technique of extracting the dissolved pore-water constituents is replete with potential problems. Leaching will not only extract the pore-water constituents, but will remove the soluble minerals held as a solid matter in the matrix of the rock. In addition, part of the exchangeable cations, Na +, K +, Ca 2+, and Mg 2+ on the clay minerals may also go into solution. Furthermore, this technique, as reported by Morton and Land (1987b) may produce sodium- calcium-sulfate water entirely unrelated to the in-situ chemistry of pore fluids. This effect is reflected in Fig. 10-6, where it is shown that in contrast to the sandstone data, the concentration of sulfate ions is greater than, or equal to that, of the chloride ions in shales. Chilingarian et al. (1994) discussed the method of calculating the original pore chemistry from the leached extract from Schmidt's shale cores. By assuming that the pores in the shale sidewall core samples are fully occupied by pore water, the void volume is equal to the fluid volume. The leachate volume, which is not necessarily equal
POREWATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES
243
to the original pore-water volume, has to be corrected by using a dilution factor, Df. The dilution factor is equal to the leachate volume, V~, divided by the original pore-water volume, Vp" Df =
1/1 Vp
(10-3)
Inasmuch as Vp - Vbr and Vb -- W/Pd, where Vb is the bulk volume of the shale sample and W is the weight of the dry shale sample, gp -- W q~ /gd
(10-4)
and, therefore" rOd D f - - V1W r
(10-5)
In order to estimate the original concentrations of different dissolved constituents, the respective concentrations in the leachate have to be multiplied by the dilution factor. The equation for converting the leachate concentration into pore-water concentration is given by: Cpw -- C1 N Df
(10-6)
where Cpw is the concentration of a constituent in the pore water and C1 is the concentration of the same constituent in the leachate. By substituting Df from Eq. 10-5, one obtains" Dd Cpw -- C1V1 W e
(10-7)
where 1/1 is the volume of the leachate (which in the case of Schmidt's (1973) research was 50 ml). Equation 10-7 can be rewritten by substituting pg(1 - r for rOd (Eq. 10-2): Cp w _ C1 V1 tOg( 1 - ~))
we
(10-8)
Another criticism of Schmidt's (1973) study is that he did not tabulate the values of porosity or dry bulk density anywhere except in Fig. 10-6. The shale porosity values, determined directly from the density logs of the A-5 well, essentially agree with those calculated by Schmidt from the laboratory-measured densities.
Global reconnaissance Chilingar and Rieke (1976) obtained samples of undercompacted and well-compacted sidewall shale cores from various worldwide locations, and analyzed them to determine the C1- content of the pore water. Each sample was divided into two parts. The volume of pore water present in the sample was determined by drying one portion of the sample at 105~ and weighing it. The soluble salts were determined by washing the salts out four times with distilled water from a finely crushed second portion of the sample. After analyzing the washed out solution (leachate), the C1- content of pore water was determined using a correction for dilution effects (Table 10-3).
244
H.H. RIEKE,G.V. CHILINGARAND J.O. ROBERTSONJR.
TABLE 10-3 Chlorinity of pore water in associated under-compacted and well-compacted shales and sandstones from various parts of the world where overpressured formations are present (after Chilingar and Rieke, 1976, table 1, p. 676. Courtesy of Applied Publishing Co.) Number of
Depth
Chlorinity, mg/1
samples tested
(ft)
Well-compacted shales
Undercompacted shales
Associated sandstones
3/3/3 4 / 2/ 2 3 / 3/ 2 2 / 3/ 3 6/ 2/ 3 3/ 3/ 4 3/4/ 4/3/4 5 / 3/ 2 7 / 3/4 2/ 2/ 2 2/4/
2,000-3,000 3,000-4,000 4,000-5,000 5,000-6,000 6,000-7,000 7,000-8,000 8,000-9,000 10,000-11,000 11,000-12,000 12,000-13,000 13,000-14,000 14,000-15,000
3,000-4,000 2,000-3,000 1,600-3,500 1,500-3,500 3,000-6,000 4,000-8,000 10,000-20,000 2,000-3,000 2,000-3,000 1,500-3,000 2,500-4,500 10,000-14,000
8,000-20,000 10,000-30,000 10,000-40,000 9,000-35,000 8,000-10,000 5,000-9,000 10,000-14,000 8,000-14,000 8,000-14,000 10,000-14,000 -
70,000-80,000 70,000-90,000 75,000-90,000 60,000-200,000 70,000-130,000 90,000-135,000 90,000-100,000 15,000-70,000 13,000-17,000 11,000-30,000 11,000-50,000 90,000-120,000
Fig. 10-7, which is a plot of the maximum and minimum CI- values, shows that water in shales is fresher than that in associated sandstones. The results indicate that the overpressured (undercompacted) shales have higher chloride ion concentrations than that in comparable (at about the same burial depth) well-compacted shales having similar mineralogy. Pore water in the associated sandstones has higher C1- contents than those found in either type (undercompacted or well-compacted) of shales. The maximum value of CI- concentration of 200,000 mg/1 was present at 5500 ft (about 1500 m) in the sandstone samples, whereas the minimum value of 17,000 mg/1 was found at 11,500 ft (about 3500 m). At this depth, the C1- values in the sandstones approach the values in the well-compacted shale (Fig. 10-7). Below the depth of 11,500 ft, the chloride content in the sandstone samples starts to increase with depth, whereas the content in shales remained approximately the same. Owing to possible chemical reactions between the clay-sized mineral grains and water, a reduction in pore volume in argillaceous sediments under increasing pressures can best be analyzed in terms of the removal of pore water by compaction. Some of the factors that are known to influence the water content of argillaceous sediments under applied pressures are the type of clay minerals, their particle size, adsorbed cations, organic matter content, temperature, pH, Eh, and the type of electrolyte solution present in the sediment's pores. The general effects of some of these factors are presented in Fig. 10-8. With the exception of particle size, the influence of these factors is deduced mainly from laboratory compaction experiments consisting of monomineralic clay minerals mixed with simple electrolyte solutions. Vorabutr et al. (1986) measured the chlorinity of leached solutions using rapid quantab titrations from 95 shale cuttings from both well-compacted (42 samples) and
245
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
Chloride concentration, mg/I x 1000 0
30
|
9
0
9
'
'
I
---4-== Well c o m p a c t e d ..... ~ " "
Undercompacted
shales ( 9 value)
:
"'~"
Undercompacted
shales (max. value)
~.
! :
i
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!
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: ,,,.0 .-?"
.
,
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shales (max. v a l u e ]
-- al~- Associatedsandstones[min.value) ~ Associatedsandstones(max. value)
-..!.~-.--............. ..L." ..................................... , .......... /;.~.......
:
:
:
i
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.......... -................i
i Data off scale
:'"--................ -I~ ;............................. ":"~ ~ ......................... "" X. ~!" .............................. : ..... r
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shales ( 9 value}
:
.,-"+'"""+'"""<'"-
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......:--~--./........................................... i ....... ~....:.-.-:.T.~ .....i.,:-.:i ...................... ..... 9
:~9 )~
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i ......................... 7 i :.
: ....r
i
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+
+
+
+
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. I....~.;,.-........~....:.............................~.............................................................:..............................i...
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.
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i .I, "; D"" i
12,000
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!
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:{
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:
i~ .[
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:
3000
60
I
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i ""-...
i '"-+._.i i ....:." .......... -i ................!
::
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-i .............................i .............................+............................. i ............................. ........................... I I I I I I I I ~ I a , I n ~ I
Fig. 10-7. Change in the magnitudes of the m a x i m u m and m i n i m u m chlorinity values of u n d e r c o m p a c t e d and well-compacted shales and associated sandstones. (Modified after Chilingarian et al., 1994, fig. 5-5, p. 120.)
under-compacted (53 samples) shales over a depth interval of 2 5 0 0 - 7 0 0 0 ft from an Indonesian oilfield containing overpressured formations. The chlorinity was expressed in terms of the amount of chlorine per gram of shale or ppm of interstitial solution. Salinity of the interstitial solutions in undercompacted shales, which are associated with overpressured sands, were found to be higher than those in well-compacted ones. Shale porosities were determined from sonic logs. In both cases, salinity of the interstitial solutions in shales was found to be much lower than that in the associated sands. Similar salinity trend in an offshore Louisiana well is presented in Fig. 10-9.
Bengal and Kutch basins, India Abnormally high pressures occur below the M i o c e n e - P l i o c e n e unconformity in the Port Canning and Bodra areas of the onshore portion of the Bengal Basin at depths of 3800 m and 3730 m, respectively (Sahay, 1999). Calculated formation pressures for
246
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.
10
Porosity, 8
6
4
2
3 k4z
9
4
80
0
.
",Ke/,,.~o~
2
o
1
10
1 O0
1000
o~
Median diameter, microns
o
a
1 O0
I~.
o~
~o ~
o.,
Pressure, kg/cm 2
i
,.o
10
"~ ~o
,o.ooo
2.
,
1
Effective overburden pressure, kg/cm ~
o~
~
,oo
,
O. 1
,
Pressure, kg/cm 2
E
O~
6
0 >
=
0
60
m
0
0 >
i
=.,
5O
L._
"(3
0 m
80 - e -
0 "0
0 0.1
i
f
1
10
Pressure, k g / c m 2
o
0 0
a_
0
~o B 9
I
1
1'0
0
Pressure, k g / c m 2
Fig. 10-8. Influence of different factors on the relationship between void ratio and pressure in clayey materials. (A) Relationship between void ratio and median particle diameter at overburden pressures less than 1 kg/cm 2 (modified after Meade, 1964, p. B6). (B) Generalized influence of particle size (modified after Skempton, 1953, p. 55). (C) Influence of clay-mineral species (modified after Chilingar and Knight, 1960, p. 104). (D) Influence of cations adsorbed by smectite (modified after Samuels, 1950). (E) Influence of NaC1 concentrations in unfractionated illite, about 60% of which was coarser than 2 gm is size. (modified after Mitchell, 1960, fig. M3). (F) Influence of NaCI concentrations in illite finer than 0.2 mm (modified after Bolt, 1956, p. 92). (After Meade, 1968, fig. 1, p. D4. Modified after Chilingarian et al., 1994, fig. 5-6, p. 121.)
247
PORE WATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES
'[ "
2000
1
l
I
0
X
3000
I
I
Log-derived salinities in clean sands.
Lab-measured salinitieson sidewallsamples from shales
4000
5000 ,i,i.-=
.ff ,.11.-.
6000
: 7000
-
R..X o.
8000
x.X .==
--
;X*'*'*"X ~"~Top of overpressured X* .Xx zone ,
9000
10,000
Xo:: ~
_
~e-~
_ ~
X'~
0
l 30
I 50
I 70
90
I 110
Salinity, p p m x 10 3 NaCI Fig. 10-9. Salinity trend in an offshore Louisiana well. (Modified after Fertl and Timko, 1970.)
these horizons are approximately 1.8 to 1.9 times hydrostatic. Formation water samples were obtained from drillstem tests, and their analyses indicate lower salinity values in the first high pressure horizon compared to the salinity in the shallower section in the Port Canning Well No. 1. Formation water samples from the Bodra-1 well were obtained by drillstem testing over a section from 3681 to 4193 m. Fig. 10-10 shows the relationship between salinity and fluid pressures in the Bodra-1 well. The salinity data from the drillstem test should not be considered reliable. Open flow drillstem tests taken over long intervals will contain fluid contributions from many sands present in the section. Sahay (1999), however, pointed out that the log-derived salinity values indicate a decreasing trend above the high-pressure zone at 3750 m. The salinity anomaly synchronizes with the resistivity and density log trends in the Bodra-1 well. An exploratory well drilled in 1975 in the Kutch Basin encountered high pressures ranging from 389 to 545 kg/cm 2 beginning at 2600 m down to TD at 4575 m. Sahay
248
H.H. RIEKE,G.V.CHILINGARANDJ.O. ROBERTSONJR. Age
300
400
5
10
I
1
I
Pressure, atms. 500 600
700
800
Sail,g],~, ms/I-'""
25
30
I
I
i
I
20
I
I
I
I
9
1000
1500
200C
/-
? /
E.. 2500 (.-.
CL (I) C~
l 3000
'w/tracesofgas " ~ rw/t......fgas " ~ , _
/ ,,~
rd~o~tnaa?i~ted a ~
~lt water w/little gas comingout
3500
/
~
4000
ter
~)
m
, .
a
in order to release stuck pipe
.....
7"
/- .f / ~
' ~.
I
~ 9-5/8"csg~@ 3316 m
~ L '''~
~
gas w/sali . . . .
f
l
A
l
/ y
/
-
Normal pressure h
t
g
h
No elect, log below 4040 m salinitydata from DST isnot reliable as a long interval / V/ m was tested
,,.,
4500
pressure
/
:cessful. .
9
9 II - -O--
~',,,,,,~
Casing shoe DST d a t a Salinity c u r v e d r a w n f r o m DST d a t a
---~-
Log derived
--~--
Pressure in a t m s .
salinity
Fig. 10-10. Study on salinity and pressures in the Bodra-l well, Bengal Basin, India. (Modified after Sahay, 1999, fig. 11-26, p. 258.)
(1999) reported that the pressures are approximately 1.2 to 1.4 times the hydrostatic and the pore fluids encountered in this interval were mainly water and dissolved natural gas. Fig. 10-l 1 provides the details of the formation pressures, mud weight, temperature and salinity of the water as obtained by drillstem testing in the Kutch exploratory well.
Songliao Basin, China A very important modeling study using formation pressure and pore-water chemical data was performed by He et al. (2000) to delineate the abnormal pressure-chemistry
249
P O R E WATER C O M P A C T I O N C H E M I S T R Y AS R E L A T E D TO O V E R P R E S S U R E S
Age
S 2000 T 230 ~
6000 2 5 - ~ - -
pp 5500
6300
10,000 27:0~
7100
---
18,o00 Salinity, p p m
14,000 29,0~
7900
310 ~
Temperature, ~
87p0
Pressure, psi
Mud weiqht _
930" CSG @ 146 m
Sp. Gr.
". 20" CSG @ 424 m
Pliocene -Pleistocene 1000
-1.32
b 13-3/8"CSG @ 1463 m
2000
?:T_ _
r- -i
';-~~
~
-1.12 to 1.18
N o r m a l pressure
-.. ~ IL9.5/8,,C S ' ~ " ~ K , ~....,. ~ @ 2761 m
a~176176 I
.... ~ , ~
--"
AHFP
~ . . . . . . "" --- "----,. "~ .,~,,,
_---
--~
-1.58
s ha~-rt
Lower ~ Oligocene
~.
',
\\
\ ~.
Middle Eocene
4000-
g~ ~--rLr~rL~
\T ~8
~ T D
= 4752 m
(324 ~
Fig. 10-11. Plot of pressures, salinity and temperature data in the offshore Kutch well, Kutch Basin, India. (Modified after Sahay, 1999, fig. 11-69, p. 312.)
history in the Songliao Basin. This investigation examined the vertical characteristics of underpressure, pore fluids, and sealing conditions in the Shiwu Fault Depression. The depression is part of the Songliao Basin, Jilin Province, northeastern China. Pore-pressure data were obtained from drillstem tests in 40 wells, and chemical analyses were performed on 84 pore-fluid samples. Table 10-4 presents the pore-water chemistry data for both the normal and subnormal pressure zones. Hydrochemical data profiles demonstrate that the ionic evaporite trends of the pore water in the underpressure zone are different from those trends in the overlying sediments, which normally are a hydrostatically pressured sequence. This indicates that the underpressured system is sealed. The pressure transition is sharp and there
250
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.
TABLE 10-4 Major ionic concentrations in g/1 of seawater and Cretaceous oilfield formation waters [Quantou (Kq), Denglouku (K~), and Shahezi (Ksh) formations] in the Shiwu Fault Depression Pressure system Normal pressure (Kzq2 -
Na + + K +
Ca 2+
Mg 2+
HCO 3
CI-
SO 2-
g/l**
n
0.9407
0.0540
0.0073
0.3965
1.1202
0.2928
2.85
29
0.9545
0.0660
0.0097
0.5002
1.0564
0.3696
2.98
36
1.3417
0.4480
0.0219
0.6466
2.1837
0.4603
5.13
19
0.400
1.350
0.142
2.7000
34.50
Kzq4)
Normal pressure (Kid3 -- K2ql) Subnormal pressure ( K l s h -- Kid2) Seawater *
10.88
19.00
n = the number of water samples analyzed. * Data from Snoeyink and Jenkins (1980). Modified after He et al. (2000, table 1, p. 151). ** Total dissolved solids.
is no pressure transition zone between the normal and underpressure sections. The low-pressure zone's upper boundary (seal) does not follow any particular stratigraphic horizon, and the seal was possibly created during diagenesis (He et al., 2000). Table 10-4 shows that the total dissolved solids of the oilfield waters from both zones are much lower than seawater. However, all the major ionic concentrations in the subnormal pressure zone are higher than those in the two normal pressure zones. Sulin's water type classification shows that CaC12 occurs only in the underpressure systems, whereas NazSO4 exists only in the normal-pressure systems. Why is the subnormal pressure zone's chemistry data relationship similar to the expected chemistry of pore waters in the overpressured zones? The basin's burial and thermal history was analyzed using a two-dimensional mathematical model to simulate the evolution of the abnormal pressure history. Results from the computer simulation indicate that the subnormal pressure zone evolved from a high abnormal pressure zone. He et al. (2000) interpretation of the results indicated that the present-day underpressured zone was overpressured in the Early Cretaceous when the basin experienced high depositional rates. Since the end of the Cretaceous, tectonic uplift and erosional cooling eliminated the overpressures, and a reduction in the geothermal gradient occurred creating a decrease in the formation temperatures. It was revealed in this investigation that the chemistry of pore waters in the subnormal-pressure zones can reflect the chemistry of previous high-pressure zones, and that the evolution of the structural geology can be important in modifying or preserving pore-fluid chemistry.
South Caspian Basin The retardation of the compaction processes in the South Caspian Basin is distinguished by the following environmental factors that have created and maintained high-pore pressures in the basin's thick sedimentary deposits (Buryakovsky, 1993a,b, 1993c). The pressure environment is characterized by: (1) high sedimentation rate up to 1.3 km/m.y.; (2) thick sequence of Quaternary-Pliocene age sediments that contains up to 10 km of sand-silt-shale out of a total of 25 km; (3) low heat flow and low formation temperatures (105-110~ at a depth of 6 km); (4) wide development of mud volcanism;
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
251
and (5) an inverted character of the hydrochemical profile with depth: the chemistry of water changes from a calcium chloride and magnesium chloride type to a sodium bicarbonate type (freshening of water with depth).
LABORATORY EXPERIMENTS
Little attention seems to have been given in the literature to artificially simulate (experimental laboratory work) gravitational compaction and the chemistry of expelled pore waters from deeply buried argillaceous sediments. Murray and Irvine conducted the first investigation of pore-water chemistry from marine sediments in 1895 (Manheim, 1976). Soviet geoscientists became interested in the chemistry of pore waters from Recent sediments in the 1930s. The work of Kryukov (1947) in developing effective sediment squeezers is noteworthy in this regard. Chilingar and Knight (1960) conducted experiments in the laboratory at high pressures. Sawabini and Chilingar developed a high-pressure hydrostatic apparatus incorporating the effect of temperature at the University of Southern California in Los Angeles (Sawabini et al., 1971). At Imperial College of London, during the 1960s, a high-pressure uniaxial compaction device was developed to study the influence of temperature and rate of loading on the pore-water chemistry, progressive lithification, and fabric of clay sediments (Knill et al., 1976). Brown conducted laboratory experiments in 1997. Most of the dissolved salts present in the pore waters, which are trapped during sedimentation, are squeezed out during the initial stages of compaction. Laboratory results (Von Engelhardt and Gaida, 1963; Rieke et al., 1964; Chilingar et al., 1969; Kryukov, 1971; Knill et al., 1976) showed that mineralization of expelled solutions progressively decreases with increasing overburden pressure. These results led to the conclusion that the concentrations of pore waters in shales should be lower than those in associated sandstones. A corollary of this premise suggests that solutions squeezed-out at the beginning of compaction should have higher concentrations than the pore waters initially present in argillaceous sediments.
Early laboratory experiments Von Engelhardt and Gaida (1963) found that for pressures between 30 and 800 kg/cm 2 (2.94-78.45 MPa) the concentration of electrolytes in pore waters of smectite diminishes with increasing overburden pressure. At higher pressures up to 3200 kg/cm 2 (313.8 MPa), however, an increase in salt concentration within the remaining pore water was observed by them. Von Engelhardt and Gaida (1963) explained this behavior as due to the electrochemical properties of base-exchanging clays. If the pore water contains an electrolyte, then the liquid immediately surrounding the clay particle will contain fewer electrolytes than the liquid farther away from the double layer. Base-exchanging clays suspended in electrolyte solutions adsorb a certain amount of fresher water, which is bound in double layers around each clay particle. During compression, the electrolyte-rich solution is removed and the water of the double layers, poor in electrolyte content, is left behind. At higher compaction pressures (from 800 to 3200
252
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
+
200
A
n
E ]50 (1)
=4.-=.
0 >
= ,,,.m
O" E
I
2 100
3
100
5o . .. .. ..
0
0
70
.
. . . . . . . . 60 50 40
" -
4
~
30
._,,,._~. ~ 5 ' ..... 20 10
% H20
0
1~"
4o
i~
20
E
B
2
4 L
0 200
150
-,-.-,--
1O0
50
%/-/20
Fig. 10-12. Mineralization and content of various ions in solutions squeezed out of clays. (A) Kaolinite clay: 1 -- Na +" 2 = S O ] - " 3 = C I - ' 4 -- Ca 2+" 5 = Mg 2+ (Modified after Kryukov and Zhuchkova, 1963, p. 97). (B) Bentonite: 1 = k x 104, specific conductivity of solution; 2 - Na +" 3 = C1-" 4 -- S O ] - ; 5 = M g 2+" 6 -- Ca 2+. (Modified after Kryukov and Zhuchkova, 1963, p. 38. In Chilingarian et al., 1994, fig. 5-7, p. 123.)
kg/cm2; 78.45 to 313.8 MPa), an increase in salt concentration within the remaining pore water may be caused by the inclusion of small droplets of water in the highly compressed clay, acting as a barrier to movements of ions. The passage of anions through the double layer is retarded by the fixed negative surface charges on the clay particles. Ion blocking increases ion-exchange capacity and compression of the clay. Apparently, ion blocking is greater for dilute solutions than for concentrated ones. The results of Kryukov and Zhuchkova (1963) demonstrated that the last portions of water squeezed out of sediments are poor in electrolytes (Fig. 10-12). Unfortunately this and many other Soviet studies, referenced here, did not provide pressure data, because such calibrated pressure data are very difficult to obtain in these types of experiments. According to Chilingarian and Rieke (1968), the chemistry of squeezed-out solutions begins to change appreciably when the remaining moisture content is about 20 to 25% for kaolinite and about 50 to 70% for smectite. Rieke et al. (1964) observed the percentage change in concentrations of the major cations and anions with increasing pressure for smectite clay (API No. 25) saturated with seawater. Table 10-5 and Fig. 10-13 present the results of these experiments. The data demonstrate that at each stabilized pressure, the percentage concentrations of Na +, Ca 2+, Mg 2+, CI-, and SO 2- in the expelled pore water decrease with increasing overburden pressure. Kazintsev (1968) performed experiments on the Maykop Clay (eastern Pre-Caucasus). He observed a gradual decrease in chloride concentration on squeezing a sample of this clay having an initial moisture content of 20-25%; the final moisture content after compaction was decreased to 8.83-10.88% (Fig. 10-14A).
253
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
T A B L E 10-5 Mineralization and content of various ions in solutions squeezed out at different pressures from smectite clay (API No. 25, Upon, WY, U S A ) saturated with seawater (after Rieke et al., 1964, table 3, p. 31) Overburden pressure
Percentage of the concentration in solution squeezed-out at 100 psi
(psi)
C1-
100 400 1,000 3,000 10,000
100 91-95 70-83 40-82 36-61 36 a .
40,000 90,000
Na +
100 93-95 84 a 25(?)-87 . . 37 a . .
Ca 2+
M g 2+
SO 2-
Total mineralization
100 75-84 67 a 50-62 . 25 a .
100 80 a 60 a . -
100 84-95 _ 67-81
100 _ -
.
. 38 a
_ 20 a
a Only one trial.
The concentrations of the dissolved constituents in the pore water were determined by squeezing Maykop Clay samples at room temperature and at 80~ Kazintsev's results (Fig. 10-14B) show that the concentration of C1- and Na + decrease with increasing pressure. The temperature does not seem to have any appreciable effect on these two constituents. The Mg ion concentration increases about 1.5 times with increasing pressure. The absolute values, however, are lower at high temperatures than at low temperatures. The concentration of K +, Li +, I-, and HCO~- were higher in solutions expelled at higher temperatures, whereas that of SO 2- was slightly lower. Krasintseva and Korunova (1968) studied the variations in chemistry of solutions expelled from unlithified Black Sea marine muds. At room temperature, the C1concentration decreased with increasing pressure, whereas the concentration of some other components went through a maximum at pressures of 500 to 1000 k g / c m 2 (49 to 98.1 MPa) (Fig. 10-15). Fig. 10-16 shows the relationship between the concentration of various ions and compaction pressure at 80~ for the same marine mud. The results further demonstrate that at a temperature of 80~ the amount of Mg 2+ is less than that at room temperature and does not change much with increasing pressure. No such behavior was noted for Ca 2+ (Fig. 10-16). Shishkina (1968) did not observe any appreciable change in the chemistry of the squeezed-out pore waters up to a pressure of 1260 k g / c m 2 (123.6 MPa) in some samples and up to a pressure of 3000 k g / c m 2 (294.2 MPa) in others from the Atlantic and Pacific oceans and from the Black Sea. There was some increase in Ca 2+ concentration at a pressure range of 675-1080 k g / c m 2 (66.2-105.9 MPa). This was followed by a decrease at higher pressures. Shishkina (1968) stated that at compaction pressures, at which 80 to 85% of pore water is expelled, there are no changes in concentration. Manheim (1966) also noted that pressures ranging from approximately 4 to 85 MPa did not appreciably affect the ion concentrations in expelled pore water. Chilingar et al. (1969) saturated two samples of smectite clay (API No. 25) with seawater and squeezed the pore waters at pressures which were raised rapidly to 5000 psi in the first case and to 10,000 psi in the second case (corresponding to about 35 and
254
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.
,,,..
100
If~ No +
D. 0
C a ++ 9 Mg ++
80
0
Q
60 ,.li..
0 "13 U
cO .,,i,.
0 cO ii..
p c"
40
20
0 b
100
100 80
60
l,O00
40
0
20
0
0 I,i,
a_
100,000
I
I~ c r So4 2-
1
0
cO
l0,000
Overburden pressure, psi
9 I
OIO0
1,000
10,000
1 O0 000
Overburden pressure, psi
Fig. 10-13. Content of various cations and anions expelled at different overburden pressures from seawater saturated smectite clay (API No. 25, Upton, WY, USA). (Modified after Rieke et al., 1964. In Chilingarian et al., 1994, fig. 5-8, p. 124.)
70 MPa). They noted that the concentrations of the major ions in the squeezed-out pore waters increased with increasing pressures with the exception of K + (Table 10-6). This anomalous behavior was explained as follows: upon squeezing rapidly, the portion of the liquid close to the samples' discharging face is expelled at lower pressures; whereas at higher pressures the water inside the sample also has a chance to contribute, but only the more saline portion of the pore water. To further investigate this problem, Rieke (1970) performed an additional experiment in which the same clay as above was remolded with seawater to form a slurry. The slurry was allowed to hydrate for a few days and the supernatant liquid (leachate) was
255
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
I
600
II
,
Ill
A
,
IV
V
VI
VII
,
s00
. i
O"
2
b~
,._.,._. ~
_
1 4
0
6
8
10
12
14
16
18
20
22
Amount of solution s q u e e z e d out, g
B
mg/kg
mg-equiv./kg 34
26
7O .'
85C
~ s o : : r
650
30,
18
90, 45s
lO
50' 250
2
;o
~ / Hco,-rr}
j/
/
r .----''HB~
180, '"
14
/
ij ,/,,,f' ' .
140,
~
Jf
6
so~~-
I
~
Mg2§ )
r
_
6
%
HCO;
2
HCO
60,
M g ~*
o.,1o,, 1o i lOO 500. I
56
,14o. . . .
.........
1oo.
9
mg-equiv./kg I o.18. ,18'1 18o 900
3
6
9
i
II
iii
g
II
112
15
18
IV
v
Vl
/
20;
2
0.02
S12
g
2
20.
K~
_
-
Sr Sr01 c& +
,100,
C F+ N M g 2§
r
!
,,!
"~,v ~~
:,'~
g
Fig. 10-14. (A) Variation in chloride ion concentration in subsequent fractions (I-VII) of squeezed-out interstitial solutions of Maykop Clay, eastern Pre-Caucasus: 1 = depth of 42 m, Divnoe area; 2 -- depth of 158 m, Divnoe area. (Modified after Kazintsev, 1968, fig. 1, p. 186. In Chilingarian et al., 1994, fig. 5-9, p. 125.) (B) Changes in concentration of anions and cations and microcomponents with increasing compaction pressure in subsequent fractions (I-VII) of extruded pore waters. Maykop clay, depth of 158 m, Divnoe area, eastern Pre-Caucasus, Russia. Solid lines - room temperature; dashed lines = heated to 80~ The amount of extruded solutions in grams is plotted on the abscissa. (Modified after Kazintsev, 1968, fig. 2, p. 188. In Chilingarian et al., 1994, fig. 5-9, p. 125.)
analyzed for major dissolved constituents. The clay sample was then centrifuged and the composition of the expelled water was also analyzed. Finally, the c o m p o s i t i o n of the remaining water left in the sample was calculated. The results of this experiment are given in Table 10-7. It can be seen that the total dissolved solids of the initially squeezed-out water first increases, but the pore water left in the sample has a much lower salinity. The concentrations of both Ca 2+ and M g 2+ increased in the remaining pore water, whereas that of Na + 4- K + as well as C1- decreased. The results shown in Table 10-8 were obtained by Kazi and M o u m (1972). They performed leaching experiments on soft marine clay from Drammen, Norway, with an initial salinity of 26,700 mg/1. An undisturbed sample of this clay was confined between two porous stones and assembled into a consolidation cell. The sample was consolidated
256
H.H. RIEKE, G.V. CHILINGARAND J.O. ROBERTSONJR. g/kg
mg/kg
CI ~
mg/kg
300
50 -
50-
200
25'
25'
=
~
~
+~0.c , / B , ~
S O ~ - ~ --
"I" 100 a
0
CI/Br
B
0 Br
Ma 2L -
,.
0
~
~~-
........
HCOa
500
"1000
1500
Compaction pressure, kg/cm 2
Fig. 10-15. Relationship between the concentrations of various ions in interstitial solutions squeezed out of marine mud and compaction pressure at room temperature. (Modified after Krasintseva and Korunova, 1968, fig. 2, p. 195. In Chilingarian et al., 1994, fig. 5-10, p. 126.)
TABLE 10-6 Variation in composition of pore water squeezed out of smectite clay (No. 25, Upton, WY, USA). Composition of seawater used in saturating the sample is also given (after Chilingar et al., 1969, table 2, p.
5) Ions
Composition, ppm seawater
0-5,000 psi
0-10,000 psi
Ca 2+ Mg 2+ Na + K+ SO 2C1Total solids
380 650 10,200 390 1,350 18,000 30,970
280 17 14,400 660 7,100 19,500 41,957
720 320 17,000 610 7,600 23,600 49,850
Na/C1 Ca/C1 K/C1 Na/Ca Ca/Mg
0.5667 0.0211 0.02167 26.842 0.585
0.7385 0.0144 0.03385 51.43 16.47
0.7203 0.0305 0.02585 23.611 2.5
POREWATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES
257
g/kg mg/kg
300 50 10
I00
0"
CI/Br Br-
0
C
l
~
Br
0
,
250
5~30
Ca~ §
750
Compaction pressure, kg/cm Fig. 10-16. Variation in the concentration of various ions in interstitial solutions expelled from marine mud with increasing pressure at 80~ (Modified after Krasintseva and Korunova, 1968, fig. 3, p. 196. In Chilingarian et al., 1994, fig. 5-11, p. 127.)
to an in-situ overburden pressure of 8.7 psi (60 MPa). De-aired distilled water, under the head of a few centimeters, was then flushed through the two porous stones. The leachate (flushed water) was collected in a measuring cylinder and analyzed for major cations (Na +, K +, Mg 2+ and Ca 2+) at regular intervals of time. After leaching, the clay was squeezed, and the salinity of the expelled pore water was measured. It was found that as a result of leaching, the salinity of the squeezed out pore water was reduced from its original value of 26,700 to 1640 mg/1. It is interesting to note that the amounts of Na + and K + extracted in the leachate are in excess of those present in the original pore water, whereas the opposite is true for Ca 2+ and Mg 2+ (Table 10-8). This led Kazi and Moum (1972) to conclude that postdepositional leaching of marine clays is manifested by the migration of high-valence cations from the pore water towards the clay mineral surface at the expense of low-valence cations, which move from the clay's surface into the pore water. Chilingarian et al. (1973) saturated a sample of smectite clay (API No. 25) in seawater for a period of seven days. The sample was shaken vigorously twice a day. Then the supernatant liquid (leachate), which was assumed to have the same composition as
258
H.H. RIEKE, G.V. CHILINGARAND J.O. ROBERTSONJR.
TABLE 10-7 Variation in the composition of the supernatant liquid and pore water centrifuged out of smectite clay (API No. 25, Upton WY, USA); the chlorinity ratios (Ca/CI, K/C1 and Na/C1) are presented along with the Na/C1 and Ca/Mg ratios (after Rieke, 1970) Ions
Composition, ppm seawater, St
(Vt = 10 ml)
supernatant liquid, S1 (V~ = 2.95 ml)
centrifuged liquid, 82 (V2 = 2.9 ml)
remaining liquid, $3 ( ~ = 4.15 ml)
remaining liquid a, $3 (V3 = 4.15 ml)
Ca 2+ Mg2+ K+ Na + SO 2C1Total solids
480 1,283 427 10,554 2,172 19,574 34,490
444 765 260 13,949 4,380 20,355 40,153
462 794 274 14,813 4,471 21,823 42,661
518.2 1,992 652.6 5,164 b 16,202 24,530
431 744 250 13,345 4,292 19,329 38,391
Na/C1 Ca/C1 K/C1 Na/C1 Ca/Mg
0.539 0.0245 0.0218 21.9 0.374
0.685 0.0218 0.0128 31.4 0.58
0.678 0.0212 0.0126 32.0 0.581
0.319 0.0320 0.0403 9.966 0.26
0.69 0.0223 0.0129 30.96 0.579
a Remaining liquid composition was calculated using the supernatant liquid as the starting fluid. b The results are not reported because the clay tested appears to have a high SO42- content.
TABLE 10-8 A summary of the chemical analyses of the major cations present in the pore water of the original (unleached) clay sample (undisturbed marine clay, Drammen, Norway) and the cations present in the leachate (after Kazi and Mourn, 1972, table 2, p. 10) Cation
Na + K+ Ca e+ Mg 2+
Cation concentration a pore water
leachate
438.73 15.66 21.93 41.78
484.57 36.85 16.15 26.46
Remarks
Na + and K + are leached in excess of that present in the pore water of the original sample, whereas the amounts of Ca 2+ and Mg 2+ in the leachate are lower than those in the original sample.
a Expressed in mg/100 g of the original dry weight of the sample.
the free pore water, was removed and analyzed. The remaining saturated sample was placed in a hydrostatic compaction cell (Sawabini et al., 1971) and the successive portions of the expelled solutions were analyzed. The final remaining moisture content was 62%, which corresponds to an overburden pressure of 35 kg/cm 2 (3.43 MPa). The results presented in Table 10-9 illustrate that the concentration of the various ions expelled at the initial stages of compaction are slightly higher than that of the original pore water present in the smectite clay saturated in seawater. As shown in Fig. 10-17, the concentration of the various anions and cations go through a maximum,
TABLE 10-9 U
Variation in the concentration of various components in solutions expelled from srnectite clay saturated with seawater (after Chilingarian et al., 1973, table 1, p. 395) Ion
Concentration, mg/l
z
82 z
0
I I
seawater
supernatant fluid Fraction No.: Cumulative volume, cm3:
ca2+ Mg2+ Na + K+ HCO, SO:C1FNO, CaC03 ~ e ~ + Mn2' Si02 B~+ Total dissolved solids
690 1,189 10,116 400 520 2,759 18,929 3 34 6,612 -
43 4 34,423
560 572 13,400 210 165 4,610 19,310 20 3 3,750 24 5 15 14 38,804
E
Expelled solutions
I
I1
111
IV
V
16.5
25.5
34.5
49.5
59.0
460 644 13,300 226 262 5,350 19,030 20 0 3,800 36 <5 5 21 39,2 16
560 557 13,200 216 165 5,840 19,200 20 0 4,100 56 t5 0 14 39,844
580 669 13,400 206 189 5,270 19,170 120 0.5 4,200 28 <5 5 17 39,433
620 657 13,200 206 165 4,610 19,170 <20 0 4,250 28 (5 10 4 38,576
560 754 12,800 160 128 5,180 18.990 40 0 4,500 64 t5 20 0 38,611
B 4
? %
Er 4rn 0
8 9m 7
m V)
g n e!
260
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.
A (cations) F
B (anions) K+ Ca 2+ Mg2+Na§
03CI S02 I 50H C.00 950016d00
I00 '00
~00
~k
'
"
,
-\
E
-
C~ c)
/
\
Na+
i
~/,
"
m. m
12)
O0 300
300 ~00 700
9000
E C:
0
\
m~,,
,
0Imm C:
50
co3- \ 200 500 600
20C 1850(
0 0
9
r"
/.....
0
wO
-10C "1800
0
I
20
,
I:
\
W-. . . . . .
9
..',,,t#
40
t
~..
(~0
"10C
"40C
"500
20
,
40
, I
60
Amount of Extruded Solution, cm 3 Fig. 10-17. Variations in the concentration of dissolved constituents with increasing compaction pressure in the subsequent fractions of expelled solutions from smectite clay hydrated in seawater: (A) anions; (B) cations. (Modified after Chilingarian et al., 1973, figs. 1 and 2, p. 396. In Chilingarian et al., 1994, fig. 5-12, p. 131.)
or at least remain constant, before starting to decrease with increasing overburden pressure. Chilingar and Rieke (1976) saturated a sample consisting of 50% smectite and 50% illite in seawater, having a salinity of 34,500 mg/1, for ten days. After shaking vigorously the sample several times a day, the supernatant liquid (leachate) was removed, analyzed, and found to have a total dissolved solids content of 37,900 mg/1. The higher salinity of the supernatant water as compared to the initial seawater salinity is possibly due to the presence of soluble salts in the original sample. The authors assumed that the supernatant liquid had the same composition as the free pore water. The remaining saturated sample was placed in a hydrostatic compaction cell, squeezed and the successive portions of the expelled water were analyzed. Fig. 10-18 shows the concentrations of Ca 2+ and Mg 2+, whereas the concentrations of C1- and total dissolved solids are presented in Figs. 10-19 and 20, respectively. These results indicate that the total concentration of expelled solutions goes through a maximum before starting to decrease with increasing pressure. The concentrations of Ca 2+ and Mg 2+ ions in squeezed-out solutions, however, start to increase again during the latest stages of compaction. This can possibly be attributed to
261
PORE WATERCOMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
~E E 0 e-.
600
C a ++
.
._o ~
"-8
" ("- .
o ~ e-. 0
0
500
400
0
20
40
60
80
l O0
Cumulative volume of
expelled solution, ml Fig. 10-18. Variation in the concentrations of Mg 2+ and Ca 2+ with increasing compaction pressure in the subsequent fractions of expelled solutions from an illite plus smectite clay mixture (50"50) saturated with seawater. (Modified after Chilingar and Rieke, 1976, fig. 1, p. 675. Courtesy of the Applied Publ. Co. In Chilingarian et al., 1994, fig. 5-13, p.132.)
their higher concentration in the water in close vicinity to the clay platelets. The final porosity of the tested sample at a compaction pressure of 40,000 psi (about 275 MPa) was equal to 14.8%.
Effect of rate of loading (experiments) Knill et al. (1976) carried out gravitational compaction experiments to study the influence of pressure, temperature, and rate of loading on the composition of expelled pore waters from different clays. The compaction equipment was designed so that pore pressures can be measured. At the upper end of the specimen cup a small-bore drainage pipe is connected, outside the cell, to a pressure transducer. The pore pressures recorded are those at the undrained end of the specimen. Pressures at the drained end of the cell were measured when a backpressure was applied; otherwise the pressure at the drained end is equal to atmospheric pressure - an open system (Knill et al., 1976, fig. 2.1b, p. 9). The two clays used in their experiments, which are important to the present discussion, are Ca-smectite and kaolinite. The clay properties and the composition of the saturating hydration solutions can be found in Knill et al. (1976) and Wijeyesekera and de Freitas (1976). Fig. 10-21 shows the composition of expelled pore fluids from Ca-smectite hydrated in seawater as a function of pressure under a constant temperature of 40~ and a loading rate of 10 psi/h (19.15 Pa/s). Total dissolved solids (TDS), and CI-, Na +, and Ca 2+ concentrations decreased only slightly until reaching a pressure of about 700 psi (4.8 MPa). At this pressure the expelled ion concentrations begin to decrease abruptly with pressure (plotted on the log scale). The concentrations of K +, Mg 2+, and SO 2- do not exhibit much change with tested pressures. The effect of increasing the test temperature to 80~ is shown in Fig. 10-22. The overall trend in composition of expelled ions remains about the same, except for SO]-, which
262
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.
E
20,000 r
O. O.
0 0 IC 0
10,000
13 (!) 0
IC
0
s
0
0
20
40
60
80
100
Cumulative volume of expelled solution,ml Fig. 10-19. Variation in the concentration of Cl- with increasing compaction pressure in subsequent fractions of expelled solutions from an illite plus smectite mixture of (50: 50) saturated with seawater. (After Chilingar and Rieke, 1976, fig. 2, p. 676. Courtesy of the Applied Publ. Co. In Chilingarian et al., 1994, fig. 5-14, p. 133.)
at higher pressures shows a slight increase. There is a very steep decrease in the concentration of total dissolved solids at about 700 psi (4.8 MPa). Furthermore, the relative concentrations of C1- and Na + ions and TDS at the same pressure are lower at 80~ than at 40~ (Fig. 10-21). Knill et al.'s (1976) results for the smectite remolded in distilled water showed a small difference between the expelled concentrations at 40~ and 80~ under the same loading conditions (Figs. 10-23 and 24). The major difference, between the data shown in Figs. 10-23 and 24 and those in Figs. 10-21 and 22, is the rate of decrease in the expelled ion concentrations. Figs. 10-23 and 24 show a constant decrease in the concentration of various expelled ions from the beginning of the test. It is further shown that for the same temperature (40~ and rate of loading (10 psi/h; 19.15 Pa/s), the sample having seawater as initial pore water (Fig. 10-21) experienced less rapid change in ionic concentrations than the sample hydrated with distilled water (Fig. 10-23). There was very little change in the ion concentrations of expelled pore water with increasing pressure in kaolinite remolded in seawater (Fig. 10-25). When the same data are plotted (Fig. 10-26) as a percentage of ion composition of the initial concentration at 50 psi (0.34 MPa), however, the concentration of the SO 2- ion initially remained constant and then increased above its initial concentration with further compaction. There was a systematic decrease in the Na + and K + ion concentrations in the pore water as compaction progressed. The concentrations of the Ca 2+ and Mg 2+ ions gradually
263
PORE WATERCOMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES 50,000
(3.
40,000
L
"a 0 > 0
30,000
"O m
20,000
10,000
0
20
40
60
80
1O0
Cumulative volume of
expelled fluid, ml Fig. 10-20. Variation in the total dissolved solids with increasing compaction pressure in the subsequent fractions of expelled solutions from an illite plus smectite clay mixture (50:50) saturated with seawater. (After Chilingar and Rieke, 1976, fig. 3, p. 677. Courtesy of the Applied Publ. Co. In Chilingarian et al., 1994, fig. 5-15, p. 134.)
decreased initially, followed by an increase starting at a compaction pressure of about 1000 psi (6.9 MPa). As noted by Wijeyesekera and de Freitas (1976), this effect is more pronounced in the case of kaolinite hydrated in distilled water than in the case of kaolinite hydrated in seawater. It is important to state that variations in the ionic concentrations as they appear in Figs. 10-21-26, are plotted as a function of total axial pressure and not the effective pressure (total axial pressure on the sample minus the pore-water pressure). A constant gradient of the curves followed by a break in curvature indicates two distinct stages of pore-water expulsion. The turning point in this trend, as pointed out by Knill et al. (1976), Wijeyesekera and de Freitas (1976) and Rosenbaum (1976), is attributed to a change in the pattern of clay compaction. As compaction progresses at a constant rate of loading (simulating a constant rate of sedimentation in sedimentary basins), there is a buildup of pore pressure to a maximum value, followed by a decline of pressure to a residual constant value. During the early stages of compaction, the rate of pore-water
264
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR. !
....
!
l
.......................... "t ........................ t ......................... | ..................................................~'~
o o (:3
d r---
E
|
'i
"
} | |
i
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--~: ........................ ,
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R 9
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.
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.................... .....~..~....--...o..~.~.,.'-t....o....o....,...,,o,,.~ .................................................. i
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................................................... 9 i TDS
{
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0
'
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4 ...~i......................... -:......................... ).......................... }: ....".~.,..................... " Mg
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i
9--~ . . . . ~,.-~-v;-~-;...;-~., .... ~"'";"'L.......... | -
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i
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~
0
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l O0
1000
...........................
"--..,,...
.,,..
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.i
i i i ". . ~" ,"-,"-*="* .-~-~-. - - - - ~...~,.. ~~ ~ ~mot,~,,,,,,,,,m~ ..... !. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .~...!.~. ~...~. ~ ~ l 0,000
i ~..,J
100,000
Axial pressure, psi Fig. 10-21. Relationship between the axial pressure and major ion concentration in expelled pore water from a Ca-smectite clay hydrated in seawater. Loading rate was 10 psi/h (19.15 P a / s ) at a temperature of 40~ (Based upon data from Knill et al., 1976, Table 7.6, pp. 115-116. In Chilingarian et al., 1994, fig. 5-16, p.
135.) pressure dissipation is slower than the rate of loading, and consequently there is a rapid buildup of pore pressure accompanied by a rapid decrease in sample thickness (Fig. 10-27). In the latter stages of compaction, the sample thickness decreases less rapidly and the pore pressure decays until equilibrium is reached between the rate of pore-pressure dissipation and the rate of loading. It is at this stage of compaction that a break in the curvature occurs. During the early stages of compaction, the clay samples are clearly undercompacted. At this stage, the rate of loading is faster than the rate of pore-pressure dissipation. In the later stages, when the rate of pore-pressure dissipation is equal to the rate of loading, the compaction trend is one for well-compacted clay. The observation of Chilingar and Rieke (1976) that ionic concentrations of water in undercompacted shales are generally higher than the ionic concentrations in the well-compacted shales is in good agreement with these experimental results.
Smectite to illite transformation Until recently, little attention has been given to the determination of the mobile, fresh, expelled pore-water composition that saturated the clay minerals undergoing
265
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
_."! ........................ ; ........................ :..-......................... : ......................... i ........................... 0 0 0
d
4
,-
X
-
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E
3
i,
i
i
i
§
~
i . . i "i. . . . . . . . . . . . . . . . . . . . . . . . +---a,- . . . . -'---'- 9-'+i t
i
+ |
..........................
ff
)
"
)
.*Na ~
-
.!i
"K+
ii
.
+
.
.
..:
..
"
9 t~,-, ,..,.,
"
2+
-
? Mg 2+ ............... ,i, S04~-
+i
*
i
+ ........................ + ...........................
cr
".. T D S
. . . . . . . . . . . .
$
. .-m,
~
l
0 13 !,._..
0 0
o
o
2
c"
"
i
"
i
-
)
"go
~ .:g-~..~,.~.w.;;.g~ ........ g...g--.w i
.:
)
+
.................
~
:":
~. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
~o o o o
"
"
"~~
"
"
"~ "
~ : . =: ~ . 1 --..~ ........................ :.g........................ ~-......................... : ......................... ~......................... .i-.--
-.
-
0
II1
+ .......
~
-
-
-
-
-i.
X X
"T ...... ~' ...... m.~. ..... .~...m..~...,i,.~.:.~..~;i i.... ~ " ~ ' ~ " " ~ " ~ ' ~ ~ ~ i
l
)
l0
l O0
1000
Axial pressure, psi
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .,.
l 0,000
100,000
Fig. 10-22. R e l a t i o n s h i p b e t w e e n the axial p r e s s u r e and m a j o r ion c o n c e n t r a t i o n in e x p e l l e d p o r e w a t e r f r o m a C a - s m e c t i t e c l a y h y d r a t e d in seawater. L o a d i n g rate w a s 10 p s i / h (19.15 P a / s ) at a t e m p e r a t u r e of 80~ (Based u p o n data f r o m Knill et al., 1976, table 10.1, pp. 219. In C h i l i n g a r i a n et al., 1994, fig. 5-17, p. 136.)
compaction. Little quantitative data exist from laboratory experiments on the changes in chemical composition at high temperatures and pressures. Consequently, there is a difference in opinion on the prevailing mechanisms, when laboratory data are compared to field data, which are obtained for the most part from the Texas Gulf Coast shales. This difference can be attributed not only to scaling effects (microscopic versus macro- and gigascopic-scaled reactions), but also to the elementary reactions in the laboratory in contrast to the bulk and complex natural reactions. This has led to confusion, when discussing the smectite dehydration and the conversion of smectite to illite. The slow transformation of smectite to a non-expanding illite proceeds through an intermediate mixed-layer clay phase in deeply buried marine sediments. It involves the movement of water from the smectite's interparticle pores and of water from its interlayers, and fixation of potassium in the clay structure. Transformation is brought about by an exchange of ions in the silicate layer and/or the interlayer space. Both smectite and illite have an 'identical' silicate framework (tetrahedral-octahedraltetrahedral). They differ, however, from each other owing to the location and type of the ions in the clay mineral structure. For further details on possible framework reactions one can consult the Boles and Franks (1979) paper on smectite diagenesis in the Wilcox
266
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR. I
i
I
, ! I , I --v_ ........................ .~. .................................................. r........................."f ........................:--
!,
~:
~
!9
1 Na +
t." 'i
:
!
i
!
:
!9
.
t
.i-v+ .
i.
4
:
'
I
,k
~_2+
i
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:" " : ................
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!"
~ f J
:
i
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: 9. : . . . . . . . . . . . . . . . . . . . . . . . . .
:
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I
~ M g 2+
;' :.
......... ~--
p,.,.
.
X 9
13') 3
~. 9 .........................
IE ff
.-. . . . . . . . . . . . . . . . . . . . . . . . .
.,. . . . .
2
r' (1) O E O
L)
i
" TDS
a
O
. i -I--.
I
.'. . . . . . . . . . . . . . . . . . . .
S O ~ ~Cl-
e
i ,,...: ..........................
.
: .........................
~ :
i
--~ . . . . . . . . . . . . . . . . . . . . . . . . . .
---i ......................... i
1
.",..'. . . . . . . . . . . . . . . . . . . . .
x
x
:
"
i
K
i. . . . . . . . . . . . . . . . . . . . . . . . .
~. . . . . . . . . . . ~ ' ; ; ! 2
.......................
~ . . . . . . * . . . . . . . . . * ..... i..... * .... z ~ . . , ~ . . $ . . a . ~ . a ~ . a ~ |
10
; ............................
"
"
1
o
.:. . . . . . . . . . . . . . . . . . . . . . . . . . .
|
1 O0
1000
Axial pressure,
i .........................
......... i. . . . . . . . . . . . . . . . . . . . . . . . . .
1 O, 0 0 0
~-
}-.-t
100,000
psi
Fig. 10-23. Relationship between the axial pressure and major ion concentration in expelled pore water from a Ca-smectite clay hydrated in seawater. Loading rate was 10 psi/h (19.15 Pa/s) at a temperature of 40~ (Based upon data from Knill et al., 1976, table 7.2, pp. 97. In Chilingarian et al., 1994, fig. 5-18, p. 137.)
sandstone, and also Berger et al. (1999) laboratory analysis of illitization in the Texas Gulf Coast shales. The dehydration mechanism has been linked to the generation of abnormally high subsurface pressures found in Tertiary basins and postulated as a means by which petroleum could be expelled from shales. It was also used to explain the anomalous freshwater in the upper parts of geopressured zones. Powers (1959) proposed a two-stage water-escape dehydration model, which was modified by Burst (1969) to include thermal dehydration and a third stage as shown in Fig. 10-28. Burst's three-stage system considers the initial water flow to consist of interstitial pore water and water from clay interlayers (more than two) after a few thousand feet of burial, where the water is being removed as a result of overburden pressure. A second stage is thought to occur when the heat absorbed by the buried sediment becomes sufficient to mobilize the next-to-last water interlayer. Fertl (1976) pointed out that the first and last dehydration stages are probably unimportant in Gulf Coast oil migration, because they occur at levels either too shallow or too deep to intersect the interval of maximum liquid petroleum availability. The mobile, freed water during the second stage intersects the maximum liquid petroleum interval. The amount of water is calculated to be 1015% of the compacted bulk shale volume and could account for redistribution of the
267
PORE WATER COMPACTION C H E M I S T R Y AS RELATED TO O V E R P R E S S U R E S
/ _ 0 0 0 0
.:
t
--
"
"1"
K
+
,I,
-~-a
.
2+
"
...................................................... .~................................................................... -._ = M g 2+
4
X
_
*
S O . ~-
.
-
.
c'i
-
i
m
3 .......................
E
l
n"n~ +
-
- .......... :"........................................................................ ,~,o "',~,~ .
9
.
..
i
.
" 9
i
0
=.,.. =in=
2 ............................. ".-".................................................. . ' } ' " .................................................... c -
0 c 0
"
x
x
:;
_
1 -i
o
:i
x•
•
i-
f
i
:
i
-:"
............................................................
"
--
:
--
.:i
,.,
:
o _..)...a ................ i . i,i $ i i ~ ~ i ) . i . . . i t. . / ~ 1
l 0
l O0
Axial
"
! "~•
"
"
-
"
......... " ......................................................
x
x
X x
"
i . i . ~)~ i ~ ~ . 1000
pressure,
....... ~"......................... .i _ 10,000
100,000
psi
Fig. 10-24. Relationship between the axial pressure and major ion concentration in expelled pore water from a Ca-smectite clay hydrated in seawater. Loading rate was 10 psi/h (19.15 Pa/s) at a temperature of 80~ (Based upon data from Knill et al., 1976, table 7.5, pp. 110-111. In Chilingarian et al., 1994, fig. 5-19, p. 138.) mobile subsurface components. Movement appears to occur in a relatively restricted, depth-dependent temperature zone where the dehydration temperature is around 221~ (]05oc).
Van Olphen (1963) theoretically predicted the temperature and pressure conditions for removal of interlayer water from smectite by using desorption isotherms to calculate the approximate amount of work-of-removal for the water layers located between the unit layers of smectite. He determined that at 77~ (25~ the fourth, third, second, and first layers of the interplanar water would be removed at pressures of 2940, 19100, 36750, and 79380 psi, respectively. At 122~ (50~ the removal decreases for the last two layers of water to 9702 and 65,415 psi. It should be noted that most or all interlayer water is released from smectite during drying in an oven at 221 ~ (105~ His theoretical values agree satisfactorily with the experimental results of Von Engelhardt and Gaida (1963). Their findings show that smectite compacted at 11,379 psi has a porosity of 33%, and when compacted at 42,670 psi has a porosity of 20%. These values correspond to a smectite having two and one water layer, respectively (Long et al., 1966). The Von Engelhardt-Gaida data appear to confirm that in shales compacted to porosity values at around 33%, intercrystalline porosity would no longer be present. In addition, experimental data of Steinfink and Gebhart (1962) on the removal of
268
H.H. R I E K E , G.V. C H I L I N G A R A N D J.O. R O B E R T S O N JR.
.......................
T ........................ ! !
":" . . . .
|
i
ii
o o o
+ Na+
4 K+ .i. C & +
........................ [ ..........................
~. M g ~+ ,. SO, ~-
x
.~ c r
E
............................................... ~. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
-I--TD s
ff
0
a
; ..........................
: ..........................
: ..........................
~ ...................................
i;
e.-
o cO o
"
"
~
"
i ."
i :.
i
i
i
i
9
~
....
"
:
9
"."
:,<
~
:" x
x x x
..i..........................i................. -~.......!......................... I~......I...I..~.11....... :
_
:
1
10
1 O0
Axial
pressure,
:
1000
9
10,000
100,000
psi
Fig. 10-25. Relationship between the axial pressure and major ion concentration of expelled pore water from a kaolinitic clay hydrated in seawater loaded at a rate of 60 psi/h (114.9 Pa/s). (Based on data from Knill et al., 1976, table 7.16, p. 154. Modified after Chilingarian et al., 1994, fig. 5-20, p. 139.)
monomolecular layers of water from a calcium smectite substantiate Van Olphen's results. Based on Steinfink and Gebhart's results, Fig. 10-29 shows the amount of pressure and approximate equivalent depth of burial necessary to remove each one of the four water layers from interlayer positions on a calcium smectite. For a more complete summary of numerous laboratory experiments and field observations on clay mineral transformation and neoformation, and a comprehensive analytical identification scheme, the reader is referred to Rieke (1972). Experimental compaction studies reported by Brown (1997, 1998) focused on the dehydration reaction for pure sodium- and potassium-smectite samples using a one-dimensional consolidometer system having the capability of providing temperatures up to 482~ (250~ vertical loads up to 6527 psi (45 MPa), run times of about 46 weeks (]100 h) in duration, and internal fluid pressures of up to 4351 psi (30 MPa). Brown's results indicate that a significant decrease occurred in the concentration of C1and K + ions in the expelled fluid from a potassium-smectite sample over a temperature range from 158~ (70~ to 203~ (95~ As the fresh pore fluids were flushed out of the sample, the C1- and K + values regained their original pore-fluid concentrations over a 19-week period. By contrast, the sodium-smectite sample started to partially dehydrate in the 122 ~ to 167~ (50 ~ to 75~ range, and then again at 75 ~ to 100~
PORE WATER COMPACTION i
130 0 a
C
.
.
.
.
.
: :
110
C
0
.
AS RELATED
269
TO OVERPRESSURES
!
9
9
9 '
9 "I
'
'
'
'
.
.
.i
. .
.~ 9 .: : ::
i --
120
C
..==
fl) 0
CHEMISTRY
: :
~
...................................
-
100
: :
~
:
9 -: :-
: :
:
: 9 :
:::
~ :
...-
i iiii!
...........................
: -
~ ~i~i~ . . . . . . .i..i-,.-~. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . i..i .i-!..;.!! i~ii~ ~ ~~i
i
i..:-~.~.!.i .............................
i 9 " ~'" i ~ i ~ ~i " " ~ . - . ~ . ' . : ; - t ~ ~ ~ . "
_..*k---,i....'."i :. " - : - " . ."*"'i " ""..i..~..i..~.'._
.===
~
o O. --o ._a .==-
O
90
. . . . . Na + -
_._K
:. . . .:. . : : : : :
80
". - - ! - -.. . . - , ..- . - . -.C a
70
' ..............
.,.
.
60 o r~
" .~..L.i..;.i.~ . . . . . . . . ..;.. . . . . . . . . . ~. . . . . . . ~ . . . "
+
.
.
Mg
~+
2+
S O 4
.
!
:
.-
., i
: :
i ! ~ii
i
-~- C l --..- TDS
i
i
i .
.
~
.
.
~ i i i ii .
.
.
:
.
............ *~ - " ~ , " ~ " .... ~" " ~: ~ ?" ~ :? ~
,,i
i.~ 9--:-i -.-i i-.~i !-.~.! ............
2-
~ ~
~
!
~ i i iii ".:..... i - ! - - - . : - - . : - - - ~ ~
i i i i ~ -
i
~ :. ! :: i i
: ~ ~~ - ~ "" ~ .~i ":i . . ...............................
~ ! ! ~i
~. i !i~!~
.:....... .~.... ....~---.i ~ i !"-!
i
"
:: i i !~i
-
~~~ -
9+ 9~.- :. ! ............ ! ....... ~ ..... .~ 9- -'.:- 9i 9- ! 9-!--.:-:.-- . ~ ! !i i i ~ ! i ~ ! i!
i i iill i i i i i!~! "-"':":":"~'~ . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ":"~ ' " ' : " - ~ i i iili i !ii!i
..................
i
.
~" ~ ~ ~~ ~ ~~ ~ "
.~ .... ;..i..i.,.~ . .i.. . . . . . . . . . ~. . . . . . . ; ..... i.... ;..;..i..~..i.;..-"
-.k
.... -'"'~"'~"~
i ~ iii
i
i i ! ;iil
..... i.... ~ " i " i
* i
~ , ~" ::,,::
i"~*i"-
i ! :: i~
i i iiiiii! i i i!iiill i !iiii!ii
5 0
"~
............. ~.......
4 0
--:- ............. :........ :-..... ......i..-:..-..-.!.! ............ ! ....... - .... ~...~...:....i..~..i...: .............. !....... ! ..... !.... ! . . . i . . i . ! . . ; . ; . . ,
:,
10
i
............ ~ ....... :-.... !-..-.:.--.:---i-.i-.~--~............ ,~....... i ..... !-..~-..!.i.!-.:-.;..-
i i i :,i~i 1 O0
i
~
i i i i ill 1000
i
:
i i i i i:i , 1 O, 000
A x i a l p r e s s u r e , psi Fig. initial
10-26.
Relationship
concentrations
(Modified
between at 50 psi
after Chilingarian
the (0.34
axial
pressure
MPa)
in expelled
et al., 1994,
fig. 5-21,
and
the
major
ions
pore
water
from
expressed a kaolinite
as a percentage clay
(see
Fig.
of their 11-24).
p. 140.)
temperature interval. These results show that the smectite interlayer water represents the only substantial available source that can freshen pore fluids during the 70 ~ to 95~ experimental heating range, indicating that possibly little water remains in the smectite interlayer regions by the time the transformation of smectite to illite reaction becomes very active at temperatures above 212~ (100~ threshold. Brown's data are in general agreement with the range of values reported by Colten-Bradley (1987). On the other hand, Burst's (1969) field observations indicate that the Gulf Coast smectite was predominantly stable until buried at a depth of 8000 ft and a temperature of 194~ Rieke (1972) attributed this observation to the mixed mineralogy of the argillaceous sediments and demonstrated approximate transitions based on marked reduction of the glycolated 17-A X-ray diffraction smectite peak from Gulf Coast well sample analysis and autoclave experiments (Fig. 10-30). According to him, the smectite to illite transformation is dependent more on temperature than on pressure (Rieke, 1972, p. 101). At elevated temperature and pressure, the smectite to illite conversion did not occur when sodium- or calcium-smectites were hydrated in water with various concentrations of potassium chloride and relatively short periods of time up to 144 h. Hall (1993) proposed that such smectite-illite conversion/nonconversion results, which occur over a wide range of temperatures and timescales is characteristic of a kinetically hindered reaction. A kinetically hindered reaction is one where the cumulative effect of time and temperature control the degree of reaction. Smectite dehydration depends on the
270
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
Early Stage of
compaction
IL ! TM
Late stage of
compaction
~JL~ *- !1"
.e r~o
e
a=
",...
Pore pressure
i===,--..=m
~==, .==,
Time e
Compaction Not to scale Fig. 10-27. Schematic showing the interrelationships among the degree of compaction and variations in the total effective and pore-water pressures with respect to time. (Modified after Chilingarian et al., 1994, fig. 5-22, p. 141.)
temperature (geothermal gradient) as proposed by Burst (1969) and Perry and Hower (1970) and is independent of the burial rate. According to Brown (1998), however, the transformation of smectite to illite appears to be very dependent on the burial rate inasmuch as it takes a considerable amount of time to run to completion. In conclusion, the experimental results point to the possible creation of a fresh water zone in the AHPF zones and support the previously discussed laboratory results on chemistry of pore water squeezed out at various pressures and temperatures.
Experiments involving mixtures of oil and seawater Discussion on the expulsion of pore fluids from compacting argillaceous sediments would not be complete, if a brief mention of the role of crude oil is left out. Aoyagi et al. (1985) performed laboratory experiments to delineate the mechanism of primary migration of crude oil from the source to reservoir rocks. A sample of Na-smectite clay (19% by volume) was mixed with crude oil (3%) and seawater (78%). This mixture was compacted for 25 days under a constant pressure of 14,502 psi (100 MPa) and a temperature of 140~ (60~ Fig. 10-31 shows that the proportion of oil in the expelled liquid gradually increases with time, possibly due to decreasing water saturation. The chemical composition of expelled pore water is presented in Fig. 10-32. The amounts of
REMARKS
SEVERAL MONOLAYERS OF HYDROGEN BONDED WATER HELD IN INTERLAYER POSITION IN MONTMORILLONITE CANNOT BE SQUEEZED OUT BY COMPACTION PRESSURES. AS MONTMORILLONITE ALTERS TO ILLITE. WATER THAT IS HYDROGEN B O N E D BETWEEN UNIT LAYERS IS DESORBEO AWTRANSFERRED AS FREE WATER TO INTERPARTICLE POSITIONS. OVERBURDEN PRESSURES CAN THEN FLUSH WATER FROM THE SEDIMENT ALONG WITH AVAILABLE HYDROCARBONS
MOST HYDROCARBONS FORMED OR MADE AVAILABLE N THIS ZONE BUT NO
NO-UONTMORILLONITE L E V E L (USUALLY ABOUT 9,000 TU 10,000 FEET1
1-1 m i
WATER-ESCAPE
CURVE
MONTMORILLONITE
I ]
ILLlTE
n y
ILLITE
MlXEO
LAYER
AND K A O L l N l T E
Fig. 10-28. Compaction history of various clays when deposited in marine environments and its probable relation to the release of hydrocarbons from mudrocks. (Modified after Powers, 1967, fig. 3, p. 1245. Courtesy of American Association of Petroleum Geologists. In Rieke and Chilingarian, 1974, fig. 58, p. 11 1.)
272
H.H. RIEKE,G.V.CHILINGARANDJ.O. ROBERTSONJR 80,000
80,000
t
B 70,000
70,000 ~ cud
Q..
60,000
60,000
.Q 0 (1) "0
50,000
50,000
0
40,000
0 40,000 r C~
(!)
ff I1)
0 !._
.Q 0
t~O
"0
"0
om
30,000
30,000
E
x 0
L_
L_
20,000
20,000
10,000
10,000
O.. <
3000 4th
3rd Number
2nd
of adsorbed
layers from clay
1st water
surface
Fig. 10-29. Cross-plot showing the approximate pressures required for the removal of successive monomolecular layers of water from a calcium smectite. (Based on data from Van Olphen, 1963. Powers, 1967, fig. 2, p. 1243).
Na +, Mg 2+, C l - , and SO42- contents in the expelled water decreased after a slight initial increase. Both K + and Ca 2+ contents gradually increased after an initial decrease. More work is needed to fully understand the mechanisms operative in experiments involving both oil and water.
FLUID CHEMISTRY COMPACTION MODELS The writers have presented field and laboratory evidence that the concentration of squeezed-out pore water from saturated argillaceous sediments decreases with increasing overburden pressure. Numerous models at various scales have been proposed in the literature to explain this behavior. Several modeling approaches have been
273
PORE WATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES
Temperature, ~ 200 0
220 I
I
240 I
I ~
260
280 I
[
300
I
"
320
I
I
340 I
I
13AI,
5,000
\
.m
D.
I
I0,000
r
t~
15,000
\
\ 20,000
I \
I
\ \ 25,000
\ \
Fig. 10-30. Phase diagram showing an approximate relationship between smectite (M), mixed-layer smectite/illite (MLj-random), and mixed-layered smectite/illite (MLz-ordered) derived from autoclave and field data (Rieke, 1972, fig. 7, p. 108).
advanced for simulating, conceptually and numerically, this change in chemistry with increasing overburden pressures. These models can be broadly classified into two groups based on non-thermodynamic and thermodynamic approaches. Some of the important models are reviewed briefly. This discussion, however, is limited to the pore-size scale models. Basin-wide gigascopic-scale transport models are beyond the scope of this discussion and are not addressed by the writers.
Non-thermodynamic approaches Non-thermodynamic approaches consider the pore-water flow in the clay-waterelectrolyte capillary systems. Curve-fitting techniques are applied to the experimental results.
Warner's double-layer model Warner (1964) considered a double-layer model having the potential field developed at the mid-point of two charged clay particles parallel to each other. In this model the
274
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
i>//.
100
//
75
.I_"
'/9 '
//
50
12I
.o_
0 25
/ |
0
. 5
/ 4 : ..> .
10
.
.
;. ; ; . , " . . : . . ; 15
.
20
25
100
Compaction Time, days Fig. 10-31. Changes in the proportions of oil and water in the expelled pore fluid with compaction time. (Modified after Aoyagi et al., 1985, fig. 2, p. 388. In Chilingarian et al., 1994, fig. 5-23, p. 141.)
concentration of the expelled water, at a certain time, depends on the surface potential and spacing of clay particles, as given by: C -
Coe -U
(I0-9)
where C is the concentration of the expelled pore water in the equilibrium solution; Co, as interpreted by Warner, is the initial electrolyte concentration in contact with clay particles, and U --
vs~ KT
(10-10)
In the latter equation, ~ is the electric potential at the midpoint between two clay plates (as calculated by Verwey and Overbeek, 1948, p. 67), v is the ion valency, s is the elementary charge of an electron, K is the Boltzman constant, and T is the absolute temperature. Warner determined experimentally the electrolyte concentration of water expelled from bentonite, illite, and kaolinite clays compacted in NaCI solutions, having approximately the same C1- content as seawater. The theoretical and experimental results agreed reasonably well for bentonite down to a void ratio of 0.5 and very well for illite down to a void ratio of 0.25. (Void ratio = volume of voids/volume of solids.) No change in concentration was observed for waters expelled from kaolinite. According to Warner, the packing of particles is such that the platy surfaces of most of the kaolinite particles probably did not approach each other at a spacing equivalent to their combined double-layer thickness (about 8 ,& in 0.55 NaC1 solution). Warner (1964)
275
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
10,000 -
E
\
C). CL cO ,m,,,
1000
~
"'"'~'--x k
\" Na +
-
\
0
~
t~,,,,2 +
~%~'
C}.
E
~.
0
0 0 0
,CI
100 "
\..
-'---e h A _ 2 +
S.
"~-.-,...,,
~'~..~/
_e , / +
..,(," ./ \ ~
%
E (b
\ SO4 2
r
(,9 seo ~oter
i
Compaction
1'2
2~,
time, d a y s
Fig. 10-32. Changes in cation contents of expelled water with time. Composition of seawater is also shown for comparison. (Modified after Aoyagi et al., 1985, fig. 3, p. 388. In Chilingarian et al., 1994, fig. 5-24, p. 142.)
calculated that even at a pressure of 60,000 psi (400 MPa), the platy surfaces of the kaolinite particles in 0.55 NaC1 solutions would still be separated by 90/k. Knill et al. (1976) obtained similar results for kaolinite clay hydrated in seawater and compacted up to 5000 psi (35 MPa) (Fig. 10-25). When the same data are replotted with composition expressed as a percentage of the initial concentration, however, then there is a distinct change in the concentration of expelled pore water with increasing pressure (Fig. 10-26). Wijeyesekera and de Freitas (1976) reported similar findings.
Kotova and Pavlov's empirical model Using Kotova and Pavlov's model, it is possible to calculate the concentration of dissolved constituents remaining in the pore water of the compacted sediments (Kotova and Pavlov, 1968). Their numerical model is as follows: C--Co
1
e p
(10-11)
where C is the ion concentration of pore water at a pressure p, Co is the initial ion concentration of pore water at p = O, and )~ and n are constants, the values of which depend on the physicochemical and geological conditions. In their experiments, )~ was
276
H.H. R I E K E , G.V. C H I L I N G A R A N D J.O. R O B E R T S O N JR.
A ~xxxxxxx'~xxx'
:::-
~xxx xxxxxx xx
q
r _..L_
~' ,' , X X X
L L" I X X X X ~ k X ' X X X X X X X X X X X X X X X X X V
=
t
' tm
~_
~
1 | 1 - - - -
1 ~ i ~ . ~ - - - ~
~
"
-
r __.i._.
.~XXXXXXXXXXN2~XXXXXXX,XXXXXXXXXXXXXXXXXXXXXXX'~
C , . . . . .
. . . . . . . limit r = 0
.
tZZZI|||||||||| .
.
.
.
.
.
.
.
.
.
.
.
.
Fig. 10-33. Behavior of electrolyte solutions in a capillary having radius r. (A) Distribution of interstitial fluid density; maximum density occurs at the capillary walls. (B) Distribution of the dissolving capacity of interstitial fluid; maximum dissolving capacity is at the center. (C) Compaction of the capillary by a force F, illustrating that the part of the fluid squeezed out first is the one with the highest dissolving capacity (maximum salinity). (Modified after Chilingarian et al., 1994, fig. 5-25, p. 113.) equal to 4.0 to 4.45 and n was equal to 0.097 to 0. l l 6. An excellent agreement was obtained between the measured and the calculated results (Rieke and Chilingarian, 1974, fig. 133, p. 246). This model has an inherent difficulty in predicting the composition of the non-expelled (held) pore water, inasmuch as ~, and n have to be obtained from the best-fit curve.
Pol'ster's capillary model The conceptual ambient temperature model of Pol'ster et al. (1967) provides an explanation for the gradual decrease in the concentration of squeezed-out pore waters as demonstrated in Fig. 10-33. Capillaries represent the voids in the argillaceous sediment. In saturated sediments, the density of water next to the capillary walls is maximum, whereas along the center part of the capillary the density is lowest and approaches a normal value of one if the capillary radius is large enough. Martin (1960, p. 32) stated
PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES
277
that the density of adsorbed water of Na-smectite varies with the amount of water present in the clay. The highest densities of adsorbed water occur when the HzO/clay weight ratio for Na-smectite is less than 0.5. The highest density values range up to 1.5, as reported by DeWit and Arens (1950), Mooney et al. (1951), and Mackenzie (1958). The low-density values are slightly lower than one (1) as reported by Norrish (1954), Anderson and Low (1958), and Cebell and Chilingarian (1972). The dissolving capacity of water is inversely proportional to density (Fig. 10-33B). As the capillary is squeezed during compaction, its radius is decreased and the water expelled first will be the least bound, which is the more saline water close to the center of the capillary. The results obtained by Chilingar and Rieke (1976) show that the total concentration of expelled solutions goes through a maximum before starting to decrease with increasing overburden pressure. The remaining adsorbed water poor in electrolytes is expelled at higher overburden pressures until the concentrations of Mg 2+ and Ca 2+ ions start to increase. This can be attributed, in these experiments at ambient temperature, to the higher concentration of these ions in the water in close vicinity to the clay platelets. Rieke and Chilingarian (1974) used this model to explain the relative salinities of interstitial waters in well-compacted and undercompacted shales and their associated sandstones, as shown in Fig. 10-34. Although a very simple model, it explains some of the ambient-temperature, experimental results reported in this chapter.
Thermodynamic approach Thermodynamic models combine the concepts of electrochemical equilibrium and electroneutrality in compacting sediments. They are elaborate in determining the effects of decreasing porosity (or void ratio) on the concentration of squeezed-out pore water and the remaining pore water held in the sediments.
Bolt's pressurefiltrate model The model of Bolt (1961) is based on the way the cationic and anionic concentrations vary in the vicinity of a charged clay particle. The model is applicable to a symmetric electrolyte, such as NaC1 held in sediments with infinite initial void ratios (dilute solutions). The concentration, C, expressed in equivalents of ions per unit of fluid volume (mequiv/cm 3) of the expelled pore water is: C =
4Cok
(10-12)
(1 + k) 2
where k is the ratio of the negative-ion concentration toward the middle of the pores divided by C, and k is presumed to vary from unity to zero during compaction (Smith, 1977). Co is the initial concentration of solution in equilibrium with the clay in mequiv/cm 3. The void ratio of the compacting clay is expressed as: e--
(l+k)
1+ 1-k
qpmax
(10-13)
4Co
where e is the void ratio, q is the cation exchange capacity expressed in mequiv/g, and Pmax is the matrix density in g/cm 3. Elimination of k between Eqs. 10-12 and 10-13
Well compacted
S3
Enlarged view of shale capillary
Undercompacted (overpressured)
------------------_ -------------------------------- - - ----------------- - -- - ------- -Shale
-------------------------------------------------------------------
Fig. 10-34. Relative salinities of interstitial fluids in well-compacted and undercompacted (overpressured) shales. Arrows show direction of flow and velocity profile in an enlarged view of a capillary in a vertical direction. S = salinity. (Modified after Rieke and Chilingarian, 1974, fig. 9, p. 25. In Chilingarian et al., 1994, fig. 5-26, p. 143.)
279
PORE WATERCOMPACTION CHEMISTRY AS RELATEDTO OVERPRESSURES
Initial Stage /
~
II
II
II
~CI il
1
=
mll
I
,,m~-.ll"l. q l ~ . , l l ' l , a l ' L - a l l ~ t
1
mci + x
J
==-X==4-.:,m C I ~"--~- .m Na~-~ =-----------,
----------
-=-_---~--_---L ~
C I =_----_---'~. Na---_.~ --. --- -------:.---:
Su pe rnat a n t
mci
~.E~s~ .~ ~~ sTo~~---=_---=." ~
. . . . . . . . . . . .
:-_ _
x
1-_so Vo
--
=
=
_,
mci
xo
Phase I1'
. . . . . . . . .
.....
i,
System requirements
1. Electroneutrality Phase I 9
Na
Supernatant
=-=- -- -- -----
'
II
z--.=~_-_zSusp-e~~To~---_--_----So,Vo
l
~ Na
mci l'lll'~l" ~
Next stage /
Compactionn ~
f
x
-
-
V
VoXo
V
ii = mNa
2. E l e c t r o c h e m i c a l e q u i l i b r i u m Electrochemical potential I
, _ _s _
mll Cl
I
= m Na
II
Electrochemical potential I
~Na
--
II ~Na
Fig. 10-35. Basic concept of Appelo's model; m = ion concentration, # = electrochemical potential. (Modified after Chilingarian et al., 1994, fig. 5-27, p. 145.)
gives the following relationship (Smith, 1977)" C-~
2Co-
(max 2e ) 1 2Co
(10-14)
Appelo's Donnan equilibrium model Appelo (1977) considered the compaction of a Donnanian suspension consisting of a clay hydrated in the NaC1 solution. The conceptual model, which is presented in Fig. 10-35, after satisfying the electrochemical equilibrium and electroneutrality requirements, is represented by the following equation: m~l =
(VNaYC1)I (X + m ~ l ) m ~ l (~]NaYC1) II
(10-15)
where, as shown in Fig. 10-35, the superscript I (phase I) represents the suspension and the superscript II (phase II) denotes the expelled pore water. YNa is the activity coefficient of the sodium ion, YCl is the activity coefficient of the chloride ion, and x is the cation exchange capacity parameter of the clay expressed in equivalents per liter of the suspension, mI1 is the concentration of chloride ion expressed in equiv/1 of the suspension and m~l is the concentration of chloride ion expressed in equiv/1 of the expelled pore water. Fig. 10-35 shows that with an initial suspension volume Vo in liters and the chloride ion content So in equivalents, the initial concentration of the suspension is
280
H.H. RIEKE, G.V. CHILINGARAND J.O. ROBERTSONJR.
m -- s o / V o . The compaction of the suspension from Vo to V (at any time) will change
the concentration of chloride in the suspension to s / V , and the initial cation-exchange parameter Xo will change to x - V o x o / V . As a result of compaction, the concentration of the chloride ion in the squeezed-out pore water will be given by: m~l-
f [s(s ~-
+ Voxo)] 1/2
(10-16)
where f is defined as the square root of the product of the sodium and chloride ion activity coefficients in the suspension to that in the expelled pore water, as expressed below: (yN~YCl)II
gll 4- NaC1
(10-17)
Appelo (1977) applied Eq. 10-16 to two distinct cases: the infinitesimal equilibration case and the mass-balance case. The infinitesimal equilibration case, which applies to drop-wise removal of the squeezed-out pore water from the suspension, has two conditions, which are important to comprehending laboratory-simulated pore-water expulsion experiments. The first condition of the infinitesimal equilibration case examines the concentration of the pore water held in the compacted clay suspension, m~l -- s / V , at different times. Under these conditions, s is given by: s --
o4 oE( l .rexp(y) +
-.re x p ( - y ) -2 ]
(10-18)
where y -- arc c o s h ( ~2S,~ + 1). The second condition considers the concentration of the expelled pore water, m~l = d s / d V , at different times. Under these conditions m~l is expressed as: mc~ =
4V
exp(y) -
exp(-y)
(10-19)
The mass-balance case, which is applicable to field conditions, explains the compaction of a clay-rich layer sandwiched between permeable sandy layers. As in the first case, there are two conditions. The first condition of the mass-balance case applies to the concentration of pore water held in a compacted clay suspension, mI~l - s~ V , at different times. Under these conditions, s is given by"
S
/E
~
21_(
1
1 (10-20)
_
_2so+
1
_4s:
281
PORE WATERCOMPACTIONCHEMISTRY AS RELATEDTO OVERPRESSURES
0.6 m
0 E
oE
m
0
Xo = 0 . 5 So = 0.25
0.4-
......
_
~ ~ ~
jmcl
0.2
0
0L5
Volume of suspension, I
1
Fig. 10-36. The relationship between the chloride ion concentration and the volume of the suspension. The concentration of chloride inside the suspension is given by the solid line curve, whereas that of the squeezed-out liquid is shown by a dashed line; Xo -- initial cation exchange capacity expressed in equivalents per liter, so = chlorine ion content in equiv.; f = the square root of the ratio of activity coefficients inside and outside the suspension. (Modified after Appelo, 1977, fig. 5, p. 96. In Chilingarian et al., 1994, fig. 5-28, p. 147.)
The second condition of the mass-balance case considers the cumulative concentration of the expelled pore water squeezed from the suspension at the end of compaction. At this stage, there is no more reduction in porosity taking place, and the cumulative concentration of the chloride ion at any overburden pressure is: So - s (10-21) m~l= V0- V where the value of s is obtained from Eq. 10-20. Appelo (1977) plotted the last two equations (Eqs. 10-20 and 10-21) to express the variation in the concentration of the chloride ion inside the suspension and in the squeezed-out pore water as a function of the suspension volume (Fig. 10-36). In construction of Fig. 10-36, Appelo used arbitrary values of x = 0.5 and So = 0.25 for two different f values of 1 and 0.52. His plotted results confirm that the chloride ion concentration in the suspension decreases upon compaction for the two selected values of f . In the case of squeezed-out pore water, however, the concentration of the chloride ions decreases with compaction when f = 1. On the other hand, when f = 0.52, the concentration of chloride ions first increases and then decreases to a limiting value at which the porosity is the only governing factor that determines the chloride ion concentration. This is in agreement with the data presented in Von Engelhardt and Gaida (1963), Rieke and Chilingarian (1974), Knill et al. (1976), and Rosenbaum (1976).
Smith's Gibbs equilibrium model Smith's (1977) thermodynamic model is similar to Appelo's in many respects. In deriving his equations, however, Smith assumed that the ratio of activity coefficients
282
H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
of dissolved constituents both inside and outside the clay suspension is unity ( f = 1). Furthermore, in Smith's case, the concentration of either negative or positive ions is expressed as a fraction of pore volume rather than concentration per unit of bulk volume. An additional assumption is that there is no association between cations and negatively charged clay particles. A complete association would eliminate the cation-exchange capacity, such that the concentration of ions, both inside and outside the suspension, would not change with decreasing porosity. Partial association, therefore, would be expected to reduce or delay changes in these concentrations. Realizing this, Smith extended his model to include the case in which the cations are partially associated with exchange sites on the negatively charged particles. Smith (1977) compared his experimental data, for the infinitesimal equilibration case, with equations describing his, Appelo's (1977), and Bolt's (1961) models. The plotted data show the variation between porosity and salinity of squeezed-out pore water from smectite clay (Smith, 1977, fig. 6, p. 384). Neither Bolt's nor Smith's equation gives good agreement with the experimental results. The trends predicted by these two models deviate from the experimental results with decreasing porosity. At high values of porosity, the three models (Appelo, Bolt and Smith) all are in good agreement with the experimental data.
ISOTOPE STUDIES OF I N T E R S T I T I A L F L U I D S
Aside from the ion concentrations, the stable isotopic composition of water is another parameter to characterize pore waters. Deuterium and oxygen-18 concentrations in meteoric surface waters vary by about 43 and 5.6%, respectively, and are linearly related (Degens and Chilingar, 1967). A comparison of the 180/160 and D/H2 ratios shows that atmospheric precipitations normally follow a Rayleigh process at liquidvapor equilibrium. The Raleigh process explains why with higher altitudes and latitudes fresh waters become progressively lighter, whereas tropical samples show very small depletions relative to mean ocean water. In contrast to meteoric waters, ocean waters are isotopically heavy and fall within a narrow range of 1 and 0.1% for deuterium and oxygen-18, respectively. Evaporation strongly affects the 180/160 and D/H2 ratios by causing a preferential depletion in the lighter isotopes ~H and 160, which are concentrated in the vapor phase. The remaining water will be heavier, and the D and 180 contents will show a relative increase.
Geological observations and evaluation Degens and Chilingar (1967) pointed out that hydrochemical field evidence by Knetsch et al. (1963) showed that in the Nubian Series aquifer in the western Egyptian Desert the oxygen isotopes were not fractionated during subsurface transportation over a distance of 700 miles and at a depth range of 500-2000 ft. The oxygen isotope ratios of the water samples taken at intervals of 20-100 miles stayed within 1%o, whereas the chemical composition fluctuated strongly in response to migration and diagenesis.
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283
Degens et al. (1964) reported on the analyses of the oxygen isotope composition of pore waters ranging in age from the Cambrian to the Tertiary. The results presented by them show that the 3180 values in the highly saline pore waters do not deviate appreciably from the 3180 of present-day ocean water (~ = %0 deviation relative to the Chicago Belemnite standard). Deviations from this mean value in pore waters into the negative range of ~lSo, from Cambrian-Ordovician, Devonian, and Pennsylvanian age formations in Oklahoma, U.S.A., are always well correlated to a decrease in salinity. This was explained by Degens and Chilingar (1967) as the effect of dilution with meteoric waters during migration of the pore water, or by later-stage infiltrations as a result of uplift, denudation, or other geological phenomena. This similarity between the isotope characteristics of the pore water and present seawater leads to the conclusion that the concentration of the inorganic salts has not been accomplished by syngenetic evaporation. Possible explanations are that it is an effect of compaction or ion-filtration by charged net clay membranes, or both. Coplen and Hanshaw (1973) found that when water is forced through a compacted Na-smectite disc it was depleted in D by 2.5% and in lSO relative to the water left behind the disc. The enrichment in D of residual waters closely follows a Rayleigh distillation curve, which results in the enrichment in deuterium in the residual pore water if a large proportion of the water has been transmitted through the clay membrane. Any slight deviations into the positive range of ~lSo values in the samples could be caused by original evaporation in a surface environment, or by isotope equilibration with the surrounding mineral matter for millions of years.
Isotope studies of shales in the Gulf Coast Yeh and Savin (1977) measured t h e 1 8 0 / 1 6 0 ratios of size-separated clays from Gulf Coast shales buried at depths ranging from 1000 to 18,400 ft in three wells. Their O-isotope results showed that the sediments are not isotopically equilibrated systems even for those buried at depths where the temperatures are around 338~ (170~ The finer fractions of both clay minerals and quartz are richer in lSo than the coarser fractions. The values of ISo for the <0.1 ~m fraction fell in the range of +22.45%o (1371 ft) to + 17.66%o (5580 ft), whereas the calculated pore-water values changed with temperature from about -1.8%o (35~ to + 10.9%o (170~ Oxygen isotope disequilibrium among the clay fraction became less as the temperature increased (Yeh and Savin, 1977). They noted that the variation of the calculated (not measured) O-isotope ratio of the pore water with depth in a single well indicates a lack of communication between the water at different depths. Calculated pore-water O-isotope ratios from O-isotope fractionations between coexisting fine-grained quartz and clay indicate that the diagenetic reaction of the clay minerals probably proceeded under conditions of a leaky pressure system. Degens and Chilingar (1967) commented that compaction and filtration by charged-net clay membranes should not noticeably influence the O-isotope ratios of waters, but will be influenced by diagenesis. One of Yeh and Savins' conclusions is that any upward movement of pore water in the compacting sequence occurred after chemical reaction and O-isotope exchange of silicate minerals in the overlaying rocks had ceased. This is in contradiction with the results of the previously discussed laboratory compaction experiments of dehydration taking place before conversion.
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H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
Yeh (1980) used D/H ratios of OH hydrogen in clay minerals to further investigate the above three sequences of the buried Gulf Coast shales. The purpose of his investigation was to show if there is (1) a relationship between the isotope ratios and particle size, (2) effect of the smectite to illite conversion, (3) dehydration event, and (4) if there is evidence of isotopic fractionation between residual and expelled pore waters. Yeh indicated that the diagenetic clays (mixed-layer illite-smectite; diagenetic illite) appear to be in oxygen and hydrogen isotope equilibrium with the pore waters (calculated) at the time the most recent diagenesis occurred. Detrital clays (smectite, illite and kaolinite) have undergone different degrees of oxygen and hydrogen isotope exchange with the coexisting pore waters, which became enriched with increasing depth of burial. Pleistocene shales that were buried at 1000 ft having an in-situ temperature of about 68~ (20~ were not isotopically equilibrated with their coexisting pore water, and had 3D value of -72%o from the fine shale fraction (<0.1 txm). This value lies within the range of those of modem Mississippi River sediments and detrital marine sediments of the Gulf of Mexico fight off the Mississippi River delta (-50%o to -90%o). In general, Yeh (1980) found that the spread in ~D values ( - 7 to -8%o) among the six different size fractions remained roughly constant in the wells below the range of 7000 to 8700 ft. Inspecting Yeh's average hydrogen isotope values for each of the wells results shows a spread ranging from -11%o to -21%~ in the <0.1 Ixm fraction from a depth around 2000 ft to TD. He ascribed the progressive change in the clay 3D values with burial depth to an enrichment (lower values) of the pore-water 3D values associated with the clays. The percentage decrease in the smectite in the mixed-layer illite/smectite per unit interval of depth (or temperature) is a direct indicator of the amount of water released from the interlayer sites to the interstitial water. This is attributed to the late-stage dehydration of mixed layer illite/smectite to illite and is based on Yeh's statement that the percent change in the diagenetic montmorillonite correlates with a corresponding percent change in ~D and not simply with the burial depth or temperature. Poulson et al. (1995) performed O-isotope analyses of water, C-isotope analysis of dissolved inorganic carbon, and gas analyses (CO2 and CH4) on samples from normal and overpressured horizons located in the Morganza and Moore-Sams gas fields producing from the Tuscaloosa Formation, Louisiana, U.S.A. 3~8OsMow values of the formation waters range from - 2 . 2 to +8.7%~ showing that possible mixing with a low-salinity, isotopically light water took place. Mixing analysis suggest that the Tuscaloosa pore waters gave 8~80 ~ +8%o, which is normal for deep, basinal waters, although the C1- concentrations indicate that there are two water populations (approximately 35,000 rag/1 and 15,000 to 20,000 mg/1). They reported that there is no systematic difference between the overpressured and normally pressured samples, or between samples from the two fields. Evidence for the gases having a thermogenic origin is based on the values for 3~3CpDB from dissolved inorganic carbon ranging from - 1 0 6 to -3.2%~, ~13CpDB values of CH4 ranging from -43.9%o to -40.8%o, and ~13CpDB values of CO2 ranging from -8.8%e to -6.3%o. In conclusion, the writers believe that a considerable amount of research work still remains to be done in this area.
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SUMMARY AND CONCLUSIONS A study of variations in the chemical composition of subsurface brines has revealed that salinity generally increases with depth in mature sedimentary sequences. Salinities many times greater than that of seawater are frequently encountered in permeable sandstones, but are higher than the salinity of water in associated shales. This applies mainly to geologically older sedimentary basins with hydrostatic fluid pressures. In immature sedimentary basins, where abnormally high formation pore pressures are known to occur, the difference in the magnitude of salinity between the sandstone and shale waters is greatly reduced. In any case, the salinity of pore water in well-compacted shales is often lower than that found in undercompacted shales at comparable depths. Figs. 10-33 and 34 are conceptual models that reveal why pore water in the undercompacted shales is more saline than in the well-compacted shales. The overprinting of fresh water from the dehydration of smectite and from the associated salt deposits can lower or increase the concentrations, respectively. These factors must be considered in using the resistivity and SP well logs to evaluate abnormal pressure zones. The fact that interstitial waters in shales is fresher than that in associated sandstones is further confirmed by the results presented in Table 10-10 and Fig. 10-37. Table 10-10 illustrates pore-fluid freshening by the percentage increase in resistivity with increasing sample pressure for solutions squeezed out of a fresh marine mud from the Santa Cruz Basin, offshore southern California (Rieke et al., 1964). Fig. 10-37 presents the chemical results, which show that both the expelled anions and the cations decrease at about the same rate with increasing pressure at ambient temperature. The results show that the ions being removed represent the interstitial electrolyte solution and do not include the adsorbed cations, and suggest that an analysis for a single ion such as CI- might reveal nearly as much as the analyses of all the ions. These findings support those of Kryukov et al. (1962, p. 1365) that the mineralization of interstitial solutions in shales is lower than that of waters present in the associated sandstones. Water of dehydration (fresh water) from clay conversion accentuates this difference. This water can be trapped at the top of overpressure zones by seals or moves into the associated sand bodies. Among the major dissolved constituents of brines, in normally pressured formations, it is the CI-,
TABLE 10-10 The percentage increase in the resistivity of solutions squeezed out of marine mud with increasing overburden pressure (after Rieke and Chilingarian, 1974, table 2, p. 240) Overburden pressure (psi)
Increase in resistivity (%), as compared to resistivity of solution squeezed out at 500 psi
1,000 2,000 3,000 7,000 14,000 30,000 40,000
2.3-6.5 3.5-15.2 10.5-19.6 16.3-32.0 18.6-37.0 23.2-45.6 25.6-48.0
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H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.
r
.o m
o
100 80 .-...
.c_ g
.o_ g r
a,_ t-"
60 40 20 0
c-
100 c-
O
80 60 40 20 0
100
1000
10,000
100,000
Overburden Pressure, psi Fig. 10-37. Relationship between the overburden pressure in psi and the concentration of various anions and cations in the squeezed-out solutions from a marine mud, Santa Cruz Basin, southern California, U.S.A., as compared to the their concentrations in solution squeezed out at 100 psi. (Modified after Rieke et al., 1964, fig. 8, p. 34.)
Na +, and Ca 2+ ions, which together with total dissolved solids, experience the greatest change in their concentrations with depth. On the other hand, changes in the magnitudes of concentrations of dissolved Mg 2+, SO 2-, and HCO 3 in these formations are rather too small to affect the overall salinity of the formation waters. Much of the information about the chemical composition of brines is generally available from the chemical analyses of water produced from the more permeable sandstone beds during hydrocarbon production operations. These data, however, should be used with caution owing to many possible sources of contamination. Knowledge about the composition of water present in the less permeable shale beds is generally acquired by leaching out the salts or by squeezing out water from the representative shale samples obtained during drilling operations. The most common mineralogical components of shales are smectite, illite, or kaolinite clay minerals. They are hydrated in the laboratory in an electrolyte of known concentration. The hydrated sample is then compacted under different loading and temperature conditions, and the composition of the expelled water is determined to provide information about the behavior of fine-grained sediments in nature. Results of laboratory experiments have shown that the composition of the water expelled from clays, undergoing compaction, is a function of the type of clay mineral, the initial concentration of the electrolyte in interstitial fluids, the temperature, and the rate of sediment loading.
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Based on the field and laboratory experimental data obtained by the writers, the following conclusions have been reached. (1) If dehydration of smectite (conversion to illite), with the release of relatively fresh water, is in part responsible for the overpressured formations and undercompacted shales, then the undercompacted shales will contain fresher waters (compared to water in the associated sandstones). Salinity changes (usually freshening of water) have been used as a warning of impending abnormal pressures while drilling through thick sandshale sequences. This could also be due to influx of fresher water from the shales into sands. Water in shales, both well-compacted and undercompacted, is fresher than that in associated sandstones. (2) The salinity of undercompacted shales appears to be higher than the salinity of associated well-compacted shales. In the literature, comparison is made between the well-compacted and undercompacted shales of diverse origins. Some investigators compared interstitial waters in shales having different mineralogy and obtained from different depths. (3) In the case of both undercompacted and well-compacted shales, the salinities of interstitial fluids in shales are lower than those in associated sandstones if all the other variables remain unchanged. (4) As compaction fluids move upwards in a thick shale sequence, they become more saline. Thus the undercompacted shales lower in the sequence may contain fresher water. (5) The concentration of ions in expelled pore water becomes higher with increasing sediment-loading rate. (6) The higher the temperature, the more rapid is the decrease in the ionic concentration of the expelled pore water up to a certain level (Brown, 1998). (7) The higher the initial salinity of the pore water, the faster is the rate at which the concentration of the expelled pore water decreases. (8) The concentration of high-valence (Mg 2+, Ca 2+) ions may first decrease with increasing overburden pressure, and then increase to values higher than their initial concentrations. (9) In the case of same initial electrolyte concentration of ions in pore water, the change in concentrations of ions in expelled water from low-cation exchange capacity clays (e.g., kaolinite) is much lower, at a given overburden pressure, as compared to a high-cation exchange capacity clay, such as smectite. (10) There is a need for further research involving laboratory high-temperature and high-pressure autoclave experiments involving clay compaction (dehydration and conversion) and the measurement of the resulting D/H and 31SO ratios in the squeezed-out fluids. The above conclusions relating to the field and laboratory investigations clarify many of the observations made on the (1) extracted pore waters from ocean sediments, (2) oilfield water chemistry, and (3) calculated pore-water chemistry from geophysical log analyses. A number of models have been proposed to describe how the chemical changes of pore-water are brought about by the burial of sediments under gravitational compaction. Additional modifications can take place, as noted in this chapter, owing to dissolution of subsurface salt beds and thermohaline convection.
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M o d e l s e m p l o y i n g both t h e r m o d y n a m i c and n o n - t h e r m o d y n a m i c approaches explain some of the field and laboratory observations on a pore-level (microscopic) scale. These models are not comprehensive e n o u g h to explain all aspects of chemical composition of pore waters in sedimentary basins. The models, however, do serve as an insight into some of the m e c h a n i s m s operating in such sedimentary systems and indicate trends of changes in pore-water composition associated with burial of the sediments. Findings presented in this chapter can be applied to some of the important aspects of reservoir characterization and petroleum recovery operations in the petroleum industry as observed by a n u m b e r of investigators. These include a m o n g others: (1) prediction of high-pressured fluid zones (Fertl and Chilingarian, 1977); (2) quantitative interpretation of electric logs (Chilingar et al., 1969), (3) interpretation of the direction of hydrod y n a m i c flow over geologic time in compacting s a n d - s h a l e sequences (Magara, 1969, 1978; Burrus, 1998); and (4) determination of possible water influx into a producing petroleum reservoir from the surrounding shales (Dzhevanshir et al., 1987; Bourgoyne, 1990).
BIBLIOGRAPHY Aharon, E, Roberts, H.H. and Snelling, R., 1992. Submarine venting of brines in the deep Gulf of Mexico: observations and geochemistry. Geology, 20(6): 481-576. Anderson, D.M. and Low, P.E, 1958. The density of water adsorbed by lithium-, sodium-, and potassiumbentonite. Soil Sci. Soc. Am. Proc., 22(2): 99-103. Angino, E.E. and Billings, G.K., 1969. Geochemistry of Surface Brines. Proc. Symp. Univ. Kansas, Lawrence, KA. Chem. Geol., 4( 1/2): 371 pp. Aoyagi, K., Kazama, T., Sekiguchi, K. and Chilingarian, G.V., 1985. Experimental compaction of Na-montmorillonite clay mixed with crude oil and seawater. Chem. Geol., 49: 385-392. Appelo, C.A.J., 1977. Chemistry of water expelled from compacting clay layers: a model based on Donnan equilibrium. Chem. Geol., 19:91-98. Arps, J.J., 1953. The effect of temperature on the density and electrical resistivity of sodium chloride solutions. Trans. AIME, 198: 327-330. Bailey, A.M., Cohen, A.D., Orem, W.H. and Blackson, J.H., 2000. Mobilization of major inorganic ions during experimental diagenesis of characterized peats. Chem. Geol., 66: 287-300. Berger, G., Velde, B. and Aigouy, T., 1999. Potassium sources and iilitization in Texas Gulf Coast shale diagenesis. J. Sediment. Res., 69( ! ): 151- 157. Berry, F.A.E, 1959. Hydrodynamics and Geochemistry of the Jurassic and Cretaceous Systems in the San Juan Basin, Northwestern New Mexico and Southwestern Colorado. Ph.D. Dissertation, Department of Geology, Stanford University, Palo Alto, CA. Berry, F.A.E, 1973. High fluid potentials in California Coast Ranges and their tectonic significance. Bull. Am. Assoc. Pet. Geol., 57(7): 1219-1249. Bethke, C.M., 1996. Geochemical Reaction Modeling. Oxford Univ. Press, New York, NY, 397 pp. Bigelow, E.L., 1994. Well logging methods to detect abnormal pressure. In: W.H. Fertl, R.E. Chapman and R.E Hotz (Eds.), Studies in Abnormal Pressures. Elsevier, Amsterdam, pp. 187-240. Bischoff, J.L., Greer, R.E. and Lusitro, A.O., 1970. Composition of interstitial waters of marine sediments: temperature of squeezing effect. Science, 167: 1245-1246. Boles, J.R. and Franks, S.G., 1979. Clay diagenesis in Wilcox sandstone of southwest Texas: implications of smectite diagenesis on sandstone cementation. J. Sediment. Petrol., 49(1): 55-70. Bolt, G.H., 1956. Physico-chemical analysis of the compressibility of pure clays. Geotechnique, 6(1): 86-93. Bolt, G.H., 1961. The pressure filtrate of colloidal suspensions, I. Theoretical considerations. Kolloid. Z., 175: 33-39.
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Bourgoyne Jr., A.T., 1990. Shale water as a pressure support mechanism in gas reservoirs having abnormal formation pressure. J. Pet. Sci. Eng., 3(4): 305-319. Bredehoeft, J.D., Blyth, C.R., White, W.A. and Maxey, G.B., 1963. A possible mechanism for the concentration of brines in subsurface formations. Bull. Am. Assoc. Pet. Geol., 47: 257-269. Brown, K.M., 1997. Deep origins of fresh water and geopressures. 41 Annu. Rep. Res., Am. Chem. Soc., pp. 251-252. Brown, K.M., 1998. Deep origins of fresh and geopressured water in sedimentary basins and convergent margins. 42nd Annu. Rep. Res., Am. Chem. Soc., pp. 90-91. Burrus, J., 1998. Overpressure models for clastic rocks, their relation to hydrocarbon expulsion: A critical reevaluation. In: B.E. Law, G.E Ulmishek and V.I. Slavin (Eds.), Abnormal Pressures in Hydrocarbon Environments. Am. Assoc. Pet. Geol., Mem., 70: 35-63. Burst, J.E, 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. Am. Assoc. Pet. Geol., 53(1): 73-93. Buryakovsky, L.A., 1993a. Outline of general and petroleum geology in Azerbaijan and the South Caspian Basin, 1. Houston Geol. Soc. BulL, 35(6): 16-33. Buryakovsky, L.A., 1993b. Outline of general and petroleum geology in Azerbaijan and the South Caspian Basin, 2. Houston Geol. Soc. Bull., 35(6): 43-47. Buryakovsky, L.A., 1993c. Offshore oil and gas fields in Azerbaijan: History and description. Houston Geol. Soc. Bull., 36(3): 23-37. Buryakovsky, L.A., Djevanshir, R.Dj. and Chilingar, G.V., 1994. Abnormally high formation pressures in Azerbaijan and the South Caspian Basin (as related to smectite ~-+ illite transformations during diagenesis and catagenesis). J. Pet. Sci. Eng., 13(3/4): 203-218. Cannon, G.E. and Craze, R.C., 1938. Excessive pressures and pressure variations with depth of petroleum reservoirs in the Gulf Coast region of Texas and Louisiana. AIME Trans., 137: 31-38. Capuano, R.M., 1990. Hydrochemical constraints on fluid-mineral equilibria during compaction diagenesis of kerogen-rich geopressured sediments. Geochim. Cosmochim. Acta, 54: 1283-1299. Carpenter, A.B., 1978. Origin and chemical evolution of brines in sedimentary basins. Okla. Geol. Surv. Circ., 79: 60-77. Cebell, W.A. and Chilingarian, G.V., 1972. Some data on compressibility and density anomalies in halloysite, hectorite and illite clays. Bull. Am. Assoc. Pet. Geol., 56(4): 796-802. Chave, K.E., 1960. Evidence on history of sea water from chemistry of deeper subsurface waters of ancient basins. Bull. Am. Assoc. Pet. Geol., 44(3): 357-370. Cheema, M.S., 1976. Prediction of Fracture Gradients in the Appalachian Basin of West Virginia, MS Thesis, West Virginia University, Morgantown, WV, 63 pp. Chilingar, G.V., 1957. Soviet methods of reporting and displaying results of chemical analyses of natural waters and methods of recognizing oil-field waters. Trans. Am. Geophys. Union, 38: 219-221. Chilingar, G.V., 1958. Chemical composition of oil-field waters from Apsheron Peninsula, Azerbaidzhan, S.S.R.: a summary. Geochim. Cosmochim. Acta, 14: 168-178. Chilingar, G.V. and Degens, E.T., 1964. Notes on chemistry of oil-field waters. Boll. Assoc., Mexicana Geol. Pet., 15(7-8): 177-193. Chilingar, G.V. and Knight, L., 1960. Relationship between pressure and moisture content of kaolinite, illite and montmoriUonite clays. Bull. Am. Assoc. Pet. Geol., 44(1): 101-106. Chilingar, G.V. and Rieke III, H.H., 1976. Chemistry of interstitial solutions in undercompacted (overpressured) versus well-compacted shales. Proc. Int. Clay Conf. 1975. Applied Publishers Ltd., Wilmette, IL, pp. 673-678. Chilingar, G.V., Rieke III, H.H., Sawabini, C.T. and Ershaghi, I., 1969. Chemistry of interstitial solutions in shales versus that in associated sandstones. SPE 2527, 44th Annu. Meet., Soc. Pet. Eng., Denver, CO, 8 PP. Chilingar, G.V., Khilyuk, L.F. and Katz, S.A., 1996. Pronounced changes of upward natural gas migration as precursors of major seismic events. J. Pet. Sci. Eng., 14(3/4): 133-136. Chilingarian, G.V. and Rieke III, H.H., 1968. Data on consolidation of fine-grained sediments. J. Sediment. Petrol., 38(3): 811-816. Chilingarian, G.V. and Rieke III, H.H., 1976. Compaction of argillaceous sediments. In: W.H. Fertl, Abnormal Formation Pressures. Elsevier, Amsterdam, pp. 49-100.
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Chapter 11 ABNORMALLY LOW FORMATION PRESSURES V.A. SEREBRYAKOV, G.V. CHILINGAR and J.O. ROBERTSON JR.
INTRODUCTION
The existence of underpressured fluid chambers has enormous significance to oil and gas exploration and production in the world. Such fluid compartments are determinative elements for undetected hydrocarbon traps (i.e., so-called subtle traps). Traditionally, most hydrocarbon production in the world has been from conventional structural and stratigraphic traps. Traps of a newly identified type, the underpressured hydrocarbon traps, may evolve from conventional traps as a result of changes in temperature and pressure. This kind of underpressured traps can be created by considerable overburden removal and local temperature change due to uplift and erosion giving rise to decreased pore pressure. Chapter 11 is an outline of a theoretical basis for an investigation of the validity of this concept. Examples of these kinds of traps can be found in the Denver and Oklahoma basins (Russell, 1972), the Alberta Basin (Hitchon, 1969), and the Volga-Ural and Middle Kura basins (Dobrynin and Serebryakov, 1989). It is important to construct a model for potential hydrocarbon sources in geological sections with abnormally low pressure. This model can be constructed using the change of rock temperature in local zones with significant uplift and erosion. For estimating the thicknesses of eroded deposits the authors used the method of compression curves, that indicate the presence of unconformities and the thickness of eroded deposits not only near the surface, but also deep in the geologic section. The modeling of subsurface underpressured zones may indicate a technique for making underpressured compartment traps viable exploration targets, because exploration strategies can be made significantly more effective if the mechanism of their formation is well understood. Subnormal pressures were discussed in three very important books: Gurevich et al. (1987), Dobrynin and Serebryakov (1989) and Dobrynin and Kuznetsov (1993). Gurevich et al. (1987) briefly analyzed all possible mechanisms of pressure subnormality, including permafrost degradation, fast leakage of gas from gas pools, decrease in temperature, formation of gas hydrates, expansion of rocks owing to the reduction in the overburden caused by erosion and disappearance of ice cover, etc. These authors believed that temperature decrease is possibly the most common cause of subnormally low pressures and occurs in formations overlain by permafrost. It does not include cases of pressure subnormality caused by distribution of the piezometric head in deep layers under the highest portions of the Earth's surface and by fluid withdrawal. Subnormal pressure distributions in several regions were analyzed. Dobrynin and Serebryakov (1989) believed that the major origin of subnormally low pressures is associated with permafrost and temperature changes. Subnormal pressures
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in the Siberian Platform and their origin due to temperature decrease in geologic section were analyzed quantitatively. Using the regional situation as an example of the origin of pressure subnormality, Dobrynin and Serebryakov introduced the concept of thermodynamic gradient. They took the bottom surface of the permafrost (instead of the watertable surface) as the reference surface to determine the hydrostatic pressure in formations below the permafrost. Dobrynin and Kuznetsov (1993) concentrated on the thermodynamic gradient and its role in originating the pressure subnormality. They analyzed, from the viewpoint of this concept, different aspects of pressure subnormality origin, migration and accumulation of hydrocarbons, and sealing properties of formations with higher pressures than pressures of the lower formations. These authors also took into account the possible viscoplastic property of water in narrow pore channels and its influence on the water flow through formations.
ORIGIN OF A B N O R M A L PRESSURES
The origin and characteristics of abnormally low pressure may be related to regional phenomena, or it can be local. Different origin was ascribed by different scientists. For example, Berry (1959), Hill et al. (1961) and Breeze (1970) attributed the abnormally low pressure of the Alberta (Canada), San Juan (New Mexico and Colorado) basins and the Morrow sands of northern Oklahoma to osmotic-pressure differences. Russell (1972) in the Appalachian region, and A.G. Durmishyan (pers. commun., 1976) in the northern Caucasus described the low-pressured reservoirs in well-consolidated rocks, which have been uplifted and eroded in the geologic past. Barker (1972) ascribed the subnormal pressure to the removal of overburden, which would cause a drop in pressure of the pore fluids. Erosional unloading has been suggested to explain certain abnormally low pressures by Louden (1972) and by Dickey and Cox (1977), although a quantitative analysis of the process has not yet been presented. Later, Neuzil and Pollock (1983), using the mass-balance equation (Domenico and Palciauskas, 1979) for water and grains in a small control volume of saturated porous medium, described the unloading of saturated elastic rocks caused by decreasing thickness. Thermal effects, however, were not included. In the opinion of the writers, the thermal effects play the main role in pore pressure changes. Basically, the influence of temperature on pore pressure is strongest in regions with more compacted rocks. In undercompacted, plastic rocks with a high coefficient of compressibility, thermal expansion of fluids can be compensated by deformation of rock pore spaces. Neuzil and Pollock (1983) noted the same effect for the overburden removal. They stated that only in rocks of low permeability is pore pressure likely to be affected by erosion, and if the permeable unit is effectively isolated by surrounding 'tight' rocks, erosional unloading could cause pressure lowering. Changes in temperature of rocks could occur in two ways. The first (regional one), caused by the changes in the temperature at the surface of the Earth in geologic time, affects usual and unusual fluid filtrations. The second (local one), can be caused by changes in the temperature of rocks during the significant uplift and erosion, or subsidence and aggradation. The first phenomenon is a fundamental process in the
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Earth's crust, whereas the second one is a local process in some areas. But both of these processes are associated with well-compacted rocks. In this chapter, the authors discuss only the second phenomenon. In order to estimate and compare compaction of rocks in different basins and regions, the writers used the coefficient of irreversible compaction of rocks /3(t, T), where t is time and T is temperature. The change in porosity of a sedimentary rock with depth can be presented as follows (Dobrynin, 1970): 0(~p = /3 (t, T) x d(~ - p) (1 -- ~p)~p
(11- l)
where a is the overburden pressure, p is the pore pressure, (or - p) is the effective stress, and ~bp is the value of porosity in the highest part of the interval of interest. Effective stress can be estimated as follows: (or -
p) = g(Pr -
(11-2)
pw)h
where g is the gravitational acceleration, fir is the average rock density, Pw is the average density of water, and h is the depth. Using fir 2.5 g/cm 3 and Pw -- 1.1 g/cm 3 as the average density of rocks and water, respectively, one can estimate the average effective stress for a geological section as (c~ - p) = 0.014 h, and determine the coefficient of irreversible compaction/3 (t, T) as: -
~(t, T) ~
1
Aq~p
0 . 0 1 4 ( 1 -- ~bp)~bp A h
-
(11-3)
where A~bp/Ah is the porosity gradient in the depth interval of interest. One can estimate and compare the coefficient of irreversible compaction of shales /3(t, T) in different basins. On comparing shale porosity-depth relationships of the Gulf Coast (Dickinson, 1953), the Oklahoma Basin (Athy, 1930), the West Kuban Depression (Popov, pers. commun., 1970), the North Caspian Basin (Dobrynin and Serebryakov, 1978) and the Powder River Basin, one can observe that shale porositydepth relationships in various basins are quite different (also see Rieke and Chilingarian, 1974). Using these data and Eq. 11-3, one can estimate the coefficient of irreversible compaction for these four basins (Table 11-1). In three of these basins (Gulf Coast, Oklahoma and West Kuban Depression), the coefficient of irreversible compaction varies greatly with depth. There is a fourfold change with a depth of 2 km in the Gulf Coast, almost twice in Oklahoma, and one and a half times in the West Kuban Depression. This variation shows that rocks in these basins are not fully compacted and that the compaction of these rocks may be continuing even now. Only two basins in Table 11-1, the North Caspian and Powder River, have highly compacted rocks, as shown by the fact that the coefficient of irreversible compaction is not changing much with depth. Compaction of these rocks has stopped. The probability of creating abnormal pressure in the more compacted, isolated rocks of these basins is significantly greater, because the influence of temperature on pore pressure in these rocks is significantly greater. Unusual underpressured hydrocarbon traps, and the seals that isolate them, result from global temperature change at the Earth's surface or from local temperate change
298
V.A.SEREBRYAKOV,G.V.CHILINGARANDJ.O. ROBERTSONJR.
TABLE 11-1 Coefficient of irreversible compaction for various basins Basin (source)
Depth (m)
Coefficient of irreversible compaction/~ (t, T) x 103 (mPa-~ )
Gulf Coast, USA (Dickinson, 1953)
0 1000 2000 3000 4000
0 101.5 24.6 14.8 14.5
Oklahoma (Athy, 1930)
0 1000 2000
98.0 51.0
West Kuban Depression, Russia (Popov, 1970, personal communication)
0 1000 2000 3000
66.0 42.0 29.0
Caspian, Russia (Dobrynin and Serebryakov, 1978)
0 1000 2000 3000 4000
28.2 21.1 26.6 26.3
Powder River
0 1000 2000 3000 4000
30.4 30.9 25.0 24.4
N.
due to significant subsidence and aggradation, or uplift and erosion. The existence of abnormally low pressured zones due to global temperature change at the Earth's surface was first observed in eastern Siberia at a depth of 2.0-2.5 km near the crystalline basement by Dobrynin and Serebryakov (1989). This phenomenon was also discovered in other parts of the former USSR (C.I.S.): the Volga-Ural Province, northern part of West Siberia, Ukraine and Georgia. Mostly, this phenomenon is attributed to the changes in temperature at the Earth's surface during geologic time, with consequent changes in hydrogenetic processes in geologic sections with compacted rocks (eastern and western Siberia). In the Ukraine and Georgia, abnormally high and abnormally low pressures are caused by subsidence and uplift, respectively. The theoretical basis of this phenomenon can be analyzed as follows. At a certain time in the basin's history, there was a hydrologic equilibrium defined by" p l _ gPw (h - hst)
(11-4)
where pl is the pore pressure, g is the gravitational acceleration, Pw is the average density of water, h is the depth, and hst is the depth of the static water level. At a later time, the depth changed. The overburden pressure ~r changed because of subsidence,
299
ABNORMALLY LOW FORMATION PRESSURES
permafrost, or tectonic uplift and erosion. The temperature changed in response to the change in the global Earth's surface temperature or to the change in depth. Such changes may create volumetric changes in (1) rocks, (2) pore space, and (3) the interstitial water. Relative pore volume change d V p / V p and pore water volume change dVw/Vw with respect to a change in temperature can be expressed as follows (Dobrynin, 1970):
Vp
- - j~r d(a - p) + fis dp - as dT
(11-5)
dVw = flw dp - O~wdT Vw
(11-6)
where fir, fis, and fiw, are the coefficients of compressibility of pore volume, solids and water, respectively; and O~s, and O~w are the coefficients of thermal expansion of solids (minerals) and water, respectively. In the case of static pore water (full hydrodynamic isolation of pores), a relative change in the volume of pores must be equal to the relative change of pore water volume: dVr
Vr
dVw
=
(11-7)
Vw
Equating the right-hand sides of Eqs. 11-5 and 11-6, one obtains" flw dp - OewdT -- fir d(a - p) + fis dp - Ors dT
(11-8)
Thus, the change in pore pressure (dp) that occurs during a change in the thermodynamic conditions of a deposit is equal to: fir
dp -
da +
/~r -'[- flw -- fls
lYw -- tYs
dT
11-9
fir -[- flw -- fls
2 1 The average normal stress (a) for horizontal layers is a -- 5ax + 5az, where ax is the horizontal component of stress (and ax -- ay), and az is the vertical component of stress. Using the mean lateral compression: l)
Crx -- Oy = ~1 _ a v z
(11-10)
The total overburden stress is equal to" -
a
-
3
1-v
az
(11-11)
where v is Poisson's ratio. Differentiating Eq. 11-11 one obtains: da--~
1 [l+V]d, 1-v
(11-12)
where da z is the change in the vertical component of stress during sedimentation or erosion. Expressing da z in terms of change in sedimentary overburden, one obtains: da-~
1 [l+VlgprAh
1-v
(11-13)
300
V.A. SEREBRYAKOV, G.V. CHILINGAR AND J.O. ROBERTSON JR.
where Ah is the thickness of rocks accumulated during subsidence or thickness of eroded deposits during uplift, and Dr is the average density of the newly deposited or eroded rocks. Combining Eq. 11-13 with Eq. 11-9, one obtains: dP--•
ill+v] t..jl-v
fir
gprAh+
fir nt- flw - fls
Otw - Ors fir + fiw --/3s d r
(11-14)
where plus (+) designates the change in pressure due to subsidence, whereas minus is used to designate the change in pressure due to uplift and erosion. Usually, for sedimentary rocks/~r -+" /~w >) /~s and O~w >> ot~. Thus, Eq. 11-14 can be simplified to: l[l+v] fir gprAh+ Otw dp -- 4-~ 1 - V fir + fl--------~ fir +/3--------~dT
(11-15)
where + and - are treated as in Eq. 11-14. Combining Eqs. 11-4 and 11-15, the new value of pore pressure (p) after thermodynamic change can be estimated as follows: 1 [l+v] p = p l _4_ d p -- g p w ( h
- hst) 4- 5
1 - v
/3r /~r nt- /~w
gprAh+
Otw fir +/3---------~dT(ll_16 )
where pl is the original pore pressure. Using Eq. 11-16, one can estimate pressure after a change in pore pressure in isolated pores, when rock temperature and stress have changed because of sedimentation due to subsidence or erosion owing to uplift, or due to the creation of permafrost. It is necessary to pay special attention to the coefficient of thermal expansion of water, Otw, which increases with increasing temperature and, therefore, with depth. On the basis of the experimental data (Vukolovich et al., 1969), the equation for thermal expansion of fresh water was determined in the temperature interval of 5~ to 200~ to be (Dobrynin and Serebryakov, 1989): Otw = (0.694T ~
1.446) x 10-4
(11-17)
This equation shows dependence of the thermal expansion coefficient on temperature, which is most important in its influence on pore pressure.
ESTIMATION OF THE EFFECTS OF TEMPERATURE CHANGE AND EROSION ON PORE PRESSURE
Serebryakov and Chilingar (1994) discussed the effects of temperature change and erosion on pore pressure in the northem part (Recluse area) of the Powder River Basin (T55-58N, R73-76W) (Fig. 11-1). DST data from 59 wells showed the existence of abnormally low pressure in the Cretaceous deposits at a depth of 7200-7900 ft (2-2.4 km), where the abnormal pressure coefficient K, = P" ranges from 0.4 to 0.8 (Tables 11-2 and 11-3); Pa is the abnormal pressure and Pn Pls the normal hydrostatic pressure. Using the process-oriented conceptual model, presented above, for the generation of abnormal pressure, one can explain the existence of underpressured reservoirs in this
301
ABNORMALLY LOW FORMATION PRESSURES
Hammond
__..__.__._. _ _ _ _ ~Creek F e r " c~. e
--•T
Bell Creek
MONTAN_..AA
9 S
T 57
R64W
N
Gas Draw
Springen Ranch
T R64w
L~yB
Coyote Creek
R61W
i
T.
45 N 1 |
CJareton Ar~
Sfeinle Ranch
T 58 N R61W
WYOMIN
R8Zw
R71W
y
,
Fig. 11-1. Production areas in the Powder River Basin, Wyoming and Montana. The Recluse area as discussed in the text is located at T55-58N, R73-76W. (Modified after Serebryakov and Chilingar, 1994, fig. 1, p. 254.)
TABLE 11-2 Compression curve parameters (both sonic and resistivity data) as related to depth, pressure and temperature in ten wells, Powder River Basin, Wyoming (after Serebryakov and Chilingar, 1994, table 2) Name and number of well
Location
Depth (ft)
1. Oedekoven F 1 2. Oedekoven E 1 3. Oedekoven C 7x 4. Aztec-Govt 3 5. Southland 1 6. Phillips F 1 1-21 7. K Cotter-Govt 2 8. Govt Parker 1 9. Arco-Kendrick 3-47 10. Kendrick Cattle 4
S07T55NR73W S12T55NR74W S24T55NR74W S17T56NR73W SIlT56NR74W S21T57NR74W S07T57NR75W S13T57NR75W S31T58NR76W S31T58NR76W
7748 7759 7780 7205 7276 7225 7240 7533 7851 7796
Pressure (m)
2362 2365 2371 2196 2218 2202 2207 2296 2393 2376
(psi)
2164 2057 1909 2440 2030 2020 1400 2107 1890 1427
MPa
15.2 14.5 13.4 17.2 14.3 14.2 9.8 14.8 13.3 10
Temperature
Compression curve parameter
("F)
resistivity
155
("C)
68
147
64
150
66
172
78
sonic
nx
mx
n,
m,
$
0.0957 0.0779 0.0775 0.082 0.0825 0.0906 0.875 0.086 0.105 0.09
0.953 1.013 1.039 1.029 1.057 1.056 0.895 0.956 1.278 0.955
0.013
3.43
%
0.0078 0.108 0.0181
3.44 3.45 3.42
%w
5
6 F
.< n
2
0.01 16
3.45
5
0
%u
6 P
3rn Ti
TABLE 11-3 Thickness of eroded deposits determined from both resistivity and sonic logs; pore pressure changes due to removal of overburden and temperature changes; and comparison of overburden and temperature changes; and comparison between the estimated coefficient of abnormally low pressure (Ka = pa/p,) and that obtained from DTS data (after Serebryakov and Chilingar, 1994, table 3)
5
2 rn w vl
Name and number of well
1. Oedekoven F 1 2. Oedekoven E 7 3. Oedekoven C 7 x 4. Aztec-Govt 1 5. Southland Govt 2 6. Phillips-Fed. 11-21 7. K Cotter-Govt 2 8. Govt Parker 1 9. Arko-Kendrick 3-47 10. Kendrick Cattle 4
Location
S07T55NR73W S12T55NR74W S24T55NR74W S17T56NR73W S 11T56NR74W S21T57NR74W S07T57NR75W S013T57NR75W S31T58NR76W S3 lT58NR76W
Thickness of eroded deposits:
Pressure change by:
Resistivity logs
Sonic logs
Overburden removal
Temperature change
(ft)
(m)
(ft)
(m)
(psi)
MPa
(psi)
MPa
3707 4872 5141 4688 4793 4360 4199 4147 4573 4531
1130 1485 1567 1429 1461 1329 1280 1264 1394 1381
3878
1182
6929 5466 2451
2112 1666 747
1491
8.3 11.2 11.9 10.7 10.9 9.7 9.4 9.5 10.5 10.4
2034 1920 2233 1721 1863 1593 1565 1607 1963 1934
14.3 13.5 15.7 12.1 13.1 11.2
4892
1180 1593 1689 1519 1547 1380 1337 1351 1493 1479
11.3 13.8 13.6
Ka DST data
Ka = P ~ / P " est
0.64 0.61 0.57 0.78 0.64 0.65 0.45 0.64 0.55 0.42
0.55 0.54 0.5 0.61 0.58 0.65 0.66 0.64 0.57 0.57
2w 6
304
V.A. SEREBRYAKOV, G.V. CHILINGAR AND J.O. ROBERTSON JR.
area by considerable overburden removal and local temperature change owing to uplift and erosion. One can use Eq. 11-16, which consists of three parts. The first part is: g p w ( h - hst)
(11-18)
which is normal hydrostatic pressure at a certain depth before uplift and erosion. The second part is:
, I,+vl 1 - v
-3
-[-/3--------~ j~r g pr A h
(11-19)
The latter shows the influence of overburden removal on pore pressure. The third part is: O~W
dT
(11-20)
fir -'~--j~ w
which describes the changes of pore pressure due to the local temperature changes during uplift and erosion. Dobrynin and Serebryakov (1989) suggested that subnormal pressure could be predicted as the algebraic sum of hydrostatic pressure and pressure change in closed pores due to temperature change. According to these authors, for formations below the permafrost, the hydrostatic pressure is equal to the weight of the water column from the permafrost bottom down to the point where pressure is to be determined. They applied this approach to the examples from the Siberian Platform and Kura Region (Caucasus). The same approach, but at a greater detail, was presented by Dobrynin and Kuznetsov (1993). The first step in studying the underpressured zones in the Powder River Basin was to estimate the thickness of eroded rocks in the target area. The authors used the method of compression curves. Compression curves show the relationship between different parameters (porosity, density, resistivity, transit time, etc.) and effective stress (i.e., overburden pressure minus pore pressure). The parameters n (slope of straight line), and m (intercept) of the compression curve are very important because of their geologic significance. Slope n~ characterizes the compaction of that rock as a function of geologic age, mineralogy, etc. This parameter has to be estimated for each area under investigation or perhaps for each well, using normal compaction trend. Parameter mx (y-intercept), at the beginning of the compaction curve, enables one to estimate the physical rock property of interest near the surface, where effective stress (overburden pressure minus pore pressure) is zero. This parameter depends on the attributes of the entire geologic section, including eroded deposits and major unconformities. It has to be estimated in each well, using the normal compaction trend. The equation for estimating the thickness of an eroded deposit is as follows: Aher =
m x -- mxl g(Pr- pw)nx
(11-21)
where the taxi parameter is for the compression curve in a section without erosion; nx and mx parameters are for the compression curve of interest; g is the gravitational acceleration; Pr is the average density of the rocks, and Pw is the average density of water. Serebryakov and Chilingar (1994) estimated parameters of compression curves
ABNORMALLY LOW FORMATION PRESSURES
305
(Table 11-2) and thicknesses of eroded deposits (Table 11-3) in ten wells of the Powder River Basin using resistivity data, and in five of these wells using sonic data. For the estimation of thicknesses of eroded deposits, it is very important to know the value of parameter mx~ of compression curve in a geologic cross-section devoid of erosion. For the estimation of this parameter, one has to know values of geophysical data (transit time or resistivity) near the surface. In geologic sections without erosion, the value of transit time is close to 200 ~s/ft (660 ~s/m) (Magara, 1978). Using this value, one can estimate the value of mx~ in the cross-section without erosion: mx~ = 3.3. For resistivity value, the authors used estimates that had been made in Russia (Alexandrov, 1987; Dobrynin and Serebryakov, 1989): the value of shale resistivity near the surface in geologic section without erosion is 0.8 ohm m. This value was used for the Powder River Basin. The mx~ value used in calculating the amount of erosion was 0.033. An earlier study of sonic logs in the Powder River Basin (Fig. 11-2a: area without abnormal pressure; Fig. l l-2b: area with abnormally high pressure) showed some difficulty in estimating the thicknesses of eroded deposits by extrapolating the trend of normally compacted shale in terms of sonic travel time in geologic sections without erosion (Magara, 1978). In the Powder River Basin there is no single exponential relationship between transit time and depth. Instead, there are two relationships: one at a depth below 3000-3500 ft, and the other near the surface (Fig. 11-2). The change of sonic trend at shallow depth is possibly related to a significant change in pore tortuosity. Serebryakov and Chilingar (1994) had less difficulty in estimating the thickness of eroded deposits using the resistivity normal compaction trend (Fig. 11-3). It is necessary to correct for the influence of water salinity change near the surface when plotting the resistivity normal compaction trend (Dobrynin and Serebryakov, 1989). Values of estimated thicknesses of eroded deposits vary from 3707 ft (1130 m) to 5141 ft (1567 m). Values of eroded thicknesses estimated by using sonic data are greater in the majority of wells, because there were not enough sonic data at shallow depth and the authors had to use the normal trend of deep deposits. In one well (#1 Southland Govt.), these authors obtained a lower value of eroded thickness using sonic data, but these sonic data were not of good quality. Another way to estimate the approximate thickness of eroded deposits is to determine shale density near the surface. Unfortunately, core data are not available for the near-surface sediments in the target area. Serebryakov and Chilingar (1994), however, estimated the grey shale density of outcrop samples (Oedekoven area) near the surface: 2.35 g/cm 3. The shale density at a depth of 300-400 ft (90-120 m) was estimated to be 2.2-2.3 g/cm 3, using density logs. In geologic sections without erosion, such values of shale density usually denote a depth of 3300-5000 ft (1000-1500 m) (Alexandrov, 1987). These results are thus indirect confirmation of the erosion of 1000-1500 m of overburden in this area. Serebryakov and Chilingar (1994) estimated the influence of overburden removal and temperature change, owing to erosion, from the thicknesses of eroded deposits (resistivity log data). Using the second part of Eq. 11-16, the decrease in pressure due to the removal of overburden was determined. These authors used a value of 0.25 for the Poisson ratio for compacted rocks (Means, 1985), a value of 1 x 10 -3 for the coefficient of pore volume compressibility, a value of 0.5 x 10 -3 for compressibility of water
306
V.A. SEREBRYAKOV, G.V. CHILINGAR AND J.O. ROBERTSON JR.
,.~~~
~
9
A
~
r'
B
- 1000
~
~
........
9 -
.....~. . . . . . . . . . ..... . . . y _ ~ ~9 ~ !i i_ ":
i'
i!
-5000 Teapot Parkman Steele
.....:~' !~i i~_
i
-5000
.
9 ....";~~-.--=... . . . . . . .
: J
Niobrara
:
"!":__.2_,
.... ~_1 :'~i-. . .
:;
- ~9 - -
-.g-
:
;-~- .
"
.
.
.
.
.
.
i ''~' "" . . . .
Teapot Parkman
"
-+-
. . . . . .
"
t....
..... i ....
:
MuddyMowry ' i Morrison ""]'""
i==,,,=~m,
I k ' ~ :.
.
:
.
.
,-.-~-..
.__.k=., Niobrara -I0,000'
: _.a...," .
....~_. i
,..A_.._.~_. 140
r,"._L_.~
Sonic, m/ft
:
!.
9
-I0,000 ,-=2-=.
-4--,
40
*"
.
'r,i
i-.~
: ,_.2._~ . . . . ~.
Muddy M o w r y .--:...-. :
140
:
i "
.
" 9....
i
9 ,i
: .._._: .....
" .... _
il
,._2._ 40
Sonic, m/ft
Fig. 11-2. Relationship between transit time and depth in (A) an area without abnormal pressure (Int. Nuclear Gov't Lee, $34 T45N R70W), and (B) an area with abnormally high pressure (Mongoose Federal 32-6, SO6 T41N R72W). (Modified after Serebryakov and Chilingar, 1994, fig. 2, p. 257.)
(Dobrynin and Serebryakov, 1989), and estimated value of average density of eroded deposits, ,Or, and an estimated thickness of eroded deposits a h (Table 11-2). Values for the pressure decrease (Table 11-3) are 1180-1689 psi (8.3-11.9 MPa). These authors used the third part of Eq. 11-16 for estimating the decrease in pore pressure owing to temperature change. The average geothermal gradient in this area is 0.03~ m. Due to the erosion (1000-1500 m), the temperature could have changed 30~176 The main parameter in the third part of Eq. 11-16 is the coefficient of thermal expansion of water. To determine this coefficient, the authors used Eq. 11-17 for different values of temperature before uplift and erosion. Average values of this coefficient, which was changing during geologic time, were used in Eq. 11-16. Values of pore-pressure decrease due to temperature change vary from 1565 to 2233 psi (11 to 15.7 MPa; Table 11-3).
307
ABNORMALLY LOW FORMATION PRESSURES
3000
A
4000 m~
c-
5000
I I I I I I I I I !
O. 0
6000
7000
v a
8000
I
10
1000
lo0
Shale transit time,
s/ft
3000
B
4000
%
"k
r
5000
O. (!)
l
$ l
6000
$ l
I
,f
7000
o~Im
8000
i
l0
100
1000
Shale transit time, las/ft Fig. 11-3. Relationship between geophysical parameters and depth in the Arco Kendrick 3-47 well: (A) shale transit time, and (B) shale resistivity. (Modified after Serebryakov and Chilingar, 1994, fig. 3, p. 258.) On using the values of decrease of pore pressure due to overburden removal and temperature change, Serebryakov and Chilingar (1994) estimated the values of abnormally low pressure in each well owing to uplift and erosion. Then the estimated coefficients of abnormal pressure were compared with those derived from the DST data (Table 11-3). Results are close, but the estimated coefficients of abnormal pressure are usually lower than those derived from DST data. One possible explanation for this discrepancy is that during geological time the pore pressure was changing due to leaking
308
V.A. SEREBRYAKOV,G.V. CHILINGARAND J.O. ROBERTSONJR.
seals. These calculations show the possibility of existence of underpressured zones not only in the Recluse area but also elsewhere in the Powder River Basin. Overburden removal and temperature change could both cause decrease in pore pressure. One more significant condition, however, must exist for the existence of underpressured zones at present: good seals having low permeability, which could hold pore pressure during geologic time. One can evaluate the sealing capacity of Cretaceous shale in the target area using the sonic travel time data that have been used by Magara (1978) for the Alberta and Saskatchewan areas. Using the linear relationship between the shale porosity (4~) and transit time (At) in the Cretaceous shale (4~ = 0.00466 At --0.317), Serebryakov and Chilingar (1994) estimated the porosity of shale in the Recluse area at a depth of 7000-8000 ft to be 10-13%. Using the porosity-permeability relationship for the Cretaceous shale (Magara, 1978), the permeability of the shale was found to be less than 5 x 10 -3 mD. These shales could act as good seals and could hold pore pressure over a long period of geologic time in the absence of fracturing. As a rule, in the zones where a seal has been fractured, there is normal hydrostatic pressure. Underpressured zones are not present where liquid hydrocarbons have been converted to natural gas, with creation of abnormally high pore pressures. Such examples can be found in the southern part of the Powder River Basin.
SUMMARY
Underpressured reservoirs could form as a result of removal of overburden (erosional unloading). Thermal effects (decrease in temperature) could play a major role in causing underpressure in well-compacted rocks. In estimating the thickness of eroded deposits, the writers recommend the use of "compression curves method" (Dobrynin et al., 1982). Underpressured hydrocarbon reservoirs in the Powder River Basin of Wyoming and Montana have been studied. A significant amount of research work, however, still remains to be done in this field in order to reach definite conclusions.
BIBLIOGRAPHY Abasov, M.T., Azimov, E.Kh., Aliyarov, P.Yu. et al., 1991. The Theory and Practice of GeologicGeophysical Exploration and Development of the Offshore Oil and Gas Fields. Elm Publ., Baku, Azerbaijan, 428 pp. Alexandrov, B.L., 1987. Abnormally High Formation Pressures in Oil-Gas-Bearing Basins. Nedra Publ., Moscow, 216 pp. Athy, L.E, 1930. Density, porosity and compaction of sedimentary rocks. Am. Assoc. Pet. Geol. Bull., 14: 1-24. Barker, C., 1972. Aquathermal pressuring role of temperature in development of abnormal pressure zones. Am. Assoc. Pet. Geol. Bull., 56: 2068-2871. Berry, E, 1959. Hydrodynamics and Geochemistry of the Jurassic and Cretaceous System in the San Juan Basin, Northwest New Mexico and Southwestern Colorado. Ph.D. Thesis, Stanford University, Stanford, CA, 213 pp.
ABNORMALLYLOW FORMATIONPRESSURES
309
Breeze, A., 1970. Abnormal-Subnormal Relationships in the Morrow Sands of Northwestern Oklahoma. M.Sc. Thesis, University Oklahoma, Tulsa, OK, 122 pp. Dickey, L. and Cox, W., 1977. Oil and gas reservoirs with subnormal pressure. Am. Assoc. Pet. Geol. Bull., 61: 2134-2142. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana. Am. Assoc. Pet. Geol. Bull., 37: 410-432. Dobrynin, V., 1970. Deformation and Physical Properties Change in the Oil and Gas Reservoir Rocks. Nedra, Moscow, 288 pp. Dobrynin, V.M. and Kuznetsov, O.L., 1993. Thermoelastic Processes in the Rocks of Sedimentary Basins. VNII Geosystem, Moscow, 169 pp. Dobrynin, V. and Serebryakov, V., 1978. Methods for the Prediction of Abnormally High Formation Pressures. Nedra, Moscow, 231 pp. (in Russian.) Dobrynin, V. and Serebryakov, V.A., 1989. Geological Geophysical Methods for Prediction of Pressure Anomalies. Nedra, Moscow, 287 pp. Dobrynin, V.M., Serebryakov, V. and Srebrodolskiy, A., 1982. Determination of abnormally high formation pressures in shales using the method of compression curves. Geol. Neftii Gaza, 5: 25-28. Domenico, E and Palciauskas, A., 1979. Thermal expansion of fluids and fracture initiation in compacting sediments. Geol. Soc. Am. Bull., 90: 953-979. Fertl, W., 1976. Abnormal Formation Pressures. Implications in Exploration, Drilling and Production of Oil and Gas Resources. Elsevier, Amsterdam, 382 pp. Gurevich, A.E., Batygina, N.B. and Kraichik, M.S. et al., 1987. Formation Fluid Pressure. Nedra Publ., Leningrad, 223 pp. Gurevich, A.E., Chilingar, G.V. and Aminzadeh, E, 1994. Origin of the formation fluid pressure distribution and ways of improving pressure prediction methods. J. Pet. Sci. Eng., 12: 67-77. Hill, G., Calburn, W. and Knight, J., 1961. Reducing Oil Finding Cost by Use of Hydrodynamic Evaluation. Economics of Petroleum Exploration, Development, and Property Evaluation. Prentice-Hall, Englewood Cliffs, CA, 380 pp. Hitchon, B., 1969. Fluid flow in the western Canada sedimentary basin, 2. Effect of geology. Water Resour. Res., 5: 460-469. Hubbert, M.K. and Rubey, W.W., 1959. Role of fluid pressure in mechanics of overthrust faulting. 1. Mechanics of fluid-filled porous solids and its application to overthrust faulting. Geol. Soc. Am. Bull., 70: 115-166. Kazimirov, D.A., 1974. Impulse tectonic movements. Geotectonics, 4: 19-32. Louden, I., 1972. Origin and maintenance of abnormal pressure. 3rd Symp. Abnormal Subsurface Pore Pressure. Soc. Pet. Eng. AIME, pp. 23-27. Magara, K., 1978. Compaction and Fluid Migration, Practical Petroleum Geology. Elsevier, Amsterdam, 319 pp. Means, W.D., 1985. Stress and Strain, Basic Concepts of Continuum Mechanics for Geologists. Springer, Berlin, 339 pp. Melik-Pashaev, V.S., Khalimov, E.M. and Seregina, V.N., 1983. Abnormally High Formation Pressures in Oil and Gas Fields. Nedra Publ., Moscow, 181 pp. Neuzil, C. and Pollock, D., 1983. Erosional unloading and fluid pressures in hydraulically 'tight' rocks. J. Geol., 91: 179-193. Rieke, H.H. III and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Elsevier, Amsterdam, 424 pp. Rubey, W.W. and Hubbert, M.K., 1959. Role of fluid pressure in mechanics of overthrust faulting. 11. Overthrust belt in geosynclinal area of Western Wyoming in light of fluid pressure hypothesis. Geol. Soc. Am. Bull., 70: 167-200. Russell, W., 1972. Pressure-depth relations in Appalachian region. Am. Assoc. Pet. Geol. Bull., 56: 528-536. Serebryakov, V.A. and Chilingar, G.V., 1994. Investigation of underpressured reservoirs in the Powder River Basin, Wyoming and Montana. J. Pet. Sci. Eng., 11: 249-259. Terzaghi, K., 1965. Theoretical Soil Mechanics. Wiley, New York, NY, 510 pp. Tkhostov, B.A., 1963. Initial Rock Pressures in Oil and Gas Deposits. Translated from Russian by R.A. Ledward. Macmillan, New York, NY, 118 pp.
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V.A. SEREBRYAKOV,G.V. CHILINGAR AND J.O. ROBERTSONJR.
Toth, J. and Corbet, T., 1986. Post-Paleocene evolution of regional ground water flow systems and their relation to petroleum accumulations, Taber area, Southern Alberta, Canada. Bull. Can. Pet. Geol., 34: 339-363. Vukolovich, M., Rivkin, S. and Alexandrov, A., 1969. Tables of Physical Properties of Water and Vapor. Standart, Moscow.
311
Chapter 12
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH, E AMINZADEHand L. BURYAKOVSKY
INTRODUCTION The quantity of hydrocarbon accumulation is a function of generation, migration, entrapment, sealing and preservation. All of these factors are affected by the history of fluid movement in a thermochemical setting. Fluid movement within a basin depends primarily on pressure variation (Yu and Lerche, 1996). Thus, one can improve both hydrocarbon exploration and later oil production with a better understanding of the fluid pressure environment. The additional costs of well blowouts and associated wellbore problems while drilling have forced the drilling industry to obtain methods of prediction of encountering overpressured formations. Yassir and Bell (1994) noted that often severe formation overpressures are encountered suddenly over depth intervals in the order of tens of meters. An accurate prediction of the pore pressure is crucial to avoid a wellbore blowout prior to drilling into the surpressured formation. Mud-weight balancing is the most common method of offsetting this additional wellbore pressure from overpressured formations. Numerical results from the prediction of overpressured formations can serve as a reference against which other geological scenarios can be compared for their overpressure anomalies. By comparing case histories, one can obtain valuable clues for estimating current and paleo-overpressure conditions in the frontier basins that can be assessed prior to drilling (Yu and Lerche, 1996). The relationship between formation overpressures and porosity, and overpressures and stress regime, can differ significantly depending on the geological setting and mechanisms responsible for generating surpressures. These factors should be included in any simulation approach. The most important aspect in modeling becomes a thorough study of the mechanisms and geological settings of a particular basin. As computers continue to become faster and more robust, all disciplines are moving from qualitative analysis to quantification. Modeling geological history is no exception. In view of latest developments in material science and irreversible thermodynamics, it has become important to discuss features that were previously considered to be beyond the scope of mathematical modeling. Modeling dynamic geochemical processes, such as paleotemperature and abnormal pressure of sedimentary basins, offers many challenges, as little experimental data are available to validate the laws of distribution, accumulation, and migration of hydrocarbons. The mathematical model requires initial boundary values that are difficult to define. A geological basin evolves over millions of
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years or even hundreds of millions of years, with a very large areal extent and thickness. Sedimentary processes determine the reservoir boundaries.
M E T H O D O L O G Y OF SIMULATION OF DYNAMIC SYSTEMS
Objects of geological study, i.e., geologic systems, with subsequent technologic impact (e.g., secondary and tertiary recovery) on them, are dynamic systems. They change either in 'geologic' or 'technologic' time scales. Thus to develop adequate dynamic models of geologic and technologic processes, it is necessary to introduce a time factor (Buryakovsky and Chilingarian, 1991). The rather conflicting methodological approaches, such as system-structural and genetic-historical, are merged in the modeling of dynamic geologic systems. Merger of the structural and historical approaches in one model treats a geological system as a natural phenomenon, which on one hand is relatively stable at a certain time period, and on the other hand, is evolving during a sufficiently extended interval of geologic time. The necessity to take geologic time into account meets with significant difficulties. This often causes an unwillingness to construct the geologic models when they should reflect the dynamics of geologic phenomena and processes. One of the reasons for this difficulty is the use of absolute and relative geologic time. The difference between them is substantial: the absolute time has the beginning common for the entire Earth, which is not an attribute of the relative time scale based on paleontology and stratigraphy. Another reason is the lack of reproducibility of the geologic time in physical and chemical experiments, and the practical impossibility to eliminate this obstacle using the similarity method and the dimensional analysis. The time factor is of a special importance for the problems of forecasting. Such problems necessitate the creation and application of the mathematical models. The successful forecast may depend on the retrospective historical evaluation of the geologic system under study. Two methods in constructing such models may be offered (Buryakovsky et al., 1990): analytical and statistical. A better approach in modeling such systems is a combination of the mathematical analysis (i.e., differential equation) with the statistical-probabilistic expression of the numerical values for the parameters, describing the change in dynamic geologic systems. This approach allows one to define, in a deterministic way, the main features of dynamics of the geologic systems. At the same time, it also includes a statistical-probabilistic nature for various numerical geologic parameters which determine the evolution of the systems. The implementation of analytical solutions is accomplished using the statistical sampling technique (e.g., Monte Carlo method; Buryakovsky et al., 1982).
ANALYTICAL APPROACH
Two important issues must be addressed prior to constructing analytical models:
MATHEMATICALMODELINGOF ABNORMALLYHIGH FORMATIONPRESSURES
313
(1) The primary properties of the system under study, as well as those of the surrounding lithosphere, should be defined. These properties should be described by strictly defined quantitative constraints. (2) The limitations assumed in describing these properties should be clearly delineated and reflect the substance of a particular geologic system. The main parameters are those properties of the system (and of the surrounding rocks) that would simulate or restrain the course of the geologic processes. If a process can be characterized by a single parameter, for instance, the hydrocarbon reserves or formation pressure, this parameter should be used as the main parameter for the model. In the following discussion, the writers use as synonyms the properties of the geological system and their respective numerical parameters. They may have a dual nature, i.e., they may be either deterministic or stochastic, depending upon the formalization approach at each stage of the modeling of a geologic system. Two major assumptions should be made while developing the differential equations for the geologic processes" (1) The rate of change in the geologic system, or the speed of the geologic process, is proportional to the current state of the system. (2) Influence of various natural factors is proportional to the product of the number (or quantitative estimates) of the events accelerating the process by the number (or quantitative estimates) of the events retarding the process. The first assumption leads to the differential equations similar to: dx
=e(t)f(x) (12-1) dt where x is the variable (quantitatively measured natural factor) describing the evolution of the geologic system, e(t) is the coefficient of proportionality (generally time-dependent), and f (x) is the function of variable x. In the case of a multi-phase process, a system of equations of Eq. 12-1 type can be written jointly. The second assumption puts together a system of differential equations that takes into account the effects of interrelationships among variables"
dxl dt
-- 6 1 ( t ) f l ( X l )
-k- Y 1 2 ( t ) f l ( X l ) f 2 ( x 2 )
(12-2)
= 6 2 ( t ) f 2 ( x 2 ) nt- y 2 1 ( t ) f l ( x l ) f 2 ( x 2 )
(12-3)
dx2
dt
where Xl and x2 are the variables (natural factors) respectively accelerating and retarding the process, Y12(t) and V21(t) are independency quotients of these variables (or natural factors), which are generally time-dependent. In some particular cases, the factors e and )I may not be time-dependent, i.e., they are constant. In those cases, Eq. 12-1 forms the so-called model of 'proportional effects', or an 'organism growth model'. Various functions of the affecting parameters can be used in Eqs. 12-1, 12-2 and 12-3. This creates the necessary diversity in analytical descriptions for the dynamics of the geological systems. For example, when f ( x ) -- x, the process in Eq. 12-1 is
314
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
described by the exponential curve; when f ( x ) -- x ( a - x), where a is a constant, the process is described by the logistical curve (S-like or Gompertz curve), etc. The signs of the e and F quotients in Eqs. 12-2 and 12-3 may vary. If the first equation has a positive el and a negative V12, then two sign contributions are possible for the e2 and F2~ in the second equation. In the case of a negative 62 and positive F2~, the processes of construction and destruction are antagonistic. In the case of positive ,~2 and negative F2~, the processes merge into a single process controlled by the same natural factors, and the prevalence of the constructive component over the destructive one depends upon the relation between these factors. Depending on the signs of e and F, the geologic processes can be stable or unstable in time. The former case is characterized by a point (center) or a convergent spiral on the phase plane in the (x~, x2) coordinates. The latter case is characterized by a saddle or divergent spiral. Using analytical models (Eqs. 12-1, 12-2 and 12-3), one can study the evolution of a dynamic system in time. Based upon the structure of the lithospheric space-time continuum, it is possible to equate the evolution of the geologic systems in depth to their evolution in the reversed time. In this sense, the geologic forecast is actually a reversed forecast, or ' r e t r o c a s t ' , because it is directed backwards (in time) and is directed onwards in depth (in space). Taking into account the specifics of the geologic time-space continuum, the analytical models (Eqs. 12-1, 12-2, and 12-3) forecast the behavior and structure of a geologic system at depths not yet studied through geologic techniques, provided there is a normal stratigraphic succession of consecutive time intervals.
ANALYTICAL
MODELS
Most model studies dealing with abnormal pore pressures can be characterized into two categories, namely, pore pressure prediction and pore pressure detection methods (Yoshida et al., 1996). Pore pressure prediction methods rely on seismic methods and well histories. Pore pressure detection methods utilize drilling parameters and well log information during the drilling process. The overlap of the two methods is increasing gradually, requiring the accuracy of both methods with the advent of MWD and LWD logging tools. Both methods, however, rely on data that are site specific. To-date, there is no universal method of prediction of abnormal pressures. This is mostly because such a method would necessitate the knowledge of the e x a c t nature of sedimentation and diagenetic and catagenetic processes, something that is still beyond the scope of present-day science. Most of the pore pressure prediction methods are based on the following equation: pp
=
o-t - - o- e
(12-4)
where, pp is the pore pressure, at is the total overburden pressure, and ae is the effective stress. The overburden pressure itself is related to the thickness and density of the overlying sediments through the following relationship: Ot
--
paDg
(12-5)
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
315
where Pa is the average bulk density of the rock and D is the total depth. It is important to note that the overburden should be divided into intervals that can be considered to be homogeneous with a representative average bulk density. Of course, the overburden pressure at a given depth is the total pressure exerted by all the overlying rocks and fluids. Therefore, the overburden pressure at a given depth should be calculated by adding together the entire individual interval pressures of all layers above the point of interval. Many analytical models have been proposed to predict abnormal pore pressures. In 1991, Buryakovsky et al. listed some of these models, several of which were derived from the following differential equation: dt - Pm
1 -- ~
~
t
where ~b is the porosity, t is the time, Pm is the density of the matrix and Rd is the rate of sedimentation. For analytical models, it is recommended that the last factor in Eq. 12-6 be determined by knowing the depth versus porosity curve of a region. The above equation was integrated by Buryakovsky and Djevanshir (1976) who coupled the continuity equation with Darcy's law to determine the following model for clay compaction: 4(1 ~b -- ~bo
~o)kfDt h2
(12-7)
where kf is the filtration coefficient, D is the burial depth, and h is the thickness of the compacting clay layer. Other models have been proposed, some of which include the dependence of clay porosity on the depth of burial and lithology of the rocks. For instance, Djevanshir et al. (1986) proposed the following equation: ~bsh - - ~sh0 e - ~ 1 7 6
log A-83.25 log R+2.79)-10 -3 D
(12-8)
where subscripts 'sh' and 'sh0' refer to shale and initial shale, respectively. Other variables: A is the geologic age in millions of years, and R is the relative content of clay layers in an interval of the section for which the clay porosity is being determined. The above formula was reported to have been tested independently on samples from regions of the Volga-Urals oil and gas province, the western part of Siberia, Pre-Caucasus, Venezuela, the Apsheron Peninsula in Azerbaijan, and the Caspian Depression. Another series of models was introduced by Buryakovsky et al. (1982). These models show changes in porosity with depth of burial based on organic growth models, such as: Y -- Yo e Ct
(12-9)
where y is any parameter, Yo is its initial value and c is a factor of proportionality. Another form of this organic growth model is the model of proportional effects. In this model, the parameter y is simply given by the following relationship: Y = Yo e C
(12-10)
There has to be provision for including the effects of a series of factors that might impact the factor of proportionality, c. In this case, y is expressed by the following
316
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
relationship" y-
yoexp (~i=1 ci)
(12-11)
Buryakovsky et al. (1991) developed a system of models based on the above relationship. They are: ht U t -- |
hmin
e chhmint
-- 1-
(12-12)
ho hmin - ho[ 1 - e chhmint] where U is the degree of sedimentation; ho, h t and hmin a r e the thicknesses of the layers before compaction, at time t, and for completely compacted rock, respectively; and Ch is the factor of proportionality. The related density at a time t is given by" PoPrnax
eCpPmaxt
Pt - Pmin - - Po (1 - -
eCppmaxt)
(12-13)
where po, Pt, Pmax are rock densities before compaction, at time t, and the highest value for the completely compacted rock, respectively, and Cp is the factor of proportionality. Finally, a model for porosity change was given by: ~o e-C~t
4~ --
1 - ~bo(1 - eC*t)
(12-14)
where 4~o and 4~ are the porosities before and during the process of compaction of sediments and rocks, and c~ is the factor of proportionality. Buryakovsky et al. (1991) reported successful use of these models in various geological basins in the South Caspian Depression, Dagestan Plain, and Middle-Caspian Depression at depths of 6-9 km.
Simulation of pore-fluid (formation) pressure The description of processes of pore-fluid pressure generation and destruction is obtained from Eqs. 12-2 and 12-3, where fl(xl) = Pi and f2(x2) = P2 are the pore-fluid pressures in the process of their increase and decrease. This dynamic model satisfies the following conditions: (1) A current pore-fluid pressure at any moment of time is a result of dynamic equilibrium among the synchronous processes of generation/destruction of these pressures in a given geologic object. (2) The impact of natural factors affecting generation/destruction of pore-fluid pressures is constant. (3) The rate of change in the pore-fluid pressure in a given geologic object is proportional to the current pore-fluid pressure. (4) Pore-fluid pressures increase/decrease so that a constant portion of the current pore-fluid pressure increases/decreases per unit of time (this condition is not obligatory). (5) The pressure decrease factors per unit of time are equal to the product of the number of factors that increase the pressure by the number of factors that decrease the pressure.
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
317
Dynamic models can be described by a system of nonlinear differential first-order equations as follows: dpl --- e l p l dt
?'lZplp2
(12-15)
dp2 = -ezp2 -+- Y2lPlP2 (12-16) dt where Pl - pl (t) is the pore-fluid pressure during the period of its increase, p2 - pz(t) is the pore-fluid pressure during its decrease, el and 62 are coefficients of pore-fluid pressure change during the periods of its increase and decrease, respectively, and 9/12 and ),,21 are coefficients of interaction of natural factors determining either preservation or change of the pore-fluid pressure. The system of Eqs. 12-15 and 12-16 describe theoretical processes of generation, stabilization, preservation, and dissipation of pore-fluid pressures. Due to the difficulty in simultaneous experimental determination of the coefficients of pressure change and coefficients of opposite influence for some natural factors, numerical simulation using the models is possible in a practical case only when the coefficients having opposite influence may be neglected. For ),,12 and ),,'21 -- 0, Eqs. 12-15 and 12-16 are reduced to two independent equations, one of which describes the abnormal pore pressures and the other a drop to normal hydrostatic pressure. At actual conditions, it is necessary to take into account the self-retarding effect of the process, leading to the following equation: Pl =
PmaxPo eelpmaxt Pmax - Poll - e elpmaxt]
(12-17)
where Po is the initial value of the pore pressure (hydrostatic pressure of water at a depth where sedimentation began), Pmax is the maximum possible pore pressure at given conditions, and t is the time. The coefficient of proportionality calculated for the South Caspian Basin averages 0.02 1/(MPa per million years). The change in pressure with depth is assumed to be analogous to the change in time and may be described by an equation similar to Eq. 12-17. This assumption is probably true for the South Caspian Basin, taking into account a relatively young age of rocks, absence of noticeable structuring, one-phase formation of folded structure, normal bedding of sequential stratigraphic intervals, etc. Other factors can also influence the development of abnormal pore pressure, but in the South Caspian Basin they probably play a subordinate role (Buryakovsky et al., 1986). Using Eq. 12-17, it is possible to describe the dynamics of the pore-fluid pressure (Fig. 12-1A) and to forecast the pore pressure in the reservoir rocks and caprocks at various depths (Fig. 12-1B) for different regions of the South Caspian petroleum province (Buryakovsky and Chilingarian, 1991). Fertl (1976), Fertl and Chilingarian (1976), and Magara (1978) pointed out that the abnormally high pore pressures have different origins and can be caused by various natural factors, often superimposed upon each other. In the South Caspian Basin, for example, with accumulation of thick sand-shale sequences (mainly shales), the most probable mechanism for abnormally high pore pressure development is gravitational
318
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
O
I~-
~E
(A) 60 Pmax
-- 40
O I,,..
d> o_
20
o
Ph~ro 0
2
4
6
8
10
12
Time (t), million years Pressure, MPa 0
20
40
60
1000
.ff
O. (1) a
1O0
120
(B)
2000
E
80
3000 4000 5000
Ph
6000 7000 8000
Fig. 12-1. Results of pore-fluid pressure simulation. (A) Variation in pore-fluid pressure with time. (B) Variation in pore-fluid pressure with depth for three regions of the South Caspian Basin. Ph = hydrostatic pressure, Pmax -- total overburden (geostatic) pressure. (Modified after Buryakovsky et al., 2001, fig. 7, p. 402.)
consolidation with upward filtration of fluids. Gravitational consolidation prevails over the upward flow of fluids at high rates of sedimentation. This leads to a considerable undercompaction of sediments (mainly shales) and development of abnormally high formation pressures (AHFP). Buryakovsky et al. (1986) showed that hydrostatic pressure gradients in shales at a depth interval of 1000 to 6000 m (over 2000 determinations using well-logs) range from 0.012 to 0.024 MPa/m with an average value of 0.018 MPa/m (Fig. 12-2).
N U M E R I C A L MODELS
Numerical modeling of abnormal pressure systems offers some of the most difficult challenges. A geological basin evolves over millions of years or even hundreds of
319
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
p, MPa 0
10
20
30
40
50
60
70
80
90
I00
1000
2000
3000
9
E c"
c~ (b C3
4000
5000
9
6000
7000 "" "~ Fig. 12-2. Pore-fluid pressure in clays versus depth in the South Caspian Basin. r/ = pore-fluid pressure gradient. (Modified after Buryakovsky et al., 1986.) ~
~
"-
"
-
millions of years, with a very large area and thickness. The boundary varies over time with the sedimentary, digenetic and catagenetic processes. In addition, incomplete information regarding the geologic evolution is available and numerical models have to rely on speculation. All these constitute problems in developing comprehensive numerical simulators. Yi-rang et al. (1994) presented the first coupled thermodynamic and geological history model of basin evolution. This helped them obtain solutions to a set of non-linear partial differential equations in the form of abnormal pressure, Pa, paleo-temperature, T, and porosity of the medium, 4~. The following derivation is credited to their work. If V is the volume of a rock in a basin, Vm is the volume of the matrix (solid skeleton), and 4~ is the porosity, the volume of the solid skeleton may be represented by the following relationship: Vm -- (1 -- q~)V
(12-18)
If the solid skeleton is incompressible, the skeleton volume can be considered to have reached a steady state ( ~ tm - 0). With this assumption, the change in porosity can be related to the change in total volume of the basin. Therefore, the transition in porosity
320
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSONJR., A. GUREVICHET AL.
can be given by Ot
=
V
(12-19)
Ot
If crt denotes the overburden pressure upon the rock, whereas pp is the pore pressure, the effective pressure, ere, is equal to (crt - pp). Relative deformation of the rock can then be expressed in terms of the rock compressibility, cf, through Hook's law" OV
(12-20)
= -cfOcr
V By combining Eqs. 12-18 and 12-19, one obtains"
a4~ -at
-cf(1
-05)
aae 57
(12-21)
In the case of compressible flow, with water as the flowing medium, one can obtain:
OOtlOw= PwcwOpp Ot
(12-22)
where Pw and Cw represent the density and compressibility of water, respectively. Eq. 12-23 gives the continuity equation: a (pw4~) V (pwV) -- - ~
(12-23)
Ot
where V - ~0 + ~0 + ~0 ,. the velocity vector, v, can be determined by a momentum balance equation. For instance, by using Darcy's law the following linear equation (the rigorous equation, known as Brinkman equation, yields a non-linear form as discussed later) is obtained: k v- ---V(pp - pwgD) (12-24) #
In the above equation, k is the permeability, # is the viscosity, g is the acceleration due to gravity, and D is the water depth. The last term of Eq. 12-18 represents normal pressure, Ph, in a formation. If the excess abnormal pressure is denoted by Apa, the pore pressure will be given by" pp -
(12-25)
Apa + Ph
In case both the matrix and the pore fluids are slightly compressible, the continuity equation can be re-written as follows: V-
(k)
Vpa
- - [cf(1 - ~ b ) §
--otOPa 2--
(cf(1 - ~ b ) §
O(Ph)
Ot
(12-26)
In the above equation, pressure Pa is a function of space and time. In previous modeling efforts, compositional variation during geological time has been neglected. Yi-rang et al. (1994) solved the energy balance equation and its constitutive relationships; however, the mass balance equation was not solved. The heat balance equation for a dynamic system is given by: OT
V . (ksVT) - CwPwV. (vT) + Q - C s p s ~
Ot
(12-27)
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
321
t-'i'//////-'/-'////
...i!/////i///i!i/ /11/////i/////// i ,i-S~-
2i
-
.:
.." -
-
-
-
-
!
!
i i i i i i i i i i i i i
i
.-Iy ...
.
!
!
-
.. .:
y
i
-
i
.: ...
Z
-
-
.:
d
...,.
Y
.." -
Z
, 9
...- .f ..-..- / _-.- _.../ _.
Fig. 12-3. Schematic diagram of the domains of abnormal and normal pressure regions. (Modified after Yi-rang et al., 1994.)
where, T (x, y, z, t) is the paleotemperature function; ks, Ps, Cs are the thermal conductivity, density, and specific heat of a sediment or rock, respectively. The term, Q is the heat source/sink and Cw is the specific heat. Fig. 12-3 shows the schematic of the domains for the abnormal and normal pressure regions. The definition of domain, ~2, is such that S2 -- ~"~1 [,-j ~'~2, where f21 and S22 are regions of abnormal and normal pressure, respectively. The abnormal pressure equation (Eq. 12-12) is solved for the ~1 region, whereas the abnormal pressure is set to zero for the region S22. The porosity equation is given by substituting u and Pa in Eq. 12-7. As a result, 005
__ -cf(1
at
-
- qS)
(OUt Opa t- Oph'] at at -~/
(12-28)
The constitutive relationships can be formulated based on laboratory data or experience. Yi-rang et al. (1994) used the following viscosity and permeability relationships" # - (5.3 +
3.8AT
-0.26AT3)
-1
(12-29)
where (TA T =
150) 100
and k
-
a~ b
(12-30)
Compressibility of the rock can be related to porosity by a logarithmic function. Density of the sediment is given by the following equation: Ps - ~bpw + (1 -4~)Pm
(12-31)
322
M.R. ISLAM, L. KHILYUK,G.V. CHILINGAR,S. KATZ,J.O. ROBERTSONJR., A. GUREVICHET AL.
9
9
9
6
b
~u
~
"-"'~
9
9
9
9
9
o
b
*
',"'~ .a
''~ ,
"~- ^
-- _--- -- S
9
*
_
"
"
b
e
_ , e ~" ' '
* ~
-
7
-
,
L
j
/N
~
Fig. 12-4. Schematic diagram of the basin with abnormal pressure. (Modified after Yi-rang et al., 1994.)
The heat conductivity of the sediment is equal to" ks-
kr I ~ - )
(12-32)
~
Specific heat of the sediment is given by: Cs - (1 - r
+ S2r(T - To)] + r
+ E2w(T - To)]
(12-33)
In Eq. 12-33, S-2r and S-2w represent proportionality constants between specific heats of rock and fluids, respectively, and temperature. These proportionality constants can be determined in the laboratory. Yi-rang et al. (1994) used 52r = 0.769 x 10 -3 and ~w = 0.219 x 10 -3 in order to solve for abnormal pressures in a basin as sketched in Fig. 12-4. By using a 15 strata or a 15 x 6 matrix, they introduced very large time steps in order to simulate 5 million years of history. The grid sizes in the x, y direction were 1.5 km, whereas in the z direction the grid size was 20 m. Numerical simulation results showed that the approximate abnormal pressure, paleotemperature and thickness displayed similar trends as observed by geologists in a petroleum deposit. Figs. 12-5-12-7 show some of the results of simulation of 330 million years of history. Fig. 12-8 shows the movement of the hot plume over millions of years.
TECTONIC AND LITHOLOGICAL MODELING
Yu and Lerche (1995) have presented two-dimensional numerical modeling results. In this particular model, they gave three-phase flow equations with the continuity equation.
323
MATHEMATICALMODELING OF ABNORMALLYHIGH FORMATION PRESSURES 200
160
0
2~
120
,,,11--
i~. 80
E 40
!
I
I
I
0
1050
21 O0
3150
I
4200
5250
z (m) Fig. 12-5. Temperature (~
versus depth (m) at node (4, 2). (Modified after Yi-rang et al., 1994.)
200
o • 160 ~
~
120
8040 i 0
II
0
1050
9
21 O0
II
3150
II
4200
|
5250
z (m) Fig. 12-6. Temperature (~
versus depth (m) at node (8, 2). Modified after Yi-rang et al., 1994.)
They modeled overpressure development in the presence of faults, a low-permeability salt sheet, or a shale layer. This work was an improvement over the previous work of Barr et al. (1993) who reported modeling of faults in a Nigerian basin. Yu and Lerche (1995) modeled the fault as a hydraulically open channel by assigning the depositional surface sand permeability values to the region (Yu, 1992). This is an important aspect of modeling faults as it allows for a high-permeability zone to exist in the neighborhood of
324
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
200
0
0
0
E
160
120
80
40
i-
i
0
1050
i
21 O0
i
l
3150
4200
i
5250
z (m) Fig. 12-7. Temperature (~
versus depth (m) at node (14, 2). (Modified after Yi-rang et al., 1994.)
x (m) 500
0
3
6
9
12
15
18
21 ----
1000 1500 2000
2oo1 3000
1 10 Million years
3500 4000 4500
410 million years
5000 5500
j
Fig. 12-8. Distribution of temperature in basin deposits after 40, 110 and 410 million years. Depth in meters is plotted on the ordinate. (Data from Yi-rang et al., 1994.)
325
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
Excess Pressure, kg/cm 50
1O0
150
200
250
1000
3000
Far from salt
E 2000
6000
.ff
(-
,.i,m,
CL
(b
r~
3000
4000
~9
:-~%"~
Salts h e e t
"%% ~ W i Within salt % ,~ ~:,i~!
9000
c~
12,000 15,000
5000 Fig. 12-9. Effect of salt barrier on generation of excess pressure. (Modified after Yu and Lerche, 1996.)
the fault since the onset of the fault through the present time. This allows the fault to remain a dominant conduit for fluid flow in the section as well as fluid loss along the open fault plane after fault initiation and then bleeding off overpressure from both flanks of the fault. For the same reason, sealed faults (e.g., sandy shale section) would show no pressure anomalies. Numerical simulation results showed that hydraulic 'openness' or 'closedness' for the region around the fault changes the character of fluid flow and the development of overpressure with time. The salt sheet was modeled as a permeability barrier, which serves as a trigger for overpressurization and a slower rate of compaction of the underlying formations. This example deals with a basin in which an abnormally pressured, flat-layered shale section is initially deposited. In the middle of this section, a 6-km-wide and 500-m-thick salt body is deposited. A constant sedimentation rate of 100 m / M a was allowed to form on top of the salt body. For a permeability of salt bed of 10 -5 mD, a constant density of 2.2 g / c m 3, and horizontal permeability of 5.10 -5 mD, present-day abnormal pressures were predicted (see Fig. 12-9). This figure shows the presence of overpressurization due to a burial rate faster than the fluid escape rate for the region outside of the salt basin. The overpressurization is much higher in the formation below the salt bed. This is due to the fact that the salt bed acts as a permeability barrier. The degree of overpressurization in the section above the salt sheet is reduced because the supply of fluid from greater depths is diminished. The overall effect manifests itself in a larger increase in excess
326
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
0
10
Porosity, % 20
30
0
50 0
looo - I
Within salt\
i
Far from salt
I'- 3000
-- 6000
" i
-
4000
~qlP""
t
E~ 2000 -"-.C D. 03000
40
Ill
,i
,4,-,,-
(" Salt S h e e t
D. - 9000 C l
12,000
15,000
5000
Fig. 12-10. Effect of salt barrier on abnormal pressure and porosity. (After Yu and Lerche, 1996.)
pressure across the salt body. The overpressurization always reduces compaction of a sedimentary layer. Figs. 12-9 and 12-10 show the porosity for the salt region compared to that of the outer region. Formations underlying the salt sheet have a higher porosity than that predicted by the regional trend. Numerical simulation results also show that dominant effects emerge from the presence of a low-permeability region (shale, salt, or tight carbonate), as the sediments are deposited quickly resulting in fluid entrapment. This is also manifested by porosity retention in an overpressured zone as well as in an increase in thermal gradient. The increase in thermal gradient, however, can be offset by thermal disequilibrium due to sufficiently rapid deposition. In terms of modeling shale barriers, results similar to those of Yu and Larche were also reported by Best and Katsube (1995). These authors, however, did not use the three-phase flow equations in defining fluid movement in the reservoir. More recently, Saghir and Islam (2001) presented a more rigorous approach for modeling fractures and faults. They improved the well-known Warren-Root model to develop a comprehensive model for fractured reservoirs. The same model can be employed in modeling faults. Their model considers the Navier-Stokes equation in the fracture (channel flow), while using Brinkman equation for the porous medium. Unlike the previous approach, the proposed model does not require the assumption of orthogonality of fractures (sugar cube assumption), nor does it impose incorrect boundary conditions for the interface between the fracture and the porous medium. Various cases studied include different fracture orientations, fracture frequencies, fracture widths, and permeabilities of the porous medium. Finally, a series of numerical runs provided validity of the proposed model for the cases for which thermal and solutal effects are
327
MATHEMATICALMODELING OF ABNORMALLY HIGH FORMATION PRESSURES
f,," Iiff2~/r--,
I
w,tk
!a} ,~ = l m i n
!
b) -c = 2 m i n
, c] -c = 3 m i n
-
I
11 d}
9= 4 m i n
Fig. 12-11. The evolution of the solutal profile in the presence of a vertical fracture. (After Saghir and Islam, 2001.)
important. Fig. 12-11 shows the evolution in the solutal profile in the presence of a vertical fracture for various dimensionless times. Similar scenario exists in the presence of a vertical fault. Figs. 12-12 and 12-13 show streamlines and thermal profiles, respectively. It is clear from these figures that the vertical fractures block propagation of both thermal and solutal plumes. In this process, however, the concentration profile is more affected than the temperature profiles. From the stream function contours, one can see that each compartment, as separated by a vertical fracture, has a convection cell. Such a multi-cellular pattern would not emerge if fractures were treated with the dual-porosity, dual-permeability approach. The time evolution of both thermal and solutal convection indicates that a steady state is reached more easily when fractures are vertical. Similar observations can be made for the case for which two or more vertical or slanted fractures are used.
NUMERICAL CRITERION AND SENSITIVITY ANALYSIS FOR TIME-DEPENDENT FORMATION PRESSURE IN A SEALED LAYER
Fluid pressure different from hydrostatic pressure has been observed in many oil and gas fields and extensively studied during the last 40 years. Mathematical models of various complexity have been used to explain and predict variation of formation pressure with depth and in time (e.g., Bredehoeft and Hanshaw, 1968; Fertl, 1976; Bradley, 1975; Fertl and Chilingarian, 1976; Sharp and Domenico, 1976; Bishop, 1979; Bethke, 1985; Whittaker, 1985; Dobrynin and Serebryakov, 1989). Still, relationships
328
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
c) 1: -
3 min
d) "~ -
4 min
Fig. 12-12. Evolution of the streamlines in the presence of a vertical fracture. (After Saghir and Islam, 2001.)
;":;...... IIi'1
!I--7
r
Ill
iii
~ ill
i(~
k
liJ
"
I!!! 1
Isl Iit
l"il ,' ~ Ill
i!I',i,/
J- ........
'\l~t "f~ it
t ,> I I
b) I: - 2 rain
1 min
,,J/ .............
IiI~
"'ll
I<.', I j,~i
I,, I I
a) -r -
I ,',;'----......
iLt I
v!t
Ill
7,-."5-;-..... - . . . .
......... "....... " ............
t/
"
I./
i
.,i/._ ..... ...i-
,.! ,,......"......... .
Wti (
c]
9-
3 min
d] I: - 4 min
Fig. 12-13. Evolution of the thermal profile in the presence of a vertical fracture. (After Saghir and Islam, 2001.)
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
329
between the parameters of medium and the characteristics of time-dependent formation pressure are not fully understood.
Modeling of mean value for time-dependent formation pressure The following situation is studied here when abnormal pressure is generated by changing the time for the process of sedimentation, which, in turn, causes variation in time of rate of fluid flow into the formation. The abnormal component is defined as the difference between the actual and hydrostatic formation pressure. The model used is a combination of two layers of finite thickness with fluid flowing into the permeable layer from the underlying half-space (sediments). The upper layer is a seal with low porosity and low permeability, whereas the lower layer has higher porosity and higher permeability. The abnormal formation pressure in the permeable layer is characterized by its average value: 1
/5 -- (h2 - hi)
fh2
p(h) dh
(12-34)
1
where h is the depth, p(h) is the fluid pressure at depth h; hi and h2 are the depths of the upper and lower boundaries of permeable layer, respectively; and/5 is the mean value of formation pressure in the permeable layer. It is assumed that in the upper seal layer the pressure is hydrostatic and written as PnThe methodology is based on the assumption that the process of sedimentation causes rock compaction, which in turn leads to increased flow of fluids from the underlying half-space into the permeable layer. A schematic diagram of this model is presented in Fig. 12-14. It is assumed that a layer with high porosity and permeability has a thickness Ahc, and is overlain by a seal layer (caprock) having a thickness Ahr at depth h. Flow of viscous fluids through an elastic medium and variations in formation pressure caused by the flow are described by the Fourier partial differential equation in the following form (Bear, 1972):
32p 1 Op = (12-35) Oh2 X Ot where p(h, t) is the fluid pressure at a depth h at time t, and X is piezoconductivity coefficient of the formation: kc X-
~c~[~ + ~f]
(12-36)
where ~ is the irreversible compaction coefficient: --
1
A~b
0.014(1 - ~)~b Ah
(12-37)
A~ where ~-~ is the porosity gradient, h is the depth, kc is the permeability of the reservoir, is the porosity, j3f is the compressibility coefficient of formation fluids, and/~c is the viscosity of formation fluids. Solution of Eq. 12-35 at the segment is analyzed for the following initial and boundary conditions.
330
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
P h
ho
.////, y,
-
.
.
/
,
,
.
.
,''''''" I Sand [I
....
I] Shale [withnormal hydrostaticpressure of pore fluids}
Fig. 12-14. Schematic model of a sealed permeable layer. (Modified after Khilyuk et al., 1994, fig. 1, p.
134.) At the time t -- 0, the abnormal pressure p, satisfies the following equation:
p(h, O) - po(h),
h ~ [h~, h2]
(12-38)
where
Ahc
po(h) dh - p~
(12-39)
The lower boundary condition can be given on the basis of Darcy's law. The vertical linear velocity of fluids caused by compaction of underlying layers can be written as follows: kc Op Aqv -for h - - h 2 (12-40) #c Oh where Aqv is the linear velocity of excessive vertical flow of fluids. This allows specifying the lower boundary condition for Eq. 12-35 in the following form: Op #cAqv = for h -- h: (12-41) Oh kc
MATHEMATICALMODELINGOF ABNORMALLYHIGH FORMATIONPRESSURES
331
To obtain the upper boundary condition, one should take into account that shale (seal) permeability may be of a different nature than that of sands due to presence of bound water. Bound water is rheologically viscoplastic and has noticeable shear strength. Therefore, linear Darcy's law for viscous fluid flow is inapplicable. In many cases, non-linear fluid flow of viscoplastic fluid can be linearized and written in the following form:
Aqc --
kr[G-ao] G>GoI 0 G<_Go
I
Ur
(12-42)
where G is the pressure gradient, Go is the fictitious initial pressure gradient, kr is the permeability of overlying shale, and #r is the viscosity coefficient of fluids in the pores of shale. Then, assuming that G > Go, the upper boundary condition can be obtained from the equality of the linear velocities of fluid flow below and above the upper boundary of the permeable layer: ~--~)limh__>h~+(~c Op
limh--->hl_ (kr#r [ ~
- GoJ)
(12-43)
Op In the right hand side of Eq. 12-43, the partial derivative Vfi is approximated by the mean gradient of the formation pressure in the seal:
ap
=
Oh
( / 3 - Pn)
(12-44)
Ahr
where Pn is the hydrostatic pressure, so that the boundary condition takes the following form:
OP=#ckr[ ] O#rkc h(~-pn)-G~ Ahr
for h -- hi
(12-45)
FORMATION PRESSURE IN THE CASE OF CONSTANT FLUID FLOW THROUGH THE LOWER BOUNDARY OF THE FORMATION
h2)
One can start with the integration of both parts of the Eq. 12-35 on the segment (hi, (Dobrynin and Serebryakov, 1989):
i f h2 a2p
Ahc
l fh2 aPdh
,-~dh-AhcX
(12-46)
~ 0--7
To compute the integral of the left side of Eq. 12-46, the two boundary conditions (Eqs. 12-41 and 12-45) are used. This leads to:
l fh~OZP Ahc
1 -~
1 [Aqv#c
dh -- Ahc
kc
kr#c(fi-Pn_ao)] kc #r
Ahr
(12-47)
The fight side of Eq. 12-46 is equal to:
1 fhh20Pdh_ 1 0 [~fh2 0p ] ~ 0---7 XOt -~-~pdh
Ahc
10/5 -
X
3t
(12-48)
332
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
After substituting Eqs. 12-47 and 12-48 into Eq. 12-46, one obtains an ordinary differential equation: d/3dt -- AhcX [ Aqv/zckc
kckrlzc(P-Pn-G~ Ahr
(12-49)
for the average pressure with the initial condition. Let P --/5 - Pn-Having applied the Eq. 12-35 for the variable P, one obtains:
d P _--x [ A qhcv l z C dkct
kckr/~C/zr ( ~ h r - G ~
(12-50)
with an initial condition of: P(0) = P a - Pn
(12-51)
Introducing parameters A and B of the form: A =
X krlZc AhcAhrkclZr
(12-52)
X Aqv/Zc Xkr#c 4- ~ G o Ahckc Ahckc/zr Eq. 12-50 transforms into: B =
dP
+ AP = B
dt with the initial condition of (Eq. 12-51):
(12-53)
(12-54)
P(0) = P a - P n The solution of Cauchy's problem for the ordinary differential Eq. 12-54, with the initial condition of Eq. 12-51, can be written as follows: B
P(t) -- ~-(1 - e -at) 4- (Pa - Pn) e-at
(12-55)
According to Eq. 12-55, the variation of the abnormal component of formation pressure in time is defined by three parameters: the starting value of the abnormal component Ap = (Pa -- P,), ratio B/A and the relaxation coefficient A. The first derivative of P (t) with respect to t is:
P' = B - AP = [B - ( P a - pn)a] e-at
(12-56)
Analysis of the sign shows that:
(1)
P ' ( t ) < o,
B
if - < ( p a - pn) A B
(2) P'(t) = 0, if -- = (Pa - Pn) A B
(3) P'(t) > 0, if -- > (Pa - Pn) A
(12-57)
(12-58)
(12-59)
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
333
In the first case (Eq. 12-57), the abnormal formation pressure decreases. In the second case (Eq. 12-58), abnormal pressure can be kept at the same level for infinite time. In the third case (Eq. 12-59), the formation pressure increases. The first derivative of the formation pressure (Eq. 12-56) determines the rate of change of formation pressure in time. In all cases, this rate converges to zero with time tending to infinity. The relaxation coefficient A determines the rate of change of the abnormal component of pressure. The bigger the value of relaxation coefficient, the faster the rate of change of formation pressure in time approaches zero.
Criterion for the type of time-dependent variation offormation pressure Eqs. 12-57 to 12-59 define the type of time-dependent variation of formation pressure and show whether the formation pressure will increase in time or will drop to the hydrostatic level. According to Eqs. 12-52 and 12-53, the key parameter B/A is equal to:
O Ahr[Aqv--
G~]
If the assumption kr Go << Aqv (12-61) #r is valid (this corresponds to the formation with essentially abnormal pressure) one obtains"
B a =AqvAhr(kr)-l #---~
(12-62)
Eq. 12-62 has a geological meaning: the type of abnormal formation pressure timedependent variation is determined by the ratio of excessive vertical linear velocity of fluid (flow to the porous layer from the underlying rocks) to the permeability of overlying layers (the flow capacity of the seal). It is noteworthy, that the process of pressure evolution does not depend on the thickness of the permeable layer.
Box-type fluid flow Let U be the sedimentation rate in meters/106 years and Uc be the critical sedimentation rate below which there is no flow. (h -- h') U = (12-63) At where h' and h are the depths at the base of deposits at time t and (t + At), respectively. Assuming that the differential sedimentation rate ( U - Uc) is constant at the time interval [0, t l ] , and that after the time moment t, sedimentation process stops, i.e., U - Uc -- const, for t < tl
(12-64)
334
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
U-
Uc = 0 for t > tl
(12-65)
Eqs. 12-64 and 12-65 imply that (B = const > 0) at the interval [0, t~], and B = 0 after the time ta. For this case, the evolution in time of the average formation pressure is described by the Eq. 12-55 with the initial condition of Eq. 12-56 at the time interval [0, tl], and the equation dP
4- AP = 0 dt with the initial condition of: B P(fi) -- ~-(1 - e -at') 4- (Pa - Pn) e-at' for t > tl
(12-66)
(12-67)
Eq. 12-66 has an obvious solution for the time interval (t < t~):
P(t) --
i
~(1 -e-
) 4- ( P a - Pn)
(12-68)
According to Eq. 12-68, the mean value of the formation pressure in the permeable layer decreases exponentially if there is no liquid flow from the underlying formations.
Sensitivity analysis for the mean value of the formation pressure in the sealed permeable layer In the previous sections, it was shown that evolution in time of the mean value of the formation pressure in a sealed permeable layer might be described by two main characteristics: (1) Threshold ratio ~, which discriminates between three possible types of formation pressure development: B = -(12-69) A (2) The relaxation coefficient, A, defines the time scale of formation for pressure processes. The larger the relaxation coefficient, the faster the value of the formation pressure changes in time. This allows formulating sensitivity characteristics for the development of formation pressure in time in the form of two sensitivity vectors S , and Sa:
S , = grad(~)
(12-70)
SA = grad(A)
(12-71)
where coordinates of the sensitivity vectors are the partial derivatives of the characteristics tp and A with respect to the parameters of the medium: S. -
SA-
~,
.....
OXl OX2
OXN
( OA OA OA ) Oxi' Ox2 ..... OXN
(12-72)
(12-73)
MATHEMATICALMODELINGOF ABNORMALLYHIGHFORMATIONPRESSURES
335
where x is the vector of parameters defining the formation pressure, and N is the dimension of x. It follows from Eqs. 12-72 and 12-73 that: qJ(x + dx) ~, qJ(x) + Sq, 9 dx
(12-74)
A(x + dx) ~ A(x) +
(12-75)
S A 9 dx
where dx - ( d x l , . . . , dxn) is a vector of differentials, and symbol * denotes the scalar product of two vectors. Eqs. 12-76 and 12-77 give dependence of the derivatives of ~P and A with respect to the initial pressure gradient: Oq/
OGo
= Ahr
(12-76)
OA = 0 (12-77) OGo It follows from Eqs. 12-76 and 12-77 that the initial gradient Go may be ignored if the thickness of the permeable layer is small, because the sensitivity coefficient 3Go 0~, approaches zero with decreasing thickness of the permeable layer. If the permeable layer has a large thickness, however, this parameter should be taken into account for the calculation of formation pressure. According to Eq. 12-76, the influence of the initial gradient on the criterion q~ increases with increasing thickness of the permeable layer, whereas the relaxation coefficient A, which defines the rate of decrease of formation pressure, does not depend on this parameter. Eqs. 12-78 and 12-79 give derivatives of qJ and A with respect to the linear velocity of excessive vertical flow of fluid: 0qJ Ahr (12-78)
0(Aqv) OA O(Aqv)
= 0
(12-79)
According to Eqs. 12-78 and 12-79, dependence of the threshold q~ from the linear velocity of liquid flow increases with increasing thickness of the seal and decreasing permeability of the seal. The relaxation parameter does not depend on the excessive linear velocity of flow. Eqs. 12-80 and 12-81 give derivatives of the q~ and A with respect to the thickness of seal and permeable layer and from piezoconductivity: Oq/ O(Ahr)
=
q/
(12-80)
Ahr
3A
A
O(Ahr)
nhr
(12-81)
336
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
Eqs. 12-80 and 12-81 show that both parameters ~P and A are sensitive to variations in the thickness of seal, and the sensitivity increases with decreasing thickness of the seal. Finally, Eqs. 12-82 and 12-83 characterize sensitivity of the parameters qJ and A to variations in piezoconductivity: O~ OX
(12-82)
=0
OA
A = -(12-83) OX X According to Eqs. 12-82 and 12-83, the threshold qJ does not depend on the piezoconductivity, whereas the sensitivity of the relaxation coefficient A decreases with increasing piezoconductivity. Eqs. 12-70 to 12-77 show that all parameters defining mean value of the formation pressure and its evolution in time may be divided into three groups: (a) Parameters that do not influence the value of formation pressure threshold (e.g., piezoconductivity and thickness of the seal). (b) Parameters that do not influence the relaxation coefficient (e.g., linear velocity of excessive flow and initial gradient of the Darcy law). (c) Parameters that influence both threshold and relaxation coefficient (e.g., thickness of the permeable layer). Criterion B/A and relaxation coefficient for the Western Kuban region in the southern part of Russia To give an example of the values of the criterion B / A and the relaxation coefficient A, the writers used data for the Western Kuban region in the southern part of Russia (see Dobrynin and Serebryakov, 1989). The criterion and relaxation coefficient were calculated for the following combination of thicknesses for the permeable layer and the caprock layer: A h c = 100 m, A h r = 3 0 0
m.
Other parameters that define the criterion and relaxation coefficient were taken as follows: / 3 - 2 0 • 10 -3 (MPa) -1, / ~ f - - 0 . 4 • 10 -3 (MPa) -1, q~ -- 0.2, kr/ftr - 2 • 10-5 ink- m2/(pa 9sec) The depth of the permeable layer h 0 = 3 0 0 0 m, pn(3000 m ) = 3 2 . 3 4 MPa,
p ~ = 1.3pn
For the evaluation of vertical linear velocity of the fluid flow the writers used the following relationship: Aqv = C~cpv(h)(U - Uc) where U - Uc is the differential sedimentation rate, v(h) is the compressibility factor of rocks due to sedimentation [v(h) ~ (h - h ' ) / A h , where Ah is thickness of sediments
337
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESS URES
accumulated during the time interval At, v(h) is the ratio of the rate of subsidence (h - h')/At to the sedimentation rate, Ah/At, v(0) -- 1 and v(h) tends to zero for large depth], ~b is porosity, and 0 < o~ < 1 is the coefficient that indicates the share of the flow of fluids in an upward direction. One can assume o~ = 1/2. For h0 = 3000 m, the reasonable value of the compaction coefficient is v(ho) -- 0.25. For this territory, the differential sedimentation rate (U - Uc) varies widely from 0 to 300 m / ( y e a r x 106). In this illustration, the writers used the value of 100 m for (U - Uc). Using the above assumptions:
B/A = 1.05 MPa, ( P a - Pn) = 10.7 MPa, A = 5.4 x 10 -6 (year) -1. Substituting values of B/A and ( P a - Pn) in Eq. 12-57, one can conclude that P'(t) < 0 and, therefore, the formation pressure in this region decreases with time.
Examples offormation pressure development Illustrations of possible variation of formation pressure in time are given in Fig. 12-15. The curves of the formation pressure shown in this figure were calculated for (Pa - Pn) = 10.0 MPa and
B/A = [6.0, 7.5, 9.0, 10.5, 12] MPa for the box type flow of the liquid into the permeable layer. The flow is constant up to the time t = 4 x 105 years and after that it is zero. This time corresponds to the sharp change
12 ~ lO
a--
E2
0 !1_
0
|
|
lxlO
~ 2x10
i
5
3x10
i
5 4x10
i
s
5x10
1
s 6x10
I
5
7xlO
~ 8x10
5
Time, years Fig. 12-15. Time-dependent formation pressure for the box-type fluid flow. At time t = 4 x l05 years, the fluid flow from the underlying formation drops to zero. (Modified after Khilyuk et al., 1994, fig. 2, p. 143.)
338
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
in the shape of curves, followed by the exponential decrease in formation pressure. For the time t < 4 x 105 years, the formation pressure increases with increasing time for the last two values of the threshold B/A, which satisfy the condition B / A > (Pa - Pn)- For the three first values of the threshold such that B / A < (Pa - Pn) the formation pressure decreases with time. For t > 4 x 105 years, formation pressure drops exponentially at the same rate as defined by the relaxation coefficient, because for all curves there is no liquid flow from underlying formation into the permeable layer. Discussion Numerical methodology for prediction of variation in time of a mean value of formation pressure in a layered medium was discussed above. The model used by the writers was a combination of two layers of finite thickness. The upper layer is a seal with low porosity and low permeability, whereas the lower layer has a higher porosity and permeability. The methodology is based on the assumption that the process of accumulation of sediments causes rock compaction, which in turn leads to increased flow of fluids from the underlying formation into the lower, permeable layer at a constant rate. Depending on the rate of flow of fluids into the permeable layer, the starting formation pressure, thickness of the seal, permeability of the layers, and other parameters of the model, three scenarios are possible: (1) formation pressure may increase in time, (2) it may stay unchanged, and (3) it may decrease in time. The actual scenario will be defined by the value of the B / A ratio where A and B are defined by the Eqs. 12-52 and 12-53, and the initial value of the abnormal component of the formation pressure. The B / A ratio does not depend on the thickness and permeability of the permeable layer. It is determined by the rate of fluid flow to the collector and the permeability of the seal. If B / A > (Pa - Pn), then the abnormal component in the formation pressure will increase in time asymptotically converging to the value B/A. In this case, the greater the thickness of the seal and the faster the sedimentation rate, the larger will be the rate of increase in the formation pressure. If B / A < (Pa - Pn), then the abnormal component of the formation pressure will decrease in time to the level B / A . Two models were considered for the time-dependent fluid flow into the permeable layer: (1) Rate of fluid flow jumps from zero to a constant value and does not change indefinitely. In this case, the formation pressure changes exponentially and converges to an asymptotical value of B / A . Difference between the actual value of abnormal component of the formation pressure and its asymptotical value decreases to 0.5% at a time (from the start of the process of liquid flow) equal to t -----2/A, where A is the constant defined by Eq. 12-52. (2) The rate of fluid flow increases from zero to a constant value at time t = 0 and keeps constant in the time interval [0, tl]. After that it drops to zero. In this case, at time t > tl, the abnormal component of the formation pressure drops exponentially and decreases to a level lower than 0.015 • P ( q ) at t > 2 t j / A . It was shown that evolution in time of the formation pressure in a two-layer system may be described by two major characteristics: (1) threshold qJ - B / A and by relaxation
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
339
coefficient A that defines the time scale of the development of formation pressure. This allows one to formulate sensitivity characteristics for the development of formation pressure in the form of two sensitivity vectors, S , and Sa, and to divide parameters of the formation pressure into three groups: (a) parameters that do not influence the value of formation pressure threshold (e.g., piezoconductivity and thickness of the seal), (b) parameters that do not influence the relaxation coefficient (e.g., linear velocity of liquid flow and initial gradient), and (c) parameters that influence both threshold and relaxation coefficient (e.g., thickness of the permeable layer).
IDENTIFICATION OF CONDUCTIVITY FUNCTION FOR PETROLEUM RESERVOIRS
Conductivity is one of the important characteristics of petroleum reservoirs. Its changes in space and time can describe lithological properties of the reservoir, determine direction and rate of flow of fluids, and indicate possible abnormalities in the formation pressure (Fertl and Chilingarian, 1976; Fertl, 1976; Dobrynin and Serebryakov, 1989). Because of the complexity of the description, most of the contemporary models and examples of numerical simulation of reservoir pressure behavior are developed under the assumption that the reservoir permeability is constant in time and space. This constant parameter is usually evaluated by virtue of direct laboratory testing of the rock samples or by extrapolation of the results obtained for analogous geological conditions (Fertl, 1976; Ungerer and Pelet, 1987). Obviously, this evaluation is just a zero order approximation for the formation of interest. In addition, the question about its applicability for a particular reservoir demands meticulous informal considerations regarding a degree of similarity of the particular reservoir and a chosen analog, which involves a great amount of additional information. Because of these limitations, almost all of the related studies exploit one numerical value for the reservoir permeability parameter and, as a consequence, they develop and utilize only the point concept of this parameter. Meanwhile, changing in space (with depth) permeability provides essential information about variations of lithological parameters with depth (e.g., shale/sand ratio and fracture density and orientation) and indicates transition zones to possible formation pressure abnormalities in the reservoirs. The latter is of a great importance to the petroleum industry, because this information allows making correct decisions to exclude dangerous complications (such as, 'kicks' and 'blowouts') in drilling and exploitation of hydrocarbons reservoirs, which are caused by formation pressure abnormalities. The first attempts to treat permeability as a variable were made in connection with the discussion of applicability of Darcy's law to slow flows (De Marsily, 1981). Permeability of sedimentary rocks can vary in a broad range from less than 10 -9 to more than 1 D (e.g., Ungerer and Pelet, 1987). Investigators tried to link these variations to the porosity of rocks, for example, by the Kozeny-Carman equation (Scheidegger, 1960). Taking into consideration the fact that porosity is a function of depth described by plausible exponential models (Dobrynin and Serebryakov, 1989; Fertl, 1990), one can conclude that there is a strong dependence of permeability on depth. Even homogeneous sedimentary rocks manifest anisotropy on a large scale (De Marsily, 1981). In the basin modeling problems, one is to rely primarily on the
340
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
large-scale heterogeneous permeability distribution, e.g., due to sand/shale interbedding and presence of fractures (Bethke, 1989). For a particular basin, permeability can be adequately described by a specific conductivity function x(h) [or X(X), X 6 R 3 in 3D problems]. This discussion is aimed at the development of indirect methodology for the conductivity function identification on the basis of measurements of the formation pressure for a set of successive depth points. Formation pressure is the most important integral variable of a reservoir. It characterizes the state of producing formation not only at the point of measurement, but also in the near proximity. It may be shown, that a succession of pressure measurements at various depth points of the formation can provide sufficient information for the identification of the conductivity (permeability) function.
Basic mathematical model of the pressure distribution in petroleum reservoirs If the flow of fluids in the formation of interest obeys Darcy's law, then the formation pressure distribution in the collector can be described by a certain partial differential equation. If, in addition, one can neglect the temperature variations (for example, for shallow basins) and assume that there is no specific horizontal direction of flow, then for the description of the pressure distribution one can apply a partial differential equation of the following form (Bear, 1972):
Op
O(k:Op)
l
Odp
(12-84)
It can be rewritten as follows:
0 (~Op)_ Oz \ ~
1 04) Op 1 - cb at ~ cbfl 0-7
(12-85)
where p(z, t) is the formation pressure at the depth z and time t, ~b is the porosity, fi is the compressibility of the pore fluids, k: is the vertical permeability of the rocks, and (')h -- ~ is the first-order partial derivative of the expression (.) with respect to h. Further simplification can be obtained if one computes the first derivative of porosity with respect to time:
a~
a~ a~ =
at
(12-86)
oct at
where o- is the effective stress which can be expressed as follows" o- = L - p
(12-87)
where L is the total overburden load, and p is the pore pressure. On assuming that L is constant:
04) Ot
=
04) ap
(12-88)
Op Ot
Thus"
1 1 -
1 4,
4~(1 -
Op 4,) a t
(12-89)
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
341
Introducing the compressibility of the rocks fir: ~r
1
fir - -
40 Op one can rewrite Eq. 12-85 in the following form: r
OzO(kzOp)~~z-If
kz and #
(12-90)
-
~b(fl -~- flr)~Op 7
(12-91)
are considered constant, then
kz OZp =
4~(/3 +/~r)
Op
(12-92)
After simplification,
OZp X OZ2
--
Op Ot
(12-93)
where X is the piezoconductivity coefficient which is defined by the following formula: X-
k
(12-94)
/_re (/~r -}- /~f)
where k is the permeability, # is the viscosity of the formation fluid, ~b is the porosity of the formation, /~r is the irreversible compaction of formation rocks, and /~f is the compressibility of the formation fluid. All these parameters are supposed to be constant for the layer of interest. According to the mass conservation law, large-scale conductivity variations are reflected in the formation pressure changes according to Eq. 12-93. Information about the pressure variation with depth should be available for all existing and developed wells. That is why the use of the formation pressure data for indirect evaluation of the conductivity function seems to be attractive.
Indirect evaluation of the conductivityfunction If the values pz(h, tl), pz~(h, tl), and pt(h, ta) are available, then the procedure of the conductivity function evaluation is simple. It is necessary to collect the values of these derivatives for a set of successive values of h at time tl. Thus, Eq. 12-93 would produce a set of successive values of X (h) for the chosen values of h. These values could then be arranged in a table form or used for a suitable analytical approximation. However, this situation is unrealistic, and one is obliged to use only a set of pressure measurements for the purpose of evaluation of the conductivity function. Another possible approach is to apply a finite differences approximation in order to estimate the quantities ph, Pa, and Pr in Eq. 12-93. The corresponding finite differences can be calculated using only the pressure data. The main problem in this approach is the instability of numerical approximation for the derivatives (Tikhonov, 1968). This means, that small errors in primary pressure data can lead to big errors in the resulting estimates of the pressure derivatives. The most attractive approach is the usage of some integral analog of Eq. 12-93 to avoid the operation of numerical differentiation. There is a number of procedures
342
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
of numerical integration that yield computationally stable estimates for integrals (e.g., Hamming, 1962). If one integrates Eq. 12-93 twice with respect to z in a bounded area and then applies a suitable procedure for numerical estimation of the obtained integrals, then an algebraic equation with respect to X can be obtained (assuming that X is constant). If X depends on h, then it is possible to choose a suitable form of analytical expression for X with some undefined coefficients: for example as the exponential polynomial of sufficient degree. Next, the same double integration procedure, repeated for a number of areas no less than the number of terms of the approximating polynomial, leads to the system of linear algebraic equations with respect to the undefined coefficients of approximation. Determination o f the piezoconductivity coefficient layer by layer
The easiest possible way to apply an idea of integral analogue is to study the formation of interest layer by layer. For thin layers, one can assume that the conductivity is constant and develop a simple integral procedure for determination of the conductivity coefficient. If the whole thickness of the reservoir is divided by points ho, h l . . . . . h m , into m small layers, then one can consider that the conductivity coefficient is constant within a particular layer. If Xi is the piezoconductivity coefficient for the i-th layer, then Eq. 12-93 can be expanded into m equations 02p
Op = --, Ot
Xi OZ 2
i - 1, 2 . . . . . m
(12-95)
If the parameters X are estimated for all layers, then, choosing an appropriate analytical functional approximation, one can determine the piezoconductivity function for the whole formation. If for the same h one has two sets of measurements of p for two different values of t (e.g., t' and t"), then it is possible to take a finite difference approximation for pt in the following form, assuming that the pressure changes constitute an inertial process: pt --
Op Ot
~
p(t") - p(t') _ Pt t" -- t'
(12-96)
Obviously, one needs to obtain the above estimates for all layers. If Eq. 12-93 is integrated twice on the interval (h0, h~) with respect to z, then one obtains an algebraic equation with respect to X" dh o
XP== dz -o
dh o
f,
Pt dz
(12-97)
o
In Eq. 12-97, one has to use a corresponding estimate for Pz. To exclude the first derivative Pz from the resulting equation, in addition, one needs to integrate with respect to the initial level of the layer (h0). Then, the integration for the
343
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
layer (h0, h i ) and renaming the variables leads to a simple equation with respect to X: X
{
2 p ( h l ) h l -k- ho[p(ho) - p(hl)] - 2
- 0.5pt(h0 - hi)
{
1
p ( z ) dz
0
]
hohl + ~[(h0) 2 -k- hohl -k- ( h i ) 2]
}
(12-98)
If the above-described procedure of double integration is applied to Eq. 12-93 for m non-intersecting intervals I~ . . . . . Ira, then it yields a linear system of algebraic equations with respect to the coefficients Xi, i = I, 2, . . . , m. As shown, the expressions for the computation of the values of Xi contain integrals of pressure only. This means, that one needs only the pressure data (not their derivatives) for the determination of the conductivity function. In addition, the integral form of the expressions allows one to use the well-developed numerically stable procedures of numerical integration, such as the Simpson method (Hamming, 1962), for their estimation of the pressure data. In Eq. 12-98, the integral can be computed by the following formula: p ( z ) d z -- ~ [ p ( l ) + 4p(1 + A) + p(u)]
p ( z ) dz --
(12-99)
where 1 and u are the lower and upper limits of integration, respectively, and 2A = (u -
1).
M o d e l example o f determining the conductivity f u n c t i o n
Data taken for the same oil well were organized by layers and recorded in Table 12-1. In the last column of this table, the results of determination of the conductivity coefficients layer by layer are presented. Based upon these data it is possible to express the conductivity function in a suitable analytical form; for example, as exponential or trigonometric polynomial. If one chooses the exponential polynomial approximation of the second degree, then the conductivity function constructed upon the data of Table 12-1 can be represented by the following polynomial: -x(h)
-- - 0 . 0 0 0 l h 2 -+- 0.055h - 40.73
(12-100)
which provides an analytical expression for the conductivity function. TABLE 12-1 Experimental data and the results of determination of conductivity function (A = 90 m) Layer 1 2 3 4 5
I (m)
u (m)
Pb
p(l) (MPa)
p(l -]- A) (MPa)
Xi
(MPa/yr)
2400 2580 2760 2940 3120
2580 2760 2940 3120 3300
2.05 1.09 1.22 0.54 0.95
31.81 34.02 36.64 38.99 42.97
30.29 33.08 35.12 38.16 40.78
-1.53 -9.19 -9.11 -3.99 -6.95
(m2/yr) x x x x x
104 103 103 103 103
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M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
Discussion A methodology of conductivity function determination based on the successive formation pressure measurements is presented here. The conductivity function describes in detail the variations of lithological properties with depth of the reservoir of interest. It can be used, for example, for the computation of the local rates of fluid flow. This approach can be easily extended for the determination of the other depth-dependent parameters, such as the permeability. The success of the application of the methodology presented depends mostly on the quantity and quality of formation pressure data used for the evaluation of the necessary parameters. Integration procedures forming the computational core of the developed methodology can smoothen partially the primary errors of the measurements. This property is especially useful if one tries to combine the numerous data obtained from several different measurement techniques, which is a usual situation in the case of formation pressure data.
Framework of a comprehensive model Buryakovsky et al. (1991) presented the required features of a generalized abnormal pressure model in a geologic basin. Many factors that influence compaction of a rock need to be considered. The pressure-dependent properties are commonly the focus of most numerical and mathematical models. A comprehensive model, however, must also include the effect of temperature as well as the effect of phase change and postsedimentation tectonics. Yassir and Bell (1994) outlined some of the most important factors affecting abnormally high fluid pressures. It is important to discuss these factors in order to develop a comprehensive mathematical model. Following are the most important factors that affect the development of abnormally high pressures.
Overpressurization due to rapid loading It is commonly accepted that rapid loading and the resulting undercompaction is the principal cause of abnormally high formation pressures in sand-shale sequences (Harkins and Baugher, 1969). No overpressurization is likely to occur if the fluids are allowed to flow to another sediment layer during the sedimentation, especially during the early stage (Rieke and Chilingarian, 1974). The physical effect of the rate of loading is shown in Fig. 12-16. Modeling this process may require the inclusion of a waterbed on top of the porous medium. Saghir et al. (1998a,b) developed such a model in an open duct as well as in a porous medium. The momentum balance equation was represented by the Brinkman equation in the porous medium, whereas the Navier-Stokes equation was used to describe flow in an open channel. In the x, y, and z directions, the Brinkman equation is written for the porous layer as follows: -~- U - -
E"]
-
OX + / z e
ay
+ .e
(12-101)
~ X 2 + ~022 -t- O Z 2 j
[02
+
Oy2
+
1 Oz2 J
-- Pg
-- to)]
(12-102)
345
MATHEMATICALMODELING OF ABNORMALLY HIGH FORMATION PRESSURES
-e-
Fast sedimentation
,,9
r~
$ S
f
f
Slow sedimentation
Depth ( D )
h~ V
Fig. 12-16. Effect of loading rate on porosity for various depths.
w--
+/ze
E
2w]
--~x2 + -~v2 + --~-22
(12-103)
In the above equations, u, v, w are the velocity components in the x, y and z directions, respectively, and the permeability is assumed to be uniform in the three directions. The pressure is denoted by p, the temperature is T, the reference temperature is To and the density is p. The thermal volume expansion is/~T, the viscosity is denoted by #, the effective viscosity is denoted by #e, the permeability is denoted by k, and g is the gravity term. The Brinkman approximation sets the fluid viscosity # and #e equal to each other but, in general, they are approximately equal. The continuity equation for an incompressible fluid is given by:
IOu Ov Owl ~xx + ~yy + -~z - 0
(12-104)
The energy balance equation is as follows: (/gCp)f
b/--~X -~- U--~-y --~ LO~Z
--
ke [.-~-x2 + ~y2 + --~22J
(12-105)
Along with the energy balance equation, the following constitutive thermal relationships should be used: k~ = q~kf + (1 - ~b)ks
(12-106)
where 4~ is the porosity, and (pCp)f is the product of the density and the specific heat of the fluid used in the model, which was hexane in our case. In Eq. 12-106, the conductivity of the fluid is denoted by kf, the conductivity of the solid glass bead is denoted by ks, and k~ is the effective conductivity. A possible improvement in the model can be made by describing the heat transfer in the matrix and void space with two different energy balance equations. Such an
346
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
approach has been taken by Chan and Banerjee (1981), but has yet to be adopted by a geoscience modeler. For the fluid layer, the momentum balance equation is represented by the NavierStokes equation, which is written in a vector form as follows: p
- - ~ -+- u j u i , j
]
-- --Pi + [#(ui,j -k- u j , i ) l , j -- p g [ f l T ( T -- To) - [3r
- Co)]
(12-107) where i, j = indicies, u is the velocity vector. The pressure is denoted by p, the temperature is T, concentration is C, density is p, the time is expressed by t, the thermal volume expansion is fiT, solutal volume expansion is denoted by tic, viscosity is denoted by #, and g is the gravity vector. In addition, the interfacial tension model should be used to describe Marangoni convection in the free surface. At the free surface, V = 0 and the shear stress at the free surface is expressed as follows: O'm = O'mo-- lYI(T - To)
(12-108)
where O'mo is the average surface tension at the reference temperature, To. In addition, heat is lost from the free surface to the environment by natural convection. A heat flux Q = BiO, therefore, should be used, where Bi is the Biot number and 0 is the dimensionless temperature, 7, is the thermal interfacial tension gradient. Rapid loading involves a pore pressure increase directly as a result of an increase in the vertical stress. In a tectonically inactive basin, the horizontal stress will also increase in response to burial, so that there is a constant ratio between vertical and horizontal effective stresses. A common assumption is that zero lateral strain conditions prevail. More complex models, however, have yielded better results (Addis et al., 1994). Ideally, the loading rate can be modeled effectively by coupling the above equations with a time-dependent porosity system along with compaction and deformation of the solid matrix. Experimental and numerical modeling of this system is still in its preliminary phase and has yet to be coupled with a rigorous fluid flow model (Vaziri et al., 2000, 2001). Shear deformations aided by overpressures
Even though it has long been recognized that shear deformation is aided by deformation (Rubey and Hubbert, 1959), mathematical modeling of the system has been initiated only recently (Yassir, 1990). Fig. 12-17 (Yassir and Bell, 1994) shows how various mechanisms involved can affect the porosity vs. vertical effective stress curve. If there is no volumetric change, the stress is transferred to the fluid (path D, A, B, etc. Fig. 12-17). In Case A (delineated by path A), the sediment is underconsolidated so that it slowly moves along the consolidated line as the load increases and the fluids dissipate. In Cases B, C, and D, on the other hand, the sediment has continued to consolidate and then experienced a reduction in effective stress to the same stress that A is on. B becomes overconsolidated because of the fluid injection or expansion. Postsedimentation origin of AHFP (abnormally high formation pressure) includes hydrocarbon generation and upward fluid migration (along faults, for example). Because C experiences a phase
MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES
347
Rapid burial Added fluid or thermal expansion C - Fluid c r e a t e d from solid phase D - U n d r a i n e d t e c t o n i c shear
A-
B -
0 0 fl_
Vertical effective stress Fig. 12-17. Porosity variation with different overpressure mechanisms. (Redrawn from Yassir and Bell, 1994.) change from solid to liquid, the most dramatic porosity change is exhibited in this case. Finally, D shows the effect of undrained tectonic shear leading to pore pressure increases without any volumetric change. Modeling Case D offers by far the most difficulties from both experimental and numerical perspectives. Insight into this process can be obtained from subsidence data available for many oil reservoirs. Reconstitution of a pressurization model from a depressurization model, however, is not trivial and needs comprehensive mathematical models for validation. Such an approach is yet to be reported in the literature.
Fluid generation at depth In any closed system, fluid generation can lead to overpressurization and subsequent changes in the effective stress (pe + Pp -- pt, where pe is the effective grain-to-grain pressure, pp is the pore (or fluid) pressure, and Pt is the total overburden pressure) without changing the total vertical stress. It is important to realize that such fluid generation will lead to more dramatic changes in effective stress than those due to rapid loading. The magnitude of this change can be so intense for a transient case that hydraulic fracturing is induced (Yassir and Bell, 1994). None of the numerical models presented to-date, however, include this possibility. Such a process could be modeled using a dynamic Poisson's ratio (this value could be determined experimentally under simulated geological environments). Field observations of such mechanisms are available in the literature (Meissner, 1982); however, no laboratory or numerical modeling has been reported. Laboratory tests should reveal the nature of the dynamic Poisson ratio as well as provide one with phenomenological models for porosity. In
348
M.R. ISLAM, L. KHILYUK, G.V. CHILINGAR, S. KATZ, J.O. ROBERTSON JR., A. GUREVICH ET AL.
order to scale up such experimental results, one must consider that the time factor in the laboratory must be scaled up to the field scale. Unfortunately, this is not an easy task as most of the governing equations are non-linear functions of time. Modeling of phase change is a difficult task. This is particularly true when it comes to phase change from a solid phase to a liquid phase. The model should include transient porosity and permeability values due to conversion of an immobile phase to a mobile phase. Such transition has been taken into account for hydrocarbons. If a phase transition from a solid, non-hydrocarbon phase to liquid or gas (e.g., carbon dioxide) is involved, the process becomes more difficult to model. Ideally, such a process should be modeled using full momentum, energy, and mass balance equations, while allowing a continuously changing matrix with transient porosity and permeability values. Such modeling should be done using the finite element formulation.
Diagenesis Diagenesis and catagenesis play an important role in the consolidation of sediments and, therefore, should have an impact on overpressurization. Also, rapid burial can modify the digenetic and catagenetic processes. Cementation would usually inhibit the existence of underconsolidation as a source of overpressurization. Modeling diagenesis falls under the realm of geological models and has yet to be coupled with a hydrodynamic model as discussed earlier. Modeling of such a process will possibly involve expertise from other disciplines, such as double diffusive convection and crystal growth (Saghir and Islam, 1999).
CONCLUSIONS
Modeling thermochemical convection with a deforming matrix system is a formidable task. This is even more difficult when little experimental (or field) data are available for validation of the models. Such is the case of numerical models of reservoirs with abnormally high fluid pressures. Even though many empirical and heuristic models have been presented to predict abnormal pressures in a reservoir, little has been done to develop rigorous mathematical models. This chapter is a step foreword toward developing a comprehensive model.
N O M E N C L A T U R E USED IN THIS C H A P T E R
A a
b Cf Cw
Cs Cw D
geologic age in millions of years experience constant in Eq. 12-30 experience constant in Eq. 12-30 compressibility of the rock compressibility of water specific heat of sediment specific heat of fluid burial depth
MATHEMATICALMODELINGOF ABNORMALLYHIGHFORMATIONPRESSURES h k
ks
~w R
V
Vm t T Pa Pp Pn
Q
Pt # Pm Pw Ps O-e or Pe
349
thickness of a formation permeability filtration coefficient t h e r m a l conductivity of the rock t h e r m a l c o n d u c t i v i t y of the s e d i m e n t t h e r m a l conductivity of the fluid relative c o n t e n t of clay layers in an interval of the section for w h i c h the clay porosity is being determined. velocity vector v o l u m e of the rock v o l u m e of the solid skeleton (matrix) time p a l e o t e m p e r a t u r e function a b n o r m a l pore pressure pore pressure n o r m a l pressure (hydrostatic) heat s o u r c e / s i n k pressure due to overburden porosity viscosity density of the rock matrix (skeleton) density of w a t e r bulk density of s e d i m e n t effective pressure
BIBLIOGRAPHY Addis et al., 1994. Eurock '94, Rotterdam, pp. 879-886. Barr, O., Grauls, D. and Lerche, I., 1993. Modeling of high over-pressure in an offshore Nigerian basin: slant fault models with non-horizontal beds. J. A f Earth Sci., 17: 3307-3321. Bear, J., 1972. Dynamics of Fluids in Porous Media. Elsevier, Amsterdam, 764 pp. Best, M.E. and Katsube, T.J., 1995. Shale permeability and its significance in hydrocarbon exploration. Leading Edge, March: 165-170. Bethke, C.M., 1985. A numerical model of compaction-driven ground-water flow and heat transfer and its application to the paleohydrology of intracratonic sedimentary basins. J. Geophys. Res., 90B: 6817-6828. Bethke, C.M., 1989. Modeling subsurface flow in sedimentary basins. Geol. Rundsch., 78(1): 129-154. Bishop, R.S., 1979. Calculated compaction states of thick abnormally pressured shales. AAPG Bull., 63: 916-933. Bradley, J.S., 1975. Abnormal formation pressure. AAPG Bull., 59(6): 718-731. Bredehoeft, J.D. and Hanshaw, B.B., 1968. On the maintenance of anomalous fluid pressures: I. Thick sedimentary sequences. GSA Bull., 79: 1097-1106. Buryakovsky, L.A. and Chilingarian, G.V., 1991. Time factor in mathematical models of geologic and technical processes. J. Pet. Sci. Eng., 6: 341-347. Buryakovsky, L.A. and Djevanshir, R.D., 1976. Towards evaluation of filtration and screening properties of clayey rocks. Uch. Zap. AzJ NEFTECKh IM im. M. Aizezbekov, Ser. IX(2): 7-12. Buryakovsky, L.A., Jevanshir, R.D. and Aliyarov, L.U., 1985. In: Kollektorskie Svoistva Porod na Bolshykh Glubinakh. Nauka, Moscow, pp. 193-198.
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Buryakovsky, L.A., Dzevanshir, R.D. and Aliyarov, R.Yu., 1986. Well-logging Techniques in Studying Formation Pressure. Elm Publ. House, Baku, 148 pp. Buryakovsky, L.A., Dzhafarov, I.S. and Dzhevanshir, R.D., 1990. Mathematical Modeling of Petroleum Geology Systems. Nedra Publ. House, Moscow, 295 pp. Buryakovsky, L.A., Djafarov, I.S. and Djevanshir, R.D., 1982. Prediction of Physical Properties of Reservoir Rocks and Caprocks of Oil and Gas Deposits. Nedra, Moscow, 200 pp. Buryakovsky, L.A., Djevanshir, R.D. and Chilingarian, G.V., 1991. Mathematical simulation of sediment compaction. J. Pet. Sci. Eng., 5:151-161. Buryakovsky, L.A., Chilingar, G.V. and Aminzadeh, E, 2001. Petroleum Geology of the South Caspian Basin. Gulf Professional Publ., Boston, MA, 442 pp. Carrier, G. and Pearson, C., 1988. Partial Differential Equations. Academic Press Inc., New York, NY, 340 PP. Chan, Y.T. and Banerjee, S., 1981. Analysis of transient three-dimensional natural convection in porous media. Trans. ASME J. Heat Trans., 103: 242-248. De Marsily, G., 1981. Hydrog~ologie Ouantitative. Mason, Paris, 215 pp. Djevanshir, R.D., Buryakovsky, L.A. and Chilingarian, G.V., 1986. Simple quantitative evaluation of porosity of argillaceous sediments at various depths of burial. Sediment. Geol., 46:169-175. Dobrynin, V.M. and Kuznetsov, O.L., 1993. Termouprugie Protsessy v Porodakh Osadochnykh Basseinov. Nauka, Moscow, 168 pp. Dobrynin, V.M. and Serebryakov, V.A., 1989. Geologo-Geophysicheskie Metody Prognozirovaniya Anomalnykh Plastovykh Davleniy. Nedra, Moscow, 287 pp. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Fertl, W.H. and Chilingarian, G.V., 1976. Importance of abnormal formation pressure to the oil industry. SPE 5946, Soc. Pet. Eng. AIME, Amsterdam, April 7-9. Fertl, W.H., Chapman, R.E. and Hotz, R.F. (Eds.), 1994. Studies in Abnormal Pressures. Elsevier, Amsterdam, 454 pp. Hamming, R.W., 1962. Numerical Methods for Scientists and Engineers. McGraw Hill Book Co., New York, NY, 411 pp. Harkins, K.L. and Baugher, J.W. III, 1969. Geological significance of abnormal formation pressures. J. Pet. Technol., 21(Aug.): 961-966. Hennenberg, M. et al., 1997. Porous media and the B6nard-Marangoni problem. Transport Porous Media J., 27: 327-355. Keith, L.A. and Rimstidt, J.D., 1985. A numerical compaction model of overpressuring in shales. Math. Geol., 17: 115-136. Khilyuk, L., Katz, S., Chilingarian, G.V. and Aminzadeh, E, 1994. Numerical criterion and sensitivity analysis for time-dependent formation pressure in a sealed layer. J. Pet. Sci. Eng., 12: 137-145. Lerche, I., 1996. Modelling abnormal pressure development in sandstone/shale basins. Mar. Pet. Geol., 13(2): 179. Magara, K., 1978. Compaction and Fluid Migration - - Practical Petroleum Geology. Elsevier, Amsterdam, 319 pp. Magara, K., 1980. Comparison of porosity depth relationships of shale and sandstone. J. Pet. Geol., 3: 175-185. Meissner, F., 1982. Abnormal pressures produced by hydrocarbon generation and maturation and their relation to migration and accumulation. Bull. Corpus Christi Geol. Soc., pp. 4-6. Rieke, H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Developments in Sedimentology, Elsevier, New York, NY, 424 pp. Rubey, W. and Hubbert, M., 1959. Role of fluid pressure in overthrust faulting II. Overthrust belt in a geosynclinal area of Western Wyoming in the light of the fluid pressure hypothesis. GSA Bull., 70: 167-206. Saghir, M.Z. and Islam, M.R., 1999. Double diffusive convection in a multi-cavity, layered porous bed. Int. J. Heat Mass Transfer, 42(4): 437-457. Saghir, M.Z. and Islam, M.R., 2001. Modeling of heat and mass transfer in a fractured porous medium. Int. J. Comp. Fluid Dynamics, 15(4): 279-292.
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Saghir, M.Z., Hennenberg, M. and Islam, M.R., 1998a. Double diffusive convection with Marangoni effects in a multi-cavity system. Int. J. Heat Mass Transfer, 41(14): 2157-2174. Saghir, M.Z., Hennenberg, M., Legros, J.C. and Islam, M.R., 1998b. Rayleigh-Marangoni convection in a porous cavity. In: D.G. de Vahl and E. Leonardi (Eds.), Advances in Computational Heat Transfer, CHT'97, pp. 591-602. Saghir, M.Z., Islam, M.R., Maffei, N. and Quon, D., 1999. Three-dimensional modeling of BilzGeO20 using the float zone technique. Int. J. Crystal Growth, 193(4): 623-635. Scheidegger, R., 1960. The Physics of Flow Trough Porous Media. Toronto Univ. Press, Toronto, ON, 420 pP. Sharp, J.M. and Domenico, EA., 1976. Energy transform in thick sequences of compacting sediment. GSA Bull., 87: 390-400. Tikhonov, A., 1968. Metody Regulyarizatsii. Nauka, Moscow, 312 pp. Ungerer, E and Pelet, R., 1987. Extrapolation of the kinetics of oil and gas formation from laboratory experiments to the sedimentary basin. Nature, 327(6117): 52-54. Vaziri, H., Lemoine, E. and Islam, M.R., 2000. How can sand production yield a several fold increase in productivity: Experimental and field data. SPE Paper No. 63235, presented at the SPE Annual Technical Conference and Exhibition, Dallas, TX, Oct. Vaziri, H., Jalali, J. and Islam, R., 2001. An analytical model for stability analysis of cap-rock coveting a circular opening. Int. J. Solids Struct., 38: 3735-3757. Whittaker, A. (Ed.), 1985. Theory and Evaluation of Formation Pressure. A Pressure Detection Reference Handbook. Int. Human Res. Dev. Corp., Boston, MA, 231 pp. Yassir, N.A., 1999. Undrained shear characteristics of clay at high total stresses. In: V. Maury and D. Fourmaintraux (Eds.), Rock at Great Depth, ch. 2. AA Balkema, Rotterdam, pp. 907-913. Yassir, N.A. and Bell, J.S., 1994. Abnormally high fluid pressures and associated porosities and stress regimes in sedimentary basins. Eurock '94, Rotterdam, pp. 879-886. Yi-rang, Y., Wen-qia, W. and Dan-ping, Y., 1994. Numerical simulation for evolutionary history of threedimensional basin. Appl. Math. Mech. (Engl. ed.), 15(5): 435-446. Yoshida, C., Ikeda, S. and Eaton, B.A., 1996. An investigative study of recent technologies used for prediction, detection, and evaluation of abnormal formation pressure and fracture pressure in North and South America. IADC/SPE 36381, IADC/SPE Asia Pacific Drilling Technology Conference, Sept., Kuala Lampur. Yu, Z., 1992. Quantitative Basin Modeling: An Application in the Arctic National Wildlife Refuge of Alaska, and Salt Influence on Thermal Anomalies and Fracturing Patterns of Sediments in Gulf of Mexico, Ph.D. Dissertation. University of South Carolina, 161 pp. Yu, Z. and Lerche, I., 1995. Three-phase fluid migration with solubilities in a two-dimensional basin simulation model. Mar. Pet. Geol., 12: 3-16. Yu, Z. and Lerche, I., 1996. Modeling abnormal pressure development in sandstone/shale basin. Mar. Pet. Geol., 13(2): 179-193.
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Chapter 13
I N T E R R E L A T I O N S H I P A M O N G FLUID P R O D U C T I O N , S U B S I D E N C E A N D RESERVOIR P R E S S U R E
V.A. SEREBRYAKOV,G.V. CHILINGAR and J.O. ROBERTSON JR.
INTRODUCTION Abnormally low formation pressures develop in petroleum reservoirs during intensive oil and gas production or in aquifers as a result of water extraction. The reduction in pore pressure in reservoir rocks may result in the influx of water from the adjoining shales and consequent reduction in shale pore pressure. If the influx of shale water is not sufficient to replace the produced fluids, a greater percentage of the overburden load will be carried by the skeletal structure of the rock (the grain-to-grain stress 1 is increased). This eventually will be reflected at the Earth's surface as subsidence. Compaction occurs in both the reservoir rocks and the associated shales as the skeletal structure adjusts itself to carry the additional stress. The area of subsidence as a result of subsurface fluid production is about twice as large as the area of the reservoir. Subsidence (differential) at the surface causes engineering and ecological problems. These include structural damage, rupture of casings, and disruption of pipelines (Barends et al., 1995; Chilingarian et al., 1995a,b; Dobrynin and Serebryakov, 1989). Globally, reservoir rock compaction occurs as a result of pore fluid pressure reduction. Geertsma (1973) can be considered as the 'father' of the theory of land subsidence due to underground fluid withdrawal. Large petroliferous areas in Western Siberia became marshlands as a result of subsidence. In California, over the Wilmington oilfield in Long Beach, a subsidence bowl 50 k i n 2 in area formed after 26 years of production (maximum subsidence at the center of the bowl was 9 m). Many major urban areas in the United States, Mexico, Hong Kong, Tokyo, Taiwan, Thailand, etc. have reported subsidence as a result of water withdrawal from their fresh-water aquifers. Today, subsidence can be measured accurately in situ by wireline tools, such as FSMT, whereas surface subsidence can be recorded by satellite microwave Doppler techniques, such as GPS.
COMPACTION OF ROCKS An extensive discussion on compaction of argillaceous and coarse-grained sediments was presented by Rieke and Chilingarian (1974) and by Chilingarian and Wolf (1975, 1 Pt - Pe + pressure.
Pp;
Pt is total overburden stress, Pe is grain-to-grain or effective stress, and p p is pore or fluid
354
V.A. SEREBRYAKOV,G.V. CHILINGAR AND J.O. ROBERTSONJR.
1976). Ternova and Belov (1965, in Dobrynin and Serebryakov, 1989) described subsidence at the North Stavropol oilfield in Russia. Maximum subsidence of 14.1 cm was observed during 1961-1962 after 5-6 years of production. They proposed the following formula for the determination of subsidence (Ah) of the productive horizon: (13-1)
A h -- h A p f l *
where h is thickness of compacting formation; A p is compacting pressure (MPa), and 13" is coefficient of formation compressibility (MPa -1). Eq. 13-1 takes into consideration only the productive horizon. Because the only subsidence considered in Eq. 13-1 is that of the productive horizon, the actual surface subsidence was five times higher than that calculated by Eq. 13-1. /~* -- ~f/~l "~- ~m
where ~bf is the producing formation porosity (fraction), fll is bulk compressibility of liquids (cme/kg), and/~m is matrix compressibility (cme/kg). Pore compressibility, tip, is equal to 1 (dVp) dp---p
tiP--
(13-2)
Vp
where Vp is volume of the pores (cm3), and pp is pore (fluid) pressure (kg/cm2). The formula for the coefficient of irreversible compaction (/3i, MPa -1) (Dobrynin, 1970) is: -- 4~oe-~176176
(13-3)
where 4~ois initial porosity of clays after deposition, and 4~ is porosity of clays at a burial depth D (m). The compaction of associated shales must be considered when studying subsidence. The Braguny and Yastrebinoye oilfields in the Tersko-Sunzhenskaya region of Russia were examined using geophysical data for the boreholes. The initial average (weighted) porosity of the producing zone, 4)al, was h
~--~ ~)i h i i-I q~al-
h
gp -- gb
(13-4)
i=l
where ~bi and hi are respectively the porosity (%) and thickness of the ith layer (in m), and Vp (m 3) and Vb (m 3) are the pore volume and bulk volume, respectively. Upon decrease in the pore pressure by production of fluids, the porosity decreases to ~a2" t~a 1 q~a2
=
gp / V b (Vp - A V p ) / ( V b - A Vb)
---
1 -- ( A gb / gb ) 1 -- ( A Vp/Vp)
(13-5)
where A Vb and A Vp are changes in the bulk volume (m 3) and pore volume (m3), respectively.
INTERRELATIONSHIPAMONG FLUID PRODUCTION, SUBSIDENCE AND RESERVOIR PRESSURE
355
Inasmuch as A Vp ~ A Vb, Eq. 13-5 can be also written as (AVb -- S A h and
v b - Sh): q~al qSa2
=
1 -- ( A V b / V b ) 1 - (AVb" qSalVb)
=
1 - (Ah/h)
1 -- ( A h / d P a l h )
(13-6)
where S is area of deposits (m2), and h is thickness of formation (m). Also, ~bal ~ba2
exp [/~p(Pl - P2)]
(13-7)
where/~p is weighted average coefficient of pore compressibility (MPa-1), and Pl and p2 are respectively initial and final abnormally low reservoir pressure due to production (MPa-1). Thus, from Eq. 13-6: Ah _ exp [fip(Pl - Pe)] - 1 h (1/qSal) exp [fip(pl - Pe)] - 1
(13-8)
Eq. 13-8, therefore, can be used to estimate the amount of subsidence, depending on the drop in formation pressure due to production (pl - pe). Obviously, it is necessary to determine h, ~al, and/~p. The thickness of the formation can be determined using geophysical logging methods (electrical, radioactive, and sonic). Curves for the normally compacted clays are prepared on a semilogarithmic scale (Dobrynin and Serebryakov, 1978). Fig. 13-1 illustrates the zones of abnormally low pore pressure as indicated by an increase in the specific resistivity (ohm m). The thickness of the formation, h, is 394 m. In a new region, which was not studied, the value of h necessary for estimating Ah is established using an analogy with other regions taking into account the lithological and hydrodynamic characteristics of the area. The ~al is determined using geophysical data:
Zhss q~al -- T ~ s s
~hsh nt-
h
q~sh
(I3-9)
where ~ hss and ~ hsh are the sums of thicknesses for sandstones and shales in the abnormally pressured zone, respectively (m), and ~b~s and 4~sh are the initial porosities (%) of sandstones and shales, respectively. In order to determine tip in the area of pressure reduction, one can use the following methods: (1) repeated leveling measurements of the Earth's surface (repeated measurements of borehole altitudes after pore pressure reduction), using Eq. 13-8; and (2) repeated measurements in boreholes using radioactive logging before and after production. Changes in density divided by the average density of the formation (AlOf/lOf) isabout equal to ( A h / h ) . Thus, one can determine/~p from Eq. 13-8 without repeated leveling. In new regions,/~p is estimated using analogy with other regions having similar lithology and hydrodynamic conditions. In the present chapter, the weighted average porosity was determined from Eq. 13-9. The ~bss and ~bsh were determined from graphs and analytical functions of porosity versus depth for the Tersk-Sunzhen petroliferous area of Russia, based on data obtained
356
V.A. SEREBRYAKOV,G.V. CHILINGAR AND J.O. ROBERTSONJR. E
Q. a
--Resistivity, ohm-m
c-
59 .
.
.
.
I
9
3650 D
_
E
9
_ _
.
9
3750
k--t
b
Q.
I - Shale
3850 2 - Sandstone
P
3950 _ _
/ / /|"
.//']
___--!
4050-
3- Resistivity of shales with abnormally-low pressure
~
--I. , . . x ' "2 5
- Resistivity
of shales
Fig. 13-1. Abnormally low formation pressure in borehole number 83, Braguny Oilfield, Russia. Lithology: 1 = shale; 2 = sandstone; 3 = abnormally low pressure zones; 4 = curve for normally compacted clays; 5 = resistivity of shales (ohmm). (Modified after Dobrynin and Serebryakov, 1989, fig. 122, p. 272; also Serebryakov and Chilingar, 2000, fig. 1, p. 412.)
from repeated leveling surveys after 15 years of production (Table 13-1). Using the average value of 8 x 10 -4 MPa -] for/~p, Ahcalc was calculated in boreholes in which repeated leveling was performed. The values obtained (Ahcalc) were compared with those determined by leveling (Ahmeas). Average absolute error in four boreholes was 0.24 m. Thus, Ahca]c can be obtained using the average/~p value (Table 13-2).
TABLE 13-1 Values of tip determined on the basis of repeated leveling at Braguny oilfield, Russia Borehole nr.
Depth of interval (m)
Thickness of interval (m)
4) (%)
~ hsh (m)
~ h~ (m)
/khmeas (m)
Ahcalc (m)
tip x 104 (MPa -1)
34 35 40 43
3533-3953 4073-4420 3638-4045 3840-4220
420 347 407 380
15.9 16.1 15.8 15.9
317 278 295 283
103 69 112 97
2.56 1.53 2.4 2.39
2.39 2.00 2.30 2.16
8.6 6.1 8.3 8.9
357
INTERRELATIONSHIPAMONG FLUID PRODUCTION, SUBSIDENCE AND RESERVOIR PRESSURE
TABLE 13-2 Subsidence of the Earth's surface (Ah) at the Tersk-Sunzhen pertroliferous area using /~p = 8 x 10 -4 MPa -1 Oilfield
Braguny
Yas~ebinoe
Borehole nr.
Depth of interval (m)
Thickness of interval (m)
r (%)
~ hsh (m)
~ hss (m)
Pressure drop (MPa)
Ah (m)
59 63 65 76 82 83 86 87 91
3635-4057 3507-3963 3667-4062 4222-4506 3635-4047 3706-4100 3696-4161 3459-3944 3491-3978
422 456 395 284 412 394 465 485 487
15.9 15.9 15.8 15.7 15.8 15.7 15.9 16.0 15.7
319 345 287 198 299 275 351 381 340
103 111 108 86 113 119 114 104 147
38.4 36.4 37.9 37.9 36.3 36.4 34.6 35.6 35.1
2.4 2.6 2.2 1.57 2.2 2.1 2.39 2.58 2.5
107 111 113 114 116 119
3587-3977 3502-3900 3578-3923 3773-4002 3443-3881 3654-3890
390 398 345 229 441 236
16.1 16.0 16.0 16.1 15.9 16.0
317 312 271 186 333 185
73 86 74 43 108 51
23.2 25.4 29.0 27.4 27.4 28.4
1.37 1.52 1.5 0.95 1.8 1.0
0
10
(,Oi - D, ), 20
MPo 30
40 "4
L Fig. 13-2. Relationship between Ah/h and formation pressure drop due to production (Ap -- Pi -- Pf) in MPa -1" Ah = subsidence, m; h -- formation thickness, m; Pi (Pn) ---=initial formation pressure, MPa -1" pf = final formation pressure after certain amount of production, MPa -1" ~bi -- initial porosity -- 15.9%; and numbers on curves are /~p values. /~p -- weighted average pore compressibility. (Modified after Dobrynin and Serebryakov, 1989, fig. 123, p. 279; also Serebryakov and Chilingar, 2000, fig. 3, pp 415.)
358
V.A. SEREBRYAKOV, G.V. CHILINGAR AND J.O. ROBERTSON JR.
(A)
(B)
Yastrebin Oil Field
Braguny Oil Field
#113
8a
\(2.1)
.. ~
~ ~ .
o~'--"
1.5
t__
,_# 82
\(2.2) \
#63
# 35
/-(2.6)
# 43
/ ~ s3)/ t " '
~-(2.a)
,
;'~~; " -
/IO.951
115
(~.8)
(2.6)
# 86 (2.39)
Fig. 13-3. Subsidence of the Earth's surface at the Yastrebin oilfield (A) and Braguny oilfield (B). Solid circles indicate borehole; numbers between parentheses are Ahcalc values, in m. In the case of the open circles, Ahmeas values are measured. (Modified after Dobrynin and Serebryakov, 1989, fig. 124, p. 282; also Serebryakov and Chilingar, 2000, fig. 2, p. 425.)
Based on data calculated using Eq. 13-8, a relationship between A h / h and pressure drop after production ( p i - Pal) (where Pi is the initial pressure and Pal is the abnormally low pressure after production) was established (Fig. 13-2). Using Fig. 13-2, Dobrynin and Serebryakov (1989, pp. 280-281) estimated the subsidence (Ah) of the Earth's surface during production from the Cretaceous deposits of the Tersk-Sunzhen petroliferous area of Russia. For example, Fig. 13-3 shows subsidence of the Earth's surface during the 1969-1984 period above the Braguny and Yastrebin oilfields, with the maximum subsidence corresponding to the crestal areas of anticlines (maximum production).
CONCLUSIONS
The amount of compaction of the producing formation (and resulting subsidence of the Earth's surface) can be predicted from the decrease in pore pressure due to production or vice versa. The method presented here is simple and accurate, provided compressibilities are properly determined or estimated (see Rieke and Chilingarian, 1974), which is commonly not the case.
BIBLIOGRAPHY Barends, EB.J., Brouwer, F.J.J. and Schroder, F.H. (Eds.), 1995. Land Subsidence. Proc. Fifth Int. Symp. Land Subsidence. Balkema, Rotterdam. Chilingarian, G.V. and Wolf, K., 1975. Compaction of Coarse-Grained Sediments, 1. Developments in Sedimentology 18A, Elsevier, Amsterdam, 552 pp. Chilingarian, G.V. and Wolf, K., 1976. Compaction of Coarse-Grained Sediments, 2. Developments in Sedimentology 18B, Elsevier, Amsterdam, 808 pp. Chilingarian, G.V., Donaldson, E.C. and Yen, T.E, 1995a. Subsidence Due to Fluid Withdrawal. Developments in Petroleum Science 41. Elsevier, Amsterdam, 498 pp.
INTERRELATIONSHIPAMONG FLUID PRODUCTION, SUBSIDENCEAND RESERVOIRPRESSURE
359
Chilingarian, G.V., Katz, S.A. and Khilyuk, L.F., 1995b. Neural network based prediction of subsidence, surface gas migration, and seismic activity. In: F.B.J. Barends, F.J.J. Brouwer and F.H. Schroder (Eds.), Land Subsidence, Proc. Fifth Int. Symp. Land Subsidence. Balkema, Rotterdam, pp. 41-46. Dobrynin, V.M., 1970. Deformation and Changes in Physical Properties of Oil and Gas Reservoir Rocks. Nedra, Moscow. Dobrynin, V.M. and Serebryakov, V.A., 1978. Methods of Predicting Abnormally High Formation Pressures. Nedra, Moscow, 231 pp. Dobrynin, V.M. and Serebryakov, V.A., 1989. Geologic-Geophysical Methods of Predicting Abnormal Formation Pressures. Nedra, Moscow, 285 pp. Geertsma, J., 1973. Land subsidence above compacting oil and gas reservoir. J. Pet. Technol., 25(6): 734744. Rieke, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Developments in Sedimentology 16, Elsevier, Amsterdam, 424 pp. Serebryakov, V.A. and Chilingar, G.V., 2000. Prediction of subsidence: relationship between lowering of formation pressure and subsidence due to fluid withdrawal. Energy Sources, 22(5): 409-416.
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361
Author Index * Abasov, M.T., 94, 308 Adams, N., 161, 165 Aharon, P., 229, 288 Aigouy, T., 288 Aleksandrov, B.L., 95 Alexandrov, A., 310 Alexandrov, B.L., 136, 148, 305,308 Aliev, A.I., 94 Aliyarov, L.U., 349 Aliyarov, E Yu., 308 Aliyarov, R.Yu., 95, 121,350 Alizadeh, A.A., 95, 208 Allen, D.R., 38, 40, 41, 64, 293 Almubarak, N., 19, 294 Aminzadeh, E, 70, 94, 95, 121, 173, 186, 189, 190, 206, 309, 350
Anderson, D.M., 277, 288 Anderson, R.V.V., 4, 17, 64 Anderson, T.O., 166 Angino, E.E., 225, 288 Anikiev, K.A., 90, 94, 205,206, 211,220 Antonellini, M., 75, 94 Aoki, M., 66 Aoyagi, K., 270, 274, 275,288 Appelo, C.A.J., 279-281,288 Ar'ye, A.G., 17 Arens, EL., 277, 290 Arps, J.J., 239, 288 Asadov, M.N., 82, 94 Athy, L.E, 44-46, 64, 78, 94, 297, 298, 308 Avchyan, G.M., 43, 64 Averbukh, A.G., 187, 188 Aydin, A., 75, 94 Azimov, E.Kh., 308 Azizova, Sh.A., 94 Bailey, A.M., 224, 288 Bakhtin, V.V., 208 Banerjee, S., 346, 350 * Page references to text are in Roman type, to bibliography in italics.
Barends, EB.J., 353, 358 Barker, C., 296, 308 Barnes, H., 114, 122 Barnes, R., 290 Barr, O., 323,349 Baskov, E.A., 65 Batygina, N.B., 95, 309 Baugher, J.W. III, 8, 9, 16, 18, 56, 65, 191, 193-195, 207, 344, 350 Bazylev, A.E, 187, 188 Bear, J., 329, 340, 349 Bebout, D.G., 11, 17, 64 Bell, J.S., 311,344, 346, 347, 351 Belonin, M.D., 15, 16, 17 Belotti, E, 159, 165 Berg, R.R., 13, 18, 56, 59, 63, 66 Bergan, R.A., 150 Berger, G., 266, 288 Berner, R.A., 10, 17, 64 Berry, EA.E, 224, 233, 288, 296, 308 Best, M.E., 326, 349 Bethke, C.M., 235,288, 327, 340, 349 Bigelow, E.L., 288 Billings, G.K., 225,288, 291 Birchwood, K.M., 199, 208 Bischoff, J.L., 233,238, 288, 292 Bishop, R.S., 327, 349 Bishop, W.E, 195,206 B lackson, J.H., 288 Blanc, G., 290 Blokh, A., 140, 148 Blyth, C.R., 289 Boatman, W.A., 164, 165 Bogomolov, Y.G., 58, 64 Boles, J.R., 265,288 Bolt, G.H., 246, 277, 288 Boone, D.E., 157, 165 Bourgoyne, A.T. Jr., 80, 94, 157, 158, 161, 165, 288, 289 Brace, W.E, 178, 188 Bradley, J.S., 327, 349 Brandt, H., 28, 64
362 Bredehoeft, J.D., 16, 17, 51-55, 65, 233, 289, 327, 349 Bredeson, D.H., 4, 7, 16, 18, 65 Breeze, A., 296, 309 Bridges, J.R., 149 Brodie, S., 189 Broecker, W.S., 290 Bronovitskiy, A.V., 102, 122 Brouwer, EJ.J., 358 Brown, K.E., 25, 64 Brown, K.M., 268, 270, 287, 289 Bruce, C.H., 195-198, 206 Bunyatov, J.B., 82, 94 Burger, J., 189 Burrus, J., 235, 240, 288, 289 Burst, J.E, 11, 17, 49, 64, 99, 100, 121,266, 270, 289 Buryakovsky, L.A., 82, 85-90, 94, 97, 99109, 111-120, 121, 122, 199, 206, 226, 227, 250, 289, 312, 315-319, 344, 349, 350
Bush, R.E., 162, 167 Calburn, W., 309 Callender, E., 18, 65 Cannon, G.E., 224, 289 Capuano, R.M., 238, 289 Carothers, W.W., 18, 65 Carpenter, A.B., 233, 289 Carrier, G., 350 Carroll, J.E, 144, 149 Carslaw, H.S., 52-54, 64 Carstens, H., 69, 8 l, 94, 206 Carver, R.E., 191, 195, 206 Castro, G., 206 Cathless, L.M. III, 18, 291 Cebell, W.A., 277, 289 Chan, Y.T., 346, 350 Chapman, R.E., 95, 189, 290, 350 Chave, K.E., 227, 233, 237, 289 Cheema, M.S., 289 Chenevert, M.E., 18, 66 Chernov, A.A., 49, 67 Chernyakov, A.M., 214-216, 221 Chervanev, I.G., 221 Chilingar, G.V., 13, 17, 18, 65, 83, 84, 87, 88, 90, 94, 95, 113, 114, 121, 122, 124, 140, 149, 162, 165, 189, 206, 221, 224, 238, 242-244, 246, 251,253, 256, 260-
264, 277, 282, 283, 288, 289-291, 293, 300-308, 309, 350, 356-358, 359 Chilingarian, G.V., 2, 5, 10, 12-14, 16, 17, 19, 27-29, 33, 35, 36, 38-41, 43, 45-48, 50-54, 59-63, 64-66, 78, 80, 91, 94, 95, 98, 99, 113, 114, 118, 121, 122, 123, 125-127, 140, 142, 143, 145, 146, 148, 148, 149, 152-155, 158, 162, 165, 165, 189, 194, 195, 206, 206, 207, 220, 221, 224-226, 228, 229, 233, 237, 241, 242, 245, 246, 252, 254-257, 259-271,274279, 281, 285, 288, 288-291, 293, 294, 297, 309, 312, 317, 327, 339, 344, 349, 350, 353, 358, 358, 359 Clark, S.E Jr., 16, 17, 64 Clarke, B.A., 291 Classen, J.S., 191,206 Clayton, R., 176, 188 Cohen, A.D., 288 Collins, A.G., 224, 229, 233-235,290 Colten-Bradley, V.A., 269, 290 Combs, G.E, 156, 165 Coplen, T.B., 283, 290 Corbet, T., 310 Cox, W., 296, 309 Craze, R.C., 224, 289 Culloh, T.H., 42, 66 Dan-ping, Y., 351 Daniel, E., 292 Daniel, W.L., 148 Davidbekova, E.A., 95 Davisson, M.L., 294 Daw, R.N., 160, 165 De Freitas, M.H., 261,263, 275, 291,294 De Marsily, G., 339, 350 De Sitter, L.U., 236, 290 Degens, E.T., 227, 282, 283, 289-291 Dellinger, T.B., 148 Dergunov, E.N., 95 Desbrandes, R., 176, 188 DeVries, M.R., 149 DeWit, C.T., 277, 290 Dickey, L., 296, 309 Dickey, P.A., 6, 16, 17, 57, 64, 191-194, 206, 237, 290 Dickinson, G., 1, 9, 17, 45, 64, 78, 94, 191, 192, 206, 297, 298, 309 Dimitrov, V.D., 189
363 Djafarov, I.S., 350 Djavadov, Ya.J., 95 Djevanshir, R.D., 82, 85, 94, 121, 315, 349, 350
Dobrynin, V.M., 94, 102, 122, 126, 128-130, 132-139, 141, 142, 149, 209, 220, 224, 290, 295-300, 304-306, 308, 309, 327, 331,336, 339, 350, 353-358, 359 Domenico, EA., 296, 309, 327, 351 Donaldson, E.C., 9, 16, 17, 64, 358 Doyle, EE., 189 Dupin de Saint Cyr, E, 163, 165 Durmishyan, A.G., 85, 94, 122, 211,220 Dutta, N.C., 94, 169, 170, 178, 188 Dypvik, H., 69, 81, 94, 206 Dzhafarov, I.S., 121,350 Dzhevanshir, R.D., 101, 105, 121, 122, 288, 290, 350
Eaton, B.A., 94, 170, 171,174, 178, 189, 351 Eaton, T.L., 171, 174, 189 Eberhart-Phillips, D., 178, 189 Edmond, J.M., 293 Eglinton, L.B., 18, 291 E1-Hadidi, S., 159, 165 Elderfield, H., 290 Elliott, W.C., 237, 290 Endres, B.L., 221,291 Engelder, T., 207 Eremenko, N.A., 17, 98, 122 Ershaghi, I., 165, 289 Evans, D.M., 7, 17, 64 Feather, J.N., 207 Fertl, W.H., 3, 14, 17, 19, 64, 80, 94, 95, 113, 122, 124-127, 142, 143, 145-148, 148, 149, 152, 153, 157, 158, 160-165, 165, 166, 169, 189, 191-193, 197-199, 206, 206, 207, 220, 221, 239, 240, 247, 266, 288, 290, 309, 317, 327, 339, 350 Fillippone, W.R., 172, 189 Forbes, EL., 95 Forgotson, J.M., 151,166 Foster, J.B., 45, 65, 135, 149 Fowler, W.A. Jr., 191,206, 237, 290 Frangos, W.T., 188 Franklin, K.L., 94 Franks, S.G., 265,288 Frederick, W.S., 37, 65
Freeman, S, 66 Frentrop, A.H., 150 Frick, T.C., 26, 27, 65 Friedman, M., 207 Friedman, T., 290 Frost, E., 149 Fuchtbauer, H., 11, 17, 65 Gaida, K.H., 233, 251,267, 281,294 Gajardo, I.M., 290 Gansser, A., 199, 206 Garcia, G.H., 149 Gardner, G.H.E, 172, 189 Gardner, L.W., 189 Gebhart, J.E., 267, 293 Geertsma, J., 353,359 Gerard, R.E., 159, 165 Gieskes, J.M., 223,290, 294 Giles, M.R., 225,226, 235,290 Gill, J.A., 164, 166 Gilreath, J.A., 8, 16, 17, 65 Glasstone, S., 17, 63, 65 Goddard, R.D., 160, 166 Goins, W.C., 161,166 Goldberg, E.D., 223, 228, 290 Goldschmidt, H., 11, 17, 65 Goldsmith, R.C., 160, 166 Gorfunkel, M.V., 221 Gorkun, V.N., 199, 206 Graf, D.L., 228, 290 Grauls, D., 349 Graveley, W., 148 Greet, R.E., 288 Gregory, A.R., 189 Gretener, EE., 63, 65, 198, 206 Gross, M.G., 290 Gstalder, S., 159, 166 Guest, R.J., 166 Guire, W.J., 65 Gunter, J.M., 147, 149 Gurevich, A.E., 60-62, 65, 70-72, 74, 76, 78, 83, 84, 87, 88, 90, 93, 95, 189, 206, 219, 221,295, 309
Guseva, A.N., 293 Gustavson, T.C., 8, 18, 65 Guyod, H., 161,166 Hager, R.V., 207 Hall, EL., 269, 290, 292
364 Ham, H.H., 45, 65 Hamilton, E.L., 44, 65 Hamilton, J.R., 19, 67 Hamming, R.W., 342, 343,350 Han, D.-H., 189 Handin, J., 199, 207 Hanor, J.S., 228, 229, 233, 236, 238, 290, 291
Hansen, S., 291 Hanshaw, B.B., 12, 16, 17, 51-55, 65, 283, 290, 327, 349 Hardin, ER., 195, 207 Hardin, G.C., 195,207 Harkins, K.L., 8, 9, 16, 18, 56, 65, 191, 193195, 207, 344, 350 Harper, D., 152, 166 Harrison, E., 37, 65 Harville, D.W., 13, 18 Hawkins, M.E, 13, 18 He, S., 248, 250, 291 Hedberg, H.D., 44-46, 65, 78, 95 Hedberg, W.H., 239, 291 Hennenberg, M., 350, 351 Herbert, W.E., 159, 166 Hermanrud, C., 240, 291 Hervig, R.L., 294 Hill, G., 296, 309 Hill, R.I., 292 Hitchon, B., 229, 233, 291,295,309 Ho, R., 189 Hobart, S., 189 Hobson, G.D., 225, 291 Holloway, J.R., 294 Hopkinson, E.C., 149, 150 Hosoi, H., 45, 65 Hospers, J., 57, 65, 198, 207 Hottman, C.E., 29, 35, 36, 65, 95, 149, 178, 189
Hotz, R.E, 95, 189, 350 Hower, J., 11, 18, 66, 270, 293 Hubbert, M., 346, 350 Hubbert, M.K., 4, 6, 18, 19, 25, 28, 29, 31, 37, 55, 56, 63, 65, 66, 95, 198, 207, 309 Hughes, C.R., 292 Hunt, J.M., 16, 18, 235,290, 291 Hutcheon, I., 294 Ikeda, S., 351 Imanov, A.D., 82, 94
Islam, M.R., 326-328, 348, 350, 351 Issenmann, O., 160, 166 Ivakhnenko, A.G., 189 Jaeger, J.C., 52-54, 64 Jalali, J., 351 Jenkins, D., 250, 293 Jevanshir, R.D., 349 Johnson, H.A., 4, 7, 16, 18, 65 Johnson, R.K., 29, 35, 36, 65, 95, 149, 178, 189
Johnston, C.W., 150 Jones, D., 291 Jones, EH., 11, 18, 57-59, 63, 65, 161,166, 191,207 Jorden, J.R., 95, 151,166 Kalinko, M.K., 207 Kartsev, A.A., 47, 65 Kastryulin, N.S., 208 Kasumov, K.A., 88, 95 Katsube, T.J., 326, 349 Katz, S.A., 149, 176, 189, 289, 291,350, 359 Kazama, T., 288 Kazi, A., 17, 122, 255, 257, 258, 290, 291 Kazimirov, D.A., 309 Kazintsev, E.E., 252, 255,291 Keenan, A.G., 292 Keep, C.E., 4, 18, 65 Keith, L.A., 350 Kelly, J., 171, 174, 189 Kenda, W.P., 173, 176, 189 Kerimov, A.N., 95 Kerimov, K.M., 187, 188, 189 Khalilov, N.Yu., 88, 95 Khalimov, E.M., 95, 207, 309 Kharaka, Y.K., 16, 18, 65, 114, 122, 237, 291 Kheirov, M.B., 82, 94, 95, 108, 121, 122 Khilyuk, L.E, 16, 18, 25, 65, 189, 224, 289, 291,330, 337, 350, 359 Khitarov, N.L., 110, 118, 119, 122 Kieschnick, W.J., 65 Klemme, H.D., 232, 291 Klovan, J.E., 291 Knetsch, G., 282, 291 Knight, J., 309 Knight, L., 246, 251,289 Knill, J.L., 251,261,263-268, 275, 281,291 Knipe, R.J., 293
365 Korunova, V.V., 253, 256, 257, 291 Kotova, I.S., 275,291 Kraichik, M.S., 95, 309 Krasintseva, V.V., 253, 256, 257, 291 Kreitler, C.W., 8, 18, 65 Kryukov, EA., 224, 251,252, 285,291, 292 Kucheruk, E.V., 13, 18, 69, 95 Kugler, H.G., 198, 199, 207 Kushnirov, I.V., 211,221 Kuznetsov, O.L., 224, 291, 295, 296, 304, 309, 350
Land, L.S., 292 Langseth, M.G., 58, 66 Larichev, V.I., 59-62, 66 Larsen, G., 122 Laubscher, H.E, 27, 66 Law, B.E., 2, 16, 18 Lawrence, T.D., 149 Leach, W.G., 15, 18 Lean, L., 149 Lee, S., 173, 174, 180, 181, 183, 184, 186, 189
Leftwich, J.T., 207 Legros, J.C., 351 Lemoine, E., 351 Lerche, I., 311,322, 323, 325, 326, 349-351 Levorsen, A.T., 2, 18, 37, 38, 66 Lewis, C.R., 58, 66, 161,166 Lindsay, R.O., 179, 184, 185, 189 Lo, K.Y., 32, 33, 66 Lomba, R.ET., 12, 18, 66 Long, G., 267, 292 Louden, I., 296, 309 Louden, L.R., 3, 18, 66 Low, EE, 12, 19, 67, 277,288 Lowe, R., 189 Lucon, C., 160, 166 Luo, X.R., 224, 292 Lusitro, A.O., 288 Lustig, T.E., 69, 95 Lutze, J., 159, 166 Mackenzie, R.C., 277, 292 Maffei, N., 351 Magara, K., 16, 18, 45, 66, 110, 122, 224, 288, 292, 305, 308, 309, 317, 350 Maltman, A.J., 293 Mangelsdorf, EC., 232, 233,292
Manheim, ET., 223, 224, 227, 228, 233,238, 251,253,292, 293 Manning, D.A.C., 225, 292 Manning, J.A., 19, 67 Maricelli, J.J., 236, 237, 294 Marion, B.E, 189 Martin, J.B., 294 Martin, R.T., 55, 66, 276, 292 Mathews, W.R., 171, 174, 189 Maxey, G.B., 289 Mazzullo, S.J., 94, 290 McKelvey, J.G., 11, 16, 18, 66 Meade, R.H., 45, 66, 246, 292 Means, W.D., 305,309 Meents, W.E, 290 Meissner, E, 347, 350 Mekhtiev, Sh.E, 82, 95 Melik-Pashaev, V.S., 69, 83-85, 95, 207, 211,215, 221,309 Mercer, R.E, 165 Meschan, S.R., 207 Meshcheryakov, Yu.L., 213, 221 Meyers, J.D., 191,207 Middleton, M., 291 Miinnich, K.O., 291 Millot, J., 108, 122 Milne, I.H., 11, 16, 18, 66 Mitchell, A., 292 Mitchell, J.K., 246, 292 Mohseni, A.A., 19, 294 Mondshine, T.C., 164, 166 Mooney, R.W., 277, 292 Moore, C.H., 233,294 Moore, C.V., 147, 149 Moore, EL., 151, 161,166 Morgan, J.E, 198, 207 Morton, R.A., 292 Moum, J., 255, 257, 258, 291 Muckleroy, J.A., 166 Mudford, B.S., 95 Muehlberg, EE., 19, 67 Mukhin, Yu.V., 78, 95 Murray, G.E., 8, 18, 66, 191, 196-198, 207 Myers, D.L., 165 Myers, L.L., 236, 292 Nance, G., 161,166 Neglia, S., 292 Neil, W.M., 176, 189
366 Nelligan, W.B., 150 Neruchev, S.G., 98, 122 Nesbitt, H.W., 229, 292 Neuzil, C., 296, 309 Nevins, M.J., 164, 166 Nikravesh, M., 173, 189 Nishigaki, S., 66 Nolen-Hoeksema, R.C., 190 Norrish, K., 277, 292 Nur, A., 190 Nyein, R.K., 149 O'Brien, T.B., 161,166 O'Nions, R.K., 292 Ocamb, R.D., 193, 207 Ohmoto, H., 293 Omarov, A.K., 95 Orem, W.H., 288 Ortoleva, EJ., 235, 292 Osborne, M.J., 1, 10, 12, 16, 19, 24, 57, 63, 66
Oshry, H.I., 150 Osmaston, M.E, 242, 292 Overbeek, J.Th.G., 274, 294 Overton, H.L., 51, 66, 162, 166, 239, 292 Oxburgh, E.R., 229, 292 Ozerskaya, M.L., 42, 43, 64, 66 Paine, W.R., 17, 64, 206 Pakhol'chuk, A.A., 200-205, 208 Palandri, J.L., 292 Palciauskas, A., 296, 309 Palmer, C., 224, 233, 292 Palmer, M.R., 293 Parnov, E.I., 293 Pashkovsky, V.N., 221 Pavlov, A.N., 275, 291 Pearson, C., 350 Peck, R.B., 25, 36, 67 Pelet, R., 339, 351 Pennebaker, E.S. Jr., 169, 178, 189 Perry, E., 11, 18, 66, 270, 293 Picard, L., 293 Pigott, J.D., 175, 189 Pixler, B.O., 160, 166 Plain, J, 66 Plaskova, A.G., 293 Plumley, W.J., 16, 18 Plummer, EB., 237, 293
Pol'ster, L.A., 276, 293 Pollock, D., 296, 309 Polutranko, A.J., 210, 221 Poroshin, V.D., 204, 208 Poston, S.W., 13, 18, 56, 59, 63, 66 Poulson, S.R., 284, 293 Powers, M.C., 11, 16, 18, 19, 29, 47-50, 66, 95, 233, 266, 271,272, 293 Proshlyakov, B.K., 45, 66, 102, 122 Pugin, V.A., 110, 118, 119, 122 Quic-aud, C., 166 Quintana, J.M., 189 Quon, D., 351 Ramsay, J.G., 32, 66 Randall, R.R., 149 Rapoport, M., 149 Ray, A., 178, 188 Raynal, J., 159, 166 Raynard, M., 166 Razavi, J., 19, 294 Rector, J.W. III, 189 Reed, M.H., 292 Reed, W.E., 290 Rehm, W.A., 161,166 Reilly, J., 189 Rengarten, E.V., 292 Reuter, J.H., 290 Reynolds, E.B., 181,190 Richard, J.J., 199, 207 Richardson, G.B., 233, 293 Ridd, M.E, 199, 207 Rieke, H.H. III, 5, 10, 12, 13, 16, 17, 19, 27-29, 33, 35, 36, 38, 39, 43, 45-48, 50-54, 63, 66, 78, 94, 95, 98, 99, 113, 114, 118, 122, 123, 140, 146, 149, 162, 165, 194, 195, 207, 225, 237, 242-244, 251-254, 258, 260-264, 268, 269, 271, 273, 276-278, 281, 285, 286, 289, 290, 293, 297, 309, 344, 350, 353, 358, 359 Rimstidt, J.D., 350 Rittenhouse, G., 229, 293 Rivkin, S., 310 Roberts, H.H., 288 Roberts, J.L., 198, 207 Robertson, J.O. Jr., 17, 18, 65, 291,293 Robertson, S.D. Jr., 221 Rochon, R.W., 160, 166
367 Rogers, G.L., 29, 66 Romanovsky, Yu.E., 221 Rose, S.C., 58, 66, 161,166 Rosenbaum, M.S., 263, 281,291,293 Ross, T.E, 293 Rowaik, B.M.H., 224, 293 Rubey, W.W., 4, 6, 18, 19, 25, 28, 29, 31, 37, 55, 56, 63, 65, 66, 95, 198, 207, 309, 346, 350 Rubino, E., 292 Russell, W., 295, 296, 309 Saghir, M.Z., 326-328, 344, 348, 350, 351 Sahay, B., 149, 191,207, 245, 247-249, 293 Salaev, S.T., 94 Samedov, F.I., 84, 95, 113, 114, 122 Samuels, S.G., 246, 293 Sarem, A.M.S., 189 Sargent, E.C., 237, 293 Savin, S.M., 283,294 Sawabini, C.T., 165, 251,258, 289, 290, 293 Sayles, EL., 223, 224, 227, 228, 233, 293 Schaar, G., 149 Scheidegger, R., 339, 351 Schmidt, G.W., 13, 19, 240, 293 Schoeller, H., 224, 233, 293 Schroder, EH., 358 Schultz, W.E., 149 Schwartz, R.J., 150 Seed, H.B., 207 Segonzac, G., 11,17, 64 Sekiguchi, K., 288 Serebryakov, V.A., 94, 124, 126, 128-130, 132-142, 149, 209, 220, 221, 224, 290, 295, 297, 298, 300-308, 309, 327, 331, 336, 339, 350, 353-358, 359 Seregina, V.N., 95, 207, 309 Serpas, C.J., 149 Serruya, C., 233, 293 Sexton, T.H., 148 Sharma, M.M., 18, 66 Sharp, J.M., 327, 351 Shata, A., 291 Shaw, J., 189 Shazly, M.M., 291 Shelton, J.W., 199, 207 Shenderey, L.E, 13, 18 Shimoda, S., 66 Shimp, N.E, 290
Shiram, C.R., 17, 64 Shirley, O.J., 95, 151,166 Shishkina, O.V., 253, 293 Shrestha, R.K., 189 Shriram, C.R., 206 Sidorov, A., 291 Silver, M.L., 207 Singh, S., 189 Siryk, L.M., 199, 206 Skempton, A.W., 246, 293 Slavin, V.I., 15, 17 Smirnova, E.M., 17 Smith, H.D., 149 Smith, J.E., 277, 279, 282, 293 Smith, S.W., 149 Snelling, R., 288 Snoeyink, V.L., 250, 293 Spencer, C.W., 2, 16, 18 Spivack, A.J., 293, 294 Srebrodolskiy, A., 309 Starostin, V., 140, 149 Steinfink, H., 267, 293 Stephenson, E.L., 224, 293 Stoessell, R.K., 233,294 Sudo, T., 55, 66 Sulin, V.A., 224, 234, 294 Suter, H.H., 198, 207 Swarbrick, R.E., 1, 10, 12, 16, 19, 24, 57, 63, 66
Tadepali, S.V., 175, 189 Tagiev, S.O., 121 Taneja, EK., 144, 149 Tang, Z.H., 291 Taylor, D.W., 33, 34, 67 Tdth, J., 207 Teige, G.M.G., 291 Teodorovich, G.I., 49, 67 Terzaghi, K., 25, 27, 36, 67, 309 Thorsen, C.E., 193,207 Tikhonov, A., 341,351 Timko, D.J., 14, 19, 142, 143, 147, 149, 161163, 165, 165, 166, 239, 247, 290, 292 Timm, B.C., 236, 237, 294 Timurziev, A.J., 59-62, 66 Tkhostov, B.A., 95, 309 Tolle, G.C., 148 Toth, J., 310 Towner, B., 179, 184, 185, 189
368 Traugott, M., 172, 190 Troyer, B., 189 Tura, A., 186, 190 Turekian, K.K., 290 Ulyanov, M.G., 221 Ungerer, E, 95, 339, 351 Vagin, S.B., 65 Van der Vliet, G., 58, 67 Van Moort, J.C., 1l, 19, 67 Van Olphen, H., 267, 272, 294 Vasseur, G., 224, 292 Vassoevich, M., 102, 122, 123, 150 Vaziri, H., 346, 351 Velde, B., 288 Verbout, J.L., 149 Verwey, E.J.W., 274, 294 Vik, E., 291 Viskovskiy, Yu.A., 293 Vogel, J.C., 291 Von Engelhardt, W., 233, 251,267, 281,294 Vorabutr, E, 140, 148, 152-155, 158, 162, 165, 165 Vorabutr, P.A., 13, 19, 244, 294 Vroluk, E, 290 Vukolovich, M., 300, 310 Wahl, J.S., 150 Wallace, R.H. Jr., 291 Wallace, W.E., 13, 19 Walsh, J.B., 188 Ward, H.L., 4, 18, 65 Wardlaw, H.W.R., 157, 166 Warner, D.L., 44, 67, 273,274, 294 Warris, B.J., 149 Warwick, R.A., 189 Washburne, C.W., 227, 233, 294 Watts, E.V., 4, 19, 24, 28, 67 Weaver, C.E., 11, 19, 67 Weintritt, D.J., 164, 166 Weller, EA., 45-47, 67 Weller, J.M., 78, 95, 102, 122, 123, 150 Wen-qia, W., 351 Wensaas, L., 291
West, E.R., 16 l, 166 Whalen, H.E., 45, 65, 135, 149 Whelan, J.K., 18, 291 White, D.E., 233, 294 White, W.A., 289 Whittaker, A., 95, 208, 327, 351 Wichmann, EA., 149 Wijeyesekera, D.C., 261,263, 275,294 Williams, L.B., 294 Wilson, C.C., 199, 208 Wilson, G.J., 162, 167 Wilson, J.S., 4, 19, 55, 67 Wilson, T.R.S., 292 Wolf, K.H., 78, 94, 294, 353,358 Wood, L.A., 292 Yakubov, A.A., 83, 95, 200, 208 Yassir, N.A., 311,344, 346, 347, 351 Yeh, H.-W., 283, 284, 294 Yen, T.E, 17, 19, 64, 290, 294, 358 Yi-rang, Y., 319-324, 351 Yilmaz, O., 178, 190 Yoshida, C., 314, 351 You, C.E, 294 Youd, T.L., 208 Youmans, A.H., 141,150 Young, A., 12, 19, 67 Young, ES., 156, 159, 166, 167 Yu, P., 189 Yu, Z., 311,322, 323, 325, 326, 351 Yusuf-Zadeh, Kh.B., 87, 88, 95 Zadeh, A.A., 82, 94 Zamora, M., 95 Zanier, A.M., 51, 66 Zavgorodniy, A.L., 200-205,208 Zeinalov, M.M., 95 Zen, E., 12, 16, 17, 65 Zhuchkova, A.A., 224, 252, 291, 292 Zierfuss, H., 58, 67 Zilberman, L.V., 209, 221 Zilberman, V.I., 209, 212, 214-217, 219, 221 Zkhus, I.D., 208 Zoback, M.D., 189 Zoeller, W.A., 140, 150, 157, 167
369
Subject Index Abnormality coefficient, 15 Africa, Niger Delta, 7 Akchagyl Formation, 87 Alberta Basin (Canada), 296 Alyaty-more Field (Azerbaijan), 109 Amoco, generalized density, 172-173 Analytical models, 314-316 Ankleshvar (India), 98 Appelo's Donnan equilibrium model, 279-281 Apsheron Archipelago (Azerbaijan), 82-92, 102, 107 Peninsula (Azerbaijan), 82-92, 102-104, 315 - Offshore Zone (Azerbaijan), 102-104 Aquathermal expansion, 10 pressuring, 57 Arco Kendrick well, 307 Assam-Arakan system (India), 191 Astrakhan Arch (Russia), 211 Athy's compaction model, 44 Australian North West Shelf, 230-232 AVO signatures, 175, 179, 183, 184 Azerbaijan, 69, 79, 81-92, 97-120, 129, 187, 200, 226 -
-
Brine, densities, 26 Brinkman equation, 320, 344 Bukhara-Khiva Region (Uzbekistan), 211 Bulla Island Oil Field (Azerbaijan), 84, 86, 87, 89, 90, 109 Bulla Sea Oil Field (Azerbaijan), 86, 89, 90 Bulla-more Field (Azerbaijan), 109 Buregskiy shales (Byelorussia), 200, 202, 204, 205 Burst's compaction model, 49, 99, 100 Cambay Basin (India), 93, 98 Caprocks, 169 Carpathian Basin (Ukraine), 210 Caspian Depression (Azerbaijan), 315, 316, 317 Caspian Sea, 57-62 Catagenesis, 97, 348 Chia-Surkh (Pakistan), 56 Chocolate Bayou Field (Brazoria County, TX), 237 Clay-mineral transformation, 105-110, 264-265 Coefficient of irreversible compaction, 297, 298 - thermal expansion, 306 Colorado Basin (CO), 296 Compaction coefficient, irreversible, 297 -, clays, 271 equipment, 261 -, fluid chemistry model, 272-273 , , Wagner's double-layer theory, 273 - model, Athy's, 43 -, Beall's, 49, 51 -, Burst's, 49, 99-100, 266-279 - - , Chernov's, 49 dehydration, 99 - -, Hedberg's, 43 - -, Overton's, 51 - -, Power's, 47, 50 - - , Teodorvich's, 49 - - , Weller's, 46 -
Bakhar Oil Field (Azerbaijan), 84, 86, 109 Bakhmut evaporite series (Ukraine), 217 Baku Archipelago (Azerbaijan), 82-92, 97-120, 226 Barsukovskaya Field (Belorussia), 204 Beall's compaction model, 49, 51 Bengal Basin (India), 245, 248 Bibieibat Field (Azerbaijan), 109 Biot's number, 346 Bit size, 155 Black Sea marine mud, 253 Bodra area (India), 245 Bolt's pressure filtrate model, 277 Boltzman constant, 274 Box-type fluid flow, 333, 334, 337 Braguny Oil Field (Russia), 356, 357, 358
-
-
-
-
-
,
370 -, Zanier's, 51 - models, 43 - spring model, 33-36 -, steps of, 264 Compressional curves method, 137-140 Conductivity, 339 Continuity equation, 315, 345 Convection, forced, 71, 78 -,free, 71 Cosamba Field (India), 98 Coulomb's law, 104 -
Darcy's law, 76, 219, 315, 320, 330, 331, 340 Definitions, 21, 24, 93 Density contrast, 63 of brines, 26 Denver Basin (CO), 295 Detrital clays, 284 Deviatoric stress state, 31, 32 d-exponent factor, 69, 151, 152, 153, 154 Diagenesis, 11, 48, 97, 348 Diapiric rocks, 198 Diapirism, shale, 7-8, 198 Dilution factor, 242 Disequilibrium compaction, 235 Distribution, pressure, 69 Dnepr-Donets Basin (Ukraine), 133, 209, 210,211,213 Drag, drilling, 160 Drammen, marine clay (Norway), 258 Drilling bit wear, 156 Drilling hydraulics, 153 mud, gas cut, 160 - -, pressure kicks, 161 -, shale cuttings, 163 - -, shale factor, 164 rate, 151 - -, d-exponent, 151-156 - - , equations, 156-157 Dutta's method, 172 Duvannyy Oil Field (Azerbaijan), 87, 89, 90, 109 Dynamic models, 312, 317 -
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Eaton's fracture pressure gradient, 17 l - 172, 174 Economics, 14
Effective stress, Amoco generalized, Gulf Coast, 172-173 -, Dutta's method, 172 -, Eaton's exponent, 170-171, 174 -, Fillippone, 172 Efremov Field (Ukraine), 212 Empirical calibration (PNC logs), 145 Energy balance equation, 345 Equivalent depth method, 135-136 Evaporite sequences, 209, 213 -
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Faulting, 6, 7, 192, 197 Fick's law, 219 Fillippone method, 172 Flowline mud temperature, 161, 162 weight, 160 Fluid flow, box-type, 333 Formation volume factor (EV.E), 27 Frio Clay (TX), 236 Gas migration, 59-62, 218, 219 Geophysical data, 169-170 Geothermal gradient, 108, 109, 111 temperature, 8-10 Gibbs' free energy, 114, 115, 116 Gompertz curve, 314 Granite Wash Formation (Amarillo, TX), 2 Gravitational consolidation, 318 Growth faults, 6, 57, 192-194 Gryazevaya Sopka Field (Azerbaijan), 109 Gulf Coast Region (U.S.A.), 2, 4, 6, 8-10, 24, 58-59, 158 Gyuneshli Field (Azerbaijan), 109 -
Hackberry Field (LA), 240, 241,242 Haltenbanken area (Norway), 240 Haynesville Salt (MI), 181 Hedberg's compaction model, 44 Henry's law, 219 Hook's law, 36, 320 Hydrochemical inversion, 114 Hydrostatic pressure gradient, 1, 24, 25, 39-42, 93 Illinois Basin (IL), 226 Impedance inversion, 178 Isotope studies, interstitial fluids, 282, 283 Kagichev Field (Ukraine), 213 Karabagly Field (Azerbaijan), 109
371 Kazakhstan, 57-62 Khamamdag-more Field (Azerbaijan), 109 Kharasavey Oil Field (Siberia), 140, 141 Khaur Oil Field (West Pakistan), 4, 56 Kicks, pressure, 161 Klemme's basin classification, 230-232 Kobystan region, 83 Kotova's empirical model, 275 Kozeny-Carman equation, 339 Krasnosel'skaya Field (Belorussia), 204 Krestishchenskoye gas-condensate field (Ukraine), 215-217 Kuban Depression, 129 Kura Region (Caucasus), 82-92, 102-104, 304 Kutch Basin (India), 245, 247, 248, 249 Kyurovdag Field (Azerbaijan), 109
Navagam (India), 98 Navier-Stokes equation, 346 Nepsko-Botuobin anticline (Siberia), 132, 224 Neural network performance, 177 Niger Delta (Nigeria), 7, 8, 198 Nigeria, 323 Nigerian Basin (Nigeria), 323 Normal compaction trend method, 136-137 North Caspian Basin (Russia), 297, 298 North Sea (Norway), 12, 69, 140 North Sea Viking Graben, 232 North West Shelf (Australia), 232 Numerical modeling, 318
Laboratory experiments, compaction, 251-264 Leachate volume, 242 Lithostatic gradient, 3 Louann Salt (LA and TX), 7 Lower Kura Depression (Azerbaijan), 82 Lower Surakhan shales (Azerbaijan), 87
Oil Stones Oil Field (Azerbaijan), 84, 86, 87 Oil-seawater mixtures, compaction, 270-272 Oklahoma Basin (OK), 295, 297, 298 Orenburg Field (Russia), 213 Organic matter decomposition, 59 Organism growth model, 313 Osmosis, 11-12, 63 Osmotic pressure, 12 Overbalance (drilling), 156
Maintenance of AHFR 51-55 Manchester Field (LA), 240, 241 Mangyshlyak Peninsula (Kazakhstan), 57-62 Maracaibo Basin (Venezuela), 232 Marangoni convection, 346 Mechanisms of AHFP formation, 22, 23, 55-63 Medvedov Field (Azerbaijan), 212 Melikhov Field (Ukraine), 212 Middle Kura Basin (Georgia), 133,295 Migration, fluids, 59-62, 80 Modeling, fractures, 326 Modeling, salt barrier, 325 Models, compaction, 43-51 Monte Carlo method, 312 Montmorillonite particle sizes, 117, 118 Montmorillonite/kaolinite ratio, 98 Morrow sands (OK), 296 Mud lumps, 198-199 - volcanoes, 83-85, 198-199, 250 Mudrocks, 225 Muradkhanly Oil Field (Azerbaijan), 106
Pakistan, 4 Paleo-overpressure conditions, 311 Palmer's water classification, 233, 234 Pavlov's model, 275 Permafrost, effect of, 130-131 Permeability, distribution, 74-75 -, tensor, 76 Persiyanin Bank (Azerbaijan), 86, 88 Peschanyy-Sea (Azerbaijan), 86 Piezoconductivity coefficient, 329, 341,342, 343 Poisson's ratio, 36-37, 174, 185,305,347 Pol'ster's capillary model, 276 Pore pressure versus clay content, 104 size of shales, 106 - fluid diagenesis, 228 - water chemistry, 114 Porosity-density variations with depth, 42 Porosity-depth relationship, 102 -pressure correlation, 81 Port Canning well (India), 245, 247 Potwar Plateau (West Pakistan), 4 -
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372 Powder River Basin (WY), 297, 298, 301, 302, 304, 305, 308 Power's compaction model, 47-50 Precursor indicators, salt-beating sections, 211-213 Pressure detection techniques, 123-140 - - -, borehole sonic, 123, 124 borehole sonic, bright spot, 124 -, well log data, 123 - distribution, 69, 70-71 gradients, 38, 39 -, process-oriented model, 298 Pripyatskiy Deep (Byelorussia), 200, 201, 203, 204, 205 Proportional effects, 313 Pulsed neutron capture (PNC) logs, 14-145 Punjab (India), 191 -
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Shebelinka Field (Ukraine), 211,212 Shiwu Fault Depression (China), 250 Siberian Platform (Siberia), 296, 304 Sigma (E) shale ratio, 145 - (27) trends, 142-146 - ( r ) values, 141-146 ( r ) , empirical calibration charts, 145 (27), equivalent depth method, 146 Smectite-illite transformation, 264-270 Smith's Gibbs equilibrium model, 281-282 Songliao Basin (China), 248-249 Sonic velocity-resistivity correlation, 187-188 South Caspian Basin (Azerbaijan), 81-92, 97-120, 173-175 226, 227, 250-251, 315,316,317,318,319 South Sumatra Basin, 232 Specific weight, water, 1 various fluids, 38 Spring models, 33-36 Springer Group (OK), 199 Stress notation, 5 Stress, compacting shales, 29-36 -, deviatoric, 31-32 -, hydrostatic, 31 -, tensor, 32-33 Subsidence, 353-358 Sulin's water classification, 234-235 Surinmastgarh Anticline (India), 191 Svyatogor rhythm (DDB, Russia), 211-212) -
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Radioactivity, 140-141, 142 RAMIN program, 114 Rechitskaya Field, South, 204 Red Sea marl, 228 Reservoir engineering concepts, 13, 14 Resistivity ratios, 13 Resolution of stress field, 30 Rincon-Dos Cuadros (CA), 42 Rio Grande Embayment (TX), 196, 197 River deltas, 8, 198 Sacramento Basin (CA), 232 Salinity principle, 239 variations, compacting sediments, 236-238 Salt barrier, 325, 326 - domes, 8-10, 24, 193-194, 213 - movement, 198 - plugs, 213, 214-217 San Juan Basin (NM), 296 Sangachaly Oil Field (Azerbaijan), 86, 87, 89, 90, 109 Santa Cruz Basin (CA), 285, 286 Seismic AVO data, 175, 179, 182-183 Seismic data, impedance inversion, 178 Seismic methods, 169-188 Semilukskiy carbonates (Belorussia), 205 Shale cuttings parameters, 163-164 Shale water influx, 146 -, resistivity ratios, 15 Shear deformation, 346 Shebelin Gas Field (Ukraine), 133 -
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Tadzhikistan, 211 Taylor's model, 33 Tectonic compression, 4, 16, 56 extension, 62 TEMISPACK finite volume model, 235 Temperature distribution, basin, 324 gradient, 10 Tepetate Oil Field (LA), 143 Tersk-Sunzhen area (Russia), 354, 355, 357, 358 Terzaghi's model, 36, 79 Thermobaric conditions, 110-113 Thermodynamic gradient, 296 - models, 225 Tomographic inversion, 174 Torque (drilling), 159 Transfer, load, 37-41 Transference of pressure, 57 -
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373 Transformation, depth of clays, 119 Turkmenistan Basin, 129 -, east, 211 Tuscaloosa Formation (LA), 284 Undercompaction, 4, 55-56 Urey's law, 2 ! 9 Uzbekistan, 214 Vasilevichskaya Depression (Belorussia), 201,204 Velocity profiles, 182 Ventura Basin (CA), 232 Ventura Oil Field (CA), 4, 24, 56 Vermilion area (LA), 194 Vetkhinskaya Field (Dnepr-Donets Basin), 201,204 Viking Graben (North Sea), 69, 232 Volcanoes, mud, 84, 85 Volga-Ural Basin (Russia), 98, 295, 298, 315 Warner's double-layer model, 273-275
Water classification, Palmer, 32, 232, 234 - - , Schoeller, 224 - -, Sulin, 233,234-235 - , closed system, 225 -, influx, shale, 146-147 - , open system, 225 - , reaction models, 225 - , sampling, 229 -, thermodynamic model, 225 Weakness zones, tectonic, evaporites, 215 Weller's compaction model, 46-47 West Kuban Depression (Russia), 137, 139, 297, 298, 336 Western Siberia (Russia), 97 Wichita Mountains (OK), 2 Wilcox Formation (Gulf Coast, U.S.A.), 11 Williston Basin (U.S.A.), 232 Wind River Basin (U.S.A.), 232 Yastrebinoe Oil Field (Russia), 357, 358 Young's modulus, 36, 175 Zhiloy Island Oil Field (Azerbaijan), 86
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