Studies in Abnormal Pressures 38

Developments in Petroleum Science, 38 studies in abnormal pressures DEVELOPMENTS IN PETROLEUM SCIENCE Advisory Edito...

Author: Walter H. Fertl | Richard E. Chapman

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Developments in Petroleum Science, 38

studies in abnormal pressures

DEVELOPMENTS IN PETROLEUM SCIENCE Advisory Editor: G.V. Chilingarian Volumes 1, 3 , 4 , 7 and 13 are out of print 2. W.H. FERTL - Abnormal Formation Pressures 5 . T.F. YEN and G.V. CHILINGARIAN (Editors) -Oil Shale 6. D.W. PEACEMAN - Fundamentals of Numerical Reservoir Simulation X. L.P. Dake - Fundamentals of Reservoir Engineering 9. K. MAGARA - Compaction and Fluid Migration 10. M.T. SILVIA and E.A. ROBINSON - Deconvolution of Geophysical Time Series in the Exploration for Oil and Natural Gas I I . G.V. CHILINGARIAN and P. VORABUTR - Drilling and Drilling Fluids 12. T.D. VAN GOLF-RACHT - Fundamentals of Fractured Reservoir Engeneering 14. G. MOZES (Editor) - Paraffin Products I SA. 0. SERRA - Fundamentals of Well-log Interpretation, 1. The acquisition of logging data I SB. 0. SERRA - Fundamentals of Well-log Interpretation, I . The interpretation of logging data 16. R.E. CHAPMAN - Petroleum Geology 17A. E.C. DONALDSON, G.V. CHILINGARIAN and T.F. Yen (Editors) -Enhanced Oil Recovery, I. Fundamentals and analyses I7B. E.C. DONALDSON. G.V. CHILINGARIAN and T.F. Yen (Editors) - Enhanced Oil Recovery, 11. Processes and operations I XA. A.P. SZILAS - Production and Transport of Oil and Gas, A. Flow mechanics and production (wcond completely revised edition)

I XB. A.P. SZILAS Production and Transport o f Oil and Gas, B. Gathering and Transport ~

(\ccond completely re\iwd edition)

19A. G.V. CHILINGARIAN, J.O. ROBERTSON Jr. and S. KUMAR - Surface Operations in Petroleum Production, I 19B. G.V. CHILINGARIAN, J.O. ROBERTSON Jr. and S. KUMAR - Surface Operations in Petroleum Production, I1 30. A.J. DIKKERS - Geology in Petroleum Production 21. F. RAMIREZ - Application of Optimal Control Theory to Enhanced Oil Recovery 22. E.C. DONALDSON. G.V. CHILINGARIAN and T.F. Yen - Microbial Enhanced Oil Recovery 23. J. HAGOORT - Fundamentals of Gas Reservoir Engineering 24. W. LITTMANN -Polymer Flooding 25. N.K. BAIBAKOV and A.R. GARUSHEV - Thermal Methods of Petroleum Production 26. D. MADER - Hydraulic Proppant Farcturing and Gravel Packing 27. G. DA PRAT Well Test Analysis for Naturally Fractured Reservoirs 2x. E.B. NELSON (Editor) - Well Cementing 29. R.W. ZIMMERMAN - Compressibility of Sandstones 30. G.V. CHILINGARIAN, S.J. MAZZULLO and H.H. RIEKE - Carbonate Reservoir Characterization: A Geologic-Engineering Analysis, Part I 31. E.C. DONALDSON (Editor) Microbial Enhancement of Oil Recovery - Recent Advances 32. E. BOBOK Fluid Mechanics for Petroleum Engineers 33. E. FJER, R.M. HOLT, P. HORSRUD, A.M. RAAEN and R. RISNES petroleum Related Rock Mechanics 34. M.J. ECONOMIDES - A Practical Companion to Reservoir Stimulation 35. J.M. VERWEIJ - Hydrocarbon Migration Systems Analysis 36. la. DAKE - The Practice of Reservoir Engineering 37. W.H. SOMERTON - Thermal Properties and Temperature related Behavior of Rocklfluid Systems 38. W.H. FERTL, R.E. CHAPMAN and R.F. HOTZ (Editors) - Studies in Abnormal Pressures 39. E. PREMUZIC and A. WOODHEAD (Editors) - Microbial Enhancement of Oil Recovery Recent Advances - Proceedings of the 1992 International Conference on Microbial Enhanced Oil Recovery ~

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Developments in Petroleum Science, 38

studies in abnormal pressures Edited by WALTER H. FERTL~ Late President, Atlas Wire Services, Houston, Texas, USA

RICHARD E. CHAPMAN The University of Queensland, Brisbane, Queensland, Australia and ROD F. HOTZ Western Atlas International, Houston, Texas, USA

ELSEVIER, Amsterdam -London -New York -Tokyo

1994

ELSEVIER SCIENCE B.V. Sara Burgerhartstraat 2.5 P.O. Box 21 I. I000 AE Amsterdam, The Netherlands

ISBN: 0-444-X9999-5

0 I994 Elsevier Science B.V. All rights reserved No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means. electronic, mechanical, photocopying, recording or otherwise, without the prior written permission of the publisher, Elsevier Science B.V., Copyright & Permissions Department. P.O. Box 521. IOOO AM Amsterdam, The Netherlands. Special regulations for readers in the USA - This publication has k e n registered with the Copyright Clearance Center Inc. (CCC). Salem. Massachusetts. Information can k obtained from the CCC about conditions under which photocopies of parts of this publication may k made in the USA. All other copyright questions. including photocopying outside of the USA, should be referred 10 the publisher. No responsibility is assumed by the publisher for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods. products, instructions or ideas contained in the material herein. This book is printed on acid-free paper Printed in The Netherlands

V

PREFACE

This should have been Walter’s book. It was his idea, and it grew from his very successful first book, Abnormal Formation Pressures, published by Elsevier Science Publishers in 1976. Unfortunately he did not live to see his idea take more than general form. He died on November loth, 1990. I say it should have been Walter’s book because the double tragedy was that his own contributions to it were either not written or were lost. So what was left was the work of those whom he had invited to contribute to the book. I became involved in 1987 as a contributor. In 1988 he invited me to join him as co-editor. We had known each other since the middle 1970s, and my r81e was to have been more as an editorial adviser to him. Rod Hotz worked with and eventually for Walter during the many years of their employment with Dresser Atlas, which eventually became Western Atlas International in 1987. He edited most of Walter’s work and co-authored a number of papers with him. He had begun to assist Walter in preparing both text and figures for the second book prior to November loth, 1990. After Waiter’s death there were many difficulties in restoring the project. Rod Hotz was able to locate most of the files Walter had accumulated for this book and I am very grateful to him for all the help he has given me. With the contributors coming from North America, it would have been virtually impossible for an editor across the Pacific to have done it unaided. I am also very grateful to Ed Bigelow for accepting Rod’s invitation to fill the gaps left by Walter - the chapters on worldwide occurrences of abnormal pressures and on their detection and evaluation with well logs. Last, but certainly not least, I am very grateful to the contributors for their patience with me and for updating their chapters so long after they had first written them. This then is not the book Walter Fertl would have produced. It is the best we could do without him. We dedicate it to his memory. RICHARD E. CHAPMAN

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vii

WALTER H. FERTL

Dr. Walter Hans Fertl was a relatively young man when he died in 1990, but he had achieved much. Somehow he had managed to combine a prolific writing and lecturing career with a professional career of steadily increasing executive responsibility. Walter was born in Vienna, Austria, in 1940. He studied at the University of Mining and Metallurgy at Leoben and then emigrated to the United States in the mid-1960s. At the University of Texas at Austin he received his MS and PhD degrees in petroleum engineering before launching off into his professional career. That in itself was no small achievement for one whose childhood and early education had been in the German language.

Walter Hans Fertl, 1940-1990.

...

Vlll

WALTER H. FERTL

After eight years with Conoco’s Production Research Department he moved to Dresser Atlas in 1976 (the year his book Abnormal Formation Pressures was published) as Director of Interpretation and Field Development. In 1981, largely through his initiative, Dresser Petroleum Engineering Services was formed; and he was its Vice President and General Manager until 1983 when he became Vice President of Marketing for Dresser Atlas. Four years later he was promoted to Executive Vice President - but the following year, 1988, he was appointed President of Atlas Wireline Services. It was to be his last appointment but one. His last appointment, the one we all have to keep sooner or later, was on November loth, 1990. The career here sketched would be regarded as highly satisfactory by anyone, but that was not all. While doing all these things he found time to publish over 300 technical papers and articles, write or contribute to ten books, acquire 27 U.S. patents, and lecture around the world. He was honoured by Iran and Thailand, by the Society of Professional Well Log Analysts with their Gold Medal and their Presidency, by Dresser Industries with their Silver Medal Award for Technical Creativity, by the Society of Petroleum Engineers as a Distinguished Lecturer, and by four U.S. Universities with the degree of Doctor Honoris Causa. In brief, Walter’s professional life had that rare mix of quality and quantity. No one is indispensable, but some are more so than others. Walter’s influence on all those around him was great, as was his influence on petroleum engineering.

FOREWORD

Abnormal formation pressures are no less important today than they were in 1976 when Fertl’s first book on the subject was published. What has changed is that the topic is now beyond the scope of a single mind, and for this reason, the book consists of chapters contributed by specialists in their field. Bigelow begins with a summary of the occurrence of abnormal pressures around the world. They are known to occur in all the continents except Antarctica. Chapman discusses the geology of abnormal pressures and reminds us that they occur in two distinct geological contexts, regressive sequences as in the U.S. Gulf Coast and the Niger delta, and in rift basins as in the North Sea and the Atlantic seaboard of the Americas. He follows this with a survey of causes and essential theory. The ever-increasing number of abnormally pressured producing reservoirs has demanded understanding of the reservoir engineering concepts involved. These are discussed by Bernard. And because water is always involved, Chilingarian, Rieke and Kazi describe the essential pore-water chemistry. Many of the problems of fifteen years ago are still problems today, but modern technology has reduced them. For example, the need to know the depth to abnormal pressures, and their magnitude, before drilling has been felt for at least 50 years - it is not sufficient simply to rely on local experience. In new areas it is essential for proper planning to have some idea of the risks involved. Once drilling starts, the risks must be updated; and once drilling has been completed, the pattern of pore pressures must be evaluated. These topics are treated here by their experts. Kan and Sicking describe the geophysical methods of detection and evaluation of abnormal pressures using geophysical methods before drilling. Bigelow describes their evaluation using well logs. Hardage tackles the problem of looking ahead of the bit using seismic methods in real time. Desbrandes and Clayton discuss the acquisition of parameters while drilling - the measurement-while-drilling(MWD) technology. Shallow abnormal pressures occur in many parts of the world and Bourgoyne assesses these hazards. Some hazards remain, and if the worst happens and a well blows out, it is essential to reduce the damage to the environment and to humans to a minimum. Offshore this usually involves drilling a relief well. Desbrandes treats this topic. An important development in the theory of abnormal pressures is that they can be caused by petroleum generation. Although V.C. Illing in 1938 wrote that there must be a volume increase during petroleum generation, it is only comparatively recently that abnormal pressures from this cause have been documented. Spencer looks at this aspect, taking examples from the Rocky Mountain region.

X

FOREWORD

Woods discusses the resource potential of natural gas in the context of abnormal pressures; and finally, Leach uses a massive database from the U.S. Gulf Coast region to examine the distribution of petroleum with respect to abnormal pressures in regressive sequences. It is sometimes thought that abnormal pressures are important only to the petroleum industry. This is not true, although this book does concern itself mainly with the technical and industrial aspects. It seems absolutely certain that abnormal pressures have been generated during the development of past sedimentary basins, just as they are developed in present basins such as the U.S. Gulf Coast, the Niger delta and the North Sea. And it seems absolutely certain that the geological consequences of abnormal pressures were the same then as they are now, leading to deformation that is largely controlled by stratigraphy in regressive sequences, and to the prolonged development of rift basins. While this book has been written primarily for the practising petroleum engineer (in the broadest sense) it will not be without interest to geologists interested in abnormal pressures as a geological phenomenon. RICHARD E. CHAPMAN

xi

LIST OF CONTRIBUTORS

W.J. BERNARD

Louisiana State University,Department of Petroleum Engineering, Baton Rouge, LA 70803-6417, USA

E.L. BIGELOW

Atlas Wireline Services, PO. Box 1407, Houston, TX 77251-1407, USA

A.T BOURGOYNE, Jr. Louisiana State University,Department of Petroleum Engineering, Baton Rouge, LA 70803-6417, USA R.E. CHAPMAN

Glaston Hill, Upper Camp Mountain Road, Camp Mountain, Qeensland 4520, Australia (formerly of The University of Queenrland)

G.V. CHILINGARIAN School of Engineering, University of Southern California, Los Angeles, CA 90089-1211, USA R. CLAYTON

ENSCO Technology Co., 1776 Yorktown, Suite 750, Houston, TX 77056-4114, USA

R. DESBRANDES

Department of Petroleum Engineering, Louisiana State University,Baton Rouge,

LA 70803-6417, USA B.A. HARDAGE

Bureau of Economic Geology, The University of Texas at Austin, Austin, TX 78713, USA

TK. KAN

ARCO Exploration Research and Production Technology, 2300 West Plano Parkway, Plano, TX 75075-8499, USA

A. KAZI

Directorate General of Mineral Resources, PO. Box 345, Jeddah 21191, Saudi Arabia

W.G. LEACH

46 Yosemite Drive, New Orleans, LA 70131, USA (formerly of Texaco USA)

H.H. RIEKE

Directorate General of Mineral Resources, PO. Box 345, Jeddah 21191, Saudi Arabia

C.J. SICKING

ARCO Exploration Research and Production Technology, 2300 West Plano Parkway, Plano, TX 75075-8499, USA

C.W. SPENCER

US Department of the Interior; US Geological Survey, Box 25546, MS 940, Denver Federal Center;Denver; CO 80225-0046, USA

TJ. WOODS

Gas Research Institute, 1331 Pennsylvania Avenue, N.W, Suite 730 North, Washington,DC 20004-1703, USA

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CONTENTS Preface ..................................................................................... Walter H. Fertl ............................................................................. Foreword .................................................................................. List of Contributors ......................................................................... Chapter1. GLOBALOCCURRENCES OF ABNORMALPRESSURES .................... E.L. Bigelow 1.1. Introduction .......................................................................... 1.2. Abnormal pressure occurrences in the Middle East ...................................... 1.3. Abnormal pressure occurrences in Europe .............................................. 1.4. Abnormal pressure occurrences in Russia, Azerbaijan. and Kazakhstan ................... 1.5. Abnormal pressure occurrences in Africa ............................................... 1.6. Abnormal pressure occurrences in the People’s Republic of China ....................... 1.7. Abnormal pressure occurrences in South-East Asia, Australia, New Zealand and the Indonesian Archipelago .................................................................... 1.8. Abnormal pressure occurrences in the Asian sub-continent .............................. 1.9. Abnormal pressure occurrenm in South America ....................................... 1.10. Abnormal pressure Occurrences in North America ...................................... Acknowledgements ......................................................................... References .................................................................................

Chapter2. THEGEOLOGYOFABNORMALPOREPRESSURES ........................ Richard E . Chapman 2.1. History ............................................................................... 2.1.1. Early experiences................................................................ 2.1.2. The U S. Gulf Coast ............................................................. 2.2. Regressive sequences .................................................................. 2.2.1. Selected areas ................................................................... 2.2.1.1. Borneo .................................................................. 2.2.1.2. The Niger delta .......................................................... 2.2.1.3. The Mackenzie delta, Arctic Canada ...................................... 2.2.2. Generalizations ................................................................. 2.2.2.1. Stratigraphy ............................................................. 2.2.2.2. Associations ............................................................. 2.2.2.3. Growth structures ........................................................ 2.2.2.4. Abnormal pressures ...................................................... 2.3. Rift basins ................................................................... 2.3.1. Selected areas ................................................................... 2.3.1.1. The North Sea ........................................................... 2.3.1.2. Other rift-basin occurrences .............................................. 2.3.2. Generalizations ................................................................. 2.3.2.1. Stratigraphy . .................................................. 2.3.2.2. Growth faults .................................................. 2.3.2.3. The unconfor onformities ....................................... 2.3.2.4. Abnormal pressures ...................................................... 2.4. Synthesis ............. .................................................. Acknowledgements ......................................................................... References .................................................................................

V

vii ix xi

1

8 11 11 12 15 16

19 19 19 25 28 28 28 30 33 35 35 36 37 39 39 39 40 42 45 45 45 45 46 46 47 47

CONTENTS

XiV

.

ABNORMAL PORE PRESSURES: ESSENTIALTHEORY.POSSIBLE CAUSES. AND SLIDING Richard E Chapman 3.1. Propertiesoffluidsandtharoclrsthatcontain them 3.1.1. Statics 3.1.2 Capillary pressure, surface and inteffacial tension 3.1.3. Liquid-filled porous solids in static quilibrium 3.1.4. Bulk density..................................................................... 3.1.5. Pressure and stress .............................................................. 3.1.6. Field evidence of Rrzaghi's relationship 3.1.7. Compaction Chapfer3

3.2

................................................................ ..................................... .......................................................................... ................................. ....................................

.......................................... ..................................................................... 3.1.8. Do .M ..................................................................... Liquids in motion through porous rock# ................................................ 3.2.1. Henry Darcy's experiments and the coefficient of permeability .....................

3.21.1. Geometry and hydraulic radius of pore space .............................. 3.2.1.2 lbrtuosity ............................................................... 3.2.1.3. Intrinsic permeability in terms of sedimentary parameters 3.2.2. The limits of Darcy's law 3.2.3. Relative permeability 3.3. Pore pressures 3.3.1. Normal 3.3.2. Abnormally low pore pressures ................................................... 3.3.3. Abnormally high pore pressures .................................................. 3.4. Possible causes of abnormally high pore pressures 3.4.1. Reservoir geometry 3.4.2. Petroleum genesis 3.4.3. Clay-mineral diagencsis 3.4.4. O s m d 3.4.5. ltctonics 3.4.6. 'Aquathermal" .................................................................. 3.5. Sliding 3.5.1. Unlubricated sliding 3.5.2. Lubricated sliding Acknowledgements

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51 51 52 54 55 56 56 57 59 62 63 63

65 66 66 67 68 69 69 71 73

....................................... n .............................................................. 78 79 ............................................................... .......................................................... 80 80 ......................................................................... 81 ........................................................................ 81 84 ................................................................................ ............................................................. 84 87 ............................................................... ......................................................................... 88 88 References .................................................................................

Chapter 4. RESERVOIR ENGINEERING CONCEPTS IN ABNORMAL FORMATION ENVIRONMENTS ............................................................. W i l l i a m J.Bernard 4.1. Introduction 4.2 P/Z plots and drive mechanism 4.3. Abnormally pressured depletion drive reservoirs 4.3.1. Performance prediction if the enagy sources are independently quantifiable 4.3.2. Performance prediction using past reservoir performance .......................... 4.4. Abnormally pressured water drive reservoirs ............................................

.......................................................................... ........................................................ ........................................ ........

References .................................................................................

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CHEMISTRY OF POREWATBR G.V.Chilingarian. H.H.Rieke and A.Kazi 5.1. lntroduction 5.1.1. Fundamental problem: sea water versus pore water ................................ 5.1.2. Constraints: reliability of sampling and water analyses ............................. 5.2. Compositionof subsurface brines 5.2.1. Salinity variations in compacting sandstones and d a t e d shales

Chapter5

....................................................... ..................

93 93 94 96 98 99 103 105 107 107 107 110 111 112

CONTENTS

xv

5.2.1.1. Field case studies ........................................................ 5.2.1.2. Laboratory experiments .................................................. 5.3. Fluid chemistry compaction models .................................................... 5.3.1. Non-thermodynamic approach ................................................... 5.3.1.1. Warner’s double-layer model ............................................. 5.3.1.2. Kotova and Pavlov’s empirical model ...................................... 5.3.1.3. Pol’ster’s capillary model ................................................. 5.3.2. Thermodynamic approach ....................................................... 5.3.2.1. Bolt’s pressure filtrate model ............................................. 5.3.2.2. Appelo’s Donnan equilibrium model ...................................... 5.3.2.3. Smith’s Gibbs equilibrium model ......................................... 5.4. Summary and conclusions ....................................................... References .................................................................................

114 120 136 137 137 139 140 142 144 144 146 147 149

Chapter 6. PRE-DRILL GEOPHYSICAL METHODS FOR GEOPRESSURE DETECTION AND EVALUATION ........................................................... T K . Kan and C.J. Sicking 6.1. Introduction .......................................................................... 6.2. Velocity ............................................................................... 6.2.1. Velocity from laboratory measurements ........................................... 6.2.2. Velocity from well logs ........................................................... 6.2.3. Velocity from VSP ............................................................... 6.2.4. Velocity from seismic ............................................................ 6.3. Seismic data acquisition, processing and interpretation .................................. 6.3.1. The seismic method - acquisition ............................................... 6.3.2. The seismic method - processing ................................................ 6.3.3. The seismic method - interpretation ............................................ 6.4. Pressure calibration and pre-drill geopressure detection ................................. 6.4.1. Case studies ..................................................................... 6.4.2. VSP ............................................................................ 6.5. Non-seismic geophysical techniques for geopressure prediction .......................... 6.5.1. Gravity analysis ................................................................. 6.5.2. Other geophysical methods ...................................................... 6.6. Summary .......................................................... .. References .................................................................................

.. Chapter 7. WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE E.L. Bigelow 7.1. Introduction .......................................................................... 7.2. Acoustic methods ..................................................................... 7.2.1. Method A ....................................................................... 7.2.2. Method B ....................................................................... 7.2.3. More recent depth of burial ...................................................... 7.2.4. Advancements in acoustic logging ................................................ 7.2.5. Possible limitations and pitfalls of Ar ............................................. 7.3. Density methods ...................................................................... 7.4. Conventional neutron methods ......................................................... 7.5. Resistivity methods .................................................................... 7.5.1. Approach A ..................................................................... 7.5.2. Approach B ..................................................................... 7.6. Conductivity methods ................................................................. 7.6.1. Method A . ...................................................................... 7.6.2. Method B ......................... ..........................................

155 155 156 156 156 157 158 158 159 161 165 173 176 180 184 184 184 185 185 187 187 188 190 193 194 196 199 199 200 202 203 204 205 208 208

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CONTENTS

7.7. SP method ............................................................................ 210 211 7.7.1. The salinity principle ............................................................ 216 7.8. ?he shale formation factor method ..................................................... 218 7.9. Magnetic resonance method 7.10. Method utilizing downhole gravity measurements ....................................... 219 7.11. Pulsed neutron method ................................................................ 220 7.1 1.1. Method A ...................................................................... 223 7.11.2. Method B ......................................................................223 224 7.12. Recommended well logs for conventional pressure evaluation ............................ 224 7.13. Limitations of wireline methods ........................................................ 234 7.14. Conclusions ........................................................................... 235 References .................................................................................

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Chapter 8. SEISMIC PREDICTION OF OVERPRESSURE CONDITIONS 241 AHEAD OF THE BIT IN REAL DRILL TIME ................................. Bob A . Hardage 8.1. lntroduction .......................................................................... 241 8.2. Predicting ahead of the bit with VSP data .............................................. 241 8.3. The inverse VSP concept .............................................................. 244 245 8.4. Borehole sources ...................................................................... 8.5. The drill bit source .................................................................... 245 247 8.6. Predict-ahead data examples ........................................................... 250 References ................................................................................. Chaprer 9. MEASUREMENT WHILE DRILLING ......................................... R . Desbrandes and R . Clayton 9.1. Introduction .......................................................................... 9.2. Telemetry techniques .................................................................. 9.2.1. Hardwired telemctry ............................................................. 9.2.2. Acoustic telemetry ............................................................... 9.2.3. Electromagnetic telemetry ....................................................... 9.2.4. Mud pulse telemetry ............................................................. 9.2.5. Downhole recording ............................................................. 9.2.6. Measurement After Drilling (MAD) .............................................. 9.3. MWD sensors ......................................................................... 9.3.1. Directional steering and survey ................................................... 9.3.2. Gamma ray ..................................................................... 9.3.3. Resistivity ....................................................................... 9.3.4. Neutron porosity ................................................................ 9.3.5. Density ......................................................................... 9.3.6. Weight-on-bit, torque and bending moment ....................................... 9.4. Abnormal pressure detection with MWD ............................................... 9.5. Service company comparison ........................................................... Referenccs .................................................................................

251

Chapter 10. SHALLOW ABNORMAL PRESSURE HAZARDS ............................ Adam T Bourgoyne. Jr 10.1. Introduction .......................................................................... 10.2. Prevention of shallow gas flows ......................................................... 10.3. Developing contingency plans .......................................................... 10.4. Diverter dcsign ........................................................................ 10.5. Exit velocity ulculalion ................................................................ 10.6, Flowing pressure gradient calculation ...................................................

281

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251 252 252 253 254 255 257 258 259 259 266 266 268 268 269 272 275 277

281 282 285 287 288 291

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CONTENTS

............................................................... ............................................................. ............. ................................ ..................................................................... ...................................................................... ............................................................................. .......................................................................

10.7. Formation productivity 10.8. Equilibrium gas flow rate 10.9. Formation fracture pressure .......................................................... 10.10. Working pressure of diverter components : 10.11. Diverter anchors 10.12 Rate of emion 10.13. Plugging 10.14. Control y t c m 10.15. Design considerations for dynamic kill 10.16. Diverter operation ................................................................... 10.17. Special considerations for floating drilling vessels 10.18. Recommendations Adrnowledgements Appendix - Nomendatum.. References

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293 296

297 297 300 300

307 307 308 311

...................................... 312 ...................................................................314 ......................................................................... 315

............................................................... .................................................................................

315 316

chaprcr I1. RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS................ Robert Desbrandes 11.1. Introduction 11.2. Blowout flowrate 11.2.1. Formation resistance 11.2.2 Flow-string resistance 11.2.3. Crossplots .................................................................... 11.3. Blowout control ...................................................................... 11.3.1. Water flooding kills 11.3.2. Dynamic kills 11.3.3. Overbalance kills 11.3.4. High-rate production fills 1 1.3.5. Polymer kills 11.4. Directional planning and trajectory design ............................................. 11.5. Directional surveying ................................................................. 11.5.1. Single shots and multishots 11.5.2 SteeringtoolsandMWD 11.5.3. Northseekers 11.5.4. ltajeaory calculation 115.5. Accuracy models 11.6. Blowout well distance from relief well ................................................. 11.6.1. Electricalmethod ............................................................. 11.6.2. Active electromagnetic method 11.6.3. Passive magnetic method 11.6.4. "Qean'' bomhola methods 11.7. Blowout examples 11.7.1.Coxetal.No. 1 1 1.7.2. Bergeron No. 1 ................................................................ 11.7.3. Arun Field well No.CII-2 ..................................................... 11.8. Conclusions References

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Chapter 12 ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION . EXAMPLES FROM THE ROCKY MOUNTAIN REGION Charles W.Spencer 1 2 1. Introduction 122 Mechanisms for overpressuring world-wide

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319 319 319 319 321 322 322 322 324 325 326 326 326 327 327 327 328 328 329 330 331 332 332 333 335 335 337 338 339

340

343 343 345

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CONTENTS

12.3. Abnormally high pressure from hydrocarbon generation ................................ 12.4. Distribution and character of overpressure ............................................ 12.4.1. Greater Green River Basin .................................................... 12.4.2. Piceance Basin ................................................................ 12.4.3. Williston Basin ................................................................ 12.4.4. Uinta Basin ................................................................... 12.4.5. Bighorn Basin ................................................................. 12.4.6. Powder River Basin ........................................................... 12.4.7. Hanna Basin .................................................................. 12.5. Summary and conclusions ............................................................ Acknowledgements ......................................................................... References .................................................................................

Chaprer 13. INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS: A MACROGEOLOGIC PERSPECTIVE ...................................... Thomas J . Woods 13.1. Introduction ......................................................................... 13.2. Reservoir communication ............................................................. 13.3. Associated gas ....................................................................... 13.4. Non-associated gas ................................................................... 13.4.1. Macro-reserve data ............................................................ 13.4.2. Well data ..................................................................... 13.4.3. Recovery per section .......................................................... 13.4.3.1. Oklahoma ............................................................ 13.4.3.2. South Louisiana ...................................................... 13.5. Conclusions .......................................................................... References ............. ................................................................ Chapter I4. DISTRIBUTION O F HYDROCARBONS IN ABNORMAL PRESSURE IN SOUTH LOUISIANA. U S A .................................................. William G . Leach 14.1. Introduction ......................................................................... 14.2. Top of abnormal pressure ............................................................. 14.3. Hydrocarbon distribution versus top of abnormal pressure .............................. 14.4. Hydrocarbon distribution decreases with increased pressure ............................ 14.5. Hydrocarbon distribution versus depth and temperature ................................ 14.6. Hydrocarbon distribution decreases with increased temperature ........................ 14.7. Disappearance of hydrocarbons in high-pressure/high-temperatureenvironments ........ 14.8. Vertical fluid migration and hydrocarbon concentration ................................ 14.9. Probable source of Upper lkrtiary hydrocarbons ....................................... 14.10. Maximum hydrocarbon distribution ................................................... 14.11. Maximum hydrocarbon window ....................................................... 14.12. Probability of exploration/exploitationenhancement with MHW technique .............. 14.13. Probability of exploitation enhancement with SRR technique. .......................... 14.14. Future exploration and development potential ......................................... References .................................................................................

................................................................................... Practical Conversion Factors ................................................................ Subject index ............................................................................... Glossary

345 347 349 358 363 364 367 368 369 369 372 372

377 377

000 379 382 382 383 385 385 387 388 389

391 391 391 392 395 403 404 406 409 417 419 419 420 425 426 427 429 443 447

Studies in Abnormal Pressures. Developmenu in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.EHotz 0 1994 Elsevier Science B.V. All rights reserved

1

Chapter 1

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES E.L. BIGELOW

1.1. INTRODUCTION

In the petroleum industry, abnormal formation pressures have been found throughout the world (Fig. 1-1).Abnormal pressures are encountered both offshore and onshore, at deep and shallow depths, and in rocks from the beginning of the Paleozoic (Cambrian) to the Cenozoic era (Pleistocene). Abnormal pressures have occurred in all types of rocks - shales, shaly sands, evaporites, carbonates, etc. Abnormal formation pressures are defined as any departure from normal hydrostatic pressure at any given depth. The petroleum industry is profoundly affected by both the magnitude and occurrence of abnormally high-pressure environments. Overpressured regimes play an important role in the decision-making processes of corporate managers. Greatly affected are activities such as exploration and development decisions, drilling and well completion efforts, production operations, and associated reservoir engineering functions that are so vital to effective and efficient reservoir management.

Fig. 1-1. Global occurrences of abnormal formation pressure.

2

E.L. BIGELOW

1.2. ABNORMAL PRESSURE OCCURRENCES IN THE MIDDLE EAST

Shale and salt diapirs, plate tectonics, massive overlying evaporite sequences, and the contrasts in fluid densities found in large geological structures are the typical causes of overpressured regimes in the Middle East. In Iran and Iraq, overpressured formations are found. Pressure gradients ranging from 0.85 to 0.97 psi/ft (19.2 to 21.9 kPa/m) are known to occur (Fig. 1-2). Mud weights as high as 22 lb/gal(25.8 kN/m3) are sometimes needed to control a well. Abnormally high temperature gradients (2SoF/100ft, 4.6"C/100m) and overpressured zones are found in Saudi Arabia. Overpressured horizons have been noted in Oman and the United Arab Emirates also. Both offshore and onshore wells in the Red Sea region have encountered high pressure and high temperature gradients, and Yemen, in particular, is beginning to develop its petroleum resources. Formation Pressure, MPa 100

75

125

0

1

1

E

3 g

a

0

1

5

6 20'

2

4 FOCIII.IKXI

6

'

8

10

12

14

16

18

pFe55ure. thousand PSI

Fig. 1-2. Abnormal formation pressure environments in Iran (after Fertl, 1972). Courtesy of the Society of Petroleum Engineers.

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES

3

1.3. ABNORMAL PRESSURE OCCURRENCES IN EUROPE

Today, another focal point for activity in the petroleum industry is the North Sea. Abnormal formation pressures have been encountered in areas as far south as the Groningen gas field to as far north as the 62" latitude. Abnormal pressures are encountered in offshore areas of the United Kingdom, Norway, Denmark, Germany, and The Netherlands. In Mesozoic and Tertiary age formations, abnormal pressures demonstrate a broad variation in magnitude over the entire North Sea area. Gas-bearing Triassic sandstones and Upper Permian evaporites are known to be overpressured in several areas. Some of the more prolific fractured reservoirs have been in overpressured Upper Cretaceous chalks and chalky limestones offshore of Norway and Denmark. Reported pressure data from the Ekofisk field was 7000 psi (48.3 MPa) at 10,000 ft (3048 m). Drilling in localized waters of Norway and the United Kingdom often required mud weights in the range of 13 to 15.5 lb/gal (15.3 to 18.2 kN/m-3) to control shallow, high pressure, low volume gas pockets. Thick gumbo shales also cause drilling problems down to depths of about 7000 ft (2134 m). Pressure profiles are shown in Fig. 1-3. Throughout the 1980s oil-based muds were the dominant drilling fluid in the North Sea area. Methods used for predicting and evaluating pressures in the North Sea are very similar to techniques developed years earlier in the United States, and these were a combination of seismic, drilling, and logging parameters. Data from a North Sea well demonstrates good agreement between predicted and actual pressures (Fig. 1-4). Drilling activities in the Celtic Sea offshore Ireland have encountered thick, folded, and faulted sediments that contain hydrocarbon, and overpressured shales are also present. Sp Gr

Sp Gr

=i U.5 L 16 --i -8 $9 -L' 11.

MW.

*/gu

ID)

MW.

rlo.1

Fig. 1-3. ?pica1 pressure profiles in (a) Ekofisk area and (b) Zechstein evaporite section of the North Sea (after Rehm, 1972). Courtesy of the Society of Petroleum Engineers.

4

E.L. BIGELOW

1 P ~ I O Tt o

After art I

arliilng

I

~

05 2.

SONIC L O G

0

3Predicted Drerrure 100

f

AC tuat

1

4-

normal verrure

15

5-

= o

6-

f a

7-

8 .-

E 2

; a 0 8

c? 8 -

25 9-

10

-

3 TOO

oram

I

35 12

Fig. 1-4. Comparison of the predicted and actual downhole pressure environment in the North Sea area (after Herring, 1973). Courtesy of Petroleum Engineer.

Abnormal pressures have also been encountered in the Mediterranean, Adriatic, and Aegean Seas. The Apennine Foredeep, on the Adriatic side of Italy, has led to several substantial hydrocarbon discoveries. Both onshore and offshore wells have encountered abnormal pressures that caused drilling problems, blowouts, and casing collapse. Modern pressure evaluation techniques have been successful in eliminating most of the early problems. An offshore overpressure environment from the Adriatic is shown (Fig. 1-5).

1.4. ABNORMAL PRESSURE OCCURRENCES IN RUSSIA, AZERBAIJAN, AND KAZAKHSTAN

More than 100 Russian wells were studied about 20 years ago. The data came from boreholes that penetrated formations of Devonian, Carboniferous, Mesozoic, and Tertiary age. The Devonian rocks, particularly those found in the Saratov and Kuybyshev regions, demonstrated pressures that differed little from hydrostatic, only occasionally exceeding hydrostatic by no more than 15%. Carboniferous rocks

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES

L_

4 1 Fornullon

tactor

-

c

Siule travel time

_

-

Cutting denslty

Penetratlon rile

5

Pressure graamnt

Fig. 1-5. Plots revealing an overpressured environment in the Adriatic Sea (after Rizzi, 1973).

showed similar behavior, with overpressures not exceeding hydrostatic by more than 20%. It can be generally concluded that the Paleozoic rocks of the Russian Platform exhibit pressures equal to or only slightly above hydrostatic pressures. The Russian Platform is surrounded by the Ural and Caucasus mobile belt and contains a number of arches and depressions. However, Mesozoic formations that contain hydrocarbons demonstrate marked differences in pressure conditions (Fig. 1-6). In the Dnieper-Donetz Basin, Mesozoic formations approximate hydrostatic pressure, whereas the Mesozoic rocks of the folded Ciscaucasian area exceed hydrostatic by as much as 50 to 100%. Many of Russia’s more prolific oil and gas reservoirs are of Tertiary age. They can be grouped into three pressure categories (Fig. 1-7) as: (1) Subnormal-pressure environments that occur in Middle Miocene formations, especially the Chokrak and Karagan stages. This condition occurs less at increasing depths. (2) Hydrostatic-pressure environments, in particular the gas-bearing zones of Tortonian and Sarmatian age in the Ciscaucasian depression. (3) Overpressure environments, particularly in several Maykopian beds. Russia and the area encompassing the Caspian Sea are currently creating a great deal of interest for further exploration and development activities.

1.5. ABNORMAL PRESSURE OCCURRENCES IN AFRICA

Abnormal pressures have been encountered in several countries of the African continent. Algeria has experienced highly overpressured formations in several of their more prolific fields, whereas Morocco has experienced only slight overpressures in elongated folds that are broken up by faults. Overpressure environments have also been encountered in Nigeria and the Nile Delta of Egypt. Overpressured

6

E.L. BIGELOW Formation Pressure MPa 0

5

10

1

20

15

1

25

30

35

1

A Devonian

o

MelO10l~

05

I

15 E

\

1

f 0) a

Suonorrnal pressures

n 2

25

3

1

Fig. 1-6. Plots of abnormally pressured formations of Devonian, Carboniferous, and Mesozoic age in Russia (after Fertl, 1971).

zones are found in broad areas of the west African coast, but tend to be more localized along Africa's east coast, most notably in Mozambique, Madagascar; and the Red Sea offshore from Eritrea. Blowouts have occurred offshoreAngola. Algeria, particularly in the Hassi Messaoud field and the Hassi RMel anticline, has encountered gradients of 0.62 psi/ft (14.0 kPa/m) and 0.6-0.65 psi/ft (13.6-14.7 kPa/m), respectively.

1.6. ABNORMAL PRESSURE OCCURRENCES IN THE PEOPLE'S REPUBLIC OF CHINA

Although little published data pertaining to abnormal pressures has been forthcoming from the People's Republic of China, there are more than 200 existing basins in this vast country, and geological conditions virtually guarantee that overpressured regimes must be present in several regions.

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES

7

Formation Pressure, MPa 0

5

10

15

20

25

30

35

1

)

D5

1

E 1.5

5n

: 2 7-

:I A Hydrostatic

2.5

gradient,

G,.0465PSI

/It

4-"433PsI/tt

Fig. 1-7. Abnormally pressured Tertiary age formation in Russia (after Fertl, 1971). Courtesy of the Society of Petroleum Engineers.

Plate tectonics, following the Sino-Indian Movement, had a large effect on the landmass encompassed by China. Forces from three directions - the southward movement of the Siberian plate, northern movement of the Indian plate, and the westward movement of the Pacific plate - have caused a very complex mixture of geologic structures, including uplifts, depressions, and several types of sedimentary basins. Several of the larger basins in China are Huanghua, North China Basin including the Bohai Sea, Jiyang, Biyang, Ordos, Junggar, Sichuan, Songliao, Jianghan, Shanganning, Tarim, and Xia Liaohe. Structural geology and some reported temperature gradients are strong indicators that numerous cases of abnormally pressured formations exist. Both marine and non-marine rocks contribute as producing reservoirs, and within each basin tectonic activity has played some role. Thrust faults, compressional folds, overthrust nappes, en-echelon faulting, horsts and grabens, and pull apart structural features are found in different areas of the country.

8

E.L. BIGELOW

1.7. ABNORMAL PRESSURE OCCURRENCES IN SOUTH-EAST ASIA, AUSTRALIA, NEW ZEALAND AND THE INDONESIAN ARCHIPELAGO

Abnormally pressured horizons have been experienced in Australia, Papua New Guinea, the South China Sea, New Zealand, the islands of Java, Sumatra, Borneo, and Kalimantan. Volcanics and pyroclastic rocks on Honshu, the main island of Japan, exhibit a wide range of overpressured horizons. Taiwan and the Philippines have also experienced abnormal pressures. New production in the highlands of Papua New Guinea was found in the mid-1980s, and experienced abnormally pressured horizons. Tertiary and Mesozoic sediments that are severely faulted, represent the horizons of overpressure. Overpressured zones were Pliocene/Miocene mudstones of the Aure Trough and Aptian Mudstone (Lower Cretaceous). Gradients in the Aure Trough of 0.91 psi/ft (20.6 kPa/m) were reported. Massive, gas-bearing limestone reefs encountered overpressures of 0.62 psi/ft (14.0 kPa/m). A “floating mud cap” technique was used by drillers to overcome the problem; i.e. heavy mud floats in the annulus while drilling was achieved by pumping seawater down the drill pipe. The delicate pressure requirements of this method lead to high consumption of drilling fluid, and loss of valuable geological cuttings. Several years ago drilling in the delta area of Mamberamo River on the north side of Zrian Jaya, Indonesia, encountered pressures more than twice that of hydrostatic in a gentle, unfaulted anticline. In Australia, the Bonaparte Gulf Basin, the Perth Basin, and the Carnarvon Basin all contain overpressured formations. Occurrences of moderately to mildly overpressured formations are widespread throughout Australia, including offshore areas and a variety of geological ages (Fig. 1-8). Blowouts from shallow wells have occurred in Queensland, where pressure gradients that reach 0.6 psi/ft (13.6 kPa/ m) are present at greater depth. On the Gippsland Shelf, gradients of 0.55 psi/ft (12.44 kPa/m) are present. In western Australia, overpressured regimes are quite common with gradients of 0.62 psi/ft (14.0 kPa/m) occurring below 11,000 ft (3354 m). Similar abnormal pressures are encountered in the Northern Territory, both onshore and offshore, an area that often requires drilling fluids that exceed 14 lb/gal (16.5 kN/m3) in weight. Limited drilling on the island of Timor, 300 miles (483 km) north of the Australian coast, have encountered abnormal pressure gradients of 0.65 psi/ft (14.7 kPa/m) at shallow depths. In New Zealand, mud volcanoes and a thick, rapidly deposited succession of Tertiary or Upper Cretaceous rocks have caused overpressure environments. Wells drilled near the north coast of Hawke Bay encountered pressure gradients of 0.8 psi/ft (18.1 kPa/m), particularly in the bentonitic mudstones of the Lower Tertiary. Slightly lower overpressures are found in the Upper Cretaceous formations. Also, overpressures and casing collapse are reported in the Northland Sedimentary Basin elsewhere. Drilling experience in the South China Sea has reported abnormally high geothermal gradients (3”F/100 ft, 5.5”C/100 m) in several areas. Overpressured zones show a wide variation in occurrence, but mud weights as high as 17.5 lb/gal

9

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES Pressure. P S I

0mNo1

i E

5

2 *8 0

h. (b)

1

P.SC.

2

I(.Duril

Pressure, MPa

1

3 Iokea 4 TO".l. 1A 5 Rarako Creek 1

6. Yuleroo1 7 ArClur"S1 8 Rollestonl 9 Pewel 1 1 0 8arracartal 11 Kulsnill 12 Palm valley 13 Heron 1 14 Dammer 1 1s weleone 1

16 L e O p U d w o o d l

12000

Pressure. PSI

(C)

Fig. 1-8. Abnormal formation pressures in Australia and Papua New Guinea (after Lepine and White, 1973): (a) locations of overpressured wells; (b) abnormal pressures recorded in Australian wells; and (c) pressure gradients of several wells drilled in Papua New Guinea.

(20.6 kN/m3) have been necessary on wells offshore of Sumatra, Java, Borneo, and Kalimantan. Gumbo shales, limey shales, volcanic ash beds, shallow overpressured gas pockets, and deep overpressured horizons present challenges to drillers in several areas. Trpical pressure profiles are illustrated (Fig. 1-9). In the Philippines, overpressured zones at very shallow depths (2100 ft, 640 m) have been recorded, resulting in gradients approaching 0.84 psi/ft (19.0 Wa/m). On Taiwan, overpressures as high as 0.8 psi/ft (18.1 Wa/m) are found in Tertiary shale and sand sequences. The Chuhuangkeng, Chinshui, and Tiehchenshan-'bngshiao oil and gas fields have all registered overpressured horizons. Deep gas reservoirs exemplify the higher pressure and temperature gradients. Honshu, the main island of Japan, has produced hydrocarbons from pyroclastic and volcanic rocks in the Nagaoka Plain. These Tertiary rocks exhibit a broad range of formation pressures (Table 1-1). Overpressures tend to increase with increasing depth of these reservoirs and the thickness of the overlying low-permeability mudstone caprocks. Gradients up to 0.8 psi/ft (18.1 kF'a/m) have been observed.

10

E.L. BIGELOW

Sp Gr

S p Gr 11

15

19

I : i/i Dl

2 :

1 32 3

6[

D

# 149 I/gal 1251

. # /gal 9

wetgni

-

1 0

125

16 16

f u

4

'_--:y; 3 4

' 4

14

14

5 0

%

2

10

18

% &

0

12.5

la0 la

16 MU^ weignt

.w

0

12.5

l0

12.5

l0

; E * ii a 0

5

/gat

Fig. 1-9. Typical formation pressure profiles from southeast Asia and Indonesia (after Rehm, 1972): (a) Sumatra, (b) Java, (c) South China Sea, (d) Kalimantan marine lowlands. Courtesy of the Society of Petroleum Engineers.

TABLE 1-1 Bottom-hole pressures taken from several wells in the Nagaoka Plain, Japan (after Magara, 1968) Name of field

Well No.

Formation

Depth (m)

Pressure (MPa)

Pressure gradient (MPa/m)

Fukikawa

agglomerate

Kumoide

agglomerate sandstone

2310.4

36.1

0.0156

1745.0 1394.8

24.6 15.4

0.0141 0.0110

Sekihara

agglomerate sandstone

1129.0 817.0

11.5 7.3

0.0102 0.0089

Katagai

agglomerate

1052.2

9.8

0.0103

Nishi-Nagaoka

agglomerate sandstone

1172.2 1144.5

11.5 10.4

0.0098 0.0091

Mitsuke

sandstone lava

1201.3 1744.9

12.3 25.9

0.0102 0.0148

Kurosaka

lava

1816.0

25.2

0.0139

Higashi-Sanjo

tuff

1248.8

13.0

0.0104

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES

11

1.8. ABNORMAL PRESSURE OCCURRENCES IN THE ASIAN SUB-CONTINENT

Overpressured zones have been experienced in India, Pakistan, Mynomar (Burma), and Bangladesh. In India, overpressures are found in zones of Eocene/ Pliocene age, both in high shalehand ratio sequences and in areas greatly disturbed by high tectonic activity. The folded belt of the Himalayan foothills, e.g., Jammu, Punjab, and Assam, exhibits overpressures that approach overburden pressure. The geosyncline area of the Bengal Basin exhibits abnormal pressures in the Debagram and Pandua formations immediately below a massive shale formation. Mud weights as high as 18.5 lb/gal(21.7 kN/m3) are often needed. In Pakistan, extreme overpressures are found in shallow Tertiary fresh-water sediments of the Himalayan foothills. At depths of 5400 ft (1646 m), a pressure of 7000 psi (48.3 MPa) has been reported. This gradient (1.3 psi/ft, 29.4 kPa/m) was in a shale/siltstone/sandstone sequence that was subjected to the tectonic stresses caused by the Himalayan folding, and the steep dip of the potential pay zone. Similar overpressures are found in Dhulian, Joya Mair, and other Pakistani fields as well as across the border in northern India. Offshore drilling ventures have also encountered overpressured horizons. Frequent drilling problems, caused by overpressures, occur in Bangladesh. At a depth of about 9000 ft (2744 m), pressure gradients of 0.99 psi/ft (22.4 kPa/m) have been encountered in the Sylhet structure. Thin sand streaks intermixed with massive shale sections constitute the lithology sequences. Mynomar’s Tertiary rocks of the Irrawaddy and Chindwin River Basin and offshore in the Gulf of Martaban have exhibited overpressured horizons. Gradients in the Chauk field are 0.86 psi/ft (19.5 kPa/m) and in the central part of the Yenangyaung structure pressure gradients of 1.0 psi/ft (22.6 kPa/m) are found at a depth of 5000 ft (1524 m), and mud weights of 18.9 lblgal(22.2 kN/m3) have been necessary below 9000 ft (2744 m).

1.9. ABNORMAL PRESSURE OCCURRENCES IN SOUTH AMERICA

Occurrences of abnormal pressure are typically found in offshore areas, along the Andes Mountains, and elsewhere in South America. A comparison of South American and African pressure data is illustrated (Fig. 1-10). In the Forest Reserve oil field of the Trinidad-Tobago area, overpressured zones are found in Tertiary shalehand sequences; e.g., 0.89 psi/ft (20.1 kPa/m). Similar pressure gradients of 0.75-0.90 psi/ft (17.0-20.4 kPa/m) have been encountered in the Andes foothills of Argentina, Bolivia and Colombia, some as shallow as 2000 ft (610 m). In Venezuela,overpressured zones were encountered during Cretaceous exploration in Lake Maracaibo. Abnormal pressures have also been encountered to the north of the lake and in eastern Venezuela.Mud requirements of 16-19.5 lb/gal(18.822.9 kN/m3) are often necessary. In the Anaco area of eastern Venezuela,a particular problem is presented by the massive and heavy, black Colon shale (Fig. 1-11). Offshore the west coast of Colombia, Ecuador and Peru, and along the east coast of J&nezuela, Guiana, and Brazil abnormal pressures are encountered. Extreme

12

E.L. BIGELOW Formation Pressure, MPa

2 4 6 8 10 12 I! F o r m t m oressure. thousand -1

Fig. 1-10. Comparisons of selected formation pressure data from South America and Africa (after Fertl, 1972). Courtesy of the Society of Petroleum Engineers.

overpressures in shale/sand sequences often relate to high volume initial production but limited hydrocarbon deposits; i.e., rapid production declines are typical. Data from an offshore east coast well is shown (Fig. 1-12).

1.10. ABNORMAL PRESSURE OCCURRENCES IN NORTH AMERICA

A majority of the abnormal pressure predictions and evaluation methods were developed in the United States, and include a number of publications that discuss the occurrence and implications of abnormal formation pressures. Overpressures that can be described as extreme, moderate, or minimal are found both onshore and offshore, and in both sand/shale and carbonate environments. Shallow to deep wells in places such as Alabama, Alaska, Arkansas, California, Colorado, South

13

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES Pressure. MPa 5

15

25

35

Pressure 1000 psi

Fig. 1-11. Abnormal formation pressures in Anaco area of Venezuela (modified after Funkhouser et al., 1948).

Penetrmtian rate.minJft.

w a t e r s a ~ i n i t yin wtd.

lo’wnl

Sttale t r a v d R timc.~~uclft. Qrn

ma Fig. 1-12. Overpressuredformations in a well offshore Guiana, South America

Density

glcc

Dakota, Florida, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas, Utah, Wyoming, West Virginia, and elsewhere have encountered overpressured zones. Due to its long history as a petroleum producing country, the number of U.S. wells in comparison to most of the world, is the overwhelming reason for the preponderance of data found. Over one half of the wells drilled for petroleum reserves have been within a 500 miles (800 km) radius of Houston, Texas. Typical pressure profiles for several U.S. areas are given (Fig. 1-13).

14

E.L. BIGELOW

14 0

0

125

-8 1

h... "\ !1a4

9

9 125 16 Mud we#gnt,# /gal

16

ip.7ri'

125

?

0 5 u 1

B

0

125

16

9

125 MU^

16

16

weigni.

18

*/*

9

125

I6

Fig. 1-13. 'Ispica1 formation pressures for several areas in the United States (after Rehm, 1972): (a) Santa Barbara Channel, Calif.; (b) Colusa County, Calif.; (c) Humboldt County, Calif.; (d) Uinta Basin, Utah; (e) Rio Blanco County, Colo.;( f ) Anadarko Basin, Okla.; (9) Ralph Lowe Estate, West Texas; (h) Zapata County, south Texas; (i) offshore, upper Texas coast; (j)Vermillion Parish, La.; (k) Rrrebonne Parish, La.; (1) Mississippi Delta, La.; (m) Wayne County, La. Zig-zag lines in (f), (g), and (m) represent depth breaks. Courtesy of the Society of Petroleum Engineers.

Mexico also has its overpressured areas, both onshore and offshore. Mud weights as much as 18 lb/gal (21.2 kN/m3) are necessary to control wells in several petroleum producing regions. Formation temperatures of >400"F (204°C) are often encountered. Canada experiences abnormal pressures is several areas, including the Rainbow Lake area of western Canada, off the west coast, off the east coast under the Nova Scotian Shelf, and both onshore and offshore in the Mackenzie Delta. Rapid sediment accumulation, shale and salt diapirism, and major fault systems are the causes that contribute to overpressured horizons. Mud weights in the Mackenzie

GLOBAL OCCURRENCES OF ABNORMAL PRESSURES

15

Sp Gr

ie

125

16

Fig. 1-14. Typical mud weights in drilling offshore eastern Canada (after Rehm, 1972). Courtesy of the Society of Petroleum Engineers.

Delta are typically around 17 lb/gal (20.0 kN/m3), whereas 18.5 lb/gal (21.7 kN/m3) drilling fluids are often needed in frontier areas. The initial Sable Island test on the Nova Scotian Shelf encountered overpressured shales at the base of the Naskapi Shale, and required 15.5 lb/gal(l8.2 kN/m3) mud to maintain well control. Another east coast well exhibited a gradient of 0.73 psi/ft (16.5 kPa/m) after penetrating a very thin and abrupt transition zone from normal to overpressure (Fig. 1-14). The Arctic Islands (Canada) petroleum province is located along the elongated east-west Mesozoic Sverdrup Basin, with a complex of older Paleozoic arches and basins to the south and a younger Cenozoic shelf basin to the north. Much of the pressure data has been proprietary, but blowouts are known to have occurred on King Christian and Melville Islands. Pressure gradients of 0.6 psi/ft (13.6 kPa/m) have been reported.

ACKNOWLEDGEMENTS

This writer acknowledges the numerous helpful people in the petroleum industry, governmental agencies, and academic pursuits for their encouragement and cooperation in compiling this data. Special tribute must be paid to D.J. Timko and the late W.H. Fertl who have contributed a vast amount of reference material to the subject of abnormal pressures. In the interest of space, this writer must apologize to those omitted from the references. The world undoubtedly has other areas of abnormal pressure that have not been included in this global information, but a general overview was the goal.

16

E.L. BIGELOW

REFERENCES Alliquander, O., 1973. High prcssurcs, temperatures plague deep drilling in Hungary. Oil Gas J . , 71 (21): 97-100. Anikiev, A.K., 1964. Ahnormally High Reservoir Pressures in Oil and Gas Fields. TK VNIGRI (All-Union Petroleum Scientific Research Institute of Geological Exploration), No. 233, Izd. Ncdra, Leningrad, 167 pp. Chan, Y.C., 1964. Preliminary study on the geothermal gradients and formation or reservoir prcssurcs of oil and gas fields in northern Taiwan. Pet. Geol. Taiwan, 3: 127-139. Fertl, W.H., 1971. A look at abnormally pressured formations in the U.S.S.R. SPE 3613, 46th AIME Fall Meeting, New Orlcans, La., October. Fcrtl, W.H., 1972. Worldwide occurrence of abnormal formation pressures, I. SPE 3844, 3rd Symposium on Abnormal Subsurface Pore Pressure, Louisiana State University, Baton Rouge, La., May. Fcrtl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam. Fcrtl, W.H. and Chilingarian, G.V., 1976. Importance of abnormal formation pressure to the oil industry. SPE 5946, European Spring Meeting of the Society of Perroleurn Engineers of AIME, Amstcrdam, April 7-9. Fcrtl, W.H. and Lcach, W.G., 1988. Economies of hydrocarbon reserves in overpressured reservoirs hclow 18,000 ft in South Louisiana. SPE 18146, 6.3rd Annual Technical Conference and Exhibiiron of the Society of Petroleum Engineers, Houston, Texas, October 2-5. Fcrtl, W.H. and Timko, D.J., 1970a. Associations of salinity variations and geopressures in soft and hard rock. Trans., SOC.Prot Well Log Anal., Annual Logging Symposium, Los Angeles, Calif. Fcrtl, W.H. and Timko, D.J., 1970b. How abnormal pressure detection techniques are applied. Oil Gas J., 68(2): 62-71. Fertl, W.H. and Timko, D.J., 1971. Salinity plots evaluate subsurface formations. World Oil, p. 93. Fertl, W.H. and Timko, D.J., 1972a. How downhole temperatures, pressures affect drilling, Part I . Origin of abnormal formation pressures. World Oil, June. Fcrtl, W.H. and Timko, D.J., 1972b. How downhole temperatures, pressures affect drilling, Part 2. Dctccting and cvaluating formation pressures. World Oil, July. Fertl, W.H. and Timko, D.J., 1 9 7 2 ~ .How downholc temperatures, pressures affect drilling, Part 3. Overpressure detection from wireline methods. World Oil, August. Fertl, W.H. and Timko, D.J., 1972d. How downhole temperatures, pressures affect drilling, Part 4. Pitfalls in overpressure prediction. World Oil, September. Fcrtl, W.H. and Timko, D.J., 1973. How downhole temperatures, pressures affect drilling, Part 9. Novel ways to detect abnormal prcssurc. World Oil, February. Funkhouser, H.J., Sass, L.C. and Hedberg, H.D., 1948. Santa Ana, San Joaquin, Guario, and Santa Rosa oil fields (Anaco fields), Ccntral Anzoategui, Vcnczucla. Bull., A m . Assoc. Pet. Geol., 32: 1851-1908. Gcicr, O., 1972. Begrundungen fur die An- oder Nichtanwendbharkeit der amerikanischen Merhoden fur Hochdruckzonen - Friiherkennung im adriatischen Raum, Wiener Becken und Suddeutschland an Hand einiger Beispiele des italienischen, osterreichischen und suddeutschen Raumes. Diplomarbeit (Dissertation), lnstilur fur Ticfbohrtechnik und Erdolgewinnung, Montanistische Hochschulc, Leoben, 95 pp. Guiraudct, B., 1972. Drilling for ultra-deep sour gas in France. Pet. Eng., 44: 41-45, September. Hcrring, E.A., 1973. North Sca abnormal pressures determined from logs. Pet. Eng., 45: 72-84, Novcmher. Lepinc, E H . and White, J.A.W., 1973. Drilling in overpressured formations in Australia and Papua. J. Aust. Pet. E r p l o ~Assoc., 13: 157-161. Lindberg, P., Riise, R. and Fertl, W.H., 1980. Occurrence and distribution of overpressures in the northern North Sea area. SPE 9.339, 55th Annual Fall Technical Conference of Sociely of Petroleum Engineers, Dallas, Texas, Scptember 21-24. Magara, K . , 1968. Compaction and migration of fluids in Miocene mudstone, Nagaoka Plain, Japan. Bull., Am. Assoc. Pet. Ceol., 52: 2466-2501. Mostofi, B. and Gansser, A,, 1957. The story behind the 5 Alborz. Oil Gas J., 55 (3): 78-84.

GLOBAL OCCURRENCES O F ABNORMAL PRESSURES

17

Rehm, B., 1972. Worldwide occurrence of abnormal formation pressures, 11. SPE 3845, 3rd Symposium on Abnormal Subsurface Pore Pressure, Louisiana State University, Baton Rouge, La., May. Rissi, R., 1980. Pore pressure and formation integrity in the Viking Graben, East Shetland Basin and the Bergen High Area in the North Sea. Norwegian Petroleum Society Symposium, Stavanger, April. Rizzi, P.W., 1973. Hochdruckzonen-Friiherkennung in Mitteleuropa. Erdol Erdgas Z., 89: 249-256. Timko, D.J., 1965. Practical applications of log-calculated pressures as an aid to solving drilling problems. The Log Analyst, October. Timko, D.J., 1972. How downhole temperatures, pressures affect drilling, Part 5. Predicting hydrocarbon environments with wireline data. World Oil,October. Timko, D.J., 1973. How downhole temperatures, pressures affect drilling, Part 8. Needless spending of drilling and exploration money can be predicted - and prevented. World Oil,January. Timko, D.J. and Fertl, W.H., 1971. Hydrocarbon accumulation and geopressure relationship of well economics with log-calculated geopressures. J. Per. Technol., 23: 923-933. Timko, D.J. and Fertl, W.H., 1972a. How downhole temperatures, pressures affect drilling, Part 6. Correlating geopressure gradients with hydrocarbon accumulations. World Oil,November. Timko, D.J. and Fertl, W.H., 1972b. How downhole temperatures, pressures affect drilling, Part 7. The shale resistivity ratio - a valuable tool for making economic drilling decisions. World Oil, December. Timko, D.J. and Fertl, W.H., 1973. How downhole temperatures, pressures affect drilling, Part 10. Miscellaneous ways to detect abnormal pressure. World Oil,March. Zil’berman, V.I., 1972. Indications of approach to horizons with abnormally high reservoir pressure during drilling of wells. Neft. moz.,50: 12-14.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 0 1994 Elsevier Science B.V. All rights reserved

19

Chapter 2

THE GEOLOGY OF ABNORMAL PORE PRESSURES RICHARD E. CHAPMAN

2.1. HISTORY

2.1.1. Early experiences

The drilling of countless thousands of boreholes for water, petroleum, and other resources, had established by about 1930 that water found in the subsurface, occupying the pores and fissures of rocks, was almost always at pressures that corresponded to those that one would expect in a body of static water at that depth - that is, the water would rise in the borehole to reach a level close to the surface of the earth. There were exceptions, notably in artesian basins where the water flowed at the surface; and there were also areas in which the water table, the free upper surface of the ground water, lay at considerable depths. Artesian basins had long been put to good use on most of the inhabited continents, and the water supplied without the expense of pumping was a boon to areas such as Colorado and eastern Australia, and later, the island of Hawaii, providing relatively cheap water in large quantities. The nature of artesian basins was also well understood. The energy that brought the water to the surface under pressure was due to the fact that the outcrop of the reservoir of water, or aquifer, was at higher elevation than ground level at the position of the borehole. Water, then, “seeking to find its own level”, flowed up the borehole. At the surface, the pressure in artesian wells was usually not large, but quite commonly of the order of 1 megapascal (140 psi), which is enough to support a column of water to an elevation of 100 m (300 ft) or so above ground level. There were also occasional reports that when drilling for oil, pressures were encountered that were larger, some considerably larger, than those that could be attributed to artesian conditions. Anderson (1927) reported in a perceptive paper that drilling for petroleum in the Jhatla area of the Punjab, in northern Pakistan just east of the Indus river and south of the foothills of the Himalayas (Fig. 2-1), had encountered water pressures rather greater than would be expected under artesian conditions. The geology of the area is interesting. It contains a thick, dominantly regressive Tertiary sequence with non-marine Oligocene to Upper Pliocene sandstones and silts lying on marine and paralic Eocene limestones and marls of the “Nummulitic series”. Regional considerations of thicknesses led Anderson to conclude that subsidence of the area, greatest nearest the mountain front to the north, had been accompanied by “aggradation keeping the surface level constant” (Anderson, 1927, p. 667) and that there were “deformational forces affecting the beds while accumulation of the system (the Nimradic, the post-Eocene non-marine beds, at least 6 km

20

R.E. CHAPMAN

Upper and Middle Siwalik

I[IIIII Chiefly Nurnrnulitic

Lower Siwalik

Murree

Palaeozoic and Mesozoic

Fig. 2-1. Location map: Jhatla and Khaur, northern Pakistan After Anderson, 1927, p. 668, fig. 1 .

or 20,000 ft thick) was going on”. The regressive sequence was due to the orogeny that was beginning to the north, which gradually and steadily encroached on the sedimentary basin from the north. This orogeny, which was building the Himalayas (and apparently still is, because in places there are vertical Pleistocene gravel and boulder beds), eventually embraced the plains of the Punjab. The severity of deformation decreases from the foothills towards the south, from isoclinal folds and overthrusts with southward vergence, through anticlines and synclines, to gentle monoclines. The Jhatla well was drilled on the crest of a dome at an elevation of 530 m above sea-level (1740 ft) and, using both cable-tool and rotary drilling, it reached a total depth of 1831 m (6007 ft) having penetrated the top of the Nurnrnulitic limestone at 1807 m (5925 ft). Specific gravities of core samples were found to be 2.68-2.71, averaging about 2.69. The sandstones were all heavily cemented, with porosities between 8 and 17.5%. Six water sands were encountered, perhaps seven, all flowing freshwater. That at about 1164 m (3820 ft) had a pressure of at least 3.3 MPa (480 psi) at the wellhead, and this pressure was considered to be too large to be due to artesian conditions, and Anderson (1927, p. 708) quoted a report by Condit in which he suggested that the pressures might be hydrostatic pressures “inherited” from a time when the relative elevation of the surface was much higher. A point of interest, and perhaps importance, is that these water-bearing sandstones have residual oil at their outcrops (but Anderson considered the source of this crude oil to be in the marine Eocene on account of seepages).

THE GEOLOGY OF ABNORMAL PORE PRESSURES

21

After completion of the well, temperatures were obtained at five depths, from which the geothermal gradient appears to be between 29 and 36"C/km (1.6 to 2.0"F/100 ft), the latter figure if Anderson was correct in assuming a mean surface temperature of 10°C (50°F) (Anderson, 1927, p. 705). The data suggest 30.3"C/km (1.7"F/100 ft) with a mean surface temperature of 21°C. Another early report, and perhaps the first to describe unambiguously abnormal pressures, concerned rotary drilling in the Khaur oil field, 48 km (30 miles) north of the Jhatla well, in the same area of the Punjab (33"15'N, 72"12'E), near the foothills of the Himalayas (Keep and Ward, 1934). The Khaur field is in an anticline that would be regarded as steep nowadays, with 70-75" dips in the north flank, and 45-50" in the south flank. It consists of a Miocene sequence of sandstones, silts and shales the sandstones having porosities between 4 and lo%, and very small permeabilities due to cementation. The upper part of the sequence, to about 1000 m (3200 ft) is dominantly sandy, with shale dominating below. The waters were very saline, with up to 18% NaCl equivalent. Shallow oil sands (30-150 m; 100-500 ft) had relatively high pressures, but at depths below about 1500 m (5000 ft), pressures about equal to the total overburden were encountered (the overburden gradient was estimated to be 2.3 kPa/m or 1.06 psi/foot), and these zones could only be drilled effectively by circulating heavy mud with the mud-discharge line beaned, to apply pressure to the mud so that the pressure exerted in the hole was greater than that due to the weight of the mud. The range of problems must have been intimidating, but very ingenious solutions were found. At 1590 m (5215 ft) in a deep well, balance was probably achieved with a mud of specific gravity 1.41 and a "control" pressure of 13.8 MPa (88 Ib/cu.ft or 11.8 lb/gal, 2000 psi), and from there to 1670 m (5478 ft) the mud was of specific gravity 1.44 and the control pressure 12.4 MPa (90 Ib/cu.ft or 12 lblgal, 1800 psi). These figures imply pressures of 34.9 MPa at 1 590 m (5060 psi at 5215 feet), or 2.2 times the normal hydrostatic. Rotary drilling elsewhere in India (as it was then, now Pakistan) and in Burma (Abraham, 1937) and in the swamps of the U.S. Gulf Coast (Cannon and Craze, 1938) had also encountered pore pressures that were considerably larger than normal, some also approaching the pressure exerted by the total overburden. Trinidad shared these difficulties. The prevailing opinion in India and Burma was that these pressures were caused by the weight of the "superincumbent strata", and Abraham (1937, p. 382) noted that this corresponded to a pressure gradient "... of the order of 1 lb. per square inch for each foot of depth" (22.6 kPa/m). Mudweights to specific gravities of 2.6 (165 lb/cu.ft, 22 lb/gal) were sometimes required, and this was achieved by the addition of baryte. It was also the prevailing opinion, with some reservations, that once abnormal pressures had been encountered, they would continue indefinitely with depth. As early as 1934, D. Comins (an engineer) had shown a great interest in, and a clear understanding of, the principal components of abnormal pressures; he had even suggested that

',

T h e terminology of mudrocks remains inconsistent in applied geology, shales and mudstones often being used synonymously.

22

R.E. CHAPMAN

fractures in cap rocks could open as the pressure in underlying reservoirs exceeded the overburden pressure, and then close when fluid bled away (see Journal of the Institution of Petroleum Technologists,vol. 20, p. 722, and vol. 23, pp. 375-376). Drilling in Iran had, from the discovery of Masjid-i-Sulaiman in 1908, experienced difficulties that sometimes led to blow-outs (Colville, 1937). In the days of cable-tool drilling (up to the mid-1930s) this was fairly normal because a “gusher” was, in a sense, a blow-out; and the cause was not hard to find because cable-tool drilling was normally in a borehole that had no satisfactory means of containing any fluids that had greater energy than that of the mud in the borehole 2. But even before the introduction of rotary drilling reservoir pressures had been experienced in Iranian oil fields greatly in excess of those expected from normal experience (and these had been clearly understood by Comins, as mentioned above). The main producing horizon in Iran is the Asmari Limestone, a shallow-water non-reefal limestone of Miocene/Oligocene age, capped by evaporites of the Gachsaran Formation. The oil accumulations are in large and long anticlines, with vertical oil columns of 1 km (and more) in anticlines (not fields!) up to 150 km long. Production comes more from the open joints or fractures in the limestone than from the pore space. Hull and Warman (1970, p. 431) reported an average porosity of 9-14%, with an intrinsic permeability of about 10 mD. When “drilling in”, it was often found that the reservoir pressure was considerably above that expected for that depth. Great care, with attention to the detailed stratigraphy, was always required but this did not prevent some spectacular blow-outs. It was the great vertical thickness of petroleum, less dense than water, that led to the high reservoir pressures. The Gachsaran Formation is abnormally pressured, locally severely, but little seems to have been published on the nature of the pressures in this formation. F!T. Cox, in the discussion at the 1937 meeting on deep drilling problems (see Journal of the Institution of Petroleum Technologists,vol. 23, p. 374) attributed these abnormal pressures in the Masjid-i-Sulaiman and Haft Kel fields to mechanical compaction of incompetent beds. Although Abraham (1937, p. 385) could remark that abnormal pressures seemed to be more common in India and Burma than in the Americas, this experience was soon to change. It was in the U.S. Gulf Coast that, more and more commonly, drilling for oil encountered pore pressures that were much greater than normal, and there was clearly no reason in the swamps of Louisiana to suppose that the process was artesian. This experience was shared by other areas, new and old, particularly in South-East Asia. In the U.S. Gulf Coast region, abnormal pressures were encountered at depths between about 2300 m (7500 ft) and 2750 m (9000 ft); and as drilling technology improved, and deeper wells were drilled, later also off-shore, so the occurrence of abnormal pressures in the U S . Gulf Coast continued to increase in frequency. The commonly accepted cause of these pressures was compaction. Compaction, it

* T h e account of drilling at Khaur (Keep and Ward, 1934) is evidence that physical constraints on t h e borehole fluids were being developed early.

THE GEOLOGY OF ABNORMAL PORE PRESSURES

23

was supposed, so reduced the permeability of the rocks that below a certain depth, the pore water could no longer be expelled and so its pressure increased. This view prevailed in North America until the early 1950s, and by then, similar drilling problems were being experienced in many more parts of the world. Abnormal pressures, as they had come to be called, were found in the former Soviet Union in the Baku district on the shores of the Caspian Sea; in South-East Asia, in the sedimentary basins around the island of Borneo, in New Guinea, and on the island of Sumatra; and in Trinidad, which was one of the areas earliest to encounter such pressures. They were soon to be found in the great delta regions, notably the Niger delta of Africa and the Mackenzie delta of the Canadian arctic. Abnormal pore pressure was (and to some extent, still is) a serious problem because it caused blow-outs in boreholes being drilled for petroleum. Rotary drilling excludes formation fluids from the borehole with a drilling mud that has a specific gravity greater than that of water; and the mud is treated with chemicals so that it remains stable in the borehole, and keeps the borehole stable. The specific gravity of drilling muds was varied by the addition of weighting materials such as baryte (which has a specific gravity of 4.5) or haematite. It had been found by experience that drilling muds with specific gravities of 1.5 to 2.0 were commonly required to contain the subsurface fluids, and that even specific gravities of 2.3, which is close to the specific gravity of the total overburden, fluid and solid, were occasionally required. These extremely high pressures brought their own problems, because excessive mud-weight could fracture the rocks in the subsurface, leading to loss of mud in the borehole, and so to loss of control. By the early 1950s the drilling problem was exacerbated by the drillers’ desire to anticipate abnormal pressures by increasing the mud weight at a shallow depth. This practice not only proved expensive because drilling progress was found to be slower with the heavier mud (a matter to which we shall return shortly), but also proved dangerous because it did not prevent blow-outs, merely postponing them to a rather greater depth and higher pressures in many cases. The solution to that problem was a stroke of genius from Shell Oil Company in the U.S. Gulf Coast. They found that by using the lightest-possible mud, abnormal pressures were detected almost as soon as they were encountered. They were there only slightly above normal, and so easily controlled. The bonus was that the rate of drilling above abnormal pressures increased substantially, and the protective casing could be set at the optimum depth. The procedure was to drill with all controllable parameters kept constant (weight on bit, revolutions, mud weight and pump rates). A record of the penetration rate, in minutes to drill unit depth, was found to distinguish sandstones from shales very clearly over the normally pressured part of the section. When abnormal pressures were encountered, always in shales, the rate of penetration increased two or threefold. This was called a “drilling break”. Drilling was then stopped, the bit pulled to above the top of the drilling break, and the mud circulated “bottoms up”. A careful watch was also kept on the mud tanks, and mud properties were closely monitored. If there was no influx into the well, it might be deepened cautiously. If the well “kicked”, it was closed in, and the minimum mud-weight required would be determined from the closed-in pressure. The idea of drilling for kicks was hard

24 R.E. CHAPMAN

N

i

25

THE GEOLOGY OF ABNORMAL PORE PRESSURES

to accept, but its great merits were safety and economy, with casing rarely set so shallow that another string had to be run soon afterwards. It also had the merit that wall-sticking, due to heavy mud in open hole opposite a normally pressured sandstone, became much less common. 2.1.2. The US.Gulf Coast

A landmark in the understanding of the geology of pore pressures, normal and abnormal, came with the publication of George Dickinson's work in the Gulf Coast of Louisiana (Dickinson, 1951, 1953). In a study of a large number of wells drilled for petroleum, with data obtained from pressure measurements as well as mud-weights at the time of blow-out, Dickinson showed that there was stratigraphic control on the abnormally high pore pressures, and that the apparently consistent depth to the top of abnormal pressures was also a consequence of the stratigraphy. The age of the mudrocks in which the top of abnormal pressures occurred was found to be younger the nearer the borehole was to the coast, in a southerly direction. These are all illustrated in Fig. 2-2. SOU 1H

NORlH E. BATON ROUGE

15.000'

SAMSTOWN ST. GABRIEL L A PICE

W. LAKE VERRET CHACAHOULA

GIBSON DE LARGE LAKE HATCH

BAY ST. ELAINE FOUR ISLE

m

i

1

SCALE

& . . -0

5

-

5

10 P

I5

POYILCS

__1

Fig. 2-2 (continued). Map (p. 24) and cross-sections through Louisiana Gulf Coast showing the diachronism and younging of the top of abnormal pressures towards the south. Reproduced from Dickinson, 1953, pp. 416-417, fig. 3; p. 421, fig. 8; and p. 422, fig. 9; courtesy of the American Association of Petroleum Geologists.

26

R.E. CHAPMAN

s E.

N.W.

GOODHOPE

LAKE PONTCHARTRAIN

BARATARIA

WESTWEGO

L A FlTTE

LAKE HERMITAGE

200oL

4000’-

6000’-

0000’-

10.000-

LLGCND

U

ZONL

or LDNORY*L

PRCISJRC

--

5

0

DELTA AREA SCALE 5

10

I5 MILES I

Fig. 2-2 (continued). For caption see p. 24.

The stratigraphy of the U.S. Gulf Coast records a Tertiary sequence, dominantly regressive, in which the sediments prograded towards the south (and presumably continue to prograde into the Gulf of Mexico). In the shallower portion, the sequence consists of a diachronous pair of rock units, one sandy (with a large sand/shale ratio), the other a mudrock with few sandstones. Dickinson observed that pore pressures in the sandy (upper) part of the sequence were normal (that is, if the water were free to rise in a borehole, it would rise to a level close to the surface, or sea-level) and that the top of abnormal pressures was encountered below the sandy part of the sequence, in the upper part of the massive mudrock unit. The diachronous nature of the “contact” between these two units was clearly demonstrated, and the relationship between geologic age, position and depth of the top of abnormal pressures indicated that the approximate constancy of depth was largely coincidental, arising from the progradation of the sandy sequence towards the south. Dickinson found cases where sandstones that had become isolated due to faulting were also abnormally pressured (Fig. 2-3); and he also found a case where the abnormal pressures in a petroleum reservoir were evidently due to the vertical extent of the reservoir (which had been found in Iran and which will be examined

THE GEOLOGY OF ABNORMAL PORE PRESSURES

27

\ \ '*.:.

'...........:

.".., . .:.:. .,.. ....:... '

.-.

I SMALL

RESERVOIR

SEALED

BY

PINCHOUT

( 0 )

Main

ormal

Shole

Scric

Pressure Rcccrvoi igh Pressure Reservoir

L A R G E RESERVOIR S E A L E D UPDIP B Y FAULTING DOWN AGAINS1 THICK S H A L E S E R I E S . S E A L E D DOWNDIP B Y REGIONAL FACIES CHANGE. (b)

R E L A T I V E P O S I T I O N OF DOWNTHROWN BLOCKS.

FAULT

SEALS

IN UPTHROWN AND

(C)

Fig. 2-3. Abnormally pressured sandstone isolated by fault. Reproduced from Dickinson, 1953, p. 423, fig. 10; courtesy of the American Association of Petroleum Geologists.

28

R.E. CHAPMAN

in more detail in Chapter 3 , on p. 78). The shape of the pressureidepth curve below the top of abnormal pressures, the transition zone, was shown to vary greatly from area to area. The limiting pore-fluid pressure was close to the overburden pressure. Dickinson (1953, p. 425) inferred that at some stage during the compaction of argillaceous beds, the permeability is reduced below that required for the expulsion of sufficient pore water for full compaction. When this stage is reached, the gravitational forces of compaction are insufficient to expel the pore water, and part of the pressure is transmitted to the fluids from the overburden. Dickinson’s papers are still important because they were based on borehole data, including pressure measurements in abnormally pressured reservoirs. The topic was soon to develop and the main subsurface data in such studies would be indirect measurements obtained from geophysical well logs (a topic that will be taken up in Chapter 7). It is interesting to read the discussion that followed the presentation of Dickinson’s paper, in his absence, to the 3rd World Petroleum Congress in The Hague in 1951. Some of the participants were from the Anglo-Iranian Oil Company, and we can understand now that each side was discussing the paper with the background of their own experience (which we all do) and that the main phenomenon in Iran was not the same as that in the U.S. Gulf Coast.

2.2. REGRESSIVE SEQUENCES

2.2.1. Selected areas 2.2.1.1. Borneo Exploration for petroleum began in Borneo before the end of the 19th century, and there are some old fields (such as Sanga-Sanga in Kalimantan, 1898, and Miri in Sarawak, 1911) that still produce. Seram has had oil production since 1897. Many of the fields of Borneo (and, indeed, South-East Asia) had producible oil at very shallow depths, of the order of hundreds rather than thousands of metres. For example, the shallowest producible crude oil in the Seria field in Brunei was at 288 m (945 ft); and in Kalimantan, Bunju’s was at less than 800 m (2600 ft), Handil’s at 450 m (1476 ft) and Tarakan’s at less than 500 m (1640 ft). These fields were found in Tertiary sedimentary basins in the coastal areas and in the near off-shore; and subsequently abnormal pressures were found to be widespread beneath the producing horizons - the norm rather than the exception. Stratigraphy. The stratigraphy of the Tertiary sedimentary basins around the island of Borneo is interesting at both local and regional levels. The local interest is that the main petroleum accumulations are found in regressive sequences, in structural traps, usually over a depth range of about 1.5-3 km with many reservoir sands on a massive mudrock formation that is abnormally pressured. As Koesoemadinata (1969) pointed out, several Tertiary sedimentary basins of Indonesia, Malaysia and Brunei have very

THE GEOLOGY OF ABNORMAL PORE PRESSURES

29

similar stratigraphy. This is the regional interest, because the regressive sequences around the island of Borneo are recording orogeny within the island of Borneo, and it is this orogeny that gives these sedimentary basins their similarities. It is in the nature of regressive sequences that their formations are diachronous, becoming younger in the direction of progradation away from the orogeny. The abnormally pressured mudrocks beneath the productive formations may well have been abnormally pressured to some extent before the regressive sands accumulated on top of them, but the association of growth faults (in which the downthrown block is thicker than the correlative sequence in the upthrown) with the stratigraphy of regressive sequences, as for example, in Brunei (James, 1984) suggests that the faulting of the sandy part of the sequence during its accumulation is closely related to the abnormal pressures in the mudrocks. Mud volcanoes are also associated with regressive sequences in which the massive mudrock is abnormally pressured. For example, the Setap Shale, which lies beneath the producing formations of the fields of northern Sarawak and Brunei, crops out north of Jerudong in an area of mud volcanoes and also gives rise to mud volcanoes in southern Sabah (Liechti et al., 1960, p. 326). The small field of Jerudong in Brunei has abnormally pressured mudrock beneath the producing sandstones only a few kilometres from its outcrop. Habitat of petroleum. The habitat of petroleum in virtually all the on-shore and near-shore fields of Kalimantan, Brunei, Sarawak and Sabah is in multiple reservoirs in structural traps in the regressive sandstones. Many, but not all, have faults; and many of these, but not all, are normal growth faults. The faults characteristically trap crude oil and natural gas, and fields such as Seria field in Brunei should be classified as fault traps rather than anticlinal traps because the accumulations are not symmetrical to the anticline but confined to the south by the faults. Beneath the productive sandstones lies a thick mudrock unit that is abnormally pressured, and this sequence contains some sandstones that are also abnormally pressured. This generalization applies to the on-shore and near-shore fields of Brunei, and to the fields under and near the Mahakam delta in Kalimantan. The massive mudrock is very widespread, occurring from northern Sarawak clockwise round Borneo to the Mahakam delta and beyond. It outcrops in Brunei and southern Sabah, giving rise to mud volcanoes. The top of abnormal pressures does not mark the bottom of the productive interval, but there is little doubt that a very high proportion of the production from the island of Borneo comes from normally pressured reservoirs in the normally pressured part of the more arenaceous part of the sequence. Scherer (1980) gives an interesting account of the geology of northwest Borneo and some of its fields, and Schaar (1977) described some reservoirs in the Baram delta, Sarawak, that had been inflated by migration of abnormally pressured fluid. Some of the fields are in what can be regarded as ancient deltas: Baram in Sarawak (Rijks, 1981); Attaka, Badak, Bekapai, Handil and Nilam in the Mahakam delta area of Kalimantan (Magnier et al., 1975). It is perhaps surprising that these

30

R.E. CHAPMAN

BEKAPAI 0

km.

25

Fig. 2-4. Sketch map of the Mahakam delta, Kalimantan, Indonesia.

fields (Fig. 2-4) have superficial similarities only, and differ in some important respects. For example, Badak contains mainly gas, but the other Mahakam delta fields contain crude oil with some associated gas. The crude oil tends to be heavier in successive reservoirs of increasing depth and age, the opposite of the normal experience in regressive sequences. There are no known faults in Badak; in Handil there are five or six transverse faults, normal to the depositional strike. Attaka and Bekapai have normal growth faults. They all appear to be growth anticlines. 2.2.1.2. The Niger delta

Nigeria was a relative new-comer as a petroleum-producing nation of great importance, and it was not until late 1955 that crude oil was finally found in commercial quantities in the Niger delta (Fig. 2-5) at Oloibiri. Production started in 1958, and a long series of successes took this to about 80,000 m3/day (more than 500,000 barreldday) by the end of the 1960s. Part of the reason for the initially unsuccessful exploration program was the difficulty of drilling deep holes in the relatively unconsolidated sedimentary rocks of the delta. This had been overcome by about 1960, and it became the area of the Royal-Dutch Shell Group and the British Petroleum Company (in partnership) with most of the drilling records of the time - because fast drilling was essential for success. Abnormally high pore pressures became a serious problem, but less serious than

z

THE GEOLOGY OF ABNORMAL PORE PRESSURES

t

-

/

i

Y E

31

Fig. 5-1. Changes in concentration of pore waters with depth (based on data obtained from Collins, 1975, table VIII.8). A lumped-parameteranalysis having a 10-point moving average of 110 data points from

32

R.E. CHAPMAN

it might have been on account of the experience that had been gained in other areas. Drilling was carried out with the lightest possible mud and casing was set at (or soon after) the first kick. Drilling in the Niger delta was complicated by the fact that the Niger river is at its highest during the local dry season, and at its lowest during the local wet season, so that the choice of rig, submersible barge or land rig, depended on the season of drilling as well as the position of the site.

Stratigraphy. The stratigraphy of the Niger delta consists of three diachronous formations, each belonging to the ancestral delta and recording its growth towards the south (e.g., Dailly, 1976a, b; Evamy et al., 1978). These are, from top to bottom: (1) The Benin Formation: sandy, dominantly continental (2) The Agbada Formation: paralic-neritic mudrocks and sandstones, from which almost all the production comes (3) The Akata Formation: neritic mudrocks. These three formations become younger towards the south, and the upper or landward pair is also cut by extensive growth faults that generally dip away from the heart of the delta. These faults are so intimately related to the stratigraphy that they cannot be regarded as independent of it. The Benin Formation consists mainly of continental sandstones, and is remarkable for the depth to which freshwater is found. The freshwater-bearing sands and sandstones are more than 3 km (10,000 ft) thick, and appear to have formed this thickness on account of subsidence into the delta during accumulation (Dailly, 1976a, p. 94). The Agbada Formation is cut by growth faults that appear to die out in the underlying Akata Formation. The Akata Formation consists almost entirely of mudrock, and the formation is seriously overpressured over a very wide area of the delta. As in the Louisiana Gulf coast, the age of the rocks that contain the top of abnormal pressures is younger towards the coast. Hubifaf ofpetroleum. The Niger delta contains oil and gas fields in structural traps, mainly growth anticlines associated with growth faults (Weber and Daukoru, 1975; Evamy et al., 1978). The fields contain multiple pools, commonly with crude oil of different compositions in pools of the same field. Almost all the reservoirs are normally pressured, in the normally pressured Agbada Formation. Some are just above the top of abnormal pressures; others have numerous water-bearing sandstones between them and the abnormal pressures. There is a pattern to the distribution of petroleum accumulations within the delta, dominated by a fairly straight and symmetrical NW-SE prolific belt (Evamy et al., 1978, p. 15). This pattern does not appear to be related specifically to the abnormally pressured Akata Formation, which is ubiquitous, but the structure of the delta has been affected by it. The diapiric structures on the continental slope of the delta (Mascle et al., 1973) and the apparent overthrust near the foot of the slope (Beck, 1972, p. 12, fig. 4) are likely due to the mass flowage of abnormally pressured mudrock under the gravitational load of the delta (Dailly, 1976a).

THE GEOLOGY OF ABNORMAL PORE PRESSURES

33

Fig. 2-6. Map of the Mackenzie delta region, Canada. Courtesy of Esso Resources Canada Ltd.

2.2.1.3. The Mackenzie delta, Arctic Canada The Mackenzie delta shares with the Lena delta in Siberia the distinction of being a large delta well north of the Arctic Circle (Fig. 2-6), with a thick zone of permafrost that makes the upper 800 m (2600 ft) or so totally impermeable in all lithologies. The direction of river flow means that the mouth of the river freezes before the main body of the river, and thaws after the main river has thawed. The thickness of permafrost is doubtless due to subsidence of the sedimentary column while frozen (rather than freezing from the surface) and no doubt this subsidence has also led to a stratigraphic record of seasonal freezing and thawing of the parent river - a sort of deltaic varves. Subsidence is also supported by anecdotal evidence of toolpushers in the Mackenzie delta who told the author in 1975 of drilling in places through pure ice (evidently frozen lakes), and through more than 100 m (>328 ft) of green timber. The effect of permafrost on the geothermal gradient is significant because if the pore water is to remain frozen at a depth of 800 m, the mean annual surface temperature must be considerably below freezing point. It is presumably for this reason that the permafrost is thin under the Arctic Ocean, the seas remaining warmer than the land owing to their circulation. These differences from the other great deltas of the world, mostly tropical, do not seem to lead to a pressure regime at depth that is significantly different from them. At the surface, the only real difference is the presence of pingos in the arctic deltas. These are due to the combined effects of freezing and expansion of the pore water to ice.

I am indebted to Esso Canada Resources Ltd and to P. Hemingson and W. Carew for their paper “Hydrocarbons and geopressure in the Beaufort-Mackenzie basin” presented at the Canadian National Conference on Earth Sciences, held in Banff in November 1984, on “Geopressures and hydrocarbon occurrences”. I am also grateful to Peter Gretener for his important contributions to the subject, and the organization of this stimulating conference.

34

R.E. CHAPMAN

SE

NW 0 4

. . . . . .

.

. .

.lz

v 7

5 12

E

16

20

#

-

Gas

0 - Oil

Mesozoic

a Pre-Mesozoic Basement

Fig. 2-7. Schematic section through the Beaufort-Mackenzie delta area (located on Fig. 2-6). showing the top of abnormal pressures (heavy dashed line). Courtesy of &so Canada Resources Ltd.

Stratigraphy and structure. The present-day delta is the surface expression of a Tertiary delta system that accumulated in the Beaufort-Mackenzie basin at the margin of the continent on Mesozoic and older rocks (Hemingson and Carew, 1984). Drilling for oil and gas has revealed three cycles of deltaic development, four if the deepest is counted, each separated from its successor by a transgressive mudrock sequence (Fig. 2-7). Growth faults are common and appear to be intimately related to the stratigraphy because each delta development seems to have its own faults. Habitat of petroteurn. Each of the deltaic cycles contains petroleum, except the youngest (Plio-Pleistocene), and the accumulations are in structural traps. This is the habitat of petroleum in regressive sequences, and it is unlikely that there is any significant accumulation in stratigraphic traps in the regressive sequence. However, the basal transgressive sequence could contain petroleum in stratigraphic traps. Abnormal pressures. The top of abnormal pressures in the Beaufort-Mackenzie basin in the delta region occurs in progressively younger rocks to the north, in the direction of the regression (Fig. 2-8), and at progressively shallower depths. As Fig. 2-7 clearly shows, the abnormal pressures are strongly influenced by the stratigraphy. This is not hypothetical. Boreholes have been drilled that have encountered abnormal pressures, passed through them into normal hydrostatic pressures and then entered another zone of abnormal pressures. For example, Taglu F-43 onshore has a normally pressured gas reservoir between two abnormal zones. In general, petroleum lies above or between overpressured zones, and a few are themselves overpressured, as in Kopanoar where the sandstones appear to be isolated within massive mudrocks that are overpressured. Abnormal pressures are confined to the dominantly regressive sequence of the basin.

35

THE GEOLOGY OF ABNORMAL PORE PRESSURES

140'

138"

136'

1340

132'

130"

Fig. 2-8. Map showing depth to top of abnormal pressures in the Mackenzie delta, and the stratigraphic sequence in which it occurs. Note both the shallowing and younging trends towards the north in the direction of progradation. Courtesy of Esso Canada Resources Ltd.

2.2.2. Generalizations

2.2.2.1. Stratigraphy We see in the examples discussed that there are several common features. Most notably, each is a dominantly regressive sequence, with a diachronous stratigraphy; each has growth faults that are intimately related to the stratigraphy; each has developed as a consequence of orogeny, but the deltas have clearly not suffered orogeny themselves. The contemporaneous deformation of the sequence while it was accumulating must clearly be attributed to the stratigraphy, and the stratigraphy to orogeny outside the sedimentary basin. The surface of the top of abnormal pressures is also diachronous, and is related to the stratigraphy as shown schematically in Fig. 2-9. It is at a constant stratigraphic position not in terms of age, but of lithology. It lies beneath the sandy part of the regressive sequence in the massive mudrock and occurs in younger rocks in the direction of the regression. It is therefore also associated with facies. The facies association, however, is ambiguous and within it are other associations that are the associations of clay minerals in the regressive sequence. Martin (1972) drew attention to this, but facies can hardly be the cause of abnormal pressures other than in the gross sense that the massive mudrock as a unit has very low permeability. If the mudrock is also a petroleum source rock, generation

36

R.E. CHAPMAN

Fig. 2-9. Stratigraphic diagram of relationship of abnormally pressured mudrocks to the stratigraphy (time lines horizontal). From Chapman, 1983, p. 307, fig. 14-2.

of hydrocarbons as a second (probably non-wetting) phase in the pore space with the water will, as Chapman (1972) and Hedberg (1974) pointed out, reduce the effective permeability to water and may therefore considerably retard its expulsion. The association of detrital clay minerals with facies may well be important in the generation of hydrocarbons. In studies relevant to the stratigraphy of regressive sequences, van Andel and Postma (1954, p. 78) found that in the Gulf of Paria, illite is associated with the Orinoco delta platform and waters of lower salinity, and montmorillonite (smectite) is associated with the more saline environments. Later, Gibbs (1977) found that the proportion of montmorillonite in the muds increased away from the Amazon. The Niger delta has similar patterns (Porrenga, 1966), with montmorillonite content increasing to more than 50% offshore, in zones roughly parallel to the present delta. In the sandier facies, the proportions of montmorillonite are smaller. Porrenga also found that kaolinite decreased seawards from the Niger delta. In regressive sequences, therefore, Walther’s law tells us that the mudrock beneath a regressive sandstone would have an illitic facies on top of a montmorillonitic facies before diagenesis of these minerals. In a transgressive sequence the facies would be inverted, with the primary illitic facies lying on the sandy facies. Kaolinite would tend to decrease away from the sandy facies. Martin’s (1972) data lend support to this. 2.2.2.2. Associations Associations are notoriously difficult to interpret in geology, but the associations of regressive sequences with abnormal pressures are very strong and appear to be causal. They are: (1) regional structural style of narrow, steep anticlines separated by broad, gentle synclines; commonly with mud volcanoes; (2) growth faults and growth anticlines; (3) petroleum accumulation in structural traps; (4) accumulations with multiple sandstone reservoirs; (5) tendency for crude oils to be lighter in deeper, older reservoirs.

THE GEOLOGY OF ABNORMAL PORE PRESSURES

37

The last two may well not be causally associated with abnormal pressures in the mudrocks, but the first three almost certainly are because the essential ingredients appear to be the relatively small density and viscosity of the massive mudrock unit. The regional style is consistent with mechanical instability in the stratigraphic sequence, as shown by mathematical and physical models (e.g., Biot and OdC, 1965; Tanner and Williams, 1968). 2.2.2.3. Growth structures Growth faults. Growth faults are significant in the geology of abnormal pressures for two main reasons: first, they are evidence that the deformation of the sedimentary basin took place during subsidence while the sediment was accumulating; and second, their regional pattern of becoming younger in the direction of regression shows that they are intimately associated with the stratigraphy. Most of these growth faults are normal faults, so they also indicate that the deformation was taking place in a stress field in which the greatest principal compressive stress was vertical, the least being horizontal and normal to the strike of the faults. It is evident that the strike of the growth faults in regressive sequences and deltas is generally parallel to the depositional strike. Thorsen (1963) studied a large number of growth faults in southeast Louisiana and determined their period of maximum rate of movement by finding the horizon at which the growth index (the ratio of the thickness in the downthrown block to that of the correlative unit in the upthrown block) was greatest. H e found that the maximum rate of movement occurred progressively later in faults to the south, towards the Gulf of Mexico, in the direction of the regression. Comparison of Thorsen’s map (Thorsen, 1963, p. 107, fig. 4) with Dickinson’s (1953, pp. 416-417, fig. 3) shows that the maximum rate of growth-fault movement took place within a couple of biostratigraphic subzones above the top of abnormal pressures. Thorsen also noted that growth faults were associated with sand/shale ratios of 10% or less, and it is worth noting here that Harkins and Baugher (1969) concluded that abnormal pressures were associated with sandlshale ratios less than 5% to 10%. Chapman (1983, pp. 23-34) presented detailed arguments around the nature of growth faults in regressive sequences. In essence, these are that accumulation of sediment is due mainly to subsidence, and that the accumulation of sediment on both sides of a growth fault indicates that the whole fault was subsiding, but the downthrowing block was subsiding faster than the upthrowing block. Abnormally pressured mudrock at relatively shallow depths, to two or three kilometres, are commonly undercompacted for their depth, and have mechanical properties that would be appropriate at a much shallower depth. The incompetence of these mudrocks is widely considered to be the cause of the growth faults, which reflect a tendency for the overlying sequence to slide. The association between a growing delta, its growth faults and its stratigraphy is clearly revealed in the Niger delta (Fig. 2-5). Growth anticlines. A growth anticline, which is characterized by thicker rock units on the flanks than on the crest, formed during subsidence and, by analogy with

38

R.E. CHAPMAN

growth faults, the flanks were subsiding more rapidly than the crest. The relative rate of subsidence over the structure is indicated by the thickness of correlative units, and so can be represented by isopach and cumulative isopach maps, and sections drawn from them. Growth anticlines do not contain unambiguous evidence of their formation unless they are cut by growth faults. When they are cut by normal growth faults, the evidence is then unambiguous that the anticline was formed in the same stress field as that for the normal faults, that is, with the greatest principal compressive stress vertical. This constitutes strong, if not unambiguous, evidence that the anticlines were formed by incipient diapirism on account of mechanical instability, a topic modelled by Tanner and Williams (1968). Thorsen’s study of the ages of the Louisiana Gulf Coast’s growth faults did not include the rates of growth of growth anticlines, but he concluded that their maximum rate of growth occurred at about the same time as the maximum rate of movement on nearby growth faults (Thorsen, 1963). The pseudo-diapiric cause of growth anticlines is further supported by another feature of regressive sequences, elaborated by Chapman (1973, 1977, 1983) and mentioned above: the regional structural style of young regressive sequences is characterized by long, sinuous, narrow anticlinal trends separated by broad, gentle synclines. This is also a feature of mathematical and physical models of diapirism, the anticlinal ridges being separated by a distance that is the dominant wavelength of diapirism. This is a function of the ratio of the viscosities of the relatively compacted sandy sequence and the abnormally pressured mudrock; and it is also a function of the ratio of the thicknesses of the sandy overburden and the abnormally pressured mudrock, representing a regressive sequence as a two-layer mechanical system. The sandy overburden is the more rigid upper layer and the abnormally pressured mudrock is the more mobile lower layer. When the overburden is relatively more viscous, the dominant wavelength is longer and the rate of growth slower; and as the thickness ratio increases, so the dominant wavelength increases (see, for example, Biot and Ode, 1965). In due course, the sedimentary basin may suffer uplift and orogeny. When this happens, the structural style has already been imprinted on it. Around the Mahakam delta in eastern Borneo (Fig. 2-4) we see an example of this. On land, there are steep, narrow, sinuous anticlines that are separated by broad, gentle synclines. Some of the anticlines are sheared and overthrust, and were interpreted by van Bemmelen (1949, pp. 352 and 732) as sliding towards the sea in his hypothesis of gravitational tectogenesis. Offshore, however, we find normal growth anticlines in the ancestral delta, those in the landward trend through the “base” of the delta having few faults (Handil, Nilam, Badak), and the seaward ones having normal growth faults (Attaka, Bekapai). Abnormally pressured mudrocks underlie the sandy facies in all these fields, and are clearly capable of being the cause both of the incipient diapirism and the sliding, acting as a relatively low-density, low-viscosity lubricant. The change from a regime of superficial lateral “compression” to an extensional regime is a matter of considerable interest and importance. The lack of faults parallel to the depositional strike in the trend between the two regimes is consistent with a change from a

THE GEOLOGY OF ABNORMAL PORE PRESSURES

39

region in which the greatest principal compressive stress is horizontal to one in which it is vertical: the deviatoric stress in the intervening zone is too small for faults to be initiated, or sustained. The cause of the change of stress regime is not clear. It could be due to the presence of the sea because subaerial sliding is almost twice as “efficient” a process as submarine sliding (as we shall see in Chapter 3). It could be due to an obstacle to sliding near the present-day coast such as a change in the slope of the surface of the top of abnormal pressures. Or it could be due to relatively rapid sliding of the submarine portion on a steeper slope towards the Makassar Straits. Whatever the cause, the result is surely significant because the structural styles retain the feature of long, sinuous anticlines separated by broad, gentle synclines but the complexity of the anticlines changes. Part of this could be due to timing, the younger, seaward, anticlines having had less time to develop than the older, landward ones. 2.2.2.4. Abnormal pressures In regressive sequences, the top of abnormal pressures lies below the base of the sandy sequence, usually in the zone where the sand/shale ratio has become 10% or less. Although the pattern of the transition zone from normal to abnormal pressures is variable, the pressure tends to increase fairly steadily to a maximum that is normally rather less than the equivalent total overburden pressure. Sandy parts of this zone may show a reduction in the abnormality, and may be taken as evidence of leakage through the more permeable layer. If there are sevei a1 transgressivehegressive cycles, as in the Mackenzie delta, the top of abnormal pressures will become the bottom of abnormal pressure at the base of a cycle, and the surface enclosing abnormal pressures will be related to the stratigraphy.

2.3. RIFT BASINS

2.3.1. Selected areas The East African rift system has long been known and studied, but it was the computer-based technological advance of exploration seismology at the end of the 1960s that revealed an important class of basins that has come to be known as the rift basin. The cardinal features have been well described by Kent (1977) and may be summarized as follows: (1) The rift basin was initiated with normal faulting of basement, the faults becoming normal growth faults. In many parts of the world, these events occurred during the Triassic and Jurassic. (2) As “highs” developed, they were eroded and we commonly find two local unconformities in the Jurassic and Lower Cretaceous. These unconformities appear to become disconformities off the highs. (3) The last unconformity was followed by the accumulation of fine-grained sediments belonging to low-energy environments - mudrocks, silts, marls and limestones. This sequence of sedimentary rocks is typically Cretaceous to Tertiary

40

R.E. CHAPMAN

in age, and in most areas accumulation seems to be continuing at present. The post-unconformity sequence is typically unfaulted and unfolded, and the older faults appear to terminate at an unconformity. There is at least one area that has these features but perhaps would not normally be classified as a rift basin: the Arctic North Slope of Alaska in the area of the Barrow arch in general and of Prudhoe Bay oil field in particular. There is a most remarkable similarity of geology of widely separated areas. Prudhoe Bay, the North West Shelf of Australia, and the North Sea of northwest Europe share a very similar geological history not only of events, but also of the timing of those events. A notable, and probably very important, exception to this pattern is the Gippsland basin of southeast Australia. This basin shares the events with the other areas, but not the timing. The unconformity there is Eocene, separating faulted non-marine Cretaceous and Early Eocene sedimentary rocks from Oligocene marine marls and mudrocks (Fig. 2-10). 2.3.1.1. The North Sea The North Sea is such a rift basin, and the extensive and successful exploration for petroleum over a large area of it has provided a large amount of important data (Woodland, 1975; Illing and Hobson, 1981; Glennie, 1986). Abnormal pressures have been found in both the pre-unconformity sequence and the post-unconformity sequence. It will be more convenient to consider them in the reverse order because the younger one may be the cause, at least in part, of the older.

Post-unconformity sequence. There are two unconformities/disconformities (depending on position) in the North Sea, the first of Late Jurassic age, and the second of later Jurassic to Early Cretaceous; and this was followed by a long period of accumulation of muds in the Viking Graben. These mudrocks are abnormally pressured over a wide area, and undoubtedly their role in this petroleum province is very important. We may take the published data of Ekofisk as representative (Byrd, 1975; Van den Bark and Thomas, 1980,1981). The reservoir of Ekofisk is a Paleocene/Upper Cretaceous (DaniadMaastrichtian) chalk, overlain and underlain by mudrocks. The whole sequence is overpressured, including the reservoir originally, but the overlying Tertiary mudrocks are “more overpressured” than the water below the crude oil accumulation and much of the accumulation itself (for the energy of the accumulated oil relative to that of the water increases with elevation above the oil/water contact). Figure 2-11 illustrates this in terms of the acoustic-log response. Typically we find that the top of abnormal pressures is less pronounced than it is in a typical regressive sequence, with a gradual increase in abnormality with depth. This feature is seen in most of 4The customary jargon hcre is rather misleading. Pressure is not the only parameter; it is really a matter of energy. It is quite possible for an overlying bed to have pore fluids with greater energy than the underlying, but smaller pressures; and, conversely, an underlying bed with fluids with greater pressures but smaller energy. In Ekofisk, the pore-fluids in the overlying and underlying mudrocks have more energy than the water below the crude oil accumulation.

41

THE GEOLOGY OF ABNORMAL PORE PRESSURES

ESSO EXPLORATION AN0 PRODUCTION AUSTRALIA INC.

STRATIGRAPHY OFFSHORE GIPPSLAND BASIN

Up to 10.000' Non Marine

Fig. 2-10. Stratigraphic chart of the offshore Gippsland basin, southeast Australia. Courtesy of Esso Australia Ltd.

Herring's (1973) examples, but the transit time scale of his figures is too small for confidence. Pre-unconformify sequence. Much of the sequence below the unconformities/ disconformities is also abnormally pressured, as are their reservoirs; and the abnormality covers a large area of the Viking Graben (Fig. 2-12) (Chiarelli and

42

R.E. CHAPMAN Shale Transit Time, pSm 100

110

120

130

140

150

160

170

180

0

500

1 000

d e P

1500

t

h

2000

2 500

3 000

3 500

Fig. 2-11. Acoustic log response above the reservoir of Ekofisk, North Sea. The maximum abnormality is at about 1800 m. After Byrd, 1975, p. 443, fig. 2.

Duffaud, 1980). Many of the fields have abnormally pressured reservoirs. Again, the distribution patterns of the abnormal pressures, with greatest abnormality in the central areas of the graben, suggest that they are significant in this petroleum province. Of particular importance is the Kimmeridge Clay Formation, generally considered to be an important petroleum source rock. It is widely and seriously abnormally pressured and it is not only hot in the normal sense - it is also unusually highly radioactive. HCritier et al. (1981, p. 381) reported that 77 m (253 ft) of oil shale of Kimmeridgian age in the Frigg discovery well registered 250 API units of gamma radiation at about 4200 m (13,780 ft). Gamma-ray spectral logging shows a large uranium content (W.H. Fertl, pers. commun., 1988). An example of abnormal pressures in this context is the Brent field, described by Bowen (1975). Figure 2-13 shows the stratigraphy of the area. Abnormal pressures seem to be fault-controlled, and the field is near the eastern margin of the abnormally pressured Viking Graben. Clearly the faults are either sealing the fluids in this field, or leaking too slowly to dissipate their pressure. 2.3.1,2. Other rip-basin occurrences

Abnormal pressures exist in off-shore fields of the Atlantic shelf of North America (Grant et al., 1986) and in the North-West Shelf of Australia (Kyaw Nyein et al., 1977), but few details have been published and it is too soon to make an assessment of their nature.

THE GEOLOGY OF ABNORMAL PORE PRESSURES

43

61O

L

b

UNITED 60°

590

-t

NORWAY

1

KIN60DM

4 PIPER

I

50 O

\

0

000

1000

1500

IBNOIYIL

1000

PRt55UIt5

+

*

1000

Fig. 2-12. Abnormal pressure distribution in the North Sea. Reproduced from Chiarelli and Duffaud, 1980, p. 1248, fig. 3; courtesy of the American Association of Petroleum Geologists.

Two boreholes drilled in the southeast part of the Exmouth Plateau, Western Australia, beneath ocean depths of about 1 km (about 3000 ft), also encountered abnormally pressured mudrocks and associated sandstones. Resolution-1 (20"18'S, 113'41'E) was drilled in 1087 m (3566 ft) of water, and kicked while coring at 3797 m (12,457 ft) below KE3 in Jurassic sandstones. These sandstones were found to have pore pressures about 30% above normal hydrostatic, and subsequent logging found

44

R.E. C H A P M A N

LITHOSTRATIGRAPHIC COLUMN NORWAY OFFSHORE LICENCE 037 TI M E STRATIGRAPHIC UNITS

THICK-

LlTHO5TRATlGRAPHlC U N IT 5 LITHOLOGY GROUP FORMATION OR OR FORMATIOH MEMBER SEA BOTTOI

SERIES/STAGE

NESS

RANQE

-A

MAASTRICHTIA

CAMPANIAN SANTONIAN

u

SHETLAND GROUP

N

?

!

CONlAClAN

!

~

~

~

E

N T ~ 758.399

MII

CENOMANIAN

).USTIIAb

ALBIAN CLAYSTONEI

CROMER YNOLL

LATE IMYEUIA

MAIN IYMLIIA

I

a1430

a1017 -7-

IAULI IMMLRIAI

UPPER RlASSlC

6032 +

I

CARNIAN

- OLDE!

SECTION ENETRA > IN LO3 WELL 33/12-5

I? LADINIAN

I

ANlSlAN

7 SCYTHtAN

L

A

LEGEND

L

E

OIL RESERVOIR

1 I

C

Fig. 2-13. North Sea stratigraphy. Reproduced from Kirk, 1980, p. 102, fig. 7 with permission.

THE GEOLOGY OF ABNORMAL PORE PRESSURES

45

sharp changes in the trends of shale conductivity, acoustic velocity and shale density below 3020 m (9908 ft). Zeepaard-1 (20”44’S, 114“25’E), drilled 100 km (60 miles) to the northeast of Resolution-1, in 740 m (2428 ft) of water, encountered abnormal pressures at 3844 m (12,612 ft), at the same horizon as those of Resolution-1 5 . Proper evaluation of these pressures from borehole logs was prevented by variable lithology. Drilling in such deep water has its own problems, and even modest over-pressure could prove difficult to control. 2.3.2. Generalizations 2.3.2.1. Stratigraphy In very broad terms the stratigraphy of rift basins is found to be a sequence of generally shallow-marine to non-marine sediments from inception until the period of non-accumulation that also marks the end of faulting, followed by an unfaulted and unfolded sequence of low-energy marine sediments, mudrocks, marls o r carbonates. There is commonly a marked contrast in the provenance of these two sequences. There does not appear to be any pattern to the abnormal pressures in the older sequence other than the pattern of greater abnormality in the centre of the rift basin, and normality at the margins. Some reservoir sandstones are also abnormally pressured, and their distribution may be affected by faults. The pattern in the younger sequence seems to be largely controlled by lithology, with abnormal pressures being found in the thick massive mudrocks. Where there are extensive sandstones, such as in the Frigg fields, pressures are normal or close to normal. 2.3.2.2. Growthfaults The growth faults of rift basins record the development of the rift. The bounding fault or faults may have the peculiar feature that the stratigraphic record of their movement exists only in the downthrown block. For example, the Darling Fault bounding the Perth basin in Western Australia has a throw of 6 km. The Permian to Cretaceous rocks in the downthrown block do not exist in the “upthrown”, eastern block, which is of Precambrian basement (see Chapman, 1983, p. 365). 2.3.2.3. The unconformitiesldisconfomities The stratigraphic hiatus of rift basins, so significant in the understanding of their development, appear to play no significant part per se in the development or existence of abnormal pressures. Their significance is that they heralded a change in the facies of sediment that accumulated - usually a very considerable change, not only of lithology but also of source of supply. The accumulation of fine-grained sediments on the unconformities/disconformities not only provided a potential petroleum source rock, but also a seal to many of the accumulations (e.g., Statfjord and Brent fields in the North Sea; and Prudhoe Bay in Alaska). I am indebted to Esso Australia Ltd for these data, but the well completion reports are on open file at the Western Australian Department of Mines.

46

R.E. CHAPMAN

2.3.2.4. Abnormal pressures Rift basins may contain two distinct zones of abnormal pressures. The upper one, above the unconformities/disconformities, typically shows a slow build-up of excess pressure with depth; and the build-up may be interrupted by sandstones or carbonates that act as local drains. The pre-unconformity sequence may also be abnormally pressured, and severely so, in spite of the presence of a high proportion of sandstone and carbonate. Whereas petroleum reservoirs in regressive sequences are rarely overpressured, reservoirs in the pre-unconformity sequence of rift basins are quite commonly overpressured.

2.4. SYNTHESIS

Faulting in rift basins is confined virtually to normal faults that were initiated in basement and continued to move during the early development of the rift basin. These growth faults differ in some important respects from those in the regressive sequences described earlier, but they share the essential feature of separating a thicker correlative sequence from a thinner correlative sequence; and they share the feature of dying out upwards. Both types commonly form barriers to fluid migration. The main points of difference are in the shape. Growth faults in regressive sequences are curved in plan and section, concave to the direction of the regression 6 , and roughly parallel to the depositional strike. They apparently flatten and die out with depth, in the massive mudrock unit that is abnormally pressured. They may also die out upwards. These growth faults may also be deformed by growth anticlines. Growth faults in rift basins are planar, and parallel to the rift (of course). They commonly die out upwards. The age-relationship of growth faults in regressive sequences is usually of younger faults being on the downthrowing side of older faults, in the direction of the regression. In rift basins, it is possible that the oldest faults tend to be in the centre of the basin, the rift basin widening with time; but the marginal faults are usually very large, with throws to be measured in kilometres (e.g., as seen in the southern Perth basin in Western Australia). Growth faults in regressive sequences are intimately associated with abnormal pressures. Both are associated with sand/shale ratios of less than 10% (e.g., Thorsen, 1963, and Harkins and Baugher, 1969) and there are areas where they seem to contain the abnormal pressures (Dickey et al., 1968; Fowler et al., 1971). In contrast, growth faults are probably non-existent in the abnormally pressured mudrocks of post-unconformity sequences in rift basins (but it is conceivable that they do exist but are undetectable). The essential difference between the abnormal pore-fluid pressures in a regressive sequence and those in the post-unconformity mudrocks of rift basins is that the The term “down-to-thc-basin” fault is objectionable mainly for the reason that the basin referred to is the physiographic basin, not the sedimentary basin. Such faults are not necessarily “down” to the sedimentary basin.

THE GEOLOGY OF ABNORMAL PORE PRESSURES

47

latter exist by virtue of the relatively rapid accumulation of a thick mudrock, while the former are accentuated by the regressive sandstones that overlie them and act as a filter press, making the transition zone thinner. The change to serious abnormality in regressive sequences takes place over a smaller vertical distance. We have much to learn about the geology of abnormal pressures, but there is no doubt that it is an important topic for both “pure” and applied geology. Its proper understanding is, of course, important for the exploration and development of those areas that have abnormal pressures, and it seems quite certain that these abnormal pressures play a significant role in the migration of crude oil and gas as well as the formation of the traps. Abnormal pressures are hardly abnormal any more.

ACKNOWLEDGEMENTS

I am very grateful to the following people and organizations for help in the preparation of this chapter: late Walter Fertl for criticism and discussion of this chapter; Professor R. D. Collerson and his Department at the University of Queensland for assistance with the figures; Mrs E. Burdin drew Figs. 2-1, 2-6, 2-7, and 2-8, and Mrs Irene Lenneberg drew Figs. 2-4 and 2-9; to Esso Resources Canada Ltd and Paul Hemingson for Figs. 2-6, 2-7, and 2-8; to Esso Australia Ltd for Fig. 2-11; to AndrC Chiarelli and SociCtC Nationale Elf Aquitaine for Fig. 2-12. I am also very grateful to the American Association of Petroleum Geologists for permission to reproduce Figs. 2-2, 2-3, 2-5, 2-12, originally published in their Bulletin. The source of other figures is acknowledged in the captions.

REFERENCES Abraham, W.E.V., 1937. Geological aspects of deep drilling problems. 1. Inst. Pet. Technol., 23: 378-387. Discussion: pp. 387-390. Anderson, R. van V., 1927. Tertiary stratigraphy and orogeny of the northern Punjab. Bull. Geol. SOC. Am., 38: 665-720. Beck, R.H., 1972. The oceans, the new frontier in exploration. L Aust. Pet. Explor: Assoc., 12(2): 7-28. Biot, M.A. and OdC, H., 1965. Theory of gravity instability with variable overburden and compaction. Geophysics, 30: 213-227. Bowen, J.M., 1975. The Brent oil-field. In: A.W. Woodland (Editor), Petroleum and the Continental Sherf of North-West Europe, Vol. 1. Geology. Institute of Petroleum, London, and Applied Science Publishers, Barking, pp. 353-361. Byrd, W.D., 1975. Geology of the Ekofisk field, offshore Norway. In: A.W. Woodland (Editor), Petroleum and the Continental Shelfof Noah-West Europe, Vol. 1. Geology. Institute of Petroleum, London, and Applied Science Publishers, Barking, pp. 439-444. 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. 7jans. Am. Inst. Min. Metall. Eng., 127: 31-38. Chapman, R.E., 1972. Primary migration of petroleum from clay source rocks. Bull., Am. Assoc. Pet. Geol., 5 6 2185-2191. Chapman, R.E., 1973. Petroleurn Geology: A Concise Study. Elsevier, Amsterdam, 304 pp. Chapman, R.E., 1977. Subsidence and deformation of terminal regressive sequences in the Indonesian region. Proc. Indonesian Pet. Inst., 5 (1) (for 1976): 151-158.

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Chapman, R.E., 1983. Petroleum Geology. Elsevier, Amsterdam, 415 pp. Chiarelli, A. and Duffaud, F., 1980. Pressure origin and distribution in Jurassic of Viking Basin (United Kingdom-Norway). Bull., Am. Assoc. Pet. Geol., 64 (8): 1245-1250. Colville, G.W., 1937. Notes on deep wells drilled in Iran. J. Inst. Pet. Technol., 23: 408-41 1 . Dailly, G.C., 1976a. A possible mechanism relating progradation, growth faulting, clay diapirism and overthrusting in a regressive sequence of sediments. Bull. Can. Pet. Geol., 24: 92-116. Dailly, G.C., 1976b. Pendulum effect and Niger delta prolific belt. Bull., Am. Assoc. Pet. Geol., 60: 1543-1550. Dickey, P.A., Shriram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160 (3828): 609-615. Dickinson, G., 1951. Geological aspects of abnormal reservoir pressures in Gulf Coast region of Louisiana, U.S.A. Proceedings of the 3rd World Petroleum Congress, The Hague, 1951, Section 1: 1-16. Discussion: 1: 16-17. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana. Bull., Am. Assoc. Pet. Geol., 37: 410-432. Evamy, B.D., Haremboure, J., Kamerling, P., Knaap, W.A., Molloy, F.A. and Rowlands, P.H., 1978. Hydrocarbon habitat of Tertiary Niger delta. Bull., Am. Assoc. Pet. Geol., 62: 1-39. Fertl, W.H. and Sahay, B., 1984. Occurrence of high pressure formations on and off India. Oil Gas J., 82(32) (Aug. 6): 81-87. Fowler, W.A., Boyd, W.A., Marshall, S.W. and Meyers, R.L., 1971. Abnormal pressures in Midland field, Louisiana. In: Houston Geological Society, Abnormal Subsurface Pressure: A Study Group Report 1969-71. Houston Geological Society, Houston, Texas, pp. 48-77. Gibbs, R.J., 1977. Clay mineral segregation in the marine environment. 1.Sediment. Petrol., 47: 237-243. Glennie, K.W. (Editor), 1986. Introduction to the Petroleum Geology ofrhe North Sea. Blackwell Scientific Publications, Oxford, 2nd ed., 278 pp. Grant, R.A., McAlpine, K.D. and Wade, J.A., 1986. The continental margin of eastern Canada: geologic framework and petroleum potential. In: M.7: Halbouty (Editor), Future Petroleum Provinces of the World. Am. Assoc. Pet. Geol., Mem., 40: 177-205. Harkins, K.L. and Baugher, J.W., 1969. Geological significance of abnormal formation pressures. J. Pet. Technol., 21: 961-966. Hedberg, H.D. 1974. Relation of methane generation to undercompacted shales, shale diapirs, and mud volcanoes. Bull., Am. Assoc. Pet. Geol., 58: 661-673. Hemingson, P. and Carew, W., 1984. Hydrocarbons and geopressure in the Beaufort-Mackenzie basin. Paper presented to the Canadian National Conference on Earth Sciences, “Geopressures and Hydrocarbon Occurrences”, Banff. Htritier, EE., Lossel, P. and Wathne, E., 1981. The Frigg gas field. In: L.V. Illing and G.D. Hobson (Editors), Petroleum Geology of the Continental Shelf of North- West Europe. Institute of Petroleum and Heyden, London, pp. 380-391. Herring, E.A., 1973. North Sea abnormal pressures determined from logs. Pet. Eng., 45 (November): 72-84. Hull, C.E. and Warman, H.R., 1970. Asmari oil fields of Iran. In: M.T. Halbouty (Editor), Geology of Giant Petroleum Fields. Am. Assoc. Pet. Geol., Mem., 14: 428-437. Illing, L.V. and Hobson, G.D. (Editors), 1981. Petroleum Geology ofthe Continental Shelf of North- West Europe. Institute of Petroleum, London, and Heyden, London, 521 pp. James, D.M.D. (Editor), 1984. The Geology and Hydrocarbon Resources of Negara Brunei Darussalam. Muzium Brunei (Kota Batu) and Brunei Shell Petroleum (Seria), Brunei, 169 pp. Keep, C.E. and Ward, H.L., 1934. Drilling against high rock pressures with particular reference to operations conducted in the Khaur field, Punjab. J. Inst. Pet. Technol., 20: 990-1013. Discussion: pp. 1013-1026. Kent, P.E., 1977. The Mesozoic development of aseismic continental margins. J. Geol. SOC. London, 134: 1-18. Kirk, R.H., 1980. Statfjord field - a North Sea giant. In: M.T. Halbouty (Editor), Giant Oil and Gas Fields of the Decade 1968-1978. Am. Assoc. Pet. Geol., Mem., 30: 95-116.

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Koesoemadinata, R.P., 1969. Outline of geologic occurrence of oil in Tertiary basins of west Indonesia. Bull., Am. Assoc. Pet. Geol., 53: 2368-2376. Kyaw Nyein, R., MacLean, L. and Warris, B.J., 1977. Occurrence, prediction and control of geopressures on the Northwest Shelf of Australia. J. Aust. Pet. Explor Assoc., 17 (1): 64-77. Liechti, P,Roe, EW. and Haile, N.S., 1960. The geology of Sarawak, Brunei, and the western part of North Borneo, Bull. Geol. Sun! Dep., Br Em'tories Borneo, 3 (2 vols.). Magnier, Ph., Oki, T. and Kartaadiputra, L.W., 1975. The Mahakam delta, Kalimantan, Indonesia. Proceedings of the 9th World Petroleum Congress, Tokyo 1975,2: 239-250. Martin, G.B.,1972. Abnormal high pressure and environment of deposition. 3rd Abnormal Pressure Symposium of the Sociev of Petroleum Engineers of the American Institute of Mining and Metallurgical Engineering, Baton Rouge, La., May 1972, Paper SPE 3846. Mascle, J.R., Bornhold, B.D. and Renard, V, 1973. Diapiric structures off Niger delta. Bull., Am. Assoc. Pet. Geol., 57: 1672-1678. Porrenga, D.H., 1966. Clay minerals in Recent sediments of the Niger delta. Clays and Clay Minerals: Proceedings, 14th National Conference, pp. 221-233. Rijks, E.J.H., 1981. Baram delta geology and hydrocarbon occurrence. Bull. Persatuan Geol. Malaysia, 14: 1-18. Schaar, G., 1977. The occurrence of hydrocarbons in overpressured reservoirs in the Baram delta (offshore Sarawak, Malaysia). Proceedings of the Indonesian Petroleum Institute, 5 (for 1976): 163170. Scherer, F.C., 1980. Exploration in east Malaysia over the past decade. In: M.T. Halbouty (Editor), Giant Oil and Gas Fields of the Decade 1968-78. Am. Assoc. Pet. Geol., Mem., 30: 423-440. Tanner, W.F. and Williams, G.K., 1968. Model diapirs, plasticity, and tension. In: J. Braunstein and G.D. O'Brien (Editors), Diapirism and Diapirs. Am. Assoc. Pet. Geol., Mem., 8 10-15. Thorsen, C.E., 1963. Age of growth faulting in southeast Louisiana. Trans., Gulf Coast Assoc. Geol. Soc., 13: 103-110. Van Andel, Tj. and Postma, H., 1954. Recent Sediments of the Gulf of Paria. Reports of the Orinoco Shelf Expedition, Vol. 1. Verh. K. Ned. Akad. Wetensch., Afd. Natuurkd., Eerste Reeks, Dee1 XX, No. 5, 245 pp. Van Bemmelen, R.W., 1949. The Geology of Indonesia, VoL IA. General GeJogy of Indonesia and Adjacent Archipelagoes. Government Printing Office, The Hague, 732 pp. Van den Bark, E. and Thomas, O.D., 1980. Ekofisk: first of the giant oil fields ir, western Europe. In: M.T. Halbouty (Editor), Giant Oil and Gas Fields of the Decade 1968-78. Am. Assoc. Pet. Geol., Mem., 30: 195-224. Also in: Bull., Am. Assoc. Pet. Geol., 65: 2341-2363 (1981). Van den Bark, E. and Thomas, O.D., 1981. Ekofisk: first of the giant oil fields in western Europe. Bull., Am. Assoc. Pet. Geol., 65: 2341-2363. Weber, K.J. and Daukoru, E., 1975. Petroleum geology of the Niger delta. Proceedings of the 9th World Petroleum Congress, Tokyo 1975,2: 209-221. Wilson, G.F., 1937. Drilling of a deep pressure test in India. J. Inst. Pet. Technol., 23: 401-407. Woodland, A.W. (Editor), 1975. Petroleum and the Continental Shelf of Norlh-Wesl Europe, Vol. 1. Geology. Institute of Petroleum, London, and Applied Science Publishers, Barking, 501 pp.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 0 1994 Elsevier Science B.V. All rights reserved

51

Chapter 3

ABNORMAL PORE PRESSURES: ESSENTIAL THEORK POSSIBLE CAUSES, AND SLIDING RICHARD E. CHAPMAN

3.1. PROPERTIES OF FLUIDS AND THE ROCKS THAT CONTAIN THEM

A fluid, as the name implies, is a substance that flows. That is, it yields at once to shear or tangential stress. Fluids may be liquid or gaseous. Some fluids flow more easily than others, and these are then said to be less viscous. Viscosity is the property of internal resistance to flow, and it is due to molecular cohesion. The greater the internal resistance to flow, the larger the viscosity. It is the inverse of fluidity. Isaac Newton examined the question of viscosity of fluids, and considered the behaviour of a fluid between two parallel plates, close together, one moving relative to the other (Fig. 3-1). Imagine the upper plate moving at constant velocity V relative to the lower, with the molecules of water adjacent to each plate stationary relative to that plate. The relative motion of the water at the upper plate is therefore V, and that at the lower plate is zero. Between the two, we can imagine that the velocities will be distributed between zero and V, each layer slipping relative to those above and below. A force applied to the upper plate with a more-viscous fluid between the plates will result in a smaller velocity V than would be found with a less-viscous fluid. This was Newton’s concept of viscosity, and it is what we mean when we speak of newtonian viscosity. The coeflcient of viscosity (q), also known as the absolute or dynamic viscosity, is the tangential force per unit of area that maintains unit relative velocity between two parallel planes unit distance apart, and it is defined as the ratio of shear stress, t,to the rate of shear strain, or: q = t/(dV/dz)

dz

or

t = q(dV/dz)

i

Fig. 3-1.Newton’s coefficient of viscosity.

(3-1)

52

I

R.E. CHAPMAN Ideal elastic solid

fluid

R a t e of shear strain ( d x / d z )

Fig. 3-2. Different types of viscosity.

It is useful to consider such properties in terms of the dimensions of Mass ( M ) , Length ( L ) , and Time (7'). The dimensions of the coefficient of viscosity are ( M L - ' T - 2 ) / ( L T - ' L - ' ) = ML-'T-'. Note that viscosity has the dimension of time, and so most materials will "flow" if the time is long enough. The units of the coefficient of viscosity are: - newton second per square metre (N s m-2) in SI units - poise (P), or dyne second per square centimetre in units of force, length and time; or grams per centimetre second (g cm-' s-l) in units of mass, length and time. The fluid is said to be newtonian, and its viscosity newtonian, if the coefficient of viscosity is constant throughout the fluid. Fluids in which the viscosity is not constant are, of course, non-newtonian fluids. This is shown in Fig. 3-2. A fluid that has no internal resistance to flow, no viscosity, is called an ideal fluid, and is represented in the diagram by a horizontal line - zero shear stress, finite rate of shear strain. There is another property of fluids that is also called viscosity, but qualified by the adjective kinematic because it concerns motion without reference to force. Kinematic viscosity is the ratio of the coefficient of viscosity to the mass density of the , it appears in many expressions in fluid mechanics. It has the dimenfluid ( ~ / p )and sions L 2 T - ' , a length multiplied by a velocity. The units of kinematicviscosity are: - m2/s in SI Units - stoke (S), which is cm2/s, in metric units (lo4 S = 1 m2/s) - square feet/second (10.7639 ft2/s = 1m2/s)

3.1.1. Statics Statics is the study of materials at rest, in this case fluids at rest. The inability of fluids to withstand the slightest shear stress leads to four fundamental propositions: (1) The free upper suq5ace of a liquid in static equilibrium is horizontal. We see this in everyday life, and use it for practical purposes in surveying and building. It can be demonstrated analytically (see, for example, Chapman, 1981, p. 5).

ABNORMAL PORE PRESSURES

53

P, Fig. 3-3. Forces acting on a small prism of liquid.

( 2 ) Surfaces of equal pressure in static liquids are horizontal. This proposition is intuitively acceptable provided the liquid is homogeneous throughout. The pressure at depth d below the surface is given by pgd, where p g = y is the weight density, the weight of unit volume of the liquid. If the liquid is not homogeneous, stresses will be set up and it will flow until the stresses are relieved by mixing or stratification. (3) The pressure at a point in a liquid in static equilibrium is equal in all directions. Again, this is intuitively satisfying because if it were not true there would be stresses in the liquid that would cause flow until they were eliminated. It can also be demonstrated analytically by considering the forces acting on a prism of the liquid that is so small that its weight is insignificant compared to the pressure (Fig. 3-3). If the side b has unit area, the area of side a is sina and that of c is cosa. The force (pressure x area) exerted by the liquid on side a is pa sina, and on side c is pc cosa. The force p on side b of unit area can be resolved into horizontal and vertical components, P b sina and P b cosa, respectively. The prism is in static equilibrium so the sum of the forces acting on it must be zero. Hence, pa sina - pb sina = 0 and pa = Pb pc COSU - P b

COSa = 0

and pc = P b

and from the second proposition, the forces acting on the two parallel sides are clearly equal and opposite. Since pa = P b = pc is independent of the angle a,which may be arbitrarily assigned any value and orientation, the pressure at a point in a static liquid is equal in all directions. (Note most carefully the emphasis on point, because the pressure on an object is not equal in all directions.) This leads to the fourth proposition: (4) The horizontal force acting on a surface in a static fluid is the product of the pressure and the vertical projection of the area. This can also be shown to be true for curved surfaces by considering a very small area of the surface and its slope.

54

R.E. CHAPMAN

3.1.2. Capillaly pressure, surface and integacial tension When two fluids coexist in a confined space, the geometry of the surface separating them becomes distorted by forces in and around the interface. The interface is also distorted where it comes into contact with solids. We see this when reading a rain-gauge, or looking at the water surface in any small tube (Fig. 3-4). In petroleum reservoirs, capillary pressures account for the zone between 100% water and the irreducible water saturation at the base of an accumulation Above the oil/water contact, above the level at which the irreducible water saturation is achieved, the water is concentrated around the points of grain-to-grain contact in pendular rings (Fig. 3-5). The water, which is in contact with the solid surfaces, is said to be the wettingphase. This water is immobile, each pendular ring being hydraulically isolated from the others, and there is much evidence that this water is the water that existed in the reservoir when the crude oil or gas accumulated (Chapman, 1982). The problems of understanding the physics of petroleum reservoirs are severe enough, and we have very little data on the fluid distribution in mudrocks, but there are reasons to believe that the same principles apply. These centre around the evidence for the existence of petroleum as a separate phase during primary migration, both from resistivity measurements in supposed source rocks and from evidence of elevated pore pressures due to petroleum generation (Meissner, 1978, and Spencer, this volume). It seems essential for the petroleum to form a continuous non-wetting phase if it is to migrate through the very small pores of mudrocks (Dickey, 1975). By the same token, if the water saturation is high because the permeability is too low for its rapid expulsion, the paths of the non-wetting fluid (in this case, petroleum) will be constricted, and burial under these conditions may lead to abnormally high pore pressures.

'.

I Fig. 3-4. Water rises in a small tube inserted into a bowl of water due to capillary pressure.

' Surface tension is known as interfacial tension between two liquids.

ABNORMAL PORE PRESSURES

55

Fig. 3-5.Pendular rings at irreducible water saturation.

Such pressures do not require an immediate source rock for their existence because reduction of water pressure during migration may lead to the exsolution of gas (particularly C02) as a separate, continuous or non-continuous, non-wetting phase. Indeed, Hedberg (1974) regarded this as an important part of the process of diapirism.

3.1.3. Liquid-filledporous solids in static equilibrium Liquids in porous rocks behave no differently in principle from liquids in other containers. The free upper surface of a liquid at rest in a porous rock is horizontal. If the free upper surface is not horizontal, the water (all the water) is moving. There is a scale effect due to capillarity (as discussed above), but over an area measured in tens of square metres the free surface of static water is macroscopically horizontal. This would be revealed by the static2 water level in boreholes. If the liquid is moving, the free upper surface is inclined in the direction of motion, due to the loss of energy to friction. Because of the very large solid surface area in contact with the flowing liquid, the frictional losses are very large. The rate of flow in porous rocks is very small, rarely exceeding a few metres a year; but the slope of the free surface can be large, measured in a few tens of degrees. The well-known observation that the water table is a subdued model of the topography in many regions is testimony to this, and to the fact that this water is moving. The liquid affects the whole rock because the grains of the rock are partly supported by the force of buoyancy. This support exists with both static and flowing water. Heavy rain may cause land-slips because the high water table reduces the effective stress in soil and rocks, and because the weight of the water-saturated 'Static, in this context, refers to the water level in a well that is not producing.

56

R.E. CHAPMAN

material may be unsupported on the hillside. This is why retaining walls have drainage holes in them. 3.1.4. Bulk density

The density (mass density or weight density) of rocks in bulk is a function of the porosity, the mean density of the solid components and the mean density of the liquids in the pores:

where pp is the mean pore-fluid mass density, ps is the mean grain mass density, and f is the fractional porosity. (It is customary to write mean density 7,but we are almost always concerned with mean densities, so the bar will be omitted.) Because the mean grain density is commonly about 2650 kg mP3 (2.65 g/cm3), an estimate of porosity or density, knowing the other, can easily be made. The weight of a volume v of water-saturated sedimentary rocks is made up of the weight of solids: ws = ps

gv(1 - f)

and the weight of water in the pore space:

so the total weight is their sum:

3.1.5. Pressure and stress

The pressure (which is a force on an area) exerted by the whole rock, solid and liquid, on a horizontal surface within the rocks is clearly pb g v / A or pb gz, where z is the vertical thickness of the rocks to the surface. It may appear from eq. 3-3 that this pressure is partitioned into one due to solids acting on the proportion of the area occupied by solids, A ( l - f), and another due to pore water acting on that proportion occupied by water, Af. That this is not so was demonstrated by Terzaghi (1933) in an analysis of the effects of buoyancy on concrete dams. Terzaghi postulated that the force of buoyancy acts only on solid surfaces in contact with water in the pore spaces, and he set up a buoyancy coefficient: m = 1 - (A,/A) where A, is the area of solids in the undulating surface that only passes though grain contacts. This surface is projected onto a horizontal surface, so the term A , / A is the proportion of the area not exposed to buoyant forces, and m is a measure of the area over which they do act. In two series of experiments he found that the value of m varied little from unity. The buoyant force was found to be:

ABNORMAL PORE PRESSURES

57

where y is the weight density of the water. This was found to hold even for dense concrete of small porosity. His postulate was therefore not supported by his experiments. This result is of interest because it means that the force of buoyancy acts on the total relative area of solids, (1 - f ) , irrespective of the contact areas between grains. The existence of a finite tensile strength is sufficient indication that the value of A , is not zero. The same was found for plastic clays, and Terzaghi reported that “The strain in clay and in concrete exclusively depends on the differences between the total stresses and the neutral stresses [pore pressures]. In every point of the saturated material the neutral stresses act in every direction with equal intensity and they are equal to the pressures in the water at that point.” (Terzaghi, 1936, p. 875.) Without actually using the words, he is describing a body force. This led to what has become known as Tenaghi’s relationship:

a=S-p

(3-4)

where a is the effective stress, S is the vertical component of total stress (pbgz), and p is the pore-fluid pressure (the neutral stress of Terzaghi). The logic of this is that if the vertical component of total stress is sensibly constant, if the compressibility of solids is negligible compared to that of the fluids, and if the only components are the pore-fluid pressure and the effective stress, then p can only increase as a proportion of S at the expense of a , and vice versa. Compaction is due to the effective stress - the stress transmitted through the solid framework. It is only an approximation because the vertical component of total stress does not remain strictly constant in a sedimentary basin that is actively developing and accumulating sediment, nor does it remain strictly constant during compaction of the sedimentary rocks. 3.1.6. Field evidence of Tenaghi’s relationship

The field evidence for Terzaghi’s relationship is quite simply that the surface over many oil fields subsided after production had begun. For example, subsidence over the Lagunillas field on the shore of Lake Maracaibo, Venezuela, was reported by M. ap Rhys Price to be “in direct proportion with the production taken out” (Kugler, 1933, discussion on p. 769). And water extraction in the Houston district of Texas has also led to surface subsidence that coincides closely with the decline in static water level (Gabrysch, 1967). Evidently the extraction of liquid led to a reduction in pore pressure, an increase in the effective stress (a),and hence compaction of the reservoirs. A well-known and well-documented example is that of the Wilmington oil field, California, described by Mayuga (1970). Beneath the southern coastal districts of Los Angeles and the city of Long Beach, an industrial and residential area that included the harbour and naval shipyard of Long Beach, Wilmington oil field was discovered in 1932. During the first 30 years of its life, more than 184 x lo6 m3 (1156 million barrels) of oil and 23.8 x lo9 m3

58

R.E. CHAPMAN

35

1

i

I50

a

w 25

5

Fig. 3-6. Crude oil production and subsidence, Wilmington field, California (after Mayuga, 1970, fig. 16).

(840 x 10' ft3) of gas were produced. Major production began about 1937 when the size of the discovery became apparent, and within a decade the land surface began to subside, threatening coastal installations. Figure 3-6 shows the relationship with time between fluid extraction and injection, and surface subsidence. Maximum subsidence was 8.8 m (29 ft), and this was over the crest of the anticline. This vertical movement also caused horizontal movements of up to 3 m (10 ft), and severe damage was done to oil wells and to surface installations. There is no doubt about the cause of the subsidence. The maximum subsidence rate, of 0.71 m/year or 2.3 ft/year, occurred in 1951 about 9 months after production peaked. Water-injection schemes began in 1953, and by 1958 production could be increased while the rate of subsidence decreased. In the areas of greatest water injection, the surface was even raised by about 25 cm (10 inches). Mayuga (1970) has given a full account of these field operations, including evidence that almost all the subsidence could be attributed to compaction of the petroleum reservoirs. These examples of dominantly sandstone compaction have now been joined by a striking example of carbonate reservoir compaction, in the Ekofisk oil field in the Norwegian North Sea. The Norwegian Petroleum Directorate, in its Annual Report for 1986 (p. 44), reported that the sea floor had subsided about 3.8 m (12.5 ft) near the centre. During the period 1980-1986, the average rate of subsidence was between 0.4 and 0.5 m/year (1.3-1.6 ft/year). By 1989 subsidence was 4.4 m at a rate

59

ABNORMAL PORE PRESSURES

of 0.3 m/year (Berget et al., 1989); and by 1992 subsidence at Ekofisk was more than 5 m, and was also taking place in the smaller chalk fields of the area. The cause of the subsidence is clear. Ekofisk, at the time of discovery in December 1969, had a single, large, abnormally pressured crude oil reservoir of Paleocene/Upper Cretaceous chalk. The cap rock is a thick Tertiary mudrock that is also abnormally pressured (Van den Bark and Thomas, 1981). The initial reservoir pressures were about 49.2 MPa at 3170 m (7135 psi at 10,400 ft), or nearly 17 MPa (2500 psi) above normal hydrostatic, so that the effective stress in the reservoir was less than normal for its depth. During subsequent production to the end of 1985, the following volumes of fluids were extracted and injected: Produced Crude oil (gross) Gas

204.45 x lo6 m3 80.87 x lo9 m3

1.286 x lo9 bbl 2.85 TCF

Injected Gas Water Natural gas liquids

19.40 x lo9 m3 3.45 x lo6 m3 1.82 x lo6 m3

0.69 TCF 21.7 x lo6 bbl 11.4 x lo6 bbl

During this period the reservoir pressure declined to approximately 27.6 MPa (4000 psi), a loss of more than 21 MPa (3000 psi), and the effective stress increased by approximately the same amount, according to Terzaghi’s relationship (a = S - p). The reservoir pressures are now below normal hydrostatic, and gas and water are being injected to counteract the subsidence. The early subsidence reduced the elevation of the platforms above the sea, of course, and the platforms had to be raised 6 m (20 ft) for safety. It appears that the compaction and subsidence have deformed the wells. It has also been found that this recent compaction has altered the performance of the wells by altering the reservoir characteristics, but no significant decrease in permeability has so far been reported. These changes may also reduce the ultimate recovery. The process is, of course, being carefully studied (see for example Potts et al., 1988, and Jones et al., 1991, p. 19). We may expect to learn much when the full details of these events are published. 3.1.7. Compaction Compaction under the gravity load of the overlying sediments and sedimentary rocks is one of the fundamental processes of geology, and one that is important in petroleum geology and in the understanding of abnormal pressures. It affects stratigraphic thicknesses and relationships, pore-water movement and chemistry (discussed in Chapter 5), the migration of petroleum and probably also of base I am indebted to the Norwegian Petroleum Directorate in Stavanger for these data (letter of 6 May 1988), and to the Directorate and 0ystein Dretvik for bringing me up-to-date with their letter of 22 May 1992.

60

R.E. CHAPMAN

metals. All sediments and sedimentary rocks compact to some extent. Sediment begins to compact soon after it accumulates, and the process changes some of its properties. We are only concerned with sediment that accumulates into the stratigraphic record, and therefore we are not concerned with initial mud porosities of 80% and more, but rather with about 50% and less. Early compaction, as Hedberg (1936) noted, involves grain re-arrangement as well as mechanical deformation of grains. Most obviously, the sediment becomes more dense, less porous and less permeable, and the stratigraphic unit becomes thinner. The mechanical strength of the sediment increases and the combination of compaction and consolidation converts the sediment to a rock. A rock that is compacted and consolidated suffers virtually no further compaction, but of course further burial may well lead to more diagenetic changes, and ultimately metamorphism. Compaction of sediment normally increases with increasing depth due to the increase in load, so the porosity normally decreases with increasing depth, and bulk density increases. It is a process that can only proceed with the commensurate expulsion or compression of the pore fluids. In the consideration of abnormal pressures, we are mainly concerned with the indirect measurement of compaction of mudrocks because we are concerned with in-situ values and, as we have seen, the effect of the Terzaghi principle is most pronounced. The electrical and acoustic responses follow a similar pattern: acoustic transit time decreases and resistivity increases (a topic that is treated in more detail in Chapter 7). A recent technically oriented discussion of compaction will be found in Jones et al. (1991). Compaction of mudrocks, which may contain 50% silt, is a complex process involving chemical and physico-chemical processes as well as physical ones. There is irreversible deformation of the ductile grains as well as diagenesis. Nevertheless, early studies by Hedberg (1926, 1936) in Venezuela and Athy (1930) in Oklahoma, U.S.A., revealed fairly regular compaction trends (Fig. 3-7), although they differ greatly in their numerical form. To some extent the differences are probably due to the ages of the sequences studied. The curves suggest that compaction of mudrocks (or at least loss of porosity) continues to considerable depths. It is essential to understand the nature of these and similar curves, which are commonly called compaction curves. They are, of course, a plot of present porosity (or bulk wet density) against present depth. Time and temperature are not included explicitly: depth embraces time, temperature, effective stress (a,which we have discussed above) and pore-water pressures. Temperature and pressure may, for practical purposes, be taken as linear functions of depth, but it is not at all certain that time is. We cannot interpret such curves as representing the hisfoly of compaction - that the mudrock now at a depth of 2 km followed the curve down from the time it accumulated into the stratigraphic record. Nor can we assume that a mudrock unit has a single history-of-burial curve. It is much more likely that the top and the bottom of a mudrock unit have histories like the curve, but the middle would be different because of the greater difficulty in expelling the pore water the greater distance to the permeable unit above or below. So we would not expect a smooth curve like these for a thick mudrock unit that is still compacting, but we would for a unit that has reached compaction equilibrium.

61

ABNORMAL PORE PRESSURES POROSITY f 0.5

/ - I - 0- - - -

kn

/ /

I F

ni Lu P

5

XlOOOft.

Fig. 3-7.Athy’s and Hedberg’s mudrock compaction curves.

Important as Hedberg’s studies were for the understanding of compaction of mudrocks, Athy’s curve has generally been taken as representative of mudrock compaction curves, in spite of the fact that Athy had to extrapolate to the top 1400 ft (430 m). H e found the relationship: f

= 0.48e-1.42~10-3~

where z is in metres, and the exponential factor 1.42 x inverse length [L-’1. He proposed the general form:

f = foe-az

(3-5) has the dimension of (3-6)

where fo is the fractional porosity when z = 0, which is to be interpreted as the porosity when the mudrock accumulates into the stratigraphic record. There are advantages in writing this: f = fo e-zlb

(3-6a)

where b is a scale length in the same units as z, and z/b can be regarded as a dimensionless depth. The differences between Hedberg’s and Athy’s curves are not to be explained by compromise. Almost certainly they are due to the role of time and temperature, neither of which is explicitly included in the formula. The sandhhale ratio is also probably important (Hedberg’s section was much sandier than Athy’s). Evidently there is no such thing as a simple depth-porosity formula that has general validity.

62

R.E. CHAPMAN

The local constants, f, and 6 , are not universal and their local value takes local conditions into account. In all practical applications, we need an indirect measure of in-situ porosity trends with depth that can be readily acquired from normal borehole logs. The acoustic log is well suited to this purpose. If the logarithm of the acoustic transit time (inverse velocity) in mudrock, Atshale, is plotted against linear depth, a linear trend (at least to depths of about 2 km) is usually found, suggesting a relationship of a form analogous to eq. 3-6:

where At, is the extrapolated value of the transit time when z = 0, and c is the slope of the plot In At and depth z . It must be noted at once that eq. 3-7 must be wrong. It cannot be correct because as porosity is eliminated, the transit time approaches the matrix transit time of about 180 pslm or 55 pslft. It can be shown (Chapman, 1983, pp. 41-53) that fractional porosity can be expressed in terms of acoustic transit time in mudrock or shale by:

and that a better formula for the normal compaction curve in terms of At is: Atshale = (At0 - Atmatrix) ePz” -k Atmatrix

+ = 375 eCzlb+ 180 ps/m

GZ

115 eczlb 55 p d f t

It is found that At, is usually close to 170 p d f t or 555 ps/m, but the scale length b must be determined empirically (in the same units as z). Note that the larger the value of b the smaller the curvature, so that areas like the U.S. Gulf Coast, where b is commonly about 12,000 ft (3600 m), the plot of In Atshaleversus depth is almost linear (see Fig. 7-2 on p. 190). When compaction is retarded due to the failure of the pore fluids to compress or be expelled, some of the load is taken by the pore fluid, and the state of compaction is not in equilibrium with the load, and the porosity is greater than normal for its depth. We shall return to this topic. 3.1.8. Dimensions

It is important to bear in mind that all quantities fall into one of two categories: those that are dimensionless and those that have dimensions. The numerical value of those that have dimensions, such as volume [ L 3 ] and acceleration [LT-’1, depends on the units used. Units are said to be consistent when you can use them in equations without the need for conversion factors. Pressure, for example, is a force on an area. The dimensions of force are M L - ’ T-’; but if the unit of length is feet and the unit of pressure, pounds per square inch (as is commonly the case in U.S.

ABNORMAL PORE PRESSURES

63

drilling), a conversion factor is required. These are therefore inconsistent units. The great strength of SI Units is that no conversion factors are required because all the units are consistent and invariant. Dimensions are particularly important in fluid mechanics to distinguish similar concepts, in particular the two qualities of viscosity and the two qualities of permeability. We must also distinguish between mass density [ M L - 3 ] and weight density [ M L - 2 T - 2 ] . There are two forms of viscosity, as we have seen. Absolute or dynamic viscosity has the dimensions M L-’ T-’, while kinematic viscosity is absolute viscosity divided by the mass density of the fluid, or L2T-’. Similarly with permeability. The coeficient of permeability or hydraulic conductivity, has the dimensions of a velocity, LT-I, and it includes the properties of the fluid flowing in the permeable material. The intrinsic permeability, on the other hand, has the dimensions of an area, L2, and it is a property of the rock alone and is independent of the fluid in it. When referring to qualities, we need not qualify the terms.

3.2. LIQUIDS IN MOTION THROUGH POROUS ROCKS

3.2.1. Henry Darcy’s experiments and the coeficient ofpermeability Henry Darcy, who was an engineer in charge of the water supply for the town of Dijon in France, wished to filter the water. In 1856 he published as an appendix to a larger report the results of some experiments he had conducted “to determine the laws of water flow through sands” (Darcy, 1856, pp. 590-594; reprinted in Hubbert, 1969, pp. 303-311. See also Hubbert, 1940, p. 787 et seq., Hubbert, 1956, 1957, for analyses of these experiments). For these he used a simple apparatus, shown diagrammatically in Fig. 3-8, into which he put sand supported by a thin filter. Water was passed through the system at a measured rate, and the effects were observed in two manometers. Experiments were repeated with sand of different qualities and lengths. The results are shown in Fig. 3-9. Darcy observed that “for sands of the same nature” the flow of water was proportional to the difference in elevation between the levels in the manometers (as computed for water) and inversely proportional to the length of the sand in the direction of water flow. He found that (using modern notation): Q = K(A/l)Ah

where Q is the volumetric flow rate [ L 3 T - ’ ] ,K is “a coefficient depending on the permeability of the bed” [LT-’I, A is the gross cross-sectional area normal to the flow [ L 2 ] ,1 is the length of sand traversed [ L ] ,and Ah is the difference of elevation of the water surfaces in the manometers [L]. Defining a quantity q = Q / A as the specific discharge [LT-’1, Darcy’s law (as it has come to be called) is usually written: 4 = Q/A =KAh/l

(3-10)

64

R.E. CHAPMAN

Fig. 3-8. Darcy’s apparatus, diagrammatic and simplified by having water manometers instead of mercury.

0 m3C’

Fig. 3-9. Darcy’s results.

It can be seen that this is a linear equation in which K is a material, not a true, constant because it has the dimensions of a velocity (as does the specific discharge, 4). This equation has probably been quoted erroneously more than any other, with the substitution of p for h , and it is essential for understanding to note that Darcy wrote, “Toutesles pressions ont t t t rapporttes au niveau de la face inftrieure du Jiltre” (Darcy, 1856, p. 592; my italics) - “All pressures have been referred to the lower surface of the filter”. This is what we would now call the total head, the sum of the elevation head and the pressure head above the base of the sand as datum (see Fig. 3-13). He was not measuring the difference of pressure across the sand because it

65

ABNORMAL PORE PRESSURES

is evident that there is a pressure difference across the sand even when there is no flow. Darcy’s equation, 3-10, shows that when there is no flow and q = 0, Ah = 0. This is consistent with our fundamental proposition in the Statics section above. If Darcy had used oil or another liquid in his experiments, he would no doubt have drawn the same conclusions, but the numbers would have been different. Clearly K , the coefficient of permeability, takes several factors into account, one being attributable to the sand, the others to the liquid. The liquid properties that affect fluid flow are mass density and viscosity. Gravity is a driving force. The sand itself has a property of permeability that is independent of the fluid flowing in its pore space. This is called intrinsic permeability, k , which can be shown to have the dimensions of an area, and to be related to the coefficient of permeability, K , by: (3-11)

K = kpgIr7

Again, it is evident that intrinsic permeability, with the dimensions of an area, involves more than one quantity in the sand. These include the size and shape of the pore space (as a whole), but they are probably the only quantities. The problem is to measure them. Chapman (1981, p. 52f.; 1987) has shown that intrinsic permeability can be quantified approximately with measurable parameters of a sediment or sedimentary rock. 3.2.1.1. Geornetly and hydraulic radius ofpore space

The concept of hydraulic radius is straight-forward for pipes and channels. It is the volume of water (for example) flowing in a pipe or channel divided by the total wetted surface bounding that water. If the pipe or channel is symmetrical and of constant dimensions, then it is also equal to the cross-sectionalarea of water flowing divided by its wetted perimeter. So, for round pipes: R, = rrr21/2rrrl = r/2

(3-12)

Half the radius is therefore the critical dimension for pipes. In symmetrical channels, the hydraulic radius (or hydraulic mean depth, because the first approaches the second in a wide shallow channel) is:

R, = hwl/(2hl+ wl) = hwl/l(2h

+ W)

(3-12a)

where h, w and 1 are the height, length and width of the water in the channel. When pipes and channels are not uniform in size and shape, we have to resort to measurement or estimates of the total volume of water flowing and the total areas involved. The hydraulic radius is then found to be the characteristic dimension of the conduit for liquid flow, and is therefore a concept that embraces both size and shape and it has the dimension of length. Whether the pipe is full or partly empty, whether it is a channel or a pipe, the hydraulic radius is the quantity that characterises liquid flow. It can be rationalized as the ratio of the boundary shear stress to the component of unit weight down the channel for uniform flow by gravity. By analogy, we see that a sedimentary rock (or for that matter, any porous and permeable material) has a characteristic pore dimension that is its hydraulic

66

R.E. CHAPMAN

radius. This is the total volume of pore space in which fluid can flow divided by its bounding surface area. In sedimentary rocks in general, and mudrocks in particular, the hydraulic radius is a very small number with the dimension of length. It is a number that combines the size and shape of the pore space as a whole, and it must not be regarded as representative of a single pore. There is reason to believe that the equations for pipe flow are but special cases of the more general equations for fluid flow in porous rocks (Chapman, 1981, p. 65; and in the context of turbulence, Hubbert, 1940). In other words, a single pipe with the same hydraulic radius would, under the same conditions, pass the same quantity of water in unit time. It is most important not to regard the hydraulic radius as an average pore-passage dimension: it is a measure of size and shape. The hydraulic radius is the same for 1 cm3 as for 1 m3 of homogeneous rocks of fine grains. In mudrocks, the wetted surface area of the pore space is a very large number, and the hydraulic radius is a very small number. They are difficult, but not impossible numbers to measure. There are two approaches. The internal surface area of a sample can be measured by gas adsorption techniques; or it can be estimated from photomicrographs by statistical techniques due to Corrsin (1955). Chapman (1987) suggested that the size and shape of sedimentary grains could also be represented by a characteristic dimension given by the volume of solids divided by the area bounding the solids. Such a dimension has no apparent physical meaning (it is precisely the dimension that has no fluid flow), but it makes the use of the hydraulic radius easier because if the volume of solids divided by their bounding area, a , is given by V s / a = D , and the hydraulic radius by V,/a = R , the hydraulic radius becomes: R = f Dl(1-

f)

where f is the fractional porosity, and f / ( l

-

f) is the void ratio.

3.2.1.2. Tortuosity Flow paths through the pore space are not straight, so the mean path length is greater than straight flow paths would be. Tortuosity is the ratio of true mean flow-path length through the rock to the macroscopic length of rock traversed. It is a dimensionless vector (with magnitude and direction). Anisotropy of permeability in rocks is due to tortuosity, particularly anisotropy in mudrocks. Tortuosity can be estimated from the Formation Factor, F , the ratio of the resistivity of a rock saturated with an electrolyte to the resistivity of the electrolyte:

where f is, as before, the fractional porosity (see Chapman, 1983, pp. 113-114). 3.2.1.3. Intrinsic permeability in terms of sedimentalyparameters The dimensions of intrinsic permeability are those of an area, and it is probably composed of a tortuosity component, which is dimensionless, and an hydraulic radius component, which has the dimension of length. There will also be a true

67

ABNORMAL PORE PRESSURES

coefficient that will be dimensionless. For an equation to be valid it must be dimensionally homogeneous and the constants must be dimensionless. We therefore write the expression for intrinsic permeability in terms of a constant, the tortuosity term derived above, and the square of the hydraulic radius:

k =cf T-3R2 -CT-3 f 3 D 2 /(I - fY - CF-1.5 f 1 5 D 2 / ( I - f I 2 ’

where F is the formation factor, R is the hydraulic radius with D as the characteristic dimension of the solids, and c is a true constant perhaps with the value of 0.5 (cf. Chapman, 1981, pp. 55-57,65). We cannot assert that this partition of the intrinsic permeability applies equally to very fine-grained sediments and sedimentary rocks, such as mudrocks and shales, but we have no reason to suppose that it does not. The tortuosity term is logically satisfying in that it would account for anisotropic permeability in sedimentary rocks, and the reduction of permeability with compaction. 3.2.2. The limits of Darcy’s law A lower limit for Darcy’s law has often been postulated but it has yet to be demonstrated. It has been postulated on theoretical grounds, due to liquid adsorption on solid surfaces and to comparison of molecular and pore-throat sizes. It has also been postulated on experimental grounds. Figure 3-10 shows experimental data of Nordberg (1944) and of Debye and Cleland (1959) obtained by flowing various liquids through a permeable glass called VYKOR.VYKORhas a very small intrinsic permeability, of the order of cm2 or darcies. For all practical purposes, the results show a linear relationship between the coefficient of permeability (through the specific yield, q, or volumetric

1 x

2

3

lo-’

cm / s

4

5

1

9

x10-6cm3/s

2

3

4

Q

Fig. 3-10. Experimental data of fluid flow through VYKOR,a porous glass of very small permeability, data of Nordberg (1944) and of Debye and Cleland (1959).

68

R.E. CHAPMAN

rate of flow, Q) and the hydraulic gradient, A h / l , so we can say that Darcy’s law holds for such small flows. But both results indicate the possibility of an intercept on the vertical (hydraulic gradient) axis, suggesting that a small but finite amount of energy is needed to start How, and that these liquids do not yield to the slightest shear stress. However, the results are likely due to evaporation, the evaporative losses at zero flow rates appearing as a negative flow at zero hydraulic gradient. An upper limit for Darcy’s law does exist. Fortunately, there are very few subsurface geological situations where this critical value is exceeded, the most important probably being the final stages of approach of fluid to boreholes with very high production rates. Although the upper limit is almost certainly irrelevant to the study of abnormal pressures, there are some points of general interest. When the specific discharge, q , exceeds some critical value, the relationship between it and the hydraulic gradient, Ah/f is no longer linear. There has been some discussion about the nature of this change. Is it due to the onset of turbulence or is it due to inertial forces ceasing to be insignificant? We know from Reynolds’ experiments that there is a real critical value of the Reynolds number above which pipe flow is no longer linear with respect to the hydraulic gradient, and this has led some experimenters to seek a critical Reynolds number for flow in porous media. The Reynolds number chosen has usually been q d / u , where d is the mean grain diameter and u is the kinematic viscosity, q / p . We will not waste time with this, because the grain diameter is only indirectly related to the pore dimensions, and this can hardly be a useful Reynolds number. When a valid Reynolds number is found, it will surely contain the hydraulic radius, and probably also the porosity and tortuosity. Experimental work by Lindquist (1933) and Schneebeli (1955) led to the significant result that Darcy’s law failed well before the onset of turbulence - a point emphasized by Hubbert (1940, pp. 819-822). This was the basis for his assertion that Darcy’s law is more fundamental than the pipe-flow laws. 3.2.3. Relative permeability

When the pore space is occupied by two or more fluids, the movement of each is affected by the other. We know quite a lot about these matters in reservoirs, very little about them in very fine-grained rocks of low permeability. Nevertheless, the physical principles that apply to reservoirs almost certainly apply to the fine-grained rocks. When two immiscible fluids occupy the pore space of a rock, one tends to occupy the space adjacent to the solids in preference to the other (see Fig. 3-5). That fluid is said to be the wetting fluid, the other, the non-wetting fluid. When the wetting fluid is water, the rock is said to be water-wet; when it is oil, it is said to be oil-wet. We shall consider a water-wet rock, with crude oil as the non-wetting fluid. The important aspects of this distribution of fluids is that once the irreducible water-saturation is reached, the water is not in hydraulic continuity: if it were, it would have flowed away. The flow of the two fluids is therefore a function of their saturation (Fig. 3-11) and we talk of efective permeability and relative permeability

69

ABNORMAL PORE PRESSURES Oil saturation

1

1

0

L

.*

-

.-n

PI

E

LP PI

.” m

0

a 0 Water saturation imbibition

sw

-+ + drainage

Fig. 3-1 1. Idealized relative permeabilitycurves for oi1 and water.

of a rock to oil or water. Effective permeability is a special case of intrinsic permeability, and it is symbolized k,, kg or k,. At 100% and zero water saturation, the effective permeability is equal to the intrinsic permeability, so it is convenient to express these as relative permeabilities: k, = k , / k , kr, = k , / k , and krg = k , / k . The important points to note in Fig. 3-11 are that as the water saturation approaches its irreducible level, swi, the relative permeability of oil approaches that would prevail if the rock was 100% saturated with oil (k, approaches k); and the sum of the relative permeabilities is less than one when the water saturation is larger than irreducible. We have no reason to believe that these characteristics of two-phase flow in permeable coarse-grained rocks are not shared by the relatively impermeable finegrained rocks. If so, the generation of petroleum will result in an increasing crude oil saturation and a decreasing water saturation. This will lead to a decreasing permeability to water, and zero permeability to oil until it exists in a continuous phase in a sufficiently large volume in which the energies of buoyancy and compaction are sufficient to drive it through the rock. When the water saturation becomes irreducible, water flow ceases, and the effective permeability to oil approaches the intrinsic permeability of the rock.

3.3. PORE PRESSURES

3.3.1. Normal

The pressure within a body of water at rest increases with depth, as we have seen, as a function of the weight density of the water: The qualification at msr is perhaps pedantic because subsurface waters move so slowly that the kinetic effects can usually be ignored.

70

R.E. CHAPMAN

SPECIFIC VOLUME

Fig. 3-12. Density of subsurface pore water.

where pw is the mean mass density of the water, g is the acceleration due to gravity, and z is the depth below sea-level or the land surface. This is not a rigorous equation. The use of z in this way implies that the water table coincides with the land surface, and this is usually a satisfactory approximation. It is not strictly a linear equation because pw is not strictly constant. Water tends to expand with rising temperature, but contracts with rising pressure. Of these two processes in the subsurface, thermal expansion with depth is greater than mechanical compression, and the net result is shown in Fig. 3-12 for a typical geothermal gradient. There are also changes of composition, the amount of salts in solution generally increasing with increasing depth. Water is typically drinkable to depths of a few hundred metres (exceptionally, thousands). Subsurface brines are almost always more saline than ocean water, with salinities up to 200,000 parts per million (ppm) being common This increase in total dissolved solids increases the weight density of the water. The net effect of thermal expansion, mechanical compression, and increase in salinity is that normal subsurface water pressures can usually be closely approximated by one or two straight lines, the deeper one corresponding to a weight density of 1050 kg m-3, or a specific gravity of about 1.05. The nomenclature of subsurface fluids has been in a sad state of confusion and the correct terms must now be introduced. We begin with the general term head, and the meanings are made clear in Fig. 3-13.

ABNORMAL PORE PRESSURES

71

Fig. 3-13. Total head, pressure head, and elevation head.

Head refers to a vertical dimension and so has the dimension of length [L]. There are four types of head: (1) Pressure head is the vertical elevation of the free surface of water above the point of interest or at which the pressure is measured. It is given by h, = p / p g = p / y , where y is the weight density of the water. (2) Elevation head (or simply elevation) is the elevation of the point of interest above some arbitrary datum, usually sea-level. If the point is above the datum, it is positive (+); if below, negative (-). (3) Kinetic head is the head due to energy of movement of the water. In subsurface flow through porous rocks, this is negligibly small and is always omitted. (4) Total head is the algebraic sum of the pressure head and the elevation, so: (3-13)

Hydraulic gradient is the loss of total head divided by the macroscopic length of flow within the aquifer between the two points at which the total head was measured, that is A h / l . It is a measure of the loss of energy due to flow over the distance 1. 3.3.2. Abnormally low pore pressures

Abnormally low pore-fluid pressures, or subnormal pressures, are pressures less than those expected for their depth in a body of (static) water. They are relatively uncommon, and most are probably to be attributed to a deep water-table. For example, the Molasse basin in southern Germany (Fig. 3-14) has pore water in the Jurassic formations that is relatively fresh, relatively cool, and has a pressure head that is significantly less than its depth so that the potentiometric surface is well below the land surface away from the river Danube. The pore water has normal hydrostatic gradients, with pressures that are normal hydrostatic with reference to

72 R.E. CHAPMAN

ABNORMAL PORE PRESSURES

73

the water table or potentiometric surface, but subnormal with reference to the land surface. There are also two large basins in North America with similar features (Fig. 3-15) except that both clearly show a sink through which water is being abstracted from the basins. Proximity to a great mountain range is a feature common to all three basins. 3.3.3. Abnormally high pore pressures

Abnormal pressures are, of course, pressures that are not normal hydrostatic in the sense that normal hydrostatic implies a free water surface near the surface of the ground or sea-level. It is usual to express abnormally high pressures in term of a liquid density, such as the weight density of 0.465 psi/ft (10.5 kPa/m) used in the U.S. Gulf Coast. This has some practical advantages, but large deviations from normal hydrostatic pressures are independent of density of the pore water. Another practical definition is that abnormal pressures begin when the mudweight has to be increased above the minimum. These definitions are much the same. Even if we seek to define abnormal pressures in terms of head, we must be careful not to become victims of pedantry. From the early days, as we saw in Chapter 2, it was observed that pore pressures tended, in extreme cases, to approach the pressure exerted by the total overburden, so that S = pbgz, where S is, as before, the vertical component of total stress, pb is the mean bulk wet density of the overburden, and g is the acceleration due to gravity. These pressures and their gradients are called overburden, geostafic, or lifhostatic (in that order of priority). In pressure-depth diagrams, such as Fig. 3-16, the overburden gradient is plotted as a straight line. This is an approximation because the weight density (pbg) is a function of lithology and the state of compaction, but it is sufficiently close to linear for most purposes. The overburden gradient is usually taken as 1 psi/ft (22.6 kPa/m) for convenience; however, Tertiary sequences are usually about 90% of that. Hubbert and Rubey (1959, p. 142) introduced a dimensionless parameter A. that is the ratio of pore pressure to the vertical component of overburden pressure:

A. = p / s

(3-14)

This may be understood as the proportion of the overburden supported by the pore water. Substituting eq. 3-14 into Terzaghi’s relationship 3-3, we get: CT

=s-p = (1 - h)S

(3-15)

= (1 - A.)pbgz

It is in this form that Terzaghi’s relationship usually appears in numerical studies of abnormal pressures, high and low.

74

R.E. CHAPMAN

W0

50

0

SO K I L O M E T R E S

Fig. 3-15. (a) Potentiornetric surface of Viking Sandstone (after Hill et al., 1961, fig. 2)

75

ABNORMAL PORE PRESSURES

S C A L E I

5

0

0

10

20

30

40

50 MILES

I

50 KILOYETRES

Fig. 3-15 (continued). (b) Potentiometric surface of Mesaverde Sandstone (after Hill et al., 1961, fig. 3).

76

R.E. CHAPMAN

z Fig. 3- 16. Typical form of pressure-depth distribution.

Because compaction is caused by effective stress, (T,a normally compacted mudrock is one in which the pore-water pressures are normal hydrostatic. Undercompacted mudrocks with abnormally high pore pressures are compacted to a state that would be normal at a shallower depth. Hubbert and Rubey called this the effective or equilibrium compaction depth, ze. Figure 3-17 shows this. So, under equilibrium conditions, eq. 3-15 can be written: (3-15a) This implies that the porosity of an abnormally pressured mudrock or shale at depth z will be approximately the same as a similar, but normally pressured, mudrock at depth ze. This is by no means always found to be true (Plumley, 1980), and one reason is probably that the mudrocks are not similar because an abnormally pressured mudrock belongs to a deeper-water facies than the one with which it is compared at shallower depth in a regressive sequence. There may also be diagenetic effects when the abnormally pressured mudrock is deep.

Fig. 3-17. Diagram of effective stress and equilibrium depth.

77

ABNORMAL PORE PRESSURES

The parameter h has a theoretical limitation in that it quantifies the effect of the pore water without reference to whether the mudrock is submarine or subaerial. The ambient fluid also has an effect. Chapman (1972, 1979) defined a more general parameter S that also generalized the equations used for evaluating sliding. Equating 3-15 and 3-15a, and assuming that the mean bulk wet density of the overburden above depth Ze does not differ significantly from that above z, Ze/Z = (I

- h ) / ( l - he) = 6

(3-16)

The parameter S has the value of 1 when pore-fluid pressures are normal hydrostatic, and the value of 0 when pore pressures are equal to the overburden pressures. The effective compaction depth has a real geological meaning: it is an estimate of the maximum thickness of overburden above z when compaction equilibrium was lost. We cannot measure pore pressures in mudrocks directly, so we must use indirect methods. It was shown earlier that fractional porosity can be expressed in terms of acoustic transit time in mudrock or shale (Atshale) by:

f

= fo(Atshale - Atmatrix)/(Ato - Atmatrix)

(3-17)

and that the normal compaction curve for mudrock can be written: Atshale =

(At0 - Atmatrix) e-‘lb

+ Atmatrix

(3-18)

where fo is the fractional porosity when mudrock first accumulates into the stratigraphic record (usually about O S ) , Ato is the corresponding transit time (usually 540-560 pslm, 165-170 pslft), and b is a scale length in the same units as z given by -z/In[(Atshale - Atmatrix)/(Ato- Atmatrix)]. The matrix transit time for mudrock is close to 180 ps/m, 55 pslft. The quantity z/b can be regarded as a dimensionless depth, and when b = z, Atshale = 313 pslm, 95.5 pslft. Equation 3-18 can be generalized by the substitution of 6z for z because z x ze in that equation by definition (it is the normal compaction curve): Atshale =

(At0 - Atmatrix) e-Sze’b

+ Atmatrix

(3-18a)

This is a family of curves that are asymptotic to Atmatrix. The value of Atmatrix for mudrock or shale is close to 180 ps/m or 55 pslft. The exponent 6z/b can be regarded as a dimensionless depth that takes not only pore pressure into account, but also the weight of the overburden, its temperature gradient and the mechanical nature of the solids.

3.4. POSSIBLE CAUSES OF ABNORMALLY HIGH PORE PRESSURES

It was George Dickinson’s great achievement that he demonstrated that the real control on abnormal pressures was stratigraphic, and that the relatively constant depth to top of abnormal pressures in the U.S. Gulf Coast was coincidental. To say

78

R.E. CHAPMAN

that the cause is stratigraphic is not really an answer to the question because any one of several possible causes would also result in a stratigraphic association. Dickinson (1951, 1953) recognized that abnormally high pore pressures in Louisiana always occurred below the sandy part of the sequence, below the top of the massive mudrock unit. The pressures were measured pressures, measured in permeable units that were encountered in the mudrock section, or pressures estimated from the mudweight required for control. He observed that the age of the rocks at the top of abnormal pressures was younger towards the south, in the direction of progradation of the Tertiary sequence. He attributed these pressures to “compaction of the shales under the weight of the overburden”, and noted that they occurred in sandstones that were isolated from the main sandy sequence either because they were lenticular, or because of faulting. He wrote (1953, p. 425): “The pressures in fluids within the sediments are dominated by two factors, the compression due to compaction on the one hand and the resistance to expulsion on the other; but as compaction becomes more difficult other factors may become important.” Compaction can only take place with the expulsion or compression of the pore fluids, and if the permeability of the system is so small that the fluids cannot be expelled fast enough for normal compaction, then the fluids bear some of the load and compaction is retarded. This conclusion had also been reached in the context of soil mechanics by Terzaghi (1933, 1936), and was to play an important part in the theoretical treatment of sliding. For many years, Dickinson’s explanation was accepted, and the accumulating field data seemed to support it. The term “undercompacted shale” came into common use, and “heaving shales” in such areas tended to close off open hole both while drilling and while logging, and this was detected by many caliper surveys. Nevertheless, it was clearly not the only explanation. Over the years various causes of abnormal pressures have been proposed. 3.4.1. Reservoir geometly It had long been recognized in Iran that some reservoirs were abnormally pressured by virtue of the large vertical distance between the oil/water contact and the top of the trap in a single reservoir. In a discussion at a 1937 meeting on deep drilling problems (see Journal of the Institution of Petroleum Technologists, vol. 23, pp. 371-377) D. Comins demonstrated this with figures and stated that the elevated initial pressures of the Masjid-i-Suleiman field were due to the geometry of the reservoir rock. Within an accumuIation of gas, for example, the pore-fluid pressure decreases upwards above the gadwater contact in proportion to its weight density (Fig. 3-18). However, outside the reservoir, the pore-fluid pressure decreases upwards in proportion to the weight density of water. The abnormality of pressure is therefore a function of the difference in densities and the elevation above the water contact (Az): AP =

water

-

Ppetro1eum)gAZ

ABNORMAL PORE PRESSURES

79

Fig. 3-18. A thick accumulation of petroleum can give rise to reservoir pressures much larger than those in the water above.

These pressures are also applied to the connate water, and this is the process by which water is expelled downwards from the reservoir as the petroleum accumulates. Once the irreducible water saturation is reached, no further water expulsion takes place, and the water pressure increases with that of the adjacent petroleum. These are not strictly abnormal pressures, because they are the result of pressure gradients that are normal for their fluids, but they must be treated as such. An important part of their danger when drilling comes from the sudden onset of higher pressures without any transition zone that would act as a warning. 3.4.2. Petroleum genesis Petroleum genesis can affect pore pressures in two ways: by increasing the net fluid volume, and by reducing the relative permeabilities to water and to petroleum. Both processes are likely to occur together. Illing (1938, p. 227) pointed out that petroleum genesis must involve an enlargement of the volume of organic matter, and there are now some published examples that seem to support this hypothesis. Particularly clear was the case presented by Meissner (1978) for the Lower Mississippian Bakken Shale of the Williston basin in North America. He found abnormal pressures (not very severe, but nevertheless abnormal) over certain depth intervals in certain areas, and ascribed them to petroleum generation in a relatively well-compacted source rock. Similarly, the Jurassic Kimmeridge Clay in the North Sea of N.W. Europe is widely and severely over-pressured, and is regarded by many as the source rock of much of the crude oil in the region. In the upper half of thick, abnormally pressured mudrocks, upward flow of pore water through the transition zone to lower pressures may lead to exsolution of petroleum. Drilling of the Gesa anticline in the Mamberamo delta of Irian Jaya, Indonesia, encountered serious problems at shallow depth with abnormal pressures

80

R.E. CHAPMAN

(Visser and Hermes, 1962, p. 228). No petroleum was found in the sandstones, but methane and carbon dioxide were found in the mudrocks. Gas is sometimes (but not always) encountered when drilling into the transition zone. Chapman (1972) concluded that such exsolution could enhance abnormal pressures by reducing the effective permeability of the mudrock to water. Hedberg (1974, 1980) went further and suggested that the generation of methane and other hydrocarbons of low molecular weight could also be an important source of energy for primary migration, mudrock diapirs, and mud volcanoes. Spencer gives an interesting example in Chapter 12. 3.4.3. Cluy-mineral diagenesis

The diagenesis of smectite (montmorillonite) to illite involves release of interlayer water. Powers (1967) suggested that the release of this water could aid primary migration, and the hypothesis grew from that suggestion that this process could give rise to abnormally high pore pressures. There is ample evidence that the process is real and is largely temperaturedependent (see, for example: Burst, 1969; Perry and Hower, 1970; Weaver and Beck, 1971), but little that it contributes to abnormal pressures (Magara, 1975, 1978, pp. 100-109). It has not yet been demonstrated that lattice-water density is sufficiently different from free-water density. If it is to contribute to abnormal pressures, lattice water must be at least 50% denser than free water, so that there is an increase in water volume and a decrease in bulk density when this diagenesis occurs. The rate of diagenesis is also important because it must generate a volume of water faster than it can be dissipated. Burst (1969) concluded that this diagenesis has not taken place in the U.S. Gulf Coast between depths of 800 m (2500 ft) and 2500 m (8250 ft), much as Perry and Hower (1970, p. 171) were to find. Rather greater depths were found by Weaver and Beck (1971, p. 18). But there are many large areas with abnormal pressures in that zone, both in the U.S. and elsewhere. Tops of abnormal pressures between two and three kilometres depth are common, so some coincidence of such tops with the onset of smectite diagenesis is to be expected. 3.4.4. Osmosis

When a semi-permeable membrane separates two liquids of different salinities, the less saline liquid moves through the membrane into the more saline liquid until the chemical potentials of the two are equal. This tendency to equalize chemical potentials across membranes can lead to pressure differentials across the membrane and, in theory, to very large differentials. However, there is little evidence that this is an important process in the generation of abnormally high pore pressures, and some that the osmotic gradient in abnormally pressured mudrocks opposes the generation of abnormal pressures by assisting in the expulsion of pore water (Magara, 1978, pp. 283-284). Water expelled early from a compacting mudrock is more saline than that expelled later (McKelvey and Milne, 1962; von Engelhardt and Gaida, 1963;

ABNORMAL PORE PRESSURES

81

Chapter 5 of this volume), and there is field evidence that the salinity of mudrock pore water is less than that of the adjacent sandstone when the latter are normally pressured (Schmidt, 1973). When abnormally pressured, the salinity of sandstone pore water tends to be less than that of normally pressured sandstones, and more comparable with that of the abnormally pressured mudrock. So the osmotic gradient is either very small, or assisting the expulsion of the mudrock pore water. However, osmosis seems a likely cause of abnormally low pressures, such as those in the Viking Sandstone in Alberta, Canada, the Mesaverde Sandstone in Colorado and New Mexico, U.S.A., and in the Molasse basin in southern Germany. These formation waters are unusually fresh. The pressure regimes in the first two have been studied by Hill et al. (1961), and their maps (Fig. 3-15) show that there is a hydraulic sink in the basins through which water is evidently being abstracted from the main aquifer of the basins. The Molasse basin has been well studied by Lemcke (1976) and his map (Fig. 3-14) shows a possible sink east of Munich. In all three basins, the potentiometric surface is largely below ground level. The low salinity of the water suggests a possible osmotic cause for the shape of the potentiometric surface. 3.4.5. Tectonics Uplift has long been suggested as a cause of abnormal pressures. A normal pressure regime, if elevated and preserved, would be abnormal at the shallower depths. As always, there may be areas where that has happened, but the unambiguous evidence of areas with abnormal pressures below a regressive sandy sequence is that they were generated during subsidence and the accumulation of sediment in a stress field with a component of horizontal tension. Tectonic compression (in the sense of horizontal deforming stresses) cannot be a generuf cause because the Niger and Mackenzie deltas are, along with the U.S. Gulf Coast and many other areas, tectonically passive. The unambiguous evidence of growth faults in such areas is that there has been prolonged extension and subsidence during the development of the normal growth faults in a stress field in which the greatest principal compressive stress, 01, is vertical, a2 is horizontal and parallel to the depositional strike, and a3 is horizontal and normal to the depositional strike. 3.4.6. 2quathermal”

The thermal hypothesis, which Barker (1972), although not the first, advocated most effectively, postulates an “isolation depth” at which mudrocks become virtually impermeable to water. Further burial increases the temperature of the pore water and the water’s tendency to expand, resisted by the overburden, results in elevated pressures. This hypothesis enjoyed considerable popular support, but it has some serious weaknesses. Figure 3-19 shows the PVT (pressure-volume-temperature) diagram for pure water (we have no reason to believe that the diagram would be significantly different for the variable quality of subsurface waters). If the volume of pore space remains constant, the pressure rises rapidly as a function of temperature

82

R.E. CHAPMAN

Fig. 3-19. Pressure, volume, temperature relationships for pure water.

(but not necessarily rapidly as a function of time), and the limit would appear to be the pressure required to support the overburden. The thermal hypothesis is amenable to some numerical assessment because the data are reasonably well known. Chapman (1981) calculated the permeability required for dissipation of the volume of water created by thermal expansion during burial at the maximum rate known in the U.S. Gulf Coast (500 years/ m, 150 years/ft) down the maximum geothermal gradient known there (36"C/km, 2"F/100 ft). A mudrock 500 m (1640 ft) thick, with 20% porosity, would require a coefficient of permeability or hydraulic conductivity of about m/s, or an cm2, 5 x mD) to intrinsic permeability of about 5 x lop9 pm2 (50 x dissipate the extra volume due to thermal expansion. This is near the lower limit of measured Tertiary mudrock permeabilities reported by Magara (1971, fig. 9) from Japan. Even under these extreme conditions, only very small permeabilities are required to nullify this process. A similar argument was used later by Daines (1982). However, it follows that there may be conditions in other contexts where the permeability is not great enough (probably at greater depth) and that the importance of thermal effects may increase with burial.

83

ABNORMAL PORE PRESSURES

Fig. 3-20. Schematic profile of pore pressure with depth, including a pressure reversion.

Another important weakness is that whereas a case can perhaps be made for the upper transition zone’s being caused by thermal expansion of the pore fluids, any reversal of that trend must have another cause (Fig. 3-20). The upper transition zone may be close to the shape expected for thermal expansion of the pore water, but a reduction in abnormality in the same mudrock can hardly have a thermal cause. The normally pressured gas sand in the Taglu field in the Mackenzie delta between abnormally pressured mudrocks (Chapter 2, p. 34) is likely to have been sourced from one or other or both of the mudrocks. It seems impossible to reconcile a return to normal hydrostatic pressures in mudrocks with a thermal origin of the abnormal pressures. Another problem is that the aquathermal theory implies a late origin of abnormal pressure, whereas there is much evidence for an early origin, as we shall see.

*** The question is not “Which of these is right?” but “Which of these is the dominant process and under what circumstances?”. The evidence is persuasive that the dominant cause is mechanical, but that the thermal effects may become more important with depth and time. This is a good example of a theoretical problem of great practical importance. If the thermal school is right, abnormal pressures form late and migration of fluids from them is minimal once they form. If the mechanical school is right, they form early and there is a steady (if slow) flow of pore fluids from them. These differences lead to another line of evidence on the causes: growth structures. If growth structures are caused by abnormally pressured mudrocks, then the abnormal pressures must be an early feature. Geological support for the mechanical hypothesis is found in the association between growth structures and abnormal pressures. Dickinson’s (1953, pp. 416-417) map of the age of the rocks containing

84

R.E. CHAPMAN

the top of abnormal pressures in Louisiana and Thorsen’s (1963) map of the age of maximum rate of growth-fault movement in Louisiana show that faulting occurs soon after the accumulation of the mudrock in which the top of abnormal pressures occurs (within a few biostratigraphical subzones). Growth faulting involves fault movement while the sediment is accumulating, and it seems an inescapable conclusion that abnormal pressures existed by the time the growth faults moved. Growth anticlines also are strong evidence of early generation of abnormal pressures because the cause is almost certainly diapiric, and diapirism requires a degree of undercompaction in the mudrocks. Thorsen (1963) noted that the maximum rate of anticlinal growth was approximately contemporaneous with that of local growth faults. It is important to understand abnormal pressures, their causes and their effects, because the evidence is strong that they give rise to structures in regressive sequences that contain important quantities of petroleum, and that they constrain the paths of petroleum migration. Their importance in “pure” geology is no less because the evidence is strong that some regional structural styles are caused by the stratigraphy and the abnormal pressures generated. One effect of contemporaneous deformation of sedimentary sequences during accumulation must be to imprint its pattern on all future deformation.

3.5. SLIDING

Pore pressures are important in the mechanics of sliding, and for the mechanical strength of rocks. Terzaghi’s principle, that the vertical component of total stress is divided between the pore-fluid pressure and the effective stress, S = cr - p , was examined earlier. Terzaghi himself used it early in his study of landsliding (Terzaghi, 1943,1950), which formed the basis for subsequent work on sliding in the geological context. Before proceeding further, it is essential to appreciate that sliding is not the same as flowing. Sliding involves movement of a block on a single surface, such as a brick on a plank, but flowing involves the progressive displacement through a body of rock that is behaving as a lubricant or a fluid (Figs. 3-21 and 3-22). Both are influenced by pore pressures, but in different ways. We shall consider sliding first. 3.5.1. Unlubricated sliding

Figure 3-21 shows the main components of unlubricated sliding. It is sometimes forgotten that the weight of the block is affected by the ambient fluid - the fluid in which the sliding block is immersed - so that both the normal and the shear components contain the term (pb - pa), where pa is the mass density of the ambient fluid, and pb is the mass bulk density of the sliding block. So its weight per unit area of the base:

ABNORMAL PORE PRESSURES

85

Fig. 3-21. The components of unlubricated sliding.

can be resolved into a component normal to the sliding surface: a, = (pb - pa)gh cos8

and a shear component: T = (pb - pa) gh sin8

The Coulomb criterion for simple unlubricated sliding is: It1 = to +a,

tan+

(3-19)

where It1 is the shear stress parallel to the sliding surface, to is the shear strength parallel to the sliding surface when the normal stress, a,, is zero; and tan4 is the coefficient of sliding friction. There has been some debate on the significance and size of to (Hubbert and Rubey, 1959; Birch, 1961; Raleigh and Griggs, 1963; Hsii, 1969) but for generality it should be retained even if there are conditions in which it is negligibly small. It is important to understand that the Coulomb criterion so expressed is a function of pore pressure (through a), but the coefficient of &ding fiction is unaltered. The angle of sliding friction, 4, is defined (in practical terms) as the angle at which a dry block just slides subaerially; but the angle is the same for a water-saturated block sliding under water. Provided the ambient fluid is the same as the pore fluid, the angle of sliding friction is the same. It is not the same for a water-saturated block sliding subaerially. Pore pressures in such a subaerial block are abnormal with reference to the ambient fluid, and the ambient fluid is important in this regard. The sliding of a water-saturated block subaerially down a slope to the sea is a more “efficient” process than the submarine sliding when it reaches the sea because a smaller slope is needed for subaerial sliding. The sliding block, on reaching the sea, encounters an obstruction that will tend to stop the sliding. That obstruction is due to the reduction of the driving force by the force of buoyancy. The weight of the block is reduced by the weight of the volume of water displaced, but the resisting forces remain the same.

86

R.E. CHAPMAN

Sliding occurs when the shear component of stress down the slope is equal to the Mohr-Coulomb criterion, and it can be shown (see Chapman, 1979, p. 23, and 1981, p. 175) that this is when: T = t = to + a n t a n 4 ,

or

a z s i n 8 = t o + S a z c o s tan@, ~

and

(3-20)

+6 tan4 pa) gh cos 8 + S tan 4

tan8 = (to/azcos8) = to/(&

-

The parameter S = (1 - A)/(1 - A,) is quite general, and has different values for subaerial and submarine conditions. When the cohesive strength term is negligibly small and to -+0, eq. 3-20 shows that sliding can take place on an angle of slope very much smaller than the angle of sliding friction provided the value of 6 is less than one. And when the value of S is very small, as in the case when pore pressures approach the total overburden pressures, sliding can take place on very small angles of slope (typically 3" to 5"). Table 3-1 shows the value of the critical angle of unlubricated gravitational sliding for identical water-saturated subaerial (A) and submarine (6) blocks assuming a value of to = 3 x lo6 N m-2 (30 bar). Note how this angle in the submarine environment is nearly double that for a water-saturated block sliding subaerially. It will also be noted that the thickness makes little difference if the block is 1 km thick, or so. Because abnormal pressures reduce the effective stress, it seems certain that the cohesive strength also decreases with abnormality, and that sliding can indeed take place on very small slopes.

TABLE 3-1

Critical angle of unlubricated gravitational sliding for identical water-saturated subaerial (A) and submarine ( 6 ) blocks of thickness shown ~~

T, = 3 x

lo6 N m-2

A.

6

r,, = 0

1 km

2km

3km

4km

5km

24"

20"

1 8"

18"

16"

1.0

43

36

33

33

30

21

17

0.8

38

31

19" 34 16 29

18

14

12

12

11

10

0.6

33

26

24

23

22

19

15

11

9

9

8

7

0.4

27

20

18

17

16

13

11

7

6

5

5

3

0.2

21

14

11

10

4

3

2

0.0

8 15"

7"

5"

4"

9 2 3"

7 0 0"

~~

0.5

0.6 0.7 0.8 0.9 1.O

15

15

13

28

21

25

87

ABNORMAL PORE PRESSURES

The essence of this sliding is that there is a surface in which the cohesive strength is insufficient, and the material fails. It is implicit in the mechanism that some sort of permeability barrier is required for this surface to be nearly horizontal, and to prevent the dissipation of the excess pore pressures. Chapman (1979, p. 27) discussed some examples of sliding in nature, and concluded that this mechanism could well account for turbidites. But he concluded also that the mechanism is likely to be less common in nature than a viscous flow due to the abnormally pressured mudrock’s behaving as a lubricant.

3.5.2. Lubricated sliding Smoluchowski (1909), in an early but penetrating discussion of sliding, wrote: “Suppose a layer of plastic material, say pitch, interposed between the block and the underlying bed; o r suppose the bed to be composed of such material: then the law of viscous liquid friction will come into play, instead of the friction of solids; therefore any force, however small, will succeed in moving the block. Its velocity may be small, but in geology we have plenty of time; there is no hurry.”

This is the process we shall now examine. We must consider extensive sheets because that is their nature and because a small block will displace the lubricant with a radial component. We shall follow Kehle (1970) and treat this as laminar flow of the lubricant down a slope (Fig. 3-22). If we consider relatively thin sheets with very large viscosities and small angles of slope, we can probably regard this as obeying Newton’s law sufficiently closely: t = 9 dV/dh

(3-21)

where 9 is the dynamic viscosity with dimensions A4L-lT-l. These are the dimensions of stress x time, and we see the interdependence of stress and time in geological strain. For rocks, the term equivalent viscosity is applied for very small strain rates. We assume in the geological context that sliding will begin when: T =t=(pt,-pa)g(H-h)sin8

9

Fig. 3-22. Idealized velocity profile in a flowing sheet or bed that is acting as a lubricant.

(3-22)

88

R.E. CHAPMAN

where H is the total thickness of material flowing, and H - h is the thickness contributing to the shear stress at the level of interest. This shear stress is greatest at the rigid basal surface where the velocity is zero, and least at the top of the “fluid” where the veIocity is greatest. Equating 3-21 and 3-22, and integrating with respect to h , noting that V = 0 when h = 0, we obtain:

v = [ ( P b - Pa)/7?l g [ H h - (h2/2)1 sine

(3-23)

We must remind ourselves that it is very unlikely that nature will follow this expression precisely, but it gives an indication of the likely velocities under different circumstances. We may be confident that the density of the ambient fluid is important, and that the velocity of the subaerial “flow” will be greater, other things being equal, than the velocity of submarine “flow”. Abnormality of pressure does not appear explicitly in eq. 3-23: it is included in the viscosity term, q, probably in terms of the dimensionless quantity 6 [ = (1 - A ) / ( l - A,)]. Empirical experience with mud-volcanoes and “heaving shales” in boreholes supports the contention that abnormal pressures reduce the effective stress and the effective viscosity of rocks.

ACKNOWLEDGEMENTS

I am very grateful to the late Walter Fertl for criticism and discussion of this chapter, to Professor R.D. Collerson and his department at the University of Queensland for assistance with the reproduction of the figures, and to Mrs. Irene Lenneberg for drawing them.

REFERENCES Athy, L.F., 1930. Density, porosity, and compaction of sedimentary rocks. Bull., Am. Assoc. Pet. Geol., 14: 1-24. Barker, C., 1972. Aquathermal pressuring-role of temperature in development of abnormal-pressure zones. Bull., Am. Assoc. Pet. Geol., 56: 2068-2071. Barker, C. and Horsfield, B., 1982. Mechanical versus thermal cause of abnormally high pore pressure in shales: discussion [of Chapman, 19801. Bull., Am. Assoc. Pet. GeoL, 66: 99-100. Berget, O.P., Dretvik, 0.,Tonstad, K. and Mathiesen, E., 1989. Production of oil and gas from chalk reservoirs in the Norwegian part of the North Sea. In: J.B. Burland (Editor), Chalk: Proceedings of the 1989 International Chalk Symposium, Brighton, September 4-7, 1989, 315-320. Birch, F., 1961. Role of fluid pressure in mechanics of overthrust faulting: discussion [of Hubbert and Rubey, 19591. Bull. Geol. SOC.Am., 72: 1441-1444. Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull., Am. Assoc. Pet. Geol., 53: 73-93. Chapman, R.E., 1972. Primary migration of petroleum from clay source rocks. Bull., Am. Assoc. Pet. Geol., 56: 2185-2191. Chapman, R.E., 1979. Mechanics of unlubricated sliding. Bull. Geol. SOC.Am., 90: 19-28. Chapman, R.E., 1980. Mechanical versus thermal cause of abnormally high pore pressures in shales. Bull., Am. Assoc. Pet. Geol., 64: 2179-2183. Chapman, R.E., 1981. Geology and Water: An Introduction to Fluid Mechanics for Geologists. Nijhoffl Junk, T h e Hague, 228 pp.

ABNORMAL PORE PRESSURES

89

Chapman, R.E., 1982. Mechanical versus thermal causes of abnormally high pore pressures: reply [to Barker and Horsfield]. BulL, Am. Assoc. Pet. Geol., 6 6 101-102. Chapman, R.E., 1983. Petroleum Geology. Elsevier, Amsterdam, 415 pp. Chapman, R.E., 1987. Fluid flow in sedimentary basins: a geologist’s perspective. In: J.C. Goff and B.P.J. Williams (Editors), Fluid Flow in Sedimentary Basins and Aquifers. Geol. SOC.London, Spec. Publ., 3 4 3-18. Corrsin, S., 1955. A measure of the area of a homogeneous random surface in space. Q. Appl. Math., 1 2 404-408. Daines, S.R., 1982. Aquathermal pressuring and geopressure evaluation. BulL, Am. Assoc. Pet. Geol., 6 6 931-939. Darcy, H., 1856. Les fontainespubliqyes de la ville de Dijon. Victor Dalmont, Paris, 674 pp. Debye, P. and Cleland, R.L., 1959. Flow of liquid hyrdrocarbons in porous VYCOR. J. Appl. Phys., 30: 843-849. Dickey, RA., 1975. Possible primary migration of oil from source rock in oil phase. Bull., Am. Assoc. Pet. GeoL, 59: 337-345. Dickinson, G., 1951. Geological aspects of abnormal reservoir pressures in the Gulf Coast region of Louisiana, U.S.A. Proceedings, 3rd World Petroleum Congress, The Hague, Sect. 1: 1-16. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana. Bull., Am. Assoc. Pet. Geol., 37: 410-432. Gabrysch, R.K., 1967. Development of ground water in the Houston District, Rxas, 1961-65. T a . Water Dev. Board, Rep., 63, 35 pp. Gretener, P. and Feng, Zeng-Mo, 1985. Three decades of geopressures - insights and enigmas. Bull. Vex Schweu. Pet. Geol. I g . , 51 (120): 1-34. Hedberg, H.D., 1926. The effect of gravitation compaction on the structure of sedimentary rocks. Bull., Am. Assoc. Pet. Geol., 10: 1035-1072. Hedberg, H.D., 1936. Gravitational compaction of clays and shales. Am. J. Sci., 31: 241-287. Hedberg, H.D., 1974. Relation of methane generation to undercompacted shales, shale diapirs, and mud volcanoes. Bull., Am. Assoc. Pet. GeoL, 58: 661-673. Hedberg, H.D., 1980. Methane generation and petroleum migration. In: W.H. Roberts and R.J. Cordell (Editors), Problems of Petroleum Migration. Am. Assoc. Pet. Geol., Stud. Geol., 10: 179-206. Hill, G.A., Colburn, W.A. and Knight, J.W., 1961. Reducing oil-finding costs by use of hydrodynamic evaluations. In: Economics of Petroleum Exploration, Development, and Property Evaluation. PrenticeHall, Englewood Cliffs, N.J., pp. 38-69. Hsii, K.J., 1969. Role of cohesive strength in the mechanics of overthrust faulting and of landsliding. Bull. Geol. SOC.Am., 80: 927-952. Hubbert, M.K., 1940. The theory of ground-water motion. J. Geol., 48: 785-944. Hubbert, M.K., 1956. Darcy’s law and the field equations of the flow of underground fluids. Trans., Am. Inst. Min., Metall. Pet. Eng., 207: 222-239. Hubbert, M.K., 1957. Darcy’s law and the field equations of the flow of underground fluids. Bull. Assoc. Int. HydroL Sci., 5: 24-59. Hubbert, M.K., 1969. The Theory of Ground-Water Motion and Related Papers. Hafner, New York, N.Y., 311 pp. 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 application to overthrust faulting. Bull. GeoL SOC. Am., 70: 115-166. Illing, V.C., 1938. The origin of pressure in oil pools. In: A.E. Dunstan (Editor), The Science of Petroleum, Vol. 1. Oxford University Press, London, pp. 224-229. Jones, M.E., Leddra, M.J., Goldsmith, AS. and Yassir, N., 1991. Mechanisms of compaction and flow in porous sedimentary rocks. In: J. Cosgrove and M. Jones (Editors), Neotectonics and Resources. Belhaven Press, London, pp. 16-42. Kehle, R.O., 1970. Analysis of gravity sliding and orogenic translation. Bull. Geol. SOC.Am., 81: 1641- 1664. Kennedy, G.C. and Holser, W.T., 1966. Pressure-volume-temperature and phase relations of water and carbon dioxide. In: S.R Clark (Editor), Handbook of Physical Constants (revised ed.). Geol. SOC.

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Am., Mem., 97: 371-384. Kugler, H.G., 1933. Contribution to the knowledge of sedimentary volcanism in ’Itinidad. J. Inst. Pet. Technol., 19: 743-760. Discussion: pp. 760-772. Lerncke, K., 1976. Uber Grundwisser im suddeutschen Alpenvorland. Bull., Vex Schweiz. Pet. Geol. Ing., 42(103): 9-18. Lindquist, E., 1933. On the flow of water through porous soil. ler Congr2s des Grands Barrages, Stockholm, 1933,5: 81-101. Magara, K., 1971. Permeability considerations in generation of abnormal pressures. J. SOC.Pet. Eng., 11: 236-242. Magara, K., 1975. Reevaluation of montmorillonite dehydration as cause of abnormal pressure and hydrocarbon migration. Bull., Am. Assoc. Pet. Geol., 59: 292-302. Magara, K., 1978. Compaction and Fluid Migration: Practical Petroleum Geology. Elsevier, Amsterdam, 319 pp. Mayuga, M.N., 1970. Geology and development of California’s giant - Wilmington oil field. In: M.7: Halbouty (Editor), Geology of Giant Petroleum Fields. Am. Assoc. Pet. Geol., Mem., 14: 158-184. McKelvey, J.G. and Milne, I.H., 1962. Flow of salt solutions through compacted clay. Clays and Clay Minerals: Proceedings, 9th National Conference, pp. 248-259. Meissner, F.F., 1978. Petroleum geology of the Bakken Formation, Williston basin, North Dakota and Montana. In: The Economic Geology of the Williston Basin; Montana, North Dakota, South Dakota, Saskatchewan, Manitoba. Montana Geological Society, Billings, Mont., pp. 207-227. Nordberg, M.E., 1944. Properties of some Vycor-brand glasses. J. Am. Ceram. SOC.,27: 299-305. Palciauskas, VV. and Domenico, PA., 1980. Microfracture development in compacting sediments: relation to hydrocarbon-maturation kinetics. Bull., Am. Assoc. Pet. Geol., 6 4 927-937. 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. Bull., Am. Assoc. Pet. Geol., 64: 414-422. Potts, D.M., Jones, M.E. and Berget, O X , 1988. Subsidence above the Ekofisk oil reservoirs. Proceedings of the International Conference on Behaviour of Offshore Structures, Pondheim, June 1988, pp. 113128. Powers, M.C., 1967. Fluid-release mechanisms in compaction marine mudrocks and their importance in oil exploration. Bull.,Am. Assoc. Pet. Geol., 51: 1240-1254. Raleigh, C.B. and Griggs, D.T., 1963. Effect of the toe in mechanics of overthrust faulting. Butt. Geol. SOC.Am., 74: 819-830. Schmidt, G.W., 1973. Interstitial water composition and geochemistry of deep Gulf Coast shales and sandstones. Bull., Am. Assoc. Pet. Geol., 57: 321-337. Schneebeli, G., 1955. Exptriences sur la limite de validiti de la loi de Darcy et I’apparition de la turbulence dans un tcoulement de filtration. Houille Blanche, 10 (2): 141-149. Smoluchowski, M.S., 1909. Some remarks on the mechanics of overthrusting. Geol. Mag., N.S., Decade V, 6: 204-205. Terzaghi, K., 1933. Auftrieb und Kapillardruck an betonierten Talsperren. ler Con@s des Grands Barrages, Stockholm, 1933,5: 5-15. Terzaghi, K., 1936. Simple tests determine hydrostatic uplift. Eng. News Rec., 116 (June 18): 872-875. Terzaghi, K., 1943. Theoretical Soil Mechanics. Chapman and Hall, London; John Wiley and Sons, New York, N.Y., 510 pp. Terzaghi, K., 1950. Mechanisms of landslides. In: S. Paige (Chairman), Application of Geology to Engineering Practice (Berkey Volume).Geological Society of America, Boulder, Colo., pp. 83-124. Thorsen, C.E., 1963. Age of growth faulting in southeast Louisiana. Tram. Gulf Coast Assoc. Geol. SOC., 13: 103-110. Van den Bark, E. and Thomas, O.D., 1980. Ekofisk: first of the giant oil fields in western Europe. In: M.T. Halbouty (Editor), Giant Oil and Gas Field of the Decade 1968-78. Am. Assoc. Pet. Geol., Mem., 30: 195-224. Van den Bark, E. and Thomas, O.D., 1981. Ekofisk: first of the giant oil fields in western Europe. Bull., Am. Assoc. Pet. Geol., 65: 2341-2363.

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Visser, W.A. and Hermes, J.J., 1962. Geological results of the exploration for oil in Netherlands New Guinea. Veda. K. Ned. GeoL Mijnbouwkd. Genoof. Ned Kol., GeoL SeK, 20: 1-265. Von Engelhardt, W. and Gaida, K.H., 1963. Concentration changes of pore solutions during the compaction of clay sediments. J. Sediment. PefroL, 33: 919-930. Weaver, C.E. and Beck, K.C., 1971. Clay water diagenesis during burial: how mud becomes gneiss. Geol. SOC.Am., Spec. Pap., 134,96 pp.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38

edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 8 1994 Elsevier Science B.V. All rights reserved

93

Chapter 4

RESERVOIR ENGINEERING CONCEPTS IN ABNORMAL FORMATION ENVIRONMENTS WILLIAM J. BERNARD

4.1. INTRODUCTION

Reservoir engineering is a specialized field of petroleum engineering. A reservoir engineer is charged primarily with estimating remaining reserves, predicting future reservoir performance and optimizing ultimate recovery. The fundamental principles of reservoir engineering are well understood and are available from several excellent references (Craft and Hawkins, 1959; Dake, 1978). The principles are valid for both normally pressured and abnormally pressured reservoirs, although most reservoir engineering references are primarily oriented toward normally pressured reservoirs. Reservoir simulation is becoming more accessible to the engineer. This is particularly true since the advent of powerful, low-cost computers. Reservoir simulators allow a much more detailed analysis of reservoirs than is possible with conventional calculation techniques. A description of reservoir simulation is beyond the scope of this book and the reader is referred to Crichlow (1977), Peaceman (1977) and Aziz and Settari (1979). Although simulation is an important facet of reservoir engineering, the vast majority of reservoir studies are still done without the aid of computer simulation. One of the tools of the reservoir engineer is material balance, which states that the mass of oil and gas in a reservoir at any time is equal to the original mass minus the mass that has been produced. Implicit in the material balance are the various sources of reservoir energy that drive the oil and gas to the well. For a natural gas reservoir, for example, we often consider the only sources of reservoir energy to be the compressibility of the gas and the influx of water from an aquifer. Other sources of reservoir energy are present such as the compressibility of the pore volume of the rock, compressibility of the connate water, and invasion of water from the confining layers of shale and interbedded layers of shale. For normally pressured gas reservoirs, the energy from the compressibility of the gas itself and/or the influx from large aquifers is comparatively large so that the other energy sources can be neglected without appreciable error. Since gas compressibility decreases with increasing pressure, the energy derived from the gas compressibility may no longer dwarf these other energy sources for highly pressured reservoirs. Neglecting rock and water compressibilities, influx from shales and influx from small aquifers may lead to serious errors in such reservoirs.

94

W.J. BERNARD

4.2. P / Z PLOTS AND DRIVE MECHANISM

Natural gas reservoirs are normally divided into two major categories according to their drive mechanisms. A depletion drive, or volumetric, reservoir is one in which the gas-containing volume does not change as pressure depletes. A water drive reservoir is one in which water invades the reservoir from an associated aquifer. For a volumetric reservoir, it can be shown (Dake, 1978, p. 25) that the material balance may be written as:

where P = average reservoir pressure; Z = gas compressibility factor at P; Gp = cumulative gas produced; G = initial gas in place; i = initial reservoir conditions. Equation 4-1 assumes that the effects of rock and water compressibility and water influx are negligible. Usually eq. 4-1 is solved graphically. If successive data points of P / Z and Gp are plotted, the result is a straight line, as shown in Fig. 4-1. An extrapolation of this plot to zero P / Z yields the initial volume of gas in the reservoir. An extrapolation of this plot to a value of P / Z corresponding to the anticipated abandonment pressure yields the ultimate recovery from the reservoir. Totally volumetric reservoirs do not exist in nature. As reservoir pressure declines, the laws of physics dictate that the rock matrix and connate water must expand and also that water must flow out of the confining-layer shales, interbedded shales and the adjacent aquifer. Therefore a P / Z plot can never be perfectly linear. CUMULATIVE GAS PRODUCED, lo6 rn3 5000

4000

.0

3000

0

-20

In 0

1

II)

0

N \

a

a

2000

-

N \

- I0

1000

a

p I

OO

I

2

I

I

I

\

4 I

X

E

A I

4 6 8 CUMULATIVE GAS PRODUCED, Bcf

C

E I

' 0

Fig. 4-1. Typical P / Z versus cumulative production for a normally pressured volumetric gas reservoir. Initial gas-in-place and ultimate recovery are indicated.

95

RESERVOIR ENGINEERING CONCEPTS CUMULATIVE GAS PRODUCED, 10

5

1

- 50 -40 0

-4000 -

a

-

2000

1000 -

C U M U L A T I V E GAS PRODUCED, B c f

Fig. 4-2. P / Z versus cumulative production for an abnormally pressured gas reservoir (initial gradient of 0.843 psi/foot, 19.1 kPa/m). It shows severe deviation of plot from a straight line. (After Bernard, 1987.)

CUMULATIVE 0

100

8000

0

5000

G A S PRODUCED, 1 0 % ~ 200 300 I

I

-

YI Q *

4000 -

N

2

30002000 -

1000 l

o 00 o

0

o 2L

2

1

4I 4

I

6I 6

I

8I 8

I

I0 I I0

\

CUMULATIVE GAS PRODUCED, Bcf

Fig. 4-3. P / Z versus cumulative production for an abnormally pressured gas reservoir (initial gradient of 0.676 psi/foot, 15.3 kPa/m). It shows minor deviation of plot from a straight line. (After Bernard, 1987.)

As a practical matter, if the effects of rock and water compressibility and the effects of water influx are negligible in comparison to the compressibility of the gas, it is acceptable to consider the reservoir as being volumetric and to use straight-line extrapolations of P / Z plots. When the reservoir pressures are great, as in abnormally pressured reservoirs, straight-line extrapolations of P / Z plots can yield erroneous results. P / Z plots for two abnormally pressured U.S. Gulf Coast reservoirs are shown in Figs. 4-2 and 4-3. The two reservoirs had initial pressure gradients of 0.843 and 0.676 psi/foot (19.1 and 15.3 kPa/m). These two reservoirs perform differently because of the relative effects of rock and water compressibility and water influx compared to

96

W.J. BERNARD

the compressibility of the gas. Since the reservoir in Fig. 4-3 exhibited a nearly straight-line behavior, it must have derived virtually all of its energy from the compressibility of the gas. This reservoir was negligibly affected by other energy sources. The reservoir in Fig. 4-2, as evidenced by its non-linear P / Z behavior, clearly was influenced by energy sources other than just gas compressibility. Observations from numerous P / Z plots confirm that it is very common for the early-life P / Z plot to be nearly linear, regardless of drive mechanism and regardless as to whether or not abnormally pressured. One must be cautious about extrapolating this early-life straight-line behavior. For example, extrapolation of the early-life P / Z for the reservoir in Fig. 4-2 would have resulted in serious over-estimation of reserves. Even though there are no purely volumetric reservoirs in nature, convention defines a volumetric reservoir (i.e. depletion drive) as one in which water influx is negligible when compared to the other reservoir energy sources. This definition applies to both normally pressured and abnormally pressured reservoirs. A water-drive reservoir can be defined as one in which there is enough water influx to be significant in terms of a reservoir material balance. The water comes from adjoining aquifers and from shales. If the adjoining aquifer is fairly large, the aquifer influx will far exceed any influx from the shales and the effects of shale-water influx can be neglected. It is important to establish the drive mechanism of a reservoir as early in its life as possible. The most common method of determining drive mechanism for a gas reservoir is to plot P / Z versus cumulative gas production, as shown in Figs. 4-1, 4-2, and 4-3. If the reservoir is depletion-driven and normally pressured, the plot will remain linear throughout the life of the reservoir (Fig. 4-1). If the reservoir is water-driven and normally pressured, the plot can take on a spectrum of shapes, depending upon the properties of the aquifer and the corresponding volume of influx. Figure 4-4 is one of several such P / Z plots presented by Bruns et al. (1965). Notice that all of the curves show an early-life straight line portion. It is important to not rely solely on the shape of the P / Z curve when determining drive mechanism during the early life of the reservoir. For highly pressured reservoirs, the P / Z plot generally will not remain linear, even for depletion drive, because the effects of compressibility and influx can no longer be neglected. Equation 4-1 is not valid in this situation and other methods of analysis are required.

4.3. ABNORMALLY PRESSURED DEPLETION DRIVE RESERVOIRS

As discussed earlier, it is physically impossible for a reservoir to be completely volumetric. The reservoir gas volume must change as pressure decreases because of rock compressibility, water compressibility and influx of water from shales and associated aquifers. These effects, while they can be safely ignored for normally pressured reservoirs, must be taken into account when dealing with highly pressured gas reservoirs.

97

RESERVOIR ENGINEERING CONCEPTS CUMULATIVE G A S PRODUCED, 5

0 5000

10

30 4000 0

a

0 3000

20 mx

u)

P

0

N

2 2000

N \

10

looo

t

01 0

a

\

\ \

\,Ornd I

I

I

I

100

200

300

400

‘

.

I

0

500

CUMULATIVE GAS PRODUCED, Bcf

Fig. 4-4. P / Z versus cumulative production for a hypothetical water drive gas reservoir. It shows the effect of aquifer permeability on the shape of the plot. The early life P / Z plot is linear for all cases. (After Bruns et al., 1965.)

Shale-water influx, while minor when compared to the conventional influx from aquifers, can be an important contribution to the overall reservoir energy of an abnormally pressured reservoir. Wallace (1969) studied the performance of several abnormally pressured reservoirs in south Louisiana and concluded that water from shales had encroached into “volumetric” reservoirs and affected their performance. Bourgoyne et al. (1972) also concluded that shale-water influx is a possible mechanism for pressure support in abnormally pressured gas reservoirs. They also concluded that permeability and compressibility are the most important shale properties. Bass (1972) suggested that peripheral water influx from small aquifers is a likely source of energy support. Harville and Hawkins (1969) reported on a study of the NS2B gas reservoir in the North Ossun field located in south Louisiana. They concluded that rock compressibility could be used to explain the performance of this abnormally pressured (gradient of 0.725 psi/foot) (16.4 kPa/m) reservoir assuming that the reservoir was volumetric. Calculations showed that the reservoir performance could be matched if kPa-’) was used until an initial rock compressibility of 28 x psi-’ (4.1 x the reservoir reached a pressure equivalent to a normal 0.465 psilfoot (10.5 kPalm) psi-’ (0.87 x gradient, at which time the compressibility changed to 6 x kPa-’). The change of rock compressibility from an unusually high value to a more normal value when the reservoir reached hydrostatic gradient gave rise to the term “rock collapse” as a possible description for this behavior. The authors cautioned that the results of their study did not prove that rock collapse is the major source of pressure support but rather suggested the possibility. Bernard (1987) reported that since the publication of the Handle and Hawkins (1969) study, additional performance data from the NSZB reservoir showed that the

98

W.J. BERNARD

reservoir was not volumetric but rather was being driven by a fairly active water influx, having produced over 5.6 million barrels (890 x lo3 m3) of water with all wells eventually watering out. Bernard concluded that the non-linear P / Z from the NS2B reservoir was explainable in part by the water influx and that the high rock compressibility and rock-collapse ideas of Harville and Hawkins (1969), while perfectly logical at the time of their study, were not necessary to explain reservoir performance. The Harville and Hawkins analysis was significant in that it focused attention on the importance of rock and water compressibility. There are two general possibilities for the analysis of volumetric, abnormally pressured gas reservoirs. First, if the reservoir energy sources are known and independently quantifiable, eq. 4-1 can be modified to take these into account. Second, if the reservoir energy sources are not independently quantifiable, the past performance history of the reservoir can be matched, thus allowing the engineer to “back in” to these parameters such that future performance predictions are possible. 4.3.1. Pedormance prediction

if the energy sources are independently quantifiable

If the rock and water compressibilities of the reservoir are known, and if the influx of water from shales or an aquifer is negligible, there are several methods for analyzing reservoir performance. Water compressibility can be obtained with good accuracy from a correlation such as of Dodson and Standing (1944). Rock compressibility is best determined by laboratory measurement but can be approximated with varying degrees of accuracy from correlations of Hall (1953) and Newman (1973). Hammerlindl (1971) developed a method to account for the effects of rock and water compressibilities. His method is based upon the simplification that the P / Z plot for an abnormally pressured depletion drive reservoir is composed of two distinct straight lines of different slope that intersect at hydrostatic pressure. The early straight line is influenced by high formation compressibility and water compressibility. The second straight line is less influenced by rock and water compressibility because the rock compaction is essentially complete when the reservoir reaches a pressure equivalent to the normal pressure gradient. Hammerlindl suggests extrapolating the early straight line to obtain an “apparent” initial gas-in-place. The actual initial gas-in-place is obtained by the following equation: Actual G = Apparent

G/(CeR/cg)

(4-2)

where ( c ~ R / c ~= )[(ceff/cg)i ~ ~ ~ + (ce~/cg)h]+ 2; G = initial gas in place, standard volume units; c e ~= (cgSg+ cwSw+ cf)/Sg, reciprocal pressure units; Sg = gas saturation, fraction; S, = water saturation, fraction; cg = gas compressibility, reciprocal pressure units; c, = water compressibility, reciprocal pressure units; cf = rock compressibility, reciprocal pressure units; i = initial conditions of pressure; h = pressure of hydrostatic gradient (i.e. 0.465 psi/ft, 10.5 kPa/m) Hammerlindl’s method is very simple to use but requires knowledge of the rock and water compressibilities and the water saturation. Hammerlindl presented a

RESERVOIR ENGINEERING CONCEPTS

99

correlation to allow determination of rock compressibility, but the correlation is based on a very small statistical sample and yields values which appear to be high when compared to laboratory data. Prasad and Rogers (1987) report that analysis of 21 abnormally pressured reservoirs indicates that only rarely is the P / Z plot composed of two straight lines that intersect at the hydrostatic pressure gradient. Nevertheless, Hammerlindl’s method is used by many engineers. The method is simple and yields results that can be good engineering approximations in some instances. Dake (1978) and Ramagost and Farshad (1981) presented a material balance equation for a depletion drive gas reservoir that took into account the effects of rock and water compressibilities.This equation is:

A comparison of eq. 4-3 with eq. 4-1 shows that the two equations differ by the term:

Ramagost and Farshad (1981) refer to this term as the “ P / Z adjustment factor”. A plot of

L[l-

z

(CWSW

+ Cf)(Pi- P ) I-&

1

versus the cumulative gas production, G,, should yield a straight line if there is no influx of water. Extrapolation of this straight line to a value of zero for P / Z yields the initial gas-in-place. An example of this method is shown in Fig. 4-5. Begland and Whitehead (1986) presented a method that accounts for the changing value of rock compressibility with decline in reservoir pressure. Their method also accounts for the change in water compressibility with pressure decline due to dissolved natural gas. This approach also ignores water influx and requires a computer solution. 4.3.2. Performance prediction using past reservoirperformance

Early in the life of a reservoir, when the P / Z plot still resembles a straight line, there is no way to confidently infer information such as compressibility, influx and initial gas-in-place from reservoir performance. If, on the other hand, the reservoir pressure-production history is sufficiently long and accurate that the P / Z plot has developed a distinct non-linear behavior, the magnitude of the reservoir energy sources can be inferred simultaneouslywith an estimate of initial gas-in-place. Bernard (1987) suggested that the effects of rock and water compressibility, shale-water influx and influx from small aquifers could be lumped together and described by eq. 4-4:

100

W.J. BERNARD C U M U L A T I V E GAS PRODUCED. 1 0 9 ~ 3 800C

a I

-- a-

5000

u’

4000

+ 3-

2

-

3000

0

GAS-IN-PLACE

0

Fig. 4-5. “Adjusted” P / Z versus cumulative production for an abnormally pressured offshore Louisiana gas reservoir (initial gradient of 0.860 psi/foot, 19.5 kPa/m). (After Ramagost and Farshad, 1981.)

P -[l-C(Pi-P)]=

z

(‘)i[

1--

I‘

(4-4)

where C is a catch-all term with units of reciprocal pressure to approximately account for rock and water compressibilities, influx from a small, steady-state aquifer and steady-state influx from shale. If only rock and water compressibilities supply the supplementary reservoir energy, the value of C in eq. 4-4would be equal to (cwSw cf)/(l - Sw). Equation 4-4would then be equivalent to eq. 4-3.If the supplementary energy is due entirely to influx from a small, steady-state-acting aquifer, the value of C in eq. 4-4would be a function of the water volume of the aquifer and the average compressibility of the aquifer. If the supplemental energy is due entirely to influx of water from shales, the value of C would be a function of the shale permeability, cross-sectional area of shale open to the flow of water, and other variables. Actually, the equations describing the influx of water from shale are too complex to be precisely described by eq. 4-4. The value of C in eq. 4-4is virtually impossible to find independently of reservoir performance. The rock compressibility, the size of aquifer and the properties of shale are seldom known. It appears virtually hopeless to attempt to sort out the contribution of each of these energy courses. For this reason all of the energy sources are lumped together into C . A study of thirteen supposedly “volumetric” abnormally pressured reservoirs in the U.S. Gulf Coast area revealed, if typical rock and water compressibilities existed in the reservoirs and if shale-water influx was negligible, that on the average an

+

RESERVOIR ENGINEERING CONCEPTS

101

aquifer of only 1.4 times the size of the gas accumulation was sufficient to account for the observed non-linear P/Z behavior. Since most Gulf Coast reservoirs are relatively small and have few wells drilled into them, it is likely that such small aquifers would not be detected geologically. The volume of water encroaching from these small aquifers would be enough to affect the P/Z curve but would often be insufficient to reach the wells. It follows that the absence of water production does not, in itself, disprove water influx. For a further discussion of these studies see Bernard (1987). In eq. 4-4 there are two unknowns, C and G. Roach (1981) demonstrated that it is possible to re-arrange an equation similar to eq. 4-4 such that C and G can be determined directly. The rearranged equation takes on the form: 1 G where:

a=-B-

C

(4-5)

The quantities that make up a! and B are known. A plot of a versus B should result in a straight line. The slope of this line is the reciprocal of G, the initial gas-in-place. The negative of the a intercept is C. The data shown in Table 4-1 were obtained from an offshore gas reservoir in the Gulf of Mexico. The reservoir depth was 13,500 feet (4115 m) and the initial pressure gradient was 0.675 psi/foot (15.3 kPa/m). The P/Z and production data have been combined to yield the values of a and B. The plot of a versus is shown in Fig. 4-6. It is common for the early-life points to fall off the straight line because of the sensitivity to measurement error for these small pressure changes. The latelife points should be the most accurate and should be given more weight. For this set of data it was decided to fit the straight line through the last 4 data points. This straight line had a slope of 0.0438 which when inverted yielded an estimate of 22.8 Bcf (billion standard cubic feet) (646 x lo6 m3) as the initial gas-in-place. The a intercept was -0.000070, which is equivalent to a C of 70 x psi-' (10.2 x kPa-'). Once these values of C and G have been found, the data can be re-plotted as (P/Z)[l - C(Pi - P)] versus G,, as shown in Fig. 4-7. If the abandonment conditions of P / Z are known, the ultimate recovery from this reservoir can be found from this plot or by substituting into eq. 4-4 to get G , at abandonment. This method has been used on numerous abnormally pressured reservoirs. Experience has revealed that good data yield good results. The method is not reliable if the data are poor or if the reservoir life is too young. During the early life of the reservoir, the P/Z plot will almost always appear to be linear. Extrapolation of this behavior will generally result in over-prediction of ultimate gas recovery, as has been previously discussed. Bernard (1987) developed

TABLE 4-1

Parameters from an offshore gas reservoir in the Gulf of Mexico Z

P (psia)

(kPa)

9116 8545 7485 6301 5633 5148

62853 58916 51608 43444 38838 35494

1.327 1.283 1.203 1.113 1.073 1.052

PlZ

GP

B

ff

(psia)

(kPa)

(Bcf)

(m3)

6870 6660 6222 5661 5250 4894

47365 45920 42899 39033 36196 33740

0.000 1.734 4.255 7.620 9.489 11.019

0.0 49.1 x 120.5 x 215.9 x 268.8 x 312.2 x

(psia:’) lo6 lo6 lo6 lo6 lo6

5.508 x 6.382 x 7.582 x 8.859 x 1.018 x

lo-’ lo-’ lo-’ lo-’

(kPa-’ )

(Bcf/psia)

(m3/kPa)

7.989 x 9.256 x 10W6 10.997 x 12.849 x 14.765 x lop6

0.003132 0.002880 0.003285 0.003565 0.003898

12.86 x 11.83 x 13.49 x 14.64 x 16.01 x

lo3 lo3 lo3 lo3 lo3

103

RESERVOIR ENGINEERING CONCEPTS BETA, 106m3/ kPo 0 000010

-

000008

-

000006

-

0 005

0010

I

I

0 015

-

15

- 10

-

0

a

0

x

-5

a 000002 r J

a

-O SLOPE = 0 0438 INITIAL GAS-IN-PLACE=SLOPE-’= 22 8 8cf ( 6 w X1 0 6 ~ 3 )

-

0

0 a

0-

-000004

‘p

0001

0 002

0 003

2-I a

- -5

0 004

B E T A , Bcf /psi0

Fig. 4-6. Plot of eq. 4-5 for an abnormally pressured offshore Louisiana reservoir. Data are taken from lkble 4-1.

a correlation that relates the actual gas-in-place to the apparent gas-in-place (i.e. the gas-in-place obtained by extrapolating the early-life straight line P / Z plot). The correlation is based on 13 U.S. Gulf Coast “volumetric” reservoirs and is shown in Fig. 4-8. The author admits that the correlation is based on a very limited statistical base. Bernard suggested during the early life of a reservoir, while the P / Z plot is still linear, that the correlation be used to estimate the initial gas-in-place. Once the non-linear behavior of the P / Z plot becomes evident, the method described by eq. 4-4 should be utilized.

4.4. ABNORMALLY PRESSURED WATER DRIVE RESERVOIRS

If the reservoir is influenced by the influx of water from a large aquifer, the energy supplied by the water will generally mask the effects of rock and water compressibilities and shale-water influx. Therefore it is reasonable to ignore these energy sources and consider the reservoir to be driven by only aquifer influx and gas compressibility. Standard techniques such as those suggested by van Everdingen and Hurst (1949) can be used to model the unsteady-state influx. The reader is referred to Craft and Hawkins (1959) and Dake (1978) for a discussion of water influx into normally pressured reservoirs. The same principles will apply to abnormally pressured reservoirs.

104

W.J. BERNARD

CUMULATIVE G A S PRODUCED, 106m3 7000

100

200

300

400

500

600

700

I

I

I

I

1

I

I

6000

z 5000

T a 4000 I

-

a

I

3000

V

I

2000

QIN I000 I

0

1

0

1

4

,

I

8

I

I

12

I

I

16

t

1

20

24

Fig. 4-7. Plot of adjusted P / Z versus cumulative production. C of 7.0 x lo-' psis-] (10.2 x kPa-') and initial gas-in-place of 22.8 Bcf (646 x lo6 m') were found from plot shown in Fig. 4-6.

APPARENT G A S - I N - P L A C E , Bcf

Fig. 4-8. Correlation to estimate actual gas-in-place from apparent gas-in-place during the early life of a reservoir. Correlation is based on south Louisiana and offshore Louisiana reservoirs. (After Bernard, 1987.)

RESERVOIR ENGINEERING CONCEPTS

105

REFERENCES Aziz, K. and Settari, A., 1979. Petroleum Reservoir Simulation. Elsevier Applied Science Publishers, Essex. Bass, D.M., 1972. Analysis of abnormally pressured gas reservoirs with partial water influx. SPE 3850, 3rd Symp. Abnormal Subsurface Pore Pressure, Louisiana State University, Baton Rouge, La., May. Begland, T.F. and Whitehead, W.R., 1986. Depletion performance of volumetric high-pressured gas reservoirs. SPE 15523, 61st Annual Technical Conference and Exhibition of the SPE, New Orleans, La., October. Bernard, W.J., 1987. Reserves estimation and performance prediction for geopressured gas reservoirs. J. Pet. Sci. Eng., 1:15-21. Bourgoyne, A.T., Hawkins, M.F., Lavaquial, EP.and Wickenhauser, TL., 1972. Shale water as a pressure support mechanism in superpressured reservoirs. SPE 3851, 3rd Symp. Abnormal Subsurface Pore Pressure, Baton Rouge, La., May. Bruns, J.R., Fetkovich, M.J. and Meitzen, V.C., 1965. The effect OF water influx on p/z-cumulative gas production curves. J. Pet. TechnoL, 17: 287-291. Craft, B.C. and Hawkins, M.F., 1959.Applied Petroleum Reservoir Engineering. Prentice-Hall, Englewood Cliffs, N.J., 437 pp. Crichlow, H.B., 1977. Modem Reservoir Engineering - A Simulation Approach. Prentice-Hall, Englewood Cliffs, N.J. Dake, L.P., 1978. Fundamentals of Reservoir Engineering. Elsevier, Amsterdam, 443 pp. Dodson, C.R. and Standing, M.B., 1944. Pressure-volume-temperature and solubility relations for natural gas-water mixtures. Drilling and Production Practices, API, pp. 173-179. Hall, H.N., 1953. Compressibility of reservoir rocks. Trans. AIME, 98: 309-311. Hammerlindl, D.J., 1971. Predicting as reserves in abnormally pressured reservoirs. SPE 3479, 46th AIME Fall Meeting, New Orleans, La., October. Harville, D.W. and Hawkins, M.F., 1969. Rock compressibility and failure as reservoir mechanisms in geopressured gas reservoirs. J. Pet. Technol., 21: 1528-1530. Newman, G.H., 1973. Pore-volume compressibility for consolidated, friable, and unconsolidated reservoir rocks under hydrostatic loading. J. Pet. TechnoL, 255: 129-134. Peaceman, D.W., 1977. Fundamentals of Numerical Reservoir Simulation. Elsevier, Amsterdam. Prasad, R.K. and Rogers, L.A., 1987. Superpressured gas reservoirs: case studies and a generalized tank model. SPE 16861, 62nd Annual Technical Conference and Exhibition of the SPE, Dallas, Texas, September. Ramagost, B.F and Farshad, EE, 1981. PiZ abnormally pressured gas reservoirs. SPE lU125, 56th Annual Fall Technical Conference and Exhibition of the SPE, San Antonio, Texas, October. Roach, R.H., 1981. Analyzing geopressured reservoirs - a material balance technique. SPE 9968, Unsolicited, December. van Everdingen, A.F. and Hurst, W., 1949. The application of the Laplace transformation to flow problems in reservoirs. Trans. AIME, 186: 305. Wallace, W.E., 1969. Water production from abnormally pressured gas reservoirs in South Louisiana. J. Pet. Technol., 21: 969-983.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38

edited by W.H. Fertl, R.E.Chapman and R.E Hotz 0 1994 Elsevier Science B.V. All rights reserved

107

Chapter 5

CHEMISTRY OF PORE WATER G.V. CHILINGARIAN, H.H. RIEKE and A. KAZI

5.1. INTRODUCIION

The composition of pore waters in abnormally high-pressured zones in sedimentary basins often differs from the composition of the pore waters in associated normally pressured zones. This is especially true for subsiding immature Tertiary or younger sedimentary basins with high sedimentation rates and thick shale components. The overburden pressures on sediments in these basins may reach magnitudes as high as 45,000 psi (about 300 MPa). This is a strong driving force for the migration of excess pore waters during gravitational compaction when large amounts of water are squeezed out of argillaceous sediments and are expelled into the associated permeable beds. Since the mid-1950's there has been a steady progress toward an understanding on how subsurface pore fluids have evolved under gravitational compaction conditions. The theories explaining the cause of these high-pressure zones have been discussed in the previous chapters and among others by Chilingarian and Rieke (1976). Hobson (1954) discussed the concept of open and closed fluid pressure systems in explaining the origin of abnormal formation pressures. 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. The present-day understanding on how these pore waters originate, what affects their chemical compositions, and how they migrate are presented and discussed in this chapter. The primary emphasis will be on the expulsion chemistry of pore water by gravitational compaction. Ancillary processes are briefly discussed if they have an effect on the modification of the pore-water chemistry during compaction. Main thrust of this 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 the available laboratory-simulated compaction data with field information. 5.1.1. Fundamentalproblem: sea water versus 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 pore 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.

108

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZI

Washburne (1914) stated that the pore water contained in sediments is not just buried sea water. Subsequent studies have shown that pore waters in marine Tertiary sediments are essentially remnants of sea water 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 age from the Cambrian to the Tertiary, and reported that the 6 l 8 0 values of the highly saline oilfield brines do not deviate appreciably from the 6 l 8 0 of modern sea water. Later studies have shown that in all but the most slowly deposited sediments pore water exhibits changes in its composition during burial (Sayles and Manheim, 1975). 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 5-1 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 during the early 1970’s showed that biogenic sediments and pelagic clays undergoing a rate of deposition < 1 cm/1000 years were the only sediments that exhibited low 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 as shown by the chemical composition of the pore water extracted from the Red Sea marl. Another way of looking at pore-water chemistry changes is presented in Fig. 5-1. 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 alterations of pore waters were shown by Hanor (1987a), using data from Graf et al. (1966), for the Paleozoic Illinois Basin (U.S.A.). The term used to denote these changes is “pore fluid diagenesis”. Sayles and Manheim (1975) pointed out TABLE 5-1 Chemical composition of sea water, bottom water, and average concentrations of pore water squeezedout from ocean sediments expressed in g/kg (data for normal sea water from Goldberg et al., 1971; all

other data modified after Manheim, 1976) Ions

Sea water normal

Ocean sediments Red Sea

~

Na+ K+ Ca2+ Mg2+ CISO:HCO;

10.5 0.4 0.4 1.3 19.1 2.7 0.17

11.8 0.43 0.46 1.42 21.4 3.06 0.15

terrigenous clay ( > 3 cm/lo yr)

pelagic clay hemipelagic (<’ cm/lo yr) bottom burial depth water

223-243 m

10.8 0.38 0.41 1.26 19.2 2.7

11.1 0.52 0.41 1.18 19.5 2.7 -

Red Sea 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

-

28.7 0.22 0.98 0.84 46.1 3.57 0.15

0

I

4

0

0

0

0

I

E

I

I

8

CHEMISTRY OF PORE WATER

00

81

0

I

n

1 1

I I

0

0 *)

I I

I

0

0

R

109

Fig. 5-1. Changes in concentration of pore waters with depth (based on data obtained from Collins, 1975, table VIII.8). A lumped-parameteranalysis having a 10-point moving average of 110 data points from 10 formations in 8 sedimentaly basins in U.S.A.

110

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZl

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. The mechanisms involved in their formation are probably as poorly understood as the diagenesis of their pore fluids. Contradictions in the geochemical pore-water data from various basins can be explained by the basin’s classification and its degree of geological maturity. Here the term Tertiary basin is used to describe those geologically young depositional sites where present-day deposition is still taking place. These basins can be described as being immature and forming along the continental margins, versus those mature basins which are geologically older and exist now directly on the craton. Sediments in the latter basins have been, for the most part, lithified and indurated into rocks. Some of the processes affecting pore-water chemical composition in “mature” basins consist of dilution by fresh-water recharge, possible concentration by membrane filtration, late diagenetic mineral transformation reactions, and dissolution of evaporites (Rittenhouse, 1967; Hitchon et al., 1971; Hanor, 1987a: Aharon et al., 1992). Locally the influx of mantle volatiles have further caused post-depositional changes to the pore-water chemistry (Oxburgh et al., 1986). The presence of a meteoric component is often indicated by the pore waters having salinities less than that of sea water. As an example, the pore waters in the Illinois Basin have been modified by fresh-water influx (Nesbitt, 1985). Table 5-2 lists many of the mechanisms that have been proposed to account for the origin of subsurface pore waters. 5.1.2. Constraints: reliability of sampling and water analyses

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 was that the permeability of shales is so low that the exposed shale intervals in oil wells rarely produce pore waters in measurable quantities. Another reason is that such studies always had a low priority until the late 1960’s when abnormally high fluid pressures were intensely investigated by the petroleum industry. The water produced from oil and gas wells is probably not representative of the interstitial fluid because of contamination, dilution by condensed water vapor, questionable sampling, preservation, and laboratory analytical procedures. Drilling fluids can cause dilution of and/or introduction of dissolved materials into the pore waters. Water produced with the oil can represent a mixture from different production horizons if it is comingled production or as a result of leaky casings. The majority of oil and gas wells have been cemented behind the casing. Filtrate from the cement slurry may penetrate the permeable sandy zones and contaminate the pore water. Hydraulic fracturing fluids are notorious for contaminating reservoir waters. In some cases it takes more than three months for the fracturing fluids to be produced back after fracture treatment. These are just some of the problems encountered by investigators looking at pore-water chemistry. With respect to unconsolidated sediment samples, the

111

CHEMlSTRY OF PORE WATER TABLE 5-2

An overview of proposed mechanisms to account for the origin of chemical differences in subsurface pore waters 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 beds. Burial diagensis of sea water. Chemical osmosis. 'Rapped remnants of sea water moved by sediment compaction. Ion exchange capacity of clays under compaction.

Sayles and Manheim (1975) Carpenter (1978) Stoessell and Moore (1983) Hanor (1987b)

Membrane filtration by clays. Alteration of smectite to illite during deep burial. Electrical potentials (electrodiagenesis). Molecular settling. 'Rapped 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 sea water. Thermohaline overturn of pore water.

handling of the samples can be critical in obtaining accurate analytical results. Problems include changes in temperature and pressure, contamination by bottom water and sea water as the cores are retrieved. Further changes can take place due to evaporation, oxidation, and the type of equipment and supplies used in extracting and storing the sample, and the magnitude of the pressure at which the pore water is squeezed out of the sample. Mangelsdorf et al. (1969) first demonstrated that temperature changes alter ion exchange equilibria and bring about changes in pore-water chemistry. Bischoff et al. (1970) confirmed these effects. Sayles and Manheim (1975) state that temperature is the most single significant factor affecting the composition of pore waters. With respect to laboratory-simulated compaction studies, problems arise from measuring sample pressure accurately, analytical techniques involving minute amounts of squeezed-out pore waters, specimen preparation, and contamination in collecting the pore water.

5.2. COMPOSlTlON OF SUBSURFACE BRINES

Pore waters can be classified as (1) syngenetic (formed at the same time as the enclosing rocks), and (2) epigenetic (owing their origin to subsequent infiltration of

112

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZI

meteoric and other waters into already formed rocks). The main processes which alter the chemistry of buried waters are those related to physical (gravitational compaction), chemical (reactions involving minerals, organic matter and interstitial solutions), physicochemical (filtration through charged-net clay membranes, adsorption and base exchange), electrochemical, and biochemical changes. 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 attributed 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 concentration of pore-water fluids during the process of compaction, as reported by different investigators, and presented in this section are related to field and laboratory data obtained from various sources. 5.2.1. 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 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 sea water. The distribution of the salinity of pore waters present in the young geosynclinal sediments along the U.S. Gulf Coast has been 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 sea water characterize the pore waters in Miocene/ Pliocene sediments, where the relative quantity of undercompacted shale is small. In Eocene/Oligocene 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 sea water. Figure 5-2 illustrates their concept that the formation waters in downdip, interfingering, marine sandstone members, have lower salinities than that of sea water. These sandstones have proportionately less volume than the associated massive shales. More massive sands updip have salinities greater than that of sea water, 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 pprn 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 Gulf Coast of Texas indicated that the salinity of water in the geopressured zone ranged from 20,000 to 70,000 mg/l total dissolved solids. Water samples from many gas wells, on the other hand, yield much lower salinities. Kharaka et al. (1977) believed that these samples are not representative

CHEMISTRY OF PORE WATER

113

Fig. 5-2. A typical idealized cross-section of some sands and shales in southwest Louisiana showing generalized salinity relationships. (Modified after Timm and Maricelli, 1953, pp. 396, 397 and 408; from Rieke and Chilingarian, 1974, fig. 146, p. 271.)

of the true formation waters’ salinity due to the dilution of the condensed water produced with the natural gas. This study further showed that the salinity in the geopressured zone is generally, but not always, lower than 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 well-compacted shales. A definite correlation between the high salinity of pore waters of shales and abnormally high pressures was found to exist. This is possibly owing 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 at different times ranging from 1 to 48 months. They found that there was no definite trend of ion concentration 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. For example, Chave (1960, table I, p. 359) reported that the percentage difference in the concentration of a given ion could vary from less than 1% to as much as

114

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI

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 natural chemical differences of waters in a given local stratigraphic zone or the samples were contaminated. It is our opinion that any chemical analyses of pore waters should be verified by charge balance criteria. The total number of cations and anions expressed in milliequivalents per liter have to approximate each other within 5 to 10%. In order to run this check, the analysis must include the major cations and anions present in the sample. Morton and Land (1987) 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/l of total dissolved solids. The high values are believed to be derived from dissolution of diapiric salt. Low salinities are attributed to pore-water dilution by water released from the transformation of smectite to illite, and by mineral dehydration reactions. The increase of pore-water salinity with depth in relationship to diapiric salt structures in the Gulf Coast was first suggested by Manheim and Bischoff (1969). Pore waters were analyzed from six holes drilled offshore in the Gulf of Mexico. Pore-water samples from the drill holes near diapiric structures showed systematic increases in salinity with depth. The salinity showed little change with depth in those holes 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 transfer of subsurface pore water in the Gulf Coast owing to existence of density inversions was discussed by Hanor (1987b). The resulting convective overturn of pore fluids is caused partly by the dissolution of salt diapirs resulting in the formation of dense, saline brines at shallow depths. If salt dissolution is confined to the base of a sedimentary sequence, however, there may be no density inversion and thus no fluid overturn (Hanor, 198%). The concept of 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. Capuano (1990) simply stated that compaction-driven flow dominates in the abnormally high fluid pressured sediments, whereas gravity-driven or thermaldensity-driven flow dominates in normally pressured sediments. 5.2.1.1. Field case studies

The importance of knowing that the pore-water concentrations are lower in shales than in sandstones was pointed out by Chilingar et al. (1969). Erroneous interpretation in log analysis may result if calculations assume that the salinity of pore waters in sandstone and associated shales are the same. In order to determine the water saturation, S,, in well log analyses, it is necessary to know R, (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. The best method, which has been practiced for many years, is the analysis of a sample of formation water collected from a permeable zone in the well. Once the water salinity is determined in an area, R, is calculated for any subsurface zone

115

CHEMISTRY OF PORE WATER

gg40m -3600.

3800 -

9960

I I

Shale

I

1 'OP2qO

Sand 1Sha:e

20.

, 30

Chlorinity.pPm x10'

1

1

I

*?,

I\....

'.:.Sh a1e

-. L

I

-*-i'

4

4000-

4

n

-

.!

-0

ppm r a n g e ~n sand

u

a

.:..,

:

4200-

1

44001

40

30

,

,

,

50

70

90

1

0

Chlorinity.ppm x 1 0'

Fig. 5-3. Chloride concentrations in shales and sands. (After Fertl and Timko, 1970, fig. 4, p. 15, based on data by Hedberg, 1967.)

by making only a temperature correction ( A r p s , 1953). Another approach to find R, in a sandstone involves the use of the log-derived values of adjacent shales. The pore-water salinities in shales and in associated sandstones are compared in Fig. 5-3. The case studies are from the Middle East and Texas. Some data from offshore wells in Louisiana have been given by Fertl and Timko (1970). In all cases, the salinities of pore waters in shales are considerably lower than those in associated sandstones. An important field case study was performed by Schmidt (1973). He analyzed the pore waters of both shales and sandstones from the Gulf Coast region in the State of Louisiana. He determined, among others, the concentration of various cations and anions together with base-exchange capacity, type of exchangeable cations, and mineral composition of clays. Salinity 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. The sandstone salinity determinations were confirmed by 56 water sample analyses of major cations and anions from normally pressured producing zones in the Hackberry Field and from the highly pressured zone in the Manchester Field. Furthermore, 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. 5-4. The data show changes in concentration of pore water with depth in 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 (4000 m). The data from the normally pressured Hackberry Field extend from near surface down to a depth of 12,500 ft (3800 m). The data from shale sidewall cores were taken at intervals of every 500 ft (152 m) between depths

116

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZI

Concentration, m g / l x 10,000 0

4

8

12

16

20

24

26

0

0

000

!OW

1000

Ll

1000

,000

5000

$000

2000

E

roo0

=: c

c

c

c

a

3ooo

0)

0

g

0

1000

3000

0000

11000

I 2 000

3000 4 000

14000

Fig. 5-4. 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/l and are not shown. This figure is based on data from Schmidt’s (1975) tables 1 and 2, pp. 332-337.

CHEMISTRY OF PORE WATER

117

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 the various ions in the high pressured Manchester Field. Figure 5-4 illustrates that there is a significant difference between the total dissolved solids concentrations in waters from the normally pressured sandstones (600 mg/l to 225,000 mg/l) in the Hackberry Field and the highly pressured sandstones (16,000-49,000 mg/l) in the Manchester Field. Changes in the concentrations of chloride and sodium follow the same trend as that of the total dissolved solids (Cl- > Na+). The concentrations of the HCO;, SO:-, Ca2+, Mg2+, and K+ in sandstones are so small as compared to the concentration of other major constituents at the scale used in Fig. 5-4, that values less than 10,000 mg/l 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 high-pressure zone. It can be seen that in shale pore water, the concentration order is generally SO:- ? Na+ ? HCO, 2 C1-, whereas water in normally pressured sandstones has an opposite concentration order (Fig. 5-4). The concentrations of the Ca2+, Mg2+, 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 the first to point out the difference in salinity between the shale and the associated sandstone. Osmaston (1975) in his discussion on Schmidt’s (1973) field study, pointed out that there are some discrepancies in the porosity or density values. The fundamental expression showing the relationship between fractional porosity, 4, bulk dry weight density, Pd, and grain weight density, pg (which was assumed to be a constant: 2.65 g/cm3) is: Pd = Pg(1 - 4)

(5-1) 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 (1979, 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 in pore water with depth. It may be pointed out 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 also remove the soluble minerals held as solid matter in the matrix of the original sample. In addition, part of the exchangeable cations, such as Na+, K+, Ca2+, and Mg2+ on the clay minerals may also go into solution. Furthermore, this technique, as reported by Morton and Land (1988) may produce a sodium-calcium-sulfate water entirely unrelated to the in-situ chemistry of pore fluids. This effect is reflected in Fig. 5-4, where it can be seen 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.

118

G.V. CHILINGARIAN. H.H. RIEKE AND A. K A Z I

The present discussion would not be complete without some comments on the method of calculating the original pore chemistry from the leached extract from shale cores. Assuming that the voids in the original sample are fully occupied by pore water, the void volume will be equal to the pore-water volume. The leachate volume, which is not necessarily equal to the original pore-water volume, has to be corrected by using a dilution factor, Df.It is equal to the leachate volume (K) divided by the original pore-water volume (Vp): Df = V / V p

(5-2a)

Inasmuch as Vp = v b x 4, and v b = w/pd, where sample and W is the weight of the dry shale sample, vp

=

w x 4/Pd

vb

is the bulk volume of the (5-2b)

and, therefore:

Df = K x P d / ( w x 4)

(5-2~)

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= CI x Dr

(5-3)

where C, is the concentration of a constituent in the pore water and CI is the concentration of the same constituent in the leachate. By substituting Dfin eq. 5-2c, one gets: cpw

= CI x

6 x pd/(w

x

4)

(5-4)

where V, is the volume of the leachate (which in the case of Schmidt's (1973) research was 50 ml). Equation 4 can be rewritten by substituting pg(l - 4) for P d (eq. 5-1): c p w = CI x

v,

x

Pg(1 - 4 > / wx 4)

(5-5)

Another criticism of Schmidt's (1973) study is that he did not tabulate the values of porosity or dry bulk density anywhere except in his fig. 4 (p. 324). 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. Chilingar and Rieke (1976) obtained samples of undercompacted and wellcompacted sidewall shale cores from various parts of the world, 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°C and weighing it. The soluble salts were determined by washing them out four times with distilled water from a finely crushed second portion of the sample. After analyzing the washed out solution

119

CHEMISTRY OF PORE WATER TABLE 5-3

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 samples tested

Depth (ft)

31313 41212 31312 21213 61213 31314 314 41314 51312 713/4 21212 214

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,OOO-15,000

Chlorinity (mg/l) well-compacted shales

undercompacted shales

associated sandstones

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,OOO-14,000

8,000-20,000 10,OOO-30,000 10,000-40,000 9,000-35,000 8,000-10,000 5,000- 9,000

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

-

10,000-14,000 8,000-14,000 8,000-14,000 lO,OOO-14,000

(leachate), the C1- content of pore water was calculated, after the correction for dilution effects (Table 5-3). The salinity of pore water in associated sandstones was provided by Dr. Walter Fertl. Figure 5-5, which is a plot of the maximum and minimum C1- values, shows that water in shales is fresher than that in associated sandstones. The results indicate that the overpressured (undercompacted) shales have slightly 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- values than those found in either type of the above shales. The maximum value of C1- concentration of 200,000 mg/l was present at 5,500 ft (about 1500 m) in the sandstone samples, whereas the minimum value of 17,000 mg/l 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. 5-5). Below the depth of 11,500 ft, the chloride content in the sandstone samples starts to increase with depth, whereas the shale values remained approximately the same. Owing to the intimacy of the reactions between clay-sized mineral grains and water, a reduction in pore volume in sediments under increasing pressures can best be analyzed in terms of the removal of pore water. Some of the factors that are known to influence the water content of argillaceous sediments under applied pressures are the type of clay minerals, 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. 5-6. 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.

120

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI CHLORIDE CONCENTRATION, mg/l x loo0 0

l

60

30

l

l

l

l

l

l

120

90

l

l

l

l

l

l

150

l

l

]

Fig. 5-5. Change in the magnitudes of the maximum and minimum chlorinity values of undercompacted and well-compacted shales and associated sandstones (see Table 5-3).

5.2.1.2. Laboratoly experiments Little attention seems to have been given in the literature to artificially simulate gravitational compaction and expulsion of pore waters from deeply buried argillaceous sediments. The first investigation of pore water from marine sediments was made by Murray and Irvine in 1895 (Manheim, 1976). Soviet geoscientists became interested in the chemistry of pore waters from Recent sediments in the 1930's. The work of Kryukov (1947) in developing effective sediment squeezers is noteworthy in this regard. The application of this idea to simulate sediment compaction in the laboratory at high pressures was accomplished by Chilingar and Knight (1960). A high-pressure triaxial cell incorporating the effect of temperature was developed by Chilingarian and Sawabini at the University of Southern California in Los Angeles

121

CHEMISTRY OF PORE WATER

3

l-

70

0 Q

i2

: 3

P r

P 1 t

1

10

100

M E M A N DIAMETER. IN MICRONS

EFFECTIVE OVERBURDEN PRESSURE, IN KILOGRAMS PER SQUARE CENTIMETER

PRCSSURE. I N KILOGRAMS PER SQUARE CENTIMETER

PRESSURE. I N KILOGRAMS PER SOUARE CENTIMETER

s

P

PRESSURE, I N KILOGRAMS PER SQUARE CENTIMETER

PRESSURE I N KILOGRAMS PER SQUARE CENTIMETER

Fig. 5-6. 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 kgf/cm2 (after Meade, 1964, p. B6). (B) Generalized influence of particle size (modified from Skempton, 1953, p. 55). (C) Influence of clay-mineral species (modified from Chilingar and Knight, 1960, p. 104). (D) Influence of cations adsorbed by smectite (modified from Samuels, 1950). (E) Influence of NaCl concentrations in unfractionated illite, about 60% of which was coarser than 2 pm in size (modified from Mitchell, 1960, fig. M3). (F) Influence of NaCl concentration in illite finer than 0.2 p m (modified from Bolt, 1956, p. 92). (After Meade, 1968,fig. 1, p. D4.)

122

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI

(Sawabini et al., 1971). At the Imperial College of London, during the 19603, a similar high-pressure uniaxial compaction device was developed to study the influence of temperature and rate of loading on the pore-water chemistry, progressive lithifaction, and fabric of clay sediments (Knill et al., 1976). Most of the dissolved salts present in the pore waters, which are trapped during sedimentation, are squeezed out in the initial stages of compaction. Laboratory results (Rieke et al., 1964; Chilingar et al., 1969; Kryukov, 1971) 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. Von Engelhardt and Gaida (1963) found that for pressures between 30 and 800 kgf/cm2 (2.94 MPa to 78.45 MPa) the concentration of electrolytes in pore waters of smectite diminishes with increasing overburden pressure. At higher pressures up to 3200 kgf/cm2 (313.8 MPa), however, an increase in salt concentration within the remaining pore water was observed. This behavior was explained by Von Engelhardt and Gaida (1963) as due to the electrochemical properties of base-exchanging clays. If the pore water contains an electrolyte, the liquid immediately surrounding the clay particle will contain less electrolyte 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 kgf/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 movement 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 ionexchange 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. 5-7). Unfortunately this and many other Soviet studies, referenced here, never provided pressure data. Such calibrated pressure data are very difficult to obtain in these type 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 sea water. The results of these experiments are given in Table 5-4 and Fig. 5-8. These results demonstrate that at each stabilized pressure, the percentage concentrations of Na+, Ca2+, Mg2+, C1-, and SO:- in the expelled pore water decrease with increasing overburden pressure.

123

CHEMISTRY OF PORE WATER

I50

.-f

d

v

ol o-o-\

+-7

50

-

E" 0

-

-

- -4

0 ~

-5

TABLE 5-4 Mineralization and content of various ions in solutions squeezed-out at different overburden pressures from smectite clay (API No. 25, Upton, Wyo., U.S.A.) saturated with sea water (after Rieke et al., 1964, table 3, p. 31) ~~

Overburden pressure (psi)

Percentage of the concentration in solution squeezed-out at 100 psi

a-

Na+

Ca2+

Mg2+

SO:-

total mineralization

100 400 1,000 3,000 10,000 40,000 90,000

100 91-95 70-83 40-82 36-61 36 a -

100 93-95 84a 25(?)-87 37 a

100 75-84 67 a 50-62

100 -

100 84-95 67-81 38 a -

100 20a

a

-

-

25 a -

80 a

60a -

Only one trial.

Kazintsev (1968) performed experiments on the Maykop Clay (eastern PreCaucasus). 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. 5-9A). He also determined changes in the concentrations of dissolved constituents in the pore waters of squeezing Maykop Clay samples at room temperature and at 80°C. The clay samples used in these experiments had initial moisture contents

124

G.V. CHILINGARIAN, H.H. RlEKE A N D A. KAZI I

1

.-

Q

d

0

0 + a t 3

Na' 0 co'*

100

ul

80

-

60

-

40

-

20

-

8 Mg"

I ?

-

0 P W N W W

3 0

0

N

v)

z

0 c

1

0 -

b

3 -I

0 v)

z z 0 t-

a

ar

100

80

-

60

-

40

-

20

-

K

c

z

W

V

I

I

!

>

CI-

B so,'-

I

z

0 V

LL

1 -

0

c

z

W

V K W

a.

0

I

1

Fig. 5-8.Content of various cations and anions expelled at different overburden pressures from a sea-water saturated smectite clay (API No. 25, Upton, Wyo., U.S.A.). (After Rieke et al., 1964.)

of 20-25%. The final moisture contents after compaction were 8.8-10.9%. His results (Fig. 5-9B) 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+ decreased with pressure. Concentrations of K+, Li+, I-, and HCO; were higher in solutions expelled at higher temperatures, whereas that of SO:- was slightly lower.

A 1

m

U

m

600

a 500

x

\

.->

g 400

al l

a

'-

-0

300

I

200

0

2

4

6

8

I0

I2

14

16

I8

20

22

AMOUNT OF SOUEEZED - OUT SOLUTION, g

3

I

9

6

P

12

$5

~

(8

~

P

H

Fig. 5-9.(A) Variation in chloride ion concentration in subsequent fractions (I-WI) of squeezed-out interstitial solutions of Maykop Clay, eastern Pre-Caucasus: I = depth of 42 m, Divnoe area; 2 = depth of 158 m, Divnoe area. (After Kazintsev, 1968,fig. 1, p. 186.) (B)Changes in concentration of anions, cations and microcomponents with increasing compaction in subsequent fractions (I-HI) of extruded pore waters. Maykop clay, depth of 158 m, Divnoe area, eastern Pre-Caucasus, U.S.S.R.(After Kazintsev, 1968,fig. 2, p. 188.) Solid curves = room temperatures; dashed curves = heated to 80°C. The amount of extruded solutions in grams is plotted on the abscissa.

cL

126

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI

50

300

01 X

0,

-.200 V L

m

I00

50

Y

\

E25

e

m

m

\

25

L '

C

0

COMPACTION PRESSURE, kg/cm'

Fig. 5-10, Relationship between the concentration of various ions in interstitial solutions squeezed out of marine mud and compaction pressure at room temperature. (After Krasintseva and Korunova, 1968, fig. 2, p. 195.)

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 kgf/cm2 (49.0 to 98.1 MPa) (Fig. 5-10). Figure 5-11 shows the relationship between the concentration of various ions and compaction pressure at 80°C for the same marine mud. The results further demonstrate that at a temperature of 80°C the amount of Mg2' is less than that at room temperature and does not change much with increasing pressure. No such influence was noted for Ca2+ (Fig. 5-11). Shishkina (1968) did not observe any appreciable change in the chemistry of the squeezed-out pore waters up to a pressure of 1260 kgf/cm2 (123.6 MPa) in some samples and up to a pressure of 3000 kgf/cm2 (294.2 MPa) in others from the Atlantic and Pacific oceans and from the Black Sea. There was some increase in CaZi concentration at a pressure range of 675-1080 kgf/cm2 (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 sea water 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

127

CHEMISTRY O F PORE WATER

so0

i

\ 200

3

We"

lOa

2%

ncoi CO"

300

,

7 50

COMPACTION PRESSURE, kg /me Fig. 5-11. Variation in the concentration of various ions in interstitial solutions expelled from marine mud with increasing pressure at 80°C. (After Krasintseva and Korunova, 1968, fig. 3, p. 196.)

about 35 and 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 5-5). 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 sea water to form a slurry. The slurry was allowed to hydrate for a few days and the supernatant liquid (leachate) was analyzed for major dissolved constituents. The clay sample was then centrifuged and the composition of the expelled water was also analyzed. Finally, the composition of the remaining water left in the sample was calculated. The results of this experiment are given in Table 5-6. 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 Ca2+ and Mg2+ have increased in the remaining pore water, whereas that of Na++K+ as well as C1- have decreased.

128

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZI

TABLE5-5 Variation in composition of pore water squeezed out of smectite clay (API No. 25, Upton, Wyo., U.S.A.). Composition of sea water used in saturating the sample is also given (after Chilingar et al., 1969, table 2, p. 5) Ions

Composition fppm) sea water

0-5,000 psi

0-10,000 psi

so:c1-

380 650 10,200 390 1,350 18,000 -

280 17 14,400 660 7,100 19,500 -

720 320 17,000 610 7,600 23,600 -

Total solids

30,970

41,957

49,850

NaICI CaiCl WCI NaICa CaIMg

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

Ca2+ Mg2+ Na+

K+

TABLE 5-6 Variation in the composition of the supernatant liquid and pore water centrifuged out of smectite clay (API No. 25, Upton, Wyo., U.S.A.); the chlorinity ratios (Ca/CI, WCI and Na/CI) are presented along with the NalCa and CaIMg ratios (after Rieke, 1970) Ions

Composition (ppm) sea water (Vt = 10 ml)

supernatant liquid (Sl) (V1 = 2.95 ml)

centrifuged liquid (Sz) (Vz = 2.9 ml)

ClTotal 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

24,530 +S0:-(4,471?)

38,391

Na/C1 Ca/C1 WCI NalCa CaIMg

0.539 0.0245 0.02 18 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 0.0 129 30.96 0.579

(Sl)

Ca2+ Mg2+ K+ Na+

so:-

a

remaining liquid ($3) (V3 = 4.15 ml) 518.2 1,992 652.6 5,164 b

16,202 -

remaining liquid (S3)a ( V , = 4.15 ml) 43 1 744 250 13,345 4,292 19,329 -

Remaining liquid composition was calculated using the supernatant liquid as the starting fluid. The results are not reported because the clay tested appears to have high SO:- content.

129

CHEMISTRY OF PORE WATER

TABLE57 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 Moum, 1972, table 2, p. 10) Cation

Na+ K+ Ca2+ ME2+

Cation concentration a

Remarks

pore water

leachate

438.73 15.66 21.93 41.78

484.51 36.85 16.15 26.46

Na+ and K+ is leached in excess of that present in the pore water of the original sample, whereas the amounts of Ca2+ and Mg2+ 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 results as shown in Table 5-6 are further substantiated by work of Kazi and Moum (1972). They carried out leaching experiments on a soft marine clay from Drammen, Norway, with an initial salinity of 26,700 mg/l. An undisturbed sample of this clay was confined between two porous stones and assembled into a consolidation cell. The sample was consolidated to an in-situ overburden pressure of 8.7 psi (60 Wa). 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+, Mg2+, Ca2+) 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 pore water was reduced from its original value of 26,700 to 1640 mg/l. 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 Ca2+ and Mg2+ (Table 5-7). This led Kazi and Moum (1972) to conclude that post-depositional 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 (MI No. 25) in sea water 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 the free pore water, was removed and analyzed. The remaining saturated sample was placed in a triaxial 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 kgf/cm2 (3.43 MPa). The results shown in Table 5-8 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 sea water. As shown in Fig. 5-12, the concentration of the various anions and cations go through a maximum, or least remain constant, before starting to decrease with increasing overburden pressure.

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI TABLE 5-8 Variation in the concentration of various components in solutions expelled from smectite clay saturated with sea water (after Chilingarian et al., 1973, table 1, p.395) Ion

Ca2+ Mg2+ Na+

K+ HCO;

so:CI FNO; CaC03 Fe2+ Mn2+ Si02 B3* Total dissolved solids

Concentration (mg/l) sea water

supernatant fluid

690 1,189 10,116 400 520 2,759 18,929 3 34 6,612 43 4

560 572 13,400 210 165 4,610 19,310 20 3 3,750 24 5 15 14

expelled solutions fraction No.: cumul. vol. (cm3):

-~ 34,423 38,804

I 16.5

I1 25.5

I11 34.5

IV 49.5

V 59.0

460 644 13,300 226 262 5,350 19,030 20

560 557 13,200 216 165 5,840 19,200 20 0 4,100 56

580 669 13,400 206 189 5,270 19,170 <20 0.5 4,200 28 <5 5

620 657 13,200 206 165 4,610 19,170 <20 0 4,250 28 15 10 4

560 754 12,800 160 128 5,180 18,990 40 0 4,500 64 <5 20

0

3,800 36 <5 5 21

<5

0 14

_

_

39,216

39,844

17

-

39,433

0

~- -

38,576

38,61I

Chilingar and Rieke (1976) saturated a sample consisting of 50% smectite and 50% illite in sea water, having a salinity of 34,500 mgil, for ten days. After shaking vigorously several times a day, the supernatant liquid (leachate) was removed, analyzed, and found to have 37,900 mg/l of total dissolved solids. The higher salinity of the analyzed liquid as compared to that of the initial sea-water salinity is possibly due to the presence of soluble salts in the original sample. The authors assumed that the supernatant liquid (leachate) had the same composition as the free pore water. The remaining saturated sample was piaced in a hydrostatic compaction unit, squeezed and the successive portions of the expelled water were analyzed. Figure 5-13 shows the concentrations of Ca2+ and Mg2+,whereas the concentrations of C1and total dissolved solids are presented in Figs. 5-14 and 5-15, respectively. These results indicate that the total concentration of expelled solutions goes through a maximum before starting to decrease with increasing pressure. The concentration of Ca2+ and Mg2+ ions in squeezed-out solutions, however, start to increase again during the latest stages of compaction. This can possibly be attributed to 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%. Knill et al. (1976) carried out gravitational compaction experiments to study the influence of pressure, temperature, and rate of loading on the composition of

131

CHEMISTRY OF PORE WATER I('

ya

'= i -\

P z 0 la c

I0 W

z z

00

--100

A

AMOUNT OF EXTRUDED SOLUTION, Cm'

B

12.m

i 20

40

60

AMOUNT OF EXTRUDED SOLUTION, cm'

Fig. 5-12. Variations in the Concentrations of dissolved constituents with increasing compaction pressure in the subsequent fractions of expelled solutions from smectite clay hydrated in sea water: (A) anions; (B) cations. (After Chilingarian et al., 1973, figs. 1 and 2, p. 396.)

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 here are those at the undrained end of the specimen. The pressures at the drained end were measured when a back pressure was applied, otherwise the pressure at the drained end is equal to atmospheric pressure (Knill et al., 1976, fig. 2.lb, 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 h i l l et al. (1976) and Wijeyesekera and de Freitas (1976). Figure 5-16 shows the composition of expelled pore fluids from Ca-smectite hydrated in sea water as a function of pressure under a constant temperature of 40°C and a loading rate of 10 psi/h (19.15 Pa/s). Total dissolved solids (TDS), C1- , Na+, and Ca2+ 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+,Mg2+,and SO:- do not exhibit much change with

132

G.V. CHILINGARIAN, H.H. RIEKE A N D A. KAZI I

I

I

1

I

I

I

1

1

1

I

I

I

I

1

I

I

600

E

a 0

;-

8

6 400

k b

p

200

0

0 0

20

40

60

I

80

100

CUMULATIVE VOWME OF: EXPELLEO SOtuTlON, m I Fig. 5-13. Variation in the concentrations of Mg2+ and Ca2+ with increasing compaction pressure in the subsequent fractions of expelled solutions from illite plus smectite clay mixture ( 5 0 :50) saturated with sea water. (After Chilingar and Rieke, 1976, fig. 1, p. 675; courtesy of the Applied Publ. Co.)

tested pressures. The effect of increasing the test temperature to 80°C is shown in Fig. 5-17. The trend of the change in composition of expelled ions remains about the same, except for SO:- which 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 concentration of TDS, C1-, and Na+ at the same pressure is lower at 80°C than that at 40°C (Fig. 5-16). b i l l et al.3 (1976) results for the smectite remolded in distilled water showed little change in the difference between the expelled concentrations at 40°C and 80°C under the same loading conditions (Figs. 5-18 and 5-19). The major difference, between the data shown in Figs. 5-18 and 5-19 and those in Figs. 5-16 and 5-17, is the rate of

-

133

CHEMISTRY OF PORE WATER

20.000 t

C L p.

n. c

'-0

8

I

8

I

I

I

I

I

II

I

II

0 ' 0

I

I

20

I

I

40

I

I

60

1

I

1

1

80

1 I00

CUMULATIVE W K OF €)(PELLED SOUITION, m L Fig. 5-14. Variation in the concentration of C1- with increasing compaction pressure in subsequent fractions of expelled solutions from illite plus smectite clay mixture (50: 50) saturated with sea water. (After Chilingar and Rieke, 1976, fig. 2, p. 676; courtesy of the Applied Publ. Co.)

decrease in the expelled ion concentrations. Figures 5-18 and 5-19 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°C) and rate of loading (10 psi/h; 19.15 Pals), the sample having sea water as initial pore water (Fig. 5-16) experienced less rapid change in ionic concentrations than the sample hydrated with distilled water (Fig. 5-18). There was very little change in the ion concentrations of expelled pore water with respect to pressure in kaolinite remolded in sea water (Fig. 5-20). When the same data are plotted as a percentage of ion composition of the initial concentration at 50 psi (0.34 MPa) as shown in Fig. 5-21, however, the concentration of the SO:ion initially remained constant and then increased above its initial concentration with further compaction. There was a systematic depletion of Naf and K+ ion concentrations in the pore water as compaction progressed. The concentrations of the Ca2+ and Mg2+ ions gradually 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 kaoiinitic clay hydrated in distilled water than in the case of samples hydrated in sea water.

134

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZI

50,000

I

*

.

1

I

1

I

I

I

1

1

-

40,000

E Q. Q.

d

2 Y)

30,000

50

a000

1

10,000

0

1

a0

1

40

I

60

100

00

CUMJLATIVE VOLUME OF EXPELLED SOUmON,

mI

Fig. 5-15. Variation in the total dissolved solids with increasing compaction pressure in the subsequent fractions of expelled solutions from illite plus smectite clay mixture (50 : 50) saturated with sea water. (After Chilingar and Rieke, 1976, fig. 3, p. 677; courtesy of the Applied Publ. Co.)

It is important to state that variations in the ionic concentrations as they appear in Figs. 5-16 through 5-21, are plotted as a function of total axial pressure and not the effective pressure. The latter pressure is equal to the 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 in the compaction of the clay. As compaction progresses at a constant rate of

135

CHEMISTRY OF PORE WATER ..............

.... - . - - .--._ ,

Na'

- -

...........

.

ODD

.

......... - ....-.--...-. . -. . .-. .-... : ..-.. .-.-.--

...................

L

1.

S

W

1a

n

%

x

so:

P

CI

.

. . . . .

Iwee

seem-

AXIAL PRESSURE, psi

Fig. 5-16. Relationship between the axial pressure and major ion concentrations in expelled pore water from a Ca-smectite hydrated in sea water. Loading rate was 10 psi/h (19.15 Pa/s) at a temperature of 40°C. (Based on data from h i l l et al., 1976, table 7.6, pp. 115-116.)

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 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. 5-22). In the later 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 of a well-compacted clay. The observation of Chilingar and Rieke (1976) that the ionic concentrations of water in overpressured shales are generally higher than those of the well-compacted shales is in good agreement with these experimental results. Aoyagi et al. (1985) performed laboratory experiments to understand the mechanism of primary migration of crude oil from the source to reservoir rocks. A sample

136

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZl

0

0

0

0

0 0 0

AXIAL PRESSURE, psi

Fig. 5-17. Relationship between the axial pressure and major ion concentrations in expelled pore water from a Ca-smectite hydrated in sea water. Loading rate was 10 psi/h (19.15 Pa/s) at a temperature of 80°C. (Based on data from b i l l e t al., 1976, table 10.1, p. 219.)

of Na-smectite clay (19% by volume) was mixed with 3% of crude oil and 78% of sea water. This mixture was compacted for 25 days under a constant pressure of 100 MPa and a temperature of 60°C. Figure 5-23 shows that the proportion of oil in the expelled liquid gradually increased with time, possibly due to decreasing water saturation. The chemical composition of the expelled pore water is presented in Fig. 5-24. The amounts of Na+, Mg2+, C1-, and SO:- contents in the expelled water decreased after a slight initial increase. Both K+ and Ca2+ contents gradually increased after an initial decrease. More work is needed to fully understand the mechanisms involved in experiments involving both oil and water. Based on field and laboratory data, the results are discussed in terms of models.

5.3. FLUID CHEMISTRY COMPACTION MODELS

There is overwhelming field and laboratory evidence that the concentration of squeezed-out pore water from saturated argillaceous sediments decreases with increasing overburden pressure. Numerous models have been proposed in the literature to explain this behavior. Several modelling approaches have been advanced for simulating, conceptually and numerically, this change in chemistry with increas-

137

CHEMISTRY OF PORE WATER

8

P x

9

AXIAL PRESSURE, psi

Fig. 5-18. Relationship between the axial pressure and major ion concentrations of expelled pore water from a Ca-srnectite hydrated in distilled water. Loading rate was 10 psi/h (19.15 Pats) at a temperature of 40°C. (Based on data from b i l l et al., 1976, table 7.2, p. 97.)

ing overburden pressures. These models can be broadly classified into two groups based on non-thermodynamic and thermodynamic approaches. Some of the more important models are reviewed briefly. This discussion, however, is limited to the pore-size scale models. Basinwide transport models are beyond the scope of this discussion and are not covered in this chapter.

5.3.1. Non-thermodynamicapproach Non-thermodynamic approaches consider the pore-water flow associated with clay-water-electrolyte systems and that through capillaries, applying curve-fitting techniques to the experimental results.

5.3.1.1. 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 concentration of the expelled water, at a certain time, depends on the surface potential and spacing of clay particles, as given by: C = C,exp ( - V )

(5-6)

138

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZI I 3

I

I

I

I

-

-

Na'

..

. C

.

.

.

. . . . . ..

-X

-%

I

- .1

le

L

-.-....... .. leers

1ease

seesee

AXIAL PRESSURE, psi

Fig. 5-19. Relationship between the axial pressure and major ion concentrations of expelled pore water from a Ca-smectite hydrated in distilled water. Loading rate is 10 psi/h (19.15 Pa/s) at a temperature of 80°C. (Based on data from h i l l et al., 1976, table 7.5, pp. 110-1 1 1 . )

where C is the concentration of the expelled pore water in the equilibrium solution; C,, as interpreted by Warner, is the initial electrolyte concentration in contact with clay particles, and U = v e + / K T . In the latter equation, is the electric potential at the midpoint between two clay plates (as calculated by Verwey and Overbeek, 1948, p. 67), K is the Boltzman's constant, T is absolute temperature, e is the elementary charge of an electron, and v is the ion valency. Warner determined experimentally the electrolyte concentration of water expelled from bentonite, illite, and kaolinite clays compacted in NaCl solutions, having approximately the same C1- content as sea water. 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. 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 A in 0.55 NaCl solution). Warner (1964) calculated that even at a pressure of 60,000 psi (400 MPa), the platy surfaces of the kaolinite particles in 0.55 NaCl solution would still be separated by 90 A. Similar results were obtained by Knill et al. (1976) for kaolinite clay hydrated in sea water and compacted up to 5000 psi (35 MPa) (Fig. 5-20).

+

CHEMISTRY OF PORE WATER I Nd K' C2+

W2'

so:

-

I-

*

.-

CI

TDS

- .x

x x x

?! I C ? I

re

I ee

lee0

,-as

1

eeem0

AXIAL PRESSURE, psi

Fig. 5-20. Relationship between the axial pressure and major ion concentrations of expelled pore water from a kaolinitic clay hydrated in sea water loaded at a rate of 60 psi/h (114.9 Pa/s). (Based on data from h i l l et al., 1976, table 7.16, p. 154.)

However, when the same data are replotted with the composition expressed as a percentage of the initial concentration, then there is a distinct change in the concentration of expelled pore water with increasing pressure (Fig. 5-21). Similar findings were reported by Wijeyeseskera and de Freitas (1976). 5.3.1.2. 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). The model states that: C = Co[l - exp(-A/p")]

(5-7)

where C is the concentration of pore water at a pressure p , C , is the initial concentration of pore water at p = 0, and A. and n are constants, the values of which depend on the physicochemical and geological conditions. In their experiments, A was equal to 4.0 to 4.45 and n was equal to 0.097 to 0.116. An excellent agreement was obtained between the measured and the calculated results (see fig. 133, p. 246, of Rieke and Chilingarian, 1974). This model has an inherent difficulty in predicting the composition of the non-expelled (held) pore water, inasmuch as A and n have to be obtained from the best-fit curve.

140

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI

I88

AXIAL PRESSURE psi

Fig. 5-21. Relationship between the axial pressure and the major ions expressed as a percentage of their initial concentrations at 50 psi (0.34 MPa) in expelled pore water from a kaolinitic clay (see Fig. 5-20).

5.3.1,3. Pol’ster’s capillaly model The model of Pol’ster et al. (1967) presents a conceptual explanation for the gradual decrease in the concentration of squeezed-out pore waters as demonstrated in Fig. 5-25. The voids in the sediment are represented by small capillaries. 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 1 if the capillary radius is large enough. Martin (1960, p. 32) stated that the density of adsorbed water on 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 k e n s (1950), Mooney et al. (1951), and Mackenzie (1958). The low density values are slightly lower than 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. 5-25B). As the capillary is squeezed during compaction, its radius is decreased and the water expelled first will be the least bound, more saline water close to the center of the capillary. The remaining adsorbed waters poor in electrolytes are expelled at higher overburden pressures. Rieke and Chilingarian (1974) used this model in explaining the relative salinities of interstitial waters in well-compacted and under-

141

CHEMISTRY OF PORE WATER

Early Stage of Compactlon

k

Late Stage of

__

Compoctlon

~

- 1

BL

21

Total pressure

Effective prerrure

Compaction

Not to scale

Fig. 5-22. A schematic diagram showing the interrelationships among the degree of compaction, and the variations in the total, effective and pore-water pressures with time.

Fig. 5-23. Changes in the proportions of oil and water in the expelled pore fluid with compaction time. (After Aoyagi et al., 1985, fig. 2, p. 388.)

142

G.V. CHILINGARIAN, H.H. RIEKE AND A. KAZl

10000

ct-

H

1000

a--

-*-

\..

100

.+

C.

--

z+

MgZ+ \

\

'.

K+

/*

\

\ \'

X

Compaction

Time

I

I

12

25

50~'-

(days 1

Fig. 5-24. Changes in cation and anion contents of expelled water with time. Composition of sea water is also shown for comparison. (After Aoyagi et al., 1985, fig. 3, p. 388.)

compacted shales and their associated sandstones, as shown in Fig. 5-26. Although a very simple model, it explains some of the experimental results reported in this chapter. 5.3.2. Thermodynamic approach

Thermodynamic models combine the concepts of electrochemical equilibrium and electroneutrality in compacting sediments. They are elaborate in determining

143

CHEMISTRY OF PORE WATER

A

Y B

Fig. 5-25. Behavior of electrolyte solution in a capillary having radius r (after Pol’ster et al., 1967, fig. 32, p. 72). (A) Distribution of interstitial fluid density; maximum density occurs at the capillary walls. (B) Distribution of dissolving capacity of the interstitial fluid; maximum dissolving capacity is at the center of capillary. (C) Compaction of the capillary by a force F, illustrating that the part of the interstitial fluid squeezed-out first is the one with the highest dissolving capacity (i.e., maximum salinity).

WELL COMPACTED

ENLARGED VIEW OF SHALE CAPILLARY

UNDERCOMPACTED (OVERPRESSURED)

~....SALTIER WATER Fig. 5-26. 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. (After Rieke and Chilingarian, 1974, fig. 9, p. 25.)

144

G.V. CHILINGARIAN, H.H. RlEKE AND A. M

I

the effects of decreasing void ratio (or porosity) on the concentration of squeezedout pore water and the remaining pore water held in the sediments.

5.3.2.1. Bolt's pressure Jiltrate model Bolt's model is based on the way the cationic and anionic concentrations vary in the vicinity of a charged clay particle (Bolt, 1961). The model is applicable to a symmetric electrolyte, such as NaCl, held in sediments with infinite initial void ratios (dilute solutions). The concentration, C, expressed in equivalents of ions per unit fluid volume (meq/cm3) of the expelled pore water is given by:

c=-4C0k (1

+k)2

(5-8)

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 0 during compaction (Smith, 1977). C, is the initial concentration of solution in equilibrium with the clay in meq/cm3. The void ratio of the compacting clay is expressed as:

e = -q(P-m) a 4C,

1Sk 1-k

(5-9)

where e is the void ratio, q is the cation exchange capacity expressed in meq/g, and pmais the matrix weight density in g/cm3. Elimination of k between eqs. 5-8 and 5-9 gives a relationship, as stated by Smith (1977), to be very close to:

(5-10) 5.3.2.2. Appelo's Donnan equilibrium model Appelo (1977) considered the compaction of a Donnanian suspension consisting of a clay hydrated in a NaCl solution. The conceptual model, which is shown in Fig. 5-27, after satisfying the electrochemical equilibrium and electroneutrality requirements is represented by the following equation:

(5-11) where, as shown in Fig. 5-27, the superscript I (phase I) represents the suspension and the superscript I1 (phase 11) denotes the expelled pore water. mais the activity coefficient of sodium ion and ycl is the activity coefficient of chloride ion, and x is the cation exchange capacity parameter of the clay expressed in equiv./l of the suspension. mkl is the concentration of chloride ion expressed in equiv./l of the suspension and m:, is the concentration of chloride ion expressed in equiv./l of the expelled pore water. Figure 5-27 shows that with an initial suspension volume V, in liters and chloride ion content so (equiv.), the initial concentration of the suspension is m = so/Vo. The compaction of the suspension from V, to V (at any time) will change the concentration of chloride in the suspension to s / V , and the initial cation exchange parameter x, will change to x = V,x,/ V . As a result of compaction, the

145

CHEMISTRY OF PORE WATER

System Requirements V

II

1

I

Fig. 5-27. Basic concept of Appelo's model. p = electrochemical potential.

concentration of chloride ion in the squeezed-out pore water will be given by:

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:

(5-13) Appelo (1977) applied eq. 5-13 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 understanding laboratory-simulated pore-water expulsion experiments. The first condition of the infinitesimal equilibration case looks at the concentration of the pore water held in the compacted clay suspension, rnk, = s / V , at different times. Under these conditions, s is given by:

(5-14)

+

where y = arccosh [(2s,/ V, x,) 13. The second condition considers the concentration of the expelled pore water, rn:, = ds/dV, at different times. Under these conditions mg, is expressed as:

146

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZl

=

(*)

[(

;)f

exP(Y) -

(

;)-f

eXP(-Y)]

(5-15)

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, mgl = s/ V , at different times. Under these conditions, s is given by:

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 given by: (5-17)

where the value of s is obtained from eq. 5-16. Appelo (1977) plotted the last two equations (eqs. 5-16 and 5-17) to express the variation in the concentration of chloride ion inside the suspension and in the squeezed-out pore water as a function of the suspension volume (Fig. 5-28). In constructing Fig. 5-28, Appelo used arbitrary values of x = 0.5 and so = 0.25 for two different f values (1 and 0.52). The 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 chloride ions decreases with compaction where 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 ions’ concentration. This is in agreement with data presented in Rieke and Chilingarian (1974), and data from von Engelhardt and Gaida (1963), h i l l et al. (1976), and Rosenbaum (1976). 5.3.2.3. Smith’sGibbs equilibrium model Smith’s (1977) model is similar to Appelo’s in many respects. In deriving his equations, however, Smith assumed that the ratio of activity coefficients 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

CHEMISTRY OF PORE WATER

147

0.6

Volume o f susprnsion, I

Fig. 5-28. The relation between the chloride ion concentration and the volume of the suspension. The concentration of chloride inside the suspension is given by the full line curve, whereas that of the squeezed-out liquid is shown by a dashed line (Appelo, 1977, fig. 5, p. 96). xo = initial cation exchange capacity expressed in equiv./l; so = chloride ion content in equiv.; f = the square root of the ratio of activity coefficients inside and outside the suspension.

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 or 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.

5.4. SUMMARY AND CONCLUSIONS

A study of variations in the chemical composition of subsurface brines has revealed that salinity generally increases with depth in sedimentary sequences. Salinities many times greater than that of sea water are frequently encountered in permeable sandstone beds as compared to the less permeable shale beds at similar depths. This applies mainly to mature sedimentary basins which are under hydrostatic fluid pressures. In immature basins, however, where abnormally high

148

G.V. CHILINGARIAN, H.H. RlEKE AND A. KAZI

formation pressures (pore pressures) are known to occur, the difference in the magnitude of salinity between sandstone and shale members is greatly reduced. In any case, the salinity of pore water in well-compacted shales is often lower than that in undercompacted shales at comparable depths. Figures 5-25 and 5-26, and associated discussion, clearly demonstrate why pore water in undercompacted shales is more saline than in the well-compacted shales. Among the major dissolved constituents of brines, in normally pressured formations, it is the C1-, Na+, and Ca2+ 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 Mg2+, SO:-, and HCO; 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 water pumped out of the more permeable sandstone beds. Knowledge about the nature and composition of the water held 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. More often, the most common component of shales (smectite, illite, or kaolinite clays) is 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 throw some light on the geological behavior of fine-grained sediments in nature. Results of laboratory experiments have shown that the composition of the water expelled from clays, undergoing gravitational compaction, is a function of the type of clay mineral, the initial concentration of the electrolyte held in the sediment pore space, the geothermal temperature, and the rate of sediment loading. More specifically: (1) The concentration of ions in pore water is higher with increasing sediment loading rate. (2) The higher the temperature, the more rapid is the decrease in the ionic concentration of the expelled pore water. (3) The higher the initial concentration of the pore water, the faster is the rate at which the concentration of the expelled pore water decreases. (4) The concentration of high-valence ions may first decrease with increasing overburden pressure, and then increase to values higher than their respective initial concentrations. ( 5 ) 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 high-cation exchange capacity clay (e.g., smectite). (6) One of the main unresolved problems is obtaining representative pore-water samples, because the chemistry of solutions squeezed from marine muds changes with the magnitude of applied pressure. Inasmuch as the latter is usually very low, the chemistry of squeezed-out pore water is close to that of sea water, with most of the pore water remaining behind in the mud after compaction (also see Wolf and Chilingarian, 1992).

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(7) Salinity changes (usually freshening of water) have been used as a warning of impending abnormal pressures while drilling through thick sand-shale sequences. This is owing to influx of fresher water from shales into sands. Water in shales, both well-compacted and undercompacted, is fresher than in associated sandstones. A number of models has been proposed to describe how the pore-water chemical changes 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. Models employing both thermodynamic and non-thermodynamic approaches explain some of the field and laboratory observations on a pore-level (microscopic) scale. These models are not comprehensive enough 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 mechanisms operating in such sedimentary systems and indicate trends of changes in pore-water composition associated with burial of the sediments. The above conclusions relating to the field and laboratory results clarify many of the observations made on (1) the extracted pore waters from offshore sediments, (2) oilfield water samples, and (3) calculated pore-water chemistry from geophysical log analyses. This study can be applied to some of the important aspects of geological reservoir characterization and petroleum recovery operations in the petroleum industry as specified by a number of investigators. This includes among others (1) the prediction of high-pressured fluid zones (Fertl and Chilingarian, 1977, and elsewhere in this volume), (2) the quantitative interpretation of electric logs (Chilingar et al., 1969), (3) the interpretation of the direction of hydrodynamic flow over geologic time in compacting sand-shale sequences (Magara, 1969, 1978), and (4) the determination whether any water influx into a producing petroleum reservoir could have come from surrounding shales (Dzhevanshir et al., 1987; Bourgoyne, 1990).

REFERENCES Aharon, P., 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.F., 1958. The density of water adsorbed by lithium-, sodium-, and potassium-bentonite. Soil Sci. SOC.Am. Proc., 22(2): 99-103. 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. Berry, F.A.F., 1959. Hydrodynamics and Geochemistry of the Jurassic and Cretaceous System in the San Juan Basin, Northwestern New Merico and Sourhwestem Colorado. Ph.D. Dissertation, Department of Geology, Stanford University, Palo Alto, Calif. Bischoff, J.L., Greer, R.E., and Luistro, A.O., 1970. Composition of interstitial waters of marine sediments: temperature of squeezing effect. Science, 167: 1245-1246.

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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, 1. Theoretical considerations. Kolloid. Z., 175: 33-39. 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. Capuano, R.M., 1990. Hydrochemical constraints on fluid-mineral equilibria during compaction diagenesis of kerogen-rich geopressured sediments. Geochirn. Cosmochim. Acta, 54: 1283- 1299. Carpenter, A.B., 1978. Origin and chemical evolution of brines in sedimentary basins. Okla. Geol. Suw., 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. Chilingar, G.V. and Knight, L., 1960. Relationship between pressure and moisture content of kaolinite, illite and montmorillonite clays. Bull., Am. Assoc. Pet. GeoL, 44(1): 101-106. Chilingar, G.V. and Rieke, 111, H.H., 1976. Chemistry of interstitial solutions in undercompacted (overpressured) versus well-compacted shales. Proc. Int. Clay Con$ 1975. Applied Publishers Ltd., Wilmette, Ill., pp. 673-678. Chilingar, G.V., Rieke, 111, H.H., Sawabini, C.T. and Ershaghi, I., 1969. Chemistry of interstitial solutions in shales versus that in associated sandstones. SPE 2527, 44th Annual Meeting, SOC.Pet. Eng., Denver, Colo., 8 pp. Chilingarian, G.V. and Rieke, 111, H.H., 1976. Compaction of argillaceous sediments. In: W.H. Fertl, Abnormal Formation Pressures. Elsevier, Amsterdam, pp. 49-100. Chilingarian, G.V. and Rieke, 111, H.H., 1968. Data on consolidation of fine-grained sediments. J. Sediment. Petrol., 38: 81 1-816. Chilingarian, G.V., Sawabini, C.T and Rieke, H.H., 1973. Effect of compaction on chemistry of solutions expelled from montmorillonite clay saturated in sea water. Sedimentology, 20: 391-398. Collins, A.G., 1975. Geochemistry of Oilfield Waters. Elsevier, Amsterdam, 496 pp. Degens, E.T., Hunt, J.M., Reuter, J.H. and Reed, W.E., 1964. Data on the distribution of amino-acids and oxygen isotopes in petroleum brine waters of various geologic ages. Sedimentology, 3: 199-225. De Sitter, L.U., 1947. Diagenesis of oil-field brines. Bull.,Am. Assoc. Pet. GeoL, 31: 2030-2040. DeWit, C.T. and Arens, P.L., 1950. Moisture content and the density of some clay minerals and some remarks on the hydration pattern of clay. Trans. Soil Sci., 2 59-62. Dickey, P.A., Collins, A.G. and Gajardo, I.M., 1972. Chemical composition of deep formation waters in southwestern Louisiana. Bull., Am. Assoc. Pet. Geol., 56: 1530-1570. Dzhevanshir, R.D., Chilingarian, G.V. and Yen, TF., 1987. Influx of water from overlying, undercompacted, overpressured shale beds into producing reservoirs. Energy Sources, 9 (1): 79-85. Elliott, W.C., 1953. Chemical characteristics of waters from the Canyon, Straw, and Wolfcamp formations in Scurry, Kent, Borden, and Howard counties, Texas. Pet. Eng., 25: B77-B89. Fertl, W.H. and Chilingarian, G.V., 1977. Importance of abnormal formation pressures to the oil industry. 1. Pet. Technot., 29 (4): 347-354. F e d , W.H. and Timko, D.J., 1970. Association of salinity variations and geopressures in soft and hard rocks. 11th Prof. Well Log Analysts Symp., Los Angeles, Calif., May, pp. 1-24. Fowler, Jr., W.A., 1968. Pressures, hydrocarbon accumulation and salinities, Chocolate Bayou Field, Brazoria County, Texas. SPE 2226, 43rd Annual Fall Meeting, SOC.Pet. Eng., Houston, Texas. Goldberg, E.D., Broecker, W.S., Gross, M.G. and nrekian, K.K., 1971. Marine chemistry. In: Radioactivity in the Marine Environment. National Academy of Science, Washington, D.C., pp. 137146. Graf, D.L., Meents, W.F., Friedman, T. and Shimp, N.F., 1966. The Origin of Saline Formation Waters, 11. Isotopic Fractionation by Shale Micropore System. Ill. State Geol. Suw., Circ., 393, 32 pp.

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Hanor, J.S., 1981. Composition of fluids expelled during compaction of Mississippi Delta sediments. Geo-Mar: Lett., 1: 169-172. Hanor, J.S., 1987a. Origin and migration of subsurface sedimentary brines. SOC. Econ. Paleontol. Mineral., Shon Course Notes, No. 21, 247 pp. Hanor, J.S., 1987b. Kilometre-scale thermohaline overturn of pore waters in the Louisiana Gulf Coast. Nature, 327: 501-503. Hedberg, W.H., 1967. Pore- Water Chlorinities of Subsurface Shales. Ph.D. Dissertation, University of Wisconsin, Madison, Wisc., 122 pp. Hitchon, B., Billings, G.K. and Klovan, J.E., 1971. Geochemistry and origin of formation waters in the western Canada sedimentary basin, Ill. Factors controlling chemical composition. Geochim. Cosmochim. Acta, 35: 567-598. Hobson, G.D., 1954. Some Fundamentals of Petroleum Geology. Oxford University Press, London, 139 pp. Kazi, A. and Moum, J., 1972. The Effect of Leaching on Cation Exchange in a Marine Clay from Dmmmen, Norway. Norwegian Geotechnical Inst., Oslo, Internal Rep., 56401-6: 14 pp. Kazintsev, E.E., 1968. Pore solutions of Maykop Formation of Eastern Pre-Caucasus and methods of squeezing pore waters at high temperatures. In: G.V.Bogomolov et al. (Editors), Pore Solutions and Methods of Their Study - A Symposium. Izd. Nauka i Tekhnika, Minsk, pp. 178-190. Kharaka, Y.K., Callender, E. and Wallace, Jr., R.H., 1977. geochemistry of geopressured geothermal waters from the Frio Clay in the Gulf Coast region of Texas. Geology, 5 : 241-244. Knill, J.L., Clarke, B.A., de Freitas, M.H., Jones, D. and Rosenbaum, M., 1976. Anificialb Simulating the Geological Histoly of Clay. Imperial College Sci. Rchnol. Rep., US. Army European Research Office, Grant No. DA-ERO-124-74-G0085,250pp. Kotova, I.S. and Pavlov, A.N., 1968. About leaching of impervious rocks on increasing geostatic pressure. In: G.V. Bogomolov et al. (Editors), Pore Solutions and Methods of Their Study - A Symposium. Izd. Nauka i Tekhnika, Minsk, pp. 55-68. Krasintseva, V.V. and Korunova, V.V., 1968. Influence of pressure and temperature on composition of extruded solutions during mud compaction. In: G.V. Bogomolov et al. (Editors), Pore Solutions and Methods of Their Study - A Symposium. Izd. Nauka i Tekhnika, Minsk, pp. 191-204. Kryukov, P.A., 1947. In ‘Sovremennye Metody Issledovanja Fiziko-khimicheskikh Svoisrv Pochv’, Vol. 2. Moscow. Kryukov, PA., 1971. Rock, Soil and Mud Soluiions. M a d . Nauk S.S.S.R., Siberian Branch, Izd. Nauka, Novosibirsk, 220 pp. Kryukov, P.A. and Zhuchkova, A.A., 1963. Physical-chemical phenomena associated with driving out of solutions from rocks. In: Present-Day Concept of Bound Water in Rocks. Izd. Akad. Nauk S.S.S.R., Laboratory of Hydrogeological Problems of EP. Savarenskiy, Moscow, pp. 95-105. Mackenzie, R.C., 1958. Density of water sorbed on montmorillonite. Nature, 181: 334. Mangelsdorf, PC., Wilson, T.R.S. and Daniel, E., 1969. Potassium enrichments in interstitial waters of recent marine sediments. Science, 165: 171-174. Manheim, F.T., 1966. A hydraulic squeezer for obtaining interstitial water from consolidated and unconsolidated sediments. US.GeoL Sum, Prof: Pap., 550-C (3256-C261. Manheim, F.T., 1976. Interstitial waters of marine sediments. In: J.P. Riley and R. Chester (Editors), Chemical Oceanography. Academic Press, London, pp. 115-186. Manheim, ET and Bischoff, J.L., 1969. Geochemistry of pore waters from Shell oil company drill holes on the continental slope of the northern Gulf of Mexico. Chem. Geol., 4 (1/2): 63-82. Magara, K., 1969. Upward and downward migrations of fluids in the subsurface. Bull. Can. Pet. Geol., 17(1): 20-46. Magara, K., 1978. Compaction and Fluid Migration Practical Petroleum Geology. Elsevier, Amsterdam, 319 pp. Martin, R.T.,1960. Water vapor sorption on kaolinite: entropy of adsorption. Clays Clay Miner. Proc. Natl. Conf:Clays Clay Miner., 8: 102-114. Meade, R.H., 1964. Removal of water and rearrangement of particles during the compaction of clayey sediments - review. US.GeoL Sum., Prof: Pap., 497-B: 1-23.

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Meade, R.H., 1968. Compaction of sediments underlying areas of land subsidence in central California. U S . Geol. Sum, Pro$ Pap., 497-D: 1-39. Mitchell, J.K., 1960. The application of colloidal theory to the compressibility of clays. In: R.H.G. Parry (Editor), Interparticle Forces in Clay- Water-Electrolyte Systems. Commonwealth Scientific and Industrial Research Organization, Melbourne, pp. 2-92-2-97. Mooney, R.W., Keenan, A.G. and Wood, L.A., 1951. Adsorption of water vapor on montmorillonite, 11. J. Am. Chem. SOC.,74: 1371. Morton, R.A. and Land, L.S., 1987. Regional variations in formation water chemistry, Frio Formation (Oligocene), Texas Gulf Coast. Bull., Am. Assoc. Pet. Geol., 71 (2): 191-206. Morton, R.A. and Land, L.S., 1988. Regional variations in formation water chemistry, Frio Formation (Oligocene), Texas Gulf Coast: Reply. Bull., Am. Assoc. Pet. Geol., 72 (7): 858-859. Myers, L.L., 1963. Dynamic Phenomena of Sediment Compaction in Matagorda County, T m s . Thesis, University of Houston, Houston, Texas, 62 pp. Nesbitt, H.W., 1985. A chemical equilibrium model for the Illinois Basin formation waters. Am. J. Sci., 285: 436-458. Norrish, K., 1954. The swelling of montmorillonite. Faraday SOC., London, Disc.,18: 120-134. Osmaston, M.F., 1975. Interstitial water composition and geochemistry of deep Gulf Coast shales and sandstones: Discussion. Bull., Am. Assoc. Pet. Geol., 59 (4): 715-726. Oxburgh, E.R., O’Nions, R.K. and Hill, R.I., 1986. Helium isotopes in sedimentary basins. Nature, 324 (18): 632-635. Plummer, F.B. and Sargent, E.C., 1931. Underground waters and subsurface temperatures of the Woodbine Formation in Northeast Texas. Univ. T m s Bull., 3138: 178 pp. Pol’ster, L.A., Viskovskiy, Yu.A., Guseva, A.N., Parnov, E.I. and Plaskova, A.G., 1967. Physicochemical Characteristics and Hydrogeological Factors of Migration of Natural Solutions (in Relation to Study of Oil- and Gas-Bearing Basins). Nedra, Leningrad, 172 pp. Powers, M.O., 1967. Fluid-release mechanisms in compacting marine mudrocks and their importance in oil exploration. Bull., Am. Assoc. Pet. Geol., 51: 1240-1254. Richardson, G.B., 1917. Note on Appalachian oil-field brines. Econ. Geol., 12: 37-41. Rieke, 111, H.H., 1970. Compaction of Argillaceous Sediments (20-500,00 p.s.i.). Ph.D. Dissertation, University of Southern California, Los Angeles, Calif., 682 pp. Riekc, 111, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Elsevier, Amsterdam, 424 pp. Rieke, 111, H.H., Chilingar, G.V. and Robertson, Jr., J.O., 1964. High-pressure (up to 500,000 psi) compaction studies on various clays. Proc. 22nd Int. Geol. Congr., New Delhi, 15: 22-38. Rittenhouse, G., 1967. Bromine in oil-field waters and its use in determining possibilities of origin of thesc waters. Bull., Am. Assoc. Pet. Geol., 51: 2430-2440. Rosenbaum, M.S., 1976. Effect of compaction of the pore fluid chemistry of montmorillonite. Clays Clay Miner., 24: 118-121. Samuels, S.G., 1950. The effect of base exchange on the engineering properties of soils. Build. Res. Stn. (Great Britain), Note, C176: 16 pp. Sawabini, C.T., Chilingar, G.V. and Allcn, D.R., 1971. Design and operation of a triaxial, high-pressure, high-temperature compaction apparatus. J. Sediment. Petrol., 41 (3): 871-881. Sayles, EL., 1979. The composition and diagenesis of interstitial solutions, 1. Fluxes across the seawatersediment interface in the Atlantic Ocean. Geochim. Cosmochim. Acra, 43: 527-545. Sayles, EL. and Manhcim, F.T, 1975. Interstitial solutions and diagenesis in deeply buried marine sediments: results from the Deep Sea Drilling Project. Geochim. Cosmochim. Acta, 39: 103-127. Schmidt, G.W., 1973. Interstitial water composition and geochemistry of deep Gulf Coast shales and sandstones. Bull., Am. Assoc. Pet. Geol., 57 (2): 321-337. Serruya, C., Picard, L. and Chilingarian, G.V., 1967. Possible role of electrical currents and potentials during diagenesis (electrodiagenesis). J. Sediment. Petrol., 32 (2): 659-698. Shishkina, O.V., 1968. Methods of investigating marine and ocean waters. In: G.V. Bogomolov et al. (Editors), Pore Solufionsand Methods of Their Study - A Symposium. Izd. Nauka i Tekhnika, Minsk, pp. 167-176. Skempton, A.W., 1953. Soil mechanics in relation to geology. Proc. Yorkrhire Geol. SOC.,29: 33-62.

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Smith, J.E., 1977. Thermodynamics of salinity changes accompanying compaction of shaly rocks. SOC. Pet. Eng. J., 17 (5): 377-386. Stoessell, R.K. and Moore, C.H., 1983. Chemical constraints and origins of four groups of Gulf Coast reservoir fluids. Bull., Am. Assoc. Pet. Geol., 67: 896-906. Timm, B.C. and Maricelli, J.J., 1953. Formations waters in southwest Louisiana. Bull., Am. Assoc. Pet. Geol., 37: 394-409. Verwey, E.J.W. and Overbeek, J.Th.G., 1948. Theory of the Stability of Lyophobic Colloids - The Interaction of Soil Particles Having an Electric Double Layer. Elsevier, Amsterdam, 199 pp. Von Engelhardt, W. and Gaida, K.H., 1963. Concentration changes of pore solutions during the compaction of clay sediments. J. Sediment. Petrol., 33: 919-930. Warner, D.L., 1964. An Analysis of the Influence of Physical-Chemical Factors Upon the Consolidation of Fine-Grained Clastic Sediments. Ph.D. Dissertation, University of California, Berkeley, Calif., 136 PP. Washburne, C.W., 1914. Chlorides in oil-field waters. Am. Inst. Min. Eng., Tmns., 48: 687-693. White, D.E., 1957. Magmatic, connate, and metamorphic waters. Geol. Soc. Am. Bull., 68: 1659-1682. Wijeyesekera, D.C. and de Freitas, M.H., 1976. High-pressure consolidation of kaolinitic clay. Bull., Am. Assoc. Pet. GeoL, 60(2): 293-298. Wolf, K.H. and Chilingarian, G.V., 1992. Diagenesis, III. Developments in SedimentologV 47. Elsevier, Amsterdam, 674 pp.

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Chapter 6 PRE-DRILL GEOPHYSICAL METHODS FOR GEOPRESSURE DETECTION AND EVALUATION TK.KAN and C.J. SICKING

6.1. INTRODUCTION

The existence of geologic formations with pore fluid pressure in excess of hydrostatic pressure is well documented in this book. The phenomenon of geopressure is essentially stratigraphic in nature and in most cases its occurrence correlates strikingly well with some mappable geologic characteristics, such as its regional correlation with high shale and low sand content, and its relationship with sediment deformation and faulting. In this chapter we discuss geophysical methods for geopressure detection and evaluation. Of all the geophysical methods, the reflection seismic method is essentially the only technique used to predict pore pressures. Pennebaker (1968) was one of the first authors to describe in detail the application of surface seismic techniques to indicate depth and magnitude of abnormal pressures. Pennebaker’s work stimulated much interest throughout the industry and is still used with considerable success. The seismic method detects changes of interval velocity with depth from velocity analysis of the seismic data. These changes are in turn related to lithology, pore fluid type, rock fracturing and pressure changes within a stratigraphic column. When the factors affecting the velocity are understood for a given area, a successful pressure prediction can be made. For clastic environments such as the Tertiary section of the Gulf of Mexico or the Niger delta, the interval velocity of the rocks increases with depth because of compaction. In these areas deviations from normal compaction trends are related to abnormally high pore pressures. The seismic velocity versus depth is translated into pore pressure gradient versus depth in any place where seismic velocity analysis has been performed. The different methods of measuring rock velocities are presented in Section 6.2. They include laboratory, well logs, Vertical Seismic Profile (VSP), and surface seismic. Examination of the velocities obtained from the different methods enhances our understanding of the velocity of rock and the pitfalls of the methods used to measure it. Section 6.3 is devoted to the description of recording, processing and interpreting CMP (Common Mid Point) seismic data for velocity. The procedure for developing the velocity-to-pressure calibration curves and case studies using seismic data for geopressure prediction are presented in Section 6.4. An example of the use of VSP to aid the driller in a geopressure zone is also presented in Section 6.4. The use of other geophysical methods in geopresssure prediction is discussed in Section 6.5.

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6.2. VELOCITY

In this section we discuss the different velocities commonly measured (laboratory, well logs, vertical seismic profile (VSP), and seismic) and show how they relate to the velocity of rock. Because velocity is critical for the prediction of the' magnitude and depth of geopressure, it is important to understand the meaning of the different velocities and how they relate to each other. Comparing velocities obtained from the different methods helps identify pitfalls in using the velocities from any given method. Comparing the sonic velocity to the laboratory measurements from core samples can help identify the effect of mineralogical components and pore fluid type on velocity. Comparing the sonic log velocity to the VSP velocity helps to identify zones where borehole alteration has modified the sonic velocity. 6.2.1. Elocity from laboratory measurements

The velocity of sound in a rock is a function of the rock's elastic constants and the mode of propagation of waves. It is usually measured in the laboratory by sending an impulse through a rock sample (typical length 2 inches, 5 cm). The length of the rock sample divided by the time required for the impulse to travel through the rock yields an estimate of the velocity of the rock sample. The relation between the compressional velocity, Vp, and the elastic constants is:

The relation between the shear velocity, V,, and the elastic constants is:

vs= Here K is the bulk modulus, p is the shear modulus and p is the bulk density. The ratio of the compressional velocity to the shear velocity is:

where u is the Poison ratio. The quantity, V,/ V,, is a diagnostic of rock type. In the current state of the art for pre-drill geopressure prediction, only the compressional velocity is used. The following discussions of velocity measurements consider only the compressional velocity. 6.2.2. Velocity from well logs

The sonic logging tool measures the velocity of rocks across an interval in the subsurface by transmitting a sound pulse at one depth and receiving the sound pulse at other depths in a well (Fig. 6-la). Dividing the distance between the two receivers, Az, by the difference in arrival times, A t , at the receivers gives

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STransmitter

R1:Receiver 1 R2:Receiver 2

Fig. 6-1. (a) Configuration for a sonic tool. (b) Arrival time difference for a pulse arriving at two receivers in a sonic tool.

the velocity for the rock interval between the receivers (Fig. 6-lb). This velocity is close to the velocity which would be measured in the laboratory. Because the receivers are separated by distance Az, this velocity is an average over that interval. To the extent that the rock properties vary over this interval, the velocity will deviate from the laboratory measurement. Typically, Az is on the order of 2 ft (61 cm) so that the correlation with the laboratory measurements will generally be satisfactory provided the frequency-dependent propagation effects are minimal. Therefore, when care is taken in recording and editing sonic logs, we can obtain reliable velocity information. A major source of error in sonic velocity can result from borehole alteration. The corrected velocity data from sonic logs is used to obtain the velocity to pressure calibration data which is used for converting seismic velocity data to pressure. The procedure for computing the pressure calibration is presented in Section 4. 6.2.3. Velocityfrom VSP

In the VSP method an energy pulse or source is placed at the surface near the well and the receiver is placed in the well. A series of shots is recorded with the receiver placed at different depths for each shot. The receiver spacing is typically 50 ft (about 15 m) but is sometimes greater. Dividing the distance between the receiver locations for two different shots by the difference in the travel time between the source and receiver for the two shots gives the velocity over the interval between the receiver locations. This velocity is normally close to the velocity measured by a sonic tool. It may deviate from the sonic tool measurement because the VSP velocity is an average over an interval of 50 ft while the sonic tool is an average over 2 ft and the VSP velocity is measured at the seismic frequencies of 10 to 100 Hz, while the sonic tool operates at frequencies of 10 to 20 kHz. To the extent that

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the rock properties vary over the receiver spacing interval and to the extent that the velocity is frequency-dependent, the VSP velocity will deviate from the sonic tool velocity (Stewart et al., 1984). The VSP has larger receiver spacing and operates at lower frequency than the sonic tool. Therefore, the VSP velocities are less reliable than sonic velocities. However, the VSP is not effected by borehole problems which can cause significant error in the sonic data. Because the VSP uses a downhole tool and measures the propagation time one way through the rocks, the velocities from the VSP are more accurate than the velocities from surface seismic for the depth interval of the well occupied by the receiver. The primary applications of VSP are correlating time to depth, calibrating the interval velocity data, and integrating surface seismic with borehole data. When the VSP data is used to calibrate the interval velocities obtained from surface seismic data the predictions of depths and the magnitudes of geopressure from surface seismic can be more accurate. A case where the VSP tool was used to detect a highly permeable sand in a geopressure zone below the bottom of the well is presented in Section 6.4. 6.2.4. Velocifyfrom seismic

In seismology we are concerned with the speed of propagation of a seismic wave in the earth. The seismic velocity, therefore, refers to the speed of a wavefront in the direction of energy propagation (perpendicular to the wavefront for isotropic earth). Unfortunately, we cannot directly measure the seismic velocity using reflection seismic data. We must measure normal moveout (NMO) velocity, interpret root means square (RMS) velocity from NMO velocity and then convert RMS velocity to interval velocity. Interval velocities thus derived are our best estimate of the velocity of rocks required for geopressure prediction. The method of reflection seismic data acquisition, processing and interpretation is covered in detail in the next section.

6.3. SEISMIC DATA ACQUISITION, PROCESSING AND INTERPRETATION

In this section we review the acquisition, processing and interpretation of reflection seismic data. The limitations of the seismic technique which lead to errors in the velocity information are discussed in detail. In general, the reflection seismic method readily detects increases or decreases in velocity while the absolute magnitude of the velocity is less accurate. For this reason, the depth to the top of geopressure and the magnitude of geopressure are inaccurate. Proper interpretation of seismic data can predict the top of overpressure to within an average of plus or minus 500 f t (152 m), and pore pressure magnitudes can be estimated to within plus or minus 1.0 lb/gal (0.052 psi/ft, 1.175 kPa/m) mud weight equivalent in more than 50% of field cases studied (Reynolds, 1973). Woeber and Penhollow (1973) have carried out a statistical study of the accuracy of formation-top predictions from seismic velocity profiles in shalehand sequences along the Texas Gulf Coast area. Whereas in 80% of field cases an accuracy of 1-2% is found over the depth range between 5000 and 12,000 ft (1524 and 3659 m),

PRE-DRILL GEOPHYSICAL METHODS

159

the accuracy falls off fairly rapidly at depths below 12,000 ft (3659 m) with only 50% of the cases still showing an accuracy of 2% or more below 15,000 ft (4573 m). The authors attribute this accuracy to the 2-mile (3.22 km) spread lengths used, the overall quality and density of the data, and to the moderate velocity range: 7000-11,000 ft/s (2134-3354 m/s). 6.3.1. The seismic method - acquisition In the reflection method the two primary measurements we can make for estimating velocity are distance between the shot and receiver and the travel time from the shot to the receiver. In order to exploit these measurements effectively, the common midpoint (CMP) method is used. This method provides multiple measurements of source-to-receiver distance (offset) and time for any given interface in the subsurface. As shown in Fig. 6-2a, the CMP method consists of recording a number of seismic traces for which the midpoint between the source and receiver

(b)

X-

0.3 0.4

3 0.5 Q)

0

0.6

rI- 0.7

I

.! . 1

0.8

;

,

't

0.9 Fig. 6-2. (a) Geometry for the common mid point (CMP) method in reflection seismology. S1, S2 etc. denote shot locations, and R1 and R2 etc. denote receiver locations. (b) Seismic traces in a CMP gather showing the hyperbolic moveout.

160

TK. KAN AND C.J. SICKING

are at the same surface location. Each trace has a different offset distance (X). The group of traces which have a common midpoint is called a CMP gather. When the traces are assembled so that the offset distance progressively increases, the arrival time for a given reflection also increases as shown in Fig. 6-2b. This arrival time (T) is a function of offset (X) and can be written as:

[

[

]

x 2 dT2] d2T2 T2=To++ -x 4 l! d x 2 x=o 2! (dx2)2 x=o

3

d3T2 + -x3!6 [+. (dx2)3 x=o

(6-4)

This is the Taylor series expansion of T2 and is valid for an earth model which consists of a series of plane reflecting layers. In eq. 6-4, To is the time that is measured by a coincident shot and receiver ( X = 0). It is the movement away from this time which is a measure of the “normal moveout velocity”, VNMO,and is defined by the coefficient for the second term in the Taylor series: 1

(6-5) x=o This is the slope of the T-X curve evaluated at the origin. If the additional terms in eq. 6-4 are neglected, the Taylor series equation describes a hyperbola that is tangent to the curve of T versus X at X = 0 T2 21 To2 +

X2 ~

‘4MO

Truncating the equation to only two terms leads to additional error which is over and above the error that results from assuming a layered earth model. However, for offsets less than the depth, the error is small. It is empirically observed that the travel time curve for CMP data can be approximated by the hyperbola:

where the stacking velocity, VSTK, is the one that provides the best hyperbolic fit to a given reflection (see Fig. 6-2b). The above approximation is valid only for cases where the spread length is not too large. In general, the reflecting events will describe hyperbolae according to eq. 6-7. However, as a result of the above assumptions, the measured velocities are usually different from the true velocities. We can compute the coherency along a suite of hyperbolae defined by eq. 6-7 using different stacking velocities for each To time and plot the value of the coherency as a function of velocity and To time as shown in Fig. 6-3. The peaks in this plot can then be picked and a velocity function developed. The measure of coherency used is the semblance developed by Taner and Koehler, 1969. If the earth model is one of flat, horizontal layers, the velocities derived from the semblance plot can be considered to be RMS velocities, VRMS.In this case, VNMO and VRMS are approximately equal and stacking velocity is a good approximation to VRMS.The stack time approximates To. Interval velocities can then be computed from RMS velocities using Dix’s equation (Dix, 1939):

PRE-DRILL GEOPHYSICAL METHODS

161

VELOCITY (ftlsec) PEAK SEMBLANCE

~

::-

Fig. 6-3. Semblance plotted as a function of velocity and coincident shot to receiver time, To.

where the suffix j denotes the layer number and V, denotes the RMS velocity of that layer. These interval velocities are our best estimates from seismic for the desired rock velocities. It should be realized that seismic resolution is low so that the interval velocities computed in this way are averaged over thick layers in the subsurface. Therefore, these velocities will only approximate the velocities from sonic well logs. In addition, the stacking velocities obtained from semblance will deviate from RMS velocities in the presence of structure and in the presence of lateral variations in the subsurface, and we may be led to pick wrong semblance peaks due to the presence of faults, diffractions, sideswipe, multiples and other seismic noise. These limitations are discussed below in the velocity interpretation section.

6.3.2. The seismic method -processing In order to improve our ability to obtain high-quality velocity data it is necessary to process the seismic traces properly prior to computing the semblance data. The goal of processing is to enhance the signal-to-noise ratio, improve the resolution and remove ambiguities present in the data. The processing should: reject coherent noise, shorten the seismic wavelet, and correct for structural effects. Coherent noise can be defined as any undesirable component of the signal arriving at the receivers which has been generated by the source. This can include ground roll, air wave, multiples, mode conversions, and sideswipe. When these types of signals are present in the data and interfere with velocity estimation, they must be removed. There are various coherent filters which can be used to reject ground

162

TK. KAN A N D C.J. SICKING

roll and air waves. When these filters do not work we must use mutes, f-k filters and band pass filters. Multiples are generated between the surface boundary and the subsurface interfaces or between interbedded layered sequences. Many methods have been proposed for multiple removal. No one method is universally applicable. A method recently published by Hampson (1986) seems to be more useful than most. Multiples cause problems in velocity analysis because they can be erroneously picked as primary events in which case the estimated velocity will usually be low. In geologic sections characterized by abnormally pressured shales, the multiples may be the only arrivals in the shale zone and may be erroneously picked as primary events. It is very important to reject the multiples prior to velocity analysis. Figure 6-4 shows a velocity semblance spectrum without multiple rejection and the same velocity semblance spectrum with multiple rejection. We have higher confidence in the velocities picked from the semblance computed after multiple rejection. Mode-converted shear waves are generated at elastic boundaries. The incident compressional wave induces reflected and refracted compressional and shear wave secondary energy. Normally the shear wave events are weak relative to compressional wave events. However, there are cases in which the shear wave energy can have a large amplitude (Tatham and Stoffa, 1976). Converted energy will appear in STACKING VELOCITY (ftlsec)

STACKING VELOCITY (ftlsec)

0.5

k

- 1.0

-w

VELOCiTY 'FUNCTION

\-

-I

VELOCITY FUNCTION 10

I

0 (D 8

H t

1.5

15

2.c

20

Fig. 6-4. Semblance spectra computed before multiple rejection (a) and after multiple rejection (b). (From Cordier, 1985.)

PRE-DRILL GEOPHYSICAL METHODS

163

the semblance spectra the same as multiples. Sometimes, they can be rejected in the same process used for multiple removal. However, when the moveout on the converted wave approaches the moveout for the primaries it cannot be removed. In this case the semblance and the traces in the gather must be carefully and simultaneously examined in order to pick the correct velocity for the primaries. The changes in pore pressure which are computed from seismic velocities can be resolved only to the limits of the resolution in the seismic data. The primary purpose of deconvolution is to shorten the source wavelet which in turn improves the resolution. The wavelet estimated in the deconvolution process is the source pulse convolved with other effects such as ghosts and certain multiples. In general, this wavelet is very long. The deconvolution process attempts to estimate this very long wavelet and computes an operator which shortens it. Deconvolution is very important because geopressure can occur in intervals which are thinner than can be resolved in the semblance spectrum. The attenuation phenomenon has been extensively studied (e.g., Spencer, 1981; Murphy, 1982; Kan et al., 1984). Attenuation is frequency-dependent and causes greater loss of energy at the higher frequencies than at the low frequencies. After propagation through thousands of feet of rock, the seismic pulse broadens which decreases the resolution. In addition to the loss in amplitude and frequency content, attenuation causes velocity dispersion (Futterman, 1962). This causes disagreement between the velocities measured in different frequency bands such as seismic, sonic and laboratory. Wuenschel(l965) and Stewart et al. (1984) have reported that there are differences in travel times measured from VSP (10-50 Hz) and from sonic logs (15 kHz). In a case from Anadarko Basin, Oklahoma, Stewart et al. (1984) reported 7 ms of travel time difference per 1000 ft of propagation between the VSP and the sonic. Because sonic logs are commonly used to generate pressure versus velocity calibration curves, there may be a small bias in the pressures predicted using the velocities estimated from seismic due to the dispersion phenomenon. Bickle and Natarajan (1985) discuss the deconvolution process which compensates for anelastic attenuation. If proper attenuation compensation is applied to the seismic data, the amplitude and dispersion can be corrected before velocity estimation. Structure can cause the peaks in the semblance spectra to be biased toward higher or lower velocity due to the presence of dipping reflectors or lateral changes in overburden velocity. Diffractions from terminations along faults and other structures also cause anomalous peaks in the semblance spectra. Interfaces which dip cause velocities to be too high. Levin (1971) defined the apparent velocity, Va, for a dipping reflector in terms of true velocity V, dip 4, and inclination 8 (see Fig. 6-5): V va =

\/ci&EG

(6-9)

In the velocity analysis step we measure the apparent velocity and eq. 6-9 denotes the error in velocity as a function of dip. Levin calculated Va/V as a function of 4 and 8 (Fig. 6-6). From this figure we can see that for dips less than lo", the error

164

TK. KAN AND C.J. SICKING ORIENTATION OF SEISMIC PROFILE

Fig. 6-5. Illustration of the parameters @ and 0 used in eq. 9. (Modified after Levin, 1971.)

3.0

>

--..

3 1.o 90

60 30 0 (Degrees)

0

Fig. 6-6. V,/ V as a function of dip, @, for different values of inclination 8. (Modified after Levin, 1971.)

is negligible. However, this examination is for a single layer. When there are many layers and each layer has its own dip, the accumulative error can be large (Cordier, 1985). Recently, dip moveout (DMO) processing has been applied which corrects the data for structure (Deregowski, 1986). In addition to removing the structural imprint from the velocity estimation, DMO improves the imaging of the seismic section which provides for better interpretation of the faults and seals. A good understanding of the structure and lithology is crucial for predicting geopressure. Diffractions are generated by the seismic source energy being scattered from terminations such as an interface truncating against a fault. Diffractions generally have semblance peaks at higher velocities than the velocities for reflections at the same two-way travel time as shown in Fig. 6-7 taken from Aud (1979). The stacked section can be used to help identify diffractions. The DMO process corrects the diffractions so that they have the same moveout velocity as the primaries. When the velocity changes laterally in the overburden, the arrival times for the reflection events are not hyperbolic. When these changes are rapid, as in the case of an irregular weathered zone in the near surface, the arrival times can be erratic. This causes the peaks in the semblance spectrum to be dispersed. In modern seismic processing, statics corrections for the irregular topography and weathering layers

PRE-DRILL GEOPHYSICAL METHODS

165

AVERAGE VEUXITY (ftlsec)

0.0.

1.o

3.0.

4.0

Fig. 6-7. Semblance spectrum showing the faster velocities for diffraction arrivals. (From Aud, 1979.)

are carried out routinely. The short period or rapid changes in the near surface are corrected using residual statics programs (see for example Wiggins et al. 1976). The long-period static problems are corrected using refraction static programs. It is important that we correct the data for statics problems before trying to estimate the velocities. Even with good quality statics corrections, the problems due to statics continue to be some of the largest limitations on velocity measurement accuracy. 6.3.3. The seismic method - interpretation

This section could be entitled “How to avoid pitfalls and limitations when picking semblance data”, because interpretation of the semblance data is the most artistic and the most tedious step in the procedure for estimating accurate interval velocities. In order to prepare for picking velocities, one should review the available velocity information for the area. The sonic log data and check shot data from nearby wells will help establish a reasonable vertical velocity trend. The criteria for a good velocity function should include: lateral consistency between adjacent CMPs; reasonable vertical velocity trend; and meaningful interval velocities. The CMP spacing should be on the order of 80 to 100 ft (24-30 m) in order to insure that lateral consistency can be used to verify and constrain the picks. In order to efficiently pick the semblance data and compare the picks from one CMP to another, it is productive to have an interactive work station. An important point to keep in mind is that the semblance peaks do not always occur at true RMS velocities. The velocity picks must be adjusted away from the location of the peaks using knowledge and experience.

166

TK. KAN AND C.J. SICKING STACKING VELOCITY (f tlsec)

3';I

Peak Semblance

3.0Fig. 6-8. Semblance spectrum showing thick low-velocity zones.

Problems which may be encountered while picking the semblance spectra include: resolution, coherent noise, dip, diffractions, faults, sideswipe, lateral velocity anomalies, and lack of reflections. Anisotropy causes problems in obtaining accurate velocities but cannot be detected in the semblance data. Widess (1973, 1982) analyzed the resolution of the seismic system. The resolution is determined by the length of the wavelet in the data and the velocity of the rock layers. The length of the wavelet is dependent on the seismic source, area of recording and processing. Figure 6-8 shows three zones with low interval velocity at two-way times of 2.0, 2.24, and 2.44 s, respectively. These zones can be picked with confidence because they are thick and very slow. The semblance resolves separate reflections from the top and the bottom of the zones. In order to gain confidence in the picks, the semblance data from adjacent CDPs were examined. In this case the three zones are consistent over a large spatial distance. In order to resolve beds such as these, the beds must be at least a few hundred feet thick. A very thin bed can be resolved with confidence only at shallow depths where the bandwidth is very broad. Ground roll, air waves, multiples and converted waves can affect the quality and accuracy of the velocity analysis. It is important to try to remove these types of noise in processing. When they cannot be removed in processing, it is sometimes possible to use the lateral consistency criterion to correct the peak semblance data for these problems. If an interface is dipping, the velocity at which the peak semblance occurs is biased toward higher velocities. This bias is proportional to the dip. This error in

PRE-DRILL GEOPHYSICAL METHODS

167

STACKING VELOCITY (ftkec)

8*- E rc)

8

a-

3

Peak Semblance

3.0Fig. 6-9. Semblance spectrum showing the smearing due to a fault zone. The semblance peak is not laterally consistent with adjacent CMPs.

the RMS velocity must be corrected or the interval velocities both above and below the dipping horizon will be in error. In some cases, processing the CMP gathers (see Fig. 6-2) through dip moveout (DMO) prior to velocity analysis can help. In other cases, migration velocity analysis can resolve the problem. When dip is encountered and not corrected by DMO, the stacking velocities must be corrected in the interpretation step. Diffracted energy is common in seismic data. When energy from a strong diffractor is present in a CDP gather, the semblance peaks for the reflectors of interest can be misinterpreted. Again, DMO can be used to correct the diffractions. When a fault crosses the analysis point, anomalies in the semblance matrix will occur at the two-way time of the fault. Figures 6-9 and 6-10 show the semblance data for two CMPs separated along a seismic line by 164 ft. There is a peak in the semblance at 1.75 s and 5725 ft/s on both plots. A fault zone crosses these CMPs at 1.7 to 1.85 s and causes the smear in the semblance peaks observed in the plots. In Fig. 6-9 the peak in semblance due to the fault overlies and obscures the peak due to the primary reflection energy while in Fig. 6-10 the fault and the reflection peaks are separated. If the semblance data in Fig. 6-9 were analyzed in isolation, it is possible to pick two events in the semblance peak from 1.75 to 1.83 s. However, after analyzing the stacked section and semblance data from several adjacent CMPs, it becomes clear that this smeared peak in semblance is isolated to 3 CMPs and should not be given much confidence in the interpretation. The isolated semblance peak due to the primary reflector as shown in Fig. 6-10 is laterally consistent with other CMPs and is the correct interpretation of the data.

168

TK. KAN AND C.J. SICKING

STACKING VELOCITY (ftfsec)

8*-

to-l.!

Peak Ev 8d 3-7 Semblance m I

I

__ 3.0Fig. 6-10. Semblance spectrum for a CMP located 164 ft away from the CMP in Fig. 6-9. The primary reflector is well focussed and is laterally consistent with adjacent CMPs.

Sideswipe energy is that part of the energy which is reflected from structures such as salt domes or shale diapirs or from surface irregularities, and is received in a more or less horizontal direction. It arrives at the receivers from any azimuth and has anomalous moveout which can confuse the semblance picks for reflecting interfaces of interest. The moveout for sideswipe energy can range from very slow to very fast and, in general, it may not be possible to remove it from the data. Therefore, it is important to recognize it in the velocity picking step. The velocities obtained from parts of the line which are not contaminated can sometimes be used as a guide in interpreting the semblance. Figure 6-11 shows an example where the presence of sideswipe energy from the flank of a salt dome is evident and severely contaminates the CMP semblance data. In cases such as these, migration velocity analysis gives a much better estimate of the velocities. For additional discussions of migration velocity analysis, see Gonzalez-Serrano and Chon (1984), VerWest et al. (1985) and Sicking (1987). The pressure prediction based on seismic velocities assumes that any negative deviation from the velocity trend for normally compacted shales is due to undercompaction and is indicative of geopressure. Therefore, normally pressured low-velocity sands or coals will show up as high-pressure zones. It is important to recognize these differences. When the velocity data from the semblance plot in Fig. 6-8 is converted to pressure, the low-velocity zones indicate abnormally high pore pressure. While the bit did not penetrate these zones, a well was drilled within a few hundred feet. The available data indicate that the pressure predicted for the low-velocity zones is too high.

169

PRE-DRILL GEOPHYSICAL METHODS

CMP SEMBLANCE

MIGRATION VELOCITY SEMBLANCE

VELOCITY (Wsec)

VELOCITY (Wsec)

8 @

8 8

PEAK BSEMBLANCE

PEAK !SEMBLANCE

0.0

1.o

2.0

3.0 Fig. 6-11. CMP and migration velocity analysis semblance spectra for the same surface location. The velocity is easier to pick in the migration velocity semblance. (From Sicking, 1987.)

A lateral variation in the formation velocity which occurs above the zone of interest, perhaps due to a sand lens, structural wedge, or gas pocket, can cause erroneous velocity estimation. Static programs cannot correct for these anomalies. The magnitude of the error depends on the lateral velocity contrast as well as the separation in depth between the target zone and the lateral inhomogeneity. A simple two-dimensional model is illustrated in Fig. 6-12a where the weathering zone varies laterally in thickness. The NMO velocity for the target horizon is plotted in Fig. 6-12b along with the true average velocity as a function of spatial location. It is clear that the NMO velocity significantly deviates from the true RMS velocity. If we treat the stacking velocity as the RMS velocity, we would compute erroneous interval velocities. Lynn (1982) and Sherwood (1987) have discussed the problems associated with lateral velocity variations. Coons (1988) has combined refraction analysis with stacking velocity analysis to solve the problem of lateral velocity variation for an offshore Gulf of Mexico area. A case of lateral velocity changes in real data is shown in Figs. 6-13 and 6-14. Figure 6-13 shows the stacked section for a portion of a marine seismic line. Figure 6-14 (from Sicking, 1987) shows the stacking velocity along two horizons in Fig. 6-13. The upper horizon is just above the bright spot at 2.4 s, while the lower horizon is just below the bright spot. The bright spot has severe lateral velocity changes due to the presence of gas. It is clear

170

TK.KAN AND C.J. SICKING 200 ft.

ial

I

I

I

mf

t . 4

10,000 ft.

100 ft.

t

t-

t

9ooo ft./sec

14,000 ft./sec

17ob ft.

I 0

+ Distance klween source and receiver 1O.W ft.

(b)

10

18

42

I

I , I ' I ' I * I ' l ' I ' l ' I ' I

I

Fig. 6-12. (a) Model of a subsurface showing a thickening of the weathered zone. (b) Stacking velocity for reflectors A and B as a function of spatial location for the model in Fig. 6-12a. (From Prescott and Scanlan, 1971.)

that these lateral velocity changes have caused significant distortion in the stacking velocities for the lower horizon. If one were to interpret the semblance velocity for each CDP in isolation, the predictions for the zone below the bright spot would range between severely overcompacted to severely undercompacted depending on the spatial location. Therefore, it is necessary to look for lateral consistency in interpreting this type of data. Because geopressured zones typically occur in thick shales, there may be no interfaces to produce reflections. Figure 6-15 shows the semblance for a thick geopressure zone. There are no strong reflectors in this interval. The lack of reflectors also leads one to try to pick semblance peaks which may be due to multiples or converted waves. In Fig. 6-15 it would be very easy to pick anomalously low velocities in the pressure zone. However, when we look at the expected RMS velocity function (Fig. 6-16) which has been computed from the sonic log from the well at this location, it is clear that most of the semblance peaks within the geopressure zone in Fig. 6-15 are anomalous. Anisotropy has been discussed by Dunoyer de Segonzac and Laherrer (1959), Vander Stoep (1966) and others. Vander Stoep (1966) expressed the magnitude of apparent anisotropy in terms of an anisotropy factor, A , which is the ratio of the horizontal velocity to the vertical velocity. This ratio varies with lithology. Some estimates of A are given below for two wells in Northern Sahara (Dunoyer de Segonzac and Leherrer, 1959):

171

PRE-DRILL GEOPHYSICAL METHODS CMP

CMP

430490 WELL WELL 2-B 2-A

72001

LOWER

I

rZ2Oo

\-. I

!

'

6200 4 h

',!ii i

do

4 b

,

I

460 470 CMP NUMBER

I

I

480

490

I 1900

500

Fig. 6-14. Stacking velocity versus CMP for two horizons in the section shown in Fig. 6-13. The upper horizon is just above the bright spot at approximately2.4 s. The lower horizon is just below the bright spot at approximately 2.6 s. (From Sicking, 1987.)

Lithology

Anisotropy factor A

Salt Sandstones Limestones Anhydrites

1.O-1.05 1.0 1.08-1.12 1.15-1.20

In sedimentary rocks, A is greater than unity because of layer-induced apparent anisotropy and because of the layering within shales. When A is greater than unity, the travel times will be less than would be observed if anisotropy effects were not present. The presence of anisotropy produces a bias in the estimated seismic velocity

172

T.K. KAN AND C.J. SICKING

STACKING VELOCITY (ftlsec)

1.5-

6 2.0-

%

v

W

5.

F 2.5-

3.0-

Fig. 6-15. Semblance spectrum for a CMP over a thick geopressure zone located between 2.6 and 3.0 s.

VELOCITY (ftlsec)

m

7000

8ooo I

1500

2000

o

rn --I D

-I3 2500 3000

I800

2000

2200 2400 VELOCITY (rn/s)

2600

Fig. 6-16. RMS and interval velocity plot computed from sonic data from the well located at the CMP shown in Fig. 6-16.

PRE-DRILL GEOPHYSICAL METHODS

173

but will not necessarily affect the estimate of the magnitude of pore pressure. The bias in velocity introduces a systematic bias in the estimate of the depth to top of geopressure. For example, if anisotropy factor is three percent and the top of geopressure is at 10,000 ft (3048 m), the estimate would be 10,300 ft (3139 m). By using the sonic log from a nearby well, an apparent anisotropy correction factor can be derived. This will correct the depth estimates for the error due to anisotropy. In summary, velocity interpretation is critical to obtaining good-quality interval velocities and this requires much knowledge and experience. It is truly a problem of interpretation and not simply a problem of picking numerical values which are provided by a given algorithm.

6.4. PRESSURE CALIBRATION AND PRE-DRILL GEOPRESSURE DETECTION

The seismic method detects changes of interval velocity with depth from velocity analysis of the CMP seismic data. These changes are in turn related to lithology, pore fluid type and pressure changes within a stratigraphic column. In Fig. 6-17, modified after Sherif (1978), we show an example of compressional velocity data for various rock and fluid types. The velocity for each class of rock encompasses a fairly broad range and the velocities for the different classes of rock overlap. In order to infer subsurface lithology and pressure from seismic velocity one needs some independent knowledge of the lithology in a given area. In the clastic environment, such as in the Tertiary province of the Gulf of Mexico, or Niger Delta, the lithologic column of the sedimentary strata is generally composed of sands and shales. Due to compaction of the clastics, the interval velocity of these rocks increases with depth. However, there are anomalies in the trend of interval velocity versus depth in certain areas which coincide with the onset of zones of abnormally high pore pressures. An example of an anomaly or velocity reversal is shown in Fig. 6-18, taken from the work of Reynolds (1973). In this

RANGE OF V,

I

w

C X J

Sandstone

msxu

Limestone Dolomite Anhydrite

KxxXl

Rock Salt 1

0

4 8 12 16 20 VELOCITY (ftkec x 1ooO)

1

24

Gas

011

Fig. 6-17. Observed ranges of velocity data for various rock and fluid types.

174

TK. KAN AND C.J. SICKING

1-

- 305

2-

-610

-914

D

rn

-1219

; I

3

- 1524

- 1829 - 2134 - 2438

I

20

I

I1.1llll

I

1

I

405060 80100 200 400 At, INT. SONIC, bsedft)

I

I Ill1

€00800

Fig. 6-18. Comparison of seismically derived transit time plot with velocity data from a well. (From Reynolds, 1973.)

figure the log of the seismic interval transit times have been plotted versus depth. Velocities are abnormally low because the formations are undercompacted. The departure of the seismically derived interval transit times at a given depth from the normal trend line is a measure of the degree of geopressuring. While in practice the normal trend is taken to be linear, it has been shown by Chapman (1983, pp. 44-53) that the normal compaction trend cannot be linear even when plotted semi-log as in Fig. 6-18. When calibrated against available pressure data, the velocity departure curve is converted to pore pressure. This pressure calibration procedure has been used by the drilling engineers since the pioneering work by Hottman and Johnson (1965). Some examples of these calibration charts are given in Fig. 6-19 which is modified after the work of Reynolds (1973) and Nyein et al. (1977). As expected, such correlations differ in various basins throughout the world. The velocity-to-pressure calibration procedure outlined above assumes that the interval transit times are indicating effective stress and, therefore, compaction differences are due only to geopressure. In reality there are various factors which affect velocities of rocks. Pore fluid pressure is just one. Some examples of the factors affecting velocities of rocks are: rock and fluid types, effective stress, porosity, temperature, and geological age. In constructing normal compaction trend lines and interval transit times versus pressure curves, it is essential that the interpreter account for the above factors and be reasonably assured that the observed velocity anomalies are indicative of pressure changes.

175

PRE-DRILL GEOPHYSICAL METHODS

04

I

I

E 0.5

I

I I I I SONIC LOG DEPARTURE VERSUS FORMATION PRESSURE GRADIENT (TERTIARY BASINS)

-g 1

-10

....

v)

P, I-

z

-11

; 0

-12

3

06

wn

2-

w

n 3 -13 I c -14

v)

-152

4.

g 07 CL: 3

-I

Q

g-j 0 8 a:

3

- 16

a

2

09

I I I 30 40 50 AIOBSERVED - AtNORMAL ps/ft

I 60

I 20

I 10

0

70

Fig. 6-19. Acoustic log transit time departure versus fluid pressure gradient for various basins. (Modified after Reynolds, 1973; Nyein et al., 1977.)

-

12

g

16

\

'I 24I1 6

/TOP

1

L

8

10

HAYNESVILLE

14877

I b

12

14

16

18

I-".?

'IJIJ

20

INTERVAL VELOCITY x loo0 (ft/S€C)

Fig. 6-20. Interpreted velocity analysis for a southern Mississippi prospect shows the effect of lithology change. Without knowledge of well site lithology, overpressure trends can be distorted. (From Reynolds e t al., 1971.)

An example is shown in Fig. 6-20 which is taken from Reynolds et al. (1971). This

figure clearly demonstrates that the observed decrease in the interval velocity at the base of the Smackover interval (carbonate grainstones) and the onset of Norphlet sandstone is due not to the pressure but to the lithologic change. It has been mentioned earlier that abnormally high pore pressure implies abnormally low effective stress and high porosity both of which lower velocity. However, in interpreting velocity from seismic or sonic log data, we usually ignore the effect

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of stress on the rock matrix. In most cases higher than normal porosity provides the overriding effect while matrix stress assumes a secondary role. This may not be true in “hard” geopressure formations where the pore fluid pressure approaches the overburden stress due to the lithostatic column. Most of the preceding discussion was limited to sand-shale sequences. The velocity analysis technique discussed in Section 3 is valid without regard to the rock types. Abnormally high pore pressures occur both in carbonate and clastic sequences (Mostofi and Gansser, 1957; Parker, 1974). In carbonate sequences, especially evaporites, pore pressures can rise very abruptly because these rocks form very effective seals. In carbonate environments there is no transition zone between the hydrostatic and geopressure zones as is normally found in clastic environments. 6.4.1. Case studies

Several examples of the use of seismic velocities in predicting geopressure in clastics are presented here. One of the most significant advantages of using seismic velocity is that it can produce a 2-D cross-section of geopressure. This allows for the mapping of geopressure away from a borehole and can be indispensable in planning deviated boreholes. The first example of using seismic to estimate geopressure is for an area in the offshore, U.S. Gulf of Mexico. The clastic sediments in this area are known to be high-porosity, poorly consolidated and of Upper Pliocene age. In Fig. 6-21 we show a stacked section of the seismic data. The location of the well control (well A) is indicated. The seismic velocity analyses were carried out on this line and tied to the well control at the indicated CDP location. The available well log data from well A was used to construct a “normal” compaction trend and checked for consistency with other available trends in that area. The normal compaction trend was used in conjunction with the seismic interval velocity at the well location to predict the pore pressure gradient versus depth shown by the heavy line in Fig. 6-22. The other line in the figure, marked mud weight, shows the driller’s choice of the mud equivalent of “true” formation pressure used in the well. The comparison is good. The predicted values are within 10% of the actual mud weights. This method was used to predict pore pressure in a well from another block which is located to the right of Fig. 6-21 in the southeast direction. The location is more than 3.5 miles from well A. Surface seismic data, the “normal” compaction trend for the shales of Fig. 6-22 derived from well A, and a pressure calibration curve valid for the Pliocene area were used to predict fluid pressure as a function of depth. The predicted results are shown in Fig. 6-23 and compared with the actual mud weights used in drilling the well. The predicted pressures from seismic velocity analysis are within 7% of the actual mud weights. In the second example illustrating this procedure, we show another case from the offshore Gulf of Mexico area. The stacked seismic section is shown in Fig. 6-13. There are two wells on the seismic line as indicated. The distance between the two wells is about 2500 ft (762 m). The target horizon is indicated and it contains hydrocarbons. In well 2-A, the driller encountered hard geopressure below the

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target horizon and used 16 lb/gal (18.80 kN/m3) mud weight to complete the well. In well 2-B, pore pressure was much lower and the maximum mud weight used was only 14 lb/gal (16.45 kN/m3). Following the velocity analysis procedure discussed in the previous section, a high-density 2-D interval velocity cross-section, shown in Fig 6-24, was generated. The analysis was performed every 80 ft (24 m) and it

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shows both lateral and vertical velocity variations. A normal compaction trend was constructed from well 2-A. A pressure calibration relationship was also established using pressure information from well 2-A. Using the method outlined above, the 2-D pore pressure gradient (seis-pressure) cross-section is shown in Fig. 6-25. The color scale ranges from 9 lb/gal (10.58 kN/m3) (blue) to 16 lb/gal (18.80 kN/m3) (red). As shown on this figure, the abnormal pressure zone below the target horizon is not laterally continuous. This is probably because the locally deposited massive shale bodies are not laterally continuous. The well data shows that there is more sand under the target horizon at well 2-B. Above the target horizon, the figure shows differential compaction along the line. The fault closer to well 2-A could possibly serve as a conduit and provide a plumbing system for drainage of the fluids in sediments. There is a rapid lateral variation in pore pressure gradient below the target. Because of this kind of lateral variation, a pre-drill prediction of the 2-D pressure profile is essential to completing the wells, especially if the wellbore path is deviated. Using a velocity-density relationship appropriate for the area, an effective stress versus depth cross-section was also computed and displayed in Fig. 6-26. The zone of low effective stress is quite obvious. This information is important to investigating the problems associated with wellbore mechanics. Geopressure prediction using continuous interval velocity analysis is becoming routine with the advent of various workstations which facilitate velocity picking over close intervals. An example of a true amplitude stacked section from a data set in Niger Delta (Bilgeri and Ademeno, 1982) together with seismoacoustic facies interpretation is shown in Fig. 6-27. In Fig. 6-27b, the deflections to the right correspond to high-velocity layers (interpreted as sands), while those to the

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T K . KAN AND C.J. SICKING

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left correspond to low-velocity layers (interpreted as shales). This is verified by comparison of borehole data and seismic acoustic logs (Lavergne, 1975; Lindseth, 1978). In Fig. 6-28, continuous logs of absolute to hydrostatic pressure ratios and 2-D formation pressure logs versus time are shown for the same data set. 6.4.2. VSP

While the primary application of VSP has been the integration of surface seismic with borehole data, it should be possible to record VSP data while drilling and use the reflection amplitude data to predict the depth to horizons and the velocity profile below the bottom of the well. This would give the driller dynamic look ahead of drilling capability. Using a seismic data analysis procedure called inversion, the VSP reflection amplitude data can be converted to interval velocity. The result is calibrated using the depth interval which overlaps a zone of the well which has been logged. This analysis is primarily valuable in identifying the depth to potentially highly permeable sands located within geopressure. Large-amplitude reflections can be identified and their depth predicted as much as 1000 ft ahead of drilling. An example of predicting ahead of drilling is shown in Fig. 6-29. A VSP was recorded in well number 2 over the depth interval 5510-8210 ft. The T D of the well was 8210 ft. The interval transit times derived from the VSP are shown in the right hand track of Fig. 6-29. The zone below 8210 ft is looking below the bottom of the well. Well number 1was drilled to a depth of 9500 ft from the same platform as well

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181

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number 2 such that the well separation is 700 ft at a depth of 8500 ft. The interval transit time from the VSP in well number 2 is plotted on the top of the interval transit time from the sonic log from well number 1 in the middle track of Fig. 6-29. Below 8210 ft there is a clear increase in transit time (decrease in velocity) which indicates geopressure. There is a lithology change at 8750 ft which can be identified on the well logs from well number 1. There is also a large-amplitude event in the look ahead VSP data at this depth. In comparing the VSP data from well number 2 to the sonic data from well number 1 there are three zones of interest. First, there is a discrepancy in the depth interval from 8000 to 8300 ft. The discrepancy over this interval is also present between the sonic from well number 2 and the VSP data and is probably due to borehole effects in porous sands at this depth. Because the VSP velocity is slower than the sonic velocity, the zone is probably invaded. Second, the depth interval from 8300 to 8750 ft shows good agreement between the sonic and the VSP. Third, there is a discrepancy in the depth interval from 8750 to 9500 ft. This interval is below the lithology change at 8750 ft. The sonic shows a large increase in transit time (decrease in velocity) in this zone which would indicate a significant increase in geopressure. The VSP data does not show the correct magnitude of this increase in transit time. In summary, in predicting ahead of the drilling the VSP data does show the event due to the lithology change and

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does show a velocity slowdown which would indicate the presence of geopressure. However, due to lack of low-frequency information, the velocity trend indicated by the VSP data would not give an accurate prediction of the magnitude of the geopressure.

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6.5. NON-SEISMIC GEOPHYSICAL TECHNIQUES FOR GEOPRESSURE PREDICTION

6.5.1. Gravity analysis Among the non-seismic geophysical techniques, the gravity method holds the most potential for use in geopressure prediction. Because geopressured shales are characterized by low bulk density, it is sometimes possible to detect massive geopressured shales from surface gravity measurements. For geopressured shales, bulk mass densities typically range between 2100 and 2300 km/m3 (see McCulloh, 1967) and therefore, gravity anomalies in thick shale masses are detectable. The magnitude of the Bouguer gravity anomaly is directly proportional to the size of the mass and the contrast in density between the disturbing mass (for example, geopressured shales or salt) and its surroundings. Tsimelzon (1959) and Musgrave and Hicks (1966) discuss the use of gravity surveys in detecting massive undercompacted shale zones which lie below normally compacted stratigraphic units. Musgrave and Hicks (1966) used refraction surveys along with the gravity data to distinguish between salt and geopressured shale masses. The gravity method was used to outline the low-density material and the refraction method was used to indicate the velocity differences between salt (typical velocity of 15,000 ft/s, 4572 m/s) and shales (velocity range of 7000-9000 ft/s, 2134-2743 m/s). For all of the potential of the gravity method for geopressure prediction, the method is inherently low resolution. In the design of casing and mud programs it is important to know the magnitude of pore pressure as a function of depth. The gravity method can at best supply only an inaccurate estimate of the depth to the top of a hard geopressure zone. In areas where geopressure is wide spread and not limited to isolated bodies, the method has little chance of detecting geopressure. In many offshore areas, the top of geopressure is transitional over thousands of feet. The gravity method cannot predict this. For all of these reasons, the gravity method is not extensively used for geopressure prediction.

6.5.2. Other geophysical methods Geophysical methods other than seismic and gravity, such as magnetics and possibly electrical, are not very useful in predicting geopressures before drilling. These methods suffer from low resolution and their use beyond shallow targets remains to be seen. Not much use is made of these methods today.

6.6. SUMMARY

As noted by Reynolds (1970) and Fertl (1976), proper interpretation of seismic data can predict the top of geopressures to within plus or minus 500 ft (150 m), and pore pressure magnitudes can be estimated to within plus or minus 1.0 lb/gal (1.18 kN/m3) mud weight equivalent in more than 50% of field cases studied. The power of the surface seismic technique in locating and predicting geopressures is well documented in the geophysical community. Routine integration of seismic

PRE-DRILL GEOPHYSICAL METHODS

185

data with other available data at the well planning stage is important. In addition, because geopressuring is a stratigraphic phenomenon, the seismic processors should pay special attention to preserving and extracting maximum information about stratigraphy from the seismic data if they expect their velocity analyses to be useful for geopressure prediction. Finally, seismic velocity analysis must be guided by interpreters. In other words, there should be “interpretive velocity analysis” so that seismic data processors and interpreters work together. Interpretive analysis is critically important for geopressure detection because not every velocity anomaly results from overpressuring, nor is it unambiguously indicative of subsurface lithology. It is possible that we could make more use of surface seismic data in pore pressure prediction work. We could combine velocity and amplitude analysis (e.g. seismic log) in detecting and measuring the extent of geopressures. In addition, it is possible that the attenuation of seismic waves in shales could help stratigraphic and lithologic evaluations. By combining seismic attenuation coefficients and interval velocities, some of the interpretational ambiguities could possibly be removed. Much work needs to be done in this area.

REFERENCES Aud, B.W., 1979. Seismic velocity data usage for prediction of zones of abnormal pressure and relative lithology. Sociev of Exploration Geophysicists Continuing Education Program. Bickle, S.H. and Natarajan, R.R., 1985. Plane-wave Q deconvolution. Geophysics, 50 (9): 1426-1439. Bilgeri, D. and Ademeno, E.B., 1982. Prediction abnormally pressured sedimentary rocks. Geophys. Prospect., 30 (5): 608-621. Chapman, R.E., 1983. Petroleum Geology. Elsevier, Amsterdam, 415 pp. Coons, R., 1988. Prestack interpretation for depth mapping. Geophysics: The leading edge of exploration, 7(4): 16-22. Cordier, J.P., 1985. Velocities in Reflecfion Seismology. D. Reidel, Boston, Mass., 201 pp. Deregowski, S.M., 1986. What is DMO? First Break, 4 (7): 7-23. D k , C.H., 1939. Interpretation of well shot data 1. Geophysics, 4(1): 24-32. Dunoyer de Segonzac, P. and Leherrer, J., 1959. Application of the continuous velocity log to anisotropy measurements in Northern Sahara; results and consequences. Geophys. Prospect., 7 (2): 202-217. Fertl, W.H., 1976. Abnormal Formation Pressure. Elsevier, Amsterdam, 382 pp. Futterman, W.L., 1962. Dispersive body waves. J. Geophys. Res., 67 (13): 5257-5291. Gonzalez-Serrano, A. and Chon, Y., 1984. Migration velocity analysis in 3D. Presented at the 54th Annual SEG Meeting, Atlanta, Ga., 2-6 December. Hampson, D., 1986. Inverse velocity stacking for multiple elimination. Presented at the 56th Annual Meeting of the SEG, Houston, Texas, 2-6 November. Hottman, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., 17 (June): 717-722. Kan, TK., Corrigan, D. and Huddleston, P.D., 1984. Attenuation measurement from vertical seismic profiling. In: M. Nofi Toksoz and R.R. Stewart (Editors), Handbook of Geophysical Explomtion, Vol. 14B. Vertical Seismic Profiling. Geophysical Press, London, pp. 338-350. Lavergne, M., 1975. Pseudo-diagraphics de vitesse en offshore profond. Geophys. Pospect., 23 (4): 695-711. Levin, F.K., 1971. Apparent velocity for dipping interface reflections. Geophysics, 36 (3): 510-516. Lindseth, R.O., 1978. Synthetic sonic logs - a process for stratigraphic interpretation. Geophysics, 44 (1): 3-26.

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Lynn, W.S.,1982.VelociQ Estimation in Laterally Varying Media. Ph.D. Dissertation, Stanford University, Palo Alto, Calif., 79 pp. McCulloh, T.H., 1967.Mass properties of sedimentary rocks and gravimetric effects of petroleum and natural gas reservoirs. US.Geol. Sum, Prof Pap., 528-A, 50 pp. Mostofi, B. and Gansser, A., 1957.The story behind the 5 Alborz. Oil Gas J., 55 (3):78-84. Murphy, W.F. 111, 1982.Effects of partial water saturation on attenuation in sandstones. J. Acoustic SOC. Am., 71: 1458-1468. Musgrave, A.W. and Hicks, W.G., 1966.Outlining of shale masses by geophysical methods. Geophysics, 31 (4): 711-725. Nyein, R.K., Maclean, L. and Waroris, B.J., 1977.Occurrence, prediction and control of geopressures on the Northwest shelf of Australia. 1.Aust. Pet. Eiplol: Assoc., 17 (1): 64-70. Parker, C.A., 1974. Geopressures and secondary porosity in deep Jurassic of Mississippi. Bull., Am. Assoc. Pet. GeoL, 58 (10): 2212. Pennebaker, E.S., 1968. Seismic data indicate depth, magnitude of abnormal pressure. World Oil, 166(7): 73-78. Prescott, M. and Scanlan, A.J., 1971. Effects of weathering on derived velocities. Presented at the 41st Annual SEG Meeting, Houston, Texas, 7-1 1 November. Reynolds, E.B., 1970. Predicting overpressured zones with seismic data, World Oil, 171 (5): 78-82. Reynolds, E.B., 1973.The application of seismic techniques to drilling techniques. SPE 4643, 48th AIME Fall Meeting, Las Vegas, Nev., October. Reynolds, E.B., May, J.E. and Klaveness, A., 1971. Geophysical aspects of abnormal fluid pressures. In: Abnormal Subsurface Pressure, A Study Group Report 1969-1971. Houston Geological Society, Houston, Texas, pp. 31-47. Sherif, R.E., 1978.A First Course in Geophysical Exploration and Interpretation. International Human Resources Development Corporation, Boston, Ma. Shenvood, J.W.C., 1987.Invited Introductory paper to statics and velocity analysis. Presented at 57th Annual SEG Meeting, New Orleans, La., 11-15 October. Sicking, C.J., 1987. Diffraction semblance for velocity and structure analysis. Presented at the 57th Annual SEG Meeting, New Orleans, La., 11-15 October. Spencer, J.W., Jr., 1981.Stress relaxations at low frequencies in fluid-saturated rocks: attenuation and modules dispersion. J. Geophys. Rex, 86 (B3): 1803-1812. Stewart, R.R., Huddleston, P.D. and Kan, 'KK., 1984.Seismic versus sonic velocities - a vertical seismic profiling study. Geophysics, 49 (8): 1153-1168. Taner, M.H. and Koehler, F., 1969.Velocity spectra - digital computer derivation and applications of velocity functions. Geophysics, 34 (6):859-881. Tatham, R.H. and Stoffa, P.L., 1976. Vp/Vs - a potential hydrocarbon indicator. Geophysics, 41 ( 5 ) : 837-849. Tsimelzon, I.O., 1959.The relationship between local gravitational anomalies and the tectonics of gas and oil bearing regions. IN. Vyssh. Zaved., Neft'i Gaz, 8: 13-16. Vander Stoep, D.M., 1966.Velocity anisotropy measurements in wells. Geophysics, 31 (5): 900-916. VerWest, B.J., Sun, J.C. and Carayannopoulos, N.L., 1985. Relation between velocity fields and imaging in the presence of lateral velocity variations. Presented at the 55th Annual SEG Meeting, Washington, D.C., 6-10 October. Widess, M.B., 1973.How thin is a thin bed? Geophysics, 38(6): 1176-1180. Widess, M.B., 1982.Quantifying resolving power of seismic systems. Geophysics, 47 (8): 1160-1173. Wiggins, R.A., Lamer, K.L. and Wisecup, R.D., 1976. Residual statics analysis as a general linear inverse problem. Geophysics, 41 (5): 922-938. Woeber, A.F. and Penhollow, J.O., 1973.The accuracy of depth predictions from velocity profiles on the Texas Gulf Coast. Presented at the 43rd Annual SEG Meeting, Mexico City, 21-25 October. Wuenschel, P.S., 1965.Dispersive bodywaves - an experimental study. Geophysics, 30 (4): 539-551.

Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 0 1994 Elsevier Science B.V. All rights reserved

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Chapter 7

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE E.L. BIGELOW

7.1. INTRODUCIION

Several well logging services can be utilized to detect, or at least infer, the presence of abnormal pressures. The primary attributes of using well log data are that depths are recorded simultaneously with other measurements, and at least some of the log data encompasses most of the borehole length. Today, log data is not only recorded by wireline methods, but also while drilling (MWD) and soon after drilling (MAD). Wireline logs must be considered an “after-thefact” technique, but nevertheless provide valuable information for future drilling programs. The following log measurements are used to detect abnormally high formation pressures. - Acoustic measurements of the compressional, shear, and Stoneley arrivals in terms of interval transit time. - Bulk density measurements are useful provided the borehole condition is reasonably in-gauge and good pad-to-wall contact is obtained. - Neutron measurements are useful where lithology and borehole conditions permit. -Resistivity data from various shallow reading devices such as short normal, focused laterolog devices, and spherically focused logs, or conductivity measurements from deep induction devices, and on occasion dielectric data. - Spontaneous Potential (SP) is informative when conditions permit adequate measurement resolution. - The shale formation factor method also provides suitable identification of the normal compaction trends and the onset of abnormal pressured regimes by a departure from the normal. - Magnetic resonance Zogging has been used to determine the rate of fluid flow in overpressured shales. - Borehole gravity data measures the bulk density of a large volume of formation surrounding the wellbore. -Pulsed neutron methods are applicable for cased wellbores. MWD and MAD measurements currently available include resistivity (both electrode and low-frequency dielectric methods) gamma ray, neutron and bulk density. Neutron availability is offered by several contractors, but density availability is very limited. MWD acoustic methods are in the research and development stage of a few contractors. Some limited success has been achieved with a seismic-while-drilling (Tomex) technique, generally in soft rock environments. For detection of abnormal pressure, MWD or MAD resistivity data can be used in the same manner as that

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which will be described for wireline resistivity. But, MWD offers the ability to detect impending pressure problems during the drilling process, and warn operators that proper action must be taken immediately. For abnormal pressure detection, the important log information is represented by recordings in shale formations (exception: SP). The log data is plotted versus depth. Trend lines of the log data are established through various shale formations along the trajectory of recorded borehole depth. The normal trend is interpreted as being representative of normal overburden cornpaction. The shape and slope of particular trend lines are often characteristic of certain formations over an entire geological region, but on occasion may be representative of smaller features, e.g., a single field or single fault block. Interpretation of abnormal pressures uses the log data from shale intervals plotted versus depth as the normal trend, to determine where departures from those trends occur. The degree of abnormality is believed to be dependent on the amount of divergence of formation pore pressure from the hydrostatic pore pressure that causes the normal trend. Interpretation is often straightforward, but complications arise periodically. Some particular complications are: (1) drastic changes in lithology; (2) changes in geological age; (3) enlarged or rugose borehole effects; (4)steeply dipping formations; ( 5 ) very thin beds; ( 6 ) nearness to salt domes or other intrusives; (7) malfunctioning logging equipment. These limitations and pitfalls will be discussed later in the chapter.

7.2. ACOUSTIC METHODS

The acoustic methods are probably the best log measurements to do any quantitative pressure evaluation because this type of log measurement is usually less affected by borehole size, formation temperature, or formation water salinity. Nevertheless, recorded interval transit time in a given formation is a function of several parameters; namely, the degree of compaction, the type and amount of porosity, type and amount of fluid content, and the lithology. The basic principle of an acoustic (sonic) logging device is the transmission of a sound pulse that is recorded at receivers placed at fixed distances away from the transmitter(s). The elastic waves created by the sound pulse travel through the borehole fluid to the wall of the borehole where they are refracted through the formation, and back through the fluid to the different receivers. The log was originally developed as a method to tie measured borehole depths of particular horizons to surface seismic for use as a depth-to-time control. Later, the log was found to be useful for porosity, lithology, and fluid determination. The elastic wave logs are also used in cased hole for cement evaluation purposes (Bigelow, 1990). The time required for the transmitted signal to travel its path to the receiver(s) is called travel time, and by making a measurement of the differences between its arrival at two or more receivers, an interval transit time can be determined. These measurements are generally recorded in microseconds (ps) per foot or meter. The total waveform can also be recorded; i.e., all the pulses that occur after the first

189

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arrivals until the system is momentarily switched off prior to the next firing of the transmitter. Waveforms, or a modulated z-axis presentation known as a variable density display, are recorded with many of today's acoustic logging tools (Fig. 7-1). Interval transit time is the reciprocal of wave velocity (generally measured in ft/s or m/s): At (ps/ft or m) = 1, 000, OOO/ V (ft/s or m/s)

In any formation, the acoustic measurement is dependent on lithology, type of fluid occupying pores, amount of porosity including porosity type, and the degree of sediment compaction. The log can be recorded in any type of drilling fluid. It is much less affected by hole size irregularities, temperature, and water salinities than most other log types. However, cycle-skippingoften occurs in gas-cut drilling fluid. Evaluation of formation pressure requires a semilog plot of At versus depth, with the data preferably from shale beds only. Environments of normal pressure will display a trend line that relates to normal compaction (Hottman and Johnson, 1965), and each borehole will characteristically display such a trend (Fig. 7-2). Although the trend of normal compaction cannot be strictly linear when log At

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Fig. 7-2. Plot of depth versus acoustic transit time in shale formations of the upper coastal area of the U.S. Gulf Coast (after Hottman and Johnson, 1965). Courtesy of the Society of Petroleum Engineers.

is plotted against depth (see Chapter 3, p. 62), it is commonly sufficiently close. Pressure anomalies can be detected by an increase in At values above the gradient observed as normal. The deflected data is accepted as being caused by a significant increase in the size of shale pores due to the abnormally high pressures, as demonstrated (Fig. 7-3). Several methods have been applied to pressure evaluation with acoustic data; the two most common are discussed here. The shale transit time (At) is plotted versus depth in either method. 7.2.1. MethodA

(1) Establish the normal compaction trend from the semilog plot of At vs. depth. (2) The top of the pressure anomaly is selected at the depth where the plotted data points diverge from the normal trend. (3) The At values from the normal gradient (Atnor)and the observed abnormal pressure trend (Atat,,,) are extended downward to the At time scale at the bottom of the chart (Fig. 7-4). (4) The log relationship between the acoustic parameter differences (Atat," Atnor)is then found (Fig. 7-5). ( 5 ) The fluid pressure gradient (FPG) is then multiplied by the corresponding depth to obtain the formation pressure. A pressure gradient profile can then be constructed for that particular well. The relationship between the shale transit time values ( A h n - Atnor) and FPG for Miocene and Oligocene formations along the U.S. Gulf Coast is shown (Fig. 7-5). Input data is collected and used to establish this empirical relationship (Table 7-1). The standard deviation from the average trend line representing the

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE SP curve

191

Transit ttm A t

Fig. 7-3. Acoustic log response across an overpressured zone (modified after Matthews, 1971). The numbers represent acoustic transit time values in pslft.

E

1

Fig. 7-4. Plot of depth versus acoustic transit time in shale formations (after Hottman and Johnson, 1965). Courtesy of Journal of Petrolewn Technology.

192

E.L. BIGELOW

0400 0500 t

: 0.600 -

loo

a

4

2

12.0

Ti cn

c

% 0

0700

J

140

LL

. D

c

E L

L

C

'6 OBOO > L u

u

160

:0900

K

j -J 0

la0

1000

0 2 0 4 0 6 0

% b ~ s n ~ - A tn,snlr pl- /ft

Fig. 7-5. Relationship between fluid pressure gradient (FPG) and the shale acoustic parameter difference (At,,, - At,bn) (after Hottman and Johnson, 1965). Courtesy of J o u m l of Petroleum Technology. TABLE7-1 Formation pressure and acoustic log data in overpressured Miocene/Oligocene shales of the U S . Gulf Coast area (after Hottrnan and Johnson, 1965) Parish or County and State

Terrabonne, La. Offsh. Lafourche, La. Assumption, La. Offsh. Vermilion, La. Offsh. Terrebonne, La. East Baton Rouge, La. St Martin, La. Offsh. St Mary, La. Calcasieu, La. Offsh. St Mary, La. Offsh. St Mary, La. Offsh. Plaquenines, La. Cameron, La. Cameron, La. Jefferson, Texas Terrebonne, La. Offsh. Galveston, Texas Chambers, Texas

Well Depth

1 2 3

4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Pressure

Fluid pressure gradient

Shale Atobs

- Atn

(m)

(ft)

(MPa) (psi)

(kPa/m) (psi/ft) (psIm) (pslft)

4 080 3 353 3 298 3 627 3 998 3 347 3 505 4 069 3 597 3 965 4 214 2 705 3 388 3 485 3 319 3 368 3 581 3 682

13,387 11,000 10,820 11,900 13,118 10,980 11,500 13,350 11,800 13,010 13,825 8,874 11,115 11,435 10,890 11,050 11,750 12,080

80.30 47.02 61.17 68.92 77.78 55.26 42.82 79.16 45.56 75.35 87.69 36.71 67.44 77.86 68.33 61.71 78.59 64.96

19.68 14.02 18.55 19.00 19.45 16.51 12.22 19.45 12.67 19.00 20.81 13.57 19.91 20.36 20.58 18.32 21.94 17.64

11,647 6,820 8,872 9,996 11,281 8,015 6,210 11,481 6,608 10,928 12,719 5,324 9,781 11,292 9,910 8,951 11,398 9,422

0.87 0.62 0.82 0.84 0.86 0.73 0.54 0.86 0.56 0.84 0.92 0.60 0.88 0.90 0.91 0.81 0.97 0.78

72 30 69 89 89 43 13 98 23 75 108 16 105 125 128 69 184 59

22 9 21 27 27 13 4 30 7 23 33 5 32 38 39 21 56 18

data points was 0.020 psi (0.45 kPa/m). As required of any log data in any given area, pressure evaluation efforts must first develop calibration charts €or different geographical and geological settings (e.g., the North Sea vs. South China Sea, etc.).

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

193

1

2

E

Y

3 5 Q

a,

n

4

5

Fig. 7-6.Plot of acoustic transit time in shales versus depth is applied as an equivalent depth method to quantify pressures. Casing points and mud weight requirements are also given.

In a US. Gulf Coast well, this method used an observed 30 ps/ft difference in Atabn and At,,, that resulted in a FPG of 0.882 psi/ft (19.95 kPa/m). As indicated

by the depth (Fig. 7-6), a pressure of 13,100 psi (90.3 MPa). Maximum mud weight used in the well was 17.1 lb/gal(20.1 kN/m3). 7.2.2. Method B

The equivalent depth technique is another approach to quantitative pressure evaluation. This method is based on the following mathematical relationship, and is valid for several log measurements, including shale At, shale resistivity, shale conductivity, shale density, etc. The technique includes the following steps: (1) Plot the Atshale values vs. depth, and establish the normal compaction trend line (A&). (2) Determine the formation pressure from:

194

E.L. BIGELOW

Pi = Go x DA - DE(G,- GH)

Pi = D A - 0.535 x D E where Pf = formation pressure (psi); DA = depth of interest in the abnormal pressure environment (ft); D E = normal pressure gradient, in equivalent depth corresponding to DA (ft); GH = hydrostatic pressure gradient (psi/ft) The hydrostatic pressure gradient can vary from one geographical and/or geological province to another. As an example, hydrostatic pressure gradient for the U.S. Gulf Coast is generally taken as 0.465 psi/ft (10.31 kPa/m) for salt water, and the brackish to fresh waters of the Rocky Mountains and Mid-Continent (USA) generally use 0.433 psi/ft (9.8 kPa/m). The concept of variable overburden gradient requires area data. Oftentimes a constant overburden gradient of 1.0 psi/ft (corresponding to an average bulk mass density of 2308 kg/m3) is a satisfactory assumption. The first of the above equations holds true for normal, hydrostatic pressure environments, because D = D A = DE.This permits the equation to be simplified as: &(psi) = G H D After constructing the normal compaction trend for a given area, it is relatively easy to construct a pressure evaluation chart for the set conditions. This especially holds true for any Tertiary basin in the world. A nomogram for south Louisiana (USA) was created from such a set of conditions (Ham, 1966). The grid at the bottom of the chart permits shifts in the At scale to account for local conditions, i.e., geological age, etc. To use the chart, several points representative of shale Atnor values are plotted (Fig. 7-7). These data are used to determine which baseline of the chart should be used for formation pressure determination (e.g., a, b, 0, c, or d). If a A? value of 132 pslft is recorded in a shale bed at a depth of 12,500 ft (3811 m), the 132 value is used to enter the chart on the O-scale of the lower nomograph. From that point, a line can be projected upward to the intersection with a line projected to the right from the 12,500 ft (3811 m) point on the y-axis of the chart. The indicated formation pressure should be 10,200 psi (70.3 MPa). The mud weight necessary to balance the formation pressure is read from the chart as 15.8 lb/gal(l8.6 kN/m3). 7.2.3. More recent depth of burial

Profiles of the acoustic At versus depth profiles can also be utilized for wellto-well correlations to study regional tectonics (Bigelow, 1985). In basins where faulting and upheaval are prevalent, such studies add support to seismic and dipmeter analyses. It is fortunate that diagenesis imparts physical changes primarily to shale beds. When such plots have been used to study abnormal pressures, they are readily available for well-to-well correlations over extensive areas. The method is very helpful in determining if a more recent depth of burial has occurred because of uplift and erosion. An example of four wells from the Far East is used to demonstrate the method (Fig. 7-8).

WELL LOGGING METHODS TO D E T E n ABNORMAL PRESSURE

195

Fig. 7-7. Nomograph for estimating formation pressure from sonic logs in the U.S. Gulf Coast area (after Ham, 1966).

In the subject area, normal vertical sections demonstrate At,h = 100 ps/ft at about 8300 ft (2767 m) depth, as observed on Well 4. From that point upward, a consistent normai gradient generally occurs. Note that similar normal grudients occur in Wells 2 and 3, but the 100 ps value is read at considerably different depths: 4000 ft and 7500 ft, respectively (1333 and 2500 m). It is possible to take segments with similar trends from Wells 2,3, and 4 and construct a composite that represents a type compaction gradient that is representative of the area under study. Well 1 was the deepest well in the area, and displayed the most complete compaction data. Note how the type gradient on the right conforms to Well 1. The depth difference between interval C on Well 2 and interval C on the composite is approximately 5900 ft (1967 m), while interval B on Well 3 and interval B on the composite differ by only 800 ft (267 m). This suggests a large amount of uplift in the vicinity of Well 2, and a comparatively smaller amount of uplift in the area of Well 3. Seismic reflectors and dipmeter data showed correlative indications of faulting.

196

E.L. BIGELOW

Fig. 7-8. Acoustic log data used for a “more recent depth of burial” study (after Bigelow, Courtesy of the Society of Professional Well Log Analysts.

7.2.4. Advancements in acoustic logging

Nearly 20 years ago, long-spaced acoustic devices were introduced to the petroleum industry. Transmitter-to-receiver spacings of 7 to as much 20 ft have been utilized (2.10-6 m). Noted differences were found between conventionally spaced tools and the long-spaced devices, mostly across shale formations. These differences in Atc are generally attributed to shale alteration near the borehole wall, caused by mechanical damage, stress relaxation, and/or interaction between the drilling fluid and rock matrix material such as clay hydration. Alteration affected the conventional devices by reading a high At value. The refracted paths of the long-spaced tools are believed to measure slightly deeper in the formation, thereby eliminating most, if not all of the alteration effect. In well consolidated formations, shear data is usually obtained without difficulty. These tools were implemented largely for time-to-depth ties of surface seismic to borehole data, but offered some help in defining normal versus abnormal pressure gradients. Array acoustic devices that employ anywhere from 6 to 12 receivers, and transmitters of different frequencies were introduced in the early 1980s (Fig. 7-9). These devices improved the identification of the primary compressional (Ap) and secondary shear (As) arrivals. However, in unconsolidated rocks (slow formations), the identification of shear data remained troublesome. Soft, unconsolidated rocks are those that exhibit values of shear velocity near to or less than the value of borehole fluid velocity.

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

- R1

12n-0~7

(3.66rn)

T2

Fig. 7-9. Schematic of downhole digital array acoustic logging device.

197

198

E.L. BIGELOW C A n M A RAV 1 A P I > CALIPER

<

INCHES

150

>

................................

I7

Fig. 7-10. A presentation of dipole acoustic log data.

Contractors are currently field-testing dipole acoustic devices that should particularly accentuate the detection of shear slowness (Fig. 7-10). Low-frequency transmitters ( 5 3 kHz) are implemented. Mobil Oil has experimented with these devices (Zemanek et al., 1984) in slow (low velocity) formations such as found in the Gulf of Mexico and the North Sea. Flexural waves are actually measured by the

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

199

devices and at least two different methods are used to process shear arrival time. A correction for the effects of dispersion is needed to obtain true shear transit time. Data accumulated thus far hints that overpressured zones should be easily observed by the ratio Ats/Atp; i.e., within the shale formations that are normally pressured, a consistency should be found between the two acoustic arrivals. In overpressured zones, shear detection often exhibits a very attenuated signal amplitude or is totally lost. However, the physics of granular systems that are rich in clay minerals are much more complex than clean sandstones. Clay frameworks are generally very anisotropic. More practical experience and research is needed. 7.2.5. Possible limitations and pitfalls of At Although At values are generally the most reliable quantitative pressure evaluation method from log data, it is nevertheless prudent to recognize that At measurements are not a perfect solution. Detailed discussion of the pitfalls is found at the end of the chapter. MWD acoustic log measurements are not currently available.

7.3. DENSITY METHODS

Density tools contain a skid that consists of a radioactivity source that is forced against the wall of the borehole, and irradiates the formation with medium-energy gamma rays (Compton scattering effect). The skid also contains detectors that record the resultant countrates at the borehole wall. Collision with electrons in sedimentary rocks cause a gamma ray to lose its energy, and the number of collisions and resultant scattering of electrons is directly related to the electron density of the formation (Alger et al., 1963; Tittman and Wahl, 1965). Electron density is related to the true bulk density (pb). The log presents a value of pb in g/cm3 that is related to the density of the rock matrix, its pore space, and the density of the fluids occupying the pores. Detectors record the intensity of back-scattered gamma rays, a count that varies with the formation’s bulk density. The normal compaction gradient for density is a gradual increase in log value with increasing depth. In general, a marked departure and decrease in log value from the normal compaction gradient is indicative of an overpressured zone. A severe limitation to this method is caused by the presence of enlarged holes, or washouts, in many shale sections, and when this occurs, the density skid often loses contact with the borehole wall, resulting in readings that are adversely affected by the borehole fluid. As a result, the reliability of density vs. depth plots for pressure evaluation is drastically curtailed because the very low density values measured from the fluid column will reflect extremely high and erroneous calculations of formation pressure. Heavily weighted drilling fluids (e.g., barite, iron toroid, etc.) can also complicate the measurement. The equivalent depth method is probably the most versatile approach if and when density log data is used for formation pressure evaluation. Density values are plotted

200

E.L. BIGELOW

d '

to

ZD L Y I

1

30

LO

2.2

24

2¶

s t w e nut& o n a t y , g/cma

Fig. 7-1 1. Linear and logarithm scales of density versus depth to study pressure profile.

versus depth on either a linear or logarithmic scale (Fig. 7-11), but experience suggests that density devices are not usually reliable because of the borehole conditions normally encountered. However, when the borehole is reasonably in gauge (e.g., wells drilled with oil-based mud), the density method is regarded as very accurate. MWD density recordings are still in the pioneering stages of development, but show some promise. Considering that development succeeds, an accurate accounting of normal and abnormal pressure trends will be available during the drilling process, or soon afterwards (MAD). Density measurements made from the drill string also suffer from the aspects of irregular borehole geometry.

7.4. CONVENTIONAL NEUTRON METHODS

Conventional neutron logging methods utilize a chemical source to continuously emit high-energy neutrons. Collisions of the neutrons with nuclei in the reservoir rock cause the neutrons to lose some of their energy, and since neutrons have a mass almost identical to that of the hydrogen atom, their slowing down is mostly dependent on the amount of hydrogen present in the formation. The detector(s) are generally responding to the amount of hydrogen present in the formation. A large variety of tool types (e.g., compensated and uncompensated, pad-device, and non-pad devices) and energy detection methods are available in the marketplace (Dewan and Allaud, 1953; Tittle, 1961; Tittman et al., 1966). These logs are used mainly for delineation of porous reservoir rocks, but are also affected greatly by lithology type. Increase in the porosity and corresponding water content of shales in overpres-

WELL LOGGING METHODS TO DETECX ABNORMAL PRESSURE

0

GAMMA RAY ( A P I )

11(

201

0 rn D -4

I

1

\

2

0 (D

cn

0

A

P

8 0

1

I

11

I

I

2

P

0 cn 0

A

P A

0 0

Fig. 7-12. Overpressured shale is identified by compensated neutron data.

sured regimes permits the use of these data for formation pressure evaluation (Fig. 7-12). Again, it must be stated that borehole conditions can critically curtail the accuracy of neutron devices for reliable pressure evaluations.

202

E.L. BIGELOW

7.5. RESISTIVITY METHODS

Recognition of normal versus abnormal formation pressures often requires the analyst to evaluate older logs (e.g., the electrical surveys that are seldom recorded today). Conventional, non-focused electrodes were used as a current and measure circuit in such tools. The electrodes of the measuring circuit are placed in an electromagnetic field at selective distances from the current electrodes. The difference in electrical potential between the measuring electrodes was then recorded, and knowing the required distance parameters, was converted into a value of resistivity. Conductive, water-based muds are required. Longer electrode spacing generally allows a deeper investigation of the formation. As a result, the short normal measurement, usually a 16-inch (40 cm) spacing, is a shallow reading resistivity device. In many areas, the amplified short normal trace (5 x amplification) has been presented along with the actual short normal resistivity measurement. The amplified short normal has been found to be a very reliable tool for evaluating formation pressures. Short normal and amplified short normal measurements were also used with induction measurements for several years. The method relies on the observation, that under normal compaction, the shale resistivity (Rsh) increases in value with increasing depth. This is because porosity normally decreases with depth due to compaction, and resistivity is a function of the type and amount of water present in the formation. The exact shape and slope of the short normal trend line varies with the age and type of shales present (Fig. 7-13). This is to say that normal compaction trends will not be identical along the U.S. Gulf Coast, the North Sea, the Persian Gulf, or elsewhere. Rsh values are plotted on a logarithmic scale versus a linear depth scale. In normal pressure regimes, all the data points will follow a general trend, i.e.,

18

a2

I

0.4

,

I

, [ , I

0.0 0.8 1D

$

1

2

I

3

%.Qm

Fig. 7-13. Shale resistivity values plotted versus depth (after Hottman and Johnson, 1965). Courtesy of Journal of Petroleum Technology.

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

7-

-

s 0

O-

203

t. *\

8. y. .r

5 0

0 11-

13

-

a4

oa 0.e

10

20

u)

S n r e tvmstivaty R,.Om

Fig. 7-14. Shale resistivity plot versus depth from U.S. Gulf Coast well. Limey caprock caused slight resistivity increase just above the point where 9-5/8 inch casing was set.

R,h increases in value with depth (Fig. 7-14). When overpressured zones are encountered, the short normal curve shows a departure from the normal trend line, and reads lower values of resistivity in shales. This is caused by a porosity increase, and subsequent conductive fluid increase, that results from the higher pore pressure (Hottman and Johnson, 1965; Ham, 1966). The salinity of the pore fluids in the well-compacted versus the under-compacted shales must also be considered. As with the acoustic method, quantitative pressure evaluation can be carried out by either of two methods.

7.5.1. Approach A

(1) Plot R,h versus depth and determine the normal compaction trend. (2) The depth at which the plotted R,h values begin to diverge from the normal trend is identified as the top of the abnormally pressured zone. (3) Formation pressure at a specific depth is determined as follows: (a) divergence of the observed overpressured Rsh value from the normal trend line of R,h determines the shale resistivity ratio (normal R,h divided by observed overpressured Rsh), and (b) find the fluid pressure gradient (FPG) corresponding to the shale resistivity ratio (Fig. 7-15). (4) Multiply the determined FPG value by the subject depth to obtain formation pressure.

204

E.L. BIGELOW

Norrnal.prcuured R,/observcd

R,

Fig. 7-15. Relationship between shale resistivity ratio (Rsh,nor/Rsh,abn) and reservoir fluid pressure gradient (FPG) in overpressured Miocene/Oligocene formations of the U.S. Gulf Coast (after Hottman and Johnson, 1965). Courtesy of Journul of Perroleurn Technology.

A pressure gradient profile can be constructed for the subject well by the above procedure. The relation between the shale resistivity ratio and formation pressure, as proposed by Hottman and Johnson (1965), was for the Miocene and Oligocene of the U.S. Gulf Coast area (Fig. 7-15). Their basic input data to establish this empirical relation is listed (Table 7-2). The standard deviation from the average line representing the data in Fig. 7-15 is 0.020 psi/ft (0.45 kPa/m). Similar calibration charts must be constructed in other geographical areas and/or geological settings. Furthermore, it must be considered that all these methods are restricted to areas where overpressures resulted primarily from compaction processes.

7.5.2. Approach B

Another possibility is the equivalent depth method that was discussed previously (Section 2) with acoustic methods of formation pressure evaluation. Once a normal compaction trend is established for a particular field, area, or region, proper nomographs for pressure evaluation can be constructed to fit those specific conditions. This approach was used in an offshore Louisiana (USA) well to illustrate the presence of a drastic formation pressure increase (Fig. 7-16). This plot was made on semilog paper, as opposed to the linear scales discussed above. Either scale option is satisfactory. As an example, if a short normal reads Rsh = 0.8 C2 m at 14,350 ft (4375 m), and local conditions determined the 0-scale of the lower nomogram to be applicable, the following approach is used. First, enter 14,350 ft on the ordinate and then enter 0.8 on the 0-abscissa. Project a line to the right from the 14,350-ft depth, and upward from the value 0.8 C2 m. At the point of intersection of the two lines, the following values can be determined: (1) estimated pore fluid pressure of 9000 psi (62.1 MPa), and (2) an equivalent mud weight of 12 lb/gal (14.10 kN/m3) needed to balance that pressure.

205

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE TABLE 7-2

Shale resistivity ratios and formation pressures from overpressured Miocene/Oligocene formations along the U. S. Gulf Coast (after Hottman and Johnson, 1965) Parish or County and State

St Martin, La. Cameron, La. Cameron, La.

Offsh. St Mary, La.

Jefferson Davis, La.

Well

A B B C D E F

G H

I

Cameron, La. Iberia, La.

J

Lafayette, La.

K

Cameron, La. Rrrebonne, La. Jefferson, Texas St Martin, La. Cameron, La.

L M N

0 P

Q R

Depth

Pressure

Fluid pressure gradient

(m)

(ft)

(MPa)

(psi)

(kPa/m)

(psi/ft)

3780 3069 3094 3993 2856 3749 3810 4267 3337 3292 3277 3932 4220 4680 3840 3932 3581 4435 3374 3627 4145 3048 3292 3871 4115 4252

12,400 10,070 10,150 13,100 9,370 12,300 12,500 14,000 10,948 10,800 10,750 12,900 13,844 15,353 12,600 12,900 11,750 14,550 11,070 11,900 13,600 10,000 10,800 12,700 13,500 13,950

70.60 51.71 55.16 79.98 34.47 43.78 44.40 79.29 54.95 52.40 52.40 75.84 49.64 83.43 62.05 62.05 59.98 74.46 64.81 55.85 75.15 60.33 52.95 76.88 79.98 86.18

10,240 7,500 8,000 11,600 5,000 6,350 6,440 11,500 7,970 7,600 7,600 11,000 7,200 12,100 9,000 9,000 8,700 10,800 9,400 8,100 10,900 8,750 7,680 11,150 11,600 12,500

18.78 16.74 17.87 20.13 11.99 11.76 11.76 18.55 16.51 15.83 16.06 19.23 11.76 17.87 16.06 15.83 16.74 16.74 19.23 15.38 18.10 19.91 16.06 19.91 19.45 20.36

0.83 0.74 0.79 0.89 0.53 0.52 0.52 0.82 0.73 0.70 0.71 0.85 0.52 0.79 0.71 0.70 0.74 0.74 0.85 0.68 0.80 0.88 0.71 0.88 0.86 0.90

Shale resist. ratio RnlRobs

2.60 1.70 1.95 4.20 1.15 1.15 1.30 2.40 1.78 1.92 1.77 3.30 1.10 2.30 1.60 1.70 1.60 1.85 3.90 1.70 2.35 3.20 1.60 2.80 2.50 2.75

Obviously, any compaction trend line that is found from any shale parameter (not just resistivity) suggests that a transparent chart of parallel lines for equivalent mud weight requirements can be established. This method is illustrated in the next section on conductivity. Formation resistivity measurements are influenced by porosity, temperatures, formation water salinity, mineral composition of shale, etc.; therefore, the limitations and/or pitfalls of using resistivity for abnormal pressure detection will be discussed in more detail at the end of this chapter.

7.6. CONDUCTIVITY METHODS

Induction logs measure the conductivity of a formation, and reciprocate the conductivity value (mmhos) to its reciprocal resistivity value (S2 m). A high-frequency

206

E.L. BIGELOW

Rsh. n m

Fig. 7-16. Shale resistivity nomograph for estimating formation pressures along the Louisiana Gulf Coast (after Ham, 1966).

alternating current is induced into the formation, creating a magnetic field that causes eddy currents to flow in coaxial, circular paths surrounding the device. The eddy currents themselves cause magnetic fields that induce a signal into the logging tool’s receiver coils, and these recorded measurements are essentially proportional to formation conductivity. Induction logs can be recorded with all types of drilling methods, including water-based, oil-based, gas, or air. Conductivity values in normally compacted shales decrease in value with increasing depth. Transition to abnormally pressured shales is identified by greater-than-normal conductivity. This results from the larger volume of conductive water coincidental with the increased pore volume. A field log demonstrates a marked change in conductivity gradient caused by a pressure transition (Fig. 7-17). Plots of conductivity versus depth illustrate a normal pressure gradient in one well compared to a similar plot from another well that

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

207

Fig. 7-17. Conductivity trace and short normal curve clearly define increase in formation pressure over the shale interval from 10,060 to 11,000 ft (3066-3354 m).

4-

L ..

L *.

we11 A

weit

e

Gulf Coast a r e a

Gulf Coast a r e a

L'

6-

-. il2 -

-15

'I

-20 Mud w t used

8-

-25

112 14 5

10-

- 30

17 0

a

I I

n

u-

f a

-

0 W

35

I I

14

E

1

40

17 3

4 5

I YU a n d c t i v i t y . C,tmnN1)

Fig. 7-18. Well A displays normal pressures to total depth, but Well B displays a sharp increase in shale resistivity below 7800 ft (2378 m) indicating a transition to an overpressured zone.

indicates overpressuring. The pressure tops are defined by the divergence from the normal trend line (Fig. 7-18). Several methods have been used to evaluate pressure with induction devices, but again, only two will be discussed.

208

E.L. BIGELOW

‘EX-

uwrnrnno lm#

worn -mu

16

0

2000 4000 Ccnductivity. mmM

Fig. 7-19. An example of field evaluation of formation pressure on a south Louisiana (USA) wildcat (after Wallace, 1965a).

7.6.1. Method A An early south Louisiana (USA) application of conductivity for pressure evaluation (Wallace, 1964) is shown. A departure of 1200 mmhos at a depth of 12,200 ft (3720 m) was observed (Fig. 7-19), and by use of an empirical calibration chart (Fig. 7-20) developed for this particular area, a formation pressure of 9882 psi (68.13 MPa) is found. Wireline formation tests in the sand immediately below this shale zone recorded pressure measurements of 9900 psi (68.26 MPa). A conductivity ratio calibration scheme proposed by Matthews (1971) is shown (Fig. 7-21). This method is based on empirical correlation of actual formation pressure data and shale conductivity values for a given area. A similar nomograph for quantitative pressure evaluation throughout the Louisiana coast (USA) was also developed (Wallace, 1965a), and claimed an accuracy within *lo%.

7.6.2. Method B

The equivalent depth method can be used with conductivity also. This approach was used beneficially offshore Louisiana (USA) to illustrate the presence of a drastic increase in formation pressure (Fig. 7-22). Plotted on a semilog scale, it shows that either linear or semilog scales are again applicable. Transparent overlays were devised as a method to determine necessary mud weights (Fig. 7-23). This version plots the mud weight lines parallel to the normal compaction trend, as indicated by the conductivity trace. Overlaying these plotted lines on a conductivity plot allows the user to read mud weight and/or formation

602

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

209

Formation Pressure Gradient (kPaim)

E

200

noon I-

aa pi/n

100

0.5

06

07

1D

QO

0-8

F O ~ ~ U I O ~ - ~ Bm - i r m .pl/ i t

u d.ptn qinos u!

Q4

aJnssaJd

Fig. 7-20. Empirical relation between shale conductivity and formation pressure gradients in south Louisiana (after Wallace, 1965a). . .

13

12

E m

P

0

B

n

U

a4 1.0 1.1 1.2 1.3 1 1 (Obsorvod) /t N0rm.L ) conductivity

Fig. 7-21. Relationship of the shale conductivity ratio (Csh,abn/Csh,nor) and formation fluid pressure gradient (FPG) in Pleistocene rocks of the U.S. Gulf Coast (after Matthews, 1972).

pressure directly from the conductivity plot. Versions of these charts are shown for formations in south Texas and Italy. Possible pitfalls include limey shales, temperature, formation water salinity, mineral composition of shales, and nearness to salt domes all adversely affect the conductivity measurement if any of those conditions are extreme.

210

E.L. BIGELOW

Fig. 7-22. Conductivity plot and formation pressure profile calculated by the equivalent depth method in an offshore Louisiana well.

Fig. 7-23. Overlays can be made to determine equivalent mud weight requirements. (a) Frio formation, south Texas, (b) Wilcox formation, south Texas; (c) Pleistocene and Pliocene formations, Italy. (After Matthews, 1972.)

7.7. SP METHOD

The SP curve is a measurement (millivolts) of naturally occurring potential differences between the fixed potential of a surface electrode and a moveable electrode that is part of the logging string downhole. The borehole must be filled with a water-based fluid. The components that cause this potential are: (a) electrochemical including membrane potential between the shale and adjacent permeable strata,

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

211

and the liquid junction interface between the borehole, flushed zone, undisturbed zone, etc.; (b) electrokinetic effects that include streaming potential. The sum of the two potential causes of the SP measurement in permeable formations that are essentially shale-free is considered to be:

EC = -K log(aw/amf) where a, and a,f are the chemical activities of the formation water and mud filtrate at formation temperature. K, the electrochemical coefficient, is directly proportional to the absolute temperature and, for sodium chloride, it is equal to 71 at 77°F (25°C). Furthermore, for pure sodium chloride solutions that are not too concentrated, resistivity values are inversely proportional to activities. However, this inverse proportionality does not hold exactly at high concentrations or for fresh waters that contain prevailing divalent ions. Empirical K values and correction charts for formation water have been developed (Gondoin et al., 1957; Moore et al., 1966; Desai and Moore, 1969). Under normal circumstances, the SP trace is primarily dependent on salinity (or equivalent resistivity) contrast between the drilling mud filtrate and formation water, and in general, the best SP results where fresh-water-based muds are used. Little, if any, SP development normally occurs when salt-based muds are used; i.e., the SP curve is almost featureless. SP recordings can not be obtained in cased holes, empty or gas-drilled holes, or those drilled with oil-based fluids. When a sharp contrast of R , / R , occurs, SP’s have little character. Stray currents from underground mines, radio transmission facilities, magnetized rotary tables or cable spooling drums can also cause “noisy SP’s”. Principle uses of the SP measurement have traditionally been the location of permeable beds, determination of water salinity, estimation of clay content within potential sand reservoirs, and indication of tectonic stress for use in abnormal pressure detection. 7.7.1. The salinity principle

Several investigators have cited field observations of striking changes in decreasing water salinity with increasing depth. Data on water salinities and associated pressures for the U.S. Gulf Coast are presented (Table 7-3). Low salinity values were observed in many of the abnormally high-pressured wells. Such observations led to a proposal (Overton and Timko, 1969) of plotting salinity variations (as calculated from the SP) for abnormal formation pressure detection. A remarkably simple relationship was agreed upon, and christened the salinity principle; i.e., between the salinity of clean sands, CW,and the porosity of adjacent shales, qh,: Cw x &, = constant Simply stated, the above says that formation water salinity will vary inversely with the porosity of adjacent shales (assuming equilibrium between the shales and

TABLE 7-3 Geostatic ratios and formation water composition a in wells located in the Texas and Louisiana Gulf Coast area (after Jones, 1968) Depth (ft)

Original pressure (m)

(Psi)

12,992 3960 11,960 10,400 3170 10,400 12,500 3810 10,500 11,106 3385 9,030 10,082 3073 8,000 10,875 3315 8,110 10,401 3170 7,700 10,870 3313 7,900 12,552 3826 8,690 16,064 4876 9.600 9,051 2759 5,000 11,000 3353 5,950 12,200 3719 6,500 11,200 3414 5,830 10,500 3200 5,440 13,000 3962 6,600 Gulf of Mexico water a

(MPa) 82.5 71.7 72.4 62.3 55.2 55.9 53.1 54.5 59.9 66.2 34.5 41.0 44.8 37.5 40.2 45.5

Geostatic ratio

Dissolved solids (mdl)

Sodium (mg/l)

Calcium (mg/l)

Magnesium (mdl)

Bicarbonate

(Wl)

0.92 0.87 0.85 0.81 0.79 0.74 0.74 0.73 0.69 0.60 0.55 0.53 0.54 0.52 0.52 0.51

92,000 98,000 99,000 111,000 55,000 41,000 146,000 136,000 175,000 93,000 14,000 66,000 97,000 72,000 100,000 45,000 35,000

38,000 38,000 36,000 40,000 19,000 15,000 46,000 43,000 63,000 30,000 4,800 24,000 36,000 26,000 35,000 16,000 10,970

520 200 200 320 130 100 320 500 540 480 30 100 220 210 210 100 429

4,300 1,200 1,100 2,700 1,100 340 6,700 5,400 6,100 4,200 290 1,300 1,300 1,100 1,600 560 423

580 200 200 360 200 60 600 700 700 300 60 300 300 200 400 100 1,324

700 1,100 1,200 500 3,100 2,900 400 300 200 600 1,400 1,000 100 800 600 147

In sands. Ratio of aquifer fluid pressure to overburden pressure.

Potassium

Sulfate (mg/l) 260 26 27 82 700 100 53 10 60 25 12

2,750

Halides (as chloride) (mm 52,300 56,700 56,600 30,200 21,600 76,000 73,000 98,000 53,500 7,700 38,200 55,500 40,900 57,000 26,000 19,770

m

r

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

213

sands) - an issue that has been argued about for years. Under normal compaction, shale porosity decreases with increasing depth, whereas formation water salinity normally increases with depth. Abnormal formation pressure environments cause divergence from such normal trends. Apparent shale porosity increases in overpressured zones which in turn suggests that a decrease in formation water salinity provided the salinity principle is applicable. A decrease in the water salinity, indicated by the SP trace, would therefore indicate proximity to abnormal formation pressures. Field cases from Matagorda County, Texas (USA) and offshore Louisiana (USA) illustrate the observations (Figs. 7-24 and 7-25).

2'

(1 I

I I

4-

I

--__-_

I

'-

z e-

8

c. c

n 0 U

0-

/

I I u -I

/

,

--=.I--

/'

I

I

,

I

]lo

Fig. 7-24. A decrease in water salinity can be recognized on the SP curve, and indicate an approach or proximity to abnormal pressured regimes (after Myers and Van Siclen, 1964).

8i

b

L

-15

E

58-

f

n

2

-20 7-

a-

+,

1 10 0

r.;

-

t

-- 2 5 - 30

Fa I

u

wervessur*o 7.011.

O -0

2

0

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1

7 0 9 0 1 0 Salinity. wm a N~CL

3 0 5 0

a'

Fig. 7-25. Salinity trend in an offshore Louisiana well (after Fertl and Timko, 197Oc).

214

E.L. BIGELOW

Fig. 7-26. Comparison of shale resistivity and formation water salinity plots in a Gulf Coast well (after Fertl and Timko, 1970~).

For comparative purposes, salinity data from shale zones that were determined in the laboratory from sidewall cores, were plotted with salinity data derived from the SP in clean sands (Fig. 7-26). The normal salinity trend in the sands show a consistent increase from the surface to about 5500 ft (1677 m). Throughout the illustrated interval, pore waters were less saline in the shales than in the associated sandstones. This particular observation agreed with other similar investigations (Sukharev and Krumbol’dt, 1962). Some success has been achieved in using the SP as a tectonic stress indicator in sandhhale sequences. It has been observed that the freshening of formation waters often occurs just prior to drill bit penetration of overpressured zones. This offers a forewarning of impending downhole pressure changes. The well example from Iberia Parish, Louisiana (USA) provided comparative plots of shale resistivity and variation of pore water salinities from associated sandstones (Fig. 7-26). Changes in shale resistivity and salinity values suggest that the well cut a fault. Additional geological data confirmed the presence of the fault. The presence of a limey sealing barrier (caprock) on top of the overpressured interval is also readily observed by the increase in shale resistivity at about 11,800 ft (3598 m). Salinities in the sand above indicate a freshening at about 11,400 ft (3476 m) which would allow about 400 ft (122 m) of forewarning of the overpressured zone. In addition to this data, mud weight requirements to drill the well are shown. Another field example from the U.S. Gulf Coast shows a drastic pressure increase below a well-developed caprock at about 13,000 ft (3963 m). The transition from

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

215

Fig. 7-27. Apparent relationship between geologic age and compaction coefficient (after Zanier, 1969).

normal to abnormal pressure in this well is quite abrupt. Worldwide experience suggests that such pressure transition zones may exhibit pore fluid pressure changes of 5000 psi (34.5 MPa) over shale intervals as short as 300-400 ft (91-122 m), therefore requiring close control of drilling operations. Nevertheless, pressure transition zones that extend over several thousand feet have been drilled without any problem because the pressure increase is very gradual. Salinity reductions in overpressured environments at greater depths often become drastic enough to cause polarity reverses on the SP trace; i.e., a positive SP is recorded across overpressured sands. Such drastic changes have been observed in Oklahoma (USA), the Himalayan foothill belt of India, and the South China Sea. Correlations of formation pressures to salinity variations may be limited to specific locales; i.e., a straightfonvard application of the salinity principle is not always possible. This probably results because of (1) problems inherent to SP measurements, and/or (2) the fact that formation water salinities can vary appreciably across faults, unconformities, or other geological causes. In the absence of such geological features being superimposed on the overburden compaction stress, the formation water salinities may increase with depth at a predictable gradient, depending on the geological age of the interval (Fig. 7-27). Drastic salinity changes across unconformities have been reported from several areas, such as Kansas (USA) and Israel (Case, 1945; Levorsen, 1967; Bentor, 1969). Salinity variations are often found in the Morrow sands of Oklahoma (USA). Using formation water salinity plots, derived from SP data, well-known unconformities can be correlated over large lateral areas (Zanier and Timko, 1970).

216

E.L. BIGELOW

7.8. THE SHALE FORMATION FACTOR METHOD

For each porosity value (4) of a given clay, there is a maximum value of effective compressive stress that clay can support without further compaction (Hubbert and Rubey, 1959). This state of abnormal pressure condition can be expressed as an exponential function:

4 = #i(e-Ku) where 4 = shale porosity, 4i

= initial sediment porosity (zero overburden), K = constant, a = net overburden pressure or vertical component of rock frame stress. Empirical observations relate porosity to the degree of consolidation (cementation factor m ) and the formation factor ( F ) of the rock:

F = #-m Basically, the formation factor ( F ) is a dimensionless quantity by which the formation water resistivity ( R , ) is to be multiplied in order to obtain the resistivity of the reservoir rock ( R , ) when the rock is 100% saturated with formation water:

F = Ro/Rw Combining the two equations above, and taking the natural logarithm of both sides leads to: In F = m ( K a -In$,)

or: log F = m(0.434Ka

-

log&)

The value log F can therefore be plotted against (T as a straight line. However, it is much simpler to plot log F versus depth ( D ) ,since the vertical rock frame stress for normal compaction equals 0.535 D (Foster and Whalen, 1965). The Foster and Whalen method to estimate formation pressure includes the following steps: (1) Construct a formation water resistivity ( R , ) profile by computing R, values from the SP curve in clean, shale-free water-bearing sands (Pirson, 1963). (2) Plot shale resistivity Rsh from the short normal or conductivity logs in pure, lime-free shales. (3) Compute formation factor Fsh from Rsh and R, at the corresponding depth (Fsh = Rsh/Rw>. (4) Plot Fsh versus depth on semilog paper. In normal pressure environments, all Fsh values will fall along a straight line representing the normal compaction trend. Onset (top) of overpressured formations is characterized by departure from the normal trend; i.e., the Fsh values become less than under normal compaction conditions. The Fsh versus depth plot from an offshore Louisiana (USA) well exhibits the normal trend (Fig. 7-28). The pressure top was selected at about 11,750 ft (3581 m). Quantitative pressure data is easily

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

217

’ 5

I0

E

1

35

I

rn n

60

\

I . I . .$A

i I

20

x)

so

45

,

1 , I . l 100

eo m

i

F.1

Fig. 7-28. Shale formation factor plotted versus depth in a US.Gulf Coast well.

obtained using the equivalent depth method. For example, formation pressures in the subject well at 14,000 ft (4268 m) (point A) are calculated as follows: (1) At point A, Fsh = 40. (2) From point A, move vertically up to intersect the normal trend line. Intersection establishes point B at an equivalent depth (DE) of 10,000 ft. (3) Q = 0.53508 = 5350 psi (36.9 MPa) at point A (14,000 ft). (4) Pf = Po - Q = 1.0 (depth at A) - 0.535 (DEat B) = 14,000 - 5350 = 8650 psi. ( P o = total overburden stress and u = grain-to-grain or effective stress.) From the above data, it can be predicted that a pore fluid pressure of 8650 psi (59.6 MPa) exists at the depth of 14,000 ft (4268 m) in the subject well. The shale formation factor method assumes that formation water salinities are the same in adjacent sands and shales. However, it has been observed that this is not usually the case (Sukharev and Krumbol’dt, 1962; Von Engelhardt and Gaida, 1963; Fertl and Timko, 1970c; Schmidt, 1973). Lithology variations, shale gas, large washouts, etc. will affect the measured R,h values and therefore the computed F s h . Furthermore, pressures in shales and sands are not necessarily the same; field cases of this observation are shown later in the chapter. The method is somewhat time-consuming, since both the R, and Rsh values have to be determined first in order to compute Fsh. Nevertheless, application of this method has been helpful and successful in many situations. Foster and Whalen (1965) have claimed an accuracy of 4 3 % for pressure predictions in over 80 wells.

218

E.L. BIGELOW

7.9. MAGNETIC RESONANCE METHOD

Magnetic resonance logging methods were first investigated as early as 1946 (Bloch, 1946; Purcell, 1946). Basically, the principle is to measure the free movement of proton nuclear magnetic moments in the earth's magnetic field. A very strong DC polarizing magnetic field ( H , ) is directed into the formation and is designed to align the spinning protons as nearly as possible to an axis perpendicular to the earth's magnetic field (HE). A characteristic time constant for the spin polarization is called spin-lattice relaxation time (TI). Full polarization requires about 5 times TI for the polarizing field to be affected. Following polarization, the tool is quickly turned off, and since the spins cannot follow such a sudden change, the protons are momentarily abandoned in a state of alignment ( H E ) .The Larmor ~ y x HE)describes the proton movement about the earth's magnetic frequency ( f = field, and y is the term describing the gyromagnetic ratio of the proton ( y = 4.2576 x lo3 Hz/G). This phenomenon is likened to the motion of a gyroscope in the presence of a magnetic field. Depending on the geographical location, Larmor frequency can vary from about 1300 to about 2600 Hz. A pickup coil with sinusoidal ) included in the spin operation, and has an amplitude signal frequency ( f ~ is proportional to the number of protons in the formation. Lack of H E homogeneity will cause the spins to dephase and result in an exponential decaying sine wave with time constant T2 and frequency f ~ . Detailed evaluation of pulsed MRL data for estimating porosity, permeability, irreducible water saturation, and residual oil saturation have been explored (Timur, 1969; Brown and Neuman, 1980; Coates et al., 1991). The use of MRL measurements on shale drill cuttings was discussed (Seevers, 1972) as a method to determine the permeability to fluid flow in overpressured shales. The permeabilities can be combined with pressure data from adjacent sands to yield the present-day flux of water through the shales. Knowing the variation of water flux with depth aids in understanding the mode of pressure origin in the particular area under study. Two striking features are shown in the vertical water flux versus depth plot (Fig. 7-29). One feature shows that the flux out of the sand at 16,500 ft (5030 m) is much less than the influx, and the other feature shows the very rapid buildup of flux between 14,000 and 15,000 ft (4268 and 4573 m). Supplementary data include the mud weight used and the formation temperature in the subject well. The discontinuity in the vertical flux implies that the sand at 16,500 ft (5030 m) leaks. In engineering units, the influx is 6 barrelslacre-year (235 ml m2 yr-') and the vertical outflux is about 1 barrel/acre-year. Therefore, approximately 5 barreWacre-year flush through the sand in the horizontal direction. An estimate for the rate of increase in flux due to normal compaction is about ml cm-3 yr-l (100 x lop6 ml m-3 yr-l), whereas the apparent rate of increase ml cm-3 yr-'. This between 14,000 and 15,000 ft (4268 m and 4573 m) is 6.5 x large rate implies a source of water other than that caused by compaction. One possible source that has been suggested is the diagenetic alteration of the clay mineral montmorillonite to illite (Powers, 1967;Burst, 1969; Perry and Hower, 1970).

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

219

Temperalure K

355

400

375

h t c r c ~ u r . r n / c d-year

FPG. pY/ft I

80

280

220 T.mg.r.Na

:F

Fig. 7-29. Comparison of fluid pressure gradient (FPG) and formation temperature gradient with the water influx computed from a magnetic resonance log (after Seevers, 1972).

7.10. METHOD UTILIZING DOWNHOLE GRAVITY MEASUREMENTS

Downhole gravity meters make measurements that are equivalent to a large volume bulk density measurement. Differences of gravitational attraction between any two points below the earth’s surface are a function of the free-air gradient and the mass of material between the two points. In simple terms the following holds: &(g/cm3) = 3.687 -39.18AGIAZ where AG = the downhole gravity measurement, and A 2 = elevation difference between the two stationary measurement points on the instrumentation. An illustration (Fig. 7-30) of the rock volume involved in density measurement deciphers 95% of the effect coming from a rock cylinder A 2 ft in thickness and approximately 5AZ ft in radius. As an example, A 2 is 100 ft (30.48 m), the cylinder is 100 ft (30.48 m) thick, with a radius of 495 ft (150.9 m) or approaching 500 ft (152.4 m) depth of investigation (Jones, 1972). The above illustrates that gravity meter measurements are practically unaffected by mud cake, infiltrated zones, washouts or casing. The borehole gravity log is therefore a density logging tool with a very large radius of investigation. Of particular interest here is a statement by Jones (1972) that “bulk densities measured with the borehole gravity log do not show a density change in the overpressured shale zones”. The borehole gravity log has its limitations. For instance, tolerance for borehole deviation is extremely limited, and changes in tides, phases of the moon, etc. have to be considered.

220

"4

103

E.L. BIGELOW

8

Sheet

Fig. 7-30. Difference in gravity effect on downhole gravity instrument at two elevations indicates density of rock in the interval (after Jones, 1972).

7.11. PULSED NEUTRON METHOD

Thermal neutron lifetime is the rate at which thermal neutrons are captured or absorbed by a material. This lifetime is actually controlled by the microscopic thermal neutron capture cross section ( C ) of the material. The larger the cross section, the more quickly the neutrons are captured. Lifetime, in ps, is the time required for the neutron population to be reduced to one-half. The chlorine ion is the strongest absorber of all the commonly occurring elements in sedimentary rocks. Pulsed neutron log response is related to the same basic parameters that were exploited by the chlorine log. The neutron generator for these devices is an electromechanical source that emits 14-MeV neutrons in precisely controlled repetitive bursts. Following each burst, there is a period of quiescence during which the neutron population dies away. This neutron population is sampled by a scintillation counter that detects the gamma rays produced when the thermal neutrons are captured. The gamma-ray intensity is proportional to the neutron population. The early part of neutron die-away time is very complex. The instrument is surrounded by several materials, including the tool housing, well casing, cement sheath, borehole environment, and the formation. After some period of time, the borehole perturbations are gone and the rate of change of the neutron population is controlled by the formation. It is at this time that the formation capture cross section measurement (C) is made. Capture gamma rays are counted at two separate and known times during this latter die-away phase (Youmans et al., 1964, 1966; Wichmann et al., 1967). The pulsed neutron logging devices have an advantage over conventional neutrons (that use a chemical source) in that the casing and cement sheath have little effect on the log response. Presentation of the pulsed neutron logs are similar to that of open-hole resistivity devices, thereby allowing easy correlation. Beyond the more conventional applications, pulsed neutron devices are also used to monitor/

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

E

ei-

.I

bt

em'

221

I

i.5

-

0 U

0-

sigma *ur..I,.

Fig. 7-31. Use of pulsed neutron logging for quantitative formation pressure evaluation in cased holes (after Fertl and Timko, 1970b). Courtesy of Oil and Gas Journal.

detect overpressures and/or pressure depletion behind pipe (Fertl and Timko, 1970b; Fertl, 1987). To quantify pressures, the equivalent depth method has proven to be a very successful approach with these devices. A well located in Louisiana (US) is used to show the application of a pulsed neutron log for abnormal formation pressure identification (Fig. 7-31). Computations indicated that a mud weight of 10.2 lb/gal (12.0 kN/m3) should be sufficient for well control on a sidetrack. The sidetrack well was drilled with 10.4 lb/gal (12.2 kN/m3) mud and did not encounter any complications. The pulsed neutron log accomplishes several things: (1) The log data provides information through casing that indicates changes in saturation of a productive zone. (2) The log can be used very effectively (log-inject-log) to determine residual oil saturation, and predict the producibility of a formation, or the effectiveness of secondary or tertiary floods. (3) Pulsed neutron logs can also be used in pressure evaluation work (Fig. 7-32). A log can be run through the drill pipe or in already cased holes to detect and evaluate pressure variations. (4)In the open hole, pulsed neutron logs have successfully identified salt-plugged pore space in rocks that appear to be gas-bearing by conventional open hole log analysis.

222

E.L. BIGELOW NLL 1968

N LL 1967

IES 1964

,

30

40

20

30

40

20

Fig. 7-32. Pulsed neutron capture logs recorded several years after the IES and completion of a highpressure Louisiana well demonstrate the effects of pressure depletion. The decrease in Zone A was probably caused by increased compaction and decreased porosity. Also note the apparent saturation decrease with time in the sand interval.

c w

u.

lbiQP

8

12 5

Ly

0 I c

a

y1

16 5

0 A

U

0 U Y 5

16 4

w

3

*

01

1

J

i5

1

2

60

SHALE RESISTIVITY R,”

17 6

179

I , , , , , 50 40 30 20 10 0 SIGMA SHALE. T,”

Fig. 7-33. Shale resistivity and sigma values plotted versus depth to define overpressure environments.

A n overpressured environment is defined by logs (Rsh and &h) in an offshore U.S. Gulf Coast well (Fig. 7-33). Both logs were plotted versus depth to emphasize the effectiveness of the two methods. Quantitative pressure evaluation can be performed by either of the two techniques described earlier.

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

-

223

gbv

FORMATION FFG. osilft EQUIVALENT MUD WEIGHT, lblgal

Fig. 7-34. Empirical relationship between sigma shale ratio (&h,abn/ gradient (FPG) and equivalent mud weight requirement (Ib/gal).

&,nor)

and reservoir fluid pressure

7.11.1. MethodA An empirical calibration chart can be created as follows.

(1) Plot &, values on either a logarithmic or linear scale versus a linear depth scale, and establish the normal compaction trend line. (2) Top of the overpressured zone is located at the depth where the plotted Csh values begin to diverge from the normal trend. (3) Determine the formation pressure at a specific depth as follows: (a) divergence of the observed &, value from the extrapolated normal trend line &, value determines the (observed Csh divided by normal &,). (b) From Fig. 7-34, the formation fluid pressure gradient (FPG) and equivalent mud weight corresponding to the Xratiois found.

7.11.2. Method B The equivalent depth method includes the following steps with a pulsed neutron device (1) Plot &.h values versus depth and establish the normal compaction trend. (2) Determine the formation pressure (Fig. 7-35) mathematically as follows: Pf = Go x DA - D E ( G , - GH) Pf = DA - 0 . 5 3 5 D ~ where Pf = formation pore pressure (psi), DA = depth of overpressure interval (ft), DE = normal, equivalent depth corresponding to DA (ft), G H = hydrostatic pressure gradient (psi/ft), Go = overburden pressure gradient (psi/ft).

E.L. BIGELOW

S H A L E PARAMETER

Fig. 7-35. Schematic illustration of the equivalent depth method. 7.12. RECOMMENDED WELL LOGS FOR CONVENTIONAL PRESSURE EVALUATION

Today’s numerous acoustic devices are generally the best approach to quantify pressures because the log(s) are relatively unaffected by changes in hole size, formation temperature, or formation water salinity. Nevertheless, the recorded interval transit time ( A t ) in a given formation does depend on several parameters; namely, degree of compaction, amount and type of porosity, fluid content, and lithology. As if often the case, older logs may be the only data available. When this occurs, the short normal, or preferably its 5-fold amplification, the amplified short normal, allows reasonably accurate assessment of shale resistivity (&) that can be plotted versus depth. The short normal was part of the electrical log and older versions of induction logs. There are literally tens of thousands of these logs that have been recorded in the past fifty years. The response of resistivity measurements must be considered as having been affected by large variations in formation temperature or salinity. Lithology variations, proximity to massive salt deposits, enlarged boreholes, and presence of steeply dipping and thin formations can also affect the recorded resistivity values. Newer devices that have generally replaced the short normal include focused and spherically focused logs, but these new generation devices also perform satisfactorily for shale evaluation. Although the acoustic and shallow reading resistivity devices are preferred, users should not consider the other methods as not being useful or obsolete. It is prudent practice to not rely solely and completely on most of the other methods.

7.13. LIMITATIONS OF WIRELINE METHODS

A large volume of technical information has been contributed on the subject of formation pressure detection and evaluation by wireline techniques. Drilling personnel and wellsite geologists have a need to know :

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

225

(1) Which well logs are superior for quantitative pressure evaluation? (2) How should they quickly and efficiently recognize, select, plot, and evaluate logging parameters for in-situ formation pressure changes? (3) What are the traps and limitations? The intent of the following discussion is to answer the above questions. Excepting the SP salinity method, all other logs discussed in this chapter used values recorded in shale formations. The shale parameters are plotted versus a preselected depth scale, perhaps 500 or 1000 ft/inch (or equivalent and convenient metric scales). Detailed studies require a more expanded scale. Formation pressure plots generally rely on four main considerations: (1) log data acquisition is acceptable quality; (2) major detrimental effects such as hole washouts, bit size changes, lithology variations, etc. are not present or can be recognized and avoided when plotting the data; (3) thick-and pure-shale zones are available; (4) realistic normal compaction trend lines can be established. Logs must be properly calibrated if any realistic and accurate pressure evaluation is to be performed. There is always the possibility of instrument malfunction, especially in ultra-deep, ultra-hot wells. Temperature and pressure ratings, tool dimensions, and measurement tolerances are provided by reputable service contractors; however, log quality control is a lengthy subject and beyond the scope of this material. Nevertheless, it should be pointed out that logs from offset wells do not always allow good comparison for log quality. If two adjacent wells are drilled into different fault blocks, and the faults are known to act either as pressure continuities or discontinuities, the pressure profiles from the adjacent wells might be identical, similar, or completely different. live conductivity logs from offshore Louisiana (USA) were drilled 2000 ft (610 m) apart, but they were separated by well-established faults (Fig. 7-36). Well A was drilled in an environment of normal hydrostatic pressure to a depth of 12,500 ft (3811 m). Well B encountered abnormally high pressures below 11,000 ft (3354 m). Well B’s mud weight requirements to drill the succeeding 1000 ft (305 m) were 18 lb/gal(21.2 kN/m3) due to several well kicks and gas cutting the mud. Another offshore example (USA) features Rsh correlation from a new well drilled in the same fault block as an older well (Fig. 7-37). Similar formation pressure correlations have been used on a regional scale, as well as local, and involved several conventional methods of measuring shale properties. These correlative features become important in early development drilling. Correlation of driller data from a well currently being drilled with log and drilling data from previously drilled wells is important information in that it helps the driller determine “where he is” with respect to formation pressure variations. This approach has proven successful worldwide. A field case from Texas (USA) illustrates Rsh data from a short normal and shale transit time (A&) from an acoustic log. The two plots show considerably different characteristics in the depth interval from 8000 ft (2439 m) to 10,000 ft (3048 m). Subsequent examination and comparison of all three log runs with induction electrical log clearly indicated that the logging tool malfunctioned on run No. 2, as very low values of resistivity were recorded. Formation pressure computations based

226

E.L. BIGELOW WELL A

WELL E

0

0

5 0

x 0

0 N

0

well with 17 7 lblgal

Fig. 7-36. Induction-electrical surveys from two offshore Louisiana wells located 2000 ft (610 m) apart, but located in different fault blocks (after Wallace, 1965b).

on the induction log measurements would have been erroneous. On occasion, different service contractors run the same type of log over different intervals in the same well. Comparative pressure plots from short normal resistivity, recorded by two different service companies, over the same interval in a far East wildcat well are shown (Fig. 7-38). Resistivity profiles are similar but the shale resistivities are considerably different. If assumed that company B only had logged the lower part of the borehole (interval Z), the lower shale resistivity could easily have been misinterpreted as an increase in formation pressure. Calling for a much higher mud weight to maintain well control would have been an unnecessary expense. It is very important that data from every available source be examined and studied carefilly. Major changes in lithology, borehole condition, or drastic formation pressure variations can cause “unusual pressure profiles” (Figs. 7-39 and 7-40). Subsequent logging runs on a well usually overlap a section of the previous log runs if possible. This permits a “tie-in” and check for depth and shale resistivity values between the two log runs. It must be considered that prolonged exposure of shale zones to the drilling fluid might alter some shale properties (Louden and Woods, 1970). Significant variations in shale resistivities are sometimes observed from one logging run to the next (Fertl and Timko, 1972). These effects appear to be related to the

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1 . 1 1 1

I

I l l

01 a06 0.e 1.0

I

2

.

1

3

, , , 1 . 1

4 5 6 7

a-..am R,h.Pm

Fig. 7-37. Shale resistivity plots from two adjacent wells both show massive pressure caprock at about 13,000 ft (3963 m) (after Fertl and Timko, 1970d). Courtesy of the Society of Petroleum Engineers.

228

E.L. BIGELOW

0

--10.0

179.

-11 0

lb9.

-110

216.

5

i: 91 ' 05

E

r

f

0 9

5 1

x

1

I

I

10

20

54

I

,

I

'

1

R,,,.Pm

Fig. 7-38. Shale resistivity plots from short normal logs recorded by different contractors in the same borehole interval.

type of drilling fluid (its composition, pH value and weight), the time the openhole is exposed to the fluid, the magnitude of formation pressures, the downhole temperatures, the presence or absence of shale gas, and shale mineralogy. The possibility of shale hydration effects to acoustic log measurements were discussed by Reynolds et al. (1973). One of their field cases shows the conventional normal compaction trend, but with apparent overpressures starting at 7000 ft (2134 m) and continuing to total depth. The well was drilled with 10.5 lblgal(l2.3 kN/m3) mud and no significant problems were encountered. This suggests the presence of essentially normal formation pressures. Further investigation showed that the first log was run within a few hours after the interval was drilled, and the second log was run after the well was deepened another 8000 ft (2439 m) over a period of 5 weeks. Discovering the above, the acoustic log data from 5200 to 5500 ft (1585 to 1677 m) was studied in greater detail. It first appears that there is fair agreement between the two log runs. However, closer scrutiny shows that the better-quality shales (those with high gamma ray) are associated with the larger separations between the two At traces. These separations were felt to be caused by shale hydrate that increased acoustic transit time. Other evidence supports the shale alteration hypothesis (Fig. 7-41). From 5200 to about 10,500 ft (1585-3201 m) the overall velocity of the predominantly shale section is considerably higher than the acoustic log data would indicate. Velocity surveys are recorded through the virgin, undisturbed zone, whereas the log data records refracted values from the flushed or invaded zones of the formation. As shown in the figure, the shales have been affected enough by hydration to alter their true transit times by as much as 40 @sift (122 pslm).

229

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

35

10

I

15

20 E

:7 -

8-

x

25

0-

5 0

1I'

30

x)

12 13 11

02

35

40

0.3 0.4 0.5 0.7 091.0

2

0.4

a6 a8

' 1.0

2

3

R-Dm

Fig. 7-39. Major changes such as (a) geologic age, (b) fluid sensitive shales, or (c) lithology effects can cause changes on shale resistivity plots (after Fertl and Timko, 1971a).

4 r

7 0

. i

620

30 8-

- c

0 0

0

10-

5

-

" 0 12

30

"1

E

x c

40

p

0

40

14-

50

I

Fig. 7-40. Shale resistivity plots on two offshore R x a s (USA) wells are both affected by h e y shales between 7000 and 9000 ft, and by overpressured Migura formation at about 11,000 ft. Also, note the fresher shale water above 3500 ft.

230

E.L. BIGELOW

I

M

40

,

, I , I

I

6080lOO

Ka

I

A t . #IeC

I

I

L

I l l .

45

/ ft

Fig. 7-41. Acoustic data used to derive a shale pressure plot in an offshore well with water-sensitive shales. Velocity survey is seismic data interpretation (after Reynolds et al., 1973). Courtesy of Journal of Petroleum Technology.

A “new normal trend” was established through the normally pressured and maximum transit time shales in an attempt to correct for the hydration effects (Fig. 7-41). It is parallel but shifted from the “originalnormal trend”. This “new normal trend” suggests that only the interval from 11,000 to 13,000 ft (3354-3963 m) is overpressured. Representatives of operating companies are often confused when induction electrical surveys are run and the short normal and induction resistivity curves indicate quite different values in the shale sections. Many wellsite representatives consider such logs as being miscalibrated, while others use this apparent separation in recorded shale resistivity as criteria to determine if a well is being drilled overbalanced. In general, neither concept is correct because they have failed to consider the following: (1) inherent differences to conventional electrical measurements, such as the short normal and induction measurements; (2) the fact that the horizontal layering of plate-like clay particles in shales results in both physical and electrical anisotropy. Frequently, shale resistivity values from the short normal are in excess of the values recorded by induction resistivity. Such data have been confirmed in the laboratory. Electrical anisotropy is defined as:

where h = electrical anisotropy coefficient, RE{ = longitudinal resistivity (i.e., horizontal or parallel to bedding planes), Rv = transverse resistivity (i.e., vertical to the bedding planes).

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE I-

I

23 1

10

Fresh wale shale5

15 pressure

Region 'A*

mvironmmt

limy

mates

20

E

1

25

I

30

rnssurc.

I

0.1

1

0.5

.

change I

, . I

1D

5.0

R,.Rm

Fig. 7-42. Erroneous normal compaction trend lines and several other possible pitfalls of pressure evaluation using shale parameters.

Kunz and Moran (1958) showed A shale values that ranged from 1.0 to about 2.5. Consider the following when plotting shale parameters. (1) Use intervals that are at least 10 to 30 ft (3.05-9.15 m) thick. (2) Use log data from relatively pure and clean shales and avoid those shales that appear limey, silty, or sandy. Cross-check the information with reported data from a well cuttings analysis. (3) Avoid plotting shale resistivity values that occur above depths of about 2500 to 3500 ft (762-1067 m) because they are usually above critical compaction depth. Usually, such shales also contain formation water that is much fresher than seawater, resulting in higher resistivity values (Fig. 7-42). It is possible, however, to work out local empirical correlations. (4) Recognize that changes in geologic age, major unconformities, etc. are reflected by changes in shale properties. Miocene and Oligocene shales in the US. Gulf Coast area have different electrical properties that cause a marked shift in the normal trend lines. Acoustic log data can be affected by unconformities (Fig. 7-43), usually with a shift in the normal compaction trend line. Similar observations occur with resistivity, acoustic, and density data on a global basis. (5) Avoid plotting log data that was acquired from steeply dipping, thin-bedded, and/or tectonically overturned shales. (6) Close proximity to large salt masses, especially salt domes, have very low resistivities caused by the salinity increase in pore water. This falsely indicates higher-than-actual formation pressures. Associated salinity variation in adjacent sands is shown (Fig. 7-44).

232

E.L. BIGELOW

1.I.

r=ln

Fig. 7-43. Unconformity causes shift in the normal compaction trend line. Laleial dislance from Salt dome. krn

a

I

t9 :I 31 0

1

2 3 4 Lateral alsiancc from s a t

5

a. x d t

t

Fig. 7-44. Salinity variations in sands as a function of the proximity to a salt dome, U S . Gulf Coast (after Fertl and Timko, 1 9 7 1 ~ ) .

(7) Very fresh formation waters (e.g., 5000 ppm NaCl equivalent or less) can occur at great depth, and increase the resistivity values, falsely indicating lowerthan-actual formation pressures. (8) Presence of “shale gas” can cause drastic increase to shale resistivity or shale acoustic values, yet have no direct relationship to formation pressure variations. (9) Gas-cut drilling fluids and lost circulation additives such as mica can scatter acoustic energy, sometimes attenuating the signal so greatly that no realistic measurement can be made. (10) Bentonitic and fluid-sensitive shales exhibit very low resistivity values, suggesting very high formation pressures that are seldom present (Fig. 7-45).

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

4

\

233

5

,;

r 4 2 5

lo

20

R,.Rm

Fig. 7-45. Effect of bentonitic shale streaks on shale resistivity plots.

(11) Avoid log readings from zones that are severely washed out because all log measurements are affected. (12) Major changes in bit size affect resistivity parameters. (13) Recognize major lithology changes; e.g., limey shales that may occur in normal or abnormal pressure regimes. Limey shales cause resistivity to increase and acoustic transit time to decrease. This was illustrated earlier where it resulted in computing excess mud weight requirements. Gulf Coast (USA) experience has also shown that specific temperature ranges host major changes in shale properties; e.g., higher resistivity values that bear no relation to formation pressure variations. Correction methods for lithology effects are attempted successfully in some local situations, but beware of applying such corrections universally. (14) Some observers have noted that thick, massive shale sections display a decreasing pressure gradient that is a function of the proximity to permeable sands. This has clear implications for drilling, testing, and completion techniques in that higher mud weights are necessary to prevent the shales from sloughing and heaving, but concern must also be directed toward circulation loss that can occur in adjacent lower-pressured formations. In such cases, the shale resistivity values should be replotted on an expanded depth scale and plot all available shale data as close as possible to the sands. A well drilled through the Springer sand in Oklahoma (US) demonstrates this (Fig. 7-46). (15) Make certain the normal trend line is realistic, because it is the basis for selecting the top of abnormal pressured zones and used for quantitative pressure interpretation. In ultra-deep wells, accurate normal compaction trend lines are of the utmost importance, because with increasing depth, any deviation from the correct trend line becomes enhanced, and aggravates quantitative pressure calculations. Proper trend lines are important in boreholes plagued by major washouts, presence of abrupt age/lithology changes, thick and massive pressure

E.L. BIGELOW

15

’ 0

!5

Fig. 7-46. Formation pressure gradients in shales as a function of proximity to permeable sands. Note pressure gradients on expanded shale resistivity in the vicinity of Springer Sand (Oklahoma, USA).

caps, etc. No fixed or universal rules establish proper trend lines; i.e., there is no substitute for experience. Use all the available data, not well data alone. (16) If an interpretation is proven wrong, return to and restudy the pressure plots of all available data. Define the cause of error, and gain the experience of knowing how to avoid technical and financial problems prior to drilling the next well.

7.14. CONCLUSIONS

Detection and evaluation of abnormally pressured horizons are provided by many subsurface and surface techniques. Geophysical methods, drilling parameters, measurements of the drilling fluid and well cuttings, well log measurements, and direct downhole pressure-measuring devices are included in the arsenal of information. A large volume of technical material that includes both theoretical and practical considerations is available. Wireline logs provide some of the best qualitative and quantitative detection and evaluation methods, but they must be considered “after-the-fact’’ measurements. Measurement-while-drilling (MWD) offers important resistivity criteria during the drilling operation. In 1965, Hottman and Johnson discussed methods to estimate formation pressures from log-derived shale values (resistivity and acoustic). Since then, several investigators have demonstrated the potential of other log measurements. The manner in which several of these log measurements are used to identify hydrostatic, normal pressures, and overpressures is summarized in Fig. 7-47. Acoustic transit time and shallow reading resistivity devices (focused, spherical focused, and short normal) are the logging tools that are most valuable for qualitative and quantitative in-situ formation pressure evaluations. These techniques have proven their worth and will continue to do so. Application is not always straightfor-

WELL LOGGING METHODS TO DETECT ABNORMAL PRESSURE

235

NORMAL

I c

n OVERPRESSURE LOG R,” (P-ml

LOG C,, (mmnoi

F,“

NaCl 41,” (ppml (rreclfl)

p

(g/cc)

+,

I (10- 3 ~ c m ~

Fig. 7-47. Summation of different well logging parameters to normal and abnormal pressured environments (after Fertl and Timko, 1971a). Courtesy of the Society of Petroleum Engineers.

ward or simple, but complications can usually be recognized and compensated for when investigated thoroughly.

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Desai, K.P. and Moore, E.J., 1969. Equivalent NaCl solutions from ionic concentrations. Log Analyst, 10 (2): 23-29. Dewan, J.T. and Allaud, L.A., 1953. Environmental basis for neutron logging interpretation. Pet. Eng., 25 (9): B49-B54. Dickey, P.E., 1969. Increasing concentration of subsurface brines with depth. Chem. Geol., 4 361-370. Doll, H.G., 1948. The SP log: theoretical analysis and principles of interpretation. Trans. AIME, 179: 146- 186. Doll, H.G., 1949. Introduction to induction logging and application to logging of wells drilled with oil-base mud. Trans. AIME, 186: 148-162. Elphick, R.Y., 1991. Determining geopressures from resistivity logs. Geobyte, 6 (3): 48-58. Ferran, L.H., 1973. Evaluation of Abnormally High and Low Pressured Morrow Sands in Notthwestern Oklahoma Using Well Logs and Water Sample Data. M.S. Thesis, University of 'hlsa, TUsa, Okla., 110 pp. Fertl, W.H., 1976.Abnormal Formafion Pressures; Implications to Exploration, Drilling, and Production of Oil and Gas Resources. Elsevier, Amsterdam, 382 pp. Fertl, W.H., 1987. Pulsed neutron capture logs evaluate geopressure environments. 19th Annual Offshore Technology Conference, Houston, Texas, April 27-30. Fertl, W.H. and Chilingarian, G.V., 1977. Importance of abnormal formation pressures. J. Pet. Techno/., April. Fertl, W.H. and Chilingarian, G.V., 1988. Detection and evaluation of geopressured subsurface formations based on dielectric (electromagnetic wave propagation) measurements. Energy Sources, 10: 195-200. 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. Fertl, W.H. and Ilavia, P.E., 1977. Detection and evaluation of abnormally high formation pressures using the team approach. Trans., 6th Formation Evaluaiion Symposium ofthe Canadian Well Logging Society, Calgary, Aka., October 24-26. Fertl, W.H. and Leach, W.G., 1988. Economics of Hydrocarbon Reserves in Overpressured Reservoirs Below 18,000 ft in South Louisiana. SPE 18146, Society of Petroleum Engineers 63rd Annual Technical Conference and Exhibition, Houston, Texas, October 2-5. Fertl, W.H. and Leach, W.G., 1990. Formation temperature and formation pressure affect the oil and gas distribution in Tertiary Gulf Coast sediments. Trans., Gulf Coast Assoc. Geol. SOC.,40: 205-216. Fertl, W.H. and Timko, D.J., 1970a. Occurrence and significance of abnormal pressure formations. Oil GusJ.,68(1): 97-108. Fertl, W.H. and Timko, D.J., 1970b. How abnormal pressure detection techniques are applied. Oil Gas J., 68(2): 62-71. Fertl, W.H. and Timko, D.J., 1970c. Association of salinity variations and geopressures in soft and hard rocks. Trans., Society of Professional Well Log Analysts, 11th Annual Logging Symposium, Los Angeles, Calif. Fertl, W.H. and Timko, D.J., 1970d. Occurrence of cemented reservoir roof rock and geopressure cap rock and its implication in petroleum geology and geohydrology. SPE 3085, 45th AIME Full Meeting, Houston, Texas, October. Fertl, W.H. and Timko, D.J., 1971a. Parameters for identification of overpressured formations. SPE 3223, Society of Peiroleum Engineers 5th Conference on Drilling and Rock Mechanics, University of Texas, Austin, Texas, January. Fertl, W.H. and Timko, D.J., 1971b. Application of well logs to geopressure problems in the search, drilling, and production of hydrocarbons. Colloq. A.R. TE.R, French Petroleum Institute, Rueil, June, Paper No. 4. Fertl, W.H. and Timko, D.J., 1971c. Salinity plots evaluate subsurface formations. World Oil, 173 (1): 93- 100. Fertl, W.H. and Timko, D.J., 1971d. How downhole temperatures affect drilling pressures. World Oil, 175 (3). Fertl, W.H. and Timko, D.J., 1972. How downhole temperatures, pressures affect drilling, 4. Pitfalls in overpressure prediction. World Oil, 175 (4): 45-50.

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Foster, J., Jr., 1990. Pore-pressure plot accuracy increased by multiple trend lines. Oil Gas J., 88(19): 100-108. Fowler, W.A., Jr., 1968. Pressure, hydrocarbon accumulation and salinities - Chocolate Bayou Field, Brazoria County, TX.SPE 2226, 43rd AIME Fall Meeting, Houston, Rxas, September. Foster, J.B. and Whalen, H.E., 1965. Estimation of formation pressure from electrical surveys, offshore Louisiana. SPE 1200, 40th AIME Fall Meeting, Las Vegas, Nev., October. Gondoin, M., Tixier, M.P. and Simard, G.L., 1957. An experimental study of the influence of the chemical composition of electrolytes on the SP curve. Trans. AIME, 210: 58-72. Ham, H.H., 1966. A method of estimating formation pressures from Gulf Coast well logs. Trans., Gulf Coast Assoc. Geol. SOC.,16: 185-197. Hedberg, H.D., 1936. Pore- Water Chlorinitiesof Subsurface Shales. Ph.D. Thesis, University of Wisconsin, Madison, Wisc., 121 pp. Hicks, W.G. and Berry, J.E., 1956. Application of continuous velocity logs to determination of fluid saturation of reservoir rocks. Geophysics, 21: 739-754. Hilchie, D.W., 1969. Some aspects of pulsed neutron logging. LogAnalysr, lO(2): 7-18. Hill, H.J. and Anderson, A.E., 1959. Streaming potential phenomena in SP log interpretation. Trans. AIME, 216 203-208. 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 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. Bull. Geol. SOC. Am., 70: 115-166. Hunt, J.M., 1990. Generation and migration of petroleum from abnormally pressured fluid compartments. Bull., Am. Assoc. Pet. Geol., 74(1): 1-12. Jones, B.R., 1972. The use of downhole gravity data in formation evaluation. 13th Annual Society of Professional Well Log Ana!vsts, Logging Symposium, lhlsa, Okla. Jones, B.R., 1972. Borehole gravity tool spots distant porosity. World Oil, 175 (2): 56-59. Jones, B.R., Jageler, A. and Nettleton, L.L., 1971. Applications of borehole gravity data. 41st Annual SEG Meeting, Houston, Texas, November. Jones, P.H., 1968. Hydrodynamics of geopressures in the northern Gulf of Mexico Basin. SPE 2207, 43rd AIME Fall Meeting, Houston, Texas, September. Keyser, W., Johnston, L.K., Reeves, R. and Rodriguez, G., 1991. Pore pressure prediction from surface seismic. World Oil, 212(9): 115-124. Korringa, J., 1962. Theory of spin pumping and relaxation in systems with a low concentration of electron spin resonance centers. Phys. Rev., 127: 1143-1149. Kunz, K.S. and Moran, J.H., 1958. Some effects of formation anisotropy on resistivity measurements in boreholes. Geophysics, 23: 770-794. Leach, W.G. and Fertl, W.H., 1990. The relationship of formation pressure and hydrocarbon temperature to lithology and hydrocarbon distribution in Tertiary sandstones. Paper E, International Well Logging Symposium, Society of Professional Well Log Analysts, Beijing, 14 pp. Lesage, M., Hall, P., Pearson, J.R.A. and Thiercelin, M.J., 1991. Pore-pressure and fracture-gradient predictions. J. Pet. Techno!., June. Levorsen, A.I., 1967. Geology of Petroleum. W.H. Freeman and Co.,San Francisco, Calif., 2nd ed., 724 PP. Lindberg, P., Riise, R. and Fertl, W.H., 1980. Occurrence and distribution of overpressures in the northern North Sea. SPE 9339, 55th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers, Dallas, Texas, September 21-24. Lindtrop, N.T., 1927. Outline of Water Problems in New Grozny Oil Field, Russia. Bull., Am. Assoc. Pet. Geol., 11: 1037-1043. Loren, J.D. and Robinson, J.D., 1970. Relations between pore size, fluid and matrix properties and NML measurements. SOC.Pet. Eng. J., 1 0 268-278. b u d e n , L.R. and Woods, E.W., 1970. Is shale remineralization a cause for formation damage? World Oil, 170(2): 55-58.

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239

Timko, D.J., 1973. How downhole temperatures, pressures affect drilling: needless spending of drilling and exploration money can be predicted - and prevented. World Oil, 176 (8). Timko, D.J. and Fertl, W.H., 1970. Hydrocarbon accumulation and geopressure relationship and prediction of well economics from log calculated geopressures. SPE 2990, 45th AIME Fall Meeting, Houston, Texas, October. Timko, D.J. and Fertl, W.H., 1972a. How downhole temperatures, pressures affect drilling: predicting hydrocarbon environments with wireline data. World Oil, 175 (5). Timko, D.J. and Fertl, W.H., 1972b. How downhole temperatures, pressures affect drilling: correlating geopressure gradients with hydrocarbon accumulations. World Oil, 175 (6). Timko, D.J. and Fertl, W.H., 1972~.How downhole temperatures, pressures affect drilling: the shale resistivity ratio - a valuable tool for making economic drilling decisions. World Oil, 175 (7). Timko, D.J. and Fertl, W.H., 1973. How downhole temperatures, pressures affect drilling: miscellaneous ways to detect abnormal pressure. World Oil, 176 (10). Timm, B.C. and Maricelli, J.J., 1953. Formation waters in southwest Louisiana. Bull., Am. Assoc. Pet. Geol., 37: 394-409. Timur, A,, 1969. Pulsed neutron magnetic resonance studies of porosity, movable fluid, and permeability in sandstones. Tram, AIME, 2 4 6 775-786. Tittle, C.W., 1961. Theory of neutron logging, I. Geophysics, 26: 27-39. Tittman, J. and Wahl, J.S., 1965. The physical foundations of formation density logging (gammagamma). Geophysics, 30: 284-294. Tittman, J., Sherman, H., Nagel, W.A. and Alger, R.P., 1966. The sidewall epithermal neutron porosity log. J. Pet. Technol., 18: 1351-1363. Tixier, M.P., Alger, R.P. and Tanguy, D.R., 1960. New developments in induction and sonic logging. J. Pet. Technol., 12: 79-88. Von Engelhardt, W., 1961. Neue Ergebnisse der Tonmineralienforschung. GeoL Rundsch., 51: 457-477. Von Engelhardt, W. and Gaida, K.H., 1963. Concentration changes of pore solutions during the compaction of clay sediments. J. Sediment. Petrol., 33: 919-930. Wallace, W.E., 1964. Will induction log yield pressure data? Oil Gas J., 62 (37): 124-126. Wallace, W.E., 1965a. Abnormal subsurface pressures measured from conductivity or resistivity logs. Society of Professional Well Log Analysts, 6th Annual Well Logging Symposium, Dallas, Texas. Wallace, W.E., 1965b. Application of electric-log measured pressures to drilling problems and a new simplified chart for well site pressure computation. Log Analyst, 6 (6):26-38. Weakley, R.R., 1989. Recalibration techniques for accurate determinations of formation pore pressures from shale resistivity. SPE 19563, Society of Petroleum Engineers Annual Technical Conference and Exhibition, Drilling, pp. 457-466. Weakley, R.R., 1990. Plotting sonic logs to determine formation pore pressures and creating overlays to do so worldwide. IADCISPE 19995. Weakley, R.R., 1991. Determination of formation pore pressures in carbonate environments from sonic logs. Paper 90-9 in Technology in the 90s; Prospering in a Changing Environment: Society of CIMISPE International Technical Meeting, Preprints, 1, 19 pp. Weaver, C.E. and Beck, K.C., 1971. Clay water diagenesis during burial: how clay becomes gneiss. Geol. SOC.Am., Spec. Pap., 134, 93 pp. Wichmann, PA., Youmans, A.H. and Hopkinson, E.C., 1967. Advances in neutron lifetime logging. J. Pet. Technol., 19: 479-487. Williams, D.M., Cowper, D.R., Nieto, J.A., Hurley, M.T. and Schmitt, D.P., 1991. Shear wave acoustic logging in slow formations - examples and problems. Trans., 14th European Formation Evaluation Symposium, London, December. Wyllie, M.R.J., 1949. A quantitative analysis of the electro- chemical component of the SP curve. J. Pet. Technol., 1: 17-26. Wyllie, M.R.J., 1951. An investigation of the electrokinetic component of the SP curve. Trans. AIME, 1 9 2 1-15. Wyllie, M.R.J., 1963. The Fundamentals of Well Log Interpretation. Academic Press, New York, N.Y., 3rd ed., 238 pp.

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Wyllie, M.R.J., De Witte, A.J. and Warren, J.E., 1958a. On the streaming potential problem. Trans. AIME, 213: 409-417. Wyllie, M.R.J., Gregory, A.R. and Gardner, G.H.F., 1958b. An experimental investigation of factors affecting elastic wave velocities in porous media. Geophysics, 23: 459-494. Youmans, A.H., Hopkinson, E.C., Bergan, R.A. and Oshry, H.I., 1964. Neutron lifetime, a new nuclear log. J. Pet. Technol., 16(3): 319-328. Youmans, A.H., Hopkinson, E.C. and Wichmann, P.A., 1966. Neutron lifetime logging in theory and practice. Society of Professional Well Log Analysts, 7th Annual Well Logging Symposium, Tulsa, Okla. Zanier, A.M., 1969. Use of the salinity principle to find formation geologic age. Oil Gas J., 67(50): 84-85. Zanier, A.M. and Tirnko, D.J., 1970. Prediction of Morrow Sand performance and geological environment by well log salinity. Paper 85I-44-B, API Mid-Continent Spring Meefing, Wichita, Kansas. Zemanek, J., Angona, EA., Williams, D.M. and Caldwell, R.L., 1984. Continuous acoustic shear wave logging. Trans., Society of Professional Well Log Analysts, 25fh Annual Logging Symposium, New Orleans, La., June.

Sfudies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. F e d , R.E. Chapman and R.F. Hotz 8 1994 Elsevier Science B.V. All rights reserved

241

Chapter 8

SEISMIC PREDICTION OF OVERPRESSURE CONDITIONS AHEAD OF THE BIT IN REAL DRILL TIME BOB A. H A R D A G E

8.1. INTRODUCTION

This chapter illustrates how surface-recorded seismic data can be used to infer the subsurface location of overpressure zones. Basically, the detection of overpressure conditions by means of surface seismic data involves performing closely spaced, detailed analyses of the stacking velocity functions along a seismic line, and then assuming that any reversal in what should be a monotonically increasing trend of velocity with increasing reflection time is an indication of an abnormally high pore pressure at the depth where the velocity decrease occurs. These surface-determined seismic velocity reversals, particularly when coupled with supportive geological information, have been reasonably reliable indicators of overpressured stratigraphic intervals. However, the seismic depth prediction of the overpressured zones is sometimes not accurate enough for precisely defining casing points and mud programs. For this reason, there has been considerable interest in improving both the detection and the depth prediction of overpressure conditions by vertical seismic profiling (VSP). The recent development of recording VSP-equivalent data in real drill time by using an active drill bit as a seismic energy source is attracting even more interest from engineers who are concerned with insuring safe and economical drilling practices in pressure problem areas. One of the primary reasons for this strong interest is that allowing a rotating drill bit to be a seismic source provides a predict-ahead capability in real drill time and does not interfere with or delay drilling progress. Before describing drill bit data examples, the principles of conventional VSP predict-ahead technology and the concept of inverse VSP measurements will be reviewed.

8.2. PREDICTING A H E A D OF THE BIT WITH VSP DATA

There are several reasons why VSP data have the potential of predicting a more accurate estimate of a subsurface impedance sequence than can surface-recorded seismic data. The first is that a VSP, if it is recorded using a broadband seismic source, will typically have a wider frequency bandwidth than will surface data, and thus will have a greater resolving power. This increased frequency content results because the travel path involved in VSP recording is shorter than the path required in surface recording, and also because the VSP raypath traverses the attenuating near-surface layer only once, as shown in Fig. 8-1.

242

B.A. HARDAGE

(4

(8)

Fig. 8-1. A comparison of the seismic travel paths involved in the surface detection (A) of overpressure conditions and in VSP detection (B). The symbols G and S represent the geophone and the source, respectively.

A second reason is that seismic inversion techniques require that the basic wavelet contained in the reflection response be known. In VSP, the basic source wavelet contained in the upgoing reflection wavefield generated below the stratigraphic depth at which a seismic predict-ahead is to start is precisely defined by the downgoing VSP first arrival measured immediately above that depth. In surface-recorded seismic data, however, the downgoing wavelet must be estimated by detectors located on or near the surface, and it is not possible to deterministically measure the downgoing wavelet at the depth where the seismic inversion is to start, which is where its amplitude, phase and frequency content need to be known. Thus, a VSP-based inversion should be more accurate than a surface-based inversion. There are several published examples of VSP data being used for determining impedance changes ahead of the bit (Grivelet, 1983; Stone, 1983; Stewart, 1984; Toksoz and Stewart, 1984, pp. 122-147). A common, robust technique for performing this inversion of seismic reflection data into impedance estimates is the Generalized Linear Inversion (GLI) procedure, which is summarized by the flow chart in Fig. 8-2. In the GLI technique, an initial impedance model of the earth is assumed, and the synthetic seismic reflection response of this impedance layering is calculated. This response is designated A ( t ) in Fig. 8-2, and it is compared in a least-squares sense to the actual seismic response, B ( t ) . It is at this point where the basic wavelet contained in the actual reflection response must be known with considerable accuracy in order for it to be used in calculating the synthetic reflection response. If these two functions, A ( t ) and B ( t ) , do not agree within an accepted tolerance error, E , then the impedance model is altered, a new synthetic response, A ( t ) , is calculated, and the comparison is repeated. This process is iterated until the synthetic response satisfactorily matches the actual response, and then it is assumed that the last impedance model in the iteration is the best estimate of the impedance sequence that can be obtained from the seismic reflection data. An example of an inversion of VSP data into an estimate of an overpressured impedance sequence is shown in Fig. 8-3. The actual seismic response, B ( t ) in

SEISMIC PREDICTION OF OVERPRESSURE CONDITIONS

243

AFinal lrnpsdancs

Fig. 8-2. A data flow chart illustrating the concept of the Generalized Linear Inversion (GLI) technique that is commonly used in predict-ahead algorithms.

I .o

t

a

?

0

c 2.0

2.5

Fig. 8-3. An example of a depth prediction of an overpressure zone using VSP data processed with a Generalized Linear Inversion technique (Hardage, 1985).

244

B.A. HARDAGE

Fig. 8-2, is plotted in column E; the all important actual seismic wavelet deterministically measured by a geophone immediately above the prediction interval is shown in column D; the synthetic response, A ( t ) in Fig. 8-2, is in column C; and the final impedance model that produced this synthetic response is shown in column A. The arrow on curve A indicates the predicted onset of overpressure, and that prediction can be compared with the evidence provided by the actual logs, particularly the density log, on the right side of the figure. In this case, the VSP prediction of the depth of overpressuring is accurate to about 100 feet (30 m).

8.3. T H E INVERSE VSP CONCEPT

The practice of recording VSP data by using a borehole energy source rather than a surface source is termed inverse VSP, or reverse VSP, or inverted VSP, depending on who is speaking or writing on the topic. The term “inverse VSP” will be used in this discussion, and the conventional method of recording VSP data will be termed “forward VSP”. A comparison of the source-receiver geometries and raypaths involved in these two approaches to recording borehole seismic data is shown in Fig. 8-4. Basically, the source and receiver positions used in a forward VSP measurement are simply exchanged in an inverse VSP. In each of the two techniques, the raypath between source and receiver should be identical, and the same subsurface reflection point, R, should be illuminated by the raypath if the two sources have similar radiation patterns and the receivers have similar antenna patterns. Under these conditions, the same subsurface imaging capability should be achieved by either technique. The principal advantage of the inverse VSP approach is that the use of surface receivers rather than surface sources allows the seismic wavefield to be sampled at a large number of surface locations simultaneously and at an economical cost. Thus, large volume, 3-D imaging around a borehole is economically viable with the inverse VSP technique, but is usually prohibitively expensive in a forward VSP.

U

U

(4

(6)

Fig. 8-4. A comparison of thc source-rccciver geometries and raypaths involved in forward VSP (A) and invcrse VSP (B). S rcprcscnts the source, G is the gcophone, and R is a spectral reflection point.

SEISMIC PREDICTION OF OVERPRESSURE CONDITIONS

245

8.4. BOREHOLE SOURCES

The major barrier to developing inverse VSP technology has been the difficulty of finding an appropriate borehole energy source. Numerous people have conducted tests with various sources such as air guns (Parrott, 1980), piezoelectric devices (Balogh et al., 1988), electric arc discharges (Owen et al., 1988), mechanical vibrators (Paulsson, 1988), and fluid resonators (Kennedy et al., 1988). Two physical restraints have made the selection of an appropriate borehole source difficult: (1) The source cannot cause physical damage to the casing or the cement bond. This requirement means that the energy output of the source must be carefully controlled so it stays well below any possible damage threshold. Sometimes, this restriction eliminates strong impulsive sources such as explosives or large air guns from consideration. (2) The source cannot produce tube waves in the fluid column of the well. This requirement may be the most demanding one to satisfy. If tube waves are created, then they in turn generate secondary body waves at every impedance contrast that they encounter as they repeatedly traverse the wellbore. These secondary sources occur at various time delays and create such a complicated composite wavefield at the earth’s surface that it is virtually impossible to process the data with current software algorithms. One of the more promising borehole sources is the swept frequency resonator (Kennedy et al., 1988). This device emits a broadband, low energy wavefield over a long sweep time, which in preliminary field tests has created no damage to casing or to cement bonds. However, the wavefield is still of sufficient strength to produce good signal-to-noise conditions over propagation distances of several thousands of feet. Perhaps most importantly, the portion of the fluid column that is set into resonance is isolated by gas-filled bladders that prevent tube waves from propagating up and down the well.

8.5. THE DRILL BIT SOURCE

An even more versatile inverse VSP borehole source concept is the idea of taking advantage of the seismic radiation that results as a drill bit digs through a sedimentary sequence with an appreciable weight on the bit (Rector et al., 1988). This source has the practical advantage that no instrumentation goes downhole, and thus it does not endanger the well to the possibility of an expensive fishing operation to retrieve a stuck tool. Neither does it require that drilling be halted while seismic measurements are made. This latter source feature means that the drill rig does not have to stand by for several hours while seismic data are recorded, and this time saving can significantly reduce the drilling costs associated with any well where borehole seismic data are required. Equally important is the fact that these seismic data are acquired in real drill time, and thus offset imaging and prediction ahead of the bit can be made at various time intervals during the drilling if desired. In order for the seismic wavefield created by a drill bit to be effectively used in predict-ahead applications, the wavefield must possess good signal-to-noise (S/N)

B.A.HARDAGE

$3

40

€b

eb

r o o 1 i o

Frequency (Hz)

Fig. 8-5. The frequency spectrum measured at the top of a drill string when a rotary cone bit was cutting section at a depth of approximately 8000 feet.

conditions and contain a relatively broad range of frequencies. Thus, it is important to define these two properties, SIN and bandwidth, for the wavefields created by an active drill bit. Two data examples will be used to illustrate that a drill bit can generate an adequate seismic source spectrum and can also produce an acceptable signal-tonoise wavefield at significant propagation distances. Evidence that the drill bit spectrum contains a wide range of frequencies is shown in Fig. 8-5. This spectrum was calculated from the response measured by receivers mounted on the top of a drill string as a rotary cone bit was working at a depth of about 8000 feet, and it is thought to be a reliable estimate of the frequency content of the seismic wavefield that radiates away from the bit and propagates through the earth as a body wave. This spectrum is reasonably flat from 15 to 80 Hz, which is a good bandwidth in the onshore area where these data were recorded. The receiver response was sampled at 4 ms, thus the spectral cutoff at 80 Hz is largely due to the alias filter in the recording system. The drill bit seismic wavefield could, in this instance, have significant energy above 80 Hz. A n example of the potential signal-to-noise properties of the seismic wavefield produced by a drill bit is shown in Fig. 8-6, where there is a side-by-side comparison of a VSPCDP image created from a drill bit wavefield and a VSPCDP image constructed from a forward VSP using an air gun energy source. Some of the techniques used to process this drill bit seismic wavefield are described by Rector et al. (1988). Air guns are a widely accepted seismic source, and in the area where these data were recorded, air guns produce good signal-to-noise wavefields. By visual comparison of the two images, it appears that the signal-to-noise quality of the drill bit wavefield is equivalent to that of the air gun wavefield.

SEISMIC PREDICTION OF OVERPRESSURE CONDITIONS

Tomex

247

VSP

Fig. 8-6. A comparison of VSPCDP images constructed from a drill bit generated seismic wavefield (left) and an air gun wavefield (right) recorded in the same well. The registered trademark TOMEX@ is used by Western Atlas International to specify their technology which produces drill bit seismic wavefields.

8.6. PREDICT-AHEAD DATA EXAMPLES

The subsurface images in Fig. 8-6 are one form of a predict-ahead capability in that each image shows the reflection sequence below the TD of the well which occurs at 1.64 s. However, the large offset involved in the source-receiver geometry used in this instance does not image directly beneath the bit, which is where the prediction is usually needed for purposes of drilling safety. In the flat, horizontal structural layering penetrated by this well, a zero-offset source-receiver geometry is required for predicting directly ahead of the bit. Nonetheless, these offset images demonstrate that real drill-time imaging of the impedance sequence below, and laterally displaced from, the bit are possible. This type of lateral predict-ahead capability may often be needed in order to decide in real drill-time if a well should be deviated to penetrate a more attractive stratigraphic section. In this instance, there are no abnormal pressure conditions to be predicted. An example of an unprocessed drill bit wavefield recorded with a surface receiver array positioned near the well head of a vertical well drilled in an area of overpressuring is shown in Fig. 8-7. Because of the near-offset positioning of the array, the reflection events contained in these traces, once they are extracted from these raw field data, allow stratigraphic conditions to be imaged vertically beneath the deepest position of the bit. The depth marked A represents the top of an overpressured section penetrated by the well, and to demonstrate the ability of the drill bit wavefield to predict geopressure conditions ahead of the bit, the reflected wavefield obtained from

248

B.A.HARDAGE

Time (s)

Fig. 8-7. A drill bit wavefield recorded with an array of geophones positioned near the well head as the bit progressed vertically from 2212 to 8512 feet. Depth A represents the top of an overpressured section.

only those traces above A will be used to look ahead and predict the effects of geopressuring before the bit penetrates the hazardous zone below A. The primary reflection events contained in the drill bit responses recorded above A are spliced into a seismic line crossing the well in Fig. 8-8. The traces in Fig. 8-7 actually extend to 5 s, rather than to just 2 s as shown, so late arriving reflections can be obtained from interfaces within and considerably below the geopressured section, which ends near the level marked B. These drill bit reflection events satisfactorily agree with the surface-recorded seismic reflection response throughout interval AB and also for some distance below B. Thus, reasonable confidence can be placed in a look-ahead impedance prediction obtained by inverting the drill bit reflection sequence to obtain an estimate of the earth’s velocity and density layering. In order to verify the look-ahead capability of the drill bit wavefield, an inversion program, roughly similar to that described in Fig. 8-2, was used to convert this drill bit reflection trace into a hypothetical velocity-layered earth model. This estimated velocity behavior is shown as the leftmost trace in Fig. 8-9. The lowest frequency portion of this inversion curve (0-5 Hz) was derived from nearby velocity control and not from the reflection trace plotted in Fig. 8-7 since these frequencies are not present in the seismic wavefield. The following logic is usually followed in these types of inversion studies, viz.: “The true earth velocity layering must closely match the estimated velocity curve

SEISMIC PREDICTION O F OVERPRESSURE CONDITIONS

249

Reflected Drill Bit

Fig. 8-8. The primary seismic reflection events (center panel) extracted from the drill bit wavefield generated above depth A. All events below A represent a look-ahead image of the stratigraphy yet to be penetrated by the bit. The bottom of the overpressured section is approximately at depth B . Estimated Velocity (fils x looo)

Measured Velocity (*/ax looo)

i ..

.. ....

.

....

.

. ..--

Density (9mW

. ...

..

. . . .

..

. . . .

... ..-.

Fig. 8-9. A calculated velocity layering (left curve) that can generare the measured drill bit reflection sequence shown in Fig. 8-8. A significant velocity decrease is predicted in interval AB, indicating a geopressured section. The sonic log recorded in the well is shown in the center. Neither this log nor the density log (right curve) were recorded throughout the entire overpressured section.

250

B.A. HARDAGE

(shown in Fig. 8-9) since that layering estimate produces the observed reflection response, and the observed response is similar to nearby surface-recorded seismic control.” Applying this logic means that the geological conditions below depth A can be deduced directly from the estimated velocity model. In this particular case, this velocity response implies that a geopressure condition begins immediately below A since a significant velocity decrease is predicted to occur there. In this instance, this geopressure prediction appears to be valid as shown by the sonic log, plotted in units of feet per second, and by the formation density curve, both of which were recorded in the study well and plotted in Fig. 8-9. Neither of these logs was recorded in the entire overpressured section AB, but the log-measured velocity above A and below B implies that the predicted, look-ahead velocity decrease across AB is reasonable. Knowing the possibility of overpressure problems in real drill-time by using the drill bit as a seismic look ahead energy source offers obvious advantages in drilling safety and in the design of casing and mud programs. This predict ahead capability will probably become a major application area for drill-bit source, inverse VSP technology.

REFERENCES Balogh, W.T., Owen, T.E. and Harris, J.M., 1988. New piezoelectric transducer for hole-to-hole seismic applications. 58th Annu. Int. Meet. SEG, Tech. Prog. Abstr, pp. 155-157. Grivelet, P.A., 1983. Application of iterativc modeling to inversion of VSP. 53rd Annu. Int. Meet. SEG, Tech. Prog. Abstr:, Paper S19.6, pp. 533-535. Hardage, B.A., 1985. Verticai Seismic Profiling, Part A. Principles. Pergamon Press, Oxford, 2nd ed., 509 PP. Kennedy, W., Wiggins, W. and Aronstam, P., 1988. Swept-frequency borehole source for inverse VSP and cross-borehole surveying. 58th Annu. Int. Meet. SEG, Tech. h o g . Abstr, pp. 158-160. Owen, T.E., Balogh, W.T. and Peters, W.R., 1988. Arc discharge pulse for borehole seismic applications. 58th Annu. Int. Meet. SEG, Tech. Bog. Abstl:, pp. 151-154. Parrott, K.R., 1980. An Investigation of the Interior of a Salt Structure Using the Vertical Seismic Profiling Technique. Master of Seismic Thesis, Colorado School of Mines, Golden, Colo. Paulsson, B.N.P., 1988. Three-component downhole seismic vibrator. 58th Annu. Inf. Meet. SEG, Tech. Prog. Abstr, pp. 139-142. Rector, J.W., Marion, B.P. and Widrow, B., 1988. Use of drill-bit energy as a downhole seismic source. 58th Annu. Int. Meet. SEG, Tech. Prog. Abstr, pp. 161-164. Stewart, R.R., 1984. VSP interval velocities from traveltime inversion. Geophys. Prospect., 32: 608-628. Stone, D.G., 1983. Predicting pore pressure and porosity from VSP data. 53rd Annu. Int. Meet. SEG, Tech. Prog. Abstr, Paper S23.8, pp. 601-604. Toksoz, M.N. and Stewart, R.R. (Editors), 1984. Vertical Seismic Profiling, Part B. Advanced Concepts. Pergamon Press, Oxford, 419 pp.

Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.E Hotz 8 1994 Elsevier Science B.V. All rights reserved

25 1

Chapter 9

MEASUREMENT WHILE DRILLING R. DESBRANDES and R. CLAYTON

9.1. INTRODUCTION

Collecting and transmitting downhole data from the bottom of a wellbore during drilling became a commercial success in the late 1970’s. The service is known as Measurement While Drilling, more frequently referred to by its abbreviation MWD. MWD was not a new idea in the 1970’s but, rather, the culmination of years of ideas, experimentation, and general “wishful thinking”. For many years researchers have been looking for simple, reliable rneasurementwhile-drilling techniques. In 1939 an electrical logging/drilling system using a wire was attempted successfully but was not commercialized (Reed, 1939; Mills, 1940). Mud pulse systems were proposed in 1963 (Arps, 1963; A r p s and A r p s , 1964). The first mechanical mud pulse system was marketed in 1964 by Teledrift for transmitting directional information (Roberts and Johnson, 1978). The steering tool, a wireline system that is used with a downhole motor to make directional measurements, was introduced in 1970 (Russell, 1970). Finally, the first modern mud pulse data transmission system was commercialized in 1977 (Spinnler and Stone, 1978). Stateof-the-art surveys of the technology were made in 1978 (Oil and Gus Journal, 1978), in 1988 (Desbrandes, 1988a, b, c), and in 1990 (Desbrandes, 1990). The initial commercial application of measurement while drilling was for directional control, mainly offshore where the high cost of the service was justified. The application has since been extended to formation logging data, then to drilling parameters, and now to safety parameters. Most of the cost in producing a well is expended during the drilling phase. Any amount of information gathered during drilling can be used to make decisions regarding the efficiency of the process. But the scope and ultimate cost to gather and analyze such information must be offset by the decrease in drilling expenditures, i.e., increase in drilling efficiency. Mud logging services, initiated for well control and drilling fluids programs, are a focal point for data gathering and anaIysis of drilling parameters. Sophisticated surface instrumentation, computer technology, and mathematical analyses give skilled drilling engineers the necessary tools to predict a significant portion of downhole drilling parameters with only surface measurements. In the past as drilling technology moved the pursuit of hydrocarbon resources into higher-cost offshore and hostile environments, intentionally deviated boreholes required information such as azimuth and inclination that could not be derived by surface instrumentation alone. Survey instruments, either dropped into the drill pipe for later retrieval or deployed on an electrical cable, to some degree satisfied the requirements but consumed expensive rig time and sometimes pro-

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R. DESBRANDES AND R. CLAYTON

duced questionable results. Hence, the need for real time directional measurements while drilling was increasing and emerging technology would make MWD viable. The race to place a man on the moon and military defense developments provided major advances in electronics, data processing, and materials technology. In a nation stunned by the Arab oil embargo of the 1970’s, the U.S. oil industry was emphasizing the need for new techniques to improve drilling efficiency. MWD appeared not only to offer a technical solution but a lucrative one at that. A study performed in 1978 (McDonald, 1978) revealed 44 known companies to be involved in the development of MWD. The interests of those companies ranged from financial investments in MWD projects to hardware development programs. The list was believed to be as complete as possible since McDonald obtained information from literature and personal contacts with knowledgeable industry personnel. Nevertheless, much of the early work was regarded as proprietary and often confidential due to its competitive nature. Out of these 44 companies, only 15 had active MWD hardware-directed projects in stages from prototype design to field testing. As of this writing seven companies, only four of which were on the original list of 44,offer commercial services. The key to the incorporation of MWD into the drilling process was the development of a reliable, cost-effective data transmission system. Hardware that could survive the rigors of the harsh downhole drilling environment and not significantly perturb the drilling operation would ultimately satisfy the MWD requirements in high-cost wells. Hence, initial emphasis was placed on the communications network and secondarily on parameter measurement and data handling.

9.2. TELEMETRY TECHNIQUES

Classical communication networks consist of three basic components: transmitter, communications link, and receiver. The communications link has absorbed most of the R and D expenditures. Four choices of communications links are available: (1) the drilling fluid; (2) the drillstring; (3) the earth surrounding the borehole; or (4) the addition of an electrical conductor. MWD telemetry techniques involving one or more of these links have become known as mud pulse, electromagnetic, acoustic, and hardwired. Only mud pulse telemetry has succeeded so far in fully commercial practice.

9.2.1. Hardwired telemetry Electric logging introduces electrical cables into the borehole and drill pipe but precludes simultaneous drilling operations. Directional drilling, however, requires the use of downhole steering and survey tools while drilling. With downhole drilling motors, the real time measurement can be carried out with a wireline since the drill pipe is not rotating. However, the encumbrance of the electrical cable seriously affects drilling efficiency. Several companies developed more efficient hardwired systems since an electrical conductor provides the maximum possible data rate.

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253

Shell developed a system (Dennison, 1976) in which the electrical cable was made part of each joint of drill pipe. Each box and pin of the drill pipe was configured with special connectors that would provide an electrical connection across the tool joint under normal drillstring make-up. The high cost of the special drill pipe and potential reliability problems with multiple series connectors overshadowed its benefits. k o n developed another hardwired concept (Heilhecker, 1975) in which long sections of electrical cable were doubled up and stowed in the bore of a drillstring. Additional standard drill pipe is added until the cable is pulled to its full length. This technique eliminates multiple connectors and dedicated drillstring as in the Shell system but introduces considerable erosion, abrasion, and potential damage to the cable in the drill pipe. After significanttesting the technology was abandoned. Znstitut Franpis du Petrole developed a drilling technique (Thiery, 1978) which uses a continuous flexible drillstring for straight and deviated wells. Imbedded in the drillstring are electrical conductors for both telemetry and remote control of downhole equipment. While feasibility was proven, inherent problems with the hardware limited the application of the technique. General Electric joined forces with Cullen Research (Traynor, 1978) to demonstrate the operational effectiveness and economic viability of the Electrodril system. Electrodril uses a downhole electric motor for drilling, and electronic downhole data acquisition and monitoring system, standard drill pipe, and an easily deployed cable and wet connector system (Aker et al., 1966). Like Flexodrill (Thiery, 1978), which is a drilling technique using a flexible drillstring and developed by the Institut Fransais du Petrole, feasibility was proven. However, GE would not independently fund the additional research required, and the program was dropped. Hardwired telemetry can provide a high data rate, two-way communications, and ample electrical power. However, rig cost, reliability of connectors, abrasion and failure of the cable due to fluid flow and pipe rotation, and equipment encumbrances have challenged further development. Only low-cost drilling operations revert to wireline steering tools for directional drilling where MWD cannot be cost justified. The steering tool technique involves lowering a directional tool in the drillstring when a downhole mud motor is used. The directional tool gives the inclination and azimuth of the drill collar in real time. 9.2.2. Acoustic telernety The drillstring as well as the earth can be used to communicate downhole information to the surface. Acoustic telemetry through the earth to delineate subsurface lithology is continuing to be developed and refined. Vertical Seismic Profiling (VSP) has been well established as a means to provide seismic images near a wellbore. A new seismic technique (Rector and Marion, 1988) produces a VSP while drilling. The natural vibrations created by the drill bit become a downhole energy source for surface receivers and subsequent survey generation (see Chapter 8 for details). Elf-Aquitaine devised a scheme (Raynal et al., 1970) in which vibrations sensed on the drill pipe are used to indicate drill bit condition and drilling performance. But difficulty in the 1960’s in deciphering bit vibrations from

254

R. DESBRANDES AND R. CLAYTON

other sources of drilling noise resulted in little industry interest. A R C 0 conceived and demonstrated a similar technique, known as Advanced Drillstring Analysis and Measurement System (ADAMS), as a means to analyze efficient drillstring performance (Besaisow and Payne, 1988). Through the use of sophisticated transducer technology, specialized algorithms, and personal computers, on-site analysis can minimize drillstring vibrations and optimize penetration rates. Even though drillstring and earth measurements are made while drilling, these techniques do not use the acoustic channel as a true MWD communications medium for downhole parameters other than acousticrelated data. Acoustic MWD research was pursued (McDonald, 1978) by several companies (e.g., Sandia Laboratories, Motorola, and Sperry Research) to develop an acoustic signaling scheme for transmission through the drillstem. Rapid signal attenuation and other noise generated by the drilling environment limited the usefulness to depths of approximately 3000 ft. Although used in production wells for pressure monitoring and control of valves, acoustic transmission was not a viable MWD transmission scheme. 9.2.3. Electromagnetic telemetry

The drillstring and earth have been studied as means to transmit electromagnetic (EM) signals in telemetry methods. McDonald’s 1978 study revealed that seven companies were researching EM technology. Most of the work was funded through government contracts relating to coal mine safety, military applications, and nuclear testing. A n oilfield application of EM for formation logging while drilling was studied by Lane Wells in the 1950’s (Applied Research Associates, 1959). With testing and experimentation supporting theoretical work, the conclusion was reached that depth limitations in highly conductive sediments would preclude its use as a general MWD telemetry system. Two basic means of transmitting electromagnetic signals are: (1) inducing a magnetic field about the drill pipe and into the earth; and (2) generating into the drillstem a current that returns through the earth. The generation of current is the more common technique and has been implemented in one of two methods. A toroidal coupling method (Smith, 1983) configures the transducer apparatus as a slender toroidal transformer with a mandrel in the center which serves as the structural member. The direct coupled method (Rubin and Harrison, 1987) requires a complete electrical discontinuity in the drillstring so that an electrical potential difference can be produced across adjacent conducting faces. Articles in the literature (DeGauque and Grudzinski, 1987) indicate continued testing and modeling of electromagnetic communications capabilities of a drillstring. The Geoservices Company is offering an electromagnetic MWD and MAD (Measurement After Drilling) service to a depth of 2000 m at 10 Hz in formations with an average resistivity 10 ohm m or higher (Grudzinski and Isseman, 1990). Figure 9-1 shows a schematic of the path of the current in the earth. The electromagnetic MWD is particularly useful in boreholes drilled with air, gas, mist, foam, or aerated mud.

MEASUREMENT WHILE DRILLING

255

Fig. 9-1. Principle of the Geoservices electromagnetic MWD. An emitting antenna in the drill collar transmits the data to the surface electrodes. A signal can be transmitted downwards to activate or modify the tool mode. (Courtesy of Geoservices Co.)

9.2.4. Mud pulse telemetry

While mud pulse telemetry has the slowest data rate of all the telemetry techniques, it is the only viable MWD system in commercial use today. Compared later in this chapter, seven service companies offer commercial MWD systems today. All generate coded pressure variations in the mud column that are decoded through a pressure transducer on the standpipe at the surface. Pressure pulses travel up the mud column at a velocity of 4000 to 5000 ft/s (1.2-1.5 km/s) or close to the velocity of sound in the mud ( A r p s , 1963). However, factors such as the pulse shape, pulse frequency, system pressure noise, reflections, and detections schemes impose limitations on the information rate or the time it takes to transmit a piece of useable information. All mud pulse systems require the mud pumps to be running to generate the pressure environments. The systems are categorized as either pulse telemetry or continuous-wave telemetry (Anon., 1988). In pulse telemetry, information is sent to the surface by either a positive or negative pressure pulse generated in the drilling fluid.

256

R. DESBRANDES AND R. CLAYTON

MAXIMUM, VALVE TRAVEL MUD VALVI

TURBINE.

ELECTRI CP CABLE

VI BRAT1 ON ISOLATOR

4zLlJR

'

GENERATOR

\

CENTF L ZER

mmR

SENSOR AP ELECTRON] PACKAGE

,

VIBRATION ISOLATOR

I . 3

1 0 0 1 1 0 1 1 0 0 0

v)

a

1 1 1 1 1 1 I I I

I

a

PULSE

b

I

1

I

1

I

I

I

1

1

1

I I I f

I I I I I l l I 1

1

1

I

TIM3

Fig. 9-2. Positive mud pressure pulse transmission system (after Spinnler and Stone, 1978). (a) The downhole tool assembly showing major components. (b) The pressure variation and coding principle (courtesy of Teleco). The binary number shown is 1100110110 or 822 in decimal equivalence.

A positive pressure pulse system (Spinnler and Stone, 1978) varies pressure in the flowing mud column by placing a variable restriction in the path of the mud stream. The restriction, or mud valve, consists of an orifice and a movable poppet as shown in Fig. 9-2. The poppet has two possible positions, either retracted away from the orifice or extended towards the orifice. With the poppet retracted, a negligible pressure drop is effected in the mud as it flows through the orifice. But extended, the effective area for mud flow through the orifice is reduced. Since the flow is essentially constant, a pressure increase occurs. Negative pressure pulse systems (Anonymous, 1978) vary pressure in the flowing mud column controlling a valve which opens and closes a small passageway between the inside and outside (annulus) of the drill collar as depicted in Fig. 9-3. When momentarily opened, a sudden pressure drop is caused inside the drill collar. This pressure drop causes a negative pulse to be transmitted to the surface.

257

MEASUREMENT WHILE DRILLING

b

t

Fig. 9-3. Negative mud pressure pulse transmission system (after Anonymous, 1978). (a) The pulse generator or valve which momentarily vents internal pipe bore pressure to the annulus creating a negative pressure pulse. (b) The pressure variation on coding (courtesy of Gearhart). No pulse is a binary zero and a negative pulse is a binary one.

The continuous-wave system was a concept developed by MobiZ (Patton et al., 1976). A rotary valve is used to generate a pressure wave in the flowing mud column, as seen in Fig. 9-4. The wave is sinusoidal at a constant frequency. Data is transmitted digitally by phase shifting the pressure wave. Regardless of the pressure pulsing scheme, MWD surface systems consist of at least a pressure transducer for signal detection, a signal decoding processor, and various output devices including displays, plotters, and printers. As coding and decoding schemes become more sophisticated, software systems will become increasingly complex. Interpretation software is growing in importance as operators search for additional ways to use downhole information. 9.2.5. Downhole recording An alternative to the real-time telemetry techniques is recorded MWD. Directional drilling requires real-time measurements to be telemetered to the surface in order to control bottom hole assemblies and to keep the borehole on its planned trajectory. However, some measurements can be recorded and studied for analysis when the bit is pulled. k o n developed and used a downhole recorder system (McDonald, 1978) in the late 1960's to measure and record vibration information at the bit. This information was captured purely for research purposes. Services to record formation evaluation data for situations where real-time data

258

R. DESBRANDES AND R. CLAYTON

Fully b

open

Fully closed

Fig. 9-4. Continuous mud pressure wave transmission system (after Patton et al., 1976). (a) The rotary valve or “siren” used to modulatc the continuous 12-Hz pressure wave in the mud flow. (b) One cycle of the wave form.

is not required have been commercialized. In lieu of running some surface and intermediate wireline logs, adequate data is measured and recorded downhole while drilling. As illustrated in Fig. 9-5, a typical configuration records gamma ray and resistivity (Coope and Hendricks, 1984) with the possibility of adding other formation sensors (Fig. 9-5). The primary advantages of recorded MWD over real-time MWD are lower cost to the user and increased amount of data. However, real-time MWD systems are now offering downhole memory (Honeybourne, 1985) for increased data density, particularly in fast drilling intervals. This new technology enables recording formation evaluation information while supplying real-time directional data and/or enhancing real-time data with that which is recorded. 9.2.6. Measurement Afier Drilling (MAD) Downhole recordings can also be made while tripping the drill pipes. Formation evaluation data are recorded during each trip and the invasion effect can be determined (Holbrook, 1985). The recently commercialized electromagnetic MWD can also be used to transmit formation evaluation parameters during tripping since the downhole package is battery-powered. The mud pulse telemetry cannot be used since no circulation can be established during tripping the drill pipes.

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259

Fig. 9-5. Downhole sub to record resistivity and gamma-ray data. (Courtesy of SPWLA, 1984.)

9.3. MWD SENSORS

Data retrieved from a borehole during drilling is acquired for either: (1) directional steering and survey; (2) formation evaluation; (3) drilling efficiency; or (4) safety. Sensors used to obtain downhole data provide information that may apply to one or more of these areas. The following descriptions cover sensor technology that is available on a commercial basis.

9.3.1. Directional steering and survey Early steering tools used a plumb bob equipped with a potentiometer to convert the inclination angle to an electric signal. Plumb bobs have a tendency to oscillate when submitted to the vibration and shock that occurs in a bottomhole assembly during drilling. Plumb bobs have been replaced with accelerometers in today’s technology.

260

R. DESBRANDES AND R. CLAYTON TEST MASS COILS

1

PO

SIGNAL

PROXIMITY SENSORS

Fig. 9-6. In a servo-controlled accelerometer, the test mass is kept in position by the coils (after Desbrandes, 1982).

The principle of a single-axis servo-controlled accelerometer is shown in Fig. 9-6 (Desbrandes, 1982). A test mass is attached to a housing with flexible joints. Two proximity sensors maintain the mass at a given position, up to a maximum acceleration, by controlling the current flowing in two coils. This current generates a force that balances the inertial force. The current is proportional to the acceleration. These sensors can fit in a cylinder 3 cm in diameter as show in Fig. 9-7. They are not perfectly linear and must be calibrated. Furthermore, their performance is dependent on temperature, which must be monitored so that corrections can be made. If the acceleration due to the vibration is greater than the measuring range, then the average reading is not equal to the static acceleration. MWD accelerometers are single-axis instruments and the acceleration is measured along the sensitive axis of the accelerometer. The typical values of the characteristics for an MWD accelerometer are: Measurement range Scale factor Resolution Zero offset Service temperature

= -20 m/s2 to +20 m/s2 = 0.13 mA per m/s2 = 10-~ m/s2 = lo-' m/s2 = -55°C to 100°C

With three accelerometers, three components of the gravity acceleration vector can be measured in any frame of reference. In an MWD tool, the frame of reference is the tool (borehole) axis, the toolface direction and a third axis normal to both. By convention, the z-axis is along the tool body and oriented towards the bit. Axes x and y are perpendicular to the tool body and make a direct orthogonal frame. Figure 9-8 shows a typical accelerometer cartridge. The inclination is given by: for I > 60"

1 = arcsin ([(Gi

+ G;)',']/G]

261

MEASUREMENT WHILE DRILLING

bTOROUER

lEy:E

1

THIN FILM PICKOFF AND TOROUER LEADS

CONNECTOR ELECTR0N IC S

PICKOFFAND DAMPING GAPS

J

PROOF MASS SUBASSEMBLY

PICKOFF PLATE

Fig. 9-7. Q-flex servo controlled accelerometer (courtesy of Sundstrand Data Control). (a) The actual device. (b) A detailed illustration of the component parts.

for I c 60”

I = arccos(G,/G)

where:

G = (Gi

+ G ; + G3O.5

(9-1)

and G , = acceleration along axis x , G , = acceleration along axis y , and G , = acceleration along axis z. The value of G computed in eq. 9-1 represents the value of the gravitational acceleration of the site for valid readings. The measurement of the borehole orientation is carried out with reference to the earth’s magnetic field. Regular compasses are too fragile for the drilling conditions and solid state magnetometers must be used. The most common are the flux-gate, single-axis magnetometers. While their design is complex, the principle is simple. A drive winding is coiled around a high magnetic permeability toroid with a sharp saturation characteristic as shown in Fig. 9-8. When the winding is not energized, the toroid will attract the earth’s field, so-called “gate open”. When a current flows in the drive winding, the toroid saturates and does not attract the earth’s field, “gate

262

R. DESBRANDES AND R. CLAYTON

2-ACCELEROMETER

HOLDING POINT

Y-ACCELEROMETER

23

X-ACCELEROMETER

CONNECTOR HOLDING POINT REFERENCE PIN

Fig. 9-8. T h e three-axes accelerometer unit uses three accelerometers, similar to the one shown in Fig. 9-7, aligned with the two perpendicular horizontal axes and the vertical axis (courtesy of Sundstrand Data Control).

A DRIVE WINDING A

b B

SENSE WINDING

b B

Fig. 9-9. In the flux gate magnetometer principle, a magnetic field applied along the axis of a toroid includes a signal in the sense winding B-B when drive winding A-A is excited with an alternating current.

closed”. With an alternating current flowing through the drive winding, the earth’s field is successively attracted and not attracted, inducing a signal in the sensing coil as shown in Fig. 9-9. The signal is proportional to the component of the magnetic field normal to the toroid plan. Other techniques have been devised to achieve the same effect.

MEASUREMENT WHILE DRILLING

263

Magnetic orientation requires three magnetometers mounted in a manner similar to the accelerometers of Fig. 9-8. This gives the three components of the magnetic field in the frame of reference of the accelerometers. The MWD magnetometers are built to measure a maximum magnetic field of one gauss’ and can fit in a 3 cm-diameter cylinder. The typical values of the characteristics are: Measurement range Scale factor Resolution Accuracy Frequency response Service temperature

= -1 to +1 G = 5 VIG = 10-4 G

= lo-’ G = DC to 1 kHz (generally used with a l-Hz low-pass filter) = -55°C to 150°C

Non-magnetic drill collars are required when using magnetic sensors; however, their length is less critical than with the single-shot or multi-shot since the effect of the magnetic drill collars above and below can be corrected (Russell and Russell, 1979; Grinrod and Wolff, 1983). The correction principle rests on the possibility of measuring the magnetic vector module, which can be adjusted to the normal value by correcting the axial magnetic components. In mud motor drilling, the bottomhole assembly is essentially stationary and the orientation can be measured during drilling. In rotary drilling, until recently, the rotation had to be stopped long enough for the directional measurements to be made. The most accurate borehole surveying technique is performed with gyroscopic technology. The delicacy of mechanically gimballed gyros precludes their use under drilling conditions. However, a three-axis laser gyro can be used when the bottomhole assembly is perfectly stationary (Gibbons and Hense, 1987). Such a gyro system is a North seeker and determines the earth’s rotation vector, which can be used in lieu of the earth’s magnetic vector for azimuth calculations. In this case, expensive magnetic drill collars would no longer be required. The information needed for directional surveying is azimuth and inclination. Directional steering requires a third parameter known as toolface (mentioned earlier). Magnetometers and accelerometers are used to derive these parameters through calculations of magnetic vectors or acceleration components. Inclination can be calculated from eq. 9-1. The gravity toolface angle is the angle between the vertical plane passing through the drill collar axis and the plane containing the drill collar axis and the mud motor axis. The notion of toolface applies only to downhole motor drilling with a bent sub. It does not apply to rotary drilling. Figure 9-10 shows the toolface angle. This angle, TF, is calculated simply with the equation: TF = arctan (-G,,/Gx)

(9-2)

Gauss (G) is an electromagnetic unit of flux density defined as one line per square centimeter. The SI unit for magnetic flux density is the t a l a (T): 1 T = G.

264 VERTICAL PLANE PASSING THROUGH

R. DESBRANDES AND R. CLAYTON

P L A N E THROUGH COLLAR, BENT SUB AND MUD MOTOR

PLANE NORMAL

Fig. 9-10. Schematic of the planes defining toolface angle. The gravity toolface angle is shown as T F . In a nearly vertical hole, the magnetic toolface is the orientation of the bent sub with respect to magnetic north.

where G, = gravity acceleration component lined up with the motor or bit face in a plane normal to the borehole axis, G, = normal to G, in the same plane. If TF > 0, the bottomhole assembly (BHA) will direct the borehole to the right; if TF = 0, the borehole will go straight ahead and continue to build angle; if TF < 0, the borehole will turn left. The angle TF cannot be defined gravitationally if the inclination is zero. When a directional borehole section is initiated from a vertical (or zero inclination) wellbore, the magnetic toolface is used. It is the angle of the vertical plane containing the bent sub or bent housing with respect to the north. The magnetic toolface is used until sufficient build angle or inclination is reached, typically up to 5". The azimuth calculation for a directional borehole can be achieved throu&h vector analysis. In Fig. 9-11 the vecto! .? represents the borehole axis; vector H , the earth's magnetic field, and vector G, the vertical or gravity vector. The azimuth is the angle between the vertical planes V H and VZ measur_ed clo$wise starting at V H .This angle is the same as the angle between vectors A and B, respectively, perpendicular to VH and V Z .We know that the vector products are: (9-3) The components of B and G are measured in the referential of the MWD tool and 2 is (0, 0, 1) in the same referential; Now the azimuth of the borehole can be computed with the scalar product k x A; thus:

MEASUREMENT WHILE DRILLING

265

Fig. 9-11. Schematic of the planes defining the azimuth angle. Measurements are made in the tool referential. Digi_al ana9sis provides orientation angle 01 in real time as a function of the components of the vectors G , H , and 2.

(9-4)

Some precautions must be taken to assure that the correct angle is computed. The magnetic sensors must be located in a non-magnetic drill collar. The magnetic collars, while located several meters away, still have an effect by creating a perturbation in the direction of the borehole axis. This introduces an error, which is empjrically corrected with the single-shot instruments. Since the three components of H are measured, the magnitude of the error vector can be calculated if the module of the non-perturbed earth magnetic vector is known (Russell and Russell, 1979). The corrected dip angle vector can also be computed and compared to the non-perturbed dip angle. These two angles should match; if they do not, then an non-axial perturbation is present. This perturbation may be due to “hot spots”, points in the non-magnetic drill collar that have developed some magnetism, or due to external factors such as a cased well in the vicinity. Correction techniques have been introduced for the “hot spots’’ (van Dongen and Maeklaho, 1987). External magnetism due to casing or steel in the well vicinity is used in passive ranging tools for blowout well detection from a relief well (Morris et al., 1977). The accuracy of MWD directional measurements is generally superior to singleshot or multi-shot type measurements since the sensors are more advanced and the measurements more numerous. The azimuth measurement is made with the three components of the earth’s magnetic field vector, but only the horizontal

266

R. DESBRANDES AND R. CLAYTON

component is used in the case of the single-shot or multi-shot. The accelerometer measurements of the inclination are also more accurate regardless of the value of the inclination. The average error in the horizontal position varies from 2 m per 1000 m drilled at zero inclination to 8 m per 1000 m drilled at 55" of inclination (Knox and Milne, 1987; de Lange et al., 1988). The reference position is given by the inertial Ferranti platform FINDS (Morgan, 1979). A large error dispersion was noted on the 102 wells surveyed. 9.3.2. Gamma ray The first formation evaluation sensor to be offered with an MWD system was gamma-ray measurement. Because of the difference between wireline and MWD gamma-ray measurements, the measurement required proper definition and evaluation (Coope, 1983). MWD gamma-ray sensors are run inside a steel drill collar and move through the formation at significantly slower speeds than wireline gamma ray, i.e. 10-100 ft (3-30 m) per hour as compared to 1800 ft (550 m) per hour with wireline. These factors influence log accuracy, bed resolution, and log amplitude variation due to spectral biasing. A comparison of wireline and MWD gamma ray is shown in Fig. 9-12. Since the industry has begun to accept MWD gamma ray, studies have continued to be conducted to pursue calibration to API standards (Bryant and Gage, 1988) 9.3.3. Resistivity MWD formation resistivity technology has evolved in a manner similar to that of wireline techniques. The simplest measurement technique to implement is made with electrodes (Tanguy and Zoeller, 1981). More commonly known as a 16-inch short normal, this measurement is made by mounting electrically conducting bands on an insulated portion of the MWD drill collar for excitation and measurement. Resistivity is also measured around the drill collars with toroidal transmitter and receivers working at 1000 Hz (Gianzero et al., 1985, 1986). The drill collars and bit are used as electrodes. A well-focused lateral curve with an investigation similar to the medium induction and an axial measurement focused downward are recorded. Figure 9-13 shows the current pattern in an homogeneous formation. This tool only functions in water-base drilling muds; results in oil-base muds are being evaluated. For applications in oil-base drilling fluids, propagating electromagnetic wave measurements have been developed (Rodney et al., 1983). True formation resistivities can be read directly by using technologies adapted from wireline tools. Figure 9-14 shows the configuration of the tool adapted for MWD. The frequency used is 2 MHz in order to minimize the drill collar perturbation. The receiver antennae used for these measurements reduce the near zone influence, and their spacing gives excellent vertical resolution. Further advancing propagation electromagnetic wave technology, a dual induction technique has been developed (Clark et al., 1988). The phase shift and

267

Fig. 9-12. Comparison of a wireline and MWD gamma-ray recording. (Courtesy of SPWLA, 1988.)

attenuation of the electromagnetic signals indicate two apparent resistivities at two depths of investigation. Figure 9-15 shows how two transmitters can eliminate much of the error in rugose holes by averaging the signals transmitted upward and downward. A new tool with four sets of receivers can measure eight apparent resistivities at various depths of investigation (Bittar et al., 1991).

268

R. DESBRANDES AND R. CLAYTON

LATERAL CURRENT

BIT CURRENT

Fig. 9-13. Computed current pattern in a homogeneous formation for the MWD toroid sonde (after Gianzero et al., 1985, 1986). The drill collar acts as a series of electrodes in a way similar to the Laterolog 3 sonde. The lower guard electrode (the bit) is used to get a forward resistivity curve.

9.3.4. Neutron porosity

In addition to true resistivity, formation porosity must also be measured to calculate the amount of oil in place (Rao and Fontenot, 1988). This porosity measurement is accomplished with the MWD nuclear tools. A neutron porosity sensor has been developed which counts the flux of neutron capture gamma radiation. The formation is bombarded with fast neutrons that are slowed down, or “thermalized”, through collisions with hydrogen nuclei. The thermal neutrons are then absorbed by other atomic species to produce gamma radiation. The concentration of hydrogen nuclei is determined by the flux counts. The tool is designed to act as a thermal neutron detector, measuring the gamma rays that result from capture by the steel in the tool (Roesler et al., 1987). Improvement in neutron detection technology has facilitated this MWD measurement. One configuration permits retrieval of the nuclear source in the event that the drill pipe becomes stuck (Evans et al., 1988)

9.3.5. Density A formation density measurement complements the neutron porosity measurement, enabling more accurate porosity determination (especially in shaley and/or

MEASUREMENT WHILE DRILLlNG

269

STEEL COLLAR

TR

Fig. 9-14. Configuration of the MWD resistivity tool. Usually Z l = l m and Z z = 0.80 rn.

gas-bearing formations) and lithology determination via standard cross plot methods (Paske et al., 1987). Unlike the wireline tools, this gamma-gamma density measurement does not use pads in contact with the borehole wall. The formation is bombarded with gamma radiation, and the scattered radiation returning to the sensors is counted (Rao and Fontenot, 1988). The returning flux is inversely related to the bulk density of the formation. By assuming a formation matrix density and formation fluid density, porosity can be calculated. 9.3.6. Weight-on-bit,torque and bending moment

Weight-on-bit, torque, and bending moment are all measured in the same sub with strain gauges. The strain gauges are resistors with straight fine wires oriented in the direction of the strain to be measured (Holman, 1984) and are bonded to the metallic part of the sub under test with a special epoxy. Figure 9-16 shows a sketch of a strain gauge. The measured strain is related to the stress by Hook’s law. The stress can, in turn, be related to the weight-on-bit (axial load), torque, and bending moment. One disturbance that must be taken into account is the end effect, which is due to the differential pressure A P between the pressure inside the drill collar and the annulus pressure. The action of AP upon the mud motor and/or the drill bit introduces an axial load. With a typical A P of 70 bars (1000 psi) and a drill collar

270

R. DESBRANDES AND R. CLAYTON

ATU= Attenuation Up PSU= Phase Shift U p

ATU= Attenuation Dowr

PSU= Phase Shift Down

Fig. 9-15. A dual transmitter configuration of an electromagnetic wave resistivity tool illustrated with the receiver coils passing through a rugose section of the borehole (Clark et al., 1988). Averaging the PSU and PSD or ATU and ATD eliminates much of the error in such holes.

ID of 3.5 inches, the end effect may reach 4.5 tons (9000 lbs, 40 kN). The hydraulic lift must also be taken into account for both diamond and PDC bits (Winters and Warren, 1986). A zero-weight test should always be performed with full mud circulation and the bit just off bottom. The strain gauges are placed on a cylindrical sub as shown in Fig. 9-17. Two gauges on opposite sides of the sub can be used for the weight-on-bit measurement in the opposite legs of a wheatstone bridge; thus the bending moment effect will be compensated. Two other gauges, also on opposite legs of the sub but in adjacent legs of another bridge, record the bending moment as an alternating signal. Finally, two gauges placed at a 45" angle in adjacent legs of a bridge measure the torque. The resistance variation per gauge for the weight-on-bit is given by: AR

=

F x R x WOB E x A

(9-5)

where, in SI units: F = gauge factor; R = gauge resistance in ohms; WOB = weight-on-bit in newtons; E = Young modulus in newtons per square meter; A =

27 1

MEASUREMENT WHILE DRILLING FOIL GRID PATTERN TE

WIRE

-'

I

<

INSULATING LAYER AND BONDING CEMENT

<

NEUTRAL AXIS

STRUCTURE UNDER BENDING

Fig. 9-16. Bonded foil strain gauge transducer. The resistance of the gauge changes when a strain is applied along the OX-axis.

sub cross-section in square meters; or, in English units: F = gauge factor; R = gauge resistance in ohms; WOB = weight-on-bit in pounds; E = Young modulus in psi; A = sub cross-section in square inches. For the torque, the equation is: AR=

F x R x x T x R, n x G x (R: - R!)

(9-6a)

where in SI units: F = gauge factor; R = gauge resistance in ohms; T = torque in meter newtons; R, = sub outside radius in meters; Ri = sub inside diameter in meters; G = shear modulus in newtons per square meter; or: A R = 0.083

F x R x x T x R, R x G x (R: - R f )

(9-6b)

where in English units: F = gauge factor; R = gauge resistance in ohms; T = torque in foot pounds; R , = sub outside radius in inches; Ri = sub inside diameter in inches; G = shear modulus in psi.

272

R. DESBRANDES A N D R. CLAYTON

Fig. 9-17. Measurement principle for weight-on-bit, torque, and bending moment. WOB and bending moment gauges are laid with their sensitive axis parallel to the drill collar axis. Torque gauges are positioned at a 45" angle.

9.4. ABNORMAL PRESSURE DETECTION WITH MWD

The natural gamma-ray curve is part of the suite of standard MWD logs, as shown in Figs. 9-18, 9-19, and 9-20. According to Zoeller (1983), the gamma-ray counts in the shale sections are found to decrease in overpressured zones since the amount of shale per unit volume decreases. This phenomenon is shown in Fig. 9-21. MWD neutron and formation density measurements have been developed (Roesler et al., 1987; Paske et al., 1987), and these data can be interpreted in the same manner as the corresponding wireline measurements (Fertl, 1976). Quantitative computer-based pore pressure determination seems to be possible and to give good results (Hauck et al., 1986; Holbrook and Hauck, 1987). Furthermore, in porous intervals the presence of gas can be immediately detected with the density-neutron combination because of the shallow invasion of mud filtrate at the time of the measurement. Measurements in the annulus to detect fluid inflow, particularly gas, have also

273

MEASUREMENT WHILE DRILLING

AMRlfIf0 MYSllVlIV anno. n2tn ).

...

. .. . .....

SHORI NORMAL RfSlSllVllV OMYO. YXlY

OowWrmLf Wfl6111Ow BII

of .ou(DI . . . . . . . . .1(

TIOU.AW.

. . ..

SURFACt WflGHI OW 111

T I ( W # A y O l ff

POUND*

I

+++++++++4

1( 42.6 1 m.10 43.0 1 0440

43.1 1 a 4 7 3 43.3 2 .SO6 43.4 2 *a37 43..

8800

2

*no.

44.3 2 0.04 44.a a 0031

48.4 3 0 7 2 0

46.5 2 a T 6 0 40.2

8800

3 0T.T

4?.0 3 .#I?

7000

*-

4T.n 5 *a62 40.0 6 O O T O 40.4 4 0.01 40.5 4 0040

4a.T 0 0072

40.5 4

49.0 0 ?0.6

50.4

7200

TO34

40.0 6 TOO6

4

1121

50.6 6 1169 60.4 T I 1 0 0 51.2 4 I 1 0 0 61.1 5 T Z Z O 61.4 4 1 2 5 3 5t.O 0 T I 0 4 61.9

5

T3PO

7400

62.0 0 T 4 7 2

63.1 T 1603 6 x 6 T 7636

7800

63..

T T500

53..

7.01

64.1 I 7.21 64.4 m 7.6. 64.. 0 I*.*

s6.0

m

7800

65.. 66.m 66.m 66.0

7721

T762

SO..

S T7#J

.

7014

m

7.44

?#T6

Fig. 9-18. MWD log in a deviated borehole (after %guy and Zoeller, 1981). Gamma-ray and resistivity curves outline the sand-shale sequence. The saw-tooth pattern of the temperature curve is due to drilling interruptions for directional measurements. Low bottomhole weight-on-bit values occur mostly in sand zones.

274

R.DESBRANDES AND R.CLAYTON

,I

Fig. 9-19. MWD log showing weight-on-bit and torque recordings (after Tanguy and Zoeller, 1981). Sand and shale sequences are defined by gamma ray and resistivity. The correlation bottomhole torque and weight-on-bit is good. Weight transfer is poor only in the lower part of the section.

been suggested (Desbrandes and Bourgoyne, 1987). Sound velocity in a fluid is affected by entrained gas. Since the velocity is related to both the density and the compressibility of the fluid, a qualitative monitor could be devised. After reaching a predefined threshold, an influx alarm could be activated, even overriding other transmissions should an emergency situation occur.

275

MEASUREMENT WHILE DRILLING

Fig. 9-20. MWD mud motor drilling log shows the magnetic toolface up to 4" of deviation and the gravity toolface afterwards (Tanguy and Zoeller, 1981). Directional data are printed on the right.

GROUND LEVEL

GAMMA RAY, CPS 40 6080

RE 1.0

OVER

:

PRESSURE

J

k

a

g

5000

3

;6000 7000 8000

t

I

I I11111

I

Fig. 9-21. MWD gamma-ray shale profile in well located offshore in Texas. The observed gamma-ray curve is corrected for the mud density in the annulus. Both resistivity and corrected gamma-ray plots indicate a high pressure zone.

9.5. SERVICE COMPANY COMPARISON

Table 9-1 provides a reference source and comparison of several MWD systems (Anonymous, 1988). All specifications are supplied and approved by the appropriate vendors. Since MWD technology is advancing rapidly, these specifications may also

TABLE 9-1

h,

4 Q\

Service Company comparison (1990) Company

Tool O.D. (inch mm)

Tool length (ft m)

Bending inertia (inch4)

(cm4)

Baker Hughes

2 51

>25 >7.6

as NMDC

as NMDC

Eastman Christensen

6%-9Y2 171-241

18 5.5

87.4 to 386.8

Exlog

6%-9% 159-241

31% 9.6

Geodata (Halliburton)

3%-9% 83-241

Geodata (Halliburton)

Max. operat. temperature (“C

Power source

Time operating (hours)

Max. hydrostat. pressure (psi ma)

Mud flowrate (gal/min Ilmin)

Max mud viscosity (cP)

Lost circulation material

Mud screen

Pressure drop

125 257

battery

150

20,000 137.9

100-1000 378-3785

no limit

handle most

recommended

variable

3638to 16,100

125 257

battery

200

20,000 137.9

clear 2” ID

50 CP

no restriction

not required

32 psi @ 450 gpm

NA

NA

125 257

turbine

no limit

18,000 124.1

200-1750 757-6624

no limit

40 Ib/bl 1.12 W / m 3

recommended

70 psi @ 450 gpm

30 9.1

68.5 to 393.4

2851 to 16,375

150 302

battery

75-200

20,000 137.9

50-1500 189-5677

no limit

not recommended

recommended

equiv. 1000 ft 4Wdp

3%-9% 83-241

30 9.1

68.5 to 393.4

2851 to 16,375

175 347

turbine

no limit

20,000 137.9

250-1500 9465677

no limit

not recommended

recommended

equiv. 1000 ft 4%” dp

SperrySun MPT

6%-8 159-203

31 11.3

79.3 to 174

3301 to 7242

140 284

battery

250

15,000 103.4

750-1000 2839-3785

50 CP

40 Ib/bl 1.12 kN/m3

not required

80 psi @ 300 gpm

SperrySun RLL

6%-8 159-203

18

NA

NA

140 284

battery

400

15,000 103.4

1000 3785

no limit

no restriction

not required

1.9” thru b.

5.5

SperrySun Directional only Anadrill Schlumberger

6%-10 165-229

35 10.7

as NMDC

as NMDC

125 257

turbine

no limit

15,000 103.4

225-1200 852-4542

50 CP

20 lb/bl 560 N/m3

recommended

100 psi @ 410 gpm

6%-9 165-229

30-45 9.1-13.7

98.8to 395.8

4112to 16,474

150 302

turbine

no limit

20,000 137.9

210-1200 795-4542

no limit

medium nut max

recommended

150 psi @ 350 gpm

Smith Datadrill Sonat Teleco Geoservices Electromagnetic a

4%-9% 108-241

45 13.7

18to 318.1

749to 13,240

150 302

battery

250-600

20,000 137.9

350-1200 1325-4542

no limit

no restriction

recommended

125 psi @ 600gpm

4%-9% 108-241 4%-8 121-203

30-40 9.1-12.2 30-31 9.1-9.5

84.6to 355.4 19.5 to 176.6

3521to 14,793 812to 7351

125 257 125 257

turbine

no limit

20,000 137.9

250-1100 9464163

no limit

medium nut max

recommended

100 psi @ 450 gpm

E %U

battery

144-190

10,000 68.96

NA

no limit

no restriction

not required

NA

P

“F)

P er

rn

vl

1 psi = 6.894 kPa; 1gal = 3.785 liter. base mud, air, gas, mist, foam, aerated mud. All others in water/oil base mud only.

a Works in water/oil

vl

g

s

MEASUREMENT WHILE DRILLING

277

change rapidly. In fact, in these days of oil field acquisitions and competitive repositioning, company and product names are also subject to change. Despite the evolution of electronics technology, the development of numerical methods, and the advent of high-speed computers, many companies have come and gone in the pursuit of final solutions to MWD problems. The benefits of simplified downhole hardware and increased data rates continue to entice further development for the oilfield.

REFERENCES Aker, J.R., Cullen, R.H. and Elliott, C.H., 1966. Methods and Appurutusfor Mounting Electrical Cable in Flexible Drilling Hose. US.Patent No. 3,285,629, November 15. Anonymous, 1978. Gearhart-owen uses negative pulse telemetry. Oil Gas J., 76 (24): 70-72. Anonymous, 1988. Vendors provide wide array of MWD tools. Pet. Eng. Int., 5 (60): 57-61. Applied Research Associates, 1959. A Data Transmission System Using a Single Uninsuluted Conductor. An internal report submitted to Lane Wells Co.,April 1. Arps, J.J., 1963. Continuous logging while drilling: a practical reality. SPE 710, SPE Annu. Full Meeting, New Orleans, La., October 6-9. Arps, J.J. and Arps, J.L., 1964. The subsurface telemetry problem: a practical solution. J. Pet. Technol., 16(5), pp. 487-493. Besaisow, A.A. and Payne, M.L., 1988. A study of excitation mechanisms and resonances inducing bottomhole assembly vibrations. SPE Drill. Eng., 3 (1): 93-101. Bittar, M.S., Rodney, P.F., Mack, S.G. and Bartel, R.P., 1991. A true multiple depth of investigation electromagnetic wave resistivity sensor: theory, experiment, and prototype field test results. SPE 22705, SOC.Pet. Eng. 66th Annu. Tech. Conf, Dallas, Texas, October 6-9. Bryant, TM. and Gage, TD., 1988. API pit calibration of MWD gamma ray tools. SOC.Prof Well Log Analysts 29th Annu. Log. Symp., San Antonio, Texas, June 5-8. Clark, B., Luling, M.G., Jundt, J., Ros, M. and Best, D., 1988. A dual depth resistivity measurement of FEWD. Soc. Prof Well Log Analysts 29th Annu. Log. Symp., San Antonio, Texas, June 5-8. Coope, D.F., 1983. Gamma ray measurement-while-drilling. Log Analyst, 24 (1): 3-9. Coope, D.F. and Hendricks, W.E., 1984. Formation evaluation using measurements recorded while drilling. SOC.Prof Well LogAnalysts 25th Annu. Log. Symp., New Orleans, La., June 10-13. DeGauque, P. and Grudzinski, R., 1987. Propagation of electromagnetic waves along a drillstring of finite length. SPE Drill. Eng., 2(2): 127-134. de Lange, J.I., Tbilhaar, G.D.N. and Pelgrom, J.J. 1988. Accurate surveying: an operator point of view. IADCISPE 17214, UDCISPE Drill. Conf, Dallas, Texas, February 28-March 2. Dennison, E.B., 1976. Making downhole measurements through modified drill pipe. World Oil, 183 (5): 86-94. Desbrandes, R., 1982. llajectometrie inertielle dans les forages. Forages, Bull. AEMS-IFP, 96: 51-76; 97: 73-100. Desbrandes, R., 1985, 1989. Encyclopedia of Well Logging. Gulf Publishing, Houston, Texas, 502 pp. . Desbrandes, R., 1988a. Status report: MWD technology, Part 1. Data acquisition and downhole recording processing. Pet. Eng. lnt., 60 (9): 27,30-33. Desbrandes, R., 1988b. Status report: MWD technology, Part 2. Data transmission. Pet. Eng. Int., 60(10): 48,51-54. Desbrandes, R., 1988c. Status report: MWD technology, Part 3. Processing, display, and applications. Pet. Eng. Int., 60(11): 42-44, 46, 48, 51. Desbrandes, R., 1990. An overview of measurement while drilling/logging while drilling technology. MWD Symposium, Louisiana State University, Baton Rouge, La., February 26-27. Desbrandes, R. and Bourgoyne, A.T., Jr., 1987. MWD monitoring of gas kicks ensures safer drilling. Pet. Eng. Int., 59 (7): 46-52.

278

R. DESBRANDES AND R. CLAYTON

Evans, M., Wraight, P., Marienbach, E., Rhein-Knudsen, E. and Best, D., 1988. Formation porosity measurement while drilling. SOC.Prof: Well Log Anubsts 29th Annu. Log. Symp., San Antonio, Texas, June 5-8. Fertl, W.H., 1976.Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Gianzero, S., Chemali, R., Lin, Y., Su, S. and Foster, M., 1985. A new resistivity tool for measurementwhile-drilling. Paper A, SOC. Prof Well Log Analysts 26th Annu. Log. Symp., Dallas, Texas, June 17-20. Gianzero, S., Chemali, R. and Su, S.M., 1986. Determining the invasion near the bit with the MWD toroid sonde. Paper SOC. Prof Well Log Analysts 27th Annu. Log. Symp., Houston, Texas, June 9-13. Gibbons, EL. and Hense, U., 1987. A three-axis laser gyro system for borehole wireline surveying. SPE 16679, SOC.Pet Eng. Annu. Fall Meet., Dallas, Texas, September 27-30. Grinrod, S.J. and Wolff, J.M., 1983. Calculation of NMDC length required for various latitudes, developed from field measurements of drill string magnetization. IALKISPE 11382, IADCISPE 1983 Drill. Conf, New Orleans, La., February 20. Grudzinski, R. and Issenman, O., 1990. Telemetry using the propagation of an electromagnetic wave along a drill pipe string. M W D Symp., Louisiana State University, Baton Rouge, La., February 26-27. Hauck, M.L., Holbrook, P. and Robertson, H., 1986. Quantitative computer-based pore pressure determination from MWD data. Proc., Am. Assoc. Pet. Geol., Geotech Conf:, Houston, Sepember 21-23, pp. 8 4 9 1 . Heilhecker, J.K. 1975. Method for Mounting An Electrical Conductor in a Drill String. US. Patent 3,825,079 (November 11). Holbrook, P., 1985. The effect of mud filtrate invasion on the EWR log: a case history. Paper NNN, SOC. Prof: Well Log Analysts 26th Annu. Log. Symp., June 17-20. Holbrook, P. and Hauck, M.L., 1987. A petrophysical-mechanical math model for real time well-site pore pressure/fracture gradient prediction. SPE 16666, SOC.Pet. Eng. Annu. Fall Meet., Dallas, Texas, September 27-30. Holman, J.P., 1984. Experimental Methodr for Engineers. McGraw-Hill, New York, N.Y., 514 pp. Honeybourne, W., 1985. Formation MWD benefits evaluation and efficiency. Oil Gas I . , 83 (8): 83-90. Knox, D.W.J. and Milne, J.M., 1987. Measurement-while-drilling tool performance. SPE 16523, SOC. Pet. Eng. Offshore European Conf:, Aberdeen, September 3-7. McDonald, W.J., 1978. Four different systems used for MWD. Oil GasI., 76(14): 115-124. Mills, B., 1940. Simultaneous and continuous electrical logging and drilling achieved. Oil Weekly (Jan. l), pp. 16-20. Morgan, D.G., 1979. High accuracy directional surveying of wells employing inertial techniques. SPE 8156, SOC.Pet. Eng. Offshore European Conf., Aberdeen, September 3-7. Morris, F.J., Waters, R.L., Roberts, G.F. and Costa, J.F., 1977. A new method of determining range and direction from a relief well to a blowout well. SPE 6781, SOC. Pet. Eng. Annu. Fall Meet., Denver, Colo., October 9-12. Oil and Gas Journal, 1978. MWD: State of the Art. 10 articles: 76(13): 141-147; 76(14): 114-124; 76(16): 108-124; 76(18): 59-66; 76(20): 68-71; 76(22): 68-76; 76(24): 70-72; 76(27): 72-76; 76(29): 63-64; 76(31): 153-162. Paske, W.C., Roesler, R.F., Barnett, W.C. and Rodney, P.F., 1987. Formation density logging while drilling. SPE 16756, SOC. Pet. Eng. 62nd Annu. Tech. Conf: and Exhibition, Dallas, Texas, September 27-30. Patton, B.J., Gravely, W., Godbey, J.K., Sexton, J.H., Hawk, D.E., Slover, V.R. and Harrell, J.W., 1976. Development and successful testing of a continuous wave logging-while-drilling telemetry system. SPE 6157, SOC. Pet. Eng. Annu. Meet., New Orleans, La., October 3-6. Rao, M.V. and Fontenot, J.E., 1988. MWD gains as formation-evaluation tool. Oil Gas J., 86(6): 4448. Raynal, J., Gstalder, S., Quichand, C. and Raynand, M., 1970. Method and Apparatus for Measuring Mechanical Charactetistics of Rocks While They Are Being Drilled. U S . Patent, 3,520,375. Rector 111, J.W. and Marion, B.P., 1989. Real time inverse VSP using drill bit as a downhole seismic

MEASUREMENT WHILE DRILLING

279

source. SAID (Sociew of Professional Well Log Analysts Paris Chapter),12rh Int. Loggkg Symp., Paris, October 24-27. Reed, P., 1939. Amerada develops special rotary drill stem for simultaneous electrical logging and drilling. Oil Gas J. (Nov. 17), pp. 68-76. Roberts, W.E and Johnson, H.A., 1978. Systems available for measuring hole direction. Oil Gus J., 76 (22): 68-70. Rodney, P.F., Wider, M.M., Thompson, L.W. and Meador, R.A., 1983. The electromagnetic wave resistivity MWD tool. SPE 12167, SOC. Pet. Eng. 58th Annu. Tech. Conf and Exhibition, San Francisco, Calif., October 5-8. Roesler, R.F., Paske, W.D. and Barnett, W.C., 1987. Theory and application of a measurement-whiledrilling neutron porosity sensor. SPEIIADC 16056, SPEIIADC Drill. Conf, New Orleans, La., March 15-18. Rubin, L.A. and Harrison, W.H., 1987. Downhole Telemetry Apparatus and Method. U.S.Patent 4,691,203 (September 1). Russell, M.K., 1970. The design and development of a surface reading survey. Paper 801-46R,API Prod. Div. Pacific Coast District Meet., Los Angeles, Calif., May 12-14. Russell, M.K. and Russell, A.W., 1979. Surveying of Boreholes. U.S. Patent 1,163,324 (August). Smith, H.C., 1983. Toroidal coupled measurements while drilling. IADCISPE 11361, IADCISPE Drill. Conf, New Orleans, La., February 20-23. Spinnler, R.F. and Stone, EA., 1978. MWD program nearing commerciality. Oil GasJ., 76(18): 59-66. lhnguy, D.R. and Zoeller, W.A., 1981. Applications of measurements while drilling. SPE 10324, SPEI AIME 56th Annu. Fall Tech. Conf, San Antonio, Texas, October 5-7. Thiery, J.R., 1978. Flexodrill monitors borehole continuously. Oil Gas J., 76 (16): 108-129. 'Raynor, Jr., B.W., 1978. Electrodrill demonstration program shows promise, Oil Gas J. 76 (16): 99-129. van Dongen, C.M. and Maeklaho, L.B., 1987. Method for Determining the Azimuth of a Borehole. US. Patent 4,682,421 (July 28). Winters, W.J. and Warren, TM., 1986. Field application of diamond bit hydraulic-lift principles. SPE DrilL Eng., l(3): 277-287. Zoeller, W.A., 1983. Pore pressure detection from MWD gamma ray. SPE 12166, SOC. Pet. Eng. 58th Annu. Fall Meet., San Francisco, Calif., October 5-8.

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Studies in Abnormal Pressurn. Developments in Petroleum Science, 38

edited by W.H. F e d , R.E. Chapman and R.E Hotz 0 1994 Elsevier Science B.V. All rights reserved

28 1

Chapter 10

SHALLOW ABNORMAL PRESSURE HAZARDS ADAM T BOURGOYNE,Jr.

10.1. INTRODUCTION

In some marine environments where abnormal formation pressures may be encountered at very shallow depths, conventional blowout prevention equipment and procedures are likely to be of no benefit. This situation can lead to very severe well control problems when permeable, gas-bearing formations are drilled. There have been numerous disastrous blowouts resulting from loss of well control after drilling into shallow, abnormally pressured gas formations. In this chapter, concepts used to minimize shallow gas hazards will be presented. Shallow gas accumulations are always at least slightly over-pressured in the upper portion of the reservoir due to the density difference between the gas and the surrounding water. Abnormal formation pore pressures that are approaching the formation fracture pressure are thought to be possible in sand lenses due to gas migration along fault planes from below. Shown in Fig. 10-1, there is a recently discovered crater (Prior et al., 1989) in the floor of the Gulf of Mexico that is thought to be the result of a naturally occurring shallow gas blowout. It was discovered by a Shell Oil Company survey team in 2176 m (7139 ft) of water, about

Fig. 10-1. Side view of a crater on the sea floor thought to be due to a naturally occurring shallow gas blowout. (After Prior et al., 1989.) (Courtesy of Science Magazine.)

282

A.T BOURGOYNE

Fig. 10-2. Example blowout illustrating the need for a diverter system. (After Bourgoyne, 1989.) (Courtesy of SPE.)

115 km (71 miles) southeast of the Mississippi River delta. The crater was elliptical in shape, 58 m (190 ft) deep, 280 m (920 ft) across, and about 400 m (1300 ft) long. Slow seepage of the abnormally pressured gas was thought to be blocked by the formation of gas hydrates in the near surface sediments. Even when the formation pore pressure is nearly normal, it is generally not feasible to shut-in a shallow gas flow when drilling from a bottom-supported vessel. By the time the rig crew can recognize that the well has started to flow, the gas has already traveled a considerable distance up the open borehole. If the blowout preventers are closed, the pressure at the casing seat will generally build to a value exceeding the formation fracture pressure. If one or more fractures reach the surface, the resulting flow can destroy the foundations of a bottom-supported structure and ultimately lead to the formation of a crater. The rig shown in Fig. 10-2 eventually collapsed into a large crater in the sea floor.

10.2. PREVENTION OF SHALLOW GAS FLOWS

Considerable attention should be given to preventing a shallow gas flow when planning the well. Seismic surveys can sometimes be used to identify potential shallow gas zones prior to drilling (Fig. 10-3). If localized gas concentrations are detected by seismic analysis, hazards can be reduced when selecting the surface well location. When possible, an empirical correlation should be applied to the seismic data to estimate formation pore pressures (Bourgoyne et al., 1986). This will sometimes

SHALLOW ABNORMAL PRESSURE HAZARDS

283

Fig. 10-3. Example seismic profile showing possible shallow gas accumulation as darker reflection or “bright spot”. (Courtesy of ARC0 Oil and Gas.)

permit the detection of shallow, abnormal pressure in the marine sediments. When formation pore pressures can be accurately estimated, an appropriate mud density program can be followed to prevent gas from entering the borehole. Drilling practices followed when drilling the shallow portion of the well can also affect the blowout risk. Operations that can reduce downhole pressures, such as pulling the drill string from the well, should be carefully controlled to ensure that a pressure overbalance is always maintained in the open borehole. Pressure changes due to pipe movement tend to increase with decreasing hole size and thus would be more of a problem when drilling small-diameter pilot holes. At shallow depths, a small loss in borehole pressure can result in a significant loss in equivalent mud density. For example, a pressure loss of 400 kPa (58 psi) when pulling pipe from a depth of 4000 m (13,123 ft) is equivalent to a loss in drilling fluid density of only 98 N/m3 (0.08 lb/gal), which can be neglected. However, the same pressure loss of 400 kPa at only 400 m (1312 ft) is equivalent to a loss in drilling fluid density of 1000 kg/m3 (0.85 lb/gal), which could be very dangerous. Trip-tank arrangements that keep the well completely full of drilling fluid at all times are better than those that require periodic refilling of the well. Modern top-drive rotary systems permit pumping down the drill-string while pulling pipe and can be used when necessary to eliminate the swabbing effect caused by pipe movement. Gas-cut drilling fluid can also cause a loss in borehole pressure that can result in a significant reduction in equivalent mud density at shallow depths. For example, severe gas-cut mud observed at the surface can cause a 600 kPa (87 psi) reduction in bottom-hole pressure. This pressure loss is equivalent to a loss of only 147 N/m3 (0.13 lb/gal) at a depth of 4000 m (13,123 ft), which is usually within a normal safety margin of 0.3 to 0.5 lb/gal. However, this same pressure loss at a depth of 400 m

284

A.T BOURGOYNE

- 1000 -2500

-3000 0.4445-10 blt (175.41~)

0

10 '20 30 40 Maximum Safe Dnlhng Rate

50

mm/S

Fig. 10-4. Example calculation of maximum safe drilling rates when drilling multiple gas sands at shallow depths.

(1312 ft) would cause a loss in equivalent mud density of 1500 N/m3 (1.28 lb/gal), which could be very dangerous. Thus, when drilling at very shallow depths, even the small pressure loss due to gas-cut mud can be significant. If gas-cut mud appears prior to setting surface casing, it is advisable to periodically check for flow and to clean the well by circulating. Conditions favoring a shallow gas flow due to gas-cut mud become more severe with increasing hole size, increasing drilling rate, and increasing length of uncased borehole. Entrained gas entering the drilling fluid from the sediments removed by the bit at the hole bottom may reduce the hydrostatic pressure below the allowable safety margin opposite a shallower sand. This potential problem can be controlled by limiting the penetration rate of the bit. An approximate relationship between penetration rate and loss of borehole pressure was previously presented by Bourgoyne et al. (1978). This relationship permits the development of guidelines for an estimated maximum safe drilling rate in the shallow portion of the borehole. Shown in Fig. 10-4 are computed maximum safe drilling rates for a bit having a diameter of 0.4445 m (17.5 in.) that is cutting rock having a porosity of 28% and a gas saturation of 85%. The calculations assume a drilling fluid having a density of 10.9 kN/m3 (9.3 Ib/gal) that is being circulated at a rate of 53 x lop3 m3/s (840 gal/min). The depth, D1, of the shallowest exposed gas sand that could flow is 300 m (984 ft), and the pore pressure gradient was 10.5 Wa/m (0.465 psi/ft). Note that as the depth, D2, of the bit increases, the maximum safe penetration rate decreases. A BASIC program that can be used to estimate the maximum safe drilling rate for other well conditions is shown in Fig. 10-5.

285

SHALLOW ABNORMAL PRESSURE HAZARDS 1OLNPUT"Bntcrthepumpratcmcubicm~-

",QM

2OINPUT"bratbemuddearityin)rJcllbicmam-

"pH0

"D 40LNPUT"BntartbedqnhDldtheBdbrrmgrrrmdkm- ",Dl 30iNPIJT~tbebit~iam

SOJ"~"8ntsr~pac~~uDlhPA/ m ",GPl 60INPLW"BnrcrthedephdtbebitMmm"pz 7 0 I N P U T " b r a t b e p a e ~ g r d L n t . t M h h h",m 80INPUT-E3lK%tbepUD2~f?MZiOO85~"Bnrcrrbeg~C.arhrt~UfnCth.l-

"POR

"SG 9OP1 tGP1 D1+ 101300 lOOA = 1 - 1 3 W PI 11oQ6= 0 120PZ=m*m+ 101300 l W P = 1 138-011*P2 140x1 o9.807*RHO*D1 +lOlMO-Pl lK)XDHN=8314*311*Z1 IDG(Pl/ 10130)- 1569 D1 16oxNv=X1/XDBN 17ORP m4/3.141b* 8314* 311 XNV T2 (QM+ QS)/ (DA2 * POR SG P2) l80QS =3.141b/4 M RP ( 1 -wR) 190RHOA = (QS 26 lo00 + QM RHO ) I ( QS + QM ) a x ? = 9.807 RHOA D1+ 10130O-Pl 210IFABs(x2-x1)<1THENGoTo 240 ELSB m?2n 220x1 =x2 U o m 150

-

~ P R D l T " D m s i t y d ~ a p i n Q m i s ~ ~ ~ ~ m k g . & m=c",RHOA ta

".

2SOPRINT"Muhnmns8fe~R.emmh= =END Fig. 10-5. Algorithm (BASIC programming language) for calculating maximum safe drilling rate at shallow depths in presence of drilled gas. 10.3. DEVELOPING CONTINGENCY PLANS

Unfortunately, industry is not always successful in preventing the occurrence of shallow gas flows. Drilling records for the Outer Continental Shelf of the Gulf of Mexico indicate that shallow gas flows have been encountered approximately on 1 well out of every 900 drilled since 1965. Shallow gas blowouts have accounted for 25% of all blowouts experienced in this area. In some other offshore development areas of the world, this percentage has been much higher. Thus, contingency plans must be developed to address this possibility. Since 1975, a diverter system has been required for rigs drilling on the Outer Continental Shelf of the Gulf of Mexico. The function of the diverter system is to divert flow from the well overboard, away from the drilling personnel and rig structure. The essential elements of a diverter system include: (1) a vent line for conducting the flow away from the structure that is large enough to prevent a pressure build-up in the well to values above the fracture pressure; (2) a means for closing the well annulus above the vent line during diverter system operations; and (3) a means for closing the vent line during normal drilling operations. The sequence of events occurring when a shallow gas flow is encountered is illustrated in Fig. 10-6. When the driller recognizes that the well has begun to flow, the diverter system is actuated (Fig. 10-6b). This action simultaneously causes the vent line to open and the annular diverter head to close. If a proper assessment of the application of a dynamic kill has been made and if the well plan calls for a

286

A.T. BOURGOYNE

(b) hverter Act~vated

(a) Shallow Gas Flow Encountered

(d) Pseudo-Steady State Flow

(c) Well IS Unloaded

Fig. 10-6 Sequence of events modeled

in

experimental study of diverter operations

dynamic well control method to be attempted with the rig pumps, the driller may continue to pump drilling fluid at the maximum possible rate as an attempt to regain control. As drilling fluid is displaced from the well, the rate of flow of gas into the well increases due to the loss in bottom-hole pressure (Fig. 10-6c). After the well is unloaded of drilling fluid, a semi-steady state is reached (Fig. 10-6d) in which formation gas, water, and sand are flowing through the vent line. The loss of drilling fluid from the wellbore and the resulting decrease in pressure will usually result in an unstable borehole wall that will eventually cave-in and form a plug that stops the flow. For many rigs, diverter systems have been added after rig construction, which have complicated the placement of vent lines. Also, since diverter systems are not routinely used, special testing and training are needed to ensure maintenance of the diverter components and readiness of the rig crew to handle a shallow gas flow. Records available in the Events File of the Minerals Management Service indicate a diverter failure rate of approximately 50% during shallow gas flows. The three most common modes of diverter failure have been: (1) a failure of the vent line valve to open; (2) formation fracture due to insufficient vent line size; and (3) erosion. Diverter design criteria have been developed that are directed at overcoming these common modes of diverter failure.

SHALLOW ABNORMAL PRESSURE HAZARDS

287

10.4. DIVERTER DESIGN

In the past, diverter systems have been designed primarily based on surface pressure considerations. Equations for single phase flow of gas were used to select a vent line size that would result in a maximum acceptable wellhead pressure for a maximum anticipated gas flow rate. It was generally assumed in these calculations that the exit pressure of the vent line was atmospheric pressure. Many offshore rigs were equipped with 15.2-cm (6-in.) diverter lines, and until recently, this design was considered acceptable practice by many offshore operators and by regulatory agencies. Experience with these systems in the Gulf of Mexico later provided evidence that larger diverter vent lines were sometimes needed. An example incident that occurred on a jack-up type rig in the Gulf of Mexico (offshore Texas) in 1975 illustrates the need for a more complete analysis of diverter system operating conditions. Two 0.152-m (6411.) diverter vent lines were attached to 0.762-m (30-in.) casing, which was set at 149 m (490 ft), and penetrated 58 m (190 ft) of sediments. A 0.251-m (9.875411.) pilot hole was drilled to 351 m (1150 ft). The well plan called for enlargement of the hole to 0.508 m (20 in.) prior to setting conductor casing. However, a gas flow was encountered after pulling two stands of the drill-string out of the hole. The diverter system was actuated and both diverter vent lines were opened. Both mud pumps were used to circulate fluid into the well as fast as possible in an attempt to regain control. The rig began to list slightly and was evacuated. Within the next 12 hr, the rig turned over and sank into a subsea crater. The well stopped flowing after six days, and was thought to have bridged. Beck et al. (1987) have suggested an improved diverter system design procedure. They recommend that the final well design should consider the gas reservoir, borehole, casing, and diverter linked together as a single hydraulic system. A systems analysis approach (Clark and Perkins, 1980; Crouch and Pack, 1980; Brown, 1984) permits the simultaneous calculation of pressures throughout the wellbore and diverter system. Through this type of analysis, it can be determined if a successful diverter system operation can be maintained using the design under consideration. The predicted operating pressures can be used to evaluate the working pressure of diverter system components and the tendency for formation fracture at the casing seat. This approach can be used to determine the minimum safe conductor setting depth for expected well conditions and for the available vent line size. If a practical casing program cannot be achieved with the diverter system available on the rig, then the benefits achieved by increasing the vent line size can be evaluated. In performing the systems analysis, Beck et al. (1986) have shown that the flow at the vent line exit is usually sonic, and the assumption of atmospheric pressure at the diverter exit can lead to large errors. They also showed that near the exit, a significant pressure gradient resulted from fluid acceleration, which could also cause significant errors if ignored. Experimental data (Bourgoyne, 1992) was obtained in a model diverter system to permit evaluation of various methods for calculating flowing pressures for single and multiphase flow at near sonic conditions.

288

A.T BOURGOYNE

The systems analysis is accomplished by defining the pressure change occurring in each system component as a function of flow rate. The calculation is most easily accomplished by starting at the vent line exit, and proceeding stepwise through each component of the flow path to obtain the bottom-hole pressure and temperature. The calculation is repeated for several assumed exit pressures or flow rates to define a flow-string resistance curve. An inflow performance equation is used to model the flowing reservoir pressure at the borehole wall as a function of flow rate. The pseudo-steady-state flow rate that will be observed during the diverter system operations is determined from the intersection of the flow-string resistance curve and the formation-inflow performance curve.

10.5. EXIT VELOCITY CALCULATION

The limiting (sonic) velocity at the vent line exit, u,, can be computed for any fluid using: Ve

(10-1)

=

where p is the density of the fluid, and c is the compressibility of the fluid. For liquids, the density p and compressibility c can be assumed constant and are easily defined. For gases, the density can be determined from the real-gas equation, and is given by: (10-2)

for any given pressure p , gas molecular weight M , gas deviation factor z, and temperature T at the diverter exit. The coefficient R is the universal gas constant for the system of units being used. For most accurate results, the gas compressibility at the exit should be computed assuming a polytropic process. This assumption gives: cg = l / n p

(10-3)

where n is the polytropic expansion coefficient for the process. For an adiabatic expansion of an ideal gas, n becomes equal to the ratio, k , of specific heat at constant pressure, C,, to specific heat at constant volume, C,. For sonic flow through a restriction, k is often used as an approximate value for n. When the fluid being produced from the well is a multiphase mixture, eq. 10-1 can still be applied through use of appropriate values for effective density and effective compressibility. It is recommended that the effective multiphase density, p,, is calculated using: Pe = PgHg

+ PIHI+ PSHS

(10-4)

where H denotes the volume fraction (hold-up), and subscripts g, 1, and s denote the gas, liquid, and solid phases present. For sonic flow, the slip velocity between the phases can be neglected when calculating the volume fractions. The effective compressibility,c,, can be obtained in a similar manner using:

289

SHALLOW ABNORMAL PRESSURE HAZARDS 2.0

1.6 1.2

0.8

0.4 n 0.2

0.1

0.3

0.4

0.5

1.0

Gas Quality (Weight Fraction)

Fig. 10-7. Values of polytropic expansion coefficient, n, measured during experimental study of diverter operations.

C,

+

= cgHg ciHi

+ cSHs

(10-5)

Ross (1960) had previously used this approach, but for simplicity, considered the second and third terms of this equation to be negligible. Beck et al. (1987) performed experiments in model diverter systems to measure sonic exit velocities for a natural gas having a specific gravity of 0.64. Data were presented for single and multiphase flow for diverter vent line diameters of 2.33 cm (0.918 in.), 4.92 cm (1.937 in.), and 12.44 cm (4.897 in.). More recently, Bourgoyne (1992) presented experimental data obtained with air-water mixtures in 20.27 cm (7.891 in.) and 25.45 cm (10.02 in.) vent lines. These data were used to determine experimental values for the polytropic expansion coefficient, n. The experimentally determined n values are shown in Fig. 10-7. Note that the measured value of n varied with gas weight percentage (quality), xg.For the range of conditions studied, n could be approximately defined by: n = k - 2log,o(xg)

(10-6)

The value of n departs significantly from k for increasing values of gas quality (weight percentage). The use of eqs. 10-1 to 10-6 for calculating the relationship between flow rate and diverter vent line exit pressure is illustrated in Table 10-1 for a natural gas having a specific gravity of 0.64. The calculation was done for a 15.2-cm (6-in.) vent line diameter that was previously the minimum size approved by the U.S. Minerals Management Service and for a 25.4-cm (10-in.) diverter diameter that is now required by that agency. The results given in Table 10-1 show that a 25.4-cm (10-in.) diverter vent line diameter will handle approximately three times the flow rate of a 15.2-cm (6-in.) vent line for a given exit pressure. For the smaller line, note that approximately 10 atmospheres of backpressure would result at the diverter exit for a design gas-flow rate at standard conditions of 75.6 m3/s (230.5 MMScf/D).

TABLE 10-1

N \o 0

Example calculation of pressure-flow rate relationship at diverter vent line exit ~~

Conditions of calculation: Base pressure Base temperature Temperature

101.3 kPa 15°C -5°C

14.6923 psi 59°F 23°F

Liquid content Density liquids Liquid compressibility

0.1 wt fraction 1060 kg/m3 4.74 x 1 0 - ~ Wa-'

15 Bbl/MMscf 8.85 Ib/gal 3.27 x psi-'

Solid content Density of solids Solid compressibility

0.02 wt fraction 2630 kg/m3 4.00 x lo-' Wa-'

1112 Ib/MMscf 21.95 lb/gal 2.76 x psi-'

Pressure P a ) ~

z

(Psi)

Gas density n Cg eq. 10-2 (kg/m3) eq. 10-6 eq. 10-3 (kPa-')

~~

Gas specific gravity Heat capacity ratio, k Gas quality Universal gas constant, R Gas constant (mass basis), R'

Gas volume fraction

0.64 1.31 0.88 wt fraction 8.31 kJ h o l e - ' K-' 0.448 kJ kg-' K-I

Mixture density Mixture compression eq. 10-4 (kg/m3) eq. 10-5 (Pa-')

~

0.64 1.31 0.88 wt fraction 1.99 btu mole-' R-' 10.73 psi ft3 R-I mole-'

Exit velocity

Gas flow rate at S.C.

eq. lo-' (m's)

(m3/s) (MMscf/D)

~~

Diameter: 0.1524 m (6.000 in.) 101.3 14.7 0.997 0.85 200 29.0 0.993 1.67 58.0 0.987 3.37 400 87.0 0.980 5.09 600 1000 145.0 0.966 8.61 362.6 0.915 22.73 2500

1.42 1.42 1.42 1.42 1.42 1.42

6.95 x W3 3.52 x 1.76 x 1.17 x 7.04 x 2.81 x W 4

0.9999 0.9998 0.9996 0.9994 0.9990 0.9974

0.96 1.90 3.83 5.78 9.77 25.76

Diameter: 0.254 m (lO.OO0 in.) 101.3 14.7 0.997 0.85 200 29.0 0.993 1.67 300 43.5 0.990 2.52 400 58.0 0.987 3.37 500 72.5 0.983 4.23 1000 145.0 0.966 8.61

1.42 1.42 1.42 1.42 1.42 1.42

6.95 x 3.52 x 2.35 x lop3 1.76 x 1.41 x 7.04 x

0.9999 0.9998 0.9997 0.9996 0.9995 0.9990

0.96 1.90 2.86 3.83 4.80 9.77

6.95 x 3.52 1.76 1.17 7.03 2.81 x

10-3

10-3 10-3 10-3 10-4 10-~

387 387 385 384 382 372

7.6 15.1 30.2 45.5 76.3 196.1

23.2 45.9 92.2 138.8 232.9 598.5

6.95 3.52 2.35 1.76 1.41 7.03

10-3 10-3 10-3 10-3 10-3 10-4

387 387 386 385 385 382

21.1 41.8 62.8 83.9 105.1 212.0

64.5 127.6 191.8 256.1 320.7 646.9

*

A W

0 C 73

0

2z m

SHALLOW ABNORMAL PRESSURE HAZARDS

29 1

10.6. FLOWING PRESSURE GRADIENT CALCULATION

Upstream of the vent line exit, the pressure gradient, dp/dL, is given by the expression: d P- - pgCos(e) dL

f p F 2 pAF2 ++2d 2AL

(10-7)

where the first term accounts for hydrostatic pressure changes, the second term accounts for frictional pressure losses, and the third term accounts for pressure changes caused by fluid acceleration. In the first term, g represents the acceleration of gravity, and 0 represents the vertical deviation angle of the flow section under consideration. The Moody (1944) friction factor, f , in the second term is given by: (10-8) where e is the absolute roughness and d is the pipe diameter. A value of 16.5 mm (0.00065 in.) for roughness was found to yield good agreement with experimental data obtained in pipe having a diameter of 0.1244 m (4.9 in.). The Reynolds number, N R e , is defined by:

where iT is the average fluid velocity and p is the fluid viscosity. At a sudden decrease in the area of the flow path, such as at the vent line entrance, the pressure drop due to fluid acceleration, Apa, can be estimated using: AS2 APa=P--

2

(10-10)

However, the downstream velocity cannot exceed the sonic velocity predicted by eq. 10-1. When sonic velocity occurs, the downstream pressure will be governed by eq. 10-1. At a sudden increase in the area of the flow path, such as at the casing seat and at the top of the drill collars, the increase in pressure due to fluid deceleration is generally small and can be neglected. Since there is no diffuser present that can provide a smooth transition to the larger flow area, almost all of the theoretical pressure recovery predicted by eq. 10-10 is lost to turbulence. When the fluid being produced from the well is a multiphase mixture, eqs. 10-8 to 10-10 can be applied through use of appropriate values for effective density, effective viscosity, and effective velocity. For high flow rates typical of shallow gas flows, the effective multiphase density, pe, viscosity, W e , and velocity, V e , can be calculated assuming no slippage between the phases. Thus, the effective multiphase density pe is given by eq. 10-4 and effective multiphase viscosity p e is given by:

292

A.T BOURGOYNE

where the subscript “1s” refers to a liquid-solids slurry mixture and thus includes the effect of any solids present by including them in the liquid phase. The effective multiphase velocity ue is defined in terms of flow rate 4 and cross-sectional area A, by: 4g + 41 + 4s (10-12) A Experiments conducted in model diverter systems (Bourgoyne, 1992) have indicated that significant cooling of the flow stream occurs due to gas expansion. It is recommended that if a software package for calculating heat-loss is not available, adiabatic flow should be assumed rather than isothermal flow. For adiabatic flow, temperature changes between points can be computed using: ue

=

AT=

Ail2

2(xg c p g

+ xi Cpl + xs Cps)

(10-13)

Convenient distance step sizes can be assumed when using the pressure gradient to move upstream in a stepwise manner. It is often convenient to choose a step size that will end on a fitting boundary when a diameter change or bend occurs. The use of eqs. 10-8 to 10-13 for calculating the flowing pressure gradients upstream of the vent line exit is illustrated in Table 10-2 for the same conditions used in the calculation of Table 10-1 and a horizontal diverter length of 30 m (98 ft). The other well conditions correspond to the example diverter system failure discussed previously for the jack-up rig that was lost offshore Texas in 1975. The 0.762-m (30-in.) casing that was set at 149 m (490 ft) was assumed to have a 2.54-cm (1-in.) wall thickness. The drill string was composed of 224 m (735 ft) of drillpipe having an outer diameter of 12.7 cm (5 in.) and 100 m (328 ft) of drill collars having an outer diameter of 19.1 cm (7.5 in.). Beneath the bit was 27 m (89 ft) of open borehole having a diameter of 25.1 cm (9.875-in.). The *projected area of the bit that partly blocked the annular flow path was equivalent to a diameter of 22.2 cm (8.74 in.). The starting point of the calculation was a gas flow rate of 30.2 m3/s (92.2 MMScf/D), which corresponds to the third entry in Table 10-1. For this flow rate, the calculated absolute pressure at the gas formation was 2.823 MPa (410 psi). By repeating this calculation for a number of different assumed gas flow rates, a flow-string resistance curve can be defined. Flow-string resistance curves obtained in this manner for both a 15.2-cm (6-in.) and a 25.4-cm (10-in.) vent line diameter are shown in Fig. 10-8. Point D corresponds to the example calculation of Table 10-2. When the shallow gas contingency plan calls for using two diverter lines of equal diameter in parallel, half of the total flow will exit through each of the vent lines. This situation is easily handled in the analysis procedure illustrated above by using half of the total gas flow rate in the calculations of Table 10-1 and in the surface vent line section of Table 10-2. The total gas flow rate must be used for the annulus and borehole sections of Table 10-2.

293

SHALLOW ABNORMAL PRESSURE HAZARDS

0

m

6ooo

4Ooo

B o r n Hole Rcssm

( k Pa )

Fig. 10-8. Pseudo-steady-state systems analysis plot for example of Tables 10-1 and 10-2. 10.7. FORMATION PRODUCTIVITY

Resistance to flow is present in the gas reservoir as well as in the flow path to the surface. Since little is generally known about the properties of the gas reservoir causing the unexpected flow, detailed reservoir simulations are not usually justified. However, it is important to take into account turbulence and other factors that become important at high gas velocities. The Forchheimer (1901) equation as adapted for horizontal, radial, semi-steady state flow in a homogeneous gas reservoir is recommended for use in design calculations for diverter systems. This equation can be arranged to give flowing bottom-hole pressure, Pbh, within a wellbore of radius r,, due to flow within a horizontal, circular reservoir of external radius re and effective thickness h and having an average reservoir pressure p r . The Forchheimer equation for these conditions is defined by:

where the subscript sc denotes standard conditions. The terms in brackets reduce to a constant for a given reservoir. The second term is needed to properly model high-velocity gas flow where the velocity coefficient, j?, is determined empirically. Note that once the bracketed terms are reduced to a constant, a relatively simple relationship between gas flow rate and flowing bottom-hole pressure results.

TABLE 10-2

t3 \c)

P

Example calculation of flow-path pressure drop

(2)

(1) Distance from exit (m)

0 0.5 1 2 3 4 5 6 8 10 15 20 25 30 30 30 100 179 179 200 254 254 275 300 325 353 354 354 360 370 381 381

Vertical depth (m)

0 0 0 0 0 0

0 0 0 0 0 0 0 0

0 0

70 149 149 170 224 224 245 270 295 323 324 324 330 340 35 1 35 1

(3)

(4)

(5)

(6)

(7)

(8)

(9)

Outer pipe diameter (m)

Inner pipe diameter (m)

Pressure (Wa)

Temperature

z

Gas density eq. 10-2 (kg/rn3)

Gas viscosity (Pas)

Gas volume

(OK)

Pseudo-reduced density

0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.152 0.711 0.711 0.711 0.711 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251 0.251

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0.127 0.127 0.127 0.127 0.127 0.127 0.127 0.191 0.191 0.191 0.191 0.191 0.222 0 0 0 0

400 411.6 439.4 493.9 568.7 644.4 705.3 149.2 794.4 837.6 912.6 992.1 1064.5 1128.6 1142.0 1253.1 1260.9 1269.7 1269.7 1324.7 1462.3 1467.0 1805.9 2159.7 2450.6 2730.2 2747.5 2745.5 2871.2 2876.8 2882.4 2882.4

268 268 270 273 278 283 286 288 289 290 291 293 294 294 295 300 300 300 300 299 299 299 298 298 299 299 299 298 300 300 300

0.0182 0.0187 0.0198 0.0220 0.0250 0.0279 0.0302 0.0318 0.0337 0.0354 0.0385 0.0418 0.0447 0.0474 0.0478 0.0517 0.0521 0.0524 0.0524 0.0550 0.0609 0.0610 0.0762 0.0917 0.1046 0.1172 0.1180 0.1187 0.1234 0.1237 0.1239

0.987 0.986 0.986 0.984 0.983 0.982 0.981 0.980 0.979 0.978 0.977 0.975 0.973 0.972 0.972 0.971 0.970 0.970 0.970 0.969 0.965 0.965 0.957 0.949 0.942 0.936 0.935 0.934 0.933 0.933 0.932

3.37 3.47 3.68 4.09 4.64 5.17 5.60 5.91 6.25 6.57 7.15 7.76 8.30 8.79 8.88 9.61 9.67 9.74 9.74 10.21 11.31 11.34 14.15 17.02 19.42 21.77 21.91 22.05 22.92 22.96 23.01

9.97 x 9.97 x 1.00 1.02 1.04 1.06 1.07 1.08 1.08 1.09

1.09 1.10 1.10 1.11 1.11 1.13 0.13 1.13 1.13 1.12 1.13 1.13 1.13 1.14 1.15 1.15 1.15 1.15 1.16 1.16 1.16

fraction

0.9996 0.9996 0.9996 0.9995 0.9995 0.9994 I O - ~ 0.9994 1 0 - ~ 0.9993 1 0 - ~ 0.9993 0.9992 10-5 1 0 - ~ 0.9992 0.9991 10-5 0.9990 10-~ 0.9990 10-5 0.9990 10-5 10-5 0.9989 0.9989 10-5 0.9989 10-5 1 0 - ~ 0.9989 0.9988 10-5 0.9987 10-5 0.9987 10-5 0.9984 10-5 1 0 - ~ 0.9980 0.9978 1 0 - ~ 0.9975 10-5 0.9975 0.9975 10-5 0.9974 10-5 10-5 0.9973 10-5 0.9973 10-6 10-6 10-5 10-5 10-5 10-5

W

0 C 3

0

5z

m

Mixture density eq. 10-4 (kg/m3)

Mixture velocity (m/s)

Mixture viscosity (Pa s)

3.83 3.94 4.18 4.65 5.26 5.87 6.36 6.72 7.10 7.46 8.12 8.81 9.43 9.98 10.08 10.91 10.98 11.06 11.06 11.59 12.83 12.87 16.05 19.31 22.02 24.68 24.83 24.99 25.97 26.03 26.08

387.3 376.3 354.6 319.0 281.8 252.6 233.2 220.9 209.0 198.8 182.7 168.5 157.4 148.6 6.9 6.4 6.4 6.3 66.1 63.1 57.0 100.5 80.5 66.9 58.7 52.4 100.6 21.8 20.9 20.9 20.9

1.04 1.04 1.05 1.06 1.09 1.12 1.13 1.15 1.15 1.16 1.17 1.19 1.20 1.21 1.21 1.24 1.24 1.24 1.24 1.24 1.26 1.26 1.29 1.33 1.37

1.40 1.40 1.40 1.42 1.42 1.42

10-5 10-5 10-5 10-5 10-5 10-5 10-5 10-5 10-5 10-5 10-5 lo-’ 10-~ 10-5 10-5 10-~ 10-5 10-5 10-5 10-5 10-5 lo-’ 10-5 10-5 10-5 10-5 10-~ 10-~ 10-5 10-5 10-5

Reynolds number

Moody friction

Hyd. dp

Fric. dp

Acc. d p

factor

(Pa)

(Pa)

(Val

218 2.17 2.15 2.12 2.07 2.02 1.99 1.97 1.95 1.94 1.92 1.90 1.88 1.87 3.38 x 3.31 x 3.30 x 3.30 x 7.32 x 7.30 x 7.22 x 6.17 x 6.01 x 5.82 x 5.61 x 5.53 x 5.16 x 9.75 x 9.62 x 9.61 x 9.61 x

0.0122 0.0122 0.0122 0.0123 0.0123 0.0123 0.0123 0.0123 0.0123 0.0123 0.0123 0.0123 0.0123 0.0123 0.0107 0.0107 0.0107 0.0107 0.0129 0.0129 0.0129 0.0148 0.0148 0.0148 0.0148 0.0148 0.0173 0.0113 0.0113 0.0113 0.0113

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

11.6 11.2 21.2 19.1 16.8 15.1 13.9 26.4 25.0 59.4 54.6 50.4 47.1 0.0 0.0 0.3 0.3 0.0 52.7 129.2 0.0 336.3 320.9 266.9 262.1 8.4 0.0 1.6 2.6 2.8 0.0

0.0 16.6 33.3 55.7 58.9 45.9 30.0 18.8 18.2 15.5 24.9 21.9 17.1 13.4 111.1 0.0 0.0 0.0 0.0 2.3 4.7 0.0 29.0 19.3 11.4 8.7 0.0 120.6 0.5 0.0 0.0

107 107 107 107 107 107 107 107 107 107 107 107 107 107 106

lo6 lo6 lo6 lo6 lo6 lo6 lo6 lo6 106 lo6 106 lo6 106 lo6

lo6 lo6

0.0 0.0 0.0 7.5 8.5 0.0 2.3 6.1 0.0 2.6 3.9 4.7 6.0 0.2 0.0 1.5 2.5 2.8 0.0

296

A.T BOURGOYNE

Laboratory core data shows that the velocity coefficient /l tends to decrease with increasing permeability. Since shallow sands tend to be unconsolidated, a correlation based on data taken in unconsolidated samples (Johnson and Taliaferro, 1938) is recommended for diverter system design calculations. The recommended correlation gives /l in m-’ using: /9 = 1.031/&

(10-15)

where the permeability k is given in m2. Choosing a representative value for the reservoir thickness, h, is complicated by the fact that the wellbore often penetrates through only part of the gas reservoir before the shallow gas flow is detected and drilling is stopped. When this is true, the gas flow is not radial as assumed by eq. 10-14, and an effective thickness value must be used. This effective thickness depends on the ratio of the horizontal to vertical permeability, the wellbore radius r,, the total formation thickness hf, and the formation thickness penetrated by the bit, h,. When the vertical permeability is much less than the horizontal permeability, the effective thickness is approximately equal to the thickness penetrated by the bit. As the vertical permeability increases and approaches the horizontal permeability, the following equation presented by Craft and Hawkins (1959) can be used to estimate the effective thickness for use in the first term of eq. 10-14:

[+

h = h, 1 7

I)$(

6 cos

(10-16)

The thickness penetrated by the bit is always used for the second term in eq. 10-14 because non-darcy flow is generally limited to a region very close to the borehole. A formation productivity curve that is thought to be representative of the example shallow gas reservoir encountered at a depth of 351 m (1150 ft) is shown in Fig. 10-8. The reservoir was assumed to have a permeability of 15 mm2 (15,000 mD), an effective thickness of 3.05 m (10 ft), an external radius of 305 m (1000 ft), and an average absolute reservoir pressure of 4.137 MPa (600 psi). Since well control was lost when pulling pipe from the borehole, it is possible that the entire reservoir thickness was penetrated by the bit. Shallow gas formations having a thickness of 3 m or less are difficult to detect using seismic data. The gas properties used were as previously defined for the calculations of Tables 10-1 and 10-2.

10.8. EQUILIBRIUM GAS FLOW RATE

The equilibrium flow rate that will be observed during diverter operations is obtained from the intersection of the flow-string resistance curve and the formationinflow performance curve. Note that for the example under consideration (Fig. 10-8) the gas flow rate predicted is 37.9 m3/s (116 MMScf/D) for a 0.152-m (6-in.) diverter system and 39.2 m3/s (120 MMScflD) for a 0.254-m (10-in.) vent line.

297

SHALLOW ABNORMAL PRESSURE HAZARDS

Once the pseudo-steady-state gas flow rate has been determined, the pressure at various key points in the flow path can be established. The pressures can be determined by interpolation from the pressure traverses previously calculated in Tables 10-1 and 10-2 or by a new pressure traverse calculated for the equilibrium gas flow rate. It is important that the pressures in the open borehole are maintained below formation fracture pressure after pseudo-steady-state conditions are reached. If borehole pressures are sustained above the formation fracture pressure for a long period of time, the probability that fracturing will reach the seafloor (Fig. 10-2) is greatly increased.

10.9. FORMATION FRACTURE PRESSURE

Constant and Bourgoyne (1988) have recommended fracture pressure equations for offshore drilling operations based on Eaton’s correlation. The recommended method gives the vertical component of total overburden stress, liquids and solids, S, in SI units (kPa) in terms of the seawater depth, D,,, and the sediment depth below the seafloor, D,,(both in meters) using: S = 101.3

+ 10 D,, + 25.5 D,- 21,980[1-

exp(-0.000279 D,)]

(10-17)

The minimum expected absolute formation fracture pressure, pf, is then determined from the absolute formation pore pressure, pp,and the overburden pressure, S, by: pf = pp

+ [l - 0.629exp(-0.00042

Ds)] [S - pp]

(10-18)

This minimum fracture pressure would correspond to extending an existing fracture in a sandy formation. Higher formation fracture pressures would be expected for fracture initiation and in plastic “gumbo” shale formations. The maximum expected pressure for fracture extension is the overburden pressure given by eq. 10-18. A comparison of the borehole pressures and fracture pressures for the two vent line sizes considered in the example is shown in Table 10-3. Note that for the 0.152-m (6-in.) vent line, the expected fracture pressure at the casing seat would be exceeded, whereas for the 0.254-m (10-in.) vent line, a 953 kPa (138 psi) safety margin would exist.

10.10. WORKING PRESSURE OF DIVERTER COMPONENTS

The systems analysis procedure provides information about the pressures that could be expected on the diverter system components after the well is unloaded and pseudo-steady-state conditions are reached. However, while the drilling fluid is being displaced from the well, the mud in the system behaves as a viscous plug which greatly slows flow through the diverter. This situation results in a pressure peak occurring when the leading edge of the gas reaches the vent line entrance. The magnitude of the pressure peak depends primarily on the formation pressure

A.T. BOURGOYNE

TABLE 10-3 Comparison of equilibrium pressure traverses for 0.152-111(6-in.) and 0.254-111 (10-in.) vent lines (water depth of 58 m and air gap of 33 m) Location

Depth (m)

(ft)

Pressure for 0.152-111system

Pressure for 0.254-m system

Minimum fracture extension pressure

(kPa)

(kPa)

(kPa)

(psi)

(psi)

(psi)

Diverter exit

0

0

500

73

187

27

Protected by casing

Wellhead

0

0

1554

225

505

73

Protected by casing

149 174

490 571

1575 1644

228 238

514 736

75 107

1467 1846

214 270

Top of drill collars

224

735

1822

264

1274

185

2692

394

Bottom of drill collars

324

1063

3419

496

3397

490

4264

629

Below bit

324

1064

3573

518

3545

514

4264

629

Hole bottom

351

1150

3587

520

3559

516

4825

712

Casing seat

and on the amount of mud that remains in the well due to slippage past the gas while the well is unloading. The pressure peak can be substantially higher than the equilibrium wellhead pressure calculated from a systems analysis procedure. This pressure peak is of short duration, typically lasting only a few seconds. If fracturing occurs, it is unlikely that fracture propagation would move very far from the wellbore before the pressure subsides to the equilibrium value. As long as the equilibrium borehole pressure is less than the fracture extension pressure, there is a high probability that the fracture will not propagate to the surface. It is recommended, therefore, that the design load at the casing seat is based on equilibrium flowing conditions. However, the design load for surface diverter system components should be based on the pressure peak occurring when the drilling fluid is being displaced from the well. Santos and Bourgoyne (1989) performed experiments on a 0.152-m (6-in.) diverter vent line attached to a 382 m (1252 ft) well containing 0.178-m (7-in.) casing to study unsteady-state pressure behavior when the well is first placed on a diverter system. In the experiments, the gas entering the bottom of the well flowed through a valve that was controlled by a process control computer that simulated the behavior of a formation. A program was developed for the flow control computer to permit a range of formation productivities to be simulated. Pressures were monitored during the experiments at a number of locations in the well and diverter. Experimental runs were made using a number of different mud systems. Typical experimental results obtained by Santos and Bourgoyne (1989) for the pressure history and flow-rate history at any given point in the surface system during the simulated diverter operations are shown in Fig. 10-9. Note that the flow rate from the well begins slowly but accelerates very quickly as gas approaches the

SHALLOW ABNORMAL PRESSURE HAZARDS

299

Time Fig. 10-9. ?frpical pressure and drilling fluid flow rate history observed during experimental study of diverter operations. (After Santos and Bourgoyne, 1989.)

surface. As the column of drilling fluid in the well decreases, the pressure imposed on the gas decreases, causing rapid expansion of the gas in the well and an increase in the gas flow rate into the bottom to the well. Also note the pressure peak in the vent line that is seen just before the bottom of the drilling fluid column exits the system. Eventually, a pseudo-steady-state condition is reached in which the pressures change very slowly with time due to reservoir depletion. Santos and Bourgoyne (1989) developed a computer model for predicting the pressures and flow rates observed during a shallow gas flow as a function of both time and position. The program was first verified using the experimental results obtained with the model diverter system. The computed results for peak wellhead pressure matched the observed pressure peaks within an error band of about 25%. The program was then used to simulate a wide variety of field conditions. It was found that the peak wellhead pressure tended to decrease with decreasing formation pressure, decreasing formation productivity, and increasing vent line diameter. For the field conditions studied, the peak wellhead pressure was generally less than 65% of the formation pressure. Also, the time required to unload the well was typically only a few minutes. Results obtained using the computer model for the 0.254-m (10-in.) diverter vent line discussed in the previous example calculations are shown in Fig. 10-10. The drilling fluid in the well when the shallow gas flow began, was assumed to have a density of 10.9 kN/m3 (9.3 lb/gal). Note that it is predicted that the well will unload in about one minute with a peak wellhead pressure of 1.436 MPa (208 psi), which was about 34% of the formation pressure. Thus, a working pressure for diverter components of at least this value would be needed. The calculated pressure at the casing seat exceeds the minimum fracture extension pressure of 1.467 MPa (214 psi) during most of the first minute but drops to about 496 kPa (72 psi) after pseudo-steady-state conditions are reached. Similar simulations performed for a 0.152-m (6-in.) diverter vent line gave a peak wellhead pressure of 2.620 MPa (380 psi), which was about 63% of the formation pressure.

300

A.T. BOURGOYNE

- unloading -

Period

Pseudo -steady

psi

-

State PreSSUreS

600

, Bottom Hole Pressure .\

J

/

500

I-

casing seat pressure

400 300

200 Exit 1 Pressure 0

20

40

60 Time

80

100

120

140

160

-

100 0

180

(sec)

Fig. 10-10. Qpical pressure and drilling fluid flow rate history observed during experimental study of diverter operations. (After Santos and Bourgoyne, 1989.)

10.11. DIVERTER ANCHORS

Some diverter failures have involved the anchor system used to hold the vent line piping in place. The anchor system should be carefully designed to withstand the forces resulting from the moving fluids. The maximum forces on the anchoring system occur when the wellhead pressure reaches its peak value. When telescoping segments or slip joints are used below the annular blowout preventer, a maximum upward force on the wellhead must be resisted that is equal to the peak pressure multiplied by the internal annular cross-sectional area at the slip joint. In computer simulations made by Santos and Bourgoyne (1989), these forces sometimes reached as high as 1.3 MN (300,000 lbf) for the field conditions studied. Similarly, a maximum axial thrust distributed along the length of the vent line exists which is equal to the peak pressure multiplied by the internal cross-sectional area of the vent line. In addition, at bends in the diverter system, the anchor system must resist a force equal to the mass rate of flow multiplied by the change in the fluid velocity vector at the bend. For a 90" bend, this force is approximately given by the fluid density times the square of the average velocity, pv2.

10.12. RATE OF EROSION

Information was collected on 31 wells that encountered shallow gas. Typical locations of erosion type failures are shown in Fig. 10-11 for a simplified diverter schematic. Problems tend to occur: (1) at bends in the vent line; (2) at flexible hoses connecting the vent line to the wellhead; (3) at valves or just downstream from valves; and (4) in the wellhead and diverter spool.

SHALLOW ABNORMAL PRESSURE HAZARDS

301

Fig. 10-11. ljpical locations of erosive wear on diverter system for bottom-supported rig. (After Bourgoyne, 1989.)

The severity of the erosion problems experienced was greatly affected by the quantity of sand produced by the well. When considerable sand was produced, diverter system component failures started in the bends and valves and progressed back to the wellhead. The entire wellhead and annular preventer was cut from the well in an extreme case. For this well, sand piles of 10 ft (3 m) in height were reported on the rig floor after the well bridged. Erosion can be caused by cavitation, impingement of liquids, or impingement of solid particles. Erosion by impingement of solid particles is the most rapid and is of primary concern for diverter operations. Previous erosion studies using flat plates (Finnie, 1960; Goodwin et al., 1969; Ives and Ruff, 1978) have shown that the total mass of material abraded from a solid surface is directly proportional to the total mass of abrasives striking the solid surface. Thus, the erosion resulting from abrasive particle impact is often expressed in terms of a specific erosion factor, Fe, which is defined as the mass of steel removed per unit mass of abrasive. Bourgoyne (1989) used two experimental set-ups to measure the rate of erosion in various fittings. The first set-up (Fig. 10-12a) was used for mud-sand slurries. Drilling mud flowed from the right side of a partitioned tank to a centrifugal pump, through 6.1 m (20 ft) of pipe having an inside diameter of 5.08 cm (2.0 in.), through the fitting being evaluated, and then back into the tank. Flow rates were periodically checked by temporarily closing an equalizing line connecting the left and right sides of the tank. Sand concentration in the mud was also periodically checked by taking a sample from the tank.

302

A.T BOURGOYNE

-/

-

Equalizing Valve

Being-

(a) Exwrimental Set-ur, for flow of MudSand Mixture

Evaluated

- 304011

Sand Hopper -_

\

I

1)

Control

Fitting Being

II l n H

6,000 lb pressure pot

Evaluated Differential pressure

Sensor B ,

\

Experimental Set-up for Flow of Gas/Sand and GadLiquidSand Mixture

3

Ell

Flexible Hose

(c) Types of Fittings Tested Fig. 10-12. Schematic of model diverter systems used in erosion study. (After Bourgoyne, 1989.)

The second set-up (Fig. 10-12b) was used for gas-sand and gas-water-sand mixtures. Air supplied from a compressor flowed first through a flow control valve and a 5.08-cm (2-in.) orifice meter. The flow control valve maintained a constant flow rate by means of a process control computer. Sand was added to the flow stream from a 27-kN (6000-lb) capacity sand blasting pressure pot through a metering valve. The weight of the pressure pot was continuously monitored, and the

SHALLOW ABNORMAL PRESSURE HAZARDS 20

40

60

sand-.

80

100

303

lWmin

m3/s

Fig. 10-13. Effect of sand concentration on rate of erosion at gas velocity of 100 m/s for ASTM a-234, Grade WPB ells with r / d = 1.5 (No. 2 blasting sand). (After Bourgoyne, 1989.)

sand flow rate was determined from the rate of change of weight with time. Water or mud could be introduced downstream of the sand injection point. The mixture then flowed through 17 m (56 ft) of 5.08-cm (2411.) inside diameter line, through the fitting being evaluated, through a l-ft tail piece, and then exited to the atmosphere. The fittings evaluated included steel ells, plugged tees, vortice ells, and rubber hoses (Fig. 10-12c). The plugged tees had only a blind flange on the dead-end portion and did not contain any special lead of steel targets. Weight loss and wall thickness loss were periodically determined during the tests. Wall thickness measurements were made using an ultrasonic method. Thickness profiles were determined along both inside and outside radii of the bends. The location of the areas of maximum wear are shown in Fig. 10-12c for the various fittings and fluid types studied. Data were collected to permit evaluation of sand rate, fluid velocity, fluid properties, and fitting type. The sand used in the experimental tests was No. 2 blasting sand. The use of the specific erosion factor, F,, for characterizing the effect of sand concentration on erosion in bends was evaluated using the data shown in Fig. 10-13. Note that the wear rate was found to be directly proportional to the sand rate for the entire range of conditions studied. These sand rates were sufficient to result in sand concentrations of up to 0.12%. At high concentrations, significant decreases in the specific erosion factor would be expected due to interference between sand grains. However, this behavior was not observed in this study. It appears that the use of a constant value for the specific erosion factor is acceptable for the range of sand concentrations representative of diverter system operating conditions. Experiments were conducted to determine the effect of velocity on the rate of erosion for velocities of up to 220 m/s (722 ft/s). The results are shown in Fig. 10-14.

304

A.?: BOURGOYNE

10

1.

0.1

0.0

Superficial Gas Velocity, mls Ag. 10-14. Effect of gas velocity on rate of erosion for ASTM 234, Grade WPB ells with r / d = 1.5 (No. 2 blasting sand). (After Bourgoyne, 1989.)

The apparent slope of 2 includes the effect of increasing steel temperature with increasing flow velocity due to the sand particles striking the wall of the fitting. When using dry gas at very high velocities, portions of the fittings were observed to smoke and begin to turn red due to very high temperature increases. Comparison of specific erosion factors, F,, obtained in similar fittings for mudcarried abrasives and gas-carried abrasives suggests that erosion rates are lower for mud by one to two orders of magnitude. The higher erosion rates for gas are thought to occur because the transfer of momentum from the solids to the fluid is much less efficient. Thus, the solid particles strike the wall of a bend at a much greater angle in gas than in liquid. For ductile materials such as steel, the maximum rate of erosion occurs at an angle of impact with the eroding surface of about 20". For brittle materials, the maximum rate of erosion occurs at an angle of 90" (Ives and Ruff, 1978). Based on the experimental work performed, Bourgoyne (1989) proposed the following equation in SI units for estimating the rate of loss in wall thickness h w , with time t , in a diverter component of density ps and cross-sectional area A , flowing abrasives having density pa, at a volumetric flow rate qa, and flowing gas or liquid at superficial velocity, us, or usl, and volume fraction (holdup) H, or HI: Gas continuousphase (dry gas or mist pow)

(10-19)

305

SHALLOW ABNORMAL PRESSURE HAZARDS TABLE 10-4 Recommended values of specific erosion factor

r/d

Fitting type

Material

Dry gas flow

Mist flow

Cast steel Seamless steel

2.2

2.8

Cast steel Seamless steel

2.0

Cast steel Seamless steel

1.7

3.0

Cast steel Seamless steel

1.5 0.60

3.5

Cast steel Seamless steel

1.2

Cast steel Seamless steel

0.9

Cast steel Seamless steel Cast steel Seamless steel

0.7

Rubber

1.00 0.40 0.37 0.33 0.29 0.25

Cast steel Seamless steel

0.026

Cast steel

0.0078 a

1.5

Ell

2.0 2.5

4.0 4.5 5.0 Flexible hose

6.0 8.0 10.0 12.0 15.0 20.0

-

Plugged tee

3.0

Vortice ell a

Specific erosion factors (glkg)

0.89

Liquid flow 0.001 1.1

2.4 0.79

0.001 0.93

2.0 0.69

0.001 0.77

1.65 0.66

0.0014

1.32 0.52

0.0076 0.55

1.0

0.01

0.45

0.49

0.77 0.40

0.01 0.44

0.55

0.5

0.01

0.38

0.35 1.22 0.45 0.39 0.35 0.31 0.28

0.02

0.0046

0.064 0.012

0.0040

0.01 0.0028

Assumes failure in pipe wall downstream of bend.

Liquid continuous phase

dhw = Fe-Pa 4a dt

ps A

(-)

USI

100 Hi

2

(10-20)

Recommended values for specific erosion factor F, are given in Table 10-4. The accuracy of the proposed calculation method was verified using the experimental data collected. The average error observed was 29%. This level of accuracy was felt to be acceptable for diverter design considerations. Relatively large error ranges are often associated with the use of an empirical correlation for describing multiphase flow phenomena. Equations 10-19 and 10-20 were used to estimate the erosion life of various diverter components under a variety of assumed field conditions. Calculated erosion

306

A.T BOURGOYNE

100

10

Erosion Rate P m/s 1

0.1

10

100 Superficial Gas Velocity,

loo0

mls

Fig. 10-15. Effect of fitting type on predicted erosion rate. (After Bourgoyne, 1989.)

rates for various fittings and for a sand rate of 0.001 m3/s (350 lblmin) are shown in Fig. 10-15 as a function of superficial gas velocity. Note that erosion rates increase by two orders of magnitude as velocity increases from 30 m/s to the maximum (sonic) velocity of about 300 m/s. Note also, that for a given sand production rate, an order of magnitude decrease in erosion rate is predicted for changing from an ell to a plugged tee or vortice ell. The use of eq. 10-19 for calculating the erosion life of various fittings for making a turn near the wellhead for the diverter system discussed in the previous example calculations is illustrated in Table 10-5. A design sand rate of 0.001 m3/s (350 lb/min) was used in these calculations. Note that for the 25.4-cm (10-in.) system, the calculated time to failure is just 7 min for a short-radius ell. Use of a plugged tee would increase the estimated life to 8.9 hr and use of a vortice ell would increase the estimated life to 13 hr. The estimated life for a 15.2-cm (6411.) system would be about a third of that for the 25.4-cm (10 in.) system. The calculations above illustrate the importance of avoiding bends in diverter systems. When a bend is required, a vortice ell or plugged tee should be used. When a plugged tee is used, metal targets in the dead-end branch can increase the erosion resistance to shallow gas flows containing significant quantities of water. However, field problems have been reported due to metal targets (lead fillings) breaking loose and moving downstream. This problem is made worse when the target is installed in a vertical position where they may fall down into the flow stream. It is recommended that targets be designed as an integral part of the fitting.

307

SHALLOW ABNORMAL PRESSURE HAZARDS TABLE 10-5

Comparison of erosion near wellhead for various fittings used to make bend in 0.254-m(10-in.) diverter system and 0.154-m(6-in.) diverter system Parameter

Units

Diameter 0.152 m (6 in.)

0.254 m (10 in.)

Wall thickness

m in.

0.0071 0.28

0.00927 0.365

Flow rate at S.C.

m3/s MMscfID

40.8 124

43.3 132

Pressure at fitting

Pa psi

1,485,000 215

488,000 71

Temperature at fitting

"C "F

38 100

38 100

Flow rate at fitting

m3/s MMscf/D

3.0 9.2

9.7 29.5

Velocity at fitting

rnls fls

165 542

191 628

0.9997

0.9999 2.2 x 1 0 - ~ (7 min) 3.1

Gas volume fraction

Erosion rates Ell-r/d = 1.5 F. = 0.00089

mls in.lhr

4.5 x 1 0 - ~ (3 min) 6.4

Flexible hose Fe = 0.00033

mls in./hr

1.7 x 2.4

(7 min)

Pugged tee Fe = 0.000012

rnls in./hr

6.1 x 0.087

(3.2 hr)

2.9 x 0.041

(8.9 hr)

Vortice ell Fe = 0.000008

mls in./hr

4.0 x 0.058

(4.8 hr)

1.9 x 0.028

(13 hr)

9.0 x

(20 min)

1.1

10.13. PLUGGING

Solids in the drilling fluid tend to settle in the diverter components and can lead to valve malfunctions and vent line plugging. To the extent possible, the diverter system is generally sloped towards its exit to promote draining and minimize the accumulation of solids in the system. In addition, provisions for flushing the system should be made. Clean-out connections with flushing jets should be placed upstream of all valves, bends, and local low spots.

10.14. CONTROL SYSTEM

Control of the diverter vent lines should be achieved by means of valves that can be fully opened to minimize erosion and pressure losses. The diverter control sys-

308

A.T. BOURGOYNE

tem generally involves pneumatic or hydraulic valve operators and can be operated from remote panels located with the blowout-preventer control panels. It is often advantageous to integrate the diverter control system with the blowout preventer control system. Standards regarding the accumulator unit which stores the pressurized control fluid needed to operate the valves, should be similar to those adopted for the blowout preventer system. A non-flammable, low-freezing-point power fluid should be used in the hydraulic units. The controls should be designed so that the well cannot be closed with the diverter system, i.e. the valves to the vent line should automatically open before the annular sealing device is closed. When multiple vent lines are needed to ensure downwind diversion, the currently selected vent valve should open before the other vent valve is closed. Specially designed integral sequencing diverter components have recently become available that provide the annular sealing device with a vent line valve in a single unit (Roche, 1986).

10.15. DESIGN CONSIDERATIONS FOR DYNAMIC KILL

Some operators use a contingency plan which calls for a “dynamic” well control procedure to be attempted as soon as the well is placed on a diverter. The dynamic well control procedure has been described in detail by Blount and Soeiinah (1981). With this method, high-circulating rates are used to increase annular frictional pressure losses sufficiently to cause the bottom-hole pressure to be raised above the formation pressure. Some operators maintain a volume of weighted drilling fluid on location for use in an immediate attempt at a dynamic kill. Other operators plan the use of sea water after the available mud volume has been exhausted. The success of the dynamic well control method is governed primarily by the hole size being drilled, the flow rate and pressure limitations of the available rig pumps and the effective thickness of the gas formation penetrated by the bit before the gas flow is detected. Data that was collected on 28 shallow gas flows occurring in the Gulf of Mexico indicated that in two of the 28 cases reported, the flow was successfully stopped using a dynamic kill procedure. When a dynamic well control procedure is included in the shallow gas contingency plan, the diverter system design load should be based on the well conditions that will result with the rig pumps operating at the maximum available flow rate. The basic calculation procedure remains unchanged, except that the liquid pumped is added to the formation gas being produced on bottom. A systems analysis plot for a dynamic kill attempt using sea water at a maximum pump rate of 0.063 m3/s (1000 gal/min) in a 25.1-cm (9.875-in.) hole is shown in Fig. 10-16. Other well conditions were taken to be the same as the previously discussed offshore Texas example. Formation productivity curves are shown for a range of effective formation thickness values from 0.15 rn to 3.05 m (0.5-10 ft). Flow-string resistance curves are shown for both a non-pumping case and for a dynamic kill attempt at the maximum available pump rate. Note that for the maximum effective formation thickness value considered, the dynamic well control method would reduce the equilibrium gas flow rate from 43 to 22 m3/s (132-67 MMScf/D), but would not bring the well under control.

309

SHALLOW ABNORMAL PRESSURE HAZARDS

b=3.OSm

80-

0

I

x'

m

Y

6OoO

4Ooo

Bottom Hole Pressure

( k Pa )

Fig. 10-16. Pseudo-steady-state systems analysis plot for dynamic well control attempt using available rig pumps.

Note also that control is not predicted for any of the effective formation thickness values considered. These calculations suggest that the dynamic well control method will be successful only for very thin formations or low-permeability formations with relatively small diameter boreholes. Using the methods previously presented, it can be shown that the pressure at the casing seat during the example dynamic kill attempt in a 25.1-cm (9.875-in.) hole would increase slightly to 525 kPa (76 psi). Since the minimum fracture extension pressure is 1.467 MPa (214 psi), the 25.4-cm (10-in.) diverter system would be adequate to permit the dynamic well control method to be tried. If the dynamic kill rate of 0.063 m3/s (1000 gal/min) could be implemented as soon as the flow from the formation began, the peak wellhead pressure observed when the gas first reaches the surface would be reduced from 1.436 MPa to 1.138 MPa (208-165 psi). The velocity at a bend near the wellhead would be reduced due to the introduction of liquids from 191 m/s to 131 m/s. This would result in about a 40% reduction in the erosion rate at this location.

310

A.T BOURGOYNE

Even when the dynamic well control method cannot be successfully employed using the available rig equipment, there is a high probability that control of the well can be regained through borehole collapse or reservoir depletion. In 25 of 28 shallow gas flow events that occurred in the Gulf of Mexico (90%), the well plugged due to borehole collapse. In 14 cases (50%), flow stopped within a one-day period. In 22 cases (79%), flow stopped within a one week period. However, in one case, two relief wells had to be drilled before the well could be brought under control with auxiliary pumping equipment. Koederitz et al. (1987) developed a computer program for determining the flow rate and pressure requirements to bring a shallow gas flow under control using the dynamic well control method. The program can be used to evaluate the requirements for regaining control either using the existing wellbore, or using one or more relief wells. The program is based on the systems analysis approach illustrated in the previous offshore Texas example, except that the analysis is repeated at successively higher pumping rates until well control is indicated by the lack of an intersection

0

2OOo

Pressure

4Ooo

(kPa)

Fig. 10-17. Pseudo-steady-state systems analysis plot for dynamic well control attempt using available rig pumps.

SHALLOW ABNORMAL PRESSURE HAZARDS

311

between the flow-string resistance .curve and the formation inflow-performance curve. The flow-string resistance curve at the minimum pump rate required for well control for the previous example is also shown in Fig. 10-16. Note that a pump rate of 0.189 m3/s (3000 gal/min) would be required. At least one relief well and use of auxiliary pumping equipment would be needed to achieve this rate without exceeding a maximum pump pressure of 2.2 MPa (15,000 psi). The program developed by Koederitz et al. (1987) also determines the maximum pressure experienced at every point in the borehole as the pumping rate is increased up to the value required to bring the well under control. It was found that the maximum pressure at a given point in the borehole does not necessarily occur at the maximum liquid rate. Ideally, the diverter system design would permit any pumping rate up to the kill rate to be maintained without exceeding the fracture pressure. A comparison of the fracture and borehole pressures as a function of pumping rate for the offshore Texas example is shown in Fig. 10-17. The calculations indicate that the 25.4-cm (10-in.) diverter vent line would achieve this design objective.

10.16. DIVERTER OPERATION

The infrequent use of the diverter system increases the need for scheduled system maintenance and personnel training activities. Since a shallow gas flow can surface in less than a minute, there will be little time for communicating instructions to the rig crew after the flow is detected. Calculation results used to verify the adequacy of the diverter system for the anticipated drilling plan are also useful for personnel training. Each member of the rig crew should thoroughly understand the contingency plans that will be used in the event of a shallow gas flow and the action required from them when executing these plans. These plans should be covered in a “pre-spud conference” held for operator and contractor personnel. The rig crew should also understand the purpose and importance of the activities directed towards system maintenance. A properly designed system will be of no use if it is not properly maintained. In operation, the diverter system should be used primarily to provide time for an orderly rig abandonment. If the shallow gas flow is detected before the bit has opened a significant thickness of the gas-bearing formation, or if the formation permeability is low, use of the dynamic well control method may be successful. The success or failure of an attempted dynamic kill will depend on many factors, including the size of the borehole being drilled. However, the diverter exit should be carefully monitored to detect when the flow velocity begins to approach sonic velocity and to detect sand production. A transducer at the diverter exit that could detect the onset of sonic flow, and estimate gas rates would be very useful. A sand probe that could detect significant levels of sand production is also needed. A novel vent line exit monitor is under development as a result of the research completed at Louisiana State University.

312

A.T. BOURGOYNE

10.17. SPECIAL CONSIDERATIONS FOR FLOATING DRILLING VESSELS

When drilling from a floating vessel, the operator has more options available for handling a shallow gas flow. The vessel is not supported from bottom, so the danger of losing the vessel to a crater is no longer present. Various options that are available are illustrated in Fig. 10-18. Each of these options has different advantages and disadvantages, and its use must be based on the drilling conditions anticipated. The option illustrated in Fig. 10-18a is similar to the approach used with a bottom-supported vessel. During drilling operations, the drilling fluid is returned to the surface through the marine riser. If a shallow gas flow is encountered, an annular sealing device or diverter located at the top of the marine riser is closed, and the gas flow is vented through a conventional diverter system. An annular blowout preventer with the associated choke and kill lines may also be deployed below the marine riser. The use of a surface diverter system (Fig. 10-18a) has the advantage of maintaining a closed drilling fluid system in which fluid properties can be controlled. High formation fracture pressures permit better control of the borehole pressures through selection of a higher drilling fluid density. The use of a higher-density fluid increases the ability to prevent a shallow gas flow. When the formation fracture pressure is low, it may not be possible to bring drilling fluid back to the vessel without the aid of booster lines used to gas-lift the marine riser. A riser dump valve may also be used to periodically release dense drilling fluid that has become loaded with drilled cuttings at the sea floor. r

I

(a) Surface Diversion

(b) Open System

(c) Subsea Diversion

Fig. 10-18. Various methods for handling shallow gas flows on floating drilling vessels.

SHALLOW ABNORMAL PRESSURE HAZARDS

313

The use of a surface diverter system has the disadvantage of bringing the gas on board the vessel, perhaps creating a need to abandon the vessel for personnel safety. An abandoned dynamically positioned floating vessel may not be able to maintain its station over the subsea wellhead. Also, the slip joint used to permit motion of the floating vessel relative to the wellhead introduces a weak link in the system. The pressure-integrity problem of the slip joint (Fig. 10-18a) can be eliminated through use of a newly available annular sealing unit that can be placed below the slip joint. When using this new technology, outlets below the sealing unit are attached to the surface vent lines by means of flexible hoses. (Hall et al., 1986). The marine riser should (whenever feasible) be designed to withstand the external pressure of the sea water while containing only gas. Several cases of riser collapse have occurred which indicate an elastic collapse mode of failure. This failure mode is controlled by the diameter to wall thickness ratio, and is independent of the yield strength of the steel used (Erb et al., 1983). When it is not feasible to design the marine riser to withstand the full collapse loading of the sea at the water depth of interest, an anti-collapse valve can be used in the marine riser (Fig. 10-18a). This valve will automatically open when the internal pressure in the marine riser falls too low, admitting sea water to the marine riser. Newly designed anti-collapse valves have recently become available. The systems analysis procedure described previously can be used to determine the flow rate at which sea water will enter. This is accomplished by modifying the procedure used to calculate the flow-string resistance at a given gas flow rate. The flow-string resistance must be computed for various assumed sea water flow rates through the anti-collapse valve. The correct flow-string resistance curve is then selected based on a knowledge that the pressure in the marine riser at the valve must be equal to the pressure in the ocean at that depth, less any pressure drop across the valve due to the flow of sea water. Another option that can be used with the equipment arrangement shown in Fig. 10-18a is to close the annular blowout preventer at the sea floor and accept the possibility of sea floor fracturing. When using this option, the lower marine riser package is usually unlatched from the blowout preventer. If gas begins surfacing near the vessel, the vessel is moved as quickly as possible. In deep water, the gas may be carried a considerable distance from the vessel. In addition, much of the gas may go into solution in the sea water. The solubility of natural gas in sea water increases significantly with increasing pressure and decreasing temperature (Dodson and Standing, 1944). The option illustrated in Fig. 10-18b is the use of an open system in which the drilling fluid and cuttings are discharged at the sea floor. No marine riser is deployed and sea water is generally used for the drilling fluid. In the event of a shallow gas flow, gas is discharged through the open wellhead at the sea floor. Returns at the sea floor are generally monitored with a subsea camera. The pressure at the wellhead is maintained at the hydrostatic pressure for the given ocean water depth, causing borehole pressures to be maintained at a higher value than for a surface diversion. This results in a lower gas rate but may also reduce the tendency for the well to plug by borehole collapse, especially in very deep water. This option

3 14

A.7: BOURGOYNE

is best suited to areas where the formation pore pressures and fracture pressures are known to be low. All of the problems of returning the drilling fluid to the surface vessel without causing formation fracture are avoided. The major disadvantages of this approach are an inability to increase the drilling fluid density to minimize the chance of a shallow gas flow from an abnormally pressured formation, and the possibility of a gas boil near the vessel. However, if gas begins surfacing near the vessel, the vessel can be moved away from the well location, preferably up-current, but wind direction must be considered too. The option illustrated in Fig. 10-18c involves the use of a subsea diverter system between the wellhead and the marine riser. This system has the advantages of a closed drilling fluid system in which the drilling fluid density can be controlled, but yet does not require that the gas flow be brought on board. The vent line is short, so the problems associated with the possibility of gas surfacing near the vessel remain. The time required to leave the location is slightly greater than that of an open system.

10.18. RECOMMENDATIONS

As a result of the research conducted, the following recommendations are made: (1) Seismic surveys should be made at proposed offshore wildcat-well locations and the data processed for shows of shallow, abnormally pressured gas. However, the operator should recognize that the use of shallow hazard surveys will not always detect the presence of shallow gas formations. (2) Maximum controlled safe drilling rates should be estimated for the shallow portion of a well in which gas-cut mud could occur and increase the risk of a shallow gas flow. (3) A systems analysis design procedure should be employed for proposed wildcat wells to verify the adequacy of the planned casing program for the available diverter system. The systems analysis should consider the possibility of sonic flow velocity at the diverter vent line exit and at restrictions and changes in direction of the flow path. (4) The working pressure of a diverter system should be based on pressure peaks that could be expected during the unloading of the drilling fluid from the well. (5) Bends in diverter vent lines should be avoided whenever possible. When bends are required, a plugged tee or vortice ell should be used. (6) Dynamic well control methods have been successfully used to control some shallow gas flows with available rig pumps. However, a vent line exit monitor should be developed which will detect sonic flow, significant levels of sand production, and provide appropriate warning when these conditions are detected. (7) When shallow gas flows are severe, the diverter system on a bottomsupported drilling vessel should be used primarily to provide time for an orderly rig abandonment.

SHALLOW ABNORMAL PRESSURE HAZARDS

315

ACKNOWLEDGEMENTS

The research which formed the basis for this chapter was supported by the U.S. Minerals Management Service and by unrestricted grants from ARCO, Chevron, and Conoco. Equipment grants were provided by Daniel, Dresser Industries, Foxboro, Hydril, and Rosemount Instruments.

APPENDIX 1 - NOMENCLATURE A C

d e

f F h H k

k M n P 9 r R S t

T u

z

B P

e P

0

X

cross-sectional area, m2 compressibility, Pa-' diameter roughness, m Moody friction factor specific erosion factor, kglkg thickness, m fractional volume or holdup ratio of heat capacity at constant pressure to heat capacity at constant volume intrinsic permeability, mm2 molecular weight polytropic expansion coefficient pressure, Pa volumetric flow rate, m3/s radius universal gas constant vertical component of total stress time, s temperature, K velocity, m/s gas deviation factor velocity coefficient, m-l viscosity, Pa s vertical deviation angle, radians mass density, kg/m3 stress weight fraction or quality

Subscripts 1, 2 a bh e f

reference depths of casing seat and bit abrasive bottom-hole effective; also, external reservoir limit formation; also, fracture

g

gas

I

liquid solid; also, steel; also, sediments liquid-solid mixture overburden at constant pressure; also, pore; also, thickness penetrated standard conditions superficial gas flux

S

Is ob

P sc sg

316 sw V W

A.T. BOURGOYNE sea water at constant volume wall; also, wellbore

REFERENCES Beck, F.E., Langlinais, J.P. and Bourgoyne, A.T., 1986. Experimental and theoretical considerations for diverter evaluation and design. SPE 15111, California Regional Meeting of the Society of Petroleum Engineers, Oakland, Calif., April 3-6. Beck, F.E., Langlinais, J.P. and Bourgoyne, A.T., 1987. An analysis of the design loads placed on a well by a diverter system. SPEIIADC 16129, Drilling Conference, New Orleans, La., March. Blount, E.M. and Soeiinah, E., 1981. Dynamic kill: controlling wells in a new way. World Oil, October, pp. 109-126. Bourgoyne, A.T., 1989. Experimental study of erosion in diverter systems due to sand production. SPEIDIDC 18716, Drilling Conference, New Orleans, La., pp 807-816. Bourgoyne, A. T., 1992. Improved method of predicting wellhead pressure during diverter operations. IADCs Third Annual European Well Control Conference, Noordwijkerhout, June 2-4. Bourgoyne, A.T., Hise, B.R., Holden, W.R. and Sullins, R.S., 1978. Well control procedures for deepwater drilling, Part 2. Control of shallow kicks. Ocean Resour: Eng., October, pp. 8-18. Bourgoyne, A.T., Millheim, K.K., Chenevert, M.E. and Young, F.S., 1986. Applied Drilling Engineering. SPE Tatbook Series, Vol. 2. Society of Petroleum Engineers, Dallas, Texas, pp. 252-285. Brown, K.E., 1984. The Technology of Artificial Lift Methods, Vol. 4. Penn Well Books, ’hlsa, Okla, pp. 71-118. Clark, A.R. and Perkins, TK., 1980. Wellbore and near surface hydraulics of a blown-out oil well. SPE 9257, Annual Fall Meeting of the Society of Petroleum Engineers, Dallas, Texas, September 21-24, 6 PP. Constant, W.D. and Bourgoyne, A.T., 1988. Fracture-gradient prediction for offshore wells. SPE Drilling Eng., June, pp. 136-140. Craft, B.C. and Hawkins, M.F., 1959. Applied Petroleum Reservoir Engineering. Prentice-Hall, Englewood Cliffs, N.J. Crouch, E.C. and Pack, K.J., 1980. ‘Systems analysis’ use for the design and evaluation of high rate gas wells. SPE 9422, Annual Fall Meeting of the Society of Petroleum Engineers, Dallas, Texas, September 21-24,4 pp. Uodson, C.R. and Standing, M.B., 1944. Pressure-volume-temperature and solubility relations for natural gas-water mixtures. Drilling and Production Practice, API, p. 173. Erb, P.R., Ma, T.C. and Stockinger, M.P., 1983. Riser collapse - a unique problem in deep-water drilling. IADCISPE 11394, Drilling Conference, New Orleans, La., February 20-23, pp. 307-312. Finnie, I., 1960. Erosion of surfaces by solid particles. Wear, 3: 87-103. Forchheimer, P., 1901. Wasserbewegung durch Boden. Z. Ver: Dtsch. Ing., 45: 1731. Goodwin, J.E., Sage, W. and Tilly, G.P., 1969. Proceedings of the Institute of Mechanical Engineers, Vol. 184. ASME, New York, N.Y., pp. 279-292. Hall, J.G., Roche, J. and Boulet, C.H., 1986. Means for handling gas influx in marine risers. SPEIIADC 14739, Drilling Conference, New Orleans, La., February, pp. 173-176. Ives, L.K. and Ruff, A.W., 1978. Wear, 46: 149-162. Johnson, TW. and Taliaferro, D.B., 1938. Flow of air and natural gas through porous media. USBM Tech. Pap., 592. Koederitz, W.L., Beck, F.E., Langlinais, J.P. and Bourgoyne, A.T., 1987. Methods for determining the feasibility of dynamic kills for shallow gas flows. SPE 16691, Annual Fall Meeting of the Society of Perroleum Engineers, Dallas, Tcxas, September. Moody, L.F., 1944. Friction factors for pipe flow. Trans. ASME, 66: 671. Prior, D.B., Doyle, E.H. and Kaluza, M.J., 1989. Evidence for sediment eruption on deep sea floor, Gulf of Mexico. Science, 243: 517-519.

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317

Roche, J., 1986. Diverter improvements help handle shallow gas kicks safely. Oil Gas J., 84 (6): 60-65. Ross, N.C.J., 1960. An analysis of critical simultaneous gas-liquid flow through a restriction and its application to flow metering. Appl. Sci. Res., 9: 374. Santos, 0. and Bourgoyne, A.T, 1989. Estimation of peak pressures occurring when diverting shallow gas. SPE 19559, Annual Fall Meeting of Society of Petroleum Engineers, San Antonio, Texas, October 1-8. Tolle, G.C. and Greenwood, D.R., 1977. Design of fittings to reduce wear caused by sand erosion. American Petroleum Institute OSAPR Project No. 6, Texas A&M, College Station, Texas, May.

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Studier in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 0 1994 Elsevier Science B.V.All rights reserved

319

Chapter 11 RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS ROBERT DESBRANDES

11.1. INTRODUCTION

When formation pore pressure is underestimated and significantly exceeds the hydrostatic pressure exerted by the wellbore fluid, formation fluids start flowing into the borehole resulting in a “kick”. Most of the time such a kick is not severe and the well can be controlled. If a large kick occurs and the wellsite personnel and equipment are not fully prepared for it, the well blows out and frequently catches fire. Shallow blowouts, which occur as results of small gas pockets, usually cease as soon as the formation pressure is depleted or the well bridges, usually after a relatively short period. Deep blowouts may last for years and produce an enormous quantity of fluid if no attempt is made to control them. The most efficient way to control a blowout is to drill one or several relief wells which will reach the “wild” or uncontrolled well, above or at the producing problem formation. Fluid will then be injected to kill it. Surveys of Gulf Coast blowouts over the last twenty years have been made by Podio et al. (1983a, b) and Hughes et al. (1987). This chapter provides a brief discussion of the following considerations: flowrate estimates, control techniques, trajectory planning, relief well directional surveying, and distance ranging techniques. Several examples of typical blowouts related to overpressure will be presented.

11.2. BLOWOUT FLOWRATE

A well out of control discharges large amounts of hydrocarbons, usually gas. Estimates of the flowrate and downhole pressure are necessary to plan the control operations because metering devices cannot be installed. Calculations are made by crossplotting the formation resistance and the flow-string resistance (Hawkins et al., 1981).

11.2.1. Formation resistance Unless the reservoir is well known, the calculation procedures are based on a simple radial flow geometry. The reservoir is assumed circular of constant thickness. The volume of gas computed for a steady-state flow is given in practical metric units by:

320

R. DESBRANDES

(11-1)

where Qs, = volume of gas produced at standard conditions (1 atm and 15°C) in m3/d; k = reservoir permeability in pm2; h = reservoir thickness in m; Pe = reservoir pressure at radius re in kPa; P, = wellbore pressure at radius r, in kPa; p = average viscosity in mPa s; T = reservoir temperature in K Z = average gas deviation factor; and re/rw = ratio of external drainage radius to wellbore radius. In customary units: (11-la) where Qsc = volume of gas produced at standard conditions (14.7 psi and 60°F) in scf/d; k = reservoir permeability in D; h = reservoir thickness in ft; f e = reservoir pressure at radius re in psia; P, = wellbore pressure at radius r, in psia; p = average viscosity in cP; T = reservoir temperature in OR;Z = average gas deviation factor; and re/rw = ratio of external drainage radius to wellbore radius. The calculation is made for various values of P, resulting in a curve of the gas flowrate versus P, as shown schematically in Fig. 11-1. Transient flowrate calculation can be made at different times assuming that the pressure perturbation radius increases according to the following formula in practical metric units (Lee, 1982):

::/

re = 0.584 -

(11-2)

where re = perturbation radius in m; TR = time in days; p = average gas viscosity in mPa s; k = permeability in pm2; c = gas compressibility in kPa-'; and 4 = M Pa

0

20

30

BOTTOM HOLE P R E S S U R E , 1000 P S l A

Fig. 1 1 - 1 . Typical formation and flow string resistance curves. The flowrate and bottomhole pressure are read at the intersection of the two curves (after Hawkins et al., 1980).

321

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS M Po

0

100

I0

20

30 25

0

2

80

0

20

0

60

e

15% W

2

(D

0

40

IC

(L

3

9LL

20

5

I 2 3 4 5 BOTTOM HOLE P R E S S U R E , 1000 P S l A

0

Fig. 11-2.m i c a 1 transient formation resistance curves. The formation resistance curves vary with time as the pressure perturbation progresses toward the edge of the reservoir (after Hawkins et al., 1980).

formation porosity in fraction. In customary units: I

(11-2a) where re = perturbation radius in ft; TR = time in days; p = average gas velocity in cP; k = permeability in D; c = gas compressibility in psi-'; and = formation porosity in fraction. By using re in eq. 11-1 the flowrate can be calculated at different times for various wellbore pressures, as shown in Fig. 11-2. When the perturbation has reached the edge of the reservoir, an average reservoir pressure based on a material balance calculation must be used to compute the flowrate for a given bottomhole well pressure.

11.2.2. Flow-string resktance For a flowing gas well, the bottomhole well pressure is given in S.I. units by:

where Pw = bottomhole pressure in Pa; P, = surface pressure in Pa; p = gas density in kg/m3; z = elevation above reference level in m; Pf = pressure loss due to friction in Pa; v = velocity of gas in m/s; and g = acceleration due to gravity in m/s2. In customary units: (11-3a)

322

R. DESBRANDES

where P, = bottomhole pressure in psia; P, = surface pressure in psia; p = gas density in lbs/ft3; z = elevation above reference level in ft; Pf = pressure loss due to friction in psia; v = velocity of gas in ft/s; and g = acceleration due to gravity in ft/s2. The first integral term in eq. 11-3 accounts for the change in pressure due to potential energy along the flow path. The second is the change in pressure over the flow path due to friction. The third accounts for the change in pressure due to change in kinetic energy along the flow path. With the use of modern computers numerical integration of the basic terms in the general eq. 11-3 can be easily accomplished. The surface pressure must be estimated first. At the subsonic flow the exit pressure will be atmospheric. If the flow is sonic the pressure will be greater than atmospheric. A sample calculation is given by Hawkins et al. (1980). The case of two-phase flow, gas-condensate and oil, must be considered (Hawkins et al., 1981). A pressure less than the bubble point pressure may be reached in the reservoir; in that case, an empirical formula must be used. Flow-string resistance for simultaneous oil, gas, and water flow can be estimated using one of the numerous correlations available for that purpose (Brill and Beggs, 1978). For example, the Poettmann and Carpenter (1952) correlation considers one flow regime and no slip, i.e., liquid and gas are traveling up the well at the same velocity. The Hagedorn and Brown (1965) correlation accounts for both slip and multiple flow regimes. Typical flow regimes are bubble flow, slug flow, transition flow, and mist flow. A recent work (Reinicke et al., 1987) shows that the Hagedorn and Brown correlation gives the best results although the correlation is less sophisticated than the others. The downhole well pressure is then computed for various flowrates. 11.2.3. Crossplots

When the formation resistance and flow-string resistance curves are plotted on the same graph, the intersections give both the probable flowrate and the downhole pressure. Figures 11-1and 11-2 are typical crossplots for gas blowouts. Figure 11-3 shows a typical crossplot for two-phase flow conditions. If the permeability is not known, then several values may have to be used to get a range of possible well pressures and flowrates. These figures illustrate the large differences that may be encountered when using the various correlations in two-phase flow.

11.3. BLOWOUT CONTROL

A review of relief well kill procedures was carried out by Flak and Goins (1984). Four techniques are described: water flooding kills, dynamic kills, overbalance kills, and high-rate production kills. 11.3.1. Waterflooding kills

One technique used especially in high-permeability formations (>500 mD) consists of (i) prekilling the blowout by flooding the formation with water; (ii) when

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

323

FLOW RATE ( x 1000 STBO / D A Y

Fig. 11-3. Example of crossplot of formation and flowstring resistance in two-phase flow. The various correlations provide different solutions. The Hagedorn and Brown correlation gives the best results (after Hawkins et al., 1981).

the blowout is producing 100% water, injecting mud by fracturing the formation, thus terminating the kill operation. This technique was used successfully by Shell during the 1970-1971 Bay Marchand fire (Miller and Clements, 1972). The injection operation was simulated with a simple computer model based on Darcy's law for radial flow of an incompressible fluid. According to the results of this simulation, it is important not to fracture the formation during the flooding phase since such a fracturation would create a direct path to the blowout well, making the kill operation impossible (Lehner and Williamson, 1974). One concern in the Bay Marchand case was the high overbalance pressure required during drilling and cementing the blowout zone in the relief well. Actually, this high overbalance pressure did not cause problems. Hence the conclusions are: (i) since a large overbalance is generally permissible, circulation cannot be lost in the relief well unless it intersects the blowout well; (ii) the flow of water from the relief well is basically radial; (iii) at breakthrough, high production rates will cause the oil to cusp into the side opposite the blowout for an appreciable period; (iv) mud fracturation is required as a final step to create a direct path to the "wild" well and control abnormal formation pressures. Of the eleven wells on fire in Bay Marchand, eight were controlled without significant problems, two with great difficulty, and one had to be controlled by surface operations. The success of the technique is highly dependent on the distance between the blowout well and relief well, which should be less than 18 ft (5.5 m). Other factors, including permeability barriers, anisotropy, and too large an injection

324

R. DESBRANDES

thickness, may prevent a successful kill. In addition to this particular example, this method has been used successfully for other blowouts (Barnett, 1977). 11.3.2. Dynamic kills

The dynamic kill technique involves killing a well by injecting a fluid through a communication link and up the blowout annulus at such a rate that the static formation pressure is exceeded and the formation stops producing (Blount and Soelinah, 1981). Multiphase flow occurs during the kill and single phase immediately after. The flowrate must be maintained such that the sum of the frictional and hydrostatic pressures exceeds the static formation pressure until a heavier kill mud can replace the lighter dynamic kill fluid. Figure 11-4 shows the principle of dynamic kill. In the relief well, the downhole pressure must be monitored and maintained at about formation pressure. A small tubing full of water is used for monitoring the pressure. The annulus of the relief well is used for injection. Figure 11-5 shows the typical variation of the formation gas production versus the flowing bottomhole

-

P l w = BHP Waterhead + PI NoControl Pan = EHP - Ph,d. PI (WHP = 0)

Q Relief Well Annulus

-

-3STubing

-Static water

-.

Blowout

Well

(58.62 MPa) 85Oopsi

Relief valve

Positive choke

-1

BHP = WHP +

/ Pn,, +PI

1 7,100 ( 4 9 . 9 6 M P a ) PSI Reservoir

Fig. 11-4.Principle of dynamic kill. The high water Rowrate injected in the blowout generates a pressure loss sufficient to kill it. The relief valve in the figure represents the formation fracturation pressure not to be surpassed (after Blount and Soelinah, 1981).

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

325

MPa

FLOWING BOTTOMHOLE P R E S S U R E ( p s i x 103)

Fig. 11-5. String and formation resistance curves for a dynamic kill. The two-phase string resistance shows a minimum pressure as the gas flowrate increases for a constant water injection.

pressure for various water injection flowrates. In this case a water flowrate of 80 barrels per minute (0.212 m3/s) will be sufficient to kill the well and, with zero gas flowrate, the water injection rate can be cut back to 70 bbl/min (0.185 m3/s). In contrast to the water-flooding technique, the communication link used in the dynamic kill is produced by fracturing and “acid worming”. Acid worming is achieved by injecting hydrochloric acid into limestone formations. The two wells must be as close as possible to provide the least pressure drop in the link. This technique can also be used to control a cased blowout by targeting the relief well to contact the wild well and establishing the link by jet perforating. Several blowouts have been killed successfully using dynamic kill (Wiryodiarjo et al., 1982). 11.3.3. Overbalance kills

Overbalance kill is the procedure that most relief well kill attempts have followed in the past. A communication is established by fracturing the formation with a light fluid. Subsequently, a fluid of sufficient density to control (overbalance) the reservoir pressure is pumped into the blowout at a rate high enough to overcome the reservoir flow; then cement is pumped into the well to complete the kill. The major difficulty is injecting the dense fluid at a high enough rate without fracturing the formation around the relief well and losing the mud. This technique is essentially a crude dynamic kill. The modern dynamic kill approach has many advantages over the overbalance kill.

326

R. DESBRANDES

11.3.4. High-rateproduction kills

If salt water is produced with the oil or gas in the wild well, it may be possible to complete the relief well in the blowout formation and produce it at a very high rate, developing a low-pressure zone that intercepts the blowout formation and draws salt water by coning. In this case, the blowout will kill itself by failing to lift the salt water. This technique has reportedly been used successfully (Flak and Goins, 1984). 11.3.5. Polymer kills Polymer injection has been attempted with success to control the leakoff into the formation and to focus the kill fluid toward the blowout. This technique only works in high-permeability, fractured, or vuggy-type formations. Since blowouts occur most often in these types of formations (Ely and Holditch, 1987), this technique is widely used.

11.4. DIRECTIONAL PLANNING AND TRAJECTORY DESIGN

Relief wells are normally spudded upwind and at a secure distance from the blowout, which means that the horizontal departure to the target well will be 1500 to 3000 ft (460-915 m). Four major types of wellbore trajectories, shown schematically in Fig. 11-6, can be selected: continuous-build, build-and-hold, build-

‘s’ PIPE)

Fig. 11-6. Major types of wellbore trajectories. The most common trajectory is “build-hold-and-drop,” especially when the casing must be contacted (after Bourgoyne et al., 1986).

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

327

hold-drop-and-hold (modified “S”), build-hold-and-drop (“S” type) (Bourgoyne et al., 1986, p. 351). The preferred trajectory is the build-hold-and-drop type. Unless the blowout trajectory is known, a first build-and-hold relief well is drilled to go past the blowout. The distance and orientation of the blowout is determined at the nearest point. After plugging back, a sidetrack is drilled from the drop portion of the relief well. Often several sidetracks are necessary, especially if a contact or mill-through is required (Grace, 1985).

11.5. DIRECTIONAL SURVEYING

Directional surveying includes directional measurements, trajectory calculation and accuracy estimates. Directional measurements include: single shots and multishots, steering tools and MWD (measurement-while-drilling),and north seekers. The progress in this area over the last few years is mainly due to the use of advanced sensors and computers. 11.5.1. Single shots and multishots Devices for measuring the inclination and orientation of the borehole, which take downhole photographs of a pendulum and of the face of a magnetic compass or gyroscope, were exclusively used before 1970. They are still used today due to their low cost. Non-magnetic drill collars are required for the magnetic measurements. The single-shot instrument takes one photograph (shot) either for inclination control in regular drilling operations or for orienting the bottomhole assembly during directional drilling. The multishot can take up to 1000 photographs while the drill string is being pulled out (Bourgoyne et al., 1986, p. 377). The gyroscope data require a tedious and complex interpretation. To alleviate this difficulty, computerized gyroscopes, operated on electric wireline, can supply on-the-spot directional data and trajectory calculations (Guillory, 1978). 11.5.2. Steering tools and MWD

Steering tools and MWD techniques use the same type of instrument package. Three servo-controlled accelerometers are used to measure the inclination of the well, and three single-axis magnetometers are used to measure the earth’s magnetic field orientation (Russell, 1970). The six data measured are used in a computer program to determine the inclination, the orientation with respect to magnetic north, the tool face if a bent sub is used, and the possible magnetic perturbations, especially drill collar perturbations (Russell and Russell, 1979; Grinrod and Wolff, 1983). The measurements are usually carried out during drilling. Multishot-type devices using accelerometer/magnetometer packages and digital recording are now available to replace the conventional multishots (Gust, 1986).

328

R. DESBRANDES

11.5.3. North seekers Rate gyroscopes are instruments that measure the rate of absolute rotation around a sensitive axis. In the borehole they detect the earth’s rotation vector and, consequently, are immune to any magnetic perturbation. Two systems are presently used: single-axis gyroscopes rotated slowly, and two- or three-axis stationary gyroscopes (strapped down) to determine the earth’s rotation vector. In both instances the housing of the instrument must be perfectly still in the borehole while station measurements are made. As the platform containing the single-axis gyro rotates slowly along the borehole axis, the gyro will sense the maximum signal when its sensitive axis is lined up with the geographic north. An accelerometer mounted on the same platform will sense the maximum signal when its sensitive axis is in the vertical plane. The borehole orientation can then be calculated from the phase difference between the two signals (Wright, 1983). In a three-axis gyroscope system, each sensitive axis measures one rotation component. The three components can be used to define a vector, the earth’s rotation vector, located in the north vertical plane. This vector can be used in lieu of the magnetic field vector in a steering tool or MWD computer-type program if accelerometer measurements are available (Gibbons and Hense, 1987). It should be noted that each measurement is made with respect to geographic north with no perturbation possible. Other gyroscope-type measurements can be made using inertial platforms. One of these uses a two-axis gyroscope and a two-axis accelerometer (Camden et al., 1981), the other is a regular aircraft platform (Morgan, 1979). This second instrument makes displacement measurements in 3-D and defines the trajectory without using inclination, azimuth, or well depth. 11.5.4. Trajectory calculation

Many algorithms are used for trajectory calculation. The three most common are: the tangential method, the average angle method, and the minimum curvature method (Bourgoyne et al., 1986, p. 362). In the tangential method it is assumed that for each survey station, inclination and orientation angles remain constant over the preceding course length. The corresponding horizontal departures and true vertical depth are readily calculated. A summation leads to the total north/south and east/west coordinates as well as total vertical depth. The average angle method is similar, but the angles considered are the average values of the angles measured at the beginning and at the end of a course length increment. This method eliminates part of the sizeable error caused by not considering the previous inclination and direction. The minimum curvature method uses the angles at both ends of the increment and assumes a curved wellbore tangent to the vectors defined by the inclination angles at each end. This method is one of the most accurate. Many other methods

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

329

have been used commonly but with only a minimal accuracy improvement. The accuracy depends also on the distance, which should not exceed 100 ft (30 m), between survey points. Since the best possible accuracy is required for a successful relief well operation the minimum curvature method should be used. 11.5.5. Accuracy models

Since the relief well must sometimes physically intersect the blowout, trajectory accuracy is very important in relief well engineering. Two approaches are currently in use: the probability model, and the systematic error model. The probability model is based on the assumption that inclination and azimuth angle errors are uniformly distributed between two limits. Furthermore, there is no correlation between the errors recorded at different stations (Walstrom et al., 1969). With this model the uncertainty ellipses can be calculated to define a numerical probability of the hole being located at a certain distance from the calculated position. Figure 11-7 shows the ellipses for a highly deviated hole at a total depth of 5400 ft (1646 m). The same results can be obtained by adding an algorithm of Monte Carlo simulation of error to the station data. The ellipses can be defined by running the trajectory calculation many times. The small dimension of the ellipse for 0.999 certitude is striking and does cast some doubt on the method.

rn

- 740 2420:

4a

C

E

2400:

-730 2380

2360

{

720

Fig. 11-7. Ellipses of uncertainty of bottomhole position for a 5400-ft borehole. The calculated position is at the center of the ellipses. The probability of the true position is indicated for each ellipse (after Walstrom et al., 1969).

330

R. DESBRANDES 300

I

w-

1 I-

a

J W

K

I 0

,

,

,

I

I

I

I

,

]

30 40 50 60 7 0 00 90 A V E R A G E HOLE INCLINATION ( Degrees 1 10 20

Fig. 11-8. Spical lateral position uncertainties of magnetic and gyroscopic surveys. A “good” gyroscope survey is better than a “good” magnetic survey for deviations less than 70”; above that point, the magnetic survey is better (after Wolff and de Wardt, 1981).

The systematic error model (Wolff and de Wardt, 1981) suggests that the errors in a particular survey are systematic and leads to a total error larger by a factor of f i than the Walstrom model error (n being the number of stations). Taking into account the typical error values for good or poor surveys, Wolff and de Wardt (1981) computed the lateral position uncertainty shown in Fig. 11-8. They also define radial and vertical uncertainties that are smaller for the same set of directional data. This worhpplies to multishot-type measurements. For the accelerometer-magnetometer or rate-gyroscope type of measurements, a new method has been proposed recently that takes into account errors in the raw vector component data (Holmes, 1987). The method is based on the observation that, although errors exhibit a Gaussian distribution, they are also highly correlated from one survey station to the next. Limited results are currently available.

11.6. BLOWOUT WELL DISTANCE FROM RELIEF WELL

Frequently, when a well is out of control, no directional data are available. Consequently, the bottomhole position is not known, and, even with state-of-the-art directional measurements in the relief well, ranging techniques are necessary to locate the wild well. With steel in the borehole, drill pipes and/or casing, three

331

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

methods are applicable: electrical, active electromagnetic, and passive electromagnetic. For a “clean” borehole (i.e., metal-free) only acoustic noise recording is currently available. 11.6.1. Electrical method

The electrical method uses the Ultra-Long Spaced Electric Log (ULSEL) technique (Runge et al., 1969) and was originally designed to detect and map the profile of salt domes and other large resistive anomalies. Here the technique is used for detecting conductive casings. Basically, the electric sonde is a very long “normal”, with the typical electrode arrangement on the insulating bridle being A-75’-M175’-M2-200’-N-350’ cable armor (A-22.86 m-MI-22.86 m-M2-60.96 m-N-106.68 m cable armor) (Haanschoten, 1977a, b). This arrangement is labeled 75/350 or 150/350in the literature. In order to calculate the expected resistivity in an infinite tabular formation, measurements made with short-spacing resistivity sondes are necessary. The resistivity measured with the ULSEL spacings is then compared with the expected resistivity. When a conductive casing is in the vicinity, the ULSEL-measured resistivity is a function of the distance of the casing, approach angle, resistivity values and casing size. Charts have been calculated for various conditions (Mitchell et al., 1972). Figure 11-9 shows typical curves for 75- and 150-ft (22.86 and 45.73 m) “normal” resistivity measurements. A field example of ULSEL resistivity measurements is presented in Fig. 11-10. The distance has been determined using the resistivity ratio and the response curve “150/350 normal” shown in Fig. 11-9. Although this analysis does not give the direction of the blowout casing with respect to the relief well, the technique has been widely used with success for distance determination. m 10

5

0 l.Or

15

20

I

I

I

25

I

30

11

I

BASIS I. FORMATION RESIST.6 Om (HORIZ.)

2. RESIST. VERT./HORIZ. = 1.5 3. VERTICAL ANGLE = 4 DEGREES

4

I I

I

1

I

I

1

1

I

i

Fig. 11-9. Response of ULSEL devices in proximity to a 7” casing. The curves cross over at 13 ft (4 m). The shape and position of the curves depend on formation resistivity, anisotropy and relative angle between relief and blowout wells (after Robinson and Vogiatzis, 1972).

332

R. DESBRANDES R E S I S T I V I T Y , Ohm- meters

0 2720

10 20

d (ft.) 30 40 50 60

I

2730

-L

I 2740

+ a W

n 2750

2760 L

0

5

10

15

2

d (ml Fig. 11-10, Example of an ULSEL survey near a casing and its interpretation. The expected values have been computed from a deep investigation resistivity log to average for the various resistivities of the strata included in the long spacing. The distance is computed with the data of Fig. 11-9.

11.6.2. Active electromagnetic method This method is similar to the electrical method but the alternating magnetic field generated by the current flowing in the casing is measured instead of the electric potential. Figure 11-11 shows the current emitted by electrode A. The magnetometer, located in M at 300 ft (91.44 m) below the current electrode in the relief well, measures the magnetic field induced by the casing current (West et al., 1983). The intensity of the field is related to the distance between the blowout and the relief well. The direction given by the three magnetic components is at 90" from the blowout direction according to the Biot-Savart law. Amplitude measurements are shown in Fig. 11-12. The technique has been used with success to intersect a blowout at 16,053 ft (4893 m) (Grace, 1985).

11.6.3. Passive magnetic method Due to inspection and manufacturing processes, the casing is usually magnetized. A typical magnetization pattern is shown in Fig. 11-13 (Robinson and Vogiatzis, 1972). A sonde equipped with four magnetometers has been built for detecting the magnetism of the casing up to 100 ft (30.5 m) away in the presence of the earth's magnetic field (Morris and Costa, 1977; Morris et al., 1978). A vertical gradient, which is a function of distance and independent of the earth's magnetic field, is measured. Radial measurements of two magnetic components at 90°, when stripped of the earth's magnetic field, give the direction of the blowout. Figure 11-14 is a sketch

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

333

S U R FA C E

-BLOWOUT

)”: c

-

L

c

c

- IWNI RRELI ELINE EF

WELL

WELL

c

-d CURRENT FLOW IN PIPE

I

1 \

f

c

/

CURRENT EMITTED INTO THE GROUND

M

Z Fig. 11-11. Current flow in the casing of blowout well due to the current emitted by an electrode. The current flow in the casing is nu1 at the electrode depth and increases then decreases as more current is emitted than received by the casing. The current pattern is symmetrical both upward and downward (after West et al., 1983).

of the Magrange I1 logging tool (Desbrandes, 1985, p. 453). The illustration of a typical recording of the vertical gradient shown in Fig. 11-15, indicates a dipole and a monopole and includes a schematic interpretation (Morris and Costa, 1977; Morris et al., 1978). The passive magnetic technique has been used widely with good results.

11.6.4. “Clean” borehole methods In a “clean” borehole (one containing no steel), magnetic or electrical techniques cannot be used. Acoustic noise measurements are the sole possibility. A sensitive microphone is lowered into the borehole and the frequency spectrum of the noise is recorded at various depths (McKinley et al., 1973; Britt, 1976). Maximum amplitudes are recorded at the nearest point to the blowout well. No published information relates the application of this measurement to blowout well distance ranging although this technique has been used. An estimate of the noise source

334

R. DESBRANDES

2200 Legend

*

Run 1 Run2. o Run 3 - 0

a a

g

600j

$

300

:*.

z

1i J

g o

I

200-

2

v,

100

7500

7000

8000 8500 9000 ALONG HOLE DEPTH, Ft

9500

10000

Fig. 11-12. Field data showing the alternating magnetic field intensity near a casing. With this data the distance and the direction of the casing of the blowout well can be calculated (after West et al., 1983).

COLLA(I END

a

THREAD E N 0

RADIAL M A G N E T I C FIELD AT

3/Ain , G A U S S

Fig. 11-13. A typical example of the radial magnetic field exterior to a long casing joint: (a) schematic form; (b) intensity 3/4" away from the casing. Magnetization will differ from casing to casing according to the manufacturing, handling, and inspection procedures (after Robinson and Vogiatzis, 1972).

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

335

magnetometer

I Fig. 11-14. Schematic diagram of the Magrange I1 logging tool. The sketch shows the two axial magnetometers to measure the field axial gradient and the two radial magnetometers to determine the direction of the blowout well with respect to the relief well (after Desbrandes, 1985).

intensity can be made if the flowrate in the blowout well is known. According to R.M.McKinley (pers. commun., 1987) and E.L. Britt (pers. commun., 1987) the amplitude decreases approximately with the square of the distance up to 100 ft (30.5 m); thus, the distance, but not the direction, can be estimated. Acoustic noise logs are also used for making sure that the wild well is definitely killed and that no underground flow is persisting (Bruist, 1972). Until new technologies become available only cased wells or wells containing drill strings can be located with certainty.

11.7. BLOWOUT EXAMPLES

11.7.1. Cox et al. No. 1

Cox et al. No. 1, an exploratory well, near Jackson, Mississippi, blew out at 21,122 ft (6438 m) in the Smackover on March 25, 1970 while a trip out of the hole with a core was being made (Bruist, 1972). Cox No. 2 was spudded and planned with a

a

-

1,500

w w

G?

~

I.SS0

a.

W W

e

I

Blowout well

1

I

1,610

1,700

,.

'

'

P 1,740

,

Fig. 11-15. Magnetic axial gradient measurement in a rclicf well. (a) Recorded vcrtical magnetic gradient (after Morris e t al., 1978;courtcsy of Oi! and Gus Journal). (b) Schematic interpretation (after Dcsbrandes, 19851. This is the typical axial gradient rccorded near a magnetic dipole in the lower part and near B magnetic monopole in the upper part.

U

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

337

21.112’ (6.438rn)

Fig. 11-16. Diagram of the proposed relief wells to kill Cox No. 1. Cox No. 4 reached its target first and was used to kill Cox No. 1 (after Bruist, 1972; courtesy of Journal of Petroleum Technology).

“build-and-hold” trajectory to intersect the blowing well at the bottom. A second well, Cox No. 4, was also spudded to intersect Cox No. 1 at 10,000 ft (3048 m), as shown in Fig. 11-16. This last well reached its target first and was directed to contact the wild well casing with the ULSEL technique and magnetostatic measurements. Two sidetracks were necessary. Interwell communication was established at 10,550 ft (3216 m) by jet-perforating, and the well was killed with a heavy cement slurry. The kill was confirmed with a noise-temperature survey. 11.7.2. Bergeron No. 1

R.L. Bergeron No. 1 was being drilled in the Tuscaloosa Trend near Baton Rouge, La., when it blew out at 18,562 ft (5658 m) (Warren, 1981). The relief well, Bergeron No. 2, was planned as shown in Fig. 11-17. The Bergeron No. 1trajectory was known within a 32 ft (9.75 m) radius. Then Bergeron No. 1 bridged and died. A noise survey was run in Bergeron No. 2 to make sure that no underground flow was taking place.

338

R. DESBRANDES

I' 4

-DRILL STRING

Fig. 11-17. Schematic of relief well Bergeron No. 2 with the detail of the casing design. Contact was established as shown, but Bergeron No. 1 bridged and died before a communication could be attempted. A noise survey run in Bergeron No. 2 indicated that no flow was taking place (after Warren, 1981; courtcsy of Journal of Petroleum Technology).

11.7.3. Arun Field well No. CII-2

Well No. CII-2 in Indonesia's Arun Field blew out during drilling operations at 9650 ft (2941 m) on June 4, 1978 (Blount and Soelinah, 1981). Two relief wells were spudded as shown in Fig. 11-18 (Leonard, 1979). Relief well CII-8 reached the formation first. Accurate directional data and magnetostatic surveys indicated that the wells were less than 50 ft (15.24 m) apart. A communication link was produced by acid worming and fracturing. The dynamic kill technique was used to control the wild well with 85 bbl/min (0.225 m3/s) of water, followed by intermediate mud of 14.5 ppg (1737 kg/m3) at 30 bbl/min (0.079 m3/s). Finally, a 16.5 ppg (1977 kg/m3) mud was injected to complete the kill.

RELIEF WELL ENGINEERING TO CONTROL BLOWOUTS

339

/*

/

1 Fig. 11-18. Schematic diagram of the two relief wells spudded to kill well Arun (211-2. CII-8 reached its target first, less than 60 ft (18.3 m) away from (211-2. A dynamic kill was used to control CII-2 after a communication was established (after Leonard, 1979; courtesy of Oil and Gas Journal).

11.8. CONCLUSIONS

Relief well drilling is mandatory when a deep blowout occurs since there is no guarantee that the well will bridge and the blowout will die. Even if bridging does occur, an underground blowout may still be in progress. In any well, a reliable borehole trajectory survey should be made when highpressure zones are suspected and a blowout is possible. This strategy prevents long and costly ranging operation to locate the blowout well. Measurement-while-drilling (MWD) techniques provide excellent trajectory control of the relief well, allowing the target to be reached precisely and efficiently. Today’s ranging technology defines the distance and direction of the blowout with an accuracy that permits casing contact if necessary. However, ranging problems still persist when the borehole does not contain magnetic material. Several kill techniques have been developed and applied with success. In several of these applications, the blowout well was salvaged. Acoustic noise logs are often used as final confirmation that the blowout well has been definitively killed.

340

R. DESBRANDES

REFERENCES Barnett, R.D., 1977. A logical approach to killing an offshore blowout: West Cameron 165, Well No. 3, Offshore Louisiana. SPE 6903, SOC.Pet. Eng. Annu. Fall Meet., Denver, Colo., October 9-12. Beggs, H.D. and Brill, J.P., 1973. A study of two-phase flow in inclined pipes. J. Pet. Technol., 25 (4): 607-617. Blount, E.M. and Soelinah, E., 1981. Dynamic kill: controlling wild wells a new way. World Oil, 193 (5): 109-126. Bourgoyne, A.T., Jr., Millheim, K.K., Chenevert, M.E. and Young, ES., Jr., 1986. Applied Drilling Engineering. SPE Tatbook Series, Vol. 2. Richardson, Texas, 502 pp. Brill, J.P. and Beggs, H.D., 1978. Two-phase Flow in Pipes. University of W s a , 'hlsa, Okla., 480 pp. Britt, E.L., 1976. Theory and application of the borehole audio tracer survey. Paper BB, SOC.Prof: Well Log Analysts Symp., Denver, Colo., June 9-12. Bruist, E.H., 1972. A new approach in relief well drilling. J. Pet. Technol., 24 (6): 713-722. Camden, D.J., Gartner, J.E. and Moulin, P.A., 1981. A new continuous guidance tool used for high accuracy directional survey. SPE 10057, SOC.Pet. Eng. Annu. Fall Meet., San Antonio, Texas, October 5-7. Desbrandes, R., 1985. Encyclopedia of Well Logging. Gulf Publishing, Houston, Texas, 584 pp. Ely, J.W. and Holditch, S.A., 1987. Conventional and unconventional kill techniques for wild wells. SPE 16674, SOC. Pet. Eng. Annu. Fall Meet., Dallas, Texas, September 27-30. Flak, L. and Goins, W.C., 1984. New techniques, equipment improve relief well success. World Oil, 198(1): 113-118. Gibbons, EL. and Hense, U., 1987. A three-axis laser gyro system for borehole wireline surveying. SPE 16679, SOC. Pet. Eng. Annu. Fall Meef.,Dallas, Texas, September 27-30. Grace, R.D., 1985. Case history of Texas' largest blowout shows successful techniques on deepest relief well. Oil Gas L , 83 (20): 68-76. Grinrod, S.J. and Wolff, J.M., 1983. Calculation of NMDC length required for various latitudes developed from field measurements of drill string magnetization. IADCISPE 11382, MDC/SPE Drill. Conf., New Orleans, La., February 20-23. Guillory, C., Jr., 1978. Surface recording gyroscope system saves rigtime. Oil Gas J., 76(19): 186-192. Gust, D.A., 1986. An evaluation of survey accuracy at Cold Lake. Paper 86-37-06, Pet. SOC. of CIM, 37th Annu. Tech. Meet., Calgary, Aka., June 8-11, pp. 75-84. Haanschoten, G.W., 1977a. Logging tool offers greater depth of investigation for relief well. Oil Gas J., 75 (2): 70-74. Haanschoten, G.W., 1977b. Ulscl system performs on Brunei blowout under tough conditions. Oil Gas J., 75 (3): 77-79. Hagedorn, A.R. and Brown, K.E., 1965. Experimental study of pressure gradients occurring during continuous two-phase flow in small diameter vertical conduits. J. Pet. Technol., 17 (4): 475-484. Hawkins, M.F., Bassiouni, Z., Bernard, W.J., Bourgoyne, A.T, Jr., Veasey, M.J. and Whitehead, W.R., 1980. Methods for Determining Vented Volumes During Gas Well Blowouts. Document DOE/ BETC/2215-1, US.Department of Energy, NTIS, U.S. Department of Commerce, Springfield, Va., October, 95 pp. Hawkins, M.F., Bassiouni, Z., Bernard, W.J., Bourgoyne, A.T., Jr., McMullan, J.H., Veasey, M.J. and Whitchead, W.R., 1981. Methods for Determining Vented Volumes During Gas-Condensate and Oil Well Blowouts. Document DOE/BETC-3000-1 (DE81030779), U.S. Department of Energy, NTIS, U S . Department of Commcrce, Springfield, Va., September, 36 pp. Holmcs, A,, 1987. A method to analyze directional surveying accuracy. SPE 16680, SOC.Pet. Eng. Annu. Fall Meet., Dallas, Tcxas, September 27-30. Hughes, V.M., Podio, A.L. and Sepehrnoori, K., 1987. A computer assisted analysis of trends among Gulf Coast blowouts. SPEIIADC 16127, IADC Drill. Conf, New Orleans, La., March 15-18. Lee, J . , 1982. Well Testing. Society of Petroleum Engineers, New York, N.Y. Lehner, F, and Williamson, AS., 1974. Gas-blowout control by water injection through relief wells: a thcorctical analysis. SOC.Pet. Eng. J., 14(4): 321-329. Leonard, J.E., 1979. Single relief well kills Arun blowout. Otl GasJ., 77(2): 73-76.

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341

McKinley, R.M., Bower, EM. and Rumble, R.C., 1973. The structure and interpretation of noise from flow behind cemented casing. J. Pet. Technol., 25 (3): 329-338. Miller, R.T and Clements, R.L., 1972. Reservoir engineering techniques used to predict blowout control during the Bay Marchand fire. J. Pet. Technol., 24(3): 234-240. Mitchell, ER., Robinson, J.D., Vogiatzis. J.P., Pehoushek, F., Moran, J.M., Auburn, B.E. and Berry, L.N., 1972. Using resistivity measurements to determine the distance between wells. 1.Pet. Technol., 24 (6): 723-740. Morgan, D.G., 1979. High accuracy directional surveying of wells employing inertial techniques. SPE 8156, SOC.Pet. Eng. Offshore European Con$, Aberdeen, September 3-7. Morris, EJ. and Costa, J.P., 1977. A new method of determining range and direction from a relief well to a blowout well. SPE 6781, SOC.Pet. Eng. Annu. Fall Meet., Denver, Colo., October 9-12. Morris, F.J., Waters, R.L., Roberts, G.E and Costa, J.P., 1978. New magnetic ranging system pinpoints blowout well location. Oil Gas L , 76 (1 1): 57-62. Podio, A.L., Fosdick, M.R. and Mills, J., 1983a. Study shows incidence of blowouts in southeastern U.S./Gulf of Mexico. Oil Gas 1,81(44): 119-123. Podio, A.L., Fosdick, M.R. and Mills, J., 1983b. Analysis gives blowout causes, trends, costs. Oil GasJ., 81 (45): 125-133. Poettmann, F.H. and Carpenter, P.G., 1952. The multiphase flow of gas oil, and water through vertical flow strings with application to the design of gas-lift installations. Drilling and Production Practice, API, pp. 257-317. Reinicke, K.M., Remer and Hueni, 1987. Comparison of measured and predicted pressure drops in tubing for high-water-cut gas wells. SPE Prod. Eng., 2 (3): 165-177. Robinson, J.D. and Vogiatzis, J.P., 1972. Magnetostatic methods for estimating distance and direction from a relief well to a cased borehole. J. Pet. Technol., 25 (6): 741-749. Runge, R.J., Worthington, A.E. and Lucas, D.R., 1969. Ultra-long spaced electric log (ULSEL). Paper H, SOC.Prof. Well LogAnulysts Symp., Houston, Texas, May 25-28. Russell, M.K., 1970. The design and development of a surface reading orienting survey. Paper 801-46R, API Prod. Div., Pacific Coast District Meet., LQSAngeles, Calif., May 12-14. Russell, M.K. and Russell, A.W., 1979. Surveying of Boreholes. U.S. Patent No. 4, 163,324 (August 7); 7 claims; 7 figs. Walstrom, J.E., Brown, A.A. and Harvey, R.P., 1969. An analysis of uncertainty in directional surveying. J. Pet. Technol., 21 (4): 515-523. Warren, T.M., 1981. Directional survey and proximity log analysis of a downhole well intersection. J. Pet. Technol., 33 (12): 2351-2362. West, C.L. Kuckes, A.F. and Ritch, A.J., 1983. Successful ELREC logging for casing proximity in an offshore Louisiana blowout. SPE 11996, SOC. Pet. Eng. Annu. Fall Meet., San Francisco, Calif., October 5-8. Wiryodiarjo, S., Sumanta, K. and Mustiko, S., 1982. Formation fracturing kills Indonesian blowout. Oil CasJ., 80(46): 115-127. Wolff, C.J.M. and de Wardt, J.P., 1981. Borehole position uncertainty - analysis of measuring methods and derivation of systematic error model. J. Pet. Technol., 33 (12): 2339-2350. Wright, J., 1983. Rate gyro surveying of wellbores in the Rocky Mountains. SPE 11841, SOC.Pet. Eng. Rocky Mountains Reg. Meet., Salt Lake City, Utah, May 23-25.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 0 1994 Elsevier Science B.V. All rights reserved

343

Chapter 12

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION - EXAMPLES FROM THE ROCKY MOUNTAIN REGION CHARLES W. SPENCER

12.1. INTRODUCTION

The Rocky Mountain region provides many examples of basin-wide, abnormally high reservoir pressure caused by hydrocarbon generation. Sediment accumulation was slow and the rocks were mostly “dewatered” and well compacted prior to heating to sufficient levels to generate oil and gas. Abnormally high pressure is present in the deeper parts of at least twelve basins and subbasins in the Rocky Mountain region. A variety of conditions can cause overpressuring world-wide, discussed in Chapter 3. However, most high pressures in this region are interpreted to be caused by present-day or recently active oil and gas generation or generation in the last few million years in low-permeability (tight) rock sequences that still contain organic matter capable of yielding thermally generated hydrocarbons. Figure 12-1 shows distribution of abnormally high pressure in the Rocky Mountain region. Most of the overpressuring occurs in Cretaceous and lower Tertiary rocks. Overpressuring in rocks older than the Cretaceous is rare and where present only occurs in strata with very rich hydrocarbon source beds such as the Mississippian-Devonian Bakken Formation. For the purposes of this study, reservoirs are considered significantly overpressured if the pressure gradient exceeds 0.5 psi/ft (11.311 H a / m) in basins with fresh to moderately saline water, and 0.55 psi/ft (12.4 Ha/m) in basins with very saline water. The conditions causing abnormally high reservoir pressure in slowly accumulated reservoir and source-rock sequences in the Rocky Mountain region now can be well documented (Spencer, 1987). It is likely that abnormally high pressures caused by hydrocarbon generation occur in many other basins in the world. In order to recognize these occurrences it is helpful to list the observed conditions in the Rocky Mountain region examples. With very few exceptions, regionally overpressured reservoirs in the Rocky Mountain region have the following characteristics in common. (1) Hydrocarbons are almost always the fluid-pressuringphase. (2) Abnormally high pressuring occurs in rock sequences that accumulated slowly. They have present-day temperatures of about 200°F f 10” (93°C f 6“) or higher. Some residual or “inactive” (Law, 1984a) overpressuring occurs at temperatures less than this threshold temperature. This phenomenon is described later. (3) Natural fracturing is needed for high production rates. (4) The overpressuring occurs mostly in tight rock sequences.

344

C.W. SPENCER

CANADA -------__ UNITED S T A T E S

MOUNTAINS CRAZY

!i

u1

Fig. 12-1. Index map showing Rocky Mountain basins. The patterned areas show the interpreted areal distribution of overpressuring; boundaries dashed where uncertain (Spencer, 1987). MWX denotes the location of the U.S. Department of Energy's Multiwell Experiment site. See Fig. 12-14 for cross-section A-A' in the Uinta Basin.

( 5 ) Reservoirs rarely have discrete gas-water or oil-water contacts and commonly produce no water. Exceptions occur in rocks where high porosity and permeability have allowed gas-water or oil-water segregation by buoyancy. (6) The organic-rich source beds must still be capable of generating hydrocarbons at rates that exceed loss by migration. (7) Minimum vitrinite reflectance in oil (R,) of the kerogen in these rock sequences is usually more than 0.6% in very rich oil-prone source beds and more than 0.7% in very rich gas-prone source beds. Because most Rocky Mountain basins have been cooled below their maximum temperatures, overpressure seems to correlate better with present-day temperature. If the rock sequence is very organically lean or nonorganic, no regional overpressuring is present. (8) The maximum-pressure gradients observed in a given area are about equal to the natural fracture gradient of the rocks. (9) Local structure and stratigraphy are of secondary importance in the occurrence of abnormally high pressure.

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

345

(10) The overpressured strata are commonly at the center of the basin and water-bearing reservoirs with normal to subnormal pressure are usually present updip from the overpressuring.

12.2. MECHANISMS FOR OVERPRESSURING WORLD-WIDE

A review of the occurrence of world-wide abnormally high pressures or geopressuring (Fertl, 1976; and discussions elsewhere in this volume) indicates that there is no single mechanism that can adequately explain all occurrences of above-normal pressures. However, most proposed mechanisms require that the reservoirs be isolated or relatively well sealed in order to retain abnormal pressure. Some of the more commonly accepted causes of overpressuring are the dewatering of shales in conjunction with undercompaction, clay-mineral transformations that release water, and aquathermal pressuring caused by thermal expansion of water. The physical dewatering of clayey sediments and shales by compaction caused by weight of overburden is a widely accepted mechanism (Dickinson, 1953; Morgan et al., 1968; Chapman, 1980; Chiarelli and Duffaud, 1980). Water is released by diagenetic alteration of smectite-bearing shales and claystones to more stable mixed-layer illitehmectite or illitic shale. This alteration is a mechanism commonly used to explain overpressuring in the United States Gulf Coast region (Powers, 1967; Burst, 1969; Bruce, 1984). Aquathermal pressuring was proposed by Barker (1972) as the cause of some of the high pore pressure present along the northern coast of the Gulf of Mexico. Magara (1975) suggested that aquathermal pressuring produced reservoir pressures in the Gulf Coast area that exceed the weight of overburden. Daines (1982) concluded that aquathermal pressuring could occur at shallow depth in impermeable sediments in areas of high geothermal gradients. However, he concluded that even clay-rich shales will leak off the pressure caused by the relatively small water volume increase caused by thermal expansion. Barker (1972) noted that aquathermal pressuring might not be the only cause of abnormally high pressure but could add to reservoir pressure caused by other mechanisms. Other mechanisms for overpressuring are discussed by Fertl (1976), Gretner (1981), and others, and the likely causes are discussed in Chapter 3.

12.3. ABNORMALLY HIGH PRESSURE FROM HYDROCARBON GENERATION

Pressures that are above normal in the Rocky Mountain region can best be explained by three mechanisms: (1) long hydrocarbon columns; (2) artesian conditions caused by topographically high recharge areas; and (3) active generation of hydrocarbons. Active generation of hydrocarbons best explains busin-wide overpressuring, whereas artesian conditions and long hydrocarbon columns commonly only cause local occurrences of above-normal pressure. Regional overpressuring in the Rockies nearly always occurs in deep reservoirs that accumulated slowly and are now well compacted. These rocks usually produce

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only gas or oil and gas. If water is produced, it usually comes from an isolated reservoir within an overall hydrocarbon-bearing reservoir sequence or it is movable water in reservoirs with high water saturation. Therefore, in the example region, water-caused overpressuring from clay transformations, nonequilibrium compaction, aquathermal pressuring, artesian conditions, or osmosis seems very unlikely in reservoirs where the pressuring fluid is dominantly hydrocarbons. Overpressuring caused by the thermal generation of hydrocarbons involves conversion of overburden-supporting kerogen to fluids coupled with a volume increase (Meissner, 1978a). The rocks in the overpressured sequences are tight but are usually not completely impermeable; therefore, pressure maintenance by continuous or active generation of hydrocarbons is necessary (Meissner, 1978a; Law et al., 1980; Law, 1984a; Law and Dickinson, 1985). Several authors have speculated that overpressuring may be caused by the thermal generation of hydrocarbons. As early as 1949, Chaney (1949) speculated that the thermal destruction of oil and gas in sealed reservoirs could cause abnormally high reservoir pressures, up to the point of pressure release by fracturing or other means. Hedberg (1974) noted an association of methane generation with undercompacted clayey sediments and overpressuring and proposed that methane generation could add to other causes of overpressuring or could cause high pore pressure. However, some of the occurrences he described were probably caused by the biogenic generation of gas (Rice and Claypool, 1981) at very low temperature. In a later study, Hedberg (1980) strongly emphasized the importance of overpressuring caused by thermal generation of methane as well as proposing primary migration by microfracturing. Most workers agree that regardless of the origin of high pressure, good seals are necessary to prevent rapid pressure loss. However, when they suggest hydrocarbon generation as an overpressure mechanism, generally they do not define any specific criteria necessary for this type of pressure generation other than depth and (or) heat. However, Meissner (1976, 1978a) noted specific characteristics associated with overpressuring caused by oil generation in the Mississippian-Devonian Bakken Formation in the Williston Basin (Fig. 12-1). These characteristics are: (1) a minimum present-day temperature of 165°F (74°C); (2) organic-rich, thermally mature source beds; (3) reservoirs of very low permeability; (4) oil as the pressuring phase; (5) abnormally low sonic velocity in source beds; and (6) high resistivity in oil-saturated source beds. Most of the measured abnormally high Bakken pressures I have been able to obtain are in rocks with temperatures of 200°F (93°C) or higher. Law et al. (1980), studying Cretaceous gas reservoirs in southwestern Wyoming, noted the following characteristics of overpressuring: (1) minimum present-day temperatures of 180°F (82°C) from uncorrected borehole geophysical-log data; (2) organic-rich source beds; (3) tight reservoirs; and (4) below-normal salinity in some reservoir rocks interbedded with coals. Law and Spencer (1981) made the following observations of overpressured gas sequences in the northern Green River Basin of Wyoming: (1) the top of the overpressured interval coincides with the top of the gas-saturated interval; (2) source rocks are interbedded coal and other carbonaceous rocks still capable of

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

347

gas generation at a rate that exceeds gas loss; (3) overpressured sequences have an average of about 2% organic carbon; (4) vitrinite reflectance values at the top of the overpressured sequence are 0.75% to 0.84%; and ( 5 ) low-permeability ( ~ 0 . 1 mD), discontinuous reservoirs and seals. Spencer (1983) described the following characteristics for overpressured Tertiary and Cretaceous oil and gas reservoirs in the Rocky Mountain region: (1) most reservoirs (and source beds) have minimum present-day temperatures of about 200°F (93°C); (2) the top of overpressuring has a minimum vitrinite reflectance of 0.5% in oil-prone source beds and a minimum of 0.7% in gas-prone source beds; (3) the reservoirs are in tight rock sequences; (4) organic-rich source beds still capable of hydrocarbon generation; and (5) overpressured water reservoirs are rare in the region. In addition to the type and abundance of kerogen and the thermal maturation level, the top of overpressuring also seems to strongly depend on: (1) the permeability of the rock sequence; and (2) present-day subsurface temperature. There seems to be a general consistency of temperature and the top of overpressuring in Tertiary and Cretaceous rocks. The top of overpressuring in Cretaceous rocks occurs at about 200°F f 10" (93°C f 6") and in early Tertiary age (Paleocene and early Eocene) rocks it occurs at about 220°F f 20" (104°C f 11"). There are exceptions to these generalizations. Some overpressure can leak or diffuse vertically upward, and cause lower levels of overpressure or transition zones above the main interval of high pressure. There are some areas where previously overpressured rocks have been uplifted and cooled below the threshold temperature for active generation, but the overpressure has not fully declined to a normal pressure. In these areas, low values of overpressuring exist in thermally mature rocks with temperatures as low as 150°F (66°C). Law (1984a) called these residual anomalies, zones of "inactive" overpressure and this phenomenon is discussed later in this chapter. In areas of substantial cooling the reservoirs may have subnormal pressures (Meissner, 1978b; Law and Dickinson, 1985). If the high pressure is related to maturation, the zone of active hydrocarbon generation and high pressure in a given stratigraphic section moves upward with increasing depth of burial. Some wells appeared to be normally pressured within areas where most of the other wells were clearly overpressured. At least two explanations are possible: (1) that the apparent normal-pressure well is, in fact, overpressured but the rocks are so tight and unfractured that evidence of overpressure is lacking; or (2) that the pressure in the vicinity of the well has been drained by vertical migration of gas or oil migration along faults and (or) major fracture systems.

12.4. DISTRIBUTION AND CHARACTER OF OVERPRESSURE

Abnormally high pressure was identified in the twelve Rocky Mountain basins by both direct and indirect methods. Direct methods involved the use of extrapolated drillstem tests (DSTs) from Roger L. Hoeger's proprietary file of more than 30,000 Rocky Mountain DSTs. Long-term well shut-in pressures were another source of direct pressure measurement.

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TIME

Fig. 12-2. Drillstem-test chart run in moderately low-permeability rocks that are overpressured. Even though the chart can not be accurately extrapolated, pressure at point A yields a minimum-pressure gradient of 0.615 psi/ft (13.91 kPa/rn).

Indirect methods of overpressure mapping used in this study included compilation of mud weights, drillbit-penetration rates, and hydrocarbon shows. However, the most useful method to locate abnormal pressure on a regional basis was to computer-process large amounts of well-history DST report data and extract apparent-pressure-gradient information. DST initial and final shut-in pressures are reported in each digitized well record. These pressure values were converted to an apparent gradient and computer plotted to show the areal distribution of the apparent gradients for selected formations. These gradients are described as “apparent” because they are only minimum values. The reported shut-in pressure is almost always less than an extrapolated DST pressure. Very tight reservoirs have a very low apparent gradient. A small percentage of the DSTs tested well-fractured rocks or rocks with enough matrix permeability that calculated apparent-pressure gradients above normal can be identified. For example, Fig. 12-2 shows a DST chart from a well in the Greater Green River Basin. The test interval was from 10,978 to 11,070 ft (3346.1 to 3374.1 m). The initial shut-in pressure reported at point A was 6805 psi (46.9 MPa) which yields an apparent gradient of 0.615 psi/ft (13.91 kPa/ m). The pressure during the initial shut-in time was increasing rapidly and, even though the true reservoir pressure is much higher than the apparent pressure, the data are sufficient to readily identify the occurrence of overpressuring but not the maximum amount of abnormally high pressure. Overpressured hydrocarbon-bearing reservoirs are present in the following basins and stratigraphic units (1) Greater Green River Basin (aggregate of four subbasins). Cretaceous Cloverly (Dakota) Sandstone, Frontier Formation, Niobrara Formation and equivalents, Mesaverde Group and its equivalents, sandstone in the Lewis Shale, Fox Hills Sandstone, and Lance Formation, and Tertiary Fort Union Formation (Rathbun, 1968; Law et al., 1980; McPeek, 1981).

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

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( 2 ) Piceance Basin. Cretaceous Dakota Sandstone, sandstone and siltstone in the Mancos Shale (called Mancos “B” by subsurface workers), and sandstones in the Mesaverde Group (Spencer, 1987). (3) Uinta Basin. Tertiary Wasatch and Green River Formations, including its Flagstaff Member and equivalents (Lucas and Drexler, 1975, 1976), Cretaceous Mesaverde Formation and equivalents, and Cretaceous and Tertiary North Horn Formation. (4) Williston Basin. Mississippian-Devonian fractured, organic-rich Bakken Formation (Meissner, 1978a). These reservoirs are being developed using horizontal drilling and completion techniques. ( 5 ) Bighorn Basin. Cretaceous Cloverly Formation (Dakota Sandstone of subsurface usage), Frontier Formation, and lower part of Mesaverde Formation. (6) Powder River Basin. Cretaceous Lakota Formation, Muddy Sandstone, Frontier Formation, Niobrara Shale, and Shannon and Sussex Sandstone Members of the Steele Shale, and Parkman Sandstone Member of the Mesaverde Formation. (7) Wind River Basin. Cretaceous Frontier Formation, Meeteetse, and Lance Formations, and sandstone in the Cody Shale, and Tertiary Fort Union Formation and its Waltman Shale Member (Bilyeu, 1978; Reid, 1978;J.D. Haun, pers. commun., 1986). (8) Hanna Basin. Cretaceous Mesaverde Group and sandstone in the Lewis Shale. (R.M. Mattson, pers. commun., 1984). (9) Paradox Basin. Isolated occurrences of overpressuring have been found in fractured, organic-rich marine shales and associated rocks enclosed in salt in the Pennsylvanian Paradox Member of the Hermosa Formation. The areal extent of this overpressuring is not known but these fractured rocks are a target for horizontal drilling. This basin is in southwestern Colorado and southeastern Utah. 12.4.1. Greater Green River Basin In the Greater Green River Basin (Fig. 12-3), above-normal pressures occur in gas-bearing tight marine-to-fluvial sandstone reservoirs of Cretaceous to Paleocene age. All these strata contain interbedded humic-rich source beds and produce gas within and adjacent to the basin. Abundant Tertiary and Cretaceous sourcerock data are available (Law, 1984b). The shallow reservoirs normally have good reservoir quality and have normal to below normal reservoir pressures. Structure and stratigraphy are the trapping mechanisms for most of the shallow gas, and the accumulations generally have a gas-water contact (Spencer, 1985). In the Greater Green River Basin overpressured Cretaceous tight gas-bearing reservoirs occur at depths less than 10,000 ft (t3050 m) to more than 20,000 ft (>6100 m). Rocks older than Cretaceous are not regionally overpressured. The National Petroleum Council (1980, p. 33) estimated that the Greater Green River Basin has a maximum recoverable tight gas resource of 86.5 trillion cubic feet of gas (Tcf) (2449 x lo9 m3); however, they did not evaluate any resources at depths greater than 15,000 ft (>4570 m). Figure 12-3 shows the general distribution of overpressuring in the Greater Green River Basin and the location of several pressure-profile sites described in this

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Miles

A C I F I CC R E E K

Fig. 12-3. General distribution of overpressuring (patterned area) in the Greater Green River Basin and the location of some sites and areas where pressure and thermal maturation are discussed (from Spencer, 1987).

report. Regional overpressuring in the basin has previously been noted (Spencer and Law, 1981; Spencer, 1983, 1985; Law, 1984a). Local studies of overpressure have been made in the eastern part of the Greater Green River Basin (McPeek, 198l), the northern Green River Basin (Rathbun, 1968; Rathbun and Dickey, 1969; Law and Spencer, 1981; Law, 1984b; Spencer, 1984), and the Pacific Creek area (Law et al., 1980) (see Fig. 12-3). Rathbun (1968) and Rathbun and Dickey (1969) concluded that the overpressuring in the northern part of the Green River Basin proper was a local phenomenon caused by tectonic compression. Their conclusion was based on limited well data available at the time and the observation that the area is bounded on the west by the eastward-thrusted Wyoming Thrust Belt and on the northeast by the southwest-thrusted Wind River Mountains. Evidence from the present study indicates that gas generation is the cause of overpressuring in the northern Green River Basin. Overpressuring in southwestern Wyoming is regionally distributed and not a local phenomenon (Fig. 12-3). Furthermore, the thrusting ceased about 40 million years ago (Jordan, 198l), providing ample time for any pressure caused by stress to decay. However, the tectonic compression in the northern Green River Basin, caused by the opposing thrust systems, may be significant to the present study. The compression should have produced an increase in the in-situ stress. This stress should have increased the natural fracture gradient. The natural fracture gradient is probably the most important factor limiting marimurn reservoir pressure. Although no measured stress data exist, it is important to note that the highest reservoir pressure identified in the Rocky Mountain region (Spencer, 1983) occurs in the

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

351

northern Green River Basin at the Merna site (Fig. 12-3). Here, pressures in the top of the Upper Cretaceous Cody Shale and the base of the Mesaverde Group are about 16,700 psi (115.142 MPa) at 17,200 ft (5242.56 m). This pressure is equal to a gradient of 0.97 psi/ft (21.942 kPa/ m). The interpreted first occurrence of overpressuring (Fig. 12-4A) occurs at a depth of about 10,600 ft (3230 m), with a borehole temperature of about 194°F (90"C), and an estimated vitrinite reflectance (R,) of 0.84% (Law, 1984a; Fig. 12-4B). The Merna well site probably has not been significantly hotter in the past than it is at present. The Pacific Creek locality (Fig. 12-3) has present-day temperatures which are only slightly less than maximum paleotemperatures on the basis of vitrinite reflectance data (Law et al., 1980; Law, 1984a). The onset of overpressure at Pacific Creek (Fig. 12-5) occurs at a depth of about 11,600ft (3550 m) near the base of the Upper Cretaceous Lance Formation within and below a sequence of interbedded sandstones, organic-rich mudstones, shales, and coals. The DST data are from tests run in the Terra No. 1 Federal. The temperature at the top of overpressuring is about 200°F f 10" (93°C f 6"). Note that the interpreted reservoir pressure decreases at about the top of the Jurassic. The Jurassic and older rocks have little or no organic matter. Mud weights were increased near total depth because a hole was worn through the intermediate casing opposite overpressured Mesaverde rocks. The Mesaverde was producing gas into the mud column. Law et al. (1980) show percent organic carbon for 27 core and cuttings samples in the Tertiary and Cretaceous. Most samples exceeded 0.5% organic carbon and the average was 1.38%. Figure 12-6 is a burial curve for the Pacific Creek site using time and thickness data furnished by B.E. Law and N.M. Denson (pers. communs., 1986). The Pinedale area (Fig. 12-3) iies about half-way between Merna and Pacific Creek. Tight gas-bearing strata in the area have been extensively studied (Law, 1984b) because of the availability of deep cores. Figure 12-7 shows mud-weight profiles for most of the wells in the immediate Pinedale anticline area including the No. 1 Wagon Wheel. The No. 1 Wagon Wheel was drilled as a proposed site for stimulation with nuclear explosives and was drilled with considerable care to balance mud weights with reservoir pressures. Consequently, this well appears to have the most reliable pressure profile. However, most of the other wells show the first use of heavier-than-normal mud weights at about the same depth although the actual weights used varied. The deepest well drilled at the Pinedale area is the El Paso Natural Gas No. 1 Wagon Wheel (Sec. 5, T30N, R108W, Sublette Co., Wyoming). This 19,000-ft (5791 m) well was drilled to the top of the Upper Cretaceous Hilliard Shale (Baxter Shale equivalent). The well penetrated over 11,000 ft (3352 m) of gas-saturated Upper Cretaceous fluvial and marine rocks. Above-normal pressures occur from about 8000 ft (2440 m) to total depth at 19,000 ft (5791 m). Figure 12-8 shows the interpreted pressure profile and vitrinite data for the No. 1 Wagon Wheel (Law, 1984b). Several DSTs were run in this well but none could be extrapolated. The

TEMPERATURE

@ Cunmgs 0

A.

PRESSURE

B.

Cure

VlTRlNlTE REFLECTANCE (Ro)

Fig. 12-4. Pressure (A) and vitrinite-reflectance (B) profiles of the Belco No. 3-28 Merna Unit well, Sec. 28, n 6 N , R112W, Sublette County, Wyoming (from Law,1984a). For location see Merna, Fig. 12-3.

0

z

v)

Q

rn

z

c1

m P

353

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

-

FT

EXPLANATION Extrapolated DST pressure

A

>

DST mud-weight pressure

U

5

Terra X1 Fed. mud weight

IU

Rainbow L1-34 Fed. mud weight

W I-

DST 6 5 0 FI water

Superior X 1 Pac. Cr. mud weight

X

DST 12.590 Ft water cushion 8 180 Ft mud v)

3

P0

2 0 Ft gas-cut mud

2w 8 U

W

a

P 3

20

L. CRET R l ASSIC URASSI(

25

’ERMIAN PENN.

-

MISS.

TD 2 5 ,7 6 4 F T (7.852.9 rn) 10 O

I

L

5

8

50

1

8

10

140

100 I

1

0

15

1

1

I

MPa

I

20

PRESSURE (PSI X 1000)

Fig. 12-5. Pressure profile for wells in the Pacific Creek area using extrapolated drillstem-test (DST) and mud-weight pressures, gas shows, and drilling-time data. Profile is dashed where uncertain. Lower Cretaceous and deeper data from Rainbow 1-34 Federal well. For location see Pacific Creek, Fig. 12-3.

top of overpressuring occurs at a depth of 8030 ft (2450 m), at a temperature of about 150°F (66”C), and a vitrinite reflectance of 0.74% R,. At a depth of about 10,400 ft (3170 m), the pressure gradient is about 0.7 psi/ft (15.835 kPa/ m), and the uncorrected temperature at this depth is 180°F(82°C) corrected to an estimated temperature of 212°F (100°C). Law (1984a, b) interpreted the interval from 8030 to 10,400 ft (2450 to 3170 m) to be a zone of residual or “inactive” overpressure resulting from uplift and cooling of an interval that was formerly generating gas. Loss of gas and reduction of temperature causes a pressure reduction in this inactive zone. The top of the presently active gas-generation zone is the top of the pressure-gradient increase at

354

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0

50

I

I

-

\\

n'.

I

I

1

I

1

I

O

tt

c

t t

t

a w

v)

n

z <

10

2

0

E b

I

t w 15

4 - 8 2 2 m y Surlace Temp

50'F

(10°C)

Geothermal Gradient 1 3 ° F i 1 0 0 Ft ( 2 3 7 " C 1 1 0 0 m )

20

Fig. 12-6. Burial reconstruction profile of base of Upper Cretaceous Mesaverde Group at Pacific Creek site (Fig. 12-3). Using the method described by Waples (1980), if a variable surface temperature is used, a calculated time temperature index (7Tl) of 20 is at about 10,760 ft (3280 m), the base of the Tertiary is ? T I 7.4 and the base of the Mesaverde is 'IT1 258.2. If uniform surface temperature of 40°F (4.4"C) is used, then 7 T I 20 is calculated to be at 11,500 ft (3505 rn).

10,400 ft (3170 m). Residual or inactive overpressure has been observed in other areas where rocks have been significantly cooled in geologically recent time. Figure 12-9 is a stratigraphic cross-section by Law (1984a, fig. 16) that integrates pressure and stratigraphic data from the Merna, Wagon Wheel (Pinedale), and Pacific Creek areas. The top of overpressuring and associated vitrinite values are also shown. Law ascribed the changes in pressure gradients with depth to the relationships between source-rock richness, "present-day" temperature, and thermal maturity. At a temperature of about 190" to 200°F (88-93"C), pressure gradients in the Merna and Pacific Creek wells increase owing to present-day minimum threshold temperatures for pressure-sustaining gas generation. As noted previously, the top of the inactive zone coincides in the No 1. Wagon Wheel well with a small pressure-gradient increase. Another pressure-gradient increase occurs at the top of the interpreted active zone. Pressure increases also were detected as the top of organic-rich facies were penetrated (Law, 1984a). The marked pressure increase in the Merna well near total depth is difficult to explain. However, as noted earlier, the fracture gradient of overpressured strata is believed to be a critical factor that limits maximum pore pressure and the pressure in this well is the highest that I have detected in the Rocky Mountain region. The Merna well is in a narrow wedge of an area of possible high stress caused by opposing thrusts. Pressure in unfractured shales is difficult to estimate; however, the Merna deep anomaly

355

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION 1

EXPLANATION

-No.1 Wagon Wheel - - - - - -- No.1 Mesa Unit

-- ---

Nn.2 Pinedale Unit

...**-**-

No.4 Pinedale Unit

___-

No.7 Pinedale Unit

-- No.5 Pinedale Unit 2

% t, W

3

2

2 Y

z

X

5n 4

5

6

2

4

6

8

10

12

14 PSI(. 10001

PRESSURE

Fig. 12-7. Mud-weight profiles for six wells drilled on the Pinedale anticline showing a similar depth for the first use of above-normal mud weights. For location see Pinedale, Fig. 12-3.

occurs in sandstone and siltstone enclosed in marine shale. These brittle reservoir rocks are probably fractured giving them enough permeability to show detectable overpressure. Higher pressures may actually be present in unfractured shales above and below the siltstone and sandstone.

TE MP . F t 100

3 0 0 (OF)

200

D MU0 WEIGHT

MUD WEIGHT

A

MUD WEIGHT

km

-

Ft

km

MUD LOG

- WELL LOGS - ORILLSTEM

TEST

0 TEMPERATURE DATA POINT

A.

P R E S S U R E ( P S I X 1000)

B.

VITRINITE R EF L EC T AN C E (R,)

Fig. 12-8. Pressure (A) and vitrinite (B) profiles for the El Paso Natural Gas No. 1 Wagon Wheel, Sec. 5, T30N, R108W, Sublette County, Wyoming (from Law,1984a; Spencer, 1984). For location see Pinedale site, Fig. 12-3.

0

z

v)

V

rn

z

c)

rn

;a

NW

SE

MERNA

0 -

WAGON WHEEL

-0-

39 mi (63 k m ) \ A

A

PRESS

D

PACIFIC CREEK

40 mi (64 k m )

I I

I ( T = 1 5 0 ° F . R,=O

74)

-0

\

I

NORMAL P R E S S U R E D R O C K S

\

BASE

E R ~ C S O NSo.

ORGANIC RICHNESS

HIGH LOw Fig. 12-9. Stratigraphic cross-sectlon from Merna to Pacific Creek showing relationships among pressure gradients, organic richness, vltrimte values, and uncorrected temperature at the top of overpressured rocks (from Law, 1984a). Pacific Creek pressure gradient shown in Fig. 12-5 has been modified with additional well data but top of overpressure is still interpreted to occur at 11,600 ft (3500 m). Figure 12-3 shows location of wells. The Wagon Wheel well is shown as Plnedale site in Fig. 12-3.

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12.4.2. Piceance Basin Regional overpressuring is present in the deeper parts of the Piceance Basin of northwestern Colorado (Fig. 12-1). It occurs in low-permeability Cretaceous Dakota Sandstone, Frontier Formation marginal-marine sandstone, Mancos Shale marine siltstones and very fine-grained sandstones (called Mancos “B” by subsurface workers), and Mesaverde Group marginal-marine and fluvial sandstones, coals, and associated rock sequence. The pressuring-fluid phase is gas. All these strata produce gas from tight and conventional reservoirs in and adjacent to the basin. There is very little drilling in the basin deeper than 10,000 ft (3050 m); therefore, the exact extent of overpressuring is not well defined but in the few deep wells that have been drilled, overpressuring commonly occurs where subsurface temperatures exceed 200°F (93°C). Interestingly enough, some wells with bottom-hole temperatures greater than 200°F (93°C) were drilled with normal mud weights. It is possible that: (1) normal pressures are present in these wells because of pressure decay owing to gas migration in vertical fractures or faults; (2) the rocks are too organically lean to generate gas at a rate that exceeds gas loss; or (3) the rocks are overpressured but the permeability is too low to necessitate using heavy mud weights. Subnormal to normal pressures are present in most of the gas fields producing from reservoirs with temperatures less than 160°F (71°C). Basin-wide maximum, recoverable gas resources in tight reservoirs are estimated to be 33 Tcf (935 x lo9 m3) (National Petroleum Council, 1980). This estimate does not include major resources of gas in coals. Nuccio and Johnson (1983,1984) have studied the thermal maturity of Mesaverde Group rocks in the basin using vitrinite reflectance and coal-rank data. The basin is kidney-shaped and asymmetrical and the deepest part of the basin is on the east side. In general, the deepest part of the basin is the most thermally mature with a slight regional increase in maturity from north to south. Present-day subsurface temperature mapping (Nuccio and Johnson, 1984) indicates that the basin is cooler than the time and temperature values represented by the vitrinite reflectance data. The Multiwell Experiment (MWX) site is located in NW1/4, Sec. 34, T6S, R94W, Garfield County, within the Rulison field. The MWX is a U.S. Department of Energy field research project designed to advance the knowledge of well-log interpretation, artificial stimulation, and recovery of gas from tight gas reservoirs (Northrop et al., 1984). This research project is an excellent source of pressure, temperature, thermal maturation, and fracture-gradient data. Three closely spaced (115-215 ft, 35-66 m) wells were drilled. The wells were designated as the CER MWX Nos. 1, 2, and 3 (MWX-1, -2, and -3). A wide variety of geologic studies (Spencer and Keighin, 1984) have been conducted at the MWX site where 4100 ft (1250 m) of core was cut. Nuccio and Johnson (1984) and Bostick and Freeman (1984) show burial curves for the MWX site. Figure 12-10 is an interpreted pressure profile for the MWX site. Measured pore-pressure data are from Warpinski et al. (1984) and Paul Branagan (pers. commun., 1984). The top of overpressuring occurs in gas-bearing sandstones in the fluvial part of the Mesaverde Group at a depth of about 5600 ft (1707 m) and a

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION Ft 1 km

359

EXPLANATION

X

-

5

’ 5

U

I

c

-

P

8

20 I I

2

3

\ \

\

\ \

3;

60

\SO

4;

MPa

I

I

1

I

1

4

5

6

7

I 8

9 PSI ~ x 1 0 0 0 )

PRESSURE

Fig. 12-10. Interpreted pressure profile for MWX site wells, Piceance Basin (see Fig. 12-1 for location). Fracture-gradient data for various lithologies are also shown. Generally, shales and mudstones have higher fracture gradients than sandstones. Modified from Spencer (1987) to incorporate additional fracture-gradient data.

present-day temperature of 165°F (74°C). It is interpreted that the overpressuring present from the 165°F (74°C) line down to the 200°F (93°C) line represents a zone of residual overpressuring and presently little or no gas is being generated. The gas pressure in the inactive zone is being depleted by migration mostly along fractures and by diffusion. The interpreted top of “active” present-day overpressure is at a depth of 7024 ft (2141 m) and a true temperature of 200°F (93°C). The temperature data were derived from stabilized, high-resolution temperature logs run in the MWX-1 well by Los Alamos National Laboratory (Spencer, 1987). The reservoir-pressure profile (Fig. 12-10) also shows the depth of the R, 0.7% and 0.8% levels projected by Bostick and Freeman (1984). The Tertiary rocks in these wells are organically very lean and consequently, overpressuring probably never occurred in the Tertiary at this site. However, the 0.8% level occurs at a present-day

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well depth of about 4000 ft (1220 m) in Mesaverde rocks that contain dark-gray to black organic shales and mudstones. The top of the Mesaverde and the base of the Tertiary is present at a depth of 3900 ft (1189 m) based on correlations by R.C. Johnson (pers. commun., 1982). Maximum burial probably occurred about 9 to 10 m.y. ago (Nuccio and Johnson, 1984; Bostick and Freeman, 1984), and at that time the top of overpressuring was probably as shallow as the present 4000 ft (1220 m) depth in the MWX wells. After maximum burial the Colorado River eroded 4000 to 5000 ft (1220 to 1520 m) to the present elevation at the well site. This erosion caused the rock sequence to cool considerably and the interpreted original abnormally high reservoir pressure began to decrease in the MWX rocks in the interval between the present 4000-ft (1220-m) depth to the top of active generation. This pressure decay continued so that the present-day top of interpreted inactive overpressure is at a depth of 5600 ft (1707 m) as noted earlier. Active- and inactive-zone pressures at the Wagon Wheel (Pinedale) and MWX localities can be compared by adjusting the gradients at both sites to a 200°F (93°C) subsurface-temperature datum as shown in Fig. 12-11. In this manner, pressuregradient changes can be evaluated irrespective of actual reservoir pressure and differences in drill depths and temperature gradients. The interpreted shallow zone of inactive or residual overpressure in the Wagon Wheel No. 1 well is about 2400 ft (730 m) thick and at the MWX site it is about 1400 ft (430 m) thick. Assuming that the factors controlling overpressuring are correctly understood, then the relative thicknesses of the inactive intervals are, in part, related to pressure loss owing to gas phase migration and diffusion after gas generation ceased. The stratigraphy and reservoir character of both areas are fairly similar. Consequently, one would expect that there would be more loss of abnormally high pressure at the site where the gas generation has ceased for the longest period of time. This seems to be the case, because rocks at the MWX site started cooling about 10 m.y. ago (Nuccio and Johnson, 1984; Bostick and Freeman, 1984). It is interpreted that the original top of high pressure was as shallow as 4000 ft (1220 m) (Spencer, 1987). Therefore, the pressure from 4000 ft (1220 m) to 5600 ft (1707 m) in the MWX wells appears to have decayed to normal or subnormal pressures. Active pressure maintenance is interpreted to be occurring at and beneath the 200°F (93°C) present-day subsurface temperature level. The extent to which some of the MWX inactive zone is being charged by vertical gas migration from the underlying active zone is not known. It is not likely that this effect occurs over more than a few hundred feet above the active zone owing to the extremely low permeability of the horizontally bedded, sealing shales and mudstones. Most of the pressure is probably being lost by lateral migration in the sandstone reservoirs which are very tight but yet have slightly better matrix and fracture permeability than the argillaceous seals. The cooling event at the Pinedale (Wagon Wheel No. 1) area started more recently than that at the MWX site. On the basis of fission-track annealing studies, the rocks at the Wagon Wheel No. 1 started cooling only about 2 to 4 m.y. ago (Naeser, 1984) as opposed to about 10 m.y. ago for the MWX site. This more recent cooling seems to be a reasonable explanation for the somewhat thicker inactive

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

Ft

km

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Fig. 12-11. Comparison of pressure gradients at the Pinedale and MWX localities adjusted to a common 200°F (93°C) present-day subsurface temperature datum.

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zone in the Wagon Wheel No. 1 when compared to the thickness of the inactive zone in the MWX site wells (Fig. 12-11). The more recent cooling also helps explain why the maturation level R, 0.74%, about equivalent to the onset of significant gas generation (Law, 1984a), is about at the top of the inactive zone in the Wagon Wheel well. Conversely, the R, 0.7-0.8% vitrinite reflectance levels in the MWX wells are considerably shallower than the top of the inactive zone. Overpressuring caused by hydrocarbon generation may cause natural fracturing (Chaney, 1949; Meissner, 1978a; Law et al., 1980; Hedberg, 1980). Based on maximum pressures seen at MWX and elsewhere, it would seem that the gas (and oil) migration in many low-permeability reservoirs may be controlled by pressureinduced fractures in sandstone lithology and the shales may serve as confining seals and source beds. Fracture-gradient data is obtained from measurement of instantaneous shut-in pressures in the MWX wells compiled by Warpinski et al. (1984) and Paul Branagan (pers. commun., 1985) and is shown on the pore-pressure profile (Fig. 12-10). This technique is used to measure minimum rock stress or the approximate pressure at which a natural, or artificial, fluid-driven fracture will propagate. These data show that the fracture gradient is lowest in the sandstones and high but variable in shales and mudstones. Fracture gradients were only measured in two coals but they seem to be higher than most sandstones. These data suggest that if abnormal pressures can cause natural fractures, then the limiting maximum pore pressure in a sandstone reservoir is controlled by the sandstone fracture gradient and not the gradient of the enclosing seals. It is also interpreted that pressure caused by hydrocarbon generation in the coal, mudstone, and shale source beds is probably higher than that in the adjacent sandstones. Therefore, the source beds which have a high fracture gradient can be pressurized by gas generation to a higher level than the fracture gradient of the adjacent sandstone. Warpinski (1986) believed that it might be difficult to produce natural hydraulic fractures but shear or extension fractures could be formed by stress caused by high pore pressure. Meissner (1978a) had earlier proposed a similar origin for extension fractures. There are many calcite-cemented and open natural fractures in the MWX core. Pitman and Sprunt (1984) have studied the 13C and l*O stable isotopes of these cements and they concluded that the isotopes become slightly heavier with depth but are not significantly different, indicating that they probably formed under somewhat similar conditions. This may have been caused by: (1) extensive vertical fractures that formed during a single episode, allowing fluid movement over thousands of feet of strata; or (2) more likely that local cementation occurred in fractures at different times, but under somewhat similar conditions of depth and temperature (Pitman and Sprunt, 1984). The latter conclusion is consistent with the concept that some or many of the natural fractures may have been caused by overpressuring initiated by large volumes of gas (and some water) being generated in the source beds as the sediments become progressively heated (buried). Fluid inclusions in the MWX and Pinedale calcite fracture-filling cements have been studied by C.E. Barker (pers. commun., 1984). All the deep core samples that Barker studied at MWX and the Pinedale area burst or deformed prior to reaching the homogenization temperature, indicating that the gas had low solubility in the inclusion liquid and

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that the internal pressure within the inclusion exceeded the strength of the crystal when heated. He concluded from crushing stage studies that the inclusion gases are methane and that the calcite was precipitated from methane-saturated water under relatively high pressure and temperature. This observation also helps support the concept of fracture cementation from gas-saturated water at elevated temperature and pressure. However, the observation does not necessarily prove that the fractures were initiated by abnormally high pressures. 12.4.3. Williston Basin

A slightly different example of above-normal pressure occurs in the deeper parts of the Williston Basin of Montana and North Dakota (Meissner, 1976, 1978a; Spencer, 1987). It is present in low-permeability, fractured marine shale, siltstone, sandstone, and carbonate reservoirs in the Bakken Formation of Mississippian and Devonian age. The pressuring phase is predominantly oil and dissolved gas. The maximum measured pressure gradients are about 0.73 psi/ft (16.514 P a / m). The Bakken is relatively thin and is the only formation in the basin that is regionally overpressured. The Bakken has a maximum thickness of only 145 ft (44.2 m) in the depocenter of the basin (Webster, 1984) and thins generally uniformly toward the basin margins. Examples of overpressuring in most of the other basins occur in much younger rocks of Tertiary and (or) Cretaceous age and are distributed over thousands of feet of section. The Williston Basin is an intracratonic, symmetrical basin (Hansen, 1972). The interpreted extent of above-normal pressure in the United States portion of the basin (Fig. 12-1) is from Meissner (1978a). Even though the Bakken is an extremely rich source rock, it is not presently a major producing formation in the basin because of low matrix porosity and permeability. However, the Bakken is actively being developed by horizontal-well drilling. The major producing reservoirs are porous, shallow-water, marine carbonates that range in age from Ordovician to Mississippian. Oil-typing and paleomigration studies indicate that most of the Mississippian oil and some of the Devonian oil came from the Bakken (Dow, 1974; Williams, 1974). However, at least some Mississippian oil came from younger Mississippian source beds (Parker and Hess, 1980). The Bakken is rich in kerogen, blanket-like, and easily correlated throughout the basin. Therefore, it has been studied in detail by workers interested in basin-wide variations in organic richness and thermal maturation (Dow, 1974; Williams, 1974; Schmoker and Hester, 1983; Webster, 1984; Krystinik and Charpentier, 1984; Price et al., 1984; Dembicki and Pirkle, 1985). These studies vary somewhat in detail and interpretation but all conclude that the very kerogen-rich Bakken Formation has generated very large volumes of oil. On the basis of core and well-log studies, Schmoker and Hester (1983) estimated that the upper member of the Bakken has an average organic-carbon content of 12.1% weight percent and the lower member averages 11.5%. This average weight percent equates to a rock with about 30% kerogen by volume. Therefore, this oilprone source-bed sequence is similar to an oil shale. Schmoker and Hester (1983)

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speculated that hydrocarbons equivalent to 132 billion barrels (17.6 x lo9 t) may have been expelled from the Bakken in the United States’ part of the basin. They noted that this volume is an order of magnitude greater than all the Bakken-like oil-in-place discovered in the United States and Canada. Isolated occurrences of high pressure in the basin were described by Finch (1969). Meissner (1978a) studied the Bakken and concluded that the overpressuring was regional and present in a large area in the central part of the basin. He interpreted that oil generation at present-day temperatures as low as 165°F (74°C) causes the overpressuring in the Bakken. Meissner’s study was the first published report to propose oil generation as the only mechanism that could logically explain overpressuring in hydrocarbon-bearing rocks in a Rocky Mountain basin. Meissner (1978a) had six actual measurements of abnormal reservoir pressure and based much of his interpretation of high pressure on “compaction” trends from sonic logs. Lacking vitrinite or other maturation data he used the distribution of high well-log resistivity in shales of the Bakken Formation to identify areas and depths of mature, highly resistive, oil-saturated Bakken shales. This resistivity method has potential for application to studies of thermal maturation in compacted, organic-rich shales, especially where no other maturation data are available. It is significant that this increased resistivity, due to oil saturation in thermally mature rocks, is the opposite of the low resistivity on logs of undercompacted, overpressured shales in the Gulf Coast area (Fertl, 1976). Studies of Bakken-core organic richness and density-log response by Schmoker and Hester (1983) showed a high correlation of low shale bulk density and high organic richness. Therefore, sonic and density logs cannot be used to determine pore pressure in the Bakken because it contains 10 to 30 vol.% of kerogen. Spencer (1987) compiled measured-pressure data for the Bakken and, with one exception, all abnormally high pressures occurred in rocks with present-day temperatures higher than 200°F (93°C) but this may be a result of availability of data, and there may be some overpressured cooler areas. 12.4.4. Uinta Basin The Uinta Basin in northeastern Utah (see Fig. 12-1) contains major resources of oil in Tertiary Paleocene and Eocene overpressured deep reservoirs in the Altamont-Bluebell field. Most of the oil is contained in a 2,500 to 3000 ft (760 to 915 m) section of naturally fractured, low-porosity, tight sandstone, shale, and carbonates. Although water is produced with oil in many wells, discrete oil-water contacts do not appear to be present. The producing trend is now more than 48 mi long (77 km) and covers more than 400 mi2 (644 km2). Lucas and Drexler (1975, 1976) estimated that the trend may ultimately produce more than 250 million barrels of oil. The Tertiary section may be more than 19,000 ft (>5800 m) thick in the deepest part of the basin and it overlies a mostly undrilled Cretaceous section that may be more than 9000 ft (2750 m) thick in the axis of the basin. Though only limited data are available, the Cretaceous section is probably regionally gas bearing and overpressured, especially where coals are present. Figure 12-1 shows

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the interpreted extent of overpressuring in both Tertiary and Cretaceous rocks. The interpreted extent of above-normal pressure in Cretaceous rocks probably covers a larger area than in the Tertiary rocks. The Paleocene and Eocene rocks accumulated in an internally drained sedimentary basin that contains a central, organic-rich sequence of lacustrine shale, mudstone, and mud-supported carbonate (Fouch, 1975). Many of these organic-rich rocks are high-quality oil shales. The source beds are surrounded by marginal-lacustrine sandstone, claystone, and carbonates. These deposits intertongue landward with alluvial sandstone, claystone, and conglomerates of the Wasatch and Colton Formations (Fouch, 1975). Oil and gas fields with normal to subnormal reservoir pressure occur at shallow depths in the basin. Major resources of heavy oil (tar) are present in outcropping Tertiary sandstones around the basin (Ritzma, 1973). Lucas and Drexler (1976) described the general characteristics of the reservoirs and the basin-center overpressure, and suggested that oil generation could have caused overpressuring. They noted that the wells produce mostly from overpressured multiple sandstone pays with an average of 5% porosity (minimum 3%, maximum 10%) and that commercial production depends on the presence of natural fractures. Tight sandstone in the marginal lacustrine facies of the Green River Formation is the most productive reservoir type (Fouch, 1975). The basin axis is oriented east-west. The basin is asymmetrical with the deepest part along the north edge adjacent to the reverse fault on the south side of the Uinta Mountains uplift. There are a number of small displacement eastwest and northwest-trending faults present in the basin. Narr and Currie (1982) discussed the structural trends and stress history of the basin. They concluded that natural fractures can originate from several geologic processes and that these natural fractures are important in the enhancement of production in the basin. Their calculations suggest that the most important type of fractures are extension fractures and interpreted that these fractures can be caused by deep burial and tectonic unloading. The overpressuring in the Uinta Basin provides a unique example relative to other Rocky Mountain overpressured basins. The fluid-pressuring phase is oil and the overpressured interval is thick (>3000 ft, >915 m). The Williston Basin has overpressured oil reservoirs but the interval is thin (<145 ft, <44 m). The thick overpressured tight gas intervals present in many Rocky Mountain basins have quite variable reservoir pressures, both vertically and areally. As noted earlier, this variation is interpreted to be caused by the variable organic richness and quality of shale and siltstone seals and leakage along vertical fractures and faults. Therefore, attempts to contour pore pressure in the tight gas basins are frustrating and produce generally illogical patterns if more than a few data points are obtained. In contrast, the kerogen-rich oil shales of the Green River Formation make good seals and pressure patterns are relatively consistent. Figure 12-12 shows a contour map of maximum pore-pressure gradient in various parts of the central Uinta Basin slightly modified from Lucas and Drexler (1976). The highest pressure-gradient areas slightly exceed 0.8 psi/ft (>18.1 kPa/ m). Figure 12-13 is a pressure-depth plot of interpreted pore pressure in the Shell No. 1-llB4 Brotherson (Sec. 11, T2S,

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1 1 N

-T I

s

T2S

5 Miles

0

i,

j

Kilometers

Fig. 12-12. Map of maximum Tertiary pressure gradients (in psi/ft) for the Greater Altamont field, Uinta Basin and adjacent area, Utah, based on mud weights, hydrocarbon shows, and measured pressures (from Lucas and Drexler, 1976). Contour interval is 0.1 psiift. Maximum values may occur in various stratigraphic intervals within overall source-bed, reservoir, and seal sequence.

R4W, Duchesne Co., Utah). The estimated depth to the 200°F (93°C) isotherm is just above the top of overpressuring. The well reached a total depth of 17,776 ft (5418.1 m) in the top of the Cretaceous. A burial curve for the Tertiary in this well was prepared by Meissner (1978b). Figure 12-14 is a northeast to southwest cross-section modified from Fouch (1975), which shows gross formations and my interpretation of the overpressured interval. Also shown are initial potentials in barrels of oil per day (BOD) and gas in thousands of cubic feet per day (MCFD) and initial gross producing intervals from Fouch (1981). Some wells have subsequently been recompleted in additional Tertiary reservoirs. The Moncrief No. 14-1 Marsing (Fig. 12-14) was drilled to 19,391 ft (5910.4 m) into the top of the Upper Jurassic Morrison Formation. The well encountered the top of strong gas shows at about 10,600 ft (3230 m) near the top of the Cretaceous, and mud weights equivalent to a gradient of 0.557 psi/ft (12.6 kPa/ m) were being heavily gas cut at that depth and deeper. At a depth of about 15,000 ft (4572 m), mud with an equivalent gradient weight of 0.63 psi/ft (14.251 kPa/ m) was being heavily gas cut while the well was drilling the Upper Cretaceous Emery Sandstone Member of the Mancos Shale. A mud-weight equivalent to a gradient of about 0.88 psilft (19.9 kPa/ m) was used to control the well while drilling the Lower Cretaceous below 19,000 ft (>5791 m). Several unsuccessful attempts were made to establish commercial production. As noted earlier, the deep Cretaceous gas play in the Uinta Basin is relatively untested and probably will remain unevaluated until the Tertiary oil production is depleted and (or) gas price increases occur.

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

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12.4.5. Bighorn Basin

The Bighorn Basin in northwest Wyoming is a northwest-trending, nearly symmetrical structural basin that has indicated overpressure in Cretaceous Cloverly

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20 Miles 0

5

10

15

20 Kilometers

Fig. 12-14. Cross-section A-A’ across Uinta Basin through the Greater Altamont field, modified from Fouch (1975). Interpretation of overpressured section from Spencer (1987) is shown. Data are lacking to determine base of overpressure. Initial potential and producing interval from Fouch (1981). Some wells have been recompleted in other intervals. See Fig. 12-1 for location of section.

Formation (Dakota), Frontier Formation, and lower part of the Mesaverde Formation sandstones (C.C. Gregg, pers. commun., 1983). Only a few deep tests have been drilled; therefore, the distribution of overpressuring shown in Fig. 12-1 is highly interpretative but is based on the expected distribution of source beds and subsurface temperature. 12.4.6. Powder River Basin

Abnormally high reservoir pressure occurs in the deeper parts of the Powder River Basin, in northeast Wyoming (Larberg, 1976; Berg et al., 1980; Meissner, 1985). Reservoirs older than Cretaceous are not regionally overpressured. Meissner (1985) interprets that currently active hydrocarbon generation, principally in the Niobrara Shale and Mowry Formation, has caused the development of an overpressured cell in the deep parts of the basin and that oil and gas have migrated from this cell vertically and laterally into shallower and deeper reservoirs. Reservoir pressures in the Lower Cretaceous Muddy Sandstone in the Buck Draw field (T41N, R73W, Campbell Co.) are equivalent to a gradient of 0.65 psi/ft (14.704 kPa/ m) at 12,500 ft (3810 m) and a temperature of 280°F (138°C). The Highland Flats field (T37N, R73W, Converse Co.) has a reservoir pressure equivalent to a pressure gradient of 0.627 psi/ft (14.184 kPa/m) at 9895 ft (3016.0 m) and

ABNORMAL FORMATION PRESSURES CAUSED BY HYDROCARBON GENERATION

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an uncorrected DST temperature of 200°F (93°C) in the Upper Cretaceous Sussex Sandstone Member of the Steele Shale. Larberg (1976) and Berg et al. (1980) noted above-normal pressure in the Muddy Sandstone in the Kitty field (T50-52N, R73-74W, Campbell Co.). They attributed the above-normal pressure to clay diagenesis (water loss) in the Mowry Shale overlying the Muddy reservoirs and downward expulsion of water that may have also carried Mowry oil. However, Kitty field does not have a consistent oil-water contact and active oil generation is believed to be the cause of the abnormally high pressure (EE Meissner, pers. commun., 1986). Reservoir temperatures in the Muddy and Mowry in the field (Larberg, 1976, fig. 38) vary considerably from about 160°F (71°C) to 200°F (93°C) at a depth of about 8000 ft (2440 m). At 9000 ft (2740 m) the temperature vanes from about 200°F (93°C) to more than 225°F (>107”C). Pressure gradients vary in the field from subnormal at depths less than 8000 ft (2440 m) more than 0.5 psi/ft (11.311 kPa/ m) below 9000 ft (2740 m). The Frontier Formation at the Spearhead Ranch and Spearhead Ranch South fields (T37-39N, R74-75W, Converse Co.) is slightly overpressured. 12.4.7. Hanna Basin

Overpressuring is present but poorly defined in the Hanna Basin in south-central Wyoming (Fig. 12-1). This small but deep basin is only sparsely drilled and contains up to 20,000 ft (6100 m) of coals, sandstones, and lacustrine shales (Mattson, 1984). The Upper Cretaceous section consists of up to 10,000 ft (3050 m) of marine and nonmarine, organic-rich shales interbedded with hydrocarbon-bearing sandstones (Mattson, 1984). Overpressuring is present in the few wells drilled to depths below 11,000 ft (3350 m) having temperatures higher than 200°F (93°C) (R.M. Mattson, pers. commun., 1984). This basin has major potential for hydrocarbon production from a thick (>10,000 ft, >3050 m) sequence of organic-rich, overpressured rocks.

12.5. SUMMARY AND CONCLUSIONS

Tight oil- and gas-bearing reservoirs with abnormally high pressure are common in the deeper parts of most Rocky Mountain basins. These reservoirs and source beds range in age from Late Devonian to early Tertiary. World-wide there are many mechanisms that can cause above-normal pressure. However, in the Rocky Mountain region only the active generation of hydrocarbons adequately explains basin-wide, deep overpressure in rocks that were well compacted prior to hydrocarbon generation. Some local overpressuring can be explained by long hydrocarbon columns, vertical pressure leakage from deeper reservoirs, or artesian water conditions. Several types of sedimentary sequences have significant overpressuring. The most common overpressured rock sequences are thick (>3000 ft, >900 m) tight gas sandstone and coal-bed intervals of Cretaceous age. A thick sequence of overpressured oil-bearing rocks occurs in lower Tertiary lacustrine and associated deposits in the Uinta Basin. A thin (maximum 145 ft, 44.2 m) oil-source and reservoir-bed

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sequence is present in the Upper Devonian-Lower Mississippian Bakken Formation in the Williston Basin. The Powder River and Wind River Basins have some overpressured Cretaceous fields producing oil and gas, and gas and condensate. The examples described previously provide the basis for the following conclusions about overpressuring in the Rocky Mountain region. (1) Hydrocarbons are the fluid-pressuring phase even though water may be occasionally produced with the oil or gas. The origin of the overpressuring is hydrocarbon generation at sufficiently high temperatures. If water is produced, it generally comes from a few high-water-saturation reservoirs interbedded with the primary hydrocarbon-producing rocks. Initial gas- or oil-well completions may be water free, but following pressure drawdown, water may start to be produced. Rarely do overpressured reservoirs have discrete gas-water or oil-water contacts. (2) Present-day rock temperatures are mostly at least 200°F f lo” (93°C f 6“) or higher suggesting that present or near present-day temperature is a factor in pressure maintenance caused by active hydrocarbon generation. (3) For a few wells, available data suggest a rate of pressure leak-off. Cooled reservoirs in the MWX (Piceance Basin) and Pinedale (Green River Basin) areas have lost pressure and (or) returned to normal pressures in the last several million years. Therefore, the term “present-day” may represent a few thousand years to a few million years ago. This factor is not well resolved. (4) Organic-rich source beds stiil capable of hydrocarbon generation must be present. The richer the source beds, the more easily the pressure can be maintained even if the reservoir temperature has significantly decreased from its maximum (e.g. MWX site). ( 5 ) Thermally immature rocks are not regionally overpressured. High pressure is generally not present if the rocks contain little or no organic matter. (6) The maximum pressures encountered are about equal to the lowest fracture gradient of the rocks in a particular sequence. However, the maximum pressures can be influenced by rock and fracture permeability and result in pressures much lower than the expected fracture gradient. Limited data suggest that high pore pressure can cause vertical natural fractures and may be a major mechanism to move hydrocarbons and water through the reservoirs. Fracture gradients seem to be generally higher in mudstones and shales and lowest in sandstones. If correct, this relationship implies that organic-rich clay rocks can have a pore pressure considerably above that in an adjacent sandstone. (7) Classical hydrodynamic concepts involving groundwater movement are not very applicable in the analysis of pressure variations in deep Rocky Mountain basins, because the pressuring phase is not water, and the hydrocarbon generation is a very dynamic condition. Pressure differentials caused by variable rates of hydrocarbon generation and leak-off can cause rapid changes in pressure. (8) Much oil and gas in conventional reservoirs may have been originally generated in overpressured source beds and migrated vertically and laterally into the closest available high-permeability reservoirs where they then migrated updip by the buoyancy of a continuous oil or gas column (Meissner, 1985). The conventional reservoirs generally have normal to subnormal pressure. The permeability of tight

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oil or gas reservoirs is generally too low to permit migration by buoyancy; therefore, migration in these rocks occurs mostly by pressure differential. (9) The ability to predict the onset of abnormally high pressures can assist well operators in anticipating where to set intermediate casing strings and (or) prepare for well kicks or blowouts. (10) Modeling of basin evolution and paleohydrodynamics should consider the effects of the timing and duration of abnormal pore pressure caused by hydrocarbon generation. (1 1) Finally, the occurrence of abnormally high pressure in Rocky Mountain basins means that: (a) the sequence is mostly oil and (or) gas saturated; (b) water should not be a major obstacle to production; (c) reservoir energy is present to increase productive capacity; and (d) for gas reservoirs, higher pressure means significantly more gas-in-place for a given percent of gas-saturated pore volume. Successful exploration for overpressured reservoirs should concentrate in areas and at drilling depths where rich source beds are present, and where minimum subsurface temperatures are at least 200" to 220°F (93-104°C) in lower Tertiary and older rocks. The optimum areas will be those with a mixture of source beds, reservoirs, vertical seals, and natural fracture intersections. Very heavily fractured or faulted areas may have lost pressure and hydrocarbons. The optimum depths for exploration in thick, overpressured sequences are generally the top 1000 to 2000 ft (305-610 m) of the overpressured sequence. The reason for this is that in spite of overpressuring there is a general trend of decreasing reservoir porosity and permeability with depth. Therefore, the shallow part of overpressured intervals should generally have better reservoir quality. These concepts developed from the Rocky Mountain region examples should have application to basins elsewhere in the United States and world-wide where similar conditions of slow sediment accumulation, low permeability, thermal maturation, heat, and organic richness occur. A cursory review of world-wide pressure data suggests that where regional overpressuring occurs it is most common in rocks with temperature higher than 200°F (93°C). Obviously the author firmly believes that the abnormally high pressure in the Rockies is caused by active or recently active hydrocarbon generation. But frankly, it is difficult to explain the coincidence of the onset of much of the overpressuring with a minimum temperature of about 200°F (93°C) because so many factors such as permeability, source-bed richness, time, etc., are also important. More research is needed on the relationships among these factors. It is not suggested that hydrocarbon generation is an explanation for all regional overpressuring. In basins where rapid sediment accumulation has occurred, undercompaction, clay diagenesis, and aquathermal heating seem to be important pressure-causing factors. However, even in some of these basins, hydrocarbon generation should be an additive pressure-causing mechanism. This paper may encourage workers in other areas to test these models.

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ACKNOWLEDGEMENTS

This report was prepared in cooperation with the U.S. Department of Energy, Morgantown, West Virginia. Some of this work was originally published in the American Association of Petroleum Geologists Bulletin (Spencer, 1987) and their permission to republish some of these data and figures is gratefully acknowledged. The helpful comments of Roger L. Hoeger, B.E. Law, EE Meissner, J.R.Castano, R.E. Chapman, B.J. Katz, R.B. Powers, and S.E. Prensky are gratefully appreciated. M.P. Krupa and Yolanda Clausen typed the manuscript. R.L. Hoeger’s proprietary file of more than 30,000 Rocky Mountain drillstem tests was used extensively in this study.

REFERENCES Barker, C., 1972. Aquathermal pressuring - role of temperature in development of abnormal pressure zones. Bull., Am. Assoc. Pet. Geol., 56: 2068-2071. Berg, R.R., Larberg, G.M. and Lin, J.T., 1980. Hydrodynamic flow in Lower Cretaceous Muddy Formation, northeast Powder River Basin, Wyoming and Montana. Bull, Am. Assoc. Pet. Geol., 6 4 676. Bilyeu, B.D., 1978. Deep drilling practices - Wind River Basin of Wyoming. Wyo. Geol. Assoc. Annu. Field Con$ Guideb., 13: 13-24. Bostick, N.H., 1983. Vitrinite reflectance and temperature gradient models applied to a site in the Piceance Basin, Colorado. Bull., Am. Assoc. Pet. Geol., 67: 427-428. Bostick, N.H. and Freeman, V.L., 1984. Tests of vitrinite reflectance and paleotemperature models at the Multiwell Experiment site, Piceance Creek Basin, Colorado. In: C.W. Spencer and C.W. Keighin (Editors), Geologic Studies in Support of the U.S. Department of Energy Multiwell Experiment, Garfield County, Colorado. U S . Geol. Surv., Open-File Rep., 84-757: 110-120. Bruce, C.H., 1984. Smectite dehydration - its relation to structural development and hydrocarbon accumulation in northern Gulf of Mexico Basin. Bull., Am. Assoc. Pet. Geol., 6 8 673-683. Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull., Am. Assoc. Pet. Geol., 53: 73-93. Chaney, P.E., 1949. Abnormal pressures, lost circulation Gulf Coast’s top drilling problem. Oil Gas J. (April 21): 210-215. Chapman, R.E., 1980. Mechanical versus thermal cause of abnormally high pore pressures in shales. Bull., Am. Assoc. Pet. Geol., 64: 2179-2183. Chiarelli, A. and Duffaud, F., 1980. Pressure origin and distribution in Jurassic of Viking Basin (United Kingdom-Norway). Bull., Am. Assoc. Pet. Geol., 64: 1245-1250. Daines, S.R., 1982. Aquathermal pressuring and geopressure evaluation. Bull., Am. Assoc. Pet. Geol., 66: 931-939. Dembicki, H., Jr. and Pirkle, EL., 1985. Regional source rock mapping using a source potential rating index. Bull., Am. Assoc. Pet. Geol., 69: 567-581. Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana. Bull., Am. Assoc. Pet. Geol., 37: 410-432. Dow, W.G., 1974. Application of oil-correlation and source-rock data to exploration in the Williston Basin. Bull., Am. Assoc. Pet. Geol. ,58: 1253-1262. Fertl, W.H., 1976. Abnormal Formation Pressures. Developments in Petroleum Science, 2. Elsevier, Amsterdam, 382 pp. Finch, W.C., 1969. Abnormal pressure in the Antelope field, North Dakota. J. Pet. Techno[.,21: 821-826. Fouch, TD., 1975. Lithofacies and related hydrocarbon accumulations in Tertiary strata of the western and central Uinta Basin, Utah. In: D.W. Bolyard (Editor), Symposium on Deep DriNing Frontiers in the Central Rocky Mountains. Rocky Mountain Association of Geologists, pp. 163-173.

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Fouch, TD., 1981. Distribution of rock types, lithologic groups and interpreted depositional environments for some lower Tertiary and Upper Cretaceous rocks from outcrops at Willow Creek-Indian Canyon through the subsurface of Duchesne and Altamont oil fields, southwest to north central parts of the Uinta Basin, Utah. US. Geol. Sun., Oil Gas Invest., Map OC-81, 2 sheets. Gretner, RE., 1981. Pore pressure-fundamentals, general ramifications and implications for structural geology (revised). Am. Assoc. Pet. GeoL, Continuing Educ. Course Note Ser., 4, 131 pp. Hansen, A.R., 1972. The Williston Basin. In: W.W. Mallory (Editor), Geologic Atlas of the Rocky Mountain Region. Rocky Mountain Association of Geologists, pp. 265-269. Hedberg, H.D., 1974. Relation of methane generation to undercompacted shales, shale diapirs, and mud volcanoes. Bull., A m Assoc. Pet. Ceol., 58: 661-673. Hedberg, H.D., 1980. Methane generation and petroleum migration. In: W.H. Roberts and R.J. Cordell (Editors), Problems of Petroleum Migration. Am. Assoc. Pet. Geol., Spec. Stud. Geol., 10: 179-206. Jordan, TE., 1981. Thrust loads and foreland basin evolution, Cretaceous, Western United States. Bull., Am. Assoc. Pet. GeoL, 65: 2506-2520. Krystinik, K.B. and Charpentier, R.R., 1984. Developing an oil generation model for resource assessment of the Bakken Formation, U.S. portion of Williston Basin. US. Geol. Sum, OpenFile Rep., 84-694, 23 pp. Larberg, G.M., 1976. Hydrodynamic Effect on Oil Accumulation in a Stratigraphic Eap, Kitty Field, Powder River Basin, Wyoming. Thesis, Texas A&M University, College Station, Texas, 176 pp. Law, B.E., 1984a. Relationships of source-rock, thermal maturity, and overpressuring to gas generation and occurrence in low-permeability Upper Cretaceous and lower Tertiary rocks, Greater Green River Basin, Wyoming, Colorado, and Utah. In: Jane Wood, F.F. Meissner and J.L. Clayton (Editors), Hydrocarbon Source Rocks of the Greater Rocky Mountain Region. Rocky Mountain Association of Geologists, pp. 469-490. Law, B.E. (Editor), 1984b. Geological characteristics of low-permeability Upper Cretaceous and lower Tertiary rocks in the Pinedale anticline area, Sublette County, Wyoming. US.Geol. Sum, Open-File Rep., 84-753, 107 pp. Law, B.E. and Dickinson, W.W., 1985. Conceptual model for origin of abnormally pressured gas accumulations in low-permeability reservoirs. Bull., Am. Assoc. Pet. Geol., 69: 1295-1304. Law, B.E. and Spencer, C.W., 1981. Abnormally high-pressured, low-permeability, Upper Cretaceous and Rrtiary gas reservoirs, northern Green River Basin, Wyoming. Bull., Am. Assoc. Per. Geol., 65: 948. Law, B.E., Spencer, C.W. and Bostick, N.H., 1980. Evaluation of organic matter, subsurface temperature and pressure with regard to gas generation in low-permeability Upper Cretaceous and lower Tertiary sandstones in Pacific Creek area, Sublette and Sweehvater Counties, Wyoming. Mount. Geol., 17 (2): 23-35. Law, B.E., Spencer, C.W., Charpentier, R.R., Crovelli, R.A., Mast, R.F., Dolton, G.L. and Wandrey, C.J., 1989. Estimates of gas resources in overpressured low-permeability Cretaceous and Tertiary sandstone reservoirs, Greater Green River Basin, Wyoming, Colorado, and Utah. Wyoming Geological Association, Guidebook 1989, Gas Reserves of Wyoming. Wyoming Geological Society, pp. 39-61. Lucas, RT and Drexler, J.M., 1975. Altamont-Bluebell: a major fractured and overpressured stratigraphic trap, Uinta Basin, Utah. In: D.W. Bolyard (Editor), Symposium on Deep Drilling Fronfiersin the Central Rocky Mountains. Rocky Mountain Association of Geologists, pp. 265-273. Lucas, RT and Drexler, J.M., 1976. Altamont-Bluebell: a major, naturally fractured stratigraphic trap, Uinta Basin, Utah. In: J. Braunstein (Editor), North American Oil and Gas Fields. Am. Assoc. Pet. Geol., Mem., 24: 121-135. Magara, K., 1975. Importance of aquathermal pressuring effect in Gulf Coast. Bull., Am. Assoc. Pet. Geol., 59: 2037-2045. Mattson, R.M., 1984. Geology and petroleum potential of Hanna Basin, Carbon County, Wyoming. Bull., Am. Assoc. Pet. Geol., 68: 504. McPeek, L.A., 1981. Eastern Green River Basin - a developing giant gas supply from deepoverpressured Upper Cretaceous sandstones. Bull., Am. Assoc. Pet. Geol., 65: 1078-1098.

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Meissner, F.F., 1976. Abnormal electric resistivity and fluid pressure in Bakken Formation, Williston Basin and its relation to petroleum generation, migration and accumulation. Bull., Am. Assoc. Pet. Geol., 60: 1403-1404. Meissner, F.E, 1978a. Petroleum geology of the Bakken Formation, Williston Basin, North Dakota and Montana. 24th Annual Conference, Williston Basin Symposium. Montana Geological Society, pp. 207-227. Meissner, F.F., 1978b. Patterns of source-rock maturity in non-marine source-rocks of some typical Western Interior Basins. Non-marine Tertiary and Upper Cretaceous Source Rocks and the Occurrence of Oil and Gas in West-central U.S. Rocky Mountain Association of Geologists Continuing Education Lecture Series, pp. 1-37. Meissner, F.F., 1985. Regional hydrocarbon generation, migration, and accumulation pattern of Cretaceous strata, Powder River Basin. Bull., Am. Assoc. Pet. GeoL, 69: 856. Morgan, J.P., Coleman, J.M. and Gagliano, S.M., 1968. Mudlumps - diapiric structures in Mississippi delta sediments. In: J. Braunstein and G.D. O’Brien (Editors), Diapirism and Diapirs. Am. Assoc. Pet. GeoL, Mem., 8: 145-161. Naeser, N.D., 1984. Fission-track ages from the Wagon Wheel No. 1 well, northern Green River Basin, Wyoming - evidence for recent cooling. In: B.E. Law (Editor), Geological Characteristics of Low-permeability Upper Cretaceous and Lower Tertiary Rocks in the Pinedale Anticline Area, Sublette Counfy, Wyoming. US. Geol. Sum., Open-File Rep., 84-753: 66-77. Narr, W. and Currie, J.B., 1982. Origin of fracture porosity - example from Altamont field, Utah. Bull., Am. Assoc. Pet. Geol., 66: 1231-1247. National Petroleum Council, 1980. Tight gas reservoirs, Part I. In: National Petroleum Council Unconventional Gas Resources. National Petroleum Council, Washington D.C., 222 pp., with appendices. Northrop, D.A., Sattler, A.R., Mann, R.L. and Frohne, K.-H., 1984. Current status of the Multiwell Experiment. SPEIGRIIDOE Unconventional Gas Recovery Symposium, Proceedings. Society of Petroleum Engineers, Dallas, Texas, pp. 351-358. Nuccio, VF. and Johnson, R.C., 1983. Preliminary thermal maturity map of the Cameo-Fairfield or equivalent coal zone through the Piceance Creek Basin, Colorado. US.GeoL Sum.,Misc. Field Stud., Map MF-1575. Nuccio, V.F. and Johnson, R.C., 1984. Thermal maturation and burial history of the Upper Cretaceous Mesaverde Group, including the Multiwell Experiment (MWX), Piceance Creek Basin, Colorado. In: C.W. Spencer and C.W. Keighin (Editors), Geologic Studies in Support of the US.Department of Energy Multiwell Experiment, Garfield Counfy, Colorado. U S . Geol. Surv., Open-File Rep., 84-757: 102-1 09. Parker, J.M. and Hess, P.D., 1980. The Mondak Mississippian oil field, Williston Basin, U.S.A. Oil Gas J. (October 13), pp. 210-216. Pitman, J.K. and Sprunt, E.S., 1984. Origin and occurrence of fracture-filling cements in the Upper Cretaceous Mesaverde Formation at MWX, Piceance Creek Basin, Colorado. In: C.W. Spencer and C.W. Keighin (Editors), Geologic Studies in Support of the U.S. Department of Energy Multiwell Experiment, Ga$eld Counfy, Colorado. U S . Geol. Sum, Open-File Rep., 84-757: 87-101. 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. Price, L.C., Ging, T, Daws, T, Love, A., Pawlewicz, M. and Anders, D.E., 1984. Organic metamorphism in the Mississippian-Devonian Bakken Shale, North Dakota portion of the Williston Basin. In: Jane Woodward, F.F. Meissner and J.L. Clayton (Editors), Hydrocarbon Source Rocks of the Greater Rocky Mountain Region. Rocky Mountain Association of Geologists, pp. 83-133. Rathbun, F.C., 1968. Abnormal pressures and conductivity anomaly, northern Green River Basin, Wyoming. SPE 2205, 43rdAnnual Fall Meeting, Society of Petroleum Engineers, Dallas, Texas, pp. 1-8. Rathbun, F.C. and Dickey, P., 1969. Abnormal pressures and conductivity anomaly, northern Green River Basin, Wyoming. Log Anal. (July-August), pp. 3-8. Reid, S.G., 1978. Madden Deep Unit - Fremont and Natrona Counties, Wyoming. Wyo. Geol. Assoc., Earth Sci. Bull., 1 1 : 34-42. Rice, D.D. and Claypool, G.E., 1981. Generation, accumulation, and resource potential of biogenic gas. Bull., Am. Assoc. Pet. Geol., 65: 5-25.

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Ritzma, H.R., 1973.Oil-impregnated rock deposits of Utah. Utah GeoL Mineml. Suw. Map, 33,2 sheets. Schmoker, J.W. and Hester, TC., 1983. Organic carbon in Bakken Formation, United States portion of Williston Basin. Bull., Am. Assoc. Pet. Geol., 6 7 2165-2174. Skeeters, W.W. and Hale, L.A., 1972. Southern Wyoming. In: W.W. Mallory (Editor), Geologic Atlas of the Rocky Mountain Region. Rocky Mountain Association of Geologists, pp. 274-276. Spencer, C.W., 1983. Overpressured reservoirs in the Rocky Mountain region. Bull., Am. Assoc. Pet. Geol., 67: 1356-1357. Spencer, C.W., 1984. Overpressured tight gas reservoirs in the Pinedale anticline area, Sublette County, Wyoming. In: B.E. Law (Editor), Geological Chamcteristics of Low-permeability Upper Cretaceous and Lower Tertiary R o c b in the Pinedale Anticline Area, Sublette County, Wyoming. US. Geol. Suw., Open-File Rep., 84-753: 51-59. Spencer, C.W., 1985. Geologic aspects of tight gas reservoirs in the Rocky Mountain region. J. Pet. Technol., 37: 1308-1314. Spencer, C.W., 1987. Hydrocarbon generation as a mechanism for overpressuring in the Rocky Mountain region. Bull., Am. Assoc. Pet. Geol., 71: 368-388. Spencer, C.W. and Keighin, C.W. (Editors), 1984. Geologic Studies in Support of the US. Department of Energy Multiwell Experiment, Garfield County, Colomdo. US.Geol. Sum, Open-File Rep., 84-757, 134 PP. Spencer, C.W. and Law, B.E., 1981. Overpressured, low-permeability gas reservoirs in Green River, Washakie, and Great Divide Basins, southwestern Wyoming. Bull., Am. Assoc. Pet. Geol., 65: 569. Waples, D.W., 1980. Time and temperature in petroleum formation - application of Lopatin’s method to petroleum exploration. BulL, Am. Assoc. Pet. GeoL, 64:916-926. Warpinski, N.R., 1986. Elastic and Vicoelastic Model of the Stress History of Sedimentay Rocks. Sandia National Laboratories, SAND86-0238, 119 pp. Warpinski, N.R., Branagan, P. and Wilmer, R., 1984. In situ stress measurements at DOE’S Multiwell Experiment. In: K.-H. Frohne (Editor), Western Gas Sands Subprogram Review Proceedings. U S . Department of Energy, Morgantown, Penn. DOE/METC 84-3, pp. 181-189. Webster, R.L., 1984. Petroleum source rocks and stratigraphy of the Bakken Formation in North Dakota. In: J. Woodward, F.F. Meissner and J.L. Clayton (Editors), Hydrocarbon Source Rocb of the Greater Rocky Mountain Region. Rocky Mountain Association of Geologists, pp. 57-81. Williams, J.A., 1974. Characterization of oil types in Williston Basin. Bull., Am. Assoc. Pet. Geol., 58: 1243-1252.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.E Hotz 8 1994 Elsevier Science B.V. All rights reserved

377

Chapter 13 INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS: A MACROGEOLOGIC PERSPECTIVE THOMAS J. WOODS

13.1. INTRODUCTION

Improved recovery of gas-in-place has been traditionally held to be relatively unimportant because recovery of gas-in-place in high permeability non-associated gas pools was thought to be in the neighborhood of 80 to 90%. This relative unimportance was reflected in the fact that net revisions, the category where improved recovery reserve additions would tend to be reported, have played a rather minor role in U.S. gas reserve additions, accounting for less than 7% of U.S. gas reserve additions in the last ten years. This is in marked contrast to the oil picture, where revisions have accounted for more than half of oil reserve additions in the last ten years. Recent work has indicated that the potential for oil reserve additions as a result of improved recovery of oil-in-place is substantially larger than previously thought. Traditionally, primary and secondary recovery were thought to be able to recover, on average, about one-third of the oil-in-place in a reservoir. Any substantial additional recovery of oil-in-placewas thought to require expensive enhanced oil recovery (EOR) techniques (e.g., C02 flooding, polymers), many of which were still under development. Recent work on Texas reservoirs, however, shows that reservoir heterogeneities trap much higher percentages of mobile oil reservoirs and that improved production practices, without recourse to expensive EOR techniques, could substantially increase the recovery of oil-in-place in these reservoirs ( v l e r et al., 1984). The recent successes in improving the recovery of oil-in-placeusing infill drilling in many oil fields, such as Salt Creek and Ellenberger, have substantiated this observation. Estimates of the incremental recovery of oil from known reservoirs in the lower-48 have been as high as 80 billion barrels (12.7 x lo9 m3) (Fisher, 1987). The existence of heterogeneities in oil reservoirs have led to a hypothesis that heterogeneities in gas reservoirs might result in much lower recoveries of gas-in-place than previously thought. While the recovery of gas-in-place in high permeability reservoirs might still be 80 to 90% of the gas-in-place within the radius of drainage of a gas well, that radius of drainage, due to reservoir heterogeneities, might be a lot less than 640 acres (259 ha), the usual well spacing for high permeability reservoirs. As a result, infill drilling in known gas reservoirs might be able to recover substantial incremental quantities of gas, and at rather modest prices. The Gas Research Institute has begun a project to assess the incremental gas resource potential as a result of increased gas recovery in producing reservoirs. This work has proceeded on both a micro basis, that is, detailed analysis of specific plays,

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and a macro basis, that is, on a broad, area-wide basis averaging over a variety of geologic plays in the area. The purpose of the macro analysis is to provide some generalized rules to rank specific plays as well as to extrapolate the play-specific microanalysis to basins and larger areas. This paper will report on the initial results of the macro analysis. The work described in this paper has been done with the assistance of Harry Vidas, Robert Hugman, and Tom Hazeu of Energy and Environmental Analysis of Arlington, Virginia.

13.2. RESERVOIR COMMUNICATION

The level of communication that is observed in an oil or gas reservoir can be viewed from either a static or a dynamic perspective. From a static perspective, reservoirs can be highly complex, showing rather large changes in reservoir parameters as one moves through the reservoir. As a result of this complexity, substantial volumes of the reservoir remain undrained because they are not in communication with producing wells. Thus, infill wells drilled in a reservoir can often encounter reservoir compartments at or near original pressure, even if the reservoir has been produced for more than 30 years, as in the case of the Salt Greek field in West Texas. Reservoir communication, however, is also a dynamic concept. It is possible to have a situation in which wells at a particular spacing have shown strong evidence of communication. However, as the pressure in the reservoir declines, the pressure gradient becomes flatter. As a result, the basic reservoir characteristics, combined with the characteristics of the fluid being produced from the well, lead to a situation in which the radius of drainage of the well can shrink as the reservoir is produced. Under such conditions, the reservoir could exhibit poor communication at some point in its production history, despite the evidence of good communication early in its production history and possibly very modest differences between the pressures of the infill well and the original well. Figure 13-1 illustrates three general classifications of communication: complete, partial, and poor. In the complete communication illustration, the tank can be drained by one well. However, given the nature of the reservoir and fluid parameters, a situation could arise akin to the partial communication illustration. As the fluid is drained, until the fluid falls below the level of the bulkheads in the bottom of the tank, one well could drain the entire tank. But, once the fluid falls below the level of the bulkheads, the radius of drainage is constricted to the single compartment the well is in. Other wells are then necessary to complete the drainage of the tank. It should be noted that the partial communication can occur even if the reservoir parameters show little change over the volume of the reservoir (i.e., the reservoir is homogeneous). The poor communication illustration shows a situation in which there is virtually no communication. This poor communication can be a result of a highly heterogeneous reservoir breaking the reservoir up into many compartments or the interaction among fluid and reservoir parameters in a rather homogenous reservoir,

379

INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS

Complete

Partial

Poor

Fig. 13-1. Reservoir communication.

such as a low-permeability,modest pressure gas reservoir that reduces the radius of drainage of the well. These illustrations can also provide some insight into the drainage patterns of oilfassociated-gas reservoirs. Because gas has a higher mobility than oil, a reservoir that has relatively poor communication for oil could have a situation more akin to partial communication for gas that is not in solution with the oil. As a result, infill wells in oil reservoirs could find a lower gas-to-oil (GOR) than had been observed in the producing parts of the reservoir.

13.3. ASSOCIATED GAS

A great deal of attention has been focused on the potential for incremental oil recovery from known reservoirs; the incremental gas recovery that might be expected to be observed with the improved recovery has received little attention. However, this recovery could be significant, and the incremental revenue that is obtained from the gas recovery could play an important role in the economics of the infill project. An analysis done for the San Andres/Greyburg South Central Basin Platform of the Permian Basin indicates that the revenues from the incremental associated gas production play a significant role in the resource economics of infill drilling at prices below $15.00 per barrel ($94 per m3) (K. McFall, pers. commun., 1987). Thus, the incremental associated gas revenues provide a basis to maintain the resource economics of oil infill drilling during a period of very uncertain prices.

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The incremental oil reserve additions as a result of infill drilling are reported as revisions in the U.S. Department of Energy, Energy Information (EIA) reserve reports. It is reasonable to conclude that the incremental associated gas recovery would also be reported as revisions to associated gas reserves. A comparison of the GOR for revisions and reserves indicates that the average GOR for revisions reported from 1981 to 1987 for the lower-48 was less than the GOR for producing reserves at the end of 1987. This would imply that the incremental gas reserves associated with improved oil recovery would not be proportional to the incremental oil recovery. However, the total lower-48 picture averages over some substantially different incremental oil recovery prospects with very different GORs. The Texas Bureau of Economic Geology study of incremental oil recovery from Texas oil reservoirs shows that the biggest incremental potential occurs for carbonate reservoirs (Tyler et al., 1984). That is, the uncovered mobile oil target using current production practices is usually larger in carbonate plays than in sandstone plays. In addition, the net revisions for associated gas on the onshore Gulf of Mexico (Texas Districts 2 to 4 and South Louisiana) have been very small, reflecting the effects of net negative revisions in the 1980s. Thus, on the Gulf Coast, improved recovery of oil-in-place seems to have had a limited effect on increased gas recovery. Finally, California, with its large component of heavy oil and its very low GOR in its revisions and reserves, severely distorts any national figures. Table 13-1 presents the trends in revisions for wet associated gas broken out by selected lower-48 regions for the period 1981 to 1987. The volumes are presented in billion cubic feet (Bcf) and billion cubic meters (lo9 m3). The numbers in these and other tables may not add due to rounding. The carbonate region is comprised of those parts of the lower-48 that have more than half of their oil reserves in carbonates. This includes Texas Railroad Commission Districts 1, 7C, 8, 8A, and 10, Eastern New Mexico, and Kansas. Other lower-48 have significant volumes of oil carbonate formations, namely East Texas and Oklahoma, but they are not included in the carbonate region. The onshore Gulf includes Texas Railroad Commission Districts 2, 3, and 4 plus South Louisiana. TABLE 13-1 Lower-48 wet associated gas revisions: 1981-1987 Region

Bcf

Carbonates a Onshore Gulfb Offshore Gulf Onshore California Remaining

2909 66 897 178 828 4878

Lower-48 total

lo9 m3 82 2 25

5 23 137

~

a

Kansas, Eastern New Mexico, Texas RR Districts 1, 7C, 8, 8A, 10. Texas RR Districts 2, 3, 4 and South Louisiana.

INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS

381

TABLE 13-2 Gas-to-oil ratio a (Mcf per barrel) (volumetric ratio) Category

1981-1987 revisions

1987 reserves

Carbonates Onshore Gulf Offshore Gulf Onshore California Remaining

1.08 0.15 1.49 0.07 0.58

[193] [27] [265] [13] [lo31

1.11

Lower-48 total

[114]

~

a

_ -

3.08 0.58 1.39

[197] [585] [549] [lo31 [217]

- -

0.64

1.38

[246]

3.28

Gas is reported on a wet basis. Kansas, Eastern New Mexico, Texas RR Districts 1,7C, 8,8A, 10. Texas RR Districts 2, 3, 4 and South Louisiana.

Table 13-1 shows that almost 60% of the revisions to wet associated gas reserves between 1981 and 1987 were in the carbonate-dominated regions. The revisions are substantial in the remaining lower-48 and offshore Gulf of Mexico as well. Only the onshore Gulf, with its history of negative revisions, and California, with its heavy oil and low GOR, played a modest role in associated gas revisions during this period. a b l e 13-2 compares the GOR for the reported revisions from 1981 and 1987 to the GOR for 1987 reserves. The values in the parentheses are the ratios of the gas volume to the oil volume measured in the same units, such as cubic meters. Table 13-2 shows that the incremental gas recovery reported as revisions in the carbonate-dominated regions between 1981 and 1987 has essentially the same GOR as the 1987 reserves. This indicates that the heterogeneity effects for associated gas could be as strong as for oil in these formations. In all other regions, however, the GOR for revisions is less than the GOR for reserves. The GOR for revisions in the offshore Gulf and remaining lower-48 is about 40 to 50% of the GOR for reserves in these regions, indicating that the heterogeneity effects on associated gas in these regions are not as strong as for oil. The GOR for revisions in onshore California is less than one eight of the GOR for reserves, reflecting a combination of reservoir heterogeneity and the large difference between the mobility of gas and the mobility of the generally heavy California crude. The very low GOR for revisions in the onshore Gulf reflects the lingering effects of negative associated gas revisions between 1981 and 1984. Since 1985, the GOR for revisions in the onshore Gulf has been about two-thirds of the GOR for reserves. The likelihood of incremental gas recovery is tied to oil recovery. About twothirds of the oil revisions between 1981 and 1987 were in California or the carbonate-dominated regions. The rest of the oil revisions occurred in the remaining sandstone-dominated lower-48 regions. Given the Texas analysis, it would be reasonable to conclude that these shares could be representative of the future. The major uncertainty would be a shift in the shares between California and the remaining lower-48 shares of incremental oil recovery on the grounds that improved

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recovery was overly concentrated in California in the 1980s. This would imply some additional incremental associated gas recovery. Recent estimates of the incremental oil recovery for the lower-48 based on the Texas work imply 80 billion barrels of incremental recovery for the entire lower48. This would imply an average ultimate recovery of oil-in-place near 50%. The incremental gas recovery associated with these incremental oil estimates would be 56 trillion cubic feet (Tcf), almost 60% of which would be expected to be found in the carbonate-dominated region stretching from Kansas to Eastern New Mexico.

13.4. NON-ASSOCIATED GAS

A more detailed macro-analysis can be made of the incremental resource potential of non-associated gas because of the detailed well production data available. Comparable data for oil wells are only available for a few states. The analysis will utilize the EIA data on reserve additions and the data for producing gas wells. The producing gas well data were obtained from Dwight’s.

13.4.1. Macro-reserve data

Table 13-3 shows the trend in the revisions and adjustments to non-associated gas reserves in the lower-48 states. The regions are the carbonate-dominated areas, onshore Gulf, offshore Gulf, areas with large volumes of unconventional gas (e.g., tight sands, coalbed methane), and the East. The onshore Gulf area, the carbonate-dominated area, and the offshore Gulf are unchanged from the associated gas discussion. The unconventional area is comprised of Colorado, Western New Mexico, Wyoming, and Texas Railroad

TABLE 13-3 Lower-48 revisions and adjustments wet non-associated gas Area

1981-1987 (lo9 m3)

1981-1987(Bcf) revisions

adjustments

Carbonate a Onshore Gulf Offshore Gulf Unconventional East Remaining lower-48

5,000 -3,247 3,128 2,189 1,103 3,530

Lower-48 total

11.703

735 1,801 385 -405 576 4,868 7.960

a

Kansas, Eastern New Mexico, Texas RR Districts 1,7C, 8, SA, 10.

Texas R R Districts 2, 3, 4 and South Louisiana. Colorado, Western New Mexico, Wyoming, Texas RR Districts 5, 6. Kentucky, New York, Ohio, Pennsylvania, Virginia, West Virginia.

revisions 142 -92

89 62 31 100 331

adjustments 21 21 11 11 16 138 225

383

INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS

Commission Districts 5 and 6 (tight sands). The East area is comprised of Kentucky, New York, Ohio, Pennsylvania, Virginia, and West Virginia. The remaining lower-48 category can be said to generally represent high permeability gas in sandstones. Adjustments are presented in this table because some overlap may exist between revisions and adjustments for non-associated gas, particularly in the East. Table 13-3 shows that, as in the case of associated gas, the carbonate area is the largest source of positive revisions for non-associated gas, but the dominance is not as clear-cut. Many other areas also show substantial volumes of positive revisions. The most surprising result in Table 13-3, however, is the continued large volume of negative revisions in the onshore Gulf area. Table 13-3 indicates that, with the exception of the onshore Gulf, revisions play a noticeable role in lower-48 gas reserve additions. As a result, if revisions are a good indicator of the effects of improved recovery of gas-in-place,then Table 13-3 implies that substantial volumes of gas reserves could be added as a result of infill drilling in producing fields. As in the case of oil, the carbonate-dominated areas may have a disproportionate share of the potential for improved recovery of gas-in-place. 13.4.2. Well data

Using the Dwight’s well history data, some detailed profiles of gas well recoveries can be developed. We have analyzed these well production profiles, correlating them with the year of discovery of the field in which they occur, the year of completion, and the section within which they were completed. Table 13-4 presents the trends in new gas wells drilled in the lower-48 states (ex the Appalachian states) correlated with the discovery date of the field in which they were drilled. Table 13-4 shows that onshore gas wells were predominantly drilled in fields that had been discovered prior to 1970. Even in the 1981-1985 period, almost two-thirds of the gas wells were completed in fields discovered before 1970. Therefore, the story of the improved reserve additions in the lower-48 states onshore area in the 1970s and 1980s is a story of drilling in rather old fields. The 1971-1985 reserve additions for the other fields can be assessed using the estimated recovery of gas from the wells that have been drilled between 1971 and 1985. Table 13-5 presents the estimated recovery for gas wells drilled between 1971 TABLE 13-4 Lower-48 gas wells by field discovery year (ex Appalachian states) (percentages) ~

Field discovery year

pre-1950 1950-1959 1960-1969 post-1969 a

Includes state waters.

~

1976-1980

~

1981-1985

onshore a

offshore

onshore a

offshore

42.6 18.1 11.2 28.1

4.9 12.0 21.6 61.5

38.5 16.9 10.6 34.1

3.0 15.6 23.3 58.0

TJ. WOODS TABLE 13-5 Recovery shares for new gas wells drilled from 1971 to 1985 (percent) State

Colorado Kansas Onshore Louisiana New Mexico Oklahoma Onshore Texas Wyoming Federal Offshore Gulf

Wells drilled in pre-1971 sections

pre-1971 fields

13 65 40 46 18 NA 13 NA

76 88 81 15 79 64 45 53

and 1985 for some selected regions. The recoveries presented are the shares of the total estimated recovery for gas wells in fields discovered prior to 1971 and for the sections in those fields that had been producing prior to 1971. Section data are not presented for Texas because Texas wells have no section data on a consistent basis and section data have limited value for the offshore. Table 13-5 shows that the overwhelming share of new recovery for gas wells completed between 1971 and 1985 was for gas wells completed in fields discovered prior to 1971. For example, in onshore Louisiana, 81% of the estimated ultimate recovery from gas wells completed between 1971 and 1985 was for wells completed in fields discovered prior to 1971. Only two locations, Wyoming and the Federal Offshore Gulf, show that comparable volumes of gas were recovered from wells drilled in pre-1971 fields and fields discovered from 1971 on. Surprisingly, Texas shows a much larger volume of gas recovered from wells drilled in fields discovered since 1971 than Oklahoma or Louisiana. When the wells are further restricted by the condition that the well also be drilled in a section that was producing before 1971, the results are quite surprising. The Kansas data show that the major share of the new recovery since 1971 was not only in fields discovered before 1971; it was in sections producing before 1971 in those fields. Thus, step-out drilling in pre-1971 fields was not a major contributor to recovery from wells drilled between 1971 and 1985 in Kansas. Onshore Louisiana and New Mexico also show a substantial contribution from pre-1971 sections, but only 40 to 50% of the new recovery. The rather intense drilling in the pre-1971 Louisiana sections occurs throughout the state; however, in New Mexico, the intense drilling in the pre-1971 sections is predominantly in the San Juan Basin. All the other states presented in Table 13-5 show that the major share of the new recovery was in step-out drilling into new sections (i.e., extension) of the pre-1971 fields, not more intensive drilling in pre-1971 sections in those fields. The estimated average recovery per new well (i.e., wells drilled between 1971 and 1985) in the pre-1971 sections was usually larger than the recovery per well in the sections drilled since 1971. Whether this was infill drilling or completions in

385

INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS

new zones in the section, the data indicate that the best recoveries were usually found in new completions in known sections, not step-outs from producing sections. Nevertheless, with the exception of a few locations, most drilling between 1971 and 1985 was in sections that were not producing before 1971. 13.4.3. Recovery per section

The potential for incremental gas recovery from producing sections as a result of more intensive drilling appears to be quite significant.A sense of the magnitude can be obtained by assessing the trends in gas recovery per section. Two areas will be considered because their potential seems to be quite large. They are Oklahoma and South Louisiana. 13.4.3.1. Oklahoma Figure 13-2 presents the trend in recovery per well as a function of the wells per section producing before 1971. The trend is taken out to nine wells per section. There are 8053 sections in this sample with 16,428 wells. The number of sections with only one well is 4088,51% of the total number of sections. Thirty sections have nine wells. In fact, 96 sections have ten or more wells per section, accounting for 9% of the 16,428 wells. Interestingly, the average recovery per well for these 96 sections is 33 x lo6 m3 (1.17 Bcf) per well, essentially the same as the average recovery per well observed for sections having from four to nine wells. The data in Fig. 13-2 show a steady decline in recovery per well as the well density grows to four wells per section. This is consistent with what one would expect as a result of more intensive drilling. After four wells, however, the pattern changes, and the recovery per well remains essentially constant at about 30 x lo6 m3 per well out to nine wells per section and even beyond. This is a very surprising

0

1

2

3

4

5

6

7

8

Well.IS.sUon

Fig. 13-2. Recovery versus well density, Oklahoma pre-1971 sections.

9

10

386

T.J. WOODS

I

0

1

2

3

4

5

6

7

0

Complellon./Sectlon

Fig. 13-3. Recovery versus completion density, pre-1971 Oklahoma sections.

result, and it indicates that a substantial incremental gas reserve could be added with more wells in a producing section. The data in Fig. 13-2 are presented on an areal extent. Thus, many sections with multiple wells could have the well completions separated by thousands of feet. Accordingly, the data in Fig. 13-2 were further disaggregated into 5000 ft depth intervals (1524 m) to analyze the extent to which some of the patterns in Fig. 13-2 might reflect multiple wells at very different depth intervals that would not even be in the same formation or field. In this analysis, the recoveries were sorted by completion, however, not well. Thus, if a well were completed in the 10,000-15,000 ft interval and below 15,000 ft, the data sort would count it as a completion in each section. The results of the division into depth intervals are shown in Fig. 13-3. The recovery per well is taken out to the point at which there are at least ten sections with that number of wells. Figure 13-3 shows that the fall-off in the 0-5000 ft interval is qualitatively like the aggregate trend in Fig. 13-2. The stabilized recovery per well is about 30% of the recovery per well in the sections that have only one well. However, the fall-off in recovery per well is over by three wells per section instead of four as in the total Oklahoma picture. The 5000-10,000 ft interval shows a stabilization at two wells per section at about 40% of the recovery of the sections in which only one well was drilled. The 10,000-50,000 ft interval at three wells per section has a recovery of about 40% of the one well per section average recovery. Below 15,000 ft, there are only four pre-1971 sections with two wells per section, so no data are shown. The stabilization in recovery rate, particularly above 10,000 ft, further indicates a substantial potential for increased recovery as a result of more intensive drilling in the pre-1971 sections. The significance of this potential is supported by the fact that

387

INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS

the average recovery per well in the pre-1971 sections has remained relatively stable for wells drilled since 1976 for all depth intervals above 15,000 ft.

13.4.3.2. South Louisiana Figure 13-4 presents the trends in recovery per gas well in South Louisiana for the sections producing before 1971 and sections that began producing between 1971 and 1985. Figure 13-4 shows another very surprising result. The recovery per section for the pre-1971 sections increases slightly as the number of wells drilled per section increases. This growth, however, is due to the concentration of the highly drilled sections in the 10,000-15,000 ft interval. Overall, the recovery is fairly constant at about 180 x lo6 m3 (6.4 Bcf) per well, regardless of the drilling density. It should be noted that 121 sections of the 2521 pre-1971 sections in South Louisiana have ten or more wells, accounting for more than 20% of the wells drilled in the pre-1971 sections. The average recovery per well in these 121 sections is about 170 x lo6 m3 (5.94 Bcf). The 1971-1985 sections show a slight decline in recovery as the well density increases; at best the recovery per well might be said to remain constant as less than 85 x lo6 m3 (Bcf) per well. It should be noted that about an equal number of wells were drilled in the pre-1971 and the 1971-1985 sections. As in the case of Oklahoma, the onshore South Louisiana data were distributed among drilling depth intervals. Figure 13-5 presents the results of this analysis. The 0-5000 ft interval is not shown due to the limited number of wells and the highly variable recovery per well in this interval. Figure 13-5 shows the same basic patterns observed in Fig. 13-4. The recovery per completion even increases in some cases as the completion density increases. The recovery per well for the 5000-10,000 ft interval is fairly constant up to eight wells

m150

-

1w

-

50-

0 0

1

2

3

4

5

6

7

8

W I s psr wctlon

Fig. 13-4. Recovery versus well density onshore South Louisiana.

9

10

388

TJ. WOODS

0

1

2

3

4

5

6

7

8

9

10

Completions per aeetlon

Fig. 13-5. Recovery versus completion density, onshore South Louisiana pre-1971 sections,

per section. The 10,000-15,000 ft interval shows a noticeable increase in recovery per completion for the sections with four or more completions averaging about 225 x lo6 m3 (8 Bcf) per well, compared to 170 x lo6 m3 (6 Bcf) per well for the one- to three-completion sections. Below 15,000 ft, the recovery per well fluctuates noticeably.

13.5. CONCLUSIONS

The analysis indicates that a substantial gas resource potential remains to be recovered in known lower-48 fields as a result of the improved recovery of oil-in-place or more intensive drilling in currently producing sections. The incremental gas resource associated with increased recovery of oil-in-place appears to be mostly in carbonate reservoirs. The potential in sandstone reservoirs appears to be more modest. The carbonate/sandstone distinction appears to also have some importance when considering reserves in gas reservoirs, but it does not appear as important as for associated gas. The analysis of incremental gas resources for a well basis using the density of wells per section indicates that geological conditions of the type found on the Gulf Coast in onshore Louisiana and Texas could have the largest incremental potential arising from increasing the drilling density in producing sections. With the exception of Louisiana, Kansas, and Northwest New Mexico, more intense drilling in producing sections appears to have played a smaller role in drilling activity than step-out drilling to new sections. This is despite the fact that, with few exceptions, the recovery per well in the new sections was poorer than the recovery per well in the pre-1971 sections; sometimes noticeably poorer.

INCREMENTAL GAS RESOURCE POTENTIAL IN KNOWN FIELDS

389

REFERENCES Fisher, W.L., 1987. Can the U.S. oil and gas resource base support sustained production? Science, 236 (4809): 1631-1636. vier, N., Galloway, W.E., Garret, C.M., Jr. and Ewing, TE., 1984. Oil accumulation, production characteristics, and targets for additional recovery in major oil reservoirs of Texas. Bur: Econ Geol., Univ. T m s at Austin, GeoL Ck.,84-2.

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Studies in Abnormal Pressures. Developments in Petroleum Science, 38 edited by W.H. Fertl, R.E. Chapman and R.F. Hotz 8 1994 Elsevier Science B.V. All rights reserved

391

Chapter 14

DISTRIBUTION OF HYDROCARBONSIN ABNORMAL PRESSURE IN SOUTH LOUISIANA, U.S.A. WILLIAM G . LEACH

14.1. INTRODUCTION

Most hydrocarbon accumulations are associated with the top of abnormal pressure in clastic sedimentary basins. This is particularly true in the Tertiary sands found along the Louisiana gulf coast. Below the top of abnormal pressure, hydrocarbon distribution is consistently decreasing with increased pressure and temperature. At a pressure gradient of about 0.85 psi/ft (19.2 kPa/m) and/or in a temperature environment of 350°F (450 K), most hydrocarbons are beginning to disappear. Furthermore, the hydrocarbons did not originate in Upper Tertiary sediments. Lower Tertiary, Cretaceous, and older sediments were probably the source of most of the hydrocarbons. These conclusions are based on new insight into the migration and distribution of hydrocarbons utilizing computerized pressure, production, and temperature databases. Analyses of this vast volume of data, when combined with geochemical data and geological and engineering principles, indicate that the hydrocarbons pulsated up from their deep-seated source through Upper Tertiary sediments to near the top of abnormal pressure. Production distribution studies show that hydrocarbons are predominantly concentrated near the top of abnormal formation pressure regardless of depth, temperature, or lithology. Although there is an optimum depth and temperature for both gas and oil, the temperature distribution relationship is believed to be secondary. Depth (including lithology) and temperature directly affect pressure, which in turn directly affects hydrocarbon distribution. Depth and temperature primarily affect the molecular composition of the prevailing hydrocarbons (e.g., gas, light oil, or heavy oil). These findings come from a study of over 32,000 wells that produced 71 Tcf (2.0 x 1OI2 m3) of gas and 5.5 Bbbl(875 x lo6 m3) of oil. Knowledge gained from this study should substantially change the approach to future exploration programs in most clastic sedimentary basins similar in origin to the south Louisiana Tertiary.

14.2. TOP OF ABNORMAL PRESSURE

The top of abnormal pressure is the depth where the existing formation pressure gradient exceeds that of a normal hydrostatic gradient of saltwater. A normal hydrostatic head of saltwater is generally assumed to have a 0.465-psi/ft (10.5kPa/m) gradient. Any pressure gradient exceeding this 0.465 psi/ft (10.5 kPa/m)

392

W.G. LEACH

would, theoretically, be abnormal. As a practical matter, it is not realistic to work in terms of an exact 0.465-psi/ft (lOS-kPa/m) gradient. Changes in formation pressure gradients are often very subtle and hard to determine, particularly from an economic standpoint. Therefore, abnormal pressure must be defined through readily available parameters. Such parameters are mud weights, low-density shale tops from electric logs, and geophysical formation velocity data. Mud weights and low-density shale tops were used in this study to represent the top of abnormal pressure. It is not the purpose of this chapter to discuss the causes of abnormal pressure. Most authors agree that abnormal pressure is caused by a combination of (1) mechanical compaction, (2) thermal expansion (aquathermal and isothermal), and (3) second-stage clay dehydration. Abnormal pressure, up to an overburden gradient of 1.O psi/ft (22.6 kPa/m), is probably caused primarily by mechanical compaction. Chapman (1980 and this volume, pp. 81-84) believes that most abnormal pressure is related to mechanical compaction. However, the incremental pressure or pressure in excess of a 1.0 psi/ft (22.6 kPa/m) gradient is believed to be caused by thermal expansion of fluids. The increase in sand and shale porosity in the deep abnormally pressured formations certainly seems to substantiate the presence of this internal force. The mapping correlation of regional isotherm with top of abnormal pressure provides further evidence that abnormal pressure is related to thermal expansion. Also, maps prepared on the top of massive shales show good correlation trends with both temperature and abnormal pressure. Because shale, which is a good insulator, holds heat longer than sand, there is a three-way relationship between lithology, temperature, and abnormal pressure. Regional maps prepared on the top of abnormal pressure or a particular temperature isotherm can be used to ascertain areas of better sand quality (Leach and Fertl, 1990).

14.3. HYDROCARBON DISTRIBUTION VERSUS TOP OF ABNORMAL PRESSURE

The bulk of all hydrocarbons is concentrated near the top of abnormal pressure zones (Fig. 14-1). Depth of production in this study ranged from 2000 ft (610 m) to 22,000 ft (6706 m). Approximately 5.1 Rbbl (8.1 x lo9 m3) of oil and 69.0 Tcf (1.93 x 10l2 m3) of gas from 21,300 wells was produced within this distribution framework (Table 14-1). This distribution represents about 97% of all the gas and 93% of all the oil produced from the Tertiary sands of onshore south Louisiana since 1965. The distribution of hydrocarbons in relation to the top of abnormal pressure was determined through the use of a special computer program. The program consisted of an imaginary 10,000-it (W in) window shnx:, i c Table 14-1. Each of the 21,300 wells was reviewed for production within the imaginary window. The center of the window or midpoint was always positioned at the depth of abnormal pressure in each well. The window had ten 1000-ft (305-m) compartments. Five 1000-ft (305-m) fi--- '000-ft (30c IT) comDartner.i- (negative) wf-p 'wvr m i d w i n t :! :' T > ' ' - P ~ .

393

DISTRIBUTION O F HYDROCARBONS IN ABNORMAL PRESSURE

5

,

0

5

10

15

20

25

Cumulative Production (Yo) Fig. 14-1. Hydrocarbon distribution (best curve fit) versus onset of abnormal pressure based on oil and gas production from 25,204 wells, south Louisiana Tertiary. Depth range: 2000-22,000 ft (610-6710 m). TABLE 14-1 Production versus onset of abnormal pressure (21,300 wells)

Depth (fi) (m)

-

Oil (Mbbl)

Gas (MMcf)

Oil

Gas

(%I

- 5,000

- 1524

370,581

1,245,451

7.33

1.80

-4,000

-1219

526,299

2,248,541

10.42

3.25

-3,000

-914

737,466

4,915,273

14.60

7.10

(0

$ 0

a

t 1

3

z

-610

1,169,760

10,888,850

23.15

15.73

-305

1,157,659

17,466,810

22.91

25.23

16,353,638

11.88

23.62

(0

m

g g 5 -2

-2,000 -1,OOO

1.000

305

600,392

2.000

610

263,592

8,513,015

5.22

12.30

3,000 4,000

914 1219

142,022

4,670,146

2.81

6.75

48,948

1,855,328

0.97

2.68

5,000

1524

35,862

1,079,735

0.71

1.56

Totals

5,052,581

69,236,787

100.00

100.00

394

W.G. LEACH

compartments (positive) were below midpoint in the window. Production from each well evaluated was placed in the proper compartment or interval above or below the top of abnormal pressure. The top of abnormal pressure depth came from a 12,000 well database. This database was used to map the top of abnormal pressure. The computer program was designed to project the depth of abnormal pressure from a grid system into each well. This was the top of abnormal pressure that the imaginary window was centered upon. Abnormal pressure as used here is defined as the top of low-density shale. This is the first shift of the shale resistivity on the short normal resistivity curve already discussed. As can be seen in both Fig. 14-1 and Table 14-1, gas production near the top of abnormal pressure shows an almost perfect bell-shaped distribution. Oil production is concentrated slightly above the top of abnormal pressure. Almost half of the oil production, 46.1%, was produced within a 2000-ft (610-m) interval immediately above the top of abnormal pressure. Approximately half of the gas production, 48.9%, came from a 2000-ft (610-m) interval centered at the top of abnormal pressure. Even at an isolated depth environment, hydrocarbon distribution is still associated with the top of abnormal pressure (Fig. 14-2). Production distribution

I

0

5

I 10

I

15

I 20

I

I

I

25

30

35

415 40

Cumulative Production ( o h )

Fig. 14-2. Hydrocarbon distribution (best curve fit) versus onset of abnormal pressure based on oil and gas production from 1095 wells, south Louisiana Tertiary. Depth range: 14,000-15,000 ft (4270-4575 m).

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

395

associated with the top of abnormal pressure is shown in Fig. 14-2 for 1095 wells completed between 14,000 ft (4267 m) and 15,000 ft (4572 m). Approximately 8.3 Tcf (232 x lo9 m3) of gas and 244 million barrels of oil were produced from this depth interval. Peak distribution for both oil and gas, however, is concentrated slightly below the top of abnormal pressure. The change in hydrocarbon distribution with increased depth is believed to be due to a change in the fracture gradient. This observation, another important finding in the study, merits further discussion. The consistent bell-shaped distribution of hydrocarbons near the onset of abnormal pressure is considered a major geological discovery. Based on an extensive library computer search, this is the first time that a hydrocarbon distribution study of this type and magnitude has ever been made. There have been numerous hypotheses about hydrocarbons being associated with abnormal pressure. In fact, there have been several small studies, but actual production data has never been correlated with the top of abnormal pressure over any significant area. Burst (1969) related the number of increased well completions in south Louisiana to the top of second-stage clay dehydration. Scharr (1976) studied 24 wells in the Baram Delta, offshore Malaysia, in which he concluded that the production was associated with the top of abnormal pressure. Ashirmamedov and Khadzhinusov (1980) presented a plot of the percentage of gas and oil production versus pressure gradient for Pliocene sands in the West-Turkmen basin in Turkmenistan. The plot showed both oil and gas to be related to the top of abnormal pressure. The amount of production was not indicated. Dow (1984) noted a number of authors observed that most oil production occurred in the transition zone between hydropressured and geopressured sediments. However, in all cases except our study, no actual production volumes were documented of having been statistically correlated with the top of abnormal pressure. Findings in this study should substantiate for the first time that the preponderance of all hydrocarbons are associated with the top of abnormal pressure in clastic sedimentary basins. Although this study covers only the Tertiary sands along the Gulf of Mexico, the results should apply to other clastic basins. The application to other sedimentary basins is further supported by the Baram Delta and the West-Turkmen basin studies. Future exploration potential utilizing this production distribution information should be substantial.

14.4. HYDROCARBON DISTRIBUTION DECREASES WITH INCREASED PRESSURE

Gas distribution at the onset of abnormal pressure (Fig. 14-3A) is compared to that at the onset of 1/2-ohm shale (Fig. 14-3B).A major reduction in gas distribution has occurred in this abnormally high-pressured environment. In Fig. 14-3A, about 50% of the gas is found below the onset of abnormal pressure (Table 14-2). Gas distribution found below the onset of 1/2-ohm shale has dropped to 16% (Fig. 14-3B). This was one of a number of indications that hydrocarbons were beginning to disappear at higher reservoir pressures. Oil production distribution at the onset of abnormal pressure (Fig. 14-4A) is also compared to oil distribution

396

W.G. LEACH Distance Above (100 rn)

-15

- 10

-5

I

I

Distance Below (100 rn)

0

I

Distance Above (1,000 ft)

5

10

15

I

I

I

Distance Below (1,000 fi)

I

B

I

Distance Above (1,000 ft)

Distance Below (1,000 ft)

Fig. 14-3. (A) Gas production versus onset of abnormal pressure (21,300 wells). (B) Gas production versus onset of 1/2-ohm shale (18,274 wells).

at the top of l/Zohm shale (Fig. 14-4B). As would be expected, liquids are also beginning to disappear with increased formation pressure. The incremental effects of increased pressure on hydrocarbon distribution is best shown through the utilization of increasing mud weights (Leach and Fertl, 1990). An analysis was made of production distribution versus different mud weight selections (Table 14-3). Four of these mud weights are shown in Fig. 14-5. Figure

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

397

TABLE 14-2 Production versus onset of 1/2-ohm shale (18,274 wells)

Depth (ft)

(m)

Oil (Mwl)

Gas (MMc9

Oil

Gas

(W

(W

-5,000

-1524

592,372

4,454,491

14.35

6.77

-4,000

-1219

937,017

7,551,393

22.69

11.48

-3,000 -2,000

-914 -610

945,599 756,602

11,692,525 15,952,091

22.90 18.32

17.78 24.25

- 1,000

-305

504,911

15,497,783

12.23

23.56

:

1,000

305

203,392

6,175,263

4.93

9.39

E

3.66

$ 5

2*ooo 3,000

a

Q)

2 q 0 3 2 t I 1

Q

-

610

109,316

2,407,774

2.65

43,163 23,530

995,897

1.05

1.51

4,000

914 1219

718,682

0.57

1.09

5,000

1524

12,900

328,176

0.31

0.50

Totals

4,128,802

65,774,075

100.00

100.00

14-5A, 12.5 lblgal (14.7 kN/m3) mud, shows 49% of the oil and 58% of the gas concentrated below the onset of this mud weight. Figures 14-5B and 14-5Cshow a modest decline in both oil and gas production. But, a significant drop is seen in hydrocarbon distribution below the top of 18.0-lb/gal (21.2-kN/m3) mud (Fig. 14-5D). Only 17% of the oil and 24% of the gas remains below the top of this 18.0lb/gal (21.2-kN/m3) abnormal pressure environment. It should be emphasized that although hydrocarbons are beginning to disappear in an abnormally high-pressured environment, the wells still averaged good production at higher depths. In other words, the preponderance of all hydrocarbons remains concentrated near the top of abnormal pressure but not in the vicinity of 18.0-lb/gal (21.2-kN/m3)mud. Gas production distribution plots associated with six different mud weights are superimposed over each other to further illustrate the relative effects of increased pressure (Fig. 14-6). All six plots show that the bulk of gas production is concentrated at some point in relation to that particular mud weight. A decrease in gas production is observed as you move away from this point, either below or above. In other words, there is an optimum zone of concentration for the occurrence of gas as a function of a particular mud weight or abnormal pressure. For example, in Fig. 14-6, assuming a minimum gas distribution chance of lo%, a well should not be drilled more than 1200 ft (366 m) below the top of 18.0-lb/gal (21.2-kN/m3) mud. Wells drilled 2500 ft (762 m) below the top of 18.0-lb/gal (21.2-kN/m3) mud statistically would contain no reserves. However, a well drilled 2500 ft (762 m) below the top of 12.5-lb/gal (14.7-kN/m3)mud would still be in the 10% gas distribution range.

398

W.G. LEACH

' \ I I I

I

Distance Above (1,000 11)

1

Distance Below (1,000 h)

Distance Above (100 m) -15

-10

-5

I

I

Distance Above (1,000 R)

Distance Below (100 m)

0

I

5

10

I

I

15

I

1

Distance Below (1,000 h)

Fig. 14-4. (A) Oil production versus onset of abnormal pressure (21,300 wells). (B) Oil production versus onset of 1/2-ohm shale (18,274 wells).

The percent gas and oil production found in wells below a particular mud weight ranging from 10.5 lb/gal to 19.0 lb/gal (12.3 kN/m3 to 22.3 kN/m3) can best be shown in Fig. 14-7. Production data for the four additional mud weights used in

399

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE TABLE 14-3

Distribution of oil and gas production versus onset of overpressures, number of wells, and several mud weight cutoffs in 139 South Louisiana fields 11.5 lbrnlgal (13.5 kN/mt) Mud (3140 Wells)

10.5 lbrnlgal (12.3 Wlm*) Mud (4101 Wells) Depth Cftl (ml

o

-5.000 -4.000 -3,000 0 c -2,000

55 4

1 f

-

1

g

-1.000

-1524 -1219 -914 -610 -305

Oil (MW

Gas WMa)

3,018 5,701 12.515 49,783 130,675

31,307 196.853 275.784 956,961 2,515,436

Gas

011 (%)

(W -0.2 1.5 2.1 7.1 18.7

0.6 1.1 2.5 9.9 25.9

; 0

305 610 914 1219 1524

101,594 82,041

3,129,704 2,658.490 53.090 1,768.379 43,582 1,256,646 637.231 22.087

1 1

23.3 19.8 13.2 9.4 4.7

20.2 16.3 10.5 8.6 4.4

Totals 504,086 13,426,791 100.0 100.0

1

-1524 -1219 -914 -610 -305

2,514 4,574 13.090 45,253 114.874

66.878 208,835 371,940 1,134,759 3,182.961

-5,000 -4.000 -3.000 -2.000 -1.000

-1524 -1219 -914 -610 -305

011

W W

Gas

Oil

Wd)

(W

2.344

32.903

4,695 12,663 44.649 122,080

175,575 338.376 1,083,491 2,874.661

305

88,913 43,970 44,439 27.090 17.292

3,591.005 1,817.941 1,321,211 690,725 512.792

610

914 1219 1524

Gas

(W -

0.6 1.2 3.1 10.9 29.9

0.3 1.4 2.7 8.6 22.7

21 .a 10.8 10.9 6.6 4.2

28.4 14.4 10.5 7.0 4.1

--

Totals 408,134 12.638.679 100.0 100.0

14.0 Ibrn/gal (16.5 kNlm*) Mud (2076 Wells)

0.6 1.8 3.2 9.6 27.0

0.7 1.3 3.7 12.7 32.3

1,000 2,000 3.000 4.000 5,000

I

12.5 Ibm/gal (14.7 kN/rna) Mud (2565 Wells)

-5.000 -4,000 -3.000 -2.000 -1.000

Depth (m)

~

~

1,000 2~~ 3.000 4,000 5.000

(fib

1

-5.000 -4,000 -3.000 -2.000 -1,000

-1524 -1219 -914 -610 -305

2,317 4,044 14,726 47,200 90,421

69,548 223,503 453,255 1,179,458 3.128.840

0.8 1.4 5.1 16.2 31.0

0.6 2.1 4.2 11.0 29.2

70.289 29,349 17,505 6,631 9,028

3,050,078 1.398.685 600,457 327,602 286.970

24.1 10.1 .6.0 2.3 3.1

28.5 13.0 5.6 3.1 2.7

~

1

1,000 2,000 3,000 4.000 5.000

305 610 914 1219 1524

81.931 36,739

32.634 13.884 9.849

3,249,619 1,612,806 1,013,700 572,771 374.172

Totals 355.341 11.788.440

23.1 10.3 9.2 3.9 2.8

1

27.6 13.7 8.6 4.9 3.2

100.0 100.0

I

Oil (MW

Gas

Oil

Gas

Wcr)

(W

(W

1 1

-5.000 -4,000 -3.000 -2,000 -1.000

-1524 -1219 -914 -610 -305

2,414 5.258 16.370 37.816 61,219

109,365 265,182 522.016 1,094.766 2.358.590

1.1 2.4 7.5 17.3 28.0

1.3 3.1 6.0 12.6 27.2

1,000 2.000 3.000 4,000 5,000

305 610 914 1219 1524

45.882 25,736 10,625 4,832

2,302,005 1,184,528 433,568 183,742 226,220

21.0 11.8 4.9 2.2 3.8

265 13.6 5.0 2.1 2.6

8.338

Totals 218.491

8.679.981 100.0 100.0

305 610 914 1219 1524

Totals 291.510

10.718.395 1W.O 100.0

18.0 Ibmfgal (21.2 kNlrn3) Mud (378Wells)

16.0 lbrnlgal (16.8 kNlm*) Mud (1543 Wells) Depth (fi) (m)

1,000 2.000 3.000 4.000 5.000

Depth (11) (m)

1 1

-5.000 -4.000 -3.000 -2.000 -1.000

1,000 2.000 3.000 4.000 5.000

011

(MW

Gas WMa)

a1

Gas

(W

(W

2,511 3.007 5.840 17,034 20.161

51,619 162.146 354.993 690.151 721,369

4.3 5.1 9.9 29.0 34.3

2.0 6.2 13.6 26.4 27.5

305 610 914 1219 1524

7.648 2,202 0 0

436,935 172.360 0 0 28,897

13.0 38 0.0 00 0.5

16.7 6.6 0.0 0.0 1.1

Totals

58.703

-1524 -1219 -914 -610 -305

299

2.618.469 100.0 100.0

Fig. 14-7 are found in Table 14-4. These two distribution plots show that below 17.5lb/gal (20.6-kN/m3) mud, hydrocarbons are beginning to disappear rapidly and are almost non-existent at a 19.0-lb/gal (22.3-kN/m3) mud environment. This is not to say that all the wells drilled below a 19.0-lb/gal (22.3-kN/m3)mud environment were

400

W.G. LEACH

--15

-5

B

2 0

0

--lo P

9 0

--5

5

VI .-

n -0

0 E

0

-5

6 m m

-Oil

-10

---Gas

Cumulative Gas Production ( O h )

VI -

n

12.5Ib/gal (14.7 kN/mJ) mud 2,565wells

5-

1

I

I

0

10

20

30

m

a m

715 40

Cumulative Gas Production (%) 140 Ib/gal (16.5kN/rn3) mud 2.076wells

t Cumulative Gas Production ( o h )

16.0 lblgal (18.8kN/m3) mud 1.543 wells

Cumulative Gas Production (%) 18.0 Ib/gal (212 kNlrn3) mud 378 wells

Fig. 14-5. Hydrocarbon distribution based on 139 south Louisiana Tertiary fields versus distance above and below the onset of abnormal pressure at four different mud weight cutoffs.

+ Fig. 14-7. Oil and gas production distribution versus mud weight and pressure gradient in 139 south Louisiana Tertiary fields.

401

DISTRIBUTION O F HYDROCARBONS IN ABNORMAL PRESSURE Distance from Abnormal Pressure (100 m)

lo Distance from Abnormal Pressure (ft)

Fig. 14-6. Gas production distribution based on 139 south Louisiana Tertiary fields versus distance above and below the onset of abnormal pressure at several mud weight cutoffs. 12 1001

--s EO -

Mud Weight (kNIm3) 16 10 I I

14 1

20 I

90-

+

22 I

Oil Gas

70-

U

._

g

e

-5

30-

e

20-

a"

10-

0

a

0 - ' 10

I 11

'

12

I 0.5

1

I 12

'

I 13

'

I

'

Gradient (kPalm) 16 10

14 I 0.6

I ' 15I 14 Mud Weight (Iblgal)

I

I I

I

0.7

Gradient (psim)

0.0

16

17

10

20 I 0.9

22 I

1 .o

402

W.G. LEACH

TABLE 14-4 Distribution of oil and gas production versus onset of overpressures, number of wells, and four mud weight cutoffs in 139 South Louisiana fields 17.0 Ibm/gal (20.0 kN/ma)Mud (988Wells)

:5

9 0z 1

-

f

1 F

42 m

-5,000 -1524 -4.000 -1219 -3,000 -914 -610 -2.000 -1,000 -305 1.000 2.000 3.000 4.000 5.000

173 lbmlgal (20.6 kN/m’) Mud (701 Wells)

1.824 4,051 10,500 29.382 39,452

118.463 13 28 238.137 314.448 73 1,162,755 205 1,827,036 275

20 39 52 193 303

-5.000 -4,000 - 3,000 - 2.000 1 -1.000

305 610 914 1219 1524

35,228 9,033 4,349 6,831

1,550,989 246 364.360 63 223,878 3 0 170.790 48 19 64,909

25 7 60 37 28

1

Totals

143.427

2.777

11

6,035,765 1000 1000

-5.000 -1524 -4.000 -1219 -3.000 -914 -2.000 -610 -1.000 -305

1

1.000 2.000

3.000 4.000 5.000

Depth (W (m)

IMbbl)

305 610 914 1219 1524

1,320 359 297 0

Totals

20,958

1

23,721 14 122,890 89 249.955 195 392.783 333 201,056 274

21 109 223 350 179

63 17 14 00 00

65 28 25 00 00

72,937 30.996 28.469 0 434

3.002 4,144 8,534 17.734 30.842

103,588 30 251,323 41 407,480 8 5 697,945 176 1272.130 306

24 59 95 163 298

21,674 1,066,934 21 5 8,989 304,022 8 9 44,521 1.829 18 3.867 95,624 3 8 300 28,922 0 3

250 71 10 22 07

100,914 4,272,489 100.0 1000

19.0 Ibm/gal(22.3 kN/ma)Mud (28Wells)

Oil

303 1.875 4,086 6.978 5,739

305 610 914 1219 1524 Totals

18.5 Ibm/gal(21.7kN/mr)Mud (145 Wells) Depth (fi) (m)

1.000 2.000 3.000 4.000 5.000

-1524 -1219 -914 -610 -305

1,123,242 100.0 100.0

-5.000 -1524 - 4 w -1219 - 3.000 -914 -2.000 -610 -1.000 -305

1

1.000 2.000

3.000 4,000 5.000

Oil (MbW 131 948

214 2.009 330

305 610 914 1219 1524

25 53 0 0

Totals

3,709

1

Gas (MMcfl

011

10.865 35 81,003 256 2.004 58 81.222 542 1,341 8 9 1.078 76 0 0 10

Gas

(9 (W

07 14 00 00 00

61 456 1 1

457 08 06 00 00 00 00

177,600 1W.O 100.0

uneconomical. The wells averaged over 800,000 barrels (1270 m3) of oil equivalent (BOE) per well. However, as already discussed, the bulk of this production came from near the onset of abnormal pressure, not in the deeper 18.0-lb/gal (21.2-kN/ m3) mud environment. The main point here is that hydrocarbons are beginning to disappear at a driller’s mud weight of 17.5 lb/gal (20.6 kN/m3). A statistical study of deep wells in south Louisiana has shown that the driller’s mud weight exceeds the calculated pore pressure mud weight by more than 1.0 lbigal (1.2 kN/m3). If it is assumed that the average driller’s mud weight in Fig. 14-7 is 1.0 lb/gal (1.2 kN/m3) in excess of the required weight, it can be concluded that there is a major reduction in hydrocarbon concentration beginning to occur at a pore pressure mud weight of 16.5 Ib/gal (19.4 kN/m3). The 16.5-lb/gal (19.4-kN/ m3) mud is equivalent to a pressure gradient of about 0.85 psi/ft (19.23 kPa/m). Therefore, the probability of encountering economical production in a pressure gradient environment of 0.85 psi/ft (19.23 kPa/m) would be extremely low. These conclusions are in line with earlier observations by Fertl and Leach (1988) in their study of wells completed below 18,000 ft (5486 m).

403

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE 14.5. HYDROCARBON DISTRIBUTION VERSUS DEPTH AND TEMPERATURE

Hydrocarbon distribution was first evaluated in terms of depth. Based on the analyses of almost 33,000 wells that produced 5.5 billion barrels (880 x lo6 m3) of oil and 71 Tcf (1.99 x 10l2 m3) of gas, it was concluded that there is an optimum depth for both oil and gas (Table 14-5). Oil is concentrated at 8500 ft (2591 m) (Fig. 14-8). The maximum gas production is found at about 11,000 ft (3353 m) (Fig. 14-9). The relationship of hydrocarbon distribution to depth is due to the relation of the top of abnormal pressure to depth. Although the top of abnormal pressure in south Louisiana ranges from 4000 ft (1219 m) to over 20,000 ft (6096 m), the average top of abnormal pressure is at about 11,000 ft (3353 m). In Fig. 14-1, the maximum distribution of oil is encountered at about 2000 ft (610 m) above the top of abnormal pressure. The maximum distribution of gas was centered near the top of abnormal pressure at 11,000 ft (3353 m). Therefore, in Figs. 14-8 and 14-9, hydrocarbons are related to depth in terms of the average depth of abnormal pressure. TABLE 14-5 Cumulative production from 32,939 wells drilled since 1965 in South Louisiana Tertiary sands ~~

Interval

(fi)

(m)

Number of Wells

Cum. Gas

Cum. Liq.

(Mc9

(W

Cum. Water (bW

2.000-3.000

600-900

1.454

141,062,259

57,060,243

338.483.525

3,000-4.000

900-1200

1.415

159,049,516

102,013,713

377.076.877 622,582.207

4.000-5.000

1200-1500

1,681

230,578.783

170,258,492

5.000-6,000

1500-1800

1.71 1

328,422,666

239,862,723

877.568,344

6,000-7.000

1800-2100

2,114

700,433,054

359,435,391

1,595,503,675

7,000-8.000

2100-2400

3,086

1,470,566,355

692,467,007

2,913,963,921

3,726,676,438

743.027.236

2,770,456,221

8.000-9.000

2400-2700

3.790

9.000-10,000

2700-3100

4,197

6,802,856,426

721,594,964

2,620,755,244

1O.OOO-11.000

3100-3400

4,176

10,849.697.352

700.832.939

1,979,200,977

11.000-12.000

3400-3700

3,253

12,064,742,978

479,600,442

1,204,231,550

12.000-13,000

3700-4000

2.158

11,269,734,333

383.395999

706,190,086

13.000-14.000

4000-4300

1,658

7,165,400,363

362,252.978

505,742,363

14.000-15.000

4300-4600

1,049

8,095,506,683

229,338.047

323,011,213

15.000-16.000

4600-4900

693

5,094,232,423

153,650,781

206,999,832

16.000-17,000

4900-5200

277

1,776,194,710

75,004,885

53,057,931

17.000-18.000

5200-5500

141

782,162,599

28.329227

21,386,016

18,000-19.000

5500-5800

53

190.592.184

13,387.955

4,629,306

19.000-20.000

5800-6100

24

78.477,772

8,971,555

3,705,846

20,000-21.000

6100-6400

3

7.689.235

1.758.393

123,402

21.000-22.000

6400-6700

6

3.51 1,460

211.176

876

32,939

70.947.587.589

Totals

5,522,462,146

17.324.689.412

404

W.G. LEACH

7

-

-2

-3

-E 0

8

I

-4

g 6

-5

-6

0

200 400 600 Cumulative Liquids (million bbl)

800

Fig. 14-8. Liquid distribution versus depth in south Louisiana Tertiary sands (Fertl and Leach, 1990).

Since temperature is also a function of depth and the prevailing geothermal gradient, it was further concluded that hydrocarbon distribution is an indirect function of temperature (Fertl and Leach, 1990). The optimum temperature for oil and gas production in one of the most prolific producing areas of south Louisiana is shown in Figs. 14-10 and 14-11. Data in these two figures are based on production of 1.3 billion barrels (210 x lo6 m3) of oil and 5.4 Tcf (151 x lo9 m3) of gas from ten fields in the Terrebonne Bay area (Table 14-6). The area had an average geothermal gradient of 1.2”F/100 ft (22 Wkm). Seventy-five percent of the oil was found between 160 and 240°F (344-389 K). Seventy-five percent of the gas was found between 200 and 260°F (366-400 K).

14.6. HYDROCARBON DISTRIBUTION DECREASES WITH INCREASED TEMPERATURE

Gas and oil production decreases with increased temperature below 140°F (333 K) (Figs. 14-12 and 14-13). The amount and percent of oil and gas production found above and below each temperature level is shown in Table 14-7. Data in Table 14-7 were determined by the same computerized 10,000-ft (3048-m) window program used in obtaining production associated with abnormal pressure. The distribution

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

01

2

02

03

405

04

3

1

4

5 6

2

7

8 9

8-

12

g 0"

13 14

r

10

3

-E Es-

4

z 0

11

15 16 5

17

18 19

6

20 21

22 0

3

6 9 Cumulative Gas (Tc9

12

15

Fig. 14-9. Gas distribution versus depth in south Louisiana Tkrtiary sands (Fertl and Leach, 1990).

plot for gas in Fig. 14-12 also indicates an optimum temperature interval, but the most important finding in this particular analysis is that hydrocarbons are definitely decreasing with increased temperature. Source of the temperature data utilized in this analysis is from mud temperature on openhole electric logs (Tenroc Data Base, owned by Petroleum Information, Houston, Texas). No correction was made for mud temperature. Depth of all of the production is between 2000 ft (610 m) and 22,000 ft (6706 m). As previously discussed, the reduction in hydrocarbons with increased temperature is believed to be an indirect relationship. Temperature affects pressure, which in turn directly affects hydrocarbon distribution. Pressure is related to temperature and temperature is related to lithology and depth. The three-way relationship between lithology (depth), temperature, and pressure should always be kept in perspective. Lithology and temperature determine the magnitude of formation pressure. Formation pressure controls the migration and accumulation of hydrocarbons through gravity and fluid expansion. Although secondary in terms of actual physical reservoir parameters, there is still an optimum temperature for hydrocarbons. Analyses of hundreds of reservoirs in the Terrebonne trough area (Terrebonne Parish, Louisiana) indicate that temperature primarily determines the type of hydrocarbons (i.e., oil, gas, or gas condensate) encountered at a particular depth.

406

W.G. LEACH

104116128140152164176188200p 2128 224FE 236248260272 284 296-

g

~

308320 332 0

3

6

9

1

2

1

5

Fig. 14-10. Oil production distribution versus temperature in ten major south Louisiana Tertiary fields (Fertl and Leach, 1990).

For example, in the Caillou Island field, one of the largest oil and gas fields in onshore Louisiana, most reservoirs contain oil to a depth of 10,000 ft (3048 m). Reservoirs between 10,000 and 15,000 ft (3048 and 4572 m) contain both gas caps and oil columns. Between 15,000 and 18,000 ft (4572 and 5486 m), the gas cap occupies about 80% of the reservoir. Below 18,000 f t (5490 m), most reservoirs are of the gas-condensate type. These deep gas reservoirs (-18,000 ft, -5486 m) generally produce with high condensate yields and often reflect retrograde characteristics. The aforementioned analysis is typical of most late Tertiary reservoirs in south Louisiana.

14.7. DISAPPEARANCE OF HYDROCARBONS IN HIGH-PRESSURE/HIGH-TEMPERATURE ENVIRONMENTS

Most commercial hydrocarbons have disappeared at a pressure gradient of 0.85 psi/ft (19.2 kPa/m) and a temperature of 350°F (450 K) in the south Louisiana Tertiary. The reason is quite simple; the bulk of all hydrocarbons is concentrated near the onset of abnormal pressure and between 140 and 260°F (333-400 K). Very little production is found beyond this pressure/temperature environment. Timko and Fertl (1970) also found that commercial hydrocarbons did not exist beyond a pressure gradient of 0.85 psi/ft (19.2 kPa/m) and a temperature of

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

104116-

407

320

128140152-

340

164-

-

176-

fg 188E m$

& E F

360

g E3

212-

iii

224-

380

&E

c

236248260272 284 -

400

?LA:: 332 320

0

3

6

9

1

2

1

5

Fig. 14-11. Gas production distribution versus temperature in ten major south Louisiana Tertiary sands (Fertl and Leach, 1990).

300°F (422 K). In their bell-shaped curve (Fig. 14-14), the authors maintained that hydrocarbons produced from a pressure-temperature region beyond the phase line or to the right of point A came from aquifers with gas in solution. Characteristics of these type reservoirs are (1) rapid drop in pressure, (2) always gas production, and (3) low water salinity. A few wells were found to have produced substantial gas reserves from this region of aquifers with gas in solution; however, the produced waters had high salinities. The high water salinity indicated that the reservoirs were not of the aquifer with gas in solution type. A salinity axis was added in Fig. 14-14 to normalize this condition. It is believed that the low water salinity in these non-commercial aquifers is due primarily to reservoir isolation. This resulted in the trapping of molecular water from clay dehydration and some water from liquid condensation. The condensation of water probably resulted when hydrocarbons were expelled from the isolated reservoir and was due to a drop in pressure that occurred when the pressure in the isolated reservoir exceeded the fracture gradient. The reduction in hydrocarbon occurrence with increased pressure and temperature can also be correlated to the shale resistivity ratio (SRR) (Fertl and Leach, 1988), The SRR (Fig. 14-15) is defined as the normal shale resistivity (Rsh, based on compaction trends) divided by the actual observed shale resistivity (&). The &,-value is thermodynamically related to both pressure and temperature, particularly abnormal pressure in low-density shales. Since pressure and temperature affect

408

W.G. LEACH

TABLE 14-6 Temperature versus hydrocarbon distribution for ten major South Louisiana fields

2.500

762

104

313

10,728,645

25,658.852

15,152,585

0.9

0.5

07

21,859.878

25,127,831

26,192,263

1.7

0.5

12

08

3.500

1067

116

320

4.500

1372

128

327

15,556,288

10,955,132

17.447.104

1.2

0.2

5,500

1676

140

333

33,551,289

27,446,831

38.283.501

2.7

0.5

17

6.500

1981

152

340

45,840,478

36,745,575

52,175,922

3.6

0.7

24

7.500

2286

164

347

122,380,376

129,743,875

144,750,012

9.7

2.4

66

8.500

2591

176

353

168,965,685

215,767,754

206,167,022

13.4

4.r

94

9.500

2896

188

360

134,459,537

287.702.831

184.063.473

10.7

5.3

84

10,500

3200

200

367

175,452,349

477,517,139

257,782,890

13.9

8.1

11 7

11,500

3505

212

373

99,350,461

548,695,108

193,953,066

7.9

10.1

88

12.2

10 4

12.500

3810

224

380

114,894,414

662,953.837

229,196,800

9.1

13.500

4115

236

387

133,750,147

81432.132

271,152,239

10.4

15.0

12 3

14,500

4420

248

393

68,408.328

81 1,585,168

208.336.805

5.4

14.9

95

15.500

4724

260

400

54,549,177

665.1 36,961

169,227,963

4.3

12.2

77

16,500

5029

272

407

20,146,838

353,929,410

81,169,150

1.6

6.5

37

17.500

5334

284

413

17,689.887

176,211,518

48,071,183

1.4

3.2

22

18.500

5639

296

420

10,090,693

79,174,847

23,741.529

0.8

1.5

11

19.500

5944

308

427

12,246,918

81,075,851

26,225,513

1.o

1.5

12

20.500

6248

320

433

1,891,866

7,961.841

3,264,597

0.2

0.1

01

21.500

6553

332

440

195,974

3,161,866

741,123

0.0

0.1

00

1,259,011,230

5,440,884,359

2,197,094,740

100.0

100.0

100.0

Totals

‘T = 74+ 1.2(D/100) EOE = Barrel Oil Equivalent

resistivity measurements, the SRR can be used to provide further insight into the probability of production from a high-pressured, high-temperature environment. The SRR also provides knowledge of reservoir size. For example, based on the 1988 study, it was found that once the SRR had reached 3.5, the reservoir size or reserves are reduced by 80%. These reservoirs are generally small, high-risk, and consist of one-well segments. It was discovered that no well had ever required an economic offset in the same reservoir once the SRR exceeded 3.5. The study also found that no well had ever been perforated below 20,700 ft (6309 m) with a SRR of less than 3.5. This indicated that the deep abnormally high-pressured, high-temperature reservoirs are all very small.

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

409

Temperature (K)

Temperature (P)

Fig. 14-12. Distribution of oil and gas production encountered below indicated temperature level at depths between 2000 and 22,000 ft (610-6710 m) in Ertiary sandstones, south Louisiana (Fertl and Leach, 1990).

14.8. VERTICAL FLUID MIGRATION AND HYDROCARBON CONCENTRATION

Further insight into why commercial hydrocarbons do not exist beyond a 0.85-psi/ ft (19.2-kPa/m) gradient and 350°F (450 K) is illustrated in Fig. 14-16. This figure is a plot of depth versus normal (hydrostatic), abnormal, and fracture pressure gradients. Temperature is incorporated in the depth scale based on an average Louisiana gulf coast geothermal gradient. The abnormal pressure gradient is shown in terms of two aquathermal expansion plots. The average depth of abnormal pressure in the gulf coast Tertiary, which ranges from 4000 ft (1219 m) to 20,000 ft (6096 m), is shown here at 12,000 ft (3658 m). The 1.8-psi/ft (40.7-kPa/m) gradient (Barker, 1972) represents the maximum theoretical pressure from the thermal expansion of water in an isolated reservoir with no permeability. The 1.4-psi/ft (31.7-kPa/m) gradient, an average between the lithostatic gradient of 1.0 psi/ft (22.6 kPa/m) and 1.8 psi/ft (40.7 kPa/m), allows for some permeability or pressure bleed-off across pressure seals. Most of the wells drilled below the top of abnormal pressure in south Louisiana fit fairly close to an average pressure gradient of 1.4 psi/ft (31.7 kPa/m).

410

W.G. LEACH

100

80

-0-6

320

340

I

I

360 I

380

400

I

I

420 I

440 I

-

60-

U 3

0

n m

s -

40

-

20

-

m 0

0 100

140

180

220

260

300

340

Fig. 14-13. Percent of total production distribution encountered below indicated temperature level at depths between 2000 and 22,000 ft (610-6710 m) in Tertiary sandstones, south Louisiana (Fertl and Leach, 1990).

The aquathermal pressure gradients in Fig. 14-16 illustrate how, with increased depth (temperature), pressure becomes abnormally high in deep isolated reservoirs. Although the first abnormal pressure trapped may have been from mechanical compaction of shales, most of the increased pressure is believed to be from aquathermal expansion. However, in small isolated reservoirs containing hydrocarbons, isothermal expansion will contribute even more to an already extremely high-pressured condition. As pressure continues to build up, the reservoirs are eventually broken down when the fracture gradient is exceeded. These fractures probably result in even smaller reservoirs. The high SRR of 3.5 or greater found in all wells completed below 20,700 ft (6309 m) substantiates the probability of many fractures or small reservoirs. But more important, these fractures result in the expulsion of fluids from the ruptured reservoirs. The fluids, primarily hydrocarbons and water, will always pulsate up to a higher structural position. Ultimately, the fluids will migrate up through faults or salt intrusions to near the top of abnormal pressure. This is the point of fluid equilibrium. The vertical movement of hydrocarbons probably consists of multiphase fluid flow (gas, condensate, and water). Prior to reservoir rupture, most of the hydro-

411

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE TABLE 14-7 Oil and gas distribution versus temperature and number of wells in South Louisiana Pmduction n Top Tempanturn 140 O F (333 K) (Compkllona 10o..;36m2 011)

ow

apm (m)

(n)

-1524 -1219 -3.000 -914 -2.000 -610 -1.000 -305 -5.020

-4.000

5

1 g

T $P $

1.000

305

2,000

610 914 1219 1524

3.000 4.000 5.000

m

Production n Top Tempanturn 180 O F (356 K) (Completionr 12,811 Ga; 31.152 011)

Gn

apm

F a b l ) o

78,514 159.726 223,597 337,746

(n)

221.317

5z.m

570.570 l.gSe,480 3,598,772

4.00 5.61 8.47 13.18

0.85 1.47 5.05 9.25

656.291 703,939 575,984 4 4 4 . m 282.178

4.805.367 5,70.584 6.017.394 8.521.842 7.095.797

16.45 17.65 14.44 11.15 7.07

12.35 14.88 15.46 21.90 18.23

Totlb 3.988.578

330,880

D.p(h

1

1

- 2.000

-1524 -1219 -914 -610

-1,000

- 305

1.000

305 610 914 1219 1524

-5.W -4.000

-3.000

2.000

3.000 4.000 5.000

011

Gn

0

CUR

391.375

623.339 806,318 734,215 585.063

388.595 225.156 171,332 76.185 31.-

kt*r 4.133.008

38.918.013 100.00 100.00

Pmduction n Top Temperature 220 O F (378 K) ( h p l e t l o n a 12.280 Gn; 22,746 011)

(fo

(m)

OH

00

375.924 1.149.211 3,078,936 7,161,910 12,128,111

9.47 i5.m 19.51 17.76 16.58

0.61 1.87 5.01 11 66 19 74

12.535.752 9,240.078 82Wmo.817 5,007,689 2.553.121

940 5.45 4.15 1.84 0.76

2041 15.04 13.35 8.15 4.16

(W (W -

-

61.431.549 100.00 100.00

Production yb. Top Temperaturn 260 'F (400K) (Completions 9.511 bs; 10,416 Oil)

011

(m)

-5.000 -4.000 -3,000 -2.000 -1.000

-1524 -1219 -914 -610 -305

1.000 2.000 3.000 4.000 5.000

305 610 914 1219 1524

CW

.

2,629,538 739.635 697.338 5.928.612 595,471 9,310,633 4 2 5 . W 13,865,906 iz.m.537 298.387

202.893 55.151

28.235 24.560 6.762

TOWI 3.073.238

9.145.346 4.863.537 1,804,149 493.041 248.126

24.07 22.69 19.38 13.83 9.71

6.60 1.79 0.92 0.80

0.22

4.32 9.73 15.28 22.76 2073

1

15.01 7.98 2.96 0.81 0.41

1

oapth

5.000

I

60,917.425 100.00 100.00

011

00

011

01.

CW

CUR

(W

(W

435.422 221.799 136.538 114.261

4484 9.378.616 2284 7.886.052 1406 5.171.005 11 77 1,478,120 392

(m)

-1524 -1219 -914 -610

f

-5.000 -4,000 - 3.000 -2.000 -1.000

-r)5

38,052

1

1.000

305 610 914 1219 1524

16,668 8.203 41 137 0

Totlk

971,121

1.m 2.000

3.000 4.000

8.834.444

2638 2800 2355 1544 441

305

610 914 1219 1524 TOWS

Pmductlon v8. Top Tempenturn 300 'F (422 K) (Completions 5.767 Oar; 6,272 Oil)

In)

-5.000 -1524 -4.000 -1219 -3,m -914 -2.000 -610 -1.000 -305

558.389 474.133 233,492 122.592 66.780 47.495 14.579 5.931 97 128 1,523,616

.,

.

9.167.157 36.65 12,656,692 31.12 8911.555 15.32 8.05 8.saz.in 7,357,997 4.38 2,740,165 946,161

303,392 8.966

369

3.12 0.96 0.39 0.01 0.01

. . 17.95 24.78 17.45 17.59 14.41 5.36 1.85 0.59 0.02 0.00

51,076,831 100.m ioooo

Pmductlon ys. Top Temperaturn 320 "F (433 K) (Completions 2.861 Oar; 1,531 Oil)

1

Oil (W)

00

(kl (YW

wa)

8,551.215 41 43 5,883,172 3730 879 3.154.802 9m.m 565 335.028 475

-5.000 -4.000 -3.000 -2.000 -1.000

-1524 -1219 -914 -610 -305

147.929 133,209 31.382 20.164 16,947

1.000 2.000

305 610 914 1219 1524

1.979 4.159 2 1.313 0

Totlb

357.084

Gn

(W 4463 3071 1647 506

175

~

2.000

3.000 4.000 5.000

657,121 83.039

344 350 0

172 084 000 001 000

196 025 000 000 000

33.489.091 10000 10000

1

3.000 4.000 5.000

243.189 1.398 55

0

055

127

116 000 037 000

o 11 001

OW

ow

19,159.805 10000 10000

carbons are in a super-critical gas phase because of the high temperature and pressure. As the gas migrates to a higher structural position after the fracture, a lower pressure and temperature will be encountered. Condensate-type liquids will begin to break out when the gas-liquid phase region is reached. This is the region below that pressure (dew point) and temperature (cricondentherm) level on

412

W.G. LEACH

Temperature(Fa)

Fig. 14-14. Pore pressure gradient versus formation temperature (after Timko and Fertl, 1970) expanded to include formation water salinity adjustment. Salinity normalization is based on deep Terrebonne Xough wells, Louisiana, e.g., reservoir at 0.8 psi/ft (18.1 kPa/m), 300°F (422 K), and 120 k ppm salinity). When plotting this information as initially proposed by Timko en Fertl, point A falls in the boundary zone of both regions, whereas after salinity adjustment, the resulting point A' clearly falls into the shaded region (Fertl and Leach, 1990). Shale Resistivily Profile

f a n

normal R,, actual Rlh

Shorl Normal Resistivity (&, Logarithmic)

-

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE Pressure (lo3kPa)

L

0

I

I

4

1

I

0

I

I

12

1

I

16

I

I

20

I

I

24

I

I

20

Pressure (103 psi)

Fig. 14-16. Relation between depth, hydrostatic pressure, aquathermal pressure, fracture pressure, and small isolated reservoirs where the shale resistivity ratio (SRR) is greater than 3.5. The relation is based on U.S. gulf coast Tertiary sediments.

a pressure-temperature phase diagram where gas begins to break out into liquids. As the pressure continues to drop in the fractured reservoir, the conduit seals off and the pressure starts building up again in the reservoir. When the pressure once again exceeds the fracture gradient, the reservoir ruptures, and the cycle is repeated. Additional hydrocarbons are pulsated up to near the top of abnormal pressure or the point of fluid equilibrium. Not all hydrocarbons are trapped near the top of abnormal pressure. Pressure seals weak in cementing material may not always be sufficiently strong at a particular

+ Fig. 14-15. qpical shale resistivity profile and shale resistivity ratio (SRR), Louisiana gulf coast region.

414

W.G. LEACH

depth to stop a column of charging fluid. For example, assume that at a depth of 10,000 ft (3048 m), a reservoir has been charged by a fluid column with a pressure of 9000 psi (62.046 MPa). This is equivalent to a pressure gradient of 0.9 psi/ft (20.4 kPa/m). But the fracture gradient in Fig. 14-16 at 10,000 ft (3048 m) is only 0.87 psi/ft (19.7 kPa/m). Consequently, the reservoir or fault conduit near the top of abnormal pressure would probably be fractured, and a portion of the fluids (including hydrocarbons) would escape and migrate up to a higher structural position. Most of the hydrocarbons, however, would remain in the reservoir near the top of abnormal pressure. The reason for this is that as the fracture occurs, there is an immediate drop in reservoir pressure due to fluid expansion. The reservoir pressure will drop almost immediately to some value below the fracture gradient. It appears appropriate to re-emphasize that if the pressure of a hot column of charging fluid is high enough, it will fracture its way up through one or more hydrocarbon accumulations. This may carry all or a portion of the hydrocarbons up to a higher structural position. In a subsiding basin, essentially all of the hydrocarbons in the deeper reservoirs will ultimately be erupted up to higher reservoirs. However, such reservoirs may still be at approximately the same depth and have the same relationship to the top of abnormal pressure. The top of abnormal pressure will also move up to a younger stratigraphic sequence. Anything contrary to this type of fluid and pressure migration and redistribution would actually be in opposition to the laws of physics. This is that part of physics relating to the strength of materials and the thermodynamic properties of the fluids involved. Evidence of the pulsation or cyclic migration of hot fluids is found throughout the world. In the Caspian Sea area of the former Soviet Union, the pulsating eruption of mud and hydrocarbons to the earth’s surface is described as a type of hydrovolcanism (Lysenin and Ezhov, 1987). Further evidence of cyclic migration and/or redistribution of hydrocarbons is supported by the following: (1) The absence of hydrocarbons in ultradeep wells - mostly small reservoirs (SRR > 3.5) where only aquifers with gas in solution are encountered. (2) Radioactive minerals encountered along fault planes. (3) Reservoirs originally wet when first logged, but now contain hydrocarbons. (4) Presence of “hot spots” in some wells in vicinity of regional faults. (5) Large number of active and nonactive hydrocarbon seeps associated with faults in the Gulf of Mexico and other parts of the world. Fluid compressibility, fluid expulsion, vertical fluid migration, and redistribution is simply a defluiding process. All clastic sedimentary basins such as the U.S. gulf coast Tertiary go through this episodic defluiding process. Since the bulk of formation fluids is water, some authors have referred to this process as episodic dewatering (Hunt, 1990). In some areas, there may be a continuous migration of fluids up to the earth’s surface due to pressure leakage. Most of the deep hydrocarbon migration, -20,000 ft (6096 m), below the top of abnormal pressure is believed to be cyclic. This is due to the compressible (dissipates heat) and expandable (absorbs heat) nature of fluids, particularly for hydrocarbons in a gas phase. Fluids exposed to increasingly higher formation temperature while contained

I ~

,1

i

i4500 Fig. 14-17. North-south cross-section of Tcxaco's Hollywood field showing vertical fluid migration ( M u m m e and Ferrell, 1979, a thcsis).

in an isolated reservoir with a certain fracture gradient or "relief valve" will ultimately breakout of containment. The initial temperature buildup in most of the gulf coast Tertiary reservoirs was primarily due to increased depth under the influence of a sinking basin. During rupture, the temperature in the reservoir probably dropped slightly due to fluid expansion. As the rupture sealed, the temperature gradually increased, and the "pressure-cooker'' cycle was repeated. The cyclic pulsation of hot fluids up to the point of fluid pressure equilibrium explains why the major percentile of all hydrocarbons will always be associated with or near the top of abnormal pressure. The Hollywood field in Terrebonne Parish, Louisiana is a classical example where vertical migration of hot fluids has been prevalent (Mumme and Ferrell, 1979). A cross-section of the field is shown in Fig. 14-17. This deep-seated structure, which has produced over 2.5 Tcf (7.08 x lo9 m3) of gas, is one of the most prolific gas fields in onshore south Louisiana. Hightemperature fluids, see 200°F (367 K) isotherm and the 40,000 ppm water level, have moved up to near or above the top of abnormal pressure. Although one cannot tell which faults provided the plumbing, it is obvious that hot fluids have migrated up regionally connected faults to near the top of abnormal pressure.

4 lb

W.Ci. I.liACI I

I I

Fig. 14- IS. Iiypoihciical cross-section of a dccp-scatcd saltdomc struciurc showing whcrc the 2 O U O F isothcrm mows ahovc (cross-oucr) thc lop of ahnorma! prcssurc duc to hot vcrtical fluid niigra~ion.

The 200°F (367 K) temperature isotherm will often follow close to or slightly below the top o f abnormal pressure in non-producing areas such as off-structure synclines. But in many of the deep-seated saltdome fields such as the Hollywood field, the 200°F (367 K) temperature level will often shift substantially above thc top of abnormal pressure. The shift in the 200’1: (367 K) isotherm from below abnormal pressure to above abnormal pressure in the vicinity of hydrocarbons was also noted by Jones (1984). An example of this temperature shift above abnormal pressure or “cross over” is shown diagrammatically (Fig. 14-18). The temperature-abnormal pressure “cross over” points can be easily mapped. Most of the deep-seated saltdome gas and oil fields along the gulf coast have now been delineated by mapping this temperature-abnormal pressure “cross over”. Crosssections and maps of actual field applications cannot be shown a1 this time because of proprietary reasons. The temperature-pressure “cross over” mapping does not appear applicable to shallow piercing-type saltdome fields. The temperature is apparently convected up through the salt and heaved away from the structure. This condition still seems to result in a temperature shift above abnormal pressure, but the “cross over” is off structure and generally encountered on the north side of the field. Also, the depth of abnormal pressure varies too much around the flank of a shallow saltdome structure for this type of mapping.

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

417

In many cases, the temperature-abnormal pressure “cross over” has been observed over most of the field, particularly the deep-seited saltdome structures. But in some fields, these are individual wells where the temperature is much higher than in adjacent wells. Such wells or areas have been termed “hot spots”. These “hot spots”, when observed in the vicinity of large faults, tend to indicate major hydrocarbon migration routes. The “hot spots” can be quickly identified by computer-mapping utilizing a good temperature database. This map is then superimposed over regular geologic structure maps in order to help identify major hydrocarbon migration routes in a particular field or region.

14.9. PROBABLE SOURCE OF UPPER TERTIARY HYDROCARBONS

The preponderance of Upper Tertiary (Miocene) gas and oil deposits could not have reasonably originated in adjacent or nearby source beds. The nearby source bed concept was originally held by many geologists and geochemists in spite of the following: (1) small percent of organic material contained in the rocks; (2) organic material poor in hydrocarbon and rich in oxygen; (3) hydrogen product distribution in producing reservoirs is different from that in adjacent shales; (4) paraffin patterns are also different. Information in this study on hydrocarbon distribution and ascending hot fluid migration makes the adjacent source bed theory unlikely. Vertical fluid migration and the concentration of most hydrocarbons near the top of abnormal pressure provide the mechanism that many geochemists have been searching for over the past three decades. Based on the mechanics of episodic defluiding, there is practically no depth limit from where the hydrocarbons could have originated. A portion of the hydrocarbons may have originated in Lower Tertiary sediments (Sassen, 1990). However, a major portion of the hydrocarbons probably migrated up from deep Cretaceous and older organic-rich rocks (Bissada et al., 1988). A small percentage of the hydrocarbons obviously comes from biogenic gas. Some hydrocarbons may even have come from inorganic acids. The availability of suitable source rocks at some depth below or off slope to the sands being evaluated is an obvious prerequisite for gas and oil exploration. Plumbing (faults) and trap size are also essential. But drilling to and within the maximum hydrocarbon environment is essential for sound economics. The drilling success ratio in the deep south Louisiana Tertiary has been very poor, particularly below 15,000 ft (4572 m). This success ratio can now be improved substantially by drilling to the maximum hydrocarbon environment. In the future, the explorationist should become concerned about ascending fluid migration routes (“hot spots”) and maximum hydrocarbon distribution patterns. The best place to look for seismic “bright spots” will be in the maximum hydrocarbon distribution interval.

418

,

I

I

I

0 I

Lo

0

I

Lo

I

*I

I

I

I

I

I

I I *

I

I

I

I

I

I

I

I

I

I

Production (oh) 18,000-19,000 ft (5486-5791 rn)

2 m

0

Production (Vo) 16,000-17,000 11 (4677-5182 m)

m

m

0

N Lo

m

d 0

m 0

Production (Vo) 14,000-15.000 ft (4267-4572 m)

z

I

\,

I

I

I

Production ( o h ) 12,000-13,000 11 (3658-3962 rn)

0

W.G. LEACFI

5

Y

8

Y

Fig. 14-19. Plots showing gas distribution (best curve fit) in relation to abnormal pressure as a function of depth at four different depth intervals for U.S. (Louisiana) gulf coast Tertiary sands.

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

419

14.10. MAXIMUM HYDROCARBON DISTRIBUTION

Based on many individual plots, it was found that hydrocarbon distribution will vary according to the depth of abnormal pressure and lithology. For example, Fig. 14-19 consists of four plots showing gas distribution as a function of abnormal pressure and depth. In this analysis, lithology is statistically related to depth. The reason for this is that with increased depth, shale becomes more prevalent than sand in south Louisiana Tertiary sediments. The four plots in Fig. 14-19, from left to right, show that the center of gas distribution is consistently dropping further below the top of abnormal pressure with increased depth. Initially, it was not known which parameters were causing maximum hydrocarbon distribution to shift further below the top of abnormal pressure with increased depth. Three facts were known. First, all fluids contained in a high-pressure environment are trying to migrate up to the top of abnormal pressure or the highest point of fluid equilibrium. Secondly, these fluids have to fracture up to this point of fluid equilibrium. Thirdly, it has already been observed that the fracture gradient for the south Louisiana Tertiary (Fig. 14-16) increases with depth. This increase in fracture gradient with depth is not only due to overburden but is also related to a change in lithology or increase in the amount of shale with depth. Therefore, it was concluded that the position of maximum gas distribution to abnormal pressure is primarily a function of formation fracture strength. In other words, the greater the depth, the greater the fracture strength and the further below the top of abnormal pressure will-the maximum concentration of gas most likely be encountered.

14.11. MAXIMUM HYDROCARBON WINDOW

The relation of maximum hydrocarbon distribution to formation fracture strength or depth opens the door to the utilization of a maximum hydrocarbon window (MHW) technique (Fig. 14-20). This MHW technique can be used as a decisionmaking tool on how deep to drill a well, particularly how deep to drill a well below the top of abnormal pressure. For example, gas distribution in Fig. 14-20 is shown as a percentage of total gas encountered above and below abnormal pressure as a function of well depth. When the top of abnormal pressure is at a depth of 12,000 ft (3658 m), 95% of the gas distribution has been statistically penetrated at a depth 2400 ft (732 m) below the top of abnormal pressure. But when abnormal pressure is at a depth of 18,000 ft (5486 m), this 95% concentration point is not penetrated until 4200 ft (1280 m) below the top of abnormal pressure. In other words, a well should be drilled about 1800 f t (549 m) deeper below the top of abnormal pressure at 18,000 ft (5486 m) than when the top of abnormal pressure is encountered at 12,000 ft (3658 m). This is necessary in order to drill through the 95% concentration level. However, economic factors involving smaller reservoirs and higher drilling cost may be a limiting factor at the greater depths.

420

W.G. LEACH Depth (100 m)

P

53

-

1

5

4L

12

I

I

I

I

I

I

13

14

15

16

17

18

19

Depth (1,000 it)

Fig. 14-20. Plots showing maximum hydrocarbon window (MHW) for gas, based on the percent distribution of gas encountered above and below the top of abnormal pressure (TAP) as a function of depth, U.S. gulf coast Tertiary sands.

14.12. PROBABILITY OF EXPLORATION/EXPLOITATIONENHANCEMENT WITH MHW TECHNIQUE

The need for both exploration and exploitation enhancement in deep well drilling is shown in a randomly selected control sample of 309 wells (Fig. 14-21). The plot shows production versus number of wells. The 309 well-control sample represents the approximately 1200 wells completed to date between 15,000 ft (4572 m) and 18,000 ft (5486 m) in the onshore Tertiary sands of south Louisiana. About 90% of the production was produced by 50% of the wells. This is typical of most wells drilled below 15,000 ft (4572 m) in the area. The fact that 50% of the wells produced only 10% of the production illustrates the need for better insight into exploitation drilling in deep Tertiary sands. Utilization of the MHW technique could have increased production in the wells completed between 15,000 and 18,000 ft (4572-5486 m) by 400%. This conclusion is based on the analysis of estimated gas reserves from the 309 well-control sample (Fig. 14-22). Using actual reserve data, the curve on the right represents the probability of gas reserves per well inside the MHW. The curve on the left shows the

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

421

Wells (010)

Fig. 14-21. Percent wells versus percent cumulative production of a 309 well-control sample representing wells completed between 15,000 ft (4575 m) and 18,000 ft (5490 m) in the south Louisiana Tertiary.

probability of gas reserves per well outside the MHW. There is a 40% chance that wells completed inside the MHW will produce 4 Bcf (113 x lo6 m3) of gas per well; however, wells completed outside the MHW have only a 10% change of producing 4 Bcf (113 x lo6 m3) of gas per well. The MHW technique has the potential to enhance exploration and development in all clastic sedimentary basins throughout the world. The technique should be of particular benefit when drilling gas wells below 12,000 ft (3658 m) in Upper Tertiary sediments. However, hydrocarbon distribution associated with the top of abnormal pressure for any combination of clastic sediments should be predictable with the MHW technique. A special MHW plot for a particular sandhhale environment should be developed for maximum benefit. For example, MHW plots were developed for the Camerina and Miogyp gas sands (Frio) in southwest Louisiana. The maximum gas window for the Camerina sand is centered about 2,500 ft (762 m) below the top of abnormal pressure (Fig. 14-23). Gas distribution is divided equally above and below this point (Table 14-8). Almost 90% of the Camerina gas production was encountered in this distribution interval. To date, over 1.6 Tcf (45 x lo9 m3) of gas has been produced from 99 Camerina completions in this southwest Louisiana area.

422

W.G. LEACH

0

30

20

40

30

60

50

70

80

90

100

Percent Greater Than

Fig. 14-22. Probability of gas reserves as a function of the maximum hydrocarbon window (MHW) for a randomly selected 309 well-control sample from wells drilled below 15,000 ft (4575 m), south Louisiana Tertiary.

Distance from Abnormal Pressure (100 m)

60

I

I

I

I

I

I

I

I

I

I 50 -

I I

Distance from Abnormal Pressure (1,000 ft)

Fig. 14-23. Gas production distribution (best curve fit), percent, encountered below the top of abnormal pressure for 99 Camerina completions in 30 southwest Louisiana fields.

423

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE TABLE 14-8 Production distribution versus onset of abnormal pressure, Camerina (99 perforations)

- 7,000 - 6,000 - 5,000 - 4,000

- 2134 - 1829 - 1524

-3,000

- 914

c

0,

%

> c

:: 0 q ? ? 3

t $ ?? I

;

m"g

9

- 1219

-2,000

-610

-1,000

- 305

0

0

1,000

305

2,000

610

3,000

914

4,000

1219

5,000

1524

6,000

1829

7.000

2134

Totals

33,719,283

924,087

2.1

4.7

16,153,691

1,009,288

1 .o

5.1

261,175,333

1,777,377

16.2

9.1

906,309,582

5,556,871

56.1

28.3

207,038,932

1,966,386

12.8

10.0

80,790,287

1,943,534

5.0

9.9

100,937,694

6,377,644

6.2

32.5

8,996,159

63,277

0.6

0.3

1,615,120,961

19,618,464

100.00

SW.00

The Miogyp gas sands (Fig. 14-24 and Table 14-9) further illustrate the need for different regional geological distribution plots. The production distribution plot in Fig. 14-24 is reflecting lithological differences in wells producing from the Miogyp sands. The subtle plateau at 3500 ft (1067 m) below the top of abnormal pressure represents production from Miogyp completion upthrown to a series of major regional faults. However, the major peak at 6500 ft (1981 m) below the top of abnormal pressure reflects production from Miogyp reservoirs over leaned by massive transgressive shale wedges. The production distribution of wells encountered below the massive shale is shown in Fig. 14-25. The massive shale encountered above the Miogyp sands in these down-thrown blocks have much higher fracture gradients. As already mentioned, shales have higher fracture gradients than sand. These higher fracture gradients restrict the vertical migration of fluids in the hydrodynamic defluiding process. Consequently, the maximum hydrocarbon window in this type of geological environment will always be found much deeper below the top of abnormal pressure. Some geologists believe that hydrocarbons may be associated with the top of abnormal pressure primarily because of geological reasons. This is partially

424

W.G. LEACH

-15 I

50

-5

-10 I

0

5

I

I

I

10 1

15 I

20 I

I

1

40 -

I I

I I I

30-

-

C 0 .-

I

2 20-

I I I I I

a

10

lil,i4 I

3

U

'

0

I

I

Distance from Abnormal Pressure (1,ooO It)

Fig. 14-24. Gas production distribution (best curve fit), percent, encountered below the top of abnormal pressure for 63 Miogyp completions in 30 southwest Louisiana fields. TABLE 14-9 Production distribution versus onset of abnormal pressure, Miogyp (63 perforations)

- 6,000

- 1829

- 5.000

- 1524

- 4,000

- 1219

G -3,000 av)

-914

0

-2,000

-610

g

-1,000

- 305

>

a f:: -

c

'6 Eg F

a

-

2 Ea

0

0

1.OOo

305

2,000 3,000

610 914 1219

4,000 5,000

1524

6,000

1829

7,000 8,000

2134 2438 Totals

78,990,126

1,303,855

14.1

15.9

96,701,787

927,077

17.3

11.3

90,570,656

3,518,627

16.2

42.8

85,481,048

1,917,422

15.3

23.3

188,285,132 19,890.818

490,549 61,645

33.6 3.6

6.0 0.8

559,919,567

8,219,175

100.00

100.00

425

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE Distance from Abnormal Pressure (100 m) -18 6Or

50t

E

-12

-6

I

I

0

I

6

12

18

I

I

I

L

\

/ -

20

I I 1 1 I 0 - 6 - 5 - 4 - 3 - 2 - 1

I

1

1

1

1

0

1

2

3

1

4

I

I

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Distance from Abnormal Pressure (1,OOO It)

Fig. 14-25. Gas production distribution (best curve fit), percent, encountered below the top of abnormal pressure for 42 Miogyp completions southwest Louisiana.

true because of trap availability and the three-way relationship between lithology, temperature and pressure. However, based on the results of two deep-well studies in south Louisiana, it is believed that hydrocarbons are more directly associated with the top of abnormal pressure than recognizable geological features. For example, geologists often use the top of abnormal pressure to determine what geological formation is present. Over 700 dry holes have been drilled below 18,000 ft (5486 m) in the south Louisiana Tertiary. Most of the geological objectives were penetrated at about the depth anticipated. Drilling in most of these dry holes stopped either too high above the top of abnormal pressure or dry hole footage was drilled too far below the top of abnormal pressure. The same thing happened to wells drilled between 15,000 ft (4572 m) and 18,000 ft (5486 m) where there were approximately 2000 dry holes.

14.13. PROBABILITY OF EXPLOITATION ENHANCEMENT WITH SRR TECHNIQUE

The shale resistivity ratio (SRR) can also be used as an aid in predicting probability of production. The SRR technique can best be used as a decisionmaking tool on whether to set pipe and complete the well. This technique has been very valuable in wells drilled below 18,000 ft (5486 m) in south Louisiana. The probability of producing equivalent gas reserves as a function of SRR for wells perforated below 18,000 ft (5486 m) is shown in Fig. 14-26. Gas reserves and SRR values for each well were determined by an interdisciplinary study team for all wells completed below 18,000 ft (5486 m) in the south Louisiana Tertiary

426

W.G. LEACH

Probabilily ( O h )

Fig. 14-26. Probability of equivalent gas reserves (EGR) as a function of shale resistivity (SRR) for wells perforated below 18,000 f t (5490 rn), south Louisiana (Fertl and Leach, 1990).

(Fertl and Leach, 1988). In this study, it was found that the SRR technique can be used as an integral part of a risk analysis program to improve the economic success of deep-well completions. For example, in Fig. 14-26, if gas reserves of 2 Bcf (56.6 x lo6 m3) are needed to payout the completion cost of a well with a SRR above 3.5, the percent chance of success would be 28%; conversely, at a SRR below 3.5, the chance of success would be 65% or more than double the chance for success. This technique is presented as another method that can be utilized to improve drilling well success in deep Tertiary sands.

14.14. FUTURE EXPLORATION AND DEVELOPMENT POTENTIAL

The MHW and SRR techniques should be applicable in all clastic sedimentary basins where abnormal pressure is encountered. The MHW technique can best be used in the initial exploration planning stage on where and how deep to drill. The SRR technique can be used as an aid in deciding whether to set pipe after the well is drilled. The SRR approach is used primarily in deep wells, generally below 15,000 ft (4572 m). The MHW technique can be used for any particular sand-shale type environment if the depth of abnormal pressure is known. The MHW plot should

DISTRIBUTION OF HYDROCARBONS IN ABNORMAL PRESSURE

427

be from wells that have produced from a similar stratigraphic type of sand-shale environment. Since the largest distribution of hydrocarbon reserves is found associated with the top of abnormal pressure, the first exploration prerequisite for a new clastic sedimentary basin area or prospect should be mapping the top of abnormal pressure. In new clastic basins where there is little or no well control, the top of abnormal pressure must be predicted from seismic velocity data. Since rock velocity changes with rock bulk density, the change in pore pressure gradient due to undercompaction or abnormal pressure can also be detected. Drilling engineers have used this technique for several years to determine the setting depth for protective casing (Weakley, 1989). After drilling begins, the seismic velocity data can be augmented by mud weights, openhole well logs, and formation pressure tests. A top of 12.5-lb/gal (14.7-kN/m3) mud in a well is a good selection point for the top of abnormal pressure. Wells using 12.5-lb/gal (14.7-kN/m3) mud are generally always in abnormal pressure. However, wells using mud in the 11.0 lb/gal (12.9 kN/m3) range may be in anticipation of abnormal pressure. The most practical way to determine the depth of abnormal pressure is from the top of low-density shale. Top of low-density shale is easily recognized by a sudden shift or decrease in shale resistivity on the short normal curve of an openhole electric log. The utilization of abnormal pressure mapping and the MHW technique in conjunction with existing geophysical and geological methods dictate the need for multidisciplined teams. The multidisciplined team (i.e., geophysicists,geologists, and engineers) is needed at an early exploratory stage in order to (1)map the top of abnormal pressure, (2) predict maximum hydrocarbon distribution patterns, (3) locate better quality reservoir traps, and (4) evaluate the economics of the total program.

REFERENCES Ashirmamedov, M.A. and Khadzhinurov, N., 1980. Regularities of the distribution of abnormally high formation pressure in the West-TWunen depression and their connection with hydrocarbons. Leu. Acad. Sci Turkmenistan, Sex Phys., Technol., Chem., Geol., 1: 100-106 (in Russian). Barker, C., 1972. Role of temperature in development of abnormal pressure zone. Bull., Am. Assoc. Pet. Geol., 56 (10): 2068-2071. Bissada, K.K., Katz, B.J., Barnicle, S.C. and Schunk, D.S., 1988. Origin of hydrocarbons in Gulf of Mexico Basin; a reappraisal. Presented at Annual American Association of Petroleum Geologists Convention, Houston, Texas, March, 1988.Am. Assoc. Pet. Geol., Bull., 72(2): 163 (abstr.). Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull., Am. Assoc. Pet. Geol., 53: 73-93. Chapman, R.E., 1980. Geological notes, mechanical versus thermal cause of abnormally high pore pressure in shales. Bull., Am. Assoc. Pet. Geol., 64: 2179-2183. Dow, W.G., 1984. Oil source beds and oil prospect definition in the Upper Tertiary of the Gulf Coast. GulfCoast Assoc. Geol. SOC.,Trans., XXXIV 329-339. Fertl, W.H. and Leach, W.G., 1988. Economics of hydrocarbon reserves in overpressured reservoirs below 18,000 ft in South Louisiana. SPE 18146, I988 Society of Petroleum Engineers Annual Technical Conference and Exhibition, Houston, Texas, October 2-5.

428

W.G. LEACH

Fertl, W.H. and Leach, W.G., 1990. Formation temperature and formation pressure affect oil and gas distribution in Tertiary Gulf Coast sediments. Paper presented at the Gulf Coast Association of Geological Societies Conference, Lafayette, La., October. Gulf Coast Assoc. Geol. SOC.,Tmns., X L 203-216. Hunt, J.M., 1990. Generation and migration of petroleum from abnormally pressured fluid compartments. Paper presented at the American Association of Petroleum Geologists Research Conference, Leesburg, Va., April 1988. Bull., Am. Assoc. Pet. Geol., 74(1): 1-12. Jones, P.H., 1984. Deep water discharge: A mechanism for the vertical migration of oil and gas. In: Third SMU Unconventional Methods in Explorationfor Petroleum and Natural Gas Symposium, Dallas, Texas, September 1982. SMU Press, Dallas, Texas. Leach, W.G. and Fertl, W.H., 1990. The relationship of formation pressure and temperature to lithology and hydrocarbon distribution in lkrtiary sandstones. Paper presented at International Meeting on Well Logging Techniques. Transactions, International Well Logging Symposium, Section E , Beijing, May 28, 1990. Lysenin, G.P. and Ezhov, Y.A., 1987. Hydrogeodynamic determination of hydrocarbon potential. Geol. Nat’l Gaza, March, 1987. Mumme, S.T and Ferrell, R.E., 1979. Thesis, Department of Geology, Louisiana State University. Gulf Coast Assoc. Geol. SOC.,Trans., XXIX: 321-327. Sassen, R., 1990. Lower Tertiary and Upper Cretaceous source rocks in Louisiana and Mississippi: implications to Gulf of Mexico crude oil. Bull., Am. Assoc. Pet. Geol., 74 (6) 857-878. Scharr, G., 1976. The occurrence of hydrocarbons in overpressured reservoir of the Baram Delta, offshore Sarawak, Malaysia. In: Proceedings of the 5th Annual Convention of the Indonesian Petroleum Association, pp. 163-169. Timko, D.J. and Fertl, W.H., 1970. Hydrocarbon accumulation and geopressure relationships and prediction of well economics with log-calculated geopressures. SPE 2990, 1971 Sociery of Petroleum Engineers Annual Meeting, October, Houston, Texas; J. Pet. Technol., 23: 923-933. Weakley, R.R., 1989. Use of surface seismic data to predict formation pore pressures. Paper presented at the SPEIUDC Drilling Conference, New Orleans, La., February 28-March 3.

429

GLOSSARY *

Aquiclude A relatively impermeable rock unit that confines an aquifer (above, below, or both). Aquifer A porous and permeable, or fissured, rock unit that contains exploitable water. Originally used for any water-bearing stratum, but probably meant in practice what it now means. Aquitard A rock unit that is not as permeable as an aquifer or as impermeable as an aquiclude. Artesian Wells or aquifers are said to be artesian when the energy of the water is sufficient to raise it above the land surface without the use of pumps. An aquifer is artesian if its total head (see Head) is greater than the elevation of the land above the same datum. Authigenic Minerals that are formed where they are now found, particularly those in the pores of sedimentary rocks, are called authigenic. Petroleum accumulation inhibits the formation of authigenic minerals in the reservoir. Bi11ion lo9 in the USA; 10l2 (officially) in many European countries and Australasia - but in the petroleum industry, lo9 is always meant. Better to say “thousand million” and write lo9 if there is any danger of misunderstanding. Blowout Uncontrolled flow of fluid (natural gas, crude oil, or water) into a borehole, and from it to the surface or to permeable subsurface fomzations, when the pressure or energy of the pore fluids is greater than the pressure or energy of the mud, and a human or mechanical failure prevents this excess energy from being contained at the surface by the blowout preventers (BOPS),which are devices for closing the borehole. ~

* Compiled by Richard E. Chapman.

430

GLOSSARY

Bottom water The water below an accumulation of crude oil or gas, occupying the same general area (cf. Edge water). “Bottoms up”, to circulate To circulate mud through the drilling string in order to bring the mud at the bottom of the hole to the surface. Used to identify the nature of fluid influx into the borehole after a drilling break. Cap rock (a) The rock that prevents petroleum from escaping from a reservoir rock. Cap rocks are relatively impermeable, but it is their small pore size and the associated large capillary pressure that leads to their property of restraining the petroleum. (b) A hard calcareous layer of mudstone above the top of abnormally high pore pressures. (c) The material that is not salt near the top of a salt plug, stock, or dome. Usually gypsum and anhydrite. Capillary pressure The difference in pressure across an interface between two immiscible fluids (e.g., water and oil). When crude oil and water, or gas and water, occupy the same pore, the petroleum occupies the central position of minimum potential energy in the space. The pressure is higher on the concave side in the oil or gas than on the convex side in the water, and the amount of this difference is related to the size of the pore and to the relative proportions of petroleum and water. If the petroleum is a separate droplet in the pore (larger than the passages to the next pore), it can only be moved to the next pore space by exerting a displacement pressure that is greater than the capillary pressure. This increases as the size of the constriction decreases, and is a function of the radius of curvature of the interface. Casing Boreholes are cased with steel pipe to prevent the hole from caving in, to isolate the fluids of the formations penetrated, and to facilitate the removal and running of the drilling string. Circulate In rotary drilling, the mud circulates from the suction tank through the pumps, the drilling string, up the annulus between the drilling string and the wall of the hole, or the casing, and so through the shale-shaker and settling tanks back to the suction tank. When drilling is stopped, the mud must be circulated to remove all cuttings before the bit is pulled from the hole. Coefficient of permeability The coefficient K in Darcy’s law when written q = K A h / l . It has the dimensions of a velocity, L T-’ . Synonym: hydraulic conductivity. See Permeability.

GLOSSARY

43 1

Completion A well is completed on one or more petroleum reservoirs, after drilling and casing the hole, with a view to producing the petroleum from it or them. If production is, or becomes, impossible or underirable (due to high water-cut, high gasloil ratio, low yield, or other reason) the well may be re-completed on another reservoir or group of reservoirs. Concurrent fault Synonym for growth fault. It is rarely used, but strictly has priority. Connate water The water that accumulates with a sediment is said to be connate, but it is a difficult concept because there is much movement of most pore water as the rock is buried. Thick mudstones may have connate water. The immobile water in a petroleum reservoir is also called connate water. Contemporaneous fault Synonym for growth fault. Darcy The darcy is the unit of intrinsic permeability based on an incomplete (if not erroneous) expression of Darcy’s law. The common unit is the millidarcy (mD), which is equal to cm2 or 1@m2,for practical purposes. Density The weight or mass of unit volume of material is called its density. In general, it need not be qualified; but in formulae and equations it must be qualified as follows. Mass density: the mass of unit volume of material. Dimensions M L V 3 . Weight density: the weight of unit volume of material. Dimensions M L V 2 T P 2 . Depositional fault Synonym for growth fault, common in the literature of the 1950s and 60s. Diachronous Rock units are said to be diachronous when their age-ranges vary according to position. They are the consequence of migration of adjacent facies during sediment accumulation. The lithological surfaces are not strictly isochronous surfaces. “Timetransgressive” is an undesirable synonym. Diagenesis Diagenesis embraces all the changes, physical and chemical, that take place in a sediment from the time it accumulates until metamolphism begins.

432

GLOSSARY

Diapir Intrusions of salt or mudstone are called diapirs. They are caused by the density and viscosity contrasts between these materials and the other sedimentary rocks. Folds caused by the same processes are called incipient diapirs. Differential sticking See Wall sticking. Drilling break A sudden and marked increase in the penetration rate. It may be due to a change of lithology, but it must be assumed to be due to an increase in the pore pressure relative to the mud pressure at the bottom of the hole. Edge water When a petroleum accumulation is thicker than the reservoir, so that the petroleum/ water contact forms a strip around the accumulation, the water is described as edge water. Cf. Bottom water. Equipotential surface or line A surface or line upon which points of equal fluid potential or energy lie. Not synonymous with potentiornetric surjace. Synonym: isopotential, which is not to be preferred. Facies (singular and plural) The character of a rock may change from place to place. The appearance and nature of a rock that distinguish it from others is its facies. There are several related concepts: lithological (lithofacies) as in “mudstone facies”; biological (biofacies) as in “graptolite facies”; and environmental, as in “littoral facies”. Fish, fishing When seeking to recover tools or equipment accidentally left in a borehole, such as part of a drilling string, one is said to befishing. What has been lost in the hole is, of course, the fish. Fluid A substance that flows, that yields at once to shear or tangential stress. Liquids and gases are fluids. The time frame is important because some materials, such as pitch, behave as solids when struck with a hammer, but flow when smaller stresses are applied for longer time. Fluid potential The mechanical potential energy of an element of fluid with respect to its physical environment. It is also (and equivalently) the amount of work required to move unit mass of fluid from the reference position and state (e.g., sea-level and atmospheric pressure) to the point specified.

433

GLOSSARY

+

For liquids, the potential at a point is @ = gz p / p , where g is the acceleration due to gravity, z is the elevation of the point above (+) or below (-) the datum level (commonly sea-level), p is the gauge pressure at the point, and p is the mass density of the liquid. See also Head. Fluid potential gradient. When a fluid is at different potentials in two points in subsurface space, there is a fluid potential gradient between them, and fluid tends to flow from the point with higher potential towards that with lower potential. More generally, fluid potential gradients exist in fluid that is not at rest (not in hydrostatic equilibrium).

Formation (a) A general term in the petroleum industry for “bed”, “reservoir”, or any rock unit or group of rock units. E.g., formation water, producing formation, formation density log. (b) Strictly, it is the name of an objective subdivision of a sequence of rocks on the basis of lithology only. In subsurface geology, the basis may be electrical log characteristics. Gas-cut mud Mud in circulation is said to be gas-cut when it contains bubbles of gas at the shale-shaker. Release from solution may be involved, but gas can be incorporated in the mud from the volume of rock drilled. The bubbles expand as they approach the surface due to the decreasing pressure. The mean density of the mud column is thus reduced, leading to a risk of a blowout. Geopressures Formations in which the pore-fluid pressures exceed the normal hydrostatic have been called geopressured, and their pressures, geopressures. It is an undesirable synonym for abnormally high pore pressures because all pressure regimes within the Earth are geopressures -but it is too widely used to be abandoned now. Geostatic Pressures and pressure gradients due to the gravitational load of the total overburden (solid and fluid) are called geostatic. Synonymous with overburden, which has priority. The synonym lithostatic is undesirable. Ground water In practice, this term is restricted to the llsuble water in rocks (fresh or brackish), not for the saline pore water. Growth structures Structures that grew while the sediment in them accumulated, so that the thicknesses of rock units reflect the growth of the structure. Growth anticline. Anticline in which the rock units are thinner in crestal areas than in the flanks, interpreted as due to a slower rate of subsidence in crestal areas.

434

GLOSSARY

Growth fault. A fault that separates correlative sequences of which the thicker is on the downthrown side. As a consequence of this thickness contrast, the throw tends to increase with depth. This is not a diagnostic criterion because antithetic faults may reduce the throw. The interpretation is that the “upthrown” block was subsiding slower than the downthrown block. There are many synonyms: concurrent, contemporaneous, depositional, progressive, recurrent, synsedimentary.

Halokinesis, halokinetic The deformation of sedimentary rocks by a salt dome is halokinetic deformation, and the process is halokinesis. This usage is mainly European. Preferred synonym: salt tectonics. Head Refers to the vertical length of a column of fluid, usually liquid. It is ambiguous if not qualified. It is an energy per unit of weight, with dimensions of length, not pressure. Elevation head (less desirably, potential head). The potential energy per unit of weight due to elevation, ie., the elevation of the point at which pressure p is measured, above (+) or below (-) an arbitrary datum (usually sea-level). Pressure head. The vertical length of a column of liquid supported, or capable of being supported, by pressure p at a point in that liquid. It is given by the pressure divided by the weight density ( p l p g ) . When the purpose is to draw maps of potentiometnc surfaces, pg is replaced by a constant, which in SI units is conveniently lo4 kg rnp2 sP2. Velocity head. This is the head due to the kinetic energy of the fluid. It is given by V 2 / 2 g ,and is negligibly small in most geological contexts. Total head. The total head, h , is the algebraic sum of the pressure head and the elevation head, h = ( p / p g ) + z . It is strictly proportional to the fluid potential (lacking only the factor g). The velocity head is neglected. Hiatus A break in the sequence of accumulated sediments; a surface that represents the passage of time without the accumulation of sediment. The synonym non-deposition is undesirable because there may have been deposition without accumulation. Plural, hiatus or hiatuses, not hiati. Hydraulic conductivity Synonymous with coeficient of permeability. See Permeability. Hydraulic gradient The difference of total head (see Head) divided by the macroscopic length of porous material between the points where the total head is measured. (More properly, it is the gradient at a point.) Note that the gradient of apotentiometnc surface is strictly equal to the hydraulic gradient only when the aquifer is horizontal, but it may well be a sufficiently close approximation.

GLOSSARY

435

Hydraulic radius A measure of the size and shape of the pore space in a rock. It is the volume of the movable liquid divided by the total wetted area. In section, it is the area of movable liquid divided by the wetted perimeter. It has the dimension of length, L. There are difficulties in understanding the significance of this because 1 m3 of homogeneous material has the same hydraulic radius as 1 cm3, or any part, of the same material. Perhaps for this reason it is called the characteristic dimension of the pore space. Hydrostatic The pressures in a liquid at rest, and their gradients, are said to be hydrostatic. The velocity of subsurface liquids is usually so small that the criterion “at rest” is not strictly required. When these pressures imply a free upper surface to the liquid near the surface of the earth, they are called normal hydrostatic (for an abnormally pressured reservoir may have a hydrostatic gradient). Interfacial tension When two immiscible fluids are present in the pore-space of porous material, the interface between the two fluids acts as if it were an elastic membrane in a state of tension. It is called surface tension when the second fluid is air. The dimensions are MT-~. Intrinsic permeability The component of permeability that is due to the porous material alone, independent of the physical properties of the fluid passing through it. It has the dimensions of an area, L2. See Permeability. IsoThis prefix is from the Greek and means equal, so an isobar, for example, is a line of equal pressure. Those who enjoyed a classical education will not mix prefixes and roots from Latin and Greek. For this reason, isopotential is regarded as undesirable - but few would regard this as important nowadays. Joint A single length of drill pipe, or a single length of casing. The length is nominally 30 ft or 10 m, but the actual length is variable and usually rather less than the nominal length. See also Stand. Juxtaposed Two rock units that are brought together by a fault are said to be juxtaposed.

Kick A borehole is said to kick if the pressure or energy of the pore fluids exceeds the pressure or energy of the mud in the borehole. A kick is the first stage of a blowout, but by no means do all kicks lead to blowouts.

436

GLOSSARY

Liner A string of casing that is not continuous to the surface, but hung in a casing that has been cemented, Lithostatic The pressure, or pressure gradient, exerted by the total overburden, solid and fluid. Synonyms: overburden, geostatic, both of which have priority over lithostatic. Undesirable synonym of overburden and geostatic. Marker Any distinctive, but usually thin, part of a stratigraphic sequence that can be recognized over an area, or from borehole to borehole in electrical logs. Mass density See Density. Migration The movement of fluids generally through rocks in the subsurface. Primary migration. The movement of petroleum from its source material within the source rock to the carrier bed in which it will migrate further. Secondary migration. The migration of petroleum within the carrier bed, from the end of primary migration to the trap. Non-deposition Commonly refers to a break in a sequence of sedimentary rocks, but the term has no merit. Deposition of sediment is not necessarily the same thing as accumulation of sediment. Non-accumulation is factual, and much to be preferred. Normal hydrostatic See Hydrostatic. Offlap Used in the opposite sense to onlap, an offlap sequence is one in which successively younger strata occur seaward of the older, as in some regressive sequences, but it is not strictly synonymous with regressive sequence. It is a word that should probably be restricted to seismic stratigraphy. Onlap The accumulation of successively younger strata, each overlapping the previous, in a transgressive sequence. Like oflap, onlap is not strictly synonymous with transgressive sequence; and it is a word that should probably be restricted to seismic stratigraphy.

GLOSSARY

437

Overburden In subsurface geology, the overburden is the total sequence of rocks, solid and fluid, above the layer of interest. The pressures exerted by the overburden are overburden pressures (and they give rise to overburden pressure gradients). Synonym to the adjective geostatic, only in the context of pressures. Permeability A porous rock through which fluid can flow is said to be permeable, and the rock has the property of permeability. A rock through which fluid easily flows is said to have high, good, or large permeability: conversely, low, bad, or small permeability. There are two distinct types of permeability, intrinsic permeability and hydraulic conductivity. Intrinsic permeability ( k ) . Permeability that is a property of a rock, independent of the fluid flowing. It has the dimensions of an area, L2. Hydraulic conductivity or coeficient of permeability ( K ) . In these quantities, the physical properties of the fluid are lumped into one coefficient with those of the rock. Dimensions of a velocity, L T-'. Effective permeability. When two immiscible fluids occupy the same pore space of a rock, the movement of each is influenced by the other, and by their saturations. We speak of the effective permeability of that rock to oil, or to gas, or to water. It is in the nature of an intrinsic permeability, and its dimensions are those of an area, L2.

Relative permeability. The ratio of effective permeability to oil, gas, or water, to the permeability when that rock is saturated with that fluid only is called the relative permeability. It is dimensionless,being a ratio of identical dimensions. Note: For more detailed discussion, see Chapman, 1981. Geology and Water. Nijhoff/Junk, The Hague, pp. 49-70.

Piezometric surface See Potentiometric surface. Pore ratio See Void ratio. Porosity (f,4 commonly) The ratio of pore volume to gross rock volume, that is, the volume of pore space divided by the volume of pore space and solids. It is usually spoken of as a percentage. It is dimensionless, and related to void ratio by f = E / ( E + 1). The symbol 4 should be used with care because it is also the normalized unit of grain size in sedimentary rocks. Potential See Fluid potential.

438

GLOSSARY

Potentiometric surface If the total head (see Head) relative to the same datum surface is computed for several points in a body of fluid, points on a notional surface are obtained. The potentiometric-surface map is a map of total head. The notional surface can be contoured, and the contours are equipotentiallines. Fluid flows in a direction at right angles to these contours, and flows in the direction of decreasing head. Piezometric surjiuce is an undesirable synonym because it implies a pressure-measuring surface, which it is not. It is an energy-measuring surface. Pressure Force per unit of area. The pressure af a point in a fluid is the force per unit of area acting on an element of volume that is small in relation to the bulk of the fluid, but large in relation to its molecules. Dimensions are M L - ' T - 2 . SI units are pascals (Pa) = newtons per square metre (N m-2) = kg m-' s - ~ . Regression, regressive Strictly, a fall of sea-level relative to the land, with a consequent extension of the land area at the expense of the sea. Sedimentary sequences that contain shallowerwater sedimentary rocks on deeper-water sedimentary rocks, or continental on marine, are called regressive. Most regressive sequences, however, are more readily understood in terms of an excess of sediment supply over that that can be distributed more widely by the energy available, so that this surplus accumulates and extends the land area, as in a delta. Cf. Wansgression. Round trip In rotary drilling, pulling the bit and running in a new one. Saturation The saturation of a rock with respect to a fluid is the proportion of the pore space occupied by that fluid. Specific surface The surface area of solids in bulk volume of porous materials. Dimension L-'

.

Specific volume The volume of unit mass of the substance, that is, the reciprocal of mass density. Dimensions M-' L3. Specific weight Weight divided by the volume of substance or material. It is the same as the weight density, pg. Dimensions M L - 2 T - 2 . Stand When drill pipe or casing is pulled from the hole, it is stood in the derrick in lengths of threejoints, called a stand. A long stand is of four joints.

GLOSSARY

439

Strain The deformation of a material under stress. Stress A force per unit of area. It may be compressive, tending to shorten the dimension of the material under stress in the direction of the stress, or tensional, tending to extend. Aprincipal stress is a stress acting perpendicularly to a surface along which there is no shear stress. When the three principal stresses are equal, the state of stress is said to be hydrostatic (an unfortunate term for those of us who are also concerned with the fluid content of rocks, and care must obviously be taken to avoid ambiguity). When they are unequal, they are called the maximum, intermediate, and minimum principal stresses, and they are labelled 0 1 , 0 2 , and 0 3 , respectively. Stresses can be resolved into components, such as that normal to a fault plane (the normal stress, a,) and a shear stress, t,along the fault plane. Stoke Unit of kinematic viscosity, which is the absolute or dynamic viscosity divided by the mass density of the fluid, q / p . Dimensions are L2T-', and the units are square centimetres per second. The common practical unit is the centistoke (cSt), a hundredth part of a stoke.

Sub A short length of drill pipe. A short length of drill-collar is sometimes called a stinger. Subcrop The area of a rock unit that is in contact with an overlying unconformity surface is the subcrop of that unit. A subcrop map may be regarded as a palaeogeological map of that unit at the time of the commencement of post-unconformity sediment accumulation. Surface tension The air/water interface in a porous rock acts as if it were an elastic membrane in a state of tension, supporting a pressure differential across it. This is surface tension. But it is defined in terms of the work required to separate unit area of the interface. Dimensions are M T - 2 . See also Interfacial tension. Swab A piston-like action that sucks formation fluids into the borehole. It can also occur accidently when pulling the drill-string, and is sometimes the cause of blowouts. Synsedimentary Occurring at the same time as accumulation of sediment. For example, synsedimentary fault, a synonym for growth fault.

440

GLOSSARY

TCF Trillion cubic feet. (See Rillion.) Ransgression, transgressive Strictly, a rise of sea-level relative to the land, with a consequent reduction of land area. Sequences that contain deeper-water sedimentary rocks on top of shallowerwater sedimentary rocks, or marine on continental, are called transgressive. Cf. Regression. 'Ransition zone In a stratigraphic sequence that contains mudstones with abnormally high pore pressures, the zone in which the pore pressure increases rapidly with depth is called the transition zone. It is the zone between that of normal hydrostatic pore pressures and that of relatively constant abnormality. It is also the zone in reservoirs of transitional saturations between crude oil and water, natural gas and water, and natural gas and crude oil. Billion 10l2 in U.S.A., 10l8 in many other countries. Like billion, it should only be used when there is no danger of misunderstanding. In the oil industry, lo1* is always meant. Natural gas volumes in trillion cubic feet (TCF) mean 10l2 standard cubic feet. 'kip gas When resuming circulation after a round trip, the mud that was near the bottom of the hole is sometimes found to be gas-cut when it reaches the shale shaker. This is trip gas. It is distinguished from true gas-cutting by its short duration and its relationship to the round trip. Viscosity The internal resistance of fluid to flow. The larger the resistance, the larger is the viscosity. There are two measures of viscosity. Coeficient of viscosity, absolute viscosity, dynamic viscosity. The ratio of shear stress to rate of shear strain: Q = t/(dV/dz). It is the tangential force per unit of area that maintains unit relative velocity between two parallel planes unit distance apart. Dimensions M L-' T-'. Kinematic viscosity. The ratio of dynamic viscosity to mass density of the fluid: u = q / p . It concerns motion without reference to force. Dimensions L2T-'. Void ratio The ratio of pore volume to the volume of solids in a sedimentary rock. The symbol is usually E or e. So 6 = f / ( l - f ) . See Porosity. Void ratio has the merit of being a ratio of a variable to a constant (for practical geological purposes) and is useful in numerical compaction studies.

GLOSSARY

441

Wall-sticking If the mudweight greatly exceeds that required to contain the formation fluids in a permeable sandstone, the fluid potential gradient across the wall of the borehole, through the mud cake, may cause pipe to stick to the wall of the hole. It is cured by lightening the mud. Casing can also stick in this manner. Water-table In practice, the free upper surface of the water in an unconfined aquifer, that is, the level at which the water would be found in a well cased to the aquifer, but not pumping. Weight density The weight of a substance divided by its volume, that is, pg. This term is to be preferred over specific weight, but they are synonymous. Dimensions M L - 2 T - 2 . Symbol commonly y . Wet, wetted, wetting When two immiscible fluids saturate a porous material, one preferentially adheres to the solid surface, excluding (or tending to exclude) the other. The adhering fluid is called the wetting fluid or wetting phase: the other is the non-wetting fluid or non-wetting phase. Producing oil sands are water-wet. Once the irreducible water saturation has been reached in a homogeneous reservoir, the wetting phase (oil or gas) only is produced, without water. (This is the reason for the assertion that producing reservoirs are water-wet. Water production is the result of inhomogeneity in the reservoir or coning of the water table.)

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443

PRACTICAL CONVERSION FACTORS *

Area [ L ~ ] 1m2

= 1.55 lo3 = 10.7639 = 1.196 = 247.11 x

Density (mass or weight) 1kg mP3 = 10-3 = 62.428 x = 1.940 x loP3 1 Nm-3 = 6.366 x = 851.0 x lop6 = 35.74 10-3

square inches square feet square yards acres

grams/cubic centimetre pounds/cubic foot slugs/cubic foot pounds weight per cubic foot pounds weight per U.S. gallon pounds weight per barrel (lbf/bl)

Flow rate [L3T-' and LT-'1 1m3 s-l

1m3 mP2 s-l

= 35.31445 = 13.198 x lo3 = 15.850 x lo3 = 791.89 x lo3 = 951.02 x lo3

= 543.44 103 = 3.051 x lo6 = 3.1557 x lo9 = 24.542 = 20.436

cubic feet/second (cusec) gallons/minute, British or Imperial U.S. gallons/minute Imperial gallons/hour U.S. gallondhour barrels of oil/day cubic feet/day ml cm-2 per year U.S. gallons per sq. foot per second Imp. gallons per sq. foot per second

Force and weight [ M L T - 2 ] 1newton (N)

=1 = 100 x Id = 0.1020 = 0.2248 = 7.233

kg m sP2 dynes kilograms force (kgf) pounds force (lbf) poundals

* These conversion factors are sufficiently accurate for most practical use, but not for legal conversion.

444

PRACTICAL CONVERSION FACTORS

Gradient 1 N m-l

= 101.97 x lop3 = 68.522 x

1 Pa m-'

=1 = 101.97 x lop3 = 10.197 x lop6 = 44.208 x = 54.864 x lop3

1°C km-'

kgf m-l lbf/ft N m-3 = N m-2 m-1 kgf m-2 m-l kgf cmW2m-l psi/ft "F/lOOft

Length [ L ] l m

= 39.37

inches feet yards = 621.371 x lop6 miles = 106 microns ( p ) = 1010 angstroms (A)

= 3.2808 = 1.0936

Permeability (intrinsic) 1 darcy 1mD

x 10 x 10-~ cm2 x 1pm2 x 10 x 10-12 cm2 x 1 0 - ~ pm2

Pressure 1pascal (Pa)

=1 = 10 x 10-6 = 10.197 x = 9.8692 x = 10 = 145.04 x 10W6 = 20.8854 x lop3

N m-2 bar kgf cmP2 atmospheres dynes cm-2 lbf/square inch (psi) lbf/square foot

= 277.78 x = 11,574 x lop6

hours days weeks months of 30.44 days years of 365.25 days

Time 1 second

= 1.6534 x lop6 = 380.23 x = 31.688 x lop9

Velocity [L T-'1

1 m s-l

= 3.6

= 3.2808 = 2.2369

km/hour feetlsecond miles per hour

445

PRACTICAL CONVERSION FACI'ORS

Viscosity 1P a s 1m2 s-l

=1Nm-2s = 0.6720 = 20.8854 = 10 103 = 1.5500 x lo3 = 10.7639

= 10 poise = lo3 CP pounds (mass)/foot second lbf. secondhquare foot stokes = lo6 cSt square inches/second square feetlsecond

= 219.969 = 264.173 = 35.3145 = 810.71 x lop6 = 6.2898

Imperial gallons U.S. gallons cubic feet acre-feet barrels (bbl)

= 10 = 10

maxwell line

Volume [ L ~ ] 1m3

Magnetic flux 1weber (Wb)

10-9 10-9

Magnetic flux density, induction 1 tesla (T)

= 100 x = 100 x 10-6 = 1 10-9

gauss maxwell cm-2 gamma

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447

SUBJECT INDEX *

abnormal pressures bottom of, 34, 83,249 causes, 77,392,410 petroleum generation, 80,343 detection/prediction, 155, 163, 168, 177, 178, 187,241 ahead of bit, 241 case histories, 176, 247 geophysical, 155, 173, 174, 178 MWD, 155,272 evaluation borehole logs, 189-194, 202-210, 216217,223 limitations, 224 geophysical, 155 direct and indirect measurement, 77,347 limestone reefs, 8 shallow hazards, 281 top, 173, 174, 190, 203, 216, 224, 229, 231, 234,346, 247,353,366 and production, 29,391-427 diachronous, 25,35 Gulf Coast, 77, 78, 83, 84 petroleum distribution, 391-427 prediction, 158,243,244 temperatures, 347 acoustic (see also sonic) detection, blowouts, 331, 333 logging, see well logging Adriatic, 4 Aegean, 4 Africa, 5 S.America compared, 11 ages Carboniferous, 4 Cretaceous, 3, 8, 39, 40, 45, 343, 347, 349, 351,358,364-367,391 Devonian, 4, 369 Jurassic, 39, 40, 366 Mesozoic, 3, 4, 5, 8 Mississippian-Devonian, 343 Permian, 45 See also the Table of Contents.

Tertiary, 3-5, 8, 9, 11, 19, 26, 28, 34, 39, 40, 343, 347-349, 351, 359, 363-366, 369, 371, 173, 176,391-427 Algeria, 5, 6 Angola, 6 “aquathermal” pressuring, 81-83, 409, 413 Argentina, 11 artesian basins, 19 Asia, 11 Asia, Southeast stratigraphy similarities, 28 Asmari Limestone, 22 associations, 36 Australia, 8, 9, 41, 42, 45 At departure, 175 Azerbaijan, 4,23 Bakken Formation, 343 Bangladesh, 11 BASIC program, safe penetration rate, 285 basins, sedimentary (see a h rift basins), 20, 57, 73 AureTrough, 8 Beaufort-Mackenzie, 34 Bengal, 11 Bighorn, 349,367 Bonaparte Gulf, 8 Carnarvon, 8 Exmouth Plateau, 43 Gippsland, 8 Green River, 346,348,349,350 pressures, 351 temperatures, 351 Gulf Coast, see Gulf Coast Hanna, 349,369 temperatures, 369 Molasse, 71,81 potentiometric surface, 72 North China, 7 Paradox, 349 Perth, 8, 46 Piceance, 349,358 pressures, 358,359 recoverable gas, 358

448 basins, sedimentary (continued) Piceance temperatures, 359 vitrinite reflectance, 362 Powder River, 349,368 pressures, 368 temperature, 368 'hrkmen, 395 Uinta, 349, 364 pressures, 365,366 Viking Graben, 40 WiIliston, 79, 346, 349,363 pressures, 363 temperatures, 364 Wind River, 349 biogenic gas, 346 Black Sea, 126 blowouts, 282, 335-338 deep, 319 diverter system, 285 anchors, 300 control system, 307 design, 287 example, 287 failure, 286 plugging, 307 working pressure, 297 dynamic well control, 286 design, 308-311 equilibrium gas flow rate, 296 exit velocity calculation, 288 floating drilling vessels, 312 flow rate, 319 formation fracture pressure, 297 gas drilling practices, 283 natural, 281 shallow, 282 prevention, 282 Gulf Coast, 319 prevention diverter system, 285-288 recommendations, 314 relief wells (see also Measurement While Drilling) accuracy, 329 acoustic location, 331, 333 control, 322 dynamic, 324 high production, 326 overbalance, 325 polymer injection, 326 water flood, 322 design, 326

SUBJECT INDEX engineering, 319 examples, 335 locating target, 330 MWD, 327 planning, 326 steering, 327 surveying, 327 trajectories, 326 trajectory calculation, 328 shallow early procedures, 285 formation productivity, 293, 296 gas, 319 computer model, 299 rate of erosion, 300-306 Bolivia, 11 borehole orientation (see also blowouts, relief wells) MWD, 261-263 Borneo, 8, 9, 23, 28 stratigraphy, 28 Brazil, 11 bright spots, 171, 283,417 Brunei, 29 bulk density of rocks, 56 Burma, 11,21 calculations acoustic velocity in rocks, 156 borehole trajectory, 328 compaction curves, 61, 62, 77 exit velocity, 288 flowing pressure gradient, 291 formation fracture pressure, 297 heads, 71 hydraulic radius, 65 loss of wall thickness, 304 material balance, 94f. pore pressure from logs, 190-194, 203-210, 216,217,221-223 reservoir performance, 98-103 resistance, flow string, 321 resistance, formation, 319 safe pmetration rate, 285 sliding velocity, 88 tortuosity, 66 Canada, 14,23,33-35 caprock 214 capillary pressure, 54 carbonates, 8, 19, 20, 22, 39, 40, 42, 45, 46, 58, 176,380,381,382 ase studies, 114, 176, 178, 181, 182, 247 Caspian Sea, 5, 23, 414 Celtic Sea,

SUBJECT INDEX chalks, 3 China, People’s Republic of, 6 clay minerals, 36, 80 diagenesis, 80, 345, 395 clays void ratios, pressure, 121 Colombia, 11 Common Mid Point (CMP), 155,159,165 compaction, 59, 98, 107, 111, 112, 173, 188, 345 water composition changes, 112-120, 143 laboratory experiments, 120,131, 135 normal trend, 61,62,174, 178,187, 188-193, 202-206 undercompaction, 37, 76, 78, 84, 113, 118, 119, 168,203 compaction curves, 60 Athy, 60,61 formulae, 61, 62, 77 Hedberg, 60,61 compressibilities, 97, 98 gas, 95 rock and water, 93 Compton scattering, 199 computer program, 285 conductivity, 205-210,225-226 Darcy’s apparatus and results, 64 Darcy’s law, 63 common error, 64 limits, 67 Reynolds number, 68 Deep Sea Drilling Project, 108 deltas Baram, 29,395 Lena (Siberia), 33 Mackenzie, 14,23,33-35 habitat of petroleum, 34 stratigraphy, 34 structure, 34 Mahakam, 29 structural style, 38 Mamberamo, 8,79 Mississippi, 112, 282 Niger, 23,30, 31, 155, 173 case history, 178, 181, 182 cf. Orinoco, 36 diapirs, 32 habitat of petroleum, 32 overthrust, 32 seismic section, 181, 182 stratigraphy, 32 Nile, 5 Orinoco, 36 Denmark, 3

449 density, formation MWD, 268 diachronism, 25 diapiddiapirism, 2, 168 anticlines, 38, 84 migration of fluids, 410, 416 Niger delta, 32 dimensions, physical, 62 Dickinson’s work, 25 drill bit, seismic energy source, 241,245, 247 frequency spectrum, 246 drilling break, 23 drilling practices, 283 drilling parameters MWD, 269 drive mechanisms, see reservoir Ecuador, 11 effective stress, 57, 180 and compaction, 76 Egypt, 5 electrical logging, see well logging electrical properties shales, 232 enhanced oil recovery, 377 Ethiopia, 6 Europe, 3 evaluation: 155 formation, 257-259, 266 faults (see also growth structures), 167 isolate sandstones, 26 migration of fluids, 410 fields Arun, 338 Attaka, 29 Badak, 29 Baram, 29 Bekapai, 29 Bunju, 28 Caillou Island, 406 Chocolate Bayou, 113 Ekofisk, 3,40,42,58 Ellenburger, 377 Groningen, 3 Hackberry, 115, 116, 117 Haft Kel, 22 Handil, 29 Hassi Messaoud, 6 Hollywood, 415, 416 Jerudong, 29 Khaur, 21 land subsidence over, 57 Ekofisk, 58

450 fields (continued) land subsidence over, 57 Lagunillas, 57 Wilmington, 57 Manchester, 115, 116, 117 Masjid-i-Sulaiman, 22 Miri, 28 Nilam, 29 North Ossum, 97 Oloibiri, 30 Salt Creek, 377 Sanga-Sanga, 28 Seria, 29 Spearhead Ranch, 369 Taglu, 34, 83 Tarakan, 28 floating mud cap, 8 fluid statics, 52 fluids, see water, pore water formation fracture gradients, 344, 350, 354, 358, 362, 370, 409, 414, 419 natural, 343, 362, 365, 370, 371 pressures, 297 gamma ray MWD, 266 gas associated, 379 biogenic, 346 non-associated, 382 well data, 383 probability, 422 recovery vs. well density, 385-388 resourccs, 377 vs. depth, 405 gasloil ratio, 379, 380, 381 Gas Research Institute, 377 Generalized Linear Inversion (GLI), 242 geophysics (see also seismic), 155 geothermal, see temperature Germany, 3 gradients, see pressure gradients growth structures, 37 and abnormal pressures, 83 anticlines, 36, 37, 38, 46 diapiric, 38, 84 Mahakam delta fields, 30 Nigcr dclta, 32 faults, 29, 35, 36, 37, 38, 46, 84 age relationships, 46 Gulf Coast, 38 isolate sandstoncs, 26 Mackenzie delta, 34

SUBJECT INDEX Mahakam delta, 30, 38 Niger delta, 32, 37 rift basins, 39, 45 subsidence, 81 gravity, 184 Guiana, 11, 13 Gulf Coast, 21, 23, 24, 25, 37, 115, 158, 190, 193, 202,223, 345,364,380, 382, 383 and Iran, 28 blowouts, 319 caprock, 214 clay mineral diagenesis, 80 At departure, 175 diapiric salt, 114 geothermal gradients, 82 normal compaction, 204 normal gradient, 73, 194 P l Z plot, 95 petroleum distribution, 391-427 sources, 417 plotting advice, 231, 232 pore-water salinities, 112 prcssurcs, 192, 21 1,212 shale properties and temperature, 234 stratigraphy, 26 Tertiary shale properties, 232 top of abnormal pressures (TAP), 22 Gulf of Mexico, 101, 114, 287, 345, 155, 169, 173,380, 381,395 case history, 176 fault seeps, 414 outer continental shelf, 285 seismic section, 177, 179, 180 habitat of petroleum Bornco, 29 Mackenzie delta, 34 Niger delta, 32 heads defined, 71 Himalayas, 19 hot spots, 414, 417 hydraulic gradient, 71 hydraulic radius defined, 65 hydrocarbons, see also petroleum generating rate, 344 India, 11 Indonesia, 8, 23, 338 Java, 8, 9 Kalimantan, 8, 9, 28, 29 structural style, 38 Sumatra, 8, 9 Timor, 8

SUBJECT INDEX interfacial tension, 54 interval transit time/velocity, 155, 173 and RMS, 172 inverse VSP, see Vertical Seismic Profile, inverse Iran pressure gradients, 2 early difficulties, 22 Iraq pressure gradients, 2 Ireland, 3 Irian Jaya Mamberamo River, 8 isolated sandstones, 27 Italy, 4 Japan, 8 Nagaoka Plain, 9 Kazakhstan, 4 kicks, 23,319 Madagascar, 6 magnetic field near casing, 334 magnetometer, 332 maximum hydrocarbon window, 419-427 Measurement After Drilling (MAD), 187, 258 Measurement While Drilling (MWD), 187, 235 251,327 abnormal pressure detection, 272 accelerometers, 260, 328 borehole orientation, 261-266 density, 268 directional steering and survey, 259-266 accuracy, 265 drilling parameters, 274 gamma ray, 266 gamma ray, resistivity, 257, 258 neutron porosity, 268 relief wells, 327, 337 resistivity, 266 sensors, 259 systems, 275-277 telemetry techniques, 252 acoustic, 253 electromagnetic, 254 hardwired, 252 mud pulse, 255 Mediterranean, 4 Mesaverde Group, 348,349,351,358,360,368 methane, 80,346,363 Mexico, 14 migration, fluids, 419 diapirs, 410 faults, 410

45 1 vertical, 409 Middle East, 2 Mohr-Coulomb criterion, 86 Morocco, 5 Mozambique, 6 mud circulation rate, 284 gas-cut, 283 effect of hole size, 284 weights (see also pressures), 2, 3, 8, 10, 11, 21,23,158,178,192-194,283,348,392 petroleum cut-off, 396, 397, 401 predicted, 178 profiles, 353,355 mud volcanoes, 8,29 Multiwell Experiment (MWX), 358 MWD, see Measurement While Drilling neutron porosity MWD, 268 New Guinea, 23 New Zealand, 8 Nigeria (see also deltas), 5, 30-32 North America, 12, 79 North Sea, 3,40,202 Ar departure, 175 stratigraphy, 44 Norway, 3, 40, 42, 58 Norwegian Petroleum Directorate, 58 Oman, 2 osmosis, 80 orogeny, 29 overburden gradient, 73

P / Z plots, 94 Hammerlindl’s method, 98 modified, 101 normal pressure gradient, 99 not perfectly linear, 94 vs. cumulative gas, 96 Pakistan, 11, 19 Papua New Guinea, 8 parameter d defined, 77 parameter 1 defined, 73 pendular rings, 54 penetration rate, 13, 30, 284, 348 BASIC program, safe rate, 285 permafrost, 33 permeability, 63-65,110,219,296,320-322,343, 346,347 and abnormal pressures, 82 and velocity coefficient, 296 effective, 68

452 permeability (continued) intrinsic and coefficient of, 65 relative, 68 Persian Gulf, 202 Peru, 11 petroleum distribution re abnormal pressures, 391 Phillipines, 8, 9 Plate tectonics, 7 pore fluids, see pore water pore pressures, see pressures pore water (see also pore fluids) case studies, 114 chemistry compaction models, 136 Appelo’s, 142 Bolt’s, 141 Kotova and Pavlov’s, 139 non-thermodynamic, 137 Pol’ster’s, 140, 144 Smith’s, 146 thermodynamic, 141 Warner’s, 137 chlorinity and compaction compared, 119 composition, 111, 116, 117 changes, 108,109 from cores, 118 concentrations, 109 diagenesis, 108, 111 6I8ovalues, 108 density inversion, 114 diagenesis, 111 expulsion, 107 composition, 123-130, 133-136 laboratory experiments, 120 Mississippi delta, 112 salinity changes, 116 in sandstone greater than shale, 115 variations, 112 diapiric salt, 114 potentiometric surfaces, 71 Mesaverde Sandstone, 75 Molasse basin, 72 Viking Sandstone, 74 pressure losses when pulling pipe, 283 pressure estimation equivalent depth technique, 193, 199, 204, 208,218,222, 224 pressure gradients, 21, 97, 178, 179, 203, 343, 344, 353, 356, 361, 362, 366, 368, 406, 414 Algeria, 6 apparent, 348

SUBJECT INDEX “aquathermal”, 410 Aure’Itough, 8 Australia, 8 Bangladesh, 11 Burma, 11 calculation, flowing p.g., 291-295 Canada, 14 Gulf Coast, 95 Gulf of Mexico, 101 Iran, 2 Iraq, 2 Japan, 9, 10 Khaur, 21 New Zealand, 8 normal hydrostatic, 70, 76, 81, 83, 98, 391 Molasse basin, 71 Pakistan, 11 Phillipines, 9 profile, 204 Taiwan, 9 Timor, 8 Trinidad, 11 value of A, 6 , 77 pressures, 69, 155,351, 352, 370, 416 limiting, 28 Pakistan, 20 prediction, 155, 163, 168, 177, 178 shut-in vs. DST, 348 subnormal, 5 primary migration, 54 production versus top abnormal pressures, 423-425 regressive sequences structural style, 38 reservoir communication, 378, 379 drive mechanisms, 94, 96 depletion drive, 96, 99 water drive, 96 reservoirs abnormally pressured, 103 engineering, 93 fractured, 413 material balance, 94, 99 performance prediction, 98 pressure decline, 59 simulation, 93 resistivity (see also shale resistivity), 183, 364, 394, 397,412 MWD, 266 source beds, 346 Reynolds number, 68,291 rift basins, 39, 42 Australia, 42

SUBJECT INDEX rift basins (conrinued) Exmouth Plateau, 43 Gippsland, 8,41 growth faults, 45 North Sea, 40, 41 Perth, 8, 46 stratigraphy, 45 unconformities, 45, 46 Viking Graben, 42 Western Atlantic, 42 Rocky Mountain region, 343, 370 Russia, 4 Sabah, 29 sandhhale ratios, 26, 37, 39, 46, 61, 155, 207, 419 Sarawak, 28, 29 Saudi Arabia, 2 sediment accumulation rates, 108 seismic arrival times, 164 functions, 160 data acquisition, 158 diffraction, 165, 167 reflection, 159 resolution, 163, 166 sideswipe energy, 168 semblance defined, 160 spectra, 162,163, 165-172 shale resistivity plots, 13, 214, 228, 230, 412 shale resistivity ratio, 203, 204, 407, 410, 413, 425 shale water influx, 97 shallow production, 28 sliding, 84 lubricated, 87 unlubricated, 84 sonic logs, 156, 157, 163, 165, 173 departure from normal, 175, 249 sonic velocity/transit time (see also velocity), 188 normal trend, 62 source beds, 346 source beds resistivity, 346 sonic velocity, 346 source rocks, 346 South America, 11 Africa compared, 11 South China Sea, 8 At departure, 175 Southeast Asia, 8 stable isotopes, 362

453 stratigraphy Gippsland basin, 41 Green River basin, 357 Mackenzie delta, 34 Niger delta, 32 NorthSea, 44 regressive sequences, 35 rift basins, 45 top of abnormal pressures and growth structures, 37 structural style regressive sequences, 38 subnormal pressures, 5,71 subsidence Ekofisk, 58,59 Houston district, 57 Lagunillas, 57 Wilmington field, 57, 58 Taiwan, 8 , 9 temperature gradients, 361 China, 7 Gulf Coast, 82 Pakistan, 21 permafrost, 33 South China Sea, 8 Saudi Arabia, 2 temperatures, 343, 346, 347, 351, 353, 354, 366, 369,370,392,403,404,407-409,415 and pore pressure, 412 Mexico, 14 Terzaghi’s relationship, 57 The Netherlands, 3 tortuosity defined, 66 transition zone, 28, 39, 47, 76, 79, 80, 214 and “aquathermal”, 83 ’Rinidad, 11, 21 unconformities, 41 Eocene, 40 Jurassic and Cretaceous, 39 rift basins, 45, 46 United Arab Emirates, 2 United Kingdom, 3 United States, 12-14, 22, 25-28, 57, 58, 377388,385-387,391-427 velocity/transit time, 13, 156-158, 184, 392 anisotropy, 170 elastic constants, 156 inversion, 168, 241, 249 lateral changes, 164, 169 normal trend, 174, 178, 190 not %ear, 62

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