Origin and Prediction of Abnormal Formation Pressures

ORIGINAND PREDICTIONOF ABNORMALFORMATION PRESSURES Volumes 1-5, 7, 10, 11, 13, 14, 16, 17, 21, 22, 23-27, 29, 31 are ...

Author: Chilingar G.V. | Serebryakov V.A. | Robertson J.O.

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ORIGINAND PREDICTIONOF ABNORMALFORMATION PRESSURES

Volumes 1-5, 7, 10, 11, 13, 14, 16, 17, 21, 22, 23-27, 29, 31 are out of print.

6 8 9 12 15a 15b 18a 18b 19a 19b 20 28 30 32 33 34 35 36 37 38 39

Fundamentals of Numerical Reservoir Simulation Fundamentals of Reservoir Engineering Compaction and Fluid Migration Fundamentals of Fractured Reservoir Engineering Fundamentals of Well-log Interpretation, 1. The acquisition of logging data Fundamentals of Well-log Interpretation, 2. The interpretation of logging data Production and Transport of Oil and Gas, A. Flow mechanics and production Production and Transport of Oil and Gas, B. Gathering and Transport Surface Operations in Petroleum Production, I Surface Operations in Petroleum Production, II Geology in Petroleum Production Well Cementing Carbonate Reservoir Characterization: A Geologic-Engineering Analysis, Part I Fluid Mechanics for Petroleum Engineers Petroleum Related Rock Mechanics A Practical Companion to Reservoir Stimulation Hydrocarbon Migration Systems Analysis The Practice of Reservoir Engineering Thermal Properties and Temperature related Behavior of Rock/fluid Systems Studies in Abnormal Pressures Microbial Enhancement of Oil Recovery- Recent Advances - Proceedings of the 1992 International Conference on Microbial Enhanced Oil Recovery 40a Asphaltenes and Asphalts, I 40b Asphaltenes and Asphalts, II 41 Subsidence due to Fluid Withdrawal 42 Casing Design - Theory and Practice 43 Tracers in the Oil Field 44 Carbonate Reservoir Characterization: A Geologic-Engineering Analysis, Part II 45 Thermal Modeling of Petroleum Generation: Theory and Applications 46 Hydrocarbon Exploration and Production 47 PVT and Phase Behaviour of Petroleum Reservoir Fluids 48 Applied Geothermics for Petroleum Engineers 49 Integrated Flow Modeling 50 Origin and Prediction of Abnormal Formation Pressures

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ORIGINANDPREDICTIONOF ABNORMALFORMATION PRESSURES G.V. CHILINGAR Professor of Civil and Petroleum Engineering, University of Southern California, Los Angeles, CA 90089-2531, USA V.A. SEREBRYAKOV DCD, Inc., Coulter Lane, Gillette, WY 82 716, USA J.O. ROBERTSON, Jr. Earth Engineering, Inc., 4244 Live Oak Street, Cudahy, CA 90201, USA

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2002 ELSEVIER Amsterdam San Diego-

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92002 Elsevier Science B.V. All rights reserved. This work is protected under copyright by Elsevier Science, and the following terms and conditions apply to its use: Photocopying Single photocopies of single chapters may be made for personal use as allowed by national copyright laws. Permission of the Publisher and payment of a fee is required for all other photocopying, including multiple or systematic copying, copying for advertising or promotional purposes, resale, and all forms of document delivery. Special rates are available for educational institutions that wish to make photocopies for non-profit educational classroom use. Permissions may be sought directly from Elsevier Science Global Rights Department, PO Box 800, Oxford OX5 1DX, UK; phone: (+44) 1865 843830, fax: (+44) 1865 853333, e-mail: [email protected]. You may also contact Global Rights directly through Elsevier's home page (http://www.elsevier.com), by selecting 'Obtaining Permissions'. In the USA, users may clear permissions and make payments through the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, USA; phone: (978) 7508400, fax: (978) 7504744, and in the UK through the Copyright Licensing Agency Rapid Clearance Service (CLARCS), 90 Tottenham Court Road, London WIP OLP, UK; phone: (+44) 207 631 5555; fax: (+44) 207 631 5500. Other countries may have a local reprographic rights agency for payments. Derivative Works Tables of contents may be reproduced for internal circulation, but permission of Elsevier Science is required for external resale or distribution of such material. Permission of the Publisher is required for all other derivative works, including compilations and translations. Electronic Storage or Usage Permission of the Publisher is required to store or use electronically any material contained in this work, including any chapter or part of a chapter. Except as outlined above, no part of this work may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without prior written permission of the Publisher. Address permissions requests to: Elsevier Science Global Rights Department, at the mail, fax and e-mail addresses noted above. Notice 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. Because of rapid advances in the medical sciences, in particular, independent verification of diagnoses and drug dosages should be made. First edition 2002 British Library Cataloguing in Publication Data A catalogue record from the British Library has been applied for. Library of Congress Cataloging-in-Publication Data Chilingar, George V., 1929Origin and prediction of abnormal formation pressures / George V. Chilingar.- 1st ed. p. cm. - (Developments in petroleum science, ISSN 0376-7361 ; 50) ISBN 0-444-51001-X (alk. paper) 1. Reservoir oil pressure. 2. Oil well drilling. 3. Gas well drilling. I. Title. I1. Series. TN871 .C52 2002 622'.3382-dc21

2002016357

ISBN: 0 444 51001 X ISSN: 0376 7361 Q The paper used in this publication meets the requirements of ANSl/NISO Z39.48-1992 (Permanence of Paper). Printed in The Netherlands.

DEDICATION This book is dedicated to His Royal Highness Prince Abdullah bin Abdulaziz, Crown Prince and Deputy Prime Minister, and Head of The National Guard of Kingdom of Saudi Arabia for his relentless support of all branches of engineering and sciences in order to improve the well-being of mankind.

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Vll

PREFACE

This book's 1 goal is to provide the geologists and engineers working in the petroleum industry with the latest knowledge on subsurface abnormally-pressured systems associated with hydrocarbon accumulations. Abnormally high- or low-pressured zones are succinctly defined as having a pore pressure gradient trend deviating from the normal hydrostatic pressure gradient over a given depth range. Drs. G.V. Chilingar, V. Serebryakov and J.O, Robertson have brought together a team of experts who have methodically scrutinized recent scientific and engineering developments concerning the global distribution, origins and predictions of abnormallypressured environments. The contributors have many years of collective experience as geologists, geochemists, geophysicists and petroleum engineers in studying, strategizing, detecting and coping with different kinds of pressure environments and subsurface mass transport-pressure phenomena. Their findings are based upon critical inquiry into the scientific details behind the proposed ideas and concepts of this phenomenon. They present an account of the nature of mass transport processes associated with such pressure systems and their accompanying patterns of geochemical and mineralogical changes. As petroleum engineer and geologist, I am convinced that their approach is definitely a worthwhile effort, even if many of the relationships that have been formulated and presented in the technical literature about the framework of these pressure systems are still of an observational and empirical nature. Exploration for large oil and gas accumulations is taking the industry into the offshore deep-water environments on the outer continental shelf. Abnormally-high formation pressures are ubiquitous in 'geologically' recent pelitic sedimentary environments, and their overpressure magnitude must be by necessity identified prior to drilling and completing a well. The subsurface pressure regime is hostile. Seismic detection and prior knowledge on subsurface pressure conditions are prerequisites in promoting safe drilling and development operations. Certainly, caution mitigates the risk of having costly pressure surges and blowouts, disruption of the company's unrealized cash stream, and occurrence of potential injury and loss of life to those individuals who are involved in well construction. Pressure prediction is the main technology focus in the majority of the book's chapters. Though the topic of abnormally-pressured zones is rooted in the preceding century, the application of thermodynamics to the physicochemical problem is just now being explored. Recent publications are helping to recast our opinions on the origin and maintenance of abnormal pressure zones and the resulting physical and chemical artifacts. 1This book is contribution No. 15 of the Rudolf W. Gunnerman Energy and Environment laboratory, University of Southern California, Los Angeles, California

viii The patterns of fluid flow powered by compaction disequilibrium or tectonic stress conditions, presence of salt beds and higher than normal geothermal temperatures create changes in the salinity of the pore water and its content of dissolved gases that flow out of and through the sediment/rock pore space. These processes determine the subsurface pressure regime, its integrity and stratigraphic distribution, and diagenetic/catagenetic alteration. The nature of abnormal pressure zones fluctuates over geologic time, and diagenetic/catagenetic history is manifested in the aqueous geochemistry and corresponding changes in the associated mineralogy especially clay mineralogy. Discussion on the lack of smectite to illite transformation in the Caspian Basin is enlightening. The book is offered in the hope that our knowledge will provide a new foundation for bringing about improved field performance, initiating innovative field and laboratory research, and nurturing analytical dialogue among the geoscientists and engineers. In addition to the customary topics discussed, there are two chapters that address other associated issues. One important ancillary topic is production-induced surface subsidence. Subsidence is the result of abnormally-low formation pressures owing to the production of fluids. The influx of shale water into the depleting hydrocarbon-producing zones results in shale compaction. The other chapter explores the use of analytical model studies, which complete the abnormal pressure picture by adding insight into likely pressure prediction strategies. In conclusion, this book is a welcome addition to the petroleum literature. H.H. Rieke Lafayette, LA, USA

1x

LIST OF CONTRIBUTORS

E AMINZADEH

President d G B - USA & FACT, 14019 SW FWY, Suite 301-230, Sugarland, TX 77478, USA

L.A. BURYAKOVS KY

5001 Woodway Dr., Apt. No. 702, Houston, TX 77056-1718, USA

G.V. CHILINGAR

University of Southern California, 101 So. Windsor Blvd., Los Angeles, CA 90004, USA

R.D. DJEVANSHIR

Institute of Deep Oil and Gas Deposits, Azerbaijan Academy of Sciences, Baku, Azerbaijan

E.C. DONALDSON

Consultant, Rt2, EO. Box 53, Wynnewood, OK 73098, USA

W.H. FERTL

Deceased

M.V. GORFUNKEL

Consultant, 676 Rain Tree Circle, Coppell, TX 75019, USA

A.E. GUREVICH

Consultant, 119 Avonlea Dr., The Woodlands, TX 77382-1058, USA

R. ISLAM

Professor and Killam Chair in Oil and Gas, Faculty of Engineering, Dalhousie University, E O. Box 1000, Halifax, Nova Scotia, Canada B3J2X4

S.A. KATZ

Consultant, 12250 S. Kirkwood Road, No. 1625, Stafford, TX 77477, USA

L. KHILYUK

Consultant, Russian Academy of Natural Sciences, U.S.A. Branch, 101 So. Windsor Blvd., Los Angeles, CA 90004, USA

H.H. RIEKE

Chairman, Petroleum Engineering Dept., USL, EO. Box 44683, Lafayette, LA 70504-4691, USA

J.0. ROBERTSON JR.

President Earth Engineering, Inc., 4244 Live Oak St., Cudahy, CA 90201, USA

V.A. SEREBRYAKOV

Consultant, 118 Mesa Dr., Gillette, WY 82716, USA

V.I. ZILBERMAN

Russian Academy of Natural Sciences, U.S.A. Branch, 101 So. Windsor Blvd., Los Angeles, CA 90004, USA


x1

CONTENTS

Preface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . List of Contributors

Chapter 1

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

INTRODUCTION

TO ABNORMALLY

PRESSURED

vii ix

FORMATIONS

E.C. D o n a l d s o n , G.V. C h i l i n g a r , J.O. R o b e r t s o n Jr. a n d V. S e r e b r y a k o v . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1

Abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2

Introduction

1

Subpressures

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

2

Surpressures

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

2

O r i g i n o f vertical b a r r i e r s r e s u l t i n g in a b n o r m a l f o r m a t i o n p r e s s u r e s

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

3

Undercompaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

4

Tectonic compression

4

Faulting

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

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

6

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

7

Diapirism

Geothermal temperature

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

P h a s e c h a n g e s that p r o d u c e a b n o r m a l p r e s s u r e s

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

O s m o s i s as a f a c t o r for g e n e r a t i o n o f a b n o r m a l p r e s s u r e S a l i n i t y o f interstitial w a t e r

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

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

8 10 11 12

R e s e r v o i r e n g i n e e r i n g c o n c e p t s in a b n o r m a l p r e s s u r e e n v i r o n m e n t s . . . . . . . . . . . . . . . . . . .

13

E c o n o m i c s in o v e r p r e s s u r e e n v i r o n m e n t s

14

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

Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

16

Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

17

Chapter 2

ORIGIN OF ABNORMAL

FORMATION

PRESSURES

G.V. C h i l i n g a r , J.O. R o b e r t s o n Jr. a n d H . H . R i e k e III Introduction

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

Definitions

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

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

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

Compaction process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrostatic pressure

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

F o r m a t i o n or interstitial fluid p r e s s u r e

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

Sediment consolidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S t a t e o f stress in c o m p a c t i n g shales

21 21 21 24 24 24 25

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

29

R e s o l u t i o n o f the total stress field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

30

H y d r o s t a t i c stress state . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

31

D e v i a t o r i c stress state

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

31

Total stress t e n s o r . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

32

Spring models of compaction

33

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

Hooke's law . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Load transfer

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

Porosity-density variations with depth

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

Compaction models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Athy's compaction model

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

Hedberg's compaction model Weller's compaction model

36 37 42 43 44

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

44

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

46

Xll

CONTENTS

Powers' compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Teodorovich and Chernov's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . Burst's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Beall's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overton and Zanier's compaction model . . . . . . . . . . . . . . . . . . . . . . Creation and maintenance of abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M e c h a n i s m s generating abnormal formation pressures . . . . . . . . . . . . . . . . . . . . . . . . . . Undercompaction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tectonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Growth faults . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Transference . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of temperature increase on formation pressure (aquathermal pressuring) Decomposition of organic matter . . . . . . . . . . . . . . . . . . . . . . . . . . Gas migration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Osmosis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Density contrast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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

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

. . . .

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47 49 49 49 51 51 55 55 56 57 57 57 59 59 63 63 64 64

Chapter 3

ORIGIN OF FORMATION FLUID PRESSURE DISTRIBUTIONS A. Gurevich, G.V. Chilingar, J.O. Robertson and E A m i n z a d e h . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Factors causing fluid flow and pressure distributions . . . . . . . . . . . . . . . . . . . . . . . . . . . Factors of fluid flow and pressure distribution and changes . . . . . . . . . . . . . . . . . . . . . Free convection of ground fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forced convection of ground fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Role and distribution of formation permeability . . . . . . . . . . . . . . . . . . . . . . . . . . . Presentation of pressure as the additive sum of two components . . . . . . . . . . . . . . . . . . . . . S o m e major factors of underground fluid forced convection and characteristics for correlation Compaction of granular sediments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . U p w a r d fluid migration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Correlation between porosity and pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Methods used in Azerbaijan to determine abnormal pressures . . . . . . . . . . . . . . . . . . . . Distributions of abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . Definitions of terms as used in this chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 4

Introduction

. . . .

69 69 70 70 71 72 74 75 78 78 80 81 85 85 93 93 94

SMECTITE-ILLITE TRANSFORMATIONS DURING DIAGENESIS AND C A T A G E N E S I S AS R E L A T E D TO O V E R P R E S S U R E S L.A. Buryakovsky, R.D. Djevanshir, G.V. Chilingar, H.H. Rieke III and J.O. Robertson, Jr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

97 97

Burst's compaction model . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of abnormally high formation pressure . . . . . . . . . . . . . . . . . Clay-mineral transformation . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of thermobaric conditions . . . . . . . . . . . . . . . . . . . . . . . . Effect of hydrochemical factors . . . . . . . . . . . . . . . . . . . . . . . . Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . .

. . . . . . . . .

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.... . . .

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99

100 105

110 113

116 120 121 121

CONTENTS

Xlll

Chapter 5

M E T H O D S OF ESTIMATING AND P R E D I C T I N G A B N O R M A L F O R M A T I O N PRESSURES G.V. Chilingar, V.A. Serebryakov, S.A. Katz and J.O. Robertson Jr. . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prediction of a b n o r m a l l y high pressure in regions with n o n e q u i l i b r i u m c o m p a c t i o n . . . . . . . . . . A b n o r m a l pressure due to temperature variations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimation and prediction of a b n o r m a l l y low pressures in basins in permafrost regions . . . . . . . . Formation pressure in regions with u p t h r o w n and d o w n t h r o w n blocks (uplift and subsidence of sedimentary rocks) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Calculation of a b n o r m a l pore pressure during drilling . . . . . . . . . . . . . . . . . . . . . . . . . . Method of equivalent depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Method of n o r m a l c o m p a c t i o n trend . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Method of c o m p r e s s i o n a l curves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Radioactivity study of zones with a b n o r m a l l y high formation pressure . . . . . . . . . . . . . . . . . Pulsed neutron capture logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantitative pressure evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Technique A: empirical calibration charts . . . . . . . . . . . . . . . . . . . . . . . . . . . . M e t h o d B: equivalent depth m e t h o d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale water influx - - driving m e c h a n i s m . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Various geophysical well logging methods - - a s u m m a r y . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

123 123 126 130 130 131 134 135 136 137 140 141 145 145 146 146 147 148

148

Chapter 6

DRILLING PARAMETERS W.H. Fertl, G.V. Chilingar and J.O. Robertson Jr. . . . . . . . . . . . . . . . . . . . . Drilling rate (penetration) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . N o r m a l i z e d rate of penetration (d-exponent) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of drilling hydraulics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of drill bits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overbalance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling rate equations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Porosity and f o r m a t i o n pressure logs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . L o g g i n g while drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Torque . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drag . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling m u d p a r a m e t e r s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M u d - g a s cutting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flowline specific w e i g h t of drilling fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pressure kicks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flowline t e m p e r a t u r e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Resistivity, chloride ion content, and other methods . . . . . . . . . . . . . . . . . . . . . . . . . Pit level and total pit v o l u m e . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hole fill-up . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M u d flow rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale cuttings parameters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale bulk specific w e i g h t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Volume of shale cuttings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shape and size of shale cuttings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Other pressure indicator methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Drilling concepts in overpressured environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

151 151 151 153 155 156 156 157 159 159 160 160 160 160 161

161 162 163 163 163 163 163 164 164 164 165 165 165

XIV

CONTENTS

Chapter 7

S E I S M I C M E T H O D S OF P R E S S U R E P R E D I C T I O N F. A m i n z a d e h , G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prediction of abnormal pressure f r o m geophysical data . . . . . . . . . . . . . . . . . . . . . . . . . . Empirical relationships . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eaton's exponent of pore pressure determination from sonic data . . . . . . . . . . . . . . . . . . E a t o n ' s exponent for pore pressure determination f r o m resistivity logs . . . . . . . . . . . . . . . Eaton's fracture pressure gradient equation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Dutta's m e t h o d . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fillippone f o r m u l a . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Modified Fillippone f o r m u l a . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Practical applications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Caspian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . AVO effects of overpressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Real time pressure analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lithology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E m p i r i c a l relationships based on laboratory m e a s u r e m e n t s . . . . . . . . . . . . . . . . . . . . . Velocity and acoustic i m p e d a n c e inversion of seismic data . . . . . . . . . . . . . . . . . . . . . Pore pressure and seismic amplitude versus offset (AVO) . . . . . . . . . . . . . . . . . . . . . . Pore pressure estimation from seismic velocities . . . . . . . . . . . . . . . . . . . . . . . . . . . D e e p - w a t e r prospects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . M a p p i n g reservoir fluid m o v e m e n t and d y n a m i c changes of reservoir pressure using time lapse (4-D seismic) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimation of sonic velocity from resistivity logs . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

169 169 169 170 170 171 171 172 172 172 173 173 175 175 176 177 178 179 179 183 186 187 188

Chapter 8

TECTONICS AND OVERPRESSURED FORMATIONS G.V. Chilingar, W. Fertl, H. Rieke and J.O. Robertson Jr . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Faulting as a cause of overpressured formations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shale diapirism (mud lumps, m u d volcanoes) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Prediction of tectonically caused overpressures by using resistivity and density measurements of associated shales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin and distribution of overpressures in carbonate reservoirs . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

191 191

191 198 200 200 205 206

Chapter 9

P R E D I C T I O N O F A B N O R M A L L Y H I G H P R E S S U R E S IN P E T R O L I F E R O U S SALT-BEARING SECTIONS V.I. Zilberman, V.A. Serebryakov, M.V. Gorfunkel, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Indicators of approaching the overpressured zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . Locating the areal positions of A H F P zones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Quantitative A H F P forecast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

209 209 211 213 217 220 220

Chapter 10

P O R E WATER C O M P A C T I O N C H E M I S T R Y AS R E L A T E D T O O V E R P R E S S U R E S H.H. Rieke, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . O v e r v i e w and constraints . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . T h e r m o d y n a m i c and reaction models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Evolution of seawater into pore water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

223 223 224 225 227

(SUIN 1 L N I ~ i

X V

Reliability of water sampling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . P a l m e r and Sulin water classifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . P a l m e r ' s classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sulin's classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . C h e m i c a l composition of subsurface brines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Salinity variations in c o m p a c t i n g sandstones and associated shales . . . . . . . . . . . . . . . . . Field case studies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . H a c k b e r r y and M a n c h e s t e r fields, Louisiana, U . S . A . . . . . . . . . . . . . . . . . . . . . . . Global reconnaissance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bengal and Kutch basins, India . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Songliao Basin, China . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . South Caspian Basin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Laboratory experiments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Early laboratory experiments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of rate of loading (experiments) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Smectite to illite transformation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E x p e r i m e n t s involving mixtures of oil and seawater . . . . . . . . . . . . . . . . . . . . . . . . . Fluid chemistry c o m p a c t i o n models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . N o n - t h e r m o d y n a m i c approaches . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Warner's double-layer model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Kotova and Pavlov's empirical m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Pol'ster's capillary m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . T h e r m o d y n a m i c approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bolt's pressure filtrate m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A p p e l o ' s D o n n a n equilibrium model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S m i t h ' s Gibbs e q u i l i b r i u m m o d e l . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Isotope studies of interstitial fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Geological observations and evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Isotope studies of shales in the G u l f Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . S u m m a r y and conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

229 233 233 234 235 236 238 240 243 245 248 250 251 251 261 264 270 272 273 273 275 276 277 277 279 281 282 282 283 285 288

Chapter 11

ABNORMALLY LOW FORMATION PRESSURES V.A. Serebryakov, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Origin of abnormal pressures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Estimation of the effects of temperature change and erosion on pore pressure . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 12

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

295 295 296 300 308 308

MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES M.R. Islam, L. Khilyuk, G.V. Chilingar, S. Katz, J.O. Robertson Jr., A. Gurevich, E A m i n z a d e h and L. B u r y a k o v s k y . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 311 M e t h o d o l o g y of simulation of d y n a m i c systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312 Analytical approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 312 Analytical models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 314 Simulation of pore-fluid (formation) pressure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 316 N u m e r i c a l models . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 318 Tectonic and lithological m o d e l i n g . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 322 N u m e r i c a l criterion and sensitivity analysis for t i m e - d e p e n d e n t formation pressure in a sealed layer . 327 M o d e l i n g of m e a n value for t i m e - d e p e n d e n t formation pressure . . . . . . . . . . . . . . . . . . 329 F o r m a t i o n pressure in the case of constant fluid flow t h r o u g h the lower b o u n d a r y of the f o r m a t i o n . . 331 Criterion for the type of t i m e - d e p e n d e n t variation of formation pressure . . . . . . . . . . . . . . 333

xvi

CONTENTS

B o x - t y p e fluid flow . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sensitivity analysis for the m e a n value of the formation pressure in the sealed p e r m e a b l e layer Criterion B / A and relaxation coefficient for the Western K u b a n region in the southern part of Russia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . E x a m p l e s of formation pressure d e v e l o p m e n t . . . . . . . . . . . . . . . . . . . . . . . . . . . . Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Identification of conductivity function for p e t r o l e u m reservoirs . . . . . . . . . . . . . . . . . . . . . Basic m a t h e m a t i c a l m o d e l of the pressure distribution in petroleum reservoirs . . . . . . . . . . Indirect evaluation of the conductivity function . . . . . . . . . . . . . . . . . . . . . . . . . . . Determination of the piezoconductivity coefficient layer by layer . . . . . . . . . . . . . . . . . . Model e x a m p l e of determining the conductivity function . . . . . . . . . . . . . . . . . . . . . . Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . F r a m e w o r k of a c o m p r e h e n s i v e model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Overpressurization due to rapid loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shear deformations aided by overpressures . . . . . . . . . . . . . . . . . . . . . . . . . . . Fluid generation at depth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Diagenesis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . N o m e n c l a t u r e used in this chapter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 13

.

333 334 336 337 338 339 340 341 342 343 344 344 344 346 347 348 348 348 349

Introduction . C o m p a c t i o n of Conclusions . Bibliography .

INTERRELATIONSHIP AMONG FLUID PRODUCTION, SUBSIDENCE RESERVOIR PRESSURE V.A. Serebryakov, G.V. Chilingar and J.O. Robertson Jr . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . rocks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

AND

. . . .

353 353 353 358 358

A u t h o r Index

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

361

Subject Index

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

369

. . . .

. . . .

Chapter 1

INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. and V. SEREBRYAKOV

INTRODUCTION There are wide variations in the subsurface formation fluid pressures due to a variety of hydraulic and tectonic phenomena. Variations of interstitial fluid pressure from the hydrostatic pressure of the subsurface fluids are labeled as abnormal formation pressure. The hydrostatic pressure is equal to the vertical height of a column of water extending from the surface to the formation of interest: Ph -- Vw X h

(1-1)

where Ph is the hydrostatic pressure in lb/ft 2, Vw is the specific weight of water in lb/ft 3, and h is the height of the column of water, in ft. The hydrostatic pressure gradient, Gh, in psi/ft, is equal to: Gh =

Vw 144

(1-2)

If the specific weight of water is 62.4 lb/ft 3, the Gh -- 0.433 psi/ft (0.10 kg cm -2 m - l ) . The specific weight of water is a function of the salinity of the water, temperature, and content of dissolved gases. Therefore, there is a general variation in the hydrostatic pressure gradient at different locations and the average estimated hydrostatic pressure gradient is usually taken as 0.465 psi/ft (0.074 kg cm -2 m - l ) ; this corresponds to water with a salinity of 80,000 parts per million (ppm) of sodium chloride at 77~ (25~ (Dickinson, 1953). In the presence of a normal hydrostatic pressure gradient, there is fluid communication (vertical) between the formations. The coexistence of normal and abnormal formation pressures in the same geologic environment can occur if one or more of the formations are impermeable to the vertical hydraulic communication. The average total overburden (lithostatic) pressure gradient resulting from the combined pressure of the rocks (grain-to-grain or rock matrix stress) and their interstitial fluids are taken as 1.0 psi/ft (0.231 kg cm -2 m-l): Pob -- Pe + Pp

(1-3)

where Pob is the total overburden (lithostatic) pressure which increases with depth, Pe is the stress exerted through the grain-to-grain contacts, and pp is the pressure of the fluids present in the pore spaces of the rocks. The hydrostatic, fluid pressure gradient cannot exceed the pressure gradient of the total overburden load. Thus, any reservoir with a hydrostatic gradient between 0.465 and 1.0 psi/ft is considered to have an abnormally high pressure. Actually, as pointed out by Swarbrick and Osborne (1998), when the

2

E.C. DONALDSON, G.V. CHILINGAR, J.O. ROBERTSON JR. AND V. SEREBRYAKOV

porosity of sediments is high (60-70%), the lithostatic pressure gradient is 0.7 psi/ft. Only at a depth of about 1.0 km, this variable is about 1.0 psi/ft. There are many factors that cause abnormal formation pressures, which may be either less than, or greater than, the pressure resulting from the normal hydrostatic pressure gradient of the region.

ABNORMAL PRESSURES

Subpressures In the accumulated experience of the petroleum industry in exploration wells, abnormally low formation pressures (subpressures or ALFPs) have been encountered far less than the surpressures (abnormally high formation pressures). In the United States, ALFPs have been found in Arkansas, some areas of the Appalachian Mountains, the eastern Colorado plateau and the Oklahoma-Texas panhandle areas. Other locations of subnormal formation pressures are in central Alberta in Canada, in the Siberian oilfields of Russia, and the arid regions of the Middle East. Many subnormal formation pressures have been artificially induced by production of hydrocarbons and water from subsurface reservoirs, which reduces the formation pore pressure of isolated reservoirs where a sufficient influx of water does not exist to compensate for the fluids that are withdrawn. In many cases, this reduction of formation pressure leads to surface subsidence, which in some cases has resulted in the destructive damage to surface structures. Examples of subsidence due to fluid withdrawal have taken place in: the Po Delta of Italy; the Bolivar Coast of Lake Maracaibo, Venezuela; Galveston Bay, Texas; Long Beach, California; Japan; Taiwan; and other areas (Chilingarian et al., 1995). The Granite Wash oil-producing formation near Amarillo, Texas, exhibited a formation pressure of almost one half of the expected normal hydrostatic pressure. Levorsen (1967) stated that a possible reason may be the fact that the Granite Wash Formation outcrops in Oklahoma east of the Wichita Mountains at an elevation which is about 1000 ft (305 m) lower than the surface elevation at the producing field in Texas. Subnormal pressures in the semi-arid areas of the Middle East occur because the water table is exceedingly deep (several thousand feet in some cases) and the hydrostatic gradient begins at the water table depth.

Surpressures Formations containing fluids with abnormally high formation pressures (AHFPs) have been encountered in all of the continents of the world where exploratory drilling for hydrocarbons has been conducted. Hunt has noted that AHFPs are present in around 180 basins around the globe. According to Law and Spencer (1998), in the US Gulf Coast region, for example, there are at least seven stratigraphic units, ranging in age from Jurassic to Recent, that are abnormally pressured. These fluid reservoirs are isolated environments or at least the fluid flow out of the reservoirs is restricted, and the total overburden load is partially supported by the

3

INTRODUCTION TO ABNORMALLYPRESSURED FORMATIONS

pore fluids. These AHFPs can only exist if the formation is separated by impermeable barriers that contain the pressure in the reservoir. The origins of these barriers may be physical, chemical, or a combination of both (Louden, 1972). There are a multitude of origins for AHFPs among which are (1) compaction, (2) tectonic compression, (3) faulting, (4) diapirism, (5) unusually high geothermal temperature gradients, (6) phase changes of minerals, (7) hydrocarbon (oil and gas) generation, (8) upward migration of hydrocarbon gases along faults, and (9) osmosis. Formation of a fluid seal (caprock) in the subsurface and development of the zone of abnormally high pore pressure is a highly complex mechanism. All of the mechanisms listed above, in any combination, with the passage of geologic time work together to cause the changes in the physicochemical environment (Fertl, 1976).

ORIGIN OF VERTICAL BARRIERS RESULTING IN ABNORMAL FORMATION PRESSURES

Fig. l-1 shows the approximate average subsurface pressure gradient. The rate of sedimentation and compaction and the density of the rock determine the overburden pressure gradient. As indicated in Fig. 1-1, the hydrostatic pressure gradient is 10.5 kPa/m (0.454 psi/ft), and at the other extreme, the lithostatic gradient is about 22.6 kPa/m (1.0

Hydrostatic gradient 10.5 kPa/m ( 0 . 4 5 4 p s i / f t )

\ A

6

!

o m

x

FLU UJ 9

~9

Lithostatic gradient 22.6 kPa/m (I.0 p s i / f t )

a

3

~,~

v

Geopressured zone "~~0.3 kPa/m (0.9 psi/ft}

\

IJ.

-r"

I-Q. LU "12

-. %

, 16

20

- 0 I 0

I 2

I 4

\

\ "\ \

9

\

%

40 60 80 PRESSURE (mPo) I I I i 6 8 I0 12

I00 I 14

120 I 16

I 18

PRESSURE (PSI x 10 - 3 ) Fig. 1-l. Approximate average subsurface pressure gradient in a geopressured zone.

4


psi/ft). In the geopressured reservoirs of the Gulf Coast region of the United States, at a depths greater than 3000 m, the pressure gradient increases to about 20.3 kPa/m (0.9 psi/ft). Hence, fluids in the geopressured zones can exhibit pressures greater than 68 MPa (about 10,000 psi). The formation with normal pressure gradient and the geopressured zone above can coexist only if they are separated by barriers that are impermeable to the vertical movement of fluids over millions of years of geologic time. The pressure seals (caprocks) above the geopressured zones are impermeable to the flow of fluids.

Undercompaction Undercompaction of the sediments can occur during rapid sedimentation and burial of sediments containing a large quantity of clay minerals (Rubey and Hubbert, 1959; Wilson et al., 1977). The complete expulsion of water does not occur, leaving the sediments as a loosely bound system of swollen clay particles with interlayer water. Where rapid deposition involves large quantities of clays, the sand bodies can be surrounded by clays, and if the loading rate of sediments is high, the permeability will decrease rapidly. Consequently, the pore fluids are prevented from escaping vertically through the overlying argillaceous sediments. Support of the overburden load is then transferred to the interstitial fluids and the formation becomes abnormally pressured because the fluids are subjected to the load of the newly deposited sediments. Thus fluids support a greater portion of the total overburden load (see Eq. 1-3). If the rate of migration of water from the formation undergoing sedimentation is equal to the rate of sedimentation, the excess fluid pressure created by the increasing loading will be dissipated and hydrostatic pressure will be maintained at all depths as the compaction of sediments takes place (Johnson and Bredeson, 1971).

Tectonic compression Lateral compression can occur in orogenic belts resulting in development of abnormally high pore pressures. Cretaceous mudstones of northern Wyoming (USA) have been deformed by lateral compression, which has decreased the formation porosity with consequent fluid expulsion through permeable beds or increase of formation pressure within the sealed zones (Rubey and Hubbert, 1959). Fluid pressure almost equal to the overburden pressure was encountered during the initial drilling of the Ventura Field (California). The presence of these faulted and folded zones suggests that lateral tectonic stresses are responsible for some of the surpressures that were encountered (Watts, 1948). Anderson (1927) reported that abnormally high formation pressures were encountered on the Potwar Plateau of West Pakistan just south of a folding zone in the foothills of the Himalaya Mountains; high fluid pressures were also associated with folding in the Khaur Field of West Pakistan (Keep and Ward, 1934). As a result of the compressive forces, water from shales can be squeezed into the associated reservoir rocks (sandstones or carbonates), giving rise to overpressures (see Chapter 8). A cubic element in the subsurface has nine stress components acting on it: three principal, normal stresses, cri, acting on the planes normal to the major axes and six

INTRODUCTION TO ABNORMALLY PRESSURED FORMATIONS

Z

~z

l I

*

~Y

~z

/

a~z

Fig. 1-2. Stress notation in a cubic argillaceous rock slice. Stress notation of the normal component of stress, a2, on the plane normal to the z-axis, rzx and rzy refer to the shear stress components in the plane normal to the z-axis and acting in the x- and y-directions, respectively, crz + ( O a z ) / ( O z ) d z is the incremental change in vertical stress through the free body. (Modified after Rieke and Chilingarian, 1974, fig. 52, p. 93.)

tangential (shear) stresses, ri, that act on each face of the cube normal to the major axes (Eq. 1-4, and Fig. 1-2). The tensor (S) of the nine stresses may be represented by the following equation:

I 0"x "Cxy "Cxz S ~ Tyx Oy "gyz

(1-4)

L'Czx 72zy O"z If compression is produced by tectonic horizontal compressive stresses, such as folding, the greatest principal stress is horizontal ( ~ ) , and the least principal stress is vertical (~z), which is equal to the overburden load per unit area (Pob). The greatest and least effective stresses m a y be expressed as follows: P e x - - Ox - - p p

(1-5)

Pez -- ~

(1-6)

-- Pp

6


where pp is the pore fluid pressure. If the overburden pressure (~rz) is fixed, and the effective horizontal stress, Pex, increases more rapidly than the pore pressure is dissipated from the formation by leakage, the pore pressure will increase until it reaches a maximum value equal to the overburden pressure (pp = O-z). Then, Pez will be equal to zero, and crx will increase toward the failure stress of the rock. At this condition, the superincumbent material can be moved tangentially with negligible resistance. Approach to this condition depends on the relative rates of the opposing processes: (1) the rate of the lateral deformation stress (crx) and (2) the rate of pressure dissipation by fluid leakage. According to Hubbert and Rubey (1959), the application of orogenic stresses is more effective in promoting the conditions of surpressures than sedimentary loading in tectonically quiescent geosynclines. Thus, if the rate of increase of applied orogenic stresses is more rapid than the pore fluid pressure dissipation (through leakage of the fluid), only the presence of stronger rocks can prevent pp from becoming equal to ~rz.

Faulting Some high-pressure zones in the Louisiana and Texas Gulf Coast region of the United States apparently originate from the pattern of block faulting accompanied by contemporaneous sedimentation and compaction. The process creates lateral seals that, together with a layer of thick shale overlying the surpressure zones, prevent the loss of pore fluids from the sediments during compaction and other diagenetic processes. Resistance to the flow of water through the clay is a function of decreasing porosity and permeability of the clay as compaction progresses. The hydraulic permeability of clay is negligible in the geopressured environments. The clay beds have overlain abnormally pressured formations for millions of years without the release of the pressure by fluid flow across the clay/shale beds. Apparently when the beds of clay are compacted, a stage is reached when the porosity and permeability are so low that the vertical flow of fluids is completely restricted. According to Dickey et al. (1968) the 'growth faults' of the Gulf Coast exhibit the characteristics of slump-type landslides and in many cases may indeed be due to old slides that were later buried by sedimentation. The units are thicker on the downthrown side of the growth faults than they are on the upthrown side, probably because during sedimentation there was continuous movement along the fault planes. During compaction of the sediments while sedimentation was taking place, fluids in the pores of the sediments normally travel vertically upward. As compaction progressed, the vertical permeability of argillaceous sediments decreased rapidly and as burial continued the pore pressure increased due to the mass of the overburden sediments and temperature increase. The abnormally high formation pressures are commonly found at depths beginning at about 10,000 ft (3000 m). Continued sedimentation can cause a shear zone to develop by overloading the undercompacted shale. Expulsion of the water is accompanied by subsidence of blocks of sediments. Thus, the contemporaneous faults of the Gulf Coast Basin (USA) are characterized by the cycle of deposition, expulsion of water, subsidence of blocks of sediments, and temperature increase.


7

Abnormally high formation pressures are also encountered in the Niger Delta in Nigeria, Africa. This delta is characterized by growth faults caused by gravity creating zones of high pressure overlain by thick shale beds. There is no doubt that several other mechanisms were active as supplementary pressure generators during the origin of the high pressures found in zones where growth faults predominate, and also in the maintenance of the high pressures after their generation. Although several mechanisms may have made their contributions, gravitational loading and tectonic compression probably exerted the greatest influence on pore pressures and hydrocarbon/water migration. Therefore, knowledge of the vertical and lateral orogenic stresses in the depositional basins is of major importance for interpreting the abnormal fluid pressure environments and anticipating the location of oil and gas reservoirs associated with the abnormally high pressures. The analysis of fluid-rock stress conditions has many other applications: earthquake prediction, hydraulic fracturing, compaction of rocks during their geological history, and the deformation of rocks in subsiding formations. The same theoretical basis applies for the solution of deformational problems by earthquakes and hydraulic effects that dissipate tectonic stresses through small earthquakes; and deformations caused by oil, gas, and water production. There is the curious generation of earthquakes up to magnitude 5 created near Denver, Colorado, USA, by the injection of waste fluids into the fractured gneiss using a 3700-m deep well. The increase of subsurface pressure disturbed the fluid-rock stress equilibrium and promoted sudden slippage along fracture planes (faults), some with very deep epicenters up to 5500 m deep (Evans, 1966).

Diapirism The Jurassic age Louann Salt underlying deep sediments of Louisiana and Texas in the United States was thinned by diapiric flow during the period of rapid sedimentation that began with the uplift of the Rocky Mountains at the beginning of the Cenozoic era. Salt was squeezed gulf-ward by sand and clay deposits forming domes and ridges, with some diapirs rising through the entire thickness of the overlying deposits. As the depth of burial continued, the increases in temperature induced dehydration of the clays within the buried zone and contributed to the shearing stresses. The salt became ductile and flowed like a viscous plastic under pressure and at elevated temperatures, such as those encountered in deep subsurface formations: 93~ (approximately 200~ at 3700 m (12,000 ft). The low density and strength of salt readily allowed development of domes when the density of overlying sediments exceeded the salt density. Salt was pushed upward penetrating the overlying sedimentary structures and acquiring a sheath of pliable clays, or shales, around parts of the salt diapir. The term sheath refers to the predominantly shale material which is out of place between the salt stock and the younger sedimentary rocks. The sheaths originate from folding of the clay bed and deposits of younger sediments against the dome, or from faulting of the clay bed which is then pressed into its position between the salt dome and the flanking sediments (Fig. 1-3). Structural features generally associated with salt domes, such as the configuration of the sheath, indications of uplift, subsidence at the surface, and development of rim synclines, are a consequence of the physical properties of

8


Basinward

D, ~ :

~ ~ . . . . . ,

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

.:...,...,~:

. .,.:..

......

Sand

~,.... . . . . . . . . . . . .

.......

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

Salt

~~~ABNORMAL~

Fig. 1-3. Schematic section through a piercement salt dome showing modification of abnormal pressure surface. (Modified after Harkins and Baugher, 1969, p. 964. Courtesy of the Society of Petroleum Engineers.)

salt and the overlying sediments (Johnson and Bredeson, 1971). In Fig. 1-3, the steep boundary demarcation of the abnormally pressured lower zone reflects earlier (before development of the salt dome) topography associated with the uplift of the region. Harkins and Baugher (1969) illustrated the abnormal pressures associated with the sheath in Fig. 1-3. A well drilled into Formation C would encounter high pressures in the Formation D rocks. The sheath deposits are out of place, having been dragged into their present position by the dome. Growth of salt domes in the Gulf Coast region of the United States was contemporaneous with the sedimentation (see Fig. 1-4). Deep shale beds also undergo plastic flow when subjected to high overburden pressures, forming diapiric masses with the same characteristics as those of salt beds (low bulk density, high pressure gradients, and low electrical resistivity) (Gilreath, 1968). This condition probably occurs when low-density, low-permeability formations are rapidly loaded by sediments; this occurs in major river deltas such as the Niger, Nile, Mississippi, Amazon, etc. where shales are rapidly loaded by sands (Murray, 1961). Geothermal temperature Another contributor to the fluid pressure is the temperature increase that occurs within the geopressured zone. The overlying, normally pressured, sediments that are compacted possess a lower thermal conductivity and act as a 'blanket', decreasing the transfer of heat from the deep mantle. A leak-proof permeability seal is required in order to have a closed system, and the heat trapped by the blanket effect above the geopressured zone produces an abnormally high temperature in the formation. This contributes another incremental pressure increase to the fluid (Kreitler and Gustavson, 1976). The approximate subsurface temperature gradients are illustrated in Fig. 1-5. The temperature gradient increases from the normal gradient of 18.2~ (1.0~ ft) to about 30~ (1.7~ ft) in the geopressured zone at a depth of about 3000 m.

9

INTRODUCTION TO ABNORMALLYPRESSURED FORMATIONS

Hence, water in the geopressured zone can be expected to have a temperature of 152~ (305~ Several factors affect the heat flux in subsurface formations: (1) the prevailing temperature of the zone; (2) the specific heats of the matrix and fluids; (3) the porosity and permeability of the sedimentary layers; (4) the density and thermal expansion of the rock and fluids; and (5) the chemical composition of the rocks and fluids (Donaldson, 1980). The geopressured zones along the Gulf Coast region (USA) generally occur at depths below 2500 m and require special drilling technology whenever these zones are to be penetrated. These zones usually contain a considerable amount of methane that is frequently separated and recovered when the geopressured formations are penetrated (Harkins and Baugher, 1969). Dickinson (1951) made a thorough study of the geologic aspects of the high fluid pressures in the Tertiary Basin of the U.S. Gulf Coast region. The high-pressured zones occur most frequently in isolated Miocene and Pliocene sand beds surrounded by thick shale sections located below the main deltaic sand series. The high fluid pressures appear to be independent of the depth or geologic age of the formations. Where sedimentation has been rapid, the thick accumulation of shales and mudstones having low permeability (< 10 -7 D) have retarded the expulsion of water and hydrocarbons. The trapped pore fluids bear a portion of the overburden load that would normally be supported by the grain-to-grain contacts. In the geopressured/geothermal zones (at depths greater than 3000 m) with pressure and temperature of about 70 MPa (10,000 psi) and 152~ respectively, the solubility of methane in water is about 0.058 mole fraction (40 ft3/bbl). The actual gas production from several zones, however, exhibits an approximate saturation of 0.029 mole fraction

Plain

Shelf Top of geopressured zone

Sand and shale sequence---

Louann salt Sandstone Granite Fig. 1-4. Top of geopressured zone in the Gulf Coast of the U.S. in relation to salt domes (Louann Salt).

10


(20 ft3/bbl) (Kharaka et al., 1977). Organic matter which is a substantial part of freshly deposited muds decomposes during diagenesis as a result of biochemical and thermochemical processes. The resulting methane gas which is released during the transformations can create, or accentuate, the overpressured, undercompacted, state of the compacting mud sediments in two ways: (a) by building up additional pore pressure; and (b) by further impeding the expulsion of interstitial pore water through the development of a second gas-fluid phase. Gas bubbles dispersed in water reduce the permeability of the rock to either phase (Chilingarian et al., 1995). The mechanism of temperature increase (aquathermal expansion) as a possible cause of overpressures has been questioned by several authors (e.g., see Swarbrick and Osborne, 1998). The main objection is the absence of practically impermeable seals. Phase changes that produce abnormal pressures Berner (1980) described two phases in early diagenesis. The first one consisted of two stages: (1) the initial stage which is regulated by the chemistry of water; and (2) the early burial stage which is controlled by the entrapped pore water that is chemically modified by bacteria and bioturbation of surface organisms. During the initial stage, the clay minerals undergo a gradual change of their ionic exchange capacity, and

Normal thermal gradient 1 8 . 2 ~ (I.O~ ft.) 6

.-. if3 i c)

x IuJ bJ

9

Geothermal

,,=, a

-rl-o. w ol2

zone

/~30.OOC/km (I.7~

ft.)

\ 16

-

50

I

0

,

I

I00

I00 TEMPERATURE

~

I

200

TEMPERATURE

\

\

\

\

150 ~

I

I

300

2_00

I

~

Fig. 1-5. Approximate average subsurface temperature gradients.


11

bioturbation creates a well-oxidized depositional environment. The early burial state is recognized as a reducing zone where anaerobic bacteria are dominant. Rieke (1972) presented a discussion of the transformation of clay minerals from field observation and laboratory experiments. During sedimentation, montmorillonite clay adsorbs water into its three-dimensional lattice structure that is later released into the pores of the surrounding porous media during compaction and burial. The transformation of montmorillonite clay to illite occurs between 80 ~ and 120~ releasing an amount of water equal to one half of its volume (Powers, 1967). This infusion of water leads to further undercompaction in the geopressured zone. When the fluid pressure exceeds the lithostatic pressure, the faults act as valves for discharge of fluids upward into the hydro-pressured aquifers overlying the zone. As the formation pressure declines, the valves close until the pressure once more exceeds the lithostatic pressure (Jones, 1975; Bebout, 1976). Various investigators have shown that during compaction accompanied by deep burial, a diagenetic conversion of montmorillonite to illite, and also kaolinite to chlorite, occurs with increasing depth as the subsurface temperature increases. Progressive modification of the structure of montmorillonite with its eventual disappearance was observed with increasing burial depth in the Wilcox Formation of the Gulf Coast (USA). Burst (1969) proposed that the disappearance of montmorillonite in the sediments was caused by conversion to illite as Mg 2+ cation was substituted in the silicate lattice structure for A13+ ion, accompanied by fixation of the interlayer potassium. Powers (1959) and Weaver (1961) have also reported on the lack of non-interlayered montmorillonite in deeply buried sediments. The gradual change of montmorillonite clay to illite and kaolinite to chlorite has been investigated by many authors: Fuchtbauer and Goldschmidt (1963), Dunoyer de Segonzac (1964), Perry and Hower (1970), Van Moort (1971) and others. The fact remains, however, that smectite-to-illite transformation during diagenesis and catagenesis does not occur in many overpressured environments (see Chapter 4). Osmosis as a factor for generation of abnormal pressure Osmotic pressure occurs when two solutions having different ionic concentrations are separated by a semipermeable membrane that will allow the solvent to pass through by diffusion from the more dilute side to the more concentrated side of the membrane. The osmotic flow will continue until the chemical potential of diffusion is equal on both sides of the membrane; thus, the pressure increase occurs if the solvent moving into the more concentrated solution enters a closed compartment (Fig. 1-6). McKelvey and Milne (1962) measured the osmotic pressure of 1 N sodium chloride solution versus distilled water across plugs (0.26-0.51 cm in thickness) of bentonite. The pressure was 695 psi (4.8 KPa): 95% of the theoretical value. Probably the natural clay/shale beds will act only as imperfect semipermeable membranes because of the presence of fractures and large pores, which may be too large or too weakly charged to restrict the movement of salt. Thus, the generated osmotic pressure will be less than the theoretical one on the basis of salinity differences across them.

1~


Zone of decreasing pore pressure

Zone of increasing pore pressure

H20 - - - - - - - ~ I i i~iiliii!iiiiiEi ili iiiii.iiiiiiiiiiii~lH20 i.._

H20 ~

H20

0 ..-.

e"

9

'*-

N),.,,-

"" 0

-4,.,,.

N~O ~

H~O

~

H20 ~

H20

~

H~O ~

H~O

~

H20

H20

O

(I)

rO

N

.0 o NI,,,,-

O

H20 "'~iiHiiiiiiiiiiii!iiiiiiiiiiiii~iiii

iii iiii iiil H20

(]) tO

N

'' i,,

Fig. 1-6. Schematic diagram of osmotic flow through semipermeable clay membrane (without fractures).

The pressure will be abnormally high in the water influx side of the membrane, and the water will contain a considerably lower concentration of electrolytes. Formations with a large lateral continuity and high permeability would probably dissipate the osmotically induced high pressure, whereas the formations which are surrounded by rocks having low transmissibility would exhibit higher pressure. Young and Low (1965) conducted experiments that illustrated the behavior and effectiveness of argillaceous sediments as semipermeable membranes (Hanshaw and Zen, 1965). Lomba et al. (2000) discussed a model for calculation of transient pressure profiles and solute diffusion through low-permeability shales applied to the calculation of pore pressures near a wellbore. They found that the osmotic potential contributes to the generation of a high hydraulic pressure gradient near the wellbore that controls the flow of water from the formation. Swarbrick and Osborne (1998), on the other hand, calculated that in the North Sea rocks, an osmotic pressure of only about 3 MPa (435 psi) can be generated even with salinity contrasts as high as 35 wt% NaC1 equivalent. They also stated that if shale contains microfactures, osmosis is impossible. Thus, this possible mechanism for creating overpressures should be thoroughly investigated.

Salinity of interstitial water Often on approaching formations with abnormally high pressure, there is a freshening of interstitial water (e.g., see Rieke and Chilingarian, 1974). Yet, the reasons for this


13

decrease in salinity of water are not clear. In analyzing this problem, one should consider the following established facts. (1) Water in shales is much fresher than that in associated sands and sandstones (Schmidt, 1973; Chilingar and Rieke, 1976). (2) Influx of fresher shale water into the associated sandstone reservoirs results in freshening of produced water as production of oil and water progresses (Rieke and Chilingarian, 1976; Chilingarian et al., 1994). (3) Salinity of water in well-compacted shales is lower than that in associated undercompacted shales, but still remains lower than those in associated sands and sandstones (Chilingar and Rieke, 1976). (4) In thick sand-shale sequences, with overpressured formations, the salinity of interstitial water in shales and sandstones often decreases with depth (Rieke and Chilingarian, 1976). (5) Water in the center of shale capillaries is more saline than water adjacent to the capillary walls (Rieke and Chilingarian, 1974). (6) There is good correlation between the salinity of interstitial water in shales and sonic data, which is used for prediction of abnormal formation pressure (Vorabutr et al., 1986). On considering the above-established facts, one may consider the following suggestions: (1) In thick shale sequences, as compaction water moves up, it becomes more saline. Thus, in undercompacted sediments, the salinity of formation waters may decrease with increasing depth. Also, the more-compacted shales below will contain fresher water than less-compacted shales above. (2) In interbedded sands and shales, the variation of salinity with depth is not clear (see Kucheruk and Shenderey, 1975) and considerable field and laboratory research work is required to elucidate the problem.

RESERVOIR E N G I N E E R I N G CONCEPTS IN A B N O R M A L P R E S S U R E E N V I R O N M E N T S

Much attention has been focused on the analysis of hydrocarbon reserves, reservoir behavior, and possible mechanisms important to the production from abnormally high-pressured reservoir rocks. Frequently, overpressured gas reservoirs do not behave as volumetric reservoirs which complicate gas-in-place estimates. For years it has been observed that the production curves in many gas reservoirs show a rapid decline in the early-life history after which they flatten out (Fig. 1-7). The reader is also referred to the classical book of Poston and Berg (1997) on overpressured gas reservoirs. The following characterize overpressured reservoirs: (1) water influx from the shales into adjacent pay sands (i.e., shale water influx) (Wallace, 1969); (2) rock compressibility and rock failure (Harville and Hawkins, 1969); (3) water influx into the reservoirs from limited aquifers.

14


True gas-in-place

estimate

.o a

=IN==

Erroneous

gas-in-place estimate i i g i

",,,,i

i

2

i i i

9

Cum. gas producti( )n

li~

Overestimate

Fig. 1-7. Typical p/z versus cumulative production behavior for an overpressured gas reservoir in sand-shale sequence. (Modified after Fertl and Chilingarian, 1977, fig. 4, p. 35.)

.E Q. (1) "4--

N \\

\i~.~

~

1

x'" 2 "~3

Time risk, cost Fig. 1-8. Generalized trends of key drilling factors in hydrostatic and overpressured environments: 1 = hydrostatic pressures" 2 = overpressures; and 3 = severe overpressures. (Modified after Fertl and Chilingarian, 1987, fig. 13, p. 37.)

E C O N O M I C S IN O V E R P R E S S U R E E N V I R O N M E N T S

Exploration in normal-pressure environments generally shows predictable trends for time, cost, and risk. Presence of abnormal pressures, especially superpressures, however, is a very critical factor. Time, cost and risks can increase drastically, greatly affecting the profit. This is clearly shown in Fig. 1-8. Based upon the shale resistivity ratio method (Fig. 1-9) and regardless of measured formation pressure gradients, the following conclusions were drawn by Timko and Fertl (1971) and Fertl and Chilingarian (1976) for the shale-sand sequences (but not massive carbonate sections).

INTRODUCTION

TO ABNORMALLY

PRESSURED

FORMATIONS

15

D O

~

._~ 2 o C

,I,,,9

r-

U'O

OVERPRESSURE

.

d-

~~.

/ ~

r',,,"

13 No. MW

,,p.z\

COMMERCIAL OIL/GAS FIELDS

\

t

NO

-

A

. 6\- -

",-,99~

SMALL RESERVOIRS

~r

=

MAJORITY GULF COAST FIELDS

.~ \

/

oo~e~o,~ ~

3.s NORMAL

B m ~ oS

\

i

-'~ \ Rsh

RESERVOIRS

TOP SUPER

\

F~

_ 3 O ~ m -(3 ,,,.. ~ > -4

PRESSURE

\

~

~

r-

, ,,,., ,,.

iiiiiiiii

Shoff normal resistivity, log Rsh Fig. 1-9. Statistical relationship of hydrocarbon distribution to shale resistivity profile based on short normal curve in Tertiary clastic sequence, U.S. Gulf Coast area. (Modified after Timko and Fertl, 1971. Courtesy of the Society of Petroleum Engineers. In Fertl and Chilingarian, 1987, fig. 11, p. 36.)

(1) Most commercial oil sands exhibit shale resistivity ratios (ratio of normal Rsh to observed Rsh) less than 1.6 in adjacent shales and can generally be reached without an expensive string of protection pipe. (2) Most commercial gas-sand reservoirs exhibit ratios of about 3.0 and less. These wells can have extremely high measured pressure gradients. (3) Wells with ratios of 3.0 to 3.5 can be commercially gas productive and generally will produce as one- or two-well reservoirs. (4) No commercial production is found when the shale resistivity ratio reaches and/or exceeds 3.5, no mater what the actual pressure gradient is. These wells are often highly productive initially and are characterized by extremely fast pressure depletion. Of course, this can also be due to plastic deformation (irreversible compaction) in undercompacted rocks with increasing effective stress soon after production commences. According to Belonin and Slavin (1998), most of the overpressured production in Russia occurs at an abnormality coefficient, Ka, of less than 1.8 (Ka is measured pore pressure, Ppa :hydrostatic pressure, Ph; 0.45 psi/ft (10.2 kPa/m) was assumed for the hydrostatic gradient). Leach (1993) stated that pressure gradients equal to or in excess

16


of 0.85 psi/ft (19.6 kPa/m) exceed the FPGs of most sandstone reservoirs. Thus, if hydrocarbons are present initially, they probably would have escaped through fractures. (For a detailed discussion see Law and Spencer, 1998.) The writers, however, would like to point out that well testing is a sword of two edges in overpressured formations. As soon as some fluids are produced, the effective pressure increases to a critical limit and closes down the pores (irreversible compaction). Thus many overpressured reservoirs have been condemned in the belief that the reservoir cannot produce fluids (see Belonin et al., 2002).

SUMMARY

Abnormal subsurface formation pressures are encountered throughout the world and are produced by many different causes that may be physical, chemical, or a combination of the two. Many reasons for the formation of subsurface abnormal fluid pressures have been postulated and discovered. There is some disagreement among engineers and geologists regarding some of the mechanisms that have been proposed for the origin of abnormal pressures; however, developments in drilling, seismic technology and well-logging are resolving many of the disputes. This book presents analyses of the theories for the creation and maintenance of abnormal fluid pressures in sedimentary rock environments and their prediction. Clark (1961) coined the term 'tectonic overpressure' during his discussion of tectonic compression. Dickey et al. (1968) developed theories based on faulting. Rieke and Chilingarian (1974), Magara (1975) and Plumley (1980) discussed compaction as a 'disequilibrium mechanism' causing abnormal fluid pressures. According to Gilreath (1968) and Johnson and Bredeson (1971), diapirism of salt and shale was responsible for the creation of some abnormal pressure environments. The influence of abnormal formation temperature on the maintenance of abnormally high fluid pressures (especially along the Gulf Coast of the United States) was discussed by several authors: Harkins and Baugher (1969), Kharaka et al. (1977), Donaldson (1980), and others. Phase changes of minerals during diagenesis and catagenesis was investigated by Powers (1967) and Hanshaw and Bredehoeft (1968). Osmotic pressures were investigated by McKelvey and Milne (1962), Hanshaw and Zen (1965), Swarbrick and Osborne (1998), and others. The two mechanisms of formation of overpressures which have been underestimated in the past are (1) hydrocarbon (both liquid and gas) generation (e.g., Hunt et al., 1998), and (2) upward gas migration along faults from lower to upper horizons, resulting in the overpressures in the upper horizons (Khilyuk et al., 2000). (See Chapter 2.) The chapters that follow are devoted to more detailed analyses of the origins of abnormal subsurface pressures, their prediction and distribution, the effects of diagenetic and catagenetic changes, and mathematical models.

INTRODUCTIONTO ABNORMALLYPRESSURED FORMATIONS

]7

BIBLIOGRAPHY Anderson, R.V.V., 1927. Tertiary stratigraphy and orogeny of the northern Punjab. Geol. Soc. Am. Bull., 38: 665-720. Bebout, D.G., 1976. Subsurface techniques for locating and evaluating geopressured-geothermal reservoirs along the Texas Gulf Coast. Proc. 2nd Geopressured/Geothermal Energy Conf., II, pp. 1-16. Belonin, M.D. and Slavin, W.I., 1998. Abnormally-high formation pressures in petroleum regions of Russia and other countries of the Commonwealth of Independent States (CIS). Am. Assoc. Pet. Geol. Mem., 70: 115-121. Belonin, M.D., Slavin, V.I., Smirnova, E.M., Chilingar, G.V. and Robertson, J.O. Jr., 2002. Exploration in oil and gas fields with abnormally-high formation pressures (AHFP). Energy Sources. (in press). Berner, R.A., 1980. Early Diagenesis: A Theoretical Approach. Princeton University Press, Princeton, NJ, 241 pp. Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. Am. Assoc. Pet. Geol., 53(1): 73-93. Chilingar, G.V. and Rieke, H.H. III, 1976. Chemistry of interstitial solutions in undercompacted (overpressured) versus well-compacted shales. Proc. Int. Clay Conf. 1975, Mexico City. Applied Publishers Ltd., Wilmette, IL, pp. 673-678. Chilingarian, G.V., Rieke, H.H. and Kazi, A., 1994. Chemistry of pore water. In: W.E. Fertl, R.E. Chapman and R.F. Holtz (Eds.), Studies in Abnormal Pressures. Developments in Petroleum Science 38, Elsevier, Amsterdam, pp. 107-153. Chilingarian, G.V., Donaldson, E.C. and Yen, T.E, 1995. Subsidence Due to Fluid Withdrawal. Developments in Petroleum Science 41, Elsevier, Amsterdam, 498 pp. Chilingar, G.V., Eremenko, N.A. and Ar'ye, A.G., 1997. Anomalously high pressures in natural geofluiddynamic systems. Geol. Oil Gas, 5: 19-27. Clark Jr., S.E, 1961. A redetermination of equilibrium relations between kyanite and sellimanite. Am. J. Sci., 259:641-650. Dickey, EA., Shiram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160:609-615. Dickinson, G., 1951. Geological aspects of abnormal reservoir pressures in Gulf Coast region of Louisiana, U.S.A. Proc. 3rd World Petrol. Congr., 1: 1-17. Dickinson, G., 1953. Reservoir pressures in Gulf Coast, Louisiana. Bull. Am. Assoc. Pet. Geol., 37: 410-432. Donaldson, E.C., 1980. Underground disposal of brines from geopressured reservoirs. Proc. 73rd Annu. Meet., Am. Inst. Chem. Eng., 30 pp. Dunoyer de Segonzac, G., 1964. Les argiles du Cr6tac6 Sup6rieur dans le bassin de Douala (Cameroun): Problbmes de diagenbse. Bull. Serv. Carte Geol. Alsace-Lorraine, 17(4): 287-310. Evans, D.M., 1966. The Denver area earthquakes and the Rocky Mountain Arsenal disposal well. Mt. Geol., 3(1): 23-36. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 382 pp. Fertl, W.H. and Chilingarian, G.V., 1976. Importance of abnormal formation pressure to the oil industry. SPE 5946, Soc. Pet. Eng. AIME, Amsterdam, April 7-9. Fertl, W.H. and Chilingarian, G.V., 1977. Importance of abnormal formation pressures to the oil industry. Paper SPE 5946 presented at the Spring Meeting of the European Societ of Petroleum Engineers of AIME, Amsterdam; also J. Pet. Technol., 29(4): 347-354. Fertl, W.H. and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1(1): 23-38. Fuchtbauer, H. and Goldschmidt, H., 1963. Beobachtungen zur Tonmineral Diagenese. Proc. 1st Int. Congr. Clays, Stockholm, pp. 99-111. Gilreath, J.A., 1968. Electric-log characteristics of diapiric shale. Am. Assoc. Pet. Geol. Mem., 8: 137-144. Glasstone, S., 1946. Textbook of Physical Chemistry. Van Nostrand, New York, 1320 pp. Hanshaw, B.B. and Bredehoeft, J.D., 1968. On the maintenance of anomalous fluid pressures, II. Source layer at depth. Geol. Soc. Am. Bull., 79:1107-1122. Hanshaw, B.B. and Zen, E., 1965. Osmotic equilibrium and overthrust faulting. Geol. Soc. Am. Bull., 76: 1379-1386.

18

E.C. DONALDSON,G.V. CHILINGAR,J.O. ROBERTSONJR. AND V. SEREBRYAKOV

Harkins, K.L. and Baugher III, J.W., 1969. Geological significance of abnormal formation pressures. J. Pet. Technol., 21 (8): 961-966. Harville, D.W. and Hawkins, M.E, 1969. Rock compressibility and failure as reservoir mechanism in geopressured gas reservoirs. J. Pet. Technol., 21: 1528-1530. Hubbert, M.K. and Rubey, W.W., 1959. Role of fluid pressure in mechanics of overthrust faulting. I. Mechanics of fluid-filled porous solids and its applications to overthrust faulting. Geol. Soc. Am. Bull., 70(2): 167-206. Hunt, J.M., 1990. Generation and migration of petroleum from abnormally pressured compartments. Am. Assoc. Pet. Geol. Bull., 74: 1-12. Hunt, J.M., Whelan, J.K., Eglinton, L.B. and Cathless III, L.M., 1994. Gas generation - - a major cause of deep Gulf Coast overpressures. Oil Gas J., Jul. 18, pp. 59-63. Hunt, J.M., Whelan, J.K., Eglinton, L.B. and Cathless III, L.M., 1998. Relation of shale porosities, gas generation, and compaction to deep overpressures in the U.S. Gulf Coast. Am. Assoc. Pet. Geol. Mem., 70: 84-104. Johnson, H.A. and Bredeson, D.H., 1971. Structural development of some shallow salt domes in Louisiana Miocene productive belt. Am. Assoc. Pet. Geol. Bull., 55(2): 204-226. Jones, EH., 1975. Geothermal and hydrocarbon regimes, Northern Gulf of Mexico Basin. Proc. 1st Geopressured/Geothermal Energy Conf., V (Part 3), pp. 15-39. Keep, C.E. and Ward, H.L., 1934. Drilling against high rock pressures with particular reference to operation conducted in the Khaur field, Punjab. J. Inst. Pet. Technol., 20: 990-1013. Kharaka, Y.K., Callender, E. and Carothers, W.W., 1977. Geochemistry of waters in the geopressured zone from coastal Louisiana: implications for the geothermal development. 3rd Geopressured/Geothermal Energy Conf., Univ. Southwestern Louisiana, Lafayette, LA, Nov. 16-18, 1: GI- 121-165. Khilyuk, L.E, Chilingar, G.V., Endres, B. and Robertson, J.O. Jr., 2000. Gas Migration - - Events Preceding Earthquakes. Gulf Publ. Co., Houston, TX, 389 pp. Kreitler, C.W. and Gustavson, T.C., 1976. Geothermal resources of the Texas Gulf Coast: environmental concerns arising from the production and disposal of geothermal waters. Proc. 2nd Geopressured/Geothermal Energy Conf., V (Part 3), 1- 14. Kucheruk, E.V. and Shenderey, L.P., 1975. Present-Day Understanding of Nature of Anomalously-High Formation Pressures. V. 6, VINITI, Moscow, 165 pp. Law, B.E. and Spencer, C.W., 1998. Abnormal pressures in hydrocarbon environments. Am. Assoc. Pet. Geol. Mem., 70:1-11. Leach, W.G., 1993. Fluid migration, hydrocarbon concentration in South Louisiana Tertiary sediments. Oil Gas J., Mar. 1, pp. 71-74. Levorsen, A.T., 1967. Geology of Petroleum. Freeman, San Francisco, CA, 724 pp. Lomba, R.ET., Chenevert, M.E. and Sharma, M.M., 2000. The role of osmotic effects in fluid flow through shales. J. Pet. Sci. Eng., 25(I-2): 25-35. Louden, L.R., 1972. Origin and maintenance of abnormal pressures. SPE 3843, 3rd Symp. Abnormal Subsurface Pore Pressure. Magara, K., 1974. Compaction, ion filtration, and osmosis in shale and their significance in primary migration. Bull. Am. Assoc. Pet. Geol., 58: 283-290. McKelvey, J.G. and Milne, I.H., 1962. Flow of salt solutions through compacted clay. Clays Clay Miner., 9: 248-259. Murray, G.E., 1961. Geology :

o~

0,005 0.004

~

i=~ 0.003 0

!: 0

0.002 0.001 0.000

0

1000

2000

3000

4000

5000

6000

Pressure, p, psia Fig. 2-3. Difference between the formation volume factor of gas-saturated pure water and that of pure water at various temperatures. Correction for the formation volume factor (EV.F.) is F.g-F.gas saturatedpurewater F.V.F.purewater. (Modified after Frick, 1962, fig. 22.16, p. 22.21.) F.V.F. = volume occupied at reservoir

conditions divided by the volume occupied at standard conditions at the surface (60~ and 1 atm pressure).

If the buoyant force Fb is equal to the weight of fluid displaced by the grains Fb -- Wb

--

~fgb(l

--

~b)

(2-6)

and inasmuch as

Vb--A.D

(2-7)

where A is the total cross-sectional surface area and D is the depth, and the pore pressure, pp: pp -- yfD

(2-8)

Fb -- p p . A (1 - ~b)

(2-9)

then:

Eq. 2-9, derived by Rieke and Chilingarian (1974), is in close agreement with the view of Terzaghi (1926) that the uplift force, due to pore pressure, is proportional to the surface porosity (also see Laubscher, 1960). Surface or boundary porosity is the ratio of the pore area to the gross area, along the surface, A. It can also be shown that surface porosity on a plane surface is the same as volumetric porosity. Hubbert and Rubey

28

G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III

,,4,,,-,

4000

' \~e

(1) 11)

.ff O. (1) 1=1

"~ x,~4 o

\ \ '~ "~_ ~ ~ "

8000

9

California - Ventura Field pressuresnear crest

~....\ b . . \ Q

.

~

\ \

~

_,ro~\

w

~ ~

~ Ventura Field ,0 ~ D-7 Zone

,,

"~,

12,000

\

\

Wyoming Church Buttes

Texas -- Louisiana Gulf~oast Fields

'\

\

\

\ 0

4000

8000

Pressure, psi

12000

16000

Fig. 2-4. Relationship between the formation fluid pressure and depth in several abnormally pressured pools. Specific weight of water = 62.4 lb/ft 3 (+144 in2/ft 2 = 0.433 psi/ft). (Redrawn from Watts, 1948, fig. 2, p. 194; in Rieke and Chilingarian, 1974, fig. 10, p. 26.)

(1959; also see Hubbert and Rubey, 1960), however, showed that the pore pressure, pp, is common to both the water and the clay and acts over the whole of any surface passed through the porous solid, with the surface porosity being in no way involved (see experimental results of Rieke and Chilingarian, 1974, p. 6). On assuming that all pores are filled with water, at a depth, D, the total overburden pressure, pt, resulting from the weight of overlying water and solids can be expressed by the following equation: Pt-

[y~(1 -4>) + y'wr

(2-10)

where Vs is specific weight of the sediment grains (lb/ft3), 05 is fractional porosity, and Vw is specific weight of water (lb/ft3). Inasmuch as the effective pressure (grain-to-grain stress), Pe, is equal to the difference between the total overburden pressure and the pore pressure [Pe - Pt - Pp], and pore pressure at a depth D is equal to VwD, then: Pe -- [ys(1 --q~) + Ywq~- yw]D

(2-11)

Pe -- D[(1 - ~ b ) ( y s - Yw)]

(2-12)

or:

Brandt (1955) introduced an 85% correction factor (n) into the pp term to take into account the "fact that the internal fluid pressure does not wholly react against

ORIGIN OF ABNORMAL FORMATION PRESSURES

29

the e x t e r n a l p r e s s u r e " . According to him, this factor, n, is structure dependent and, therefore, is not the same for all sediments: Pe = Pt - npp

(2-13)

Rieke and Chilingarian (1974, p. 6), however, showed that n is equal to one. Accumulation of additional sediments upon the older sediments will cause a gradual change in the vertical stress throughout the sediment column. The matrix pressure is redistributed by the grains squeezing closer together so that they bear more load. Many authors (Hubbert and Rubey, 1959; Hottman and Johnson, 1965; Powers, 1967; and others) have stated that for thick shale sequences having low permeability, compaction is a slow process and the fluid must support the additional load. This creates abnormally high pore-fluid pressures, which must be balanced by a corresponding decrease in the shale matrix pressure, because the total weight of overlying rock and water to be supported is practically the same.

STATE OF STRESS IN C O M P A C T I N G S H A L E S

The lithostatic pressure (overburden weight) is probably equal to the vertical normal component of the stress. There is the possibility, however, that the normal stress at a point in a shale body undergoing compaction at some depth is equal to the overburden weight per unit area plus contributions from the vertical shear components of stress (r). A total stress field in such a sedimentary body can be specified in terms of its normal and tangential stress components across a given plane surface (Fig. 1-2) (see Rogers, 1964, p. 25): f x - - {Crx-Cxy-Cxz}AyAz

Fy = {72yxGy'gyz} A x A z

(2-14)

F z = {rzxrzyCrz}AxAy

where Fx, Fy, and Fz are the forces in the x-, y-, and z-directions. It should be noted that the pressure (load per unit area) has the dimensions of stress (e.g., psf or psi). The surface forces are measured in units of force per unit area, whereas the body forces are measured in units of force per unit volume. Examples of these would be specific weight and pressure. In the case of a normal stress as expressed in Eq. 2-14, the subscript refers to the direction (axis) normal to the plane on which the stress acts. In the case of shear stresses, the first subscript denotes the axis perpendicular to the plane in which the stress acts, whereas the second subscript denotes the direction in which the stress acts. It is important to note that one must be consistent in considering either (1) all forces acting on the system or (2) all forces acting outward from the system. If Ft is the normal component of the total force exerted on the element, and Ftt is the tangential component of the force, then for any change in Ft or Ftt, owing to additional overburden weight, there will be a corresponding change in the shear and tangential

30


stresses" Acr--

AFt A

At--

(2-15)

AFtt

A

Resolution o f the total stress field

The stress tensor for a porous, homogeneous, isotropic shale body can be written in the conventional way:

S ~

crx

"gxy

rxz

ry x

Cry

12yz

72zx

Tzy

Oz.

(2-16)

where S signifies the symmetrical tensor of the total stress; cri and rij represent the normal and shear forces, respectively, acting on the faces of a unit of an argillaceous sediment. Next, one can take moments about point O (Fig. 1-2). The tangential stress, r~y, multiplied by the area in which it acts, gives the force rxydzdy, and this times dx, gives a clockwise moment about O. The stress, ryx, times the area gives r,.xdxdz, and the latter times dy results in a counterclockwise moment r y x d x d z d y . At equilibrium, the two moments balance each other: rxydzdydx - ryxdxdzdy

(2-17)

rxy -- ryx

(2-18)

or

Then it follows that rx: - r:x

(2-19)

ryz - rzy

(2-20)

and

The total stress array for a point in a cylindrical body under compaction can be expressed in cylindrical coordinates r, 0, and z"

S ~

crr

TrO

Trz

"fOr

crO

gOz

Tzr

"gzO

crz

(2-21)

The total stress tensor can be decomposed into two distinct parts for a body of sediment in equilibrium: (1) hydrostatic stress; and (2) deviatoric stress.

31

ORIGIN OF ABNORMALFORMATIONPRESSURES H y d r o s t a t i c stress s t a t e

The component attributable to the interstitial fluid is the hydrostatic stress (pressure), O-w, which can be regarded as being continuous throughout the medium. The normal and shear stress components are given by:

P --

O-wx

72wxy "Cwxz

"Cwyx

O-wy

rwyz

rwzx

"gwzy

Crwz

(2-22)

where P is the hydrostatic tensor. It can be assumed that under hydrostatic conditions no shearing stresses exist in the interstitial fluid. By definition, a fluid is a substance that cannot sustain tangential or shear forces when in static equilibrium. This may not hold true for adsorbed water because of its probable quasi-crystalline nature. Hubbert and Rubey (1959, p. 138) noted that if a viscous fluid occupies the pore space, there are then microscopic shear stresses, which are expended locally against the fluid-solid boundaries. Thus, their only macroscopic effect is to transmit to the solid skeleton by viscous coupling whatever net impelling force may be applied to the interstitial fluid. In any stress system with the principal stresses, O-~,O-y, and crz, one can determine the local mean value for the hydrostatic stress, 6w, as: 1

(2-23)

6w -- 5(o-wx .qt_O-wy + O-wz)

Now, the hydrostatic stress tensor, P, can be represented by

P ----

-iw

0 6w

0 0

0

~w

(2-24)

and P - - 5 1 (36w) -- 6w

(2-25)

The above expression represents the hydrostatic pressure of a fluid whether it is flowing or is stationary in the porous system of the shale. Note that O-wx -- O-wy = O-wz - 6w, and that the hydrostatic portion of the total stress system causes only volume changes in the deformed material. D e v i a t o r i c stress state

The second component is known as the stress deviator from the hydrostatic state. It is expressed as the difference between total stress and the hydrostatic stress, which resists deformation:

D --

(O-x -- O-wx )

75xy

"Cxz

ryx

(o-y -- O-wy)

ryz

rzx

rzy

(O-z -- O-wz)

(2-26)

32

G.V. CHILINGAR,J.O. ROBERTSONJR. AND H.H. RIEKEIII

where D is the deviatoric portion of the total stress tensor. The effect of the deviator stress is to produce a distortion, which is elastic or plastic in nature and is introduced into the shale body. Total stress tensor

If the sediment body is not in equilibrium, the second component will not be a symmetric tensor for "gxy ~ "gyx. Ramsay (1967, p. 282) subdivided the asymmetric tensor into symmetric and skew-symmetric parts. The hydrostatic stress component is the same as in Eq. 2-23. The second symmetrical part is the deviatoric stress component which can be expressed as follows:

D --

(O'x --O'w)

"~l ( 72x y -+- "Cy x )

1 ~('gxy + "gyx) 1 ~ ( "gx z + "gz x )

(Oy - ~w) 1 "~ ( 72y z + 7Jay)

-~l(r~z + rz~) 1 ~("gyz 'Jl- "gzy)

(2-27)

( O'z - - O ' w )

The skew-symmetric part is termed the disequilibrium component, which causes the shale to undergo a rotation in space and is expressed as:

l ~('rxy + ryx)

0

R =

l(r~ + r~)

1

(2-28)

! (r~,:. + r:..~,)

1 ~(r:.~ + r~:.)

1 ~(r:.y + ry:.)

0

where R is the disequilibrium component. Such a stress state would be anticipated if tectonic forces were acting on the shale mass in a basin within a geosyncline. The total stress tensor for a shale body not in equilibrium is expressed as the sum of the above-described parts: S= P+D+R

(2-29)

Namely, the total stress = hydrostatic stress + deviatoric stress + disequilibrium component. Each one of the three components making up the state of stress is directly related to the respective component of the strain tensor. The hydrostatic portion of the stress system causes changes in volume, the deviatoric stress components cause distortion, and the disequilibrium components cause the material to undergo rotation in space (Ramsay, 1967). Lo (1969) demonstrated that the pore pressure induced by shear may be expressed as a sole function of the major principal strain. According to him, the only unambiguous and correct principle of superposition of pore pressure is to consider an isotropic stress system and a deviatoric stress system, namely, m

ACrl

0

0

0

Act 2

0

0

0

AO-3

--

Act3

0

0

0

Act 3

0

0

0

AO"3

(ACrl -- Act3) +

0 0

0

0

( A o 2 -- / k o 3) 0 0

0

(2-30)

33


where crl is the total major stress, ~r2 is the total intermediate stress and or3 is the total m i n o r stress. According to Lo (1969), the physical justification for Eq. 2-30 lies in the fact that under ambient stress, the induced pore pressure corresponds almost exactly to the applied pressure, because the compressibility of the pore water and argillaceous sediment grains are m u c h lower than that of the sediment structure. M o s t of the pore-pressure equations presented in literature give almost identical results providing they are properly used. For further detailed discussion see Rieke and Chilingarian (1974).

Spring models of compaction The concept of the s h a l e - c o m p a c t i o n process can be best explained by a m e c h a n i c a l m o d e l which is c o m p o s e d of a perforated, round metal plate and the enclosing cylinder which contains a metal spring and water (Fig. 2-5). In this analogy, the spring represents the compressible clay particles, the water represents the fluid in the pore space, and the size of the perforations in the metal plate determines the permeability. Using this model, well-saturated clay can be treated mathematically, as a two-phase continuum. The hydrated clay is envisioned as clean clay plates in m e c h a n i c a l contact

A

Overburden P r e s s u r e

0 psig =

B

Overburden Pressure

25 psig 9

C

D

Overburden Pressure

25 psig

Overburden Pressure

25 psig

Perforated plate / /

Manometer

/ t.t or'= 0 p s i g ~w = 0 psig )~ = i n f i n i t y

~'= 0psig crw = 25 psig

or'= 3 p s i g ~ = 22 psig

~'= 25psig crw = 0 psig

~L

)~

X

=

I

-

0.875

=

0

Fig. 2-5. Compaction analogy using a spring and perforated plate, o-t is the effective (intergranular) stress, ~w is the pore-water stress and X is the ratio of the pore-water stress to the overburden stress on the system (c~t and Crw are in psig). (Case A) Initial conditions; tightly fitted, frictionless metal plate seals the water in the cylinder. There is no overburden load on the system and perforations of plate are sealed. (Case B) A 25-psig load is imposed on the model. This load is entirely carried by the water. Perforations in the plate are sealed. (Case C) The fluid is allowed to flow out through the perforations. The plate descends as the fluid escapes. The spring carries a portion of the load. (Case D) The spring now carries the entire 25 psig load. The system is in equilibrium and there is no water outflow. (Modified after Taylor, 1948; in Rieke and Chilingarian, 1974, fig. 49, p. 90.)

34


with each other and the fluid wetting the clay-particle surfaces and filling the pore space between the particles. If the mechanical model were sealed in such a manner that no fluid could escape through the plate, then the total applied pressure to the system would be carried by the fluid and none by the spring (Fig. 2-5B). The compressibility of the spring is assumed to be so great that the strains produced in the fluid and in the cylinder walls are negligible in comparison (Taylor, 1948, p. 223). Fig. 2-5C shows that if the fluid is allowed to escape through the perforations, then the overburden pressure is carried both by the spring and the fluid. As the fluid escapes, the plate sinks lower and lower, compressing the metal spring. The length of time required for the spring to pass from one state of compaction to the next depends on how rapidly the water escapes; this is determined by the size of the perforations in the plate. Equilibrium is reached at a point where none of the overburden stress is borne by the fluid (Fig. 2-5D); however, any additional applied loads cause the plate to compact the spring still further, expelling additional fluid. In this manner the clay layers are thought to be compacted under the weight of the overlying sediments. In the spring analogy of the compaction, the following relationship (static equilibrium) must exist at any particular time: Ft = Fs + Fw

(2-31)

where Ft is the total overburden force applied to the system, Fs is the force carried by the spring, and Fw is the force applied to the fluid. If these forces are divided by the total cross-sectional area, A, of the enclosing cylinder, then: Pt or o- =

Ft/A

(2-32)

lS~/A

(2-33)

pp or aw = Fw/A

(2-34)

Pe or o r ' =

where pt or cr is the total stress applied to the system, Pe or a ' is the effective stress, and pp or crw is the pore-water pressure. Thus, Eq. 2-31 can be rewritten as: cr = o-' + aw

(2-35)

As expressed in Eq. 2-35, the total stress, or, normal to any plane in the skeletal structure consists of two components: (1) the pore fluid pressure, Crw; and (2) the effective stress component, or', which is 'effectively' carried by the skeletal structure. The spring analogy fails to agree with the actual compaction of clay in that the pressure conditions are not the same throughout the thickness of the clay mass as they are in the cylinder. In compacting saturated clay at a given pressure, the water pressure at its surface is atmospheric (0 psig), whereas at short distances inside the clay sample the water pressure is equal to o- - or'. Fig. 2-6 illustrates a void space surrounded by a shale matrix. In this figure, the total weight of the overburden, which acts downward, and the vertical and horizontal portions of the effective stress are shown. The high fluid-pressure gradient at the clay's surface is caused by the rapid expulsion of the fluid from the pores near the surface. Under a constant overburden pressure, the water pressure decreases with time, whereas the intergranular pressure increases.

35


!

O" v

i

O" H + O'w

t

]~

.= O"w

~W

0"

CYx

(5" z

Fig. 2-6. Stress state in a shale. Schematic of the stress state in a shale body underground, where crv' is the effective (intergranular) stress in the vertical direction, cr~ is the horizontal effective stress, Ow is the pore water stress and crz is the total vertical stress component. The total horizontal stress component in the x-direction Crx is equal to cr~ + ~r~. (Modified after Rieke and Chilingarian, 1974, fig. 50, p. 92.)

A useful expression in studying compaction is the ratio of the fluid stress to the total stress, )~ (see Hottman and Johnson, 1965): )~ --

Ow cr

=

pp Pt

(2-36)

W h e n stress is initially applied to the closed system, )~ has a value of 1 and the system is overpressured. At final compaction equilibrium, when the load is carried entirely by the skeletal structure (grains; spring), )~ is equal to 0. An example of the use of )~ is demonstrated in Figs. 2-5 and 2-7. At the final stages of compaction equilibrium, the applied load is supported jointly by the skeletal structure and intergranular water (hydrostatic) and the value of )~ is approximately equal to the normal pressure gradient, i.e., 0.465. This value is typical of the normal pressure gradient on the U.S. Gulf Coast (~0.465 psi/ft). The lithostatic (geostatic or overburden) pressure gradient is considered to be about 1.0 psi/ft (0.231 kg cm -2 m -1) of depth. As discussed earlier, the hydrostatic pressure will vary from locality to locality dependent upon the specific weight of the water (salinity).

36


S S

S

P ; : : ,,)

(2-43)

Consequently, Pb = ps(1

- ~bmaxe -0"45D)

(2-44)

In Fig. 2-12 the density of mineral grains was assumed to be equal to 2.7 g/cm 3. It was assumed that the initial maximum porosity of the clayey sediment was equal to 60%. If the values read from Fig. 2-12 indicate a lower initial porosity, there are several possible

43


POROSITY (~), % 60

50

40

30

20

10

o

0,1

5C 0.5

E

4,5

1.0

c~

30

"1-

2~

0_

LJJ

20

c~ 5.0

10.0

] .1

1.5

1.9

DENSITY (pJ,

2.3

2.7

g/cm

Fig. 2-12. Interrelationship among the bulk density, porosity and depth of burial (lithostatic load) for argillaceous sediments. 4) = q~maxe-0"45D; jOb -- ps(1 --q~maxe-045D); Ps = 2.7. The numbers des gnate the values of initial porosity (4~max) from 60 to 5%. The same numbers shown on the first curve to the left, correspond to the curves with different initial porosity, shifted along the depth scale to the 60% curve. (Modified after Ozerskaya, 1965; also see Avchyan and Ozerskaya, 1968, fig. 2, p. 139; in Rieke and Chilingarian, 1974, fig. 54, p. 106.)

explanations: (1) part of the overburden load was removed by erosion; (2) uplift of the region; (3) geotectonic forces caused excess compaction; (4) subsequent cementation and filling of pores; (5) presence of sand and carbonate fractions; (6) wrong initial porosity assumption.

COMPACTION MODEL5

The pore volume of clastic sediments and rocks decreases with increasing depth. This decrease in porosity is a convenient measure of the amount of compaction undergone by

44


argillaceous sediment since deposition. There is a problem in evaluating the effects of depositional rates and geologic age in developing a simple sediment compaction model. Nevertheless, empirical data suggest that the effect of age and depositional rates are commonly predictable. Although the effect of temperature on formations is difficult to evaluate, experiments by Warner (1964, pp. 50-79) suggest that at temperatures less than 200~ temperature may not have a significant effect (other than in accelerating compaction rates). Most compaction models utilize clay minerals of an idealized size and shape, which are influenced by mechanical rearrangement during burial. The following theories, presented in chronological order, are intended to enable the reader to better visualize the interrelationship among pressure, porosity reduction, and interstitial fluid release in argillaceous sediments. A comparison of the relationship between the porosity and depth of burial is shown for several regions in Fig. 2-13.

Athy's compaction model According to Athy (1930a) compaction represents a simple process of squeezing out the interstitial fluids and thereby reducing the porosity. In relatively pure shales a definite relationship exists between porosity and depth of burial (Fig. 2-14). After a sediment has been deposited and buried, the pore volume may be modified by: (1) deformation and granulation of the mineral grains; (2) cementation; (3) solution; (4) recrystallization; and (5) squeezing together of the grains. The continued application of overburden or tectonic stress is the mechanism by which porosity is reduced and bulk density is increased further. Athy (1930b) pointed out that the amount of compaction is not directly proportional either to reduction of pore volume or to increase in bulk density because of the above-mentioned processes.

Hedberg's compaction model Hedberg (1936) stated that because of the numerous processes involved in compaction, it is not possible to express satisfactorily pressure-porosity relationships for clays and shales throughout the entire depth range by any one simple equation. Hedberg (1936) determined the porosities of shale core samples taken from Venezuelan wells from depths of 291 ft to 6175 ft. An analysis of these data, led Hedberg (1936) to propose a compaction process consisting of three distinct stages. The first stage consists mainly of the mechanical rearrangement and dewatering of the clayey mass in the pressure interval from zero to 800 psi. During this period of dewatering, there is a rapid decrease in porosity for small increments of additional overburden pressure. Expulsion of free water and mechanical particle rearrangement are dominant in the porosity range from 90% to 75%. Some adsorbed water is also lost during this stage. Between a porosity of 75% and 35%, adsorbed water is expelled from the sediment. Mechanical deformation of the clay structure occurs below a porosity of 35% where the clay particles come in closer contact with each other. As a result, there is a greater resistance to further reduction in porosity. According to Hamilton (1959, p. 1407), the


45

|

1

J

jS 5o00

,-l-,Wl--,

'!'

q .C:

l o,ooo

'

C}. (I) C~

,

/~

/

1

r

I

i

,o

15,000

20,000

.........

i 0

, 20

,,

i

40

60

Porosity (~). % Fig. 2-13. Various compaction models showing the relationship between porosity and depth of burial for shales and argillaceous sediments. 1 --- Proshlyakov (1960); 2 = Meade (1966); 3 = Athy (1930a); 4 = Hosoi (1963a,b); 5 = Hedberg (1936); 6 = Dickinson (1953); 7 = Magara (1968); 8 = Weller (1959); 9 = Ham (1966); 10 = Foster and Whalen (1966). (Modified after Rieke and Chilingarian, 1974, fig. 17, p.42.)

transition from clay to shale likely occurs at about 35% porosity, because the chemical changes and cementation between the grains impart rigidity to the skeletal structure. There is also some recrystallization of the clay particles during this stage (Hedberg, 1936). Recrystallization stage is the third and final stage with porosities less than 10%. The main compaction mechanism during this stage is recrystallization under high pressures. Reduction of the pore volume occurs slowly and only with large pressure increments. The larger crystals may grow at the expense of the smaller ones, and a gradual transition may occur from a shale to a slate and then to phyllite.

46

G.V. CHILINGAR,J.O. ROBERTSONJR. AND H.H. RIEKE III

2.6

A

,

..'-(

..

..

.

,~...>7.

..#/.,~?:.'

,.....:

.

.

.

.

9

: .

2.4

E

O

C d~ L3

2.2

2.0

1.8 /

1.6 I

/

/

/

!

!

/

/

/

/

/

/

/

I

i

1.4

I

I

I

i

,

1000

I

I

3000

i

i

Depth at Garber (O), It ~

5o

--O-

.,~

4o

o

30

w

i

I 5000

\

'

% %

B

% % % % % %

O

IX. C

20

O O

l0

.=u. .@,m

E O

i1_

0

I

0

i

l

2000

i

4000

Depth (O), ft

i

i

6000

Fig. 2-14. (A) Relationship between the dry bulk density and depth for Oklahoma (USA) shales. (B) Relationship between the porosity and depth for Oklahoma (USA) shales. (Modified after Athy, 1930a, figs. 2 and 3, pp. 12-13; in Rieke and Chilingarian, 1974, fig. 14, p. 37. Courtesy of Am. Assoc. Pet. Geol.)

Weller's compaction model Wello," cloCaa described a compaction process ,,or,, ~imil,r to the one proposed by

Ilcdbci~; (lPJo). ,Vcllt~i'a cuJ,Jpuaitc pu~uaity-dvpm cmvc ~llu'~vnin Fig. 2-i5 lcplcSClitS an equilibrium condition in a continuous column of ordinary mud and shale. This curve is based on Terzaghi's, Athy's, and Hedberg's data. The porosity-depth relationships can be distorted by the occurrence of carbonates and sands in shales and by abnormally

47

ORIGIN OF ABNORMALFORMATIONPRESSURES 1.8

5.4

12.8

01

20.0

27.2

34.6

41.8

49.1

. . . .

"-~~2.0

9

"8 3.0

~

4.0

/

- .

! 5.0 98

196

392

588

784

980

1176

Pressure, N/m 2 Fig. 2-15. Interrelationship among porosity, depth of burial and overburden pressure. N = unit of force (Newton) = 102 g-force = 105 dyn. (Modified after Weller and Vassoevich, in Kartsev et al., 1969; in Rieke and Chilingarian, 1974, fig. 18, p. 43.)

overpressured zones. In addition, application of laboratory soil-compression tests to buried sediments presents some problems. Weller (1959) proposed a compaction process starting with a mud at the surface having a porosity between 85% and 45%. As the overburden pressure increases owing to sedimentation, the interstitial fluids are expelled from the pore space (porosity ranges from 45% to 10%). As a result, there is rearrangement of the mineral grains and development of closer packing. Compaction in this stage is related to yielding of the clay minerals between the more resistant grains. Weller theorized that at about 10% porosity, the non-clay mineral grains are in contact with each other, and the clays are being squeezed into the void space. Further compaction (porosity < 10%) requires deformation and crushing of the grains.

Powers' compaction model Powers (1967) presented a shale fluid-release theory based on changes in clay minerals and bulk properties with depth in argillaceous sediments. His theory assumes that mineralogical transformation of montmorillonite to illite occurs during deep burial, with the consequent release of large volumes of bound water from montmorillonite surfaces to interparticle areas where it becomes interstitial water. In the case of marine montmorillonitic sediments buried to a few hundred feet, a balance is reached between the water retained in the sediment and the water-retaining

48


~ MONTMORILLONrrE BEFORE DIAGENE$1S

AFTER DIAGENESIS TO ILLITE

O ~

"r~

0 0

VOLUME

o.

"o d, l r

LOST

AFTER DIAGENESIS 8= COMPACTION

~

UNIT LAYER OF CLAY WATER CLAY PARTICLE (AS

NUMBEREO)

Fig. 2-16. Effect of clay diagenesis on compaction of mudrocks, on assuming that the same number of particles, crystal aggregates, and unit layers of clay occur in each compaction stage shown. (A) No effective porosity or permeability; practically all water is bound water. (B) Most bound water becomes free water; consequently, effective porosity and permeability are greatly increased. (C) Free water squeezed out; effective porosity, permeability, and original volume are greatly reduced. (Modified after Powers, 1967, fig. 1, p. 1242; in Rieke and Chilingarian, 1974, fig. 57, p. 110. Courtesy of Am. Assoc. Pet. Geol.)

properties of montmorillonite (Powers, 1967, p. 1244). Further increase in overburden stress alone, resulting from deeper burial of the mud is ineffective in squeezing the remaining water out of the plastic sediment. At burial depths greater than 1500 to 3000 ft, most of the water exists as water of hydration and is stacked at least four monomolecular layers thick between the unit layers of montmorillonite. Only a small amount of oriented water occurs between the crystals and particles at depths of about 3000 to 6000 ft (Fig. 2-16A). At burial depths below about 6000 ft, montmorillonite is altered to illite and the bound water is desorbed and becomes free pore water (Fig. 2-16B). This causes a decrease in clay-particle size with a corresponding increase in the porosity and permeability at burial depths of 6000 to 9000 ft. Below a depth of

ORIGIN OF A B N O R M A L FORMATION PRESSURES

49

9000 to 10,000 ft, the water released from the clay is compacted until a new balance is established corresponding to the water-retaining properties of the illitic alteration product (Fig. 2-16C). The relationships among water expulsion, type of clay mineral, and depth of burial are illustrated in Fig. 2-17, for both expanding and non-expanding clay deposits (Powers, 1967, p. 1245). The water-escape curves are diagnostic of the porosity, permeability, and bulk density of compacting argillaceous sediments. Powers stated that the compaction history of mudrocks depends largely on their original clay composition and the diagenesis and catagenesis, which they undergo after burial.

Teodorovich and Chernov's compaction model Teodorovich and Chernov (1968) suggested the following stages in the compaction of productive Apsheron horizons in Azerbaijan. (1) The first stage occurs at burial depths of 0 to 8-10 m where there is a rapid compaction. Porosity in clays decreases from 66% to 40%, whereas that of sandstonessiltstones decreases from 56% to 40%. Large amounts of water are squeezed out during this stage (sedimentogenesis and early diagenesis). (2) During the second stage there was a rapid decrease in the compaction rate in the intervals from 8-10 m to 1200-1400 m. During this stage, porosities of the shales and sandstones-siltstones decrease to about 20%. (3) The third stage (burial to a depth of 1400-6000 m) is characterized by slow compaction. The absolute porosity of sandstones-siltstones at a depth of 6000 m decreases to approximately 15-16%, whereas that of shales to 7-8%.

Burst's compaction model Burst (1969) proposed a compaction model based on a three-stage dehydration sequence and the transformation of montmorillonite clay to mixed-layer varieties. A description of this model appears in Chapter 4.

Beall's compaction model A. Beall (personal communication, 1970), proposed a simple model for consolidation of clastic muds, based on the data from offshore well core samples, Louisiana, the JOIDES Deep Sea Drilling Project, and from high-pressure experiments on marine muds. The initial stage of compaction (down to a depth of approximately 3300 ft) primarily involves expulsion of fluids by mechanical processes as in the other proposed theories. Approximately 50% of total consolidation is reached at a very shallow depth. The average calculated pore throat diameters during the first stage are around 6~. During the second stage (at depths of 3300 to approx. 8000 ft) about 75% of total compaction is complete, and pore throat widths in the clays approach 1 *. The fluid pressures remain hydrostatic. During the third-stage of compaction there is an extremely slow decrease of porosity with depth, and pore throat diameters are generally less than

REMARKS

SEVERAL MONOLAYERS OF UYOROGEN BONDED WATER HELD IN INTERLAYER POSITION IN MONTMORlLLONlTE CANNOT BE SQUEEZED W T BY COMPACTION PRESSURES. AS MONTMORlLLONlTE ALTERS TO ILLITE. WATER THAT I S HYDROGEN BONDED BETWEEN UNIT LAYERS IS DESOReEO ANOTRANSFERRED AS FREE WATER TO INTERPARTICLE POSITIONS. OVERBURDEN

MOST HYDROCARBONS FORYEO OR MADE AVAILABLE N THIS ZONE BUT NO

HYDROCARBONS

NO-UONTMORILLONITE LEVEL (USUALLY ABOUT 9,000 TO 10.000 FEET)

1-1 m i

WATER-ESCAPE

CURVE

MONTMORILLONITE

1-1

ILLlTE

m y

ILLITE

MIXED

LAYER

AND KAOLINITE

Fig. 2-17, Compaction history of various clays when deposited in marine environments and its probable relation to release of hydrocarbons from mudrocks. (Modified after Powers, 1967, fig. 3, p. 1245; in Rieke and Chilingarian, 1974, fig. 58, p. 111. Courtesy of Am. Assoc. Pet. Geol.)


51

1 ,~. According to Beall, NaC1 filtration could probably take place during the third stage, resulting in the expulsion of progressively less saline fluids to associated permeable sands, if the latter are present. In Beall's model, overburden pressure between 8000 and 12,500 psi would be required to initiate NaC1 filtration in marine muds. In the absence of permeable sands, the excess fluid pressure may be generated during the third stage. Overton and Zanier's compaction model

Overton and Zanier (1970) proposed a similar model to that of A. Beall with four zones having different water types: (1) depths less than 3000 ft m fresh water; (2) depths of 3000-10,000 ft m depending on the temperature, exponentially increasing salinities; (3) depths greater than 10,000 f t - decreasing salinities to the depth of greatest pressure gradients; (4) depths greater than 15,000 ft ~ increasing salinities with decreasing water fractions; physicochemical changes in shales occur in this indistinct zone. Overton and Zanier (1970) noted that for the Gulf Coast (USA), sands and shales are difficult to distinguish on SP (self-potential electric log) curves at depths less than 3000 ft, due to similarity of the waters in them. Water expelled from this interval is loose (free) water, which constitutes 30% to 70% of the rocks. At a critical compaction depth (depth around and usually less than 3200 ft), shales and sands become readily distinguishable on the SP curve. In zone 2, fresher water is held in the more-ordered or crystalline layer next to the clay, whereas saline water is forced into an equilibrium position in an outer layer (large pores in the shale and in the nearest sand). As the crystallinity of water increases, ions are expelled into a less-ordered or more fluid layer. Below a depth of 10,000 ft, shales remineralize (Overton and Zanier, 1970) and associated sandstones contain fresher waters. The beginning of zone 3 is readily apparent on the SP curve. The water freshening is probably due to the expulsion of (1) the last layers of dense, fresh water from shales into sands, and/or (2) water of hydration resulting from montmorillonite-to-illite alteration. For further details on compaction of argillaceous sediments, see Rieke and Chilingarian (!974).

CREATION A N D M A I N T E N A N C E OF A B N O R M A L P R E S S U R E S

Hanshaw and Bredehoeft (1968, p. 1117) suggested a hydrologic model in which there is a constant flux of water flowing from the compacting sediments. They examined the rate of fluid production as a result of mineral dehydration and conversion from a quantitative viewpoint. The creation of excess pore pressure in the formation and its maintenance with time is a boundary value problem expressed as: OZh' Oz 2

=

Ss Oh' K Ot

(2-45)

52


1.0

1.0

0.9 0.8

0.8

0.7

t~ 4::

0.6

0.6

0.5 0.4

0.4

0.3 0.2

0.2

z/i :0.1 01111 10 .3

I 04

I 0 "2

10 I

I

I0

Kt/Ss12

Fig. 2-18. Dimensionless graph of the excess-head pressure distribution for a finite layer with a constant flux at one boundary. Specific storage, Ss = volume of water taken into storage, or discharged per unit volume, per unit change in head. (Modified after Hanshaw and Bredehoeft, 1968, fig. 9, p. 1118; in Rieke and Chilingarian, 1974, fig. 177, p. 331. Courtesy of the Geol. Soc. Am. Bull.)

for the conditions of 0 < z < 1

h'(z, 0) -

0

att - 0

h'(O, t) - 0

att > 0

ah' = 0z z=t

qo K

att > 0

where h' is the excess head, z is the vertical coordinate, S~ is the specific storage, K is the hydraulic conductivity, t is the time, l is the thickness of sediments, and qo is the flow into or out of the confining layer per unit area. The vertical dimension is defined at the source layer as z -- 1 (Hanshaw and Bredehoeft, 1968, p. 1118). The solution to this problem is taken by analogy from conduction of heat in solids (Carslaw and Jaeger, 1959, p. 113) as"

h'K_z qol -- 1

8 L (-1) n 7/-2 (2n + 1----~exp ,,=0

[-(2n+l)27r2Kt] 4S~12

[(2n + 1)7rz] sin

21

(2-46)

Fig. 2-18 is a graphical solution of Eq. 2-46 presented by Hanshaw and Bredehoeft (1968, p. 1118). The finite zone (Fig. 2-18) behaves as an infinite medium until the effect reaches the outer boundary. Hanshaw and Bredehoeft (1968, p. 1118) simplified the problem for time before the change in head reaches the outer boundary by considering the head

53

ORIGIN OF ABNORMAL FORMATION PRESSURES 10

%

O"

10 -1

10-2 10 -1

1

10

100

z/fKt/Ss} 1/2 Fig. 2-19. Dimensionless graph of excess-head pressure distribution in a semi-infinite medium with constant flux at the boundary. (Modified after Hanshaw and Bredehoeft, 1968, fig. 10, p. 1119; in Rieke and Chilingarian, 1974, fig. 178, p. 332. Courtesy of the Geol. Soc. Am. Bull.)

distribution in a semi-infinite medium: 02h '

Ss Oh'

Oz 2

K Ot

(2-47)

where 0 < z _< ec h'(z, 0) - 0 h'(oc, 0) - 0

at t - - 0 att>0

Ohl

qo

Oz z=0

K

att>0

It is necessary to define z = 0 at the boundary of the media, which for the core of a semi-finite m e d i u m is at the source layer. By analogy, the solution is obtained from Carslaw and Jaeger (1959, p. 75):

Ssz~2 exp

-qoz

~

-Ssz2 4Kt

erf

~ 2

- 1

(2-48)

/Kt

A graphical solution to Eq. 2-48 is presented in Fig. 2-19. The head at the surface,

54

G.V. CHILINGAR, J.O. ROBERTSON JR. AND H.H. RIEKE III 10

-1

10

.2

10

.3

o

O" E:

lo-4t 10

l

-7

10 .6

10 .5

10 .4

10 .3

I I i I li:

10 .2

ktlSs 12

Fig. 2-20. Dimensionless graph of excess-head variation for small values of time at a surface of constant flux (z/1 = 1). The solution is the same for either the semi-infinite or finite medium. (Modified after Hanshaw and Bredehoeft, 1968, fig. I1, p. 1119; in Rieke and Chilingarian, 1974, fig. 179, p. 332. Courtesy of the Geol. Soc. Am. Bull.)

z = 0, was given by Carslaw and Jaeger (1959, p. 75) as:

h'K = 2 / K t qo

(2-49)

V Jr S~

For small intervals of time, Eq. 2-49 gives the same results as Eq. 2-45 for the finite layer that is evaluated at the surface of constant flux (z/l = 1) (Hanshaw and Bredehoeft, 1968). Excess head at the surface of constant flux is presented in Fig. 2-20 for very small amounts of time by solving Eq. 2-45. Hanshaw and Bredehoeft (1968, p. 1119) used Figs. 2-19 and 2-20 to compute the pressure, for a source bed at 1200 m depth, overlain and underlain by beds of low hydraulic conductivity. The conductivities of 10 -12 cm/s and 10 -l~ cm/s were both used. They reported that the results obtained are extremely sensitive to hydraulic conductivities and flow rates. Assuming a burial rate of 500 m/106 years, the phase transition period (time during which fluid will be produced) for a 15-m-thick bed is about 30,000 years; upward or downward flow will be 3.85 x 10 -~~ cm/s. At a hydraulic conductivity of 10 -12 cm/s, Hanshaw and Bredehoeft (1968) calculated that it is possible for the fluid pressure to approach the lithostatic load. As the fluid pressure increases, it will also decrease the reaction rate and, therefore, decrease the fluid flux at low values of the hydraulic conductivity. If the hydraulic conductivity is increased to 10 -1~ cm/s, there will be an insufficient quantity of fluid produced to create pressures much in excess of the hydrostatic pressure. The important variables are the burial rate, thickness of the


55

gypsum bed, and hydraulic conductivity of the confining layer. The gypsum-dehydration mechanism in compacting sediments will produce high fluid pressures only if all the above variables are within certain definable limits. This is also true for the montmorillonite-dehydration model: Hanshaw and Bredehoeft (1968, p. 1117) assumed that if each cubic centimeter of sediment contains 2 g of montmorillonite, then dehydration of montmorillonite will produce 0.33 g/cm 3 of H20. Enthalpy data from Sudo et al. (1967) indicate that 178 cal/cm 3 is required to release the interlayer water. Employing the following assumed values of 10 -6 cal cm -2 s -1 for a heat flow rate and 1.6 x 10 -9 cm/s as a burial rate, 6.3 x 101~ s would be required to increase the depth by 1 cm. In that time, 630 cal/cm 2 would be available from the usual flow of heat found in the Earth. There would be more than enough heat available for the dehydration reaction to proceed (Hanshaw and Bredehoeft, 1968). Interlayer water would be released at the rate of 5.1 x 10 -1~ cm/s. In the phase transition of gypsum, the reaction went from a solid to a solid plus water; however, in the dehydration of montmorillonite the dense water expands. Not all of the water is moved from the reaction site. If one assumes that all interlayer water has a density of 1.4 g/cm 3 (Martin, 1962), expansion, upon release to water having a normal density of 1 g/cm 3, will result in an increase in specific volume (reciprocal of density) of 28.5%. Hanshaw and Bredehoeft (1968, p. 1117) calculated that the total flow (qo) upward or downward will be equal to 0.285 x 0.5 x 5.1 x 10 -1~ or 7.3 x 10 -11 cm/s. In this case, a conductivity of 10 -12 cm/s and about 106 years would be required to approach lithostatic pressure on the fluid. In an actively subsiding basin such as the Gulf Coast Basin, this mechanism could provide a significant increase in pore pressure if the amount of montmorillonite is high and the permeability is low.

MECHANISMS GENERATING ABNORMAL FORMATION PRESSURES

The mechanisms responsible for generating abnormal pressures can be classified into three categories (see Tables 2-1 and 2-2), as indicated previously. (1) Changes in rock pore volume: (a) vertical loading (undercompaction); (b) lateral tectonic loading; (c) secondary cementation. (2) Changes in the volume of interstitial fluids: (a) temperature change; (b) mineral transformations; (c) hydrocarbon generation; (d) thermogenic decomposition of hydrocarbons; (e) migration of fluids (mainly gas). (3) Changes in fluid pressure (hydraulic head) and movement of fluids: (a) osmosis; (b) fluid pressure head; (c) oilfield operations; (d) permafrost environment; (e) differences in specific weights (e.g., between gas and oil).

Undercompaction Undercompaction of sediments can occur during rapid sedimentation and burial of sediments containing a large quantity of clay minerals (Rubey and Hubbert, 1959; Wilson et al., 1977). Thus, the complete expulsion of water from the sediments does not occur, and sediments are left as a loosely bound system of swollen clay particles with

56


interlayered water. According to Harkins and Baugher (1969), in order for abnormal pressures to develop, the shales must be over 200 ft in thickness. Continued sedimentary deposition can result in a shear zone developed by overloading the undercompacted shale. Expulsion of water from these sediments is accompanied by the subsidence of blocks of sediments. Many contemporaneous faults found in the Gulf Coast Basin (USA) exhibit the following cycles: (1) deposition, (2) expulsion of water, (3) subsidence of blocks of sediments, and (4) temperature increase. (Also see Chapter 1.) Tectonics

Tectonic activity may be the cause of AHFPs, including local and regional faulting, folding, lateral sliding and slipping, squeezing resulting from down-dropping of fault blocks, diapiric salt/shale movements, and earthquakes. In their classical book, Poston and Berg (1997) stated that some of the earliest recorded AHFPs were reported from areas where recent tectonic activity caused the principal normal stress to be horizontal. Transfer of tectonic stress to the fluids can result in overpressures, as exemplified by the Ventura oilfield of California (USA). Fig. 2-21 illustrates the effect of tectonic activity on oilfield pressures. Other pertinent references appear in Chapter 8.

%

%

",,

Khaur

o o o \ Ventura \

Q.

"-'~\

s

,

\

o~k, Chia-Surkh 'O~, . ,, e -, ~ ~ - Qum

10

\

G~

"G, \

12 0

2

4

6

8

10

12

Pressure, 1,000 psig Fig. 2-21. Overpressures recorded in wells drilled in or near active tectonic belts of compressional loading and faulting. (Modified after Hubbert and Rubey, 1959, p. 115.)


57

Growth faults According to Dickey et al. (1968), high-pressure zones in the Louisiana and Texas Gulf Coast region of the United States are related to the particular patterns of block faulting accompanied by contemporaneous sedimentation and compaction. This creates lateral seals that, together with a layer of thick shale overlying the surpressure zones, prevent the loss of pore fluids from the sediments during compaction and diagenesis. Resistance to the flow of water through the clay is a function of decreasing porosity and permeability of the clays as compaction progresses. The hydraulic permeability of clay is negligible in the geopressured environments. The clay beds have overlain abnormally pressured formations for millions of years without the release of the pressure by fluid flow across the clay/shale beds. When clays are compacted, a stage is reached where the porosity and permeability are so low that the flow of water is completely restricted. According to Dickey et al. (1968) the growth faults of the Gulf Coast exhibit the characteristics of slump-type landslides, which in many cases may be due to old slides that were later buried by sedimentation. The stratigraphic units are thicker on the downthrown side of the growth faults than they are on the upthrown side, because during sedimentation there was continuous movement along the fault planes. As compaction of sediments progresses, the vertical permeability of argillaceous sediments decreases rapidly. As burial continues, the pore pressure is increased by the mass of the additional overburden of sediments and temperature increase. In general, abnormally high pressures are found at depths of 10,000 to 11,000 ft. Abnormally high formation pressures are encountered in the Niger Delta area in Nigeria, Africa, where the subsurface structure of the delta is characterized by growth faults with associated rollover structures, which are caused by gravity (Hospers, 1971). (Also see Chapter 1 on Growth Faults.)

Transference Redistribution of excess pore pressure in the subsurface is referred to as transference (Swarbrick and Osborne, 1998). It is not a primary mechanism in itself for creating overpressures, but transference may exert a strong influence on many of the pore pressure profiles seen in the subsurface, and may mask recognition of the underlying causal mechanism.

Effect of temperature increase on formation pressure (aquathermal pressuring) Jones (1969, p. 804) pointed out that abrupt changes in temperatures over short depth ranges are hydrologically critical to the geopressured regime, because the movement of water is the most important factor in sustaining terrestrial heat flow in the sedimentary basins. Conventional maps of geothermal conditions, however, tend to obscure, rather than to identify, abrupt changes in temperature. An increase in the geothermal temperature, as the compacting sediments are subsiding in the basin, causes the pore fluids (gas, oil and water) to expand more than the enclosing rocks. Such an expansion would create abnormal fluid pressures in the rocks. There are three modes of heat transport through fluid-saturated sediments: (1) convective flow of interstitial fluids,

58


(2) conduction through mineral grains and interstitial fluids, and (3) radiation. Jones (1969, p. 807) listed several factors that have a direct beating on the heat flux in sediments: (1) thermal conductivity and composition of (a) the mineral grains that form the rock matrix and (b) interstitial fluids; (2) specific heat of the pore fluids and solids; (3) porosity and pore distribution in the shales and sands; (4) density, viscosity and thermal expansion of the pore fluids; (5) thermal expansion of solids; (6) absolute temperature. Lewis and Rose (1970) and Jones (1969) observed that in the Gulf Coast region the overpressured zones have abnormal temperature gradients. Jones (1969, p. 804) found no relationship between the average geothermal gradient and pressure/depth ratio (geostatic ratio) in the Gulf Coast Tertiary sediments after studying 175 south Louisiana overpressured reservoirs above a depth of l 1,000 ft. Nevertheless, the occurrence of abnormal pressures is commonly associated with a sharp increase in the geothermal gradient in the sealing clay member of the reservoir (C.E. Hottman, personal communication, 1966; in Jones, 1969, p. 804). According to Lewis and Rose (1970), the abnormally pressured shale zones constitute thermal barriers, because they are undercompacted and have high porosity compared to the adjoining sediments. Reduction in the upward flow of water in these zones greatly reduces the rate of upward flow of heat and, consequently, the overpressured zones become heat storage areas. In addition, the insulating effect of water is three times greater than that of the shale matrix. The larger the amounts of fluid stored in the overpressured shales, the greater is the insulating value of the zone. Whenever there is an insulating layer in the Earth's crust there can be a buildup of heat beneath this layer. Thus, the geothermal gradient is steepest in the portion of the beds above a permeable reservoir. Jones (1969, p. 805) reported gradients as high as 6~ ft in such settings. The steepness of the geothermal gradient varies inversely with the thickness of unconsolidated sediments in the structural basins (Jones, 1969, p. 807). Geothermal gradients are large in the undercompacted shales overlying the reservoir sands and are very much reduced in the aquifers. The thermal conductivity of sediments varies inversely with the geothermal gradient, if the geothermal flux is uniform over broad areas. Langseth (1965) stated that the thermal conductivity of clay varies inversely with its water content, and Zierfuss and van der Vliet (1956) discovered that the thermal conductivity of sand increases with porosity owing to the occurrence of convective heat transport in the wider pores. As pointed out by Bogomolov (1967), water plays a major role in the redistribution and subtraction of heat in the geothermal field of the Earth's sediments. Jones (1969) stated that convective and conductive heat flow is important in the low-temperature range above depths of 10,000 ft in the northern Gulf of Mexico Basin. Water temperatures in this area are greater than 250~ at depths ranging from 10,000 to 14,000 ft (Jones, 1969). Lewis and Rose (1970) showed a range in average geothermal gradients from 1.6~ to 2.2~ ft for the Texas Gulf Coast.


59

Perhaps the most obvious feature of the geothermal-gradient maps of the northern Gulf Coast Basin is its conformity with the structural map. Elongate areas, beneath which the geothermal gradient is lowest, overlie the axis of the depositional basin (Gulf Coast geosyncline). Sediments which overlie the deepest portion of the Gulf Coast geosyncline would appear, then, to possess the highest thermal conductivity. Jones (1969, p. 807) stated that if they do not, then they must form a thermal sink and are now storing heat energy received from below; their temperature must inevitably rise. The endothermic diagenetic processes occurring in these argillaceous sediments, such as the dehydration of montmorillonite, require the addition of heat and, thus, reduce the amount of heat flux to the overlying sediments. Jones (1969, p. 808) concluded that, by checking the upward flow of water from the saturated sediments beneath the shales, the sealing clay beds have caused a reduction of the geothermal flux above and overheating of the undercompacted sediments below. When the interstitial fluids cannot escape the sediment, subsurface temperature changes can result in changes in pore pressure, especially if gas is present in the interstitial fluid. As sediments and pore fluids are buried deeper during sedimentation, the temperature rises and if the fluid cannot escape, the fluid density would decrease and volume will increase. If the fluid cannot escape, the effective pressure (grain-to-grain stress) decreases and the pore pressure increases; thus, the interstitial fluids support more of the overburden pressure (see Poston and Berg, 1997, pp. 13-16). Calculation of pressure abnormality due to changes in temperature is presented in Chapter 5.

Decomposition of organic matter Organic matter (or kerogen), which constitutes a substantial part of freshly deposited muds, converts to liquid and gaseous hydrocarbons during diagenesis and catagenesis. The resulting fluids released during these transformations can create, or accentuate, the overpressured, undercompacted, state of the compacting clay sediments: (a) by increasing the pore pressure; and (b) by further impeding the expulsion of interstitial pore water through the development of a second gas-fluid phase. Methane bubbles dispersed in water reduce the permeability of the rock to either phase (Chilingarian et al., 1995).

Gas migration As mentioned in Chapter 1, one mechanism which is responsible for the formation of abnormal pressures and yet not fully recognized is the migration of hydrocarbons (mostly gas) from the lower to upper horizons along faults. One such example is presented here. Larichev and Timurziev (1987) studied petroleum geology of pre-Jurassic formations in the Mangyshlyak Peninsula on the eastern shore of the Caspian Sea in relation to the neotectonic movements (Fig. 2-22). One of the tectonic characteristics that they investigated was the gradient of the amplitudes of recent vertical movement defined as the amplitude per unit horizontal distance. First, the map of recent vertical

60


Gradient of movement amplitude, m/km I

...: 9 ..:.~

"".'"':7 9.'..I~-

0

9

9

4

8

12

is

20-a2

~

..~ o'.. 9' , ; .'..... o. 9 .';.o

1650

2

Pressure, kg/cm IO0 !

200

300

!

I

400

800

E c'-

1200

11

8 6e ~ 7

~.4 e2

1600

-4,,,-

~=

2000

%

2400 2800

,CI 3200 Fig. 4-1. Variation of formation pressure with depth in Cambay Basin, India. 1-3 = Calol" 4 - 8 -- Navagam; 9 = Cambay; 10, 11 - Ankleshvar; 12 = Cosamba. (Modified after Eremenko and Neruchev, 1968, fig. 2, p. 8.)

According to Rieke and Chilingarian (1974), the AHFP in argillaceous sequences is often attributed to montmorillonite dehydration as it is altered to hydromica (illite). For example, according to N. Batacharya (in Eremenko and Neruchev, 1968, p. 8), in the Cambay Basin of India, where the geothermal gradient reaches 6.5~ m (about twice as high as those in the Volga-Ural region and West Siberia in Russia: 2.5 and 3.3~ m, respectively) montmorillonite disappears at depths of 1412 to 1500 m (see Table 4-1). Abnormal formation pressures in the Cambay Basin are presented in

99

SMECTITE-ILLITE TRANSFORMATIONS

%

2000

20 40 60

20 40 60

,,

'

9

'ca

c ;l ..

oo

o 9

E

3000

i

Cc)

9"

ea

oe

20 40 60

20 40 60 i

II

i

i

o

i

20 40 60

;

I

1

Cd)

1

Ce)

,o

9 ee

1" I!.

oo

!.

1

9

..c: 4000

9

NI,,,,-

o.

eo

9

9

9 9

m

e 9

o

-0

e,,

9 " 9,

9

9

e 9

eee

9

.;Io

9

I

II, 9

9

Q 9149

,

.,I "'i|" et

9

9

9

:

9

9

!:

~

o

"I:',

9

~Q

.

9

,.

9

oQ

9 e e,

o

5000 6000

9

oeO

e 9

oQ 9

9

eJ

o

:o

9

:8 ~ oe

!t" .::,|o QOqS

oe

18

"~ e9

9

Fig. 4-2. Contents of various clay minerals in the Productive Unit of the Baku Archipelago: (a) montmorillonite, (b) hydromica, (c) kaolinite, (d) chlorite, and (e) mixed-layered minerals. (Modified after Buryakovsky et al., 1995, fig. 4, p. 206.)

Fig. 4-1. On the other hand, field data in the South Caspian region, as discussed in this chapter, shows that a practically unaltered montmorillonite is present in the Baku Archipelago deposits at depths down to 6 km, i.e., throughout the entire drilled section (Fig. 4-2). This suggests a subordinate role of montmorillonite dehydration in the total process of AHFP development.

BURST'S COMPACTION MODEL A compaction model based on a three-stage dehydration sequence and the transformation of montmorillonite clay to mixed-layer varieties was proposed by Burst (1969). The initial dehydration stage is essentially completed in the first few thousand feet of burial as the interstitial water content is reduced to approximately 30% (20-25% interlayer water and 5-10% residual pore water) (Fig. 4-3). During the second stage, the argillaceous sediment is in a state of quasi-equilibrium as it continues to absorb geothermal heat. Pressure is relatively ineffective as a dehydrating agent because of the increased density of the interlayer water packet. As soon as the heat accumulation is sufficient to mobilize the interlayer water, one of the two remaining interlayers of bound water (statistically averaged) is discharged into the bulk system. Burst (1969, p. 80) stated that the amount of water in movement should constitute 10-15% of the compacted bulk volume. During the third stage, the final water increment, having approximately capillary water density, gradually is forced out of the clay mineral lattice and voids as sediment temperature increases. Burst's dehydration-compaction model was discussed by Rieke and Chilingarian (1974).

] 00

L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR Recent density

burial =

1.32

~

-v

Pore w a t e r

~

~

~

Interlayer

water

[-:.~--'--2"1

Swelling c l a y solids

t

"~""~'~~

I

~

~

~

~

~

After

l ~ ~

....

_

..... s,ooe,

~

20-/,, ~

- ...... ~ -----

_

.p

N o n - c l a y solids

I st

dehydration density = 1.96 L_ . . . . . ;;, ~ ..

~:.'zT~.:T:.l

c l a y solids

Non-swelling

x~

"-..

"" -.-.

After 2 n d dehydration

dens ity = 2. 28

"- - ~ ~ V o ~ - - . .

/

........ s,ooe,,

Aft e r. 3r.cl

~.

~:4 ............ 9........ ~ ........................... ;;:~.

"I"

dehvaraTion .

.

.

.

.

.

.

.

.

:~~IU:~i~C."~.~.~ ..-~ ..................... ........

s,ooe,,,

Fig. 4-3. Marine shale bulk composition during dehydration. (Modified after Burst, 1969, fig. 6. p. 81.)

ORIGIN OF ABNORMALLYHIGH FORMATIONPRESSURE Abnormally high formation (pore) pressure (AHFP) in reservoirs is known to be caused by several diverse factors. Buryakovsky et al. (1995) suggested that the most probable mechanism for development of AHFP, in regions with thick terrigenous sedimentary rocks (sand/shale sequence), is rapid sedimentation and gravitational

SMECTITE-ILLITETRANSFORMATIONS

101

E

Q

c-

Akchagyiian to A p s h e r o n i a n Quaternary Deposits

I0

20

30

40

50

i

i

I

;

i

70

60 I

80

90

I

I

1200

-

2000

-

2800

-

3600

-

4400

-

5200

-

r .m

> t~

I

400

E .mO .m

MPa

100

F•

Shales

r ~

Reservoir Rock

(1) (3. o. or (1) :3 o" (!) r

(1) > o :3 "(3

o

IX.

VII Horizon

~ 6000

-

.

~

.,,~

Fig. 4-4. Pore fluid pressure gradient, ~ (in MPa/m) in shales and in reservoir rocks in the Baku Archipelago. (Modified after Buryakovsky et al., 1995, fig. 2, p. 205.)

compaction. This leads to significant underconsolidation (undercompaction) of rocks and to development of AHFE In this process, abnormal pressures in reservoir rocks are caused by those in shales and approach each other only in moderately thick beds. The regionally developed reservoirs have a better pressure distribution than that in shales; consequently, their pore pressure is usually lower than that in the enclosing shales (Fig. 4-4). In the South Caspian Basin, the drilled Pliocene terrigenous section is 6.5 km thick, with AHFP unevenly distributed, both vertically and laterally. Presence and intensity of AHFP are determined by lithofacies of the oil- and gas-beating rocks, tectonics (uplifts), feasibility of underground water discharge and other factors. The highest clay content (up to 95%) has been observed in the Productive Unit of the Baku Archipelago. An important regional feature is the very high porosity of argillaceous rocks, much higher than those at similar depths in other areas of the world (Buryakovsky et al., 1982, 1986, 1995; Dzhevanshir et al., 1986). Porosity of Pliocene shales in Azerbaijan at depths of

102

L.A. BURYAKOVSKY, R.D. DJEVANSHIR, G.V. CHILINGAR, H.H. RIEKE III AND J.O. ROBERTSON, JR.

Porosity, IE

0.001 o

2 I

3 4 56 I

I

I

0.01

I I I II

2 I

3 4 56 I

[

I

I II

0.1 II

2

3

,,,,.

:::I::: 7

i

.,,,..

"-

2000

0

,2 ~

6, 'S

r,,

r

400C

6000

Fig. 4-5. Relationship between porosity (r %) and depth of burial (H, m) (Weller, 1959); 2 = Mesozoic (Proshlyakov, 1960, and Dobrynin, 1970); 3 (Vassoyevich and Bronovitskiy, 1962); 4 - 6 -- Middle Pliocene (Durmishyan, Archipelago; 5 = South Apsheron Offshore Zone; 6 -- Baku Archipelago (Modified after Buryakovsky et al., 1995, fig. 3, p. 206.)

for shales. 1 - Devonian = Oligocene to Miocene 1973a,b) (4 - Apsheron and Lower Kura region).

4.0-5.5 km is several times higher than in consolidated shales present in other regions (Fig. 4-5). Such a difference is due to geological age, relative contents of clay and sand, temperature and other factors. The abnormally high porosity of Apsheron Archipelago shales is primarily a result of slower rate of compaction as compared to the subsidence rate, due to the slow pore water removal from the compacting argillaceous rocks during rapid sedimentation rate. This process was critical in the development of AHFP in the South Caspian Basin. Numerous initial formation pressure measurements in reservoir rocks and wireline logging determination of pore pressure in argillaceous rocks reveal a pattern of AHFP distribution throughout the section at the northwest flank of the South Caspian Basin (Table 4-2). The average gradients of initial formation pressures in the reservoir rocks, r/res, and of pore pressures in shales, rich, at the investigated depths, are (in MPa/m): 0.0106 and 0.0120 for the Apsheron Archipelago; 0.0119 and 0.0145 for the South Apsheron Offshore Zone; and 0.0138 and 0.0182 for the Baku Archipelago and Lower Kura region. A substantial difference between the initial formation pressures in reservoir rocks and pore pressures in shales (by a factor of over 1.5) exists in the Baku Archipelago, where the average thickness of shales, hsh, is particularly higher than in the other regions of Azerbaijan. Generally, AHFP rises with the relative content of shales, Xsh, throughout the section (Table 4-2) and within the reservoir (Fig. 4-6). The highest shale pore pressures are associated with shale sequences in the Baku Archipelago

9

e~0

9

r

9

,

.. +..a

9

o~

Apsheron Archipelago

South Apsheron Offshore Zone

Baku Archipelago and Lower Kura region Vies

(MPa/m)

(MPa/m)

50 40 30 20

12 8 5 3

0.0122 0.0125 0.0120 0.01 10

0.01 I6 0.0108 0.0100 0.0098

250 235

15 12 10 8

0.0137 0.0146 0.0149 0.0 148

0.0 124 0.0119 0.0116 0.01 16

900 725 460 350

21 18 16 13

O ~

O

O

~

oO

0.0135 0.0137 0.0 140 0.0142 O

~ o ~ o

~

~

q'~ ~

O

O

~

I50

r

185

0.0167 0.0179 0.0187 0.0 193

o ~ o ~

qsh

(%)

~

'$%h

(m)

r

hsh

(MPa/m)

O

Dies

(MPa/m)

O

l)$h

(%)

O

d%h

(m)

o ~ o

hsh

(MPa/m)

tt~

rlres

(MPa/m)

oO

O

O q'~

%h

(%)

O q'~ q'~ O Ig') r162 oO Ig'3 r r ,---~ ,---~

~

dJsh

(m)

~

O ~ r162 "r

h h

~.C~ oO

O O

~ r

2000 3000 4000 5000

,.azZ

(m)

~
1 rMg 2+ where r is percent equivalent, are gradually replaced by bicarbonate waters rNa + - rC1rSO z-

>1

For magnesium chloride type of water rC1- - rNa + > fls

(5-10)

Otw >> ors

(5-11)

and:

Thus, the following equation for estimating the pore pressure in cross-sections with permafrost and without permafrost can be derived:

[

(

Pa = P n - A p =

gPw

(h -

hst) -

1+

v

3(1 - v)

)(

tip

)() ](ow)

tip + flw

Pi

Pw

hi

AT

tiP + / %

(5-12)

where hst is the depth of the static water level. The first term in Eq. 5-12: H

=

gpw(h

-

hst)

represents the normal hydrostatic pressure, whereas the second term in Eq. 5-12: O

-- gPw

(lqt-l) ) ( ~P ) (P-~w)hi 3(1 - v)

/~p -+- flw

indicates deformation of the rocks and fluids due to increase in the mass of ice. The last and most important term in Eq. 5-12: V--

(ow) /~P -nt- flw

AT

represents the pore pressure component caused by volume changes in rocks and especially in interstitial fluids due to decreasing temperature (cooling). Fig. 5-3 shows the graph for estimating the pore pressure in the Nepsko-Botuobin anticline (eastern Siberia) based on Eq. 5-1. Using this equation, an estimated abnormally low pressure was calculated in more than 40 wells in 23 oilfields, and then compared to data obtained from field tests. The margin of error was usually not more than 4-5%. Abnormally high pressure (10-20% higher than the normal hydrostatic pressure) was present in one formation of this region (Osinskiy Horizon). But the origin of this pressure appears to be related to the decrease in pore volume due to salt deposition in pores and salt injection into the highly fractured zones.

FORMATION PRESSURE IN REGIONS WITH UPTHROWN AND DOWNTHROWN BLOCKS (UPLIFT AND SUBSIDENCE OF SEDIMENTARY ROCKS)

Some tectonic processes in the Earth's crust create abnormal pressure. Most likely, these processes involve multiple changes in the overburden, temperature, and squeezing out of water from shales into associated sandstones. A change in the overburden creates volumetric changes (increase or decrease in pore volume), whereas a change

132

G.V. CHILINGAR,V.A. SEREBRYAKOV,S.A. KATZAND J.O. ROBERTSONJR.

Pore Pressure (pp), MPa 10

20

30

0

600

600

10

20

30

'

qF]

'

2Vzz:1 1200

A)

CB)

1200

r \\

~8oo

1800

a \

2600

2600

\ \

Fig. 5-3. Curves for estimating pore pressure in the formations of the Nepsko-Botuobin anticline in East Siberia. (A) Areas with permafrost and average geothermal gradient (G2) of 0.8~ m. (B) Areas devoid of permafrost. Figures on curves represent geothermal gradient: 1 = normal hydrostatic pressure gradient; 2 -- calculated using the following equation: Pa = g p w ( h --

O/w 0.8hi) -- ~ [ T o . I tip "t- ~w

-F ( G I - G 2 ) h 4-

G2hi]

where tSw is the average density of formation water at depth h; hi is the thickness of the permafrost; G1 and G2 are geothermal gradients respectively before and after cooling; T0,1 is yearly average temperature of the Earth's surface prior to cooling; /4p is coefficient of pore compressibility and flw is coefficient of compressibility of pore water; and oe,,, is coefficient of thermal expansion of pore water. Assumptions for dense carbonate rocks: /4p ~ flw; tip + flw >> fl~ (/4~ is compressibility of solid mineral grains of rocks); C~w >> c~ (c~ is coefficient of thermal expansion of solid mineral grains composing the rocks); Poisson's ratio, v = 0.25; and Pi/lSw ,~ 0.75 (,oi is average density of ice). (Modified after Dobrynin and Serebryakov, 1989, fig. 51, p. 108.)

in temperature creates volume changes in the rock's skeletal structure and interstitial fluids. These processes operate only in sedimentary basins with aquifer systems; they do not operate in infiltration water systems. The following equation can be used for the estimation of abnormal pressure in regions with uplift plus erosion, or subsidence plus sedimentation (Dobrynin and Serebryakov, 1989): pa = Pn 4- A p

gpw(h

( I + V ) hst) +

3(1 - v)

(tip)gprAh_4_ /~p --~ flw

~C~w /~p + / 3 w A T

(5-13)

where parameters are the same as in Eqs. 5-5, 5-8, 5-9 and 5-10; Ah is the amplitude of subsidence or uplift and Pr is the average density of new deposits after subsidence and sedimentation. After the first and second parts of Eq. 5-13, it is necessary to use a minus sign in the case of uplift and erosion and a plus sign in the case of subsidence plus sedimentation.

133

METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATION PRESSURES

Pore Pressure (Pc,), MPa

Pore Pressure (p,:,), Mpa

(B)

(AI

~

0

E .,c

0..

4000

L3

i

40 ,,,

80

I

1

0

40

80

k

\\\ oo oo

I

,;oo2.oo oo..

..

Pore Pressure (Pc,l, MPa 0

40

(c)

80

I[.. -1 21"-..I 31~ 4000

a

'

\\

,,,,,

Fig. 5-4. Theoretical dependence of anomalous pressures in rocks with hydraulically closed pores on magnitude (amplitude) of downthrust (subsidence) and upthrust (uplift) of blocks. Figures on the curves for (A) and (B) represent amplitude of downthrust of blocks in m; for (C), amplitude of upthrust blocks in m. 1 = Normal hydrostatic pressure; 2 = geostatic (total overburden) pressure; and 3 = theoretical curves for pressure in hydraulically closed pores. Geothermal gradients: (A) and (B): 3 x 10-2~ (C): 4 x 10-2~ (Modified after Dobrynin and Serebryakov, 1989, fig. 26, p. 61.)

Cross-plots for estimating the abnormally high pressure in regions with downthrown blocks (subsidence) are presented in Fig. 5-4A,B, whereas for the estimation of abnormally low pressure in regions with uplift and erosion, Fig. 5-4C can be used. An estimate of the pressure in the D n i e p r - D o n e t z (Ukraine) and Middle Kura (Georgia) basins can be made. In Georgia, an abnormally low pressure was estimated in Eocene deposits at depths of 2 0 0 0 - 3 0 0 0 m. The amplitude of the compressional thrust is 800 m. According to Fig. 5-4, coefficients of abnormal pressure range from 0.7 to 0.9. In the Shebelin gas field (Ukraine), abnormally high pressures are related to strike-slip faulting with displacements of 1000 m. Using Fig. 5-4, at a depth below 5400 m, the coefficient of abnormal pressure is 1.5. It should be noted that the methods described lack precision and should only be used as a preliminary pressure prediction prior to drilling. More precise methods of calculating abnormal pore pressures are utilized during drilling, using well log and drilling data.

134

G.V. CHILINGAR, V.A. SEREBRYAKOV, S.A. KATZ AND J.O. ROBERTSON JR.

(A) Abnormally-High Pressure Log r

Log p

Log R

Log Ln,

Log In~,

...... --

Log A,~ .....

n

L .......

"1~

"t

me

s|. "I,

:1, im

(B) Abnormally-Low Pressure Log

Log p ,,,,

9 ,

Log R .

.

.

.

.

.

.

.

.

Log I~,~ t .

.

.

.

.

.

Log In~

Log Az

.

~. 9

~

;.;.-

Fig. 5-5. Well-log responses in zones of (A) abnormally high and (B) abnormally low pressures. 1 = Abnormally high formation pressure (AHFP) in reservoir rock; 2 = shales; 3 = limestone; 4 -sandstone; and 5 = abnormally high and abnormally low pressures in shales. (Modified after Dobrynin and Serebryakov, 1989, fig. 54, p. 112.)

C A L C U L A T I O N OF A B N O R M A L PORE PRESSURE DURING DRILLING

In normally pressured zones, all log responses related to porosity, when plotted on a semilogarithmic paper, form straight lines (i.e., the vertical axis is log (x), where x is a geophysical parameter such as resistivity, sonic travel time, density, and gamma-ray and neutron log responses). In zones of abnormally high and abnormally low pressures, however, the magnitudes of the responses change significantly (Fig. 5-5). Abnormal pressure, therefore, can be detected on wireline logs (also logging while drilling).


135

>, 0 0 t-

Resistivity 20

20

R

i

R

CB)

h

Fig. 5-6. Determination of abnormally high (A) and abnormally low (B) pressures using the method of equivalent depth. 1 -- Shale; 2 = sandstone; 3 = reservoir rock with anomalous pressures; 4 =

abnormal-pressure zone (pore pressure in shale); and 5 = crossed zone = zone not penetrated by drilling. h is the depth of investigation and he the equivalent depth (see Eq. 5-17). (Modified after Dobrynin and Serebryakov, 1989, fig. 55, p. 113.)

There are many methods for estimating and predicting abnormal pressure during drilling. Most methods are empirical dependencies between the pore pressure and log responses. There are three well-known analytical methods: (1) the method of equivalent depth (Foster and Whalen, 1966), (2) the method of normal compaction trend (Dobrynin and Serebryakov, 1978), and (3) the method of compressional curves (Dobrynin et al., 1982).

Method of equivalent depth The method of equivalent depth (Fig. 5-6) is based on the assumption that the same shale with equal physical properties at different depths will have equal effective stress (total overburden load, or, minus the pore pressure, pp)" ((7 -- P p ) l - - (0- - - P p ) 2

(5-14)

136


Using the above equation and the equations for the estimation of overburden pressure: (5-15)

~y -- gprh

and of pore pressure: (5-16)

pp = gpwh

it is possible to obtain an equation for the estimation of abnormally high pressure, ph (Alexandrov, 1987): ph

--

gphh

--

g(phre

--

he )he Pw

( 5 - 1 7 )

where prh and/9 he a r e the average densities of rocks at the estimated depth h and at the equivalent depth he, respectively, and phweis the average density of pore fluids to depth he. It is necessary to correct all parameter values for temperature, especially when the resistivity data are used as a geophysical property to identify equivalent depths. Method of normal compaction trend

In the method of normal compaction trend, the same assumptions are used as in the equivalent depth method, i.e., lithologically identical rocks with equal values of physical properties at different depths have the same effective stress. The normal compaction trend is dependent on the variation of rock properties with depth of burial at normal hydrostatic pressure. These properties can be determined using well-log data, drilling data, core analysis data, etc. In particular, the physical properties of shales depend primarily upon the degree of compaction. In nature, an exponential relationship exists between the depth of burial and porosity, density, or resistivity of normally compacted rocks (Fig. 5-7). When displayed on semilogarithmic plots, these exponential dependencies are shown by straight lines. Deviations from the straight lines indicate the upper boundary (top) of abnormal-pressure zones. For estimating abnormal pressure, Pa, the following equation can be used (Dobrynin and Serebryakov, 1978): P, -- Pn +

g(Pr - Pw) Ah log(xn/Xa) log(x2/xl ) + 0.435c~(x)GAh

(5-18)

where Pn is the normal hydrostatic pressure; Pr is the average density of rocks; Pw is the average density of water; or(x) is the temperature coefficient for each physical property; x2 and x~ are values of a certain geophysical parameter at depths h2 and hi; G is the geothermal gradient for the interval (hi - h2); Ah = (h2 - hi); and Xn and Xa are the values of a certain geophysical parameter used for the estimation of abnormal pressure within the normal compaction trend and within the zone of abnormal pore pressure. In the framework of this approach, it is not necessary to correct the values of geophysical parameters for temperature effects, because the temperature coefficient and geothermal gradient are included in Eq. 5-18. Using this equation, it is possible to estimate abnormally high and abnormally low pressures. In the case of abnormally high pressure, the second term in Eq. 5-18 is positive, whereas it is negative in the case of abnormally low pressure.

137


Log X B\ A

hi aZZ r

i\\

h2

I

S

J

2o 2~ Fig. 5-7. Correction of normal compaction curve to temperature T1 at depth hi. Abnormally high pressure zone in shale is dashed; solid line above h2 is normal compaction trend, AAt; dashed line above h2 is normal compaction curve corrected to temperature Tt at depth h 1 (BB ~ trend); 2a is the trend in abnormally pressured zone without correction to temperature T1; 2b is the trend in the abnormally pressured zone with correction to temperature T1. (Modified after Dobrynin and Serebryakov, 1989, fig. 56, p. 115.)

The method of normal compaction trend was used in hundreds of wells in various basins. It was also used for interpreting seismic data in studying the possibility of predicting anomalously high pressure intervals in the sand-shale sequences of the West Kuban Depression, Russia (Dobrynin et al., 1979).

Method of compressional curves The method of compressional curves has also been used in estimating abnormally high and abnormally low pressures for a very large number of wells. This method is based on the use of compressional curves of regularly compacted rocks, the shape of which depends on the difference between the overburden pressure and pore fluid pressure. A compressional curve is defined as a plot of several physical rock properties, which characterize the compaction of rock, versus effective stress (effective stress is the difference between the total overburden pressure and the pore pressure). Compressional curves (semilogarithmic plots of rock properties versus depth) are more useful for estimating the abnormal pressure than the normal compaction trend,

138


Log X

m

E t-

O

N

1

3

r > 0 I.Li

E

o .Q

2

,< o o

N

l

Fig. 5-8. Schematic showing the dependence of the physical properties of shales on the effective pressure Pe (Pe -- o" -- pp): 1 = depth hi" 2 = depth h z" 3 = depth h. (Modified after Dobrynin and Serebryakov, 1989, fig. 57, p. 119.)

because they are continuous through the zones of both normal and abnormal pressure. Thus, all values of a geophysical p a r a m e t e r in the zones of normal hydrostatic pressure and abnormal pressure lie on a straight line (Fig. 5-8), because the physical properties do not depend on depth, but rather on the effective stress (0" - pp). The general equation for estimating the abnormal pressure using this m e t h o d is: Pa - 0" -

log(x) -t- [0.435ot(x)(h - h i ) G ] - mx

(5-19)

?/x

where x is the value of a certain geophysical parameter at a depth of pressure estimation; mx and n~ are the y-intercept and slope of the compressional curve, respectively; or(x) is the temperature coefficient for each geophysical p a r a m e t e r used (plus or minus sign is used depending on the physical property of the rock); and G is the geothermal gradient for the depth interval (h - hI). The parameters m~, and n~ are defined by the following equations: nx =

l o g ( x z / x l ) • ot(x)(h2 - h l ) ( G / 2 . 3 ) (0"2 -- P2) -- (0"1 -- P l )

(5-20)

M E T H O D S OF E S T I M A T I N G A N D P R E D I C T I N G A B N O R M A L F O R M A T I O N P R E S S U R E S

139

n x (slope) .05~ -.o56 .----'.05

.054

-

-----'----'.04 .033o ,035

.029

9 , .025

~.0~

.033

. . . .

.04

~5~

[intercept]

\ .I ~

"35 9

9

e'[4

9

~

-.01~~

20211,/

/

q,. -.22

Fig. 5-9. Schematic maps of nx (slope) and mx (intercept) of compressional curve in West Kuban Depression. (Modified after Dobrynin and Serebryakov, 1989, fig. 85, pp. 180-181.)

mx

-

log(xl)(o-2 - P2) (o-2 - P2) - (o-1 - Pl) (5-21) log(x2) • ol(x)(h2 --

hI)(G/2.3)(o-I

(o-2 -- P2) -- (o-1

-

Pl)

Pl)

Maps of these parameters may be useful for the prediction of abnormal formation pressure during drilling of new fields. As an example, schematic maps of mx, and nx in the West Kuban Depression are presented in Fig. 5-9. The mx is the value of a physical property of the formation near the surface (at the beginning of the compressional curve), where the effective stress is equal to zero.

140


Another advantage of the compressional curves method is that it enables the estimation of thickness of eroded deposits and also the detection of unconformities (Serebryakov and Chilingar, 1994).

RADIOACTIVITY STUDY OF ZONES WITH A B N O R M A L L Y HIGH FORMATION PRESSURE

Zoeller (1984) and Starostin (1985) discovered a gamma-ray phenomenon (decreasing radioactivity) in zones of abnormally high pressure. They attributed this phenomenon to a high porosity in zones of abnormally high pressure. Upon extensive research, however, Serebryakov et al. (1995) noted that the decrease in radioactivity is not related to the change in porosity, because this phenomenon can be found only in basins with nonequilibrium compaction and only in overpressured zones. Radioactivity of sedimentary rocks primarily depends upon the presence of uranium, thorium and potassium. Starostin (1985) examined 166 core samples of shale both in the zones of abnormally high pressure and zones of normal hydrostatic pressure. He found that the contents of uranium and thorium are not different in the normally pressured and abnormally high pressured zones. In addition, U and Th are not sufficiently soluble. In the opinion of Serebryakov et al. (1995), the most important indicator is the radioactive isotope of K: (4~ The potassium ion has a negative hydration in water (Blokh, 1969), i.e., water molecules become more mobile in the vicinity of potassium ions than they do in pure water. According to the principle of Le Chatelier, there is a mobile balance between interstitial solutions and the solid phase. An increase in pore pressure leads to the disruption of mobile balance and, as a result, ions which can decrease the pressure (potassium ions) of the solution move into filtrating water. Water molecules become more mobile in the presence of potassium ions than in pure water (negative hydration) and migrate more easily, removing potassium ions. This leads to a decrease in concentration of 4~ ions in the shales of abnormally high pressured zones. It is interesting to note that mud (drilling fluid) engineers are quite familiar with potassium-based muds which inhibit clay swelling and hydration and, consequently, prevent heaving and sloughing of shales (Chilingarian and Vorabutr, 1981). The removal of potassium ions from abnormally pressured zones prevents the transformation of montmorillonites to illites, which requires potassium ions to complete the reaction. In addition, there is a conversion of illites to montmorillonites (reverse reaction). Both phenomena (in addition to overpressure) contribute to the greater potential of shales to swell because montmorillonites swell more than illites (Rieke and Chilingarian, 1974). The results of radioactivity studies of natural shales in the Kharasavey oilfield (northwestern Siberia) are presented in Table 5-4 and Fig. 5-10. The total radioactivity and the radioactivity of 4~ were obtained from gamma-ray logs and by measuring the radioactivity of 4~ in the core samples. Thus, it appears possible to use the natural shale radioactivity to locate the abnormally high pressured zones in basins with nonequilibrium compaction (origin of abnormal pressure) and where pore pressure is abnormal.

141


TABLE 5-4 Depth of wells, porosity, 4~ radioactivity (imp/min cm3), and total natural radioactivity (Iz, imp/min cm3) in the Kharasavey oilfield (after Dobrynin and Serebryakov, 1989, table 5, p. 88) Well No.

Depth, h (m)

Porosity, 4~ (%)

Radioactivity of 4~ (imp/min cm3)

Total radioactivity (imp/min cm3)

17 9 11 6 3 4 11 16 6 8 9 11 9 16 2 2 2

1812 1858 1504 1415 2068 2201 1508 1820 1417 2237 1528 2511 1530 802 1515 1469 1478

10.6 10.5 16.4 15.4 10.0 10.4 15.0 10.1 14.6 9.0 14.0 8.5 11.0 24.8 11.7 12.8 15.5

3.39 3.27 2.79 2.90 3.15 3.19 2.87 3.21 2.94 2.88 2.58 2.97 2.56 2.26 2.71 3.21 2.76

4.74 4.40 4.00 4.13 4.39 4.27 4.11 4.47 4.14 4.02 3.66 4.29 3.66 3.18 3.80 4.54 3.92

This method can possibly also be used for the paleoreconstruction of a hydrodynamic scenario in the geologic cross-sections based on the 4~ content, because shale can ' r e m e m b e r ' the existence of overpressures in the past in a particular zone (decreasing 4~ content).

PULSED NEUTRON CAPTURE LOGS Pulsed neutron capture (PNC) logging devices have been highly successful in distinguishing between formation waters and hydrocarbons and also in detecting formations that have an abnormally high pressure. These PNC logging devices measure the macroscopic cross-section, Sigma ( r ) , for t h e ~ a l neutron capture in the borehole environment. They have been used to examine formation waters behind casing and monitor production and depletion behavior of hydrocarbon reservoirs. Pulsed neutron capture (PNC) logging was initially developed to measure the parameter Sigma (27) (Youmans et al., 1964). This macroscopic cross-section of the absorption of thermal neutrons, I7, is a basic physical parameter of the formation surrounding the logging instrument. As such, the Z - v a l u e is a function of the chemical composition of the rocks and the amount, type, and composition of the fluids present in the pore space. Inasmuch as the Z - v a l u e s in shale formations can be determined by observing the thermal neutron die-away in the formation, following a burst of neutrons from a

142


Resistivity 2

500

I

5 l

I I

]0

2O

I

I

30 I

'

Total Radioactivity 3 4 5 I

I

I

Radioactivity of 4~ 2 3 4 I

I

I

Q

1000

E w

t-"

,4,.=-

o. (D

1500

2000

o;Ao

o ~,1"r

O o

O 9 1 499

e'~, O

"li Fig. 5-10. Resistivity (p, ohmm) total radioactivity (lr~, imp/mincm3), and radioactivity of 4~ versus depth (m) in shales in the abnormally high formation pressured (AHFP) Kharasavey oilfield, northwestern Siberia. (Modified after Dobrynin and Serebryakov, 1989, fig. 40, p. 88.)

pulsed neutron generator, the Z'-measurement is made by analyzing the time rate of decay of the thermal neutron population. The E-values in shale formations decrease in a regular fashion with depth in normally compacted clastic sequences. Abnormal formation pressures are, however, flagged by divergence from this normal Z-trend (Fertl and Chilingarian, 1987). Although this absorption cross-section is a nuclear measurement, the recorded log response is similar in appearance to the induction log. As a result, the r-measurement can be used in many geological applications in cased holes previously available only from the open-hole resistivity logs. Fig. 5-11 shows a useful application of PNC logs for quantitative formation pressure evaluation (Fertl and Timko, 1970). Shale resistivity (R~h) versus depth for a well drilled in Louisiana in 1946 is shown in Fig. 5-11A. All reservoir sands below 8200 ft have been productive for at least 25 years. This particular well produced from the Klump Series. After a casing collapse below 8100 ft, the plan called for placing the well back on production by recompleting it in the Homeseekers 'A' sand at a depth of 9060 ft

Tepetate, LA 7,000-

-

1946

(A1

.I.I

Original Shale Pressure 1946 (Short Normal)

x---x

' a

Shale Pressure 1966 (Sigma Curve)

Original Mud Weight

IOrtego A

t

*

.-

9.7 Iblgal

,8.000 -

A

5:

Y

c t

G

Q a,

= HomeseekenA I Homeseeken B

13

=

-

=

Kick off Point

0.53(10.2Ib/gal)

12.8 lWgal

14.0Iblgal 14.3 Iblgal Homeseeken C 14.8 lbigal Homeseeken 0 14.9 Iblgal

- Twedel

17.3 Iblgal 17.6 Iblgal

10.2Ib/gal MW-Maximu needed to redrill well

0.3

0.5

1 .O

2.0

Shale Resistivity, R,

20

30

40 50

Sigma Shale, C,

Formation Pressure, 1000 psi

Fig. 5-1 1. PNC log used in quantitative formation pressure evaluation. (After Fertl and Timko, 1970.) (A) Shale resistivity plot in Tepetate field well, Louisiana, drilled in 1946. (B) Sigma shale plot in the same well (cased) based on PNC log run in 1966. (C) Original shale pressure from short normal log (1946) and depleted shale pressures from Sigma curve (1966). (Modified after Fertl and Chilingarian, 1987, fig. 4, p. 32.)

144

G.V. CHILINGAR, V.A. SEREBRYAKOV,S.A. KATZ AND J.O. ROBERTSON JR.

6000

6000

-4===

8000 c~

Q)

r~ m

c~

0

!

-

.~_.. 7000 -

7000 -

8000

9000 ~ 9-5/8" casing ~ ' ~ I0,000 -

~:-

II

~

II

:~

Ib/gal

-

9000 [9"5/8" casin~ ----~

l l l

I0'000-

12.5 16.5 -

l

11,000 -

(D

7" casing

12,000

~~'~

i

12,000

15,000 0.1

" casi

13,000 -

13,000 14,000

t t

i

~5" casing

1

i

Shale Resistivity,

t

16.4 t

"oa'ng

17.6 -

14,000 - - 15,000 2 60

I 50

17.9

I

40

J

30

J, ,

20

-

I

10

Sigma Shale, Ysh

0

Fig. 5-12. Plots of a shale resistivity and Z-shale values versus the true vertical depth, which define the overpressure environment in offshore U.S. Gulf Coast well. (Modified after Taneja and Carroll, 1985.)

by side-tracking the original well above the casing restriction and redrilling to this target. The mud weight required to safely drill this well initially in 1946 to the Homeseekers 'A' target zone was approximately 14.0 lb/gal, because both the sands and shales contained overpressures equivalent to this specific weight of drilling mud. Due to production-related pressure depletion over the years, however, most of the sands had exhibited pressure gradients throughout this oilfield considerably less than hydrostatic. Thus, it was known that the interval to be redrilled would not sustain nor require the high mud weights used to drill the original well. The PNC log was run in the old cased wellbore to evaluate present pressure conditions. Fig. 5-11B presents the Z-trend versus depth to a depth of 9110 ft. The maximum mud weight determined to reach the Homeseekers 'A' sands was 10.2 lb/gal. Fig. 5-11C clearly shows the change in shale pressure due to pressure depletion of the sands. The well was side-tracked at 8120 ft, and redrilled to 9215 ft without difficulty. A mud weight of 10.4 lb/gal was required for redrilling the well rather than the mud weight (MW) of 14.3 lb/gal used for the original drilling fluid. Plots of shale resistivity and Z-shale values versus true vertical depth (Fig. 5-12), were used to define the overpressure environment for 18 offshore Gulf Coast wells in 12 fields to establish the generalized compaction trend (Taneja and Carroll, 1985). The


I I I I I

D

E

0 t-.

o D 0 0 .Q

o

0

,.,...

D !

r,,q

9

/ 2 / /

/

I

,

/

"1- ~ ._

I

/"

~-

~

z

I ,~.~

/..,

I J

I I

I/I

] 45

9

/

/ /

/

/

J

/

/

r .......

//, .

/

9

"/

GH

GO

"~

Formation FPG, psi/ft Equivalent Mud Weight, Ib/gal

Fig. 5-13. Empirical relationship between ZT-shale ratio (Esh(observed)/Xsh(normal)) and reservoir fluid pressure gradient (FPG and equivalent mud weight requirements). GH is hydrostatic pressure gradient; Go is overburden pressure gradient; 1, 2, 3 -- empirical calibration trends established for different areas; dots represent data points obtained in a given area to establish calibration trend. (Modified after Fertl and Chilingarian, 1987, fig. 6, p. 33.)

data were replotted by Fertl and Chilingarian (1987) to highlight the similarities in the normal and overpressure environments. Quantitative pressure evaluation

Two quantitative techniques are available for using PNC logs to locate and evaluate overpressures. Technique A: empirical calibration charts

(1) Plot r - s h a l e values (either on a logarithmic or linear scale) versus depth and establish the normal compaction trendline. (2) Top of the overpressure zone is at a depth where the plotted r - v a l u e starts to diverge from the normal trend. (3) Determine the formation pressure at a specific depth as follows: (a) divergence of observed ,V-shale value from the extrapolated (normal trendline) value determines the ~7-ratio (observed Xsh/normal ZTsh); (b) from Fig. 5-13, the formation fluid pressure gradient (FPG) and equivalent mud weight corresponding to the E-ratio are found.

146

G.V. CHILINGAR, V.A. SEREBRYAKOV,S.A. KATZ AND J.O. ROBERTSON JR.

DE

ql-. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

B

i ~

cO.

PressureTop

a

DA

A

E-Shale Parameter Fig. 5-14. Schematic illustrating the equivalent depth method. (Modified after Fertl and Chilingarian, 1987, fig. 7, p. 33.)

(4) The FPG value is multiplied by the subject depth, i.e., true vertical depth, to obtain the formation pressure.

Method B: equivalent depth method The equivalent depth method is based on a mathematical relationship, which is valid for all logging parameters and includes the following steps. (1) Plot S-shale values and establish the normal compaction trendline. (2) Determine the formation pressure such as (Fig. 5-14): pf-

Go.

DA

--

D E ( G o - GH)

- - DA - - 0 . 5 3 5 D E

(5-22)

where pt is formation pore pressure in psi, DA is depth of interest in overpressured interval in ft, DE is normal, equivalent depth in ft, corresponding to DA, GIj is hydrostatic pressure gradient in psi/ft, and G0 is overburden pressure gradient in psi/ft.

SHALE WATER I N F L U X -

DRIVING MECHANISM

The influx of overpressured shale water into the associated reservoir sands has been discussed by many authors (e.g., see Rieke and Chilingarian, 1974, pp. 270-272). Mathematical model studies suggest a varying pore pressure gradient in overpressured shale sections, with the highest excess pressure being located near the center of massive shales. Less excessive pressure is found in the vicinity of permeable zones, such as sands and sandstones. This concept is supported by field observations of Fertl and Chilingarian (1987): freshening of produced water with time in thick sand-shale sequences due to the influx of fresher shale water into the sands.

147

METHODS OF ESTIMATING AND PREDICTING ABNORMAL FORMATIONPRESSURES

IES 1964 I

NLL 1967 |

NLL 1968

40

30

20

i

i

,

40

30

20

J

Fig. 5-15. PNC logs run several years following the completion of a high-pressured Louisiana well, which showed effects of pressure depletion. (After Fertl and Timko, 1970.) The increase in E-values in the pay section is due to increased water saturations caused by production. The 2S decrease in shale A apparently was caused by increased compaction and decreased porosity. A represents shale adjacent to permeable sand, and B, shale distant to the permeable sand.

Shale water depletion was diagnosed over comparatively short periods of time in an overpressured south Louisiana well (Fig. 5-15). Two PNC logs had been run a year apart to monitor hydrocarbon saturation changes in the pay zone which was being produced in several adjacent wells. The r - v a l u e changes in the pay sand were caused by the increase in water saturation. There were also changes in the adjacent shales. Zone A, the shale next to the pay, showed a marked Z-decrease as a result of increased compaction and porosity decrease. This suggests the influx of shale water into the sand. In Zone B, the portion of the shale some distance from the permeable sand shows considerably less, if any, variations in S-value as a result of pressure drawdown (Fertl and Timko, 1970).

VARIOUS GEOPHYSICAL W E L L LOGGING METHODS - - A SUMMARY

Various well logging methods significantly aid engineering planning even though short, multiple intervals may have to be logged. Several types of logs measuring electric, acoustic, and nuclear properties of formations can be used. These parameters are plotted versus depth and trendlines are then established for normal compaction. Interpreting such plots depends on their departure from the normal trend. The equivalent depth method (Fertl, 1976) and/or empirical calibration charts can be used in quantitative pressure evaluations for a specific formation, area, or geologic region. Possible pitfalls and constraints to fully utilize the potential of well logs must be recognized (see Table 5-2). Vertical formation pressure profiles obtained from the wireline multiple formation pressure tester is an important tool for improved determination of reservoir pressure and fluid distribution (Gunter and Moore, 1986). These wireline testers can record an

148


unlimited number of precise and accurate pressure measurements during a single trip into the borehole. Applications include: (1) the analysis of naturally fractured reservoirs; (2) pulse testing techniques to establish reservoir continuity; (3) qualitative estimation of permeability in low-permeability formations; (4) reservoir management in producing fields; (5) detection of fluid interfaces from vertical pressure profiles; and (6) verification (calibration) of other overpressure indicators.

CONCLUSIONS

Two groups of quantitative methods for the analysis and prediction of abnormally high and abnormally low formation pressure zones were described. The methods of the first group are based on general geologic and tectonic information and may be used prior to drilling. The methods of the second group are based on the use of geological, geophysical and drilling-related information accumulated in the process of drilling. Using equations of a general form, zones of abnormal pressure can be located using resistivity, density, sonic time travel, gamma-rays and neutron-gamma logs. In these methods, almost all log responses, except radioactivity in the abnormally high pressured zones, are related to porosity. A decrease in natural radioactivity in the abnormally high pressured zones is related to a decrease in 4~ content in the regions with nonequilibrium compaction. The following conclusions have been reached by Fertl and Chilingarian (1987): (1) Industry-wide experience shows that costly misinterpretations are best avoided by studying a combination of several pressure indicators. Not all of them, however, can always be used or are necessarily needed in any one drilling application. (2) Pulsed neutron capture (PNC) logs can be used to detect and quantitatively evaluate the overpressure environments. (3) Empirical correlations between r - s h a l e values as a function of the true vertical depth and magnitude of formation fluid pressure gradients and/or equivalent mud weight requirements can be established for a given geological area. (4) Provided Z-derived normal compaction trendlines can be easily derived, the equivalent depth method allows reliable quantitative formation pressure estimates. (5) PNC logs allow the monitoring of short- and long-term pressure depletion of, and concurrent shale water influx into, hydrocarbon-bearing reservoirs.

BIBLIOGRAPHY Alexandrov, B., 1987. Abnormally High Formation Pressures in Oil and Gas Basins. Nedra, Moscow, 215 PP. Blokh, A., 1969. Water Structure and Geological Processes. Nedra, Moscow, 216 pp. Chilingarian, G.V. and Vorabutr, P., 1981. Drilling and Drilling Fluids. Developments in Petroleum Science, 11. Elsevier, Amsterdam, 767 pp. Daniel, W.L. and Fertl, W.H., 1984. Logging high-angle, long-reach boreholes. Oil Gas J., Dec.: 103-108. Dellinger, T.B., Graveley, W., Tolle, G.C. and Sexton, T.H., 1983. Field testing to extend reach of directional wells. Oil Gas Eur. Mag., 9(2): 14-16.

METHODS OF ESTIMATINGAND PREDICTINGABNORMALFORMATIONPRESSURES

149

Dobrynin, V. and Serebryakov, V.A., 1978. Methods for Prediction of Abnormally-High Formation Pressure. Nedra, Moscow, 231 pp. Dobrynin, V. and Serebryakov, V.A., 1989. Geological-Geophysical Methods for Prediction of Pressure Anomalies. Nedra, Moscow, 288 pp. Dobrynin, V., Rapoport, M. and Serebryakov, V.A., 1979. Prediction of anomalously-high interval pressures from seismic data. Int. Geol. Rev., 21(5). Dobrynin, V., Serebryakov, V. and Srebrodol'skiy, A., 1982. Determination of abnormally-high formation pressure in shale using the method of compressional curves. Geol. Nefti Gaza, 5: 25-28. Fertl, W.H., 1976. Abnormal Formation Pressures. Elsevier, Amsterdam, 385 pp. Fertl, W.H. and Chilingarian, G.V., 1977. Importance of abnormal formation pressures to the oil industry. Paper SPE 5946 presented at the Spring Meeting of the European Society of Petroleum Engineers of AIME, Amsterdam; also J. Pet. Technol., 29(4): 347-354. Fertl, W.H. and Chilingarian, G.V., 1987. Abnormal formation pressures and their detection by pulsed neutron capture logs. J. Pet. Sci. Eng., 1(1): 23-38. Fertl, W.H. and Sahay, B., 1984. Occurrence of high-pressure formations on and off India. Oil Gas J., 82(32): 81-86. Fertl, W.H. and Timko, D.J., 1970. How abnormal pressure detection techniques are applied. Oil Gas J., 68(2): 62-71. Fertl, W.H. and Timko, D.J., 1971. Parameters for identification of overpressure formations. Paper SPE 3223 presented at the 5th Conference on Drilling and Rock Mechanics, Society of Petroleum Engineers of AIME, Univ. Texas, Austin, TX. Foster, J.B. and Whalen, H.E., 1966. Estimation of formation pressures from electrical survey offshore Louisiana. J. Pet. Technol., 18(2): 166-171. Gunter, J.M. and Moore, C.V., 1986. Improved use of wireline testers for reservoir evaluation. Paper SPE 14063 presented at the International Meeting of Petroleum Engineers, Beijing, March 17-20, 1986. Hottman, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., 17: 717-725. Nyein, R.K., MacLean, L. and Warris, B.J., 1977. Occurrence, prediction and control of geopressures on the northwest shelf of Australia. Aust. Pet. Explor. Assoc., 17(1): 64-72. Randall, R.R., Fertl, W.H. and Hopkinson, E.C., 1983. Time derived Sigma for pulsed neutron capture logging. J. Pet. Technol., 35(6): 1187-1191. Randall, R.R., Lawrence, T.D., Frost, E. and Fertl, W.H., 1985. PDK-100 log examples in the Gulf Coast. Trans., SPWLA, Paper XX. Rieke, H.H., III and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. Developments in Sedimentology, 16. Elsevier, Amsterdam, 424 pp. Schaar, G., 1985. The occurrence of hydrocarbons in overpressured reservoirs of the Baram Delta, offshore Sarawak, Malaysia. Proc. Indonesian Pet. Assoc., Fifth Annu. Convention, June, pp. 163-169. Schultz, W.E., Smith, H.D., Verbout, J.L., Bridges, J.R. and Garcia, G.H., 1983. Experimental basis for a new borehole corrected pulsed neutron capture logging system (TMD). Trans., SPWLA, Paper DD. Serebryakov, V. and Chilingar, G., 1994. Investigation of underpressured reservoirs in the Powder River Basin, Wyoming and Montana. J. Pet. Sci. Eng., 11: 249-259. Serebryakov, V., Chilingar, G.V. and Katz, S.A., 1995. Methods of estimating and predicting abnormal formation pressures. J. Pet. Sci. Eng., 13(2): 113-123. Serpas, C.J., Wichmann, EA., Fertl, W.H., DeVries, M.R. and Randall, R.R., 1977. The dual detector neutron lifetime log - - theory and practical applications. Trans., SPWLA, Paper CC. Smith, S.W., 1978. The use and validity of pulsed neutron surveys in current drilling tests. Trans., SPWLA, Paper H. Starostin, V., 1985. Estimation and Prediction of Abnormally High Formation (Pore) Pressure Using Geological-Geophysical data in the Dniepr-Donets Depression. Ph.D. thesis, MINKhiGP, Moscow. Taneja, EK. and Carroll, J.E, 1985. Abnormal pressure detection using a pulsed neutron log. Trans., SPWLA, Paper MM. Timko, D.J. and Fertl, W.H., 1971. Relationship between hydrocarbon accumulation and geopressure and its economic significance. J. Pet. Technol., 23(8): 923-931.

150


Vassoevich, M., 1960. Experiment to build typical gravitational curve of the shale deposits compaction. Nov. Neft. Tekh., 4: 11-15. Wahl, J.S., Nelligan, W.B., Frentrop, A.H., Johnston, C.W. and Schwartz, R.J., 1970. The thermal neutron decay time log. J. Pet. Technol., 22(12): 365-380. Weller, J.M., 1959. Compaction of sediments. Bull. Am. Assoc. Pet. Geol., 43(2): 273-310. Youmans, A.H., Hopkinson, E.C., Bergan, R.A. and Oshry, H.I., 1964. Neutron lifetime log, a new nuclear log. J. Pet. Technol., 16(3): 319-329. Zoeller, W., 1984. Determine pore pressures from MWD gamma ray logs. World Oil, 3: 97-102.

151

Chapter 6

DRILLING PARAMETERS

W.H. FERTL, G.V. CHILINGARand J.O. ROBERTSONJR.

DRILLING RATE (PENETRATION) Drilling rate is a function of weight on the bit, rotary speed, bit type and size, hydraulics, bottom-hole cleaning properties of drilling fluid, and formation characteristics. Under controlled conditions of constant bit weight, rotary speed, bit type, and hydraulics, the drilling rate in shales decreases uniformly with depth. This is due to increase in degree of compaction of shales with depth; however, in pressure transition zones and highly overpressured zones the penetration rate often increases. Slower penetration rate is frequently observed in the sealing pressure barrier (caprock) overlying this transition zone. Any other major lithological changes in the shales (silty and/or limey shales, mudstones, etc.) will also cause penetration rate variations. Penetration rate should be plotted at proper depth increments (5- to 10-ft increments in slow-drilling formations or in 30- to 50-ft increments in fast-drilling intervals). Plotting such data points, however, should not lag too much behind the total drilling depth (not more than twice the plotted depth increment behind the total well depth reached by the bit). Drilling rate recorders automatically plot rate in feet per hour versus depth. Simple rules of thumb, such as the one proposed by Forgotson (1969) that a twofold penetration rate increase indicates the onset of overpressures, do not always apply. For example, an increase in mud weight to 12 lb/gal upon encountering the transition zone, may partially mask any further pressure increase with depth. It is also of interest to note that the first unit of mud weight (lb/gal) in excess of formation pore pressure will reduce the drilling rate more than each subsequent unit of mud weight (lb/gal) increase (Moore, 1974). Complications may also arise during bit drilling, which may mask any penetration rate change due to overpressure. Penetration rate may even decrease due to fluctuating rotary torque and erratic action of the drill bit on the bottom of the borehole.

Normalized rate of penetration (d-exponent) Inasmuch as it is not always possible and/or feasible to maintain the bit weight and rotary speed constant, the concept of the d-exponent was developed by Jorden and Shirley (1966). Data required to calculate the d-exponent, a dimensionless number, are the penetration rate (R, in ft/h), bit size (diameter D, in inches), weight on bit (W, in

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II

B

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Fig. 6-1. Plotting the dc-exponent on a logarithmic scale using the mud weight overlay technique in South Texas (A,D), South Louisiana (B) and Oklahoma (C). (After Zamora, 1972, fig. 2, p. 70. In Chilingarian and Vorabutr, 1981, fig. 16-5, p. 588.) Note effect of bit size change (from 8 1/2 inches to 6 1/2 inches) on normal trendline in the South Texas well (D). Trendlines represent constant mud specific weights. (Courtesy of Oil and Gas Journal.)

lb), and rotary speed (N, in rpm):

log(R/6ON) d - log(12W/lO6D)

(6-1)

Basically, plots of d-exponent versus depth show a decreasing trend with depth. In transition zones and overpressured environments, in many cases the calculated values diverge from the normal trend to lower than normal values. Quantitative pressure evaluation can then be made on using the equivalent depth method (Fertl, 1976, p. 123) or specially constructed, transparent overlay of parallel, equivalent mud weight lines for the specific depth scale used for the d-exponent (see Fig. 6-1). The values of the d-exponent are affected by any change in the basic input parameters in Eq. 6-1. Furthermore, it is often difficult to establish reasonable values for bit weight in soft formations. Any major lithologic change in the shale section (e.g., limey or silty shales, mudstones, and marls) will also affect the d-exponent. The same is true in poorly maintained drilling fluid systems and for drastic changes in mud weight. Inasmuch as Eq. 6-1 ignores the direct effect of mud weight on drilling rate, a modification of the d-exponent has been proposed by Harper (1969) to normalize the d-exponent for the effective mud weight as follows: MW1 dc -- d . MW2 (6-2) where dc is modified (corrected) d-exponent, MW1 is normal mud weight, and MW2 is actual mud weight used.

0[

DRILLINGPARAMETERS

153 A

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Fig. 6-2. Comparison plots of depth versus d-exponent and de-exponent in the same well. Protective casing seat is at a depth of 8700 ft. Note that the de-exponent more clearly defines the overpressured zone. (Modified after Fertl, 1976, fig. 4-6, p. 125. In Chilingarian and Vorabutr, 1981, fig. 16-2, p. 586; Courtesy of Oil and Gas Journal.)

Consequently, de-plots represent a substantial improvement over d-plots because mud weight effects are considered (Figs. 6-2-6-4). They are used by the industry worldwide, both on- and offshore. Quantitative pressure methods include (1) the equivalent depth method, (2) transparent overlays of parallel equivalent trend lines for mud weight or pore fluid pressures (Fig. 6-1), or (3) a specially designed de-slide rule. Drilling information is normally used in elastic sediments for calculating the de-exponent. In several areas, in drilling through mixed lithologies (i.e., sands, shales, limestones, and dolomites) such computations often give good results. Frequency of calculating the d~-exponent depends on how fast formations are being drilled. Usually, the d~-exponent is determined for every 10 ft of increment in depth. In fast drilling areas, 25-, 50-, or even 100-ft depth increments may be adequate, whereas in slow-drilling areas, i.e., hard-rock intervals, 5-ft depth intervals may become necessary. The mathematical relationships shown in Eqs. 6-1 and 6-2 clearly indicate the effects of drilling variables on d~-values. Effects of hydraulics, weight on bit, bit size and type, and overbalance in the case of drilling through soft, elastic formations are discussed below.

Effect of drilling hydraulics The equations for d- and de-exponents are based on the assumption that drill cuttings are being effectively removed. In most wells drilled in the mid 1960s, transition zones were encountered at moderate depths, i.e., 8000 ft or slightly deeper, and hydraulics programs were usually adequate. Minor fluctuations in circulation rate did not significantly affect the penetration rate.

154

W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSONJR. -6

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ACTUAL MUD WEIGHT, Ib/gal Fig. 6-3. Comparison of plots of depth versus d-exponent and de-exponent based on drill bit data, Louisiana well, U.S.A. (Modified after Fontenot and Berry, 1975, fig. 3, p. 127. In Chilingarian and Vorabutr, 1981, fig. 16-3, p. 587" Courtesy of Oil and Gas Journal.)

Drilling in areas where overpressured zones are encountered in shallow, unconsolidated elastic formations, indicates the increased importance of proper hydraulics programs in achieving effective penetration rates in these soft formations. The latter are drilled utilizing a combination of tooth cutting and jetting action. As a result, increased jetting action will increase penetration rate which, in turn, will result in decreasing values of the de-exponent. This gives an appearance of a non-existent transition zone. Furthermore, maintaining a constant circulating rate when a transition zone is anticipated in unconsolidated sediments will minimize effects of hydraulics. Transition zones at depths as shallow as 1500 ft have been successfully defined by .~ontrolled drilling conditions (i.e., maintaining constant bit weight, rotary speed, mud weight, and circulation rate). The fast penetration rate may be measured even by timing with a stop watch the drill joints lowered during drilling.

DRILLING PARAMETERS

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Effect of drill bits When button and diamond bits are used instead of standard rock bits, an empirical correction is required, i.e., a 1-inch reduction in the bit diameter is used in calculations. Reliability of this concept in actual field applications, however, is debatable. There is a decrease in dc-values when a button or diamond bit is used. It should be assumed that, at the point of a bit change, the first shale layer drilled with the button or diamond bit has the same pore pressure as the last shale layer drilled with a rock bit. Hence, a shift of the normal compaction trend line in the de-versus-depth plot is required to account for the change in bit type. This shift is similar to the one required due to the change in bit size. The effect of bit size change is shown in Fig. 6-1. Consequently, trendline shifts become necessary when the (weight-on-bit)/(bit size) ratio is significantly changed, regardless of the type of the bit.

156


Bit wear will cause a decrease in penetration rate and, thus, an increase in the dc-exponent. Consequently, dull bits can mask the presence of a transition zone. Consideration of bit wear in graphical and computerized techniques will eliminate this limitation. An alternative solution is to study the offset well data and previous bit performance in order to determine when to pull a bit prior to drilling through transition zones. Although this approach may result in an additional trip, it will greatly reduce the hazards of a well kick and time required to kill it, or even of a blowout, should the downhole mechanical problems occur.

Overbalance The dc-exponent is also affected by the difference between hydrostatic pressure of the mud column and formation pressure (i.e., amount of overbalance). A linear, instead of the required hyperbolic, correction will introduce a serious error into calculations with increasing overbalance. In other words, arbitrary and 'emotional' mud weight increases should be avoided. Knowledge of formation pressure while drilling is important for achieving safe and economic operations and in the selection of proper casing seats. The dc-exponent, supplemented with several other pressure indicators, provides the drilling engineer with the required information for making proper decisions.

D R I L L I N G RATE E Q U A T I O N S

The application of proper drilling rate equations in order to establish correlations between the formation and borehole pressures requires instrumentation at the rig site to record simultaneously several drilling parameters. For example, a general equation for penetration rate in shales has been developed by Combs (1968) using data from six Louisiana wells in a regression-type analysis. Combs' correlation shows that penetration rate (R) is proportional to the weight on the bit (W), rotary speed (N), and bit hydraulics, each raised to a fixed power:

R - Ro ~

-~

31~D,

f (Po)f (T)

(6-3)

where Dh is borehole diameter (inches), Dn is bit nozzle diameter (inches), f is function and n3 is weight, speed and hydraulics exponents, respectively; Combs' recommendations: nl - 1.0, n2 = 0 . 6 , n3 -- 3; N is rotary speed (rpm), Q is flow rate (gal/min), Pa is differential pressure (lb gal -l 1000 ft-I), R is penetration rate (ft/h), R0 is shale drillability with sharp bit at zero differential pressure (ft/h), T is bit wear index-equivalent rotating index, and W is weight on bit (in 1000 lb). According to Combs (1968), penetration can be predicted from Eq. 6-3 with a standard deviation of approximately 30%, whereas pore pressure can be predicted with a standard deviation of about 1.0 lb/gal equivalent pore pressure. In connection with computerized drilling control, Young (1968) expressed penetration of, n l, n2

DRILLINGPARAMETERS

157

rate as follows:

R=GNm(W-Wf)K

(6-4)

where a reciprocal drilling constant (K), the weight intercept value (Wf), and the bit rotary speed exponent (m) are determined by a five-spot drilling test. G is a function of the normalized bit tooth height. Drilling performance optimization and identification of overpressured formations have been also investigated by Wardlaw (1969). Several other empirical equations for drilling rate determination have been developed by different investigators. Consequently, field data from (1) previously drilled adjacent wells, and/or (2) feedback data from short-interval testing in the subject well are usually needed in order to determine input parameters. Unfortunately, drilling rates change with lithologic variations, even though the pressure gradient remains constant. Deviated holes, severe dog legs, drilling from floating vessels, and frequently occurring water-sensitive and sloughing shales can make these indicators questionable. Development of fully automated pressure-detection techniques is difficult, except for local geographic areas where the lithology is well known. Other pressure indicators, such as chemistry of produced water, drilling mud properties, density of formation cuttings, and wireline and related tools must still be used meticulously.

POROSITY AND FORMATIONPRESSURELOGS Several models establish the relationship between the formation characteristics and drilling parameters, and provide an early indication of formation type and porosity and pore pressure variations (Zoeller, 1970; Boone, 1972). Several service companies have made similar 'data units' commercially available, and many oil companies and drilling contractors have developed their own drilling program models. For example, a field example of formation porosity and pressure logs in an offshore Louisiana wildcat (U.S.A.) is shown in Fig. 6-5 (Fertl, 1976, p. 131). There is a 9g5 inch casing seat at a depth of 14,401 ft, which is followed by a fast pressure increase over the next 600 ft. Bourgoyne (1971) proposed a general equation relating various controllable drilling variables and drilling performance, which can be expressed as follows:

R = K . f l ( W / D ) , f2(N)- f 3 ( H ) , f4(Ap)

(6-5)

where R is rate of penetration (ROP); K is drillability constant or normalized ROP; fl (W/D) is a function describing the effect of bit weight, W, per inch of bit diameter, D, on ROP; fz(N) is a function defining the effect of rotary speed, N, on ROP; f3(H) is a function defining the effect of tooth dullness, H, on ROP; and f4(Ap) is a function defining the effect of the differential pressure across the hole, A p, on ROE Normalized penetration rate, K, is related to the bulk density by the following

15 8

W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSONJR.

5o

Porosity, %

|,,

Pore Pressure, "A" Exponent, o~8 Ib/gal 8 ~ 8 Ib/gal a J

I

I

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#27

~

Bit

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#28 #29

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Fig. 6-5. Field example of formation porosity and pore pressure logs in an offshore Louisiana wildcat well, U.S.A. The curve on the right ('A' exponent) gives the value for pore pressure taking porosity and lithology variations into account. Solid circles represent actual mud weight in borehole. (After Fertl, 1976, fig. 4-10, p. 131. In Chilingarian and Vorabutr, 1981, fig. 16-6, p. 592.)

equation: Pb--2.65--1 65(Sg+l~ 9

Sg

(6-6)

where Pb is bulk density in g/cm 3, and Sg is rock strength parameter (e.g., a value of 5.2 in the U.S. Gulf Coast area). These bulk density values are then converted to formation pseudo-porosity, which closely agrees with the calculated porosity from geophysical well logs, such as a density log. Bourgoyne (1971) developed a graphical approach for these concepts for wellsites without digital facilities.

DRILLINGPARAMETERS

159

Belotti and Gerard (1976) discussed a similar system, which was developed in Europe and was successfully tested in more than 40 wells. The system consisted of a set of sensors which acquire necessary information and transmit it to an on-site data unit, where the information is scaled, displayed, recorded and processed by the mini-computer. Storage on magnetic tape cassettes allowed playback of magnitude of overpressure, porosity, and geologic information at desired depth intervals for comparative studies with other individual pressure indicators, such as well logs. Herbert and Young (1972), using historical field data from several Louisiana Gulf Coast wells, developed equations based on regression analysis for predicting pore pressures. When the results of this analysis are applied to drilling data, the transition from normal pore pressures to overpressures can be predicted. This, however, can be done only on a geographically-regional basis. Correlations between the well log data and rock drillability have been developed by Gstalder and Raynal (1966) and E1-Hadidi (1970). Acoustic transit time data from geophysical well logs can be used to predict rock drillability, provided the lithology is known. The basic concepts of the SNAP log (Lutze et al., 1972) apply the vibrations from the tricone bit, as measured at the Kelly, to give an instantaneous log of the formation characteristics while it is being drilled.

LOGGING WHILE DRILLING Methods have been developed for recording the formation, mud, and bit data at the bottom of the borehole, and then transmitting these data to the surface. The great need for the development of additional energy resources and ever-increasing costs of drilling and exploration, created an incentive for developing methods providing downhole real-time measurements. Proposed methods and granted patents are numerous. Logging-while-drilling measurement systems essentially perform only two basic functions: (1) recording of the desired parameters at the bottom of the wellbore, and (2) data transmission to the surface. Downhole measurements comprise: (1) well control information, (2) directional drilling control, (3) drilling optimization, and (4) formation evaluation. Many different logging-while-drilling systems have been developed. Basically, there are four different types of data telemetry: (1) mud-pressure pulses, (2) insulated conductor or cable, (3) electromagnetic methods, and (4) acoustic methods.

TORQUE Torque variations are continually monitored at the drilling rigs. Torque usually increases gradually with depth due to increased wall-to-wall contact of drillpipe and wellbore. In the presence of underbalance (i.e., negative differential pressure), overpressured shales tend to flow or heave into the borehole. Hence, a drastic increase in torque may serve as an additional pressure indicator.

160


DRAG

Drag is defined as the excess in hook load over the free handling load. Drastic increase in drag may signal the presence of an overpressured formation. In the presence of a gradual pore pressure increase, however, as in very long transition zones or in the case of drilling from floating vessels, this pressure indicator becomes questionable. Furthermore, increase in drag may be caused by bit balling, severe dog legs, deviated holes, differential sticking, and extra volume of cuttings influx into the wellbore while drilling through transition zones.

DRILLING MUD PARAMETERS

Mud-gas cutting Mud logging aids in formation evaluation and detection of overpressured zones. As early as 1945, the use of mud-gas logging was recommended as an overpressure indicator and as a warning of impending blowouts (Pixler, 1945). Similarly, Rochon (1968) proposed mud-gas anomalies as an aid in controlling drilling mud hydrostatic head-pore pressure relationships. If formation permeabilities are extremely low, the degree of gas cutting can be roughly correlated with the amount of underbalance (Goldsmith, 1972). Generally speaking, however, mud-gas cutting may or may not be directly related to the increased formation pressures, because it is greatly affected by the geological environment penetrated and the drilling techniques used in the subject well (Fertl, 1973; Daw et al., 1977). Several factors which may affect mud-gas logs and, thus, complicate their use for pressure detection include (Fertl, 1973): (1) potential pay zones, (2) connection gas, (3) Kelly air, (4) downtime, (5) gas composition, (6) presence of lignite and (7) coal seams, (8) degradation of mud additives, (9) gas flushing, (10) volcanic material, (11) deep-seated mud volcanoes, (12) faults, (13) shale gas, (14) thermodynamic processes, and (15) recycled gas. Equipment for gas detection and analysis of gas is readily available.

Flowline specific weight of drilling fluids Reduction in the specific weight of the drilling fluid at the mud flowline can be used as an additional indicator for gas cutting and the possible presence of overpressured formations. Consequently, continuous mud weight indicators have become an integral part of many on-site data collection and analysis units. Issenmann and Lucon (1971) discussed a continuous mud weight recorder, which basically consists of a constant-height column through which mud from the wellhead outlet is circulated by a special pump at a constant flow rate. The weight of the mud is measured by a pressure gauge located at the bottom of the column and then transmitted to a recorder. Another high-resolution drilling fluid monitor system, which consists of pressure and density sensors, has been developed by Goddard et al. (1973). The measurements are

DRILLINGPARAMETERS

161

based on the principle that the degree of absorption of gamma rays by a material is a function of the density of that material. With proper calibration, radioactive densometers provide density measurements with an accuracy of +0.1 lb/gal for muds in the 7-20 lb/gal specific weight range. Pressure kicks

Balanced drilling techniques require a very narrow margin between the effective pressure control and threatened blowout. Differential pressures are frequently reduced considerably below 500 psi. Improper pressure balance, therefore, may cause well kicks, which can be a direct indication of the presence of overpressured formations. Whereas pressure kicks have occurred at pressure differentials as high as 9 lb/gal, the control of most kicks requires less than 2 lb/gal mud weight increase. Pressure kicks in high-pressure wells are influenced by the following factors: (1) difference between pressure due to the hydrostatic mud-column weight and formation pressure; (2) thermodynamic behavior of the gas; (3) interaction of gas with drilling fluids (especially oil-base); (4) downhole pressures and temperatures; and (5) time required for the circulation of mud (which is a function of depth) and recording of the transmitted pressures. Further considerations include: (a) well location, including onshore and offshore remote areas; (b) deep-water drilling; and (c) pressure kicks associated with drilling shallow surface holes and zones below the protection pipe. Excellent discussions and detailed reviews of well control methods are available in the literature. The articles by O'Brien and Goins (1960), Goins and O'Brien (1962), Goins (1968, 1969), Rehm (1969), Moore (1974), West (1976), Bourgoyne (1976), Nance (1977) and Adams (1977) are notable examples. In general, however, proper pressure control requires installation of blowout preventor valves, adjustable surface chokes, accurate and reliable pressure reading equipment, gas separators, and drilling and mud analysis equipment. In addition, the presence of trained rig personnel, with a sound understanding of the basic concepts involved and having a planned control program to meet any emergency, is of utmost importance. Flowline temperature

In a pressure transition zone, the formation pressure increases with depth at a rate above the normal one. The same appears to hold true for the rate of formation temperature increase with depth. Inasmuch as heat conductivity varies with rock and fluid characteristics of subsurface formations, overpressured, high-porosity shales act as 'thermal barriers', thereby locally increasing the geothermal gradient (Jones, 1968; Fertl and Timko, 1970). Lewis and Rose (1970) proposed a mathematical model relating overpressures and high formation temperatures, which is based upon basic heat flow considerations (Guyod, 1946). Changes in flowline temperature gradients of up to 10~ ft have been observed prior to and/or when entering overpressured intervals. This pressure indicator, however, is also affected by the lithology, circulation and penetration rates, tripping the drillstring for bit change, long risers in deep-water drilling, and drilling through permafrost

162

W.H. FERTL, G.V. CHILINGAR AND J.O. ROBERTSONJR.

2

-

4

-

i

AHFP top fro

6

0 0 0

8

r

lo

~-~

sonic log ~

i

c~

~, 12

-

Max. temp.

mud 14

weight

Q~

= 7 3 7 0 psi

i1~

= 14.7 Ib/gal

Kick

-

mud

weight

from

11.3 to 14.5 Ib/gal

ranged

16

18

= 167~

P = 17,000 x 0.433 G = 0.767

I

t 40

,

I I,i 60 80 100

Ats~, l~sec/ft

,

I 100

I iI

i~ Equivalent temperature for i. normal conditions at 1 7,000 ft. d I 200

I 300

Temperature, ~

, 2

,

I 4

.

t 6

.

I 8

. .I 1/0

Formation Pressure, 1000 psi

Fig. 6-6. Use of quantitative pressure evaluation using flowline temperature data in a Texas wildcat, U.S.A. For comparison, an acoustic plot and pore pressure variations with depth are presented. Casing seats are also shown. G = geostatic pressure gradient in psi/ft; A H F P = abnormal formation pressure; and M W = specific weight of drilling mud in lb/gal. (After Fertl, 1976, fig. 4-10, p. 131. In Chilingarian and Vorabutr, 1981, fig. 16-7, p. 596).

intervals. Thus, certain precautions and refinements are required in use and interpretation of temperature gradients (Wilson and Bush, 1973) when plotting flowline temperatures, including (1) use of temperature readings (points) of each drill bit run, (2) replotting segments of individual bit runs end-to-end without regard to actual temperature values, and (3) use of inlet and outlet flowline temperatures. The possible application of the flowline temperature data as a semiquantitative pressure indicator in a Texas wildcat has been illustrated by Fertl (1976, pp. 146-147). Fig. 6-6 shows a similar, or at least complementary, evaluation of both acoustic log and flowline temperature data in this well. Resistivity, chloride ion content, and other methods

Relationship between the salinity of formation waters and formation pressure variations in consolidated and unconsolidated rocks has been discussed by Chilingarian and Rieke (1968), Chilingar et al. (1969), Overton and Timko (1969), and Fertl and Timko

DRILLINGPARAMETERS

163

(1970). The increase or decrease in the chloride content of the drilling mud between the inlet and outlet of the mud stream can be related to the drilling and pressure conditions. In addition, the drilling rig data gathering units enable measuring and recording both inlet and flowline drilling fluid resistivities. Other techniques, such as variations in the contents of specific ions, redox and pH measurements on the drilling mud stream, and various physical and chemical analyses of drill cuttings, have been investigated by Fertl and Timko (1973a,b).

Pit level and total pit volume Pit level indicators, which monitor variations in the total mud volume, may show mud-volume reduction caused by lost circulation or increase in mud volume due to the fluid entry into the wellbore as a result of unexpected high formation pressures. An ultrasonic equipment exists to measure accurately drilling fluid levels in mud tanks without having any contact with the mud (Dupin de Saint Cyr, 1973). Hence, this method is particularly effective on floating, deep-water offshore drilling figs.

Hole fill-up If the drillstring is pulled, the mud volume needed to fill the borehole should be equal to the displaced pipe volume. Keeping the hole full is especially critical at the time when drill collars are pulled, because on pulling the same length of collars as that of the drillpipe, the level of drilling mud in the borehole will fall four to five times as fast. Furthermore, if salt water, oil, or gas from the formation enters the well, the mud volume required to fill the borehole will be less than the displaced volume of the pipe pulled out. Consequently, this gives the first indication of a pressure kick. Measurement of mud volume used to fill the borehole can be checked from changes in the pit mud level.

Mud flow rate Flow rate measurements are superior to pit level checks, because even small flows can be detected before they become sufficiently large to show on any pit level measuring device. More time is available, therefore, to take proper control measures.

SHALE CUTTINGS PARAMETERS

Shale bulk specific weight Bulk specific weight of drill cuttings usually increases with depth. Measurement techniques include (1) the high-pressure mercury pump technique, (2) the fluid density gradient column, and (3) the mud balance method. Care must be taken in selecting and preparing the drill cuttings for analysis. Multiple cuttings samples have to be tested due to the variance in sample data. The average bulk specific weight value, for a given depth,

164


is then plotted on a linear or logarithmic scale versus borehole depth, thus establishing normal compaction trend lines. Inasmuch as shale porosity commonly increases in overpressured zones, any decrease in bulk specific weight may indicate the presence of overpressured environments. Quantitative pressure evaluation is then possible by the equivalent depth method (Fertl, 1976) or from empirical curves established for a given area (Boatman, 1967). Major limitations are (1) examination of cavings and/or recirculated cuttings which constitute the contaminating part of drill cuttings being investigated, and (2) limited care taken by rigsite personnel to collect and analyze samples. Several other factors, which may greatly affect the measured bulk specific weight values of drill cuttings, include: (1) presence of shale gas which decreases the apparent bulk specific weight values; (2) presence of organic-rich shales, which results in lower bulk specific weight values; (3) lithologic variations, e.g., presence of silty or sandy shales, mudstones, and marls; variation in carbonate content of shales also affects bulk specific weight; (4) presence of heavy minerals, such as pyrite (Permian Basin, U.S.A.; offshore Cameroon, Africa; South China Sea area), siderite (South China Sea area; Mackenzie Delta, Canada), and mica (biotite and muscovite; North Sea area), will increase the bulk specific weight values; (5) age boundaries, unconformities, differential compaction, structural effects, and position within the clastic basin may affect the normal compaction trendline (Fertl, 1977).

Shale factor The shale factor can be successfully measured by the methylene blue test (Nevins and Weintritt, 1967). This shale formation factor method (Gill, 1968; Mondshine, 1969; Gill and Weintritt, 1970) may be equated with the cation exchange capacity (CEC) of solids carried by the drilling fluid out of the wellbore. This CEC value, in turn, can be related to the water-holding capacity of drill cuttings or montmorillonite content. The shale factor also appears to be a supplementary and useful indicator for the detection of impermeable pressure seals (caprocks) on top of the overpressured zones.

Volume of shale cuttings During drilling, entry into overpressured environments is characterized by an increase in the penetration rate, which gives rise to an increase in volume of cuttings over the shale shaker.

Shape and size of shale cuttings In pressure transition zones, the shape of drill cuttings is angular and sharp, rather than rounded as found in normal, hydrostatic pressure environments. Furthermore, cuttings from high-pressure formations are unusually large and splintery in appearance.

DRILLINGPARAMETERS

165

OTHER PRESSURE INDICATOR METHODS Several unconventional methods for detecting overpressured formations and, possibly, even predicting transition zones ahead of the drill bit have been investigated in detail by Fertl and Timko (1973a,b). These m e t h o d s include: (1) shale cuttings resistivity, (2) filtration rate of shale slurry; (3) filtrate (shale water) color; (4) shale cuttings moisture index; (5) litho-function plots; (6) bicarbonate content of shale slurry filtrate; (7) redox and pH potential m e a s u r e m e n t s ; (8) distribution of specific ions in shale slurry filtrates.

DRILLING CONCEPTS IN OVERPRESSURED ENVIRONMENTS M a x i m u m well control and m i n i m u m cost are key factors in present-day drilling operations. To achieve this, a basic understanding of two key formation pressures, i.e., formation pore pressure and fracture pressure, is a prerequisite. This aspect has been discussed in detail by Chilingarian and Vorabutr (1981).

BIBLIOGRAPHY Adams, N., 1977. Deep waters pose unique well kick problems. Pet. Eng., 49(5): 25-36. Belotti, E and Gerard, R.E., 1976. Instantaneous log indicates porosity and pore pressure. World Oil, 183(5): 90-94. Boatman, W.A., 1967. Shale density key to safer, faster drilling. World Oil, 165(2): 69-74; also J. Pet. Technol., 19: 1423-1431. Boone, D.E., 1972. Porosity and pressure log performs well in the North Sea. Pet. Eng., 48(5): 122-218. Bourgoyne, A.T., 1971. A graphical approach to kick severity calculations. Pet. Eng., 48(9): 22-28. Bourgoyne, A.T., 1976. Drilling strength analysis in evaporites. Pet. Eng., 48(9): 22-28. Chilingarian, G.V. and Rieke III, H.H., 1968. Data on consolidation of fine-grained sediments. J. Sediment. Petrol., 38(3): 811-816. Chilingarian, G.V. and Vorabutr, E, 1981. Drilling and Drilling Fluids. Developments in Petroleum Science, 11, Elsevier, Amsterdam, 767 pp. Chilingar, G.V., Rieke III, H.H., Sawabini, S.T. and Ershaghi, I., 1969. Chemistry of Interstitial Solutions in Shales Versus that in Associated Sandstones. 44th Annu. Fall Meet., Soc. Pet. Eng., AIME, Denver, CO, SPE 2527, 18 pp. Combs, G.E, 1968. Prediction of Pore Pressure from Penetration Rate. 43rd Annu. Fall Meet., Soc. Pet. Eng., AIME, Houston, TX, SPE 2162, 16 pp. Daw, R.N., Myers, D.L. and Mercer, R.F., 1977. Mud gas logs help predict mud pit levels on floaters. World Oil, 177(7): 57-58. Dupin de Saint Cyr, E, 1973. Ultrasonic device monitors mud pit levels on floaters. World Oil, 177(7): 57-58. E1-Hadidi, S., 1970. Use of Well Logging Data for Predicting of Rock Drillability. M.S. Thesis, Univ. California, Berkeley, CA, 90 pp. Fertl, W.H., 1973. What to remember when interpretating mud-gas cutting. World Oil, 177(4): 67-72. Fertl, W.H., 1976. Abnormal Formation Pressures, Implications to Exploration, Drilling and Production of Oil and Gas Resources. Elsevier, Amsterdam, 382 pp. Fertl, W.H., 1977. Shale density studies and their application. In: G.D. Hobson (Ed.), Developments in Petroleum Geology. Applied Science Publishers, Barking, Essex, pp. 293-327. Fertl, W.H. and Timko, D.J., 1970. How abnormal pressure detection techniques are applied. Oil Gas J., 68(2): 62-71.

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W.H. FERTL,G.V. CHILINGARAND J.O. ROBERTSONJR.

Fertl, W.H. and Timko, D.J., 1973a. How downhole temperatures, pressures affect drilling, Part 9. World Oil, 176(2): 47-51. Fertl, W.H. and Timko, D.J., 1973b. How downhole temperatures, pressures affect drilling, Part 10. World Oil, 176(4): 62-66. Forgotson, J.M., 1969. Indication of proximity of high pressure fluid reservoir, Lousiaa and Texas Gulf Coast. Bull. Am. Assoc. Pet. Geol., 53: 171-173. Gill, J.A., 1968. Applied drilling technology, an engineered package for pressure detection and control. Drilling Contractor, Mar/Apr: 128-140. Gill, J.A. and Weintritt, D.J., 1970. Shale Factor: a Diagnostic Tool for Formation Logging. 1lth Prof. Well Log Analysts Symp., Los Angeles, CA, 11 pp. Goddard, R.D., Guest, R.J. and Anderson, T.O., 1973. High resolution fluid measurements improve drilling. Drilling Contractor, Mar/Apr: 55-64. Goins, W.C., 1968. Guidelines for blowout prevention. World Oil, 167(4): 88-106. Goins, W.C., 1969. Blowout Prevention. Gulf Publ. Co., Houston, TX, 260 pp. Goins, W.C. and O'Brien, T.B., 1962. How to detect and control threatened blowouts. Oil Gas J., 60(42): 143-151. Goldsmith, R.C., 1972. Why gas-cut mud is not always a serious problem. World Oil, 175(5): 51-54. Gstalder, S. and Raynal, J., 1966. Measurement of some mechanical properties of rocks and their relationship to rock drillability. Trans. AIME, 237:991-996. Guyod, H., 1946. Temperature well logging. Oil Weekly, 28: 35-47. Harper, D., 1969. New Findings from Overpressured Detection Curves in Tectonically Stressed Beds. 40th Reg. Meet., Soc. Pet. Eng., AIME, Los Angeles, CA, 2781, 9 pp. Herbert, W.E. and Young, ES., 1972. Estimation of formation pressure with regression models of drilling rate. J. Pet. Technol., 24: 9-15. Issenmann, O. and Lucon, C., 1971. Present state of gas-logging techniques with use of a continuous mud weight indicator. J. Can. Pet. Technol., 12: 9- I 1. Jones, EH., 1968. Hydrodynamics of Geopressures in the Northern Gulf of Mexico Basin. 43rd Fall Meet. Soc. Pet. Eng. AIME, Houston, TX, 2207, 15 pp. Jorden, J.R. and Shirley, O.J., 1966. Application of drilling performance data to overpressured detection. J. Pet. Technol., 18:1387-1394. Lewis, C.R. and Rose, S.C., 1970. A theory relating high temperatures and overpressures. J. Pet. Technol., 22:11-16. Lutze, J., Raynard, M., Gstalder, S., Quic-aud, C., Raynal, J. and Muckleroy, J.A., 1972. Instantaneous logging based on a dynamic theory of drilling. J. Pet. Technol., 24: 750-758. Mondshine, T.C., 1969. New technique determines oil-mud salinity needs in shale drilling. Oil Gas J., 67(28): 70-75. Moore, EL., 1974. Drilling Practices Manual. The Petroleum Publ. Co., Tulsa, OK, 448 pp. Nance, G., 1977. How to calculate maximum surface pressure for floating drilling. Oil Gas J., 49(1): 46-54. Nevins, M.J. and Weintritt, D.J., 1967. Determination of cation-exchange capacity by methylene blue adsorption. Bull. Am. Ceram. Soc., 46: 587-592. O'Brien, T.B. and Goins, W.C., 1960. The mechanics of blowouts and how to control them. API Drill Prod. Prac., 27: 41-55. Overton, H.L. and Timko, D.J., 1969. The salinity principle, a tectonic stress indicator in marine sands. Log Anal., 10(6): 34-43. Pixler, B.O., 1945. Some Recent Developments in Mud Analysis Logging. Fall Meet. Soc. Pet. Eng., AIME, Houston, TX, Oct. SPE 2036, 8 pp. Rehm, W.A., 1969. Pressure control in drilling. Oil Gas J., 67(31)-68(7). Rochon, R.W., 1968. The Effect of Mud Weight in Mud Logging Gas Anomalies. Monarch Logging Co., San Antonio, TX, 12 pp. Wardlaw, H.W.R., 1969. Drilling Performance Optimization and Identification of Overpressure Formations. 4th Conf. Drilling and Rock Mechanics, Soc. Pet. Eng., AIME, University of Texas, Austin, TX, 2388, 12 PP. West, E.R., 1976. Hydraulic control of deep well blowouts. Pet. Eng., 48(5): 68-81.

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Wilson, G.J. and Bush, R.E., 1973. Pressure prediction with flow line temperature gradient. J. Pet. Technol., 25: 135-142. Young, ES., 1968. Computerized Drilling Control. 43rd Fall Meeting, Soc. Pet. Eng., AIME, Houston, TX, SPE 2241, 12 pp. Zoeller, W.A., 1970. The Drilling Porosity Log. 45th Fall Meet., Soc. Pet. Eng., AIME, Houston TX, Oct., SPE 3066, 10 pp.


169

Chapter 7

SEISMIC METHODS OF PRESSURE PREDICTION

E AMINZADEH, G.V. CHILINGAR and J.O. ROBERTSONJR.

INTRODUCTION Geophysical methods, in conjunction with other tools, can provide the means to predict reservoir pressure in many cases. Overpressured shales can act as good reservoir seals, but can also cause drilling difficulties, particularly in maintaining an adequate safety margin for the drilling mud weight. Geophysical techniques are based on the impact of reservoir pressure on the seismic velocities (primarily compressional waves). Many studies have demonstrated the effectiveness of geophysical methods for pore pressure prediction. One of the first of such studies was reported by Pennebaker (1968). Subsequently, the Society of Exploration Geophysicists published Geopressure (Dutta, 1987) that included major geophysics-related methods for overpressure prediction. With the advent of 3-D seismic and, more recently, four components and 4-D seismic, it has become possible to make pressure predictions that are more reliable and create three-dimensional pressure profiles. In general, the seismic reflections are functions of acoustic impedance (velocity times density) and are influenced by reservoir pressure. On the other hand, the type of reservoir fluid impacts sonic velocities. Shear waves and compressional waves respond differently to various reservoir fluids (and lithology) as well as reservoir pressure. These phenomena offer the following two practical applications: (1) prediction of abnormal pressure from seismic velocities before drilling; (2) mapping reservoir fluid movement and dynamic changes of reservoir pressure using time lapse (4-D seismic).

PREDICTION OF ABNORMAL PRESSURE FROM GEOPHYSICALDATA Most of the methods of predicting reservoir overpressures utilize the following phenomena: (1) lower bulk densities (thus lower seismic velocity); (2) higher porosity; (3) lower stress; (4) higher reservoir temperature. Table 7-1 shows how specific types of measurement at different stages of well development are employed to predict reservoir pressure using geophysical data. There are two major categories of approaches for predicting pore pressure and effective stress. They are based either on empirical relationships derived from statistical data and case histories or on laboratory measurements and rock physics models. In general, most methods use the seismically derived velocities as a basis for prediction. Some of the earlier work on the subject has been reported by Dutta (1987) and Fertl et al. (1994). The sonic velocities are calibrated against velocities derived from sonic

170

E AMINZADEH,G.V. CHILINGARAND J.O. ROBERTSONJR.

TABLE 7-1 Geopressure prediction techniques (adapted from Dutta, 1987) Development stage

Source of data

Pressure indicator

Prior to drilling

Surface geophysical methods (gravity and 2-D, 3-D, 3-C and seismic)

P- and S-wave velocity, density, porosity

During drilling

Drilling parameters

Penetration rate, logging MWD, seismic while drilling Mud gas cuttings, pressure kicks, flow-line temperature, pit-level, total pit volume, hole fillup, mudflow rate Bulk density, shale formation factor, volume, shape, size, % shale Drilling data

Drilling mud parameters

Shale cutting parameters Correlation between new and existing wells After drilling

Surface and subsurface geophysical data (VSP, Cross-well, 4D, 3C) Petrophysical data

P- and S-wave velocity, density, porosity, downhole gravity Sonic, resistivity, density, neutron

During testing and completion

Monitoring pore pressure variations in short zones

Repeat formation tester, drillstem test, pressure bombs, 4-D seismic

logs and petrophysical measurements. Under a normal pressure regime in the absence of hydrocarbon saturation, one would anticipate the sonic velocity to increase with depth. Any major deviation from this may be attributed to abnormal pressure or other anomalies (such as saturation with gas). How one can distinguish between these different situations is presented here. Formation pressure that deviates from hydrostatic pressure at a similar depth is considered as an abnormal pressure. Abnormal pressures are indicated by significant changes in the sonic velocity with depth. These changes of course can have different origins, such as lithology, hydrocarbon saturation, formation temperature and, finally, formation pressure. The main objective of earlier work on the use of seismic velocities for overpressure prediction concentrated on identifying sonic velocity changes without isolating the reasons for such changes (e.g., see Eaton, 1972).

EMPIRICAL RELATIONSHIPS

Many empirical formulas are based on case studies and real data which have been developed for overpressure prediction. The following are some well known relationships frequently used in the oil industry: Eaton's exponent of pore pressure determination from sonic data

Eaton's original formula (Eaton, 1972) uses the exponent relationship between pore pressure and several parameters. It does not differentiate between different lithologies or


171

depth: Pp -- Po -- (Po -- Ph)

~o

(7-1)

where pp is the predicted pore pressure, Ph is the normal hydrostatic pressure, Atn is the normal shale travel time, Ato is the observed shale travel time, and N is an experimental coefficient. This method of predicting pore pressure is based upon the assumption of sediment compaction; thus, it is appropriate in sand-shale sequences only. The exponential coefficient, N, is determined for different regions (geological basins) and for offset wells. A typical N value in the Gulf of Mexico is 3.

Eaton's exponent for pore pressure determination from resistivity logs Eaton's transient time equation can also be expressed in terms of resistivities: Pp -- Po -- (Po -- Ph)

Rn

(7-2)

where Ro is the observed shale resistivity and Rn is the resistivity of normally compacted shale. The exponent M is usually chosen to be 1.2 for the Gulf of Mexico.

Eaton's fracture pressure gradient equation In Eqs. 7-1 and 7-2, the overburden pressure is critical to the accuracy of prediction of overpressures. In vertical wells, the fracture pressure is related to the overburden pressure, horizontal stress and pore pressure. To fracture a formation would require a drilling mud weight pressure at least equal to the formation pressure. Any additional required pressure must be related to overcoming the horizontal stress and/or the cohesive strength of the rock matrix. Eaton's fracture gradient equation (Eaton and Eaton, 1977) is based on the equation developed by Mathews and Kelly (1967) to calculate the fracture pressure: p f = p p nL

K (Po

-

Pp)

(7-3)

where pf is the fracture pressure, and K is the coefficient describing horizontal stress/vertical stress. Eaton used the following expression in terms of the empirical depth-dependent Poisson's ratio, v, to calculate K: v

K =

(7-4) 1--v

From the data collected worldwide by Eaton, he was able to generate depth-dependent heuristic equations for v. This was done through a multi-segmented regression analysis of the empirical relationship between v and the depth below the mud line in feet (d and d2). For deep water, the fit was reasonable in many cases. The following are expressions for v: Vl = (-6.0893 x 10-9d 2) -k- (8.0214 x i0-5)d + 0.2007, for d < 4100 ft

(7-5)

172

F. AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR. 1)2 =

( - 1 . 8 8 2 x 10-1~ 2) -+- (7.2947 • 10-6)d + 0.4267,

for d > 5000 ft (7-6)

l) 3 = l) 1 --[- (d

- 4100)

5000 ~' - 41 O0~:

, for 4100 ft > d > 5000 ft (7-7) 900 Substituting v from Eqs. 7-5 to 7-7 in Eq. 7-4, one can derive a value for K for inclusion in Eq. 7-3.

Dutta's method Dutta (1988, 2002) expressed effective stress as a function of temperature, shale void ratio, and diagenetic integral depending on the time and temperature.

Fillippone formula Fillippone (1982) developed the following formula: Poverburden (Vp-grain pp-

Vp-inst)

(7-8a)

Vp_grain- Wp_fluid

where Wp-grain is the velocity when the porosity goes to zero (approximated to matrix velocity of the rock), Vp-nuid is the velocity when rigidity goes to zero (approximated to pore fluid velocity), and Wp-inst is the instantaneous velocity. The Po in the above equation is calculated from the following equation

Po (D) = PhP D

(7-8b)

where hydrostatic gradient is equal to 0.465 psi/ft, fluid density is 1.073 g/cm 3, p is the density, and D is the depth. Eq. 7-8 is valid only in certain areas. When it is applied to other areas, errors are usually over 10% (Fillippone, 1982).

Modified Fillippone formula In 1982, Fillippone presented a modified formula (Fillippone, 1982): Poverburden (Vp-grain -- Vp-inst)

pp = C Vp-~n~t C Vp-inst

V - r in- Vp-uid

(7-9)

may be calibrated by well log data. In some areas,

C Vp-inst = 0 . 1 8 6 7 7 e ~176176176....

(7-10)

If density logs are not available, for OBG calculation in Eqs. 7-1, 7-2 and 7-3, one has to use synthetically derived densities. One conventional method is to use the well-known Gardner equation (Gardner et al., 1974): p = 0.23 V ~

(7-11)

where V is the interval velocity. Another empirical relationship to develop the rock density curves has been reported by Traugott (1997). It is also known as the Amoco


173

Generalized Gulf Coast density. Density (p) is a function of depth (d), water depth (w) and air-gap (a):

(d-w-a) p -- 16.3 +

~

3125

(7-12)

Kenda et al. (1999) observed that the Gardner equation tends to underestimate density values, especially for older rocks. Traugott's (1997) method was considered more reliable for older rocks. Density can also be derived from other logs using neural networks when at least one of the wells has density information to be used for training (see Nikravesh and Aminzadeh for several examples of such neural networks and fuzzy logic-based method). As shown in Fig. 7-1, SP and resistivity logs can be used to predict synthetic density logs.

PRACTICAL APPLICATIONS

In recent years, the petroleum industry has increased exploration and production operations in overpressured areas. In drilling, the weight of the drilling mud should be at least 1 pound per gallon (ppg) greater than the formation pore pressure. Pore and fracture pressure prediction can assist the drilling engineers to design an effective casing program. If the difference between the fracture and pore pressure is less than 1 ppg, drilling can be very difficult. Accurate estimation of overburden and effective pressures can help control drilling costs. Several practical applications, each highlighting one or more aspects of pressure prediction and related issues, are presented here.

South Caspian Basin Lee et al. (1999) determined overpressure as a function of porosity and water depth. Overburden pressure is the total vertical stress exerted by the weight of the overlying rocks and the interstitial fluids. Fracture pressure is the stress necessary to fracture a formation; it is a function of overburden pressure, horizontal stress, and the pore pressure. Overburden pressure can be obtained using the following equation:

Po -- C

low

pwdw + C

loOS

{pg(1 - ~b(h)) 4- pfqb(h)dh}

(7-13)

where r is the porosity, h is the vertical depth, C is the constant coefficient, Ds is the sediment thickness, Dw is the water depth, Pw is the density of water saturated sand, pg is the density of grains, and pf is the density of interstitial fluid. Eq. 7-13 relates the overburden pressure to the height of the water column and the lithostatic column. The first integral term varies relative to the seafloor. The density can be obtained from bulk density log measurements. If direct density measurements are not available, they can be estimated from other wells or seismic data (e.g., Gardner's Eq. 7-11 or the neural network method of Nikravesh and Aminzadeh, 2001). There are a number of ways to predict pore pressure from drilling mud weights, resistivity, conductivity, and sonic and seismic interval velocity. In exploration areas

174

E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.

with seismic shadow zones, where very little or no pressure information is available, the interval velocity method can be used. Eq. 7-1 presents one such approach. Eaton's method enables prediction of pore pressure assuming compaction and is applicable only in sand-shale sequences. In Eq. 7-1, the knowledge of the overburden pressure is critical to the accuracy of pore pressure determination. In vertical wells fracture pressure is determined by the overburden pressure, horizontal stress, and the pore pressure. Fracturing a formation would require a mud weight pressure at least equal to the formation pressure. Any additional pressure required is related to overcoming the horizontal stress and the cohesive strength of the rock matrix. In this situation the fracture pressure equation (Eq. 7-3) of Mathews and Kelly (1967) can be used. As described earlier, more accurate fracture pressure can be obtained by use of Poisson's ratio (Eq. 7-4). The solution of the latter equation requires knowledge of shear wave and compressional wave velocities. Eaton and Eaton (1977) provided empirical depth-dependent relationships such as those given in Eqs. 7-5, 7-6, and 7-7. These empirical relationships may vary for different geographic areas. Historically, seismic stacking velocities, converted to depth domain interval velocities using the Dix equation, were used for pressure prediction. Pressure prediction from the Dix equation velocities can be in error when lateral velocity variations and dipping structures exist, and can become unstable when the stacking velocity decreases. These problems can occur in overpressured areas. Lee et al. (1999) corrected these problems by increasing the accuracy of the interval velocity measurement. This was accomplished by the use of tomographic inversion to yield more accurate lateral interval velocities in the depth domain. This technique allowed the integration of pressure prediction, AVO indicators, and reservoir depth imaging. The color-coded geopressure was then overlain on seismic depth sections to indicate variations in the geopressure distribution. Additionally, reservoir boundary mapping can be enhanced by overlaying color-coded geopressure distribution charts on AVO sections. Use of the tomographic inversion yields more accurate velocities both laterally and with depth. The final interval velocity model from the tomographic inversion was used to make the pore and fracture pressure predictions. The sediment compaction trend was determined by analyzing two seismic events, one shallow and one deeper. Based on the derived interval velocities and well information, the normal compaction trend was adjusted to allow the calculated pore pressure to match the actual pressure at the well location. Pore and fracture pressures were estimated from interval velocities through the low-amplitude zone, as well as deeper in the section. The geopressure estimation was then overlain on the depth migration sections providing a useful reservoir interpretation tool. Fig. 7-2 (Lee et al., 1999) is a depth domain pore pressure distribution. The pore pressure distribution shows that the pressure remains hydrostatic to a depth of 2500 m. The pressure then starts to increase with depth and reaches 10 ppg at a depth of 2800 m. In Fig. 7-2, the lighter shading with a pressure of 10 ppg represents the top of an overpressure zone. The fracture pressure was calculated using Eqs. 7-5 to 7-7 and the results were plotted in Fig. 7-3. As shown, the fracture pressure distribution in the low-amplitude zone also increases with depth. At a depth of 2800 m from the top of the overpressured zone, the fracture pressure reaches 15 ppg (equivalent mud weight). A differential pressure between the fracture pressure and


175

the pore pressure was calculated to detect the mud circulation. If the differential pressure is less than 1 ppg, drilling can be very difficult. Fig. 7-4 shows the differential pressure distribution of the fracture and pore pressures. The differential pressure ranges from 1 to 6 ppg. These results indicate that the drilling mud circulation should be smooth in the studied low-amplitude zone.

AVO effects of overpressure Pigott and Tadepali (1996) used elastic amplitude variation with the pre-stack seismic AVO data, and a three conjugate layer, iterative least-square minimization inversion technique to determine Young's modulus. Compared with the derived statistical models of laboratory-measured elastic rock properties of Young's modulus determinations enable prediction of the in-situ reservoir porosities and differential pressures, which were within 5 porosity percent and 400 psi (2.75 MPa) of the borehole measurements, respectively. They relied on the results of Pigott et al. (1988a,b), which suggest that Young's modulus can be dynamically determined from the inversion of AVO data and that, in principle, the in-situ reservoir pressures and porosities could be seismically quantified. Pigott and Tadepali (1996) procedure consists of: (1) developing a statistical model which describes differential pressure and porosity in elastic sedimentary rocks as a function of Young's Modulus; and (2) determination of the porosity and differential pressure using AVO inversion and the derived Young's modulus. Statistical analysis of the experimental laboratory data of differential pressure, compressional wave velocity, shear wave velocity, and density for dry gas sands have been compiled in earlier publications. The statistically best-fit non-linear least-square equations expressed in the form consistent with the earlier theoretical derivations of Young's modulus (E) as a function of strain, are of two types: (1) a primary equation expressing porosity as a dependent variable of Young's modulus, and (2) a secondary equation, which expresses differential pressure as a dependent variable of both porosity and Young's modulus. These equations are: q5 = 0.2423 - 0.10276 log e E

(7-14)

loge Pd = A + B ~b + C E

(7-15)

where 4~ is the % porosity, E is Young's modulus, Pd is the differential pressure and A, B, and C are constants. Based on the statistical analysis of real data, values of these constants and respective different ranges of porosity are presented in Table 7-2. The last column is the standard deviation of the estimates in each range. Thus, the porosity and reservoir pressure can be obtained for elastic sedimentary rocks using Eqs. 7-14 and 7-15 along with seismic data.

Real time pressure analysis With the introduction of measurement while drilling (MWD) logging techniques, the prediction of abnormal pressure has become more efficient, leading to considerable

176

E AMINZADEH, G.V. CHILINGAR AND J.O. ROBERTSON JR.

T A B L E 7-2 Statistically derived coefficients of differential pressure equation (Eq. 7-15) Porosity 0 10 20 30

< < <
' 15

,"J',

,I

Fig. 8-9. Variation with depth of (/) electric resistivity of the Buregskiy shales, (II) porosity, and (III) Pres/Pahyd ratio for the subsalt carbonates of the northern structural-tectonic zone in the Pripyatskiy Deep. Prospects with overpressure: 1 = Dneprovskaya; 2 = Vetkhinskaya; 3 -- Krasnosel'skaya; 4 = Barsukovskaya; 5 -- South Rechitskaya; 6 - Malodushinskaya; 7 = Demikhovskaya; 8 -- East Pervomayskaya; 9 -- Pervomayskaya; 10 -- South Ostashkovichskaya; / / = Rudninskaya; 12 = Vishanskaya; 13 = Sudovitskaya; 14 = Malynskaya; 15 -- Glusskaya; and 16 = East Drozdovskaya. (Modified after Zavgorodniy and Pakhol'chuk, 1985, fig. 3.)

Deep are illustrated in Fig. 8-9. Additional detailed information on overpressures is listed in Table 8-1. The standard average deviation of measured formation pressures (Pr~) from Curve III in Fig. 8-9 equals +0.03. According to Zavgorodniy and Pakhol'chuk (1985), two "stabilized P r e s / P a h y d regimes" have been encountered in the region" the first one occurs at 3000 m with a Pres/Pahyd ratio close to 1.14, whereas the second one starts at 3500 m with the pressure ratio asymptotically approaching the value of 1.18 (Fig. 8-9, Curve III). (Pahyd = assumed hydrostatic pressure.)

TABLE 8-1

1

rn 0

Some data on overpressured formations of the northern Pripyatskiy Deep (after Zavgorodniy and Pakhol'chuk, 1985, table I) Prospect

Well

Horizon

Depth (m)

Saturation type

Semiluksky

3450

Oil

4

Depth to O/W contact (m)

Initial reservoir pressure (MPa)

pie,/prhyd

phyd/pahyd

Abnormality

3535

44.4

1.28

1.18

0.10

(1 1 3

3535 3910

38.0 59.5

1.34 1.58

1.24 1.18

0.10 0.40

-

3910

57.7

1.51

1.18

0.33

-

1.51 1.44 1.29

1.18 1.24 1.14

0.33 0.20 0.15

L%d?%L

,Je~c/,Jd,~d

209

Dneprovskaya Vetkhinskaya

8 4

Zadonsky Voronezhsky

2845 3770

Water Oil

Vetkhinskaya

4

Semiluksky

3800

Oil

Krasnoselskaya Krasnoselskaya Barsukovskaya

210 206 9

Semiluksky Zadonsky Semiluksky

4477 2909 3000

Water Gas-condensate Oil

3852

67.6 42.0 38.6

Barsukovskaya

9

Voronezhsky

3031

Oil

3790

423

1.40

1.14

0.26

22 O 070

South Rechitskaya Malodushinskaya

I04 32

Semiluksky Voronezhsky

4770 3622

Water Oil

-

71.6 45.8

1.SO 1.26

1.18 1.18

0.32 0.08

-

3768

Demekhovskaya East Pervomayskaya

20 1 9

Semiluksky Semiluksky

3233 4188

Water Oil

42.0 52.3

1.30 1.25

1.14 1.18

0.16 0.07

-

Pervomayskaya South Tishkovskaya South Ostashkovichskaya South Ostashkovichskaya Zolotukhinskaya

21 121 18 108 13

Voronezhsky Zadonsky Zadonsky Semiluksky Zadonsky

4506 4243 4844 4604 1900

Oil Water Oil Water Oil

1.28 1.41 1.41 1.28 1.40

1.18 1.24 1.24 1.18 1.08

0.10 0.17 0.17 0.10 0.32

-

2275

57.6 59.9 54.6 59.0 26.6

2740 3664

Water Water

-

44.0 48.6

1.60 1.32

1.24 1.18

0.36 0.14

3 38

Zadonsky Sargaevsky + Pashiysky Zadonsky Zadonsky

3260 3685

Water Oil

-

43.5 52.4

1.33 1.42

I .24 1.24

0.09 0.18

Vishanskaya

9

Voronezhsky

2737

Oil

3001

32.5

1.19

1.12

0.07

Sudovitskaya Malynskaya Glusskaya

3 6 4

4479 3235 2083

Oil Water Water

-

1.24 1.25 1.25

1.18 1.14 1.10

0.06 0.11 0.15

-

-

55.6 40.4 26.1

East Drozdovskaya

1

Voronezhsky Semiluksky Voronezhsky + Semiluksky Voronerhsky + Semiluksky

1877

Water

-

21.8

1.16

1.08

0.08

-

Pritokskaya Rudninskaya South Domanovichskaya South Sosnovskaya

5 4

p,, = reservoir pressure; pahyd= assumed hydrostatic pressure; p,,, = excess pressure.

-

-

4386 -

3855 -

-

-

-

> z

Dneprovskaya

+ oil

2g

1 ) 8 I I 021 IZ -

0.032

-

0

9m F ia

m

V]

z

ia

m

-

049

11 1 6

11 9

m

1 0

5

5 5

14

(1 (134

-

15

0080 -

-

--1.8 0 050 12

0 044

-

h)

S

204

G.V. CHILINGAR, W. FERTL, H. RIEKE AND J.O. ROBERTSON JR.

By definition, abnormal formation pressures (i.e., overpressures) are characterized by conditions where the Pres/Pahyd ratio by more than twice exceeds the standard deviation value. In other words: while below 3000 m the anomalous values approach 20%, the excess anomalous deviation below 3500 m ranges from 20% to 40% (e.g., Vetkhinskaya, Krasnosel'skaya, Barsukovskaya, and South Rechitskaya fields). Only in three oil fields slight overpressures (~ =~

8

A. Extensional Sag

Elongate ( Small to Moderate )

Compression and Extension

8

Fig. 10-3.

Elongate (?)

Asymmetrical

23 ]

PORE WATER COMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES

RATIO 3asin V o l u m e

(b)

SEQUENTIAL M3

PETROLEUM

BASIN

Basin Area M 2

ARCHITECTURAL

6 5 Prod. B a s i n s

FORM

BASIN TYPES

I

Sag

Fordeep

C R A T O N INTERIOR B A S I N S

H CONTINENTAL MULTICYCLE BASINS A. CRATON MARGIN - Composite

Platform or Sag

1.

B CRATON / ACCRETED MARGIN - Complex

Sag

Rift

"'~l\l-C. CRUSTAL COLLISION ZONE-Co~wergent Rate Ma i -downwarp into small ocean b~ a) closed A 9

Fordeep a) 250%

i

b) High

4c

.

c) open i]]] 1.

-

, ,

"

--4a.----~

b) trough

Platform or Sag

c) 250%

Rift / Sag _ .._ .~.~.-

k

C O N T I N E N T A L RIFTED B A S I N S A. CRATON and ACCRETED ZONE RIFT

B. RIFTED CONVERGENT MARGIN-Oceanic Consume 180%

( Variable )

9Rift I Wrench " I. - ~ . ~

a) Back Arc ~

c) Median

1 b) Transform

~

Rift / Sag C. RIFTED PASSIVE MARGIN - Divergence 9Rift /Drift "

a) parallel

b) transform

Rift I ~ Sag 9Modified Sag "

I IV

DELTA BASINS - Tertiary to Recent A, Synsedimentary

0 - -

,o ...=o..... -

I~ Subduction

~" F O R E A R C B A S I N S

Fig. 10-3 (continued).

~

' :; ~,

I

232

H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSON JR.

from oil and gas wells is p r o b a b l y not representative of the interstitial water owing to contamination, dilution by c o n d e n s e d water vapor, q u e s t i o n a b l e fluid sampling, preservation, and laboratory analytical procedures. Water p r o d u c e d with the oil can represent a mixture from different production horizons in the case of c o m m i n g l e d production or as a result of poor c e m e n t job or leaky casings. During the c e m e n t i n g of casing into place in a well, the filtrate f r o m the c e m e n t slurry can p e n e t r a t e the p e r m e a b l e sandy zones and c o n t a m i n a t e the pore water. H y d r a u l i c fracturing fluids can also c o n t a m i n a t e reservoir waters. In some cases it takes m o r e than three m o n t h s for the fracturing fluids to be p r o d u c e d back after fracture stimulation treatment. It is prudent to view with caution pore-water c h e m i s t r y results r e p o r t e d in the literature that are based entirely on p r o d u c e d water sampled at the wellhead. T h e s e are just some o f the p r o b l e m s e n c o u n t e r e d by investigators looking at p o r e - w a t e r chemistry. With respect to u n c o n s o l i d a t e d s e d i m e n t samples, the handling of the samples can be critical in obtaining accurate analytical results. Problems include changes in t e m p e r a t u r e and pressure, c o n t a m i n a t i o n by b o t t o m water and seawater as the cores are retrieved. F u r t h e r changes can take place owing to evaporation, oxidation, and the type of e q u i p m e n t and supplies used in extracting and storing the sample, and the m a g n i t u d e of the pressure at which the pore water is s q u e e z e d out of the s e d i m e n t sample. M a n g e l s d o r f et al. (1969) first d e m o n s t r a t e d that t e m p e r a t u r e changes alter i o n - e x c h a n g e equilibria and bring about changes in p o r e - w a t e r chemistry. Bischoff et al.

Fig. 10-3. It is important to have a sense for the relationships among pore-water chemistry, petroleum basin types and the origin of the abnormal fluid pressures. Klemme's (1984) petroleum basin classification with cross-sections showing idealized basin profiles, basin parameters, stratigraphy and structures are used to proffer some generalizations about what kind of water chemistry might occur in these basin types. Basin examples given for Kiemme's (1984) basin types are the following. Basin Type I (U.S./Canada Williston) has abnormal pressures due to hydrocarbon generation rather than compaction. Basin flushing by water has influenced the water chemistry. Basin Type IIA (U.S. Wind River) has basin-centered abnormal fluid pressure zones. Well-logs show that resistivity increases in the more thermally mature rocks. Water chemistry is modified by coalbeds and artesian flow into the basin. Most of these reservoirs in this type of basin are gas and have water-free production. Basin Type IIC (U.S. Gulf Coast) and IV (Mississippi Delta) exhibit compaction water chemistry associated with regressive sedimentary sequences, growth faults, mud volcanoes, and smectite to illite clay mineral transformation. Rift basins offer a more complex picture. Basin Type IliA (North Sea Viking Graben) basins illustrate that two distinct abnormal pressure zones can exist. One pressure zone is above another below the characteristic (unconformity/disconformity) zone which tends to occur in this type of basin. The abnormal pressure zones are basin-centered making the water chemistry profile complex. Type IIIB (South Sumatra, U.S. Ventura, Maracaibo) basins have a broad range of imposed stress conditions that commingle the effects of local and major tectonic forces and gravitational compaction on the water chemistry. Usually the water chemistry shows a salinity decrease with depth but can change areally and vertically over the section and in individual structures. Basin Type IIIC (Australia's North West Shelf) having abnormal formation pressures which depend upon the rate and type of sedimentation. Water chemistry is a mixed bag. Basin Type IV are forearc basins (Sacramento, U.S.) which has a mixed history, of tectonism, compaction and basin flushing. Major deviations from compaction water chemistry expectations can be attributed to dehydration in the change from gypsum to anhydrite in evaporitic sequences, coalification, and lack of argillaceous sediments. (After Klemme, 1983, fig. 3, p. 170; reprinted with the permission of the Oil and Gas Journal.)

PORE WATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES

233

TABLE 10-2 An overview of proposed mechanisms to account for the origin of chemical differences in subsurface pore waters (after Chilingarian et al., 1994, table 5-2, p. 111) Reference

Mechanism(s)

Washburne (1914) Richardson (1917) White (1957) Berry (1959) Chave (1960) Von Engelhardt and Gaida (1963) Bredehoeft et al. (1963) Powers (1967) Serruya et al. (1967) Mangelsdorf et al. (1969) Hitchon et al. (1971)

Subsurface evaporation and juvenile water additions. Leaching of disseminated salt and salt diffusion from salt bed. Burial diagenesis of seawater. Chemical osmosis. Trapped remnants of seawater moved by sediment compaction. Ion exchange capacity of clays under compaction. Membrane filtration by clays. Alteration of smectite to illite during deep burial. Electrical potentials (electrodiagenesis). Molecular settling. Trapped pore water diluted by fresh water recharge and concentration by clay membrane filtration. Interaction between sediments and water contained in their pore spaces. Infiltration of subaerial brine. Salt related brines diluted by mixing with seawater. Thermohaline overturn of pore water.

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

(1970) confirmed these effects. Sayles and Manheim (1975) stated that temperature is the most single significant factor affecting the composition of pore waters. With respect to laboratory-simulated compaction studies, problems arise from (1) the magnitude of pressure used to squeeze out the pore water (chemistry of water changes with pressure), (2) analytical techniques involving minute amounts of squeezed-out pore waters, (3) specimen preparation, and (4) contamination involved in collecting the pore water. Palmer and Sulin water classifications A concise discussion of Palmer and Sulin's water classification methodologies is in order so the reader can quickly comprehend the meaning, formulate relationships, and categorize subsurface water chemistry results based on these classification schemes. Both schemes could be useful in making comparisons with published subsurface water analysis data. The foundation for such analytical schemes is the composition of the seawater system, i.e., contents of (Na +, K +, Ca 2+, Mg 2+, CI-, SO 2-, and CO 2-) in H20. Schoeller's system for the most part addresses petroleum-reservoir waters and the reader is referred to Schoeller (1955) and Collins (1975) for details. Palmer's classification Palmer (1911) devised his water classification system based on the chemical salinity (salts of strong acids) and alkalinity (salts of weak acids). Briefly, the concept of the chemical salinity is that all cations (positive ions) and certain anions (negative ions), such as chloride, sulfate, and nitrate, can cause salinity. Alkalinity depends on the

234


free alkaline bases, which is a result of the hydrolytic action of water on dissolved weak acid salts. Dissolved ions in water are divided into three groups: (1) soluble alkalies (sodium, potassium, lithium); (2) meagerly soluble alkaline earths (magnesium, calcium, strontium, barium); and (3) hydrogen, whose salts are acids and cause acidity (Collins, 1975). Palmer's classification system uses the sum of the reacting values (capacity for reaction) of the individual ionic species in each group to define five classes based on five special properties of water. Reacting values are calculated in percent by summing the milliequivalents of all the ions, then dividing the mequiv of a given ion by the sum of the total mequiv and multiplying by 100. The predominance of reacting values in each group is the basis for the special properties, which are: 9 Primary salinity (alkali salinity), which does not exceed twice the sum of the reacting values of the alkali radicals. 9 Secondary salinity (permanent hardness) is defined as the excess of any salinity over primary salinity and does not exceed twice the sum of the reacting values of the alkaline earth group radicals. 9 Tertiary salinity (acidity) is any excess of salinity over primary and secondary salinity. 9 Primary alkalinity (permanent alkalinity) is any excess of twice the sum of the reacting values of the alkalies over salinity. 9 Secondary alkalinity (permanent alkalinity) is the excess of twice the sum of the reacting values of the alkaline earth group radicals over secondary salinity. The Palmer classification system has some shortcomings, such as the grouping of some of the constituents together that are not closely related chemically, and it does not consider ionic concentrations of saturation conditions related to sulfate or bicarbonate. (For additional details see Collins, 1975.)

Sulin's classification Sulin (1946) devised a classification system based upon various combinations of dissolved salts in water and tied it to the environmental origin of the water. The sulfatesodium water groups are indicative of terrestrial conditions, bicarbonate-sodium water groups represent continental conditions, chloride-magnesium water groups form under marine conditions, and the chloride-calcium groups are related to deep subsurface conditions. The water classification scheme of Sulin consists of: (1) genetic water types established by value of the Na/CI ratio; (2) chemical types using values of the ratios of (Na-C1)/SO4 and (CI-Na)/Mg; (3) groups subdivided based on Palmer's characteristics as determined by the classes; (4) classes depending on Palmer's salinity or alkalinity values; and (5) subgroups established using the Ca/Mg and SO4/C1 ratios. Sulin considered sodium as the sum of Na, Li, K ions, and chlorides as the sum of C1, Br, and I. The classification system is completed by determining the sum of the milligram equivalents per 100 g of water (indicator of water mineralization). The Sulin's class subdivision scheme employs the distinction of whether or not sodium bicarbonate is present. In the sulfate-sodium, chloride-magnesium, and chloride-calcium water types there is no sodium bicarbonate present.


235

(1) Bicarbonate-sodium type (a) Class At: primary alkalinity predominates (alkali carbonates and bicarbonates). (b) Class A2: secondary alkalinity predominates (alkaline earth carbonates and bicarbonates). (c) Class St: primary salinity predominates (alkali chlorides and sulfates). (2) Sulfate-sodium, chloride-magnesium, and chloride-calcium types (a) Class A2: secondary alkalinity predominates (alkaline earth carbonates and bicarbonates). (b) Class St: primary salinity predominates (alkali sulfates and chlorides). (c) Class $2: secondary salinity predominates (alkaline earth sulfates and chlorides).

C H E M I C A L C O M P O S I T I O N OF S U B S U R F A C E B R I N E S

Petroleum engineers, geochemists, hydrologists, well-log analysts, sedimentologists, and water chemists all have an interest in classifying water based on its chemical composition, physical properties, origin, or association with diagenetic processes. Collins (1975) discussed his compilation of chemical and physical analysis of oilfield brines occurring in various formations and producing oil and gas reservoirs in the U.S. Geochemists such as Ortoleva (1994), Bethke (1996) and Giles (1997) approach the problem by employing different strategies. Ortoleva looked at the geochemical self-organization in overpressuring and compartmentalization in sediments. Giles focused on the resolution of geochemistry theory with basin modeling aspects. Bethke's methodology is concerned with the analyses of open and closed fluid systems using computational geochemical reaction modeling. His reaction model considers the transfer of mass and heat in and out of a system having an aqueous fluid and one or more minerals, and can accommodate a buffer (an external gas reservoir) in order to calculate the system's equilibrium state. The reaction path is determined by the course the equilibrium state takes as it responds to changes in composition and temperature. Changes in the equilibrium system are audited, thereby monitoring the reactants (minerals and fluids) influence on the system composition. How does this fit in with the present research trend on the fluid chemistry relationships in compacting pelitic sediments? Hunt et al. (1998) believe that the cessation of compaction does not appear to be related to overpressuring, but is a phenomenon that occurs with hydrostatic-pressured shales. This means that the two-stage, linear compaction is a normal compaction trend (see section on Field Case Studies). At depths where compaction no longer occurs, gas generation seems to be the major cause of overpressures. Now we have all the reaction modeling ingredients (seawater, smectite, smectite/illite mixed interlayer clays, and illite, and a gas reservoir) needed to explore Hunts et al.'s premise, and to see if their model matches field results. This could confirm whether or not the pore waters in shales should be fresher than those in associated sandstones, and confirm the origin of the fresh water in the overpressure zones. The alternative to Hunt et al.'s hypothesis is the study by Burrus (1998) on stress-porosity, using the TEMISPACK finite volume model, showing that compaction disequilibrium is the dominant cause of overpressures.

236


Pore waters can be classified based on their origin as (1) syngenetic (formed at the same time as the enclosing rocks), and (2) epigenetic (owing their origin to subsequent infiltration of meteoric and other waters into already formed rocks). The main processes, which alter the chemistry of buried waters, are: (1) physical (gravitational compaction); (2) chemical (reactions involving minerals, organic matter and interstitial solutions); (3) physicochemical (filtration through charged-net clay membranes, adsorption and base exchange); (4) electrochemical; and (5) biochemical. Data provided by Hanor (1981) illustrate that the geochemical properties of fluids being expelled from recently deposited sediments of the Mississippi River delta undergo a compositional change. He attributes these changes to early diagenetic processes of bacterial respiration, mineral precipitation, and possible fractionation due to the presence of clays having high exchange capacity. Changes in the concentration of pore-water fluids during the process of compaction, as reported by different investigators and presented in the following section, are based on field and laboratory data. Conceptual models relating the results to gravitational compaction and the generation of overpressures are also presented. Salinity variations in compacting sandstones and associated shales Much of the available data on the composition of oilfield brines pertains to water from permeable formations and only in a few instances are data on the composition of pore water from associated shale beds are reported in the literature. De Sitter (1947) noted that the salinity of formation waters in sandstones varies from that of fresh water to ten times the salinity of seawater. The distribution of salinity of pore water present in the young geosynclinal sediments (recent deposition in the crustal collision zone-closed convergent plate margin) along the U.S. Gulf Coast is well documented by a number of investigators. Timm and Maricelli (1953, p. 394) stated that high salinities up to 4.5 times that of normal seawater characterize the pore waters in Miocene/Pliocene sediments. Where the relative quantity of shale is large and the degree of compaction is high, pore waters have salinities as low as one-half that of normal seawater. Fig. 10-4 illustrates their concept that the formation waters in downdip, interfingering, marine sandstone members, have lower salinities than that of seawater. These sandstones have proportionately less volume than the associated massive shales. More massive sands updip have salinities greater than that of seawater, because of lack of influx of fresher waters from shales. Myers (1963) studied the chemical properties of formation waters, down to a depth of 12,400 ft (3780 m), in four producing oil wells in Matagorda County, Texas. Salinities of pore waters ranging from 5000 ppm to 12,500 ppm were found below 10,000 ft (3048 m) in each of the four wells, as compared to salinities of about 70,000 ppm above that depth. Myers commented that in the deeper section the proportion of massive shale is large and the sands are near their downdip limits. These results were in close accord with those of Timm and Maricelli (1953). Kharaka et al.'s (1977) study of the geochemistry of geopressured geothermal waters from the Frio Clay in the Texas Gulf Coast indicated that the salinity (total dissolved solids) of water in the geopressured zone ranged from 20,000 to 70,000 mg/1. Water

237

PORE WATERCOMPACTIONCHEMISTRY AS RELATEDTO OVERPRESSURES

Sea Level

,-':.:!~!:-!:i!". ;'!"--':-').':.''.~:."..".~::."::.)).~i...:.

::-'.;.:.::..:.-.'..:: ::...:.;::;:..:.........:.....'..-...:.:.:-:.;...

'.-'-?'-~":..':.. "'"-"';::."-.....

" " #:."::..-"-".'i!i:!'i'~':':.:"-):'."." :.,

oa

9 00

"'-"?'-':-."::. ".';?:~ '~o~

Fig. 10-4. An idealized cross-section of some sands and shales in the offshore subsurface of southwest Louisiana illustrating salinity relationships. (Modified after Timm and Maricelli, 1953, pp. 396, 397 and 408; in Rieke and Chilingarian, 1974, fig. 146, p. 271.)

samples from many gas wells, on the other hand, yield much lower salinities. Kharaka et al. (1977) believed that these samples are not representative of the true formation waters' salinity owing to the dilution of the condensed water produced with the natural gas. Their study shows that the salinity in the geopressured zone is generally, but not always lower, than salinities in the normally pressured zone. Dickey et al. (1972) reported that formation waters from four wells in southwestern Louisiana showed almost normal concentrations of total dissolved solids in the geopressured zone for those depths of burial. The findings of Fowler (1968) suggest that the salinity of water in undercompacted shales in the Chocolate Bayou Field, Brazoria County, Texas, is higher than in the well-compacted ones. A definite correlation between the high salinity of interstitial fluids and abnormally high pressures was found to exist. This is possibly due to the fact that undercompacted shales did not have a chance to contribute their fresher water to the associated sandstones. Fowler (1968) also studied the variation in salinity of produced water with time. The typical pattern is one of decreasing salinity with time, and the freshest water is found in sands receiving most of this water from associated shales. Plummer and Sargent (1931) and Elliott (1953) also studied the variability of pore waters from specific zones in wells taken over a 1- to 48-month time period. They found that there was no definite trend of ion concentration with time. Chave (1960, p. 359) reported that the percentage difference in the concentration of a given ion could vary from less than 1% to as much as 168%. Chave commented that the reasons for the differences between resampling by Plummer and Sargent (1931) and Elliott (1953) were not clear. He suggested that they could represent the natural

238


chemical difference of waters in a given local stratigraphic zone or the samples were contaminated. In the opinion of the writers, any chemical analyses of pore waters should be checked by charge balance criteria. The total milliequivalents per liter of cations and anions must be equal to each other within 5 to 10%. In order to perform this check, the analysis must be made for all the major cations and anions present in the sample. Morton and Land (1987a) pointed out that abnormally high pressured Oligocene Frio sandstones in Texas contain waters having salinities ranging from around 8000 to more than 250,000 mg/1 (total dissolved solids). The high values could be due to the dissolution of diapiric salt. Low salinities are attributed to pore-water dilution by water released from the transformation of smectite clay to illite (hydromica), i.e., by mineral dehydration reactions. Manheim and Bischoff (1969) were the first to suggest the increase of pore-water salinity with depth in relationship to diapiric salt structures in the Gulf Coast. Pore waters were analyzed from six boreholes drilled offshore in the Gulf of Mexico. Pore-water samples from the drillholes near diapiric structures showed systematic increases in salinity with depth. The salinity showed little change with depth in those boreholes drilled away from the diapiric structures. Manheim and Bischoff (1969) suggested that salt diffusion from underlying salt structures were the cause of this increase in salinity. The mass transport of highly saline waters in sedimentary basins will have a strong impact on the transport of hydrocarbons, ore fluids, heat, and diagenetically reactive dissolved constituents. Hanor (1987b, 1999) discussed the concept of thermohaline overturns and the resulting mass transfer of pore water in southeastern Louisiana. He proposed that there are three major types of subsurface flow regimes in this area. The uppermost (shallowest) consists of topographically driven, fresh-water systems (ground water). A thermohaline system can exist at an intermediate depth where salt diapirs are present. The deepest zone is the regional overpressured regime. The salinity (total dissolved solids) overprint on the intermediate zone's pore-water chemistry is a direct result of the presence of salt, and the induced fluid circulation is driven in part by fluid density inversions resulting from spatial variations in salinity and temperature. This chemical overprint could be expected to exist in other young basins where salt beds and diapirism are present. Capuano (1990) simply stated that compaction-driven flow dominates in the abnormally high pressured sediments, whereas gravity-driven or thermal-density-driven flow dominates in normally pressured sediments. Field case studies

The importance of knowing that the pore-water concentrations are lower in shales than in associated sandstones was pointed out by Chilingar et al. (1969). Erroneous interpretation of well logs may result if it is assumed that the salinity of pore waters in sandstones and associated shales are the same. In order to determine the water saturation, Sw, in well log analyses, it is necessary to know Rw (resistivity of the pore water in the formation being evaluated). Under favorable conditions, the latter can be determined on using the SP curve. This approach, however, is not practical in many cases owing to the properties of some drilling fluids and other variables that can cause

239

PORE WATERCOMPACTION CHEMISTRY AS RELATED TO OVERPRESSURES 3600

9940

T

o,,

I

9980

l

3800

I

9960

I-Q. IJJ a

(B)

(A)

SHALE

i

" r 4OOO I-Q. IJJ C~

e,,~o,,==,

p,p.m. RANGE IN ":..

SAND

4200

l

to,ooo

i

SAND

I SHALE

10,020 I0

20

4400 30

CHLORINITY, p.lam,x I0 a

40

30

50

70

90

I10

CHLORINITY, Rl~m.,x I0 a

Fig. 10-5. Chlorine ion concentration in shales and sands versus depth. (Modified after Fertl and Timko, 1970, fig. 4, p. 15" based upon data by Hedberg, 1967.)

wellbore contamination. The best method, which has been practiced for many years, is the analysis of formation water collected from a permeable zone or the use of the petroleum industry's compiled water atlases. Once the water salinity is determined in an area, Rw is calculated for any subsurface zone by making only a temperature correction (Arps, 1953). Another approach to find Rw in sandstones involves the use of log-derived values of adjacent shales. It was proposed by Overton and Timko (1969) to plot salinity variations as calculated from the SP curve for abnormal formation pressure detection work. Their simple relationship, so-called salinity principle, between the salinity of clean sands, Cw, and the porosity of adjacent shales, 4~sh,is expressed as C w x (~sh - -

constant

(10-1)

The assumption is that the formation water salinity is in equilibrium between sands and shales and that it will vary inversely with the porosity of adjacent shales. In most instances it is generally accepted that shale porosity decreases with increasing depth, whereas formation water salinity tends to increase with depth. AHFP environments cause divergence from such normal trends. Shale porosity is shown to increase or remains constant in these overpressured zones, which in turn suggests a decrease of constant value in the formation water salinity as calculated by Eq. 10-1. Any decreasing trend in the water salinity as indicated by the SP curve would indicate possible abnormal fluid pressures. Fig. 10-5 is an example illustrating the relationship between shale resistivity values derived from sidewall cores and those obtained from the SP curve in clean sands (Fertl and Timko, 1970). It should be stressed that the shale pore waters are less saline than those in the associated clean sandstones. The validity of Overton and Timko's empirical relationship is questioned based on their assumption that the pore water in shale and clean sand is in chemical equilibrium

240


(G.V. Chilingar, personal communication, in Fertl, 1976, p. 190). This is a valid observation by Chilingar as demonstrated by the plot of salinity values for log and laboratory results in Fig. 10-5. Hermanrud et al. (1998, 1999) raised additional doubt by expanding the question to include other well logging data used to establish such trends. They evaluated sonic, resistivity, neutron, and density well-log data from 80 wells on the Norwegian continental shelf in the North Sea to show that there is no clear correlation between the well-log response (abnormally high porosity) and interpreted fluid pressure. They did not find a depth in these wells below which porosity ceases to decrease (overpressure indicator); therefore, undercompaction in these shales associated with the dominating clastic sediments was not demonstrated. In the offshore, Atlantic Haltenbanken area of Norway, however, both the resistivity and sonic logs responded to high fluid pressures present in the Jurassic intra-reservoir shales of the Ror and Not formations. The shales separate reservoir sandstones deposited in deltaic and shallow marine environments. Hermanrud et al. (1998) suggested that the well logging tools were responding to textural changes in the shales or microfracturing rather than elevated porosity induced by the overpressuring of the heterogeneous shales. One can raise the following question, however: was their choice of formation water resistivity and matrix transit time values used for evaluating the 'Not Formation' high-pressure regimes correct? These values were determined using an average porosity for a low-pressure reference well in the Not Formation, rather than using actual chemical measurements. Would there have been a more precise demarcation of the porosity-depth relationship if fluid samples were used? Burrus (1998) noted that the conversion of log measurements in shales into porosity values is not straightforward. Density logs are sensitive to changes in lithology, neutron logs are sensitive to changes in mineralogy, and the sonic logs are not linearly related to porosities. The above brief discussion raises concern about the present trend in the literature to place specific well data from wide areas into a lumped-parameter evaluation plot. Well-log interpretation techniques should be performed in conjunction with water analysis of in-situ formation test fluid samples and from the cores of shales and their associated sandstones. Such analyses should be carried out on a well-by-well basis rather than making the assumption that the hydrochemical facies hold from one well to the other.

Hackberry and Manchester fields, Louisiana, U.S.A. Schmidt (1973) performed an important field case study. He analyzed the pore waters of both shales and sandstones from the Manchester and Hackberry fields in the south Louisiana Gulf Coast Basin by determining the concentration of various cations and anions together with base-exchange capacity, type of exchangeable cations, and mineral composition of the clays. Similar data from sandstones, in the A-5 Farmers Land and Canal well in the Manchester Field, were calculated by Schmidt (1973) using the spontaneous potential (SP) electric log curve. Sandstone salinity values are based on 56 water sample analyses for major cations and anions. The sampling was from normally pressured producing zones in the Hackberry Field, and highly pressured zone in the Manchester Field.

PORE

WATER COMPACTION

CHEMISTRY

AS RELATED

Concentration, 0

0 ' .

'

4 ' I '

8 ' I '

'

~-----10,000 mg/I "'""........

", -

_

/

/

4...

,,

.

.:-:

I"

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...'

.......

R"

~,..~-~

a"""~2

,-~

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/

~ ~

1

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WK~ d C h e s t e l S S

'4"

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F

~

, ' ~s1

2000

-

3000

-

4000

-

5000

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6000

-

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8000

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9000

o- .... :":::~2~ ~ / ." / :" ~

~ berry SS Field

.,_.

.ff

,

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-..,n-- H C O ~

Note abrupt change between normally pressured Hackberry sandstone and high pressured Hackberry ( M a n c h e s t e r Field) sandstone

-

l

0,000

-

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1,000

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- 12,000

"

'~ 4000

....... CI

1 0 0 0

~ .....

,

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28

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3000

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241

TO OVERPRESSURES

~'"o.

r~..... :'.':o~Hackberry SS Field

- 13,000 - 14,000

i

11

, Manchester I SS r l l dlel l

1111~1

" " I

I I

I

Fig. 10-6. Changes in concentration of pore waters within sandstones and shale beds in the Hackberry and Manchester fields, Louisiana (U.S.A.). The concentrations of HCO~-, SO]-, Ca2+, Mg2+, and, K+ in sandstones are less than 10,000 mg/1 and are not shown. (This figure is based on data from Schmidt's (1975) tables 1 and 2, pp. 332-337. (Modified after Chilingarian et al., 1994, fig. 5-4, p. 116.) Additionally, sidewall cores from shales in well A-5 were leached and analyzed for major dissolved constituents. Schmidt's study showed that the compositions of pore water in shales and those in sandstones are different. His data on sandstone and shale pore-water chemistry (as given in his tables 1 and 2, respectively), have been plotted as lumped parameters in Fig. 10-6. The data reveal changes in the concentration of pore water with depth in the sandstones and shales. It should be noted that the sandstone pore-water data from the Manchester Field is only for the high-pressure zone, which lies between 11,200 ft (3400 m) and 12,900 ft (3800 m). The data from the shale sidewall cores were taken at intervals of every 500 ft (152 m) between depths of 3000 ft (914 m) and 14,000 ft (4257 m) to include normal- and high-pressure zones in the Manchester Field. There is an abrupt decrease in the concentration of various ions in the high-pressure Manchester Field. Fig. 10-6 illustrates that there is a significant difference between the

242


total dissolved solids concentrations in waters from the normally pressured sandstones and the abnormally pressured sandstones in the Hackberry Field. Concentration values range from 600 to 225,000 mg/1 in the normally pressured sandstones and from 16,000 to 49,000 mg/1 in the abnormally high-pressured sandstones. Changes in the concentrations of chloride and sodium follow the same trend as that of the total dissolved solids (C1- > Na+). The concentrations of the HCO 3, SO 2-, Ca 2+, Mg 2+, and K + in interstitial waters in sandstones are so small as compared to the concentration of other major constituents at the scale used in Fig. 10-6, that values less than 10,000 mg/1 are not plotted in the diagram. The salinity of the water in shales is lower than that in the adjacent normally pressured sandstones. The concentrations, however, were found to be more similar in the AHFP zone. It was shown that in shale pore water, the ionic concentration order is generally SO 2- > Na + > HCO 3 > CI-, whereas water in normally pressured sandstones has an opposite concentration order (Fig. 10-6). The concentrations of the Ca 2+, Mg 2+, and K + show very little variations and plot in the band mentioned above. In all cases, the salinities of pore waters in shales were found to be considerably lower than those in associated sandstones. Rieke et al. (1964) were first to point out the difference in salinity between the shale and the associated sandstone (also see Chilingar and Rieke, 1976). Osmaston (1975) in his discussion of Schmidt's (1973) field study pointed out that there are some discrepancies in Schmidt's porosity and density values. The fundamental expression showing the relationship between fractional porosity, 4~, bulk dry weight density, Pa, and grain density, pg (which was assumed to be a constant, 2.65 g/cm 3) is: Pd =

,Og(1 - - q~)

(10-2)

These porosity or density values were used to calculate the concentration of dissolved constituents in the pore water. The constituents were extracted by leaching the sidewall cores of shales. The correction factors suggested by Osmaston (1975), by which the concentration of each constituent needed to be multiplied, ranged from 0.81 to 2.19 with an average of 1.12. Apparently, the average correction factor is too insignificant to alter the main trend of change in Schmidt's concentration of dissolved constituents with depth. It is well known that the technique of extracting the dissolved pore-water constituents is replete with potential problems. Leaching will not only extract the pore-water constituents, but will remove the soluble minerals held as a solid matter in the matrix of the rock. In addition, part of the exchangeable cations, Na +, K +, Ca 2+, and Mg 2+ on the clay minerals may also go into solution. Furthermore, this technique, as reported by Morton and Land (1987b) may produce sodium- calcium-sulfate water entirely unrelated to the in-situ chemistry of pore fluids. This effect is reflected in Fig. 10-6, where it is shown that in contrast to the sandstone data, the concentration of sulfate ions is greater than, or equal to that, of the chloride ions in shales. Chilingarian et al. (1994) discussed the method of calculating the original pore chemistry from the leached extract from Schmidt's shale cores. By assuming that the pores in the shale sidewall core samples are fully occupied by pore water, the void volume is equal to the fluid volume. The leachate volume, which is not necessarily equal

POREWATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES

243

to the original pore-water volume, has to be corrected by using a dilution factor, Df. The dilution factor is equal to the leachate volume, V~, divided by the original pore-water volume, Vp" Df =

1/1 Vp

(10-3)

Inasmuch as Vp - Vbr and Vb -- W/Pd, where Vb is the bulk volume of the shale sample and W is the weight of the dry shale sample, gp -- W q~ /gd

(10-4)

and, therefore" rOd D f - - V1W r

(10-5)

In order to estimate the original concentrations of different dissolved constituents, the respective concentrations in the leachate have to be multiplied by the dilution factor. The equation for converting the leachate concentration into pore-water concentration is given by: Cpw -- C1 N Df

(10-6)

where Cpw is the concentration of a constituent in the pore water and C1 is the concentration of the same constituent in the leachate. By substituting Df from Eq. 10-5, one obtains" Dd Cpw -- C1V1 W e

(10-7)

where 1/1 is the volume of the leachate (which in the case of Schmidt's (1973) research was 50 ml). Equation 10-7 can be rewritten by substituting pg(1 - r for rOd (Eq. 10-2): Cp w _ C1 V1 tOg( 1 - ~))

we

(10-8)

Another criticism of Schmidt's (1973) study is that he did not tabulate the values of porosity or dry bulk density anywhere except in Fig. 10-6. The shale porosity values, determined directly from the density logs of the A-5 well, essentially agree with those calculated by Schmidt from the laboratory-measured densities.

Global reconnaissance Chilingar and Rieke (1976) obtained samples of undercompacted and well-compacted sidewall shale cores from various worldwide locations, and analyzed them to determine the C1- content of the pore water. Each sample was divided into two parts. The volume of pore water present in the sample was determined by drying one portion of the sample at 105~ and weighing it. The soluble salts were determined by washing the salts out four times with distilled water from a finely crushed second portion of the sample. After analyzing the washed out solution (leachate), the C1- content of pore water was determined using a correction for dilution effects (Table 10-3).

244

H.H. RIEKE,G.V. CHILINGARAND J.O. ROBERTSONJR.

TABLE 10-3 Chlorinity of pore water in associated under-compacted and well-compacted shales and sandstones from various parts of the world where overpressured formations are present (after Chilingar and Rieke, 1976, table 1, p. 676. Courtesy of Applied Publishing Co.) Number of

Depth

Chlorinity, mg/1

samples tested

(ft)

Well-compacted shales

Undercompacted shales

Associated sandstones

3/3/3 4 / 2/ 2 3 / 3/ 2 2 / 3/ 3 6/ 2/ 3 3/ 3/ 4 3/4/ 4/3/4 5 / 3/ 2 7 / 3/4 2/ 2/ 2 2/4/

2,000-3,000 3,000-4,000 4,000-5,000 5,000-6,000 6,000-7,000 7,000-8,000 8,000-9,000 10,000-11,000 11,000-12,000 12,000-13,000 13,000-14,000 14,000-15,000

3,000-4,000 2,000-3,000 1,600-3,500 1,500-3,500 3,000-6,000 4,000-8,000 10,000-20,000 2,000-3,000 2,000-3,000 1,500-3,000 2,500-4,500 10,000-14,000

8,000-20,000 10,000-30,000 10,000-40,000 9,000-35,000 8,000-10,000 5,000-9,000 10,000-14,000 8,000-14,000 8,000-14,000 10,000-14,000 -

70,000-80,000 70,000-90,000 75,000-90,000 60,000-200,000 70,000-130,000 90,000-135,000 90,000-100,000 15,000-70,000 13,000-17,000 11,000-30,000 11,000-50,000 90,000-120,000

Fig. 10-7, which is a plot of the maximum and minimum CI- values, shows that water in shales is fresher than that in associated sandstones. The results indicate that the overpressured (undercompacted) shales have higher chloride ion concentrations than that in comparable (at about the same burial depth) well-compacted shales having similar mineralogy. Pore water in the associated sandstones has higher C1- contents than those found in either type (undercompacted or well-compacted) of shales. The maximum value of CI- concentration of 200,000 mg/1 was present at 5500 ft (about 1500 m) in the sandstone samples, whereas the minimum value of 17,000 mg/1 was found at 11,500 ft (about 3500 m). At this depth, the C1- values in the sandstones approach the values in the well-compacted shale (Fig. 10-7). Below the depth of 11,500 ft, the chloride content in the sandstone samples starts to increase with depth, whereas the content in shales remained approximately the same. Owing to possible chemical reactions between the clay-sized mineral grains and water, a reduction in pore volume in argillaceous sediments under increasing pressures can best be analyzed in terms of the removal of pore water by compaction. Some of the factors that are known to influence the water content of argillaceous sediments under applied pressures are the type of clay minerals, their particle size, adsorbed cations, organic matter content, temperature, pH, Eh, and the type of electrolyte solution present in the sediment's pores. The general effects of some of these factors are presented in Fig. 10-8. With the exception of particle size, the influence of these factors is deduced mainly from laboratory compaction experiments consisting of monomineralic clay minerals mixed with simple electrolyte solutions. Vorabutr et al. (1986) measured the chlorinity of leached solutions using rapid quantab titrations from 95 shale cuttings from both well-compacted (42 samples) and

245


Chloride concentration, mg/I x 1000 0

30

|

9

0

9

'

'

I

---4-== Well c o m p a c t e d ..... ~ " "

Undercompacted

shales ( 9 value)

:

"'~"

Undercompacted

shales (max. value)

~.

! :

i

X

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~r

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: ,,,.0 .-?"

.

,

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:

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shales (max. v a l u e ]

-- al~- Associatedsandstones[min.value) ~ Associatedsandstones(max. value)

-..!.~-.--............. ..L." ..................................... , .......... /;.~.......

:

:

:

i

:

.......... -................i

i Data off scale

:'"--................ -I~ ;............................. ":"~ ~ ......................... "" X. ~!" .............................. : ..... r

---!.-l-. jl

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9 i\

]+

:

~'-"~"i"" """*

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l

:- .

..

shales ( 9 value}

:

.,-"+'"""+'"""

= ,,,.m

O" E

I

2 100

3

100

5o . .. .. ..

0

0

70

.

. . . . . . . . 60 50 40

" -

4

~

30

._,,,._~. ~ 5 ' ..... 20 10

% H20

0

1~"

4o

i~

20

E

B

2

4 L

0 200

150

-,-.-,--

1O0

50

%/-/20

Fig. 10-12. Mineralization and content of various ions in solutions squeezed out of clays. (A) Kaolinite clay: 1 -- Na +" 2 = S O ] - " 3 = C I - ' 4 -- Ca 2+" 5 = Mg 2+ (Modified after Kryukov and Zhuchkova, 1963, p. 97). (B) Bentonite: 1 = k x 104, specific conductivity of solution; 2 - Na +" 3 = C1-" 4 -- S O ] - ; 5 = M g 2+" 6 -- Ca 2+. (Modified after Kryukov and Zhuchkova, 1963, p. 38. In Chilingarian et al., 1994, fig. 5-7, p. 123.)

kg/cm2; 78.45 to 313.8 MPa), an increase in salt concentration within the remaining pore water may be caused by the inclusion of small droplets of water in the highly compressed clay, acting as a barrier to movements of ions. The passage of anions through the double layer is retarded by the fixed negative surface charges on the clay particles. Ion blocking increases ion-exchange capacity and compression of the clay. Apparently, ion blocking is greater for dilute solutions than for concentrated ones. The results of Kryukov and Zhuchkova (1963) demonstrated that the last portions of water squeezed out of sediments are poor in electrolytes (Fig. 10-12). Unfortunately this and many other Soviet studies, referenced here, did not provide pressure data, because such calibrated pressure data are very difficult to obtain in these types of experiments. According to Chilingarian and Rieke (1968), the chemistry of squeezed-out solutions begins to change appreciably when the remaining moisture content is about 20 to 25% for kaolinite and about 50 to 70% for smectite. Rieke et al. (1964) observed the percentage change in concentrations of the major cations and anions with increasing pressure for smectite clay (API No. 25) saturated with seawater. Table 10-5 and Fig. 10-13 present the results of these experiments. The data demonstrate that at each stabilized pressure, the percentage concentrations of Na +, Ca 2+, Mg 2+, CI-, and SO 2- in the expelled pore water decrease with increasing overburden pressure. Kazintsev (1968) performed experiments on the Maykop Clay (eastern Pre-Caucasus). He observed a gradual decrease in chloride concentration on squeezing a sample of this clay having an initial moisture content of 20-25%; the final moisture content after compaction was decreased to 8.83-10.88% (Fig. 10-14A).

253


T A B L E 10-5 Mineralization and content of various ions in solutions squeezed out at different pressures from smectite clay (API No. 25, Upon, WY, U S A ) saturated with seawater (after Rieke et al., 1964, table 3, p. 31) Overburden pressure

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

(psi)

C1-

100 400 1,000 3,000 10,000

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

40,000 90,000

Na +

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

Ca 2+

M g 2+

SO 2-

Total mineralization

100 75-84 67 a 50-62 . 25 a .

100 80 a 60 a . -

100 84-95 _ 67-81

100 _ -

.

. 38 a

_ 20 a

a Only one trial.

The concentrations of the dissolved constituents in the pore water were determined by squeezing Maykop Clay samples at room temperature and at 80~ Kazintsev's results (Fig. 10-14B) show that the concentration of C1- and Na + decrease with increasing pressure. The temperature does not seem to have any appreciable effect on these two constituents. The Mg ion concentration increases about 1.5 times with increasing pressure. The absolute values, however, are lower at high temperatures than at low temperatures. The concentration of K +, Li +, I-, and HCO~- were higher in solutions expelled at higher temperatures, whereas that of SO 2- was slightly lower. Krasintseva and Korunova (1968) studied the variations in chemistry of solutions expelled from unlithified Black Sea marine muds. At room temperature, the C1concentration decreased with increasing pressure, whereas the concentration of some other components went through a maximum at pressures of 500 to 1000 k g / c m 2 (49 to 98.1 MPa) (Fig. 10-15). Fig. 10-16 shows the relationship between the concentration of various ions and compaction pressure at 80~ for the same marine mud. The results further demonstrate that at a temperature of 80~ the amount of Mg 2+ is less than that at room temperature and does not change much with increasing pressure. No such behavior was noted for Ca 2+ (Fig. 10-16). Shishkina (1968) did not observe any appreciable change in the chemistry of the squeezed-out pore waters up to a pressure of 1260 k g / c m 2 (123.6 MPa) in some samples and up to a pressure of 3000 k g / c m 2 (294.2 MPa) in others from the Atlantic and Pacific oceans and from the Black Sea. There was some increase in Ca 2+ concentration at a pressure range of 675-1080 k g / c m 2 (66.2-105.9 MPa). This was followed by a decrease at higher pressures. Shishkina (1968) stated that at compaction pressures, at which 80 to 85% of pore water is expelled, there are no changes in concentration. Manheim (1966) also noted that pressures ranging from approximately 4 to 85 MPa did not appreciably affect the ion concentrations in expelled pore water. Chilingar et al. (1969) saturated two samples of smectite clay (API No. 25) with seawater and squeezed the pore waters at pressures which were raised rapidly to 5000 psi in the first case and to 10,000 psi in the second case (corresponding to about 35 and

254

H.H. RIEKE, G.V. CHILINGAR AND J.O. ROBERTSONJR.

,,,..

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40

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100

100 80

60

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20

0

0 I,i,

a_

100,000

I

I~ c r So4 2-

1

0

cO

l0,000

Overburden pressure, psi

9 I

OIO0

1,000

10,000

1 O0 000

Overburden pressure, psi

Fig. 10-13. Content of various cations and anions expelled at different overburden pressures from seawater saturated smectite clay (API No. 25, Upton, WY, USA). (Modified after Rieke et al., 1964. In Chilingarian et al., 1994, fig. 5-8, p. 124.)

70 MPa). They noted that the concentrations of the major ions in the squeezed-out pore waters increased with increasing pressures with the exception of K + (Table 10-6). This anomalous behavior was explained as follows: upon squeezing rapidly, the portion of the liquid close to the samples' discharging face is expelled at lower pressures; whereas at higher pressures the water inside the sample also has a chance to contribute, but only the more saline portion of the pore water. To further investigate this problem, Rieke (1970) performed an additional experiment in which the same clay as above was remolded with seawater to form a slurry. The slurry was allowed to hydrate for a few days and the supernatant liquid (leachate) was

255


I

600

II

,

Ill

A

,

IV

V

VI

VII

,

s00

. i

O"

2

b~

,._.,._. ~

_

1 4

0

6

8

10

12

14

16

18

20

22

Amount of solution s q u e e z e d out, g

B

mg/kg

mg-equiv./kg 34

26

7O .'

85C

~ s o : : r

650

30,

18

90, 45s

lO

50' 250

2

;o

~ / Hco,-rr}

j/

/

r .----''HB~

180, '"

14

/

ij ,/,,,f' ' .

140,

~

Jf

6

so~~-

I

~

Mg2§ )

r

_

6

%

HCO;

2

HCO

60,

M g ~*

o.,1o,, 1o i lOO 500. I

56

,14o. . . .

.........

1oo.

9

mg-equiv./kg I o.18. ,18'1 18o 900

3

6

9

i

II

iii

g

II

112

15

18

IV

v

Vl

/

20;

2

0.02

S12

g

2

20.

K~

_

-

Sr Sr01 c& +

,100,

C F+ N M g 2§

r

!

,,!

"~,v ~~

:,'~

g

Fig. 10-14. (A) Variation in chloride ion concentration in subsequent fractions (I-VII) of squeezed-out interstitial solutions of Maykop Clay, eastern Pre-Caucasus: 1 = depth of 42 m, Divnoe area; 2 -- depth of 158 m, Divnoe area. (Modified after Kazintsev, 1968, fig. 1, p. 186. In Chilingarian et al., 1994, fig. 5-9, p. 125.) (B) Changes in concentration of anions and cations and microcomponents with increasing compaction pressure in subsequent fractions (I-VII) of extruded pore waters. Maykop clay, depth of 158 m, Divnoe area, eastern Pre-Caucasus, Russia. Solid lines - room temperature; dashed lines = heated to 80~ The amount of extruded solutions in grams is plotted on the abscissa. (Modified after Kazintsev, 1968, fig. 2, p. 188. In Chilingarian et al., 1994, fig. 5-9, p. 125.)

analyzed for major dissolved constituents. The clay sample was then centrifuged and the composition of the expelled water was also analyzed. Finally, the c o m p o s i t i o n of the remaining water left in the sample was calculated. The results of this experiment are given in Table 10-7. It can be seen that the total dissolved solids of the initially squeezed-out water first increases, but the pore water left in the sample has a much lower salinity. The concentrations of both Ca 2+ and M g 2+ increased in the remaining pore water, whereas that of Na + 4- K + as well as C1- decreased. The results shown in Table 10-8 were obtained by Kazi and M o u m (1972). They performed leaching experiments on soft marine clay from Drammen, Norway, with an initial salinity of 26,700 mg/1. An undisturbed sample of this clay was confined between two porous stones and assembled into a consolidation cell. The sample was consolidated

256

H.H. RIEKE, G.V. CHILINGARAND J.O. ROBERTSONJR. g/kg

mg/kg

CI ~

mg/kg

300

50 -

50-

200

25'

25'

=

~

~

+~0.c , / B , ~

S O ~ - ~ --

"I" 100 a

0

CI/Br

B

0 Br

Ma 2L -

,.

0

~

~~-

........

HCOa

500

"1000

1500

Compaction pressure, kg/cm 2

Fig. 10-15. Relationship between the concentrations of various ions in interstitial solutions squeezed out of marine mud and compaction pressure at room temperature. (Modified after Krasintseva and Korunova, 1968, fig. 2, p. 195. In Chilingarian et al., 1994, fig. 5-10, p. 126.)

TABLE 10-6 Variation in composition of pore water squeezed out of smectite clay (No. 25, Upton, WY, USA). Composition of seawater used in saturating the sample is also given (after Chilingar et al., 1969, table 2, p.

5) Ions

Composition, ppm seawater

0-5,000 psi

0-10,000 psi

Ca 2+ Mg 2+ Na + K+ SO 2C1Total solids

380 650 10,200 390 1,350 18,000 30,970

280 17 14,400 660 7,100 19,500 41,957

720 320 17,000 610 7,600 23,600 49,850

Na/C1 Ca/C1 K/C1 Na/Ca Ca/Mg

0.5667 0.0211 0.02167 26.842 0.585

0.7385 0.0144 0.03385 51.43 16.47

0.7203 0.0305 0.02585 23.611 2.5

POREWATERCOMPACTIONCHEMISTRYAS RELATEDTO OVERPRESSURES

257

g/kg mg/kg

300 50 10

I00

0"

CI/Br Br-

0

C

l

~

Br

0

,

250

5~30

Ca~ §

750

Compaction pressure, kg/cm Fig. 10-16. Variation in the concentration of various ions in interstitial solutions expelled from marine mud with increasing pressure at 80~ (Modified after Krasintseva and Korunova, 1968, fig. 3, p. 196. In Chilingarian et al., 1994, fig. 5-11, p. 127.)

to an in-situ overburden pressure of 8.7 psi (60 MPa). De-aired distilled water, under the head of a few centimeters, was then flushed through the two porous stones. The leachate (flushed water) was collected in a measuring cylinder and analyzed for major cations (Na +, K +, Mg 2+ and Ca 2+) at regular intervals of time. After leaching, the clay was squeezed, and the salinity of the expelled pore water was measured. It was found that as a result of leaching, the salinity of the squeezed out pore water was reduced from its original value of 26,700 to 1640 mg/1. It is interesting to note that the amounts of Na + and K + extracted in the leachate are in excess of those present in the original pore water, whereas the opposite is true for Ca 2+ and Mg 2+ (Table 10-8). This led Kazi and Moum (1972) to conclude that postdepositional leaching of marine clays is manifested by the migration of high-valence cations from the pore water towards the clay mineral surface at the expense of low-valence cations, which move from the clay's surface into the pore water. Chilingarian et al. (1973) saturated a sample of smectite clay (API No. 25) in seawater for a period of seven days. The sample was shaken vigorously twice a day. Then the supernatant liquid (leachate), which was assumed to have the same composition as

258

H.H. RIEKE, G.V. CHILINGARAND J.O. ROBERTSONJR.

TABLE 10-7 Variation in the composition of the supernatant liquid and pore water centrifuged out of smectite clay (API No. 25, Upton WY, USA); the chlorinity ratios (Ca/CI, K/C1 and Na/C1) are presented along with the Na/C1 and Ca/Mg ratios (after Rieke, 1970) Ions

Composition, ppm seawater, St

(Vt = 10 ml)

supernatant liquid, S1 (V~ = 2.95 ml)

centrifuged liquid, 82 (V2 = 2.9 ml)

remaining liquid, $3 ( ~ = 4.15 ml)

remaining liquid a, $3 (V3 = 4.15 ml)

Ca 2+ Mg2+ K+ Na + SO 2C1Total solids

480 1,283 427 10,554 2,172 19,574 34,490

444 765 260 13,949 4,380 20,355 40,153

462 794 274 14,813 4,471 21,823 42,661

518.2 1,992 652.6 5,164 b 16,202 24,530

431 744 250 13,345 4,292 19,329 38,391

Na/C1 Ca/C1 K/C1 Na/C1 Ca/Mg

0.539 0.0245 0.0218 21.9 0.374

0.685 0.0218 0.0128 31.4 0.58

0.678 0.0212 0.0126 32.0 0.581

0.319 0.0320 0.0403 9.966 0.26

0.69 0.0223 0.0129 30.96 0.579

a Remaining liquid composition was calculated using the supernatant liquid as the starting fluid. b The results are not reported because the clay tested appears to have a high SO42- content.

TABLE 10-8 A summary of the chemical analyses of the major cations present in the pore water of the original (unleached) clay sample (undisturbed marine clay, Drammen, Norway) and the cations present in the leachate (after Kazi and Mourn, 1972, table 2, p. 10) Cation

Na + K+ Ca e+ Mg 2+

Cation concentration a pore water

leachate

438.73 15.66 21.93 41.78

484.57 36.85 16.15 26.46

Remarks

Na + and K + are leached in excess of that present in the pore water of the original sample, whereas the amounts of Ca 2+ and Mg 2+ in the leachate are lower than those in the original sample.

a Expressed in mg/100 g of the original dry weight of the sample.

the free pore water, was removed and analyzed. The remaining saturated sample was placed in a hydrostatic compaction cell (Sawabini et al., 1971) and the successive portions of the expelled solutions were analyzed. The final remaining moisture content was 62%, which corresponds to an overburden pressure of 35 kg/cm 2 (3.43 MPa). The results presented in Table 10-9 illustrate that the concentration of the various ions expelled at the initial stages of compaction are slightly higher than that of the original pore water present in the smectite clay saturated in seawater. As shown in Fig. 10-17, the concentration of the various anions and cations go through a maximum,

TABLE 10-9 U

Variation in the concentration of various components in solutions expelled from srnectite clay saturated with seawater (after Chilingarian et al., 1973, table 1, p. 395) Ion

Concentration, mg/l

z

82 z

0

I I

seawater

supernatant fluid Fraction No.: Cumulative volume, cm3:

ca2+ Mg2+ Na + K+ HCO, SO:C1FNO, CaC03 ~ e ~ + Mn2' Si02 B~+ Total dissolved solids

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

43 4 34,423

560 572 13,400 210 165 4,610 19,310 20 3 3,750 24 5 15 14 38,804

E

Expelled solutions

I

I1

111

IV

V

16.5

25.5

34.5

49.5

59.0

460 644 13,300 226 262 5,350 19,030 20 0 3,800 36 //.

100

//

75

.I_"

'/9 '

//

50

12I

.o_

0 25

/ |

0

. 5

/ 4 : ..> .

10

.

.

;. ; ; . , " . . : . . ; 15

.

20

25

100

Compaction Time, days Fig. 10-31. Changes in the proportions of oil and water in the expelled pore fluid with compaction time. (Modified after Aoyagi et al., 1985, fig. 2, p. 388. In Chilingarian et al., 1994, fig. 5-23, p. 141.)

concentration of the expelled water, at a certain time, depends on the surface potential and spacing of clay particles, as given by: C -

Coe -U

(I0-9)

where C is the concentration of the expelled pore water in the equilibrium solution; Co, as interpreted by Warner, is the initial electrolyte concentration in contact with clay particles, and U --

vs~ KT

(10-10)

In the latter equation, ~ is the electric potential at the midpoint between two clay plates (as calculated by Verwey and Overbeek, 1948, p. 67), v is the ion valency, s is the elementary charge of an electron, K is the Boltzman constant, and T is the absolute temperature. Warner determined experimentally the electrolyte concentration of water expelled from bentonite, illite, and kaolinite clays compacted in NaCI solutions, having approximately the same C1- content as seawater. The theoretical and experimental results agreed reasonably well for bentonite down to a void ratio of 0.5 and very well for illite down to a void ratio of 0.25. (Void ratio = volume of voids/volume of solids.) No change in concentration was observed for waters expelled from kaolinite. According to Warner, the packing of particles is such that the platy surfaces of most of the kaolinite particles probably did not approach each other at a spacing equivalent to their combined double-layer thickness (about 8 ,& in 0.55 NaC1 solution). Warner (1964)

275


10,000 -

E

\

C). CL cO ,m,,,

1000

~

"'"'~'--x k

\" Na +

-

\

0

~

t~,,,,2 +

~%~'

C}.

E

~.

0

0 0 0

,CI

100 "

\..

-'---e h A _ 2 +

S.

"~-.-,...,,

~'~..~/

_e , / +

..,(," ./ \ ~

%

E (b

\ SO4 2

r

(,9 seo ~oter

i

Compaction

1'2

2~,

time, d a y s

Fig. 10-32. Changes in cation contents of expelled water with time. Composition of seawater is also shown for comparison. (Modified after Aoyagi et al., 1985, fig. 3, p. 388. In Chilingarian et al., 1994, fig. 5-24, p. 142.)

calculated that even at a pressure of 60,000 psi (400 MPa), the platy surfaces of the kaolinite particles in 0.55 NaC1 solutions would still be separated by 90/k. Knill et al. (1976) obtained similar results for kaolinite clay hydrated in seawater and compacted up to 5000 psi (35 MPa) (Fig. 10-25). When the same data are replotted with composition expressed as a percentage of the initial concentration, however, then there is a distinct change in the concentration of expelled pore water with increasing pressure (Fig. 10-26). Wijeyesekera and de Freitas (1976) reported similar findings.

Kotova and Pavlov's empirical model Using Kotova and Pavlov's model, it is possible to calculate the concentration of dissolved constituents remaining in the pore water of the compacted sediments (Kotova and Pavlov, 1968). Their numerical model is as follows: C--Co

1

e p

(10-11)

where C is the ion concentration of pore water at a pressure p, Co is the initial ion concentration of pore water at p = O, and )~ and n are constants, the values of which depend on the physicochemical and geological conditions. In their experiments, )~ was

276

H.H. R I E K E , G.V. C H I L I N G A R A N D J.O. R O B E R T S O N JR.

A ~xxxxxxx'~xxx'

:::-

~xxx xxxxxx xx

q

r _..L_

~' ,' , X X X

L L" I X X X X ~ k X ' X X X X X X X X X X X X X X X X X V

=

t

' tm

~_

~

1 | 1 - - - -

1 ~ i ~ . ~ - - - ~

~

"

-

r __.i._.

.~XXXXXXXXXXN2~XXXXXXX,XXXXXXXXXXXXXXXXXXXXXXX'~

C , . . . . .

. . . . . . . limit r = 0

.

tZZZI|||||||||| .

.

.

.

.

.

.

.

.

.

.

.

.

Fig. 10-33. Behavior of electrolyte solutions in a capillary having radius r. (A) Distribution of interstitial fluid density; maximum density occurs at the capillary walls. (B) Distribution of the dissolving capacity of interstitial fluid; maximum dissolving capacity is at the center. (C) Compaction of the capillary by a force F, illustrating that the part of the fluid squeezed out first is the one with the highest dissolving capacity (maximum salinity). (Modified after Chilingarian et al., 1994, fig. 5-25, p. 113.) equal to 4.0 to 4.45 and n was equal to 0.097 to 0. l l 6. An excellent agreement was obtained between the measured and the calculated results (Rieke and Chilingarian, 1974, fig. 133, p. 246). This model has an inherent difficulty in predicting the composition of the non-expelled (held) pore water, inasmuch as ~, and n have to be obtained from the best-fit curve.

Pol'ster's capillary model The conceptual ambient temperature model of Pol'ster et al. (1967) provides an explanation for the gradual decrease in the concentration of squeezed-out pore waters as demonstrated in Fig. 10-33. Capillaries represent the voids in the argillaceous sediment. In saturated sediments, the density of water next to the capillary walls is maximum, whereas along the center part of the capillary the density is lowest and approaches a normal value of one if the capillary radius is large enough. Martin (1960, p. 32) stated


277

that the density of adsorbed water of Na-smectite varies with the amount of water present in the clay. The highest densities of adsorbed water occur when the HzO/clay weight ratio for Na-smectite is less than 0.5. The highest density values range up to 1.5, as reported by DeWit and Arens (1950), Mooney et al. (1951), and Mackenzie (1958). The low-density values are slightly lower than one (1) as reported by Norrish (1954), Anderson and Low (1958), and Cebell and Chilingarian (1972). The dissolving capacity of water is inversely proportional to density (Fig. 10-33B). As the capillary is squeezed during compaction, its radius is decreased and the water expelled first will be the least bound, which is the more saline water close to the center of the capillary. The results obtained by Chilingar and Rieke (1976) show that the total concentration of expelled solutions goes through a maximum before starting to decrease with increasing overburden pressure. The remaining adsorbed water poor in electrolytes is expelled at higher overburden pressures until the concentrations of Mg 2+ and Ca 2+ ions start to increase. This can be attributed, in these experiments at ambient temperature, to the higher concentration of these ions in the water in close vicinity to the clay platelets. Rieke and Chilingarian (1974) used this model to explain the relative salinities of interstitial waters in well-compacted and undercompacted shales and their associated sandstones, as shown in Fig. 10-34. Although a very simple model, it explains some of the ambient-temperature, experimental results reported in this chapter.

Thermodynamic approach Thermodynamic models combine the concepts of electrochemical equilibrium and electroneutrality in compacting sediments. They are elaborate in determining the effects of decreasing porosity (or void ratio) on the concentration of squeezed-out pore water and the remaining pore water held in the sediments.

Bolt's pressurefiltrate model The model of Bolt (1961) is based on the way the cationic and anionic concentrations vary in the vicinity of a charged clay particle. The model is applicable to a symmetric electrolyte, such as NaC1 held in sediments with infinite initial void ratios (dilute solutions). The concentration, C, expressed in equivalents of ions per unit of fluid volume (mequiv/cm 3) of the expelled pore water is: C =

4Cok

(10-12)

(1 + k) 2

where k is the ratio of the negative-ion concentration toward the middle of the pores divided by C, and k is presumed to vary from unity to zero during compaction (Smith, 1977). Co is the initial concentration of solution in equilibrium with the clay in mequiv/cm 3. The void ratio of the compacting clay is expressed as: e--

(l+k)

1+ 1-k

qpmax

(10-13)

4Co

where e is the void ratio, q is the cation exchange capacity expressed in mequiv/g, and Pmax is the matrix density in g/cm 3. Elimination of k between Eqs. 10-12 and 10-13

Well compacted

S3

Enlarged view of shale capillary

Undercompacted (overpressured)

------------------_ -------------------------------- - - ----------------- - -- - ------- -Shale

-------------------------------------------------------------------

Fig. 10-34. Relative salinities of interstitial fluids in well-compacted and undercompacted (overpressured) shales. Arrows show direction of flow and velocity profile in an enlarged view of a capillary in a vertical direction. S = salinity. (Modified after Rieke and Chilingarian, 1974, fig. 9, p. 25. In Chilingarian et al., 1994, fig. 5-26, p. 143.)

279

PORE WATERCOMPACTION CHEMISTRY AS RELATEDTO OVERPRESSURES

Initial Stage /

~

II

II

II

~CI il

1

=

mll

I

,,m~-.ll"l. q l ~ . , l l ' l , a l ' L - a l l ~ t

1

mci + x

J

==-X==4-.:,m C I ~"--~- .m Na~-~ =-----------,

----------

-=-_---~--_---L ~

C I =_----_---'~. Na---_.~ --. --- -------:.---:

Su pe rnat a n t

mci

~.E~s~ .~ ~~ sTo~~---=_---=." ~

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

:-_ _

x

1-_so Vo

--

=

=

_,

mci

xo

Phase I1'

. . . . . . . . .

.....

i,

System requirements

1. Electroneutrality Phase I 9

Na

Supernatant

=-=- -- -- -----

'

II

z--.=~_-_zSusp-e~~To~---_--_----So,Vo

l

~ Na

mci l'lll'~l" ~

Next stage /

Compactionn ~

f

x

-

-

V

VoXo

V

ii = mNa

2. E l e c t r o c h e m i c a l e q u i l i b r i u m Electrochemical potential I

, _ _s _

mll Cl

I

= m Na

II

Electrochemical potential I

~Na

--

II ~Na

Fig. 10-35. Basic concept of Appelo's model; m = ion concentration, # = electrochemical potential. (Modified after Chilingarian et al., 1994, fig. 5-27, p. 145.)

gives the following relationship (Smith, 1977)" C-~

2Co-

(max 2e ) 1 2Co

(10-14)

Appelo's Donnan equilibrium model Appelo (1977) considered the compaction of a Donnanian suspension consisting of a clay hydrated in the NaC1 solution. The conceptual model, which is presented in Fig. 10-35, after satisfying the electrochemical equilibrium and electroneutrality requirements, is represented by the following equation: m~l =

(VNaYC1)I (X + m ~ l ) m ~ l (~]NaYC1) II

(10-15)

where, as shown in Fig. 10-35, the superscript I (phase I) represents the suspension and the superscript II (phase II) denotes the expelled pore water. YNa is the activity coefficient of the sodium ion, YCl is the activity coefficient of the chloride ion, and x is the cation exchange capacity parameter of the clay expressed in equivalents per liter of the suspension, mI1 is the concentration of chloride ion expressed in equiv/1 of the suspension and m~l is the concentration of chloride ion expressed in equiv/1 of the expelled pore water. Fig. 10-35 shows that with an initial suspension volume Vo in liters and the chloride ion content So in equivalents, the initial concentration of the suspension is

280

H.H. RIEKE, G.V. CHILINGARAND J.O. ROBERTSONJR.

m -- s o / V o . The compaction of the suspension from Vo to V (at any time) will change

the concentration of chloride in the suspension to s / V , and the initial cation-exchange parameter Xo will change to x - V o x o / V . As a result of compaction, the concentration of the chloride ion in the squeezed-out pore water will be given by: m~l-

f [s(s ~-

+ Voxo)] 1/2

(10-16)

where f is defined as the square root of the product of the sodium and chloride ion activity coefficients in the suspension to that in the expelled pore water, as expressed below: (yN~YCl)II

gll 4- NaC1

(10-17)

Appelo (1977) applied Eq. 10-16 to two distinct cases: the infinitesimal equilibration case and the mass-balance case. The infinitesimal equilibration case, which applies to drop-wise removal of the squeezed-out pore water from the suspension, has two conditions, which are important to comprehending laboratory-simulated pore-water expulsion experiments. The first condition of the infinitesimal equilibration case examines the concentration of the pore water held in the compacted clay suspension, m~l -- s / V , at different times. Under these conditions, s is given by: s --

o4 oE( l .rexp(y) +

-.re x p ( - y ) -2 ]

(10-18)

where y -- arc c o s h ( ~2S,~ + 1). The second condition considers the concentration of the expelled pore water, m~l = d s / d V , at different times. Under these conditions m~l is expressed as: mc~ =

4V

exp(y) -

exp(-y)

(10-19)

The mass-balance case, which is applicable to field conditions, explains the compaction of a clay-rich layer sandwiched between permeable sandy layers. As in the first case, there are two conditions. The first condition of the mass-balance case applies to the concentration of pore water held in a compacted clay suspension, mI~l - s~ V , at different times. Under these conditions, s is given by"

S

/E

~

21_(

1

1 (10-20)

_

_2so+

1

_4s:

281

PORE WATERCOMPACTIONCHEMISTRY AS RELATEDTO OVERPRESSURES

0.6 m

0 E

oE

m

0

Xo = 0 . 5 So = 0.25

0.4-

......

_

~ ~ ~

jmcl

0.2

0

0L5

Volume of suspension, I

1

Fig. 10-36. The relationship between the chloride ion concentration and the volume of the suspension. The concentration of chloride inside the suspension is given by the solid line curve, whereas that of the squeezed-out liquid is shown by a dashed line; Xo -- initial cation exchange capacity expressed in equivalents per liter, so = chlorine ion content in equiv.; f = the square root of the ratio of activity coefficients inside and outside the suspension. (Modified after Appelo, 1977, fig. 5, p. 96. In Chilingarian et al., 1994, fig. 5-28, p. 147.)

The second condition of the mass-balance case considers the cumulative concentration of the expelled pore water squeezed from the suspension at the end of compaction. At this stage, there is no more reduction in porosity taking place, and the cumulative concentration of the chloride ion at any overburden pressure is: So - s (10-21) m~l= V0- V where the value of s is obtained from Eq. 10-20. Appelo (1977) plotted the last two equations (Eqs. 10-20 and 10-21) to express the variation in the concentration of the chloride ion inside the suspension and in the squeezed-out pore water as a function of the suspension volume (Fig. 10-36). In construction of Fig. 10-36, Appelo used arbitrary values of x = 0.5 and So = 0.25 for two different f values of 1 and 0.52. His plotted results confirm that the chloride ion concentration in the suspension decreases upon compaction for the two selected values of f . In the case of squeezed-out pore water, however, the concentration of the chloride ions decreases with compaction when f = 1. On the other hand, when f = 0.52, the concentration of chloride ions first increases and then decreases to a limiting value at which the porosity is the only governing factor that determines the chloride ion concentration. This is in agreement with the data presented in Von Engelhardt and Gaida (1963), Rieke and Chilingarian (1974), Knill et al. (1976), and Rosenbaum (1976).

Smith's Gibbs equilibrium model Smith's (1977) thermodynamic model is similar to Appelo's in many respects. In deriving his equations, however, Smith assumed that the ratio of activity coefficients

282


of dissolved constituents both inside and outside the clay suspension is unity ( f = 1). Furthermore, in Smith's case, the concentration of either negative or positive ions is expressed as a fraction of pore volume rather than concentration per unit of bulk volume. An additional assumption is that there is no association between cations and negatively charged clay particles. A complete association would eliminate the cation-exchange capacity, such that the concentration of ions, both inside and outside the suspension, would not change with decreasing porosity. Partial association, therefore, would be expected to reduce or delay changes in these concentrations. Realizing this, Smith extended his model to include the case in which the cations are partially associated with exchange sites on the negatively charged particles. Smith (1977) compared his experimental data, for the infinitesimal equilibration case, with equations describing his, Appelo's (1977), and Bolt's (1961) models. The plotted data show the variation between porosity and salinity of squeezed-out pore water from smectite clay (Smith, 1977, fig. 6, p. 384). Neither Bolt's nor Smith's equation gives good agreement with the experimental results. The trends predicted by these two models deviate from the experimental results with decreasing porosity. At high values of porosity, the three models (Appelo, Bolt and Smith) all are in good agreement with the experimental data.

ISOTOPE STUDIES OF I N T E R S T I T I A L F L U I D S

Aside from the ion concentrations, the stable isotopic composition of water is another parameter to characterize pore waters. Deuterium and oxygen-18 concentrations in meteoric surface waters vary by about 43 and 5.6%, respectively, and are linearly related (Degens and Chilingar, 1967). A comparison of the 180/160 and D/H2 ratios shows that atmospheric precipitations normally follow a Rayleigh process at liquidvapor equilibrium. The Raleigh process explains why with higher altitudes and latitudes fresh waters become progressively lighter, whereas tropical samples show very small depletions relative to mean ocean water. In contrast to meteoric waters, ocean waters are isotopically heavy and fall within a narrow range of 1 and 0.1% for deuterium and oxygen-18, respectively. Evaporation strongly affects the 180/160 and D/H2 ratios by causing a preferential depletion in the lighter isotopes ~H and 160, which are concentrated in the vapor phase. The remaining water will be heavier, and the D and 180 contents will show a relative increase.

Geological observations and evaluation Degens and Chilingar (1967) pointed out that hydrochemical field evidence by Knetsch et al. (1963) showed that in the Nubian Series aquifer in the western Egyptian Desert the oxygen isotopes were not fractionated during subsurface transportation over a distance of 700 miles and at a depth range of 500-2000 ft. The oxygen isotope ratios of the water samples taken at intervals of 20-100 miles stayed within 1%o, whereas the chemical composition fluctuated strongly in response to migration and diagenesis.

PORE WATERCOMPACTION CHEMISTRY AS RELATEDTO OVERPRESSURES

283

Degens et al. (1964) reported on the analyses of the oxygen isotope composition of pore waters ranging in age from the Cambrian to the Tertiary. The results presented by them show that the 3180 values in the highly saline pore waters do not deviate appreciably from the 3180 of present-day ocean water (~ = %0 deviation relative to the Chicago Belemnite standard). Deviations from this mean value in pore waters into the negative range of ~lSo, from Cambrian-Ordovician, Devonian, and Pennsylvanian age formations in Oklahoma, U.S.A., are always well correlated to a decrease in salinity. This was explained by Degens and Chilingar (1967) as the effect of dilution with meteoric waters during migration of the pore water, or by later-stage infiltrations as a result of uplift, denudation, or other geological phenomena. This similarity between the isotope characteristics of the pore water and present seawater leads to the conclusion that the concentration of the inorganic salts has not been accomplished by syngenetic evaporation. Possible explanations are that it is an effect of compaction or ion-filtration by charged net clay membranes, or both. Coplen and Hanshaw (1973) found that when water is forced through a compacted Na-smectite disc it was depleted in D by 2.5% and in lSO relative to the water left behind the disc. The enrichment in D of residual waters closely follows a Rayleigh distillation curve, which results in the enrichment in deuterium in the residual pore water if a large proportion of the water has been transmitted through the clay membrane. Any slight deviations into the positive range of ~lSo values in the samples could be caused by original evaporation in a surface environment, or by isotope equilibration with the surrounding mineral matter for millions of years.

Isotope studies of shales in the Gulf Coast Yeh and Savin (1977) measured t h e 1 8 0 / 1 6 0 ratios of size-separated clays from Gulf Coast shales buried at depths ranging from 1000 to 18,400 ft in three wells. Their O-isotope results showed that the sediments are not isotopically equilibrated systems even for those buried at depths where the temperatures are around 338~ (170~ The finer fractions of both clay minerals and quartz are richer in lSo than the coarser fractions. The values of ISo for the 0, if -- > (Pa - Pn) A

(12-57)

(12-58)

(12-59)

MATHEMATICAL MODELING OF ABNORMALLY HIGH FORMATION PRESSURES

333

In the first case (Eq. 12-57), the abnormal formation pressure decreases. In the second case (Eq. 12-58), abnormal pressure can be kept at the same level for infinite time. In the third case (Eq. 12-59), the formation pressure increases. The first derivative of the formation pressure (Eq. 12-56) determines the rate of change of formation pressure in time. In all cases, this rate converges to zero with time tending to infinity. The relaxation coefficient A determines the rate of change of the abnormal component of pressure. The bigger the value of relaxation coefficient, the faster the rate of change of formation pressure in time approaches zero.

Criterion for the type of time-dependent variation offormation pressure Eqs. 12-57 to 12-59 define the type of time-dependent variation of formation pressure and show whether the formation pressure will increase in time or will drop to the hydrostatic level. According to Eqs. 12-52 and 12-53, the key parameter B/A is equal to:

O Ahr[Aqv--

G~]

If the assumption kr Go

Origin and Prediction of Abnormal Formation Pressures

Origin and Prediction of Abnormal Formation Pressures (Developments in Petroleum Science)

Origin and Prediction of Abnormal Formation Pressures (Developments in Petroleum Science)

Abnormal Formation Pressures (Developments in Petroleum Science)

Studies in Abnormal Pressures 38

Abnormal Experience and Abnormal Belief

Essentials of Abnormal Psychology

Abnormal and Clinical Psychology

Abnormal and Clinical Psychology

Abnormal and Clinical Psychology

Fundamentals of Abnormal Psychology

Prediction

Abnormal Psychology

Formation and Logic of Quantum Mechanics: Formation of Atomic Models

Abnormal Psychology

Abnormal Psychology

Abnormal psychology

Abnormal Psychology

Inference, Explanation, and Prediction

Prediction, Learning, and Games

Abnormal Psychology

Formation and Evolution of Exoplanets

Abnormal Psychology

Abnormal Psychology

Explanation, Prediction, and Confirmation

Causation, Prediction, and Search

Abnormal Psychology and Modern Life

Prediction of polymer properties

Reason and Prediction

Prediction, Learning, and Games

Origin and Prediction of Abnormal Formation Pressures