Hydrocarbon Seals

Norwegian Petroleum Society (NPF), Special Publication No. 7 Hydrocarbon Seals Importance for Exploration and Product...

Author: Moller-Pedersen P. | Koestler A.G.

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Norwegian Petroleum Society (NPF), Special Publication No. 7

Hydrocarbon Seals

Importance for Exploration and Production

Further titles in the series:

1. R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleraas (Editors) STRUCTURAL AND TECTONIC MODELLING AND ITS APPLICATION TO PETROLEUM GEOLOGY- Proceedings of Norwegian Petroleum Society Workshop, 18-20 October 1989, Stavanger, Norway 2. T.O. Vorren, E. Bergsager, Q.A. DahI-Stamnes, E. Holter, B. Johansen, E. Lie and T.B. Lund (Editors) ARCTIC GEOLOGY AND PETROLEUM POTENTIAL- Proceedings of the Norwegian Petroleum Society Conference, 15-17 August 1990, Tromso, Norway 3. A.G. Dorb et al. (Editors) BASIN MODELLING" ADVANCES AND APPLICATIONS - Proceedings of the Norwegian Petroleum Society Conference, 13-15 March 1991, Stavanger, Norway

4. S. Hanslien (Editor) PETROLEUM" EXPLORATION AND EXPLOITATION IN NORWAYProceedings of the Norwegian Petroleum Society Conference, 9-11 December 1991, Stavanger, Norway 5. R.J. Steel, V.L. Felt, E.P. Johannesson and C Mathieu (Editors) SEQUENCE STRATIGRAPHY ON THE NORTHWEST EUROPEAN MARGIN Proceedings of the Norwegian Petroleum Society Conference, 1-3 February, 1993, Stavanger, Norway

6. A.G. Dor~, R. Sinding-Larsen (Editors) QUANTIFICATION AND PREDICTION OF HYDROCARBON RESOURCESProceedings of the Norwegian Petroleum Society Conference, 6-8 December, 1993, Stavanger, Norway

N o r w e g i a n P e t r o l e u m S o c i e t y (NPF), S p e c i a l P u b l i c a t i o n No. 7

Hydrocarbon Seals

Importance for Exploration and Production Edited by

Dr. P. Moller-Pedersen

Norwegian Petroleum Society, Lervigsveien 32, Postboks 547, N-4001 Stavanger, Norway and

Dr. A.G. Koestler

Geo-Recon S/S, Munkedamsveien 59, N-0270 Oslo, Norway

1997 ELSEVIER Amsterdam - Lausanne - New Y o r k - Oxford - Shannon - Singapore - Tokyo

ELSEVIER SCIENCE (Singapore) Pte Ltd No. 1 Temasek Avenue, #17-01 Millenia Tower Singapore 039192

ISBN: 0-444-82825-7 91997 Elsevier Science (Singapore) Pte Ltd. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior written permission of the publisher, Elsevier Science (Singapore) Pte Ltd. Copyright & Permissions, No. 1 Temasek Avenue, #17-01 Millenia Tower, Singapore 039192. Special regulations for readers in the U S A - This publication has been registered with the Copyright Clearance Center Inc. (CCC), 222 Rosewood Drive, Danvers, MA 01923. Information can be obtained from the CCC about conditions under which photocopies of parts of this publication may be made in the USA. All other copyright questions, including photocopying outside of the USA, should be referred to the copyright owner, Elsevier Science (Singapore) Pte Ltd., unless otherwise specified. No responsibility is assumed by the publisher for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions or ideas contained in the material herein. This book is printed on acid-free paper. Printed in The Netherlands.

Preface

In January 1996 a total of 270 conference participants gathered for 3 days in Trondheim, Norway, to focus on and to discuss the complex topic of hydrocarbon seals particularly related to deformation zones and to caprocks. All together 32 oral papers and 9 poster were presented. There was also a plenary discussion and informal gatherings. The conference was the first in Norway and one of the first in Europe to exclusively address this very important subject. The purposes of the conference were to present some of the most recent research results, to establish state-of-the-art with respect to understanding hydrocarbon seals and to discuss where to go from here to find some of the keys to successful future exploration and enhanced oil and gas recovery. Out of the presented papers and posters, 17 are compiled and published in this volume. These provide a good overview of and an introduction to the numerous aspects covered during the fruitful days in Trondheim. In the introductory paper by K.J. Weber, a wide-ranging and well illustrated historical overview, the development of theories and methods to predict and quantify trapping mechanisms is presented. The paper covers the period from the early days of the oil business around 1850 up to now and it contains a significant amount of previously unpublished historic material. The section on fault seals comprises a total of 10 papers ranging from case studies to in-depth studies of specific sealing mechanisms. R.J. Knipe et al. provide an introduction to fault seals and processes, describe how properties and evolution of seals within fault zones can be evaluated and suggest ways forward to improve fault seal risk evaluation. F.K. Lehner and W.F Pilaar document some previously unpublished observations from a study of clay smears in synsedimentary normal faults displayed in lignite mines at Frechen in Germany. Although several earlier studies covered these beautiful outcrops, a new approach to the well documented observations confirm that substantial clay smears can occur if ductile shale source beds are faulted at slow displacement rates. J.R. Fulljames with co-authors present a method to systematically analyse fault seals and to quantitatively approach the prediction of two types of fault seals, namely juxtaposition seals and fault gouge seals. C. Childs et al. provide a description of the complexity of fault zones based on outcrop studies. They outline a model for the development of the complex internal structures which seem to be important for the evaluation of the sealing potential. The way forward in fault seal prediction is in the authors' opinion by refinement of current empirical and comparative methods through more detailed characterisation of sub-surface faults. A study of fracture systems and rock mechanical properties of the cap rocks of the Late Jurassic Fuglen and Hekkingen Formations in the south-western Barents Sea, Norway, is presented by R.H. Gabrielsen and O.S. Klcvjan. They propose that leakage of hydrocarbons to the surface caused by the Tertiary uplift and erosion could be related to one of four fracture groups associated with major fault zones. To predict deformation mechanisms and cementation of faults in sandstones, E. Sverdrup and K. BjCrlykke developed models by studying cores and outcrops. Timing of faulting relative to the diagenetic processes is critical and fault characteristics and cementation can be predicted by relating fault episodes to the diagenetic history of the basin. T. Fristad et al. describe a methodology to predict fault-seal behaviour from analysis of a detailed depth model in conjunction with detailed lithological mapping. The case study concentrates on the Oseberg area in the North Viking Graben, Norway. Another case study done by A.I. Welbon et al. documents a fault seal analysis of the Greater Heidrun area in Mid-Norway. The study assesses the control of fault seal on migration, trap integrity and filling history, which serves as a basis for assessment of risk parameters for exploration prospects and their subsequent ranking. A. Makurat et al. present results from laboratory tests to study flow behaviour associated with fractures. They conclude that five factors in addition to the fracture orientation affect the flow along and across fractures. These are uniaxial compressive strength, permeability and porosity of the intact rock, fracture roughness, shear displacement and the ratio between effective

vi

Preface

stress on the fracture and the compressive strength of the intact rock. T.R. Harper and E.R. Lundin review the predictability of juxtaposition and deformation seals, describe the mechanisms of shear bands and clay smear, estimate the sealing capacity of shear bands and assess the influence of presentday stress on the sealing capacity of faults. G.M. Ingram and M.A. Naylor introduce the section on migration and top seal integrity totalling 6 papers by presenting an approach to top seal assessment. They review the physics of capillary sealing and flow barriers, discuss static versus dynamic sealing and present a technique for assessing the effect of sub-seismic fault populations within the top seal. A model for gas migration is developed by D. Kettel based on history matches of gas flow by diffusion and Darcy flow through nine known gas fields sealed by salt. The model can be used to derive permeability/depth functions for rock salt that may be used in the prediction of the degree of gas fill for a prospect. N.C. Dutta describes a technique to predict pore pressure before drilling based on seismic velocity data. Examples from deep water areas of the Gulf of Mexico are shown. The technique allows seal failure risk assessment for prospects. R. Olstad et al. has studied the porewater flow and petroleum migration in the SmCrbukk area, Norway. They found that a major sealing fault zone has affected lateral migration and has caused the development of high overpressure cells. The authors conclude that petroleum migration cannot be inferred from the pressure distribution because the permeability changes continuously due to diagenetic processes. The Njord Field, Norway, is an interesting case of reservoir compartmentalization as demonstrated by T. Lilleng and R. Gundesr Formation pressure data confirms the presence of sealing faults creating hydraulic compartments. A dynamic model of active hydrocarbon migration coupled with vertical leakage through breaching of the reservoir top seal is discussed. D.M. Hall et al. review the processes for top seal failure in the greater Ekofisk area, Norway. There is no evidence that a significant amount of leakage has occurred as a result of hydraulic breaching, tectonic breaching or capillary leakage. The authors argue that pressure-inhibit charge is an alternative explanation for the limited extent of the hydrocarbon columns in some structures. The editors hope that this volume will make a contribution towards a better understanding of hydrocarbon seals and that it may stimulate further research and studies. The aim would be to improve understanding and promote proper application for the numerous cases where sealing prediction might be the key for enhanced recovery or more effective exploration. We would like to thank all the contributors for their interest in the topic and their cooperation during the preparation of this volume. The important work done by reviewers of the papers is highly acknowledged. Thanks are given to NPF, who made this conference possible. Finally, we would like to encourage further research within this field of geology and engineering to make creative steps towards unraveling the true potential of seal evaluation and predictions to improve hydrocarbon exploration and production. Per MOller-Pedersen The Norwegian Oil Industry Association, P.O. Box 547, N-4001 Stavanger, Norway Andreas G. Koestler Geo-Recon A/S, Munkedamsveien 59, N-0270 Oslo, Norway

vii

List of Contributors

L. BACKER

Norwegian Technical Institute, P.O. Box 3930 Ullevaal Hageby, Sognsveien 72, N-0806 Oslo, Norway

A. BEACH

Alastair Beach Associates Ltd., 11 Royal Exchange Square, Glasgow, G1 3AJ, UK

K. BJORLYKKE

Department of Geology, University of Oslo, P.O. Box 1047, N-0316 Oslo, Norway

P.J. BROCKBANK

Alastair Beach Associates Ltd., 11 Royal Exchange Square, Glasgow, G1 3AJ, UK

C. CHILDS

Fault Analysis Group, Department of Earth Sciences, University of Liverpool Liverpool L69 3BX, UK

M.R. CLENNELL

Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK

B.A. DUFF

PetroFina sa, Rue de l'industrie 52, B-1040 Bruxelles, Belgium

N.C. DUTTA

BP Exploration Inc., 200 Westlake Park Boulevard, Houston, TX 77079, USA

M. ELIAS

Fina Italiana, Viale Premuda 27, 1-20129, Milano, Italy

A.B. FARMER


Q.J. FISHER


O. FJELD

Phillips Petroleum Company Norway, P.O. Box 220, 4056 Tananger, Norway

R.C.M.W. FRANSSEN

Shell Oil Company, OPA, P.O. Box 4704, Houston, TX 77210-4704, USA

B. FREEMAN

Badley Earth Sciences Ltd., North Beck House, North Beck Lane, Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK

T. FRISTAD

Norsk Hydro, P.O. Box 200, N-1321 Stabekk, Norway

J.R. FULLJAMES

Shell International Exploration & Production BV., P.O. Box 60, 2280 AB Rijswijk, The Netherlands

R.H. GABRIELSEN

Department of Geology, University of Bergen, All~gaten 41, N-5007 Bergen, Norway

A. GROTH

Norsk Hydro, P.O. Box 200, N-1321 Stabekk, Norway

R. GUNDESO

Norsk Hydro Produksjon a.s., N-5020 Bergen, Norway

M. GUTIERREZ


S.R. GYTRI

Fina Exploration Norway, SkOgstostraen, P.O. Box 4055, Stavanger, Norway

D.M. HALL

PetroFina sa, Rue de l'industrie 52, B-1040 Bruxelles, Belgium

viii


T.R. H A R P E R

Geosphere Ltd., Netherton Farm, Sheepwash, Beaworthy, Devon EX21 5PL, UK

A. HARRISON


G.M. INGRAM

Shell International Exploration and Production, Research & Technical Services, P.O. Box 60, 2280 AB Rijswijk, The Netherlands

G. JONES


D.A. KARLSEN

Department of Geology, University of Oslo, P.O. Box 1047, N-0316 Oslo, Norway

D. KETTEL

Kettel Consultants, Ch~tellon de Cornelle, 01640 Boyeux St. Jgr6me, France

B. KIDD


O.S. KLOVJAN

Norsk Hydro U&P Research Centre, N-5020 Bergen, Norway

R.J. KNIPE


S.D. KNOTT

3 Creagbat Avenue, Quarriers Village, Bridge of Wear, UK

F.K. LEHNER

Institute for Geodynamics, Bonn University, Nussalle 8, D-53115 Bonn, Germany

T. LILLENG

Norsk Hydro Produksjon a.s., N-5020 Bergen, Norway

E.R. LUNDIN

Statoil Research Centre, Postuttak, 7005 Trondheim, Norway

A. M A K U R A T


E. MCALLISTER


M.A. NAYLOR

Petroleum Development Oman LLC, PDO Office, Mina al Fahal, Muscat, Oman

R. OLSTAD

Esso Norway AS, PO Box 60, N-4033 Forus, Norway

T. P E D E R S E N

Conoco Norway Inc., Randberg, PO Box 488, N-4001 Stavanger, Norway

W.F. PILAAR

J.F. Kennedy plantsoen 63, 2252 EV Voorschoten, The Netherlands

J.R. PORTER


E. SVERDRUP

Saga Petroleum as, P.O. Box 490, N-1301 Sandvika, Norway

S. THOMAS

Statoil a.s., 4035 Stavanger, Norway

J.L. URAI

Geologie-Endogene Dynamik, RWTH Aachen, Lochnerstrasse4-20, D52056 Aachen, Germany

J.J. W A L S H

Fault Analysis Group, Department of Earth Sciences, University of Liverpool Liverpool, L69 3BX, UK

J. W A T T E R S O N

Fault Analysis Group, Department of Earth Sciences, University of Liverpool, Liverpool, L69 3BX, UK

K.J. W E B E R

Faculty of Applied Earth Sciences, Delft University of Technology, P.O. Box 5028, 2600 GA Delft, The Netherlands


ix

A.I. W E L B O N

Alastair Beach Associates Ltd., 11 Royal Exchange Square, Glasgow, G1 3A J, UK (now at Statoil a.s., Stavanger, Norway)

E.A. W H I T E

Rock Deformation Research Group, Department of Earth Sciences, Uni, versity of Leeds, Leeds, LS2 9JT, UK

G. YIELDING

Badley Earth Sciences Ltd., North Beck House, North Beck Lane, Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK

L.J.J. ZIJERVELD

21 Oxford Street, Edinburgh EH8 9PQ, UK

This Page Intentionally Left Blank

Contents

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

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

,

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

v vii

A historical overview of the efforts to predict and quantify hydrocarbon trapping features in the exploration phase and in field development planning ............................................................. K.J. Weber

I. Fault Seals Fault seal analysis: successful methodologies, application and future directions ............................ R.J. Knipe, Q.J. Fisher, G. Jones, M.R. Clennell, A.B. Farmer, A. Harrison, B. Kidd, E. McAllister, J.R. Porter and E.A. White

15

The emplacement of clay smears in synsedimentary normal faults: inferences from field observations near Frechen, Germany ...................................................................................... F.K. Lehner and W.F. Pilaar

39

Fault seal processes: systematic analysis of fault seals over geological and production time scales J.R. Fulljames, L.J.J. Zijerveld and R.C.M.W. Franssen

51

Complexity in fault zone structure and implications for fault seal prediction .................................. C. Childs, J.J. Walsh and J. Watterson

61

Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties ...................................................................................................... Roy H. Gabrielsen and OddbjCrn S. KlCvjan

73

Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models .............................................................................................. E. Sverdrup and K. BjCrlykke

91

Quantitative fault seal prediction: a case study from Oseberg Syd .................................................. T. Fristad, A. Groth, G. Yielding and B. Freeman

107

Fault seal analysis in hydrocarbon exploration and appraisal: examples from offshore midNorway .................................................................................................................................... 125 A.I. Welbon, A. Beach, P.J. Brockbank, O. Fjeld, S.D. Knott, T. Pedersen and S. Thomas Fracture flow and fracture cross flow experiments .......................................................................... A. Makurat, M. Gutierrez and L. Backer

139

Fault seal analysis: reducing our dependence on empiricism ........................................................... T.R. Harper and E.R. Lundin

149

II. Migration and Top Seal Integrity Sealing processes and top seal assessment ....................................................................................... 165 G.M. Ingram, J.L. Urai and M.A. Naylor The dynamics of gas flow through rock salt in the scope of time .................................................... D. Kettel

175

xii

Contents

Pressure prediction from seismic data: implications for seal distribution and hydrocarbon exploration and exploitation in the deepwater Gulf Of Mexico .............................................. N.C. Dutta

187

Pore water flow and petroleum migration in the SmCrbukk field area, offshore mid-Norway ........ R. Olstad, K. BjCrlykke and D.A. Karlsen

201

The Njord Field: a dynamic hydrocarbon trap ................................................................................. T. Lilleng and R. Gundesr

217

Pre-cretaceous top-seal integrity in the greater Ekofisk area ........................................................... D.M. Hall, B.A. Duff, M. Elias and S.R. Gytri

231

References index ..............................................................................................................................

243

Subject index ....................................................................................................................................

249

A historical overview of the efforts to predict and quantify

hydrocarbon trapping features in the exploration phase and in field development planning K.J. Weber

The story of the development of theories and methods related to trapping mechanisms is a fascinating succession of brilliant observations, ludicrous misconceptions, empirical trials, and eventually the breakthrough of sound geological and physical principles. It took some 30 years from the start of the oil industry before petroleum geology began to have an impact. The period from 1885 to 1915 was very fruitful although the pendulum swung too much the other way and exploration focussed on anticlinal traps only. However, by 1915 considerable progress had been made and most trapping configurations had been recognised. Also the basic physical principles of trapping were understood in a qualitative sense. The years from 1915 to 1935 saw the development of most of the important exploration tools and also the invention of wireline logging and many petrophysical analysis methods. Consequently, the structural control on traps and the petrophysical characterisation improved significantly. By 1935, so much oilfield data had become available that several geologists in succession designed detailed classification systems for trapping configurations. After 1935, the physics of rock mechanics, flow in porous media and interfacial tension formed the subject of important studies that put petroleum geology and engineering on a much more scientific footing. This led in turn to more quantitative analysis of trapping capacity and trap integrity. After 1955, there was another upsurge in technical sophistication with respect to seismic quality, wireline logging, geochemistry and laboratory equipment. More recently, the understanding and quantification of trapping has improved steadily through sophisticated well test analysis, reservoir performance monitoring, borehole imaging logs and, in particular, the detailed images provided by 3D-seismic. Outcrop studies have been undertaken to learn more about fault zones. Research is by no means finished and there is still a wide variety of uncertainties and controversies concerning trapping phenomena.

Early struggles, 1850-1885 In nearly all oil-producing basins, numerous seeps exist. Early usage of petroleum goes back to biblical times in the Middle East. The fact that seeps are often related to faults and fractures was noted, and it was even observed that seepages along the Dead Sea were activated during earthquakes. The beginnings of petroleum production are always around seeps. Some petroleum was collected as medicine, for example, near Modena (Fig. 1). In this case, the seep is along a thrust fault and nearby oil fields are not situated directly underneath the seep. However, many seepages take place along crestal fractures of anticlinal structures. The earliest mention of this fact was made by William Logan, the first director of the new Geological Survey of Canada, in 1842. He observed the coincidence of oil seeps with anticlinal crests in the Gasp6 peninsula near the mouth of the St. Lawrence. Prior to drilling for oil, some oil was produced from hand dug pits in places like Burma and along the Caspian Sea. Thomas Young of the Geological Survey of India reported the occurrence of oil seeps

and oil production on anticlinal structures in the Yenang Yaung field in Burma already in 1855. That other types of accumulation existed also was clear from studies of the Pechelbronn field along the Rhine graben in the Alsace, where oil production from mine shafts was started in 1735. In Indonesia, the oil seeps on Java were studied by a group of mining engineers from the Delft University who started to inventorise the mineral resources in 1850. In 1865 they had located 52 seeps in the parts of Indonesia accessible at that time. Interestingly, the famous naturalist Junghuhn advised against drilling on Java. He argued that the strongly disturbed and faulted beds were likely to be incapable of holding sizeable accumulations. Nevertheless, present maps show that the recorded seeps overlie nearly all oil provinces that have since been located. Drilling wells was already common practice by the time the first oil wells were planned. Particularly the drilling of brine wells for the production of salt was carried out in many places. In Pennsylvania this had occasionally led to the inadvertent penetration of oil accumulations, which rendered the wells useless. Seneca Indians in this region used petroleum scooped

Hydrocarbon Seals: Importance for Exploration and Production edited by P. M~ller-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 1-13, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997

2

K.J. Weber

ilblrlu liI lililolllr Ilul~lf:, Ioqiit:llc lltII;illilill cI ploiifllillllr Fig. 1. Oil seep near M o d e n a , Italy, used since m e d i e v a l times to prepare medicines.

from pools to impregnate torches. Thus, the first oil company was named Seneca Oil Company (Fig. 2). In 1859, Drake drilled the first well which penetrated a productive oil accumulation at about 21 m depth. Production amounted to 25 barrels per day, soon dropping to 15.

~

Elsewhere, drilling for oil started at about the same time, for instance, in Germany, at Wietze, in 1857, near a well-known seep. In Rumania, after starting with hand dug wells, drilling started in 1882. In Baku and Grosny, in Russia, hand dug wells were followed by drilling in 1869. In Galicia, which at that time was

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rre~20%) of dissolvable sponge spicules. (e) Weakly lithified cataclasite with little or no evidence of post-faulting compaction/cementation and dominated by point contacts between angular fracture fragments. (f) Partially lithified cataclasites, characterised by some compaction and lithification by dissolution-precipitation processes. (g) Lithified cataclasite, composed of a low permeability interlocking array of grains formed by dissolution and precipitation processes. (h) Disaggregation zone formed in unlithified or poorly lithified sediment, where no or little grain fracturing occurs during the deformation.

Fault seal analysis: successful methodologies, application and future directions

19

20

R.J. Knipe et al.

Fault seal analysis: successful methodologies, application and future directions

21

22

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Fig. 3. Porosity-permeability plot of cataclastic fault rocks developed from sandstones with low (25 North Sea seals are applicable here: Seal analysis based on the assumption that juxtaposition analysis (i.e., construction of Allan diagrams, clay smear assessment and leaking sand/sand contacts) would only have been successful in -40% of the cases studied. - Clay smearing is the critical sealing mechanism in only -35% of cases. - A cement seal may be present in -60% of fields. Cross fault sand juxtaposed against sand seal in -65% of cases. Inversion/reactivation creates leaks in -20% of cases. It should be noted that these figures refer to an amalgamation of North Sea data and do not reflect the risk assessment of smaller sub-areas in the North Sea where more restricted and consistent geohistories are present. The analysis presented in the paper has highlighted the need to integrate data sets from different scales into a seal analysis (e.g., Leveille et al., 1996). Fig. 18 reviews the four critical factors needed from the different scales. These include: (i) data on the 3D sediment architecture; (ii) the petrophysical properties of the fault rocks present; (iii) the architecture of individual fault zones; and (iv) the fault array evolution. It is the combined resolution and characterisation level of each of these which defines the risk level of the seal analysis. There is an important geohistory component in each of these factors. This emphasises the problems associated with transferring data or resuits from areas with different geohistories, with-out consideration of the different geohistories involved. Despite the common assumption of fault sealing in hydrocarbon fields, very few faults have been characterised in the detail needed which allows identification of the sealing mechanism or controls. Without the construction of a robust set of case histories from such analysis, future seal evaluation will remain a high risk venture. These case histories are also needed to integrate seal behaviour with pressure test, production and in situ stress analysis. The paper has highlighted the importance of an integrated approach from micro to macro and stressed the value of corebased studies to quantify fault rock properties, subseismic fault populations and sealing mechanisms.

-

-

-

The aim of this review has been to demonstrate that although a complex problem there are techniques which can be, and should be, applied to fault seal analysis as they allow a clearer understanding, quantification and therefore predictability associated with a fault seal analysis.

Acknowledgements Support from AGIP, British Gas, BP, Conoco, Phillips, Mobil and Stratoil is gratefully acknowledged. Comments on the initial manuscript from Roy Gabrielsen also gratefully acknowledged.

References Allan, U.S. 1989. Model for hydrocarbon migration and entrapment within faulted structures. Am. Assoc. Pet. Geol. Bull. 73: 803811. Antonellini, M. and Aydin, A. 1994. Effect of faulting on fluid flow in porous sandstones: petrophysical properties. Am. Assoc. Pet. Geol. Bull., 78: 335-377. Aydin, A. 1978. Small faults formed as deformation bands in sandstone. Pure Appl. Geophys., 116: 913-942. Berg, R.B. and Avery, A.H. 1995. Sealing properties of Tertiary growth faults, Texas Gulf coast. Am. Assoc. Pet. Geol. Bull., 79: 375-393. Bouvier, J.D., Sijpesteijn, K., Kluesner, D.F., Onyejekwe, C.C. and van der Pal, R.C. 1989. Three-dimensional seismic interpretation and fault sealing investigations, Nun River field, Nigeria. Am. Assoc. Pet. Geol. Bull., 73: 1397-1414. Budey, S.D., Mullis, J. and Matter, A. 1989. Timing diagenesis in the Tartan Reservoir (U.K. North Sea): constraints from combined cathodoluminescence microscopy and fluid inclusion studies. Mar. Pet. Geol., 6: 98-120. Carter, N.L., Kronenberg, A.K., Ross, J.V. and Wiltschkko, D.V. 1990. Control of fluids on deformation of rocks. In: R.J. Knipe and E.H. Rutter (Editors), Deformation Mechanisms, Rheology and Tectonics. Geol. Soc. Special Publication 54, pp. 1-13. Cartwright, J.A., Mansfield, C. and Trudgill B. 1996. The growth of normal faults by segment linkage. In: P.G. Buchanan and D.A. Nieuwland (Editors), Modern Development in Structural Interpretation, Validation and Modelling. Geol. Soc. Special Publication 99, pp. 163-177. Chester, F.M. and Logan, J.M. 1986. Implications for mechanical properties of brittle faults from observations of the Punchbowl Fault zone, California. Pure Appl. Geophys., 124: 77-106. Cowie, P.A. and Scholz, C.H. 1992. Displacement-length scaling relationships for faults: data synthesis and discussion. J. Struct. Geol., 14:1149-1156. Cowie, P.A., Vanneste, C. and Sornette, D. 1993. Statistical physics model for the spatio-temporal evolution of faults. J. Geophys. Res., 98: 21809-21821. Cowie, P.A., Knipe, R.J. and Main, I.G. 1996 Introduction to the Special Issue. Scaling Laws for Fault and Fracture Populations Analysis and Applications. J. Struct. Geol., 18: 135-383. Dewers, T. and Ortoleva, P.J. 1990. Interaction of reaction, mass transport, and rock deformation during diagenesis: mathematical modelling of integranular pressure solution, stylolites, and differential compaction/cementation. In: I.D. Meshri and P.J. Ortoleva (Editors), Prediction of Reservoir Quality through Chemical Modelling, Memoir, 49. Am. Assoc. Pet. Geol. Tulsa, OK. Engelder, J.T. 1974. Cataclasis and the generation of fault gouge. Bull. Geol. Soc. Am., 85: 1515-1522.

Fault seal analysis: successful methodologies, application and future directions Fowles, J. and Burley, S.D. 1994. Textural and permeability characteristics of faulted, high porosity sandstones. Mar. Pet. Geol., 11: 608-623. Freeman, B., Yielding, G. and Badley, M. 1990. Fault correlation during seismic interpretation. First Break, 8: 3. Gauthier, B.D.M. and Lake, S.D. 1993. Probabilistic modelling of faults below the limit of seismic resolution in Pelican Field, North Sea, Offshore United Kingdom. Am. Assoc. Pet. Geol. Bull., 77: 761-777. Gibson, R.G. 1994. Fault-zone seals in siliclastic strata of the Columbus Basin, Offshore Trinidad. Am. Assoc. Pet. Geol. Bull., 78: 1372-1385. Gillespie, P.A., Howard, C.B., Walsh, J.J. and Watterson, J. 1993. Measurement and characterisation of spatial distributions of fractures. Tectonophysics, 226:113-141. Harding, T.P. and Tuminas, A.C. 1989. Structural interpretation of hydrocarbon traps sealed by basement normal blocks and at stable flank of foredeep basins and at rift basins. Am. Assoc. Pet. Geol. Bull., 73:812-840. Hatton, C.G., Main, I.G. and Meredith, P.G. 1994. Non-universal scaling of fracture length and opening displacement (letter). Nature, 367: 160-162. Jev, B.I., Kaars-Sijpesteijn, C.H., Peters, M.P.A.M., Watts, N.L. and Wilkie, J.T. 1993. Akaso field, Nigeria: use of integrated 3-D seismic, fault slicing, clay smearing, and RFT pressure data on fault trapping and dynamic leakage. Am. Assoc. Pet. Geol. Bull., 77: 1389-1404. Jones, G. and Knipe R.J. 1996. Seismic attribute maps; application to structural interpretation and fault seal analysis in the North Sea Basin. First Break, in press. Knipe, R.J. 1989. Deformation mechanisms - recognition from natural tectonites. J. Struct. Geol., 11: 127-146. Knipe, R.J. 1992a. Faulting processes and fault seal. In: R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleraas (Editors), Structural and Tectonic Modelling and its Application to Petroleum Geology. NPF Special Publication 1, Stavanger, pp. 325342. Knipe, R.J. 1992b. Faulting processes, seal evolution and reservoir discontinuities: an integrated analysis of the ULA Field, Central Graben, North Sea. Abstracts of the Petroleum Group Meeting on Collaborative Research Programme in Petroleum Geoscience between UK Higher Education Institutes and the Petroleum Industry. Geological Soceity, London. Knipe, R.J. 1993a. The influence of fault zone processes and diagenesis on fluid flow. In: A.D. Horbury and A.G. Robinson (Editors), Diagenesis and Basin Development. Am. Assoc. Pet. Geol. Studies in Geology, 36. American Association of Petroleum Geologists, Tulsa, OK, pp. 135-154. Knipe, R.J. 1993b. Micromechanisms of deformation and fluid behaviour during faulting. The Mechanical Involvement of Fluids in Faulting. USGS, Open-File Report 94-228, pp. 301-310. Knipe, R.J. 1994. Fault zone geometry and behaviour: the importance of the damage zone evolution. Abstracts of Meetings Modem Developments in Structural Interpretation. Geological Society, London. Knipe, R.J. 1997. Juxtaposition and seal diagrams to help analyze fault seals in hydrocarbon reservoirs. Am. Assoc. Pet. Geol. Bull., 81: 187-195. Knipe, R.J.,and Lloyd, G.E. 1994. Microstructural analysis of faulting in quartzite, Assynt, NW Scotland: implications for fault zone evolution. Pure Appl. Geophys., 143: 229-254. Knipe, R.J. and McAllister, E. 1996. Fault population analysis: identification of fractal characteristics for scaling. J. Struct. Geol., submitted. Knipe, R.J., Agar, S.M. and Prior, D.J. 1991. The microstructural evolution of flow paths in semi-lithified sediments from subduction complexes. Philos. Trans. R. Soc. London, Ser. A, 335: 261273. Knipe, R.J., Fisher, Q.J., Jones, G., Clennell, M.R., Farmer, A.B.,

37

Harrison, A., Kidd, B., McAllister, E., Porter, J.R. and White, E.A. The architecture of fault damage zones. Unpublished data. Knott, S.D. 1993. Fault seal analysis in the North Sea. Am. Assoc. Pet. Geol. Bull., 77: 778-792. Leveille, G.P., Knipe, R.J., More, C., Ellis, D., Dudley, G., Jones, G. and Fisher, Q.J. 1997. Compartmentalisation of Rotliegended gas reservoirs by sealing faults, Jupiter Area, Southern North Sea. In: K. Ziegler, P. Turner and S.R. Daines (Editors), Petroleum Geology of the Southern North Sea: Future Potential. Geol. Soc. Special Publication No.123, pp. 87-104. Lindsay, N.G., Murphy, F.C., Walsh J.J. and Watterson, J. 1993. Outcrop studies of shale smears of fault surfaces. Special Publication Int. Assoc. Sediment. 15, pp. 113-123. McGrath, A. and Davison, I. 1995. Damage zone geometry around fault tips. In: J. Struct. Geol., 17:1011-1024. Mitra, S. 1988. Effects of deformation mechanisms on reservoir potential in central Appalachian overthrust belt. Am. Assoc. Pet. Geol. Bull., 72: 536-554. Mullis, A.M. 1993. Determination of the rate limiting mechanism for quartz pressure solution. Geochim. Cosmochim. Acta, 57: 14991503. Needham, D.T., Yielding, G. and Freeman, B. 1996. Analysis of fault geometry and displacement patterns. In: P.G. Buchanan and D.A. Nieuwland (Editors), Modem Developments in Structural Interpretation Validation and Modelling. Geol. Soc. Special Publication No. 99, pp. 189-200. Peacock, D.C.P. and Sanderson, D.J. 1994. Geometry and development of relay ramps in normal fault systems. Am. Assoc. Pet. Geol. Bull., 78: 147-165. Pitman, E.D. 1981. Effect of fault-related granulation on porosity and permeability of quartz sandstones, Simpson Group (Ordovician), Oklahoma. Am. Assoc. Pet. Geol. Bull., 65:2381-2387. Rutter, E.H. 1983. Pressure solution in nature, theory and experiment. J. Geol. Soc. London, 140: 725-740. Scholz, C.H. 1989. Mechanics of faulting. Annu. Rev. Earth Planet. Sci., 17: 309-334. Schowalter, T.T. 1979. Mechanisms of secondary hydrocarbon migration and entrapment. Am. Assoc. Pet. Geol. Bull., 63: 723760. Sibson, R.H. 1994. Crustal stress, faulting and fluid flow. In: J. Parnell (Editor), Geofluids: Origin, Migration and Evolution of Fluids in Sedimentary Basins. Geol. Soc. Special Publication 78, pp. 69-84. Smith, D.A. 1966. Theoretical consideration of sealing and nonsealing faults. Am. Assoc. Pet. Geol. Bull., 50: 363-374. Smith, D.A. 1980. Sealing and non-sealing faults in Louisiana Gulf Coast salt basin. Am. Assoc. Petrol. Geol. Bull., 64: 145-172. Somette, A., Davy, P. and Somette, D. 1990. Growth of fractal fault patterns. Phys. Rev. Lett., 65, 18: 2266-2269. Spiers, C.J., Schutjens, P.M.T.M., Brzesowsky, R.H., Peach, C.J., Liezenberg, J.L. and Zwart, H.J. 1990. Experimental determination of constitutive parameters governing creep of rocksalt by pressure solution. In: R.J. Knipe and E.H. Rutter (Editors), Deformation Mechanisms, Rheology and Tectonics. Geol. Soc. Special Publication 54, pp. 215-228. Sverdrup, E. and Bjorlykke, K. 1992. Small faults in sandstones from Spitsbergen and Haltenbanken. A study of diagenetic and deformational structures and their relation to fluid flow. In: R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleraas (Editors), Structural and Tectonic Modelling and its Application to Petroleum Geology. NPF Special Publication 1. Elsevier, Amsterdam, pp. 507518. Underhill, J.R. and Woodcock, N.H. 1987. Faulting mechanisms in high porosity sandstones; Nw Red Standstone, Arran, Scotland. In: M.E. Jones and R.M.F. Preston (Editors), Deformation of Sediments and Sedimentary Rocks. Geol. Soc. Special Publication 29, pp. 91-105. Wallace, R.E. and Morris, H.T. 1986. Characteristics of faults and shear zones in deep mines. Pure Appl. Geophys., 124: 107-125.

R.J. Knipe et al.

38 Walsh, J.J. and Watterson, J. 1991. Geometric and kinematic coherence and scale effects in normal fault systems. In: A.M. Roberts, G. Yielding and B. Freeman (Editors), The Geometry of Normal Faults. Geol. Soc. Special Publication 56, pp. 193-203. Walsh, J.J. and Watterson, J. 1992. Populations of faults and fault displacements and their effects on estimates of fault-related regional extension. J. Struct. Geol., 14: 701-712.

R.J. KNIPE Q.J. FISHER G. JONES M.R. CLENNELL A.B. FARMER A. HARRISON B. KIDD E. MCALLIsTER J.R. PORTER E.A. WHITE

Watts, N.L. 1987. Theoretical aspects of cap-rock and fault seals for single and two phase hydrocarbon columns. Mar. Pet. Geol., 4: 274-307. Yielding, G., Needham, T. and Jones, H. 1996. Sampling of fault populations using sub-surface data: a review. J. Struct. Geol., 18: 135-146.

Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK (e-mail: r.j.knipe@ rdr.leeds.ac.uk) Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK

39

The emplacement of clay smears in synsedimentary normal faultsinferences from field observations near Frechen, Germany F.K. Lehner and W.F. Pilaar

Background and methods: This paper reports on an outcrop study of clay smears in synsedimentary normal faults that were exposed in the open-cast lignite mines at Frechen near Cologne, Germany. The observations made are interpreted in terms of a mechanism of clay smear emplacement.

Results and conclusions: The fault zones at Frechen contain clay fillings of up to 1 m in thickness, derived from extremely plastic shale source beds and smeared out over distances as much as 70 m in dip direction. The generation of substantial smears requires slow fault displacement rates and sufficient shale ductility. When a thick shale source bed is traversed by a normal fault, it is first flexed and eventually disrupted by a pull-apart mechanism that creates room for the emplacement of thick clay smears. Simple theoretical considerations suggest that the source bed thickness to some power n + 1 > 2 may be a key parameter in the ranking of seal quality. The length of continuous smears increases with source bed thickness, but will ultimately be controlled by the smearing process. The latter remains to be investigated.

Introduction Among the various conditions known to promote sealing of shear faults in sediments, the presence of "clay smears" or "shale smears" has long been recognized as important. Field observations, indicating mud stone flow into fault zones, were reported by Edwards et al. (1944). "Fault plane fillings" consisting of clay material from side walls were described even earlier in faulting experiments on soft sediments by Rettger (1935). Perkins (1961), in a study of certain fault closure-type fields in the Lousiana Gulf Coast, explained accumulations in sands upthrown against massive sands by shale flowage along the fault zone, whereby he envisaged the formation of a "natural mudcake" over the sand interface by impregnation of the pore space of the sand with plastic shale material. In the same region, Smith (1980) studied the occurrence of fault seals in deltaic sand/shale sequences in relation to the age and lithology of the juxtaposed sediments and found: (1) fault sealing, with hydrocarbon-bearing sandstone in juxtaposition with shale; (2) fault non-sealing, with parts of the same sandstone body juxtaposed within the hydrocarbon column; (3) fault non-sealing, with sandstone bodies of different ages juxtaposed within the hydrocarbon column; and (4) fault sealing, with sandstone bodies of different ages juxtaposed within the hydrocarbon column. In some places, all four relations were found to be present at different levels along the same fault. In the last case, the seal was attributed by Smith to "the presence of boundary fault-zone material (i.e., material from the fault walls)

emplaced along the fault by mechanical or chemical processes related directly or indirectly to faulting". Smith discusses evidence from fault-zone exposures for cemented and indurated sandstones, a fairly frequent observation (see, e.g., Knipe (1992) and further references cited therein), but also describes a fault zone which separates two different sandstones by a clay-fill of 1 m thickness. According to Smith, "the clay is not fault-gouge material, but is apparently part of a shale formation that has become stretched and trapped in the fault zone". As Smith observes, if the fault-zone shale provides the seal, the thickness and physical properties (soft or indurated) of the shale at the time of faulting are factors which may determine whether or not shale will form boundary fault-zone material for hydrocarbon entrapment. Growth faults, relatively near the surface in soft sediments, may thus have a different capacity to trap hydrocarbons than post-depositional faults at depth in more indurated sediments. The last observation could indeed have major practical implications as a guiding principle in assessing fault trap prospects. It is therefore of some interest that Lindsay et al. (1993) have observed clay smears in tectonic faults that affected a Westphalian sand/shale sequences after lithification. These smears were apparently formed by abrasion of indurated shales. In this process, the surface of a sandstone becomes coated by a thin veneer of abraded material in much the same way as the surface of sandpaper. This veneer may run continuously along polished slip surfaces, but - as Lindsay et al. have documented in their s t u d y - with increasing fault displacement and de-

Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mr

and A.G. Koestler. NPF Special Publication 7, pp. 39-50, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997

40 pending upon the thickness of the shale source bed, the veneer will eventually be eroded. Clay smears formed by a process of abrasion in the faulting of lithified sediments must thus be distinguished carefully from smears that are formed by the injection of soft clay material from plastic source beds. Clay smears of the latter kind were found in coal-bearing sequences by Lindsay et al. and were associated characteristically with soft seat earths. The picture emerging from these studies tends to confirm the results of an earlier outcrop study, conducted in 1973-1974 by the present authors on synsedimentary normal faults in the open-cast lignite mines of the lower Rhine Graben at Frechen, west of Cologne in Germany. Although an abbreviated and limited exposition was given in a paper by Weber et al. (1978), the results of this study have so far never been published in full. The work of Weber et al. (1978) and Weber (1987) was in fact primarily concerned with the broader issue of hydrocarbon migration and accumulation patterns in the Niger Delta. In presenting a brief synopsis of the observations made at Frechen, Weber et al. (1978) were, however, offering a rational explanation for observed lithologytrapping relationships in soft deltaic sand/shale sequences in terms of sealing clay smears, in much the same way as was proposed later by Smith (1980). The quality of the fresh fault-zone exposures in the Frechen mines was in fact unique and some of the most interesting unpublished observations made there relate to the mechanism of clay-smear emplacement. Clay smears ranging in length from a few centimeters (on minor shear faults) to more than 70 m (on major graben faults) provide strong evidence of an injection-type mechanism of emplacement, the mechanics of which remained enigmatic, however, especially for clay smear thicknesses of nearly 1 m. Here a detailed study of the deformation and rupture behavior of some shale source beds, as they become affected by normal faulting during burial, has shed light, not only on the mechanism of clay smear emplacement in a fault zone, but also on the broader question of fault propagation through a rheologically layered sequence of soft sediments. It was therefore felt that a detailed account of the observations made in 1973-1974 in the Frechen mines would provide a useful contribution to the discussion on fault sealing mechanisms and potential.

Main findings of outcrop study The open-cast lignite mines near Frechen (west of Cologne in Germany) provide an excellent location for studying well exposed normal faults, which had been brought to our attention by J. Haremboure (pers.

F.K. Lehner and W.F. Pilaar

commun.). The faults occur in a deltaic sequence of moderately cohesive sediments. At the time of this study, outcrops could be examined down to about 200 m depth below surface. The faults chosen for study are situated on the eastern flank of the Tertiary graben system of the lower Rhine Valley and affect the deltaic sequence that filled this part of the graben. The faults are synsedimentary normal faults, i.e., growth faults, that have been active during the Upper Miocene and lowermost Pliocene (Quitzow, 1954; Prange, 1958). Throws up to about 100 m and dip angles averaging around 70 ~ are observed in the open pits. The exposed sediments comprise altemating well-bedded loose to slightly consolidated, sands, silts, shales, and gravels with an intercalation of a thick brown-coal layer in the lower part of the exposed section. Sand predominates over the other lithological constituents, the average sand/shale ratio being near 3:1 in the Frechen mine. The focus of our investigation lay on the structure and composition of fault zones and in particular on any evidence that would shed light on the process of clay smear emplacement. We begin with an overview of the most important observations.

Shear zones associated with normal faulting Fault displacement along the major normal faults is typically partitioned (in space and time) over a number of slip surfaces that define a "shear zone". The style of shearing within such a shear zone contrasts with the pattern formed by minor shear bands in the adjacent sediments. The width of the shear zones varies with the lithological composition of the fault walls over the throw interval. With sand against sand displacement, the shear zones are usually only a few centimeters wide. Where sand is displaced against other material, shear zones are often wider and include material from different locations along the fault walls. Such shear zones often have a lithologically layered appearance. They contain clay smears in almost every location within the throw interval of a faulted shale bed, be it along a minor shear band or a major fault. These observations are documented in Plates 1 and 2. Minor shear bands, called "shears" in the following, appear as streaks of discolored material in outcrop. Shearing in combination with fluid transport through dilated shear bands appears to remove the fine coal particles that are attached to the sand grains and are responsible for the brownish color of many (unsheared) sands in the mines. This creates a unique opportunity for locating minor shears in sandy material, where they would otherwise remain invisible to the naked eye.

The emplacement of clay smears in synsedimentary normal faults

PLATE

41

PLATE 2

1

(a) (a)

1IlL

ay source beds

~c~

(b)

D

F cl smear

1l 11 t~

(b)

F

Jl o,~yg.uge

li

Plate 1. (a) "Max Rudolph" fault (Frechen mine): continuous clay smear over approx. 70 m throw, visible as a thin streak between sand and downthrown coal (Height of exposure approx. 40 m). (b) Earlier exposure of same fault, showing continuity of clay smear in strike direction over approx. 400 m. (c) Detail of fault zone with compact clay smear (approx. 30 cm thick) and fault-parallel minor D-shear in upthrown block. Plate 2. (a) Clay smear in minor shear. (b) Sample of clay smear (approx. 5 cm thick) filling fault zone of "Max Rudolph" fault (Frechen mine). Sigmoidal shear pattern became visible upon drying.

The style of shearing within major shear zones varies with the lithology of the fault-zone material. In sandy material, one encounters the patterns of shear of the "classical" shear zones described by Skempton (1966), Morgenstern and Tchalenko (1967), Tchalenko (1970), Mandl et al. (1977) and Logan et al. (1979) (see also more recent work on experimental shear zones by Logan et al. (1992) and Gu and Wong (1994). Typical of this style are the fault-parallel "principal displacement shears" (D-shears) and enechelon "Riedel shears" (R-shears) that are inclined at 10-30 ~ to the D-shears, the acute angle pointing in the direction of the relative movement of the fault block on which they occur.

In freshly cut, i.e., wet clay smears, such as shown in Plate 1, much less evidence is found of discontinuous deformation along well-defined slip planes than in sandy shear zones. Dried samples, however, reveal intense sheafing along often slicken-sided, slip surfaces across which the material retains a certain reduced cohesion. On a centimeter scale, the mode of plastic deformation of the soft clay smears appears to be slip along distributed, often gently warped surfaces. This is visible in the clay smear sample shown in Plate 2b from a fault zone whose main slip surfaces (or Dshears) coincided with the margins of the clay smear, as is often observed. After some drying, a very regular pattern of sigmoidal shears appeared in the sample.


42

PLATE 4

PLATE 3

R

F

F

/)

coal shale

(a)

(a) R

F

F

sand coal

shale

(b)

(b)

~/I

Plate 3. (a) Clay smear and sets of R- and conjugate W-shears in near-surface position on upthrown and downthrown blocks of "Max Rudolph" fault (F). (b) Detail of (a) showing R-shears offset by later R'-shears and truncation of shears by fault. Plate 4. (a) "Max Rudolph" fault (Frechen mine, throw approx. 70 m). Clay from different source beds on upthrown and downthrown blocks merges to form layered clay smear free of sandy or coal material. (b) Hexed shale bed on downthrown side of "Max Rudolph" fault (F). The clay smear (approx. 20 cm thick) and sand wedge to the left of the person resemble situation shown in Fig. 2.

D e f o r m a t i o n outside the s h e a r z o n e s

On either side of the "shear zone proper" (the term is used here to designate the zone that accommodates most of the fault displacement and is typically bounded by D-shears), a much wider zone of continuous and/or discontinuous (slip) deformation is usually discernible. Faulted monoclinal flexures in shale layers (Plate 3) furnish the most prominent examples of continuous, fault-related deformation. At places, the coal seam is flexed together with an overlying or underlying shale. Almost everywhere along a fault, a fringe zone of (discolored) shears is observed in the sands (Plate 4). On the downthrown side, the flexed shales are often intersected by these shears

(Plate 5b). A large number of observations suggests that these shears form two sets of conjugate shears whose attitude with respect to the major slip planes of the fault is the same as that of the Riedel shears (Rshears) and their conjugates (W-shears) in the abovediscussed "classical" shear zone. We have therefore used the abbreviations R and R' to denote these sets in the plates shown. In Plate 4 these sets can be seen on the upthrown and downthrown sides of a fault. An important observation, to which we shall return presently, is that this pattern of R- and W-shears is discontinuous across the fault, i.e., is truncated by it. The material has been deformed along these sets of shears by a double-gliding motion involving alternating slip on two conjugate sets of slip surfaces, with some pre-


Plate 5. (a) Near-surface exposure of "Max Rudolph" fault (F) forming narrow shear zone in sand. Sets of precursory R- and R'-shears on upthrown and downthrown blocks are truncated by fault (shears open upon drying of slope face). (b) Shale A in juxtaposition with shale B and underlying coal across "Max Rudolph" fault (F). Note the small graben feature, where shale is intersected by R- and R'-shears. Rshear visible also upon upthrown side.

dominance of slip along R-shears in the early phase of the deformation. The same pattern is shown in Plate 5a, where the shears form open superficial cracks upon drying. Where R- and R'-shears cut into a sand/shale bedding plane, characteristic graben structures are formed, as is seen in Plate 5b. Shears that cut into a shale at such localities have been found to end in a zone of continuous deformation.

Clay smears The clay smears found in the major fault zones form a continuous band which is gradually thinning away from the source bed (see Plates 1 and 3). The smears consists of remarkably pure clay material. At places these smears can reach a thickness of approximately 1 m, but thicknesses of the order of 1020 cm are more common. Along portions of the "Max Rudolph" fault, a continuous smear exists over the

43

total throw interval of more than 70 m (Plate 1). Smears occasionally contain clay material from different beds, that tends to become sharply aligned, with hardly any inclusions of other material from the fault walls, giving the smear a layered appearance (Plate 3). Sandy material between two distinct clay smears is found only at locations where a shale bed merges with a smear from a different source bed, but the sand wedges seen at these locations were associated with the flexure formed by the shale source bed, allowing the two distinct clay smears to merge into a single, layered smear beyond the zone of flexing (Fig. 1). The material forming the clay smear is supplied both from the upthrown and the downthrown parts of a source bed (see Plate 3a, for example). The thicker clay beds clearly produce thicker and longer smears. Full continuity in strike direction could be confirmed for about 400 m of exposure of the smear shown in Plate 1. In the Frechen mines, there is substantial evidence to suggest that continuous smears extend over large distances in strike and dip direction and that these smears act as a seal against transverse flow of groundwater, a fact that requires careful consideration in the mining operations. Fig. 2 summarizes in a schematic fashion the main features associated with the continuous clay smears that were observed in the major fault zones of the Frechen mines. It is reproduced from Weber et al. (1978), again to provide a synthesis of the most pertinent observations and a convenient reference in the subsequent discussion.

Mechanism of clay smear emplacement suggested by observations The overall picture emerging in the course of this field study was that clay smears are formed consistently on all scales in the Frechen exposures, where they represent a "universal" phenomenon. This would suggest that the conditions necessary for the emplacement of clay smears in minor shear bands are the same as those met along the major faults. Among the factors that are likely to determine the thickness, length and continuity of a smear, the thickness of the source bed and the fault throw are readily identified in the field. The requirement that the shales possess the necessary "plasticity" is also clearly met, i.e., the shale source bed material may be characterized as highly plastic, fat clay in accordance with the standard soil mechanics classification (Bowles, 1984).

Extrusion of plastic clays from source beds In the Frechen mines, one often sees evidence for


44

Fig. 1. Merging of two clay smears to form layered smear (cf. Plate 3b).

extrusion of plastic clay material into the open air, where source beds are intersected by the excavation surface. This observation can be made on all scales, from clay seams only a few millimeters thick to major shale beds. Drying hardens the clay and this embrittlement process appears to stop the squeeze-out. This suggests that a similar extrusion phenomenon may be involved in the emplacement of clay smears. The argument is based on the reasonable assumption that the large-scale stresses giving rise to normal faulting in the sands may be approximated in terms of the average bulk density of the sediments p, the density of water Pw, the burial depth D, and the angle of internal friction q~ by crv = p g D

vertical total stress in sands

trh = k p ' y D + p w g D

horizontal total stress in sands

(1)

(2) where p ' = p - P w is an effective overburden density, while k = (1 - sin ~p)/(1 + sin ~p) for poorly consolidated, i.e., only slightly cohesive sands. Outside any flexed portion in the immediate vicinity of a fault, a shale may be assumed to remain under stresses close to hydrostatic, so that for horizontal shale beds one may put t7h - "

(7 v

=

pgD

stresses in shales

(3)

It is now evident that if the above stress distribution in a horizontally stratified sand/shale sequence were to persist even after the truncation of a particular shale bed by the fault, then this hydrostatically stressed source bed would be put in juxtaposition with a sand at a much lower horizontal stress. In con-

sequence, the soft shale would be expected to flow towards the fault intersection, i.e., would extrude from the source bed in a manner similar to that observed along the totally unloaded excavation faces. As discussed by Weber et al. (1978), the same mechanism appears to have operated in experiments performed by Mandl et al. (1977), during which continuous clay smears were produced in a ring-shear apparatus by extruding material from a sheared-off clay band. In these experiments, the much smaller difference between the fault-parallel and the faultnormal stress within the plastic clay, as compared with that in the sand, must have caused the observed extrusion. Extrusion, as such, of plastic clays from faulted source beds does not fully explain the emplacement of clay smears in a fault zone, however. Are clay smears put in place by an "injection" process, in the manner of a dyke intrusion? In fact, nothing appears to support such the idea of a forced injection. On all scales clay smears always tend to connect the offset portions of a source bed. They are never observed to extend upwards from the upthrown or downwards from the downthrown source bed and must indeed be viewed as genuine smears. Thus, while the abovediscussed horizontal excess stress will be essential as an agency for clay extrusion from a source bed, it clearly cannot account for the transport of the clay material in the fault zone. In other words, clay smear emplacement requires the shearing action of active fault motion and cannot be viewed solely as the result of injection into a stationary plane of weakness. On the other hand, shearing alone also cannot possibly account for the emplacement of tens of meters of continuous clay smear. The main observation ruling out this "simple shearing" interpretation is that major fault zones, such as that of the Max Rudolph fault shown in Plate 1 accommodate almost the total fault displacement within a fault-zone width that tends differ only little from the clay smear thickness (cf. also the sample shown in Plate 2b, where the clay smear is found to be bounded by principal displacement shears). A further pertinent observation in this context is the extreme narrowness of the fault zone that is observed in positions with sand/sand juxtaposition above an upthrown and below a downthrown source bed (cf. locations (3) in Fig. 2). This suggests that the mechanism of clay smear emplacement must involve both a component of shear transport within the faultzone as well as a component of continuous supply from the source bed. How do these different mechanisms cooperate in reality? A solution to this problem is suggested by observations made at Frechen and will now be described.

45


Fig. 2. Mainobservations along sealing faults.

Pull-apart mechanism of clay-smear emplacement A continuous supply of clay material from the source bed to the shear zone can be maintained, given the necessary "plastic" properties of the material, if a driving horizontal stress difference between distant parts of the source bed and the immediate vicinity of the fault can be maintained. This requires some mechanism of horizontal stress relief to operate at the fault intersection of a source bed. Preferably, the same mechanism should be capable of resolving the space problem implied by the emplacement of massive clay smears. Such a mechanism was in fact conceived at some stage in the course of this study, in the first place as a way to overcome the space problem kinematically. Thus we invented the "pull-apart" mechanism shown in Fig. 3. On traversing a shale source bed, a normal fault only has to be offset in the direction of the downthrown block in order to make room for the emplacement of a clay smear. Evidently, this mechanism

can also provide an effective way of unloading the source bed along the rupture faces, thus facilitating the extrusion of plastic clay material. The extruded material will fill the gap created by the pull-apart mechanism. It will thereby enter the shear zone proper, where it will be subjected to the slow shearing imparted by the relative displacement of the fault blocks, to be smeared out along the fault. The pull-apart mechanism that has just been described served as a valuable working hypothesis, which, in its final form (see Fig. 4), provided a unifying explanation for all main observations as summarized in Fig. 2 above. The difference between the process depicted in Fig. 4 and the principle sketched in Fig. 3 is that the former suggests an explanation for the fault offset, by linking it to the development and eventual mode of failure of a monoclinal flexure in the shale bed. Our observations thus suggest the following main stages in the development of a continuous clay smear long a major fault (cf. Fig. 4). (a) A newly deposited, highly plastic shale first forms a monocline in re-

46


reconstructed from field evidence, such as shown in Plates 4 and 5. The pattern of shear bands formed in the course of this early deformation is eventually cut through by the fault, the part lying on the downthrown block becoming displaced along the fault into a position corresponding to that of Plate 4 and explaining the observations made there, in particular the truncation of R'-shears that exhibit several centimeters of slip displacement close to the fault. A simple approximate argument can explain the spatial orientation of the pattern of shears shown in Fig. 5, as follows. First, it is stipulated that on traversing the shale bed, the fault is offset in the direction of the downthrown block, but maintains its angle of dip in propagating into the accumulating sand above. Moreover, if the deformation immediately preceding the development of a fault in the overlying sand is visualized as forming a plastic "hinge" zone in a Coulomb material at peak strength, with the maximum rate of shearing taking place on planes roughly parallel to the future fault plane, and if it is further

Fig. 3. Kinematics of "pull-apart" of shale source bed during faulting.

sponse to faulting of its substratum, in a manner observed by Cloos (1930) in experimentally deformed clay layers. The slip systems described by Cloos correspond closely to the R- and R'-shears seen in the sands and along the sand/shale interface, but rarely visible in the freshly cut shales (see also the discussion of Fig. 5 below). (b) With continuing burial, the shale bed is gradually disrupted as faulting progresses from the underlying sand into the accumulating sandy overburden. There the fault follows a path that is slightly offset towards the downthrown block. (c) The gap implied by the pull-apart and accompanying fault offset is closed by the extrusion of clay material from the truncated source beds and the subsequent formation of a clay smear. Extrusion is consistent with the thinning and associated faulting of the source bed close to the fault (cf. also Figs. 1 and 2). The same sequence of events also explains more subtle features. For example, the consistently observed gradual increase in shearing intensity (i.e., density of fault-parallel D-shears) within the sandy portion of a fault zone as one moves against the relative slip direction on either side of a clay smear, i.e., in the direction of increasing total slip displacement of sand against sand (cf. Fig. 2). Fig. 5 depicts the early stage in the deformation of the sandy material immediately above a shale bed as

Fig. 4. Three stages in the disruption of a ductile shale bed by an upward propagating normal fault; pull-apart allowing the emplacement of massive clay smears.


47

ments. This is not to say that the problem of fault propagation through rheologically layered sequences offers no scope for further experimental studies, especially perhaps, if one were to adopt a strategy of "conservation of material" (Mandel, 1962) in combination with centrifuge techniques. Certain essential aspects of the problem may well be tackled theoretically. Thus, it should be possible to model the important initiation phase of faulting in the overlying sands prior to the development of a throughgoing fault in the highly ductile shale, i.e., while the latter is forming a macroscopically smooth monocline. Of particular interest would be studies of rupture transgression across a shale bed, focussing on the development of a fault offset in the manner depicted in Fig. 4. Since fault offset is likely to determine the thickness, continuity, and overall length of clay smears along a throw interval, any quantitative link of fault offset to factors such as material characteristics of the shales, shale bed thickness, depth of burial, and possibly fault slip rate, should contribute significantly to our ability to predict the occurrence of substantial clay smears. Fig. 5. Mohr-circle construction of precursory R- and R'-shears that form early during upward-propagation of normal fault through ductile shale bed. The maximum shear stress is assumed to occur on faultparallel planes; the shear orientations are obtained through the use of Terzaghi's pole construction (Mandl et al., 1977).

assumed that the maximum shear stress occurs along the same plane, then the R- and R'-shears can readily be explained as conjugate sets of Coulomb slip surfaces by means of the Mohr-diagram construction shown in Fig. 5 (see also Mandl et al. (1977) for a detailed discussion of this coaxiality assumption for shear zones in frictional materials). This simple argument can explain the consistently observed orientation of conjugate sets of R- and R'shears in the field; it also links the presence of such shears in a fringe zone or "damage zone" on either side of the shear zone proper to a precursory deformation, which is visualized here as taking place in a "process zone" just ahead of the tip line of the propagating fault. The fault offset shown in the conceptual Figs. 3 and 4 not only solves a geometrical problem, but may also correspond to a mechanically preferred rupture transgression of the shale bed, primarily because faulting at the shale/overburden interface would be expected to nucleate where the strains are largest, i.e., near the point of maximum curvature of that interface (cf. Fig. 4a,b). Early laboratory model experiments appear to support such an interpretation (Cloos, 1930; Rettger, 1935; Wunderlich, 1957), but can hardly be viewed as conclusive in view of the notorious difficulty of satisfying scaling require-

Criteria for the ranking of seal quality We shall now discuss a simple dimensional argument, put forward in our original report, where we attempted to establish criteria that would allow one to discriminate between conditions favorable and unfavorable for the formation of clay smears. Taking as a starting point the picture drawn in Fig. 4, we considered that a continuity requirement on the relevant fluxes might furnish a first rough criterion. Thus, on one hand, one has the rate of extrusion qextr of ductile clays from their source beds, while on the other hand there is the rate of transport or "smearing" qsmear o f the clay material within the fault zone proper. If it is assumed then that the rate-dependent response of the soft clay material may be characterized simply by an effective viscosity, as for a Newtonian viscous fluid, then the total rate of extrusion from a horizontal source bed through a vertical cross-section close to the fault is given by an expression, well-known in the theory of lubrication squeeze flows (Langlois, 1964): h 3 ap

qextr =

12r/Ox

(4)

Here h is the source bed thickness (in m), r/ is the effective viscosity (in Pa s), and ap/ax is the pressure gradient in the source bed in the horizontal direction (in Pa/m); thus, qx is the total volumetric extrusion rate (in m2/s) per unit width perpendicular to a fault-


48

dip section. A rough estimate of the magnitude of the pressure gradient in the source bed is provided by the ratio of the maximum stress difference in the surrounding sands divided by the layer thickness. Using Eqs. (1) and (2) we have crv - crh = (1 - k)p'gD and hence arrive at the estimate

(1-k)p'gDh 2 qextra --

12r/

Let it be assumed further that transport of clay or "smearing" within the shear zone proper is accomplished by simple shearing. Then the rate of transport per unit width perpendicular to a fault-dip section is given by qsmear =

lw3 2

where w is the local clay smear thickness and ~ is the local rate of slip of the downthrown block relative to the upthrown block. If we imagine now, that the sequential processes of clay extrusion and smearing progress through a sequence of approximately steady states such that, for reasons of continuity, the rates of these processes must be approximately equal, then qextra = qsmear

h 2 (1 - k)p' gD = 1 2Y]Wt~

where w must now be interpreted as the clay smear thickness close to the source bed. The last relationship provides some information on parameters that are likely to control the quality of a clay smear, where quality is expressed simply in terms of clay smear thickness close to the source bed. Other things remaining equal, it suggests that the smear "quality" may be expected to improve with increasing source bed thickness and burial depth, but to deteriorate with increasing fault slip rates and clay viscosity. The negative effects of an increase in slip rate and clay viscosity are intuitively expected. However, the capability of relation (7) to capture these effects quantitatively should not be overrated in view of the strongly simplifying assumptions on which it is based. Indeed, the most useful conclusion to be drawn from Eq. (7) is that clay smear thickness may be expected to depend strongly on source bed thickness. Thus, for linear viscous behavior Eq. (7) predicts the proportionality w ,,~ h 2. The equivalent result for a power-law secondary creep behavior of the clay would take the form w o~ h(" + ~, where n is the appropriate power-law stress exponent. Again, however, this distinction should not be overrated in view of the fact that very little appears to be known about secondary (deviatoric) creep of clays at strain rates less

than 10-1~ s-l, which are likely to characterize the slow process of clay extrusion from a source bed. The proportionality w ~ h 2 or w ~ h(" § 1) does, however, provide a simple criterion for ranking the sealing quality of any two clay smears that originate from distinct source beds with thicknesses h l and h2, respectively. In particular, in instances where two source beds form a layered clay smear within a given throw interval, the total contribution from these source beds to the smear would be ranked below the contribution from a single source bed of thickness h 1 + h2, simply because w ~ (hi 2 + h2 2) in the former case while w ~ h i + h 2 in the latter. In practice, any ranking procedure which is based on a partial description and limited quantitative understanding of a process should be used only in combination with additional empirical evidence, e.g., evid e n c e - in a specific geological setting - for the occurrence of clay smears along major faults. Adding to such knowledge, the geologist can then proceed to rank potential fault seals on the basis of the above criterion for "seal quality". Major uncertainties may indeed be set aside by a "calibration" against field data. Among others, these include the question of sufficient clay ductility (the factor r/) and slow enough fault slip rates (the factor 6 ). The latter, in particular, may be improperly constrained by the stratigraphic record, if faulting occurs in a jerky fashion, with long periods of quiescence or slow creep followed by episodes of accelerated creep or seismic slip. In situations where most of the fault displacement is due to rapid slip, the formation of smears by extrusion of clay material from source beds will become impossible, in qualitative agreement with criterion (7). An obvious shortcoming of the above criterion stems from the steady-state assumption which underlies Eq. (7). It implies, in particular, that nothing can be learned from Eq. (7) about the maximum length that might be attained by a clay smear. The criterion assumes indeed an unlimited supply of clay material at a fixed rate. In reality, however, the extrusion process must go together with a progressive thinning of the source bed and this phenomenon is indeed observed in the field (cf. Plates 3a and 5b). The maximum length of any continuous clay smear must therefore be controlled by the depth of penetration of the extrusion flow into the source bed, i.e., by the size of the region of supply. The actual length of a smear will of course be determined by the effectiveness of the transport mechanism that is implied by the term "smear". Here one can visualize several processes at work. Thus, for small enough fault throws, clay injection by excess pressures within the source bed may well furnish an important contribution, giving rise to


a combined shear- and squeeze-flow mode of transport of ductile clay material, although these excess pressures would not suffice to squeeze the material against the direction of shearing upwards beyond the upthrown source bed and downwards beyond the downthrown source bed. For larger throws, direct observations on fault zone structure (cf. Plates 1 and 2b) would suggest that the process of smearing involves episodes of smearing-without-slip and slipwithout-smearing, whose occurrence is governed by such factors as clay properties, depth (i.e., stress level) and fault displacement rates. That such behavior would tend to limit seal length is clear, but the process itself remains poorly understood. In the absence of further experimental and theoretical work that would elucidate and help quantifying the smearing process, one is therefore left with an empirical ranking procedure that rests on a number of key observations, which have been incorporated together with other factors in the procedure used by Fulljames et al. (1997) in this volume.

Conclusions The clay smears observed in the shallow deltaic sequence of the Frechen mines occur on all scales, ranging from minor shears with clay source laminae less than 1 cm in thickness and slip displacements of the order of centimeters to major normal faults with clay source bed thicknesses in the meter range and continuous smears over some 70 m of fault throw. Direct observations in the Frechen mines show that soft clay material is extruded from source beds, where these are intersected by an excavation surface. We also present evidence for clay extrusion at fault intersections of minor and major source beds. We explain the occurrence of extrusion by horizontal excess stresses in highly ductile source beds. The emplacement of the extruded material within a fault zone as clay smear we ascribe to the shearing action imposed by the wall rock. Thick clay smears appear to be accommodated within a faultzone by a slight offset of the fault in the direction of the downthrown block, as the fault cuts upwards through a shale source bed in the course of its burial. Slow fault displacement rates, typical of synsedimentary faults, and sufficient clay "plasticity" appear to be essential to the occurrence of these phenomena. Thicker source beds produce thicker smears and from simple theoretical considerations one may expect the square of source bed thickness to enter as a key parameter into the ranking of seal quality. The length of continuous smears increases with source bed thickness, but must ultimately be controlled by the smearing process. The latter remains to be investigated in detail.

49

Acknowledgements The field studies in the Frechen mines were made possible by the kind permission of the management of Rheinische Braunkohlenwerke AG, Ki31n and the generous support offered by its technical staff, which are herewith gratefully acknowledged. The paper is published by permission of Shell Research B.V.

References Bowles, J.E. 1984. Physical and Geotechnical Properties of Soils, 2nd edn. McGraw-Hill, New York. Cloos, H. 1930. Zur experimentellen Tektonik. Geol. Rundschau 21: 353-367. Edwards, A.B., Baker, G. and Knight, J.L. 1944. The geology of the Wonthaggi coal field, Victoria. Proc. Aust. Inst. Min. Met. N.S. 134: 1-54. Fulljames, J.R., Zijerveld, L.J.J., Franssen, R.C.M.W., Ingram, G.M. and Richard, P.D. 1997. Fault seal processes. In: P. M~llerPedersen and A.G. Koestler (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 51-59. Gu, Y. and Wong, T.-f. 1994. Development of shear localization in simulated quartz gouge. PAGEOPH, 143: 387-423. Knipe, R.J. 1992. Faulting processes and fault seal. In: R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleraas (Editors), Structural and Tectonic Modelling and its Application to Petroleum Geology, NPF Special Publication 1. Elsevier, Amsterdam, pp. 325342. Langlois, W.E. 1964. Slow Viscous Flow. Macmillan, New York. Lindsay, N.G., Murphy, F.C., Walsh, J.J. and Watterson, J. 1993. Outcrop studies of shale smears on fault surfaces. Special Publication 15. Int. Assoc. Sediment, pp. 113-123. Logan, J.T., Friedman, M., Higgs, N., Dengo, C.A. and Shimamoto, T. 1979. Experimental studies of simulated gouge and their application to studies of natural fault zones. Proc. Congr. VIII - Analysis of Actual Fault Zones in Bedrock. US Geol. Surv. Open-file Report 79-1239, pp. 305-343. Logan, J.T., Dengo, C.A., Higgs, N. and Wang, Z.Z. 1992. Fabrics of experimental fault zones: their development and relationship to mechanical behaviour. In: B. Evans and T.-f. Wong (Editors), Fault Mechanics and Transport Properties of Rock. Academic Press, New York, pp. 34--67. Mandel, J. 1962. Essais sur models r6duit en mechanique de terrains. Etude des conditions de similitude. Rev. Industrie Minerale 44: 611-620. Mandl, G., de Jong, L.N.J. and Maltha, A. 1977. Shear zones in granular material. Rock Mech. 9: 95-144. Morgenstern, N.R. and Tchalenko, J.S. 1967. Microscopic structures in kaolin subject to direct shear. G6otechnique. 17: 309-328. Perkins, H. 1961. Fault-closure type fields, Southeast Lousiana. Trans. Gulf Coast Assoc. Geol. Soc. 11: 177-196. Prange, W. 1958. Tektonik und Sedimentation in den Deckschichten des Niederrheinischen Hauptbraunkohlenfl6zes in der Ville, mit Bemerkungen zur Feintektonik der Niederrheinischen Bucht. Fortschr. Geol. Rheinld. Westf. 2: 651-682. Quitzow, H.W. 1954. Tektonik und Grundwasserstockwerke im Erftbecken. Geol. J. 69: 455-464. Rettger, R.E. 1935. Experiments on soft-rock deformation. Am. Ass. Pet. Geol. Bull. 19:271-292. Skempton, A.W. 1966. Some observations on tectonic shear zones. Proc. 1st Congr. Int. Soc. Rock. Mech. Lisbon, Vol. 1, pp. 329385. Smith, D.A. 1980. Sealing and nonsealing faults in Lousiana Gulf Coast salt basin. Am. Ass. Pet. Geol. Bull. 64: 145-172.


50 Tchalenko, J.S. 1970. Similarities between shear zones of different magnitudes. Geol. Soc. Am. Bull. 81: 1625-1640. Weber, K.J. 1987. Hydrocarbon distribution patterns in Nigerian growth fault structures controlled by structural style and stratigraphy. J. Pet. Sci. Eng. 1: 91-104. Weber, K.J., Mandl, G., Pilaar, W.F., Lehner, F.K. and Precious, R.G.

1978. The role of faults in hydrocarbon migration and trapping in Nigerian growth fault structures. Proc. 10th Ann. Offshore Technol. Conf., Houston, TX, Vol. 4, pp. 2643-2653. Wunderlich, H.G. 1957. Briiche und Gr~iben im tektonischen Experiment. N. Jahrbuch f. Geologie u. Pal~iontologie. Monatshefte pp. 477-498.

F.K. LEHNER Institute for Geodynamics, Bonn University, Nussalle 8, D-53115 Bonn, Germany W.F. PILAAR J.F. Kennedy plantsoen 63, 2252 EV Voorschoten, The Netherlands

51

Fault seal processes- systematic analysis of fault seals over

geological and production time scales J.R. Fulljames, L.J.J. Zijerveld and R.C.M.W. Franssen

Fault seal analysis should apply a rigorous, integrated strategy, including all possible aspects of fault seals as well as top seals. In this paper we describe data and empirical relationships that enable a quantitative approach to fault seal prediction. We subdivide fault seals into juxtaposition seals and fault gouge seals. Clay smear continuity along a fault is quantified using the clay smear potential formula, which can be calibrated using data from proven oil accumulations. Prediction of brittle deformation mechanisms, and related retention capacities as well as fault transmissibilities can be based on empirical relationships with measurable matrix properties presented in this paper. On geological time scales the retention capacity of a fault seal depends on the minimum capillary entry pressure encountered along it. All categories of fault seals may greatly affect production behaviour. The effects on production of faults acting as transmissibility barriers are illustrated using reservoir simulation models.

Introduction The initial step in quantification of fault sealing is to identify the mechanism(s) involved in fault sealing. We subdivide fault seals into two types based on: (1) geometrical or juxtaposition fault seals, where the hydrocarbons are trapped by the sealing properties of the juxtaposed lithology and (2) fault gouge seals where the fault gouge material itself retains hydrocarbons. Fault seals caused by processes such as clay smear, brittle deformation and diagenesis fall into this latter category (Fig. 1). The prediction of fault seal capacity requires the evaluation of each fault seal mechanism and its possible effect on fault sealing.

Capillary seals versus permeability barriers Faults that are water wet act as capillary seals, i.e., retention is controlled by capillary entry pressure (Smith, 1980; Watts, 1987; Ingram and Naylor, 1997). In a water-hydrocarbon system, the fault's minimum capillary entry pressure is the maximum pressure difference which can be maintained across the fault before the hydrocarbons have sufficient pressure to breach through the pore throats and leak across the fault. Over geological time a fault is only as sealing as its most leaky part. The static sealing capacity of a fault is the maximum hydrocarbon column length (HCco~umn) which can be retained by this fault over geological time. It depends on the capillary entry pressure of the seal for a specific hydrocarbonwater interface (Pencwat~,), the difference between water and hydrocarbon densities at depth (DwaterPuc), and the acceleration of gravity (g)

P e HCwater n f c o l u m n --

(1) g(/gwate r - - / 9 HC )

If a fault is hydrocarbon-wet or the pressure difference across it exceeds the capillary entry pressure, it will leak and become a permeability barrier to flow. The probability that a hydrc:arbon column will be retained by a permeability barrier over geological time is a function of the rate of flow through the fault. In the case of Darcy flow, the rate of flow (Q) per unit area is proportional to the pressure gradient (AP/Ax) across the fault, the fault permeability (x), and inversely proportional to the fluid viscosity (,u): x AP Q=--• (2) kt Ax

Fault sealing over geological time scales In the following sections we outline a systematic approach to analyse fault sealing over geological time scales, integrating geometric fault seals and fault gouge seals (Fig. 2).

Juxtaposition fault seals A pre-requisite for fault seal analysis is a consistent structural model, with sufficient detail and proper fault linkage relationships. The first step of static fault seal analysis (Fig. 2) involves the construction of a juxtaposition diagram (Allan, 1989), in which areas where reservoir is juxtaposed against a sealing lithology are identified. The retention capacity is calculated from the minimum capillary entry pressure of the juxtaposed lithology, which can be measured or

Hydrocarbon Seals: Importance for Exploration and Production edited by P. M~ller-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 51-59, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997

52

J.R. Fulljames, L.J.J. Zijerveld and R. C.M.W. Franssen

Fig. 1. Classification of fault seal processes. Fault seals are divided into two types: juxtaposition fault seals and fault gouge seals (e.g., cataclasis and clay smear). One fault may have a combination of different sealing processes affecting its sealing capacity.

predicted from a database of lithology properties. Shales have high entry pressures due to their small pore throat sizes (Ingram and Naylor, 1997). They retain large columns and traps with juxtaposed shales tend to be filled to the fault spill point (geometry dependent). Coarser lithologies, such as siltstones, have lower retention capacities due to their larger pore throat sizes (Watts, 1987). The retainable hydrocarbon column lengths are therefore strongly controlled by

properties of the juxtaposed lithology (lithology dependent). Fault gouge seals The second stage of static fault seal analysis is the evaluation of the properties of the fault gouge (Fig. 2). In the presence of clay layers, the introduction of clay into a fault is one way of strongly increasing the capillary entry pressure. A common process is the

Fig. 2. Strategy for the analysis of fault seals over geological time scales. Based on a fault juxtaposition diagram, the effects of the different fault seal processes are assessed in a systematic manner for their seal capacity due to clay smear, brittle fault sealing and juxtaposition fault seal.

Fault seal processes: systematic analysis of fault seals over geological and production time scales

smearing of clay into the fault by a combination of ductile flow and dilation of the fault zone (Lehner and Pilaar, 1997). The effectiveness of clay smearing strongly depends on the ductility of the clays at the time of deformation, which can be assessed from sonic log trends and consolidation history (Ingram and Naylor, 1997). In high net to gross stratigraphies, or if clays were not ductile at the time of deformation, faults should be assessed for their sealing properties due to brittle faulting.

Clay smear Clay smear forms as a result of a ductile flow of clay source bed whereby the clay is squeezed into and smeared along the fault between the up and down

53

thrown source beds (Fig. 3) (Weber et al., 1978; Smith, 1980; Lindsay et al., 1993; Lehner and Pilaar, 1997). The amount of clay smear at a point on the fault reduces with distance to the source bed. The smear forms a layered gouge containing clay from each source bed. The greater the number and thickness of source beds, within the throw window, the greater the thickness of the smear. A thick smear is more likely to be continuous across the area of the fault, whereas a thin smear is more likely to be discontinuous. Aside from easily derivable quantities like fault throw and stratigraphic bed thickness there are several other factors which affect the amount of clay smear, like the clay rheology during deformation, the

Fig. 3. Outcrop picture of a clay smear. Photograph was taken in a lignite quarry in SE Germany, throw ca. 10 cm. It shows the cumulative effect of two thin clay layers. The deformation occurs by a combination of squeeze flow, as indicated by thinning of the source bed, and simple shear as evidenced by the sharp contacts between fault gouge and undeformed rock.

54

Fig. 4. Schematic diagram of the clay smear potential calculation. The CSP is calculated at a certain point at a fault from the thickness of individual clay source beds (hi), and the distance from the source beds to that point (si). For each clay bed that passed the calculation point, the thickness is squared and divided over the distance (h i + si). The clay smears derived from all source beds that passed the calculation point are summed, both for the upthrown and downthrown side (CSP-, CSP+). The highest of these is found to have the most predictive power and taken as the CSP. A calibration term (c) is included to cover rheological properties and stress dependencies of clay smear.

depth of deformation and the angle of the fault. The present quantification of clay smear potential (CSP) includes 0nly the geometrical effects of fault throw and stratigraphic bed thickness (Fig. 4) (Bouvier et

J.R. Fulljames, L.J.J. Zijerveld and R. C.M. W. Franssen

al., 1989). A calibration term is included to cover rheological properties (i.e., weaker clays form better smears) and stress dependencies of clay smear (clay smear formation is favoured by low normal stress on the fault). The CSP value is interpreted to represent an indication of the continuity of a clay smear seal. As it is a relative measure, it can be used to rank prospects along faults of similar type within similar stratigraphies. To actually calculate the hydrocarbon column length retained by a fault sealed by clay smear, a calibration must be performed using faults known to retain hydrocarbons across sand to sand juxtaposition windows. By overlaying both CSP data and hydrocarbon fill data on the juxtaposition diagram, the lowest CSP values at sealed sand to sand contacts can be found. A compilation of CSP studies shows that an increased number of traps are filled at higher CSP (Fig. 5), i.e., CSP should be used in a probabilistic manner, where high CSP indicates a greater chance of an intact fault seal, than low CSP.

Brittle deformation of reservoir sandstones The prediction of the sealing effect of brittle deformation in reservoir sandstones involves several steps (Figs. 2 and 6). At present, predictions are limited to clean sandstones. The initial step assesses the potential for and extent of cataclastic deformation. If cataclastic deformation can be shown to be the likely deformation mechanism, then the fault properties can

Fig. 5. CSP calibration. The data for this calibration were gathered on 91 reservoirs along 10 faults in three different fields. Comparing the CSP in hydrocarbon bearing sand to sand windows with those in water bearing sand to sand windows results in a fault seal probability curve. The fault seal probability increases with increasing CSP up to a certain value above which sealing is independent of CSP.


55

Fig. 6. Brittle fault seal analysis strategy. The strategy aims to quantify the sealing capacity of brittle faults by first predicting the deformation mechanism. Particulate flow faults are treated as non-sealing. Cataclastic faults have variable sealing properties according to fault throw and matrix properties. The chart in the lower left of this figure is reproduced at a larger scale in Fig. 8.

be estimated from empirical relationships. These estimates together with throw and fault continuity are combined to predict the fault's overall retention capacity. The brittle deformation mechanism map for clean reservoir sandstones (Fig. 6) relates the type of deformation to matrix porosity and depth of burial at the time of deformation (Loosveld and Franssen, 1992). It is based on data from deformation experiments on cored samples and field specimens. As a rule of thumb, at less than 1 km depth, high porosity sandstones deform by particulate flow (Fig. 6). During particulate flow, the grains roll past one another without grain crushing and the pores within the fault zone tend to dilate. After deformation, the faults are buried and compacted. Unless significant diagenesis occurs, the resulting fault gouge has properties not significantly different from the surrounding matrix and negligible retention capacity. At greater depths (and consequently lower porosities), faults tend to deform by cataclasis (Fig. 6). Grain crushing along discrete shear faults leads to significant grain size reduction within fault zones (Fig. 7). Subsequent compaction and cementation of the deformed fault gouge during further burial, cause significant reductions in fault porosity and permeability and increased capillary entry pressures. An extensive database has been collected to develop empirical relationships which enable the prediction of cataclastic fault properties from measurable matrix properties. Fig. 8 illustrates how the perme-

ability change of a fault, relative to the surrounding reservoir rock, varies with porosity. Faults which are currently deforming are termed active faults whereas faults which have been buried, compacted, and cemented are termed inactive faults. The available data cover deformation bands and to a lesser extent slip planes. The normal statistical variation in these types of data tends to be quite large. Apart from that, some of the spread in the data may be due to variations in lithology, strain rate, total displacement and burial depth at which the faults were active. These effects are not accounted for. At small fault displacements, deformation bands form a loosely anastomosing network. As displacement increases slip planes develop. Ultimately, deformation bands become more and more linked, forming a closer network and slip planes become increasingly continuous. On slip planes, the intensity of cataclasis is significantly increased, which results in a further reduction in permeability of two orders of magnitude compared to small scale cataclastic deformation bands (Fig. 8). An empirical relationship of capillary entry pressures and permeability (Fig. 9) can be used for the prediction of retainable hydrocarbon column length for cataclastic faults (Eq. (1)). The development described from loosely anastomosing deformation bands to zones of highly interconnected deformation bands and slip planes has major implications for retention capacity (Loosveld and Franssen, 1992; Antonellini and Aydin, 1994, 1995). At low fault displacements the retention ca-

J.R. Fulljames, L.J.J. Zijerveld and R. C.M.W. Franssen

56

Fig. 7. SEM image of a cataclastic fault gouge in a clean sandstone.

pacity will be negligible and as displacement increases, the retention capacity will increase to deformation band properties and subsequently to slip plane properties. Improved understanding of internal fault geometries will enable better estimation of retention capacities (ideally from a mapable quantity like fault displacement).

Permeable fault seals

Simple one-dimensional reservoir models (two phase Darcy flow) indicate that, in general, the flow rates across permeable fault seals will be too high to sustain high pressure gradients or corresponding differences in hydrocarbon column lengths over geo-

Fig. 8. Matrix porosity versus permeability reduction in faults. The upper trend describes the range of permeabilities observed within actively deforming cataclastic deformation bands. Permeabilities are enhanced at low porosities, and slightly reduced at high porosities. The lower trend describes how inactive faults after burial show highly reduced permeability relative to the matrix. This permeability reduction gets more significant with increasing matrix porosity.


57

Fig. 9. Permeability versus capillary entry pressure. Entry pressure increases with decreasing permeability. The regression line drawn through the data was derived for a range of lithologies by Ibrahim et al. (1970) (Watts, 1987; Antonellini and Aydin, 1995). The relationship appears to hold for the cataclastic faults as well. Some of the deviations from the regression are due to uncertainties in the thickness of the deformation bands and slip planes, which lead to overestimated fracture permeabilities of up to one order of magnitude.

logical time (several millions of years). This is due to the fact that the widths of faults are small and fault permeabilities are relatively high. On a production time scale, however, these faults are seen to have a significant effect on reservoir behaviour.

Fault sealing over production time scales On production time scales, faults may leak and become permeability barriers if the entry pressure has been exceeded by the pressure difference across the fault. Once the seal is breached, "Darcy" flow of hydrocarbons occurs across the fault. In the case of a juxtaposition fault seal, the large thickness and low permeability of the sealing lithology lead to negligible flow rates. Due to their variable permeabilities and relatively small widths, the leak rates through fault gouge seals tend to be significantly higher. We describe a systematic strategy to quantify the various factors which inhibit the flow of hydrocarbons across faults. Faults acting as flow barriers over production time scales will develop pressure lags, and reduce the drainage efficiency of faulted reservoirs. Fault properties controlling the magnitude of the pressure lag across a permeable fault are the fault transmissibility (its capacity to resist flow based on average sealing properties) and the size of the area on the fault across which flow can occur. Additional controls are the size of the reservoir compartments (the bigger the non-producing compartment the bigger the pressure lag), and the rate of pressure draw down in the producing block.

The effectiveness of a fault as a flow barrier is hard to measure directly but can be estimated from 1-D and 3-D flow simulations of field examples. The results give estimates which can be applied to similar faults of unknown properties. An example where such a methodology was used is schematically illustrated in Fig. 10. A hydrocarbon filled block, in an existing field, was produced over a number of years from a single producing cluster. A series of observation wells monitoring the depletion profiles over several years in different fault blocks, revealed pressure lags developing through time. The magnitude of these pressure lags was different across different faults. A model was built using the best estimates of the variables including volumetrics, stratigraphy, leak window area, hydrocarbon and aquifer properties. By "producing" hydrocarbons, the pressure in one block was depleted at the measured rate while the depletion profiles of the non-producing block were monitored. The least known parameter, the transmissibility of the faults, was varied until a history match was achieved between the modelled and observed depletion profiles. Comparison for different faults showed that faults with small displacements had to be modelled with higher transmissibilities than faults with large displacements.

Discussion We strongly recommend a rigorous, integrated strategy to fault seal analysis, including all possible aspects of fault as well as top seals. The rigour of the

58

J.R. Fulljames, L.J.J. Zijerveld and R. C.M. W. Franssen

Fig. 10. Flow simulation pressure history match. A simple block model was depleted by producing gas from a production well. The fault transmissibility varied to alter depletion rates in the non-producing block until a best-fit pressure history match was achieved. The resulting transmissibility could be related to the observed throw on the fault.

analysis strongly depends on the quantity and quality of the data available. We have reached a high level of understanding of clay smear seals and cataclastic seals in clean reservoir sands. Our studies are currently aimed at expanding our knowledge to other lithologies like micaceous sands, carbonates and brittle shales. In addition we focus on an improved understanding of the internal fault zone geometry, and how this varies with fault displacement. It seems unlikely to formulate a general approach to analysis of diagenetic overprints on the mechanically formed fault gouge fabrics. In our present approach, these are assessed on a field by field basis.

Conclusions We subdivide fault seals into juxtaposition seals and fault gouge seals. Juxtaposition seals retain hydrocarbons due to the geometrical juxtaposition of a

sealing lithology across a fault. At fault gouge seals, hydrocarbon retention depends on the properties of the material in the fault zone itself. The minimum capillary entry pressure of a seal determines the retainable hydrocarbon column length on geological time scales. Permeable fault seals are unlikely to retain significant hydrocarbon columns on geological time scales, but may have a significant effect on production behaviour. Effective clay smears are likely to form along synsedimentary faults in low net to gross sections. It can be quantified using the geometrically derived CSP equation, which requires fault throw and stratigraphic data. High CSP values relate to thick, continuous clay smears with high retention capacities. Low CSP values relate to thin, discontinuous clay smears which may act as strong transmissibility barriers over production time scales. The prediction of the retention capacity of a fault due to Clay smear requires calibration on known fault-bounded accumulations

Fault seal processes: systematic analysis o f fault seals over geological and production time scales

Faults in sandstones deformed at depths greater than 1 km tend to deform by cataclasis. Permeability and entry pressure of such faults can be predicted from estimates of matrix properties. Static seal capacities of cataclastic faults depend on the minimum sealing properties, which are related to the fault displacements. Identifying fault barriers, and the compartments resulting from them, at an early stage of production can help to optimise development well planning. Faults become more effective transmissibility barriers with increasing average sealing properties, decreasing leak window areas and increasing size of nonproducing blocks.

Acknowledgements Shell International Exploration and Production B.V. is thanked for granting permission to publish this paper.

References Allan, U.S. 1989. Model for hydrocarbon migration and entrapment within faulted structures. Am. Assoc. Pet. Geol. Bull., 73: 803811. Antonellini, M. and Aydin, A. 1994. Effect of faulting on fluid flow in porous sandstones. Am. Assoc. Pet. Geol. Bull., 78: 355-377.

Antonellini, M. and Aydin, A. 1995. Effect of faulting in porous sandstones: geometry and spatial distributions. Am. Assoc. Pet. Geol. Bull., 79: 642-671. Bouvier, J.D., Kaars-Sijpesteijn, C.H., Kluesner, D.F., Onyejekwe, C.C. and van der Pal, R.C. 1989. Three-dimensional seismic interpretation and fault sealing investigations, Nun River Field, Nigeria. Am. Assoc. Pet. Geol. Bull., 73: 1397-1414. Ibrahim, M.A., Tek, M.R. and Katz, D.L. 1970. Threshold Pressure in Gas Storage. American Gas Association, Arlington, VA, 309 pp. Ingram, G.A. and Naylor, M.A. 1997. Top seal processes and assessment. In: P. Mr and A.G. Koeslter (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 165-174. Lehner, F.K. and Pilaar, W.F. 1997. On a mechanism of clay smear emplacement in synsedimentary normal faults. In: P. M~llerPedersen and A.G. Koeslter (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 39-50. Lindsay, N.G., Murphy, F.C., Walsh, J.J. and Watterson, J. 1993. Outcrop studies of shale smears on fault surfaces. Special Publication 15. Int. Assoc. Sediment, pp. 113-123. Loosveld, R.J.H. and Franssen, R.C.M.W. 1992. Extensional versus shear fractures - implications for reservoir characterisation. SPE.25017. Smith, D.A. 1980. Sealing and non-sealing faults in Louisiana Gulf Coast basins. Am. Assoc. Pet. Geol. Bull., 64: 145-172. Watts, N.L. 1987. Theoretical aspects of cap-rock and fault seals for single and two-phase hydrocarbon columns. Marine Pet. Geol., 4: 274-307. Weber, K.J., Mandl, G., Pilaar, W.F., Lehner, F. and Precious, R.G. 1978. The role of faults in hydrocarbon migration and trapping in Nigerian growth fault structures. Proc. 10th Annual Offshore Technology Conf.

Shell International Exploration & Production BV., P.O. Box 60, 2280 AB Rijswijk, The Netherlands Shell International Exploration & Production BV., P.O. Box 60, 2280 AB Rijswijk, The Netherlands Present address: 21 Oxford Street, Edinburgh EH8 9PQ, UK R.C.M.W. FRANSSEN Shell International Exploration & Production BV., P.O. Box 60, 2280 AB Rijswijk, The Netherlands Present address: Shell Oil Company, OPA, P.O. Box 4704, Houston, TX 77210-4704, USA

J.R. FULLJAMES L.J.J. ZIJERvELD

59


61

Complexity in fault zone structure and implications for fault seal prediction C. Childs, J.J. Walsh and J. Watterson

In their simplest form, brittle faults consist of a single zone of intense deformation which macroscopically is seen as a slip surface and/or a zone of fault rock. More generally, fault zones have complex geometries with multiple slip surfaces and/or deformation zones. The most common pattern in complex fault zones observed at outcrop is a fault zone bounded by a pair of sub-parallel slip surfaces. In three dimensions, fault zones bounded by paired slip surfaces alternate both laterally and up/down dip with areas of only one slip surface. Within this overall framework, a range of fault rocks is irregularly distributed as spatially impersistent sheets and lenses. Due to seismically irresolvable complexities of fault zone structure, the juxtapositions of footwall and hangingwall rocks predicted from seismic data will in most cases be different from those actually present. The importance of such differences to the prediction of across-fault connectivity, of both hydraulically passive and hydraulically active fault zones, is strongly dependent on the reservoir sequence. Connectivities are calculated for hydraulically passive and active faults offsetting an Upper Brent Reservoir sequence. Shaley fault rocks within brittle fault zones often represent a spatially persistent, although variable thickness, component of the zones and provide a basis for the application of empirical methods of fault seal prediction to brittle faults. The distribution of fault rocks cannot be characterised from well data, raising the question of whether purely deterministic methods for fault seal prediction can ever be successful. The way forward is refinement of current empirical methods by achieving a more detailed characterisation of sub-surface faults, allowing more quantitative comparisons of target faults with those of known sealing behaviour.

Introduction

Data for characterisation of faults in the subsurface are limited to two sources, seismics and wells. Seismic reflection data allow the displacement distribution over a fault surface to be mapped while well and core data may allow determination of fault rock types and deformation mechanisms at specific points, in addition to characterising the lithologies of the host sequence. It is evident from outcrop studies that the internal geometries of fault zones are usually complex, in terms of the numbers of individual slip surfaces, the partitioning of slip between them and in the distribution of different fault rocks, all of which vary over a fault surface. This 3-D complexity of fault zone structure may not be apparent from either seismic or core data but is nevertheless crucial to the bulk hydraulic properties of a fault. A model for the development of the complex internal structures of fault zones has recently been proposed (Childs et al., 1996). Although this model does not increase the predictability of sub-surface fault zone structure, it demonstrates how complexity can arise from the operation of simple processes and provides a framework for consideration of the uncertainties inherent in prediction. The purpose of this paper is to describe and develop this model in terms relevant to the problems of fault seal prediction. While

the model represents a further step towards development of a deterministic method of fault seal prediction, the successful application of a reductionist approach to seal prediction remains a remote possibility. The fault sealing mechanisms considered are those which occur as a direct result of the faulting process, i.e., those due to either across-fault juxtapositions of reservoir and non-reservoir units or to the presence of sealing fault rocks, i.e., membrane seals. The diagenetic contribution to seals (Knipe, 1992) is not considered. Fault zone structure

Brittle fault zones comprise discrete slip surface(s) and fault rocks. There is a general positive correlation between fault displacement and the thickness and complexity of the fault zones (Robertson, 1983; Hull, 1988). Complex fault zones generally comprise multiple slip surfaces or zones of intense shear (Childs et al., 1996). The simplest and most common multi-slip fault zones observed in outcrop are structures with two discrete bounding slip surfaces, enclosing fault rock which may vary from intensely deformed to virtually undeformed (Koestler and Ehrmann, 1991; Childs et al., 1996). Where sufficient data are available, areas of a fault zone with the paired slip surface geometry can be seen to alternate with areas with a

Hydrocarbon Seals: Importancefor Exploration and Production edited by P. Mr


C. Childs, J.J. Walsh and J. Watterson

62

a

a

b

b C

Fig. I. Cartoon illustrating the asperity bifurcation model of fault zone widening. An irregularity on a fault surface (grey fill) in (a) is sheared off by the formation of a new slip surface in (b). Subsequent fault movement may result in deformation of the newly formed slip surface bounded lens.

" ,~iiiiii!iiii!iiiiiii!iiiiiiiiiiiiiiiiiiiiiiiiiiiiiiili!i!i~ ............ ~,iiiiiiiiiiiiiiiiiiiiiiiiiiiiiii!!ii!iiiii~ ......

single slip surface or zone of intense deformation. This type of structure, with rock lenses bounded by slip surfaces, is developed by either or both of the processes, asperity bifurcation and tip-line bifurcation (Childs et al., 1996), illustrated in Figs. 1 and 2, respectively. Asperity bifurcation is due to the shearing off of fault surface irregularities by the formation of new slip surfaces. These irregularities may occur anywhere on a fault surface and on any scale. Irregular Fig. 2. Successive stages of the tip-line bifurcation process of fault zone widening and generation of paired bounding slip surfaces (see text). The tip-line of a fault surface (e), part of which is shown shaded in (a)-(d), propagates upwards through a rock volume. The area shown in (a)-(d) is indicated by the rectangle in (e). With fault growth the elliptical tip-line bounding the fault surface propagates radially to the successive positions, a-d, shown in (e). The lines labelled I-III in (a) indicate successive positions of the fault surface tipline.

e

Complexity in fault zone structure and implications f or fault seal prediction

fault surfaces can either be inherited from non-planar surfaces formed when a fault propagated or be developed during continued fault growth, for example by bedding-parallel slip. Strain of a rock volume adjacent to a fault (Barnett et al., 1987) is often partly accommodated by bedding-plane slip which disrupts existing planar fault surfaces. Asperity bifurcation at outcrop or larger scales is equivalent to the grain scale wear process described by Engelder (1978). A paired bounding slip surface geometry will persist until the newly formed active slip surface has significantly higher displacement than its predecessor. Tip-line bifurcation is a process related to the radial propagation of the fault surface tip-line which accompanies increase in fault displacement, as shown in Fig. 2e. Tip-lines are locally retarded where they encounter mechanical heterogeneities (Huggins et al., 1995) and tip-line embayments are formed as shown in Fig. 2a by local arrest of a propagating tip-line. An embayment locally divides the fault surface into two lobes which are free to propagate independently and slightly out of plane with respect both to the main fault surface and to one another (Fig. 2b). At this stage the overall fault tip-line has by-passed the point of embayment, as shown in Fig. 2e. With continued fault growth the two fault lobes propagate laterally and overlap one another (Fig. 2c) to form a relay zone (Peacock and Sanderson, 1994; Huggins et al., 1995). With further fault growth, failure occurs by linkage of the overlapping fault surfaces (Fig. 2d). This evolution is accompanied by increasing strain of the sliver of rock between the slip surfaces. The end result of this process is the formation of a fault bounded lens of relatively undeformed rock, a cross-section through which displays a paired bounding slip surface geometry. Both bifurcation processes are independent of scale and can result in the formation of slip surface separations and lens dimensions on different scales, often simultaneously. Whereas asperity bifurcation can occur at any point on a fault surface, the tip-line bifurcation process is restricted to tip-lines but can occur on a range of scales at the same location. The varied scales can be visualised by thinking of the simple elliptical tip-line shown in Fig. 2e as having embayments on all scales. Offset and overlapping fault geometries (Fig. 2b,c) occur on faults of all sizes (Griffiths, 1980; Larsen, 1988; Peacock and Sanderson, 1991; Stewart and Hancock, 1991; Peacock and Sanderson, 1994). The action of either, or both, bifurcation processes at a point on a fault surface generally results in a stepwise increase in fault zone thickness and in a highly complex internal fault zone geometry. The asperity bifurcation process, and the formation of new slip surfaces within a fault zone, may also cause

63

fault zone thinning by "structural erosion" of previously formed fault rock as fault displacement increases. Both bifurcation processes result, at least initially, in lenses or pods of relatively undeformed rock becoming incorporated in a fault zone. Fig. 3a-c shows an outcropping fault zone consisting of lenses of fault rock each of which is bounded by discrete slip surfaces, These lenses range from intensely deformed to virtually undeformed. Each lens of fault rock may differ from neighbouring lenses in respect of both deformation intensity and rock composition. Each lens is a distinct element many of which are interpreted as having been incorporated into the fault zone by a fault surface bifurcation event. In the fault zone illustrated (Fig. 3), the numerous slip surface bounded lenses of similar size are consistent with this fault zone having widened dominantly by asperity bifurcation. Many of the slip surfaces which form boundaries to lenses within this fault zone may have formed within the existing fault zone and therefore would not have contributed to widening of the fault zone. Fault zone thickness

Measurement of fault zone and fault rock thicknesses in complex fault zones (Fig. 4) can be very subjective (Evans, 1990). In particular, the distinction in either outcrop or core between a single multi-slip surface fault zone and two or more individual faults is dependent on the distances between slip surfaces relative to their displacements, their relative orientations, the deformation state of the intervening rock and the larger scale context. Slip surfaces which at one scale of observation appear as separate faults may, with a more extended view, be clearly seen to be part of a single fault zone. As this problem can occur on any scale of observation and is effectively intractable, it should be borne in mind when assessing fault zone thickness data. The fault zone thickness versus fault displacement data in Fig. 4 are assigned to one of three fault zone categories. These are (i) single zones of fault rock, (ii) complex fault zones containing both fault rock and weakly deformed lenses of rock enclosed by two or more slip surfaces, and (iii) unclassified zones. The data distribution is broadly similar to that shown by previous workers (Otsuki, 1978; Robertson, 1983; Segall and Pollard, 1983; Hull, 1988; Blenkinsop, 1989) except that the data in Fig. 4 define a wider band and larger range of fault zone thicknesses for a given throw value than previously published datasets. This difference is largely, but not entirely, due to inclusion of category (ii) fault zones. Inclusion of these

C. Childs, J.J. Walsh and J. Watterson

64

a

b

C

Fig. 3. (a) A normal fault with a throw of 18 m in a Carboniferous mixed sandstone/shale sequence from a quarry in Lancashire, UK. The fault zone dips towards the observer. The hangingwall rocks have been removed by quarrying operations to expose the fault zone rocks which occur as lenses. Outlines of the most prominent lenses are shown in (b). Lenses dominantly of sandstone are stippled and those dominantly of shale are shaded. Mixed sandstone/shale lenses also occur (shaded and heavy stipple). Rocks in the lenses range from almost undeformed to highly deformed. (c) Detail of the sandstone breccia lens marked SB in (b), which, during quarrying operations, has slipped along its lower bounding slip surface and broken open, revealing a ca. 1 m thickness of sandstone breccia which tapers in all directions. The hammer at the centre of the photograph is 0.5 m long.

complex fault zones increases by an order of magnitude the range of fault zone thicknesses for a given displacement. A complex multi-slip surface fault zone may even have a thickness greater than the fault displacement. Although prediction of fault hydraulic properties is relevant to both exploration and production, a differ-

ent prediction is required in each of the two situations. For exploration, prediction of the sealing capacity of a particular fault is required, while for production purposes prediction of the combined effects of many faults within a reservoir volume may be the main concern. Uncertainties in the two cases are therefore viewed differently. In exploration, a fault is

Complexity in fault zone structure and implications for fault seal prediction

OEb

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., ",

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.,, ,,

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ii

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Fig. 4. Plot of fault displacement versus fault zone thickness. Faults zones are distinguished as (i) simple fault zones comprising a single slip surface or zone of deformation (small crosses), (ii) complex fault zones comprising multiple (normally two) slip surfaces separated by undeformed or slightly deformed rock (squares), and (iii) fault zones n o t assigned to either category (filled circles). Many of the data assigned to category (i) are from published sources (Robertson, 1983; Hull, 1988; Otsuki, 1978; Segall and Pollard, 1983; Blenkinsop, 1989). Published data in category (ii) are from Wolf (1985). Data from a coastal section exposing small normal and oblique-slip faults cutting a chalk sequence at Flamborough Head, UK, represent maximum (large crosses) and minimum (small circumscribed crosses) fault rock thicknesses (category (i)) measured on individual fault traces.

predicted to be either sealing or non-sealing, and a level of uncertainty is attached to the prediction. In the case of production, uncertainty in the estimation of hydraulic properties of faults is expressed as uncertainty (or probability) in the results of reservoir flow simulation. The crucial difference between the two types of requirement can be summarised by saying that production requires estimation of the average hydraulic properties of a typical reservoir fault on a relatively short timescale, while exploration requires estimation of the hydraulic properties of the "weakest link" on a fault surface on a geological timescale. For production purposes, data relating fault displacement to fault thickness (Fig. 4) can readily be applied by taking a median line through the data distribution. For individual fault seal prediction it is the minimum rather than the average fault rock thickness in a fault zone which is crucial in determining whether or not an oil column can be supported. Fig. 4 shows that for a given throw, fault rock thickness varies by more than two orders of magnitude. B lenkinsop (1989) showed that, on a fault with 23 m strike-slip move-

65

ment, the fault rock thickness varied by an order of magnitude over an exposed fault trace length of only 12 m. If thickness had been measured over the entire fault surface rather than on a single short section, this range is likely to have been greatly extended. Fault rock thickness data from small (throw 25-35 25-35 60--65

E50 (MPa) 7600-9500 1800-1600 5700-9500 2400-3500 4000-6000 7500-8700 2800-5510 6310-9570 15000 35000

eef (%)

CS (MPa)

~' (o)

o"2' or o"3'/Ol ' ratio

0.2-0.8 1.18-1.64 0.49 0.5-2.7 0.6-1.9 0.9-1.4 0.6-1.9 0.4-1.3 >0.3

11.5-16.0 9.1-20.0 6.4 4.5-5.5 16.9-17.5 12.5 14.5-18.5 4.75 35 2.5 37

15-20 13-20 30 19-23 8-13 25 4-9.5 26.5 5 48 23

0.20-0.43 0.32 0.32 0.1-0.5 0.48 0.25 0.1-0.54 0.23-0.31

c. 0.3

The following data are given: rma x = range of measured shear strength, ES0 = range of tangent Young's modulus, eef = range of axial strain at failure, C ' = "cohesion" intercept, ~ ' = angle of internal friction, a 2' or o.3'/o'1' = ratio of cell pressure to axial stress at failure. "Cohesion" and angle of internal friction are given in terms of effective stress. Note that data from both vertical and horizontal specimens are given for wells 7321/9-1, 7125/1-1 and 7228/2-1.

tween 7.5 and 32.0 MPa. For "horizontal" samples (drilled and loaded parallel to the bedding), shear strengths in the range between 13.7 and 22.4 MPa were obtained. During CAU triaxial testing, most specimens showed a general brittle deformation, although brittleness varied from sample to sample. With one exception (test 3 of well 7321/9-1 where the rock strength exceeded that of the apparatus), the tests were run to failure. The dip angle of the experimentally generated fractures were measured after the deformation. For the Fuglen Formation of well 7321/91, planar conjugate fractures (double shears) were developed, and nine fractures with an average dip of 56 ~ were measured. Shales of the Fuglen Formation in well 7219/9-1 revealed a slightly different pattern in that single shears were predominant and fractures with gentle dips (10-25 ~) were developed in connection with the steeper fractures (mean dip angle 55~ For the shales of the Hekkingen Formation in Well 7228/9-1 the mean was 58 ~. This indicates that the shales of the Fuglen as well as the Hekkingen Formation develop fractures very close to the theoretically value of 20 = 60 ~ during vertical loading.

A model for the fracture development of cap rocks in the southwestern Barents Sea Both mode I (tensile) and mode II (shear) fractures are commonly generated in sedimentary rocks during burial and uplift, and it is well established that the horizontal stresses (all and ah) as a function of burial and loading alone are related to the vertical stress av according to

v (XH = Uh =

1-v

aEAt - ~V +

~

1-v

(v is Poisson's ratio, E is Young's modulus, a is the thermal expansion factor of the rock), where (v/(1 - v ) ) a v accordingly describes the Poisson effect and (aEAT/(1- v)) describes the thermal expansion/ contraction (Voight and St. Pierre, 1974). Engelder (1985) used this relation to substantiate that sediments that have undergone burial and lithification may reach tensile stresses which are larger than the tensile strength of the rock during unroofing. Simultaneously, and supported by eventual tectonic stresses and fluid pressure (pf), the shear strength of the rock may be overcome during burial. Thus, depending on the mechanical strength and thermal properties of the rock, fracture populations generated during compaction and decompaction may include near-vertical and subhorizontal tensile (mode I) fractures and moderately dipping as well as low-angle elements (Engelder, 1985, 1993; Gabrielsen et al., 1997b). To evaluate the potential of fracturing of the cap rocks of the Fuglen and Hekkingen Formations, a minimum estimate of the state of stress may be compared to the measured shear strength of these rocks. Assuming an effective vertical gradient of 15 kPa/m (which is a conservative estimate), loading curves suggest normal stresses in the order of 16 MPa (well 7228/9-1; 1050 m, Hekkingen Formation), 20 MPa (well 7321/9-1; 1370 m, Fuglen Formation) to 29 MPa (well 7219/9-1; 1940 m, Fuglen Formation) at the present depth of burial. As seen from the measured shear strength values (Table 3), this is on the low side entirely to cause fracturing of the formations. However, assuming an erosion of 1000 m of sediments (which is also a conservative estimate), the corresponding vertical stresses at maximum depths of burial were 31, 36 and 44 MPa, respectively, and using a more realistic gradient of 20 kPa/m the measured shear strength values of the investigated rock.~

R.H. Gabrielsen and O.S. KlCvjan

86

all lie below the critical value. It should be emphasised here, that neither tectonic stresses nor the effect of pore pressure are considered in these simplistic calculations. Applying a distinct element discontinuum model, Makurat et al. (1992) performed a risk analysis of fracture potential of the Hekkingen Formation cap rock, applying rock mechanical data from well 7125/1-1. They found that steep, extensional fractures were initiated during unloading of a column corresponding to more than 1600 m of sediments, and concluded that erosion of more than 1600-1700 m contributes significantly to the risk of fracturing during unroofing. Their modelling also suggested that added tectonic extension would result in development of meso-scale shear fractures. Therefore, it is concluded that the burial and tectonic history of the cap rocks of the Fuglen and Hekkingen Formations are such that both mode I and mode II fractures are likely to have developed. This is in accordance with the observations made in cores, where the considerable differences observed in fracture morphology, distribution and orientation, makes it unlikely that all fractures in the Teistengrunnen Group of the study area can be attributed to the same mechanism. Accordingly, it is not likely that all fractures are of the same age. Combining these observations, four groups of fractures are identified (Table 4). Group GI consists of vertical and subvertical fractures. These structures are of type FI, and are found in small numbers in all wells except for well 7321/9-1. The fracture surfaces do generally not reveal strong slickenside lineation, and plumose markings have been seen in a couple of cases. Mineralisation is not found on fracture surfaces of group GI. Due to orientation and morphology, it is believed that these fractures are tensile of origin, that they were initiated at relatively shallow depth, and that they are associated with a vertical al. Accordingly, they expectedly should be generated during the burial stage (perhaps contemporaneously with group II fractures), or syn- or post uplift. In the latter case, they would be younger than most of the other fractures in the area. Modelling fracture development in shales of the Hekkingen Formation, Makurat et al. (1992) demon' strated that fractures with the characteristics of those

of group I may have developed during uplift and erosion. Group GII fractures are high angle (dips of 5060 ~ structures, and are generally of types FI and FII, occasionally of type FIII. They are characterised by slickenside lineations indicative of dip-slip and oblique-slip, and are found throughout the entire study area. The morphology and orientation of the group II fractures also suggest that these were initiated due to a vertically oriented cr1, and their regular distribution all over the investigated area may be taken as an argument in favour of those being generated during extension and burial. This suggests that the group II fractures are of (?) early Cretaceous (Aptian-Albian) age. It is noted that the modelling performed by Makurat et al. (1992) indicated that shear fractures with dips between 40 and 50 ~ were (re)activated during uplift under influence of extension, opening the possibility that they are younger, i.e., Palaeogene or Pliocene-Pleistocene. Group Gill fractures are typically low-angle (dips of 10-30~ and are dominated by fracture populations of types FI and FII. Slickenside lineations are common structures, and dip-slip, oblique-slip, and strike-slip movements are indicated. Recrystallisation of illitic mica along the fracture planes is characteristic of fractures of group GIII, and orientation of the mica flakes is indicative of shear movements. The group GIII fractures seem to graduate into rubble zones of type RIII, which is interpreted to represent zones of scaly foliation as defined by Lundberg and Casey Moore (1986). The fractures of group GIII dominate the wells within the master fault complexes, but are rare or non-existent in the basin areas, except for well 7125/1-1 where low-angle fractures are abundant. The orientation, distribution and strainmarkers of group GIII fractures suggest that they were generated in connection with contractional reactivation of the master faults, presumably in early Tertiary times. The fracture modelling of Makurat et al. (1992) suggests that the shales at present and deeper depths of burial would fracture during small or moderate vertical tectonic stresses. Group GIV fractures are generally infrequent, but seem to be most common in the eastern basin areas (Hammerfest Basin and Nordkapp Basin). Some low-

Table 4 Distribution of different fracture types cap rocks of the southwestern Barents Sea (see Table 1) Group

Orientation

Type

Distribution

Significance

I II III IV

Vertical/subvertical High-angle (50-60~ dip slip/oblique slip Low-angle (1-60~ mineral growth Bedding parallel

FI FI and FII FI and FII FVI

All wells All wells Bjcrn~yrenna F.C. & Asterias All wells

? Compactional Tactonic: mainly extensional Tectonic: contactional Decompaction/unloading

Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties

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Fig. 7. Subsidence curves for the southwestern Barents Sea. (a) BjcmCya Basin (Brekke and Riis, 1987). (b) BjcmCya Basin (Roufosse, 1987). (c) Tromsr Basin (Brekke and Riis, 1987). (d) Hammerfest Basin (Brekke and Riis, 1987). (e) Loppa High (Roufosse, 1987).

angle, calcite-filled fractures of this group, which are partly bedding-parallel, are partly cutting the bedding with a small angle (typically less than 10~ The fracture fill is characterised by fibrous growth perpendicular to the fracture surfaces, indicating a tensile origin. This requires fluid pressure in excess of vertical loading stress, which makes it reasonable to assume that the group IV fractures originated during uplift and unloading. Finally, the question arises whether it is possible to correlate the fractures mapped in the rocks of the Teistengrunnen Group to the established events of the tectonic history of the southwestern Barents Sea. Since the deposition of the sediments of the Teistengrunnen Group in the late Callovian (locally late Bathonian) to the early Ryazanian (Dalland et al., 1988), the different structural elements of the study area un-

derwent strongly contrasting subsidence and structuring. The Tromsr and BjCrnCya Basins underwent fast subsidence, perhaps interrupted by an inversional phase in the Cretaceous (Gabrielsen et al., 1992, 1997a), whereas more stable conditions prevailed in the Hammerfest and Nordkapp Basins as well as at the Loppa High (Brekke and Riis, 1987; Roufosse, 1987) (Fig. 7). The RingvassCy-Loppa and BjCmCyrenna Fault Complexes, which are regarded as a crustal-scale zone of weakness with a great potential of reactivation, represents the transition between these two domains. In Tertiary times, particularly the BjCrnCyrenna Fault Complex was affected by inversion. Erosion associated with Plio-/Pleistocene uplift and erosion in the southwestern Barents Sea have been calculated to vary between approximately 500 and 2000 m.

88 The maximum uncompacted depth of burial for the rocks of the Teistengrunnen Group in the southwestem Barents Sea is in the order of 2400-3500 m. Taking the results of the present rock mechanical experiments into account, it is suggested that the shear strength of the shales is exceeded at such depths. This is particularly likely since the effects of pore pressure and tectonic stresses were not taken into consideration in the minimum case calculations presented above. This would facilitate development of fractures of the kinds included in groups GI and GII during burial and compaction. It is also noted that the modelling results of Makurat et al. (1992) suggested that fractures of these types might also be generated during uplift, particularly if a tectonic extensional stress were added, and that no firm conclusion regarding the age of these structures can accordingly be drawn. Hence, it is concluded that fractures of groups GI and GII represent a "back-ground fracture network" (Gabrielsen and Koestler, 1987) associated with burial or reloading or both, and that tectonic stresses might have contributed to their development. Since calculations suggest that the cap rock seal may have been broken due to hydrocarbon expansion during uplift, it cannot be ruled out that some of the group GI fractures are related to this event. Still, it seems that the fracture frequencies of these fracture types are low, and that fractures of these types should be expected to be evenly distributed throughout the study area. It is possible that the present stress situation may contribute to continued development of fractures of this category, but it is considered unlikely that they occur in large numbers and create networks of regional importance. With the exception of well 7125/1-1, group GIII fractures are restricted to the master fault complexes which are known to be characterised by inversion. Well 7125/1-1 is situated in the foot-wall of the Nysleppen Fault Complex, and it may be speculated as to whether the abundance of low-angle fractures in this well implies that inversion also took place at the northwestern margin of the Nordkapp Basin. It is considered most likely that the microfractures of group GIII constitute networks which are continuous in three dimensions in the vicinity fault zones which have suffered inversion. This implies that the fractures of group GIII may represent a risk of leakage. According to results from their experiments on shales from the Hekkingen Formation, however, Makurat et al. (1992) found that the fractures would be characterised by small apertures when loaded, and considered leakage through this type of fracture to be less likely. Group GIV fractures are most conveniently set in relation to the stress release due to late uplift. It does

R.H. Gabrielsen and O.S. KlCvjan

not seem that these are abundant, and they are accordingly believed to be of less significance for eventual leakage.

Conclusions It is found that the cap rocks of the Teistengrunnen Formation in the southwestern Barents Sea most probably were affected by fracturing during burial and/or unroofing. The frequency of fractures related to these events seems to be low, however, and they are regarded as a minor risk for hydrocarbon leakage on the regional scale. More comprehensive fracture networks are encountered in connection with the major fault zones of the study area. The fracture intensity is highest within the master fault complexes, and particularly along those which were affected by inversion in Tertiary times. Observations and calculations elsewhere in the Norwegian continental shelf suggest that the cap rock seal may be broken due to the effects of expansion of hydrocarbons as a consequence of uplift and erosion (Caillet et al., 1991). Very few fractures at the present scale of observation that can be attributed to this effect with any confidence, have been observed in the present study area. It is concluded that the relation between cap rock quality, uplift and erosion and tectonic reactivation and hydrocarbon leakage in the southwestern Barents Sea is still obscure, and will remain so until more rock mechanical data from the cap rocks become available. It is, however, still possible to assess a risk evaluation on both regional and field scales by applying the data presently available form the area.

Acknowledgements The authors would like to thank Norsk Hydro and its licence partners for permission to publish this paper. During the present work, the authors benefited from the support, enthusiasm, and willingness to provide data from the staff of Norsk Hydro a.s., Harstad. Particularly the support of P~I Kongsg~rden has been of great help. Comments by Roald B. Fa~rseth on an early draft of the report, and helpful referee comments and suggestions by BjCm TCrudbakken are greatly acknowledged. RandiKristin Aarland, University of Bergen assisted in fracture logging, and figures were drafted by Masaoki Adachi, Jane Ellingsen and Eva BjCrseth of the University of Bergen, and the rock mechanical experiments where performed at the Norwegian Geotechnical Institute by Colin G. Rawlings and Panayiotis Chryssanthakis.

Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties

References Arthur, E., Carson, B. and von Huene, R. 1980. Initial tectonic deformation of hemipelagic sediment at the leading edge of the Japan convergent margin. Initial Report Deep Sea Drilling Project, 56, 57, part 1, pp. 569-6 13. Augustson, J.H. 1993. A method on classification of oil traps based on heavy oil content in cores with relevance to filling and drainage of Barents Sea oil-bearing structures. In: T.O. Vorren, E. Bergsager, O.A. Dahl-Stamnes, E. Holter, B. Johansen, E. Lie and T.B. Lund (Editors), Arctic Geology and Petroleum Potential. NPF Special Publication 2. Elsevier, Amsterdam, pp. 691-702. Brekke, H. and Riis, F. 1987. Tectonics and basin evolution of the Norwegian shelf between 62~ and 72~ Norsk Geol. Tidsskr. 67: 295-322. Buol, S.W., Hole, F.D. and McCracken. 1980. Soil Genesis and Classification, 2nd edn. University Press, Ames, IO, 360 pp. Caillet, G., Soum~,, C., Grauls, D. and Amaud, J. 1991. The hydrodynamics of the Snorre Field area, offshore Norway. Terra Nova, 3: 180-194. Carson, B., von Huene, R. and Arthur, M. 1982. Small-scale deformation structures and physical properties related to convergence in Japan Trench slope sediments. Tectonics, 1: 277-302. Cowan, D.S. 1974. Deformation and metamorphism of Fransiscan subduction zones complex northwest of Pacheco Pass, California. Geol. Soc. Am. Bull. 85: 1623-1634. Dalland, A., Worsley, D. and Ofstad, K. (Editors) 1988. A lithostratigraphic scheme for the Mesozoic and Cenozoic succession offshore mid- and northern Norway. Norwegian Petroleum Directorate Bulletin No. 4, 65 pp. Engelder, T. 1985. Loading paths to joint propagation during a tectonic cycle: an example from the appalachian Plateau, USA. J. Struct. Geol. 7: 459-476. Engelder, T. 1993. Stress Regimes in the Lithosphere. Princeton University Press, Princeton, NJ, 467 pp. Faleide, J.I., Gudlaugsson, S.T. and Jacquart, G. 1984. Evolution of the western Barents Sea. Mar. Pet. Geol. 1: 123-150. Faleide, J.l., VAgnes, E. and Gudlaugsson, S.T. 1993. Late Mesozoic Cenozoic evolution of the south-western Barents Sea in a regional rift-shear tectonic setting. Mar. Pet. Geol. 10:186-214. Gabrielsen, R.H., 1984. Long-lived fault zones and their influence on the tectonic development of the south-western Barents Sea. J. Geol. Soc. London 141: 651-662. Gabrielsen, R.H. and Faerseth, R.B., 1989. The off-shore extension of the Trollfjord-Komagelv fault zone - a comment. Norsk Geol. Tidsskr. 69: 57-62. Gabrielsen, R.H. and Koestler, A.G. 1987. Description and structural implications of fractures in late Jurassic sandstones of the Troll Field, northern North Sea. Norsk Geol. Tidsskr. 67: 371-381. Gabrielsen, R.H., Fa~rseth, R.B., Jensen, L.N., Kalheim, J.E. and Riis, F. 1990. Structural elements of the Norwegian Continental Shelf. Part I: the Barents Sea Region. Norwegian Petroleum Directorate Bulletin No. 6, 33 pp. Gabrielsen, R.H., Grunnaleite, I. and Ottesen, S. 1992. Reactivation of faults complexes in the Loppa High area, southwestern Barents Sea. In: T.O. Vorren, E. Bergsager, O.A. Dahl-Stamnes, E. Holter, B. Johansen, E. Lie and T.B. Lund (Editors), Arctic Geology and Petroleum Potential. NPF Special Publication 2. Elsevier, Amsterdam, pp. 631-641. Gabrielsen, R.H., Grunnaleite, I. and Rasmussen, E. 1997a. Cretaceous and Tertiary inversion in the BjcmCyrenna Fault Complex, south-western Barents Sea. Mar. Pet. Geol., 14: 165-178.

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Gabrielsen, R.H., Aarland, R.-K. and Alsaker, E. 1997b. Distribution of tectonic and non-tectonic fractures in siliciclastic porous rocks. Geol. Soc. London, Special Publication No. 127, pp. 49-64. Gray, M.B. and Nickelsen, R.P. 1989. Pedogenic slickensides, indicators of strain and deformation processes in redbed sequences of the Appalachian foreland. Geology 17: 72-75. Groshong, Jr., R.H. 1975. Strain, fractures, and pressure solution in natural single-layer folds. Geol. Soc. Am. Bull. 86:1363-1376. Hsii, K.J. 1974. Melanges and their distinction from olistostromes. In: R.H. Dott Jr. and R.H. Shaver (Editors). Modem and Ancient Geosynclinal Sedimentation. Society of Economical Paleontology Mineralogical Special Publication 19, pp. 321-333. Linjordet, A.V. and Grung-Olsen, R. 1992. The Jurassic Snr Gas Field, Hammerfest Basin, offshore North Norway. in: Giant Gas and Oil Fields of the decade 1978-1988. Am. Assoc. Pet. Geol. Memoir 54. Lundberg, N. and Casey Moore, J. 1982. Structural features of the Middle America Trench slope off southern Mexico, Deep Sea Drilling Project Leg 66. In: J.S. Watkins, J. Casey Moore et al. (Editors), Initial Reports of the Deep Sea Drilling Project, 66. US Government Printing Office, Washington DC, pp. 793-805. Lundberg, N. and Casey Moore, J. 1986. Macroscopic features in Deep Sea Drilling Project cores from forearc regions. Geol. Soc. Am. Mem., 166:13-44 Makurat, A., TCrudbakken, B., Monsen, K. and Rawlings, C. 1992. Cenozoic uplift and caprock seal in the Barents Sea: fracture modelling and seal risk evaluation. Soc. Pet. Eng. SPE 24740: 821-830. Nansen, F. 1904. The bathymetrical features of the north polar seas, with a discussion of the continental shelves and previous oscillations of the shore-line. In: F. Nansen (Editor), The Norwegian North Polar Expedition 1893-1896. Scientific Results IV(13), Jacob Dybwad, Cristiania, 232 pp. Nyland, B., Jensen, L.N., Skagen, J., Skarpnes, O. and Vorren, T. 1992. Tertiary uplift and erosion in the Barents Sea: magnitude, timing and consequences. In: R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleraas (Editors), Structural and Tectonic Modelling and its Application to Petroleum Geology. NPF Special Publication 1. Elsevier, Amsterdam, pp. 153-162. Ramsay, J.G. and Huber, M.I. 1987. The Techniques of Modem Structural Geology, Vol. 1: Strain Analysis. Academic Press, 307 PP. Riis, F. and Fjeldskaar, W. 1992. On the magnitude of the Late Tertiaruy and Quaternary erosion and its significance for the uplift of Scandanavia and Barents Sea. In: R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleraas (Editors), Structural Modelling and its Application to Petroleum Geology. NPF Special Publication 1. Elsevier, Amsterdam, pp. 163-188. Roufosse, M.C. 1987. The formation and evolution of sedimentary basins in the Western Barents Sea. In: J. Brooks and K. Glennie (Editors), Petroleum Geology of North West Europe. Graham and Trotman, pp. 1149-1161. Skagen, J.l. 1992. Effects of hydrocarbon potential caused by Tertiary uplift and erosion in the Barents Sea. In: T.O. Vorren, E. Bergsager, O.A. Dahl-Stamnes, E. Holter, B. Johansen, E. Lie and T.B. Lund (Editors), Arctic Geology and Petroleum Potential, NPF Special Publication 2. Elsevier, Amsterdam, pp. 711-719. Voight, B. and St. Pierre, B.H.P. 1974. Stress history and rock stress. In: Advances in Rock Mechanics. Proc 3rd Congr., Vol. 2. International Society of Rock Mechanics, pp. 580-582. Westre, S. 1994. The Askeladd gas f i e l d - TromsI. In: A.M. Spencer et al. (Editors), Petroleum Geology of the North European Margin. Graham and Trotman, pp. 33-39.

Departmentof Geology, Universityof Bergen, All~gaten 41, N-5007 Bergen, Norway Norsk Hydro U&P Research Centre, N-5020 Bergen, Norway


91

Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models E. Sverdrup and K. Bjerlykke

The aims of this study were to establish deformation products of faults which cut through sandstones, and to relate these products to the mechanical properties of the sandstones at the time of faulting. Based on fault descriptions and diagenetic studies, a general model for predicting deformation mechanisms and cementation of faults in sandstones is presented. Data for this study include cores from Middle Jurassic sediments in the North Sea and Haltenbanken offshore Norway, and onshore faulted sediments from the Gulf of Corinth (Greece), Brora (Scotland) and Kvalvfigen (Spitsbergen). The main results from this study show that sandstones generally are deformed by interparticulate flow at shallow to moderate burial depths due small amounts of grain locking cement and, consequently, low shear strength. Relatively denser packing of grains and local enrichment of phyllosilicates within faults are commonly observed for such faults. These are processes which tend to reduce the permeability of faults compared to the surrounding rocks, and it is therefore considered unlikely that such faults favour significant fault parallel, mineral precipitating fluid flow subsequent to faulting. Sandstones may, however, become calcite cemented due to aragonite and Mg-calcite dissolution at very shallow depth (even at the surface). When cemented, the sediments may obtain brittle properties and deform by cataclasis and brecciation. Another source for early cement within sandstones is biogenic silica which acts as a precursor for silica cements at relatively shallow depth (ca. 1500 m). Clean quartz sandstones, however, are usually not cemented until the sediment has reached a considerable depth (approx. 3 km). Brittle deformation, which may occur in cemented sandstones, prevents fault planes closing entirely and can augment a fault-parallel permeability which increases the potential for mineralization. A general model which relates fault episodes to the diagenetic history of a basin is also presented. This model may serve as a guide in order to predict fault characteristics (deformation products and style) as well as the possible presence of fault related cementation. Predictions on deformation products are highly relevant when seal evaluations of faults are to be performed.

Introduction

Flow of fluids in sedimentary basins can normally not be modelled based on the average properties of the sedimentary units filling the basins. The flow is, to a very large extent, controlled by inhomogeneities which are created by primary facies and mineral composition superimposed by diagenesis. Faults cutting through such sequences are important because they offset the sedimentary strata and thus produce lateral lithological discontinuities due to juxtaposition. In addition, the fault rocks may enhance or inhibit fluid flow within a sequence dependent on their internal structures. The development of a fault zone and its characteristics within a sedimentary sequence depend on several factors among which the most important are:

a. The tectonic framework (e.g., extensional or compressional). b. The fluid pressure and stress conditions. c. The mechanical properties of the sedimentary rocks at the time of deformation. The mechanical properties of sediments are to a

large degree determined by the diagenesis which has occurred during burial, and the mechanical properties are themselves important with respect to the textural characteristics of fractures which may evolve and cut through the sediments. The objective of this paper is to demonstrate that timing of faulting relative to diagenetic processes is critical in order to determine the deformation mechanisms which develop within fault zones (e.g., interparticulate flow, clay smear and cataclasis). Furthermore, it is demonstrated that continued subsidence and diagenesis may modify primary fault textures. A database for faults which includes onshore data (Spitsbergen, Scotland and Greece) and core data from the North Sea and Haltenbanken is presented (Fig. 1) and discussed in the first part of this paper. Observations from these areas are interpreted and discussed using burial histories and diagenetic theories. In the last part of this paper, a general model for predicting deformation mechanisms of faults which cut through sandstones at different depths in a subsiding basin is presented, and related to cementation processes which may occur along faults.

Hydrocarbon Seals: Importancefor Exploration and Production edited by P. M~ller-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 91-106, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997

92

E. Sverdrup and K. BjCrlykke

Fig. 1. Data localities for the present study (Kvalv~gen, Spitsbergen; Tilje Formation, Haltenbanken; Brent Group, Tampen Spur; Brora, Scotland; Gulf of Corinth, Greece).

Observations

Kvalv~gen, Spitsbergen The cliff section studied at Kvalvhgen, Eastern Spitsbergen displays gravitational synsedimentary faults which cut through an upper Jurassic deltaic system, representing the distal development of the Helvetiafjellet and Janusfjellet Formations. Detailed descriptions of the geological setting and deformational history are given by Nemec et al. (1988) and Sverdrup and Prestholm (1990). The faulting is interpreted to be due to collapse of the prograding delta front at, or very close to the surface. The faults through the channel sandstones appear as curved and planar fault zones, internally characterized as fault-parallel (weakly) laminated sand-

stones (see Fig. 4 in Sverdrup and Prestholm, 1990). Vertical throws fall in the range between 3 and 35 m, dips vary between 40 and 60 ~, and widths of the fault zones are between 5 and 40 cm. Fault zone boundaries are sub-parallel and the fault zone itself may express a lithological contrast if grain sizes within the faults are different to those in the adjacent beds. Enrichment of phyllosilicates locally characterize the fault boundaries. By examining grain size and mineralogical composition of the fault zones it is clear that the material herein was derived from the channel sandstones (Sverdrup and Prestholm, 1990). Variations in grain size and matrix content define the fault-parallel lamination. The undeformed sandstones and the fault zones both have porosities in the range between 0 and 5%. Additional field observations and textural char-

Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models

acteristics as discussed by Sverdrup and Prestholm (1990), concluded that the development of the fault zones within the channel sandstones was the result of fluidization and remobilization of sand (sand dikes) due to water escape from the underlying sediments. Also, because no second generation faults are seen to cut the sand dikes, the process was suggested to have occurred as a single-phase injection. Obvious fault related micro-structures include fault parallel clay laminae only (see Fig. 5 in Sverdrup and Prestholm, 1990). Although the deformation process was dominated by sand mobilization and clay smear, no evidence of a relative denser physical packing of grains in the fault zones compared to the channel sandstones were observed, a phenomenon which usually characterizes synsedimentary faulting (Allen, 1992). Furthermore, no textural evidences of faultrelated cataclasis was observed. From observations on both meso and micro scale, these faults therefore could easily have been ignored/overlooked in core studies. Later diagenetic processes include development of fault-parallel micro-stylolites (see Fig. 7 in Sverdrup and Prestholm, 1990) and extensive quartz cementation due to deep burial (ca. 3500 m) prior to later uplift and erosion. Some key observations from Kvalv~.gen are presented in Table 1a.

Tilje Formation, Haltenbanken The faults from Haltenbanken have previously been described in detail by Sverdrup and BjCrlykke (1992). The faults studied were collected from cored Middle Jurassic rocks of shallow marine origin (the Tilje Formation), at present buried to approximately 3000 m. Based on regional data and observations from cores, as well as diagenetic studies, the faulting is interpreted to have occurred at a burial depth less than ca. 5 0 0 m (Sverdrup and BjCrlykke, 1992). Faults observed in sandstones are characterized by dark seams, and appear as small-scale, individual structures concentrated within certain intervals as anastomozing or conjugated structures (see Fig. 7 in Sverdrup and BjCrlykke, 1992). Displacements are on the order of 0.5-2.0 cm, and in the microscopic scale they appear as micro-fault zones with widths between 0.1 and 5.0mm. Porosity is considerably lower within the micro-fault zones (2-7%) compared to the adjacent undeformed rocks (15-25%). Fig. 2a shows a fault characterized by dense packing of grains only. In addition, most faults were enriched in phyllosilicates (see Fig. 2b), which probably is due to concentration of dispersed mica along the fault plane in an environment where meteoric water diagenesis occurred. Similarly, authigenic

93

kaolinite may have been mobilized by shear deformation and concentrated along the fault plane. Several of the investigated faults display smaller grains within the fault zones compared to the iandeformed adjacent parent sandstones. Typically, micas are kinked and locally crushed. In a few samples, feldspar and rock fragments have been cracked. Calcite cemented brittle fractures are observed within some of the carbonate cemented intervals. Isotope studies of these fracture cements suggested very low precipitation temperatures (15-20~ (Sverdrup and BjCrlykke, 1992) compared to carbonate cement which occurs within other sandstone intervals that exhibit isotope values corresponding to crystallization temperature in the range between 50 and 77~ Fault structures cutting the late cemented sandstones, however, display fault textures similar to non-cemented sandstones (dense packing of grains and phyllosilicate enrichment). The fact that the late cement is observed to only affect the porous undeformed sandstone, is interpreted to be caused by the dense packing of grains, local enrichment of phyllosilicates, and, consequently, a reduced porosity within these micro-faults. The relationships between fault structures and carbonate cements (pre- and postfaulting cements) allowed results from the isotope studies to constrain the depth at which deformation took place. The data gave arguments to conclude that this depth was at maximum ca. 500 m (see Fig. 11 in Sverdrup and BjCrlykke, 1992). The fact that authigenic kaolinite, which probably formed by meteoric water flushing, has grown within the fault zones at the expense of feldspar grains, further supported the conclusion regarding a shallow origin of the faults. Similar to what was found in the faults at Kvalvhgen, concentration of mica triggered stylolitization during deeper burial (at ca. 3000 m) along the faults (see Fig. 2c). Table l b gives a summary of some key parameters for the Haltenbanken faults described here.

Brent Group, Tampen Spur An interpreted regional seismic profile which includes parts of the Horda Platform (Fig. 3) show that the Triassic and lower-middle Jurassic sediments are offset up to 500m along upper Jurassic block bounding and intra-block faults in a NW-SE profile. At the level of the Base Cretaceous Unconformity, however, only minor offsets are observed. Nearly all faults which cut the Base Cretaceous die out rapidly upsection. Only few faults can be observed on seismic lines in this area to extend upwards beyond the Cretaceous, which is similar to what has been described by for instance Glennie (1990). In this study


94

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Fig. 2. Photo-micrograph of fault structures from the Njord Field, Haltenbanken. (a) Micro-fault zone characterized by dense packing of grains only. (b) Micro-fault zone characterized by dense packing of grains and phyllosilicate enrichment. Dissolution of quartz occur at grain contact with mica (arrow). (c) Micro-fault zone with abundant stylolites.

rocks from the Brent Group were investigated. Burial depth-time relationships for the cored wells suggest that the Brent Group sediments were never buried deeper than approximately 500 m prior to faulting. Several cored intervals from the Brent Group which contain faults have been examined. The present depths range between ca. 2500 and 2800 m, and most faults display similar characteristics to those described from Haltenbanken. Mesoscopic faults with small throws (0.5-2.0 cm) are easily identified, commonly as dark seams. Larger faults, which exhibit displacements above the seismic resolution (>ca. 20 m), are characterized by enrichment of phyllosilicates, sand injection and shale smear. Fig. 4a shows a cored structure which clearly re-

sembles the characteristics of the sand dikes as described from KvalvS.gen. The sand dike is approximately 2 cm wide, shows fault parallel laminae, and is separated from the undeformed sandstone by clay enriched rims. Fig. 4b illustrates small-scale faults (associated with enrichment of phyllosilicates) some of which are partly enclosed within a carbonate nodule. The examination of this nodule suggests an early origin. Original porosity presently filled with calcite cement (minus cement porosity) within the nodule is ca. 40%, while the surrounding rock exhibits a porosity of ca. 25%. Within the nodule there is evidence of less leaching of feldspar and mica compared to the uncemented sandstone. Stable isotope analyses of the cement give values in the order o f - 2 t o - 6 ~180(PDB )

Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models

95

Fig. 3. Interpreted seismic profile (NW-SE) across parts of the Tampen Spur. Note the changes in fault throw when moving upsection. Largest throw is experienced within the deeper parts of the section. The Base Cretaceous Unconformity is only minor affected by faults.

(Fig. 5). Assuming a water composition of - 4 to - 2 ~i180 H20(SMOW) , the corresponding temperature range during calcite precipitation was 15-20~ which cer-

a

Fig. 4. (a) Synsedimentary fault (sand dike) within the Etive Formation, Tampen Spur. (b) Early faults in the Etive Formation characterized by enrichment of phyllosilicates. Some of the faults are embedded by early carbonate cement (see text for further details).

tainly indicates a very shallow origin for the faults shown in Fig. 4b. Separate studies from the Tampen Spur area which have been documented by Saigal et al. (1995) further suggest that at least some of the fault structures within the Brent Group (Etive and Ness formations) on the Tampen Spur are of synsedimentary origin. The textures for the faults from Tampen Spur which are not interpreted as synsedimentary, suggest that most sediments were poorly lithified at the time

Fig. 5. Stable isotope data from calcite nodule shown in Fig. 4. The data suggest that the calcite precipitated very close to the surface.


96

Gulf of Corinth, Greece

Fig. 6. Fault structures cutting through a calcite cemented (lower part) and non-calcite cemented (upper part) sandstone. The calcite cemented sandstone displays calcite filled fault structures, while the non-calcite cemented sandstone displays phyllosilicate enrichment only.

when faulting affected them unless the sediments were cemented by early carbonate cement. Typically, increased content of phyllosilicates and denser packing of grains characterize the micro-fault zones. Faults cutting through early carbonate cemented intervals, however, display brittle textures and are commonly filled with calcite cement (Fig. 6). No open fractures were observed. In one of the investigated wells, 18 faults and fractures were characterized by carbonate cement along their surfaces. Of these, 12 where located in a fine grained carbonate rich mudstone containing carbonate nodules and layers. The remaining six structures were all located in carbonate cemented sandstone intervals. All other fault structures within the sandstones did cut through lithified but not carbonate cemented intervals. Although the sandstones had abundant quartz cement, none of these faults exhibit quartz cement as fracture filling. A compilation of the fault characteristics from Tampen as described here is given in Table lc.

Pliocene to Pleistocene rocks exposed on the northern Peloponnes coast in Greece, are cut by normal faults which relate to the Gulf of Corinth graben structuring during the last 5 my years. The sedimentology, tectonic framework and structural evolution have been described by several authors (Brooks and Ferentinos, 1984; Higgs, 1988; Ori, 1989; Doutsos and Piper, 1990; Billiris et al., 1991; Gawthorpe et al., 1994). The sediments in the region are composed of sandstones and conglomerates derived from the Hellenide basement to the south, as well as clastic clay- and siltstones. Erosion of basement limestones have sourced the basin with predominantly calcareous sediments, which are all carbonate cemented at present. Faults which cut through alluvial, fluvial and deltaic sediments have been included in this study. While some of the faults are synsedimentary and interpreted as delta collapse structures (Dart et al., 1994), most focus in this paper is given to faults which affected the sediments some time after deposition. These structures relate to large, block bounding faults with throws up to 100 m, whose origin is related to the NNE-SSW trending extensional regime still active in this area. Faults dominantly trend WNW-ESE and exhibit dip-slip towards north. Based on analysis and reconstructions presented by Doutsos and Poulimenos (1992) the synrift stratigraphical interval exposed onshore never exceeds ca. 1200 m in this area. The position of the sedimentary sequence studied, which is approximately 500 m above basement, suggests a maximum burial of the fault studied to be in the order of 500700 m, prior to the extensive footwall uplift related to

Table 1 Summary of fault structures as described in the text Locality

Depth of faulting (m)

Matrix cement prior to faulting

Fault throws (m)

Deformation characteristics

Fault cement

Later, burial modification of faults

Max. burial (m)

Late uplift

Late extensional fracture fill

a. Kvalvhgen, Spitsbergen b. Tilje, Haltenbanken c. Brent Tampen Spur

Surface

No

1 bar) are from gas caps, whereas the smaller pressure differences are generated by oil. Fig. 7b shows a similar cross-plot, using data provided by Gibson (1994; his Fig. 8) from the Columbus Basin. In this plot, each data-point represents one reservoir top, with observations from many different faults. All reservoirs contain oil, and no gas. The distribution of points is similar to that in Fig. 7a, although with a slightly different position for the bounding line. The similarity of the plots is encouraging, in that they represent data from different sequences in different areas. This implies that the SGR might be a useful predictive attribute across a range of environments. Detailed differences in the calibrations in different areas might possibly be due to factors such as shale lithology, degree of consolidation, fluid type, etc.

Cataclasis Cataclasis is the brittle deformation of material in a fault zone, and typically involves grain breakage and comminution (often associated with improved packing). This results in a significantly reduced grain size in the fault zone which can therefore support a pressure difference because of the increased capillary entry pressure. Knipe (1992) reviews microstructural studies of fault-zone rocks and notes that cataclastic fault gouge may have pore throat radii of 90% carbonate), which reduces the effect of a low permeability gouge layer on the bulk flow. The increase of the bulk flow beyond the initial intact rock permeability at very low an'/ac ratios (tests 5 and 12) is not yet fully understood, but could be related to fracturing of the samples perpendicular to the fracture plane at very low confining stresses. In order to improve the illustration of the combined effects of the stress to strength ratio and fracture shear displacement on the bulk flow, the Kc/Ki values have been contoured in the O'n'/O"c - - 6 s space, as shown in Figs. 15-17. The x-axisparallel contour lines in Fig. 15 (YBS) indicate that fracture shear displacement has little influence on the bulk flow, whereas the stress to strength ratio seems to be the dominating factor. For the RWS, Fig. 16 shows the combined effect of the an'/ac ratio and shear displacement, with minimum Kc/Ki values at 4 mm shear displacement (test 11). Fig. 17 shows the KJKi contours for the LC. For this rock type the an'/a~ ratio

144

A. Makurat, M. Gutierrez and L. Backer

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and the shear displacement seem to be of equal importance. When interpreting Figs. 15-17, keep in mind that due to the limited data base, these interpolations can be strongly dominated by the results of single tests (e.g., tests 1 and 11).

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In Fig. 18 all cross-flow results from YBS, RWS and LC have been combined in one plot. This is done under the simplifying assumption that the combined effect of factors such as porosity, grain geometry, mineralogy and cementation on the rock strength can represented by the uniaxial compressive strength crc, and therefore the normalization procedures applied (~rn'/Crc and Kc/Ki) allow comparison of results from different rock types. Because of the limited data set available, the only conclusion drawn from Fig. 18 so far, is that the Kc/K i ratio seems to reach minimum values when the effective fracture normal stress approaches two times the uniaxial strength of the intact rock..

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Based on the results presented, the following factors controlling fracture flow and bulk flow have been identified: (i) the uniaxial compressive strength of the intact rock, ac (ii) the intact rock permeability k (iii) the ratio between the effective fracture normal stress and the intact rock uniaxial compressive strength, cr//~L (iv) the fracture roughness coefficient, JRC (vi) the fracture shear displacement, 6s Stress dependent fracture flow experiments on various rock types and different sample sizes have

Fig. 5. Block sampling of L~igerdorf chalk. Fig. 10. Secondary fractures in the L~igerdorf chalk test. Fig. 11. Fracture surface alteration and gouge production: Yellow Brumunddal sandstone. Left, before test; right, after test.


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illustrated the effect of shear displacement and fracture normal stress on fracture flow and bulk flow. The tests have shown that fracture flow can increase with increasing shear displacement, even when rather weak rocks are sheared under high stress to strength ratios. Both fracture dilation and propping of the fracture by deformation products can contribute to the maintenance or even increase in fracture conductivity. The experiments have also demonstrated the flow reducing effect of fracture normal stress and fracture shear displacement on the fracture cross flow. Both fracture normal stress and fracture shear displacement seem to be of equal importance for the weakest rock tested. When the rock strength increases, the stress to strength ratio becomes the dominating factor, and fracture shear displacement seems to be of reduced importance.

References Aydin, A. and Johnson, A.M. 1983. Analysis of faulting in porous sandstones. J. Struct. Geol., 5:19-31. Bandis, S.C., Lumsden, A.C. and Barton, N.R. 1980. Fundamentals of rock joint deformation. Int. J. Rock Mech. Min. Sci., 20: 249268. Barenblatt, G.E. et al. 1960. Basic concepts in the theory of seepage of homogeneous liquids in fissured rocks. J. Appl. Math. Mech., 1286-1303. Barton, N., Bandis, S. and Bakhtar, K. 1985. Strength, deformation and conductivity coupling of rock fractures. Int. J. Rock Mech. Min. Sci., 22: 121-140.

Bear, J. and Berkowitz, B. 1987. Groundwater flow and pollution in fractured rock aquifers. In: Developments in Hydraulic Engineering. Elsevier, New York, pp. 175-238. Dean, R.H. and Lo, L.L. 1988. Simulations of naturally fractured reservoirs. SPE Reservoir Engineering, May: 638-648. Dunn, D.E., Lefountain, L.J. and Jackson, R.E. 1973. Porosity dependence and mechanisms of brittle fracture in sandstones. J. Geophys. Res., 78: 2403-2417. Gabrielsen, R.H. and Koestler, A.G. 1987. Description and structural implications of fractures in late Jurassic sandstones of the Troll Field, northern North Sea. Norsk Geol. Tidsskr., 67:371-381. Gutierrez, M., Tunbridge, L., Hansteen, H., Makurat, A., Barton, N. and Landa, G.H. 1994. Modelling of the compaction behaviour of fractured chalk., EUROCK '94, Rock Mechanics in Petroleum Engineering, Delft, pp. 803-810. Gutierrez, M., Makurat, A., Cuisiat, F., Tunbridge, L. and Jostad, H.P. 1995. In-situ stress variation in fractured reservoirs. Project Summary Reports, Norwegian Petroleum Directorate, Stavanger, Norway, pp. 231-245. Heffer, K.J., Last, N.C., Koutsabeloulis, N.C., Chan, H.C.M., Gutierrez, M. and Makurat, A. 1994. The influence of natural fractures, faults and earth stresses on reservoir performance - geomechanical analysis by numerical modelling. In: North Sea Oil and Gas Reservoirs - III, pp. 201-211. Kazemi, H. and Merill, L.S. 1979. Numerical simulation of water imbibition in fractured cores. Am. Assoc. Pet. Geol. Bull., 77: 778-729. Kazemi, H., Seth, M.S. and Thomas, G.W. 1969. The interpretation of interference tests in naturally fractured reservoirs with uniform fracture distribution. SPEJ, 463-427. Lorenz, J.C. 1988. Results of the multiwell experiment. In situ stresses, natural fractures and other controls on reservoirs. EOS, Trans. Am. Geophys. Union, 69: 817-826. Makurat, A. 1985. The effect of shear displacement on the permeability of natural rough fractures. In: Hydrogeology of Rocks of Low Permeability, Proc. 17th Int. Congr. Hydrogeol., Tucson, AZ, pp. 99-106.


1 48 Makurat, A., Barton, N. and Rad, N.S. 1990. Fracture conductivity variation due to normal and shear deformation. In: Proc. Int. Symp. on Rock Fractures, Loen, Norway, pp. 535-540. Makurat, A., Gutierrez, M., Backer, L., Tunbridge, L. and Vangba~k, S. 1995a. Laboratory investigation of fault sealing mechanisms. In: Project Summary Reports, Norwegian Petroleum Directorate, Stavanger, Norway, pp. 59-67. Makurat, A., Gutierrez, M., Knapstad, B., Johnsen, J.H. and Koestler, A. 1995b. Discrete Element Simulation of Faulted Reservoir Behaviour. SPE Formation Evaluation, September. Narr, W. and Currie, J.B. 1982. Origin of fracture porosity - example from the Altamont Field, Utah. Am. Assoc. Pet. Geol. Bull., 66: 1231-1247. Nelson, R.A. 1981. Significance of fracture sets associated with stylolite zones. Am. Assoc. Pet. Geol. Bull., 65: 2417-2425. Pitman, E.D. 1981. Effect of fault-related granulation on porosity and permeability of quartz sandstones. Simpson Group (Ordovician), Oklahoma. Am. Assoc. Pet. Geol. Bull., 65, 2381-2387.

A. MAKURAT M. GUTIERREZ L. BACKER

Reiss, L.H. 1980. The Reservoir Engineering Aspects of Fractured Formations. Gulf Publishing, Houston, TX, p. 108. Teufel, L.W. and Rhett, B.W. 1991. Geomechanical evidence for shear failure of Chalk during production of the Ekofiwsk field. Paper SPE 22755, presented at the 66th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Dallas, 1991. Tillman, J.E. 1983. Exploration for reservoirs with fractured enhanced permeability. Oil Gas J., 81: 165-180. Van Golf-Racht, T.D. 1982. Fundamentals of Fractured Reservoir Engineering. Elsevier, New York, pp. 710. Warren, J.E. and Root, P.J. 1963. The behaviour of naturally fractured reservoirs. Soc. Pet. Eng., L: 245-255. Watts, N.L. 1983. Microfractures in chalks from the Albuskjell Field, Norwegian sector, North Sea: possible origin and distribution. Am. Assoc. Pet. Geol. Bull., 67: 201-234.

Norwegian Technical Institute, P.O. Box 3930 Ullevaal Hageby, Sognsveien 72, N-0806 Oslo, Norway Norwegian Technical Institute, P.O. Box 3930 Ullevaal Hageby, Sognsveien 72, N-0806 Oslo, Norway Norwegian Technical Institute, P.O. Box 3930 Ullevaal Hageby, Sognsveien 72, N-0806 Oslo, Norway

149

Fault seal analysis: reducing our dependence on empiricism T.R. Harper and E.R. Lundin

Background: Unresolved issues of fault seal analysis include the column height trapped by shear bands, seal predictability and the influence of current stress state. Methods: The predictability of fault seals is related to seal type. The mechanics of shear band and clay smear formation are ,compared numerically. Combining the mechanics with pore physics modelling, permeability and other measurements, the column height supportable by shear bands is estimated. The mechanical analysis is further used to evaluate the rotation of stress trajectories around faults with and without clay filling. North Sea fault seals are compared to regional horizontal stress directions. Results: Shear bands are shown to trap a maximum of approximately 20 m of hydrocarbon. The influence of fault "gouge" on stress trajectories around faults is documented for two extremes of material property. Conclusions: Because the predictability of fault seals depends on the type of seal ,this should be factored into risk assessments. Zones of shear bands should be ignored as potential fault traps, at least for offshore exploration. Available data support a correlation of stress directions with orientation of sealing faults, but present day stress is only one of several influential factors. A marked rotation of stress trajectories around a fault does not uniquely characterise a particular type of fault rock.

Introduction Faced with the practical requirement to estimate fault sealing capacity, it is essential to combine an interpretation of the geologic processes relevant to seal formation and evolution with local experience. Any deterministic, process-based analysis will typically be constrained by the limitations of our understanding of the process and/or the availability of quality data. Any dependable analysis based primarily on experience typically requires such a large body of data that the exploration/production decisions of greatest value will have already been taken. It is therefore appropriate to combine the two approaches. However, the more we can reduce our dependence upon empirical or semi-empirical use of local experience, the more commercially valuable will be fault seal analyses. There can never be one single applicable method of fault seal analysis. The appropriate nature and scale of an analysis is a function of the overall objective (e.g., exploration risking or production planning); the potential commercial value of meeting that objective; the geologic history of the faults of interest; the quantity and quality of available seismic, geologic and engineering data; and, practical constraints such as an exploration timetable. Consequently, the industry should aim for a range of procedures from which individual (field) solutions can be devised. In the absence of exhaustive local well and seismic coverage, the requirement to semi-quantitatively describe the engineering properties of any reservoir (or parts thereof) resulting from, say, 100 million years

of geological history, is a major challenge. We suggest that it is essential that the practitioners in this field develop a clear perspective of the whole range of geological processes of fault seal formation and evolution. We fear that there is enormous potential in this subject to be seduced into a state of "not seeing the wood for the trees", thus rendering the process flawed from the start. This broad perspective is necessary if we are to identify in a timely manner which processes and governing factors are of first order and set aside the others. As part of this process, it is essential to strive for clarity and simplicity. This paper seeks to contribute to a clarification of the overall perspective. The influence of a single layer of clay in a sandstone sequence on the basic mechanics of fault development and associated seal formation are examined by numerical comparisons with shear band and fault development in a homogeneous sandstone. The potential sealing capacity of shear bands, formed in the absence of clay layers, is re-evaluated by reference to pore physics models relating permeability and capillary pressure, supported by field data. By this means it is hoped to expedite resolution of apparently ongoing industry misconceptions of the potential sealing capacity of such structures. Currently, there appear to be strongly differing views on the predictability of fault seals. We suggest that this is in part because our current ability for prediction is strongly dependent on the type of seal. At present there are major differences in our level of understanding of the different genetic processes. Concerns regarding basic juxtaposition analysis, and



150

by implication its potential as a predictive procedure, have recently contributed to this confusion. Juxtaposition analysis offers a basic first step in seal risking. In itself this step might be thought sufficient to analyse seal capacity in some cases without the need for any more complex procedures. However, this may not always be as straightforward as suggested at first sight and has recently been implicitly challenged by the concept of a damage zone within which the displacements across a fault are distributed across a series of faults. The available data for describing displacement distributions are reviewed and an interim pragmatic approach to handling this complication is noted, pending more information concerning damage zone distribution. Most fault seals of relevance in the Norwegian continental shelf (NOCS) probably have their origins in the Jurassic syn-rift faulting. While various observations suggest that present-day stress state influences seal capacity, this issue has yet to be resolved. Our current perception of the influence of stress is recorded. Based on tectonic concepts, one may infer that the current regional direction of horizontal stress in the NOCS (North Sea and offshore mid-Norway) has existed since the onset of oceanic spreading in the NE Atlantic in the Early Eocene. Prior to break-up the regional minimum horizontal stress is inferred to have been NW-SE; after break-up this is inferred to have become the direction of the maximum horizontal stress.

Terminology We perceive the apparent lack of a simple and consistent terminology as an impediment to progress in the clarification and simplification of fault seal. We seek here only to promote greater consistency and rigour in the use of descriptive terms, having encountered multiple terms for the same structure or process when we started working in this area, which obstructed our assimilation of the current understanding. For example, what we refer to here as shear bands have also been called granulation seams, deformation bands, cataclastic slip bands, cataclasites, gouge zones, shear fractures, granulated fault strands, microfaults, Ltider bands, tabular compaction zones, and gouge-filled fractures. Likewise, what we call here clay smear has also been referred to as shale smear, smear gouge, shaly smear gouge, fault plane fillings, and phyllosilicate smear. Neither list is comprehensive. They nevertheless illustrate the confusion potentially caused by a plethora of terminology, in some cases unnecessarily verbose. A theory for shear bands was introduced by Hill (1962). Here we combine the descriptions given by

T.R. Harper and E.R. Lundin

Jenkins (1990) and Poliakov, et al. (1993) of the formation of shear bands with the findings of Mulhaus and Vardoulakis (1987). A shear band is a narrow zone of intense shear of a thickness which is a small multiple of the mean grain size of the rock or soil in which it was formed. It is understood to be the product of spontaneous localisation of a previously homogeneous deformation. We distinguish clay smear from fault gouge in accordance with Smith (1980). We identify clay smear based on the description of Lehner and Pilaar (1997), our own observations of the Rhine graben browncoal mines and the results of our numerical modelling. In accordance with Smith (1980), clay smears are understood to be clay fault filling derived from bedded material.

Predictability of fault seals Introduction Some major controls on fault sealing are intrinsically related to the fault itself. Juxtaposition and deformation of the fault rocks belong to this type of control. With some exceptions, predicting juxtaposition seal does not generally hinge upon understanding the deformation process. The same does not hold for predicting deformation seal. Local geologic conditions at the time of faulting dictate the deformation process. Identification of the deformation process is the basis for choosing the appropriate method of analysis. After a fault seal has formed, its sealing capacity may be altered by changes not directly associated with the formation of the fault itself. Such changes include the direction of the horizontal stresses, renewed slip, rapid subsidence/uplift, and diagenetic overprint. Some of these subsequent changes are more predictable than others and it is important to recognize their limits of predictability. The reliability of a fault seal prediction depends to a large extent on the rigour of the analysis, which in turn relies on the quality of the input data. Our understanding of structural geometries typically depends on seismic interpretation. Correct linking of fault cutoffs is essential; if cut-offs are incorrectly linked, a non-existent fault is generated and any subsequent analysis is meaningless. Therefore, quality controlling seismic interpretations is an elementary step in any fault seal analysis. Methods and software for such quality control exist and are steadily improving (Badley et al., 1997). Wells provide detailed information about the stratigraphy, hydrocarbon contacts, and pressures, but only at the points of penetration. Lateral and vertical stratigraphic variations must be

Fault seal analysis: reducing our dependence on empiricism

interpreted. This subjective step may be sensitivitytested by varying the stratigraphic templates during the analysis.

Juxtaposition seal Juxtaposition seal is defined here as a fault seal caused solely by juxtaposition of reservoirs and sealing lithologies; no sealing properties are implied for the fault rock itself. Predicting this type of seal is essentially a deterministic process (for a single slip plane). With modem computer tools, fault plane diagrams or Allan diagrams (Allan, 1989), can be generated with relative ease. This allows the interpreter to assess the stratigraphic juxtaposition across a fault. An obvious strength of computerized juxtaposition analyses is the possibility of quickly altering the stratigraphy of footwall and/or hangingwall and thereby rapidly testing the sensitivity to stratigraphic variation. Juxtaposition seal can be complicated by a number of factors. These include unsystematic lateral lithologic variations, for instance those of channel belts. While it is common to model such lithologic variations stochastically for input to reservoir simulations, this is not to our knowledge used in fault seal analysis. For small fault throws any continuous (i.e., not wedged out) sand horizons may provide across-fault connectivity which could be misinterpreted as a seal if interpreted by juxtaposition analysis alone. Other complications relate to so-called damage and relay zones. The use of the term damage zone (Knipe et al., 1994), is applied here to the distribution of minor faults and fractures within an ellipsoidal volume of rock surrounding a larger fault. Distributed deformation of this type is reported by several authors (Chester and Logan, 1986; Barnett et al., 1987; Koestler and Milnes, 1992; Gillespie et al., 1993; Peacock and Sanderson, 1994). While deformation is also distributed in a relay zone, we prefer to separate relay zones from damage zones. A literature survey of damage zones performed internally in Statoil (Arneson, 1995), revealed that most reports on damage zones are descriptive, with little supporting quantitative field evidence. The difficulty in investigating damage zones quantitatively can be attributed to their three-dimensional nature whilst the nature of our observations typically are one- or two-dimensional. The little published qantitative data tend to be one-dimensional, such as recordings of faults and fractures from outcrop/seismic traverses or from core (e.g., Gillespie et al., 1993; Peacock and Sanderson, 1994). The degree of deformation surrounding a large fault will vary due to a num-

151

ber of factors. From previous reports, such factors include the influence of rock properties related to lithologic variations (Chester and Logan, 1986; Andresen et al., 1994), and fault curvature in plan and cross section (Badley et al., 1997). Indeed, different data sets have revealed different distributions of deformation between footwall and hangingwall (e.g., Koestler and Milnes, 1992; Andresen et al., 1994; Aarland, 1995). There does not appear to be a consensus on a possible fractal distribution of small-scale structures within the damage zone, nor is there agreement that a power-law describes the spacing between the structures (Arnesen, 1995). It is concluded that the spatial distribution of localised deformation within damage zones currently is too little understood to be predictable. Fig. 1 shows a random example of the spatial variability which can be encountered. No attempt was made to assess how representative this was of the local conditions. The alternative, to directly delineate distributed deformation in damage zones from seismic data, is viewed with scepticism. Finally, mechanical considerations imply that the damage zones around clay smears may be less developed than is the case if the weakness of the fault plane filling is less pronounced. It can be inferred that the least work is done by concentrating the deformation in the clay. Also, clay smears form at shallow depth where plastic yield may reduce the opportunity for the stress concentrations necessary for damage zone fracturing to develop. Limited or minimal development of a damage zone around a clay smear may contribute to the predictability of such structures. Some possible support for this inferred lack of damage has been reported by Koestler et al. (1995; Fig. 8) but no firm conclusion can be drawn pending more documented field data. Faults consisting of linked segments of the same age contain relay zones. Prior to breaching of overlapping normal faults that dip in the same direction (ignoring the effect of any other strain), "soft" linkage provides full connectivity between hangingwall and footwall strata through the ramps (e.g., Trudgill and Cartwright, 1994). Upon breaching, the fault segments become "hard"-linked, but the fault displacement remains reduced in the relay zone, at least until substantial growth of the whole fault system has taken place. An unrecognized relay zone (e.g., due to large profile spacing) would thus lead to an overestimation of the degree of juxtaposition. While the existence of an undetected relay zone may be difficult to prove, the following characteristics may be used as indicators: bends or lateral shifts of "a" fault in map view; large lateral displacement gradients towards the relay zone (e.g., Childs et al., 1995); topographic

152


Fig. 1. Distributed deformation in two outcrops along the same normal fault (grey line), located approximately 150 m apart. One outcrop contains a damage zone in the footwall (left) while the other outcrop contains the damage zone in the hangingwall (right). This example illustrates the degree of spatial variability which can be encountered. No attempt was made to assess how representative this was of the local conditions. Location: Wadi Feiran, Western Sinai, Egypt.

lows in footwall and highs in the hangingwall (e.g., Trudgill and Cartwright, 1994); low displacement versus fault-length-ratio (e.g., Barnett et al., 1987). In addition, time slices and various displays of attributes from modern 3-D seismic data can reveal otherwise overlooked structures, including relay zones. However, even if the presence of a relay zone is indicated, it may remain difficult to predict whether the fault segments are soft-linked, or if hard-linked to what extent they are breached. An interim pragmatic approach to solving the problem is therefore noted. Until the spatial distribution of displacements within relay and damage zones is predictable, a possible approach to evaluating their effects on juxtaposition is to perform sensitivity analyses. The effect on juxtaposition can be tested by reducing the displacement from a seismically derived maximum value. Applying the same degree of displacement reduction to a group of faults permits risking between faults. Applying a range of displacement reductions to a single fault allows determination of a critical throw, at which connectivity related to juxtaposition would cause communication across the fault. Computerised juxtaposition analyses expedite such sensitivity testing.

Deformation seal We use the term deformation seal to denote seals which rely on the capillary resistance of the products of shearing. The are a large number of conceivable

geologic processes leading to some degree of deformation seal (e.g., Knipe, 1992). An exhaustive list of possible processes is of little use to the geologist or engineer assigned to predict fault sealing potential, unless she or he understands which process applies in a given case. Because certain processes operate only under specific geologic conditions, it is necessary to understand what the geologic conditions were at the time of faulting as well as the subsequent geologic history. This provides the basis for choosing the predictive method. Because some types of deformation seals are less predictable than others, recognition of the process can be used to assign a risk to the prediction. Clay smearing and the development of "gouge" are different processes. As previously explained, the term clay smearing is applied here to the process of flexuring, extension, and shearing of clay in normal fault zones derived from source beds within layered sand-clay sequences, in accordance with the early papers on this subject (Smith, 1980; Weber et al., 1978; Weber, 1987). The sealing capacity of a clay "smeared into" a fault can be assumed to range up to the same value as that of a clay forming a top seal. An example of the significance of clay smearing to exploration is indicated by the report of a clay smear capable of withstanding a pressure differential of 600 psi (Jev et al., 1993). A rough conversion of this pressure differential yields an oil column height equivalent of approximately 1400m (assuming a density difference of 300 kg/m 3 between water and

153


oil). Locally calibrated estimates of clay smear sealing potential (e.g., Bentley, 1991; Jev et al., 1993) have provided an optimistic view of the predictability of clay smear potential. Interestingly, some studies (Weber et al., 1978; Weber, 1987) suggest that clay smearing only provides seals to accumulations in the footwall block; oil-water contacts in the hangingwall traps often coincide with the highest point of contact between reservoir and fault. One explanation for this asymmetry is simply the inherent geometry of a clay smear "flexure" in a bedded sequence. Other explanations involve leakage through wedge-shaped sand "smears" during periods of fault activity (Weber et al., 1978). Other authors (Berg and Avery, 1995) also describe asymmetric sealing behaviour. They propose that the asymmetry depends on whether a given reservoir, bounded by a fault zone, is in contact with "sheared zone" (which may be some type of clay smear) or in contact with a through-going fault plane. Berg and Avery (1995) propose that the shear zones seal while the fault planes leak. Estimates of the average shale proportion along a fault, so-called "gouge ratio", have been calibrated against pressure differential across faults (e.g., Fristad et al., 1997). The nature of the calculation suggests that the underlying deformation process of gouge development differs from clay smearing. Possibly, the process is segregation (Mandl et al., 1977) whereby clay particles from a sandstone matrix are redistributed and concentrated in the fault zone during fault movement. Alternatively, gouge may be formed by cataclastic wear of the wall rock during fault movement (e.g., Scholz, 1987). Successful identification of threshold values of gouge ratios, separating sealing from non-sealing faults, suggests it would be worthwhile determining the underlying process. If this process can be identified, it will provide the basis for a further step away from reliance upon empiricism. In contrast to clay smears, if gouge forms by some mechanism of mixing along the fault, then the seal is presumably symmetric with respect to footwall and hangingwall. Some sealing processes are either too poorly understood (currently) or too complicated to be predictable. For example, for faults which experience abrupt slip increments (earthquake generating) apparently irregularly distributed openings are generated. Such openings form as part of the overall dilatation of the rock mass and can be preserved. Some are mineralized and commonly seen in outcrop. In the presence of clays and shales, however, it can be inferred that the abrupt stress changes associated with slip increments can essentially liquefy the mudrock during the sudden application of load. We suggest that this flu-

idized or very weak material may be injected into the irregular openings of the dilated rock in the immediate vicinity of the fault. Such a process is expected to result in a very patchy and unpredictable'distribution of clay in the fault unless, by segregation or some as yet unquantified mechanism, subsequent shearing results in a continuous clay gouge. (This would appear to be consistent with the detailed field observations of Childs et al. (1997)). Another example of a seal with an often unpredictable continuity is one formed by diagenetic alteration of fault rocks. Should an area be characterized by such unpredictable processes, it must be risked high, and one can only resort to an empirical "black box" approach to fault seal analysis.

Mechanics of shear bands and clay smear In terms of time invested in understanding the basic processes of seal formation, shear bands and clay seals have attracted the most attention. Previous studies have mostly focussed on either one or the other process in isolation. Here we compare the two. The mechanics of localisation and shear band formation have been lucidly described by Cundall (1990) who numerically modelled a sandbox experiment. This author explained that shear bands localise in a homogeneous clean sand by a process whereby at least one component of the stress tensor progressively decreases. Consequently, strain energy is dissipated. Strain concentrates in the shear band as long as stress reduction continues. This can be achieved by progressive strain softening whereby the intrinsic properties of the material in the shear zone change, such as by dilatation and loosening of an initially dense material. However, contrary to some opinions of shear band formation, Cundall (1990) emphasised that the material does not need to strain harden or strain soften: localisation can occur without change of intrinsic material properties. A reduction of mean stress occurs inside the shear band, relative to the material outside the band. This process of stress reduction cannot continue ad infinitum and it becomes necessary for the concentrated shearing to be transferred elsewhere, forming a new shear band, after a finite shear displacement. The presence of a clay bed can radically alter the state of the material within the fault. To better understand this we have numerically compared the behaviour of an approximately 400 m wide x 100 m deep block of sand subject to faulting induced by slow differential subsidence, with and without a single clay bed of 1 m or 3 m thickness near the centre of the block. The simulation was conducted such that the burial depth of the clay corresponded to approxi-


154

mately 300 m depth in a normally pressured section. The influence of the clay bed can be illustrated using a similar format to Cundall (1990) for faulting in cohesionless sand. The numerical experiments were conducted using FLAC 3.3, a large strain finite difference program. Details of this model and a discussion of its capability to model the genesis of faults are given in Cundall (1990). A Mohr-Coulomb constitutive behaviour was assumed and the properties of the materials were as follows: the homogeneous sandstone was assumed to be cohesionless, of zero tensile strength and to have a friction angle of 35~ the clay was also assumed to have zero tensile strength; the cohesion of the clay was assumed to be 8 x 104 Pa and the friction angle 15 ~ The simulated approximately 4000 m 2 block was assigned vertical lateral boundaries at which free vertical movement was allowed (roller boundaries). The block was compacted under gravity prior to simulating the faulting. A distribution of velocities was then applied at the base of the model to simulate differential subsidence and propagate one or more extensional faults upwards through the section at an angle of 70-75 ~. Fig. 2 shows a qualitative comparison of the stress states using a similar format to that adopted by Cundall (1990). Components of the stress inside the fault/shear band in the homogeneous sand are reduced (Fig. 2). Our model showed that this effective weakening of the material (resulting solely from reduction of confining pressure, i.e., without any need for change of intrinsic material property) continues at larger displacements. Weakening of the material in a normal fault thus appears to be a natural characteristic

HOMOGENEOUS SAND

of extensional faults even without intrinsic property changes such as grain crushing. The clay smear is formed from the bedded material. This becomes part of the fault zone following folding in a precursory monocline. The rotated and extended section of the bed is subparallel to the plane of faulting prior to the shearing in the fault zone which occurs at a small angle to the rotated bedding. Prior to and during faulting, the mean stress in the (undeformed) clay bed is higher than that in the surrounding sand (a condition which is typically exploited during fracture stimulation well treatments). This is not shown here but results from the low shear strength of the clay and the gravitational loading during burial under conditions of no lateral displacement. The least principal stress inside the simulated clay smear is larger than the corresponding stress in the surrounding sandstone (Fig. 2). The mean stress in the clay smear is nevertheless reduced relative to that in the source clay bed. When a clay bed is incorporated in the section, not only the clay but also local areas of the sand in the hangingwall can be at yield. Outside the fault, the principal stresses are markedly inclined to the fault plane for both of the two very different situations (Fig. 2). The corresponding volumetric strains are compared in Fig. 3, which records horizontal line profiles through the fault zone for the two numerical experiments. The difference is striking: in the homogeneous cohesionless sandstone a minor contraction is demonstrated; however, with clay in the fault, a strong dilatation results. This implies that incorporation of a clay

CLAY SMEAR

Yield (sand) (clay) (5

f

'~,~

~Sand

Fault /zone"t/

Fig. 2. Stress states: (a) inside and outside a fault in homogeneous cohesionless sand; (b) inside and outside a fault filled by clay derived from a single clay bed (within a sand of the same properties as modelled in (a)). Both representations are qualitative.


155

duction, this is not true of exploration. It may not be commercially viable to explore for accumulations depending on faults capable of sealing only small hydrocarbon columns. The commercial trapping potential of clay smears has been demonstrated (e.g., Weber et al., 1978; Jev et al., 1993; Bouvier et al., 1989), but that of shear bands remains disputed. Knipe (1992) diagrammatically indicated average

Fig. 3. Horizontal line profile of the volumetric strains across a fault in cohesionless homogeneous sand and across a clay smear in sand of identical properties.

bed into the fault during clay smear development creates conditions suitable for dilatation and the consequent maintenance of continuity of the seal. Finally, in the presence of a clay bed, shearing remains concentrated in the same location with increasing shear displacement. This would be intuitively expected because the clay is an intrinsically weaker material. Fig. 4 shows an example of the shear strain concentrated in the clay smear derived from the rotated limb of the monocline. (In our simulations the persistence of the location of shearing was also partly dependent on the imposed distribution of boundary velocities.) The shear bands described by geologists (e.g., Pittman, 1981; Jamison and Steams, 1982; Antonellini and Aydin, 1994) characteristically show very small displacement with the result that large numbers of bands are required to accumulate any significant shear displacement. Based on Cundall's (1990) analysis of the mechanics of localisation, we should not expect to find an intrinsically weak material such as clay in shear bands. The presence of a weak material would facilitate continued displacement in contrast to the limited shear displacement which can occur when stress reduction within the shear band is critical to its development.

The sealing capacity of shear bands Whilst any seal is of potential relevance to pro-

Fig. 4. Simulation of a single 3 m clay bed (outlined in black) in homogeneous sand faulted to form a clay smear. Filled contour plot of shear strain rate showing concentration of rate of faulting in the section of the clay bed now forming the smear. Fault induced by velocity distribution imposed at base of model to simulate basement dislocation. Contour interval 5E-5 per unit time shown only to explain the sense of the strain rate increase.

156 column heights of 100 m attribiatable to cataclasites, ranging to substantially higher columns at the upper limit. This author's calculations were based on a theoretical relation between pore radius and grain diameter developed by Berg (1975). This relation assumes rock composed of uniform spherical grains with rhombohedral packing. The validity of Berg's assumptions, however, was thrown into considerable doubt by Catalan et al. (1992). These authors observed hydrocarbon column heights in glass bead packs and concluded that Berg's (1975) method systematically overpredicts column heights. Antonellini and Aydin (1994) estimated trapped hydrocarbon column heights ranging from a few metres to about 100 m attributable to a single deformation band. This estimate was based on capillary pressures deduced from measurements of grain size and pore aperture and inferred from image analysis. Published field examples of column heights trapped by shear bands are scarce. An exception is the paper by Gibson (1994) who discussed fault traps in a siliciclastic section in the Columbus Basin, offshore Trinidad. Referring to these traps, Gibson concluded: "These observations show that portions of faults across which self-juxtaposition of a reservoir occurs do not form significant lateral seals or, at most, are able to seal columns of up to approximately 20 m. Based on the outcrop and core observations of fault zones in these rocks, these apparently poorly sealing fault segments are probably composed predominantly of cataclastic sandstone." So where does this leave the explorer, who may not be concerned with columns of 20 m yet be interested in those of 100 m? Should traps formed by deformation bands be sought after or ignored? In an attempt to resolve this question, an alternative approach was adopted. There is a fairly extensive database of measurements of the permeability of shear bands. Consequently, a relation between permeability and capillary pressure was sought in order to use these permeability measurements to prepare estimates of trapping potential. This was achieved using a combination of numerical modelling and oilfield data. We first consider single shear bands as a basis for subsequently assessing the trapping potential of zones of shear bands. Pittman (1981) reported permeability measurements down to 2000 m oil column). However, for very large columns, the strength of the formation becomes an important factor in order to resist seal hydrofracturing.

Capillary sealing versus seal thickness I Ho~o~n~ou,i

[ Micr~

I Layered shaleI [

| ~

I

S i l t , t o n e or

Capillary sealing effects take place at the interface between the non-wetting phase in a reservoir and the wetting phase within a top seal. The capillary forces exerted at this interface are in no way related to the thickness of the seal above. Therefore the existence of a relationship between top seal thickness and sealing capacity is not expected in the field. Thicker seals may be better equipped to resist breaching by faults, but will not retain greater columns by capillary resistance.

I

~Cap#laryl

Wetting

Fig. 1. Simplified evaluation strategy for top seal assessment. The flow chart begins by determining if faults throws are greater than the top seal thickness. If so, then a fault seal analysis is an additional requirement. Top seals are simplified into three main types: (1) massive shale, (2) layered shale/sand/silt, and (3) massive strata of other coarser grained lithologies. Key top seal risks and the data required to carry out their assessments are shown in the flow chart. The rectangles represent leakage scenarios and the ellipses indicate data which will contribute to analysis of the scenarios (abbreviations: Fluid P, formation fluid pressure; 6 hor, minimum horizontal stress; Entry P, capillary entry pressure; HC prop's, hydrocarbon physical properties, including wetting characteristics).

h _ 2Xcos0 = Pe

rgAp

(2)

Capillary sealing effects are controlled by wetting phenomena which, for hydrocarbons in general, are poorly constrained. In real sub-surface situations, the assumption of a water-wet seal is reasonable for an initially hydrocarbon-free seal. This may be less likely in dynamic situations where capillary seals may leak periodically in the presence of active charge. The wetting properties of seals may change through time: an initially water-wet seal may evolve into a hydrocarbon-wet seal, due to the adsorption of a variety of compounds from crude oil, such as asphaltenes (Anderson, 1986). This may ultimately result in a top seal which has no capillary seal capacity and leaks via two-phase flow.

gap

where Ap is the brine-hydrocarbon density difference and Pe is the seal entry pressure. Laboratory measurements of capillary entry pressures are commonly performed on Hg-air systems. To calculate maximum hydrocarbon column heights, mercury-air capillary pressure data must first be converted to hydrocarbon-water pressures, using the following equation (Watts, 1987): (Xnc cos0m)

(3)

PeHc = PeHg (~/Hg cOSOHg)

where PeHg is the mercury entry pressure and PeHc is the hydrocarbon-water entry pressure. Significant columns can be retained by P~ng > 1 MPa. Our database indicates mercury-air capillary entry pressures for siltstones between 20 and 30 MPa (equivalent to a 400-700 m column of 30 ~ API oil sealed at 2.5 km depth), and 45-55 MPa for mudstones (900-1200 m oil columns). For shales, these

Dynamic leakage: control due to top seal wetting characteristics Background Permeability and capillary displacement pressure (defined as the pressure at which significant wetting phase saturation of the seal occurs, commonly 5% of the pore volume) are related by an inverse function (Fig. 3) (Ibrahim et al., 1970): log Pd = -0.33(log k) - 0.2611

(4)

where Pd is displacement pressure (MPa) and k is permeability (mD). This function was used in numerical simulations of the variation in hydrocarbon column height in a trap through time. The simulations aimed to model the results of leakage in traps of varying shape and seal leakiness, in the presence of active charge equivalent to a typical Central North sea drainage area of 50 km 2, over a 60 million year period.

Sealing processes and top seal assessment

167

Fig. 2. Key seal and leak mechanisms pertaining to top seal integrity. Capillary seal: the sealing takes place at the hydrocarbon-water interface and a sharp pressure discontinuity is preserved across the seal (note illustrated pressure profile). Permeable seal, hydrocarbons have invaded the seal and a gradient of pressure is maintained throughout. Hydrofracture, the hydrocarbon pressure may become high enough to exceed the fracture strength of the seal and leakage will take place through fractures. Bottom: fault-linked leak path. Small faults may link up leaky strata in a top seal, thus forming a tortuous, but effective, leak pathway over geological time.

Three seal wetting scenarios are envisaged for the simulations: the seal is initially hydrocarbon-wet and remains hydrocarbon-wet; a capillary seal becomes hydrocarbon-wet after capillary breakthrough and subsequent leakage; and a capillary seal remains water-wet throughout the charge/leakage cycle. These scenarios were modelled and the results are discussed in the following sections.

formed. Noting that the flux out of a trap is a function of the hydrocarbon column length, and taking a reasonable column length to volume relationship ( V = C h 2 where C is a constant and h is the height of the closure, Fig. 4a), the dynamic behaviour of the system was modelled by numerically solving the resuiting differential equation by an explicit time stepping procedure:

Darcy flow simulation

Vn - Vn _ 1 d- At(Q~n_l - OOUt ~_~)

To illustrate these top seal leakage dynamics, model calculations of simple Darcy flow were per-

(5)

where V is the volume in the trap, At is the time step and Q is the flow rate. Results are shown in Fig. 4, for a simple influx

G.M. lngram, J.L. Urai and M.A. Naylor

168

Fig. 3. Plot of displacement pressure against permeability for a wide range of undifferentiated lithologies (including shale, limestone and anhydrite) measured under in situ conditions. Dataset of Ibrahim et al. (1970).

profile. The term (kA)/Al was chosen by us to describe the leakiness of a seal in the simulations and was taken from the equation for Darcy flow: AP kA Q=~ ~ /z Al

(6)

where AP is the buoyancy pressure (MPa), A is the leak window area (m2),/~ is the viscosity of the fluid and Al is the seal thickness (m). Therefore at low values of (kA)/Al, the seal leaks slowly and vice versa. The trap shape was also varied, by changing the trap shape factor C, defined above. At low (kA)/Al leakage is governed by the spill point and at high (kA)/Al leakage occurs through the seal. Trap shape factor C also has a strong influence: traps with large C (large, low relief traps) are more likely to retain significant volumes of hydrocarbons than those with low C (small, high relief), for a given (kA)/Al value. The most important observation here is the relatively narrow range of conditions at which dynamically stable underfilled traps can form.

Simulations of mixed wetting To add complexity to the simulations, a capillary sealing effect was introduced, which satisfied the inverse correlation with permeability (Ibrahim et al., 1970; Fig. 3). Two scenarios were modelled: (1) the capillary sealing effect is removed after hydrocarbons have passed through the seal and (2) the capillary effect remains unchanged throughout the charge-leakage cycle. Results for (1) are similar to the Darcy flow simulation above, where there is a narrow range within which dynamically stable underfilled traps may form after capillary seal failure. For scenario (2), the traps will never be completely empty because, at the high permeabilities which previously resulted in rapid leakage in the Darcy flow scenario, the column height is now regulated by the capillary entry pressure (Fig. 5). At lower permeabilities, and correspondingly higher entry pressures of around 5 MPa (typical for muddy sandstones or clean siltstones) or greater, the results are essentially equivalent to those calculated for the Darcy flow model and the capillary seal scenario.


169

Fig. 4. The effect of trap shape on seal leakage. (a) Explanation of the trap shape factor, C. High C traps have larger volumes than low C traps with the same hydrocarbon column length, h. (b) Hydrocarbon flux into the trap over a 60 My period. (c) Volume of oil in the traps after 60 Ma, as a function of (kA)/A/and trap shape C, where k is permeability in m 2, A is leak area in m 2 and Al is the seal thickness. Flux rate into the trap is typical for the central North Sea. Note the relatively narrow range of parameters leading to a dynamically stable, underfilled trap.

This happens because, under these conditions, once the capillary seal has been breached, the flux into the trap is always greater than the flux out of the trap. The accumulating column of hydrocarbons will therefore always have a buoyancy force greater than the capillary entry pressure, which renders the capillary seal ineffective. The result is that leakage is controlled by the permeability of the seal rock alone.

Conclusions for simulations These results suggest that dynamically stable, underfilled, traps can be expected to be rare in real subsurface cases and that most traps will either be full to spillpoint, or will have leaked their charge completely. It has been demonstrated above that capillary entry pressures are not the sole control on maximum column heights in top seals. The relative importance of permeability and entry pressure, in controlling maximum columns, changes in response to changes in petrophysical parameters, which are,

in turn, related to top seal lithology. In rocl~s, the transition from control by capillary entry pressure to control by permeability, for the conditions described above, occurs at the lithological transition between "clean" siltstones, or muddy sandstones, into finer grained, or more clay-rich siltstones. Thick seal units will tend to create a sharper transition from capillary sealing to permeable sealing than thin seal units of the same lithology. This is because leakage out of traps with thick seals will be less than that for thin seals, leading to an increased likelihood that the hydrocarbon column height will continue to increase after capillary seal breaching has taken place.

Mechanical effects Mechanical effects become important in massive shale top seals where the pore throats in the seal rock are commonly so small that the seals may only leak after hydrofracturing, or by forming linked, permeable, dilatant fractures during deformation. The key

170

G.M. Ingram, J.L. Urai and M.A. Naylor

Fig. 5. Simulations of a trap dynamically leaking oil though a 10 m thick capillary seal. (a) Variation in oil column height with time as a function of entry pressure (and permeability), assuming that the capillary seal becomes oil-wet after the entry pressure (PeHC) is first exceeded and thus becomes a permeable seal. (b) Volume in trap with time as a function of entry pressure (and permeability), assuming a permanent capillary seal. The following parameters were used: leak area = 10 000 m 2, oil viscosity = 0.01 Pa s, density difference = 200 kg m -3 (= 36 ~ API) and trap shape factor C = 10 000. Note that in (b), it is possible to maintain a dynamically stable hydrocarbon column across a wide range. At low entry pressures and high permeabilities, the column length is controlled by the PeHC. At high entry pressure and corresponding low permeability, the permeability controls the column length, as in (a).

factors to predict in these cases are minimum in-situ stress and shale ductility.

Seal strength and hydrofracture At very low permeabilities, typical for many shales, capillary breakthrough is highly unlikely and therefore seal strength, or resistance to fracturing, becomes more important. Pore pressure is an important parameter in these situations and if the pressure in the reservoir just below the seal approaches the formation fracture strength, the risk of driving natural hydraulic fractures upwards through the seal is greatly increased. The retain capacity is defined here as the difference between the repeat formation test (RFT) pressure and the leakoff test (LOT) pressure at the shallowest point in the reservoir, calculated using the regression through t h e

lower bound of the LOT data (Fig. 6). In the Central North Sea, seal breaching is much more likely below a particular retain capacity cut-off (1000 psi, 6.9 MPa; Gaarenstroom et al., 1993). A similar methodology can be employed in other areas, where significant well data exist, either on a regional scale or on a field scale, in order to ascertain the point at which leak risk increases.

Brittle-ductile behaviour The terms brittle and ductile are used in the literature in different ways. Here, the following definitions are adopted: a brittle shale will increase its permeability by developing dilatant fractures (Fig. 2), whereas a ductile shale is able to undergo plastic deformation without increasing its permeability (it will


171

these surfaces accommodates more deformation but, because of their curvature, sliding can be only accommodated by either dilatancy, or by formation of new shear zones. Put simply, the tendency to dilate will be a function of mechanical properties of the rock, effective pressure and shear zone geometry. At a given effective pressure, a stronger (over-consolidated or cemented) rock is more likely to dilate than a weaker one. Two methods have been developed for estimating seal embrittlement in shales. One method requires calculation of the overconsolidation ratio, which is essentially a measure of uplift, and in the other, the unconfined compressive strength is estimated from sonic log data. Both methods produce results which may be used to assess the relative risk of dilatant behaviour.

Over-consolidation ratio (OCR) The over-consolidation ratio (OCR) is defined as:

OCR = Peff max P~ffactual

(7)

where Peffmaxis the maximum past effective pressure and Peffactual is the present-day effective pressure. It is, therefore, essentially a measure of uplift. Our inhouse research indicates that the critical overconsolidation ratio (OCR) needed for dilatancy in poorly cemented shales is significantly larger than 1. Therefore, normally compacted, uncemented shales can be expected to be ductile over the whole depth range, and only very strong uplift will lead to embrittlement.

Estimation of brittleness from unconfined compressive strength (UCS) Fig. 6. Retain capacity. (a) Leak off pressures and repeat formation test data from the North Sea Central Graben. The curve is the minimum in situ horizontal stress trend, determined from the lower bound of leak off test data. (b) Retain capacity in the North Sea Central Graben. Retain capacity is the difference between the minimum horizontal in situ stress and the fluid pressure at any point. At low retain capacity (1000 psi or lower) the likelihood of trap failure is increased (Gaarenstroom et al., 1993).

contain non-dilatant, sealing fractures; Fig. 2), when deformed. Note that this definition does not address uncertainties about fracture linkage. The main micro-scale controls on dilatancy during shear failure in shales can be described by considering the processes taking place in a stressed rock element. Strain begins to localise in the sample at peak differential stress and this leads to the formation of undulating shear zones (shear fractures). Sliding on

An alternative method to quantify the brittleness of a seal rock uses the unconfined compressive strength derived from sonic logs. This method uses the brittleness index, BRI = UCSIUCSNc, where UCSNc is the unconfined compressive strength of a normally consolidated rock. UCS can be measured directly or is estimated from logs based on empirical correlations using the equation log UCS = -6.36 + 2.45 log(0.86Vp - 1172)

(8)

with UCS in MPa, Vp in m/s. UCSNc is determined from empirical soil mechanics correlations (e.g., Craig, 1987) and is estimated by the equation UCSNc = 0.5a', where o' is the in situ effective pressure corresponding to normal consolidation at the depth of interest. Empirical observations show that for brittleness indices greater

172

than 2, the risk of embrittlement increases with increasing BRI. However, this criterion does not give absolute brittleness values, but is useful for ranking. Cementation increases a rock's strength in comparison to its uncemented equivalent, at the same depth, and therefore the risk of dilatant behaviour is correspondingly increased.

Seal architecture: stratigraphy and subseismic fault density The possibility of other leakage mechanisms taking place can depend on the seal architecture. For


example, top seals in which leaky layers are known to exist may leak if sufficient numbers of small (subseismic) faults are present to form a tortuous faultlinked leak path, due to juxtaposition of the leaky layers across the faults. The risk of leakage, through a fault-connected network of leaky beds (Fig. 2), can be quantified from the number of relatively thick shale beds in the seal and the statistics of the fault population in the trap area, derived from 3-D seismic. In order to model fault-assisted top seal leakage, a basic configuration of identical shale layers of similar thickness, separated by very thin, laterally continuous, leaky beds (siltstones, sandstones), in which a number of

Fig. 7. Fault assisted top seal leakage. (a) Probability of top seal leakage. Analytical solution for shale beds of constant thickness t, in which identical faults of maximum throw Tmax are randomly dispersed. This relationship for probability of seal leakage also holds approximately for seals in which the shale layers and fault throws are each normally distributed about the same mean t. (b) Determination of the throw-cumulative frequency relationship. Faults in a volume of rock, from a map-based statistical analysis of the fault population. Adding 1 to the slope C 2 simulates the addition of the third dimension (Gauthier and Lake, 1993). Here a length/Tma x ratio of 100:1 was used. (c) Determination of the seal risk. Comparing the number of faults required for leakage with the number of faults in the trap volume determines the seal risk. In the example shown, the probability that the seal is breached lies between 50 and 90%. For points in the "sealed" field, the effect of increasing fault throw on the number of faults needed for breaching is illustrated.


173

identical faults are randomly dispersed, was considered. In this model, fault throws may bring adjacent leaky beds into contact, but the faults may not seal or act as conduits to flow. The probability of leakage can be found by considering all permutations of fault positions relative to the shale layers in the seal. Fig. 7a shows the analytical solution for probability of top seal leakage, which has been validated using Monte Carlo simulations. The maximum throw (Tmax) needed for juxtaposition of leaky beds either side of a fault is calculated by considering the thickness of the thickest shale layer and the fault plane aspect ratio (AR). The latter is included because the locus of Tmax may not coincide with the shale layer mid-point. A small correction to Tmax for the effect of the vertical gradient in displacement is described by Tmax = (1 +

a)t,

where a =

0.5AR (L/Tmax)

(9)

where L/Tmax is the fault length/maximum throw ratio. Practical estimation of fault leakage involves the following steps: (!) Carry out a fault analysis of a 3-D fault map at top reservoir level. (2) Calculate the throw-frequency distribution (Fig. 7b) for the rock volume around the seal, by converting fault lengths to throws, using the mean fault length/maximum throw ratio. Assuming that the map samples largest fault close to its true maximum throw, adjust the fractal dimension of fault population relative to sample dimensions by increasing the gradient of the log(frequency) versus log(length) regression from C to C + 1 (the fractal dimension of the population is related to the geometric dimensions of the sampling domain, i.e., areas = 2, volumes = 3; Gauthier and Lake, 1993). (3) For seals with one or more layers significantly thicker than the rest, the effective number of shale layers in the seal should be calculated as the total seal thickness divided by the thickest layer. The thickest layer determines the minimum throw required for juxtaposition of leaky layers and the formation of a connected system. (4) Compare the throw-frequency line, which has been calculated for the trap area, with the minimum fault throw and frequency values which we know are required for breaching. This determines the seal risk (Fig. 7c). As a general rule, for a 90% probability of top seal leakage by this method, the number of faults with sufficient throw to juxtapose leaky layers must be

at least five times the number of shale layers in the seal.

Summary This paper outlines the elements of a strategy for determining the risk of top seal leakage and provides some insights into the fluid dynamic behaviour of simple hydrocarbon traps under different wetting scenarios. The elements of the assessment strategy are considered to be the minimum requirements for successful ranking of top seals. It has become clear from the use of such a strategy, that some old dogmas, such as the assumption that seal capacity increases with top seal thickness and that faults smaller than the gross thickness of a seal do not represent a seal risk, are unrealistic and misleading, and should be avoided. Although there are numerous examples worldwide of four-way dip closed traps, for which only a top seal assessment would be required in the exploration stage, many other traps under exploration today rely on the sealing capacity of fault closures. For this reason, it is recommended to assess top seal capacity in tandem with an assessment of the sealing capacity of faults (e.g., Fulljames et al., 1997).

Acknowledgements The authors wish to thank Shell International Exploration and Production for permission to publish this paper and Bernhard Krooss for a helpful review.

References Anderson, W.G. 1986. Wettability literature survey - part 1: rock/oil/brine interactions and the effects of core handling on wettability. J. Pet. Technol., 1125-1144. Berg, R.R. 1975. Capillary pressures in stratigraphic traps. Am. Assoc. Pet. Geol. Bull., 59: 939-956. Craig, R.F. 1987. Soil Mechanics, 4th edn. Van Nostrand Reinhold, New York. Fulljames, J., Zijerveld, L.J.J., Franssen, R.C.M.W., Ingram, G.M. and Richard, P.D. 1997. Fault seal processes: systematic analysis of fault seals over geological and production time scales. In: P. Moller-Pedersen and A.G. Koeslter (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 51-59. Gaarenstroom, L., Tromp, R.A.J., de Jong, M.C. and Brandenburg, A.M. 1993. Overpressures in the Central North Sea: implications for trap integrity and drilling safety. In: J.R. Parker (Editor), Petroleum Geology of Northwest Europe. Proc. 4th Conf., Geological Society, pp. 1305-1313. Gauthier, B.D.M. and Lake, S.D. 1993. Probabilistic modelling of faults below the limit of seismic resolution in the Pelican field, North Sea, offshore United Kingdom. Am. Assoc. Pet. Geol. Bull., 77: 761-777. Ibrahim, M.A., Tek, M,R. and Katz, D.L. 1970. Threshold Pressure in Gas Storage. American Gas Association, Arlington, VA.

174


Schowalter, T.T. 1979. Mechanics of secondary hydrocarbon migration and entrapment. Am. Assoc. Pet. Geol. Bull., 6 3 : 7 2 3 760.

G.M. INGRAM J.L. URAI M.A. NAYLOR

Watts, N.L. 1987. Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns. Mar. Pet. Geol., 4: 274-307.

Shell International Exploration and Production, Research & Technical Services, P.O. Box 60, 2280 AB Rijswijk, The Netherlands (e-mail: [email protected]) Geologie-Endogene Dynamik, RWTH Aachen, Lochnerstrasse4-20, D-52056 Aachen, Germany (e-mail: [email protected]) Petroleum Development Oman LLC, PDO Office, Mina al Fahal, Muscat, Oman

175

The dynamics of gas flow through rock salt in the scope of time D. Kettel

Observations on the occurrence of gas in nature have provoked controversial discussion on the process of gas migration through sedimentary rocks. The controversies seem to arise from different goals to reach through the study of gas behavior rather than from interest in a natural phenomenon. Observation on the behavior of gas in nature, provided by geological, well and test data are modeled here using history matches on gas flow through known gas fields from The Netherlands offshore and Germany onshore over the last 100 myr. The flow models are based on diffusion or on Darcy flow. The common sealing lithology is rock salt. Once the reservoir content is matched, a diffusion constant and a rock salt permeability for methane are obtained. Diffusion constants are shown to scatter over the same order of magnitude as the input parameters do; moreover, the balances obtained with diffusional flow are physically meaningless. Rock salt permeabilities, however, follow a consistent function with depth. They develop from 1 x 10-21 m 2 (equals 1 nanoDarcy) at 3000 m depth down to 2 • 10-22 m 2 at 6000 m depth with an increase by factor 10 between 115 and 151 ~ Darcy flow is highly dynamic. Methane generation rates exceed any capacity of even multiple reservoir/seal systems over the same area by at least a factor of 10. Mean residence time of methane in accumulations has been calculated as 10 myr for the European Upper Carboniferous Basin. The quantity of >90% of methane not stored directly enters the atmosphere providing a global methane input of around 500 Tg per year - or a cover of 7 std. mm thickness per year over the globe's surface. This is in the same order of magnitude as presently reported in the literature to be the total input on the base of vegetational, animal and human activity only. This additional input may stabilize atmospheric reactants cycling and global change calculations. The balance additionally proves that under the condition of equilibrium of flow, methane must migrate strictly vertical.

Observations in nature and controversial arguments arising from these Gases in different reservoirs, additionally revealing different geochemical characters are commonly thought to be sourced at different times and/or by different sources or thermal states (maturities) of the same source (England, 1990; Schoell et al., 1993). As most reservoirs are stacked in a vertical direction, this necessarily requires the interference of a migration behavior different in time or s p a c e - mainly as lateral m i g r a t i o n - and/or differences in the gas generation behavior of the same source. Following the literature of the past few decades, this - in analogy to the migration behavior of oil - led to the implementation of a source "kitchen" to be responsible for the fill of a discrete structure or set of reservoirs of interest; this is what normally is called "put the thing upside down". If one wants to understand the functions of a spider "Bugatti" for example, he will not look at the car from the point of view of the cover of a road, because here he will never reach further than examining the profile of a tire perhaps. If he really wants to understand the way in which the car works and of what it might be capable under pregiven conditions, he will first study its basic functions and then will stepwise follow its working mechanisms in subsequently greater detail and under different conditions. Back to our gas accumulation this means that we first must

understand the process of generation of gas and its migration, and subsequently we will see that a partial retainment of gas on the way through a sedimentary column is no first-order phenomenon but a byproduct only which owes its existence to an accidentally given petrophysical contrast. Moreover, the view reported in the literature of looking at and exploring for gas handed down from one generation of geologists to the next, consequently implements the restriction that a gas once reservoired stays definitely within the reservoir and no processes will drive gas through a seal. Besides the unlikeliness of this concept, here we have the first real problem: the quantities of gases reservoired anywhere are by no means in the order of magnitude of the gases generated over the same area. We calculated earlier (Jurgan et al., 1983) that for an area of the European Upper Carboniferous Basin onshore Germany, the quantity of methane generated over the total potential of its sources exceeds the quantity actually reserv o i r e d - as proven by tests or predicted as reserves by factor 1000. This is easy to understand if we look at the physical properties of gases compared with those of oils: due to their small molecular size and their low molecular weight they are extremely mobile within the geological environment. Expressed in physical terms: they reveal a rapid solution/dissolution, diffusion and adsorption/desorption behavior. The high generation/retention rate reported was ob-



176

tained in spite of the fact that the sealing lithology in the European Upper Carboniferous Basin is rock salt. Rock salt is the most continuous lithology of all, forming the fill of sedimentary basins. Under this view, the first idea of a gas accumulation to behave in a static m a n n e r - which means that the sealing capacity is definite- appears not to be so strange. We will show in the following, however, that even rock salt does not impede a flow of gas to behave dynamically if geologic time is considered. The fundamental difference in the behavior of light and heavy hydrocarbons has been pointed out by Russian authors since the 1950s and 1960s (e.g., Vetsoskiy, 1979), and after that has often been repeated (e.g., Zhang, 1994). They already state that, under consideration of the thermodynamics of gases, gas accumulations should be a rather short-lived and accidental phenomenon during geologic history. Therefore, in recent times some authors, among them Kettel (1989) and Bredehoeft et al. (1994), have forced the view that a continuous flow of gases through all rock materials composing sedimentary basins must be the basic and ubiquitous process affecting subsurface behavior of fluids.

Methods of investigation In order to verify the dynamic concept of the behavior of gas throughout sedimentary basins, we first report the results of an empirical study on The Netherlands offshore gas fields (Broad Fourteens Basin, Fig. 1 shadowed area). This basin is part of the European Upper Carboniferous Basin. The gas fields are sourced from Upper Carboniferous coals and shales, reservoired in Upper Permian Zechstein carbonates (Plattendolomit) and sealed by Zechstein rock salt (Na2-4). The problem facing exploration was that the rate of dry holes was very high even if structural closure and favorable reservoir properties were confirmed. In order to find a solution and to offer a tool for the prediction of fill or non-fill of structures before drilling, we examined 29 case histories (fields, finds, shows and dry holes) under the aspect of dynamics of gas flow. The question how dynamic a system of fluid flow under geological conditions really is can only be answered if the losses of gas from a reservoir over time are quantified - or the complete balance of gases over a sedimentary section is established. This requires the determination of the physical process which drives the flow of gas through rocks. There are two different options for this mostly discussed: (1) flow as a free phase controlled by capillary pressure within the seal (Hubbert, 1953; Antonellini and Aydin, 1984; Downey, 1984) and (2) diffusion (Leythaeuser et al.,

D. Kettel

Fig. 1. European Upper Carboniferous Basin: location map of gas fields A--G and M and N Germany onshore (black dots) and of the 29 gas fields from the Broad Fourteens Basin, Netherlands offshore (shadowed area).

1982; Krooss, B.M. et al., 1992). There is a third process possible but not seriously considered by authors up to now, which is Darcy or pressure driven flow. We used the data of nine gas fields located over the North German part of the European Upper Carboniferous Basin (see Fig. 1, black dots named A - G and M and N) to simulate the vertical flow of methane over the last 100 myr, using a diffusion model and a Darcy flow model. From the results obtained we determined the physical process driving gas through rocks.

Geological parameters controlling balances of gas flow" empirical observations On the left hand site of Fig. 2, for the gas fields located over the Broad Fourteens Basin, the thicknesses of the Zechstein rock salt seal are plotted against the gas columns held by the seal throughout the reservoir, both in a logarithmic scale. As a third parameter, the cumulative methane generation from the source directly below, standardized over 1 m 2 of area, over the last 10 myr was calculated using subsidence history and the BasinMod software. If this information is marked on the data points of the graph, they arrange perfectly along lines of the same methane generation rate. In this way, a simple function is obtained for the gas column actually held to depend on the thickness of the seal and the gas generation rate directly below. The functionality of the graph tells us that in order to obtain the same degree of structural fill, the seal

177

The dynamics of gas flow through rock salt in the scope of time

flow and simulations of cases A - G and M and N have been performed with both. With the appropriate process, however, the boundary conditions put by these empirical observations must be fulfilled.

Consequences of the empirical observations on the seal capillary pressure hypothesis

Fig. 2. Plot of methane columns actually held throughout the reservoir against rock salt seal thicknesses for all gas fields. The data points arrange along the local methane generation rates.

thickness must roughly be doubled if the gas supply rate is reduced to one-quarter. The same functionality is given for the nine gas fields A - G and M and N which include one show (G), situated Germany onshore (Fig. 2, right hand side). Reservoirs are provided by Upper Permian Rotliegend sandstones (cases A-G) or by Zechstein carbonates (Hauptdolomit, cases M and N), seal and source being identical with those of the Broad Fourteens Basin. Methane generation rates over the last 10 myr are apparently smaller than those from the Broad Fourteens Basin which is due to a deeper position and subsequently higher maturities of the source. In order to produce similar methane quantities retained, this is compensated by generally thicker seals. Approximately one-half of the Broad Fourteens cases and cases A, B, M and N from North Germany are situated in the inverted area which follows the southern rim of the European Upper Carboniferous Basin. This area is under uplift since 85 myrbp which implies a strong reduction of vertical methane flow since then. From this evidence, it is important to remember that under otherwise equal conditions, the degree of reservoir fill should depend roughly linearly on the seal thickness and the gas generation rate directly below. In order to determine the physical process driving gas through a seal, two different models have been programmed based on diffusion and on Darcy

It is reported that gas flow as a separate phase through a seal is given if the pressure of a non-wetting phase (gas) can displace the connate water out of the pore space, or in other words if the buoyancy forces created by the gas column exceed the capillary pressure within the seal. It is important to state that the most relevant factor controlling capillary pressure is the effective interconnected pore radius and that the pore radius does not depend on seal thickness (Zieglar, 1992; Antonellini and Aydin, 1994). If gas flow as a separate phase was controlled by capillary pressure, the gas column held under a seal would exclusively be a function of the petrophysical properties of the seal and not of its thickness, except under perfect conditions, e.g., as observed with shales, when a thick seal may result in a greater continuity and higher resistance against later fracturing (Hunsche and Schulze, 1993). This consequence clearly contradicts the boundary conditions put on the process to be found by the empirical observations. Therefore, it is unlikely that capillary pressure exerts a control on migration of gas through rocks even through rock salt.

The diffusion model A computer program has been developed which simulates the diffusional flow through geological environments. The model is based on the following simplifications: 1. Gas from a source rock migrates vertically upwards into a trap which is closed by a seal. 2. Gas flux from a source occurs over different time intervals, each characterized by a constant flux rate. 3. The capacity of a trap to accumulate gas is constant through time and is defined by the structural height, reservoir porosity, reservoir pressure and temperature. 4. The seal is defined by a thickness and a diffusion constant. Both are constant over time. 5. If a cumulative gas flux from the source exceeds the capacity of the trap, lateral spill, which means loss of gas from the system, occurs. 6. The following balance must be valid for every time t:

1

7

8

D

Table 1 Methane generation rate and reservoir pressure/temperature histories for cases A - G and M and N, North Germany onshore Case

Start time (myrbp)

Cumulative methane input (std. m3/m 2)

Reservoir pressure (10 MPa)

Reservoir temperature (~

A A A A B B B B C C C D D D E E E F F F G G G M M M M N N N N

100 85 10 0 100 85 10 0 100 10 0 100 10 0 100 10 0 100 10 0 100 10 0 100 85 10 0 100 85 10 0

16488 11 0 0 23982 16 2 0 12492 8 0 10000 1 0 18994 6 0 7995 5 0 11987 13 0 23887 102 11 0 23784 204 12 0

260 423 160 150 300 380 210 200 156 318 326 250 380 400 290 455 460 305 420 421 362 426 442 400 400 310 300 400 400 310 300

86 160 53 50 99 153 69 66 47 106 108 82 125 132 96 150 152 99 138 139 119 139 145 132 214 129 125 132 163 134 130

cumulative i n p u t - reservoir content + seal content + losses at top seal + lateral spill

c(t,x) in std. m3/m3 volume is the gas concentration within the seal at distance x from the reservoir/seal boundary at time t. c(t,O) is the gas concentration in the reservoir. For c(t,x) the following boundary conditions must be fulfilled: 7. Starting condition c(0,x) = 0, x > 0 8. Diffusion law c(t,x)=Dcxx(t,x) for t > 0 and 0 < x < L where D is the diffusion constant of methane through the seal and L is the total thickness of the seal. 9. Upper boundary condition (x = L): gas concentration at top seal remains zero, c(t,L)= 0 for t>0. 10. Lower boundary condition (x=0): Ct(t,O)= rinp(t)/V + D/Vcx(t,O). This means that a change of gas concentration within the reservoir dc(t,0) =

.

Kettel

c(t + d r , 0 ) - c(t,0) during the time increment dt is controlled by the gas input rinp(t)dt from the source and by the gas quantity Dcx(t,O)dt which is lost by diffusion through the reservoir/ seal boundary (the gradient Cx(t,O) is negative). V is the volume representing the maximum capacity of the reservoir. 11. c(t,O)< 1/bg for t > 0. This means that the gas concentration in the reservoir at every time must be not greater than the maximum capacity of the reservoir under subsurface temperature/pressure conditions (bg is the compressional factor). 12. The gas quantity which leaves the top of the seal in time interval (t,t + dt) is:-Dcx(t,L) dr. The problem described by conditions 7-12 is solved numerically by discretisation of t and x.

Results of modeling gas flow with diffusion Table 1 shows the histories of methane input given in std. m3/m2 into structures A - G and M and N and the actual reservoir pressure/temperatures. Their capacities resulting from porosity of the reservoir and structural height as well as the rock salt seal thicknesses and methane columns held are given in Table 2. Case histories are matched using an inverse modeling mode: given the reservoir capacity, the seal thickness, the actual temperature regime, the gas generation history and a starting value for the gas diffusion constant through the seal, methane columns actually held are obtained for each case. These are iteratively adjusted to the gas columns tested by modifying the diffusion constant. Once the gas columns are matched, a diffusion constant for methane throught the seal and the complete balance of flow are obtained. They are given in Table 3. The balances are determined by the cumulative gas input, an eventual lateral spill, the reservoir content, the seal content and the losses from top seal.; They are presented Table 2 Well and test data for cases A - G and M and N Case

Thickness of rock salt seal (m)

Methane Structural column height held (std. (m) m3/m 2)

Porosity Max. of reservoir capacity (%) of reservoir (std. m3/m 2)

A B C D E F G M N

562 420 100 367 200 106 29 136 234

352 485 122 138 334 106 20 388 952

9.0 11.0 12.4 10.8 8.7 9.7 5.0 7.8 11.7

150 250 150 150 100 150 150 150 150

1699 7025 4281 4298 2536 4007 2132 2382 3529


Fig. 3. History match of cases A-G and M and N over the last 100 myr with diffusion: gas balances obtained for vertical flow of methane.

graphically in Fig. 3. Four arguments exclude diffusion as an effective driving mechanism for gas. (1) although a major part of the cumulative gas input enters the reservoir/seal interface, only 50% down to 5% of this quantity leaves the top of the seal over the same time interval. This percentage is the measure for the degree of stationarity of flow through the reservoir/seal system as a whole. Therefore all balances obtained remain in a pre-stationary state of flow. Stationarity may rather be given for the reservoir/seal boundary. This is demonstrated by a methane concentration profile through the seal calculated for case A over the last 100 myr. Fig. 4 shows that gas driven by concentration gradients under average geological conditions will rarely reach the top of a seal over geologic time. (2) A major part of the gas input is calculated to be hidden in the seal. This quantity amounts to several times the actual reservoir content. There is no physical explanation, however, how these quantities may be stored in rock salt. (3) The diffusion constants for methane obtained from the history match scatter over approximately one order of magnitude which is between 1.35 x 10-~ and 1.16 x 10-l~ m2/s. They are plotted in Fig. 5 against the maximum temperature of the seal reached. As a general range they may coincide with results obtained by Krooss

17'9

and Leythaeuser (1988) from laboratory experiments. These authors, however, with a preview of contrarieties ahead, named their parameter "effective diffusion constant" to add a contribution of bulk flow. Diffusion, however, is a model to describe physical processes defined by Fick's two laws. If we can describe a natural phenomenon within the restrictions of this law we can call it "diffusion", if not we must look for a different explanation. (4) A crossplot shows that the degree of deviation of the calculated diffusion constants from a virtual mean value is a direct function of the gas input and the seal thickness. As the parameter gas column held in a reservoir varies within a range of 1.5 decades (see Table 2), according to argument (3), the controlling parameter scatters over the same order of magnitude as the matched parameter. This means that the mathematical model for diffusion becomes unstable in terms of the predictability of gas columns held. According to argument (4), given the same gas generation history, a case with a thicker seal requires a smaller diffusion constant to match the real gas column. Sensitivity runs with the diffusion model demonstrate that there is a linear dependency between the diffusion constant and the gas column but not between the seal thickness and the gas column. This agrees with the observation reported in argument (1) that diffusional transport is

Fig. 4. Methane concentration profile through the rock salt seal obtained for case A with diffusion: example for an extremely prestationary flow.

D. Kettel

180

too slow to consider thicknesses of seals. Moreover, this already seems not to be the whole truth: diffusional flow does not care about rocks at all. Any match of partial retainment of gas - or in the terminology of diffusion, of an anomaly in gas concentrat i o n - could only be produced attributing different diffusion constants to different rocks at the same time and under the same temperature regime. Here the question becomes boring; already the definition of diffusional flow as a transport process driven by internal or molecular forces excludes any possibility for substantial entities such as rocks to realize a control on flow.

diffusion constant for methane (m2/sec) 1 e-12

1 e-ll

1 e-10

1 e-9

50

100

The Darcy flow model The evidence of gas columns held to depend on gas generation rate and seal thickness suggests that a bulk transport mechanism is responsible for the migration of gases through rocks. In order to verify this, we set up a computer program based on Darcy flow. The idea was that all seals are permeable. Although permeability may be very small, the reservoired gas should pass the reservoir/seal interface and in the same way leave the top of the seal. Gas losses from a reservoir must then be a function of the partial excess pressure gradient at the reservoir/seal interface. The factor of proportionality between partial excess pressure gradients and gas fluxes is the permeability of the sealing rock for a molecular species and its viscosity. The viscosity of methane under high pressure is taken as 2 x 10-5 (Pa x s) according to estimations clone by Lorbach and Sch/3ffmann (1991) for dense gases and is included in the model. The calculation procedure is the same as applied with the diffusion model: using a starting value for the seal permeability, the real gas column is matched by adjusting the seal permeabilities. If R(t) is the reservoir content (std. m s) of gas at time t, and p(t,x) is the excess pressure (bar) of the gas within the seal, the starting conditions are: R(0) = 0

p(O,x) = 0

for 0 < x < L

The boundary condition at the top seal (x = L) is

p(t,L)-O

for t > 0

The problem described is solved numerically by discretisation of t and x.

Results of modeling case histories with Darcy flow In addition to the methane viscosity, the variable parameter controlling the balance of flow is the per-

150

200

250

Fig. 5. History match of cases A-G and M and N with diffusion: diffusion constants for methane through the calculated seal plotted against the maximum temperatures reached by the seal.

meability of the seal. With the pregiven sets of data (Tables 1 and 2), a permeability for the seal is obtained for each case once the simulation matches the tested methane column (see Table 3). The set of seal permeabilities obtained in this way provides the control on the validity of the model. It is plotted against the maximum depth of the seal reached in Fig. 7. Gas balances obtained for each history match are also given in Table 3; they are also shown graphically in Fig. 6. The results demonstrate that: (1) the quantity of gas flowing into a structure is simply the sum of the quantity stored within the reservoir and the quantity leaving the top of the seal. Other than required by the diffusion model, there are no quantities lost along the way and therefore mass balances are maintained. (2) About 98-99.9% of methane generated over a standard area leaves the top of the seal. These quantities may provide the input for a shallower reservoir/seal system and in this way follow up. Altogether, the


181

Table 3 Results from the history matches cases A-G and M and N using diffusion and Darcy flow of methane: gas balances, diffusion constants and rock salt permeabilities Case

Model

Cumulative input

Reservoir content

Seal content

Loss from top seal

Lateral spill

Diffusion constant (m2/s)

A A B B C C D D E E F F G G M M N N

Diffus Darcy Diffus Darcy Diffus Darcy Diffus Darcy Diffus Darcy Diffus Darcy Diffus Darcy Diffus Darcy Diffus Darcy

16500 16500 24000 24000 12500 12500 10000 10000 19000 19000 8000 8000 12000 12000 24000 24000 24000 24000

371 352 419 481 133 123 141 138 322 339 103 103 17 21 374 380 969 958

15190 0 10943 0 7727 0 7473 0 13657 0 4971 0 7260 0 10947 0 14028 0

952 3691 12187 7270 4624 12377 2392 9862 4955 18661 2935 7896 4776 11979 12663 2715 8953 3763

0 12456 0 16248 0 0 0 0 0 0 0 0 0 0 0 20905 0 19278

1.35E-11

Permeability (m 2)

8.40E-22 1.16E-10 7.13E-22 2.00E-11 1.02E-21 4.00E-11 3.31E-21 1.50E-11 1.64E-21 2.00E-11 9.88E-22 2.60E-11 4.90E-22 1.45E-11 1.78E-22 1.2E-11 2.34E-22

All quantities of methane input, contents and loss are given in std. m3/m 2. Gas input is cumulative since 100 myrbp.

Fig. 6. History match of cases A-G and M and N over the last 100 myr with Darcy flow: gas balances obtained for vertical flow of methane.

Fig. 7. History match of cases A-G and M and N with Darcy flow: permeabilities of the rock salt seal for methane calculated plotted against the maximum depths reached by the seal.

182 bulk quantity of gas generated directly enters the atmosphere or the ocean water. (3) The values obtained for the controlling parameter rock salt permeability form a consistent function with the maximum depth or temperature reached by the seal (see Fig. 7). They develop close to 1 • 10-21 m 2 (which equals 1 nanoDarcy) above 3000 m followed by an increase up to approximately 4 x 10-2~ m 2 over the temperature range of 115-151~ Below 4300m, corresponding to temperatures higher than 142~ they approach a value of around 2 x 10-22 m 2 which seems to keep stable with increasing depth. No scattering from this function is observed; therefore the model is mathematically stable.

Calibration of the Darcy flow model: the resulting rock salt seal permeabilities and their significance The validity of the Darcy flow model depends on the consistency of the permeability/depth function obtained, on its mathematical stability and on the reliability of the absolute values for the rock salt permeability. Laboratory measurements of rock salt permeabilities are difficult to perform because the expected values had always approached the lower limit of laboratory resolution. Precisely, the time required to mn a reliable measurement under maintenance of conditions is very long. Borgmeier (1992) reports rock salt permeabilities to converge within the range of 10-21 m 2 On the base of flow measurements. Peach (1993) provided data on permeabilities of synthetic rock salt plugs and on their dependency on different degrees of admixture of anhydrate and its grain size. Due to the physical stringency of this concept, the data seem to be reliable. Peach's interest was in underground storage and waste disposal, therefore the measurements were performed under confining pressures up to 20 mPa which in terms of hydrostatic pressure correspond to depths down to 2000 m. His data for halite with admixtures 90% of gases generated directly enter the atmosphere. It is illustrated in Fig. 8 that gas flow through rocks over geologic time is highly dynamic. It is of minor importance then how many reservoir/seal systems may retain part of the gas because retainment is transitorial. Mean residence time of reservoired methane within the European Upper Carboniferous Basin has been calculated as 10 myr.

Impact of Darcy flow of gases: on physics, exploration for gas and atmospheric research Darcy flow implies that, with the flow of gas, even if input is strong but the seal is highly permeable or thin, no retainment of gases must occur. On the other hand, to produce an accumulation, gas input may remain low if appropriate petrophysical contrasts or seal thicknesses operate. It was the aim of this paper to demonstrate that with a set of case histories representing a wide range of geological settings a reliable


183

Global i n p u t o f t h e r m o c a t a l y t i c m e t h a n e per year (1) Slowly subsiding sedimentary basins (e.g. European Carboniferous Basin): ca. 20 Std. m3/m2 over 1 myr = 20 m over 1 myr = 0.02 mm over lyr Rapidly subsiding sedimentary basins (e.g. Indus Basin): ca. 10,000 Std. m3/m2 over 1 myr = 10,000 m over 1 myr = 10 mm over lyr Decomposition of hydrates (e.g. Alaskan North Slope, King et al. 1989): ca. 2 x 10-4 Std. m3/m2 over 1 day = 0.2 mm over 1 day = 70 mm over lyr Mean all sedimentary basins (estimate): ca. 7 mm over lyr Earth's surface area:

Sedimentary basin's surface area:

4.7 x 108 km2

ca. 1.2 x 108 km2

= 4.7 x 1014 m2

= 1.2 x 1014 m2

Fig. 9. First estimate of the global input of methane to the atmosphere per year from thermocatalytic sources (part 1, in std. m3).

Fig. 8. Illustration of the interaction between a long-lasting vertical methane flow and reservoir/seal systems through sedimentary basins and of the dynamics of flow produced by it.

permeability/depth function is obtained which allows the unknown parameter, "degree of fill of a reservoir with gas", to be predicted for undrilled prospects in a forward modeling mode. A column of gas accidentally held in a reservoir/seal system which is exposed to a gas flow is then a function of the seal permeability and its thickness. This is illustrated in Fig. 8.

Fig. 10. First estimate of the global input of methane to the atmosphere per year from thermocatalytic sources (part 2, in g).

1

8

4

D

Establishing gas balances over sedimentary sections shows that gas quantities generated over a defined area and migrating through the overlying volume are more than a factor of 10 over any capacities of reservoirs/seal systems contained in this volume. It is apparent from this that generation of gas normally does not constitute a limiting factor in exploration for gas filled reservoirs except if a seal is very poor. Moreover, this leads to a fundamental insight into gas migration: under the condition of equilibrium of flow, gas must migrate strictly vertically, and a standardisation of gas balances over a unit of area is justified. There are, however, exceptions which apply to conditions where at the same time gas generation diminishes or ceases laterally. Where a gas molecule finds no or only a few neighbours, it is free to migrate in all directions, even laterally. This is commonly observed with gases stored in basement rocks where soft sourcing rocks or source sediments are found laterally (e.g., Chung-Hsiang, 1982). The quantity of more than 90% of methane generated which is not stored directly enters the atmosphere or the ocean water. It is apparent that this has a serious impact on models of the atmospheric gas and reactants cycles. On the base of the calculations reported here, a first estimate has been made on the quantity of thermocatalytical methane to enter the atmosphere per year with reference to the total surface of the globe (see Figs. 9 and 10). A mean value is given over slowly, rapidly subsiding basins and hydrate decomposing basins (based on direct flux chamber measurements by King et al., 1989). It amounts to 500 Tg/year (which equals 500 x 1012 g/ year). This apporaches the quantity reported so far in the literature to be the total input based excusively on animal, vegetational and human activities (e.g., Stevens and Engelkemeir, 1988). To date, this value is taken as the input to atmospheric balance calculations. In consequence, the evidence from this paper requires at least a doubling of the source quantity of methane, or of the input into atmospheric balance calculations, respectively. A third source, which is bacterially generated methane, may deliver high quantities over short geologic time. This is not included here. With higher input quantities, however, the poor stability of the simulation models would possibly disappear, and a definite determination of reactants cycling velocities and subsequently a convergent prediction of climatic evolution should be possible.

Acknowledgements I thank BEB Erdgas and Erdtil GmbH, Hannover

.

Ke ttel

and Wintershall Noordzee, den Haag for the permission to publish the results of the modeling. Otto Schulze and Erdin Idiz helpfully discussed the concept and the consequences of this paper.

References Antonellini, M. and Aydin, A. 1994. Effect of faulting on fluid flow in porous sandstones: petrophysical properties. Am.'Assoc. Pet. Geol. Bull., 78: 355-377. Borgmeier, M. 1992. Untersuchungen zum belastungsabh/ingigen Durchl~sigkeitsverhalten von Salzgesteinen fur Gase unter besonderer Berticksichtigung der Porenraumbeladung. PhD Thesis, University of Clausthal, Germany. Borgmeier, M. and Weber, J.R. 1992. Gaspermeabilit~itsmessungen an homogenen Modellsalzkemen. Erd61 Erdgas Kohle, 108: 412414. Bredehoeft, J.D., Wesley, J.B. and Fouch, T.D. 1994. Simulations of the origin of fluid pressure, fracture generation, and the movement of fluids in the Uinta Basin, Utah. Am. Assoc. Pet. Geol. Bull., 78: 1729-1747. Chung-Hsiang, P. 1982. Petroleum in basement rocks. Am. Assoc. Pet. Geol. Bull., 66: 1597-1643. Downey, M.W. 1984. Evaluating seals for hydrocarbon accumulations. Am. Assoc. Pet. Geol. Bull., 86: 1752-1763. England, W.A. 1990. The organic geochemistry of petroleum reservoirs. Org. Geochem., 16: 1-3: 415-425. Hubbert, M.K. 1953. Entrapment of petroleum under hydrodynamic conditions. Am. Assoc. Pet. Geol. Bull., 37: 1954-2026. Hunsche, U. and Schulze O. 1993. Effect of humidity and confining pressure on creep of rock salt. Preliminary Proc. 3rd Conf. Mechanical Behaviour of Salt, Paliseau, France. Jurgan, H., Devay, L., Block, M., Kettel, D. and Mattern, G. 1983. Erdgas-Migration und Lagerst/ittenbildung am Beispiel der Erdgasfelder Ost-Niedersachsens. BMFT-Forschungsbericht T83153, German Ministry for Research and Technology. Kettel, D. 1989. Upper Carboniferous source rocks North and South of the Variscan Front (NW and Central Europe). Mar. Pet. Geol., 6: 170-181. King, S.L., Quay, P.D. and Landsdown, J.M. 1989. The 12C/13C kinetic isotope effect for soil oxidation of methane at ambient atmospheric concentrations. J. Geophys. Res., 94:18273-18277. Krooss, B.M. and Leythaeuser, D. 1988. Experimental measurements of the diffusion parameters of light hydrocarbons in watersaturated sedimentary rocks - 2. Results and geochemical significance. Org. Geochem., 12: 91-108. Krooss, B.M., Leythaeuser, D. and Schaefer, R.G. 1992. The quantification of diffusive hydrocarbon losses through cap rocks of natural gas reservoirs - a reevaluation. Am. Assoc. Pet. Geol. Bull., 76: 403-406. Leythaeuser, D., Schaefer, R.G. and Yukler, A. 1982. Role of diffusion in primary migration of hydrocarbons. Am. Assoc. Pet. Geol. Bull., 66: 408-429. Lorbach, M. and Sch6ffmann, F. 1991. Gasverhalten, ZufluBraten und Druckaufbau in geschlossenen Systemen. Erd61 Erdgas Kohle, 107: 500-506. Peach, C.J. 1993. Deformation, dilatancy and permeability development in halite/anhydrite composities. Preliminary Proc. 3rd Conf. Mechanical Behaviour of Salt, Paliseau, France, pp. 139-152. Reid, R.C., Prausnitz, J.M. and Poling, B.E. 1987. The Properties of Gases and Liquids, 4th edn. McGraw-Hill, New York. Schoell, M., Jenden, P.D., Beeunas, M.A. and Coleman, D.D. 1993. Isotope analyses of gases in gas field and gas storage operations. SPE Gas Technology Symposium, Alberta, Canada, SPE 26171, pp. 337-344. Stevens, C.M. and Engelkemeir, A. 1988. Stable carbon isotopic composition of methane from some natural and anthropogenic sources. J. Geophys. Res., 93: 725-733.


185

Vetsoskiy, T.V. 1979. Natural gas geology: NEDRA Press, Moscow. Zhang, Y. 1994. Factors affecting the dynamic equilibrium of gas accumulations. J. Pet. Geol., 17: 339-350.

Zieglar, D.L. 1992. Hydrocarbon columns, buoyancy pressures, and seal efficiency: comparisons of oil and gas accumulations in California and the Rocky Mountain area. Am. Assoc. Pet. Geol. Bull., 76: 501-508.

D. KETTEL

Kettel Consultants, Chfitellon de Cornelle, 01640 Boyeux St. Jgr3me, France


187

Pressure prediction from seismic data- implications for seal distribution and hydrocarbon exploration and exploitation in the deepwater Gulf Of Mexico N.C. Dutta

Pore-pressure prediction before drilling is critical for several reasons. It is required to assess "seal" effectiveness, map hydrocarbon migration pathways and analyze "trap" configuration and geometry of a prospective basin. Furthermore, it aids in the well planning process by providing proper casing and mud program design which can help prevent dangerous "blow-outs", lost circulation of drilling fluids and stuck pipes. The conventional techniques for pressure prediction are limited by two factors: establishing a "normal" trend of an attribute (usually a porosity indicator) and a set of calibration curves relating "overpressure" to deviation from the normal trend of that attribute. Thus, these techniques cannot be used in rank wildcat areas and areas such as the deep water environment (water depth greater than 330 m) of the Gulf of Mexico where normal compaction trends are usually non-existent. At BP, a new technique for pressure prediction has been developed. The essentials of this technique are as follows. It uses a proprietary transform that relates velocity to effective stress (defined as the difference between overburden and pore-pressure), temperature and gross lithology directly. It takes into account the major causes of overpressure mechanisms: undercompaction, clay dehydration and transformation, buoyancy and charging of fluids in dipping, permeable beds. It does not require local calibration and predicts effective stress directly, which is the most fundamental quantity for pressure prediction. In this paper a brief description of this technology is presented together with several examples from the deepwater environment of the Gulf of Mexico. Applications are made in I-D, 2-D and 3-D and have enabled explorationists to define "seal" failure risks in deepwater prospects. Drilling experiences have shown that this technology can predict pressures to within 0.5-0.75 pounds per gallon (ppg) at target depths, provided the "low-frequency" trends of seismic interval velocities are of good quality and "close" to well velocities to within 5-10%. The quantitative reliability of the method depends on two factors: availability of high quality seismic velocity data and an understanding of the rock properties. The vertical (temporal) resolution is limited by the available bandwidth of the seismic velocity data whereas the spatial resolution is dictated by the acquisition parameters and the frequency of velocity analysis (CDP spacing and panels for analysis).

Introduction Abnormal pore fluid pressures are known to occur worldwide. By definition these pressures are either higher or lower than the hydrostatic pressure, which is the pressure required to support a column of fluid from subsurface formation to the surface. In this paper, the word "geopressure" is used to denote those pore pressures which are higher than the hydrostatic pressure. Prediction of pore pressure prior to drilling can be critical at several stages in the exploration, and development process. It can be used during exploration: - to assess the effectiveness of a regional top seal section, to provide calibration to basin modeling, - to map hydrocarbon migration pathways, and - to analyze "trap" configuration and geometry of a prospective basin. In the exploration and appraisal drilling and development phase, pressure prediction is a pre-requisite for safe and economic drilling, where an optimized casing and mud program design can avoid well control problems. -

A new integrated geological and geophysical technique for pressure prediction has been developed by B P, where pressure is derived from seismic velocity data. This technique is particularly suited for pressure prediction in areas with no well control, and is seeing increasing use in BP's deep water acreage in the Gulf of Mexico, where seismic data often provide the only measure of subsurface pore pressure. Predictions of pressure can be made in the l-D, 2-D and 3-D, and a "pressure cube" can be and has been generated from 3-D seismic data. When calibrated with offset and correlation well information in the appraisal and development phase, this technique is very powerful for providing pressure prediction along well-bore paths and at the reservoir scale. In the next section, a concept of subsurface pressure is briefly explained along with a short discussion on the origin of geopressure. Then, a brief discussion of the developed technique is presented. Some examples of applications of this technique in the deep water Gulf of Mexico (GOM) are contained in the section on Applications and our conclusions and discussions follow.



188

N. C. Dutta

Basic pressure concepts and origin of abnormal pressures

The effective pressure or differential pressure, or, is the pressure which is acting on the solid rock framework. According to Terzaghi's principle (Terzaghi and Peck, 1968), it is defined as

Definitions and pressure concept Formation pressure or pore pressure, p, is defined as the pressure acting upon the fluids in the pore space of a formation. Hydrostatic pressure, PH, is the pressure caused by the weight of a column of fluid: PH-pf'g

(1)

"z

where z is the height of the column, ,of, is the fluid density, and g is acceleration due to gravity. The size and shape of the fluid column has no effect on hydrostatic pressure. The fluid density depends on the fluid type, concentration of dissolved solids (i.e., salts and other minerals) and gasses in the fluid column and the temperature of the fluid. In the SI system, the unit of pressure is Pascal (Pa), and in the British system, the unit is pounds per square inch (psi). We note that Pa = 1.45 x 10-4 psi. The formation pressure gradient, expressed usually in pounds per square inch per foot (abbreviated by psi/ft) in the British system of units, is the ratio of the formation pressure, p, in psi to the depth, z, in feet. It is not the true gradient, dp/dz, but is strictly an engineering term. In general, the hydrostatic pressure gradient, PH (in psi/ft), can be defined by PH (psi/ft) = 0.433 (fluid density)

(in g/cm 3)

(2)

We note that 1 psi/ft = 0.0225 MPa/m. The pressure gradient of 0.465 psi/ft (0.0105 MPa/m), typical for the offshore, Gulf of Mexico, assumes a salt concentration of 80 000 ppm of NaC1 at 77~ The overburden pressure at any point, S, is the pressure which results from the combined weight of the rock matrix and the fluids in the pore space overlying the formation of interest. This is expressed as

(5)

tr= S- p

where S is the total vertical component of overburden pressure and p is the pore pressure. It is the effective pressure that controls the compaction process of sedimentary rocks; any condition at depth that causes a reduction in a will also reduce the compaction rate and result in geopressure. Fig. 1 shows a pressure versus depth profile in a clastic sequence. This profile is typical for the Louisiana and Texas Shelf, Offshore GOM. The transition from hydrostatic to overpressured interval in these areas is fairly well defined and can vary from a few hundred to several thousand feet in thickness. However, drilling experiences in the Plio-Pleistocene formations of the deep water GOM (water depth greater than 1000 ft) have shown that in these areas, the transition zone is usually not well developed, and the pore pressures are usually higher than hydrostatic pressure at shallow depths and continue to build up gradually with depth, with occasional occurrences of pressure reversal. The variables that are required for prediction and assigning risks for prospectivity are: - the depth of the top of the overpressured zone, the depth of the top of the "hard-pressure" zone (defined as a limit of 1000 psi effective stress),

PRESSURE

i '~k " "\"~.O~. ~ i ~.k\

O- =S-P

'~ "",~d>. S=g

I/Pb (Z) dz

(3)

where S is the overburden pressure, Pb is the bulk density (depth dependent), and g is the acceleration due to gravity. The bulk density of a rock is given by /O b = t#/Of +

(1 - t # ) / O g

(4)

where $ is the fractional porosity, p f is the pore fluid density, and p g is the density of the matrix (grain density). Overburden pressure is depth dependent and increases with depth. In the literature, overburden pressure has also been referred to as geostatic or lithostatic pressure.

'k I ' I

! \\ / \"\.

///I I

",, ,'N~/,..pj

.

TOP OFOVERPRESSURE

", \ "\x~~ ,

iH Ig R)a ~

eo

seal failure limit

"'~.~

r-~

'~PRESSURE

EFFECTIVE \~.--~_ pn.~ " ' , , ~ STRESS(0-) ~~E'SSURE{p)\.\~

Fig. 1. Typical pressure profile in clastic basins. Top of hard pressure is defined as that pressure where effective stress is 1000 psi. When effective stress reaches this value, the likelihood of seal failure increases considerably.

Pressure prediction from seismic data

189

the seal failure limit, and the shape of the effective stress profile. Although there is no universally accepted scale expressing the degree of geopressuring, the nomenclature introduced for the Gulf of Mexico's Tertiary Clastic by Dutta (1987, Table 1, p. 5) will be used in the present work. The effective pressure, cr, plays the key role in the model discussed here. It should be noted that geopressuring implies low effective stress and high porosity. Low ~r and high porosity tend to lower acoustic velocity. In the current model, a relationship is utilized which relates velocity to effective stress, temperature, lithology and pore pressure. This relationship is used to predict effective and pore pressures using seismic velocity data (see below).

-

-

Origin of geopressure

Fig. 2. Differential compaction due to fluid flow in a dipping, permeable bed embedded in geopressured shale.

Development of geopressure suggests that fluid movement is retarded both vertically and horizontally. This can be due to rapid burial of lowpermeability sediments, rapid enough to prevent compaction water to leave the system, or lithology change, or both. Some of the important mechanisms that cause geopressure are: 1. mechanical compaction disequilibrium (Hubbert and Rubey, 1959), 2. clay dehydration and alteration due to burial diagenesis (Dutta, 1987, Ch. 2), 3. dipping or lenticular permeable beds embedded in shales (Fertl, 1976), 4. buoyancy (Fertl, 1976), 5. tectonism (Dutta, 1987, Ch. 2), and 6. aquathermal pressuring (Dutta, 1987, Ch. 2). In the current work, a model was developed which includes the first four mechanisms. The first two mechanisms are explicitly included via a generalized compaction law for clastics, the third mechanism is included implicitly via the use of seismic velocity analysis which is a critical step in this method. This is qualitatively explained in Fig. 2. The permeable bed in this example transmits geopressure from the "down dip" to "up dip" direction. This causes relatively more undercompaction in shales which are adjacent Table 1 Classification of geopressures (Dutta, 1987) Fluid pressure gradient (psi/ft)

Geopressure characterization

Greater than 0.465 but less than or equal to 0.65 Greater than 0.65 but less than or equal to 0.85 Greater than 0.85

Soft or mild Intermediate or moderate Hard

to the crest of the structure than the shales laterally removed from the crestal structure. This leads to a lateral change in velocity (a lateral velocity gradient is created), the magnitude of which depends on the relief of the structure and the degree of geopressuring in the down dip direction. The fourth mechanism is included via appropriate equations of state for density of the pore fluid as a function of temperature, gas-tooil ratio (GOR), salinity and pressure.

Subsurface stress Under the hydrostatic condition, water within the pore spaces of the rocks is connected to water in the sediments and the sea above. Under lower rates of sedimentation, it is possible for water to be expelled at a rate adequate to maintain the hydrostatic equilibrium. However, at rapid burial rates, with relatively impermeable shales, this equilibrium is not maintained. The fluid motion is retarded, and the pore fluid begins to support the overburden, resulting in pressure increase. Fig. 3 shows the state of subsurface stress. The empty space in this figure shows a pore surrounded by solid rock. The vertical overburden pressure, S, is supported by two unequal forces: the formation fluid (pore) pressure, p, and the vertical effective stress acting on the rock flame, av. By Newton's third law of motion S = av + p

(6)

Similarly, the horizontal effective stress on the rock frame is crh. If we assume S/Z= 1.0psi/ft, and p/Z = 0.46 where Z is depth in feet, then Crv/Z= 0.535 psi/ft. However, if p/Z = 0.70 psi/ft, then S/Z remains

190

N.C. Dutta

I

S

O-h+ p

o-h

(ROCKFRAME) WHERE" S = p + cry Fig. 3. Effective stress concept as defined by Terzaghi.

1.0 psi/ft and av/Z becomes 0.30 psi/ft. Therefore, geopressuring (caused by compaction and trapping of fluid) causes a reduction in rock frame stress. Note that effective stress increases linearly with depth at a rate of approximately 0.535 psi/ft, until formation pressure becomes abnormal. At this point effective stress decreases, causing a decrease in velocity and density of the rock. If p approaches S, then av approaches 0, and the seal failure occurs via creation of open fractures. This is known as fracture failure and its likelihood of occurrence provides a risking criterion for a prospect. In the present work, a seal failure criterion of av < 1000 psi is set. The horizontal effective stress, ah, is related to av through Poisson's ratio, 7, namely, Y ah=~ a 1-7

v

(7)

For silty-shales, 7 = 0.4, and ah = 0.67 av. Thus, horizontal seal failures are likely to occur before vertical seal failure. In this report, we will drop the suffix v of av and use a to denote vertical effective stress unless otherwise noted. In the next section, we present a brief discussion of the model which relates velocity and density of rocks directly to a.

Present technique Database The conventional methods (Hottman and Johnson 1965; Pennebaker, 1968; Eaton, 1969) of relating velocity to pore pressure are via empirical calibration curves based on well log velocity data and in situ

pressure measurements in the borehole (e.g., repeat formation tester, RFF). Although this approach has been successful in many cases, it could not be used in the deep water Gulf of Mexico because of lack of borehole data. Even if local calibration was feasible, it may not be applied throughout the field because of significant faulting visible on the seismic data. The faulting can create pressure compartments or pressure anomalies, depending on whether faults are sealing or non-sealing. Therefore, a pressure calibration curve created from one side of the fault block may not be applicable on the other side. In the present technique, empirical calibration curves such as those discussed above are not required. Instead, velocity of a given rock lithology is related directly to effective stress, a, and temperature, T. The model was constructed using BP's extensive database (wireline logs, cores, pressure measurements using R F r tools) in the Tertiary Clastic Province of the offshore Gulf of Mexico (Plio-Pleistocene to Miocene). The data were first quality controlled for environmental effects; particularly all sonic logs were checkshot corrected. Then the well logs were segregated by lithology (sand, and shale) by careful petrophysical analysis. This was followed by binning the data (velocity and bulk density for each lithology) in terms of pressure. Whether rocks were hydropressured or not was judged by common log response of four logs; velocity, density, resistivity and induction. This binning procedure enables one to relate velocity (for a given lithology) to effective stress directly. For hydropressured rocks, the effective stress is uniquely defined. It is given by

G=S--PH

(8)

where PH is defined in Eq. (1) and S is obtained via numerical integration of density log using Eqs. (3) and (4). For stratigraphic sections where RFT data were available, effective stresses were calculated using these data and the overburden derived from density logs. For each rock unit, a corresponding temperature was also posted in the bin. The temperature information was obtained either from the maximum bottom hole temperature data (BHT), after correcting for mud circulation effects in the borehole, or from AMF logs, if available. In this fashion, a dataset was compiled which contained, for a given lithology, effective stress and temperature. This dataset provided two fundamental relations: (a) bulk density versus velocity (or its reciprocal, sonic transit time) for a given lithology, and (b) velocity versus effective stress and temperature for a given lithology. The first relationship allows us to calculate bulk density, and hence overburden, S, from velocity data. The second relationship enables us to calculate

191


effective stress, a, directly from velocity. By knowing S, we can compute pore pressure, p, easily from Eq. (5).

interpret and laterally smooth stacking velocities, transform stacking velocities to interval velocity using the Dix equation, and smooth interval velocities laterally and vertically to give interval velocity versus two way time. Fig. 4 shows the procedure for pressure prediction in a schematic way. The quality of the predicted pressure field is critically dependent on the velocity field. Many processes can cause stacking velocities to be unrepresentative of true average velocity and hence incorrect interval velocities may result. The Dix equation assumes parallel layers with zero dip. It is generally thought that modern dip moveout operation (DMO) in seismic processing largely corrects for non-zero dip but not for the case of non-parallel layers. More sophisticated methods of building depth/ velocity models are becoming available and it is recommended that some of these have to be tried in any future work. The major source of errors in interval velocity estimations are probably velocity anisotropies. Until the effects of such phenomena are better understood, the method in its present form may only be reliable to a scale as large as a spread length used during seismic acquisition. We should also remember that velocity alone may not discriminate lithology and this is especially true where clastic (sand/shale) sequences are mixed with carbonates and anhydrites. Experience in the Gulf of Mexico has shown that for hydrostatically pressured rocks, velocity is insensitive to lithology. We can thus attribute a velocity inversion to a lowering of effective stress (increasing pore pressure above hydrostatic) with some confidence. In any case, even if a velocity anomaly is mistakenly attributed to compaction and pressure rather than lithology, it is preferable to have a false alarm rather than an overlooked pressure anomaly in evaluation of drilling hazards. This is equivalent to accepting a hypothesis even if it may be false rather than reject it to find it true. We note that the vertical resolution of the seismic interval velocity is low; the frequency content is no more than 2-4 Hz. Thus, the pressure estimate using conventional velocity analysis is fairly "gross" and it may not provide estimates within individual reservoir layers, where RFT measurements are made. For pressure estimates in the reservoir scale, one would require high frequency velocity information from other sources, such as acoustic impedance data. The current technique can be and has been extended for applications at reservoir scale (Dutta and Ray, 1996) using velocities obtained from inversion of acoustic impedence of seismic data. The entire flow chart for pressure prediction using seismic velocity (without well control) is Shown in Fig. 5. With a sonic log from a well, a similar proce-

-

-

-

Procedure The necessary sequence of operations to predict effective pressure and overburden and hence, pore pressure from seismic data starts with detailed velocity analysis (Dix, 1955). The usual steps for velocity analysis (VA) are listed below: obtain pre-stack migrated seismic data, - pick stacking velocities, - correct for offset bias and anisotropy, obtain horizon consistent stacking velocities using a geologic model (an interpreted time section), -

-

NPUT 9 Velocity . Temperature . Gross Lithology

TRAN 9 Velocity vs Effective Stress (or), Temperature (T) and Lithology 9 Velocity to Overburden (S)

Pressure (p), Effective Stress (cr) 8 Overburden (S) S-cr+p

Fig. 4. A schematic of the key components in the present technique for pressure prediction.

192

N.C. Dutta

seismic interval velocity at a CMP vs time

velocity vs density relation

velocity vs temperature/ effective stress relation

color display

geothermal gradient

time-depth conversion

temperature vs depth relation

,

~_~

mudline temperature

effective stress vs depth

density vs depth

obtain fluid pressure

integrate to obtain overburden(S) vs depth

1

Fig. 5. A flow chart which outlines the steps involved in the current approach for pressure prediction using seismic interval velocity, temperature and lithology.

dure is followed with two important differences. Firstly, the sonic log must be edited and filtered. Secondly, the velocity log must be corrected by a check shot survey to account for important low frequency drift. In summary, the new technique developed at BP uses a proprietary transformation that relates velocity directly to effective stress, temperature and gross lithology, takes account of the major causes of overpressure in clastic basins (namely, undercompaction, clay dehydration and diagenesis, buoyancy and charging of fluids in dipping, permeable beds), and predicts effective stress directly, which is the most fundamental quantity for pressure prediction.

Applications The technology described above was developed in

the Gulf of Mexico, an area where B P has been involved in deep water exploration for many years. The technology has been applied by B P to the following exploration areas: - Deepwater Gulf of Mexico, - South Caspian Sea - Offshore Angola, - North Sea, - East Venezuela, and - Offshore, Nigeria These applications have been made and continue to be made in different dimensions: l-D, 2-D and 3D. Below some examples are presented.

3-D applications For 3-D applications velocities come from either 3-D seismic survey or a grid of closely-spaced 2-D

Fig. 6. Effective stress has been color coded for its proximity to the hydraulic seal failure limit of 1000 psi. Green represents a low likelihood of seal failure. Yellow indicates uncertainty based on an analysis of the estimated error in effective stress. Certain basins stand out as either low risk (e.g., Auger basin) or high risk (e.g., Amundsen basin). The updip margins of most basins show high risk in prospectivity. This allowed explorationists a quantitative means of not only highgrading prospects in this fairway but also opening new opportunities. The inset shows the extent of the area of study in the Gulf of Mexico. Fig. 7. A map of the two way time to the top of hard pressure in a deepwater fairway, Gulf of Mexico. The inset shows the extent of the area of study in the Gulf of Mexico.


193

194

lines. Typically, interval velocities, from analysis of stacking velocities, are loaded in a 3-D gridding algorithm where velocity conditioning, including lateral and temporal smoothing and interpolation is carried out. The output of this process is a velocity cube in 3-D which is then loaded on a workstation and converted to several other 3-D cubes: effective stress, density, overburden, pressure and pressure gradient. After this, slices from any of these cubes can be taken and projected on a map view onto interpreted geologic attribute maps, such as faults and geologic time horizons. Fig. 6 shows an application of the BP technique on a regional scale in the deep water acreage of the Gulf of Mexico (taken from the work of D. Foster, D. Whitcombe and J. George in B P). The area of study is shown in the inset. Here a 3-D model of effective stress has been developed over a prospective play fairway, derived from a closely spaced grid of 2-D seismic interval velocities. The model covers an area of 140 x 102 km, with water depths greater than 330 m. Fig. 6 is a map of effective stress, derived from the model and projected at a prospective horizon

N. C. Dutta

over the blocks of interest. The color codes in Fig. 6 represent the risk associated with hydraulic seal failure. This map has enabled the explorationists to highgrade areas of low top seal risk, and down-grade risky areas. Prospective areas were highlighted using this method, which other techniques (such as basin simulation using burial history analysis) had overlooked. Fig. 7 is a map of top of hard pressure in the same fairway as a function of two way time, again, taken from the work of Foster et al. at B P. Here the top of hard pressure has been defined as that depth (or time) where the effective stress reaches a threshold value of 1000 psi. Recall that in Fig. 1, this limit on effective stress was also referred to as the seal failure limit.

1-D/2-D applications At the prospect scale, the resolution of the seismic velocity analysis can be greatly enhanced by detailed velocity analysis, modeling and calibration against well data. A very detailed subsurface image of pres-

Fig. 8. This figure shows a cross-section of the effective stress, in psi, versus two way time over a prospect in the deepwater, Gulf of Mexico. A pressure cell is clearly visible, which is bounded by salt on the left hand side. The discovery well location through the bright spots is also noted on the seismic section.

195


tO t~

,,,,~ / - ~ RFT.,

I,Q,O 41'-

ca.

i _,bl'

A

/

4

5

6

j,#

7

9~

8

9

~

S

9

10

11

12

13

Depth, Feet (* 1000)

14

15

16

17

18

Fig. 9. This figure shows the pressure versus depth profiles for the discovery well shown in Fig. 8. Computed pressures from both seismic (predrill) and sonic (post-drill) velocities are shown and compared with the measured pressures from the repeat formation testers denoted by RFF. The overburden pressure was estimated from the seismic velocity and found to be in good agreement with that obtained from integrating the density log (post-drill).

sure and effective stress can be obtained, both at the prospect and the well-bore scale. An example of such an analysis from the Gulf of Mexico is shown in Fig. 8, on a 2-D seismic line which has been carefully processed to preserve stratigraphic details. A discovery well, shown on the seismic line, was drilled on the flank of a salt dome in a water depth of approximately 900 m. Fig. 8 shows the effective stress, in psi, as a function of two-way time and common depth point (CDP) locations. The figure shows the existence of a pressure cell associated with stratigraphic variations within the prospect. It also indicates pressure traps in the vertical direction, shown as reversals of effective stresses. A comparison of the predicted pressures with the RFT data from the well is shown in Fig. 9. The comparison is good, and the predictions are within 400 psi of the formation pressure. An analogous prospect was drilled in the same deep water fairway close to the geographic location depicted in Fig. 8, partly based on the results of the pressure prediction, which resulted in a commercial discovery for BP. Another example from the deepwater Gulf of Mexico (Garden Banks) is shown in Figs. 10-14. The color plot of Fig. 10 shows the interval velocity field together with the stacked traces. We note the general conformity of the structure with the velocity field. The color scale on the left side of Fig. 10 is expressed in ft/s. Using the velocity as input and a geothermal

gradient of 1.1~ ft, we predicted the 2-D crosssection of effective stress, in psi, in Fig. 11 as a function of two way time and CDP number. The color scale of the figure ranges from 470 to 4150 psi. A gradual increase of effective stress (meaning a decrease in fluid pressure) is apparent from left to right (away from the well). This suggests relatively more compaction (and consequent expulsion of water) as one moves away from the well and moves updip to the fight. Thus, an increase in effective stress (decrease in pore pressure) updip and away from the well location suggests an active migration pathway of fluids. Turning next to pressure estimation using sonic log, Fig. 12 shows a comparison of the band passed calibrated sonic log and the seismic interval velocity of Fig. 10 at the well location; the two velocities are in good agreement showing a general goodness of the velocity analysis of the reflection seismic data. The predicted effective stresses from both sonic and seismic are shown in Fig. 13. The line marked "hydrostatic" shows the expected effective stress variation, had the fluid pressure been in hydrostatic equilibrium. That the pressures are higher than the hydrostatic is reflected by the fact that the effective stresses are much lower than the hydrostatic curve; the difference is being supported by the pore fluid. The geopressuring in this well began at approximately 6 kft below the seismic datum where the predicted effective stresses depart from the hydrostatic line.


] 97'

i

'[ ....

. . . . . . . . .

I

i 3

4

5

I

!

6

7

8

9

10

11

12

13

14

15

16

17

18

Depth, Feet (* 1000) Fig. 12. A comparison of the seismic interval velocity at the well location (pre-drill model) with those obtained from sonic log (post-drill). The sonic log has been filtered to mimic the seismic bandwidth.

The predicted pore pressures from seismic are compared with those predicted from sonic log in Fig. 14. The curve marked "lithostatic" is the overburden pressure obtained from integrating the seismically

derived density curve. By subtracting from it the seismically derived effective stress curve of Fig. 13, we obtain the fluid pressure curve marked "seismic" in Fig. 14. The curve marked "sonic" is obtained by

1

f

f

i

f

f

_o o~"- 9

SIEISMIC,.p~

.I

lIFT

l i nl am II m I

Z)N!

i

I 3

4

5

6

7

8

9

10

11

12

Depth, Feet (* 1000)

13

14

15

16

7

18

Fig. 13. Predicted effective stress versus depth using the seismic velocity and sonic data of Fig. 12. The curve labeled "hydrostatic" is obtained using a fluid pressure gradient of 0.465 psi/ft. The overburden pressures needed to generate the effective stress plots of this figure are obtained by integrating the appropriate density curve. Fig. 10. A color plot of the smoothed seismic interval velocity versus two way time for a deepwater, Gulf of Mexico prospect. The color chart on the left shows interval velocities in ft/s. Fig. 11. This figure shows the effective stress, in psi, versus two way time for the velocities displayed in Fig. 10. The well location is also shown.

198

N. C. Dutta

Fig. 14. A plot of predicted fluid pressures versus depth derived from seismic velocity and calibrated sonic log. Pressure data from RFT measurements are also shown for comparison. The lithostatic or overburden curve was also generated using seismic velocity.

subtracting the sonic-derived effective stress curve (Fig. 13) from the corresponding lithostatic curve (not shown) obtained by integrating the sonic-derived density curve. The predicted pressures from both "seismic" and "sonic" are in good agreement with each other and with those obtained by RFT measurements (shown by diamond in Fig. 14). The predicted pressures from sonic are not reliable beyond 17 000 ft because of the "edge effect" of the filter applied on the sonic log. Thus, the disagreement between the RFT data and the predicted pressure beyond 17 000 ft is easily explainable. These case studies revealed that: (i) active migration pathway of fluids can be imaged by 2-D/3-D effective stress maps using seismic velocity data, and (ii) the predicted pore pressures at the well using both seismic and sonic data are in agreement with each other and with an independent set of data: the RFT measurements.

Conclusions and discussions The B P technology for prediction of pore pressure using seismic velocities has a number of merits: - maps and 3-D models of effective stress and porepressure can be generated from seismic data alone. - 3-D pressure models can be used to map pressure at specific reservoir levels. These maps can be combined with structure maps and seismic attribute maps to constrain the risks at the target level. - prior knowledge of the likely pore pressure allows

optimum well design and thus safer and cheaper drilling, and - pressure can be mapped at the reservoir scale, and related to faults, folds, diapirs and stratigraphy. These results can have a considerable impact on reservoir modeling. Drilling experience has shown that this technology can predict pressures to within 0.75 ppg at target depths, provided the low-frequency trends of seismic interval velocities are of good quality and are within 5-10% of well velocities. This has been observed by numerous case studies and applications within B P's exploration and exploitation community. The current technique predicts effective stress quantitatively and directly, unlike any other method. The method is completely pre-drill in nature; it does not use trend data and it is not tied to block-to-block well calibration. However, it does require an understanding of the local geology and in particular, of rock properties. In addition, the reliability of the predicted effective stress and pore pressure is limited by the resolution of the seismic velocity.

Acknowledgements I am grateful to B P for the permission to present and publish this paper at the "Hydrocarbon s e a l s importance for exploration and productions" conference held in Trondheim, Norway, and sponsored by the Norwegian Petroleum Society during 29-31 January, 1996. Thanks are due to D. Foster, D. Whit-


combe and J. George for the use of Figs. 6-7 which are taken from their work and C. Yeilding for reviewing the manuscript.

References Dix, C.H. 1955. Seismic velocities from surface measurements. Geophysics, 20: 68-86. Dutta, N.C. (Editor) 1987. Geopressure, Geophysical Reprint Series No. 7, Society of Exploration Geophysicists, Tulsa, OK. Dutta, N.C. and Ray, A. 1996. Subsurface image of geopressured rocks using seismic velocity and acoustic impedance inversion. 58th Annu. Mtg. Eur. Assoc. Geosci. Eng., Amsterdam (extended Abstr.).

N.C. DUTTA

199

Eaton, B.A. 1969. Fracture gradient - prediction and its application in oil field operations. J. Pet. Technol., October: 1353. Fertl, H.W. 1976. Abnormal Formation Pressures. Elsevier, New York. Hottmann, C.E. and Johnson, R.K. 1965. Estimation of formation pressures from log-derived shale properties. J. Pet. Technol., June: 717-722. Hubert, M.K. and Rubey, W.W. 1956. Role of fluid pressure in mechanics of overthrust faulting. Geol. Soc. Am. Bull., 70:115-166. Pennebaker, E.S. 1968. Seismic data indicate depth and magnitude of abnormal pressure. World Oil, 166: 73-82. Terazaghi, K. and Peck, R.P. 1968. Soil Mechanics in Engineering Practice. Wiley, New York.

BP Exploration Inc., 200 Westlake Park Boulevard, Houston, TX 77079, USA


201

Pore water flow and petroleum migration in the Smorbukk field

area, offshore mid-Norway R. Olstad, K. Bjorlykke and D.A. Karlsen

In the SmOrbukk field, offshore mid-Norway, the Upper Jurassic to Lower Tertiary sequence is over-pressured, while the Lower and Middle Jurassic reservoir sandstones exhibit in most cases pressures close to hydrostatic, causing a downwards reduction in hydrodynamic potential. Based on the observed pressure gradients in the cap-rocks, the effective permeability of water was calculated to be about 1 nanoDarcy (10 -21 m 2 for calculated fluxes equal to 10-13 m3/m2), which agrees well with the lowest permeability measurements on samples. An over-pressured section to the west of the SmCrbukk field, is separated from the field by a fault zone which presently acts as a pressure barrier. The western edge of this fault zone has been assumed in earlier studies to mark the western limit of the hydrocarbon drainage area for the SmCrbukk field. The present study has found evidence that much of the oil migration into the Sm~rbukk field occurred in the Early Tertiary, much earlier than was previously assumed. This would require migration from areas to the west and south where the Spekk Formation source rock was mature at this stage. Our model implies that migration occurred from the west across faults at shallow depth (2 km), and that these faults were progressively sealed by diagenetic processes during deeper burial (4-5 km). The reduced lateral drainage of petroleum and water to the east caused high overpressures and probably fracturing and loss of hydrocarbons in some of the reservoirs to the west of the SmOrbukk field. Within the SmCrbukk field, hydrocarbons of different oil to gas ratios and maturities may indicate stratigraphic and structural compartments, and also creation of diagenetic seals caused partly by quartz cementation. This study from Haltenbanken clearly demonstrates that petroleum migration cannot be inferred from the present pressure distribution, because the permeability and therefore also the pressure gradients changes continuously, due to diagenetic processes.

Introduction Several quantitative one- and two-dimensional fluid flow models relating pressure, subsidence rate and compaction have been developed through the last few decades. The advantage of such models is that they can help us to understand the evolution of pore pressures through time and to investigate the relative importance of various mechanisms suggested for the generation of overpressure. However, one should bear in mind that the confidence of such models relies on the geological parameters going into the mathematical equations. Up to now, such models have mainly considered the effect of mechanical compaction and not the effect of chemical compaction (diagenesis), which also may release water. Water recharge through clay diagenesis and its impact on the overpressure generation has been modelled by Bethke (1985), Bethke et al. (1988), and Bredehoeft et al. (1988). One-dimensional models of overpressure have been carried out in several sedimentary basins (Gibson, 1958; Bredehoeft and Hanshaw, 1968; Smith, 1971; Sharp and Domineco, 1976; Bishop, 1979; Keith and Rimstidt, 1985; Thorne and Watts, 1989; Mudford et al., 1991). The predictive value of such studies are, however, limited and Haltenbanken is a good example of how important the lateral drainage can be for the pressure distribution. A thorough

knowledge of the permeability distribution would also have significant consequences for understanding the development of the hydrocarbon migration. Migration of hydrocarbons from source rocks to reservoirs is still poorly understood and several different models have been published. Early attempts to explain the mechanism of migration were based on the dissolution of petroleum in pore water (Baker, 1959; Meinschein, 1959; Cordell, 1973) and/or diffusion through water-wet rocks (Watts, 1963; Bray and Foster, 1979; Hinch, 1980). Quantification of these mechanisms has shown that the solubilities and diffusion constants are far too low to account for the masses transported, or the time scales given (Jones, 1980; Leythaeuser et al., 1982). It now seems to be generally accepted that hydrocarbon migration takes place mostly as a separate phase, with buoyancy as the main driving force (England et al., 1987). The buoyancy force is resisted, however, by the capillary pressure, and in a water-wet system there is a minimum pore-throat size through which oil can flow. This minimum pore-throat size is dependent upon the height and density of the migrating petroleum stringer. At burial depths of 4.0 km, shales may have permeabilities of about 1 nD and pore sizes as small as 3/~ (0.3 nm); however, typical pore sizes are in the range of 30-120 ~ (0.3-12.0 nm) (Leonard, 1993; Best and Katsube, 1995). Such small pore sizes (and throats) would imply that many of the organic mole-

Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mc~ller-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 201-217, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997

202

R. Olstad, K. BjCrlykke and D.A. Karlsen

Fig. 1. Map of Haltenbanken, showing locations of wells included in this study, numbered in the following order: (1) 6506/11-1, (2) 6506/12-1, (3) 6506/11-3, (4) 6506/12-4, (5) 6506/12-5, (6) 6506/12-6 (modified from Ehrenberg et al., 1992).

cules generally found in the crude oil could not have been transported through the matrix of such shales and that fracturing in most cases is required. The purpose of the present paper is to integrate models for fluid flow, diagenesis and petroleum geochemistry using Haltenbanken and the SmCrbukk field as a study area. Based on analysis of 106 core samples from the Jurassic succession and drilling data from 6 wells drilled in the SmCrbukk field area, on Haltenbanken, offshore mid-Norway, we propose a new migration history and we suggest alternative drainage areas for the hydrocarbons in this area.

Study area, stratigraphy and regional geology The wells included in this study are located on the western edge of the Halten Terrace (Fig. 1). The Halten Terrace is highly block faulted, and the major extensional fault activity took place during the Late Jurassic to Early Cretaceous Kimmerian tectonic phases (Been et al., 1984; Bugge et al., 1984; Bukovics and Ziegler, 1985). Differential subsidence of pre-Cretaceous rocks along the Kristiansund-Bodr Fault Complex resulted in a platform area to the east

and a basinal area to the west. The subsidence of the Halten Terrace relative to the TrCndelag Platform accelerated throughout Cretaceous time (Aasheim and Larsen, 1984). Thus, the Haltenbanken area has undergone continued subsidence with no major uplift since Paleozoic time (Fig. 2). The subsidence history of the Mesozoic sediments corresponds to moderate to high sedimentation rates (0.001-0.1 mm/year) and a high degree of differential subsidence in the Upper Jurassic and Lower Cretaceous, following rifting and fault block rotation. Lower Tertiary sedimentation is characterized by moderate sedimentation rates. Overpressure has been reported both in the Upper Jurassic, Cretaceous and Tertiary successions. In Late Pleistocene time, the Haltenbanken area experienced rapid subsidence and deposition of 1000-1500 m of sediments (subsidence rate of 0.5 mm/year) (Hollander, 1984; Dalland et al., 1988). A generalized stratigraphic column of the area (Dalland et al., 1988) is shown in Fig. 3. The poorly sorted, shallow marine sandstones of the Tilje Formation, is overlain by the Ror Formation, which consists predominantly of clay- and silt-stones, in an overall coarsening upward trend. The Ror Formation is overlain by a regressive sandstone known as the

Pore water f l o w and petroleum migration in the SmCrbukkfield area, offshore mid-Norway

I

t

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1 1

I I iiilr 200

150

100

50

203

tween 15 and 45% (mean value 28.5%). The Melke Formation has also been reported to contain scattered sandstone stringers (Dalland et al., 1988). The clay minerals are mainly illite (40-60%) and kaolinite (40-60%), with chlorite in varying amounts (up to 10%). Where the chlorite content is high, the illite/ kaolinite ratio is lower than in the adjacent samples, where only traces or a few percent of chlorite is present. In samples which have a high chlorite content, the illitization seem to have been inhibited, at least to some degree. This is probably due to the fact that chlorite may form by replacement of kaolinite and smectite and the amount of chlorite precipitated is limited by the supply of iron and magnesium from dissolving mafic minerals and rock fragments (BjCrlykke and Aagaard, 1992). In the deeper shales

0

TIME (M.Y.)

CHRONOSTRATIGR.

GP.

FORMATION

Holocene Pleistocene

Fig. 2. Compaction corrected burial history for top Gain Formation in well 6506/12-1 (modified from Walderhaug, 1997).

? Z< ' ~ - - - - - N ~ ' U S ~ - - - ~ - -

Z

Pliocene

-~

....:.:.. ~

..

Fangst Group, which was deposited in a shallow marine to coastal deltaic environment. Because of major rifting in the Upper Jurassic, the boundary between the Fangst Group and the Viking Group is represented by an unconformity, whose magnitude depends on structural position. The upper part of the Viking Group, the Spekk Formation, is time equivalent with the Kimmeridge Clay Formation and the Draupne Formation in the North Sea. Organic geochemical data suggests that the Spekk Formation is the main source-rock in the area (Karlsen et al., 1995). The Viking Group rocks are the main caprocks in the SmCrbukk field area. Marine conditions prevailed during the Cretaceous, and up to 1700 m of silt, mud, and thin beds of lime-stones were deposited. The Tertiary sequence is separated by a regional Upper Cretaceous unconformity. The Rogaland Group consists of a marine shale overlain by the tuffaceous Tare Formation, which is equivalent to the Balder Formation of the northern North Sea. The overlying Brygge Formation is a marine shale with minor amounts of sandstone and limestone. Following a Mid-Oligocene unconformity, Haltenbanken was covered by an up to 1500-m thick succession of Miocene-Pliocene and Quarternary sediments.

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2/~m) fraction, reported in XRD percent

Pressure gradients and estimated permeabilities in the Melke formation, based on the method given in the text

Well

6506/12-1 6506/12-1 6506/12-4 6506/12-5 6506/12-5 6506/12-5 6506/12-6 6506/12-6 6506/12-6

Formation

Not Tilje Melke Melke lie Ror Melke Ror Tilje

No. of samples

Illite

21 3 6 17 2 11 17 5 6

88 90 50 47 70 83 51 88 91

Kaolinite

(19) (22) (24) (12) (32) (12) (20) (29) (34)

4 (4) 5 (5) 49 (32) 51 (24) 18 (14) 9 (12) 46 (32) 3 (3) 3 (3)

Chlorite

8 (7) 5 (7) 1 (1) 2 (2) 12 (12) 8 (7) 3 (2) 9 (8) 6 (6)

aAll values are given in XRD percent, without weight factors.

However, the effective (mean) permeability of this interval, assuming that the flux is perpendicular to the bedding, is given by the harmonic mean. The harmonic mean is defined as the reciprocal of the arithmetic mean of the reciprocals of the total number of measured samples, which means that the flow is very much controlled by the least permeable strata in the column. Thus, the effective permeability of the sequence would be close to a point in the column where the permeability is lowest. Analysis of permeability from samples can therefore give too high values due to fractures produced by unloading, and it is also difficult to know if the least permeable layer is sampled. In Table 4 we have also calculated maximum permeabilities for the same set of assumptions as above, but altered the degree of porosity reduction during burial, and thus the calculated fluxes. Fluids can be released from solids by mineral dehydration thus adding fluids to the compaction-driven fluid flux in a sedimentary column undergoing burial. The relative contribution of such diagenetic processes to the compaction-driven flow, can be estimated. Dehydration of smectite may be important (Burst, 1969), but at greater depths illitization of kaolinite may be significant (Eq. (2)). BjCrlykke et al. (1986) and Table 3 Measured permeabilities and porosities from a selection of shales in the Sm~arbukk Field area Well

Depth (m)

Formation

Porosity

Permeability (m 2)

6506/12-4 6506/12-4 6506/12-4 6506/12-6 6506/12-6 6506/12-6 6506/12-6

3972.4 3973.7 3976.6 4184.7 4197.5 4209.5 4227.7

Melke Melke Melke Melke Melke Melke Melke

2.8 2.2 6.7 3.1 1.6 2.8 3.0

7.80E-21 1.05E-18 9.00E-21 4.38E-21 4.60E-20 2.60E-20 1.50E-21

aData are taken from Schl6mer (1995).

Well

Grad P (bar/m)

Flux (m3/m 2 per s)

Permeability (m 2)

6506/12-1 6506/12-5 6506/12-6

0.71 0.81 0.69

6.30E-13 6.30E- 13 6.30E- 13

2.50E-21 2.19E-21 2.57E-21

6506/12-1 a 6506/12-5 a 6506/12-6 a

0.71 0.81 0.69

3.20E-13 3.20E-13 3.20E- 13

1.27E-21 1.11E-21 1.31E-21

6506/12-1 b 6506/12-5 b 6506/12-6b

0.71 0.81 0.69

1.60E- 13 1.60E-13 1.60E- 13

6.35E-22 5.57E-22 6.54E-22

6506/12-1 c 6506/12-5 c 6506/12-6 c

0.71 0.81 0.69

7.90E- 14 7.90E- 14 7.90E- 14

3.14E-22 2.75E-22 3.23E-22

The flux is calculated on 4% reduction in porosity and 1000m interval. aThe flux is calculated on 2% reduction in porosity and 1000 m interval. bThe flux is calculated on 1% reduction in porosity and 250 m interval. CThe flux is calculated on 0.5% reduction in porosity and 250 m interval.

Ehrenberg and Nadeau (1989) concluded that extensive illitization occurs in the Garn Formation mainly through reaction between potassium feldspar and early diagenetically formed kaolinite: K A 1 S i 3 0 8 + A 1 2 S i 2 O s ( O H ) 4 --+ K-Feldspar Kaolinite

KA13Si308(OH)1o + 2SIO2 + H20 Illite

Quartz

(2)

Water

Extensive illitization occurs as the sandstone attains a thermal threshold corresponding to a burial depth of about 3.7-4.0 km (Bjcrlykke et al., 1986; Ehrenberg and Nadeau, 1989; Ehrenberg, 1991). The same depth dependence of the illitization reaction has been reported from the North Sea (BjCrlykke and Aagaard, 1992). This means that illitization can contribute to overpressuring in the shales, also during deep burial. The illite content of the Melke Formation shales is approximately 40% lower than in the Not and Tilje Formation shales (Table 2). From Table 1 we can see that the limiting reactant for the reaction (Eq. (2)) is potassium feldspar. However, the potassium feldspar content at the time of deposition was probably higher, because potassium feldspar dissolves and acts as a potassium source in diagenetic reactions such as precipitation of kaolinite (BjCrlykke, 1983) and conversion of smectite to illite (Hower et al., 1976). This fact is reflected in the Melke Formation shales, where potassium feldspar and

210


Fig. 10. SEM pictures of a Melke Formation siltstone sample (well 6506/12-4; depth 3979.3 mKB). (A) Detrital potassium feldspar undergoing dissolution. (B) Authigenic kaolinite.

kaolinite are detrital and authigenic, respectively (Fig. 10). Below we examine two alternatives; in the first we assume that the potassium feldspar content is 10%, and in the second we assume that the mean content of potassium feldspar is the same as it is today, 5% (Table 1). In the following calculations, all of the available potassium feldspar reacts into illite. This calculation can be summarized by the following equation: MmH20 / PH20 V'H20 / (H.x) VH2~= V' (H. x) = MmKAISi3Os / PKAISiOs KAISi30~

(3)

where V' is the molar volume or the volume taken up by one mole of water and potassium feldspar, which is the molecular mass (Mm; g/mol) divided by density (p; g/cm3). H (m) is the true vertical thickness of the column of rock we are estimating. When estimating the relative contribution from the illitization reaction (Eq. (2)) to the volume of compactional fluids, the H would be the same as the H in Eq. (1) (1250 m). x is the mean content of potassium feldspar in volume percent, which in this case is 10 and 5%, respectively. Given the densities of potassium feldspar (2.6 g/cm3), water (1.0 g/cm3), the molecular

Pore water flow and petroleum migration in the SmCrbukk field area, offshore mid-Norway

masses of potassium feldspar (278.4 g/mol), and water (18.0 g/mol), the total volume of water released during illitization in the above scenarios will be 21 m3/m 2 and 10 m3/m 2 of water, or 2.1 and 1.0% of the rock volume drained, respectively. This is 42 and 20%, respectively, of what comes from compaction alone, given the above assumptions. However, it is not certain that all of the reactants react 100% to form illite. Generation of hydrocarbons in the Spekk Formation source rocks may have contributed to the generation of overpressure, because of the phase change from solid kerogen to fluid petroleum (BjCrlykke, 1997). During expulsion, petroleum displaces water and may contribute to the build-up of pressure in the water phase. Cracking of oil and the formation of gas is also a phase change which will cause increased pressure. The effect of maturation of kerogen is a significant factor at depths below 3.0-4.0 km where the permeabilities of the shales are low and the lateral flow drainage is limited (BjCrlykke, 1997). However, this is not an important factor in our quantitative examples, since the hydrocarbons would migrate upwards and therefore not contribute to the downwards flux over the Melke-Garn Formation border.

Discussion The present day pore pressures, in the Upper Jurassic-Cretaceous sequence, do not reach fracture pressure, estimated from LOT, although 70% of the lithostatic pressure is reached in all the wells at depths below 2200 m. At hydrostatic pressures or at low degrees of overpressure, open fractures are not likely to develop in an actively subsiding basin like the Halten Terrace, because of the increasing confining pressures causing the shales to have mostly ductile behavior (Handin and Hager, 1957) unless highly overpressured (Davis, 1984). Oil migration through shales therefore probably requires high over-pressure and hydro-fracturing to provide sufficient vertical fracture permeability. The top of the overpressure is defined by a steep pressure gradient, coinciding with the smectite rich layers of the Rogaland Group. High sedimentation rates during the Tertiary and Quarternary clearly contributes to the generation of overpressure in the Haltenbanken area. However, mineralogical composition and diagenesis are also important, for two reasons: (1) release of crystal-bound water adds to the pore water flux (i.e., smectite ~ illite, and kaolinite + K-feldspar --~ illite); and (2) minerals with different specific surfaces (i.e., kaolinite versus smectite) have a strong influence on the permeability. Thus, mudstones with similar porosities may have very different

211

permeabilities, depending on their texture and specific surface areas. In the case of smectitic clays, the specific surface may be several hundreds of m2/g, while kaolinite and illite typically have surfaces of about 10 m2/g. The relationship between the permeability and the specific surface of a porous rock is known as the KozenyCarman equation (Rieke and Chilingarian, 1974). The specific surface of mudstones rich in smectite may be more than 10 times that of mudstones containing mostly kaolinite, chlorite and illite. According to the Kozeny-Carman equation, the permeability in the smectite-rich layer (i.e., due to volcanic ash), may be lower by a factor of 10-2 relative to other mudstones, with the same porosity. Dalland et al. (1988) have noted that the smectite content of the Rogaland Group decreases southwards. In this limited dataset, we found that the pressure gradients in the Rogaland Group do also decrease southwards.

Timing of migration relative to subsidence and diagenesis The dry structures in the Halten west area have probably initially been filled with petroleum (Ungerer et al., 1991; Ehrenberg et al., 1992), which later has leaked. Understanding the leakage mechanism and timing of leakage, the main factors causing the dry wells in the Halten West area, is important for evaluating neighboring blocks. In this overpressured region, it is likely that the leakage was due to hydrofracturing of the cap-rock, whereas the normally pressured areas to the east retained petroleum in the traps. The following results give evidence that petroleum migration into the SmCrbukk field started relatively early, perhaps during Late Cretaceous to Early Tertiary times. Organic geochemical data of the C15+ extracts and DST oils shows a wide range of maturities (Karlsen et al., 1995). The gas/oil ratios of Haltenbanken petroleum vary, both laterally between wells and vertically within single wells (Heum et al., 1986; Ehrenberg et al., 1992; Karlsen et al., 1995). Petroleum inclusions in the SmCrbukk field and in the Halten west wells are often found in the first generation of quartz cement close to the grain surface, suggesting oil emplacement prior to extensive quartz cementation (K. Backer-Owe, pers. commun.) and implying that oil filling occurred when the reservoirs were buried to only 2-3 km depth, which is here a typical depth corresponding to onset of significant quartz cementation (BjCrlykke and Egeberg, 1993). The burial curves (i.e., Fig. 2) show that the reservoir where at 2-3 km burial depth, in the Late CretaceousEarly Tertiary, and that the first oil migration started then. This is contrary to earlier interpretation which

212


Fig. 11. Maturity and drainage area map of the Spekk Formation in the Haltenbanken area, as defined by Whitley (1992) and Heum et al. (1986).

suggests that the SmCrbukk field was mainly filled during the last 5 million years (Heum et al., 1986; Forbes et al., 1991; Ungerer et al., 1991; Ehrenberg et al., 1992). In the SmCrbukk South reservoir, on the other hand, the amount of petroleum inclusions is low and formed relatively later than quartz cementation, implying late (Pliocene/Pleistocene) filling of this structure. This is consistent with modelling of the migration into the SmCrbukk South structure from the source-rocks in the local drainage area of this structure (Forbes et al., 1991). The result of the modelling of petroleum migration in the SmCrbukk field will depend very much upon the assumed drainage area for the hydrocarbons (Fig. 11). Geochemical studies suggest an open marine source rock facies for the oils in the SmCrbukk field area (Karlsen et al., 1995). Given the drainage area defined by Heum et al. (1986), modelling studies have shown that the Spekk Formation generates too little petroleum to explain the accumulations in the SmCrbukk and Heidrun fields (Ungerer et al., 1991). The coal-bearing ~re Formation was therefore considered as an additional source rock (Heum et al., 1986; Mo et al., 1989). Previous studies (Heum et al., 1986; Forbes et al., 1991) assumed that the SmCrbukk field did not drain the deeper area to the west and southwest of the SmCrbukk field, which presently is highly overpressured.

Expanding the drainage area to the west and southwest, would not only quantitatively facilitate the Spekk formation as the main source rock, but also support that the SmCrbukk field could be filled much earlier than the last 5 million years. At present, the SmCrbukk field has internal pressure barriers and compartments (Ehrenberg et al., 1992), indicating that hydrocarbons of different compositions and maturities ("ages") are locked into compartments, and that active intra reservoir migration is not presently taking place in parts of the reservoir. The fact that the gas/oil ratio varies vertically (Heum et al., 1986; Ehrenberg et al., 1992; Karlsen et al., 1995) shows that the hydrocarbon column is not in gravitational equilibrium on a large scale, confirming a high degree of compartmentalization. There is no clear evidence of major faults within the SmCrbukk reservoir (Heum et al., 1986), and pressure barriers within the same formation appear not to be structurally controlled (Ehrenberg et al., 1992). It is therefore possible that compartmentalization to a large extent is due to progressive burial diagenesis of sandstones and siltstones, particularly in the Tilje Formation which may have lateral facies variations. If the establishment of the overpressure was only caused by faulting, offsetting the Jurassic sandstones


against shales, along the main fault zone to the west of the SmCrbukk field, there would probably not have been migration of hydrocarbons from the west. However, it is possible that earlier there was a permeable pathway for fluids across the fault zone, before it became progressively sealed by diagenetic processes. The occurrence of overpressure inside parts of the S mCrbukk field suggests that diagenetic seals may act

213

as low-permeable barriers, therefore creating overpressures inside the different compartments on the intra-reservoir scale. If the fluid pathways across the fault zone were partly petroleum saturated, the relative permeability of water would have been reduced, contributing to the build-up of a pressure barrier. Thus, as the lateral drainage to the east was reduced, an overpressure would have been built up in the

EARLY MIGRATION CRETACEOUS / TERTIARY

"DIAGENETIC SEALING" PLIOcENE / PLEISTOCENE Fig. 12. Schematic presentation of the present model suggesting migration from the west and southwest through a major fault at shallow burial depth (Lower Tertiary), which at greater depth became sealed by mineralogical reactions during diagenesis.

214 western areas and hydrofracturing would have led to leakage and reduction of the petroleum column in these paleo-reservoirs. A present day analog to the SmCrbukk field area in Late Cretaceous to Early Tertiary times, could be the Tampen Spur area, where actively migration of oil through faults buried to 2 km depth, takes place today (Horstad et al., 1995). Progressive burial by 2 km would probably alter the present day migration route in the Tampen Spur area. An enlargement of the drainage area and hydrofracturing of the paleo-reservoirs in the Halten West has also been suggested by Ungerer et al. (1991). However, these authors assumed that the fault zone to the west of the SmCrbukk field had been a flow barrier throughout the entire migration phase from the time it was created.

Conclusions Permeabilities in shales have been calculated based on observed pressure gradients and fluid fluxes derived from compaction rates. At constant rates of subsidence the compaction-driven flux would be nearly constant over a limited section, thus the pressure gradients is inversely proportional to the permeability. Assuming a flux of 10-13 m3/m2 per s, an effective permeability of about 1 nD was calculated, based on the observed pressure gradients. This is in good agreement with the permeabilities measured on samples (Schli3mer, 1995). The pressure data from the SmCrbukk field area shows that the top of the overpressure occurs at different depths in the different wells. This suggests that the permeability distribution is mainly controlled by the stratigraphy and mineralogy, and not by the developments of depth controlled pressure seals. The Eocene and Oligocene mudstones have low permeabilities and are poorly compacted, probably due to high amounts of smectite. In much of the Halten Terrace, the Lower and Middle Jurassic reservoir sandstones are normally or close to normally pressured (Fig. 1), which is due to lateral drainage of fluids through Jurassic sandstones, probably up to the surface. This cause an inverted potentiometric gradient and thus a flow into these Jurassic sandstones from the overlying and overpressured Upper Jurassic and Cretaceous mudstones. Subsurface pressures are therefore controlled mainly by lateral drainage through Jurassic sandstones and to a lesser degree by the permeability of the overlying shales and mudstones, making it impossible to model pressure realistically assuming one-dimensional , vertical flow. The lateral drainage system of fluids serves as a kind of valve preventing the build-up of overpressures in the SmCrbukk reservoir, thereby pre-


serves the hydrocarbon column which otherwise could lead to fracturing of the cap rock. However, on the western side of the fault zone, such lateral drainage is strongly reduced and vertical flow is increased, causing an increase in pore pressure. The C15+ fraction of the oils, suggest that the oils are derived mainly from one source rock, the Spekk Formation. Numerous hydrocarbon inclusions in both the SmCrbukk field and in the wells to the west of this field indicate that these structures were filled at a much earlier time than previously suggested (Heum et al., 1986; BjCrlykke and Egeberg, 1993). We suggest that significant migration into the SmCrbukk field started already in Late Cretaceous and Early Tertiary times from the deeper parts of the basin to the west and south. At that time the burial depth was about 2 km shallower than at present. The reservoirs to the west which are presently overpressured would then have been normally pressured and a part of the lateral drainage system observed in the eastern areas today. Progressive burial diagenesis with quartz cementation and illitization, have led to a strong reduction in porosity and permeability during burial and to the present pore pressure distribution with hydrofracturing of the reservoirs in the Halten west area (Fig. 12). Our work suggest that the sealing capacity of faults are not only functions of factors like offset and presence of clay smears, but that it also changes greatly with increasing burial depth. This is because progressive burial diagenesis with stylolites and quartz cementation, overprints the primary tectonic features.

Appendix A Darcy's Law:

~=Q~ dP / dZ

where Q is the flux (m3/m2 per s), d P / d Z is the pressure gradient (bar/m), r/ is the viscosity of the fluid (=28.2 x 10-1~ bar s at 100~ and k is the permeability (m2).

Acknowledgements This research was funded by The Research Council of Norway and Statoil. Statoil is also acknowledged for providing core samples and data. We especially thank E. Vik of Statoil for valuable help and discussions during the progress of this work. Statoil and partners are gratefully acknowledged for giving permission to publish. A. Dale has kindly corrected the English manuscript.


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216 gian Central Graben and applications for exploration. In: J.R. Parker (Editor), Petroleum Geology of Northwest Europe. Proc. 4th Conf. 2. The Geological Society, London, pp. 1295-1303. Leythaeuser, D., Schaefer, R.G. and Yukler, A. 1982. Role of diffusion in primary migration of hydrocarbons. Am. Assoc. Pet. Geol. Bull., 66: 408-429. Meinschein, W.G. 1959. Origin of petroleum. Am. Assoc. Pet. Geol. Bull., 43: 925-943. Mo, E.S., Throndsen, T., Andresen, P., B/ickstrtJm, S.A., Forsberg, A., Haug, S. and T~rudbakken, B. 1989. A dynamic deterministic model of hydrocarbon generation in the Midgard field drainage area offshore mid-Norway. Geol. Rund., 78:305-317. Mudford, B.S., Gradstein, F.M., Katsube, T.J. and Best, M.E. 1991. Modelling 1D compaction driven flow in sedimentary basins: a comparison of the Scotian Shelf, North Sea and Gulf Coast. Geol. Soc. Spec. Publ., 59: 65-85. Rieke, H.H. and Chilingarian, G.V. 1974. Compaction of Argillaceous Sediments. Elsevier, New York. SchlSmer, S. 1995. Mineralogie, Geochemie und Petrophysik toniger Sedimentgesteine fiber Kohlenwasserstoffvorkommen - charakterisierung der Abdichtungseigenschaften unter einbeziehung experimenteller Messungen der Transportparameter. Diploma Thesis, University of Aachen. Sharp, Jr., J. and Domenico, P. 1976. Energy transport in thick sequences of compacting sediment. Geol. Soc. Am. Bull., 87: 390400. Smith, J. 1971. The dynamics of shale compaction and evolution of pore fluid pressures. Math. Geol., 3: 239-263.

R. OLSTAD K. BJORLYKKE D.A. KARLSEN

Str

H.H., Smalley, P.C. and Hanken, N.M. 1993. Prediction of large-scale communication in the Smc~rbukk fields from strontium fingerprinting. In: J.R. Parker (Editor), Petroleum Geology of North West Europe. Proc. 4th Conf. 2. The Geological Society, London, pp. 1421-1432. Thorne, J.A. and Watts, A.B. 1989. Quantitative analysis of North Sea subsidence. Am. Assoc. Pet. Geol. Bull., 73:88-116. Tissot, B.P. and Welte, D.H. 1984. Petroleum Formation and Occurrence. Springer-Verlag, Berlin. Ungerer, P., Bun'us, J., Doligez, B., Ch6net, P.Y. and Bessis, F. 1991. Basin evaluation by integrated two-dimensional modeling of heat transfer, fluid flow, hydrocarbon generation, and migration. Am. Assoc. Pet. Geol. Bull., 74: 309-335. Vik, E., Heum, O.R. and Amaliksen, K.G. 1992. Leakage from deep reservoirs: possible mechanisms and relationship to shallow gas in the Haltenbanken area, mid-Norwegian Shelf. Geol. Soc. Spec. Publ., 59: 273. Walderhaug, O. 1997. Precipitation rates for quartz cement in sandstones determined by fluid-inclusion microthermometry and temperature-history modeling. J. Sedim. Res., in press. Watts, H. 1963. The possible role of adsorbtion and diffusion in the accumulation of crude petroleum deposits, a hypothesis. Geochim. Cosmochim. Acta, 27: 925-928. Whitley, P.K. 1992. The geology of Heidrun. Am. Assoc. Pet. Geol. Memoir, 54: 383-406.

Esso Norway AS, PO Box 60, N-4033 Forus, Norway Department of Geology, University of Oslo, P.O. Box 1047, N-0316 Oslo, Norway Department of Geology, University of Oslo, P.O. Box 1047, N-0316 Oslo, Norway

217

The Njord Field- a dynamic hydrocarbon trap T. Lilleng and R. Gundeso

The Njord Field is located at Haltenbanken 30 km west of the Draugen Field at a water depth of 325 m. The field was discovered in 1985. Plans for the development and operation of the field were submitted to the authorities in Spring 1995 and planned production start-up is Autumn 1997. The expected recoverable oil reserves for the main production phase are estimated to be 32 MS m 3. The field is covered by high quality 3-D seismic and has been delineated by seven wells. Four wells proved to have producible hydrocarbons in marginal marine, heterogenous sandstone reservoirs of Early-Middle Jurassic age (Tilje and Ile Formations). The Njord structure developed during the Late Jurassic by downfaulting and rotation of a large hanging-wall fault block along a major listric shaped fault plane belonging to the Vingleia Fault Complex which separates the FrCya High from the Halten Terrace. The structure is compartmentalized by a complex set of faults. Although no firm fluid contacts have been proven by the wells, a total hydrocarbon column of approximately 400 m is inferred from formation pressure data. The Late Jurassic Spekk Formation represents the major source rock, charging the structure, during Eocene to Recent. Within single reservoir units, formation pressure data indicate lateral stepwise increasing overpressures from approximately 70 bar above hydrostatic in the south-east to approximately 120 bar in the north-west, controlled by major northeast trending sealing faults, which subdivide the Njord structure into a series of hydraulic compartments. There is also a stepwise formation pressure increase with depth, corresponding to Triassic and Jurassic stratigraphic boundaries. The main reason for the observed overpressures is believed to be related to the dramatic increase in subsidence rate of the Njord area during the Pliocene to Recent causing a rapid increase in overburden loading and a renewed pulse of intense fluid charge to the reservoir units. Sealing along the major northeast trending faults has prevented lateral pressure dissipation, and allowed formation pressures to reach the level controlled by the vertical top seal strength of the structure. Residual hydrocarbons within the Triassic and hydrocarbon shows within the Cretaceous overburden support the concept of a dynamic model with an element of active vertical flux through the Jurassic sequences implying breaching of the reservoir top seal and vertical leakage. The relationships between the pore-pressures of the Jurassic reservoirs, the estimated overburden pore pressures and the formation integrity trends of the structure are taken to suggest that capillary entry pressures (membrane seal failure), possibly in combination with cap rock microfracturing, are the main controlling mechanisms for vertical leakage. A proper understanding of the above items, including maturation and filling history, formation pressure distributions, intra-reservoir communications, fault and top seal potentials, and leakage mechanisms, is considered essential for resource assessment, safe drilling of further exploration/delineation and production wells, and for reservoir management and production planning of the Njord Field. L

Introduction The Njord Field is located at Haltenbanken, blocks 6407-7 and 6407-10, approximately 30 km west of the Draugen Field in about 325 m of water (Figs. 1 and 2). The field was discovered in late 1985. Plans for the development and operation of the field were submitted to the authorities in Spring 1995 and production start-up is planned for Autumn 1997. The main reservoir unit is the Lower Jurassic Tilje Formation, which has its shallowest depth at 2700 m MSL and proven oil down to 3098 m MSL (Fig. 3). Recoverable oil reserves are estimated to be 32 MS m 3. The secondary Ile reservoir contains a saturated oil accumulation with a free gas cap. Additional prospective resources are identified to the southeast and northwest. The structure is not filled to its structural spillpoint.

Due to the complex geology of the field, reserve and resource estimates have relatively large uncertainties. The field is covered by high-quality 3-D seismic and has been delineated by seven wells (hereafter referred to as wells 7-1, 7-2, 7-3, 7-4, 7-5, 10-1 and 10-2). A total of 1128 m of core have been recovered. Four wells proved to have producible hydrocarbons within the lie and Tilje formations. A total of 14 production tests have been performed with typical flow rates of 500-700 S m3/day (39-43 ~ API). An extended production test to evaluate intra-reservoir pressure, communication and fluid flow within the Tilje Formation was performed in one of the central area wells (7-2). The Tilje Formation oils are undersaturated with initial solution gas--oil ratios in the order of 220 S m3/S m 3.



218

T. Lilleng and R. Gundesr

Fig. 1. Njord Field location map.

Pressure data Vertical pore-pressure profiles from seabed to TD based on estimated overburden pressures and RFTdata for three "type wells" (representing hydraulic compartment I, II and III, respectively, see discussion below) are presented in Fig. 4, and the total RFT dataset from the Njord wells is illustrated in Fig. 5. Fig. 6 shows a map of the lateral formation pressure distribution of the field. Analysis of the RFT-data combined with detailed sequence stratigraphic studies were performed to obtain representative pore-pressure gradients from top to base of the individual permeable sands. Fig. 7 shows the interpreted pressure gradients for the Jurassic-Triassic sequences within hydraulic compartment I based on RFT data from wells 10-1 and 10-2. Figs. 8 and 10 illustrate the same for hydraulic compartment II (based on wells 7-1, 7-2 and 7-4) and hydraulic compartment III (based on wells 7-3 and 7-5) respectively. Fig. 14 relates the pore-pressure data from all the wells to the minimum fracture pressure gradient of

the field as estimated from leak-off-tests (LOT), and to the lithostatic pressure gradient obtained from integration of density logs.

Stratigraphic setting Triassic (Norian) continental "Red Beds" and the overlying "Grey Beds" represent the oldest penetrated strata of the field. The Lower Jurassic succession starts with the terrestrial to marginal marine Are Formation (Hettangian-Sinemunian) characterized by medium to coarse channel sands separated by shales and coal layers. The top of the Are Formation corresponds to a flooding surface marking the transition to the overlying Tilje Formation (Pliensbachian) which represents the main reservoir of the field. The Tilje Formation is subdivided into Tilje 1, Tilje 2 and Tilje 3 separated by marine mudstones. The reservoirs consist of fandelta and mouthbar sands showing a heterogeneous character. The succeeding marine Ror Formation (mainly Toarcian) consists of silty shales with occasional

The Njord Field: a dynamic hydrocarbon trap

219

Fig. 2. Njord Field structure map (Top Tilje depth).

stringers of fine-grained sandstones, grading into the coastal and flood plain deposits of the overlying Ile Formation (Aalenian-Early Bajocian). The overlying fine-grained offshore sediments of the Not Formation (Early-Late Bajocian) and overlying Melke Formation (Oxfordian) are thin in crestal areas, but thicken towards the south and southeast. Local fault scarp sand wedges were deposited during Oxfordian-Early Portlandian as seen in wells 10-1 and 10-2. Thin upper Jurassic sands are also seen in several of the other Njord wells. The organic rich shales of the Spekk Formation (Kimmeridgian-Ryazanian) represent the main cap and source rock for the field. The formation drapes the entire structure, but is thin (5-10 m) across the crestal areas thickening downflank to above 100 m.

The Lower Cretaceous drape (10-20m thick) across the crestal parts of the structure consists of claystones, thin sandstone stringers and marly limestones, constituting the lower part of the Cromer Knoll Group. The upper part of this unit consists of Cenomanian claystones, and is succeeded by the Shetland Group (Turonian-Campanian) which also mainly consists of silty claystones with stringers of sandstones, dolomites and limestones. The Campanian was followed by a relatively long period of non-deposition. Thus the Maastrichtian is not represented and the Paleocene Rogaland Group claystones directly overlie Campanian strata. The Hordaland Group (Eocene-Oligocene) and Nordland Group (Pliocene-Recent) are separated by the Base Pliocene unconformity which represents a

220


Fig. 3. Cross-section through hydrocarbon bearing wells within hydraulic compartment II.

major stratigraphic brake. Clays and claystones (1000-1100 m) constituting the Nordland Group overlie the unconformity.

Structural setting The main development of the Njord structure occurred during the Late Jurassic by downfaulting and rotation of a large hanging-wall fault block along a major listric shaped fault plane belonging to the Vingleia Fault Complex (VFC), which separates the Njord structure from the FrCya High to the south-east. Major northeast trending faults divide the structure into a downfaulted, folded south-eastern area, a central area and a series of elongated stepwise downfaulted compartments to the northwest. Most faults appear to terminate below the Base Cretaceous unconformity. Based on the structural mapping and the RFT data, the Njord structure may be sub-divided into four hydraulic compartments (Fig. 6): - Hydraulic compartment I covers the south-eastern area and holds an overpressure relative to hydrostatic of approximately 70 bar as observed in wells 10-1 and 10-2 (Figs. 4 and 7);

-

Hydraulic compartment II covers the central area of the structure and holds an overpressure of approximately 90 bar as observed in wells 7-1, 7-2 and 7-4 (Figs. 4 and 8). Hydraulic compartment III is downfaulted to the north of hydraulic compartment II and holds an overpressure of approximately 120 bar as observed in wells 7-3 and 7-5 (Figs. 4 and 10). - Hydraulic compartment IV consists of several subcompartments downfaulted to the north of hydraulic compartment III. Hydraulic compartment IV is defined on the basis of structural mapping only as no wells have been drilled in this area. Small scale listric faults close to and below seismic resolution have been mapped, particularly within the fiat-lying central areas belonging to hydraulic compartment II. These have variable, but dominantly north-south orientation and appear to sole out within the upper Triassic. Several of these faults are also interpreted from VSP data, dipmeter logs and from deformation features in cores. Faults observed at Top Cretaceous level are believed to be related to instability due to disequilibrium or folding strain compaction, and appear not to be "linked up" with the deeper faults.

221

The Njord Field." a dynamic hydrocarbon trap

10-1

7-1 Total

Pore pressure

(thermal}

Gas (%) i

1,1 ~l

1,3 |

i

Gas

(S.G.)

(%)

1 , .~ i

Pore pressure

Total

(thermall

(S.G.)

0,51,0 i

7-3

0,51 |

L

|

1,1

,E

9 i

i

1,3 i

1,

i

i

o ~J

o

-.-.o

~

o o o

.

,3

i

"ct-Q ::=

:=:

Q

==

o r

i

q i

v ==v

t.,,i sl --

(

:=::

:=:

(

9

....

o

::=., c o

::t=

c

:= i, :=:

c

J, ::=:

m

y~-7.z~

c

*---

o. ,,

,1

d

9

II Hydrocarbon bearing reservoir sand

T

o Estimated pore-pressure from sonic logs and D-exponent v Pore-pressure from RFT-data

![

Fig. 4. "Type well" pore-pressure profiles.

Hydrocarbon charge The subsidence history of the Njord structure is reflected by the subsidence curve for the Spekk Formation as illustrated in Fig. 11. The figure also illustrates the calculated hydrocarbon charge through time within the Njord drainage area, showing significant expulsion during the Paleocene-Eocene and in particular during the MidPliocene to Recent (last 3-5 m.a.). Vitrinite reflectance data suggests that the present

day top Spekk Formation oil window starts at approximately 3100 m and top of condensate/gas generation at approximately 4100 m (Fig. 12). Geochemical (biomarker and carbon-isotype) analysis suggest that the Njord oils constitute a relatively homogeneous population mostly derived from a mature source corresponding to Spekk Formation depths of approximately 3800(+) m, suggesting fairly long distance secondary migration for most of the Njord oils, possibly along intra Upper Jurassic unconformities or thin sands. Analysis of migrated oil ex-

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tracts from the dry 10-1 (hydraulic compartment I) well show a biodegraded composition and much lower maturity than oils from the other Njord wells, suggesting lack of migration across the major northeast trending fault separating hydraulic compartments I and II. Oil shows have been reported from the Triassic and in most of the wells from siltstones, limestone and occasional sandstone stringers within the Cretaceous overburden. The oil shows tend to terminate within the upper Shetland Group below the top Cretaceous unconformity probably due to the increased upward counterpressure in the overlying Paleocene strata (Fig. 4). Fig. 4 also includes total (thermal) gas curves for the wells, showing the increased gas levels accompanying the undercompacted Rogaland and Hordaland Group claystones (causing increased amplitudes at the Top Paleocene seismic reflector above the structure), and the Jurassic hydrocarbon bearing sands.

Discussion Causes of overpressure The pore pressure profiles illustrated in Fig. 4 show overpressures within the Rogaland and Hordaland claystones (approx. 1.50 SG). The pore-pressure gradient for this interval is parallel to the lithostatic pressure gradient (Fig. 14, yellow pore-pressure trend line) and is interpreted to have been caused by disequilibrium compaction (Ward, 1994) in response to the extreme Pliocane to Recent subsidence. The lower relative overpressures within the underlying Shetland and the Cromer Knoll Group (approx. 1.30 SG), probably reflects the presence of semipermeable silt and sandstone stringers and more time available for dewatering, pressure dissipation and lateral drainage for these strata prior to the Pliocene to Recent subsidence. The pore-pressure profiles for the wells belonging to hydraulic compartments II and III show a rapid increase versus depth for the lowermost CretaceousUpper Jurassic interval (Figs. 4 and 14; red trend line). This pressure increase versus depth is higher than lithostatic, and is taken to suggest that the primary cause of overpressure for this interval is related to the pulse of increased maturation and pressure build-up within the Spekk Formation source rock caused by increased maturation and kerogen transformation to liquid hydrocarbons, again primarily in response to the Pliocene to Recent subsidence.

223

The pore-pressure profiles further show that pressure equalization has been reached between the Jurassic reservoirs and the lowermost Cretaceous-Upper Jurassic caprock of the Njord structure as there is no drop in pressure when entering into the Jurassic reservoir units (as seen in many other fields on Haltenbanken; Koch and Heum, 1995). Lateral pressure distribution The observed pattern of lateral pressure distribution between the defined hydraulic compartments reflects lack of pressure communication across the major northeast trending faults separating the compartments. There might, however, be pressure communication within the lie Formation between hydraulic compartments I and II either due to cross-fault Ile/Ile communication, or due to communication downflank in the water zone at around 3900 m MSL around the tip of the fault separating these two compartments. For the Tilje Formation, however, there is no indication of pressure communication between hydraulic compartments I and II, i.e., no cross-fault communication and no downflank communication (possibly due to sub-seismic reservoir discontinuities and deteriorated reservoir quality). The fact that the Tilje Formation is offset along most of the main northeast trending faults probably explains their sealing properties. However, also at Tilje/Tilje juxtapositions and (frequently) Tilje/Ile juxtapositions, these faults seem to be sealing, suggesting the fault plane itself to be able to hold significant differential pressures (30(+) bar). Further calibrations with respect to cross fault communication within hydraulic compartment II was obtained by re-entering well 7-2 2 years after the initial production test to assess formation pressure recovery relative to the initial drawdown and to perform further testing. The data acquired gave indications of partial pressure communication across intensity zones and small scale (10-20 m throw) faults in the vicinity of the well. The very small differences in formation pressures (approximately 1.3 bar) and bubble point pressures (normalized to a common reference depth) between well 7-2 and wells 7-1 and 7-4 also suggest only partial sealing along the north-south fault east of well 72. The apparent higher sealing efficiency of the north-east trending faults relative to the north-south faults might be related to the horizontal stress field distribution of the structure as mapped from well-bore

Fig. 5. Njord Field RFT dataset. Fig. 6. Interpreted lateral pressure distribution and hydraulic compartments.

224

T. Lilleng and R. GundesO

Fig. 7. Interpreted formation pressure gradients, hydraulic compartment I. Fig. 8. Interpreted formation pressure gradients, hydraulic compartment I1


225

Fig. 9. Interpreted formation pressure gradients of pseudo-well downflank hydraulic compartment I1 Fig. 10. Interpreted formation pressure gradients, hydraulic compartment 111.

226


Fig. 11. Subsidence history of the Njord structure illustrated by the Spekk Formation subsidence curve of well 7-2.

break-out (ovality) studies based on four arm caliper data from the dipmeter logs, which show an east-west dominant minimum horizontal stress direction for the lower-middle Jurassic sequence within the central area of hydraulic compartment II.

Vertical pressure distribution The vertical pressure distributions as interpreted from the RFT-data are illustrated in Figs. 7-10, and are further discussed below. All penetrated reservoir units within hydraulic compartment I (Fig. 7) are water-bearing. There is a pressure drop between the Ile and Tilje Formation and apparently good pressure communication between the Tilje Formation and the underlying separate sands of the ,~re Formation (direct vertical pressure control from the top of the Tilje Formation in well 10-1 to TD in well 10-2 totals 854 m). Within hydraulic compartment II (Fig. 8) all wells contain hydrocarbons in the Ile and Tilje Formation and show a pressure increase from Ile to Tilje of approximately 16 bar. As mentioned above there is a slight pressure increase within the Tilje oil column (approx. 1.3 bar) between well 7-2 and wells 7-1 and

Fig. 12. Present day Spekk Formation maturity distribution within the drainage area of the Njord structure.

7-4. Otherwise the drilled oil columns in these wells "line up" (totalling 348 m). Well 7-4 encountered water within the lower part of the Tilje Formation. However, movable oil was encountered below the water within underlying Are Formation sands. The RFT data from the individual sands below the Tilje Formation within hydraulic compartment II show an apparent random scatter. However, when seen in relation to their structural positions and tied in detail to the-stratigraphy in each well, a consistent stepwise increasing pressure trend through the Lower Jurassic-Triassic stratigraphic sequence becomes apparent. This is illustrated in Fig. 9, which shows the proposed p0re-pressures for an imaginary "pseudowell" downflank of well 7-4 (assuming penetration of top Tilje Formation at 3050 m MSL). The RFT dataset within hydraulic compartment HI (Fig. 10) is less abundant than for hydraulic compartment II, but show the same main trends, i.e., a

Fig. 13. Pore-pressure for the Ile- and Tilje formations extrapolated to the apexes of the defined hydraulic compartments. The red trend-line passing through the aquifer pore-pressure points at the apexes of hydraulic compartment II and III represents the "maximum reservoir pore-pressure" trendline. At points along this line pressure equalization is reached between the reservoir units and the counter-pressure of the overlying cap rock. Fig. 14. Relationships between pore-pressures, the hydrostatic gradient, the fracture pressure gradient (approximation to the minimal horizontal stress, Sh) and the lithostatic pressure gradient (approximation to the vertical stress, Sv). Pore-pressures from sea floor to base Pliocene equals hydrostatic. The yellow, dark blue and red pore-pressure trend-lines represent the pore-pressure versus depth gradients for the Paleocene-Eocene, Mid-late Cretaceous and Upper Jurassic-lowermost Cretaceous, respectively. The portion of the red trend-line below approximately 2550 m MSL equals the "maximum reservoir pore-pressure" trend-line of Fig. 13 and reflects the counter-pressure of the topseal controlling the p6re-pressure distribution of hydraulic compartments II, III and (probably) IV.


227

228

pressure increase from Ile to Tilje and a stepwise increase in pressure when penetrating downward through the Lower Jurassic-Triassic sand/shale sequences. This systematic pressure distribution may be explained by assuming a general upwards fluid flux through the Triassic-Jurassic sequences towards the crestal areas of the Njord structure. As discussed above, the wells within hydraulic compartment I (wells 10-1 and 10-2) show a formation pressure decrease between the Ile and the Tilje Formation (i.e., opposite to what we observe in hydraulic compartment II and III) and a common water pressure gradient for the Tilje Formation and the underlying individual Are Formation sands. The systematic upward pressure release discussed for hydraulic compartments II and III thus does not pertain to hydraulic compartment I, further substantiating that the north-east trending fault separating hydraulic compartments I and II is acting as an efficient seal (with possible exception for Ile/Ile communication), thus allowing different mechanisms to control the vertical pressure distribution within each compartment.

Vertical leakage mechanism The apparent pressure equalization between the Jurassic reservoirs and the lowermost Cretaceous-Upper Jurassic cap rock, and the vertical distribution of oil and gas shows (Fig. 4) provides clear indications of vertical leakage from the Njord structure. This is further supported by the indications of vertical fluid flux upwards through the Triassic-Jurassic sequences as discussed above. The interplay between reservoir and cap rock porepressures and vertical leakage mechanisms for the field has been further assessed by analysing the reservoir pore-pressure situation at the apex (i.e., the "weak point") of each hydraulic compartment (Fig. 13), and by relating the apex reservoir pore-pressures to the corresponding minimum fracture pressures of the cap rock (Fig. 14). The fact that the Spekk Formation represents both the main source rock and cap rock for the Njord Field is a key aspect in these considerations. In Fig. 13 the aquifer pore-pressure gradients for the lie and Tilje reservoir units have been extrapolated to their respective apexes within each hydraulic compartment. A common pore-pressure versus depth gradient can be drawn through the apex pressures of hydraulic compartments II and III, and is referred to as the "maximum reservoir pore-pressure" trend-line. The Tilje Formation apex pressure of hydraulic compartment I plots slightly below the said gradient.


The fact that the aquifer pore-pressure for the lie and Tilje reservoirs at the apex of hydraulic compartments II and III fall along-.a common porepressure versus depth trend line suggests that a common depth-related mechanism controls the maximum aquifer pressure within these compartments. This controlling mechanism is believed to be the counterpressure of the Spekk Formation (increasing versus depth due to gradually increasing maturity). GaarenstrCm et al. (1993) suggest that the risk of breaching of a seal increases when the retention capacity is less than 1000 psi (71 bar). As seen from Fig. 14 the maximum reservoir porepressure at the apex of hydraulic compartments II and III lie in the order of 100 bar below the minimum fracture gradient. This pressure difference (i.e., effective horizontal stress or retention capacity, R~) decreases with depth and goes below 70 bar at approximately 3500 m. Hydraulic compartments II and III and the two next downfaulted sub-compartments to the northwest belonging to hydraulic compartment IV have apexes above 3500. Based on the above and assuming that vertical leakage actually does occur, "membrane leakage" (Watts, 1987) is suggested as the dominating vertical leakage mechanism for these compartments, possibly "helped" by microfracturing (dilatency) within the Spekk Formation (which at this depth is at the early oil generation stage). For apexes below 3500 m, i.e., the deepest subcompartments of the north flank, there is an increased possibility of actual breaching (vertical fracturing) of the Spekk Formation cap rock. This could cause direct coupling between the Jurassic reservoirs (overpressured to the extent controlled by the Spekk Formation prior to breaching) and the overlying less overpressured Lower Cretaceous semi-permeable silty (occasionally sandy) claystones. Once attained, this situation might be expected to cause relatively dramatic pulses of vertical leakage (e.g., Mandl and Harkness, 1987). From Fig. 13 the following differences between the formation water (wetting phase) pressures and the hydrocarbon phase pressures at the apexes of hydraulic compartments II and III and corresponding hydrocarbon column highs can be observed: These differences in Aphc_wate r illustrate to what extent the hydrocarbon phase pressure at the weak point/apex of each reservoir reaches above the "maximum reservoir pore-pressure" trend-line, along which, according to the discussion above, pressure equalization (for the wetting phase) has been reached between the reservoir and cap rock. Aphc_wate r consists of a fluid flux (Darcy) component and a non-wetting phase capillary entry-pressure


component, and reflects the present resistance against hydrocarbon leakage through the top seal. Independent entry-pressure measurements of six top-seal core-plug samples gave comparable Ap values. The mechanisms and observations discussed above may indicate that the Njord reservoirs, particularly the Tilje and Ile reservoirs in hydraulic compartment II and the Tilje reservoir in hydraulic compartment III at present hold close to their maximum hydrocarbon columns, which further implies active present day recharging of these reservoirs compensating for the vertical leakage.

Summary and conclusions An extensive database has been available for evaluation of the dynamic aspects of the Njord Field. The data suggest lateral sealing along the major northeast faults of the structure. Smaller faults within the central area of the field with dominantly northsouth orientation represent semipermeable faults. Vertical pore-pressure distributions, hydrocarbon shows and relationships between reservoir and cap rock pressures indicate present day vertical "membrane-dominated" hydrocarbon leakage from the "bald" central area of the structure where the Spekk Formation (cap and source rock) is thin and immature and is overlain by Cretaceous silty and occasionally sandy claystones with limited seal capacity. There is an increasing probability of "hydraulic fracturing" leakage for the deep downfaulted compartments of the north flank. Active re-charging of

T. LILLENG Norsk Hydro Produksjon a.s., N-5020 Bergen, Norway R. GUNDESO Norsk Hydro Produksjon a.s., N-5020 Bergen, Norway

229

the structure is indicated from the present day extensive hydrocarbon columns and supported by indications of strong present day downflank oil and gas/condensate generation from the Spekk Formation with focused charge towards the structure, thus making the Njord Field a true dynamic hydrocarbon trap.

Acknowledgements The authors are grateful to a number of colleagues within Norsk Hydro a.s for fruitful discussions and comments and to the Njord partners for allowing publication of the paper. It is emphasized that the opinions expressed herein are those of the authors only and not necessarily shared by Norsk Hydro a.s. as Operator or by the Njord licence partners.

References Gaarenstr0m, L., Tromp, R.A.J., de Jong, M.C. and Brandenburg, A.M. 1993. Overpressures in the Central North Sea: implications for trap integrity and drilling safety. In: Petroleum Geology of Northwest Europe: Proc. 4th Conf., pp. 1305-1313. Koch, J.-O. and Heum, O.R. 1995. Exploration trends of the Halten Terrace. NPF Special Publication 4, pp. 235-251. Mandl, G. and Harkness, R.M. 1987. Hydrocarbon migration by hydraulic fracturing. In: Deformation of Sediments and Sedimentary Rocks, Special Publication 29. Geologic Society, pp. 39-53. Ward, C.D. 1994. The Application of Petrophysical Data to Improve Pore and Fracture Pressure Determination in North Sea Central Graben HPHT Wells, SPE 28297, pp. 53-68. Watts, N.L. 1987. Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns. Mar. Pet. Geol., 4: 274-307.


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Pre-cretaceous top-seal integrity in the greater Ekofisk area D.M. Hall, B.A. Duff, M. Elias and S.R. Gytri

Evaluation of pre-Cretaceous prospectivity in the Greater Ekofisk Area (GEA), based on the interpretation of multiple 3-D seismic surveys, semi-regional geological studies and analysis of over 60 wells, suggests that tectonic breaching is the dominant process responsible for top-seal failure. The likelihood of tectonic breaching is related to closure style, being highest for structural inversions, and lowest for footwall fault blocks. The magnitude of tectonic breaching depends upon the extent of wrench faulting, youngest age of deformation, and stratigraphic position of reservoir levels with respect to the neutral surface of inversion folds. Variation in aquifer overpressure can also be related to regional pressure domains and depth of the reservoir, enabling prediction of maximum hydrocarbon columns. In structures where crestal reservoir pressures coincide with leak-off test fracture pressures, it is commonly assumed that the extent of hydrocarbon columns has been regulated by hydraulic breaching. However, within the GEA, there is no evidence that significant volumes of formerly trapped hydrocarbons have been released by this process. An alternative explanation, referred to as pressure-inhibited charge, is that in some cases downward migration from overpressured, organic-rich top seals ceases at the point where pressure equilibrium is reached with the underlying reservoir. As a result, the height of the hydrocarbon column remains constant without inducing hydraulic breaching. Capillary leakage does not appear to be a significant process at pre-Cretaceous levels within the GEA. A possible exception concerns leakage during relatively shallow depths of burial from reservoirs which sub-crop the Chalk Group. Spatial variations in seal effectiveness can be summarised in terms of a top-seal chance domain map.

Introduction The Greater Ekofisk Area (GEA) forms the southeast part of the UK/Norwegian Central Graben, an extremely complex tectonic WNW trending entity which links the NNE-trending Viking Graben and Outer Moray Firth Graben to the west, with the NNEtrending Danish-Dutch arm of the Central Graben. Within the GEA, the intersection of the NNE and NW to WNW fault trends has resulted in a mosaic of stratotectonic domains, each of which has a unique subsidence history (Fig. 1). The GEA is well known as a major hydrocarbon province owing to the substantial oil and gascondensate discoveries that have been made within the Lowermost Tertiary to Upper Cretaceous Chalk Group. In contrast, exploration results for deeper, high-temperature, high-pressure pre-Cretaceous objectives have been relatively disappointing despite the proximity of prolific Lowermost Cretaceous to Upper Jurassic (early Ryazanian to Kimmeridgian) source rocks and the presence of porous Jurassic reservoirs at depths greater than 4500 m. As a consequence, attention is focused on the effectiveness of the topseals as a cause of exploration failure. These are provided by Lowermost Cretaceous to Upper Jurassic organic-rich claystones, which act as both source and seal, as well as Lower Cretaceous marls and Upper Cretaceous chalk lithologies. Seals mostly fail either by capillary leakage through interconnected pores, or the formation of fractures. The theoretical relationships between these

processes are already well understood (e.g., Berg, 1975; Downey, 1984; Watts, 1987; Clayton and Hay, 1994). However, it remains the task of the explorationist to assess the relative significance that these

Fig. 1. Producing fields and stratotectonic domains within the GEA. The intersection of NNE and NW to WNW fault trends is mostly responsible for the segmentation of the area into stratotectonic domains.



232

Fig. 2. GEA database and location of successful and unsuccessful preCretaceous exploration wells. Successful wells are mostly located near the margins of the deep graben area. Fields are shown by a single well symbol.

D.M. Hall, B.A. Duff, M. Elias and S.R. Gytri

processes have in specific geological situations because without this understanding realistic estimates of the risk of seal failure cannot be made. A previous assessment of pre-Cretaceous seals within the Central North Sea has been made by Gaarenstroom et al. (1993) who emphasise the retention aspects of reservoir overpressure and the implications for trap integrity. Our evaluation of pre-Cretaceous seal integrity is based on the interpretation of a substantial GEA database including over 60 exploration wells, regional seismic lines and a significant amount of the area's blanket 3-D seismic coverage (Fig. 2). We highlight the seal effectiveness of the two most common pre-Cretaceous closure types within the GEA: footwall fault blocks resulting from tectonic extension and inversion structures resulting from compression or transpression. Both closure types include basement-detached and basement-coupled varieties (Fig. 3). We assess the relative importance of capillary leakage and fracture-related seal failure for both of these closure types. We distinguish between fractures caused by tectonic deformation, and hydraulic fractures induced by both cap-rock overpressure and reservoir overpressure. We also suggest an alternative process controlling retention capacity which we term pressure-inhibited charge. Differences in aquifer overpressure are related to regional pressure domains and burial depth, thus providing a

Fig. 3. Footwall fault block and inversion closure styles. Both basement-coupled and basement-detached varieties are present within the GEA. Inversions may also be transpressional or compressional in origin.

Pre-cretaceous top-seal integrity in the greater Ekofisk area

233

greatest number of failures are associated with inversion structures, especially in cases where structural growth has continued until, or after, the midOligocene orogeny. In contrast, none of l~he assessed footwall fault blocks have been involved in these younger deformation events. It is reasonable to assume that ineffective seals are the cause of exploration failure where porous waterwet reservoirs occur in clearly defined closures, and where the reservoirs are also in direct contact with mature, organic-rich source rocks. We refer to these as "proven" seal failures. Accordingly, seal failure can be proven in only seven cases, all of which are associated with young inversions. One reason for this is that most exploration wells have not been drilled deep enough to prove or disprove the presence of sealed reservoirs underlying the thick Upper Jurassic claystones that occur in many inversion structures. The implication of this analysis is that drilling success ratios provide valuable insight into possible causes of failure but, within the GEA at least, do not yield a unique criterion for assigning levels of seal

a) Footwall Fault Blocks

Fig. 4. Comparison of undifferentiated pre-Cretaceous exploration successes and failures.

method by which the retention capacity of individual prospects can be estimated. Spatial variation in the effectiveness of top-seals is summarised in the form of a top-seal chance domain map. Before addressing these issues, we commence with an analysis of preCretaceous drilling results and assess their relevance to the estimation of the risk of seal failure.

b) Inversions

Pre-cretaceous drilling success ratios The undifferentiated GEA pre-Cretaceous drilling success ratio, where success is defined by proven movable hydrocarbons, is about 20% (Fig. 4). However, of these success cases only five have resulted in commercial production. These are Ula and Cod (both inversions), Embla and Mjr (both footwall fault blocks) and Gyda (combination trap). Successful wells are mostly located on the terrace areas flanking the main graben depocentres, particularly to the northeast and to the south (Fig. 2). Drilling results for the footwall fault block and inversion closure types (excluding hybrid closures such as the Gyda Field), segregated by youngest age of deformation, are shown in Fig. 5. These results clearly indicate that the

Fig. 5. Analysis of pre-Cretaceous drilling results for (a) footwall fault blocks and (b) inversions. The greatest number of failures are associated with inversion structures where deformation has continued until, or after, the mid-Oligocene unconformity.

D.M. Hall B.A. Duff, M. Elias and S.R. Gytri

234

risk. A more reliable basis for risk estimation requires an assessment of the relative significance of the processes controlling seal effectiveness.

Capillary leakage The capillary pressure equation (Berg, 1975) predicts that capillary leakage will occur when the upward pressure of the hydrocarbon column is greater than the capillary resistance of the seal. The magnitude of upward reservoir pressure is determined by hydrocarbon buoyancy pressure plus any overpressure in the reservoir relative to the seal. The capillary resistance of the seal is determined by the size of interconnected pore throats and the interfacial tension between hydrocarbon (gas or oil) and formation water. The relationship between these factors can be expressed as follows if the angle of contact of the hydrocabon-water interface is assumed to be 0 ~ (Clayton and Hay, 1994): Th =

2~,h _ AP r(pw - Ph)g (Pw -- Ph)g

(1)

where Th is the thickness of the hydrocarbon column, )'h is the hydrocarbon interfacial tension, r is the pore throat radius of the sealing lithology, Pw is the density of formation water, Ph is the density of the trapped hydrocarbon, g is the acceleration due to gravity and AP is the overpressure in reservoir relative to the seal. The first part of the right-hand side of the equation gives the column height which can be expected under normal hydrostatic conditions, and the second part gives a correction for excess reservoir overpressure. Using this relationship, Clayton and Hay (1994) demonstrate that pore throat radius is the single most important variable in determining capillary retention capacity. In the case of a dry gas column they predict that the retention capacity of a mudstone seal lies within the range of 900-1000 m. This is compatible with our own prediction that Upper Jurassic and Lower Cretaceous top-seals within the deeper parts of the GEA will retain wet gas columns of at least 800 m before capillary leakage occurs. In contrast, the retention capacity of siltstone lithologies, where pore throat size can be over two orders of magnitude larger than claystones, may be as low as 10 m. This may be particularly relevant during the first 3000 m of burial where pre-Cretaceous reservoirs sub-crop the Chalk Group (Fig. 6). This is because chalk lithologies are associated with high primary porosities (SCrensen et al., 1986) and, therefore, large porethroat sizes. Capillary leakage causing fluid flow along fault planes, as opposed to leakage caused by tectonically induced dilation of faults, is also possible

Fig. 6. Schematic illustration of capillary leakage from GEA traps. This mostly occurs at shallow and intermediate burial depths both via fault planes and through Chalk Group cap-rocks.

although the relative importance of this is difficult to assess within the GEA. The typical GEA pore-pressure profile shown in Fig. 7, demonstrates significant and stepped increases in pore-pressure below 4000 m. This is consistent with the presence of pressure seals, a term which describes seals in which pore throat diameters have effectively become closed (Hunt, 1990; Bradley and Powley, 1995). According to Deming (1994), the weakness of this definition of pressure seals is that zero permeability rocks are unlikely. However, despite this limitation, the concept is useful when evaluating the integrity of seals in that it identifies seals in which the rate of pressure leakage is insignificant over the time-scale of the trap. It follows that the failure of these seals can only occur by fracturing of the cap-rock (hydraulic seals of Watts, 1987). In addition to highly overpressured Lowermost Cretaceous to Upper Jurassic organic-rich claystones, Lower Cretaceous marls and the basal section of the Chalk Group can also form part of a pressure sealing interval if they are buffed deeply enough. The concept of regional pressure cells within the GEA based on the existence of barriers caused by sealing faults has also been well established (Leonard, 1993). The implication, within GEA pressure cells, is that top-seal failure at burial depths greater than 3500--4000 m is likely to be determined by fracturing rather than capillary leakage.

Fracturing According to the Terzaghi principle, the effect of pore fluid pressure (P) and total stress (S) on tensile failure can be described by the Terzaghi effective stress tr (Hubbert and Rubey, 1959), given by


a = S- P

(2)

Subsurface tension fractures will form when the minimum effective stress (ty3) reduces to the tensile strength of the rock (-Ct). This will occur when the minimum total stress ($3) is reduced by tectonic dilation, or pore fluid pressure is increased (Watts, 1987). These failure conditions can be summarised as follows: S3S3+C

t

(3)

In most extensional basins it can be assumed that minimum total stress is horizontal, and maximum total stress (S1) is equivalent to vertical lithostatic load. From Eq. (3) it can also be predicted that minimum total stress plus tensile rock strength is equivalent to the maximum formation fracture pressures that are measured from leak-off tests performed after drilling out casing shoes (LOT), or more approximately from formation interval tests (FIT). As suggested by Gaarenstroom et al. (1993), the lower bound envelope of LOT values may correspond to the

235

re-opening of previously formed fractures with zero, or very low, tensile rock strength. Although seal failure caused by fracturing results from the interplay of pore-pressure and tectonic deformation, it is useful from the point of view of risk analysis to consider them separately as tectonic breaching (caused by tectonically-induced dilation), and hydraulic breaching (caused by increase in porepressure).

Tectonic breaching Tectonic breaching within the GEA is mostly related to Cretaceous to Tertiary compressional or transpressional deformation and is manifested by two processes. Firstly, extension occurs above the neutral surface of inversion folds (Fig. 8a), thereby creating a pattern of radial tension fractures, extending upwards from the seal into the overlying section. Radial fractures will not form below the neutral surface of the fold limb which is in compression. As a consequence, reservoir objectives lying above or close to the neu-

Fig. 7. The typical pore-pressure profile of a well drilled within the GEA. Stepped increases in pore-pressure are recorded within the basal Chalk Group and underlying section. The maximum increase in pore-pressure coincides with Lowermost Cretaceous to Upper Jurassic organic-rich claystones where it approaches minimum values of LOT/FIT fracture pressure.

236

D.M. Hail B.A. Duff, M. Elias and S.R. Gytri

Fig. 8. Schematic illustration of tectonic breaching for (a) structural inversions and (b) footwall fault blocks. Tectonic breaching within inversions is caused by radial fractures and wrench faults. It is also possible that tectonic breaching may be caused by the re-activation of normal faults.

tral surface of the inversion folds have a higher chance of being breached than reservoirs lying below the neutral surface. Maximum dilation of the radial fractures will coincide with the acme of the inversion. Secondly, regional interpretation of fault styles indicates that wrench faults occurring within discrete linear trends usually affect all levels within the inversion fold thereby creating pervasive pathways for upward migration. Within the GEA, recurrent transpressional inversions along pre-existing NW to NNE basement grains occurred throughout the Cretaceous to Tertiary. Chance of tectonic breaching appears to be most closely related with the Laramide (end Paleocene) and mid-late Alpine (mid-Oligocene) deformations, probably because they coincide respectively with the beginning and end of peak hydrocarbon generation. Although available data indicate that footwall fault blocks are mostly unaffected by these deformations, breaching caused by extensional or transtensional reactivation of normal faults cannot be completely discounted (Fig. 8b). Within the GEA, regional interpretation of fault histories indicates that fault movement during the Cretaceous to Tertiary probably became progressively more localised as successive fault systems "locked up". The chance of tectonic breaching is therefore spatially determined and critically dependent upon the age of charge into the reservoir and youngest age of deformation. Available data indicates that the chance of tectonic breaching is highest along the trend of Laramide transpression, coincident with the Lindesnes Ridge and northwest margin of the Utstein High (Fig. 1). To date, all of the Jurassic reservoirs penetrated by exploration wells located within this trend have been water-wet. Tectonic breaching is suggested as the main cause of failure by the presence of wrench faults linking pre-Cretaceous levels with

the Cretaceous and Tertiary overburden. Differences in strain rate may have resulted in variations in seal effectiveness between individual fault segments, although insufficient data exists to confirm this. Cored Upper Jurassic claystones from a well located within the Lindesnes trend display both dilational and shear fractures (Fig. 9). Although both shear and dilational fractures can be produced by hydraulic fracturing (Lockner and Byerlee, 1977), the location of this well within a major wrench zone suggests tectonic breaching as the most likely cause.

Hydraulic fracturing Hydraulic breaching occurs when pore fluid pressure exceeds the total minimum confining stress and the tensile strength of the rock (Eq. (3)). In order to understand how this process works, the difference between pore-pressure build-up within the cap-rocks and underlying reservoir needs to be clarified. Cap-rock overpressure mainly occurs due to incomplete dewatering caused by rapid burial, generation of hydrocarbons, and in some cases tectonic stress. The typical pore-pressure profile shown in Fig. 7 demonstrates that pore-pressures within Lowermost Cretaceous to Upper Jurassic claystones reach a maximum of 90% of lithostatic load and also approach the lowest fracture pressures measured from leak-off tests and formation integrity tests. Indeed in other GEA wells, pore-pressures exceed these minimum fracture pressures. Despite this, the suggestion that in situ pore-pressures alone can cause natural hydraulic fractures has been disputed by Gretener (1981) and Lorentz et al. (1991), who argue that uniform porepressures do not allow pressure gradients between pores and fractures of sufficient magnitude to open fractures. An alternative mechanism for fracture


'.

~

'

:~

~. ::.~, K ( S 1 - Pseal) + Pseal + Ct

Fig. 11. Plot of fracture pressure gradients versus depth. Fracture pressure gradients approach the lithostatic gradient with increasing depth and the two trends more-or-less coincide below 5000 m.

draulically induced fractures can be derived by considering the relationship between vertical (maximum) effective stress (al) and horizontal (minimum) effective stress (or3). Eq. (2) shows that vertical effective stress is equivalent to total vertical (or lithostatic) stress ($1) minus the pore fluid pressure (P): o'1 = S1 - P

(4)

A similar relationship can be written for horizontal effective stress (cr3): or3 = s3 - / '

(5)

If K is the ratio of horizontal to vertical effective stress, then o'3 = Kal

(6)

Combining Eqs. (4), (5) and (6) gives $3 = K(S1 - eseal) -I- Pseal

(7)

As indicated by Eq. (3), in order to breach the seal, underlying reservoir pore fluid pressure (Pr~servoir) must exceed the horizontal total stress ($3) plus the rock strength of the seal (Ct). By combining Eqs. (3) and (7), it can be shown that the condition required for seal breaching by underlying reservoir pressure is as follows:

(8)

As for capillary leakage, reservoir pressures are controlled by the buoyancy pressure of the hydrocarbon column, plus reservoir overpressure which in turn is mostly controlled by the aquifer pressure gradient. Within the GEA, direct measurement of aquifer gradient from repeat formation tester (RFT) measurements was possible in only four cases, all of which indicated a salt-saturated or near salt-saturated formation gradient of 0.5 ~psi/ft (Fig. 12). These sparse data were supplemented by estimated aquifer pressures obtained by: (i) by extrapolation of measured hydrocarbon gradients down to an assumed hydrocarbon contact and (ii) from drilling pore-pressure gradients over intervals where logs indicate porous, water-bearing reservoirs. Although less reliable than the results obtained by direct measurement, estimated pressures provide a useful indication of the full variation in aquifer overpressure within the GEA. The results show that aquifer pressure gradients can be divided into two regional domains: those located within terrace areas and those located within the deeper graben. Within both domains, the overpressure of individual pressure gradients increases with increasing depth. Individual aquifer trends for the terrace areas are similar and modestly overpressured with respect to surface hydrostatic conditions (ca. 0.6 psi/ft with respect to surface). Aquifer trends within the deep graben domain are more variable and more highly overpressured (up to 0.9 psi/ft with respect to surface). The hiatus in aquifer pressure between the terrace and graben domains suggests the presence of regional lateral pressure barriers (Fig. 13). The tectonic complexity of the GEA suggests that it is likely that these regional domains will be separated into a number of secondary pressure cells, although further data are required to confirm this. The relationship between closure type and aquifer overpressure is also unclear. The retention capacity of individual closures, according to the conditions necessary for hydraulic seal failure, can be predicted from Fig. 12 by the following simple method. (i) Select the aquifer trend most relevant to the particular prospect (based on depth and location). (ii) Extrapolate a hydrocarbon fluid gradient upwards from the closure elevation. There is a risk of hydraulic failure if the fluid gradient intersects with the crestal elevation within the fracture envelope. Crestal pressures of GEA pre-Cretaceous hydrocarbon accumulations are also plotted. Most of these points lie within the envelope of LOT/FIT fracture pressures, apparently suggesting that hydrocarbons have been released as a result of hydraulic failure of


the top-seal. However, these results represent present day conditions, which will differ from conditions during earlier stages of burial. In particular, hydraulically induced seal failure can only occur if reservoir pressure exceeds cap-rock pore pressure (Eq. (8)). Within the GEA, pressure data suggest this condition is more likely during relatively late stages of burial. There are two reasons for this. Firstly, reservoir pressure increases as buoyancy of hydrocarbon columns increase by the generation and entrapment of gas, and also by depth-related increases in aquifer pressure. Secondly, cap-rock overpressures are likely to be depleted following peak hydrocarbon generation. This model of late-stage hydraulic breaching is also in agreement with the conclusions of Gaarenstroom et al. (1993).

Pressure-inhibited hydrocarbon charge Notwithstanding the correspondence of certain crestal reservoir pressure results to the regional frac-

239

ture gradient (Fig. 12), there is no clear evidence within the GEA of widespread leakage of preCretaceous trapped hydrocarbons as the result of hydraulic breaching. Interpretation of the extensive 3-D seismic coverage suggests that all the major gas plumes originate from Chalk reservoirs rather than pre-Cretaceous reservoirs. Furthermore, seismic evidence for recent leakage of pre-Cretaceous hydrocarbons along fault planes can usually be related to the presence of clearly defined wrench faults rather than hydraulic fractures. Oil shows above pre-Cretaceous traps, which are unaffected by wrench faulting, can be explained by capillary leakage through overlying chalk before porosity reduction within the chalk created pressure seals. An alternative explanation, which we refer to as pressure-inhibited charge, is that downward hydrocarbon migration from sealing source rocks ceases as the pressure of the underlying stratigraphically contiguous reservoir approaches the pore-pressure of the seal. This process is consistent with capillary theory,

Fig. 12. GEA pressure/depth plot showing the relationship between aquifer overpressure, fracture pressures, crestal reservoir pressures and closure style. Aquifer pressures are grouped into a terrace domain and a deep graben domain.

240

D.M. Hail B.A. Duff, M. Elias and S.R. Gytri

risk of hydraulically induced fractures caused by the migration of highly pressured fluids from the deeper parts of the graben.

Summary of processes controlling seal effectiveness

Fig. 13. Probable distribution of the terrace and deep graben pressure domains.

which predicts that downward migration of hydrocarbons will occur into the water-leg of underlying reservoirs if overpressure of the cap-rock relative to the seal is greater than the reservoir capillary entry pressure. It also follows that hydrocarbon migration will stop when reservoir pressure and overpressure of the sealing source rock reach equilibrium. As hydrocarbons have ceased to migrate into the trap, the buoyancy pressure of the retained column remains constant without inducing hydraulic breaching of the cap-rock (Fig. 14a). In contrast, the organic-rich overpressured seal may induce hydraulic fractures within the overburden. Within the GEA, this probably explains why the pore-pressures of organic rich seals coincide with the lowest values of the fracture envelope (Fig. 7). Although this will result in the upward migration of hydrocarbons originating from the sealing source rock it does not follow that hydrocarbons trapped below the seal will also be released. As illustrated in Fig. 14b, pressure-inhibited charge is less likely in cases where hydrocarbons are able to migrate across the boundary of different pressure cells. In these cases the concept of pressure equilibrium does not apply as reservoir pore pressure is unrelated to the migration of hydrocarbons from the overlying seal. Excess reservoir overpressure relative to the seal may therefore induce hydraulic fractures which breach both the seal and the overburden. It follows that closures located near to frequently reactivated boundary faults have a relatively greater

Spatial variations in seal effectiveness can be represented by a chance factor map (Duff and Hall, 1996). Each domain can be associated with a chance factor score representing the estimated chance of encountering a successful seal. The magnitude of the scores combines a process-based interpretation of the factors controlling seal effectiveness together with an assessment of the quality of the data on which the interpretation is based. The chance domain map shown in Fig. 15 represents the top-seal effectiveness for the two pre-Cretaceous play styles that have been the subject of this paper: footwall fault blocks and inversions. A grading from "higher chance of seal" to "lower chance of seal" is shown rather than numerical chance factor values for simplicity. Within the deeper parts of the GEA, the seal integrity of pre-Cretaceous prospects coinciding with inversion trends younger than early Tertiary is suspect. In such cases tectonic breaching is likely to post-date or coincide with the main phase of hydrocarbon migration. The chance of tectonic breaching was highest within zones of recurrent wrench movement, resulting in linear or sigmoidal faults and fractures. Within the GEA, wrench-related deformation is most severe along the trend of the Lindesnes inversion, on the southwest flank of the Feda stratotectonic domain (Fig. 1). Accordingly, this area coincides with the lowest scoring chance domain. A further mode of tectonic breaching is the formation of radial tension fractures around the crests of inversion structures. Consequently, seal integrity is even more suspect where pre-Cretaceous reservoirs occur close to, or above, the neutral surface of the folds. Conversely, it is possible that seal integrity is maintained in cases

Fig. 14. Schematic illustration of the conditions under which pressure-inhib';ted charge and hydraulic breaching can occur.

241


Fig. 15. Pre-Cretaceous top-seal chance domains. The lowest chance of top-seal coincides with zones of wrench-related deformation. The highest chance of top-seal coincide with fault block structures or where hydrocarbon migration has post-dated the deformation of inversion structures.

where the reservoir objective lies stratigraphically below the neutral surface of inversions or where deformation has been compressional, rather than translational. The latter explanation may apply in the case of the Ula Field located on the northeastern terrace of the GEA. Alternatively, this success may be explained by the occurrence of localised hydrocarbon migration after the mid-Oligocene deformation. As a consequence, the highest scoring chance domains coincide with unreactivated fault-block structures or where hydrocarbon migration has post-dated inversion deformation (Fig. 15). Evaluation of the conditions required for hydraulic failure and capillary leakage indicates that neither process explains the total absence of trapped hydrocarbons. Despite this, these processes may have had some influence in limiting retention capacity. Capillary leakage is more likely during shallow and intermediate stages of burial, especially where leakage is possible along fault planes and through chalk topseals. In contrast, hydraulic breaching is most likely during the deepest stages of burial or where prospects lie adjacent to major non-sealing faults. Within the GEA, there is no evidence that significant quantities of hydrocarbons have been released from pre-

Cretaceous reservoirs by hydraulic fracturing. The alternative explanation presented in this paper, is "pressure-inhibited charge", in which downward migration of hydrocarbons from overpressured, organicrich top seals ceases at the point where pressure equilibrium is reached with the underlying reservoir. This causes the height of the hydrocarbon column to remain constant without inducing hydraulic breaching of the overlying seal. Overpressure within the organic-rich seals may induce hydraulic fractures within the overburden thereby maintaining seal porepressures close to the fracture gradient. This appears to be the case within the GEA where seal porepressures often coincide with the fracture values of overlying lithologies. The significance of the pressure-inhibited charge process is that trapped hydrocarbons below the overpressed seal will not be released by hydraulic fracturing induced above the overpressured seal. Within the GEA, this suggests that early migrated hydrocarbons may be retained in some of the deep pre-Cretaceous traps. By associating aquifer gradients (Fig. 12) with first-order spatial pressure domains and depth of burial, aquifer pressures for individual prospects can be predicted. Retention capacity as dictated by the pressure difference between the reservoir aquifer pressure and seal pore-pressure or fracture ~envelope can then estimated. The critical stage in this method is the selection of the correct aquifer pressure. Of the other variables required, the crestal elevation of the prospect is usually known with a reasonable degree of confidence, and seal pore-pressures are coincident with the fracture gradient which in turn is confirmed by measured (LOT/FIT) data. Application of this method within the GEA suggests that pre-Cretaceous seals retain hydrocarbon columns within the range from 200 to over 750 m.

Acknowledgements We wish to thank the management of Petrofina S.A. and our partners in the Ekofisk area PL018 licence group for permission to publish this paper. In particular, we would like to acknowledge the contribution of Messrs L. Jacobs, M. Green and G.A. McLanachan of Petrofina, and G. Caillet of Elf Petroleum Norge. We are also grateful for the many constructive discussions that we have had with our partners, and would also like to acknowledge the proprietary study carried out by J.R. Rose of Valebridge Exploration Consultants Ltd. We stress, however, that the views expressed here are those of the authors and do not necessarily reflect those of Petrofina S.A. or the PL018 group. Finally we thank G.M. Ingram of Shell International Exploration and Production whose

D.M. Hall B.A. Duff, M. Elias and S.R. Gytri

242

helpful comments as referee undoubtedly improved the text.

References Berg, R.B. 1975. Capillary pressures in stratigraphic traps. Am. Assoc. Pet. Geol. Bull., 59: 939-956. Bradley, J.S. and Powley, D.E. 1995. Pressure compartments in sedimentary basins: a review. In: P.J. Ortoleva (Editor), Pressure Compartments and Seals, Memoir 61. Am. Assoc. Pet. Geol., pp. 3-26. Clayton, C.J. and Hay, S.J. 1994. Gas migration mechanisms from accumulation to surface. Bull. Geol. Soc. Denmark, 41: 12-23. Deming, D. 1994. Factors necessary to define a pressure seal. Am. Assoc. Pet. Geol. Bull., 78: 1005-1009. Downey, M.W. 1984. Evaluating seals for hydrocarbon accumulations. Am. Assoc. Pet. Geol. Bull., 68: 1752-1763. Duff, B.A. and Hall, D.M. 1996. A model-based approach to evaluation of exploration opportunities. In" A.G. Dor6 and R. SindlingLarsen (Editors), Quantification and Prediction of Petroleum Resources, Special Publication 6. NPF, pp. 183-198. Gaarenstroom, L., Tromp, R.A.J., de Jong, M.C. and Brandenburg, A.M. 1993. Overpressures in the Central North Sea: implications for trap integrity and drilling safety. In: J.R. Parker (Editor), Petroleum Geology of Northwest Europe. Proc. 4th Conf. Geological Society, London, pp. 1305-1313. Gretener, P.E. 1981. Pore pressure fundamentals, general ramifications and implications for structural geology (revised). Am. Assoc. Pet. Geol. Educational Course Note 4, 131 pp.

D.M. HALL B.A. DUFF M. ELIAS S.R. GYTRI

Hubbert, M.K. and Rubey, W.W. 1959. Role of fluid pressure in mechanics of overthrust faulting. Bull. Geol. Soc. Am., 70; 115166. Hunt, J.M. 1990. Generation and migration of petroleum from abnormally pressured fluid compartments. Am. Assoc. Pet. Geol. Bull., 74: 1-12. Leonard, R.C. 1993. Distribution of sub-surface pressures in the Norwegian Central Graben and applications for exploration. In: J.R. Parker (Editor), Petroleum Geology of Northwest Europe. Proc. 4th Conf. Geological Society, London, pp. 1295-1303. Lockner, D. and Byerlee, J.D. 1977. Hydrofracture in Weber sandstone at high confining pressure and differential stress. J. Geophys. Res., 82: 2018-2026. Lorentz, J.C., Lawrence, W.T. and Warpinski, N.R. 1991. Regional fractures I: a mechanism for the formation of regional fractures at depth in fiat-lying reservoirs. Am. Assoc. Pet. Geol. Bull., 79: 1005-1018. Miller, T.W. 1995. New insights on natural hydraulic fractures induced by abnormally high pore pressures. Am. Assoc. Pet. Geol. Bull, 79: 1005-1018. SCrensen, S., Jones, M., Hardman, R.F.P., Leutz, W.K. and Schwartz, P.H. 1986. Reservoir characteristics of high- and low-productivity chalks from the Central North Sea. In: Norwegian Petroleum Society (Editors), Habitat of Hydrocarbons on the Norwegian Continental Shelf. Graham and Trotman, London, pp. 91-110. Watts, N.L. 1987. Theoretical aspects of cap-rock and fault seals for single and two phase hydrocarbon columns. Mar. Pet. Geol., 4: 274-307.

PetroFina sa, Rue de l'industrie 52, B-1040 Bruxelles, Belgium PetroFina sa, Rue de l'industrie 52, B-I040 Bruxelles, Belgium Fina Italiana, Viale Premuda 27, 1-20129, Milano, Italy Fina Exploration Norway, SkCgstostraen, P.O. Box 4055, Stavanger, Norway

243

References index

Aagaard, P., 203, 210, 216 Aarland, R.K., 85, 89, 151,162 Aasheim, S.M., 202, 216 Adams, J., 160, 161,163 Agar, S.M., 17, 37 Ahmed, A.S., 11, 12 Airo'Farulla, C., 161,162 Akbar, M., 11, 13 Aleksandrowski, P.A., 160, 162 Allan, U.S., 15, 36, 51, 59, 151,162 Allen, J.R.L., 93, 105 Alsaker, E., 85, 89 Altaner, S.P., 201, 216 Amaliksen, K.G., 205, 217 Ambraseys, N., 96, 105 Anderson, W.G., 166, 173 Andresen, A., 151,163 Andresen, P., 213, 217 Antonellini, M., 16, 17, 36, 55, 57, 59, 67, 71, 98, 103, 105, 127, 137, 155, 156, 158, 159, 163, 176, 177, 184 Amaud, J., 88, 89 Amesen, L., 151,163 Arthur, E., 75, 77, 89 Arthur, M., 77, 89 Ashkenazi, V., 96, 105 Augustson, J.H., 73, 89 Avery, A.H., 15, 16, 36, 153, 163 Aydin, 16, 17, 36, 55, 57, 59, 67, 71, 98, 103, 105, 127, 137, 139, 147, 155,156, 158, 159, 163, 176, 177, 184 Backer, L., 139, 148 Backer-Owe, K., 203,207, 212, 213, 216 B~ickstr6m, S.A., 213, 217 Badley, M., 33, 37, 109, 114, 124, 150, 151,163 Baker, E.G., 201,216 Baker, G., 39, 49 Bakhtar, K., 139, 140, 147 Bakke, S., 157, 163, 164 Bandis, S., 139, 140, 147 Barenblatt, G.E., 139, 147 Barnett, J.A.M., 63, 71,151,152, 163 Barry, J.J., 67, 71 Barton, N., 139, 140, 147, 148 Barton, N.R., 147 Baxter, K., 151,163 Bear, J., 139, 147 Beeunas, M.A., 175, 185 Belitz, K.R., 201, 216 Bell, J.S., 160, 161,163 Bentley, M.R., 67, 71,153, 163 Berg, R., 15, 16, 36, 153, 156, 163, 165, 173, 231,234, 242 Berkowitz, B., 139, 147 Bessis, F., 212, 213,215,217

Best, M.E., 201,207,209, 216, 217 Bethke, C., 201, 216 Billiris, H., 96, 105 Birkeland, O., 125,138 Bishop, R.S., 201,216 Bjcrlykke, K., 17, 37, 93, 99, 101,105, 106, 203,207,208, 210,212,215,216

Blenkinsop, T.G., 63, 65, 71 Block, M., 175, 184 Been, F., 202, 216 Bolton, A., 151,163 Borgmeier, M., 182, 183,184 Bouvier, J.D., 10, 12, 15, 17, 36, 54, 59, 67, 71, 111, 113, 114, 123, 129, 137, 155, 163 Bowles, J.E., 49 Bradley, J.S., 234, 242 Brandenburg, A.M., 170, 173, 228, 229, 232, 235,239, 242 Bray, E.E., 201,216 Bredehoeft, J., 176, 184, 201,216 Brekke, H., 87, 89 Brekke, T., 203,207, 212, 213,216 Brooks, M., 96, 106 Brzesowsky, R.H., 17, 37 Bugge, T., 202, 205,216 Bukovics, C., 125, 137, 202, 216 Buol, S.W., 82, 89 Burchell, M.T., 125, 137 Burley, S., 16, 17, 36, 37, 98, 103, 106 Burrus, J., 212, 213,215,217 Burst, J.F., 210, 216 Byerlee, J.D., 236, 242 Caillet, G., 88, 89, 160, 161,163 Cannon, S.J.C., 99, 106 Carew, W., 204, 216 Carson, B., 75, 77, 89 Carter, N.L., 17, 36 Cartier, E.G., 125,137 Cartwright, J., 26, 36, 151,164 Casey Moore, J., 75, 77, 82, 84, 86, 89 Catalan, L., 156, 163 Chan, H.C.M., 139, 147 Ch6net, P.Y., 212, 213,215,217 Chester, F.M., 25, 36, 151,163 Childs, C., 61, 63, 67, 71, 72, 151,153, 163 Chilingarian, G.V., 212, 217 Chung-Hsiang, P., 184 Clapp, F.G., 8, 12 Clayton, C.J., 231,234, 242 Clennell, M.B., 151,163 Clennell, M.R., 26, 27, 28, 37 Cloos, H., 47, 49 Coleman, D.D., 175, 185

244 Collier, R.E.L.I., 96, 106 Collinson, J.D., 92, 106 Coney, D., 161,163 Cordell, R.J., 201, 216 Cowan, D.S., 82, 89 Cowie, P.A., 16, 26, 28, 36 Craig, R.F., 171,173 Cross, P., 96, 105 Cuisiat, F., 139, 147 Cundall, P.A., 153, 155, 161,163 Currie, J.B., 139, 148 Dake, L.P., 11, 12 Dalland, A., 75, 87, 89, 202, 203,204, 212, 213, 215, 216 Dart, C.J., 96, 106 Davis, G.H., 212, 216 Davison, I., 26, 37 Davison, M., 96, 105 Davy, P., 24, 37 de Jong, L.N.J., 10, 13, 41, 44, 47, 49, 114, 124, 153, 163 de Jong, M.C., 170, 173, 228, 229, 232, 235,239, 242 de Marsily, G., 158, 163 Deacon, K., 103,106 Dean, R.H., 139, 147 Deming, D., 234, 242 Dengo, C.A., 41,49 Devay, L., 175,184 Dewers, T., 17, 36 Dix, C.H., 191,199 Djevanshir, R.D., 201,216 Doligez, B., 212, 213,215,217 Domenico, P., 201, 217 Dorn-Lopez, D., 109, 124 Doutsos, T., 96, 106 Downey, M.W., 176, 184, 231,242 Dowokpor, A.B., 161,163 Doyle, M.A., 11, 13 Driggs, A., 150, 151,163 Dudley, G., 23, 26, 37 Duff, B.A., 240, 242 Dullien, F.A.L., 156, 163 Dunn, D.E., 139, 147 DuRouchet, J., 204, 216 Dutta, N.C., 189, 191,199 Dypvik, H., 99, 101, 102, 106, 21 O, 216 Eaton, B.A., 190, 199 Edwards, A.B., 39, 49 Egeberg, P.K., 99, 106, 212, 215,216 Eggen, S., 202, 213, 216 Ehrenberg, S.N., 202, 204, 210, 212, 213, 216 Ehrmann, W.U., 61, 72 Ellis, D., 23, 26, 37 Elsinger, R.L., 11, 12 Engelder, J.T., 11, 12, 25, 36, 113,124, 127, 137 Engelder, T., 63, 71, 85, 89 Engelkemeir, A., 184, 185 England, P., 96, 105 England, W.A., 175,184, 201, 216 Eslinger, E.V., 210, 216 Evans, J.P., 63, 71, 127, 137 Fa~rseth, R.B., 73, 74, 89

References index

Faleide, J.I., 73, 89 Farmer, A.B., 26, 27, 28, 37, 151,163 Featherstone, W., 96, 105 Feder, J., 156, 163 Ferentinos, G., 96, 106 Fertl, H.W., 189, 199 Fischer, Q.J., 23, 26, 27, 28, 36, 37, 151,163 Fjeldskaar, W., 74, 89 Flood, B., 203,207, 212, 213, 216 Forbes, P.L., 213, 216 Forbes, R.J., 6, 7, 12 Forsberg, A., 213, 217 Foster, W.R., 201, 216 Fouch, T.D., 176, 184 Fowles, J., 16, 37, 98, 106 Franssen, R.C.M.W., 49, 55, 59, 111,124, 160, 163, 173 Fraser, A.J., 96, 106, 125, 137 Freeman, B., 33, 37, 67, 70, 71, 111, 114, 115, 124, 134, 136, 138, 150, 151,153, 159, 163 Freeman, D.H., 156, 158, 159, 163 Friedman, M., 41, 49 Fristad, T., 67, 70, 71,153, 163 Fulljames, J.R., 49, 111, 124, 160, 163, 173 Fyfe, T.B., 161,163 Gaarenstroom, L., 170, 173, 228, 229, 232, 235,239, 242 Gabrielsen, R.H., 73, 74, 75, 82, 85, 87, 88, 89, 103, 106, 139, 147

Gale, J.E., 160, 161,163 Gauthier, B.D.M., 15, 37, 172, 173 Gawthorpe, R.L., 96, 106 Gerritson, C., 4, 5, 12 Gibson, R., 11, 12, 15, 17, 23, 24, 37, 67, 70, 71, 72, 111, 113, 114, 124, 134, 137, 156, 159, 163, 201,216 Gijsen, M.A., 11, 13 Giles, M.R., 99, 106 Gillespie, P.A., 16, 24, 37, 151,163 Gjelberg, J., 92, 106 Gjerstad, H.M., 202, 204, 212, 213, 216 Glennie, E.W., 93,106 Gradstein, F.M., 201, 217 Grauls, D., 88, 89 Gray, M.B., 82, 89 Gretener, P.E., 236, 242 Griffiths, P.S., 63, 72 Groshong, R.H., 77, 89, 100, 106 Groth, A., 67, 70, 71,153, 163 Grunau, H.R., 11, 12 Gruner-Schlumberger, A., 8, 12 Grung-Olsen, R., 73, 89 Grunnaleite, I., 74, 75, 87, 89 Gu, Y., 41, 49 Gudlaugsson, S.T., 73, 89 Gussow, W.C., 9, 12 Gutierrez, M., 139, 147, 148 Hadler-Jacobsen, F., 202, 204, 212, 213, 216 Hager, D., 4, 5, 6, 12 Hager, R.V., 212, 216 Hairr, R., 150, 151,163 Hall, D.M., 240, 242 Hancock, P.L., 63, 72 Handin, J., 212, 216

245

References index

Hanken, N.M., 204, 217 Hanshaw, B., 201,216 Hansteen, H., 139, 147 Harding, T.P., 15, 37, 129, 137 Hardman, R.F.P., 234, 242 Harkness, R.M., 228, 229 Harper, A.S., 210, 216 Harper, T.R., 156, 159, 163 Harrison, A., 26, 27, 28, 37 Harrison, W.J., 201,216 Hartz, E., 151,163 Hastings, D.S., 210, 216 Hatton, C.G., 24, 37 Haug, S., 213,217 Hay, S.J., 231,234, 242 Heffer, K.J., 139, 147, 161,163 Hellem, T., 95, 101,106 Hemingson, P., 204, 216 Hemmens, P.D., 125,137 Henriquez, A., 157, 164 Hermanrud, 134, 135,138 Heum, O.R., 136, 137, 204, 205,212, 213,215, 216, 217, 223,229 Higgs, N., 41,49 Higgs, W.G., 96, 106 Hill, R., 150, 163 Hinch, H.H., 201,216 Hinkley, R.J., 151,163 Hocott, C.R., 8, 12 HCegh, K., 103,106 Hole, A., 125,137 Hole, F.D., 82, 89 Hollander, N.B., 202, 216 Horstad, I., 215, 216 Hottmann, C.E., 190, 199 Howard, C.B., 16, 24, 37, 151,163 Howell, J.V., 8, 12 Hower, J., 210, 216 Hower, M.E., 210, 216 Hsii, K.J., 82, 89 Hubbert, M.K., 8, 9, 12, 176, 184,, 189, 199, 234, 242 Huber, M.I., 77, 89 Huggins, P., 63, 72 Hull, J., 61, 63, 65, 72, 104, 106 Hunsche, U., 177, 184 Hunt, J.M., 234, 242 Hurst, A., 98, 99, 101,102, 106 Ibrahim, M.A., 57, 59, 166, 168, 173 Inderhaug, O.H., 160, 162 Ingram, G.A., 51, 52, 53, 59 Ingram, G.M., 49, 111,124, 160, 163, 173 loannis, C., 156, 163 Jackson, J., 96, 105 Jackson, R.E., 139, 147 Jacquart, G., 73, 89 Jamison, W.R., 155, 156, 163 Jenden, P.D., 175, 185 Jenkins, J.T., 150, 163 Jensen, L.N., 73, 74, 89 Jev, B.I., 15, 37, 152, 155, 163

Johnsen, J.H., 139, 148 Johnson, A.M., 139, 147 Johnson, H.D., 12 Johnson, R.K., 190, 199 Jolley, E.J., 125, 137 Jones, G., 23, 24, 26, 27, 28, 36, 37, 151,163 Jones, H., 24, 38 Jones, M., 234, 242 Jones, R.W., 201, 216 Jostad, H.P., 139, 147 Jurgan, H., 175, 184 Kaars-Sijpesteijn, C.D., 10, 12 Kaars-Sijpesteijn, C.H., 15, 37, 54, 59, 67, 71, 111, 113, 114, 123, 129, 137, 152, 155, 163 Kalheim, J.E., 73, 89 Karlsen, D.A., 203,207, 212, 213,216 Karlsson, W., 204, 216 Katsube, T.J., 201,207, 209, 216, 217 Katz, D.L., 57, 59, 166, 168, 173 Kaufman, R.L., 11, 12 Kazemi, H., 139, 147 Keith, L., 201, 216 Keller, J.V.A., 96, 106 Keller, P., 151,163 Kerrich, R., 103,106 Kettel, D., 175, 176, 184 Kidd, B., 26, 27, 28, 37 Kidd, B.E., 151,163 King, S.L., 184 Kluesner, D.F., 10, 12, 15, 17, 36, 54, 67, 71, 111, 113, 114, 123, 129, 137, 155, 163 Knapstad, B., 139, 148, 160, 162 Knarud, R., 95, 101,106, 202, 205, 216 Knight, J.L., 39, 49 Knipe, R.J., 15, 16, 17, 18, 23, 24, 25, 26, 28, 33, 35, 36, 37, 39, 49, 61, 72, 100, 106, 111, 113, 114, 124, 126, 127, 134, 137, 151,152, 155, 163 Knott, S.D., 15, 17, 30, 37, 67, 72, 125, 126, 127, 129, 137, 159, 163 Koch, J.O., 125, 138, 223,229 Koestler, A.G., 61, 72, 82, 88, 89, 103, 106, 139, 147, 151, 163

Koutsabeloulis, N.C., 139, 147 Kronenberg, A.K., 17, 36 Krooss, B.M., 176, 184 Kuhfuss, A.B., 213, 216 Kusznir, N.J., 109, 124 Labyerie, L., 98, 106 Lake, S.D., 15, 37, 172, 173 Landa, G.H., 139, 147 Landes, K.K., 3, 4, 9, 13 Landrum, W.R., 125, 137 Landsdown, J.M., 184 Langlois, W.E., 47, 49 Larsen, P.-H., 63, 72 Larsen, V., 202, 216 Larter, S.R., 215,216 Last, N.C., 139, 147 Lawrence, W.T., 236, 242 Leach, P.R.L., 125,137

246 Lefountain, L.J., 139, 147 Lehner, F., 10, 13, 40, 43, 44, 50, 53, 59, 70, 71, 72, 150, 152, 155,163,164

Leonard, R.C., 201,207,216, 234, 242 LeRoy, L.W., 6, 7, 13 Leutz, W.K., 234, 242 Leveille, G.P., 23, 26, 37 Leverett, M.C., 8, 13 Levorsen, A.I., 9, 13 Leythaeuser, D., 176, 184, 201,217 Liezenberg, J.L., 17, 37 Lindsay, D., 150, 151,163 Lindsay, N.G., 10,13, 17,37,39,49,53,59,70,72, 111,113, 124, 126, 132, 134, 138 Linjordet, A., 73, 89, 159, 163 Livera, S.E., 11, 13 Livingston, H.K., 8, 13 Lloyd, G.E., 17, 37 Lo, L.L., 139, 147 Lockner, D., 236, 242 Logan, J.M., 25, 36, 151,163 Logan, J.T., 41, 49 Loosveld, R.J.H., 55, 59 Lorbach, M., 180, 184 Lorentz, J.C., 236, 242 Lorenz, J.C., 139, 14 7 Lumsden, A.C., 147 Lundberg, N., 75, 77, 82, 84, 86, 89 Lytle, W.S., 3, 13 Mackay, T.A., 12 Mackenzie, A.S., 201, 216 Main, I.G., 16, 24, 28, 36, 37 Makurat, A., 73, 86, 88, 89, 139, 147, 148 Maltha, A., i0, 13, 41, 44, 47, 49, 114, 124, 153, 163 Mandel, J., 47, 49 Mandl, G., 10, 13, 40, 41, 43, 44, 47, 49, 50, 53, 59, 72, 114, 124, 152, 153, 155, 163, 164, 228, 229 Mann, D.M., 201,216 Mansfield, C., 26, 36 Martin, S.V., 99, 106 Matter, A., 17, 36, 103, 106 Mattern, G., 175, 184 McAllister, E., 26, 27, 28, 37 McCollough, E.H., 8, 13 McCracken, 82, 89 McGrath, A., 26, 37 Meinschein, W.G., 201, 217 Meisingset, K.K., 204, 212, 213, 215,216 Mercadier, C.G.L., 11, 13 Mercer, T.B., 160, 164 Meredith, P.G., 24, 37 Merill, L.S., 139, 147 Miller, T.W., 237, 242 Mills, N., 215,216 Milnes, A.G., 151,163 Mitra, S., 17, 37, 100, 106 Mo, E.S., 213,217 Moftah, I., 156, 159, 163 MOiler, N.K., 109, 124 Monsen, K., 73, 86, 88, 89 Moore, J.Mc.M., 100, 103,106 More, C., 23, 36, 37

References index

Moretti, I., 103,106 Morgenstem, N.R., 41, 49 MOrk, A., 202, 205,216 Morris, H.T., 25, 37 Mortimer, J., 63, 71,151,152, 163 Mudford, B.S., 201,209, 216, 217 Muhlhaus, H.-B., 150, 163 Mullis, A.M., 17, 36, 37 Mullis, J., 103, 106 Murphy, F.C., 10, 13, 17, 37, 39, 49, 53, 59, 70, 72, 111,113, 124, 132, 134, 138 Murris, R.J., 11, 13 Muskat, M., 8, 13 Nadeau, P.H., 210, 216 Nansen, F., 74, 89 Narr, W., 139, 148 Naylor, M.A., 51, 52, 53, 59 Nederlof, P.J.R., 11, 13 Nedkvitne, T., 99, 101,106 Needham, D.T., 24, 33, 37, 111, 114, 115, 124, 134, 136, 138 Needham, T., 38, 150, 151,163 Nelson, R.A., 139, 148 Nemec, W., 92, 106 Nichols, G., 96, 106 Nickelsen, R.P., 82, 89 Nurmi, R., 11, 13 Nybakken, S., 126, 138 Nyland, B., 73, 74, 89, 203, 207, 212, 213, 216 O'Beime, D.R., 6, 7, 12 Ofstad, K., 75, 87, 89, 202, 203,204, 212, 216 Ohm, S.E., 203,207, 212, 213, 216 Oksnevad, I.E., 92, 106 Olsen, S., 203,207, 212, 213,216 Onyejekwe, C.C., 10, 12, 15, 17, 36, 54, 67, 71, 111, 113, 114, 123, 129, 137, 155, 163 Oren, P.E., 157, 163, 164 Ori, G.G., 96, 106 Ortoleva, P.J., 17, 36 Otsuki, K., 63, 65, 72, 104, 106 Ottesen, S., 74, 87, 89 Owen, E.W., 3, 13 Paradissis, D., 96, 105 Parsons, B., 96, 105 Peach, C.J., 17, 37, 182, 184 Peacock, D.C.P., 16, 26, 37, 63, 72, 151,164 Peck, R.P., 188, 199 Pedersen, T., 103,106 Pennebaker, E.S., 190, 199 Perkins, H., 39, 49 Perry, E.A., 210, 216 Peters, M.P.A.M., 15, 37, 152, 155, 163 Pilaar, W.F., 10, 13, 40, 43, 44, 50, 53, 59, 70, 71, 72, 150, 152, 155, 163, 164 Piper, D.W., 96, 106 Pittman, E.D., 11, 13, 16, 37, 103, 106, 139, 148, 156, 164 Podladchikov, Yu., 150, 164 Poliakov, A.N.B., 150, 164 Poling, B.E., 182, 184, 185 Pollard, D.D., 63, 65, 72 Porter, J.R., 26, 27, 28, 37, 151,163

247

References index

Poulimenos, G., 96, 106 Powley, D.E., 234, 242 Prange, W., 40, 49 Prausnitz, J.M., 182, 184, 185 Precious, R.G., 10, 13, 40, 43, 44, 50, 53, 59, 72, 152, 155, 164

Prestholm, E., 92, 106 Prior, D.J., 17, 37 Quay, P.D., 184 Quigley, T.M., 201, 216 Quitzow, H.W., 40, 49 Rad, N.S., 139, 148 Ramm, M., 99, 101,106 Ramsay, J.G., 77, 89 Rands, P., 96, 105 Rankin, A.H., 100, 103,106 Rasmussen, E., 74, 75, 87, 89 Rawlings, C., 73, 86, 88, 89 Ray, A., 191,199 Rayson, P., 96, 105 Reid, B.E., 125, 137 Reid, R.C., 182, 184, 185 Reiss, L.H., 139, 148 Retail, P., 161,163 Rettger, R.E., 39, 47, 49 Rhett, B.W., 139, 148 Richard, P.D., 49, 111,124, 160, 163, 173 Rieke, H.H., 212, 217 Riis, F., 74, 73, 87, 89, 213, 216 Rimstidt, J., 201,216 Rippon, J., 63, 71, 151, 152, 163 Roberts, A.M., 109, 124 Robertson, E.C., 61, 63, 65, 72 Rodriguez, J.M., 160, 164 Root, P.J., 139, 148 Ross, J.V., 17, 36 Roufosse, M.C., 87, 89 Rubey, W.W., 189, 199, 234, 242 Rutter, E.H., 17, 37 Saigal, G.C., 95, 99, 101,106 Sancar, 134, 138 Sanderson, D.J., 16, 26, 37, 63, 72, 151,164 Sapru, A., 11, 13 Scandellari Nilsen, L., 157, 164 Schaefer, R.G., 176, 184, 217 Schl6mer, S., 204, 207, 210, 215, 217 Schmidt, W.J., 125, 138 Schoell, M., 175,185 Sch6ffmann, F., 180, 184 Scholz, C.H., 11, 13, 16, 26, 36, 37, 104, 106, 153, 164 Schowalter, T.T., 11, 13, 15, 37, 113, 124, 157, 158, 164, 165, 174

Schulze, O., 177, 184 Schutjens, P.M.T.M., 17, 37 Schwartz, P.H., 234, 242 Segall, P., 63, 65, 72 Sellers, P., 96, 105 Seth, M.S., 139, 147 Sharp, Jr., J., 201,217

Shaw, N.D., 125,137 Shimamoto, T., 41,49 Sibson, R.H., 16, 17, 37, 100, 103, 106 Sijpesteijn, K., 15, 17, 36 Skagen, J., 73, 74, 89 Skarpnes, O., 73, 74, 89, 159, 163 Skempton, A.W., 41,49 Smalley, P.C., 204, 217 Smith, D.A., 10, 13, 15, 37, 39, 40, 49, 51, 53, 59, 67, 72, 126, 138, 150, 152, 158, 164 Smith, J., 201,217 Smith, P.J., 161,163 SCrensen, S., 234, 242 Sornette, A., 16, 24, 28, 37 Sornette, D., 36, 37 Soum~, C., 88, 89 Spencer, A.M., 125, 138 Spiers, C.J., 17, 37 St. Pierre, B.H.P., 85, 89 Stearns, D.W., 155, 156, 163 Steel, R.J., 92, 106 Steen, 0., 151,163 Stevens, C.M., 184, 185 Stevenson, S., 99, 106 Stewart, D.J., 12 Stewart, I.S., 63, 72 Str H.H., 204, 217 Sverdrup, E., 17, 37, 92, 93, 95, 101,103, 106 Sykes, R.M., 98, 106 Talbot, C., 150, 164 Tchalenko, J.S., 41, 49, 50 Tek, M.R., 57, 59, 166, 168, 173 Terzaghi, K., 188, 199 Teufel, L.W., 139, 148 Thomas, G.W., 139, 147 Thorne, J.A., 201, 217 Throndsen, T., 213,217 Tillman, J.E., 139, 148 Tissot, B.P., 208, 217 TCrudbakken, B., 73, 86, 88, 89, 213,217 Tromp, R.A.J., 170, 173, 228, 229, 232, 235, 239, 242 Trudgill, B., 26, 36, 151,164 Tuminas, A.C., 15, 37, 129, 137 Tunbridge, L., 139, 147, 148 Tveiten, B., 95, 101,106 Underhill, J.R., 16, 37, 127, 138 Ungerer, P., 212, 213,215,216, 217 Upson, C., 201, 216 Vagle, G.B., 98, 99, 101,102, 106 VAgnes, E., 73, 89 Valore, C., 161,162 van der Pal, R.C., 10, 12, 15, 17, 36, 54, 67, 71, 111, 113, 114, 123, 129, 137, 155, 163 van der Wel, D., 109, 124 Van Golf-Racht, T.D., 139, 148 Vangb~ek, S., 139, 148 Vanneste, C., 16, 28, 36 Vardoulakis, I., 150, 163 Veis, G., 96, 105

248 Vetsoskiy, T.V., 176, 185 Vik, E., 134, 135, 138, 205,217 Voight, B., 85, 89 Vollset, J., 202, 216 von Huene, R., 75, 77, 89 Vorren, T., 73, 74, 89 Walderhaug, O., 203,217 Waldschmidt, W.A., 9, 13 Walker, I., 109, 124 Wallace, R.E., 25, 37 Walsh, J.J., 10, 13, 16, 17, 24, 34, 37, 38, 39, 49, 53, 59, 61, 63, 67, 70, 71, 72, 111, 113, 124, 132, 134, 138, 151,152, 153,163 Wang, Z.Z., 41,49 Ward, C.D., 223,229 Warpinski, N.R., 236, 242 Warren, J.E., 139, 148 Watterson, J., 10, 13, 16, 17, 24, 34, 37, 38, 39, 49, 53, 59, 61, 63, 67, 70, 71, 72, 111, 113, 124, 132, 134, 138, 151,152, 153,163 Watts, A.B., 201, 217 Watts, H., 201, 217 Watts, N.L., 11, 13, 15, 37, 38, 51, 52, 57, 59, 111, 113, 124, 126, 138, 139, 148, 152, 155, 163, 165, 166, 174, 228, 229, 231,234, 235, 242 Weber, C.J., 152, 155,164 Weber, J.R., 182, 184 Weber, K.J., 10, 11, 12, 13, 40, 43, 44, 50, 53, 59, 70, 72 Welte, D.H., 208,217

References index

Wesley, J.B., 176, 184 Westre, S., 73, 89 White, E.A., 26, 27, 28, 37, 151,163 White, I.C., 4, 13 Whitley, P.K., 213,217 Wilhelm, O., 8, 13 Wilkie, J.T., 15, 37, 152, 155, 163 Wilkinson, D., 156, 164 Willemsen, J.F., 156, 164 Wiltschkko, D.V., 17, 36 Wiltse, E., 11, 13 Wolf, R., 65, 72 Wong, T.-f., 41, 49 Woodcock, N.H., 16, 37, 127, 138 Worsley, D., 75, 87, 89, 202, 203,204, 212, 216 Wunderlich, H.G., 47, 50 Xiaowen, F., 156, 163 Yale, D.P., 160, 164 Yielding, G., 24, 33, 37, 38, 67, 70, 71, 109, 111, 114, 115, 124, 134, 136, 138, 150, 151,153, 163 Yukler, A., 176, 184, 217 Zhang, Y., 176, 185 Zieglar, D.L., 11, 13, 177, 185 Ziegler, P.A., 125, 137, 202, 216 Zijerveld, L.J.J., 49, 111, 124, 160, 163, 173 Zung Huinong, 11, 13 Zwart, H.J., 17, 37

249

Subject Index

abnormal pore fluid pressures, 187 Brent Group, Tampen Spur, 93 Brent sequence, 65 Brora, Scotland, 98 cap rock, 73 capillary entry pressure, 165 capillary leakage, 234 capillary pressure, 149 capillary seal, 51 cataclasis, 55, 113 causes of overpressure, 223 cemented fault zones, 91 classification and quantification, 1935-1955, 8 clay smear, 58, 111,150 clay smears, 39, 43 criteria for the ranking of seal quality, 47 damage zones, 25 Darcy flow model, 180 deformation band, 55 deformation outside the shear zones, 42 diffusion model, 177 dynamic leakage, 166 early struggles, 1850-1885, 1 effective pressure, 188 effective stress, 189 extrusion of plastic clays from source beds, 43 fault population, 172 fault properties, 91 fault rock petrophysical properties, 18 fault rocks, 26 fault seal, 68 fault seal analysis, 125 fault seal mechanisms, 111 fault seal probability, 125 fault seal probability map, 125 fault seal risk analysis, 16 fault surface bifurcation, 68 fault zone structure, 61 fault-seal methodology, 114 flow barriers, 165 fracture cross (bulk) flow measurements, 143 fracture cross flow, 139 fracture flow, 139 fracture flow results, 142 fracture systems, 73 fracturing, 234 gas in nature, 175

geological parameters controlling gas flow, 176 geopressure, 189 Greater Ekofisk Area, 231 Gulf of Corinth, Greece, 96 Haltenbanken, 202 Heidrun, 125 hydraulic fracturing, 236 hydrocarbon charge, 221 hydrocarbon leakage, 73 impact of Darcy flow of gases, 182 juxtaposition seal, 58 Kvalvhgen, Spitsbergen, 92 lateral pressure distribution, 223 migration, 201 migration pathways, 125 modern times, 9 Njord Field, 217 Oseberg Syd, 109 outcrop study, 40 overpressured zone, 188 permeabilities, 201 permeability barrier, 51 pore-pressure prediction, 187 pre-cretaceous drilling success ratios, 233 pressure, 201, 218 pressure-inhibited hydrocarbon charge, 239 pull-apart mechanism of clay-smear emplacement, 45 quantitative fault seal prediction, 107 reservoir connectivity, 67 seal capillary pressure hypothesis, 177 seal predictability, 149 sedimentary basins, 91 shale ductility, 170 shale gouge ratio, 67 shales, 201 shear bands, 149 shear zones associated with normal faulting, 40 slip plane, 55 SmCrbukk, 202 Southwestern Barents Sea, 73 start of petroleum geology, 1885-1915, 4

250

stress, 150 subseismic faults, 172 subsurface stress, 189 synsedimentary normal faults, 39 tectonic breaching, 235 tectonic development, 109 Tilje Formation, Haltenbanken, 93

Subject index top seals, 165 vertical leakage mechanism, 228 vertical pressure distribution, 226 wetting, 166 years of development, 1915-1935, 5

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