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
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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
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
Q.J. FISHER
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
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
Norwegian Technical Institute, P.O. Box 3930 Ullevaal Hageby, Sognsveien 72, N-0806 Oslo, Norway
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
List of Contributors
T.R. H A R P E R
Geosphere Ltd., Netherton Farm, Sheepwash, Beaworthy, Devon EX21 5PL, UK
A. HARRISON
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
G.M. INGRAM
Shell International Exploration and Production, Research & Technical Services, P.O. Box 60, 2280 AB Rijswijk, The Netherlands
G. JONES
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
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
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
O.S. KLOVJAN
Norsk Hydro U&P Research Centre, N-5020 Bergen, Norway
R.J. KNIPE
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
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
Norwegian Technical Institute, P.O. Box 3930 Ullevaal Hageby, Sognsveien 72, N-0806 Oslo, Norway
E. MCALLISTER
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
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
Rock Deformation Research Group, Department of Earth Sciences, University of Leeds, Leeds, LS2 9JT, UK
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
List of Contributors
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
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Contents
Preface .............................................................................................................................................. List of Contributors
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
,
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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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A historical overview of hydrocarbon trapping features
3
Austrian, drilling started in 1862. In Indonesia, drilling started in 1871 near the seep at Madja, on Java. In Canada, discoveries were made in 1857 in Ontario. Independently of each other, two geologists published their theories on anticlinical trapping in 1861. T. Sperry Hunt of the Canadian Geological Survey observed that the oil produced in western Ontario was associated with a broad, moderately folded anticline. Furthermore he recognised that the oil was situated in porous strata between impermeable shale layers. The gravity segregation of gas, oil and water was another interesting feature which he described. E.B. Andrews, Professor of Geology at Marietta, OH, also observed the close association of productive wells with anticlinal axes in West Virginia. He attributed this partly to the numerous cracks and fissures in these regions caused by the folding. These observations had little impact on the exploration practice which relied on local empirical lore and much pure wild-catting near seeps. Several fields were even found with the aid of a divining-rod! Even in Pennsylvania, where Professor H.D. Rogers indicated that several of the successful new wells were located on anticlines less than a year after the drilling of Drake's well, such information was ignored. Of course, it is always easy to ridicule this primitive approach. However, undoubtedly many geological advisors were quite unreliable. Moreover, if the structural style is not too complicated, empirical rules often work. Trends of rivers frequently played a part in predictions and these are often parallel to the structural strike. Another characteristic of early exploration efforts was the technical difficulty of drilling to any considerable depth and the poor recording of stratigraphic detail, which both hamper the subsurface analysis.
The situation in the USA is well illustrated by the statement by J.P. Lesley, the director of the Geological Survey of Pennsylvania, in 1875: "The supposed connection of petroleum with anticlinical and synclinical axes, faults, crevices, cleavage planes, etc., is now a deservedly forgotten superstition" (Landes, 1951). One gets the impression that the situation outside the USA was generally somewhat better and that geologists were involved at an earlier stage. In Europe, several interesting papers on petroleum geology appeared between 1870 and 1885. A striking example is the section through a salt dome from a paper by Posepny, dating from 1871 (Fig. 3). This form of trapping against the flanks of piercement domes was only discovered in the USA in 1925. In Vienna, in 1877, Hans von Hofer published a paper on anticlinical trapping (Owen, 1957). In 1870, B.S. Lyman a Pennsylvanian geologist, working for the Public Works Department in India, published the first structural contour maps of oil bearing strata. In the USA. the breakthrough of petroleum geology was mostly the work of two men: J.F. Carll and I.C. White. Carll, a civil engineer who had worked in the oil fields, joined the Pennsylvanian Geological Survey in 1874. His seven reports are a major contribution to petroleum geology. One can also see him as a petrophysicist and reservoir engineer. He realised the role of a gas cap in providing a drive mechanism for the oil but also the magnitude of the sandstone porosity and its importance for production and storage capacity (Lytle, 1957). Professor I.C. White is chiefly known for his reinvention of the anticlinal theory for oil accumulation, which he started to promote as of 1880. By 1885
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Fig. 3. Carpathian salt dome as depicted by F. Posepny (1871) showing the potential trapping configurations along the flanks.
4
K.J. Weber
he had already made several discoveries and his ideas began to have influence (Landes, 1951). From this time onwards petroleum geology was clearly on the way up in the USA, although one can say that the anticlinical theory got too much attention to the detriment of consideration of other trapping configurations. Later geologists have criticized some of White's publications (White, 1885) and pointed out serious discrepancies with the much more complicated reality. However, his influence was what counted and we must remember the saying: "A petroleum geologist's life is a never-ending struggle between brilliant concepts and inconvenient facts!" (Lament of a Shell exploration guru).
Start of petroleum geology, 1885-1915 As an example of the state-of-the-art in petroleum geology around 1885, it is interesting to follow the history of exploration on the island of Sumatra in Indonesia. The initial story is rather similar to the Pennsylvanian situation. In 1880, a Dutch tobacco planter, A.J. Zijlker, sheltering on a rainy night, noticed the long-burning torches of the natives and found that these were soaked in petroleum scooped from a nearby pool. He managed to obtain a concession from the Sultan of Langkat. To obtain capital for his venture, Zijlker needed the assurance of a competent geologist that an economic volume of oil might be present. For this he had to turn to the government mining department. Initially, he only received help in the form of a drilling engineer and the first well was spudded near an oil-covered pool. The well encountered some oil at a depth of about 100 m, but deepening only led to water production. However, a second well, placed by pure luck on the crest of an anticline, resulted in significant oil production at about 30 m and a blow-out of gas, oil and water when a depth of 121 m was reached. This event, in 1885, heralded oil production in Indonesia and is also the origin of the Shell company (Gerritson, 1939). A proper analysis of the find came after a government mining engineer, R. Fennema, was put in technical charge in 1886. Fennema was not only a competent engineer but also an accomplished geologist. He carried out geological surveys and showed the anticlinical nature of the oil accumulation at Talaga Toenggal, the site of the discovery well. In one of his letters from 1888 one can read the following: At one boring near Telaga Toenggal really magnificent results were obtained. Here the proper petroleumreservoir had been reached; geological investigations related with the results of the wells has shown us that this petroleum-reservoir (a thick sand layer soaked with
petroleum) is covered by a protective layer, which has
been bent to a so-called saddle or anticline. The saddle axis runs about parallel to the longitudinal axis of Sumatra and a section perpendicular to the axis is shown in the adjacent figure (Fig. 4); a-b is the petroleum soaked layer, which is encountered at 120 m below the surface at c, and produces the large amounts of gas and oil; d. are fissures in the coveting rock, in which the oil rises by the pressures of the gasses in the oil layer to the surface locally. Some of the covering layers that are more or less porous have been fed by the fissures and have in that way become secondary locations. (From the special commemorative book A Century of Exploration, 18851985, Shell Internationale Petroleum Maatschappij B.V., The Hague.) It is obvious from the above that the basic trapping conditions were well understood. Surface mapping of structures also started at this time and on the section of the Telaga Said field, the surface dips measured around the field are indicated (Fig. 5), This structure is situated on the same axial trend as the Telaga Toenggal anticline at a distance of about 1 km towards the NW). In the USA this surface mapping became popular after the famous Spindletop discovery in the anticlinical structure overlying a salt dome in 1901. However, it would take 25 years before the oil reservoir trapped against the flanks of the dome would be found. Good fieldwork and continued drilling near seeps resulted in numerous discoveries in the USA but also in Argentina, Venezuela, Trinidad, Mexico, Indonesia and very importantly in the Middle East, in Iran. Typically, the discovery well in Iran at Masjid-iSuleiman is only a stone's throw away from a large seep. The first book on pertroleum geology appeared in 1915 (Hager, 1915) and in it, several types of trap are described (Fig. 6). Production geological problems such as the gap in a reservoir as a result of a normal
.e,,
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Fig. 4. Sketch of a section across the Telaga-Toenggal anticline drawn by the mining engineer R. Fennema (1886). This section clearly shows the stratigraphy, structure and fissures which control the hydrocarbon distribution (from A Century of Exploration, 18851985, Shell Internationale Petroleum Maatschappij B.V., The Hague).
A historical overview of hydrocarbon trapping features
5
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Fig. 5. Section of the famous Telaga Said oil field which was the major oil producer in Sumatra at the end of the 19th century. The surface expressions of the structure of this overturned anticline are indicated showing that geological field work had been executed (from Gerritson, 1939).
fault had been understood (Fig. 7). Correlations between wells were carried out with the help of logs made by glueing cuttings to narrow wooden planks. Because the regular bailing out of the holes in cable tool drilling gives a quite accurate depth control on the sampling, this method results in excellent well records. From Hager's book, it is worthwhile to paraphrase some of the keys statements: - All oil and gas deposits, so far as known, are capped or covered by practically impervious beds of shale, sandstone or limestone; also such beds are underlaid by impervious beds. - No beds are actually impervious but are impervious only in a relative sense. - Where faults or unconformities occur, water will force oil to enter the upper strata by driving it from the lower sands. - Since water has about 50% higher surface tension than oil, it tends to be drawn into the finest capillaries with half again as much force as that drawing oil into the fine openings. Thus the tendency is for water to occupy the shale and oil and gas to fill the pores of the coarser strata.
Migration can thus be upwards, downwards or laterally. - Sometimes the more volatile oils will escape where the strata have been eroded, unless asphaltic or paraffinic deposits coat the faces of the strata, and act as seals. The above gives a good overview of the state-ofthe-art in 1915. By that time the USA produced 65% of the world's oil, Russia was second with 16%, followed by Mexico with 6%. Rumania and Indonesia produced 3% each, Burma and East Galicia with 2% and finally Japan and Iran with 1% close the list of prominent oil producing countries in the fateful year 1914. -
Years of development, 1915-1935 This is a period in which technical development was rapid. Rotary drilling led to much deeper drilling compared with the now outdated cable tool drilling. Surface mapping was insufficient to reveal the traps at greater depth, and a search was made for other methods. In 1915, the first field use was made of the torsion balance in gravimetric surveys in Czechoslo-
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Fig. 6. Fault trap from the early book on petroleum geology by Hager (1915).
o
6
K.J. Weber
Fig. 7. Fault cut-out from the book of Hager (1915), illustrating the increasing understanding of subsurface reservoir configurations.
vakia. This instrument had been developed over the period 1888 to 1896 by the Hungarian Baron R. von Ei3tvtis. After the First World War the method was introduced in the major oil producing countries. Shell tested the method in 1922 over the already known Hurghada structure in Egypt, resulting in a clear "high" in the gravity map (Forbes and O'Beirne, 1957). Elsewhere, particularly good results were obtained over salt domes. Improved gravimeters were developed and after 1935 these instruments are in general use throughout the oil provinces. Magnetic surveys were tried out after the Askania
factory produced a sensitive magnetometer in 1915. These proved to be much less successful than the gravimetric surveys for mapping structures, although the method yields much useful information on regional structural trends and rock composition. Of much greater importance with regard to the unravelling of trapping configurations was the development of seismic methods. The first seismic profile was actually already recorded by O. Hecker in 1900 but it took some time to achieve practically useful results. The first seismic method used in exploration for oil
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A historical overview of hydrocarbon trapping features
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a German, L. Mintrop, to locate enemy artillery. Mintrop was engaged by Shell after the war to try out this method for delineating structural features in Mexico. Useful results started to be obtained in the period 1924 to 1930, mainly in locating and mapping salt domes along the Gulf Coast. The reflection seismic method, that would eventually supplant the refraction technique, was patented in 1914 by R. Fessenden in the USA. Use of this method for oil exploration was proposed by J.C. Karcher in 1917. In 1921 the first field tests were carried out in the USA, but it took until 1929 before the first successes were achieved (Forbes and O'Beirne, 1957). Soon afterwards the method was already used in several countries often together with the refraction technique. A good example of an early reflection seismogram that resulted in the discovery of a field is shown in Fig. 8. The Tucupita field in eastern Venezuela was discovered on the basis of seismic surveys carried out in the period 1939-1941 (LeRoy, 1951). In 1927, the first wireline logs were recorded by the Schlumberger brothers at P6chelbronn in the A1-
51MPLE CONVEX TRAP
(BY FOLDING)
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(BY DIFFERENTIAL THICKNESS)
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Fig. 9. Correlation of electrical logs from the Midcontinent area in the USA. Logs of this type were invented in 1927 by the Schlumberger brothers (from LeRoy, 1951).
TRAP
POROUS BED
was based on recording the arrival at the surface of refracted waves originating from an explosion. This technique was developed during the World War I by
Fig. 10. Elementary reservoir traps from the classification of O. Wilhelm (1945).
K.J. Weber
8
Homoclinical ravines 4. Quaquaversal structures (domes) Domes and anticlines Domes on homoclines and monoclines - Closed salt domes Perforated salt domes Domal structures caused by igneous intrusions 5. Unconformities 6. Lenticular sands (on structure) 7. Crevices and cavities irrespective of the structure In limestone and dolomite In shales - In igneous rocks 8. Structures due to faulting On upthrown and downthrown sides - Overthrusts - Fault blocks Gradually it became clear that the anticlinal trapping theory had been given too much emphasis. Especially the discovery of the giant East Texas field in 1930 was seen as a demonstration of the importance of stratigraphic trapping. Actually, the word trap, as used in petroleum geology, was first introduced by McCollough in 1934, in an article on the influence of structure on the accumulation of petroleum in California (McCollough, 1934). Towards the end of this period, petroleum geologists were already starting to look back and a book on the historical development of the structural theory of the accumulation of oil and gas appeared (Howell, 1934). -
-
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Fig. 11. A set of composite and complex reservoirs with identifying symbols from O. Wilhelms classification (1945).
Classification and quantification, 1935-1955
sace (Gruner-Schlumberger, 1982). Electrical logging soon became an important oilfield method which not only helped to identify hydrocarbon bearing zones but also provided excellent correlations (Fig. 9). In 1931, a tool was invented to take reliable PVT sampies. Laboratory equipment was also improved and measurements of interfacial tension under in situ conditions became possible (Hocott, 1938; Livingston, 1938). Clapp (1910) proposed a classification of oilfields. He kept working on this system and eventually (Clapp, 1929) the following classification was proposed: 1. Anticlinical structures Normal anticlines - Broad geanticlinal folds - Overturned folds 2. Synclinical structures 3. Homoclinical structures - Structural terraces Homoclinical noses
At the end of the 1930s, a number of scientifically minded geologists took a hand in improving the understanding of the physical principles of migration and trapping. In 1941, Leverett published his famous paper on capillary behaviour in porous solids (Leverett, 1941). Hubbert studied dynamic trapping conditions (Hubbert, 1940, 1953). Very useful for the understanding of reservoir behaviour and sealing mechanism is Physical Principles of Oil Production, the classic work of Muskat (1949). This book contains an excellent discussion of capillary effects and also of the diffusion process. The efforts to classify every conceivable trapping configuration finds its culmination in the paper by Wilhelm (1945). He subdivided reservoirs into five groups: convex traps, permeability traps, pinch-out traps, fault traps and piercement traps. He constructed a set of diagrams illustrating all the various basic types (Fig. 10) and their numerous combinations (Fig. 11). With this classification, we can consider the recognition of trap types as
-
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A historical overview of hydrocarbon trapping features
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Fig. 12. Photograph of a surface exposure of a fault iri east Texas. A sandstone is juxtaposed across a 180 m throw fault with another sandstone. The fault zone consists of about a meter wide soft clay (from Smith, Company Report).
complete if we take diagenetic trapping as a very rare case. Limitations to the proper analysis of accumulation conditions were still formed by poor seismic resolution, unreliable pressure measurements and lack of sophisticated geochemistry. Until the wireline formation tester had reached such a state of development that it could provide reliable and repeatable pressure measurements, it was often difficult to recognise either separate or connected accumulations in the more complicated structures. In this period, a start was made on the study of fault zones. On the Gulf Coast, it had already been noticed that faults can separate oil or gas accumulations from water-bearing sands. Hubbert, in deriving the theoretical concepts of petroleum trapping, had shown that the boundary of a reservoir rock is a barrier to hydrocarbon migration because of its capillary properties (Hubbert, 1953). Observations of fault zone material showed the effect of cataclasis but also the presence of smeared-in shale. One finds fairly extensive descriptions of fault
sealing in the books Petroleum Geology by Landes (1951) and Geology of Petroleum by Levorsen (1954). However, most observations were reported within the oil companies and the general literature does not reflect the actual knowledge of the time. An interesting attempt at quantification of trapping of oil and gas was published by Gussow (1954), who analysed the differential entrapment of oil and gas. Overpressures were still poorly understood and attributed to undercompaction of the sands or diagenesis (Waldschmidt, 1941).
Modern times After 1955, there was an avalanche of papers on trapping and the subject gradually reached a status that one can speak of as true quantification, with the possibility of making reliable predictions. Undoubtedly, the development of seismic methods made a very large impact in the delineation of trapping configurations. However, also outcrop observations and laboratory experiments contributed markedly to the
10
K.J. Weber
Fig. 13. Schematic section of a Nigerian field showing the migration and accumulation conditions (from Weber, 1987).
gave an excellent overview of his observations in an article on sealing and non-sealing faults in Louisiana (Smith, 1980). More recently there appeared a paper on outcrop studies of shale smears on fault surfaces (Lindsay et al., 1993). Research by Shell resulted in predictions of the sealing capacity of normal faults in sand/shale sequences (Bouvier et al., 1989). The research concluded that sealing capacity of a fault at a
understanding of trapping, especially of fault sealing phenomena. Experiments with shearing granular material (Mandl et al., 1977) and observations in active open pit mines (Weber et al., 1978) led to a good description of shale smearing into fault zones. This phenomenon had already been described by Smith (1966) in the Gulf Coast fields and outcrops (Fig. 12). He
"ACTIVE" SEALING
1.(Mechanical) of faultzone
Permeability reduction due to
properties
~
Formatlon of Clay Gouge (clay smear) Downward Intrusion of weaker materlal Cataclasls (Grain crushing)
Pressure solution 2. Dlagenetlc processes (associated w i t h f a u l t i n g )
J
. ..
Cementation of grains
Authlgenlc growth of clay minerals, etc "PASSIVE" SEALING
Juxtaposition of llthologles across the
Fig. 14. Fault sealing mechanisms.
fault
A historical overview of hydrocarbon trapping features
given point is a function of the squares of the thicknesses of the shales that passed by that point, divided by the distance to each shale. The integration of fault sealing and along fault migration into field models was used in both Nigeria (Weber, 1987) and Trinidad (Gibson, 1994). It is obvious that one must consider the structures and the hydrocarbon migration as a dynamic system in time (Fig. 13). A classic paper describing the evolution of migration and trapping in the Middle East was written by Murris (1980). The mechanics of secondary hydrocarbon migration and entrapment were treated in a comprehensive way by Schowalter (1979). Fault gouge resulting from faulting of brittle materials was the subject of several papers (Engelder, 1974; Pittman, 1981; Scholz, 1987). Scholz showed that the thickness of the gouge zone for brittle faults increases linearly with total slip. Considering the fault zone as a membrane, one can introduce some numerical values on interfacial tensions, permeabilities, columns and pressures, and describe the various resulting trapping or non-trapping configurations (Watts, 1987; Zieglar, 1992). An overview of the various fault sealing mechanisms recognised at present is shown in Fig. 14. In producing oil fields, useful data can be measured to aid in fault sealing studies. Maximum differential pressures across fault zones, pulse testing (Dake, 1982; Zung Huinong, 1984) and dipmeter logs (Mercadier and Livera, 1993) all give important in-
11
formation concerning fault zone properties. The increase in the number of horizontal wells is also resuiting in a large number of fault penetrations at angles which allow a better analysis of fault zones (Nurmi et al., 1994). The use of gas chromatography is now common practice in many areas. This method is particularly useful in studying the origin of oils and, hence, migration pathways, but also to clearly recognise separation between adjacent reservoirs (Kaufman et al., 1990; Nederlof et al., 1994). In 1990, the first conference on cap-rocks was held in London but no significant new concepts emerged at that time. An overview of the cap-rock problem in all oil provinces was compiled by Grunau (1987). The objective was to investigate geological aspects of the cap-rock problem to provide guidelines for assessing the sealing and retention risk in exploration ventures. Again, it is important to place the cap-rocks in the framework of a hydrocarbon habitat with its alterations with time, taking into account geomechanical deformation, faulting and rate of diffusion through the cap-rocks. The present status of the trapping theories has been summarized in Fig. 15. Most of the configurations are well understood but still very difficult to quantify. There is a need for continued research on trapping and sealing phenomena comprising outcrop studies, field monitoring, core analysis, borehole imaging, analysis of cap-rocks, geochemistry, and detailed
,I
w,T. oar - .ocK _
1
CONTROLLED BY ENTRY PRESSURE OF LARGEST INTERCONNECTED PORE THROAT (ONCE THICKNESS EXCEEDS CRITICAL SLUG PINCH - OFF LENGTH )
1
FOR INFINITE ENTRY PRESSURE OF C A P - ROCK (eg. SALT~ ANHYDRITE )~ SEAL CAPACITY RELATED TO= o ) MINIMUM HORIZONTAL EFFECTIVE STRESS (TO WITHOLD HYDROCARBON COLUMN PRIOR TO FRACTURING ) b) THICKNES (OFTEN INDICATES LATERAL CONTINUITY + RELATION TO FRACTURE C O N T I N U I T Y )
1
CONTROLLED BY ENTRY PRESSURE OF LARGEST INTERCONNECTED PORE THROAT ACROSS FAULT PLANE
SEAL MECHANISMS INCLUDE : a ) CLAY SMEAR b ) CATACLASIS c ) DIAGENETIC HEALING
Fig. 15. Overview of sealing mechanisms.
,T.ouT car
1
"OCK i
CONTROLLED BY EXCESS HYDRODYNAMIC HEAD ABOVE ACCUMULATION. HYDROCARBON COLUMN REACHES EQUILIBRIUM LENGTH WHEN U P W A R D / DOWNWARD FLOW FORCES EQUAL
12
K.J. Weber
Fig. 16. Examples of perched hydrocarbon-water contracts in Borneo and the UK offshore (from Weber, 1995).
seismic studies of cap-rocks and faults. A good example of the use of seismic data for fault sealing prediction is the paper by Bouvier et al. (1989), describing the three-dimensional modelling of fault throw and shale smearing for a field in Nigeria. Finally, there is still a trapping configuration which, although quite common, is often overlooked or misunderstood, the so-called perched water-contact (Johnson et al., 1986; Weber, 1995). This occurs when a reservoir has a U-tube shape with a fault seal or a pinch-out at the closed end. The water cannot escape from this side of the U-tube resulting in different hydrocarbon-water contacts in the same reservoir. In the North Sea, we find perched oil-water contacts in Fulmar (Fig. 16), Tern, Ulla and Logger fields, but there are probably many more cases.
Conclusions The physical principles of the trapping of oil and gas are well established but quantification remains problematic in many cases. Consequently, the trapping capacity of structures and the retention of hydrocarbons with time is difficult to predict in exploration ventures. In a production setting, with a number of similar fields, the situation is much more favourable for the quantification of sealing capacity. There is still too little attention being paid to the four-dimensional aspects of migration and trapping. In some places we are looking at remigrated oil, trapped after several phases of deformation, while in other cases we are dealing with active migration and accumulations which have not reached equilibrium conditions. Thus, there is a large scope for additional research covering virtually the entire range of trapping mechanisms. Much data will have to be derived from wellstudied producing fields and this is a subject in which
exploration and production geologists must cooperate
closely. References Bouvier, J.D., Kaars-Sijpesteijn, C.D., 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. Clapp, F.G. 1910. A proposed classification of petroleum and natural gas fields. Econ. Geol., 5: 503-521. Clapp, F.G. 1929. Role of geologic structure in the accumulation of petroleum. In: Structure of Typical American Oil Fields, Vol. 2. Am. Assoc. Pet. Geol., Tulsa, OK, pp. 667-716. Dake, L.P. 1982. Application of the repeat formation tester in vertical and horizontal pulse testing in the Middle Jurassic Brent Sands. Paper EUR 270, Proc. Eur. Offshore Pet. Conf. 1982. Engelder, J.T. 1974. Cataclasis and the generation of fault gouge. Geol. Soc. Am. Bull., 85: 1515-1522. Forbes, R.J. and O'Beime, D.R. 1957. The Technical Development of the Royal Dutch/Shell, 1890-1940. E.J. Brill, Leiden. Gerritson, C. 1939. Geschiedenis der Koninklijke, 3 Vols. N.V.A. Oosthoeks's Uitgeverij, Utrecht. Gibson, R.G. 1994, Fault-zone seals in siliciclastic strata of the Columbus Basin, offshore Trinidad. Am. Assoc. Pet. Geol. Bull., 78: 13721385. Grunau, H.R. 1987. A worldwide look at the cap-rock problem. J. Pet. Geol., 10: 245-266. Gruner-Schlumberger, A. 1982. The Schlumberger Adventure. Arco, New York. Gussow, W.C. 1954. Differential entrapment of oil and gas: a fundamental principle. Am. Assoc. Pet. Geol. Bull., 38: 816-853. Hager, D. 1915. Practical Oil Geology. McGraw-Hill, New York. Hocott, C.R. 1938. Interfacial tension between water and oil under reservoir conditions, AIME Pet. Trans., 32:184-190. Howell, J.V. 1934. Historical development of structural theory of accumulation of oil and gas. In: Problems of Petroleum Geology. Am. Assoc. Pet. Geol., Tulsa, OK, pp. 1-23. Hubbert, M.K. 1940. The theory of ground-water motion. J. Geol., 48: 785-944. Hubbert, M.K. 1953. Entrapment of petroleum under hydrodynamic conditions. Am. Assoc. Pet. Geol. Bull., 37: 1954-2026. Johnson, H.D., Mackay, T.A. and Stewart, D.J. 1986. The Fulmar oilfield (Central North Sea): geological aspects of its discovery, appraisal and development. Mar. Pet. Geol., 3:99-125. Kaufman, R.L., Ahmed, A.S. and Elsinger, R.L. 1990. Gas chromatog-
A historical overview of hydrocarbon trapping features raphy as a development and production tool for fingerprinting oils from individual reservoirs: applications in the Gulf of Mexico, Gulf Coast Section of the Soc. Econ. Paleont. and Min. Foundation, 9th Annual Research Conf. Proc., pp. 263-282. Landes, K.K. 1951. Petroleum Geology. Chapman and Hall, London and Wiley, New York. LeRoy, L.W. 1951. Subsurface Geologic Methods (A Symposium). Colorado School of Mines, Department of Publications, Golden, CO. Leverett, M.C. 1941. Capillary behaviour in porous solids, AIME Pet. Trans., 142: 152-169. Levorsen, A.I. 1954. Geology of Petroleum. W.H. Freeman, San Francisco, CA. Lindsay, N.G., Murphy, F.C., Walsh, J.J. and Watterson, J. 1993. Outcrop studies of shale smears on fault surfaces. Int. Assoc. Sedimentol. Special Publication, 15:113-123. Livingston, H.K. 1938. Surface and interfacial tension of oil-water systems in Texas oil sands. Pet. Technol., 1: 1-13. Lytle, W.S. 1957. John F. Carll. Geotimes, 1: 8-14. Mandl, G., de Jong, L.N.J. and Maltha, A. 1977. Shear zones in granular material. An experimental study of their structure and mechanical genesis. Rock Mech., 9: 209-221. McCollough, E.H. 1934. Structural influence on the accumulation of petroleum in California. In: Problems of Petroleum Geology. Am. Assoc. Pet. Geol., Tulsa, OK, pp. 735-760. Mercadier, C.G.L. and Livera, S.E. 1993. Applications of the formation micro-scanner to modelling of Palaeozoic reservoirs in Oman. In: S.S. Flint and I.D. Bryant (Editors), Spec. Publ. Int. Ass. Sediment., no. 15. Blackwell Science, pp. 125-142. Murris, R.J. 1980. Middle East stratigraphic evolution and oil habitat. Am. Assoc. Pet. Geol. Bull., 64:597-618. Muskat, M. 1949. Physical Principles of Oil Production. McGraw-Hill, New York. Nederlof, P.J.R., Gijsen, M.A. and Doyle, M.A. 1994. Application of reservoir geochemistry to field appraisal. In: M.I. A1-Husseini (Editor), Geo'94, The Middle East Petroleum Geosciences, Vol. II. Gulf Petrolink, pp. 709-722. Nurmi, R., Wiltse, E., Sapru, A. and Akbar, M. 1994. Geological characterisation of horizontal wells during and after drilling. In: M.I. AIHusseini (Editor), Geo'94, The Middle East Petroleum Geosciences, Vol. II. Gulf Petrolink, pp. 724-736.
K.J. WEBER
13 Owen, E.W. 1957. Trek of the oil finders: a history of exploration for petroleum. Am. Assoc. Pet. Geol. Memoir, 6. Pittman, E.D. 1981. Effect of fault-related granulation of porosity and permeability of quartz sandstones, Simpson Group (Ordovician), Oklahoma. Am. Assoc. Pet. Geol. Bull., 65: 2381-2387. Scholz, C.H. 1987. Wear and gouge formation in brittle faulting. Geology, 15: 493-495. Schowalter, T.T. 1979. Mechanics of secondary hydrocarbon migration and entrapment. Am. Assoc. Pet. Geol. Bull., 63: 723-760. Smith, D.A. 1966. Theoretical considerations of sealing and non-sealing 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. Pet. Geol. Bull., 64: 145-172. Waldschmidt, W.A. 1941. Cementing materials in sandstones and probable influence of migration and accumulation of oil and gas. Am. Assoc. Pet. Geol. Bull., 25: 1839-1879. 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. Weber, K.J. 1987. Hydrocarbon distribution pattems in Nigerian growth fault structures controlled by structural style and stratigraphy. J. Pet. Sci. Eng., 1: 91-104. Weber, K.J. 1995. Perched hydrocarbon-water contacts- a common but poorly understood phenomenon. In: Extended Abstracts, Vol. 2, F035, 7th EAPG Conf. and Tech. Exhib., Glasgow, UK. EAPG Business Office, Zeist, pp. 1-2. 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. Offshore Conf., Houston, TX, Paper OTC 3356. White, I.C., 1885. The geology of natural gas. Science, 5: 521-522. Wilhelm, O. 1945. Classification of petroleum reservoirs. Am. Assoc. Pet. Geol. Bull., 29: 1537-1580. Zieglar, D.L. 1992. Hydrocarbon columns, buoyancy pressures, and seal efficiency: comparisons of oil and gas accumulations in California and the Rocky Mountains area. Am. Assoc. Pet. Geol. Bull., 76: 501-508. Zung Huinong, 1984. Interference testing and pulse testing in the Kenli carbonate oil pool - a case history. J. Pet. Technol., 1009-1017.
Faculty of Applied Earth Sciences, Delft University of Technology, P.O. Box 5028, 2600 GA Delft, The Netherlands
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15
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. McAIlister, J.R. Porter and E.A. White
Fault seal prediction in hydrocarbon reservoirs requires an understanding of fault seal mechanisms, fault rock petrophysical properties, the spatial distribution of seals, and seal stability. The properties and evolution of seals within fault zones can be evaluated using the combined results of structural core logging, microstructural and physical property characterisation, together with information on fault populations from seismic and outcrop studies and well test data. The important structural elements of fault zones which require characterisation are: the microstructural/petrophysical properties of the different fault rocks present; the population of faults and fractures which define damage zones around large faults; the spatial distribution, orientation and clustering of the deformation in individual fault zones; the history of fault activity, diagenesis and migration; the distribution and volume of fault rocks with different properties. Fault rocks in siliclastic sequences range from quartz-rich cataclasites, developed from pure sandstones, to phyllosilicate smears developed from shales. Fault rocks developed along sand/sand fault juxtapositions can have transmissibility reduction factors of > 106. The exact value depends upon the conditions of faulting and the amount of self-sealing experienced by the fault rock. An important class of intermediate fault rocks are those generated from impure sandstones, or from sandstones with concentrations of fine phyllosilicate laminations. The localisation of cement precipitation within the damage zone may occur, which will remove the applicability of simple seal prediction based only on the host-rock lithology and fault displacement. The density of structures present in damage zones around faults is related to the cumulative displacement across the zone. The detailed internal structure of a fault zone is dependent on the conditions of deformation, the lithological architecture present and the position in the fault array. Successful seal analyses depends upon the amalgamation of data from the micro-scale to the macro-scale. This review demonstrates that improvements in fault seal risk evaluation are possible. The future directions for improving fault seal risk evaluation are also discussed. The most critical of these are; characterisation of the internal structure of fault zones, generation of a database for fault rock petrophysical properties and incorporation of the impact of realistic fault zone geometries into reservoir modelling programs.
Introduction
The fault seal problem Fault sealing is now recognised as one of the key factors controlling hydrocarbon reservoir trapping and behaviour during production (Bouvier et al., 1989; Harding and Tuminas, 1989; Knipe, 1992a; Gauthier and Lake, 1993; Berg and Avery, 1995). Fault seal represents a significant unknown in any risk analysis associated with both hydrocarbon exploration and development strategies. Characterisation of the properties and distribution of structural heterogeneities, which can form barriers to fluid flow, is a prerequisite for detailed reservoir simulation. Despite the acknowledged importance of fault behaviour to reservoir management and development, as well to the role of faults during hydrocarbon migration, the detailed properties of faults remains poorly defined. This paper reviews the critical limitations which re-
strict present fault seal evaluation and identifies a number of methodologies and approaches which can improve the understanding of fault seal processes and significantly reduce the risk associated with fault seal prediction.
Towards solving fault seal issues The fundamental concepts needed for understanding fault sealing and trapping of hydrocarbons were introduced and reviewed by Smith (1966, 1980), Schowalter, (1979), Watts, (1987), Allan (1989) and Bouvier et al. (1989). A recent renewed interest in the behaviour of faults has resulted in a number of approaches to assessing different aspects of fault sealing (Knipe, 1992a, 1993a,b; Jev et al., 1993; Knott, 1993; Gibson, 1994; Berg and Avery, 1995). Fig. 1 outlines the important components needed for fault seal evaluation. The evaluation route shown emphasises that a range of different elements have to
Hydrocarbon Seals: Importancefor Exploration and Production edited by P. M~ller-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 15-40, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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R.J. Knipe et al.
Define geometry of fault array
Establish sub-seismic
fault density and fault zone structure
I I Map seal distributions Test models against I I on fault planes which ~ hydrocarbon contact ~-'~might form compartment levels if known 1 ~ 1 boundaries
Assess sealing mechanisms and fault rock properties
Evaluate critical juxtapositions and seal distributions
I Model reservoir flow and the impact of faults on drainage I Fig. 1. Outline of the important components in a fault seal evaluation.
be combined in order to assess the fault sealing potential. Each of these components carries its own resolution limits and sources of error. One of the limitations of fault seal analysis has been the complex nature of the variables involved and the difficulty in accurately defining each of the important factors. Calibration of any method is dependent upon the ability to separate the impact of individual components in the analysis and the need to include all the critical variables. The lack of data on the accurate characterisation of fault zones and fault properties has resulted in the adoption of a number of assumptions about faults which are not always applicable and have resulted in the exclusion of a number of important factors from fault seal risk evaluations. Such omissions have reduced the success of fault seal analysis and generated a perception that risk evaluation is impossible rather than difficult. Recent progress in understanding faulting processes (Scholz 1989; Cowie et al., 1993; Sibson, 1994), fault rock evolution (Knipe, 1989), fault geometry (Peacock and Sanderson, 1994), fault populations (Gillespie et al., 1993; Cowie et al., 1996) and improved analysis of reservoir hydrodynamics as well as new core recovery techniques and the capabilities of 3D seismic, all provide a platform for improving the understanding of fault seal. The data available to the geoscientist, geophysicist and reservoir engineer now allow a new level of integration needed to develop and test different methodologies of fault seal evaluation. The challenge is to make use of these advances and to identify the best practices which lead to a more cost-effective and accurate prediction of faulting related influences on hydrocarbon reservoir behaviour. The critical questions which now require evaluation in order to advance fault seal analysis are listed below: - Can fault rock properties be predicted?
-
Can sub-seismic fault zone structures and population characteristics be predicted? Can fault seal distributions be mapped? What is involved in fault seal risk analysis and what future requirements can be defined?
The structure of this paper Each of the questions listed above forms a subsection of this paper. A review of the recent advances in these areas, the requirements for answering the questions, and likely limitations to present solutions are discussed. The final section of the paper integrates these different aspects into a discussion of the risks associated with fault seal evaluation, and attempts to identify the future directions which will help remove the present limitations.
Prediction of fault rock properties Without a detailed understanding of the fundamental processes which control the evolution of fault rocks and their properties, the prediction of sealing capacity and the evaluation of the behaviour of a faulted reservoir will never be anything more than speculative.
Critical information required for fault-rock property evaluation Surprising little has been published on the detailed physical properties or microstructural evolution of fault rocks in hydrocarbon reservoirs. Recent papers which have begun to address this aspect of sealing include: analysis of clay smears (Knipe 1992a, 1994; Berg and Avery, 1995), cataclasites from pure sandstones (Pitman, 1981; Underhill and Woodcock, 1987; Antonellini and Aydin, 1994; Fowles and Burley, 1994), and deformation in impure sandstones
Fault seal analysis: successful methodologies, application and future directions
(Sverdrup and Bjcrlykke, 1992; Gibson, 1994). A detailed evaluation of fault-rock properties requires the integration of microstructural information on the deformation mechanism history of fault rocks with quantification of the porosity, pore geometry and pore aperture distributions, which control the capillary entry pressure characteristics. Such an analysis should involve the use of electron microscope based techniques (especially BSEM and CL) for detailed microstructural analysis. In addition, equipment capable of accurately measuring low (>>0.01 mD) permeabilities is required. Some of the studies reported in the literature listed above have not used techniques which allow clear resolution of the important microstructural elements or have been restricted by the measurement ability of equipment used for petrophysical property determination. Without such information, the identification of the origin and controls of seal petrophysical properties may be impossible, because the type of (and timing of) deformation processes which control the pore characteristics and the strength, of the fault-rocks remain poorly defined.
Fault seal processes The fundamental processes which result in the development of fault related permeability barriers have been reviewed by Mitra (1988) and Knipe (1989, 1992a, 1993a,b). There are five groups of processes which can operate individually or which may combine to alter the pore structure during or after deformation events. These processes are briefly reviewed below. (a) Deformation induced porosity collapse by
disaggregation, mixing and grain boundary sliding without large scale cataclasis. This group of processes dominates deformation of unconsolidated or unlithified material and is therefore characteristic of the deformation at shallow depths of burial. The processes result in the reorganisation of grain packing, redistribution of phyllosilicate material from peloids or lamina to a more homogeneous micro-fabric, and may involve the introduction of new fine-grained phyllosilicate material by fluid flow. The replacement of macroporosity with microporosity induces a permeability decrease and a change in the pore aperture sizes. In addition, the changes in the structure of the deformed material can alter the response of such early formed faults to later deformation events. For example, the lower grain size and concentration of phyllosilicates can induce pressure solution, or diffusive mass transfer, and create an effective seal which postdates the initial fault event. (b) Diffusive mass transfer. This process involves the redistribution of material away from sites of high
17
stress by dissolution, transport and precipitation (Rutter, 1983; Dewers and Ortoleva, 1990; Spiers et al. 1990; Mullis, 1993). The rate of diffusive mass transfer in lithified rocks is particularly enhanced by small grain sizes and the presence of phyllosilicates at grain contacts is therefore an important factor in the modification of fault rock properties following cataclasis in fault zones (see Knipe, 1993a,b). (c) Cataclasis. Processes which induce grain size reduction by fracturing are grouped together as cataclasis (Aydin, 1978; Antonellini and Aydin, 1994; Knipe and Lloyd, 1994), and dominate the deformation associated with faulting in lithified rocks. (d) Cementation. Faults may act as conduits for fluid flow during deformation (Burley et al., 1989; Carter et al., 1990; Knipe et al., 1991; Sibson, 1994) and are therefore susceptible to mineralisation. In addition, the higher rates of diffusive mass transfer in fine-grained cataclasites, as well as the concentration of local dilation sites, render fault zones susceptible to "self-sealing" processes via local dissolution and precipitation processes. (e) Clay or phyllosilicate smearing. This is a general term used to describe deformation induced shearing of clays or phyllosilicates (Smith, 1980; Bouvier et al., 1989; Gibson, 1994). Lindsay et al. (1993) have identified three types of clay smear associated with: (i) abrasion by movement past sandstones; (ii) shearing and ductile deformation between hanging-wall and footwall cut-offs of shale beds; and (iii) injection of clays during fluidisation. Knipe (1992a) and Gibson (1994) have recognised that the deformation of impure sandstones, with either high phyllosilicate contents or concentrations of phyllosilicate-rich lamina, can also give rise to micro-clay smears and emphasise that discrete shale beds are not a prerequisite for clay smear formation.
Fault seal types and faulting processes? The terminology and classification of fault-rocks and seal types is not yet universally agreed (Knipe, 1992a; Knott, 1993). The classification presented below is based on identification of the main process responsible for the reduction in permeability associated with the faults. Mechanistic terms have been combined with textural descriptive terms to provide a more expansive nomenclature system which covers the most common fault rocks and seal types. The fault seal types and associated fault-rock types can be divided into two broad categories: (a) Juxtaposition seals. These seals are associated with the cross-fault juxtaposition of lithologies with different petrophysical properties, e.g., sand on shale or sand on cemented unit.
18
(b) Fault rock seals. These seals are associated with the type of fault rock developed during deformation. Their development is primarily dependent upon the original host rock lithology, the deformation processes, and conditions as well as the amount of cementation involved. The seals can be sub-divided into seven types reviewed below (see also Fig. 2): 1. Cemented faults and fractures: The main porosity reduction mechanism is cementation (Fig. 2a). Cementation is taken here to cover situations where cements have developed from (i) fluids flowing along the fault zone, or (ii) preferential growth in cataclasites because of the high concentration of nucleation sites on the newly created fracture surfaces. 2. Phyllosilicate/clay smears: These are developed by the deformation of material with high concentrations of phyllosilicates. The type and continuity of the clay smear (Fig. 2b) depends on the architecture or proximity of the shale units, the lithification state of the phyllosilicate rich units at the time of deformation and the amount of shearing or fault offset. 3. Framework - phyllosilicate fault rocks: This class of fault rock, developed in impure or immature sandstones (with low framework silicate to phyllosilicate ratios) where the clay/phyllosilicate content is in the r a n g e - 1 5 % to -40%. These rocks can develop seals by a combination of shearing, smearing and mixing of detrital clays/ phyllosilicates, enhanced pressure solution during the late stages (or after) faulting, cataclasis, and finally the precipitation of new phyllosilicates (see Fig. 2c). 4. Framework - phyllosilicate/microcrystalline quartz fault rocks: This class of fault rock is introduced here to describe fault rocks which form in sediments with concentrations (>20%) of dissolvable sponge spicules and varying amounts (15-40%) of phyllosilicates (Fig. 2d). Although not common, sediments with high sponge spicules contents are prone to the development of fault rocks by the cataclasis, dissolution and reprecipitation of silica. The process may be initiated by the collapse of secondary pores created by spicule dissolution and induce the redistribution of more soluble material " by mixing.
R.J. Knipe et al.
5. Cataclasites developed in clean, mature sandstones with less than - 1 5 % cIay/phyllosilicate material. The evolution of these fault rocks is
dominated by grain fracturing and gives rise to zones sometimes referred to as granulation seams, cataclastic seams or deformation zones. Cataclasites can be divided into three types depending on the degree of lithification (Knipe 1992a, 1993b). Firstly, weakly lithified cataclasites, (Fig. 2e) which show little or no evidence of post-faulting compaction/cementation and which are dominated by point contacts between angular fracture fragments. Secondly, partially lithified cataclasites (Fig. 2f), characterised by some compaction and precipitation processes. Thirdly, lithified cataclasites (Fig. 2g), composed of interlocking grains formed by dissolution/precipitation processes. This sequence controls the evolution of fault rock petrophysical properties developed in sand on sand faults discussed in the next section of the paper. The degree of lithification is controlled by the extent of the grain size reduction, the amount of pressure solution, the amount of post-deformation quartz cementation by self-sealing processes, the conditions (pressure, temperature) of deformation and the timing of deformation relative to hydrocarbon emplacement. 6. Disaggregation zones are formed where no or little grain fracturing occurs during the deformation (Fig. 2h). These can develop as deformation bands in unlithified or poorly consolidated lithologies and in general do not form effective barriers to flow in sandstones with clay/phyllosilicate contents below - 15%.
Properties of different fault rock/seal types Fundamental to a successful fault seal analysis is quantification of the petrophysical properties of the different fault rocks present in the hydrocarbon field under investigation. The critical properties which require quantification are permeabilities, capillary entry pressures, transmissibility, fault-rock thickness and the strength of the fault rocks. One of the reasons why fault seal analysis and reservoir modelling has proved difficult has been the absence of data on these properties. Analysis of the petrophysical properties of
Fig. 2. Microstructures of fault seals. (a) Cemented fault zone where the main porosity reduction mechanism is cementation. (b) Phyllosilicate/clay smears formed by the deformation induced alignment of phyllosilicates. (c) Framework-phyllosilicate fault rock developed in impure or immature sandstones. Note the shearing, smearing and mixing of detrital clays/phyllosilicates, the elongate fabric created by pressure solution the as well as the generation of a fine-grained matrix formed by cataclasis. (d) Framework-phyllosilicate/microcrystalline quartz fault rock formed in a sediment with concentrations (>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
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R.J. Knipe et al.
Fault seal analysis: successful methodologies, application and future directions
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R.J. Knipe et al.
Fault seal analysis: successful methodologies, application and future directions 10000 []
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Fig. 3. Porosity-permeability plot of cataclastic fault rocks developed from sandstones with low (<6%) clay contents. Note the values extend over six orders of magnitude.
more than 300 fault rocks by the Rock Deformation Research group from over 25 hydrocarbon fields in the North Sea has allowed the construction of a database on fault rocks developed in different host sediments under different conditions and with different geohistories. Presentation of the results of these analysis is not possible in this short contribution. However, some of the important trends and themes which emerge from these analyses which have general implications for fault seal analysis are outlined below. (a) Cataclastic fault rocks developed from sandstones with low (<10-15%) clay content can have permeability values which extend over six orders of magnitude (Fig. 3). This is extremely important to fault seal analysis as it is often assumed that sand on sand faults (i.e., cataclastic fault rocks) leak. This is not a viable assumption for fault seal analysis as the sealing capacity of the low permeability (<<0.001 mD) cataclastic fault rocks can be -- 1000 m and equivalent to the cap-rock lithologies. The factors which control the exact values for particular cataclastic rocks are related to the geohistory experienced by the specimen, particularly the conditions of deformation, the depth of burial and the timing with respect to the hydrocarbon influx. Permeability measurements of cataclastic fault rocks reported in the literature are often quoted as being much higher than the values reported here. This is considered to reflect in part the inability of standard permeability equipment used to accurately measure permeabilities below 0.1 mD. (b) Impure sandstones with clay contents of between --15% and -40% form an important, but neglected, class of fault rocks which can form effective seals (see also Knipe 1992a; Gibson, 1994). This conclusion means that a simple fault seal analysis,
23
which considers the potential of clay smearing in sediment/reservoir sequences, based only on the distribution and proximity of shale units may be inaccurate. A more detailed analysis of the small scale (--cm to m) distribution of phyllosilicate rich units as well as impure sandstones is needed for accurate assessment of fault rock properties. (c) Fault rocks often show complex entry pressure characteristics which do not allow the accurate representation of this property by a single pressure value. Fig. 4 shows some representative mercury injection curves for two different fault rocks. The data emphasise that while a single entry pressure does describe the properties of material with a simple pore structure, the complex mixing of grain and pore sizes in impure sandstones and some cataclastic and phyllosilicate framework fault rocks generates a pressure curve which reflects a membrane behaviour. In this case the ability to retard flow will depend upon the pressure conditions imposed on the material. Accurate modelling of reservoirs containing such fault rocks will require inclusion of membrane behaviour. (d) Cement seals associated with faults are not uncommon. The presence of cemented fault zones renders incorrect the common assumption that prediction of fault rock properties can be based on an evaluation of the host rocks juxtaposed by faulting. An assessment of fault propagation into stratigraphic units, which can provide sources for cements (tip-tapping (Knipe, 1993a), using seismic data, or microstructural analysis of core material) is needed to evaluate the potential for cement seals (see e.g., Leveille et al., 1997). (e) Inversion or fault reactivation has a complex influence on sealing behaviour with both seal enhancement and breakdown occurring. (f) Fault rock seals have a wide range of lithification states and therefore a wide range of strengths. The strength of the fault rocks will control the changes in the flow properties in response to changes in the stress conditions applied to the reservoir. Very few studies have considered integration of microstructural and rock mechanics testing programmes with well test data to evaluate the importance of these factors in reservoir management.
Improved prediction of fault rock properties Each of the points made in the last section above highlights the complex interaction of variables which can control the final properties of fault rocks. The list also demonstrates that although a difficult problem, understanding of fault rock behaviour is possible if systematic investigations of fault rock evolution are
24
R.J. Knipe et al.
Fig. 4. Capillary pressure curves for two fault rocks. The data emphasise that while a single entry pressure does describe the properties of material with a simple pore structure, e.g., (a), the complex mixing of grain and pore sizes in the cataclastic shown in (b) generates a more complex pressure curve where a single characteristic entry pressure is more difficult to define, i.e., reflects more of a membrane behaviour.
undertaken. The creation of a database on the fault rock products from different host lithologies deformed under various conditions is clearly a vital component in fault seal analysis. The following list of points is important to the improvement of fault seal analysis and the reduction of risks associated with the quantification and prediction of fault rock petrophysical properties. - Microstructural studies have an important role in identifying and characterising the sealing mechanisms, and the diagenetic timing associated with fault activity (including reactivation) in particular fields and regions. Analysis which does not make use of available core material carries a higher risk of inaccurate and poorly constrained fault seal analysis. - The role of impure sandstones in generating flow barriers has been largely ignored (see however, Knipe, 1992a; Gibson, 1994). The critical role of the clay content in fault rock development can be assessed more accurately if phyllosilicate content logs are generated from sedimentary analysis of reservoir stratigraphies. Note that down-hole tool information on phyllosilicate contents may require careful inteqaretation and/or validation against core material as the detection of some minerals (e.g., kaolinite) may not be a simple process. - Accurate permeability measurements of fault rocks as well as characterisation of capillary entry pressure data of fault rocks requires different equipment and procedures than those applicable to
high permeability well sorted sandstones with large and unimodal pore size distributions.
Prediction of sub-seismic fault zone structures and populations
Why is the sub-seismic fault population important ? A large proportion of the structural features which can impact on the flow properties of a reservoir are below the resolution of seismic data. Therefore, understanding the spatial distribution and internal structure of fault zones can be fundamental to the flow behaviour of hydrocarbon reservoirs. This section reviews the important geometrical characteristics of fault zones and sub-seismic deformation features which can influence fault seal analysis. Two aspects of sub-seismic fault arrays are particularly important. Firstly, the recent recognition that some fault geometrical characteristics appear to be fractal (Sornette et al., 1990; Walsh and Watterson, 1992; Gillespie et al., 1993; Hatton et al., 1994; Yielding et al., 1996) raises the possibility of predicting sub-seismic fault patterns from seismic data for input into reservoir modelling. Secondly, the internal structure of individual fault zones needs characterisation because this influences the distribution of fault rocks and juxtapositions. Information on both these aspects of fault seal analysis can be obtained from core material recovered from drilling pro-
Fault seal analysis: successful methodologies, application and future directions
grammes. The data presented in this section are based on the analysis of >25 km of core from North Sea reservoirs and onshore outcrop studies of exposed faults.
Is the structure of fault zones usually assumed in fault seal analysis valid and what is the impact of fault damage zones? A common but important assumption made about faults during many fault seal analysis is that the seismically defined throw represents the magnitude of throw on a single fault. This assumption is valid for locating the general position of large structural discontinuities and assessing the overall fault displacement and coherency but can be incorrect for detailed flow or fault seal analysis. That fault zones are composed of clusters of deformation features which surround (or form a halos to) large offset faults has been recognised for some time (e.g., Engelder, 1974; Chester and Logan, 1986; Wallace and Morris, 1986). The importance of these damage zones to fault seal analysis in hydrocarbon reservoirs was highlighted by Knipe (1992b, 1994). The impact of the damage zones on fault seal are reviewed in Fig. 5. The pri-
Fig. 5. Cartoon of the main structural elements of a fault damage zone. The zone is composed of a clusters of deformation features around a large offset fault. Note that the juxtapositions present differ from those which would be present if only a single fault was present and that the presence of an array of deformation features can induce the development of micro-compartments or sealed cells in the fault zone.
25
mary influences of damage zones on fault seal and reservoir behaviour analysis are: The juxtapositions inferred by using a single fault model are different from those associated with a cluster of smaller faults. - The volume of deformed rocks around faults can affect the volume of reservoir with recoverable hydrocarbons. - The presence of an array of deformation features rather than a single fault can influence the changes in cross- or along-fault communication induced by reactivation events. -
What fault zone properties need to be incorporated into a robust fault seal analysis? A robust fault seal analysis requires incorporation of information on the internal architecture of large fault zones. The important factors include the population, the clustering and the orientation distribution of faults present close to the largest fault. An example of the complexity of a fault damage zone is shown in Fig. 6a. The illustration is of a seismic attribute map (dip magnitude) and shows that the fault zone is composed of linked segments and domains where different sub-structures are present. The intemal structure of the northem and southern segments is made up of anastomosing faults which enclose lenses of more intact reservoir. The central segment has fewer faults and appears to be composed of a smaller number of faults with larger throws. It is also interesting to note that a concentration of low amplitude discontinuities occur on the esstern side of the fault and probably represent the accomodation zone of small structures. The width of this zone increases towards the central (high displacement) portions of individual segments. Fig. 6b illustrates the type of simple interpretation of the fault structure often used as a basis of fault seal analysis. This interpretation is based on representation of the fault as a single fault plane, where the offset is assumed to be equal to the seismic (cumulative) offset. This is clearly not valid as a representation of throw distributions for use in fault seal analysis. Fig. 6 also illustrates that sub-seismic fault populations can be clustered around larger faults with extensive areas of low fault densities away from the large faults. This has important implications for the spatial distribution of sub-seismic faults and emphasises that uniform distributions of small faults are not always applicable (except perhaps in areas where more uniform straining is associated with doming). The information contained in Fig. 6 reinforces the results of other recent studies which have noted different fault
R.J. Knipe et al.
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Fig. 6. (a) An example of the complex architecture of a fault damage zone as imaged on a seismic attribute map (dip magnitude in this case). Note that the fault zone is composed of linked segments and domains where different sub-structures are present. (b) The simple interpretation of the fault zone which would be misleading if used as a basis for fault seal analysis.
architecture associated with fault segment structures or domains (Cartwright et al., 1996), relay zones (Peacock and Sanderson, 1994), and tip zones (McGrath and Davison, 1995). It is also clear that attribute mapping from high-quality 3D seismic surveys offers an important direction for the future characterisation of fault segment and damage zone geometries (see Jones and Knipe, 1996).
What are the important characteristics of fault damage zones? Damage zones represent the accommodation of strain around large faults, and are the products of fault propagation, displacement and linking processes operating during the growth of the zone. It is important to recognise that the damage zone is the final product of the total history of strain accumulation in the volume around the fault and should therefore be separated from fault processes zones (Cowie and Scholz, 1992), which develop at fault tips during propagation. A detailed report on the internal structure (Knipe et al., unpublished data) is beyond the scope of this paper and only some aspects of damage zones important to fault seal analysis are reviewed here.
The critical elements of fault damage zones which are needed for fault seal evaluation and for input into reservoir behaviour simulation include: (i) the dimensions of the damage zone; (ii) the fault clustering characteristics; (iii) the fault offset populations, which can control the distribution of fault rocks and juxtapositions; (iv) the orientation distributions of deformation features present within damage zones; and (v) the total thickness of fault-rocks. Each of these aspects are reviewed below, where the data presented are part of a large database collected from the structural analysis o f - 9 0 wells, (-25 km of core) from the North Sea area (see example in Fig. 7). The final part of this section presents a simple model which demonstrates the impact of damage zone structures on flow.
Damage zone dimensions The development of an increased frequency of structural features in the volume around large faults is a ubiquitous characteristic of the cores studied from the North Sea. The frequency of deformation features can increase from background levels of <50/100 m of core to values exceeding 600/100 m of core close to faults. The data set reveals that the structural frequency increases with increasing offset, and that
Fault seal analysis: successful methodologies, application and future directions
27
Fig. 7. Structural log of core entering a fault damage zone. The high structural frequency, faults and fractures concentrated at the base of the core, are arranged in clusters which define steps in the cumulative frequency curves.
faults with offsets of >75 m have damage zones which can extend for > 150 m. The edge of the damage zone is taken here as twice the background structural density. An example of the variation in the frequency of structural features away from one fault (the Ninety Fathom fault exposed in Whitley Bay, Tynemouth) is shown in Fig. 8. These data highlight the degradation of the reservoir properties close to the faults. The size of the damage zone is also dependent upon the lithologies which have been faulted, the deformation conditions and the distribution of strain between the hanging wall and footwall (Knipe et al.,
unpublished data). Fig. 9 is a cartoon which reviews the main factors which can control the dimensions and shape of damage zones and illustrates how the observed concentrations of deformation in either the hanging wall and the footwall can arise. It should be noted that these variations are part of the 3D variation in fault zone structure likely along faults as noted from the earlier discussion on fault segments and domains.
Fault clustering patterns Analysis of the frequency of structures in depth intervals (widths) which constitute clusters of defor-
R.J. Knipe et al.
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mation in cores (see Fig. 7, for examples of such clusters) reveals a clear power-law relationship. This has been found to hold for all well/cores assessed from the North Sea. Fig. 10 shows an example of data from one area which illustrates the relationship and reveals the presence of a lithological control on the cluster dimensions. The importance of this type of data is that it can be used to quantify the number of structural features which develop in clusters during fault growth. This helps to define a critical parameter needed for modelling the impact of faults of fluid flow.
Fault offset populations in damage zones Most fault offset population analysis (see Cowie et al., 1996) have concentrated on prediction of the number of sub-seismic over large areas (>1 km 2) faults rather than the distribution of the faults within the fault zones. In many cases a uniform distribution of faults across an area is assumed. The data from the structural logging of North Sea wells illustrate that the characteristics of faults found on a field scale are also present within individual fault zones identified on seismic or from well data. Because the population of small faults around larger structures will control the distribution of juxtapositions and fault rocks, detailed characterisation of the offsets is important to seal analysis. Fig. 11 illustrates the population characteristics of three fault zones with different offsets.
The plot illustrates the increasing population with a similar slope (or power-law, fractal relationship) for the central part of the measured populations. The identification of fractal characteristics is not a simple process and a recent work suggests that using a straight line fit to the log cumulative population data can be misleading. Fig. 12 shows a larger number of fault offset population analyses from cores through different faults and presents new information on the growth of fault populations. The figure shows that with increasing fault development (increasing total population) there is a change in the fractal number or slope towards higher values. This indicates that as the level of deformation increases (either with increasing fault offset magnitude or proximity to a fault) the fault population grows to contain a larger proportion of small offset faults. This is an important result as it reveals that this core data set on individual fault zones is preserving evidence of the continued addition of small faults throughout the fault development. This also emphasises the important distinction between population addition associated with initial propagation, process zone related, and the finite population which includes development from later displacement and accommodation events, i.e., damage zone related, (Knipe et al., unpublished data). This behaviour, of adding more small faults, may contrast with the late stages of fault growth on faults, when displacement activity may localise on established larger faults from an initial, more uniform, distribution (Cowie et al., 1993). An important part of modelling the impact of fault damage zones of reservoir flow relies on the ability to
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Fault seal analysis: successful methodologies, application and future directions
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evaluate if certain fault sizes (or offsets) are preferentially developed or if gaps in the fault offset population are present. Analysis of fault populations form the core database indicates that there can be gaps as well as some order in the offset population of individual clusters. Fig. 13 presents a conceptual model of a fault damage zone using a Sierpinski Carpet as an analogue. This model can be considered as the repositioning of faults which together make up a cluster of deformation features into an ideal arrangement. There are two properties of this ideal structure which may prove important to the analysis of natural fault clusters: (i) the population series, which defines the cascade of fault populations of different sizes (e.g., 1:8:64 in Fig. 13), and the dimension series, which describes the cascade of fault size attributes (length, offset, etc.) present relative to the largest fault (e.g., lengths 1:1/3:1/9 in Fig. 13). The presence of such order has been detected in fault clusters from core and field data. Fig. 14 shows an example of a probability density function analysis of one natural fault cluster and illustrates that there is a relationship between the largest offsets present and the number and size of smaller offset groups in the cluster. Such analysis is important to modelling fault zone flow
behaviour because the combination of the population series and the offset series will control the gradient of the fault population data on cumulative or frequency vs size attribute plots; i.e., will determine the fract# number of the population. In addition, it is important to establish the size of the largest fault offset in an array where only the cumulative throw is available from seismic.
Fault orientation distributions The 3D orientation distributions of structural features within damage zones are important for modelling of fluid flow as the non-parallel members of the arrays induce an intersection network which will control the connectivity of barriers. It is insufficient to characterise the average fault orientations or to identify average fault trends or families. A more detailed statistical analysis of fault orientations is needed in order to evaluate the 3D distribution of flow paths and barriers. An analysis of fault dips from North Sea wells (-20 km of total core studied) yields an average dip of 59 ~. However the standard deviations of these data sets, which will control the density and pattern of intersections, is typically between 15 ~ and 26 ~ Fig. 15 illustrates one example which com
R.J. Knipe et al.
30
Populations of Cores Intersected by Seismic Faults
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Fig. 11. The fault offset populations of three fault zones with different cumulative offsets. The plot illustrates the increasing population with a similar slope (or power-law, fractal relationship) for the central part of the measured populations.
The thickness of the low permeability fault rocks is an important variable in evaluation of cross-fault flow behaviour. Because fault zones are usually composed of complex arrays of intersecting sub-seismic faults and fractures and because the permeability reductions associated with faulting develop after low amounts (-cm) of displacement incorporation of the impact of complex fault zones (as opposed to single faults ) is not a simple procedure.
Two variables are fundamental to assessing the flow across complex fault zones. The first variable is the cumulative fault-rock thickness across the fault zone, i.e., the total thickness of fault-rock from all faults along the flow path. This depends upon the fault frequency along the flow path and is not equivalent to the fault damage zone thickness (cf. Knott, 1993) unless the fault zone is invaded by cements. The second variable is the connectivity of the faults or deformation features with low permeabilities in the fault zone. In the case of a completely connected array with no windows of undeformed material along possible flow paths, the flow is controlled by the permeability of the fault rocks. Where a more open network of faults is present then the flow will depend upon the tortuosity associated with flow around the low permeability zones and the ratio of matrix to fault-rock permeability. The interaction of these two factors will control the effective transmissivity of the zone. We have constructed a database on
Fig. 12. Fault offset populations from cores through different faults. Note that with increasing fault development (increasing total population) there is a change in the fractal number or slope towards high values.
Fig. 13. Conceptual model of a fault damage zone using a Sierpinski carpet. The fault zone structure can be considered to be characterised by a population series (i.e., the number of faults of different sizes, 1:8:64) and a dimension series (i.e., the size cascade of the faults present, 1, 1/3, 1/9).
pares the orientation distribution derived from an analysis of faults on seismic data with an orientation distribution of smaller scale fault orientation derived from core data. It is clear that the small scale structures exhibit more variation in orientation than the larger scale structure, and demonstrates that seismic fault orientation distributions cannot be used in a simple way to predict sub-seismic fault patterns.
The volume and continuity of fault rock in the damage zone
Fault seal analysis." successful methodologies, application and future directions I
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The data presented above on sub-seismic fault populations highlight the complexity of fault zones and that a detailed analysis of fault sealing can be of limited value if a simple fault zone structure is assumed. Despite these complexities, it is also clear that a more constrained analysis of fault sealing is possible if the detailed fault zone architecture is considered. The model of fault damage zones which emerges from the data presented above is of a volume of deformed reservoir surrounding fault zones, where with increasing proximity to the main fault, the structure of the fault zone alters (Knipe, 1994). The damage zone can be viewed as being composed of "onion skins" each with different densities, architectures and connectivities between potential barriers. Damage zones can be considered made up of two main domains with different flow properties: an outer zone and an inner zone. The outer zone of the damage zone will be composed of a volume with a higher structural density (minor faults and fractures) than outside where, if the fault rocks are effective barriers, tortuosity controls the flow behaviour. The inner zone, is where the structural density and architecture (i.e., the fault population, clustering and orientation
Fig. 15. Comparison of the orientation distribution derived from an analysis of fault orientation based on seismic data with an orientation distribu-
tion of smaller scale fault orientation derived from core data in the same area. Note that the small scale structures exhibit more variation in orientation than the larger scale structure.
R.J. Knipe et aL
32
Fig. 16. Numerical analysis evaluating the connectivity of faults with a damage zone. The analysis is aimed at identifying the critical density of structural features needed to separate domains with (a) fault-rock controlled flow behaviour and (b) tortuosity controlled flow behaviour. In the example shown, a transition from an openarray of faults with tortuosity flow to a connected array occurs when the structural frequency is equivalent to between 200 features/100 m of core and 400 features/100 m of core.
characteristics present) generate a linked 3D array, which together form a continuous barrier, where flow is controlled by the fault rock properties. This can create sealed cells or micro-compartments within fault zones. The challenge for fault seal analysis is to be able to define the geometry and location of these inner and outer zones of damage zones. For the analysis of fault flow behaviour identifying the characteristics of the boundary between the outer and inner damage zone domains is essential. Fig. 16 presents a simple numerical analysis evaluating the critical density of structural features needed to define the boundary between the inner (with fault-rock controlled flow behaviour) and outer (tortuosity controlled flow behaviour) damage zones. The analysis shown is based on the concept of creating an array of faults with defined population, size, spatial and orientation distributions and then testing the flow properties of the array by creating "fires" at specific points and evaluating the spread of the "fire" or flow through the grid matrix, where the faults act as barriers to flow. The array can then be sampled to determine the density of structural features present when flow or penetration is prevented across the grid/lattice
system. The example shown is for a 2D situation and the progressive increase in the density of structural features causes a transition from flow to sealing when the structural frequency is equivalent to between 200 deformation features/100m of core and 400 features/100m of core. The transition zone between these values reflects the different spatial arrangements possible in this range where some specific geometries are able seal and others form open networks. It is clear that such modelling can provide an important step in the analysis of flow properties of faults before more detailed flow modelling with a reservoir simulation package is undertaken.
Mapping fault seal distributions The basic requirement for mapping fault seals is the generation of a realistic, maximum probability map of sealing capacities along individual fault zones. This involves evaluation of the possible juxtaposition patterns within the zone as well as an assessment of the variance of fault rock properties. The method most commonly used in evaluating fault seal distributions is the construction of Allan
Fault seal analysis: successful methodologies, application and future directions
maps (Allan, 1989) which illustrate stratigraphic geometries of horizon/fault plane intersections and are either drawn by hand or used in conjunction with fault mapping software (such as FAPS) (Freeman et al., 1990; Needham et al., 1996). Construction of these maps can be an essential, but difficult and timeconsuming task and the important limitations of these maps are not always considered in detail. The assumption made in constructing these fault plane maps is that the throw indicated across a fault identified on seismic represents a single fault plane. The real situation is more complex and the seismically defined fault should be considered as the cumulative throw of the zone, which may not be accommodated on a single fault. Two factors are therefore critical in the evaluation of the geometrical distribution of seals in fault zones. The first relates to the accuracy of mapping, the stratigraphic horizons, the fault zone location and the cumulative throw distributions. This is usually controlled by the resolution of seismic data and is generally of the order of 20-30 m for high quality data sets. Such a resolution of both surface and fault mapping can introduce a large range of possible juxtapositions patterns, even if a fault zone with a single fault plane is present. The second limitation centres around the problem of characterising the sub-seismic fault damage zone architecture along the fault zones and in tip areas. The last section of the paper on sub-seismic faults reviewed how characterisation and modelling of the critical parameters of sub-seismic faults can reduce the risk associated with fault seal analysis. How many fault seal analyses or reservoir modelling attempts have produced poor history matching because the potential variation in fault juxtapositions arising from the combined impact of resolution limitations and fault zone sub-structure have not been considered?
Towards a solution to fault seal mapping The evaluation of fault-seal potential along individual faults can be time consuming if each fault has to be mapped in enough detail to allow accurate definition of reservoir and fault intersections. It is often more efficient to divide the evaluation process into two phases: (a) Phase 1: involving a rapid assessment of the impact of fault throw, sedimentary architecture and fault zone structure on the juxtapositions and sealing properties of faults in the field. This can be achieved by the use of simple juxtaposition/fault seal diagrams (Knipe, 1992b, 1997) without the need for detailed (or in some cases any) seismic mapping of either stratigraphy horizons or faults. The advantage of this procedure is that critical fault throws, which create
33
"leaky" windows across faults, can be identified and used to help locate areas of the field where more detailed analysis of the seismic data is needed. (b) Phase 2: seismic mapping (in selected areas) of detailed fault and reservoir horizon geometries to constrain the depth and location of, leaky windows, and to provide a platform for analysis of the potential controls on hydrocarbon/water contacts, drainage patterns and field communication. Some important aspects of each of these phases of fault seal distribution analysis are reviewed below. Phase 1 is aimed at investigating the seal potential of faults with different throws and rapidly assessing the consequences of seismic resolution problems, fault damage zones and variations in the internal reservoir architecture. Fig. 17a,b illustrates the basis of the juxtaposition and fault seal diagrams. The details of the construction of these diagrams are presented by Knipe (1997); a software package is available. The figure plots the reservoir stratigraphies in the footwall and hanging-wall along the vertical axes and increasing fault throw along the horizontal axis. The diagrams can be considered as a horizontal view of a "transparent" fault where the stratigraphy in the footwall is horizontal and the hanging-wall inclined. The juxtapositions between the hanging-wall and footwall are represented as either triangles or parallelograms on the fault surface. The range of juxtapositions along a fault with constant or variable throw can be assessed from therange of triangular and parallelogram areas intersected by either a vertical or inclined line. The impact of seismic resolution can be assessed by considering the intersection of a band of throws with a thickness which accounts for the resolution. Damage zones can be evaluated by considering an array of faults, where the combined throw is equal to the cumulative throw interpreted from seismic. The diagrams can be adjusted for reverse and syn-sedimentary fault-growth fault situations. We have also found it useful to include "side-wall" plots of the critical depth property data which help in the delineation and classification of fault rock types and properties. These side-wall plots can include porosity, permeability, net gross ratios, and various down-holetool log data sets (see Fig. 17c). Fault seal types, based on the analysis of fault rock properties derived from the different host rocks as well as on the throw and juxtaposition history, can be generated on a separate (fault seal type) diagram. Areas on the diagram with different properties can then be identified (see Fig. 17c). This procedure allows the mapping or contouring important sealing properties on the diagrams. The fault properties which can be mapped onto these diagrams include permeabilities, shale smear potential, transmissibilities, sealing ca-
R.J. Knipe et al.
34
Fig. 17. Juxtaposition diagrams for use in fault seal analysis. See text for details.
pacities, and seal strengths. The diagrams can also be used to correlate these properties with well test or production data to validate the analysis. Phase 2 involves the detailed mapping of both reservoir horizons and faults and requires assembling fault plane maps, as well as integration with well data
on hydrocarbon/water contacts, pressure distributions and production data. The following is a list of the important considerations which should be involved in this stage of the analysis: (1) Evaluation of the coherency of fault offset patterns and gradients (Walsh and Watterson, 1991)
Fault seal analysis: successful methodologies, application and future directions
to identify faults intersections, erosion of fault tops at unconformities, the sub-structure of tip areas and connectivity of fault zones (tip-tapping) into stratigraphic horizons able to generate cements. (2) Assessment of data on the presence of fault damage zones and structural variation along fault zones, from both individual seismic lines as well as attribute data, if available (Jones and Knipe, 1996). The aim is to identify segments or domains, where different fault patterns may be present. For example, early relay zones, which mark the ends of linked fault segments, have a high probability of developing from overlapping faults and often represent areas where accommodation of displacement is distributed on a number of faults, i.e., these areas will be characterised by low throw juxtapositions (see Knipe, 1997). (3) Analysis of the location and heights of potential leaky fault juxtaposition windows which arise from variations in: (i) the possible depths, geometries and locations of stratigraphic horizons and faults; (ii) the difference between the cumulative throw on individual fault zones, indicated from seismic and the most likely size of the throw on the largest real fault in that zone; and (iii) the sediment architecture and continuity. The end result should be a probability map of the distribution of sealed and leaky windows along the critical fault zones.
35
(4) The generation of communication and drainage maps for potential compartments and the correlation and integration of these with hydrocarbon/water contacts, pressure test and production data. (5) Input of the most robust reservoir characterisation geometries and properties into simulation models. Note that in the exploration situation, versus the development case, the different levels of data availability will dictate which of the above analytical procedures are possible and which missing (or poorly defined) elements represent the high risk factors.
Fault seal risk analysis and future requirements This paper has highlighted that a number of components, important to fault seal analysis, are often either not included or not quantified in sufficient detail to allow a low risk seal evaluation. The main components which are not always considered in detail are: (i) the errors in throw patterns which arise from seismic resolution and fault damage zone structures; (ii) the assumption that juxtaposition of reservoir against low permeability units and shale smear are the only sealing mechanisms; and (iii) that fault seal data from anywhere is directly applicable to any other sealing problem, i.e., that the geohistory is not critical
Fig. 18. Reviews of the critical factors needed for an integrated seal analysis. 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.
R.J. Knipe et al.
36
to the seal evaluation. Each of these factors can have a major impact on seal analysis, induce a poorly constrained, high risk model and render detailed reservoir modelling of little value. It is interesting to evaluate the success of the simple fault seal analysis, based on the list of common assumptions outlined above, after a more detailed and integrated seal analysis has been performed. The following results from our analysis of >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.,
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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
D
~c~
(b)
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.
F.K. Lehner and W.F. Pilaar
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-
The emplacement of clay smears in synsedimentary normal faults
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
F.K. Lehner and W.F. Pilaar
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
The emplacement of clay smears in synsedimentary normal faults
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
F.K. Lehner and W.F. Pilaar
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.
The emplacement of clay smears in synsedimentary normal faults
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-
F.K. Lehner and W.F. Pilaar
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
The emplacement of clay smears in synsedimentary normal faults
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.
F.K. Lehner and W.F. Pilaar
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
P e HCwater n f c o l u m n --
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.
(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
Capillary seals versus permeability barriers Fault sealing over geological time scales 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)
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.
Fault seal processes: systematic analysis of fault seals over geological and production time scales
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.
Fault seal processes: systematic analysis of fault seals over geological and production time scales
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
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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
and A.G. Koestler. NPF Special Publication 7, pp. 61-72, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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
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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 <11 m) normal and oblique slip faults from Flamborough Head, UK, show that on individual fault traces, fault rock thicknesses vary by more than two orders of magnitude (Fig. 4). The bifurcation mechanisms for formation of multi-slip fault zones suggest that maximum fault zone thickness will often correspond to the strikenormal distance between the traces of two overlapping slip surfaces (Fig. 2c). Fault overlaps and their breached equivalents occur on faults of all sizes as do, by implication, paired and multi-slip surface fault zones. Complex and paired slip surface fault zone structures will occur on scales below that resolvable by even high quality seismic data (lateral resolution is no better than 5 0 - 1 0 0 m at North Sea reservoir depths). The possible impact of sub-seismic complexity and paired slip surfaces on connectivity and sealing across faults offsetting an Upper Brent type sequence are briefly considered below. Across-fault juxtapositions" sequence
Upper Brent
Hydraulically passive fault rocks The consequences of sub-resolution fault zone complexity can be assessed for both hydraulically passive and hydraulically active fault rocks. Hydraulically passive here refers to fault rocks which have hydraulic properties identical with their host rocks and, therefore, only primary juxtaposition effects need to be considered. Fig. 5a shows two fault zones which offset an Upper Brent sequence, each with an aggregate displacement of ca. 40 m. On the scale of observation, fault zone A comprises a single slip surface, while fault zone B comprises two parallel slip surfaces each of which accommodates about half of the total displacement. In this case the paired slip surfaces are separated by ca. 15 m of rock with low shear strain, as indicated by bedding re-orientation. Two slip surfaces would not be distinguished even with good quality seismic data. Across-fault juxtapositions calculated on the basis of a single slip surface would be valid in the case of fault A, but invalid for fault B. The consequences of incorrect juxtapositions on fault B are illustrated in Fig. 5b-d), for the Upper Brent sequence shown in Fig. 5a. Fig. 5b shows the range of across-fault juxtaposi-
66
C. Childs, J.J. Walsh and J. Watterson
a
b
Complexity in fault zone structure and implications for fault seal prediction
tions for the 84 m thick Upper Brent sequence for fault throws from 0 to 84 m; all the juxtapositions represented in this figure would occur at some point on a fault with throws from 0 to 84 m. The traces of fault zone A and both of the slip surfaces of fault zone B (Fig. 5a) are sufficiently short for the throws along them to be constant, and so to be represented in Fig. 5b by a vertical line. If the traces were longer and throws along them varied, then the locus of each fault trace in Fig. 5b would be curved rather than straight. Across-fault reservoir connectivity for a single slip surface, over the 0-84 m range of throw values, is represented in Fig. 5c. For hydraulically passive faults the across-fault connectivity is 0.65, or 65%, at zero throw and is identical with the sequence net/ gross. The connectivity is sharply decreased by even a small throw. The subsequent, approximately linear, reduction in connectivity with increasing throw, reflects the relatively regular and frequent alternation of reservoir and non-reservoir lithologies within the gross reservoir sequence (Knott, 1993). Minor irregularities in the curve are due to connectivity peaks when individual sandstone units are juxtaposed. Connectivities for fault zones comprising two slip surfaces with equal displacements are shown in Fig. 5d for aggregate throw values over the range 0-84 m; an aggregate throw of 40 m is represented by two slip surfaces each with a throw of 20 m. The connectivity for paired slip surfaces is derived from Fig. 5b as follows. For each reservoir unit within the fault zone and bounded by slip surfaces, the connectivity across each slip surface is measured and the minimum of these taken as the net connectivity for that unit. The process is repeated for all reservoir units within the fault zone and the aggregate of the net connectivities represents the connectivity of the fault zone. For the Brent sequence shown here, across-fault connectivity is higher for a single slip surface than paired slip surfaces for all throws less than 80 m. For this sequence the across-fault sandstone connectivity of fault zone A is 23% of the gross reservoir thickness, and that of fault zone B is 14%. The difference in connectivity between the two fault zones is relatively small in this example. In general, however, the
67
difference in connectivity between single and paired slip surface geometries is highly sequence dependent. For some reservoir sequences, fault zone B would have a higher connectivity than fault zone A.
Hydraulically active fault rocks Fault zones with hydraulically active fault rocks may act as either conduits or barriers to flow, but only the latter case is discussed here. Hydraulically active fault rocks in clastic reservoir sequences form primarily either by cataclasis of sandstones or by incorporation of shale into fault zones, or both. The effects on fault seal potential of fault rocks formed by cataclasis of reservoir quality sandstones are not considered. The hydraulic properties of these cataclastic rocks as measured in outcrop samples suggest that they can form hydrocarbon seals (Antonellini and Aydin, 1994), but there is no consensus on their importance in the trapping of large oil columns (Smith, 1980; Gibson, 1994). By contrast, shaley fault rocks are believed to support significant hydrocarbon columns and there is a variety of methods for relating the amount and distribution of shale in a faulted sequence to the sealing potential of faults within it (Bouvier et al., 1989; Gibson, 1994; Fristad et al., 1997, this volume). In one of the simplest and most widely applied methods, the percentage shale of that part of the sequence which has been displaced past a point is calculated for each point on the fault surface. The percentage shale calculated in this way is expressed as the shale gouge ratio (SGR), as shown colour coded in Fig. 5b. Given data on faults of known sealing behaviour in a particular reservoir or province, SGR can be calibrated to provide cut-off values for fault seal for target faults within the same reservoir or province (Fristad et al., 1997, this volume; see Implications for fault seal: fault rock distribution). The software used to produce Fig. 5b calculates SGRs, and a range of other fault seal parameters, to provide a range of uncalibrated values for a given reservoir sequence. The reservoir sequence is represented either as lithological units classified as either reservoir or non-reservoir or shale, or as a percentage shale curve as derived, for example, from a gamma log.
Fig. 5. (a) A typical Upper Brent gross reservoir sequence (reservoir units, grey; non-reservoir (shale), black) offset by two fault zones, A and B. The fault geometries are from a fault map of strike-slip faults offsetting vertical beds (Childs et al., 1996). (b) Sequence/throw juxtaposition diagram (Bentley and Barry, 1991) for the reservoir sequence shown on the left (same sequence as in (a)). The diagram illustrates the across-fault juxtapositions for the range of throw values 0-84 m, non-reservoir units are shown black. Footwall shale layers are represented by horizontal black lines and hangingwall shales by oblique lines. Reservoir/reservoir across-fault juxtapositions are colour coded (see key) according to the SGR (see text) calculated for each element of the surface area. (c) Across-fault connectivity curves for the reservoir sequence in (a) and (b). The reservoir/reservoir across-fault connectivity for a given SGR cut-off value is expressed as a proportion of the gross reservoir sequence thickness (84 m). Connectivity curves for SGR cut-off values are based on the premise that reservoir/reservoir juxtapositions are not connected if the SGR is above the specified cut-off value. The connectivity curve for SGR = 100 is the curve for simple juxtaposition, i.e., hydraulically passive faults. (d) Across fault connectivity curves for the same sequence as (c) but with the total throw distributed equally on two slip surfaces.
68 Connectivity curves for a single slip surface are shown in Fig. 5c for a range of SGR cut-off values, for the Upper Brent sequence shown in Fig. 5b. The forms of the connectivity curves are very different. For an SGR cut-off = 20 there is no connectivity for throws >33 m. For an SGR cut-off = 30, there is no connectivity for throws from 40 to 60 m, but 8% connectivity at a throw of 65 m. For an SGR cutoff = 40, there is a sharp increase in connectivity at 45 m when the Tarbert and Lower Ness reservoirs become juxtaposed. Connectivity curves for paired hydraulically active slip surfaces can be calculated by the same method used for hydraulically passive faults. Connectivity curves for a range of SGR cut-off values are shown in Fig. 5d. For the Upper Brent sequence the connectivity of a single slip surface, for a given SGR cutoff, is generally higher than that for a fault zone with paired slip surfaces. The difference in connectivity between paired and single slip surface geometries is greatest at an SGR cut-off = 40. Although connectivities for the single and paired slip surfaces, at SGR cut-off = 40, are equal at a throw of 25 m, they are 24% (the same as that for a hydraulically passive fault) and 3%, respectively, at a throw of 50 m. For an SGR cut-off = 20 the connectivities for the single and paired slip surfaces are similar at all throws, so the sequence is insensitive to fault zone structure at this cut-off value. These variations in relative connectivities between single and paired slip surface geometries illustrate the complexity and non-linear consequences of multiple slip surfaces.
Summary The significance of sub-seismic fault zone complexity to calculation of across-fault connectivities and of fault seal potential is very strongly dependent not only on the amount but also on the distribution of non-reservoir and shale units within the gross reservoir sequence. The effect of an increased number of slip surfaces within a fault zone is twofold, namely increased average connectivity across individual slip surfaces and increased probability of an individual reservoir unit being juxtaposed against a nonreservoir layer or shaley fault gouge. Complex interplay between these two opposing effects determines the overall connectivity of a fault zone. Fault surface bifurcation processes result in areas of a fault zone with paired bounding slip surfaces alternating with areas with only a single slip surface. Either laterally or up-/down-dip, the two slip surfaces of fault zone B may give way to a single slip surface. Similarly, it is unlikely that fault zone A is characterised everywhere by only a single slip surface. As
c. Childs, J.J. Walsh and J. Watterson
there is no requirement for displacement to be partitioned equally between two slip surfaces, the range of possible connectivities across a 40 m fault zone is much greater than is indicated by the simple example illustrated. If more than two slip surfaces are present, the range of possible connectivities is increased further. The complexity of sequence juxtapositions due to sub-seismic fault zone structure is therefore compounded by the 3-D variation of fault zone structure. We consider that the sensitivity of individual sequences to partitioning of slip onto multiple slip surfaces in 3-D can be assessed only in very general terms. Although sensitivity studies can be performed, existing empirical methods, which implicitly incorporate sub-seismic fault zone complexity, may represent the best approach to fault seal prediction (see below).
Implications for fault seal: fault rock distribution The combined effects of the asperity and tip-line bifurcation processes can result in the formation of fault zones with highly complex internal geometries and highly variable fault rock compositions and distributions. Even detailed information on the fault rocks at a point on the fault zone shown in Fig. 3a-c, as would be provided by a well for example, would not enable valid extrapolation even to nearby parts of the fault zone. The implications of fault zone complexity for the distribution of potential sealing lithologies over a fault surface are illustrated in Fig. 6a which shows a cross-section through a shale-rich normal fault zone. Two distinct layers of shale-derived fault rock are present, a thicker layer derived from an 8 m thick shale source layer and a thinner gouge layer derived from thinner shale units within the footwall sequence. This fault zone has paired external slip surfaces with the intervening rocks intensely deformed. One slip surface occurs along the very thin lower layer of shale gouge and the other along the contact between the thick shale layer and the hangingwall sandstones. The fault zone thins upwards from 2 m at the base of the illustrated section to 1 m at the top. Both the relative and absolute thicknesses of sandstone and shale within the fault zone are determine by lenses of footwall derived sandstone, so the thickness of shalederived fault rock varies rapidly within the section. Rapid changes in both fault rock deformation state and fault rock composition also occur along the fault strike. Fig. 7 shows a map section through a fault of similar throw and offsetting the same sequence as the fault shown in Fig. 6. The mapped surface is 1-2 m below the footwall cut-off of the 8 m thick shale unit and shows paired bounding slip surfaces. The fault
Complexity in fault zone structure and implications f or fault seal prediction
a
69
distribution precludes the possibility of these breccias forming a seal. The shales within these fault zones show highly irregular thickness variations but, nevertheless, display a high degree of conl~inuity. The sealing integrity of a fault would be maintained if this continuity occurred over the whole fault surface. However, given the very small proportion of an entire fault surface which is represented by any single crosssection or map trace, nothing can be concluded about the likelihood of a continuous shale layer over the whole fault surface. A cross-section through a series of minor faults offsetting a mixed sandstone shale sequence (Fig. 8)
b
Fig. 6. (a) Cross-section through a normal fault in a Carboniferous mixed sandstone/shale sequence from a quarry in Lancashire, UK. The fault dips to the left, with a throw of ca. 15 m. (b) Sketch of the outcrop in (a). The well developed shale gouge layer within the fault zone (black) is derived from an 8 m thick shale unit. The base of this shale unit is ca. 1 m above the top of the exposed face in the footwall and 1.5 m below ground level in the hangingwall. The fault separates sandstones in the hangingwall (stippled) from a mixed sandstone (no ornament) and shale (black) footwall sequence. Dense coarse stipple indicates sandstone breccia. Mixed sandstone and shale breccias are shown shaded with a coarse stipple. The boundary between the fault zone and the footwall country rock is a slip surface with a thin (<2 cm), but continuous, layer of clay gouge; this gouge layer is too thin to be represented in the figure. Only structural features which are clearly not the result of quarrying activity are shown in (b).
rocks include shale gouge, sandstone breccias and relatively undeformed blocks of sandstone and shale within which bedding has been rotated towards the hangingwall, as shown in the vertical cross-sections. The fault zone is of more or less constant thickness (2 m) over its mapped length but the fault rock content is highly variable. On cross-section C the fault zone contains 2 m of shale, of varying degree of deformation, while 8 m along-strike (cross-section B) the shale component is reduced to 3 cm of shale gouge. These rapid variations in fault rock content and, particularly, in the content of potentially sealing lithologies raise the question of whether or not deterministic predictions of fault seal potential are feasible. Sandstone derived breccias within the fault zones shown in Figs. 3, 6 and 7 occur either as thin sheets of limited extent or as localised lenses. This patchy
Fig. 7. Map (left) and three cross-sections, A-C, through a normal fault with ca. 15 m throw. The fault offsets the same sequence as shown in Fig. 7. The mapped surface is at a level ca. 1 m below the top of the outcrop in Fig. 6. Deformed shale, either strongly foliated or shale gouge, is shown in black. Shale with preserved bedding is dark shaded with broken lines indicating approximate bedding orientations. Hangingwall sandstones are ornamented with regular stipple and footwall sandstones with irregular stipple. Sandstone bedding directions on cross-sections are shown by thin lines. Sandstone breccias are indicated by a coarse stipple. The boundary between the fault zone and the footwall sandstones on cross-sections B and C is a discrete slip surface.
70
C. Childs, J.J. Walsh and J. Watterson
t
2m
Fig. 8. Cross-section showing a number of small faults offsetting a carboniferous sandstone/shale sequence. Thin shales are shown as subhorizontal lines. Fault traces are shown as steep lines and those with shale smears are shown as wide grey lines. There is no horizontal connectivity across this 2-D section but 3-D connectivity is likely.
shows the frequency with which shale is incorporated into the fault zones and the apparent absence of sandstone connectivity. However, this 2-D section allows no conclusion to be drawn concerning the sandstone connectivity in 3-D. The observations reported here are consistent with those of Lindsay et al. (1993) who concluded that for faults in the same working quarry as Figs. 3, 6, 7 and 8, shale smears in outcrop can be discontinuous when the displaced sequence has an SGR value of <15. This SGR value does not, however, imply a sharp cut-off and continuous shale smears do occur at SGR values <15. These results are broadly comparable with those of Fristad et al. (1997), who find that significant static seal on subsurface faults does not occur for SGR values <15 but does occur at SGR values >18. Gibson (1994) estimates the SGR cut-off value to be 2 2 - 3 0 . Variation in SGR cut-off values is expected for different datasets from different geological settings (Fristad et al., 1997). Observations of shale smear continuity from outcrop are not directly comparable with SGR cutoffs derived from sub-surface datasets, because outcrop observations are small scale and generally only 2-D (Gibson, 1994) and do not allow assessment of the sealing effects of shale-derived fault rock in the 3-D system. A mechanism by which regular and continuous clay smears are generated on relatively low strain rate faults in soft sediments has been described by Weber (1978) and Lehner and Pilaar (1997, this volume). Soft-sediment faults are effectively ductile shear zones and may lack the discontinuities and complexity typical of fault zones, in rocks of either low or high shear strength, characterised by high instantaneous slip rates, i.e., "brittle" faults. Although the faults we have described formed in already lithified sedi-
ments (Lindsay et al., 1993) and the clay smears do not show the thickness regularity of those described by Weber (1978), the continuity of the clay smears may be comparable. The frequency of thick shale smears in the quarry (as in Figs. 6 and 7) is such that the local quarrymen refer to them as "vertical shales".
Discussion Faults are not directly imaged on seismic sections but interpreted, where reflections are offset, as discrete fault surfaces. It is acknowledged by interpreters that these discrete surfaces may comprise two or more seismically unresolved slip surfaces. The bifurcation model of fault growth implies that multi-slip surface fault zones are the rule rather than the exception and that there will be a minimum of two discrete slip surfaces on at least some places on a fault zone. More generally, the high degree of complexity within brittle fault zones, which is evident on all scales of observation, means that no fault surface can be fully defined in three dimensions and on the relevant scale. The fault zone structure observed either at a point or on a cross-section of the fault surface, cannot be extrapolated any significant distance from the point or line of observation. Given these limitations, we question whether it is possible, even theoretically, to predict deterministically the sealing potential of fault zones in the sub-surface. Clearly, detailed observations of fault zones have a role in fault seal prediction. Data from wells which penetrate fault zones can be used to determine both the deformation mechanisms which operated and the fault rocks which are present or which are likely to occur. However, well data provide no constraints on the spatial distribution of the fault rocks and on the sealing potential of faults
Complexity in fault zone structure and implications f or fault seal prediction
on geological timescales. The poroperm properties of fault rock sampled from wells may provide useful constraints on the permeabilities of faults for production timescale flow simulations A contrasting approach to fault seal prediction is to apply the empirical method by which a prediction is made simply on the basis of the known behaviour of comparable faults. We suggest that progress will best be made by moderating the extreme empirical approach by applying deterministic methods to quantifying the degree of comparability between a target fault and faults of known behaviour. An important aspect of an empirical approach is quantifying the degree to which one fault can be considered a valid hydraulic analogue of another. Methods of fault seal prediction employing empirical databases in which faults of known sealing capacities are characterised by reference to shale smear parameters (Gibson, 1994; Fristad et al., 1997, this volume; Lehner and Pilaar, 1997, this volume) represent a combination of the deterministic and empirical approaches. The methods of shale smear parameterisation are, implicitly or otherwise, based on the assumption of a regular and predictable distribution of shale-derived fault rock within a fault zone. While the complexity in fault zones suggests that the juxtaposition diagrams on which these methods are based may not represent the actual across-fault juxtapositions, the methods have nevertheless achieved a measure of credibility within the industry. This apparent contradiction can, however, be resolved. Although the constructions on which fault seal potential calculations are based take no account of subseismic complexity of fault zones, the complexity is incorporated implicitly in the databases against which fault seal potentials are calibrated. For some reservoir sequences, calculated fault seal potentials are to some degree independent of a certain level of fault zone complexity. Figs. 6 and 7 illustrate the extreme spatial variation in thickness of shale-derived fault rock within a fault zone but, together with Fig. 8, they also demonstrate the high degree of continuity of shalederived fault rocks which can occur. It is this continuity of shale-derived fault rock which, despite the complexity of its distribution, provides a physical basis for methods of prediction of fault seal potential based on shale smear parameterisation.
Conclusions Observations show that the internal structure of fault zones is highly complex, largely as a consequence of bifurcation processes. Simple examples of fault zone complexity, in which displacement on a fault of constant displacement is partitioned onto two
71
slip surfaces, illustrate the sensitivity of across-fault connectivity to fault zone structure. In general fault zones have multiple slip surfaces separating volumes of mildly to intensely deformed rock, with chaotic spatial variation in structure of the fault zone. We question whether it is even theoretically possible to characterise deterministically, complex fault zone architectures of subsurface faults, given the limited data available. Empirical risking methods implicitly take account of the unpredictable complexities in fault zone structure which inevitably are present. The way forward is by further refinement of current empirical methods, i.e., by more detailed characterisation of sub-surface faults to allow more objective comparison of target faults and faults of known sealing behaviour.
Acknowledgements This research was part funded by the EC Joule II Reservoir Engineering Project (Contract No. JOU2CT92-0182) and the EC Joule III PUNQ Project (Contract No. JOF3-CT95-0006). The lithological sequence in Fig. 5 was interpreted by Kees Geel from a well log provided by Norsk Hydro. We are grateful to Barry Murphy and Nick Lindsay for fieldwork leading to the production of Fig. 8. We thank Marie Eeles for help in preparing the manuscript. Peter Keller and Andreas Koestler are thanked for their helpful reviews of the manuscript.
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. Barnett, J.A.M., Mortimer, J., Rippon, J., Walsh, J.J. and Watterson, J. 1987. Displacement geometry in the volume containing a single normal fault. Am. Assoc. Pet. Geol. Bull., 71: 925-937. Bentley, M.R. and Barry, J.J. 1991. Representation of fault sealing in a reservoir simulation: Cormorant block IV UK North Sea. In: 66th Ann. Tech. Conf. and Exhibition of the Soc. Pet. Engineers, Dallas TX, pp. 119-126. Blenkinsop, T.G. 1989. Thickness-displacement relationships for deformation zones: discussion. J. Struct. Geol., 11: 1051-1054. 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. Childs, C., Watterson, J. and Walsh, J.J. 1996. A model for the structure and development of fault zones. J. Geol. Soc. London, 153: 337-340. Engelder, T. 1978. Aspects of asperity-surface interaction and surface damage of rocks during experimental frictional sliding. Pure Appl. Geophys., 116: 705-716. Evans, J.P. 1990. Thickness-displacement relationships for fault zones. J. Struct. Geol., 12: 1061-1065. Fristad, T., Groth, A., Yielding, G. and Freeman, B. 1997. Quantitative fault seal prediction: a case study from Oseberg Syd. In: P. Mr and A.G. Koestler (Editors), Hydrocarbon Seals:
C. Childs, J.J. Walsh and J. Watterson
72 Importance for Exploration and Production. Norwegian Petroleum Society (NPF), Special Publication No. 7. Elsevier, Singapore, pp. 107-124. Gibson, R.G. 1994. Fault zones seals in siliciclastic strata of the Columbus Basin, offshore Trinidad. Am. Assoc. Pet. Geol. Bull., 78: 1372-1385. Griffiths, P.S. 1980. Box-fault systems and ramps: atypical associations of structures from the eastern shoulder of the Kenya Rift. Geol. Mag., 117: 579-586. Huggins, P., Watterson, J., Walsh, J.J. and Childs, C. 1995. Relay zone geometry and displacement transfer between normal faults recorded in coal-mine plans. J. Struct. Geol., 17: 1741-1755. Hull, J. 1988. Thickness-displacement relationships for deformation zones. J. Struct. Geol., 10: 431-435. Knipe, R.J. 1992. Faulting processes and fault seal. In: R.M. Larsen, H. Brekke, B.T. Larsen and E. Talleras (Editors), Structural and Tectonic Modelling and its Application to Petroleum Geology. Norwegian Petroleum Society Special Publication (NPF), Special Publication 1. Elsevier, Amsterdam, pp. 325-342. Knott, S.D. 1993. Fault seal analysis in the North Sea. Am. Assoc. Pet. Geol. Bull., 77: 778-792. Koestler, A.G. and Ehrmann, W.U. 1991. Description of brittle extensional features in chalk on the crest of a salt ridge (NW Germany). In: A.M. Roberts, G. Yielding and B. Freeman (Editors), The Geometry of Normal Faults, Special Publication 56. Geol. Soc. London, pp. 113-123. Larsen, P.-H. 1988. Relay structures in a Lower Permian basementinvolved extension system, East Greenland. J. Struct. Geol., 10: 3-8. Lehner, F.K. and Pilaar, W.F. 1997. On a mechanism of clay smear emplacement in synsedimentary normal faults. In: P. Mr Pedersen and A.G. Koestler (Editors), Hydrocarbon seals: Importance for Exploration and Production. Norwegian Petroleum Society (NPF), Special Publication 7. Elsevier, Singapore, pp. 39-50.
C. CHILDS J.J. WALSH J. WATTERSON
Lindsay, N.G., Murphy, F.C., Walsh, J.J. and Watterson, J. 1993. Outcrop studies of shale smears on fault surfaces. In: S. Hint and A.D. Bryant (Editors), The Geological Modelling of Hydrocarbon Reservoirs and Outcrop Analogues. Int. Assoc. Sediment., 15: 113-123. Otsuki, K. 1978. On the relationship between the width of shear zone and the displacement along fault. J. Geol. Soc. Jpn., 84:661-669. Peacock, D.C.P. and Sanderson, D.J. 1991. Displacements, segment linkage and relay ramps in normal fault zones. J. Struct. Geol., 13: 721-733. 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. Robertson, E.C. 1983. Relationship of fault displacement to gouge and breccia thickness. Soc. Mining Eng., Am. Inst. Mining Eng. Trans., 35: 1426-1432. Segall, P. and Pollard, D.D. 1983. Joint formation in granitic rock of the Sierra Nevada. Am. Assoc. Pet. Geol. Bull., 94: 563-575. Smith, D.A. 1980. Sealing and non-sealing faults in Louisiana Gulf Coast salt basin. Am. Assoc. Pet. Geol. Bull., 64: 145-172. Stewart, I.S. and Hancock, P.L. 1991. Scales of structural heterogeneity with neotectonic normal fault zones in the Aegean region. J. Struct. Geol., 13:191-204. 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. In: 10th Ann. Offshore Technology Conf., Soc. Pet. Eng., Paper No. 3356, pp. 2643-2653. Wolf, R. 1985. Tiefentektonik des linksneiderrheinischen Steinkohlengebietes. In: G. Drozdzewski, H. Engel, R. Wolf and V. Wrede (Editors), Beitr~ige zur Tiefentektonik westdeutscher Steinkolhlenlagerst~itten, Geologisches Landesamt NordrheinWestfalen, Krefeld.
Fault Analysis Group, Department of Earth Sciences, University of Liverpool, Liverpool, L69 3BX, UK Fault Analysis Group, Department of Earth Sciences, University of Liverpool, Liverpool, L69 3BX, UK Fault Analysis Group, Department of Earth Sciences, University of Liverpool, Liverpool, L69 3BX, UK
73
Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties R.H. Gabrielsen and O.S. Klovjan
The late Callovian-Oxfordian Fuglen and Oxfordian-Ryazanian Hekkingen Formations of the Teistengrunnen Group provide cap rocks for the bulk of the hydrocarbon structures drilled so far in the southwestern Barents Sea. Remnant oil is common in many of the drilled structures, and it has been suggested that Eocene-Oligocene and late Neogene to Pleistocene uplift and erosion caused cap rock failure and hydrocarbon leakage. Investigations of cores have revealed that fracturing is common throughout the study area. Still, considerable differences with regard to fracture frequencies, fracture orientation and distribution exist. Four main groups of fractures have been identified. Group I and II fractures are presumably related to burial and/or unroofing. The frequencies of fractures of these groups are low, and these fracture types are regarded as a minor risk for hydrocarbon leakage on the regional scale. Fractures of group III are low-angle structures, probably making up comprehensive fracture networks near and within 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. Although experiments suggest that these types of fracture have small apertures when loaded, they are still regarded as potential conduits for transport of hydrocarbons. Group IV fractures are rare, mainly subhorizontal structures which can contribute little to hydrocarbon migration.
Cap rock problems and hydrocarbon leakage in the southwestern Barents Sea In the early phase of hydrocarbon exploration in the southwestern Barents Sea (Fig. 1) several promising gas discoveries were made in the Hammerfest Basin area (Alke and Askeladden in 1981; Albatross in 1982; e.g., Westre, 1984). The reservoir zones are situated in the mid-Jurassic Str Formation (Fig. 2), and the discoveries were associated with moderately rotated fault blocks. Oil shows were frequent in the cores below gas zones, but wireline log data showed that these parts of the formations carried water. The first significant oil leg (15 m) in the Barents Sea was encountered below the gas zone in the SnChvit Field, but also in this case traces of oil were reported to occur in the deeper, presently water-saturated part of the reservoir (Linjorde and Grung-Olsen, 1992). It was clear that the Hekkingen Formation, which is the principle source rock in the area, had more than sufficient potential to fill the major structures of the Hammerfest Basin. Recent studies have confirmed that many of the traps in the southwestern Barents Sea, now dry, have been filled by hydrocarbons (Augustson, 1993), and that leakage accordingly is a problem of regional dimensions (Nyland et al., 1992). Several explanations for hydrocarbon leakage in the southwestern Barents Sea have been attempted. Although tilting of fault blocks and lack of continuity of the cap rocks may provide the simplest explanations, modelling suggests that other mechanisms must
be evaluated. Thus, Nyland et al. (1992) and Skagen (1992), in calculating expansion of the hydrocarbon phase resulting from Eocene-Oligocene and late Neogene to Pleistocene uplift and erosion, which in total amounts to between 1000 and 2000 m or more in the southwestern Barents Sea, concluded that this effect was sufficient to cause the observed hydrocarbon spill. In a rock mechanical model study, Makurat et al. (1992) demonstrated that failure of the Hekkingen Formation cap rock may occur due to build-up of deviatoric stresses during uplift and unroofing. Still, since there seems to be a close correlation between the present oil-water-contacts, the spill-point of the structures, and geophysical anomalies ascribed to gas accumulations, and the presence of reactivated faults (Fig. 3), leakage of hydrocarbons along reactivated fault planes may not be entirely ruled out.
Structural history of the southwestern Barents Sea The southwestern Barents Sea continental shelf is dominated by ENE-WSW to NE-SW, and NNE-SSW to NNW-SSE trends with local influence of WNWESE- to E-W-striking elements (Faleide et al., 1984, 1993; Gabrielsen et al., 1990). In the southern part of the Barents Sea, a regional ENE-WSW grain is defined by the major fault complexes bordering the Hammerfest and Nordkapp Basins. To the west and northwest, N-S trends prevail (Tromsr Basin, Knr Fault, Hornsund Fault Complex).
Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mr
and A.G. Koestler. NPF Special Publication 7, pp. 73-89, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
74
R.H. Gabrielsen and O.S. KlCvjan
Fig. 1. Main structural features of the southwestern Barents Sea, and locations of wells used in the present study. Geology after Gabrielsen et al. (1990).
The major regional fault zones in the Barents Sea were probably established by Carboniferous times. In the subsequent structuring of the southwestern Barents Sea area, activity was associated with these important elements, causing repeated reactivation of the fault complexes (Gabrielsen, 1984). After Carboniferous structuring, and following a tectonically quiet period in the Triassic, block-faulting started in midJurassic. During the period from late Jurassic and into the early Cretaceous, the fault activity increased, terminating with formation of the major basins and highs, with extreme subsidence in the Tromsr Basin and the BjCrnCya Basin during Aptian-Albian. Indications of local early Cretaceous inversion occur,
e.g., along BjCmCyrenna Fault Complex (Gabrielsen et al., 1992, 1997a), near the junction between the RingvassCy-Loppa Fault Complex and the Asterias Fault Complex and along the Trollfjord-Komagelv fault trend (Gabrielsen and Fa~rseth, 1989). Towards the end of the Cretaceous period, reverse faulting and folding, combined with extensional faulting in some areas, became locally more abundant, even though subsidence may have prevailed on the regional scale. Inversion peaked in early Tertiary times, and was followed by severe regional uplift and erosion in the Pliocene-Pleistocene (Nansen, 1904, 1920; Nyland et al., 1992; Riis and Fjeldskaar, 1992; Gabrielsen et al., 1997a).
Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties
Fracture types in Fuglen and Hekkingen Formations Rocks of the late Callovian-Oxfordian Fuglen and Oxfordian-Ryazanian Hekkingen Formations of the
75
Teistengrunnen Group (Fig. 2) commonly provide the hydrocarbon seal in the basin areas of the southwestern Barents Sea. These are predominantly dark grey to brownish shales and pyritic mudstones interbedded by stringers of limestones. The Hekkingen Formation may locally contain dolomites, silt and sandstone (Dalland et al., 1988). A total of 92 m of cores of the Fuglen and Hekkingen Formations, and 9 m from the Ryazanian/Valanginian-Barremian Knurr Formation from nine wells (7321/9-1, 7219/9-1, 7120/2-2, 7120/6-1, 7120/12-1, 7125/1-1, 7228/2-1, 7228/9-1 and 7117/92) (Fig. 1) were included in the present study. With the exception of wells 7120/6-1, 7117/9-2 and 7324/10-1, where only mounted B-cuts were avail, able, the cores were inspected both previous to and after core slabbing. The fracture analysis included fracture frequency studies, orientation studies, fracture- characterisation (core inspection, light microscope and electron microscope investigation)and rock mechanical experiments. All fractures observed, including those ascribed to drilling and core handling, were included in the original fracture logs. In the final logs, which were applied for statistical calculations and further descriptions, however, "artificial" fractures were excluded. To identify this type of structure, the criteria suggested by Arthur et al. (1980), Carson et al. (1982), and Lundberg and Casey Moore (1982) were applied. Core discing is common in shales and mudstones in the study area. Surfaces of this type of structure are either dull with parallel-oriented flaky mineral grains, or glossy to lustrous, in a few cases with faint traces of slickenside lineations. The former is considered to represent the primary fissability of the rock, and were not included in the final logs. Based on fracture morphology, characteristic mineralogy and orientation, a classification system of the main fracture types was constructed. An overview of the fracture characteristics and their distribution as given below is summarised in Table 1.
Fracture types
Fig. 2. Stratigraphic column, Barents Sea. Arrows indicate the units studied. After Gabrielsen et al. (1997a), based on Dalland et al.
(1988).
Planar fractures represent the most common fracture type in the investigated rocks of the Fuglen, Hekkingen and the Knurr Formations, and approximately 70-90% of the structures fall into this group. The planar fractures are commonly single structures, but are also found in clusters of 2-5, and as swarms of more than 5 closely spaced parallel or sub-parallel fractures. Based on morphology, the planar fractures are subdivided into four sub-types. Type FI are polished, glossy fractures without or with faint slickenside striations (Fig. 4a). This frac-
76 R.H. Gabrielsen and O.S. KlCvjan
o
~9
.=.
t~ o
r~
. ,.q
Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties Table 1 Geometrical/morphological classification of fractures in cap rocks of the southwestern Barents Sea Type
III IV V VI
Characteristics
Mode
Polished, faint slicken side lineations Growth of illite occ. plumose markings Strong slicken side lineations Slightly wavy surfaces Wave, heavily striated surfaces Low-angle with mineral fill Fibrious calcite c. Listric, small scale Planar/curvi-planar, smooth surfaces
Tensile (I) (dominant) Shear (II) Shear (II) Tensile (I) Shear (II) Tensile (I)
ture type is found in most of the investigated cores. It may constitute complete, remarkably smooth (Fig. 4b) surfaces on the scale of the core, or may be typical of a certain part of the fracture surface, perhaps indicating a step-wise development. In most cases, however, a faint pattern of slickenside striations is found on closer inspection in the scanning electron microscope. Thin section studies reveal mineral grain rotation and growth of tiny white illite flakes. The illite grains are frequently oriented at an angle of 2530 ~ to the fracture planes, indicative of shear along the fractures (Fig. 4c). There are also examples of combinations of growth of illite parallel to, and at right angle to the fracture surfaces (Fig. 4d). The latter situation suggests that extension has taken place across the fracture (Groshong, 1975; Ramsay and Huber, 1987). Type FII are polished fractures with well developed slickenside striations (Fig. 4e,h) and are the most common type of tectonic feature in the cap rocks investigated. The surfaces are commonly slightly wavy, and more than one set of slickenside lineations may occur. These may represent two different stages of deformation (Fig. 4f), but there are good examples of slickenside lineations which seem to belong to one single set, but which have angular linear geometries, suggesting deflection of the relative movements during deformation (Fig. 4g). Slickenside striations both parallel, oblique and perpendicular to the strike of fractures are observed, indicating strike-slip as well as oblique and dip-slip displacements. Particularly in the wells of the BjCmCyrenna Fault Complex, oblique slickenside striations are frequently seen. Also in Type FII fractures mineral rotation and growth of white mica adjacent to fracture planes are common. The mica flakes may be oriented both parallel and perpendicular to the fracture surfaces. Type Fill, wavy, heavily striated fractures, are not common, but have been recorded in a few cases. This fracture type seems to be more common in the more
77
silty lithologies, and mica growth has not yet been recorded in association with these structures. Examples of type FIII-fractures are given in Fig. 4i,j. Fracture types FI-FIII may be characterised by their striation frequencies ~ = striations/ktm as measured transverse to the striation strike-line). Table 2 gives one example of results from striation countings from well 7321/9-1, illustrating that type FI and FII fractures have typical fs values in the range of 0.0100.035, significantly different from type FIII which has typical f~ values of 5.5-8.3 x 10-3. Type FIV, low-angle fractures with mineral fracture fill, are seen in a few cases. They are commonly oriented parallel to bedding, or are cutting the bedding by a small angle. Fibrous mineral growth with fibres at right angles to the fracture surfaces indicates that the fractures may be related to vertical stress release (Fig. 4k,1). Type FV are listric, small-scale structures, usually restricted to one layer or a small scale sequence. A (small scale) detachment fault is usually developed. Type FVI, planar to curviplanar, smooth fractures without slickenside striations or polished surfaces, are frequently recorded. They are often blind on the scale of the core, or may end at bedding surfaces or other fractures. It has not been possible to determine absolute offsets on any fractures, mainly due to lack of marker horizons on the cm and mm scales. Planar fractures with polished surfaces and slickenside lineation are interpreted by most authors to be tectonic in origin. Arthur et al. (1980) and Carson et al. (1982) stressed that mineralization is a meaningful criterion for the identification of natural fractures, whereas Lundberg and Casey Moore (1986) added healed fractures which restore cohesion across the fracture plane as an equal criterion. Most planar
Table 2 Striation frequency (fs) correlated to fracture type. Example from well 7321/9-1 Depth (m)
Type
fs
1366.00 1366.00 1366.10 1366.10 1366.10 1366.10 1366.10 1366.20 1366.20 1366.20 1366.20 1366.20 1367.00 1370.00
FII FII FI FII FII FII FII FII FII FII FII FII Fill Fill
0.010 0.038 0.035 0.022 0.021 0.012 0.055 0.017 0.018 0.020 0.051 0.036 5.46 x 10-3 8.27 x 10-3
78
R.H. Gabrielsen and O.S. KlCvjan
Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties
79
80 R.H. Gabrielsen and O.S. KlCvjan
Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties
Fig. 4. (a) Composite planar fracture, well 71 1719-2,depth 3477.20 m; (b) SEM imagery of Type FI surface, well 7219/9-1. Scale bar is 48.5 pm. (c) Micrograph of fracture, type FI, perpendicular to fracture surface, well 7219/9-1, 1934.25 m. Note grains of illite growing with an angle of approximately 25-30" to the fracture surface. (d) Growth of illite associated with planar fracture surface type F1, well 721919-1, 1942.50 m. Note that illite growth is both parallel to and at a right angles to the fractures. ( e ) Type FII fracture, with dip-parallel slickenside lineation, well 7219/9-1, 1934.20 m. (f) Type FII fracture with composite, oblique slickenside lineation. Well 71 17/9-2, 3477.65 m. (g) SEM imagery of fracture with slickenside lineation, Fuglen Formation, well 7321/9-I, 1366.00 m. Note change in strike of striation, indicating change in relative movement. Scale bar is 31.9pm. (h) SEM imagery, slickensided fracture surface, well 7219/9-1, 1934.45 m. On this scale, the slickensides appear as a series of grooves. Scale bar is 386pm. (i) Type FIII fracture. Well 721919-1, 1934.20 m. (i)Thin section across surface of type FIII fracture, Fuglen Formation, well 7321/9-1, 1370 m. (k) Mineral fill on planar fracture surface. Well 712012-2, 2639.70-75 m RKB. (I) Micrograph of calcite mineralisation on fracture surface. Well 7228/2-I, 1172.50m RKB. (m) Scaly foliation, well 7120/2-2. (n) Scaly foliation, well 7321/9-1.
81
82
fractures of types FI, FII and Fill satisfy one or more of these criteria. Thus, many of the fractures are healed, and the samples split along the fracture planes only when knocked upon or during slabbing. As described above, slickenside lineations are frequent, as well as recrystallization/mineralization along fracture planes, and in some cases mineral fill is observed. It is therefore concluded that the bulk of the planar fractures of types FI, FII and FIII are tectonic in origin. Type IV (subhorizontal) fractures were probably initiated during unloading and/or anomalously high fluid pressure build-up. Some of the type IV fractures are filled by fibrous carbonate, confirming tensile origin, and that the fractures were activated in situ. It 9is still reasonable to assume, however, that some of the type IV- fractures, which are not filled by minerals, were generated during stress release when brought to the surface. Fractures of type FV probably represent soft sediment deformation or collapse associated with water escape, whereas the origin of type FVI fractures is more uncertain. It seems, however, most reasonable to ascribe the latter structures to drilling, core handling or drying during storing. The origin of type VI fractures is enigmatic, but it may be speculated that these are associated with volume reducing processes during burial. Since this fracture type is rare, no further steps have been taken to determine their origin.
Rubble zones, anastamosing fractures, scaly foliation and breccias Rubble zones are very common in cored mudstones and shales in many regions of the Norwegian continental shelf, and the southwestern Barents Sea seems to be no exception. Three types of rubble zones are recorded in the wells investigated. Type RI is characterised by pencil-shaped fragments with hackly or rough surfaces. X-Ray tomographic investigations of similar structure elsewhere has show that such fragments are commonly oriented parallel to the core axis (Gabrielsen and Koestler, 1987; their Plate lh), and accordingly should be regarded as drilling-induced artificial structures. Type RH contains tablet-shaped fragments with smooth larger ("upper" and "lower") surfaces and rough to irregular smaller "side walls". The larger surfaces have the morphology which is typical of undeformed bedding, and it is reasonable to interpret the
R.H. Gabrielsen and O.S. KlCvjan
type RII rubble zones to represent the original fissibility of the rock. Type Rill rubble zones are frequently associated with anastamosing fractures, and are characterised by lens-shaped chips with slickensided surfaces (Fig. 4m,n). In the electron and light microscopes, the morphologies and textures of the fractures defining the surfaces of the fragments are similar to those seen on planar fracture surfaces of type FII (see above). Rubble zones of types RI and RII are not considered to have any tectonic implications. In contrast, rubble zones of type RIII, which are characterised by slickensided lens-shaped chips are typical of tectonized zones (faults) (Lundberg and Casey Moore, 1986), and have been reported to be typical in accretionary complexes (shear-fracture fabric (Cowan, 1974) and pervasively sheared fabric (Hsia, 1974)). It is noted that slickensided lens-shaped chips are also typical of pedogenic structures (Buol et al., 1980; Gray and Nickelsen, 1989). Pedogenic slickensides typically occur in the upper part of fining-upward sequences of floodplain and upper delta-plain facies, which have experienced multiple cycles of wetting and drying. Still, most zones of scaly structure encountered in the cores presently investigated are believed to be of tectonic rather than pedogenic origin because: (a) the scaly foliation is frequently associated with or delineated by anastamosing fractures which dip steeper than the bedding; (b) zones of scaly foliation are developed in well defined zones which do not seem to reflect any contrast in primary texture or composition; (c) the fragments of the zones are truly lensoid in shape, rather than trapezoid which may be expected for pedogenic structures; and finally (d) since the shales of the Fuglen and Hekkingen Formations were deposited in a marine environment, multiple cycles of wetting and drying are difficult to imagine. Accordingly, it seems most reasonable to interpret rubble zones of type RIII to be intensely deformed zones, most likely faults with throws in the order of decimetres or metres.
Observed fracture frequencies and dip relations Figure 5 summarises fracture frequencies and dip relations as recorded in the wells investigated. The diagrams demonstrate that the fracture frequencies vary considerably and unsystematically with depth, and between the wells. The fractures which are of
Fig. 5. Diagram showing lithology, fracture frequency, fracture orientation and rock strength of Fuglen Formation in (a) well 7321/9-1, (b) well 7219/9-1, (c) well 7120/2-2, (d) well 7120/6-1, (e) well 7120/12-1 and (f) well 7228/9-1.
Late Jurassic-early Cretaceous caprocks of the southwestern Barents Sea: fracture systems and rock mechanical properties
a Core Oep
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R.H. Gabrielsen and O.S. KtCvjan
84
tectonic origin, and which define observable angles to the bedding, are recorded in the ft column in the logs (ft = number of fractures per core meter). Rubble zones and zones of scaly foliation believed to be of tectonic origin, have also been marked individually. Dips of fracture planes have been measured whenever possible. Except for well 7125/1-1, the cores are not oriented, and strikes of fractures are accordingly generally unknown. Dip measurements have preferentially been carried out on unslabbed cores, or on Acuts. For some of the cores, however, only B-cuts have been available. In these cases, dip measurements are less reliable, and even a minimum dip angle may be difficult to assess. In such cases, the measurements were excluded from that database. The dips were measured assuming that the core axis is vertical. In general, the dips are measured with an estimated error of less than 5 ~. This is in accordance with similar estimates of errors of dip measurements in cores done by others (e.g., Lundberg and Casey Moore, 1986). As seen from Fig. 5, there are considerable differences in fracture frequencies and fracture orientation between the rocks of the Teistengrunnen Group encountered in the wells of the study area. For geological interpretation of the fracture systems, data presented in Fig. 5 need to be combined with "fracture dip profiles" which illustrate the distribution in percent of fractures (y-axis) with different dips (x-axis) (Fig. 6). The figures illustrate a clear difference between the three main fault complexes. The fracture dip profiles from the BjCrnCyrenna Fault Complex display a Poisson distribution with a clear dominance of low-angle fractures, whereas results from the Hammerfest and Nordkapp Basins reveals a Gaussian distribution with a maximum for the dip angle around 50 ~ Also steep dip angles (80-90 ~ are seen in the latter domain. (In evaluating the "fracture dip profiles", it should, however, be noted that the total number of fractures in the eastern basin areas is only 15 as compared to 150 in the master fault complexes.) From the fracture orientation and frequency data, the following general observations are made: (1) the shales in the western part of the investigated area, and especially those situated within or near the major fault complexes, generally are more heavily fractured than those from the eastern areas. (2) The shales of the Fuglen Formation sampled within the BjCrnCyrenna Fault Complex are dominated by low-angle fractures. (3) The shales of the Hammerfest and Nordkapp Basins are characterised by more highangle (50-60 ~ fractures. This seems to be a valid observation, even when the small number of fractures observed in this domain are taken into account.
Rock mechanical data from cap rocks of the southwestern Barents Sea Two series of rock mechanical experiments (consolidated anisotropically undrained (CAU) triaxial and uniaxial compression tests) were performed on shales and mudstones from the Fuglen and Hekkingen Formations for Norsk Hydro by the Norwegian Geotechnical Institute. Using "vertical" samples (drilled and loaded at a right angle to bedding) from well 7219/9-1, shear strengths between 22.6 and 37.5 MPa were obtained, compared to 16.3-40.2 MPa for samples from well 7321/9-1 (Table 3). The tests made on a shale from the Hekkingen Formation (well 7228/2-1, 7228/9-1, and 7125/1-1) gave values be-
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1051 0 0-10 11!20 21!30 31-40 41-50 51!60 61!70 71-80 81-90 Fig. 6. Fracture dip profiles, (a) well 7321/9-1 (Fuglen Formation), (b) well 7219/9-1 (Fuglen Formation), (c) well 7120/2-2 (Hekkingen Formation), (d) 7120/6-1 (Fuglen Formation), (e) well 7120/12-1 (Fuglen and Hekkingen Formations), (f) well 7228/9-1 (Hekkingen Formation), (g) wells 7321/9-1, 7219/9-1 and 7228/9-1, experimental results, x-axis, dip-angle from 0 to 90 ~ y-axis, percentage number of fractures.
Late Jurassic-early Cretaceous caprocks o f the southwestern Barents Sea: fracture systems and rock mechanicaJ prqpertres
,__
Table 3 Summary of rock mechanical properties of shales from the Fuglen (wells 7321/9-1 and 7219/9-1) and Hekkingen (well 7228/9-1) formations Well
Orientation
Ymax (MPa)
7219/9-1 7321/9-1 7321/9-1 7228/9-1 7125/1-1 7125/1-1 7228/2-1 7228/2-1 7324/10-1 7324/10-1 7324/10-1
Vertical Fuglen Vertical Fuglen Horizontal Fuglen Vertical Hekk. Vertical Hekk. Horizontal Hekk. Vertical Hekk. Horizontal Hekk. Vertical Horizontal Horizontal (cc) Snadd
22.6-37.5 16.3-40.2 13.7-22.4 7.5-22.7 8.9-32.0 30.2-39.0 7.5-27.2 15.8-30.6 >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
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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
E. Sverdrup and K. BjCrlykke
94
a
C
!
I
1ram
b
'
0,5 mm
"
0,5ram
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.
E. Sverdrup and K. BjCrlykke
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
<35
IPF, Ph
No
Stylolitization
-3500
Yes
No
<500 <500 <500 <500 <500 Surface <700 -3000
Yes (cc) No No Yes (cc) No No Yes (cc) Yes (qz)
<0.02 <0.02 >20 <0.02 <0.02 <20 <100 <150
BR IPF, Ph IPF, Ph, ShS BR IPF, Ph IPF, CS BR, CC CC
Yes (cc) No No Yes (cc) No No Yes (cc) Yes (qz)
None Stylolitization None None None None None None
-3000 -3000 -2500 -2500 -2500 -700 -700 - 3000m
No No No No No Yes Yes Yes
No Yes (cc) No
d. Gulf of Corinth, Greece e. Brora, Scotland
Cements: cc, calcite; qz, quartz. Deformation characteristics: IPF, interparticulate flow; Ph, enrichment of phyllosilicates; CS, clay smear; ShS, shale smear; BR, brecciation; CC, cataclasis.
Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models
lapsed close to the surface and were not lithified when deformation occurred. The alluvial and fluvial strata were flooded by meteoric pore water and got cemented prior to faulting. While clay smear and intergranual shear fractures dominate in fine-grained and poorly cemented intervals (Fig. 7a), well cemented intervals cut by faults display fault gouges characterized by brecciation and granulation (Fig. 7b). Within these (brittle) fault
the ongoing fault activity along the Gulf of Corinth Fault. Delta collapse structures which occurred in a similar sedimentological setting to those described for Kvalv~tgen show intraformational terminations and growth within sequences. The faults are characterized by clay smear and sand mobilization, generating dikes with fault parallel laminae. These sediments, which were deposited in marine environments, col-
a
c
97
b
cl
Fig. 7. (a) Fault structure within fluvial conglomerates interbedded with silt- and mudstones. Clay smear dominates. (b) Brittle deformation of grains within a fault zone cutting through fluvial conglomerates. (c) Fault gouge filling low Mg calcite. See Table 1 for analysis results. (d) Joint filling low Mg calcite within fluvial conglomerates. See Table 1 for analysis results.
98
E. Sverdrup and K. BjCrlykke
Table 2 Results from chemical analysis of fault gougefilling cementandjoint filling cement from faulted sequencesin the Gulf of Corinth graben Element
faults north of the Inner Moray Firth Basin. The sandstones cut by these fault structures belong to the shallow marine Brora Arenaceous Formation (Oxfordian) (Sykes, 1975). The sediments are cemented by quartz, to an extent related to the occurrence and abundance of Rhaxella perforata sponge spicules (Hurst, 1992; Vagle, 1994). The exposed fault structures are very similar to the deformation bands as described by Antonellini and Aydin (1994) and Fowles and Burley (1994). Numerous, sub-parallel shear fractures up to ca. 10 mm thickness have developed fault zones up to 5 m wide. Displacements are in the millimetric scale for each individual band, adding up to a maximum of ca. 100 m for the fault zones. Based on isotope data of fault abundant quartz cement, the minimum depth at which faulting occurred has been estimated to ca. 3000 m (Fig. 8). The undeformed sandstone consist of cemented subrounded to rounded grains with porosities in the range between 25 and 30%. Faults which cut through this sandstone are 1.0-10.0 mm wide, and have thin transition rims (0.1-0.5 mm wide) towards the undeformed sandstones. The micro-fault zones are characterized by ruptured cement as well as broken allogenic grains. Also, dense packing of fragments is characteristic. To document the different grain size distribution of quartz in the undeformed sandstones and associated micro-fault zones, point-counts using an optical microscope were carried out across faults to quantitatively assess the changes. A distinct reduction is observed for grain sizes between 0.1 mm and 0.03 mm (Fig. 9). For example, the grain size corresponding to a cumulative percent of 50 in each sandstone is reduced about an order of magnitude in the
Analysis no. 1
2
3
48.07 0.19 0.45 0.22
46.28 0.21 0.32 0.06
52.26 0.02 0.05 0.04
51.05 0.10 0.21 0.00
Gouge filling cement (element wt%) Ca Mg Fe Mn
48.87 0.20 1.01 0.23
Joint filling cement (element wt%) Ca Mg Fe Mn
52.29 0.05 0.00 0.10
gouges, low Mg calcites have locally precipitated (Fig. 7c, Table 2). Low Mg calcites are also found along pre-existing open joints. Some of these fractures bear evidence of periodic cementation, as suggested by compositional variations of the low Mg calcites (Table 2). The cemented fractures may be related to the fault movements, but may also have developed due to unloading during uplift. Some fractures are still partly open. The blocky low Mg calcites which are observed to fill the fractures are typical for shallow diagenesis (Fig. 7d). The schematic overview for the faults described from the Gulf of Corinth is shown in Table 1d. Brora, S c o t l a n d
The faults studied near Brora village, Scotland, belong to the Brora Fault which is one of several
Oxygene
i s o t o p e f r a c t i o n a t i o n vs. t e m p e r a t u r e 18
_.
t(Delta Owater
-2,0~176
145 124-1370C 125
Oz. cement (fault zone)
A 105
tO =._. Q.
E
85
I--
y =-135,61Ln(x) + 496,56 (Labyerie, 1974)
65
Diagenetic qz. cement (Vagle et al., 1994)
24,o.30,o
45
10
15
20
25
|
30
35.660C
35
DeltatSO ~ Fig. 8. Isotope data from Brora fault zone quartz cement. Precipitation temperature is suggested to be in the range between 120 and ! 25~ based on
a solutionfrom Labyerie (1974).
Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models Grain size
99
9Fault z o n e vs. host rock
Brora A r e n a c e o u s 100
,.--.,
m Q;
.> m E u
9Fault zone
50
m Undeformed sst
U
g k._ 11
0 0,001
~
r
0,01
! 0,1
Grain size (mm)
Host rock porosity = 23,5% Fault zone porosity = 6%
Fig. 9. Relative changes in grain size distribution as evidenced from point counting across micro-faults and the adjacent, undeformed sandstone.
corresponding micro-fault zone. Fig. 9 further shows that the grains in the micro-fault zones have a large spread in sizes, meaning they are more poorly sorted than the grains in the parent sandstone. The porosity is considerably lowered within the micro-fault zones compared to the undeformed sediment (Fig. 10). Also, the amount of quartz cement is higher within the micro-faults zones and their associated rims compared to the undeformed rocks. The increase however, is minor (1-4%), and only extends in the order of 0.5 mm (width of rim) out from the micro-fault zone. This indicates that only small volumes of precipitating silica have been available along the faults. Table l e summarizes some key parameters for the Brora faults. Discussion
The normal faults described above show a wide range of structures and textures. Although the differences observed can derive from a combination of several causes (i.e., strain rate, orientation of principal axis of stresses, sense of shear and pore pressure), some of the characteristic features of the faults are suggested to relate to the state of lithification during faulting as well as later diagenetic modifications. Below, an overview is given which addresses the relationship between diagenesis of sandstones and fault structures, and discuss the described faults with reference to their diagenetic framework. Quartz sandstones are generally expected to remain loose and friable until they have been subjected to a burial depth greater than about 3 km (BjCrlykke et al., 1992; Giles et al., 1992; BjCrlykke and Egeberg, 1993) unless the sediments experience very
high pore-pressures. Mechanical compaction, causing denser packing of grains, dominates the sediment during the upper 2-3 km of burial. At depths about 3 km (above ca. 100~ the kinetics of quartz precipitation and dissolution is sufficiently high to cause significant quartz cementation in 1-10 million years. Increased amounts of dissolved quartz are caused by different diagenetic reactions (e.g., smectite-illite and Kspar-kaolinite transformations). When the quartz cement has reached about 10% (volume) the rock strength is very much increased and the material may be brittle under most conditions. At shallower depths than 2.5-3 km, sandstones will tend to disintegrate between individual grains if not cemented by, for instance, carbonate or early silica cements (see below). B iogenic silica is one potential source of quartz cement which may affect the sediments before they reach a depth of ca. 2000 m. Opal-A is unstable and dissolves, and silica may subsequently reprecipitate as Opal-CT which again dissolves to precipitate quartz cement. Development of quartz cement from biogenic silica has been interpreted to occur at temperatures below ca. 60~ ((Vagle et al., 1994). The transition of Opal-A to Opal-CT is accompanied by an increase in seismic velocity and brittleness. At shallow depths carbonate cements may cause sands to become brittle and hard. Carbonate which precipitates on the sea floor may also form hard grounds in dominantly clastic sequences. Sandstones may become calcite cemented due to dissolution of biogenic aragonite at relatively shallow depth (less than a few hundred meters). Calcareous sediments flushed by meteoric water at shallow depth or exposed during regression may become rapidly ce-
1O0
E. Sverdrup and K. BjCrlykke
Fig. 10. Porosity and cementation profiles across micro-fault, rim and undeformed sandstone.
mented by low Mg calcites. At greater depths, carbonate cementation is mainly sourced by the initial carbonate clasts or cement by, for instance, pressure solution. Precipitation of calcite from CO2 is not very significant due to the limited Ca 2§ supply. Hard and brittle carbonate cemented zones are therefore largely controlled by the primary biogenic and clastic input, and by early diagenesis. Because the rock mechanical properties of a sediment change during burial (i.e., from cohesionless sand to a well cemented sandstone), deformation processes and products will change as well. It is therefore essential to establish the diagenetic history as well as the depth of burial when the deformation took place in order to predict fault properties and their effect on fluid flow. Deformation mechanisms related to faulting have been reviewed by several authors (Sibson et al., 1975; Sibson, 1986; Groshong, 1988; Mitra, 1988; Knipe, 1989, 1992)and are demonstrated to have close links with the environmental conditions (pressure and temperature). The most important mechanisms regarding faulting in sediments
are independent particulate flow (IPF), fracturing and crystal plasticity. The early (synsedimentary) faults described from Kvalv~gen, Tampen Spur and the Gulf of Corinth are all characterized by grain reorganization (dense packing of grains), and sand mobilization due to fluid movements along the fractures as well as clay/shale smear. All structures bear evidence of movement in a non-lithified sediment (ductile deformation). The water escape structures (clastic dikes), probably extend from underlying sand sequences embedded within prodelta muds. Of these, only the Kvalv~gen faults, which were buried to approximately 3500 m prior to uplift, have been considerably modified with respect to initial fault textures. Here, later diagenesis modified the fault structures by intensive quartz overgrowths and development of micro-stylolites. Tectonic faults relate to a certain stress regime within the basin in which they evolve. They therefore usually display orientations in a systematic manner. These faults may also involve deeper seated basement. The faulting can affect the sedimentary se-
Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models
quence at shallow, medium or deep burial. The structures therefore cut sequences of different lithification states (soft sediments to solid rocks) and the deformation mechanisms may vary accordingly. These faults, as observed from Haltenbanken, Tampen Spur, Gulf of Corinth and Brora, are characterized by dense packing of grains and enrichment of phyllosilicates, and, locally, by grain disaggregation and cementation. The variability is proposed to, at least partly, be a consequence of the sediment strength at the time of deformation, which again depends on the initial composition of the faulted sequences and their diagenetic overprint. Most of the sediments from the Haltenbanken and Tampen Spur were not well cemented or lithified prior to faulting. Texturally, these faults display internal textures which evidence grain reorientation, dense packing of grains and enrichment of phyllosilicates due to faulting at shallow to moderate depths. Very weak grains, as for instance micas and (prefractured?) rock fragments are locally broken, a phenomenon which, however, may well occur in sands sheared close to the surface. The faulted, non-carbonate cemented sandstones which were sampled from Haltenbanken and Tampen Spur, show clear evidence of diagenetic modifications after the deformation had occurred. Feldspar dissolution, illite precipitation and stylolitization are examples of such diagenetic processes. The pre- and post-faulting diagenetic reactions have been demonstrated to be a useful tool for the purpose of dating fault movements relative to basin subsidence (Sverdrup and BjCrlykke, 1992; Saigal et al., 1995). The faults from Haltenbanken, Tampen Spur and Gulf of Corinth which were observed within carbonate cemented sediments (both quartz dominated and calcareous sandstones) exhibit more brittle deformation textures compared to the non-cemented sandstones, even though the depth of faulting was similar. Deltaic sediments (Gulf of Corinth) which were more prone to marine water are less cemented than the alluvial/fluvial sediments from the same region which were flooded by meteoric porewater, and the finegrained sediments were found to be less cemented than more poreous, coarse grained clastics. Poorly cemented sequences showed evidence of ductile deformation, while the well cemented, hard and resistant beds are characterized by cataclastic breakage of individual pebbles and grains along faults. The observations from Haltenbanken, Tampen Spur and Gulf of Corinth further demonstrate that carbonate cemented faults and fractures are limited to carbonate cemented sequences, suggesting that most of the carbonate is derived from the surrounding rock, probably transported by diffusion. The absence of
101
carbonate cement along the fault planes which extend out from cemented layers/intervals, suggests that there is insufficient flow of fluids along the fractures to transport significant carbonate cement, or that the faults were not open for flow to occur. Besides, upward cooling flow along the fault planes would be more likely to dissolve than precipitate carbonates (BjCrlykke, 1993). The quartz cement within the Brora fault may have been precipitated at approximately 3000 m depth according to the isotope study which was performed on fault related quartz cement. The isotope values of 13.2-15.6 6180(SMOW)correspondto temperatures in excess of 120~ (Fig. 8). At such depths, sandstones are expected to exhibit brittle behaviour (BjCrlykke et al., 1992). The isotope studies performed by Vagle et al. (1994) on intergranular quartz cement from the same rocks, however, gave higher isotope values (24.0-30.0 dlaO(sMow~) which indicates precipitation temperatures in the order of ca. 60~ The difference between these results may be explained by the rock materials actually sampled. While Vagle et al. (1994) sampled early silica cement from Opal-CT within the undeformed sandstones, we separated authicenic late quartz from the faults. This suggests that the sands were lithified already at a relatively shallow depth by the Opal-CT to quartz transformation. At deeper burial when the sandstones were deformed, the presence of open micro-fractures due to brittle failure possibly enabled a limited fluid flow, which allowed silica to precipitate as quartz cement close to the faults. The very localized nature of the fault-related cement does not favour an interpretation which involves significant fault-parallel fluid flow.
Cementation of faults" predictive models Based on the observations and discussions presented here, a relationship between burial diagenesis, rock properties and faulting in sandstones has been generated. This is displayed in Fig. 11. As shown in this figure, the depth at which sandstones behave ductile or brittle when deformed will depend on the cementation processes during the burial diagenesis. It should be noted, however, that other factors such as strain rate and pore pressure will have impact on the indicated transition between ductile and brittle properties of sandstones as presented in Fig. 11. In Fig. 11 three categories of sandstones ("clean", "calcareous" and "biogenic") are separated depending on their original composition. The term "clean" sandstone is used for well sorted quartz sandstones with a phyllosilicate content below ca. 20%. "Calcareous" has been used for sandstones with similar textures in which carbonate grains dominate above, for instance,
102
E. Sverdrup and K. BjCrlykke Deposition
~,0
Time
i t a l c Sand i Biog' Sand i I clean Sand 1 ~ G 1 ~ K1 H2 T2\ ......... . \ H3 T3 i Early G2 "\ H4 T4 , carbonate ! \ 1 cementation i ,\ :
E
\
\
DUCTILE
Exposure
K7 B7 G7 Fracturing due to unloading
.l
:
DEFORMATI()N i
",
r-
Q a
rO
(g !--
~"
BRITTLE ~'DEFORMATION \ \
\
03
\
I0(]
20
\",,
B5~
', i T6
"'...
O n s e t of e x t e n s i v e
quartz cementation
i
......
BRITTLE DEFORMATION
, ', '
g"6 ....,' ~,K6
Burial
'i
'
i i I
',,
Uplift
i
I
Fig. 11. Diagram separating the brittle and ductile fields of sediments with respect to faulting. The described faults are indicated as numbered letters (see text for further details).
quartz. The "biogenic" sandstone is used for quartz dominated, clean sandstones which originally contain biogenic silica (Opal-CT). In loose sandstones containing small amounts of clay minerals, relative movement will cause grain reorganization and pore collapse. If accompanied by fluid escape, fault parallel dikes develop. The positions of these types of structures from Kvalv~gen, Tampen Spur and Gulf of Corinth are indicated as K1, T1 and G1 in Fig. 11. Soft sediments cannot remain open for long periods due to their low shear strength, and cement seals are therefore not expected for such structures. In the examples where the sediments contained carbonate material or had been subjected to early carbonate cementation (e.g., Haltenbanken, Tampen Spur and the Gulf of Corinth), the sandstones showed brittle behaviour at shallow depths. These observations (H2, T2 and G2) are also indicated on the deformation-diagenesis curve in Fig. 11. Faulting at shallow burial in carbonate cemented sequences will develop breccias, which may prevent the fault plane closing mechanically despite the horizontal stress. Such faults therefore may create and maintain high permeability pathways for fault-parallel fluid flow and cause precipitation of minerals. Depending on the pore fluid composition, fluid flux, temperature and pressure gradients, dissolution processes are, however, likely to occur along the fracture walls. The rate of fluid flow along fractures are also controlled by the
rate of compaction of the adjacent sediments which is normally low. Ductile deformation of "clean" quartz sandstones is expected at depths shallower than about 2.5-3 km (Fig. 11) unless the porepressure is very high. This is due to low amounts of quartz cement. The observations from Haltenbanken and Tampen Spur are included as H3 and T3 (shallow deformation depth) and H4 and T4 (intermediate deformation depth) in Fig. 11. Cementation processes along such faults are normally not considered important, as the deformation mechanisms related to them are dominated by porosity reducing processes such as denser packing of grains and increased amounts of phyllosilicates. When the sediment have reached the onset of extensive quartz cementation, brittle behaviour and granulation may be experienced if the cement strength exceeds the grain strength. If weakly cemented, fractures eventually break the cement which may create space for precipitating cement. Brittle behaviour of quartz was, however, not observed for the faults from Haltenbanken and Tampen Spur. The "biogenic" sandstone is exemplified from the Brora area. Due to dissolution of biogenic silica which reprecipitate as intergranular quartz cement before faulting occur, brittle deformation occurs as a response to the faulting. The Brora fault episode is indicated in Fig. 11 as B5. The presence of dissolved silica at even moderate depths (Vagle et al., 1994), may cause quartz to precipitate as fracture fill also
Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models
during uplift and unloading, until a depth of ca. 1.5 km is reached. Subsequent to the faulting, the sediments from Kvalv~egen, Haltenbanken and Tampen Spur got buried to approximately 3500 m, 3000 m and 2500 m, respectively. The positions are indicated as K6, H6 and T6 in Fig. 11. The presence of micro-stylolites was observed for the Kvalvhgen and Haltenbanken faults only, which is explained by the fact that these sediments are buried at or below the onset of extensive pressure solution of quartz at ca. 3 km depth (Fig. 11). The sediments from Kvalvgtgen, Brora and Gulf of Corinth was later uplifted, and this process may have caused open fractures to evolve clue to the released stress. Their present position are indicated as K7, B7 and G7, respectively. The sediments from the Gulf of Corinth show open fractures filled with low Mg calcites (Table 2), typical for shallow cliagenesis. It can be argued that some of these fractures are generated due to unloading, as they locally cut pre-existing shear fractures in the region. Open fractures filled with quartz cement were not observed from Kvalvgtgen or Brora. This is most probably explained by the fact that these sediments were heavily cemented prior to uplift, and that open fractures did not develop before the sediments were shallower than ca. 2.5 km (Kvalvgtgen) and 1.5 km (Brora). At such depths, the process of quartz cementation will stop. This study gives input to our ability to predict cleformation mechanisms within sandstones clue to faulting at different burial depths, as well as the possibility for fault-related cementation within such sediments. While "clean" quartz dominated sandstones tend to be loose and deform by independent particulate flow down to about 3 km, calcareous sands may become brittle during the first 20 m. Biogenic rich sandstones may similarly be cemented at relatively shallow depth (ca. 1500 m). Although not discussed in this paper, it is important to be aware that most commonly the interbedded nature of sediments will cause deformation mechanisms and cementation processes to alternate along larger faults. The implications on fault properties for structures which displace and/or juxtapose different types of sediments can be extremely difficult to assess (e.g., if a "clean" sand is moved past a "calcareous" sand and subsequently juxtaposed against a "biogenic" sand in which both the throw and geometry of the fault vary). It has been argued by several authors (Sibson et al., 1975; Kerrich, 1986; Burley et al., 1989) that cement seals are important features in faulted sedimentary sequences. This may be correct for specific tectonic settings, but is considered unlikely to be important for structures which cut poorly or non-cemented
103
sediments, because of the associated reduction of porosity and fracture permeability. Furthermore, the increased confining pressure as basins subside, as well as low shear strengths will cause open fractures to close rapidly in such sediments (BjCrlykke and HCegh, 1993). In the case of brittle fracturing of cemented sequences (e.g., associated with brecciation), the fractures need to provide a continuous fluid pathway in order to be filled with significant amounts of cement. However, even in the case of focussed flow, the necessary fluid flux for considerable quartz cementation is difficult to obtain (Pedersen and BjCrlykke, 1994). Secondly, during cementation, the permeability within the fracture approaches a very low value before the fracture is completely cemented. In order to continue the process, a fault reactivation with associated re-opening of the fluid pathway (e.g., by brecciation) is necessary. A complete wall of cement seal along a fault is therefore unlikely. Also, cementation into the sediment surrounding a fracture due to sloping isotherms was considered limited by Pedersen and BjCrlykke (1994) due to the extreme time required. Assuming that most intra-reservoir faults are not constantly reactivated, very continuous and lateral cement seals are unlikely to develop. Open fractures are more likely to evolve during uplift and unloading due to a reduction of the confining pressure. Such fractures are likely to be healed by quartz cement when temperatures are higher than ca. 80-90~ If temperatures are lower, the rate of quartz cementation is slowed down and open fractures may stay open for long periods. At shallower depth, however, the fractures may get healed by other mineral phases, for instance calcite. Although the description of fault seal types is important, it is also critical for the purpose of assessing fault properties that possible diagenetic modifications of fault structures are established. For instance, the impact of stylolitization on fluid flow across faults has been well documented for the Haltenbanken faults (Sverdrup and BjCrlykke, 1992). Similar to what has been presented by several authors (Antonellini and Aydin, 1994; Pittman, 1981; Gabrielsen and Koestler, 1987), it was observed that the porosity and permeability of all the measured faults were considerably lower than for the undeformed parent sandstones. Of particular interest, however, an additional reduction was noted for faults which were subjected to fault-parallel stylolitization. Such possible modifications of fault properties can be important during seal evaluations. Based on data from the Tampen Spur area, Moretti and Deacon (1995) concluded that oil migration generally occurred from late Cretaceous to early Tertiary time, thus after the faulting had established the structural pattern of the
E. Sverdrup and K. BjCrlykke
104
area. The fault structures at the time of migration most probably were characterized by their original textures as only shallow to moderate burial depth was obtained by then. Thus, the initial pressure threshold for the faults, and related hydrocarbon contacts across, were determined by their early textures. From early Tertiary time to the present day, the hydrocarbon filled sediments have been subjected to additional subsidence in the order of 1500-2000 m. At present, these rocks are found at depths down to 3000 m. During the Tertiary subsidence, considerable modifications due to diagenesis according to the descriptions above may have caused further permeability reductions of faults. Differences in oil-water contacts presently observed may therefore lead to an underestimation of sealing properties (pressure thresholds) for the faults. Further implications from this study include that throw-width relationships of faults are highly dependent on the lithology and the rock properties at the time (depth) deformation occurred. Clay-rich lithologies and shale-rich sequences may be dominated by strain softening processes along faults (e.g., clay smearing and shale injection). Renewed movement will be reactivated along the existing planes of weakness. Rocks which deform by grain reorganization (denser packing) and cataclasis will, on the other hand, develop planes which are stronger than the surrounding sequences (strain hardening). These faults will be broader as movement continues. A compiled dataset on throw-width (Otsuki, 1978; Scholz, 1987; Hull, 1988), should therefore be treated with care if implemented in reservoir models. Lithological variations within a subsiding basin may also have effects on growth faults and how they modify during burial. A porosity-depth relationship for sandstones and shales is given in Fig. 12. In Fig. 13a-c, a schematic development of an initial growth fault as it subsides is displayed. Typically, mudstones are characterized by high compaction rates, and may exhibit porosity reductions from 60-70% to 10-15% during the first 2 km. Hence, an initial mud sequence of 100 m is reduced to ca. 25 m at 2 km depth. Well sorted sandstones have a low initial compaction gradient, but at ca. 3.5 km depth, this rate exceeds that of shales. An initial sand thickness of 100 m will be reduced by approximately 25% at 2 km depth, leaving a total thickness of 75 m. At ca. 2 km, a relative reverse movement in the order of 50 m can occur between the lithologies (Fig. 13b). Additional subsidence may augment renewed movement between the two sequences, although with an opposite direction of shear due to the relative change in compaction rates (Fig. 13c). The implications of this model should be considered where different lithologies of considerable
10
20
30
40
50
60
I
I
I
I
I
I
70 _
I
0(%)
Shale porosity with depth ( O s h ) . ~ ~ / / L
/
Sand porosity with depth (Osst)
x = Porosity difference between sandstones and shales
Differential compaction rate (y) with depth (Z): Depth (km)
dOsst
Y-
dZ
dOsh dZ
Fig. 12. Burial depth-compaction curves for sands and shales.
thicknesses are juxtaposed across faults. Also, the gradual change in deformation mechanisms from soft to brittle which may occur during progressive burial should be addressed. Although initially characterized by soft-sediment deformation structures, brittle deformation may gradually become more important.
Conclusions Diagenetic analysis has proved to be useful in order to constrain the depths at which faulting occurs, and may help to predict deformation mechanisms and the related fault characteristics. The diagenetic processes are also important after the faults have been generated, as modifications of fault structures may occur during deeper burial. Understanding the deformation mechanisms is important in order to perform valid evaluations of the sealing potential of faults in reservoirs. In Mesozoic sandstones on Tampen Spur and Haltenbanken, normal faults are usually characterized by grain reorientation and enrichment of clay minerals which suggest that ductile deformation dominates. Abundant quartz cement is only observed along these faults associated with stylolites. Open fractures were not present in the sandstones from Tampen Spur and Haltenbanken. Fractures in these sediments therefore normally represent permeability barriers for fluid flow. Carbonate cement may affect sandstones at shal-
Fault properties and the development of cemented fault zones in sedimentary basins: field examples and predictive models
105
Compaction related faulting
au,,,n0 a, su,ace'
b
_ _ C,a,
iiii . . .i;iiiiii!iiii .....
Depth < ,v 2000m: y<0
u ,a o ,,,Onsan0 an0 c,a, o,
"Reverse"
fault
due to rapid
compaction shale ,. _ ~ S h a l e
C
of
" " "
Depth > -,. 2000my>0
"Normal"
fault
due to late compaction sst.
of
Fig. 13. (a) Faulting at shallow burial. (b) Compaction derived normal reactivation of fault. (c) Compaction derived reversed reactivation of fault.
low depths. Carbonate cemented sandstones tend to deform in a brittle manner when cut by faults. Carbonate filled fractures are generally limited to carbonate cemented intervals, sourced by diffusion processes rather than fault-parallel fluid flow. If biogenic silica is abundant in the sandstones, silica cement may precipitate and lithify the sands at intermediate depths. Depending on the cement strength, intergranular fractures, disaggregation of grains or brecciation may evolve. Considerable cementation of fault zones in such sediments will only occur if continuous pathways for fluid flow are established and prevail for long periods, or if renewed fault movement re-establish the fluid pathway. During progressive burial the confining stress increases. This implies that open fractures are unlikely to form unless the sedimentary rock is hydrofractured due to high pore pressures. During uplift and erosion, however, the sediments become over-consolidated as stress is released, and brittle failure may cause open fractures to evolve and persist. Compaction curves are significantly different for sands and muds. At shallow depths, muds compact rapidly, while at greater depths compaction rates for sands exceed that of shales. Such differences may cause considerable differential compaction effects across, for instance, growth faults, which cause reactivation of such faults during burial.
Acknowledgements Saga Petroleum A.S. is acknowledged for allowing us to publish data from the Tampen Spur area. The fieldwork in Greece was partly performed through the SAFARI project, and partly in cooperation with Norsk Hydro in the period between 1994 and 1995. The Norwegian Petroleum Directorate, Norsk Hydro, Statoil and Saga Petroleum gave permission to use the SAFARI data in this work. In particular, Eivind Aarseth (Norsk Hydro) is credited for numerous discussions during the fieldwork in Greece. Drawing assistance from Wenche Jonassen, Petter Lystad and Vivi Furu (Saga Petroleum) is appreciated. The authors thank Per Arild Reksnes, Andreas Koestler and NN for helpful comments on the manuscript.
References Allen, J.R.L. 1992. Sedimentary Structures: Their Character and Physical Basis. Elsevier, Amsterdam. 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. Billiris, H., Paradissis, D., Veis, G., England, P., Featherstone, W., Parsons, B., Cross, P., Rands, P., Rayson, P., Sellers, PI, Ashkenazi, V., Davison, M., Jackson, J. and Ambraseys, N. 1991. Geodetic determination of tectonic deformation in central Greece from 1900 to 1988. Nature, 350: 124-129. Bjcrlykke, K. 1993. Fluid flow in sedimentary basins. Sedimentary Geol., 86: 137-158.
E. Sverdrup and K. BjCrlykke
106 Bjcrlykke, K. and Egeberg, P.K. 1993. Quartz cementation in sedimentary basins. Am. Assoc. Pet. Geol. Bull., 77: 1538-1548. Bj~rlykke, K. and HCegh, K. 1997. Effects of burial diagenesis on stresses, compaction and fluid flow in sedimentary basins. Mar. Pet. Geol., in press. Bj~dykke, K., Nedkvitne, T., Ramm, M. and Saigal, G. Diagenetic processes in the Brent Group (Middle Jurassic) reservoirs of the North S e a - an overview. In: A.C. Morton, R.S. Haszeldine, M.R. Giles and S. Brown (Editors), Geology of the Brent Group, Special Publication 61. Geol. Soc., pp. 263-287. Brooks, M. and Ferentinos, G. 1984. Tectonics and sedimentation in the Gulf of Corinth and the Zakynthos and Kefallinia channels, western Greece. Tectonophysics, 101: 25-54. Burley, S.D., Mullis, J. and Matter, A. 1989. Timing diagenesis in the Tartan Reservoir (UK North Sea): constraints from combined cathodoluminescence microscopy and fluid inclusion studies. Mar. Pet. Geol., 6: 98-120. Dart, C.J., Collier, R.E.L.I., Gawthorpe, R.L., Keller, J.V.A. and Nichols, G. 1994. Sequence stratigraphy of (?)PlioceneQuarternary synrift, Gilbert-type fan deltas, northern Peloponnesos, Greece. Mar. Pet. Geol., 11: 545-560. Doutsos, T. and Piper, D.W. 1990. Listric faulting, sedimentation, and morphological evolution of the Quarternary eastem Corinth rift, Greece: first stages of continental rifting. Geol. Soc. Am. Bull., 102: 812-829. Doutsos, T. and Poulimenos, G. 1992. Geometry and kinematics of active faults and their seismotectonic significance in the western Corinth-Patras rift (Greece). J. Struct. Geol., 14: 689-699. Fowles, J. and Burley, S. 1994. Textural and permeability characteristics of faulted, high porosity sandstones. Mar. Pet. Geol., 11: 608-623. 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. NGT, 67:371-382. Gawthorpe, R.L., Fraser, A.J. and Collier, R.E.L.I. 1994. Sequence stratigraphy in active extensional basins: implications for the interpretation of ancient basin-fills. Mar. Pet. Geol., 11: 642-658. Giles, M.R., Stevenson, S., Martin, S.V. and Cannon, S.J.C. 1992. The reservoir properties and diagenesis of the Brent Group: a regional perspective. In: A.C. Morton, R.S. Haszeldine, M.R. Giles and S. Brown (Editors), Geology of the Brent Group, Special Publication 61. Geol. Soc., pp. 289-327. Glennie, E.W. 1990. Introduction to the Petroleum Geology of the North Sea. Blackwell, Oxford. Groshong, R.H. 1988. Low temperature deformation mechanisms and their interpretation. Geol. Soc. Am. Bull., 100: 1329-1360. Higgs, W.G. 1988. Syn-sedimentary structural controls on basin formation in the Gulf of Corinth, Greece. Basin Res., 1: 155-165. Hull, J. 1988. Thickness-displacement relationship for deformation zones. J. Struct. Geol., 10: 431-435. Hurst, A. 1992. The clay mineralogy of Jurassic shales from Brora, NE Scotland. In: H. van Olphen and F. Veniale (Editors), International Clay Conference, Developments in Sedimentology, Vol. 35. Elsevier, Amsterdam, pp. 677-684. Kerrich, R. 1986. Fluid infiltration into fault zones: Chemical, isotopic, and mechanical effects. PAGEOPH, 124: 225-268. Knipe, R.J. 1989. Deformation mechanisms - recognition from natural tectonites. J. Struct. Geol., 11: 127-146.
E. SVERDRUP K. BJORLYKKE
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. 325-342. Labyerie, L. Jr. 1974. New approach to surface seawater paleotemperatures using 180/160 in silica of diatom frustules. Nature, 248" 40--42. Mitra, S. 1988. Effects of deformation mechanisms on reservoir potential in Central Appalachian overthrust belt. Am. Assoc. Pet. Geol. Bull., 72: 536-554. Moretti, I. and Deacon, K. 1995. Subsidence, maturation and migration history of the Tampen Spur area. Mar. Pet. Geol., 12: 345375. Nemec, W., Steel, R.J., Gjelberg, J., Collinson, J.D., Prestholm, E. and Oksnevad, I.E. 1988. Anatomy of a collapsed and reestablished delta front in the lower Cretaceous of eastern Spitsbergen: gravitational sliding and sedimentation processes. Bull. Am. Assoc. Pet. Geol., 72: 454-476. Ori, G.G. 1989. Geological history of the extensional basin of the Gulf of Corinth (?Miocene-Pleistocene), Greece. Geology, 17: 918-921. Otsuki, K. 1978. On the relationship between the width of shear zone and the displacement along fault. J. Geol. Soc. Jpn., 84:661-669. Pedersen, T. and BjCrlykke, K. 1994. Fluid flow in sedimentary basins: model of pore water flow in a vertical fracture. Basin Res., 6: 1-16. Pittman, E.D. 1981. Effect of fault-related granulation on porosity and permeability of quartz sandstones, Simpson Group (Ordovician), Oklahoma. Bull. Am. Assoc. Pet. Geol., 65: 23812387. Saigal, G.C., Hellem, T., Knarud, R., Sverdrup, E. and Tveiten, B. 1995. Sequence stratigraphy of the Brent Group from the Tampen Spur, Norwegian North S e a - assessing importance of tectonics in development of sequences. Predictive High Resolution Sequence Stratigraphy, NPF, Stavanger, 6-8 November, (abstract). Scholz, C.H. 1987. Wear and gouge formation in brittle faulting. Geology, 15: 493-495. Sibson, R.H. 1986. Earthquakes and rock deformation in crystal fault zones. Annu. Rev. Earth Planet. Sci., 14: 149-175. Sibson, R.H., Moore, J.Mc.M. and Rankin, A.H. 1975. Seismic pumping hydrothermal fluid transport mechanisms. J. Geol. Soc. London, 131: 653-659. Sverdrup, E. and Bj~rlykke, 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. 507517. Sverdrup, E. and Prestholm, E. 1990. Synsedimentary deformation structures and their implications for stylolitization during deeper burial. Sedimentary Geol., 68:201-210. Sykes, R.M. 1975. The stratigraphy of the Callovian and Oxfordian stages (M-U Jurassic) in the northern Scotland. Scott. J. Geol., 11: 51-78. Vagle, G.B., Hurst, A. and Dypvik, H. 1994. Origin of quartz cements in some sandstones from the Jurassic of the Inner Moray Firth (UK). Sedimentology, 41:363-377.
Saga Petroleum as, P.O. Box 490, N-1301 Sandvika, Norway Department of Geology, University of Oslo, P.O. Box 1047, N-0316 Oslo, Norway
107
Quantitative fault seal prediction: a case study from Oseberg Syd T. Fristad, A. Groth, G. Yielding and B. Freeman
We describe a case study from Oseberg Syd where fault-seal behaviour has been predicted from analysis of a detailed depth model in conjunction with detailed lithological control. Juxtaposition seal of reservoir against non-reservoir can be assessed by fault-plane diagrams. Additional seal may be developed (at reservoir juxtapositions) if fault-plane processes increase the capillary entry pressure. In Oseberg Syd, clay smearing is considered to be dominant because of the relatively shaly nature of the Brent Group and the shallow burial depths during faulting (<500 m). For each fault, we calculate the shale gouge ratio (SGR) at all points of reservoir overlap. SGR is defined as the proportion (%) of shale in the rock interval that has moved past any point on the fault. This requires mapping of the fault displacement and combination with the shale percentage in the reservoir zones. RFT data provide a calibration of the value of SGR required to seal a fault plane. SGR values of 15-18% are consistent with adjacent fault blocks having small pressure differentials (<1-2 bar). Values of > 18% correspond to significant seal (ca. 8 bar). The major faults are believed to be fully sealed at the Brent level, and they are able to support large OWC differences. Some minor faults will maintain only a small difference in OWC across them. In the south-east, a change in the reservoir zonation results in minor faults being more strongly sealing except for restricted areas of very low seal. Such "low-seal windows" can be incorporated in a simulation model as areas of different transmissibility.
Introduction Oseberg Syd is located within Block 30/9 on the Norwegian Continental Shelf (Figs. 1 and 2). The area comprises a series of elongated fault blocks between the Horda Platform and the Viking Graben. Main fault strike directions are N-S to NNW-SSE, subparallel to the Viking Graben. The main block-bounding normal faults of the Oseberg Syd region have throws in the range of 200500 m in the reservoir section (the Brent Group). The following structural elements are defined by these faults (Fig. 2): J structures - C/Alpha structures - Gamma structures - Omega/B structures - G structures Almost all of the individual fault blocks, that have been drilled, contain oil and gas. In the western part of Block 30/9 (Omega, B and G structures), the main reservoir unit comprises the predominantly transgressive marine sands in the upper part of the Brent Gp (the Tarbert Fm), whereas channel sands within the Lower and Upper Ness Fms constitute the main reservoir units in the C and J structures. Due to the general complexity of the area (relatively small fault blocks and separate fluid contacts within the different compartments), a better understanding of reservoir separation, fault linkage and
likelihood for seal along the individual faults is crucial in order to address prospectivity and effects of static seal during production. During early 1994 a study was undertaken to provide geometric descriptions of the faults and their likely sealing mechanisms. A total of 16 blockbounding and internal faults (Fig. 3) were selected and analysed. A simplified stratigraphy of the Brent Gp in the
62 ~
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58 ~
2*
3~
4*
5*
6~
7~
Fig. 1. Location of Oseberg Syd off the western coast of Norway.
Hydrocarbon Seals: Importancefor Exploration and Production edited by P. M~ller-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 107-124, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
r 108
Fig. 3. Map showing the faults (labelled 1 to 16) analysed in this study.
T. Fristad, A. Groth, G. Yielding and B. Freeman
Fig. 2. Structural elements defined within Block 30/9. The faults are subdivided into fault categories depending on their predominant time of development.
Quantitative fault seal prediction
109
Table 1 Simplified stratigraphy of the Brent Group Formation
Depositional environment
Permeability characteristics
Sand quality
Draupne Shale Draupne Sand Heather shale Heather 2
Offshore Turbidite fan Offshore Lower to upper shoreface
Mudstone Whole range Mudstone Fine to medium
Heather 1
Lower shoreface to offshore transition zone
Upper Tarbert
Lower to upper shoreface
Middle Tarbert 2
Coastal lagoon, barriers, inlet channels
Non-reservoir Strongly heterogeneous Non-reservoir Strongly layered, partly calcite cemented, moderate to poor permeability Strongly layered, partly calcite cemented, poor reservoir quality Strongly layered, moderate to poor permeability Strongly heterogeneous but many high permeable intercalations
Middle Tarbert 1 Lower Tarbert Upper Ness Middle Ness Lower Ness Lower Ness sand
Coastal lagoon, swamp Lower shoreface to foreshore Upper to lower delta plain Upper delta plain (abandoned lobe, lacustrine, swamp) Upper delta plain Fluvial channel
Oseberg/Rannoch/Etive
Marginal marine delta deposits
study area is presented in Table 1. A more comprehensive description of the sequence stratigraphy within Block 30/9 can be found in MOiler and Van der Wel (1997).
Strongly heterogeneous Low to very high permeability Strongly heterogeneous, clay-rich Reservoir quality poor to absent Strongly heterogeneous, clay-rich Stacked channel sand with high permeability Not significant reservoir unit
Very fine to fine sand Fine to medium sand Whole range, medium to coarse sand forms an important component Whole range Very fine to coarse sand Whole range Predominantly fine grained components Whole range Coarse to medium grained sand Whole range
major faults in the area, with a stepwise thickness increase across each of the major faults. There are fairly constant interval thicknesses within each main fault-bounded compartment (cf. Yielding et al., 1992).
Oseberg Syd- structural setting Tectonic development The Oseberg/Oseberg Syd area lies between the Horda Platform and the Viking Graben, an area of Mesozoic extension. The study area comprises some 15-20 elongated fault blocks. Most faults within the Oseberg/Oseberg Syd region strike N-S to NNWSSE, subparallel to the Viking Graben, in an anastomosing pattern. The areal extent of each fault block ranges from 250 km 2 to less than 10 km 2. An attempt to subdivide the area into structural sub-units outlined by major faults with offsets in the range 200-1000 m, is shown in Fig. 2. Recent improvements in the seismic database in the Oseberg/Oseberg Syd region provided a significantly improved seismic interpretability, and a more confident fault interpretation has greatly enhanced the understanding of the structural framework. Local areas of excellent seismic data allow for interpretation of a comparatively large number of seismic reflectors within the Jurassic succession (Fig. 4). This facilitates a confident mapping of thickness variations across faults. Even without correction for differential compaction, the section demonstrates a spectacular thickness increase of nearly 100% within the Brent, Dunlin and Statfjord Formations across the major fault between the Gamma and Omega structures. Similar thickness changes are mapped across several
The spatial distribution of fault-related growth in the Oseberg Syd region is shown in Fig. 2. It can be concluded that most of the main faults (i.e., those that outline the key structural elements) were subject to substantial differential subsidence even prior to the main Late Jurassic rifting event. This indicates the existence of an early Viking Graben, exerting a strong influence on the Early to Middle Jurassic depositional systems. Furthermore, these faults were subject to accelerated differential subsidence in the Late Jurassic, recorded by substantial expansion of the Viking Group (Heather/Draupne Fms). This Late Jurassic phase of extension and block rotation caused a collapse along the crests of the major fault blocks already established in the Lower/Middle Jurassic. A series of minor fault blocks was thus formed in the Oseberg Syd region during the Late Jurassic, possibly extending into the Cretaceous. In conclusion, the local thickness variations imply a relatively shallow depth of burial during the fault activity (below ca. 500m). Basin modelling and backstripping across the Oseberg area supports this statement (Roberts et al., 1993, 1995). The Brent Group in general is quite shaly and,
1 10 T. Fristad, A. Groth, G. Yielding and B. Freeman
Fig. 4.Seismic and geoseismic cross-section through the 30/9-3A and -4s wells, illustrating the sedimentary growth across faults in the Oseberg Syd area. Note the dramatic thickness increase of the Brent Group of ca. 100% from the Gamma to the Omega North structure, and an +additional 30 ms increase to the westernmost fault block. The growth observed in the Dunlin Group and Statfjord Fm indicate that most of the faults were active through most of the Jurassic period.
Quantitative fault seal prediction
therefore, we might expect any observed sealing behaviour to be a consequence either of juxtaposition or of some mechanism of clay smearing. Because of the shallow depth of burial during faulting, the shales would be expected to be ductile. Thin sections and core fractures from C and J areas show clear indications of smearing along small-scale faults in shaly sand intervals (Fig. 5). In more sandy intervals, fracture zones are observed where the fracture porosity is filled with fine-grained material. However, increased fault throw would probably smear clay along the entire fault surface. Fault seal mechanisms
11 1
vironment is that by Bouvier et al. (1989), describing the Nun River Field in the Niger Delta. They present a predictive method of assessing whether clay smear is likely to be sufficient to form a membrane seal along the fault zone. A "clay smear potential" (CSP) is stated to represent the "relative amount of clay that has been smeared from individual shale source beds at a certain point along a fault plane". CSP is not defined explicitly by Bouvier et al., but is stated to: (i) increase with shale source bed thickness, (ii) increase with the number of source beds displaced past a particular point along a fault plane, and (iii) decrease with increased fault throw. Fulljames et al. (1997) give the algorithm for CSP as
Most seals in clastic sequences are membrane seals (Watts, 1987). The dominant control on seal failure is the capillary entry pressure of the seal-rock, that is, the pressure required for hydrocarbons to enter the largest interconnected pore throat of the seal. A number of mechanisms have been recognised whereby fault planes can act as a membrane seal (e.g., Watts, 1987; Knipe, 1992): (i) Juxtaposition. Reservoir sands are juxtaposed against a low permeability unit with a high entry pressure (e.g., shale). (ii) Clay smear. Entrainment of clay or shale into the fault plane, thereby giving the fault itself a high entry pressure. (iii) Cataclasis. Crushing of sand grains to produce a fault gouge of finer-grained material, again giving the fault a high capillary entry pressure. (iv) Diagenesis. Preferential cementation along an originally permeable fault plane significantly increases the entry pressure. Juxtaposition seals can be recognised explicitly by mapping the juxtaposition of units across the fault plane. To identify or predict sealing by clay smear, cataclasis or diagenesis requires an ability to relate these mechanisms to measurable properties of the subsurface (such as lithology and fault displacement), so that deterministic estimates of seal potential can be made. These different mechanisms and methods are discussed below. At present, significant success has been achieved in developing algorithms for prediction of seal capacity by clay smear (Fulljames et al., 1997; Yielding et al., 1997). It seems likely that seal by cataclasis may be similarly understood in the near future (Fulljames et al., 1997). Seal by diagenesis, however, will probably be much less amenable to prediction by simple algorithms.
Clay smear The classic study of clay smear in a production en-
T2
(1) where T is the thickness of the source bed, and D is the distance from the source bed. Bouvier et al. calibrated their CSP calculations against known sealing and non-sealing faults, and divided the observed range into high, medium and low CSP. Low CSP represents little chance for the presence of continuous clay smear seals that can trap hydrocarbons. Lindsay et al. (1993) describe outcrop studies of shale smears in a carboniferous fluvio-deltaic sequence in northern England. As in the study described above, Lindsay et al. concentrated on the effects of individual shale beds in the sequence rather than the bulk properties of the sequence. Smear is observed to be thickest when derived from thicker source layers and with small fault throw values; smear thicknesses commonly decrease with distance from the shale source bed. From a study of 80 faults they conclude that shale smears may become incomplete when the ratio of fault throw to shale layer thickness exceeds 7. Smaller ratios are more likely to correspond to continuous smears and therefore to a sealing layer on the fault surface. Gibson (1994) presents observations from the Tertiary sand-shale sequence of the Columbus Basin, offshore Trinidad. From an analysis of fault-sealed hydrocarbon columns, he concludes that the more significant seals are developed where the ratio of fault throw to shale layer thickness is less than 4 (i.e., the shale bed is >25% of the displaced section). The above studies suggest that sealing by clay smear may be predicted deterministically from a consideration of the thickness and offset of individual shale beds. However, such an approach is difficult to apply directly in the Brent Group because of the heterogeneity of the sequence. It is not feasible to map
112
T. Fristad, A. Groth, G. Yielding and B. Freeman
Fig. 5. Thin-section taken from the Ness Fm (2408 m MD) in the 30/9-9 well (J structure). Note the concentration of clay minerals in the small fault. Fig. 6. Diagram illustrating the calculation of SGR at a point on a fault surface. The throw (t) at the point is defined from the offset horizons. The "throw window" in the hangingwall represents the thickness of the rock that has slipped past the point. The SGR at the point is equal to the percentage of shale in the throw window. For units composed of "pure" shale and non-shale, SGR is the sum of the shale thicknesses divided by the throw. For units of given shale fraction, these fractions are used as weighting factors in the summation such that the result is the net shale percentage within all units in the window.
Quantitative fault seal prediction
113
every shale bed and consider its effect at the fault surface. Therefore, we take here a simpler approach of considering only the bulk properties of the sequence at the scale of the reservoir mapping (later we show the equivalence of the two approaches by sensitivity analysis). We define a fault-surface attribute called the shale gouge ratio (SGR) which is simply the percentage of shale or clay in the slipped interval. Fig. 6 illustrates how this would be calculated at a point on a fault surface: SGR - E (V~l • Az) x 100%
(2)
t
Vc~ is the clay or shale volume fraction in each interval of thickness Az and t is the fault throw at that point. The interval thicknesses are measured in a "window" with a height equal to the throw; this window therefore represents the column of rock that has slid past this point on the fault. The SGR represents, in a general way, the proportion of shale that might be entrained in the fault zone. The more shaly the wall rocks, the greater the proportion of shale in the fault zone and therefore the higher the capillary entry pressure. Whilst this is undoubtedly an oversimplification of the detailed processes occurring in the fault zone, it represents a tractable "up-scaling" of the lithological diversity at the fault surface; the required information is simply fault displacement and shale fraction through the sequence. SGR is approximately the reciprocal of "shale smear factor" (SSF) defined by Lindsay et al. (1993). Direct observations of sub-surface pressure allow a calibration to be made between the SGR and seal capacity. Ideally, an in situ measurement of the porepressure in the reservoir and that inside the fault zone would allow the capillary entry pressure of the fault to be calculated. However, fault-zone pressures are rarely available. Instead, the pressure difference between the two walls of the fault is a more general parameter that can be derived from pressure measurements in pairs of wells across the fault. Fig. 7a shows one such calibration, based on the Nun River dataset of Bouvier et al. (1989). From their strike projections of Fault "K", values of SGR have been calculated on a dense grid across the fault surface. On the same grid, minimum across-fault pressure differences have also been derived, using the proven distribution of hydrocarbons in the footwall sands to calculate buoyancy pressures. Fig. 7a shows a cross-plot of these two parameters for the areas of sand-sand contact at the fault surface. The dashed line indicates the inferred relationship between SGR and seal capacity. At SGR < 20%, no fault-sealed hydrocarbons are observed; the shale content of the slipped interval
is too low. Above 20%, the maximum observed pressure difference progressively increases, reaching ca. 7 bars at a SGR of ca. 60% (for gas). The large cloud of points lying below the dashed line indicates that many points on the fault do not achieve their full seal capacity, because they lie at lower elevations in the structurally-controlled hydrocarbon columns. The line is important as a calibration in describing the maximum pressure difference supportable by that part of the fault, if other factors are favourable. Interfacial tension (and, therefore, the entry pressure) for the gas-water system is typically as much as twice that for the oil-water system over a wide range of conditions (Schowalter, 1979). This suggests that the likelihood for seal is greater for gas than for oil. Therefore a given SGR value might be expected to sustain a greater pressure difference for gas than for oil. In Fig. 7a, the higher values of pressure difference (> 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 <0.001 mm, capable of supporting an oil column height of tens of metres. In general however, clay smear will be a much more efficient seal (oil column height up to several hundreds metres). A major control on the development of a cataclastic gouge is the magnitude of the effective normal stress on the fault plane during movement (Engelder, 1974; Watts, 1987). Thus generation of cataclastic
114
T. Fristad, A. Groth, G. Yielding and B. Freeman
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can occur at low overburden pressures, corresponding to only 100 m of burial. Knipe (1992) makes the pertinent point that the nature of a fault zone will vary across the fault surface, depending on which lithotypes are being displaced. Clay smear may be significant over some parts of the fault surface, but cataclastic gouge may be developed where shale beds are absent. We should expect that the sealing capacity of a fault will often be highly variable over different parts of its surface, and simple whole-fault descriptions such as "sealing" and "non-sealing" may often be misleading. Any pressure difference across the fault would have to be supported by its weakest point.
Fault-seal methodology
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S h a l e g o u g e ratio (%) Fig. 7. Examples of calibration of SGR against across-fault pressure difference. (a) Data from the Nun River field (Fault K of Bouvier et al., 1989). Each point represents one point (grid-node) on the fault surface. SGR was calculated using the sand-shale sequence shown by Bouvier et al. Across-fault pressure difference was calculated using densities of 1.0, 0.83 and 0.3 for water, oil and gas, respectively. The dashed line labelled "seal capacity" represents the maximum pressure difference that can be supported by a given value of SGR. (b) Data from the Columbus Basin, offshore Trinidad, based on Fig. 8 of Gibson (1994). Each point represents one reservoir top, with observations from many different faults (all reservoirs are oil-beating). Data points falling well to the right of the "seal capacity" line are faults bounding relatively small dip closures (i.e., the seal capacity is not realised).
gouge should be more likely at greater depth, and during reverse and strike-slip faulting rather than extensional faulting. However, experimental studies (Mandl et al., 1977) show that some grain breakage
Our approach in this paper has been to examine juxtaposition relationships and compute fault seal attributes on strike projections of fault surfaces. The analysis was carried out using FAPS software (Freeman et al., 1989; Needham et al., 1996). The overall procedure was as follows: (i) produce depth cross-sections from mapped horizon depth grids, incorporating reconstructed fault "sticks"; (ii) generate gridded representations of the individual fault surfaces, modelling their three-dimensional shape, displacement variation and horizon intersections; (iii) construct a simplified geological layer model for the Brent Group, and interpolate this zonation into the mapped horizon intervals at the fault surfaces; (iv) establish shale-volume fractions within each of the layers (reservoir zones) at each fault; (v) calculate values of SGR over each fault surface, using fault displacement and layer shale-volume fractions; (vi) compare SGR with pressure (RFT) data where available for well pairs across a fault. Each of these steps is described in more detail below.
Depth sections All fault and fault-seal analysis was performed in the depth domain, since this allows: (a) direct comparison with fluid contact levels, and (b) incorporation of additional geological information such as zone isochores. Primary mapping of the subsurface, however, was performed on seismic data, in the time domain. The seismic interpretation was depth-converted by applying appropriate velocity models to the TWT grids. The faults are now represented as polygons on each
Quantitative fault seal prediction
Horizon grids with fault polygons
115
Cross-sections with reconstructed fault segments
Fig. 8. Diagram illustrating how vertical depth sections of a fault can be reconstructed from fault polygons and horizon grids. The points defining the fault segments on the sections correspond to the centre-lines of the polygons on the depth grids.
of the horizon surfaces, and information about the vertical correlation of faults between horizons is lost. An important part of the analysis was therefore the reconstruction of the fault planes in depth. Depth grids for the primary mapped horizons (Base Cretaceous, Top Lower Tarbert, Base Brent, Top Cook and Top Statfjord) were available at a 50 x 50 m grid node spacing. Most of the faults in the study area trend approximately N-S and therefore the strategy adopted was to sample the depth grids on E-W rows to create a suite of sections at 50 m spacing (486 in total). Taking each horizon grid in turn, in conjunction with its fault-polygon file, an automated search of the grid rows was made in order to locate the positions of the horizon cutoffs at the faults. Fault "sticks" on the cross-sections were generated by joining the centre-line points of corresponding fault polygons on successive horizons: the position of each point is defined by the x,y information from the polygon and the z data from the grid (see Fig. 8). These fault segments were then labelled according to the fault surface to which they belong.
Gridded fault surfaces The x,y,z information of a group of fault segments is used to construct a grid that accurately matches the three-dimensional shape of the fault plane. This grid is the base on which all the calculations of fault attributes are performed. In this study, the larger faults were gridded at 100 x 100 m, the smaller faults at 50 x 50 m. The primary information for displacement and stratigraphic computations is the geometry of the horizon/fault intersections. Gaps between horizons and faults are corrected for by applying a "snapping" procedure (see Needham et al. (1996) for further discussion). Taking the depth difference between the upthrown and downthrown cutoffs of the same horizon gives the throw at that point on the fault. These measurements are used as the control points for pro-
ducing a grid of throw variation over the entire fault surface.
Geological layer model In addition to the mapped horizons (i.e., those imported from the grids), additional horizons such as the intra-Brent zonation were interpolated into the fault models by reference to the primary, mapped horizons. Detailed isochore maps for the study area were constructed on the basis of well data and seismic character mapping. Five to seven zones were recognised within the Brent Group, with an additional overlying sand in the Heather Formation. The additional horizons are posted onto each fault grid in one of two ways: firstly, as a fixed distance (thickness) above or below a primary horizon, or secondly, at a fixed percentage of the interval between two primary horizons. Posting of these horizons for both the footwall and hangingwall side of the fault results in a detailed and geometrically-robust juxtaposition plot.
Shale-volume data Petrophysical analysis of the well data was used to define the shale fraction in each stratigraphic unit. CPI logs were used to derive explicit shale percentages within both "sandstone" units (e.g., 5% shale in the Lower Ness Sandstone) and "shale" units (e.g., 65% shale in the upper part of the Dunlin Group). This information was then compiled geographically to estimate likely compositions between the wells, i.e., at the fault locations. Example profiles of shalevolume fractions are shown in Fig. 9.
Shale gouge ratio Having constructed the fault grid, with detailed juxtapositions and compositional data for all layers, we calculate a SGR. It was stated earlier that the fault surfaces were gridded at 100 x 100m or 50 x 50 m. Whilst this is adequate for analysis of displacement
1 16
T. Fristad, A. Groth, G. Yielding and B. Freeman
(a)
(b)
Fig. 9. Schematic illustration of the shale-fractions for (a) Fault 1 (G structures) and (b) Fault 9 (J structures). Note that the lowest fraction of shale for Fault 1 is within the upper part of the interval (Tarbert Fm), whereas for Fault 9 it is found in the lower half. The total Brent thickness in (a) is approximately four times the thickness in (b).
variation, it cannot capture the detailed stratigraphic variation that affects the SGR calculation. A grid refinement was therefore applied when calculating SGR, replacing each original grid node by 5 x 5 new nodes. At each node, the local throw value defines the height of a "search window" in the hangingwall (cf. Fig. 6). Within the search window, the program measures the thickness of each unit (down the fault plane) and combines these with the units' shale fractions to calculate the net shale percentage in the search window. By definition (Eq. (2)) this is equal to the local SGR at that point on the fault. The window over which shale values are summed could be in the footwall or hangingwall. In the absence of sedimentary growth across the fault these will be identical. If growth has occurred then an average of the two is more appropriate. In the Oseberg Syd dataset there is some growth across some of the faults; however it is often not possible to use data from the footwall "window" because there has been erosion. Therefore, SGR has always been calculated using the hangingwall "window".
Comparison with pressure data Where wells are present on both sides of a fault, we calibrate the SGR attribute with pressure data. Detailed RFT data permit the construction of pressure profiles at the wells, and since the pressure environ-
ment is static (pre-production) it is possible to project these pressure profiles to adjacent faults. With a cross-fault well pair, the pressure profile can be constructed in both the footwall and hangingwall of the fault, on the same refined grid as that used for the SGR calculation. Comparison of across-fault pressure differences with SGR at every point on the fault allows any relationship between the two to be examined. This relationship can then be extrapolated to those faults where well control is lacking, i.e., SGR can be used to constrain predictions of potential pressures (and hence hydrocarbon columns) in untested compartments.
Fault descriptions The poor seismic data quality in the C and J structures limits the reliability of the fault seal analysis in these areas. Consequently, the description below is focused upon the good quality seismic of the western area of Block 30/9 (Omega, B and G). The eastern area is covered in more general terms.
Fault I Fault 1 is located in the south-west part of the study area in the G area (see Fig. 3). The maximum throw observed on this fault is about 175 m, dimin-
Quantitative fault seal prediction
117
a
b
Fig. 10. Strike projections of Fault 1, viewed from the downthrown (west) side; vertical exaggeration x5. (a) Juxtaposition plot. Upthrown Brent zones are shown with coloured fill (see legend); downthrown zones are shown in black outline, labelled at each end of the fault. Footwall hydrocarbon contacts are shown in black, hangingwall contacts in blue. (b) SGR for the area of Brent-Brent overlap. Upthrown zones outlined in blue, downthrown zones in black; contacts as in (a). SGR is colour-coded in the ranges 0-15%, 15-20%, 20-30% and >30%. Note the area of slightly lower SGR on the upper part of the overlap zone; this is the critical area for fault seal.
ishing to zero displacement towards the south. The G East and G Central aquifers are therefore in communication around the southern end of the fault. The pattern of juxtaposed Brent zones on the fault is shown in Fig. 10a. Note the considerable area of Brent-Brent overlap: maximum fault offset is about half the Brent thickness. Wells are located both in the
footwall (30/9-13S) and hangingwall (30/9-14) and have different hydrocarbon columns, and so this fault provides a good calibration point with respect to the SGR calculation. The hangingwall oil-water contact is probably controlled by a structural spill-point (saddle) along the southern part of the fault. The fault is therefore probably not at seal capacity, and the
T Fristad, A. Groth, G. Yielding and B. Freeman
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the hangingwall structure, about 1 km from the north end of the fault. To calibrate the SGR calculation, we need to compare the observed pressure drops at every part of the fault surface with the SGR at the same point. The pressure profiles shown in Fig. 11 have been input to the fault model and are stored at every grid-point for footwall and hangingwall. At each grid node, the difference between the footwall and hangingwall pressures is the in situ pressure drop at the fault. Fig. 12a shows a cross-plot of SGR against across-fault pressure difference for every fault grid node in the Brent-
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calibration below represents a minimum potential for seal on this fault surface. The display of SGR on the fault surface (Fig. 10b) uses the shale fractions observed in the a d j a c e n t wells. Since the fault displacements are generally greater than the zone thicknesses, the calculated SGR values are relatively homogeneous. However, a significant point is the area of lower values (in yellow, <20%) near the upper part of the reservoir overlap zone. This represents the critical area for fault seal calibration. Fig. 11 shows the reservoir pressure profile on each side of the fault, constructed from RFT data in t h e - 1 3 S a n d - 1 4 wells. Individual RFT points have an accuracy of about 1 bar. The Brent-Heather sand sequence in the G area forms a single pressure compartment, i.e., there is no vertical compartmentalisation of the reservoir. As already stated, the aquifer is continuous around the end of the fault. On the hangingwall side there are deep oil-water and gas-oil contacts, giving a thin (30 m) oil rim under a thick gas cap. On the footwall side, both the OWC and GOC are higher and the oil rim is much thicker. The difference in OWCs is 90 m and the difference in GOCs is 165 m. Extrapolation of the hangingwall gas gradient implies that the across-fault pressure difference reaches about 9.5 bar at the level of the footwall GOC. Inspection of the juxtaposition pattern (Fig. 10a) shows that this geometry occurs near the crest of
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Quantitative fault seal prediction
Brent overlap zone. For fault seal, the significant question here is: which points on the fault are capable of holding back a large pressure difference for a relatively small SGR? Such points represent the critical areas for seal, and in Fig. 12 they will lie to the upper left of the cross-plot. A SGR of ca. 18% is capable of sustaining a pressure difference of almost 8 bar, and slightly higher SGRs (23%) can sustain 9.5 bar. These points correspond to the uppermost part of the reservoir-reservoir overlap zone: in Fig. 10b they occur at and just above the yellow area ca. 1 km from the north end of the fault. This part of the fault is holding back the higher-pressured gas column in the hangingwall. As with Fig. 7, Fig. 12a shows many data points that represent smaller pressure differences than the maximum, for a given SGR. These points correspond to structurally lower parts of the fault surface, for example near the hangingwall fluid contacts. Here seal is probably well-developed, but the in situ pressure difference is small. To test the sensitivity of the analysis a detailed template consisting of 65 layers within the Heather Fm and the Brent Gp was generated (Fig. 13a). The resulting SGR plot (Fig. 13b), shows only minor differences compared to the coarse model (Fig. 10b). This is because Eq. (2) tends to reduce the effect of stratigraphic complexity as the throw increases. As a rule of thumb, the detail of the stratigraphic template needs to be at the same order of scale as the minimum throw in the area of interest. The plot of pressure differences versus SGR (Fig. 12b) reveals more or less the same trend as observed in Fig. 12a, but with a SGR of 17% sustaining an 8.3 bar pressure difference. The fault demonstrates static sealing since it separates two hydrocarbon columns with a maximum pressure difference of 9.5 bar. Accordingly, this fault can be used for calibration of the calculated SGR values. The lowest calculated SGR value above the HC contacts is slightly below 20% (ca. 18%), indicating that for other faults having a SGR value in the same range, static sealing up to ca. 8 bar differential pressure could be anticipated (for gas as the high pressure phase). Eight bars differential pressure corresponds to about 240 m difference in OWC or 106 m difference in GWC, for single-phase hydrocarbon columns and typical densities (gas 0.25 g/cm 3, oil 0.66 g/cm 3, water 1 g/cm3).
Fault 2 Prior to the drilling of well 30/9-14, the ca. E-W fault located 350-450 m to the south was regarded as a block-bounding fault (see Fig. 3 for location). The
119
fault has a minimum displacement of about 15-20 m at its centre and consequently the different units within the Tarbert Fm are juxtaposed against themselves (self-juxtaposed) (Fig. 14a). The SGR values within the Tarbert Fm juxtaposition are close to 15% (Fig. 14b). DST testing of well 30/9-14 indicated the fault to be open, as the closest barrier to flow was interpreted to be 810 m away. Implications from this fault and Fault 1 therefore suggest that a SGR below or close to 15% corresponds to no seal and SGR a b o v e - 1 8 - 2 0 % corresponds to significant seal. This is a very tight range, but it remains quite consistent throughout the dataset.
Fault 3 This fault was selected to investigate the segmentation of the B structures and for calibration purposes with respect to Fault 1 (see Fig. 3 for location). The maximum displacement lies between the branch lines with Faults 1 and 7, and the displacement decreases southwards. Just north of the southern branch with Fault 4, the uppermost part of the Tarbert and Heather Fms (oil and gas) are juxtaposed against the lower parts of the Tarbert Fm (water), with about 2 bar pressure difference. In addition, the SGR values are just below 20% or higher, indicating by analogy that the observations from Fault 1 can be applied to this fault as well. Between B South and B North, the SGR is above 20%, which agrees well with the different fluid contacts and pressure regimes observed in wells 30/9-7 and 30/9-4S (ca. 5 bar pressure difference). In the central part of the fault (between G Central and B South), over 8 bar pressure difference is observed, at a SGR of ca. 28%.
Fault 4 Just north of the southern branch line with Fault 3, the displacement on Fault 4 is at a minimum (Fig. 3). The throw is in the order of 15-30 m, and a large area with SGR of 15-20% is observed, implying that there is a likelihood of having no seal, or a slight static seal across the fault. In the area of low SGR values, the Tarbert Fm is juxtaposed above the OWC in a restricted area only. This could explain the slight differences in OWC between the two compartments (B South and Omega South). With respect to the aquifer, it is likely that the B structure is in communication with the Omega South structure, because the area of juxtaposition is increased. The water gradient in well 30/9-7 is almost equal to the gradients in well 30/9-8 and 30/9-10. The gas in the B North compartment is separated
120
T. Fristad, A. Groth, G. Yielding and B. Freeman
El
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Fig. 13. Strike projections of Fault 1, using a detailed (65-layer) stratigraphic template (cf. Fig. 10). (a) Juxtapositions. Upthrown units are colourfilled, downthrown units shown outlined. The colour-coding is: yellow, <20% shale; olive, 20-40% shale, black, >40% shale. (b) SGR. In comparison with Fig. 10b, note low values on upper part of fault, and increased variability at south (fight) end of the fault where the throw decreases to zero.
from the Omega North structure by a 5 bar pressure difference, and on this part of the fault the SGR is about 24%. Fault zone 5 and 6
This fault zone most likely explains a difference in OWC of about 30 m between Omega North and
Omega South (Fig. 3). Unfortunately the seismic data quality is poor, and the definition of the details of the zone is difficult to elaborate. Consequently the two mapped faults separating the structures were analysed together. Where the throw on one fault decreases, the throw on the other increases accordingly. This observation strongly suggests that this pair of faults developed simultaneously and partitioned the displacement
Quantitative fault seal prediction
121
between them. It might therefore be expected that the overlap zone has distributed strain, and may have unresolved small faults linking the two main faults. The SGR variations along-strike where units within Tarbert Fm overlap are between 15 and 20% and minor faults linking the two main faults can be expected to have a SGR profile similar to that seen in the tip regions of the mapped faults (between 15 and 17%). The observed kinematic linkage of the large faults, in combination with a consideration of the SGR, therefore leads to an interpretation of the fault zone as being able to support a small differential pressure (less than 1 bar) in the area of Tarbert juxtaposition. This is sufficient to explain the differences in OWC observed in wells 30/9-8 and 30/9-10. The faults described above all have wells located on either side of the fault. In Fig. 15, a summary of the SGR versus across-fault pressure difference is plotted for critical oil and gas values along the different analysed faults. One fault can have several values depending on how many compartments are present on each side of the fault. For example the points for Fault 4 represent the segments where Omega North is juxtaposed against B North and B South, respectively. The purpose of compiling this essential infor-
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Fault 7 An E-W syncline defines a separate closure north of the 30/9-14 well. Analysis of Fault 7 was consequently performed in order to conclude whether a HC-column could be trapped in the hangingwall to the B West structure or not (Fig. 3). The fault has its minimum displacement (ca. 75 m) where it branches with Fault 3. In this area the SGR is just below 20% or higher, and by analogy with Fault 1, the potential for having a trapped HC-column at the extension of G Central is good. In addition, a gas column is more likely to be present rather than an oil column, increasing the possibilities for a static seal. The B West structure itself has not been tested by wells, but by analogy with Fault 3 (separating wells 30/9-4S and 30/9-7), a differential pressure across the fault between B West and B North could be anticipated as the throw is of the same order of magnitude.
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mation in one figure is to make predictions for faults where sufficient well control points are lacking. For the faults described below, SGR distributions were used to predict likely seal capacities and therefore constrain the occurrence of hydrocarbons in undrilled compartments.
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Fault 1. G-Central (30/9-14) against G-East (30/9-13S) Fault 2. intra-G-Central (-14 DST) Fault 3. B-North (-4S) against B-South (7) Fault 3m. G-Central (-14) against B-South (7) Fault 3s. G-East (-13S) against B-South (7) Fault 4. B-North (-4S) against Omega North (-3,-3A) Fault 4s. B-South (-7) against Omega North (-3,-3A) Faults 5/6. Omega North (-8) against Omega South (-10) Fig. 15. Summary diagram indicating the observed relationship between SGR and across-fault pressure difference for all analysed faults in the study area. Each point represents the "critical" part of the fault surface, i.e., maximum pressure difference for small SGR values.
This fault is an example of a number of crossfaults intersecting Omega South (Fig. 3). The throw decreases towards the NW, and along-strike the different units within the Tarbert Fm, except Lower Tarbert Fm, are self-juxtaposed. Where Middle Tarbert 2 and Upper Tarbert Fms are juxtaposed, the SGR varies between 15 and 20% possibly introducing small pressure differences across the fault. Because the area south of well 30/9-10 is intersected by several of these NW-SE striking faults, it is likely that different HC-contacts could be present. The difference in OWC across each separate fault, however, is probably not more than 10-15 m (or about 0.5 bar).
Fault 9 In light of the poor seismic data quality on the C and J structures the SGR calculations in these areas should be treated as guidelines rather than an exact definition of the individual faults. Fault 9 was selected in order to focus upon internal segmentation in the J structures (Fig. 3). The R2A unit of the Lower Ness Fm consists of a sheet of relatively homogeneous and clean channel sands. The thickness variation of the sheet is around
122
T. Fristad, A. Groth, G. Yielding and B. Freeman
Fig. 14. (a) The juxtaposition profile of Fault 2 (upper left) shows that the lowest value of throw is located at the centre of the fault (ca. 15 m). (b) SGR (lower fight) below 15% are found where the Middle Tarbert 2 unit is self-juxtaposed. This area of low SGR is not likely to behave as a pressure barrier. Note that the low SGR is found in the upper part of the interval as illustrated in Fig. 9a. Fig. 16. The SGR for Fault 9 reveals that the lowest values are found in the lower part of the Brent Group. The weakest point with respect to leak would consequently be expected to be found in the lower one third of the Brent Gp, whereas the upper two thirds would be expected to seal well.
Quantitative fault seal prediction 10-20 m where present. In addition, the shale percentage is as low as 8%. Consequently, where the sands are juxtaposed against themselves, clay smearing is probably absent and here, cataclasis is more likely than in the western area. The calculated SGR is generally above 20%, except for the R2A unit, where it is less than 15% in areas of small throw. If the SGR thresholds that we have obtained on the G structures are representative for the C structure, the upper two-thirds of the Brent Group juxtaposition are expected to seal well, and the lower part would be open to flow (Fig. 16). Note that this is in contrast with the faults in the western area, where seal is poorest on the upper parts of the faults (Tarbert Fro).
Conclusions A fault-surface attribute called the shale gouge ratio (SGR) has been defined for calculation of clay smearing in the heterogeneous Brent Group sequence. The attribute corresponds simply to the percentage of shale in the slipped interval. Furthermore a methodology for incorporating this fault related attribute into the evaluation of sealing properties has been implemented in the Oseberg Syd area. The SGR is variable over the fault surface, varying as the displacement changes and depending on the lithology of the wall rocks. Therefore the predicted sealing properties vary over the fault surface. The following observations are seen. Western area
Throughout the western part of Block 30/9, clay smearing and sealing by juxtaposition seem to be the main contributors to static seal. In light of the growth observed across most of the faults in this region, such a conclusion seems appropriate. However, the observed range of SGR, from non-seal to considerable static seal, is extremely tight, but remains quite consistent in light of the fluid contacts and pressure data in the 30/9 wells. Seal capacities for the individual faults are plotted in Fig. 15. Note that the highest seal capacities are observed where the gas is the higher pressure phase. The following is observed: SGR < 15% 15% < SGR < 18%
SGR > 18%
no seal expected slight seal expected (<1 bar pressure difference or 30 m difference in OWC) considerable seal expected (e.g., 8 bar pressure difference or up to 240 m difference in OWC)
123
Lowest values of SGR are generally observed on the upper parts of the faults (Tarbert Fm). Eastern area
The eastern area of Block 30/9 is structurally not as well constrained as the western area because of the seismic data quality. In addition, the hydrocarbons are located in geologically more heterogeneous reservoir units (channels). Consequently, the sealing evaluation performed is more uncertain, and should be used as a guideline rather than an exact measure of the sealing potential. The reservoir is thinner and less shaly, and if sealing is to occur then cataclasis and/or diagenesis would have to play a more important role. The lowest values of SGR are found on the lower parts of the faults (Lower Ness Fm). The study has provided essential information with respect to the juxtaposition of units across faults (information that otherwise is difficult to obtain from depth grids), telling us where the critical areas for leak in hangingwall blocks are present. In addition the SGR estimates indicate where clay smearing is more likely to occur on each fault surface. This information can guide transmissibility reduction factors to be implemented in reservoir simulators (e.g., ECLIPSE), in order to predict flow across faults. This has been tested for a small area in the Omega South structure. Due to the overall consistency of the SGR versus RFT data observed in the Oseberg Syd area, the resuits have been used in surrounding areas for risking of prospective resources. Similar studies will consequently be performed further south in block 30/9 to risk untested compartments.
Acknowledgements We are grateful to Peter Leach for assistance with analysis of the RFT data, to Helen Jones for compilation of the seal capacities, and to Peter Bretan for generation of the 65-layer template used for Fault 1. We appreciate the constructive reviews of the first draft of this manuscript by Inger Fj~ertoft and David Phelps. Thanks to the partners of licences PL079 and PL104 (Statoil, Saga Petroleum, Conoco Norway Inc., Norsk Agip A/S and Mobil Exploration Norway Inc.), for allowing us to present the material. The opinions expressed in the paper are not necessarily the opinions of the partners.
References Bouvier, J.D., Kaars-Sijpesteijn, C.H., Kluesner, D.F., Onyejekwe, C.C. and van der Pal, R.C. 1989. Three-dimensional seismic in-
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terpretation and fault sealing investigations, Nun River Field, Nigeria. Am. Assoc. Pet. Geol. Bull., 73: 1397-1414. Engelder, J.T. 1974. Cataclasis and the generation of fault gouge. Geol. Soc. Am. Bull., 85: 1515-1522. Freeman, B., Yielding, G. and Badley, M.E. 1989. Fault correlation during seismic interpretation. First Break, 8: 87-95. 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. Koeslter (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 51-59. Gibson, R.G. 1994. Fault-zone seals in siliciclastic strata of the Columbus Basin, offshore Trinidad. Am. Assoc. Pet. Geol. Bull., 78: 1372-1385. 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 Petoleum Geology. NPF Special Publication 1, pp. 325-342. Lindsay, N.G., Murphy, F.C., Walsh, J.J. and Watterson, J. 1993. Outcrop studies of shale smear on fault surfaces, Special Publication 15. Int. Assoc. Sediment, pp. 113-123. Mandl, G., de Jong, L.N.J. and Maltha, A. 1977. Shear zones in granular material. Rock Mech., 9:95-144. M~ller, N.K. and van der Wel, D. 1997. High resolution sequence stratigraphy as a basis for 3D reservoir modelling: a case study
T. FRISTAD A. GROTH G. YIELDING B. FREEMAN
from the southern Oseberg area. In: K.O. Sandvik, F. Gradstein and N. Milton (Editors), Predictive High Resolution Sequence Stratigraphy, NPF Special Publication, in press. Needham, D.T., Yielding, G. and Freeman, B. 1996. Analysis of fault geometry and displacement patterns, Special Publication 99. Geol. Soc. London, pp. 189-199. Roberts, A.M., Yielding, G., Kusznir, N.J., Walker, I. and DornLopez, D. 1993. Mesozoic extension in the North Sea: constraints from flexural backstripping, forward modelling and fault populations. In: J.R. Parker (Editor), Petroleum Geology of Northwest Europe: Proc. 4th Conf., Geol. Soc. London, pp. 1123-1136. Roberts, A.M., Yielding, G., Kusznir, N.J., Walker, I. and DornLopez, D. 1995. Quantitative analysis of Triassic extension in the northern Viking Graben. J. Geol. Soc., 152: 15-26. Schowalter, T.T. 1979. Mechanics of secondary hydrocarbon migration and entrapment. Am. Assoc. Pet. Geol. Bull., 63: 723-760. Watts, N. 1987. Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns. Mar. Pet. Geol., 4: 274-307. Yielding, G., Badley, M.E. and Roberts, A.M. 1992. The structural evolution of the Brent province. In: A.C. Morton, R.S. Haszeldine, M.R. Giles and S. Brown (Editors), Geology of the Brent Group. Geol. Soc. Special Publication 61. pp. 27-43. Yielding, G., Freeman, B. and Needham, D.T. 1997. Quantitative fault seal prediction. Am. Assoc. Pet. Geol. Bull., 81:897-917.
Norsk Hydro, P.O. Box 200, N-1321 Stabekk, Norway Norsk Hydro, P.O. Box 200, N-1321 Stabekk, Norway Badley Earth Sciences Ltd., North Beck House, North Beck Lane, Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK Badley Earth Sciences Ltd., North Beck House, North Beck Lane, Hundleby, Spilsby, Lincolnshire, PE23 5NB, UK
125
Fault seal analysis in hydrocarbon exploration and appraisalexamples from offshore mid-Norway A.I. Welbon, A. Beach, P.J. Brockbank, O. Fjeld, S.D. Knott, T. Pedersen and S. Thomas
Fault seal analysis of the Greater Heidrun area on the Haltenbanken platform, offshore mid-Norway, has been carried out as part of a larger integrated study. Analysis included the construction of fault seal probability maps and shale smear diagrams. Fault seal probabilities were derived from an empirical relationship based on fault throw, reservoir/non-reservoir juxtaposition, and a shale smear factor, thus incorporating a measure of cataclastic gouge thickness and cementation, juxtaposition, and shale smear. A fault seal probability map, showing variations in fault seal probabilities both along the strike of faults as well as from fault to fault, was used to derive likely migration pathways into and through traps at the level of the Top Fangst Group. Shale smear diagrams, which independently corroborate the results of the fault seal analysis, were derived from shale thickness and fault throw. Fault seal probability was calibrated for hydrocarbon column height and differential pressure based on data from adjacent hydrocarbon pools. Fault seal analysis successfully explained the well results and allowed an assessment of undrilled prospects, providing a direction for future exploration. Dynamic fault seal is seen as a characteristic process in this area. Most faults are predicted to be sealing with respect to oil, but non-sealing with respect to gas. The Revfallet Fault Complex was determined as a sealing fault apart from its southern end. This may have been the entry point of overspill from Sm~rbukk to the Heidrun Platform. Sealing faults on the Heidrun Platform focused hydrocarbons to the Heidrun and Heidrun North areas, and created migration shadows to the east and west of Heidrun North.
Introduction This paper documents a fault seal analysis of the Greater Heidrun area carried out by Alastair Beach Associates Ltd. for Conoco Norway Inc., Statoil a.s. and their partners as part of a much larger integrated study. The integrated study covered parts of blocks 6507/7 and 6507/8 (PL095, PL124), operated by Conoco and Statoil, around the Heidrun Field (Figs. 1 and 2). The objectives of the fault seal study were to provide an assessment of the control fault seal may have on migration, trap integrity and filling history for the discoveries, pools and prospects within the Greater Heidrun area (Fig. 2), with the aim of furnishing results that would contribute to prospect definition and reduce exploration risk in the area. One method of risking the control of faults on migration and trap integrity is to assess fault seal probability and to produce fault seal probability maps. This was the method followed in this study. The structural style of the Heidrun area is the result of episodes of stretching and of salt tectonics. The patterns of sedimentation in the area generally reflect the simultaneous operation of these two processes. Based on seismic, well, structural and sedimentological data, the structural history of the Greater Heidrun study area is summarised by Bukoviks et al. (1984), Schmidt (1992), Knott et al.
(1993) and Spencer et al. (1993). From volumetric calculations and the distribution of hydrocarbons, it is conjectured that hydrocarbons in the Heidrun Field were derived, in the main, as overspill from the SmCrbukk Field to the southwest. Recent exploration efforts have focused on the areas around the Heidrun unit area, particularly to the north, following expected migration pathways, and resulted in the discovery of Heidrun North (well 6507/8-4; Fig. 2). The next two wells in the northern part of the area met with less success, however. Well 6507/7-10 encountered shows and the 6507/8-6 well was dry. These results indicate that the hydrocarbon migration pathways are complex and that further work was required to more fully understand them. The hydraulic properties of faults determine whether they act as migration barriers or pathways across the region. Fault seal analysis was applied, therefore, to predict the degree of fault seal across the area and hence define migration pathways and also to risk trap integrity. The fault seal analysis is also used to explain earlier well results and to calculate likely hydrocarbon column heights in undrilled prospects. Fault seal has not been perceived to be a problem in the Heidrun Field (Hemmens et al., 1994) but elsewhere in the Greater Heidrun area it is considered one of the key controls on migration, trap filling and trap integrity. A key part of the structural analysis of
Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mr
and A.G. Koestler. NPF Special Publication 7, pp. 125-138, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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A.I. Welbon, A. Beach, P.J. Brockbank, O. Fjeld, S.D. Knott, T. Pedersen and S. Thomas
distance plots and fault geometry analysis using fault plane diagrams. Both analyses highlight anomalous fault geometries and displacement gradients which were checked against the original seismic data to create a more robust structure map.
Fault seal analysis The general characteristics of fault seal have been described in the literature (e.g., Smith, 1966; Watts, 1987; Nybakken, 1991). The understanding of fault seal is based upon physical and theoretical modelling (Watts, 1987), studies from core (Knipe, 1992), hydrocarbon field databases (Knott, 1993), and studies of outcrops (Lindsay et al., 1993; Knott, 1994). In general, there are two types of fault-related seal (Fig. 3), the first resulting from juxtaposition of shales and other sealing lithologies against reservoirs (Fig. 3a). This first category is called juxtaposition seal. The second type is seal between juxtaposed reservoirs caused by reduction of pore throat radii in fault zones by either smear of impermeable layers along the fault surface, or through cataclasis and cementation within sandstones. This second category is called membrane seal (Fig. 3b). Knott (1993) used a database of faults in the North Sea to define empirical relationships between fault seal and some key parameters including fault throw, connectivity of reser-
Fig. 1. Regional structural map.
the Greater Heidrun area was to complete a detailed fault seal analysis based, in the main, on the depth structure map of the top Fangst horizon, which was first modified following the results of a fault analysis study. Fault analysis is an essential prerequisite to fault seal analysis because it examines the distribution of fault throw, a key input parameter to the fault seal evaluation. If the input data, particularly fault throw, are suspect, then the fault seal analysis does not achieve optimum results. The geometry of traps in the Greater Heidrun area has been defined on the basis of interpreted faults and horizons. Some degree of uncertainty was present in these trap geometries and in the location of faults which may act as barriers to fluid migration. As a result of this, fault analysis was carried out in order to refine the structural geometry. Although a detailed description of the fault analysis goes beyond the scope of the present paper, it nevertheless formed an important part of the study and provided a foundation upon which the fault seal analysis was established. The two main fault analysis techniques used were an analysis of displacement gradients using throw versus
Fig. 2. Study area and location map.
Fault seal analysis, offshore mid-Norway
a) Juxtaposition seal
127
mation, fault zones in thin-section can be seen to comprise areas of intense grain size reduction and cementation (Underhill and Woodcock, 1987; Knipe, 1989; Antonellini and Aydin, 1994). The.thickness of a fault zone within sandstone has been shown to be roughly proportional to fault throw (Engelder, 1974; Evans, 1990; Knott, 1994). Fault throw can therefore be used as a part of the process of predicting the probability of sealing along a fault zone due to cataclasis and fault-related cementation; particularly in sandstone-rich successions such as the Fangst Group and the Are and Tilje Formations (Fig. 4).
Connectivity
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Fig. 3. Fault-related seals classification.
voirs across a fault, and net to gross ratio. The fault seal probability equation used in this project is based on these relationships. Fault seal probability analysis is a quantitative method that allows an assessment of the risk of a fault acting either as a barrier to hydrocarbon migration, or as a trapping element within a structure. Fault seal probability is a value ranging from one to zero where a value of one is the highest probability for sealing, and zero is the lowest. This value is derived from the equation that combines the main parameters involved in the formation of fault seal. These parameters, fault displacement, connectivity, and net to gross ratio, are related to the processes of cataclasis and cementation, juxtaposition, and shale smear. The parameters, their measurement and impact on fault seal, are discussed below.
Fault displacement Fault displacement is usually taken as fault throw from depth structure maps. A relation has been determined, from empirical oil and gas field data (Knott, 1993) and outcrop studies (Knott, 1994), which shows that there is a positive correlation between the probability of a fault sealing and fault throw divided by reservoir thickness (Dn). For sandstones that are cemented prior to defor-
Sealing also occurs across a fault due to juxtaposition of non-sealing lithologies with sealing lithologies, such as shale against reservoir sandstones. A method of quantifying juxtaposition has been incorporated into the fault seal probability technique and involves the calculation of the connectivity, or fraction of sandstone in geometric contact across the fault. By offsetting a stratigraphic template from the footwall against a stratigraphic template from the hangingwall a connectivity plot is obtained (Fig. 5). At each increment of offset, which mimics the variation in throw along the fault surface, the thickness of sandstone in geometric contact across the fault is measured as a fraction of the total thickness of sandstone in the stratigraphy under study. This fraction, for a given displacement, is called the connectivity, and a connectivity plot is derived by plotting the connectivity against the corresponding normalised displacement (Dn). The connectivity value is a quantitative estimate of the degree of juxtaposition of sandstone against sandstone for given stratigraphies and a range of fault throws. The connectivity value ranges from zero to one and, from empirical studies (Knott, 1993), it has been shown that connectivity is proportional to fault seal probability.
Stratigraphic templates Composite logs were used to derive stratigraphic templates (Fig. 5) for input into the analysis. Gamma, sonic and resistivity logs were used to make an assessment of potential reservoir and non-reservoir rocks and the stratigraphic templates were obtained by dividing the interval of interest into reservoir and non-reservoir sections. Since faulting predated, or was synchronous with, much of the erosion in the area of the Heidrun Field, preserved stratigraphies do not always represent the stratigraphy that was present at the time of faulting. Therefore, in some instances, a synthetic stratigraphy was added on top of the existing well stratigraphy to model the missing section.
128
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Fig. 4. Generalised stratigraphy of the Greater Heidrun area.
Also, wells do not very often penetrate beneath the Jurassic section and, therefore, a synthetic stratigraphy needed to be added to the base of each well stratigraphy where fault throws were large enough to offset Jurassic against Triassic rocks. In both these cases, synthetic stratigraphies were added from existing well penetrations that most closely represented the missing, or unpenetrated sections. An example of a stratigraphic template and corresponding connectivity plot is given in Fig. 5. In cases where detailed stratigraphies are unknown, or difficult to model, such as the Upper Jurassic and Lower Cretaceous, both of which contain potential reservoir sandstones, it is still possible to gain a good approximation of fault seal probability using
Fig. 5. Stratigraphic template and connectivity plot.
Fault seal analysis, offshore mid-Norway
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the relationship between throw, net to gross ratio and connectivity derived by Knott (1993). The observation that the slope of a best fit straight line through the data on a connectivity plot is proportional to the net to gross ratio of the stratigraphy can be used to estimate fault seal probabilities, even without knowing the detailed bed-by-bed composition of the stratigraphy. A straight line can be drawn through connectivity plots from well data. This straight line approximates the actual relationship between Dn and C and the connectivity value thus obtained can then be input into the fault seal probability equation as usual. Sensitivity studies of the impact of the stratigraphy used in calculating fault seal probabilities in the study were carried out. These indicated that for large fault throws (say several hundred metres), significant variation in fault seal probability values occurs (roughly 10-30%; Fig. 6). For smaller throws, however, fault seal probability values are relatively insensitive to the stratigraphies used. Net to gross The last variable to be included in the fault seal probability equation is the net to gross ratio. The assumptions used in the formulation of the equation are that with low net to gross ratios, say <0.4, there is a greater likelihood for sealing due to shale smear than in higher net to gross ratio successions (see also Bouvier et al., 1989; Harding and Tuminas, 1989). Clearly, in any given situation each of the parameters described above will be acting in concert, and therefore, a realistic assessment of fault seal must take into account the combined effects of different
fault seal mechanisms. Based upon empirical relationships, the fault seal probability equation incorporates all of these parameters together to provide an overall assessment of fault seal. The results of the fault seal probability technique from the Greater Heidmn study area give good matches with observations from well test and fluid contact data and therefore indicate that the technique can be applied in basins outside the North Sea such as the mid-Norway margin. For this study the relatively simple and pragmatic approach described above has proved successful.
Fault seal probability maps The presentation of the results of the fault seal analysis is best seen on fault seal probability maps. These show the variation in fault seal probability not only from fault to fault, but also along the strike of faults. The maps are colour-coded to separate out faults that have a high, moderate or low probability for seal, coloured red, yellow and green, respectively. From experience in the North Sea, particularly from producing fields, it has been found that sealing faults that behave as barriers to migration and during production have fault seal probability values that range from 1 to 0.67; these are coloured red. Faults can also behave as temporary seals, for example they may leak dynamically during filling of the trap over geologic time, but conversely, during the production time scale, they may act as barriers to flow of hydrocarbons. These faults typically have fault seal probability values in the range 0.67-0.33; these are coloured yellow. Faults that leak on both geologic and production time scales have values between 0.33 and 0; these are coloured green.
130
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Fig. 7. Top Fangst fault map showing stratigraphic templates used.
The stratigraphic templates used, and the sub-areas which they cover, as input for the Fangst Group fault seal probability map, are shown in Fig. 7. In general, the values of fault seal probability over the Fangst map (Fig. 8) are high to moderate with very few nonsealing (green) faults except in the Heidrun Field.
This implies that the majority of mapped faults will be either (1) sealing over geologic time (red faults) and therefore barriers to migration or will form traps, or (2) the faults will be temporarily sealing (i.e., dynamic seals, yellow faults) and will become sealing either during filling of the traps or during production
Fault seal analysis, offshore mid-Norway
131
Fig. 8. Top Fangst fault seal probability map.
when reservoir pressures are modified, the sealing capacity of the faults depending on their hydraulic properties. Fault seal probabilities along the Revfallet Fault Complex are generally high to moderate with nearly
all segments west of the Heidrun Field having values of 1. In the south the values reduce and a moderate probability segment occurs to the south west of the Heidrun Field. The fault bounding the tilted fault block to the west of the Revfallet Fault Complex has
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A.I. Welbon, A. Beach, P.J. Brockbank, O. Fjeld, S.D. Knott, T. Pedersen and S. Thomas
Not all faults in the graben to the northeast of Heidrun North (north of 6507/8-4 and -6) have been assigned fault seal probability values because erosion has removed Fangst Group from most footwalls, and fault throws have not been estimated for the whole of the eroded area. There is also a critical trap risk in this graben as a result of the uncertainty in the fault geometry in the far north of the prospect, at the edge of the seismic survey. Where the fault throws have been estimated, fault seal probability values are high to moderate. The graben to the east of Heidrun North, penetrated by well 6507/8-6, is almost entirely surrounded by high values of fault seal probability except at the northern end where moderate fault seal probabilities occur. Most internal faults within the graben have values at the high end of the moderate category.
mainly moderate values of fault seal probability with a small segment having high fault seal probabilities at the centre of the fault. In the Heidrun Field, fault seal probabilities range from low (i.e., green faults), to the low end of the moderate class (i.e., yellow faults). The eastern bounding fault has a moderate fault seal probability marked on the map but this is speculative, based on extrapolation upwards of fault throws on the top Coal Marker 1 map (not included). Heidrun North is surrounded by either unconformities at top Fangst level or faults with high to moderate values of fault seal probability. Due to the erosion of the Fangst, it was not possible to ascertain the exact values of fault seal probability on the fault separating the Heidrun Field from the Heidrun North structure. In order to address this, a restored structure map was produced based on extrapolation of the isopach from Top Coal Marker 1 to Top Fangst over the eroded area. Fault throws were then interpolated based on this restored structure map. The horst to the west of Heidrun North, at top Fangst level, is bounded on its western side by a fault with a very high probability for sealing. In the east, this horst is bounded by a fault with moderate to high probability for sealing and the Base Cretaceous unconformity. The graben between the horst and Heidrun North (penetrated by well 6507/7-10) is almost entirely surrounded by faults with moderate probabilities for sealing, small segments with high fault seal probability, and one portion bounded by the Base cretaceous unconformity. The northwestern side of Heidrun North and the highs due north and northeast have high or moderate fault seal probability, with moderate values at the high end of that category.
Shale smear maps
Another useful tool for determining fault seal characteristics is the shale smear map. Although the fault seal probability calculation, derived from an empirical database which contains faults which were affected by shale smear, already incorporates a shale smear factor (see also Lindsay et al., 1993), the purpose of producing shale smear maps is to define the shale smear envelope for individual shale beds across fault surfaces. They can also be used as an independent check on the fault seal probability calculations. Only one shale smear map was produced in the study, for the Revfallet Fault Complex, where the greatest thickness of syn- to post-rift shale occurs. A shale smear map is constructed by firstly pro
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Fig. 10. Displacement contour plot: Revfallet Fault Complex.
ducing a fault plane diagram (Fig. 9), which shows the intersections of the key horizons with the fault plane in both the footwall and the hangingwall. From the fault plane diagram, a fault displacement contour plot was derived (Fig. 10). A shale map was produced
next (Fig. 11), which shows the intersection of the main, thick shale intervals with the fault plane. In Fig. 11, only the footwall intersections are shown. Only those shale intervals with thickness greater than 10 m are represented because shale smears only develop
Fig. 11. Shale map of Revfallet Fault Complex. Shows footwall shale units superimposed on to the fault plane.
134
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continuously when shale intervals are thick and fault throws are small (Lindsay et al., 1993; Yielding et al., 1997). One method of predicting when smears will start to become discontinuous is based on the relationship developed by Lindsay et al. (1993). In this, smears become discontinuous when fault throw (t) divided by shale bed thickness (7) is greater than 7, i.e., shale smear is likely to be discontinuous when t/T > 7. Shale units thinner than say 10 m are likely to be very discontinuous for throws greater than about 100 m and for the Revfallet Fault Complex, can therefore be ignored. The shale smear map was constructed by overlaying the shale map and the displacement contour plot, and shading in the area from the footwall cutoff of a shale bed down to the displacement contour equal to 7 times the thickness of the shale bed. This area represents the surface of the fault where the shale smear will be continuous and will be a significant barrier to hydrocarbon migration. Where the displacement value is >7 times the thickness of the shale bed, the smear is likely to be discontinuous and is unlikely to be a barrier to hydrocarbon migration. This mapping of shale smear is repeated for all thick shale units. The shale smear map (Fig. 12) is the end result of the above outlined process and shows the areas of likely continuous shale smear for each of the thick shale intervals and areas of discontinuous shale smear. The form of the shale smear envelope is a result of the interplay between the variation in fault throw, the thickness variation of the shale intervals,
and the shale smear factor chosen which depends in part on the rheology of the shale at the time of faulting (Knipe, 1992; Gibson, 1997). For the Revfallet Fault Complex, the shale smear of the two thickest shale sections are continuous and overlapping. This independently supports the high values of fault seal probability shown on the fault seal probability maps.
Migration pathways and filling history Two formations are believed to be potential source rocks for hydrocarbon generation in the Greater Heidrun area: the Spekk Formation (Fig. 4) and the coals of the Are Formation (Fig. 4; Sancar, 1992). It is believed that the Spekk Formation is of type II kerogen and generates primarily oil at low to moderate maturity and gas at higher maturity measures. The /~re Formation is represented by type III kerogen and is believed to generate primarily gas. On the basis of regional studies of the Haltenbanken area (Sancar, 1992; Vik and Hermanrud, 1992), hydrocarbon generation from the Spekk and ]kre Formations in the kitchen area is relatively young. The Greater Heidrun area is marginally mature with respect to both Spekk Formation and/~re Formation source rocks (Vik and Hermanrud, 1992). Only small volumes in the deeper parts of the area expelled significant amounts of hydrocarbons. The generally subdued and smooth structural relief in the area also contributes to the loss of hydrocarbons due
Fig. 12. Shale smear map: Revfallet Fault Complex.
Fault seal analysis, offshore mid-Norway
135
Fig. 13. Top Fangst fault map showing pressure cells.
to secondary migration. Accumulated hydrocarbons in the Heidrun Field are mostly oil, some of which is biodegraded, with a significant gas cap. The primary drainage area of the Heidrun Field is not able to yield enough hydrocarbons to fill the proven field (Vik and Hermanrud, 1992). The excess volumes must be de-
rived from the SmCrbukk and SmCrbukk South fields by spill. The gas/oil contact for Heidrun and Heidrun North coincides with the four way dip closure and indicates the faults were likely leaking with respect to gas. Consequently the fault seal probability results have stronger implications for oil migration and trap-
136
A.L Welbon, A. Beach, P.J. Brockbank, O. Fjeld, S.D. Knott, T. Pedersen and S. Thomas
problematic. The main pathways have been diverted away from this graben and are focused on Heidrun and Heidrun North.
ping than gas which appears to leak across most faults (see also Heum, 1996). The fault seal probability maps can be used to derive oil migration pathways. It is assumed that high fault seal probability faults are considered to be barriers to oil migration, moderate fault seal probability faults are considered to be partial barriers to migration, and faults coloured green provide no barrier to migration. Migration across the fault bounding Heidrun and Heidrun North is proven and is probably achieved by dynamic leakage because of the significant hydrocarbon column within the Heidrun Field. West of Heidrun the Revfallet Fault Complex provides an effective migration barrier (Fig. 8). Prospects situated east of the fault complex are poorly located for migrating hydrocarbons from the DOnna Terrace further northwest. To the south along the Revfallet Fault Complex, throw and fault seal probability reduce and there may be the possibility of hydrocarbons passing across the fault along this segment given sufficient overpressures during expulsion. On the Heidrun platform, the graben to the east of Heidrun North, penetrated by well 6507/8-6, is probably in a migration shadow at Fangst level, particularly with respect to hydrocarbons that migrated into the Heidrun Field. It is bounded by faults with generally high fault seal probabilities. Charge to the Fangst Group in the graben to the northeast of Heidrun North is possible through the Are reservoirs in the latter structure, given the dynamic sealing faults (yellow) defined in this study to separate the two areas. The horst to the west of Heidmn North appears to be in a migration shadow adjacent to its main western bounding fault. Charge to the intervening graben, penetrated by well 6507/7-10, is also
Pressure data and hydrocarbon column heights In general, in the Greater Heidrun there are significant pressure differences on a regional scale between areas bounded by the major sealing faults. Fault seal probability can thus be used to assist in the definition of possible pressure compartments. The same faults also bound the main hydrocarbon-bearing traps and prospects, particularly those that rely on fault seal for success.
The inferred boundaries to the main pressure cells are shown in Fig. 13 for the Fangst level. The simple picture is a general decrease in reservoir pressure from west to east, with a large drop over the Revfallet Fault Complex, then small drops for each fault block going eastward. There is roughly a 2000 psi pressure difference between the water-bearing Fangst Group in the hangingwall to the Revfallet Fault Complex and the rest of the Heidrun Field. Pressure differences across faults for which fault seal probability values have been calculated, using well data in the surrounding region (not shown), provide a means of calibrating the fault seal probability technique against differential pressure (Fig. 14). It can be seen from Fig. 14 that there is a positive correlation between pressure difference and fault seal probability. Higher pressure differences are correlated with higher values of fault seal probability. Yielding et al. (1997) show similar relationships between differential pressure and other measures of fault seal. In
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fault seal in the area has enabled a quantitative assessment of risk due to fault seal to be carried out. In detail, the picture of possible migration scenarios based on the fault seal analysis maps, has assisted in ranking of prospects and contributed to the direction for future exploration efforts.
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9
05
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Fault seal probability Fig. 15. Oil column height versus fault seal probability. (Note scale change on y axis.)
We thank Conoco Norway Inc., Statoil a.s., Neste Petroleum a.s., and Saga Petroleum a.s., for giving permission to publish this work. The conclusions presented in this paper are derived from the results of one part of a much larger, integrated study. The conclusions are primarily those of Alastair Beach Associates Ltd., and may not necessarily reflect the individual Licencee's (Conoco, Neste Petroleum, Statoil, Saga) conclusions. Thanks to Michelle Smith, Barbara Bruce and Martin Kidd for preparing the figures.
References a limited analysis, we also show that fault seal probability can also be calibrated against oil column height (Fig. 15). This type of relationship can be used to predict possible hydrocarbon column heights in undrilled prospects or compartments.
Conclusions Fault seal analysis has defined the main migration pathways, the regional pressure distribution and the likely seal characteristics of undrilled structures where fault seal is a critical prospect risk in the Greater Heidrun area. The fault seal analysis explains most of the present well results, including wells 6507/7-10 and 6507/8-6, and provides a basis for the risking of future prospects. For example, the Revfallet Fault Complex is confirmed as a major migration barrier, but in the south of the study area, hydrocarbons may have crossed the fault zone at Fangst levels or shallower. Many other faults currently mapped in the study area are interpreted to have dynamic seals, i.e., they may have leaked during hydrocarbon migration and filling of traps. Heidrun and Heidrun North are the main foci of migrating hydrocarbons into the area. Heidrun North may be in dynamic communication with the Heidrun Field at Are level. Further remigration from the Heidrun North discovery into exploration prospects on the same structural trend to the northeast is a critical element to the success of these prospects. The graben to the east of Heidrun North is poorly situated for hydrocarbon charge and is in a migration shadow provided by the faults bounding the graben. The increased understanding of the distribution of
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. 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. Bukoviks, C., Shaw, N.D., Cartier, E.G. and Ziegler, P.A. 1984. Structure and development of the mid-Norway continental margin. In: A.M. Spencer et al. (Editors), Petroleum Geology of the North European Margin. Norwegian Petroleum Society, Graham and Trotman, London, pp. 407-423. Engelder, J.T. 1974. Cataclasis and the generation of fault gouge. Bull. Geol. Soc. Am., 85: 1515-1522. Evans, J.P. 1990. Thickness-displacement relationships for fault zones. J. Struct. Geol., 12: 1061-1065. Gibson, R.G. 1997. Physical character and fluid flow properties of sandstone-derived fault gouge. Geol. Soc. Spec. Publ. Harding, T.P. and Tuminas, A.C. 1989. Structural interpretation of hydrocarbon traps sealed by basement normal fault blocks at stable flanks of foredeep basins and rift basins. Am. Assoc. Pet. Geol. Bull., 73: 812-840. Hemmens, P.D., Hole, A., Reid, B.E., Leach, P.R.L. and Landrum, W.R. 1994. The Heidrun Field. North Sea Oil and Gas Reservoirs III. Kluwer, Dordrecht, pp. 1-23. Heum, O.R. 1996. A fluid dynamic classification of hydrocarbon entrapment. Pet. Geosci., 2: 145-158. Knipe, R.J. 1989. Deformation mechanisms - recognition from natural tectonites. J. Struct. Geol., 11: 127-146. Knipe, R.J. 1992. Faulting processes and fault seal. In: R.M. Larsen et al. (Editors), Structural Modelling and its Application to Petroleum Geology, Special Publication, 1. Norwegian Petroleum Society, pp. 325-342. Knott, S.D. 1993. Fault seal analysis in the North Sea. Am. Assoc. Pet. Geol. Bull., 5: 778-792. Knott, S.D. 1994. Fault zone thickness versus displacement: results from Permo-Triassic sandstone outcrops in NW England. J. Geol. Soc. London, 151: 17-25. Knott, S.D., Burchell, M.T., Jolley, E.J. and Fraser, A.J. 1993. Mesozoic to Cenozoic plate reconstructions of the North Atlantic and hydrocarbon plays of the Atlantic margins. In: J.R. Parker
138
A.L Welbon, A. Beach, P.J. Brockbank, O. Fjeld, S.D. Knott, T. Pedersen and S. Thomas
(Editor), Petroleum Geology of Northwest Europe: Proc. 4th Conf., Geological Society, London, pp. 953-974. Lindsey, N.G., Murphy, F.C., Walsh, J.J. and Watterson, J. 1993. Outcrop studies of shale smears on fault surfaces. Special Publication 15. International Association of Sedimentologists, pp. 113123. Nybakken, S. 1991. Sealing fault traps - an exploration concept in a mature petroleum province: Tampen Spur, northern North Sea. First Break, 9: 209-222. Sancar, 1992. Statoil In-House Basin Modelling Report. Schmidt, W.J. 1992. The structure of the mid-Norway Heidrun field and its regional implications. In: R.M. Larsen et al. (Editors), Structural Modelling and its Application to Petroleum Geology, Special Publication, 1. Norwegian Petroleum Society, pp. 381395. Smith, D.A. 1966. Theoretical considerations of sealing and nonsealing faults. Am. Assoc. Pet. Geol. Bull., 50: 363-374.
A.I. WELBON A. BEACH P.J. BROCKBANK O. FJELD S.D. KNOTT T. PEDERSEN S. THOMAS
Spencer, A.M., Birkeland, O. and Koch, J.O. 1993. Petroleum geology of the proven hydrocarbon basins, offshore Norway. First Break, 11: 161-176. Underhill, J.R. and Woodcock, N.H. 1987. Faulting mechanisms in high porosity sandstones: New Red sandstone, Arran, Scotland. In: M.E. Jones and R.M.F. Preston (Editors), Deformation of Sediments and Sedimentary Rocks, Special Publication 29. Geological Society, pp. 91-105. Vik and Hermanrud, 1992. Statoil In-House Basin Modelling Report. 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., Freeman, B. and Needham, D.T. 1997. Quantitative fault seal prediction. Am. Assoc. Pet. Geol. Bull., 81:987-917.
Alastair Beach Associates Ltd., 11 Royal Exchange Square, Glasgow, G1 3AJ, UK (now at Statoil a.s., Stavanger, Norway) Alastair Beach Associates Ltd., 11 Royal Exchange Square, Glasgow, GI 3AJ, UK Alastair Beach Associates Ltd., 11 Royal Exchange Square, Glasgow, G1 3AJ, UK Phillips Petroleum Company Norway, P.O. Box 220, 4056 Tananger, Norway Independent Consultant Conoco Norway Inc., Randberg, PO Box 488, N-4001 Stavanger, Norway Statoil a.s., Stavanger, Norway
139
Fracture flow and fracture cross flow experiments A. Makurat, M. Gutierrez and L. Backer
Flow through single fractures depends strongly on the fracture aperture and the flow channels formed by the fracture surface contact areas. Since fracture apertures are highly stress dependent, production induced stress variations will change fracture apertures and in addition cause blockage of the flow channels by deformation products during shearing. This gouge formation may, together with changes of the pore structure in the fracture walls, also have an influence on the fracture cross flow. The laboratory results presented in this paper indicate that favourably oriented fractures can dramatically increase the total flow, even in rather permeable sandstones. However, the same fractures, if oriented nearly perpendicular to the flow direction, can reduce fracture cross flow substantially. The effects of fracture normal stress, shear displacement, intact rock strength and permeability and fracture surface properties on fracture flow and cross flow are demonstrated by the results presented.
Introduction The bulk permeability of a porous rock can either be increased (Narr and Currie, 1982; Nelson, 1981; Tillman, 1983; Watts, 1983; Makurat, 1985; Makurat et al., 1990, 1995b) or decreased (Dunn et al., 1973; Pitman, 1981; Aydin and Johnson, 1983; Gabrielsen and Koestler, 1987; Lorenz, 1988) by the existence of fractures. The effect of conductive fractures on the productivity of reservoirs and different simulation procedures are well published (e.g., Barenblatt et al., 1960; Barenblatt, 1963; Warren and Root, 1963; Kazemi et al., 1969; Kazemi and Merill, 1979; Reiss, 1980; Van Golf-Racht, 1982; Bear and Berkovitz, 1987; Dean and Lo, 1988). Teufel and Rhett (1991), Heifer et al. (1994), Gutierrez et al. (1994) and Makurat et al. (1995b) have demonstrated the change in the reservoir stress state due to production related pore pressure changes and temperature variation. Beside these global stress changes, local geological structures and heterogeneities, such as faults and fractures can cause spatial variations of the in-situ stress state. Simulations of two-phase flow through a fractured sandstone reservoir with stress dependent fracture apertures (Gutierrez et al., 1995) have shown that high fluid velocities along fractures can reduce sweep efficiency and cause early water breakthrough. Whether fractures act as barriers/seals or conduits will depend mostly on their surface properties (e.g., roughness, mineralogy, strength, infilling), their spatial distribution (including parameters such as length, width, continuity, spacing, orientation and dip) and the state of stress. Fracture sealing can be due to several mechanisms. A common mechanical sealing mechanism for the flow along fractures is the combination of a negative dilation angle with the formation of gouge material during shearing. Since the flow rate
through a single fracture is proportional to the fracture aperture cubed (Q o~ e3), small variations in fracture apertures will have a strong influence on fracture flow. Fracture cross flow has been shown to be strongly influenced by the reduction of the pore space in the vicinity of the fracture surfaces and the permeability of the gouge material. Experimental work conducted at NGI through the last decade now allows the effect of production induced stress changes on the permeability of fractures in different rock formations to be quantified. To calculate flow through single fractures, the parallel plate model is commonly used: k =~
e
2
(1)
12 where k is the fracture permeability and e is the hydraulic fracture aperture. This model assumes laminar flow between two perfectly smooth and parallel plates. However, Experiments have shown that the real mechanical aperture (E) and the hydraulic conducting aperture (e) are not equal. The cubic law (e = E) is only valid for very open fractures and/or for fractures with smooth fracture surfaces (low JRC). The mechanical aperture E can be converted into the hydraulic conducting aperture e, by using Eq. (2) (Barton et al., 1985): JRC 2
e = ~
(E/e) 2
(/zm)
(2)
where E is the mechanical fracture aperture, J R C is the fracture roughness coefficient (JRC = 1, very smooth fracture surface, J R C = 20, extremely rough fracture surface). Fig. 1 illustrates the relation between e, E and J R C as expressed by Eq. (2).
Hydrocarbon Seals: Importancefor Exploration and Production edited by P. M011er-Pedersen and A.G. Koestler. NPF Special Publication 7, pp. 139-148, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
140
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Fracture flow and cross-flow measurements Results from different laboratory tests have been chosen to demonstrate the combined effect of shear displacement and dilation/closure under different normal stresses on fracture flow and fracture crossflow. These tests simulate the in situ (stressed, "closed") state of critical single fractures and their alteration by increasing or decreasing normal and shear stresses. Closure, opening or shear-induceddilation of the fracture can be caused by these stress changes. Normal/shear displacements and flow are recorded continuously. The flow tests are conducted such that all samples are exposed to several pure normal stress cycles (no shear displacement) to consolidate the fracture. The basic assumption is that no major fracture surface degradation occurs during this pure normal stress loading. Thereafter the fracture is subjected to increasing shear displacement under controlled normal stress conditions. The identification of mechanisms responsible for gouge formation and local pore size reduction during sheafing and their influence on flow along/across fractures is the main goal of these tests. Only the results related to the shear part of the tests are presented in this paper. In the following, the term fracture flow refers to the flow along the fracture alone, whereas bulk flow refers to the flow perpendicular to the fracture plane, through the intact rock, across the fracture and through the intact rock on the other side of the fracture plane. For all the results, the numbers along the
curves represent the ratio between the effective normal stress acting across the fracture plane and the uniaxial compression strength of the intact rock (stress to strength ratio Un'/ac).
Test equipment The tests were conducted in three different fracture flow cells. All three devices allow the measurement of fracture flow and bulk flow and normal and shear displacement. Fig. 2 shows a horizontal cross-section through NGI's coupled shear flow test (CSFT) cell. This biaxial cell allows fractured samples (14 x 12 x 5 cm) to be displaced by a maximum 8 mm under controlled fracture normal stresses and temperatures up to 80~ Variation in fracture aperture (dilation) is measured by a total of four displacement gages, whereas shear displacement is measured by a total of two gages. The flow measurements, as illustrated in Fig. 2, measure the total flow in the direction of the fracture plane and do not differentiate between fracture and matrix flow. To quantify the matrix flow component, tests on nonfractured samples with the same principal geometry as the fractured tests and under the same stress conditions, were conducted in the CSFT cell. Fig. 3 shows a vertical cross-section of NGI's triaxial coupled shear flow test (TCSFT) cell. This modified triaxial cell allows higher confining stresses and the testing of smaller samples compared to the CSFT cell. The tested samples had a diameter of
Fracture flow and fracture cross flow experiments
141
10cm and fracture planes dipping about 52 ~ with respect to a horizontal reference line. The fracture cross flow results presented in this paper are based on measurements made with this cell. Fracture flow results from large scale laboratory tests in NGI's polyaxial cell (see Fig. 4) are also presented, and compared to the fracture flow tests conducted in the CSFT cell. The block size for all three tests was 30 x 30 x 40 cm with fracture planes oriented either diagonally (L~igerdorf chalk, 42 x 40 cm) or parallel to the 30 x 40 cm horizontal block sides (both sandstone tests).
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Rock types tested The results presented are based on tests conducted on chalk and two different sandstones. The chalks of L~igerdorf, North Germany, are of Upper Cretaceous age, highly bioturbated and with 90-98% carbonate content. The chalks have been pushed upwards by an underlying salt ridge, causing brittle fracturing of the chalk and conjugated fault zones. This allows the sampling of suitable natural fractures (see Fig. 5). L~igerdorf chalk has about 44.4% porosity, 5.1 mD matrix permeability, and 2.1 MPa uniaxial compressive strength at 22% water content. The block, with a 45 ~ inclined natural fracture, was sealed, instrumented and placed in NGI's pressure tank. The Red Wildmoor sandstone is a Lower-Triassic, fine-grained and well sorted sandstone. The mineralogy is dominated by 74% quartz with some feldspar (14%) and 12% clay minerals. The average porosity
v///A ~/A z//A
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Fig. 3. NGI' s TCSFT, triaxial coupled shear flow cell.
is 28.1%; matrix permeability is 0.29 D, and the average uniaxial compressive strength is 4.7 MPa. The Yellow Brumunddal Sandstone is a Triassic, predominantly aeolian sandstone, with pronounced anisotropic properties, and with feldspar that has been weathered to clay. The average porosity is 14%, and the matrix permeability varies between 3.8 mD (perpendicular to bedding planes) and 35 mD (parallel to bedding planes). The average uniaxial compressive strength is 19 MPa.
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Fracture flow results Figs. 6 and 7 show the results from the CSFT fracture flow experiments with Red Wildmoor (RWS) and Yellow Brumunddal sandstone (YBS) samples. Tests on non-fractured RWS and YBS samples resuited in permeability values of 3.5 x 1 0 -9 c m 2 and 1.0 x 10 -~l cm 2, respectively. These measurements are about four orders of magnitude below the total flow measurements. It can therefore be assumed that the measured flow is predominantly due to flow through the fractures. All RWS tests were conducted under stress to strength ratios close to 1, and show an initial reduction of fracture permeability with the onset of shear. After 100-200/tm shear displacement the permeability increases again until the end of the tests (see Fig. 7). The initial drop in fracture permeability corresponds to the measured negative dilation (closure) in the same shear interval shown in Fig. 6. The YBS samples were sheared under stress to strength ratios between 0.16 and 0.48. The two tests with the lowest stress to strength ratios (0.16 and 0.29) show a corresponding positive dilation after some initial closure (see Fig. 6). However, this is not reflected in the fracture permeabilities (see Fig. 7). More or less independent of the stress to strength ratio, all YBS tests show an increase of fracture permeability with increasing shear. The dilation curves are similar for the RWS and YBS, both with respect to the principal shape and the magnitude. However, the RWS fractures show permeabilities which are substantially higher compared to the YBS fractures. Furthermore, the RWS fracture
permeabilities increase more during shear compared to the YBS fracture permeabilities. A comparison of the joint roughness coefficient (JRC) before and after shearing shows an increase of 44% for the loosely cemented RWS, whereas the fine grained and well cemented YBS shows a 14% JRC reduction during shear. The grains of the RWS seem to act as propants in the fracture plane, whereas the increase in fracture roughness, due to the combination of high stress to strength ratios and weak cementation, causes an increase in fracture aperture and a related increase in fracture permeability. Figs. 8 and 9 show the results from large scale block tests on RWS, YBS and L~igerdorf chalk (LC). The dilation curves for the two sandstones (Crn'kr~ = 0.18 and 0.16) are similar to the low O'n'/O"c YBS CSFT results. The LC sample, however, shows some initial dilation and then continuous closure until the end of shear. The initial dilation can be related to the occurrence of numerous fractures in the block (see Fig. 10), whereas the subsequent closure is related to the fracture surface degradation. One should also notice the higher Crn'/Oc ratio (=0.6) for the LC test compared to the sandstone tests (=0.17). The positive dilation of the sandstone fractures coincides with the marked increase in fracture permeability (Fig. 9). The fracture with the strongest dilation (YBS) also shows the most pronounced increase in permeability. The general decrease in the LC fracture permeability is well related to the fracture dilation behaviour. However, the continuing closure between 3.5 and 6 mm shear displacement does not result in a further decrease of fracture permeability. Once the fracture has been filled with gouge material, fracture permeability
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Fracture flow and fracture cross flow experiments
143
is more controlled by the gouge material permeability than fracture shear displacement. Despite the substantial lower stress to strength ratios (=0.11) during the large scale RWS test compared to the RWS CSFT tests (--0.94), similar fracture permeabilities were measured. When comparing these results, it has to be considered that lower Crn'/Crc ratios of the large scale test are expected to result in more dilation during shear (increase in fracture aperture). However, since this fracture is substantially larger (L = 40 cm, A = 1200 cm 2) than the CSFT samples (L = 12 cm, A = 168 cm2), a pronounced scale effect will result in reduced fracture roughness and fracture surface strength (Barton, 1985), and hence in reduced dilation during shear.
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When a fracture becomes mismatched during shearing, damage of the fracture surface is induced. Such damage may occur at the asperity contact points due to stress concentration and causes gouge formation and grinding of the asperity contacts. Evidence of asperity damage and modification of the flow potential across fractures is provided by the laboratory data presented. Visual inspection of the fracture surfaces after test completion shows massive gouge production for all rock types tested (see Fig. 11). The effect of shear displacement under different normal stress conditions on fracture cross-flow for RWS, YBS and LC is illustrated by the TCSFT results in Figs. 12-14. The (current) bulk permeability (Kc) at any given shear displacement has been normalized with the initial bulk permeability prior to 4111) - _
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shear. This normalization is based on the assumption that the initial bulk permeability prior to shear is identical to the intact rock permeability. The general observation for all three rock types is decreasing bulk flow with increasing a~'/ac ratio, and some effect of the fracture shear displacement on the bulk flow. For the clay containing YBS, bulk flow is actually reduced by 90% for an'/ac = 1.3. The strongest rock (YBS) shows the most pronounced crossflow reduction, whereas the weakest rock (LC) shows the least reduction. The explanation for the limited cross-flow reduction for the LC sample lies in the low matrix permeability in combination with its special mineralogical composition (>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
145
Fracture flow and fracture cross flow experiments 2 -2 m Y e l l . w Brumunddal Sandstone ~
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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).
Test g 4 1.0
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Fig. 14. Fracture cross flow: L~igerdorf chalk. Normalized bulk permeability versus shear displacement.
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.
A. Makurat, M. Gutierrez and L. Backer
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
Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mr
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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-
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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
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T.R. Harper and E.R. Lundin
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
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Fault seal analysis: reducing our dependence on empiricism
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-
T.R. Harper and E.R. Lundin
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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) f
'~,~
~Sand
(5 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.
Fault seal analysis: reducing our dependence on empiricism
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 <0.05 mD from sandstones "collected near fault zones where granulation seams are developed" in which porosity had been reduced by both quartz cement and cataclasis. Jamison and Steams (1982) reported reductions of permeability by "microfaulting" by "as much as three orders of magnitude" in sandstone they interpreted to have been deformed at a burial depth of 2 km. Harper and
T.R. Harper and E.R. Lundin
Moftah (1984) attributed the low well productivity of wells in Unit 1 of the Nubian Sandstone in the Ras Budran field, Gulf of Suez, to the influence of shear bands in the immediate vicinity of the well. Two measurements of core plugs revealed shear band permeabilities 58 and 27 times less than that of the reservoir rock outside the shear band. Subsequently, Freeman (1990) and most recently Antonellini and Aydin (1994) documented a far greater number of measurements taking samples from outcrop. Relative to the undeformed sandstone, Freeman (1990) measured permeability reductions of 0.5-3 orders of magnitude in shear bands in plugs taken from more than 200 samples of shear bands in the Jurassic Aztec formation in Nevada. Antonellini and Aydin (1994) reported permeabilities normal to shear bands in six sandstone formations based on image analysis and minipermeater measurements. They concluded that shear bands have permeabilities of 1--4 orders of magnitude less than the surrounding rock, with an average reduction of 3 orders of magnitude. It was noted that the permeability reduction was greatest when the porosity of the host rock was greatest, which appears from their plotted data to correspond to rocks of permeability greater than approximately 1 Darcy. This quite extensive database of shear band permeabilities offers the possibility of estimating the trapping potential of shear bands if a relationship between permeability and capillary pressure can be identified. One possible route is to model the drainage process for a range of permeabilities. Numerical modelling was therefore used to identify the likely form of the capillary pressure-permeability relationship. Drainage (i.e., displacement of a wetting fluid by a non-wetting fluid) was modelled by an invasionpercolation process (Wilkinson and Willemsen, 1983). This implies that viscous forces may be ignored (i.e., pressure drops in both fluids may be ignored) and that capillary forces (pressure difference AP between the two fluids) control the process: AP = 2), cos O/r where ~, is the interfacial tension between the two fluids, 0 is the contact angle, and r is the radius of the pore. The pressure in the invading fluid exceeds that in the resident wetting fluid and, with displacement driven by increasing capillary pressure, progressively narrower pores are filled. Wilkinson and Willemsen (1983) proposed simulating the process in a regular lattice (Feder, 1988); the lattice elements represent the pore throats and the nodes (spherical cavities) represent the pores, hence the description "stick and ball" model.
Fault seal analysis: reducing our dependence on empiricism
The stick-and-ball modelling technique used here has been described by Scandellari Nilsen et al. (1996) and supporting verification runs reported in Bakke and Oren (1996). The simulations employed a cubic lattice with a log-normal distribution of triangular pore cross-sections having a coordination number of 5.5 to allow for some dead-end pores. A variance of 0.5 was chosen to represent a narrow pore size distribution and a variance of 2.0 to represent a wide pore size distribution. Although 10% saturation of a mercury injection sample is usually thought to be suitable for selecting threshold values for fault seal analysis (Schowalter, 1979), experience of drainage experiments for other purposes has suggested that mercury commonly first appears at the core plug outlet at higher saturations. Therefore, both 10 and 25% saturations were modelled. The general form of the relationship to be expected between capillary pressure and permeability can be predicted. Capillary pressure (Pc) is inversely proportional to a value of pore radius (r). Intrinsic permeability (k) is measured in units of (length) z, which may be taken to represent a radius (R) by reference to a capillary bundle representation of a porous medium. We do not know a priori whether r = R in a complex capillary network. Essentially,
157
Pc o~ 1/r
and
k
oc R 2
therefore, if r = R Pc ~ k-~
or
log Pc '~ -0.5 log k
Thus we should expect a power relationship with an exponent o f - 0 . 5 if the radius describing the drainage process is comparable to that controlling permeability. With the exception of the wide pore size distribution at 10% saturation, well defined power relationships are predicted by the model (Fig. 5). Whilst the curves representing 10 and 25% saturation for the wide pore size distribution are markedly displaced from one another, as would be expected, the curves representing the narrow pore size distributions are essentially identical. This of course indicates that selecting the saturation level at which threshold pressure is picked from laboratory drainage tests (i.e., 10% saturation versus some higher value), is not critical for narrow sample pore size distributions. To select a suitable capillary pressure versus permeability relationship to estimate the sealing capacity of a shear band, the curve with the largest exponent, corresponding to the greatest slope on the log-log plot, will predict the largest hydrocarbon column
Fig. 5. Comparison of power law relationships between capillary pressure (psi) and permeability derived from the numerical model and as fitted to laboratory measurements of samples from a North Sea field. (The numerical model results represent a narrow pore size distribution at both 10 and 25% saturation). Squares represent data, diamonds represent the model results.
T.R. Harper and E.R. Lundin
158
height. However, assuming a single power relationship through all the four sets of data revealed only rather small differences of exponent, ranging from -0.51 to-0.54, close to the theoretical prediction. Measuring capillary pressure and selecting a suitable threshold saturation of fault rock requires exceptionally comprehensive saturation monitoring if the measurements are made on microfaults so small that the test sample is heterogeneous. Without comprehensive saturation monitoring, picking of a suitable saturation level for capillary pressure determination is subjective. Typically, large numbers of such laboratory results are required to give confidence in any relationship drawn from the laboratory tests alone. We are therefore not prepared in this case to place as much emphasis on the laboratory observations (relative to the model results) which might otherwise be appropriate. For a narrow pore size distribution, at 25% saturation (which as noted was almost identical to the curve for 10% saturation), the following power relation can be fitted to the model results: log Pc = log 65.453 k -0.5056 or
log P~ = 1.816 - 0.5056 log k where R 2 = 0.9991. The limited available laboratory measurements of microfault capillary pressure supported the selection of this curve (Fig. 5). Permeability was determined using a mixture of minipermeameter, image analysis and flow tests, and capillary pressure by mercury injection, at the University of Leeds for Statoil. The correlation of these limited data with the model prediction is fair for the majority of the results (which are 8 mD and higher) and lends some support to the model results. The correspondence between field and model results is certainly best with the narrow pore size distribution model for the majority of the data. The exponent of the curve selected is closest to the theoretical prediction of 0.5. Given that the slope of the model prediction as shown on Fig. 5 is greater than that fitted to the field data, the model prediction of Pc versus k will lead to the most optimistic upper estimates of the hydrocarTable 1 Fluid properties used to estimate hydrocarbon column heights Field
Phase
Interfacial tension (Pax 10-3)
Bfine density (kg/m 3)
Hydrocarbon density (kg/m 3)
Oil Gas Gas
20.4 29.5 26.35
1030.00 1030.00 960.00
758.9 172.2 277.00
Table 2 Estimates of hydrocarbon column height for a range of possible fault rock permeabilities Permeability (mD) Reservoir rock 10000
1000 (100)
Shear band 1
1 (0.1)
Approximate height of hydrocarbon column (m) Field A oil
Field A gas
Field B gas
10
4
5
9 (29)
4 (13)
5 (15)
bon column height which can be trapped by a shear band. Single-phase column calculations were made using the relationships of Smith (1966) and Schowalter (1979). The fluid properties taken from North Sea and offshore mid-Norway data are shown in Table 1. The permeability measurements in Antonellini and Aydin (1994) indicate that an estimate of hydrocarbon column height supportable by a single shear band can be calculated assuming a permeability reduction by 3 orders of magnitude (for permeabilities of undeformed reservoir below 1 D) and by 4 orders of magnitude (for permeabilities of undeformed reservoir greater than 1 D). Their data show that the shear bands had in no cases a permeability as low as 0.1 mD. The calculated estimates are shown in Table 2 for the two North Sea fields. The third calculation in Table 2 is based on an unrealistic permeability reduction from 100 mD, and is prepared only for the purposes of presenting a range of calculations. These estimates indicate that only if a shear band permeability approaches 0.1 mD does the sealing potential become significant in exploration terms, at least for offshore fields. This permeability would correspond to borderline silt-clay particle size in the shear band (de Marsily, 1986). As discussed earlier, such an intrinsically weaker material would allow continued shear displacement, quite contrary to the characteristic behaviour of shear bands. Thus the mechanical analysis presented earlier is consistent with Antonellini and Aydin's (1994) measurements of permeability (the lower bound values of which exceed 0.1 mD). It can be argued that the lower bound values are influenced by limitations of the measuring equipment or method of permeability estimation. This was the case for Freeman's (1990) work. Note, however, that measurements even approaching 0.1 mD are a very minor proportion of Antonellini and Aydin's (1994) results. These calculations are based on a single shear band. Shear bands tend to cluster in zones, so the possibility of a "stepped" seal amounting in total to a multiple of the calculated values must be assessed.
Fault seal analysis: reducing our dependence on empiricism
Not surprisingly, no reports of systematic measurements of the distribution of capillary pressure in three dimensions could be found. Shear bands tend to anastomose (Antonellini and Aydin, 1994). The potential for a stepped trap therefore appears to be small because leakage could occur at a capillary entry pressure equivalent to a single shear band at points where the shear bands merge. Alternatively, a tortuous, stepped trap might be developed comprising a combination of "nodes" where bands merge and sections of single bands. Freeman (1990) reported variations of permeability by a factor of approximately 25 along each of the two bands for which he investigated this variation. The lowest values of capillary pressure along each of the single band segments would control the contributions of the single bands to the composite trap. For these reasons we can see no justification in concluding that zones of shear bands are likely to trap significantly larger columns than single bands. At the very minimum, such an assumption would be associated with unquantifiable and therefore very high risk. The estimated column heights were calculated using values based on single deformation bands. Had values determined from slip planes adjacent to zones of deformation bands been used (which have experienced shear displacements of several metres to tens of metres (Antonellini and Aydin, 1994), then greater column heights would have been obtained. However, as these authors point out, slip planes are not continuous. As discussed, such large displacements are also not characteristic of shear bands from the mechanistic point of view. Our theoretical estimates of trapped column height are consistent with Gibson's (1994) field observations. We have demonstrated that an upper limit to the hydrocarbon column height which can be trapped by a single shear band is indeed in the region of 20 m. Gibson's (1994) field data are consistent with our perception of the trapping capacity of a zone of shear bands, and we expect that Gibson's conclusions are widely applicable. We suggest that zones of shear bands are of no direct interest to the majority of offshore exploration activities. One exception to this conclusion could arise if the shear bands in a field were known to have experienced preferential (because of increased grain surface area from fracturing) post-formation diagenesis, but one would have to be confident of both the occurrence of the process and its continuity. Whilst we are concerned here with exploration, we emphasise that shear bands can be critical to production (Harper and Moftah, 1984). Harper and Moftah (1984) observed a correspondence between poor well productivity and the presence of shear bands in the
159
vicinity of completions in the Ras Budran field. They interpreted the effect of the shear bands both as an increase in tortuosity and a decrease in the area available for flow near the wellbore, and, as giving rise to a partial penetration effect. In general, a reduction of transmissivity caused by zones of shear bands, where these are present, and a potential deterioration of sweep efficiency where wells are located near such structures, is also to be expected.
The influence of present-day stress Linjordet and Skarpnes (1992) proposed that exploration prospects may be graded on the basis of the post-migration direction of the maximum and minimum horizontal stresses. They interpreted exploration potential using gas chimneys as indicators of leakage and stress directions deduced from wellbore breakout data. Their central thesis was that the direction of the maximum and minimum horizontal stresses relative to the strike of the fault influences the seal capacity. This idea does not appear to have been more thoroughly tested by others. Knott (1993) plotted the ratio of sealing faults to non-sealing faults in the northern North Sea for a sample of 85 faults but could draw no strong conclusions from these data regarding any preferential directions. The database used by Knott was then extended by collaboration between Statoil and BP. Wilson (pers. commun.) subsequently identified a direction corresponding to a strong minimum of intrareservoir sealing fault segments in the northern North Sea. This direction is approximately 120 ~ and Wilson (pers. commun.) noted a correspondence with the regional trend of the maximum horizontal stress deduced from breakout data. Fig. 6 is a rose diagram of the number of intra-
TRENDS OF INTRA-RESERVOIR SEALING FAULTS
SH
=
Northern North Sea N = 116 / (116+213)
Fig. 6. Relationship of the regional maximum horizontal stress direction to the proportion of intra-reservoir sealing faults in any direction in the Northern North Sea.
160
reservoir sealing fault segments expressed as a proportion of the total number of faults, per 10~ fault strike segment, in the Northern North Sea. A segment was delineated on the basis of the broadly similar characteristics of orientation, maximum displacement, reservoir thickness, depth of reservoir, net-gross and acrossfault connectivity. Fig. 6 clearly shows the low sealing capacity in the interpreted direction of the regional maximum horizontal stress. An asymmetry about the axis of maximum horizontal stress is also evident. There is a remote chance that the pattern recorded by Wilson (pers. commun.) is an artifact resulting from a limited database. Because straightforward geological explanations for a pattern of some form can be proposed, we consider this no further. The criteria adopted to classify a fault as sealing were based on differences of pre-production pressures and hydrocarbon-water contacts or fluid compositional differences. Because of uncertainties in the interpretation of whether faults are indeed sealing, combined with limited amounts of data and any bias associated with the methods of fault segment identification, the industry is unlikely to develop a database of this type which is entirely free of uncertainty. The Statoil-BP database is no exception, but is sufficient to indicate some correlation with stress directions which merits further evaluation. In addition, the observed asymmetry about the horizontal stress axes requires explanation. Assuming the most common situation that the maximum principal stress is subvertical, the obvious first step is to consider the values of the resolved normal and shear stress acting on high angle faults striking parallel to the maximum horizontal stress.
Resolved normal stress The normal stress acting on such a fault plane approaches the lowest values of the stress tensor. In the writers' experience, the least effective stress in North Sea fields is typically less than 10 MPa. The hydraulic conductivity of many open natural fractures is reduced to that of the unfractured rock at approximately 10 MPa (see, for example, data presented by Gale (1982)). Consequently, we may readily infer that at least any unfilled fractures which are subparallel to the main fault plane, within or adjacent to that plane, may be conductive. Although fractures may not always be present (e.g., if the fault plane is filled with salt), this provides one mechanism which is broadly consistent with the observation of a minimum of sealing faults striking parallel to the maximum horizontal stress.
Resolved shear stress It is assumed that the present day maximum hori-
T.R. Harper and E.R. Lundin
zontal stress is approximately equal to the intermediate principal stress in the reservoir. In this case, assuming the maximum principal stress is sub-vertical, the maximum shear stress on approximately 120 ~ striking high angle faults is relatively close to the maximum shear stress currently applied (this corresponds to a dip-slip situation). If in any way the fault plane is intrinsically weaker than the surrounding rock, such as if filled by continuous mudrock, then any shear displacements are most likely to occur on the fault plane. Another reason for shearing to occur preferentially on the fault plane is the corresponding low effective normal stress, as reviewed in the previous paragraph.
Influence of geological history This simple assessment of the resolved normal and shear stresses acting on fault planes striking parallel to the intermediate principal stress infers a relation between stress and sealing. However, the asymmetry of Fig. 6 implies that other factors may also influence the apparent directional nature of sealing. One such factor is the strike of the original syn-rift faults. Given the history of syn-rift faulting, it is not unreasonable to imply that clay smears formed in some or many of the northern North Sea faults. If the continuity of a smear is inversely related to the distance between the source bed and centre of the seal (e.g., Fulljames et al., 1997), then those faults with pure dip-slip motion are most likely to maintain seal continuity as the fault throw increases. In the northern North Sea, such faults are inferred to have been orientated approximately N-NNE. Some support for this line of argument is given by the Statoil-BP data in that such a phenomenon could be reflected in the broad maximum extending from approximately NNW to NNE. Regardless of whether the preceding surmise is correct, it serves to illustrate a central point: to assume that present day stress alone influences any tendency for a directional preference of sealing capacity would be unreasonable for any but the simplest of geological histories. The history of the NOCS has included a change from rift to passive margin conditions, so such an assumption is not justified for this region.
Potential for detecting fault sealing characteristics based on the rotation of the stress trajectories A number of previous authors have noted a variability of the horizontal stress directions in the vicinity of faults (e.g., Aleksandrowski et al., 1992; Bell et al., 1992; Yale et al., 1994). This characteristic can-
161
Fault seal analysis: reducing our dependence on empiricism
not be ignored in the lumping together of all stressrelated observations into a regional direction of maximum horizontal stress to assess any relation to sealing. The relevance of the above discussion of resolved shear and normal stress may be limited to those cases where the fault strike is close to being strictly parallel with the axis of maximum horizontal stress. The analytic comparison of faulting with and without a clay layer given here can also be used to demonstrate the nature and causes of stress rotation in the vicinity of a fault. Bell et al. (1992) suggested that it may be possible to identify open fractures and nonsealing faults from a rotation of the stress trajectories adjacent to the fault. However, as shown in Fig. 2, the faulting process must necessarily be accompanied by a rotation of the stress trajectories in the vicinity of the fault regardless of the intrinsic strength of the material in the fault plane. Faults do not need to be "open" to induce stress "anomalies". The fault plane filling may influence the angle of rotation, but this is likely to be a second order effect compared to such factors as the need to satisfy equilibrium. Note that Cundall (1990) concluded that the stresses remain "locked-in", i.e., these internal forces are balanced and thereby persist after the end of faulting or other changes of boundary conditions. If these internal forces developed during syn-rift faulting corresponding to a low mean stress, then subsequent burial to much greater depths and higher mean stress might render them a second-order effect. In such circumstances, if a rotation of the stress trajectories is observed in the field, this may imply more recent slip. However, we wish to emphasise that these last two statements are generalized comments which are not rooted in comprehensive quantitative analysis of such a geological history.
Fault reactivation The sensitivity of the hydraulic conductivity and other transport properties of discontinua (fractured media) to normal stress is typically substantially greater than that of continua (unfractured media). The stress-sensitivity has been demonstrated in numerous studies of fracture flow (e.g., Gale, 1982). Natural fractures are a suspected cause of anisotropic waterflooding with a maximum rate of flood front advance approximately in the direction of the maximum horizontal stress (Heffer and Dowokpor, 1990). Natural fractures were recognised as significantly contributing to Clair well productivity (Coney et al., 1993). These fractures are aligned with the present day direction of the maximum horizontal stress in at least one of the wells in the Clair Field.
It may be prudent to consider the possible influence of small shear displacements on faults brought about by mild reactivation or slip related to differential compaction. The Jurassic syn-rift conditions can be inferred to be favourable to clay smear formation, so it is appropriate to evaluate the probable response to burial and to at least minor shear displacement of clay smears in the northern North Sea. Here we resort only to field observations for this purpose. In cores taken in the NOCS, we have observed networks of closely spaced fractures in shale within faults which we would interpret as sometimes representing shear displacements measured in centimetres or even less. At the outcrop scale, Airo'Farulla and Valore (1993) and others have described "tectonized clay" as composed of small, hard, tightly interlocked fragments or "scales". This is clearly a discontinuum but with very closely spaced fractures. We suspect that an early network of fractures as seen in core develops into such a fragmented material as described (Airo'Farulla and Valore, 1993) after larger shear displacements (perhaps only 10s of cm). Laboratory simple shear tests are required to check and quantify these thoughts. If small shear displacements can fragment shale so that it behaves as a discontinuum, we need to better understand this for purposes of predicting clay smear sealing capacity.
Conclusions The ability to evaluate fault seal capacity in any given situation depends on a number factors, both technical and commercial. The "predictability" of a given fault seal bears directly on the confidence with which sealing capacity can be estimated. This predictability can be reflected in the exploration risk. The extent of published observations of the distribution of displacements across fractures comprising a fault damage zone appears to be minimal. Detection of damage zones from seismic data is uncertain at best. Given the availability of software able to represent juxtaposition of beds across a fault zone, this uncertainty can be addressed by assuming various distributions of displacements and testing the sensitivity to these assumptions. This can then indicate the reliance or otherwise which must be placed on the products of deformation in the fault zone for sealing to be predicted. Some forms of deformation seal are relatively predictable from a knowledge of the geological history of the field or prospect. Others, at least at present, are essentially unpredictable (or predictable only with such uncertainty that the outcome of the seal analysis is of little or no value to the industry). For this reason alone it is prudent to identify the process of deforma-
T.R. Harper and E.R. Lundin
162
tion seal which applies to a fault. There are other compelling reasons for identifying the geological process governing the seal formation process. Different types of seal have may have different trapping characteristics, such as a difference between the hangingwall and footwall. They may also have a differing mechanical response to the geological events occurring after seal formation. The mechanism of the formation of clay smears and their trapping capacity appears to be reasonably well documented and relatively uncontroversial. This is not the case for shear bands. Shear band formation and evolution, and the change of shear displacement from one location to another, can be analysed numerically. The small and finite displacement on each band, after which the shear displacement is transferred elsewhere, can be explained by a progressive reduction of one or more stress components (and lower mean stress), thus dissipating strain energy. It is not necessary to invoke strain hardening or softening, change of pore pressure or any other intrinsic material weakness in the band. To the contrary, if a layer of clay is present, in the sequence which is sheared, then continuation of the displacement is facilitated by the intrinsic weakness of the material in the shear zone. A distinction between shear in a homogeneous sandstone in which localisation is dependent on progressive reduction of stress within the shear zone, and shearing in heterogeneous sandstone localised by intrinsic material weakness, is theoretically predictable. The theory is found to be consistent with measurements of the permeability of shear bands. These measurements reveal a range of permeabilities which closely approach but rarely reach a value corresponding to the presence of a clay fraction. In either case, whether faults occur in homogeneous sandstone or with clay in the fault, the principal stresses are markedly rotated outside the fault zone. This demonstrates that a rotation of the stress trajectories cannot uniquely characterise open and nonsealing faults. A strong dilatation occurs in clay subject to the clay smear process. Previously, dilatation has typically been perceived as a characteristic of strong rock e.g., during shear of two rough surfaces in strongly lithified or cemented sediments. Available published estimates of the trapping potential of shear bands suggest that the maximum column height which can be trapped ranges from 20 m (a field case history) to one or more hundreds of metres (theoretical estimates). This is far too wide a range to allow the explorationist to decide whether or not hydrocarbon accumulations trapped against shear bands should be sought after or totally ignored. Nu-
merical modelling can be used to indicate the nature of the relationship between permeability and capillary pressure. Both a simple theoretical approach and the modelling results indicate that a power relationship with an exponent close t o - 0 . 5 is an adequate representation for many reservoir and fault rocks. This relationship between capillary pressure and permeability can be used to estimate an upper bound sealing capacity using published reports of shear band permeability. Limited field data have been used to support this power relationship. The predicting trapping capacity is consistent with the field observations in that approximately 20 m is a reasonable upper estimate of the trapping capacity of zones of shear bands. Zones of shear bands are of very substantial potential relevance to production but typically of no interest to the explorer. In our opinion, they should be ignored for exploration purposes, at least in an offshore setting such as the Norwegian continental shelf. There now exists some evidence for a tendency for fault sealing capacity to relate to the azimuth of fault strike in part of the North Sea. It has previously been suggested that this relates to the azimuth of the maximum and minimum horizontal stresses. However, this relationship can be inferred to relate to some yet unspecified combination of the present day stress state and the overall geological history, including previous stress states. We suspect that minor shear displacements can potentially greatly increase the stress-sensitivity of seals composed of mudrock.
Acknowledgements We are indebted to Dr. P~l-Eric Oren of Statoil for his analysis of capillary pressure-permeability relations. Kes Heifer of B P Exploration motivated the statistical analysis and improved presentation of the Statoil-BP fault seal directional data by Jonathan Wilson, which clarified what was previously a weaker correlation. We are pleased to acknowledge the support and encouragement of Statoil in this research.
References Aarland, R.K. 1995. Deformasjonsstil over en kjemetatt forkastning; Bragefeltet, Nordlige Vikinggraben. Geonytt, 1: 74. Airo'Farulla, C. and Valore, C. 1993. Some aspects of the mechanical behaviour of compacted tectonized clays. In: Anagnostopoulos et al. (Editors), Geotechnical Engineering of Hard Soils - Soft Rocks. Balkema, Rotterdam, pp. 335-342. Aleksandrowski, P.A., Inderhaug, O.H. and Knapstad, B. 1992. Tectonic structures and wellbore breakout orientation. In: Tillerson and Wawersik (Editors), Rock Mechanics Proc. 33rd Symp., Balkema, Rotterdam. Allan, U.S. 1989. Model for hydrocarbon migration and entrapment within faulted structures. Am. Assoc. Pet. Geol. Bull., 73: 803811.
Fault seal analysis: reducing our dependence on empiricism Andresen, A., Steen, 0. and Hartz, E. 1994. Fault populations and fault distributions in rotated fault blocks, Traill 0, East Greenland. In: Olsen et al. (Editors), Profit Project Summary Reports, Reservoir Characterization, Near Well Flow, pp. 43-59. Antonellini, M. and Aydin, A. 1994. Effect of faulting and fluid flow in porous sandstones: petrophysical properties. Am. Assoc. Pet. Geol. Bull., 78: 355-377. Amesen, L. 1995. Damage zones around large faults. NTH Prosjektarbeid 1995, Institutt for Geologi og Bergteknikk, NTH, Trondheim, 31 pp. Badley, M., Freeman, B., Needham, T., Yielding, G., Driggs, A., Hairr, R. and Lindsay, D. 1997. Fault seal analysis: methodolgy and case studies. In: Proc. Conf. Hydrocarbon Seals Relating to deformation Zones and Caprocks. Trondheim, Norway. Bakke, S. and Oren, P.E. 1996. 3-D pore-scale modelling of heterogeneous sandstone reservoir rocks and quantitative analysis of the architecture, geometry and spatial continuity of the pore network. SPE 35479. Barnett, J.A.M., Mortimer, J., Rippon, J.H., Walsh, J.J. and Watterson, J. 1987. Displacement geometry in the volume containing a single normal fault. Am. Assoc. Pet. Geol. Bull., 71: 925-937. Bell, J.S., Caillet, G. and Adams, J. 1992. Attempts to detect open fractures and non-sealing faults with dipmeter logs. In: A. Hurst et al. (Editors), Geological Applications of Wireline Logs II, Special Publication 65. Geol. Soc., pp. 211-220. Bentley, M.R. 1991. Representation of fault sealing in a reservoir simulation: Cormorant Field Block IV, UK North Sea. SPE 22667, pp. 119-126. Berg, R.R. 1975. Capillary pressure in stratigraphic traps. Am. Assoc. Pet. Geol. Bull., 59: 939-956. Berg, R.R. 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., 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. Catalan, L., Xiaowen, F., Ioannis, C. and Dullien, F.A.L. 1992. An experimental study of secondary oil migration. Am. Assoc. Pet. Geol. Bull., 76: 638-650. 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: 79-105. Childs, C., Watterson, J. and Walsh, J.J. 1995. Fault overlap zones within developing normal fault systems. J. Geol. Soc. London, 152: 535-549. Childs, C., Walsh, J.J. and Watterson, J. 1997. Complexity in fault zone structure and its implication for fault seal prediction. In: P. Mr and A.G. Koestler (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 61-72. Coney, D., Fyfe, T.B., Retail, P. and Smith, P.J. 1993. Clair appraisal: the benefits of a co-operative approach. In: J.R. Parker et al. (Editors), Petroleum Geology of Northwest Europe. Proc. 4th Conf. Geol. Soc. London, pp. 1409-1420. Cundall, P.A. 1990 Numerical modelling of jointed and faulted rock. In: Rossmanith (Editor), Mechanics of Jointed and Faulted Rock, Balkema, Rotterdam, pp. 11-18. de Marsily, G. 1986. Quantitative Hydrogeology, Academic Press, San Diego, CA. Feder, J. 1988. Fractals. Plenum Press, New York. Freeman, D.H. 1990. Permeability effects of deformation bands in porous sandstones. MS Thesis, University of Oklahoma, Norman, OK, 90 pp. Fristad, T., Groth, A., Yielding, G. and Freeman, B. 1997. Quantitative fault seal prediction - a case study from Oseberg Syd. In: P. Mr and A.G. Koestler (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 107-124.
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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. Mr and A.G. Koestler (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 51-59. Gale, J.E. 1982. Assessing the permeability characteristics of fractured rock. Geol. Soc. Am. Special Paper 189. Gibson, R. 1994. Fault-zone seals in siliciclastic 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. Measurements and characterisation of spatial distribution of fractures. Tectonophysics, 226:113-141. Harper, T.R. and Moftah, I. 1984. Skin effect and completion options in the Ras Budran Reservoir. SPE 13708, pp. 211-226. Heffer, K.J. and Dowokpor, A.B. 1990. Relationship between azimuths of flood anisotropy and local earth stresses in oil reservoirs. In: A.T. Buller et al. (Editors), North Sea Oil and Gas Reservoirs II. Graham and Trotman, London, pp. 251-260. Hill, R. 1962. Acceleration waves in solids. J. Mech. Phys. Sol., 10: 1-16. Jamison, W.R. and Steams, D.W. 1982. Tectonic deformation of Wingate Sandstone, Colorado National Monument. Am. Assoc. Pet. Geol. Bull., 66: 2584-2608. Jenkins, J.T. 1990. Localization in granular materials. Appl. Mech. Rev., 43: 194-195. 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 RFF pressure data on fault trapping and dynamic leakage. Am. Assoc. Pet. Geol. Bull., 77: 1389-1404. Knipe, R.J. 1992. Faulting processes and fault seal. In: R.M. Larsen et al. (Editors), Structural and Tectonic Modelling and its Application to Petroleum Geology, Special Publication 1. Norwegian Petroleum Society, pp. 325-342. Knipe, R.J., Baxter, K., Clennell, M.B., Farmer, A.B., Fischer, Q.J., Jones, G., Bolton, A., Hinkley, R.J., Kidd, B.E., Porter, J.R. and White, E.A. 1994. Fault zone geometry and behaviour; the importance of the damage zone evolution. In: Abstracts, Modem Developments in Structural Interpretation, Validation, and Modelling, London, February. Knott, S.D. 1993. Fault seal analysis in the North Sea. Am. Assoc. Pet. Geol. Bull., 77: 778-792. Koestler, A.G. and Milnes, A.G. 1992. The importance of structural reservoir characterization and reservoir mechanics for enhanced oil recovery. In: Sadek et al. (Editors), Proc. 1st Conf. on Geology of the Arab World, Cairo, pp. 87-109. Koestler, A.G., Milnes, A.G. and Keller, P. 1995. Quantification of fault/fracture systems for reservoir simulation - use of systematic data from field analogues. In: Olsen et al. (Editors), Project Summary Report on Reservoir Characterisation and Near Well Flow, PROFIT, Norwegian Petroleum Directorate. Lehner, F.K. and Pilaar, W.F. 1997. The emplacement of clay smears in synsedimentary normal faults: inferences from field observations near Frechen, Germany. In: P. Mr and A.G. Koestler (Editors), Hydrocarbon Seals: Importance for Exploration and Production, NPF Special Publication 7. Elsevier, Singapore, pp. 39-50. Linjordet, A. and Skarpnes, O. 1992. Application of horizontal stress directions interpreted from borehole breakouts recorded by fourarm dipmeter tools. In: T.O. Vorren et al. (Editors), Arctic Geology and Petroleum Potential, Special Publication 2. Norwegian Petroleum Society, pp. 681-690. Mandl, G., de Jong, L.N.J. and Maltha, A. 1977. Shear zones in granular material, Rock Mech., 9: 95-144. Mulhaus, H.-B. and Vardoulakis, I. 1987. The thickness of shear bands of shear bands in granular materials. Geotechnique, 37: 271-283.
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164 Peacock, D.C.P. and Sanderson, D.J. 1994. Strain, stress and scaling of faults in the chalk at Flamborough Head, UK. J. Struct. Geol., 16: 97-107. Pittman, 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: 23812387. Poliakov, A.N.B., Podladchikov, Yu. and Talbot, C. 1993. Initiation of salt diapirs with frictional overburdens: numerical experiments. Tectonophysics, 228:199-210. Scandellari Nilsen, L., Oren, P.E., Bakke, S. and Henriquez, A. 1996. Prediction of relative permeability and capillary pressure from a pore model. SPE 35531. Scholz, C.H. 1987. Wear and gouge formation in brittle faulting. Geology, 15: 493-495. Schowalter, T. 1979. Mechanics of secondary hydrocarbon migration and entrapment. Am. Assoc. Pet. Geol. Bull., 63: 723-760. Smith, D. 1966. Theoretical considerations of sealing and non-sealing faults. Am. Assoc. Pet. Geol. Bull., 50: 363-374.
T.R. HARPER E.R. LUNDIN
Smith, D.A. 1980. Sealing and non-sealing faults in the Lousiana Gulf Coast salt basin. Am. Assoc. Pet. Geol. Bull., 64: 145-172. Trudgill, B. and Cartwright, J. 1994. Relay-ramp forms and normalfault linkages, Canyonlands National Park, Utah. Geol. Soc. Am. Bull., 106:1143-1157. Weber, C.J. 1987. Hydrocarbon distribution patterns in Nigerian growth fault structures controlled by structural style and stratigraphy. J. Pet. Sci. Eng., 1:91-104. Weber, C.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. 10th Annu. Offshore Technol. Conf., Houston, TX, Proc. 4, pp. 2643-2653. Wilkinsofi, D. and Willemsen, J.F. 1983. Invasion percolation: a new form of percolation theory. J. Phys. A., 16, 3365-3376. Yale, D.P., Rodriguez, J.M. and Mercer, T.B. 1994. In-situ stress orientation and the effects of local structure - Scott Field, North Sea. EUROCK '94, Balkema, Rotterdam.
Geosphere Ltd., Netherton Farm, Sheepwash, Beaworthy, Devon EX21 5PL, UK Statoil Research Centre, Postuttak, 7005 Trondheim, Norway
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Sealing processes and top seal assessment G.M. Ingram, J.L. Urai and M.A. Naylor
Hydrocarbon entrapment takes place when the rocks defining the bounding surfaces of a valid trapping geometry possess hydrocarbon sealing properties. Consideration of subsurface hydrocarbon seals should therefore have a high priority in an exploration programme. In the following contribution we suggest a simple approach to top seal assessment, present a review of the physics of capillary sealing and flow barriers, discuss static (capillary) versus dynamic sealing and present a technique for assessing the effect of sub-seismic fault populations upon layered siltstone/shale top seal sequences.
Introduction
Static top seals: capillary sealing
Top seals prevent the vertical migration of hydrocarbons out of traps and commonly comprise fine grained rocks, which have much reduced pore throat radii compared with reservoir rocks. They may act as static seals and also as permeable flow barriers, such as seals which permit slow leakage to take place by Darcy flow, or diffusion seals which allow light hydrocarbons to pass in solution through the pore fluid. A water-wet seal will act as a capillary seal to hydrocarbons, unless the buoyancy pressure exceeds the capillary entry pressure, at which point leakage will occur by permeable, two-phase flow. However, the pore throats in claystone, or shale top seals are commonly so small that significant leakage may only occur after hydrofracturing of the formation, or by forming linked, permeable, dilatant fracture networks through the seal, during deformation. Layered top seals, i.e., shale seals with significant intercalations of leaky layers, may leak if sufficient small faults are present to form a tortuous, fault-linked leak path, due to across-fault juxtaposition. Assessment of hydrocarbon top seals, using a rigorous strategy, is essential for a sound prospect appraisal. A simplified strategy for top seal assessment (Fig. 1) is introduced below, which draws on assessments of several sealing and leakage processes, considered to represent key controls on retention (Fig. 2). Aspects of topand fault-sealing are interrelated in petrophysical terms. Most traps are formed from a combination of dip- and fault-closures, therefore both seal types depend on one another to maintain overall trap integrity. For this reason, a collective approach is recommended, linking elements of both top- and fault-seals.
Capillary seals rely on the balance between opposing forces of gravity (buoyancy) and capillarity in order to seal. For a water-filled reservoir rock, underlain by a source rock and overlain by a top seal rock, hydrocarbons initially expelled from the source rock will accumulate to form small droplets at the base of the reservoir. As accumulation of hydrocarbons progresses further, the droplets coalesce and buoyancy pressure increases until the reservoir capillary entry pressure has been exceeded, at which time the hydrocarbons will begin to move into the reservoir and migrate vertically. The migrating hydrocarbons will eventually encounter the overlying top seal rock and spread out along the sealing boundary. A capillary seal acts as a perfect seal to these hydrocarbons until the hydrocarbon buoyancy pressure, exerted by the increasing column, exceeds the top seal capillary entry pressure, at which point leakage will take place by permeable two-phase flow. The height of static hydrocarbon columns sealed by capillary seals can be theoretically calculated using the following standard equations (Berg, 1975; Schowalter, 1979; Watts, 1987): p~ _ 2), cos 0
(1)
r
where (using SI units) Pe is capillary entry pressure (= maximum sustainable pressure difference across the fluid-fluid interface; Pa); y is the surface tension (N/m); 0 is the wetting angle (degrees) and r is the pore throat radius (m). This relationship can be used to calculate the hydrocarbon column (h) held by a capillary seal:
Hydrocarbon Seals: Importancefor Exploration and Production edited by P. Mr
and A.G. Koestler. NPF Special Publication 7, pp. 165-174, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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values can be very much greater (>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.
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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.
Darcy flow simulation To illustrate these top seal leakage dynamics, model calculations of simple Darcy flow were per-
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: Vn - Vn _ 1 d- At(Q~n_l - OOUt ~_~)
(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
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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.
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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
Sealing processes and top seal assessment
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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
G.M. Ingram, J.L. Urai and M.A. Naylor
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.
Sealing processes and top seal assessment
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.
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G.M. Ingram, J.L. Urai and M.A. Naylor
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-
Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mr
and A.G. Koestler. NPF Special Publication 7, pp. 175-186, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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
The dynamics of gas flow through rock salt in the scope of time
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
The dynamics of gas flow through rock salt in the scope of time
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 <20% of anhydrate are close to 10-21 m 2 and show an increase with admixtures up to 35% of anhydrate dependent on their grain size of up to 10 -17 m 2 which already fits into the range of shale permeabilites. The plot of Fig. 7 is made against the maximum depth reached by the seal. For cases C-G this is the present depth; for cases A, B, M, and N this was the depth at 85 myrbp. The maximum depth of the seal has been chosen as the control on the permeabilities because a body of rock salt once exposed to a pressure/temperature regime largely keeps the petrophysical properties acquired at that time even if subsequently discharged and cooled due to tectonic uplift (permeability hysteresis; see Borgmeier and Weber,
D. Kettel
1992). Additionally a scale of temperature with depth is given using the mean regional temperature gradient of 33~ m. The temperatures of 115 and 151 ~ have been marked in Fig. 7. They confine an anomaly of higher rock salt permeabilities. Under the condition of geothermal gradients, water will never reach a point of phase transition until passing the critical point. According to kno,wn characteristics (Reid et al., 1987), with a temperature of 100~ water vapor pressure starts to increase near exponentially. The first derivation of the water vapor pressure curve reveals a m a x i m u m - or a maximum in pressure increase which directly relates to the dimension of time or velocity - within the temperature range of 115-145~ This means that for a given velocity of a gas to migrate through a rock salt seal, the evolution of the internal pressure over water as the co-migrating fluid may create an additional force to move all fluids together faster through the seal. This finally leads to the conclusion, that any permeability measured through or calculated for a body of rock salt does not express its term as a static network of conducting pathways but excusively its term as a velocity. Further details on this will be a subject for a forthcoming paper. With the published laboratory data, strong support is obtained for Darcy flow to be the mechanism driving gas through rocks. Additionally the boundary condition put on the migration process by the evidence in Fig. 2 is fulfilled: Darcy flow requires a strict dependency of methane quantities stored in reservoirs on those generated over the same area and on the thickness of seals. Point (2) in the previous section concludes that >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
The dynamics of gas flow through rock salt in the scope of time
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.
The dynamics of gas flow through rock salt in the scope of time
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
This Page Intentionally Left Blank
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.
Hydrocarbon Seals: Importance for Exploration and Production edited by P. Mr
and A.G. Koestler. NPF Special Publication 7, pp. 187-199, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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\
i '~k " "\"~.O~. ~
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
Pressure prediction from seismic data
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.
N.C. Dutta
192
seismic interval velocity at a CMP vs time
velocity vs density relation
velocity vs temperature/ effective stress relation
geothermal gradient
time-depth conversion
mudline temperature
temperature vs depth relation
,
effective stress vs depth
density vs depth
obtain fluid pressure
integrate to obtain overburden(S) vs depth
1
color display
~_~
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.
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 Applications The technology described above was developed in
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.
Pressure prediction from seismic data
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
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Depth, Feet (* 1000) 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.
Pressure prediction from seismic data
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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
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Depth, Feet (* 1000) 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-
Pressure prediction from seismic data
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
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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
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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
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204 and siltstones of the Not and Ror Formations, illite is much more abundant (up to 90% of the total clay content) than in the Melke Formation. We also observe a marked decrease in potassium feldspar as the illite content increases (with increasing depth). The illite/kaolinite ratio is also much higher in the siltstones than in the adjacent low-permeable shales. The Garn Formation has a high quartz content (60-92%), and it has been described by other authors (Karlsson, 1984; Ehrenberg, 1991) as a subarkosic arenite in which potassium feldspar is several times more abundant than plagioclase. The clay content of the Garn Formation is very low and the clay minerals present are mainly authigenic (kaolinite and illite) except in primary clay lamina (Karlsson, 1984; Ehrenberg, 1991), where mica-rich zones are also present (Dalland et al., 1988). Well 6506/11-3 (Fig. 1) is the only well in which chlorite has been observed in the Garn Formation. Generally low content of chlorite in the Garn Formation is also reported by Ehrenberg (1993). Carbonate cemented zones (siderite; Fig. 4) occurs both in the sandstones of the Garn Formation as well as in the shales of the Melke Formation. These carbonate cemented zones are thin, approximately 0.2-200.0 cm in vertical thickness. However, they have very low porosities (about 2.0%), and the permeabilities are in the nanoDarcy range (1.0x 10 -21 m 2) (Schltimer, 1995). Thus, they may function as local seals to vertical flow, even though they are generally not correlative from well to well. Fluid pressures on Haltenbanken
Pore pressure measurements have been compiled from drill stem tests (DST) and repeated formation tests (RFT) for the presumed reservoir zones in the study area. Since DST and RFT, are run only in the reservoir zones, we have gathered information about fluid pore pressure through mud weight densities. The fluid pressures of investigated wells are summarized in Fig. 5. Fracture pressures are estimated from leak-off tests (LOT), where mud is pumped into the formation until the first evidence of fractures is detected. "Leak-off pressure" is the pressure at which the formation develops very thin fractures prior to rock failure. A great advantage of this kind of test is that it is an in situ test, thus we do not have to deal with relaxation or unloading problems. Fracture pressures estimated from LOT is in the range of 0.6-0.8 times the lithostatic pressure, which is within the fracture pressure domain (0.7-0.9 lithostatic pressure) given by DuRouchet (1981). The overpressures do not reach fracture pressure (LOT) in any of the wells investigated. However, the pore pressure reaches 80% of
R. Olstad, K. BjCrlykke and D.A. Karlsen
estimated fracture pressure in sediments of the Lower Tertiary-Cretaceous. In the Upper Jurassic succession the pore-pressures are stabilized at a constant gradient. The overpressure abruptly decreases (downwards) in the Fangst Group, in the eastern areas, at the border between Garn Formation and the overpressured Melke Formation (Fig. 5; well 6506/12-1, 6506/12-5, and 6506/12-6). This would imply that the Upper Jurassic and Lower Cretaceous shales provide an ideal vertical seal, since the fluid flow must be directed from the overlying Melke Formation into the Garn Formation, because the hydrodynamic potential (defined as the sum of the pressure-depth ratio and depth (below sea floor) times the acceleration of gravity) is lower in the Garn Formation as compared to the Melke Formation (Fig. 6). A similar setting with inverse hydrodynamic potential has been described by Hemingson and Carew (1984) from gas accumulations in the MacKenzie delta. Other studies on the prediction of large-scale fluid communication and reservoir connectivity in the SmCrbukk fields have been evaluated both from pressure measurements (Ehrenberg et al., 1992) and strontium isotope studies (Str et al., 1993). The strontium analysis from the cored intervals shows good correlation with interpretations from the pressure data. The main conclusions from these studies (Ehrenberg et al., 1992; Str et al., 1993) are: (1) The Garn Formation has good vertical communication, but it is "isolated" from both the underlying Not and Ile Formations and the overlying Melke Formation. (2) The lie Formation forms three laterally isolated compartments. (3) The Tilje Formation is subdivided into three flow units, which have poor communication with each other. Furthermore, Heum et al. (1986) noted that the rotated fault-block, which constitutes the SmCrbukk field structure, is completely devoid of seismically detectable internal faults, restricting inter-reservoir communication. Pressures exceeding the hydrostatic gradient are encountered in all of the wells in the SmCrbukk area. In the wells investigated in the SmCrbukk field, the overpressure starts at the border between the Naust and Kai Formations, at depths ranging from 1420 to 1470mKB (Fig. 5). However, in well 6506/11-3, to the west of the SmCrbukk field, the shallowest overpressure develops in the Miocene Kai Formation (1750 mKB). The variable depth to top overpressure indicates that the overpressuring is stratigraphically (lithologically) controlled and not depth controlled. The border between the normally pressured shales in the Naust Formation and the overpressured Kai Formation in the SmCrbukk field is clearly shown in both the sonic log and the density log (Fig. 7).
Pore water flow and petroleum migration in the SmCrbukk field area, offshore mid-Norway
205
Fig. 4. SEM pictures of a siderite cemented interval in the Melke Formation (well 6506/12-6; depth 4197.6 mKB). Carbonate cementation contribute to a reduction in permeability. (A) Thin section in backscattered mode. (B) Authigenic siderite.
The pressures in the Jurassic reservoir sandstones are normal (hydrostatic) or close to normal in the SmCrbukk and SmCrbukk South field wells, while high overpressures exist in the westerly wells outside the SmCrbukk field (well 6506/11-1, 6506/11-3, and 6506/12-4). The normally pressured Middle-Jurassic sandstones subcrop on the seafloor not far from the Norwegian coastline (Bugge et al., 1984). Thus, lateral drainage of fluids through the Middle Jurassic sandstones has occurred at high enough fluxes to pre-
vent the build-up of overpressure. The overpressuring of the reservoirs in the western areas has been explained by some authors to result from gas generating source rocks and structural differences (larger faults) between the eastern and western areas (Vik et al., 1992). Because of the limited lateral drainage of the areas to the west of the SmCrbukk field, the pore pressure has been able to build up to a much higher level, and it is possible that fracture pressure has been reached in the west. The western reservoirs are pre-
R. Olstad, K. BjCrlykke and D.A. Karlsen
206
Fig. 5. Pore pressure given as equivalent mudweight (EMW) densities, for the investigated wells of the SmCrbukk area.
sently devoid of hydrocarbons, even though petrographic evidence such as hydrocarbon inclusions, suggests that they have been petroleum saturated for considerable geologic time (Karlsen et al., 1995). It is
A) P
I:::rr~irm~al I l n n n n f o r m i t v
SmCrbukk Field Area
Compactiondriven flow upwards and downwards
I~rnelnn~l
I Inr.nnfnrmitv
Halten West
Compactiondriven flow upwards
Compaction-driven fluids ~P-
Pore water flow in aquifer
Fig. 6. Schematic presentation showing how the fluid pressure and lateral drainage control flow patterns (modified from Bj0rlykke, 1993). (A) Flow pattern in the Sm0rbukk Field. (B) Flow pattern in the Halten West area.
therefore possible that the highly overpressured wells leaked due to hydraulic fracturing of the seal, although the pressures at present are not quite at fracture pressure. It should also be noted that these overpressured reservoirs would trap a smaller hydrocarbon column than the normally pressured reservoirs further to the east, if one assumes that the cap-rocks have the same mean pore throat radius in the two locations. This is easily visualized in a pressure/depth plot (Fig. 8), given the different pressure regimes encountered in the Halten West and the SmCrbukk field area. Rock-Eval analysis shows high production indexes (PI), of the cap-rocks sealing both normally and overpressured reservoirs, indicating that they have to some degree been intruded by hydrocarbons (probably mainly gas) from the underlying reservoir (Fig. 9). An upwards decreasing trend of PI in the cap-rock (Fig. 9), suggests that leakage through the matrix is not very effective. Mercury porosimetry implies typical pore-sizes between 25 and 75/~ for the Melke, Not and Ror Formation shales investigated in this study (Schli3mer, 1995). Leonard (1993) estimated pore diameter values as small as 10/~ for Gulf Coast shales buried to 4.5 km depth, and Best and Katsube (1995) state that pore sizes on the order of 30-120/~ are not unusual for tight shales buried deeper than 4000 m. Best and Katsube (1995) have also claimed that shales may have pore sizes as small as 3/~ (0.3 nm). The type of hydrocarbons that may be transported through the sediments during migration ranges from methane (mol. wt. = 16 and effective molecular diameter= 3.8 ~) to heavy compounds such as asphaltenes (mol. wt. up to 5000 and more,
Pore water flow and petroleum migration in the SmCrbukkfield area, offshore mid-Norway
6506/12-1 Sonic (!ts/ft) 100
110
120 130
140
Density (g/co)
150
160
170
180 2.00
2.05
2.10
2.15
2.20
2.25
2.30
2.35
!
1440
~
t"
1450
2~
defining whether fluid flow is vertically upwards or downwards, lies in the identification of lateral drainage systems in the overburden. In the Lysing Formation, lower pore pressures and hydrodynamic potentials may indicate some degree of lateral drainage in this sandy to silty facies, in much the same way as does the Garn Formation in the eastern areas (Fig. 5). The correct identification of such systems would be crucial when trying to model the fluxes derived by compaction and thus also for modelling permeability.
TOP KAI F O R M A T I O N ( 1459 mKB)
1460
Calculations of fluid flow and permeability
__....~ ~
4~----
~'"
6506/12-4 Sonic ([ts/ft) 80
207
100 120 140 160 180 200 220 240 260
2.00
2.05
2.10
Density (g/co) 2.15 2.20 2.25
2.30
2.35
If the flux of pore water relative to the sediments can be determined, one can calculate the effective permeability of pressure seals for different potentiometric gradients, assuming Darcy flow (see Appendix A). The average upwards flux of pore water driven by compaction is the result of porosity reduction in the underlying compacting layers and the velocity is at a constant sedimentation rate less than the subsidence rate (BjCrlykke, 1993). We can therefore calculate the compaction-driven flux from a limited thickness of
1460
TOP KAI F O R M A T I O N ( 1470 mKB) ~
J
1470 ---.___. x_____ :=
>
..=--.-q ~
_ ..~.--
.it:"---
Fig. 7. Sonic and density logs from wells 6506/12-1 and 6506/12-4, which clearly depict the reduced density and low sonic velocity near the Naust-Kai Formation border.
and effective molecular diameter of 50-100 ~ ) (Tissot and Welte, 1984). We would therefore expect to see some degree of molecular sieving, of the organic molecules if migration took place through the matrix of such tight shales. Pore pressure gradients are very difficult to estimate with the same accuracy in shales outside the reservoir zones, where RFT or DST measurements are impossible. We have, however, estimated pressure gradients in three wells on the border between the Melke and Garn Formations, based on the drilling data in Fig. 5. We have attempted to calculate the flow of water from the overpressured Upper Jurassic and Lower Cretaceous shales, into the underlying Middle Jurassic sandstones. The main uncertainty in
Fig. 8. Hypothetic pressure-depth plot showing the thickness of a hydrocarbon column in a normally (hydrostatic) versus overpressured reservoir. As the pore pressure in the water phase increases, a smaller hydrocarbon column can be trapped before the cap-rock reach fracture pressure. Note that the oil-water contact is presumed but realistic.
R. Olstad, K. BjCrlykke and D.A. Karlsen
208
6506/12-6
6506/12-4 "OverpressuredReservoir" 7-.
Normally Pressured reservoir
m
6-' mm m
r~
4-" .
~
~3-"
----
2-
[]
II
1
II o0.40 0.50
l 0.60
0.70
0.80
0.90
1.00
o.0o o.10 0.20 0.30 0.40 0.50 0.60 0.70
PI (S1/SI+S2)
PI (Sl/Sl+S2)
Fig. 9. Production index in the Melke Formation plotted against distance from the Gain Formation. Showing decreasing amounts of hydrocarbons, probably mostly gas diffused from the underlying reservoir.
shales, where the flux can be expressed as F=
A0 H T
(1)
F is expelled compaction driven flux (m3/m2 per s), AOT is the porosity reduction during time T (s) and H is the true vertical thickness of rock column undergoing compaction (m). In the calculation of fluxes over the Melke-Garn Formation border we have assumed a subsidence rate of 2.0 x 106 km/year (sedimentation rate = 0.5 mm/year; Fig. 2). The porosity of the Melke Formation at about 4 km depth is 3.0% (Table 3). The porosity loss due to compaction is es-
timated to be 4%, assuming an average porosity of 7% at 3 km depth. From Fig. 5 we can see that the vertical thickness of the overpressured compartment overlying the Garn Formation is approximately 2500 m. If we then assume that half of this overpressured compartment drains downwards, which is not unlikely since the pressure gradient is uniform over the whole compartment, the thickness (H) of, rock that "drains" downwards is 1250 m. Another important factor underlying these calculations is that the pressure gradient over the Melke-Garn Formation border is assumed to have been approximately constant during the last 2.0 x 106years. Thus the flux is equal to (0.04 x 1250 m3/m2 per 6.3 x 1013s =) 7.9 x 10 -13 m3/m 2 per s. The resulting Melke permeabilities derived from this calculation for the three different wells with reversed pressure gradients (0.60.8 bar/m) at the Melke-Garn Formation border is given in Table 4. The lowest of the permeabilities measured in the laboratory (Table 3) are on average close to the values obtained by this calculation. The highest values in Table 3 may be due to fractures produced by unloading, or variations in the lithology. Fractures could of course also be created during sample preparation. Another reason that the in situ permeability might be estimated significantly incorrect is that the measurements were done in the laboratory, with uniform stress conditions, and not under reservoir conditions. According to Katsube et al. (1991), the permeability measured in the laboratory could be lowered by two orders of magnitude by increasing the effective stress. It should be noted that the calculated permeabilities are the mean permeability for the whole stratigraphic interval, whereas the measured permeabilities represent "points" within this interval.
Table 1 Mean (and standard deviations) mineralogical content from XRD bulk analysis a Well
Formation
No. a
14/~
10 A
7/~
Quartz (4.26 ~)
K-Fld (3.24/~)
Plag. (3.19/~)
Calcite (3.03/~)
Ankerite/ Apatite dolomite (2.81/~) (2.90 A)
Siderite (2.79/~)
Pyrite (2.71/~)
6506/11-1 6506/12-1 6506/12-1 6506/12-1 6506/12-1 6506/12-4 6506/12-5 6506/12-5 6506/12-5 6506/12-5 6506/12-6 6506/12-6 6506/12-6
Garn Gain Not Tofte Tilje Melke Melke Not Ile Ror Melke Ror Tilje
13 2 23 1 2 7 17 1 1 11 17 5 6
0 (0) 0 (0) 3 (2) 7 (-) 3 (5) 1 (2) 1 (1) 2 (-) 0 (-) 1 (1) 2 (4) 0 (0) 0 (0)
8 (7) 14 (17) 14 (7) 20 (-) 13 (10) 12 (7) 6 (3) 7 (-) 9 (-) 7 (2) 9 (9) 14 (6) 25 (13)
2 (5) 6 (7) 28 (22) 29 (-) 19 (13) 35 (22) 16 (10) 60 (-) 21 (-) 13 (4) 42 (19) 6 (4) 19 (6)
80 (12) 68 (22) 41 (22) 26 (-) 52 (37) 47 (27) 30 (12) 19 (-) 23 (-) 51 (6) 27 (12) 68 (9) 27 (15)
5 (9) 8 (6) 4 (2) 5 (-) 5 (1) 0 (0) 9 (8) 0 (-) 0 (-) 6 (5) 0 (1) 5 (3) 4 (3)
1 (2) 1 (1) 3 (2) 4 (-) 3 (3) 3 (1) 12 (6) 7 (-) 31 (-) 10 (1) 8 (3) 2 (3) 9 (4)
0 (0) 0 (0) 0 (0) 0 (-) 0 (0) 0 (0) 0 (0) 0 (-) 0 (-) 0 ((3) 0 (0) 0 (0) 0 (0)
0 (0) 0 (0) 0 (0) 0 (-) 0 (0) 0 (0) 0 (0) 0 (-) 0 (-) 0 (0) 0 (0) 0 (0) 0 (0)
1 (1) 1 (1) 5 (10) 9 (-) 5 (7) 1 (1) 8 (8) 4 (-) 2 (-) 6 (3) 10 (21) 2 (2) 12 (10)
2 (5) 1 (2) 1 (1) 0 (-) 0 (0) 1 (2) 10 (10) 0 (-) 15 (-) 6 (3) 2 (1) 2 (3) 0 (0)
All values are given in XRD per cent, without weight factors. aNumber of samples.
0 (0) 0 (0) 0 (0) 0 (-) 0 (0) 0 (0) 8 (29) 0 (-) 0 (-) 0 (0) 0 (0) 0 (0) 0 (0)
Pore water flow and petroleum migration in the SmCrbukk field area, offshore mid-Norway
209
Table 2
Table 4
XRD data from the clay (>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
R. Olstad, K. BjCrlykke and D.A. Karlsen
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
R. Olstad, K. BjCrlykke and D.A. Karlsen
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
Pore water flow and petroleum migration in the SmCrbukk field area, offshore mid-Norway
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-
R. Olstad, K. BjCrlykke and D.A. Karlsen
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.
Pore water flow and petroleum migration in the SmCrbukk field area, offshore mid-Norway
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R. Olstad, K. BjCrlykke and D.A. Karlsen
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.
Hydrocarbon Seals: Importancefor Exploration and Production edited by P. Mr
and A.G. Koestler. NPF Special Publication 7, pp. 217-229, Elsevier, Singapore. 9 Norwegian Petroleum Society (NPF) 1997
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
T. Lilleng and R. Gundesr
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.
The Njord Field." a dynamic hydrocarbon trap
221
10-1
7-1 Total
Pore pressure
(thermal}
Gas (%) i
1,1 ~l
1,3 |
i
i
Pore pressure
Total (thermall
Gas
(S.G.)
0,51,0 i
7-3
(S.G.)
(%)
1 , .~
0,51
L
|
1,1
,E |
9 i
1,3 i
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
T
o Estimated pore-pressure from sonic logs and D-exponent II Hydrocarbon bearing reservoir sand
v Pore-pressure from RFT-data
