Hydrocarbon Migration Systems Analysis

Developments in Petroleum Science, 35 hydrocarbon migration systems analysis DEVELOPMENTS I N PETROLEUM SCIENCE Advi...

Author: J.M. Verweij

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Developments in Petroleum Science, 35

hydrocarbon migration systems analysis

DEVELOPMENTS I N PETROLEUM SCIENCE Advisory Editor: G.V. Chilingarian Volumes I . 3 . 4 , 7 and 13 are out of print W.H. FERTL - Abnonnal Formation Pressures T.F. YEN and G.V. CHILINGARIAN (Editors) - O i l Shale D.W. PEACEMAN - Fundamentals of Numerical Resevoir Simulation L.P. Dake - Fundamentals of Resevoir Engineering K. MAGARA - Compaction and Fluid Migration M.T. SlLVIA and E.A. ROBINSON - Deconvolution of Geophysical Time Series in the Exploration for Oil and Natural Gas I I . G.V. CHILINGARIAN and P. VORABUTR - Drilling and Drilling Fluids 12. T.D. VAN GOLF-RACHT - Fundamentals of Fractured Reservoir Engeneering 14. G. MOZES (Editor) - Paraffin Products 15A. 0. SERRA - Fundamentals of Well-log Interpretation, 1. The acquisition of logging data 15B. 0. SERRA - Fundamentals of Well-log Interpretation, 1. The interpretation of logging data 16. R.E. CHAPMAN - Petroleum Geology 17A. E.C. DONALDSON, G.V. CHILINGARIAN and T.F.Yen (Editors) - Enhanced Oil Recovery, I. Fundamentals and analyses 17B. E.C. DONALDSON, G.V. CHILINGARIAN and T.F.Yen (Editors) - Enhanced Oil Recovery, 11. Processes and operations 18A. A.P. SZILAS - Production and Transport of Oil and Gas, A. Flow mechanics and production 2. 5. 6. 8. 9. 10.

(\econd cimpletely revised edition)

18B. A.P. SZILAS - Production and Transport of Oil and Gas, B. Gathering and Transport (second completely revised edilion)

19A. G.V. CHILINGARIAN. J.O. ROBERTSON Jr. and S. KUMAR - Surface Operations in Petroleum Production, I 19B. G.V. CHILINGARIAN, J.O. ROBERTSON Jr. and S. KUMAR - Surface Operations in Petroleum Production, II 20. A.J. DIKKERS - Geology in Petroleum Production 21. F. RAMIREZ - Application of Optimal Control Theory to Enhanced Oil Recovery 22. E.C. DONALDSON, G.V. CHILINGARIAN and T.F. Yen - Microbial Enhanced Oil Recovery 23. J. HAGOORT - Fundamentals of Gas Resevoir Engineering 24. W. LITTMANN - Potymer Flooding 25. N.K. BAIBAKOV and A.R. GARUSHEV - Thermal Methods of Petroleum Production 26. D. MADER - Hydraulic Proppant Farcturing and Gravel Packing 27. G. DA PRAT - Well Test Analysis for Naturally Farctured Resevoirs 28. E.B. NELSON (Editor) - Well Cementing 29. R.W. ZIMMERMAN - Compressibility of Sandstones 30. G.V. CHILINGARIAN, S.J. MAZZULLO and H.H. RlEKE - Carbonate Resevoir Characterization: A Geologic-Engineering Analysis, Part 1 31. E.C. DONALDSON (Editor) - Microbial Enhancement o f Oil Recovery - Recent Advances 33. E. F J E R , R.M. HOLT, P. HORSRUD, A.M. RAAEN and R. RISNES - Petroleum Related Rock Mechanics 34. M.J. ECONOMIDES - A Practical Companion 10 Resevoir Stimulation 36. L. DAKE -The Practice of Reservoir Engineering 37. W.H. SOMERTON - Thermal Properties and Temperature Related Behavior of Rock/Fluid Systems

Developments in Petroleum Science, 35

hydrocarbon migration systems analysis

J.M. VERWEIJ TNO Institute of Applied Geoscience, Schoemakerstr. 97, P.O. Box 6012,2600 JA Delft, The Netherlands

ELSEVIER, Amsterdam -London -New York -Tokyo

1993

ELSEVIER SCIENCE PUBLISHERS B.V. Sara Burgerhartstraat 25 P.O. Box 2 I I , 1000 A E Amsterdam, The Netherlands

ISBN: 0-444-89103-X

0 1993 Elsevier Science Publishers B.V. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form

or by any means, electronic, mechanical, photocopying. recording or otherwise, without the prior written permission of the publisher, Elsevier Science Publishers B.V., Copyright & Permissions Department, P.O. Box 521, loo0 AM Amsterdam, The Netherlands. Special regulations for readers in the USA - This publication has been registered with the Copyright Clearance Center Inc. (CCC). Salem. Massachusetts. 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 publisher. No responsibility is assumed by the publisher for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions or ideas contained in the material herein.

Although all advertising material is expected to confonn to ethical (medical) standards, inclusion in this publication does not constitute a guarantee or endorsement of the quality or value of such product or of the claims made of it by its manufacturer. This book is printed on acid-free paper. Printed in The Netherlands

V

ACKNOWLEDGEMENTS

I would like t o thank the TNO Institute of Applied Geoscience, Delft, The Netherlands for continued support and cooperation during the preparation of the book. The use of facilities of the TNO Institute, including library and drafting services, is also gratefully acknowledged. I thank mr Jos Rietstap for drafting most of the illustrations. Special thanks are due t o mrs Gerda Boone of Gebotekst, Zoetermeer, who typed the different versions of the manuscript and assisted in the organization of the final version. Finally, I appreciate the constructive comments of the anonymous reviewer of Elsevier, on an earlier version of this book.

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vii

PREFACE

The distribution of oil and gas in a sedimentary basin is determined by a combination of evolutionary processes that may have taken place during the geological history of the basin. The processes that determine the hydrocarbon potential of a basin are the generation, primary and secondary migration of hydrocarbons and the accumulation and preservation of hydrocarbons in traps. The hydrocarbon migration system influences the distribution, accumulation and nature of hydrocarbons in sedimentary basins. Hydrocarbon migration systems analysis is the integrated study of the evolution of hydrocarbon migration systems in sedimentary basins. This book has been prepared t o provide geoscientists - both university students and professionals interested in or working in hydrocarbon exploration - with a comprehensive understanding of the evolution of hydrocarbon migration systems and its application for basin evaluation. For this purpose, the book treats hydrocarbon migration in a multidisciplinary and explanatory manner. In order t o present geoscientists with the necessary basic understanding of fluid flow in sedimentary basins, the whole first part of the book is dedicated t o this subject. Chapter 1 reviews the fundamentals of single-phase fluid flowlgroundwater flow and associated processes of mass, energy and chemical transport. Chapter 2 considers groundwater flow on a basin-wide scale. It provides information on the processes controlling the development of groundwater flow systems, and the characteristic physico-chemical features associated with the different types of flow system. The second part deals with the hydrocarbon system. Chapter 3 gives relevant information on the processes of hydrocarbon generation and migration in source rocks. The principles of secondary hydrocarbon migration are outlined in Chapter 4. The theoretical concepts concerning hydrocarbon migration, given in this chapter, are derived from published literature. The different migration concepts have been integrated to give a more coherent and more generally valid picture of the evolution of secondary hydrocarbon migration systems in sedimentary basins. Chapter 4 pays ample attention to the influence of hydrodynamic conditions on secondary hydrocarbon migration. Chapter 5

viii

Preface

covers the processes of hydrocarbon accumulation, entrapment and preservation, and the influence of hydrodynamic and hydrocarbon migration conditions on these processes. The third and final part of the book presents a multidisciplinary approach to identify the present secondary hydrocarbon migration systems and the geohistory of secondary hydrocarbon migration systems in a sedimentary basin, and indicates how the results can be used for hydrocarbon exploration purposes. The presented secondary hydrocarbon migration systems analysis has been developed by extending a methodology that is applied successfully by hydrogeologists for the quantitative analysis of groundwater flow systems, taking into account the principles of groundwater flow, hydrocarbon migration, accumulation, entrapment and preservation as given in the first and second part of the book.

J.M. Verweij

ix

CONTENTS PART 1

FLUID FLOW

Introduction to single-phase fluid flow Chapter 1 1.1 Driving forces 1.2 Basic equations 1.2.1 Darcy’s equation 1.2.2 Continuity equations 1.2.3 Flow equations Large scale flow of groundwater 1.3 1.3.1 Applicability Darcy’s law 1.3.2 Continuity equations 1.4 S um m a r y Groundwater flow in sedimentary basins Chapter 2 Groundwater flow in actively filling and subsiding basins 2.1 2.1.1 Driving forces 2.1.2 Permeability distribution 2.1.3 Burial-induced groundwater flow system 2.2 Tectonically-induced groundwater flow 2.3 Groundwater flow in stable subaerial basins 2.3.1 Gravity-induced groundwater flow system 2.4 Local groundwater flow systems 2.4.1 Buoyancy-induced groundwater flow system 2.4.2 Osmotically-induced groundwater flow 2.5 Interaction of groundwater flow systems 2.6 Summary PART 2

3

3 5 5 6 10 11 12 15 21

23 26 26 28 34 51

55 55 70 70

74 75 78

GENERATION, MIGRATION AND ACCUMULATION OF HYDROCARBONS

Generation and expulsion of hydrocarbons Chapter 3 3.1 Origin of natural hydrocarbons 3.1.1 Organic matter Generation of hydrocarbons from organic matter 3.1.2 Generation of hydrocarbons from coal 3.1.3 Masses of generated hydrocarbons 3.1.4 Temperature and depth of hydrocarbon generation 3.1.5 Primary hydrocarbon migration 3.2 Primary hydrocarbon migration involving active groundwater 3.2.1 flow

83

85 85 86

91 93 91

97

99

Contents

X

3.2.1.1 3.2.1.2 3.2.1.3 3.2.1.4 3.2.2

Hydrocarbons in molecular solution Hydrocarbons in micellar solution Hydrocarbons in separate phase Conclusion Primary hydrocarbon migration independent of active groundwater flow 3.2.2.1 Continuous separate phase hydrocarbon migration Diffusion-induced hydrocarbon migration 3.2.2.2 Expulsion efficiency 3.2.3 3.3 Summary

Chapter 4 Secondary hydrocarbon migration Secondary hydrocarbon migration under hydrostatic conditions 4.1 Buoyancy 4.1.1 4.1.2 Capillary pressure 4.1.3 Separate phase hydrocarbon migration Secondary hydrocarbon migration under hydrodynamic conditions 4.2 Separate phase hydrocarbon migration 4.2.1 4.2.2 Migration of hydrocarbons in aqueous solution Regional aspects of secondary hydrocarbon migration 4.3 4.3.1 Changing conditions along the migration path 4.3.2 Secondary migration efficiency 4.3.3 Hydrostatic secondary hydrocarbon migration 4.3.4 Hydrodynamic secondary hydrocarbon migration Secondary hydrocarbon migration in actively filling and 4.3.4.1 subsiding basins Secondary hydrocarbon migration in stable subaerial basins 4.3.4.2 Secondary hydrocarbon migration in tectonically affected 4.3.4.3 basins Summary 4.4 Hydrocarbon accumulation, entrapment and preservation Hydrocarbon accumulation and entrapment under hydrostatic conditions Hydrocarbon accumulation and entrapment under hydrodynamic conditions Hydrocarbon accumulation and entrapment in hydrodynamic sedimentary basins Accumulation and entrapment in actively filling and subsiding basins Accumulation and entrapment in stable subaerial basins Accumulation and entrapment in tectonically active basins Preservation of trapped hydrocarbons Hydrocarbon preservation under stable geological conditions

99 103 103

104 105 105 111 115 119 121 122

122 125

127

134 135 140 140 141 144 145 148 149

154 157 158

Chapter 5 5.1 5.2 5.3 5.3.1

5.3.2 5.3.3 5.4 5.4.1

161 162 169 178

178 181 182 183 183

Contents

5.4.2 5.5

xi

Hydrocarbon preservation under changing geological conditions 187 Summary 189

PART 3

BASIN EVALUATION FOR HYDROCARBON EXPLORATION

Application to basin evaluation Chapter 6 Hydrodynamic condition, hydrocarbon migration and basin 6.1 evaluation 6.2 Hydrocarbon migration systems analysis 6.3 Data base 6.3.1 Pressure 6.3.2 Temperature 6.3.3 Chemical composition 6.3.4 Porosity and permeability Qualitative analysis of secondary hydrocarbon migration systems 7.1 Present-day hydrocarbon migration systems 7.1.1 Identification of the depocentres Identification of the hydrostatic hydrocarbon migration patterns 7.1.2 Identification of the hydrodynamic conditions 7.1.3 Hydrodynamic conditions in subaerial regions 7.1.3.1 7.1.3.2 Hydrodynamic conditions in subsiding and filling basins 7.1.4 Identification of the hydrodynamic influence on the hydrocarbon migration system History of hydrocarbon migration systems 7.2

193 193 197

m 201

2Q5 207

208

Chapter 7

211 211 212 212 213 214 219 221

224

Chapter 8 8.1 8.2 8.2.1 8.2.2 8.2.3 8.3 8.4

Quantitative analysis of secondary hydrocarbon migration systems Present-day hydrostatic hydrocarbon migration systems Present-day hydrodynamic conditions Hydrodynamic conditions in stable subaerial regions Hydrodynamic conditions in subsiding and filling basins Hydrodynamic conditions resulting from interactions of different groundwater flow systems Present-day hydrodynamic hydrocarbon migration systems History of hydrocarbon migration systems

227 229 232 232

239 241 a43 249

References

251

Subject index

269

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PART I

FLUID FLOW

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3

CHAPTER 1 INTRODUCTION TO SINGLE-PHASE FLUID FLOW

The pore spaces in the subsurface are normally water-saturated. In this book, all subsurface free H20-rich fluids are referred t o as groundwater. Groundwater is present throughout the crust to depths of at least 15 t o 20 km (Bredehoeft and Norton, 1990). Oil and gas accumulations are found between the ground surface and depth levels of about 6000 t o 7000 m and deeper (Tissot and Welte, 1984). The processes of generation, migration, accumulation and preservation of natural hydrocarbons take place in a water-saturated environment. The physico-chemical characteristics of groundwater may influence each of these processes. Knowledge on groundwater characteristics is indispensable to assess this potential influence. The theory on the flow of groundwater is based on the general principles of single-phase fluid flow through porous media. The same principles also apply t o the single-phase flow of hydrocarbons. The following sections treat the driving forces for the flow of fluids in the subsurface (Section 1.1),the basic equations describing single-phase fluid flow through porous media (Section 1.2) and regional aspects of fluid flow (Section 1.3) with respect t o groundwater.

1.1 Driving forces The driving forces for the flow of groundwater are groundwater potential gradients, temperature gradients, electrical gradients and chemical gradients (De Marsily, 1986; Freeze and Cherry, 1979). Ynder groundwater flow conditions, i.e. hydrodynamic conditions, the net force E, acting on a unit mass of water can be given by e,=-grad

@,-grad T-grad E-grad C

where, @W

= groundwater potential

(1.1)

4

Chapter 1

T = temperature of the groundwater E = electrical potential of the groundwater C = chemical potential of the groundwater Under hydrostatic conditions, there is no flow of groundwater and E, = 0.

-

The groundwater potential gradient is the main driving force for groundwater flow. A t a certain point the groundwater potential Qw, i.e. the mechanical energy per unit mass of groundwater, and the corresponding total head hT,i.e. the mechanical energy per unit weight, for groundwater whose density is a function of pressure only, is given by Hubbert (1953) as

where, QW

= potential of the groundwater

(LV2)

hT g

= total head of the groundwater (L)

z

= elevation of point of measurement above datum (L) = velocity of the groundwater (LT1) = pressure of the groundwater (ML-1T-2) = density of the groundwater (ML-3)

VW

PW Pw

= acceleration due to gravity ( L T 2 )

Because velocities of groundwater are extremely low, the term v&/g is generally considered t o be negligible and Z

P

qW= g h = g J d z + j dP w

(1.3)

pw where, h = hydraulic head (L). 20

PO

The potential of a unit mass of groundwater, as given by Equation 1.3 is thus determined by its place in the earth gravitational field and by the pressure and density of the groundwater. In groundwater practice, sea level and atmospheric pressure are taken as reference state, i.e. zo = 0 and po = 1 atmosphere. If, in addition, the density of the groundwater is constant (pwisnot a function of pw,i.e. the water is incompressible), the hydraulic head becomes h = z + - P- -w

(1.4)

Pwg

The gradient of the groundwater potential, as defined in Equation 1.3, is 1

grad Qw = g grad z + -grad Pw

pw

(1.5)

5

Introduction to single-phase fluid flow

which can be rewritten as (Hubbert, 1953) 1

-grad $, = 2 --grad

p,

(1.6)

Pw

The net driving force for groundwater flow that results from the groundwater potential gradient only, can thus be expressed as

2, =-grad

$w

1

= -g grad h = g--grad Pw

p,

(1.7)

-+

The direction of this force E, is perpendicular to the equipotenti-a1 surfaces of the groundwater. The water will be driven in the direction of E,, i.e. in the direction of decreasing potential.

1.2 Basic equations

The three-dimensional flow of groundwater through the subsurface can be described by a combination of Darcy’s equation for groundwater flow with a continuity equation ( o r mass balance equation) and equations of state for the groundwater and the porous medium. A detailed theoretical overview of equations for groundwater flow is given by e.g. Barenblatt et al. (1990), De Marsily (19861, Domenico and Schwartz (1990) and Freeze and Cherry (1979). Sections 1.2.1 t o 1.2.3 present the basic equations for groundwater flow through a representative elementary volume of the porous medium (Bear, 1972) under certain restrictive assumptions, such as isothermal and isochemical subsurface conditions and absence of changes in tectonic stress.

1.2.1 Darcy’s equation Darcy’s law (Darcy, 1856) is a phenomenological law that is valid for the viscous flow of a single-phase fluid (e.g. groundwater flow) through porous media in any direction. This basic law of fluid flow is a macroscopic law providing averaged descriptions of the actual microscopic flow behaviour of the fluids over some representative elementary volume of the porous medium. For isothermal and isochemical subsurface conditions, the law can be written as (Hubbert, 1953)

cw =--grad hw P W

where,

@,

=-K grad h

(1.8)

6 +

5. K +

k PW

Chapter 1

-(pwg)

= specific discharge of the groundwater (LT-l) = k = hydraulic conductivity of the water-saturated porous PW

medium (LT-') = intrinsic permeability of the solid matrix (L? = dynamic viscosity of the groundwater (ML-lT-l)

The intrinsic permeability and the hydraulic conductivity are tensorial properties. The intrinsic permeability is a measure of the resistance to flow of a fluid in a porous medium. It depends on the physical properties of the porous medium. The hydraulic conductivity is the amount of groundwater flow per unit cross-sectional area under influence of a unit gradient of hydraulic head. It depends both on the properties of the porous medium, such as the size, shape, orientation of its interstices and the interconnection of the interstices, and on the groundwater, namely its density and viscosity. The density and viscosity of the groundwater may vary with pressure, temperature and concentration of dissolved solids, thus influencing the hydraulic conductivity. The viscosity is the property of the internal resistance of the groundwater to flow. It is most strongly influenced by the temperature: the higher the temperature the lower the viscosity of the water, resulting in higher values of the hydraulic conductivity and consequently in higher values of the specific discharge of groundwater. In a homogeneous and isotropic porous medium, where the groundwater conditions are isothermal and isochemical, the hydraulic conductivity K of the subsurface will be constant and the flow of groundwater will be in the direction of - grad qW, i.e. perpendicular to the equipotential surfaces of the groundwater. However, in for instance an anisotropic porous medium K is not constant, and the directions of Gw and - grad @w may not coincide; the flow of groundwater has a tendency t o follow the direction of highest hydraulic conductivity (Davis and De Wiest, 1967; De Marsily, 1986). By introducing the appropriate expression for the hydraulic head, i.e. Equation 1.3 or 1.4, into Darcy's equation 1.8, it describes the flow for compressible and incompressible groundwater, respectively. The flow of compressible groundwater can thus be described by a more general form of Darcy's equation, in which the gradient of the groundwater potential is given by Equation 1.5

G~ = --{pwg i; PW

grad z + grad P,)

(1.9)

1.2.2 Continuity equations A continuity equation for fluid flow through a certain representative elemental volume of porous media fixed and rigid in space is based on the law

7

Introduction to single-phase fluid flow

of conservation of mass, i.e. mass inflow rate of fluid = mass outflow rate of fluid + time rate of change of fluid mass storage. For steady-state groundwater flow, i.e. when the magnitude and direction of the flow is constant with time, the continuity equation can be written as (e.g. Freeze and Cherry, 1979) (1.10)

The parameter pw can be neglected if pw = constant and Equation 1.10 becomes (1.11)

For unsteady-state groundwater flow, i.e. when the magnitude and direction of the flow change with time, the equation of continuity is (1.12) where,

6t

= time-rate of change of groundwater mass storage per unit of volume

Provided that the following assumptions are met, the time-rate of change of groundwater mass storage can be related to changes in the density of the groundwater, in the porosity of the porous medium and in the vertical dimensions of the representative elementary volume of the porous medium, i.e. 6AM 6t

-=--

where, n VT

V" v s

Az

6p, 6(npw)-n-+p,-+-6t 6t

6n pWn6Az 6t Az 6t

(1.13)

= porosity = V" (dimensionless) VT = V, + V, = total unit volume of porous medium (L9 = volume of the voids (L3> = volume of the solid matrix (L3>

= vertical height of elementary volume of the porous medium (L)

The assumptions are:

- The subsurface conditions are isothermal and isochemical; - There are no time-changes in temperature and chemical subsurface conditions; There are no time-changes in stress externally imposed on the representative elementary volume of porous medium; - The porous medium is compressible and behaves as a linear elastic solid;

-

Chapter I

8

- Lateral deformations of the representative elementary volume of porous medium are negligible;

- The solid grains are incompressible; - The groundwater is compressible. Forces applied to a water-saturated porous medium will cause stresses which result in strain (deformation). The stress, strain and groundwater pressure in a water-saturated porous medium are coupled, as first recognized by Biot (1941). Under the assumed stress conditions, the vertical normal component of total stress (0,) that acts downwards on a horizontal plane a t any depth is caused by the weight of the overlying water-saturated rock. This stress is born by the solid matrix of the porous medium (0,)and by the pressure of the groundwater in the pores (pJ (e.g. Hubbert and Rubey, 1959) 0,=

oe + Pw

(1.14)

and do, = do, where,

+ dp,

Ge

= vertical normal component of total stress (ML-IT-2) = vertical effective component of total stress (ML-~T-~)

PW

= pressure of the groundwater (ML-IY2)

0,

(1.15)

The weight of the overlying water-saturated rock is assumed to be constant with time, hence do, = - dp,

(1.16)

The changes in vertical effective component of total stress are thus directly coupled to changes in pressure of the groundwater. When stress is applied to a unit mass of water-saturated porous rock, a change in the total volume of the rock mass can result from: - compression of the groundwater in the pores (a change in density of the groundwater), which is controlled by the compressibility of the groundwater,

-

P,;

compression of the individual solid grains (change i n density of the solid grains), controlled by the compressibility of the grains, p,; - rearrangement of the solid grains, controlled by the compressibility of the porous rock matrix, a. In general, compressibility can be defined as the rate of change of volume V with respect to an applied stress per unit of volume (Fertl, 1976). The isothermal compressibility of water, p, is given by

Introduction to single-phase fluid flow

dVwNw - dPw/Pw doe dPw where, = isothermal compressibility of groundwater (M-lLT? P W = volume of groundwater = nV, (L3> VW = effective component of total stress ( M L - ~ Y ~ ) Oe pw=-

9

(1.17)

The time-change in density of the groundwater can be written as

-at

p

apw

w w

at

(1.18)

The time-change in density of the solid grains has been assumed t o be negligible. The compressibility of a porous rock matrix is (1.19)

Under the assumed conditions, the vertical compressibility of the porous medium, a,,can be given by a, = - d(Az)I Az - d(Az)I Az doe dPw

(1.20)

and the time-change of the vertical dimension of the elementary volume of the porous medium with pressure is ~ ( A z )- a,(Az)- 6Pw --

6t

6t

(1.21)

An increase in effective stress results in a reduction in the total volume of the rock mass dV, = dVv + dV,. Under the assumption that the solid grains are incompressible, the reduction dV, is caused by grain rearrangements, i.e. dV, = dV,. Hence

The time-change of porosity of the porous medium with pressure is given by Sn = a,(l -n)- 6Pw 6t st

(1.23)

Chapter I

10

By introducing the equations of state for the groundwater and the porous medium (Equations 1.18, and 1.21 and 1.23, respectively) into the continuity Equation 1.13 gives (e.g. Walton, 1970) (1.24) The groundwater pressure in a representative elementary volume of the porous medium fixed in space, changes directly with the hydraulic head, i.e. dpw = pwgdhand Equation 1.24 can be written as (1.25) where, ss

= PJZ

(a, + nPw)= vertical specific storage (L-l).

Jacob (1940) introduced the term specific storage. Expanding the terms on the left-hand side of Equation 1.25 by the chain rule, gives (1.26) aq are in general much greater than the Because the terms of the form pw 3

ax

terms of the form q,

h, Equation (1.26)is often simplified (e.g. Walton, 1970) ax (1.27)

1.2.3 Flow equations For steady-state flow of groundwater, a combination of the continuity Equation 1.11with Darcy's equation 1.8 yields (1.28) For flow through homogeneous isotropic media (K, = reduces to the Laplace equation d2h d2h a2h 2+--T+7=0 ax ay aZ

or V2h=0

= &), Equation 1.28

(1.29)

Introduction to single-phase fluid flow

11

The solution h(x,y,z) describes the value of the hydraulic head at any point in a flow field. Introducing Darcy's equation 1.8 into the simplified continuity Equation 1.27 yields the general equation for unsteady-state flow through a water-saturated anisotropic medium under the assumed conditions listed in Section 1.2.2. (1.30) For flow through homogeneous and isotropic media, Equation 1.30 reduces t o the diffusion equation

s, ah V2h = -K at

(1.31)

The solution h(x,y,z,t) describes the hydraulic head at any point in a flow field at any time. The equations for steady and unsteady-state flow of groundwater (Equations 1.28, 1.29, 1.30, 1.31)can be solved for a particular hydrogeological situation by stating the appropriate initial and boundary conditions.

1.3 Large scale flow of groundwater In order to study the potential influence of groundwater flow on the distribution and characteristics of oil and gas accumulations, knowledge on the evolution of large-scale (basin-wide) groundwater flow systems is needed. The classical equations given in the previous sections describe the flow of groundwater through a representative elementary volume of porous medium under restrictive assumed conditions. On large temporal and spatial scales the actual conditions may deviate significantly from the assumed ones. On a regional scale, for example, the subsurface cannot considered t o be a homogeneous and isotropic porous medium and the subsurface conditions may not be isothermal and isochemical. When geological time scales are taken into account, changes in the direction and velocity of groundwater in large-scale systems may be influenced by time-changes in total stresses, thermal, hydrochemical and geochemical conditions. Time-changes of total stress accompany geological processes such as sedimentation, erosion and tectonic activity. The time-changes of temperature may result from changes in terrestrial heat flow, or may be caused by the displacement of a unit watersaturated porous medium along the geothermal gradient during e.g.

12

Chapter 1

sedimentation in a basin or uplift and erosion of a sedimentary basin. In turn, the chemical characteristics of both the groundwater and the rock matrix of the porous medium are changed in time as a result of changing stress and temperature conditions. Local groundwater flow conditions of importance in petroleum-related studies may also deviate from the general assumptions underlying the Laplace and diffusion equations, e.g. chemical and electrical gradients may influence the flow through low-permeable media (e.g. Neuzil, 1986). 1.3.1 Applicability Darcy’s law Darcy’s law applies to flow of groundwater relative to the solid matrix of a water-saturated porous medium (Fertl, 1976). For isothermal and isochemical subsurface conditions, Darcy’s law (Equation 1.8) is valid provided there is a linear relationship between the specific discharge of the groundwater and the gradient of the groundwater potential. A condition to be fulfilled is that the flow of groundwater should be purely laminar, i.e. not turbulent (e.g. De Marsily, 1986; Freeze and Cherry, 1979). In general, the natural flow of groundwater is laminar, except for flow through rocks with large-diameter (solution) openings. Whether or not Darcy’s law is valid for the relation between groundwater flow through a poorly permeable medium (K < 10-9m/s) and for low groundwater potential gradients 2 1is untested (Neuzil, 1986). Darcy’s law is valid for three-dimensional flow of groundwater through water-saturated porous and permeable media. On a large-scale the intrinsic permeability of the subsurface varies widely in space. The permeability is observed in nature t o vary over a t least 15 orders of magnitude (Bredehoeft and Norton, 1990; Figure 1.1).In groundwater studies, this spatial variability is generally converted t o averaged values of permeability in the two o r three principal directions of anisotropy (e.g. De Marsily, 1986). In a sedimentary basin, generally one main direction of anisotropy will be normal to the stratification and the other two parallel t o it. In fractured rocks, one principal direction of anisotropy will be in the direction of the main fractures, the other normal t o those fractures. The flow of groundwater in each of the principal directions of anisotropy is parallel to the hydraulic gradient in that direction. Consequently, by introducing the appropriate value of permeability in a principal direction of anisotropy into Darcy’s equation 1.8, the equation describes correctly the flow of groundwater in that direction. Darcy’s equation 1.8 describes the flow of groundwater as induced by hydraulic head gradients only. Darcy’s equation for groundwater flow can be generalized t o take the other driving forces for groundwater flow, i.e.: temperature gradients, electrical gradients and chemical gradients, into account (De Marsily, 1986)

Introduction to single-phase fluid flow

-

Karst limestone Permeable basalt Fractured igneous and metamorphic rocksLimestone and dolomite -Sandstone

-

-

--

-

-

Unfractud metamorphic and igneous rocks Shale Unweatheredmarine clay Glaclal till

-

-

- -

-Silt.

loess-

-

Silty sand -Cleansand-

Gravel-

Figure 1.1 Ranges of permeabilities and hydraulic conductivities for different types of rock (modified after R. Allan Freeze and John A. Cherry, GROUNDWATER, 0 1979, p. 29. Reprinted by permission of Prentice Hall, Englewood Cliffs, New Jersey).

+

q, = -K, grad h - &grad T - K3grad E - K4grad C

(1.32)

where, K, (= hydraulic conductivity), K2, K, and K4 are phenomenological coefficients, which may be scalar o r tensorial. The flow of groundwater, electricity, solutes and heat through porous media are interdependent transport processes. The interdependency of the different processes is a reflection of the thermodynamic concept of coupled flow (Freeze and Cherry, 1979). One kind of flow influences each of the other kinds of flow, and all of the driving gradients given in Equation 1.32 are of influence on the flow of groundwater, heat, solutes as well as electricity. For example, the hydraulic head gradient does not only induce flow of groundwater, but also of heat, electricity and solutes. This coupling between groundwater flow, heat flow and flow of solutes is in part explained by the dependency of both the density and viscosity of groundwater (which appear in the Darcy equations 1.8 and 1.9) on the pressure, temperature and concentration of dissolved solids. Figure 1.2 illustrates the strong dependency of the viscosity of groundwater on the temperature. The influence of both temperature and pressure on the density of groundwater, omitting variations in chemical composition, can be given by the following equation of state (e.g. Palciauskas and Domenico, 1980)

14

Chapter 1

20

40

60

80

100

120

140

Temperature (“C)

Figure 1.2 Variation of the viscosity of water with temperature and NaCl concentration at a constant pressure of 10 MPa (modified after Garven and Freeze, 1984a, American Journal of Science, Volume 284, Figure 5. Reprinted by permission of American Journal of Science).

1

-dp,

= P,dp,

20

40

60

80

100

120

140

Temperature (“C)

Figure 1.3 Variation of the density of water with temperature and NaCl concentration at a constant pressure of 10 MPa (modified after Garven and Freeze, 1984a, American Journal of Science, Volume 284, Figure 4. Reprinted by permission of American Journal Science).

- a&dT

(1.33)

Pw

where, a, PW

= volumetric thermal expansion coefficient of the groundwater

(K-1)

= isothermal compressibility of the groundwater (M-lLT2)

The variation in density of the groundwater due to differences in concentration of dissolved solids and temperature is given in Figure 1.3. The spatial differences in groundwater density generate a buoyancy force for groundwater flow. The more general form of Darcy’s equation (Equation 1.9) may be used t o describe flow of groundwater of variable density under non isothermal conditions (see e.g. Garven and Freeze, 1984a; Hanor, 1987a; Harrison and Summa, 1991). It should be realized that for groundwater of

Introduction to single-phase fluid flow

15

temperature- or salinity-induced variable density, the expression g grad z + 1grad pw Pw

is not equal anymore to the groundwater potential gradient, grad ,$, by Hubbert (1953)(Section 1.1).

as defined

The characteristics of the groundwater and the porous medium that appear in Darcy’s equation vary independently on a geological time scale. Equation 1.9 should be used when dealing with large temporal and spatial scales. 1.3.2 Continuity equations The conservation of groundwater mass in a large-scale groundwater flow system under steady-state flow conditions is given by continuity Equation 1.10. For unsteady-state large-scale flow of groundwater on a geological time scale, Equation 1.12 is valid. The time-rate of change of groundwater mass storage per unit of volume of saturated porous medium (6AW6t) results from the changing stress, thermal, hydrochemical and geochemical conditions in the watersaturated porous medium during its geological evolution. Hence, knowledge of the mechanical, thermal and chemical processes operating during the geological evolution of the water-saturated porous medium is indispensable for a correct understanding and assessment of the unsteady-state groundwater flow behaviour. Equations based on the concept of conservation are presented below for each of these processes to provide a general insight in the processes concerned.

Conservation of solid mass On a geological time scale the conservation of mass for the solid phase is determined by the deformation of the solid matrix and the accompanying timechanges of porosity, and the dislocation of the solid matrix in space. The deformation and dislocation of the solid matrix depend on the changing stress, groundwater pressure, temperature and chemical conditions. The changes in stress will induce both reversible elastic deformations of the porous medium as well as inelastic deformations (Houseknecht, 1987; Plumley, 1980). The stress-induced inelastic deformations may include macroscopic fracturing and dilatancy resulting from microfracturing (Palciauskas and Domenico, 1980). The pressure and temperature dependent processes, such as precipitation or dissolution of authigenic minerals, cause reversible changes of porosity, while irreversible changes of porosity are induced by pressure solution of grains at their points of contact, which occurs frequently in combination with precipitation on free surfaces of adjacent grains (Bj~rlykkeet al., 1989; Harrison, 1990; Houseknecht, 1987). On a geological time scale, the deformations of the porous medium are dominated by irreversible processes and can be considerably larger than the elastic ones for the same applied effective stress (Palciauskas and Domenico, 1989).

Chapter I

16

The general expression for the conservation of mass for the solid phase in a deforming medium may be given as (Palciauskas and Domenico, 1989) (1.34) where, Ps n vs

= density of the solid grains (ML-3) = porosity (dimensionless)

= velocity of the solid matrix with respect to fixed coordinates (LT-')

Conservation of heat The transport of heat in a water-saturated porous medium is governed by conduction in the solid matrix, transport by the groundwater (convective movement of heat) and heat exchange between the solid and the groundwater, which depends on their temperature difference (e.g. De Marsily, 1986). Assuming that, the viscous dissipation of energy is small and may be neglected, the adiabatic temperature changes are negligible, there is instantaneous thermal equilibrium between the solid and the groundwater, the thermal conductivity of the solid matrix is isotropic, a n expression for the conservation of heat in a representative elementary volume of water-saturated porous medium fixed and rigid in space is (Van der Kamp and Bachu, 1989) (1.35) where,

Fc %n

%W

%

T C

CW

T*

= thermal conductivity (MLT3K-') = thermal conductivity of the water-saturated porous medium

(MLPK-I) = n qw + (1-n) qS = thermal conductivity of the groundwater (MLY3K-') = thermal conductivity of the solid (MLPK-') = temperature (K) = specific heat (LV2K-') = specific heat of the groundwater (Lv2K-l) = specific heat of the solid (LV2K-') = heat capacity of the water-saturated porous medium (ML-'T2K-I) = npwcw+ (1-n) psc, = heat sink or source term

The heat sink o r source term represents the local sources of heat produced by radio-active decay in the porous medium and the time-change in basal heat flux.

Introduction to single-phase fluid flow

17

Conservation of chemical mass The conservation of chemical mass in the subsurface is mainly controlled by the transport of solutes through the water-saturated porous medium, the chemical reactions in the groundwater and the reactions between the groundwater plus solutes and the solid matrix. The solutes are transported through the subsurface by convection, molecular diffusion and dynamic dispersion. Convection of solutes involves the displacement of dissolved chemical components by the flowing groundwater. Molecular diffusion is the mass flux of chemical components that takes place through both the mobile and immobile water in the porous medium as resulting from the chemical concentration gradients only. The dynamic dispersion is a physical mixing process which results from the heterogeneity of the velocity of groundwater in the porous medium (e.g. De Marsily, 1986). In the subsurface, there are variations in groundwater flow velocity inside the pores, variations in groundwater flow velocity and direction between pores and those resulting from larger-scale heterogeneity of the porous medium.

A general expression for the conservation of solute mass for a certain chemical component in a representative elementary volume of water-saturated porous medium fixed and rigid in space is (e.g. Garven, 1985; Garven and Freeze, 1984a) (1.36) where, D C

= coefficient of dispersion (a tensor) (L-1) = mass of a single chemical solute per unit volume of aqueous

C*

solution (ML-3) = net source or sink term (ML-3T-1)

The coefficient of dispersion in this advection-dispersion-reactionequation describes the combined processes of molecular diffusion and hydrodynamical dispersion (see e.g. Bear, 1972; De Marsily, 1986). The term C* indicates the disappearance or addition of a chemical component. It represents the influence of changes, exchanges and reactions of chemical components during their subsurface transport. The transport of chemical components may be stopped by physical (membrane) filtration (Bredehoeft et al., 1983; De Sitter, 1947; Graf, 1982; Neuzil, 1986). Many different types of geochemical reaction can be involved in changing the concentration of a certain solute, e.g. precipitation I dissolution; sorption via surface complexation (adsorption) o r sorption via ion exchange I desorption; oxidation I reduction; acid base reactions, complexation, radio-active decay (e.g. De Marsily 1986; Garven, 1985; Garven and Freeze, 1984a). Additional equations governing this geochemical mass transfer are

Chapter 1

la

needed to provide the proper values of C* in Equation 1.36 (see e.g. De Marsily, 1986; Garven and Freeze, 1984a; Yeh and Tripathi, 1989). The conservation of chemical mass in a multi-component groundwater flow system is given by a set of advection-dispersion-reactionequations, i.e. an appropriate equation for each chemical solute of interest. The equations describing the conservation of groundwater mass (Equation 1.12), solid mass (Equation 1.341, chemical mass (Equation 1.36) and heat (Equation 1.35) and Darcy's equation for groundwater flow (Equations 1.8 and 1.9) are coupled and nonlinear (Bredehoeft and Norton, 1990; Garven, 1985).

Conservation of groundwater mass The influence of the mechanical, thermal and chemical processes on the flow of groundwater can be introduced into the continuity equation for groundwater (Equation 1.12) assuming appropriate simplifying conditions. For example, if the assumptions listed in Section 1.2.2 are met, with the exception of the second assumption which is replaced by - There are time-changes in temperature and in total stress imposed on the elementary volume of porous medium; - There are no time-changes in chemical conditions; And, - The thermo-mechanical effects on the solid part of the water-saturated porous medium are negligible, the time-rate of change of groundwater mass per unit of volume of watersaturated porous medium can be given by (Sharp, 1983) (1.37) Taking into account the compressibility of the solid grains, Equation 1.37 may be written as (see Neuzil, 1986; Van der Kamp and Gale, 1983)

-

-

1 6pw 60 6T -V.(pwqw)= -s, -- p w ( a - a s6t) - - p w n a ~ ~ g where, = three dimensional specific storage (L-1) S S = pwg[(a - ad + n (Pw - ad] = bulk compressibility of the porous medium (LTW-1) a = bulk compressibility of the solids (LTM-1) a, = compressibility of the groundwater (LT?M-1) PW

s}

(LTW-~)

a

= az{

V

= Poisson's ratio for the porous medium (dimensionless) = mean total stress (M'PL-1) = thermal expansion coefficient of the groundwater (K-1)

ot

aTw

(1.38)

Introduction to single-phase fluid flow

19

In order to account for additional changes in groundwater mass storage by processes not included in the terms at the right-hand side of Equation 1.38, a source or sink term (pwQ;) can be added to this equation. Such a source or sink term may account for e.g. the dehydration of gypsum and the release of interlayer water from clay minerals as a function of temperature, pressure and groundwater chemistry (e.g. dehydration of smectite, kaolinite) (e.g. Bethke, 1986b; Bjprrlykke, 1989; Buhrig, 1989; Colten-Bradley, 1987; Powers, 1967); the introduction of juvenile water from magmatic sources; the reversible change of porosity due to chemical processes and irreversible change of porosity by intergranular pressure solution; and irreversible change of porosity due to stress-induced inelastic deformation. Strictly speaking, Equation 1.38 is a continuity equation for groundwater flow through a certain representative elemental volume of porous medium fixed and rigid in space. For small elastic deformations of the porous medium, the equation can be considered t o be valid provided that the specific discharge of groundwater is taken as relative to the rock grains (Cooper, 1966 and e.g. Neuzil, 1986; Sharp, 1983). When large, possibly inelastic, deformations are involved, i.e. when the representative elementary volume of porous medium is both deformed and dislocated in space, the dislocation of the porous medium with respect t o fixed coordinates should be taken into account as well (e.g. Bayer, 1989; De Marsily, 1986; Palciauskas and Domenico, 1989; Shi and Wang, 1986). So as to take the time-change in the location of the deforming representative elementary volume of porous medium into account, the continuity equations are often given in terms of material derivatives (e.g. De Marsily, 1986). The material derivative of a property (d( Ydt) in a deforming coordinate system with velocity v, is related to the derivative in a fixed coordinate system (6( Y6t) by (1.39)

For example, the general continuity equation for groundwater (Equation 1.12; 6AM/6t = 6npJ6t) written in terms of material derivatives in a deforming coordinate system following the motion of the solids, becomes (e.g. Palciauskas and Domenico, 1989; Shi and Wang, 1986) (1.40) where, VS

= velocity of the solid matrix with respect to the fixed coordinates (LT-1)

qw

= specific discharge of groundwater relative t o the rock grains (LT-1)

Chapter 1

20

Table 1.1 Symbolic equations representing the processes of mass, energy and chemical transport related t o groundwater flow

Darcv's eauation for Proundwater flow Gw

i;

=--bwg PW

grad z + grad Pw)

Conservation of groundwater mass steady state groundwater flow condition

unsteady state groundwater flow condition

-.

6pw

-V.(pwqw)=-s,-g 6t

p w ( a - " , ) ~60 - p w n c r T w - +6T pwQ,,

6t

6t

Conservation of solid mass -V.[p, (1- n)3,1= 6[p, (1- n)l

6t

Conservation of heat V.$,

VT - cwpWGw VT + T* = (PC),

Conservation of chemical ma=

Eauations of state

pw = f(P, T, C) Pw = f(P, T, C)

fl 6t

Introduction to single-phase fluid flow

21

1.4 Summary

The flow of groundwater in a sedimentary basin results from the combined influence of the different driving forces for groundwater flow (mechanical, thermal, chemical and electrical driving forces) and the hydraulic conductivity of the subsurface. The transport of groundwater, heat and electricity, the mass transport of chemical components and the deformation of the solid part of the subsurface are coupled processes. Table 1.1 gives an overview of the equations that symbolically represent the processes of mass, energy and chemical transport related to groundwater flow. The equations in Table 1.1are coupled and nonlinear.

22

Table 2.1 Five main types of sedimentary basins

I.

Divergent margin basins A. Rift basins 1. Rifted arch basins 2. Rim basins 3. Sag basins 4. Half-graben B. Ocean margin basins 1. Red Sea type (youthful) 2. Atlantic type (mature) C. Aulacogens and failed rifts D. Oceanic islands, seamounts, plateaus 11. Convergent margin basins A. Trenches and subduction complexes B. Forearc basins C. Interarc and backarc basins D. Retroarc (foreland) basins 111. Transform and transcurrent fault basins A. Basin setting 1. Plate boundary transform fault 2. Divergent margin transform fault 3. Convergent margin transcurrent fault 4. Suture zone transcurrent fault B. Basintype 1. Basins in braided fault systems 2. Fault termination basins 3. Pull-apart basins in en echelon fault systems 4. Transrotational basins IV. Basins developed during continental collision and suturing A. Peripheral (foreland or foredeep) basins (on underriding plate) B. Intrasuture embayment basins (remnant ocean basins) C. Hinterland foreland, strike-slip, and graben basins (on overriding plate) V. Cratonic basins From: Miall, 1990. Reprinted with permission of Springer-Verlag.

CHAPTER 2 GROUNDWATER FLOW IN SEDIMENTARY BASINS

A sedimentary basin is a subaquatic or subaerial region on the earth surface in which sediments have accumulated at a greater rate and to a greater thickness than they have in adjacent areas. Sedimentary basins form by deformation of the lithosphere mainly as a result of crustal extension during divergent plate movements and by compression and crustal thickening during convergent plate movements (extension may also occur during convergent movements) (Miall, 1990). The evolution of a sedimentary basin (i.e. its subsidence history; basal heat flow history; evolution of its physical size and shape, style of deformation, bottom configuration, water depth and sedimentary fill) is related to the successive plate-tectonic settings of the basin, the geological history of the plate margin processes and the successive latitudinal (i.e. climatic) settings of the basin (see Miall, 1990). Sedimentary basins are classified on the basis of the control of plate-tectonic processes on their evolution (Allen and Allen, 1990; Miall, 1990). Table 2.1 gives a classification of sedimentary basins based on their plate-tectonic setting. Similar types of basins may show a consistent pattern in their sedimentary evolution, whilst basins of different type show correspondingly different sedimentary styles (see Allen and Allen, 1990 and Miall, 1990). Most sedimentary basins cover tens of thousands of square kilometres and may contain a thickness of over five kilometres of sedimentary fill (Selley, 1985). Numerous studies demonstrate the existence of groundwater flow on a basinal scale (Beck et al., 1989; Bethke and Marshak, 1990; Bredehoeft et al., 1988; Chiarelli, 1978; Garven, 1985, 1989; Ge and Garven, 1989; Goff and Williams, 1987; Harrison and Summa, 1991; Lloyd and Jacobson, 1987; Oliver, 1986, 1992; Torgerson, 1990; T6th, 1978, 1980; Verweij, 1990). A large-scale groundwater flow system in a sedimentary basin can be described by the threedimensional pattern of groundwater flow in combination with the physicochemical characteristics of the groundwater. Different types of groundwater flow system and different parts of a single groundwater flow system are associated with characteristic physico-chemical features. This is because the mass transport of chemical compounds, the transport of heat, the deformation of the solid part of the subsurface and the flow of groundwater are coupled processes (Chapter 1).The groundwater flow pattern, i.e. the directions and

24

Chapter 2

velocities of the groundwater in a basin, results from the combined influence of the different forces driving groundwater flow (mechanical, thermal, chemical and electrical driving forces; Section 1.3) and the subsurface distribution of hydraulic conductivities. The main classification criterion for large-scale groundwater flow systems is the dominating driving force or forces for groundwater flow. The forces inducing basin-wide groundwater flow systems are principally controlled by the following processes: - sedimentation in a subsiding sedimentary basin - introduction of heat into a basin - tectonic processes acting on a basin - infiltration of meteoric water in a subaerial basin. Each process can be associated with a particular type or types of groundwater flow system. The characteristics of a groundwater flow system are also controlled by the subsurface permeability distribution. The subsurface permeability distribution a t a certain time during the evolution of a sedimentary basin is given by the hydrogeological framework of the basin at t h a t time. This framework is characterized by the distribution, interconnectivity, thickness and dip of porous and permeable hydrogeological units (aquifers/potential carrier-reservoir rocks, e.g. sands, sandstones, carbonates, fractured rocks) and poorly permeable hydrogeological units (aquitardslpotential barrier rocks, e.g. shales, evaporites) (Figure 2. l), and by the location of geological structures and tectonic elements of importance for groundwater flow, e.g. permeable or impermeable faults, unconfomities. The hydrogeological framework of a basin is determined by the original nature of its sedimentary fill and the syn- and postdepositional mechanical, thermal and chemical deformations of the sediments. Similar types of sedimentary basin can be expected t o show corresponding hydrogeological frameworks. Processes like subsidence, heat flow and style of deformation of a basin greatly influence the main driving forces for groundwater flow. A certain type of sedimentary basin, associated with a particular history of subsidence, heat flow and deformation, may thus be related t o a particular hydrogeological framework and to a particular dominating driving force or particular evolution of different dominating driving forces for groundwater flow. The main large-scale groundwater flow systems that may develop during the different stages of evolution of a sedimentary basin are described in Sections 2.1 to 2.3.These sections also present some examples of the relation between a basin type and type of groundwater flow system. Section 2.4 gives an overview of local groundwater flow systems of interest in petroleum-related studies. When the characteristics of a groundwater flow system are adjusted to the prevailing boundary conditions and remain constant in a sedimentary basin during a certain period, the groundwater flow system is said to be in steady state. Different groundwater flow systems may coexist and interact in the same

Groundwater flow in sedimentary basins

25 East

west

upperaquifer

Deep-basin brine aauife

Shelf limestone and chert Ordovician

Lower Paleozoic carbonate aquifer

aquitad

Shelf dolomite

Shallowmarine('?) sandstone

Lower Paleozoic sandstone aquifer

Figure 2.1 Generalized lithostratigraphic units and corresponding hydrogeological units of the Palo Duro Basin, USA (modified after Bassett and Bentley, 1982. Reprinted by permission of Elsevier Science Publishers BV).

Chapter 2

26

sedimentary basin (Section 2.5). During the different stages of evolution of a sedimentary basin, different groundwater flow systems will develop. While the characteristics of the groundwater flow system change, the groundwater flow system is in unsteady state. Under unsteady state conditions relict groundwater flow systems may exist in the basin.

2.1 Groundwater flow in actively filling and subsiding basins 2.1.1 Driving forces The continued sedimentation in a subsiding basin is the overall driving force for the large-scale groundwater flow system in the basin. The hydrogeological framework of the basin strongly influences the actual physical characteristics of this basin-wide burial-induced groundwater flow system, such as the distribution of groundwater potentials and pressures and the directions and velocities of groundwater flow. Both the overall driving force for groundwater flow and the hydrogeological framework are time-dependent in an actively filling and subsiding basin. The groundwater flow at a certain time during the basin’s evolution can be described by the equations for unsteady state groundwater flow given in Section 1.3. Assuming that hydrostatic conditions prevail in a n isothermal and isochemical basin, the net force acting on a unit mass of water is zero at any point in the basin and (Section 1.1) e,=-grad

+w=Z-

grad Pw

=o

(2.1)

Pw

Hence,

The increase of groundwater pressure with depth (grad p,) follows the hydrostatic pressure gradient, which is numerically equal to p,g (Figure 2.2)) i.e. the hydrostatic pressure gradient varies with groundwater density. The vertical normal component of total stress (az)caused by the weight of the overlying water-saturated rock at a certain depth in the basin is borne by the solid matrix of the porous subsurface ( 0 , ) and by the pressure of the groundwater in the pores (p,):

Groundwater flow in sedimentary basins

27

The increase in ozwith depth is numerically equal to g { p s + ps (1- n)) and is known as the lithostatic gradient (grad o, = 23 MPa/km). Sedimentation in the basin results in an increase in the vertical component of total stress (do,) at that depth, which initially affects only the groundwater pressure (e.g. Bayer, 1989),i.e. do, = dp, creating a superhydrostatic pressure of the groundwater (also known as overpressure, excess pressure , supernormal or abnormally high pressure of the groundwater). This pressure increase, dp, is caused by the weight of both the water and the solid rock of the deposited sediments. In a permeable subsurface, the initial change in groundwater potential will induce a flow of groundwater until the groundwater pressure has returned to the hydrostatic pressure for the depth in question, i.e. until the groundwater pressure increase caused by sedimentation reflects only the weight of the water in the deposited sediments. The dissipation of the superhydrostatic pressure of the groundwater leads to an increase in effective stress and consequently to a reduction in the volume of the water-saturated rock. Hence, the process of mechanical compaction of the water-saturated sediments caused by an increase in the gravity load of the sediments is time-dependent and is influenced by the rate of increase in total stress resulting from sedimentation and by the rate of dissipation of superhydrostatic pressures of the groundwater (i.e. the rate of groundwater flow out of the sediments as controlled by the permeability of the sediments and the viscosity of the groundwater). In a sedimentary basin, both the groundwater pressure and temperature increase with depth: increasing pressure tends t o reduce the volume of a given weight of water and increasing temperature tends t o increase its volume. The effect of water expansion with increasing temperature is more pronounced, resulting in water expanding the deeper it is buried. This aquathermal effect was first identified by Barker (1972). The temperature-induced increase in depth

fresh water: p , - 1000 k g / m 3 p, g 10,000 Pa/m

-

brine:

pz

1000-

2000-

3000-

L

pressure (MPa)

Figure 2.2 Hydrostatic water gradient.

- 1200 kg/m3

28

Chapter 2

groundwater pressure resulting from this aquathermal effect is known as aquathermal pressuring and may occur at all depths. Additional mechanisms of groundwater pressure generation that are induced by the increasing pressure and temperature conditions during the burial of the sedimentary rocks, include the generation of hydrocarbons from organic matter and the resulting volume expansion, and the dehydration of minerals such as smectite, kaolinite and gypsum. The volume increase caused by the generation of hydrocarbon gases, which occurs in the temperature range of 150 - 220 "C (Chapter 3), is especially important. The stability of smectite and mixed layer clays decreases with increasing temperature and depth. Smectite may transform t o illite a t 60 - 100 "C, whereas kaolinite becomes increasingly unstable between 120 - 150 "C(Bj~rlykkeet al., 1989). The dominant mechanism of pressure generation in a filling and subsiding basin seems to be mechanical pressuring of groundwater caused by sedimentary loading (Bethke, 1985, 1986b; England et al., 1987; Harrison and Summa, 1991; Keith and Rimstidt, 1985; Shi and Wang, 1986). Shi and Wang (1986) quantitatively analysed the relative importance of mechanical pressuring versus aquathermal pressuring in the generation of groundwater pressure. They found that under normal geological conditions in sedimentary basins, the mechanical pressuring is the main mechanism in the generation of groundwater pressures. Studies by Bethke (1985, 1986b) agree with Shi and Wang's conclusion. Bethke's (1985) study showed that the aquathermal effect is probably of only limited importance in generating superhydrostatic pressures within slowly subsiding basins (c 1%of the calculated total superhydrostatic groundwater potentials). The aquathermal effect was also found t o be a less important cause of the abnormally high pressures that have developed in a rapidly subsiding shaly basin like the Gulf of Mexico Basin, USA (Bethke, 1986b; Harrison and Summa, 1991). Sharp (1983) showed that under special conditions, such as steep geothermal gradients and very poorly permeable rocks, the effect of aquathermal pressuring of the groundwater may be a significant supplementary process of pressure generation. Locally, at greater depths the groundwater pressure may be influenced by massive gas generation (e.g. Buhrig, 1989). The significance of dehydration of minerals on the generation of groundwater pressures in a sedimentary basin, or in certain parts of a basin, is disputed (e.g. Bethke, 1986b, Colten-Bradley,1987). 2.1.2 Permeability distribution The flow of groundwater in an actively filling basin is greatly influenced by the space- and time-dependent hydraulic conductivity of the subsurface. The permeability of an isotropic porous sediment is related to its porosity and grainsize distribution (Figure 2.3; Chilingarian and Wolf, 1975). Figure 2.3 shows that for the same porosity, coarser-grained well sorted sediments will have greater permeabilities than fine-grained sediments. In general, the

Groundwater flow in sedimentary basins

'0 888 Z 6 LXMJ2 4000

1

1 0

Coarse- and very coarse-grained Coarse- and medium-grained

0 0

A Fineqralned

1

1

1

1

1

1

1

1

2

4

6

8

10

12

14

16

1

1

1

1

1

1

1

1

18 20 22 porosity W)

1

1

24

26

28

30

32

34

36

Figure 2.3 Relationship between porosity and permeability of very coarse-grained, coarsegrained, medium-grained, silty and clayey sandstones (after Chilingar, 1964).

porosity of a sediment decreases with depth in a sedimentary basin (Figure 2.4). The porosity of a sediment decreases with depth of burial, leading t o an associated decrease of its permeability. However, because temperature increases with depth, the groundwater will become less viscous. Under normal geological conditions, the decrease in permeability with depth is greater than the viscosity effect (Sharp, 1983), and the hydraulic conductivity will also decrease with depth of burial. The decline in porosity of a sediment with depth of burial may result from mechanical compaction, intergranular pressure solution and cementation. Porosity loss due t o mechanical compaction or pressure solution is a function of effective stress, i.e. of total stress and groundwater pressure. Cementation by the precipitation of authigenic minerals (quartz, calcite) is influenced by the chemical composition and flow of groundwater. The groundwater flow condition in the basin thus affects all three processes that reduce the porosity of sediments with depth of burial. Mechanical compaction is the dominant process responsible for porosity reduction in argillaceous sediments (Rieke and Chilingarian, 1974). The porosity reduction in coarse-grained sediments like sands may be influenced by mechanical compaction, pressure solution and cementation (Bjorlykke et al.,

Chapter 2

30

1989; Houseknecht, 1987). The porosity of carbonate sediments and rocks is reduced by cementation, recrystallization, and mechanical and chemical compaction (Mazzullo and Chilingarian, 1992).

Compaction o f fine-grained sediments In a homogeneous isotropic basin overlying an impermeable base, the first burial of newly deposited fine-grained rocks will initially result in the compaction of the fine-grained rocks as a commensurate volume of the relatively incompressible groundwater is expelled. Under these compaction equilibrium conditions, the pressure of groundwater is near hydrostatic. The burial-induced flow of groundwater will be directed principally vertically upwards (Figure 2.5; Einsele, 1976, 1977; Magara, 1978). The rearrangement of clay mineral particles during compaction results in a preferred orientation of

10

70

30

tJOROSITY ( % )

Figure 2.4 Porosity-depth curve for sandstones, carbonates and shales (from Harrison and Summa, 1991, American Journal of Science, Vol. 291, Fig. 8. Reprinted by permission of American Journal of Science).

Groundwater flow in sedimentary basins

31

the clay particles because of their characteristic platy shape (Rieke and Chilingarian, 1974).The clay becomes vertically anisotropic during compaction (k, < kh). This vertical anisotropy in combination with overall decreasing permeability with increasing depth will eventually restrict the movement of groundwater in the fine-grained sedimentary rocks. When the expulsion of groundwater can no longer keep pace with subsidence at a certain depth, the pressure of the groundwater cannot dissipate and, consequently, the increase in effective stress slows down. As a result, the compaction of the fine-grained rocks will be delayed and the rocks will become undercompacted for the depth in question. The actual depth at which compaction disequilibrium conditions will occur is influenced by the sedimentation rate and the actual permeability of the fine-grained rocks (see e.g. Hunt, 1979; Rieke and Chilingarian, 1974; Smith, 1971). The reduction of porosity and permeability with increasing porosity 0.L

0.5

0.6

0.7

0.8

ho

height of layer 0

M,

height of mineral substance o f layer 0

r

burial induced groundwater flow as caused by sediment load o f layer ho porosity depth relation

-

relation between Zh and EM hemipelagic carbonaceous silty clay

imentation ( c m A 0 0 0 years)

0

100

200

300 EM (m)

Figure 2.5 Burial-induced vertically upward directed groundwater flow under conditions of compaction equilibrium (modified after Einsele, 1977. Reprinted by permission of Blackwell Scientific Publications Ltd.).

32

Chapter 2

effective stress caused by overburden load also depends on the loading path of the sedimentary rocks (Jones and Addis, 1985; Shi and Wang, 1986). When reburial of sedimentary rocks starts, the rocks will already be of reduced porosity and permeability. During reburial, overpressuring of the groundwater will start at shallower depths. In addition, if the effective stress during reburial is less than the maximum effective stress was in the past, the porosity will change much more slowly with the increasing effective stress during reburial than i t did as a result of mechanical compaction during first burial (Shi and Wang, 1986).

Compaction of coarse-grained sediments The evolution of porosity and permeability of coarse-grained sedimentary rocks during burial may be influenced by mechanical compaction, pressure solution and cementation. This evolution depends on the original mineralogical composition, the sorting and the packing of the sediments and the effective stress and groundwater flow conditions during burial (e.g. Bjerlykke et al., 1989; Harrison, 1990; Houseknecht, 1987). The following examples of the influence of mineralogical composition of coarse-grained sediments (sands) on the evolution of their porosity is taken from Bjerlykke et al. (1989) (Figure 2.6). Quartzarenites and subarkoses are generally less vulnerable to compaction than lithic arkoses and feldspathic litharenites. In sandstones with a high percentage of stable grains (i.e. quartzrich sandstones) the porosity decline resulting from mechanical compaction is relatively slow during shallow to moderate burial (< 3 km). A t greater depths (3 - 4 km) the porosity decline is accelerated because of increased pressure solution and stylolitization. The presence of clay laminae and micaceous layers enhance pressure solution, causing stylolites to form. The porosity of sandstones with more than 20 - 25% unstable grains will be reduced at moderate depths of burial because of the collapse of the grain framework. In contrast t o the fine-grained rocks, the initially permeable coarse-grained rocks allow enough throughflow of groundwater t o either create secondary porosity by leaching chemically unstable minerals (from rock grains or cement) (McDonald and Surdam, 1984) or to reduce porosity by cementation (silica, carbonate, authigenic clay cement). Authigenic illite, montmorillonite and kaolinite may form aggregates which reduce the permeability considerably. The remaining porosity in sandstones with early diagenetic silica or carbonate cement may be preserved relatively better during subsequent burial (Bjwlykke et al., 1989).Secondary porosity may also have a greater preservation potential than primary porosity during subsequent burial (Bj~rlykkeet al., 1989).

Groundwater flow in sedimentary basins Porosiry, 36

33 Estimated primary porosity I

0

1

2

E

Y

c;n. B

3

4

Figure 2.6 Influence of mineralogy of sandstones on porosity-depth gradient based on data from Nagtegaal, 1978 (from ELEMENTS OF PETROLEUM GEOLOGY by Robert C. Selley. Copyright (0)1985 by W.H.Freeman and Company. Reprinted by permission).

Compaction of carbonate sediments and rocks The compaction of carbonates with depth is more complex than that of sandstones, because carbonate minerals (calcite, aragonite, dolomite) are chemically less stable than silica (e.g. Chilingarian et al., 1992). At shallow burial the post-depositional evolution of porosity and permeability of the carbonate sediments is greatly affected by porosity reducing processes, such as mechanical compaction, internaI sedimentation and marine and meteoric cementation, and porosity creating processes including aqueous dissolution of carbonates (Mazzulo and Chilingarian, 1992). The processes of cementation and dissolution are influenced by the groundwater flow conditions in the basin. For example, because carbonate sediments are deposited in a shallow water environment, the sediments may come into contact with meteoric groundwater soon after their deposition. The carbonate sediments are very susceptible to leaching when invaded by acid meteoric water. The leaching creates secondary porosity. Secondary porosity may also be created by dolomitization in the mixing

34

Chapter 2

zone between meteoric and synsedimentary marine groundwater. Lithification of carbonate sediments through reprecipitation of the carbonate minerals and dolomitization may occur already during shallow burial (e.g. Chilingarian and Wolf, 1975). During deeper burial of newly deposited carbonate sediments, the primary and secondary porosity is decreased by cementation and chemical compaction. A t these deeper burial depths pressure solution causes the sedimentary grains to dissolve and cement, and stylolites to form. Stylolites may start to form at depths of 1 t o 2 km (Bj~rlykke,1989). Early formed carbonate cement may hamper later pressure solution, i.e. carbonate sediments which have been subject t o relatively early cementation may retain their remaining porosity better with depth (Bj~rlykke,1989). Aqueous dissolution of carbonates may also create secondary porosity in carbonate rocks at deeper burial. The complex evolution of porosity in carbonate sediments and rocks is reflected in the extreme lateral and vertical heterogeneity of carbonate rocks (Mazzullo and Chilingarian, 1992). 2.1.3 Burial-induced groundwater flow system The combined result of the time-dependent processes of groundwater pressure generation and dissipation determine the groundwater pressure distribution and the other associated characteristics of the burial-induced groundwater flow system at a certain moment in an actively filling and subsiding basin. The groundwater pressures in a filling sedimentary basin are generated by the combined effect of the increase in load of the water-saturated sediments and the aquathermal effect, which at greater depths is enhanced by the dehydration of clay minerals and hydrocarbon generation from organic matter. Mechanical pressuring of groundwater as a result of sedimentary loading is probably the dominant mechanism of groundwater pressure generation. In a basin consisting of homogeneous isotropic sedimentary rocks overlying an impermeable base, the burial-induced groundwater flow will be directed principally vertically upwards under compaction equilibrium conditions (Figure 2.5; Einsele, 1976, 1977; Magara, 1978). According to Bonham (1980) this groundwater flow is upward across chrono-stratigraphic units, but downward with reference to the surface of deposition.The velocity of burial-induced groundwater flow will diminish with depth. A homogeneous basin consisting of isotropic fine-grained sedimentary rocks will maintain compaction equilibrium when the sedimentation rate is slow. However, when the sedimentation rate is rapid, the expulsion of the groundwater from the sedimentary rocks at a certain depth can no longer keep pace with subsidence, because of the rapid burial of the rocks and the already reduced permeabilities of the rocks. Under compaction disequilibrium conditions the groundwater is overpressured and the compaction of the sedimentary rocks will be delayed (the

Groundwater flow in sedimentary basins

35

sedimentary rocks will be undercompacted) and consequently the basin may no longer be homogeneous.

No perfectly homogeneous isotropic sedimentary basin exists in nature, though certain parts of existing basins may be considered homogeneous, favouring burial-driven vertical upward flow of groundwater. In general, in an actively filling and subsiding inhomogeneous sedimentary basin consisting of alternating fine-grained and coarse-grained sedimentary rocks, most groundwater tends to move vertically upwards during the earliest burial stages, i.e. in the relatively shallow part of the basin (
As long as the permeable coarse-grained rocks adjacent to overpressured fine-grained rocks in a subsiding basin provide a continuous lateral escape way for the water expelled from the compacting coarse-grained rocks, compaction equilibrium conditions can be maintained and no significant superhydrostatic pressures of the groundwater will develop in the coarse-grained rocks themselves. As shown in the previous section, the porosity and permeability of coarse-grained rocks also decline with depth. A t greater burial depth, the lateral flow through the originally porous and permeable coarse-grained rocks

Chapter 2

9 P Z O 9 P Z O

9 b Z 09 P 1 0 9 P Z 09 P Z 0

Figure 2.7 Pressure-depth relation in thick compacting fine-grained rocks (modified after Magara, 1978. Reprinted by permission of Elsevier Science Publishers BV). 0

4 J W

depth (rn)

0

000 1

1000

oooz

2000

OOOE

3000

0007

1000

000s

5000

0

20

40

60

80

100

120

pressure IMPa)

Figure 2.8 Change of groundwater pressure with depth in a sand-shale sequence (modified after Hunt, 1979. Reprinted by permission of W.H. Freeman and Company).

Groundwater flow in sedimentary basins

37

will become increasingly restricted by this permeability loss and by the increasing heterogeneity of the rocks. Overpressuring of lithic arkoses and feldspathic arkoses probably starts at shallower depths than overpressuring in quartzarenites and subarkoses. Intercalations of clays in the coarse-grained rocks will enhance the occurrence of overpressuring because the clays increase the processes of pressure solution and stylolitization and consequently increase permeability loss and heterogeneity. In addition, during continued sedimentation and subsidence of the basin, differential tectonic movements along faults (growth faults, basin boundary faults) or diapiric movements of salt or mud may disrupt the lateral continuity of the relatively permeable coarse-grained rocks.

Subsystems of burial-induced groundwater flow The basin-wide burial-induced groundwater flow system in a subsiding basin consisting of alternating fine-grained and coarse-grained sedimentary rocks may consist of three interacting subsystems of groundwater flow (Figure 2.9): -

A shallow subsystem, characterized by cross-formational vertical upward flow of groundwater. The groundwater potential increases slightly with depth. The pressure-depth gradient is near hydrostatic t o slightly superhydrostatic (Figure 2.10).

012-

5

:: 5-

0

20 km

670-

I I I

Shallow subsystem of burial-induced groundwater flow: Groundwater flow Is verticalb upwards and cross-formational Intermediatesubsystem of burial-induced groundwater flow: Lateral flow of groundwater is away from the depocentre and focussed along unconformities and through relatively permeable, sandy, silty and limestone units Deep eopressured subsystem of burial-induced roundwater flow: Lateral flow oygroundwater is restricted;vertical upward low of groundwater is focussed along faults and through hydrofractured zones

Figure 2.9 Cross-section showing hypothetical distribution of the three subsystems of burialinduced groundwater flow (geological cross-section of the Viking Graben, North Sea, adapted from Doligez et al., 1987. Reprinted by permission of Graham and Trotman Ltd.).

38

Chapter 2

Shallow subsystem ~

Intermediate

Lithostatic

1

0

20

40

60

100 120 Pressure (MPa)

80

140

160

180

200

Figure 2.10 Characteristic pressure-depth relations in the three subsystems of burial-induced groundwater flow.

An intermediate subsystem, characterized by vertical upward and downward expulsion of water from compacting fine-grained rocks and continuous lateral flow of groundwater through relatively permeable coarsegrained rocks. In this regime there is no cross-formational flow through the fine-grained rocks. The groundwater potential in the fine-grained rocks is higher than that in adjacent coarse-grained rocks. The groundwater pressure in the coarse-grained rocks is superhydrostatic. The groundwater pressure-depth gradient in the coarse-grained rocks is parallel to the hydrostatic gradient, reflecting the lateral flow of groundwater (Figure 2.10). A deep subsystem, characterized by restricted groundwater flow conditions. Groundwater flow from the deep regime is either very slow and continuous o r episodic. The groundwater potential in coarse-grained rocks may be higher than in overlying fine-grained rocks. Significant superhydrostatic pressures prevail in both rock types. The groundwater pressures in the deep regime are in between the gradient of 16 MPakm and the lithostatic gradient (23 MPa/km). Groundwater pressure gradients greater than 16 MPa/km describe hard geopressures (Bethke et al., 1988). The groundwater potentials in the isolated parts of coarse-grained rocks may equalize (Mann and Mackenzie, 1990).

Groundwater flow in sedimentary basins

39

Whether or not all three subsystems of burial-induced groundwater flow occur in a basin and at what depths depends on the same factors that control the distribution of groundwater pressures in the basin, namely the rate of groundwater pressure generation and the hydrogeological framework of the basin. The main factors of influence seem to be the rate of sedimentation and subsidence, the shaliness of the basin, the presence of layers of very poor permeability (evaporites) and the lateral continuity of the hydrogeological units (e.g. Bethke, 198613; Harrison and Summa, 1991; Hunt, 1979; Lerche, 1990; Magara, 1971,1978;Rubey and Hubbert, 1959). With the help of a two-dimensional numerical model of groundwater flow, Bethke (1985) calculated that for an idealized slowly subsiding inhomogeneous basin (sedimentation rate of 0.05 mdyear, subsidence rate of 0.03 mdyear) only small superhydrostatic pressures developed in the basin, suggesting that these basins may not be subject t o overpressuring during their evolution. In such slowly subsiding basins only the shallow subsystem of groundwater flow may develop. Bethke (1986b) studied the origin and distribution of superhydrostatic pressured zones in subsiding sedimentary basins by applying an inverse solution t o a one-dimensional version of the compaction flow equation (Bethke, 19851, which accounts for the effects of aquathermal pressuring and dehydration reactions. Bethke (198613) showed that geopressured zones are likely to form in shaly basins that subside more than about 1 mdyear, but are unlikely to develop in shale-poor basins. Significant superhydrostatic groundwater pressures are unlikely to develop in basins that subside less than 0.1 m d y e a r (Bethke, 198613). Basins with extensive layers of very poor permeability, such as evaporites, probably develop superhydrostatic pressured zones even at relatively slow burial rates (Bethke, 1986b). A continuation study by Bethke and Corbet (19881, in which they calculated onedimensional flow in a compacting basin by applying a nonlinear equation in which, in contrast to Bethke’s earlier study, hydraulic conductivity and specific storage vary with depth, predict that hard geopressures should occur in shaly basins with burial rates of 2 0.5 m d y e a r and near lithostatic pressures will develop when burial rates exceed about 5 d y e a r . The results of Bethke’s (1986b) theoretical study conform with the groundwater flow study of the Gulf of Mexico Basin done by Harrison and Summa (1991). By using a two-dimensional numerical model of groundwater flow in the shaly Gulf of Mexico Basin, Harrison and Summa calculated that sedimentation rates of 0.1 &year will develop moderate superhydrostatic pressures and rates of > 1 m d y e a r will induce groundwater pressures to approach lithostatic gradients. The shallow and intermediate subsystems of burial-induced groundwater flow may develop in shaly basins with moderate subsidence rates (0.1 mm - 1 mdyear). In rapidly subsiding shaly basins (burial rates > 1 mdyear), all three subsystems may occur.

40

Chapter 2

Figure 2.11 Variable depths to the geopressured zone in the Gulf of Mexico Basin, USA, modified from Wallace and others, 1979 by Harrison and Summa, 1991 (after Hamson and Summa, 1991, American Journal of Science, Vol. 291, Fig. 3. Reprinted by permission of American Journal of Science).

The actual depths at which the subsystems occur will differ for different basin types and will vary within a single basin. This can be illustrated by the variable depth t o burial-induced geopressures within, for example, the North Sea Basin (Buhrig, 1989; Cayley, 1987) and within the Gulf of Mexico Basin (Harrison and Summa, 1991; Figure 2.11). Fertl (1976) presents examples of the extremely variable depths of occurrence of geopressured zones for basins around the world. Some of these examples are in actively filling and subsiding basins. The rate of subsidence differs for different types of sedimentary basin. The rate of subsidence of cratonic basins is in the order of 10 to 20 m per million years, and basins in mobile belts (foredeep, intradeep, backdeep, marginal basins and associated troughs) subside at rates in the order of 50 or 100 m per million years or more (Tissot and Welte, 1984). The shaliness of a basin and the continuity of the shale layers depend on the original depositional environment (Figure 2.12). The original porosity, permeability and connectivity of the fine-grained and coarse-grained rocks are

Groundwater flow in sedimentary basins

41

100

\

\ Delta

Deltaic, banier(Zeito)

I

I

I fringe and delta plain

I Distr. channel (Zdto)

m e inet al) 0 560

0

I 0

1600 I

I

I

100

200 L-th

300

2600 n

1500 I

I

400

500

I

600 rn

of shale intercalation

Figure 2.12 Continuity of shale (silt) intercalations as a function of depositional environment (from Weber, 1982, Journal of Petroleum Technology, March 1982, Fig. 2. Copyright (0)1982 by Society of Petroleum Engineers. Reprinted by permission).

related to the genetic type of sedimentary basin. For example, the stratigraphy of cratonic basins is dominated by broad shallow depositional systems. The basins are characterized by a layer-cake stratigraphy with individual lithostratigraphic units sometimes traceable for thousands of kilometres and an intimate interbedding of marine and nonmarine units (Miall, 1990). The source area of the clastic sediments is continental and characterized by the presence of abundant quartz and a paucity of lithic fragments (Miall, 1990). The hydrogeological framework of a cratonic basin is thus characterized by laterally continuous hydrogeological units and a relatively small percentage of poorly permeable shales. The coarse-grained units (quartz-rich sands) probably compact slowly until depths of 3 to 4 kilometres and may provide laterally continuous escape ways for the water expelled from the compacting finegrained rocks. During the slow subsidence of cratonic basins geopressured zones will probably not be created (see also Bethke, 198613). The burial-induced flow of groundwater in a subsiding cratonic basin will belong to the shallow subsystem and possibly in the deeper parts of the basin to the intermediate system. Studies of basins underlying the North American craton confirm this general picture (e.g. Bethke et al., 1991). In contrast, aulacogens do not appear

42

Chapter 2

t o be characterized by any distinctive lithofacies assemblage or sequence. The sediments may be shallow or deep marine, carbonate or clastic, although a transition from nonmarine in the graben stage t o marine in the downwarp stage seems typical (Miall, 1990). The lateral continuity of individual hydrogeological units in an aulacogen will be slight for various reasons including the presence of abundant deep-reaching faults. The faster subsidence rates, greater percentage of fine-grained rocks and poorer lateral continuity of the hydrogeological units, potentially favour the development of all three subsystems of burial-induced groundwater flow. The present-day groundwater pressure conditions in the Viking and Central Grabens of the North Sea Basin (e.g. Buhrig, 1989; Cayley, 1987)indicate the presence of the three subsystems of burial-induced groundwater flow. The main driving force for burial-induced groundwater flow is thought to be mechanical pressuring of the groundwater caused by sedimentary loading. When the sedimentation and subsidence of a basin cease, the groundwater pressures induced by sedimentary loading and the associated groundwater flow system will eventually dissipate. This dissipation may take millions to tens of millions of years in poorly permeable basins (e.g. Lerche, 1990; Neuzil, 1986).

Pattern of burial-induced groundwater flow Different groundwater modelling studies have provided a general insight in the pattern of burial-induced groundwater flow in sedimentary basins (Bethke, 1985; Bethke et al., 1991; Bethke and Marshak, 1990;Harrison and Summa, 1991; Magara, 1978). Magara (1978) presented a fluid-flow model for a compacting sandstone-shale sequence. This model showed that the groundwater moves principally through the more permeable sandstone layers from an area of more loading (thicker deposition) to one of less. In a sedimentary basin consisting of alternating laterally continuous fine-grained and coarse-grained sedimentary rocks, the groundwater below a certain depth will flow through the individual coarse-grained rocks and will be directed from the depocentre(s1of the basin to its edges. The results of later modelling studies of burial-driven flow in inhomogeneous basins confirmed this tendency for groundwater to flow laterally towards the edge of the basin as previously predicted by Magara (Figure 2.13). Bethke’s (1985) studies further showed that the groundwater fluxes along lateral flow paths increase toward the basin edges. According to Bethke, this is because compaction-driven flow is cumulative along a flow path, with the volume flux at a point along the path nearly equal to the rate of pore volume collapse for the entire path up to that point. Bredehoeft et al. (1988) presented field evidence for the existence of burial-induced lateral groundwater flow in the rapidly subsiding South Caspian Basin. The distribution of superhydrostatic pressures in part of the South Caspian Basin, which consists predominantly of sands and shales, was interpreted by Bredehoeft et al. (1988) to indicate the occurrence of a lateral flow of groundwater focussed through the sands, from the basin centre towards its edges (Figure 2.14). The lateral

43

Groundwater flow in sedimentary basins

l

!

I

r

~ (

l r

r

l r

l r

( 1

l

l r

~ '

( ~

'

~

~

~

l

~

max. v,

-0.1997 cm/yr

rnax. vZ =0.0033 cm/yr t=50 M.Y. max. vzm =0.0050 cm/yr

0

0

-

50 kin

max. v,

=0.2060 cm/yr

max. v,

=0.0056 cm/yr

max.

-0.0050 cm/yr

VZm

groundwater velocity vector groundwater velocities a r e shown relative t o the subsiding medium equipotential o f 0.106 MPa

-0.106-

+

subsidence velocity o f the basement relative to fixed elevation

Figure 2.13 Calculated directions and velocities of burial-induced groundwater flow in a subsiding inhomogeneous basin, after 50 and 100 million years of subsidence (after Bethke, 1985, Journal of Geophysical Research, Vol. 9, no. B8, Fig. 5, p. 6822. Copyright by the American Geophysical Union).

groundwater flow pattern in a compacting basin can be related to the variations in thickness of its sedimentary fill, i.e. t o the geometry of the base of the sedimentary fill of the basin. Figure 2.15 shows the groundwater flow patterns for different geometries of simple compacting basins. The classification of the basin geometry types is according to Pratsch (1982). Pratsch's classification is based on the assumptions that the fine-grained and coarse-grained rock units are continuous throughout the basin, the geometry of the interface between the fine-grained and coarse-grained rock units follows the geometry of the basin and that the permeabilities of the individual rock units are constant.

l

Chapter 2

44

4 Stmctures 0Oil and gas fields

-

0

50

lOOkm

A. Location of area 1. I1 and 111 near the Baku Archipelago

6 . Hydraulic head of groundwater in sand units in areas I, I1 and 111

Area II

Area I

Area 111

0 2 4 1

g6

50

8 2 4 6

0

2

4

60

2 4 6 Pressure (km water)

0

2

4

6

0

I

b

k

m

C. Pressure-depth curves for sand and shale units in areas I, I1 and 111 Figure 2.14 Distribution of superhydrostatic pressures of the groundwater in part of the South Caspian Basin near t h e Baku Archipelago, indicating lateral flow of groundwater through sand units from area I11 towards area I (from Bredehoeft e t al., 1988. Reprinted by permission of the American Association of Petroleum Geologists).

The velocities of groundwater flow in actively filling and subsiding basins depend, among other things, on the sedimentation rate in the basin. The burialinduced velocity of groundwater flow has been calculated to be less than 2 m d y e a r during gradual subsidence of the Illinois Basin, USA, in Permian

Groundwater flow in sedimentary basins

4-5

A

a

a p l e circular symmetrical basin No concentration of groundwater flow

b

a p l e circular asymmetrical basin Concentration of groundwater flow towards narrow concave side B o f the basin

E E

c

c

c

C

A

c

Simple elonqate symmetrical basin Concentration o f groundwater flow towards the long flanks A and B o f the basin

d

Simple elonqate asymmetrical basin Concentration o f groundwater flow towards t h e long flanks A and B o f t h e basin

e

Simple elonqate symmetrical curved basin Concentration o f groundwater flow towards concave long flank A o f t h e basin

f

Simple elonqate asymmetrical curved basin Concentration o f groundwater flow towards concave long flank A o f the basin

-

isopach sedimentary f i l l

T

I depocentre of

t h e sedimentary basin

______

*

basin axis burial induced groundwater flow direction

Figure 2.15 Lateral groundwater flow patterns for different geometries of simple compacting basins (classification of basin geometry types according to Pratsch, 1982).

46

Chapter 2

times (average rate of sedimentation near the depocentre = 0.03 m d y e a r ; velocity of groundwater, v, = qdn, is taken relative to the medium) (Bethke et al., 1991). In the Gulf of Mexico Basin, USA, with recent sediment accumulation rates of up t o 2.2 mdyear, the velocities of groundwater flow in large parts of the basin are in the range 0.1 to 0.001 m d y e a r (Harrison and Summa, 1991). In the shallow subsystem of burial-induced groundwater flow in the Gulf of Mexico Basin, the velocities of groundwater flow are a few tens of centimetres per year, while minimum velocities in the order of 5 x m d y e a r are found in the geopressured zone near the basement (Harrison and Summa, 1991). The velocities of groundwater flow i n actively filling and subsiding basins possibly range from fractions of millimetres per year in the deep geopressured subsystem of groundwater flow t o centimetres per year in the shallow subsystem. In theory, there may be no vertical groundwater flow between different coarse-grained rocks below a certain depth in a simple compacting basin consisting of laterally continuous fine-grained and coarse-grained rocks. In reality, however, facies changes will occur and permeable faults, fracture systems, salt diapirs etc will disrupt the lateral continuity of the individual fine-grained and coarse-grained rocks, thus allowing vertical communication between different coarse-grained rocks, which may result in vertical upward flow of groundwater. In the deep subsystem of burial-induced groundwater flow, geopressured conditions prevail in both the fine-grained and the coarse-grained rocks. Several authors have discussed the formation of fractures (microfractures; hydraulic fractures) in the geopressured zone (Cathles and Smith, 1983; Domenico and Palciauskas, 1979; Du Rouchet, 1981; Etheridge et al., 1984; Nur and Walder, 1990; Palciauskas and Domenico, 1980). When the groundwater pressure reaches its upper limit, i.e. the sum of the least principal stress plus the tensile strength of the medium, the water-saturated rock may fracture and faults may open or reopen (e.g. Du Rouchet, 1981; Price, 1980a). The created fractures have a preferred orientation normal or nearly normal to the least principal stress (Palciauskas and Domenico, 1980). According to Nur and Walder (1990) the natural hydrofracturing leads t o a rapid release of water together with a sudden drop in groundwater pressure. As a result of the decline in groundwater pressure, the hydrofractures will close again. Subsequently the groundwater pressure will increase again in an actively subsiding basin leading t o another cycle of hydrofracturing, release of groundwater and sealing (see Nur and Walder, 1990). In addition to this discontinuous flow of groundwater related to hydrofracturing, episodic flow of groundwater may also occur along faults opened by high superhydrostatic pressures (Price, 1980a) o r along tectonically active faults (Hooper, 1991). According t o Hooper (1991) the hydraulic conductivity along growth faults increases as these faults become more active. This is considered to be caused by

Groundwater flow in sedimentary basins

47

dilation-increased permeability, refracturing of mineral zones and seismic pumping (Hooper, 1991). Since activity of growth faults is related to sediment accumulation rates, the amount of groundwater flowing up faults should be greatest when accumulation rates are fast (Hooper, 1991). During periods when the faults are inactive, probably no vertical upward flow of groundwater occurs and lateral flow of groundwater across the faults may also be restricted. During continued burial, large lateral differences in groundwater potential may build up across the closed faults reflecting restricted flow conditions. The vertical upward escape of groundwater from a deep geopressured subsystem of groundwater flow may occur as a periodic flow of groundwater focussed along distinct vertical pathways (faults, along salt diapirs) or directed through a hydrofractured zone in the upper poorly permeable part of the geopressured system (i.e. a zone of seal failure). In a simple compacting basin, local vertically upward groundwater flow will not disturb the general picture of the basin-wide lateral groundwater flow pattern. In a simple inhomogeneous compacting basin, the sedimentary rocks dip towards the centre of the basin: the moving groundwater following the dip directions of the individual coarse-grained rocks therefore also has a vertical component of flow. While flowing from the depocentre to the basin edges, the groundwater will reach ever shallower parts of the basin. Indicators of burial-induced groundwater flow In addition to the groundwater pressure distribution, the burial-induced flow of groundwater is associated with several physical and chemical characteristics of the sedimentary basin. These include the distribution of temperature, salinity and chemical composition of the groundwater, and the distribution of diagenetic minerals in the basin. In the subsurface, heat moves from the centre of the earth outwards through the sedimentary crust into the ocean or atmosphere, where it is lost as radiant energy. The subsurface temperature distribution is influenced by conductive heat transport, which depends on the thermal conductivity and the specific heat properties of the rock matrix and the pore fillers (e.g. water), and by convective heat transport by groundwater flow (Section 1.3.2). The general direction of burial-induced groundwater flow is from the deeper and hotter parts of a sedimentary basin to its shallower and cooler parts. This upwarddirected component of groundwater flow may induce positive temperature anomalies, when the groundwater flow velocities are sufficiently high (Bethke, 19851,i.e. in areas where upward directed groundwater flow is concentrated, such as along the basin edges, along permeable faults and other permeable escape routes. Such thermal effects caused by burial-driven groundwater flow in slowly subsiding basins are probably negligible because of the slow

48

Chapter 2

groundwater flow velocities perpendicular to the hydrostatic isotherms (Bethke, 1985; Cathles and Smith, 1983). In rapidly subsiding basins, the deeper subsystem of burial-induced flow of groundwater may be associated with relatively high temperatures if the rocks are undercompacted. Because pore fillers, such as groundwater, have much smaller thermal conductivities than the rock minerals, the relatively large porosity of undercompacted sedimentary rocks in the geopressured zone reduces the thermal conductivity and therefore raises the geothermal gradient of most rocks (e.g. Hunt, 1979). Concentrated vertical upward flow of groundwater escaping from the high-temperature geopressured zone along e.g. faults or salt diapirs, will induce positive anomalies of temperature, thermal gradient and heat flow at shallower depths in the basin (Bodner and Sharp, 1988; Hooper, 1991; Jensenius and Munksgaard, 1989). The salinity, i.e. the amount of total dissolved solids, of the groundwater in the permeable coarse-grained rocks of both actively filling and subsiding sedimentary basins and stable subaerial basins generally increases with depth at rates ranging from 50-80 t o 300 r n m m (Hunt, 1979; Selley, 1985). Salinities as high as 400,000 mg/l have been observed (Kreitler, 1989). Although, the salinity of groundwater generally increases with depth in a sedimentary basin, there is a wide variation in the actual total content of dissolved solids and chemical composition of the groundwater with depth. The gradual change in chemical characteristics of the groundwater in a clastic basin is influenced by the original chemical composition of the rock and the synsedimentary water, and the increase in solubility of most rock minerals with depth. A t relatively shallow depths ion exchange with clay minerals may play a role, and membrane filtration and the expulsion of ions plus water from compacting fine-grained rocks may increase the salinity of the adjacent coarse-grained rock. A t greater depths, i.e. at increased temperatures (> 80 "C) and assuming near hydrostatic groundwater flow conditions, the groundwater in the coarsegrained rocks will tend t o be in equilibrium with most minerals present (Bj~irlykke, 1989). There is no general agreement as to the origin of the great salinity of the deeper groundwaters, i.e. of the deep basin brines (Na-Cl brines and Na-Ca-C1 brines) (Hanor, 1987b; Kreitler, 1989). Different processes have been proposed. The main ones are (Hanor, 1987b): membrane filtration or reverse osmosis; subsurface infiltration of subaerially produced brines (residual bittern brines); dissolution of evaporite minerals. Several authors have postulated that finegrained rocks (shales) may act as semi-permeable membranes that retard the passage of ions while allowing relatively unrestricted passage of water (Bredehoeft et al. 1963,1982;De Sitter 1947; Graf, 1982).De Sitter (1947)proposed a filtration mechanism t o account for the subsurface increase in groundwater salinity. The fine-grained sedimentary rocks are thought to acquire the property of a semi-permeable membrane by compaction. The process of

Groundwater flow in sedimentay basins

49

membrane filtration requires large volumes of water to pass through the poorly permeable layers in order to create brine concentrations (Kreitler, 1989). In an actively filling and subsiding basin, active cross-formational flow through poorly permeable layers probably only occurs in the shallow subsystem of burial-induced flow of groundwater. In slowly subsiding basins, burial-induced flow of groundwater is unable to cause concentration of brines by membrane filtration (Bethke, 1985). The other two brine-forming processes are restricted to basins in which evaporites have been deposited. The large influence that evaporites may have on the chemical composition of groundwater in sedimentary basins is indicated by Bjorlykke (1989). He states that sedimentary basins along the Atlantic Coast where Mesozoic evaporites occur have chemical groundwater compositions which are essentially different from groundwater compositions in basins north of this area of occurrence of evaporites. The infiltration of bittern brines in the basin is a syngenetic process of brine formation. The location of the brine in the sedimentary basin may change during the hydrodynamic evolution of the basin. Dissolution of the extremely soluble evaporites (e.g. halite) will result in an increase of the groundwater salinity near salt layers and diapirs (e.g. Morton and Land, 1987; Stoessel and Moore, 1983). The subsequent movement of the groundwater of increased salinity through relatively permeable layers or along vertical routes in the shallow and intermediate subsystem of burial-induced groundwater flow may spread the saline water through the basin. In the deep subsystem with restricted groundwater flow conditions, the movement of saline groundwater by diffusion may become important ( B j ~ l y k k eet al. 1988; Ranganathan and Hanor, 1987). The present-day occurrence of high salinities of the groundwater in sedimentary basins is the combined result of the water-rock interactions and groundwater flow conditions that occurred during the evolution of these basins. In addition to the periods of burial-induced flow of groundwater, the periods of meteoric flow may have greatly influenced the present-day salinity distribution in a basin because of their great potential for changing the chemical composition and salinity of the groundwater. The reasons for this include the relatively large groundwater flow velocities and fluxes in a meteoric system (Section 2.3)and the associated greater potential for membrane filtration. In addition to the generally observed increase in salinity of the groundwater in the permeable coarse-grained layers in an actively filling and subsiding basin, the difference between the salinity of groundwater in fine-grained rocks and that of groundwater in the adjacent coarse-grained rocks increases with depth (Dickey, 1988; Hunt, 1979). The groundwater salinities in the coarsegrained rocks exceed those in fine-grained rocks (e.g. Fertl, 1976). In the shallow subsystem of burial-induced groundwater flow, the process of membrane filtration may cause a relative increase in the groundwater salinity of the coarse-grained rocks. In the shallow and intermediate subsystems of burial-induced groundwater flow, both water and dissolved ions may move from the compacting fine-grained rocks into the adjacent coarse-grained rocks.

50

Chapter 2

However, the movement of some water molecules is inhibited by their adsorption on mineral surfaces of the fine-grained rocks (structured water), while the dissolved ions are relatively free to move into the coarse-grained rock, increasing the salinity of its groundwater. As compaction proceeds all the larger pores in the fine-grained rock lose their salts to the coarse-grained rocks, until finally only small pores filled with fresh (structured) water remain (Hinch, 1980). Dehydration of clay minerals at greater depths, i.e. at higher temperatures and pressures causes the groundwater salinity in the finegrained rocks t o decline (e.g. Bjprrlykke, 1989). Many researchers have shown that the salinity of the water expelled from fine-grained rocks decreases with increasing overburden pressure (Fertl, 1976). In the intermediate subsystem of burial-induced groundwater flow, there is no cross-formational flow through the poorly permeable fine-grained rocks, while the permeable nature of the coarse-grained rocks still allows throughflow of groundwater. Groundwater of different origins and chemical compositions may be introduced into the coarsegrained rocks; this in turn also influences the interactions between water and rock. The chemical compositions of groundwater in the coarse-grained rocks in the intermediate subsystem may be extremely variable. In the deep subsystem of burial-induced groundwater flow, the flow of groundwater through both the fine-grained and coarse-grained rocks is restricted. As a consequence, the groundwater in the geopressured zone supplies o r removes hardly any solids in solution except by diffusion. This probably restricts the water-rock interactions to isochemical reactions (Bjprrlykke et al., 1989). Possibly, the increase with depth of the salinity of groundwater in the coarse-grained rocks in the geopressured zone is slowed down, because dissolved solids are no longer expelled by the fine-grained rocks, dissolved solids are not supplied by flowing groundwaters and there is less chemical activity as a result of the restricted flow of groundwater through the coarse-grained rocks. Deviations from these general variations of the groundwater salinity in the different subsystems of burial-induced groundwater flow of an actively filling and subsiding basin can be expected in areas with concentrated flow of groundwater. In a basin-wide burial-induced groundwater flow system, appreciable concentrated upward-directed flow of groundwater, for instance along the basin edges, permeable faults or other vertical escape ways, will induce positive groundwater salinity anomalies in the shallower parts of the basin. The concentrated vertical upward flow of relatively warm, saline and high pressured groundwater may cause diagenetic reactions when this groundwater enters shallower parts of a basin (e.g. Glasmann et al., 1989a, 1989b; Hooper, 1991; Mathieu and Velde, 1989). For instance, a drop in pressure of the upward-flowing groundwater may induce diagenetic reactions, such as calcite and silica cementation (e.g. Harrison, 1990). Illite formation in coarsegrained rocks may be associated with the introduction of groundwater of deeper

Groundwater flow in sedimentary basins

51

origin. Lee et al. (1989) studied the timing and conditions of diagenesis of the Permian Rotliegende sandstone in the southern part of the North Sea Basin using burial histories, petrographic data, WAr ages and 180/160ratios. They interpreted the data from a sample in the Groningen area to indicate a late intense period of illite formation related to a period of groundwater flow along a major fault nearby. Hence, zones with appreciable vertical upward flow of groundwater in a burial-induced groundwater flow system can be characterized by positive pressure, temperature and salinity anomalies and associated diagenetic mineral assemblages.

2.2 Tectonically-induced groundwater flow

Plate-tectonic processes control the evolution of sedimentary basins and consequently influence the evolution of groundwater flow within the basins. In this section tectonically-induced flow of groundwater is restricted to groundwater flow which is related directly to tectonic activity. The influence of the increase in stresses of tectonic origin on the development of superhydrostatic groundwater pressures in a sedimentary basin was recognized more than 30 years ago by Hubbert and Rubey (1959) and Rubey and Hubbert (1959). More recently, Oliver (1986,1990,1992) suggested a causal relationship between plate-tectonic interaction in zones of convergence and large-scale flow of groundwater. The tectonic origin of ancient groundwater flow conditions in zones of plate convergence and continental collision has been demonstrated by several, mainly geochemical, studies (e.g. Dorobek, 1989; Losh, 1989; Roberts, 1991; Vrolijk and Myers, 1990). From geochemical, thermal and structural geological data the present-day occurrence of tectonically-induced flow of groundwater has been inferred to occur at the Barbados Ridge Complex along the detachment zone separating the underthrusting Atlantic Ocean crust and the overthrusting Caribbean plate (Moore et al., 1987, 1988). The occurrence of tectonically-induced flow of groundwater has been proven, but as yet no detailed tectonically-induced groundwater flow system has been defined. In sedimentary basins within the area of influence of tectonic activity, the directions and velocities of groundwater flow will be affected by the magnitude and directions of the tectonic driving force for groundwater flow in combination with the tectonically changed hydrogeological framework of the basin. The tectonic driving force for groundwater flow may interact with other driving forces acting on the groundwater in a particular basin, such as mechanical driving forces caused by sedimentary loading in a filling and subsiding basin (Section 2.1) and the relief of the water table in subaerial basins (Section 2.3).

52

Chapter 2

A direct tectonic driving force for groundwater flow in sedimentary basins at o r near zones of plate convergence is the increase in both vertical and lateral compressive stresses. The increase in lateral compressive stresses at a zone of continental collision may propagate far into plate interiors and may change the intra-plate stress fields at distances of more than 1000 km from the collisional margin (Klein and Barr, 1986; Ziegler, 1987). Kooi et al. (1989) presented a synthetic paleo-stress curve inferred from the foreward modelling of the North Sea Basin stratigraphy. This curve shows an increase in compressive stress of 4 kbar (400 MPa) over a period of approximately 10 million years in the Early Tertiary. The compressive stresses are probably primarily controlled by European-African plate convergence and continental collision. The strong phase of Early Tertiary compression in the North Sea Basin corresponds in timing with the occurrence of strong folding phases in the Alpine domain (Kooi et al., 1989). The Alpine deformation front is more than 800 km away from the North Sea Basin. The increase in lateral compressive stress of 400 MPa/lO million year is significantly larger than the minimal increase in vertical stress necessary to induce geopressured conditions in a sedimentary basin. For instance, Harrison and Summa (1991) calculated for the Gulf of Mexico Basin, USA, that sedimentation rates of 1 mndyear, i.e. 1000 dmillion year corresponding to an increase in vertical stress of approximately 23 MPdmillion year, will induce groundwater pressures to approach lithostatic gradients. From this example, it seems likely that changes in tectonic stresses acting on a sedimentary basin a t a considerable distance from a zone of convergence, may be large enough to change significantly the groundwater pressure condition in the basin. Changing groundwater pressure conditions affect directly the system of groundwater flow in the basin. In addition, the directions of groundwater flow may also be influenced indirectly by the tectonically increasing groundwater pressures because under high superhydrostatic groundwater pressure conditions, the water-saturated rock may fracture and faults may (refopen (Section 2.1) and displacement of the rocks along faults may be facilitated (Hubbert and Rubey, 1959; Rubey and Hubbert, 1959). The fractures and active faults may become the preferred escape routes for the groundwater in a tectonically-induced geopressured zone. A sedimentary basin at o r near a convergent plate margin (e.g. a foreland basin) may be affected by both vertical and lateral compressive stresses. An initial increase in lateral tectonic compression may amplify the subsidence of a foreland basin (Allen and Allen, 19901, affecting the rate of sedimentation in the basin. A burial-induced groundwater flow system and the associated distribution of superhydrostatic pressure can be expected to develop in such an actively filling and subsiding basin. The continued lateral tectonic compression may also directly affect the magnitude and distribution of groundwater pressures. Lateral tectonic compression may readily raise the already superhydrostatic groundwater pressures to lithostatic pressures. The increased groundwater pressures, i.e. the decreased effective stresses may

Groundwater flow in sedimentary basins

53

facilitate faultinglthrusting (Hubbert and Rubey, 1959; Rubey and Hubbert, 1959). The vertical load of thrust sheets emplaced over the foreland basin will further increase the groundwater pressures below the thrust sheets and induce groundwater flow away from the zone of convergence. Several studies suggest that the tectonically-induced flow of groundwater is an episodic and focussed flow of groundwater which is directed away from the area of convergence (Bradbury and Woodwell, 1987;Dorobek, 1989;Duane and De Wit, 1988; Losh, 1989; Moore et al., 1987, 1988; Vrolijk and Myers, 1990). The tectonically-induced flux of groundwater focussed along active faults or available aquifers may be large enough to create geochemical and temperature anomalies in the subsurface (e.g. Moore et al., 1987, 1988;Deming et al., 1990). The episodicity of groundwater flow along faults or basal aquifers in thrust sheets has been related to episodic movement of thrust sheets (e.g. Bradbury and Woodwell, 1987;Moore et al., 1987,1988;Roberts, 1991). Ge and Garven (1989)used numerical modelling to evaluate the role of compressional tectonics in driving regional groundwater flow in a foreland basin in a late period of thrusting and uplift (Figure 2.16). Their model assumed that emplacement of the tectonic loads on the foreland basin platform is instantaneous. Ge and Garven (1989)found that lateral compression and tectonic loading can create significant large-scale flow of groundwater soon after compression of the foreland basin, with flow rates in the order of 0.001 0.01 m per year for thrust sheet loads 1 to 10 km thick. They found that the groundwater flow velocities increase more significantly in the vicinity of the loading area. The flow of groundwater is directed away from the area of loading and most groundwater is focussed into a basal aquifer. The study suggests that cycles of tectonically-induced flow could exist repeatedly during the history of foreland basin thrusting (Ge and Garven, 1989).

-

-

Compression and v8rtlcal loading

Figure 2.16 Conceptual model of a foreland basin in a late period of thrusting and uplift (from Ge and Garven, 1989, Geophysical Monograph 48, Fig. 5, p. 148. Copyright by the American Geophysical Union).

54

Chapter 2

B a s e Tene Marie Galante Basin (Guadeloum)

Barbados Ridge

Atlantic Plain

i: CEPM line CRV 128

Inset 1

(no vertical exaggeration)

A = Accreted sequences D = D&dlement

U = Underthrust sequences

0 = Top Of Oceanic Crust

4

L B 6

Inset 2

Figure 2.17 Generalized cross-section of the northern Barbados Ridge and adjacent Lesser Antilles arc, showing t h e decollement zone separating the underthrusting Atlantic ocean crust and the overthrusting Caribbean plate. Inset 2 shows the upward directions of fluid flow along faults in the Barbados Ridge accretionary prism, along the dbcollement and in the underthrust sediments (modified after Moore e t al., 1987. Reprinted by permission from NATURE vol. 326, p. 786. Copyright (0)1987 Macmillan Magazines Ltd.;and after Moore e t al., 1988 in Geological Society of America Bulletin, Vol. 100, pp 1580 and 1590).

In subduction zones, subduction of water-saturated sedimentary rocks, i.e. continued burial of the rocks and the associated increase in vertical stress and temperature, will induce superhydrostatic pressures in the subducting rocks if groundwater cannot escape fast enough to keep up with the rate of subduction. Near lithostatic pressures have been inferred t o occur along the d6collement zone, i.e. the detachment zone, between subducting and overriding plates (Moore et al., 1987, 1988; Vrolijk and Myers, 1990).The detachment zone appears t o constitute a preferred lateral escape way for the overpressured groundwater in the underthrust sedimentary rocks (Moore et al., 1987, 1988). Vrolijk and Myers (1990) propose the term tectonic aquifer t o characterize the watertransmitting properties of a detachment zone. The adjective ‘tectonic’ signifies the role that deformation along the detachment zone plays in increasing the permeability (Vrolijk and Myers, 1990). At the Barbados Ridge Complex, separate groundwater flow systems appear t o be present in the accretionary wedge of the overthrusting Caribbean plate and the subducting Atlantic plate.

Groundwater flow in sedimentary basins

55

Lateral flow of ‘Atlantic’ groundwater through the detachment zone is preferred to vertical upward flow through the accretionary wedge (Figure 2.17). According to Moore et al. 1987,this may in part be explained by the expected change in stress orientation across the top of the detachment zone (Figure 2.17). The low plunge of the maximum principal stress in the accretionary wedge would discourage the opening of steeply dipping fractures by high groundwater pressures while encouraging flow along gently dipping surfaces (Moore et al., 1987). Flows along both the detachment zone and the faults within the accretionary wedge of the Barbados Ridge Complex are apparently episodic (Moore et al., 1988).

2.3 Groundwater flow in stable subaerial basins

When a sedimentary basin emerges and stabilizes above sea level, infiltrating meteoric water will become the main driving force for the development and maintenance of a regional groundwater flow system, i.e. the gravity-induced cross-formational groundwater flow system (also called topography-induced groundwater flow system). Buoyancy forces may play a role by modifying gravity-induced flow systems. Under certain conditions local flow systems may form within the gravity-induced flow system (Section 2.4). 2.3.1 Gravity-induced groundwater flow system In various papers (T6th, 1962,1963,1970,1978,1979,1980) T6th outlined the theoretical and observed characteristics of gravity-induced groundwater flow in geologically mature drainage basins. According to T6th, the groundwater flow pattern in a geologically mature sedimentary basin (i.e. a tectonically stable and non-compacting basin) is induced by the relief of the water table, which in most cases follows its ground surface topography. The water table represents the surface at which groundwater pressure equals that of the free atmosphere. Given adequate rainfall the water table closely follows the topographic relief and this relief can be considered to generate the differences in the potential energy of the groundwater. The rock framework of a geologically mature basin is hydraulically continuous, i.e. there is no absolute permeability barrier to water flow, and the gravity-induced cross-formational groundwater flow pattern will only be modified by the differences in subsurface permeability (T6th, 1980). In a geologically mature basin, the possible existence of driving forces for groundwater flow other than gravity are considered to be temporary or local (T6th, 1980).

T6th describes the gravity-induced groundwater flow pattern in terms of interdependent flow systems as existing in drainage basins. A drainage basin is a depression of the ground surface, partly or entirely surrounded by

Chapter 2

56

relatively high areas and underlain a t some depth by an effectively impermeable base. A flow system is defined by T6th (1963) as a set of flow lines in which any two flow lines adjacent at one point of the flow region remain adjacent through the whole region; they can be intersected anywhere by an uninterrupted surface across which flow takes place in one direction only. Under steady-state conditions, the groundwater flow system in a homogeneous and isotropic drainage basin with simple ground surface geometry consists of three parts; the area of recharge, mid-line and discharge (Figure 2.18). Meteoric water infiltrates in the upland recharge area and subsequently descends in that area, flows laterally through the area of midline, and finally ascends towards the ground surface in the topographically low discharge area. In the mid-line area, there is no vertical flow. As a consequence, the groundwater potential does not change with depth in the midline area, and the corresponding gradient of groundwater pressure is hydrostatic (Figure 2.19). Below recharge areas the groundwater potential decreases, reflecting the downward flow of groundwater. The corresponding groundwater pressure gradient is subhydrostatic. In discharge areas, the vertical upward flow of groundwater is reflected in increasing groundwater topographic e l e v a t i o n above s t a n d a r d datum

-

mid line

I

line o f equal hydraulic h e a d

20,000 f e e t (6096 m l

standard datumJ

g r o u n d w a t e r f l o w line

Figure 2.18 Cross-section showing theoretical distribution of hydraulic head and gravityinduced groundwater flow pattern in a homogeneous and isotropic drainage basin with simple ground surface geometry (modified after T6th, 1962, Journal of Geophysical Research, Vol. 67, no. 11, Fig. 3, p. 4380. Copyright by the American Geophysical Union).

Groundwater flow in sedimentary basins

57

depth Im)

soperhydrostatic pressures (discharge area) hydrostatic pressures (midline area) subhydrostatic pressures (recharge areal

2000

3000

.

\'

pressure

Figure 2.19 Change of groundwater pressure with depth in different parts of a flow system of a hypothetical homogeneous drainage basin with simple ground surface geometry (modified after Tbth, 1980. Reprinted by permission of the American Association of Petroleum Geologists).

potentials with depth and in superhydrostatic pressure gradients (Figure 2.19). When the geometry of the basin's ground surface is not simple but complex, i.e. local relief is superimposed on the regional slope of the basin, flow systems of three different orders can be distinguished: local, intermediate and regional (Figure 2.20). Each flow system consists of the same three parts as mentioned above with the corresponding descending, lateral and ascending directions of groundwater flow. In a local flow system, the recharge and discharge areas are contiguous. In intermediate and regional flow systems, the recharge and discharge areas are separated by one or more local systems. In regional systems, the groundwater flow path is between the highest upland recharge area and the lowest discharge area of the basin (Figure 2.21). The depth of penetration of the various flow systems in a homogeneous isotropic basin is a function of the ratio of local relief and regional slope (T6th, 1963), and may reach several thousand feet in a homogeneous basin under the effect of local topography of a few tens of feet (T6th, 1980).The intensity of flow in a single flow system decreases with increasing depth and away from the area of mid-line, and near-stagnant conditions exist in the lower corners of the flow field (Figure 2.18). Where two or more flow systems meet or part, the groundwater flow directions may change significantly over the interface between the different flow systems. In the areas between these different flow systems, the groundwater movement will be relatively slow to zero, and the areas are referred to as near stagnant to stagnant (Figure 2.20).

58

Chapter 2

topographic elevation and head o f w a t e r above s t a n d a r d datum in f e e t i m l ,valley b o t t o m

"-3 02,

potential distribution on t h e s u r f a c e o f t h e ,theoretical f l o w reqion

20,000 f e e t (6096 m l C'

--

-_*--

v ... .....

regional slope o f ground s u r f a c e

water divide

s t a n d a r d datum

-.-.-.

boundary b e t w e e n groundwater flow systems

line o f equal hydraulic head I

i n t e r s y s t e m s t a g n a n t zone

2

b o t t o m s t a g n a n t zone

g r o u n d w a t e r f l o w line local groundwater flow system

intermediate groundwater f l o w s y s t e m I I regional g r o u n d w a t e r f l o w s y s t e m

Figure 2.20 Cross-section showing the theoretical distribution of hydraulic head and gravityinduced groundwater flow pattern in a homogeneous and isotropic drainage basin with complex ground surface geometry (modified after T6th, 1970. Reprinted by permission of the National Research Council of Canada).

In nature, the subsurface of a drainage basin will not be isothermal and isochemical, nor will it be isotropic or homogeneous. Temperature and salinity variations in a basin influence the density and viscosity of the groundwater and consequently the direction and velocity of groundwater flow (Section 1.3).The temperature and salinity variations and the anisotropy and inhomogeneity of the subsurface may change the gravity-induced groundwater flow pattern as illustrated in Figures 2.18 and 2.20, but will not change its general character (e.g. Garven and Freeze, 198413;T&h, 1978, 1980).

59

Groundwater flow in sedimentary basins

a

S h p l e circular symmetrical basin No concentration o f groundwater flow

b

S h p l e circular asymmetrical basin Concentration o f groundwater flow towards n a r r o w concave side B o f the basin

I

B

B

c

c

c

c A

A

c

Simple elongate symmetrical basin Concentration o f groundwater flow t o w a r d s t h e long f l a n k s A and B o f t h e basin

d

Simple elonqate asymmetrical basin Concentration o f groundwater flow t o w a r d s t h e long f l a n k s A and B o f t h e basin

I

I

c

c c

___

J,,I,p,E e , " , , y ~ , , I I , I I E , , I ~ . . L L " ,

1s"

Y--III

Concentration o f groundwater flow towards concave long flank A o f t h e basin

1

I

area o f recharge

,

-",,,p,': _ _

_

~ , " " , j ~ , C

~

'-',""""'ILOL

L",

.LY

- 1 - . . 1

Concentration of groundwater flow towards concave long flank A o f the basin

g r a v i t y induced g r o u n d w a t e r f l o w direction

ground surface geometry (ground surface geometry types patterned after basin geometry types given by Pratsch, 1982).

Chapter 2 elevation above datum in f e e t Im)

feet m)

(-1219) *

c'

-

regional slope of ground surface

___-----line K , ,K,,Kj

30 miles (68 km)

o f equal hydraulic head

groundwater flow line relative hydraulic conductivities

(1219)

Discharge area

6000

(1829) (2438)

8ooo{ Pressure

...-.--.. Calculated pressures in low permeabilitylayer Figure 2.22 Distribution of hydraulic head and gravity-induced groundwater flow pattern, and change of groundwater pressure with depth in different parts of the flow system in a hypothetical inhomogeneous drainage basin with a n areally extensive poorly permeable Iayer and simple ground surface geometry (modified after T6th, 1980. Reprinted by permission of the American Association of Petroleum Geologists).

Groundwater flow in sedimentary basins

61

The modifying influence of the subsurface permeability distribution, as studied by theoretical models (Freeze and Witherspoon, 1967; Garven, 1989; Garven and Freeze, 1984a,b;T6th, 1962,1963,1978)indicate that Layers of poor permeability may cause large losses of energy (Figure 2.22). Figure 2.22 shows the pressure-depth curves for an inhomogeneous drainage basin with an areally extensive poorly permeable layer and simple ground surface topography. The groundwater in the poorly permeable layer and basal aquifer is relatively more underpressured in the recharge area and more overpressured in the discharge area. I n a n inhomogeneous drainage basin with laterally extensive hydrogeological units, the flow of groundwater is essentially lateral in the aquifers (Figure 2.22). Vertical flow of groundwater is more widespread across the poorly permeable layer than in the aquifer. In a n inhomogeneous drainage basin with laterally extensive hydrogeological units, the regional flow tends to be focussed into units of relatively good permeability (Figure 2.23). The degree of focussing is controlled by the permeability contrast between the very permeable units and the surrounding hydrogeological units (Garven and Freeze, 1984b). Garven and Freeze (1984b) calculated that specific discharge rates on the order of 1to 10 m3/m2/yearare possible in basin aquifers.

0.1 s

0 0

0.1s

0.2s

0.3s

0.4s

0.5s

0.6s

0.7s

0.8s

0.9s

S

0

0.1s

0.2s

0.3s

0.4s

0.5s

0.6s

0.7s

0.8s

0.9s

S

0.1 s

0

Figure 2.23 Cross-sections showing the theoretical distribution of hydraulic head and gravity-induced groundwater flow pattern in two inhomogeneous drainage basins with laterally extensive hydrogeological units and a complex ground surface geometry (after Freeze and Witherspoon, 1967, Water Resources Research, Vol. 3, no. 2, Fig. 3, p. 628. Copyright by the American Geophysical Union).

M

Chapter 2

0.1

s 0 0

0:l S

0:2 S

0:3S

014 S

0:5 S

016 S

0:7S

OhS

0:9 S

S

0

0.1s

0.2s

0.3s

0.4s

0.5s

0.6s

0.7s

0.6s

0.9s

S

0.2 s

Figure 2.24 Cross-sections showing the theoretical effect of a partial aquifer of relatively good permeability on the distribution of hydraulic head and gravity-induced groundwater flow pattern in two drainage basins (after Freeze and Witherspoon, 1967, Water Resources Research, Vol. 3, no. 2, Fig. 4, p. 629. Copyright by the American Geophysical Union).

-

Lateral variations in permeability, caused by e.g. facies changes unconformities, faults, can profoundly affect the gravity-induced groundwater flow system (Figure 2.241, which in some cases can lead t o the creation of local flow systems (Garven and Freeze, 1984b).

Numerous field examples of regional gravity-induced groundwater flow systems as compiled for example from literature by T6th (1980) confirm the existence of hydraulic continuity i.e. of cross-formational flow, in geologically mature drainage basins. Field evidence from actual cross-formational flow through poorly permeable layers is rare. Alexander et al. (1987) present an example of measurements of head and chemical composition of groundwater in argillaceous formations in the middle Thames Valley area, UK, which are consistent with the concept of cross-formational flow. The theoretically determined influence of laterally extensive hydrogeological units of different permeability on the gravity-induced groundwater flow and associated groundwater potential and pressure distributions in sedimentary basins is confirmed by field observations. For example, regional underpressuring of groundwater in Mesozoic and Paleozoic rocks in the Denver Basin, USA (Figure 2.25, Belitz and Bredehoeft, 1988) and in the Deep Basin Brine aquifer in the Palo Duro Basin, Texas, USA (Senger and Fogg, 1987) were shown to result from steady-state gravity-induced groundwater flow

Groundwater flow in sedimentary basins

0

Pressure (MPa) 10 20

30

-z 5

i

.

+

Figure 2.25 Subhydrostatic groundwater pressures in Cretaceous D and J sandstones in northeastern Colorado and Nebraska panhandle USA (after Belitz and Bredehoeft, 1988. Reprinted by permission of the American Association of Petroleum Geologists).

in the basins and the presence of poorly permeable units (Cretaceous shales and Permian evaporites, respectively), which hydraulically isolate these underpressured deep aquifers from the recharge zones (compare with Figure 2.22). Although poorly permeable units cause a large downward loss of groundwater potential, it has been shown that vertical leakage, i.e. crossformational flow, through such units on a basin-wide scale can contribute significantly to the total groundwater flow in the system (Bredehoeft et al., 1983; Senger and Fogg, 1987). The focussing of gravity-induced groundwater flow into regionally extensive aquifers has been observed in e.g. the Denver (Belitz and BredehoeR, 1988), Palo Duro (Senger and Fogg, 1987) and Kennedy Basins, USA, (Gosnold, 1990) and in sedimentary basins in the UK (Downing et al., 1987).

Indicators of gravity-induced groundwater flow Different physical and chemical phenomena are considered to be associated with regional gravity-induced groundwater flow (e.g. T6th, 1972, 1980). These phenomena may be apparent in the subsurface (e.g. the distribution of pressure, temperature, salinity] geochemical characteristics of groundwater; the distribution of diagenetic minerals) or at the ground surface (e.g. moisture conditions). Under isochemical and isothermal conditions in a stable drainage basin, groundwater moves in the direction of decreasing groundwater

64

Chapter 2

A.

r

Temperature estimate (contours“c)

s.Ll

2000 m

-2000

m

0

B.

10

20

30

40

Distance (km) Temperature anomaly (contours“c)

50

60

70

80

DR Duchesne River Formation

Uinta Formation

Green River Formation

Wasatch Formation

Figure 2.26 Temperatures and temperature anomalies along a characteristic cross-section in the Uinta Basin, USA (after Willet and Chapman, 1987. Reprinted by permission of Editions Technip; and Willet and Chapman, 1989, Geophysical Monograph 47, Fig. 2, p. 31. Copyright by the American Geophysical Union). 2.26a Temperatures estimated from local formation gradients. 2.26b Temperature anomalies calculated from t h e estimated temperatures in Figure 2.28a by removing a constant regional temperature gradient of 25 ‘Ckm. 2 . 2 6 ~ Temperature anomalies calculated by modelling conductive heat transport and advective h e a t transport by gravity-induced groundwater flow through the Duchesne River Formation and the Upper Uinta Formation.

Groundwater flow in sedimentary basins

Rocky Mountains

Interior plains Foothills

major regional drainage basin

regional

regional lateral fiow

dsChafQ8

’

r -

local

Recharge area

local

local

Discharge area

Figure 2.27 Schematic model of the relation between cross-formational gravity-induced groundwater flow and changes in temperature and heat flow with depth in Alberta, Canada (after Majorowicz et al., 1985. Reprinted with permission from Journal of Geodynamics 4, Fig. 10, p. 280; Copyright, 1985, Pergamon Press Ltd.).

potentials. The groundwater potential distribution and the pressure distribution are direct indicators of the groundwater flow directions. The temperature, salinity and chemical composition (including isotopic composition) of the groundwater change systematically along its flow path from the recharge areas, where meteoric waters infiltrate, to the groundwater discharge areas. Forced convection of heat by flowing groundwater (Section 1.3) can significantIy change the purely conductive subsurface thermal regime, i.e. the temperature distribution and heat flow pattern, in a basin. Theoretical studies show that the main effects of a gravity-induced groundwater flow system on the temperature distribution in a basin occur in the recharge and discharge areas

66

Chapter 2

of the system, i.e. in areas of vertical groundwater flow (e.g. Smith and Chapman, 1983; Woodbury and Smith, 1985). The downward flow of infiltrated meteoric water decreases the subsurface temperatures in recharge areas, while the upward flow of groundwater increases the temperatures in discharge areas. Recharge areas are characterized by negative temperature anomalies, relatively low geothermal gradients and low heat flows, and discharge areas by positive temperature anomalies, relatively high geothermal gradients and high heat flows (Figure 2.26). The geothermal gradient and heat flow will increase with depth in recharge areas and decrease with depth in discharge areas (Figure 2.27). These thermal characteristics associated with large-scale gravity-induced groundwater flow have been recognized in numerous basins worldwide, e.g. Western Canada Sedimentary Basin (Garven, 1989; Hitchon, 1984; Jones and Majorowicz, 1987; Majorowicz et al., 1984, 1985); Kennedy, Denver and Williston Basins, USA (Gosnold, 1985,1990; Gosnold and Fischer, 1986), Illinois Basin, USA (Bethke, 1986a1, Michigan Basin, USA (Vugrinovich, 1989), Uinta Basin, USA (Willet and Chapman, 1987, 1989), Hungarian Basin (Afoldi et al., 1985; ErdBlyi, 1985), Rhine Graben, Germany (Person and Garven, 1989, 1992). Alps and Northern Foreland, Switzerland (Bodmer and Rybach, 1985),Liaohe Basin, China (Wang and Xiong, 1989).

Meteoric water has an extremely small content of total dissolved solids, is slightly t o moderately acidic and has a large oxygen content. After infiltration in the recharge area, the change in chemical composition of the groundwater of meteoric origin involves many different types of geochemical reaction, e.g. dissolution and precipitation; oxidation and reduction; adsorption anddesorption; acid-base reactions and complexation (e.g. Hem, 1985). At shallow depths, i.e. at low temperatures, the reaction rate will be slow, and the groundwater may be oversaturated or undersaturated with respect to several minerals. The composition of groundwater is initially influenced by the chemical characteristics of the infiltrating water and the climatic conditions prevailing during infiltration. Subsequently, the concentration and type of ions in the groundwater will be controlled by - the initial chemical composition of the groundwater; - the rock framework and its mineralogy: the distribution, solubility and sorption capacity (ion exchange) of the rock minerals. The soluble components of rocks (halite, gypsum, anhydrite, calcite, dolomite) are of special influence on the composition and salinity of groundwater; - the groundwater flow system, i.e. the groundwater flow velocity and flow path of the groundwater, which determine the residence time of the groundwater, the depth of the flow system and hence the temperature and pressure conditions. The chemical characteristics of groundwater of meteoric origin change systematically in the direction of flow in a gravity-induced groundwater flow system (Bredehoeft e t al., 1982; Collins, 1975; Herczeg et d.,1991; T&h, 1980).The

Groundwater flow in sedimentary basins

67

recently infiltrated meteoric waters at shallow depths in recharge areas have a small content of total dissolved solids. The salinity of the groundwater increases in the direction of flow, i.e. with increasing depth (increasing temperature) and with increasing residence time of the groundwater in the subsurface. The salinity increases with depth and along the flow path, mainly because the solubility of most minerals increases with increasing temperature, the water reacts with the more readily soluble minerals present along its flow path and because of salt filtering by semi-permeable membranes. Hence, the salinity of shallow groundwater in a recharge area of a certain gravity-induced groundwater flow system is less than that of the groundwater in the deeper parts of the system and less than that of the groundwater in the discharge area. In recharge areas, the groundwater wiIl initially have a high oxygen content and will oxidize organic matter and minerals. As a result, the oxygen content of the groundwater will decrease in the direction of flow. Chebotarev (1955) observed that in general the chemical evolution of groundwater of meteoric origin is related t o a distinctive sequence of dominating anions. The dominating anion changes from bicarbonate to sulphate to chlorine in the direction of groundwater flow and with increasing residence time of the groundwater. In addition to changes in the physico-chemical characteristics of the groundwater itself, the infiltrating meteoric water causes chemical and physical changes in the solid rock matrix, e.g. by diagenesis of the sediments, by changing its porosity and permeability and by forming ore deposits (Table 2.2). Diagenetic reactions that occur in a gravity-induced groundwater flow system include the leaching of quartz and chert, alteration of K-feldspar and plagioclase to kaolinite, the dissolution of high Mg-calcite and aragonite, the precipitation of calcite and smectite (Harrison, 1990). Metals leached in trace amounts from rocks near the surface, which are more soluble in an oxidized than in a reduced state, will precipitate at the boundary between oxidizing and reducing groundwater (e.g. uranium, vanadium, Bethke et al., 1988; Bj~rlykke, 1989). Several studies suggest that basin-wide gravity-induced groundwater flow may lead to the genesis of Mississippi Valley-type lead-zinc deposits in groundwater discharge areas (Bethke, 1986a; Bethke and Marshak, 1990; Garven, 1985; Garven and Freeze, 1984a,b; Deming and Nunn, 1991). In a recently uplifted sedimentary basin, or after an increase in water table relief by e.g. a fall in sea level, groundwater of meteoric origin will come into contact with original, probably more saline, groundwater. The meteoric water may dilute the original water in the rocks and dissolve minerals that were stable under originally more saline conditions, changing the porosity and permeability of the rocks. In the zone where nonsaline meteoric waters mix with more saline groundwater, dolomite may be formed in both carbonate and siliciclastic rocks (Harrison, 1990). Domenico and Robbins (1985) indicate that groundwater of meteoric origin may never completely replace the original connate groundwater in a sedimentary basin. Hence, the chemical

Table 2.2 Some of the different kinds of ore deposits whose origin depends in part on flowing groundwater Type of deposit

Example

Type of flow system

Factors contributing to precipitation

Nickel laterite

New Caledonia

Shallow, water table

Weathering and changing E H - ~ Hat the water table

Laterite bauxite

Jamaica

Shallow, water table drainage helped by karst

Accumulation as residual deposit accompanying weathering

Supergene sulfide

Chuquicamate, Chile

Shallow, water table

Weathering and changing EH-PH at the water table

Calcrete uranium

Yeelirrie, Australia

Discharge end of shallow groundwater flow system

Dissolution from source rock, transport, and precipitation due to evaporation and decomplexation

Roll-front uranium

Texas coastal plain

Shallow groundwater

Leaching of ash, transport, and precipitation at redox front

Unconformity-related uranium

Athabasca district Saskatchewan, Canada

Deep groundwater flow related to faulting

Mixing of oxidizing uraniferous and reducing waters

Mississippi Valley type Lead Zinc deposits

Pine Point, Northwest Gravity o r compaction flow Territories, Canada of brines from deep sedimentary basins

Porphyry copper

San Manuel, Kalamazoo, Arizona

Convection in response to intrusion of a stock or dike

Mixing of meteoric and magmatic fluids and cooling

Lode gold deposits

Carlin, Nevada

Fluid convection of meteoric water deep in the crust

Leaching of source rocks, transport and deposition in fractured rocks due to declining temperature

Leaching from sedimentary source rocks, transport, and deposition due to declining temperatures and and possibly changing EH-PH

From: Domenico and Schwartz, 1990; Copyright 0 1990 by John Wiley & Sons, Inc. Reprinted by permission.

Groundwater flow in sedimentary basins

89

characteristics of groundwater and solid rock matrix in part of a gravityinduced groundwater flow system may still reflect the connate groundwater conditions in certain basins, even a long time after steady-state groundwater flow has been reached. At shallow depths in recharge and discharge areas, there is a difference in the ground moisture supply because of the difference in groundwater flow direction. In recharge areas with vertical downward groundwater flow, relatively unmoist conditions can be expected, whereas in discharge areas with vertical upward groundwater flow very moist conditions will prevail. In turn, these differences in moisture supply may produce observable contrasts in the vegetation, erosional features, soil types and surface accumulations of salts (T6th, 1980).

Unsteady-state groundwater flow conditions A present-day regional groundwater flow pattern may not be in steady state. For example, the observed groundwater flow pattern may not be entirely the result of the present-day relief of the water table. The relief of a water table in a tectonically stable subaerial basin may change in time as a result of climatological changes, eustatic sea level changes o r erosion of the ground surface topography. The rate at which changes in the relief of the water table will be reflected entirely in the regional groundwater flow pattern depends on the magnitude of the change in water table relief, the total depth of the groundwater flow system and the hydraulic properties of the subsurface (especially the thickness, lateral continuity and permeability of poorly permeable layers). Considering a geological time-scale, very poorly permeable layers will delay rather than inhibit the transmission of water table changes to the underlying parts of the basin. It may take millions to tens of millions of years for hydraulic heads at depth i n a multi-aquifer system to adjust to changes in head at the ground surface (England and Freeze, 1988;Senger et al., 1987;Tbth, 1978;T6th and Corbet, 1987;T6th and Millar, 1983). Under unsteady-state conditions, the regional groundwater flow pattern in all or part of a sedimentary basin is not entirely the result of the present-day relief of the water table. Different relict groundwater flow patterns reflecting former water table configurations may exist at different depths (e.g. T6th and Corbet, 1987). Besides changing the hydraulic head at the ground surface, erosion may also influence the groundwater pressure conditions by changing the subsurface temperature conditions and the stress conditions caused by erosional unloading. Erosional unloading can induce dilation of poorly permeable units (decompaction). When the unloading is rapid, groundwater flow into the poorly permeable unit may be too slow to accommodate the pore

Chapter 2

70

volume increase and groundwater pressures in the poorly permeable unit may decrease to subhydrostatic values (Neuzil and Pollock, 1983;Neuzil, 1986).T6th and Corbet’s (1987)study in part of the Western Canada Sedimentary Basin shows that erosional unloading may result in extensive regions of subhydrostatic pressures and associated unsteady-state groundwater flow conditions.

2.4 Local groundwater flow systems Two types of local groundwater flow systems may develop in sedimentary basins at depth ranges of interest for studies of hydrocarbon migration and accumulation: flow systems driven by buoyancy (Section 2.4.1) and those driven by osmosis (Section 2.4.2).

2.4.1 Buoyancy-induced groundwater flow system Buoyancy-induced flow of groundwater is driven by density gradients of the groundwater. The density of the groundwater depends on the pressure, temperature and chemical characteristics of the groundwater (Section 1.3.1). Darcy’s equation 1.9 gives the specific discharge for groundwater of varying densities. Equation 1.9 may be rewritten as (e.g. Garven and Freeze, 1984a).

where, Po CLr

PO

h

k

= reference density of the groundwater (ML-3) = pdp = relative dynamic viscosity of the groundwater = reference dynamic viscosity of the groundwater which is defined for

the same pressure, temperature and chemical characteristics as po (ML-IT-’) =&+z POg =-GPog PO

The first term represents the buoyancy force. The buoyancy force and the hydraulic gradient may act simultaneously on the groundwater. However, under certain conditions, the spatial differences in groundwater densities alone may induce a recirculating flow of groundwater (free convection of groundwater). The development of buoyancy-driven convection cells in sedimentary basins with normal geothermal gradients has been inferred to account for the volumes of groundwater necessary t o explain observed diagenetic characteristics of sedimentary rocks (e.g. Wood and Hewett, 1982;

Groundwater flow in sedimentary basins

71

Davis et al., 1985; Rabinowicz et al., 1985; Haszeldine et al., 1984; Gerretsen et al., 1991) and to explain observed chemical characteristics of groundwater around salt domes (e.g. Hanor, 1987a; Ranganathan and Hanor, 1988).

Free thermal convection The increasing temperatures with depth in a sedimentary basin cause a thermal expansion and hence a decrease in density of the groundwater with depth. This vertical density stratification may induce free convection of the groundwater if the critical Rayleigh number (R, = 40) is exceeded (e.g. Wood and Hewett, 1982).

where, k g aTw (PC),

AT P W

KTm

= permeability of the isotropic porous medium = acceleration due to gravity = volumetric thermal expansion coefficient of the groundwater = heat capacity of the groundwater = temperature difference over a vertical distance Az of the porous medium = dynamic viscosity of the groundwater = thermal conductivity of the water-saturated porous medium

Bethke (1989) calculated that a 100-m thick isotropic water-saturated permeable unit under a normal geothermal gradient requires a permeability of about 2 x 10-12 m2 (= 2D) t o satisfy the Rayleigh criterion; and a kilometre thick unit requires a permeability of about 2 x 10-14 m2 (20mD). Vertical anisotropy of a hydrogeological unit, caused by e.g. intercalations of poorly permeable layers (shales) in an otherwise homogeneous isotropic unit, increases the stability of a thermal stratification as compared with a corresponding isotropic unit of the same horizontal permeability (Bjorlykke et al., 1988; Bethke, 1989). The critical Rayleigh number is considered t o be a rather restrictive criterion in sedimentary basins, because of the common characteristics of the hydrogeological framework of basins (i.e. the wide range and heterogeneous distribution of permeabilities and thicknesses of hydrogeological units) (Bjgrlykke et al., 1988, 1989; Bethke, 1989). According to Bj~rlykkeet al. (1988, 1989) thermal convection is unlikely t o occur under normal geothermal conditions in sedimentary basins with horizontal hydrogeological units and horizontal isotherms. In basins, or parts of basins, with high geothermal gradients, free convection of groundwater may create an important groundwater flow system (Chapman and Rybach, 1985; Person and Garven, 1989). Figure 2.28 gives an overview of typical heat flow values associated with different types of sedimentary basin as given by Allen and Allen (1990).

Chapter 2

72

EXTENSIONAL BASINS

1 -

Active Ocean ridges and volcanoes

I;:;:-

Approximate global average heat flow

';...: : ! ] T I

:.:.:.I

120

Active (syn-rift) back-arc basins

85

Active (syn-rift) rift or passive margin

(post-rift) rift or passive margin

.. COMPRESSIONAL BASINS

..

1

I

1

Collisionalfoldbelt

70

I AI Ocean trench foreland basin (foothills-margin) 80

40

unrelated to arc magmatism

35

..... STRIKE-SLIP BASiNS Active strike-slip, deep lithosphere involvement 100 Active strike-slip, shallow thin-skinned (crustal) extension only

60 1. BASEMENT

... ..

Precambrian Shield

Oceanic crust (200Myr)

"""

(..A_..

20

40

60

80

I

I

1

I

I

1

mWm-2q

I

I

2

100

120

140

160

I

I

I

1

1

3

180 I

I

4

Heat Flow Units

F i g u r e 2.28 Typical h e a t flows associated w i t h different types o f sedimentary basins (from A l l e n and Allen, 1990. Reprinted by permission o f Blackwell Scientific Publications Ltd.).

73

Groundwater flow in sedimentary basins

c

Gravitational potentiel surface \

Ti

Figure 2.29 Schematic illustration of free thermal convection in sloping parts of a hydrogeological unit with isothermal and impermeable boundaries (after Wood and Hewett, 1982. Reprinted with permission from Geochimica et Cosmochimica Acta, Vol. 46, Copyright 1982, Pergamon Press Ltd.).

For sloping isotherms, and corresponding lateral differences in groundwater densities, free convection of groundwater may occur at any value of the Rayleigh number (Wood and Hewett, 1982)(Figure 2.29). The velocity of groundwater flow in the convection cells is affected by the lateral temperature gradient, the permeability of the hydrogeological unit and the geometry of the unit. Bjerlykke et al. (1988)calculated that for a normal geothermal gradient of 30 ' C h , the velocity of groundwater will be 10 d y e a r in a 10 metre-thick permeable unit with a permeability of 1D for a 15' slope of both the permeable unit and the isotherms. For a 1' slope, the velocity of the groundwater was calculated to diminish to 0.1 d y e a r . Large lateral changes in temperature can be expected to occur around intrusions in sedimentary basins e.g. igneous intrusions and salt diapirs. The free thermal convection of groundwater, as described here, is attributable to temperature-induced density differences of the groundwater only if it is assumed that there are no other driving forces for groundwater flow. This assumption is unlikely t o be met in sedimentary basins. According to Bethke (1989)there has been little work to determine the extent to which free convection persists in the presence of other groundwater flow systems.

Free thermohaline convection In sedimentary basins, the gradient of groundwater density resulting from the change in solubility of minerals with temperature, is very small (Bjerlykke

74

Chapter 2

et al. 1988). The density of groundwater is strongly influenced by the concentration of very soluble salts. Steep density gradients can be expected to occur near evaporites. Differences in groundwater salinity may cause a density flow of groundwater (e.g. salt-water intrusions in coastal aquifers, density flow around salt domes where active halite dissolution is taking place). Free convection of groundwater induced by density differences resulting from the combined influence of salinity and temperature gradients (thermohaline convection) has been studied near salt diapirs (e.g. Hanor, 1987a; Ranganathan and Hanor, 1988; Evans and Nunn, 1989). The calculations of Evans and Nunn (1989) indicate that upward flow of groundwater near the diapir edge is present over most of the vertical extent of the salt dome. This groundwater flow is considered to be caused by viscous drag of brines flowing off the top of the dome and upward buoyant forces caused by the increasing temperature with depth and a salinity inversion caused by preferential dissolution of salt a t the dome crest. The last effect is enhanced by salt diapirism and diminishes after diapirism ceases (Evans and NUM, 1989).

Methanogenic convection Park et al. (1990) suggested an alternative mechanism that may induce free convection in the subsurface: the methanogenesis-driven convection system. By numerically simulating reaction-transport equations, Park et al. (1990) calculated that the generation of methane from kerogen maturation can induce kilometre scale flow in a porous medium because of the density dependence of groundwater on methane concentration. 2.4.2 Osmotically-inducedgroundwater flow The flow of water through a semi-permeable membrane (clay, shale) from water with a small concentration of dissolved solids to water with a greater concentration is called osmosis (e.g. Bredehoeft et al., 1982; Neuzil, 1986). The osmotically-induced flow of water occurs because of a difference in vapour pressure across the membrane (Hinch, 1980). The aqueous activity will be relatively small in water with a relatively large concentration of dissolved solids, because more water molecules are bonded on the dissolved ions (Hinch, 1980). In a sandstone-shale sequence with water of equal chemical concentration, the aqueous activity of the shale water will be less than that of the sandstone-water, because water molecules are adsorped on the large mineral surfaces of the shale (Hinch, 1980). As a consequence, the water salinity differences that may exist in sandstone-shale sequences in the intermediate and deep subsystems of burial-induced groundwater flow may actually be in osmotic equilibrium.

The osmotically-induced flow of water across a semi-permeable membrane can cause superhydrostatic o r subhydrostatic pressures. When the osmotic pressure difference induced by the groundwater at opposite sides of the

Groundwater flow in sedimentary basins

75

membrane is exceeded by an externally applied force, groundwater may flow through the semi-permeable membrane in a direction opposite to the direction of osmotic flow. This reverse osmosis may cause membrane filtration (salt sieving or ultrafiltration). The role of semi-permeable membranes and the associated importance of osmosis in sedimentary basins is disputed (Neuzil, 1986).

2.5 Interaction of groundwater flow systems The four processes controlling the development of groundwater flow systems in sedimentary basins are sedimentation in a subsiding basin, introduction of heat into a basin, tectonic deformation of all or part of a basin and infiltration of meteoric water in a subaerial basin. During subsequent stages of evolution of a sedimentary basin, different processes or combination of processes may dominate the development of a groundwater flow system in the basin. A t a certain time during the evolution of a basin different groundwater flow systems may co-exist and interact. During active sedimentation in a subsiding basin, the burial-induced system of groundwater flow will initially be the main flow system. Local buoyancyinduced groundwater flow systems may develop in certain basins, e.g. in rift basins with high heat flow and in basins with magmatic intrusions, while in e.g. foreland basins tectonic driving forces may influence the burial-induced groundwater flow. In general, when the subsiding basin is surrounded by areas of high topographic relief, o r when part of the basin has emerged and stabilized above sea level, the regional groundwater flow system for the entire basin is determined principally by the interaction of the burial- and gravity-induced groundwater flow systems. In a simple subsiding and filling sedimentary basin that is surrounded by areas of high topographic relief, the burial-induced flow of groundwater is directed radially outwards from the basin’s depocentre towards its edges, where it will meet the oppositely directed gravity-induced groundwater flow. The position of the interface between the two groundwater flow systems is determined by the permeability distribution in the subsurface and the magnitude and directions of the driving forces for the burial- and gravity-induced flows. Bethke et al. (1988) and Harrison and Summa (1991) modelled the interaction of burial- and gravity-induced flow systems during the evolution of the Gulf of Mexico Basin, USA. They showed that the present-day gravity-induced groundwater flow system reaches depths of 2 km and extends tens of kilometres into offshore strata in the rapidly subsiding and filling Gulf of Mexico Basin. Changing rates of sedimentation and eustatic rises and falls

Chapter 2

76

in sea level were found t o be important in shifting the interface between the gravity- and burial-induced groundwater flow systems. Figure 2.30 shows the distribution of the gravity-induced system of groundwater flow in the Gulf of Mexico Basin during Miocene times and the present-day, as calculated by Harrison and Summa (1991). In the Miocene, meteoric water may have penetrated deeper into the basin in comparison with the present-day situation, because the opposing burial-induced forces were smaller during the Miocene (Harrison and Summa, 1991). Figure 2.31 shows the effect of a fall in sea level on the basinward extension of the gravity-induced groundwater flow system. N

S

Present day 01-

2-

3-

!i 2:

1 ;09-

10

Miocene

0

so

lWkm

Gravity-induced groundwater flow system Burial-induced groundwater flow system Vmax Maximum velocity of groundwater flow Figure 2.30 Calculated distribution of gravity- and burial-induced groundwater flow systems in the Gulf of Mexico Basin for present-day and Miocene times (after Harrison and Summa, 1991, American Journal of Science, Vol. 291, Fig. 25. Reprinted by permission of American Journal of Science).

77

Groundwater flow in sedimentary basins

N

8

200 rn fall in sea level

0

elo-

<:<:

50 l 0 0 k m

Groundwater potential = 10 MPa Groundwater of meteoric origin Increase in basinward extension of groundwater of meteoric origin due to fall in sea level

Figure 2.31 Calculated increase in basinward extension of the gravity-induced groundwater flow system in the Gulf of Mexico Basin resulting from a 200 m fall in sea level during the Oligocene (after Hamson and Summa, 1991, American Journal of Science, Vol. 291, Fig. 26. Reprinted by permission of American Journal of Science).

The evolution of groundwater flow conditions in sedimentary basins may also be influenced by periods of tectonic activity. For example, in foreland basins, the groundwater flow conditions are initially determined by sedimentary loading and tectonic compression. During a later stage of foreland basin development, when the orogenic belt has become aerially exposed, the groundwater flow in the actively filling foreland basin may become influenced by sedimentary and tectonic loading and by infiltration of meteoric water. At this stage of foreland basin development, the gravity-induced flow of groundwater directed from the orogenic zone towards the basin will not be cross-formational because of the tectonically-induced presence of pressure barriers. After emergence of the foreland basin itself, gravity- and tectonicallyinduced flow of groundwater may occur simultaneously in the basin. Ge and Garven (1989) used numerical modelling to investigate the influence of periods of tectonic compression on the hydraulic head distribution and groundwater flow velocities in a gravity-induced system of groundwater flow in a subaerial foreland basin. They calculated that tectonic compression may increase the groundwater flow velocities by 0.001 to 0.01 m per year. The increase in groundwater flow velocity was found to be more significant near the tectonic loading area relative to far field discharge areas. The original general direction of gravity-induced groundwater flow away from the orogen was not affected by the tectonic compression. The tectonic compression seems t o reinforce the

78

Chapter 2

original gravity-induced flow of groundwater. Finally, when tectonic activity has dissipated, cross-formational gravity-induced flow of groundwater will be established in the entire foreland basin. Woodbury and Smith (1985) calculated that in subaerial basins with normal geothermal gradients where gravity-induced flow prevails, thermally induced buoyancy forces modify but do not control the flow system.

2.6 Summary

The driving forces for large-scale groundwater flow in sedimentary basins are mainly controlled by the following processes; sedimentation in a subsiding basin; introduction of heat into a basin; tectonic processes acting on a basin and infiltration of meteoric water in a subaerial basin. The actual characteristics of basin-wide groundwater flow systems are also strongly influenced by the basin's hydrogeological framework. During subsequent stages of evolution of a sedimentary basin, different processes o r combination of processes may dominate the development of a groundwater flow system in the basin. A t a certain time during the evolution of a basin different groundwater flow systems may co-exist and interact. Sedimentation in a subsiding basin leads t o the development of the burialinduced groundwater flow system. The groundwater flow results from the combined influence of the increase in sedimentary load and the aquathermal effects and at greater depths, also from the dehydration of clay minerals and hydrocarbon generation from organic matter. Sedimentary loading and the associated mechanical pressuring of the groundwater is the dominant mechanism inducing flow of groundwater. Three interacting subsystems of burial-induced groundwater flow can be recognized: the shallow, intermediate and deep subsystem. The shallow subsystem is characterized by crossformational vertical upward flow of groundwater. The intermediate subsystem is characterized by vertical upward and downward expulsion of water from compacting fine-grained rocks and continuous lateral flow of groundwater through relatively permeable coarse-grained rocks. The lateral flow of groundwater is directed from the depocentre of the basin towards its edges. The deep subsystem is characterized by restricted groundwater flow conditions. Groundwater flow from the deep geopressured subsystem is either very slow and continuous or is episodic and focussed along distinct vertical pathways (faults, along salt diapirs) or through a hydrofractured zone. The shallow and intermediate subsystems of burial-induced groundwater flow are likely to occur in shale-poor basins and in shaly basins with subsidence rates not exceeding 0.1 - 1 mm per year. In rapidly subsiding shaly basins (burial rates >

Groundwater flow in sedimentary basins

79

1&year) all three subsystems may occur. The velocities of groundwater flow in actively filling and subsiding basins possibly range from fractions of millimetres per year in the deep geopressured subsystem of groundwater flow t o centimetres per year in the shallow subsystem. Zones with appreciable concentrated upward-directed flow (along basin edges, faults, salt diapirs) are characterized by positive pressure, temperature and salinity anomalies and associated diagenetic mineral assemblages.

The tectonically-induced flow of groundwater has been causally related t o the plate-tectonic interaction in zones of convergence and continental collision. The direct tectonic driving force for groundwater flow in sedimentary basins at or near zones of plate convergence and continental collision is the increase in both vertical and lateral compressive stress. Tectonically-induced flow of groundwater probably occurs as an episodic and focussed flow of groundwater, which is directed away from the area of convergence. The tectonically-induced flux of groundwater focussed along active faults or available permeable hydrogeological units may be large enough to create geochemical and temperature anomalies in the subsurface. Infiltration of meteoric water is the driving force for the development and maintenance of the gravity-induced cross-formational groundwater flow system in stable subaerial basins. The gravity-induced groundwater flow is distributed into regionally unconfined flow systems, each consisting of a recharge area, an intermediate area and a discharge area, where the directions of flow are descending, lateral and ascending, respectively. The flow systems are induced by and adjusted to the relief of the water table, which follows the ground surface relief given adequate rainfall, and are modified by permeability differences in the rock framework. Under steady-state conditions, the depth of penetration of each gravity-induced flow system in a homogeneous basin is a function of the ratio of local relief and regional slope of the ground surface. The intensity of groundwater flow decreases with increasing depth. Hydrogeological units of poor permeability cause large losses of energy. In an inhomogeneous basin, with laterally extensive hydrogeological units, the regional flow tends t o be focussed into units of relatively good permeability. Specific discharge rates in the order of 1- 10 d y e a r are possible in such units. Different physical and chemical phenomena are considered to be associated with a gravity-induced groundwater flow system. The recharge area of the flow system is characterized, amongst other things, by subhydrostatic pressuredepth gradients, low salinities, high oxygen content, negative temperature anomalies and relatively low geothermal gradients. Typical characteristics of discharge areas are superhydrostatic pressure-depth gradients, relatively high salinities, low t o negligible oxygen content, positive temperature anomalies and relatively high geothermal gradients.

80

Chapter 2

Flow of groundwater driven by osmosis and free thermal and thermohaline convection may occur locally in sedimentary basins. Thermal convection of groundwater can be expected to develop in sedimentary basins with high heat flows o r around magmatic intrusions and salt diapirs. Free thermohaline convection may be induced near evaporites. The possible role of osmosis and associated flow of groundwater in sedimentary basins is disputed.

PART 2

GENERATION, MIGRATION AND ACCUMULATION OF HYDROCARBONS

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83

CHAPTER 3 GENERATION AND EXPULSION OF HYDROCARBONS

Petroleum can be defined as a mixture of natural hydrocarbons (compounds of hydrogen and carbon only) usually with some contaminant non-hydrocarbon compounds (e.g. nitrogen, sulfur, oxygen). Petroleum occurs in the subsurface as semi-solids, liquids (crude oil, gas condensates) or gases (dry and wet gases) or mutual solutions of these. In petroleum industry practice, the terms oil and gas are generally reserved for describing petroleum phases under ground surface conditions of temperature and pressure. Under ground surface conditions of temperature and pressure, oil refers t o liquid phase petroleum containing hydrocarbons with six or more carbon (c6+)atoms, whereas gas refers t o gaseous phase petroleum with less than six carbon atoms (C1- C5). Under subsurface conditions liquid phase petroleum may contain C1 - C5 hydrocarbons in solution (the gas-oil ratio indicates the quantity of C1- C5 hydrocarbons dissolved in the liquid phase) and gaseous phase petroleum may contain c6+ hydrocarbons (the condensate-gas ratio is a measure for the quantity of c g + hydrocarbons dissolved in the gas phase). T h e terms oil and gas are also used to describe the subsurface liquid and gaseous phase petroleum, respectively. Dry gases are natural gases without appreciable content of c g + hydrocarbons, while wet gases do have an appreciable content of cg + hydrocarbons. Rocks that are, may become or have been able to generate migratable petroleum are known as petroleum or hydrocarbon source rocks (Section 3.1). Hydrocarbons originate predominantly from organic matter, as derived from the organic parts of living organisms, which has accumulated and has been preserved in fine-grained sedimentary deposits (Section 3.1.1). An abiogenic origin for hydrocarbons is not considered here. Whether or not part of the preserved organic matter will actually be transformed into petroleum-like compounds depends on the geological evolution of the sedimentary basin and its potential source rocks (Sections 3.1.2 and 3.1.3).The different aspects of the origin of hydrocarbons are treated extensively by Tissot and Welte (1984). The contents of Sections 3.1.1,3.1.2 and 3.1.3 are taken from their work. In the sections in question no further references will be made to these authors.

84

Chapter 3

sealevel

barrier rock

carrier & reservoir rock source rock carrier & reservoir rock basement

secondary migration

h

trapped hydrocarbons

Figure 3.1 Schematic illustration of primary and secondary migration.

Commercial accumulations of oil and gas do not occur in source rocks, but in more coarse-grained and permeable rocks (reservoir rocks) that contain little o r no organic matter. The formation of oil and gas accumulations in reservoir rocks requires some kind of hydrocarbon transport from source rock t o trap positions. This transport is known as hydrocarbon (or petroleum) migration (Figure 3.1).The release of hydrocarbons from organic matter within source rocks and its subsequent movement through these fine-grained rocks and the expulsion from the source rocks towards more permeable rocks (carrier o r reservoir rocks) is called primary migration (Section 3.2). Secondary migration is the movement of hydrocarbons after expulsion from a source rock through carrier and reservoir rocks or fault and fracture systems until an oil o r gas accumulation is formed or the hydrocarbons have escaped into the atmosphere. The term “remigration” refers to any subsequent movement of the accumulated oil or gas.

Generation and expulsion of hydrocarbons

3.1 Origin of natural hydrocarbons 3.1.1 Organic matter Production of organic matter From the Precambrian until the Devonian, the producer of organic matter was marine phytoplankton. Since the Devonian an increasing amount of primary production of organic matter has been contributed by higher terrestrial plants. At present, marine phytoplankton and terrestrial higher pIants are estimated to produce about equal amounts of organic carbon. Quantitatively, the main contributors to organic matter in sediments are phytoplankton, zooplankton, higher plants and bacteria. Chemical composition of organic matter The composition and type of organic matter to be deposited and incorporated in sediments depend on the natural association of phytoplankton, zooplankton, higher plants and bacteria in the depositional environment. As far as their soft parts are concerned, basically all organisms are composed of the same chemical constituents, i.e., proteins, lipids, carbohydrates and, in higher plants, lignins. There is a fundamental difference between the chemical composition of marine planktonic algae and terrestrial higher plants. The organic matter of marine plankton is mainly (50% and more) composed of proteins, a variable amount of lipids (5 to 25%) and generally not more than 40% carbohydrates. Higher terrestrial plants are largely composed of cellulose (30 to 50%) and lignin (15 to 25%). Organic material mainly derived from marine plankton is more of an aliphatic or alicyclic nature (Table 3.1) and reaches hydrogen to carbon ratios of around 1.7 to 1.9. Predominantly land-derived organic matter with high contents of lignin and carbohydrates is more aromatic and has hydrogen t o carbon ratios of around 1.0 to 1.5.

Deposition and preservation of organic matter Sediments rich in organic matter that may become source sediments for petroleum may accumulate in aquatic environments and be preserved wherever there is sufficient supply of organic matter in the form of dead or living particulate organic matter or as dissolved organic matter, reasonably quiet waters and an intermediate rate of sedimentation of fine-grained mineral particles. The supply of organic matter is high along continental margins, because of high primary productivity of coastal water and/or a high input of allochthonous land-derived terrestrial plant material. Favourable conditions for accumulation and preservation of organic matter are found on the continental shelfs in areas of quiet water, such as in lagoons and estuaries, on continental slopes and in deep basins of restricted circulation.

Chapter 3

86

Table 3.1 Classification of organic compounds in terms of their skeletal carbon structure

ALIPHATIC

Open chains, straight or branched, of carbon atoms bonded with single, double or triple bounds o r combinations of them.

ALICYCLIC

Closed o r ring arrangements of carbon atoms with single or multiple bonds.

AROMATIC

A special arrangement of six carbon atoms in a ring with alternate double and single bonds between the carbon atoms. There may be a wide variety of side chains of groups attached to the aromatic ring.

HETEROCYCLIC Closed or ring arrangements of carbon and other atoms such as nitrogen, oxygen and sulfur with single or multiple bonds. The aliphatic hydrocarbons containing only single carbon-carbon bonds are called alkanes (their traditional name is paraffins; alkenes: double bonds; alkynes: triple bonds). Definitions taken from Slabaugh and Parsons (1966)

Organic matter may also be deposited and preserved under favourable nonmarine conditions. Most coals, which consist mainly of detritus from higher terrestrial plants, are formed under non-marine conditions.

3.1.2 Generation of hydrocarbons from organic matter The organic matter incorporated in the fine-grained sediments of a sedimentary basin will be transformed physicochemically during the geological evolution of that sedimentary basin. During and shortly after sedimentation the organic matter is changed by microbial and chemical action. Continued deposition of sediments in a subsiding sedimentary basin results in burial of the previously deposited sediments rich in organic matter; this leads to an increase in temperature according to the prevailing geothermal gradient, and an increase in pressure due to overburden. The original organic matter will not be stable under these new temperature and pressure conditions. Degradation of the organic matter will occur towards a new (thermodynamic) equilibrium. A general scheme of evolution of the organic matter with reference to the stages of hydrocarbon generation is shown in Figure 3.2. The three main stages of evolution of organic matter in sediments upon burial are diagenesis, catagenesis and metagenesis. The evolutionary stages

Generation and expulsion of hydrocarbons

87

can be determined from optical and/or geochemical properties of organic matter. This concept is commonly referred to as the maturity of sedimentary rocks that contain organic matter. The maturity of such a rock is often indicated by its vitrinite reflectance, i.e. the reflectance of finely dispersed small vitrinite (or huminite) particles in reflected light (Figure 3.2). The relationship between vitrinite reflectance and evolutionary stages of organic matter in the rocks (hydrocarbon generation stages) is influenced by burial rates (heating rates) and geothermal histories of the rocks (Leythaeuser et al., 1987a).

Diagenesis Sediments deposited in a sedimentary basin in subaquatic environments, contain large amounts of water, minerals, dead organic matter and numerous

organic matter

-vitrinite relectance 1% in oil1 CH AA

FA HA

L HC N. 5. 0 RO

carbohydrates amino acids fulvic acids humic acids lipids hydrocarbons N. 5. 0 compounds Inon-hydrocarbons1 vitrinite reflectance

Figure 3.2 General scheme of evolution of organic matter from the freshly deposited sediment to the metamorphic zone (after Tissot and Welte, 1984. Reprinted by permission of Springer-Verlag).

Chapter 3

living organisms

I

lignin

I

Carbohydratar

I

Proteins

I

lipids

I

Recent sediment

Principal zone of oil formation

II

Ciscking

Zone o f gas formation

High MW Cracking

Light hydrocarbons

U Carbon residua

Figure 3.3 Sources of hydrocarbons in geological situations, with regard to the evolution of organic matter. Geochemical fossils represent a first source of hydrocarbons in the subsurface (black solid arrows). Degradation of kerogen represents a second source of hydrocarbons (grey dotted arrows) (from Tissot and Welte, 1984. Reprinted by permission of Springer-Verlag).

living micro-organisms. During diagenesis this system tends to approach equilibrium under conditions of shallow burial, and the sediments normally become consolidated. The depth interval concerned is in the order of a few hundred metres, occasionally t o a few thousand metres. During early diagenesis, one of the main agents of transformation of the organic matter is microbial activity. Chemical rearrangements, such as polycondensation and insolubilization, then occur at shallow depths. Diagenesis of organic matter leads from biopolymers (proteins, lipids, carbohydrates and lignins as synthesized by plants and animals) to geopolymers collectively called kerogen

Generation and expulsion of hydrocarbons

.-

$9

(Figure 3.3). Kerogen is the fraction of the organic matter in sedimentary rocks that is neither soluble in aqueous alkaline solvents nor in the common organic solvents, whereas bitumen is soluble in organic solvents (Figure 3.4). Kerogen is a macromolecule made of condensed cyclic nuclei linked by hetero-atomic bonds or aliphatic chains. Three main types of kerogen can be recognized (Figures 3.5): - Type I kerogen. This type is either mainly derived from algal lipids or from organic matter enriched in lipids by microbial activity. The hydrogen to carbon ratio is originally high, and the potential for oil and gas generation is also high. - Type I1 kerogen. This type is usually related t o marine organic matter deposited in a reducing environment with medium to high sulfur content. The hydrogen to carbon ratio and the oil and gas potential are lower than observed for type I kerogen but still very important. - Type I11 kerogen. The organic matter is mostly derived from terrestrial higher plants. The hydrogen to carbon ratio is low, and oil potential is only moderate. This kerogen may still generate abundant gas at greater depths. The oxygen to carbon ratio is comparatively higher than in the other two types of kerogen.

t o t a l rock

minerals

I

t o t a l organic m a t t e r

kerogen

linsolublei

I

I Ir asphaltenes t resins

bitumen fraction /soluble

in

organa solvenfsl

heavy molecules containing C, H, 0, 8, N molecular weight usually over 500

* containing only C, H. usually 4 0 0

Figure 3.4 Composition of disseminated organic matter in ancient sedimentary rocks (after Tissot and Welte, 1984. Reprinted by permission of Springer-Verlag).

Chapter 3

I

,-.I

Vitrinite reflectance

0

03 0

2

1 0

0

4

---

Approximate 150-values of vitrinite reflectance Boundaries of the fleld of keroaen

0

Figure 3.5 General scheme of kerogen evolution from diagenesis t o metagenesis in the Van Krevelen diagram (from Tissot and Welte, 1984. Reprinted by permission of SpringerVerlag).

Residual kerogen is one form of ‘dead carbon’ and has no potential for oil and gas. Besides kerogen, a t the end of diagenesis organic matter comprises a minor amount of free hydrocarbons and related compounds, as synthesized by

Generation and expulsion of hydrocarbons

91

living organisms and preserved with minor alteration. They can be considered as geochemical fossils (Figure 3.3).

Generation of hydrocarbons during diagenesis (Figure 3.2) In young sediments, a t shallow depths, small amounts of hydrocarbons are present (geochemical fossils). The only new hydrocarbon generated is methane. In special cases microbial activity may result in abundant methane generation (biogenic gas). The degradation of kerogen as a function of burial during diagenesis is marked by an important decrease of oxygen and an associated increase of carbon content with increasing depth. Large quantities of carbon dioxide and water and also some heavy hetero-atomic nitrogen, sulfur, oxygen compounds may be produced in relation to oxygen elimination. A certain amount of gas may also be generated, especially from type I11 kerogen. In terms of hydrocarbon exploration, source rocks are considered as immature during diagenesis. Catagenesis (Figure 3.2) During the continued burial of sediments, the increase in temperature results in the thermal degradation of kerogen, which eliminates hydrocarbon chains and cycles. Most of the newly formed hydrocarbons are of medium to low molecular weight. These hydrocarbons are the source of the bulk of crude oils. Catagenesis is the principal stage of oil formation. The corresponding depth range is also referred to as oil window. In addition, catagenesis also corresponds t o the beginning of the cracking stage (i.e. cracking of oil to gas; cracking = breaking of carbon-carbon bonds), which produces wet gas with a rapidly increasing proportion of dry gas. In terms of hydrocarbon exploration, source rocks are considered as being mature during catagenesis. Metagenesis (Figure 3.2) This last stage of evolution of organic matter is reached only at great depths. During metagenesis no significant amounts of hydrocarbons are generated from kerogen, except for some methane. However, large amounts of methane may result from the cracking of previously generated liquid hydrocarbons. The residual kerogen usually consists of two or more carbon atoms per three atoms (hydrogen t o carbon ratio less than 0.5). In terms of hydrocarbon exploration, the stage of metagenesis corresponds t o the dry gas zone.

3.1.3 Generation of hydrocarbons from coal (Figure 3.6) Most coals are remnants of terrestrial higher plants and are formed under non-marine conditions. Following the accumulation of dead plant debris on the ground, the same biochemical (and after burial, geochemical) processes that constitute diagenesis and catagenesis, are initiated. With continued burial, these processes progressively cause coalification of the organic matter t o form the maturational sequence (the successive levels of rank) of peat, brown coal, bituminous (hard) coal and finally anthracite. During coalification,

Chapter 3

92

hydrocarbons of low molecular weight, especially methane, and other volatile non-hydrocarbon compounds, such as carbon dioxide and water, are generated. The main phase of methane generation in coal begins in the range of medium volatile bituminous coal. The formation of volatile compounds during coalification greatly exceeds the storage (absorption) capacity for these products in coal. In addition, heavier non-volatile hydrocarbons are formed. However, in contrast to the large amounts of methane generated, the potential of coals to produce higher molecular weight hydrocarbons is limited. The oil generation potential of coal is determined by its organic constituents, i.e. by its maceral composition (EspitaliB et al., 1991). Main s t a q e s o f e v o l u t i o n

I

Coal Rank USA 119711

~

!!C. -

. .

Lignite Oiagenesis

IBraun-

1

Sub c bituminousB Rg-05

------4 -Iigh volatile B bituminous A

Catagenesis

Med v o l b i t -ow vol bit Rn- 2

Semianthracite Metagenesis

Anth. 4nthracite

R,-l

--

Metamorphism

Yeta-anth.

Anth.

Coal r a n k s are adapted f r o m Vassoevich 1969, 197L. I n t e r n a t i o n a l Handbook o f Coal

P e t r o l o g y , 1971, Hood

Pt

a l . 1975. Stach e t a l . 1975

Figure 3.6 The main stages of evolution of the organic matter in comparison with the successive coal ranks (modified after Tissot and Welte, 1984. Reprinted by permission of Springer-Verlag).

Generation and expulsion of hydrocarbons

93

Chemical changes in coal during its evolution through the different rank stages can be compared with the evolution of various kerogen types. The greatest chemical and evolutionary similarities are observed between coal and type I11 kerogen.

3.1.4 Masses of generated hydrocarbons The total masses of hydrocarbons that can be generated in a source rock, depend on its initial total organic carbon (TOO content, type of organic matter and maturation of the organic matter. The source rock hydrocarbon potential is often expressed relative to the total organic carbon content, the resulting ratio being called hydrogen index. Cooles et al. (1986) use the “petroleum generation index” to indicate the fraction of petroleum-prone organic matter that has transformed into petroleum. This petroleum generation index may vary fiom values close to zero (no generation) for immature source rocks to 1.0 for source rocks which have realized all their petroleum potential. According to Jones R.W.(1980) most of the major oil accumulations of the world originated in source rocks with TOC’s 2 2.5% weight and occasionally with TOC‘s 2 10% weight. Cooles et al. (1986) regard oil-prone source rocks with initial hydrocarbon potentials greater than 0.005 kg of hydrocarbons per kilogram of source rock and average organic carbon contents greater than 1.5% as good source rocks for oil. Studies by Leythaeuser et al. (1987a) showed that rich source rocks that contain type I1 kerogen (with initial hydrogen index values of about 0.7 kg/kg TOC) can generate about 0.5 kg of liquid hydrocarbons per kilogram of organic carbon at the peak phase of oil generation. The modest quality source rocks that contain predominantly type I11 kerogen (with initial hydrogen index values of about 0.3 kgkg TOC) can generate at most 0.2 kg of liquid hydrocarbons per kilogram of organic carbon at the peak phase of oil generation (Leythaeuser et al., 1987a). Higgs (1986) studied the thermal histories and gas generating potentials of a

U.S. Palaeozoic and a German Tertiary coal by laboratory simulation experiments using samples with maturity ranges from 0.4 - 3.0% vitrinite reflectance. The cumulative hydrocarbon yield (measured as methane equivalents) was found to be 170 ml per gram of organic carbon for the Palaeozoic coal (Figure 3.7a) and 225 ml per gram of organic carbon for the Tertiary coal (figure 3.7b). Maturation of the organic matter results in an increase of total volume of organic matter (Ungerer et al., 1983; Duppenbecker et al., 1991). Ungerer et al. (1983) used theoretical calculations to predict volume expansion of organic matter during the evolutionary stages of catagenesis and metagenesis. For the kerogen types I1 and 111, the expansion was calculated not to exceed 15% during catagenesis. A t the metagenesis stage the calculations showed that the volume expansion may reach high to very high values (> 35%).

Chapter 3 400 -

400 7

300

:

-

e 200

3

-

Carbon dioxide

21

4

Carbon dioxide

,0°: 200-

i+

.Q 9

._ 9

._ 0 c

.

100-

5

0

0

,

0

a.

I

.

I

.

(

.

,

1 2 3 4 Vitrinite reflectance

US.Carboniferous coals

Heated at 550 "C for 72 hours 400 7

0 ._

5

g

9 E

Y

9 .Q x

3

405

:1

c

.

Carbon dioxide

300 -

Methane

0 ._ c

Carbon dioxide

100

0

0

4001

Total gas

1 2 3 4 Vitrinite reflectance

200

-

F L

100-

0

8

0 -0

1 2 3 4 Vitrinite reflectance

b. German Tertiary coals

Figure 3.7 a. Cumulative gas yield and rate of gas generation for US Carboniferous coals; b. Cumulative gas yield and rate of gas generation for German Tertiary coals (after Higgs, 1986, Geological Society Special Publication, no. 23, Figs 4, 8, 10 and 11. Reprinted by permission).

3.1.5 Temperature and depth of hydrocarbon generation Quigley et al. (1987; see also Quigley and Mackenzie, 1988) predicted the thermal degradation of kerogen and the thermal cracking of oil to gas from a kinetic model which they had calibrated with geochemical data from source rocks matured in nature and results of laboratory pyrolysis experiments. They used the following classification of kerogen types: inert kerogen, which has no

Generation and expulsion of hydrocarbons

Table 3.2 Temperature ranges of petroleum-forming reactions

Reaction Labile kerogen breakdown Oil to gas cracking Refractory kerogen breakdown

Temperature ("C)

100- 150 150- 190 150-220

From Quigley et al., 1987. Reprinted with permission of Editions Technip.

potential for hydrocarbon generation; labile kerogen, which has potential to generate chiefly oil with some gas; and refractory kerogen, which yields only gas at relatively high maturities. This kerogen classification corresponds to the kerogen types I, I1 and I11 (Section 3.1.2)in the following way: type I kerogen corresponds to a kerogen whose reactive fraction is predominantly labile, type I11 kerogen has a reactive fraction that is chiefly refractory and type I1 kerogen lies between types I and I11 but has more labile than refractory material (Mackenzie and Quigley, 1988).Figure 3.8 shows the calculated degradation of labile and refractory kerogen and oil cracking to gas as a function of maximum temperatures for a range of heating rates. Geological heating rates range mostly between 1 and 10 "C per million years. Within this heating rate range the main zone of labile kerogen breakdown to form oil and some gas is between ca 100 - 150 "C(Table 3.2). Significant gas generation from refractory kerogen occurs between ca 150 - 220 "C and significant thermal cracking of oil to gas from ca 150 - 190 'C. An uplift of a sedimentary basin and its source rock will lower the temperature of the source rock and terminate the generation of hydrocarbons. If the uplifted source rock is later reburied beyond its previous hydrocarbon generative depth (i.e. temperature), a second release of hydrocarbons may occur (Hunt, 1979). The actual depth a t which hydrocarbon generation will occur varies from place to place. It depends on the nature of the original organic matter in the source rock, its burial history and the history of the geothermal gradient. The history of the geothermal gradient, in turn, depends upon the history of regional heat flow and groundwater flow conditions and the history of thermal conductivities of the sedimentary rocks. Several authors recognized the control of hydrodynamic conditions on the process of hydrocarbon generation through their influence on geothermal gradients (e.g. Person and Garven, 1992; Summer and Verosub, 1989; Willet and Chapman, 1987). The geothermal gradients may range from 10 - 80 'C km-l with an average value of about 30 "C

Chapter 3

93

km-1 (e.g.Tissot and Welte, 1984). During shallow burial of the source rocks, dry gas - methane - is the principal hydrocarbon that may be generated. For the principal zone of oil generation at temperatures between 100 and 150 "C and a geothermal gradient of 30 'C km-1, the corresponding burial depths of the oilgenerating source rocks are between 2500 - 3000 m and 4000 - 5000 m.

a

10 labile kerogen concentration

0.0

rate

140

100

year)

180

temperature

("0

temperature

("0

C

160

200

2LQ

temperature i"C)

Figure 3.8 Calculated relative concentrations of a) labile kerogen; b) oil; and c) refractory kerogen as a function of temperature and heating rate (after Quigley et al., 1987. Reprinted by permission of Editions Teehnip).

Generation and expulsion of hydrocarbons

97

Hydrocarbon gases (methane) are generated simultaneously at these depths. The principal generation of methane occurs beyond depths of ca 4000 m until a burial depth of 6500 - 7000 m, corresponding to the temperature range of 150 220 'C.

3.2 Primary hydrocarbon migration The primary migration of petroleum hydrocarbons through the fine-grained source rocks towards the more permeable coarse-grained carrier rocks is influenced by the characteristics of the generated hydrocarbons as well as by the Characteristics of the source rocks. The abundance and physico-chemical characteristics of the generated hydrocarbons available for primary migration are influenced by the burial history of the source rock, the history of the geothermal gradient and the nature and initial amounts of the original organic matter (Section 3.1). The characteristics of the porous water-bearing source rock itself is also influenced by its burial history. An increasing depth of burial is accompanied by: increasing temperatures and pressures; decreasing porosities, permeabilities and groundwater content of the source rock; and changing physico-chemical characteristics of the groundwater (Chapter 2). Because of these different subsurface conditions of both the hydrocarbons to be moved and the medium through which the movement occurs, many different migration mechanisms have been suggested for moving hydrocarbons out of a source rock. The various suggested primary migration mechanisms are treated by, among others: Cordell, 1972;Doligez, 1987;Momper, 1978;Roberts I11 and Cordell, 1980; and Tissot and Welte, 1984. These migration mechanisms can be divided into those that involve the movement of groundwater (Section 3.2.1)and those that can also operate independently of groundwater movement (Section 3.2.2). The Sections 3.2.1 and 3.2.2 present a selection of the main theories with respect t o the possible modes and mechanisms that have been considered in literature to explain primary migration. Probably, different primary migration mechanisms are responsible for the transport of hydrocarbons through source rocks. The movement of a separate hydrocarbon phase (oil; gas; oil dissolved in gas; gas dissolved in oil) driven by gradients of hydrocarbon potential is widely considered t o be an important mechanism of primary migration during the peak phase of hydrocarbon expulsion from rich source rocks (e.g. Durand, 1983;England et al., 1987;Tissot and Welte, 1984). This migration theory is supported by mass-balance considerations (Jones, R.W., 1980), by successful geochemical correlations between crude oils and source rock bitumen (Barker, 1980;McAuliffe, 1980; Tissot and Welte, 1984) and by (geochemical) studies on actively expelling source rocks (Comer and Hinch, 1987;Leythaeuser et al., 1987,1988;

Chapter 3

93 Table 3.3 Aqueous solubility of selected petroleum compounds at 25 'C in ppm (wt./wt.)

COMPOUND

PRICE (1973,1976)

Aliphatic hydrocarbons Normal alkanes Methane Ethane Propane n-Butane 39.5 n-Pentane f n-Hexane 9.47 f n-Heptane 2.24 f n-Octane 0.431 f n-Nonane 0.122 f Is0 alkanes 2,3-Dimethylbutane 19.1 f 21.2 f 2,2-Dimethylbutane 2,4-Dimethylpentane 4.41 f 2,3-Dimethylpentane 5.25 f 1.14 f 2,2,4-Trimethylpentane Isobutane Isopentane 48.0 f 2-Methylhexane 2.54 f 3-Methylheptane 0.792 f 4-Methyloctane 0.115 f Alicyclic hydrocarbons Cyclopentane 160.0 f Methylcyclopentane 41.8 f 2.04 f n-Propylcyclopentane 1,1,3-Trirnethylcyclopentane 3.73 f Cyclohexane 66.5 f Methylcyclohexane 16.0 f 1,trans-4-Dimethylcyclohexane 3.84 f 1,1,3-Trimethylcyclohexane 1.77 f Aromatic hydrocarbons 1740.0 f Benzene 554.0 f Toluene m-Xylene 134.0 f o-Xylene 167.0 f p-Xylene 157.0 f 1,2,4-Trimethylbenzene 51.9 f 3.48 f 1,2,4,5-Tetramethylbenzene 131.0 f E thylbenzene Is0 ropylbenzene 48.3 f Isogut ylbenzene 10.1 f Sulfur and nitrogen compounds 3015 f Thiophene mi 2-Ethylthiophene 1795 f 2,7-Dimethylquinoline 3558f Indole lo800 f Indoline

0.6 0.20 0.04 0.012 0.007 0.2 0.3 0.05 0.02 0.02

McAULIFFE (1966)

24.4 60.4 62.4 61.4 38.5 9.5 2.93 0.66 0.220

4.06

1 1.3 2.1 2.1 2.0 f 12 f 0.20 f 0.06 f 0.021

f f f f f

f 0.29

22 48.9 47.8

f 0.12 f 21 f 1.6

2.0 1.0 0.10 0.17 0.8 0.2 0.17 0.05

156.0 42.0

f 9.0 f 1.6

17.0 15.0 2.0 4.0 1.0 1.2 0.28 1.4 1.2 0.4

1780

1.0 0.02 0.028 0.011

55.0 f 2.3 14.0 f 12

515

f 45 f 17

175

f

8

m

f

4

152f8 5 0 * 5

34 7 127 171 700

Modified after Tissot and Welte, 1984. Reprinted with permission of Springer-Verlag.

Generation and expulsion of hydrocarbons

99

Leythaeuser and Poelchau, 1990;Mackenzie et al., 1987,1988). The pressuredriven separate phase hydrocarbon migration is treated in Section 3.2.2.

Primary hydrocarbon migration involving active groundwater flow Three possible modes of primary hydrocarbon migration involving groundwater movement, are described below: - Migration of hydrocarbons in molecular solution, - Migration of hydrocarbons in micellar solution, - Migration of hydrocarbons in separate phase. 3.2.1

3.2.1.1 Hydrocarbons in molecular solution The solubility of individual hydrocarbons in pure water at 25 "C,as summarized by Tissot and Welte (1984)is given in Table 3.3.Table 3.3 indicates that there is a marked decrease in solubility with an increase in molecular weight (carbon number) for each class of hydrocarbons (alkanes, cyclo-alkanes, aromatics). It also shows that aromatics are more soluble than alkanes for a given carbon number. Polar heterocompounds (organic acids or alcohols) are more water soluble than the corresponding hydrocarbon with the same carbon number (Tissot and Welte, 1984). The hydrocarbon solubilities in water are influenced by temperature, salinity and pressure. Price (1976) studied the effect of temperature on the solubility of hydrocarbons. He found that increasing the temperature, while keeping the pressure constant, causes an increase in the aqueous solubilities of liquid hydrocarbons. The solubility of hydrocarbons gradually increases t o around 100 'C,where a more drastic increase takes place because of a change in the solution mechanism. A t temperatures above roughly 150 "C the solubility increase is very large. From his study Price (1976)also concluded, that an increase in temperature greatly increased the relative solubilities of aromatic hydrocarbons compared with the corresponding carbon-number cyclo-alkanes and normal-alkanes. Cyclo-alkane solubilities increased slightly more than normal alkanes. Temperature also has a strong positive influence on the aqueous solubilities of hetero-atom (nitrogen-, sulfur-, oxygen-bearing hydrocarbons. According to McAuliffe (19801,the solubility of natural gas (methane) decreases with increasing temperature to about 80 "C and then increases. A significant increase in aqueous solubility of methane occurs at temperatures above 250 'C. Gas and liquid hydrocarbon solubilities decrease with increasing water salinity (Price, 1976). The influence of pressure on hydrocarbon solubility has been studied for methane by Bonham (1978)and Price (1976).Figure 3.9, as presented by Bonham, shows the increase of methane solubility with increasing pressure.

Chapter 3

100

Temperature and salinity changes have smaller effects on solubility of natural gas in water than that produced by pressure changes. A solubility study by Price (as quoted by Price, 1976)indicated that the presence of gas in solution greatly increases the solubility of crude oil in pure water at temperatures above 250 "Cto 300 "C. Some additional geochemical and geohydrological observations are given below in order to answer the question of whether it is likely that hydrocarbon transport in solution can be considered as a primary migration mechanism.

A t peak hydrocarbon generation, the bitumens in the source rock show their greatest compositional similarity t o the genetically associated reservoired crude oils (e.g. Jones, 1980).A comparison of the gross chemical composition between crude oils and source rock bitumen shows that most crude oils are enriched in saturated hydrocarbons and depleted in polar nitrogen, sulfur, oxygen compounds (Tissot and Welte, 1984). McAuliffe (1980)studied the compositions of hydrocarbons dissolved in water from crude oils, and found that these hydrocarbon compositions differ vastly from those of crude oils, both in molecular size and molecular weight. From his findings he concluded that solution can be ruled out as a primary migration mechanism (for liquid hydrocarbons) over the temperature range of 60"to 150 'C. 200,000

100,000 80.000

60,000 10.000 L

r

p

20,000

3

n x

10,000 LL

a

* 0

:

8000 6000 LOO0

L

c u Y c

d

2000

1000 800

600

400 300

.. 20

...

50

100

I

150

"

"

1

"

"

200

1

"

~

~

I

250

'

"

'

I

'

300

'

350

DC

temperature

Figure 3.9 Solubility of methane in water (after Bonham, 1978. Reprinted by permission of the American Association of Petroleum Geologists).

Generution and expulsion of hydrocarbons

101

As was shown in Table 3.3, in general, the liquid hydrocarbons have a very low solubility in water. However, in the zone of peak oil formation, the groundwater in the source rocks will become saturated with hydrocarbons. Section 2.1 described movement of groundwater in an actively subsiding and filling basin. It appeared that the flux of water through the source rock diminishes with increasing depth of burial. Several mass balance studies have shown that in compacting sedimentary basins there is insufficient burialinduced water movement through the source rock during peak generation of hydrocarbons for aqueous solution of hydrocarbons to be a significant factor in the origin of commercial oil accumulations (Dickey, 1975;Jones, 1980;Magara, 1980;Tissot and Welte, 1984). The extra amount of water expelled by excess pressure gradients in the source rock induced by aquathermal pressuring, volume expansion of organic matter during hydrocarbon generation and the release of additional water by clay dehydration may not be sufficient to overcome this deficiency of mobile water. If the sedimentary basin is geologically mature, and the source rocks are not overpressured during peak hydrocarbon generation, gravity-induced groundwater flow through a source rock may occur during the hydrocarbon generation phase to account for commercial oil accumulations (see Jones, 1980).The condition that the source rock itself should not be overpressured (due to hydrocarbon generation, for instance) should be met, because otherwise the source rocks will act as a barrier to the gravity-induced groundwater flow. The chances for primary migration of liquid hydrocarbons dissolved in groundwater seem best at relatively shallow depths corresponding to an early phase of oil generation in areas with normal geothermal gradients, or to early and peak phases of oil generation in areas with high geothermal gradients. During an early phase of oil generation, the oil saturation of the pore system is low and the pores are still predominantly water-filled. At relatively shallow depths, the source rocks have enough porosity for additional compaction and/or enough permeability to allow a sufficient flux of water through the source rocks. At relatively shallow depths, i.e. at relatively low temperatures, only the more soluble hydrocarbons of low molecular weight and some polar nitrogen, sulfur, oxygen compounds of high molecular weight are likely to be taken into solution (Tissot and Welte, 1984). Price (1976;1980b) proposed a model of primary hydrocarbon migration by molecular solution based on the movement of groundwater from source rocks occurring at great depths (6 - 9 km) and high temperatures (higher than 180 "C).Although there will not be much movement of groundwaters at great depths, the high temperatures prevailing there are thought to provide the necessary solubility for creating commercial oil accumulations.

102

Chapter 3

Compared with liquid hydrocarbons, natural gas hydrocarbons (principally methane, with decreasing amounts of ethane through pentane) have relatively high solubilities in water. In theory, sufficient gaseous hydrocarbons may be transported in solution during primary migration t o account for commercial gas accumulations (see McAuliffe, 1980). Methane is produced throughout the process of hydrocarbon generation (from diagenesis to metagenesis, i.e. from shallow depths of burial of the source rock t o great depths of burial) but principally with deep burial (Section 3.1.2, Figure 3.2). In theory, primary migration of hydrocarbon gases in aqueous solution may take place from shallow t o great depths. In subsiding and filling sedimentary basins, burial-induced groundwater flow may occur a t depth ranges corresponding t o the entire methanegenerating zone. A t shallow depths, the burial-induced groundwater flow may be an important migration mechanism for gaseous hydrocarbons. The amount of burial-induced groundwater flow from the source rock decreases with depth. As a consequence, the burial-induced flow alone may not be able to transport significant amounts of dissolved gaseous hydrocarbons a t depths corresponding to the main zone of gas generation. The additional expulsion of groundwater from the source rock by pressure gradients induced by hydrocarbon generation and aquathermal pressuring is probably not sufficient to overcome the lack of flowing groundwater at these depths ranges. In subaerial sedimentary basins, the gravity-induced cross-formational groundwater flow may transport dissolved gaseous hydrocarbons through the source rocks. A t depths corresponding to the main zone of gas generation (> 4000 m), massive hydrocarbon gas generation will create pressure barriers to gravity-induced groundwater flow. Gravity-induced groundwater flow will not be active in source rocks at these great depths. A t shallower depths, however, cross-formational groundwater flow may transport significant amounts of dissolved gaseous hydrocarbons. This is because the amount of groundwater available for transport of gaseous hydrocarbons in solution by gravity-induced flow is unlimited, contrary to the amount of groundwater available for burialinduced flow. Liquid and gaseous hydrocarbons dissolved in water during primary migration may come out of solution when an increase in salinity and a decrease in pressure and temperature take place. In general, the salinity of the groundwater in the coarse-grained carrier rock (reservoir rock) will be higher than that in the adjacent source rock, while the groundwater pressure in the carrier rock will be lower than that in the source rock (Section 2.1.3), and exsolution may take place at the source rock - carrier rock interface. According to Hunt (1979) exsolution is not necessarily completed at the entry point of groundwater into the carrier rock. Hydrocarbons remaining in solution during movement through the coarse-grained rocks could be further depleted due to

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further changes in salinity, pressure and/or temperature, o r on contacting an oil (or gas) accumulation.

3.2.1.2 Hydrocarbons in micellar solution Micelles are molecular aggregates formed in solutions of surface-active agents (surfactants: compounds that orient at an interface such as between oil and water) (McAuliffe, 1980).Micelles may contain up to 100 or more surfactant molecules with a nonpolar (hydrophobic) end on the inside and a polar (hydrophilic) end on the outside. In 1959,Baker first advanced the concept of solubilization of hydrocarbons in (soap) micelles as a possible primary migration mechanism. The possible role of soaps, i.e. salts of organic acids, in primary migration was supported by Cordell (1973). The concept was considered attractive because it also explains how the practically waterinsoluble hydrocarbons can solubilize in groundwater at relatively low temperatures. However, the likelihood of micellar solution as an effective primary migration mechanism has been seriously questioned by many authors (for instance Price, 1976;Hunt, 1979;Tissot and Welte, 1984). The main problems associated with micellar solution are: - The size of micelles. Ionic micelles suitable to solubilize natural hydrocarbons would have median diameters of about 60 A. Micelles appear t o be larger than the small size of the pore throats in the source rock at a depth of burial corresponding to the main zone of oil and gas generation. According to Tissot and Welte (1984),primary migration of hydrocarbons in micellar solution would definitely be limited down to a depth of about 2000 m. - Availability of sufficient surface active agents to form micelles. McAuliffe (1980)showed that even if the source rocks contain a high percentage of organic matter, it is unlikely that sufficient surfactant to attain micelle formation would be attained from the organic matter. In addition, the concentration of potential micelle-formers will decrease with depth of burial of the source rock (as the generation of nitrogen, sulfur and oxygen polar compounds, which are more likely to form micellar solution, decreases with increasing depth). - The electrical barrier to flow caused by negative charges on both micelle and mineral surfaces. - The probable lack of sufficient groundwater flow to carry micelles from the source rock during peak hydrocarbon generation. Hence, the role of micellar solution of hydrocarbons in primary migration can be considered to be limited. 3.2.1.3 Hydrocarbons in separate phase When separate phase hydrocarbons and groundwater are both present in a porous rock, one of the two immiscible phases will preferentially adhere to the rock matrix. The wettability of the rock is a measure of which fluid preferentially adheres to the rock. The boundary between two immiscible fluids

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or a fluid and a gas is called an interface. The force that acts on the interface is known as interfacial tension. As a result of this force, a pressure difference exists across the interface. The difference in pressure across the interface is the capillary pressure, which is related to the interfacial tension, the radius of the pore throats of the rock, and the wettability (Dake, 1978)(see also Section 4.1.2). If small discrete oil droplets (or gas bubbles) are dispersed in an otherwise water-saturated source rock, the water adheres to the rock matrix and is called the wetting fluid; the source rock is said to be water-wet. As long as the oil dropletdgas bubbles are the same size as or smaller than the effective pore diameters of the water-wet source rock, the droplets and bubbles can be transported along with the moving groundwater. When the droplets or bubbles encounter pore throats with diameters smaller than their own diameters, they experience a resistance to movement, which is determined by the capillary pressure. The smaller the pore throats, the higher the capillary pressure gradient between the pore and the adjacent pore throat. High pressure differentials will be needed to overcome the capillary pressure gradient and to force the droplets or bubbles through the small pores in densely compacted source rocks during the main phase of oil and gas generation. The necessary pressure differentials are much higher than those needed to force groundwater alone out of the source rock. Transport of hydrocarbon droplets and bubbles along with groundwater movement is not considered to be important as a primary hydrocarbon migration mechanism (McAuliffe, 1980; Price, 1976; Tissot and Welte, 1984). 3.2.1.4Conclusion Primary hydrocarbon migration controlled by active groundwater flow, principally involves the movement of hydrocarbons in aqueous solution. In general, the liquid hydrocarbons have a very low solubility in water. The most soluble liquid hydrocarbons are low molecular weight hydrocarbons and polar high molecular weight nitrogen-sulfur-oxygen compounds. In comparison with liquid hydrocarbons, gaseous hydrocarbons (principally methane) have relatively high solubilities in water. Methane gas is produced throughout the hydrocarbon generating process: from shallow depths of burial of the source rock, where biogenic methane is the principal hydrocarbon that is generated, to great depths of burial of the source rock. The principal zone of gas generation is encountered at deep burial (> 4000 m). Under average geological conditions, the groundwater-driven transport of both liquid and gaseous hydrocarbons in aqueous solution is probably not important as a primary migration mechanism at depths corresponding to the peak phase of oil and gas generation. At relatively shallow depths groundwater flow may be an important migration mechanism for (biogenic) gaseous hydrocarbons. Possibly, primary solution migration of the more soluble constituents of liquid hydrocarbons may also take place at shallow depths corresponding to early phases of oil generation.

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3.2.2 Primary hydrocarbon migration independent of active groundwater flow Pressure-driven primary migration of continuous separate phase hydrocarbons and diffusion controlled primary migration of hydrocarbons through the kerogen network and the pore network of the source rock do not need the actual flow of groundwater as a driving force. However, hydrodynamic conditions are likely to prevail in the sedimentary basin during hydrocarbon generation. Therefore, groundwater flow through the source rock may occur simultaneously with both hydrocarbon expulsion processes. 3.2.2.1 Continuous separate phase hydrocarbon migration As shown in Section 3.2.1,transport of hydrocarbons in their own phase in the form of oil droplets or gas bubbles in water cannot be considered a major primary migration mechanism because of the high capillary pressures that have to be overcome. The problem of high capillary pressures that restrict the movement of a separate hydrocarbon phase as droplets or bubbles in a waterwet source rock, can be solved if a more or less continuous hydrocarbon phase could be assumed to be present in the source rock (see also Section 4.1.2).The flow of continuous separate phase hydrocarbons through source rocks can be described by Darcy’s law (Section 1.2.1)extended to multiphase flow. The resistance to flow of each of the immiscible phases (groundwater, hydrocarbons) present in the pore system of the source rock, is determined by its effective permeability. These effective permeabilities are functions of hydrocarbon (or water) saturation: the greater the hydrocarbon saturation, the greater the effective permeability to hydrocarbons and the smaller the effective permeability to water. The permeability to hydrocarbons will remain negligible until a certain threshold is reached. This means that a certain critical hydrocarbon saturation of the pore system has to be exceeded before the hydrocarbons can start migrating through the source rock (Durand, 1983; Leythaeuser et al., 1987a;Mackenzie et al., 1987). The hydrocarbon saturation of the pore system is controlled primarily by the rate of hydrocarbon generation from the organic matter in the source rock. The rate of hydrocarbon generation in a source rock depends on its initial total organic carbon content, type of organic matter and maturation of organic matter (Section 3.1.4). In source rocks with a good oil potential, the oil saturation of the pore system will reach higher values more quickly during burial than in source rocks with a poor oil potential (Durand, 1983).Mackenzie and Quigley (1988)calculated that in a rich oil-prone source rock at depths of 3 - 4 km,the oily hydrocarbons must displace groundwater and saturate about 40% of the pores of a source rock (assumed porosity 5%) before major hydrocarbon migration and expulsion can begin. Source rocks with poor oil potential may never reach the threshold oil saturation and consequently no primary migration of a separate oil phase can take place. In addition to massive generation of hydrocarbons the three following circumstances have been proposed to favour the development of a

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continuous separate hydrocarbon phase in a source rock andfor the primary migration of hydrocarbon in its own phase. 1. The organic matter is concentrated Organic matter I kerogen in source rocks occurs primarily in a solid finely disseminated condition, but is often very inhomogeneously distributed being concentrated in layers (Momper, 1978; Jones, 1980). The minimum hydrocarbon saturation necessary t o initiate primary migration may be reached sooner in layers with relatively high concentrations of organic matter. 2. The pore water i n the source rock is structured During the main phase of hydrocarbon generation the source rocks are deeply buried and the porosities and pore diameters of the rocks are small, because of their high degree of compaction. Some pore water is adsorbed on the mineral surfaces of the source rocks. The effect of this adsorption is to cause structuring of the water close t o the mineral surfaces. The pore water closest to the mineral surfaces is more strongly adsorbed and more highly structured than the water farther from the mineral surfaces. The ratio of mobile pore water t o structured pore water decreases with decreasing pore diameters, i.e. with an increasing state of compaction of the source rocks. In densely compacted source rocks, most of the pore water is either adsorbed or close enough to the mineral surfaces of the rock matrix to be structured t o some degree (Dickey, 1975;Hinch, 1980; Hunt, 1979). Hydrocarbon molecules tend to be excluded from the more highly structured pore water (Hinch, 1980). Consequently, the hydrocarbons are expelled from the smallest pores and will concentrate in the centre of the larger pores, where the water is least structured. According t o Barker (1980), a pore-centre network of hydrocarbons may thus ultimately be formed. In a study of Talukdar et al. (1987) on source rocks of the La Luna Formation (Venezuela), Talukdar et al. suggested that the primary migration of oil in these source rocks takes place in continuous separate oil phase because of the high bitumen concentration in the source rocks and the lack of significant amounts of free and mobile groundwater. Even if a continuous network of hydrocarbons does not develop, the large proportion of structured water in the pore spaces of densely compacted source rocks facilitates the movement of hydrocarbons in separate phase. According to Dickey (1975) the saturation of hydrocarbons in terms of the total mobile pore fluids may become very large (possibly more than 50%) if a large part of the pore water is structured. As a consequence, the relative permeability of the source rock t o the generated hydrocarbons will increase during continued compaction and will become greater than the relative permeability of the rock t o water, and with progressive burial of the source rock the hydrocarbons will be expelled preferentially t o water. Price (1989), however, questiones the actual occurrence of structured water at depth in sedimentary basins. This is because at great burial depths, the high temperatures would disrupt structured water. In addition, Price (1989) states that multiple layers of structured water would totally close-offthe pore throats in compacted source rock and would thus inhibit the movement of hydrocarbons in separate phase instead of enhancing it.

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107

3. The source rock is partially oil-wet If part of the source rock matrix is oil-wet instead of water-wet, liquid hydrocarbons can flow as a separate phase even at low saturations (less than 20 o r 30% according t o Dickey, 1975). It can be expected that during peak hydrocarbon generation, the source rocks rich in kerogen will be partially oilwet. The kerogen itself almost certainly is, and the kerogen will blanket a large part of the matrix. Organic matterkerogen i n source rocks is often concentrated in layers. Momper (1978) observed that the organic matter (or kerogen) has larger dimensions than the small mineral particles of the source rock matrix. Based on these observations, McAuliffe (1980)postulated that with compaction, the kerogen may form a three-dimensional kerogen network that is wettable with oil. When the concentrations of hydrocarbons in separate phase inside the kerogen are sufficiently high, the kerogen network may provide a primary migration avenue for the hydrocarbons generated. Lewan’s (1987) petrographic study on a shale source rock actually showed that under increasing thermal stress, the bitumen generated from the initially dispersed kerogen eventually formed a continuous network in the source rock. The driving force for continuous separate phase hydrocarbon movement through source rocks is the hydrocarbon potential gradient which in turn depends on, among other things, the groundwater potential gradient. Large groundwater potential gradients may be generated in a source rock by e.g. sedimentary or tectonic loading, hydrocarbon generation and thermal expansion of pore water, and infiltration of meteoric water (Chapter 2). As described in Section 2.1.3,during continued burial of fine-grained rocks the groundwater potentials in fine-grained rocks (e.g. source rocks) may become higher than those in adjacent more permeable rocks. Abnormally high pressures may build up in the source rocks, especially during rapid burial of hydrocarbon-generating source rocks. The groundwater pressure gradients in the source rocks, induced by sedimentary loading, at depths corresponding to the intermediate subsystem of burial-induced groundwater flow, are directed both vertically upwards and downwards. At greater depths, corresponding to the deep subsystem of burial-induced flow, the loading-induced pressure gradients in the source rocks may be directed principally vertically upwards (Section 2.1.3). Figure 3.10 shows the large increase in burial-induced groundwater overpressure with depth as observed in several wells in Jurassic and Triassic carrier-reservoir rocks in the Viking Graben, North Sea area. The groundwater pressures of U.K. Well 16/3-1 are measured a t four different intervals in deeply buried sands intercalated in Upper Jurassic shales (Buhrig, 1989). The increase in groundwater pressure with depth in the sandy carrier rocks themselves is near-hydrostatic. However, large vertical changes of groundwater pressure with depth occur over the shales. For example, the pressure-depth gradient over the deepest shale interval between depths of c. 4200 and 4600 m, is approximately 44,500Pa m-1, which corresponds to a net driving force for vertically upward-directed groundwater flow of approximately

108

Chapter 3 groundwateroverpressure(MPa) 10

0

20

30

40

1500

2000

2500

3 v)

3000

T N

3414-2

3500

4000

4500

Groundwateroverpressure= observed groundwater pressure hydrostaticgroundwater pressure (for pw= 1020 kg/m3) UJ MJ LJ TR NW UK

= Upper Jurassic sands = Middle Jurassic sands = Lower Jurassic sands = Triassic sands

= Norwegian well = British well

Figure 3.10 Observed groundwater pressures in Jurassic and Triassic carrier-reservoir rocks in the Viking Graben, North Sea (based on data presented by Buhrig, 1989, in Fig. 6, p. 38, Marine and Petroleum Geology, Vol. 6. Reproduced by permission of the publishers, Butterworth Heinemann Ltd. 0).

Generation and expulsion of hydrocarbons

109

34,000 Pa m-1. At shallower levels even larger vertical pressure gradients occur (Figure 3.10). These magnitudes of the vertical driving force for groundwater flow clearly are a highly significant factor in controlling the primary migration of hydrocarbons. Volume expansion of organic matter during hydrocarbon generation (Section 3.1.4) may increase the groundwater pressure in the source rock. The effect of water expansion with increasing temperature may induce aquathermal pressuring, resulting in an increase in groundwater pressures in the source rocks. The hydrocarbon potential gradient resulting from these three pressure generating mechanisms will be directed vertically up or down towards adjacent more permeable carrier rocks. The hydrocarbon potential gradients in the source rocks may induce the vertical expulsion of continuous separate phase hydrocarbons towards the carrier rocks (e.g. England et al., 1987). Infiltration of meteoric water in stable subaerial basins may induce large vertical groundwater potential gradients over low permeable source rocks located in the recharge and discharge areas of the meteoric groundwater flow system (Section 2.3.1). In recharge areas the groundwater potential gradient is directed vertically downwards and in discharge areas vertically upwards. The resulting hydrocarbon potential gradient in source rocks in discharge areas may become large enough to induce the vertical upward expulsion of separate phase hydrocarbons towards adjacent carrier rocks. In theory, downward expulsion of separate phase hydrocarbons from source rocks in recharge areas may result from very large downwards directed groundwater potential gradients. The capillary pressure gradient is the resistant force for separate phase hydrocarbon migration in the source rock. However, at the interface between coarse-grained rocks (carrier rocks with relatively large connected pore throats) and fine-grained rocks (source rocks), the capillary pressure gradient is directed towards the coarse-grained rocks. This means, that at the interface between source rocks and carrier rocks, the capillary pressure gradient becomes a driving force for the movement of separate phase hydrocarbons out of the source rock instead of a resistant force. The ‘positive’ influence of capillary effects on the primary migration close to the edges of a source rock has been suggested by Hubbert (19531, Leythaeuser et al. (1987a, b, 1988) and Mackenzie et al. (1987,1988). The continuous separate phase hydrocarbon transport may occur through a kerogen network and through the pore network of the inorganic part of the source rock. After the hydrocarbons have left the kerogen network, they move preferably through a network of selected large pores (Mann, 1989). The migration of continuous separate phase hydrocarbons through the primary porosity of the source rock is thought to be a continuous process (Leythaeuser et al., 198713). If the source rock is of very poor permeability and the hydrocarbon

110

Chapter 3

phase is not really continuous, the primary hydrocarbon migration may be a discontinuous process involving microfracturing of the source rock (e.g. Du Rouchet, 1981; Hedberg, 1980; Price, 1989; Tissot and Welte, 1984; Talukdar et al., 1986). The development of microfractures in the source rock relieves pressure and permits previously trapped hydrocarbons t o escape. The microfractures may periodically open o r heal, depending on internal pore pressures (Section 2.1.3). Microfracturing may be caused by a build-up of the groundwater pressure in rocks of very low permeability (Section 2.1.3). Rapid burial of the source rock and the resulting increase in sedimentary load, aquathermal pressuring and generation of hydrocarbons, may cause local centres of abnormally high groundwater pressures. In source rocks, massive gas generation, like that beginning a t the later stage of peak hydrocarbon (oil) generation may cause groundwater pressures t o rise to its upper limit, i.e. the sum of the least principal stress plus the tensile strength of the rock, leading to microfracturing (Hedberg, 1980; Buhrig, 1989). The gas (methane) generation thus facilitates the escape from the source rock. Hitherto, it has been assumed that the primary migration of separate phase hydrocarbons takes place in either a hydrocarbon liquid (oil) phase or a hydrocarbon gas phase. Different studies suggest that all hydrocarbons generated from type I1 and type I11 kerogen source rocks will probably be expelled as a single phase fluid (e.g. England and Mackenzie, 1989; England et al., 1987; Leythaeuser and Poelchau, 1991). The generation of oil from source rocks bearing type I1 and type I11 kerogen is generally accompanied by the generation of gas (Section 3.1.2, Figure 3.2). Mature source rocks bearing a type I1 kerogen generate predominantly oil and only small quantities of gas during the peak interval of hydrocarbon generation. According to Leythaeuser and Poelchau (1991) the gas is expelled by dissolution in oil and no separate gas phase will evolve during primary migration and all generated hydrocarbons will be expelled as a single fluid. Source rocks that contain the type I11 kerogen may generate predominantly gas. With increasing depths of burial of the source rock cracking will produce large amounts of gas both from the kerogen and from unexpelled oil. As temperature and pressure increase, the capacity of gas to dissolve liquid hydrocarbons increases as well (Price et al., 1983). The increase in pressure exerts the largest influence on the increase in solubility of oil in methane gas (Price et al., 1983). The presence of water, and admixtures of ethane through butane in the methane gas phase, enhance the capacity of gas to dissolve oil (Price et al., 1983). Gas as a transport vehicle for the primary migration of oil has been suggested by e.g. Hedberg (1980), Leythaeuser et al. (1987a), Leythaeuser and Poelchau (1991) and Price (1989). Gaseous solution can be an effective migration mechanism for oil generated from mature type I11 kerogen (Leythaeuser and Poelchau, 1991; Price, 1989). The composition of the oil expelled in gaseous solution by type I11 kerogen source rocks may show signs of fractionation (e.g. Price, 1989). Leythaeuser and Poelchau (1991) found from a study using observed molecular compositions of bitumen extracts from

Generation and expulsion of hydrocarbons

111

source rocks, data on oil solubility in methane and numerical modelling, that the degree of fractionation of expelled C15+normal alkanes varies from high at early stages of migration to very low at advanced stages of migration and source rock maturity. Ultimately, with an oversupply of gas, they found that fractionation effects are no longer apparent as more and more of the limited amount of oil generated by such source rocks is dissolved and expelled. England and Mackenzie (1989) recognized that beyond some critical temperature and pressure, gas-saturated oil and condensate-saturated gas approach similar compositions and properties. At these depths of more than c. 4 - 5 km, there is no longer a distinction between gaseous and liquid phases, and the hydrocarbons (C1 - C5 and C6+)are expelled from the source rock as a single phase supercritical fluid (England and Mackenzie, 1989).

3.2.2.2 Diffusion-induced hydrocarbon migration The rate and direction of diffusive transport of atoms or molecules in liquids, gases and solids is determined by gradients in chemical potential of the atom or molecule. Diffusion through water-saturated source rocks The diffusion of hydrocarbons in source rocks is influenced by (Krooss and Leythaeuser, 1988): - physico-chemical characteristics of the diffusing hydrocarbon (molecular weight; size; geometry; polarity; solubility), - properties of the source rock (porosity and pore structure; composition of pore fluids; composition of mineral and organic matter), - boundary conditions (pore pressure; temperature; initial concentration of diffusing hydrocarbon). The diffusion of hydrocarbon molecules as a possible primary migration mechanism has been described in several papers (e.g. Barker, 1980; Hinch, 1980;Hunt, 1979;Leythaeuser et al., 1980, 1982;Mackenzie et al., 1987, 1988; Krooss, 1987;Krooss and Leythaeuser, 1988). In order to assess quantitatively the role of diffusion in primary hydrocarbon migration, Leythaeuser et al. (1982)modelled the process of diffusion of light hydrocarbons (n-alkanes C1to Cld under hydrostatic conditions for eight source rock examples (shales). Their mathematical model was based on effective diffusion coefficients of light hydrocarbons as determined by Leythaeuser et al. (1980;Figure 3.11). It was shown that molecular diffusion through water-saturated source rocks represents an effective process for primary migration of gas but not for oil. The rate of mass transport for gas from source rocks with geological time can be sufficiently high to account for the origin of commercial-size gas fields. Due to an exponential decrease of the diffusion coefficient with increasing carbon number (Figure 3.11), the mass transport rate of liquid hydrocarbons is probably too low to contribute significantly to their primary migration. The primary migration of gas by diffusion as modelled by Leythaeuser et al. (1982)is

112

Chapter 3

0 Measured

A

Based on the regression curve

Figure 3.11 Effective diffusion coefficient versus carbon number per molecule for normal alkanes of low molecular weight (after Leythaeuser et al., 1982. Reprinted by permission of the American Association of Petroleum Geologists).

thought t o be effective over short distances within the source rock itself (Figure 3.12). Leythaeuser et al. (1982) stated that primary migration of gas by diffusion may be an important mechanism in three types of source rock: early to low mature source rocks; abnormally high pressured source rocks; deeply buried source rocks rich in organic matter. Early to low mature source rocks may not yet have generated sufficient amounts of hydrocarbons to oversaturate the pore water and initiate the formation of a separate hydrocarbon phase. Under these circumstances primary migration by separate phase movement is not yet possible, but diffusive transport of hydrocarbons is. It should be kept in mind that Leythaeuser et al.’s reasoning is based on their model assuming hydrostatic conditions. However, hydrodynamic conditions may prevail in early t o low mature source rocks enhancing to a greater or less extent the mass transport rate of hydrocarbons through and out of the source rocks. In abnormally high pressured and undercompacted source rocks, and assuming that no potential gradients exist inside the abnormally pressured zone, gas can be transported by diffusion, as the diffusion process is independent of pressure and predominantly dependent on concentration gradients. According t o Leythaeuser et al. (19821, the porosities and permeabilities of deeply buried source rocks may become too low t o permit formation of a continuous gas phase, while gas can still effectively move by diffusion under these circumstances.

Generation and expulsion of hydrocarbons

113

A,A',B,B',C,D

likely sites for diffusive transport of light hydrocarbons

A,A'

toward contact with carrier rock

B

toward fracture system communicating with f a u l t

fault

B'

toward fracture system communicating with carrier rock

predominant gas migration mechanisms by diffusion

C

toward fault

D

toward interbedded siltstone lens

shale source rock carrier rocks siltstone fracture system

other

Figure 3.12 Schematic illustration of likely sites and directions of light hydrocarbon diffusion in shale source rocks (after Leythaeuser et al., 1982. Reprinted by permission of the American Association of Petroleum Geologists).

Leythaeuser et al.'s (1982)study showed that the composition of the gas accumulated in a reservoir after transportation from a source rock where diffusion was the initial process of primary migration is controlled by three principal factors: the initial concentration of the individual hydrocarbons in the source rock, their relative differences in diffusion rates, and the source rock thickness. Diffusion through water-saturated rock is probably a relatively minor primary migration mechanism, in view of the total amounts of

Chapter 3

114

hydrocarbons transported by separate phase hydrocarbon migration. However, it is considered t o be of importance because it may alter the composition of the hydrocarbons retained and expelled by the source rock (Mackenzie et al., 1987, 1988).

Diffusion through organic matter network Stainforth and Reinders (1990) proposed activated diffusion of bitumen molecules through organic matter in source rocks as a rate-limiting primary migration mechanism. This activated diffusion is a more temperature than pressure dependent process. It moves small molecules more easily than larger o r more awkwardly shaped ones and may explain the compositional fractionations of bitumen observed in source rocks and laboratory experiments (Stainforth and Reinders, 1990). According to the authors this primary migration mechanism applies t o both gaseous and oily hydrocarbons and it may occur in all kerogen types and in source rocks with a wide range of total organic carbon contents so long as a continuous organic network can be established, The hypothesis for primary migration by activated diffusion through organic matter has been developed by the authors from a conceptual model of a primary migration system given in Figure 3.13. The permeable inorganic lenses are not in direct hydraulic contact with the secondary migration system. In the permeable lenses pressure-driven movement of gas or fluids may occur. The “impermeable”part of the primary migration system

1-100 m

B. Microscopic OM network

Primary migration system

C. Molecular kerogen polymer

Figure 3.13 Conceptual model of a primary migration system a t three scales (after Stainforth and Reinders, 1990. Reprinted with permission from Organic Geochemistry, Vol. 16, nos. 1-3, Copyright 1990, Pergamon Press Ltd.).

Generation and expulsion of hydrocarbons

115

consists of a three dimensional network of organic matter in an inorganic matrix. The organic matter network consists mainly of solid organic matter (kerogen plus coke) in which bitumen is dissolved and a lesser component of microcracks in which bitumen is adsorbed. The inorganic highly compacted matrix has a porosity of only a few percent, a mean porosity in the order of nanometres and an inferred permeability in the order of nanodarcies or less. The pores in the inorganic matrix are hydrophilic. Stainforth and Reinders (1990) recognize that with increasing permeability of the inorganic part of the source rock and decreasing contents of organic matter, the dominance of the proposed primary migration mechanism through organic matter probably changes via primary migration by diffusion of hydrocarbons in groundwater to pressure-driven migration of separate phase hydrocarbons.

3.2.3 Expulsion efficiency After primary migration has taken place, a certain proportion of the generated hydrocarbons remains in the pore system of the source rock (Hunt, 1979). The oil fraction that remains in the source rock will be cracked to gas as the source rock is buried to greater depths and temperatures (Section 3.1.5). The effect of primary migration of hydrocarbons can be indicated by the expulsion efficiency. The petroleum expulsion efficiency is the ratio of the expelled petroleum and the sum of the generated and initial petroleum and can vary from zero (no expulsion) to 1.0 (complete expulsion) (Cooles et al., 1986). The expulsion efficiencies are not uniform in time and space (Leythaeuser et al. 1987b). They depend on the type of source rock, its richness and thermal maturity and the primary migration mechanism. Cooles et al. (1986) estimated the bulk oil generation and the average oil expulsion efficiency for eleven example source rocks. Between 120 and 150 'C and above a critical value of the petroleum generation index (usually 0.2 - 0.4) petroleum expulsion efficiency is strongly dependent on initial petroleum potential (Cooles et al., 1986; Mackenzie and Quigley, 1988). Figure 3.14 illustrates the calculated relationship between the overall average oil expulsion efficiency and the average initial petroleum potential of a source rock. Between 120 and 150 'C the oil expulsion is very efficient (ca 60-90%) for good oil-prone source rocks with initial petroleum potentials greater than ca 0.01 kg/kg of rock (Mackenzie and Quigley, 1988). The oil expulsion from leaner oil-prone source rocks (initial petroleum potential < 0.005 kg/kg of rock) is relatively inefficient (Mackenzie and Quigley, 1988). Most of the oil generated will remain in this source rock and be converted to gases at higher temperatures (> 150 "C)and expelled as gas condensate followed by dry gas (Mackenzie and Quigley, 1988). The expulsion of gas is probably very efficient. Altebaumer (1982, in Cooles et al., 1986), for instance, showed that gas expulsion from the gas-prone Lias 6 shales, N.W.Germany, is very efficient with up t o 95% of generated gas being expelled from the source rock. As outlined in Section 3.2.2.1, gas generation

116

Chapter 3 1.0

shilaif

0.8 -

hrz

A

u x

.I

W c

kingak

.-

.-"

-+

brown limestone

0.6

-

0.4

- Lias6

0.2

-

lW e

c

.-0

-

n

.

W X

W

," L

W

.

dukhan

douala. cretaceous

m >

0.0

I 0.001

0.01

c

average initial hydrocarbon potential ( k g / k g o f rock)

Figure 3.14 Variation of average bulk oil expulsion efficiency with average initial hydrocarbon potential (after Cooles et al., 1986. Reprinted with permission from Organic Geochemistry, Vol. 10, Copyright 1990, Pergamon Press Ltd.).

facilitates the escape of liquid hydrocarbons. Cooles et al. (1986) found very high expulsion efficiencies associated with high maturities of the source rock irrespective of the initial petroleum potential of the source rock. They believe that these high efficiencies are the result of oil cracking to gas at these high maturity levels.

For a certain geological heating rate, the petroleum expulsion efficiency, in combination with the type and richness of a source rock, determine whether oil, gas condensate o r gas will be expelled over a certain temperature range (Mackenzie and Quigley, 1988; Figure 3.15). For the same source rock, the expulsion efficiencies increase with increasing hydrocarbon generation rates. The highest expulsion efficiencies of oil occur in rich source rocks containing type 11kerogen during the peak phase of oil generation, when oil is expelled in a separate phase (Figure 3.16). The expulsion efficiencies in a single source rock may vary due to capillary effects (Leythaeuser et al. 1987,1988; Mackenzie et al. 1987, 1988). The capillary forces enhance the efficiency of expulsion close t o the interfaces between source rock and carrier rock. Thin source rock layers may exhibit higher expulsion eficiencies than thick source rock layers because of the capillary effects near the edges of the source rocks.

Generation and expulsion of hydrocarbons

117

CLASS1 1

PGI 0 1

PEE 0

Petmkum exp4ed

1

PGI 0 1

PEE 0

Petrokum expelled CLASS3 1

PGI 0 1

PEE 0

Petmkum expelled

80

120

160

200

240

PGI = Petroleum Generation Index PEE = Petroleurn Expulsion Efficiency

Figure 3.15 Principal petroleum phases expelled from three classes of source rock over relevant temperature ranges assuming a mean heating rate of 5 'C per million years (after Mackenzie and Quigley, 1988. Reprinted by permission of the American Association of Petroleum Geologists).

Figure 3.16 shows that some expulsion does occur prior to the peak phase of oil generation. During this early expulsion stage the edges of thick source rock layers and the thin source rock layers are depleted (Leythaeuser et al., 1987). The rate of hydrocarbon expulsion from mature rich oil-prone source rocks is about 8 x 10-15 to 8 x 10-14 mh-%-I, according to a rough estimate made by England et al. (1987). England et al.'s calculations are based on the subsurface conditions given in Table 3.4.

Chapter 3

118

1

I

I

I

I

0

-1

0

n 0.5

-

0.8

-

n

early expulsion

x

-

L

L

3

+ m

E

peak generation

0-

Figure 3.16 Schematic representation of amount of hydrocarbons generated in, and expelled from a type I1 kerogen-bearing source rock as a function of organic matter maturity for the initial part of the oil window (after Leythaeuser e t al., 1987. Reprinted with permission from the Proceedings 12th World Petroleum Congress, Houston, Vol. 2, Fig. 2a, p. 229).

Table 3.4 Assumed average subsurface conditions for rich oil-prone source rocks

TOC Hydrogen index Petroleum generated Expulsion efficiency Temperature range of hydrocarbon generation Geological heating rate Source rock thickness Source rock density Petroleum fluid density Data from England e t al., 1987

= 4% weight = 0.7 k&g TOC = 0.02 kgkg rock

= 100% = 120- 150 "C = 1- 10 'Clmillion year = 100 m = 2400 kg m a = 650 kg m a

Generation and expulsion of hydrocarbons

119

3.3 Summary Hydrocarbons are generated from finely disseminated organic matter in fine-grained sedimentary rocks, such as shales, mudstones and fine-grained carbonates. When sediments rich in organic matter are buried as caused by continued sedimentation in a subsiding sedimentary basin, successive steps of evolution of organic matter occur, i.e. diagenesis, catagenesis and metagenesis. Kerogen, the insoluble part of organic matter in sedimentary rocks that is formed during diagenesis, is the main precursor of hydrocarbon compounds. Temperature increase is of primary importance for hydrocarbon generation. During burial, the kerogens (type I, 11, and 111) are altered, with trends to lower hydrogen to carbon and oxygen t o carbon ratios due to the generation and liberation of hydrocarbons, carbon dioxide and water. Some organic matters (kerogens) are less able to generate oil than others, but any organic matter may generate gas, provided it is buried sufficiently deeply for long enough. Kerogen type 111, the insoluble organic matter derived from terrestrial plants, generates comparatively less oil than the kerogen types I or 11. At greater depths type 111 kerogen, and coal, may be a good source of hydrocarbon gas. For average geothermal gradients and geological heating rates, the principal zone of oil generation occurs at burial depths between ca 2500 and 5000 m, corresponding to temperatures between 100 and 150 'C. Hydrocarbon gases (methane) are generated simultaneously at these depths. Significant gas generation occurs at burial depths beyond 4000 m until ca 7000 m, corresponding to temperatures of 150 - 220 "C. Thermal cracking of oil to gas takes place in the temperature range 150 - 190 'C. Different primary migration mechanisms are probably responsible for the transport of hydrocarbons through the hydrocarbon-generating source rocks in sedimentary basins. The three major mechanisms of primary hydrocarbon migration seem to be: - primary migration of continuous separate phase hydrocarbons (oil and gases and mutual solutions of these) driven by hydrocarbon potential gradients, including capillary-pressure driven primary migration of separate phase hydrocarbons (oil and gases) - groundwater-driven primary migration of hydrocarbons in aqueous solution (mainly gases and t o a less extent the most water-soluble liquid hydrocarbons) - diffusion-driven primary migration of hydrocarbons (principally gases) in aqueous solution, and diffusion-driven primary migration of hydrocarbons through organic matter network.

120

Chapter 3

The effectiveness of the different primary migration mechanisms is determined by the subsurface characteristics of both the hydrocarbons to be moved and the medium through which the movement takes place. During the peak phase of hydrocarbon expulsion, the hydrocarbons are transported through the already low permeable source rock mainly as a continuous single phase fluid in a vertically upward o r downward direction. The driving forces for the separate phase hydrocarbon migration are large hydrocarbon potential gradients which are related t o large groundwater potential gradients generated in the source rock by e.g. sedimentary or tectonic loading, volume expansion of organic matter during hydrocarbon generation, thermal expansion of groundwater, and infiltration of meteoric water. Under average geological conditions, the active groundwater-driven transport of both liquid and gaseous hydrocarbons in aqueous solution is probably not important a s a primary migration mechanism at depths corresponding t o the peak phase of oil and gas expulsion from good source rocks. A t relatively shallow depths active groundwater flow may be an important migration mechanism for (biogenic) gaseous hydrocarbons. Possibly primary solution migration of the more water-soluble constituents of liquid hydrocarbons takes place in good source rocks at shallow depths corresponding to early phases of oil generation and in leaner source rocks at depths corresponding to the entire phase of oil generation. Diffusion of light hydrocarbons through water-saturated source rock may be active at all depth ranges. It is considered to be a relatively minor transport process in comparison with separate phase hydrocarbon migration. It may influence, however, the composition of the hydrocarbons expelled from the source rock. In rich source rocks with practically negligible matrix permeability, primary migration may possibly also occur by activated diffusion of hydrocarbons through organic matter network. The primary migration mechanism or combination of mechanisms by which the hydrocarbons are moved through and expelled from the source rock, is of influence on the geochemical composition of the expelled hydrocarbons. Oil expulsion from good oil-prone source rocks is very efficient, whereas oil expulsion from leaner source rocks is relatively inefficient. Probably, most of the oil generated in leaner oil-prone source rocks will remain in the source rock and be cracked t o gas a t higher temperatures and expelled as gas condensate followed by dry gas. Gaseous solution can be an effective migration mechanism for oil generated from mature type I11 kerogen. The expulsion of gas is very efficient .

I21

CHAPTER 4

SECONDARY HYDROCARBON MIGRATION

Secondary hydrocarbon migration is the movement of hydrocarbons after expulsion from a source rock through carrier and reservoir rocks or fault and fracture systems. During the peak phase of hydrocarbon expulsion, the hydrocarbons are probably mainly expelled as a single phase fluid (Chapter 3). Expulsion of hydrocarbons in aqueous solution may be of importance before the start of the peak phase of hydrocarbon expulsion from good source rocks, and possibly during the entire phase of hydrocarbon generation in leaner source rocks. After expulsion from the fine-grained source rock the hydrocarbons enter the water-saturated relatively coarse-grained carrier rock or reservoir rock. The magnitude and direction of the driving forces for hydrocarbon migration through the carrier rock are influenced by, amongst other things, the hydrodynamic conditions in the rock and the form in which the hydrocarbons move. Sections 4.1 and 4.2 give information on the driving forces for secondary hydrocarbon migration under hydrostatic and hydrodynamic conditions, respectively. The characteristics of a hydrocarbon migration system in a sedimentary basin at a certain moment during its evolution are defined by the masses and composition of hydrocarbons available for migration and the starting point of hydrocarbon migration (i.e. by the location, type, richness and maturity of the hydrocarbon-generating source rocks); the hydrogeological framework of the sedimentary basin; and the hydrodynamic condition of the basin. Different hydrocarbon migration systems may coexist and interact in the same sedimentary basin. During different stages of evolution of a basin, different hydrocarbon migration systems may develop. The secondary hydrocarbon migration system distributes the hydrocarbons in a sedimentary basin in a way that may lead to either concentration of hydrocarbons into economic accumulations or loss of hydrocarbons due to dispersion, destruction or escape into the atmosphere (e.g. Demaison and Huizinga, 1991). Secondary hydrocarbon migration systems are treated in Section 4.3. In Section 4.3 attention is focussed on the regional pattern of hydrocarbon migration.

Chapter 4

122

4.1 Secondary hydrocarbon migration under hydrostatic conditions Generally speaking, hydrocarbons may leave the fine-grained source rocks as separate phase hydrocarbons, or as hydrocarbons in aqueous solution. The primary migration and expulsion of dissolved hydrocarbons occurs principally under hydrodynamic circumstances, although light hydrocarbons may also be expelled by molecular diffusion under hydrostatic conditions (Chapter 3). Molecular diffusion of light hydrocarbons through water-saturated carrierreservoir rocks is not thought t o be significant as a secondary migration process (Leythaeuser et al., 1982, England et al., 1987). In this section, description of the secondary hydrocarbon migration under hydrostatic conditions will be restricted to separate phase hydrocarbon migration. After expulsion from the source rock, the separate phase hydrocarbons may initially form small oil globules or gas bubbles in the larger pores of the coarsegrained carrier rocks. With continued supply of hydrocarbons from the source rock, the oil globules or gas bubbles grow in size and become subject to buoyancy forces (Section 4.1.1).Upward secondary migration of oil or gas in the watersaturated carrier rock will occur whenever the buoyancy force is larger than the capillary force that resists this migration (Sections 4.1.2 and 4.1.3).The nature of the multiphase flow through the carrier rocks is laminar (nonturbulent) and is dominated by capillary forces in the pore network of the carrier rocks (England et al., 1987). 4.1.1 Buoyancy

In an isothermal and isochemical body of water under hydrostatic conditions, there is no flow of water. The potential of the water is constant, at any point in the water, and assuming the density of the water is constant, the potential can be given by (Chapter l), +w

= gz + PW = constant

(4.1)

Pw

where, g

= potential of the water (L?F2) = acceleration due to gravity ( L P 2 )

Z

= elevation (L)

Pw

= pressure of the water (ML-lY2) = density of water (ML-3)

+W

Pw

Hence, the net force acting on a unit mass of water is zero (Figure 4.1) (Section 2.1.1).

-

Ew=-grad +,=O

(4.2)

Secondary hydrocarbon migration

t 7

-grad p,

pw

E,=O

Figure 4.1 The magnitude and direction of the net driving forces for separate phase oil and gas migration under hydrostatic conditions.

The net forces acting on a unit mass of separate phase oil or gas completely immersed in water under isothermal and isochemical conditions, as given by Hubbert (1953),is: (4.3) PO

where, = g z + -Pw $0

Po $0

Po

= potential of the oil ( m 2 ) = density of the oil ( m a ) (4.4)

where,

%J

p,

= potential of the gas (LV2) = density of the gas (ML-3)

These net forces acting on oil and gas can also be expressed in terms of gravity, and the net force acting on water (Hubbert, 1953):

Chapter 4

124

(4.5)

(4.6) From Equations 4.5 and 4.6 it follows that since g is fixed, the direction and magnitude of the net force acting on a unit mass of oil or gas immersed in water under isothermal and isochemical conditions depend upon the density of acting on the the oil o r gas and the direction and magnitude of the net force water.

ew

eo eg

and will be directed Under hydrostatic conditions Rw = 0 and therefore vertically upwards under these circumstances and Equations 4.5 and 4.6 will reduce to (4.7) and

These upward directed forces are generally called buoyancy forces and are the driving forces for separate phase oil o r gas migration through water under hydrostatic conditions. The magnitude of the buoyancy force for a vertical length zo of a body of oil or gas immersed in water can be expressed by

or

E, = zog

(Pw - P g )

(4.10)

Equations 4.9 and 4.10 show that the greater the density difference between the immiscible phases oil and water, or gas and water, the greater the buoyancy force for a given vertical length of the body of oil or gas. Small changes in the density of either hydrocarbon o r water will be of great influence on the magnitude of the buoyancy force (Davis, 1987). For a subsurface density of oil po= 600 kg m-3, a subsurface density of gas pg = 200 kg m-3, a groundwater density of pw = 1000 kg m-3, the buoyancy force per unit vertical length of the immersed hydrocarbon body is 4000 Pa m-1 and 8000 Pa m-1, respectively. For the same densities of oil and gas, and a groundwater density of pw = 1200 kg m3 the buoyancy forces increase to 6000 and 10,000 Pa m-1, respectively.

Secondary hydrocarbon migration

125

The buoyancy force is also considered a driving force for secondary separate phase hydrocarbon migration through water-saturated rocks (Schowalter, 1979). However, in the subsurface the hydrocarbons must migrate through the rock pores and they encounter a resistant force to movement when the diameter of the oil globule or gas bubble is larger than any throat connecting the pores of the rock. This resistant force is indicated as capillary pressure. The net force acting on a unit mass of hydrocarbon in water-saturated rock under isothermal and isochemical conditions, as given by Hubbert (1953),is

(4.11) where, PC subscript hc

= capillary pressure (ML-'T-~)

= hydrocarbon

4.1.2 Capillary pressure When two immiscible fluids (or a fluid and a gas) are in contact, molecular attractions between similar molecules in each fluid are greater than the attractions between the different molecules of the two fluids and a clearly defined interface exists between them. The force that acts on this interface is called interfacial tension (or surface tension in case of a gas-fluid contact). As a result of this force, a pressure difference exists across the interface. This pressure difference is known as capillary pressure and is given by the following equation (Dake, 1978): (4.12) where, PC

Y-+1 1'

1 2'

= capillary pressure (ML-lY2) = interfacial tension (MY2) = curvature of the interface; rl and r2 are the two principal radii measured in planes at right angles to each other and normal to the interface (L) = pressure in the hydrocarbon (ML-lT2) = pressure in the water (ML-"F2)

Phc Pw When an immiscible fluid or a gas is completely immersed in another fluid it assumes a spherical shape of minimum surface area. The curvature of the interface is spherical and (l/rl + l/r2)in Equation 4.12can be replaced by 2/r:

2Y Pc =I-

(4.13)

When two immiscible fluids are in contact with a rock surface, the capillary pressure is also influenced by the wettability of the rock. The wettability of a

Chapter 4

elevation1

Pv'=Po

capillary tube'

pressure

Figure 4.2 Capillary tube experiment for two immiscible fluids (after Dake, 1978).

rock is expressed by the contact angle 8 of the hydrocarbon and water against the solid pore walls as measured through the water phase (Figure 4.2). For rock-fluid systems with contact angles between 0" and go", the rocks are generally considered water-wet; for contact angles greater than go", the rocks are considered oil-wet. For a hydrocarbon-water-rock system, the capillary pressure is given by (e.g. Dake, 1978).

(4.14) where, pd

= hydrocarbon-water displacement pressure (ML-'T2)

R

as measured through the water phase = radius of largest connected pore throats in the rock; R defines the radius of curvature of the hydrocarbon-water interface R = r cos 8

e

= contact angle of hydrocarbon and water against the solid pore walls

The displacement pressure is a rock property and is defined as the force required t o replace water from a cylindrical pore with oil or gas. Hence the displacement pressure determines the minimum buoyancy pressure needed for migration. Secondary hydrocarbon migration generally occurs through water-saturated sedimentary rocks, i.e. through rocks that are water-wet. As water is generally considered a perfect wetting fluid (Schowalter, 1979),the contact angle 8 in Equation 4.14 for hydrocarbon-water-rock systems can be taken to be zero. If, in addition, the hydrocarbon-water interface is assumed to be spherical, then Equation 4.14becomes identical with Equation 4.13.

Secondary hydrocarbon migration

127

The magnitudes of the displacement pressure, and capillary pressure, are inversely proportional to the largest connected pore throats in the rock, R (R < radius of rock pore). The average pore diameters in shales are around 5 . 10-9 10 . 10-9 m a t depths of about 2000 m and will be smaller at greater depths (Tissot ant Welte, 1984). Assuming an interfacial tension of y = 0.03 N m-1, the capillary pressures in such shales may reach values of 10 MPa or more. The largest available pores are generally one or two orders of magnitude larger than the average pore sizes (Mann, 1989). For example, England et al. (1987) give a magnitude cd 10-8 m for the mean radius of the larger interconnected pores in shales at depths of approximately 3 km, and a mean radius of 10-6 m for sandstones at the same depths. The capillary pressure in the interconnected pores of sandstones with a pore radius of 10-6 m and an interfacial tension of y = 0.03 N m-1 is 0.06 ma. 4.1.3 Separate phase hydrocarbon migration Berg (1975) amongst others, has described separate phase hydrocarbon migration from a rock pore through an adjacent pore throat in a water-wet rock under hydrostatic conditions. The following outline of the migration process is largely based on his work. The capillary pressure of a spherical globule of oil (or gas bubble) that is in equilibrium with the surrounding pore water is given by Equation 4.13 (Figure 4.3a):

where, r 5 rp rP

= radius of the rock pore

A

0

Pc = 2Y

%>% rt

D

C

rp

2Y r

-

2Y r

a a

-<rp

rt

Figure 4.3 Migration of an oil globule through pore throats in a water-wet rock (after Berg, 1975. Reprinted by permission of the American Association of Petroleum Geologists).

Chapter 4

128

When the buoyancy force is large enough, the globule is forced upwards through an adjacent pore throat and the globule will be distorted (Figure 4.3b). The capillary pressure at the upper end of the distorted globule in the pore throat is: pt = 2y/rt. The capillary pressure is greater in the throat than in the pore: (2y/rt) > (2yh ). In this situation, the capillary pressure gradient is P directed downwards in opposition to buoyancy (Berg, 1975): (4.15) ZO

where, ZO

= vertical height of the globule

When the buoyancy force is greater than the capillary pressure gradient, the globule can rise further. The next situation encountered by the globule is depicted in Figure 4 . 3 ~ .The globule has moved halfway through the throat where the radii are equal a t the upper and lower end of the globule and the capillary pressure gradient has become zero. The globule can easily continue to rise by buoyancy . As soon as the globule attains a position more than halfway up the pore throat, the radius at its upper end is larger than at the lower end, and the capillary pressure gradient and the buoyancy force both act in the same upward direction. Secondary migration of an oil globule or gas bubble in a water-wet rock will occur if the buoyancy force acting on an oil globule or gas bubble is large enough t o overcome the capillary pressure gradient within the globule or bubble caused by the greater pressure in the pore throat than in the pores, i.e. (Berg, 19751,

In an equilibrium situation (Berg, 1975): (4.16) Under a given subsurface condition (i.e. a given hydrogeological framework and pressure, temperature, chemical conditions), the only variable in Equation 4.16 is the vertical height of the oil globule or gas bubble (i.e. the hydrocarbon column). The value of zo may increase by the accretion of the oil globule/gas bubble, e.g. because of a continued supply of oil or gas from the source rock. The maximum height of an oil globule or gas bubble that can be held in place, is called the critical height z, and is given by (Berg, 1975):

Secondary hydrocarbon migration

129

(4.17) For migration to occur a continuous oil stringer must extend through the interconnected pores of a water-saturated carrier rock (e.g. Berg, 1975;England et al., 1987; Schowalter, 1979). England et al. (1987) calculated that the hydrocarbons must fill c. 50% of all available carrier rock pore volume (which probably corresponds to 1 t o 10% of the rock’s cross-sectional area which represents the more coarse-grained parts) in order to create an interconnected pathway allowing hydrocarbon movement to occur. Secondary vertical upward migration of hydrocarbons through a carrier rock can continue as long as the buoyancy force of the hydrocarbon column is greater than the resistant force of the carrier rock. The hydrocarbons will migrate in a tortuous manner, focussed into the path of lowest resistance by moving through part of the rocks with the largest connected pore throats or lowest displacement pressure, i.e. through the larger pores and the coarsegrained parts of the carrier reservoir rock (Dembicki and Anderson, 1989; England et al., 1987; Schowalter, 1979). The smaller pores will remain waterfilled. A t the base of a migrating hydrocarbon stringer small isolated droplets or bubbles will be left behind as the stringer migrates upwards. The residual hydrocarbon droplets or gas bubbles are permanently trapped by capillary forces. The amount of hydrocarbons left behind in a carrier rock will be approximately equal to the amount necessary to form an interconnected pathway initially (England et al., 1987). The capillary-trapped gas and the soluble portion of the residual oil may dissolve in the pore water and dissipate by diffusion. As the migrating stringer loses oil at its base, the vertical height of the hydrocarbon column diminishes and consequently the buoyancy force will be reduced. Eventually, migration will stop until additional hydrocarbons migrate upwards along the same pathway to the stalled stringer, thus increasing the vertical height of the hydrocarbon column, i.e. the buoyancy force, and migration will continue. This continuous pulsating migration process, as described by Schowalter (19791, will continue as long as hydrocarbons are being added up. When the thus migrating hydrocarbons encounter an overlying rock with small pore diameters that exert capillary pressures that are too high to be overcome by the buoyancy force of the hydrocarbons, initially, the hydrocarbons will spread out along this seal boundary (barrier rock) (Figure 4.4). If the barrier rock is inclined, the hydrocarbons will start to migrate laterally updip along the seal boundary perpendicular to its strike as soon as the critical height of the hydrocarbon column is attained again by addition of hydrocarbons. For a dip of the carrier rock - barrier rock interface (a),the length of the hydrocarbon stringer (L) needed to obtain the critical vertical hydrocarbon column height (z,) is given by

130

Chapter 4 a

. . . _ . ., . , . ;. . . . . . . . :.. .' . .. . . .. _ . . . .. . . . .; .. .. .

U g r a t i o n of finely dispersed hydrocarbons Initially. the hydrocarbons entering a t the base o f a horizontal carrier rock are very finely dispersed and the buoyancy forces are s t i l l too small t o initiate hydrocarbon migration.

b

Vertical upward hydrocarbon migration through carrier

rock

Continued supply of hydrocarbons from the source rock increases the vertical height of the hydrocarbon column lz,) As soon as z, is large enough, i e as soon as the buoyancy force of the hydrocarbon column is greater than the resistant force of the carrier rock, vertical upward migration through the carrier rock w i l l start

c

... .. ..... .... . . . . '

. .. ..

Capillary pressures excerted by the barrier rock resist vertical upward hydrocarbon migration Hydrocarbons accumulate and spread out along the horizontal barrier rock - carrier rock interface.

. . . ., .

d

-..

..

. <.: :

; .:.. . ". , . . . . . .. . . ._ . , . . ' '

1-1

. .. .:.

Accumulation of hydrocarbons along horizontal barrier rock - carrrier rock interface

Lateral updip hydrocarbon migration along inclined barrier rock - carrier rock interface Hydrocarbons accumulated along an inclined barrier rock - carrier rock interface, w i l l s t a r t t o migrate laterally updip through the carrier rock when the critical height o f the hydrocarbon column is exceeded again by addition of hydrocarbons

barrier rock

w]

.. .. carrier rock

w d

source rock

o

small fraction of pore space occupied by hydrocarbons

0

large fraction of pore space occupied by hydrocarbons hydrocarbon migration direction

Figure 4.4 Secondary separate phase hydrocarbon migration under hydrostatic conditions (after Hobson and Tiratsoo, 1975. Reprinted by permission of Scientific Press Ltd.).

Secondary hydrocarbon migration

131

I , = z, / sin a. The steeper the dip, the shorter the length of the hydrocarbon stringer needed to obtain the critical vertical hydrocarbon column height. The updip directed buoyancy force per unit vertical height of hydrocarbon column is greatly reduced in comparison with the corresponding vertically upwards directed buoyancy force. For oil of density po = 600 kg m-3, groundwater of density pw = 1000 kg m a and a dip of the carrier rock - barrier rock interface of 2', the updip directed buoyancy force per unit vertical height of oil column is sin 2" (p, - po)g = 140 Pa m-1. For a unit length of hydrocarbon stringer measured parallel to the carrier rock - barrier rock interface with dip a, the updip directed buoyancy force equals (p, - phc)g sin%.

When the source rock is on top of the carrier reservoir rock, the downward expelled separate phase hydrocarbons will initially accumulate along the source rock - carrier rock boundary, as the fine-grained source rock acts as a top seal boundary. Once the critical vertical height of the hydrocarbons has been reached, the hydrocarbons 4 1 1 migrate vertically updip along the source rock - carrier rock boundary. The hydrocarbons will keep on migrating through the carrier rock initially encountered unless, along the migration path, the rock is immediately overlain by a yet more permeable rock, or juxtaposed with another potential carrier rock updip at an unconformity or fault (Mackenzie and Quigley, 1988). In addition the hydrocarbons may escape from the carrier rock vertically upwards along faults or through fractured parts, or otherwise leaky parts, of the overlying barrier rock. Eventually, oil or gas will be trapped along a migration path whenever a closed displacement pressure barrier is encountered. Reservoir engineers use an adjusted form of Darcy's law for single-phase fluid flow through porous media (Chapter 1)to describe the flow of separate phase hydrocarbons through water-saturated rock (Dake, 1978). This generalized Darcy's equation is also used t o study secondary migration of separate phase hydrocarbons (e.g. Bethke et al., 1991; England et al., 1987; Ungerer et al., 1987a), 4

ah, = --khcphc grad $hc

(4.18)

phc

where khc= effective permeability of the rock to hydrocarbons.

For single-phase flow, when the rock is completely saturated with one fluid (or gas) only, the permeability k (= absolute permeability), is a rock property and a constant, irrespective of the nature of the fluid flowing through the pores. For two-phase (water and hydrocarbon) flow, each fluid has its own effective permeability that is dependent on the saturation of the rock to the fluid. The greater the hydrocarbon saturation, the greater the effective permeability of the

132

Chapter 4

k

= =

kw = Sw = Sw, = Sor =

absolute permeability of the porous medium effective permeability of the porous medium to oil effective permeability of the porous medium to water water saturation irreducible water saturation irreducible oil saturation

Figure 4.5 Effective permeabilities as functions of water saturation (after Dake, 1978).

rock to hydrocarbons and the smaller its effective permeability to water (Figure 4.5). The sum of the effective permeabilities is always less than the absolute , = 0, then khc = k. The expression permeability. When the water saturation S relative permeability is also used for describing flow in two-phase systems. The relative permeability is the ratio of the effective permeability to that of a onephase system. The adjustment of Darcy’s equation to two-phase flow by the relative permeability concept is known t o be approximate (e.g. Doligez, 1987). For instance, as outlined above, the migration path of the hydrocarbons is probabIy restricted to the more coarse-grained parts of a carrier rock. Below a certain minimum hydrocarbon saturation no hydrocarbon migration will occur because of the resistant force t o movement that is caused by the capillary pressure gradient of the rock, and consequently the effective permeability khc = 0. Because of the capillarity effects, the relation between q and grad Q will not be linear for two-phase flow. This is inconsistent with Darcy’s law which allows for linear q t o grad @ relations only. The generalized Darcy equation is based on the assumption that the flow of the hydrocarbon phase for a certain hydrocarbon saturation of the rock, is the same as if the water phase were a part of the solid matrix of the rock. Kalaydjian and Marle (1987), amongst others, criticize this assumption. They state that one can expect that the flow of

Secondary hydrocarbon migration

133

each fluid phase (and not only its presence) may have an effect on the flow of the other phase and that the motions of the fluid-fluid interfaces may have some effects on the flow. Although Darcy's law is known to be approximate, it is generally applied to describe two-phase flow through porous media. Assuming that the subsurface conditions are isothermal and isochemical and the migration system is in steady state, the flux of separate phase hydrocarbon migration at a certain location may be estimated from Equation 4.18.For hydrostatic conditions, the generalized Darcy equation 4.18,

-

qhc=-- khcphc grad

ohc

phc in combination with

yields the following expression for the specific discharge qhc for buoyancydriven vertical upward migration of hydrocarbons through a carrier rock under isothermal and isochemical conditions

(4.19) England et al. (1987)use the following expression to estimate the effective hydrocarbon permeability of a carrier rock at a certain point in the subsurface khc

-2 r =Tn

8 2

(4.20)

where,

-r

2

n

= mean radius of the rock pores (L) = tortuosity of the migration network, taken to be & (dimensionless) = porosity of the rock (dimensionless) = saturation of the rock to hydrocarbons (dimensionless)

Table 4.1 gives the characteristics of the carrier rock (sandstone) and the fluids (oil and water) considered to be representative for conditions prevailing at about 3 km depth (England et al., 1987).These characteristics are used in the following example calculations. Introducing the values given in Table 4.1 into Equation 4.19results in a specific discharge q, = 3.6x lO-'m s-l= 113 cm yr-'

134

Chapter 4

Table 4.1 Rock and fluid properties representative for conditions prevailing at a depth of 3 km.

Rock = sandstone hydrocarbon = oil r = 10-6m = 0.2 n z =& = 0.5 SO -2 r =x nS = 4 x 10-15 m2 k0 8 T2 PO = 5 x @Pa s Po = 650 kg m3 Pw = 1100 kg m3 = 10m s-2 g Data from England et al., 1987

For updip flow along a carrier rock - barrier rock interface with an inclination of a = 2", go becomes k PO

qo = O g (pw - p o l sin a = L 3 x 10-lOm s-l= 0.4 cm y F 1

These estimated specific discharges for the buoyancy-driven migration of oil through a carrier rock are about 5 orders of magnitude greater than the estimated expulsion rates for oil from source rocks as given in Chapter 3.

4.2

Secondary hydrocarbon migration under hydrodynamic conditions

Under hydrodynamic conditions, the potential in a body of water is not constant, and the net force acting on a unit mass of water under isothermal and isochemical conditions is given by Equation 1.6 (Section 1.1).

Pw

The direction of this force Rw is perpendicular to the equipotential surfaces of the water. The water will be driven in the direction of gw,i.e. in the direction of decreasing potential. As the values of grad pw and Rw are interrelated, it

Secondary hydrocarbon migration

135

follows from Equations 4.5 and 4.6 that the net-driving forces for separate phase hydrocarbon movement are influenced by E, . Section 4.2.1 discusses the separate phase hydrocarbon movement in the subsurface under hydrodynamic conditions. Movement of hydrocarbons in aqueous solution through the subsurface is driven by convection, molecular diffusion and dynamic dispersion (Section 4.2.2). 4.2.1 Separate phase hydrocarbon migration The net force acting on a unit mass of oil or gas immersed in groundwater under hydrodynamic conditions, assuming that the subsurface is isothermal and isochemical, can also be described by Equation 4.11.

As the magnitude and direction of 2 are fixed, and the magnitude and direction of (- grad pc/phc) are dependent on the geological subsurface conditions and the physico-chemical characteristics of the hydrocarbon-water system, the only variable that is changed under hydrodynamic circumstances in comparison with hydrostatic circumstances is (- grad Pv/Phc). From Equations 4.3 and 4.5 it follows that,

(4.21) Under hydrodynamic circumstances in a homoge_neous and isotropic subsurface the groundwater flows in the direction of E,. A change in the magnitude and/or direction of 2, will cause a change in the magnitude and/or direction of the net driving force for secondary hydrocarbon migration. Figure 4.6 illustrates this influence of the groundwater flow on hydrocarbon migration is not included in Figure 4.6). (the influence of the capillary forces on goand In addition, Figure 4.6a shows the effect on the direction and magnitude of the net driving force for hydrocarbon migration as produced by density differences of the hydrocarbons for a fixed value of kw in a non-vertical direction. As stated by Hubbert (1953), it is clear that under hydrodynamic conditions with groundwater flowing in a non-vertical direction, oil and gas at the same point will be acted upon by forces differing both in magnitude and direction and accordingly will migrate in different directions. The migration direction for separate phase oil migration has a greater angle of deflection from the vertical compared with that for separate phase gas migration.

eg

For a hydrodynamic condition with groundwater flowing i n a vertical direction, the net driving force for water flow is directed either vertically

136

Chapter 4

a

Non-vertical groundwater f l o w

9 b

Vertical upward groundwater flow

c

c

9

Vertical downward groundwater f l o w

Figure 4.6 The magnitude and direction of the n e t driving forces for separate phase oil and gas migration under hydrodynamic conditions.

Secondary hydrocarbon migration

137

upwards o r downwards (Figure 4.6b and c). The net driving force acting on a unit mass of hydrocarbon will also be vertical. In the case of vertical upward groundwater flow, the magnitude of the upward directed jib, will be greater than in a hydrostatic condition, while vertical downward groundwater flow will diminish the magnitude of gh,. Only when the vertically downward directed net driving force for water flow is very large, i.e. the vertical hydraulic gradient is very large, will the direction of the net driving force for separate phase hydrocarbon movement be vertically downwards too. The magnitude of the resistant force to hydrocarbon movement caused by capillarity is not influenced by the groundwater flow condition and is also given by Equation 4.15.The net driving force for a vertical height zo of a hydrocarbon column influenced by vertically upward or downward directed groundwater flow can be derived from Equations 4.5 and 4.6 and equals

The critical height z, of the hydrocarbon column under vertical groundwater flow conditions becomes

(4.22) From expression 4.22 follows that vertically upward directed groundwater flow will diminish the critical height z, of the hydrocarbon column while vertically downward directed flow will increase its vertical height. In a heterogeneous basin, in a carrier rock with groundwater flow parallel to the inclined upper boundary of the rock, the updip migration of a hydrocarbon stringer of length 1 accumulated along the carrier rock - barrier rock interface will start if

f1

2r --- l’i

In addition to the increasing influence of vertical or lateral groundwater flow on the migration of hydrocarbons with increasing magnitudes of the net driving forces for groundwater flow, the influence of lateral groundwater flow through carrier rocks increases with decreasing inclinations of the carrier rock - barrier rock interfaces and will be largest in horizontally layered basins.

138

Chapter 4

Vertically directed driving forces for groundwater flow occur e.g. in the recharge and discharge areas of gravity-induced groundwater flow systems and in burial-induced groundwater flow systems (Chapter 2). Large vertical hydraulic gradients are expected to exist over poorly permeable layers in the intermediate and deep subsystems of burial-induced groundwater flow in actively subsiding and filling heterogeneous basins, and in recharge and discharge areas of gravity-induced groundwater flow systems in heterogeneous subaerial basins with a large relief of the ground surface topography. The large magnitudes of the net vertical driving force for groundwater flow are a highly significant factor in controlling hydrocarbon migration. For example, vertical upward directed net driving forces for groundwater flow of 34,000 Pa m-1 have been calculated to exist over poorly permeable layers at depths of c. 4000 m in the Viking Graben, North Sea (Section 3.2.2.1). The flow of groundwater in sedimentary basins tends to be focussed into units of relatively high permeability, i.e. into potential reservoir-carrier rocks. The magnitude of the driving forces for lateral groundwater flow through reservoir-carrier rocks in actively filling and subsiding basins and in stable subaerial basins may be comparable in magnitude to the lateral updip component of the buoyancy force for hydrocarbon migration o r even larger. For example, in the rapidly subsiding South Caspian Basin consisting predominantly of sands and shales, the regional value of the lateral driving force for groundwater flow through the sands at a depth of 4 km is about 100 Pa m-1 (calculated from data presented in Bredehoeft et al., 1988). According t o England et al. (1987)values of 500 - 1000 Pa m-1 for the lateral driving force for groundwater flow are common at depths beyond 3 km in the North Sea area. In the gravity-induced groundwater flow system in the Denver Basin, USA, groundwater flow is focussed through the Dakota and basal Cretaceous sandstones which behave as a regional aquifer (Belitz and Bredehoeft, 1988). The driving force for lateral flow of groundwater through the Dakota and basal Cretaceous sandstones in large part of the Denver basin is in the order of 30 Pa m-1 o r less (depth of the sandstones c. 600 - 2500 m, sandstone intrinsic permeabilities c. 10 - 1000 mD). In the western part of the basin near the Laramie uplift, the sandstone aquifer occurs at depths of more than 2500 m and its intrinsic permeability is less than 10 mD. In this deepest lying and least permeable part of the aquifer the driving force for lateral groundwater flow is calculated to amount up to 500 Pa m-1 (calculations for the Denver Basin are based on data derived from Belitz and Bredehoeft, 1988).

As outlined in Section 4.1,the migration of very finely dispersed oil droplets or gas bubbles with diameters smaller than those of the smallest pore throats of the carrier rock will not be influenced by capillary forces. In addition, according t o Tissot and Welte (1984) the very finely dispersed oil droplets will not strictly follow the law of buoyancy. In the initial stages of secondary migration, the hydrocarbons in separate phase may occur as droplets or

Secondary hydrocarbon migration

139

bubbles that are smaller on average and in a more dispersed state than during the final stage (Tissot and Welte, 1984;Hunt, 1979).Under these circumstances the magnitude and direction of separate phase hydrocarbon migration will be controlled mainly by the groundwater flow condition. During subsequent stages of secondary hydrocarbon migration, when the hydrocarbon droplets or bubbles have grown in size, the density differences between the hydrocarbons and the groundwater will, in addition t o the groundwater flow condition, strongly influence the magnitude and direction of the hydrocarbon migration. Under hydrodynamic conditions, the actual flow of separate phase hydrocarbons through carrier rocks can also be approximated by applying Darcy Equation 4.18. In order to give an idea of the orders of magnitude involved, an estimation of the specific discharge of separate phase hydrocarbon migration under steady state hydrodynamic conditions is given below. For hydrodynamic subsurface conditions, Equation 4.5

Ro = -grad

$o

= 5+

h ( e w-I> Po

in combination with the Darcy Equation 4.18 yields the following expression for the specific discharge Q for separate phase oil migration along a carrier rock barrier rock interface with an inclination a, under isothermal and isochemical conditions go =-(g(pw k0 -polsin a*pwE,)

(4.24)

PO

Assuming the updip directed driving force for groundwater flow at a depth of approximately 3 km is p S w= 500 Pa m-l, the characteristics of the carrier rock and the oil and groundwater are according to Table 4.1,and the inclination of the carrier rock - barrier rock interface is given by a = 2', the estimated specific discharge for oil migration becomes Qo

=

kog@w - polsin a koPwEw +

PO

+ 400 x

= 125.64x

=

PO

= 5.3 x 10-lOm s-l= 166 cm yr-'

For a downdip directed driving force for groundwater flow p,,,Ew = 500 Pa m-1 under otherwise equal conditions qo = 125.64x

- 400x

= -2.7 x 10-lOm s-l

ii:

-0.85 cm yr-'

Under these hydrodynamic conditions, the separate phase oil migration will be directed downdip with a specific discharge of 0.85 cm per year. It follows

140

Chapter 4

from Equation 4.24, that under the assumed subsurface conditions, a downdip directed driving force for groundwater flow of pJ3, = 157 Pa m-1 is able to stop the updip migration of oil in the carrier rock.

4.2.2 Migration of hydrocarbons in aqueous solution Hydrocarbons, that is principally the light hydrocarbons, may leave a source rock in aqueous solution, and initially may stay in solution in the carrier rock (Chapter 3). Hydrocarbons in aqueous solution are transported through the subsurface by convection, molecular diffusion and dynamic dispersion (Section

1.3.2). Garven (1989) modeled the migration of oil in aqueous solution through the Upper Devonian Carbonate aquifer in the Western Canada sedimentary basin t o investigate the role of groundwater flow in the formation of the Alberta heavy oil deposits. Numerical simulations of the advection and dispersion of soluble hydrocarbons entering the aquifer at a single point in the upstream part of the flow system considered (in which velocities of groundwater flow reach 8 ndyear) shows that the hydrocarbons initially disperse into a cloud and subsequently move in the directions of groundwater flow over a lateral distance of c. 300 km in 60,000years. The migration path of hydrocarbons in aqueous solution will follow the groundwater flow path until pressure, temperature, hydrochemical and/or geochemical conditions are encountered that force the hydrocarbons out of solution. As hydrocarbons in aqueous solution probably move along with the groundwater in the same direction but with somewhat lower velocities, even a very weak groundwater flow, will cause secondary hydrocarbon migration in the direction of groundwater flow.

A t the start of secondary hydrocarbon migration, i.e. in the vicinity of the source rocks, the migration direction of both hydrocarbons in aqueous solution and hydrocarbons in very fine suspension (Section 4.2.1)are strongly influenced by the direction of groundwater flow.

4.3 Regional aspects of secondary hydrocarbon migration The factors of influence on secondary hydrocarbon migration vary on large temporal and spatial scales (Section 4.3.1). The secondary hydrocarbon migration system in a basin at a certain moment during its evolution can be characterized by the masses and initial composition of the petroleum hydrocarbons available for secondary migration, the three-dimensional pattern of secondary hydrocarbon migration, i.e. the directions and lengths of the hydrocarbon migration paths, the flux of

Secondary hydrocarbon migration

141

migrating hydrocarbons and the migration losses. Secondary hydrocarbon migration may take place through permeable carrier reservoir rocks mainly in a lateral direction. The lateral distance of the hydrocarbon migration from source rock to accumulation may be a few metres to hundreds of kilometres (Sluijk and Nederlof, 19841, but is generally less than 30 km (Demaison and Huizinga, 1991). Tectonic elements (e.g. fracture and fault systems) may provide vertical hydrocarbon migration paths. I t is not uncommon for hydrocarbons t o migrate 2 kilometres vertically (Sluijk and Nederlof, 1984). During secondary migration hydrocarbons are lost along the migration path (Section 4.3.2). The system of secondary hydrocarbon migration, whether the hydrocarbons move in separate phase, in very fine suspension, or in aqueous solution, is influenced by the porosity and permeability distribution in a sedimentary basin and the magnitude and direction of the net driving force for groundwater flow. In addition, the magnitude of the hydrocarbon-groundwater density difference is of influence on the separate phase hydrocarbon migration. Secondary hydrocarbon migration systems can be classified as follows, according t o the dominating force or combination of forces affecting hydrocarbon migration: - Hydrostatic secondary hydrocarbon migration systems, i n which the dominant forces influencing hydrocarbon migration are the buoyancy forces and the capillary pressure gradients (Section 4.3.3). - Hydrodynamic secondary hydrocarbon migration systems, in which the hydrodynamic conditions in a basin affect hydrocarbon migration (Section 4.3.4). A further subdivision of hydrodynamic hydrocarbon migration systems can be made based on the different processes and associated forces that induce hydrodynamic conditions in sedimentary basins (Chapter 21, and their influence on hydrocarbon migration (Section 4.3.4.1 to 4.3.4.3). In addition, local groundwater flow systems that are driven by buoyancy and osmosis (Section 2.4) may be present within the basin-wide groundwater flow system (e.g. free thermohaline convection system around salt diapirs in an otherwise burial-induced groundwater flow system) and will influence the hydrocarbon migration accordingly. 4.3.1 Changing conditions along the migration path Strictly speaking, the acceleration due t o gravity is the only factor influencing the secondary hydrocarbon migration that can be considered to have a constant magnitude and direction on a regional scale. The migration depth, and consequently the pressure and temperature condition, as well as the hydrogeological framework of the subsurface change continuously along the hydrocarbon migration path. These changing conditions, in turn, affect the separate phase hydrocarbon migration by influencing e.g. the density, viscosity and chemical composition of the hydrocarbons and groundwater, the capillary pressure, and the effective permeability of the rocks for hydrocarbons.

Chapter 4

142

Major compositional changes in migrating hydrocarbons result from phase changes (e.g. England and Mackenzie, 1989; England et al., 1987; Larter and Mills, 1991) and biodegradation (e.g. Barnard and Bastow, 1991: Bockmeulen et al., 1983). After expulsion of hydrocarbons as a single phase fluid, the generally decreasing pressures and temperatures along a migration path cause the fluid to separate into liquid (gas-saturated oil) and gaseous (condensate-saturated gas) phases (e.g. England and Mackenzie, 1989). With continued upward migration, the gas-oil ratios of the liquid phase will decrease and that of the gaseous phase will increase (England et al., 1987). As a consequence, the properties of the liquid and gaseous phases become increasingly dissimilar. The migration and entrapment conditions along the migration path are different for the liquid and gaseous phase and they may become physically separated. Microbial degradation of hydrocarbons may occur when the migrating hydrocarbons are introduced into the realm of gravity-induced groundwater flow systems (Section 5.4.1). Biodegradation results in an increase in density and viscosity of the residual migrating hydrocarbons.

. .

100

1001

.-.m a

I

450

(u L

2 50

500

400

(u a

550

300

VI

L

200 100

600 0 0

1

100 temperature ("C1

a. Density o f gas-saturated petroleum liquid ( k g m-3 1

200

0

200

100 temperature

(OC)

b. Density o f condensate-saturated petroleum gas (kg.m-3 1

range o f pressure-temperature pairs encountered in the subsurface

Figure 4.7 Densities of subsurface oils and gases under equilibrium phase conditions, as a function of pressure and temperature (after England et al., 1987, 'The movement and entrapment of petroleum fluids in the subsurface', Journal of the Geological Society, London, Volume 144. Reprinted by permission of Blackwell Scientific Publications Ltd.).

143

Secondary hydrocarbon migration Table 4.2 Approximate subsurface viscosities of gas, oil and water.

Viscosity (Pa s) Gas Oil Water

1 P - 10-4 5 x l e - 5xW2 10-4 - 1 P

Data from Frick and Taylor, 1962 in England et al., 1987.

The density of the hydrocarbon phase is determined by its temperature, pressure and composition. Figure 4.7 shows the changes in densities of gas and oil with changing temperature and pressure for equilibrium phase conditions. The subsurface density of a gas-saturated oil increases during upward migration, i.e. increases with decreasing pressure, because the quantity of lighter hydrocarbons (generally gases a t ground surface conditions) that can be kept in solution in the liquid phase, decreases as well. In contrast, the subsurface density of an oil-saturated gas decreases rapidly with decreasing pressure. The decrease of the gas density is enhanced by the exsolution of the heavier hydrocarbons with decreasing pressure. The viscosities of water and oil are strongly influenced by temperature. Increasing temperatures reduce the oil and water viscosities (Chapter 1; Dake, 1978). The viscosity of gas is directly proportional to the pressure (Dake, 1978). The viscosity of subsurface gases increases, whereas the viscosity of subsurface oil decreases with increasing depth (England et al., 1987; Table 4.2). The capillary pressures are determined by the hydrocarbon-water interfacial tension, 'y, and the diameters of the interconnected pore throats of the carrier rock. The interfacial tension between oil and water increases a little with depth: it varies between 25 x 10-3Nm-1 and 35 x 10-3Nm-1 (Berg, 1975). The gas-water interfacial tension decreases with depth from 75 x 10-3Nm-1 at ground surface conditions to 35 x 10"Nm-' at depths of > 2 km (Berg, 1975). At depths of more than 2 km, the gas-water interfacial tension is similar to the oil-water interfacial tension (Berg, 1975; England et al., 1987). The size of the pore throats is determined by the physical properties of the carrier rock. The effective permeability of a carrier rock t o hydrocarbons depends on the physical properties of the rock and on its hydrocarbon saturation. Both factors may change along the migration path. The hydrocarbon saturation of the carrier rock is influenced by the supply of hydrocarbons from the source rock, the characteristics of the carrier rock and the losses of hydrocarbons during the migration.

144

Chapter 4

The flux of separate phase hydrocarbons through a carrier rock is given by the generalized Darcy Equation 4.18 and depends on the effective permeability of the rock t o hydrocarbons, the density and viscosity of hydrocarbons and on the hydrocarbon potential gradient. Hence, the flux of hydrocarbons may change continuously along a regional migration path. In addition t o the above described changing conditions that may occur along a single migration path a t a certain stage during the evolution of a sedimentary basin, the time-dependency of these conditions should be taken into consideration as well. This is because regional secondary hydrocarbon migration takes place on a geological time scale. Most factors influencing the migration system are time-dependent; e.g. the physico-chemical characteristics of the expelled hydrocarbons may change with time, as well as the pressure and temperature conditions at the starting point of secondary migration, the hydrodynamic conditions and the hydrogeological characteristics of the subsurface. 4.3.2 Secondary migration efficiency During the secondary separate phase hydrocarbon migration the hydrocarbons move along discrete interconnected pathways, i.e. through the larger pores and the coarse-grained parts of carrier-reservoir rocks or fracture networks. The hydrocarbon migration is concentrated in a relatively small percentage of the carrier-reservoir rocks (between 1 and 10% according to England et al., 1987). When migration along a certain migration pathway has come t o an end, hydrocarbons are left behind along the interconnected pathway in the canierreservoir rock. Residual oil saturations along a discrete migration pathway of 2 0 4 0 % occur (Mackenzie and Quigley, 1988). This corresponds with an apparent residual saturation of 1-3% of the total available pore space of the carrier-reservoir rock (Mackenzie and Quigley, 1988). The total volume of hydrocarbons (both oil and gas) lost during secondary migration can be estimated from the total volume of rock through which the hydrocarbons migrate and the mean porosity of the rock according to the following relation given by Mackenzie and Quigley (1988) V, = n S, VD (4.25) where, VL = volume of petroleum (hydrocarbons) lost during secondary migration VD = drainage volume = volume of carrier-reservoir rock through which petroleum migrates = porosity of the carrier-reservoir rock n s, = apparent residual saturation of the carrier-reservoir rock t o petroleum

Secondary hydrocarbon migration

145

From Equation 4.25 follows, that the longer the migration path, the larger the volume of petroleum lost. The secondary migration losses may limit the total length of the migration path. In separate-phase hydrocarbon migration systems, under steady state conditions, the same migration paths will be used by the hydrocarbons expelled from the source rocks. The larger the total volume of hydrocarbons expelled from the source rock, the smaller the percentage of expelled hydrocarbons lost during secondary migration. In addition to the losses of hydrocarbons during secondary migration indicated by Equation 4.25,additional losses of hydrocarbons can be expected to occur by accumulation of small non-economic volumes of hydrocarbons in miniature traps present along the migration path, and by dissolution and diffusion of especially hydrocarbon gases after their expulsion from the source rock (Chapter 3.2;Sluijk and Nederlof, 1984). 4.3.3 Hydrostatic secondary hydrocarbon migration

The net driving force for secondary separate phase hydrocarbon migration under hydrostatic conditions results from the buoyancy force, which is directed vertically upwards with a magnitude strongly dependent on water-hydrocarbon density differences, and capillary forces. As outlined in Section 4.1, separate phase hydrocarbons released from the top part of a source rock will initially move vertically upwards through an overlying more permeable and porous water-saturated carrier rock until a less permeable barrier rock is encountered that stops the vertical upward movement of the hydrocarbons by exerting capillary pressures greater than the driving forces. Subsequently, the separate phase hydrocarbons, accumulated along the carrier rock - barrier rock interface, will move updip perpendicular t o strike. Whenever lateral facies changes occur in the barrier rock, changing its sealing capacities, or whenever permeable fault or fracture systems or other preferred avenues like thrust plains, dikes, or salt diapirs cross the barrier rock, further vertical upward hydrocarbon migration is again possible. Finally, the vertical upward or updip migrating hydrocarbons are either lost to the atmosphere or accumulate in traps when capillary pressures encountered along the migration path become too high. The direction and length of the hydrocarbon migration path in a sedimentary basin is strongly determined by the porosity and permeability distribution in the basin and the location of hydrocarbon expelling source rocks. The secondary hydrocarbon migration path begins at the location of the mature hydrocarbon expelling source rock. Potential source rocks start generating and expelling hydrocarbons under the influence of elevated temperatures i.e. beyond a certain burial depth (Chapter 3). The depocentres of a sedimentary basin contain the maximum thickness of generative sedimentary rocks, and hence the maximum thickness of mature (or over-mature) source rocks (Pratsch, 1982,1983).Therefore, the effective depocentres of a sedimentary basin

146

Chapter 4

hydrocarbon migration directions

structure contours of basin f l o o r

I

I

B

basin axis

I

e f f e c t i v e depocentre 3

w p l e circular symmetrical basin No p r e f e r r e d hydrocarbon migration directions

b

I

A 1 w p l e circular asymmetrical basin P r e f e r r e d hydrocarbon migration t o w a r d s narrow concave side B o f the basin migration p r e f e r e n c e B over A

B

c

c

A c

Simple elonqate symmetrical basin P r e f e r r e d hydrocarbon migration t o w a r d s t h e long f l a n k s A and 0 o f the basin migration p r e f e r e n c e A and B over C

d

Simple elonqate asymmetrical basin P r e f e r r e d hydrocarbon migration t o w a r d s t h e long f l a n k s A and B However t h e l a r g e s t amount o f migratable hydrocarbons is available f o r miqration t o w a r d s side A

e

Simple elonqate symmetrical curved basin P r e f e r r e d hydrocarbon migration t o w a r d s concave long flank A migration preference A over 0 over C

f

Simple elonqate asymmetrical curved basin P r e f e r r e d hydrocarbon migration t o w a r d s concave long f l a n k A migration preference A over 0 over C

B

g

c

C

c

c

0

Composite linear symmetrical basin P r e f e r r e d hydrocarbon migration t o w a r d s c e n t r e o f common flanks migration preference A over B over C

h

Composite p a r a l l e l symmetrical basin P r e f e r r e d hydrocarbon migration t o w a r d s c e n t r e of common flanks migration preference A over 0 over C

Figure 4.8 Planar view of theoretical hydrostatic hydrocarbon migration patterns for simple and composite basin geometries (after Pratsch, 1982. Reprinted by permission from Erdol und Kohle, Erdgas, Petrochemie, Bd. 35, Heft 2).

Secondary hydrocarbon migration

147

can be considered as starting points for secondary hydrocarbon migration. Pratsch (1982,1983) assumes that the separate phase hydrocarbons migrate from the effective depocentres of the basin to its edges. Based on observations in many sedimentary basins Pratsch (1982,1983; Pratsch and Lawrence, 1982) concluded that the lateral hydrocarbon migration pattern in a basin is related to the geometry of that basin, or strictly speaking, is related to the geometry of the regional carrier reservoir rock - barrier rock interface. Pratsch (1982,1983; Pratsch and Lawrence, 1982) presented a classification of theoretical basin geometry types and their corresponding lateral hydrocarbon migration patterns (Figure 4.8). From these lateral migration patterns, those parts of the basin can be identified towards which the secondary hydrocarbon migration is focussed. The classification is based on the assumptions, that the carrier reservoir rocks and barrier rocks are continuous throughout the basin, the geometry of the carrier rock - barrier rock interface follows the geometry of the basin, the permeabilities of the individual rock units are constant, the pressure distribution is uniform, the source rock thickness is uniform, and kerogenhydrocarbon conversion rates are uniform. The lateral hydrocarbon migration patterns as shown in Pratsch’s classification will not be disturbed by the presence of local vertical escape ways for migrating hydrocarbons, as long as the carrier rock - barrier rock interfaces dip basinward, i.e. follow the general basin geometry. Facies changes, faults, fracture systems and salt diapirs may disrupt the lateral continuity of the individual carrier and barrier rocks. Vertical communcation between different carrier rocks by means of e.g. faults and fractures is probably of less frequent occurrence in hydrostatic basins than in hydrodynamic basins. This is because buoyancy forces of even a very high column of normally pressured oil or gas are inadequate to open fractures (Weber, 19871, while i n subsiding and filling basins and in otherwise tectonically active basins, high superhydrostatic groundwater pressures may open faults and fractures, and tectonically active faults may become migration paths for fluids (Section 2.1.3).In hydrostatic basins, faults may still play a role i n vertical migration, if they juxtapose carrier rocks from different stratigraphic horizon (Allan, 1989). Vertical hydrocarbon migration then takes place by a combination of cross-fault migration and updip migration (Allan, 1989). The length of the lateral hydrocarbon migration path is influenced by the hydrogeological framework of the basin. Tectonically stable basins composed of laterally continuous barrier rocks and carrier rocks dipping basinwards provide a favourable hydrogeological framework for long-distance lateral migration (e.g. the hydrogeological framework of cratonic basins is characterized by laterally continuous hydrogeological units). If the masses of hydrocarbons expelled from the source rocks and the secondary migration losses allow such long distance migration, the hydrocarbons may migrate as far as the basin edges. Any capillary pressure barrier (resulting from e.g.

148

Chapter 4

facies changes or faults) along the potential lateral migration path will shorten the actual length of secondary hydrocarbon migration. Under hydrostatic conditions the basin-wide secondary hydrocarbon migration patterns and consequently also the final distribution of the oil and gas accumulations in a sedimentary basin are closely linked to the stable basin geometry present during hydrocarbon expulsion from the source rocks.

4.3.4 Hydrodynamic secondary hydrocarbon migration Under hydrodynamic conditions, the transport of hydrocarbons from source rock to trapping positions can occur in three different ways, as separate phase hydrocarbons, as very finely dispersed hydrocarbons and as hydrocarbons in aqueous solution. During the peak phase of hydrocarbon expulsion (corresponding for oil expulsion from rich oil-prone source rocks to depths of approximately 2500 to 5000 m and for gas to depths of > 4000 m), the predominant form in which the hydrocarbons leave the source rock is probably continuous separate phase hydrocarbons (Chapter 3). After entering the carrier rock, the separate phase hydrocarbons may either become very finely dispersed in the groundwater o r stay in continuous separate phase. The expulsion of hydrocarbons in aqueous solution may occur during the early phase of hydrocarbon expulsion from good source rocks, and possibly during the entire phase of hydrocarbon generation in leaner source rocks. Under hydrodynamic conditions the geological and hydrogeological framework of the basin exerts a great influence on all three modes of secondary hydrocarbon migration. The fine-grained poorly permeable rocks in the subsurface resist the transmigration of separate phase hydrocarbons including the very finely dispersed hydrocarbons, because of the large capillary pressure gradients in the poorly permeable rocks. These poorly permeable rocks probably also resist throughflow of the hydrocarbons in aqueous solution by acting as semipermeable membranes. The actual hydrocarbon migration path will thus be restricted t o the permeable coarse-grained rocks (carrier rocks). The groundwater, however, may flow through the poorly permeable rocks. The direction that hydrocarbons in aqueous solution and hydrocarbons in very fine suspension migrate through these carrier rocks will be parallel t o the groundwater flow in these rocks. The dip directions of the barrier rocks will not influence the lateral migration directions of these two hydrocarbon manifestations. When the groundwater flow direction is downdip, the hydrocarbons in aqueous solution and in very fine suspension will also move in a downdip direction. Hence, the lateral migration pattern for hydrocarbons transported in these forms may be considered to be identical to the prevailing lateral groundwater flow pattern. In contrast, the migration direction of continuous separate phase hydrocarbons through a carrier rock is determined by the dip direction and angle of dip of the carrier rock - barrier rock interface, in addition to the density differences between hydrocarbons and water, and the

Secondary hydrocarbon migration

149

magnitude and direction of the net driving force for groundwater flow in the carrier rock. Section 4.1 showed that as a result of the buoyancy forces alone, the separate phase hydrocarbons will always migrate in an updip direction along the carrier rock - barrier rock interface perpendicular t o strike. These buoyancy forces will be greater along steeply dipping carrier rock - barrier rock interfaces. Hence, under similar hydrodynamic conditions the influence of groundwater flow on the direction of hydrocarbon migration will be more pronounced in horizontally layered basins than in basins composed of steeply dipping rocks (e.g. Davis, 1987). Because the gas-water density difference is greater than the oil-water density difference at shallower depths, the influence of groundwater flow will be stronger on the direction of the separate phase oil migration than on the direction of the separate phase gas migration at these depth levels. The system of hydrodynamic secondary hydrocarbon migration, whether the hydrocarbons move in separate phase, in very fine suspension o r in aqueous solution, is influenced by the porosity and permeability distribution in a sedimentary basin, and the magnitude and direction of the net driving force for groundwater flow. As a consequence, the different processes and associated forces that are responsible for the hydrodynamic conditions in a sedimentary basin also determine t o a greater or less extent the characteristics of the hydrocarbon migration system in a hydrodynamic basin (Sections 4.3.4.1,4.3.4.2 and 4.3.4.3).

4.3.4.1 Secondary hydrocarbon migration in actively filling and subsiding basins The dominant mechanism of pressure generation in a filling and subsiding basin probably is mechanical pressuring of groundwater due to sedimentary loading. The actual distribution of groundwater pressures and potentials is strongly influenced by the hydrogeological framework. This sedimentary loading in a subsiding basin leads to the development of the burial-induced groundwater flow system, which may consist of three interacting subsystems (Section 2.1,Figures 2.9 and 2.10). In shale-poor basins, and in shaly basins with subsidence rates not exceeding 0.1 - 1 mm per year, the shallow and intermediate subsystem of burial-induced groundwater flow can develop, while all three subsystems may prevail in rapidly subsiding basins. The shallow subsystem is characterized by cross-formational vertical upward flow of groundwater and near-hydrostatic pressure-depth gradients. In the intermediate subsystem, there is no cross-formational flow through compacting fine-grained rocks. The intermediate system is characterized by vertical upward and downward expulsion of water from compacting finegrained rocks and continuous lateral flow through relatively coarse-grained rocks (carrier-reservoir rocks) from the depocentre of the basin towards its edges. In the deep geopressured subsystem, restricted groundwater flow conditions prevail. Groundwater flow from the deep geopressured subsystem is

150

Chapter 4

either very slow and continuous or occurs as an episodic flow of groundwater focussed along distinct vertical pathways.

Hydrocarbons in aqueous solution In general, liquid hydrocarbons have a very low solubility in water (Section 3.2.1.1).The chances for expulsion from source rocks of liquid hydrocarbons dissolved in groundwater possibly are best at relatively shallow depths corresponding t o an early phase of oil generation. A t shallow depths in a sedimentary basin, the burial-induced groundwater flow is directed vertically upwards (Section 2.1.3). The light hydrocarbons expelled in aqueous solution by the source rocks in these shallow parts of the basin will, in theory, be transported along with this vertical upward groundwater flow until exsolution occurs o r further movement is impeded by the semipermeable membrane filtering by poorly permeable rocks. Compared with liquid hydrocarbons, natural gas hydrocarbons (principally methane) have relatively high solubilities in water. Methane is produced throughout the process of hydrocarbon generation from shallow depths of burial of the source rock t o great depths of burial, but principally during deep burial (> 4000 m). At the peak phase of gas expulsion, transport of gaseous hydrocarbons in aqueous solution is probably not important as an expulsion mechanisms. However, gaseous hydrocarbons may also become dissolved in groundwater in the carrier rocks after their expulsion from source rocks. According t o Demaison and Huizinga (1991; Sluijk and Nederlof, 1984) natural gas must continuously saturate the water in the carrier rock if it is to persist as a separate hydrocarbon phase during secondary migration. The migration of methane in aqueous solution may be affected by all three subsystems of burialinduced flow. The methane in aqueous solution in the deep subsystem will migrate vertically upwards along with the focussed flow of groundwater through e.g. faults, fracture systems and along salt diapirs. The sharply decreasing pressures and temperatures encountered along these vertical migration paths may force the gases out of solution. When, either directly after expulsion from the source rock, o r during later stages of migration, the hydrocarbons in aqueous solution reach the intermediate subsystem of burialinduced flow, the pattern of hydrocarbon gas migration through the carrier rocks will be parallel to the lateral groundwater flow pattern, directed from the basin’s depocentre towards its edges.

Hydrocarbons in very fine suspension The hydrocarbons expelled from the mature source rocks in separate phase, may initially occur in a very finely dispersed state. At depths corresponding t o the peak phase of hydrocarbon expulsion in actively filling and subsiding basins, the hydrodynamic condition is characterized by the intermediate o r the deep subsystem of burial-induced groundwater flow. Initially, the very finely dispersed hydrocarbons will move along with the burial-induced groundwater

Secondary hydrocarbon migration

151

flow. In theory, the secondary migration pattern for finely dispersed hydrocarbons will be identical with the burial-induced groundwater flow pattern (Section 2.1.3). The actual lengths of the migration paths of finely dispersed hydrocarbons are not indicated by these flow patterns, only the migration directions. The concentration of finely suspended hydrocarbons may gradually increase in the migration direction, increasing the coagulation of the hydrocarbons. The coagulated hydrocarbons will become subject to buoyancy forces and will thereafter migrate as continuous separate phase hydrocarbons. The migration pattern for hydrocarbons in very fine suspension at depths where hydrodynamic conditions are according to the intermediate subsystem of burial-induced flow, can be illustrated for the situation in simple compacting basins where the depocentres of the basin are also the effective depocentres containing mature source rocks (Figure 2.15). As the groundwater flow pattern in a simple compacting basin is radially outward from the depocentre of the basin t o its edges, after expulsion from the source rocks in the depocentre the very finely dispersed hydrocarbons will migrate through carrier rocks in a lateral direction away from the depocentres.

Separate phase hydrocarbons After expulsion from the source rocks during the peak phase of hydrocarbon generation, the separate phase hydrocarbons may also stay in continuous separate phase in the adjacent water-saturated carrier rocks. A t depths corresponding to the peak phases of hydrocarbon expulsion, intermediate or deep subsystems of burial-induced groundwater flow will prevail. Whether the magnitude and direction of the secondary separate phase hydrocarbon migration will deviate noticeably from those under hydrostatic conditions will depend on the magnitude and direction of the net driving force for groundwater flow in combination with the density differences between hydrocarbons and water and the geological and hydrogeological framework of the basin. In a deep geopressured subsystem of burial-induced flow, separate phase hydrocarbons expelled into a carrier rock overlain by a laterally continuous barrier rock probably stay close to the expelling source-rock because of restricted lateral migration conditions. As treated in Section 2.1.2, the lateral continuity of originally porous and permeable carrier rocks decreases with depth because of permeability loss, increasing heterogeneity of the rocks and/or tectonic elements. The very large vertical gradients in groundwater pressure that exist over the barrier rocks in the geopressured system (e.g. Figure 3.10) is the driving force for a focussed vertical upward escape of hydrocarbons from the geopressured zone through zones of seal failure. Focussed vertical migration of both hydrocarbons and groundwater can be expected to occur in e.g. rift basins and young deltaic basins, as observed e.g. in the Viking and Central Graben, North Sea (Buhrig, 1989 and Cayley, 1987, respectively), the Niger Delta of Nigeria (Weber et al., 1978;Weber, 1987; Figure 4.9)and the Gulf of Mexico Basin (Price, 1980a). The hydrocarbon migration system in the deep geopressured subsystem of burial-induced groundwater flow is strongly

Chapter 4

152

0

GAS

0

WATER

Figure 4.9 Schematic cross-section of a Nigerian field showing focussed vertical upward escape of hydrocarbons from a deep geopressured subsystem of burial-induced groundwater flow (from Weber, 1987. Reprinted by permission of Elsevier Science Publishers BV).

influenced by the hydrodynamic condition and clearly deviates from a theoretical hydrostatic migration system. Hydrocarbons expelled from source rocks at the level of the intermediate subsystem of burial-induced groundwater flow can be considered t o result from a theoretical hydrostatic buoyancy-driven hydrocarbon migration system and the intermediate subsystem of burial-induced flow. Both systems are strongly lithostratigraphically controlled. The poorly permeable fine-grained rocks in the intermediate subsystem of groundwater flow are effective barriers t o separate phase hydrocarbon migration not only due t o capillary pressure gradients opposing migration, but also because of hydrodynamic reasons: the groundwater potentials in the fine-grained rocks in this subsystem are larger than the groundwater potentials in adjacent more permeable coarse-grained rocks. The transport directions in both systems show lateral and vertical components of flow. When the starting points of the hydrocarbon migration and the burial-induced groundwater flow coincide in a sedimentary basin, the groundwater flow directions may be parallel t o the theoretical directions of hydrostatic hydrocarbon migration: the hydrodynamic hydrocarbon migration pattern may be equal to the hydrocarbon migration pattern under hydrostatic conditions. However, the total lengths of the hydrocarbon migration paths may differ from those under assumed hydrostatic conditions, as the hydrodynamic

Secondary hydrocarbon migration

153

condition also changes the trapping energy conditions for hydrocarbons (Chapter 5 ) . In a simple compacting basin, for instance, the hydrostatic buoyancy-induced pattern of hydrocarbon migration (Figure 4.8) and the burial-induced pattern of groundwater flow (Figure 2.15)are identical. Under hydrodynamic conditions in such a simple compacting basin, the directions of separate phase hydrocarbon migration are parallel to those under hydrostatic conditions. In a more complex basin, the theoretical pattern of hydrostatic hydrocarbon migration and the burial-induced pattern of groundwater flow will often not be identical. One reason may be that the location of the hydrocarbon-generating source rock does not coincide with the location of the basin’s depocentre that acts as starting point for burial-induced groundwater flow. In those parts of the basin where the burial-induced groundwater flow direction is not parallel to the theoretical direction of hydrostatic hydrocarbon migration, the direction of separate phase hydrocarbon migration under hydrodynamic conditions may deviate from that under assumed hydrostatic conditions. The secondary migration system of separate phase hydrocarbons in the intermediate subsystem of burial-induced groundwater flow is characterized by preponderantly lateral migration of hydrocarbons through carrier rocks with directions and lengths of the migration path that may deviate from those resulting from theoretical buoyancy-induced migration alone. Such lateral hydrocarbon migration can be expected to occur in shaly basins with moderate subsidence rates and at intermediate depth levels in rapidly subsiding basins. Magara (1978,1986,19871,amongst others, recognized the potential influence of lateral burial-induced groundwater flow on secondary hydrocarbon migration. During later stages of separate phase hydrocarbon migration the hydrocarbons may reach shallower parts of the compacting basin, where the shallow subsystem of burial-induced groundwater flow prevails and the groundwater flow is directed vertically upwards. In these shallow parts of the basin, the vertical upward groundwater flow and the buoyancy force act in the same direction. The ultimate direction of separate phase hydrocarbon migration is determined by the total magnitude of these two driving forces for hydrocarbon movement with respect t o the magnitude of the resistant force to hydrocarbon movement that is determined by the capillary pressure gradient in the fine-grained rocks. When the capillary pressure gradient in the finegrained rocks is still too high to be overcome by the two driving forces, the migration pattern of separate phase hydrocarbons will be stratigraphically controlled and will be identical t o the hydrostatic hydrocarbon migration pattern. Generally speaking, the largest influence of groundwater flow on both the length and direction of separate phase hydrocarbon migration is to be expected in areas where the largest differences in groundwater potential occur. In an actively filling and subsiding compacting basin large lateral and vertical

Chapter 4

154

potential differences can be expected near areas of relatively fast sedimentation (depocentres). Figure 4.10 schematically shows different features of secondary hydrocarbon migration in an actively filling and subsiding basin. 4.3.4.2 Secondary hydrocarbon migration in stable subaerial basins

In subaerial sedimentary basins, the secondary hydrocarbon migration may be influenced by gravity-induced cross-formational groundwater flow (Section 2.3). In theory, the gravity-induced groundwater flow may reach depths corresponding t o the peak zones of oil and gas generation. It should be remembered that when the generation of hydrocarbons results in abnormally high pressures in the zone of oil and gas formation, such a zone will be a barrier to groundwater flow, i.e. the condition of subsurface hydraulic continuity will not be fulfilled and consequently no cross-formational gravityinduced groundwater flow will be possible through the peak zone of hydrocarbon formation. When the gravity-induced groundwater flow systems do not reach the depths of the hydrocarbon-generating source rocks themselves, they may influence the hydrocarbon transport during later stages of migration. For instance: After an initial upward migration of the hydrocarbons as induced by other hydrocarbon migration mechanisms prevailing a t greater depths (e.g. buoyancy; relict or actual conditions of burial-induced flow) or after initial lateral migration from e.g. a subsiding part of the basin; After changed subsurface energy conditions as induced by tectonic movements, changes in climatic conditions, eustatic sealevel changes, erosional changes at the ground surface. Under changed subsurface conditions previously accumulated hydrocarbons transported under hydrostatic conditions o r by burial-induced forces may remigrate. The remigration may take place in the realm of gravity-induced groundwater flow. 1-

2-

,"I 5-

Shallow subsystem of bunal-induced groundwater flow Separate phase hydrocarbon migration is lateral in the

6-

7-

intermediate subsystem of burial-induced groundwater flow Lateral hydrocarbon migration focussed along unconformltles and through sandy, sky and limestone units

0-

20 km 1

OOo1

Deep eopressured subsystem of burial-induced groundwater flow: estricted lateral hydrocarbon migration;focussed upward escape of hydrocarbonsfrom gsopressured zone through zones of seal failure (faults, hydrofractured zones)

Figure 4.10 Cross-section showing hypothetical distribution of three subsystems of burialinduced groundwater flow and associated features of secondary hydrocarbon migration (geological cross-section of the Viking Graben, North Sea; adapted from Doligez e t al., 1987. Reprinted by permission by Graham and Trotman, Ltd.).

Secondury hydrocarbon migration

155

The directions and lengths of the hydrocarbon migration paths are influenced by the magnitude and directions of the net driving force for gravityinduced groundwater flow. The direction and magnitude of the net driving force for water flow in the carrier rocks depend on the characteristics of the prevailing local, intermediate or regional groundwater flow system, which in turn ultimately depend on the configuration of the basin’s ground surface topography. I n a n inhomogeneous basin with laterally extensive hydrogeological units, the regional flow tends to be focussed into units of relatively high permeability. In a single carrier rock opposing groundwater flow directions may be present, influencing the total lengths of the path of secondary hydrocarbon migration (Chapter 5 ) . The lateral component of gravity-induced groundwater flow will be directed from an area of recharge to an area of discharge. For a deep regional system, the flow will be directed from the highest upland recharge area t o the lowest discharge area (Figure 2.21). The recharge area of the groundwater flow system is characterized by downward flow of groundwater and associated subhydrostatic pressure-depth gradients, which oppose the buoyancy forces for separate phase hydrocarbon migration. In the discharge area the flow of groundwater is vertically upwards and associated with superhydrostatic pressure-depth gradients, which act in the same direction as the buoyancy forces. The starting point of secondary hydrocarbon migration, i.e. the location of mature source rocks, and the starting point of regional gravity-induced groundwater flow, i.e. an upland recharge area, are not logically related to each other and in general will not coincide. Generally speaking, the mature source rocks will be present below relatively low-lying areas, corresponding to the areas of discharge andlor the areas of midline of the regional gravity-induced groundwater flow systems. However, remigration of hydrocarbons may s t a r t in upland recharge areas, for instance after uplift of areas containing previously accumulated hydrocarbons. Hydrocarbons in aqueous solution The hydrocarbons in aqueous solution will be transported along with the gravity-induced groundwater flow prevailing in the permeable carrier rocks, in a predominantly lateral direction from an area of recharge to an area of discharge (Figure 2.21). Hydrocarbons in very fine suspension As long as the hydrocarbons occur in very fine suspension, they will follow the lateral groundwater flow directions through the carrier rocks from an area of recharge t o an area of discharge (Figure 2.21). Separate phase hydrocarbons The direction and length of the continuous separate phase hydrocarbons through the carrier rock are determined by the dip direction and angle of dip of

oil window

,

rn

basement

1

sedimentary f i l l mducing compaction

__--

potential source rock

*buoyancy-

area o f influence of buoyancy f o r c e

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\ ~ E q

topography

\\\ \\\ \\ \ \ \ \ \

\

\ \

potential l a t e r a l direction o f separate phase hydrocarbon migration assuming hydrostatic conditions l a t e r a l groundwater flow direction as induced by burial only, p o t e n t i a l l a t e r a l migration direction of hydrocarbons in aqueous solution and/or in very fine suspension induced by burial driven groundwater flow only l a t e r a l groundwater flow direction as induced by 'topography' only, p o t e n t i a l l a t e r a l migration direction o f hydrocarbons in aqueous solution and/or in very fine suspension induced by topography driven groundwater flow only

Figure 4.11 Schematic cross-section showing areas of influence of the different driving forces for hydrocarbon migration.

Secondary hydrocarbon migration

157

the carrier rock - barrier rock interface, and the hydrocarbon - water density differences, in addition to the magnitude and direction of the net driving force for groundwater flow. The largest influence of lateral gravity-induced flow in a single carrier rock can be expected in horizontally layered basins in areas where large lateral groundwater potential differences prevail, e.g. at shallow depths in areas of large topographic relief. In a horizontally layered basin, the separate phase hydrocarbons will migrate laterally towards a discharge area. In a simple subaquatic sedimentary basin with rocks dipping basinwards, which is uplifted at its edges or surrounded by areas of high topographic relief, the separate phase hydrocarbons moving updip from the basin centre towards its edges under the influence of buoyancy and eventually of burial-induced forces, will meet oppositely directed gravity-induced groundwater flow that will influence the total length of the hydrocarbon migration path (Figure 4.11). Different authors have indicated the relation between regional gravityinduced flow and the distribution of hydrocarbon accumulations. T6th (1980) presented field examples and a review from published literature showing qualitatively the relation between the gravity-induced groundwater flow pattern and known hydrocarbon accumulations in different parts of the world (Red Earth Region, Canada; Dzungarian Artesian Basin, China; Great Lowland Basin, Hungary; Surat Basin, Australia). An increasing number of studies on the relationship between gravity-induced groundwater flow and hydrocarbon accumulations have been published since (e.g. Zawisza, 1986, Lublin Synclinorium Poland; T6th and Corbet, 1987,Taber Area, Canada; Vugrinovich, 1988,Michigan Basin USA; Wells, 1988, Offshore Qatar; T6th and Otto, 1989, Upper Rhine Graben, Germany; Garven, 1989,Western Canada Sedimentary Basin; Bethke et al., 1991, Illinois Basin, USA). The results of the studies of Garven (1989)and Bethke et al., (1991)suggest that long distance lateral migration of hydrocarbons (> 100 km in intracratonic basins like the Western Canada Basin and Illinois Basin, respectively), can be explained by a basinwide gravity-induced groundwater flow focussing groundwater and hydrocarbons into laterally continuous hydrogeological units and providing an additional driving force to transport the hydrocarbons laterally across the basin. The relation between the location of known hydrocarbon accumulations and the regional hydrodynamic condition caused by the combined effects of burial- and gravity-induced groundwater flow, has been identified by several authors, e.g. in the Algerian Sahara and the Parentis Basin, France (Chiarelli, 1978;Chiarelli and Richy, 1984;Coustau et al., 1975;Makarov and Morozov, 1980; T6th, 1980),and in the Gippsland Basin Australia (Kuttan et al., 1986). 4.3.4.3 Secondary hydrocarbon migration in tectonically affected basins Tectonic processes may influence both the groundwater pressure condition and the hydrogeological framework in a basin (Section 2.21, and as a consequence may affect the driving force for hydrocarbon migration and the

158

Chapter 4

potential migration paths. The development of geopressured conditions in a basin may be enhanced by tectonic forces. Escape of groundwater and hydrocarbons from such tectonically geopressured zones probably occurs as a focussed vertical upward transport along fractures and active faults. In general, the tectonically-induced flow of groundwater is thought to occur as an episodic and focussed flow of groundwater directed away from zones of conversion and continental collision. The tectonically-induced lateral driving force for groundwater flow may enhance lateral migration of hydrocarbons focussed through available carrier rocks, away from the zones of convergence and continental collision. Moore et al. (1987, 1988)present an example of lateral secondary hydrocarbon migration in a tectonically active area, the Barbados Ridge Complex. Methanebearing groundwater has been observed at the Barbados Ridge Complex along and beneath the detachment zone separating the underthrusting Atlantic ocean crust and the overthrusting Caribbean plate (Moore et al., 1987, 1988; Figure 2.17). The methane is of thermogenic origin and probably has been generated from deeply underthrust source rocks (Moore et al., 1987, 1988). The length of the migration path of the methane, moving along with the tectonically induced flow of groundwater along the detachment zone (Section 2.21,has been inferred to be more than 25 km laterally (Moore et al., 1987).

4.4 Summary

A secondary hydrocarbon migration system is characterized by the masses and initial composition of petroleum (hydrocarbons) available for secondary migration, the three-dimensional migration pattern, the flux of migrating hydrocarbons and the migration losses. Secondary hydrocarbon migration systems are classified according to the dominant force or combination of forces affecting migration. In hydrostatic secondary hydrocarbon migration systems the separate phase hydrocarbons are moved by buoyancy forces, which are directed vertically upwards with a magnitude strongly dependent on hydrocarbon-water density differences and capillary forces, which are affected, amongst other things, by variations in pore size and are directed e.g. from fine-grained to coarse-grained rocks or towards open fractures. During secondary migration, separate phase hydrocarbons move through carrier rocks along discrete interconnected pathways because of the capillary effects. Hydrostatic hydrocarbon migration is directed laterally updip along a carrier rock-barrier rock interface. The basinwide hydrocarbon migration pattern is related to the stable basin geometry, or

Secondary hydrocarbon migration

159

strictly speaking, to the regional interface between the carrier rock and barrier rock. Preferred migration of hydrocarbons takes place from the effective depocentre of the basin towards those parts of the basin showing the largest dips. In hydrodynamic secondary hydrocarbon migration systems, the hydrodynamic conditions in a basin affect the migration of hydrocarbons. The hydrocarbons may move in separate phase, very fine dispersion or in aqueous solution. The influence of the hydrodynamic conditions on hydrocarbon migration increases with increasing magnitudes of the net driving forces for groundwater flow. The magnitude of the net driving force for lateral groundwater flow may be comparable to the lateral updip component of the buoyancy force. The vertically directed net driving force for groundwater flow may be significantly larger than buoyancy forces. In a subsiding and filling sedimentary basin, three systems of hydrocarbon migration corresponding to the three interrelated burial-induced hydrodynamic conditions in the basin, can be distinguished. In the deep geopressured subsystem of burial-induced flow, the lateral hydrocarbon migration is restricted and migration from the subsystem occurs mainly as a focussed vertical migration of hydrocarbons (and water) through zones of seal failure. In the intermediate subsystem of burial-induced groundwater flow, hydrocarbons migrate laterally through carrier rocks. In a simple compacting basin, the hydrostatic pattern of hydrocarbon migration and the burial-induced pattern of groundwater flow are identical and directed from the basin’s depocentre towards its edges. The hydrodynamic condition may lengthen the migration path. The shallow subsystem of burial-induced groundwater flow is characterized by a vertically upward directed net driving force for groundwater flow, and near hydrostatic pressure-depth gradients. As a consequence, the pattern of separate phase hydrocarbon migration in the shallow subsystem will not deviate much from a hydrostatic migration pattern. In stable subaerial horizontally layered basins with a large relief of the ground surface, the gravity-induced flow is focussed through regional carrier rocks towards discharge areas. This gravity-induced groundwater flow condition enhances lateral migration of hydrocarbons towards groundwater discharge areas. The tectonically-induced lateral driving force for groundwater flow in basins near zones of plate convergence and continental collision may enhance lateral migration of hydrocarbons through available carrier rocks in the basins away from the active zones. Escape of groundwater and hydrocarbons from tectonically geopressured zones in a basin occurs probably as a focussed vertical upward transport along fractures and active faults.

160

Chapter 4

The length of the path of secondary hydrocarbon migration may be a few metres to hundreds of kilometres laterally, and a few metres to kilometres vertically. The lateral flux of separate phase hydrocarbon migration through carrier rocks at depths of approximately 3 km, probably is in the order of millimetres to centimetres per year. The flux of hydrocarbons in aqueous solution is in the same order of magnitude as the flux for groundwater. The loss of separate phase hydrocarbons during secondary migration is indicated by the apparent residual saturation of hydrocarbons, which is on average in the order of 1 - 3% of the total available pore space of the carrier rocks through which hydrocarbons have migrated.

161

CHAPTER 5 HYDROCARBON ACCUMULATION, ENTRAPMENT AND PRESERVATION

The process of migration may lead to focussed movement of hydrocarbons into economic accumulations. The secondary migration of hydrocarbons may occur under hydrostatic o r hydrodynamic conditions. Under hydrostatic conditions, the hydrocarbons migrate through the water-saturated carrierreservoir rocks as separate phase hydrocarbons. Under hydrodynamic conditions, the hydrocarbons may be transported in continuous separate phase, in suspension o r in aqueous solution. Under both hydrostatic and hydrodynamic conditions, the hydrocarbons ultimately appear as separate phase hydrocarbons before they can accumulate in a trap (Tissot and Welte, 1984). Separate phase hydrocarbons migrate in the direction of their decreasing potential energies. Under hydrostatic conditions the separate phase hydrocarbons are driven by the vertical upward directed buoyancy forces. The hydrocarbon equipotential surfaces are horizontal under these conditions. The hydrocarbons will migrate through the carrier-reservoir rock in an upward direction, generally laterally updip along a vertical barrier boundary with a capillary pressure gradient too high to be overcome by the buoyancy forces. When lateral upward hydrocarbon migration in the carrier reservoir rock is resisted by a lateral capillary pressure boundary, the hydrocarbons will become trapped in the reservoir rock. The configuration of rocks, or rocks and faults, impermeable t o hydrocarbons, partly enveloping the reservoir so as to prevent escape of accumulating, o r accumulated, hydrocarbons is known as a trap. Various terms that are generally used to describe a trap are given in Figure 5.1. A trap may contain oil, gas or both. Where separate oil and gas phases occur together in the same trap, the gas overlies the oil because it is less dense. The oil-water or gas-water contact is the level below which all pores are completely filled with water. The hydrocarbon-water contact is an equipotential surface. Under hydrostatic conditions, hydrocarbons may accumulate in hydrostatic traps, which include structural traps, stratigraphic traps and combination traps (Section 5.1).

Chapter 5

clos

edge water--bottorn I

water-

I

-edge

water

Figure 5.1 Cross-section through a trap (after Elements of Petroleum Geology, by Robert C. Selley. Copyright (0)1985 by W.H. Freeman and Company. Reprinted by permission).

Hydrodynamic conditions influence the system of hydrocarbon migration in a basin, i.e. the volumes of hydrocarbons available for entrapment in a certain part of the basin, and the trapping energy conditions in the basin, i.e. the location of potential trapping positions and the sealing capacity of rocks and faults (Sections 5.2 and 5.3). The preservation of hydrocarbons accumulated in a trap that is no longer replenished, depends on the type of trap, the type of accumulated hydrocarbon and the subsequent geological and associated hydrodynamic evolution of the sedimentary basin (Section 5.4).

5.1

Hydrocarbon accumulation and entrapment under hydrostatic conditions

The sealing capacity of a rock under hydrostatic conditions is determined by the minimum hydrocarbon-water displacement pressure of the rock, which depends on the radius of the largest connected pore throats in the rock and the oil-water and gas-water interfacial tensions, and in addition on the densities of groundwater and hydrocarbons accumulating in the adjacent reservoir rock. The maximum height of an oil or gas column that can accumulate below a seal is given by Equation 4.17 (Section 4.1.3)

Hydrocarbon accumulation, entrapment and preservation

163

The sealing capacity of a rock changes with depth. This is because the characteristics of the rock change with depth (e.g. the porosities and permeabilities decrease with depth), the interfacial tensions of oil and gas change (Section 4.3.1)and the densities of groundwater, oil and gas change (Section 4.3.1).At shallower depths (< 2 km) the gas-water interfacial tension of gas is greater than the oil-water interfacial tension, while at depths of more than > 2 km the gas-water interfacial tension is similar t o the oil-water interfacial tension (Section 4.3.1). Effective seals for hydrocarbon accumulations are typically thick, laterally continuous, ductile rocks with high hydrocarbon-water displacement pressures (Downey, 1984). The most common seal lithologies are evaporites (rocksalt, anhydrite) and fine-grained clastics and organic-rich rocks (organicrich shales, i.e. potential source rocks; clay shales; clays), which have thicknesses of tens to hundreds of metres (Grunau, 1987).Seals do not need to be thick to be effective, as long as they are laterally continuous (Allen and Allen, 1990).Thin seals are less favourable for creating a trap, however, because there is a low probability that a sealing layer of only a few centimetres thick could be Cross sealing mechanisms

CHARACTERISTICS

\\

I

PROCESSES cataclasis clay smearing clay injection

cataclasis clay smearing cla injection lelhpar weatherinQ clay mineral lormafion

shearing water flow

dia enesis (catite preci itation clay mineral Pormation)

Heavy h drocarbon dration

hydrocarbon migration (liltration increases the sealing properties)

Figure 5.2 Cross-sealing mechanisms (from Nybakken, 1991. Reprinted by permission of the European Association of Exploration Geophysicists).

Chapter 5

164

continuous, unbroken, unbreached and maintain stable lithic character over a sizable accumulation (Downey, 1984). Fault-related seals can be subdivided in sealing faults S.S. and juxtaposition faults (Watts, 1987). In sealing faults s.s., the fault plane itself is laterally impermeable to hydrocarbons. The sealing capacity of a fault zone to hydrocarbon migration across fault may increase e.g. by clay smearing, clay injection, grain grushing and diagenesis (Nybakken, 1991) (Figure 5.2). The lateral sealing capacity of a juxtaposition fault depends upon the juxtaposition of rocks of different sealing capacity, e.g. reservoir rocks and barrier rocks, along the fault plane. Allan (1989) investigated the trapping potential of faults by virtue of stratigraphic juxtaposition assuming the fault itself is not sealing and is not an open conduit (Figure 5.3). In a hydrostatic basin, i.e. in a tectonically stable basin where the groundwater pressure distribution is hydrostatic, the fault planes themselves probably do not offer vertical pathways to migrating hydrocarbons. Under hydrostatic conditions three different types of traps are generally distinguished: structural traps, stratigraphic traps and combination traps (e.g. Selley, 1985; Allen and Allen, 1990). Structural traps are traps whose geometry is formed by tectonic, diapiric, gravitational and compactional processes, e.g. by folding (fold traps: compressional and compactional anticlines, Figure 5.41, faulting (fault traps, Figure 5.5; b and c in Figure 5.61, and the upward movement of sediments that are less dense than those overlying them (Diapiric traps; Figure 5.6). Stratigraphic traps are traps whose geometry is formed by changes in lithology. The lithological variations may be depositional (the trap geometry is related t o sedimentary facies changes, e.g. pinchouts, channels, bars, reefs in Figure 5.6) or postdepositional (e.g. the trap geometry is related to unconformity surfaces and diagenetic changes, Figure 5.7). The diagenetic

2000

1

Hangingwall reservoirs Footwall reservoirs

Figure 5.3 ‘Allan’ fault-plane section showing intersection of reservoir rocks in footwall and hanging wall to the fault plane. The intersections control the cross-fault spillpoints, where hydrocarbons migrate across the fault plane moving to higher structural levels (from Allen and Allen, 1990. Reprinted by permission of Blackwell Scientific Publications Ltd.).

Hydrocarbon accumulation, entrapment and preservation

0

5

165

10 km

Figure 5.4 Cross-section of a structural trap (Forties field, North Sea): a compactional anticline draped over an old basement high (from Elements of Petroleum Geology, by Robert C. Selley. Copyright (0)1985 by W.H. Freeman and Company. Reprinted by permission).

fault offset,

structural closure

pinch out, fault offset

Truncation pinch out, structural closure

e.g. Statfjord N

e.g. Snorre

closure e.g. Snorre Statfjord 0

e.g. Tordis Snorre V

\

C-field

\

Figure 5.5 Hydrocarbon traps in the Tampen Spur Block 34/7,North Sea (from Nybakken, 1991. Reprinted by permission of the European Association of Exploration Geophysicists).

166

Chapter 5

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Figure 5.6 Cross-section showing the various types of trap that may be associated with salt movement: domal trap (A); fault traps (B and C ) ; pinchout traps (D); turtle-back o r sedimentary anticline (El; truncation trap (Ff(from Elements of Petroleum Geology, by Robert C. Selley. Copyright (0) 1985 by W.H. Freeman and Company. Reprinted by permission).

traps not only result from mineral diagenesis, but also from biodegradation of petroleum (tar mats), phase changes t o petroleum gas (gas hydrates) and interstitial water (permafrost). Combination traps are traps formed by a combination of two or more of the above-mentioned processes. Jenyon (1990) distinguishes combination traps and complex traps. In Jenyon’s classification complex traps are those occurring in highly folded and thrust-faulted belts, while combination traps are those that involve strong structural and stratigraphic elements. The hydrocarbons migrating into the water-saturated reservoir trap will first enter the layers of the reservoir rock with the largest pores. As more and more hydrocarbons fill the trap, the buoyancy pressure exerted by the hydrocarbon increases with the growing height of the interconnected hydrocarbon stringers and will be able t o overcome the larger capillary pressure of the smaller water-filled pores (England et al., 1987). Since exit from the trap is prevented by the overlying barrier rock, fresh hydrocarbons entering the trap will force the previously trapped hydrocarbons into progressively smaller pores (Ruckheim, 1989). The hydrocarbons accumulating in the reservoir trap will not displace all of the pore water. The degree of hydrocarbon saturation of a reservoir trap depends largely on the dualism between the driving force for hydrocarbon movement, and the resisting force of capillary pressures (Tissot and Welte, 1984). Under hydrostatic conditions a maximum hydrocarbon saturation is reached in the upper part of the reservoir trap. After a long period of exposure to accumulated oils, the wettability of the porous reservoir rock may be changed from water-wet to oil-wet (Winter, 1987). A

Hydrocarbon accumulation, entrapment and preservation

167

transition zone with increasingly lower hydrocarbon saturation separates the hydrocarbon accumulation from the zone of complete water saturation. Only the largest pores are hydrocarbon filled near the base of the trap. In a hydrostatic trap, the oil-water and gas-water contacts are generally horizontal, because the equipotential surfaces for oil and gas are horizontal under hydrostatic conditions. Irregular contacts may be observed as a result of - capillary effects resulting from pore size differences in the reservoir. This is because water rises higher in the relatively fine-grained part of the reservoir than in the coarse-grained part, because of capillary attraction. - tilting of the trap after it was filled with hydrocarbons, and a hydrocarbonwater contact that could not adjust itself to a new horizontal level. The maximum height of a hydrocarbon column that can be contained in a hydrostatic trap is determined by the sealing capacity and geometry of the rocks, or rocks and faults that form the trap. When the vertical distance from crest to spill plane of the trap (Figure 5.1) is less than the maximum height of the hydrocarbon column z, (Equation 4.171,the accumulating hydrocarbons may fill the trap t o its spillpoint. As hydrocarbons continue to migrate into the

‘Uncemented

sand A

Meteoric water

Cemented sand

‘Cementcd limestone

‘Porous leached limestone

B

h \ 3

3 u

Degraded

011

acts as

sealI inhibiting further

migration

C

Figure 5.7 Cross-sections showing configurations for diagenetic stratigraphic traps caused by: cementation (A), solution (B) and shallow oil degradation (C) (from Elements of Petroleum Geology, by Robert C. Selley. Copyright (0)1985 by W.H.Freeman and Company. Reprinted by permission).

168

Chapter 5

trap, excess hydrocarbons will spill updip out of the trap. When the vertical distance from crest to spill plane exceeds zc, the trap cannot become filled to its spillpoint, because excess hydrocarbons will leak vertically through the barrier rock. Along a hydrocarbon migration route with a series of traps that are spilling hydrocarbons, there is a potential for differential entrapment for oil and gas, provided that both oil and gas are present as separate phases. A distinction can be made between spill differential entrapment and leak differential entrapment (Schowalter, 1979). Because of spill differential entrapment, gas may be trapped downdip from oil along a migration path with successive traps that spill updip (Figure 5.8). In contrast, gas may be trapped updip from oil because of leak differential entrapment (Figure 5.8). Barrier rocks that have inadequate sealing capacities for trapping hydrocarbons according to Equation 4.17, may form a kinetic trap, provided that hydrocarbons are supplied to the trap faster than they can leak away (e.g. Waples, 1985).

Figure 5.8 Spill differential entrapment of oil and gas according to Gussow (1954) (top); Leak differential entrapment of oil and gas (bottom) (after Schowalter, 1979. Reprinted by permission of the American Association of Petroleum Geologists).

Hydrocarbon accumulation, entrapment and preservation

5.2

Hydrocarbon accumulation hydrodynamic conditions

and

entrapment

169

under

Hydrodynamic conditions affect the sealing capacity of a rock or fault, and consequently influence the holding capacity for hydrocarbons of hydrostatic structural, stratigraphic and combination traps. In addition, hydrodynamic conditions may create additional regions of minimum potential energy for separate phase hydrocarbons, i.e. purely hydrodynamic trapping positions. Hubbert (1967)described a trap for either oil or gas as an underground region of low potential for the respective fluid, which is either completely enclosed by equipotential surfaces and regions of higher potential, or else jointly enclosed by higher equipotential surfaces and an impermeable boundary. The potential of a unit mass of separate phase hydrocarbons in water-saturated rock under hydrodynamic conditions is given by

which can be rewritten as

(5.2)

As outlined in Chapter 4, the net driving force for separate phase hydrocarbon migration is (Equation 4.11).

Equations 5.1 and 5.2 show that regions of low potential for hydrocarbons, i.e. favourable regions for accumulation and entrapment of hydrocarbons, are created by the combined influence of buoyancy forces, net driving forces for groundwater flow and capillary forces. The net driving force for groundwater flow and the capillary pressure gradient, or a combination of both, may enhance, decrease o r stop buoyancy-induced migration of hydrocarbons. As a result of hydrodynamic conditions, the trapping potential of conventional hydrostatic seals may change.

Hydrodynamic influence on holding capacity of conventional hydrostatic traps Separate phase hydrocarbons introduced into a conventional hydrostatic trap, move against the hydrostatic sealing surface, e.g. a carrier rock-barrier

170

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rock interface. Under hydrostatic conditions, the potential of the hydrocarbons in the barrier rock is much larger than that in the carrier rock, because of the larger capillary pressures in the barrier rock, thus resisting further movement of the hydrocarbons. Under most hydrodynamic subsurface conditions, the magnitude, and often the direction of grad $wchanges sharply at an interface between rocks of different permeability, i.e. at a carrier rock-barrier rock interface (Chapter 2). In a horizontally layered basin, the groundwater potential gradients in barrier rocks are vertically directed, while those in carrier-reservoir rocks may be laterally or vertically directed. The abruptly increasing or decreasing groundwater potentials across a carrier rock-barrier rock interface directly influence the magnitude of the difference in hydrocarbon potentials in both rocks, i.e. influence the sealing capacity of the barrier rock. A vertically downward directed groundwater potential gradient in a barrier rock will increase its sealing capacity. Significant influences on the sealing capacity of fine-grained rocks can be expected to occur in parts of groundwater flow systems with large groundwater potential gradients over these rocks. Large vertical groundwater potential gradients occur e.g. over laterally extensive lowpermeable rocks in the recharge and discharge areas of gravity-induced groundwater flow systems in subaerial basins and in the intermediate and deep subsystems of burial-induced groundwater flow in filling and subsiding basins. Large lateral groundwater potential gradients can be expected to occur across sealing faults S.S. crossing regional carrier rocks and across juxtaposition faults in e.g. the deep geopressured subsystem of burial-induced groundwater flow. Under the assumption that the capillary pressure gradient across the carrier rock-barrier rock interface is the only significant resistant force affecting hydrocarbon accumulation in a conventional hydrostatic trap, i.e. the influence of the hydrodynamic condition in the barrier rock on its sealing capacity can be considered to be negligible, the maximum height of the hydrocarbon column below the barrier rock can be given by Equation 4.22

where Ew = net driving force for vertical groundwater flow in the carrierreservoir rock.

A vertically upward directed component of the net driving force for groundwater flow in the carrier-reservoir rock will increase the upward directed driving force for hydrocarbon migration and as a consequence will diminish the maximum height of the hydrocarbon column that can accumulate below a hydrostatic top seal, or will cause seal failure leaving the hydrostatic trap empty by forcing the hydrocarbons through the seal. A

Hydrocarbon accumulation, entrapment and preservation

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vertically downward directed component of the net driving force for groundwater flow in the carrier-reservoir rock will increase the maximum height of the hydrocarbon column that can be trapped in a conventional hydrostatic trap or may even create a hydrodynamic trap in a location without hydrostatic trapping conditions. In recharge and discharge areas of gravityinduced flow systems and in the shallow and deep subsystems of burialinduced flow in layered sedimentary basins, the vertical net driving forces for groundwater flow in adjacent carrier and barrier rocks act in the same direction, thus reinforcing their influence on the sealing capacity of the barrier rocks. The hydrodynamic holding capacity of conventional hydrostatic traps is not only determined by the direct hydrodynamic influence on the sealing characteristics of the barrier rocks, or barrier rocks and faults, but also combined influence of the geometry of the trap and the hydrodynamic condition in the carrier-reservoir rock. This can be illustrated by looking at the hydrodynamic influence on the position of a hydrocarbon accumulation in a conventional hydrostatic trap. Under vertical groundwater flow conditions, the equipotential surfaces for groundwater and separate phase hydrocarbons are horizontal and the hydrocarbons may move into a conventional hydrostatic trap. As the hydrocarbon equipotential surfaces are horizontal, the oil-water and gas-water contacts in the trap will also be horizontal. In areas with non-vertical groundwater flow through the carrier-reservoir rock, the equipotential surfaces for oil and gas are tilted downwards in the direction of the net driving force for groundwater flow. The angle of tilt for the gas or oil equipotential surface is given by Hubbert (1953) (see Figure 5.9) as (5.3) This angle of tilt equals the angle of tilt for the corresponding gas-water or oil-water contacts in a hydrocarbon accumulation. The larger the horizontal hydraulic gradient AhJAx in the carrier-reservoir rock, the larger the angle of tilt of the hydrocarbon-water contact, i.e. the larger the angle of tilt of the hydrocarbon equipotential surfaces. The density ratio p,,/(p, - phc) is a tilt amplification factor, which expresses the ratio of the tilt of the hydrocarbonwater interface, AdAx, to the hydraulic gradient, AhJAx. This factor increases with the density of the hydrocarbon and is therefore greater for oil than for gas (for pw = 1100 kg m3, po= 600 kg m3 and p = 200 kg ma, pJ(pw - phc) is 2.2 and 1.2 respectively). The influence of different hydrocarbon densities and increasing hydraulic gradients on the angle of tilt of the hydrocarbon-water

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II

Ax

II

water manometers

hydrocarbon

Figure 5.9 Relation between the angle of tilt (tan a) of the hydrocarbon-water contact and the horizontal hydraulic gradient AhJAx (after Hubbert, 1953. Reprinted by permission of the American Association of Petroleum Geologists).

contact in a trap is illustrated in Figure 5.10. The three configurations 8, h, and

c in Figure 5.10 could represent the conditions under which an oil of given density would be trapped by a weak, B moderate or, c strong groundwater flow through the carrier-reservoir rock. Alternatively, when the groundwater flow conditions are the same in each case, they could also represent the conditions under which 2 light, h medium or heavy oil would be trapped. Figure 5.10 also shows that hydrocarbons can only be trapped in a hydrodynamic environment by a certain permeability boundary if its dip downstream is steeper than the angle of tilt of the hydrocarbon equipotential surface. According t o Hubbert (1967), considering hydrodynamic conditions in the carrier-reservoir rock the number of permutations of lithological and hydrodynamic conditions, and of oil and gas densities that can combine t o produce hydrocarbon traps is unlimited. Hubbert distinguished two groups of traps: 1. Those that occur in conventionally closed lithological structures (i.e. in hydrostatic traps). In these traps the hydrocarbon-water contact may have any degree of tilt from the horizontal t o the maximum dip of the barrier boundary at the downstream side of the closure. Although hydrocarbons may become trapped in the conventional hydrostatic traps of sufficient sealing capacity, the hydrocarbon accumulation is not necessarily present in the same position within the trap, as its actual position depends on the hydrodynamic condition in the carrier-reservoir rock (Figure 5.10).

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Figure 5.10 Three types of oil and gas accumulation in a folded reservoir rock under hydrodynamic conditions (after Hubbert, 1953. Reprinted by permission of the American Association of Petroleum Geologists).

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In addition, when the closing dip of a hydrostatic trap in the downstream direction is less than the angle of tilt of the hydrocarbon equipotential surface, the closed structure will not hold hydrocarbons under the prevailing hydrodynamic conditions. 2. Those that occur in structures without a hydrostatic closure (i.e. pure hydrodynamic traps).

Hydrodynamic traps Vertically downward directed net driving forces for groundwater flow in a layered sedimentary basin may increase the resistant force to hydrocarbon movement of certain rock layers in such a way as to make them impermeable to hydrocarbons, creating hydrodynamic trapping possibilities. Lateral changes in permeability of a carrier-reservoir rock (resulting from e.g. stratigraphic changes, diagenetic changes or structural features) that are not large enough to entrap hydrocarbons by capillary forces alone, may become sites for hydrodynamic traps. This latter situation will occur when a downdip directed driving force for groundwater flow will increase the sealing capacity of the relatively poorly-permeable part of the rock (e.g. Hubbert, 1967; Dahlberg, 1982; Figure 5.11). Hubbert (1967) presented examples of the combined influence of different hydrodynamic conditions and different geometries of the upper boundary of a carrier-reservoir rock, like anticlinal noses, structural terraces and homoclinal dips, on the position and capacity of hydrodynamic traps (Figure 5.12). As shown in Section 4.2.1,the lateral updip buoyancy-induced migration of hydrocarbons in a dipping homogeneous carrier-reservoir rock can be stopped, merely by a downdip directed driving force for groundwater flow. According t o Nyland (19911, the absence of hydrocarbons in presently overpressured reservoir rocks in the Haltenbanken area on the Norwegian shelf is partly explained by the high pressures acting as a migration barrier for late generated oil. T6th (1980) considered a more regional scale than Hubbert (1953, 19671, trying t o link locations of hydrocarbon accumulations with groundwater flow characteristics (in T6th’s case, especially those that are gravity-driven). He studied these relations in different areas, including the Red Earth Region in Alberta, Canada; Parentis Artesian Basin, France; Great Lowland Artesian Basin, Hungary; and The Gulf. T6th observed that the hydrocarbon accumulations in these areas were preferentially associated with particular parts of gravity-driven cross-formational groundwater flow systems. Generally, the frequency of hydrocarbon accumulations was observed to increase and be maximum in areas of groundwater discharge and in hydraulically stagnant zones. The discharge zones and associated stagnant zones are zones of regional energy minima for groundwater and may coincide with zones of energy minima for separate phase hydrocarbons, i.e. with potential trapping zones. However, the zones of minimum energy for groundwater and hydrocarbons

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z+l4Az ztl3Az z+12Az z + l 1Az z+lOAz z+9Az Z+8AZ

a

Direction o f groundwater flow is downdip: oil w i l l be trapped against upper boundary of reservoir rock lfrom Hubbert. 1967)

Z+lLAZ z+13Az

z+l2Az z + l lAz z+lOAz z+9Az Zt8AZ

b

Direction o f groundwater f l o w

is

updip o i l w i l l be moving updip no oil trap

is

formed

Figure 5.1 1 Cross-section of homoclinally dipping carrier-reservoir rock with variable permeability, showing potential oil migration directions and trapping positions for different directions of groundwater flow (after Hubbert, 1967).

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a

Groundwater f l o w direction is downdip

b

Groundwater f l o w direction i s downdip Groundwater f l o w velocity b < a

z Z+ Z hZ

flow direttion

c

L Az !+~Az ,z+ZAZ +Az

Groundwater f l o w direction i s updip no p o t e n t i a l 0 1 1 t r a p p i n g p o s i t i o n

Figure 5.12 Cross-section of isotropic carrier-reservoir rock showing potential oil migration directions and trapping positions for different groundwater flow conditions.

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will not always coincide, because the subsurface geological (structural, lithostratigraphic) setting also influences the position of minimum energy for separate phase hydrocarbons: In the stagnant zones, the groundwater flow is negligible, and the separate phase hydrocarbons introduced into these zones, will be moved by vertically upward directed buoyancy forces alone. In discharge areas, the groundwater flow is vertically upwards and consequently the net driving force for separate phase hydrocarbons is directed vertically upwards. Hence, the separate phase hydrocarbons in the discharge areas and in the adjacent stagnant zones will become trapped in available hydrostatic traps of sufEcient sealing capacity. When no hydrostatic traps are available, the

source rock, barrier rock, aquitard

. . C.

reservoir rock, carrier rock, aquifer migrating hydrocarbons groundwater flow line o i l accumulation

Figure 5.13 Cross-section of a horizontally layered drainage basin showing positions of hydraulic traps in connection with the gravity-induced groundwater flow systems (modified after Tbth, 1980. Reprinted by permission of the American Association of Petroleum Geologists).

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hydrocarbons may still accumulate in the area, when the reservoir rock barrier rock interface is horizontal. In this situation, lateral movement of hydrocarbons out of the discharge zone will be impeded by the oppositely directed hydrodynamic forces (i.e. the oppositely directed net driving forces for hydrocarbon movement on both sides of the discharge zone), and the hydrocarbons will become trapped against the horizontal upper boundary of the reservoir rock. These purely hydrodynamic trapping positions may be considered as hydraulic traps, a term introduced by T6th (1980) (Figure 5.13). Actually, T6th uses this term in a wider meaning, i.e. for the quasistagnant regions between oppositely directed groundwater flow systems. However, when no hydrostatic traps are available and the reservoir rock - barrier rock interface dips homoclinally, the separate phase hydrocarbons will only become trapped in the stagnant o r discharge zone if the downdip directed driving force of groundwater flow outside these zones is strong enough to restrict the continuation of updip separate phase hydrocarbon movement. More generally speaking, when zones between oppositely directed groundwater flow systems occur in horizontal parts of a sedimentary basin, hydrocarbons will become trapped against the horizontal upper boundary of the carrier-reservoir rock, because lateral movement out of the discharge zone will be impeded by the oppositely directed hydrodynamic forces. Zones between oppositely directed groundwater flow systems occur e.g. in stable subaerial basins, in filling and subsiding basins with more than one depocentre and along the borders of e.g. subaerial parts of basins. In these border zones, landward directed burialinduced groundwater flow from the subaquatic part of a sedimentary basin may meet oppositely directed gravity-induced groundwater flow from the continental part of the basin.

5.3

Hydrocarbon accumulation and entrapment in hydrodynamic sedimentary basins

Each type of groundwater flow system that may develop in a sedimentary basin is characterized by a specific distribution of the magnitude and direction of the net driving force for groundwater flow (Chapter 2). As a consequence, each groundwater flow system will modify the accumulation and trapping conditions for hydrocarbons in a certain basin in a specific way in comparison with theoretical hydrostatic conditions for that basin.

5.3.1

Accumulation and entrapment in actively filling and subsiding basins

The shallow subsystem of burial-induced groundwater flow is characterized by cross-formational vertical upward flow of groundwater and near-hydrostatic pressure-depth gradients. In comparison with hydrostatic conditions, the

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sealing capacity of fine-grained barrier rocks will be slightly smaller, because of the vertically upward directed net driving forces for groundwater flow. This potential influence of the shallow subsystem of groundwater flow will be largest near the basin’s depocentre. The intermediate subsystem of burial-induced groundwater flow is characterized by vertical upward and downward expulsion of water from compacting fine-grained rocks and continuous lateral flow through carrierreservoir rocks. The groundwater potential in the fine-grained rocks may be considerably larger than in adjacent coarse-grained rocks, thus increasing the sealing capacity of these fine-grained rocks. In the Smorbukk gas condensate field in the Haltenbanken area, Norway, the hydrocarbons are trapped in a near-hydrostatic Jurassic sandstone reservoir below burial-induced overpressured Cretaceous shales (Ungerer et al., 1987a). The Norwegian Oseberg oil field on the eastern side of the Viking Graben, North Sea, is another example of the efficient sealing capacity of overpressured rocks in an intermediate subsystem of burial-induced flow. In the Oseberg field the groundwater pressures in the sandstone reservoir rock of the Jurassic Brent Group are less than those in the overlying barrier rock consisting of a thin Cretaceous sequence of marls and sandstones (Doligez et al., 1987). In a geometrically simple basin, in which the sedimentary rocks dip towards the basin’s depocentre, the lateral flow of groundwater is directed from the depocentre to the basin’s edges and will be parallel to the directions of secondary hydrocarbon migration as induced by buoyancy forces alone. Parts of a basin, where the directions of hydrostatic hydrocarbon migration and of groundwater flow are parallel can be considered as less favourable for hydrocarbon entrapment. Theoretically, in such a hydrodynamic and geometrically simple basin, the hydrocarbons may accumulate below the finegrained rocks of hydrodynamically increased sealing capacity a t greater lateral distances from the depocentre than in a comparable hydrostatic basin. In subsiding and filling basins with a more complex hydrogeological framework, the lateral net driving force for groundwater flow in carrier-reservoir rocks, as directed from the basin’s depocentre towards its edges, may also oppose the theoretical hydrostatic migration directions in those rocks, and may consequently increase the lateral sealing capacity of carrier rocks with variable porosities and permeabilities or cross-formational tectonic features and may even create hydrodynamic traps. Cross-formational faults which juxtapose rocks of different porosity and permeability are sites where large lateral groundwater potential gradients can be expected, especially if the lateral continuity is disrupted by a fault placing a barrier rock in juxtaposition of the carrier rock. Large lateral groundwater potential gradients directed towards the carrier rock will increase the lateral sealing capacity of the barrier rock. The well known field example from the Niger Delta, as given by Weber et al. (19781, shows hydrocarbon accumulations present against the downthrown side of growth faults, where carrier rocks are opposite overpressured shales (Figure

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4.9).The largest influence of hydrodynamic conditions in the intermediate subsystem on the entrapment conditions can be expected near parts of the basin with the largest vertical and lateral groundwater potential gradients, i.e. near the basin’s depocentre. The deep geopressured subsystem of burial-induced groundwater flow is characterized by restricted groundwater flow conditions. Significant superhydrostatic groundwater pressures prevail in both coarse-grained and fine-grained rocks. Very large, mainly vertically upward directed, groundwater potential gradients occur over the fine-grained rocks in the geopressured subsystem. In this deep geopressured subsystem, the hydrodynamic conditions alone, may already create zones of seal failure by hydrofracturing of the barrier rocks or by opening up of faults. The occurrence of this type of seal failure is further enhanced during the accumulation process by the additional increase in total pore pressure at the barrier rock-carrier rock interface induced by the accumulating hydrocarbons (e.g. Watts, 1987).The very large, mainly vertically upward directed, groundwater potential gradients over low-permeable layers in the geopressured zone also decrease the porous sealing capacity of these layers in comparison with a theoretical hydrostatic condition. Caillet et al. (1991) present a field example of a leaking caprock in a geopressured subsystem of burial-induced groundwater flow for the Snorre Field area, in the Norwegian North Sea. In the Snorre field area, heavy hydrocarbons have been encountered in shales capping an overpressured reservoir (overpressuring in the reservoir is 14 MPa at a depth of approximately 2500 m). Caillet et al. (1991)explain the presence of hydrocarbons in the caprock by leakage from the reservoir enhanced by hydraulic fracturing of the shaly caprock which in turn is favoured by the overpressuring of the reservoir. As outlined in Section 4.3.4.1, the lateral migration conditions in carrier-reservoir rocks in the geopressured subsystem are restricted. Hence, in the absence of zones of top seal failure, hydrocarbons probably accumulate close to expelling source rocks. The heterogeneity of the carrier rocks and/or the presence of tectonic elements and associated large lateral gradients of groundwater potential will influence the ultimate location of the hydrocarbon accumulation. Cayley’s (1987)study on hydrocarbon migration in the Central Graben of the North Sea confirms the existence of restricted lateral migration in geopressured subsystems of burialinduced flow. In the Central Graben, the Late Jurassic Kimmeridge Clay Formation is the primary source rock, currently generating wet gas, condensate and oil. The geopressured Jurassic sandstone reservoir rocks are highly structured and faulted. Cayley (1987)observed a close association between the location of known hydrocarbon accumulations and mature source rocks. In the Central North Sea Graben almost all Jurassic gas fields occur in the overmature zone and most Jurassic oil fields occur in the mature zone of the Kimmeridge clay source rock, whereas 8 km updip of the mature oil window no Jurassic reservoired hydrocarbons have been found (Cayley, 1987).

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In comparison with a hydrostatic condition, the accumulation and trapping conditions in a subsiding and filling basin are improved in the intermediate subsystem of burial-induced groundwater flow and deteriorated in the deep geopressured subsystem. This theoretical observation is confirmed, for example, by the distribution of hydrocarbon accumulations in the Norwegian Central Graben. Most recoverable hydrocarbons in the Norwegian Central Graben are found in the intermediate subsystem overlying or adjacent to the deep geopressured subsystem (Leonard, 1992).

Accumulation preceded by hydrocarbon migration in aqueous solution Hydrocarbons dissolved in groundwater first have to come out of solution before oil and/or gas accumulation can start. Hydrocarbons in aqueous solution may come out of solution when an increase in salinity andor a decrease in pressure and temperature take place. Areas where vertical upward groundwater flow is dominant are especially favourable for the exsolution of hydrocarbons from the groundwater. In a filling and subsiding basin predominantly vertically upward-directed groundwater flow occurs as cross-formational flow in the shallow subsystem of burial-induced flow and as focussed flow in the deep geopressured subsystem. Hydrocarbons migrating in aqueous solution into the above-mentioned regions of predominantly vertically upward directed groundwater flow may come out of solution in those areas, and subsequently accumulate as separate phase oil or gases in available trapping positions. 5.3.2 Accumulation and entrapment in stable subaerial basins

Different interdependent gravity-induced cross-formational groundwater flow systems may develop in a subaerial basin. Each groundwater flow system consists of a recharge area, an intermediate area and a discharge area, where the directions of flow are descending, lateral and ascending, respectively. In an inhomogeneous basin with laterally extensive hydrogeological units, the regional lateral flow from recharge t o discharge area tends to be focussed into units of relatively high permeability. In comparison with a hydrostatic situation, the different hydrodynamic conditions in the recharge, intermediate and discharge area of a subaerial hydrodynamic basin each exert a specific influence on the hydrocarbon accumulation and entrapment. In the recharge area, the holding capacity of hydrostatic traps is increased and additional rocks may reach sufficient sealing capacity t o entrap hydrocarbons because of the vertically downward directed net driving forces for groundwater flow in the carrier and barrier rocks. Only when the vertically downward directed forces in the carrier rocks are very large, e.g. a t shallow depths in regional recharge areas, may the hydrocarbons actually move vertically downward, leaving the hydrostatic trapping positions in the recharge area empty. In contrast, in the discharge

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area, the holding capacity of hydrostatic traps is decreased because of the vertically upward directed net driving forces for groundwater flow in the carrier and barrier rocks. In addition to available hydrostatic traps of sufficient sealing capacity, hydrocarbons may accumulate in hydraulic trapping positions in the discharge area. In the intermediate area of stable subaerial basins with laterally extensive hydrogeological units and a large relief of the ground surface, the gravity-induced flow of groundwater is focussed through regional carrier rocks towards discharge areas. If the updip directed buoyancy force for hydrocarbon migration and the lateral direction of the net driving force for groundwater flow run parallel in the regional carrier rock, the holding capacity of hydrostatic traps decreases and the intermediate area can be considered to be a less favourable area for hydrocarbon entrapment in comparison with a hydrostatic subsurface condition. However, opposing directions of these forces are favourable for the entrapment of hydrocarbons in the intermediate area of a regional gravity-induced groundwater flow system. Stone and Hoeger (1973) presented a field example showing clearly the influence of downdip gravity-induced flow of groundwater on the holding capacity of stratigraphic traps in three Lower Cretaceous reservoirs in the Big Muddy South Glenrock field area USA. Stone and Hoeger observed unusually long oil columns in each of the three reservoirs (1400- 2800 ft = 427 - 854 m) in relation t o the barrier facies in the reservoir, which are characterized by low displacement pressures, a well-defined tilt of the oil-water contact of 500 Wmile (95 m/km) and a downdip directed flow of groundwater through the carrierreservoir rock. They concluded that the Lower Cretaceous oil accumulations are in stratigraphic traps in which a favourable fluid potential environment is the critical factor responsible for the large size of the accumulations. T6th (1980) observed that the frequency of occurrence of hydrocarbon accumulations in stable subaerial basins increases and is maximum in areas of groundwater discharge and in hydraulically stagnant zones. The infrequent occurrence of hydrocarbon accumulations in recharge areas may in part be explained by hydrodynamic reasons such as large vertically downward directed net driving forces for groundwater flow flushing hydrostatic trapping locations. An additional explanation may be that the location of hydrocarbon generating mature source rocks and upland recharge areas are not logically related to each other (Section 4.3.4.2):in general, mature source rocks are more likely t o occur in areas of discharge or areas of midline of regional gravityinduced groundwater flow systems. 5.3.3 Accumulation and entrapment in tectonically active basins Tectonic processes affecting a basin by e.g. faulting, folding and tilting of its sedimentary fill may exert a direct influence on the accumulation and entrapment of hydrocarbons by changing the geometry of existing traps, creating new traps and disrupting seals.

Hydrocarbon accumulation, entrapment and preservation

183

Tectonic forces may affect the hydrocarbon accumulation and entrapment indirectly by changing the hydrodynamic condition of the basin (Chapter 4) and thus the sealing capacity of rocks and the holding capacity of hydrostatic traps.

5.4 Preservation of trapped hydrocarbons

Whether a hydrocarbon accumulation that is no longer replenished from the source rock will persist through extended periods of geological time basically depends on the type of trap, the type of accumulated hydrocarbon and the geological and associated hydrodynamic evolution of the sedimentary basin since entrapment.

5.4.1 Hydrocarbon preservation under stable geological conditions A kinetic trap that is no longer charged with hydrocarbons will loose its accumulated hydrocarbons in time. In addition, when the geological and associated hydrodynamic conditions are stable, a hydrocarbon accumulation may be destroyed by diffusion or by removal of hydrocarbons in aqueous solution. Changes in the chemical composition of accumulated hydrocarbons may result from inorganic oxidation, biodegradation and water washing. Diffusion The type of hydrocarbon accumulated in a reservoir trap determines whether or not the hydrocarbon accumulation may be destroyed by diffusive transport of hydrocarbons through a water-saturated barrier rock. Light hydrocarbons may diffuse into and through the water-saturated cap rocks of hydrocarbon accumulations (Thompson, 1979;Leythaeuser et al., 1982;Krooss et al., 1988, 1992). Krooss et al. (1992)presented a calculation procedure to evaluate the order of magnitude of diffusive gas losses through cap rocks with geologic time as a function of effective diffusion coefficients, thickness and extension of the cap rocks and the aqueous solubility of methane. Krooss et al. (1992)applied their procedure t o estimate the diffisive loss of methane from the Harlingen gas field in The Netherlands (reservoir: Lower-Cretaceous sands; cap rock: sequence of Lower Cretaceous shaly and marly sediments of thickness 390 m; total in-place gas reserves = 2.5 x 109 std.m3; field size: 2500 x 1500 m; amount of methane stored beneath unit area of cap rock: 347.8 kg CHdm2 cap rock). The calculation showed that the time required to reduce the present-day methane content of the Harlingen gas field by one-half is approximately 70 million years. Smaller thicknesses of the cap rock will decrease the half-time values. The diffusion coefficient for individual hydrocarbons in water-saturated rock decreases exponentially with increasing carbon number (Leythaeuser et al., 1982). The diffusive flux rate of oily

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hydrocarbons through water-saturated barrier rocks is so low that diffusion of oily hydrocarbons can be disregarded as a mechanism of destruction for an oil accumulation.

Inorganic oxidation The occurrence of inorganic oxidation of hydrocarbons is restricted largely t o near-surface accumulations (e.g. Bailey et al. 1973). Biodegradation Biodegradation of oil in shalIow reservoirs is a common phenomena in many basins (Connan, 1984).The biodegradation of oil is caused by the selective

Table 5.1 Biodegradation effects on gross properties of crude oils

Gases (C1- Cd 1 GOR (Gadoil Ratio) L 3. Gasoline range (Cs - Cld 1 4. M IGravity L 5. Viscosity T 6. Changes in gross composition of CIS+compounds alkanes 1 aromatics 1 NSO’s compounds t asphaltenes t 7. Sulphur content 7 8. Nitrogen content t 9. V andNi t 10. Optical Activity t alkanes t 11. Pour point 1 12. 61% whole oil t alkanes t aromatics s or L asphaltenes L 13. Changes in oil types paraffinic oil + naphthenic oils paraffinic o r paraffinic-naphthenic oils + aromatic-naphthenic oils + naphthenic condensates paraffinic condensates condensates + light oils aromatic-intermediate oils + aromatic-asphaltic oils 1. 2.

From Connan, 1984. Reprinted with permission of Academic Press Inc.

Hydrocarbon accumulation, entrapment and preservation

541 Crude oils

185

ARoM4l-K Hc *NSO COMPOUNDS

Figure 5.14 Main trends of alteration of crude oils (from Tissot and Welte, 1984. Reprinted by permission of Springer-Verlag).

utilization of certain types of hydrocarbons by bacteria. The effect of biodegradation on crude oil composition is given in Table 5.1 and Figure 5.14. Biodegradation results in an increase in density and viscosity of the oil. From an economic point of view, the results of biodegradation are adverse (e.g. Cornford et al., 1986;Tissot and Welte, 1984).Aerobic microbial degradation of accumulated oils may occur when the following conditions are fulfilled (Connan, 1984): the subsurface condition is hydrodynamic and active flow of groundwater takes place through the reservoir rock; the groundwater carries bacteria, dissolved oxygen and nutrients (nitrate, phosphate) into the reservoir rock and brings them in contact with the oil-water contact; the subsurface temperature allows activity of bacteria. Extensive biodegradation of oils is encountered in reservoirs with a temperature range from 20 to 60 - 75 "C, while slightly biodegraded crude oils occur in the 60 - 88 "C range (Connan, 1984). Hence the process of biodegradation is restricted to the upper 3000 m of a sedimentary basin with average geothermal gradients. Bacteria live in the aqueous phase and do not thrive in oil (Connan, 1984). Conventionally

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biodegradation is thought t o take place at the oil-water contact only. Because of the rare occurrence of partially degraded oil accumulations, Cornford et al. (1986) wondered if biodegradation really only takes place at the oil-water contact of an accumulation that is no longer replenished. They suggested that possibly bacteria attack the oil as i t arrives in the trap, following the downward movement of the oillwater contact as the trap fills. Barnard and Bastow (1991) observed that in many of the biodegraded Tertiary oil accumulations in the Central and Northern North Sea, very large volumes of oil are of constant composition throughout the reservoir both laterally and vertically. Barnard and Bastow considered this uniformity in composition not consistent with biodegradation taking place at the oil-water contact or during filling of the reservoir and suggested that the biodegradation took place during secondary migration of the hydrocarbons. Groundwater of meteoric origin may introduce oxygen, bacteria and their supporting nutrients into the subsiirface. In a gravity-induced groundwater flow system, the oxygen content decreases from the recharge towards the discharge area. As biodegradation of hydrocarbons depends on a supply of oxygen, it can be expected that accumulated oils will be less degraded towards a discharge area of a gravity-induced groundwater flow system. Oil accumulations at shallow depths in a regional discharge area will not be biodegraded if the upward flowing groundwater is depleted in oxygen. It can be expected that oil accumulations near recharge areas will become more biodegraded towards shallower depths, i.e. in the direction of decreasing salinities and temperatures, and increasing oxygen content and flow velocities of the groundwater. Bockmeulen et al. (1983) studied the geology and geochemistry of the Bolivar Coastal Fields in Venezuela. In the Bolivar Coastal Fields, there is a complete sequence from light undegraded oil to heavy asphaltic oil originating from the same source rock. Groundwater associated with the degraded oils is typically meteoric in chemical composition. The more meteoric the groundwater, as indicated by the amount of bicarbonates in the water, the more degraded the oil (Bockmeulen et al., 1983). Bockmeulen et al. (1983) suggested that the characteristics of the observed degraded oil accumulations can be explained by biodegradation taking place during secondary migration of oil through groundwater of meteoric origin.

Water washing Water washing is the removal of the more water soluble components from a hydrocarbon accumulation by flowing groundwater. Gas accumulations may be destroyed under hydrodynamic conditions by the continuous removal of gases in aqueous solution. Lafargue and Barker’s (1988) experimental and theoretical investigations of water washing of crude oils showed that water washing is particularly effective in removing the lighter ends of oil, i.e. the C ~ T fraction of crude oils, while it removes only the aromatics and sulfir-bearing compounds in the C15+fraction.

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Water washing results in an increase in density of the residual oil. Lafargue and Barker's investigations further indicated that the effect of water washing increases with increasing temperatures and decreasing salinities of the groundwater, and that its effect is probably not severe during secondary migration. Water washing commonly accompanies biodegradation. Theoretically, the process of water washing is not restricted to gravity-induced groundwater flow systems, but may take place under any hydrodynamic condition, where groundwater undersaturated with hydrocarbons, flows past a hydrocarbon accumulation. As indicated above, water washing is most effective in groundwater of low salinity and relatively high temperatures, i.e. in groundwater recharge areas of regional gravity-induced flow systems, and in shallow local gravity-induced systems. Water washing may still be active at temperatures too high for biodegradation to occur, e.g. in the deeper parts of gravity-induced flow systems and in intermediate subsystems of burial-induced flow, and in areas where dissolved oxygen is absent, e.g. in groundwater discharge areas of regional gravity-induced systems and shallow subsystems of burial-induced flow. 5.4.2 Hydrocarbon preservation under changing geological conditions The geological evolution of the sedimentary basin since the hydrocarbons accumulated in a reservoir trap, strongly determines the fate of the accumulated hydrocarbons. The relative compositions of subsurface gases and liquids will be adjusted to changing pressure and temperature conditions. With increasing depth of burial of an oil accumulation, thermal maturation of oil produces lighter oils and ultimately the oil may be converted to gas. Figure 5.14 shows the influence of thermal maturation of crude oil on the residual oil composition. According to Quigley et al. (1987) and Quigley and Mackenzie (1988) significant thermal cracking of oil to gas occurs between 150 'C and 190 "C. They calculated the oil half-life, i.e. the time taken for half of a given mass of oil t o be converted t o gas at a given temperature, to be less than one million years for temperatures exceeding 170 "C.The generation of large amounts of gas in an oil accumulation resulting from thermal alteration of the oil may induce gas deasphalting of heavy to medium oils producing lighter oils provided the gas is dissolved in the oil (e.g. Tissot and Welte, 1984). Changes in the composition of a hydrocarbon accumulation may also be the result of selective losses of certain hydrocarbons from the accumulation because of changing geological and hydrodynamic conditions. These changing conditions may reduce for example the holding capacity of a trap inducing a selective loss of hydrocarbons through e.g. leaking caprocks or by lateral updip migration. Because of uplift of a gas-saturated oil accumulation in a trap filled to spillpoint, degassing and gas expansion may induce spilling of oil updip out of a trap. Tectonically-induced pressure changes in a gas-saturated oil accumulation may favour escape of light hydrocarbons in gaseous solution,

188

Chapter 5

thus inducing compositional fractionation of the hydrocarbon accumulation (Thompson, 1988). The geometry of the traps, the sealing capacity of rocks and faults, and the directions and magnitudes of the driving forces for hydrocarbon migration, accumulation and entrapment may all change during the geological evolution of a sedimentary basin. These changing conditions may induce readjustment of hydrocarbons in a trap (e.g. change the position of oil-water and gas-water contacts), remigration of the hydrocarbons to new trapping positions, or the escape of hydrocarbons to the atmosphere. The hydrogeological framework and the subsurface energy conditions change during the geological evolution of a basin as a result of e.g. tectonics, erosion, sedimentation, eustatic sea level changes and climatic changes (Chapter 2). Tectonic movements directly influence the hydrogeological framework. Fracturing or faulting of the bamer rock overlying the hydrocarbon trap, will provide permeable escape ways for all or part of the trapped hydrocarbons. Folding and tilting of the sedimentary rocks will change the dip of the reservoir rock-barrier rock interface, changing its trapping capacity. Uplift of traps originally filled to spillpoint, may induce updip spilling of part of the hydrocarbons. Uplift and subsequent erosion may cause the hydrocarbon accumulation t o be destroyed by hydrocarbons escaping directly to the atmosphere. The subsurface hydrodynamic condition that prevailed during the period of hydrocarbon accumulation may change during the subsequent evolution of the basin, affecting both the driving forces for hydrocarbon movement and the hydrogeological framework of the basin. For instance, uplift of a previously filling and subsiding sedimentary basin above sea level may raise the hydrocarbon accumulation into the realm of gravity-induced groundwater flow. Uplift of an already subaerial basin (as well as eustatic sea level falls or climatic changes) will increase the differences in water table potential and therefore also increase the depth of penetration and the intensity of gravityinduced groundwater flow. The magnitude and direction of the burial-induced forces active a t the reservoir trap in a subsiding basin may change continuously because of continued sedimentation. Uplift or subsidence of the sedimentary basin will generally change the intensity of groundwater flow andfor the directions of groundwater flow, thus changing the trapping energy conditions at the location of the formerly accumulated hydrocarbons.

Hydrocarbon accumulation, entrapment and preservation

189

5.5 Summary

Favourable regions for accumulation and entrapment of hydrocarbons are created by the combined influence of buoyancy forces, net driving forces for groundwater flow and capillary forces. Under hydrostatic conditions, the hydrocarbons will become trapped in the reservoir rock when buoyancy-induced lateral upward hydrocarbon migration in the carrier-reservoir rock is stopped by a capillary pressure boundary. Hydrostatic trapping positions include structural traps, stratigraphic traps and combination traps. The maximum height of a hydrocarbon column that can be contained in a hydrostatic trap is determined by the sealing capacity and geometry of the rocks, or rocks and faults, that form the trap. Hydrodynamic conditions affect the sealing capacity of a rock o r fault, and consequently influence the holding capacity of hydrostatic traps. In addition, hydrodynamic conditions may create additional regions of minimum potential energy for hydrocarbons, i.e. purely hydrodynamic trapping positions. Each type of groundwater flow system modifies the accumulation and trapping conditions for hydrocarbons in a sedimentary basin in a specific way in comparison with theoretical hydrostatic conditions for that basin. In comparison with a hydrostatic situation, the accumulation and trapping conditions in a subsiding and filling basin are improved in the intermediate subsystem of burial-induced groundwater flow and deteriorated in the deep geopressured subsystem. The different hydrodynamic conditions in the recharge, intermediate and discharge areas of a gravity-induced groundwater flow system in a subaerial basin each exert a specific influence on hydrocarbon accumulation and entrapment. In the shallow parts of a recharge area, infiltrating meteoric waters may flush hydrostatic trapping positions. In contrast, the deeper parts of a recharge area are relatively favourable for the entrapment of hydrocarbons. Lateral hydrocarbon migration towards discharge areas enhances the volumes of hydrocarbons available for entrapment in these areas. The holding capacity of available hydrostatic traps in the discharge areas may be reduced by the hydrodynamic conditions. Whether the intermediate area of a gravity-induced groundwater flow system can be considered favourable o r unfavourable for accumulation and entrapment depends on the combined influence of the hydrogeological framework of the basin and the magnitudes and directions of the net driving forces for groundwater flow in the carrier rocks. Preservation of trapped hydrocarbons depends on the type of trap, the type of accumulated hydrocarbon and the geological and associated hydrodynamic evolution of the sedimentary basin since entrapment.

190

Chapter 5

Under stable geological and hydrodynamic conditions, accumulations of light hydrocarbons may be destroyed by diffusion or by removal in aqueous solution. Changes in chemical composition of accumulated hydrocarbons may result from inorganic oxidation in near-surface accumulations, biodegradation in gravity-induced groundwater flow systems and water washing by flowing groundwater. Biodegradation and water washing commonly occur in combination and result e.g. in an increase in density of the residual hydrocarbons. Changing geological conditions, i.e. changing hydrogeological frameworks, pressure and temperature conditions and hydrodynamic conditions may induce changes in the composition of accumulated hydrocarbons, readjustment of hydrocarbons in a trap, remigration of hydrocarbons to new trapping positions, and escape of hydrocarbons to the atmosphere. Two important processes altering the chemical composition of accumulated hydrocarbons upon burial are thermal maturation and deasphalting of oil, producing lighter residual oils.

PART 3

BASIN EVALUATION FOR HYDROCARBON EXPLORATION

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CHAPTER 6 APPLICATION TO BASIN EVALUATION

6.1

Hydrodynamic condition, hydrocarbon migration and basin evaluation

The hydrocarbon potential of a sedimentary basin is determined by a combination of evolutionary processes that may have taken place during the geological history of the basin. Considering a geological time-scale, the majority of the world's oil and gas reserves is probably quite young (Klemme and Ulmishek, 1991). Klemme and Ulmishek (1991) found that almost 70% of the reserves has been generated since the Late Cretaceous Coniacian and nearly 50% has been generated and trapped since the Oligocene. The processes that determine the hydrocarbon potential of a basin are the generation, primary and secondary migration of hydrocarbons and the accumulation and preservation of hydrocarbons in traps. The previous chapters of this book have shown that hydrodynamic conditions in a basin, in combination with associated physicochemical phenomena, may influence each of these processes and may affect the permeability-porosity characteristics of the medium in which these processes take place. Hydrocarbons are generated from finely disseminated organic matter in fine-grained sedimentary rocks mainly under the influence of elevated temperatures (Chapter 3). The main phase of oil generation occurs at temperatures between 100 and 150 "C, which corresponds to burial depths of the source rock between c. 2500 and 5000 m for average geothermal gradients and geological heating rates. Hydrocarbon gases are generated simultaneously at these depths. Significant gas generation occurs at temperatures of 150 - 220 "C, i.e. at burial depths beyond 4000 m until c. 7000 m. Thermal cracking of oil t o gas takes place in the temperature range 150 - 190 'C. The hydrodynamic condition in a sedimentary basin affects the temperature distribution in the basin and hence the process of hydrocarbon generation. Between 120 and 150 "C the oil expulsion is very efficient (c. 60 - 90%)for good oil-prone source rocks with initial petroleum potentials greater than c. 0.01 kgkg of rock (Mackenzie and Quigley, 1988). The oil expulsion from leaner oil

Table 6.1 Relations between type of sedimentary basin, hydrodynamic condition, hydrocarbon migration, accumulation and preservation Type of sedimentary basin

Hydrostatic basin

Stable subaerial basin

Groundwater flow system Type

-

Gravity-induced flow system

Characteristicdflow pattern

grad $w = 0 grad pw = hydrostatic no flow

Groundwater of meteoric origin; cross-formational flow; Recharge area: grad pw = subhydrostatic; vertical downward flow Discharge area: grad pw = superhydrostatic; vertical upward flow Intermediate area: focussed lateral flow towards discharge area

Secondary hydrocarbon migration

Hydrostatic migration pattern; preferred lateral migration towards parts of basin with largest dips

Lateral migration; enhanced migration towards discharge areas; length migration path < = > hydrostatic

Entrapment; Type of trap

Hydrostatic traps

Hydrostatic and hydrodynamic traps

Trapping condition

Hydrostatic

Recharge area (near-surface): unfavourable Recharge area (deep): increased holding capacity top seal Discharge area: favourable charge; decreased holding capacity top seal

Preservation (Principal processes affecting preservation)

Diffusion

Biodegradation; water washing

(Characteristicdflow pattern)

s

e39

Y 0,

b

2

(continued) Table 6.1

h

3 Type of sedimentary basin

f?.

5.

-

Slowly subsiding & filling basin; Rapidly subsiding and filling basin Shaldevaporite poor subsiding (rich in shales and/or evaporites) L filling basin

0

a.

Groundwater flow system

8

Type

Shallow subsystem of burial-induced flow

Shallow subsystem of burial-induced flow

Characteristicdflow pattern

grad pw = near hydrostatic; cross-formational vertical upward flow

grad pw = near hydrostatic; grad pw = superhydrostatic; @w (sh) =. ow (sst); cross-formational vertical upward flow vertical water expulsion from sh; no crossformational flow; continuous lateral flow through sst from depocentre to basin edges

grad pw = superhydrostatic geopressured conditions; E restricted lateral flow; episodic focussed flow 3

f Hydrostatic migration pattern

f Hydrostatic migration

Lateral migration; length migration path c = > hydrostatic

Restricted lateral migration; focussed vertical migration

Hydrostatic and hydrodynamic traps Favourable; increased holding capacity top seals

Hydrostatic and hydrodynamic traps Unfavourable; decreased holding capacity top seal

Thermal degradation; deasphal ting

Thermal degradation; deasphalting

Intermediate subsystem of burial-induced flow

Deep subsystem of burial-induced flow

t...

D

rn

Secondary hydrocarbon migration (Characteristicdflow pattern)

pattern

Entrapment: Type of trap

Hydrostatic traps

Hydrostatic traps

Trapping condition

Hydrostatic

f Hydrostatic

Preservation (Principal processes affecting preservation)

Diffusion; thermal degradation

Diffusion; (water washing) (thermal degradation)

C

$.

196

Chapter 6

prone source rocks is relatively inefficient. Most of the oil generated will remain in this source rock and be converted to gases a t higher temperatures and expelled as gas condensate followed by dry gas. The expulsion of gas is probably very efficient. During the peak phase of hydrocarbon expulsion, the hydrocarbons are transported through the source rock, mainly as a continuous separate hydrocarbon phase in a vertically upward or downward direction. The driving forces for the separate phase hydrocarbon migration are large hydrocarbon potential gradients, which are related t o large groundwater potential gradients. After expulsion from the source rock, the hydrocarbons are distributed throughout the basin by secondary migration (Chapter 4). Hydrocarbon in separate phase is the dominant form in which secondary hydrocarbon migration takes place during the peak phase of hydrocarbon expulsion from source rocks. A secondary hydrocarbon migration system is characterized by the masses and initial composition of hydrocarbons available for secondary migration, the three-dimensional migration pattern, the flux of migrating hydrocarbons and the migration losses. Secondary migration of separate phase hydrocarbons is induced by hydrocarbon potential gradients, which in turn result from buoyancy forces, capillary forces and net driving forces for groundwater flow. The secondary migration may lead t o focussed movement of hydrocarbons into traps (Chapter 5). Under hydrostatic conditions the hydrocarbons may accumulate in conventional hydrostatic traps (structural, stratigraphic o r combination traps). Hydrodynamic conditions in a basin influence the pattern of hydrocarbon migration, i.e. the volumes of hydrocarbons available for entrapment in a certain part of the basin, and the trapping energy conditions in the basin, i.e. the location of potential trapping positions and the sealing capacity of rocks and faults (Table 6.1). Under hydrodynamic conditions, hydrocarbons may accumulate in structures without a hydrostatic closure. The preservation of trapped hydrocarbons depends on the type of trap, the type of accumulated hydrocarbon, the time that has elapsed since entrapment, and the geological and associated hydrodynamic evolution of the sedimentary basin in that time interval (Chapter 5). The secondary hydrocarbon migration system influences both the distribution and the accumulation of hydrocarbons in a sedimentary basin (Table 6.1). Knowledge of the characteristics of a hydrocarbon migration pattern a t a certain time during the basin’s evolution, provides information on preferred paths of hydrocarbon migration and may indicate areas favourable or unfavourable for hydrocarbon accumulation during that time. In order to establish the amounts and nature of accumulated hydrocarbons and the exact location of the most favourable positions for hydrocarbon accumulation in a

Application to basin evaluation

197

sedimentary basin at a certain time, information on secondary hydrocarbon migration should be evaluated in combination with data concerning hydrocarbon generation and location of hydrostatic traps. Different procedures are available to determine the input into the secondary hydrocarbon migration system, i.e. the masses and initial composition of hydrocarbons available f o r secondary hydrocarbon migration (e.g. Duppenbecker et al., 1991;Mackenzie and Quigley, 1988;Tissot and Welte, 1984). Generally the actual system of secondary hydrocarbon migration cannot be identified directly from measurable data on currently migrating hydrocarbons in the same way as e.g. the presence of potential source rocks or hydrostatic traps can be identified. Instead, present and paleo secondary hydrocarbon migration systems may be inferred from an integrated analysis of a wide variety of existing data from different disciplines, such as geophysical, geological, geographical, geochemical, reservoir engineering, hydrogeological, geohydrological and hydrochemical data. This third part of the book describes a multidisciplinary approach to identify the present hydrocarbon migration systems and the geohistory of hydrocarbon migration systems in a basin, and indicates how the results can be used for basin evaluation. An introduction to the multidisciplinary approach is given in Section 6.2.

6.2 Hydrocarbon migration systems analysis The methods for identifying the secondary hydrocarbon migration systems in a sedimentary basin, which are given in the next sections, are based on the combined influence of the different factors controlling secondary hydrocarbon migration as treated in Chapter 4. During secondary hydrocarbon migration, the hydrocarbons may be transported as separate phase hydrocarbons, in very fine suspension or in aqueous solution. The dominant form in which secondary hydrocarbon migration takes place during the peak phase of hydrocarbon expulsion is migration of hydrocarbons in separate phase. A t depth ranges of hydrocarbon migration in a sedimentary basin, hydrodynamic conditions will be the rule rather than the exception. A t a certain time during the evolution of a sedimentary basin the secondary separate phase hydrocarbon migration is driven by hydrocarbon potential gradients (Equation 4.11;Sections 4.1.1and 5.21, which in turn are controlled by 1. Magnitude and direction of the force of gravity (g) The magnitude of g is supposed to be constant and known. The direction of is always vertical and positive downward. 2. Densities of the hydrocarbons (phc) and the groundwater (p,) The magnitude of the differences between phc and pw influences the

1%

Chapter 6

magnitude and direction of the hydrocarbon potential gradient under hydrodynamic conditions. The influence of water-hydrocarbon density differences is supposed to be negligible for very finely suspended hydrocarbons. Water-hydrocarbon density differences may change during secondary migration because of changing temperatures, pressures and salinities. 3. Magnitude and direction of the net driving force for groundwater flow The magnitude and direction of the net driving force for groundwater flow are determined by the combined influence of groundwater potential gradients, temperature gradients, electrical gradients and chemical gradients. The groundwater potential gradient is considered to be the main driving force for groundwater flow followed by temperature gradients. 4. Magnitude and direction of the capillary pressure gradient (grad pc) The magnitude and direction of the capillary pressure gradient strongly influence the magnitude and direction of the net driving force for separate phase hydrocarbon migration. Generally, the capillary pressure gradient acts as a resistant force for separate phase hydrocarbon migration and for migration of very finely suspended hydrocarbons in water-saturated rocks. The capillary effect on the net driving force for hydrocarbon migration is significant in poorly permeable fine-grained rocks with small pores (aquitards, barrier rocks or seals). In permeable, relatively coarse-grained rocks (aquifers, carrier reservoir rocks) the migrating hydrocarbons exploit the larger rock pores in preference t o the smaller rock pores because of the capillary effect on the net driving force for hydrocarbon migration. The capillary pressure gradient is perpendicular to the interface between permeable coarse-grained rocks and poorly permeable fine-grained rocks and is directed towards the coarse-grained rocks. The capillary pressure gradients in the poorly permeable rocks do not resist the throughflow of hydrocarbons in aqueous solution. The poorly permeable rocks, however, may also form a barrier for these migrating hydrocarbons, for instance by acting as a semipermeable membrane.

(ew)

The actual rate of secondary hydrocarbon migration is controlled by the hydrocarbon potential gradient, the density and viscosity of the hydrocarbons and the effective permeability of rocks t o hydrocarbons. On a basin-wide scale, the pattern of secondary migration of separate phase hydrocarbons in a sedimentary basin at a certain time during its evolution is thus determined by - the hydrogeological framework of the basin; - the hydrodynamic condition of the basin and the associated groundwater flow systems in the basin; - the density differences between hydrocarbons and water.

Application to basin evaluation

199

Under assumed hydrostatic conditions the magnitude and direction of separate phase hydrocarbon migration are determined by the buoyancy force, which is directed vertically upwards with a magnitude strongly dependent on water-hydrocarbon density differences, and the capillary pressure gradient. The resultant direction of separate phase hydrocarbon migration is vertically updip along the interface between carrier-reservoir rock and barrier rock. The hydrocarbon migration pattern under hydrostatic conditions is strongly determined by the dip of these interfaces. The basin-wide pattern of hydrostatic secondary migration of separate phase hydrocarbons is determined by the hydrogeological framework of the basin and the buoyancy force, and is preponderantly lateral. The system of hydrodynamic secondary hydrocarbon migration, whether the hydrocarbons move in separate phase, in very fine suspension or in aqueous solution, is influenced by the porosity and permeability distribution in a sedimentary basin, and the magnitude and direction of the net driving force for groundwater flow. As a consequence, the different processes and associated forces that are responsible for the hydrodynamic conditions in a sedimentary basin also determine to a greater or less extent the characteristics of the hydrocarbon migration system in a hydrodynamic sedimentary basin (Chapter 4). Whether the magnitude and direction of separate phase hydrocarbon migration will deviate noticeably from those present under hydrostatic conditions depends on the magnitude and direction of the net driving force for groundwater flow in combination with the density differences between water and hydrocarbons, and the hydrogeological framework. For example, the influence of the net driving force for groundwater flowwill be greater in horizontally layered basins than in basins composed of steeply dipping hydrogeological units (the buoyancy force is greater along steeply dipping interfaces). The hydrodynamic condition in a basin influences the secondary hydrocarbon migration differently in different types of groundwater flow system and in different parts of a single groundwater flow system (Table 6.1). Generally speaking, the largest influence of the hydrodynamic condition within a groundwater flow system on both the length and direction of hydrocarbon migration in the basin is to be expected in areas where concentrated lateral or vertical flow of groundwater occurs and where the groundwater potential gradients are large. The flow of groundwater, the mass-transport of chemical compounds, the transport of heat, the deformation of the solid part of the subsurface are interlinked (Chapter 1). Different types of groundwater flow system and different parts of a single groundwater flow system are associated with characteristic physico-chemical features such as specific distributions of pressure, temperature, salinity, chemical composition of groundwater, distribution of diagenetic minerals and phenomena associated with hydrodynamic influence on known hydrocarbon accumulations (Chapter 2). Present-day hydrodynamic conditions in a sedimentary basin can be assessed and explained genetically by the integrated analysis of these measurable

200

Chapter 6

physico-chemical features in combination with groundwater flow modelling techniques. T6th (1963, 1972, 1978) developed such an analysing technique for the quantitative assessment of gravity-induced groundwater flow systems and the genetic explanation of the identified systems. This analysing technique has been extended to a systematic regional mapping procedure of hydrological systems by Engelen (Engelen, 1984, 1986) which is applied successfully in the Netherlands (e.g. De Ruiter, 1988; Gieske, 1989; Stuurman and Pakes, 1991). T6th proposed to use the gravity-induced groundwater flow systems analysis for basin evaluation for hydrocarbon exploration (T6th, 1980, 1987; T6th and Corbet, 1986,1987;T6th and Otto, 1989;Vugrinovich, 1988;Wells, 1988). The multidisciplinary analysis of hydrocarbon migration systems for basin evaluation presented hereafter, has been developed by applying the ideas of T6th and Engelen t o the principles of groundwater flow, hydrocarbon migration, accumulation, entrapment and preservation given in the previous chapters. This hydrocarbon migration systems analysis is a systematic procedure, which is applied successively on a basin-wide scale, a regional scale and a local scale. It involves both qualitative and quantitative approaches. The qualitative approach on a basin-wide scale consists of a sequence of steps involving the preparation of a set of maps, which in combination will qualitatively show the basin-wide potential patterns of hydrocarbon migration at a certain time during basin evolution, and thus the potential distribution of migrated hydrocarbons in the basin at that time (Chapter 7). The quantitative approaches require a large amount of reliable data. Their practical application may therefore be restricted to parts of the basin most favourable for hydrocarbon exploration, as determined before by the qualitative approach. The quantitative regional studies result in the identification of the location of migration pathways and the physico-chemical conditions and potential trapping positions along these migration routes (Chapter 8). The final output of the analysis on a local scale is the rating of petroleum prospects.

6.3 Database The first qualitative approach t o identify secondary hydrocarbon migration systems in a basin makes use of information on a wide variety of existing data from readily available published sources. Very convenient for the analysis is the regional information available in the form of maps and cross-sections (different types of geological maps, such as tectonic, depth-contour, isopach, subcrop, paleogeographic maps; structural and litho-stratigraphic crosssections; topographic and geomorphologic maps of the ground surface; isotherm and heat flow maps; contour maps of groundwater potentials,

Application to basin evaluation

201

salinities and special chemical compounds; hydrogeological cross-sections; distribution of potential source rocks). Such regional information is used in combination with local information derived from e.g. reservoir engineering studies and local groundwater, geochemical, environmental and wastedisposal studies. General information on the geological, geographical and climatological evolution of the basin will support a correct interpretation of the data. The quantitative approach requires the use of additional raw data of different sources and different qualities. The reader is referred to published literature for information on the processing of raw data and evaluation procedures to determine the reliability of the measured data. The main types of raw data used in the analysis of secondary hydrocarbon migration systems for basin evaluation are those relating to present and past physico-chemical characteristics of groundwater (groundwater pressures, temperatures, salinities, chemical compositions) and porosities and permeabilities of the subsurface. In addition, information on the physicochemical characteristics of source rocks and of hydrocarbon accumulations is necessary to complete the quantitative assessment of hydrocarbon migration systems. 6.3.1 Pressure Reliable groundwater pressure data in shallow parts of a subaerial basin can usually be derived from information on groundwater levels as monitored in open boreholes for the benefit of e.g. groundwater resource studies for public water supply or agricultural purposes.

Reliable groundwater pressure data in the deeper parts of subaerial basins and i n subaquatic basins are generally derived from bottomhole measurements, taken in boreholes after mud circulation stops, and from measurements taken during recovery periods of well tests (e.g. drill stem tests, repeat formation tests, production tests and interference tests). In 1951,Horner devised a widely used procedure to determine the natural undisturbed groundwater pressure in the tested interval of a well from the graphical extrapolation of the shut-in groundwater pressures observed during the recovery period of a well test (Horner, 1951;Earlougher, 1977;Matthews and Russell, 1967). The graphical procedure and the conditions and assumptions underlying Horner’s method are similar to those used by hydrogeologists in the Theis method for analysing recovery tests (Theis, 1935;Kruseman et al., 1990). Because of the scarcity or uneven distribution of available well test data, it may be necessary to use indirect indicators of groundwater pressure. A wide variety of pressure indicators can be derived from surface and borehole seismic, drilling and well logging data (Fertl, 1976;Fertl and Chilingarian,

Chapter 6

NORMAL COMPACT ION

I t-

D

OVERPRESSURE LOG R 5 h (Rmi

LOG C, (rnrnhol

Fsb

NaCl ~ 1 % ~ IDPmI ( v S e C It-’] 1 Q CZ-’

$,.

c

110 ’icml

Figure 6.1 Schematic response of well logging parameters to normal and overpressure environments. c s h = shale conductivity (mmho); Rsh = resistivity (Qm), resistivity log; F,h = formation resistivity factor, dimensionless; Atsh = acoustic log; p = bulk density (g ~ m - ~ density ), log; $N = porosity index (a), neutron log; zsh = neutron capture cross-section of shale (lO-3), PNC log. (from Fertl and Chilingarian, 1987. Reprinted by permission of Elsevier Science Publishers BV).

1987; Magara, 1978; Sahay and Fertl, 1989). Actually, these data are indirect indicators of superhydrostatic conditions in siliciclastic sedimentary rocks (Table 6.2; Figure 6.1). The combined interpretation of both drilling and logging indicators for quantitative pressure evaluations is outlined in detail by Fertl (19761, Sahay and Fertl (1989) and Magara (1978). Basically, these evaluation procedures involve the estimation of groundwater pressures from compactionrelated data. Most log data are related either directly or indirectly to porosity (e.g. sonic, resistivity, conductivity, bulk density logs). The interpretation of the observed log data-depth relations, or the log-derived porosity-depth relations, involves the identification of the observed log data-depth relation for compaction equilibrium conditions and the identification of the depth and magnitude of the divergence from the equilibrium data-depth relation. The magnitude of this divergence is related t o the magnitude of overpressuring of the groundwater at a certain depth. Magara (1978) presented a simple procedure t o estimate groundwater pressures from porosity-depth relations by the use of charts. Figure 6.2 shows the chart for a compacting basin in which the influence of aquathermal pressuring on the groundwater pressure is negligible, the average bulk density of the sediments and the density of the groundwater are assumed t o be 1.00 psi ft-1 (2310 kg m-3) and 0.435 psi ft-1 (1005 kg m-31, respectively. The following example calculation, given by Magara (1978), illustrates the use of this chart. In order to estimate the groundwater pressure at depth z = 8500 ft (2591 m), the porosity at this depth must be determined first. For this purpose the porosity-depth plot indicated on the top right of Figure 6.2 is used. Then, a vertical line is drawn through the identified porosity at depth z.

Application to basin evaluation

Table 6.2 Techniques available to predict, detect and evaluate overpressures Source of data

Pressure indicators

Time of recording

Geophysical methods

Seismic (formation velocity) Gravity Magnetics Electrical prospecting methods Drilling rate d-exponent Modified d-exponent Drilling rate equations Drilling porosity and formation pressure logs Logging while drilling Torque Drag

Prior to spudding well

Mud-gas cutting Flow-line mud weight Pressure kicks Flow-line temperature Resistivity, chloride ion, and other novel concepts Pit level and total pit volume Hole fill-up Mud flow rate Bulk density Shale factor Volume, shape, and size Novel, miscellaneous methods

While drilling (delayed by the time required for mud return)

Drilling parameters

Drilling mud parameters

Shale cuttings parameters

While drilling (no delay time)

While drilling (delayed by the time required for mud return)

Well logging

Electrical surveys After drilling resistivity conductivity shale formation factor salinity variations Interval transit time Bulk density Hydrogen index Thermal neutron capture cross section Nuclear magnetic resonance Downhole gravity data

Direct pressure measuring devices

Pressure bombs Drill-stem test Wire-line formation test

When well is tested or completed

Other methods more or less direct, but generally not as accurate as those indicated above, include surface tubing pressure measurements. The hydrostatic pressure of the fluid in the column must be added to the surface measurementsto obtain the formation pressures. From: Fertl, 1976. Reprinted with permission of Elsevier Science Publishers BV.

Chapter 6

Figure 6.2 Nonaquathermal-pressure detection chart (from Magara, 1978. Reprinted by permission of Elsevier Science Publishers BV).

The interception point of this vertical line and the compaction-equilibrium porosity-depth line gives the compaction equivalent depth z, = 6500 ft (1981 m). The porosity is the same a t the two depth points z and z,. After entering the depth z (8500 ft) on the horizontal depth scale, the procedure continues by following the black arrows indicated on Figure 6.2: first, vertically upwards up to the hydrostatic pressure line and then along a line parallel to the diagonal lines, until this line intercepts the vertical corresponding to depth z, (= 6500 ft). Finally, the groundwater pressure is read for this point from the vertical pressure scale of the chart: pw= 4800 psi (33 MPa). The application of the various procedures for estimating groundwater pressures from pressure indicators is restricted to superhydrostatic parts of a sedimentary basin associated with strong undercompaction of siliciclastic sedimentary rocks (e.g. Carstens and Dypvik, 1981; Gretener and Feng, 1985). Chapter 2 showed that superhydrostatic pressure conditions are not necessarily associated with undercompaction of the sedimentary rocks. Superhydrostatic pressure conditions that are not related t o undercompaction

Application to basin evaluation

205

occur for example in gravity-induced groundwater flow systems, in reburied sedimentary rocks in a filling and subsiding basin and in tectonically affected basins. The drilling mud weight is a more widely-applicable indicator for groundwater pressures. Figure 6.2 shows the relationship between groundwater pressure, depth and equivalent mud weight. Knowing the weight of the drilling mud used at a certain depth of the borehole, the groundwater pressure at that depth can be estimated. For example, a drilling mud weight of 1500 kg m-3 applied in a borehole of 3000 m depth corresponds to a drilling mud pressure gradient of 15000 Pa m-1 and a drilling mud pressure of 45 MPa at a depth of 3000 m. This drilling mud pressure of 45 MPa balances the groundwater pressure at the depth of 3000 m. 6.3.2 Temperature Present-day temperatures of the subsurface can be derived from different kinds of measurements: temperature logs from wells with equilibrium temperatures, such as temperature logs from shallow groundwater observation wells; temperatures recorded during well tests or sampling programs; temperature logs from wells with disturbed temperatures caused by drilling; temperatures measured a t the bottom of a borehole during interruptions in drilling.

Measured bottomhole temperatures are widely used in thermal studies in sedimentary basins. The measured bottomhole temperatures are usually lower than the actual subsurface temperatures, because the circulating drilling fluids tend t o cool the rocks, and measurements are generally taken before thermal equilibrium has been established. There are different methods of estimating the actual subsurface temperature from bottomhole temperature measurements (e.g. Dowdle and Cobb, 1975; Leblanc et al., 1982). The Horner method used for extrapolating pressure build-up data to actual groundwater pressures, may also be applied to correct temperature measurements provided that two or more measurements taken at different times after drilling and circulation stopped in the borehole, are available for a certain depth. In the Horner method (Dowdle and Cobb, 1975) temperatures are plotted against the logarithm of At/(t + At), where t is the total duration of mud circulation at the depth in question and A t is the time since mud circulation stopped to the time of temperature measurement. The actual subsurface temperature is obtained by extrapolation of a fitted straight line through the temperature data to the ordinate where At/(t + At) = 1 (Figure 6.3).Regional temperature corrections can be obtained, for example, by constructing and comparing temperaturedepth plots for the measured equilibrium and corrected bottomhole temperatures and for the measured uncorrected bottomhole temperatures, respectively (e.g. Majorowicz et al., 1985).

Chapter 6

300

Circulation slopped

~

4 001161h

Circulation time 3'1, hows

290

Tool

280

DIL FDC SNP

Time since circulalion slopped Temperalure (hours) ( F)

Thermometer Time 011 depth (It) bottom 16200 16200 16200

1215116th 15001161h 1730116th

8 15 11 00 1330

241 257 262

270 LL

i260

250

240

230

1

1.o

I

I

1.2

I

1.4 (f

I

I

1.6

I

I

1.8

I

I

2.0

+ Af ) / Af

Figure 6.3 The Horner correction method for temperatures (from Dowdle and Cobb, 1975, Journal of Petroleum Technology, November 1975, Fig. 5, Table 2. Copyright 0 by Society of Petroleum Engineers. Reprinted by permission).

In the analysis of groundwater flow systems and hydrocarbon migration systems, the measured temperature data are used t o calculate heat flows and geothermal gradients. In a sedimentary basin, within which the transport of heat is largely by conduction and where refraction of heat flow is unimportant, the heat flow is constant with depth (e.g. Andrews-Speed, et al., 1984) and is given by

Application to basin evaluation AT qT=KTrnx

207

(6.1)

where, qT = conductive heat flow KTm = thermal conductivity of water-saturated, isotropic and homogeneous porous medium of thickness Az = temperature difference over thickness Az of the porous medium. AT The thermal conductivity of a porous medium is a function of density, porosity, grainsize, shape, cementation, mineral composition and nature of the pore fillers (Somerton, 1992), i.e. the thermal conductivity is different for different types of rock. The heat flow in an inhomogeneous porous medium under conductive equilibrium conditions is given by AT (6.2) qT = (KTrn = Z /Z (Li4 ) = effective thermal conductivity of the inhomogeneous porous medium of total thickness Az thermal conductivity of a rock unit of thickness Li AZ

A heat flow profile can be constructed from observed temperature data and measured thermal conductivities of the individual rock units. Thermal conductivities of rocks are determined by laboratory measurements on rock samples o r are estimated from geophysical well logs, especially from logs that yield values of in-situ porosity, water-saturation and mineral composition (Somerton, 1992). The constructed heat flow profiles may show variations of heat flow with depth, which may result from hydrodynamic conditions (Chapter 2). In interpreting regional variations in heat flow in a sedimentary basin in relation t o hydrodynamic conditions, it should be kept in mind that heat flow variations may also reflect varying heat flow input from the basement of a sedimentary basin, o r transient conditions induced by e.g. recent introduction of intrusions in the basin, tectonic loading, or rapid subsidence caused by sedimentary loading of the basin, and climatic changes at shallow depths. The identification of paleo anomalies in heat flow and geothermal gradients supports the identification of former hydrodynamic and migration conditions in a basin. Information on paleotemperatures can be derived from fluid inclusion data (Roedder, 1984), apatite fission track analysis, biomarkers and vitrinite reflectance data (Allen and Allen, 1990; Naeser and McCulloh, 1989).

6.3.3 Chemical composition The analyses of groundwater samples collected from hydrogeological, geothermal and petroleum exploratory boreholes and producing wells are the

2 a 3

Chapter 6

most common sources of raw data on the present-day chemical composition of groundwater in a sedimentary basin. Additional data may be available from analyses of groundwater derived from sediment samples. In subaerial basins, the quality of groundwater is often monitored in a network of observation wells in relation with drinking water supply, industrial, agricultural o r environmental purposes. The analyses of water samples from this network of observation wells also provide useful information on the chemical composition of the groundwater. The standard analyses of groundwater samples provide data on the main cations (calcium, magnesium, sodium, potassium, iron) and anions (bicarbonate, sulfate, chloride, carbonate, nitrate, fluoride) and on pH and total dissolved solids content (e.g. Hem, 1985; Domenico and Schwarz, 1990). Local information on isotopes, gases, trace metals and organic compounds in groundwater may be available from specialized studies, such as studies on reservoir diagenesis, genesis of ore deposits, o r waste disposal studies. Chemical analyses of aqueous fluid inclusions provide valuable information for the reconstruction of paleogroundwater flow conditions (Roedder, 1984). Data on fluid inclusions can be obtained from published geochemical studies on amongst other things, reservoir diagenesis (Glasmann et al., 1989a; Liewig et al., 1987) and tectonic development of geological structures (e.g. Banks et al., 1991;Bouiller et al., 1991). 6.3.4 Porosity and permeability Porosity Porosity data can be obtained from laboratory measurements on sidewall samples and core samples from boreholes (e.g. Monicard, 19811, from geophysical well logs (sonic, density and neutron logs; Serra, 1987) or from seismic data. Permeability / hydraulic conductivity Various direct and indirect methods are generally used to determine the permeability of a sedimentary basin. The direct methods include laboratory measurements on core samples; wire-line formation tests, single-well tests and interference tests. The data from the different types of well test and interference test can be analysed and interpreted by well-established procedures (Da Prat, 1990; Earlougher, 1977; Kruseman et al., 1990; Matthews and Russel, 1967). The conventional, indirect methods are theoretical, semi-empirical and empirical procedures which are based on the relation between permeability, grainsize characteristics and porosity (e.g. the Kozeny-Carman method, Domenico and Schwartz, 1990; Van Baaren method, Van Baaren, 1979). The laboratory methods and the conventional indirect methods provide permeability values which are representative of only a very small portion of the subsurface (cmscale). The single-well test and interference test provide information representative of a larger volume of the subsurface (m - km scale).

Application to basin evaluation

m

Permeabilities in sedimentary basins are known to vary with the scale of observation (e.g. BredehoeR et al., 1983,1992;Chapman et al., 1991;Neuzil, 1986). Different techniques are being developed to estimate reservoir- and basin-scale permeabilities, e.g. computer-aided techniques based on relations between characteristics of depositional systems and permeability distribution (Weber, 1982,1987;Stam, 1989;Stam et al., 1989;Mijnssen, 1991),and techniques based on numerical simulations of basin-scale groundwater flow in combination with known groundwater pressure distributions (e.g. Bredehoeft et al., 1983, 1992; Burrus et al., 19911, techniques that use numerical models of coupled groundwater flowheat flow and known thermal characteristics t o estimate basin-scale permeabilities (Chapman et al., 1991). For groundwater purposes the basin-scale permeability distribution, or more correctly the distribution of hydraulic conductivities, can be represented by the basin’s hydrogeological framework. The hydrogeological framework is characterized by the distribution, interconnectivity, thickness and dip of porous and permeable hydrogeological units (aquifers/carrier-reservoirrocks) and poorly permeable hydrogeological units (aquitardsharrier rocks) and the location of geological structures and tectonic elements of importance for groundwater flow (faults, unconformities). A hydrogeological unit is a geological formation, part of a formation or group of formations with similar watertransmitting properties (i.e. similar hydraulic conductivity characteristics). Different orders of hydrogeological units may be used to describe the hydrogeological framework of a basin (e.g. T&h, 1978). The lithostratigraphic build-up and structural geological setting of the basin provide the necessary information on the areal extent, depth, thickness and dip of hydrogeological units.

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211

CHAPTER 7 QUALITATNE ANALYSIS OF SECONDARY HYDROCARBON MIGRATION SYSTEMS

In the qualitative analysis of hydrocarbon migration systems, attention is focussed on the identification of present and past basin-wide or regional patterns of secondary hydrocarbon migration. In a sequence of steps, a set of maps is prepared, which in combination will qualitatively show the potential patterns of secondary hydrocarbon migration at a certain time during the evolution of a sedimentary basin.

7.1

Present-day hydrocarbon migration systems

A first qualitative assessment of the present-day potential hydrocarbon migration pattern in a sedimentary basin does not require data on the location and characteristics of potential source rocks. It is known that under the influence of elevated temperatures potential source rocks start generating hydrocarbons. The deeper parts of a basin may therefore be considered as potential zones of oil and gas formation. The depocentres of a sedimentary basin contain the maximum thickness of sedimentary rocks above basement. Effective depocentres contain the maximum thickness of generative sedimentary rocks and hence the maximum thickness of mature (or overmature) source rocks (Pratsch, 1982, 1983). Therefore, secondary hydrocarbon migration will probably mainly start from the effective depocentres of a sedimentary basin. The pattern of steady-state secondary hydrocarbon migration depends to a greater or lesser extent on: - The present hydrogeological framework of the sedimentary basin, which is characterized by the distribution, thickness and dip of porous and permeable hydrogeological units (aquiferdpotential carrier-reservoir rocks, e.g. sands, sandstones, carbonates, fractured rocks) and poorly permeable hydrogeological units (aquitarddpotential barrier rocks, e.g. shales, evaporites), and the location of geological structures and tectonic elements of importance for subsurface fluid flow, e.g. permeable or impermeable faults, unconformities

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The present magnitude and direction of the net driving force for groundwater flow - The present density differences between groundwater and hydrocarbons - The magnitude and direction of the force of gravity -

The hydrogeological framework is of influence on the hydrocarbon migration pattern regardless of whether hydrodynamic or hydrostatic conditions prevail, and whether hydrocarbon is transported as a separate phase, in very fine suspension o r in aqueous solution. The qualitative method for assessing the present-day hydrocarbon migration pattern is based on the assumption that there is a density difference between groundwater and hydrocarbons and uses geological and geomorphological data to identify the basin’s depocentres, the hydrogeological framework and the directions of the net driving force for groundwater flow. The qualitative method involves the following sequence of steps:

- Identification of the depocentres of the basin - Identification of the hydrocarbon migration pattern assuming hydrostatic conditions

- Identification of the hydrodynamic conditions - Identification of the characteristics of the present-day hydrocarbon migration pattern

7.1.1 Identification of the depocentres The depocentres may be identified from a published map of the geometry of the basement of a sedimentary basin (a depth-contour map of the basement, or an isopach map of the sedimentary fill of the basin), or can be constructed from geophysical, subsurface and surface geological and remote sensing information.

Identification of the hydrostatic hydrocarbon migration patterns Strictly speaking, the complete hydrogeological framework of the basin in combination with the positions of the mature source rocks should be known in order t o determine the hydrocarbon migration paths. When data concerning the positions of mature source rocks are lacking and no reliable picture of the hydrogeological framework can be obtained, the depth-contour map of the basement of the sedimentary basin (Section 7.1.1) may be used as a first approach for identifying the starting points of secondary hydrocarbon migration and the pattern of lateral hydrocarbon migration using Pratsch’s classification (Section 4.3.3,Figure 4.8). The classification is based on the assumptions that the carrier-reservoir rocks and barrier rocks are continuous throughout the basin, the geometry of the carrier reservoir rock - barrier rock interface follows the geometry of the basin, the permeabilities of the individual 7.1.2

Qualitative analysis of secondary hydrocarbon migration systems

213

rock units are constant, the pressure distributions are uniform, the richness of the source rock is uniform and kerogen-hydrocarbon conversion rates are uniform. The hydrocarbon migration map constructed with the help of the depthcontour map of the basement of the sedimentary basin gives the pattern of lateral hydrocarbon migration from the depocentres of the basin to its edges. The actual lengths of the lateral migration paths are not indicated by this migration pattern. The presence of permeable fractures, vertical faults etc. inducing vertical upward flow locally will not necessarily disturb the general picture of hydrocarbon movement to the basin edges, as long as the carrier rock - barrier rock interfaces dip basinwards. However, not all the potential carrier-reservoir rocks and barrier rocks in the basin will dip basinwards, nor will the geometry of the deeper parts of the basin always correspond with the geometry of that basin’s shallower parts. If possible, i.e. if the data required are available, the schematic picture of the pattern of hydrocarbon migration should be modified according to the actual hydrogeological framework of the basin. The distribution, lateral continuation, orientation and thickness of permeable and poorly permeable hydrogeological units and the location of potential vertical pathways for groundwater and hydrocarbons may be obtained from lithostratigraphic, structural geological and geophysical information or, of course, directly from the hydrogeological data often readily available for continental basins or onshort parts of basins. The construction of hydrogeological sections over the basin will be very helpful in adjusting the pattern of hydrostatic hydrocarbon migration. When the distribution of mature source rocks is known, the first step of the above-described method can be carried out in a comparable way. The pattern of lateral hydrocarbon migration is derived from the basin geometry at the level of the source rock. 7.1.3 Identification of the hydrodynamic conditions The type of sedimentary basin and its history of subsidence, heat flow and deformation are the main factors that determine the present-day hydrodynamic conditions in a basin. In the qualitative approach, the identification of the hydrodynamic conditions in present-day stable subaerial basins is restricted to the identification of the gravity-induced groundwater flow conditions. The identification of hydrodynamic conditions in sedimentary basins which are in whole or in part below sea level, should be based on the presupposition that both subsidence of and sedimentation in the basin as well as gravity-induced flow from continental areas surrounding the subaquatic part of the basin may have induced the present-day hydrodynamic conditions. In addition the potential influence of recent tectonic and/or magmatic activity should be taken into account.

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7.1.3.1 Hydrodynamic conditions in subaerial regions When all or part of the sedimentary basin is above sea level, or when the basin is surrounded by areas of high topographic relief, the influence of gravity-induced groundwater flow on hydrocarbon migration should be evaluated. The main characteristics of a gravity-induced groundwater flow system that are of importance for secondary hydrocarbon migration are: depth of penetration of the flow system; areas of concentrated flow of groundwater; main directions of groundwater flow. In the qualitative phase of assessing hydrocarbon migration paths, the possible influence of gravity-induced flow on hydrocarbon migration can be evaluated by a. Identifying areas of high topographic relief in the subaerial part of the basin, and also areas of high topographic relief directly bordering a subaerial or subaquatic sedimentary basin; b. Identifying the highest upland recharge area and lowest discharge area; c. Identifying the depth of penetration of the gravity-induced flow system; d. Identifying the general pattern of groundwater flow. a. Identification of areas of high topographic relief Areas of high topographic relief can be identified from topographic maps of the ground surface and from images produced by remote sensing techniques.

b. Identification of the highest upland recharge area and lowest discharge area The main regional discharge and recharge area can also be identified from topographic maps and remote sensing techniques. The differences in moisture supply in the recharge and discharge areas may produce observable contrasts in the vegetation, erosional features, soil types and surface accumulations of salts (T6th, 1980). The presence of marshes, lakes and salt flats may be indicative of regional discharge conditions in the topographically lowest part of an inland basin. Such phenomena can be identified from, for instance, air photos, infrared imagery, and other remote sensing techniques. The regional discharge zones of continental areas bordering subaquatic basins or subaquatic parts of a basin are in the coastal zones and may extend in a greater or less degree into the subaquatic part of the basin. c. Identification of the depth of penetration of the gravity-induced flow system In practice, it will generally not be known whether or not the studied area is hydraulically continuous and whether or not the gravity-induced groundwater flow systems are in steady-state, i.e. whether or not the flow systems are adjusted t o the present ground surface topography. Two different approaches may be followed to obtain an impression of the maximum depth of penetration of the regional gravity-induced groundwater flow system. The first is based on the evaluation of hydrogeological indicators of gravity-induced groundwater

Qualitative analysis of secondary hydrocarbon migration systems

215

flow. The second approach uses a computer-based simulation of groundwater flow assuming steady-state conditions and a hydraulically continuous subsurface.

Evaluation of hydrogeological indicators The groundwater in a gravity-induced flow system is of meteoric origin. The influence of active groundwater flow of meteoric origin at a certain depth may be deduced from the temperature, the salinity, the hydrochemical composition, stable isotopic composition (deuterium and oxygen-18) of the groundwater, the distribution of diagenetic minerals and, in addition, from degradation phenomena of known hydrocarbon accumulations. Groundwaters of meteoric origin differ from connate waters in their salinity and hydrochemical and isotopic composition. As the residence time of actively flowing groundwater of meteoric origin will be less than that of connate waters, groundwater of meteoric origin in a presently active gravity-induced flow system, will be less saline. Low salinity of the groundwater at a certain depth is an indication of the influence of gravity-induced flow. Regarding the hydrochemical composition of the groundwater, it is generally assumed that groundwaters of meteoric origin have higher concentrations of bicarbonate and sulphate ions and lower Na/(Ca+Mg) ratios than connate waters (Collins, 1975, De Sitter, 1947, Selley, 1985). The different origins of groundwater (meteoric water, seawater, mixed origin) can be determined from the characteristics of the isotopic ratios of hydrogen (D/H) and oxygen ('80/'60) of the groundwater (e.g. Fritz and Fontes, 1980; Hitchon and Friedman, 1969; Rodriguez and Briceiio de Monroy, 1980; Sheppard, 1984). When a component of meteoric water is present in the groundwater at a certain depth, it may be deduced that the originally synsedimentary groundwaters have been wholly or partly replaced by postdepositional gravity-induced groundwater flow. However, the presence of a meteoric component is not necessarily caused by a currently active gravityinduced flow system. The presence of certain diagenetic minerals that are considered to be associated with gravity-induced groundwater flow (Section 3.2.1) may provide additional evidence for the existence of a present (or past) gravity-induced groundwater flow system. The influence of present (or past) groundwater flow of meteoric origin may also be inferred from the chemical characteristics of known oil deposits, because the chemical composition of accumulated oil can be changed by biodegradation o r water washing as induced by moving groundwater of meteoric origin (Section 5.4). The minimal depth of occurrence of active flow of groundwater in the regional recharge area can be inferred from the maximum depth of occurrence of negative temperature anomalies or relative low geothermal gradients or heat

216

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flows as indicated on published isotherm, heat flow or geothermal gradient maps, o r on temperature maps constructed from published data. A preliminary thermal analysis of the basin using published temperature data can be carried out following an approach used by Vugrinovich (1989) and Willet and Chapman (1987). In this approach a representative geothermal gradient is calculated for the basin by linear regression of the entire database. Subsequently, temperature anomalies are calculated by subtracting the subsurface temperature for a certain location determined using the representative geothermal gradient from the observed temperature at that location. The construction of depth-contour maps of the calculated anomalies will reveal the distribution of negative temperature anomalies which may be related to groundwater flow. The interpretation of these anomalies is not straightforward, however, as the effect of variation in the thermal conductivity of the sedimentary rocks should also be taken into consideration (e.g. AndrewsSpeed et al., 1984; Willet and Chapman, 1987). Computer-based approach Under steady-state groundwater flow conditions in a hydraulically continuous basin, the actual depth of penetration of a gravity-induced flow system depends on the relief of the water table (the topographic relief) and the permeability characteristics of the subsurface (Chapter 2). Assuming both conditions (i.e. steady-state flow and a hydraulically continuous subsurface) are fulfilled, the maximum depth of penetration of the gravity-induced flow system in the area studied can thus be inferred from the readily available topographical data in combination with information on the hydrogeological framework of the area, as may be derived indirectly from lithostratigraphic, structural geological and geophysical information, or directly from hydrogeological information. In the quantitative computer-aided simulation of three-dimensional gravity-induced flow systems, the water table potential distribution and the subsurface permeability distribution are used as input data (e.g. Waardenburg, 1987; Zijl, 1984, 1988, 1989). By applying such a simulator, the geometry of the flow systems, the flowpath and residence time (travel time) distribution of the groundwater in each flow system and the subsurface groundwater potential distribution can be calculated. Hence, in theory, the simulator can be used t o support the evaluation of the maximum depth of active flow of the gravity-induced groundwater flow system (see Zijl, 1989). Whether the characteristics of the theoretical flow systems as calculated by a simulator for a certain area give a realistic picture of the actual flow systems strongly depends on the extent to which the two above-mentioned conditions underlying the theory of gravity-induced flow are fulfilled. Tectonically stable continental areas (geologically mature areas) are most favourable in this respect, although even in such stable areas the deeper regional flow systems may not be in accordance with the present water table relief because of geologically recent eustatic sea level changes andor erosional changes of the topographic relief. Unfavourable areas for applying

Qualitative analysis of secondary hydrocarbon migration systems

217

groundwater flow simulators to assess the maximum depth of present-day gravity-induced flow are e.g. tectonically active areas, where the condition of steady-state flow most probably will not be fulfilled, and young, still compacting parts of sedimentary basins possibly showing abnormally high pressure zones, where the condition of subsurface continuity will not be fulfilled. Despite these adverse conditions, the application of simulators will be the only way t o evaluate the possible maximum depth of penetration of the gravity-induced flow systems in areas where data on the hydrogeological indicators of such systems are insufficient or absent. The theoretical results produced by a simulator for the area studied (for instance, the computed travel times of groundwater) should be compared with the geological evolution of that area, in order to decide whether or not it is realistic to assume that the actual present-day gravityinduced groundwater flow system has reached its potential depth of penetration. After the probable depth of penetration of the regional gravity-induced groundwater flow system has been identified, it should be decided whether or not the gravity-induced flow system should be taken into account in the further evaluation of the potential paths of hydrocarbon migration. d. Identification of the general pattern of groundwater flow The identification of the general regional pattern of groundwater flow will only be useful for those parts of the sedimentary basin or adjacent areas, where the depth of penetration of the flow system has been found to be deep enough to be of potential influence on hydrocarbon migration. The regional gravity-induced groundwater flow will be from the highest upland recharge area to the lowest discharge area of the region of interest. As a first approach, the regional groundwater flow pattern can be deduced from a topographic map of the region studied, assuming that the water table relief follows the topographic relief (Figure 2.21). If sufficient data on groundwater potential are available for constructing a two-dimensional picture of the water table relief, these data should be used to identify the pattern of regional groundwater flow. The correctness of the pattern of regional groundwater flow thus determined can be verified by analysing the data available on those characteristics associated with regional groundwater flow that are apparent at the ground surface (moisture conditions) or in the subsurface (temperature, salinity) (Section 2.3.1). The temperature, salinity and hydrochemical composition change systematically along the groundwater flow path from the recharge area where meteoric waters infiltrate, to the groundwater discharge areas (Section 2.3.1). The main effects of gravity-induced groundwater flow on the temperature distribution in a basin can be observed in areas of concentrated vertical flow of

Chapter 7

218

groundwater, i.e. in the recharge and discharge areas of the flow system. An analysis of the thermal characteristics of the basin will delineate the presentday extent of the recharge and discharge areas more precisely in comparison with step 2, and may increase the knowledge on the hydrogeological framework of the basin (e.g. Majorowicz et al., 1985; Chapman et al., 1991). The analysis of the spatial variations in heat flow is considered t o be very useful for this purpose (e.g. Andrews-Speed et al., 1984; Majorowicz et al., 1985). The calculation of the actual vertical heat flow across a certain depth range in a basin requires information on the actual temperatures, the lithostratigraphic buildup and the measured or estimated thermal conductivities of the strata (Section 6.3.2). Andrews-Speed et al. (1984) used a convenient procedure t o examine vertical variations i n heat flow. In this procedure, the actual temperature profile derived from a series of bottomhole temperature values in one borehole is compared with the calculated profiles that would be expected if the heat flow were constant with depth (Figure 7.1). If the slope of the observed profile is steeper than the calculated profile at a certain depth, it corresponds to a lower heat flow at that depth, and if less steep, it corresponds to a higher heat flow value (Andrews-Speed et al., 1984). This procedure is then applied to all well locations with sufficient thermal and lithostratigraphic information. Calculated higher heat flows in the upper parts of boreholes than in the lower parts may be caused by vertical upward flow of groundwater, while the opposite may be the result of vertical downward flow of groundwater (provided other causes of heat flow anomalies can be considered to be negligible). In addition t o vertical heat flow profiles, the horizontal distribution of heat flow values can be Temperature Depth

----.

Calculated temperatures for heat flow q with depth (qT2 > q T 1 )

= constant

- Obsewed temmratures Figure 7.1 Variations of temperature with depth for measured temperatures and for temperatures calculated for two assumed conductive thermal equilibrium conditions.

Qualitative analysis of secondary hydrocarbon migration systems

219

plotted on maps for appropriate depth levels. Areas of high heat flow and low heat flow for a certain depth can be delineated on the map and compared with the previously identified pattern of regional groundwater flow. Salinities of groundwater are relatively low in recharge areas and relatively high in discharge areas. The chemical evolution of the groundwater in the direction of flow is related t o a distinctive sequence of water types. Chebotarev (1955)showed that the water type changes from bicarbonate to sulphate to chlorine from areas of recharge to areas of discharge. The interpretative significance of the hydrochemical composition of the groundwater for evaluating gravity-induced groundwater flow systems is widely recognized by hydrogeologists (e.g. Back, 1960;BredehoeR et al., 1982;Engelen and Jones, 1986; Herczeg et al., 1991;T6th, 1978,1980). The interpretation of water analysis data should include the identification of hydrochemical water types. Graphical representations of water analysis data provide means for identifying hydrochemical water types. Well known techniques for graphical representation of analysis data or for representing the absolute or relative contents of single ions or their ratios as used in hydrochemical groundwater and/or petroleum studies may be applied (e.g. Collins, 1975; Hem, 1985; Domenico and Schwartz, 1990). Widely used graphical representations include the bar graphs introduced by Collins (1923),the Stiff pattern diagram (Stiff, 19511, the pie-diagram and the trilinear Piper diagram (Piper, 1944) (Hem, 1985). The spatial changes in groundwater composition at shallow depths, along an inferred groundwater flow path, or in a regional aquifer can be studied on a map or cross-section by plotting the graphical representations for the different sample points or by contouring salinities and concentrations of single ions a t their ratios. Herzceg et al. (1991) illustrate the change in concentration in a single ion from an inferred recharge to discharge area with concentrations of single ions plotted against distance from the recharge zone. In addition to these graphical methods, statistical methods can be helpful in evaluating the available hydrochemical data (e.g. Davis, 1986). The procedure to combine readily available information on the driving forces for groundwater flow (i.e. the relief of the water table) and the hydrogeological framework of the basin with the various indicators of gravity-induced groundwater flow leads t o the identification of the main recharge and discharge areas and the general pattern of gravity-induced groundwater flow, including preferred paths of groundwater Sow, in all or part of a subaerial basin.

7.1.3.2 Hydrodynamic conditions in subsiding and filling basins Each of the three subsystems of burial-induced groundwater flow that may develop in a subsiding and filling basin modifies the migration, accumulation and entrapment of hydrocarbons in a specific way in comparison with theoretical hydrostatic conditions for that basin (Table 6.1). Large groundwater

220

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potential gradients and concentrated flow of groundwater in the intermediate and deep subsystems of burial-induced groundwater flow are of major influence on the migration, accumulation and entrapment of the hydrocarbons. Whether all three subsystems of groundwater flow are present in a certain basin depends on the basin’s subsidence rate and permeability characteristics. In rapidly subsiding shaly basins with burial rates of more than 1 m d y e a r all three subsystems may occur (Chapter 2). Present-day systems of hydrocarbon migration are being considered here, and therefore the present conditions of burial-induced groundwater flow that result from geologically recent deposition of sediments should be established. An appropriate geological time interval should be chosen for the analysis of burial-driven flow in all or part of the basin. Which time-interval is chosen depends on the geological evolution of the basin, the rate of sedimentation during different geological time intervals and the resulting total thickness and lateral thickness variations of the sediments in each time interval. Subsequently, a depth-contour map of the base of the sedimentary fill of the basin as deposited during the chosen time-interval, should be selected from published literature or constructed from geological and geophysical data. The thickness of the sedimentary fill of the basin gives a first indication of the subsidence rates in the basin during the chosen time-interval. The depocentres of a sedimentary basin contain the maximum thickness of the geologically recent sedimentary fill and are the most likely parts of the basin for the occurrence of all three subsystems of burial-induced groundwater flow. In the depocentres geopressured conditions may occur in the geologicalIy recent sedimentary fill and in the underlying rocks. The geometry of the base of the sedimentary fill can be used to identify qualitatively the potential directions of lateral burial-induced groundwater flow in the intermediate and deep subsystems. The lateral component of the burial-driven groundwater flow in the sedimentary fill and in the underlying rocks will be directed from the depocentreb) of the appropriate part of the basin to its edges (Figure 2.15). The actual occurrence of the three different subsystems of burial-induced groundwater flow can be verified from published groundwater pressure data and from pressure indicators (drilling mud weight, and other drilling and well logging, surface and borehole seismic data; Chapter 6). The combined interpretations of both drilling and logging indicators is outlined in detail by Fertl(197f3, Sahay and Fertl(1989) and Magara (1978) for quantitative pressure evaluations. As outlined in Chapter 6, the application of these procedures is restricted t o superhydrostatic conditions associated with undercompaction of siliciclastic sedimentary rocks. Provided these conditions occur in the studied basin, the depth of the interfaces between the different subsystems of burialinduced groundwater flow and the areal distribution of the subsystems can be estimated from the analysis of the pressure indicators in combination with the groundwater potential characteristics of the subsystem given in Section 2.1.3.

Qualitative analysis of secondary hydrocarbon migration systems

221

Hydrocarbon migration can be greatly affected by concentrated flow of groundwater. In a burial-induced groundwater flow system, appreciable concentrated upward directed flow of groundwater occurs, for example, along the basin edges, salt diapirs, permeable faults or other vertical escape ways. This concentrated flow of groundwater induces positive pressure, temperature and salinity anomalies and associated mineral assemblages in the shallower parts of the basin (Section 2.1.3). Hence, areas where upward-directed groundwater flow is concentrated can be recognized from the analysis of temperature, salinity and geochemical information (see also Section 7.1.3.1); e.g. by identifying the location of temperature anomalies on geothermal gradient maps, heat flow maps or isotherm maps, or the location of positive salinity anomalies from isosalinity maps. The qualitative assessment of the hydrodynamic conditions in a filling and subsiding basin results in the identification of the areal distribution of the different subsystems of burial-induced groundwater flow, the general pattern of lateral burial-induced groundwater flow and the identification of zones of concentrated upward directed flow of groundwater.

Identification of the hydrodynamic influence on the hydrocarbon migration system The application of the above described stepwise procedure of analysis results, amongst other things, in four basin-wide maps. The first map shows the currently active and/or nonactive depocentres of the sedimentary basin. The locations of the depocentres indicate the most probable locations of mature and/or overmature source rocks and the probable starting points of secondary hydrocarbon migration. Each of the three remaining maps shows the potential area of influence of a single driving force or combination of driving forces for secondary hydrocarbon migration: the second map shows the area of influence of buoyancy and capillary forces: and the third and fourth map show the area of influence of the two main driving forces for groundwater flow as controlled by sedimentation in a subsiding basin and infiltration of meteoric water in a subaerial basin, respectively.

7.1.4

The four maps in combination with additional information obtained in the analysis on e.g. depths of influence and intensity of each of the driving forces, permit the identification of the main characteristics of the present-day migration pattern (Table 7.1). Whether or not the identified hydrodynamic conditions in the basin will modify the migration, accumulation and trapping conditions for hydrocarbons in a certain basin in comparison with theoretical hydrostatic conditions for that basin depends on the type or types of groundwater flow system in the basin and on the location of the groundwater flow systems in the basin with respect to the location of the hydrocarbon generating source rocks (Chapters 4 and 5). For

222

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Table 7.1 Identification of hydrocarbon migration patterns

Hydrodynamic influence

Hydrodynamic condition

no

Yes

Characteristics migration pattern Hydrostatic migration pattern; preferred lateral migration towards parts of basin showing largest dips

Burial-induced shallow subsystem intermediate subsystem

deep subsystem

k Hydrostatic migration pattern Lateral migration pattern; length migration path differs from hydrostatic path (longer or shorter) Restricted lateral migration; focussed vertical migration

Gravity-induced

Lateral migration pattern; enhanced migration towards discharge areas; length migration path differs from hydrostatic path (longer or shorter)

Tectonically-induced

Enhanced focussed migration

example, very shallow gravity-induced groundwater flow systems probably do not reach depths where hydrocarbon migration takes place, and burial-induced groundwater flow systems in very slowly subsiding basins probably do not change the theoretical hydrostatic hydrocarbon migration and accumulation system. By comparing the map showing the pattern of theoretical hydrostatic hydrocarbon migration with the maps showing the different patterns of groundwater flow associated with the different identified groundwater flow systems, it can be established whether the location and directions of preferred flow paths for hydrocarbon and groundwater coincide, and whether under hydrodynamic conditions the potential distribution of migrated hydrocarbons valid for hydrostatic conditions is maintained, reinforced or changed. Figure 7.2 gives an example of such a comparison of maps. Figure 7.2 presents maps of the theoretical patterns of hydrostatic hydrocarbon migration and of the

Qualitative analysis of secondary hydrocarbon migration systems

hydrocarbon migration directions-

223

structure contours o f basin f l o o r

basin axis

'ective depocentre

a

"pLe

clrcular symmetrical basin No p r e f e r r e d hydrocarbon migration directions

a

5 A p i e circular s y m e t r l c a l basin No concentration o f groundwater flow

B

B

c

C

c

A

C

A

c

Simple elonqate symmetrical basin P r e f e r r e d hydrocarbon migration t o w a r d s t h e long f l a n k s A and B o f the basin migration preference A and B over C

c

Simple elonqate symmetrical basin Cencentration o f groundwater flow towards the long f l a n k s A and B o f the basin

e

Simple elonqate symmetrical curvedP r e f e r r e d hydrocarbon rnigratlon t o w a r d s concave l o n g flank A migration preference A over B over C

e

Simple elongate symmetrical curved basin Concentration o f groundwater flow t o w a r d s concave long flank A o f the basin

Figure 7.2 Comparison of maps showing patterns of theoretical hydrocarbon migration with maps showing groundwater flow patterns in intermediate subsystems of burial-induced flow for three hypothetical hydrodynamically and geometrically simple basins.

groundwater flow patterns in intermediate subsystems of burial-induced flow for three hypothetical hydrodynamically and geometrically simple basins. In such hydrodynamically and geometrically simple subsiding basins, the lateral flow of groundwater in an intermediate subsystem of burial-induced flow, is directed from the depocentre to the basin's edges and will be parallel to the directions of secondary hydrocarbon migration as induced by buoyancy forces

224

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alone (Figure 7.2). The lateral hydrocarbon migration distance increases because of the hydrodynamic condition in such a basin and the hydrocarbons will accumulate below fine-grained rocks of hydrodynamically increased sealing capacity, at greater lateral distances from the depocentre than in a comparable hydrostatic basin. Changing the hydrodynamic conditions in these geometrically simple basin to those associated with a deep burial-induced subsystem of groundwater flow will result in a completely different hydrocarbon migration system. The influence of the deep burial-induced flow system is t o restrict the lateral hydrocarbon migration and enhance focussed vertical migration. In addition t o the importance of hydrodynamic conditions for basin evaluation that results from their modifying influence on secondary hydrocarbon migration and entrapment in a basin, certain hydrodynamic conditions can also be considered as direct indicators of potential hydrocarbon migration paths. For example, preferred paths of groundwater flow may coincide with preferred paths of secondary hydrocarbon migration (e.g. zones of concentrated vertical upward flow of groundwater from a deep burial-induced subsystem of groundwater flow may indicate vertical escape ways for hydrocarbons; a pattern of lateral groundwater flow focussed through a regional aquifer directly indicates a potential lateral migration pattern for light hydrocarbons in aqueous solution andlor hydrocarbons very finely suspended in water). After having established the present-day hydrocarbon migration characteristics in a basin, evaluation of these characteristics leads to the selection of areas where preferred migration of hydrocarbons takes place, and, consequently, provides insight into the potential basin-wide distribution of hydrocarbons.

7.2 History of hydrocarbon migration systems

Hydrocarbon generation from mature source rocks may continue over a long geological time interval. When the secondary hydrocarbon migration pattern changes over such a time interval, the ultimate distribution of the hydrocarbon accumulations will be the common result of different patterns of hydrocarbon migration. Knowing when hydrocarbon formation started, the history of secondary hydrocarbon migration patterns can be reconstructed qualitatively from the geological evolution of the sedimentary basin. Secondary hydrocarbon migration is induced by hydrocarbon potential gradients, which in turn result from buoyancy forces, capillary forces and net

Qualitative analysis of secondary hydrocarbon migration systems

225

driving forces for groundwater flow. As a first step in assessing the history of hydrocarbon migration patterns, the areal influence of the net driving forces for groundwater flow should be established for subsequent time periods. The hydrogeohistory of a basin, i.e. the evolution of its hydrodynamic conditions and associated groundwater flow systems, can be reconstructed qualitatively from the basin’s geological evolution by identifying the periods of general subsidence and sedimentation, periods of non-sedimentation, uplift or erosion or periods of a low stand of sea level, and periods of increased tectonic activity. For each time period the theoretical hydrostatic hydrocarbon migration pattern should be reconstructed first. A map showing the hydrostatic hydrocarbon migration pattern can be constructed with the help of a paleodepth contour map of the basement of the sedimentary basin for the appropriate time interval.

For a period of general subsidence and sedimentation, the main characteristics of the burial-induced hydrodynamic condition should be determined. Ideally, an isopach map of the reconstructed original thickness of the sediments accumulated during that selected period is available and will reveal the location of the depocentres i n the basin and will give the sedimentation rates in the different depocentres during that period. From the estimated sedimentation rates in combination with knowledge on the general lithostratigraphic buildup of the basin, it can be deduced whether or not all or part of the burial-induced subsystems of groundwater flow could have existed in the selected period. The presence of deep subsystems of burial-induced flow will probably have been restricted to the depocentres. The general pattern of groundwater flow in identified intermediate subsystems of burial-induced flow can be reconstructed from the isopach map of the sedimentary fill in the same way as outlined in Section 7.1.3.2. During a period when all or part of the basin is subaerial, meteoric water will have infiltrated into the subsurface and initiated the development of a gravity-induced groundwater flow system. The areal extent of such a flow system can be inferred from the areal extent of the continental parts of the basin during a certain period, as can be deduced from paleogeographic information. The depth of penetration of a paleo gravity-induced flow system cannot readily be estimated, because detailed information on paleotopographic relief of the ground surface is generally lacking. If possible, regional recharge and discharge areas should be indicated on paleogeographic maps. The general picture of the evolution of hydrodynamic conditions thus obtained can be verified with the help of published information on indicators of paleogroundwater flow conditions. Such indicators are paleopressures, temperatures and -chemical composition of groundwater. For example, geochemical studies on reservoir diagenesis or genesis of ore deposits, may

226

Chapter 7

provide valuable information for evaluating paleogroundwater flow conditions (e.g. information on paleotemperatures, -pressures and -hydrochemistry as derived from fluid inclusions; and on dating of formation of diagenetic minerals). Information on paleotemperatures may also be derived from biomarkers and vitrinite reflectance data and from fission track analysis (Section 6.3). In addition, physico-chemical characteristics of known hydrocarbon accumulations will reflect former hydrodynamic conditions (e.g. a waterwashed and biodegraded hydrocarbon accumulation presently located in a burial-induced groundwater flow system reflects the former existence of a gravity-induced groundwater flow system). By combining the appropriate maps the main characteristics of secondary migration for separate phase hydrocarbons, hydrocarbons in aqueous solution or in very fine suspension, can be identified for each time period. In addition, the influence of periods of increased tectonic activity should be taken into account in the evaluation, because of the direct and indirect effects of tectonic activity on migration, accumulation and entrapment of hydrocarbons (Sections 4.3.4.3and 5.3.3). For each time period the resulting information on directions and lengths of preferred paths of hydrocarbon migration can be used to evaluate the potential distribution of hydrocarbons that have migrated from known or inferred source rock positions and the possibility of the previously accumulated hydrocarbons being destroyed or remigrated.

227

CHAPTER a QUANTITATIVE ANALYSIS OF SECONDARY HYDROCARBON MIGRATION SYSTEMS

A quantitative analysis of secondary hydrocarbon migration systems should result in figures for the volumes and compositions of hydrocarbons migrating in a sedimentary basin as a function of time and space. Ideally, all aspects of a secondary hydrocarbon migration system in a sedimentary basin at a certain time during the basin’s evolution, should be quantified in the analysis, i.e. the masses and initial composition of hydrocarbons available for secondary migration, the three-dimensional migration pattern, the flux of migrating hydrocarbons and the migration losses. Different procedures are available for the quantitative determination of the masses and initial compositions of hydrocarbons available for secondary hydrocarbon migration (e.g. Duppenbecker et al., 1991;Mackenzie and Quigley, 1988;Tissot and Welte, 1984). The reader is referred to the published literature for a detailed outline of these procedures. This chapter presents approaches for the quantitative determination of the remaining characteristics of present and past secondary hydrocarbon migration systems. Emphasis is placed on the identification and integrated analysis of a wide variety of observable present-day physico-chemical characteristics of fluids and rocks in a sedimentary basin in order to quantify present-day migration characteristics and t o place constraints on the reconstruction of the history of hydrocarbon migration systems in the basin.

A quantitative analysis of present-day secondary hydrocarbon migration for basin evaluation can be restricted to the prospective parts of a sedimentary basin as selected on the basis of the previously described qualitative study (Chapter 7). The quantitative assessment of present-day hydrocarbon migration systems is described separately for hydrostatic and hydrodynamic conditions of the prospective parts of the basin (Sections 8.1,8.2and 8.3). Section 8.4 briefly describes the available approaches for a quantitative analysis of the evolution of secondary hydrocarbon migration systems.

Chapter 8

MaD view

A'

m .-..-. *

; -.*

:

Structurecontours top carrier rock Hydrocarbon expelling source rocks Catchmentarea

Cross section

A'

a

Hydrocarbon expelling source rock Drainagevolume

Figure 8.1 Map view and cross-section of hypothetical prospective area.

Quantitative analysis of secondary hydrocarbon migration systems

229

8.1 Present-day hydrostatic hydrocarbon migration systems In order t o quantify the separate phase hydrocarbon migration under true or assumed hydrostatic conditions, the location of hydrocarbon expelling source rocks, the amount and characteristics of expelled hydrocarbons and the basin's hydrogeological framework should be known. The hydrostatic separate phase hydrocarbon migration starts in the porous and permeable hydrogeological units (i.e. carrier-reservoir rocks) adjacent to the expelling source rocks. As outlined in Chapter 4, secondary hydrocarbon migration in hydrostatic basins is a preponderantly lateral migration through carrier-reservoir rocks. After expulsion from the source rock, hydrocarbons will move updip along the upper boundary of the adjacent carrier-reservoir rocks until traps are encountered. The migrating hydrocarbons will seek the shortest possible migration paths. In order to establish the hydrocarbon migration pattern, the geometry of the upper boundary of these carrier reservoir rocks and the location of permeable and impermeable zones along this boundary should be derived from the known hydrogeological framework of the basin (Section 6.3.4). The hydrocarbon migration pattern from source rock to potential trapping positions can be constructed with the help of a depth-contour map of the geometry of the upper part of the appropriate carrier-reservoir rocks (Section 7.1.2). The geometry of the upper boundary of the carrier-reservoir rock and the location of vertical seals along the migration path determine the possible trapping locations. After having identified the potential hydrocarbon migration paths from expelling source rock to a trapping position, the total volume of hydrocarbons lost WL) along the migration pathways can be estimated from the total volume of rock through which the hydrocarbons migrate (the drainage volume VD) and the mean porosity of that rock (n) (Section 4.3.2, Equation 4.25: V, = n&VD; S, = apparent residual saturation, estimated at 1 - 3%) as proposed by Mackenzie and Quigley (1988; Figure 8.1). Knowing the volume of petroleum expelled from that part of the source rock that provides a drainage area for the trap being evaluated, the total hydrocarbon charge that potentially is available for the trapping location can then be estimated from the difference between the volume of hydrocarbons expelled from the source rock and the volume of hydrocarbons lost during secondary migration (Mackenzie and Quigley, 1988). Repeating this procedure for all potential trapping positions along the identified migration pathways in the studied part of the basin, the potential trapping locations can be ranked according to hydrocarbon charge. The volume of hydrocarbons that actually have reached a certain trapping position in a presently stable hydrostatic basin is, in theory, also influenced by the time required for the hydrocarbons to reach the trap in relation t o the time

Chapter 8

230

elapsed since hydrocarbon expulsion from the source rock started to the present-day. The updip lateral migration of oily hydrocarbons proceeds at a specific discharge rate in the order of millimetres per year (Section 4.1) corresponding to velocities of tens of centimetres per year. Hence, the specific discharge rate will probably not be a limiting factor on the hydrocarbon charge for the generally encountered migration distances of less than 30 km (Section 4.3). Quantitative information on migrating hydrocarbons can be obtained by using the specific discharge equations given in Section 4.1. For example, the specific discharge for hydrostatic updip migration can be calculated from the equations

-2

r

khc = T n S h c

8Z

To solve these equations, requires knowledge on geometrical and hydraulic properties of the rocks (Section 6.3.4), densities of groundwater, and densities and viscosities of hydrocarbons. The density of the groundwater can be estimated from Figure 1.3 for different temperatures and salinities. As a first approach, the densities and viscosities of hydrocarbons estimated from, respectively, Figure 4.7 and Table 4.2 can be used in the calculations. The reader is referred to England et al. (1987) and Mackenzie and Quigley (1988) for more precise techniques to determine the density and viscosity of hydrocarbons for various subsurface conditions and for different compositions of the hydrocarbons. Different modelling approaches simulating hydrostatic hydrocarbon migration have been developed (Lehner et al., 1987; Sylta, 1987, 1991a, 1991b). Figure 8.2 shows the result of an example calculation, as given by Lehner et al. (19871, for hydrostatic separate phase hydrocarbon migration through a hypothetical carrier rock of indefinite thickness at different times during subsidence. It has been assumed in the calculation that the location of hydrocarbon input into the secondary migration system shifts with continued subsidence. Sylta (1991a) incorporated modelling of phase behaviour in the modelling of secondary hydrocarbon migration by using an equation of state of a multicomponent hydrocarbon mixture. Sylta’s modelling approaches also account for migration losses (Sylta, 1987, 1991).

-.

+ r: _, l i i i ! l i i l x

a

a

,+

2

v)

0

w

al

m

m

h

h

h

h

\D 0

-

v

h

a

0

al h

w

.r

M

In

3 .

0

In

3

9

Quantitative analysis of secondary hydrocarbon migration systems

--

I

l

P

h

v

231

Y

sC !i

7

8

2

U

Y ul

Figure 8.2 Calculated hydrocarbon column heights below hypothetical cap rock structure at different times before present (from Lehner et al., 1987. Reprinted by permission of Editions Technip).

232

Chapter 8

8.2 Present-day hydrodynamic conditions

The quantitative analysis of hydrodynamic conditions in a prospective part of a basin includes the identification of the different types of groundwater flow system (gravity-induced, burial-induced, tectonically-induced), the quantitative assessment of the characteristics of the identified groundwater flow systems, the interaction and genetic explanation of the flow systems. For this purpose, a quantitative integrated analysis of direct and indirect indicators of regional groundwater flow is used in combination with groundwater flow modelling techniques. Section 6.3 provides information on the data sources for the principal direct and indirect indicators of flow (groundwater pressure; and temperature, salinity and chemical composition of groundwater). Irrespective of the type of sedimentary basin under consideration, i.e. the type of groundwater flow system under consideration, the current direction and intensity of groundwater flow at each point in a basin under isothermal and isochemical conditions are directly related to the groundwater potential gradient, the density and viscosity of groundwater and the permeability of the subsurface (Chapter 1). On a regional scale, the combination of groundwater pressure, density and viscosity data and permeability data directly indicate e.g. the lateral groundwater flow pattern, areas of concentrated horizontal or vertical flow and the location of geopressured zones. Some characteristics of indirect indicators of flow may be associated with a particular flow condition independent of the type of flow system under consideration (e.g. positive anomalies of groundwater temperatures and salinities at shallow depths may indicate focussed vertical upward flow of groundwater). A correct genetic interpretation of the direct and indirect indicators of groundwater flow and the associated groundwater flow directions and velocities requires knowledge on the type and evolution of the groundwater flow systems involved. The previously described qualitative study is a first approach to differentiate between the different groundwater flow systems (Chapter 7). 8.2.1 Hydrodynamic conditions in stable subaerial regions The hydrodynamic condition in a stable subaerial region is given by the characteristics of the prevailing gravity-induced groundwater flow systems.

The present-day groundwater flow systems in the selected study area may not be in accordance with the relief of the present-day water table, and as a consequence the characteristics of the flow system cannot be reliably inferred solely from water table relief and subsurface permeability distribution. A direct determination of the quantitative characteristics of the present-day gravityinduced groundwater flow system, requires data on pressure, density and viscosity of groundwater and data on the permeability distribution

Quantitative analysis of secondary hydrocarbon migration systems

233

supplemented with data on the relief of the present-day water table, o r eventually on the topographic relief of the ground surface. The interpretation of these data should be integrated with a n evaluation of the different characteristics associated with gravity-induced groundwater flow, as apparent at the ground surface (moisture conditions) or in the subsurface (temperature, salinity, hydrochemical composition, isotopic composition of groundwater) (Chapter 2). T6th (1978) proposed an analysing technique for the quantitative assessment of cross-formational gravity-induced groundwater flow systems and the genetic explanation of the identified systems, based on the integrated interpretation of the following five pressure-related parameters: - potentiometric surface - pressure-depth relation - dynamic pressure increment - hypsographic distribution - water table elevation.

Potentiometric surface The groundwater potentials of a certain hydrogeological unit can be calculated from groundwater pressure and density data (Chapter 1). Groundwater potentials are often expressed in equivalent fresh-water heads. Equipotential lines, or potential contours, connect points of equal groundwater potential for a single hydrogeological unit. The potential contours for a hydrogeological unit add up to a relief map of the potentiometric surface for that unit. A potentiometric surface map of a hydrogeological unit provides a regional picture of the magnitudes and directions of the groundwater potential gradients, which is also of direct importance in analysing hydrocarbon migration systems. For analysing groundwater flow conditions, the direction and spacing of the potential contours of the potentiometric surface of a hydrogeological unit can be used to identify the lateral component of the groundwater flow pattern, the location of lateral barriers to flow andor the location of vertical escape ways from the unit. Pressure -depth relation A regional picture of groundwater pressure-depth relations is indicative of the following groundwater flow characteristics: groundwater flow condition (hydrostatic or hydrodynamic), groundwater flow direction (descending, horizontal or ascending), absence or presence of pressure barriers. Dynamic pressure increment The dynamic pressure increment, Apw, at a certain depth is the difference between the hydrostatic and the hydrodynamic pressure-depth relation at that depth (T6th, 1978). T6th (1978) showed that the dynamic pressure increment is a function of both ground surface elevation and depth of measurement. He proposed the use of a two-dimensional presentation of this relation (the elevation-depth pattern: Apw-z-d)as an analysing tool. The elevation-depth

Chapter 8

234

<5

,.:

Mid I i n e Mid1 scharge a r e 7rea Recharge a r e a

a

i-+

LEGEND

10500

Regional s l o p e o f l a n d surface

C'

10000

L1

2

8000

_---_

$

6000

A

Line of flow

4000

-I--

Water t a b l e

9

m

.-0

: 2000 -a~ Datum

S

Arbitrary horizontal s u r f ace

D

w z = o

b

b

,

L i n e o f equal h y d r a u l i c head

1

Bottom zone

Pressure

(Adapted from T6th,

1962, F i g . 3,

P

P Supe rnorma I ( d i scharge-area) p r e s s u r e s

LEGEND Normal ( h y d r o s t a t i c ) V

pressures

Subnormal ( r e c h a r g e - a r e a ) pressures

3

X

8000

+Ap3

Dynamic p r e s s u r e increment a t s i t e 3. d e p t h 8000 f t

'

D

r 4 4 10000~ a

3

L i n e o f equal dynamic p r e s s u r e increment

from T6th,

1978, F i g .

Figure 8.3 Theoretical distribution of hydraulic head, groundwater flow, pressure and dynamic pressure increment in a homogeneous drainage basin with simple ground surface geometry (from T6th, 1980. Reprinted by permission of the American Association of Petroleum Geologists).

Quantitative analysis of secondary hydrocarbon migration systems

235

LEGEND c'

Regional s l o p e

a

Amplitude o f l o c a l topography

,---Line

o f equal h y d r a u l i c

head Line o f flow

,

,

c -

Boundary between f l o w systems

(Adapted f r o m T 6 t h , 1963, F i g . 2 f , p. 4802)

P Supemorma 1 pressures

LEGEND + A P ~ Dynamic p r e s s u r e increment a t s i t e 4, d e p t h 8000 f t a

Local system

b

I n t e r m e d i a t e system

c

Regional system

. i n e o f equal oynamic Nressure increment from T6th,

1978, F i g .

a

Figure 8.4 Theoretical distribution of hydraulic head, groundwater flow, pressure and dynamic pressure increment in a homogeneous drainage basin with complex ground surface geometry (from Tdth, 1980. Reprinted by permission of the American Association of Petroleum Geologists).

pattern i s a family of is0 Apw curves plotted against groundwater head elevation, z, and depth of measurement, d (Figures 8 . 3 ~and 8.44. Such an elevation-depth pattern of the dynamic pressure increment can be used to identify the type of gravity-induced flow systems (local, intermediate, regional

Chapter 8

236

flow systems), the lateral and vertical extent of each flow system, the hydrogeological framework, the hydraulic continuity between separate porous and permeable hydrogeological units, and the effect of ground surface topography on the groundwater pressure distribution.

elevation, arbitrary units

elevation, arbitrary units

,.:

0

25

50

75

100%

confined aquifer

A,]'

a

basin's ground surface

s'

hypsographic curve of basin's ground surface

Reqionally confined aqulfer Shape and position of groundwater potentiometric surface are independent of coafiguration shown portion of basin's ground surface

75

100%

h,

potentiometric surface h,

.........._. ....h i

hypsographlc curve of potentlometric surface hl

V

unconfined aquifer

s

50

relative extent of study area

relative extent of study area -A,

25

0

b

Reqionally unconfined aqulfer Shape and position of groundwater potentiometric surface are dependent of configuration shown portion of basin's ground surface

Figure 8.5 Relation between hypsographic curve of the ground surface and t h a t of the groundwater potentiometric surface of regionally confined a n d unconfined aquifers (after T6th, 1978, Water Resources Research, Vol. 14,no. 5, Fig. 7, p. 813, Copyright (0)1978 by the American Geophysical Union).

Quantitative analysis of secondary hydrocarbon migration systems

237

Hypsographic distribution A hypsographic distribution is the relative areal frequency in a certain region of elevations above datum of a laterally extensive bounded surface. It can be expressed by the hypsographic curve, which is a plot of elevations representing specified vertical intervals, e.g. of the ground surface against the cumulative sums of the relative extent of the corresponding horizontal projections. The analysing technique proposed by T6th is based on a comparison of the hypsographic curves of the ground surface and a potentiometric surface of a particular region. The analysing technique may be used t o determine whether a particular part of the groundwater flow system is in accordance with present ground surface topography. Figure 8.5 gives an example of a theoretical hypsographic distribution. According to T6th (1978) this technique can be very useful in large areas with varied topography and sparse data control. Water table elevation The elevation of the water table is the level where the groundwater pressure is atmospheric, i.e. the groundwater in an observation well would rise t o this level. The elevation of the water table is the vertical distance between a datum plane and this level, which corresponds to the water table within the aquifer (phreatic surface) or to the potentiometric surface. The elevation of the water table may be derived from groundwater pressure-depth plots (T6th, 1978). This parameter may be useful for determining outcrop regions of hydrogeological units and for identifying whether the groundwater flow is regionally unconfined or not, by correlating the elevation of the water table with the elevation of the ground surface.

The interpretation of the five pressure-related parameters can be supported by an evaluation of physico-chemical phenomena associated with gravityinduced groundwater flow and a comparison of present-day groundwater flow characteristics with theoretical flow characteristics for different hypothetical conditions and/or paleogeological and paleohydrogeological conditions. The correctness of the identified characteristics of the groundwater flow systems can be verified by analysing the observed physico-chemical characteristics of the studied region in the same way as outlined in Section 7.1.3.1. In addition, the regional distribution of indirect indicators of flow, especially temperatures, may be used t o identify geohydrological characteristics of the basin, such as directions and fluxes of groundwater flow and permeability distributions. For example, Chapman et al. (1991) used temperature distributions to constrain their numerical simulations of coupled groundwater flowheat flow for the Uinta Basin, USA. By varying geohydrological and thermal parameters they could estimate basin-scale permeabilities and groundwater flow conditions (see also Willet and Chapman 1987,1989;Smith et al., 1989).

238

Chapter 8

For the genetic interpretation of the five pressure-related parameters the observed distribution of parameter values may be compared with the theoretical distribution of parameter values as calculated for hypothetical models. T6th (1978, 1979, 1980) applied this approach in his regional groundwater flow study of the Red Earth Region in Alberta, Canada. Figures 8.3, 8.4 and 8.5 present examples of calculated parameter distributions for two different theoretical situations as given by T6th (1978,1979, 1980). Figures 8.3 and 8.4 show the distribution of the following parameters in a hypothetical homogeneous and hydraulically continuous basin with simple and complex topographic relief, respectively: groundwater potential and groundwater flow ( Figures 8.3a and 8.4a); groundwater pressure (Figures 8.3b and 8.4b) and dynamic pressure increment (Figures 8 . 3 ~ and 8.4~).An example of a theoretical hypsographic distribution is given in Figure 8.5. The quantitative characteristics of the gravity-induced groundwater flow systems identified by the interpretation of the five pressure-related parameters can be explained genetically by applying an appropriate simulation model of gravity-induced groundwater flow (e.g. Bethke, 1986a, 1989; Garven, 1989; Garven and Freeze, 1984; Zijl, 1984, 1988, 1989). Assuming steady-state conditions in the area of study, simulation of gravity-induced flow systems resulting from the present-day water table potential distribution and subsurface permeability distribution, gives information on the geometry of the flow systems, the groundwater flow directions and velocities and the groundwater potential distributions. By comparing the identified characteristics of the groundwater flow systems with those calculated for the present-day relief of the water table and the present-day permeability distribution, the characteristics of the present-day flow systems that are in accordance with the present-day relief of the water table can be identified. The maximum depth of a steady-state groundwater flow condition can thus be estimated as well. The present-day groundwater potential distributions and groundwater flow directions in the deeper parts of the basin may still be related t o former configurations of the water table (i.e. former topographic, climatic and/or sea level conditions; Section 2.3). The interpretation of such transient hydrodynamic conditions requires data on the paleotopography of the groundsurface, or on paleoclimatic and -sea level conditions, and data on the paleohydrogeological framework. Past water table configurations may be inferred from knowledge on the recent geological evolution of the basin. The reconstructed past water table configurations and the known or assumed paleohydrogeological framework of the basin may be used as input data for a steady-state groundwater flow simulator t o determine the characteristics of past groundwater flow systems in accordance with the corresponding past water table configurations. A combination of such steady-state simulations of past gravity-induced groundwater flow conditions with calculations of adjustment times of groundwater potential t o changing boundary conditions can be used to interpret the present-day transient groundwater flow conditions

Quantitative analysis of secondary hydrocarbon migration systems

239

(e.g. Garven 1989; T6th and Corbet, 1987). Simulation of the hydrogeohistory by applying models of unsteady-state gravity-induced groundwater flow are also used to interpret present-day transient groundwater flow condtions (e.g. Senger et al.,1987). 8.2.2 Hydrodynamic conditions in subsiding and filling basins

The present-day burial-induced hydrodynamic conditions in the selected area can be assessed directly from the groundwater pressure, density and viscosity data and the permeability data. Each subsystem of burial-induced groundwater flow is characterized by specific vertical and horizontal changes of the groundwater potential (Section 2.1.3): Characteristics of the shallow subsystem: the groundwater potential increases slightly with depth, reflecting cross-formational vertical upward flow of groundwater; there is no lateral change in groundwater potential; the groundwater pressure-depth gradient is near hydrostatic t o slightly superhydrostatic. Characteristics of the intermediate subsystem: the groundwater potential in fine-grained rocks is higher than that in adjacent relatively coarse-grained rocks; the groundwater potential in the relatively coarse-grained rocks changes laterally, indicating the lateral flow direction of groundwater through these rocks; the groundwater pressures in the relatively coarse-grained rocks are superhydrostatics; the groundwater pressure-depth profile in the relatively coarse-grained rocks runs parallel to the hydrostatic gradient. Characteristics of the deep subsystem: the fine-grained as well as the coarsegrained rocks are geopressured; large vertical changes in groundwater potential occur over the fine-grained rocks and large lateral changes in groundwater potential occur in the relatively coarse-grained rocks over relatively short distances, reflecting the restricted groundwater flow conditions in the deep subsystem. A regional picture of changes in groundwater pressure with depth and groundwater potential with depth in combination with potentiometric surfaces constructed for different hydrogeological units permit the delineation of the vertical and lateral extent of the shallow, intermediate and deep subsystems of burial-induced flow in the studied area.

Subsequently, additional characteristics of the burial-induced hydrodynamic conditions of importance for hydrocarbon migration, such as directions and rates of groundwater flow, zones of concentrated flow, should be determined for each of the subsystems. The shallow subsystem of burial-induced flow can be considered to be hydraulically continuous. Therefore, the concept of dynamic pressure increment, as introduced by Tdth (1978; Section 8.2.1) can be used to

240

Chapter 8

assess the vertical direction and rate of groundwater flow in the shallow subsystem. The pattern of lateral groundwater flow through the relatively permeable hydrogeological units in the intermediate subsystem can be derived from the potentiometric surface maps of the groundwater constructed for each of these units. It is also important to look for discontinuities in the distribution of the groundwater potentials (such as large differences of potential over short lateral distances and, conversely, zones of very small lateral differences of potential) in relation t o tectonic and structural elements or stratigraphic features, because they may indicate the location of lateral barriers t o flow andlor the location of vertical escape ways for groundwater from the hydrogeological unit. The rates of lateral groundwater flow through the relatively permeable hydrogeological units can be calculated from the lateral groundwater potential gradients, the groundwater density and viscosity and the permeabilities of the hydrogeological unit. The magnitudes and directions of the changes in groundwater potential with depth in the poorly permeable units in the intermediate subsystem affect the sealing capacity of these units for hydrocarbons. Ideally, a detailed regional picture of groundwater potential profiles over these units should be constructed from pressure data o r pressure indicators (Section 6.3). The potentiometric surface map of the groundwater in each of the relatively coarse-grained units in the deep geopressured subsystem in combination with lithostratigraphic and structural information of these units will indicate the lateral direction of groundwater flow, location of vertical barriers t o flow, and the location of possible vertical escape ways for groundwater. The regional distribution of the magnitudes of groundwater pressures and potentials in the geopressured zone will help t o delineate possible zones of seal failure resulting from hydraulic fracturing. Zones of concentrated upward flow of groundwater, which may occur along the edges of an intermediate subsystem, along permeable faults and diapirs, and through hydrofractured zones of seal failure in the deep geopressured subsystem, induce positive pressure, temperature and salinity anomalies and associated mineral assemblages in the shallow parts of the basin. The location of the zones of concentrated upward flow of groundwater inferred from the interpretation of groundwater potential and pressure data may thus be confirmed by an evaluation of available thermal and geochemical information (see Chapter 7). The identified pressure distribution and the other physico-chemical characteristics associated with burial-induced groundwater flow are the combined result of the time-dependent processes of groundwater pressure generation and dissipation. The groundwater pressures in a filling sedimentary basin are generated by the combined effect of the increase in load of the water-saturated sediments and the aquathermal effects, which, a t greater depths, may be enhanced by the dehydration of clay minerals and by hydrocarbon generation from organic matter (Section 2.1.3). Ideally, a

Quantitative analysis of secondary hydrocarbon migration systems

241

quantitative genetic interpretation of the identified present-day hydrodynamic conditions should take into account the combined influence of the different pressure-generating mechanisms and the hydrogeological framework of the basin. Different theoretical approaches for establishing groundwater pressure distributions in a subsiding and filling basin have been presented (Bethke, 1985, 1986b;Bethke and Corbet, 1988;Bethke et al., 1988;Doligez et al., 1986; Forbes et al., 1992; Magara, 1978, 1986, 1987; Mann and Mackenzie, 1990; Ungerer et al., 1987b). These approaches include two-dimensional basin-scale modelling techniques to simulate groundwater pressure generation and groundwater flow (e.g. Bethke’s model, Themis model). Bethke’s model (1985, 1986) considers the development of groundwater pressures and groundwater flow in a subsiding and filling basin as resulting from compaction, aquathermal pressuring and mineral dehydration reactions (Bethke, 1985,1986; Bethke et al., 1988; Harrison and Summa, 1991). Using Bethke’s model, Bethke et al. (1988) and Harrison and Summa (1991) simulated and interpreted the development of present-day groundwater pressures and groundwater flow in the Gulf of Mexico Basin, USA (Figure 2.30). The Themis (Temispack) model is a twodimensional model, which can simulate numerically compaction and burial processes, hydraulic fracturing, groundwater flow, conductive and convective heat transfer and hydrocarbon generation by using Darcy’s law for groundwater flow, porosity versus effective stress relationships for compaction, parallel first order kinetic reactions and Arrhenius laws for hydrocarbon generation (Doligez et al., 1986; Forbes et al., 1992; Ungerer et al., 1987b, 1990). The Themis model has been used to study hydrodynamic conditions in, for example, the North Sea Basin (Figure 8.6; Bunus et al., 1991; Doligez et al., 1987; Ungerer et al., 1987a1, the Mahakam Delta, Indonesia (Burrus et al., 1991; Schneider et al., 1991), the Eastern Canadian margin (Forbes et al., 1992) and the Paris Basin (Burrus et al., 1991). The application of the above-mentioned modelling techniques allow the assessment of the relative importance of the possible pressure generating mechanisms and the different characteristics of the hydrogeological framework in relation to the observed present-day hydrodynamic conditions in the basin. 8.2.3 Hydrodynamic conditions resulting from interactions of

different groundwater flow systems Different groundwater flow systems may co-exist and interact in a basin (Section 2.5). When a subsiding basin is surrounded by continental areas or when part of the basin has emerged and stabilized above sea level, the hydrodynamic characteristics of such basins reflect the interaction of burial- and gravity-

Chapter 8

242

AGE . 000 M.A.

a Krn

-

Krn

W a t e r velocity ( I 0 to GOOm/MA.)

AGE OOOMA

Krn

-

Krn Water velocity ( I 0 t o GOOm/MA.)

Figure 8.6 Temispack reconstruction of the present-day distribution of overpressures induced by compaction disequilibrium for two assumed conditions of fault permeability: a. faults are assumed to be permeable; b. faults are assumed t o be impermeable (arrows: Darcy velocity) (from Burrus e t al., 1991, Geological Society Special Publication no. 59, Fig. 7, p. 97. Reprinted by permission).

Quantitative analysis of secondary hydrocarbon migration systems

243

induced flow systems. Features, such as positive pressure, temperature and salinity anomalies are characteristic of zones of concentrated upward flow along the edges of subsiding basins as well as of upward flow in discharge zones of gravity-induced flow systems. Along the edges of subsiding basins surrounded by continental areas, these features may be genetically related to either one of these flow systems or to both. The genetic interpretation of the observed direct and indirect indicators of groundwater flow in the basin should include an evaluation of both flow systems and their interactions. Bethke et al. (1988) and Harrison and Summa (1991) used two-dimensional groundwater flow modelling techniques taking into account the two driving forces for groundwater flow, i.e. sedimentation in the subsiding part of a basin and relief of the groundwater table in its continental part, to reproduce present-day hydrodynamic conditions in the Gulf of Mexico Basin. Burrus et al. (1991) showed numerical results of a version of the Themis model that includes the two driving forces for groundwater flow for the Paris Basin and the Mahakam Delta. Hydrodynamic conditions in a basin may in part result from tectonic forces. Ge and Garven (1989) applied a numerical model of coupled tectonic- and gravity-induced flow to evaluate the relative importance of tectonic influence on groundwater 'pressure and flow in an otherwise gravity-induced flow system in a hypothetical foreland basin. Forbes et al. (1992) included an evaluation of lateral compression in their numerical reconstruction of the present-day pressure distribution in the Venture Field, Eastern Canada. Free thermal and thermohaline convection may occur locally in sedimentary basins. The possible occurrence of thermal convection of groundwater should be evaluated in sedimentary basins with high heat flows and around magmatic intrusions and salt diapirs. The possible existence of thermohaline convections should be evaluated near evaporite occurrences (Section 2.4).

8.3 Present-day hydrodynamic hydrocarbon migration systems The identified types of groundwater flow system, their groundwater-depth gradients and potentiometric surfaces in combination with the hydrogeologic _",-&meworkallow an evaluation of the sealing capacity of the barrier rocks under hydrodynamic conditions (e.g. lateral continuity of barrier rocks of sufficient sealing capacity; zones of seal failure by hydraulic fracturing of rocks) and the role of faults as vertical pathways or barriers for hydrocarbon migration (Sections 5.2 and 5.3).

Chapter 8

244

’,.

I

/

.I

-

Figure 8.7 Cross-section showing graphical relation between equipotential surfaces, u = constant, and those of v = constant and z = constant for equal intervals of Au = Av = Az (after Hubbert, 1967).

The migration pattern for hydrocarbons in aqueous solution and very fine suspension can be derived directly from the previously identified groundwater flow patterns.

For parts of the basin with laterally continuous barrier rocks of sufficient sealing capacity, the pattern of separate phase hydrocarbon migration through carrier-reservoir rocks and the location of trapping positions can be determined by applying Hubbert’s mapping technique (Dahlberg, 1982;Hubbert, 1953,1967) assuming that the locations of hydrocarbon expelling source rocks are known. The application of Hubbert’s W Z mapping procedure requires information on the geometry of the upper boundary of the carrier-reservoir rocks, the groundwater potential distribution in the carrier-reservoir rocks, the groundwater density and the hydrocarbon density. Section 5.2 showed that the potential of a unit mass of separate phase hydrocarbons in a water-saturated rock under hydrodynamic conditions is given by Equation 5.2. Omitting the influence of capillary pressures on the hydrocarbon potential reduces Equation 5.2 to (8.i) Equation 8.1 is the basis of Hubbert’s mapping procedure. For constant groundwater and hydrocarbon densities, Equation 8.1 can also be expressed as

Quantitative analysis of secondary hydrocarbon migration systems

2A5

(8.2) By letting

it follows that Uhc = vhc - z. At every point in a carrier-reservoir rock, Uhe, which is proportional to the hydrocarbon potential, can be determined from the elevation z and the value of Vhc, which can be calculated from the groundwater potential (Figure 8.7). The UVZ mapping procedure results i n maps o r cross-sections showing hydrocarbon equipotential surfaces in carrier-reservoir rocks from which hydrocarbon migration directions and potential trapping positions can be derived (Figures 8.8 and 8.9). The volume of hydrocarbons lost along a migration path from expelling source rock t o potential trapping position, can be estimated by applying Mackenzie and Quigley's procedure (Section 8.1). Under hydrodynamic conditions, additional losses can be expected to occur by removal of light hydrocarbons in aqueous solution. After having estimated the hydrocarbon charges available for the different trapping locations, the traps can be ranked according to hydrocarbon charge. The calculation of specific discharge rates for separate phase hydrocarbon migration requires knowledge on the geometrical and hydraulic properties of the carrier-reservoir rocks (Section 6.3.41,the densities of groundwater, the densities and viscosities of hydrocarbons (Section 8.1) and the groundwater potential gradients in the carrier-reservoir rock. Specific discharge rates for separate phase hydrocarbon migration under hydrodynamic conditions can be calculated from the following equations given in Sections 4.1 and 4.2

An evaluation of the probable phase and composition of trapped hydrocarbons can be improved by taking hydrodynamic conditions and associated hydrocarbon migration conditions into account. For example: the changing pressure and temperature conditions, which influence the

246

Chapter 8

a

Groundwater flow direction

b

Groundwater flow direction is downdip Groundwater flow velocity b < a

c

Groundwater flow direction is updip no potential oil trapping position

IS

downdip

Figure 8.8 Cross-section of isotropic carrier-reservoir rock showing potential oil migration directions and trapping positions for different groundwater flow conditions.

Quantitative analysis of secondary hydrocarbon migration systems

247

Figure 8.9 Map showing potential oil trapping position as determined by the WZ mapping procedure (z = structure contours of top carrier-reservoir rock; vo = groundwater equipotential lines; uo = oil equipotential lines (from Dahlberg, 1982. Reprinted by permission of SpringerVerlag).

hydrocarbon phase and composition during migration, can be estimated from the identified lengths and directions of the hydrodynamic hydrocarbon migration paths; the previously determined trap types and their positions along the migration path influence the composition of hydrocarbons accumulating in successive traps; the probable occurrence and intensity of water washing and biodegradation along the migration path and during filling of the traps can be inferred directly from knowledge on the prevailing groundwater flow systems (Chapter 5). The identified characteristics of secondary hydrocarbon migration can be verified with e.g. the location and physico-chemical characteristics of known hydrocarbon accumulations (e.g. England and Mackenzie, 1989); direct and indirect observations of oil and gas seeps (direct visual observations; indirect observations, such as hydrocarbon-charged sediments, pock marks, clay diapirs); and gas leakages indicated by seismic chimneys.

Chapter 8

248

Different modelling techniques a r e available t h a t can simulate hydrodynamic hydrocarbon migration quantitatively on a basin-wide scale. For example, the Themis migration model simulates separate phase hydrocarbon migration under hydrodynamic conditions. This model i s basically a n extension of the groundwater flow model (Section 8.2.2) through the application of a n adapted two-phase Darcy flow equation (e.g. Doligez et al., 1987; Ungerer et al., 1987a, 1990). Garven (1989) simulated numerically hydrocarbon migration in aqueous solution and in separate phase in a gravity-induced groundwater flow system. Hydrocarbon migration models can be applied to study the role of t h e different parameters affecting migration a n d accumulation of hydrocarbons (e.g. England and Fleet, 1991).

Input “uid-flow data file Digitized section, paleobathy metries,

Compaction laws (effective stress /porosity)

output: Pressures Porosities + Hydraulic head

Input thermal data file

and two-phase flow

Remesblng file Sedlmentatlon rates

output: Transformation ratio

Input hydrocarbon generation and migration data file Kinetic parameters Initial organic matter distribution Relative permeability coefficients HC density and viscosity

(distribution and

Fluid velocities for hydrocarbons and

Figure 8.10 Example of the general organization of a n integrated basin model. The model is organized into five main modules: backstripping, h e a t transfer, single-phase fluid flow, hydrocarbon generation kinetics, and two phase migration These modules may be used separately or together. The four main input data files are 1. geological knowledge of section; 2. single-phase fluid flow; 3. heat transfer, and 4. geochemical data and physical parameters of two-phase migration. (from Ungerer e t al., 1990. Reprinted by permission of the American Association of Petroleum Geologists).

Quantitative analysis of secondary hydrocarbon migration systems

249

8.4 History of hydrocarbon migration systems

A quantitative basin evaluation for petroleum exploration requires a quantitative integrated analysis of the four time-dependent processes (generation, migration, accumulation, and preservation of hydrocarbons) that determine the present hydrocarbon potential of the basin. Computer-aided integrated basin modelling on the basis of numerical simulation provides means to reconstruct these processes and their interactions in time and space on a basin-wide scale. The development of numerical models reconstructing hydrocarbon generation and migration started end -70s (Durand et al., 1984; Ungerer et al., 1984;Welte and Yukler, 1980,1981).A large variety of models has been developed since (Anonymous, 1991;Doligez, 1987;England and Fleet, 1991; Poelchau and Mann, 1989). Two- and three-dimensional models that integrate migration models into comprehensive basin models, reconstruct the tectonic, structural and sedimentological evolution, together with the thermal evolution, the evolution of groundwater pressures, single-phase groundwater flow, generation and expulsion of hydrocarbons and two-phase migration of hydrocarbons and groundwater (Figure 8.10). Computer-aided integrated basin models reconstructing hydrocarbon migration at a basin-wide scale, are used t o increase the understanding of hydrocarbon migration systems and to increase exploration efficiency. As yet, different authors question the use of migration modelling as a stand-alone exploration tool providing reliable quantitative estimates of the volumes and composition of petroleum in traps, because of the uncertainties in parameters and processes, the nonuniqueness of the models and the quality, quantity and distribution of input data (e.g. B u m s et al., 1991; England et al., 1987;Mackenzie and Quigley, 1988;Schowalter, 1991). Important applications of integrated basin modelling include (e.g. Anonymous, 1991; England and Fleet, 1991) - the quantitative evaluation of the consequences of different hypotheses concerning interacting processes of importance for hydrocarbon migration and accumulation; - the quantitative evaluation of the consequences of different boundary and initial conditions on hydrocarbon migration and accumulation; - the determination of the type of parameters the hydrocarbon migration system is sensitive t o (e.g. physico-chemical properties of migrating hydrocarbons, permeability distribution, relative permeabilities; Figure 8.6); - the estimation of the quantity and the nature of hydrocarbons in traps.

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269

SUBJECT INDEX

A Abnormally high pressure, see pressure Accumulation, of hydrocarbons 161-190, 193, 196,199-201,21%222,226,248 Adjustment time 238 Adsorption 17,50,66, 106 Advection 17, 18, 140 Alberta, Canada 65, 140,174,238 Algerian Sahara 157 Allan fault 164 Alps 66 Anisotropy, of permeability 6, 11, 12, 31, 58,71 Apatite fission track analysis 207 Apparent residual saturation 144, 160, 229 Aquathermal effect 27,28, 34, 78,240 Aquathermal pressuring 28, 39, 101, 102, 109,110,202,241 Aqueous solubility, of hydrocarbons 98-101,104,150,183 Aqueous solution, hydrocarbons in 101, 102,104,135,140,141,148-150,155, 161,181,183,186,197-199,212,224,

226,244,245,248 Aquifer, definition 24 Aquitard, definition 24 Atlantic Ocean 51, 54, 158 Aulacogen 22, 41, 42 Australia - Gippsland Basin 157 - Surat Basin 157 - Yeelirrie 68

B Barbados Ridge 51,54,55, 158 Barrier rock, definition, see also cap rock, seal 24, 129 Basin, drainage, definition 55 Basin, sedimentary - defined 23 - classified 22 - relation t o groundwater flow, see ground water - relation t o hydrocarbon migration, see hydrocarbon migration - relation t o hydrocarbon accumulation, see hydrocarbon accumulation - cratonic 22,40,41, 147

- rift 22,75,151 - intracratonic 157 - foreland 52,53,75, 77, 78, 243 Beaufort Basin 36 Bicarbonate 67,186,208,215,219 Big Muddy South Glenrock field, USA 182 Biodegradation - defined 184, 185 - during migration 142, 186, 247 - of reservoired hydrocarbons 166, 18%187,194,215 Biomarker 207, 226 Bitumen 89,97,100,106, 107, 110,114, 115 Bolivar Coastal Fields, Venezuela 186 Brine 48,49,74 Buoyancy - driving force for groundwater flow 14,55,7&75,78 - driving force for hydrocarbon migration 122-125, 196, 199,221 Buoyancy-induced hydrocarbon migration pattern 145-148, 153, 194,223 Burial-induced - flow system 26,34-51,76,78,101, 102,107,149-154,170,178-181, 221-226,239,240 Burial rate, see rate of C Canada,

Alberta 65,140,174,238 Eastern Canadian margin 241 Pine Point 68 Red Earth Region 157, 174,238 Saskatchewan 68 Taber area 157 Venture Field 243 Western Canada Sedimentary Basin 66,70, 140, 157 Capillary pressure 104,105, 109, 125-129, 161,166 Capillary pressure gradient 104, 109, 128, 132, 141, 148, 152, 153, 161, 169, 170,198,199 Cap rock 180,183,187,231 Carbonate 24,30,32-34,42,67,119,208, 211 Carlin, Nevada, USA 68 Carrier rock, definition 97 Carrier-reservoir rock, definition 24 Caspian Basin 42,44, 138 Catagenesis, of organic matter/ kerogen, see organic matter

Subject Index

270

Cementation 29,30,32-34,50,167,207 Central Graben, North Sea 42, 151, 180 Charge, hydrocarbon 194,229,230,245 Chemical composition - of groundwater 12, 17, 18,29, 47-50,62,65,66,141,186, 199,201, 207,208,215,217,219,225,232,233 - of hydrocarbons/petroleum 100, 120,141,183-188,196,197,215,227, 230,245,247,249 Chile 68 China - Dzungarian Artesian Basin 157 - Liaohe Basin 66 Chlorine 67,219 Clay diapir 247 Clay minerals 19, 30, 34, 48,50, 78,240 Coal, formation of 86, 9 1 Coalification of organic matter 91, 92 Compaction - chemical 30, 34 - mechanical 27, 29, 32, 241 - ofcarbonates 33 - of coarse-grained sediments 32 - of fine-grained sediments 30 - undercompaction 31, 35,48, 112, 204,220 Compaction disequilibrium 31, 34, 35, 242 Compaction equilibrium 30, 31, 34, 35, 202,204 Compaction equivalent depth 204 Composition - of hydrocarbons, change during migration 141-143,227,247 - of reservoired hydrocarbons 183-188,215,245 Compositional fractionation 110, 111, 114,188 Compressibility - ofgroundwater 8 , 9 , 14, 18 - of porous rock matrix 8, 9 - of solid grains 8, 18 Condensate 83, 115, 116, 120, 179, 180, 184,196 Condensate-gas ratio 83 Conductivity - hydraulic 6, 13, 21, 28, 29, 39,46, 208,209 - thermal 16,47,48,71,207,216 Connate 67,69,215 Conservation - of chemical mass 17, 18, 20 - of groundwater mass 15, 18, 20 - ofheat 16,20

- of solid mass 15, 16, 20 Continuity equation, for fluid flow 6, 7, 10, 11, 15, 18, 19 Convection - of heat 16,47,207,241 - of hydrocarbons 135, 140 - of solutes, of chemical mass 17 - see also free convection Coupled flow 13,18,21,209,237,243 Cracking 91,94,95, 110, 116, 119, 187, 193 Cratonic basin, see basin Critical height, of hydrocarbon column 128,129,137

D Darcy’s equation, Darcy’s law 5, 6, 10-15,18,20,70,241 for two-phase flow 105, 131-133, 139,144,248 Deasphalting 187 Degradation - of organic matter 86, 88,91, 94, 95 - of petroleum, see biodegradation Dehydration 19,28,34,39,50,78, 101, 240,241 Density - of gas 123,124,143,149 - of groundwater 4-10, 13-20,58, 7@--74,202,230,232,233,239,240, 244 - of hydrocarbons 118,135,139, 141-145,151,157,171,198,199,230, 244 - of oil 118, 123, 124, 131, 143, 149, 172,185,187 Denver Basin, USA 138 Depocentre - effective 145,147,151,211 - identification of 212 Di agen e sis - of organic matter 86-91, 119 - of sedimentary rocks 51, 67, 164, 166,174,208 Diagenetic minerals 47, 51, 63, 67, 79, 199,226 Differential entrapment - leak 168 - spill 168 Diffusion - ofhydrocarbons 105, 111-115,119, 120,122,129,135,140,145,183,184 - of solutes 17,49 Diffusion equation for groundwater flow ll,l2

-

271

Subject Index

Discharge area, groundwater 57, 109, 138,155,i57,170,171,177,1ai,182, 186,187,214,217-219,222,225,243 Dispersion - of hydrocarbons 135,140,159 - of solutes 17,18 Displacement pressure 126,127,129, 162, 163,182 Drainage area 229 Drainage basin 55-61, 177,234,235 Drainage volume 144,229 Dry gas, see gas Dynamic pressure increment 233-235, 238,239 Dzungarian Artesian Basin, China 157

E Effective permeability 105,131,132, 141, 143,144,198 Effective stress, see stress Equation of state - of the groundwater 5,9, 10,13,14, 20 - of the hydrocarbons 230 - of the porous medium 5,9,10 Equipotential - of groundwater 5,6,134,171,233, 244,247 - of hydrocarbons/petroleum 161, 167,169,171,172,174,244,245,247 Erosional unloading 69, 70 Evaporites 49,163,211 Expulsion, of hydrocarbondpetroleum 84,97,105,109,120,193,196, 197,229, 230,249 Expulsion eficiency, petroleum 115-118 Expulsion rate 117

- methanogenic 74 - thermal 71-73,243 - thermohaline 73,74,243

G Gas, definition 83 Gas - biogenic 91 - dry 83,91,96,115,120,196 - wet 83,91,180 Gas condensates, see condensates Gas deasphalting, see deasphalting Gas-oil ratio 83,142,184 Gas-water contact 161,167,171,188 Gaseous solution 187 Geochemical fossil 88, 91 Geothermal gradient 11, 48,66,71,73, 86,95-97,101,119,185,206,207,215, 216 Germany, Rhine Graben 157 Gippsland Basin, Australia 157 Grainsize 28,207,208 Great Lowland Basin, Hungary 157,174 Groundwater - chemical composition, see chemical composition - chemical composition, analysis of 207,208,215,219 - compressibility 8, 9, 14, 18 - density, see density - head, see head - heat capacity 16,71 - of meteoric origin, see meteoric - potential (energy), definition 4 - pressure, see pressure - salinity, see salinity - thermal expansion 14,18,71,107,

-

F Fault

-

as conduit for groundwater flow 46-55,79,213,221,240 - a s conduit for hydrocarbon migration 131,141,145,147,150, 158,188,242,243 - as barrier for hydrocarbon migration 161,164,166,170,179, 182,196,242,243 Fluid inclusion 207,208,226 Fractionation 110,111, 114,188 Fracture 12,211,213 - hydraulic fracture, hydrofracture 46,240 - microfracture 110 Free convection

120

viscosity 6,13,14,27,29,58,70,71, 141,143,232,239,240 Groundwater flow - continuity equation 6,7, 10, 11, 15, 18,lS - cross-formational 35,37,38,49,50, 55,62,63,65,77-79,102,149, 154, 174,178,181,233,239 - discontinuous 46 - driving forces, general 3-5, 12,21, 24,26,42,51,55,79 - episodic, periodic 46,47,53,55,78, 79

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focussed, concentrated, preferred 42,47,48,5&55,61,78,79, 181,182, 199,214,217,219-224,232,239,240,

Subject Index

243

laminar 12 rate, velocity 4, 11,17,27,34,44, 46,58,66, 73, 77,240,242 restricted 149, 180, 239 specific discharge 6, 12, 19, 61, 70, 79

steady-state 7, 10, 11, 15,20, 62, 69, 215217,238 steady-state, Laplace equation 10, 12

unsteady-state 7, 11, 15,20, 69, 70, 239 unsteady-state, Diffusion equation 11,12 Groundwater flow system - classification, general 24 - burial-induced - driving forces 26-28 - subsystems 37,38, 195 - flow pattern 42-47, 195 - thermal characteristics 47, 48 - chemical characteristics 48-50 - gravity-induced - drivingforces 55, 79 - flow pattern 56-73, 194 - thermal characteristics 63-66 - chemical characteristics 66, 67 - tectonically-induced - driving forces 51, 52 - flow characteristics 51-55 - local - free thermal convection 71-73 - free thermohaline convection 73,74 - methanogenic convection 74 - osmotically-induced flow 74, 75 Gulf of Mexico Basin 28, 39, 40, 46, 52, 7577,151,241,243 Gulf,The 174 H Halite 49, 66, 74 Haltenbanken area, Norwegian Shelf 174,179 Harlingen gas field, The Netherlands 183 Head, groundwater - definition 4 - equivalent fresh water 233 - hydraulic head 4,6, 10-13, 56, 58, 60-62,69,77,234,235 - total head 4 Heat capacity - of groundwater 16, 7 1

Heat flowhansport - conductive 16,47, 64,65,206,207, 241 convective 16,47,207,241 - general 11, 13, 16,21,23,24,48,65, 66,71,72,75,80,95,200,209,216, 218,219,221,237,243,248 Heterocompounds (NSO) 99 Holding capacity of traps - hydrostatic 162-168 - hydrodynamic 169-178,181,182, 194,195 Horner method 201,205,206 Hubbert's mapping procedure 244 Hungarian Basin 66 Hydraulic conductivity, see conductivity Hydrocarbon column - critical height 128, 129, 137 maximum height 162, 167,170,171 Hydrocarbon migration, petroleum migration definition 84, 121 - see primary migration see secondary migration Hydrocarbon saturation, of pore system 101,105-107,131,132,143,166,167 Hydrocarbon source rock, petroleum source rock, see source rock Hydrocarbons aqueous solubility 98-101, 104, 183 - chemical composition, see chemical composition - density, see density - expulsion, see primary migration - generation 6647,193,224,241, 248,249 generation stages 86, 87,93 - Viscosity 141-144, 184, 185, 198,230 Hydrodynamic traps, see traps Hydrogen index 93, 118,203 Hydrogeohistory 225, 239 Hydrogeological framework, definition 24,209 Hydrogeological unit, definition 24, 25, 211 Hydrostatic, pressure gradient 26, 239 Hypsographic distribution 233, 237,238 Hypsographic curve 236,237

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I Illinois Basin, USA 44, 66, 157 Illite 28,32, 50,51 Immature, source rocks 91, 93 Indicators - of groundwater flow systems

Subject Index

47-51,63-69,214216,219,232,237,

243 - of pressure 201-205,220,225,240 Indonesia, Mahakam Delta 241,243 Infiltration, of meteoric water 24,66,75,

77-79,221 Interfacial tension 104,125,127,143, 162,163 Intra-plate stress, see stress Intrinsic permeability, definition 6 Intrusion, igneous, magmatic 73, 75, 80, 207,243 Isotherm 48,71,73,200,216,221 Isotope 65,208,215,233

J Jamaica 68

K Kaolinite 19,28,32,67 Kennedy Basin, USA 63 Kerogen - definition 89 - inert 94 - labile 95,96 - refractory 95,96 - thermal degradation of - during diagenesis 91 - during catagenesis 91 - during metegenesis 91 - type1 89,95 - type I1 89,93,95,110,116,118 - type I11 89,91,93,95,110

273

150,151,155,180,182,211,221 Membrane, semi-permeable 48, 74, 75, 150,198 Membrane filtration 48,49,75 Metagenesis of organic matter, of kerogen 86,90,91,93,102 Meteoric, see also infiltration 33, 34,49, 56,65-67,75-78,109,166,215,221,225 Methane 7491-104,110,111,150,158,

183 Micelle 103 Michigan Basin, USA 157 Microbial degradation, see biodegradation - generation of gas 91 Microfracture 110 Migration, see primary and secondary migration Modelling, see also numerical simulation of groundwater flow 42,53,77,200, 232,238,239,241,243 of groundwater flow and heat flow 64,209 - of hydrocarbon generation and migration 249 - of hydrocarbon migration 140, 230,248,249 of pressure generation 39,77,241,

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-

-

243

Moisture 63,69,214,217, 233 Mud weight 203,205,220

N L Laminar, flow of groundwater 12 Laplace equation 10, 12 Liaohe Basin, China 66 Lithostatic gradient 27,38,39,52 Lithostatic pressure 39,52,54 Loading - sedimentary 28,32,34,42,51, 77, 78,149,207 - tectonic 53,77,207 Lublin Synclinorium, Poland 157

M Mahakam Delta, Indonesia 241, 243 Maturation - of crude oil 187 - of organic matter, of kerogen 93, 105 Mature, geologically mature 22,55,62, 101,216 Mature, source rocks 91, 110, 112,117,

Network, of kerogen, of organic matter 105,107,109,114,115 Niger Delta, Nigeria 151, 179 North Sea Central Graben 42,151,180 Forties Field 165 Haltenbanken area 174, 179 Snorre Fieldarea 180 T a m p e n s p u r 165 Viking Graben 37,42,107,108, 138,151,154,179 North Sea Basin 40,51,52,138,186,241 Norwegian Central Graben 181 Norwegian Shelf 174 Numerical simulation, see also modelling of groundwater flow 140,209, 215217,236,239 of groundwater flow and heat flow 209,237,241 of hydrocarbon generation and

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-

Subject Index

274

migration 241,249 - of hydrocarbon migration 140,248 - of pressure generation 241,243

0 Offshore Qatar 157 Oil, definition 83 Oil -water contact 161,167,171,182, 185,186,188 Oil -wet 107,126,166 Oil window 91,118, 180 Ore deposits 67,208 Organic matter - accumulation and preservation of 85,86 - (chemical) composition of 85, 111 - evolution of, maturation of 86-91 - production of 85 Osmosis 70,74,75,80,141 Osmosis, reverse 75 Overmature 180,221 Overpressure, see pressure

P Paleo

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geographic 225 geological 237 - groundwater flow 225,226 - hydrogeological 237,238 - migration (system) 197 - pressure 225,226 - temperature 207,225,226 - topography 225,238 Palo Duro Basin, USA 25,62,63 Parentis Basin, France 157, 174 Paris Basin, France 241,243 Permeability - basin-scale 12,28-34,4042,199, 208,209,216,220,232,237,239 - effective 105,131,132,141,143,144, 198 - intrinsic, definition 6 - loss 28-34,37,151 - relative 106,132,249 - spatial variability 12,28-34,40-42, 61-63,67,174,175,179,181

Petroleum, definition 83 Petroleum expulsion efficiency 115, 116, 118 Petroleum generation index 93, 115 Petroleum migration, hydrocarbon migration - definition 84, 121 - see primary migration - see secondary migration

Petroleum source rock, hydrocarbon source rock, definition 83 Phase behaviour of petroleum 230 Phase changes of petroleum 142,166 Phreatic surface 237 Pine Point, NW Territories, Canada 68 Poisson’s ratio 18 Pore diameter, radius 104,106,127,129, 133 Pore throat 103,104,106,109,126129, 138,143,162 Porosity - loss, change in 7,9,15,19,29-35, 67,163 - primary 32,34,109 - secondary 32-34 Potential (energy) - of gas 123,169 of groundwater, definition 4 - of hydrocarbons 97,107,109,144, 161,169,170,19&198,224,244,245 of oil 123,169 Potential, of source rocks to generate hydrocarbons 93-97,105,115-118,193, 248,249 Potentiometric surface 233,236,237,239, 240,243 Preservation, of reservoired hydrocarbons 183-188,193,196,249 Pressure, capillary 104, 105,109, 125-129,161,166,169 Pressure, of groundwater hydrostatic gradient 26,239 lithostatic gradient 27,38 subhydrostatic 63,70,74,79, 155 underpressure 61,63 superhydrostatic, excess, supernormal, overpressure 27, 28, 3546,51-54,57,74,79,101,107,155, 174,179,180,202-204,239,242 abnormally high 27,28, 107,110, 112,154,217 geopressure 3840,149,151,152, 158,170,180,181,220,232,239,240 indicators of 201-205,220,225,240 Pressure barrier, see also seal 102,147,

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233 Pressure solution 15,19,29,32,34,37 Primary migration, of hydrocarbons - definition 84 - in rnieellar solution 103 - in molecular solution 99-103 - in separate phase 103-111 - by diffusion 1 1 1- 115

Subject Index

- change in composition during, see fractionation - rate of 117

R Rate - of burial 39,78,87,220 - of sedimentation 31,34,39,44,46, 47,52,75,85,220,225 - of subsidence 39,40,42,78,149, 153,220 - of groundwater flow, see groundwater flow - of hydrocarbon expulsion 117 - of secondary hydrocarbon migration 198,230,245 Rayleigh number 71, 73 Recharge area 56,57,61,67,79, 109,155, 181,182,186,187,214-219,225 Red Earth Region, Canada 174,238 Relative permeability 106,132,249 Remigration, of hydrocarbons, of petroleum 84,154,155,188 Representative Elementary Volume 5, 7,8,10,11,16,17,19 Residence time, of groundwater 66,67, 215,216 Residual saturation, of oil, of hydrocarbons 144, 160,229 Rhine Graben, Germany 157

S Salinity, of groundwater 15,47-51, 58, 65-67,74,79,99-103, 181,186,187,199, 215,217,221,232,233,240,243 Salt diapir 46,74,141,145,147,150,221, 243 Salt sieving, see also ultrafiltration 75 San Manuel, Kalamazoo, USA 68 Saturation, of the pore system with oil, hydrocarbons, see hydrocarbon saturation Sea level 4,69,76,77,188,213,214,216, 225,238,241 Seal, see also barrier rock, cap rock 129,131,162-164,169,170,182,198 Seal failure 47,151,159,170,180,240, 243 Sealing capacity, of rocks, of faults - in hydrostatic basins 162-168 - in hydrodynamic basins 169-183, 224,240,243,244 Secondary migration, of petroleum, of hydrocarbons - compositional changes during,

275

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-

phase changes, biodegradation 141-144,186,247 definition 84, 121 distance of 140,141,147,157,224,

230

driving forces, general 122-140, 156,197-199,221 - efficiency 144,145 - focussed 147,151,152,158,159,161, 196,222,224 - losses 121,141,143,145,147,158, 227,230,245 - preferred 145,159,196,222,224,

-

2%

restricted 151,159,180,222 specific discharge, rate, velocity of 133,134,139,230,245 Secondary migration system - classification of 141 - hydrostatic system, general 16148,194 - hydrodynamic system, general - in tilling and subsiding basins 149-154,194,222 - in stable subaerial basins 154-157,194,222 - in tectonically active basins 157-158,222 Sedimentary basin, see basin Seismic chimney 247 Seismic pumping 47 Smectite 19,28,67 Snorre field, North Sea 180 Solubility - of hydrocarbons in water, aqueous solubility 98-101,104,150,183 - of oil in gas 110,111 Source rock, hydrocarbon, petroleum, definition 83 Specific discharge - of groundwater 6,12,19,61,70,79 - of hydrocarbons 133,134,139,230, 215 Specific storage 10, 18,39 Spill 167,168,187,188 Steady-state, flow of groundwater 7, 10, 11,15,20,69,215-217,238 Strain 8 Stress compressive 52,79 - effective 8,9,15,27,29,32,52,241 - intra-plate 52 principal 46,55, 110 - tectonic 5,51,52 thermal 107

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Subject Index

276

- total 8, 9,11, 15,18,26,27,29 - vertical 8,52,54 Structured water 106 Stylolites, stylolitization 32,34,37 Subhydrostatic pressure, see pressure Sulfate 67,208,215,219 Sulfur 83,86,89,91,98-101,103,104,184, 186 Superhydrostatic pressure, see pressure Surat Basin, Australia 157 Suspended, hydrocarbons 151, 198,224 Suspension, hydrocarbons in 140, 141, 148-151,155,197,199,212,226,244 Synsedimentary water 34,48,215

T Taber area, Canada 157 Tampen Spur, North Sea 165 Tectonics - and groundwater flow 11, 51-55, 225,232,240,243,249 - and hydrocarbon migration 107, 147,157,158,222,226,249 - and hydrocarbon accumulation and entrapment 182,183,187,188, 226,249 Temperature gradient, profile 3, 12, 13, 64,198,218 Texas, USA 68 Thames valley area, UK 62 The Gulf 174 The Netherlands 183, 200 Thermal 71,95,207, conductivity 16,47,48, 216,218 cracking, see cracking see degradation expansion coefficient, of groundwater 14,18,71 maturation, of crude oil see also maturation 187 Thrust, thrusting 51,53,54, 166 Topography-induced flow, of groundwater 55 Total Organic Carbon (TOC) content 93,105,114, 118 Trap combination 161,164,166,169,196 complex 166 hydraulic 177, 178,182 hydrodynamic 169,171,174-179, 194,195,224-247 hydrostatic 161,167,169-172, 174, 177,181-183,194-196,229 kinetic 168,183

- stratigraphic 161,164, 167,182,196 - structural 161,164,165,169,196 Trapping energy condition 162,188, 196

U Uinta Basin, USA 64,66,237 Ultrafiltration, salt sieving 75 Undercompaction, undercompacted rock, see compaction Unsteady-state flow, of groundwater 7, 11,15,20,69,70,239

V Van Krevelen diagram 90 Venture Field, Canada 243 Viking Graben, North Sea 37,42,107, 108,138,151,154,179 Viscosity - of groundwater 6,13,14,27,29,58, 70,71,141,143,232,239,240 - of oil, hydrocarbons 141-144,184, 185,198,230 Vitrinite reflectance 87,93,207,226 Velocity, rate - of groundwater flow, see groundwater - of hydrocarbon migration, see secondary migration

W Water table 51,55,67,69,79,188,216, 217,232,233,237,238,243 Water washing 183,186,187,194,215, 247 Water-wet 104,105,107,126-128,166 Well test 201,205,208 Western Canada Sedimentary Basin 66,70,140,157 Wet gas, see gas Wettability 103, 104,125,166 Williston Basin, USA 66