SANDSTONE DIAGENESIS AND ITS RELATION TO
PETROLEUM GENERATION AND MIGRATION IN THE NIGER DELTA
A THESIS SUBMITTED FOR THE DEGREE OF DOCTOR OF
PHILOSOPHY OF THE UNIVERSITY OF LONDON
BY
DANIEL OMOREGBE LAMBERT-AIKHIONBARE B.Sc. M.Sc. D.I.C.
GEOLOGY DEPARTMENT ROYAL SCHOOL OF MINES IMPERIAL COLLEGE OF SCIENCE AND TECHNOLOGY LONDON
NOVEMBER 198 1 DEDICATED TO MY PARENTS., GBINOSA & ATITI,
and
TO MY LOVING CHILDREN, EH I, IMADE & AME, i
ABSTRACT
The sediments of the Niger delta consist of three lithostra- tigraphic units - the pro-delta shales of the Akata Formation, the paralic sandstones and shales of the Agbada Formation, and the continental sands of the Benin Formation. Detailed petrological analyses of the sediments of the Agbada Formation have been carried out to determine their diagenetic history and explain their underconsolidation. The sandstones are poorly cemented quartz arenites containing a small quartz and clay matrix as well as a small amount of carbonate cement. The reasons for the inadequate supply of cementing materials are investigated. Early calcite cementation inhibited compaction and resulted in poor packing; later removal of this calcite generated secondary porosity at depth.
The effect of burial diagenesis on the clay assemblages of the shale and sandstones of the Agbada Formation are limited and the clay mineralogy is predominantly a detrital assemblage. Compared to the hydrocarbon reservoir sandstones, the non- hydrocarbon reservoirs are richer in authigenic minerals namely kaolinite, smectite, siderite and pyrite. This has been inter- preted as an indication of early migration of hydrocarbons, into the reservoirs, which is at variance with the previously favoured theory of late petroleum migration from the Akata shale source beds. Data from Elemental Analyses of the shales of the Agbada Formation give carbon contents ranging from 0.8 to 3.50 weight % while those of their concentrated kerogen give values ranging from 49.93 to 71.80 weight %. A plot of atomic ratios Hydrogen/ Carbon (H/C; 0.96-1.40) versus Oxygen/Carbon (0/C; 0.08-0.22) on the Van Krevelen diagram shows that the kerogen are Type II with major contributions from Type I. Carbon ratios (0R/Cm=0.16-0.53)
contd and palynomorph colouration (light yellow - orange) indicate that shales at depths.of 1,700m in the flanks and 2,200m in the depocentre have entered the catagenetic zone. These results and the evidence of early entry of hydrocarbons into the reservoirs suggest that the shales of the Agbada Formation are the major source of petroleum in the Niger delta. iii
ACKNOWLEDGEMENT
My most sincere gratitude goes to my supervisor Dr. Peter Bush, whose support, encouragement and suggestions proved most valuable during the course of this research. His criticism of the script and the suggestions he offered have led to a major improvement of the ideas expressed in this thesis. I am also grateful to Dr. Harry Shaw who was particularly helpful at all stages of the project. He was most helpful with the aspect of clay mineralogy and diagenesis. I wish to express my profound gratitude to the University of Benin, Benin City, Nigeria who financed this research and granted me leave of absence to carry out the research. The Nigerian National Petroleum Corporation (NNPC) funded some of the field trips of this project. I also wish to thank my good friends Mr. & Mrs. Grant and Mr. & Mrs. Soares for their financial as well as moral support. Let me express my gratitude to the NNPC and in particular Messrs G. Grant and A. Adam without whose help it would have been impossible to secure the samples for this study. The co-operation of Gulf Oil Company, Nigeria (my previous employers) in this respect is highly appreciated. I am particularly grateful to the then Exploration Manager, Mr. P. Howe and the Chief Geologist Mr. 0. Ariyo for their assistance. Mobil Producing, Nigeria, Shell Development Oil Company, Nigeria and Agip Oil Company, Nigeria, also provided some samples. I must not fail to mention the assistance of my former colleagues Dr. F. Fatona, Dr. A. Ibe and Mr. G. Oshahon during the period of this research. Their knowledge of the Niger delta and their willingness to discuss the problem made them the spring board against which many of the initial ideas were tested.
contd.... iv /2.
Their numerous suggestions and their diligent proof reading have greatly improved the presentation of ideas. I also wish to thank Dr. K. Weber of Shell Research Laboratory in the Hague, Dr. L. Caflisch of Gulf Research and development center in Houston, and Dr. R.C. Selley of Imperial College for assisting to formulate the problems investigated. I am also grateful to Prof. D. Shearman, Prof. R. Stoneley Dr. G. Evans, Dr. R. Kinghorn, Mr. P. Grant, Mr. R. Curtis, Mr. R. Giddens, Mr. R. Hodgkinson, Mr. M. Gill, Miss M. Pugh, Miss G. Lau, Mrs. E. Hin, and Mr. M. Rahman all of Imperial College for their assistance at various stages of this project. Mr. M. Rahman was particularly helpful with the analysis and interpretation of the organic geochemical aspect of this study. I am also grateful to Mrs. C. Yisa who typed the thesis. Finally, I am grately indebted to members of my family and my wife's family for their moral and financial support during the period of this study. The love of my wife and children, their understanding and ability to cope at financially difficult times during this period, gave me the courage to go on at all times. V
CONTENTS
Page Abstract i Acknowledgement iii Contents v List of figures x List of tables xvi
CHAPTER 1. GENERAL INTRODUCTION
1.1 Introduction 1
1.1.1 Location 1 1.1.2 Climate and Vegetation 3
1.1.3 Brief history of the Nigeria Oil Industry 5 1.2 Aim and Scope of work 10
1.3 Synopsis of previous work on the general geology of the Niger delta 11 1.4 Brief review of deltas 15
CHAPTER 2. THE GEOLOGY OF THE NIGER DELTA
2.1 Evolution of the Niger delta 19
2.2 The Modern Niger delta 25
2.3 Stratigraphy 2 9
2.3.1 The pre-Tertiary 29 2.3.2 The Tertiary 35 a) The Akata Formation 37 b) The Agbada Formation 39 c) The Benin Formation 43 2.3.3 Comments 45
2.4 Structural Geology & Hydrocarbon occurrence 45
2.4.1 Structural geology 45 2.4.2 Hydrocarbon occurrence 53 vi
CHAPTER 3. PETROLOGY OF THE AGBADA FORMATION Page 3. 1 Introduction 54 3. 2 Methods of study 54 3. 2.1 Sources of samples 54 3. 2.2 Analytical methods 57 a) Thin section petrography 57 b.i) X-Ray Diffraction 58 b ,ii) Micro-sieve analysis 61 c) Scanning electron Microscopy 62
3. 3 Terminology and Classification 64
3. 4 Mineralogy and Physical properties of Minerals 69
3. 4.1 Detrital framework grains 69 a) Quartz 69 b) Feldspar 72
c) Rock fragments 75 3. 4.2 Matrix 75 a) Quartz 75
b) Clays 79 3. 4.3 Accessory Minerals 79 3. 4.4 Cementing Materials 82 a) Carbonate cement 82 b) Secondary Quartz 86
3. 4.5 Non-binding diagenetic Minerals 88 a) Pyrite 88 b) Gypsum 88
3. 5 Non diagenetic variations in mineral assemblage of the Agbada Formation 90
3. 6 Provenance 93 vii
CHAPTER 4. DIAGENESIS OF THE SEDIMENTS
OF THE AGBADA FORMATION
Page 4.1 Introduction 94 4.2 Physical diagenesis in the sediments of the Agbada Formation 96 4.2.1 Re-arrangement of grains and grain bending 96 4.2.2 Grain. fracturing 99 4.2.3 Grain squeezing 99 4.3 Diagenesis of the Agbada Formation, shales 99 4.3.1 Comparison between the Agbada and Akata shales 105 4.4 Diagenetic clays in the Agbada Sandstones 10.7 4.5 Cementation of Agbada sandstone 118 4.5.1 Effect of poor compaction and early calcite cementation 119 4.5.2 Silica cementation 125 i) Normal solubility of quartz 126 ii) Replacement of quartz by carbonate 13l iii) Alteration of clays during diagenesis 13-2
iv) Transformat ion of feldspars 13 2 v) Pressure solution 134 a) Clay coating 136 b) Early calcite cementation 137
c) Flushing of formation water 137
4.6 Paragenesis of minerals 14l
4.7 The effects of diagenesis on the porosity and permeability of Agbada sandstones 14.4 viii
CHAPTER 5. SOURCE ROCK EVALUATION OF SHALES OF THE AGBADA FORMATION Page 5.1 Introduction 153
5.2 Method of study 255
5.2.1 Sample preparation 256 a) Pulverisation 256 b) Maceration 256
5.2.2 Geochemical analytical techniques 259
5.3 The concept of organic geochemistry 266 5.3.1 Amount and type of organic matter 263 5.3.2 Level of maturation of organic matter 271 5.3.2 Stages of maturation of organic matter 274
5.4 Results and Interpretations 281 5.4.1 Organic carbon content C^ 281 5.4.2 Type of organic matter 281
5.4.3 • Pyrolysis CR/CT 293 5.4.4 Carbonisation 208 5.5 Geothermal gradients in relation to the paleotemperatures 208
5.6 Discussion 211
CHAPTER 6. GEOLOGICAL FACTOR BEARING ON THE yr . . .•'••'— ORIGIN OF HYDROCARBONS IN THE NIGER DELTA 6.1 Introduction 213
6.2 Overpressuring of the Akata shales ;214
6.3 Growth faults & oil migration in the
Niger delta 217
6.4 Non-faulted reservoirs 223 6.5 Variation in crude properties 224
6.6 Evidence from inorganic diagenetic studies ^25 Their numerous suggestions and their diligent proof reading have greatly improved the presentation of ideas. I also wish to thank Dr. K. Weber of Shell Research Laboratory in the Hague, Dr. L. Caflisch of Gulf Research and development center in Houston, Dr. R.C. Selley and Dr. R. Dawe both of Imperial College for assisting to formulate the problems investigated. I am also grateful to Prof. D. Shearman, Prof. R.'Stoneley Dr. G. Evans, Dr. R. Kinghorn, Mr. P. Grant, Mr. R. Curtis, Mr. R. Giddens, Mr. R. Hodgkinson, Mr. M. Gill, Miss M. Pugh, Miss G. Lau, Mrs.E. Hin, and Mr. M. Rahman all of Imperial College for their assistance at various stages of this project. Mr. M. Rahman was particularly helpful with the analysis and interpretation of the organic geochemical aspect of this study. I am also grateful to Mrs. C. Yisa who typed the thesis. Finally, I am grately indebted to members of my family and my wife's family for their moral and financial support during the period of this study. The love of my wife and children, the understanding and ability to cope at financially difficult times during this period, gave me the courage to go on at all times. X
LIST OF FIGURES
Figures Page
Figure 1.1 Sketch map of the south Atlantic African Coast line showing the basins developed in the Cretaceous Figure 1.2 Sketch map showing the main geologic features of southern Nigeria 4 Figure 1.3 Sketch map showing the main physiographic features of the Niger delta. 6 Figure 1.4 Map of southern Nigeria showing some major oilfield locations 8 Figure 1.5 Graph of exploration and production activities in the Niger delta 9 Figure 2.1 Sketch map of southern Nigeria showing the configuration of the sedimentary rocks 18 Figure 2.2 Comparison between the Gulf of Guinea triple junction and the inverted version of- the Red Sea, Gulf of Eden—Afar triple junction 20 Figure 2.3 Comparison of the structure and configuration of the Benue trough and the Cameroon line 22 Figure. 2.4 Sketch map of southern Nigeria showing the paleogeography of the Cretaceous 24 Figure 2.5 Schematic cross section of the Niger delta showing the relationship of the lithostratigraphic units. 26 Figure 2.6 Sketch map of southern Nigeria, showing the various positions of the coastline through time as the delta prograded southwards. 28 Figure 2.7 Sketch map showing the major tectonic units of the pre- Santonian of southern Nigeria 30 Figure 2.8 Stratigraphic synopsis of southern Nigeria basins 32 Figure 2.9 Sketch map of southern Nigeria showing post- Santonian tectonic units 34
Figure 2J.0 Subsurface stratigraphy of the Niger delta and its main surface equivalents 36 Figure 2.11 Log motif of the major formation units in the Niger delta 40 xi
Figure Page
Figure 12 Major features of a growth fault in the Niger delta 44
Figure 2.13 Schematic representation of the stages in the formation of a growth fault 48
Figure 2.14 Schematic representation of the collapse crest structure of the growth fault in the Niger delta 50 Figure 2.15 Sketch of Niger delta showing the area of concentration of petroleum reserves 52 Figure 3.1 Map of Niger delta showing area of active exploration and sample boreholes 55
Figure 3.2 X-ray diffractograms showing stages in the identification of the clay minerals of the Niger delta 59 Figure 3.3 Sandstone classification diagrams 63
Figure 3.4a Scanning electron micrograph of Conhoidal frature in quartz grains. (Agbada Formation, Meren field - 1744m) 67 Figure 3«4b Photomicrograph of replacement of quartz edges by calcite cement (Agbada Formation Figure 3.5a Photomicrograph of zircon inclusion in quartz (Agbada Formation) Figure 3.5b Photomicrograph of quartz encircling quartz (not overgrowth) 53
Figure 3.6a Scanning electron micrograph of clay coat- ing on detrital grains (Agbada Formation, Meren field - 1396m) 70 Figure 3.6b Scanning electron micrograph of clay coating on quartz grains (Agbada Formation, Idama field - 2915m) 70 Figure 3.7a Scanning electron micrograph of initial stages of etch pit development on quartz grains (Agbada Formation, Robertlciri field - 981m) 71
Figure 3.7b Scanning electron micrograph of late or advanced stages of etch pit development (Agbada Formation, Robertkiri field - 1707m) 71
Figure 3.8a Photomicrograph of a polycrystalline quartz showing sutured contacts (Agbada Formation) 73
Figure 3.8b Photomicrograph of a large relatively unaltered feldspar grain, common in Agbada sandstone of the eastern Niger delta 73 xii
Figure Page
Figure 3.9a Photomicrograph of a small highly altered feldspar grain, common in Agbada sandstone of the western Niger delta 74 Figure 3.9b Scanning electron micrograph of diagenetic feldspar on feldspar (Agbada Formation, Meren field - 1396m) 74
Figure 3.10a Photomicrograph of open packing in Agbada sandstone 78 Figure 3.10b Photomicrograph showing distribution of micro crystalline siderite cement 78
Figure 3.11 Photomicrograph of residual calcite cement in Agbada Formation 83 Figure 3.12a Scanning electron micrograph of fractured quartz overgrowth (Agbada Formation, Olure . field - 3039m) 85 Figure 3.12b Photomicrograph of quartz overgrowth replaced by calcite in Agbada sandstone 85
Figure 3.13a Scanning electron micrograph of tiny spkies of quartz overgrowth - initial stages of quartz overgrowth development in Agbada Formation. Isan field - 1971m 87
Figure 3.13b Scanning electrom micrograph of rhombohedral pyrite in Agbada sandstone. Robertkiri field - 2076m ' 87 Figure 3.14a Scanning electron micrograph of well formed gypsum crystals aggregated into a rossette (Agbada Formation, Gbokoda field - 3099m) 89 Figure 3.14b Scanning electron micrograph of fibrous gypsum in Agbada sandstone. Meren- field - 1052m 89 Figure 3.15 X-ray diffractograms of Agbada sandstones showing inverse relationship between the relative amounts of feldspars and clays 91 Figure 4.1a Photomicrograph of mica grain bent round a detrital grain in response to stress. Agbada Formation 97
Figure 4.1b Photomicrograph of a mica grain fractured in the process of folding round a quartz grain. Reaction to stress probably due to overburden pressure. Agbada Formation 97
Figure 4.2a Scanning electron micrograph of bent shale lamina in response to stress (Agbada Formation, Idama field - 2915m) 98 xiii
Figure Page
Figure 4.2b Photomicrograph showing fractured feldspar in response to stress. Note the altera- tion of feldspar in the fracture zone (Agbada sandstone) 98 Figure 4.3a Photomicrograph of artificially induced fracture on quartz grain. Agbada Formation 100
Figure 4.3b Photomicrograph of a mica grain squeezed between two detrital grains and developing apseudo fan in the process. Agbada sandstone 100 Figure 4.4 Schematic representation of the trend of clay diagenesis with increased burial depth 101
Figure 4.5 Comparison of X-ray diffractograms of Agbada and Akata shales 103 Figure 4.6 X-ray diffractograms of Agbada shales 104 Figure 4.7a Scanning electron micrograph of book-like kaolinite in Agbada sandstone, Meren field - 2126m 109 Figure 4.7a Scanning electron micrograph of book-like and vermicular kaolinite in Agbada sandstone, Robertkiri field - 3609m 109 Figure 4.8a Scanning electron micrograph of corroded kaolinite platelets in Agbada sandstone, Meren field - 2125m 110 Figure 4.8b Scanning electron micrograph of diagenetic kaolinite showing a higher degree of alteration, Delta south field - 2771m) 110 Figure 4.9a Scanning electron micrograph of diagenetic smectite exhibiting the honeycomb structure (Agbada Formation, Makaraba field - 1999m) m Figure 4.9b Scanning electron micrograph of detrital illite showing diagenetic growth at edges. Agbada sandstone, Meren field, 1744m 111 Figure 4.10a Scanning electron micrograph of initial stages of development of filaments of illite in Agbada sandstone. Makaraba field - 3296m 113
Figure 4.10b Photomicrograph showing alteration of feldspar to clay (Agbada sandstone) 113 Figure 4.11 Schematic representation of a log motif in an oil 116 sand (Agbada Formation) in western Niger delta
Figure 4.12a Photomicrograph showing tangential contacts between the grains of Agbada sandstone 126 xiv
Figure
Figure 4.12b Photomicrograph of Agbada sandstone showing the role of calcite cement in preventing grain contact 120 Figure 4.13 Seismic profiles showing the strong shallow reflection 122 Figure 4.14 Schematic representation of siderite and calcite precipitation with increased burial depth of the Agbada Formation 124 Figure 4.15 Scanning electron micrograph of V-shaped etch pit characteristic of alkaline origin Agbada Formation, Meren field 1744m. 127 Figure 4.16 Diagramatic representation of quartz solubility with variation in pH. 129
Figure 4.17 FieldQof replacement of quartz by calcite at 25 C and one atmosphere 133 Figure 4.18 Photomicrograph of Agbada sandstone showing long grain contacts 135 Figure 4.19 Sequence of precipitation of minerals with increased burial depth of the Agbada Formation 14.0, Figure 4.20 Scanning electron micrograph showing relation- ship between kaolinite and quartz overgrowth in Agbada sandstone. Olure field - 3037m 142. Figure 4.21a Scanning electron micrograph of a pore space showing the numerous fine particles and the almost total absence of cementing materials. Agbada Formation, Idama field - 2915m 149 Figure 4.21b Scanning electron micrograph showing the reaction of a shale laminae to the drilling fluid (Agbada Formation, Olure field - 1827m) 149 Figure 4-22 Photomicrograph of mud cake left behind in the pore space due to high porosity and permeability. (Agbada Formation) 151 Figure 5.1 The Van Krevelen diagram for determining type of organic matter 160. Figure 5.2 Plot of total carbon (Cm) versus residual carbon CR to determine the level of organic maturation. 165
Figure 5.3 Schematic structure of the various types of kerogen 170
Figure 5.4 Main stages of evolution of organic matter 172: XV
Figure Page
Figure 5.5 Possible sequence of diagenesis of organic matter 175
Figure 5.6 Photomicrograph of the isolated kerogen (A-L) from Agbada and Akata shales 182. Figure 5.7 The Van Krevelen diagram with results of the elemental analysis of the kerogen of Agbada and Akata shales -^9
Figure 5.8 Plot of C^ versus Crp of the kerogen from
Agbada and Akata shales 197 Figure 5.9 Geothermal gradient map of southern Nigeria 202 Figure 5.10 (A-J) Photomicrographs of pollen and spores issolated from the kerogen of Agbada and Akata shales. Note variation in the shade of colours 203 Figure 5.11 Principal phase of organic maturation show- ing the position of the organic matter of the Niger delta 209 Figure 6.1 Diagramatic representation of the behaviour of sandstone and shale beds during shear faulting 218
Figure 6.2 Cross-section of the Jones Creek field showing hydrocarbon fill per reservior and the fluid contacts 220 Figure 6.3 Schematic representation of the principles governing hydrocarbon accumulation 222
ooooOoooo xvi
LIST OF TABLES
Table Page
Table 1.1 Comparison of some characteristics of the Mississippi, Niger and Nile deltas 13 Table 3.1 Results of point counting of Agbada sandstones 65 Table 3.2 Results of semi-quantitative micro-sieve analysis of some Agbada sandstones 76
Table 3.3a Clay mineralogy of Agbada and Akata shales 80 Table 3.3b Relative amounts of minerals in Agbada sandstone and shales 81 Table 4.1 pH measurements of pore waters of some Agbada sandstones 130 Table 4-2 Results of some water analysis of producing reservoirs of the Agbada Formation 138 Table 4-3 Approximate porosities derived from wire line logs 147 i Table 5.1 Conversion factors for computation of total organic matter from organic carbon content 167 Table 5.2 Results of elemental analysis of some kerogen from the Agbada and Akata shales 177 Table 5.3 Optical description of the isolated kerogen fromi shales of the Agbada and Akata Formations 178 Table 5-4 Carbon ratios determined from pyrolysis of whole rock samples of Agbada and Akata shales 1.91 Table 5.5 Carbon ratios determined from pyrolysis of kerogen • samples of Agbada and Akata shales 194 Table 5.6 Results of elemental analysis and carbon ratios of Agbada and Akata shales arranged in order of increasing depth per field 199 Table 6.1a Analysis of organic content of shales from Cawthorne channel 2 229 Table 6.1b Analysis of organic content of shales from Cawthorne channel 9 229
0000O0000 CHAPTER 1
GENERAL INTRODUCTION
INTRODUCTION
LOCATION
The Niger delta forms part of the sedimentary basin of Southern Nigeria. This basin is the largest of the series of sedimentary basins which developed along the West Coast of the African continent during Cretaceous times (Fig. l.l). Its.position in the Eastern corner of the Gulf of Guinea is at the intersection of the triple R junction from which the r.iftin-g and separation of the South American and African continents was initiated in Middle Cretaceous times.
On land, the Niger delta section of the basin is bounded on all sides by stable elements (Fig. 1.2). To the North-west is the Benin flank which is the subsurface continuation of the West African shield. This gently plunging monoclinal .flank terminates along a South west - North west trending flexure or fault zone known as the Benin hinge line (Merki.1970). To the East is the Calabar flank which again is the subsurface continuation of the Oban Massif. The Northern limit of the delta is marked by the Santonian Abakaliki uplift and the post-Abakaliki Anambra basin (Murat,1970). | | SEDI MENT
BASEMENT
EXTRUSIVES
ro
GULF OF GUINEA
Figure 1.1 Sketch map of the South Atlantic African Coast line showing the basins developed in the Cretaceous. 3
Offshore the modern Niger delta extends almost to the limit of the continental shelf and continues westward into the Dahomey basin without any major geological break (Fig. 1.2).
It is separated from the Douala basin by a volcanic province which stretches from the Atlantic volcanic i islands of Annabon, sao Tome and Principe via the island of Bioco (fomerly Fernando Poo) to Mt. Cameroon and the Adamaoua Massif in the Northeast. However, interna- tional boundaries have been interposed between these natural boundaries such that the extreme eastern part of the Niger delta now belongs to the Cameroon where it is now called the Rio del Rey basin.(Fig. 1.2). 1.1.2 CLIMATE AND VEGETATION The Niger delta lies in the intertropical zone and its climate is determined by the movement of the inter- tropical front which marks the boundary between the humid air masses from the south and the dry air masses from the north. As a result, two seasons characterise the delta - a 'dry season' (Nov. - March ) and a 'rainy season'. (April - Oct.) each varying in both duration and intensity across the area from the north to the south. In general the humid air mass and the associated rain- bearing south westerly monsoon winds dominate the delta and the dry Harmattan reaches the coast only occasion- ally in the months of December to February. Average temperature all year round is about 30°C. . . ., } } . 1?o \.., . I "' .!,. \ J "("' ( \ • "'~"&: . • r·~ ~-? .} -- \ >- • . UJ ( \ I . I¥11.Sf ) • :r 0 0 I 4tr·tcqn ..I <( \ 1.!J I S)). :z . 0 lr!J l d I I <( f- •I :c J 1.!J c.,~ -:q'?: {~ / ...... ' _, )
0 OliGOCENE-RECENT 0 UPPER SENONIAN~ EOCENE Q ALBIAN -LOWER SENONIAN ~ BASEMENT - EXTRUSIVES 50 0 100 200 Km. ~~~~~
FigQre 1.2 Sketch map showing the main geological features of southern Nigeria. 5
Most of the delta lies in the tropical rain forest zone and consists of a low-lying coastal region of swamps and mangrove swamps, increasing in relief northwards to a belt of dense forests merging into the Savannah in the plateau region (Fig. 1.3). Details of the general physiography are contained in the Needeco reports (1954; 196l) and Allen (1963; 1964 & 1965) Drainage is via the rivers Benue and Niger and their numerous tributaries which bring sediments from most of thehinterland.Other smaller rivers draining relatively smaller parts of the country reach the sea at various points. The volume of sediments discharged into the Niger delta basin by all these rivers ranges from 171 x 109 m-3 per year to 298 x 109 m^ per year (Short, and Stauble, 1967). This discharge figure is about 1/3 of that of the Mississippi river.
1.1.3 BRIEF HISTORY OF THE NIGERIAN OIL INDUSTRY Petroleum exploration in Nigeria commenced in 1908 when a German company drilled shallow wells for heavy oils into the outcrops of the Cretaceous sands in the Western Coastal parts of Nigeria. However, extensive exploration for petroleum employing modern methods only started in 1937 when Shell-d'Arcy acquired mineral rights over the entire country. Their activity was halted in 1939 by the second world war and it was not until 1946 that the present phase of oil exploration started in the Niger delta. HILLY Country IM Dry flat country ESS Dry I a n d & swamps Fresh water swamps Mangrove swamps cr> Estuarl e s Beaches and bars Marine
Kilometers 0 50 10 0 I I I Miles 0 30 60 Figure 1.3 Sketch map showing the main physiographic features of the Niger delta. (After Short & Stauble 3967). 7
Oil was discovered in commercial quantities in Nigeria in 1955 at Oloibiri in the eastern Niger delta (Fig. 1.4)• This discovery was followed by intensive drilling activity and the present size of the oil industry is a testimony of its success, placing Nigeria as the 9th largest world oil producer. A conservative estimate of proven reserves puts it at about 19 billion bbls of oil and 41 trillion cu. ft. of gas (Egbogah, 1978) which represent 3% and 2% respectively of world reserves. Crude production currently stands at a daily average of 1.1 million barrels. This figure is much lower than the two million barrels of oil per day (BOPD) averaged over the last few years.
The success ratio for all exploratory and development wells drilled since 1955 averages about 60$ per year (Fig. 1.5), a ratio .which is high by world standards. When exploratory drilling is considered on its own, a success ratio of 45-55% per year which again is high by world standards is obtained. Despite the success story outlined above, the need to find new reserves or increase existing ones is paramount. In this respect, exploration activities have been extended to inland basins. This new initiative has prompted interest in these basins and preliminary results of the source potential of one of them (Anambra basin) are encouraging (see Agagu and Ekeweozor 1980) . Figure 1.4 Hap of southern Nigeria showing some oilfield locations. 9
YEAR Figure 1.5 Graph of exploration and production activities in the Niger delta. 10
At a time when efforts are being directed towards locating new potential oil fields, an understanding of some of the existing problems may help improve reserve estimates and exploitation in existing fields. In the past, exploration for petroleum has been directed mainly towards structural traps. This approach developed because of the ease of discovery of structural traps and the belief that the petroleum in this region migrates along faults,from the deeply buried source rocks to the reservoir rocks above them. The decline now apparent in the rate of discovery of these petroleum-bearing structural traps has led to a re-evaluation in this thesis of the whole concept of petroleum generation and migration in this province.
A recurring production problem in this region is the occurrence of very fine materials ('fines') with the crude oils when they are brought to the surface. It was sufficient in the past to artificially aid consolidation in the reservoirs and thus reduce the amount of fines produced. However, many of these reservoirs are now at the stage where enhanced recovery methods are needed to aid the production of crudes. At this point, the causes of this problem need to be fully understood in order to efficiently plan the enhanced recovery method needed.
1.2. AIM AND SCOPE OF THE STUDY This work is directed at two rather varied but related problems: a) The diagenetic history of the sediments of the Niger delta particularly the Agbada Formatjon.
b) The major source of hydrocarbons in the Niger delta. 11
About 150 samples of sandstones and shales mainly from the Agbada Formation were examined by standard X-Ray diffraction (XRD), Scanning Electron Miscroscope (SEM) and some by the petrographic miscroscope in order to determine their diagenetic history. Interpretation of these results are used to provide explanations for the loose and friable nature of many of the sandstones of this region. This interpretation is aided by analyses of some water samples of producing reservoirs. The water analysis results, although representative of the present situations in the reservoirs acts as a control against which diagenetic interpretations is compared for credibility.
The organic matter of 37 Agbada shale samples and four Akata shales samples were chemically analysed for their carbon, nitrogen and oxygen composition, the ratio of residual carbon
CR to total organic carbon C^ and the level of carbonisation, in order to determine the nature of organic matter and their source potential. Combined with-other geological data, the results of these analyses are used-to predict the major source of hydrocarbons in the Niger delta.
1.3 SYNOPSIS OF PREVIOUS WORK ON THE GENERAL GEOLOGY OF THE NIGER DELTA
Detailed studies of the geology of the Niger delta have been provided by Short & Stauble (1967) and Frankl & Cordry (1967). The authors identified three cycles of sedimentation in the area. The youngest of these cycles is the most important because it gave rise to the Tertiary Niger delta. The strati- graphic subdivisions they established are still in use unmodified but their shortcomings will be highlighted during the 12 discussion of the stratigraphy in section 2.4. Avbovbo, (1978a) in redescribing the lithostratigraphic units, drew isopach maps for each unit and showed that the centre of sediment deposition moved southwards with time in line with delta progradation. Reyment (1965); Adegoke (1969); Murat (1970) and Adeleye (1975) have all contributed to the discussion of the stratigraphy of the entire southern Nigeria. Weber (1971) described the sedimentology of the area and showed that the progradation of the delta caused fluvial sediments to be interposed and superposed on marine deposits which makes correlation and interpretation very difficult.
Short and Stauble (1967); Frankl and Cordry (1967); Weber & Daukorq (1975); Evamy et. al. (1978) and Avbovbo & Ogbe, (1979) have all shown that hydrocarbon occurrence is restricted largely to the sediments of the transitional paralic sequence where they are held in traps formed by growth faults and their associated rollover anticlines. Merki (1970) showed that differential loading of the under-compacted shale substratum at the base of the Tertiary delta initiated the formation of the growth fault. Weber & Daukoru (1975) and Weber et. al. (1978) proposed these faults as the migration path for the hydrocarbons from their deep sources in the Akata Formation to the shallower reservoirs of the Agbada Formation. TABLE 1.1, COMPARISON OF SOME CHARACTERISTICS OF THE NIGER MISSISSIPPI AND NILE DELTAS. (COMPILED FROM COLEMAN 1976 .ELLIOT 1979) & THIS STUDY . CHARACTERISTICS MISSISSIPPI NIGER NILE
CLIMATE TEMPERATE HUMID TROPICAL DRY SUBTROPICAL RAINFAL L ( mm) 1,918 1,062 870
AREA OF DRAINAGE
BASIN3 3,344.6 1,112.7 2,715.6 (xlO sq. km.)
RATIO SUB AERIAL/ SUBAQUEOUS AREA 5.3 8.5 9.0
SHORELINE LENGTH/ DELTA WIDTH 2.03 1.24 1.20
DISCHARGE (M3/Sec) 15,631 8,769 1,480
DELTA CHANNEL BIFURCAT- REJOINING BIFURCATING PATTERN ing
RATIO CHANNEL BIFURCATIONS/ 0.26 0.84 0. 96 REJOINING
TYPE OF DELTA Whole delta Channel switch- Channel switching SWITCHING switching ing and Channel only only extension
TYPE OF SAND WIDESPREAD Channel sands Channel sands normal BODY Finger-like normal to to shoreline connec- Channels shoreline ted laterally by normal to connected barrier-beach sands shore line laterally by as well as coalesced barrier-beach channel and mouth sands. bar sands fronted by offshore barrier inlands.
DOMINANT BASI- Fluvial Wave + minor Wave + minor fluvial NAL PROCESS tidal
RIVER MOUTH Straight Constricted Straight TYPE
NO. RIVER MOUTHS 22 11 2 contd.... TABLE 1.1 CONTD.
MORPHOLOGIES Bird foot Smooth,arcuate Gently arcuate type coastline type shoreline, shoreline, with two poorly deve- nearly contin- protruding distri- loped & scarce ous sand butaries. Broad high sand beaches, beaches, with sand beaches with with marshy marshy, man- abandoned channels & open & closed grove swamps hypersaline flats bays. and beache' and lagoons. ridges.
NATURE OF Sand & shales Dominantly Sandy with carbonate SEDIMENTS in about equal sandly and evaporites. amounts
LEVEL OF Advanced with Low with minor DIAGENESIS silica & silica & Carbo- carbonate nate cement. cement. Low level of Advanced clay clay transfor- diagenesis mation with with increas- increasing ing depth. depth.
BASIN TEC TONICS Contemporan- Contemporaneous eous growth growth faulting, faulting
ECONOMIC Oil & gas Tar Dominantly oil IMPORTANCE sands & other and gas. inorganic materials. 15
1.4 BRIEF REVIEW OF DELTAS At this point, it is probably necessary to review some of what is known about deltas in general. Several definitions of the word 'delta' have been given among others by Moore and Asquith (1971);Coleman 1976; Elliott 1979- In its simplest terms, deltas can be described as, discrete shoreline protruberances, formed where rivers enter large bodies of water (oceans, Seas, Lakes and Lagoons) and the rate of sediment supply outweighs that of redistri- bution by indigenous basinal processes. Detailed descriptions of deltas started in 1921 when Johnston wrote an account of the Fraser delta. In subsequent years, intensive studies of the Mississippi delta (Russell & Russell,1939; Fisk, 1944; 1947-; 1955; 1960 ;196l, Coleman and Galiano 1964, to name a few) caused it to be regarded as the delta Model. However, studies of other deltas brought out the dissimilarities in deltas and led to the conclusion that no delta was typical. Among those who contributed to the comparative studies of deltas are : Allen (1965); Van Andel (1967); Fisher et. al- (1969); Wright and Coleman (1973); Coleman and Wright (1975); Galloway (1975). Table 1.1. list the main features of a few deltas. Deltas occur at all latitudes (except the poles) irrespective of the climate and vegetation of the area of occurrence. The volume and lithology of sediments Supplied by the rivers depend on the geology, climates, tectonics and topographies of the drainage areas (Selley, 1977) . The regime, morphology and facies pattern of their associated deltas, are however controlled by 36
the rate and amount of sediment input vis-a-vis the effectiveness of basinal processes, which include waves, tides and ocean currents, to remove the sediments. Deltas are characterised by a complex system of sub environments which can be divided into two broad parts: a) The delta front which includes the shorelines and the seaward dipping profile. It is largely sub aqueous, indeed sub-marine^, and is characterised by finer grained sediments and greater effects of basinal processes. b) The delta plain which is developed landward of the delta front. It is subaerial occuring largely above the low tidal mark and character- ised by coarser grained sediments, and frequently overlies sediments of group (a). Sedimentation in deltas is usually quite rapid and often cyclic., ^resulting. .in remarkably, thi-ek sedimentary sequences. Their diagenesis is affected by a variety of factors which include the following : i) rate of sedimentation; ii) sub environment of deposition which controls the chemistry of the formation water, iii) the textural and chemical maturity, of the sediments,, which . are -determined. by vthe prove- nance, the sedimentary processes and the depositional environments. 17
Despite these general similarities, extensive studies of boreholes in the Mississippi, Rhone and Niger deltas (Fisk et.al., 1954; Oomkens, 1967; Weber, 1971) showed that deltaic successions contain a wide variety of vertical facies sequences. These sequences vary within a delta at different locations as well as between deltas. . Similarly, variations exist between deltas in diagenetic patterns and economic mineral contents. Therefore, comparison will be made at various points in this thesis, between the observed petrologic and diagenetic changes in the Niger delta and those of other deltas particularly the Mississippi delta. 18
| | Regressive Delta Se.diments
HUU Transgress ive Sediments
Regressive Cret. Sediments m Folded Cret. Sediments Kilometers 0 50 100 Basement ^ i Mifts 60 Figure 2.1 Sketch map of southern Nigeria showing the configuration of the sedimentary rocks. 19
CHAPTER 2
THE GEOLOGY.OF.THE NIGER DELTA
2.1 EVOLUTION OF THE NIGER DELTA
The Southern Nigeria basin, composed of the Niger delta, Anambra basin, and parts of the Benue trough and Niger basin, originated in the Early Cretaceous as an X-shaped depression in the basement complex. (Fig. 2.1). The development is tectonically controlled having resulted from the rifting and separation of South America from Africa (Stoneley, 1966; Burke et. al.1970; Manchens, 1973). The instability and subsidence, along the rift margins, which followed the rifting in the Gulf of Guinea area led to a marine invasion which set the scene for the develop- ment of the delta.
The rifting in the Gulf of Guinea has been described as an RRR (ridg-e—ridge-ridge) triple junction by Burke et.al. (1970). They cite the similarity with the Red Sea - Gulf of Aden - Afar triple junction for which the overall resem- blance is striking (Fig. 2.2). Although Grant (1971) propesed an RRF (ridge-ridge-fault) model for the Gulf of Guinea, the model of Burke et, al. (1970) is now generally accepted (Wright, 1976). It more satisfactorily accounts for the present arrangement of transform fracture zones in the area. The three arms of the triple R system opened up at different times and rates. In the South Atlantic, the opening started in mid Aptian and reached the Gulf of Guinea SOMALIA PLATE
AFRICA
New Ocean Crust Margin of Rift Fracture Zone Boundary of C rato n
Figure 2.2 Comparison between the Gulf of Guinea triple junction and the inverted version of the Red Sea - Gulf of Eden -Afar triple junction (After Burke et.al.1970). 21 in lower Albian times. The Benue arm of the rift most probably also developed at this time.
The evolution of the Tertiary Niger delta is closely related to the series of events that occurred in this region from the Cretaceous to the Palaeocene. Most relevant to the present discussion is the opening of the Benue trough - a structure with which the Niger delta has been associated since the Palaeocene. The sediments building up the Niger delta are transported southwards to the sea via the Benue trough.
The Benue trough was first recognised as a tension induced split by King (1950). Since then several studies have been undertaken and the views on the origin of the trough are nearly as many as the studies themselves. In a review of these various ideas, Wright (1976) divided them into two broad groups: i) A fault controlled depression model (Lees, 1952; Cratchley and Jones, 1965; Wright, 1968). ii) A plate tectonics model (Burke e.t.al.,1970; 1971 Burke and Dewey, 1974;. Grant, 1971; Wright,1970;
1976). While the concensus is now in favour of the latter theory, a few points still remain unexplained by it (see Nwachukwu 1972; Wright, 1976). The most important of the problems is the failure to explain the disappearance of nearly 200 km of oceanic material which would have been generated during the crustal thinning that accompanied the approximately 30 My (Albian - Santonian) spreading phase of the Benue trough. This problem is further complicated by the occurrence in the Cameroon of a line 22
Figure 2.3 Comparison between the structure of the Benue trough and that of the Cameroon line. (After Fitton 1980).
Present Relationship
After super position 23
of volcanics - the Cameroon line, which occurs, along a supposed fracture zone. (See Fig. 1.2). The occurrence of this line of volcanics is difficult to explain in terms of the plate tectonics model. However, Fitton (1980) provided an excellent explanation for this discrepancy. He proposed that at its inception, the Benue trough occupied the position of the Cameroon volcanic line. It was then brought to its present position by a 7° clockwise rotation of the African Lithosphere over the asthenosphere. Thus, the extrusives along the Cameroon line represent those that should have been expelled in the Benue trough had the rotation not occurred. His major evidence for this conclusion was the close similarity in shape and trend between these features. (Fig. 2.3).
The mechanism for this rotation is not clear and its
effect is not yet documented elsewhere on the African
continent but it could explain many other problems in
the formation of the Benue trough by the plate tectonics
model. For example, it explains why the older sediments
of this region are restricted only to the extreme eastern
part of Nigeria (Fig. 2.4). The initial depression and
therefore transgression must have occurred in the
eastern part (region of the Cameroon line) since
according to Fitton (op.cit) . the rifting started in this
area. The transgression that followed was most probably
confined within the limits of the rift and hence the rest-
riction of Early Cretaceous sediments to the extreme
eastern part in the region of the longitude of Calabar
(Fig. 2.4). i. ( O/R . / Lagos
10/ R | Be nin/Ogwashi-Asaba Fms
| R |Agbada Fm.(Recent outcrop)
| E |Ameki Fm. and equivalent.
|P/E | Imo Shales and equivalents
KJ P Nkporo Shales, Mamu Ajali I Nsukka Fms.
K/U Awgu Eze A.ku & Asu river group.
Extent of Afam Member (subsurface)
P^ji Ba sem e nt
Kilometers ?. ,5P.. ?? Miles 0 30 60
Figure 2.4 Sketch map of southern Nigeria showing the -p^-leogeography- of the Cretaceous. (After Short and Stauble 1967) 25
All models on the origin of the Benue trough (Wright, 1968; Burke et. al., 1970 and Fitton 1980) agree that the trough did not reach the Rivers Benue and Niger until the Palaeocene times when the rivers were diverted southwards and the development of the proto--delta commenced soon afterwards. Prior to this southward diversion of the Niger and Benue rivers, the present writer believes that they discharged their sediments into the middle Niger basin and the middle Benue trough respectively. From the Palaeocene to the present day, the huge amount of sediments which were previously deposited in these basins were now carried southwards to the sea. Thus began the development of the prograding delta in the Eocene times.
2.2 THE MODERN NIGER DELTA
The Recent Niger delta is an arcuate wave dominated delta with strong tidal influence (Coleman, 1976; Selley, 1976; Elliott, 1979). Its development started in the Palaeocene with sedimentation in a quiet marine environment. At this time the landward parts of the transgressing sea were protected within the Benue Trough. This resulted in a reduction of wave influence and allowed the deposition of a thick shale sequence which forms the base of the Tertiary delta. During this period, small lobate deltas (Cross River and Niger River deltas) probably developed separately (Short and Stauble, 1967). Agbada Format ion (delta plain) Benin Formati on (flu vial)
8Km. ro CD
(delta slope) Pelagic clays Deep-sea turbidite fan.
30 0 Km. s.w. N.E.
Figure 2.5 Schematic cross section of the Niger delta showing the relationship between the lithostatigraphic units.(After Burke 1972). 27
During ^he Eocene, coarser clastic sediment input increased as a result of the building out of the delta. The rapid sedimentation that followed, resulted in the regression of the sea as well as the southward advancement of the Niger delta. With progradation of the delta, marine deposition passed into paralic and subsequently to continental deposition (Fig. 2.5). As the delta advanced, the hitherto protected sea regressed and wave influence increased, causing a mixing of the sediments of the Lobate deltas and giving rise to the present coastal configuration of the Niger delta (Fig. 2.6). Hospers (1965) in explaining the overlap (misfit) between South America and Africa (in the region of the Gulf of Guinea) suggested that the continent underlying the Niger delta has continually subsided under the sediment overburden. Thus, although the overall pattern since the Eocene has been that of a regression, it is truncated at intervals by marine transgressions, on either a local or regional scale. The sequence of sediments produced by this process is an alternation of sand and shales. From the thin nature of individual beds (generally 30 - 150m),it is assumed that the duration of each phase (transgressive or regressive) is short. Sediments of any particular phase may be thicker in the eastern section of the delta where the longshore current contributes additional material from the west. Port Horcourt
sia, PLIOCENEJ.PJ^i
Kilometers 0 50 100 Js—i—i—i—i— i Miles 0 3 0 6 0
Figure 2.6 Sketch map of southern Nigeria showing the various positions of the coast line through time as the delta prograded southwards. (Short & Stauble 1.967) 29
The total sediment thickness of the modern Niger
delta is estimated at about 12,000m (Hospers, 1965;
Merki, 1970; Weber and Daukoru, 1975; and Evamy et'aL,
1978).
2.3 STRATIGRAPHY
To date nearly all published studies of the
Niger delta have concentrated on the Tertiary deposits.
This is not surprising since very little is known
of the sediments older than the Palaeocene ..which under-
lie the modern Niger delta. However in order to fully
discuss the sedimentation and stratigraphy of the
Tertiary delta, it is necessary to briefly mention the
older sediments which prece.ded their deposition.
2.3.1 THE PRE-TERTIARY
Several workers, Reyment, (1965); Adegoke, (1969);
and Murat, (1970) have written about the Cretaceous
sediments of southern Nigeria* Somehow their relationship
to the petroleum geology of the area has never been
discussed.
The oldest sedimentary basins in southern Nigeria
are the Benue-Abakaliki trough,the southern part of
which is now the Abakaliki high, and the Ikang trough
(Fig. 2.7). Unlike the Ikang trough and its associated
Ituk and Eket highs which remained virtually unchanged
into the Tertiary, the Benue - Abakaliki trough received
over 3,000m of Cretaceous sediments. It then started
to close in the Santonian, and the compressional forces OJ o
CRATON
INTRACRATONIC STABLE/ MOBILE
INTRACRATONI C MOBILE
Kilometers 0 5 0 100 150 2 00
Figure 2.7 Sketch map of southern Nigeria showing the major tectonic units of the pre- Santonian.
(After Flurat 1970) 31
thus set up caused these sediments to fold (Burke et. al.,
1970). The oldest known sediments of this region
consist of arkosic sands and quartzitic sandstones
derived from the Pre-Cambrian basement. They are
generally non-fossiliferous, poorly sorted and some-
times crossbedded and are very similar to the basal
sandstones (Frank and Nairn, 1973; Furon, 1963) known from the other coastal sedimentary basins around the
South Atlantic (Fig. l.l).
The main lithostratigraphic units (Fig.2.8) of
the Pre-Tertiary, from the bottom consist of:
1. The 'Asu River Group' which is restricted to
the Abakaliki and Calabar areas and consists
mainly of shales sandstones and • micrvofos-siliifercrus
limestones of Albian-Cenomanian age.
2. The 'Odukpani Formation' known only in the
Calabar area and believed to be of Cenomanian -
lower Turonian age. It consists of sandstones,
limestones, shales and interbedded limestone and
shale sequences. Ofodile, (1976) identified
other sediments of Cenomanian age in the
Middle Benue Trough.
3. The 'Eze Aku Shales' which are sediments
deposited during the Turonian transgression.
The sequence consists of shales, limestones
and minor sandstones.
The sediments are all mainly restricted to the eastern part of southern Nigeria, with the exception of the new locality in the Benue trough, where the initial incursion of the sea occurred in Cretaceous times. U3 M
SANDS | 1 SHALES ^ ERODED OR NOT DEPOSITED
I AS = AJALI SANDSTONE, MF = MAMU FORMATION, N F = NSUKKA FORMATION )
Figure 2.8 Stratigraphic synopsis of southern Nigeria (Modified from Murat i970) 33
They belong to the first of the three cycles of deposition
identified by Short and Stauble (1967).
The Santonian folding episode changed the tectonic setting in Southern Nigeria (compare Fig. 2.7 and 2.9). The
Abakaliki trough was now raised into a high and flanked
to the west by the Anambra basin (previously a high) and the Afikpo syncline to the east. The sea now
reached the Benin flank for the first time and the scene was set for the development of the Proto-delta. Before this however, the Nkporo Shales (Campanian - Mao.strichtian) and its lateral equivalents,the Owelli Sandstones and
Enugu Shales, were deposited in 'the western part of the delta (Fig. 2.8). In the east the Ma:mu Formation,
Ajali Formation and Nsukka Formation were laid down during the same period of time. These represent the sediments of the second cycle of deposition.
From this time onwards the marine influence was reduced and the regressive phase that followed, resulted in the development of the Proto-Niger delta.
The absence of pre Tertiary evaporites in the stratigraphy of southern Nigeria is important. They are known to occur in nearly all the South Atlantic basins of the African continent (Belmonte et.al.,1966 and Brink, 1974).
Following these examples, Stoneley, (1966) suggested that the diapiric structures beneath the Niger delta were of evaporitic nature. This was disputed by Hospers,
(1971) who described the structures as semi-diapiric and probably composed of clay or shale. Pautot et. al.
(1973) confirmed the presence of diapirs but failed to ^ .—v
:
I ^ /
3 DAHOMEY EMBAYMENT, HA .w^ © il V
V N <*4<<'e NV3M CRATON 9 © HI 1N T R A CRA TO N I C MOBILE V 1 | STABLE AREAS
© STABLE
© AREA OF STRONG SUBSIDENCE
100 200
Kilometers
Figure 2.9 Sketch map of southern Nigeria showing the post-Santonian tectonic units. (After ("jurat 1970). 35
comment on their composition. Mascle et. al. (1973)
resurrected the possibility of a salt composition for
these structures.
The Santonian folding episode is the only major
tectonic event since the rifting in the mid-Cretaceous.
This episode produced ridges which trend in a northeast
- southwest direction. The direction of invasion of
the sea in this area roughly coincides with the trend
of these ridges. This situation provided free access
to the open sea at all times allowing free mixing of
the waters. It is highly unlikely that evaporites
will form under these conditions since the rate of
mixing surpasses that of evaporation, concentration and
precipitation. It therefore seems most likely that the
diapiric structures are not of salt but of shale as
proposed by Hospers (1971).
2.3.2 THE TERTIARY
The sediments of the Tertiary Niger delta are
diachronous and their stratigraphy has been subdivided
into three lithostratigraphic units by Short and Stauble
(1967). The units which are rough eqivalents of marine
(pro-delta) paralic (delta slope) and continental
(delta platform) deposits are in chronological order
of initiation:-
BENIN FORMATION (CONTINENTAL) OLIGO. - REC.
AGBADA FORMATION (PARALIC) EOC. - REC.
AKATA FORMATION (MARINE) PAL. - REC. SUBSURFACE SURFACE OUTCROPS
YOUNGEST OLDEST YDUNGEST OLDEST KNOWN AGE KNOWN AGE KNOV/N AGE KNOWN AGE
BENIN FM. PLIO/ RECENT OLIGOCENE BENIN FM. MIOCENE? AFAM SHALE MEMB. PLEISTOCENE
AGBADA MIDCENE RECENT EOCENE OGWASHI-ASABA OLIGOCENE FORMATION EOCENE FM. EOCENE AMEKI FM.
RECENT AKATA FM. EOCENE L. EOCENE IMO SHALE FM. PALEOCENE
PALEOCENE NSUKKA FM. MAESTRICHTIAN
MAESTRICHTIAN AJALI FM. MAESTRICHTIAN
EQUIVA LENTS _MAESTRI/CAMP. MAMU FM. CAMPANIAN
NOT KN OWN CAMP/SANT. NKPORO SHALE SANTONIAN
SANTONIAN/ AWGU SHALE TURONIAN CANIACIAN
TURONIAN EZE AKU SHALE TURONIAN
ALBIAN ASU RIVER GROUP ALBIAN
Figure 2.10 Subsurface stratigraphy of the Niger delta a.nd its surface equivalents in other southern Nigerian basins. 37
These formations are described mainly from their nature
in the subsurface except for parts of the Benin
Formation. Short and Stauble (1967); Murat (1970)
have also described sedimentary outcrops, in the flanks
of the basin, which they consider to be approximate
equivalents to these (Fig. 2.10). The location (see
Fig. .1.3) and description of the type section of
each of the units have been given by Short and Stauble
(op.cit,) and only the salient points are documented here. a) THE AKATA FORMATION
The type section for the Akata formation is
the Akata-1 well drilled 80km (50mls.) east of
Port-Harcourt The information on .this unit
is scanty because only a few wells have been
drilled into it. It is a marine sequence laid
down in front of an advancing delta, and is
characterised by its uniform shaley nature-
The shales are generally dark grey, sandy or
silty in places and under-compacted. The
thickness of the Akata formation is estimated
at about 6,500m (Merki, 1970). This may be an
over estimation since the total sedimentary
thickness of 12,000m may include deposits of
Cretaceous age. The top of the Akata
Formation which is also the base of the Agbada
Formation has been placed (Short and Stauble, 1967)
\ at the base of the deepest occuring deltaic
sandstone or siltstone bed. 38
While this definition is accurate, it is
often difficult to decide which is the deepest sand.
For example in Gulf's Okan field, many •
of the early wells bottom in a thick shale
(thought to be the continuous shale) which
was later discovered to belong to the Agbada
Formation. Recent drilling has shown that
Tertiary oil and gas pools lie below this thick
shale section. In view of this, the above
boundary definition is inadequate and a physical
parameter is here proposed to delineate this
boundary. The Akata Formation is known to be overpressured from drilling and seismic records
in the area and in the writers opinion, the top
of the overpressured zone is a more logical and
more easily recognisable boundary.
Overpressuring of shales have been discussed
among others by Barker (1972); Chapman (1972;
1980b): .Magara (1971.? 1975a; 1980). It is generally agreed that overpressuring is caused by
compaction disequilibrium which may arise from
rapid sedimentation and an imbalance between
shale dewatering and rate of sedimentation.
In addition to this, a facies change at the
boundary between the shale and the overlying bed
is also essential. The increased porosity and
permeability of the overlying bed (maybe silt)
allows the top section of the shale sequence to 39
compact normally. This compacted shale section
forms a seal for the rest of the shale sequence and
prevents the escape of formation water. With
increased burial and overburden pressure,
temperature increases and the formation water
expands slightly thereby increasing the pore
pressure.
Many of the shales towards the base of the
Agbada Formation are largely marine. It is
therefore difficult to distinguish between them
and the shales of the Akata Formation. As a
result of this, the top of the overpressure is
here proposed as the boundary between the Akata
and Agbada Formations. Methods of detecting overpressures using wireline logs and/or seismic methods already exist in the literature (Archie,
194-2; Hottman and Johnson, 1965; Eaton, 1972;
Magara, 1978).
THE AGBADA FORMATION
The type section of the Agbada Formation is in
Agbada - 2 well drilled 11km-(7 miles) north-
northwest of Port-Harcourt(Fig. 1.3). It is a
sequence of alternating sandstones and shales of
delta top distributary channel and deltaic plain origin. Weber, (1971) suggested that the
sequence is cyclic with marine and fluvial
influences alternating. m 30 I
CM
H P CO cn o AGBADA FORMATION BENIN FORMATION cn > : T O LOWER UPPEtt >a o vaaAV1— ^wdJdtJ 30 > • K? Ol 8 o8 O
- SHORT AND STAUBLE AGBADA FM. AKATA FORMATION cn w NAA/VYU-^^ >
H> """ * ^Y^A s? 1 a3 o 8 AGBADA FORMATION »o?r ft Si. 12 10 * 2 • C TttrS STUDY v * • a 4 CD r- if N) Sfja S ^ M y r • ° * a -si
OP 41
The maximum thickness of the Agbada Formation
is about 4,000m in the central part of the delta.
The unit thins in all directions towards the
limit of the delta. In all cases the Agbada
Formation can be subdivided into two units -
an upper unit of moderate to thick sands (50-150m)
and numerous thin shale beds; a lower unit with
generally thinner sandstone beds (<70m) and
fairly thick shale 50m) sequences (Fig. 2.11),
The lower unit contains more material of marine
origin than the upper unit.
The top of the Agbada Formation is defined by
Short and Stauble, (1967) as the first appearance
of a marine forafflinifera within the shales. This
boundaryV:thou.gh precirae, is ..dTiffd-cull to- locate
without detailed micro-palaeontological data.
A much easier boundary to locate is the base of
the high resistivity (low conductivity) fresh
water which is characteristic of the continental
deposits (Benin Formation) in the area. This
boundary is commonly used within the oil industry
and it roughly coincides with the top of the
Foraminifera zone in many wells. The use of the conductivity boundary is not accepted by all.
Avbovbo (1978a) claims that the invasion of the
Agbada Formation by fresh water from the Benin
Formation and vice-versa, precludes the use of
this physical parameter as a boundary indicator. 42
In an attempt to test the significance of the difference between the boundary determined by palaeontology and that by resistivity, the author in a separate unpublished study produced isopach maps of the Benin Formation based on boundaries determined by each method. No significant difference was observed between the two maps. It was observed that the level of invasion of one formation water by the other was related to the topographic configuration at the surface.
Although penetration of fresh water into the Agbada Forma- tion may be fairly deep where the Benin Formation is thin, the effect is minor in terms of the overall thickness of the Benin Formation. In view of this, the writer feels justified in recommending that the conductivity boundary can be safely used in routine jobs.
Nearly all of the hydrocarbon accumulations in the
Niger delta occur within the Agbada Formation. The alternation of sandstone and shale beds makes it an excellent reservoir with plenty of seals. Short and
Stauble (1967); Frankl and Cordry (1967); Reed (1969);
Egbogah and Lambert-Aikhionbare (1980) and Lambert-
Aikhionbare and Ibe (1980) have also suggested that the shales of these formation could source the reservoirs adjacent to them. The Agbada Formation is therefore the major target of petroleum exploration in the Niger delta and it is the main subject of the present research. 43
c) THE BENIN FORMATION
The type section of the Benin Formation is in
the Elele-1 well drilled 39km (24mls) north-northwest
of Port-Harcourtf.Fig, 1.3). The name Benin Sands
was first used by Parkinson, (1907) to describe a
group of sands and clays which are universally
present in Southern Nigeria-and are remarkable for their
high iron content and lack of fossils. It was again
used by Reyment, (1965) to describe - Plio-Pleistocene
sandstones outcropping in the Benin, Onitsha and
Owerri areas. The similarity in texture and minera-
logical composition between these sands and the uppermost
part of the sediments of the sub-surface Niger delta,
led Short & Stauble, (1967) to adopt a similar name.
The sands of the Benin Formation are massive,
coarse grained and very porous fresh water bearing
feldspathic quartz arenites which possess only thin
interbeds of clay. The sandstones predominantly
consist of quartz and feldspar with minor amounts of
garnet and zircon. Parkinson (1907) explains that the
i< >r high feldspar content is due to rapid weathering and
sedimentation of basement rocks to the north of the delta.
The Benin Formation varies in thickness from
0-1,500m. In most places, apart from containing the
water aquifers of Southern Nigeria, this formation is
of little value in terms of petroleum geology. The
small number of clay beds greatly reduces the ability
of the very good sands to form hydrocarbon reservoirs. .\'v SANDSTONES
SHALES
OIL GAS
Schematic representation of the main features of a growth fault in the Niger delta. 45
2.3.3 COMMENTS
The simple stratigraphic subdivision outlined
above is complicated in places by the presence of
large shale units within the continental or paralic
sequence. One such shale unit - the Afam Clay Member
was described by Short and Stauble, (1967). Many other
shale units have been identified and there is a fair
agreement between the oil companies in Nigeria that some
of these clay units are mappable and should be
designated formations. To this end, the industry has
set up a special stratigraphic committee to identify
and name new formations if necessary. For this reason
the problem of nomenclature is not discussed in this
thesis. Suffice it to say that the present system is
far too simple to account for the complex depositional
patterns characteristic of this province.
2.4 STRUCTURAL GEOLOGY AND HYDROCARBON OCCURRENCE
2.4.1 STRUCTURAL GEOLOGY
The major structural elements of the Niger delta
are the growth faults. Growth faults (Fig. 2.12) are
synsedimentary normal faults developed as a result of
contemporaneous failure of the prograding delta slope.
They are generally associated with a thicker sediment
accumulation on the downthrown side than on the upthrown and are crescent shaped. Sometimes the growth on the
downthrown side is accompan-ie-d -by downward rotation
movement of the sediments along the fault plane. The counter-
regional dips thus produced result in the development of
roll-over anticlines in the region around the faults.
(Fig. 2.12). 46
These faults and their associated rollover anticlines form the major hydrocarbon trapping mechanism in the
Niger delta and are largely confined to the Agbada
Formation.
Growth faults have been described from many parts of the world particularly the Tertiary of "the Gulf
Coast region of America. (Hardin and Hardin, 1961
Ocamb, 1961; Shelton, 1968; and Crans et.al.,1980 I ff II).
Despite the numerous studies, the mechanisms of growth fault development is still not fully understood.
Crans et.al. (1980) in reviewing the theories of growth faulting grouped them under three headings which suggest that faulting was initiated due to:
i) development of shale waves (ridges);
ii) local excess loading of the delta slope, and iii) free gravitational sliding.
No concensus exists on any of the above theories and more work is needed to resolve this problem.
As far as the Niger delta is concerned, the proposal of Merki (1970) that shale waves with local excess loading of the delta slope, appears to adequately explain the presence of growth faulting in this region.
Crans et.al.(1980) objected to Merki's shale wave theory on the ground that gravitational instabilities in salt and shale layers behave differently. He argued that contrary to the assumption of- Merki (1970), over- burden may not necessarily produce faulting in shales as it does in evaporites. 47
EXPLANATIONS TO FIGURE 2.13
A. Prograding offlap sequence. No deformation on
basin flanks with thin clay substratum. Initiation
of clay ridge at toe of advancing slope.
B. As growth of clay ridge continues,a growth fault
is initiated. Deposition of continental sands
in depressions created by compaction of offlap
sequence and flowage.
C. As delta builds basinward, younger clay ridges
are formed. Clay upheaval structures in downdip
parts of delta.
D. Late subsidence causes tilt and deposition of thick
continental sands. Continued growth of shale
upheaval structures induces expansion fault patterns
and "back to back" faulting in downdip delta. •Cs 03
DOWNDIP DELTA UPDIP DELTA
D
AKATA FORMATION AGBADA FORMATION. BENIN Fm. Figure 2.13 Schematic representation of the stages in the formation of a growth fault. 49
The development of growth faults in the Niger delta is closely related to the under-compacted Akata
Formation ( Paleoc. -Rec) pro-delta shale substratum,
Rapid deltaic sedimentation over this unit creates gravitational instabilities related to differential loading (Fig. 2.13). The stress thus created, causes the initial fracturing at the top of the shale substratum.
Upward movement of the mobile shale along the back side of this fracture releases pressure from the underlying overpressured section. This initiates the growth fault which penetrates upward to the depositional surface of the Agbada Formation at the time. Growth is achieved across the fault in the Agbada Formation by sediments being carried seawards over the fault to be deposited on the downthrown side. Merki, (1970) established a growth index which relates the bed thick- ness on the downthrown side to that on the upthrown , side. Continued upward movement of the Akata shale ridges at the back of faults may lead to the develop- ment of counter-regional growth faults. This gives rise to the 'back to back' faulting also common in the Agbada Formation of Niger delta. Crestal antithetic and synthetic faults developed within any one single growth fault unit are in response to pressures associated with the shale substratum (Weber and Daukoru,
1975; Evamy et.aL,1978) (Fig. 2..14. ) As the delta progrades seaward, the process outlined above is repeated and as a result a sequence of growth faults, younging in a similar direction is generated. SYNTHETIC FAULTS ANTHHETIC FAULTS
Figure 2.14 Schematic representation of the collapse crest structure of the growth fault in the Niger delta. Note the development of the synthetic and antithetic faults. 51
The growth faults and their associated shale
ridges trend in a roughly East-West direction parallel
to the coast line and at right angles to sediment
source. They are crescent shaped with the concave
side facing seawards. This shape is produced by an arching upward of the mobile clay at the slope due to overburden. As a result of this shape, the growth faults attain excessive curvatures at depths and die out along the bedding planes. Similarly they become
inactive at shallow depths and hardly affect the continental sands of the Benin Formation. The reason for this is not clear but it may be due to the sparse
clay beds in this sequence. Being largely a sand
sequence the sediments are able to resist the rotation along faults and therefore reduce the chances of
growth. In the Agbada Formation, throws across the
fault may range from 100m - 1,500m and sometimes more.
Closely related to the growth faults in the Niger delta are the rollover anticlines. These are produced, mainly on the downthrown side of faults,
by a downward rotational movement of sediments along
the curved surfaces of faults. The heights of the
closures generated by this movement are of the order of 10's of metres to possibly 100m. Where the closure is high enough, hydrocarbon accumulation may occur within the closure alone. More commonly, trapping is
effected by a truncation of the closure against the
fault. This intersection between the rollover structure MENT
/ j PROL I FIC CENTERS MM barrels / km2
100Kms.
Figure 2,15 Sketch map of Niger delta showing tha area of concentration of petroleum reserves. (After Ejedawe 1980). 53
and the fault serves commonly as the spill point for
many petroleum accumulations (Fig. 2.12) where the
fault is non—sealing.
The rotation of sediment along the fault plane to
produce the rollover structures is significant in
terms of petroleum accumulation. During movement the
shale beds of the Agbada Formation could provide
enough material to smear the fault zone and possibly
seal them. In fact the theory of shale smearing
along the fault zone is thought to provide the seals
for many reservoirs (Weber and Daukoru, 1975).
2.4.2 HYDROCARBON OCCURRENCE
Hydrocarbon accumulations occur in the reservoirs
of the paralic sequence of the Agbada Formation since
the growth faults which are critical to trap formation,
in this area, are restricted to this unit.
Most oil reservoirs are thin,hardly exceeding
100m. in thickness and generally sandwiched between
a gas cap and bottom water. (Fig. 2.12). They are also
limited in lateral extent due to the variations in
sedimentation patterns in the area.
Nearly all known hydrocarbon accumulations are
concentrated in a narrow arcuate belt in the northern
part of the delta (Fig. 2.15). This zone is almost
a mirror image of the present day coast line and
roughly coincides with the landward limit of the delta
at the time of rifting and initial separation of
Africa from South America (see Bullard qt.al.,1965). The
importance of this accumulation pattern is discussed in
chapters 5 and 6 of this thesis. 54
CHAPTER 3
PETROLOGY OF THE AGBADA FORMATION
3.1 INTRODUCTION
The Interpretation of the history of a sandstone depends
on a thorough knowledge of its mineral composition. This
list of mineral composition in itself is not sufficient and
must be supported by other data including the nature of the
cement, the post depositional alterations etc. This chapter
deals mainly with the mineral composition of the sandstone
of the Agbada Formation. In addition, it gives the results of
other analyses which though not directly related to the
petrography of these sediments are relevant to the diagenetic
interpretations in chapter 4. To date, very little has been
published on the petrography and petrology of the sandstones
of this region. Therefore, this chapter presents a detailed
account of the mineralogy and physical characteristics of the
sediments of the Agbada Formation. This Formation is the most
petroliferous and therefore economically most important of
the three lithostratigraphic units of this region. It is the
target of exploration and therefore the main subject of this
thesis.
3.2 METHODS OF STUDY
3.2.1 SOURCES OF SAMPLES
Sidewall cores (SWC) mainly taken from the Agbada Formation
(Eocene - Recent) of the Tertiary Niger delta, constitute the
major material used in this study. They cover the depth
interval from 800m to 4»000m and are derived mainly from
petroleum reservoirs. Although SWC are small (lM long by J"
or f" diameter) and may not be totally representative of the
entire bed from which they come, they are far more reliable 1 1 \ 3°E
Area of active exploration r7 TOO Km.
S" • Benin City r ~L W. [saniUsan^=> Onitsh a I Hlpolo. .Makaraba I MereM a r no r» \ k V Dir S o u t h "V 0 kan en 1 cn KN Ebubu .. . • Akata obe|ptki r sP or t H a re o urt
t Oyot • GULF OF QUI NEA
Figure 3.1 Map of Niger delta showing area of active exploration and sampled boreholes. 56
than ditch cuttings. It is possible to obtain valuable
information from them provided care is taken during analysis
to discount the artifacts that may be produced due to the force
of coring. The artifacts may include fracturing, twinning
(carbonates), production of matrix etc.
SWC have been used because conventional cores (2" or 3"
diameter) are difficult to obtain in this region due to the
poorly consolidated state of the sediments. Where conventional
cores were available, the results of their analyses have been
used to supplement and verify those obtained from the sidewall
cores.
All the samples used, were obtained by the operating oil
companies during drilling. Although some of them have been in
storage for over 12 years, and at average temperatures of 27°C,
little deformation or alteration of the minerals have occurred.
Samples were taken from locations scattered over the entire
delta but the preponderance were from the western delta areas
(Fig. 3.1.).
The fact that the oil companies obtained the samples for
their own purposes, imposed some limitation on the present
study which had to be designed to suit the samples available.
Generally oil companies take SWC in order to determine the fluid
content and/or fluid contacts in petroleum reservoirs. In some
cases, porosity and permeability measurements are also made.
The objectives are markedly different from those of this study
which is interested not only in the petrology of the petroleum
reservoir rocks but also in the non-reservoir sands and shales.
The size of the sidewall cores used also limited the sedimento- logical analysis that could be carried out. 57
3.2.2 ANALYTICAL METHODS
Three different analytical methods were employed in the
petrological studies of these sediments:-
a) Thin section petrography.
b) XRD analysis of both whole rock and oriented
clay fractions, supported by grain size
microsieve analysis.
c) SEM studies of the sandstones,
a) THIN SECTION PETROGRAPHY
This was carried out to determine the mineralogy as well
as the textural relationship of the various mineral components.
Preparation of thin sections was limited by the small size of
many individual samples. The samples were poorly indurated and
therefore required to be impregnated with Araldite prior to
thin section preparation. Thin sections were cut at right angles
to the bedding planes in order to facilitate the study of the
distribution of detrital framework and matrix materials as
well as those of the diagenetically precipitated minerals.
In order to aid the identification of various types of
cement (particularly the carbonates), staining of thin section
was undertaken employing the method of Evamy (1963). Techniques of staining carbonate rocks along similar lines have also been
described by Friedman, (1959); Hawkins, (1972); Lindholm &
Frinkelman, (1972). Staining in dilute hydrochloric acid with
Alizarin Red-S and freshly prepared 0.2-1$ Potassium Ferricyanide
was used to help identify carbonate minerals. Staining -for
clays using Malachite green in xylene (Tickell 1965) was not
successful and was abandoned since clays were successfully
studied using XRD and SEM. Point counting was undertaken for
quantitative estimation, with 400 counts per slide made on about
30 sampless. 58
Photomicrographs to illustrate the various features
observed were taken using Zeiss photomicroscope III with a
built-in camera, photometer and a variety of interchangeable
objectives and intermediate lenses, b.i) X-RAY DIFFRACTION
All 150 samples were analysed by x-ray powder diffraction
to determine their mineralogy particularly their clay minera-
logy. This method of analysis was most valuable in those
cases where,due to the small sizes of samples or due to their
very poor induration,thin section preparation was difficult or
not possible.
Approximately 2-5 grams of each sample was pulverised
using a Tungsten carbide mortar and a Tema mill until the
powder produced passed through a sieve with apertures of 63pm.
A cavity mount of each sample was then prepared from the powder
and analysed using a Philips x-ray powder diffractometer with
a wide angled goniometer. CoK^ radiation, generated at 34-KV and
28MA was used. The samples were scanned from 5°- 75° (20) using
a scan speed of 1° per minute and a rate meter of 4-00 or 800
counts per second depending on the peak intensities of the
minerals present. The d-spacing for all well resolved peaks
were calculated and the minerals identified (see Carroll, 1970;
Brown, .1961).
Oriented clay mounts were prepared by disaggregating the
sediments in water in an ultrasonic bath for about 30 minutes
(to ensure that each grain is water wet). The samples were then
taken out of the bath and left to stand for about five to ten
minutes to allow the larger and heavier particles to settle.
Then the suspensions were filtered through ceramic discs. By
employing a suction pump for this filtering, the clay minerals
were able to attain maximum orientation on the disc as well as 2-e-
Figure 3.2 X-ray diffractograms showing the stages in the identification of the clay minerals of the Niger delta. minimum segregation effects. (Biscaye, 1965; Shaw, 1971;
1972; 1978); The oriented day specimens were then analysed
in the powder diffTactometer employing CoIO radiation except
for those samples used for semi-quantitative analysis which
were analysed using FeK> radiation. In this case a scan
speed of 4° (29) per minute and a rate meter of 800 or 1000
counts per second was used. This was to ensure maximum
resolution of the low angled reflections from clay minerals.
In all cases the oriented clay mount specimens were analysed
as follows:
1. Air dry (2°- 50°, 29) to determine all clay
minerals present.
2. Glycerol treated (20°- 30°, (29)) to ascertain the
presence of swelling clays.
3. Heated at 400°C for li hrs. (2°-20°, 29) to confirm
the presence of smectites and mixed layers.
4. Heated to 550°C (2°- 30°, 29) to distinguish
between chlorite and kaolinite.
In all cases, care was taken to ensure that the same section
of the disc was irradiated each time (Carroll, 1970).
On X-Ray diffractograms, the presence of kaolinite in a
sample is indicated by the (001) reflection peak occurring
between 3.58 A - 3.54 A. The disappearance of these peaks on
heating the sample to a temperature of 550°C confirms the
presence of kaolinite and the absence of chlorite. (Fig. 3.2)
The variation in the position of the kaolinite peaks in the
whole rock analysis is interpreted in this case to indicate the
presence of chamosite which is present in insufficient quantities to be resolved as separate peaks. Porrenga, (1966:
1967) also reported diagenetic chamosite in the Recent sediments
of the Niger delta and stated that it persisted to a burial depth
of about 2,300m. 61 The main smectite peak in all XRD traces is a broad basal
reflection occurring between 14 A and 12 A. When treated with
glycerol the peak collapses to between 18°A and 17°A confirming
the presence of expandable clays possibly montmorillonite
(Fig. 3.2) The variation in peak position is interpreted as
being indicative of the presence of mixed layer clays which
contains large proportions of expandable constituents in some
cases.
Illite is mainly represented by a peak occurring between
9.97°A and 10.1°A. This peak increases slightly on heating the
samples to 400°C, indicating the transformation of mixed layers
and smectite to illite (Fig. 3.2)
Semi-quantitative evaluation of the various clay minerals
was undertaken by comparison of the relative peak areas of the
minerals present as outlined by Porrenga (1966). This method of
quantitative estimation was employed in order to allow for a
direct comparison between the results of this study and the
data of Porrenga (Ibid). In all cases in this study smectite
and expanding mixed layer clays were grouped together for
quantitative estimation. This quantitative data was supported
by semi-quantitative evaluation of grain size by micro-sieve
analysis j.n order to- confirm the relatively-high amount of silt
to clay grade matrix present in the s-ediments. b.ii)., MICRO-SIEVE ANALYSIS
This method was used to determine the proportion of matrix
in each sample. It was necessary to do this in order to resolve
the apparent anomaly between thin section analysis (which indi-
cated a relatively high matrix content in some cases) and XRD
results which indicated a dominance of quartz for the same
samples. A known weight of sample (5 - 12 grams) was disintegra-
ted (most commonly by squeezing between the fingers) and placed 62 in micro-sieves with apertures ranging from 63pm - 250um. The
various fractions collected in each sieve was weighed and the
percentage of the <75pm fraction calculated. c) SCANNING ELECTRON MICROSCOPY (SEM)
The SEM was primarily used to study the diagenetic minerals
and the textural relationships between the matrix, the cement and
the framework minerals. A freshly broken sample surface was used
in all SEM studies. The samples were mounted on conventional
aluminium stubs and coated with gold in a vacuum using a Polaron
E5000 diode sputter coater.
Sometimes correct vacuum conditions for coating were
difficult to attain particularly with samples from hydrocarbon
reservoirs. This is probably due to the fact that the hydro-
carbon in the samples vapourised and expanded under near vacuum
conditions. Due to the poorly indurated state of the samples,
no attempt was made to pre-extract the hydrocarbon (prior to
coating) for fear that this might cause the samples to disintegrate.
The coated samples were then examined using a Joel 35 SEM,
fitted with an energy dispersive X-ray analyser for estimation
of elemental composition. Details of the principles of the SEM
are contained in Goodhew, (l975). Using the very high magnefi-
cation of the SEM it was possible to distinguish between the
detrital and diagenetic minerals in the samples using some of
the criteria of Wilson & Pittman, (1977). No quantitative
estimation of diagenetic mineral content was attempted.
A few quartz grains, selected to represent the various
grain sizes in each sample were cleaned following the method of
Wilson, (1978) and examined under the SEM to establish the nature
and amount of silica cementation. After the initial stages of
this research, it was discovered that mere washing of the quartz
grains in soapy water was sufficient to clean the surfaces of 63
QTZ. QUARTZ ITE
FELD. RK. FRAG.
FELDS LITHIC FELDS PATHIC LITH LITH ARENITE FELDSARENITE ARENITE AR ENITE
Figure 3.3a Primary arenite triangle (after Folk et. al. 1970).
QTZ. ORTHOQUA RTZITE
CLAY 15 FELD. MUDROCKS WACKES -XR-ARENITES Figure 3.3b Sandstone classification based on clay as an indicator of textural maturity and feldspar as an indicator of chemical maturity (after Selley 1976) 64 grains. This is due to the fact that in the sediments under
investigation, quartz overgrowth only developed in those places
where the clay coating was thin, cracked or absent. The cleaned
grains were mounted on stubs and coated in gold as described
above, then examined under the SEM.
3.3 TERMINOLOGY AND CLASSIFICATION
The sediments of the Niger delta show only small variations
in mineralogical composition and textural relationship. Although
minor changes in mineral composition with depth (due to diagene-
sis) are observed, these are insignificant in terms of sediment
classification. As a result of this, a full scale classifica-
tion of the rocks was considered unnecessary. A broad division
into "Sandstones" and "Mudrocks" is considered adequate for the
purposes of this work.
Using the composition of the detrital framework minerals,
and based on the classification of Folk et. al., (1970),
modified by Selley, (1976), the sandstones of this region can
be classified as "Quartz Arenites" (Fig. 3.3). They contain
less than 15$ of unstable minerals. The composition of detrital
framework minerals is used because other parameters would give
a misleading classification. Since samples are derived by
Sidewall coring, a classification based on matrix content would
be inadequate. Many of the detrital grains are fractured by
the SWC bullet during sampling thus increasing the matrix
content and rendering this method of classification worthless.
Although the matrix thus derived can be estimated, such an
effort is tedious and would probably yield n.o significant result.
Also.,part of the clay matrix is derived diagenetically and
therefore did not constitute a part of the initially deposited
sediment. 65 TABLE 3.1 RESULTS OF SEMI-QUANTITATIVE ESTIMATION OF MINERALOGICAL COMPOSITION OF AGBADA SANDSTONES BY POINT COUNTING Sample No. QUARTZ FELDSPAR MATRIX CLAY MICA CEMENT POROSITY
^Includ- % Of (QTZ) (co3) % of ing Grains P p % r % Porosity Only
DLS 1 65 81 2 10 1 - 2 20
DLS 2 65 84 2 11 1 3 1 17
DLS 3 68 80 3 8 - 1 5 15
DLS 4 69 84 1 10 - - 2 18 DLS 5 70 81 2 12 1 - 1 14
DLS 6 67 80 2 9 3 1 3 16
DLS 7 75 92 2 5 - - - 18
DLS 9 67 84 2 10 - - 1 20 DLS 10 70 84 1 9 - - 3 17 DLS 11 61 80 1 12 1 1 - 24
DLS 15 68 82 2 10 1 - 2 17
DLS 16 68 80 1 8 2 1 5 15
DLS 18 70 84 - 10 2 - 1 17
DLS 19 70 83 1 11 1 1 - 16
DLS 20 71 87 1 7 1 - 2 18
DLS 22 69 82 1 11 2 - 1 16
DLS 23 68 80 2 9 3 1 5 15
DLS 25 73 91 1 6 - - - 20
DLS 27 62 79 3 ' 9 2 - 3 21
DLS 28 65 78 2 11 3 - 2 17
DLS 29 75 96 - 3 - - - 22 DLS 30 67 79 2 11 2 - 2 15
DLS 32 69 83 2 10 1 - 1 17 DLS 33 70 82 1 10 2 - 1 15
DLS 34 72 85 2 8 1 2 15
: "
contd.... 66 TABLE 3.1 Cond.
/2 •
DLS 36 75 90 1 5 1 - 1 17 DLS 38 71 84 2 10 - - 2 15
DLS - 39 77 96 3 - - - 20
DLS 40 76 93 - 5 - - 1 18
DLS 41 77 93 - 5 1 - - 17 1 6 7
Figure 3.4a- Scanning electron micrograph of conchoidal fracture in quartz grains.(Agbada Formation, Meren field - 1744m.).
Figure 3.4b Photomicrograph of replacement of quartz edges by calcite (Agbada Formation, 68
Figure 3.5a Photomicrograph of zircon inclusion in quartz (Agbada Formation)
Figure 3.5b Photomicrograph of quartz encircling quartz (not overgrouth). Agbada Formation, 69
3.4 MINERALOGY AND PHYSICAL PROPERTIES OF MINERALS
The data presented in this section represent a combination
of the results obtained by the previously described techniques
(see Appendix). This approach is adopted in order to avoid
repetition in the description of the sediments from various fields,
since very little variation exists in their mineralogical
composition. The significant differences observed between the
sediments from various areas are discussed collectively at the
end of this chapter.
3.4.1 DETRITAL FRAMEWORK GRAINS
a) QUARTZ: Mineralogically, nearly all the sandstones of the
Agbada Formation analysed are composed of between 80 - 90$ quartz
(Table 3.1). In some cases the quartz content of these rocks
is as high as 98$ particularly in hydrocarbon bearing sandstones
which contain relatively minor amounts of clays.
Quartz grains are generally very fine to medium sand grade
in size with occas ional coarse grade sand grains and pebbles; well
sorted and subangular to subrounded. The grains show both
undulose and straight extinction, the former being more common
in larger grains. The quartz grains of the eastern part of the
delta are more angular and coarser than those of the western part.
A few quartz grains show conchoidal fracture (Fig. 3.4a)
while some show evidence of replacement - generally replacement
of quartz edges by calcite (Fig. 3.4b). These features are common
in samples from the Meren, Delta south, Makaraba and Okan fields
in the western Niger delta. Inclusion of zircon and apatite in
quartz are common (Fig. 3.5a). In a few cases, quartz was
observed to encircle quartz (Fig. 3.5b). These grains are
usually not in optical continuity and therefore could not be
described as syntaxial overgrowths. It is most likely that this
relationship developed during a late magmatic phase in the parent
source rock. 70
Figure 3.6a Scanning electron micrograph of clay coating on detrital grains (Agbada Formation, Heren field - 1396m).
Figure 3.6b Scanning electron micrograph of clay coating on quartz grains (Agbada Formation, Idama field - 2915m) 71
Figure 3.7a Scanning electron micrograph of initial stages of etch pit development on quartz grains (Agbada Formation, Robertkiri field - 981m)
Figure 3.7b Scanning electron micrograph of late or advanced stages of etch pit fcrmation (Agbada Formaticn, Rcbertkiri field - 1707m) 72
Quartz overgrowths are few but when they do occur they show
optical continuity with the detrital grains. Commonly, these
overgrowths are poorly developed and only detectable under the
SEM. Many detrital grains also have a coating of either clay
or other matrix around them (Fig. 3.6a,b),
Under the high magnification of the SEM, corrosion pits
(etch pits) which represent sites of dissolution of quartz
(Fig. 3.7a)) were observed. These features closely resemble the
etch pits (presolved surfaces) of Krinsley and Doornkamp (1973)
and Wilson (1978; 1979). The pits are mainly irregular in shape
and their intensity varies from sample to sample.
Examination of grains from samples covering the depth
interval between 800m and 3,500m from many wells, show that the
zone of intensive dissolution of quartz is restricted to depths
of less than 1,800m. Up to the depth of 1,800m a progressive
increase in the size of etch pits is observed in samples from
many wells (Fig. 3.7a & b). Below this depth the grains appear
to have reached equilibruim with their environment and show no
further increase in size of pits developed on their surfaces.
Polycrystalline quartz grains are fairly common in thin
sections (Fig.3.8a). The contact between the individual grains
of a polycrystalline composite exhibit concavo-convex and
sutured contacts. Apart from these, the single grains of the
framework minerals mostly show tangential contacts..
b) FELDSPARS: Feldspars are the next in order of abundance ,
constituting between 2 and 1% of the detrital mineral composition of the sandstones. A number of varieties of feldspars were
recognised. They include, in order of decreasing abundance,
potash feldspars - twinned and untwinned, microcline and plagio-
clase. 7 3
Figure 3.8a Photomicrograph of a polycrystalline quartz, showing sutured contacts (Agbada Formation
Figure 3.8b Photomicrograph of a large relatively unaltered feldspar grain, common in Agbada sandstone of the eastern Niger delta. 74
Figure 3.9a Photomicrograph of a small highly altered feldspar grain, common in Agbada sandstone of the western Niger delta.
Figure 3.9b Scanning electron micrograph of diagenetic feldspar overgrowth (Agbada Formation, Meren field - 1396m) The grains are predominantly of fine to medium sand grade.
They vary, even in one thin section, from fresh (Fig. 3.8b) to
all degrees of alteration (Fig. 3.9a). Diagenetic feldspars are
developed in rare cases (Fig. 3.9b). Like the quartz previously
described, the feldspars show a variation in grain size between
the western (finer) and eastern (coarser) parts of the delta.
In addition, they show a variation in both abundance and minera-
logy. This variation is related to the proximity of the sources
of sediments and it is fully discussed along with other mineralo-
gical and textural variations in section 3.5.
c) ROCK FRAGMENTS: Very few rock fragments (lithic grains) were
observed. Lithic grains occur in such minor amounts in the samples
examined that they were considered insignificant and not
quantitatively evaluated.
3.4.2 MATRIX MINERAL
a) QUARTZ: The matrix in many of the sandstones analysed consists
dominantly of quartz. These are of silt to clay grade sizes.
Therefore, although the matrix content may be as high as 15$ and
sometimes slightly higher, (Table 3.1 & 3.2) it is difficult to
classify the sediments as wackes sinces mineralogical composition
determined from XRD show quartz to be dominant even in the <2ym
fraction. Also, bearing in mind that some of the matrix may have
been generated during sidewall coring, the designation of 'quartz
arenites' used for the sandstones of this region is thought to be
more justified. The matrix consists dominantly of detrital
material although diagenetic clay phases also contribute.
In many sandstones of the Niger delta, the matrix provide
the major binding force holding the framework minerals together.
Meade (1966), has suggested that in some cases, matrix in sand-
stones can provide enough binding force in the sediment to with-
stand conventional coring. This is very true of some fields in 76 TABLE 3,2 RESULTS OF SEMI-QUANTITATIVE MICRO-SIEVE ANALYSIS OF SOME AGBADA SANDSTONES Sample Wt. of Sample Wt. of Sample % of <7 5jjm Sample No. Weight <7 5ym fraction >7 5jim fraction Fraction
y DLM 1 10.4236 2.0328 8.3908 20.0
DLM 2 4.9602 0.8517 4.1085 17.0
DLM 3 5.4168 0.6504 4.7664 12.0 y
DLM 4 5.5608 1.0724 4.4884 19.00 ^
DLM 5 7.9506 1.4964 6.4842 19.00^
DLM 6 5.5820 1.0900 4.4920 20.00^
DLM 7 5.0022 1.0682 3 .9340 21.00 ^
DLM 8 5.6118 0.6624 4.9494 12.00 y
DLM 9 5.4244 1.1284 0.2960 21.00 y
DLM 10 12.8416 1.9928 10.8488 16.00 ^
DLM 11 5.1656 0.9684 4.1972 19.00 J
DLM 12 5.5517 1.1235 4.4282 20.00 y
DLM 13 4.9565 0.6900 4.2665 14.00 ^
DLM 14 4.8924 0.8060 4.0864 17.00 ^
DLM 15 4.8428 0.4428 4.3820 9.00 y
DLM 16 5.1275 0.7098 A.4177 14.OO^
DLM 17 4.7940 1.0244 3.7696 21.00 y
DLM 18 5.9412 1.3206 4.6206 22.00 ^
DLM 19 4.9044 0.8044 4.1000 16.00y
DLM 20 5.3628 1.2678 4.0950 24.00 y
DLM 21 4.6260 1.0004 3.6256 22.00^
DLM 22 5.9843 1.3195 4.6648 22.00
Dim 23 7.3535 1.3937 5.9683 19.00 V
DIM 24 6.6157 1.3235 5.292 20.00 y
DLM 25 7.6926 1.3761 6.3165 18.00 y
DLM 26 7.1940 1.3580 5.828 19.00 ^
DLM 27 5.0155 1.1514 4.8641 23.00^
J DLM 28 7.5515 1.5900 5.9615 21.00
contd 77 /2
Table 3.2 contd.
DLM 29 5.9550 1.2078 4.7472 20.00y
DLM 30 10.5620 2.1025 8.4595 20.00^
DIM 31 7.0482 1.5118 5.5364 21.00 7
DLM 32 6.0505 1.1090 4.9415 18.00 7
DLM 33 5.1384 1.1142 4.0242 22.00^
DLM 34 6.3570 1.2030 5.1540 19.00 7
DLM 35 9.9281 1.8277 8.1004 18.00y 3000 -
4000
5-000
6000
• • •
7000 -
flOOO n Q_ ULI Q
9000
10000 •
11000 •
11000 10 20 30 % MAT RI X ( c 75jjm fraction ) Figure 3.9c Plot showing variation in matrix content with increased burial depth. Note that there is no sifmificant variation in matrix content with depth 7 8
Figure 3.10a Photomicrgraph of open packing in Agbada sandstone.
Figure 3.10b Photomicrograph shouing the distribution of microcrystalline siderite cement in Agbada sandstone. 79 the Niger delta where thin section studies show large areas
which are apparently devoid of any form of authigenic cement
(Fig. 3.10a). Such areas exhibit open packing and the matrix
constitutes the major binding material holding grains together,
b) CLAYS; Clays are present as both detrital and diagenetic mineral
phases in the sediments of the Niger delta. Although no attempt
has been made to quantitatively evaluate each of these components,
a subtle difference between them is made in the presentation of
data. This section presents a general discussion of the clay
minerals as determined by XRD analysis and thin section studies
while the diagenetic clays in the sandstones of this region are
discussed in section 4-«4-.
Clay minerals comprise between 2% and 10$ of mineralogical composition of the sandstones of the Agbada Formation. The
common clay minerals in order of. decreasing abundance are kaolinite,
smectite and illite. Mixed layer clays are also present but are
included with the smectites in all quantitative evaluations in
this thesis. The amount of kaolinite estimated from the <2pm
fraction ranges between 4.0$ and 70$ though it may sometimes
exceed 90$ of the total clay in hydrocarbon reservoirs
(Table 3.3 a &b). Smectite varies from 0-30$ and illite rarely
exceeds 20$ of total clay.
3.4.3 ACCESSORY MINERALS
Mica, iron oxide, glauconite and zircon are accessory
minerals although they are not detected in XRD. Glauconite
occurs as greenish pellets in the sandstones and is also common
in the mudrocks of the region. Mica shows various stages of
alteration and occurs in equal amounts in both sandstones and
mudrocks. Zircon occurs in a number of samples and is found
very commonly as inclusions in quartz. Apatite too, occassionally
occurs as inclusions in quartz. Iron oxide is perhaps the most
common accessory mineral and occurs in nearly all samples. 80 TABLE 1.3.3a
CLAY MINERALOGY OF AGBADA..& AKATA FORMATIONS
% Illite Sample Depth. Temp • % Smectite % Koal % Smectite Illite No. °C + Smec AGBADA FORMATION DIG 2750' 60 35 - 50 15
DIG 3150' 65 40 - 45 15
g DL 4616' 80 35 - 40 25
DLC 5117 ' 90 - 10 75 15
1 DLC 5313 85 20 - 65 15
DLC 5717 ' 95 n.d 75 25
DLC 5923 ' 95 35 - 65 n.d
1 DLC 6973 105 35 - 45 20
DLC 7250 ' 110 20 - 65 15
1 DLC 9716 140 - 20 55 25
DLC 8014 ' 97 - - 75 25
DLC 9562 ' 90 15 - 70 15
DLC 10580 ' 97 10 - 75 15 DLC 10140 ' 105 20 35 35 30
1 DLC 11060 105 — 30 40 30
AKATA FC RMATION
DIG 11930 ' 120 - - 60 20
DLC 11940 » 120 45 - 45 10 10 DLC 11945 ' 120 50 — 40 81
TABLE 3.3b RELATIVE AMOUNTS OF CLAYS IN HYDROCARBON AND NON -HYDROCARBON ZONES HYDROCARBON NON-HYDROCARBON
Total Field Kaol. Total Clay Smect. Illite Clay Koal. Smect. Illite
MEREN 5-10% 90 TRACE TRACE < 10% 70 25
DELTA
SOUTH 5% < 95% — TRACE 10% 60% 30% 10%
OKAN 5-10% 90% TRACE TRACE 10% 60 25% 15%
OPOLO 5% 95% TRACE TRACE < 10% 55% 35% 10%
MAKARABA 5% 90% - TRACE < 10% 65% 20% 15%
W. ISAN 5-10% < 95% - - 10% 60 25% 15%
ROBERTKIRI 5% < 95% - - 10% 70% 10% 20%
IDAMA 5-10% 95% - TRACE 10% 75% - 20%
OYOT 5-10% 90% TRACE TRACE <10% 65% 25% 10%
OLURE 5% 95% - TRACE 10% 55% 20% 25% 82
3.4.4 CEMENTING MATERIALS Although the amount of cementing material in the Agbada
sandstones is small, it is important when considering the
diagenetic history and economic values of the sandstones as
petroleum reservoirs. The effect of cementation on the sand-
stones of the Niger delta is two fold -
1. It partially fills pore spaces and;
2. It sometimes locally modifies the framework minerals by
processes of mineral replacement (see section 4.4) In
nearly all the sandstones examined, cementing materials
comprise less than 8% of the total mineral composition of the sands. This demonstrates how poorly indurated
the sandstones of this region are. The cementing
materials most commonly observed are siderite, calcite and
secondary quartz in order of decreasing abundance.
Pyrite and gypsum are also present but do not act as
binding minerals, and are included in this section because
they are precipitated from solution.
a) CARBONATE CEMENT
Carbonate cement although not abundant is present in many
samples. Siderite and calcite are the major carbonate minerals
present. Siderite is observed to be more abundant in thin
section and XRD. It is recognised by its characteristic brownish
colour (in thin section) which remained unchanged on staining
with Alizarin Red-S and Ferricyanide according to the method of
Evamy (1963) (Fig. 3.10b). It is observed in hand specimen as
brownish spherulitic grains with a 'botryoidal-like' form and is
more abundant in the deeper samples from many wells, whereas
calcite is more common at shallower depths. It is also the
dominant carbonate cement in the finer grained sandstones. 739 8
Figure 3.11 Photomicrograph of residual calcite cement in Agbada sandstone 84
Calcite occurs in a few thin sections but never in abundance. It exhibits simple twins part of which may be due
to the method of sampling (see section 3-2). It stained red or mauve in Alizarine red-S in hydrochloric acid but showed no + + reaction to Potassuim Ferricyanide• This indicates that Fe is either absent or present in very low concentrations. An early precipitation of calcite is inferred from the fact that in places, calcite exhibits poikilitic texture enclosing detrital grains (Fig. 3.4b) and sometimes corroding them. Apart from the few cases of poikilitic texture observed, calcite appears patchy and most probably residual, the greater portion having being disolved out at depths (Fig. 3.1l)» generating secondary porosity.
The two carbonate minerals in the sandstones were hardly ever found juxtaposed to one another yet the apparent depth segregation in their distribution is significant. Even though their relationship could not be studied, it is most likely that calcite preceded siderite. This inference is supported by the fact that:
1. Calcite exhibits a poikilitic texture enclosing many detrital grains whereas siderite is precipitated as a drusy material in the pore spaces between grains.
2. Only calcite is observed to replace quartz in these sandstones. As discussed in section 3.4.1t it appears that quartz solubility was high up to a depth of 1,800m.
Replacement of quartz by calcite would most probably have occured either before or at this level, since the condition
(high pH) that 85
Figure 3.12a Scanning electron micrograph of fractured quartz overgrowth (Agbada Formation, Olure field - 3039m)
Figure 3.12b Photomicrograph of quartz overgrowth replacement by calcite in Agbada sandstone. 86 favours the dissolution of quartz also enhances the precipitation of calcite (Kashik, 1965). + + However, the low Fe content of the calcite coupled with the fact that siderite is not observed to replace calcite appear to suggest that the transformation from calcite to siderite like most diagenetic reactions is not a solid phase reaction.
It appears that calcite is first dissolved in the pore waters, followed by the precipitation of secondary siderite. This observation is supported by the known theoretical considerations of the stability fields of these minerals (See Garrels and
Christ, 1965; Krauskopf, 1967). While both minerals are stable within approximately similar pH limits, the Eh conditions for their precipitations are different.
The depth segregation of these minerals- does not appear to be controlled by the environment of deposition since it is observed fairly consistently over the entire delta region. The observed restriction of siderite to the finer grained sediments may be due to the fact that the formation; fluids in such beds stay relatively immobile because of their lower porosities and permeabilities. As a result, the weakly acidic pore waters which dissolve most of the calcite and now laden with C0^=ions remain in the formation. Under such weakly acidic conditions, and given the right Eh conditions, siderite precipitation is favoured (Krauskopf, 1967; Berner, 1971). In the coarser grained sandstones, the C0^=ions are removed with the mobile formation water and precipitation does not take place within the porous and permeable sandstones.
SECONDARY QUARTZ
Relatively little diagenetic silica in the form of overgrowth was detected. Two distinct sizes of overgrowths were observed:- n -7 O /
Figure 3.13a Scanning electron micrograph of tiny spikes of quartz overgrowth - initial stages of quartz overgrowth development in the Agbada Formation. Isan field - 1971m
Figure 3.13b Scanning electron micrograph of rhombohedral pyrite in Agbada sandstone. Robertkiri field - 2076m. 88 a) Large, well formed, euhedral overgrowth which are detect-
able by the petrographic miscroscope. These were either
fractured (Fig. 3.12a) or partially .replaced by calcite
(Fig. 3.12b).
b) Tiny euhedral crystals observable only under the high
magnification of the SEM (Fig. 3.13a). These were observed
during the investigation of the surface textures on individual
grains. The evidence of fracturing and partial replacement
of the former indicates that they were probably developed outside
the present depositional basin. Fracturing in many cases is
indicative of transportation and abrasion of grains. It can be
concluded therefore that the latter overgrowths represent the
secondary silica precipitated in the present basin since they
show no evidence of corrosion or alteration.
3.4.5 NON-BINDING DIAGENETIC MINERALS
a. PYRITE: Pyrite occurs as tiny well formed cubic crystals
developed in the pore spaces (Fig. 3.13b). Sometimes these are
aggregated together to form framboids. The crystals are small
in size and appear to have developed indiscriminately on the
surfaces of most minerals,
b. GYPSUM: Gypsum is present as an artifact in these sandstones.
It is random in occurrence and diagenetic in origin. It exihibits
two forms:-
a) Well formed orthorhombic crystal which are limited in
occurrence and sometimes aggregated into rossettes (Fig. 3.14a).
b) Poorly formed generally fibrous crystals (Fig. 3.14b) which
may have formed late due to evaporation of the connate water
after the core was taken.
The two forms rarely occur together but each has been found
in samples from depths ranging between 2,000m and 2,500m and
corresponding temperatures of approximately 90°C to 110°C. 89
Figure 3.14a Scanning electron micrograph of well formed gypsum crystals aggregated together into a rossette (Agbada Formation, Gbokoda field - 3099m)
Figure 3.14b Scanning electron micrograph of fibrous gypsum in Agbada sandstone. Heren field - 1052m. 90
Considering this fact and the fact that the stability field of
gypsum is <60°C, it is most unlikely that even the well formed
crystals were developed in situ in the formation. (Prof. Shearman
Pers. comm.). Both phases most probably developed after the
cores were taken. Gypsum is therefore most likely introduced as
additives in the drilling mud and not contemporareous with the
sediment. The variation in crystal form may be explained by the
initial concentration of gypsum in the drilling mud, as well as
the rate of evaporation of the formation fluids.
3.5 NON DIAGENETIC VARIATIONS IN MINERAL ASSEMBLAGE OF THE AGBADA FORMATION
The suite of minerals outlined above can be found in nearly
all beds of the Agbada Formation with minor variations.
Mineralogical variation in detrital mineral assemblage is in the
amount present while diagenetic mineral assemblages show variation
in both type and amount. The most significant variation in
framework minerals occur between the eastern and western areas
of the delta. The variation is mainly reflected in the size, and
shape of the grains as well as the amount and mineralogy of the
feldspars.
In both the eastern and western areas of the delta, there
is a normal sequence of upward coarsening of grain size from the
pro-delta shales at the base to the continental sands at the top.
This upward increase in grain size is the result of the building
up of the delta. As the sea regresses and the coastline emerges,
the environment of deposition in any one place changes from
marine at the base through a transitional paralic sequence to
continental at the top. Apart from this normal upward coarsening
sequence which is exhibited in many deltas. (Selly, 1976; 1977),
there is also observed in this region a progressive increase in 34
32
30
2 8
26
24
22
20
1 8
1 6
14
12
10
8 92 grain size from the west to the east. In addition to this, there is increased angularity of the grains in the eastern section compared with those in the west. These differences are related to the proximity of the sources of the sediments in both areas (see section 3.6).
In the eastern delta, potash feldspar is dominant over the other types whereas in the western part of the delta, plagioclase feldspar is dominant. The east is characterised by larger grains of feldspars showing lower levels of alteration (Fig. 3.8b) in contrast to the smaller and more altered grains of the West
(Fig. 3.9a). In terms of abundance, the feldspar content in sediments from the east is also higher than those from the west.
In many of the samples analysed, the feldspar content bears an inverse relationship to the clay content (Fig. 3.15). This observation suggests that there may be a relationship between the diagenetic clay content and the loss of feldspars in both parts of the delta. Scarcity of samples did not allow a thorough investigation of this problem.
Very little variation in clay mineralogy is observed over the delta. The major variations are depth and temperature related and are therefore diagenetic (see section 4-.3 & 4-.4).
However, Porrenga, (1966) suggested an increase in smectite content from the west to the east of the delta. He explained that the weathering of the volcanic materials in the Cameroon mountains (basaltic & ryolitic rocks which supply sediments to the area) resulted in the increased smectite content. In addition to this, there is the fact that due to differential settling, smectite remains longer in suspension (Biscaye, 1965; Porrenga,
1966; 1967; Weaver, 1967; Shaw, 1972; Gibbs, 1977). As a result of this phenomenon, smectite constitutes the major clay mineral transported by longshore currents from the west to the east. 93
The increased smectite content in the eastern part is therefore
explainable in terms of differential settling as well as provenance.
3.6 PROVENANCE
The mineral assemblage in the sediments of the Niger delta,
including the presence of polycrystalline quartz and inclusion
of heavy minerals in quartz, reflects their derivation from the
basement and volcanic rocks in the northern part of Nigeria.
However the evidence of fractured and replacement quartz over-
growths plus the low content of unstable minerals i.e. feldspar
and the fair to good sorting, (particularly in the western delta)
indicate that at least some of the materials are derived from
pre-existing sediments. Reworking of previous sediments is more
significant in the western Niger delta where materials may be
derived from the folded sediments of the Abakaliki high.
Materials are also derived from older inland basin and possibly
the mid-Niger basin, the Benue trough and the Anambra basin
(Fig. 1.2) all of which contain older sediments (see Adeleye,1978).
The sediments supplied by these older basins are mainly deposited
in the western Niger delta which therefore shows more textural
and mineralogical maturity than those of the eastern Niger delta.
As a result of the increased angularity of the grains of the
eastern delta, as well as the higher feldspar content, they are
believed to be first cycle sediments derived largely from the near
by Oban Massif and Cameroon mountains. The short transporta-
tion history probably accounts for the larger and angular grains
as well as the high content of the relatively fresh feldspars. 94
CHAPTER 4
DIAGENESIS OF THE SEDIMENTS OF THE AGBADA FORMATION
.1 INTRODUCTION
The term diagenesis is defined as the physical and chemical
changes which take place in sediments after deposition but
excludes metamorphism and sub-aerial weathering (Blatt et. al. ,
1972; Plumley, 1980). Pettijohn (1957) and Selley (1976)
however limit the definition to include only the chemical changes.
Although chemical diagenesis becomes dominant after the initial
compaction, the former definition is used in this thesis since
both physical and chemical changes are important in the Niger
delta.
Very little exists in the published literature on the diage-
nesis of the sediments of the Niger delta, yet the diagenetic
history must be understood in order to define and solve many of
the problems of the petroleum industry in Nigeria. Of particular
interest are the problems associated with the enhanced
recovery programmes which will be embarked upon on a large
scale in the not too distant future. This chapter therefore
examines the history of compaction and cementation of the
sediments of the Agbada Formation with a view to explaining
their under-consolidation (poor compaction and poor induration).
The production of fines at the surface with the crude oil
from the reservoir rocks is a direct result of this under-
consolidation and its associated high porosities and permeabi-
lities. Although this chapter deals mainly with the Agbada
Formation, the results of the analysis of a few shale samples
of the Akata Formation are also presented and compared with
those of the Agbada Formation. 95
Generally however, the subject of diagenesis is very well documented in the literature. In the last decade alone at least five reviews of the subject of clastic diagenesis have been written. These include articles by Fuchtbaur (1974);
Jonas & McBride (1977); Wilson & Pittman (1977): Hayes
(1978; 1979); and Pittman (1979). In addition two volumes on the state of the art have independently been produced by the Geological Society of London (v. 135.1) and the Society of Economic Palaeontologists and Mineralogist (SEPM Spec.
Publ. No. 26). This recent proliferation of papers is partly due to improved technology (particularly the development of the SEM) and also due to the importance that has been attached to the subject by the petroleum industry. Of the several subdivisions under which the subject has been discussed in the literature, only those which were observed during the course of this study are considered here. They include, l) Diagenetic clays in sandstones. 2) Diagenesis of clays
3) Cementation of quartzose sandstones (including the sources of silica and 4) Secondary porosity in sandstones. 96
4.2 PHYSICAL DIAGENESIS IN THE SEDIMENTS OF THE
AGBADA FORMATION
In the Agbada Formation of the Niger delta, diagenetic
modifications to the sandstones are largely controlled by
chemical factors. However in order to fully understand these
processes, it is also necessary to consider the physical
changes that take place before and sometimes simultaneously
with them. Physical diagenesis affect the sediments more
in their early stages of burial but may continue until the
late stages. The processes of physical diagenesis include the
re-arrangement of grains (particularly mica and clay particles),
grain fracturing, grain bending and grain squeezing. Since
the occurrence of these processes appear to be broadly
similar irrespective of the location of "the sample in the Niger delta
and of the depth of burial of the Agbada Formation, the
data can be presented collectively.
4.2.1 RE-ARRANGEMENT OF GRAINS AND GRAIN BENDING
The re-arrangement of grains occurs mainly as a result
of compaction. It is most evident in the clay and micaceous
particles which become aligned with their long axes at right
angles to the principal stress. Bending of grains is more
commonly found in coarser grained sandstones and in the Niger
delta it usually involves the bending of micas around
quartz grains (Fig. 4-1 a & b). In addition, laminae of
argillaceous materials are found bent around detrital grains
in response to stress (Fig. 4.2a). 9 7
Figure 4.1a Photomicrograph of a mica grain bent round a detrital grain in response to stress. Agbada F ormation
Figure 4.1b Photomicrograph of a mica grain fractured in the process of folding round a quartz grain. Reaction to stress probably due to overburden pressure. Agbada Formation 98
Figure 4.2a Scanning electron micrograph of bent shale lamina in response to stress (Agbada Formation, Idama field - 2915m).
I Figure 4.2b Photomicrograph showing the fracturing of a feldspar grain in response to stress. Note the alteration of feldspar in the fracture zone. (Agbada sandstone 99
4.2.2 GRAIN FRACTURING
Grain fracturing is wide spread in all the sediments
analysed. However many of the fractures observed are artifi-
cial,. mainly resulting from the method of coring. The speed at
which the sidewall sample bullet is shot into the formation
creates enough force on impact to fracture the grains. Under
normal circumstances it should be possible to distinguish
between these fractures and those caused by normal compaction,
(Fig. 4.2b) by examining the amount and type of diagenetic
minerals in the fractures. The artificially induced fractures
(Fig. 4.3a) would lack the clay or matrix coating which is a
characteristic of many of the detrital grains. However, the
fact that these samples were impregnated prior to thin section-
ing, made this distinction difficult in many cases. As a
result, fracturing of grains has not been used as a valid
criterion for physical diagenesis in this study.
4.2.3 GRAIN SQUEEZING
In a number of samples, micas are found squeezed between
two detrital framework grains for most of their length but
develop a fan shape at their extremeties (Fig. 4.3b). The
splitting of the mica flake into a fan shape allows clay
alteration products to develop during diagenesis. This
diagenetic clay usually has a lower birefringence than the
parent mica and is thought to be illitic in nature.
4.3 DIAGENESIS OF THE AGBADA FORMATION SHALES
Several reviews of clay diagenesis have been made in the
recent past. Prominent among these are those of Weaver (1960)
De Segonzac (1970) and Shaw (1980). Other contributors to the
subject of clay diagenesis include Powers (1967); Burst (1969);
Perry & Hower (1972); Magara (1975a) Eberl (1978); Hancock 6
Taylor (1978); Foscolos & Powell (1979) to name a few. 100
Figure 4.3a Photomicrograph of artificially induced fracture on auartz grain. Agbada Formation
Figure 4.3b Photomicrograph of a mica grain squeezed between two detrital grains and developing a pseudo fan in the process. Agbada sandstone ACID ALKALINE ENVIRONMENT ENVIRONMENT
KAOLINITE SMECTITES, VERMICULITES, ILLITES, CHLORITES
t DICKITE MIXED LAYER PHASES
t NACRITE \7 ILLITES CHLORITES ILLITES CHLORITES \ (Micas) (destroyed at temperatures > 200-250°C ) Dehydration
Increasing crystallinity Figure 4.4 schematic representation of the trend of clay diagenesis with increased depth of burial. (After Shaw 1980). 102
About the only publication on the clay mineralogy and diage-
nesis of the Niger delta are those of Porrenga (1966; 1967)
and Adeleye (1978). The consensus of opinion from these
studies is that under normal compaction, clay diagenesis and
transformation increases with increasing burial depth. The loss of clay-bound water and the interlayer water is important to the process of clay transformation. Increased temperatures are also essential. The sequence of transformation is generally from the less stable .kaolinite and smectite at near surface conditions, through mixed layers to the more stable illite and chlorite at depth (Fig. 4.4)* However, where the normal sequence of dewatering of the clays is interrupted for any reason, overpressuring of the clay bed commonly occurs.
Before dealing with the shales of the Agbada Formation, it is perhaps necessary here to give the results of the analysis of four Akata shale samples that were available to the writer.
The results represent the base against which those of the
Agbada shales are compared for valid interpretations. However, the small number of Akata shales analysed prevents a detailed discussion of the Akata shales at this time.
The shales of the Akata Formation are predominantly composed of clay minerals (55-90$), with minor amounts of quartz and feldspars. Their clay mineralogy consists of kaolinite (35-60$) smectite (20-50$) and illite (10-30$). No mixed layer clay was recorded in all four samples (Fig* 4.5 & 6) although the burial temperature estimated for them averaged about 120° C.
The Agbada shales like those of the Akata are predo- minantly composed of clays (55-90$) but this time they also contain minor amounts of carbonates and pyrite in addition to 3375m. Figure 4.5 Comparison of X - ray diffractograms of Agbada and Akata shalas,(glyceratd fraction). 2 I
Figure 4.6 X -ray diffractograms of Agbada shales, compare with figure 4.5 (glycerated fraction). 105
the quartz and feldspars. The clay mineralogy of the Agbada
shales is similar to those of the Akata shales. However, they
contain more kaolinite (40-70$) and less smectite ( 0-35$)
while illite remains relatively the same (15-25$). Expandable
mixed layer clays are present but are included in the
smectite content (Fig. 4-6).
The clay assemblages of the Agbada shales show only minor
variation with increased depth of burial. For example
smectite is present at burial depths of 2126m, 2195m and 3226m
corresponding to burial temperatures of 105°C, 110°C and 97°C
respectively. The sample from 3226m comes from the central
Niger delta where geothemal gradients are lower. Smectite is
however noticeably absent with only illite - smectite present
in one sample with an estimated burial temperature of 140°
at a depth of 2962m. Mixed layer illite - smectite clays are
also present to the exclusion of smectite at a burial
temperature of 90° C and a depth of 1550m. This random distri-
bution of clay transformation with increased burial depth
of the Agbada Formation suggests that burial temperature is
perhaps not the only factor responsible for clay transformation
(see Shaw, 1980).
4.3.1 COMPARISON BETWEEN THE AGBADA AND AKATA SHALES
The difference in clay mineralogy between the Agbada and
Akata shales is explained in section 3.6 as due to the differ-
ential settling of clay particles from surface waters (see
Porrenga, 1966;Gibbs 1977 and Shaw, 1978). Consequently as
one would expect, the near shore environment of the Agbada
Formation contains more kaolinite and less smectite than the
deeper water environment of the Akata Formation. 106
The effect of burial diagenesis on clay mineralogy of
the shales of the Akata Formation like those of the Agbada
Formation appears to be slight. This is supported by the
broad similarities that exist between their clay mineralogy and those of the shales of the Recent sediments of the area as established by Porrenga (1966). However, the effect of burial diagenesis appears to be more marked in the Agbada
shales than those of the Akata. For example, the preservation of smectite in the Akata Formation at a depth of 3620m and a burial temperature of 120°C is a little surprising as one might have anticipated that the transformation to mixed layer illite-smectite would have occurred at such a temperature.
It has been postulated that the transformation of smectite
to the mixed layer phases would occur in the temperature
range of 8Q°C - 100°C (Burst, 1969; Perry & Hower, 1972;
Shaw, 1980). Transformation of smectite to mixed layer phases within the Agbada Formation appears to follow this broad outline since mixed layer clays are recorded in this study at depths as shallow as 1550m and temperatures of 90°C.
This difference in the degree of clay transformation may be valuable in distinguishing between the Agbada and Akata
Formations. The Akata Formation as defined in this thesis is under-compacted and overpressured. It should therefore,
(as indeed it is in the limited samples analysed) contain
smectite in the hydrated from in contrast to the normally compacted shales which contain varying proportions of mixed layer clays. On this basis, two samples from the Akata field, previously defined as Akata shales (Short & Stauble, 1967). have been grouped with the Agbada Formation since they contain 107
mixed layer illite-smectite. The burial temperature estimated
for these samples averages 105 C. Although the d eeper
samples of the Akata shales have estimated burial temperature
of 120°C their level of clay transformation is lower.
The major factor responsible for this low level of clay
transformation in the Akata Formation appears to be the poor
dewatering of the Akata shales. This observation goes to
strengthen the case made earlier in this thesis for a change
in the location of the boundary between the Akata and Agbada
Formations. Weaver (1960) proposed the use of clay minerals
as a tool for stratigraphic correlation in petroleum exploration.
4.4 DIAGENETIC CLAYS IN THE AGBADA SANDSTONES
Clays in sandstones are important because they affect
porosity and permeability which are two of the most important
parameters that determine the quality of sandstone bodies and
therefore their suitability as reservoirs. They are present
in both detrital and diagenetic phases. The diagenetic clays
create more problems in reservoirs because they more commonly
precipitate in the pore spaces. They are therefore, more
intensely studied. The criteria for their recognition and
distinction from detrital clays have been given by Wilson &
Pittman (1977).
Evidence from laboratory studies also support the possi-
bility of the diagenetic formation of clays. For example
Keene et. al. (1973) experimentally produced clays from
various rocks including tholeitic basalt at temperatures
between 150°C and 250°C, and Divis & McKenzie (1975) produced
clays in the laboratory from feldspathic sands at 200°C. The
relatively low temperatures at which these clays were
generated suggest that given the prolonged periods available 108
over the geological time-scale, similar generation of diagenetic clays could occur at much lower temperatures.
In the last two decades, it has become increasingly clear that diagenetic clays in sandstones are far more common than previously believed. This is shown by the works of
Shelton, (1964) who compiled a list of occurrences of diagenetic kaolinite in sandstones and Hayes, (1970) who did a similar thing for chlorite. Carrigy and Mellon, (1964)
also demonstrated that diagenetic clays are widely distributed in sandstones of all types and ages.
The advent of the SEM facilitated the study of the importance of clays in sandstones and led to the proliferation of papers on the subject. Among the many who contributed to this aspect of sandstone diagenesis are : Sarkisyan,(1971);
Walker & Waugh, (1973); Stalder, (1973); Almon & Davies, (1977);
Sommer, (1978); Hancock & Taylor, (1978): Thomas, (1978) and
Blatt, (1979).
The mode of occurrence of diagenetic clays has been discussed by Neasham, (1977) who identified four types: a) Pore lining, b) Pore filling c) replacement of lable grains and d) fracture and vug filling. All diagenetic clays exhibit the pore filling morphology although it is most commonly observed in the kaolinite - dickite group.
After the initial dewatering of clays in shale beds, they are less susceptible to diagenetic changes than those in sandstones. The main reason for this lies in the fact that due to their higher porosity and permeability, more fluid movement occurs within the sandstones. This allows the constant supply of materials for reactions and the removal of the end products of reactions, thus favouring the forward reaction. 109
Figure 4,7a Scanning electron micrograph of booklike kaolinite in Agbada sandstone, Meren field - 2126m.
Figure 4,7b Scanning electron micrgraph of booklike and vermicular kaolinite in Agbada sandstone, Robertkiri field - 3609m. 110
Figure 4.8a Scanning electron micrograph of corroded kaolinite platelets in Agbada sandstone, Meren field - 2125m.
Figure A,8b Scanning electron micrograph of diagenetic kaolinite showing a higher degree of alteration, probably altering to sfnectite (Agbada Formation, )r] ha Sooth, field - 7771m) . 111
Figure 4.9a Scanning electron micrograph of diagenetic smectite exhibiting the honeycomb structure (Agbada Formation, Makaraba field - 1999m).
Figure 4.9b Scanning electron micrograph of detrital illite shouing diagenetic growth at the edges. Agbada sandstone, Meren field - 174 4m. 112
Also, there are more free spaces in which the minerals can
develop. Therefore clays and their changes with increased
burial depth are best studied in sandstone beds where their
diagenetic phases can easily be identified.
The clays in the sandstones of the Agbada Formation are
present in both detrital and diagenetic phases. Their mineral
assemblages are broadly similar to those of the shales of the
Agbada and Akata Formations, suggesting that both sandstones
and shales of these Formations are derived from a common
source. Although it was not possible to accurately evaluate
the amounts of diagenetic clays present, visual estimations
suggest that they comprise less than 20$ of the matrix of
many sandstones. The predominant authigenic clay minerals
are kaolinites and smectites. Diagenetic illite and mixed
layer clays occur in trace amounts.
Koalinite is present in virtually all sandstones and it
exhibits both the typical polygonal book-like form and the
vermicular form (Fig. 4»7a &b). Individual platelets of
kaolinite may be as large as 30pm across and sometimes show
corroded edges (Fig. 4.8a) and alteration features (Fig. 4.8b).
Smectite is present in some sandstones and absent in
others. It exhibits a delicate honeycomb structure (Fig. 4-9a).
Illite occurs mainly in the detrital phase although many plafes show authigenic precipitation at the edges of the plates
(Fig. 4.9b and 4.10a).
Since there is an inverse relationship between the amounts
of feldspars and clays (see section 3.5), it appears that
most of the components for the neoformed clays are derived from detrital framework silicate minerals (particularly feldspar) as a result of their breakdown (Fig. 4.10b). It is possible 1 1 3
Figure 4.10a Scanning electron micrograph of initial*' stages of development of filamentose illite in „Agbada sandstone. Makaraba field - 3296m.
Figure 4.10b Photomicrograph showing alteration of feldspar to clay (Agbada Formation, 114 that at least some of the diagenetic clays are precipitated directly from the original materials dissolved in the interstitial fluids.
In terms of diagenesis, the major variations or alterations in the diagenetic clays in the sandstones of the Niger delta are the corrosion and alteration of kaolinite, the generation of mixed layers and the minor precipitation of illites. The corrosion and alteration of the edges of kaolinite plateletes indicate a variable chemistry of the pore waters. However, their limited nature and occurrence suggests that the adverse conditions were either not severe or did not operate for a sufficiently long enough time to cause major alteration of the kaolinite.
The honeycombestructure of smectite is observed to exist even at burial depths of 2,500m. Normally, this structure would have collapsed at burial depths greater than 1,000m (Osipov &
Sokolov, 1978). Their preservation at such depths in the Niger delta is due to the loose packing of grains (see section 4«5) in many sandstones. Despite the observed delicate structure of diagenetic smectite, XRD of the 2ym fraction indicate the presence of expandable mixed layer clays in many beds, suggesting that normal transformation of clays with increased burial depth does occur.
One of the most significant manifestation of clay diagenesis within the sandstones of the Agbada Formation becomes apparent when the nature of pore filling clays in the water-bearing sand- stones is compared with those in the hydro carbon-bearing ones.
The hydrocarbon-bearing sandstones contain 2-5% clay minerals whereas the water bearing sandstones have 5 - 10% clay minerals (Table 3.3). The difference in overall clay mineral content reflects the presence of diagenetic clay minerals on a 115
greater scale in the water-bearing zones compared to the
hydrocarbon-bearing zones 0f the sandstones. These
differences are similar to those previously reported in other
hydrocarbon provinces (Philipp et.al.,1963;Yurkova,1970;Sarkisyan,
1972; Wilson, 1975; Hancock, 1978 a 6 b). There are also
differences in the clay assemblages, with hydrocarbon-bearing
reservoirs containing mainly diagenetic kaolinite while the
water-bearing sandstones contain diagenetic smectite in addition
to the diagenetic kaolinite. The kaolinite shows evidence of
corrosion and instability in the presence of the alkaline
formation waters which once, filled the pore spaces. The corrosion of kaolinite combined with its abundance in the sandstones
suggests that the initial pore waters were weakly acidic to
encourage the formation of kaolinite but late£ became alkaline
causing the kaolinite to become unstable whilst encouraging the
formation of diagenetic smectite (De Segonzac, 1970). However,
the release of CC>2 during organic matter diagenesis regenerates
weakly acidic to neutral conditions which preserve kaolinite
and slow down the formation of diagenetic smectite. In addition
to the clays, other diagenetic minerals namely siderite, calcite
and pyrite are present in water-bearing sandstones but not in
hydrocarbon-bearing ones.
The smaller amounts of diagenetic clays and the predominance
of kaolinite in the hydrocarbon-bearing sandstones suggest that
diagenesis in these sandstones stopped earlier than in the
water-bearing sandstones. Diagenesis stopped in the petroleum
reservoirs because the connate waters left behind.with the
emplaced hydrocarbons do not contain a high enough concentration
of ions to sustain the production or alteration of kaolinite,
other clays and indeed any diagenetic mineral. 116
Figure 4.11 Schematic representation of a log motif in an oil sand (Agbada Formation) Okan field, in Uestern Niger delta. Also, they do not form a continuous film through which the ions can migrate and therefore permit the diagenetic alteration of the earlier formed kaolinite. A similar argument was invoked by
Webb (1974-) to explain his findings in some Cretaceous sandstones of Wyoming.
The conclusion drawn from the comparison of the level of diagenesis in hydrocarbon and non-hydrocarbon zones is that hydrocarbon emplacement occurred relatively early in this region.
This is significant in the Niger delta as it favours the generation of hydrocarbons in the Agbada shales adjacent to the reservoir sandstones (see Short & Stauble, 1967; Frankl &
Cordry, 1967; Reed, 1969; Lambert-Aikhionbare & Ibe, 1980) rather than in the Akata shales (Weber & Daukoru, 1975). The latter model requires a late generation and a late migration of the hydrocarbons which is not supported by the clay mineralogy just discussed.
The difference in the clay assemblages of water-bearing and hydrocarbon-bearing sandstones is not always as distinctive as outlined above. Prozorovich (1970) pointed out that the degree of difference in diagenetic mineral assemblage between hydrocarbon and non-hydrocarbon zones is dependent on the degree of flushing of the formation water by the incoming petroleum.
Where the flushing is incomplete and sufficient water remains to support chemical activities, formation of diagenetic minerals would continue in the hydrocarbon bearing reservoirs just as it does in the water bearing sandstones. There are examples of this in the Agbada Formation and a schematic representation of a log through such a reservoir in the Okan field, western Niger delta is shown in (Fig. 4.1l). The incompletely flushed upper part of the oil-bearing reservoir has a higher water content 118
and a lower permeability than the 'clean' completely flushed
sandstone beneath it. In the log shown the high resistivity of
the 'clean' section of the reservoir sand helped to draw
attention to the low resistivity but oil-bearing incompletely
flushed sandstone above. However, if there is incomplete
flushing throughout an oil-bearing sandstone horizon, its low
resistivity could make such a reservoir sand difficult to
differentiate from the water bearing sandstone horizon and so
potential oil-bearing formation could be missed.
There is no doubt that the clay content (detrital and
diagenetic) of the reservoir is one of the factors responsible
for incomplete flushing since it reduces porosity and permeability
and thus decreases the ability of the waters to move through
the formation. What is not immediately clear is whether the
water in the incompletely flushed zone is present as pore water
which was unable to move or as water trapped within the clay
lattice. A knowledge of the pore pressures within such
reservoirs could give an indication of which is more likely.
4.5 CEMENTATION OF AGBADA SANDSTONES
Quartzose sandstones with compositions similar to those
described for the Agbada sandstones of the Niger delta (Chapter 3)
generally possess a high content of carbonate as well as silica
cement if compaction and diagenesis have progressed normally
(Pettij ohn, 1957; Dapples, 1959; Thomson, 1-959; Heald and
Anderegg, 1960; Blatt et. al. 1972; Pettijohn et. al., 1972, Selley, 1976 and Hayes, 1979). As shown earlier in section 3.4.4
the amount of both carbonate and silica cements in the sediments
of the Niger delta are small, as a result the sandstones of
this region are poorly cemented. In the past the rapid rate of
sedimentation has been given as the major factor 119
responsible for the poorly consolidated state of these sediments.
When this factor is combined with the diagenetic history of the
sandstones of this region, the causes of their under-consolidation
may be fully explained.
From the petrological evidence outlined in section 3.4
and the observed diagenetic changes documented in section 4.2,
several reasons can be advanced for the under-consolidated nature
of the sediments of this region. Prominent among these are:
1) The poor compaction of the - sandstones which is related
to rapid sedimentation and early calcite cementation.
2) Low silica cementation which is related to the
inadequate supply of cementing materials.
3) Other processes which inhibit the precipitation of
cement in the pore spaces, even when the required
concentration of cementing materials exist in the
interstitial fluids.
4.5.1 EFFECT OF POOR COMPACTION AND EARLY CALCITE CEMENTATION
Compaction of sediments is the re-arrangement of grains to
give a tighter packing in response to overburden pressure and
it has been discussed among others by Athy, (1930 a & b);
Trask, (1931)5 Taylor (1950); Weller, (1959); Parasnis (1960);
Meade (1963; 1964); Smalley (1963); Rittenhouse,
(1971); Bull, (1973); Magara, (1968 , 1978); Chillingarian &
Wolf (1975; 1976). It is now generally regarded that this
physical aspect of diagenesis (Plumley, 1980) which causes
closer packing of grains often results in pressure solution.
Sometimes this normal compaction process is interrupted either
due to early cementation or due to inability of the sediment to
dewater. The latter situation generally results in excess pore
pressures which is however more common in argillaceous sediments. ; r.
1 20
Figure 4.12a Photomicrograph showing tangential contacts between the grains of Agbada sandstone
Figure 4.12b Photomicrograph of Agbada sandstone showing the role of calcite cement in preventing grain contact. 121
Although there is some evidence of compaction in the Niger
delta, (see section 4.2) it does not occur on the scale that
would be expected for the depth of burial recorded since grains
generally show only tangential contacts (Fig. 4.12a). The major
factor responsible for the loose packing of grains in the Niger
delta is the early calcite cementation. Rapid sedimentation
may also have played a part but its role is considered minor. If
rapid sedimentation had prevented efficient dewatering of the
sandstones of the Agbada Formation, they ought to be overpressured.
Only those sandstone beds towards the base of the Agbada
Formation•and juxtaposed across a growth fault to the overpressured
shales of the Akata Formation are known to have pressures in
excess of hydrostatic pressures (see Weber & Daukoru, 1975).
This situation is different from that in the Gulf Coast where
Dikinson, (1953) showed that the loose packing coupled with the
presence of hydrocarbon in the pore spaces resulted in excess
pressure in the reservoir sandstones.
It is difficult to decide the exact geochemical conditions
and stratigraphic level at which active calcite precipitation
occurs in the Niger delta. However, other evidence favour the
hypothesis advanced earlier (see section 3.4.4) that in the main,
calcite precipitation occurs early in the history of the
sediments. The active precipitation of calcite is presumed to
occur at the interface between the Benin and Agbada Formations.
This supposition can be supported by the following evidence.
On many seismic profiles from the Niger delta, a very
strong shallow seismic reflection occurs at about 0.8 to 1.0
seconds ( two way travel time). The depth intervals corresponding to this reflection ranges between 1,000m and 1, 500m which is roughly coincident with the boundary between the Benin and MEREN FIELD DELTA SOUTH
Figure 4.13 Seismic profiles through some ixcx^o j... - - y - - reflection ai t shallow depth(between 0.5 and 1.0 Sec.). 123
Agbada Formations as defined previously in section 2.4. The
strong reflection marks a substantial velocity contrast between
the strata. In many cases, this reflection occurs isolated with weak reflections above and below it (Fig. 4-13). The contrast in the physical properties of the sediments probably results from a decrease in porosity arising from calcite cementation. Tighter binding of the sediments increases density as well as the velocity of the transmitted sound waves. This velocity contrast is represented by the strong reflection. It is very likely that the region of the boundary between the Benin and Agbada Formations represents the only place where the sediments of this region are ever nearly completely cemented.
Further support for the suggestion that calcite precipitation is at a maximum at this level is the fact that the dissolution of quartz appears to be most intense up to 1,800m and hence its replacement by calcite (see section 3.4). Since similar pH conditions favour the solution of quartz and the precipitation of calcite, the assumption that active precipitation of calcite occured at similar depths is valid.
At the initial level of precipitation, sufficient calcite is precipitated (Fig.3.12b) to keep the grains apart. Beyond this level of active calcite precipitation, most of the calcite goes into solution and part of the C0^= thus released goes to form siderite which is more stable in the neutral to weakly acid as well as reducing conditions at depth. Thus with increasing depth in the Niger delta the amount of siderite cement increases while that of calcite decreases (Fig. 4.14). The substitution of siderite for calcite is important for a number of reasons.
Since sufficient siderite is precipitated to replace the dissolved calcite, enough cohesion is provided to prevent the collapse of the sediment under the overburden pressure. Thus the loose pack- ing of grains is still maintained. 124
INCREASING PROPORTION OF CALCITE AND SIDERITE
1,000m
JO -4— cx Calcite precipjtatfon. 2,000m
— —Siderite precipitation
3,000m
4,0 00m J
Figure 4.14 Schematic representation of siderite and calcite precipitation with increased burial depth of the Agbada Formation. 125
Where the substitution of siderite for calcite occurs in
an argillaceous sediment, the reduced porosity of the sediment
coupled with the stability of siderite under reducing conditions
results in the formation of marl horizons. These marl horizons
are fairly common in the upper part of the Agbada formation
particularly in the present-day swamp areas. XRD analysis of
a few samples of these marl horizons showed them to be made up
of dominantly sideritic marls.
4.5.2 SILICA CEMENTATION
Silica cementation is a very important process in the course
of sandstone lithification and it has been recorded in many
sandstones from various environments and localities (Heald, 1956;
Dapples, 1959; Heald & Andereg, 1960; Sippel, 1968). Because
the quartz cement frequently forms syntaxially and may lack
'dust' lines to delineate contacts between nucleus and overgrowth,
it is often difficult to determine the presence and amount of
quartz overgrowth in sandstones. The technique of cathodolumi-
niscence has been used to overcome this problem (Sippel, 1968;
Zinkernagel, 1978). The trace elements incorporated in the cores
of detrital quartz grains are largely different from and in higher
concentration than those in the overgrowths These impurities
cause the grain to luminensce red or blue whereas the overgrowths
do not luminesce or luminesce to a lesser degree.
The importance of quartz overgrowth to sandstone cementation
in general and to the destruction of porosity in particular has
led to intensive studies being undertaken in an attempt to under-
stand the process. One of the topics most intensively studied
is the source of the silica in sandstones and some of the
possibilities advanced in the literature include: l) pressure
solution (Waldschmidt, 1941); 2) hydration of volcanic glass 126
(Zen 1959; Warner, 1965); 3) decomposition of feldspars
(Fo thergill, 1955); 4) replacement of silicates by carbonates
(Walker, 1960; Blatt, 1979); 5) dissolution of the skeletons of silica secreting organisms such as diatoms, radiolaria and sponges (Siever 1957); 6) dissolution of eolian quartz abrasion dust in desert sands (Waugh , 1970); 7) precipitation from down- ward percolating ground water (Siever 1959); 8) Solubilizing effects of certain naturally occurring complex silica (Evans 1964);
9) precipitation directly from sea water (McKenzie & Gees 1971);
10) Clay mineral diagenesis, e.g. transformation of smectite to illite (Burst, 1959, Towe, 1962); and subsequent expulsion of silica rich solutions from mudstones into adjacent sandstones.
The poor silica cementation of the Agbada Formation sand- stones of the Niger delta appears to be the result of an inadequate supply of silica in solution. Petrographic observations during this study indicate that the major processes likely to supply silica to the interstit ial fluids of the Niger delta are l) normal solubility of quartz,2) replacement of quartz by carbonate,
3) alteration of clays during diagenesis, 4) pressure solution,
5) alteration of other silicates. If other sources of cementing materials are present, they occur in such minor amounts and on a local basis that their contribution is considered insignificant, i) Normal Solubility of Quartz: The solubility of quartz
in water under various conditions has been discussed
among others by Siever, (1959); Thomson, (1959), Krauskopf
(1959; 1967); Margolis, (1968) and Wilson (1978; 1979).
Until recently, it was generally accepted that strongly
alkaline solutions (pH >9) are more favourable to the
dissolution of quartz, and that the amount of silica 127
Figure 4.15 Scanning electron micrograph of U-shaped etch pit characteristic of alkaline origin. Agbada Formation, Meren field 1744m. 128
going into solution is dependent on the temperature and other
factors. However, Margolis (1968) and Wilson, (1978) have
shown that acidic solutions could dissolve quartz. Wilson
(1978; 1979 in an attempt to develop etch pits on the quartz
grains of the Millstone grit, used solutions from peat beds
(pH 3.15-3.2). Before this, other attempts to simulate etch
pits in the laboratory have used chemical reagents such as
hydrofluoric acid (HF) or . sodium hydroxide (NaOH) solutions
(Margolis, 1968; Schneider, 1970; Bond & Fernandes, 1974; and
Subramanian, 1975). The conclusion reached on the above experi-
ments have demonstrated that both acidic and basic solutions
can dissolve quartz. Although the emphasis in these experiments
has been on the pH of the solutions, Siever, (1959) and
Friedman et. al., (1976) have shown that biological factors are
also important particularly in surface waters.
The work of Wilson, (1979) represents the first attempt to
dissolve quartz using natural solutions. The fact that he used
peat water is particularly important in terms of the Niger delta
where the upper part of the Agbada Formation and parts of the
Benin Formation are known to contain peat and lignite beds
(Weber & Daukoru 1975). However, it is doubtful if these beds
produce strongly acidic solution in the presence of C0^=ions,
because the pH of the interstitial solution in the Agbada
Formation varies between 6 and 9. There is little doubt there-
fore that the etch pits on grains of this region were developed
by alkaline fluids. The v-shape of some of the etch pits observed
(Fig. 4.15) are similar to those described by Subramanian,
(1975 and Wilson (1979) as due to NaOH solution. As stated
in section 3.4, the solubility of quartz (in this region) was
most intense at depths shallower than 1,800m where the high pH
of the formation also favoured calcite precipitation. 129
Figure 4.16 Diagrammatic representation of silica solubility with variation in pH. (After Alexander et. al. , 1954). 1 30
TABLE 4.1, PH MEASUREMENTS FOR PORE WATERS OF SOME
AGBADA SANDSTONE
FIELD DEPTH pH
(in meters )
MEREN E-5 6.8
E.5 6.5
G-2 7.2
G.3 8.5
H-5 8.6
OBIAFU 3565 9.5
3626 9-5
3794 8.5
3896 7.5
1254 6.6
1576 6.8
2205 6.5
2550 7.8
3115 8.5
3335 7.2
DELTA SOUTH 1551 7.5
1834 6.5
2354 8.5
3207 9.2 1 31
The amount of silica in solution in formation water due to
the normal solubility of quartz is estimated between 10-60 ppm
(Dapples, 1959; Krauskopf, 1959; 1967) below pH values of 9 and
ma.y vary depending on temperature and type of silica. Above
pH 9 the solubility of silica increases dramatically (Fig. 4-16).
The pH values of a few water samples obtained from producing
reservoirs in the Niger delta range between 6 & 7 at shallower
depths to 7 & 9 at greater depths (Table 4.1). Therefore, if
pH is used as a major criterion for the solubility of quartz,
silica concentration in formation water should not exceed 60ppm.
In the Niger delta however, the total concentration of silica
from all sources in the Agbada Formation varies between 20 & 30ppm
which is within the range expected for normal solubility alone.
It would therefore, appear that the silica supplied by this
process is small since it contributes only a fraction of what
is available. ii) Replacement of Quartz by Carbonate: Walker (1960) suggested
the replacement of quartz by calcite and/or other carbonates as
a source of silica in solution. Evidence of the occurrence of
this phenomenon has been documented by Walker (1962) and
Friedman et. al. (1976). The replacement usually takes the
form of corrosion and replacement of quartz edges by calcite.
Velde (1981 pers. comm) suggests that this replacement probably
occurs as a result of formation of complex compounds between the
SiO^ and C0^=. Therefore, the more C0^= available the more
SiO^ will dissolve since more is needed to form the complex
compounds. Siever (1957) and Kashik (1965) have estimated that
a pH value of 9.8 is most favourable to this reaction although
Kashik (ibid) also showed that it could occur in environments
with pH value as low as 4- At the optimum pH of 9.8 the field
of replacement widens considerably because of the increase in the
solubility of quartz and the decrease in the solubility of 1 32
calcite (Fig. 4.17). Temperature and other factors may affect
this reaction but pH is considered most significant, because
variations in pH value especially around pH 9 have a more marked
effect than variation in temperature at shallow depths of burial
Calcite replacement of quartz has been observed in the
Niger delta but it is by no means widespread (see section 3.4).
The extent of replacement is variable even in the same thin
section (compare Fig. 3.4b and Fig. 3.12b). Although rare cases
of replacement of entire grains may occur, it is doubtful if
this process contributed an appreciable amount of silica to the
interstitial fluids of the Niger delta, iii) Alteration of Clays during Diagenesis: The diagenesis of clays
in both sandstone and shale beds of the Agbada Formation as well
as those of the shales of the Akata Formation have been discussed
in section 4.3 and 4-4. The conclusion reached was that the
amount of clay transformation with burial depth in the Niger
delta is relatively low. However, due to the normal compaction
of the shales of the Agbada Formation, they show a higher level
of clay transformation than the overpressured shales of the Akata
Formation. Considering this low level of transformation, it is
doubtful if this process contributed a significant amount of
silica to the pore waters of this region,
iv) Transformation of Feldspars: The inverse relationship of the
feldspar and clay content of the sediments of the Agbada Formation
(see section 3.5) has been interpreted as the evidence of
diagenetic formation of clays from feldspars. Blatt, (1979);
and Hower, (1981) have shown that silica is released as a bye-
product of this reaction, 1 33
. . . 1 i 2 A 6 8 10 12
Figure 4.1
Figure 4.17 Diagrammatic representation of the field of replacement of quartz by calcite at 25°C and one atmosphere. (After Kashik 1965). 1 34
However, the low content of feldspars and clays in these sedi-
ments indicate that the amount of silica supplied by this process
will be small. v) Pressure Solution: Many investigators (see Blatt et. al., 1972
p. 359 - 360 and Pettijohn et.al., 1972 p. 4-24- - 426, for recent
reviews) have considered intergranular pressure solution as a
major mechanism of porosity reduction in quartz arenites.
Consequently, efforts have been made (see, Thomson, 1959;
Siever, 1959; Dipples, 1959; Weyl, 1959, Sippel, 1968; Trurnit,
1968; Sibley & Blatt, 1976; Robin, 1978 and Land & Dutton, 1978
to name a few) to quantitatively evaluate the importance of this
process.
Intergranular pressure solution may result in a reduction
of porosity due either to solution and repacking and/or due to
the precipitation of silica derived from the dissolution of grains.
Rittenhouse (1971) and Manus & Coogan (1974) determined the
effects of pressure solution on porosity by reference to simple
geometric models. While their approach may not exactly represent
the packing of natural sand grains, Sibley & Blatt, (1976)
agree that the assumption of orthorhombic packing of grains best
approaches the natural situation. Sibley & Blatt, (1976) working
on this assumptinn, estimated that pressure solution contributed
about 1/3 of the silica required for quartz cementation of the
Tuscarora Formation (Silurian) U.S.A. Blatt (1979) also
estimated that pressure solution contributed about 1/3 of the
silica required for quartz cementation. However, workers like
Deelman, (1975) argue that pressure solution does not form an
essential factor in quartz cementation. 1 35
Figure 4.18 Photomicrograph of Agbada sandstone showing long grain contacts. 1 36
In the Niger delta, examples of pressure solution are few.
Most of the contacts between grain are tangential (Fig. 4.12a)
with a few long or extended contacts (Fig. 4.18). The areas
that show long grain contacts generally lack any form of
precipitated quartz or carbonate cements. It. is possible that a
cement was never deposited in such areas or if deposited, it
was dissolved out and not replaced, thus causing the sediment
to collapse. During the examination and point counting of 30
thin sections of the sandstones of The Agbada Formation, no
evidence of pressure solution (sutured contacts and development
of stylolites) was recorded. Although it was therefore not
possible to quantitatively estimate pressure solution in this
study, it is clear from thin section studies that it affected
only a small proportion of the grains. This conclusion of low
pressure solution is supported by the results of Nagtegaal(1978).
Considering the importance of pressure solution to the cementa-
tion of other sandstones (Heald, 1956; Thomson, 1959; Sibley
& Blatt, 1976; Land & Dutton, 1978), its near absence in the
sediments of the Niger delta is therefore an important factor in
their under-consolidation.
The factors that could inhibit pressure solution in the
Niger delta include a) presence of a thick clay and/or matrix
coating around grains b) Loose packing due to early calcite
cement c) Flushing of formation fluid by hydrocarbons, a) Clay Coating: Many of the detrital grains in the Niger delta
are coated with a film of clay (Fig. 3-7a & b). This film is
both detrital and diagenetic. The importance of clay to the
process of pressure solution has been discussed by Heald
(1956; 1965); Siever (1959); Thomson (1959) ; Weyl (1959);
Hawkins (1972); Heald & Larese (1974); Pittman & Lumsden (1968). 1 37
Among the explanations advanced are those of Thomson (1959) who
claims that clay enhances pressure solution by changing the
pH of the micro environment, and Weyl, (1959) who stated that
the presence of clay facilitates the diffusion of the dissolved
silica. However, these explanations are only thought to be valid
if the clay coating is thin (Heald, 1956; 1965). Pittman &
Lumsden, (1968) and Heald & Larese, (1974) have shown that where
the clay rim is thick, (as is the case in the Niger delta
(Fig. 3.6b), overgrowth formation as well as pressure solution
may be inhibited. This deduction is consistent with the
correlation found between clay coating and overgrowth formation
discussed in section 3.2.2. Nucleation of the overgrowth on
detrital silica grain surfaces is prevented by the clay coating.
Similarly, without actual contacts between adjacent quartz grains,
pressure solution is unlikely to occur and no silica will be
provided to the pore waters from this source .
b) Early Calcite Cementation: The early precipitation of calcite
at shallow depth has been established (see section 3-4.4 and 4-5).
Siever, (1959) and Pettijohn, (1975) explained that poikilitic
cement texture is possible if precipitation occurred at a time
when the sediments were still largely incoherent and the grains
could be easily pushed apart by the force of crystallisation.
By keeping the grains apart, the early calcite cement and subse- -
quent siderite replacement prevent pressure solution. c) Flushing of Formation Water: The importance of water to the
process of pressure solution is borne out by the statement of
De Boer et.al.(l977p.257)experiments reveal that when samples
have undergone some consolidation, the presence of water is
essential for continuation of the compaction process.' 1 38 TABLE 4.2 ION CONCENTRATION (IN PPM) OF SOME FORMATION, WATERS ' FROM .HYDROCARBON. RESERVOIRS OF THE AGBADA FORMATION
DELTA/ MEREN/ PARABE/ OBIAFU/ DELTA SOUTH/ ELEMENTS 1800m 2200m 1900m 3600m 2500m
Na 4007 4297 8724 8437 10850
K 34.80 34.45 110.8 95.80 108.2
Mg 7.67 5.45 7.73 5 25
Ca 8. 52 3.01 23.83 18 93
Sr 1.76 1.03 2.40 2 3
Ba 0.46 0.45 0.06 0.5 0.5
Al <0.25 <0.25 <0.25 <0.25 <0.25
Cr <0.05 <0. 05 <0.05 <0.05 <0.05
Mil <0.04 <0.04 <0. 04 <0.04 <0.04
Fe <0.2 <0.2 <0.2 <0.2 <0.2
Ni <0.15 <0.15 <0.15 <0.15 <0.15
Cu <0.25 <0.25 <0.25 <0.25 <0,25
Pb <0.25 <0.25 <0.25 <0.25 <0.25
S 29.25 49.24 42.97 35.Q '33.54
B 44.51 31.27 31.98 28.0 36.08
Si 32.55 26.68 21i45 25.43 22.62
Li 0.26 0.23 0.26 0.25 0.25
La 0.09 0.10 0.12 0.11 0.11
Ti 0.04 0.03 0.24 0.20 0.08
P 3.68 3.77 3.86 3.59 3.68 1 39
The loss of formation fluid (NaCL solution) in their experiment
resulted in a stoppage of further mechanical compaction, since
migration of SiO^ away from the area of dissolution (high silica
concentration) of quartz stopped. High silica concentration
around grains inhibits further solution of quartz, thus prevent-
ing the development of pressure solution.
The displacement of formation water by incoming hydrocarbons
into the reservoirs of the Niger delta can be likened to the
situation in the experiment of De Boer et. al. (1977). The low level of compaction and cementation in many of the reservoirs of
the Niger delta is therefore also aided by an early flushing of
the formation water by the incoming hydrocarbons. Other factors
such as the amount and type of clay minerals present in the hydro-
carbon reservoirs (see section 4.4»l) are also in favour of
early migration of hydrocarbons into these reservoirs.
From the preceeding discussion, it can be concluded that pressure solution may have contributed only a small amount of
silica to the pore waters of the Niger delta. Of the several
sources of silica evaluated in this study, none has been confirmed as a substantial source of silica for cementation. The low level of quartz overgrowth development observed during this study is a confirmation of this.
The results of the few water analysis available have shown
that the concentration of silica in the formation water is between 20 and 30 ppm (Table 4.2). Although this is within the expected range of silica concentration in surface and shallow ground waters, it is much lower than the critical concen- tration of between 100 - 2Q0ppm suggested by Krauskopf, (1967) and Lahan, (1980) as being necessary to precipitate quartz. 140
SEDIMENTATIO N
SOLUTION OF SHELLS DIAGENETIC KAOL. FORMED
SUDDEN INC REASE IN pH V DUE TO THE PO RE
WATE RS OF AG BAD A F ORMA TION DISSOLUTION OF QUA RTZ
KAOL. UNSTABLE Ca C 0
DIAGENETIC SMECTITE INPUT OF C02 FORMED FROM ORGANIC
MATTER DIAGENESIS
CALCITE DISSOLVES
MIXED LAY E R S I L L - S M E C. FORMED LOWER pH AND
KAOL. STABL.E HIGHER Eh SECONDARY SILICA PPT. SIDERITE FORMED
F e C 0 3
SULPHIDE FROM
BREAK 0 OW N OF
ILLITE FORMED SULPHATES
>1/
Fe S
Figure 4.19 Diagrammatic representation of the sequence of precipitation of minerals with increased burial depth of the Agbada Formation. 1 30
Although the concentration of 20-30ppm represents that of the present formation water, the low level of overgrowth development in the sediments suggests that concentrations were similarly low in the past.
PARAGENESIS OF MINERALS
Determining the sequence of formation of diagenetic minerals is often not straight forward because the minerals are hardly ever found in close association with one another. The problem in further complicated in the Niger delta by the friable nature of the sandstones which in many cases prevents preparation of satisfactory thin sections. The relationships between minerals are best studied in thin sections where it is possible to examine relatively large areas at the same time. The SEM is a useful tool once petrographic relationships have been established as it involves the examination of only minute areas within which it is often difficult to find minerals in close proximity for direct examination of phase relationships.
The sequence of formation of minerals that has been worked out for the sediments of the Niger delta is shown in (Fig. 4.19)
Kaolinite is one of the earliest formed minerals at shallow depths when conditions were largely weakly acidic. This situation is particularly true of the eastern section of the delta where the sediments contain a high amount of feldspars which could be transformed and provide components for the formation of clays.
Calcite precipitation followed soon after with precipitation occurring at the boundary between the Benin and Agbada Formations
(see section 3.4.4 & 4»5) and also close to the surface of deposition. Corrosion and alteration of kaolinite and the preci- pitation of diagenetic smectite probably started at 142
Figure 4.20 Scanning electron micrograph showing the relationship between kaolinite and guartz overgrowth in Agbada sandstone. Olure field - 30 37m. 1 43 this time when pH may have been as high as 8 or 9. Conditions favourable to the dissolution of quartz and replacement by
calcite also occurred at this time, thereby releasing silica to the pore waters and aiding the formation of smectite as the trans- formation of kaolinite to smectite requires additional SiO^.
With increased burial, catagenesis of organic matter sets in and the CO^ released during this process dissolves in the pore waters to produce weak acids. This solution dissolves most of the calcite which is rapidly replaced by siderite in some beds.
The Eh of the environment at depths also favours the precipita- tion of siderite in preference to calcite. As explained in section 4.5.2. "the pH of the pore waters of the Agbada Formation range between 6 and 8.5 in the upper section of the formation.
This, combined with the low Eh probably favours the precipitation of siderite rather than calcite.
The precipitation of quartz overgrowths possibly occurred simultaneously as the precipitation of siderite or may be earlier.
Prior to the dissolution of quartz at the boundary between the
Benin and the Agbada Formations, it is doubtful -if a high enough concentration of silica existed in the pore waters to allow the precipitation of quartz overgrowths. However, where quartz over- growths are found juxtaposed to kaolinite (Fig. 4.20) it is observed to overgrow kaolinite. This confirms the late precipita- tion of quartz overgrowths relative to kaolinite. It may also indicate that there probably was a second phase of kaolinite precipitation.
Precipitation of pyrite is the latest event and occurred
with the generation of H2S as a result of the reduction of sulphate ions in the pore waters. This reduction is probably the result of inorganic reactions between the sulphate and hydrocarbons
(see Goldhabor & Kaplan, 1974; Rickard, 1975; Berner, 1980).
2CH2q + S0^-> H2S + 2HCO3- 144
The H^S thus formed reacts with iron in solution to produce the
pyrite.
As explained in section 3.4 the materials for the precipita-
tion of gypsum were introduced to the pore water during drilling.
Therefore, their time of formation is of little relevance to
this section.
This simple suite of diagenetic minerals and the amount and
nature of each mineral suggest that the sediments have had a
simple diagenetic history.
4.7 THE EFFECTS OF DIAGENESIS ON THE POROSITY
AND PERMEABILITY OF- AGBADA SANDSTONES
The effects of diagenesis, compaction, cementation and
mineral alteration in sandstones is to generally reduce porosity.
However, Proshlyakov, (1960) recognised that diagenesis could
also cause regeneration of porosity (secondary porosity) in
sandstones. Secondary porosity in sandstones which in its simplest
terms can be described as the generation of post depositional pores, can be generated by epidiagenesis (Selley, 1976), decarbonati-
•zation (Schmidt & McDonald-, 1979; Hayes, 1979; Pittman 1979)
and by fracturing of grains or formations. Secondary porosity
is important in a reservoir in that its generation can transform
an otherwise uneconomic reservoir, into an . exploitable and
profitable venture. For this reason, more attention is now
generally devoted to understanding secondary porosity.
Epidiagenesis, one of the factors responsible for generation
of secondary porosity requires that the sediment be close to the
surface so as to come under the influence of percolating
meteoric water. Although this may be important, in many areas of
the world, it is insignificant in the Niger delta where deposition
has continued with increased burial, almost uninterrupted since
Eocene times. 145
Dissolution of carbonate cement (decarbonitization) is a popularly accepted method for generating secondary porosity in sandstones and it is most important in the Niger delta.
Schmidt and McDonald, (1979) and Hayes", (1979) postulated that
CO^ produced during organic matter diagenesis in adjacent strata dissolves in water to yield carbonic acid.
++ CaCO^ + C02 + H20 ^ Ca + 2HC03-
This acid dissolves the carbonate minerals and either recreates primary pore spaces or generates new ones. Dissolution or alteration of other minerals such as feldspars and sulphates could also lead to the production of secondary porosity
(Rowsell & De Swardt, 197.4 ; Schmidt et. al.,1977 ; and
Lindquist, 1976).
The characteristics and criteria for recognition of second- ary porosity have been discussed among others by Phipps (1969);
Morgan & Gordon (1970); Hayes (1973); Heald & Larese (1973);
Schmidt et.al. (1977); Schmidt & McDonald (1979 a & b);
Pittman (1977; 1979); and Hayes (1979). They all agree that porosity in many petroleum reservoirs is secondary and that this generally mimics primary intergranular porosity. Also
Starton & McBride (1976); Starton (1977); McBride (1977); and Lindquist (1976; 1977) working on the Tertiary sandstones of the Gulf Coast recognised and pointed out the importance of secondary porosity in that region.
Secondary porosity whether formed early or late can be destroyed but this would probably be at a slower rate than primary porosity because initial compaction will have taken place and later compaction is of less importance. Schmidt &
McDonald (1979 AAPG course manual) have suggested that the 146 development of secondary porosity almost always precedes emplace- ment of hydrocarbons into the reservoirs. This observation is important and it holds true for the Niger delta.
The discussion of the diagenesis of the Agbada Formation have shown that both physical diagenesis (compaction) and chemical diagenesis (cementation, alteration and dissolution) have each not reached very advanced stages in the Niger delta.
The sum total of the events is that compared with sandstones of similar characteristics in the Gulf Coast (Heald, 1956; Burst,1969;
Al-Shaieb et. al. 1980)those of the Agbada Formation possess higher porosities. The high porosities of these sandstones largely result from the development of secondary porosity by dissolution
of the early precipitated calcite. Log derived porosities for
the Niger delta (Table 4.3) show that porosities of 25 - 30$ are common at burial depths of 2745m - 3050m. Pryor, (1973) has
shown that modern beach and channel sands similar to those
that may have given rise to the sandstones of the Niger delta
possess initial depositional porosities of 40 - 50$. If would
therefore, appear that only a small ultimate reduction in porosities
has taken place in the•sediments of the Agbada Formation.
Rittenhouse, (1971) and Manus & Cogan, (1974) have pointed out
that the amount of bulk volume reduction that takes place in a
rock is proportional to the initial porosity. If the present
porosities of the Agbada sandstones at their present depth of
burial are regarded to have been derived through normal dis.gene-
sis, then their initial porosities following the calculations of
Rittenhouse (1971) and Manus & Cogan (1974) will be much higher
than the 40 - 50$ measured by Pryor (1973). Since this is
highly unlikely, it is concluded that the rate of destruction 147 TABLE 4»3 LOG DERIVED AVERAGE POROSITIES OF SOME SANDSTONES OF THE AGBADA FORMATION
APPROXIMATE FIELD POROSITY ROUNDED DEPT IN METERS OFF TO NEAREST 5%
MEREN 1550 - 1650 29 - 35
1660 - 1750 15 - 45
1800 - 1900 15 - 35
2000 - 2500 20 - 35
2600 - 3500 15 - 35
UTONNANA 1900 - 1950 20 - 35
OKAN 1500 - 1600 20 - 35
1700 - 1800 20 - 30
1900 - 2500 25 • 35
3000 - 3500 20 - 30
OLURE 1500 - 2000 20 - 35
2100 - 2500 20 -- 30
2600 - 3000 15 -- 30
3100 - 3500 20 -- 30
DELTA SOUTH 1500 -- 2000 15 -- 30
2100 -• 2500 20 -- 30
2600 -• 3000 15 -- 35
MAKARABA 1500 - 2000 25 - 40
2100 - 2500 15 - 30
2600 - 3500 15 - 35
ROBERTKIRI 1500 - 2000 25 - 45
2100 - 2500 20 - 35
2600 - 3500 15 - 35
OYOT 1500 - 2000 15 - 35
2100 - 2500 20 - 30
OPOLO 1500 - 2000 20 - 35
2100 - 2700 15 - 30 148 of porosity due to diagenesis is about equal to the rate of generation of secondary porosity by dissolution of carbonate cement.
The high porosities of the Agbada sandstones of the Niger delta, coupled with their poor grain packing and high matrix content, results in the movement of the very fine matrix materials('fines') within the formation. These fines are carried up to the surface with the crude oil from many reservoirs. Their
movement within the reservoirs occur to varying degrees in different areas of the delta and is a major engineering problem in the Niger delta. Yet in terms of reservoir geology the production of fines with the crude from reservoirs is desirable since it helps to maintain permeability within the reservoir.
Neasham, (1978) has concluded that due to the discrete morphology of kaolinite within the pores, it may not grossly affect the overall porosity of reservoirs. But Todd, Tweedie and
English, (1978); Keir, Baaren & Brown, (1978) and Muecke, (1979) have pointed out that kaolinite platelets often defluocculate during fluid movement in the reservoirs and migrate to block critical throat passages, thereby reducing permeability. However, this problem does not occur in hydrocarbon reservoirs of the Niger delta where the fines in the reservoirs (Fig. 21a) are brought to the surface with the crude oil. This helps to clear some of the critical throat passages and therefore allows the floating kaolinite to be produced at the surface as well. XRD analysis of the produced fines from some reservoirs in the Okan, Parabe and
Delta South fields show that the fines compose of mainly quartz with minor amounts of kaolinite. Thus only very few throat passages may be blocked in hydrocarbon reservoirs and permeability loss is minimised. 1
Figure 4.21a Scanni ng electron micrograph of a pore
space sho~in g the n umerou s f ine particles and the almost total absence of cementing materials. Agbada Formation, Idama fiel d - 2915m.
Figure 4.71b Scanning electron micrograph sho~ing the reaction of a shale lamina t o the drilling fluid.
r~ohada Formation, Olure fieJ d - 1827m. 150
However, in the non-petroleum reservoirs, the situation is different. The increased content of clay and other diagenetic minerals as well as the increased shale laminae act as barriers to the movement of these 'fines' within the formation.
Thus, permeability reduction due to floating kaolinite platelets may become important in the water saturated sandstones. This could present a major problem in enhanced recovery operations.
In water injection projects, water is generally introduced throug down dip wells with the hope that the excess pressure thus generated will result in the up dip movement of the hydrocarbon water interface, -thus reducing the pressure depletion at the producing well. The 'fines' moving within the formation in the downdip well stand very little change- of being removed from the formation. These fines will therefore- most probably pile up against .the critical throat passages, thus reducing permeability and preventing the excess pressure effect from reaching the producing wells.
The problem is further complicated in the water zone by the reduced porosity due to the higher amounts of diagenetic minerals
In many of these water zones, the proportion of smectite is significant when compared with petroleum zones. Depending on the fluid being injected, these clays may react with the introduc water and swell (Fig. 4.21b),. th ereby increasing permeability los and causing formation damage.
The above facts demonstrate the need to consider each reservoir of the Niger delta as a separate entity. • The need for a detailed study of reservoirs before an enhanced recovery program is attempted in the Niger delta cannot be overstressed. 1 51
Figure 4.22 Photomicrograph of drilling mud cake left behind in the pore space due to high porosity porosity and permeability. 152
Also, in terms of efficient flushing of the hydrocarbon through the reservoir, the high porosities of the Agbada sand- stones could present another engineering problem. There is a high probability that crude oil can be by passed in the pore space if production rates are not carefully determined. Evidence of drilling mud left behind in the pore space is shown in (Fig. 4.22) 153
GxiAFTER 5
SOURCE ROCK EVALUATION OF SHALES OF THE AGBADA FORMATION
5.1 INTRODUCTION According to Dott & Reynolds (1969), the question of source beds of petroleum is perhaps one of the most controversial topics in petroleum geology. It is hardly surprising therefore that with nearly 4-0 years of active exploration and 25 years of production, the source of the petroleum of the Niger delta is still a matter of contro- versy. The problem is made more complex in this area by the fact that the numerous growth faults, in the province, are thought to provide effective pathways for petroleum migration from the presumed Akata shale sources to the reservoir sands of the overlying Agbada Formation. Until recently this idea has been given so much prominence that very little effort has been made to investigate alternative sources.
To date three schools of thought exist on this subject. The earliest view proposed by Short & Stauble (1967) and supported by Frankl & Cordry (1967) and Reed (1969) concluded on the basis of stratigraphical, sedimentological and petroleum geological considerations that the hydrocarbons of this province are generated within the paralic shales of the Agbada Formation adjacent to the reservoirs. Their main evidence is :- a) the lateral and vertical variation in crude properties within and between fields in the Niger delta, b) the short migration history of the hydrocarbons and c) the wax content of the crudes. 154
The second view, proposed by Weber & Daukoru (1975) and supported by Weber et. al. (1978) and Fisher (1979 unpublished Ph.D Thesis) is that the shales of the Agbada Formation interbedded with the reservoirs are immature and so could not have released hydrocarbons to the reservoirs. These authors suggest that the deeply buried Akata shales are the major sources of hydrocarbons in the delta and that the hydrocarbons generated in these shales migrate upwards via the numerous growth faults into the reservoirs of the Agbada Formation. Unfortunately, the major support for this theory is to be found in unpublished geochemical data in company internal reports.
While generally supporting this second hypothesis, Evamy et. al. (1978); Ekweozor et. al.(1979) and Ekweozor and Okoye (1980) modified it and took a middle stand in proposing that both the Akata shales and the deeply buried sections of the Agbada Formation provide hydrocarbons to the reservoirs. The network of growth faults was again advanced as the major migration pathway. Evamy et. al. (1978) in their paper supported their stand by geochemical data but concluded using other geological considerations that the thick shale columns (Akata shales) below the "oil kitchen" sto.od little chance of sourcing the reservoirs above them. On the other hand, Ekweozor et. al.(op. cit-), and Ekweozor and Okoye (1980) based their conclusions on geochemical data alone. I
155
The hypothesis being advanced in this thesis based on
the geochemical and other geological eivdence presented below
is largely similar to that of the third school. However,
it argues that the major source of hydrocarbons in this
province is the Agbada Formation and that the contribution
from the Akata shales if any, is comparatively minor. The
Agbada Formation is here defined (see section 2.4.3) as that
section between the base of the high resistivity fresh water
and the top of the over-pressure shale. In addition, this
proposal does not accept the conclusion of Ekweozor and Okoye
(198 0) that any shale shallower than 2900m (in offshore
areas) and 3 500m (in onshore areas) does not stand a chance
as a source bed. Both geochemical data as well as other
geological considerations are cited to support the present
proposal.
5.2 METHOD OF STUDY
Only shale and silt samples were used in this part of the
study. As in the case of the Petrologic and diagenetic
studies in chapters 3 and 4 of this thesis, sidewall cores
(SWC) form the major source of materials used. The samples
(37 from the Agbada shales and 4 from the Akata shales - see
appendix) were taken from a few wells mainly concentrated in
the western Niger delta (Fig. 3.1). As far as was possible,
samples were selected to represent various environments of
deposition both laterally and vertically. The shallow nature
of many wells from the Niger delta made any comprehensive
study of the transformation of organic matter with depth in one
well almost impossible. 156
5.2.1 SAMPLE PREPARATION
a) PULVERISATION: For whole rock analysis about 5 - 8gms.
of sample was pulverised in an agate mortar (using a Tema mill) until all the material was fine enough to pass through the 75um sieve. This procedure is necessary to ensure that all disseminated organic matter is included and distributed evenly within the powder for analysis.
Contamination was prevented by washing the mortar thoroughly with distilled water and drying it after each grinding operation. The pulverised samples were used for whole rock elemental analysis.
b) MACERATION: One of the steps in the study of organic matter is to isolate the kerogen (which for the purpose of this study is defined as the acid insoluble organic matter) from the rocks in such a way that its nature is not significantly affected. Although several methods exist
for kerogen isolation,the acid treatment method of remov- ing inorganic minerals (Down, 1939; Dancy 1948; Forsman & Hunt, 1958; Mclver, 1967; and Durand, 1980) was used in this study. The rock was first crushed,using an iron mortar and pestle,to an average grain size close to 1mm to accelerate the reactions with acids. About 15 - 30gms. (depending on initial sample size) of each crushed sample was treated with 10$ Hydrochloric acid (HOI) to remove calcareous matter. Frankenberg and Giles (1970) noted that 10$ HC1 generally decreased the total carbon content of samples and therefore recommended 5$ HC1. Considering the fact that 157
Frankenberg & Giles(ibid) worked on recent Carbonate samples, plus the fact that the present samples are relatively high in carbon content (l - 3%), the effect of such a decrease on the total organic carbon content was thought to be low and therefore insignificant. Moreover a lot of time will be required for the removal of the calcareous matter using 5% HC1,
At least two HC1 treatments were made to ensure total dissolution of all carbonates. It is imperative that all carbonates be removed particularly calcium carbonate which if present could form insoluble calcium flouride CaF^ when the sample is treated with Hydrofluoric acid (HF). After carefully decanting the HC1 and washing off the excess acid with distilled water, the samples were treated with 60$ Hydrofluoric acid (HF) to dissolve quartz and all the silicate minerals. The samples were stirred at intervals and fresh HF added every 24 hours (after decanting the previous aliquot of acid) until all the silicate minerals were destroyed. When fully digested, the acid was decanted and the samples washed in distilled water until they were neutral to standard laboratory blue litmus paper. At the end of this process, the kerogen would normally contain some heavy minerals (like pyrite & zircon) which are non-reactive with the acids. These were then removed from the organic matter by density separation using heavy liquids such as zinc bromide. In this study, zinc bromide solution with a density of approxi- mately 2.2gm/l was used employing the method of 158
Kinghorn & Rahman (1980). The separation was achieved by spinning the sample tube in a centrifuge for 20 minutes at approximately 2,000rpm. The float from this separation which to all intents and purposes should be mineral free was decanted and washed first with 5% HCl and then with water to remove zinc bromide.
Finally the kerogen was separated into heavier and lighter fractions using a zinc bromide solution with an approximate density of 1.44-gm/l. According to Kinghorn & Rahman (1980), organic fractions lighter than 1.44gm/l should be generally free of reworked materials and contain a high concentration of Palynomorphs. This is due to the fact that syndepositional organic matter which have not been subjected to intense chemical changes are lighter than reworked materials. Such a fraction is desirable for optical studies of the organic matter.
Separate slides were prepared of the lighter and heavier organic fractions for optical studies, after which the two fractions were mixed and a slide of total kerogen content prepared. The mixed sample was also used for pyrolysis study. All samples were mounted in glycerine and the ends of the cover slips sealed with commercial nail varnish to
prevent either the dessication of the samples 0r "the absorptior
of water by glycerine. In this way both kerogen and glycerine
could be preserved indefinitely unless the seal breaks. 159
5.2.2 GEOCHEMICAL ANALYTICAL TECHNIQUES
The geochemical analytical methods employed in this study were limited to those available at Imperial College of Science and Technology, London, and then restricted only to the determination of organic matter type, amount and level of maturation. Both optical as well as chemical methods were employed in this study. Although certain techniques are common to many of the parameters,this discu- ssion is presented such that methods directed at evaluating particular parameters are grouped together.
In view of the importance of the type and amount of organic matter (OM) to the evaluation of source potential, the study started by determining the type and amount of organic matter in the Niger delta shales. Optical and chemical methods are available for the determination of organic matter type. The optical methods which were inherited from coal petrography (Gransch & Eisma, 1970; Dow, 1977; Peters et.al.,1977; and Tissot 6 Welte, 1978) utilise the fluorescence, transmittance and reflectance properties of the organic matter to determine the type. While at least two of these properties must be used in order to obtain a reliable evaluation, any of the optical properties can also be combined with any of the chemical data to obtain a reliable evaluation. This type of combi- nation was employed in this study. Optical examination of the concentrated kerogen was undertaken with a view to 160
Atomic ratio ^
Type I' Green River shales (Pal. - Eoc . J
Typ e I Algal kerogen
Type II Lower Toarcian shale
Silurian shales Type II
Type II Various oil shales
Type III Upper Cret. shales Type III Lower Mannville shales
Figure 5.1 The Uan Krevelen diagram for determining the type of organic matter. (From Tissot and Uelte 1978) 161
identifying some of the organic matter grains. The chemical methods utilise the quantities of the elemental chemical components of organic matter, which include the carbon (C), Hydrogen (H), Oxygen (0), and Nitrogen (N), to determine its type. The ratio of the quantities of atomic hydrogen to carbon (H/C) can be plotted against the ratio of atomic oxygen to carbon (0/C) on a Van Krevelen diagram (Fig. 5.1) to determine both the type and evolution path of the kerogen. Alternatively, the hydrogen content and the ratio of the atomic hydrogen to carbon H/C can be used to characterise the organic matter type (Laplante, 1974; and Maximov et. al., 1975) These two chemical methods were combined with the optical method above to determine the type of organic matter.
In each case, samples for analysis were weighed in special platinum boats in a micro balance, 3mg (whole rock) and lmg (kerogen) of sample was used for analysis. The samples for whole rock analysis were first treated with a few drops of 5$ HC1 to remove any carbonate carbon that may be present. The use of 5% HC1 in this case was delibera Unlike the situation in maceration, only a small sample was being treated this time and the use of a strong acid may result in a spillage of some of the samples by strong effervescence. In addition to this the acid was not dis- carded ( as was the case in maceration) but evaporated to dryness at 50°C. Roberts et. al. (1973) observed that low organic carbon values for carbonate sediments resulted either from treatment with strong acids and/or discarding 162
of filtrate. The present writer agrees with this view and considers that their observation is equally relevant to calcareous samples such as those in this study. It was not necessary to treat the kerogen samples with 5$ HC1 because they had been subjected to 10$ HC1 as well as 60$ HF. Any inorganic carbonate carbon would therefore have been destroyed. Samples for C,H,N and 0 analyses were not pre-extracted with solvents, although this could have some minor effects on the interpretation of analysis results. In fact Durand & Monin (1980 p. 123) state, "There is little difference between elemental analysis before and after extraction since kerogen makes up most of the organic matter." The values of the concentrations of N (nitrogen) recorded in this analysis are considered inaccurate for quantitative evaluation.The discrepancy arises from the fact that the medical oxygen used in the machine at the time of analysis is not nitrogen free. It could therefore artificially inflate the nitrogen content of the organic matter analysed. Although the value could be used on a qualitative basis, it was not considered important during this analysis and was therefore not recorded. However care was taken before analyses to ensure that the nitrogen content of the medical oxygen had no adverse effect on the results of the other constituents of organic matter* Both optical and chemical methods are available for the determination of the level of organic maturity. One of the most commonly used optical methods is the microscopic observation in transmitted light of the colour of paly- 163 nomorphs (pollen & spores) in organic matter. The colour is indicative of the level of carbonisation, which in turn is a measure of the level of organic maturity (see section 5.4*4). This method was utilised in this study and combined with chemical methods. Other optical methods of measuring the level of organic maturation include vitrinite reflectance in oil (R ) and fluorescence studies. o Chemical methods available for evaluation of- organic matter maturity include the ratio C0/Cm of residual carbon K 1 (Cp.) to total carbon (Crp), solution extract versus total organic carbon plot, carbon preference index and bitumen extract quantity. These methods are discussed in Tissot & > Welte, (1978); Hunt, (1979); and Durand, (1980). The
C^./Crp method was used in this study. This method involves determining the total carbon content of a sample before and after pyrolysis,using the Perkin Elmer 240 elemental analyser The basis of the pyrolysis method is to simulate in the laboratory, conditions similar to those at depth in nature and to compensate for geologic time by applying high temperatures over short intervals of time. Harwood (1977); Tissot & Welte (1978) have shown that although deviations from natural conditions may exist, the results of laboratory pyrolysis are analogous to natural transformation of organic matter- Pyrolysis was carried out in this study on both whole rock and concentrated kerogen. It was carried out using a home made furnace which is programmable to give gradual increases in temperature. A maximum temperature of 900°C was used in this study. 164
Weighed samples were introduced into the furnace and left at 900C for lghrs. to ensure that all useful carbon had been converted. A constant stream of nitrogen gas flowing at 20cc/min. over the samples removed the volatile products of pyrolysis. The samples were weighed at the end of pyrolysis and the weight loss calculated. The loss was taken into account in calculating the CR values in order to allow their direct comparison with Crp values.
Organic carbon values are not in themselves diagnostic since a greater part of them could be reworked material and therefore of little consequence in petroleum generation or in the understanding of the thermal history and diagenesis of the rock. The organic matter in any potential source bed normally comprises a 'reactive' and an 'inert' part (Leythaeusers et. al.,1979). The former is that part of the total organic carbon which upon maturation will yield petroleum and is used as an indicator of the thermal evolution of the source bed (Tissot & Welte, 1978). The 'inert' part also known as 'dead carbon' (Hood & Castano,
1974), 'Fixed Carbon' or 'Residual Carbon' CR (Heroux et.al. 1979) remain essentially unchanged irrespective of the depth of burial or temperature.
Various methods exist for comparing total organic
carbon C^, with residual carbon CR. The pyrolysis method, established by Gransch & Eisma (1970), which was used in this study offers a quick inexpensive but fairly reliable
method of source bed evaluation. Here CR is given by the
equation CR= CT - S^. Where S^ is the 'useful Carbon' (carbon that is converted to petroleum and volatilised 165
0 1 2 3 4 5 6
Total Non-Carbonate Carbon Weight %(CT) Figure 5.2 Diagram for determining the level of maturation of organic matter (from Karimzadeh-Rad 1980). 166 during pyrolysis). In general increasing ratio indicates
increasing maturity although Tissot & Welte (1978) have pointed out that this trend could also indicate a change in sedimentation from marine and lacustrine (Type II kerogen) to terrestrial (type III kerogen - see section 5.3.1). With increased maturity
of the organic matter, CR/Crp value approaches 1 since most of the useful carbon would have been converted to hydrocarbons and the
C^ therefore approaches CR. Generally CR/Crp ratios greater than 0.8 are considered unrealistic since the ideal situation may never be attained in nature (see Gransch and Eisma, 1970). They also
pointed out that CR/Crp ratios between 0.6-0.8 indicates unfavourable organic matter. Karimzadeh-Rad (1980 unpublished Ph.D thesis)
also showed that CR/Crp ratios below 0.2 indicate immaturity for all types of kerogen (Fig. 5.2).
5.3 THE CONCEPT OF ORGANIC GEOCHEMISTRY The science of organic geochemistry is the application of chemical principles to the study of the origin and alteration of organic compounds and the use of this knowledge .in exploration for oil and gas and related bitumens. Although petroleum has been known since ancient times, it was only in this century that the technological capability has been developed to locate and obtain the enormous quantity needed to satisfy world energy requirements. The principles of organic geochemistry were initially applied to the study of coal petrology in coal exploration. It was White (1915) who first recognised the relationship between coal and petroleum pools. He observed that oil and gas fields died out in those places where the coal had a fixed carbon content (non-volatile content) of 60$ and 167
Table 5.1 Conversion Factors for computation of total organic matter from organic carbon content. (After Tissot & Welte, 1978)
TYPE OF KEROGEN STAGE COAL I II III
DIAGENESIS 1.25 1.34 1.48 1.57
END OF CATAGENESIS 1.20 1.19 1.18 1.12 168
65$-70$ respectively. In the years that followed, workers realised that the full range of coal petrology could be applied to the study of organic matter in petroleum exploration (Gransch & Eisma, 1970; Dow, 1977 and Peters et. al. 1977). This new concept of organic geochemistry has helped a great deal in the understanding of the processes of petroleum formation, migration and accumulation. Its use in the present study is restricted to determining the amount and type of organic matter as well as some indices of organic maturation.
5.3.1 AMOUNT AND TYPE OF ORGANIC MATTER Tht total organic carbon content (Crp) of a rock is generally considered a measure of its organic matter content. It is necessary to determine the amount of organic matter in a sediment because the quantity of petroleum produced bears a relation to its organic content as well as organic matter type and other factors. Also, critical levels of hydrocarbon concentration in a source bed have to be reached before expulsion from a source rock is possible. A definite amount of organic matter is needed in sediments to generate sufficient amounts of petroleum to create the critical level of pore pressure required to initiate migration. Generally the C^, is multiplied by a conversion factor to obtain an estimate of the amount of organic matter present. Forsman 6 Hunt (1958) determined conversion factors ranging from 1.07 for metamorphosed rocks to 1.4-0 for non metamor- phosed organic matter rich in oxygen (see Table 5.1). 169
These factors compensate for the level of organic maturation of the various samples as well as the presence of inorganic minerals.
The lower limit .-of organic matter content for non- reservoir rock shale-type sediment to be classified as a source rock is fixed at 0.5$ (Ronov, 1958) while the carbon content (Crp) is fixed at 1.0$. This lower limit of organic carbon is consistent with more recent findings from generally acknowledged source rock units (Tissot & Welte, 1978; Momper, 1978). A distinction between various types of sedimentary kerogen is essential for source rock appraisal, because different types of organic matter have different hydro- carbon potentials. The differences arise from variations in the chemical structure of the organic matter (Fig. 5.3). Remains of bacteria, phytoplankton, Zooplankton and higher plants have been recognised as the main contributors to kerogen in sediments. However, major chemical differences in gross composition exist between organisms living in an aquatic environment and those living in sub aerial (non aquatic) environment and it is therefore necessary to distinguish between the two types. The difference is important in the interpretation of source rock analysis.
Three kerogen types are generally recognised and distinguished on the basis of their chemical composition as well as optical properties. Each of these follows a different evolution path with increased burial depth and 170
TYPE I KEROGEN
TYPE H KEROGEN
TYPE HI KEROGEI
Figure 5.3 Schematic structure of the various types of kerogen. (From Hunt 1979). 1 71
yield different end products. The three kerogen types have been called types I, II and III. Type I kerogen has a high H/C and a low 0/C atomic ratios. It contains much lipid material especially aliphatic chains. Kerogen of this type is produced by the accumu- lation of structured algal material (e.g. Botryococcus) easily recognisable under a microscope. Some amorphous matter may be present, possibly derived from intense microbial reworking of various kinds of organic matter (Tissot & Welte, 1978).
Type II kerogen also has a relatively high H/C and low 0/C atomic ratio. There are still aliphatic chains of moderate length within the structure. It generally has an amorphous appearance with some identifiable particles. Those particles include algal or other planktonic remnants and some land-derived plant material, such as pollen. Humic material may also be a minor component of this type of organic material. Many of the source rocks for the world's major oil fields contain type II kerogen.
Type III kerogen has a low H/C and high 0/C atomic ratios. It contains only a minor amount of aliphatic compounds and usually consists of humic, opaque and coaly materials. It is mainly derived from terrestrial materials which have invariably been subjected to severe oxidation on land.
5.3.2 LEVEL OF MATURATION OF ORGANIC MATTER
The level of maturation of organic matter is perhaps the most significant factor in source bed evaluation. Therefore its determination is very important to the estab- lishment of the source of the petroleum in the Niger delta. Main stages of evolution Vilrinilt LOM Coal Vtssotvich Main HC rtflidinct Hood&il Int.hdbk Rank BTU This book (1969,1974) giniriled (1975) Rink USA coil put Girmiif x10-3 SVM -0 — (1971 Diogenesis Peot Peol Peot
2 - Lignite Diagenesis Methane Brown Protocotagenesis 4 - Broun- cool ft8 kohle Sub. _C_ 9 6 bituminous _ u 10 R0~0.5 0.5 A, 11 8 12 r (45) High _C 13 volatile B Oil 14 b (40) bituminous A Mesocatagenesis 10 Catagenesis b (35) 1.0 Slein- b 15 h 30 Med. vol. bit. r- 25 1.5 12 kohle I- 20 Wet gas Low vol. bit. R0~2 2.0 Hard b 15 14 H Semi- cool anlhracile Methane - 10 -2.5 Metagenesis 16 Anlh. Apocafagenesis ft 3.0 18 Anlhrocite - 5 R0~4 3.i 4.( Meta- Metamorphism 20 Anlh. Meta-anth.
Figure 5.4 The main stages in the evoluti on of kerogen. (From Tissot and Uelte 1978) 173
The level of maturation of organic matter is controlled by temperature, pressure, mineral composition of the rock and time; temperature being generally considered the most important (Philippi, 1965, 1977; Tissot & Welte, 1978). The temperature to which organic matter has been subjected and the length of time in any temperature regime affects both its physical and chemical properties (Staplin, 1969;
Vassoyevich et. al. 1970; Peters et. al. 1977-5 Correia, 1971; Gray & Boucot, 1975; and Tissot & Welte, 1978). The properties may be considered as indicators of maturation. The parameters most commonly used in petroleum exploration are the colour of the kerogen (parti- cularly the palynomorphs),the vitrinite reflectance, chemical parameters, as well as quantity of extractable bitumen. Hood & Castano, (1974) compared the various tech- niques of measuring the thermal evolution and proposed a numerical scale for it called Level of.-Organic Metamor- phism (LOM; Hood et. al. 1975; Fig.. 5-4). While it may not be necessary to use all the techniques available to obtain the full suite of maturation data, in any single study, it is important to use at least two methods preferably one optical and one chemical, to deter- mine the level of maturation of kerogen. Such a combination of methods was employed by Claypool et. al. (1978) who used bitumen extract, ratio of atomic hydrogen to carbon (H/C), and palynomorph colouration to distinguish between mature and imma- ture organic matter in the shales of the Phosphoria Formation in the U.S.A. They indicated that thermally mature organic matter has high (>1$) extractable hydrocarbons, high H/C 1 74
ratio ranging between 1.1 and 1.6 and kerogen colouration ranging between brown and dark brown; while immature organic matter yield low extractable hydrocarbon, low H/C ratio (<1.0) and kerogencolouration ranging from pale yellow to golden yellow. Incipient metamorphism is indicated by less than 0.2$ total organic matter content, very low H/C ratio (0.4 - 0.6) and dark brown to black kerogen colouration.
On the other hand, Fujita (1977) and Magara, (1980) have used only the variation in quantity of extractable hydrocarbons as an indication of migration. This could in turn be used as an indication of maturation, for, the hydrocarbons must first be generated before they can migrate.
5.3.3 STAGES OF MATURATION OF ORGANIC MATTER Based on the changes in the physical and chemical properties of kerogen during thermal evolution, the process of carbonisation has been divided into three different but continuous stages. These are: Diagenesis, Catagenesis and Metagenesis (Tissot & Welte, 1978). The diagenetic stage is the early stage of transforma- tion of organic matter which usually takes place at shallow depths (<1000m), under low temperature and pressure conditions. During early diagenesis one of the main agents of trans- formation is microbial activity. Aerobic micro-organisms consume free oxygen in the uppermost layers of sediments. Anaerobes reduce sulphates to obtain the required oxygen. The energy is provided by decomposition of organic matter which releases CO2, NH^ and H2O). At this time Eh decreases abruptly and pH increases slightly. Certain solids like organodetrital CaCO^ and SiO^ dissolve, reach saturation and reprecipitate together with diagenetic minerals such as sulphides of iron, copper, lead and zinc and siderite. 1 75
BIOPOLYMERS CARBOHYDRATES, PROTEINS, LIPIDS, LIGNINS.
Water.
BIOLOGICAL BREAKDOWN Sediment. BIOMONOMERS SUGARS, AMINO-ACIDS, FATTY ACIDS, PHENOLS.
CONDENSATION 25°C. NITROGENOUS & HUMUS 1m." Geopolymers COMPLEXES.
DIAGENESIS
Reduction, Decarboxylation, Deamination, Demethylation.
50°C 1000 m. LARGE MOLECULE: CYCLO ALKANES, ALKANES, ARENES.
THERMAL BREAKDOWN (CRACKING ) Geomonomers LOW MOLECULAR WEIGHT HYDROCARBONS.
175 °C. 6000 m. METAMORPHISM
GRAPHITE
Figure 5.5 Diagramatic representation of the possible sequence of diagenesis of organic matter. 176
Organic material proceeds to equilibrium and biopoly-
mers are converted to geoplymers (Fig. 5-5). The most
important hydrocarbon produced during this stage is
biogenic methane (Rice & Claypool, 1981). In addition,
carbon dioxide, water and hydrogen sulphide are also
produced. The end product of this stage of maturation which
corresponds to a vitrinite reflectance (RQ) of about 0.5$
is insoluble immature kerogen.
The catagenetic stage corresponds to a temperature
range of 50° to 150°c and is concerned with the break down
of the kerogen formed during diagenesis. While liquid
hydrocarbons are generated in the early stage of catagenesis,
(R = 0.5$ - 1.3$) wet gases and condensates are the main
hydrocarbon products of late catagenesis (R =1.3$ - 2.0$).
Increased temperature during early catagenesis results in
breaking of bonds to give hydrocarbons and it is marked
by a decrease in the hydrogen content and a disappearance
of the aliphatic chains in kerogen. The palynomorph
colouration ranges from yellow to orange during early catagenesis and orange to brown during late catagenesis.
The metagenetic stage is characterised by high tempera-
ture black palynomorph colouration, Rq>2.0$ and the
generation of only dry gas. This stage passes almost unnoticed, into the metamorphism stage with R >4$. 177 TABLE 5.2. RESULTS OF ELEMENTAL ANALYSIS OF SOME KEROGEN FROM THE AGBADA AND AKATA SHALES NIGER DELTA
Sample No °T Wt. % HT Wt. % °T Wt. $ Atomic H/C Atomic 0/C AGBADA FORMATION DLK- 1 56.17 5.61 14.15 1.19 0.19 DLK- 2 53.15 4.47 15.47 1.01 0.22 DLK: 3 59.99 6.13 13.11 1.15 0.17 DLK- 4 49.93 ' 4.50 15.51 1.08 0.23 DLK- 5 68.00 6.46 14.00 1.14 0.15 DLK- 8 61.76 6.52 13.03 1.26 0.16 DLK- 9 57.79 4.27 16.19 0.99 0.21 DLK-10 57.36 6.69 10.75 1.40 0.14 DLK-13 58.72 6.37 17.17 1.31 0.22 DLK-15 63.35 6.88 13.71 1.30 0.16 DLK:l6 60.59 5.96 13.07 1.18 0.16 DLK-18 67.89 6. 86 14.56 1.21 0.16 DLK-19 60.65 5. 90 14.80 1. 17 0.18 DLK-20 57.77 5.58 14.70 1. 16 0.19 DLK-21 58.66 5.65 16.13 1.16 0.21 DLK-22 50.87 4. 03 14.20 0.96 0.21 DLK-23 58.62 5.71 8.11 1.16 0.10 DLK-24 63.98 5.73 16.45 1.07 0.19 DLK-27 70.34 6.98 7.82 1.18 0.08 DLK-2 9 56.62 4.58 14.37 0.97 0.19 DLK-30 63.29 6.95 11.84 1.32 0.14 DLK-31 66.31 .7.15 12.40 1. 30 0.14 DLK-32 51.08 5.16 13.89 1.21 0.20 DLK-33 66.04 5.64 16.85 1. 02 0.19 DLK-34 62.65 5. 98 14.25 1. 15 0.17 DLK-35 52.97 4.34 15.29 0. 98 0.22 DLK-36 71.8 6.88 10.47 1.15 0.11 DLK-37 68.61 7.26 ND 1.27 ND
AKATA SHA1
DLK-38 63.49 4.57 10.17 0.86 0.12 DLK-39 64.95 6. 52 13.70 1.20 0.16 DLK-40 62.67 5.10 13.25 0. 98 0.16 DLK-41 65.38 5.20 12.55 0.95 0.14 178 TABLE 5.3 OPTICAL DESCRIPTION OF THE CONCENTRATED KERQGEN OF SHALES OF THE AGBADA AND AKATA FORMATIONS SAMPLE COLOUR OF COLOUR OF DESCRIPTION OF KEROGEN NO. KEROGEN POLLEN & SPORES
DLK 1 Mixed organic matter Yellow-Brown Yellow containing about equal amounts of amorphous and structured materials
DLK 2 Mainly amorphous organic dk. Yellow- It. Yellow-Yellow matter and fine grained. It: Brown Some structured liptini- tic materials. A few reworked grains
DLK 3 Mixed organic matter. Brown- It. Yellow Contains more struc- It. Brown tured materials (mainly liptinites) than amorphous material. Amorphous material is mainly fine grained
DLK 4 Mixed organic matter Yellow-golden It. Yellow but dominantly struc- Yellow tured. Fair amount of innertinites. Contains some humic materials
DLK 5 Fine grained organic Yellow-Brown Golden Yellow matter. About equal amounts of structured and amorphous materials. Mainly liptinite although a few large dark grains could be reworked materials (inertinites)
DLK 9 Fairly poor in organic Yellow It. Yellow- matter which is mainly Yellow structured and of cuticular. Very little amorphous materials
DLK 10 Mixed organic matter, Yellow-lt. It. Yellow- mainly liptinites. Brown Yellow Contains a fair amount of reworked materials
DLK 13 Fine grained organic Yellow- It. Yellow- matter mainly liptini-. Golden yellow Yellow tes plus some amorphous materials and some inertinite.
contd.... 18 4 / 2. DLS 15 Mixed organic matter, Yellow-Brown Yellow mainly amorphous and fine grained. Liptinite fraction contains only a small amount of pollen and spores
DLK 16 Mixed organic matter. Yellow-Brown Yellow- Contains about equal Golden Yellow amounts of structued and amorphous materials. DLK 18 Mixed organic matter, dk. Yellow Yellow mainly structured liptinite. Fine grained amorphous also present.
DLK 19 Mainly fine grained Yellow-Brown Golden Yellow organic matter. Liptin-. tes fraction contains only a small amount of pollen and spores. DLK 21 Mainly amorphous organic matter. Little structured material and also low in pollen and spores.
DLK 22 Mixed organic matter. dk. Yellow It. Yellow- Contains a high propor- Yellow tion of reworked materials.
DLK 27 Mixed organic matter, Yellow-dk. Yellow- mainly fine grained Brown Golden Yellow amorphous. Also a high proportion of liptinites. A few reworked grains. Poor in pollen and spores.
DLK 29 Mainly structured dk. Yellow Yellow organic matter, dominantly cuticular.
DLK 30 Mixed organic matter, dk. Yellow- It. Yellow- contains a high dk. Brown Yellow proportion of reworked materials
DLK 31 Mainly structured Yellow- It. Yellow- organic matter with dk. Yellow Yellow some fine grained amorphous materials. A few reworked materials
contd. i
DLK 34 Mainly structured dk. Yellow- Yellow organic matter of dk. Brown cuticular material. Low proportion of amorphous materials. A few reworked grains.
DLK 35 Mixed organic matter, Yellow- It. Yellow- contains more0 struc- dk. Yellow Yellow tured materials than amorphous. Low in pollen and spores.
DLK 36 Mainly structured Brown- It. Yellow- organic matter of dk. Brown It. Brown liptinitic type. Pollen and spore in a poor state of preserv- tion either broken or crushed. A fair amount of reworked material (.inertinite). DLK 39 Mixed organic matter, Yellow- It. Yellow- contains more amor- It. Brown Yellow phous materials. Some reworked materials.
DLK 41 Mainly structured dk. Yellow- It. Yellow- organic matter of dk. Brown Yellow cuticular materials. Contains amorphous and reworked materials. 181
5.4 RESULTS .AND INTERPRETATIONS 5.4.1 ORGANIC CARBON CONTENT CT The results of elemental analysis of the kerogen of the Niger delta are presented in (Tabl-e 5.2). The amount of organic matter has been presented as values of Crp. (total organic carbon) with no attempt made at converting them to total organic matter. In all cases the C^ values of the samples analysed range between L.l$ - 4*1$ for whole rocks and 50$ - 70$ for concentrated kerogen.
The values of C^, recorded for these samples is well above the arbitrary lower cut off point established for potential shale source beds. Therefore, all samples analysed covering the depth interval of 1,000 to 4»000mof the Agbada Formation,as defined in this thesis,are potential source beds. Depending on the temperatures and pressures to which they have been subjected, they may or may not have generated hydrocarbons.
5.4.2 TYPE OF ORGANIC MATTER
The optical descriptions of the organic matter examined are presented in (Table 5.3) whilst their photographs are shown in (Fig. 5.6, A-L). The assemblage of organic matter shows a mixture of both structured and amorphous materials. Compared with the published photographs of Combaz (1980) the majority of the kerogen examined from the Agbada and Akata shales alike are comparable to the type II kerogen which he calls Liptinites. The minor variations observed are interpreted as reflecting the dominance of particular environments (Marine, terrestrial or paludal - lacustrine) during deposition of the various beds. 1 82
•
•MMI
i m
6 Photornicrographs of kerogen issolated from shales of the Agbada Formation,(A :Meren field - 1870m, X100; BrDelta South field - 2220m ,X100 183
4 &
v.-f. - £ > * - 1 m ir' •
r p V V V V • t 1 f t : • 0 0 „ * \
• * - * M » ? Hr 1
Figure 5.6 Photomicrographs of kerogen issolated from shales of the Agbada Formation, (C: Delta South field - 2642m, X50; D: Makaraba field 3298m, X40) . 1 8 4
E
F
Figure 5.6E & F Photomicrographs of kerogen issolated from the shales of the Agbada Formation (E :M er en field - 1 559m, X100;F: Heren Field - 2111m, X40). 1 85
If is v" ' * ' V" ^!;
> *. _ • * * " * ft MV Mif'-.\* f I AS * • ft. * .*
: N V 1 J / % «• * * 4l> ... V - v \ # < V to « * A , t V- to
iSfev J,1,
5.6G & H Photomicrographs of'kerogen issolated from the shales of the Agbada Formation, (G: Oyot field - 2353m, X100> HrMakaraba field - 1225m, X100). 1*86
#41 / X?4 M * * I«
' " Ji, " " % . , mf ^ < , • »( • * ^ n
- %
r I
• 1 4 » V 4
Figure 5.6 I & 8 Photomicrographs of kerogen issolated from the shales of the Agbada Formation (I: Akata field - 3378m, X1•0; J: Akata field - 3396m, X63) . 8 7
V I % • 0
Figure 5.6K & L Photomicrograph of kerogen issolated from the shales of the Akata Formation, (K: Ebubu field - 3638m; L: Ebubu field - 3642m). 188
The results of the quantitative elemental analyses are shown in Table 5.2). The hydrogen values range from 4.0$ to 7.26$ while the oxygen values range from 8$ to 17$. A slight decrease in both hydrogen and oxygen values with depth is observed in the area. The H/C and 0/C atomic ratio! which help to distinguish between the various types of kerogen on a Van Krevelen diagram vary from 0.86 to 1*49 and 0.08 to 0.2 respectively. These values plot as a broad band of type II kerogen (on the Van Krevelen diagram) with low to fairly high degree of evolution (Fig. 5.7)
According to Maximov et. al. (1975), the hydrogen content and the H/C atomic ratio can indicate kerogen type provided a sediment has not been subjected to conditions in excess of middle catagenesis (see section 5.3.3). They define type I kerogen by H values higher than 6$ and H/C atomic ratio higher than 1; while type III has H content below 4$ and H/C atomic ratio lower than 0.8. Type II kerogen falls between these two extremes. Laplante (1974) also used the hydrogen content to indirectly classify the type of kerogen. He claims that a kerogen with >7$ hydrogen could generate oil. This type of kerogen is analogous to type I as defined by Maximov et. al. (1975). These two methods of determining organic matter type are correlatable and complementary and it is clear from them that hydrogen poor
kerogens, even when given "the right . conditions are incapable of generating significant amountsof oil (see Demaison & Shibaoka, 1975X 189
Atomic ratio 0/^-'
• AGBADA SHALES
o AKATA SHALES
Figure 5,7 The Van Krevelen diagram with results of the elemental analysis of the kerogen of Agbada and Akata shales. 190
Employing these interpretations therefore, the samples analysed except DLK 9, 22, 29 and 35 which are all shallow samples ( Maximov et. al. (1975) DLK 3,5,8,19,13,15,18,27,30,31,36,37 and 39 fall into type I kerogen while the others classify as type II. However, on the Van Krevelen diagram, only DLK 10 and 36 plot as type I. Considering the environment of deposition of these samples and the strong terrestrial influence in the Niger delta, all samples except DLK 22 and 35 are classified as type II in this thesis. It is accepted however that those samples with H-value higher than 6$ and H/C atomic ratio higher than 1, have a high contribution of type I kerogen and are therefore more aliphatic and likely precursors of oil than gas. It is significant that all the shallow samples DLK 9 (882m), DLK 22 (l,097m) and DLK 35 (l,225m) fall on the bo- rder line between type II and III. This result is not considered a reflection of a variation in organic type, since optical observations do not show that the samples contain a signifi- cantly different type of organic matter. It appears that in addition to the upper temperature limit (mid catagenesis) imposed by Maximov et. al. (1975) the application of this technique is also subject to a lower temperature and pressure condition. It is highly likely that due to the temperature and pressure condition at these shallow depths, transformation of organic matter has not advanced enough to make the H & H/C values diagnostic. Unfortunately, insufficient data precludes a full investigation of this observation at the present time. 191 TABLE 5.4 CARBON RATIOS DETERMINED FROM PYROLYSIS OF WHOLE ROCK SAMPLES OF THE AGBADA AND AKATA SHALES CT-CR * $ Wt. CT OR CR/CT ,0 SAMPLE NO. CT Loss During Pyrolysis DLW 1 ND ND ND ND - DLW 2 ND ND ND ND - DLW 3 1.22 0.21 .17 82.79 10.34 DLW 4 1.09 .33 .30 69.72 18.10 DL W 5 2.55 .28 .11 89.00 18.42 DLW 8 1.83 .31 d6 83.06 19.27 DLW 9 2.09 .14 .07 93.30 15.32 DLW 10 ND ND ND ND - DLW 13 1.46 .15 .1 89.97 13.84 DLW 15 1.71 .38 .22 77.78 15.21 DLW 16 2.87 .23 .08 91.99 15.77 DLW 18 2.55 .04 .02 98.43 18.97 DLW 19 ND . ND ND ND - DLW 20 2.73 .47 .17 82.78 15.89 DLW 21 1.42 .15 .11 89.94 15.31 DLW 22 2.76 .15 .07 94.57 18.13 DLW 23 2.55 .60 .24 76.47 17.92 DLW 24 2.24 .25 .11 88.84 13.33 DLW 27 3.35 .23 .07 93.13 18.13 DLW 2 9 1.70 .37 .22 78.24 18.67 DLW 30 ND ND ND ND - DLW 31 2.04 .05 .03 97.55 18.50 DLW 32 1.16 .22 .19 81.03 11.73 DLW 33 4.13 0.75 0.18 81.84 19.46 DLW 34 ND ND ND ND - DLW 35 1.17 0.28 0.24 76.07 12.33 DLW 36 1. 92 0.34 0.18 82.29 15.48 contd.... 192 TABLE 5.4 Cond. DLw 37 2.02 0.34 0.17 83.16 14.86 DLW 42 3.18 0.28 0.09 91.19 16.30 DLW 47 3.09 0.23 0.07 92.56 18.98 DLW 48 2.06 0.28 0.14 86.40 12.37 DLW 49 2.65 0.20 0.08 92.45 17.07 DLW 50 1.52 0.19 0.13 87.50 17.01 DLW 51 1.19 0.11 0.09 90.76 10.08 DLW 52 2.55 0.04 0.02 98.43 18.97 DLW 53 1.93 0.40 0.21 79.27 14.52 DLW 55 2.06 0.38 0.18 81.55 9.62 DLW 56 4.13 0.75 0.18 81.84 19.46 DLW 57 1.57 0.29 0.18 81.53 7.87 DLW 58 1.97 0.37 0.19 81.22 13.08 DLW 59 1.13 0.12 0.11 89.38 4.98 DLW 60 1.07 0.21 0.20 80.37 14.52 DLW 61 2.50 0.29 0.12 88.40 17.62 DLW 62 2.08 0.38 0.18 81.73 10.81 DLW 63 2.36 0.25 0.11 89.41 11.68 DLW 64 1.09 0.33 0.30 69.72 10.48 DLW 65 1.46 0.15 0.10 89.73 13.94 DLW 66 2.55 0.60 0.24 76.47 6.39 DLW 67 1.75 0.16 0.09 90.86 17.53 DLW 68 1.83 0.23 0.13 87.43 12.25 AKATA SHA1jES DLW 38 1.01 0.21 0.21 79.21 10.51 DLW 39 2.07 0.34 0.16 83.57 12.33 DLW 40 1.53 0.26 0.17 83.01 11.05 DLW 41 1.74 0.32 0.18 81.61 12.14 193 5.4.3 PYROLYSIS Cr/CT The results of the whole rock pyrolysis are presented in (Table 5.4) while those of the isolated kerogen are given in (Table 5.5).*CR/Crp values for whole rock analyses range between 0.,02-0.30 while those of kerogen vary between 0.09-0.53. Although there is some random variation, it is observed that the CD values for whole rock samples are generally lower than those for the concentrated kerogen. This observation is largely supported by results of previous workers (Tissot & Welte, 1978; Horsfield & Douglas, 1980 and Espitalie et. al., 1980) who observed that the presence of mineral matrix has an absorptive effect on the products of the organic matter transformation. However, their observation delt with programmed pyrolysis in which the products were analysed by gas chromatography. In their experiments, some higher molecular weight hydrocarbons were retained at lower temperatures and cracked at higher temperatures to give a high S^' which gives an indication of lower maturity. Although the products of pyrolysis were not analysed in this study the CR results obtained indicate that the situation is similar to the situation in the above experiments. The matrix may have either catalytically aided the maturation process during pyrolysis or formed complex compounds (which are unoxidisable) with organic matter. Therefore the carbon locked within them is not detectable and hence the low CR values. In interpreting C^/Crp data, Gransch & Eisma (1970) have shown that ratios higher than 0.6 denote organic matter which is not hydrocarbon prone. By this definition, all the kerogen analysed are potential sources of petroleum. They also showed that the values are influenced by the type of organic matter. For example a Cr/Ct yalue of Q_6 fop hun|-c 194 TABLE: 5.5 CARBON RATIOS DETERMINED FROM PYROLYSIS OF SOME KEROGEN SAMPLES 0 F THE AGBADA AND AKATA SHALES > % WT.LOSS I CT-CR C C CR/CT during R .-CT • SAMPLE NO. T Porolyasis DLK-1 56.17 22. 93 0.41 59.17 58.82 DLK-2 53.15 16.18 0.30 69. 56 58.49 DLK-3 59.99 18.56 0.31 69.06 66.23 DLK-4 49.93 12.12 0.24 75.73 70.94 DLK-5 68.0 27.83 0.41 59.07 61.36 DLK-8 61.76 28.14 0.46 54.44 61.57 DLK-9 57.79 13.26 0.26 77.05 72.65 DLK-10 57.36 22.71 0.40 60.41 63.57 DLK-13 58.72 15.64 0.27 73.32 74.72 DLK-15 63.35 28.32 0.45 55.30 60.50 DLK-16 60.59 27.35 0.45 54.86 63.09 DLK-18 67.89 27.83 0.41 59.01 65.33 DLK-19 60.65 23.04 0.38 62.01 62.55 DLK-20 57.77 20.54 0.36 64.64 65.34 DLK-21 58.66 15.05 0.26 74.34 68.33 DLK-22 50.87 15.17 0.30 70.18 68.49 DLK-23 58.62 30.04 0.51 48.55 57.33 DLK-24 63.98 18.05 0.28 71.79 71.39 DLK-27 70.34 37.19 0.53 47.13 49.60 DLK-29 56.62 21.83 0.39 61.44 67.98 DLK-30 63.29 5.47 0.09 91.47 80.86 DLK-31 66.31 25.57 0.39 61.43 60.88 DLK-32 51.08 11.98 0.23 76.55 67.67 DLK-33 66.04 25.10 0.38 61. 99 65.37 DLK-34 62.65 24.93 0.40 60.02 69.32 DLK-35 52.97 8.82 0.17 83.35 81.17 DLK-36 71.8 32.31 0.45 55.00 60.38 DLK-37 68.61 28.81 0.42 58.01 60.57 195 / 2. TABLE 5.5 Cond. AKATA SHALES DLK-38 63.49 9.86 .16 84.47 65.37 DLK-39 64.95 12.13 .19 81.32 77.28 DLK-40 62.67 10.21 .16 83.71 83.95 DLK-41 65.38 12.65 .19 80.65 78.52 196 coaly material could correspond to C^/Crp values of 0.2 for non-coaly material of similar rank. Considering that the organic matter of the Niger delta belong largely to the type II kerogen, with low amounts of coaly and humic materials in many cases, then all samples of the Agbada Formation analyses except DLK 30 and 35 could be classified as mature whereas those of the Akata are not (Fi.g 5.8). CD/Cm data for the four shale samples taken from the ft i Akata Formation show lower levels of maturation (CR/C^. values of 0.16-0.19) than many shallower samples of the Agbada Formation from similar thermal regimes. Since the organic matter type are similar, the lower C^/Crp values are interpreted as indicative of a situation of non-migration of generated hydrocarbons. The Akata samples DLK 38-41 with low C^/Crp values, contain a clay assemblage which show i\ i little evidence of diagenetic transformation with depth. In fact, smectite is largely present in the hydrated state in these samples, (see section 4*3). The lack of dewatering of these formations results in.the trapping, along with the pore- waters, of the early formed hydrocarbons and this inhibits the petroleum generating reactions. Neglia (1980) ha.s also suggested that the organic matter in over-pressured shales are generally immature, as a result of lack of heat transmittance to the organic matter due to the overpressuring. The same cannot be said of the overpressured Akata shales which in addition to being at a greater depth has also been in contact for a longer period with the heat sources around and below the Niger delta. Some heat must have been transmitted through it to the overlying Agbada Formation. Therefore the inability of the Akata to dewater, appears to be a major factor 197 TOTAL NON-CARBONATE CARBON WEIGHT %(CT) Figure 5,8 Plot of Cp versus Cj df the kerogen from the Agbada and Akata shales. 198 responsible for the low level of maturation of organic matter in the Akata Formation. This point is fully considered in section 6.2. However, Gransch & Eisma (1970) have also shown that CD/Cm ratios are subject to other interpretations depending K 1 on whether depositional or diagenetic factors are of more importance to the analyst. They presented three of such interpretations. a) If the organic matter in samples have been subjected to similar levels of maturation, then any difference in CD/Cm ratio reflects differences in the type of organic K 1 matter. b) If the organic matter in samples are of the same type, then any difference in Cp/Crp ratio reflects differences in degree or level of maturation of the organic matter. c) If the organic matter are of the same type and possess the same level of maturation, then other parameters must be used to establish the level of thermal evolution. The organic matter type in the sediments being studied from the Niger delta are broadly the same - type II. There- fore, case b) above is probably the nearest to being true for sediments of this region. This means that variations in the Cn/Crn ratios reflect differences in the level of maturation K I of organic matter. Table 5.6 arranges the samples per field in order of increasing depth. With minor variations, a trend of increasing maturity (high CR/CT ratios) with increasing depth is evident. 199 TABLE 5.6 ELEMENTAL ANALYSIS AND PYROLYSIS RESULTS OF SOME KEROGEN OF THE AGBADA AND AKATA SHALES ARRANGED IN ORDER OF INCREASING DEPTH PER FIELD SAMPLE 'SAMPLE CT C C H R R/CT H 0 /C NO. DEPTH °/C ' DLK 9 ' ME/882 57.79 13.26 0.26 4.26 16.19 0.99 0.12 DLK 22 ME/1097 50.89 15.17 0.30 4.35 14.20 1.03 0.21 DLK 8 ME/1559 61.76 28.14 0.46 6.52 13.03 1.26 0.16 DLK 24 ME/1608 63.98 18.05 0.28 5.73 16.45 1.07 0.19 DLK 20 ME/1786 57.77 20.54 0.36 4.98 14.70 1.03 0.19 DLK 1 ME/1870 56.17 22.93 0.41 5.21 14.15 1.11 0.19 DLK 18 ME/1938 67.89 27.83 0.41 6.30 14.56 1.11 0.16 DLK 31 ME/2108 66.31 25.57 0.39 5.15 12.40 1.04 0.14 DLK 16 ME/2111 60.59 27.35 0.45 5.26 13.07 1.05 0.16 DLK 34 ME/2283 62.65 24.93 0.40 5.22 14.25 1.00 0.17 DLK 35 MAK/1225 52.97 8.82 0.17 4.34 15.29 0. 98 0.22 DLK 21 MAK/2021 58.66 15.05 0.26 5.65 16.13 1.16 0.21 DLK 5 MAK/3298 68.0 27.83 0.41 6.46 14.00 1.14 0.15 DLK 32 DS/1874 51.08 11.98 0.23 5.16 13.89 1.21 0.20 DLK 33 DS/1898 66.04 25.10 0.38 5.64 16.82 1.02 0.19 DLK 15 DS/2187 63.35 28.32 0.45 6.88 13.71 1.30 0.16 DLK 30 DS/2641 53.29 . 5. 47 0.09 6.95 11.84 1.32 0.14 DLK 3 DS/2542 59.99 18.56 0.31 6.13 13.11 1.15 0.17 DLK 4 ROB/1709 49.93 12.12 0.24 4.50 15.51 1.08 0.23 DLK 2 9 ROB/2152 56.62 21.83 0.39 4.58 14.37 0.97 0.19 DLK 13 ROB/3873 58.72 15.64 0.27 6.37 17.17 1.31 0.22 DLK 23 OY/2353 58.62 30.04 0.51 5.71 8.11 1.16 0.10 DLK 19 OY/2384 60.65 23.04 0-38 5.26 14.80 1.04 0.18 contd. 200 TABLE 5.6 Cond. DLK 10 WI/1994 57.36 22.71 0.40 6.69" 10.75 1.40 0.14 DLK 27 OLU/3535 70.34 37.19 0.53 6.98 7.82 1.18 0.08 DLK 36 AK/3378 71.8 32.31 0.45 6.88 10.47 1.15 0.11 DLE 37 AK/3396 68.61 28.81 0.42 7.26 ND 1.27 ND 201 Apart from DLK 35 (Makaraba/1225 m) and DLK 30 (Delta South 2654-m) every sample of the Agbada Formation analysed from Makaraba, Meren, Opolo, Oyot, Robertkiri and Akata, fields gives a Cp/C^ ratio greater than 0.2. Using the cut-off point of CR/Ct=0.4 (Type II) established by Karimzadeh-Rad (1980 Unpubl. Ph.D.thesis) most of the samples of the Agbada Formation are mature (Fig. 5.8). However, majority of them are closer to the lower limit, indicating that only the initial stages of maturation have been attained. The samples with Op/Crp lower than 0.4 mainly come from the eastern Niger delta where the goethermal gradients are lowr This observation is easily supported by the goethermal gradient data of Avbovbo (1978b) (Fig. 5.9) which predicts a lowest gradient of 1.2°F/l00ft. in the area around Robertkiri field. In the vicinity of Oyot, the gradient increases to 1.6°F/l00ft. and to 1.8-2.2°F/l00ft. in the areas around Makaraba, Meren, Opolo and Delta South. The relation of the geothermal gradients to paleotemperatures is discussed in section 5.5. Despite the high geothemal gradient in the Delta South area, Cp/Crp ratios for the samples from the field are consistently low (DLK 3=0.31, DLK. 30=0.09 and DLK 32=0.23). Since the organic matter is still largely type II, these ratios are indicative of immaturity. The reason for this is not immediately clear. All samples of the Akata Formation plot below the CR/C =0.2 line indicating that they are immature. Figure 5.9 Geothermal gradient map of southern Nigeria.(Aftar Avbovbo 1978). 203 Figure 5.10A & B Photomicrographs of pollen and issolated from the shales of the Agbada Formation, (A:Meren f i el d-1 8 70m ; BrAkata fi eld-3378m, X400) 204 C Figure 5.10C & D Photomicrograph of pollen and spores issolated from the shales of the Agbada Formation, (C:Delta South field-264?m; D: Akata field-3378m, X400). 205 Figure 5.10E & F Photomicrograph of pollen and spores issolated from the shales of the Agbada Formation , (F : Robertkiri field-1 709m; F: Makaraba field-1225m, X400). 206 Figure 5.10G & H Photomicrograph of pollen and spores issolated from the shales of the Agbada Formation, (GrAkata field-3396m; H:0yot fi eld-235 3m, X400) . 1 863 4 • Figure 5.10 I & 3 Photomicrograph of pollen and spores issolated from the shales of the Akata Formation,( I : Ebubu field-3638m; 3:Ebubu fi eld-3642m, X400m). 208 5.4.4 CARBONISATION Table 5.3 shows the colours of organic matter as well as those of pollen and spores examined. In general, colours are light varying from yellow to orange and sometimes light brown (Fig.5.10 A-J). Broadly therefore, by this criterion, the samples range from thermally immature to mature in different areas. No consistent increase in colour with increasing depth is obvious in the samples from the Agbada Formation analysed. Variation in colour of pollen and spores s is random probably due to variation in temperature gradient over the Niger delta (see Nwachuckwu, 1976; and Avbovbo, 1978b). However, as expected the samples of the Akata Formation indi- cate a higher level of carbonisation than those of the Agbada Formation. Although inconsistency in pollen and spore colour exists over the entire delta, it can be seen from the photographs that samples from depths of 1,700m have achieved at least the yellow colour which marks the onset of the catagenetic phase (Fig. 5.11, Heroux et. al. 1979). The level of early catage- nesis predicted from carbonisation studies closely correlates with that determined by C^/Crp ratios. The close correlation between the two methods confirms their suitability for evalua- ting the level of maturation in the Niger delta. 5.5 GEOTHERMAL GRADIENTS IN RELATION TO THE PALEOTEMPERATURES Although the geothermal gradient is not strictly a geo- chemical parameter, it has far reaching effects on the geochemistry of the organic matter and therefore deserves consideration here. The gradients over the entire Niger delta have been calculated by Nwachukwu (1976) and Avbovbo (1978b) (Fig. 5.11). Although they vary widely over the entire delta, an average of 18°C krc"P can be said to be representative. These gradients are higher in areas flanking the basin and drop off rapidly towards the COAL RANK VOLATILE VITRINITE SPORE MAXIMUM HYDROCARBONS IN HYDROCARBON PRODUCT USA MATTER % REFLECTIVITY COLORATION PALEO-TEMP. SOURCE ROCK Rm(oil) % Op C0 BIOGENIC GAS LIGNITE IMMATURE -53 -0-4 SUB-BIT. -50 M -100 .47 0-5 -2 Yellow -3 0-6 HEAVY OILS WITH GAS HIGH 42 -4 MATURE VOL. X" 0-7 B 39 -5 BIT. k0-8 -200 -6 100 Orange MEDIUM TO LIGHT OILS -7 1-0 ro 32 -8 o Brown 1-2 -9 VO MID VOL. BIT. -300 150_ CONDENSATE i/OR GAS I- 26 1-3 -10 Black 22 15 LOW VOL. BIT. 15 kl-9 DRY GAS - 400 200 SEMI- ANTHRACITE 8 -25 ANTHRACITE METAMORPHOSED HEAVY HYDROCARBONS FIELD OF NIGER LIGHT HYDROCARBONS DELTA SAMPLES mMETHAN E Figure 5.11 Diagram showing the principal phase of petroleum generation and the location of the kerogen issolated from the shales of the Niger delta. 210 depocentre. Offshore-wards, there is a slight increase in geo- thermal gradient possibly related to the crustal thinning in that direction (see section 2.1). This gradient is relatively low when compared with the adjacent Douala basin which has an average computed paleogradient of 50°C km"1. The volcanism along the Cameroon line is largely responsible for this. It is however, closer to the geothermal gradient of the Gulf coast area of U.S.A. which has similar tectonics and rapid sedimentation history. The gradient in the Louisiana are of the Gulf Coast is between 22°-24°C km 1 and between 20°-33°C km"1 in the Texas areas (Tissot & Welte, 1978). Despite the disparity in gradients, the average depth of occurrence of hydrocarbons in the Niger delta (l,700m-3,500m) and the Gulf Coast (l,700-5,000m) are similar. Considering the tectonics of the area (opening of the South Atlantic; Opening and partial closing of the Benue trough; and the Cameroon volcanism) the earliest sediments brought into this basis were subjected to very high heat conditions. Tissot & Welte, (1978) suggested that the first sediments deposited under such conditions could be subjected to a heat flow two or three times higher than the average and that the rate of flow decrease to reach the average value in 15 to 20 million years. Given these conditions, it can be said that the heat flow in the pre-Tertiary Niger delta has been relatively rapid in the past and probably approached equilibrium during the Tertiary. The rapid rate of sedimenta- tion in the Tertiary, no doubt contributed to the slowing down of the rate of heat flow. 211 The flanks of the basin adjacent to the basement have thinner sediment accumulations than the depocenters. Such areas therefore have attained higher temperatures due to a higher rate of heat flow from the basement areas. The findings of this study as well as the data of Evamy et. al. 1978; Fig. 17 & 18) confirm this deduction. Evamy et. al. (ibid) showed that the 'oil kitchen' in the western Niger delta is much higher than the top of the continuous shale whereas the areas of thick sediments in the east around Port-Harcout had the 'oil kitchen' well below the top of the continuous shale. The concentration of fields around the northern part of the delta (hydrocarbon concentration zone Fig. 2.15) and the shallower depth of hydrocarbon occurrences in the area are not unrelated to this fact. Beyond this zone to the north, gas is the dominant hydrocarbon accumulation, indicating that temperatures in the area have exceeded the 'oil window' and that thermal generation of gas by cracking is probably the dominant phase in areas immediately adjacent to the basement rocks. DISCUSSION Putting together the data presented in this chapter, it is clear that the organic matter of the sediments of the Niger delta have not been subj ected to the principal phase of petroleum generation even at depths in excess of 3, 500m in the low temperature gradient areas in the centre of the basin. However, data show that many samples, even at depths as shallow as 1,700m in the flanks and 2,500m in the depocenter have entered the catagenic stage and have there- fore most probably generated some of their potential 212 hydrocarbons. This conclusion is supported by the kerogen type, the H/C and 0/C atomic ratio as well as the Op/C^ ratios of the kerogen. Although the carbonisation data is not very conclusive it indicates as well that the early catagenetic phase has been reached in many beds. The good correlation between the Cp/C^ data and the carbonisation data is striking and validates the conclusion reached in the study. 21 3 CHAPTER SIX GEOLOGICAL FACTORS BEARING ON HYDROCARBON ORIGIN IN THE NIGER DELTA 6.1 INTRODUCTION Correlating non numerically quantifiable geological observations with geochemical data in source rock studies has always been a problem for workers in this field (see Weeks 1961; Hedberg, 1964; and Wilson, 1975). This conflict is particularly evident in the Niger delta where workers have proposed sources based on either purely empirical geological observations (Short & Stauble, 1967; Frankl & Cordry, 1967; Reed, 1969) or purely geochemical data (Weber & Daukoru, 1975; Ekweozor et. al., .1979 and Ekweozor & Okoye, 1980). The need exists therefore to combine both sources of information in order to reach a valid conclusion on the source of hydrocarbon in the Niger delta. Such a combination was used by Evamy et. al., (1978) who concluded that, depending on their location, both the Akata Shales and the Agbada shales could act as source beds for the Agbada sandstone reservoirs. Ekweozor et. al.(i979) and Ekweozor & Okoye (1980) also accepted this view point and con- cluded that only the deeply buried shales below depths of 2,900m offshore and 3,500m onshore could generate hydrocarbons. The major drawback of this theory is the lack of a migration path from such deep seated sources to the overlying reservoirs some- times as far away as two kilometres. While the present study favours this combined source view, it considers that the depth limits suggested by Ekweozor & Okoye (1980) for initiation of hydrocarbon generation are possibly too deep (see section 5). Also the along fault upward migration, generally accepted by proponents of the deep petroleum generation, 214 can neither explain the distribution of hydrocarbons nor the variations in crude properties. The present study (section 5.4b) shows that although the kerogen is broadly type II, it contains varying amounts of types I and III kerogen. Apart from geochemical factors advanced in the last chapter to support the candidacy of the Agbada shales, other geological factors which are vital to proving the Agbada shales as the major source of petroleum in the Niger delta will now be discussed. 6.2 OVERPRESSURING OF THE AKATA SHALES One of the major geological factors against the Akata Formation as a major source of hydrocarbons in the Niger delta is the fact that the shales are overpressured even at the present day (according to the demarcations proposed in this thesis). Under-compaction commonly occurs when, through rapid sedimentation and/or other factors^ escape of fluids from compacting muds or shales, fail to keep up with increase in pore pressure probably due to over burden load, (see section 2.4.3). The release of such fluids including perhaps clay bound water is essential for primary hydrocarbon migration (Weaver, 1960; Barker, 1972; Perry & Hower, 1972; Magara, 1978). It is difficult to envisage therefore that such an overpressured formation as the Akata Formation, which has not expelled its interstitial water, could have expelled the vast amount of hydrocarbons into the generally distant reservoirs of the overlying Agbada Formation. The subject of overpressuring has been much debated in the literature (Dickinson, 1953; Magara, 1971; 1975; Smith, 1971; Weaver & Beck, 1971; Barker, 1972; 1977; Chapman, 1972, a & b; 1974; 1980; Bradley, 1975; Plumley, 1980 to name a few). The concensus of opinion is that a substantial reduction in permea- bility (supposed seal) at the top of the shale sequence is 215 essential if overpressuring is to develop. The necessary seals are provided by the normally compacted shales of the Agbada Formation. The contribution of Aquathermal pressuring (Barker, 1972; Magara, 1978), if any, is minimal and at best complementary. Consequently any hydrocarbons generated within such a formation are unlikely to be released. Some workers (Weber & Daukoru, 1975 and Weber et.al., 1978) argue that the numerous growth faults, found in the Niger delta some of which bottom in the upper part of the Akata Formation have provided avenues for migration of both petroleum and pore fluids from the overpressured zones. However, Yoder (1955); and Barker (1972) have noted that the removal of only a small percentage of the pore fluid from an abnormally pressured zone reduces the abnormal pressure to the hydrostatic pressure for that depth. Drilling data from the Niger delta show that many of the thick shales of the Akata Formation even at shallow depths (1,850m) are still largely overpressured (e.g., Parabe field). Since these shales are overpressured, it would appear that only an insignificant amount of fluid if any has been lost from them. There is however some evidence (Weber & Daukoru, 1975; Evamy et.al. (1978) that some reservoirs towards the bottom of the Agbada sequence are overpressured due to spillage of excess pressure across faults from the Akata shales faulted against them on the upthrown side. The amount of fluid thus released is generally small compared with the over-all volume of the pore fluids of the Akata Formation and therefore does not result in a significant depletion of excess pressures. Barker, (1972) and Sengupta, (1974) have shown that pressure is an important consideration in the chemical reactions that take place during maturation of organic matter. They independently 216 advanced the theory that most maturation processes proceed with small volume increases and so would be inhibited by pressure. This situation is very similar to the classical "Le Chatelier's" principle in elementary chemistry. However, Lewis & Rose (1970) proposed that the effect of this on chemical reaction is minor and that temperature is dominant in controlling organic matter transformation particularly in abnormally pressured intervals where the temperature may be higher than adjacent normally pressured zones. While it is undoubtedly true that higher temperature will enhance maturation of organic matter, the writer supports the former view and suggests that the non release of the end products of organic matter trans- formation would lead to pore fluids being over saturated with these products. Under such conditions it is highly unlikely that the organic matter maturation reaction would go forward. Neglia (1980) cited the example of Miesback I well in West Germany, where overpressured shales caprocks are immature. He also cites Agip's Cononica I well, also in Western Germany, where the kerogen is still immature at a depth of 7,110m in Triassic overpressured shales with temperatures as high as 200°C. He also concluded p.1544..• that "The preceding cited examples prove that the maturation process of the kerogen does not depend only on the temperature value but also on other parameters. Indeed the presence of overpressured water among clay platelets can prevent mechanical deformation of the kerogen structure that occurs when the organic matter contributes to support the lithostatic pressure. Undeformed kerogen grains will then resist temperature more than loaded grains." This situation is similar to the condition within the Akata Formation and it is doubtful if maturation of organic matter occurs within the formation. 21 7 GROWTH FAULTS AND OIL MIGRATION IN THE NIGER DELTA The mechanism of migration of petroleum in general is still a matter of controversy. Smith (1971), Dickey (1975); Magara (1978; 1979 1980 a & b); Jones (1978; 1981) Momper (1978); McAuliffe (1978;1979); Barker (1977); Weyer & Van Everdinger (1979): Hobson (1980) and Price 1980; 1981) are a few that have worked on this subject in the recent past. In the Niger delta in particular, Weber & Daukoru (1975) and Weber et. al. (1978) have made the major contributions. The several theories on the primary migration of petroleum proposed so far can be broadly divided into two Those associated with solubility of petroleum in water (Barker, 1972; Price; 1976, Magara, 1978; 1981) and those not associated with water (Hobson, 1954; Dickey, 1975). The concensus these days is that both processes contribute to the migration of petroleum. The water associated migration is more important at shallower depth where active dewatering of clays take place and provide the water for migration. After the dewatering of clays and at greater depths, the non-water associated processes become dominant. In the Niger delta, the growth faults (described in section 2.3) are believed to provide the path ways for fluid migration including petroleum. Such faults would normally present avenues for the migration of fluids if they remain open. However, while faults in rigid rocks often do remain open, those in plastic rocks such as the Akata shales tend to close or seal up (Neglia 1979). In addition, the growth faults of the Niger delta are known to penetrate only a limited distance into the Akata shales. These facts throw considerable doubt on the up- fault migration proposed by Weber & Daukoru, (1975) and reiterated by Ekweozor & Okoye, (1980) as a mechanism for the 218 Figure 6.1 Diagramatic representation of the behaviour of sandstone and shale beds during shear faulting. Note similarity between experimental results and observation in nature. (After Ueber et. al. 1978). / 219 transfer of hydrocarbons from the Akata shales into the Agbada reservoirs. About this possibility, Evamy et. al. (1978 p.2l) stated: "faults at depth within the shales are not considered to provide effective migration paths." Even proponents of this migration mechanism (e.g. Weber et. al. 1978 p.2643) admitted to its limited effectiveness. World-wide evidence of petroleum occurrences indicate that, more commonly, faults act as barriers rather than conduits (Weeks 1961 p.41) and this is more so in cases where oil and gases are trapped against them as is commonly the case in the Niger delta. Extensive shale smearing along faults is known to have been widespread and has been cited by Weber & Daukoru, (1975), as a dominant trapping mechanism in the area. Weber et. al. (1978) using information from experimental simulation of shear faulting as well as field observations of growth faulting in Germany concluded that migration of petroleum occurred along the sand stringers that bridge two sand beds (Fig. 6.1). The situation described in their paper is applicable to an alternating sand and shale sequence similar to that in the Agbada Formation. The same situation does not exist between, the Ak&ta and Agbada Formations and migration up the fault is not guaranteed. Evamy et. al. (1978) suggested that migration of fluids first take place across the fault from the overpressured shales on the upthrown side to the reservoirs on the downthrown side. From there the fluids migrate by a process similar to that proposed by Weber et. al. (1978) up the fault into higher reservoirs. The present writer considers that while this mechanism may operate, it is not the main method of transfer, for the following reasons:- Figure 6.2 Cross - section through the Jones Creek field showing fluid contacts and the hydrocarbon fill per reservoir. (Modified from Ueber et. al. 1978). 221 1. Fluid contacts in many reservoirs in the Niger delta (Fig. 6.2) show that both similar and dissimilar contacts occur along a single growth fault in the field. Similar fluid contacts across a fault indicate that fluid migration has occurred across the fault while the converse may be true for dissimilar fluid contacts across a fault. The conditions governing this have been discussed by Smith (1980). The co-existence of both contacts in a multiple reservoir stack situation along a single fault, shows that the growth faults may be sealing in some parts and non sealing in others. In such a situation, it is difficult to envisage a mechanism that can migrate petroleum upward along such faults through the numerous sealing sections of the fault into shallower reservoirs. 2. Again if credence is to be given to the fault guided mechanism of hydrocarbon migration, it would be expected that in fields where multiple reservoirs exist one above the other, the deeper reservoirs would contain predominantly gas and will be filled to the spill point in all cases (Gussow's principle) (Fig. 6.3). In the Niger delta where structures are not regular anticlines, it would be expected that the deeper reservoirs should show a higher hydrocarbon-fill in relation to structural closure than the shallower reservoirs. The observed pattern of hydrocarbon accumulation in the Niger delta (Fig. 6.2) shows almost the reverse of this expectation and thicknesses of accumulations are random. It would therefore appear that factors other than up fault migration of hydrocarbons may be responsible for these accumulations. The generative capabilities of the adjacent shales to the reservoirs, of the Agbada Formation appear to be one of the major controlling factors in deciding the volume of hydrocarbons released to the reservoirs. This view is in accordance with the earlier suggestions of Short & Stauble (1967); Frankl & Cordy (1967) and Reed (1969). 222 T RA P 1 2 3 A TRA P 1 2 3 TRAP 1 2 3 Figure 6.3 Schematic representation of the principle of selective trapping of oil and gas in a basin. Gas being lighter occupies the highest point of the reservoir, oil fills the rest of the reservoir to the spill point and migrates to the next trap. The net result is that the deeper traps are filled with gas while the shallower ones are filled with oil. (After Gussow 1953) 223 Weber et. al (1978 p. 2644) stated, " ...nowhere do we observe an accumulation in the downthrown block trapped against a growth fault, unless it is in juxtaposition with overpressured beds across the fault". From the present writer's personal knowledge of the Niger delta, this claim is contrary to the observed pattern of hydrocarbon accumulation in the area. For example, Poston et. al. (1980) using field evidence from Meren field wrote, "The plane of the major growth fault of the Meren field has been penetrated by six wells and the upthrown side has never been found to be overpressured.... The study of the oil trapping characteristics in the Meren field 1B1 fault block indicates that the juxtaposition of the oil reservoirs against overpressured shale is not an essential requirement for the form- ation of lengthy oil columns in Nigerian reservoirs." Despite this observation, they went on to conclude that hydrocarbon distribution between fault blocks was a factor of the migrating path rather than in situ conditions but also noted its inadequacy to explain gas and oil segregations within fields. 6.4 NON FAULTED RESERVOIRS Most accumulations of hydrocarbons in the Niger delta are fault controlled. This is not surprising considering the fact that growth faulting was an important factor during deposition, (see section 2.3) However, the presence of hydrocarbon accumula- tions in unfaulted reservoirs such as in shell's Egbema West field indicates that growth faults may not be a major factor responsible for hydrocarbon migration into reservoirs. This evidence strongly downgrades the theory that the Akata Formation is the major source of hydrocarbon in the Niger delta, rather it indicates that the hydrocarbons have been generated in the paralic Agbada shales surrounding the porous reservoirs. 224 The presence of such major hydrocarbon accumulations support the case for the maturity of Agbada shales and point to the fact that the presence of reservoirs to which the sources can release their hydrocarbons could be necessary for a continuation of the maturation process. Otherwise, as in the case of overpressured shale, the pore fluids in contact with the kerogen being matured become saturated with the end products and the reaction is inhibited. VARIATION IN CRUDE PROPERTIES The disparity in hydrocarbon properties that exist both laterally and vertically between and within fields, coupled with the erratic distribution of oil and gas in any one field or province, make it impossible to group all the hydrocarbons of the Niger delta together as having been derived from any one source bed. The variation in crude type is best explained by variation in kerogen quality rather than any fractionation or separation that may be imposed by the method and path of migration as suggested by Poston et. al. (1980). Although the kerogen is broadly type II, it contains varying mixtures of type I and III materials (Fig. 5.7). This no doubt will affect the nature of the generated products. Reed, (1969) showed that the variation in type and properties of hydrocarbons in successive reservoirs in any one well (e.g. Okan 4) could be closely related to the differences in the depositional environments and by cor ollary the kerogen type of the shales contiguous to the reservoirs. Coupled with the variation in kerogen type is the variation in geothermal gradients in the Niger delta. When these factors are combined, the variation in crude properties can be easily explained. These facts form the basis of the conclusion reached by earlier workers (Short & Stauble, 1967; Frankl & Cordry, 1967; and Ree d, 1969) that the paralic Agbada shales probably source 225 the reservoirs of the Niger delta. 6.6 EVIDENCE FROM INORGANIC DIAGENETIC STUDIES The problem "of source bed recognition in the Niger delta or indeed anywhere else in the world, cannot be divorced from the question of time of hydrocarbon accumulation. One method of estimating this is by comparing the degree of diagenetic mineral development in oil and gas bearing reservoirs with that in water bearing ones. In chapters 3 and 4 of this thesis, a discussion of the diagenesis of the sandstones of the Niger delta was presented. Most relevant to the present discussion is the difference in clay mineral assemblage between those reservoirs that contain hydrocarbons and those which do not. Kaolinite is the dominant diagenetic mineral in hydrocarbon zones while non hydrocarbon zones contain smectite, mixed layer clays together with siderite, pyrite and calcite in addition to kaolinite. This observation implies that an early entry of hydrocarbons into the reservoirs of this province stopped further diagenesis. This conclusion is buttressed by the earlier studies of Yurkova, (1970): Sarkisyan, (1972); Levandowsky et. al.(1973);Webb,(1974) ; Wilson (1975) and Hancock, (1978) who have shown that the entry of hydrocarbons into reservoirs inhibit diagenetic mineral development or alterations which continued unabated in the water zones. The presence of kaolinite alone in the hydrocarbon reservoirs suggests that conditions were slightly acidic prior to entry of hydrocarbons into them. Such conditions normally exist at shallower depths where the influence of fresh and meteoric water is important. If entry of hydrocarbons was late, then generation of kaolinite and indeed other authigenic minerals would have been continued as it did in the non hydrocarbon bearing sandstones. 226 Although under normal conditions, the concept of late hydro- carbon generation with increasing depth of burial is well established, Tissot and Welte, (1978 p.194) have documented "examples of quick and early generation of hydrocarbons in sedimentary areas where the rate of subsidence and therefore deposition has been very high and geothermal gradient abnormally important in relation to global tectonic phenomena." Mention was specifically made that such situation might occur in rift- related sedimentary environments where initial thinning accentuates geothermal temperatures. It is known that the South Atlantic rifting marked the beginning of a period of rapid sedimentation and concomitant synsedimentary tectonism which resulted in the present day Niger delta. The Agbada Formation, where rapid sedimentation has produced a characteristic 1:1 shale/sandstone ratio would be a most favourable environment for the early generation and migration of hydrocarbons (Egbogah & Lambert- Aikhionbare, 1980; see appendix. The evidence from clay diagenesis in the shales of this province is also in favour of hydrocarbon generation and migration within the Agbada shales. The initial stages of alteration of clays (particularly smectite) to mixed layer clays and later to illite is important in the migration of generated hydrocarbons (Burst, 1959; Perry & Hower, 1972; Blatt, 1979) as these processes produce free water. Alteration to mixed layer clays is fairly common in the Agbada Formation as well as in the normally compacted upper section of the Akata Formation (which is considered as a part of the Agbada in this thesis). Below this the smectite content of the overpressured zone is preserved with little or no change even at temperatures in excess of 120°C and depths of burial of approximately 4,000m (see section 4*3.3). Therefore, 227 it can be argued that below the base of the normally compacted section of the Akata Formation, little fluid expulsion has occurred from the formation. Chapman, (1972) has suggested that petroleum expulsion from a clay source rock cannot occur in quantity if the diagenesis of most of the organic matter takes place after the expulsion of the bulk of the interstitial liquid. He further proposed that if stress equilibrium is maintained between liquids and solids, most of the liquid is expelled at depths of 700-1,000m and that petroleum thus expelled is that generated under such conditions of temperature and pressure. Subsequent burial below this point may lead to increased maturity but the products will most likely remain in the clay. The above situation is analogous to the conditions in the Niger delta. Many of the shales in the Agbada Formation are normally compacted and therefore would have expelled a large part of their interstitial fluids. The presence of a large proportion of mixed layer clays in many of these beds is a confirmation of this. It is therefore important to petroleum exploration in the Niger delta, that the base of the normally compacted shale sequence (the top of the overpressured zone) be accurately delineated. This base could mark the lower limit below which, petroleum generation and migration from Tertiary shales is highly unlikely in the Niger delta. Calculations of bottom hole temperatures from the data of Avbovbo, (1978b) gave values between 120°C-14;QOC at depths corresponding to 3, 000m-4, 000m depending on location in the Niger delta. These values are close to the upper temperature limit (150°C) of the oil window. It would appear to suggest that the deepest wells which are of the order of 4,500m are close to the limit of oil generation in the Tertiary Niger delta. 228 Below this zone, it is possible that only wet gas and/or dry gas phase will dominate. However, the large variations that exist in temperature gradients over the delta prevents a firm conclusion being reached on this subject at the present time. It should be pointed out however that the apparent increase in gas/oil ratio observed in an offshore direction in the province is probably a manifestation of thermal gas generation. As established in chapter 5, paralic shales of the Agbada Formation (which are normally compacted) deeper than an average depth of 1,700m are capable of generating hydrocarbons. Arguing along the lines of Chapman (1972)-, such petroleum would have been released with the water during compaction and clay diagenesis. Many of the shales of the Agbada Formation are at moderate depths and show evidence of diagenetic clay transformation. It can be concluded therefore that the water released from them have played a role in primary migration. The low level of clay transformation in such beds probably explains the small to medium sized hydro- carbon accumulations in the reservoirs of this province. Only those hydrocarbons which were generated prior to or at the time of final dewatering of the clays were released to the reservoirs. It can also be concluded that since smectite is still present in many beds, that the dominant migration phase is that association with primary dewatering of the clays. If non-water associated migration occurs, its effect is relatively minor at this stage. 6.7 DISCUSSION It must be reiterated here that the argument about the source of the hydrocarbons in the Niger delta will go on for a long time. The major reason for this is that many of the geo- chemical techniques currently in use for measuring organic maturation are inconclusive when employed on the sediments of this area because of their peculiar thermal history. From personal experience the writer is aware of at least three geochemical 229 TABLE 6.1 ANALYSIS OF ORGANIC CONTENT OF SHALES FROM CAWTHORNE CHANNEL 2 (FROM EKWEOZOR & OKOYE 1980) Organic Soluble Hydrocarbon Soluble Hydrocarbon Depth Sample Carbon Organic Fraction Organic Fraction(mg) No. (m) ($) Matter (Saturated) Matter(mg)/ Total Orga- (ppm) (ppm) Total Orga- nic Carbon nic Carbon (g) (g) 46 810 1.9 1,330 90 72 5 47 896 2.0 1,270 120 63 6 48 953 0.5 160 5 33 1 49 1,074 4.4 1,830 165 41 4 50 1,563 1.3 350 n.d. 27 n.d, 51 2,025 1.2 610 95 50 8 52 3,354 2.0 760 125 37 6 53 3, 622 1.1 1,270 120 115 11 TABLE 6.1 ANALYSIS OF ORGANIC CONTENT OF SHALES FROM CAWTHORNE CHANNEL 9 Soluble Hydrocarbon Soluble Hydrocarbon Sample Organic Fraction Organic Fraction(mg)/ No. (m) Matter (Saturated) Matter(mg)/ Total Orga- (ppm) (ppm) Total Orga- nic Carbon nic Carbon (g (e) 54 2,760 1.6 1,000 15 61 10 55 2,830 1.7 770 10 46 5 56 2,899 1.4 300 5 21 3 57 2,960 1.5 450 20 30 15 58 3,195 1.3 1,140 5 88 5 59 3,258 1.1 500 5 44 3 60 3,292 1.6 450 30 39 2 61 3,352 3.7 990 10 27 2 62 3,401 1.5 1,010 125 66 80 63 3,487 1.2 1,560 110 136 95 2 30 studies commissioned by operating companies in Nigeria between 1972 and 1975, each of which has proved inconclusive. The writer believes that a comprehensive evaluation of all available data is necessary for the best possible conclusion to be reached. Previous discussions in this chapter have sought to establish by indirect evidence that the Agbada rather than the Akata shales are the source rocks for the Niger delta petroleum. Presented below are the results of previous geochemical analyses which directly indicate the generative capability of the Agbada shales. These indications were inadvertently overlooked in such previous interpretations. Ekweozor & Okoye (1980 table 3 & 4; reproduced here as table 6.1 a & b) in interpreting their extract data neglected the high values at shallower depths and established a threshold depth for the principal phase much below them. In doing so they missed the significance of these high extract values at shallow depth. These high extract values most probably indicate those beds in which hydrocarbon generation occurred after the expulsion of the bulk of interstitial fluids (see Chapman 1972 and section 6.6 of this thesis). -Such beds would have a high extractable bitumen content and possibly a low C^/C^ ratio if the bitumens are not extracted prior to pyrolysis. Although Ekweozor and Okoye (op.cit.) did not comment on the low extract values, the present writer is of the opinion that these values represent those beds from which both hydrocarbon generation and migration have occurred (see Fujita, 1977; Magara, 1980). The high values, interspers- ing the low ones, indicate that petroleum generation has occurred at such shallow depths. Similarly in interpreting their vitrinite reflectance data, Ekweozor & Okoye, (op.cit) chose a threshold value of Ro$=0.54« 231 While the general reliability of reflectance measurement is not in doubt, it must be pointed out that the recommended minimum reflectance of Ro$=0.6 (Dow, 1978) is arbitrary and that maturation values may range between Ro$=0.3-0.8, depending on the vitrinite type (MaCartney and Teichmuller, 1972). For example if the vitrinite type is predominantly desmocollinite, the reflectance would show a much lower value at a specific degree of carbonisa- tion when compared with a sample rich in Tellocollinite. Such a desmocollinite-rich sample could be erroneously evaluated as an immature source bed if the normally recommended minimum value (Ro$=0.6) is adopted. On the other hand, Fisher (1979 unpubl Ph.D thesis) working on samples from the western Niger delta obtained vitrinite reflectance values higher than those of Ekweozor & Okoye (1980). Fisher's data show that samples from as shallow as 1,500m in many wells attain Ro$=0.$ which confirms the conclusion of Evamy et.al. (1978) that beds in the western Niger delta attain a higher level of maturation than those in the east. Considering all of the above, it is concluded in this study that the paralic shales of the Agbada Formation below a depth of 1,700m provide the hydrocarbons of the Niger delta. The early generation and migration of the hydrocarbons, coupled with the variation in organic content best explains the erratic distribution of crudes as well as their volume and properties. 232 CHAPTER 7 SUMMARY, CONCLUSIONS AND RECOMMENDATIONS SUMMARY AND CONCLUSIONS The modern Niger delta, covering an area of 64,000 sq. km. of the southern Nigerian basin, developed as a result of the rifting and separation of Africa from South America in Cretaceous times. The rifting in the Gulf of Guinea extended inland in the Upper Cretaceous and reached the rivers Niger and Benue in the Palaeocene. The sediment discharge of these rivers was immediately diverted southwards to the sea and thus began the development of the Niger delta. Progradation began in the Eocene, leading to the formation of the sedimentary wedge now known as the Modern Niger delta. The three lithostratigraphic units of the Niger delta are diachronous and consist from the bottom of,the Akata Formation (pro-delta shales of Eocene to Recent), the Agbada Formation (a sequence of sandstones and shales of Eocene to Recent) and the Benin Formation (Massive sands of Oligocene to Recent). Although the subdivision has been retained in this thesis, new boundaries based on physical parameters have been proposed. The physical parameters like resistivity of the formation water and state of compaction of the shales are log measurable and therefore less tedious to determine in routine oil company work. The Agbada Formation is the most petroliferous and therefore most economically important of the three. The growth faults are the major structural elements of the Niger delta. Combined with the associated roll-over anticlines, they form the major hydrocarbon trapping mechanism in the province. Petrological analyses of the sands of the Agbada Formation show quartz as the dominant mineral comprising between 80$ and 95$ of the mineral composition. Feldspars, clays and other minerals 233 each comprise less than 5% of mineral composition. Most of the samples analysed can therefore be classified as quartz arenites. Diagenetic minerals comprise less than 1% of total mineral compo- sition and consist of siderite, calcite, pyrite as well as clays. Matrix content is relatively high in many samples and it forms the major binding material in many reservoir sands. Variations observed in assemblage as well as in the physical characteristics of minerals, between the sediments of the eastern and western Niger delta are interpreted as related to the proximity of the source of sediments in both parts. In terms of diagenesis, the shales and sandstones of the Akata and Agbada Formations have attained low to moderate levels of transformation with increased burial depth. The clay mineralogy largely reflects the variations 'in the detrital clay assemblage particularly between the Akata and Agbada shales. The high smectite content (30-50$) and low kaolinite (20-60$) of the Akata shales compared with the low smectite (0-30$) and high kaolinite (40-70$) of the Agbada Formation is explained in terms of differential settling of the clay minerals. Alteration of smectite to illite-smectite mixed layers appear to occur mainly in the Agbada Formation. Even then it occurs randomly. Diagenetic alteration of clays within the Agbada Formation broadly follows the established pattern of clay transformation to the mi.xed layer phases starting from a tempera- ture of 80°C. In the Agbada Formation, mixed layer phases are recorded in beds at depths of 1,700m and burial temperatures of 90°C. However, in the Akata Formation smectite remains in the hydrated state even at depths of 3,500m and burial temperatures of 120°C. The preservation of smectite at burial temperatures in excess of what might be expected from the accepted model of clay diagenesis indicate that perha.ps factors other than temperatures are important in the 234 diagenetic transformation of clays in this region. The under- compaction of the shale of the Akata Formation is thought to be a major factor in this respect. In the Agbada Formation, there are significant differences between the clay mineral assemblages of the water-bearing and hydrocarbon-bearing sandstone reservoirs. In the latter the early migration of hydrocarbons into the reservoir sands limited the development of diagenetic clays by preserving the early formed diagenetic kaolinite and preventing its corrosion and the formation of diagenetic smectite as found in the water-bearing sandstones. This evidence for early migration of hydrocarbons also lends support to the concept of the generation of hydrocarbons in the paralic Agbada shales adjacent to the reservoirs rather than in the more distant Akata shales. However, this distinction between water-bearing and oil-bearing sandstones is not always straightfoward. In places where the flushing of the formation water is not efficient,diagenetic mineral precipitation continues in both oil and water zones. When this happens the increased water saturation results in low resitivity which may make it difficult to identify the zone as oil-bearing. The sandstones of the Agbada Formation are poorly cemented and friable. Poor cementation is attributed to the low supply of cementing materials. Of importance in this region are, the low level of pressure solution, the low level of diagenetic transformation of clays, the low level of substitution of calcite for quartz as well as the low solubility of silica in the formation waters of the Agbada formation. The near absence of these processes which should have contributed silica to the pore solutions of this region are considered to be the principal causes for the poor development of silica cement in the sandstones. 235 Calcite is derived mainly from dissolution of shells. Its early precipitation at shallow depth helped to prevent mechanical packing and therefore, pressure solution. With increased burial depth and the release of CO^ from maturing organic matter, most of the calcite goes into solution. However, sufficient secondary siderite is precipitated to replace it and prevent collapse of the sediments. A major consequence of the very friable nature of the reservoir sandstones is that the migration of fluids through them results in the movement of fines which may cause problems in the recovery of hydrocarbons from the reservoirs. The movement of fines in this region is not so much a problem in petroleum reservoirs as it is in the water-bearing sandstones. In petroleum reservoirs kaolinite, which is the major destroyer of permeability is produced, at the surface >with the crude oil, because of the large pore spaces. Thus the permeability problem is prevented. The chemical and optical analyses of the kerogen isolated from the shales of the Agbada and Akata Formations reveal that they are dominantly type II, containing varying proportions of types I and III. Although humic materials are present they constitute only minor proportions of the organic matter. Based on this determination of organic matter type, the interpretations of the C^/C.j, data as well as the carbonisation data indicate that many of the shales of the Agbada Formation below depths of 1,700m are mature. However, many samples at depths of 3,800m have still not been subjected to conditions higher than middle catagenesis. Samples of the Akata shales are still largely immature indicating that under-compaction of shales is a factor that could prevent the maturation of organic matter. This correlation between clay dewatering, clay transformation and 236 kerogen maturation is important in that it reveals the importance of clay dewatering to the process of petroleum generation and migration. When the above data are combined with the following geological data: - a) the over pressuring of the Akata Formation and its implication on petroleum generation and migration in the area. b) the presence within the Agbada Formation of unfaulted stratigraphic accumulations. c) the evidence of early migration deduced from diagenetic studies, it can be concluded that the Agbada Formation is the major source of hydrocarbons in the Niger delta. RECOMMENDATIONS The scarcity of samples prevented the full investigation of many of the observations made during this study. A combined effort between the petroleum industry in Nigeria and the research bodies should be made to systematically sample the Agbada and Akata Formation with a view to testing the model of diagenesis presented in this thesis. Of particular importance are the following:- a) The few samples of the Akata Formation analysed have shown the significant difference between the clay diagenesis in the Akata and Agbada Formations. This difference is important to understanding the processes of petroleum generation and migration in the Niger delta. More samples of the Akata shales should be obtained in order to fully establish the state of compaction and preservations of their clays. 237 b) One major draw-back in the use of the level of diagenesis of the rocks to predict the time of migration of hydrocarbons have been pointed out. There may be other factors such as the facies distribution that may affect this parameter. Such factors should be identified and investigated by sampling more water- bearing and hydrocarbon-bearing sandstones. c) The effects of the environment of deposition on the diagenesis of the sediments of the Niger delta have not been investigated during this study. The major factor against this has been the small size of many samples which prevented sedimen- tological analyses. Effort should be made to obtain full bore cores which will allow sedimentological analyses and investigation of the effects of the environment of deposition on diagenesis in the Niger delta. d) The movement of fines within the sandstones of the Agbada Formation should be investigated and the parameters controlling their movement should be determined. In particular the intricate facies relationships of the shale laminae within many sandstones should be established before embarking on enhanced recovery processes . e) More shale samples of the Agbada Formation should be obtained over the entire delta in order to establish the major role of this formation in petroleum generation in the Niger delta. Of particular importance is the role of faults in the migration of hydrocarbons in this region. Their role can be more accurately determined if the source potentials of the numerous shale beds of the Agbada Formation are known. 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Contributions to sedimentology 8, pp. 69. 270 LIST OF SAMPLES ANALYSED PER FIELD SAMPLE DEPTH SAMPLE ORGANIC IN FEET NUMBER THIN SECTION XRD SEM GEOCHEM MEREN FIELD 2950 K/W/9 X X X 3150 X X 3150 X X 33 03 3450 X X X 3650 K/W/22 X X X 4150 X 4155 X X 4337 X X 4720 X X 4760 X X 5035 X 5156 X X 5265 W/50 X X 5310 S/36,K/W/24 X X X 5311 M/l8,K/W/8 X X X 5319 X 5313 M/26 X X X 5314 X 5329-30 X 5331 S/M/10 X X X 5351 (2) X X X 5380 X 5403 X 5411 X 5432 K/42 X SAMPLE 271 DEPTH SAMPLE ORGANIC IN FEET NUMBER THIN SECTION XRD SEM GEOCHEM 5455 x x 5691 X 5673 X 5700 M/23 X X 5705 S/M/29 X X 5721 X 5730 X X 573 2 X X 5765 X X 5885 X 5895 X 5910 K/W/20 5935 X 5966 S/M/7 x X 6195 X 6230 x 6237 x X X 6252 (2) M/13 X X 6260 X X 6270 S/38, W/53 X X X X 6280 X 6375 K/l X X X 6379 S/M/24 X X X 6405 X X 6389 X X X 6411 S/M/32 x X 6432 M/U,X/U/18 x X X 6675 X X 6820 X 6852 S/M/22 X X 272 SAMPLE DEPTH SAMPLE ORGANIC IN FEET NUMBER THIN SECTION XRD SEM GEOCHEM 6892 x 6918 X 6961 K/W/21 X X 6971 K/W/16 X X X 6973 M/26 x X X X 7016 X 7070 X 7352 W/13 X X 7560 K/34 X X X 8340 W/45 X X 8556 W/46 X X X 8748 W/47 X X 8848 W/48 X X X 273 SAMPLE ORGANIC DEPTH SAMPLE XRD GEOCHEM IN FEET NUMBER THIN SECTION SEM MAKARABA FIELD 4047 K/W/35 X X x 4136 X 4212 S/M/17 x X 4437 X X 4616 X X 5800 X X 5923 X X 6222 S/M/19 X X 6226 X X 6556 X X X 6653 K/V7/21 X X X 6742 X 6841 X X 6969 X X 7176 X X 9158 X X 10423 X X 10600 X X 10617 X X X 10840 K/W/5 X X X 10938 X SAMPLE Z I H DEPTH SAMPLE ORGANIC THIN SECTION XRD SEM IN FEET NUMBER GEOCHEM OPOLO FIELD 3597 X X X 3662 X X 3668 X X X 5597 X 6300 K/W/33 X 6550 S/M/l X X 7250 K/W/15 X X X 7864 X X 8286 M/12 X X X 8778 X 8872 M/35 X X 9030 X X X 9250 X X 9308 X X 9560 X 9716 X X X 9736 S/M/6 X X 9808 S/M/5 X X X 10023 X X X DELTA SOUTH FIELD 4080 S/M/25 X X 6823 X X X 8652 X 6862 S/M/21 X X 6866 X 6994 K/W/32 X X X 7011 X X 7012 X 7030 X X X 275 SAMPLE DEPTH SAMPLE ORGAN IC IN FEET NUMBER THIN SECTION XRD SEM GEOCHEM 7038 x x 7098 X X 7102 K/2 X X 7286 M/3 X 7292 X 7560 X 8394 S/M/ll x X 8486 X 8488 X 8704 K/30 X X X 8710 K/W/3 X X X 8931 X X X 8945 X X 9087 X X OLURE FIELD 7113 X X X 9968 X X 10290 S/M/33 x X X 11395 X X X 11512 K/W/27 x X X X 11598 X X X 12010 X X X ISAN FIELD 5992 X X 6466 S/M/4 X X 7332 X 8128 X 8451 S/M/9 x X 9419 X SAMPLE 276k DEPTH SAMPLE ORGAN IC IN FEET NUMBER THIN SECTION XRD SEM GEOCHEM W. ISAN FIELD 5117 W/68 x X 5230 X X 5700 X X 6229 X X X 8901 x X X X GBOKODA FIELD 9556 W/50 X x 9896 X 10164 X X X 10582 w/67 X X X ROBERTKIRI FIELD 3497 W/63 X X X 5652 H/W/4 X X X 6827 S/4 X X 6810 X X 7103 K/W/29 X X 8110 W/64 X X 9320 X 9562 X X X 10531 X X 10554 X X 10580 X X 11815 S/M/18 X X X 11821 S/M/15 X X X 11837 X X 11843 S/M/34 X X 11850 X X 11870 S/M/27 X X 277k SAMPLE DEPTH SAMPLE ORGANIC IN FEET NUMBER THIN SECTION XRD SEM GEOCHEM 12750 K/W/13 xx x 13416 x x 13482 x xx IDAMA FIELD 6827 x xx 8110 S/41 x x x 9562 X X 10531 x x 10580 x X OYOT FIELD 778 5 K/V7/23 xx x 7885 K/W/19 x x x 7790 x x 77 96 W/66 X X 7802 x 7952 S/29 X 7970 x 8004 S/M/28 x x 8014 x 8030 x x 8060 S/M/2 x x 8100 x 8126 x x x 8136 x 8152 8200 x X 211k SAMPLE DEPTH SAMPLE THIN ORGANIC IN FEET NUMBER SECTION XRD SEM NUMBER AKATA FIELD 10140 x 10 830 X 11080 K/W/36 X 11140 K/WK37 X EBUBU FIELD 11930 K/38 x 11940 K/39 x 11945 K/40 X 11960 K/41 X K - DLK, Organic geochemistry, kerogen analysis. M - DLM, Matrix analysis by micro sieve. S - DLS, Thin section analysis. V/ - DLW, Organic geochemistry whole rock. Frankl and Cordry (1967), Weber (1971), Merki (1972), Murat (1972) and Schematic cross-section* Weber and Daukoru (1975). The stratigraphy of the Niger Delta subsurface has been simplified and divided into three rock stratigraphic units: Benin, Agbada, and Akata for- mations. The type section and the descriptions of these units (Fig. 1) have been given in Short and Stauble (1967). The deposition of these units and the history of progradation of the Niger delta have been attributed to 3 Possible new oil potentials 0«*MJf depositional cycles. The oldest of these 'a, Delta llwt, ItTIl. etaMM Itata Metal (1111) e*e Wefee, (Wl. I, I cycles extended from Albian to San- tonian, and the youngest, from lower Eocene to the present. The middle of the Niger delta cycle covered the period from Cam- panian to Paleocene. It is believed that The first commercial oil find was the necessity to construct a large, the progradation of the delta started E. Onu Egbogah* made at Oloibiri in 1955, although gas costly gas gathering system in the Flj. 1 in the third cycle. This cycle is also Dept. of Petroleum Engineering and oil shows had been encountered marshy terrain of the Niger delta. If represented by the modern Niger delta University of Ibadan Table of formations in earlier wells at Awka, Akata and plans proceed on schedule, the plant and is regarded as the most important Ibadan, Nigeria Aba. Oloibiri discovery was followed could be fully operational by the end by intensive drilling activity. Success in terms of oil generation and accumu- f SUBSURFACE SURFACE OUTCROPS of 1980, and by the end of the decade lation. D. 0. Lambert-Aikhionbare ratio for wells drilled in Nigeria over Nigeria's foreign exchange earnings YOUNGEST OLOEST YOUNGEST OLDEST KNOWN AGE KNOWN AGE KNOWN AGE KNOWN AGE the last five years averages about from gas could well overshadow those The three units have been accepted Geology Department 80%. This figure, although high, is from oil. as rough representations of the delta Royal School of Mines BENIN FORMATION PLIO. RECENT 01K30CENE BENIN FORMATION PLEISTOCENE MIOCENE? fairly representative of the history of Production levels in Nigeria (Table top, delta slope and delta front de- Imperial College | AFORN Quo IBM j the oil industry in Nigeria. Departures posits, respectively. Recognition of the London OGWASHI-ASABA 1) have, in the main, been determined MIOCENE OLICOCENE RECENT AGB*CA FORMAT^N EOCENE FORMATION from the high percentage success by world market demand than by the submarine fan environment has led THE role of the Nigerian oil in the EOCENE AMEKI FORMATION EOCENE ratio are, among other things, at- country's own energy requirements. Burke (1972) to propose a new sym- AKATA FORMATION IMO tributed to fluctuating government RECENT EOCENE LEOCENE PALEOCENE However, the government conserva- metrical five-layer interpretation of total world energy supply system can FORMATION be assessed in terms of the nation's policies. tion policies have occasionally dictated the structure of the Niger delta (Fig. proved (and/or potential) reserves and PALEOCENE NSUKKA FM. MAESTRICHTIAN With exploratory drilling success the pace of both production and allied 2). production level. MAESTRICHT1AN AJALL FORMATION MAESTRICHTIAN ratio of 45-60%/year, Nigeria's ex- exploration activities. Production from The three units lend themselves to IS) CAMRANIAN UAMU FORMATION CAMRANIAN With proved reserves of about 19 EOUTVALE NTS NOT KNOWN ploratory drilling successes rank most of the Nigerian fields come from easy recognition due to their different -s) billion bbl of oil (and 115 billion bbl CAMP. MAE ST. NKPORO SHALE SANTOMAN among the highest in the world. The very porous tertiary sandstones of the distinctive lithoiogic, resistivity, and CD CONIACIAN/ depths for exploratory drilling ranged Agbada series, which sometimes con- other log characteristics. The bound- of potential oil reserves) Nigeria con- AWGU SHALE TURONiAN &ANTONIAN between 2,100-3,100 m; however, over tain oil and associated gas, and some- ary of the Benin formation has been trols about 34% of Africa's reserves EZE AKU SHALE TURONIAN TURON1AN the past 5 years, necessity for deeper times only nonassociated gas. put at the first appearance of marine and 3.2% of the entire world proved 1 FROM SAON T-4 STAT**, M? ALBIAN ASU RIVER CROUP ALBtAN j reserves. v 1 discoveries and offshore operation The accumulations are numerous shales. This is generally easily recog- It has also been estimated (Egbo- have led to increased drilling depths but relatively small, with several nized either on the spontaneous poten- gah. 1978) that Nigeria's gas potential of up to 4,600 m. sandstone reservoirs in each. De- tial log or the gamma ray log. This is enormous, probably exceeded only tinuing Iranian crisis. opinion realistic for Nigeria. The com- There are currently over 120 oil velopment therefore is more complex lower boundary is however roughly by the U.S.S.R. and Iran. It must be said that because of the pelling factor is the financial demands fields in Nigeria of which a significant than is the case with the large oil coincident with the first major break The importance of the Nigerian incentives provided by a more-far- of a recently elected presidential sys- porportion is producing. Production is accumulations in areas such as the (in resistivity log) from fresh to petroleum and natural gas resources sighted-than-most government, pro- tem of civilian government which will currently at an average of 2.42 rrllllion Middle East; however, there are still brackish or marine formation waters. therefot-e compels a review of the ex- ducers in Nigeria have kept working require all foreign exchange and other b/d. Associated gas is also produced a number of accumulations awaiting Although it has been demonstrated ploration and production activities of to further expand reserves and ex- revenues available to it for the con- from these fields but only a small production facilities, so it is probable that the base of the fresh water ex- a country which, during the last 30 plore for new oil during a buyer's tinued fulfillment and initiation of the proportion of this is utilized for fuel, that the Nigerian output will be in tends into underlying Agbada forma- years has emerged from the position market. With the situation in Iran nation's numerous and ambitious de- the rest being flared. Plans for ex- 2.8-2.5 mbpd in the 1980s. tion (Avbovdo, 1978) the authors be- of a virtual nonproducer in 1958 to bringing more pressure to bear on the velopment programs. ploring Nigeria's natural gas reserves Nigerian crude oils have a low sul- lieve that the resistivity break which that of the sixth largest oil producer Nigerian production, the authors be- The realization of the projected pro- are still in the works, and a con- fur and a high but variable paraffin is easily recognized in logs is good in the world today. lieve that the Nigerian government, duction levels are contingent upon sortium consisting of Phillips, Shell, content It has been suggested (Dickie, enough for routine jobs. The currently high demand for oil which derives 80% of the country's continued market demand, reasonable Agip, Elf and the state-owned NNPC 1966; Hedberg 1968) that some, at In places (mainly the present day throughout the world has allowed most national revenue and 90% of its for- political/conservation conditions with- (with 60% equity in all foreign oil least, of the source material was of swamps) where secondary fresh producer nations like Nigeria to in- eign exchange, will probably stretch in the producer nation, and perhaps companies) plans to build a 45 Mcfd terrestrial vegetable origin. Their low water occurs, this distinction is hard crease her production from a slump- its production to an estimated capacity application of suitable secondary (or liquefaction plant at Bonny Island. sulfur content makes these crudes to recognize on resistivity logs. The ing 1.752 million bbl daily average of 2.6 million bbl daily average in enhanced oil) recovery methods to Facilities would be supplied by. asso- particularly sought after in pollution- picture also further complicated in during the first 8 months of 1978 to 1980. This estimate is far in excess of various producing fields. ciated gas that is presently flared conscious countries. Furthermore, places by the.presence of clay mem- 2.399 mbpd at the same period in anticipated Nigerian output due to a Overview. Exploration for oil in Ni- and from nonassociated gas fields their closeness to seaboard and rela- bers (such as the Afam clay member 1979. 10% production cut which was or- geria began as long as 1908 when the discovered during the search for oil tive proximity to the markets of in the eastern flank of the delta). This reflects a daily average pro- dered by the Nigerian National Petro- Nigerian Bituminous Co. carried out (one such huge natural gas field was Britain, Europe, Africa, and the The boundary between the Agbada duction increase of 37%, which has leum Corporation (NNPC) in October shallow drilling for heavy oils in the struck at Awka-Ugwuoba region of the Americas, are additional reasons to and Akata formations is placed at the helped to offset the dwindling avail- 1979. outcrops of the Cretaceous sands in Anambra basin in 1954 but is still not explain the speed with which the oil deepest occurrence of deltaic sand- ability of crude supplies on the world In view of the continuing demand the western coastal part of Nigeria. developed due to the lack of interest fields of Nigeria have been developed. stones. The transition from the sand market as a consequence of the con- for the Nigerian premium crude, proj- Surveys using modern techniques on the part of the oil companies to Geology and stratigraphy. The geolo- shale sequence into predominantly ected production ranges of 2.8-2.5 were not carried out until 1937, and invest on the then cheap natural gas gy of the Niger delta as far as it re- shale zone is very easily identified on •Prcstnlly with AGAT Consultants Ltd.. mbpd and 2.5-2.0 mbpd for 1985 and there was cessation of operations dur- resource. lates to petroleum has been described the lithoiogic logs. Very few wells Calgary. 1990 respectively, are, in the authors' ing the 1939-45 second world war. The main obstacle to the project is previously by Short and Stauble (1967), have, however, drilled through the 176 OIL A GAS JOURNAL —APR. 14. 1980 178 OIL & GAS JOURNAL —APR. 14, 1980 ne. 3 Agbada as a source rock are the fol- The rollover anticlines associated with lowing points: Crude oil and natural these faults are generally several The authors . . Schematic section of Nigerian field 1. The relatively short migration kilometers in length and a few kilome- E Onu Egbogah is a history of the Nigerian oil indicates gas production in ters wide; they trend east-west and lecturer in petroleum that the Agbada is the most likely are roughly parallel to the present engineering at the Uni- source. If the Akata were the source, Nigeria, 1957-1980 coastline. The major growth faults versity of Ibadan, Ni- Bis/ generally have synthetic and antithetic geria. He holds an MSc migration from the Akata into the Oil Cos oil in geology from the upper part of the Agbada or the lower production production ratio compensating faults associated with Friendship University, part of the overlying Benin would in- (million (million (m> them (Fig. 3). Moscow; MSc from the Tear bbl) cam) bbD University of Alberta volve a vertical migration of at least A good description of these faults and PhD from Imperial 4 km. It is difficult to establish the 1957 0.014 and their mechanism of formation has College, University of pathway that would support such a 1953 1.874 45.560 24 been given by Merki (1972), and Weber London, both in petro- long migration. Moreover, the growth 1959 4.094 139.834 33 and Daukoru (1975). These faults are leum engineering. Dr. faults responsible for vertical migra- 1960 6.367 144.260 23 Egbogafr is an energy E. Onu Egbocah 1961 16.802 309.834 18 characterized by almost a total lack analyst who has written numerous papers on tion in the Delta have excessive curva- 1962 24.624 486.483 20 of correlation across the major growth the role of the U.S.S.R. on the total world tures at depth and run parallel to the 1963 27.914 625.406 22 faults. Gulf's Meren field offshore is energy supply system. He is currently con- bedding planes. This leads to the situa- 1964 43.997 1028.836 23 a good example of this structure. The centrating elforts on the assessment of Ni- tion where oil can only migrate from 1965 99.354 2406.026 24 Niger>delta is also associated with a geria's petroleum and natural gas supplies the topmost part of the Akata. 1966 152.427 2935.947 19 in the 1980s and through the turn of the 1967 117.120 2668.127 23 number of stratigraphic traps; one century. 2. The 1:1 sand-to-shale ratio of the 1968 51.906 1413.228 27 such field is Shell's Egbema-West in Agbada formation appears to be suit- 1969 197.225 4125.524 21 the western onshore area. Daniel Lambert-Aikhionbare is a lecturer in 1970 395.841 8037.048 20 geology at the University of Benin, Benin able for the generation and accumula- 1971 559.328 12796.325 23 Possible new plays. The dominance City, Nigeria. He holds BSc from the Univer- tion of petroleum. This relationship 1972 665.281 16796.193 25 of the growth fault system in the Niger sity of Ibadan, MSc from Imperial College, suggests rapid deposition and hence 1973 750.050 19831.504 26 delta and the ease of the discovery University of London, all in geology. Mr. rapid burial; this is one of the condi- 1974 815.748 20624.234 25 of the structures have overshadowed Lambert-Aikhionbare is currently on a sab- tions favorable for the formation of 1975 651.393 18436.672 28 batical leave at the Royal School of Mines, 1976 756.141 20831.428 28 the investigation and the drilling of London, where he is completing requirements hydrocarbon accumulation. The depo- 1977 758.991 20322.946 27 other deltaic type plays in the prov- for a PhD degree in geology. sition character here contrasts with 1978 695.488 15756.373 23 ince. the Akata shales which have been 1979 •848.920 •5756.374 Since the middle 1950s, when active identified as slow deposition cycles. 1980 t 791.028 t22300.000 exploration started in the Niger delta, mation, the distribution of freshwater- Akata formation. The base is there- updip through growth faults to ac- 3. Geothermal gradients established 894.250 no well has been drilled through the bearing strata of the Niger delta are for the Niger delta puts the oil window Source?: Annual Report, Ministry of entire thickness of the producing of considerable significance. In a coun- fore not clearly denned, although the cumulate in shallow reservoirs of the Mines and Power, Lagos; AAPG first appearance of a major uncon- overlying Agbada formation. at between 2,134 m and 7,012 m in the Bulletins. 'Oil and Gas Journal, Agbada formation. The deepest well try of perpetual water shortages such formity below the shale has been sug- A deltawide study of source-rock depocenter, and 7,012-2,226 m in the based on daily average production of drilled in the Niger delta is the Ekedie as Nigeria, the sections of Benin and ro gested by Short and Stauble (1967). properties by Shell-BP personnel northern part (Nwachukwu, 1976). Al- 2.408 million barrels for the first 8 2 well, 80 km west of Port Harcourt, Agbada formations can be useful months of 1979 plus 1094 reduced and drilled to a depth of 5,070 m in the The total sedimentary thickness of showed the samples to be consistently though Avbovbo (1978) has corrected daily average rate of 2.159 million sources of water supply to the urban VO the Niger delta has been estimated at very poor (Evamy et al, 1978). the gradients obtained by Nwachukwu, barrels for The rest cf 1979. tAulhors' Agbada formation. The depth to the communities in the delta area. over 12,200 m of section at the ap- Samples from a wide variety of depo- no significant shift has been shown in estimates: minimum production ca- top of the underlying Akata formation To date no effort has been made to the position of the oil window. This pacity based on 1094 production cut in Ekedie 2 is probably 5,580 m. proximate depocenter in the central sitional environments ranging from enforcement by NNPC; maximum drill through the Akata formation in part of the delta. Avbovbo (1978) pub- fully marine shales (Akata) through is considered a further evidence in production capacity based on analysis Consequently, a considerable section the central, northwestern, or eastern lished simplified isopach maps of the marine/ paralic to paralic shales support of the Agbada as a possible of world market demand in 1980. Gas of the Agbada formation remains flanks of the delta. The only wells (Agbada) were analyzed and found to source rock. production will jump to at least 22 Benin and Agbada formations, which billion cu m upon commissioning the largely unexplored, especially in the that have penetrated the total thick- when overlaid, indicate a southward contain low organic content of humic 4. If the growth fault system is the LNG plant at Bonny Island. Detailed areas of shallow drilling. The need ness of the Akata are in the northern shift in the depocenter. This, in the and mixed types. only migration path for oil from the information about annual production for deeper drilling for an optimum end of the delta (Akata 1 well, 80 km opinion of the authors, is very much in Akata, it is clearly conceivable that is published in the statistics of the evaluation of the Agbada formation, east of Port Harcourt, to a depth of These have been claimed to be the Ministry of Mines and Power not agreement with the progradation of precursors for gas and light oil, re- oil will only accumulate on the down- according to the calendar year but is therefore apparent. 3,680 m). The reason for the nonpene- the delta. spectively. It has hitherto been as- thrown side of the fault unless the according to the fiscal year of the The oil window in the Niger delta tration of the total depth of the Akata Petroleum geology. In terms of sumed that the most effective source reservoir has filled to the spill point. government. Apr. 1 to Mar. 31. The extends as deep as 7,010 m in the in the central region is the overpres- Recent discoveries in the Niger delta authors have averaged data to con- petroleum generation and accumula- rocks are the marine shales and form to calendar year (January-De- depocenter. The total thickness of the sured nature of the shales. Yet below tion, the Agbada and Akata formations shales interbedded with the paralic have confirmed accumulation on the ce.nber) for purposes of international Benin formation and Agbada for- the Akata lies the Cretaceous sands, are of special significance in Nigeria. sandstones, particularly in the lower upthrown side of the faults. Accumu- data analysis and comparison. mation is estimated by Merkin (1972) of possibly the equivalent of the For a long time, the Akata has been part of the paralic sequence where lation on the upthrown side could only to be about 6,707 m at the depocenter. Nsukka, Ajali and Mamu formations. favored as the most likely source the shales are at least volumetrical- have taken place if the source were However, only a few wells drilled in In the northern part of the delta for oil in the Niger delta. Results of ly more important. It is argued that within that fault block. the Niger delta have gone deeper than where the Cretaceous sands have been source-rock studies have led to a num- the fact that the characteristics of the 5. Since the growth faults penetrate the expulsion of oil from deep down 4,570 m. Generally the total depth of penetrated, oil and gas shows have ber of reasons which will be advanced Akata and Agbada shales do not repre- only the upper part of the Akata for- in the Akata. most Nigerian wells range between been reported. It is even known that later in this paper to support the can- sent any significant difference from mation in most cases, oil from this 6. Water expulsion from clays dur- 2,744 m and 3,050 m. This is a further Elf's fields in the north central part didacy of the Agbada shales as pos- one another, leads to the conclusion part would find an outlet through such ing compaction has been advanced as indication that there is still a huge of the delta is producing from the sibly the dominant source rocks of the that both shales are source rocks, with channels. However, the upper part of the major mechanism for primary section of the producing Agbada for- Cretaceous. Nigeria's first Cretaceous Niger delta petroleum province. the Akata shales playing the more the Akata cannot conceivably account migration. The inability to dewater mation to be explored. The need for oil discovery was by Safrap in 1967 Commercial oil production in Ni- dominant role in hydrocarbon genera- for all the oil found in the Niger delta. has been given as the reason for the deeper drilling is further justified by when it successfully completed Anam- geria is from the deltaic sandstones tion. The Benin formation contains no Furthermore, any oil formed in the overpressure in the Akata formation. the high porosities (20-23%) still found bra River-1 in eastern Nigeria. This of the Agbada formation where en- commercial hydrocarbons although lower part of the Akata formation If this formation is unable to expel at the base of the most of the shallow well, which yielded 45° API oil from trapment is mostly in rollover anti- several minor oil and gas stringers are can hardly find an outlet from the its water, it is doubtful it can flush wells in the central part of the delta. several zones of late Cretaceous age, clinical structures formed by growth present. overpressured shales since this part any hydrocarbons formed within it. This is probably a pointer to the fact has become the northernmost oil dis- faults. However, the main source Recent unpublished reports on is not penetrated by the growth faults. Traps. Most of the traps discovered that diagenetic effects are probably covery in Nigeria. rock is thought to be the shales of the source-rock studies proved incon- Since evidence for fractures has not in the Niger delta to date are associ- not intensive enough to cause total Gas production from several shallow underlying Akata Formation. Hydro- clusive but point to the shales of Ag- been found, no justification can suc- ated with growth faults. destruction to the reservoir porosity. zones of late Cretaceous age was also carbons generated in the Akata for- bada formation as possible source of cessfully be advanced (at least at the These faults are crescent shaped In addition to the target oil accumu- established by Safrap with the suc- mation are conceived to have migrated oil in the Niger delta. In favor of moment) to support the hypothesis of and generally downthrown to the sea. lation deep down in the Agbada for- cessful completion of Ihandiagu-1. 180 OIL & GAS JOURNAL —APR. 14, 1980 182 OIL & GAS JOURNAL —APR. 14. 1980 These two suspended completions, to- the Akata shales would open up new and Akata formations of the Niger gether with Union's Cretaceous dis- frontiers for exploration in other fron- delta. covery in Dahomey near the Nigerian tier zones in Nigeria's extensive sedi- The existence of submarine canyons, border further justify the possibilities mentary basins. fans, and deep sea turbidite sands at for the presence of substantial oil and Summary. It would seem that the the foot of the delta, have been dem- gas reserves in sedimentary rocks of era of windfall discoveries are over onstrated by Burke (1972). It is in Cretaceous age, not only in the Niger in Nigeria. these plays, which are potential reser- delta but in other frontier regions of Exploratory efforts must therefore voirs, that exploratory efforts of the Nigeria. now be focused on the difficult-to-find future must be concentrated. Discov- This therefore justifies the need for stratigraphic traps, possibly in the eries in these areas will add to the the sections below the Akata to be transition zone from the delta to the fast dwindling Nigerial reserves and drilled and evaluated. The fact that delta front environment. It is hoped give the nation a production capacity the Cretaceous is producing in the that information contained in this that must be required to meet the Cameroons, Gabon, Congo and Angola paper will provide some incentives for energy challenge of the 1980s. may suggest continent wide possi- drilling in areas still unexplored and The need is even more crucial when bilities for the Cretaceous in Africa. will encourage the testing of deeper considering the prospects of sub- A discovery in the Cretaceous below drilling programs in both the Agbada stantially increased energy require- ments of Nigeria in the next decade of possibly unrestrained industrial and technological growth. References 1. Avbovbo. S. A.. 1978a. Tertiary Litho- stratigraphy of Niger Delta: AAPG Bull., Vol. 62, No. 2, pp. 295-300. 2. Avbovbo, S A. 1978b, Geothermal Gradients in Southern Nigeria Basin: Bull. Can. Pt-tr. Geol. Vol. 26. No. 2. pp. 268-274. 3. Burke. K., 1972, Longshore drift, sub- marine canyons, and submarine fans in development of Nieer delta: AAPG Bull., Vol. 56. No. 10, pp." 1975-1983. 4. Dickie. R K„ 1966, Nigeria, the Fed- eral Government's Control of the Oil In- dustry and the Development of Crude Oil Production in the Niger Delta: J. Inst. Pet., Vol. 52, p. 38. 5. Egbogah, E. O., 1978, Nigeria Looks to Gas for a Solution to its Problems: NO World Oil. November 1978 and OPEC Bul- letin. Vol. IX, No. 48, pp 4-7. CD 6. Egbogah, E. O. and W. I. Oronsaye, O 1979, Nigerian Oil's Future Prospects seen Keyed to Government Policies: Oil & Gas Journal, Vol. 77, No. 24, pp. 96-104. 7 Evamy, B. D., ct al, 1978, Hydro- carbon Habitat of Tertiary Niger delta: AAPG Bull. Vol. 62, No. 1, pp. 1-39. "Eighty-four wells without a 8. Hedberg. H. D„ 1968. Significance of 'Our Jaswell rig breakdown is some kind of record high-wax oils with respect to Genesis of when it comes to drilling rigs," say Petroleum: AAPG Bull. Vol. 52, pp. 736- drilled 84 wells in Larry Turner and Jerry Winter, 750. partners in Turner-Winter Drilling & 9. Frankel, E. J. and E. A. Cordry, 1967. 84 days. A total of The Niger Delta Oil Province—recent De- Exploration Co. velopments onshore and Offshore: 7lh 74,000 ft. without They are drilling for oil and gas in World Petroleum Cong.. Mexico City. Proc., Nowata County, Oklahoma, penetrat- V. IB. pp. 195-209. a breakdown." ing 850 to 900 feet of Pennsylvanian 10. Merki, P. J , 1972. Structural Geology formation and about 60 feet of of the Ccnozoic Niger Delta: 1st Conference - Larry Turner (I.) and Jerry Mississipian formation. on African Geology. Ibadan, 1970, Pro- ceedings: Ibadan, Nigeria, Ibadan Univ. Winter, Turner-Winter "We've never seen anything like Press, pp. 635-646. Drilling & Exploration Co., that Jaswell rig," says Jerry Winter. 11. Murat. R. C., 1972. Stratigraphy and Nowata, Oklahoma "Those Jaswell people managed to palcogcography of the Cretaceous and sift out the bad points found in other Lower Tertiary in Southern Nigeria: 1st rigs and come up with a winner. It's Conference on African Geology. Ibadan. I properly engineered, has excellent hydraulics and air system, and is built tough and 1970. Proceedings: Ibadan: Univ. Press, pp. [ extra lean for easy portability. 251-266. 12. Nwachukwu. S. O.. 1976. Approximate ; "It has lots of necessary features like a clutch between the compressor and engine. Gcothcrmal Gradients in Niger Delta Sedi- | which saves lots of fuel. The compressor module has greater cooling capacity than mentary Basin: AAPG Bull. Vol. 60, No. I other rigs and easily adjustable controls requiring a minimum of maintenance. 7. pp. 1073-1077. There s even a remote control winch for lifting drill pipe, and the hydraulic retract 13. Short, K. C. and J. Staublc. 1967, is excellent. /svvjx Outline of Geolotty of Niger Delta: AAPG Bull., Vol. 51. pp. 767-779. "Look, if you've run as many bug-ridden rigs as we have, it's /s^tf*"^^ 14. Weber. K. J.. 1971, Sedimentological great to finally find a hard-working, dependable rig like our Jaswell."/ Aspects of Oilfields in the Niger Delta: More information? Contact your nearest Jaswell distributor or Geologic en Mijnbouw, Vol. 50, pp. 559- | write or call Jaswell Drill Corporation, Sanderson Road. Greenville, 776. j Rl 02828. (401 >949-3700. Telex 927506. 15. Weber, K. J., and E. M. Daukoru, 1975. Petroleum Geology of the Niger Delta: You can't buy a better drilling rig. 9th World Petroleum Cong., Tokyo, Proc., 0 Vol. 2. pp. 209-221. 184 OIL & GAS JOURNAL —APR. 14, 1980 ABSTRACT The sandstones of the Niger delta oil reservoirs are predominantly quartz arenites, yet silica cementation in the form of quartz overgrowth is at a minimum. This apparent lack of cementation is attributed among other things to the low concentration of silica, in formation water, which re- sults in low bulk volume reduction, little pressure solution RELATIONSHIP BETWEEN DIAGENESIS AND and consequently, under-compaction. Under-compaction is aided by early calcite cementation which PORE FLUID CHEMISTRY IN NIGER DELTA probably occurs at the boundary between the fresh waters of OIL BEARING SANDS. the Benin formation and the brackish to saline pore waters of the paralic sequence. Early cementation may have aided the discriminate entry of hydrocarbons into the reservoirs of the area. By Entry of hydrocarbon into reservoirs appears to inhibit D. 0. LAMBE RT- Al KHIONBARE diagenetic processes as significant differences in mineral assemblage exist between hydrocarbon and non-hydrocarbon reservoirs. Kao- l\3 00 linite is the dominant authigenic mineral in most hydrocarbon re- —* MANUSCRIPT SUBMITTED JANUARY 1981 servoirs whereas kaolinite, siderite, pyrite, calcite as well REVISED AND ACCEPTED as minor amounts of smectite and illite occur in many non-hydrocarbon reservoirs. The presence of mainly kaolinite in most reservoir ACCEPTED FOR PUBLICATION BY JOURNAL OF rocks is suggestive of early entry of hydrocarbons into them. This PETROLEUM GEOLOGY AUGUST 1981. deduction is at variance with the presently accepted theory of hydrocarbon generation within the deeply burried section of the paralic Agbada formation and the overpressured marine Akara shales. Instead, it suggests generation and migration of hydrocarbons SEDIMENTOLOGY SECTION GEOLOGY DEPARTMENT from the paralic shales adjacent to the reservoirs. ROYAL SCHOOL OF MINES LONDON SW7 2BP Lack of cementation in most hydrocarbon reservoirs results in the production of very fine materials ('fines') with the oil. It is proposed that most of the kaolinite present in many petroleum reservoirs are produced with such fines. The removal 2 3 of kaolinite in this way, reduces the hazard of permeability INTRODUCTION loss which would have occurred due to blocking of throat The Tertiary paralic Agbada formation of the Niger delta passages by floating kaolinite platelets. is by far the most significant in terms of hydrocarbon generation and accumulation in the area. It is underlain by the over- pressured marine Akata formation which is presently supposed to be the dominant source rock for the hydrocarbons of this province. Overlying the Agbada formation is the Massive conti- nental Benin sands which lack effective cap rocks in many places and therefore hold very little hydrocarbons. Detailed de- scriptions of these three lithostratigraphic units as well as aspects of the general petroleum geology have been described by Short & Stauble (1967), Frankl & Cordry (1967), Weber (1971), Merki (1972), Weber & Daukoru (1975), Evamy et al (1978), Avbovbo (1978), Avbovbo & Ogbe (1979) and Egbogah & Lambert-Aikhionbare (1980). The oil reservoirs of the area comprise mainly quartz arenites which in some cases are interlaminated with shale bands. Apart from these shale laminae, the reservoir rocks are other- wise very clean and generally under-compacted. This results in poor core recovery and therefore scarcity of 'full bore' cores. Sidewall cores (SWC) are more easily available and constitute the major material used in this study. Results obtained indi- cate that despite the flushing of formation fluids during drilling, and the artifacts that may be produced due to incipient fracturing during sidewall coring, very valuable information can be derived from this type of sample. Nagtegaal (1978), briefly described the petrography of some rocks of the Niger delta. Some of his findings have been con- firmed by results obtained in this study. Apart from this, very little is available in the published literature on the dia- genesis of the rocks of this area. This apparent lack of en- 10 4 thusiasm is most probably explained by the scarcity of samples growths which were found to develop only in places where the clay as described above. This paper sets out the diagenetic changes and/or iron oxide coating on grains was thin or absent. that have taken place in these rocks and explains the under — PETROGRAPHY compaction of the sediments in terms of these changes. Some of A large proportion of the samples analysed are composed the proposals advanced to explain under—compaction include:- mineralogically of between 80 - 90% quartz. In some cases, the quartz content is as high as 98% particularly in hydrocarbon 1) the defficiency of silica, in formation water, which bearing zones where relatively small amounts of clays are held is attributed to the limited amount of pressure solution between the grains and in the pore space. and little diagenetic alteration of silicate minerals The quartz grains are generally fine to medium grained in 2) early calcite cementation which inhibits mechanical size, occasionally coarse and sometimes pebbly but generally sub- compaction angular to subrounded. Coarser and more angular grains are 3) early entry of hydrocarbons resulting in a lowering of particularly abundant in the eastern Niger delta. Most grains ion concentration of connate water appear unaltered although some show conepidal fracture and evidence The limited diagenetic alterations obviously have impli- of replacement. Where replacement features occur, they are cations for reservoir geology. The apparent high porosities and generally replacement of quartz grain edges by calcite (Fig. 1 & 2). permeabilities characteristic of reservoirs of this area with Quartz overgrowths are few and where found, are in optical con- their attendant sand production problems are some of the implications tinuity with the main detrital grains. In some cases the over- which are discussed briefly at the end of this paper. growths are themselves replaced by carbonate minerals (Fig. 2). TECHNIQUES Polycrystalline quartz grains are common in most rocks. Sutured Over 100 samples were examined by x-ray diffraction (XRD), contacts, concavo-convex contacts and other features of pressure Scanning Electron Microscope (SEM) and the petrographic micro- solution are few and sometimes lacking. This is in agreement with scope to determine their diagenetic history. Most samples were the findings of Nategaal (1978). The scarcity of pressure solution so small that only XRD and SEM studies were possible. Thin is attributed to a number of factors which are discussed later. sections were prepared only where samples were large enough. Such al samples had to be impregnated with resin (araldite) to prevent The remaining 2 to 10% of mineralogic^composition is made disintergration during thin section preparation. up of feldspars, clays, siderite, pyrite, calcite and gypsum in Surface features of quartz grains were also examined by SEM order of decreasing abundance. after they have been cleaned according to the method of Wilson Feldspars are predominantly of fine sand grade with a few (1978). As analysis progressed, it became clear that mere larger grains in various stages of alteration. Microcline washing of the grains in soap water was enough to clean their appears to be the dominant feldspar group followed by plagioclase surfaces, since the main interest was in locating quartz over- and orthoclase. Large fresh grains, showing only initial stages of 10 7 alteration are common in the eastern delta (Fig. 3), while smaller 1,200m downwards to the total depth of many wells. Replacement grains in more advanced stages of alteration are characteristic of quartz by carbonate is almost entirely by calcite (Figs. 1 & 2). of the western delta (Fig. 4). These indicate that calcite was probably the only carbonate Clay minerals are present in most samples and are of both mineral present at shallower depths where, due to the influence authigenic and detrital origin. They form a significant pro- of several peat and lignite beds, quartz solubility was high. portion of the matrix as they are believed to rim most detrital From this relationship, it can be inferred that calcite pre- grains. This clay coating is authigenic (Heald & Larese ceeded siderite and that the dissolution of calcite provided 1974) and plays an important role in preventing the process of some of the CO^ ions that combined with Fe ions to precipitate pressure solution. siderite. No conclusive evidence has been observed in thin Kaolinite is the dominant clay mineral identified. It ex- sections. hibits typical accordion like or book-like form and is therefore Pyrite occurs as well formed cubic crystals sometimes authigenic. Many kaolinite crystals show corroded edges and aggregated together into framboids. These crystals are very small sometimes alteration features - an indication of the variable in size and appear to have developed on the surfaces of most nature of the environment. In some cases tiny whiskers which other minerals, detrital or authigenic. This would appear to probably represent initial alteration to illite or mixed layer suggest that they are the latest formed of the authigenic minerals. are observed at the edges of the platelets, (Fig. 5) The kaolinite Gypsum is random in occurrence and is also authigenic in content of most clay fractions analysed ranges from 60 - 80%. isi Other clays are present in minor amounts except in laminated origin. It exhibits two crystal forms a) well formed orthorhombic CD samples where due to contribution of detrital clays, the pro- crystals which are very limited in occurrence, (Fig. 6) b) poorly portion of smectites, illites and mixed layer clays may be as formed generally fibrous crystals which may have formed late due high as 50%. Very little authigenic illite, smectite and mixed to evaporation of the connate water after the cores have been layer clays are actually detected and appear to be restricted to taken (Fig. 7). Considering the fact that some of the well formed non-hydrocarbon bearing rocks. crystals come from depths of 4,000m and lower, it is suggested that they too were formed late and that variation in crystal The other minerals - siderite, calcite, pyrite and gypsum form probably reflects original concentration of gypsum in the occur in minor amounts and also appear to be authigenic in drilling mud. origin. Other minerals which occur in trace amounts include mica, Siderite occurs mainly as microcrystalline cement and calcite zircon, glauconite and apatite. Apatite occurs commonly as as poorly formed rhombohedral crystals. Calcite is present at inclusions in the quartz grains whereas zircon and glauconite shallow depths, hardly occurring below average depths of 2,300 - are disse .minated throughout the sediment but appear more common 2,600m in most wells examined in the course of this study. Sider- in the finer grained ones. ite on the other hand appears to increase in abundance from about 8 9 DIAGENESIS Silica and/or carbonates are the most common cementing under the very^ high power of the SEM (Fig. 8 ). By virtue materials in many sandstones (Pettijohn 1956, Heald & Anderegy of their sizes and shapes, they represent the very early 1960, Blatt et al 1972, Pettijohn et al 1972, Selley 1976, and stages of overgrowth development. Dapples (1959) and Hayes 1979). However, Dapples (1959) suggests that where the Wilson (1978) identified three stages of quartz overgrowth quartz content is high as in the case described above, silica formation. Those under discussion here fall into their cementation is favoured provided compaction has progressed first category which mark the onset of overgrowth develop- normally. This important proviso does not apply in the Niger ment. The author believes that these tiny overgrowths delta and therefore cementation has not followed the favoured are the only authigenic growth in the present depositional trend. Consequently silica overgrowth is sparse. A few over- basin. Their occurrence does not appear to be controlled growths are identifiable in thin section and SEM but a rigorous by depth although only grains below 1,300m have been search is needed to locate them. Although some amorphous silica examined. The difference in degree and amount of overgrowth may be present, as cement, it cannot account for the amount normally between hydrocarbon and non hydrocarbon reservoirs suggested expected in such rocks. by Philipp et al (1963) was not observed. This variation Two types of quartz overgrowths are recognized in these rocks. is most likely due to the under-compacted nature of these I) Large well formed euhedral growth which are in optical sediments. Their occurrence at depths of 3,500m and below continuity with original detrital grains. Some of these are suggests that the second stage (aggregation of the initial fractured and some show evidence of replacement by calcite overgrowths to form fairly large euhedral crystals) of ^ 00 (Fig. 2). Fracturing probably occurred as a result of trans- development has not commenced. Retardation of growth would ^ portation of the grains. This evidence coupled with the re- occur either placement of overgrowths by calcite, indicate that such over- 1) If concentration of silica in formation water is low or growths were either developed very early in the history of 2) If overgrowth development is prevented by other dia- the sediment or were brought in as detrital material. The genetic processes operating in the area. latter is more likely as the lack of compaction and early calcite Both factors have contributed to the inhibition of over- cementation would have prevented pressure solution and the growth formation in the Niger delta and evidence for each consequent development of overgrowths. As they are detrital, will be discussed in the next section. these large overgrowths do not form a part of the present DEFFICIENCY OF SILICA IN FORMATION WATER discussion. Silica in formation water is believed to be supplied II) Well formed tiny overgrowths which are beyond the resolving among other means by:- power of the ordinary petrographical microscope. These were a) Natural solubility of silica in formation water. detected by examining washed individual quartz grains b) Alteration of clays and other silicates during dia- genesis . 10 11 in the Niger delta), it could prevent pressure solution c) Pressure solution. altogether (Siever 1959). Other sources are thought to contribute very minor amounts of 2) The 'poikilitic' texture of calcite observed in some silica and are therefore only of local importance. Dapples thin sections (Fig. 1), suggests that calcite cementation (op cit.), Towe (1962), and Blatt (1979) have discussed this is an early event. While this event may provide cohesion subject in detail. One additional source worth mentioning and rigidity to the rock, it reduces the effect of here was suggested by Walker (1960)y who claimed that the further mechanical compaction which results in low replacement of quartz by calcite may contribute some silica to grain contact and consequently little pressure solution. formation water. Such replacements have been observed in the Without a substantial amount of pressure solution, it is rocks of this area (Figs. 1 & 2) and may therefore account for doubtful if enough silica was present in solution to some of the silica in formation water. Blatt (op cit.) carried support development of large overgrowths. out a quantitative evaluation of the amount of silica con- 3) De Boer et al. (1977, page 257) state that 'experiments tributed by each of processes 'a', 'b', and 'c' above and revealed that when samples have undergone some con- concluded that 'c' (which is scarce in the rocks of the Niger solidation, the presence of water is essential for conti- delta) was the major contributor, providing about 33% of the nuation of the compaction process'. The loss of formation silica in solution. Process 'b' does not appear to have reached fluid (NaCl solution) in their experiment resulted in an advanced stage in the rocks of the area as only initial a stoppage of further mechanical compaction which reduced alteration of kaolinite to illite and mixed layer clays have ro the pressure exerted at points of grain contact and thus CD been observed. This leaves process 'a' as the only dominant CD phenomenon probably contributing its full quota of silica to pressure solution. The displacement of formation water, the formation water of the Niger delta. If this is true, the by hydrocarbon, from the reservoirs of the Niger delta apparent defficiency of silica in the formation waters of this can be likened to the situation in the above mentioned area, demonstrated by the poor quartz overgrowth is not sur- experiment. The writer believes that the migration of prising. hydrocarbon into the reservoirs in this area occurred The scarcity of process 'c' in the Niger delta may be at an early stage (discussed later) in the history of attributed to a number of factors. these sediments and that mechanical compaction also 1) The clay coating around grains (discussed above) is of a ceased then. This explains the loose nature of many re- reasonable thickness and therefore prevents grain contact. servoir sands, particularly in non-laminated beds; a Heald (1956) and Heald a Larese (1974) stated that a thin factor that results in the production of fine grained sand and silt with crude oil from such reservoirs. This clay coating could act as a catalyst for silica dis- problem is considered in the section on engineering impli- solution and therefore aid pressure solution. However, cations . where the clay coating is thick (as is commonly observed 12 13 DIAGENETIC TREND The preceeding discussion has shown that perhaps the dia- argument in his work on some Cretaceous sandstones of Wyoming. genetic pattern in the Niger delta is largely different from The presence of only kaolinite clay suggests that conditions those of many other deltaic basins. The under-compaction of were slightly acidic prior to the entry of hydrocarbon into these sediments (resulting from a combination of factors discussed reservoirs. Such conditions exist in most areas of the Niger above) coupled with the relatively rapid sedimentation and delta at shallower depths where the influence of fresh water is ly fluctuation in shoreline positions, may be largely responsible dominant. The relative small amount of kaolinite present indi- for this departure. The presence of hydrocarbon in some re- cates a possible early displacement of formation fluid which servoirs cannot be said to have affected the overall diagenetic inhibits further formation of kaolinite. If petroleum migration trend but certainly is responsible for some differences in into the reservoirs were a late event, kaolinite precipitation mineral assemblage between such reservoirs and non hydrocarbon and indeed precipitation of other authigenic minerals would have ones. Dickenson (1953) attributes the high pore pressure in attained an advanced stage as is evident in many non-hydrocarbon some gulf coast sediments to the presence of hydrocarbon in them. reservoirs. The same is not true of the Niger delta where many reservoirs are This finding contradicts the presently accepted theory of hydropressured (Weber & Daukoru 1975) except in places where they are hydrocarbon generation within the marine Akata formation and faulted against overpressured shales of the Akata formation. the lowermost part of the paralic Agbada formation (Weber & EFFECT OF HYDROCARBON ON DIAGENESIS Daukoru 1975, Evamy et al. 1978 and Ekweozor & Okoye 1980). In recent years, the effect of hydrocarbon on sediment Generation of hydrocarbons within these lowermost shale units diagenesis have been documented by Philipp (1963) Yurkova (1970), hO would call for a late generation and a late migration of the CD Sakisyan (1972), Wilson (1975) and Hancock (1978). The Niger ->J delta follows the broad patterns described and the effects are petroleum. Geological considerations in favour of generation particularly clear in terms of clay diagenesis. and early migration of hydrocarbon from the laminated shales of Kaolinite constitutes the dominant clay group in most hydro- the paralic sequence have been advanced by Egbogah & Lambert- carbon reservoirs but comprises less than 5% of the total rock Aikhionbare (1980) and Lambert-Aikhionbare & Ibe (1980). Wilson constituent. The entry of hydrocarbon flushes the formation of (1975) believes that in many cases, the conditions necessary for its original fluids and the connate water left behind at the end generation of hydrocarbons have been attained at a burial depth of the process does not contain a high enough concentration of of about 1,000m. Weeks (1961) and Hedberg (1964) based on ions either to sustain the production of kaolinite and any other empirical data also arrived at similar conclusions. IMPLICATION FOR ENGINEERING authigenic minerals or to allow migration of ions and therefore Neasham (1978) has stated that due to the discrete morphology the diagenetic alteration of the kaolinite already precipitated of kaolinite within the pore spaces, it does not grossly affect in the formation. Webb (1974) invoked similar porosity of reservoirs. However Todd and Tweedie (1978) con- 10 14 eluded that kaolinite plateletes defluocullate (during fluid reservoirs has also played a significant part in this issue. movement in the reservoir) and migrate to block critical throat The result is that compared with sediments of similar ages passages, thus reducing permeability. The presence of kaolinite and depths in other areas of the world, those of the Niger in the sediments of this region, therefore could constitute a delta possess relatively higher porosities. Porosities of significant problem, but due to the undercompaction of the re- 25 - 30% are quite common at depths of 3,500m and below. servoir rocks, very fine sands and silt to clay size particles According to Pyror (1973), modern beach and channel sands ('fines') are produced with oil from many reservoirs (Fig. 9 ). similar to those that may comprise the reservoirs of the The author believes that the production of these 'fines' clears Niger delta, possess initial porosities of 40 - 50%. Thus minute pores within the reservoirs and thus reduces the number of it can be said that only relatively low bulk volume reductions throat passages that may be blocked by floating kaolinite. In have occurred in these sediments. Rittenhouse (1971), and Manus laminated sandstone reservoirs, the production of 'fines' is & Cogan (1974) have stated that the amount of bulk volume reduced (since more clay exists to bind grains together) and reduction that takes place in a rock is proportional to initial permeability loss may become a problem, particularly in a water porosity. If large bulk volume reductions have occurred, poro- injection project. sites of 15 - 20% similar to those of many other petroleum re- Water injected into down dip wells in such situations,could servoirs of the world would have been achieved. Without such cause the movement of 'fines' which may be brush piled against large bulk volume reductions, pressure solution and consequently throat passages and consequently inhibit fluid flow. It is also silica cementation will be low, thus confirming the observations worth mentioning that the smectite content of laminated and made in these rocks. NCJD 00 non hydrocarbon reservoirs is slightly high. From semi-quantitative beds In conclusion the author wishes to stress that the era analysis carried out, the proportion of smectite in the clays of such A of easily discovered rollover structures in the Niger delta may be as high as 10 - 15%. This fact clearly demonstrates the (Ejedawe 1975) is nearly over and that more intensive studies need to treat each reservoir as a separate entity. The need for are needed in order to fully explore the potentials of this basin. a detailed study of a reservoir before an enhanced recovery The idea of hydrocarbon generation within the Akata formation programme is attempted cannot be overstressed for this region. which has dominated exploration programmes in the area is CONCLUSION erroneous as this calls for a late generation and a late migration The Niger delta is a young geological province and its of hydrocarbon into reservoirs. Diagenetic evidence advanced in diagenesis is at a relatively early stage. The under-eonpaction this paper favour the opposite, which is an early generation of the sediments, brought about by low pressure solution and and migration of hydrocarbon. The need is urgent, therefore, little silica cementation coupled with the early precipitation to investigate the paralic shales of the Agbada formation as of calcite, have caused a major shift in the diagenetic pattern a more likely source of the hydrocarbon held in the reservoirs of the sediments. The early entry of hydrocarbon into the of the Niger delta. A confirmation of an Agbada source would 16 Avbovbo, A.A. 1978, Tertiary Lithostratigraphy of Niger Delta. A.A.P.G. support earlier suggestions of Short & Stauble (1967) and Reed Bull. V 62 p. 295-300. Avbovbo, A.A. & F.G.A. OGBE, 1978, Geology and Hydrocarbon Production (1969) that the oils of this region have had a very short migration Trends of southern Nigeria basin. The Oil & Gas Jour. Nov. 27, p. 90-93 history. matt, H. 1979, Diagenetic Processes in sandstones in Aspects of Dia- genesis. Editors Schoole P.A. & P.R. Schluger. SEPM Spec. Publ. No. 26 p. 141-157. Blatt, H., G. Middleton & R. Murray, 1972, Origin of sedimentary rocks. Prentic-Hall Inc. Publ. New Jersey. 634 P. Dapples, E.C., 1959, The Behavior of Silica in Diagenesis in Silica in sediments. H.A. Ireland (ed.) SEPM Spec. Publ. No. 7. p. 36-54. De Boer, R.B., P.J.C. Nagtegaal a E.M. Duyvis, 1977, Pressure Solution Experiments on Quartz Sand. Geochim et Cosmochim Acta. v. 41 p. 257-264. Dickenson, G. , 1953, Geological Aspects of Abnormal Reservoir Pressures in Gulf Coast Louisiana. A.A.P.G. Bull v. 37 p. 410-432. Egbogah, E.O., a D.O. Lambert-Aikhionbare, 1980. Possible New Potentials of the Niger delta. The Oil a Gas Jour. April 14. p. 176-184. Ejedawe, J.E, 1975, The Niger delta Petroleum Subsprovince: Exploration Trends and Giant Oil Fields Occurrence. Abstr. of Proc. Nig. Min. Geol. a Met. Soc. 11th annual Congr. Nsukka. Ekweozor, C.M., a N.V. Okoye, 1980, Petroleum Source - bed Evolution of the Tertiary Niger delta. A.A.P.G. Bull v. 64 p. 1251-1258. Evamy, B.D., J. Haremboure, P. Kamerling, W.A. Knaap, F.A. Molloy and P.W. Rowlands, 1978, Hydrocarbon Habitat of Tertiary Niger Delta. A.A.P.G. Bull. v. 62 p. 1-39. Frankl, E.J. a E.A. Cordry, 1967, The Niger Delta Oil Province - Recent developments Onshore and Offshore. 7th World Petr. Congr. Mexico City Proc. v. 2 p. 195-209. Hancock, N.J., 1978, Diagenetic modelling in the Middle Jurassic Brent Sand of the Northern North Sea. Eur. 92. Eur. Offshore Petr. ND Confr. a Exhibition. London v. p. 275-280. 00 Hayes, 1979, Sandstone Diagenesis - the Hole Truth.in Aspects of Sand- ^ stone Diagenesis. Schoole, P.A. and P.R. Schluger (Eds.) SEPM spec. Publ. No. 26. p. 127-139. Heald, M.T. 1956, Cementation of Simpson and St. Peter Sandstones in parts of Oklahoma, Arkansas and Missouri. Jour, of Geol. v. 64 p. 16-30. ACKNOWLEDGEMENT Heald, M.T. a Anderegg, 1960, Differential Cementation in the Tuscarova The writer wishes to thank the Nigerian National Petroleum Sandstone. J. Sed. Pet. v. 30 p. 568-577. Corporation (NNPC) and Gulf Oil Company Nigeria for providing Heald, M.T. a R.E. Larese, 1974, Influence of Coatings on Quartz material for this study, Dr. P.R. Bush for supervising the work Cementation. J. sed. Pet. v. 44 p. 1269. and Dr. R.C. Selley for editing the script and suggesting the title. Hedberg, H.D. 1964, Geological Aspects of Origin of Petroleium. A.A.P.G. Bull, v. 48 p. 1755-1803. Lambert-Aikhionbare, D.O. a A.C. Ibe, 1980, The Agbada Shales as Major Source Rocks for the Niger Delta Petroleium. Abstr. of Proc. 16th Ann. Confr. of Nigerian Mining and Geosciences society. Manus, R.W. a A.H. Cogan, Bulk Volume Reduction and Pressure solution derived cement. J. sed. Pet. v. 44 p. 466-471. Merki, J.P, 1972, Structural Geology of the Cenozoic Niger Delta in African Geology- Dessauvagie T.F.J, and A.J. Whiteman (Eds). Dept. of Geol; University of Ibadan Press, p. 635-646. Murat, R.C. 1972, Stratigraphy and Paleogeography of the Cretaceous and Lower Tertiary in Southern Nigeria in African Geology: Dessanvagie T.F.J, and Whiteman (Eds), Dept. of Geol. Univ. of Ibadan Press, p. 251-265. Nagtegaal, P.J.C. 1978, Sandstone Framework Instability as a function of Burial Diagenesis. Jour. Geol. Soc. Lond. v. 135 p. 101-105. 19 12 Neasham, J.W., 1977, The Morphology of Dispersed Clay in Sandstone Reservoirs and its effect on sandstone shaliness, Pore Space LIST OF FIGURES and Fluid Flow Properties. SPE 6858. 52nd Ann. Fall Confr. & Exhibition of SPE. Denver Colorado Proc. p. 1-8. Pettijohn, F.J., 1956, Sedimentary Rocks. Harper Bros, New York 718pp. Pettijohn, F.J., P.E. Potter & R. Siever, 1972, Sand and Sandstones. Figure 1 Poikilitic calcite cement in sandstone. Springer-Verlag, Berlin. 618 pp. Philipp W.H.D., H.J. Drong, H. FU chtbauer, H.G. Haddenhorst, and W. Figure 2 Replacement of quartz grain and overgrowth Jankowsky, 1963, The History of Migration in the Gifthorn by calcite (middle). Note siderite cement Trough (NW Germany). Proc. 6th World Petr. Congr. Frankfurt Ibottom right) and its lack of penetration Section 1, PD2. p. 457-478. of quartz grains. Pryor, W.A. 1973, Permeability - Porosity Patterns and Variations in some Holocene sand bodies. A.A.P.G. Bull. v. 57 p. 162-189. Figure 3 Large relatively fresh feldspar grain, Reed, K.J. 1969, Environment of Deposition of Source Beds of High Wax common in sediments from the eastern Oil. A.A.P.G. Bull. v. 53 p. 1502-1506. Niger delta. Rittenhouse, G., 1971, Pore-Space Reduction by Solution and Cementation A.A.P.G. Bull. v. 55 p. 80-91. Figure 4 Small, highly altered feldspar grain (center) Sarkisyan, S.G., 1972, Origin of Authigenic clay Minerals and their common in sediments from western Niger Significance in Petroleum Geology. Sed. Geol. v. 7 p. 1-22. delta. Selley, R.C., 1976, An Introduction to Sedimentology. Academic Press Publ. Lond. 408 pp. Figure 5 Electron micrograph of kaolinite at initial Short, K.C. & A.J. Stduble, 1967, Outline of Geology of Niger Delta stages of alteration. Note tiny pro- A.A.P.G. Bull W. 51 p. 761-77P trutions in platelet to the right. Siever, R., 1959, Petrology and Geochemistry of Silica cementation in Figure 6 Electron micrograph of well formed ortho- some Pennsylvanian sandstones, in sediments in sediments H.A. rhombic gypsum crystals. Ireland (Ed) SEPM Spec. Publ. No. 7. p. 55-79. Todd, A.C. & J. Tweedie, 1978. Total Rock Characterisation of North Figure 7 Electron micrograph of fibrons gypsum. Sea Sandstones with particular reference to Interstitial Clays Eur. 93. Proc. Eur. Offshore Petr. Confr. & Exhibition. Lond. Figure 8 Electron micrograph of tiny spikes of quartz p. 281-288. overgrowths developed on the surface of Towe, K.M., 1962, Clay Mineral Diagenesis as a Possible Source of a detrital quartz grain. Silica Cement in sedimentary Rocks. J. sed. Pet. v. 132. p. 26-28. NJ Figure 9 Electron micrograph showing a view of a VO Walker, T.R., 1960, Carbonate Replacement of Detrital Crystalline pore space. Note the almost total lack of O Silicate Minerals as a source of Authigenic silica in sedi- cement and the extra fine size of grains, mentary Rocks. Bull. Geol. Soc. Am. v. 71 p. 145-152. (< 6>um) even the enhedral quartz in top Webb, J.E., 1974, Relation of Oil Migration to Secondary Clay right. Absence of clay is remarkable. Move- Cementations, Cretaceous Sandstone Wyoming. A.A.P.G. Bull, ment of fluid through this pore will carry v. 58 p. 2245-2249. most of these 'super' fine grains with it. Weber, K.J., 1971, Sedimentological Aspects of Oil Fields in the Niger Delta. Geologie en Mijnbouw v. 50 p. 559-576. Weber, K.J. and E. Daukoru, 1975, Petroleum Geology of the Niger Delta. 9th World Petr. Congr. Tokyo Proc. v. 2 (Geology) p. 209-221. Weeks, L.G. 1961, Origin, Migration and Occurrence of petroleum in petroleum Exploration Handbook Chap. 5: New York, McGraw-Hill p. 5-1 - 5-50. Wilson, H.H., 1975, Time of Hydrocarbon Expulsion, Paradox for Geo- logists and Geochemists. A.A.P.G. Bull. v. 59 p. 69-84. Wilson, P. 1978. A Scanning Electron Microscope Examination of Quartz Grain Surface Textures from Weathered Millstone Grit (Carboni- ferous) of the Southern Pennines, England. A Preliminary report, in Scanning Electron Microscopy in the study of Sedi- ments. W.B. Whalley (Ed.). Geo Abstracts. Publ. Norwich England, p. 307-318. Yurkova, R.M., 1970. Cdmparison of Post-Sedimentary Alterations of Oil - Gas - and Water - bearing Rocks. Sedimentology v. 15 p. 53-68. ABSTRACT The sediments of the Tertiary Akata and Agbada Formations have been studied mineralogically and petrologically. In the Akata and Agbada shales the clays are largely detrital in origin with minimal alteration arising from the effects of burial diagenesis. Clays are present in minor (^ 10%) amounts in the reservoir sand- SIGNIFICANCE OF CLAYS IN THE PETROLEUM GEOLOGY stones of the Agbada Formation as detrital and authigenic phases. There are significant differences between the clay assemblages of the water and hydrocarbon-bearing sandstones. The latter have OF THE NIGER DELTA lower overall clay contents and authigenic kaolinite, whilst authigenic kaolinite and smectite are present in the water saturated sandstones. These differences are thought to be related to the D.O. Lambert-Aikhionbare and H.F. Shaw early migration of hydrocarbons into the reservoir sands. The causes of the poor degree of cementation in the Agbada sand- Department of Geology, stones are discussed along with the engineering problems posed by Imperial College, Prince Consort Road, London SW7 U.K. their very friable nature. N3 Clays of the Niger Delta ID ACCEPTED FOR PUBLICATION BY CLAY AND CLAY MINERALS SEPTEMBER 1981 i 2 remained effectively constant from the Eocene until today any variations from the Recent sediments will be a reflection of diagenetic changes. These diagenetic changes in the clay mineral assemblages of both the shale and sandstone sequences will be outlined and their relevance SIGNIFICANCE OF CLAYS IN THE PETROLEUM GEOLOGY OF THE NIGER DELTA to the petroleum geology of the Niger Delta considered. by Geology of the Niger Delta D.O. Lambert-Aikhionbare & Short and Stauble (1967) defined three lithostratigraphic units in H.F. Shaw the Tertiary of the Niger Delta (Fig. 1). The basal Akata Formation Department of Geology, Imperial College of Science & Technology is predominantly a marine shale sequence with silty and sandy horizons London U.K. laid down in front of the advancing delta. The shales of the Akata Formation probably extend over the whole delta area and have been de- Introduction posited from the Paleocene to the Recent. The Niger Delta today occupies 64,000 sq. km of the sedimentary The Agbada Formation consists of alternating sandstones and basin of southern Nigeria. Its position in the eastern corner of shales deposited at the interface between the lower deltaic plain the Gulf of Guinea is at the intersection of the triple R junction and marine sediments of the continental shelf fronting the delta. from which the rifting and separation of South America from Africa The alternations of sandy and argillaceous sediments are the result was initiated in Middle Cretaceous times. The subsequent insta- of differential subsidence, variation in the sediment supply and hO bility and subsidence along the rift zones led to a marine trans- lO gression in the mid-Cretaceous which terminated in the late Middle shifts in the depositional lobes of the delta. Generally the upper Kl Cretaceous period. In the late Cretaceous a proto-Niger delta part of this formation is sandier than the lower part indicating the first developed but this ended with a major transgression in the general seaward advance of the delta. The age of the formation varies Palaeocene. From the Eocene onwards a regression occurred with progressively from Eocene in the north to Recent in the south at the the deposition of a wedge of fluvio-deltaic sediments which built present delta surface. out into the South Atlantic as the modern Niger Delta (Stoneley, Virtually all the hydrocarbon accumulations in the Niger delta 1966; Short &. Stauble, 1967; Burke et al, 1970). occur in the sandstones of the Agbada Formation trapped in rollover To date little appears to have been published on the clay anticlines fronting growth faults, generated contemporaneously with the mineralogy of the Niger Delta sediments with the exception of the deposition of the sediments. The shales of the formation form imper- work of Porrenga (1966, 1967) who examined the clay mineralogy of meable barriers against further upward migration of the hydrocarbons. the Recent sediments. The present study examines the clay mineralo- The same shales are also the most obvious source rocks for the hydro- gy of the Tertiary shale and sandstone sequences and relates their carbons and recently further evidence has emerged to support this distributions to those reported by Porrenga for the Recent sedi- view (Short and Stauble, 1967, Egbogah and Lambert-Aikhionbare, ments. Because the clay mineral provenance of the Niger Delta has 1980., Lambert-Aikhionbare, 1980., Lambert-Aikhionbare and Ibe, 1980). 3 The Benin Formation is predominantly a sandstone sequence with posed of clay minerals with minor amounts of quartz, feldspar, a few shale intercalations which become more abundant towards carbonates and pyrite. However, their clay mineralogy differs the base. The sands of the formation are largely deposits of the from that of the Akata Formation with more kaolinite (40-75%) continental upper deltaic plain environment ranging in age from less smectite (10-35%) and similar amounts of illite (15-25%). the Oligocene in the north to their Recent equivalents in the modern The differences in the clay mineralogy of the shales of the delta. two formations are thought to reflect differential settling of Methods of analysis the clay sediments from the Niger delta source provenance. There The samples analysed were side-wall cores from the Akata and Agbada is a general tendency in deltaic environments for kaolinite to Formations obtained from numerous oil company wells distributed over the be deposited close to shore whilst smectite will be transported whole delta though the majority are located in the western area greater distances into deeper water environments (Porrenga, 1967; 1966., (Fig. 2). Side-wall core samples were used because conventional cores Gibbs, 1977., Shaw 1978). Consequently in the near shore en- were difficult to obtain due to the friable nature of the sandstones. vironment of tKe Agbada Formation one would anticipate enhanced The samples were analysed by standard X-ray diffraction methods, kaolinite and lower smectite contents compared to the deeper water optical microscopy and scanning electron microscopy. The scanning marine environment of the Akata Formation. The effects of burial electron microscope employed was fitted with an energy dispersive diagenesis on the clay mineralogy of fc!' Akata and the Agbada For- X-ray analyser to facilitate identification of the mineral phases mation shales appear to be minimal. Their clay assemblages broadly examined. resemble those of the Recent sediments of the Niger delta (Porrenga, N) The clay mineralogy of the samples was determined by standard 1966) with variations readily explained in terms of the processes vO OJ methods of X-ray diffraction analysis of orientated specimens of of differential settling already discussed. (Table 1). their clay fractions (Biscaye, 1965; Shaw 1972) . To allow for a The preservation of smectite in the Akata Formation at depths direct comparison between the clay assemblages of the Recent and the of about 12,000 feet with burial temperatures of 120°C (Table X) Tertiary sediments, the relative proportions of the clay minerals is a little surprising as one might have anticipated that the trans- have been estimated as peak area percentages using the same method formation of smectite to mixed layer illite-smectite would have as that of Porrenga (1966). occurred at these temperatures. It has been postulated that the Mineralogy of the Akata and Agbada Formation Shales transformation of smectite to mixed layer phases would occur in The Akata Formation shales are predominantly composed of clay the temperature range of 80°-ll0°C (Burst, 1969; Perry and Hower, minerals (55-90%) with lesser amounts of quartz, feldspar, carbo- 1972; Shaw 1980). Indeed in other samples of the Akata Shales nates and pyrite. The clay mineralogy of the shales varies with at shallower depths and burial temperatures of 105°C mixed layer 35-60% kaolinite, 20-50% smectite, including some illite-smectite illite-smectite is present with smectite absent. random mixed layer phases, and 10-30% illite. In the Agbada Formation shales smectite is also present at The shales of the Agbada Formation are also predominantly com- 6 D sandstones contain only 2-5% clay minerals whereas the water bearing burial temperatures between 105° and 110°C but is noticeably absent, sandstones have 5-10% clay minerals. This difference is overall with only illice-srnecti te present, in one sample with an estimated clay mineral content reflects the presence of authigenic clay minerals burial temperature of 140°C at a depth of 9716 feet. It would on a greater scale in the water-bearing compared to the hydrocarbon therefore generally seem that smectite is present in the Akata and bearing sandstones. There are also differences in the clay assem- the Agbada Formation shales at temperatures slightly in excess of blages, the hydrocarbon-bearing contain authigenic kaolinite whilst what might be expected from the accepted models of clay mineral the water-bearing contain authigenic smectite in addition to the diagenesis. However, whilst burial temperature is the principal authigenic kaolinite. Also in the water-bearing sands the authi- control, other factors may also influence the transformation of genic kaolinites show evidence of corrosion and instability in the smectite to mixed layer phases, notably overburden pressure, pore presence of the later alkaline formation waters. water chemistry and reaction rates (Shaw, 1980). In the Akata shales The lesser amounts of authigenic clays and the predominance there is evidence of under compaction in some areas which might allow of kaolinite in the hydrocarbon-bearing sandstones suggest early the smectite to De preserved at higher temperatures whilst elsewhere migration of hydrocarbons into the formation. An early migration it is transformed to illite-smectite at lower temperatures. of hydrocarbons would have prevented further clay mineral diagenesis in these sands whilst in the water saturated sands diagenesis con- Petrology of the sandstones of the Agbada Formation tinued with the development of authigenic smectite and the corrosion The sandstones of the Agbada Formation are poorly cemented of the earlier formed authigenic kaolinite. ^ coarse to fine grained quartz arenite. Mineralogically they are tO predominantly composed of detrital quartz with minor amounts of clay The conclusion that the hydrocarbon emplacement occurred early minerals which make up 2-10% of the sandstones. The clay mineral would favour the generation of hydrocarbons in the Agbada shales assemblage of the sandstones consists of kaolinite (40-70% but may adjacent to the reservoir sands (Short and Stauble, 1967; Frankl exceed 90% of the clay fraction in the hydrocarbon bearing sandstones), and Cordry, 1967; Reed, 1969) rather than in the Akata shales illite (0-20% of the clay fraction and smectite (0-30% of the clay (Weber and Daukoru, 1975). The latter model requires a late genera- fraction). This assemblage is broadly similar to that of the tion and a late migration of the hydrocarbons which is not supported Agbada Formation shales and would suggest that the shales and sand- by this study. stones of the formation have a similar source. The nature of the authigenic clay phases in the Agbada Formation The clay minerals are present as detrital and anthigenic sandstones suggests that the initial pore waters were weakly phases. Examination of the sandstones in a scanning electron micro- acidic to encourage the formation of kaolinite but later became scope has shown that authigenic kaolinite (Fig. 3) and to a lesser alkaline causing the kaolinite to become unstable whilst encouraging extent authigenic smectite (Fig. 4) are present but no authigenic the formation of authigenic smectite (de Segonzac, 1970). illite has been detected. The differences in the clay assemblages of the water-bearing Comparisons of the hydrocarbon bearing and the water bearing and the hydrocarbon-bearing sandstones are not always as distinctive sandstones of the formation have shown that the hydrocarbon-bearing as outlined above. Prozorovich (1970) pointed out that the degree 7 of difference between authigenic clay assemblages of hydrocarbon and cipitate as a cementing phase (Pittijohn et al, 1973). In the non-hydrocarbon bearing sandstones is dependent on the degree of Agbada Formation smectite is still preserved as a clay phase in the flushing of the formation waters by the incoming petroleum. Where sandstones because the diagenetic stage involving its transformation this flushing is incomplete authigenic clay phases may continue to has not been reached and consequently no Si02 would be availabl6 form in the hydrocarbon zone and there are examples of this in the from this source. Agbada reservoir sands. A schematic representation of a log through Petroleum engineering problems of the Agbada Formation reservoir such a reservoir in the western Niger delta is shown in Fig. 5. sandstones The incompletely flushed upper part of the oil-bearing reservoir As a result of the very friable nature of the Agbada reservoir has a higher water content and a lower permeability than the 'clean' sandstones, grains varying in size from fine sand to clay grade ( 1 fines' completely flushed sandstone beneath it. In the log shown, the high material are dislodged during movement of fluids in the reservoir resistivity of the 'clean' reservoir sand helped to draw attention and carried to the surface with the crude oil (Tig.l ). Mineralogical to the low resistivity but oil bearing, incompletely flushed sand- analysis of che "fines" has shown that they are composed of quartz and stone above. However, if there is incomplete flushing throughout kaolinite. an oil-bearing sandstone horizon its low resistivity could make The movement of these "fines" during recovery of the petroleum such reservoir sands difficult to differentiate from water bearing obviously poses engineering problems though their production also sandstone horizons and thus potential oil-bearing formations could helps to widen throat passages allowing movement of kaolinite book- be missed. lets which may otherwise have blocked such passages. However, in Petrological examination of the Agbada Formation sandstones the water-bearing sandstones the higher clay content provides a degree shows that there is only a limited amount of secondary silica of additional cohesion to the sandstones and the movement of "fines" cementation around the detrital quartz grains. The absence of such is reduced. There is also a greater tendency for the kaolinite book- cementation, which is reflected in the very friable nature of the lets to block the narrower throat passages in the water bearing sandstones, may be attributable to the presence of thick clay sandstones and thus reduce permeability (Muecke, 1979., Todd et coatings around many of the detrital grains (Fig. 6). The consensus of al., 1978). This latter effect is important should water injection opinion is that whilst thin clay coatings encourage pressure processes, whereby water is introduced through down dip wells, be solution and the formation of silica cements,thick clay coatings of used to enhance the recovery of petroleum. The water injected into the type found in the Agbada sandstones will inhibit such processes the water zone of the reservoir sand would dislodge fines and it during diagenesis (Heald, 1956., Siever, 1959., Pittman and Lumsden, is likely they would then also block throat passages and reduce 1968, Heald and Lavese, 1974). permeability. This problem is likely to be further complicated by A further factor that may affect secondary silica cementation the presence of smectite in the water zone of the Agbada reservoir is the release of Si02 during the transformation of smectite to sands which may swell as a reaction to the presence of the injected illite or chlorite via mixed layer clay minerals which may then pre- water and cause further formation damage. The effect of swelling clays on the permeability of a reservoir sandstone in the Agbacia. Formation is shown in Fig 9 Summary The Tertiary shales and sandstones of the Akata and Agbada For- mations nave suffered little diagenetic change since their deposition. ACKNOWLEDGEMENTS The clay mineralogy largely reflects the variations in the detrital depositional clay assemblage with the diagenetic trans- formation of smectite to mixed layer illite-smectite only occurring The authors wish to thank the University of Benin, Nigeria for its sponsorship of the research and the Nigerian National in some horizons. The^reservation of smectite at burial temperatures Petroleum Corporation for providing part of the field expenses in excess of what might be expected from the accepted models of and core material. We are also grateful to the Gulf Oil Company clay diagenesis is thought to reflect the undercompaction of the (Lagos), the Mobil Oil Producing Company of Nigeria and the Shell Development Company (Lagos) for supplying core material sediments arising from their rapid deposition. used in this study. Finally we should like to thank Dr. Peter TV' . A • c • I '-> . In the Agbada Formation there are significant differences be- Bush, Dr. Francis Fatona ana Dr. Richard Selley for their help- ' A tween the clay mineral assemblages of the water-bearing and the ful discussions and suggestions during the course of the research. hydrocarbon-bearing sandstone reservoirs. In the latter the early migration of hydrocarbons into the reservoir sands limited the development of authigenic clays, preserving the early formed authi- genic kaolinite, and preventing its corrosion and the formation of authigenic smectite as found in the water bearing sandstones. This evidence for the early migration of hydrocarbons also lends support to the concept of the generation of hydrocarbons in the paralic Agbada shales adjacent to the reservoir sandstones rather than in the more distant Akata shales. The poorly cemented very friable nature of the Agbada sandstones reflects again the minimal effects of diagenesis within the sediments. The lack of diagenetic alteration of the clays which could have released silica into pore solutions and the presence of thick clay films around the detrital grains are considered to be the principal causes for the poor development of silica cementation in the sandstones. A major consequence of the very friable nature of the reservoir sandstones is that the migration of fluids through them can cause movement of 'fines' which are liable to produce various problems in the recovery of the hydrocarbons from the reservoirs. Table 1 Relative amounts of clay minerals in the<2^fraction of the Akata and Agkada Formation shales compared to the Recent Niger Delta sediments. Akata Formation Agkada Formation Recent (Porrenga 1966) TABLE X - Clay mineralogy of Akata Formation shales from two boreholes. Kaolinite 30 - 60 40 - 75 35 - 60 % A and B. c - 25 10 - 15 - 30 •10 30 11,060 105°C Bll.B 20 - 60 20 11,930 120°C 45 - 45 10 11,940 120°C 50 - 40 10 11,945 120°C Burial temperatures estimated from data of Avbovbo (1978). rtoo -o Logs of three wells in the Niger Delta showing the stratigraphic succession. Localities of wells from which borehole samples have been examined. Electron-micrograph of authigenic kaolinite in hydrocarbon-bearing sandstone of the Agbada For- mation . Electron-micrograph of honeycomb authigenic smectite in water-bearing sandstone of the Agbada Formation. Schematic representation of a log through a hydro- carbon and water bearing sandstone of the Agbada Formation. Electron-micrograph showing clay coatings on the detrital quartz grains in a sandstone of the Agbada Formation. Electron-micrograph of a typical pore space in an Agbada Formation sandstone showing the poor degree of cementation. Electron micrograph of a smectite in a sandstone of the Agbada Formation - note its swelling reac- tion in the presence of the drilling fluid. NtOo CD