THE PETROLEUM SYSTEM OF NIGERIA.pdf

UNIVERSITE IBN TOFAIL FACULTE DES SCIENCES DEPARTEMENT DE GEOLOGIE KENITRA LICENCE FONDAMENTALE: « SCIENCES DE LA TERRE ET DE L’UNIVERS OPTION : GEORESSOURCES »

PROJET FIN D’ÉTUDES THE PETROLEUM SYSTEM OF NIGERIA

Présenté par :

Mr. ISINUGBEN Onoiseide Samuel Soutenu le 21/06/2012 devant le jury de : Pr. HAFID M. Pr. BENAMMI M. Pr. ECHERFAOUI H.

Encadré par :

Prof. HAFID Mohamad.

ACKNOWLEDGMENTS I would like to acknowledge certain persons who made this project possible. First and foremost I thank God Almighty for giving me the energy and the Grace to complete this work. I profoundly say a million thank you to Pr. Hafid Mohamad, for haven given me his time, advice, guidance throughout the whole period of this project work. My gratitude goes to all the professors Faculty Members of the Department of Geology, Faculty of sciences, Ibn tofail University for their educational endeavors and for their qualities imbibed in me over my three years stay at the department. Finally, a big thank you goes to my family, my Father Mr. Isinugben Samuel, my sisters, brother, my colleagues in class and to everyone who cared, helped and saw this project to the fullest.

CONTENT

LIST OF FIGURES .......................................................................................3 LIST OF TABLES Fig. 1:- Burial of Organic materials by sediments ......................................14 Fig. 2: Molecular Structure and boiling point of alkane: (Hunt, J. M. 1996). ......................................................................................................................16 Fig. 3:- Molecular structures of Cyclobutane (A), Cyclopropane (B), and Cyclohexane (C) ..........................................................................................18 Fig. 4:- Molecular structure of the benzene.................................................18 Table.1:- Dry and Wet Natural Gases .........................................................20 Fig. 5: The Essential Elements of a Petroleum System ...............................24 Fig.6:- Maturation process from the organic matter ....................................27 Fig. 7: Diagram showing the composition of different Kerogen types and the changes as a function of maturation during progressive burial: (Van Krevelen) .....................................................................................................28 1

Fig. 8: Relative quantities of hydrocarbons produced in fine-grained sediments. The areas under the curves are proportional to masses as carbon. : Modified from Tissot, B. P., and D. H. Welte (1984). ..............................30 Fig.9: Relative gas yields from organic matter buried in fine-grained sediments as a function of temperature: (a) Sapropelic source and (b) humic Hunt, J. M. (1996)........................................................................................31 Fig.10: Time-temperature dependence of petroleum genesis. From: Connan, J. (1974). ........................................................................................33 Fig .11: Diagram of Primary and Secondary hydrocarbon migration .........36 Fig.15: Showing (1) a very well sorted rock grain (high porosity); (2) a poorly sorted rock grain (better reservoir)...................................................41 Fig.16: Permeability and grain size and shape ............................................43 Fig.17: Capillary pressure effects in reservoirs ...........................................44 Fig.18: The distribution of fluid in a reservoir rock ....................................45 Fig. 19:-Different types of stratigraphic Angular unconformity traps (a–c) and structural Fault and salt dome (b-d) oil traps ........................................47 Fig. 20: Anticlinal Structural Trap ..............................................................48 Fig. 21: Salt dome Structural Trap ..............................................................49 2

Fig. 24: Lens Stratigraphic Trap ..................................................................53 Fig. 25: - Pinch-out Stratigraphic trap .........................................................53 Fig. 27:- Nigeria’s geopolitical division ......................................................56 Fig. 28:-........................................................................................................58 Fig. 29: The south-south Oil and Gas producing States (Niger Delta region) and States with Potential reserves ...............................................................59 Fig. 30: Stratigraphic column showing the three formations of the Niger Delta. Modified from Shannon and Naylor (1989) and Doust and Omatsola (1990). ..........................................................................................................64 Fig.31:- Schematic section through the axial potion of the Niger Delta, showing the relationships of the tripartite division of the tertiary sequence to basement (Doust and Omatsola, 1990)....................................................65 Fig.32: - Diagram showing how the coastline of the Niger Delta has prograded since 35 Ma. The delta has advanced seaward over 200 km and has broadened from a width of less than 300 km to a width of about 500 km. modified from Whiteman (1982)..........................................................68 Fig. 33: Diagram showing the 5 depo belts of the Niger delta ....................70 Fig.34: Distal delta Depobelt showing continental slope/rise result of internal gravity tectonics on sediments, Ocean crust (I), The Late 3

Cretaceous-Early Tertiary section (II) has low velocity gradient, probably marine shales, whereas the Late Tertiary (III) has a normal velocity gradient, suggesting a much sandier facies. Modified from Lehner and De Ruiter, 1977; Doust and Omatsola, 1990. ...................................................71 Fig.35:- Niger Delta oil field structures and associated traps. Modified from Doust and Omatsola (1990) and Stacher (1995).Figure also applies below when discussion the Niger delta petroleum traps in IV.5.5 below. .............72 Fig. 36: - Generalized cross section of the offshore part “northeastsouthwest” of the Niger Delta Region. The Albian unconformity at base of the “Turonian sandstone” is the top of the syn-transform rocks, ................74 Fig. 37: Generalized stratigraphic column of the Niger Delta ....................79 Fig.38 :- Subsurface depth to top of Niger Delta oil kitchen showing where the Akata Formation is in the oil window and where a portion of the lower Agbada is in the oil window. Contours are in feet. Modified from Evamy and others (1978) .........................................................................................83 Fig. 39: - The central portion of the Niger Delta showing the relation of source rock, migration pathways and hydrocarbon traps related to growth faults, modified from Stacher (1995). .........................................................84 Fig. 40: - Map of Niger Delta showing Province outline (maximum petroleum system); bounding structural features; minimum petroleum system as defined by oil and gas field center points from (Petroconsultants, 4

1996a); 200, 2000, 3000, and 4000m bathymetric contours; and 2 and 4 km sediment thickness. ......................................................................................85 Fig. 41: - Areas in the Niger Delta where Source rock and Reservoir rocks are abundant .................................................................................................87 Fig. 42: -Diagram showing Structural and Stratigraphic traps types and their associated seals in the Niger Delta ......................................................88 Fig. 43: - Events chart for the Niger Delta Petroleum System ....................93

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List of figures

Fig. 1:- Burial of Organic materials by sediments ......................................14 Fig. 2: Molecular Structure and boiling point of alkane: (Hunt, J. M. 1996). ......................................................................................................................16 Fig. 3:- Molecular structures of Cyclobutane (A), Cyclopropane (B), and Cyclohexane (C) ..........................................................................................18 Fig. 4:- Molecular structure of the benzene.................................................18 Table.1:- Dry and Wet Natural Gases .........................................................20 Fig. 5: The Essential Elements of a Petroleum System ...............................24 Fig.6:- Maturation process from the organic matter ....................................27 Fig. 7: Diagram showing the composition of different Kerogen types and the changes as a function of maturation during progressive burial: (Van Krevelen) .....................................................................................................28 Fig. 8: Relative quantities of hydrocarbons produced in fine-grained sediments. The areas under the curves are proportional to masses as carbon. : Modified from Tissot, B. P., and D. H. Welte (1984). ..............................30 6

Fig.9: Relative gas yields from organic matter buried in fine-grained sediments as a function of temperature: (a) Sapropelic source and (b) humic Hunt, J. M. (1996)........................................................................................31 Fig.10: Time-temperature dependence of petroleum genesis. From: Connan, J. (1974). ........................................................................................33 Fig .11: Diagram of Primary and Secondary hydrocarbon migration .........36 Fig.15: Showing (1) a very well sorted rock grain (high porosity); (2) a poorly sorted rock grain (better reservoir)...................................................41 Fig.16: Permeability and grain size and shape ............................................43 Fig.17: Capillary pressure effects in reservoirs ...........................................44 Fig.18: The distribution of fluid in a reservoir rock ....................................45 Fig. 19:-Different types of stratigraphic Angular unconformity traps (a–c) and structural Fault and salt dome (b-d) oil traps ........................................47 Fig. 20: Anticlinal Structural Trap ..............................................................48 Fig. 21: Salt dome Structural Trap ..............................................................49 Fig. 24: Lens Stratigraphic Trap ..................................................................53 Fig. 25: - Pinch-out Stratigraphic trap .........................................................53 7

Fig. 27:- Nigeria’s geopolitical division ......................................................56 Fig. 28:- Geological map of Nigeria showing the major geological components; Basement, Younger Granites, and Sedimentary Basins ........58 Fig. 29: The south-south Oil and Gas producing States (Niger Delta region) and States with Potential reserves ...............................................................59 Fig. 30: Stratigraphic column showing the three formations of the Niger Delta. Modified from Shannon and Naylor (1989) and Doust and Omatsola (1990). ..........................................................................................................64 Fig.31:- Schematic section through the axial potion of the Niger Delta, showing the relationships of the tripartite division of the tertiary sequence to basement (Doust and Omatsola, 1990)....................................................65 Fig.32: - Diagram showing how the coastline of the Niger Delta has prograded since 35 Ma. The delta has advanced seaward over 200 km and has broadened from a width of less than 300 km to a width of about 500 km. modified from Whiteman (1982)..........................................................68 Fig. 33: Diagram showing the 5 depo belts of the Niger delta ....................70 Fig.34: Distal delta Depobelt showing continental slope/rise result of internal gravity tectonics on sediments, Ocean crust (I), The Late Cretaceous-Early Tertiary section (II) has low velocity gradient, probably marine shales, whereas the Late Tertiary (III) has a normal velocity 8

gradient, suggesting a much sandier facies. Modified from Lehner and De Ruiter, 1977; Doust and Omatsola, 1990. ...................................................71 Fig.35:- Niger Delta oil field structures and associated traps. Modified from Doust and Omatsola (1990) and Stacher (1995).Figure also applies below when discussion the Niger delta petroleum traps in IV.5.5 below. .............72 Fig. 36: - Generalized cross section of the offshore part “northeastsouthwest” of the Niger Delta Region. The Albian unconformity at base of the “Turonian sandstone” is the top of the syn-transform rocks, ................74 Fig. 37: Generalized stratigraphic column of the Niger Delta ....................79 Fig.38 :- Subsurface depth to top of Niger Delta oil kitchen showing where the Akata Formation is in the oil window and where a portion of the lower Agbada is in the oil window. Contours are in feet. Modified from Evamy and others (1978) .........................................................................................83 Fig. 39: - The central portion of the Niger Delta showing the relation of source rock, migration pathways and hydrocarbon traps related to growth faults, modified from Stacher (1995). .........................................................84 Fig. 40: - Map of Niger Delta showing Province outline (maximum petroleum system); bounding structural features; minimum petroleum system as defined by oil and gas field center points from (Petroconsultants, 1996a); 200, 2000, 3000, and 4000m bathymetric contours; and 2 and 4 km sediment thickness. ......................................................................................85 9

Fig. 41: - Areas in the Niger Delta where Source rock and Reservoir rocks are abundant .................................................................................................87 Fig. 42: -Diagram showing Structural and Stratigraphic traps types and their associated seals in the Niger Delta ......................................................88 Fig. 43: - Events chart for the Niger Delta Petroleum System ....................93

List of table Table 1:- Dry and Wet Natural Gases .........................................................15 Table 2:- Generalized lithostratigraphy of Niger Delta (from Nwangwu, 1990). ...........................................................................................................57 Table 3:- TABLE 3: - Table of formations Niger Delta area, Nigeria. Modified from (Short and Stauble, 1967) ...................................................68 Table 4:- Table 4: - Hydrocarbon habitat table, modified from Stacher (1995). ..........................................................................................................73

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I: INTRODUCTION Petroleum has been known and used by Man since the dawn of historical times. It gradually became the substance number one without which all economical activities of humans would stand still. In fact petroleum in one way or another pervades almost every aspect of our lives, from the transportation sector, to the energy sector, clothing sector and many others. The branch of geology which deals with the origin, occurrence, movement, accumulation, and exploration of petroleum is called Petroleum Geology. It is an applied science which makes use of concepts from almost all other geosciences disciplines including sedimentology, tectonics, stratigraphy and geophysics. In order to have a commercial hydrocarbon prospect, several necessary but generally not sufficient requirements must be met. In the present work, we propose to review all these requirements and see how they apply in a particular example, namely the petroleum system of Nigerian Delta.

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II: PETROLEUM: HISTORY ORIGIN AND CHEMISTRY GENERAL II.1. Definition of Petroleum Petroleum is from Greek, Petra (rock) and Latin Oleum (Oil), it is a mixture of gaseous, liquid, and solid hydrocarbons that occurs naturally beneath the earth's surface. It can simply be called fossil fuel (Fowler, 1929). II.2.Brief History of Petroleum Petroleum has been known throughout historical time. Its discovery goes back to more than 4000 years ago. In fact, according to two Greek historians Herodotus and Diodorus Siculus, asphalt was used in the construction of the walls and towers of Babylon; there were even oil pits near Ardericca close to Babylon and a pitch spring on Zacynthus. It was found in Great quantities on the banks of the river Issus in one of the Euphrates tributaries. Ancient Persian tablets indicate its medicinal and lighting uses in the upper levels of their society as at then. By 347 AD, oil was produced from bamboo-drilled wells in a town called “Sichuan” in China (Chisholm et al, 1911). After kerosene was distilled from petroleum, petroleum demand as fuel for lighting highly increased in North America and around the world thus in 1859, Edwin Drake drilled the first modern well near Titusville, Pennsylvania. A lot of other wells were dug within this period by different countries. Today, the world is heavily dependent on petroleum in almost every activity ranging from motive power, lubrication, fuel, dyes, drugs, and many more. 12

II.2.1.Origin of Petroleum There are two theories explaining the origin of petroleum: One is biotic and the other is abiotic. II.2.1.1 Biotic Origin In 1757, Mikhail Lomonossov originated an organic theory based on fossils that later became known as the “Rock Oil” theory. This theory postulates that: Fuel originates from bodies of animals and ancient forest material buried in the sediments (Fig. 1).  This fossil organic material lies under the influence of increased temperature and pressure acting during an unimaginably long period of time.  Petroleum is found in marine sediments at a well-defined temperature.  Finally, organic fossil materials under these conditions are transformed into “rock oil” due to burial, pressure and temperature change in depth.

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Fig. 1:- Burial of Organic materials by sediments

II.2.1.2 Abiotic Theory This theory was given by the Russians based on the fundamentals of chemistry and physics, particularly thermodynamics. It was confirmed when a “suite” of petroleum fluids (methane, ethane, propane, etc.) was observed to evolve from inorganic constituents resulting from high pressure and temperature experiment. Proponents of the abiotic theory argued that petroleum is naturally produced on a continual basis throughout the solar system, including deep within the mantle of the earth. Some main points backing this hypothesis are:  Methane is a common molecule found in huge concentrations and at great depth in the Earth  At the mantle-crust interface, located between 7 to 30 km, rising methane-based gasses hit pockets of high temperature causing 14

condensation of heavier hydrocarbons, giving rise to crude oil formation 

In the relatively cooler and more geologically stable regions around the globe, crude oil pools into reservoirs

If we combine the two theories, we see that the established biotic theory is a finite theory of relatively shallow reserves, leading to scarcity as expounded by the peak oil hypothesis. On the other hand, abiotic theory is a theory of plenty relatively deep reserves require that oil be searched according to this new paradigm. The abiotic theory has never been widely accepted and has been criticized as deficient. II.3.Chemistry of Hydrocarbons Petroleum is a mixture of hydrocarbons compounds (hydrogen + carbon) as well as some other non-hydrocarbon compounds such as nitrogen, Sulphur, oxygen, vanadium and nickel in small quantities (Chapman, 1983). It occurs naturally in the Earth as solids, semi-solids, liquids, gases or mixtures of any to give polymers depending on the environment. According to IUPAC nomenclature of organic chemistry, Hydrocarbon can be classified into:  Saturated hydrocarbons : alkanes and paraffins  Unsaturated hydrocarbons : the cycloalkanes and the aromatics  The asphalts and Resins 15

II.3.1.Saturated hydrocarbons II.3.1a.The Alkanes: The alkanes are the simplest of the hydrocarbon species, constituted of carbon (C) and hydrogen (H) atoms linked by a simple liaison bond. They have a general molecular formula of CnH2n+2. Examples are the methane (CH4), butane (C4H10), pentane (C5H12). Figure 2 shows other examples as well as their boiling point. (Tissot, 1984)

Fig. 2: Molecular Structure and boiling point of alkane: (Hunt, J. M. 1996).

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II.3.2.Unsaturated hydrocarbons II.3.2a.The cycloalkanes: The cycloalkanes are hydrocarbons containing one or more carbon rings to which hydrogen atoms are attached. On this ring, one or more linear or branched chains can be grafted. The hydrogen atoms occupy the free links on the carbon atoms. Their general formula is CnH2n .Examples includes cyclobutane (C4H8), cyclohexane (C6H12), cyclopropane (C3H6) (Fig, 3).

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Fig. 3:- Molecular structures of Cyclobutane (A), Cyclopropane (B), and Cyclohexane (C)

II.3.2b.The Aromatics: The Aromatics are unsaturated hydrocarbons with alternating double and single bonds between carbon atoms. Their general formula is CnH2n−6. They can come in two forms with benzene (C6H6) being the simplest form (Fig, 4). The first is formed by the substitution of one of the hydrogen atoms with alkanes and the second by addition of benzene ring.

Fig. 4:- Molecular structure of the benzene

II.3.3.The asphalts and Resins These are complex compounds of high molecular weight relatively rich in Sulfur (S), Oxygen (O), and Nitrogen (N), as well as traces of Nickel and Vanadium. They are soluble, chemically altered fragments of Kerogen, which 18

migrated out of the source rock for the oil, during oil catagenesis. They make up about 20% of crude oil and 50% of bitumen. (Chapman, 1983) II.3.4.Principal hydrocarbon family We can generally distinguish:  Natural Gas  Condensate  Crude oil (liquid hydrocarbons)  Solid hydrocarbons II.3.4.1.Natural gas Natural gas are composed principally of methane (CH4), they are divided into Dry gas and Wet gas (Table, 1). 

Dry gas is constituted of about 97% to 100% of methane and very little alkane quantity. It is formed as a result of bacterial activities in the early stages of diagenesis. They are usually formed at low temperature rate, reduced overburden depths, and under anaerobic conditions. They can also be called biogenetic gas.

 Wet gas have small amount of liquid present in humid form. They are natural gases resulting from the thermal alteration of Kerogen due to an increase in overburden pressure and temperature.

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Table.1:- Dry and Wet Natural Gases

II.3.4.2.Condensates The condensates are transitional hydrocarbons between gas and crude oil. They are gaseous in the subsurface but condensate to liquid at surface temperatures and pressures. Chemically, they are largely constituted of paraffins. II.3.4.3.Crude Oil Crude oil constitutes a large part of hydrocarbon. They are a mixture of many hydrocarbons that are liquid at surface temperatures and pressures. They can be considered light or heavy depending on their content; they are considered light 20

when they have low density and high gas content, if their density is high they are said to be heavy. They are usually black in color but can change depending on the type of impurities in it. (Chapman, 1983) II.3.4.4.Solid hydrocarbon The solid hydrocarbons are Asphalts or bitumen usually solid in nature. They can be distinguished as follows: 

Hydrates:

In certain conditions of low temperature and pressure, methane can precipitate and crystallize to form methane hydrates, (a molecule of methane linked with six molecule of water) making it hydrated. Other hydrocarbon molecules can also form hydrates.  The Asphaltic sand : The Asphaltic sand is a consolidated sedimentary rock containing bitumen with high viscosity, high porosity and permeability. It is a dark colored solid to semi-solid form of petroleum 

Bitumen:

It is a natural viscous mixture of heavy hydrocarbons and sometimes of sulfuric products. They possess high viscosity, high density, and high content of Nitrogen, Sulfur, Vanadium and Nickel. Bitumen forms largely as a result of the 21

breaking of chemical bonds in Kerogen as temperature rises. Bitumen becomes petroleum at some point during migration.  The Oil shale The Oil Shale is a sedimentary rock basically of 99% clay minerals and 1% organic material (algae debris). They are rich in Kerogen and poor in bitumen. (Chapman, 1983)  Kerogen: It is of great geological importance because, as we will see below, it generates hydrocarbon oil and gas in the source rock. It is a mixture of solid, insoluble organic chemical compounds naturally occurring. The insolubility is as a result of its large molecular size and requires a lot of heat to break it down. It consists of about 80% carbons, with oxygen, hydrogen, sulfur, and some nitrogen.

III: CONCEPT OF THE PETROLEUM SYSTEM III.1. Definition of a Petroleum System A petroleum system is a dynamic hydrocarbon system that functions in a restricted geologic space and geological time scale. It consists of all the geologic

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elements and processes that are essential if an oil and gas accumulation to exist (Leslie, 1998). These essential elements include the necessity of having (Fig. 5): 

A matured source rock



A reservoir rock,



A Seal or Trap rock,



An Over burden rock sufficiently thick to bury the organic matter to depths where hydrocarbons can be generated



And the right timing of the processes of Hydrocarbon generation, Trapping and Accumulation.

As the last of these points indicates, these essential elements and processes must be well arranged in time and space to allow the conversion of the organic material in a source rock to a petroleum accumulation. Below, we propose to review all the geological aspects related to these elements starting with the source rock.

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Fig. 5: The Essential Elements of a Petroleum System

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III.2. Source Rock and Hydrocarbon Maturation As seen above, a source rock forms one of the necessary elements of a working petroleum system. It is a rock from which hydrocarbons are generated or are capable of being generated. A source rock is said to be mature when it starts generating oil and gas. Sedimentologically, a source rock consists thus of organic rich sediments which are deposited in marine, deltaic, lacustrine environments or carried into other environments by seas or rivers. The organic rich sediments are deposited as fine clastic clay or silt (Gluyas, 2004). III.2.1.Type of Source rocks As we saw above, Kerogen is the organic substance from which oil and gas is generated within a rock after heating by burial. Different types of Kerogen are deposited in various environments and permit to classify source rocks in three types: 1. Type I: Source rocks generated from algal remains deposited under anoxic condition in deep lakes depleted of oxygen (anaerobic). It generates waxy crude oils when submitted to thermal stress during deep burial. 2. Type II: Source rock generated from marine planktonic and bacterial remains preserved under anoxic conditions in marine environments: they produce both oil and gas when thermally cracked during deep burial. They are considered as the best source rocks.

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3. Type III: Source rock generated from terrestrial plant decomposed by bacteria and fungi under oxic or sub-oxic conditions: They generate gas with light oils when thermally cracked during deep burial. III.2.2.Maturation of Source Rock Maturation is the process of transforming organic matter into petroleum. It involves diagenesis and catagenesis of organic matter. The diagenesis concerns the attack and degradation of organic matter by bacteria thus removing its Oxygen, Nitrogen and Sulfur. The first stage of diagenese starts immediately after the depot of sediments and continues in depth with a temperature of 50-60°C (Fig. 6).

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Fig.6:- Maturation process from the organic matter

In the process of this reaction, the pH increases slowly and the environment becomes reduced leading to the formation of kerogen which is an insoluble residue. The kerogen is of three types as we see below (Fig. 7): III.2.2a. Type I sapropelic kerogen. It is formed from organic material with high content of lipids and long chained paraffin. The organic material it takes origin from includes spores, algae and any microbial animal matter broken down. It has little amount of oxygen and produces mainly oil, with less gas (CH4 and CO2). Type I kerogen is typical of oil shales in freshwater basins (Knut, 2010). III.2.2b. Type II Kerogen This type is a complex mixture of algae, other marine organisms, and plant debris (Fig, 7). It is an intermediary between Types I and Type III with a relative high H/C content, and low O/C content. It carries more oxygen compounds than Type I (Knut, 2010). III.2.2c. Type III humic Kerogen Like we see in Figure 8 below, the type III humic Kerogen is derived from humus in land plants rich in lignin, tannins and cellulose making it rich in aromatics. It has a low H/C content, and a high O/C content, reflecting the 27

composition of the precursor plant matter. It generates abundant water, CO2 and methane (CH4) in maturing (Knut, 2010).

Fig. 7: Diagram showing the composition of different Kerogen types and the changes as a function of maturation during progressive burial: (Van Krevelen)

It is after the diagenesis stage that the Kerogen produces the Oil and gas by action of temperature and pressure.

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III.2.3. Transformation of Kerogen into Hydrocarbons When temperature increases, the Kerogen transform into oil and gas as said earlier, this transformation starts from a temperature of about 50° C which helps us distinguish two principal catagenese phases in the Kerogen to hydrocarbon transform.  Liquid Hydrocarbon weak catagese phase (Oil window) 

Gas formation metagenese phase (Gas window)

III.2.3a.The weak catagenese phase This transformation of kerogen to Oil requires a very high temperature so conversion of organic plant and animal matter can occur. The Oil window stage is between temperatures 50° C to 120° C, with distance in depth of 2 to 4km. The three types of Kerogen discussed above would play the role of supplying different quantities of Oil, with the Type 1 Kerogen being the most important giving off mostly all its CO2 gas and so it’s oxygen/carbon content reduces gradually, thus transforming the Kerogen into hydrocarbon (Knut, 2010). III.2.3b. Metagenese phase or advance catagenese This stage has very temperatures from 120°C to 200°C.This high temperature breaks the C – C bond in the Kerogen leaving the hydrocarbon that has already been formed .This breakage is called thermal cracking . It continues until we have just gas and finally methane (dry gas) (Fig. 8). 29

Fig. 8: Relative quantities of hydrocarbons produced in fine-grained sediments. The areas under the curves are proportional to masses as carbon. : Modified from Tissot, B. P., and D. H. Welte (1984).

The sapropelic kerogens generate more abiotic methane (dry gas) and H2S than the Humic kerogens because it because of it organic seawater content which has a larger supply of sulfate, enabling sedimentary sulfate reduction (Fig. 9). (Tissot, 1984)

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Fig.9: Relative gas yields from organic matter buried in fine-grained sediments as a function of temperature: (a) Sapropelic source and (b) humic Hunt, J. M. (1996).

III.2.4. Factors influencing the maturation of kerogen There are various factors that affect the degree of thermal transformation of Kerogen into hydrocarbons of which the main factors are briefly discussed below. 1. Temperature 2. Pressure 3. Time 31

4. Minerals that increases the rate of reaction (catalysts)

III.2.4.1. Temperature Temperature is the most important factor in petroleum generation. Normal heat flow within the earth’s crust produces a gradient of 1.5°F for each 30m depth underneath the surface. The temperatures required to produce crude oil is between 1500m and 6096m deep. Temperatures below or higher than this depth can affect the transformation into crude oil. (Knut, 2010) III.2.4.2. Pressure: Pressure in source rock comes from the weight of other overlying rocks .This is called overburden pressure. Overburden pressure is a function of depth. It can Overburden pressure can cause the Hydrocarbons evolve directly from an immature stage to oil generation, oil cracking (wet gas stage), and finally to dry gas generation and it as well increases temperature. It can also reduce the rate of the reaction. III.2.4.3. Time: Long geological time is needed for the maturation of Kerogen. Time plays a major role in the burial, decomposition, transformation and maturation of the organic matter to occurs it takes a long time and to have a well matured source rock u need time so a rock subjected to 100◦C for 50 million years would be a better source rock compared to that subjected to same temperature in 10 million years. As Explained in Figure 10, time needs to be greater than the temperature, 32

because when there would be a point when transformation would cease due to excess increase in temperature

Fig.10: Time-temperature dependence of petroleum genesis. From: Connan, J. (1974).

III.2.4.4. Minerals or that increases the rate of reaction (catalyst): It has been long been suspected that minerals, particularly clay and ironstones are capable of affecting the rate of hydrocarbon generation. Limestone can affect maturation by reacting with CO2 and hence the equilibrium position in favor of production of additional petroleum hydrocarbons 33

III.3. Hydrocarbon Migration Migration is the transport of petroleum from the source rocks to the reservoir rocks. Petroleum tends to migrate through permeable rocks and rock fractures and faults until an impermeable barrier is reached. Migration is done in two ways distinguished to be primary and secondary. There are two main types of migration:  Primary Migration 

Secondary Migration

III.3.1. Primary migration Primary migration is the expulsion of petroleum from a source rock into adjacent permeable rocks (Knut, 2010). It takes place within the source rock by diffusion or pressure charge thus allowing the gas and oil to travel together as a single liquid phase. It occurs in pulses in which continuing generation of petroleum creates enough pressure to reopen fractures and pores. After the pressure is released by migration, the fractures and pores then closes (Fig. 11). Primary Migration covers hundreds of kilometers (Knut, 2010). III.3.2. Secondary migration The flow of petroleum from source rocks to reservoir rocks is called secondary migration. In this flow, the gas separates from the oil to give a two or three phase flow (Fig. 11). Once the primary expulsion from the source rock is achieved, the oil and gas phases would flow upwards through buoyancy and 34

hydrodynamic force. The resisting force to secondary migration is the capillary pressure. Secondary migration covers thousands of kilometers (Knut, 2010)

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Fig .11: Diagram of Primary and Secondary hydrocarbon migration

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III.4. Reservoir Rock By definition a reservoir rock is a subsurface volume of porous and permeable rock that has both storage capacity and the ability to allow fluids to flow through it. Hydrocarbons migrate upward through porous and permeable rock formations until they either reach the surface as seepage or become trapped below the surface by a non-permeable cap rock which allows them to accumulate in place in the reservoir (Fig. 12).

Fig. 12:- A Oil reservoir

There are different types of reservoir rocks of which the most important two are:  Sandstone reservoirs which formed by the accumulation of large amounts of clastics sediments in different dispositional environment such as deltas, lakes and rivers. Their porosity and permeability is controlled by primary synsedimentary factors such as grain size,

37

sorting, and secondary post-sedimentary factors such as packing and fracturing of the sediments  Carbonate reservoirs which are accumulated in marine sedimentary environments with little or no clastic material input show porosities are mostly vuggy where dissolution vugs are generally larger than grains, intergranular (between grains), intragranular or cellular (within grains), and chalky.

III.4.1. Physical properties of a reservoir rock The most important physical properties that have a bearing on the capacity of a rock to act as a reservoir for hydrocarbons, accumulate them and retain them are discussed below. III.4.1.1. Area and thickness: The area and thickness of a reservoir rock determine the volume of reserves in the sense that the greater the area and thickness of this rock are, the greater will be the potential for large accumulations of oil and gas (Fig. 13). III.4.1.2.Porosity: Porosity is the main property of a reservoir rock that reflects its fluid storage capacity. It is the ratio of void space in this rock to its total volume. Porosity () = (𝑽𝒐𝒍𝒖𝒎𝒆 𝒐𝒇 𝒗𝒐𝒊𝒅 𝒔𝒑𝒂𝒄𝒆)/(𝑻𝒐𝒕𝒂𝒍 𝒗𝒐𝒍𝒖𝒎𝒆 𝒐𝒇 𝒓𝒐𝒄𝒌). 38

Fig.13: Showing the proportion of area to thickness

Three types of porosity can be distinguished as described below:  Primary Porosity refers to the amount of pore space present in the sediment at the time of its deposition. It is usually a function of the amount of space between rock forming grains. It is thus also termed “syn-sedimentary” porosity.  Secondary Porosity designates post depositional porosity resulting from porosity creating diagenitic and tectonic processes such as groundwater dissolution, recrystallization and fracturing.  Total Porosity vs. Effective Porosity: Total porosity is all void space present in a rock whereas effective porosity is the part of this total void volume that corresponds to interconnected pores (see permeability in III.4.1. 4). Effective porosity is thus the volume available to free fluids circulation (Fig. 14) ( Chilingar et al, 2005)

39

Fig.14: Diagram of Effective vs. Non-effective Porosity

III.4.1.3a. Factors controlling porosity Porosity is largely controlled by sedimentological and diagenitic factors of which the main ones are sorting, grain packing, roundness, the

mineralogy and

amount of cement. 1. Sorting

Sorting is a process by which the agents of transportation, especially running water, naturally separate sedimentary particles that have some particular characteristic (such as size, shape or specific gravity) from associated but dissimilar particles. Well sorted rock grains are thus of the same size and shape. When the grains are well sorted and of similar size and shape, the intergranular space they leave between them offers a large amount of pore space and thus a high porosity. But if the grains are poorly sorted and come with a wide variety of sizes and shapes the smaller grains will partially fill 40

the intergranular space between greater grains thereby reducing the void that otherwise would have been left as porosity (Fig. 15).

Fig.15: Showing (1) a very well sorted rock grain (high porosity); (2) a poorly sorted rock grain (better reservoir)

2. Grain packing Grain packing refers to the spacing patterns of grains in a sedimentary rock and is a function mainly of grain size, grain shape, and the degree of compaction of the sediment. 3. Compaction Compaction occurs over a long period of time and sediments accumulate then create formations that are thousands of feet thick. The weight of the overlying sediments squeezes the particles together as well as the water in between the pores to give a really tight arrangement. It is dependent not only on overburden pressure 41

but also on the different types of clastic materials present in the formation. Compaction affects porosity and permeability by reducing the amount of interconnected pore space to give a good reservoir rock. 4. Cementation It is the crystallization or precipitation of soluble minerals in the pore spaces between sedimentary particles. Minerals in solution crystallize out of solution to coat grains and may eventually fill the pore spaces completely. Cementation reduces porosity. III.4.1. 4.Permeability: Permeability is a measure of the ease with which fluid flows through a formation. Permeability can be between; interconnected porosity, intergranular or intercrystalline porosity, interconnected fractures. These factors determine the rate of permeability: the size and shape of the formation, its fluid properties, the pressure exerted on the fluids, sorting, cementing, fracturing, residual fluid saturation and the amount of fluid flow. Permeability is measured in Darcy; the volumetric rate of flow is proportional to the pressure gradient. Q= K( A)/µ × ΔP/L Permeability can be horizontal and vertical; the horizontal permeability is measured parallel to the bedding planes of the reservoir rock while the Vertical permeability is measured across the bedding planes and is usually less than 42

horizontal permeability because of the arrangement and packing of the rock grains during deposition and subsequent compaction (Fig. 16).

Fig.16: Permeability and grain size and shape

Whereas Porosity is generally not dependent on grain size, Permeability is always dependent on grain size. III.4.1. 5.Capillary pressure: Capillaries are channels between grains which connect pores together, sometimes called pore throats. When there are several fluids in the rock, each fluid has a different surface tension and adhesion that causes a pressure variation 43

between them. So as the size of pores and channels decreases, the surface tension of fluids in the rock increases. This pressure is called capillary pressure and is often sufficient to prevent the flow of one fluid in the presence of another. When water comes in contact with air, the adhesive forces would make it rise slightly against the walls of its container and the pull of gravity to form a concave meniscus (Fig, 17).

Fig.17: Capillary pressure effects in reservoirs

In a reservoir, the smaller the opening of the pore throat diameters, the greater the capillary pressure. In general, large pores throat yields a lower capillary pressure and lesser amounts of adsorbed hydrocarbons while a small pores throat yields higher capillary pressures and greater amounts of adsorbed hydrocarbon. (Chilingar et al, 2005) III.4.2.Fluid distribution in a reservoir rock 44

Petroleum reservoirs generally consist of three fluids precisely Natural Gas, Oil and Water. As petroleum and water accumulates in a reservoir there would be a vertical separation between them as a result of the difference in the specific gravity. Gas which is lighter rises to the top of the reservoir as shown in the diagram below, after which a gas to oil transition zone which is a relatively thin is located above the oil accumulation. The oil accumulation may be of primary importance because it contains crude oil and possibly saturated gas. Below the oil accumulation in most reservoirs is an oil-water transition zone of varying thickness, filled with water and oil. Finally, beneath the oil-water transition zone is that part of the formation completely saturated with water (Fig. 18).

Fig.18: The distribution of fluid in a reservoir rock

III.5. TRAPPING 45

A hydrocarbon trap is any combination of physical factors that promote the accumulation and retention of petroleum in one location. A trap forms when hydrocarbons are limited by a barrier when the buoyancy force driving their upward migration through a permeable rock cannot overcome the capillary forces of a sealing medium anymore .The rocks that form the barrier are referred to as Caprocks. (Gluyas, 2004) Depending on geologic processes like faulting, folding, piercing, deposition and erosion different types of traps can be generated within a given basin. Traps are thus genetically classified into three main types (Allen, 2005) (Fig. 19):  Structural Traps 

stratigraphic,

 Mixed traps which result from combination of the above types Below is a description of each one of these three types

46

Fig. 19:-Different types of stratigraphic Angular unconformity traps (a–c) and structural Fault and salt dome (b-d) oil traps

III.5.1. Structural Traps Structural traps are formed by the deformation of rock strata within the earth’s crust. This deformation can be horizontal compression or tension, vertical movement and differential compaction, resulting in folding, tilting and faulting within sedimentary rock formations. Three main Structural trap types are distinguished: anticlines, domes and faults. 47

III.5.1.1. Anticlinal Traps Anticlinal traps are the oldest known traps. The porous and permeable reservoir rocks were laid down horizontally folded upward in an arch form and hydrocarbons migrate into them. As we discussed earlier, at the top of the rock lies the impermeable cap rock which prevents farther migration hydrocarbons and results into their accumulation (Fig. 20).

Fig. 20: Anticlinal Structural Trap

III.5.1.2. Salt Dome A salt dome forms by piercing or intrusion of stratified rock layers from below by ductile non porous salt owing to its density inversion with respect to overlaying more compactable sedimentary layers (Fig. 21). This intrusion causes 48

the lower formations in the layer to be uplifted and truncated along the sides of the intrusion, thus creating a dome or anticlinal folding. Hydrocarbons migrate into the porous and permeable beds on the sides of the column of salt and accumulate in the traps around the outside of the salt plug if a seal or cap rock is present. (Schreiber, 1980)

Fig. 21: Salt dome Structural Trap

III.5.1.3. Fault Traps Faulting of stratified rocks is as a result of vertical and horizontal stress. At some point the stress breaks the rock layers, resulting in the rock faces along the fracture to move or slip past each other into an offset position. As illustrated in Figure 22, the seal is formed when a non-porous rock face is moved into a position above and opposite a porous rock face, thus sealing off the natural flow of 49

hydrocarbons allowing them and forcing it to remain in place and accumulate in the closed space thus created within the sealed porous reservoir rock.

Fig. 22: Fault structural trap

50

51

Fig. 23: Pictures of Faulting and Folding in the field

III.5.2. Stratigraphic Traps Stratigraphic traps are formed as a result of variations between or within stratified rock layers in the absence of tectonic, creating change or loss in permeability from one area to another. There are various types of stratigraphical traps which include; an unconformity trap, a lens trap and a pinch-out trap. III.5.2.1. Lenticular traps Lenticular traps are porous areas surrounded by non-porous strata formed from ancient buried sand bodies deposited in clastic environments such as river sand bars, beaches and deltas (Fig. 24).

52

Fig. 24: Lens Stratigraphic Trap

III.5.2.2. Pinch-out or lateral graded trap A trap created by difference in lateral deposition when the environmental deposition changes up-dip is referred to as a pinch-out trap (Fig. 25). The termination of a reservoir against a nonporous sealing rock by thinning forms the pinch-out traps.

Fig. 25: - Pinch-out Stratigraphic trap

53

III.5.2.3. Angular Unconformity Trap An angular unconformity trap occurs when an inclined older petroleum bearing rock subjects to the force of a younger non-porous one. This condition may occur whenever an anticline, dome or monocline are eroded and then overlain with younger, less permeable strata (Fig. 26).

Fig. 26: - Angular Unconformity

IV: THE PETROLEUM SYSTEM OF NIGERIA IV.1. Regional Overview of the Geology of Nigeria Nigeria lies on the west coast of Africa, between longitudes 3° and 14°E and latitudes 4° and 14°N of the Greenwich Meridian. It is bordered to the north by the Republics of Niger and Chad, to the west by the Republic of Benin, to the east by 54

the Republic of Cameroon and on the south by the Atlantic Ocean and the gulf of guinea. Its land mass is of 923,768 square kilometers (Fig. 27). (Nuhu, 2009) Nigeria’s climate varies from rainy in the tropical coastal zone to dry in the subtropical inlands. The Niger delta is located at the intersection of Lokoja River with the Atlantic Ocean. Its main affluents are the Niger River and the Benue River which divide Nigeria into a Y shaped figure. The “V” part of this Y shape corresponds to the northern part of the country (Northern Savannah) which lies just south of the great Sahara. On the south-western lies the West African coast and south-eastern

part

are

numbers

of

55

clearly

defined

states.

Fig. 27:- Nigeria’s geopolitical division

56

Nigeria’s geology consists of three major litho-petrological components, which are (Fig. 28).  The Basement Complex which consists of a Migmatite-Gneiss Complex, a Schist Belts and an Old Granites. Its age is more than 600 MA years (Precambrian) (Nuhu, 2009).  Jurassic Granites, that forms magmatic ring complexes around Jos and other parts of north-central Nigeria. They are about 145-200 MY old (Jurassic). Both their structure and petrology differ from those of the Older basement Granites.  And Sedimentary Basins: Nigeria contains eight distinct sedimentary basins which range in age from Craterous to Tertiary (Fig. 28). They are named: the Niger Delta Basin, the Anambra Basin, the Lower, Middle and Upper Benue Trough, the Chad Basin (bornou), the Sokoto Basin (Iullemmeden), the Mid-Niger (Bida-Nupe) Basin and the Dahomey Basin Oil and Gas has been discovered in the Niger delta basin, the Sokoto Basin, the Mid-Niger basin, the Anambra Basin, the Benue basin and the Chad basin but the Niger delta basin is the most important of all these basins because of it yields the most important oil and gas production of the country (Fig. 29).

57

Fig. 28:- Geological map of Nigeria showing the major geological components; Basement, Younger Granites, and Sedimentary Basins

58

Fig. 29: The south-south Oil and Gas producing States (Niger Delta region) and States with Potential reserves.

59

IV.2.Brief History of Petroleum discovery in Nigeria Historically, petroleum in Nigeria dates back to beginning of the twentieth century when the first known Mineral Survey was carried out in a town then called Araromi presently Ondo State in 1905. Real exploration of the country’s hydrocarbon potentials however didn’t effectively started until 1908 when a German company named “The Nigerian Bitumen Corporation” (NBC) was able to dig 16 shallow boreholes that confirmed a line of oil seepage in the Eastern Dahomey Basin in Okitipupa, Western Tar Sand deposit Region. In 1937, after World War I, Shell-D’Arcy, a branch of Shell and Royal Dutch resumed oil exploration in Owerri a northern part of the Niger Delta. Luckily on June 5, 1956 after drilling 28 wells and 25 core holes all dry the new operator, Shell-BP, struck oil at Oloibiri now called Bayelsa State. With this milestone, exploration activities started earnestly in the Niger Delta region and Nigeria’s first 5,000 barrels shipment of crude oil to the international market was done in 1958. The nation steadily rose to the sixth position on the export scale of the Organization of Petroleum Exporting Countries (OPEC) by the mid-1970s due to Shell’s production mark of more than one million barrels par a day. Today, the production is about 2.35 million barrels per day ranking Nigeria 11th in OPEC and 14th World producers of petroleum and 10th in oil reserves. In Africa, Nigeria is the second largest oil producer after Libya and 1st in reserves. 60

IV.3.Geological Framework of the Niger Delta Basin The Niger delta basin is located in the Gulf of Guinea, offshore Nigeria which lies in the southern part of the country (Fig. 28). It has a total area of about 140, 000 km and is filled with a 12 km thick sedimentary pile. As can be seen in Table 2 and figure 30 which show the general stratigraphy of Niger Delta, the ages of the formations composing this pile range from Cretaceous to Tertiary. Figure 31 shows an onshore-offshore NNE-SSW cross section which illustrates the regional structural framework of the Delta.

IV.3.1 Stratigraphic Framework

The Stratigraphic column of the Niger Delta can be subdivided into two main sections: the syn-rift Cretaceous Section and the Tertiary Clastic wedge. A description of each one of these two main units is given below with an emphasis on the Deltaic Clastic Wedge which hosts the Petroleum System, object of the present report.

IV.3.1.1 Syn-rift Section

The Niger Delta is located on the West African Atlantic passive margin. Its basement is thus formed by Synrift sediments that accumulated during Cretaceous times. The syn-rift section consists of a succession of marine, marginal marine 61

clastics and carbonates that were deposited owing to a series of transgressive and regressive phases (Table, 2) (Doust and Omatsola, 1989). The oldest dated syn-rift sediments are of Albian age. The Synrift phase ended with basin inversion in the Santonian (Late Cretaceous). Renewed subsidence occurred as the continents separated and the sea transgressed the Benue Trough.

IV.3.1.2.The Niger Delta clastic wedge

The Niger Delta clastic wedge formed along a failed arm of a triple junction system that originally developed during breakup of the South American and African plates in the late Jurassic (Fig. 31). The two arms that followed the southwestern and southeastern coast of Nigeria and Cameroon developed into the passive continental margin of West Africa, whereas the third arm failed and formed the Benue Trough (Whiteman, 1982). Other Depo belts along the African Atlantic coast also contributed to deltaic build-ups.

62

TABLE 2: Generalized lithostratigraphy of Niger Delta (from Nwangwu, 1990).

63

Fig. 30: Stratigraphic column showing the three formations of the Niger Delta. Modified from Shannon and Naylor (1989) and Doust and Omatsola (1990).

64

Fig.31:- Schematic section through the axial potion of the Niger Delta, showing the relationships of the tripartite division of the tertiary sequence to basement (Doust and Omatsola, 1990).

The Niger Delta clastic wedge continued to prograde during Middle Cretaceous time into a depo-belt located above the collapsed continental margin at the site of the triple junction. Sediment supply was mainly along drainage systems that followed two failed rift arms, the Benue and Bida Basins. Sediment

65

progradation was interrupted by episodic transgressions during Late Cretaceous time. In Tertiary times, sediment supply was mainly from the north and east through the Niger, Benue and Cross Rivers. Cross and Benue Rivers provided substantial amounts of volcanic detritus from the Cameroon volcanic zone beginning in the Miocene. The Niger Delta clastic wedge prograded into the Gulf of Guinea at a steady increasing rate then continued basement subsidence. Regression rates increased in the Eocene, with an increasing volume of sediments accumulated since the Oligocene. The morphology of Niger Delta changed from an early stage spanning the Paleocene to early Eocene to a later stage of delta development in Miocene time (Fig. 32). The early coastlines were concave to the sea and the distribution of deposits was strongly influenced by basement topography (Doust and Omatsola, 1989). Delta progradation occurred along two major axes; the first paralleled the Niger River, where sediment supply exceeded subsidence rate. The Second, smaller than the first, became active during Eocene to early Oligocene basinward of the Cross River where shorelines advanced into the Olumbe-1 area (Short and Stauble, 1967). Late stages of deposition began in the early to middle Miocene, as these separate eastern and western Depobelts merged (Fig. 32). In Late Miocene the delta prograded far enough that shorelines became broadly concave into the basin. Accelerated loading by this rapid delta progradation mobilized underlying unstable shales. These shales rose into diapiric walls and swells, deforming overlying strata. The resulting complex deformation structures caused local uplift, which resulted in 66

major erosion events leading into the progradational edge of the Niger Delta. Several deep canyons, now clay filled, cut into the shelf and are commonly interpreted to have formed during sea level lowstands. The best known are the Afam, Opuama, and Qua Iboe Canyon fills.

Three major depositional cycles have been identified within Tertiary Niger Delta deposits (Short and Stauble, 1967; Doust and Omatsola, 1990). The first two cycles being mainly marine deposition, started with a middle Cretaceous marine incursion and ended in a major Paleocene marine transgression (Doust and Omatsola, 1990). The second of these cycles starting in late Paleocene to Eocene, shows the progradation of a true delta with an arcuate coastline dominated by wave and tide. These sediments range in age from Eocene in the north to Quaternary in the south. The last depositional cycle has sediments divided into 5 depobelts separated by major synsedimentary fault zones (Doust and Omatsola, 1990).

67

Fig.32: - Diagram showing how the coastline of the Niger Delta has prograded since 35 Ma. The delta has advanced seaward over 200 km and has broadened from a width of less than 300 km to a width of about 500 km. modified from Whiteman (1982).

IV.3.2 Tectono-Stratigraphic Framework IV.3.2.1 Depobelts Depobelts represent successive phases of delta growth. They are composed of bands of sediments about 30–60 km wide with lengths of up to 300 km. (Fig. 33), (Stacher, 1995). They form when paths of sediment supply are restricted by structural deformation, focusing sediment accumulation into restricted areas on the 68

delta. Depo-belts can eventually change location when local accommodation gets filled and the locus of deposition will shift basinward (Doust and Omatsola, 1990). Five major depobelts are generally recognized, each with its own sedimentation, deformation and petroleum history they are: Northern Delta, Greater Ughelli, Central Swaps, Coastal Swamp and Offshore (Fig. 33). These five depobelts can be regrouped into three provinces: IV.3.1.a.The northern delta province: It has the oldest growth faults that are generally rotational, equally spaced and increases in their steepness seaward and overlies a relatively shallow basement (see below). IV.3.1.b.The central delta province:

It has depobelts with well-defined

structures such as successively deeper rollover crests that shift seaward for any given growth fault. IV.3.1.c.The distal delta province: This is the most structurally complex of the provinces due to internal gravity tectonics on the modern continental slope (Fig, 34).

69

Fig. 33: Diagram showing the 5 depo belts of the Niger delta

70

Fig.34: Distal delta Depobelt showing continental slope/rise result of internal gravity tectonics on sediments, Ocean crust (I), The Late Cretaceous-Early Tertiary section (II) has low velocity gradient, probably marine shales, whereas the Late Tertiary (III) has a normal velocity gradient, suggesting a much sandier facies. Modified from Lehner and De Ruiter, 1977; Doust and Omatsola, 1990.

IV.3.2.2 Growth faults The main structural tectonostratigraphic process that controls deltaic sedimentation is syn-sedimentary growth faulting. Normal faults triggered by the movement of deep-seated, overpressured, ductile, marine shale have deformed much of the Niger Delta clastic wedge (Doust and Omatsola, 1989). Many of these faults formed during delta progradation and were syndepositional, affecting sediment dispersal. Fault growth was also accompanied by slope instability along 71

the continental margin. Structural complexity in local areas reflects the density and style of faulting. Simple structures, such as flank and crestal folds, occur along individual faults. Rollover anticlines are developed because of fault geometry and differential loading of deltaic sediments above ductile shales. More complex structures include collapsed-crest structures (Fig. 35).

Fig.35:- Niger Delta oil field structures and associated traps. Modified from Doust and Omatsola (1990) and Stacher (1995).Figure also applies below when discussion the Niger delta petroleum traps in IV.5.5 below.

72

IV.4. STRATIGRAPHIC FRAMEWORK The Niger delta stratigraphy is divided into three broad stratigraphic units (Fig. 30), (Nuhu, 2009) 1. The Akata Formation which ranges in age from Paleocene to Recent. 2. The Agbada Formation which ranges in age from Eocene to Pleistocene. 3. The Benin Formation which ranges in age from Oligocene to Recent. IV.4.1. THE AKATA FORMATION The Akata formation is defined in Akata 1 well which was drilled 80 km east of Port Harcourt, to a depth of more than 3, 680 m. Its top defined by the deepest occurrence of deltaic sandstone beds at 2188m depth (Short and Stauble, 1967). It is described in the well report (Doust and Omatsola, 1989) as dark gray shale (potential source rock), silts and clay, with rare streaks of sand 30% (potential reservoirs in deep water) of probable turbidity flow origin and of marine planktonic foraminifera which makes up 50% of the micro fauna assemblage and suggests shallow marine shelf deposition. The Age of the formation ranges from Paleocene to Recent (Fig. 30). The shales, which formed during early development stages of Niger Delta progradation, show their greatest thickness along the axis of the Benue and Bida Troughs. This formation which is also called the Imo Shale is exposed onshore in the northeastern part of Nigeria. It’s is overlain by the Agbada 73

formation. Their intersection zone is rich in plant remains and micas (Doust and Omatsola, 1989).

Fig. 36: - Generalized cross section of the offshore part “northeast-southwest” of the Niger Delta Region. The Albian unconformity at base of the “Turonian sandstone” is the top of the syn-transform rocks, The Senonian unconformity at base of the Araromi Shale is related to tectonism in the Benue Trough, the Miocene unconformity at base of the Upper Afowo

74

Formation is related to a depositional hiatus from the Eocene to the Miocene, The Oshoshun Formation is included with the Akata shale. Whiteman (1982)

IV.4.2. THE AGBADA FORMATION The Agbada Formation is a major petroleum-bearing unit defined in the Agbada 2 well which drilled about 11 km north-northwest of Port Harcourt, (Short and Stauble, 1967). This well bottomed at 2896m (9500 feet) without touching the base of this formation, which lies on top of the Akata Formation in Akata 1 well. The Agbada formation occurs throughout the Niger Delta clastic wedge; having a maximum thickness of about 3962 m. It crops out in the southern Nigeria between Ogwashi and Asaba. It’s also called the Ogwashi-Asaba Formation (Doust and Omatsola, 1989). The lithology consist of alternating sands, silts and shales within ten to hundred feet successions defined by progressive upward changes in grain size and bed thickness, this alternation represents sediments of the transitional environment comprising the lower delta plain (mangrove swamps, floodplain, marsh) and the coastal barrier and fluvial marine realms. The sand percentage in the formation varies from 30% to 70%. The formation ranges in age from Eocene to Pleistocene (Table 3).

75

TABLE 3: - Table of formations Niger Delta area, Nigeria. Modified from (Short and Stauble, 1967)

IV.4.3. THE BENIN FORMATION The Benin Formation forms the top part of the Niger Delta clastic wedge, from the Benin-Onitsha area in the north to beyond the present coastline (Short and Stauble, 1967). It is defined in the Elele 1 Well, drilled about 38 km northnorthwest of Port Harcourt. The top of the formation is the recent sub aerially76

exposed delta top surface and its base extends to a depth of 1403m, the base defined by the youngest marine shale. Shallow parts of the formation are composed entirely of non-marine sand (70–100%) deposited in alluvial or upper coastal plain environments during progradation of the delta. The lack of preserved fauna inhibits accurate age dating making an estimation of the age range from Oligocene to Recent (Fig. 37). The formation thins basin ward and ends near the shelf edge. The three formations in the subsurface of the Niger Delta (Akata, Agbada and Benin Formations) decrease in age basin ward, reflecting the overall regression of depositional environments within the Niger Delta clastic wedge. The Niger Delta time-stratigraphy is based on biochronological interpretations of fossil spores, foraminifera and calcareous nonnoplaknton.

77

78

Fig. 37: Generalized stratigraphic column of the Niger Delta

IV.5. THE PETROLEUM SYSTEM OF NIGERIA As we saw above a Petroleum System is a dynamic hydrocarbon system that consists of all the geologic elements and processes that are essential if an oil and gas accumulation is to exist. The following elements are all necessary in a basin: 

A matured source rock



A reservoir rock,



A Seal or Trap rock,



An Over burden rock sufficiently thick to bury the organic matter to depths where hydrocarbons can be generated,



And the right timing of the processes of Hydrocarbon generation, Trapping and Accumulation.

Here we propose to see how these requirements apply in the case of the Nigeria Petroleum System which is a working petroleum system called “The Niger Delta Petroleum System”. Characteristics of source rock, reservoir rock and traps of this system are summarized by the hydrocarbon habitat model shown in Table 4. This model was established by Stacher (1995) on the basis of sequence stratigraphy of some petroleum-rich belts in this area.

79

Table 4: - Hydrocarbon habitat table, modified from Stacher (1995).

IV.5.1. Source rock of the Niger Delta basin The source rock or rocks of the Niger Delta Petroleum systems is still a matter of discussion. Possibilities include (Evamy et al, 1978). 80

 Variable contributions from the marine interbedded shale in the Agbada Formation,  The marine Akata shale and  The Cretaceous shale The Agbada Formation has intervals with organic matter content sufficient to be considered as good source rocks but because of its immaturity in various parts of the delta, it rarely reaches enough thickness sufficient to produce a world class oil province. However, its poor source rock quality has been compensated by their great volume, excellent migration pathways, excellent drainage, permeable interbedded sandstone and rapid hydrocarbon generation resulting from high sedimentation rates. The Akata shale is present in large volumes beneath the Agbada Formation, volumetrically sufficient and matured to generate enough oil for a world class oil province such as the Niger Delta (Fig. 40). It was proposed that the marine Cretaceous shale beneath the Niger Delta is a viable source rock (e.g. pre-Albian super source rock) (Frost, 1997. But this section has never been drilled beneath the delta due to its great depth; therefore, no concrete data exist on its source rock potential). Based on organic matter content of both the marine shale in the Akata Formation, the interbedded shale with sandstone in the lower Agbada Formation and the underlying Cretaceous shales, we can assume that these three Formations 81

make up the bulk if not the totality of the source rocks of the Niger Delta (Fig. 39) (Evamy et al, 1978). IV.5.2. Maturation and hydrocarbon generation Organic matter present in the Akata Formation consists of marine shales land plant that is low in sulfur and deprived of any algal matter. This organic matter contains Type II/III of Kerogen with The total organic-carbon (TOC) contents ranging from 2 to more than 5 weight percent. The maturation of organic matter to petroleum started from late Eocene to the Present. The top oil window of the Niger delta petroleum system ranges in depth from 2743 - 4267m and a temperature 240°F (115° C) isotherm. In the northwestern portion of the delta, the oil window lies in the upper Akata Formation and the lower Agbada Formation, to the southeast, the top of the oil window is stratigraphically lower (up to 4000’below the upper Akata/lower Agbada formation) (Fig. 38). Therefore, the depth to any temperature is depends on the distribution of sand and shale. Evamy et al., 1978

82

Fig.38 :- Subsurface depth to top of Niger Delta oil kitchen showing where the Akata Formation is in the oil window and where a portion of the lower Agbada is in the oil window. Contours are in feet. Modified from Evamy and others (1978)

83

Fig. 39: - The central portion of the Niger Delta showing the relation of source rock, migration pathways and hydrocarbon traps related to growth faults, modified from Stacher (1995).

84

Fig. 40: - Map of Niger Delta showing Province outline (maximum petroleum system); bounding structural features; minimum petroleum system as defined by oil and gas field center points from (Petroconsultants, 1996a); 200, 2000, 3000, and 4000m bathymetric contours; and 2 and 4 km sediment thickness.

85

IV.5.3. Migration Faulting in the Agbada Formation provided pathways for primary and secondary petroleum migration that lead to petroleum accumulation. The migration is from adjacent source shales to the sandstones and possible migration happens through the growth faults ,occurring sequentially in each depobelts after their structurally deformation was complete, implying that the deformation in the Northern Belt would have been completed in the Late Eocene (Fig. 39). IV.5.4. Reservoir rock The Agbada formation is the reservoir rock formed of paralic sandstones and Eocene to Pliocene in age. They occur along Northwest-Southeast “oil rich belts” as well as along a number of North-south trends deposited in fluvial to deltaic environments in the Port Harcourt area suggesting that they correspond to the transition between continental and oceanic crust within the axis of maximum sediment thickness, (Tuttle et al., 1999). They were formed due to increase in the geothermal gradient, and shifts in deposition basin ward within subsequent Depobelts (Fig. 33) (Doust and Omatsola, 1990). The Agbada reservoir contains deposits of high stand and transgressive systems tracts in proximal shallow ramp settings ranging in thickness from less than 13 m to 46 m (Evamy et al, 1978). Its permeability is 2 Darcy and its porosity is 40%. (Weber and Daukoru, 1975) 86

Reservoirs for undiscovered petroleum below currently producing intervals and in the distal portions of the delta system may include turbidity sands within the Akata.

Fig. 41: - Areas in the Niger Delta where Source rock and Reservoir rocks are abundant

IV.5.5.Traps Both Structural and Stratigraphic traps are identified in the Niger delta. Structural traps consist mainly of synsedimentary growth faulting within the Agbada Formation which is triggered by the instability of the under-compacted, over pressured shale of this formation. A variety of structural trapping elements thus created includes: simple rollover structures, clay filled channels, structures with multiple growth faults, structures with antithetic faults, and collapsed crest structures (Fig. 35, 36 and 39) (Doust and Omatsola, 1990).

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Stratigraphic traps formed preferentially along the delta flanks where pockets of sandstone occur between diapiric structures (Fig. 42). Towards the delta toe, this alternating sequence of sandstone and shale gradually grades to essentially sandstone (Evamy et al, 1978; Stacher, 1995).

Fig. 42: -Diagram showing Structural and Stratigraphic traps types and their associated seals in the Niger Delta

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IV.5.6.Seals The primary seal rock in the Niger Delta is the interbedded shale within the Agbada Formation (Fig. 43). The shale provides three types of seals namely (Doust and Omatsola, 1990):  Clay smears along faults,  Interbedded sealing units against which reservoir sands are juxtaposed due to faulting,  And vertical seals Major erosional events on the delta flanks lead to the formation of some Miocene aged canyons filled with clays. These clays form the top seals for some important offshore fields. Seals associated with structural traps are formed by both shales and faults, whereas the seals associated with stratigraphic traps are generally shales (Fig. 42) (Doust and Omatsola, 1990). IV.5.7.Events chart of the Niger Delta Petroleum System: The history of the formation of the Tertiary Niger Delta Petroleum System can be summarized as follows (see chart, Fig. 43)  Rock units of the Niger Delta are from Paleocene to Recent in age and and subdivided into three major Formations: the Akata, the Agbada and the Benin Formations.

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 Most of the petroleum is sourced from the Akata Formation, with smaller amounts generated from the mature shale beds in the lower Agbada Formation and the Cretaceous marine shale.  The maturation started from Late Eocene in the lower Agbada Formation.  Petroleum generation within the delta began in the Eocene  Reservoir rocks are sandstones encountered throughout the Agbada Formation.  Trap and seal formation is related to gravity tectonics within the delta. Structural traps of simple rollover structures, clay filled channels, structures with multiple growth faults, structures with antithetic faults, and collapsed crest structures have been the most favorable exploration target; however, stratigraphic diapiric structures traps are likely to become more important targets in distal and deeper portions of the delta. Clay smears along faults, Interbedded shales, and vertical seals form seals enclosing the Akata shales.

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Fig. 43: - Events chart for the Niger Delta Petroleum System

V: CONCLUSION Petroleum is a fossil fuel consisting of hydrocarbons. As we saw above a working petroleum system is necessary for a basin to be an oil producing basin and a Petroleum system is a dynamic hydrocarbon system that consists of all the geologic elements and processes that are necessary for oil and gas accumulation to occur in this basin. These essential elements include the necessity of having a matured source rock, a reservoir rock, a seal rock and or trapping mechanism, an over burden rock sufficiently thick to bury the organic matter to depths where hydrocarbons can be generated and the right timing of the processes of hydrocarbon generation, trapping and accumulation. The application of these concepts to the Niger Delta, allow us to make the following conclusions:  There is a working and producing Petroleum system in the Niger Delta,  The source rocks of this system consist of Paleocene to Pliocene Marine shales of the Akata Formation, the marine interbedded shale of the Agbada Formation and a possible Cretaceous marine shale beneath the Niger Delta which have not so far been drilled,  The maturation started from Late Eocene in the lower Agbada Formation, 93

 The migration is from adjacent source shales and as well as some possible migration done along faults,  The reservoir rocks are Eocene to Pliocene paralic sandstones of the Agbada Formation,  The stratigraphic traps are formed along the delta flanks where pockets of sandstone occur between diapiric structures and related to turbidity geometry while the structural traps consists of simple rollover structures, clay filled channels, structures with multiple growth faults, structures with antithetic faults, and collapsed crest structures from shale flowage.  The seals are Clay smears along faults, Interbedded shales, and vertical seals.

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BIBLIOGRAPHY Ajibola, O.D.O, The Sequence Stratigraphy of Niger Delta, Delta Field, Offshore Nigeria. 2004. p. 99. Thesis Master of Science, Federal University of Technology, Akure, Nigeria Allen, P.A., Allen, J.R., 2005, Basin Analysis: Principles and Applications. Blackwell Science Ltd., Osney Mead, Oxford. 562p. ISBN-13:978-0-632-052073 Brownfield, M.E., Charpentier, R.R., 2006, Geology and total petroleum systems of the Gulf of Guinea Province of west Africa: U.S Geological Survey Bulletin 2207-C, 32 p. Chapman, R.E., 1983, Petroleum Geology, Elsevier Science Publishers B.V., Amsterdam. 435p. ISBN 0-444-42165-3 (Vol. 16) Chilingar, G.V., Buryakovsky, L.A., Eremenko, N.A. et al., 2005, Geology and geochemistry of oil and gas. Amsterdam. 395 p. ISBN-13: 978-0-444-52053-1 Emujakporue, G.O., Ekine, A. S., Nwankwo, C. N., Evaluation of the Hydrocarbon Maturity Level of Oil Well in Sedimentary Basin of the Northern Niger Delta, Nigeria. Journal of Applied Sciences and Environmental Management, 2009, Vol. 13, no 3, p. 79 – 82

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Frank J., Mark C., Mark G., 2003, Hydrocarbon Exploration and Production, Elsevier Science B.V., Amsterdam. 397p. ISBN: 0-444-82921-0 (Paperback) Gluyas, J., Richard S., 2004, Petroleum Geoscience. Blackwell Science Ltd., London. 386p. ISBN-13: 978-0-632-03767-4 Kenneth E. P., Clifford C. Walters., Paul J. M., Evaluation of kinetic uncertainty in numerical models of petroleum generation, 2006, AAPG Bulletin,Vol.90, no 3, p. 387-403 Knut, B., 2010, Petroleum Geoscience: From Sedimentary Environments to Rock Physics, Springer-Verlag, Berlin. 518p. ISBN 978-3-642-02331-6 Magoon, L.B., Beaumont, E.A., Petroleum Systems. In: Handbook of Petroleum Geology: Exploring for Oil and Gas Traps, American Association of Petroleum Geologists, Tulsa, 1999; p. 3-1 to 3-34. Magoon, L.B., Dow, W.G. (Eds.)., 1994, The Petroleum System: From Source to Trap, American Association of Petroleum Geologists, Tulsa: USA .Vol. AAPG Memoir No. 60, 655 p. Obaje, N.G, 2009, Geology and Mineral Resources of Nigeria. London. Springer. 218 p. ISBN 978-3-540-92684-9 Opara, A .I, , Prospectivity Evaluation of “usso” field, Onshore Niger Delta Basin, using 3-d seismic and well log data. Petroleum & Coal, 2010,Vol. 52, no 4, p. 307-315 Tissot, B.P., Welte, D.H., 1984, Petroleum Formation and Occurrence, SpringerVerlag: New York, 699 p. ISBN-3-510-13282

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Tuttle, M. L. W., R. R. Charpentier, M. E. Brownfield, 1999,The Niger delta petroleum system: Niger delta province, Nigeria, Cameroon, and Equatorial Guinea, Africa: U.S Geological Survey Open-file report 99-50-H. Weber, K.J., Daukoru, E.M., Petroleum geology of the Niger delta. 1975, Proceedings of the 9th World Petroleum Congress, Tokyo, Vol. 2, p.202-221

WEBOGRAPHY (list of sites consulted between the periods of the 26th April to the 10th of June). http://en.wikipedia.org/wiki/Petroleum http://wiki.answers.com/Q/What_year_was_oil_discovered http://wiki.answers.com/Q/What_year_was_oil_discovered_at_Oloibiri http://wiki.answers.com/Q/Who_discovered_oil http://www.elsevierdirect.com/companions/9780120885305/casestudies/01-Ch26-P088530web.pdf (The Origin of Petroleum in the Marine Environment) chapter 26. http://www.geol.lsu.edu/hart/EARTH_SCIENCE/COURSES/PET_GEOL/migration_files/Slide01.JPG http://www.glossary.oilfield.slb.com/Display.cfm?Term=fault%20trap Schlumberger: Oilfield Glossary

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http://www.glossary.oilfield.slb.com/Display.cfm?Term=primary%20migration http://www.priweb.org/ed/pgws/systems/traps/structural/structural.html http://www.priweb.org/ed/pgws/systems/traps/structural/structural.html Petroleum Research Institute http://www.priweb.org/ed/pgws/systems/traps/traps_home.html http://www.window.state.tx.us/specialrpt/energy/nonrenewable/crude.php https://www.google.co.ma/search?sourceid=chrome&ie=UTF8&q=Hunt%2C+J.+M.+(1996)#hl=fr&gs_nf=1&pq=tissot%20and%20welte%20the%20origin%20of%20pe troleum%20in%20the&cp=55&gs_id=w&xhr=t&q=tissot+and+welte+the+origin+of+petroleum+in+the+ marine&pf=p&sclient=psyab&oq=tissot+and+welte+the+origin+of+petroleum+in+the+marine+&aq=f&aqi=&aql=&gs_l=&pbx=1&b av=on.2,or.r_gc.r_pw.r_qf.,cf.osb&fp=21083781ae5fe38a&biw=1366&bih=624

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Département de Géologie, Faculté des Sciences, Kénitra, BP 133, Tel :05 37 32 94 28 Fax : 0 5 37 32 94 33

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