Tectonic evolution and petroleum system of the Benue Trough

Aruagha-Ndukwe, Ndukwe John

BOO689058

PETR. 6060

Prof. Amadu Mumuni

Table of ContentsABSTRACT2INTRODUCTION21 ORIGIN AND TECTONIC EVOLUTION OF THE BENUE TROUGH21.1 GEOGRAPHICAL LOCATION21.2 ORIGIN OF THE BENUE TROUGH21.3 THE TECTONIC PHASES22 PETROLEUM SYSTEM OF THE BENUE TROUGH22.1 TOTAL PETROLEUM SYSTEM22.2 PETROLEUM SYSTEM ELEMENTS22.2.1 SOURCE ROCK22.2.2 RESERVOIR ROCK22.2.3 SEAL ROCKS22.2.4 HYDROCARBON TRAPS22.3 PETROLEUM SYSTEM OF THE BENUE TROUGH22.3.1 THE PETROLEUM SYSTEM OF THE ANAMBRA BASIN22.3.2 SOURCE ROCKS22.3.4 Reservoir Rocks22.3.5 SEAL ROCK22.3.5 MIGRATION PATHWAYS22.3.6 PETROLEUM TRAPS22.3.7 PETROLEUM PRODUCTION22.3.8 EXPLORATION ACTIVITIES22.3.9 ENVIRONMENTAL ASPECTS OF HYDROCARBON EXPLORATION AND PRODUCTION ACTIVITIES23.0 CONCLUSION2 4.0 REFERENCES2

ABSTRACTThe Benue trough is an intracratonic structure occupying the central-eastern part of Nigeria with a Northeast trend. The trough originated as a result of a triple junction rift system which separated Africa from South America, also creating the south pacific and the gulf coast of guinea. The tectonic evolution of the trough was considered, with the accepted mechanism ranging from the Aptian to the Turonian-Maastrichtian age. The trough is divided into three geographical sections, each sections experiencing different tectonic and stratigraphic activities within the above mentioned period. The identified petroleum system boundaries were the Lower cretaceous petroleum system, the Upper Cretaceous petroleum system and the Palaeogene petroleum system. Due to the size of the scope the petroleum system considered was that of the Anambra basin, in which the Upper Cretaceous Petroleum System was singularly dominant. Five potential source rocks were identified, spread over the pre-santonian and post-santonian ages. Organic matter content showed high potential of hydrocarbon generation, with predominance of Type III kerogen, signifying gas generation potential. Viable reservoir rocks were identified, mostly siliciclastic in nature. Due to the diversity of tectonic activities which affected the basin, stratigraphic, structural and combination traps have been identified. Production activities a null in this area due to discouraging results from drilled exploratory well, the cost of applying more effective exploration methods and the presence of an more viable investment in the Niger Delta.

27

INTRODUCTIONNigerias current petroleum reserves has been estimated to be 37.1 billion barrels of oil and 180.8 trillion cubic feet of natural gas. (Organization of Petroleum Exporting Countries, 2013). These results are based on proven exploration information obtained from the onshore and offshore petroleum activities in the Niger-Delta, which is currently the only hydrocarbon producing region in Nigeria. Majority of the attention is given to the Niger-Delta; however, the hydrocarbon potential of the other sedimentary basins cannot be overlooked in order to ensure expansion of the national production and exploration base, thereby increasing the countries asset reserves.The Nigerian sedimentary basins, excluding the Niger-Delta basin, comprise of the Sokoto Basin, Benue Trough, Southeast Chad (Bornou) Basin, Benin Basin, Bida Basin, and the Anambra Basin (figure 1). These inland basins have constantly frustrated the efforts of explorers due to the little available geological information, cost of exploration and the lack of evidence to show large reserves to prompt investments. Therefore, numerous international companies have focused their resources on deep-water and ultra-deep-water offshore exploration and production. Of all the basins, I have chosen the Benue Trough not just because it represents one of the most important structures in Africa as it is part of the Mid-African rift system, with its origin linked to being the failed third arm of the rifting which opened the South American Ocean and the Gulf of Guinea (Olade M. A., 1975), but also that it presents an interesting basin both to study and for petroleum exploration.This paper briefly explores the Benue Trough sedimentary basin, concentrating on its tectonic evolution, the elements of its petroleum system and the production activities currently being carried out in it.

1 ORIGIN AND TECTONIC EVOLUTION OF THE BENUE TROUGH1.1 GEOGRAPHICAL LOCATIONThe Benue trough is a sedimentary basin which trends Northeast-Southwest across the Nigerian shield. It is approximately 1000 long and 50-100km wide, showing a Y-shape at its northern end. The left branch of the shape is referred to as the Yola basin while the right branch is the Gongola basin (figure 1). The basin is filled with cretaceous sediments ranging in thickness from 6000km to 5000km moving northeastwards. Majority of the Benue trough is located within Nigeria, barring the tip of the Yola basin which extends into Cameroun. The Benue trough is bordered by the Niger-Delta in the southwest and the Chad (Bornou) basin northeast. It is also located between two large massifs, the Jos plateau to the North and Adamawa to the south (figure 1).The Benue trough is divided into three main areas with different geological features (the lower, middle and upper Benue trough) (figure 1). The lower Benue comprises mainly of the Anambra basin and the Abakaliki uplift. The Abakiliki uplift is flanked on the south by the Afikpo syncline and the Ogija area, while the Anambra basin shares a border northwards with the Bida basin.The Middle Benue trough is the linear portion of the Benue trough. It is flanked by the Kardako basin (Benkhelil, 1986) on the north, and on the south, lies the Gboko regional fraction system (Samuel O. Akande, 2011).

Figure 1: Main geographical and structural units of the Benue trough and its surroundings. [1] Tertiary volcanics; [2] Quaternary and tertiary volcanics; [3] Cretaceous sediments; [4] Basement complex (Benkhelil, 1989)

The Upper Benue trough encompasses a more complex system of units due to cover tectonic activities. These units consist majorly of the Gongola basin, Yola basin and the Kaltungo inler. The Upper Benue trough features the Kerri-kerri basin on the northwest.The lower and middle Benue trough display flat or gentle rippling areas with a few low hills, while the upper Benue trough has a rugged topography due to the copiousness of cretaceous sandstone and tertiary volcanic plugs. (Benkhelil, 1989)1.2 ORIGIN OF THE BENUE TROUGHThe origin of the Benue trough has been greatly debated over the years. Earlier geologists (King, 1950) (Wright, 1968) (Lees, 1952) hypothesized that the trough is a halted rift structure. The absence of major rift faults systems, aside for on the rim of the trough, disproves this theory. However, the protagonists insist that the rift faults may have been obliterated or concealed over time. Another postulated theory attempted to clarify the origin of the trough using plate tectonics. It concluded that the Benue trough is an arm of a rift-rift-rift junction centered beneath the Niger delta. This theory was built on the observation of similarities between the Benue trough and the Central Red sea depression. (Burke, Dessauvagie, & Whiteman, 1970) (Burke, Dessauvagie, & Whiteman, 1971). Another supporting hypothesis was the action of Santonian folding which entailed the oceanic crust being engulfed by a minor subduction zone causing the Abakaliki section of the trough to be underlain by continuous oceanic crust. However, this theory has been criticized by (Nwachukwu, 1972) (Olade M. A., 1975) (Olade, 1978).(Grant, 1971) Considered the Niger Delta triple junction as a Rift-Rift-Fault formed by the South Atlantic, Benue trough and Gulf of guinea. This model involved the presence of several transform faults along the North coast of the Gulf of Guinea, crustal thinning and concomitant subsidence and a 30 million year time frame (from Albian to Santonian times) for these occurrences. (Ofoegbu, 1981) Has reviewed these theories and presented a more detailed analysis of the origin of the Benue trough.1.3 THE TECTONIC PHASESThe Benue trough has always been tectonically active from before the Aptian to recent times (Benkhelil, 1989). Its tectonic evolution started with a thermal plume, under the today Niger Delta, resulting in the doming, uplifting, then rifting of continental lithosphere causing the formation of a rift-rift-rift triple junction involving the Benue trough, the gulf of guinea and the South Atlantic. This occurred between the Aptian and Albian period (Burke, Dessauvagie, & Whiteman, 1970) (Burke, Dessauvagie, & Whiteman, 1971).Although tectonic events are noted to have occurred during the Cenomanian, Turonian and Senonian eras (Ofoegbu C. O., 1984), the major periods in which significant effect of tectonic activities have had adverse effects are the Santonian phase, Maastrichtian phase and the Tertiary period (Benkhelil, 1989). Both phases resulted in the acute compression, folding and deformation of deposited sediments within different sections of the Benue trough over time.The Cenomanian era featured a reduction of the tension in the Benue through, through upwelling of the mantle. The resulting thinning of the lithosphere caused the deposited Albian sediments to fold and the water body to regress. (Olade M. A., 1975)Tectonic activities during the Turonian times resulted in the renewed rifting of the Benue trough. (Ayoola, 1978) Highlighted that the tectonic activities cycled until the Santonian era, allowing the transgression of the sea and deposition of Eze Aku shale over the distorted Asu River group.During the Senonian times, the mantle upwelling of the trough reduced and resulted in the regression of the sea in later times. This regression caused the deposition of new sediments and deformation of the existing ones. Also, during this period there was an eastward movement in the center of tectonic activities due to the displacement of the mantle plume caused by the rotation of the African plate. (Olade M. A., 1975)The Santonian phase is the most severe of all the phases and gives the trough most of its unique properties (Ofoegbu C. O., 1981). It involved the compression and folding of the cretaceous sediments with intensity spreading in the lateral direction of the trough and towards its edges. Dips of over 30 have been noted, with some over 60km in length. In the Lower Benue trough, this phase is distinctly evident in the Abakaliki anticlinorium and is relatively absent in the Anambra syncline (Benkhelil, 1989). The middle and upper Benue trough show very little to no signs due to the action of this phase (Carter, Barber, & Tait, 1963). A distinct result of this phase is the uplifting and eroding of the trough edges, causing the deposition of clastic sediments across the trough (Burke, Dessauvagie, & Whiteman, 1972).The Maastrichtian phase affected most of the sediments in the trough, however it was not as intensive as the Santonian phase. (Benkhelil, 1989) Stated that the Maastrichtian era showed the most effect on the Upper regions of the structure, featuring compression of sediments resulting in concentric folding and fracturing. (Figure 2) shows the average direction of the main stress elements within the trough. The post-Maastrichtian era featured little in the upper Benue trough with gentle folding of its uniform sediments. In the middle and lower section of the trough, dual folding and deformation of previous sediments occurred during this episode (Wright, 1976).The tertiary phase signified a period of great stress release in the Upper Benue trough, after the end of the cretaceous compression, due to the occurrence of Post-cretaceous and volcanism. Similarities were observed between the post-Santonian tensional regime and the early tertiary period in the Lower Benue trough (Benkhelil, 1989).The main characteristic of this period is the effect of synsedimentary normal faults. The growth of the Paleocene Kerri-Kerri basin and the deformation of the Cretaceous sediments in the Yola basin were affected by faulting in these regions during the tertiary phase (Benkhelil, 1989) (Benkhelil, 1982).A singular theory cannot conclusively explain the tectonic evolution of the Benue trough due to distinct combination of upwelling, folding and faulting units. However, coupled with other theories, (Olade M. A., 1975) provides the best baseline for building a definite theory for the evolution of the Benue trough. (Figure 3) provides a diagrammatic representation of the proposed baseline phase theory for the evolution of the Benue trough.Figure 2: Distribution of the stresses related to the Mesozoic and Tertiary tectonic events. [1] Tertiary volcanism; [2] Tertiary and Quaternary sediments; [3] Cretaceous sediments; [4] Precambrian basement; [5] Direction of 1 for the end of the cretaceous phase.; [6] Direction for the 3 for the intra-upper Cretaceous extension; [7] Direction of 3 for the Tertiary phase; [8] Direction of 1 for the lower Cretaceous phase. (Benkhelil, 1986)

Figure 3: Proposed tectonic evolution of the Benue trough (Olade M. A., 1975)

2 PETROLEUM SYSTEM OF THE BENUE TROUGH2.1 TOTAL PETROLEUM SYSTEMThe definition and description of a petroleum system has evolved over time. The concept of a petroleum system was first provided by (Dow, 1974). He used the term Oil system instead to describe the process, also listing the elements required to complete the system.The term petroleum system was first used by (Perrodon, 1983) to describe the process of formation of a family of pools in the combined presence of source rock, reservoir rock and a seal.(Meissner, Woodward, & Clayton, 1984) Used the term Hydrocarbon Machine to describe a petroleum system as a rock sequence containing the elements necessary for the generation, migration and accumulation of oil and gas.(Magoon, 1988) Stated that a petroleum system should emphasize on the genetic relationship between the source rock and the resulting petroleum accumulation.Using contributions from previous work, and inserting new words where required, (Magoon, Dow, & Geologists, 1994) recently and conclusively defined a petroleum system as a natural phenomenon that encompasses a pod of source rock, all related oil and gas produced, and the elements and processes required to ensure hydrocarbon accumulation. The elements and processes are required to be present at a particular space and time to ensure hydrocarbon generation and accumulation. This time frame is referred to as The Critical Time.The Total Petroleum System can therefore be defined as the combination of essential elements and processes, as well as all genetically related petroleum that occur in seeps, shows, and accumulations, both discovered and undiscovered, whose origin is a pod or closely related pods of active source rock (Magoon & Schmoker, 2000).The essential elements are listed and expatiated on below: Source Rocks Reservoir Rocks Seal Rocks Overburden Rocks2.2 PETROLEUM SYSTEM ELEMENTS2.2.1 SOURCE ROCKThe source rock can be described as a rock formation/structure within which hydrocarbons can be generated or have been generated (Law, 2000). Sedimentation involves the progressive accumulation of inorganic minerals, organic matter, water, etc. Rapid burial, amongst other conditions, results in the preservation of the organic matter present in the sedimentary rocks. However, organic matter exposed to the surface experience decomposition due to the presence of oxygen. The fraction of the organic matter, present within the rock, after biological, physical and chemical decomposition and which is insoluble in normal petroleum solvents is referred to as Kerogen. Source rocks are classified based on the quantity of kerogen, quality/type of kerogen, and the thermal maturity (extent of burial heating) of the kerogen (Kenneth & Mary, 1994). Source rocks are classified as follows: Inactive source rock: These are source rock which show potential for hydrocarbon generation but have for some reason ceased production (Baker, 1979). Active source rock: These are source rock which are generating and expelling hydrocarbons within the critical time window (Dow, 1977) Spent oil source rock: These are source rock which have reached the limit of thermal maturity and are incapable of further hydrocarbon production.The petroleum potential of a source rock is determined by the composition of its Kerogen. (Tissot, Durand, & Combaz, 1974) Classified kerogen as Type I, II and III, while (Demaison, Holck, Jones, & Moore, 1983) subsequently introduced a Type IV (represented in Figure 5).The kerogen types are differentiated using the Van Krevelen or H/C (Hydrogen/Carbon) versus O/C (Oxygen/Carbon) diagram (Figure 4) which were initially developed to characterize coal (Van Krevelen, 1961). However, (Tissot, Durand, & Combaz, 1974) extended this principle to include the kerogen spread within sedimentary rocks.The Krevelen diagram was modified to feature a plot of Hydrogen Index (HI) versus Oxygen Index (OI) (Figure 4), which were obtained from experimental analysis (Rock-Eval pyrolysis and Total Organic Carbon analysis) of the whole rock core sample. The hydrogen index and oxygen index information are less expensive and faster to obtain.The three kerogen types mentioned yield different hydrocarbons. The Type I kerogen (Sapropelic kerogen) is characterized by generation of oil. They are mainly of algal origin and the dominant compounds present are Lipids. They have the highest hydrogen to oxygen ratio of all the kerogen types (Richard, 1998).The Type II kerogen (Liptinic kerogen) is also of algal decent, however, it also contains organic matter from zooplankton and phytoplankton. They occupy an intermediate position with regards to hydrocarbon potential, generating both oil and gas.The Type III kerogen (Humic kerogen) are produced from Lignin present in higher woody plants. They are rich in aromatic compounds, therefore tend predominantly toward gaseous hydrocarbon potential. Determination of the properties of a source rock is critical to the modelling of a petroleum system as expelled oil can be correlated with bitumen residue from its source rock using inherited biomarkers (fingerprinting). This allows for reconstruction of deposition conditions of the source rock (Magoon, Dow, & Geologists, 1994).Figure 4: [A] Atomic H/C versus O/C or van Krevelen diagram. [B] HI versus OI diagram. (Kenneth & Mary, 1994)

Figure 5: van Krevelen diagram depicting kerogen pathways and coal and sedimentary maceral groups obtained through the combined use of organic petrography, elemental analysis, and Rock-Eval pyrolysis and Total Organic Content analysis. (Kenneth & Mary, 1994)

2.2.2 RESERVOIR ROCKA reservoir rock is a rock that has the ability to store and transmit hydrocarbons within the subsurface. It is an important part of the petroleum system as it is the location of hydrocarbon accumulation at the critical time.For a rock to be classified as a reservoir rock, it must possess pores, to enable it store the hydrocarbons, and these pores must be connected to ensure flow of fluids. Both properties are highly dependent on the compaction of the rock sediments (Richard, 1998). Therefore, the attributes that determine the viability of a reservoir rock are porosity and permeability and level of sorting.There are two basic types of reservoir rocks, they are Siliciclastic Reservoir Rocks and Carbonate Reservoir Rocks. Siliciclastic Reservoir Rocks: These rock type are formed by progressive sedimentation of sandstone and its aggregate sediments. They owe their characteristics to the depositional environment in which they are deposited. The major depositional environments of siliciclastic reservoir rocks are Fluvial, Aeolian, Lacustrine, and Deltaic environments.Fluvial depositional environments occur due to the motion of river bodies. River flow can either be meandering or braided. Meandering flow involves the movement of a river through a course with a series of bend. With the velocity being highest on the outer side of the bend, friction causes erosion at the outer end of the bend. Due to the slow motion in the inner curve of the bend, the collected sediments are deposited (Figure 6). A braided river occurs when the sediments are two large to be transported downstream. Therefore, they are deposited along the interconnecting channels (Figure 6). Figure 6: Model representation of fluvial deposition. [B] Block representation of a braided river. [C] Meandering river system. (David, 1994)

Aeolian reservoirs are formed by the action of wind along the sea coast (Beaches) or in desert areas. Sand dunes are formed as a direct result of Aeolian activities, where fine silt particles are carried by low velocity wind and accumulate over a surface irregularity e.g. a hill (Figure 7a). When wind velocity increases, eddy currents are formed on the opposite side of the dune, causing accumulation of sand particles (Figure 7b). Continuous deposition makes the crest of this structure unstable and an avalanche occurs (Figure 7c). This process continues as long as the wind velocity is enough to maintain eddy currents, sustaining accumulation and forming a very good reservoir rock.Deltaic depositional environment are formed by the progressive deposition of sediments by a river as it flows into a water body (ocean or lake). The river furcates forming numerous channels called distributaries (Figure 8). These distributaries are found mostly along swampy and marshy areas. Deltas are formed by constructive force (Figure 9a) (accumulation of sediments to form channels) or destructive force (Figure 9b) (eroding of land mass to form channels).

Figure 7: Model for formation of sand dunes. [A] Sediment deposition by low velocity wind. [B] Eddy current due to increase in wind velocity causing sediment accumulation. [C] Avalanche due to crest instability. (Norman, 2012)

Figure 8: Deltaic depositional environment. (Norman, 2012)

Figure 9: [A] Constructive Delta. [B] Destructive Delta (Norman, 2012)

Carbonate Reservoir Rocks: These are calcite based rocks which occur through the digenesis of calcite precipitates or lithification of the secretions of marine plant and animals. Limestone is a major type of carbonate reservoir rocks, acting as a base for the formation of other carbonate rock types through its physical or chemical transformation. Other carbonate rocks include Dolomites, Karst limestone and chalk.Dolomites are formed by the replacement of Calcium atoms by magnesium atoms through the leaching of surface limestone by magnesium rich waters. Dolomites are relatively better reservoir rocks than limestone as they are harder and lose less porosity under compressive conditions.Karst limestone is formed as a result of the aggressive dissolving of limestone in fresh water. This results in the creation of vugs which give karst limestone its high porosity and permeability.Chalks are formed by the lithification of undisturbed calcium carbonate-rich microfossil shells, deposited at the bottom of tropical seas by single celled organisms (coccolithophores and foraminifera). They have very fine particles, therefore giving them high porosity but very little permeability (aside for when naturally fractured).2.2.3 SEAL ROCKSA seal rock can be defined a rock which has very little pores and pore connectivity to allow the passage or migration of hydrocarbon through them. The importance of seal rocks cannot be overemphasized as the extent of a seal rock layer determines the limit of the petroleum system. The most common seal rocks are shale, however, evaporites (salts) are the most effective.

2.2.4 HYDROCARBON TRAPSA hydrocarbon trap can be defined as a geometric arrangement of rocks that allows for significant accumulation of hydrocarbons in the subsurface with other elements in place at the critical time (modified from (Kevin & Charles, 1994)). The volume of hydrocarbons accumulated in a place depends greatly on the trap size and type.

2.3 PETROLEUM SYSTEM OF THE BENUE TROUGHThe origin and tectonic evolution of the Benue trough has been shown to be strongly related to rifting and basin inversion due to compressive activities (Olade, 1975). Rifted zones have consistently shown signs of high thermal gradients and are locations for large hydrocarbon accumulation. (Klemme, 1980) Has highlighted that 35% of basin with rifted origin contain large oil fields. The sediment thickness of the Benue trough is over 4000m (Benkhelil, Guiraud, Posard, & Saugy, 1989), greater than the minimum required overburden thickness of 1000m (Hunt, 1996). These tectonic and stratigraphic evidence, coupled with the discovery of hydrocarbons in the neighboring Niger, Chad and Sudan basins, the discovery of an accumulation of about 33BCF of gas reserves in the Kolamani River-1 well (Abubakar, Dike, Obaje, Wehner, & Jauro, 2008) and the discovery of oil and gas in exploratory wells within the Anambra basin (Nwajide, 2005), give reason to conclude on the presence of a petroleum system within the Benue trough.The Benue trough is a part of the West African Rift Sub-system (WARS). (Genik, 1993) Provided a model for the tectonic framework of the basins within the West and Central African Rift sub-system (WCARS) (Figure 9) and also identified three petroleum systems within the sub-system. The identified petroleum systems are: Lower Cretaceous Petroleum System Upper Cretaceous Petroleum System Palaeogene Petroleum SystemThese petroleum systems represent the three most significant rift phases experienced by WCARS. Therefore, they provide a boundary to enable us categorize the petroleum system of the basins (Abubakar, 2014). Adopting (Abubakar, 2014) approach to defining the petroleum system of the Benue trough, we categorize the geological sections of the Benue trough under each of the three petroleum systems. Due to the large scope of the Benue trough, which encompasses numerous basin units over its three divisions, this paper will concentrate on the petroleum systems in relation to the Anambra basin. 2.3.1 THE PETROLEUM SYSTEM OF THE ANAMBRA BASINThe Upper Cretaceous Petroleum System is the most feasible petroleum systems in the Anambra basin (Nwajide, 2005). The Upper Cretaceous can also be sub-divided into the Pre-Santonian Sub-systems and the Post-Santonian Sub-systems. 2.3.2 SOURCE ROCKSIn the Pre-Santonian Sub-system, the Ezeaku and Agwu formations are identified as the potential source rocks. Organic matter preservation is as a result of pre-santonian tectonic activities facilitating rapid burial through compression, folding and faulting of the sediments with minimal deposition. Average TOC values obtained for the Ezeaku and Agwu Formations in the pre-Santonian [Table 1], are far above the standard 0.5 wt. %. The most promising being the Lokpanta member of the Ezeaku formation (Oil Shale) with a TOC range of 3-10 wt. %. This indicates that the pre-Santonian formations have adequate organic matter quantity for hydrocarbon generation.Despite the high Hydrogen Index range, majority of the Ezeaku and Agwu samples fall within the Hydrogen index range of 50 HI < 150 mg HC/g TOC (Abubakar, 2014). This indicates predominance of Type III Organic Mater or Humic Kerogen, therefore, falling into the gas generation zone on the van Krevelen Diagram. Anomalously, the Lokpanta member of the Ezeaku displayed a minimum value of 200 mg HC/g TOC, placing it under the Type II or Liptinic Kerogen zone of the van Krevelen Diagram, with tendencies of both oil and gas generation.

Formation sampleTOC range (wt. %)Average TOC (wt. %Hydrogen Index range (mg HC/g TOC)Average Hydrogen Index (HC/g TOC)Tmax Range (C)Average Tmax (C)

Pre-Santonian

Ezeaku and Agwu0.33-7.282.5238-587177426-437431

Lokpanta (Ezeaku)3-10-200-600-450-600-

Post-Santonian

Nkporo/Enugu0.31-3.511.867-32768420-443430

Coaly Shale0.82-6.102.7824-306130407-433428

Mamu coal30.80-60.8040.03266-327297407-433428

Nsukka0.50-0.820.8031-6345421-431428

Table 1: Result from TOC analysis and Rock-Eval Pyrolysis (Obaje, Ulu, & Petters, 1999) (Ehinola, Sonibare, Falode, & Awofala, 2005) (Akaegbobi, Amaichi, & Boboye, 2009) (Nwajide, 2005)

Figure 9: Tectonic frame work of the West and Central African Sub-System (WCARS) (modified from (Abubakar, 2014))

Figure 10: Micro-tectonic representation of the structural setting in the Early Cretaceous phase in the Upper Benue Trough (Guiraud, 1990).

Figure 11: Potential Petroleum System in the Anambra Basin (Nwajide, 2005).

Figure 12: Subsurface stratigraphy showing relative disposition of potential source, reservoir and seal rocks in the Anambra Basin. (Nwajide, 2005)

The temperature values obtained depicted immaturity of majority of samples from both formations. However, (Unomah & Ekweozor, 1993) suggested that the formations were exposed to temperatures in excess of 150C prior to the Mid-Santonian tectonic activities. Therefore, hydrocarbon production must have occurred prior to the halting event.In the Post-Santonian Sub-system, the identified source rocks are Nkporo/Enugu Formations, Coaly Shale Formation, Mamu Coal and Nsukka Formations. The TOC analysis results of core samples [Table 1] support the presence of enough organic matter for hydrocarbon production and classification as source rocks.The Anambra basin collapsed prior to the post-santonian period, causing a shift in the depositional axis of the sediments and leading to the third transgression period experienced by the basin. These actions ensure the increase in depth and continuous burial of source rock sediments, therefore preserving the organic matter available in the basin.The Hydrogen Index values obtained [Table 1] show high accumulations of Vitrinite and Huminite, in the Nsukka and Mumu coal formations. These properties point to the Type III hydrocarbon potential, with minor traces of Type II. (Abubakar, 2014) Concluded that majority of the post-santonian formations are immature, excluding some Nkporo/Enugu formations which showed marginal maturity.2.3.4 Reservoir RocksThe reservoir rocks within the Anambra basin are siliciclastic in nature. They are sandstone deposits obtained from the shales within the formations [figure 11]. (Nwajide, 2005) Highlighted that the sedimentation process in the Anambra basin was as a result of land erosion, resulting in a deep sedimentary layer over 3000m. The proposed reservoir rocks for both sub-systems are the sandy members within the Awgu Formation (e.g. the Coniacian Agbani Sandstone Member), the sandstones of the Nkporo/Enugu Formations (e.g. the Campanian Owelli and Otobi Sandstone Members), the sandy horizons in the Mamu Formation, the Ajali Sandstone, the sandy horizons of the Nsukka Formation and the sandstones of the Imo Formation (e.g. the Palaeocene Ebenebe Sandstone Member).2.3.5 SEAL ROCKIn the Pre-Santonian Sub-system, the seal rock is the basal part of the Nkporo/Enugu shale formation. With relatively low permeability the Nkporo shale may act as a seal/cap rock for the underlying source rock In the Post-Santonian Sub-system, Shales present in the Imo formation may act as seal rocks. Also, the overlapping source rock mentioned for this sub-system (Nkporo/Enugu Formations, Coaly Shale Formation, Mamu Coal and Nsukka Formations) may also act as seal rocks relative to the stratigraphic position of the intended reservoir rock. 2.3.5 MIGRATION PATHWAYSThe migration pathways of hydrocarbons in the Anambra basin is a topic least approached directly with regards to shale properties. Therefore very little data is available with direct mapping of the migration pathways within the Anambra basin.(Celestine & Tochuckwu, 2012) Attempted to broach this issue by categorizing the shales within the basin using their Plasticity Index and Toughness index. The values obtained [Table 2] show that the Nkporo/Enugu shales are the most brittle making them the most susceptible to faulting and joint creasing which are major pathways for hydrocarbon migration. The results obtained for the Nsukka and Imo shales showed high ductile stress preventing leakage of hydrocarbons, therefore identifying them as the possible seal/cap rock in the basin.

FormationPI rangePI averageTI rangeTI average

Nkporo/Enugu16-24200.4-0.80.7

Nsukka62-72670.8-1.71.3

Imo34-69461.5-2.21.9

(Uma & Onuoha, 1997) Used the pressure data from exploration wells (above 2000m) to determine the hydraulic fluid potential data around the basin area. However, this was done in relation to water bore holes ranging from 60-300m. Although three hydraulic systems were identified, with the central system having the largest pressure gradient, there was no direct correlation between the results and the hydraulic hydrocarbon potential.Table 2: Result from Plasticity Index and Toughness Index for Anambra basin formation samples (Celestine & Tochuckwu, 2012)

2.3.6 PETROLEUM TRAPSThe tectonic and stratigraphic evolution of the Anambra basin allow us propose the presence of both stratigraphic and structural traps. Minor fold and faults are formed within the early Cenomanian and late Santonian era due to compressive deformation. The progressive deposition of sediments, up to the transgression experienced in the Post-Santonian era promotes the possibility of growth faults along the southern direction (Yahaya, 2005) (Whiteman, 1982).(Nwajide, 2005) Also observed the presence of anticlines, faults, unconformities and combinations traps within the Anambra basin, attributing their presence to the tectonic event in the mid-santonian era. (Abubakar, 2014) Also suggested the presence of pinch-out, buried channels and hills as stratigraphic traps due to the repetitive transgression and regression episodes in the basin.

2.3.7 PETROLEUM PRODUCTIONExploration activities have been active since the early 1950s. However, results have not been as positive as those in the Niger Delta. Oil was first discovered in the basin in 1967 by now Elf Petroleum Nigeria. However, no sightings have been made after the initial discovery. Drilling activities are highly expensive, therefore more time is currently being devoted to exploration.Exploratory wells have been dug, with (Onuoha, 2005) producing a comprehensive list [Table 3]. However, these have not yielded enough positive results to facilitate production activities.

WellTotal Depth (m)Results

Aiddo3214Dry

Ajire2257Dry

Akukwa-12403Dry

Akukwa-23655Gas shows

Alade-13055Dry

Alo-12667Gas Discoveries

Amansiodo-13433Gas Discoveries

Anambra River-13433Oil, Gas Discoveries

Anambra River-22179Gas shows

Anambra River-32430Dry

Igbariam-13322Gas discoveries (well suspended)

Ihandiagu-12524Gas discovery

Iji-13003Dry

Nzam-13672Gas shows

Oda River-1 2400Dry

Okpo-12431Dry

Table 3: Exploratory wells in the Anambra Basin (Onuoha, 2005)

2.3.8 EXPLORATION ACTIVITIESThe most recent and largest aeromagnetic data was carried out by Fugro Airborne Survey funded by the Nigerian Government and the World Bank. The survey provided both magnetic and radiometric data with a Tie-line distance of 500m, Flight line spacing of 100m and a Terrain clearance of 80m, making it the most intensive data available at the moment.(Adetona & Abbass, 2013) Subjected available data to Vertical and Horizontal Derivatives, Analytical Signal and CET grid analysis. Profile and Map analysis were used to achieve the above mention tools. Results showed the presence of shallow intrusive magnetic bodies surrounded by deep lying magnetic rocks depicting areas of sedimentation.No conclusive data was found with regards to the use of the survey data in the detection of hydrocarbon potential in the Anambra basin.Exploration activities carried out on the Anambra Basin has been restricted to Aeromagnetic data. A reason for this will be the high cost required to carry out seismic exploration activities and the data at hand do not show enough potential to facilitate the risk.

2.3.9 ENVIRONMENTAL ASPECTS OF HYDROCARBON EXPLORATION AND PRODUCTION ACTIVITIESThere are currently no production activities in the Anambra basin. There have been a series of exploratory wells drilled, however there was no information on well currently being drilled. Therefore petroleum exploration possess very little threat to the surrounding environment of the Anambra basin. However, the possibility of future activities cannot be overlooked, therefore we consider the possible environmental effects of petroleum production and exploration, in relation to the activities of the juxtaposed Niger-Delta. The major environmental effects are shown below:Gas flaring: The flaring of natural gas is a common practice in the Delta zone of Nigeria. Millions of cubic feet of natural gas are flared because it is a cheaper solution to separation of gas volumes obtained from oil wells. The burning of this gas releases methane, accompanied by a conglomerate of carcinogens, into the atmosphere causing severe pollution and depletion of the ozone layer. Legislations have been set to restrict these actions, however the lax nature of the Nigerian government and high level of corruption has seen little or no decrease in flaring activities. Oil Spillage: This is the intentional or accidental release of crude oil liquids to the environment. The environment encompasses both land and water bodies. It has been reported that over 13 million barrels of oil have been spilled since the beginning of the oil boom in the Niger-delta, with over 7000 spill cases. Spillages take months to years to clean up and its effects are felt for a longer time.

3.0 CONCLUSIONThe Benue Trough is a major component of the West African Rift System with its origin from the separation of Africa from South America. It can be divided geographically into three sections, lower, middle and upper benue trough, each with its own unique attributes.The tectonic evolution of the Benue trough began mainly in the Albian age, with tectonic activities trending Northeast with increasing age. Due to the size of the scope, the consideration of its petroleum system was confined to the Anambra Basin, which is the southern lying part or the lower Benue trough. Five shale formations were identified with varying source rock potential. There was a predominance of the Type II and Type III organic matter with varying maturity, showing trends of majorly gas generation.Seeing that most of the actions of the tectonic phases were terrigenous, most of the reservoir rocks are related sands of the surrounding source rocks. The stratigraphic nature of the basin opened the possibility of overlapping shale to act as both source rock and seal rocks. The major seal rocks were identified as the Nsukka formation and Imo formation.Migration paths were greatly inconclusive however the properties of particular shale formations show the potential for upward migration of produced hydrocarbons.With no production activities and little viable exploration done, analysis of the Anambra basin is based on small scale practices, which show good prospects. Therefore, I believe that advanced exploration method should be considered, seismic specifically, by the government. This will facilitate the interest of multinational companies and is what is required to spark up the petroleum activities in this region.

4.0 REFERENCES

Abubakar, M. B. (2006). Biostratigraphy, Palaeoenvironment and Organic Geochemistry fo the Cretaceous Sequences of the Gongola Basin, Upper Benue Trough Nigeria. Bauchi: Ph.D Dissertation, Abubakar Tafawa Balewa University`.Abubakar, M. B. (2014). Petroleum Potentials of the Nigerian Benue Trough and Anambra Basin: A Regional Synthesis. Natural Resources 5, 25-58.Abubakar, M. B., Dike, E. F., Obaje, N. G., Wehner, H., & Jauro, A. (2008). Petroleum Prospectivity of Cretaceous Formations in the Gongola Basin, Upper Benue Trough, Nigeria: An Organic Geochemical Perspective on a Mi- grated Oil Controversy. Journal of Petroleum Geology, Vol. 31, No. 4, 387-408.Adetona, A., & Abbass, A. M. (2013). Investigating the Structures within the Lower Benue and Upper Anambra Basins, Nigeria - Using First Vertical Derivative, Analytical Signal and (CET) Centre for Exploration Targeting Plug-in. Earth Science Vol. 2, No. 5, 104-112.Akaegbobi, I. M., Amaichi, G. C., & Boboye, O. A. (2009). Source Rock Potential and Depositional Environment of the Campanian-Maastrichtian Shales Outcropping along the Enugu-Leru axis, Anambra Basin, Nigeria. NAPE Bulletin Vol. 21, No. 1, 25-37.Akande, S., & Erdtman, B. (1998). Burial metamorphism (thermal maturation) in cretaceous sediments of the southern Benue trough and the Anambra Basin Nigeri. AAPG 82, 1191-1206.Ayoola, E. O. (1978). Sedimentology of the Middle Benue Trough, Nigeria. London: Unpublished, PhD Thesis, University of London.Baker, C. (1979). Organic geochemistry in petroleum exploration. AAPG Continuing Education Course Noter Series 10, 159.Benkhelil, J. (1982). Benue Trough and Benue Chain. Geol. Mag.119, 155-168.Benkhelil, J. (1986). Carcteristiques structrales et evolution geodynamique du bassin intracontinental de la Benoue (Nigeria). These d'etat, 275.Benkhelil, J. (1989). The origin and evolution of the Cretaceous Benue Trough (Nigeria). Journal of African Earth Sciences (and the Middle East), Volume 8, Issues 24, 251-282.Benkhelil, J., Guiraud, M., Posard, J. F., & Saugy, L. (1989). The BornuBenue Trough, the Niger Delta and its Offshore: Tectono-Sedimentary Reconstruction during the Creta-ceous and Tertiary from Geophysical Data and Geology. In C. A. Kogbe, Geology of Nigeria 2nd ed. (pp. 277-309). Jos: Rock View Nigeria Limited.Burke, K., Dessauvagie, T., & Whiteman, A. (1970). Geological history of the Benue Valley and adjacent areas. African Geology, 187-205.Burke, K., Dessauvagie, T., & Whiteman, A. (1971). Opening of the Gulf of Guinea and geological history of the Benue Depression and Niger Delta. Nature Physical Science 233, 51-55.Burke, K., Dessauvagie, T., & Whiteman, A. (1972). Geological history of the Benue Valley and adjacent areas. African Geology, 187-206.Carter, J., Barber, W., & Tait, E. (1963). Geology of partsof Adamawa, Bauchi and Bornu provinces in Northeastern Nigeria. Bull. Geol. Surv. Nigeria 30, 1-108.Celestine, O. O., & Tochuckwu, S. U. (2012). Inferring Hydrocarbon Migration and SEaling Potentials of some of the Anambra Basin (South-Eastern Nigeria) from their Paragenesis and Geotechnical Index Properties. Geotech Geol. Eng. 30, 1249-1260.Clifton, F. J., & Wilson, J. L. (1994). Carbonate Reservoir Rocks. In L. B. Magoon, & W. G. Dow, The Petroleum System - From Source to Trap (pp. 141-158). Oklahoma: AAPG.David, G. M. (1994). Siliciclastic Reservoir Rocks. In L. B. Magoon, & G. W. Dow, The Petroleum System - From Source to Trap (pp. 121-139). Oklahoma: AAPG.Demaison, G. J., Holck, A., Jones, R. W., & Moore, G. T. (1983). Predictive source bed stratigraphy; a guide to regional petroleum occurence. 11th World Petroleum Congress v.2, (pp. 17-29). London.Dow, W. G. (1974). Application of oil correlation and source rock data to exploration in williston basin. AAPG Bulletin, 1253-1262.Dow, W. G. (1977). Petroleum source beds on continental slopes and rises. AAPG Continuing Education Course Notes Series 5, D1-D37.Ehinola, A. O., Sonibare, O. O., Falode, O. A., & Awofala, B. O. (2005). Hydrocarbon Potentials and Thermal Maturity of Nkporo Shale from Lower Benue Trough. Journal of Applied Science, Vol. 5, No. 4, 689-695.Genik, G. J. (1993). Petroleum Geology of Cretaceous - Tertiary Rift Basins in Niger, Chad and Central African Republics. AAPG Bulletin vol. 77 No. 8, 1405-1434.Grant, N. (1971). South Atlantic, Benue Trough and Gulf of Guinea Cretaceous Triple Junction. Bull. Geol. Soc. Am. 82, 2295-2298.Guiraud, M. (1990). Tectono-Sedimentary Framework of the early cretaceous continental Bima formation (Upper Benue Trough, Nigeria). Journal of African Earth Science volume 10, No. 1-2, 341-353.Haack, R. C., Sunderaman, P., Diedjomahor, J. O., Xiao, H., Gant, N. J., May, E. D., & Kelsch, K. (2000). Niger Delta Petroleum System, Nigeria. In M. R. Mello, & B. J. Katz, AAPG Memoir 73 - Petroleum System of South Atlantic Margins (pp. 213-231). Oklahoma: AAPG.Hunt, J. M. (1996). Petroleum Geochemistry and Geology 2nd edition. Newyork: Freeman, W.H. and Co.Kenneth, E. P., & Mary, R. C. (1994). Applied Source Rock Geochemistry. In L. B. Magoon, & W. G. Dow, The petroleum system - from source to trap (pp. 93-120). Oklahoma: AAPG.Kevin, T. B., & Charles, C. W. (1994). Hydrocarbon Traps. In L. B. Magoon, & W. G. Dow, The petroleum system - from source to traps (pp. 219-235). Oklahoma: AAPG.King, L. (1950). Outline and disruption of Gondwanaland. Geol. Magazine 87, 353-359.Klemme, H. D. (1980). Petroleum BasinsClassifications and Descriptions. Journal of Petroleum Geology, Vol. 3, No. 2, 187-207 .Law, C. A. (2000). Evaluating Source Rocks. In E. A. Beaumont, & N. H. Foster, Exploring for Oil and Gas Traps (pp. 6-1 - 6-41). Oklahoma: AAPG. Retrieved from AAPGwiki.Lees, G. (1952). Foreland Folding. Quarterly Journal Geol. Soc. Lond. 108, 1-34.Magoon, L. B. (1988). The petroleum system - a classification scheme of research, exploration, and resource assessment. USGS Bulletin, 2-15.Magoon, L. B., & Schmoker, J. W. (2000). The Total Petroleum System - The natural fluid network that constrains the assessment unit. U.S. Geological Survey Digital Data Series 60, 1-31.Magoon, L. B., Dow, W., & Geologists, A. A. (1994). The Petroleum system: From source to trap. Tusa Oklahoma: American Association of Petroleum Geologists.Meissner, F. F., Woodward, J., & Clayton, J. L. (1984). Stratigraphic relationships and distribution of source rocks in the greater Rocky Mountain region. Rocky Mountain Association of Geologists, 1-34.Norman, J. H. (2012). Nontechnical guide to petroleum geology, Exploration, Drilling and Production 3rd ed. Oklahoma: PennWell Corporation.Nwachukwu, S. (1972). The Tectonic Evolution of the southern portion of the Benue Trough. Goel. Mag. 109, 177-1782.Nwajide, C. S. (2005). Anambra Basin of Nigeria: Synoptic Basin Analysis as a basis for evaluating its hydrocarbon prospectivity. In C. Okogbue, Hydrocarbon Potentials of the Anambra Basin, Geochemistry and Geohistory Perspectives, (pp. 83-110 ). Nsukka: Great AP Express Publisher Limited.Obaje, N. G., Ulu, O. K., & Petters, S. W. (1999). Biostratigra-phy and Geochemical Controls of Hydrocarbon Prospects in the Benue Trough and Anambra Basin, Nigeria. NAPE Bulletin, Vol. 14, No. 1, 18-54.Ofoegbu, C. O. (1981). Methods of interpreting magnetic anomalies with application to the. Durham Thesis. Durham University. Retrieved from http://etheses.dur.ac.uk/7512/Ofoegbu, C. O. (1984). A Model for the Tectonic Evolution of the Benue Trough of Nigeria. Geologische Rundschau 73, 3, 1007- 101.Olade, M. (1978). Early Cretaceous basalt volcanism and initial continental rifting in Benue Trough, Nigeria. Nature, Lond. 273, 458-459.Olade, M. A. (1975). Evolution of Nigeria's Benue Trough (Aulacogen): a tectonical model. Geol. Mag., 112, 575--:-583.Onuoha, K. M. (2005). A closer look at the Petroleum Potentials of the Anambra Basin: Inputs from. Hydrocarbon Potentials of the Anambra Basin (pp. 47-82). Nsukka: Petroleum Technology Development Fund.Organization of Petroleum Exporting Countries. (2013). Annual Statistical Bulletin . Austria: Organization of Petroleum Exporting Countries.Perrodon, A. (1983). Dynamics of oil and gas accumulations: Pau. Elf Aquitaine, 381.Richard, C. S. (1998). Elements of Petroleum Geology 2nd ed. Oxford: Academic Press.Samuel O. Akande, O. J. (2011). Stratigraphic Evolution and Petroleum Potential of Middle Cretaceous Sediments in the Lower and Middle Benue Trough, Nigeria: Insights from New Source Rock Facies Evaluation. Petroleum Technology Development Journal Vol. 1, 1-34.Tissot, B. P., Durand, J. E., & Combaz, A. (1974). Influence of the nature and diagenesis of organic matter in formation of petroleum. AAPG Bulletin v. 58, 499-506.U, G. F. (1994). The petroleum system - concept and applications. Geological Survey, 3-11.Uma, K., & Onuoha, K. M. (1997). Hydrodynamic flow and formation pressures in the Anambra Basin, southern Nigeria. Hydrological Sciences - es-Journal-des Sciences Hydrologiqu, 141-154.Unomah, G. I., & Ekweozor, C. S. (1993). Application of Vitrinite Reflectance in Reconstruction of Tectonic features in the Anambra Basin, Nigeria: Implication for petroleum potential. AAPG Bulletin Vol. 77, No. 3, 436-451.Uzoegbu, M. U., & Dike, E. F. (2009). Petrography and technoogical evaluation of late cretaceous coals from the anambra basin, Nigeria. Ssymposium sustainable fossil fuel and renewable energy in Northeast and other related regions of Nigeria (pp. 50-62). Nigeria: NCPRD .Van Krevelen, D. W. (1961). Coal. Newyork: Elsevier.Whiteman, A. J. (1982). Nigeria: Its Petroleum Geoogy, Resources and Potential . London: Graham and Trotman.Wright, J. (1968). South Atlantic continental drift and the Benue Trough. Tectonophysics 6, 301-310.Wright, J. (1976). Origins of the Benue Trough: a critical review in Geology of NIgeria. Lagos: Elizabethan Pub. Co.Yahaya, M. (2005). Predictive Petroleum System Model of Prospective Anambra Basin, Nigeria. Retrieved from AAPGDatabase: http://www.searchanddiscovery.com/documents/abstracts/2005grants_in_aid/mohammed.htm