Petroleum geology of the Niger DeltaBasin Abstract:Nigeria wasranked fifth among the largest crude oil suppliers to the United States in1997, providing the US 689,000 barrels of crude per day. Known oil and gasresources today rank the Niger Delta province as the twelfth largest in theworld depending on 34.

5 billion barrels of oil and 93.8 trillion cubic feet ofgas that are recoverable (Petroconsultants, 1996a).. These are the amounts thathave been discovered till our day and there may be more discoveries in thefuture as the exploration technologies develop. The TertiaryNiger Delta petroleum system (Akata-Agbada) is the only identified petroleumsystem in the Niger Delta province. The delta lays at a rift triple junctionthat is related to the opening of Southern Atlantic since Late Jurassic tillthe Cretaceous time. The proper Delta began to develop in the Eocene,depositing sediments that now have thickness of more than 10 kilometers. Themarine-shale facies of the Upper Akata formation are the main and primarysource rock of the region with some contribution from the interbedded marineshales of the Lower Agbada Formation.

We produce oil from the sandstone facieswithin the Agbada formation but also the Upper Akata Formation turbidite sandis an offshore deep-water potential target.     Introduction:Location:The NigerDelta basin lays on the western edge of Africa and the Southern part ofNigeria, with an area of 75,000 km2  and 9000-12000 meters of clastic sedimentsaccumulated (Ojo et al. 2012; Aminu and Oloruniwo 2012).      Historyof the region:The Deltahas prograded Southward from the Eocene till our day , forming the most activeportion of the delta represented by depobelts (Doust and Omatsola, 1990).

 Geology,tectonics and lithology overview:The NigerDelta Province is Geologically complicated. It contains an onshore part and anoffshore part. The onshore part is delineated by the geology of southernNigeria and southwestern Cameroon, it’s bounded from the north by the Beninflank which is an east-northeast trending hinge line south of the West Africa basementmassif. While the offshore boundary is of the province is defined by theCameroon volcanic line to the east, the eastern boundary of the Dahomey basinto the west, and the two-kilometer sediment thickness contour or the 4000-meterbathymetric contour in areas where sediment thickness is greater than twokilometers to the south and southwest. The province covers 300,000 km2and includes the geologic extent of the Tertiary Niger Delta (Akata-Agbada)Petroleum System.

Thesedimentary fill of the Niger Delta Basin is divided into three diachronousformations, namely the Akata Formation, Agbada Formation and Benin Formation        SourceRock and Thermal maturity:Althoughdetermining source rock of the Niger Delta Basin has been under discussions anddebates (e.g. Evamy andothers, 1978; Ekweozor and others, 1979; Ekweozor and Okoye, 1980;Lambert-Aikhionbare and Ibe, 1984; Bustin, 1988; Doust and Omatsola, 1990), thepossibilities are that the main source rock are the Akata-Agbada Formations.Akata-AgbadaFormations:The Agbadaformation contains intervals that have sufficient organic-carbon contents to beconsidered good source rocks Ekweozor and Okoye, 1980; Nwachukwu and Chukwura,1986). However, their thickness rarely reaches a sufficient value to producesuch a valuable oil province and they are also immature in some parts of thedelta (Evamy and others, 1978; Stacher, 1995). Below theAgbada formation we have the Akata formation shales in large volumes and it isvolumetrically sufficient to produce such a valuable oil province as the NigerDelta basin.According tocontent and type of the organic-matter, Evamy and others (1978) suggested thatboth the shale with paralic sandstone interbeds (Lower Agbada formation) andthe marine shales (Akata formation) were the source rocks of the province.usingab-hopanes and oleananes, Ekweozor and others (1979) succeeded to fingerprintthe crudes to their source rocks.

Ekweozor and Okoye (1980) also built thishypothesis using geochemical maturity indicators. The indicators includedvitrinite reflectance data, which indicated that rocks which are younger thanthe lower parts of the paralic sequence are immature. Lambert-Aikhionbare andIbe (1984) discussed that the over-pressured Akata shales would affect the migrationefficiency and that it will not exceed 12%, this indicates that little fluid hasbeen released from the formation. They also derived another thermal maturityprofile which showed that the Agbada formation shales are mature enough togenerate Hydrocarbons.Conclusionsby Ejedawe and others (1984) using the maturation models indicated that in thecentral part of the delta, the shales of the Abgada formation are the source ofoil while the shales of the Akata formation are the source of gas. They alsobelieve that both shales are the source of oil in other parts of the delta.

Anotherhypothesis from Doust and Omatsola (1990) indicates that the source organicmatter lays in the deltaic off-lap sequences and in the lower coastal plainsediments. The Agbada and the Akata formations, according to their hypothesis,have dispersed source rock levels, but Agbada formation will contain the most.They also favor the deep turbidite fans and the delta slope of the Akataformation in the deep water as source rocks. There is an indication of theexistence of terrestrial input in these environments, although it may containamorphous, hydrogen-rich matter from bacterial degradation in high amounts.According to stacher(1995), the only source rock which is volumetricallysignificant and has depth of burial consistent with the depth of the oil windowis the Akata formation. Frost (1997)suggested that there is a fertile source rock beneath the Niger Delta which isthe marine shales of the cretaceous age. Unfortunately, no data exists on thissection because it is very deep. The Akata shale formation is nearly 6,000 ft.

thick so it would have required a network of faults and fractures forimmigration to take place from the cretaceous shales to the reservoirs in theAgbada formation. Chemicalcharacteristics of the source rocks:According toBustin’s study in 1988, there is no rich source rock in the delta in theuppermost Akata Formation or the transition area between Akata and Agbadaformation. However, the lack of rich source rock was compensated by somefactors such as migration pathways, excellent drainage and the volume of thesediments.

Another enhancement factor for the oil potential in the permeabilityof the interbedded sandstone and the rapid hydrocarbon generation due to highrates of sedimentation. The study indicated the TOC% content in the sand,siltstone and shale ranges from 1.4 to 1.6 TOC%. An important observation inhis study is that the TOC content seems to change with time of thesedimentation.

For example, the average TOC% in the late Eocene was 2.2% whilein the Pliocene it decreased to 0.9%. Othersreported different TOC% values, values ranging from 0.4% to 14.4% were reportedby Ekeweozor and Okoye in 1980 in the onshore and offshore paralic sediments.Nwachukwu and Chukwura (1986) reported 5.2% in paralic shales in the westerndelta parts.

Doust and Omatsola (1990) indicated the thin beds contain thehigher TOC% values.In additionto Bustin’s conclusions he also added that the organic matter is mainlycomposed of mixed maceral components, the percentage of sulfur in shales isvery low, Hydrogen indices are also low (160-50mg HC/g TOC )However,Ekweozor and Daukoru (1994) had another opinion. They suggest that Bustin’s 90mg HC/g TOC average is not true and it underestimates the true potential of thesource rock because of the matrix effect on the rock pyrolysis of deltaicrocks. Values as high as 232 were reported by Udo and others (1988) for theimmature kerogen isolates from the shales of Akata-Agbada formations.Bustin(1998) had also included pristane/phytane values in his study which rangedbetween 2 and 4. He found that pristine/phytane values and HI values vary withstratigraphic position.The averagesource rock potential index (SPI) was estimated by Demaison and Huizinga (1994)for the Niger Delta at 14 t HC/m2 as the Niger delta has smalldrainage area in its vertical drainage system. Anotherstudy was conductedto determine the maturity levels and attributes of the source rock of the Eoceneintervals (Akata).

Three wells were drilled, and 40 samples were examined, awell was drilled on the eastern part (Alpha), another was drilled in thecentral part (Beta) and the third was drilled in the western flank (Zeta).Vitrinite reflectance of the samples was measured and they were examined usingRock-Eval pyrolysis.To determine the Thermal maturity of sediments we always use theVitrinite Reflectance method.

The shale samples from the 3 wells resulted invalues of Ro% ranging between 0.42–0.70 VRo % for thefirst well (Alpha), 0.43–1.

17 VRo % for the second well(Beta) and 0.58 VRo–0.63 VRo % for thethird well (Zeta). These results indicate that they range from immature sourcerocks to thermally mature. This table shows exactly the results of the 40samples    Well name Depth(m) Measured VR% Alpha 2764 0.42 Alpha 2798 0.7 Beta 2495 0.43 Beta 3912 1.

17 Zeta 2743 0.58 Zeta 2773 0.59 Zeta 2926 0.62 Zeta 3081 0.63 Zeta 3231 0.63  The totalorganic carbon (TOC) values of the three wells : Alpha ,Beta and Zeta were highenough to indicate that the hydrocarbon generation potential was good toexcellent (Peters and Cassa 1994).

Values ranged from1.21–3.1 wt% in Alpha , 1.04–3.62 wt% in Beta and 1.

33–2.12 wt%in Zeta. When samples were subjected to pyrolysis, S2yielded values that indicated good to very good source rock with poor tofair generation potential. Hydrogen Index of the kerogen suggested type 3 andtype 4 kerogens.The following figure shows the kerogen quantity of thesamples.

It is called van krevelen Diagram and it is plotted between HI and Tmax.       Tmaxvalues in the three wells range from 412 to 459 °C which are agree with thevitrinite reflectance values, concluding that the samples have entered the oilwindow stage.Therefore,the conclusion of the study is that the three source rocks in the three wellsare gas-prone source rocks with good generating potential in the Agbadaformation. Results are based on thermal maturity, TOC content and widespreaddistribution. Migrationpathways:Short andStäuble (1967); Reed (1969) studied the wax content, oil chemistry and the APIgravity of the oils to conclude that the migration pathways were shortMigration occurredfrom the mature, over pressured shales of the Akata formation in the moredistal portion of the delta. According to Hunt’s(1990) opinion, the expulsionof hydrocarbon was related to releasing and fracturing of the over-pressuredinterval’s top seal.A prejudice towards gas and condensate ( light hydrocarbons) was predicted byBeka and Oti in 1995 from the over-pressured shale, this is due to the mitigationof the organic matter and also due to the differentiation related to expulsionfrom sources that are over pressured.Reservoir:The Agbada formation unconsolidated sands and sandstones aremajor reservoir in the Nige delta province.

Depth of burial and depositionalenvironments in Agbada formation control the reservoir rock properties.According to Evamy and others (1978) range in thickness from 15 meters to 45 meters, stacked and theirage range from Eocene to Pliocene.Doust and Omatsola (1990) suggest that thick reservoirs represent complexbodies of stacked channels.Depending on reservoir quality and geometry, coastal barrierbars intermittently cut by sand-filled channels and point bars of distributarychannels are the most important types of reservoirs (Kulke ,1990).According to Edwards and Santogrossi (1990), the Niger Deltaprimary reservoirs are Miocene paralic sandstones that are 100 meters thick ,40% porous and 2 Darcys permeable. Growth faults mainly control the latervariations in reservoir thickness, the reservoir thick part is always towardsthe down-thrown block of the fault (Weber and Daukoru, 1975).Kulke (1990) said that fluvial sandstones have coarser grainsized sandstones than the delta front sandstones, as point bars are alwaysfining upward and barrier bars have good sorting.

Beka and otti (1995), realized other potential reservoirs inthe Niger Delta region, they included the outer parts of delta complex,proximal turbidities, low-stand sand bodies and deep-sea channels. In 1972Burke described three active fans in the deep water that have been active forthe most time of the delta’s history. He also added that the fans were verysmall compared to those related to other large deltas because much of the sandis deposited on the delta’s top or buried at the position of successivedepobelts that moves seawards.Their petrophysical characteristics are not well understood (Kulke, 1995).Traps and Seals:Structural traps form the vast majority of the traps in theNiger Delta basin. However, stratigraphic traps also exist.(Evamy and others, 1978; Stacher, 1995) declared that thesestructural traps were developed due to the agbada paralic sequencesyn-sedimentary deformation.

The complexity of structure increases from the early formeddepobelts in the North to the later formed depobelts in the South due toinstability increment of the over-pressured under-compacted shales.Doust and Omatsola (1990) declared different structuraltrapping elements such as rollover structures, channels filled with clay,growth faults, collapsed crest structures and antithetic faults.On the delta flanks there are sandstone pockets that existbetween diapiric structures, towards the toe of the delta the shale/sandstonealternating sequences tend to be only sandstone.According to Doust and Omatsola (1990),the Agbada formationinterbedded shale is considered the main seal in the Niger Delta province. Thisshale seals in three ways, the first one is clay smearing along faults , thesecond is interbedded units on which the sand reservoir juxtapose due to faultsand the third is vertical seals. They also added that the clay filled canyonson the delta flanks form the top seal of some important offshore fields.Timing:According to Evamy and others (1978)opinions, expulsion and migration in the Niger Delta basin took placeconsequently among depobelts after the depobelt is structurally deformed,therefore the deformation in the norther belt is believed to have beencompleted in the Late Eocene.

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