The Niger Delta Basin also referred to as the Niger Delta province is located in the Gulf of Guinea. It is an extensional rift basin that formed as a result of a failed rift junction during the separation of the African plate and the South American plate, where the of basement tectonics on the structural evolution was limited by the movement of the oceanic fracture zones that extended beneath the deltas. Compared to the producing tertiary deltas in the Mississippi, Orinoco, Mahakam and north slope of Alaska, it is ranked one of the best petroleum reserves for production. This basin extends towards the coastal and oceanward part of the Benue through that runs diagonally through Nigeria composed of larger and older tectonic features. It is composed of Cenozoic formations deposited in high energy with sediments exceedingly approximately 35,000 ft beneath the upper and lower deltaic plains.
Lithology & Risks
The lithology of this basin is subdivided into Benin, Agbada and Akata formations deposited in continental, transitional and marine environments respectively. The Benin formation started in the ogliocence age, that consists mainly of sand and few shale layered content which varies in depth from 0 to 4600 ft below the subsurface. With the low shale content, very little oil exists in this formation and is generally water bearing.  The Agbada underlies the Benin formation that varies in depth from 5700 to 9500 ft below the subsurface and consists of a combination of sandstone and siltstone layers. The primary source of hydrocarbons in this section of the reservoir is from the sandstones, and the shale acts as a seal. The presence of the unconsolidated sandstones from its calcareous matrix creates problems in production and completion operations during the first stages of oilfield development. The main basal lithology unit in the the Niger delta basin is the Akata formation. It is predominantly composed of marine shales with a variable range of depth from 7,100 to 11,000 ft. High pressure zones are developed in this zone which creates risks in drilling activities such as a blowout or stuck pipe and difficulties in detecting gas contents.
Petroleum systems elements
It has been showed that there is no relation between growth of faults and petroleum distribution, this is evidenced by the movement of the structure-building and the resulting continued growth. There is a lot of debate about the source rock of the Niger Delta Basin, most discussions speculate the marine interbedded shale in the Agbada formation, the marine Akata shale and a cretaceous shale. The Agbada formation has zones that contain organic-carbon contents that are abundant to be classified as good source rocks, however, the zones rarely reach thicknesses that can produce a lot of oil and the carbon contents are immature in certain areas. The Akata shale is available below the Agbada formation in quantities large enough to generate large reserves for a province such as the Niger Delta. Even though, the cretaceous shale beneath the Niger Delta has been proposed as a potential source rock, no one has drilled the section due to its depth. Therefore, there is no reliable data to be able to assess the possibility of the cretaceous shale being a source rock. The Agbada formation is the most producing of all the formations that make up the Niger Delta Basin because petroleum occurs throughout the formation. Hydrocarbons are produced from sandstones and unconsolidated sands in the Agbada formation. The depositional environments and the depth of burial are key features in the characterization of the Agbada reservoirs. Reservoir thicknesses range between 45 to 150 ft, they are Pliocene and Eocene in age.
The hydrocarbon distribution is attributed to the timing of formation traps in relation to hydrocarbon migration. The earlier landward structures trapped early migrating hydrocarbons. Faults in this formation provided a pathway for petroleum migration and formed structural and stratigraphic traps for accumulated hydrocarbons. This fault fracture network in the shale reaches a thickness of 6000 meters and a migration efficiency of less than 12%, like that of over pressured shales in the Gulf of Mexico. Figure 3 shows the migration from the mature and over-pressured shales is similar to the migration from over-pressured shales in the Gulf of Mexico similar to that of Niger delta. Petroleum was expelled from abnormally pressured mature rocks to fracturing and resealing of the top of seal of the over-pressured zones.
Primary and Secondary Reservoirs Hydrocarbons from the Niger Delta basin are mainly produced from sandstone and unconsolidated sands in the Agbada formation. The primary reservoirs of the Niger Delta Basin are the Miocene paralic sandstones with 40% porosity, a permeability of 2 Darcys and 100 meters thickness. The sandstones are mostly unconsolidated with minor components of the Argillo-silicic cement. The grain size of the sandstone reservoirs highly varies as barrier bars have the best grain sorting, point bars fine upward, and fluvial sandstones coarse more than their delta front counterparts. The reservoirs thicken towards the fault in the downthrown block and the thickness variation is controlled by the growth of the faults. Deep-sea channel sands, low-stand sand bodies and proximal turbidites in the outer portion of the Delta create prospective reservoirs.
Traps and Seals
The Niger Delta is dominated by structural traps, although stratigraphic traps are found sometimes. The structural complexity increases from the north to the south due to under-compacted and over-pressured shale represented in Figure 4. The primary trap in the Basin is the interbedded shale in the Agbada formation that provides three types of traps; vertical seals, clay smears along the fault and the juxtaposition of the interbedded shale against the reservoir sands due to faulting. At the northwestern part of the Delta, the oil window is situated in the upper portion of the Akata formation and the lower Agbada formation. Further to the Southeastern is stratigraphically lower. The present-day oil in the Delta is in the 240°F isotherm. The depth to any temperature is dependent on the sand and shale distributions in the Basin.
Geologic uncertainties and overcome
The present of over-pressured zones can be a great geologic uncertainty. Niger Delta present several abnormal pressure zones. These abnormal pressure zones are all over-pressured caused by pore fluid trapped in the under compacted formation. It will influence the drilling safety and production if the over-pressure zones cannot be identified and handled well. The major oil companies in Niger Delta studied more than 230 wells which located across the Niger Delta Basin to predict the primary over-pressured zones. They use well log tools including resistivity, acoustic and density logs in the study wells. The shale resistivity ratios, shale transit time and bulk density difference between normal pressured area and over pressured area are be used to investigate the over-pressured zones. All the over-pressured wells they find in the studies are marked on the map, which can help to identify the over-pressured zones.
Current future assessment of the basin including EOR
Many wells in Niger Delta were using open hole completion before early 21st Century. Open hole completion needs a good sand control method including gravel packs, barefoot, standalone screens and so on, which are all be used in Niger Delta Basin. After that, horizontal well technology was introduced to Niger Delta Basin. The horizontal well technology enhances the production compare to the conventional wells as there are a lot of thin sandstone layers contain oil. Carbonate dioxide (CO2) can be used for future EOR. CO2 has been successfully used in the other oil producing field but haven’t been introduced to Niger Delta Basin. Simulation was been done under full water drive, partial water drive and volumetric drive mechanisms conditions. The model shows that under full water drive, CO2 injection increase the oil recovery increase but not very much. However, under partial water drive and volumetric depletion, CO2 injection increase the oil recovery for 63% and 58% respectively. Overall, CO2 injection will be a good EOR method to implement in future.
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- Seismic interpretation, structural analysis, and fractal study of the Greater Ughelli Depobelt, Niger Delta Basin, Nigeria
- Application of volumetric seismic discontinuity attribute for fault detection: Case study using deep-water Niger Delta 3D seismic data
- Reservoir Quality Variations Within a Sinuous Deepwater Channel System in the Niger Delta Basin, Offshore Western Africa
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