Growth Faulting, Rate of Oligocene Sediment Accumulations, and Stratal Geometries in a Greater Ughelli Depobelt Oil Field, Niger Delta Basin, Nigeria

A major feature of the habitat of petroleum in the Niger Delta Basin is the association of petroleum traps with growth faults. Because of the significant role of these faults in hydrocarbon accumulation and redistribution in the basin, a good understanding of the timing of fault motion has now been shown to be vital for successful exploration of fault-bounded prospects. In most petroleum habitats, structural elements such as fault patterns, their kinematics, geometry, timing, and size of the structures control the distribution of hydrocarbons in adjacent fault blocks. The success or otherwise of an exploration well in such areas depends on the location of such a well relative to the structural closure interpreted from the seismic data. Experience has shown that detailed structural analysis of prospective fields can provide a reliable kinematic and growth history upon which risks associated with fault movement, trap integrity and structure, geometry/size modification can be evaluated before deciding on the drilling location.

A structural evaluation of a post stack time migrated (PSTM) 3D seismic data over an X–Field in the eastern Niger Delta has been attempted. The objective of the study is to structurally evaluate the field with a view to identifying structural features such as faults, map geologic horizons and analyze reflection characteristics that might be a good lead to probable hydrocarbon accumulations. Results revealed that six growth faults (F1, F2, F3, F4, F5, and F6) and three seismic horizons (HI, H2 and H3) were delineated on the seismic section.  F1, F2, F4, F5 and F6   are synthetic, while F3 is antithetic growth faults. The synthetic faults trend northeast-southwest and dips southwestward, while the antithetic fault trend northwest-southeast and dips southeastward. The seismic horizons are fault truncated with hanging wall/footwall fault assisted closures characterized by distinctive high amplitude reflection events. The horizons have good reflection continuity, moderate to strong reflection strength and medium to high amplitudes. These suggests wide spread and uniform deposition of clastic sediments with thick sand facies and inter-bedding shales, which is the characteristic of a hydrocarbon reservoir in the Niger Delta basin. The potential for hydrocarbons is high in this prospect field based on our preliminary study, which could be explored.   Key words: Growth faults, seismic horizons, fault closures, post stack time migrated (PSTM) 3D seismic data.

Geopressured sedimentary formations are common within the more prolific deeper hydrocarbon reserves in the Niger Delta basin. While overpressured zones could serve as tools for hydrocarbon prospectivity evaluation, they are significant safety concern to the driller. Pre-drill pore pressure prediction using 3-D seismic data was carried out in the Niger Delta basin to predict subsurface pressure regimes and further applied in the determination of hydrocarbon column, reservoir continuity, fault seal and trap integrity. Results revealed that overpressures in the area are associated with simple rollover structures bounded by growth faults, especially at the hanging walls, while hydrostatic pressures are often observed in areas with k-faults and collapsed crested structures. The depth to top of mild overpressures(<0.71psi/ft) in the basin ranges from about 6000ftss to about 13000ft subsea. Similarly, the depth to top of hard overpressures(>0.71psi/ft) ranges from about 13000ftss to over 30000ftss(throughout the Akata Formation).Post-depositional faulting is believed to have controlled the configuration of the overpressure surface and has played later roles in modifying the present day depth to top of overpressures.

The deep drilling campaign in the Niger Delta has demonstrated the need for a detailed geopressure and trap integrity (drilling margin) analysis as an integral and required step in prospect appraisal. Pre-drill pore pressure prediction from 3-D seismic data was carried out in the Greater Ughelli depobelt, Niger Delta basin to predict subsurface pressure regimes and further applied in the determination of hydrocarbon column height, reservoir continuity, fault seal and trap integrity. Results revealed that geopressured sedimentary formations are common within the more prolific deeper hydrocarbon reserves in the Niger Delta basin. The depth to top of mild geopressure ( 0.60 psi/ft) ranges from about 10 000 ftss to over 30 000 ftss. The distribution of geopressures shows a well defined trend with depth to top of geopressures increasing towards the central part of the basin. This variation in the depth of top of geopressures in the area is believed to be related to faulting and shale diapirism, with top of geopressures becoming shallow with shale diapirism and deep with sedimentation. Post-depositional faulting is believed to have controlled the configuration of the geopressure surface and has played later roles in modifying the present day depth to top of geopressures. In general, geopressure in this area is often associated with simple rollover structures bounded by growth faults, especially at the hanging walls, while hydrostatic pressures were observed in areas with k-faults and collapsed crested structures.

Remotely acquired gravity data from satellite gravimetry is integrated into the study to investigate crustal deformation in the Niger Delta Basin. The Niger Delta Basin is a well-documented example of a passive margin delta that has gravitationally deformed. The gravity-driven deformation has not been fully understood, and new trends may be emerging. In this study, we assess and delineate structural deformation and sediment accumulation of the Agbada and Akata stratigraphic sequences within the basin's prograding clastic wedge. This was done through the integration of data from the Gravity Recovery and Climate Experiment (GRACE) mission, Landsat 8 satellite imagery, and the Advanced Land Observation Satellite (ALOS) World 3D-30 m (AW3D) DEM. The methodology workflow incorporated gravity modelling from GRACE data, lineament extraction from Landsat imagery, and drainage network analysis from the AW3D DEM. The Niger Delta Basin as seen on the gravity models depicts large-scale block faults with a well-defined graben structural topography. This eventually shows that the basin is dominated by growth faulting with differential subsidence. The predominant directions of the mapped lineaments are in the N-S and W-E directions. With over 18,500 lineaments, the W-E direction is marginally the dominant direction of the two predominant directions. Many linear structures such as shear zones and fractures which have different orientations and directions characterise the study area. Also present are the minor N-S fractures which are attributed to brittle deformation and sets of NE-SW and NW-SE trends, produced by transcurrent movements as the structural framework of the Nigerian basement complex are dominated by the NE-SW lineaments. However, the complexity in the structural geometry and thrusting sequences in the Niger Delta shows the patterns of growth structure and imbricate thrusting. The structural pattern also exhibits outward radial gravity spreading of dip-orientated, extensional structures that include delta slope radial grabens and tear faults. Radial spreading has likely increased the segmentation of Niger Delta regional depo-belts in the N-S direction. It is observed that most of the structural deformations in the basin are syn-formational, evolving at the same time as sediment deposition.

ABSTRACTThe Anambra and the Niger Delta Basins are well‐known hydrocarbon‐producing sedimentary basins in Southern Nigeria. In the present research, bulk geochemical analysis, which includes total organic carbon (TOC) and rock pyrolysis, molecular markers, and bulk and compound‐specific carbon isotopes (CSIAs), in addition to organic petrological analysis was carried out on source rocks of Cretaceous age from the Anambra Basin and oils (both Anambra and Niger Delta Basins) in order to provide information on why there was a sudden seizure in liquid hydrocarbon production in the ANAR oilfield of the Anambra Basin and also to shed more light on the unending debate on the source of Cretaceous Niger Delta oils. From the results, bulk geochemical data and maceral abundances revealed that Nkporo shales from well‐x and outcrop Mamu shales are dominantly of Types II and III organic matters and are capable of producing oil and gas upon attaining appropriate thermal maturity, whereas outcrop Mamu coals are of Types II and II/III organic matter, with good potential for oil generation but with minor gas, especially in the deeper section of the basin. Organic matter richness as deduced from TOC revealed that the Mamu coals are the richest (average TOC: 50.74 wt%), whereas Mamu shales are richer (average TOC: 2.89 wt%) than Nkporo shales (average TOC: 1.66 wt%). The hydrocarbon generative potentials of the analyzed source rocks as obtained through the hydrogen index are highest in the Mamu coals (average: 329.25 mg HC/g TOC), and are followed by Mamu shales (average: 130.89 mg HC/g TOC), whereas the least was obtained in Nkporo shales (average: 69.73 mg HC/g TOC). The maximum temperature (Tmax) and the vitrinite/huminite reflectance values of the source rocks are 396–443°C, 417–430°C, and 417–421°C, and 0.38%–1.51%, 0.23%–0.42%, and 0.22%–0.46% in Nkporo shales, Mamu shales, and coals, respectively. The values revealed that Nkporo shales are in immature to early–late hydrocarbon generation stages, whereas Mamu shales and coals are dominantly thermally immature. Further, the analyzed source rocks were deposited under sub‐oxic‐to‐oxic conditions based on molecular indices and petrographic evidence. In the Nkporo shales, there was dominant input from lacustrine organic matter, as evident from the high abundance of C28R sterane, higher C21TT, and n‐alkane maxima at n‐C20 and n‐C23. In contrast, the Mamu shales and coals and crude oil from the Anambra Basin received major input from terrigenous organic matter (high C29 R sterane, C29/C27 ratios, wax index, terrigenous/aquatic ratio (TAR), C19 + 20TT, and n‐alkane maxima at n‐C27–n‐C29). The oils (crude oils and condensates) from the Niger Delta are dominated by C29 R steranes, whereas C27 and C28 R steranes are in different proportions. Oil‐source correlation parameters also revealed that crude oil produced in the Anambra Basin was generated by Nkporo shales from well‐x and the thermally mature equivalents of Mamu shales and coals. In addition, the Mamu shales and coals are compositionally and genetically similar to oils from the onshore and offshore Niger Delta. On the basis of the oil‐source correlation parameters, in addition to the presence of other elements of the petroleum system, the Upper Cretaceous (Mamu–Nkporo/Ajali) petroleum system (!) is proposed in the Anambra Basin. The present research concludes that the absence of abundant liptinitic oil–producing macerals and Type III nature of organic matter in Nkporo shales from the ANAR oil field of the Anambra Basin led to a sudden seizure in liquid hydrocarbon production. Again, there are deeply seated Cretaceous source beds within the Niger Delta Basin that are contributing to the Cretaceous oils. This research has significant implications for future oil and gas explorations in the Southern Nigeria sedimentary basins and will contribute to the existing knowledge in the West and Central African Rift Systems (WCARS) basins and the Gulf of Guinea.

Problems encountered during initial trials of cuttings injection (CI) in Nigeria resulted in the technology being perceived by regulators as an infeasible disposal option in the Niger Delta basin and it was considered to be removed from the approved list of disposal options. This study was conducted to review the disposal technology, assess the deficiencies in the initial trials with respect to the Niger Delta geology, and proffer a framework for an environmentally-feasible application of the technology. The results of the study revealed that the geology of the Niger Delta is favorable for CI operation because of favorable lithology and a lack of strong seismic events. However, due to variations in the depth of the base of fresh water a suitable injection domain cannot be mapped across the Niger Delta basin. Therefore, each project needs to be evaluated on a case-by-case basis using site-specific information. The lessons learned from the previous practices were identified and an integrated project approach was recommended to achieve an environmentally appropriate use of CI in the Niger Delta basin.

Preliminary structural and stratigraphic assessment of an onshore field for CO2 re-injection in the Niger Delta Basin, Nigeria

Seismic analysis of growth faults to predict sequence stratigraphic reservoir properties: A case study of the middle to late Miocene Coastal Swamp strata, Niger Delta Basin, Nigeria

The shale volume factor is among the critical petrophysical parameters for reservoir characterization and formation evaluation. Inaccurate estimates of the shale volume factor can lead to poor reserves or resource estimates and wrong business decisions. While the current industry standard is to estimate the shale volume factor from the gamma ray logs using the concept of the gamma ray index, a relationship between the shale volume factor and the gamma-ray index needs to be established for any region/basin under consideration. For most applications in the Niger Delta Basin, a linear relationship is often assumed. However, there is no proven relationship between the shale volume factor and the gamma-ray index for the formations in the Niger Delta Basin. This paper proposes a new shale volume factor prediction correlation for the Niger Delta Basin in Nigeria. The correlation development is based on establishing a relationship between the shale volume factor obtained from cores and the gamma ray index obtained from petrophysical logs for over thirty wells drilled across the Niger Delta Basin. The results show that the relationship between the shale volume factor and the gamma-ray index is not linear as often assumed but a power law model. The new probabilistic correlation predicts lower shale volume factors than the linear model for all ranges of the gamma-ray index. This recent correlation will significantly impact how the hydrocarbon resources and reserves are quantified in the Niger Delta Basin.

The Saltpond Basin, situated within the South Atlantic margin of Ghana, is a significant area for petroleum exploration but has received relatively limited research attention. Previous studies have examined source rock composition, but data on crude oil organic chemistry are lacking, hindering understanding of the basin’s petroleum system and evolution. To address this gap, we analyzed biomarkers and stable carbon-isotope ratios in Saltpond Basin crude oil using gas chromatography–mass spectrometry and gas chromatography–isotope ratio mass spectrometry to elucidate organic matter source, depositional environment, and thermal maturity. Findings were compared with oils from the West African segment of the South Atlantic margin, namely the Tano Basin and the Niger Delta Basin, to identify potential correlations and gain insights into regional variations. Molecular and isotopic results unveiled a significant prevalence of organic matter derived from lower marine organisms. Patterns of organic matter deposition and preservation in Saltpond oil samples suggested a suboxic marine transitional environment, contradicting conventional understanding of terrestrial dominance in such settings. Moreover, the potential for degradation processes to obscure differentiation between terrestrial and marine organic matter origins underscores the complex nature of organic matter dynamics in transitional marine environments. Analysis of molecular thermal maturity indices suggested Saltpond oils were expelled from source rocks exhibiting thermal maturity at the early maturity stage. Correlation analysis unveiled genetic disparities among crude oils sourced from the Saltpond Basin and those from the Tano and Niger Delta Basin, primarily due to variations in source input and depositional environment conditions. Saltpond oil exhibits lower terrestrial organic input than Tano Basin’s crude oils, which also have less terrestrial input than Niger Delta Basin crude oils. Additionally, its paleodepositional environment notably differs from oils in the Tano Basin (anoxic transitional marine-lacustrine settings) and the Niger Delta Basin (suboxic–oxic terrigenous deltaic or marine or lacustrine environments). Thermal maturity range of Saltpond oil is comparable to oils in the Tano Basin but lower than oils in the Niger Delta Basin. These findings provide valuable insights into petroleum generation history and unique organic geochemical characteristics within the Saltpond Basin, essential for exploration, production, and environmental management efforts in the region. Furthermore, correlation studies provide evidence that distinct biological, geological, and paleoenvironmental conditions shaped various oil types in the West African segment of the South Atlantic margin.

Syndepositional deformation of the Permian Capitan reef carbonate platform, Guadalupe Mountains, New Mexico, USA

The distribution of dibenzothiophenes, phenyldibenzothiophenes, and benzo[b]naphthothiophenes and their geochemical significance in the crude oils and source rocks from Niger Delta Basin have been investigated by gas chromatography-mass spectrometry. The dimethyldibenzothiophenes, 4-phenyldibenzothiophene, and benzo[b]naphtho[2,1-d]thiophene were the most abundant among the dibenzothiophene and its derivatives in the crude oils and rock samples. The phenyldibenzothiophene ratio-1 and phenyldibenzothiophene ratio-2 values in the rock samples were in the ranges of 0.08 to 0.67 and 0.20 to 2.53, respectively, while the 4-/1-methyldibenzothiophene, 4,6-/(1,4 + 1,6)-dimethyldibenzothiophene, 2,4,6-/(2,4,7 + 2,4,8)-trimethyldibenzothiophene, phenyldibenzothiophene ratio-1, and phenyldibenzothiophene ratio-2 values in the crude oils ranged from 1.52 to 5.82, 0.76 to 1.98, 0.77 to 1.22, 0.11 to 0.42, and 0.30 to 0.75, respectively. These values indicate source rocks and crude oils with mixed input of terrestrial and marine organic matter and deposited in lacustrine-fluvial/deltaic environments within immature to early mature stages. Four isomers of MDBT were also present in appreciable amounts in all the samples studied. The distribution patterns of MDBTs were generally observed in the order 4-MDBT > 2+3-MDBT > 1-MDBT in the crude oils and rock samples. The (1 + 4)-/(2+3)-methyldibenzothiophene ratio in the oils and rock samples ranged from 0.03 to 0.13 and 1.31 to 2.54, respectively. These values suggested source rocks with shale lithologies. A cross plot of (1+4)-/(2+3)-methyldibenzothiophene versus pristane/phytane measured on rock samples and crude oils from Niger Delta was used to study the influence of depositional environment and lithology on the distribution of the MDBT isomers. This cross plot clearly showed that the source rocks and crude oils studied have shale lithologies and were distinguished into lacustrine and fluvial/deltaic/freshwater environments and thus proposed in this study as a potential lithology and paleoenvironment indicator. This study showed that dibenzothiophenes, phenyldibenzothiophenes, and benzo[b]naphthothiophenes were effective in determining the origin, depositional environments, and thermal maturity status of crude oils and source rocks in the Niger Delta Basin, Nigeria.

Hydrocarbon leads and prospects opportunities across a cluster of fields in parts of Onshore Niger Delta Basin

The Niger Delta Basin is a prolific petroleum province and is currently the only basin in which commercial petroleum production strives in Nigeria. The Niger Delta Basin has received a lot of research attention but with fewer studies regarding the reconstruction of the age of source rocks from their crude oils using biomarkers. The study aimed at reconstructing the age of the Niger Delta source rocks from crude oils samples from the Basin. The age determination of the sample set was attempted by looking at individual age-specific biomarkers that suggested a source age as well as looking at them together to have a clearer indication of the likely source age. Thirteen (13) crude oil samples from the “Y” Field of the Niger Delta Basin were subjected to Gas Chromatography-Mass Spectrometer analysis. The biomarkers used in this study were; oleanane index (OI), C28/ C29 ratio, C30 /(C27-C30) ratio, and Pr/Ph (pristane/phytane) ratio, with corresponding mean values of 1.08, 0.76, 0.28, and 1.12 respectively. The biomarker data based on some age-specific biomarkers, both individually and especially when used together, suggests a Tertiary age for the source rock that generated the crude oils. These results are based on the occurrences of oleanane, Pr/Ph ratios, and the high C28/C29 ratios, all indicating Tertiary age source rock.