Niger Delta Basin Research Articles

Reservoir characterization of GABO field in the niger delta basin using facies and petrophysical analyses

This study investigates the GABO field in the onshore Niger Delta Basin using well logs and core samples, with a focus on rock type distribution, reservoir continuity, and petrophysical properties to enhance hydrocarbon exploration accuracy. The research involved detailed analysis of core descriptions and images from GABO-20, along with petrophysical data from wells GABO-4, GABO-12, GABO-13, GABO-20, and GABO-51, aiming to identify rock types, evaluate reservoir quality, and determine the spatial distribution of petrophysical properties. The methodology included rigorous well log quality checks, data correlation between wells, petrophysical property evaluation, and lithofacies description. The analysis revealed thirty-five hydrocarbon-bearing zones, with GABO-20 showing average shale fraction values between 0.111 and 0.335, total porosity ranging from 0.242 to 0.329, and hydrocarbon saturation from 0.667 to 0.923, indicating substantial porosity and hydrocarbon saturation conducive to extraction. Well correlations demonstrated excellent sand-shale continuity within the reservoir intervals. Lithofacies analysis of the GABO-20 core identified eight distinct facies, including shale poles, liquid-rich shales, and sandstone poles, revealing a complex distribution of reservoir qualities with significant variations in potential. Cores 1 and 2 exhibited favourable conditions for hydrocarbon production, while Core 3 showed lower reservoir quality due to increased clay content. The depositional settings of the GABO field, particularly in the lower delta plain and delta front zones, showed well-developed reservoir bodies with moderate potential in the tidal zone and little potential in the shaly prodelta environment. This distribution highlights the complexity of the deltaic system and its implications for reservoir modeling and utilization. Reservoir zones associated with High-Quality Reservoir Facies exhibited strong petrophysical properties, suggesting excellent hydrocarbon production potential. The study underscores the importance of detailed reservoir characterization to optimize recovery strategies, offering valuable insights into the distribution and quality of reservoir sands, reducing subsurface uncertainty, and emphasizing the integration of facies and petrophysical approaches for a better understanding of reservoir characteristics in the GABO field.

Depositional environment and stratigraphic framework of the NS- 1 well, Coastal Swamp Depobelt, Niger Delta Basin: a foraminiferal perspective

A comprehensive analysis of 102 ditch-cutting samples from the NS-1 well in Leuma Field, Coastal Swamp Depobelt, Niger Delta Basin, covering depths from 4730 ft to 7790 ft, is presented. Lithologic descriptions revealed eleven lithostratigraphic sub-units within the transitional-paralic sequence of the Agbada Formation, comprising alternating sandstone and shale. The foraminiferal analysis identified 58 species: 14 planktonic, 26 calcareous benthic and 18 agglutinated benthic. Key planktonic index species such as Globigerinoides sp. and Globorotaliacontinuosa indicates a Middle to Late Miocene age. The biozonation correlates with the Blow (1969) Scheme (N7- N9/N10/N11) placing the intervals within the Middle Miocene to Late Miocene epochs. The depositional environment transitioned from Coastal Deltaic to Inner Neritic and Middle Neritic, suggesting a shallow marine setting influenced by a warm, humid climate. The presence of calcareous foraminifera supports a shallow marine deposition above the carbonate compensation depth. This study provides valuable insights into the sedimentological, stratigraphic, and paleoenvironmental history of the NS-1 well during the Miocene.

Multicriteria evaluations for sand production potentials: a case study from a producing oil field in the Niger Delta Basin (Nigeria)

Geomechanical evaluation of three wells in an onshore Niger Delta Oil Field in which some reservoirs have histories of free water production was carried out to predict their potential for sand production. The mechanical characteristics of the reservoirs, such as the Poisson ratio (v), shear modulus (G), elastic modulus (E), bulk modulus (Kb), and bulk compressibility, were calculated using petrophysical parameters such as s-velocity (Vs), p-velocity (Vp), gamma ray index (IGR), the volume of shale (Vsh), porosity (), and pseudo factor (q) derived from wireline logs (Cb). Five geomechanical techniques—porosity, acoustic wave travel time, sand production index, Schlumberger sand production index, and shear modulus to bulk compressibility ratio (G/Cb) were used to forecast the potential for sand production in the reservoirs. The porosity values varied from 14 to 27%, which is below the threshold value of 30% for sand production. The acoustic wave travel time ranged from 81.59 to 89.91s/ft, which is below the threshold value of 104s/ft for sand production. The threshold value for the sand production index was < 2.9 ×106psi. The values for the sand production index fell between 11x 106psi and 12.4 x 106psi, which is below the limits for the onset of sanding. The G/Cb values in the reservoirs across the three wells fell between 1.15 x 1012psi2 and 1.43 x 1012psi2 while the threshold value for the Schlumberger sand production index fell between 1.15 x 1012psi2 and 1.43 x 1012psi2. Only the Schlumberger criterion predicted the potential for likely sand production.

Characterization of Depleted Hydrocarbon Reservoir AA-01 of KOKA Field in the Niger Delta Basin for Sustainable Sub-Sea Carbon Dioxide Storage

Characterization of Depleted Hydrocarbon Reservoir AA-01 of KOKA Field in the Niger Delta Basin for Sustainable Sub-Sea Carbon Dioxide Storage

A Petrophysical Properties Evaluation Study of a Niger Delta Field Using Well Logs and Core Data

A petrophysical properties evaluation study of an onshore field “NEMA” was carried out to assess the petrophysical characteristics of the field in the eastern portion of the Niger Delta Basin. This was done in an effort to determine the hydrocarbon prospect and oil productivity potential of the reservoirs. The net/gross thickness was one of the examined parameters. (pay zone thickness), porosity, permeability, fluid saturation which were all inferred from geophysical wireline logs and core data. The wireline logs used in the investigation included density, resistivity, gamma ray, and spontaneous potential logs for five different wells from the “NEMA” oil field. Five reservoirs designated, NEMA 01, NEMA 04, NEMA 07, NEMA 09, and NEMA 12 were identified and correlated across the five wells in the field using gamma ray logs and shale resistivity markers. Based on the computation of petrophysical parameters, the porosity of the reservoirs ranged from 0.22 (22%) to 0.31 (31%); the permeability ranged from 851.58 mD to 1005.05 mD; the average net-to-gross thickness of the reservoir sand bodies was 140 ft; the water saturation value was less than 45%, while the hydrocarbon saturation was greater than 55%. We equally observed that our computed petrophysical parameters from well log data correlated well with the core computed values in NEMA 09. In conclusion, the delineated reservoirs were categorized as good hydrocarbon reservoirs. These results suggest huge hydrocarbon potential and a reservoir system whose performance is considered satisfactory for hydrocarbon production.

Delineation of deep-seated crustal structures from magnetic data in the southeastern part of the Niger Delta basin, Nigeria

Regional magnetic data in the southeastern segment of the Nigerian Niger Delta were evaluated with the aim of mapping deep-seated tectonic elements. Enhanced filtering operations and 3D forward modelling were applied on the magnetic data. These geologic features triggered the formation of rollover anticlines and faults that serve as structural traps in the study area. The filtered residual magnetic data revealed geologic structures characterized with NE - SW, N - S, and E - W orientations. The 3-D models detected the faulted crustal blocks, gradient zones, and intra-basement compositional magnetic variations. Furthermore, some prominent horst and graben structures as well as related normal faults characterized with distinct magnetic signatures were observed. Faults of base magnetic (of various compositions) were observed to be the fabricating mechanisms of the magnetic anomalies. Collectively, these structures influenced the patterns of magnetic anomalies with direct effects on the hydrocarbon trapping systems, as well as the pathways and accumulation zones for hydrothermal minerals. On the whole, the interpreted results revealed that the basement surface is rippling. Additionally, the depth result showed sedimentary thicknesses that ranged from 4–10 km. Again, the estimated crustal thickness varied from 14 to 19 km. This study has displayed the capabilities of the magnetic method in mapping the depth and configuration of basement rocks, which are crucial in controlling the formation of structural traps. Identifying these basement structures early helps in understanding the overall geological framework and potential hydrocarbon systems.

Refined Prediction Method for Production Performance of Deep-Water Turbidite Sandstone Oilfield: A Case Study of AKPO in Niger Delta Basin, West Africa.

Deep-water oilfields frequently employ large or superlarge well spacing, leading to significant production dynamics influenced by reservoir factors. Traditional methodologies often disregard these influences, resulting in poor accuracy. Therefore, an enhanced prediction methodology rooted in reservoir characteristics is proposed. This approach introduces the dynamic relative permeability law as a bridge, capturing macroscopic oil/water movement within the reservoir. For the first time, it integrates production dynamics with key controlling reservoir factors, encompassing reservoir architecture, injection-production connectivity, and reservoir heterogeneity. The results indicate that (1) In deep-water turbidite sandstone fields with ultralarge injector-producer well spacings, the distribution of oil-water movement is primarily influenced by reservoir connectivity and heterogeneity. The injection water sweeping ability coefficient can quantitatively describe the water flooding capacity, with a strong negative correlation between the injection water sweeping ability coefficient and interwell nonconnectivity coefficient and reservoir homogeneity coefficient. This suggests that better reservoir connectivity or weaker heterogeneity results in stronger water flooding capacity, leading to a wider range of water flooding under the same injection volume. (2) For regions with strong water flooding capacity (injection water sweeping ability coefficient 0.30-0.80), the water-free production period is the main production stage, with a focus on improving the planar flooding conditions. For regions with poor water flooding capacity (injection water sweeping ability coefficient 0.00-0.10), the middle and late water-cut periods are the main production stages, with a focus on improving interlayer dynamic differences in the later stages. For regions with moderate water flooding capacity (injection water sweeping ability coefficient 0.10-0.30), the initial focus should be on expanding planar flooding, followed by a focus on improving interlayer dynamic differences in the later stages. (3) The dynamic relative permeability law, capable of comprehensively portraying the reservoir's influence on macroscopic oil/water movement, emerges as a rational choice for production performance prediction in such contexts. Our method can improve the accuracy, compared with traditional method without geographical factors, from 45% to 90% during water-cut rising stage and 31% to 81% during production declining stage. The high prediction accuracy (90%) observed in the AKPO oilfields underscores the method's efficacy in directing on-site optimization and adjustments for the development of deep-water turbidite sandstone oilfields.

Seismic Inversion Techniques and Attribute Analysis for Accurate Well Placement in Offshore Niger Delta Basin, Nigeria

Before this study, simple methods like seismic attribute analysis have often been used for reservoir characterization with successes however, there is still the need to reduce exploration uncertainty to a negligible level and boost investors’ confidence. This study integrated seismic inversion with seismic attribute analysis to better characterize the reservoirs in MTW Field in deep-offshore Niger Delta Basin. Five (5) wells with complete suite of petrophysical logs, three-Dimensional (3-D) seismic data, checkshot and other well information were used. The well data were thoroughly quality checked, reservoirs were litho-stratigraphically delineated and used for petrophysical analysis across the wells. This was followed by seismic-to- well-tie, seismic interpretation, and seismic attribute analysis (Root Mean Square-RMS) generated using depth surface maps. 3-D static reservoir model and volumetric evaluation were carried out. Petrophysical properties were derived and distributed across the 3-D static model using sequential gaussian simulation algorithm to ascertain shale volume spread across the model. To improve the seismic resolution and reduce interpretation uncertainty at greater depth, model- based post-stack seismic inversion was performed to obtain acoustic impedance cube. Litho-stratigraphic and petrophysical analysis result revealed five reservoir sands (A, B, C, D, and E). Reservoir-A was seen to be more viable with a thickness of 13.42 m, high effective porosity of 27%, permeability of 3187.53 mD, low water saturation of 34% and low shale volume of 11% which are indication good reservoir quality and producibility. The seismic interpretation revealed thirty-one (31) growth and antithetic faults oriented in the NE-SW and NW-SE directions, respectively. The RMS result revealed high amplitude reflectivity which is a measure of zone of interest. Based on this, seven (7) prospects and three (3) leads were identified. The seismic inversion result shows a high level of accuracy with a correlation coefficient of 0.997; 0.997; 0.995; and 0.996 in MTW-001, MTW-003ST1, MTW-004ST1 and MTW-005 wells, respectively. The acoustic impedance successfully resolved and improved on the resolution of the seismic stacking velocity especially at reservoir layers and at depth deeper than 3600 ms. Acoustic impedance as a layer property has improved on the lateral and vertical resolutions of the data beyond what the usual seismic interval velocity could image thus, validating some of the prospects and leads identified in this study. This demonstrated that uncertainty can be reduced by a blend of RMS and seismic inversion in identifying reservoir for accurate placement of wells. It is therefore recommended that E and P operators should adopt the technique in their future hydrocarbon exploration endeavor in frontier and matured basins.

Development of a Probabilistic Correlation between the Gamma Ray Index and Shale Volume Factor to Improve Resource Estimation for the 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.

Delineation of the Groundwater Potential Zones using Integrated Geospatial Techniques and Multi-criteria Decision Approach in the Cretaceous Lower Benue and Niger Delta Basins of Abia State, Southern Nigeria

Delineation of the groundwater potential zones in the Cretaceous Lower Benue and Niger Delta basins of Abia state, Nigeria with geographic information system (GIS) / remote sensing (RS) multi-criteria decision approach (MCDA) considered the significant hydrogeomorphological factors affecting the availability of groundwater resources. The factors (geology, rainfall, slope, drainage density, lineament density, soil type, and land use land cover) were ranked using the analytical hierarchical process, a multi-criteria decision-making tool. The integration of the factors into a geographic information system (GIS) and weighted overlay analysis were then carried out using ArcGIS software. The result indicates 31.5% of zones of high to very high groundwater occurrence are in the southern section, and 41.6% of poor to very poor zones in the northern section. While the moderate zones make up the 26.8% of the study area. The study demonstrates that the groundwater occurrence in the study area is primarily controlled by the interactive impact of geology, rainfall, and slope factors, thus revealing the causes of the incessant random borehole failures in the moderate zones. Thus, the groundwater resources can be sustainably exploited, developed, and managed with the help of the map produced from the resulting demarcation of groundwater potential zones in the study.

Delineation of the Groundwater Potential Zones using Integrated Geospatial Techniques and Multi-criteria Decision Approach in the Cretaceous Lower Benue and Niger Delta Basins of Abia State, Southern Nigeria

Delineation of the groundwater potential zones in the Cretaceous Lower Benue and Niger Delta basins of Abia state, Nigeria with geographic information system (GIS) / remote sensing (RS) multi-criteria decision approach (MCDA) considered the significant hydrogeomorphological factors affecting the availability of groundwater resources. The factors (geology, rainfall, slope, drainage density, lineament density, soil type, and land use land cover) were ranked using the analytical hierarchical process, a multi-criteria decision-making tool. The integration of the factors into a geographic information system (GIS) and weighted overlay analysis were then carried out using ArcGIS software. The result indicates 31.5% of zones of high to very high groundwater occurrence are in the southern section, and 41.6% of poor to very poor zones in the northern section. While the moderate zones make up the 26.8% of the study area. The study demonstrates that the groundwater occurrence in the study area is primarily controlled by the interactive impact of geology, rainfall, and slope factors, thus revealing the causes of the incessant random borehole failures in the moderate zones. Thus, the groundwater resources can be sustainably exploited, developed, and managed with the help of the map produced from the resulting demarcation of groundwater potential zones in the study.

Crude oil price volatility and its impact on the development of marginal fields: a case study from the Niger Delta Basin, Nigeria

Crude oil price volatility and its impact on the development of marginal fields: a case study from the Niger Delta Basin, Nigeria

Analysis of Reservoir Properties and Quantification of Hydrocarbon Volumes Within LK Field, Niger Delta, Nigeria

This work analyzes and estimates the qualities and volumes of hydrocarbons in the identified reservoirs (Thin Sand and Sand B) of the LK field in the Niger Delta, Nigeria. The LK field is a promising hydrocarbon reservoir located at the border of the Greater Ughelli Depobelt in the Niger Delta Basin. The data utilized encompassed a 3D seismic survey, which was analyzed to delineate faults, identify stratigraphic horizons, and generate maps illustrating the time and depth structures within the subsurface. Well log data, including gamma ray, resistivity, and density/neutron measurements, were analyzed to evaluate and describe the petrophysical characteristics of the subsurface rock formations. The Thin Sand reservoir unit contains natural gas, while the Sand B reservoir is divided into two separate zones: the first zone (Z1) contains natural gas, and the second zone (Z2) contains oil. For Sand B, Z1, and Z2, the gross thicknesses are 13.16m and 57.46m, net thicknesses are 11.32m and 45.39m, NTGs are 0.86 and 0.79, shale volumes (Vsh) are 0.13 and 0.21, effective porosities (?e) are 0.28 and 0.21, water saturations (Sw) are 0.11 and 0.39, and hydrocarbon saturations (Sh) are 0.89 and 0.61, respectively. For the Thin Sand reservoir, the gross thickness is 6.00m, net thickness is 4.74m, NTG is 0.79, Vsh is 0.21, ?e is 0.23, Sw is 0.12, and Sh is 0.88. The stock tank oil initially in place (STOIIP) in the Sand B, Z2 reservoir is estimated to be 46.8 million barrels, with a recoverable oil volume of 9.4 million barrels, assuming a 20% recovery factor. The stock tank gas initially in place (STGIIP) is estimated at 10.4 billion cubic feet (Bcf) in the Thin Sand reservoir and 30.6 Bcf in the Sand B, Z1 reservoir, with recoverable gas volumes projected at 8.3 Bcf and 24.5 Bcf, respectively, assuming 80% recovery factors. After estimating the volume of hydrocarbons in the known reservoirs, significant and economic amounts of gas and oil for commercial purposes were discovered. However, this research study faces challenges such as uncertainty, unreliability, and varying scales due to different origins within the field. Further research using unconventional computational tools together with high-resolution simulating software is needed to produce more detailed and accurate results.

Hydrocarbon production potential of paralic reservoirs from the Niger Delta basin: Evidence from ichnological studies

Reservoir ichnological study was employed to improve on the inconsistencies and poor interpretation of hydrocarbon-bearing strata within the multipartite maturing terrain of the onshore Niger Delta basin. Ichnofacies characterization revealed two distinctive trace fossil suites that both reflected different feeding behaviours and responses to substrate consistency, which assisted in the high-resolution assessment of facies constituting the paralic reservoirs. Fifteen potential reservoir intervals were subdivided into productive and non-productive as revealed on core slabs as well as well log signatures. Fluctuating river sediment influx has been considered to be detrimental to the colonization of the channel deposits and barrier bars, which resulted in excellent hydrocarbon reservoirs in the study area. The sandstone facies, characterized by sparse bioturbation and extensive bedding, displays imprints of Ophiomorpha, Thalassinoides, and Palaeophycus. The removal of these imprints has minimized subtle heterogeneities, resulting in more uniform reservoir characteristics. This uniformity has favored the accumulation of hydrocarbons within the point bars.Biogenicchurning of bedded sediment generated a poorer sorting index thereby reducing the reservoir quality at 9866-9840ft, 9154-9120ft, and 9090- 060ft depth intervals, which has been interpreted to represent poor reservoir potentials. However, it is advised that future investigations should focus on the forced regressive shoreface and delta front reservoirs of the studied interval for its internal continuity that may contain maximum production potential.

Integration of Seismic and Well Log Data for Reservoir Characterization in Offshore Niger Delta, Nigeria

The demand for fossil fuels is continually increasing due to the growing global population and industrialization. It is thus necessary to find hydrocarbon prospects in new fields and those that have previously been classified as marginal fields in order to maximize production. An integrated approach is required to effectively characterize hydrocarbon reservoirs and assess their ability to store and produce hydrocarbons. 3D seismic reflection data and well log data were combined to quantitatively estimate hydrocarbon reserves in a field, offshore Niger delta, Nigeria. The reservoirs were delineated on the gamma ray and resistivity logs which penetrate four wells selected from the field. The petrophysical analysis provided information about the net-to-gross thickness ratio, porosity, shale volume and water saturation of the reservoirs, deduced from well log suites comprising gamma, resistivity, density and neutron-porosity logs through four wells. The seismic interpretation involved mapping of horizons and faults across the wells on the seismic section. Check shot data were used to tie the seismic data to the well log data to generate the synthetic seismogram. The time structural and depth structural maps were generated. The volumetric analysis entailed derivation of the Gross rock volume from the depth structural map, and estimation of the Stock Tank Oil Initially In Place (STOIIP). Four reservoirs were delineated in each of the four wells. The average thickness of the reservoirs ranges from 56.6 m to 232.7 m while the water saturation varies from 0.29% to 0.57%. The average porosities of the reservoirs ranges from 0.18% to 0.22%. The structural interpretation of the eight faults mapped reveals synthetic and antithetic faults, and rollover anticlines. The time- and depth structural maps generated from the mapped horizons show that the reservoirs are penetrated by the different faults. The Stock Tank Oil Initially In Place (STOIIP) of the reservoirs range from 25 MMstb to 468 MMstb. The study shows that the integration of 3D reflection data and well log data can be used effectively to estimate hydrocarbon reserves. The results of the study are expected to contribute to the development of new exploration and production strategies in the Niger delta basin and similar sedimentary environments.

Assessment of Sealing Potential of Fault-Bounded Hydrocarbon Prospect in Gabo Field, Niger Delta, Nigeria

Sealing potentials of faults are an important exploration risk to consider in the assessment of fault-bounded hydrocarbon prospects. This technique has been used for predicting potential hydrocarbon columns for mitigating risk in exploration and appraisals. Hence, the objective of the paper is to assess the sealing potential of the fault-bounded hydrocarbon prospects of the Gabo Field in the Niger Delta basin using seismic, well-log, and X-ray diffraction data. Three faults were interpreted as normal and syn-depositional faults. The well-log correlation showed that the shale sequence was inter-bedded with sands and showed a good spread with a relative thickness ranging between 12-105m from shallow to intermediate depth intervals. Results of the rock property analysis showed that the volume of shale ranged from 18 – 73.72% with an average of 63.59%. The total porosity ranged from 15.9 – 31.7 (good to excellent) with an average of 16.7 (good) in the shales and 27.2 (very good) in the sand. The effective porosity of the field ranged from 3.58 – 22.71 with an average of 6.028 in the shales and 20.13 in the sand. The estimated pore pressure ranged from 42.13 – 47.62psi with an average of 47.0psi in the shales and 42.8psi in the sand. The results of the X-ray diffraction analysis showed that the predominant minerals were kaolinite, rutile, gypsum, albite, microcline and quartz, which constitute the caprock sequence and the faulted rocks. Results of the sealing potential showed poor sealing in the shale sequence while the fault analysis showed good sealing along the fault planes. These results deduced the sealing uncertainty of the field and may be applied to similar siliciclastic trap configurations in deltaic environments.

Organic geochemical evaluation of crude oils from some producing fields in the Niger Delta basin, Nigeria

Geochemical and biomarker characteristics of representative crude oil samples from selected fields in southern Nigeria were evaluated to determine the organic matter input, origin of biological material, depositional environment, thermal maturity, and genetic relationship between the oils. Four crude oil samples were obtained from various oil producing fields from Delta, Bayelsa and Abia state in southern Nigeria and labeled Kwale (KW), Kolo creek (KLC), Owaza (OWA1 and OWA2). The crude oil samples were fractionated into saturates, aromatic hydrocarbons and polar compounds using column chromatography on silica gel thereafter, analyzed using Gas chromatography-mass spectrometry (GC–MS). The calculated ratios of normal alkanes, acyclic isoprenoids, carbon preference index (CPI), hopanes, and steranes showed the following results: Pr/Ph (0.34 to 0.89); C29/C27 (0.78 to 1.25); 20S/(20S + 20R)C29sterane (0.28 to 0.66); 22S/(22S + 22R)C32 homohopane (0.17 to 0.23); CPI (0.96 to 0.98); Ts/Ts + Tm (0.46 to 0.50); and sterane/hopane (0.16 to 0.87). The results obtained were used to correlate the crude oils with respect to depositional environment, thermal maturity, and organic matter source. The Pr/Ph ratios of KW and KLC were less than one, and the cross-plot of Pr/nC17 versus Ph/nC18 of KW and KLC suggested that the oils were deposited under anoxic environments, whereas OWA1 and OWA2 indicated oxic conditions with no biodegradation. From the calculated ratios of 22S (22S + 22R)C32 homohopane and CPI, the oils were mature and had entered the generating window. Sample OWA1 is the most mature, while KLC is the least mature. The calculated ratios also showed that the four oil samples were from a shale source rock with both terrestrial and marine inputs.

The organic geochemistry of crude oil in the Saltpond Basin (Ghana): Organic source input, depositional environment, and thermal maturity

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.

Reservoir Prediction and Prospectivity of Omos Field Onshore Niger Delta Basin, Nigeria

Reservoir prediction and prospectivity are performance indices of the oil and gas field development planning and reserves estimation which depicts the behaviour of the reservoir in the future; its success is dependent on accurate description of the reservoir rock properties, fluid properties, rock-fluid properties and flow. Hence, the objective of this paper was to investigate and predict the reservoir and prospectivity of Omos Field, Onshore Niger Delta Basin, by integrating appropriate standard methods. Results obtained from rock physics attribute map analysis revealed very high Mu-Rho values between 13.0-16.2 Gpa, that is expected for sand presence, and this agrees with the good quality reservoir sands predicted from sequence stratigraphy study.Lambda-Rho values obtained ranges between - 1 to 9.5 GPa, with a much lower value between -1 to 4.3 in the prospective zone that indicates the presence of hydrocarbon bearing sand. These results agree with the results of structural and amplitude maps analysis. Hence the prospective reservoir has a very good hydrocarbon potential in this zone and should be a target for further appraisal for development and production purposes.

Quantifying a tide-dominated, wave-, and river-influenced delta in Miocene facies of the Niger Delta basin

ABSTRACT The modern Niger Delta has long been classified as a mixed tide-, wave-, and river-influenced delta. Still, no detailed studies have quantified the relative proportions of formative processes and facies. This work presents the first quantitative estimate of the relative influence of formative processes in Miocene deposits based on core data from the Greater Ughelli, Central Swamp, and Coastal Swamp depositional belts of the Niger Delta basin. Facies analysis of 288.2 m of core from four wells shows approximately 53% tidal facies, 33% fluvial facies, and 14% wave-formed facies, indicating deposition in a prograding tide-dominated, wave-, and river-influenced delta. Cores from the Greater Ughelli and Central Swamp depobelts exhibit coarsening-upwards, prograding deltaic facies successions overlain by fluvial mudstone. Tidal deposits in the Coastal Swamp depobelt show coarsening-upwards prograding deltaic facies successions with well-developed tidal bundles indicating seasonal deposition. The basal part of these facies successions also reveals repeated floods characterized by slump and load structures and dewatering features. Delta-plain and delta-front–prodeltaic facies associations are identified based on physical sedimentary and biological structures. The delta-plain facies association consists of weakly bioturbated mudstone, fissile mudstone, and coarse-pebbly stratified sandstone facies with sparse trace fossils. The delta-front–prodeltaic facies association contains muddy and sandy heteroliths, stratified, medium and coarse-grained, cross-bedded sandstone, and convoluted mudstone facies. The facies vary but characteristically contain trace-fossil assemblages of the recently proposed Rosselia and Phycosiphon Ichnofacies, indicating delta-front and prodeltaic settings, respectively. Variability in the facies is determined by the relative influence of hydrodynamic processes (tide, wave, and river), variations in physicochemical stress, and the episodic character of deposition. In addition, based on the relative influence of each hydrodynamic processes, the facies differ through the successions, sometimes subtly.