UWCScholar :: Browsing by Author "Opuwari, Mimonitu"

Browsing by Author "Opuwari, Mimonitu"

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3D static modeling and CO2 static storage estimation of the hydrocarbon-depleted charis beservoir, Bredasdorp basin, South Africa
(Natural Resources Research, 2023) Afolayan, Blessing Ayotomiwa; Opuwari, Mimonitu; Mackay, Eric
An essential greenhouse gas effect mitigation technology is carbon capture, utilization and storage, with carbon dioxide (CO2) injection into underground geological formations as a core of carbon sequestration. Developing a robust 3D static model of the formation of interest for CO2 storage is paramount to deduce its facies changes and petrophysical properties. This study investigates a depleted oilfield reservoir within the Bredasdorp Basin, offshore South Africa. It is a sandstone reservoir with effective porosity mean of 13.92% and dominant permeability values of 100–560 mD (1 mD = 9.869233 × 10–16 m2). The petrophysical properties are facies controlled, as the southwestern area with siltstone and shale facies has reduced porosity and permeability. The volume of shale model shows that the reservoir is composed of clean sands, and water saturation is 10–90%, hence suitable for CO2 storage based on petrophysical characteristics. Static storage capacity of the reservoir as virgin aquifer and virgin oilfield estimates sequestration of 0.71 Mt (million tons) and 1.62 Mt of CO2, respectively. Sensitivity studies showed reservoir depletion at bubble point pressure increased storage capacity more than twice the depletion at initial reservoir pressure. Reservoir pressure below bubble point with the presence of gas cap also increased storage capacity markedly.
Application of geochemical characterization, multivariate statistics and geological modelling in assessment and prediction studies on selected coal and gold mine waste in South Africa
(University of the Western Cape, 2023) Abegunde, Oluseyi Blessed; Opuwari, Mimonitu
Over the years, South Africa has generated vast amounts of coal fly ash and gold slime tailings, constituting over 70% of the country's waste materials. These byproducts contain elevated levels of trace metals, posing a potential threat to the environment upon release. Addressing this issue requires a comparative study of the environmental impact of coal fly ash and selected mine tailings on water resources and land pollution. This research aims to investigate and compare leachability, metal release, oxidation effects, and environmental pollution between coal fly ash and gold tailings. By contrasting these aspects, the study seeks to enhance understanding of the potential risks associated with these materials, aiding informed decision-making for their management and regulation. Additionally, the research explores the correlation between gold tailings' acid potential generation and coal fly ash's alkaline potential generation in terms of leachability, metal release, oxidation effects, and environmental pollution. The research employed comprehensive laboratory experiments and analytical investigations, including leaching tests under simulated weathering conditions. A total of 51 gold tailings samples and 66 coal fly ash samples were analysed through SEM and XRD for mineralogical insights and ICP-MS and XRF for geochemical analyses. Statistical analysis revealed the significant roles of pH, Fe ions, Ca2+, and Mg2+ in metal extraction from both materials. Notably, the study identified key factors contributing to the environmental impact of coal fly ash and gold tailings. SEM imagery highlighted heterogeneous characteristics in gold tailings, while factor analysis indicated the potential release of ferrous ionic species, contributing to acidity. Trace elements like Ni, Zn, Pb, and Cu were predominantly associated with Fe/Mn oxides during leaching experiments, facilitating their mobilization with acid-generating ions.
Determination of total organic carbon content using Passey's method in coals of the central Kalahari Karoo Basin, Botswana
(2022) Mabitje, Mamphedi Sylvia; Opuwari, Mimonitu
This paper focuses on determining total organic carbon (TOC) from boreholes in the Kalahari Basin, Botswana, using Passey's method. The Kalahari Karoo basin is one of several basins in southern Africa filled with Late Carboniferous to Jurassic sedimentary strata that host Permian age coal seams. Nine exploration boreholes (wells) drilled in the central Kalahari Karoo basin are used to determine the Total Organic Carbon potential. Vitrinite reflectance (Ro), proximate and ultimate analyses were conducted on cored coal intervals. Passey's ΔLogR method applied in this study employs resistivity and porosity logs to identify and quantify potential source rocks. Results of Passey's method compared with laboratory-measured carbon showed that Passey's method effectively identifies coal intervals. In terms of TOC calculations, the method works poorly in coal metamorphosed by dolerite intrusions.
Evaluation of carbon dioxide storage potential in wells of the Bredasdorp basin offshore South Africa
(Taylor and Francis Ltd., 2024) Ngcobo, Luyanda; Afolayan, Blessing; Opuwari, Mimonitu
This study focuses on determining how carbon dioxide (CO2) storage can be stored in the central Bredasdorp basin offshore South Africa. Logs, seismic lines, and reports of three exploration wells were used to build a 3D static model, and the compressibility method was used to estimate the CO2 static storage capacity of the reservoir. The wells displayed fair to good porosity and moderate permeability. The zone of interest had little to no faulting, and there is evidence of differential deposition of marine sandstones that overlie fluvial shales. The sandstones have good reservoir characteristics and are overlain by thick shales that serve as seals. The reservoir displayed thinning in the eastern direction and over structural highs. A static storage assessment of the reservoir showed 0.64 Mt of CO2, and the effect of changing pore volume and water saturation on overall CO2 storage volume was observed. The results revealed that an increase in pore volume would also increase the amount of CO2 stored in the reservoir. Conversely, increased water saturation leads to decreased CO2 that can be stored in the reservoir. This study has shown that the pre-existing reservoir fluid has an impact on CO2 storage volume; the greater the volume of water in the reservoir, the less the volume of CO2 that can be stored in the reservoir; this is because water is less compressible than rock, oil or gas.
Geochemical evaluation of source rock potential and characterization of hydrocarbon occurrences in the Eastern Dahomey Basin, Nigeria
(University of Western Cape, 2020) Mohammed, Saeed; Opuwari, Mimonitu; Titinchi, Salam
Nigeria is endowed with significant oil sand and heavy oil reserves. These reserves are found within the Cretaceous Afowo Formation in the Eastern Dahomey Basin. The petroleum systems and quality of these reserves are poorly understood. Harnessing these resources necessitate comprehensive deposit evaluation and characterization.
Geological and geophysical evaluation of the Thebe field, Block XX, offshore Western Australia
(University of the Western Cape, 2013) Bailey, Brett B.; Opuwari, Mimonitu
The North West Shelf of Australia is a prolific gas province. The Thebe Gas Field is situated within the northern central Exmouth Plateau in the Northern Carnarvon Basin. The Exmouth Plateau is a submerged continental block whose culmination lies at about 800m below sea level. The seismic data used for this study is the HEX07B survey which was conducted in 2007. The objective of this study was to interpret all available seismic data, of which six horizons were picked, generating two-way-time structure maps and an average velocity map, performing depth conversion and generating various depth maps. The horizons picked were the economic basement, Triassic Mungaroo, Murat Siltstone, Muderong Shale, Gearle Siltstone and the Sea Bed. The horizon of interest was the Triassic Mungaroo Formation and therefore it was the only horizon with an average velocity map. The seismic sections were used in conjunction with the structure maps generated to identify possible locations for appraisal wells to be drilled. Prospect X was identified on the basis of amplitude and structure present within the Triassic Mungaroo Formation. The final task was to calculate the volumes present and a Monte-Carlo Simulation was used for this. The results obtained showed that Prospect X has a good petroleum system in place. The Mungaroo Formation is identified as being the possible source and reservoir rock, the Muderong Shale is the seal, structural traps are provided by large fault block and faults provided the migration pathways from the source in to the reservoir. The volumes were calculated using three areas identified on the structure maps by three closing contours. These areas are the P90, P50, P10 and the volumes for the gas in place were as follows, P90 = 893 Bcf (0.9Tcf), P50 = 1128 Bcf (1.1 Tcf), P10 = 1367 Bcf (1.4Tcf). Using the various parameters the probability of success for Prospect X was calculated to be 20%.
Hydrocarbon potential of the Prince Albert Formation, Ecca Group in the main Karoo Basin, South Africa.
(University of the Western Cape, 2020) Mosavel, Haajierah; Opuwari, Mimonitu
The impact of detrital minerals on reservoir flow zones in the North Eastern Bredasdorp basin, South Africa, using core data
(MDPI, 2022) Opuwari, Mimonitu; Ubong, Moses Okon; Jamjam, Simamkele
The present study uses core data to group reservoirs of a gas field in the Bredasdorp Basin offshore South Africa into flow zones. One hundred and sixty-eight core porosity and permeability data were used to establish reservoir zones from the flow zone indicator (FZI) and Winland’s methods. Storage and flow capacities were determined from the stratigraphy-modified Lorenz plot (SMLP) method. The effects of the mineralogy on the flow zones were established from mineralogy composition analyses using quantitative X-ray diffraction (XRD) and Scanning Electron Microscopy (SEM). Results reveal five flow zones grouped as high, moderate, low, very low, and tight reservoir rocks.
Investigation of the acoustic impedance variations of the upper shallow marine sandstone reservoirs in the Bredasdorp basin, offshore South Africa
(University of the Western Cape, 2019) Magoba, Moses; Opuwari, Mimonitu; Waldmann, Nicolas
Investigation of the acoustic impedance variations in the upper shallow marine sandstone reservoirs was extensively studied from 10 selected wells, namely: F-O1, F-O2, E-M4, E-CN1, E-G1, E-W1, F-A10, F-A11, F-A13, and F-L1 in the Bredasdorp Basin, offshore, South Africa. The studied wells were selected randomly across the upper shallow marine interval with the purpose of conducting a regional study to assess the variations in the acoustic impedance across the reservoirs using wireline log and core data. The datasets used in this study were geophysical wireline logs, conventional core analysis, geological well completion reports, core plugs, and core samples. The physical rock properties such as lithology, fluid type, and hydrocarbon bearing zone were identified while different parameters like the volume of clay, porosity, and water saturation were quantitatively estimated. The reservoirs were penetrated at a different depth ranging from a shallow depth of 2442m at well F-L1 to a deeper depth of 4256.7m at well E-CN1. The average volume of clay, average effective porosity from wireline log, and average water saturation ranged from 8.6%- 43%, 9%- 16% and 12%- 68%, respectively. Porosity distribution was fairly equal across the field from east to west except in well F-A10, F-A13, and F-A11 where a much higher porosity was shown with F-A13 showing the highest average value of 16%. Wells E-CN1, E-W1, F-O1, F-L1 and E-G1 had lower porosity with E-CN1 showing the lowest average value of 9%. The acoustic properties of the reservoirs were determined from geophysical wireline logs in order to calculate acoustic impedance and also investigate factors controlling density and acoustic velocities of these sediments. The acoustic impedance proved to be highest on the central to the western side of the field at E-CN1 with an average value of 11832 g/cm3s whereas, well F-A13 reservoir in the eastern side of the field proved to have the lowest average acoustic impedance of 9821 g/cm3s. There was a good linear negative relationship between acoustic impedance and porosity, compressional velocity vs porosity and porosity vs bulk density. A good linear negative relationship between acoustic impedance and porosity was obtained where the reservoir was homogenous, thick sandstone. However, interbedded shale units within the reservoir appeared to hinder a reliable correlation between acoustic impedance and porosity. The cross-plots results showed that porosity was one of the major factors controlling bulk density, compressional velocity (Vp) and acoustic impedance. The Gassmann equation was used for the determination of the effects of fluid substitution on acoustic properties using rock frame properties. Three fluid substitution models (brine, oil, and gas) were determined for pure sandstones and were used to measure the behaviour of the different sandstone saturations. A significant decrease was observed in Vp when the initial water saturation was substituted with a hydrocarbon (oil or gas) in all the wells. The value of density decreased quite visibly in all the wells when the brine (100% water saturation) was substituted with gas or oil. The fluid substitution affected the rock property significantly. The Vp slightly decreases when brine was substituted with water in wells F-A13, F-A10, F-O2, F-O1 F-A11, F-L1, and E-CN1. Wells E-G1, E-W1, and E-M4 contain oil and gas and therefore showed a notable decrease from brine to oil and from oil to gas respectively. Shear velocity (Vs) remained unaffected in all the wells. The acoustic impedance logs showed a decrease when 100% water saturation was replaced with a hydrocarbon (oil or gas) in all the wells. Clay presence significantly affects the behaviour of the acoustic properties of the reservoir rocks as a function of mineral type, volume, and distribution. The presence of glauconite mineral was observed in all the wells. Thirty-two thin sections, XRD and SEM/EDS from eight out of ten wells were studied to investigate lithology, diagenesis and the effect of mineralogy on porosity and acoustic properties (Compressional velocity and bulk density) within the studied reservoir units. Cementation (calcite and quartz), dissolution, compaction, clay mineral authigenesis, and stylolitization were the most significant diagenetic processes affecting porosity, velocity, and density.Well E-CN1 reservoir quality was very poor due to the destruction of intergranular porosity by extensive quartz and illite cementation, and compaction whereas well F-A13 show a highly porous sandstone reservoir with rounded monocrystalline quartz grain and only clusters of elongate to disc-like, authigenic chlorite crystals partly filling a depression within altered detrital grains. Overall, the results show that the porosity, lithology mineralogy, compaction and pore fluid were the major factors causing the acoustic impedance variations in the upper shallow marine sandstone reservoirs.
Metal–metal correlation of biodegraded crude oil and associated economic crops from the Eastern Dahomey Basin, Nigeria
(MDPI, 2022) Mohammed, Saeed; Opuwari, Mimonitu; Titinchi, Salam
The presence of heavy metals in plants from oil sand deposits may reflect mineralization resulting from petroleum biodegradation. Petroleum composition and heavy metal analyses were performed using thermal desorption gas chromatography and atomic absorption spectrophotometry on oil sand and plant root samples from the same localities in the Dahomey Basin. The results from the oil sand showed mainly heavy-end hydrocarbon components, humps of unresolved complex mixtures (UCM), absences of C6-C12 hydrocarbon chains, pristane, and phytane, indicating severe biodegradation. In addition, they showed varying concentrations of vanadium (2.699–7.708 ppm), nickel (4.005–11.716 ppm), chromium (1.686–5.733 ppm), cobalt (0.953–3.223 ppm), lead (0.649–0.978 ppm), and cadmium (0.188–0.461 ppm). Furthermore, these heavy metals were present in Citrus, Theobroma Cacao, Elaeis guineensis, and Cola.
New insights in the evaluation of reserves of selected wells of the Pletmos Basin offshore South Africa
(One Petro, 2016) Elamri, Samir; Opuwari, Mimonitu
The area evaluated has similar structural styles and settings as the producing neighboring fields of F-A and E-M in the adjacent Bredasdorp basin Offshore South Africa. The main objective of this study is to create a 3-D-static model and estimate hydrocarbon reserves. Based on log signatures, petrophysical properties and structural configurations, the reservoirs were divided vertically into three reservoir units in order to be properly modelled in 3-D space. The thicknesses of the layers were determined based on the vertical heterogeneity in the reservoir properties. Facies interpretation was performed based on log signatures, core description and previous geological studies. The volume of clay and porosity was used to classify facies into five units of sand, shaly sand, silt, and clay. From petrophysical interpretation, a synthetic permeability log was generated in the wells which ties closely with core data.
An overview of trace elements in soils of Keana-Awe Brine-Fields, Middle Benue Trough, Nigeria
(Taylor & Francis: STM, Behavioural Science and Public Health Titles, 2017) Sallau, Adamu; Momoh, Abuh; Opuwari, Mimonitu; Akinyemi, Segun; Lar, Uriah
The objective of this study was to determine the concentration of trace elements in soils of Keana-Awe brine-fields. Composite soil samples were randomly collected at a depth of 0–15 cm and were analysed for molybdenum, zinc, arsenic, lead, cobalt, chromium, copper, barium and nickel using Inductively Coupled Plasma Mass Spectroscopy (ICP-MS). Quantification of the degree of soil contamination by these trace elements was carried out using the enrichment factor (EF) and the geo-accumulation index (Igeo). The data were subjected to principal component analysis (PCA). The average concentrations were 1.56 ppm molybdenum, 1116.42 ppm zinc, 23.80 ppm arsenic, 71.40 ppm lead, 17.64 ppm cobalt, 237.35 ppm chromium, 24.16 ppm copper, 254.67 ppm barium and 143.71 ppm nickel. Cobalt, nickel and chromium showed positive loadings in component 1 with a total variance of 29.56%. Zinc, copper and lead showed positive loadings in component 2 with a total variance of 18.79%, while copper showed negative loading in component 3 with a total variance of 14.79%. Considering the concentration of trace elements in the soils and statistical analyses, we conclude that soils of the study area were severely enriched in molybdenum, cobalt, chromium, copper, barium, nickel, while arsenic and zinc are in excessive concentrations in the soils. These trace elements could have originated from geogenic and anthropogenic sources.
Petrophysical evaluation of the Albian Age gas bearing sandstone reservoirs of the O-M field, Orange Basin, South Africa
(University of the Western Cape, 2010) Opuwari, Mimonitu; Carey, Paul; De Poquioma, Escordia; Dept. of Earth Science; Faculty of Science
Petrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization.
Petrophysical evaluation of the albian age gas bearing sandstone reservoirs of the o-m field, orange basin, South Africa
(University of the Western Cape, 2010) Opuwari, Mimonitu; Carey, Paul; De Poquioma, Escordia; Dept. of Earth Science
Petrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization. Pore throat radius was estimated from conventional core porosity and permeability with application of the Winland’s method for assessment of reservoir rock quality on the bases of pore throat radius. Results from the Winland’s method present five Petrofacies (Mega porous, Macro porous, Meso porous, Micro porous and Nanno porous). The best Petrofacies was mega porous rock type which corresponds to lithofacies A1 and A2. The nano porous rock type corresponds to lithofacies A6 and was subsequently classified as non reservoir rock. The volume of clay model from log was taken from the gamma-ray model corrected by Steiber equations which was based on the level of agreement between log data and the x-ray diffraction (XRD) clay data. The average volume of clay determined ranged from 1 – 28 %. The field average grain density of 2.67 g/cc was determined from core data which is representative of the well formation, hence 2.67 g/cc was used to estimate porosity from the density log. Reservoir rock properties are generally good with reservoir average porosities between 10 – 22 %, an average permeability of approximately 60mD. The laterolog resistivity values have been invasion corrected to yield estimates of the true formation resistivity. In general, resistivities of above 4.0 Ohm-m are productive reservoirs, an average water resistivity of 0.1 Ohm-m was estimated. Log calculated water saturation models were calibrated with capillary pressure and conventional core determined water saturations, and the Simandoux shaly sand model best agree with capillary and conventional core water saturations and was used to determine field water saturations. The reservoir average water saturations range between 23 – 69 %. The study also revealed quartz as being the dominant mineral in addition to abundant chlorite as the major clay mineral. The fine textured and dispersed pore lining chlorite mineral affects the reservoir quality and may be the possible cause of the low resistivity recorded in the area. The reservoirs evaluated in the field are characterized as normally pressured with an average reservoir pressure of 4800 psi and temperature of 220 ºF. An interpreted field aquifer gradient of 0.44 psi/ft (1.01 g/cc) and gas gradient of 0.09 psi/ft (0.2 g/cc) were obtained from repeat formation test measurements. A total of eight gas water contacts were identified in six wells. For an interval to be regarded as having net pay potential, cut-off values were used to distinguish between pay and non-pay intervals. For an interval to be regarded as pay, it must have a porosity value of at least 10 %, volume of clay of less than 40 %, and water saturation of not more than 65 %. A total of twenty four reservoir intervals meet the cut-off criteria and was regarded as net pay intervals. The gross thickness of the reservoirs range from 2.4m to 31.7m and net pay interval from 1.03m to 25.15m respectively. In summary, this study contributes to scale transition issues in a complex gas bearing sandstone reservoirs and serves as a basis for analysis of petrophysical properties in a multi-scale system.
Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa
(Springer Nature, 2020) Magoba, Moses; Opuwari, Mimonitu
The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties.
Sandstone reservoir zonation of the north-western Bredasdorp Basin South Africa using core data
(Elsevier, 2021) Opuwari, Mimonitu; Dominick, Nehemiah
This study delineates sandstone reservoir flow zones in the north-western Bredasdorp Basin, offshore South Africa, using conventional core porosity and permeability data. The workflow begins by integrating sedimen- tology reports and logs to identify lithofacies before evaluating petrophysical flow zones. Three lithofacies were classified as lithofacies 1, 2, and 3. Lithofacies 1 is a silty shale and bioturbated sandstone, lithofacies 2 is an interbedded sandstone and shale, with very fine sandstone with well-sorted grains, and is heavily cemented. Conversely, lithofacies 3 is a fine-to medium-grained sandstone with minor shale that is moderately cementation. Lithofacies 3 is ranked as the best reservoir rock, followed by lithofacies 2 and 1. Four independent reservoir zonation methods (permeability anisotropy, Winland r35 pore throat, flow zone indicator (FZI), and stratigraphic modified Lorenz lot (SMLP)) were applied to core samples from three wells (MO4, MO5, and MO6). The core samples predominantly had slight anisotropic permeability (0.5–1.1). The reservoir units were ranked into four flow zone categories as tight, very low, low, and moderate, based on porosity and permeability, and calculated parameters.
Shale-gas potential from Cretaceous succession in South Africa’s orange basin: insights from integrated geochemical evaluations
(Taylor & Francis, 2022) Opuwari, Mimonitu; Yelwa, Nura Abdulmumini; Mustapha, Khairul Azlan
Shale sediments were collected from four Cretaceous stratigraphic units across four explorations well locations in South Africa’s Orange Basin and analysed to determine organic-matter characteristics, such as amount, quality, thermal maturity, and their viability as gas resources. The geochemical results show that the Cretaceous shales contain moderate organic quantities, as shown by TOC averagely up to 1.29%. The organic facies consist primarily of Type III kerogen, as proven alongside low hydrogen indexes between 40 and 133 mg HC/g TOC. As seen under a reflected light microscope, the dominance of such land plant-rich organic matter is in harmony with the significant amount of Vitrinite macerals. These organic sediments can produce primarily gas when they mature. The geological and geochemical properties of the organic sediments, chiefly Type III kerogen, generate both wet and dry gas, particularly when adequate thermal maturity is enhanced at deeper locations. Thus, the Orange Basin is considered promising for shale gas exploration and production.
Source rock evaluation of Afowo clay type from the Eastern Dahomey Basin, Nigeria: Insights from different measurements
(Springer Nature, 2020) Mohammed, Saeed; Opuwari, Mimonitu; Titinchi, Salam
The Cretaceous Afowo Formation in the Eastern Dohamey Basin is characterized by an admixture of lithofacies ranging from sandstones, claystones, shales, clays, sand/shale, and sand/clay intercalations. The sandy facies, a mix of sandstone, clay, shale, and intercalations, contain biodegraded hydrocarbons while the shales and claystones that underlie it are rich in organic matter. The hydrocarbon-bearing interval is commonly referred to as the oil sand or tar sand. In this study, Afowo clay type underlying an outcrop of the oil sand was appraised for its hydrocarbon potential with loss on ignition, thermogravimetry, and rock evaluation pyrolysis.
Static reservoir modeling using stochastic method: A case study of the cretaceous sequence of Gamtoos Basin, Ofshore, South Africa
(Springer, 2021) Ayodele, Oluwatoyin Lasisi; Chatterjee, Tapas; Opuwari, Mimonitu
Gamtoos Basin is an echelon sub-basin under the Outeniqua ofshore Basin of South Africa. It is a complex rift-type basin with both onshore and ofshore components and consists of relatively simple half-grabens bounded by a major fault to the northeast. This study is mainly focused on the evaluation of the reservoir heterogeneity of the Valanginian depositional sequence. The prime objective of this work is to generate a 3D static reservoir model for a better understanding of the spatial distribution of discrete and continuous reservoir properties (porosity, permeability, and water saturation). The methodology adopted in this work includes the integration of 2D seismic and well-log data. These data were used to construct 3D models of lithofacies, porosity, permeability, and water saturation through petrophysical analysis, upscaling, Sequential Indicator Simulation, and Sequential Gaussian Simulation algorithms, respectively. Results indicated that static reservoir modeling adequately captured reservoir geometry and spatial properties distribution. In this study, the static geocellular model delineates lithology into three facies: sandstone, silt, and shale. Petrophysical models were integrated with facies within the reservoir to identify the best location that has the potential to produce hydrocarbon. The statistical analysis model revealed sandstone is the best facies and that the porosity, permeability, and water saturation ranges between 8 and 22%, 0.1 mD (<1.0 mD) to 1.0 mD, and 30–55%. Geocellular model results showed that the northwestern part of the Gamtoos Basin has the best petrophysical properties, followed by the central part of the Basin. Findings from this study have provided the information needed for further gas exploration, appraisal, and development programs in the Gamtoos Basin.
The effect of diagenetic minerals on the petrophysical properties of sandstone reservoir: a case study of the upper shallow marine sandstones in the central Bredasdorp basin, offshore South Africa
(Multidisciplinary Digital Publishing Institute (MDPI), 2024) Magoba, Moses; Opuwari, Mimonitu; Liu, Kuiwu
The upper shallow marine sandstone reservoirs of the Barremian-to-Valanginian formation are the most porous and permeable sandstone reservoirs in the Bredasdorp basin and an important target for oil and gas exploration. There is a paucity of information on the reservoir characterization and effect of diagenetic mineral studies focusing on the upper shallow marine sandstone reservoirs in the central Bredasdorp basin; thus, there is a need to investigate the effect of diagenetic minerals and to characterize these reservoirs due to their high porosity and permeability. Datasets, including a suite of geophysical wireline logs, routine core analysis, geological well completion reports, description reports, and core samples, were utilized. A total of 642 core porosity measures, core water saturation, and core permeability data were used for calibration with the log-derived parameters, ranging in depth from 3615 m to 4259 m. Rock samples were prepared for diagenetic mineral analyses, such as thin sections and Scanning electron microscopy, for each well to investigate the presence of diagenetic minerals in the selected reservoir units. The petrophysical analyses showed the results of porosity, volume of clay, water saturation, and permeability, ranging from 9% to 27%, 8.6% to 19.8%, 18.9% to 30.4%, and 0.096 mD to 151.8 mD, respectively, indicating a poor-to-good reservoir quality. Mineralogical analyses revealed that micrite calcite, quartz cement, quartz overgrowth, and authigenic pore-filling and grain-coating clay minerals (illite–smectite and illite) negatively affected intergranular porosity.

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