Browsing by Author "Magoba, M."
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Item Crystallography, Mineral Optics, Igneous Petrology, Sedimentology: GLG 211, Degree Examinations June 2023(University of Fort Hare, 2023-06) Sinuka, S.; Magoba, M.; Liu, K.Item Economic Geology, Geophysics, Mining and Exploration Geology: GLG 511, Honours Examinations June 2023(2023-06) Liu, K.; Gwavava, O.; Magoba, M.; Pharoe, B.; Demlie, M.Item Flow unit determination of the upper shallow marine sandstone resevoirs in the Bredasdorp Basin, offshore South Africa(University of Fort Hare, 2024) Mudau, Ndamulelo; Magoba, M.; Opuwari, M.This study comprehensively analyses reservoir flow units and distribution in four wells (E-E1, E-S3, E-S5, and E-W1) of the lower Cretaceous upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa. The study integrated multiple techniques, including the Stratigraphic Modified Lorenz Plot, Improved Stratigraphic Modified Lorenz Plot, Winland pore throat radius, Stratigraphic Flow Profile, and Flow Zone Indicator, to establish the spatial flow unit distribution of the upper shallow marine reservoirs. Analyses of 400 core plugs, 14 thin section slides, and 15 Scanning Electron Microscopy samples and core logging provided detailed insights into petrophysical properties and diagenetic minerals affecting the flow units within the reservoir. A comprehensive examination of gamma-ray logs and core samples identified a prominent glauconitic sandstone reservoir in the upper shallow marine formations. The conventional core analysis revealed substantial variability in porosity (0.3 % - 18 %, average 6.4 %) and permeability (0.008 - 170 mD, average 24.5 mD). Stratigraphic Modified Lorenz Plot Identified three flow units: barrier, baffle, and normal flow units, with storage capacity and flow capacity, ranging from 1.6 – 12.9 and 0.08 – 32.6, respectively. Improved Stratigraphic Lorenz Plot (ISMLP) results identified six flow unit types: barrier, semi-barrier, semi-conductor, conductor, superconductor, and fractured. Flow unit ranking indicated reservoir quality ranges from barrier/seal (0°- 15°) to fractured (75° - 85°). Pore throat radius (R35) results revealed diverse rock-type distributions from nanoporous to macroporous, ranging from 0.3 µm to 6.6 µm. These rock types indicated fair reservoir quality. Flow Zone Indicator (FZI) identified five distinct Hydraulic Flow Units (HFUs): HFU 1, HFU 2, HFU 3, HFU 4, and HFU 5, with values ranging from 0.19 µm to 28.7 µm, with an average value of 2.9 µm. Flow zone correlation revealed widespread low-flow zones and localized moderate-flow zones. Core logging analysis revealed distinct lithological characteristics among the reservoirs. Wells E-E1 and E-S3 comprise medium- to coarse-grained sandstones with rip-up clasts of claystone and siltstone, predominantly pyritic and glauconitic. In contrast, well E-S5 exhibits cross-bedded sandstones, fining upward with claystone clasts, pebble shaped lithic grains, and conglomerates formed from rounded gravel. E-W1 consists of fine- to medium-grained sandstones and conglomerates with scattered pebbles. Multiple facies were identified in each well's cored intervals, with well E-E1 containing five facies (A-E), wells E-S3 and E-S5 having four facies (A-D), and well E-W1 having three facies (A-C). Diagenetic minerals such as glauconite, pore-filling illite, smectite, and cementations (quartz overgrowth and calcite) significantly affected the baffle and barrier flow units. The results from this study will improve the understanding of flow unit distribution and reservoir heterogeneity in Bredasdorp Basin. It can also be used as input parameters for the 3D dynamic flow unit modeling of the upper shallow marine sandstones in this Basin.Item Integration of routine core data and petrographic analysis to determine the sandstone reservoir flow units in the Bredasdorp Basin, Offshore South Africa(University of Fort Hare, 2024-11) Tyhutyhani, Nobathembu; Magoba, M.; Gwavava, O.The integration of routine core data and petrography to determine the sandstone reservoir flow units was extensively performed in four selected wells: F-A10, F-A13, FO1, and F-O2 in the Bredasdorp Basin, offshore South Africa. Determining the quality of reservoirs and identifying minerals present is crucial for defining the best reservoir interval for hydrocarbon flow and storage and avoiding exploration errors by using suitable drilling and hydraulic fluids. Moreover, it also helps select the best Enhanced Oil Recovery (EOR) methods. The analysed wells were randomly chosen throughout the upper shallow marine interval to examine the impact of diagenetic minerals on reservoir flow units using geophysical wireline logs, routine core analysis, and core samples. The routine core analysis data consisted of nine hundred core plugs, which were used to establish reservoir flow units from four independent methods, namely: Pore Throat Radius, Flow Zone Indicator, Stratigraphic Modified Lorenz Plot, and Improved Stratigraphic Modified Lorenz Plot. The analysis of seventeen thin sections and fifteen scanning electron microscopy samples were employed to determine the impact of diagenetic minerals on petrophysical properties. The gamma-ray log and core samples identified one reservoir from each well. The permeability and porosity of the four identified sandstone reservoirs ranged from 0–22% and 0–2250 mD, respectively. The Stratigraphic Modified Lorenz Plot results showed five flow units classified as high, moderate, low, very low, and tight reservoir rock. In contrast, the Improved Stratigraphic Modified Lorenz Plot showed six flow units: fractured, super-conductive, conductor, semi-conductor, baffle, and semi-barrier. The Improved Stratigraphic Modified Lorenz Plot method proved more effective than the Stratigraphic Modified Lorenz Plot method in identifying flow units. The pore throat radius revealed that the pores ranged from nano-porous (≤ 1 𝜇𝑚) to megaporous (≥ 10 𝜇𝑚). The best reservoir intervals had megaporous radii and were classified as high or super-conductive flow units. In contrast, the poorer or impervious reservoir intervals had nanoporous radii and were classified as tight or baffle flow units. Four hydraulic flow units were identified and ranked as impervious, poor, fair, and good. Core logging of selected reservoirs revealed that FA10 and F-A13 were composed of glauconitic, medium-grained sandstone, fine-grained sandstone, and claystone. F-O1 was composed of fine-to-coarse grained sandstone that was moderately to well-sorted. F-O2 comprised of fine-grained, argillaceous sandstones that were poorly to moderately sorted. The Scanning Electron Microscopy analysis revealed that the clay minerals in the selected wells were smectite, illite, and chlorite. The effect of diagenetic minerals on petrophysical properties was apparent in the pore-filling minerals (glauconite, siderite, smectite, illite, chlorite, quartz and feldspar overgrowth, calcite, and calcareous sponge), which affected intergranular pore spaces and pore connectivity. Various diagenetic processes, such as cementation, compaction, and pore-filling minerals, significantly impacted the reservoir petrophysical characteristics of the studied reservoirs, particularly the F-O2 reservoir. These results can serve as input parameters for the Bredasdorp Basin's static and dynamic reservoir models.Item Petrographic and Petrophysical Characterization of Sandstone Reservoir Rocks for CO₂ Geological Storage in the Bredasdorp Basin, offshore South Africa(University of Fort Hare, 2024-11-26) Hoza, Siyamtanda; Magoba, M.This study aimed to integrate the petrophysical and petrographic analyses to characterize the Lower Cretaceous sandstone reservoirs for CO2 geological storage in the Bredasdorp Basin offshore South Africa. These reservoirs are excellent for studying the potential CO2 storage, since they are depleted oil and gas reservoirs with vast exploration data available. Four wells intersecting the Lower Cretaceous sandstone reservoirs were selected for this study, namely E-AQ1, E-G2, F-A10, and F-A13. Dataset use for the study included wireline logs, geological well completion reports, 1393 conventional core analysis, 13 core samples, 16 thin section slides, and micromorphology images for 8 core samples. Interactive Petrophysics software was utilized to evaluate the petrophysical parameters. Gamma ray logs were used to identify and delineate the sandstone reservoirs above 800 m depth to determine the reservoirs' porosity, clay volume, water saturation, and permeability. Data from core samples and well logs were used to estimate the pore throat size and to compute storage and flow capacity. The thin-section petrography combined with the Scanning Electron Microscopy-Energy Dispersive Spectroscopy (SEM-EDS) was employed to assess the influence of clay minerals on reservoir characteristics. The average calculated values for volume of clay, effective porosity, water saturation, and permeability varied between 12.66 - 30.73 %, 9.37 - 13.6 %, 6.17 - 68.88 %, and 6.68 – 502 mD, respectively. E-AQ1 and E-G2 exhibited low porosity of less than 10 %, whereas F-A10 and F-A13 showed good porosity of more than 10 %. F A13 showed the highest permeability of 502.47 mD, while E-G2 showed the lowest value of 6.68 mD. E-G2 showed the highest clay volume at 30.73 %, while F-A13 showed the lowest value at 12.66 %. Furthermore, F-A10 showed the highest water saturation of 68.88 %, whereas well F-A13 showed the smallest value of 6.17 %. The pore throat radius revealed that F-A10 and F-A13 have a higher heterogeneity in the pore throat size distribution, and E-AQ1 and E-G2 showed the lowest heterogeneity, indicating that EAQ1 and E-G2 will have a consistent fluid flow when CO2 is injected. The storage and flow capacities ranged from 5.45 – 666.65 m and 12.43 – 9949.23 mD*m, respectively. Comparing the storage and flow capacities of E-G2, F-A10, and F-A13, E-G2 has the lowest storage capacity, and F-A10 has the highest. F-A13 has the lowest flow capacity, and F-A10 has the highest. The core description results for E-AQ1 showed a fine to medium-grained sandstone with glauconite, which is very calcareous. It has a calcite cement characterized by fracturing and tight cementation. E-G2 showed light grey, fine-grained sandstones, highly glauconitic, and visible bitumens. F-A10 showed medium to fine-grained, glauconitic, calcareous sandstones with better-preserved cross-bedding and heavily burrowed zones, indicating a high-energy depositional environment. F-A13 showed medium grey sandstones with varying grain sizes, visible pore spaces, and bioturbation, transitioning from fine-grained to medium-grained with depth. Thin section and SEM-EDS results show that the porosity for E-AQ1 was affected by quartz overgrowth and calcite cementation. E-G2 had carbonaceous material filling the pore spaces and compaction, thus affecting porosity. Feldspar overgrowth was observed from the intervals chosen for F-A10 and F-A13. Coarse grains were identified in F-A10, and they improved the overall porosity by creating larger spaces between particles. Glauconite was identified in all the wells. The most influential diagenetic processes impacting porosity, permeability, and water saturation included cementation (calcite and hematite), quartz and feldspar overgrowth, compaction, clay mineral authigenesis, and feldspar alteration. E-AQ1 showed poor reservoir quality due to quartz overgrowth reducing porosity and calcite cementation reducing permeability. On the other hand, F-A13 displayed a very porous sandstone reservoir containing smectite with a swelling nature, a needle-like illite, and an angular quartz grain, with calcite cementation and minimal compaction. The presence of clay minerals in the reservoir sands had a great impact on permeability and porosity. Based on the results and the criteria used, F-A10 and F-A13 are the most favourable reservoirs for CO2 storage due to their high porosity, permeability, storage and flow capacities, low volume of clay and water saturation and favourable mineralogical characteristics that enhance reservoir quality. The results from this study can help guide future CO₂ storage projects by offering a clear understanding of the reservoir quality and how well these sandstone reservoirs can hold and transport CO₂. By knowing more about factors like porosity, permeability, clay volume, and water saturation changes over time, this study can help choose the best areas for CO₂ injection and predict how CO₂ will move through the rocks. This information can also help evaluate other similar reservoirs for CO₂ storage, supporting efforts to safely store carbon in South Africa and contribute to the global climate change mitigation and the transition to a low-carbon future.Item Structrural Geology and South African Geology: GLG 313, Degree Examinations June 2023(University of Fort Hare, 2023-06) Magoba, M.; Liu, K.; Misra, S.Item Structural Geology, Geochemistry and Economic Geology: GLG 221, Degree Examinations October/November 2024(University of Fort Hare, 2024-10) Magoba, M.; Sinuka, S.; Gwavava, O.