Petrographic and Petrophysical Characterization of Sandstone Reservoir Rocks for CO₂ Geological Storage in the Bredasdorp Basin, offshore South Africa
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Date
2024-11-26
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University of Fort Hare
Abstract
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.
Description
Masters dissertation
Keywords
Geological carbon sequestration, Porosity, Permeability, Glauconite
Citation
Hoza, S. (2024) Petrographic and petrophysical characterization of sandstone reservoir rocks for CO₂ geological storage in the Bredasdorp Basin, offshore South Africa. MSc (Petroleum Geology) thesis. Alice, South Africa: University of Fort Hare.