This study aims to generate rock units based on core permeability and porosity of OW oilfield in the Bredasdorp Basin offshore South Africa. In this study, we identified and classified lithofacies based on sedimentology reports in conjunction with well logs. Lucia's petrophysical classification method is used to classify rocks into three classes. Results revealed three lithofacies as A (sandstone, coarse to medium-grained), B (fine to medium-grained sandstone), and C (carbonaceous claystone, finely laminated with siltstone). Lithofacies A is the best reservoir quality and corresponds to class 1, while lithofacies B and C correspond to class 2 and 3, which are good and poor reservoir quality rock, respectively. An integrated reservoir zonation for the rocks is based on four different zonation methods (Flow Zone indicator (FZI), Winland r35, Hydraulic conductivity (HC), and Stratigraphy modified Lorenz plot (SMLP)). Four flow zones Reservoir rock types (RRTs) were identified as RRT1, RRT3, RRT4, and RRT5, respectively. The RRT5 is the best reservoir quality composed of a megaporous rock unit, with an average FZI value between 5 and 10 µm, and HC from 40 to 120 mD/v3, ranked as very good. The most prolific flow units (RRT5 and RRT4 zones) form more than 75% of each well's flow capacities are supplied by two flow units (FU1 and FU3). The RRT1 is the most reduced rock quality composed of impervious and nanoporous rock. Quartz is the dominant framework grain, and siderite is the dominant cement that affects flow zones. This study has demonstrated a robust approach to delineate flow units in the OW oilfield. We have developed a useful regional petrophysical reservoir rock flow zonation model for clastic reservoir sediments. This study has produced, for the first time, insights into the petrophysical properties of the OW oilfield from the Bredasdorp Basin South Africa, based on integration of core and mineralogy data. A novel sandstone reservoir zonation classification criteria developed from this study can be applied to other datasets of sandstone reservoirs with confidence.

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.

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Geological carbon storage provides an efficient technology for the large-scale reduction of atmospheric carbon, and the drive for net-zero emissions may necessitate the future usage of oil reservoirs for CO2 projects, (without oil production), hence, dynamic modeling of an oil reservoir for CO2 storage in the Bredasdorp basin, South Africa, was therefore conducted. Injection into the reservoir was for 20 years (2030–2050), and 100 years (2050–2150) to study the CO2-brine-oil interactions, with sensitivities carried out on reservoir boundary conditions. The closed boundary scenario experienced pressure buildup with a target injection rate of 0.5 Mt/year, and a cutback on injection rate progressively until 2050 to not exceed the fracture pressure of the reservoir. The CO2 plume migration was not rapid due to the reduced volume of CO2 injected and the confining pressure. The system was gravity dominated, and gravity stability was not attained at the end of the simulation as fluid interfaces were not yet flat. The open boundary reservoir did not experience a pressure buildup because all boundaries were open, the target injection rate was achieved, and it was a viscous-dominated system. In both cases, the dissolution of CO2 in oil and brine was active, and there was a growing increase of CO2 fraction dissolved in water and oil, a decline in gaseous mobile CO2 phase between 2050 and 2150, and active trapping mechanisms were structural trapping, dissolution in oil and water, and residual trapping. The study showed that boundary condition was very crucial to the success of the project, with direct impacts on injection rate and pressure. This pioneer study has opened a vista on the injection of CO2, and CO2-brine-oil interactions, with sensitivities carried out on reservoir boundary conditions in a closed and an open hydrocarbon system in South Africa.