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Among the several existing geochemical methods in hydrocarbon exploration, the technique linking total organic carbon content (TOC) and Rock–Eval pyrolysis is most widely used, largely as a result of its capacity to rapidly provide vital information regarding the identification of source rocks and their defining characteristic, as well as thermal maturity levels and generative potentials. In this study, data from prospective source units within the southern depocenter of the Pletmos Sub-basin were analyzed using this geochemical method. Cutting samples from six wells in Block 11a were subjected to organic geochemical analysis to understand the occurring hydrocarbon scenario. Based on the results of the investigation, five notable source rock intervals of Kimmeridgian to Turonian ages were identified. The source rocks are shales with both indigenous and non-indigenous organic matter. Their TOC values show a fair to excellent petroleum generating potential, with the Aptian and Kimmeridgian intervals having the highest and lowest, respectively. The Hydrogen Index (HI), along with S2/S3 ratio values, typifies a predominance of mixed type II/III (oil/gas-prone) with some type III (gas-prone) and II (oil-prone) kerogens. The trends of the maturity parameters Tmax and Ro (vitrinite reflectance) indicate maturities ranging from immature to a late stage of maturity (dry gas window). Two observed breaks in the Ro profile reveal a possible link of maturity to high heat flow that is allied to sedimentation and tectonic uplift during the Late Cretaceous. Generally, based on TOC, S1, and HI, the petroleum potential trend increases with increasing depth, with a striking display of mixed hydrocarbon generating potential. Interpreted hydrocarbon typing is thus recommended to support the well-testing analysis. [ABSTRACT FROM AUTHOR]

A 3D numerical modelling workflow was applied to the Barremian—Aptian source rock interval in a shelfal to lower slope area of the northern Orange Basin, offshore western South Africa. The main objective was to investigate the timing of hydrocarbon generation and migration. Hydrocarbon migration has previously been investigated in the south of the basin by relating gas escape features with structural elements as seen on seismic sections, but migration pathways are still poorly understood. The modelling study was based on data from three exploration wells (AO‐1, AE‐1 and AF‐1) together with 42 2D seismic sections totalling 3537 km in length, and a 3D seismic cube covering an area of 750 sq. km. Modelled formation temperatures increase from north to south in the study area and were consistent with downhole temperatures at well locations. However, there is variation between measured and modelled values of vitrinite reflectance (VR), especially in the Turonian and Cenomanian intervals. The measured VR is lower than the modelled VR within the Turonian section in the north of the study area, suggesting that erosion has affected the thermal maturity of the sediments. However, in the Cenomanian interval, the measured VR is higher than the modelled VR. Uplift, increased erosion in the hinterland and sediment transport to the coastal areas resulted in Cenomanian progradation of the Orange Basin fill. This together with a heat flow pulse resulted in increased thermal maturities in the study area. Modelling results show that hydrocarbon generation began in the central part of the study area by 116 Ma and reached a peak in the Late Cretaceous (65 Ma). Hydrocarbon migration began at about 110 Ma with an expulsion efficiency of 0.77. At the present day, ∼100% transformation of reactive kerogen into hydrocarbons has taken place in the central part of the study area, with random gas migration within Cenomanian and Albian reservoirs. Modelled oil migration likely influenced by hydrodynamic factors is down‐dip (westwards), towards deeper‐water, more distal parts of the basin. Gas saturation on a reactivated listric fault, which was ∼100% saturated at 93 Ma, declined to ∼15% by 65 Ma. This decrease in gas saturation is linked to uplift of the African margin in the Late Cretaceous which resulted in fault reactivation and re‐migration of gas. Despite the uncertainties which are associated with petroleum systems modelling, the study provides an insight into hydrocarbon migration in the northern part of the Orange Basin and contributes to the de‐risking of future oil and gas exploration in this area. [ABSTRACT FROM AUTHOR]