Source rock maturity and petroleum generation in the Dahomey Basin SW Nigeria: Insights from geologic and geochemical modelling

Sedimentology, foraminifera paleoecology, geochemical and petroleum system modelling studies were performed on Cretaceous shales from onshore Orimedu-1 and offshore X (at a water depth of 914 m) wells in the Dahomey Basin, southwestern Nigeria to evaluate their maturity, hydrocarbon generation potentials, and regional significance for petroleum prospectivity. Foraminifera biofacies analysis of the studied shales suggests deposition in dominantly marine environments. The average total organic carbon content (TOC, wt%) and hydrogen index (HI, mgHC/gTOC) for Cenomanian, Turonian, and Coniacian shales in X-well are 1.3, 0.9, 1.3 and 406, 560, 214 respectively. While the Cenomanian and Turonian shales in Orimedu-1 have TOC (wt%) of 1.3 and 1.9, and HI (mgHC/gTOC) of 179 and 357 respectively. Well X source rocks contain predominantly marine-derived Type II kerogen, while Orimedu-1 well contain terrigenous-derived gas prone kerogen. The integration of recently acquired kinetic data from immature source rocks further constraints the prediction of petroleum generation in the study area.1D basin modelling of X well reveals that the Cenomanian Source Rock (CSR) is the most mature bed in the basin having attained the initial 10% transformation ratio (TR) at 87 Ma, got to peak TR (~50%) at 86 Ma, and reached 83% at 53.6 Ma With a present-day thermal maturity of 0.95% VRo. The Turonian source in well X also attained the initial 10% TR at 87 Ma, got to peak (~50% TR) at 86 Ma and 69% TR at 50 Ma. These modelled source beds are deeper than the source with 0.62 %VRo used for kinetic study. The observed maturity trend is mostly controlled by the regional erosive events associated with the West African rift system during Santonian and Eocene times. The source rocks in Orimedu-1 are immature. The timing of the generated and expelled hydrocarbons into the Cretaceous petroleum systems of Dahomey Basin is of regional significance with the entire Gulf of Guinea basins because of the similar evolution and sedimentation history along with recent discoveries and production of hydrocarbon. •Marine foraminifera biofacies suggests that the studied shales were deposited in a marine setting with varied paleowater depth.•The Cenomanian - Turonian shale in X well contain predominantly marine-derived Type II oil and gas prone kerogen.•Orimedu-1 well contains mixed and terrigenous-derived Type II/III kerogen.•1D basin modelling of X and Orimedu-1 wells reveal that the Cenomanian Source Rock