The Benin and Western Nigeria Offshore Basins, which are parts of an extensive basin called the Dahomey (Benin) Embayment, were formed during the Early Cretaceous under similar tectonic conditions and continental sedimentary environments. Based mainly on available lithological, biostratigraphic and paleoenvironmental data, this paper summarizes the stratigraphic succession of theses basins and attempts a comparison of these stratigraphic nomenclatures. The bulk of data shows that sedimentation begins with terrestrial at the base, passes through shallow marine, deep marine (with restrictive bottom circulation) and ends with open deep marine conditions. The stratigraphy of the Offshore Benin Basin was established later and considering lithological and paleontological similarities with formations of various southern Nigeria basins, the stratigraphic chart adopted for this basin was a mixed variant of various Southern Nigerian basins nomenclatures. For the first time, a correlation of stratigraphic charts of each basins and a schematic cross section showing their lithostratigraphic units, especially the Cretaceous-Paleocene interval which is petroliferous, are proposed. The study shows that the nomenclature adopted in Benin Republic must be revised by using type section/locality names for some particular Formations and widely accepted Formations names of Nigeria for the others. This will permit to avoid confusions as it is presently the case for the name "Afowo Formation" representing a Cretaceous sequence in Nigeria and which is use in Benin Republic to distinguish some sediments of Miocene age. Moreover, a High Resolution Biostratigraphy summary (including micropaleontology, nannopaleontology and palynology distributions) relating to each offshore basin is needed for sequences correlations and entire harmonization of the stratigraphic nomenclature of these offshore basins.

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Drilled core samples of the Araromi Formation in the eastern Dahomey basin penetrated by Araromi and Gbekebo exploratory wells were investigated to establish the source rocks potentials in the onshore area of the basin. The sediments are of Maastrichtian age deposited in the shallow marine environment with varying thicknesses. Rock-Eval data of forty seven (40) shales give Total Organic Carbon (TOC) range of 0.50–4.78 wt%, Hydrogen Index (HI) value range of 1 - 327mgHC/gTOC, T max values from 398 °C–437 °C and Source Potential (SP) values range from 0.01 - 14.56kgHC/ton of rock. The maceral compositions of the shales are liptinite (av. 26.0%), abundance vitrinite (av. 38.1%) and inertinite (av. 35.9 %) with vitrinite reflectance (VR o ) ranging from 0.51 - 0.68 %R o . Hydrocarbons and biomarkers results reveal a bimodal n-alkane envelope between (nC 16 and nC 18 ) and (nC 27 and nC 29 ) suggesting organic matter of mixed origin of algae and higher plant generally in the two well. The Significant contribution of marine algae in the deeper part of Gbekebo well was observed by the presence of C 30 24-n-propyl cholestane (%C 30 sterane range from 0.45 to as high as 5.23%). Integration of the Rock-Eval, organic petrology and biomarkers data reveal that the kerogen constituents of the source rocks in Araromi well are mainly Type II/III, III and IV with a high amount of inertinite constituents suggesting they have been reworked. Type II and II/III kerogen derived from marine algae are better preserved in the deeper part of Gbekebo well located more southerly in the basin than in the Araromi well. The source rocks are generally immature to marginally mature and hydrocarbon exploration effort should be targeted towards Gbekebo well area where we have more promising potential source rocks capable of generating more hydrocarbons essentially at a deeper depth.

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 Xwell 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 constrains 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

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