Hydrocarbon source-rock potential of Maastrichtian Araromi shales from a well in the eastern Dahomey basin, southwestern Nigeria: Evidence from TOC and rock-eval pyrolysis

The Dahomey Basin is hydrocarbon-bearing but less explored than the neighbouring Niger Delta. This study evaluated the organic geochemistry of 20 Maastrichtian shale samples from the Araromi Formation in a well (1128–2181 m) in southwestern Nigeria. Samples were analysed by Rock-Eval pyrolysis and TOC to assess organic richness, kerogen type, thermal maturity and hydrocarbon potential across the Lower (n = 4), Middle (n = 11) and Upper (n = 5) Maastrichtian. Mean TOC was highest in the Lower Maastrichtian (3.12 wt%), followed by the Upper (2.18 wt%) and Middle (1.39 wt%). Hydrogen index values (195.51–601.03 mg HC/g TOC) indicate mainly Type II and Type II/III kerogen, with mixed oil- and gas-prone potential. The Lower interval had the greatest generative potential (mean S1+S2 of 12.37 mg HC/g rock, versus 6.74 for the Upper and 6.33 for the Middle). Maturity indicators (Tmax 427–612°C; apparent %Ro 0.53–3.86) varied widely, with the highest means in the Lower interval. Statistical analyses (ANOVA, PCA, HCA, K-Means) showed significant vertical heterogeneity, and the Lower interval differed significantly from both younger intervals. PC1 (53.7%) reflected organic richness and PC2 (21.4%) thermal maturity. Lower Maastrichtian samples clustered together and showed better source-rock quality. The findings are relevant to petroleum-system modelling, and further study of deeper Lower Maastrichtian horizons is recommended.