Sedimentation, depositional environments, and hydrocarbon potential of the Maastrichtian-Paleocene Araromi Formation, eastern Dahomey (Benin) Basin, southwestern Nigeria

The Cretaceous sediments in southwestern Nigeria are host to one of the largest bitumen deposits in the world. In the current paper, an integrated study on sedimentology, palynology, and applied petroleum geochemistry of the Maastrichtian-Paleocene Araromi Formation was used to determine the depositional environments and hydrocarbon potentials of the formation on the eastern Dahomey Basin. Four sedimentary lithofacies were identified from core samples, namely, lower limestone (F1); medium to coarse-grained sandstone (F2); lower loosely consolidated sandstone (F3); and shale and siltstone (F4). Sedimentation in the eastern Dahomey Basin occurred mainly in fluvial and shallow-marine (shelf) environments. The palynological assemblages of the Araromi Formation reflect deposition in coastal through brackish water to shallow shelf environment with periods of localized wind-induced storms. The shale and siltstone samples of the Araromi Formation are characterized by total organic carbon (TOC) values of up to 2.50 wt % and S2 (hydrocarbon-generating potential) values ranging from 0.26 to 0.70 mgHC/g rock, indicating poor source rocks. Shales show poor quality and thermally immature organic matter at shallow depth and could neither have generated liquid hydrocarbon nor contributed to the heavy oil occurrence on the bitumen and tar-sand belt of eastern Dahomey (Benin) Basin.

Hydrocarbon Generation Potential of the Campano-Maastrichtian Dark Mudstone Lithofacies, Benin Flank, South West Anambra Basin, Nigeria

The dark mudstone lithofacies of Mamu Formation was deposited during the Campano-Maastrichtian flooding episode. It is laterally heterogeneous, and has been subdivided into marsh, bay and central basin subenvironments in order of proximality. Arising from recommendation from a previous study, we evaluated its hydrocarbon generating potential using multidisciplinary tools involving visual kerogen analysis, as well as bulk and isotope geochemistry. Seventy-seven sample materials were taken from 3-outcrop sites at Uzebba, Okpekpe and Imiegba locations, Benin flank, SW Anambra Basin, Nigeria. The results show that bulk of the samples have good organic richness. Kerogen quality is dominantly of gas prone Type III kerogen. However, visual kerogen analysis indicates the presence of an oil prone Type II/III kerogen in the central basin subenvironments. An immature thermal maturity is inferred based on spore colour index (SCI) of less than 6 on the SCI chart (thermal alteration index of <2.5). In addition, we hypothesize that the dark mudstone lithofacies possesses biogenic gas potential based on its organic richness, kerogen quality and thermal maturity. Shale gas prospectivity is further enhanced by the low dip of the Mamu Formation, shallow burial as well as high silica content. Worth mentioning is the proximal marsh mudstone (Uzebba location) with suitable microfabric, very high silica as well as >10m of combined (continuous) outcropping and subcropping thickness Keywords: Kerogen, palynofacies, stable isotope geochemistry, shale gas,