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Hydrocarbon Generation Indication from Source Rock to Reservoir Rock: Case Studies of Anambra and Abakaliki Basins South-Eastern Nigeria

Abstract

This paper sought to use information from outcrop sections to characterise the source and reservoir rocks in a basin in order to give indication(s) for hydrocarbon generation potential in a basin so as to minimize uncertainty and risk allied with exploration, field development of oil and gas, using subsurface data from well logs, well sections, seismic and core. Method of study includes detailed geological and stratigraphical studies, geochemical study, petro-graphical, and sedimentological studies of rock units from outcrop sections within two basins; Anambra Basin and Abakaliki Basin were used as case studies. Thirty-eight (38) samples of shale were collected from the Basins, a geochemical analysis (rockeval) was done on the samples to determine the total organic content (TOC) and to assess the oil generating window. The results were analyzed using Rock wares, Origin, and Surfer software to properly characterize the potential source rock(s) and reservoir rock(s) in the basins & factor(s) that can favour hydrocarbon traps. Result of the geochemical analysis of shale samples from the Anambra Basin shows TOC values ≥1wt%, Tmax≥431°C, Vitrinite reflectance values ≥0.6%, and S1+S2 values ≥2.5mg/g for Mamu Formation while shale samples from other formations within Anambra Basin fall out of these ranges. The shale unit in the Mamu Formation is the major source rock for oil generation in the Anambra Basin while others have potential for gas generation with very little oil generation. Shale samples from Abakaliki Basin shows that S1+S2 values range from <1-20mg/g, TOC values ranges from 0.31-4.55wt%, vitrinite reflectance ranges from 0.41-1.24% and Tmax ranges from 423°C-466°C. Result also shows that there is no source rock for oil generation in Abakaliki Basin; it is either gas or graphite. This observation indicates that all the source rocks within Anambra Basin have exceeded petroleum generating stage due to high geothermal heat resulting from deep depth or the shale units have not attained catagenesis stage due to S1+S2 values lesser than 2.5mg/g, TOC values ≥0.5wt% and vitrinite reflectance values ≥0.6%. This study has shown that there is more oil in Anambra Basin than previous authors claimed, and the distribution of oil and gas in the basins is controlled by two major factors; pattern of distribution of the materials of the source rock prior to subsidence & during the subsidence period and the pattern, the rate of tectonic activities in the basins.