Organic geochemistry and hydrocarbon generation characteristics of Cretaceous outcrop source rocks from the Nigerian Frontier basins

Abstract

The present study integrates organic petrographic and geochemical analyses to determine and compare the nature of organic matter, maceral assemblages, paleodepositional environment, and hydrocarbon generation characteristics of Cretaceous aged outcrop grayish-dark mudstones (claystones and shales), coaly-shale, and coals from some parts of Anambra, Bida and Dahomey Basins. The total organic carbon (TOC) obtained in the studied coals (14.41–53.69 wt%) and mudstones/shales (0.62 and 14.58 wt%) indicate excellent and a wide range (i.e., excellent – fair) of source rocks, respectively. Pyrolysis S2 of the coals revealed excellent source rock generative potentials, while average pyrolysis S2 of the mudstones/shales, (Anambra: 4.04, Bida: 4.43, and Dahomey: 25.86) indicate a wide range of source rock potentials from good-poor, excellent-poor and very good, respectively. The cross plots of HI vs Tmax, and HI vs OI in addition to maceral assemblages indicate types II, II/III, and III organic matter in the Anambra Basin, types II/III and III-IV in the Bida and type II/III in the Dahomey Basin. Vitrinite/huminite reflectance (Ro), in addition to Tmax, and other biomarker maturity parameters indicate immature thermal conditions before the onset of hydrocarbon generation in all the studied samples. The general low reflectance in the samples could be a result of perhydrous in the coals or due to marine influence. Further, similarities in the maceral assemblages in the studied samples suggest that the mudstones/shales were deposited in proximity to the coal beds. The macerals as identified through transmitted and reflected lights indicate that vitrinites/huminites are dominant with liptinites also having significant proportions (liptinite: Anambra: ≤40 %, Bida: ≤23 %, Dahomey: ≤37 %). The high proportions of liptinites (40-23 %) in addition to high hydrogen indices (HI) (>200 mg HC/g TOC) in the studied coals indicate that they could generate liquid hydrocarbons upon attaining appropriate thermal maturity level. Based on vitrinite reflectance values, the coals fall into lignite to sub-bituminous coal ranks. However, despite the low thermal maturity level in source rock from the Dahomey Basin, occurrence of exsudatinite in the sample indicates in-situ generation of petroleum-like substance. Resin-derived biomarkers (i.e., cadalene and retene) in the Dahomey source rock suggest that resinite macerals could be the source of the in-situ generated petroleum-like substance. The findings in the present study will help in making appropriate decisions on further hydrocarbon exploration activities in the Nigerian Frontier Basins and will serve as pointer to where hydrocarbons could be explored for in the basins.