New Insights Into the Geochemical Characteristics of Petroleum Source Rocks and Oils From Southern Nigerian Sedimentary Basins

The Anambra and the Niger Delta Basins are well-known hydrocarbon-producing sedimentary basins in Southern Nigeria. In the present research, bulk geochemical analysis, which includes total organic carbon (TOC) and rock pyrolysis, molecular markers, and bulk and compound-specific carbon isotopes (CSIAs), in addition to organic petrological analysis was carried out on source rocks of Cretaceous age from the Anambra Basin and oils (both Anambra and Niger Delta Basins) in order to provide information on why there was a sudden seizure in liquid hydrocarbon production in the ANAR oilfield of the Anambra Basin and also to shed more light on the unending debate on the source of Cretaceous Niger Delta oils. From the results, bulk geochemical data and maceral abundances revealed that Nkporo shales from well-x and outcrop Mamu shales are dominantly of Types II and III organic matters and are capable of producing oil and gas upon attaining appropriate thermal maturity, whereas outcrop Mamu coals are of Types II and II/III organic matter, with good potential for oil generation but with minor gas, especially in the deeper section of the basin. Organic matter richness as deduced from TOC revealed that the Mamu coals are the richest (average TOC: 50.74 wt%), whereas Mamu shales are richer (average TOC: 2.89 wt%) than Nkporo shales (average TOC: 1.66 wt%). The hydrocarbon generative potentials of the analyzed source rocks as obtained through the hydrogen index are highest in the Mamu coals (average: 329.25 mg HC/g TOC), and are followed by Mamu shales (average: 130.89 mg HC/g TOC), whereas the least was obtained in Nkporo shales (average: 69.73 mg HC/g TOC). The maximum temperature (T_max) and the vitrinite/huminite reflectance values of the source rocks are 396–443°C, 417–430°C, and 417–421°C, and 0.38%–1.51%, 0.23%–0.42%, and 0.22%–0.46% in Nkporo shales, Mamu shales, and coals, respectively. The values revealed that Nkporo shales are in immature to early–late hydrocarbon generation stages, whereas Mamu shales and coals are dominantly thermally immature. Further, the analyzed source rocks were deposited under sub-oxic-to-oxic conditions based on molecular indices and petrographic evidence. In the Nkporo shales, there was dominant input from lacustrine organic matter, as evident from the high abundance of C₂₈R sterane, higher C₂₁TT, and n-alkane maxima at n-C₂₀ and n-C₂₃. In contrast, the Mamu shales and coals and crude oil from the Anambra Basin received major input from terrigenous organic matter (high C₂₉ R sterane, C₂₉/C₂₇ ratios, wax index, terrigenous/aquatic ratio (TAR), C₁₉ + ₂₀TT, and n-alkane maxima at n-C₂₇–n-C₂₉). The oils (crude oils and condensates) from the Niger Delta are dominated by C₂₉ R steranes, whereas C₂₇ and C₂₈ R steranes are in different proportions. Oil-source correlation parameters also revealed that crude oil produced in the Anambra Basin was generated by Nkporo shales from well-x and the thermally mature equivalents of Mamu shales and coals. In addition, the Mamu shales and coals are compositionally and genetically similar to oils from the onshore and offshore Niger Delta. On the basis of the oil-source correlation parameters, in addition to the presence of other elements of the petroleum system, the Upper Cretaceous (Mamu–Nkporo/Ajali) petroleum system (!) is proposed in the Anambra Basin. The present research concludes that the absence of abundant liptinitic oil–producing macerals and Type III nature of organic matter in Nkporo shales from the ANAR oil field of the Anambra Basin led to a sudden seizure in liquid hydrocarbon production. Again, there are deeply seated Cretaceous source beds within the Niger Delta Basin that are contributing to the Cretaceous oils. This research has significant implications for future oil and gas explorations in the Southern Nigeria sedimentary basins and will contribute to the existing knowledge in the West and Central African Rift Systems (WCARS) basins and the Gulf of Guinea.