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Article Navigation >  Green Energy&Environment  > 2020  >  5(1): 83-96
Gbenga O. Ogungbesan, Taofik A. Adedosu. Geochemical record for the depositional condition and petroleum potential of the Late Cretaceous Mamu Formation in the western flank of Anambra Basin, Nigeria. Green Energy&Environment, 2020, 5(1): 83-96. doi: 10.1016/j.gee.2019.01.008
Citation: Gbenga O. Ogungbesan, Taofik A. Adedosu. Geochemical record for the depositional condition and petroleum potential of the Late Cretaceous Mamu Formation in the western flank of Anambra Basin, Nigeria. Green Energy&Environment, 2020, 5(1): 83-96. doi: 10.1016/j.gee.2019.01.008
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Geochemical record for the depositional condition and petroleum potential of the Late Cretaceous Mamu Formation in the western flank of Anambra Basin, Nigeria

doi: 10.1016/j.gee.2019.01.008
  • a.

    Department of Earth Sciences, Ladoke Akintola University of Technology, P.M.B. 4000, Ogbomoso, Nigeria

  • b.

    Department of Chemistry, Ladoke Akintola University of Technology, P.M.B. 4000, Ogbomoso, Nigeria

More Information
  • Corresponding author: E-mail address: googungbesan@lautech.edu.ng (Gbenga O. Ogungbesan)
  • Received date 27 August 2018, Accepted date 24 January 2019, RevRecd date 16 December 2018, Available online 30 January 2019, Publish date 31 January 2020,
    Abstract
  • Carbonaceous shale exposures of the Late Cretaceous Mamu Formation along Ifon-Uzebba road in western arm (Benin Flank) of Anambra Basin, southwestern Nigeria, were analyzed for bulk organic geochemical, molecular biological and poly-aromatic hydrocarbon (PAH) compositions to investigate the organic matter source, paleo-depositional condition, thermal maturity and petroleum potential of the unit. The bulk organic geochemistry was determined using Leco and Rock–Eval pyrolysis analyses while the biomarkers and PAH compositions were investigated using gas chromatography-mass spectrometer (GC–MS). The bulk organic geochemical parameters of the shale samples showed total organic carbon (TOC) (1.11–6.03 wt%), S2 (0.49–11.73 mg HC/g Rock), HI (38–242 mg HC/g TOC) and Tmax (425–435 °C) indicating good to excellent hydrocarbon source-rock. Typical HI-Tmax diagram revealed the shale samples mostly in the gas-prone Type III kerogen region with few gas and oil-prone Type II-III kerogen. The investigated biomarkers (n-alkane, isoprenoid, terpane, hopane, sterane) and PAH (alkylnaphthalene, methylphenanthrene and dibenzothiophene) indicated that the carbonaceous shales contain mix contributions of terrestrial and marine organic matter inputs that were deposited in a deltaic to shallow marine settings and preserved under relatively anoxic to suboxic conditions. Thermal maturity parameters computed from Rock–Eval pyrolysis, biomarkers (hopane, sterane) and PAH (alkylnaphthalene, alkylphenanthrene, alkyldibenzothiophene) suggested that these carbonaceous shales in Anambra Basin have entered an early-mature stage for hydrocarbon generation. This is also supported by fluoranthene/pyrene (0.27–1.12), fluoranthene/(fluoranthene + pyrene) (0.21–0.53) ratios and calculated vitrinite reflectance values (0.49–0.63% Ro) indicative that these shales have mostly reached early oil window maturity, thereby having low hydrocarbon source potential.

     

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