Improved understanding of the petroleum systems of the Niger Delta Basin, Nigeria

• Published in: Organic geochemistry 2009-04, Vol.40 (4), p.461-483
• Main Authors: Samuel, OluKayode J., Cornford, Chris, Jones, Martin, Adekeye, Olabisi A., Akande, Samuel O.
• Format: Article
• Language: English
• Subjects: Brackish; Earth sciences; Earth, ocean, space; Exact sciences and technology; Geochemistry
• ISSN: 0146-6380; 1873-5290
• DOI: 10.1016/j.orggeochem.2009.01.009

Biomarker and n-alkane compound specific stable carbon isotope analyses (CSIA) were carried out on 58 crude oil samples from shallow water and deepwater fields of the Niger Delta in order to predict the depositional environment and organic matter characteristics of their potential source rocks. Using a source organofacies prediction approach from oil geochemistry, the presence in the western deepwater oils relatively abundant C 27 steranes, C 30 24- n-propyl cholestane, low oleanane index, relatively low pr/ph ratios, gammacerane, and positive to nearly flat C 12–C 30 n-alkane compound specific stable carbon isotope profiles, suggests that the source facies that expelled these oils contain significant marine derived organic matter deposited under sub-oxic and stratified water column conditions. This contrasts with the terrigenous organic matter dominated source rocks accepted for shallow water Niger Delta oils. Oils in the shallow water accumulations can be separated into terrigenous and mixed marine-terrigenous families. The terrigenous family indicates expulsion from source rock(s) containing overwhelmingly higher plant source organic matter (average oleanane index = 0.48, high C 29 steranes) as well as having negative sloping n-alkane isotope profiles. Oxic source depositional conditions (pr/ph > 2.5) and non-stratified conditions (absence to low gammacerane content) are inferred for the terrigenous family. The mixed marine-terrigenous family has biomarker properties that are a combination of the deepwater and terrigenous shallow water oils. Bitumen extracts of the sub-delta Late Cretaceous Araromi Formation shale in the Dahomey Basin are comparable both molecularly and isotopically to the studied western deepwater oil set, but with an over all poor geochemical correlation. This poor geochemical match between Araromi shale and the western deepwater oils does not downgrade the potential of sub-delta Cretaceous source rock contribution to the regional oil charge in the deepwater Niger Delta.