Hydrocarbon source rock potential of the Late Cretaceous sediments in the Asaga–Ohafia Axis, Afikpo Basin, Nigeria: Insights from facies and kerogen analyses

Hydrocarbon source rock potential of the Late Cretaceous sediments in the Asaga–Ohafia Axis, Afikpo Basin, Nigeria: Insights from facies and kerogen analyses

This study investigated the hydrocarbon source rock potential of the Late Cretaceous Mamu and Nkporo formations in the Asaga–Ohafia Axis, Afikpo Basin, southeastern Nigeria, using integrated facies analysis, organic geochemical and palynofacies data. Five lithofacies were identified: dark grey shale...

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Main Authors: Samuel Okechukwu Onyekuru, Timothy Chibuike Anyanwu, Kenneth Okechukwu Nwosu, Ifeyinwa Juliana Ofoh, Francis Begianpuye Akiang, Obinna Chigoziem Akakuru, Onyema Uchenna Achukwu–Ononye, Kalu Kalu Ibe, Godwin Okumagbe Aigbadon
Format: Article
Language:English
Published: KeAi Communications Co., Ltd. 2025-12-01
Series:Energy Geoscience
Subjects:
Depositional facies
Palynomorphs
Kerogen typing
Total organic carbon (TOC)
Hydrocarbon source
Afikpo Basin
Online Access:http://www.sciencedirect.com/science/article/pii/S266675922500068X
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Summary:This study investigated the hydrocarbon source rock potential of the Late Cretaceous Mamu and Nkporo formations in the Asaga–Ohafia Axis, Afikpo Basin, southeastern Nigeria, using integrated facies analysis, organic geochemical and palynofacies data. Five lithofacies were identified: dark grey shale, oolitic limestone, heterolithic mudstone/sandstone, laminated bioturbated sandstone, and calcareous mudstone, indicating estuarine, deltaic, and shallow marine depositional environments. Total organic carbon (TOC) contents range from 1.47 to 2.40 wt%, which reflects moderate to good organic richness. For the Mamu Formation, kerogen composition is dominated by Type II/III, composed of 30 %–50 % amorphous organic matter (AOM), 5 %–10 % liptinite, 30 %–50 % vitrinite, and 10 %–20 % inertinite. Spore coloration and Thermal Alteration Index (TAI: 3–3+) suggest thermal maturity within the oil window (Ro: 0.80 %–1.50 %). In contrast, the Nkporo Formation shows comparable kerogen composition (20 %–45 % AOM, 0–20 % liptinite, and 40 %–65 % vitrinite) but lower maturity (TAI: 2–2+; Ro: 0.45 %–0.80 %). Rock–Eval pyrolysis further supports these findings. The Mamu Formation displays higher Hydrogen Index, favorable Tmax, and Production Index values, confirming its maturity and oil and gas–prone potential. Palynological assemblages, including marine dinoflagellate cysts (Mamu Formation) and freshwater algae/fungal spores (Nkporo Formation), align with the inferred depositional settings. Thus, the Mamu Formation is the more prolific source rock, characterized by superior organic quality and thermal maturity.
ISSN:2666-7592

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