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 (R_o: 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+; R_o: 0.45%–0.80%). Rock–Eval pyrolysis further supports these findings. The Mamu Formation displays higher Hydrogen Index, favorable T_max, 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.

Gas chromatography-mass spectrometry (GC-MS) was used to analyze the pentacyclic triterpenoid distributions, specifically hopane and oleanane fingerprints, in 24 crude oil samples from the Niger Delta depobelts, with the aim of defining the petroleum system, filling history, and the age of source rock producing these oils. The results indicate that the Niger Delta oils belong to a single fluvio-deltaic petroleum system, reflecting similar source organic facies and depositional environments. Geochemical parameters, including C₂₉/C₃₀ hopane ratios, oleanane index, Ts/Tm, (Ts/(Ts + Tm)), moretane/C₃₀ hopane ratios, and C₃₂ 22S/(22S + 22R) ratios, suggest oxic conditions during source rock deposition and thermal maturity of the oils. The presence of terrigenous organic matter and complex filling history are also evident and influenced by multiple phases of sedimentation, and petroleum generation. A comparative plot of geologic time (Paleogene-Neogene age) and oleanane percentage composition show that the crude oils are constrained to the chronostratigraphic ages of their respective depobelts, demonstrating the potential of oleanane-derived parameters for relative dating of hydrocarbon sources, complementing traditional index fossil methods.