Oil families and their inferred source rocks from the Niger Delta Basin

Abstract

The Niger Delta Basin is one of the world’s most prolific hydrocarbon provinces, yet the origin of the vast amounts of oil and gas found in numerous sub-basins across the Delta remains contested. Two principal mixed Type II/III kerogen source rocks, from the Miocene and Eocene, respectively, are often reported to be the origins of the Tertiary reservoired oils of the Delta, although contributions from a deeper Cretaceous source have also been suggested but not proven to date. The current poor understanding of the petroleum systems of the Niger Delta is mainly as a result of non-availability of mature source rock samples and variability in fluid types (oil/gas/condensates) from the various sub-basins in the delta, even from those in close proximity to each other. A total of 50 source rock samples from 6 exploration wells across different parts of the basin were subjected to geochemical analyses, including TOC and Rock Eval screening analyses, and 180 oil samples from more than 40 oil fields in the Niger Delta were analysed for their saturated, and aromatic hydrocarbons, resins and asphaltene (SARA) contents. Gas chromatography (GC), GC-mass spectrometry (GC-MS) and GC isotope-ratio mass spectrometry (GC-IRMS) was carried out on selected samples. Unravelling the history of the potentially mixed oils from the Delta was undertaken using several geochemical approaches on the different components/molecular weight ranges of each hydrocarbon fraction. The interpreted thermal maturity and source depositional environments of those hydrocarbons show significant variations depending on the components analysed, and allows no clear correlation to a single source rock but rather implies extensive mixed contributions. These observations give rise to questions on whether the Niger Delta hydrocarbons were mainly sourced from an early/marginally mature source as indicated by hopane and sterane biomarkers, or a peak mature source as indicated by aromatic steroids, or even from the thermal cracking of either earlier generated hydrocarbons or kerogen cracking within deep seated source rocks. The studied source rock samples were of relatively low thermal maturity, with mainly Type III kerogens with some Type II influence, deposited in deltaic/marine environments. Diamondoid hydrocarbon parameters were used for the first time on these Tertiary reservoir hosted oils to investigate source, thermal maturity and mixing effects and to allow crosscorrelations of these oils. The diamondoid abundances and distributions support the hypothesis of co-sourcing of oil from a thermally cracked, sub-delta, Type II marine source which was then mixed with oils of relatively lower maturities in the Tertiary reservoirs. Statistical principal component analyses (PCA) of diamondoid correlation parameters indicate that the iii suspected highly mature, deep sourced oils are from the same genetic family and not related to the studied source rocks. Furthermore, PCA of gasoline range and aromatic hydrocarbon indicate mixed sources, with the central Niger Delta region showing more contributions from terrigenous sources, while the other regions have more marine contributions. Compound specific carbon and hydrogen stable isotope analyses of n-alkanes of molecular weight greater than nC21, show some correlation between the source rocks and the oil samples, but these correlations cannot be established in the lighter hydrocarbons. However, potential source rock cuttings samples from wells BA-1, BA-SW and EA show good correlations with the produced oil samples based on the hopane and sterane biomarker distributions, however the studied source rocks are thermally immature. Two broad oil families can be identified amongst the samples analysed in this study:  Family A comprises highly cracked oil from a Type II marine shale and based on geochemical results, this oil contributes up to about 90% of the oil accumulations in some fields.  Family B is a Type II/III marine shale sourced oil from the Akata Formation which has contributed a lower percentage to the accumulations than the Family A oils, The Central delta oils are mostly biodegraded whereas the Southern delta oils are least biodegraded and there exists an interplay of multiple charge episodes, complex reservoir architecture and several other controls, such as maturity and fill-spill episodes on the current biodegradation levels of oils in the basin. The relative abundance of an unknown C29 triterpane and a parameter based on unidentified seco-oleananes (seen in m/z 193 mass chromatograms) can be useful indicators of biodegradation level in highly biodegraded oil samples. Multiple sourcing of oil samples from the basin makes migration distance studies uncertain using the parameters measured, but it appears likely that the Western and Eastern Delta oils have migrated over relatively longer distances than the Southern Delta oils. Biomarker contamination during migration appears to be an important process in this complex geological setting and as such geochemical interpretation would potentially yield erroneous interpretations based on any such standalone routine analyses. Future geochemical interpretations should treat the Niger Delta oils as potentially mixtures of oils of variable maturities from different sources, often with the most important source biomarkers depleted because of the extent of thermal cracking.