Depositional environment and reservoir characterization of the deep offshore Upper Miocene to Early Pliocene Agbada Formation, Niger delta, Nigeria

Recently, continued global demand for energy has necessitated more research for a better understanding of depositional environments and petrophysical parameters of reservoir sands in order to discover more petroleum accumulation. Therefore, the integration of lithological and well log data analyses of ditch-cutting samples from Wells A, B and C from the Niger Delta region are utilized to delineate the Upper Miocene and Early Pliocene Agbada Formation's depositional environments and to determine the quality of the delineated reservoir sands. The detailed well log analysis revealed two major electrofacies namely, shale and sand, while lithofacies analysis identified four facies, which are sandstone, siltstone, claystone and mudstone that were deposited in various depositional environments and sequences. Shale (claystone and mudstone) lithology is characterized by irregular and bell gamma-ray log motifs, which may be deposited in basin plain marine and transgressive marine shelf environments that are associated with transgressive depositional sequences. In contrast, sand (sandstone and siltstone) lithology is typified by funnel and cylindrical gamma-ray log motifs that are deposited in crevasse/prograding delta (sub-unit of fluvial/deltaic environment), and slope/inner fan channel and turbidite environments that are correlated to regressive and aggradation depositional sequences, respectively. Furthermore, sedimentology analysis evidenced twelve, four and seven reservoir sands in wells A, B and C, respectively, while qualitative analysis of well logs reveals eighteen (notated as A to R), four (A to D) and fifteen (A to P) reservoir sands in wells A, B and C, respectively. Moreover, palynological analysis shows alternation of transgressive and regressive sequences in wells A, B and C in this study. The prevalence of mangroves, spores, freshwater swamp and lowland rainforest pollen with rare occurrence of savanna pollen characterized the transgressive sequences, while low percentages of these assemblages with high occurrence of savanna pollen signified the regressive sequences in this study. Alternatively, quantitative analysis showed that volumes of shale (Vsh) are generally low and allow distinction of delineated reservoir sands into clean sand zones (<10% Vsh) and shaley sand zones (10–28% Vsh). Furthermore, water saturation (Sw) ranges from 13.0% to 63.0%, 5% to 27% and 37%–71% (wells A, B and C), and hydrocarbon saturation (Sh) ranges from 37.0% to 87.0%, 64%–95% and 29–63% in wells A, B and C, respectively. Estimated porosity values are relatively high and a porosity cutoff value of <30% permits to distinguish between reservoir and non-reservoir rocks. Furthermore, hydrocarbon saturation (37–87%) and permeability (10–50%) are relatively moderate to high and fair to moderate values, respectively. However, a strong linear relationship exists between permeability and porosity with positive coefficients of correlation that are ranging from near perfect to very significant in this study, and is an indication of permeable and porous sand facies. In conclusion, the economic importance of some of the delineated depositional environments and the outcome of reservoir characterization in this study has been previously highlighted in the Niger Delta Basin and other basins of the world. Therefore, the reconstruction of depositional environments and resulting petrophysical parameters in this study will help in understanding the geology of Agbada Formation, which will further enhance hydrocarbon exploration and exploitation in the Niger Delta region.