The cost of drilling exploration and production wells is high and the price of crude oil in the capital market is fluctuating, therefore, there is the need to mitigate the risk of improper investigation of time/age-dependent reservoir rocks continuity within a field. Sequence stratigraphic analysis was carried out in OSP field with the aim of identifying and correlating hydrocarbon reservoirs that are deposited contemporaneously. Key stratigraphic surfaces (maximum flooding surfaces and sequence boundaries) were interpreted from biostratigraphic, well log and seismic data. Biostratigraphic interpretation subdivide the study area into three floral subzones-P780, P820 and P830. Three maximum flooding surfaces dated 10.4 Ma, 9.5 Ma and 7.4 Ma and four sequence boundaries dated 10.6 Ma, 10.35 Ma, 8.5 Ma and 6.7 Ma were identified. Three depositional sequences (sequences 1-3) were identified from the integration of the biostratigraphic, well log and seismic data. The identified key stratigraphic surfaces and depositional sequences were employed in the delineation and correlation of the hydrocarbon reservoirs which were found to fall within the highstand and lowstand systems tracts. Sequence stratigraphic correlation technique aided the local arrangement and geometries of reservoirs within the field and in locating potential reservoirs.
Selected shale samples within the middle Miocene Agbada Formation of Ege-1 and Ege-2 wells, Niger Delta Basin, Nigeria, were evaluated using total organic carbon content (TOC) and Rock–Eval pyrolysis examination with the aim of determining their hydrocarbon potential. The results obtained reveal TOC values varying from 1.64 to 2.77 wt% with an average value of 2.29 wt% for Ege-1 well, while Ege-2 well TOC values ranged from 1.27 to 3.28 wt% (average of 2.27 wt%) values which both fall above the minimum threshold (0.5%) for hydrocarbon generation potential in the Niger Delta. Rock–Eval pyrolysis data revealed that the shale source rock samples from Ege-1 well are characterized by Type II–Type III kerogens which are thermally mature to generate oil or gas/oil. The Ege-2 well pyrolysis result showed that some of the ditch cutting samples are comprised of Type II (oil prone) and Type III (gas-prone kerogen) which are thermally immature to marginal maturity (Tmax 346–439 °C). This study concludes that the shale intercalations between reservoir sands of the Agbada Formation are good source rocks in early maturity and also must have contributed to the vast petroleum reserve in the Niger Delta Basin because of the subsidence of the basin.
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