An integrated study on the reservoir potential of upper Cretaceous succession of the Anambra Basin (Nigeria) using the seismic-structural, petrophysical, and sedimentological approach

Abstract

The Anambra Basin has a relatively high hydrocarbon production base compared with other Cretaceous basins in Nigeria. Structural deformation, overpressures, and faulting in the Cretaceous sequence of the Anambra Basin have resulted in significant uncertainties regarding reservoir parameters, necessitating accurate reservoir characterization. This study uses several subsurface data, including 2D seismic data, a report of core descriptions, and well log data from an exploration well drilled in the Anambra Basin to identify reservoirs and assess the petrophysical parameters of Cretaceous Formations for hydrocarbon accumulations. Three reservoirs were identified in the interpreted seismic section of the Cretaceous strata, and the structural framework was described as a system of synthetic faults dipping north-south that controlled the thickness and lateral extension of the deposited sediments. The shale volume, total and effective porosity, permeability, water, and hydrocarbon saturation were estimated using standard equations. The low shale volume, good-to-very good porosity values, fair-to-moderate permeability values, and low-to-moderate hydrocarbon saturation of the identified Cretaceous reservoirs suggest that the reservoir sands have the capacity to produce hydrocarbons. The density-neutron cross-plots of the identified reservoirs show a dual mineral system and also indicate the effect of gas in the Cretaceous reservoirs. This study found that the Anambra Basin has gas potential. However, the identified gas reservoirs should be further evaluated using reservoir pressure data, if available, to aid in accurate hydrocarbon fluid typing. The reservoirs should be developed and optimized in such a way as to keep production risk to its minimum.