During the last decades, advances in rock physics diagnostics have established them as a powerful tool for reservoir characterization. This study applies rock physics diagnostics, alongside petrophysical evaluation to the Aptian-Cenomanian Bentiu Sandstone in the Great Bamboo area of the Muglad Basin, Sudan-one of the country’s most prolific hydrocarbon-bearing reservoirs. Well log data from four wells (gamma-ray, sonic, density, neutron, photoelectric factor, and resistivity logs) calibrated with core porosity, were analyzed to evaluate reservoir quality and hydrocarbon potential. The Bentiu reservoir shows good quality with porosity ranging from 0.21 to 0.27, permeability from 169 to 1230 mD, low shale volume (0.17–0.35) and variable water saturation (0.25–0.75). Sensitivity analysis defined cutoff values of Sw = 0.72, ϕ = 0.08, and Vsh = 0.48, resulting in net-pay thickness of 13.48 and 52.43 m across seven productive zones. Integrating the rock physics diagnostics (sonic velocities and acoustic impedance) with the petrophysical parameters enabled differentiation between sand and shale intervals, as well as oil and water-bearing zones. Therefore, the main goal of this paper is to use both petrophysical methods and rock physics diagnostics in an integrated workflow to differentiate between the shale and sand zones and the oil and water-saturated zones. It is applicable to other analogues in northeast Africa and the Middle East, where the Aptian-Cenomanian sandstones spread with promising hydrocarbon potential.
Altaib et al. (Wed,) studied this question.