Integrated petrographical and petrophysical evaluation for reservoir management of the Upper Miocene Qawasim sandstones in West Dikirnis, onshore Nile Delta, Egypt

Abstract

The Upper Miocene Qawasim Formation is an important hydrocarbon reservoir of the West Dikirnis field, onshore Nile Delta. Here we present a detailed assessment of the Qawasim reservoir by integrating petrographical thin sections, SEM, XRD, wireline logs, and routine core analysis. Eight different lithofacies have been distinguished from cores, which are grouped as four facies associations: massive sandstone (FA-1), massive, gravelly and pebbly sandstone (FA-2), silty laminated sandstone (FA-3) and mudstone (FA-4). FA-4 occurs at the top and bottom of the reservoir interval. The reservoir consists dominantly of massive subfeldspathic arenites (FA-1, FA-2 and FA-3) and exhibits fine to coarse-grained, poorly to moderately sorted and subangular to subrounded texture. The reservoir has high intergranular porosity with good pore connectivity. The feldspar grains are partly leached or near completely dissolved indicating dissolution as a reservoir quality enhancing diagenetic agent. Calcite cementation, authigenic kaolinite precipitation, and minor quartz overgrowth are observed as the porosity destroying processes. Cementation has severe local effects on the reservoir quality of FA-3. The reservoir is dominated by megaporosities (mostly isotropic pore system), exhibits 20–33% porosity,>100 mD horizontal permeability, and a wide range of permeability anisotropy (0.60–24.74). Six hydraulic flow units are identified. Based on the RQI, FZI, and RPI metrics, these flow units are ranked in terms of reservoir quality and vertical permeability baffles are identified. The massive sandstones in the Middle Qawasim flow units are inferred to have superior reservoir quality contributing to 35% of the cumulative storage capacity and ∼75% of the cumulative flow capacity. We employed rock physics models to infer the effects of diagenesis on reservoir petrophysical characteristics. Sediments of constant shale content fall within the constant and contact-cement models and we infer that the velocity-porosity variation in the studied reservoir formation is mainly due to the pore-filling material and less due to the fluid effects. Based on our analyses, we drew inferences on drilling, completion, and optimum reservoir management strategies.