Petrophysical Evaluation of Reservoir Sand Units in “Hum” Field Onshore Niger Delta Basin using Well log Data

Abstract

This study presents an integrated petrophysical evaluation of the Hum Field located 
in the Niger Delta Basin, with the primary objective of delineating potential 
hydrocarbon-bearing zones and assessing the reservoir quality of key sand units. The 
analysis was based on the interpretation of composite well log suites from multiple 
wells across the field. Three prominent reservoir intervals—designated A200, B400, 
and C600 sands—were identified and evaluated using a combination of qualitative and 
quantitative techniques. Gamma ray log motifs were employed to infer lithofacies 
characteristics and reconstruct the gross depositional environments of the 
identified sand bodies. The log patterns suggested deposition within high-energy 
clastic environments, specifically beach, channel, and shoreface settings, which 
significantly influence reservoir quality. Petrophysical parameters including volume 
of shale (Vsh), net-to-gross ratio (NTG), effective porosity (Øe), and water 
saturation (Sw) were computed using industry-standard empirical models to evaluate 
the reservoir units. The results indicate that the A200, B400, and C600 sands 
exhibit favorable reservoir properties, with average effective porosity values of 
0.20, 0.30, and 0.25; net-to-gross ratios of 0.74, 0.83, and 0.84; and shale volumes 
of 0.26, 0.17, and 0.16, respectively. These values reflect well-developed, clean sand 
reservoirs with minimal shale interference, suggesting high storage capacity and good 
reservoir continuity. The computed water saturation values further confirmed the 
presence of hydrocarbons, with testing results indicating that the A200 and C600 
sands are oil-bearing, while the B400 sand contains gas. Permeability estimates 
derived from porosity-permeability correlations suggest that the reservoirs possess 
fair to good pore connectivity, enhancing fluid flow and supporting potential for 
commercial production. The variation in reservoir quality across the intervals is 
attributed to differences in depositional environment and diagenetic history.