Estimating Permeability of a Hydrocarbon Field of the Central Swamp of the Niger Delta Using Well and Seismic Data

Abstract

This research integrates well-log information with prestack seismic data to estimate permeability and delineate favourable drilling locations. The study focuses on estimating permeability in an oil field within the Central Swamp depositional belt of the Niger Delta, where CO2-EOR is currently being applied. Efficient recovery from this process requires an understanding of how permeability heterogeneity controls fluid movement within the reservoir. The objectives are to characterise reservoir permeability heterogeneity and its effect on flow and to improve flow-simulation accuracy. The reservoir succession comprises Tertiary shallow-marine deposits shaped by tidal and fluvial processes. These deposits belong to the Agbada Formation and include alternating fine-, medium-, and coarse-grained sands with shale intervals. Reservoir units were grouped into lithofacies associations to distinguish flow units. Field petrofacies were linked to permeability patterns and treated as discrete rock units with characteristic petrophysical responses. Prestack seismic analysis was integrated with well-log information to estimate geomechanical attributes including P-impedance, Vp/Vs, and elastic moduli; these attributes were then used to predict in situ principal stresses and delineate preferential drilling locations. Vertical and horizontal permeability were estimated concurrently. The 3D seismic survey used a 6 km cable, 25 × 18.75 m CMP spacing, and 80-fold coverage. Reservoir-sand porosity ranges from 18–23%, while vertical and horizontal permeability ranges from 100–480 mD, consistent with well-test results.