Applicability of Wettability Estimation Methods and Implications for Relative Permeability Characterization in Niger Delta Sandstone Reservoirs

Abstract

Wettability is a key property controlling oil-water relative permeability and capillary pressures, which in turn affect fluid distribution and displacement efficiency in reservoir rocks. In the Niger Delta, obtaining representative core samples and Special Core Analysis Laboratory (SCAL) data is challenging due to high acquisition costs and laboratory limitations, leading to reliance on analogues, databases, and algorithm-based estimates for wettability and relative permeability. These approaches can introduce inconsistencies in rock-fluid property inputs for reservoir modelling and simulation, thereby increasing uncertainty in history matching, production forecasts and field development planning. Conventional methods for determining wettability, such as Amott, Amott-Harvey and USBM are widely used. Alternative quantitative and qualitative techniques, including the Lak wettability index and normalized water fractional flow curves, have been proposed in the literature but remain largely underexplored for sandstone reservoirs. In addition, regional evaluations of wettability and relative permeability parameters in Niger Delta sandstones are limited compared to other carbonate formations, highlighting the need for localized benchmarking. This study assesses the applicability and reliability of these underutilized methods and examines their influence on relative permeability characterization in Niger Delta sandstones. Using SCAL data sets obtained from 79 core samples from multiple depositional environments subjected to established quality assurance and quality checking procedures, wettability indices were determined using both conventional and alternative techniques. Oil-water relative permeability curves were generated and fitted with Corey-type models, and the relationships between wettability classification, relative permeability endpoints, and Corey exponents were analyzed. Reservoir rock types (RRTs) and their correlation with the exponents and endpoints were also investigated. The practical applicability of the alternative wettability estimation methods for Niger Delta sands was demonstrated. The findings showed that the wettability indicators produced consistent results and revealed distinct groupings of relative permeability endpoints and exponent ranges corresponding to different wettability classes. Rock typing analysis illustrated that RRTs exert significant influence on water relative permeability in water‑wet rocks while residual oil saturation is a controlling factor in oil‑wet reservoirs. Observed sensitivities in endpoints and exponents highlight the effects of wettability alteration, laboratory distortions, and data quality on relative permeability uncertainty. Variations across depositional environments further emphasize the limitations of applying generic relative permeability models in the Niger Delta. This study provides a region-specific framework for integrating wettability interpretation with relative permeability parameterization, facilitating improved SCAL validation, more representative reservoir simulation inputs, and reduced uncertainty in reservoir engineering workflows and development strategies. The results also provide technical justification for extrapolation of SCAL insights to uncored intervals within similar depositional settings in the Niger Delta.