Theoretical and Computational Investigation of Interfacial Phenomena Controlling Gas-Condensate Relative Permeability in Ultra-Low-Permeability Reservoir Systems in Northern Nigeria

Gas-condensate relative permeability in ultra-low-permeability reservoir systems is governed by interfacial forces at the nanopore scale that produce strong coupling between capillary pressure, spreading coefficients, and condensate film flow mechanisms fundamentally different from those operative in conventional permeability systems. A theoretical treatment of these interfacial phenomena and their influence on effective gas-condensate relative permeability in northern Nigerian tight gas reservoir contexts is absent from the literature. This study develops a theoretical and computational investigation of interfacial phenomena controlling gas-condensate relative permeability in ultra-low-permeability reservoir systems applicable to the Songhai Formation and Gongola Basin tight gas plays. The theoretical development integrates molecular simulation methods with pore network modelling in a multi-scale framework. Grand Canonical Monte Carlo simulations are applied to compute phase equilibria and fluid density profiles in model slit nanopores spanning 2 to 50 nanometres representative of the dominant pore size distribution of target formations characterised from mercury injection capillary pressure analysis. An original critical condensate saturation reduction function is derived from the nano-confinement phase behaviour calculations, expressing the anomalous enhancement of condensate mobility at low saturation attributable to precursor film flow along pore walls. These molecular insights are incorporated into a pore network relative permeability model and upscaled to Darcy flow parameters for reservoir simulation use. Keywords: gas-condensate relative permeability, interfacial phenomena, nanopore, ultra-low permeability, northern Nigeria tight gas.