A Novel Pore-Network Model for Shale Oil-Water Two-Phase Flow Incorporating Lithofacies-Dependent Rock Mechanics

Summary Understanding the impact of geomechanical deformation on multiphase flow properties is crucial for accurate prediction of fluid transport in shale reservoirs. Due to current technical limitations, overburden two-phase displacement experiments in shale cannot be effectively conducted. Moreover, the simulated permeabilities fail to match the single-phase permeability measured by pressure pulse methods, leading to unclear trends in relative permeability curves with increasing effective stress. This study presents a novel pore-network modeling (PNM) framework that incorporates volumetric strain and throat closure into oil–water two-phase flow simulations. By adjusting the number of closed throats, the simulated absolute permeability closely matched experimental data from pressure pulse decay tests, achieving an average matching degree of 98.5%. The updated PNMs under varying effective stresses were used to simulate oil-water two-phase flow, revealing stress-induced fluid redistribution patterns. Increasing effective stress progressively reduced the radii of pore-throats in the PNMs, yet permeability reduction was predominantly controlled by the closure of throats. The final throat closure ratios for the three samples reached 79.2%, 63.2%, and 44.3%, respectively. As effective stress increased, water-phase permeability increased while oil-phase permeability decreased, primarily due to the reduction in saturated water volume resulting from throat closure. An extended Brooks–Corey empirical model was employed to establish a mathematical relationship between relative permeability and effective stress, achieving R2 values of 0.94, 0.92, and 0.83 for the three samples, respectively. Inflection points observed in the absolute and relative permeability trends indicated optimal pressure management thresholds for reservoir operations at 30 MPa, 20 MPa, and 30 MPa. These results provide insight into stress-regulated two-phase flow in shale and offer predictive capability for optimizing pressure drawdown and production strategies in low-permeability formations.