How Fracture Capillary Pressure Affects Ensemble Relative Permeability of Naturally Fractured Reservoirs

This work presents a significant advance over earlier methods because it employs a surface-roughness based fracture dilation model to compute aperture distributions. From these, fracture capillary pressure is computed before saturation functions are extracted. This upscaling is performed using an unsteady state approach to evaluate the impact of fracture capillary pressure on ensemble relative permeability and ultimate recovery. The simulation approach is applied to outcrop-based meter- and kilometre-scale DFM models. For these fracture geometries, aperture attributes are computed for plausible regimes of in situ stress. Corresponding capillary pressure values are assigned to individual fractures. The capillary pressure of the rock matrix is parameterized with representative data for siliciclastics and carbonates. The two-phase flow simulations are performed with the Finite Element-Centered Finite Volume Method (FECFVM). Flow-based upscaling establishes ensemble relative permeability between capillary and viscous limits. Based on results, for a water-wet rock matrix, there is more fracture-matrix transfer and oil recovery is higher. Counter-current-imbibition flux is diminished gradually since the small fractures that dominate the fracture-matrix interface area have drastically smaller fracture-matrix pressure differentials. These differences become more pronounced near the capillary limit. As the wettability tends to the oil, two phase flow occurs within a narrower range of saturation.