Pore-scale insights into relative permeability in strongly and weakly wet natural fractures: A Lattice Boltzmann Method 2D simulation study

The simplified view of two-phase flow, such as oil and gas, in a fracture is often assumed to occur in a stratified behavior. However, recent studies and production practices have revealed that two-phase flow in fractures exhibits diverse flow patterns. This paper investigates the control of the fracture aperture, fluids viscosity, and wettability on two-phase flow in a 2D cross section of a 3D Berea fracture. Lattice Boltzmann Method (LBM) simulations are used to model the impact of these properties on relative permeability curves. Notably, in strongly wet fractures, two distinct permeability regimes emerge. High aperture values exhibit behavior resembling parallel planes, while low aperture values lead to a linear decrease in permeability due to fluid interactions between fracture surfaces. Conversely, anomalous behavior of the relative permeability curves is identified in weakly wet fractures within specific aperture ranges. This behavior is associated with the occurrence of specific flow patterns within the fracture. Results also emphasize that changes in viscosity ratio do not affect the presence or the saturation range of the anomalous behavior but do influence its intensity for each fluid. Comparisons with Poiseuille profile equations reveal the limited impact of the fracture roughness. These findings enhance our understanding of the interactions between aperture, viscosity, and wettability and how they control the shape of the relative permeability curves. These curves are pivotal parameters for the continuum scale modeling (reservoir models) in oil and gas application, for instance.