Accurate estimation of rock permeability is a major challenge in industrial projects such as oil and gas extraction, geothermal energy production, radioactive waste containment, and CO 2 geosequestration. For many of these projects, the targeted formation exhibits low matrix permeability and the main fluid conduit is the fracture network (Berkowitz, 2002; Neuman, 2005; Sahimi, 2011). To accurately evaluate the hydraulic properties of such geoformations, understanding the behavior of a single rock fracture under in situ conditions is necessary. The permeability of fluids through a single rock fracture is often estimated using the Cubic law-a simplification of the Navier-Stokes (NS) equations based on several key assumptions. These include assuming that the fracture consists of two smooth and parallel plates (Witherspoon et al., 1980). Therefore, the geometry of the flow path can be represented by a single value, the uniform spacing between the two walls. However, no rock fracture is perfectly smooth and, as a result, its aperture field is heterogeneous. A natural way to reduce the heterogeneous aperture field to a single value is to average the fracture aperture distribution. Various averaging methods have been proposed in the literature (