Two-phase flows through fractures in subsurface rocks are of great importance in several domains. Despite this importance few studies have been conducted, and the results presented in the literature seem to be contradictory. So far, two-phase fracture flows are not well understood. In our recent study, it was indicated that relative permeability curves for fractures in rocks under confining pressure may different from the X model, the viscous coupling model, and even the Corey model, due to strong interference between phases by capillarity in the 2-D flow field. However, it was difficult to make a concrete conclusion due to the limited results. In the present study, oil (n-decane)-water relative permeability curves of fractures having different intrinsic permeabilities (i.e., aperture distributions) in granite and limestone under confining pressure has been investigated. First of all, no significant difference was found between fractures in the present granite and limestone. In case of the fracture having the highest intrinsic permeability (4 × 10–10 m2), there was no significant influence of capillarity due to bigger apertures, resulting in X-type relative permeability curves. On the other hand, in case of the fractures having lower intrinsic permeabilities (1 × 10–11 m2 and 4 × 10–11 m2), there was significant influence between phases by capillarity due to smaller apertures, resulting in the Corey-type and V-type (named in the present study) relative permeability curves depending on intrinsic permeability. The V-type relative permeability curves with the strongest interference between phases were found at the smallest intrinsic permeability. It has been revealed that there are three types of relative permeability curves for subsurface fractures depending on their intrinsic permeabilities (i.e., aperture distributions).

This content is only available via PDF.
You can access this article if you purchase or spend a download.