Imaging and Modeling the Impact of Multi‐Scale Pore Connectivity on Two‐Phase Flow in Mixed‐Wet Rock

Abstract The wetting properties of pore walls have a strong effect on multiphase flow through porous media. However, the fluid flow behavior in porous materials with both complex pore structures and non‐uniform wettability are still unclear. Here, we performed unsteady‐state quasi‐static oil‐ and water‐flooding experiments to study multiphase flow in two sister heterogeneous sandstones with variable wettability conditions (i.e., one natively water‐wet and one chemically treated to be mixed‐wet). The pore‐scale fluid distributions during this process were imaged by laboratory‐based X‐ray micro‐computed tomography (micro‐CT). In the mixed‐wet case, we observed pore filling events where the fluid interface appeared to be at quasi‐equilibrium at every position along the pore body (13% by volume), in contrast to capillary instabilities typically associated with slow drainage or imbibition. These events corresponded to slow displacements previously observed in unsteady‐state experiments, explaining the wide range of displacement time scales in mixed‐wet samples. Our new data allowed us to quantify the fluid saturations below the image resolution, indicating that slow events were caused by the presence of microporosity and the wetting heterogeneity. Finally, we investigated the sensitivity of the multi‐phase flow properties to the slow filling events using a state‐of‐the‐art multi‐scale pore network model. This indicated that pores where such events took place contributed up to 19% of the sample's total absolute permeability, but that the impact on the relative permeability may be smaller. Our study sheds new light on poorly understood multiphase fluid dynamics in complex rocks, of interest to for example, groundwater remediation and subsurface CO 2 storage.