Surface Wetting Characterization in Pore-scale Multiphase Flow Simulations: A Ketton Carbonate Case Study

Direct numerical simulations are commonly applied to X-ray computed microtomography images of porous rocks to measure petrophysical properties, such as relative permeability. To complement and/or expand laboratory data with useful simulations, such simulations need to reflect the true wetting condition of reservoir rock. It is therefore important to investigate approaches for assigning surface wetting conditions in pore-scale multiphase flow simulations. Two-phase Lattice-Boltzmann simulations are conducted on a Ketton carbonate image using different effective wetting models and then compared to pore-scale experimental data on the same rock, which is published elsewhere in (Scanziani et al., 2018). Two different wetting models are established based on the aging of the Ketton sample with crude oil at connate water saturation. Model 1 provides uniform wetting on all oil treated surfaces. Model 2 attempts to capture the multiscale nature of carbonate by allowing for spatially varying wetting conditions on oil treated surfaces based on local microporosity. Assessment criteria are based on pore-scale morphological measures, which include oil surface area coverage, oil phase topology, fluid/fluid curvatures, and contact angles. Overall, Model 1 with an assigned contact angle of greater than +10° above the geometrically measured contact angle from the experimental data provided the best results based on our assessment criteria.