Effect of Capillary Pressure, Salinity, and Aging on Wettability Alteration in Sandstones and Limestones

Abstract

Abstract Oil recovery in petroleum reservoirs is greatly affected by fluid -rock and fluid-fluid interactions. These surface chemical interactions directly control rock wettability, capillary pressure curves and relative permeabilities. Centrifuge coreflow tests (Berea sandstone and Texas Cream limestone) were performed with a range of fluids under different conditions to identify the factors influencing the residual wetting and non-wetting phase saturations and oil recovery. Results of the tests conducted with Prudhoe Bay and Moutray crude oil show that remaining water (Swr) and residual oil saturation vary systematically with Bond number for both sandstone and limestone samples. Differences in the shape of the wetting phase capillary desaturation curves are observed during primary and secondary drainage. This suggests that the distribution of fluids in the rock during secondary drainage is different from primary drainage due to a change in wettability of the core from a water-wet state to mixed-wet state. These trends were not observed with decane. Both limestone and sandstone cores become more susceptible to wettability alteration as the salinity is increased. The wettability index(Aw-Ao, water Amott-oil Amott) decreases from 0.56 (0.3% brine) to 0.2 (20%brine) in a limestone core with Prudhoe Bay crude oil. Aging the samples for 20-30 days with Moutray crude oil shows results in a change in the wettability of the cores. The oil recovery increases by 10-15% to more than 95% in both Berea and limestone cores. These results show that with time the crude oil changes the wettability of the core from strongly water wet to mixed wet, which leads to a higher oil recovery. Experiments with samples of sandstone and limestone aged with Prudhoe Bay crude oil and brine of different salinities also show similar trends.