Scaling of Cocurrent and Countercurrent Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs

Abstract

Summary This study tests the existing capillary imbibition scaling formulations in literature and proposes modifications to them for surfactant- and polymer-injection applications. Laboratory tests were performed using Berea Sandstone cores with different shapes, sizes, and boundary conditions. Kerosene, engine oil, mineral oil, and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were the aqueous phases. The capillary imbibition recovery curves were then used to test the existing scaling formulations. It was observed that the scaling groups were applicable with certain modifications to the cocurrent flow of surfactant and polymer solution-oil pairs as well as the brine-oil cases. In case of cocurrent flow, the gravity forces dominate recovery for low-interfacial tension (IFT) experiments, and modification to the gravity-scaling group for the boundary conditions is required. For countercurrent flow, however, the scaling groups were observed to be inapplicable even after the modifications.