Pore-Level Mechanisms of Surfactant-Enhanced Oil Recovery

Abstract

Abstract The technique of injecting water is used for about 50% of the world's oil production. However, recovery efficiency of water injection in fractured reservoirs can be very low because, guided by capillary forces, the injected fluid will preferentially flow in the fractures rather than through the matrix. As a result, most of the oil in the matrix is not contacted by the injected water and remains within the matrix. To access this oil, the role of capillary forces on fluid flow can be minimized by adding surfactants and surface-active agents to injected water. Surfactants dramatically change the interfacial properties by reducing the surface tension. In this study, micromodels were used in a series of experiments to compare the results of forced and spontaneous imbibition tests in the presence of aqueous surfactant solutions. These micromodels contain a repeated flow pattern that is etched onto silicon and roughly offer the pore-size distribution and pore sizes of sandstone. Two-dimensional movement of fluids is studied under a Nikon Optiphot-M reflected light microscope and 10X pictures are taken. Matlab is used to run image analysis on these pictures to interpret quantitatively the residual oil saturation, oil recovery and the porosity values. A screening study of 6 surfactants at different concentrations was run to choose the system that was most compatible with low-viscosity crude oil (~4.95cP). Solutions that were 2 % (by volume) were used in forced imbibition at 1 m/Day Darcy velocity. The same surfactant solution was also used in spontaneous imbibition Darcy velocity. Forced displacement compared to spontaneous displacement improves recovery efficiency. If most of the oil was removed in secondary injection of surfactant solution in forced displacement, only about 1% of oil was removed in secondary injection of surfactant solution in spontaneous displacement.