Abstract
Laboratory surfactant and hot water floods have shown a great potential in increasing oil recovery for reservoirs that are naturally fractured and have low permeability mixed-wet matrix rocks. Fractured, mixed-wet formations usually have poor waterflood performance because the injected water tends to flow in the fractures and spontaneous imbibition into the matrix is not very significant. Surfactants have been used to change the wettability for increasing the oil recovery by increased imbibition of the water into the matrix rock. The mechanisms for oil recovery are combined effects of reduced interfacial tension, reduced mobility ratio, and wettability alteration. The goal of this research is to adapt an existing numerical reservoir simulator to model chemical processes that lead to wettability alteration in naturally fractured reservoirs. Surfactants have been used to change the wettability with the goal of increasing the oil recovery by increased imbibition of the water into the matrix rocks. Reservoir simulation is required to scale up the process from laboratory to field conditions and to understand and interpret reservoir data. We have adapted the chemical flooding simulator, UTCHEM, to model improved oil recovery processes that involve wettability alteration using surfactants. Multiple relative permeability and capillary pressure curves corresponding to different wetting states are used to model the wettability alteration. Simulations were performed to better understand and predict enhanced oil recovery as a function of wettability alteration and to investigate the impact of uncertainties in the fracture and matrix properties, reservoir heterogeneity, matrix diffusion, buoyancy driven flow, initial water saturation, and formation wettability.
