Enhanced oil recovery from high-temperature, high-salinity naturally fractured carbonate reservoirs by surfactant flood

Water floods are often very inefficient in naturally fractured carbonate oil reservoirs because many of these reservoirs are mixed-wet or oil-wet as well as extremely heterogeneous. Naturally fractured reservoirs are challenging targets for chemical flooding because they typically have a high permeability contrast between the fractures and the matrix with a low matrix permeability. Some of the world׳s largest oil reservoirs are fractured carbonates with a high reservoir temperature and a high salinity formation brine. Some of them also have low API gravity oils, which also increases the difficulty of recovering the oil. A surfactant formulation has been developed that shows promising results for such difficult reservoirs. Ultra-low interfacial tension (IFT) and good aqueous stability were achieved with this new carboxylate surfactant in a hard brine at a high reservoir temperature of 100 °C. Both static and dynamic imbibition experiments were conducted using a fractured carbonate core. 65.9% Oil recovery was obtained in fractured coreflood compared to 33.3% oil recovery in static imbibition test. The surfactant retention was low at 0.086 mg/g of rock. The oil recovery is excellent taking into account that the temperature and salinity conditions were harsh, the core was extremely vuggy and fractured, no mobility control was used, and only a small surfactant slug was injected. The coreflood results were interpreted using a mechanistic chemical reservoir simulator. It showed that both the mechanisms of IFT reduction and wettability alteration were important for oil recovery. Neither IFT reduction nor wettability alteration alone recovered oil as high as the combined contributions from both.