Oilfield Surfactants Improve Recovery by Imbibition

Abstract Most carbonate reservoirs are naturally fractured and typically produce less than 10% OOIP during primary recovery. Spontaneous imbibition is an important oil recovery mechanism from these types of reservoirs. In some situations, imbibition of water can be promoted by chemical stimulation with surfactants to alter the reservoir wettability toward water-wetness such that oil is expelled at an economic rate from the rock matrix into fractures. Here, we investigated the use of chemicals to modify the wettability of reservoir rock to a more water-wet state in order to produce additional oil via imbibition. Five chemicals that effectively improved water-wetness were used in the imbibition tests: two nonionic surfactants Tomadol T91-8 and Pluronic L-64, two anionic surfactants Rhodacal A-246L and Rhodapex CD 128, and an amphoteric surfactant Mirataine CB. The San Andres formation in the Permian Basin of Texas and New Mexico is a great oil-producing formation in the United States. An estimated 50,000 wells produce oil from this oil-wet carbonate reservoir. Laboratory imbibition tests were conducted on core plugs and fluids from the Fuhrman Masho and Eagle Creek fields. Thin section analysis indicated that both fields contain dolomite, calcite, and anhydrite. The core plugs were soaked in imbibition cells containing formation water at a reservoir temperature of 40°C (104°F). For Fuhrman Masho cores, maximum oil recovery via water alone was less than 4% of the original oil in place (OOIP). After the oil production stopped, the water was replaced with a surfactant solution at a concentration of 1500 to 3500 ppm. The imbibition process then continued until no oil was produced. The incremental oil recovered varied from 0 to 48% OOIP; higher permeability and bulk volume of oil in the cores resulted in higher oil recovery by surfactant imbibition. No oil was produced by brine imbibition for some Eagle Creek cores; however, others produced up to 34% of the OOIP. Surfactant treatment did not improve oil recovery every core. The laboratory tests indicated that the improved oil recovery by surfactant treatment depended on rock mineralogy, porosity, permeability, and pore heterogeneity. Each field must be individually evaluated.