Modeling Wettability Alteration in Naturally Fractured Reservoirs

Abstract

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. Introduction About one-half of the world's oil reservoirs are carbonates and many of them are naturally fractured and mixed wet or oil wet. Typically, more than two-thirds of the original oil in place in these reservoirs remains even after many decades of primary and secondary oil recovery. The fraction of the oil recovered from naturally fractured carbonate reservoirs is typically even less than two-thirds, often much less. Waterflooding produces oil from these reservoirs through spontaneous imbibition of water from the fractures into the rock matrix and the flow of the oil out of the matrix and through the fractures to the production wells. The capillary driving force is strong and effective when the rock is water wet. Unfortunately, many naturally fractured reservoirs are mixed wet or oil-wet with low matrix rock permeability, so the driving force is weak or non existent and the oil recovery is very low. The oil recovery can be improved in such cases by using chemicals[1–8] or heat[9–15] to:decrease the interfacial tension between the oil and water,change the matrix wettability from mixed or oil wet to water wet, andincrease the viscous forces. Babadagli[7] compared the rate of capillary imbibition for both light and heavy crude oils by chemical (surfactant and polymer) and hot water in corefloods. The results showed the rate of oil recovery by water imbibition was the highest for the hot water injection. However, surfactant addition yielded greater oil recovery at a faster production rate than the brine case. Babadagli also conducted experiments to investigate the use of surfactants and hot water on heavy oil production from fractured chalk. The results indicated a higher recovery when the combination of hot water and surfactant was used for heavy oils. Austad et al.[2] conducted imbibition experiments in nearly oil-wet, low-permeable (1 to 2 md) rocks with and without surfactant present. A 1 wt% cationic dodecyltrimethyl-ammonium bromide surfactant solution was used. Their results indicated a sudden increase in oil recovery when surfactant was present. Laboratory experiments using Yates San Andreas reservoir core indicated that the injection of dilute nonionic surfactants resulted in an improved oil recovery compared to injection of brine.[5]