The Potential of Sulfate as Optimizer of Crude Oil-Water Interfacial Rheology to Increase Oil Recovery During Smart Water Injection in Carbonates

Abstract

Abstract Recovery from oil reservoirs could be improved by lowering the injection water salinity or by modifying the water injection chemistry. This has been proposed as a way to increase rock water-wetness. However, we have observed that the presence of sulfate anions in the aqueous phase can change the crude oil-water interfacial rheology drastically, and as a result, the oil recovery factor could be increased solely by alteration of fluid-fluid interactions. The purpose of this research is to show the effect of sulfate anion concentration in seawater injection on oil production through coreflooding results at low temperature. Interfacial rheological experiments were run with several crude oils and modified seawater to see the effect of different ions on visco-elasticity of the crude oil-brine interface using an AR-G2 rheometer with a dual-wall ring fixture. Based on previous experimental results, carefully selected coreflooding experiments were run to evaluate differential pressure and oil recovery for each selected brine. Coreflooding experiments used Indiana Limestone at 25°C without aging to minimize changes in rock wettability. The interfacial rheological results show that the visco-elasticity of the crude oil-brine interface is higher for a low-salinity brine compared to a higher-salinity one when individual salts are used, e.g. NaCl or Na2SO4. The difference is more pronounced if ultralow salinities are compared. For the cases with salinity values similar to that of seawater, the effect of sulfate concentration in water on interfacial visco-elasticity is more noticeable. Coreflooding results show that brines with a higher visco-elasticity, corresponding to a higher sulfate concentration in the water injected, yield higher oil recovery factor that those with lower visco-elasticity, including the experiments with salinity lower than 50% of that of seawater. Brine-rock reactions were geochemically simulated to prevent injection conditions that could cause formation damage. Additionally, pH, electrical conductivity and total dissolved solid (TDS) were analyzed in the effluents. Results show that for the model rock used, brine composition does not change significantly from contact with rock surfaces. Since wettability alteration was minimized by use of low-temperature and short ageing time, recovery correlates better with changes in interfacial rheology. For results showing an apparent lack of correspondence with the interfacial rheological response, arguments based on ganglia dynamics might shed light on the observed recovery outcome. Our findings reveal that the injection of water with sulfate can modify the fluid-fluid interactions and consequently the final oil recovery, so in some cases, low-salinity brine injection is not necessarily conducive to an increment in oil production. Findings also indicate that more characterization of the brine-crude oil interface should be carefully conducted as part of the screening of adjusted brine chemistry waterflooding.