Improving Waterflood Recovery Efficiency in Carbonate Reservoirs through Salinity Variations and Ionic Exchanges: A Promising Low-Cost "Smart-Waterflood" Approach

Abstract

Abstract Our recent study demonstrates significant improvement in waterflood recovery efficiency could be possible in carbonate reservoirs through adjusting the salinity and/or ionic composition of injecting brine, and hence, this approach holds a huge potential to enhance oil recovery from the carbonate reservoirs in the UAE and elsewhere at a much lower cost while freeing up cleaner and greener hydrocarbon gases for other use. A set of comprehensive tests using carbonate rock have been completed to estimate displacement efficiency, assess wettability variation through wettability monitoring, optimize brine composition vis-à-vis the oil recovered and to explore and better understand the possible mechanisms that are at play. Tests were conducted at temperature ranging from 70°C to 120°C to mimic the UAE reservoir conditions to the extent possible. For both coreflood and wettability monitoring tests, salinity and composition variations were tested on the injection brines, seawater and formation water. In addition, certain mechanisms at play have been identified. Although the research on this approach is still in progress, the following key findings have been noted to date and they appear to have a direct relevance towards improving oil recovery from several UAE carbonate reservoirs: Reducing water salinity and increasing sulfate concentration of the injection brine could mobilize a significant amount of extra oil beyond the conventional seawater and formation water injection at both 70 ° C and 120 °C. At 70 °C, lowering the water salinity was more effective than raising the sulfate concentration in injection water in terms of incremental oil recovery after secondary conventional waterflood, whereas they exhibited similar potential at 120 °C. And at 70 °C, wettability alteration towards less oil-wetness could be triggered by low salinity water. The process was sensitive to temperature. Lowering water salinity and raising sulfate concentration of the injection water at 120 °C led to a much higher incremental oil recovery than that at 70 °C. At 90 °C, water-wetness of our carbonates could be enhanced by either reducing water salinity or increasing sulfate concentration of the surrounding water. However, the divalent cations in the surrounding water had limited effect on rock wettability. During low salinity water injection process, oil production was usually accompanied with pressure difference increase.