In this paper, a thorough experimental investigation of enhanced oil recovery via controlled salinity-biosurfactant injection under typical reservoir temperature conditions is reported for the first time. Sixteen core flooding experiments were carried out with four displacing fluids in carbonate rock samples and the improved oil recovery was investigated in secondary, tertiary and quaternary injection modes. The temperature effect on oil recovery during floodings was compared at two temperatures (23 °C and 70 °C) on similar rock samples and fluids using two types of biosurfactants: GreenZyme® and rhamnolipids. The results of this study show that injection of controlled salinity brine (CSB) and controlled salinity biosurfactant brine (CSBSB) improve oil recovery relative to injection of high salinity formation brine (FMB) at both high and low temperatures. At 23 °C, CSBSB improved oil recovery by 15–17% OIIP compared with conventional FMB injection, and by 4–8% OIIP compared with CSB injection. At 70 °C, the injection of CSBSB increased oil recovery by 10–13% OIIP compared with injection of FMB, and by 2–6% OIIP compared with CSB injection. Furthermore, increase in the system temperature generally resulted in increased oil recovery, irrespective of the type of the injection brine. The results of this study have demonstrated for the first time the enhanced oil recovery potential of combined controlled salinity brine and biosurfactant applications at temperature relevant to hydrocarbon reservoirs. The results of this study are significant for the design of controlled salinity and biosurfactant flooding in carbonate reservoirs.
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