Exploring the Limit of Low-Salinity Waterflooding in a Carbonate Reservoir with Low Total Acid Number Oil

Abstract This paper presents a workflow for designing the optimal injection brine composition for an offshore carbonate reservoir. The crude oil from this reservoir has a very low total acid number (0.01 mg KOH/g), leading to the expectation that injecting diluted seawater would not be an effective enhanced oil recovery (EOR) fluid. To address this, we designed a water composition that maximizes electrostatic repulsion (total disjoining pressure) at the oil-rock interface. This was achieved by combining two surface complexation models (oil-water and calcite-water interfaces), tuned to represent the reservoir conditions, with the extended DLVO theory. The total disjoining pressure was calculated for more than 30 different brine compositions, and we selected the one that demonstrated the highest value. The optimized injection brine, termed ‘repulsive’ water, was then evaluated in the laboratory for its oil recovery performance. Both spontaneous imbibition tests and coreflooding tests showed limited success with the repulsive water, yielding additional oil recovery factors of only 1-2%. We believe that the poor oil recovery results from insufficient repulsion at the oil-rock interface. Greater repulsion would be necessary for improved oil recovery, but this was not achieved within the scope of this study. Additionally, injecting diluted seawater (by fifty times) also failed to yield promising oil recovery results. Based on these findings, we conclude that low-salinity waterflooding is not a viable EOR option for the studied carbonate reservoir.