The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg2+ and SO42- and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca2+, but without Mg2+ or SO42- was unsuccessful in changing calcite wettability. Modified seawater containing Mg2+ and SO42-, and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO42- and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs.

Injection of brine with tuned composition has been shown to give improved oil recovery from carbonate rocks. Contact angle studies, spontaneous imbibition and core flood experiments have shown that wettability alteration is responsible for this process. Possible mechanisms include mineral dissolution and ion exchange, which have been investigated by zeta-potential measurements and geochemical modeling of both processes. In this study, the core scale manifestation of these mechanisms is evaluated, and a geochemical model is developed for further insight into reaction pathways. Brines of different compositions were injected into carbonate cores with no oil and the effluent was analyzed for ionic composition. Seawater, sulfate-rich seawater, and dilutions of seawater were tested. Two phase oil displacement core floods were performed for the same brine cases to correlate the oil recovery to the geochemistry. A mechanistic model was developed using our in-house reservoir simulator UTCHEM-IPHREEQC for the wettability alteration process. The single phase core floods with all test brines indicate retention of SO42− within the core, seen by a delay in its effluent concentration reaching the injection concentration. Na+, Ca2+, Mg2+ and Cl− ions mostly behave as tracers in the system. In oil displacement core floods, formation brine recovers 40% OOIP on average and seawater recovers an incremental 7% OOIP. Sulfate-rich seawater and dilutions of seawater increase the recovery to 65-80% OOIP in secondary and tertiary modes, requiring more than 5 PVI. SO42− ion delay is not observed in the two phase core floods. Ca2+ concentrations remain high after 5 PVI of diluted seawater, indicating a slow dissolution process in the low salinity floods. The mechanistic model results were in good agreement with the single phase coreflood experiments and oil recovery experiments. The model showed that the reduction in surface concentration of naphthenic acids was responsible for altering the wettability on the injection of modified brines.

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