Dependence of wettability on brine composition in high temperature carbonate rocks

Laboratory experiments and small-scale field tests have shown that injection of low salinity brine can improve oil recovery from carbonate rocks. Contact angle studies, spontaneous imbibition and core flood experiments indicate that wettability alteration is responsible for this process. In this study, the core-scale manifestation of wettability 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. A mechanistic model was developed using our in-house reservoir simulator UTCHEM-IPHREEQC for the wettability alteration process. The model changes core wettability according to the adsorbed naphthenic acid concentration on the rock surface, which is controlled by the brine composition. The model was used to match previously published two-phase flow experiments. The single-phase core floods with test brines indicate retention of SO42− within the core. Calcite dissolution is prominent in ultra-dilute seawater injection. The relative permeability parameters for oil-wet and water-wet conditions were different, but the same for all the core floods. Model results were in good agreement with single-phase core floods and oil recovery experiments. Sulfate adsorption and calcium dissolution led to naphthenic acid desorption which in turn altered core wettability. Single-phase core floods reached equilibrium within 2 pore volumes (PV) of injection. Two-phase core floods with seawater and sulfate enriched seawater took longer to reach equilibrium, only after 3-4 PV. Oil-displacing ultra-dilute brine injection experiments did not reach equilibrium in 5 PV, particularly the Ca2+ ions, due to slow calcite dissolution.