Geochemical Impact on Rock Wettability in Injection of High-Concentration Formate Solution for Enhanced Geologic Carbon Storage and Oil Recovery

Abstract

Abstract Aqueous formate (FM) solution has been studied for geologic carbon storage, in which highly concentrated FM solution as carbon-bearing water is injected into the target formation. The literature shows that aqueous FM solution may cause geochemical interactions with carbonate rocks, but no experimental data exist for high-concentration FM solutions. This paper presents a new set of data focused on core-scale wettability alteration of carbonate porous media with varying FM concentration (up to 30 wt%) in NaCl brine. Experimental data from Amott wettability tests and core floods with limestone cores were analyzed to mechanistically understand the wettability alteration observed in the experiments. Static calcite dissolution tests showed that the degree of calcite dissolution increased with increasing FM concentration in the NaCl brine even with the initially neutral pH. For example, the calcium concentration in the 30-wt% FM case was 15.9 times greater than that in the NaCl brine case with the initial pH of 7.0. Furthermore, reducing the initial solution pH from 7.0 to 6.1 for the 30-wt% FM solution caused the calcium ion concentration to increase by a factor of 3.2. Geochemical modeling indicated that the increased calcite dissolution could be caused by the formation of calcium FM complexes that reduced the activity coefficient of the calcium ion and therefore, drove the calcite dissolution. The 30-wt% FM solution with the initial pH of 6.1 yielded 4.7 times greater oil recovery than the NaCl brine case in the spontaneous imbibition. The resulting Amott index clearly indicated the wettability alteration to a water-wet state by the FM solution. The 30-wt% FM solution with the initial pH of 7.0 yielded only 30% greater oil recovery than the brine case in the spontaneous imbibition; however, it reached nearly the same amount of total oil recovery (spontaneous and forced) with the 30-wt% FM solution with the initial pH of 6.1. This is likely because the in-situ solution pH could be sufficiently lower than the calcite isoelectric point consistently during the forced imbibition, unlike under the static conditions during the spontaneous imbibition. Increasing the FM concentration in the injection brine (pH 7.0) delayed the water breakthrough in core floods. Numerical history matching of the core flooding data showed that increasing the FM concentration in the injection brine rendered the initially oil-wet core to a more water-wet state as quantified by Lak and modified Lak wettability indices. Results in this research collectively suggest the importance of in-situ solution pH in wettability alteration by aqueous FM solution in carbonate media, in order to cause the rock surface to be positively charged in the presence of FM and calcium ions.