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

Abstract

This paper presents new data on core-scale wettability alteration of carbonate porous media with FM concentrations up to 30 wt % in NaCl brine. Experimental data from Amott tests, core floods, calcite dissolution experiments, and zeta potential measurements were analyzed to mechanistically understand the wettability alteration observed in the experiments. Static calcite dissolution tests showed that the degree of dissolution increased with increasing FM concentration in NaCl brine, even with an initially neutral pH. For example, the calcium concentration in the 30 wt % FM solution was 15.9 times greater than that in the NaCl brine with an 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 and Raman analysis indicated that increased calcite dissolution was caused by interactions between calcium and FM ions. The 30 wt % FM solution with an initial pH of 6.1 yielded 4.7 times greater oil recovery than the NaCl brine in the spontaneous imbibition. The resulting Amott index indicated the wettability alteration to a water-wet state by the FM solution. The 30 wt % FM solution with an initial pH of 7.0 yielded only 30% greater oil recovery than the brine in the spontaneous imbibition; however, it reached nearly the same total oil recovery (spontaneous and forced) as the 30 wt % FM solution with an initial pH of 6.1. A numerical model was calibrated using core flood data, based on which the relative permeabilities indicated the core-scale wettability alteration by FM solutions. Results showed that increasing the FM concentration in the injection brine rendered the initially oil-wet core to a more water-wet state and that the in situ solution pH played an important role in wettability alteration by FM solution in carbonate media.

Permeabilities of Water–Oil Two-Phase Flow in Capillary Fractures with Different Wettabilities

“…They pointed out that the presence of a wetting layer or a thicker wetting film on a tube would affect the wettability of channel and the distribution of water-oil two-phase flow. Oyenowo et al [16] experimentally studied the effect of aqueous formate solution on the core-scale wettability alteration of carbonate porous media and found that the fluid flowing in the porous media had an impact on the wettability of the cores. The initial oil-saturated core could reach a more water-saturated state by increasing the concentration of injected aqueous formate solution.…”

A Strategy for Enhanced Carbon Storage: A Hybrid CO2 and Aqueous Formate Solution Injection to Control Buoyancy and Reduce Risk

“…Some authors have worked with aqueous solutions based on formic acid [17] to enhance the CO2 solubility in brine or on formate ions [18,19] to enhance the pore-space utilization in carbon storage while avoiding various issues with CO2 storage. Additional benefits of the formate solution have been found for carbonate rocks concerning the wettability alteration to enhance oil recovery [18,[20][21][22].…”