CO2 solubility in brine in silica nanopores in relation to geological CO2 sequestration in tight formations: Effect of salinity and pH

Abstract

Geological CO2 sequestration during CO2 enhanced oil recovery in tight formations is a technically and economically viable option to alleviate carbon emission. In tight formations, there existsare enormous number of nano-scale pores, which can be filled with connate and injected water. In addition, the salinity and pH of the formation water vary regionally. In this work, we used molecular dynamics simulations to study the effects of salinity and pH on CO2 solubility in brine in silica nanopores under typical geological conditions (353 K and ~ 175 bar). The pH effect is characterized by the deprotonation degree of silanol on the silica surface. We find that water mainly distributes around the silanol groups and CO2 mainly enriches in the areas where silanol groups are vacant. Na+ ions are generally depleted from the non-deprotonated silica surface, whereas they are strongly attracted to the pore surfaces in the deprotonated cases. The different water hydration structures around the non-deprotonated and deprotonated silanols arise from the accumulation of Na+ ions in the vicinity of SiO− groups. As salinity increases, the average densities of CO2 and water decrease in all silica nanopores and CO2 solubility in brine in silica nanopores decreases. On the other hand, as pH increases, water density increases but CO2 density decreases, resulting in a decrease of CO2 solubility in brine in silica nanopores. CO2 solubility in brine with a low pH range (~2–5) can be as high as 1.3–1.6 times of that in bulk, while it is comparable with that in bulk at a high pH range (~7–9). Overall, low salinity and low pH conditions are favored for geological CO2 sequestration by solubility trapping in tight formations.