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 exist 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 effect 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 while 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 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 high pH range (∼7−9). Overall, low salinity and low pH conditions are favored for geological CO₂ sequestration by solubility trapping in tight formations.