This article presents a numerical investigation of the combined effects of capillary pressure, salinity and in situ thermodynamic conditions on CO2-brine-rock interactions in a saline aquifer. We demonstrate that the interrelations between capillary pressure, salinity, dissolution and drying-out affect CO2 injectivity and storage capacity of a saline aquifer. High capillary forces require a high injection pressure for a given injection rate. Depending on salinity, the increase in injection pressure due to capillary forces can be offset by the dissolution of CO2 in formation water and its compressibility. Higher capillary forces also reduce gravity segregation, and this gives a more homogeneous CO2 plume which improves the dissolution of CO2. The solubility of CO2 in formation water decreases with increasing salinity which requires an increased injection pressure. Higher salinity and capillary pressure can even block the pores, causing an increased salt precipitation. Simulations with various pressure-temperature conditions and modified salinity and capillary pressure curves demonstrate that, with the injection pressures similar for both cold and warm basins at a given injection rate, CO2 dissolves about 10% more in the warm basin water than in the cold basin. The increase in dissolution lowers the injection pressure compensating the disadvantage of low CO2 density and compressibility for storage in warm basins.