**4.5 Effect of injection depth on CO2 solubilities**

In a deep saline aquifer or oil reservoir high pressures and elevated temperatures are found. The pore pressure at depth is usually assumed to be equal to the hydrostatic pressure; a typical hydrostatic pressure gradient is 10.35 MPa/1000m (Dake 2007). In addition a geothermal gradient exists, the reservoir temperature increases with depth. Average typical geothermal gradients are 25-30 K/1000 m (Fridleifsson et al. 2008). Average temperatures and pressures at depth are listed in Table 2, they were calculated assuming typical pressure and temperature gradients and a surface temperature of 293 K. The surface temperature needs to be adjusted for each specific geographical location, e.g. average temperature is low in Norway (average temperature throughout the year is around 281 K) while average yearly temperature is high in Saudi Arabia (298 K).

As stated above CO2 solubility decreases with increase in temperature, but increases with increase in pressure. In Table 2 CO2 solubilities calculated with Duan's web based CO2 solubility calculator (Duan et al. 2003, 2006) are shown. The pressure effect over compensates the temperature effect so that CO2 solubility increases with reservoir depth up to a depth of approximately 900m when it reaches a plateau.

With regard to storage of CO2 in a supercritical phase optimal CCS conditions are conditions where the CO2 density ρCO2 is maximal, because then a maximum mass of CO2 can be stored in the same rock pore space. Thermodynamically ρCO2 increases with pressure but decreases with temperature. ρCO2 as a function of depth increases monotonically as the pressure effect also over compensates the temperature effect (Table 2).
