Lawrence Berkeley National Laboratory

Correlations are presented to compute the mutual solubilities of CO2 and chloride brines at temperatures 12–300°C, pressures 1–600 bar (0.1–60 MPa), and salinities 0–6 m NaCl. The formulation is computationally efficient and primarily intended for numerical simulations of CO2-water flow in carbon sequestration and geothermal studies. The phase-partitioning model relies on experimental data from literature for phase partitioning between CO2 and NaCl brines, and extends the previously published correlations to higher temperatures. The model relies on activity coefficients for the H2O-rich (aqueous) phase and fugacity coefficients for the CO2-rich phase. Activity coefficients are treated using a Margules expression for CO2 in pure water, and a Pitzer expression for salting-out effects. Fugacity coefficients are computed using a modified Redlich–Kwong equation of state and mixing rules that incorporate asymmetric binary interaction parameters. Parameters for the calculation of activity and fugacity coefficients were fitted to published solubility data over the P–T range of interest. In doing so, mutual solubilities and gas-phase volumetric data are typically reproduced within the scatter of the available data. An example of multiphase flow simulation implementing the mutual solubility model is presented for the case of a hypothetical, enhanced geothermal system where CO2 is used as the heat extraction fluid. In this simulation, dry supercritical CO2 at 20°C is injected into a 200°C hot-water reservoir. Results show that the injected CO2 displaces the formation water relatively quickly, but that the produced CO2 contains significant water for long periods of time. The amount of water in the CO2 could have implications for reactivity with reservoir rocks and engineered materials.