A Phase-Partitioning Model for CO2–Brine Mixtures at Elevated Temperatures and Pressures: Application to CO2-Enhanced Geothermal Systems

• Published in: Transport in porous media 2010-03, Vol.82 (1), p.173-196
• Main Authors: Spycher, Nicolas, Pruess, Karsten
• Format: Article
• Language: English
• Subjects: Activity coefficients; Brines; Carbon dioxide; Carbon sequestration; Civil Engineering; Classical and Continuum Physics; Computer simulation; Earth and Environmental Science; Earth Sciences; Equations of state; Flow simulation; Fugacity; Geotechnical Engineering & Applied Earth Sciences; Geothermal; Heat treatment; High temperature; Hydrogeology; Hydrology/Water Resources; Industrial Chemistry/Chemical Engineering; Interaction parameters; Mathematical models; Mixing rules; Moisture content; Multiphase flow; Partitioning; Reservoirs; Saline water; Salting; Solubility; Water flow
• ISSN: 0169-3913; 1573-1634
• DOI: 10.1007/s11242-009-9425-y

Correlations are presented to compute the mutual solubilities of CO 2 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 CO 2 -water flow in carbon sequestration and geothermal studies. The phase-partitioning model relies on experimental data from literature for phase partitioning between CO 2 and NaCl brines, and extends the previously published correlations to higher temperatures. The model relies on activity coefficients for the H 2 O-rich (aqueous) phase and fugacity coefficients for the CO 2 -rich phase. Activity coefficients are treated using a Margules expression for CO 2 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 CO 2 is used as the heat extraction fluid. In this simulation, dry supercritical CO 2 at 20°C is injected into a 200°C hot-water reservoir. Results show that the injected CO 2 displaces the formation water relatively quickly, but that the produced CO 2 contains significant water for long periods of time. The amount of water in the CO 2 could have implications for reactivity with reservoir rocks and engineered materials.