The fluid properties of CO2 injected into geological formations for subsurface storage are strongly affected by the specific formation conditions of pressure, temperature and salinity. Specifically, these conditions affect fluid solubility and density; we investigate their effects on subsurface CO2 storage efficiency. We compared several common equations-of-state (EOS) and solubility models; their accuracy and applicability are briefly discussed. We also evaluated the effects of gaseous/supercritical CO2 phase density and mutual solubility, including H2 O solubility in CO2. Results suggest that disparities in phase density estimates by different EOS typically do not translate to large disparities in simulation results because of the low solubility of H2 O in gaseous/supercritical CO2. However, more experimental studies on the solubility of H2 O in CO2 are needed, especially at high pressures and temperatures. Simulation results also suggest that formations at higher temperatures are less efficient for CO2 storage than equivalent formations at lower temperatures. We evaluated aqueous-CO2 solution density at a broad range of pressure and temperature conditions using different equations-of-state. Results indicate that CO2-dissolution in brine at high temperatures (>120 °C) may reduce mass density to values lower than the original brine density, nullifying the primary advantage of the dissolution trapping mechanism. This concept, equal density temperature, is proposed here for the first time. In certain scenarios with temperatures greater than the equal density temperature, CO2 can exsolve (escape the aqueous phase) and be subject to buoyancy-driven migration (and potential escape from the formation) associated with separate phase CO2. Simulation results are very sensitive to the density models selected. Predictions of CO2-enriched brine migration using different models can yield contradictory results.
All Science Journal Classification (ASJC) codes
- Water Science and Technology