On Interplay of Capillary, Gravity, and Viscous Forces on Brine/CO2 Relative Permeability in a Compositional and Parallel Simulation Framework

The effectiveness of CO2 storage in saline aquifers is governed by interplay of capillary, viscous, and buoyancy forces. Recent experimental data reveals the impact of pressure, temperature, and salinity on interfacial tension (IFT) between CO2 and brine. The dependence of CO2-brine relative permeability and capillary pressure on IFT is also clearly evident in published experimental results. Improved understanding of the mechanisms that control the migration and trapping of CO2 in subsurface is crucial to design future storage projects that warrant long term and safe containment. Simulation studies ignoring the variation in interfacial tension and its effect on petrophysical properties of trapped CO2 saturations, relative permeability and capillary pressure have a poor chance of making accurate predictions of CO2 injectivity and its migration. We have developed and implemented a general relative permeability model that combines effects of pressure gradient, buoyancy, and IFT in an Equation of State (EOS) compositional and parallel simulator. The significance of IFT variations on CO2 migration and trapping is assessed. Introduction Saline aquifers can provide vast and safe storage for carbon dioxide pending a proper understanding of the displacement mechanisms of CO2-brine binary system at insitu conditions (Bachu, 2003). These aquifers are widely distributed, have reasonable permeability and porosity values, and have good thickness with large storage capacity (Franklin and Orr, 2004). Geological carbon sequestration involves injecting the produced CO2 into subsurface formations and trapping it through many geological and chemical mechanisms. CO2 injection in subsurface invokes multiphase flow, fluid phase behavior, relative permeability, wettability, gravity and buoyancy, capillary pressure, and geochemical reactions. Several research groups have studied the interplay of the capillary, gravity, viscous forces, and other factors that may affect the trapping (Pruess et al., 2003; Bachu et al., 1994; House et al., 2003). Much experimental research is focused on interfacial tension of oil, water, and gas phases (Taha, 2010). Many achievements have been made to understand the subsurface interaction between CO2 and formation brine (Bachu, 2008; Gunter, et al., 2004; Kumar, et al., 2005). Based on these findings, the injected CO2 in saline aquifers could be characterized in following forms: dissolved in formation brine, trapped by capillary forces in the pore space as residual saturation, adsorbed on minerals by chemical trapping, and free phase that is mobile. However, because the chemical trapping is significant for CO2 sequestration only in geological time scale, it is sometimes neglected for short time behavior studies. The injectivity of CO2 into an aquifer is greatly affected by the relative permeability and interplay of capillary, gravity, and viscous forces. During injection into the aquifers, CO2 displaces formation water at the leading edge of the plume as a drainage process. On the other hand during post injection, the formation brine displaces CO2 at the trailing end as in an imbibition direction. Several hysteresis models have been developed to capture the saturation history dependent relative permeability and capillary pressure relationships (Doughty, 2007). Experimental results show the change in both drainage and imbibition capillary pressure and relative permeability as the results of variations in pressure and salinity and (Bennion and Bachu, 2006). In many simulation studies, relative permeabilities are, however, defined at the beginning of the simulation study and only the variations due to saturation is modeled and the changes of pressure, salinity, and temperature are typically ignored. With the exception of the simulators with hysteretic models, the residual CO2 saturation is also fixed for a given rock type. However, the residual saturation is affected by the interfacial tension between CO2 and water and many experimental results reveal that the IFT between CO2 and brine varies at different pressure, salinity, and temperature conditions (Hauser and Michaels, 1948; Liu et al., 2010; Bennion and Bachu 2008; Al-Abri and Amin, 2009). These results show that the IFT decreases with increasing pressure, and increases with increasing temperature and salinity. The results also