Injection of supercritical-phase CO2 may decrease injectivity near the injection well and perturb subsurface temperatures, leading to a dynamic temperature system in the storage formation and adjacent seal strata. Water vaporization in supercritical-phase CO2, is an endothermic reaction that may cool reservoir fluids. Such a cooling process may result in the precipitation of solid NaCl near the wellbore that deteriorates injectevity. We evaluated these processes with numerical simulation models that include processes of injectivity reduction and potential non-isothermal effects of commercial-scale CO2 injection. Processes of interest include the vertical CO2 profile within the wellbore, injectivity reduction and the potential non-isothermal processes including Joule- Thomson (heating and cooling) effects, exothermic CO2 dissolution, and heat changes associated with concomitant water vaporization. These processes are evaluated using numerical simulations of CO2 injection and associated pressure and temperature changes within an injection well using a wellbore dynamic code. In addition, we developed independent 2-D radially symmetric models of commercial-scale CO2 injection with the TOUGH2 simulator, using its ECO2N equation-of-state package. Results of our wellbore dynamic simulations suggest that three forces, including adiabatic (de-) compression of CO2, frictional energy losses, and conductive heat exchange between the injected CO2 and surrounding fluid/rock, govern the resulting CO2 thermal profiles within the injection well. In addition, as compressed CO2 flows from the injection well to the target storage formation, the induced pressure field begins to dissipate. Such pressure reduction induces Joule-Thomson cooling by adiabatic expansion. In the same zone, water vaporization within supercriticalphase CO2 occurs and induces NaCl precipitation; this precipitation process also cools the reservoir fluid. Finally, as supercritical-phase CO2 comes into contact with formation brine, exothermic CO2 dissolution offsets the cooling with an increase of the reservoir fluid temperature.
Bibliographical noteFunding Information:
All financial support for this research was provided by the Southwest Regional Partnership on Carbon Sequestration Phase III funded by U.S. Department of Energy, under the contract no. DE-FC26-05NT42591.
All Science Journal Classification (ASJC) codes