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Abstract Economic considerations are likely to drive operators of geologic storage projects to inject as much CO2 as possible into the smallest number of wells. In practice, then, a CO2 injection well is likely to run at the largest bottomhole pressure that is safe. However, a constant-pressure well exhibits a varying rate of CO2 injection because of classical multiphase flow effects, and also because long-term injection of CO2 dries out the near-wellbore region. Drying removes water but precipitates dissolved salts, so the permeability of the dry rock need not equal the initial aquifer permeability. In addition to mobility of CO2 in the dried rock, the injectivity depends strongly on the mobility of the two-phase flow region. The difference in injectivity for seven different measured CO2-brine relative permeability curves is substantial. Characterizing relative permeability will therefore be an important consideration for the practical implementation of CO2 storage projects. The analytical expressions developed here show that injectivity variation can be understood in terms of phase mobilities and the speeds of saturations fronts. The expressions can refine the estimate of the number of wells needed for a target overall injection rate. Well count in turn strongly affects the economics of sequestration projects.
Burton et al. (Sun,) studied this question.