Total carbon dioxide (CO2) storage capacities are estimated in numerous studies, but there is a lack of research of possible injection rates at a particular site. We have performed compositional simulation with permeability variation (based on log-normal distribution parameters of the measured data from similar formations in an oil field above the aquifer) to include changes of aqueous and gaseous phase properties (composition, viscosities, density), and heterogeneity of a regional CO2 storage site. We have performed sensitivity tests on vertical permeability multiplier, different grid block sizes, diffusivity, and capillary pressures to detect the key parameters for injectivity and storage efficiency. In this way, we modeled heterogeneity of a CO2 storage site and the possible injection rate in this detail for the first time. Based on pressure analysis in simulation cases, we found that it will be hard to avoid fracturing the near-wellbore zone, but fracturing these zones might also increase the injectivity, and this can still be done without damaging the cap rock. Simulation results indicated that maximum pressure will occur in zones above wellbores at the short period after the injection, and almost no change of average pressure in the regional aquifer will be noticeable, which leads to the conclusion that the total (theoretical) storage capacity is not the key issue for CO2 storage in aquifers and that injectivity for the storage site (expressed as the rate) should be the key parameter for selecting the pilots for CO2 storage.

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