Abstract
Carbon capture and storage (CCS) projects inject large amounts of CO2 into deep saline aquifers or depleted oil and gas reservoirs. This operation requires a leakage risk analysis for the injected CO2. The subsurface flow of CO2 at the injection formation is dependent on injection operations. This study proposes a method to combine a wellbore flow model and an analytical solution to the CO2 plume to investigate the influence of the injection temperature, pressure, and rate on the interface evolution between the CO2 and the brine. Using the wellbore flow model, the proposed mothed estimates the volume injection rate at the bottom hole under different injection parameters. Then it illustrates the effects of injection operations on the CO2 plume and its maximum radius at the interface between the caprock and formation. The results provide an estimation of the plume radius under different injection rate and duration that would help field operators manage leakage risks.
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