Carbon dioxide capture and injection into the subsurface has aroused great interest in the past few years as a method to enhance oil recovery and mitigate CO2 emissions. The Dickman Oilfield located in Kansas provides two possible CO2 sequestration targets: a regional deep saline reservoir (the primary objective) and a shallower mature depleted oil reservoir (secondary). We focused on the shallower depleted oil reservoir through a 250-year flow-simulation scenario and a fault leakage test. Seismic responses at various time intervals were simulated to help monitor CO2 flow paths and injection stability. A complex and realistic geologic model with unconformity was embedded in the flow-simulation model. A regridding technique was used that assigned geologic values to a regular seismic grid that allowed 2D acoustic and elastic finite-difference simulation. Gassmann fluid substitution theory was used to obtain the reservoir properties with different CO2 saturations, and the vertical seismic profile was used to assist in identifying geologic layers. A CO2 plume and flow path from the leakage test can be detected from the differences in seismic data (5 to 10 ms time shift) from the first year of injection and the last year of monitoring. This was supported by comparison with the prestack field data available in the Dickman Oilfield. CO2-induced reflectivity changes are relatively larger for PS events than for PP events, implying that multicomponent data acquisition and processing may give added value to characterization and monitoring of carbon capture and storage projects. We assessed 4D seismic monitoring in the evaluation of long-term CO2 containment stability for the Dickman Oilfield and suggested that time-lapse surveys will be useful.

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