Simulation of CO2 Storage in a Low‐Pressure Depleted Gas Reservoir and Economic Assessment of Multiphase CO2 Injection Strategies under Two Business Models of Storage Services

The injection stage of the CO2 storage process presents distinct technical challenges, primarily in managing multiphase flow dynamics. A comprehensive understanding of phase behavior and P–T effects is required to support efficient injection and optimal storage capacity. In this study, to maximize storage capacity, multiphase CO2 injections were simulated in a low‐pressure depleted gas reservoir in the Musi Field of South Sumatra. The economic analysis evaluates two business models (storage‐as‐a‐service and carbon‐credit storage service), each assessed within three cooperation schemes (gross split, cost recovery, and public–private partnership), using key financial indicators including NPV, IRR, contractor and government take, and the cost of CO2 storage. The simulation results indicate that CO2 storage in depleted gas reservoirs can be optimized through a variable‐phase injection approach. Injection begins in the gas phase while the reservoir pressure remains low until it reaches the CO2 bubble point. Subsequently, operators would inject dense‐phase CO2 as the reservoir pressure increases. The injection strategy evaluates multiple wellhead pressure settings and identifies a pressure‐profile discontinuity characterized by a sudden increase in bottom‐hole pressure when the wellbore pressure crosses the CO2 gas–liquid saturation boundary. With this variable‐phase injection management scenario, CO2 storage of up to 67.4 million tons can be achieved in 33.4 years. The storage fees for PPP, cost recovery, and gross split schemes are $11.94, $12.58, and $14.32 per ton CO2, respectively. Carbon credit services follow suit with fees of $36.16, $35.82, and $43.39 per ton CO2 under the same schemes.