Perpustakaan Digital ITB

Enhancing gas recovery through the CO? injection method is widely used due to its ability to maintain reservoir pressure and displace methane. Additionally, depleted gas reservoirs present promising geological storage options for CO? due to their well-documented geology and proven containment properties. Under supercritical conditions, CO?’s higher density and viscosity enable it to sweep methane effectively, supporting both natural gas recovery and CO? sequestration. CO? flooding as the injection strategy facilitates this process. This study conducted simulations in Field “X” using CMG GEM software to analyze production profiles, sensitivity analysis on injection rate up to 100 MMSCFD of CO?, optimum well spacing of inverted 5-spot injection pattern, and the best timing of injection after production decline. The results of this study, considering the recovery factor and CO? breakthrough time, indicate an optimal injection rate of 80 MMSCFD, with the maximum injector-producer well distance and injection timing set for 2030, after production begins to decline. The increase in methane recovery achieved is 25.18%, with CO? stored amounting to 16.24 million tons.