Perpustakaan Digital ITB

Geological carbon sequestration in depleted reservoirs is considered one of the most effective strategies for reducing anthropogenic greenhouse gas emissions. A critical mechanism in this process is the interaction between injected CO2 and reservoir brine, specifically solubility trapping, where CO2 dissolves into the aqueous phase, increasing brine density and enhancing storage security. This study utilizes a compositional reservoir simulator (CMG GEM) to investigate the hydrodynamic and thermodynamic behaviour of CO2-Brine interactions in a 1-Dimensional coreflood model. The primary objective is to evaluate the co-optimization of Enhanced Oil Recovery (EOR) and Carbon Storage across six continuous CO2 injection rate scenarios (0.1 to 1.0 ft3/day). The simulation results demonstrate that injection flow kinetics dictate a critical trade-off between rapid fluid displacement and storage efficiency. Following a baseline waterflood recovery of 52.75%, all tertiary CO2 injection scenarios successfully mobilized residual oil via viscosity reduction and swelling. However, the High-Rate scenario (Rate 1.0) induced a rapid displacement front and premature gas breakthrough at Day 1.208. The reduced fluid residence time hindered CO2 dissolution, plummeting the Storage Efficiency to a mere 16.67%. Conversely, the Low-Rate scenario (Rate 0.1) maintained a uniform, piston-like displacement front. This extended residence time significantly delayed breakthrough (> 3.0 Days), maximized the CO2 mole fraction in the aqueous phase, and increased the brine mass density to ~67 lb/ft3. Consequently, the optimal interaction achieved an outstanding Storage Efficiency of 97.50%. This study concludes that optimizing the injection rate is paramount to maximize solubility trapping, prevent early gas escape, and ensure secure, long-term carbon sequestration.