Geological complexities make hydrocarbon recovery challenging, requiring EOR methods tailored to specific rock and fluid properties. However, CO₂ injection in low-permeability reservoirs often suffers from gas channeling and gravity segregation, while chemical and foam flooding face high costs and environmental concerns. On the other hand, CO₂ microbubble injection has been proposed as a gas-mobility-control approach with potential environmental and economic advantages. Laboratory studies have shown that the CO₂ microbubble method positively affects sweep efficiency and increases breakthrough time; however, no field studies have been reported yet. Numerical simulation, though limited by inherent model assumptions, is an economical and powerful tool for evaluating the performance of different production program scenarios and EOR methods. In this study, the CMG simulator was used to model production behavior in a sector of a conventional oil reservoir based on actual field data. CO2 microbubble injection was represented by adapting CMG foam-model parameters, including rheology, base-fluid fraction, and rock adsorption. Performance was simulated over 700 days and compared against water and immiscible CO₂ injection scenarios, analyzing pressure profiles, recovery factor (RF), and oil saturation distribution. Results at day 480 show the CO₂ microbubble proxy achieving the highest recovery factor (54.88%), compared to water (49.90%) and immiscible CO₂ (43.62%). By day 700, however, water and microbubble recovery became nearly identical (58.13% and 58.10%), indicating faster intermediate recovery but no ultimate recovery gain over water.