Comparative Simulation Study of CO2 and N2 Foam Injection for Mobility Control in a Heavy Oil Reservoir, Niger Delta

Abstract

Heavy oil reservoirs in the Niger Delta present significant development challenges due to high oil viscosity, unfavorable mobility ratios, and poor sweep efficiency during conventional gas injection. Gravity override, viscous fingering, and early gas breakthrough typically limit recovery, while foam-assisted gas injection offers a potential solution by reducing gas relative permeability and increasing apparent gas viscosity. This study presents a comparative field-scale simulation evaluation of CO2 and N2 foam injection for mobility control in a heavy oil reservoir (oil viscosity approximately 13.5 cP, initial pressure 3088 psi, porosity (0.13–0.296) using the empirical foam model in CMG STARS. A history-matched reservoir model was developed incorporating production data, relative permeability measurements, and compositional fluid characterization. Two cases were simulated under identical reservoir and operational conditions: CO2 foam injection and N2 foam injection, with foam parameters calibrated to laboratory-derived mobility reduction functions and gas fraction-dependent viscosity behavior. Results demonstrate that both foam systems significantly alter the reservoir depletion trajectory compared to pre-foam primary recovery. The CO2 foam case achieved a peak oil production rate of approximately 850–900 bbl/day, compared to 700–750 bbl/day for N2 foam, representing an order-of-magnitude improvement over pre-foam rates of less than 100 bbl/day. Average reservoir pressure increased from 950 psi to approximately 1300–1350 psi in the CO2 case, versus 1050–1100 psi in the N2 case, while injector bottom-hole pressure stabilized 250–300 psi higher for CO2 foam, indicating greater effective flow resistance and stronger foam generation. Gas saturation at the injector remained below 5% in both cases, confirming stable foam propagation without uncontrolled gas channeling. The CO2 foam case delivered a cumulative oil recovery factor of approximately 9.5% by the end of simulation, compared to 7.8% for N2 foam, representing a technically meaningful incremental recovery of 1.5–2.0 percentage points attributable to CO2. The superior performance of CO2 foam is attributed to the combined benefits of rheological mobility control and compositional displacement enhancement. Partial dissolution of CO2 into the heavy oil phase reduces oil viscosity and promotes oil swelling, improving microscopic displacement efficiency beyond the macroscopic conformance achieved by foam alone. In contrast, N2 remains largely immiscible, providing effective mobility control through foam rheology and gas trapping but without compositional oil modification. Both systems prevented runaway gas breakthrough and maintained stable long-term gas management, as evidenced by moderated gas-oil ratio trends. Plan-view saturation and pressure maps further confirm improved areal sweep distribution following foam implementation. This study concludes that while both CO2 and N2 foam are technically viable for mobility control in Niger Delta heavy oil reservoirs, CO2 foam provides superior field-scale performance due to the synergistic combination of mobility reduction and compositional enhancement. The results underscore the importance of gas selection in foam EOR design and demonstrate that gas type significantly influences pressure response, injectivity behavior, and ultimate recovery. Future work should extend this analysis to include economic sensitivity assessment, surfactant optimization, and pilot-scale validation to determine practical feasibility for large-scale field implementation in the Niger Delta.