A Comprehensive Study on Simulation of CO2 Injection in Southwest Iran

摘要

There is a consensus among specialists that Carbon dioxide (CO2) flooding is an effective method of enhanced oil recovery. CO2 injection causes oil swelling, reduction in the oil viscosity, oil vaporization and improving oil displacement by miscibility. Iranian oil reservoirs are expected to undergo serious pressure decline in upcoming years. Abundance of CO2, its availability and environmental issues regarding this gas, makes it a promising injection gas to overcome such challenges. Because of technological complexity and financial requirements to initiate a gas flooding project, a comprehensive evaluation is necessary before any other thing. The present work is concerned with investigation of CO2 injection process in a sector of a Southwest Iranian oil reservoir, giving a special attention to phase behavior and amount of recoverable oil. Thus we use real rock and fluid properties for simulation. The main focus is on equation of state (EOS), modeling of experimental PVT data, determining MMP (minimum miscibility pressure) for different gas compositions using a slim tube model. Other aspects such as the effect of different completion patterns, CO2 injection rate, and injection pressure on oil recovery are covered. Recovery values obtained from different flooding scenarios are also compared. Finally, we inspect recovery performance in different gas flooding scenarios and natural depletion. First, we made the fluid model by the PVTi software and then tuned three-parameter Peng-Robinson equation of state by regression analysis. Subsequently,we matched calculated data with observed data (which were obtained from PVT experiments in the lab). Next, for a better understanding of reservoir fluid, we simulated swelling and slim tube experiments. The slim tube dynamic model was generated by Eclips300 software. Afterwards by making use of Eclipse300 we introduced different scenarios to identify the most optimal number of injection and production wells, rate of CO2 injection, injection pressure for CO2, and the best time to open injection wells. From the simulation results obtained from injection of CO2, CH4, N2, and mixtures of CH4-CO2, CO2-C3 and N2-CO2 on the cumulative oil production, it was observed that CO2 is the best fluid for injection purposes. The simulation results indicate that CO2 injection to the studied sector of the reservoir causes a 12.9% increase in recovery factor in comparison with the natural depletion of this sector.