Optimization of CO2 Flooding Strategy to Enhance Heavy Oil Recovery

Abstract

Heavy oil is a significant energy resource around the world. In Canada, there are tremendous heavy oil reserves lying in the north of the provinces of Alberta and Saskatchewan. The key point for heavy oil recovery is to increase the mobility of heavy oil in the reservoir condition. The most effective methods of heavy oil recovery are thermal methods such as steam flooding, cyclic steam stimulation (CSS), steam-assisted gravity drainage (SAGD) and in-situ combustion for the great heavy oil viscosity reduction by heat. However, thermal methods are proving to be unsuitable for most of the heavy oil reservoirs in Canada because of the thin net-pay zones, large depths and other rock, fluid and geological conditions. Therefore, cold production methods are mostly considered. In recent years there has been more development of solvent injection methods. CO2 is considered one of the most promising solvents used in both light and heavy oil for its high solubility. In light oil recovery, the production pressure in CO2 flooding is kept above the minimum miscible pressure in order to maintain the miscibility. Although in heavy oil recovery, CO2 miscibility can hardly be reached because of the high oil viscosity, but the oil recovery can still be stimulated to a great extent by CO2 injection. Different CO2 flooding strategies can significantly affect the recovery factor. In this study, different injection and pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one. Field data, oil samples and brine from a heavy oil field in north China were used for the core-flooding experiments. Experimental results indicated that a lower CO2 injection rate led to a higher recovery factor from 31.1% to 36.7%. In terms of the effects of different production strategies, a constant production pressure at the production port yielded a recovery factor of 31.1%, while a pressure depletion at the production port yielded 7% more oil recovery; and the best pressure control scheme was that in which the production pressure was kept constant during the CO2 injection period, then the model pressure was depleted with the injector shut-in, yielding a recovery factor of 42.5% of the initial OOIP. Numerical simulations were conducted to history match the experimental results. The same oil relative permeability curve was used to match the experimental results to all tests. Different gas relative permeability curves were obtained when the production pressure schemes were different. A much lower gas relative permeability curve and higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases. The lower gas relative permeability curve indicated that foamy oil was formed in the pressure depletion processes. A 3-D reservoir model was built by Computer Modeling Group (CMG) software based on field data and relative permeability curves from history match of the tests. Different strategies, including different injection and production schemes and different injection materials were used, and the better results were chosen for analysis.