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Abstract
CO2 injection has been used in the oil industry as an effective technique for enhanced recovery of light to medium oils. However, its utilization for heavy oil recovery has not gained enough attention because of the immiscible nature of heavy oil and CO2. Due to high solubility of CO2 in both water and oil, the overall heavy oil recovery from waterflooding can be improved by adding CO2 to the injected water. CO2 injection for the geological storage in heavy oil reservoirs can also reduce its emissions and contribute towards development of clean fossil fuel production and climate change mitigation.  This paper presents the simulation study of injecting CO2 to improve the efficiency of heavy oil waterflooding and evaluate the potential of CO2 geological storage as a part of this process. In this study, a compositional simulation model was built based on a previous experimental work and validated by comparing the simulation results with experimental data. The sensitivity analysis was run on the validated model to examine the effects of different parameters including injection scheme (separate slugs of pure CO2/carbonated water and continuous carbonated waterflooding), injection pressure, and CO2 slug size on the heavy oil recovery and CO2 storage capacity.

This study shows that CO2 can enhance the efficiency of heavy oil waterfloofing and a considerable amount of CO2 can be stored inside the porous media. Additional recovery factors up to 28% OOIP were achieved by injecting CO2 in combination with water while CO2 storage capacity of 22.5‒93.6% of the injected CO2 was obtained. It was found that depending on CO2 injection pressure, different injection schemes can lead to variant accumulative heavy oil productions and CO2 storage capacities. In general, continuous carbonated waterflooding resulted in a higher amount of CO2 to be injected and stored inside the simulation model. In addition, it was observed that increase in the CO2 injection pressure enhances the heavy oil recovery and subsequently causes more CO2 to be stored. Moreover, injecting a larger CO2 slug size did not considerably change the ultimate accumulative heavy oil production and CO2 storage capacity.

Introduction
Western Canada has tremendous heavy oil deposits which are mainly located in east-central Alberta and extended into western Saskatchewan1. These heavy oil deposits are amongst the largest in the world with the estimated OOIP of more than 5201 million m3.2 Effective and economical recovery of such heavy oil deposits has gained considerable attention due to increase in demand for hydrocarbon fuels and decline in production from conventional light and medium oil resources. The primary recovery factor from heavy oil reservoirs is typically as low as 6‒8% of the original-oil-in-place (OOIP) which is mainly because of the extremely high viscosities and almost immobile conditions of the heavy oils under the actual reservoir conditions3,4. Waterflooding as a secondary recovery method is often employed in heavy oil reservoirs after the primary recovery period to displace the heavy oil towards the production well. In comparison with the other enhanced oil recovery processes, waterflooding is certainly cheaper and simpler to employ. However, low recovery factors and poor sweep efficiencies associated with the high mobility difference between the injected water and the heavy oil, set an economic limit to the waterflooding process in heavy oil reservoirs5,6.