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The Objective of this study is to experimentally investigate the performance of dense (liquid and super-critical) CO2 injection as an Enhanced Oil Recovery (EOR) method for extra-heavy oil reservoirs. Since CO2 is not expected to develop miscibility with heavy crude oil, CO2 injection is perceived not to be a viable technology for heavy oil reservoirs. The high viscosity difference between CO2 and heavy oil is also expected to further limit the performance of CO2 injection in these reservoirs. In this study, we introduce a new CO2 injection strategy in which CO2 is injected in an intermittent fashion that cycles between a period of injection and a period of halt. The injection strategy is particularly suitable for heavy and viscous oil reservoirs as it enhances the contact between injected CO2 and the resident heavy oil. In this paper, we present the results of two coreflood experiments which have been performed to evaluate the potential of intermittent injection of CO2 for enhancing recovery of an extra-heavy crude oil under reservoir conditions. The injected CO2 was in liquid state under the conditions of the first experiment, and supercritical in the second experiment. The same crude oil and gas were used to prepare live oil for both experiments. The viscosity of the live-oil (oil saturated with gas) used under the conditions of the first experiment was around 7 times higher than that of the second experiment. After a period of continuous CO2 injection, the injection was halted (soaking period) for a period of 24 hours and then CO2 injection resumed and 0.3 pore volume of CO2 was injected in the core. This cyclic soak-alternating-CO2 injection was repeated a number of times in both experiments. The results show that the CO2 breakthrough occurred early in both experiments due to the adverse mobility ratio and hence, front instability. Production of oil with foamy nature and liberation of gas from produced oil was observed after the CO2 breakthrough as a result of the increase in pressure gradient within the core before the CO2 breakthrough. However, oil production rate dropped significantly after this period because of low residence time of CO2 in the porous medium. Continuous CO2 injection after 1.3 PV of injection resulted in 22% and 19% of oil recovery for the first and second experiments, respectively. The oil production results showed that soak-alternating-CO2 injection recovered 16% and 47% of the remaining oil after four cycles in the first experiment and after nine cycles in the second experiment. A tertiary waterflood followed the soak-alternating-CO2 injection periods which recovered 23% and 14% of the remaining oil after 1 PV of injection in the first and second experiments, respectively. The core pressure was monitored and recorded during the soaking periods and it revealed that the core pressure increased in each period which is an indication of CO2 dissolution into the oil and consequently, evolution of the dissolved hydrocarbon gas from the oil. The in-line analysis of the gas produced during the CO2 injection periods also revealed the evolution of the oil's associated gas due to competition between the injected CO2 and the hydrocarbon gas dissolved in the oil (associated gas). Although the CO2 breakthrough in the second experiment (super-critical CO2 injection) occurred later than the first experiment (liquid CO2 injection), the amount of oil produced up until CO2 breakthrough in the second experiment was lower. This can be attributed to the higher rate of CO2 dissolution into the oil due to the relatively lower viscosity of oil in the second experiment. The effect of foamy oil production was more significant in the liquid CO2 injection experiment (compared to super-critical CO2 injection experiment) due to a relatively higher pressure in the CO2 front which resulted in super-saturation of the oil in contact with CO2. Compositional (GC) analysis of the core effluent show that in the second experiment, although the supercritical CO2 had lower ability to dissolve in the oil compared to the liquid CO2 used in the first experiment, CO2 was able to liberate more of the dissolved hydrocarbon gas from the oil due to the lower viscosity of the oil and consequently higher rate of CO2 diffusion into the oil. The oil recovery results show that soak alternating CO2 injection method improves oil recovery significantly compared to continuous CO2 injection in both experiments while at the same time lower amount of CO2 was used. Waterflood performed subsequent to CO2 soak/injection period resulted in considerable additional oil recovery due to the reduction of the oil viscosity brought about by the improved diffusion and dissolution of CO2 in the oil as well as redistribution of the fluids in the rock caused by the evolution of the oil's dissolved hydrocarbon gas.

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The density of the CO2-rich phase in a reservoir would play a crucial role in the performance of an enahcned oil recovery (EOR) scheme. Many oil reservoirs are located in deep formations; hence, they have high temperatures. Moreover, the pressure of reservoirs decreases because of natural depletion. Under the conditions of those reservoirs, CO2 would be a low-density gas. A series of coreflood experiments were performed to evaluate the potential of low-density CO2 EOR. The experiments are intermittent CO2 injection, continuous tertiary and secondary CO2 injection, and water alternating CO2 injection followed by the coinjection of a surfactant and CO2. The same oil and gas were mixed to prepare live oil for all the experiments. The initial rate of oil recovery during secondary waterflood was high, but the efficiency of the process decreased after the breakthrough. Three pore volumes (PVs) of secondary CO2 injection resulted in the recovery of around 50% of the initial oil in place, which was 27% higher than the oil recovered during 1 PV of water injection. It was also observed that CO2 injection can improve the recovery factor after waterflood. However, the performance of tertiary CO2 injection is reduced because of the presence of water in pore spaces, which likely makes the oil less accessible to CO2. Waterflood after a period of CO2 injection recovered 20% of initial oil in place mainly because of the dissolution of CO2 in the oil and the resultant oil viscosity reduction. The impact of the rate of CO2 injection on the efficiency of oil recovery was investigated, and it appears that the dissolution of CO2 in the oil is the main mechanism of enhanced recovery. The reduction of oil viscosity as a result of the dissolution of CO2 in the oil as well as the low density of CO2 improved the effect of gravity drainage on oil production. In addition, it was observed that the mechanism of solution gas drive plays an important role in the process of oil recovery. The analysis of the physical properties of the core effluent reveals that CO2 can also improve the quality of produced oil compared to that of the original oil in the rock. The results of this study provide experimental evidence of the potential of low-density CO2 EOR.