Enhanced Heavy Oil Recovery by Liquid CO2 Injection under Different Injection Strategies

Abstract

There are vast resources of heavy oil located in reservoirs in which the reservoir temperature is lower than or in the vicinity of the critical temperature of CO2 (31.1 °C). A good example of that are the huge resources of heavy oil in the Alaska North Slope. In these reservoirs, CO2 would be in liquid state and would exhibit higher viscosity and solvent power compared to gaseous or supercritical CO2. The objective of this study is to experimentally assess the potential of liquid CO2 injection for enhancing recovery from these reservoirs. A positive outcome could bring significant economic and environmental benefit by improving oil recovery and at the same time managing produced CO2 from neighboring reservoirs. A comprehensive series of coreflood experiments were performed using a heavy crude oil under the conditions of a heavy oil reservoir in the North Slope, Alaska. Different injection scenarios were experimentally simulated including water flood, CO2 flood, as well as combined water and CO2 injection in the form of WAG and SWAG injection. In order to investigate the impact of an initial depletion stage on the performance of CO2 injection, the impact of the amount of dissolved hydrocarbon gas in crude oil was also investigated and the results of the different injection scenarios were compared with each other and with the base case (waterflood). The coreflood results show a very good performance for liquid CO2 injection in the heavy oil system tested in this work. Dissolution of CO2 in heavy oil and the consequent significant reduction in the oil viscosity leads to a prolonged period of oil recovery during CO2 injection. This is different from waterflood whereby oil recovery almost ceases as soon as water breaks through. Combining CO2 and water and injecting CO2SWAG (simultaneous injection of water and CO2) increased oil recovery more than water or CO2 injection alone. CO2WAG injection (alternating injection of water and CO2) brought about an ultimate oil recovery of 74 % IOIP. This was a staggering 30% higher than the ultimate oil recovery by waterflood under the same conditions.

Investigation of Low-Density CO2 Injection for Enhanced Oil Recovery

“…Thus, it was aimed to reduce the saturation of oil in the core by coinjection of CO 2 and a surfactant solution. The successful coreflood application of the coinjection of CO 2 and the surfactant solution used in this experiment has been reported in other investigations. , However, no sign of strong propagation of foam was observed in this study, mainly because of the presence of dissolved gas (methane and CO 2 ) in the remaining oil in the core.…”

“…In an immiscible displacement, because the mobility of gas is significantly higher than that of heavy oil in porous media, a dramatic drop in the oil rate would be expected to happen after the breakthrough of the gas. , However, that was not the case in this experiment, and it was noted that the oil rate reduction was relatively slow. The main reason for this observation probably was the impact of the mechanism of solution gas drive as a result of CO 2 dissolution in oil until the breakthrough.…”

Experimental study of the effect of carbonated brine on wettability and oil displacement for EOR application in the Brazilian Pre-Salt reservoirs

“…Figures 1 and 2 show that for the experiments with CO 2 saturated brine, the wettability of all carbonate rocks is shifted towards water-wet as reported in other experimental works (Farzaneh, Seyyedsar, and Sohrabi 2016;Ruidiaz, Winter, and Trevisan 2018). Several factors have been proposed as contributing to this shift in wettability.…”

Visual Investigation of Improvement in Extra-Heavy Oil Recovery by Borate-Assisted $$\hbox {CO}_{2}$$ CO 2 -Foam Injection

“…In its simplest form, injecting CO 2 , like a steam injection, reduces the viscosity of heavy oil. Viscosity reductions of up to two orders of magnitude can be achieved by CO 2 injection (Farzaneh et al 2016). Water injected after CO 2 would then be able to drive the CO 2 -diluted oil out of the reservoir and increase oil recovery.…”

“…A review of the details of important parameters which affect foam stability is given in our previous work (Farzaneh and Sohrabi 2013). The lowering of IFT using a surfactant for producing foam has been known for decades, and likewise the addition of alkali to surfactant (AS) is well known, due to decades of research in areas of chemical flood by many investigators (Nasr-El-Din and Taylor 1992;Reed and Healy 1977;Pope and Nelson 1978;Reisberg and Doscher 1956;Martin et al 1985;Nelson et al 1984;Lieu et al 1982;Green and Willhite 1998). The addition of alkali can decrease IFT further, i.e.…”