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2.2.1 Foamy oil

Compared with the CO2 huff ‘n’ puff process in a heavy oil reservoir under water drive, the pressure depletion process that is conducted in the heavy oil reservoir can result in better oil production (Monger et al., 1991) mainly due to foamy oil occurring in the production stage. Solution gas drive has been proven as the main production mechanism in the CO2 huff ‘n’ puff process applied in a heavy oil reservoir (Du et al., 2018a; Firouz and Torabi, 2014; Li et al., 2016; Or et al., 2016; Sun et al., 2017a). When CO2 is injected into the heavy oil reservoir, it will dissolve into heavy oil through mass transfer, and the dissolved CO2 gas will expand the volume of the heavy oil. Then the dissolved CO2 will drive the heavy oil out of the pores to the production well when the pressure is declined in the production stage. Because of the high viscosity of heavy oil, the phase of the CO2 appears as gas bubbles, which are dispersed in heavy oil and flow with the heavy oil when the reservoir pressure declines. The produced heavy oil is a mixture containing small bubbles. This kind of produced fluid is defined as foamy oil (Maini et al., 1993a; Sheng et al., 1999; Zhou et al., 2017). The foamy oil phenomenon has been observed in experimental studies on the CO2 huff ‘n’ puff process in heavy oil reservoirs, and it enhances heavy oil production significantly (Abedini and Torabi, 2014; Asghari and Torabi, 2007; Huang et al., 2017).

In the production stage of the CO2 huff ‘n’ puff process in heavy oil, the foamy oil phenomenon relates highly to the pressure decline rate, temperature, solvent solubility, etc. A higher pressure depletion rate results in a higher heavy oil recovery factor due to the higher pressure depletion rate producing more stable foamy oil in the production stage (Du et al., 2016; Ostos and Maini, 2005; Zhou, 2015; Zhou et al., 2014). Considering the effect of temperature, researchers have found that the stability of the foamy oil decreases sharply and the volume of the dispersed gas increases with increasing temperature (Du et al., 2018b; Tang and Firoozabadi, 2003; Zhang, 1999), but an optimized temperature can be obtained for a certain oil sample (Liu et al., 2013). Among different solvents, foamy oil, which is generated by using CO2 saturated in heavy oil, can achieve a higher quality than other solvents (CH4 or N2) due to the slow desorption of CO2 in heavy oil (Or et al., 2016). The solubility of CO2 in heavy oil relates to injection pressure, as the CO2 solubility increases with the increasing of injection pressure. With higher CO2 solubility, the foamy oil behavior will be more obvious in the production stage (Huang et al., 2017), and the heavy oil recovery factor will be higher.

 

2.2.2 Viscosity reduction

Viscosity reduction is another main mechanism in the CO2 huff ‘n’ puff process. Previous studies have indicated that the effect of viscosity reduction is more significant in heavy oil with a lower API gravity (Dyer et al., 1994; Sayegh and Maini, 1984). When CO2 is recombined into heavy oil, the viscosity of the heavy oil is extremely reduced, as shown in Table 2.1. The main reasons for viscosity reduction through CO2 injection are: (1) the particulate matters in the heavy oil are washed out by the injected CO2; (2) the viscous deposits are dissolved by the injected CO2; (3) the viscous crude in heavy oil is diluted by the injected CO2; and (4) the injected CO2 is demulsified in heavy oil (Jeffries- Harris and Coppel, 1969). The viscosity reduction of heavy oil results in the fractional flow curve shifting to the right, so that the fractional flow of water is lower than that before CO2 injection at the same water saturation and the oil mobility and oil connection are increased, which leads to a relative higher oil flow rate (Simpson, 1988).

 

Table 2.1 Summary of the measured viscosity reduction ratios and oil swelling factors in different heavy oils (Zhou et al., 2018).

 

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The viscosity reduction ratio of a heavy oil-CO2 system changes with the temperature, pressure, and solubility of the dissolved CO2 (Khatib et al., 1981). Figure 2.2 shows the viscosity reduction ratio and CO2 solubility of a heavy oil-CO2 system at different temperatures and pressures. With temperature increases, the viscosity of the dead heavy oil decreases extremely and the viscosity reduction ratios for the dead oil at 60°C

and 93°C are 86.8% and 97.3%, respectively. Therefore, the effect of temperature on heavy oil viscosity is remarkable.

With CO2 injection, when the temperature is lower than the critical temperature, the viscosity reduction mainly occurs at a lower pressure due to the mass transfer of the liquid phase being much slower than the gas phase. This leads to the effect of pressure on CO2 solubility being not significant. Regarding the heavy oil-CO2 system, the efficiency of viscosity reduction decreases with temperature increases at the same pressure due to (1) lower CO2 solubility with higher temperature in heavy oil; and (2) lower viscosity of heavy oil at higher temperature, which results in less viscosity reduction potential. The experimental study indicates that a higher percentage of viscosity can be reduced by CO2 injection for heavy oil with higher viscosity (Chung et al., 1988). With an increase in CO2 solubility, the viscosity reduction ratio increases, which means a higher percentage of the heavy oil viscosity is reduced by injecting CO2. The viscosity reduction ratio can be as high as 97% for the studied heavy oil.

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Figure 2.2 The viscosity reduction ratio and CO2 solubility of a heavy oil-CO2 system at different pressures and temperatures (Chung et al., 1988).

 

A summary of viscosity reduction studies on a heavy oil-CO2 system is tabulated in Table 2.1. Table 2.1 shows that the effect of CO2 in heavy oil is significant, the viscosity reduction ratio can reach up to 99.8%, and the viscosity reduction of the heavy oil-CO2 system relates to pressure and temperature. Among different heavy oil samples with a higher heavy oil viscosity, a greater viscosity reduction ratio can be obtained. Regarding the same heavy oil sample, the viscosity reduction ratio decreases with an increase in temperature.

 

 

2.2.3 Oil swelling

When CO2 is injected into the heavy oil reservoir, an important phenomenon is observed in terms of oil swelling, because the injected CO2 dissolves into the heavy oil and expands the volume (Avaullee et al., 1997; Bijeljic et al., 2003; Do and Pinczewski, 1991; Jha, 1986b). The oil swelling is an important mechanism to enhance heavy oil recovery in the CO2 huff ‘n’ puff process, because (1) oil swelling shows an advantage on the movable oil, and an inverse proportional relation is found between the oil swelling factor, which indicates the degree of oil swells and is defined as the volume of crude oil saturated with CO2 at the reservoir pressure and temperature divided by the volume of crude oil at the atmospheric pressure and reservoir temperature (Welker and Dunlop, 1963) and the residual oil saturation; (2) the mobility of the heavy oil is improved; (3) the dissolved heavy oil will generate a drainage force to push water out of the pore space; and (4) oil swelling can increase the oil saturation, resulting in an increase of oil relative permeability, which increases the oil phase fractional flow in the production stage (Grogan and Pinczewski, 1987; Maneeintr et al., 2014; Mangalsingh and Jagai, 1996; Tharanivasan et al., 2006; Yang and Gu, 2006).

The degree of oil swelling factor relates to pressure, temperature, and oil composition (Mangalsingh and Jagai, 1996). Figures 2.2 and 2.3 indicate that the plots of the oil swelling factor have the same trends as the plots of CO2 solubility, which means that, under the same conditions (temperature and pressure), the oil swelling factor is proportional to the CO2 solubility. The effects of pressure on the oil swelling factor are different at different temperature, and a linear relationship is obtained between the oil swelling factor and pressure when the temperature is greater than the critical temperature. However, the phase of the CO2 affects the oil swelling factor remarkably. In the low- pressure region (when the CO2 is in the gas phase), the oil swelling factor increases with pressure increases. At higher pressure, the phase of CO2 changes from the gas phase to the liquid phase, leading to lower CO2 solubility and a reduced effect of pressure on oil swelling factor. The effect of temperature shows that a higher temperature leads to a lower oil swelling factor in the low-pressure region due to CO2 solubility decreasing with temperature increases. In a higher-pressure region, the oil swelling is greater than that at low temperature due to the phase change reducing the CO2 solubility. Regarding oil composition, lighter oil can get a higher oil swelling factor than that of heaver oil, because more CO2 can be dissolved into the lighter oil (Sayegh and Maini, 1984).

 

 

2.2.4 Diffusion coefficient

Another important parameter that impacts the properties of a heavy oil-CO2 system is the diffusion coefficient, which indicates the diffusion rate and the amount of CO2 dissolved into the heavy oil (Boustani and Maini, 2001; Frauenfeld et al., 2006; Huang et al., 2016; Riazi, 1996; Wang et al., 1996; Yuan et al., 2017a, 2017b). Previous

studies indicate that heavy oil production in the vapour-extraction process is mainly from the transient zone, where heavy oil is saturated with an injected solvent and the area of the transient zone is controlled by the molecular diffusion rate of the injected solvent (Ghasemi et al., 2017; Jiang and Butler, 1996). As a type of solvent, when CO2 is injected into the heavy oil reservoir, it is gradually dissolved into the heavy oil by means of mass transfer (molecular diffusion), especially in the soaking stage (Grogan and Pinczewski, 1987; Tharanivasan et al., 2004). This results in viscosity reduction and oil swelling so that heavy oil production can be enhanced.

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Figure 2.3 Oil swelling factor of the heavy oil-CO2 system at different pressures and temperatures (Chung et al., 1988).

 

The diffusion coefficient relates to pressure, temperature, and oil composition, as shown in Figure. 2.4 and Table 2.2. The effect of pressure on the diffusion coefficient is more sensitive at a higher temperature than at a lower temperature because (1) the lower surface tension of oil molecules can be obtained at higher temperature, so that the mass transfer rate of CO2 molecules into heavy oil is higher and (2) a lower heavy oil viscosity is obtained at a higher temperature and CO2 molecules can pass through the interface easier. Kavousi et al. studied the CO2 diffusion coefficient in heavy oil at different temperatures and pressures (Kavousi et al., 2014). In their experimental researches, the CO2 diffusion coefficient increases with pressure increases. However, if the pressure continues increasing at a very high level, the viscosity and density of the heavy oil-CO2 system increases as well, which causes the diffusion coefficient decreases steadily (Jamialahmadi et al., 2006).

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Figure 2.4 CO2 solubility and diffusion coefficient at different temperatures and pressures (Kavousi et al., 2014).

 

 

 

 

 

 

 

Table 2.2 Summary of the measured diffusion coefficients of CO2 in different heavy oils (Zhou et al., 2018).

 

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Under a constant temperature, the diffusion coefficient increases with pressure increases in the relative lower pressure region, mainly because the higher pressure supports a greater drive force for the CO2 transferring into heavy oil. The combined effects of pressure and temperature show that the diffusion coefficient of CO2 in heavy oil increases with pressure and temperature increase.

The viscosity of heavy oil decreases with temperature increases, which can be concluded as the diffusion coefficient of CO2 in heavy oil decreasing with heavy oil viscosity increases. Table 2.2 indicates that CO2 diffusion coefficients are different for different oil samples. Even different diffusion coefficients can be achieved using the same experimental results (Li and Yang, 2016; Zheng et al., 2016), due to (1) different treatment of the pseudo-components for the heavy oil in the calculation, and (2) a slight difference between the objective functions.

Regarding CO2 solubility in heavy oil, the solubility of CO2 increases with pressure increases and decreases with temperature increases, but no significant relationship can be found with the CO2 diffusion coefficient.

To measure the diffusion coefficient of CO2 in heavy oil, direct and indirect measurement methods have been applied in previous studies. In the direct method (Sheikha et al., 2005; Upreti and Mehrotra, 2000), oil samples are extracted out of the tested system during the test to involve compositional analysis. Then a mathematical model is required to calculate the diffusion coefficient. Experimental errors in the direct method are not easily avoided. In the indirect method, the properties of heavy oil and CO2 are measured and the changes are monitored during the tests. The tested properties include

pressure decay monitoring (Riazi, 1996; Sheikha et al., 2005; Tharanivasan et al., 2006; Upreti and Mehrotra, 2000), volume changing measurement (Renner, 1988), volatilization rate of solvent testing (Fu and Phillips, 1979), location of the gas-liquid interface determination (Das and Butler, 1996; Riazi, 1996), etc. Other indirect methods such as dynamic pendant drop volume analysis (Yang and Gu, 2006), Nuclear Magnetic Resonance (NMR) (Wen et al., 2005), and X-ray Computer Assisted Tomography (CAT) (Song et al., 2010) are also used to determine the concentration of CO2 at different locations of the test fluids.

The diffusion coefficients measured by previous scholars are summarized in Table 2.2. Table 2.2 indicates that the diffusion coefficient of CO2 in heavy oil relates to oil components, viscosity, temperature, and pressure, and that most of the measured diffusion coefficients of CO2 in heavy oil are in the order ranges from 10-10 m2/s to 10-9 m2/s. For heavy oil with a higher API gravity, there are more light or medium components, which results in the CO2 diffusion process occurring easily, so that the CO2 diffusion coefficient is higher than that in heavy oil with a lower API gravity. Compared with different heavy oil samples, the heavy oil sample with a relative lower viscosity is beneficial to the diffusion coefficient, so that a greater diffusion coefficient can be obtained. Regarding the test methods, pressure decay is the most popular method in previous studies and the pressure profile is matched using the derived mathematical models. Then the diffusion coefficient of CO2 is calculated. In the calculation process, the diffusion coefficient of CO2 differs slightly according to different boundary conditions (equilibrium, quasi- equilibrium, and non-equilibrium) in the mathematic model even through the same tests are applied.

 

 

 

 

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