Research Progress on Displacement Mechanism of Supercritical CO2 in Low-Permeability Heavy Oil Reservoir and Improvement Mechanism of Displacement Agents

With the continuous growth of global energy demand and the late stage of conventional oilfield exploitation, the demand for developing and utilizing low-permeability heavy oil reservoirs is becoming increasingly urgent. However, the exploitation of low-permeability heavy oil reservoirs faces many challenges due to their high viscosity, low permeability, and complex geological conditions. To overcome these challenges, researchers have gradually introduced SC-CO2 as an oil displacement agent in the exploitation of heavy oil reservoirs. However, the oil displacement mechanism of SC-CO2 in low-permeability heavy oil reservoirs and its improvement mechanism are still not completely understood. The article provides a detailed study and understanding of the oil displacement mechanism of SC-CO2, which involves the expansion of heavy oil volume through SC-CO2 dissolution. This mechanism reduces the capillary resistance and flow resistance during the oil flow process. The permeation of CO2 disrupts the internal structure and arrangement of heavy oil, reducing its viscosity. CO2 extracts both light and heavy components from the heavy oil, reducing the residual oil saturation. In addition, the mechanism of improving the effect of oil displacement agents such as nanoparticles, polymers, and surfactants on SC-CO2 displacement was also explored. By further exploring the mechanisms and improvement mechanisms of SC-CO2 displacement for heavy oil, it can guide the selection and optimization of oil displacement agents. Furthermore, understanding the mechanism can also provide a theoretical basis for engineering practice and technical innovation. While the research on CO2 flooding is analyzed and evaluated, the obstacles and challenges that still exist at this stage are indicated, and future research work on CO2 in low-permeability heavy oil reservoirs is proposed.


Introduction
In the 21st century, the increasing global oil and gas demand and the gradual decline in conventional oil and gas production have not met the needs of consumption growth. The effective use of unconventional oil and gas is of key strategic significance in alleviating the contradiction between oil and gas supply and demand, ensuring energy security, promoting a low-carbon transformation of the energy mix, and promoting carbon sequestration [1][2][3]. Chemical flooding has achieved great success in conventional medium-high-permeability reservoirs. However, it has entered a late stage of development after a long period of development. The production gradually decreases, and the reservoir development target gradually shifts from medium-high-permeability reservoirs to low-permeability heavy oil reservoirs. 4 of 30 is generally similar to that of crude oil, and the low viscosity and high diffusivity of SC-CO 2 enable it to rapidly diffuse into the narrow pores of the reservoir, thereby displacing resident oil and gas. In addition, the conditions required for CO 2 to reach a supercritical state are low, making these conditions less demanding on production equipment and highly operable. As a non-toxic and odorless environmentally friendly gas, CO 2 can be recovered and reused from industrial waste gases, enabling industrial production and improving economic efficiency. At the same time, it can alleviate environmental problems such as the greenhouse effect faced by the world to a certain extent. Furthermore, CO 2 exhibits strong solubility for substances with lower molecular weights or weaker polarity, such as alkanes below C 18 . The green area in the diagram is the supercritical state. Currently, the most studied supercritical fluid is CO2. SC-CO2 is used in a wide range of industrial manufacturing applications including electrochemical deposition, preparation of nanoparticles, processing of hard-to-cut materials, cleaning of precision instruments, and centrifugal compression of petroleum [40,[47][48][49]. CO2 at its critical temperature and pressure has a higher density, and as the temperature increases, the diffusion coefficient of CO2 gradually increases while the viscosity decreases. As the pressure increases, the diffusion coefficient of CO2 gradually decreases, while the viscosity increases. Under normal conditions, the density of SC-CO2 is generally similar to that of crude oil, and the low viscosity and high diffusivity of SC-CO2 enable it to rapidly diffuse into the narrow pores of the reservoir, thereby displacing resident oil and gas. In addition, the conditions required for CO2 to reach a supercritical state are low, making these conditions less demanding on production equipment and highly operable. As a non-toxic and odorless environmentally friendly gas, CO2 can be recovered and reused from industrial waste gases, enabling industrial production and improving economic efficiency. At the same time, it can alleviate environmental problems such as the greenhouse effect faced by the world to a certain extent. Furthermore, CO2 exhibits strong solubility for substances with lower molecular weights or weaker polarity, such as alkanes below C18.

Composition and Viscous Mechanism of Heavy Oil
Heavy oil is a complex product composed of light components such as saturated hydrocarbons and aromatic hydrocarbons, as well as heavy components such as resins and asphaltenes in a certain proportion. The reason why heavy oil is "thick" is because of its high proportion of gum and asphaltene. There are many studies and assumptions about the structure and adhesion mechanism of gum and asphaltene, and it is generally believed that asphaltene is the main influencing factor.
The individual molecules of asphaltene exhibit strong polarity and contain more aromatic heterocyclic structures. These aromatic heterocyclic structures are stacked with each other by π-π conjugation, and this stacking structure can be further stabilized by hydrogen bonding of oxygen, nitrogen, sulfur, and other heteroatoms in asphaltene or the chelation of metal heteroatoms such as Ni and V in heavy oil, forming asphaltene supramolecular structures [50,51]. Asphaltenes are encapsulated by colloidal molecules with polar groups that form a surrounding coating, resulting in asphaltene particles encapsu-

Composition and Viscous Mechanism of Heavy Oil
Heavy oil is a complex product composed of light components such as saturated hydrocarbons and aromatic hydrocarbons, as well as heavy components such as resins and asphaltenes in a certain proportion. The reason why heavy oil is "thick" is because of its high proportion of gum and asphaltene. There are many studies and assumptions about the structure and adhesion mechanism of gum and asphaltene, and it is generally believed that asphaltene is the main influencing factor.
The individual molecules of asphaltene exhibit strong polarity and contain more aromatic heterocyclic structures. These aromatic heterocyclic structures are stacked with each other by π-π conjugation, and this stacking structure can be further stabilized by hydrogen bonding of oxygen, nitrogen, sulfur, and other heteroatoms in asphaltene or the chelation of metal heteroatoms such as Ni and V in heavy oil, forming asphaltene supramolecular structures [50,51]. Asphaltenes are encapsulated by colloidal molecules with polar groups that form a surrounding coating, resulting in asphaltene particles encapsulated by colloids that are also highly polar and further leading to their aggregation through hydrogen bonding and eventually forming large molecular aggregates. This phenomenon contributes to the high viscosity of heavy oil. Through hydrogen bonding, they further accumulate and eventually form macromolecular aggregates, resulting in high viscosity of heavy oil. Figure 2 shows a supramolecular assembly structure of asphaltene aggregates proposed by Gray et al. They believe that the asphaltene aggregates are supramolecular structures formed by hydrogen bonding, metal chelation, van der Waals force, π-π interaction, and acid-base interaction [52].
Additionally, heavy oil easily forms stable W/O type emulsions with small amounts of water, resulting in increased viscosity. Processing and treating this stable W/O type emulsion of heavy oil is relatively difficult and challenging in the petroleum industry. The presence of asphaltene is conducive to the stability of W/O emulsions because the asphaltene molecule itself is a natural surfactant. Its polar functional groups such as metal heteroatoms have strong hydrophilicity, while the aromatic ring structure and hydrocarbon chain in the molecule are hydrophobic. The amphiphilicity of asphaltene molecules Molecules 2023, 28, 6154 5 of 30 enables them to adsorb at the oil-water interface, forming an interfacial film with a certain mechanical strength, thus preventing water droplets from gathering and enhancing the stability of W/O emulsions [53].
Additionally, heavy oil easily forms stable W/O type emulsions with small amounts of water, resulting in increased viscosity. Processing and treating this stable W/O type emulsion of heavy oil is relatively difficult and challenging in the petroleum industry. The presence of asphaltene is conducive to the stability of W/O emulsions because the asphaltene molecule itself is a natural surfactant. Its polar functional groups such as metal heteroatoms have strong hydrophilicity, while the aromatic ring structure and hydrocarbon chain in the molecule are hydrophobic. The amphiphilicity of asphaltene molecules enables them to adsorb at the oil-water interface, forming an interfacial film with a certain mechanical strength, thus preventing water droplets from gathering and enhancing the stability of W/O emulsions [53].

Geological Characteristics of Low-Permeability Reservoirs and EOR Techniques-CO2 Flooding
With the continuous development of onshore oilfields, old oilfields have entered the late stage of high water cut, and the focus of petroleum exploration and development has gradually shifted to low-permeability reservoirs. Low-permeability reservoirs have abundant reserves both domestically and internationally, with recoverable reserves reaching 483 × 10 8 t [54]. Low-permeability oil and gas reservoirs refer to reservoirs with low porosity, poor fluid flow capacity, and low natural productivity, making it difficult to effectively develop them using conventional extraction methods. Currently, there is no unified classification standard for low-permeability reservoirs both domestically and internationally. In the US, reservoirs with permeability below 10 mD are classified as medium to poor reservoirs. In China, low-permeability reservoirs are divided into low-permeability (10-50 mD), ultra-low-permeability (1-10 mD), and super-low-permeability reservoirs (0.1-1 mD) [55][56][57][58][59]. Low-permeability oil reservoirs are predominantly lithologic reservoirs, characterized by a single type, mainly elastic drive reservoir. Its reservoir physical properties are poor, with low porosity and permeability, small pore throats, and strong heterogeneity. However, it has a high oil saturation and favorable crude oil properties. Therefore, the low-permeability oil reservoir has enormous potential and high exploitation value [60][61][62][63].
The United States is the country with the fastest development and the highest number of projects in CO2 flooding technology. In the 121 projects implemented in 2012, 75.8% of the reservoirs were classified as low-permeability oil reservoirs, indicating the significant importance of CO2 flooding in EOR for low-permeability and ultra-low-permeability . Supramolecular assembly structure of asphaltenes: acid-base interactions and hydrogenbonding (blue), metal coordination complex (red), a hydrophobic pocket (orange), π-π stacking (face-to-face dark green; within a clathrate containing toluene, light green) [52].

Geological Characteristics of Low-Permeability Reservoirs and EOR Techniques-CO 2 Flooding
With the continuous development of onshore oilfields, old oilfields have entered the late stage of high water cut, and the focus of petroleum exploration and development has gradually shifted to low-permeability reservoirs. Low-permeability reservoirs have abundant reserves both domestically and internationally, with recoverable reserves reaching 483 × 10 8 t [54]. Low-permeability oil and gas reservoirs refer to reservoirs with low porosity, poor fluid flow capacity, and low natural productivity, making it difficult to effectively develop them using conventional extraction methods. Currently, there is no unified classification standard for low-permeability reservoirs both domestically and internationally. In the US, reservoirs with permeability below 10 mD are classified as medium to poor reservoirs. In China, low-permeability reservoirs are divided into low-permeability (10-50 mD), ultra-low-permeability (1-10 mD), and super-low-permeability reservoirs (0.1-1 mD) [55][56][57][58][59]. Low-permeability oil reservoirs are predominantly lithologic reservoirs, characterized by a single type, mainly elastic drive reservoir. Its reservoir physical properties are poor, with low porosity and permeability, small pore throats, and strong heterogeneity. However, it has a high oil saturation and favorable crude oil properties. Therefore, the low-permeability oil reservoir has enormous potential and high exploitation value [60][61][62][63].
The United States is the country with the fastest development and the highest number of projects in CO 2 flooding technology. In the 121 projects implemented in 2012, 75.8% of the reservoirs were classified as low-permeability oil reservoirs, indicating the significant importance of CO 2 flooding in EOR for low-permeability and ultra-low-permeability reservoirs [64]. Compared to other gases, CO 2 has a lower critical temperature and critical pressure, generating a more favorable miscibility with crude oil. Even without miscibility, CO 2 still exhibits excellent oil displacement effects. After dissolving in crude oil, CO 2 causes the oil to expand and reduces its viscosity, making it easier to transport. Under certain pressure, CO 2 can extract both light and heavy components, causing the composition of the crude oil to approach equilibrium. CO 2 dissolved in crude oil can also reduce interfacial tension. The weak acidity of CO 2 can play a role in plugging in acidification to some extent.
The injection of external fluids complicates the flow relationship between oil, water, and gas in low-permeability reservoirs. During the oil displacement process, physical and chemical reactions such as convection, diffusion, adsorption, and ion exchange often occur. Studying the oil displacement mechanism of carbon dioxide in low-permeability reservoirs is crucial for injection-production parameters optimization and effect forecasting. Therefore, this study elaborates on the oil displacement mechanism of carbon dioxide in low-permeability heavy oil reservoirs and the improvement mechanism in Sections 3 and 4. The ecological environment in low-permeability oilfields is fragile, and the contradiction between efficient exploitation of petroleum resources and environmental protection is becoming increasingly prominent. CO 2 flooding can achieve the storage of greenhouse gases and improve the oil recovery rate, making it a highly promising technology for enhanced oil recovery in low-permeability reservoirs.

Main Mechanism of SC-CO 2 Flooding of Heavy Oil
CO 2 flooding is one of the oil displacement methods in tertiary oil recovery, and SC-CO 2 miscible drive is one of them. After reaching the reservoir, CO 2 becomes supercritical. It displaces oil from the large pores and mixes with it, forming an oil bank ahead of the miscible zone. The SC-CO 2 zone is followed by the water lock, which drives oil from the reservoir to the bottom of the production well, ultimately allowing oil to be recovered. The working principle diagram of SC-CO 2 miscible flooding technology is shown in Figure 3.
interfacial tension. The weak acidity of CO2 can play a role in plugging in acidification to some extent.
The injection of external fluids complicates the flow relationship between oil, water, and gas in low-permeability reservoirs. During the oil displacement process, physical and chemical reactions such as convection, diffusion, adsorption, and ion exchange often occur. Studying the oil displacement mechanism of carbon dioxide in low-permeability reservoirs is crucial for injection-production parameters optimization and effect forecasting. Therefore, this study elaborates on the oil displacement mechanism of carbon dioxide in low-permeability heavy oil reservoirs and the improvement mechanism in Sections 3 and 4. The ecological environment in low-permeability oilfields is fragile, and the contradiction between efficient exploitation of petroleum resources and environmental protection is becoming increasingly prominent. CO2 flooding can achieve the storage of greenhouse gases and improve the oil recovery rate, making it a highly promising technology for enhanced oil recovery in low-permeability reservoirs.

Main Mechanism of SC-CO2 Flooding of Heavy Oil
CO2 flooding is one of the oil displacement methods in tertiary oil recovery, and SC-CO2 miscible drive is one of them. After reaching the reservoir, CO2 becomes supercritical. It displaces oil from the large pores and mixes with it, forming an oil bank ahead of the miscible zone. The SC-CO2 zone is followed by the water lock, which drives oil from the reservoir to the bottom of the production well, ultimately allowing oil to be recovered.   The use of SC-CO 2 miscible flooding is due to its excellent fluidity in the formation and its ability to expand the volume of crude oil when dissolved in it, thereby reducing its viscosity and lowering the interfacial tension of the crude oil [65]. In particular, heavy oil reservoirs with high viscosity and density have a good mutual solubility with SC-CO 2 , enabling a significant reduction in crude oil viscosity, which is very beneficial for the replacement of heavy oil [66]. At the same time, CO 2 has the effect of a dissolving gas after dissolving in crude oil. CO 2 separates from the crude oil and creates bubbles in the crude oil, pushing the crude oil to flow and improving the oil drive efficiency, when the formation pressure drops below the saturation pressure [67].

The Swelling of Heavy Oil by SC-CO 2
The solubility of CO 2 in crude oil is an important parameter for EOR and CCUS, while the volume expansion of crude oil is a mechanism for CO 2 -EOR. Consequently, it is necessary to investigate the mechanism of CO 2 volume expansion under near-critical and supercritical conditions for enhanced recovery, which will provide us a better understanding of the chemical and physical reactions in the CO 2 -EOR process. The important mechanism of crude oil expansion involves CO 2 easily dissolving into crude oil and causing it to expand, thus supplementing reservoir pressure and increasing oil saturation [68]. Volume expansion increases the internal kinetic energy of crude oil and reduces the capillary resistance and flow resistance in the process of crude oil flow, thus improving the flow capacity of crude oil [69]. The effect of expansion on heavy oil is mainly manifested in three aspects. The residual oil in the reservoir after water flooding is inversely proportional to the expansion coefficient, that is, the greater the expansion, the lesser the residual oil in the reservoir [70]. The dissolution of CO 2 in oil droplets displaces water from the pore space, resulting in a process where the water-wet system becomes a drainage rather than water absorption. The relative permeability curve of oil discharge is higher than that of oil suction, creating an expedient flow environment under any given saturation condition [71]. On the one hand, volume expansion can significantly increase the oil saturation and formation elastic energy of the reservoir. On the other hand, the remaining oil after expansion can be separated or partially separated from the formation water and become mobile oil [72].
Crude oil is a mixture composed of compounds such as n-alkanes, cycloalkanes, aromatic hydrocarbons, resins, and asphaltenes, making the interaction between CO 2 and the constituents of crude oil exceedingly intricate. Since Whorton et al. applied for the patent of CO 2 flooding in 1950, many experts and scholars have studied the phenomenon of volumetric expansion effect of dissolved CO 2 in crude oil [73]. The alterations in the properties of crude oil are primarily as a result of CO 2 dissolving in crude oil and are affected by the dispersion of CO 2 in crude oil. Yang et al. analyzed the swelling behavior of oil by qualitatively discussing the dispersion properties of CO 2 in the oil. The results show that the dispersion of CO 2 molecules in the alkane phase plays a dominant role in the increase in the volume of CO 2 -alkane system. The solubility of CO 2 in alkanes and the volume of the CO 2 -alkane system decrease with increasing alkane molecular length [74]. However, the expansion mechanism of CO 2 dissolved in crude oil cannot be fully characterized under experimental conditions. In recent years, some researchers have investigated the interfacial properties and phase equilibria of the CO 2 -crude oil system by using molecular simulation techniques to understand the dynamic behavior of alkane solid surfaces. Zhang et al. investigated the solubility of CO 2 in octane and its effect on the expansion of octane (n-octane) by performing configurational-bias Monte Carlo simulations in an osmotic ensemble. The results show that the interaction between octane and CO 2 strengthens with increasing CO 2 solubility in the pressure range of 2-10 MPa and at temperatures ranging from 323-353 K. The interaction between octane and CO 2 is the main cause of octane dissolution [75]. Similar conclusions were reached by Liu et al., who found that the interaction between CO 2 and decane molecules is the main reason for the volume swelling of the CO 2 -alkane system. The dispersive interaction between CO 2 and n-decane molecules is the essence of the volume swelling of the CO 2 -n-decane system. At the same time, they noted that the volume swelling rate of decane was accelerated by the increase in the average spacing between decane molecules and the stretching of decane molecules. Figure 4 illustrates the microscopic process of volume expansion in the CO 2 -octane system [76].
As the solubility of CO 2 in oil increases, it leads to an increase in the distance between the oil molecules, and the force between oil molecules decreases, resulting in an expansion of the oil volume [77]. Figure 5 shows the process of dissolution and volume expansion of CO 2 in n-alkane. As can be seen from the figure, when the molar fraction of CO 2 is 25%, the molecules fill the space between the hydrocarbon molecules, forming a dispersed form. When the molar fraction reaches 50%, the overall volume of the system expands to a certain extent, and the CO 2 and hydrocarbon molecules interpenetrate each other. When the CO 2 mole fraction reaches 75%, the number of CO 2 molecules is absolutely dominant, and the total volume of the system is greatly increased due to the dramatic increase in the number of both molecules. In addition, the longer the carbon chain and the larger the molecule of a hydrocarbon, the harder it is to dissolve CO 2 [78].
Molecules 2023, 28, x FOR PEER REVIEW 8 of 31 molecules is the essence of the volume swelling of the CO2-n-decane system. At the same time, they noted that the volume swelling rate of decane was accelerated by the increase in the average spacing between decane molecules and the stretching of decane molecules. Figure 4 illustrates the microscopic process of volume expansion in the CO2-octane system [76]. . The microscopic process of the volume swelling for CO2-decane system. Color code: gray, carbon; red, oxygen; white, hydrogen [76].
As the solubility of CO2 in oil increases, it leads to an increase in the distance between the oil molecules, and the force between oil molecules decreases, resulting in an expansion of the oil volume [77]. Figure 5 shows the process of dissolution and volume expansion of CO2 in n-alkane. As can be seen from the figure, when the molar fraction of CO2 is 25%, the molecules fill the space between the hydrocarbon molecules, forming a dispersed form. When the molar fraction reaches 50%, the overall volume of the system expands to a certain extent, and the CO2 and hydrocarbon molecules interpenetrate each other. When the CO2 mole fraction reaches 75%, the number of CO2 molecules is absolutely dominant, and the total volume of the system is greatly increased due to the dramatic increase in the number of both molecules. In addition, the longer the carbon chain and the larger the molecule of a hydrocarbon, the harder it is to dissolve CO2 [78]. Normal n-alkanes with shorter chains have smaller negative intermolecular interaction energies, which means that the molecules are more easily separated from each other, and therefore a higher swelling factor can be observed when octane is saturated by CO2. The interaction between alkane chains decreases with increasing pressure, indicating that the diffusion capacity of oil molecules increases when more CO2 molecules are dissolved by heavy oil [79]. In order to observe the CO2 dissolution process, Wang et al. observed the CO2-octane system by using molecular dynamics simulation methods. At the initial stage, some CO2 molecules begin to penetrate into the octane phase, resulting in a slight  . The microscopic process of the volume swelling for CO2-decane system. Color code: gray, carbon; red, oxygen; white, hydrogen [76].
As the solubility of CO2 in oil increases, it leads to an increase in the distance between the oil molecules, and the force between oil molecules decreases, resulting in an expansion of the oil volume [77]. Figure 5 shows the process of dissolution and volume expansion of CO2 in n-alkane. As can be seen from the figure, when the molar fraction of CO2 is 25%, the molecules fill the space between the hydrocarbon molecules, forming a dispersed form. When the molar fraction reaches 50%, the overall volume of the system expands to a certain extent, and the CO2 and hydrocarbon molecules interpenetrate each other. When the CO2 mole fraction reaches 75%, the number of CO2 molecules is absolutely dominant, and the total volume of the system is greatly increased due to the dramatic increase in the number of both molecules. In addition, the longer the carbon chain and the larger the molecule of a hydrocarbon, the harder it is to dissolve CO2 [78]. Normal n-alkanes with shorter chains have smaller negative intermolecular interaction energies, which means that the molecules are more easily separated from each other, and therefore a higher swelling factor can be observed when octane is saturated by CO2. The interaction between alkane chains decreases with increasing pressure, indicating that the diffusion capacity of oil molecules increases when more CO2 molecules are dissolved by heavy oil [79]. In order to observe the CO2 dissolution process, Wang et al. observed the CO2-octane system by using molecular dynamics simulation methods. At the initial stage, some CO2 molecules begin to penetrate into the octane phase, resulting in a slight Normal n-alkanes with shorter chains have smaller negative intermolecular interaction energies, which means that the molecules are more easily separated from each other, and therefore a higher swelling factor can be observed when octane is saturated by CO 2 . The interaction between alkane chains decreases with increasing pressure, indicating that the diffusion capacity of oil molecules increases when more CO 2 molecules are dissolved by heavy oil [79]. In order to observe the CO 2 dissolution process, Wang et al. observed the CO 2 -octane system by using molecular dynamics simulation methods. At the initial stage, some CO 2 molecules begin to penetrate into the octane phase, resulting in a slight expansion of the octane volume. As a result, the CO 2 -octane system expands further, providing more space for the diffusion of CO 2 . The swelling process of the CO 2 -octane binary system is shown in Figure 6 [80]. It was also found that when CO 2 was injected into the system, the alkane chain was slightly extended, meaning that the presence of CO 2 molecules caused the alkane molecules to expand, which further led to the expansion of the systemic volume.
Regarding the study on the swelling behavior of CO 2 with cycloalkanes, Sima et al. studied the vapor-liquid equilibrium of binary systems of CO 2 with cycloalkanes (cyclopentane and cyclohexane) and showed that CO 2 is more soluble and miscible in n-alkanes than in cycloalkanes [81]. Similar conclusions were obtained by Zhang et al. in their study of the solubility and volume expansion factors of CO 2 in cycloalkanes. They believe that as the number of carbon atoms increases, the dispersibility between alkane molecules increase, the interactions between alkane molecules are enhanced, and the solubility of CO 2 in alkanes decreases [82]. A large number of research works have investigated the solubility and volume expansion mechanism of CO 2 in single alkane, brine, and alkane-water binary systems, while the microscopic mechanism of CO 2 in hydrocarbon mixtures is not sufficiently clear. Therefore, the study of CO 2 in hydrocarbon mixtures has received much attention. Wang et al. measured the volume expansion of CO 2 and n-dodecane in fused silica capillaries using Raman spectroscopy. The results show that the expansion coefficient increases with the increase in pressure and decreases with the increase in temperature [83]. CO 2 is less soluble in cycloalkanes and aromatics than in n-alkanes with the same number of carbon atoms. It is concluded that the solubility of CO 2 in hydrocarbon mixture is mainly affected by high-carbon hydrocarbons through the above study, i.e., the higher the proportion of high-carbon hydrocarbons in the mixture, the lower the solubility of CO 2 [84].
Molecules 2023, 28, x FOR PEER REVIEW 9 of 31 expansion of the octane volume. As a result, the CO2-octane system expands further, providing more space for the diffusion of CO2. The swelling process of the CO2-octane binary system is shown in Figure 6 [80]. It was also found that when CO2 was injected into the system, the alkane chain was slightly extended, meaning that the presence of CO2 molecules caused the alkane molecules to expand, which further led to the expansion of the systemic volume. Regarding the study on the swelling behavior of CO2 with cycloalkanes, Sima et al. studied the vapor-liquid equilibrium of binary systems of CO2 with cycloalkanes (cyclopentane and cyclohexane) and showed that CO2 is more soluble and miscible in n-alkanes than in cycloalkanes [81]. Similar conclusions were obtained by Zhang et al. in their study of the solubility and volume expansion factors of CO2 in cycloalkanes. They believe that as the number of carbon atoms increases, the dispersibility between alkane molecules increase, the interactions between alkane molecules are enhanced, and the solubility of CO2 in alkanes decreases [82]. A large number of research works have investigated the solubility and volume expansion mechanism of CO2 in single alkane, brine, and alkane-water binary systems, while the microscopic mechanism of CO2 in hydrocarbon mixtures is not sufficiently clear. Therefore, the study of CO2 in hydrocarbon mixtures has received much attention. Wang et al. measured the volume expansion of CO2 and n-dodecane in fused silica capillaries using Raman spectroscopy. The results show that the expansion coefficient increases with the increase in pressure and decreases with the increase in temperature [83]. CO2 is less soluble in cycloalkanes and aromatics than in n-alkanes with the same number of carbon atoms. It is concluded that the solubility of CO2 in hydrocarbon mixture is mainly affected by high-carbon hydrocarbons through the above study, i.e., the higher the proportion of high-carbon hydrocarbons in the mixture, the lower the solubility of CO2 [84].

SC-CO2 Viscosity Reduction Characteristics in Heavy Oil
SC-CO2 is characterized by a large diffusion coefficient and a strong solvency capacity, and it can rapidly penetrate into the mixture [85,86]. When CO2 is dissolved in crude oil, the attraction force between oil molecules becomes smaller and the internal friction during flow is reduced due to the carboxylation reaction, thus the viscosity of the oil is reduced and the fluidity of the crude oil is improved. For heavy oil reservoirs, when a certain concentration of CO2 is injected into heavy oil, the internal intermolecular force changes from the liquid-liquid intermolecular force to the liquid-gas intermolecular

SC-CO 2 Viscosity Reduction Characteristics in Heavy Oil
SC-CO 2 is characterized by a large diffusion coefficient and a strong solvency capacity, and it can rapidly penetrate into the mixture [85,86]. When CO 2 is dissolved in crude oil, the attraction force between oil molecules becomes smaller and the internal friction during flow is reduced due to the carboxylation reaction, thus the viscosity of the oil is reduced and the fluidity of the crude oil is improved. For heavy oil reservoirs, when a certain concentration of CO 2 is injected into heavy oil, the internal intermolecular force changes from the liquid-liquid intermolecular force to the liquid-gas intermolecular force, and the intermolecular force is greatly reduced. Furthermore, the gum asphalt macromolecular structure of heavy oil will also be destroyed after dissolving CO 2 , the volume will be expanded, the density will be reduced, and the viscosity will be rapidly reduced [87].
The high content of asphaltene and gum in heavy oil leads to adsorption of micelles on gum to form a solvation layer. Therefore, the dispersed phase occupy a large volume fraction, the attractive interaction between the particles of the dispersed phase is strong, and the internal friction is large, so it has a high viscosity. The stronger is the interaction between colloidal particles and solvent, the higher is the degree of solvation, the higher is the bound solvent, the greater is the viscosity of the system. In recent years, researchers have conducted a lot of research on the effect of CO 2 flooding on viscosity reduction in heavy oil. Seyyedsar et al. suggested that CO 2 can cause methane in heavy oil to be released in the form of microbubbles. The release of methane from heavy oil results in an increase in oil viscosity, and this increase is significant for heavy oil systems. However, the dissolution of CO 2 in the oil will compensate for this viscosity increase. Experimental studies have shown that the saturation of CO 2 in heavy oil is generally not linearly related to the viscosity reduction rate of heavy oil. In other words, as long as a small amount of CO 2 is added to the oil, the viscosity of the heavy oil can be greatly reduced [88,89].
In order to further prove the viscosity reduction effect of CO 2 , Sun et al. compared the viscosity reduction effect of CO 2 and nitrogen on heavy oil. The experimental results show that the viscosity reduction effect of CO 2 on heavy oil is much better than that of N 2 under the same conditions. Meanwhile, with the increase in CO 2 pressure, the shear thinning feature becomes more and more obvious. With the decrease in temperature, the viscosity reduction rate of CO 2 on heavy oil increases. The main mechanism is that when CO 2 is dissolved in crude oil, the dispersion effect increases the distance between crude oil molecules, and ultimately reduces the viscosity of crude oil [90]. Regarding the effect of pressure on the viscosity reduction in CO 2 , Wang investigated the viscosity reduction in heavy oil by CO 2 flooding through a combination of software simulation and experiment. The main findings are shown in Figure 7 below. With the increase in CO 2 injection, the critical pressure of CO 2 -heavy oil system gradually increases, and the saturation pressure at reservoir temperature also gradually increases, and the viscosity of crude oil rapidly decreases as CO 2 is injected [91]. We can conclude that the affinity of CO 2 to asphaltene is greater than that of gum, and it can be adsorbed on asphaltene in the state of small molecules, replacing the original gum adsorption layer (solvated layer). On one hand, CO 2 releases small molecules that are bound in the solvation layer, reducing the attraction between molecules, allowing them to move freely, resulting in a decrease in system viscosity. On the other hand, CO 2 molecules are too small to form a thick adsorption layer, so that the asphaltene micelle are exposed. The volume fraction of the dispersed phase in the system is greatly reduced, and it is not easy for the micelles to interact with each other. The above factors cause a decrease in the viscosity of the heavy oil system.  [97]. After the CO2 was injected, the oil-gas ratio is increased to 236.06 m 3 /t, and the viscosity of formation oil is 1.104 mPa·s, the viscosity of crude oil is reduced by 36.73%, and the fluidity of crude oil is increased. CO2 dissolved in crude oil significantly reduces the viscosity of crude oil, and the higher the viscosity of crude oil, the greater is the reduction [98]. From the above data, we conclude that CO2 has high solubility in heavy oil, and the complete miscibility of CO2 with heavy oil can dilute heavy oil, which is the main reason that the viscosity of heavy oil decreases greatly and the recovery efficiency increases.

SC-CO2 Extraction
The principle of SC-CO2 extraction and separation is to use pressure and temperature to control the dissolution capacity of supercritical fluid, and then achieve the extraction and separation of substances. Hydrocarbons and various lipid organic compounds in the reservoir medium can be extracted when CO2 reaches supercritical state, and the material inside the matrix are dissolved in the process and flow out of the pores with the gas [99,100]. The pore is widened and the crude oil adsorbed on the matrix is resolved due to the extraction of SC-CO2, which changes the heavy oil from the adsorbed state to the free state, thereby causing the crude oil to flow out of the pore channels. This process also expands the passage of crude oil, allowing gas to enter the matrix more easily and also allows the crude oil to be extracted quickly.
Kesavan et al. investigated the recovery of oil from oil shale using supercritical extraction technology with CO2 as the solvent. Their work successfully demonstrated the The dissolution of CO 2 can significantly reduce oil viscosity has been reported in the literature, especially for heavy oil. The solubility of CO 2 in three heavy oils with different densities and the corresponding crude oil viscosity and density have been studied by Miller et al. at different temperatures and pressures. When there is no CO 2 , the viscosity of crude oil increases with the increase in pressure, while when there is CO 2 , the viscosity of crude oil decreases with the increase in pressure, and the viscosity of crude oil containing CO 2 is significantly reduced with the increase in temperature [92]. Li  The experimental results show that the gas-oil ratio of the crude oil saturated with CO 2 increased from 34 m 3 /t to 114 m 3 /t, and the viscosity of the crude oil decreased from 3.41 mPa·s to 1.92 mPa·s, a reduction of about 34% [95]. Zhao et al. carried out a feasibility study on CO 2 flooding in ultra-low-permeability reservoirs using laboratory experiments and numerical simulation. Similar to the results of many of the above researchers, it is observed that the amount of dissolved CO 2 in oil increases with the increase in pressure, and the viscosity of the heavy oil rapidly decreases. Under the formation pressure (18.18 MPa), the dissolved oil-gas ratio is 80.07 m 3 /t, and the crude oil viscosity is 1.745 mPa·s. When CO 2 is injected under this pressure, the formation oil viscosity is 1.104 mPa·s, and the crude oil viscosity is reduced by 36.73% [96]. Liu et al. studied the viscosity reduction effect of CO 2 flooding on ultra-low-permeability reservoir in Daqing Oilfield by using thin tubes and natural core. The experimental results show that under the formation pressure (18.2 MPa), the dissolved oil-gas ratio is 80.07 m 3 /t, and the crude oil viscosity is 1.745 mPa·s [97]. After the CO 2 was injected, the oil-gas ratio is increased to 236.06 m 3 /t, and the viscosity of formation oil is 1.104 mPa·s, the viscosity of crude oil is reduced by 36.73%, and the fluidity of crude oil is increased. CO 2 dissolved in crude oil significantly reduces the viscosity of crude oil, and the higher the viscosity of crude oil, the greater is the reduction [98]. From the above data, we conclude that CO 2 has high solubility in heavy oil, and the complete miscibility of CO 2 with heavy oil can dilute heavy oil, which is the main reason that the viscosity of heavy oil decreases greatly and the recovery efficiency increases.

SC-CO 2 Extraction
The principle of SC-CO 2 extraction and separation is to use pressure and temperature to control the dissolution capacity of supercritical fluid, and then achieve the extraction and separation of substances. Hydrocarbons and various lipid organic compounds in the reservoir medium can be extracted when CO 2 reaches supercritical state, and the material inside the matrix are dissolved in the process and flow out of the pores with the gas [99,100]. The pore is widened and the crude oil adsorbed on the matrix is resolved due to the extraction of SC-CO 2 , which changes the heavy oil from the adsorbed state to the free state, thereby causing the crude oil to flow out of the pore channels. This process also expands the passage of crude oil, allowing gas to enter the matrix more easily and also allows the crude oil to be extracted quickly.
Kesavan et al. investigated the recovery of oil from oil shale using supercritical extraction technology with CO 2 as the solvent. Their work successfully demonstrated the feasibility of using CO 2 as a solvent for extracting oil from oil shale, completing groundbreaking research on the utilization of SC-CO 2 for oil shale extraction [101]. Deo et al. found that two solvents, CO 2 and propane, exhibited strong extraction capacity for crude oils from light-chain alkanes to heavy-chain alkanes around their respective critical temperatures [102]. With further studies on crude oil extraction, Guiliano et al. found that only n-alkanes between C 14 and C 24 were present in the extract solution at a pressure of 130 bar, with few branched chain alkanes and cycloparaffins present. Normal alkanes were extracted up to C32 at a pressure of 300 bar. The results showed that with the increase in pressure (130-300 bar), a greater variety of branched chain alkanes and cycloparaffins were extracted, along with heavier aromatic compounds [103]. A similar study was performed by Mihkel Koel et al., which was different from Guiliano as they studied the application results of SC-CO 2 extraction at different temperatures. They found that pure CO 2 preferentially extracted n-alkanes [104]. Rudolf et al. studied the extraction of aliphatic and aromatic hydrocarbons from shale rock using SC-CO 2 . SC-CO 2 was found to be effective in extracting "free" hydrocarbons from samples in a lower temperature range [105].
Studies have shown that SC-CO 2 mainly extracts components below C 20 , and the existence of a pressure critical point in this extraction process ensures that the extraction proceeds smoothly [106]. As can be seen in Figure 8a, the carbon fraction of the oil production remains essentially unchanged before the gas breakthrough. From Figure 8a,b, it can be observed that at the same pressure of 25 MPa, the fractions of components below C 20 are 56.3% and 65.3%, respectively, while the ratio of components below C 20 in crude oil is 46.3% [107]. The extraction capacity of CO 2 increases with the increase in its density. The appropriate increase in pressure increases the density of CO 2 , and the extraction is easier to carry out. Factors affecting the optimum extraction temperature include the increase in diffusion coefficient due to warming and the decrease in CO 2 density, which together influence the magnitude of the optimum extraction temperature [108]. Peng et al. conducted a study on the content and viscosity of the components in the extracted material and concluded that the extraction of light hydrocarbon components from heavy oils is enhanced with increasing extraction pressure and temperature in CO 2 extraction process. As can be seen from Figure 9, with the increase in extraction pressure, the percentage of light components in the residue after CO 2 extraction is reduced by about 56% compared with the original oil sample. The results show that with the increase in pressure, the extraction effect of CO 2 on super heavy oil is enhanced, and the light components are continuously extracted [109]. When the pressure reaches a high level, according to the colloidal system theory of heavy oil, the original stable colloidal structure of heavy oil is disrupted, and the heavy asphaltenes agglomerate, leading to asphaltene precipitation [110].  Allawzi et al. concluded that SC-CO 2 extraction of oil is selective and preferentially extracts non-polar substances. It was found that CO 2 mainly extracted saturated hydrocarbon, olefins, and some aromatics in crude oil [111]. Small aromatic hydrocarbons (such as methylbenzene, methyl naphthalene, etc.) exist in the form of micelles in crude oil, while paraffin exists in the form of colloids. The original equilibrium state of small saturated hydrocarbons and aromatic hydrocarbons is disrupted by the extraction of SC-CO 2 , leading to the deposition of macromolecular compound [112]. Ni et al. further studied the selective extraction of SC-CO 2 . It was found that SC-CO 2 cannot completely extract all components from the oil, and it preferentially extracts saturates and leaves behind asphaltene. The results show that low-boiling and non-polar or lowpolar petroleum components can be quickly extracted from rocks using SC-CO 2 [113]. The selectivity of SC-CO 2 extraction of crude oil molecules under different pressures and temperatures was studied by Cao et al. [114]. SC-CO 2 preferentially extracts small molecules with relatively low polarity, while large molecules with relatively high aromaticity and polarity are not easily extracted using SC-CO 2 , and compounds containing multiple heteroatoms are more difficult to be extracted than hydrocarbons [115]. This is because non-polar saturated hydrocarbon molecules are less affected by the adsorption of other components, so they are easily extracted using SC-CO 2 . Aromatic hydrocarbons are less affected by the circumflex network structure of asphaltene and gum due to their smaller molecular size. In addition, SC-CO 2 molecules have weak polarity, making it easier to dissolve aromatic hydrocarbon molecules and enhance the diffusion coefficient of aromatic hydrocarbons [116].  Allawzi et al. concluded that SC-CO2 extraction of oil is selective and preferentially extracts non-polar substances. It was found that CO2 mainly extracted saturated hydrocarbon, olefins, and some aromatics in crude oil [111]. Small aromatic hydrocarbons (such as methylbenzene, methyl naphthalene, etc.) exist in the form of micelles in crude oil, while paraffin exists in the form of colloids. The original equilibrium state of small saturated hydrocarbons and aromatic hydrocarbons is disrupted by the extraction of SC-CO2, leading to the deposition of macromolecular compound [112]. Ni et al. further studied the selective extraction of SC-CO2. It was found that SC-CO2 cannot completely extract all components from the oil, and it preferentially extracts saturates and leaves behind asphaltene. The results show that low-boiling and non-polar or low-polar petroleum components can be quickly extracted from rocks using SC-CO2 [113]. The selectivity of SC-CO2

Nanoparticles Inhibit Asphaltene Deposition during CO 2 Flooding
When CO 2 gas is injected into the reservoir for oil displacement, the temperature and pressure in the reservoir change after CO 2 molecules contact with crude oil, breaking the dynamic stability of the dispersion system. As shown in Figure 10, CO 2 molecules compete with gum that coats the asphaltene surface for spatial positions after entering the crude oil. As a result, the force of forming the gum solvation layer is weakened, causing the gums that stabilize the asphaltene to continuously detach from the surface of the asphaltene particles [117]. Asphaltene particles that have lost their solvation layer coating may have attractive collision and aggregation under the interaction of electrostatic, dipole, and hydrogen bonding, which leads to asphaltene deposition [118]. The surface activity of asphaltene molecules is caused by the existence of polar groups, which will lead to self-association between asphaltene molecules, causing asphaltene aggregation and even deposition. This results in many problems such as blockage of reservoir pore throat, wettability reversal, and permeability decrease [119]. Therefore, solving or mitigating the issue of asphaltene deposition during CO 2 flooding processes is crucial for enhancing oil recovery in low-permeability reservoirs. and hydrogen bonding, which leads to asphaltene deposition [118]. The surface activity of asphaltene molecules is caused by the existence of polar groups, which will lead to selfassociation between asphaltene molecules, causing asphaltene aggregation and even deposition. This results in many problems such as blockage of reservoir pore throat, wettability reversal, and permeability decrease [119]. Therefore, solving or mitigating the issue of asphaltene deposition during CO2 flooding processes is crucial for enhancing oil recovery in low-permeability reservoirs. Figure 10. Asphaltene deposition during CO2 flooding, asphaltene (blue), aromatic hydrocarbon (yellow), gum (red), CO2 (green). Figure 10. Asphaltene deposition during CO 2 flooding, asphaltene (blue), aromatic hydrocarbon (yellow), gum (red), CO 2 (green).

Adsorption of Nanoparticles
Nanoparticles are considered to be one of the most promising solutions for asphaltene deposition due to their large specific surface area and adsorption capacity, better suspension and catalytic performance, and less susceptibility to reservoir damage compared to chemical agents. The strong polarity of the surface of asphaltenes is the fundamental reason for self-association and even deposition between asphaltene molecules. In the presence of nanoparticles, the strong polarity of asphaltenes can be exploited to inhibit asphaltene deposition and stabilize their dispersion in the crude oil system. By modifying the nanoparticles, on the one hand, the charge distribution on the surface of the particles can be changed, so that the particles will adsorb asphaltene after entering the reservoir, and asphaltene aggregation and deposition can be avoided. On the other hand, nanoparticles can be surface grafted so that the surface of the particles carries the corresponding polar groups, which can interact with asphaltene molecules after entering the reservoir and promote the stable dispersion of asphaltene. According to the DLVO theory, the strong polarity of the asphaltene and the surface charge of the nanoparticles facilitate an interaction between the two [120]. For example, silica nanoparticles containing hydroxyl groups and electronegativity can adsorb with heavy components that are interfacial activity. Moreover, silica nanoparticles can destroy the self-assembled structure of the heavy components of crude oil [36]. From Figure 11, it can be seen that silica nanoparticles are adsorbed on the collapsed layer, which proves that there is an interaction between silica nanoparticles and heavy components [121].
The surface charge of the nanoparticles can be adjusted by changing the pH of the nanofluid. Moreover, nanoparticles have strong fluidity in porous media and possess high surface activity and specific surface area. Therefore, they can adsorb the asphaltenes in crude oil, thereby inhibiting asphaltene deposition [122,123]. A Fe 3 O 4 -shell polyose nanocomposite was prepared by Panahi et al. This composite material exhibits a stronger capacity for adsorbing asphaltenes compared to single Fe 3 O 4 nanoparticles. Its asphaltene adsorption isotherm is consistent with the Freundlich model, which further confirms the existence of self-association and multilayer adsorption of asphaltene on the nanoparticles [124]. Asphaltenes in crude oil tend to rapidly aggregate and deposit in low-permeability reservoirs during CO 2 flooding. When the nanofluid is injected, the asphaltene will be adsorbed by the nanoparticles, making it stably dispersed in the crude oil system, as shown in Figure 12.
asphaltene aggregation and deposition can be avoided. On the other hand, nanoparticles can be surface grafted so that the surface of the particles carries the corresponding polar groups, which can interact with asphaltene molecules after entering the reservoir and promote the stable dispersion of asphaltene. According to the DLVO theory, the strong polarity of the asphaltene and the surface charge of the nanoparticles facilitate an interaction between the two [120]. For example, silica nanoparticles containing hydroxyl groups and electronegativity can adsorb with heavy components that are interfacial activity. Moreover, silica nanoparticles can destroy the self-assembled structure of the heavy components of crude oil [36]. From Figure 11, it can be seen that silica nanoparticles are adsorbed on the collapsed layer, which proves that there is an interaction between silica nanoparticles and heavy components [121]. The surface charge of the nanoparticles can be adjusted by changing the pH of the nanofluid. Moreover, nanoparticles have strong fluidity in porous media and possess high surface activity and specific surface area. Therefore, they can adsorb the asphaltenes in crude oil, thereby inhibiting asphaltene deposition [122,123]. A Fe3O4-shell polyose nanocomposite was prepared by Panahi et al. This composite material exhibits a stronger capacity for adsorbing asphaltenes compared to single Fe3O4 nanoparticles. Its asphaltene adsorption isotherm is consistent with the Freundlich model, which further confirms the existence of self-association and multilayer adsorption of asphaltene on the nanoparticles [124]. Asphaltenes in crude oil tend to rapidly aggregate and deposit in low-permeability reservoirs during CO2 flooding. When the nanofluid is injected, the asphaltene will be adsorbed by the nanoparticles, making it stably dispersed in the crude oil system, as shown in Figure 12.

Dispersion of Nanoparticles
The self-association between asphaltene molecules will accelerate the flocculation and deposition of asphaltene. The dispersion of asphaltene by nanoparticles is mainly based on the formation of stable interaction force or space steric hindrance between the nanoparticles and asphaltene molecules. The dispersion effect disrupts the self-aggregation of asphaltene molecules, thereby inhibiting asphaltene deposition and removing asphaltene aggregates [125]. The surface-modified nanoparticles are prepared into nanofluid suspension and injected into the reservoir. When the nanoparticles enter the space between the gum and asphaltene, they can bind to asphaltene through dipole interaction, charge-transfer complexing interaction, and hydrogen-bonding interaction. An alkyl space stabilizing layer is established on the surface of asphaltene molecules, thereby dispersing the asphaltene and preventing its self-aggregation, and thus stabilizing the as-

Dispersion of Nanoparticles
The self-association between asphaltene molecules will accelerate the flocculation and deposition of asphaltene. The dispersion of asphaltene by nanoparticles is mainly based on the formation of stable interaction force or space steric hindrance between the nanoparticles and asphaltene molecules. The dispersion effect disrupts the self-aggregation of asphaltene molecules, thereby inhibiting asphaltene deposition and removing asphaltene aggregates [125]. The surface-modified nanoparticles are prepared into nanofluid suspension and injected into the reservoir. When the nanoparticles enter the space be-tween the gum and asphaltene, they can bind to asphaltene through dipole interaction, charge-transfer complexing interaction, and hydrogen-bonding interaction. An alkyl space stabilizing layer is established on the surface of asphaltene molecules, thereby dispersing the asphaltene and preventing its self-aggregation, and thus stabilizing the asphaltene and preventing it from being deposited [126]. As shown in Figure 13, the surface-modified nanoparticles are prepared into a nanofluid suspension and injected into the reservoir. When the nanoparticles enter the space between the gum and asphaltene, they bind together with the asphaltene through the effects of dipole interactions, charge transfer, and hydrogen bonding. The asphaltene molecules form a stable layer on the surface, which in turn disperses the asphaltene, avoiding self-aggregation and stabilizing the asphaltene to prevent deposition. Setoodeh found that the presence of multiple sulfur heterocycles in the structure of PT, which produce higher polarity in PT and can form stronger interactions with heteroatoms such as N, S, and O in asphaltene molecules. This creates more effective PT-coated nanoparticles than Fe 3 O 4 nanoparticles in inhibiting asphaltene deposition [127]. Nanofluids can further strip the heavy oil in the pores where CO2 does not enter through the CO2 displacement channel. Nanofluids can change the wettability of the pore surface, so that the oil on the surface of the micropore is stripped into oil droplets during the CO2 flooding process. The advantage of the synergistic effect of the two is that nanofluids can not only change the reservoir wettability, but also increase the water injection capacity. Moreover, it can inhibit the pointing phenomenon and provide a larger sweep area for subsequent CO2 flooding [128,129]. In fact, nanoparticles are considered to be effective additives for increasing sweep efficiency, and can also increase the viscosity and density of SC-CO2. In Cao et al.'s experiment on water-based nanofluid-alternating-CO2 injection, it was found that the mass content of C10~C16 intermediate components in the crude oil extracted using NWAG was 9.55%, which was much lower than that of water-alternatinggas (WAG). The results show that after emulsification with nanofluids, CO2 can extract more intermediate components from crude oil, which improves the interaction between crude oil and CO2 [121]. The above studies focused on the development of mathematical models for water-based nanofluids, so SC-CO2-based nanofluids were studied by Dezfuli et al. The results indicate that for heavy oil reservoirs, the maximum ultimate recovery of heavy oil obtained by injection of SC-CO2 is 27.82% under the condition of 5.0 vol. % nanoparticle concentration [130].

Polymer Improves CO2 Channeling
CO2 flooding has the disadvantage of low sweep efficiency, which is mainly caused by gas flow in the high-permeability area of heterogeneous reservoir, viscous fingering caused by viscosity difference between oil and gas, and gravity override caused by density difference between oil and gas [131]. The main reason for CO2 gas channeling is that the viscosity of CO2 is much smaller than that of formation water and crude oil, and the viscosity pointing caused by the unfavorable mobility ratio, which makes the injected CO2 bypass the crude oil and crossflow occurs, and the sweep efficiency decreases. The heterogeneity of the reservoir causes injected CO2 to form channeling paths along high-permeability zones, which will affect the sweep efficiency [132].
PAM gel is a conventional crosslinked gel polymer, which is mainly composed of Figure 13. Schematic diagram illustrating the mechanism of nanoparticle dispersion inhibiting asphaltene deposition.
Nanofluids can further strip the heavy oil in the pores where CO 2 does not enter through the CO 2 displacement channel. Nanofluids can change the wettability of the pore surface, so that the oil on the surface of the micropore is stripped into oil droplets during the CO 2 flooding process. The advantage of the synergistic effect of the two is that nanofluids can not only change the reservoir wettability, but also increase the water injection capacity. Moreover, it can inhibit the pointing phenomenon and provide a larger sweep area for subsequent CO 2 flooding [128,129]. In fact, nanoparticles are considered to be effective additives for increasing sweep efficiency, and can also increase the viscosity and density of SC-CO 2 . In Cao et al.'s experiment on water-based nanofluid-alternating-CO 2 injection, it was found that the mass content of C10~C16 intermediate components in the crude oil extracted using NWAG was 9.55%, which was much lower than that of water-alternatinggas (WAG). The results show that after emulsification with nanofluids, CO 2 can extract more intermediate components from crude oil, which improves the interaction between crude oil and CO 2 [121]. The above studies focused on the development of mathematical models for water-based nanofluids, so SC-CO 2 -based nanofluids were studied by Dezfuli et al. The results indicate that for heavy oil reservoirs, the maximum ultimate recovery of heavy oil obtained by injection of SC-CO 2 is 27.82% under the condition of 5.0 vol. % nano-particle concentration [130].

Polymer
Enhanced CO 2 Flooding 4.2.1. Polymer Improves CO 2 Channeling CO 2 flooding has the disadvantage of low sweep efficiency, which is mainly caused by gas flow in the high-permeability area of heterogeneous reservoir, viscous fingering caused by viscosity difference between oil and gas, and gravity override caused by density difference between oil and gas [131]. The main reason for CO 2 gas channeling is that the viscosity of CO 2 is much smaller than that of formation water and crude oil, and the viscosity pointing caused by the unfavorable mobility ratio, which makes the injected CO 2 bypass the crude oil and crossflow occurs, and the sweep efficiency decreases. The heterogeneity of the reservoir causes injected CO 2 to form channeling paths along highpermeability zones, which will affect the sweep efficiency [132].
PAM gel is a conventional crosslinked gel polymer, which is mainly composed of polyacrylamide macromolecules and a crosslinking agent. It has the advantages of low adsorption loss, insensitivity to bacterial attack, and easy dissolution [133]. As a weak gel, HPAM preferentially enters the high-permeability region through porous media by flowing and undergoing stretching deformation along the large pores. This behavior can reduce the permeability of high-permeability layers, improve the intralayer heterogeneity of reservoir, expand the swept volume, and thus enhance oil recovery [134]. HPAM contains a large number of hydrophilic groups such as carboxyl and amide groups, and the electrostatic repulsion between carboxyl groups can unfold its main chain. The hydration and electrostatic repulsion of hydrophilic groups increase the volume of gel particles, showing a larger hydrodynamics radius. Simultaneously, the three-dimensional network structure formed by crosslinking allows it to possess a certain degree of strength, enabling it to create blockages in the deeper layers of the reservoir and alter the flow direction of the fluid [135,136]. As shown in Figure 14, Al-Ali et al. found that low concentration of HPAM gel has weaker strength and would flow with the produced oil, and only a small part played the role of blocking CO 2 . However, it is effective to inject high concentration HPAM gel to block the permeation channel or crack [137]. The study conducted by Sun et al. revealed that the polyacrylamide-chromium(III) polymer gel would be degraded when it is in contact with CO 2 . Therefore, after the gel in the long-term CO 2 environment is degraded, a channel will be formed inside it, that is, the gel breaks through, thereby reducing the plugging efficiency of the polymer gel [138]. In summary, delayed crosslinked PAM can effectively block channeling and improve sweep efficiency, which is suitable for high temperature and high salt reservoirs. However, it has disadvantages such as uncontrollable gel time, easy blockage, and damage to the formation.  [135,136]. As shown in Figure 14, Al-Ali et al. found that low concentration of HPAM gel has weaker strength and would flow with the produced oil, and only a small part played the role of blocking CO2. However, it is effective to inject high concentration HPAM gel to block the permeation channel or crack [137]. The study conducted by Sun et al. revealed that the polyacrylamide-chromium(III) polymer gel would be degraded when it is in contact with CO2. Therefore, after the gel in the long-term CO2 environment is degraded, a channel will be formed inside it, that is, the gel breaks through, thereby reducing the plugging efficiency of the polymer gel [138]. In summary, delayed crosslinked PAM can effectively block channeling and improve sweep efficiency, which is suitable for high temperature and high salt reservoirs. However, it has disadvantages such as uncontrollable gel time, easy blockage, and damage to the formation. Preformed particle gel (PPG) is typically formed by PAM or HPAM with crosslinking agents on the ground to form gel particles. Both retarding crosslinking HPAM and precrosslinking gel particles diverting CO2 to the low-permeability zone by plugging highpermeability zones to improve swept efficiency. Zhou et al. found that AR-PPG exhibited better swelling and shear resistance in acidic environments. This is mainly due to the fact that the electrostatic repulsion between the cationic group and H+ and the steric hindrance effect between the sulfonic acid groups make the polymer chain difficult to be compressed, thereby increasing the acid resistance and shear resistance of AR-PPG [139]. The large presence of CO2 leads to an acidic environment in the reservoir during CO2 flooding. The development of PPG gel has resolved the issue of reduced plugging efficiency caused by the degradation of PAM in acidic reservoirs. IPN-ASSAP polymer gels were synthesized by Pu et al., which exhibit excellent CO2 responsiveness. CO2 will change the particle size, strength, and other properties of the particles, thereby improving the plugging capacity [140]. In conclusion, the research on PPG polymer gels has addressed the shortcomings of traditional PAM gels, which cannot remain stable in acidic environments for a long time. However, preformed particle gel still have the disadvantages of being too large in size, having a fast water absorption rate, and being difficult to inject.

Polymer Enhanced Stability of CO2 Foam
In the subsurface environment, SC-CO2 has lower viscosity and the density of SC-CO2 is lower than that of water and heavy oil, which leads to the phenomenon of viscous Preformed particle gel (PPG) is typically formed by PAM or HPAM with crosslinking agents on the ground to form gel particles. Both retarding crosslinking HPAM and precrosslinking gel particles diverting CO 2 to the low-permeability zone by plugging highpermeability zones to improve swept efficiency. Zhou et al. found that AR-PPG exhibited better swelling and shear resistance in acidic environments. This is mainly due to the fact that the electrostatic repulsion between the cationic group and H+ and the steric hindrance effect between the sulfonic acid groups make the polymer chain difficult to be compressed, thereby increasing the acid resistance and shear resistance of AR-PPG [139]. The large presence of CO 2 leads to an acidic environment in the reservoir during CO 2 flooding. The development of PPG gel has resolved the issue of reduced plugging efficiency caused by the degradation of PAM in acidic reservoirs. IPN-ASSAP polymer gels were synthesized by Pu et al., which exhibit excellent CO 2 responsiveness. CO 2 will change the particle size, strength, and other properties of the particles, thereby improving the plugging capacity [140]. In conclusion, the research on PPG polymer gels has addressed the shortcomings of traditional PAM gels, which cannot remain stable in acidic environments for a long time. However, preformed particle gel still have the disadvantages of being too large in size, having a fast water absorption rate, and being difficult to inject.

Polymer Enhanced Stability of CO 2 Foam
In the subsurface environment, SC-CO 2 has lower viscosity and the density of SC-CO 2 is lower than that of water and heavy oil, which leads to the phenomenon of viscous fingering and gravity override in the process of reservoir seepage. The above phenomenon will lead to a reduction in its wave coefficient and seriously weaken the effect of the recovery rate. It has been demonstrated that CO 2 foam can effectively adjust the section plane of the displacement front and reduce the fluidity of CO 2 [141]. The generating ability and stability of foam can effectively improve the sweep coefficient of foam flooding. However, the high solubility of CO 2 in water accelerates the diffusion rate of CO 2 through the liquid film, resulting in CO 2 foam generally being less stable than nitrogen foam [142,143]. Therefore, how to effectively improve the stability of CO 2 foam has attracted much attention in recent years [144].
Polymer-reinforced foam is a kind of oil displacement system in which a polymer is added to the foam as a foam stabilizer. In recent years, polymer-reinforced foam systems have been extensively reported in CO 2 foam flooding. Lv et al. found that with the addition of HPAM, the drainage rate of CO 2 foam film decreased. The liquid inside the foam film is not easily lost, and the permeability of the liquid film is reduced, inhibiting the diffusion of gas within the foam. In the experimental range, when the concentration of HPAM is 0.025%, the CO 2 foam half-life more than doubled and reached a maximum. If the polymer is added in excess, the foamability will be greatly reduced [145]. This is mainly because foam stability is primarily related to film drainage rate, Marangoni repair effect for the film, foam disproportionation rate, and liquid-sheet disintegration rate. The viscosity of the solution increases substantially with the addition of polymer. According to the film drainage rate formula, the film drainage rate decreases and the liquid film thickness increases when the solution viscosity increases. It also reduces the gas diffusion rate between the bubbles and decreases the foam disproportionation rate. On a macroscopic level, the foam exhibits higher stability [146].
3η c r f ilm ∆P f ilm V RE : film drainage rate, m/s, h f : liquid film thickness, m, t: time, s, r f ilm : liquid film curvature radius, m, η c : solution viscosity, Pa·s, and P f ilm : pressure difference on both sides of liquid film, Pa.
Within a certain mass concentration range, polymers can increase the viscosity of the foam system, increase the thickness of the foam film, reduce the film drainage rate and diffusion rate of the foam, and enhance the stability of the foam [147]. This view was also confirmed in the experiments of Zhang et al. Hydroxypropyl methyl cellulose (HPMC) can be used as a foam stabilizer to effectively improve the stability of the foam, forming a polymer-reinforced CO 2 foam system. However, the foaming ability of the foaming agent system will be weakened by excessively high polymer quality fraction [148]. In addition, the addition of PAM to the foam solution also improves the strength of the liquid film surface, thereby reducing the emission of liquid in the foam and minimizing the diffusion of the gas phase [149].
The above studies only introduce the stability mechanism of polymer on CO 2 foam from the macro aspect, and some researchers have carried out relevant discussions on the micro scale. Polymer-reinforced properties of CO 2 foam depend on the type of polymer. Pu et al. found that the CHSB-nonionic polyacrylamide system was more stable than the CHSB-anionic polyacrylamide system. Specifically, the foam reinforced with xanthan gum exhibited the best stability. As can be seen from Figure 15, the shape of the CHSB foam changes to a polyhedral shape over time, while the polymer-reinforced foam has a smaller change in size [150]. Yang et al. found that the three-dimensional network spatial structure of acid-resistant hydrophobic polymer nanospheres prompts them to form a "skeleton" at the gas-liquid interface. It increases the strength of the liquid film and regulates the viscoelasticity and liquid storage capacity of the liquid film. Polymer nanospheres swell and release free water, which prevents the rupture of liquid films and increases foam stability. Figure 16 shows the mechanism of stabilizing CO 2 foam with nanospheres [41].

Surfactants Improve CO2 Flooding
In order to improve the effect of heavy oil mining, various additives are often used to assist CO2 to further increase the EOR. After the addition of a surfactant, the solubility of CO2 in crude oil under high pressure conditions increases, but the increase is not significant. The main reason is that CO2 is a non-polar substance, while surfactants have the capability to alter the properties of CO2, thereby increasing its solubility in crude oil [151,152]. In general, the carbon atoms on the carbon chain of surfactants (C12-C18) belong to the light components of crude oil. When the surfactant is added, it disrupts the initial oil-gas phase equilibrium of crude oil, so that CO2 can extract more light components in the crude oil [153]. The high content of macromolecular gums and asphaltenes in heavy oil is the main factor leading to a high value of the MMP. With the addition of surfactants,

Surfactants Improve CO2 Flooding
In order to improve the effect of heavy oil mining, various additives are often used to assist CO2 to further increase the EOR. After the addition of a surfactant, the solubility of CO2 in crude oil under high pressure conditions increases, but the increase is not significant. The main reason is that CO2 is a non-polar substance, while surfactants have the capability to alter the properties of CO2, thereby increasing its solubility in crude oil [151,152]. In general, the carbon atoms on the carbon chain of surfactants (C12-C18) belong to the light components of crude oil. When the surfactant is added, it disrupts the initial oil-gas phase equilibrium of crude oil, so that CO2 can extract more light components in the crude oil [153]. The high content of macromolecular gums and asphaltenes in heavy oil is the main factor leading to a high value of the MMP. With the addition of surfactants,

Surfactants Improve CO 2 Flooding
In order to improve the effect of heavy oil mining, various additives are often used to assist CO 2 to further increase the EOR. After the addition of a surfactant, the solubility of CO 2 in crude oil under high pressure conditions increases, but the increase is not significant. The main reason is that CO 2 is a non-polar substance, while surfactants have the capability to alter the properties of CO 2 , thereby increasing its solubility in crude oil [151,152]. In general, the carbon atoms on the carbon chain of surfactants (C 12 -C 18 ) belong to the light components of crude oil. When the surfactant is added, it disrupts the initial oil-gas phase equilibrium of crude oil, so that CO 2 can extract more light components in the crude oil [153]. The high content of macromolecular gums and asphaltenes in heavy oil is the main factor leading to a high value of the MMP. With the addition of surfactants, the internal structure of the molecules of the heavy oil is disrupted and their content is reduced, thus allowing the properties of the crude oil to change. Surfactants with polar groups such as ester groups and hydroxyl groups have the ability to form strong hydrogen bonds with hydroxyl or amino groups in gums and asphaltenes. Hydrogen bonding causes the molecular structure to be branched and the cohesive energy of the crude oil to be reduced, which plays a role in viscosity reduction [154,155]. The surfactant forms reverse micelle or microemulsion structure with CO 2 and crude oil. The polar groups of surfactants form a polar core with the polar components in crude oil through hydrogen bonding. The polar groups of surfactants form a polar core with the polar components in crude oil through hydrogen bonding, and polar macromolecules such as asphaltenes and gums are encapsulated within it. The highly branched hydrophobic alkyl chains extend into CO 2 and aggregate with each other by van der Waals force and thus increasing the extent of CO 2 miscibility in crude oil [156][157][158]. When the surfactant spontaneously accumulates at the two-phase interface, the interaction between the CO 2 -philic end and CO 2 is close to the interaction between the oil-wet end and crude oil. The pressure difference between the two phases decreases, causing the interfacial tension between the oil and gas phases to decrease.

Surfactants on Foaming Properties and Foam Stability of CO 2 Foam
The surfactant is injected before the CO 2 injection, and foam is generated when the surfactant comes into contact with the CO 2 . It can selectively block the high-permeability channeling paths, improve the heterogeneity of the formation, and expand the swept volume, which effectively delays the time of CO 2 channeling and prolongs the contact time between CO 2 and the remaining oil [159]. Foaming ability and foam stability are two important properties to consider in CO 2 foam flooding. Surfactants, with their characteristics of fast foaming speed, high foam output, and high foaming ability at lower concentrations, are typical chemical agents used in assisting CO 2 flooding. Therefore, the foaming ability of surfactants has been extensively studied by researchers. Jones et al. suggest that as the kinetic energy of surfactant molecules increases, they are more likely to adsorb at the gas-liquid interface. A greater adsorption amount indicates a reduction in surface tension, which benefits the foaming ability of EAB surfactants [160]. This is because the generation of bubbles is related to surface tension, as shown in the following equation.
W e = Gµ S R γ G: shearing stress, µ S :viscosity of continuous phase, R: bubble radius, γ: IFT [161]. However, the link between interfacial tension and foamability has been viewed differently by researchers. Some scholars believe that the diffusion rate of surfactants increases with the maximum rate of decrease in interfacial tension. As a result, the diffusion rate of foaming properties also increases [162]. Another group of researchers believed that the excessive adsorption of surfactants leads to the disappearance of the interfacial tension differential value, which may result in damage of foaming or the cessation of the Marangoni effect [163]. The different perspectives arise from the different methods of forming CO 2 foam [164,165]. Foam stability is determined by the interaction of interfacial tension, elasticity, temperature, and pressure. For example, when the bubbles expand, the decrease in surfactant concentration at the expansion site causes a change in interfacial tension. At this time, the surfactant migrates to the surface of the thin film, compensating for the thinning of the film [166]. CO 2 dissolves in water, causing the aqueous solution to become acidic, which will accelerate the diffusion rate of CO 2 through the liquid film. Therefore, it is difficult for conventional surfactants to maintain the stability of CO 2 foam for a long time. Nonionic surfactant with an affinity for CO 2 have attracted the attention of researchers [167][168][169].
Niu et al. discovered that EAB surfactants form worm-like micelles in foam solutions, increasing the diffusion resistance of CO 2 between bubbles. At the same time, the wormlike micelles increase the interfacial viscosity and reduce the drainage rate of the liquid film. The mechanism of EAB surfactant stabilizing CO 2 foam is shown in Figure 17 [170].
Molecules 2023, 28, x FOR PEER REVIEW 22 of 31 micelles increase the interfacial viscosity and reduce the drainage rate of the liquid film. The mechanism of EAB surfactant stabilizing CO2 foam is shown in Figure 17 [170]. Figure 17. Schematic diagram of the CO2 foam stabilization mechanism and instability process for EAB [170].

Surfactants Reduce the Minimum Miscible Pressure (MMP) of CO2 Flooding
CO2 is a non-polar molecule, which has poor solubility with polar macromolecules such as gum and asphaltene in crude oil. In order to improve their miscibility, it is an effective method to add suitable surfactants to reduce the interfacial tension between CO2 and crude oil. Table 1 summarizes the experimental data of surfactants reducing the MMP between CO2 and crude oil. CO2 is a weak solvent with low dielectric constant and low polarity, which causes most surfactants to be insoluble or slightly soluble in SC-CO2. The hydrophobic tail chain of the gas-soluble surfactants contain functional groups have an affinity for CO2, thereby enhancing the compatibility between surfactants and CO2. In addition to this, it has a low cohesive energy density, reducing the interaction between CO2 and surfactants. The branched chain on the hydrophilic group increases the space steric hindrance, and the more flexible the molecular chain is, the better the compatibility with CO2. Luo et al. showed that the surfactant CiPOj significantly reduced the IFT between CO2 and crude oil, Figure 17. Schematic diagram of the CO 2 foam stabilization mechanism and instability process for EAB [170].

Surfactants Reduce the Minimum Miscible Pressure (MMP) of CO 2 Flooding
CO 2 is a non-polar molecule, which has poor solubility with polar macromolecules such as gum and asphaltene in crude oil. In order to improve their miscibility, it is an effective method to add suitable surfactants to reduce the interfacial tension between CO 2 and crude oil. Table 1 summarizes the experimental data of surfactants reducing the MMP between CO 2 and crude oil. CO 2 is a weak solvent with low dielectric constant and low polarity, which causes most surfactants to be insoluble or slightly soluble in SC-CO 2 . The hydrophobic tail chain of the gas-soluble surfactants contain functional groups have an affinity for CO 2 , thereby enhancing the compatibility between surfactants and CO 2 . In addition to this, it has a low cohesive energy density, reducing the interaction between CO 2 and surfactants. The branched chain on the hydrophilic group increases the space steric hindrance, and the more flexible the molecular chain is, the better the compatibility with CO 2 . Luo et al. showed that the surfactant C i PO j significantly reduced the IFT between CO 2 and crude oil, and the extent of CO 2 miscibility with crude oil could be directly observed. In the scenario where the dosage of C i PO j is 0.6% and the temperature is 60 • C, the MMP and first contact miscibility pressure of the CO 2 and crude oil systems decreased from 19.1 MPa and 43.0 MPa to 13.8 MPa and 19.0 MPa, respectively [176]. The study by Sun et al. found that diisobutyl citrate can reduce the MMP between CO 2 and oil. Injecting surfactants through the slug method can improve the EOR compared to CO 2 flooding [181]. Currently, research on reducing the MMP between CO 2 and oil systems using gas-soluble surfactants is in its preliminary stage, with shortcomings such as low degradability and high toxicity, which limits their application.
Based on the above reasons, oil-soluble surfactants have attracted the attention of researchers. The study conducted by Wu et al. demonstrates that adding a concentration of 0.1% to 0.5% of surfactant (composed of a mixture of five surfactants) in crude oil can effectively reduce the oil-gas interfacial tension. Among them, the addition of 0.5% mixbenzene (aromatic hydrocarbon mixture) achieved the highest reduction, reaching 25.51%. The addition of mixed benzene increases the light hydrocarbon component of the crude oil and reduces the viscosity of the crude oil, which is conducive to the dissolution of CO 2 in the crude oil and reduces the interfacial tension between the CO 2 and the crude oil [171]. The oil displacement mechanism of oil-soluble surfactants and CO 2 -soluble surfactants are compared in Figure 18, highlighting the limitations of oil-soluble surfactants. The development of amphiphilic surfactants is the main research direction at present [179]. Yang et al. found that acetyl glucose is a CO 2 -philic end and aliphatic hydrocarbon is oil-wet end. Therefore, the amphiphilic acetyl glucose dodecyl ester can reduce the interfacial tension, and the addition of a 1% concentration of the reagent reduced the MMP by 27.47% [155].  [181]. Currently, research on reducing the MMP between CO2 and oil systems using gas-soluble surfactants is in its preliminary stage, with shortcomings such as low degradability and high toxicity, which limits their application. Based on the above reasons, oil-soluble surfactants have attracted the attention of researchers. The study conducted by Wu et al. demonstrates that adding a concentration of 0.1% to 0.5% of surfactant (composed of a mixture of five surfactants) in crude oil can effectively reduce the oil-gas interfacial tension. Among them, the addition of 0.5% mixbenzene (aromatic hydrocarbon mixture) achieved the highest reduction, reaching 25.51%. The addition of mixed benzene increases the light hydrocarbon component of the crude oil and reduces the viscosity of the crude oil, which is conducive to the dissolution of CO2 in the crude oil and reduces the interfacial tension between the CO2 and the crude oil [171]. The oil displacement mechanism of oil-soluble surfactants and CO2-soluble surfactants are compared in Figure 18, highlighting the limitations of oil-soluble surfactants. The development of amphiphilic surfactants is the main research direction at present [179]. Yang et al. found that acetyl glucose is a CO2-philic end and aliphatic hydrocarbon is oil-wet end. Therefore, the amphiphilic acetyl glucose dodecyl ester can reduce the interfacial tension, and the addition of a 1% concentration of the reagent reduced the MMP by 27.47% [155].

Conclusions and Prospect
Low-permeability heavy oil reservoirs typically have low permeability and high porosity, which pose challenges to the flow of CO2 and its oil displacement efficiency. CO2 may encounter greater resistance in low-permeability reservoirs, resulting in poor mobility and limiting its diffusion capacity within the reservoir, leading to lower recovery. Heavy oil has higher viscosity and temperature, which increases the complexity of the interaction between CO2 and oil, and the solubility and diffusion rate of CO2 are influenced by temperature and viscosity. In addition, in low-permeability heavy oil reservoirs, it is a challenge for SC-CO2 to maintain the required temperature and pressure throughout the reservoir. Low-permeability heavy oil reservoir typically exhibit reservoir homogeneity,

Conclusions and Prospect
Low-permeability heavy oil reservoirs typically have low permeability and high porosity, which pose challenges to the flow of CO 2 and its oil displacement efficiency. CO 2 may encounter greater resistance in low-permeability reservoirs, resulting in poor mobility and limiting its diffusion capacity within the reservoir, leading to lower recovery. Heavy oil has higher viscosity and temperature, which increases the complexity of the interaction between CO 2 and oil, and the solubility and diffusion rate of CO 2 are influenced by temperature and viscosity. In addition, in low-permeability heavy oil reservoirs, it is a challenge for SC-CO 2 to maintain the required temperature and pressure throughout the reservoir. Low-permeability heavy oil reservoir typically exhibit reservoir homogeneity, resulting in differences in rock properties and fluid distribution. This heterogeneity will affect the sweep efficiency and the distribution of CO 2 in the reservoir, resulting in uneven recovery. Due to the low permeability of the reservoir, the transfer rate of CO 2 is slow, and it is easy to take shortcuts, which will also lead to uneven distribution of CO 2 . Meanwhile, the migration path and dose control of CO 2 are the key issues. In addition, CO 2 can affect wellbore integrity, lead to cement degradation or casing corrosion, and can cause reservoir damage such as oil well plugging and pore collapse, thus impacting the long-term stability of the well. Ensuring the safe capture, transport, and storage of CO 2 and reducing its impact on the environment is also a major challenge.
The article provides a detailed description of the main oil recovery mechanisms of SC-CO 2 in low-permeability heavy oil reservoirs, as well as the improvement effect of nanoparticles, polymers, and surfactants on the defects of CO 2 flooding. The dissolution of CO 2 expands the volume of heavy oil, which can increase the elastic strain energy of formation, and thus increase the internal kinetic energy of crude oil. Capillary resistance and flow resistance are greatly reduced, the volume of formation void is increased, the flow of oil flow in rock pores is promoted, and the oil recovery rate is improved. CO 2 interacts with heavy oil molecules through physical adsorption and chemical reactions. The infiltration of CO 2 disrupts the internal structure and arrangement of heavy oil, breaking the adhesion force between oil molecules and reducing the viscosity of heavy oil, thereby improving its flowability. CO 2 extracts light and heavy components in heavy oil or vaporizes them, thereby reducing the surface tension of oil-water interface, reducing residual oil saturation, and thereby increasing crude oil recovery. Asphaltene deposition, gas channeling, stability of CO 2 foam, and reduction in minimum reverberation pressure are all problems to be considered in CO 2 flooding. Therefore, this paper focuses on the improvement mechanism of nanoparticles, polymers, and surfactants on CO 2 flooding. In response to the above challenges and the progress of current research, more laboratory studies and numerical simulations are needed to understand the interaction and flow mechanisms between CO 2 and heavy oil. In addition, new dosage control methods need to be further developed to enhance the fluidity and solubility of CO 2 , and advanced monitoring and evaluation techniques should be employed to optimize the SC-CO 2 flooding process.