Development and Applications of CO2-Responsive Gels in CO2 Flooding and Geological Storage

Gel systems are widely used as plugging materials in the oil and gas industry. Gas channeling can be mitigated by reducing the heterogeneity of the formation and the mobility ratio of CO2 to crude oil. Cracks and other CO2 leaking pathways can be plugged during the geological storage of CO2 to increase the storage stability. By adding CO2-responsive groups to the classic polymer gel’s molecular chain, CO2 responsive gel is able to seal and recognize CO2 in the formation while maintaining the superior performance of traditional polymer gel. The application of CO2 responsive gels in oil and gas production is still in the stage of laboratory testing on the whole. To actually achieve the commercial application of CO2 responsive gels in the oil and gas industry, it is imperative to thoroughly understand the CO2 responsive mechanisms of the various types of CO2 responsive gels, as well as the advantages and drawbacks of the gels and the direction of future development prospects. This work provides an overview of the research progress and response mechanisms of various types of CO2 responsive groups and CO2 responsive gels. Studies of the CO2 responsive gel development, injectivity, and plugging performance are comprehensively reviewed and summarized. The shortcomings of the existing CO2 responsive gels system are discussed and the paths for future CO2 responsive gel development are suggested.


Introduction
The demand for energy is growing worldwide, and the majority of the energy that people need is currently provided by fossil fuels [1].This also leads to the release of a large amount of greenhouse gases such as CO 2 , CH 4 , N 2 O, HFCs, PFCs, and ReF 6 into the atmosphere, causing the Earth's temperature to rise day by day.According to the National Weather Service, the earth's temperature has risen by 0.7 • C since the 19th century [2].CO 2 is one greenhouse gas and makes up more than 60% of the greenhouse effect.The global cumulative emission reduction in CCUS is 5.5 × 10 11 to 1.017 × 10 12 t CO 2 to accomplish the goal of a 1.5 • C temperature rise control by the year 2100.The potential of CCUS to reduce global emissions has been assessed by the International Energy Agency and the Intergovernmental Panel on Climate Change (IPCC).To achieve near zero emissions globally by 2070, CCUS technology must accumulate an emission reduction of about 15% [3][4][5][6].
The development of CO 2 capture utilization and storage (CCUS) as an important technology for carbon neutrality is highly promising.CO 2 -based enhanced oil recovery (CO 2 -EOR) in hydrocarbon reservoirs is one of the most economically attractive means to achieve large-scale CO 2 utilization and geological storage.However, CO 2 channeling through high-permeability features seriously inhibits the performance of CO 2 -EOR.In addition to gas channeling issues, in the process of CO 2 flooding, the injected CO 2 can also addition to gas channeling issues, in the process of CO2 flooding, the injected CO2 can also cause inorganic salt precipitation (such as metal carbonates) and asphaltene precipitation, leading to a decrease in reservoir permeability.Due to the fact that precipitation is also generated during water flooding, and the mechanism of precipitation generation is similar to CO2 flooding It is possible to refer to the treatment method of water flooding and introduce inhibitors into the CO2 flooding process to hinder or reduce the generation of precipitation.Also, there is an urgent need for CO2 geological storage technology to solve the problem of potential CO2 leakage via cracks, faults, and other high-permeability channels.Injecting CO2 into hydrocarbon reservoirs is an attractive way to achieve the effective utilization and storage of CO2 [7,8].Current CCUS projects are mainly applied to conventional oil and gas reservoirs, in which 0.1 to 0.6 tons of crude oil can be produced for every 1 ton of CO2 injected.The next stage of research mainly focuses on improving the recovery rate of unconventional oil and gas reservoirs with carbon dioxide.How to effectively inject CO2 into shale or coal bed methane remains a key research and development direction for improving the recovery performance of such oil and gas reservoirs [9,10].When the source and sink matching conditions are suitable, some CCUS projects in China have lower costs than the enhanced oil recovery (EOR) benefits, and have the potential for negative cost reduction [11,12].In terms of CO2-enhanced oil recovery and geological storage, it is a huge challenge to choose a suitable CO2 sealing agent in order to control the migration of CO2 in the formations.As a new type of plugging agent, CO2-responsive gel can directionally identify and plug CO2 in the formation, and has good acid resistance.It has high application potential in the CO2 sealing of formations, and has received widespread attention from researchers [13,14].

Gas Channeling Control in CO2-EOR
Gas channeling, as the primary issue that restricts the significant improvement of CO2-EOR, requires an understanding of its generation mechanisms.The factors causing gas channeling can be attributed to the significant physical differences between CO2 and crude oil and reservoir heterogeneities.The former can be divided into two situations (see Figure 1): (1) the gravity overriding phenomenon: during CO2 flooding, due to the low density of CO2, a large amount of CO2 will gradually migrate above the crude oil, ultimately forming a gas channel at the top of the crude oil seepage channel [15]; (2) the viscous fingering phenomenon: the viscosity of CO2 is lower than the viscosity of crude oil, which can cause uneven propulsion during the displacement process.When the flow rate of CO2 in a local area is too fast, gas channeling will occur [16].The gas channeling caused by reservoir heterogeneity can be divided into the following scenarios: (1) when there are high-permeability channels such as natural fractures, artificial fractures, wormholes, and conduits, CO2 will bypass the matrix and cannot displace the crude oil inside [17,18]; (2) when there is a significant difference in the permeabilities of different layers or zones, CO2 preferentially flows through high-permeability reservoirs [19]; (3) the presence of wormholes, ducts, and high-permeability cracks in the matrix leads to the ineffective flow of CO2 [20].At present, there are several methods to mitigate oil and gas channeling in CO 2 flooding: water-alternating-gas (WAG) injection, the direct thickening of CO 2 , hydrogel plugging, foam plugging, and nanoparticle plugging.These methods for suppressing CO 2 gas migration have been proven to be effective in practical applications and laboratory simulations.The main purpose of this section is to figure out the sealing mechanisms of different CO 2 channeling control methods and the parameters that affect their effectiveness.

Water-Alternating-Gas (WAG) Injection
WAG is considered a reliable method to suppress gas channeling during CO 2 flooding [21,22].Awan et al. reported that, in the WAG process, CO 2 flooding provides high sweep efficiency at the micro level, while water flooding provides high sweep efficiency at the macro level.The organic combination of the two results in a significant improvement in WAG oil recovery overall [23].According to Leeuwenburg's explanation, the injected water during WAG oil displacement can adjust the CO 2 flow to a certain extent.If CO 2 is suppressed from flowing to high-permeability zones, it is forced to displace oil left in low-permeability zones, thereby improving the overall oil recovery performance [24].Kamali et al. also proposed a similar view, using three oil displacement methods: continuous CO 2 injection, simultaneous CO 2 and water injection, and WAG injection to conduct displacement experiments on sandstone cores.It was found that WAG had the best effect and continuous CO 2 injection had the worst effect.Then, numerical simulation experiments were conducted, and it was found that the presence of injected water during the WAG process effectively reduced the permeability of CO 2 , thereby reducing the mobility ratio of CO 2 to crude oil [25].Han explained the enhanced oil recovery mechanism of WAG from the perspective of miscible displacement, and they believe that an increased volume of injected water significantly increases the injection pressure of CO 2 , making it easy for CO 2 to mix with crude oil.This reduces the interfacial tension between crude oil and CO 2 , as well as the viscosity of crude oil, allowing more formation crude oil to be extracted from the ground [26].
It is worth noting that precipitation is often generated during the WAG process, which can hinder the flow of crude oil in the formation and affect the improvement of oil recovery.According to the type of precipitation, it can be divided into organic precipitation and inorganic precipitation.Organic precipitation usually refers to asphaltene precipitation [27].Due to the injection of foreign fluids, changes in the thermodynamic parameters (temperature and pressure) and composition of the crude oil system will lead to aggregation reactions of asphaltene in the crude oil, resulting in solid asphaltene precipitation.The generated asphaltene precipitate will block the channel and seal the reservoir pores, ultimately leading to a decrease in reservoir permeability.Usually, a precipitation inhibitor is added to the injected fluid to hinder the flocculation of unstable asphaltene or make the generated asphaltene precipitate easy to wash out, thereby alleviating the blocking effect of precipitation on the formation.Inorganic precipitation mainly includes metal carbonates.During the process of alternating water and gas injection, some CO 2 dissolves in the injected water, converting it into acidic carbonated water and accumulating CO 3 2− in the aqueous solution.When water contains metal scale ions such as Mg 2+ and Ca 2+ , CO 3 2− will combine with metal scale ions.When the concentration of metal carbonate reaches a critical value, precipitation occurs.These sediments can block small pores, leading to a decrease in reservoir permeability.In addition, acidic carbonated water can also erode the reservoir, alter its permeability and pore structure, and cause metal scale ions in the reservoir to enter the injected water, further exacerbating the generation of precipitation [28].Therefore, for the injected water in WAG, chelating agents should be used before injection into the formation to reduce the content of Ca 2+ and Mg 2+ .Alternatively, inhibitors can be added to inhibit the formation of precipitation.
The recovery efficiency of WAG oil displacement will be greatly impacted by the injection parameters, which include porosity, permeability, and other formation properties, as well as injection parameters like the water to gas slug ratio.Hao et al. first used a thin tube experiment to determine the minimum miscibility pressure of CO 2 and crude oil at 22.79 MPa, and then connected three different permeability cores in parallel [29].After CO 2 displacement, it was changed to WAG displacement, and it was found that under both displacement conditions, the core with the highest permeability contributed the most to the recovery performance, both exceeding 90%.The injection pressures were kept at 15 MPa and 25 MPa, respectively, with oil recovery efficiencies of 33.01% and 39.42%, respectively.A higher injection pressure was beneficial for oil recovery improvement [30].Hosseini and Wang et al. found that, after CO 2 and WAG displacement, the oil permeability and porosity of the core significantly decreased, and some areas of the core showed a reversal of wettability.They attributed this phenomenon to the presence of CO 2 -caused precipitation and the accumulation of asphaltene in the crude oil, blocking some channels, resulting in a decrease in crude oil permeability and core porosity.A combination with surfactants or other types of chemical inhibitors during WAG flooding has been reported to reduce asphaltene precipitation [31,32].

Direct Thickening of CO 2
The density and viscosity of CO 2 gas can be increased by thickening it with polymers, which reduces gas channeling issues brought on by gravity overlap and viscous fingering phenomena [33,34].Brien believes that the increase in density and viscosity can be achieved by controlling the concentration of the added polymer [35].Polymers enhance the density and viscosity of CO 2 at different levels by dissolving them in CO 2 .In general, the higher the molecular weight of a polymer, the greater its viscosity, and the better its thickening effect on CO 2 .However, the higher the molecular weight of the polymer, the lower its solubility in CO 2 , which is unfavorable for CO 2 thickening.Therefore, using low molecular weight polymers to thicken CO 2 is also a feasible option.Siloxane polymers have been proven to be an effective CO 2 thickener [36].Bac tested the thickening ability of polydimethylsiloxane (PDMS) on scCO 2 at 2500 psi and 130 • F. It was found that the viscosity of CO 2 increased from 0.04 cp to 1.2 cp after thickening.In addition, the use of toluene results in the higher solubility of polymers under the same pressure conditions.Bac conducted CO 2 core displacement experiments and found that, after adding polymers, the oil recovery rate increased, the gas breakthrough was delayed, and the oil recovery rate increased by 3.4-9% from its original value [37].
There is also a special polymer, which can form a three-dimensional grid structure through a cross-linking reaction between molecular chains, and the network can swell in water.This kind of polymer is called a gel [38][39][40].Because gels have good plugging properties, they often block high-permeability channels in CO 2 -EOR, thus inhibiting gas channeling caused by formation heterogeneity [41].There are two solutions for polymer gels used for CO 2 consistency control.The first solution is in situ gel plugging, which injects the solution composed of a polymer monomer, cross-linking agent, and auxiliary agent into the formation to form a gel in the formation and block the migration of CO 2 in the highpermeability channel.The second scheme is pre-crosslinked gel plugging, which can be directly injected into the formation after the gel has been completely formed.Alternatively, it can be processed into particles and prepared with a solution, and then injected into the formation [42].Durucan et al. carried out the core displacement experiment of supercritical CO 2 oil displacement, injected polyacrylamide-based polymer gel into the core, and then conducted the CO 2 displacement experiment again, and found that the permeability of CO 2 decreased by 99% [43].

Foam Injection
Foam is a gas dispersion system surrounded by liquid film prepared and stabilized by a surfactant [44,45].Surfactants are amphiphilic compounds, which means they are composed of hydrophilic heads and hydrophobic tails.They are generally divided into four types (according to the charge of the head group): non-ionic, anionic, cationic, and zwitterionic surfactants.Yan et al. found that foam has greater effective viscosity, which can alleviate gravity overlap and the viscous fingering phenomenon during CO 2 flooding, and improve sweep efficiency during CO 2 flooding.Foam can also control the local flow resistance of CO 2 , forcing it into the low-permeability area and displacing the crude oil [46].Through core displacement studies, Boud and Holbrook demonstrated for the first time that foam may be used to improve oil recovery by gas flooding.Additionally, foam can be produced in reservoir rocks under both miscible and immiscible circumstances using this water-soluble foaming agent.Ren et al. tested the effects of three different types of surfactants on CO 2 flooding.The first two surfactants were 2 EH-PO 5 -EO 15 and 2 EH-PO 5 -EO 9 , both of which were nonionic surfactants.The third type was the water-soluble anionic surfactant CD-1045.The phase behavior experiments conducted showed that none of these three surfactants could significantly reduce the interfacial tension between water and crude oil.However, all of them can significantly improve crude oil recovery.Compared with pure CO 2 flooding, the three surfactants can increase oil recovery by 71%, 92%, and 54%, respectively.Moreover, the effect of improving the oil recovery is closely related to the injection scheme [47].Zhang et al. used UC 11 AMPM, SDS, and their mixture as foaming agents, respectively, to prepare CO 2 foams, and tested the effect of temperature on the stability of these three foams.With the increase in temperature, the stability of the foams decreased, and the foam produced by the UC 11 AMPM and SDS mixture had the best temperature resistance [48].Combining multiple surfactants can achieve better oil recovery effects, but the proportion of different surfactants will have a significant impact on the oil displacement effect.Attarhamed and zoveidavianpoor found that the foaming performance of the mixture of AOS and TX-100 in aqueous CO 2 foam was improved compared with that of AOS and TX-100 alone [49].Memon et al. used AOS, TX-100, and a third surfactant, rose amidopropylamine oxide (LMDO), to control the fluidity of CO 2 and improve oil recovery.After the water flooding of Berea sandstone using different combinations of CO 2 and surfactant solutions at 1400 psi and 96 • C, surfactant alternating gas (SAG) injection was performed.According to core oil displacement experiments, CO 2 -SAG based on (0.6 wt% AOS + 0.6 wt% TX-100) achieved the highest recovery rate [50].
There are three main options for introducing surfactants into oil recovery processes.First, CO 2 foam is generated from the outside and then injected into the porous medium.Secondly, the surfactant solution and CO 2 can be injected together at the same time to form foam in porous media.Thirdly, carbon dioxide and surfactant solutions can be alternately injected, known as SAG injection.The advantages of surfactants mainly lie in reducing viscosity fingering, gravity segregation, and early CO 2 breakthrough by changing the magnitude of viscosity and gravity.In addition to fixing CO 2 , surfactants also tend to reduce the IFT between reservoir fluids, reduce capillary forces, and thus improve crude oil recovery.The synergistic effect of multiple surfactants may produce a better profile control effect than a single surfactant, and this profile control effect is closely related to the proportion of different types of surfactants, which will also an important development direction of foam profile control and flooding in the future.

Nanoparticle Injection
An NP (nanoparticle) is defined as a material composed of particles with sizes between 1 nm and 100 nm [51,52].In terms of CO 2 -EOR, nanoparticles enhance oil recovery through two pathways: improving the mobility ratio of CO 2 to crude oil and reducing asphaltene precipitation during CO 2 flooding [53,54].Lu et al. designed a CO 2 core displacement experiment and injected Al 2 O 3 nanoparticles into the core.They found that they adsorbed asphaltene in a solution prepared from toluene and dissolved asphaltene, which means that these NPs can be used to suppress the deposition of asphaltene during CO 2 injection in porous media.A concentration of 0.5 wt% nanoparticles and a volume ratio of 0.1 nanofluid slugs to CO 2 slugs are considered the best conditions for inhibiting asphaltene damage during CO 2 flooding.Compared to the cyclic injection mode, continuous CO 2 and nanofluid injection may be more effective.The higher the mass fraction of Al 2 O 3 nanoparticles, the lower the strength of asphaltene precipitation and the greater the decrease in interfacial tension [55].Other studies have also reached the same conclusion that nanoparticles can reduce the interfacial tension between crude oil and CO 2 and reduce asphaltene precipitation in crude oil [56,57].Ehsan et al. simulated the viscosity increasing effect of Al 2 O 3 nanoparticles with particle diameters of 1 nm, 2 nm, and 3 nm on scCO 2 in an environment of 380 K and 20 MPa.Particles with a diameter of 1 nm have the weakest effect on CO 2 viscosity, resulting in a 3.67-fold increase in CO 2 viscosity.The author also compared the viscosity increasing effect of spherical Al 2 O 3 nanoparticles and columnar CuO nanoparticles on scCO 2 , and found that the viscosity increasing effect of CuO was 3.4 times lower than that of Al 2 O 3 [58].
Because the surfactant is easy to be adsorbed on the rock surface and decomposes itself, the stability of foam in the formation is poor, and it is not suitable for large-scale application.Nanoparticles can effectively improve the stability of foam in the formation, which has attracted the attention of researchers.At present, there are several views on the mechanism of nanoparticles improving the strength of foam (see Figure 2): (1) nanoparticles will gather at the node intersection of the foam liquid film, hinder the liquid flow between liquid films, reduce the water loss rate of the foam liquid film, and thus improve the stability of the foam liquid film; (2) nanoparticles will form a single layer, double layer, and network of bridging particles between foam liquid films to hinder the coalescence and water loss of the foam, thus improving the stability of the foam [59,60].Among them, the network aggregation of nanoparticles has the strongest stabilizing effect on foam.AttarHamed et al. investigated the effect of the diameter and concentration of SiO 2 nanoparticles on the anionic surfactant effect of α-AOS-CO 2 foam stability.The concentrations of the nanoparticles were 0.1 wt%, 0.3 wt%, 0.5 wt%, and 1 wt%, respectively.The diameters of the nanoparticles were 15 nm, 70 nm, and 250 nm.The final experimental results are shown in the figure.When the particle concentration was low, the larger the particle diameter, the better the stability effect of the foam [61].Bayat et al. compared the stabilization effect of TiO 2, CuO, Al 2 O 3 , and SiO 2 nanoparticles on CO 2 foam.When the concentration of nanoparticles was 0.008 wt%, the stabilization effect was the best.When using SiO 2 nanoparticles under the same conditions, the maximum increase in crude oil recovery was 17.4%.The main reason for the poor stability of nanoparticles in foam is that nanoparticles are easily adsorbed on the rock surface and agglomerated.Therefore, the better the dispersity of particles in the system, the better the stability of the foam [62][63][64].
Gels 2023, 9, x FOR PEER REVIEW 6 of 23 nanoparticles, the lower the strength of asphaltene precipitation and the greater the decrease in interfacial tension [55].Other studies have also reached the same conclusion that nanoparticles can reduce the interfacial tension between crude oil and CO2 and reduce asphaltene precipitation in crude oil [56,57].Ehsan et al. simulated the viscosity increasing effect of Al2O3 nanoparticles with particle diameters of 1 nm, 2 nm, and 3 nm on scCO2 in an environment of 380 K and 20 MPa.Particles with a diameter of 1 nm have the weakest effect on CO2 viscosity, resulting in a 3.67-fold increase in CO2 viscosity.The author also compared the viscosity increasing effect of spherical Al2O3 nanoparticles and columnar CuO nanoparticles on scCO2, and found that the viscosity increasing effect of CuO was 3.4 times lower than that of Al2O3 [58].
Because the surfactant is easy to be adsorbed on the rock surface and decomposes itself, the stability of foam in the formation is poor, and it is not suitable for large-scale application.Nanoparticles can effectively improve the stability of foam in the formation, which has attracted the attention of researchers.At present, there are several views on the mechanism of nanoparticles improving the strength of foam (see Figure 2): (1) nanoparticles will gather at the node intersection of the foam liquid film, hinder the liquid flow between liquid films, reduce the water loss rate of the foam liquid film, and thus improve the stability of the foam liquid film; (2) nanoparticles will form a single layer, double layer, and network of bridging particles between foam liquid films to hinder the coalescence and water loss of the foam, thus improving the stability of the foam [59,60].Among them, the network aggregation of nanoparticles has the strongest stabilizing effect on foam.At-tarHamed et al. investigated the effect of the diameter and concentration of SiO2 nanoparticles on the anionic surfactant effect of α-AOS-CO2 foam stability.The concentrations of the nanoparticles were 0.1 wt%, 0.3 wt%, 0.5 wt%, and 1 wt%, respectively.The diameters of the nanoparticles were 15 nm, 70 nm, and 250 nm.The final experimental results are shown in the figure.When the particle concentration was low, the larger the particle diameter, the better the stability effect of the foam [61].Bayat et al. compared the stabilization effect of TiO2, CuO, Al2O3, and SiO2 nanoparticles on CO2 foam.When the concentration of nanoparticles was 0.008 wt%, the stabilization effect was the best.When using SiO2 nanoparticles under the same conditions, the maximum increase in crude oil recovery was 17.4%.The main reason for the poor stability of nanoparticles in foam is that nanoparticles are easily adsorbed on the rock surface and agglomerated.Therefore, the better the dispersity of particles in the system, the better the stability of the foam [62][63][64].The above four methods for preventing and controlling oil and gas migration in CO2 flooding have their own advantages and disadvantages, as summarized in Table 1.In order to further solve the problem of gas migration during CO2 flooding, in addition to making up for the shortcomings of existing technologies, efforts should also be made to develop new CO2-enhanced oil recovery technologies.The above four methods for preventing and controlling oil and gas migration in CO 2 flooding have their own advantages and disadvantages, as summarized in Table 1.In order to further solve the problem of gas migration during CO 2 flooding, in addition to making up for the shortcomings of existing technologies, efforts should also be made to develop new CO 2 -enhanced oil recovery technologies.

Pathways of CO 2 Leakage
CO 2 geological storage is the process of trapping CO 2 emitted during the burning of fossil fuels before it enters the atmosphere, moving it via pipelines to the burial location, and then sealing it in a supercritical state in the formation (which typically includes deep salt water layers, abandoned gas layers, and abandoned oil and gas reservoirs).CO 2 leakage is the term used to describe the phenomenon in which stored CO 2 migrates to the ground along faults, wellbore fractures, and other formation fractures, or where it re-enters the atmosphere due to geological events (such as earthquakes or volcanic eruptions) or human activity, ultimately leading to the failure of storage (see Figure 3).Nanoparticles are prone to coalescence, blocking the roar channel, and failing;断 Large particle sizes can pollute the environment.

Pathways of CO2 Leakage
CO2 geological storage is the process of trapping CO2 emitted during the burning of fossil fuels before it enters the atmosphere, moving it via pipelines to the burial location, and then sealing it in a supercritical state in the formation (which typically includes deep salt water layers, abandoned gas layers, and abandoned oil and gas reservoirs).CO2 leakage is the term used to describe the phenomenon in which stored CO2 migrates to the ground along faults, wellbore fractures, and other formation fractures, or where it re-enters the atmosphere due to geological events (such as earthquakes or volcanic eruptions) or human activity, ultimately leading to the failure of storage (see Figure 3).

Potential Inflence of CO2 Leakage
The hazards caused by CO2 leakage can be roughly divided into two categories: global risks and regional risks.Global risk refers to the change in the global climate caused by CO2 leakage, while local risk refers to the damage to the local ecological environment caused by CO2 leakage [65].

Potential Inflence of CO 2 Leakage
The hazards caused by CO 2 leakage can be roughly divided into two categories: global risks and regional risks.Global risk refers to the change in the global climate caused by CO 2 leakage, while local risk refers to the damage to the local ecological environment caused by CO 2 leakage [65].
After CO 2 leakage, it will enter the atmosphere again and cause a secondary greenhouse effect [66].Patil et al. believe that after CO 2 leakage, the oxygen content in the soil will be significantly reduced, leading to a decrease in crop yields such as grass and soybeans.In the experiment they designed, when the CO 2 flow rate reached 1 L/min, the yield of soybeans decreased by half [67].The United States Department of Energy designed the "Frio Brine Pioneer Experiment".In the experiment, the researchers injected 1600 t carbon dioxide into the sandstone layer 1550 m deep underground in an oil field northeast of Houston, Texas.Carbon dioxide caused the pH value of the brine in the storage formation to drop from nearly neutral 6.5 to 3.0, and dissolved a large number of carbonate rocks, leading to CO 2 leakage and the pollution of drinking water.When the concentration of CO 2 is too high, it can cause suffocation.When CO 2 is excessively injected into the formation, it can cause excessive injection pressure to cause fractures in the formation, and, additionally, it may trigger earthquakes.

The Pathways of CO 2 Leakage
There are two ways in which CO 2 might leak.The first is known as engineering leakage and is brought on by either artificially created reservoir damage or a poorly wellbore integrity.When CO 2 enters the formation and leaks due to natural geological activities or geological characteristics during the migration process, this leakage pathway is called natural leakage [68].

Engineering Leakage Pathways
When the integrity of an oil well is poor, such as when there are some small cracks on the wellbore wall or near the wellbore, CO 2 will leak along these cracks [69].When the depth of the well is low, the injected CO 2 cannot reach the designated storage location.The low density of CO 2 will continuously migrate above the formation, ultimately leading to leakage.CO 2 leakage can be avoided by restoring wellbore integrity, but this is only economically feasible when the number of wellbore repairs is small.It is not economically feasible to prevent CO 2 leakage by repairing poorly sealed wells.Excessive CO 2 injection pressure can lead to formation fractures and become a potential pathway for CO 2 leakage.In addition, other human activities such as oil and gas engineering operations such as crude oil extraction and exploration can also lead to the generation of formation fractures and CO 2 leakage [70].

Natural Leakage Pathways
Natural leakage is a CO 2 leakage caused by geological characteristics or the geological activities of reservoirs, and is not related to human activities [71].The mechanisms of natural CO 2 leakage typically include the following.Firstly, the poor sealing of the cover layer, such as the presence of cracks, may lead to CO 2 migration through the cover layer and leakage [72][73][74].Secondly, the presence of high-permeability channels such as fractures or faults in the formation can lead to CO 2 migration to the ground and leakage along the fractures or faults.Bentz et al. believed that these leakage channels are usually caused by geological activities such as earthquakes and tectonic movements [75].Therefore, geological activities are also a potential factor leading to CO 2 leakage.The deep salt water layer serves as a good CO 2 storage site, and salt water can provide a sealing effect on CO 2 .Due to the low density of CO 2 , it will continue to migrate laterally until it bypasses the saline layer and leaks along areas with poor sealing of the formation.

CO 2 -Sealing Agents
Manceau et al. suggested that existing CO 2 plugging materials can prevent CO 2 leakage using the following three techniques: (1) mitigating CO 2 leakage by restoring wellbore integrity; (2) obstructing the high-speed migration of CO 2 in cracks or faults; (3) improving the sealing of the cover layer to CO 2 [68].Wu et al. classified six types of sealants used to alleviate cement-related wellbore leakage.They are cementitious materials, temperature-activated resins, nano-strengthening sealants, gels, geopolymer cements, and low melting point alloys [66].Based on the existing literature, this article summarizes the types, characteristics, functional mechanisms, and scope of applications of seven CO 2 -sealing materials, and points out the advantages and disadvantages of each material systems.The seven materials are Portland cement, geopolymer cement, resin, gel, biofilm barrier, nanoparticles, and foam, as summarized in Table 2.

CO 2 Responsive Gel
CO 2 -responsive intelligent gel refers to a kind of gel the structure and properties of which can undergo particular transformation when contacting CO 2 .The stimulus source of this type of gel is CO 2 , which can avoid the accumulation of a large number of impurities in the response process using traditional stimulus sources.By utilizing the intelligent CO 2 response characteristics, it can be applied to sealing CO 2 during CO 2 flooding and geological storage [13].

CO 2 Responsive Functional Group
The process of synthesizing CO 2 responsive gels involves adding functional groups that are responsive to CO 2 to the conventional gel's molecular chain.As summarized in Figure 4, there are several known CO 2 responsive functional groups: primary amine groups, amidine groups, guanidine groups, tertiary amine groups, azole-containing heterocyclic groups, carboxylic acid [89].
Primary amine groups: CO 2 can react with primary amines at room temperature to generate negatively charged carbamate salts, and some of them are positively charged through protonation, forming bicarbonate between them, thus achieving the salt bridge bonding of primary amine groups, which is the basis for primary amine groups having CO 2 responsiveness.
Amidine groups: Slightly stronger in alkalinity, they will be hydrolyzed to a certain extent in aqueous solution, resulting in deviations when calculating the degree of protonation of the amidine group from the amount of CO 2 injected.When amidine group encounters CO 2 , it will generate protonated amidine salt compounds.After CO 2 is discharged, amidine salt will appear deprotonated and return to the original state again.

CO2 Responsive Functional Group
The process of synthesizing CO2 responsive gels involves adding functional groups that are responsive to CO2 to the conventional gel's molecular chain.As summarized in Figure 4, there are several known CO2 responsive functional groups: primary amine groups, amidine groups, guanidine groups, tertiary amine groups, azole-containing heterocyclic groups, carboxylic acid [89].Primary amine groups: CO2 can react with primary amines at room temperature to generate negatively charged carbamate salts, and some of them are positively charged through protonation, forming bicarbonate between them, thus achieving the salt bridge bonding of primary amine groups, which is the basis for primary amine groups having CO2 responsiveness.
Amidine groups: Slightly stronger in alkalinity, they will be hydrolyzed to a certain extent in aqueous solution, resulting in deviations when calculating the degree of protonation of the amidine group from the amount of CO2 injected.When amidine group encounters CO2, it will generate protonated amidine salt compounds.After CO2 is discharged, amidine salt will appear deprotonated and return to the original state again.
Guanidine: Guanidine is the most basic CO2-responsive functional group, and the addition of aromatic substituents slows down alkalinity.Guanidine containing N-H bonds can form carbamates or forms of salts other than bicarbonate.The alkalinity of the guanidine group is the highest among several functional groups at present, so it has the strongest CO2 responsiveness, which also leads to more energy consumption during its deprotonation process.At the same time, the higher temperature required to convert bicarbonate or guanidine formate into neutral guanidine is an advantage for applications that require high temperatures.Guanidine: Guanidine is the most basic CO 2 -responsive functional group, and the addition of aromatic substituents slows down alkalinity.Guanidine containing N-H bonds can form carbamates or forms of salts other than bicarbonate.The alkalinity of the guanidine group is the highest among several functional groups at present, so it has the strongest CO 2 responsiveness, which also leads to more energy consumption during its deprotonation process.At the same time, the higher temperature required to convert bicarbonate or guanidine formate into neutral guanidine is an advantage for applications that require high temperatures.
Tertiary amino groups: They are common weakly alkaline molecular groups that are found in many polymers.Tertiary amino groups can undergo changes with CO 2 to form cationic tertiary amine salts.When the CO 2 concentration decreases, a reversible deprotonation reaction will occur, and the goal of a CO 2 reversible response will be achieved finally.
Azazole-containing heterocycles: Numerous organisms include heterocyclic compounds including azole, and the molecular fragments of these compounds are present in peptides, genetic elements, and amino acids.In addition, azazole heterocyclic compounds can act as functional groups in response to CO 2 and exhibit weak alkalinity.This polymer can produce protonated histamine salts in response to CO 2 in solution.Imidazole functional groups can be thought of as a novel class of CO 2 -adsorbent materials since they are more stable following protonation than amidine and tertiary amine groups.
Carboxylic acid and phenols: These groups are present in the solution as anions when CO 2 is not present.The pH of the solution steadily drops as the CO 2 level rises until it reaches a critical value (corresponding to the solution pKa), and the functional groups progressively become neutral, which indicates a steady decline in the polymer's solubility.Typically, these groups are added to the solution as anions or acids.In cases when the neutral form's solubility in aqueous solution is restricted, the critical point could be noticeably higher than the pKa.
The advantages and disadvantages of each responsive group are summarized in Table 3.Based on the characteristics of each responsive group, its corresponding polymer or itself usually has the following advantages and disadvantages for CO 2 flooding profile control and CO 2 geological storage.

CO 2 -Responsible Group Advantage Disadvantage
Amino groups (primary, secondary, tertiary) The synthesis route is simple and there are many mature industrial monomers available for use; The group in aqueous solution has low alkalinity and is not easily hydrolyzed.
Slow reaction rate with CO 2 ; Unable to respond to low concentration of CO 2 .
Amine and guanidine groups Has rapid and sensitive CO 2 responsiveness.
The group in aqueous solution has strong alkalinity and is easy to hydrolyze; Complex synthesis route.

Azazole-containing heterocycles
The salt generated after responding to CO 2 is relatively stable; Widely present in organisms.
The working conditions are harsh and not suitable for geological environments.

Carboxyl and phenolic hydroxyl groups
Has good acid resistance; Easy to synthesize, with many mature industrial monomers available for use.
Sealing of wellbore cracks not applicable.

CO 2 Responsivee Gels
The studies of CO 2 responsive gels are summarized in Table 4.As early as 2003, Carretti et al. synthesized a class of polyacrylamide-based polymers (PAAm), which contained fatty alcohols and 1-methyl-2-pyrrolidone in organic solvents with a large number of primary amine groups on their side chains at room temperature.After the continuous introduction of CO 2 into the system, the system gradually changes from the initial colloidal state to a gel, and gels can absorb a high concentration of CO 2 .The primary amino group has obvious advantages in the synthesis of CO 2 -responsive gels, but the primary amino gel is relatively slow in its response to CO 2 [90].In 2005, Darabi et al. found that amidine groups are responsive to CO 2 , which inspired a series of amidine gel to be designed and synthesized [91].In 2011, Yan et al. successfully prepared CO 2 -responsive and breathable polymer vesicles using amphiphilic block copolymers containing amidine groups for the first time.They first synthesized the functional monomer N-guanidododecylacrylamide containing an amidine group, and polymerized it with polyethylene glycol macromolecules through atom transfer radical polymerization to synthesize polyethylene glycolb poly (N-guanidododecylacrylamide) (PEO-b-PAD).After introducing CO 2 into the system, the amidine group reacts with CO 2 to form a protonation amidine salt structure, and the volume of the vesicles will increase significantly.When argon is continuously injected into the system, the amidine salt structure will undergo deprotonation, and then return to the solid state [92].
The synthesis of amidine groups is relatively complex, and the degree of their protonation is reduced due to their easy hydrolysis in water.In 2013, Zou et al. polymerized dimethylaminoethyl methacrylate with a tertiary amino group, which was CO 2 -responsive, and with the increase in CO 2 concentration, the degree of protonation of the polymer also increased [93].In 2012, Hoshino et al. used 3-dimethylaminopropylacrylamide (DMAPM) containing a tertiary amine as a functional monomer to copolymerize with the thermosensitive monomer NIPAM and a crosslinking agent.A micro gel was formed in the solution.The molecular side chain of the gel contains a large number of tertiary amine groups, which can react with CO 2 , and fix CO 2 in the gel to achieve the purpose of fixing CO 2 .This is the first successful example of using microscopic materials in solution for controllable CO 2 absorption and release [94].Nitrazole-containing heterocyclic compounds (usually diazoles) are widely present in organisms.Azazole heterocyclic molecular fragments can be found in amino acids, peptides, and genetic materials.At the same time, the azazolecontaining heterocyclic molecules are also weakly alkaline and can respond to CO 2 to generate protonation histamines.The protonated functional group is more stable than the previous protonated functional groups, and can be used to prepare an intelligent responsive gel for CO 2 adsorption.The polymer is dissolved in the organic solvent containing fatty alcohol and 1-methyl-2-pyrrolidone, and CO 2 gas is continuously injected, which makes the polymer change from the initial colloidal state to chemical gel.By adjusting the ratio of MVF and DVFE monomers to control the size of polymer microspheres, the absorbable surface area inside the microspheres can be maximized.BET experiments have shown that the maximum adsorption area can reach 246 mg/g, and the total adsorption amount of CO 2 can reach 97 mg/g.CO 2 is continuously injected into the 1% polymer solution, and the solution undergoes a sol-gel-sol transition. [96]

Suzuki et al., 2011 Primary amine
In the presence of 1,8-diazabicyclo and undecen-7-ene (DBU), a novel hydrogel was prepared by the crosslinking reaction of PAAm with CO 2 .
The CO 2 absorption capacity of the hydrogel at room temperature is 2.8 times that of the traditional PAAm, and the absorption capacity and absorption efficiency of the polymer hydrogel are basically unchanged after multiple absorption of CO 2 . [97]

Xu et al., 2004 Primary amine
Firstly, four urea-substituted calixarene host units were designed, and small molecule monomers with primary amine groups were obtained through selective modification.
When CO 2 is introduced into the solution, the dimer can form linear non-covalent bond polymer through ammonium carbamate bridge bond.When competitive polar solvents are added to the solution, the hydrogen bond between the host molecule calix tetraarene is destroyed, leading to the disintegration of the supermolecule polymer. [98] Xiong et al., 2017 Primary amine Mixing HMPAM and TMPDA.
After CO 2 was introduced, the solution turned into gel, and the zero-shearing viscosity and elastic modulus increased by 360 and 400 times respectively. [99] Yan et al., 2023 Secondary amine 0.5 wt% NaSal and 3 wt% ENPD were dissolved in deionized water to form the initial system.
After injecting CO 2 , the viscosity of the system continues to increase and does not change after reaching a certain stage.
[100] After dissolving the polymer in a DMF/water mixture and alternately introducing CO 2 and N 2 , the conductivity of the system undergoes a rapid impulse change.
It is proven that the polymer responds to CO 2 gas through the protonation/deprotonation process of amidine group. [101]

Guo et al., 2011 Amidine
A class of homopolymers containing amidine groups on its side groups were prepared by RAFT method using 4-chlorostyrene as a monomer.
Alternating the stimulation of CO 2 /N 2 can achieve the transfer of substances in the organic/aqueous phase.[ After CO 2 is introduced, gel particles expand and gel particles shrink when CO 2 is removed. [111] Zhang et al., 2015 Tertiary amine PDMAEMA-PEO-PDMAEMA triblock copolymer was synthesized using ATRF method.
After CO 2 is introduced, the sol changes into gel, and the process is reversible. [112] Chen at al, 2015 Tertiary amine DEAEMA stabilized by PEGMA was obtained through lotion polymerization.
After introducing CO 2 , the system transitions from an aqueous solution to a viscoelastic fluid, followed by a milky white solution. [114]

Application of CO 2 -Responsive Gel in CO 2 Gas Channeling and Leakage Mitigation
For the application of a CO 2 responsive gel in CO 2 -enhanced oil recovery and geological storage, in addition to the performance of the gel itself, such as rheology, swelling, and acid resistance, etc.The environmental conditions(pressur, tempreture, etc.) in the action area of gel also greatly affect the action effect of gel Figure 5.
group and tertiary amine group after protonation.

Application of CO2-Responsive Gel in CO2 Gas Channeling and Leakage Mitigation
For the application of a CO2 responsive gel in CO2-enhanced oil recovery and geological storage, in addition to the performance of the gel itself, such as rheology, swelling, and acid resistance, etc.The environmental conditions(pressur, tempreture, etc.) in the action area of gel also greatly affect the action effect of gel Figure 5.The key point is to observe some characteristics of gel in the actual application process, such as evaluating the plugging strength of gel by the breakthrough pressure of CO2 after injection of gel, or evaluating gel's ability to adjust CO2 mobility by resistance coefficient and residual resistance coefficient.This paper summarizes some work on the evaluation of CO2 responsive gel for CO2 plugging ability and gas channeling inhibition ability in recent years (as shown in Table 5).The key point is to observe some characteristics of gel in the actual application process, such as evaluating the plugging strength of gel by the breakthrough pressure of CO 2 after injection of gel, or evaluating gel's ability to adjust CO 2 mobility by resistance coefficient and residual resistance coefficient.This paper summarizes some work on the evaluation of CO 2 responsive gel for CO 2 plugging ability and gas channeling inhibition ability in recent years (as shown in Table 5).The higher the matrix permeability, the poorer the system's ability to improve oil recovery; the larger the crack width, the worse the gel plugging effect.[ After the injection of gel, the injection pressure increased from 0.18 MPa to 0.64 MPa, the plugging ratio reached 70.3%, and the oil recovery increased by 10.4%. [127]

Further Development of CO 2 Responsive Gels and Concluding Remarks
The CO 2 -responsive gel has good profile control and plugging performance, as demonstrated by numerous core-scale plugging studies.This suggests that the CO 2 responsive gel has great application value in the field of CO 2 -EOR and CO 2 geological storage.At present, the application of CO 2 responsive gels on the reservoir scale is still lacking precedent, and its popularization and application in the oil and gas industry still need to solve the following problems.(1) All of the current CO 2 responsive groups depend on H + generation.In hotter conditions, CO 2 becomes less soluble in formation water, which inhibits the generation of H + .The use of CO 2 responsive gels in deep, high-temperature formation is restricted, and its sensitivity is reduced.It is necessary to explore new CO 2 responsive materials.(2) The existing CO 2 responsive gels are mainly used to qualitatively evaluate their CO 2 responsiveness according to the change in their macro phase state before and after CO 2 response.There is a lack of a systematic quantitative characterization method of gel CO 2 responsiveness in order to screen out the ideal CO 2 responsive gel.Moreover, CO 2 -responsive groups can be used not only in the preparation of CO 2 -responsive gels, but also in the preparation of CO 2 -responsive ionic solutions, which have broad application prospects in the field of CO 2 capture [128,129].(3) The current CO 2 -responsive gels are based on the mechanism of protonation of the CO 2 responsive groups, which causes the volume expansion of the gels, and thus seal the CO 2 migration channel of the formation.However, the protonation process of the responsive group is reversible.When the responding gel encounters a large amount of non-acid gas in the formation or the formation temperature increases, the CO 2 -responsive gel will return to the state before the response, thus losing the sealing effect on the formation.Further efforts are required to make the gels more stable and controllable.(4) In order to improve the mechanical strength, salt resistance, and temperature resistance, the CO 2 responsive gel has been suggested to be combined with other technologies to meet the requirements of actual production in oil fields.For example, foam compound systems, organic inorganic gel compound systems, and nanoparticle compound systems.

Figure 1 .
Figure 1.Formation mechanisms of gas channeling.Figure 1. Formation mechanisms of gas channeling.

Figure 1 .
Figure 1.Formation mechanisms of gas channeling.Figure 1. Formation mechanisms of gas channeling.

Figure 2 .
Figure 2. Mechanism of nanoparticles enhancing the stability of foam.

Figure 2 .
Figure 2. Mechanism of nanoparticles enhancing the stability of foam.

Figure 5 .
Figure 5.The responsive mechanism of CO 2 responsive gel.

Table 1 .
Comparison between the different methods of CO 2 mobility control.

Table 2 .
Formation CO 2 leakage prevention and sealing agent.

Table 3 .
Characteristics of each functional group.