Potential, Efficiency, and Leakage Risk of CO₂ Sequestration in Coal: A Review

Abstract

CO₂ sequestration in coal is effective for reducing carbon emissions, but related projects have encountered challenges in sustained CO₂ injection, highlighting the need for a comprehensive understanding of CO₂ sequestration in coal. This study reviews variations in the properties of coal/rock during/after CO₂ injection, demonstrating the potential and stability of CO₂ sequestration in coal. The coal with a high V_L-CO₂/V_L-CH₄ is accompanied by high CO₂ sequestration capacity. The matrix swelling and acid corrosion restrict CO₂ sequestration efficiency, which can be enhanced by employing coatings and increasing permeability. Long-term CO₂–water–rock interactions weaken the integrity of coal/caprocks and decrease the adsorption capacity of coal, leading to the CO₂ leakage risk. Three issues are critical in future studies: (1) Increasing CO₂ adsorption capacity. (2) Establishing optimal approaches to enhance CO₂ injection efficiency. (3) Accurately predicting variations in the adsorption capacity of deep coal and the integrity of coal/caprocks during long-term CO₂–water–rock interactions. This review provides foundations for formulating CO₂ sequestration strategies in coal.

1. Introduction

CO₂ emissions directly contribute to the global temperature rise. The Intergovernmental Panel on Climate Change predicts that the temperature will increase by 1.5 °C from 2030 to 2052 [1], and that the increase in temperature will even reach 5 °C by 2100 [2]. Significant temperature rise is prone to extreme weather, floods, heat waves, storms, wildlife extinction, and food shortages, constructing a serious threat to the survival of human beings [3,4,5]. Therefore, it is significant to efficiently dispose of CO₂ to minimize the negative impact on the environment.

CO₂ sequestration is an effective pathway to reduce carbon emissions, and coal is a potential sequestration medium. CO₂ sequestration can be divided into two categories, and the first category does not have energy benefits, as CO₂ dissolves in saline aquifers and depleted natural gas/oil reservoirs, with field applications in the USA, Canada, Netherlands, Australia, Japan, and China [6,7]. For example, 1.1 million tons of CO₂ per year was captured in the depleted P18-4 gas field near the coast of Rotterdam [7]. The other category is sequestration with energy benefits, such as enhanced oil, conventional natural gas, and coalbed methane (CBM) production. As CH₄ has a global warming potential 21 times that of CO₂, CBM emissions significantly worsen climate impact [8,9,10,11]. Therefore, CO₂ sequestration in coal can simultaneously inhibit greenhouse effects and enhance energy utilization efficiency.

The concept of CO₂ sequestration in coal was first proposed by Macdonald, Gunter, and colleagues of Alberta Energy in 1991 [12,13], and many studies focusing on CO₂ injection to enhance CBM recovery (CO₂-ECBM) have been conducted, suggesting that a large number of unrecoverable coal has the potential for CO₂ sequestration. However, the number of global field CO₂ sequestration in coal is less than that in saline aquifers, and CO₂-ECBM practices have shown difficulties in sustained CO₂ injection and unacceptable variations in CBM recovery. Moreover, the ultimate goals of CO₂ sequestration and CO₂-ECBM are significantly different, suggesting that critical issues for CO₂ sequestration in coal remain unclear. Therefore, focusing on the potential, efficiency, and leakage risk of CO₂ sequestration in coal, this study comprehensively reviewed the mechanism of CO₂ sequestration and variations in physical/chemical properties of coal/rock/CBM during and after CO₂ injection, and the main differences between CO₂ sequestration in coal and saline aquifers were summarized. Geological models of CO₂ leakage risk were established, and consequently, the critical issues to be addressed in future studies were clarified. This review provides foundations for achieving effective CO₂ sequestration in coal.

2. Potential of CO₂ Sequestration in Coal

Current CO₂ sequestration projects are mostly conducted in saline aquifers, providing fruitful sequestration theory and technology. However, CO₂ can be absorbed by coal, preliminarily indicating the differences between CO₂ sequestration in coal and saline aquifers. This section reviewed the mechanisms of CO₂ sequestration in coal, and compared the CO₂ sequestration in coal and CO₂-ECBM. Consequently, the potential of CO₂ sequestration in coal was clarified.

2.1. Mechanisms of CO₂ Sequestration in Coal

The mechanisms of CO₂ sequestration in coal are divided into four categories: structural sequestration, solubility sequestration, mineral sequestration, and adsorption sequestration. Except for the last mechanism, the other mechanisms are also reported in CO₂ sequestration in saline aquifers. Structural sequestration refers to the fact that the free CO₂ migrates to a trap (such as anticline and syncline) driven by buoyancy, and the tight coal measure caprocks (shale, siltstone, and tight sandstone) prohibit CO₂ migrating upwards. Notably, due to a small amount of organic matter and high clay content, CO₂ can be absorbed by coal measure shale [14,15,16], promoting CO₂ sequestration. Solubility sequestration refers to the fact that CO₂ is dissolved by diffusion, convection, and dispersion in the formation water. Mineral sequestration refers to carbonic acid (CO₂ dissolution) slowly reacting with minerals in coal to form solid carbonate minerals. As these mechanisms have been comprehensively clarified in many studies [6,17,18,19], this study emphasizes studies focusing on CO₂ adsorption.

Numerous micro/nano pores with large specific surface area (SSA) lead to a high CO₂ adsorption capacity, which is the critical basis for CO₂ sequestration in coal [20]. The CO₂ adsorption can be divided into two types: (1) Physical adsorption: A reversible process controlled by Van der Waals forces. (2) Physical adsorption: An irreversible process in which CO₂ occupies oxygen-containing functional groups, such as C=O [21,22,23,24]. The adsorption capacity can be divided into excess adsorption capacity and absolute adsorption capacity. The excess adsorption capacity does not consider the volume of the adsorbed phase [25,26,27], and the volume occupied by adsorbed gases at low-pressure stages is negligible, leading to a similar excess adsorption capacity to the absolute adsorption capacity. However, CO₂ occupies a measurable volume at high pressures, resulting in a large difference between the excess adsorption capacity and the absolute adsorption capacity (Figure 1) [28,29,30,31]. The absolute adsorption capacity can be obtained by the excess adsorption capacity (Equation (1)) [32].

$$n_{(excess)}(p)=n_{(absolute)}(p)(1-{\displaystyle \frac{{\rho }_{(gas)}(P,T)}{{\rho }_{(ads)}(T)}})$$

(1)

where $n_{(excess)}$ is the excess adsorption capacity, m³/t; $n_{(absolute)}$ is the absolute adsorption capacity, m³/t; p is the pressure, MPa; ${\rho }_{(gas)}(P,T)$ is the density of bulk gas phase, t/m³; ${\rho }_{(ads)}(T)$ is the adsorbed phase density, t/m³; and T is the temperature, K.

CO₂ adsorption capacity depends on temperature, pressure, and coal properties. (1) Temperature: As gas adsorption is an exothermic process, an increase in temperature generally leads to a reduction in adsorption capacity [33,34]. (2) Pressure: A high pressure increases adsorbate density, and provides greater surface coverage and stronger interactions between adsorbate molecules, leading to an increasing adsorption capacity with increasing pressure [33,35,36]. (3) Pore structure: Some studies have applied fractal dimension to clarify pore characteristics, and a high adsorption capacity is accompanied by a high surface fractal dimension [37,38]. (4) Moisture content: As CO₂ can form molecular clusters on the water surface, the adsorption capacity increases with increasing moisture content [25,39]. (5) Chemical compositions: CO₂ adsorption capacity is positively correlated with the vitrinite, fixed carbon, and oxygen contents, and negatively correlated with the inertinite content and ash yield [30,35,37,40,41,42,43]. As the pore structure and chemical compositions vary greatly with increasing organic matter maturity, the effects of coal rank on adsorption capacity are diverse. For example, Day et al. [44] pointed out that the maximum adsorption capacity showed a U-shaped correlation with the vitrinite reflectance (R_o), with an inflection at 1.1–1.2%. However, Gensterblum et al. [31] found that CO₂ adsorption capacity decreased with increasing coal rank. The divergent conclusions arise from differences in sample R_o ranges: 0.2–1.8% in the work by Day et al. [44] versus 0.2–4.5% in the work by Gensterblum et al. [31]. The CO₂ adsorption capacity of a few samples is low at R_o < 1.5% but increases progressively across the wider R_o range in the work by Gensterblum et al. [31].

2.2. Differences Between CO₂ Sequestration and CO₂-ECBM

As substantial CBM is reserved in coal, two processes occur when CO₂ is injected into coal: (1) Competitive adsorption: As CO₂ has a higher boiling point, adsorption affinity of micropores, and smaller molecular diameter [25,28], coal exhibits a significantly higher adsorption capacity of CO₂ than that of CH₄, leading to CO₂ displacing CH₄ adsorbed on the pore surface (Figure 1) [45,46,47,48]. The adsorption capacity of CO₂ is approximately 2–3 times that of CH₄ when the pressure is less than the critical point, but the adsorption capacity ratio of CH₄/supercritical CO₂ (ScCO₂) reaches 1:5 [49,50,51,52]. Similar conclusions were drawn from isothermal adsorption experiments [28,53,54,55]. (2) Chemical adsorption: CO₂ occupies oxygen-containing functional groups and promotes CH₄ desorption [34,56]. These processes mean that CO₂ adsorption by coal (CO₂ sequestration) is accompanied by CBM desorption (CO₂-ECBM, Figure 2).

CO₂-ECBM field applications were first conducted in 1995 in the Allison area in the San Juan Basin, USA [57], followed by approximately 20 projects with total CO₂ injection amount exceeding 500,000 t, such as Tanquary Farm and Pump Canyon in USA [58,59], Fenn Big Valley and Alberta CSEMP Project in Canada [60,61], Silesian Basin in Poland [6], Ishikari Basin in Japan [62], and South Shizhuang and Liulin in China [63,64,65].

CBM recovery is mostly enhanced after CO₂ injection, but the increment of recovery varies greatly in different experiments, simulations, and field tests, ranging from 14.89% to 1000% [66,67,68,69,70,71,72]. These differences are related to temperature [73,74,75,76], pressure [77,78,79,80,81,82], original permeability [6,83], water evaporation [84], mechanical strength [85,86], and gas saturation [73,87,88]. When changing these parameters, the CO₂ sequestration rate and CH₄ recovery mostly show a similar variation [73,89,90]. However, Zhang et al. [91] found that when the pressure increased from 1.0 to 1.4 MPa, the CH₄ recovery increased from 91.35% to 93.50%, but the CO₂ sequestration rate decreased from 67.89% to 47.90%. The contrary variations in those two parameters are directly related to the CO₂/CH₄ adsorption ratio. Due to the high aromatization degree in high rank coal, the CO₂/CH₄ displacement ratio generally decreases from 10:1 to 2:1 with increasing coal rank [92]. Moreover, the CO₂/CH₄ displacement ratio decreases with increasing temperature and pressure [31], leading to a greater sensitivity of CO₂ sequestration capacity compared to CH₄ production [80].

The ultimate goal of the CO₂ sequestration process is to adsorb more CO₂ in coal, but that of CO₂-ECBM is to produce more CH₄. Therefore, the applicability of different coal for two processes is diverse. Zheng et al. [70] found that the CO₂/CH₄ adsorption ratio of low rank coal in Xinjiang and high rank coal in Shanxi, China was 5.0 and 2.2, respectively, suggesting that low rank coal is suitable for CO₂ sequestration. Similarly, Sun et al. [40] concluded that coal with high V_L-CO₂/V_L-CH₄ was applicable for CO₂ sequestration. To specify the boundaries of coal for CO₂ sequestration/CO₂-ECBM, Zhang and Liu [93] proposed a desorption hysteresis plot (βCH₄-βCO₂, Figure 3). β indicates the difference between desorption and adsorption, and the value of β ranges from 0 to 1. When β is 1, all adsorption sites can be desorbed, and samples located in regions I/III/VI are more suitable for CO₂ sequestration.

2.3. Estimation of CO₂ Sequestration Capacity in Coal

Global coal resources reach 1139.33 × 10⁸ t, 91.41% of which are reserved in the USA, China, Russia, Australia, India, Germany, Ukraine, Kazakhstan, Indonesia, and Poland [94], providing the basis for CO₂ sequestration. As the current demand for coal remains high, it is essential to clarify that coal is more suitable for CO₂ sequestration. The exploitation depth of coal mines is mostly less than 1000 m, with a few mines ranging from 1000 to 1500 m, and the high temperatures/pressures in deep regions generally lead to difficulties in mining and significantly increasing costs. For the shallow regions, the thickness of some coal is significantly thin, leading to low mining value. Moreover, tectonic movements lead to severe deformation and even rupture of coal, increasing the risk of methane outbursts and mining. These coals have low mining values and high resources, which are optimal for CO₂ sequestration.

Based on the sequestration mechanism, the CO₂ sequestration capacity in coal consists of four parts, and the capacity is mostly calculated by CO₂ density and volume (volumetric method). The structural sequestration capacity depends on the scale of the trap, and the maximum injection pressure is considered a constraint to prohibit CO₂ leakage (Equation (2)) [17]. The solubility sequestration capacity contains the dissolved CO₂ volume and the space occupied by CO₂ displacing water (Equation (3)) [95]. As the mineral compositions of coal vary greatly in different areas, there is still no universal equations for the mineral sequestration capacity [17,46]. The adsorption sequestration capacity is mostly calculated by the method proposed by the Carbon Sequestration Leadership Forum (Equation (4)) [95,96,97]. The equation includes two special parameters related to the process of CH₄ displacement by CO₂ (ER and RF), and empirical values for these parameters have been provided in some studies [29].

$$M_s=\rho {CO}_2(P_{\max },T)V_{trap}$$

(2)

where M_s is the CO₂ capacity by structural sequestration, t; $\rho {CO}_2(P_{\max },T)$ is the CO₂ density at the temperature of trap and maximum injection pressure, t/m³; and V_trap is the geometrical volume of trap down to the spill point, m³.

$$M_d=(A\times H\times \phi \times (1-S_w)\times (1-R_w)\times C_w+A\times H\times \phi \times S_w\times R_w)\times \rho {CO}_2$$

(3)

where M_d is the CO₂ capacity by solubility sequestration, t; A is the area of coal, m²; H is the thickness of coal, m; φ is the porosity, dimensionless; S_w is the water saturation, dimensionless; R_w is the recovery of reservoir water, dimensionless; C_w is the CO₂ solubility coefficient in water, dimensionless; and $\rho {CO}_2$ is the CO₂ density, t/m³.

$$M_a={\rho CO}_2\times A\times H\times Gc\times {\rho }_{Coal}\times RF\times ER$$

(4)

where M_a is the CO₂ capacity by adsorption sequestration, t; G_c is the gas content, m³/t; $\rho Coal$ is the density of coal, t/m³; RF is the recovery factor, dimensionless; and ER is the CO₂/CH₄ displacement ratio, dimensionless.

Based on critical geological and reservoir parameters in different areas, the estimated global CO₂ sequestration capacity in coal reaches 964 Gt [98,99]. Considering sequestration as non-commercial development, the CO₂ sequestration capacity is significantly higher [100,101]. Moreover, some scholars have estimated the CO₂ sequestration capacity in coal in specific areas, which is high in the USA, China, and India with numerous coal-bearing basins (

Table 1. Estimated CO₂ sequestration capacity in coal in different areas.

Areas		Capacity	References
USA	Illinois Basin	4.00 Gt	[102]
	Powder River Basin	21.25 t/m2	[103]
	San Juan, Uinta and Raton Basins	8.50 Gt	[104]
	San Juan Basin	90.00 Gt	[105]
China		142.67 Gt	[106]
China	Qinshui Basin	0.19 t/m2	[107]
Russia	Kuznetsk Basin	13.60 Gt	[104]
Netherlands		3.00 Gt	[108]
Netherlands	Zuid Limburg, Peel, Achterhoek, and Zeeland	8.00 Gt	[109]
India		0.76 Gt	[110]
India	Cambay Basin	3.80 Gt	[104]
Australia		30.00 Gt	[51]
Australia	Bowen and Sydney Basins	11.20 Gt	[104]
Brazil	Santa Terezinha Basin	13.80 Gt	[111]

).

3. Comparisons of CO₂ Sequestration in Coal and Saline Aquifers

Current CO₂ sequestration field applications are mostly conducted in saline aquifers, such as Aquistore in Canada, Sleipner in Norway, CO₂CRC Otway in Australia, Ketzin in Germany, and Tomakomai in Japan [112,113], and the theory/technology of CO₂ sequestration in saline aquifers is fruitful. Therefore, the similarities and differences between CO₂ sequestration in coal and saline aquifers are summarized in this study (

Table 2. Comparisons of CO₂ sequestration in coal and saline aquifers.

	Coal	Saline Aquifers
Caprocks	Tight formations
Mechanism	Structural, solubility, residual gas and mineral sequestration
	Adsorption sequestration	/
Critical sequestration state	Adsorbed (rapid)	Dissolved (slow)
Capacity	Lower North America: 54–113 Gt China: 142.67 Gt	Higher North America: 2379–21,633 Gt China: 143.5 Gt
Extra benefits	CBM production	/

). The overlying layers of coal and saline aquifers are both tight formations, prohibiting the upward migration of CO₂, and some similar sequestration mechanisms are similar: structural, solubility, and mineral sequestration. However, the adsorption sequestration is a unique mechanism for CO₂ sequestration in coal, while the residual gas sequestration occurs in CO₂ sequestration in saline aquifers. Differences in sequestration mechanisms and coal/saline aquifer resources lead to the fact that the sequestration capacity in saline aquifers is generally higher than that in coal, especially in North America. However, CO₂ sequestration in coal can promote CBM production, providing energy and environmental (inhibiting CH₄ emissions) benefits. Differences in the sequestration mechanism also lead to the variations in critical sequestration state; when the geological conditions are similar (with same structural sequestration capacity), the CO₂ is mainly sequestered in the dissolution state in saline aquifers. Due to the generally low moisture and mineral contents, the CO₂ is mainly sequestered in the adsorption state in coal, and Jiang et al. [46] also indicated that the CO₂ sequestration capacity in the adsorption state in coal was 15 times that in the dissolution state. The dominant sequestration mechanisms in different periods after CO₂ injection vary greatly, with the structural and adsorption sequestration peaking rapidly, followed by the residual gas and solubility sequestration, and the mineral sequestration generally requires a very long time with limited sequestration amount (Figure 4). This indicates that more CO₂ can be sequestered in coal in the early stage with similar geological conditions. In summary, compared with saline aquifers, the superiority of CO₂ sequestration in coal is rapid sequestration induced by adsorption and extra energy benefits.

4. Efficiency of CO₂ Sequestration in Coal

Current CO₂-ECBM practices have shown difficulties in sustained CO₂ injection, directly restricting CO₂ sequestration efficiency in coal. This section reviewed parameters affecting CO₂ injection and approaches to enhance injection efficiency.

4.1. Effects of Matrix Swelling Induced by CO₂ Adsorption on Injection

Coal generally swells after gas adsorption [114], with the strain showing a positive correlation with adsorption capacity and a negative correlation with mechanical strength [90,115]. Some parameters affect the adsorption capacity/mechanical strength and thus indirectly lead to the difference in swelling. (1) Gas type: The adsorption capacity of CO₂ is generally higher than that of CH₄, and the swelling due to CO₂ adsorption is approximately 2–8 times than that induced by CH₄ adsorption [116,117,118,119]. Moreover, the swelling rate of CH₄ is also slower than that of CO₂ [25,119]. (2) Pressure: The adsorption capacity generally shows a rapid increase–slow increase with increasing pressure, and Kumar et al. [120] and Mukherjee and Misra. Ref. [25] found a similar variation in swelling, with a rapid increase–slow increase swelling with increasing pressure. (3) Mineral contents: The adsorption capacity mostly shows a negative correlation with mineral contents, and the mechanical strength of minerals is generally higher than that of organic matter [121,122]. Zhang et al. [123] found that CO₂ adsorption caused 0.082% more deformation in the medium-ash sample than in the high-ash sample (at a pressure of 2.3 MPa). (4) Coal rank: Syed et al. [124] pointed out that the swelling of high rank coal was larger than that of low rank coal, which is related to more micropores and higher adsorption capacity.

Coal matrix deformation leads to changes in permeability, in turn affecting continuous CO₂ injection [11,83,125,126]. The permeability of coal can increase due to the shrinkage induced by CH₄ desorption, but the deformation induced by CO₂ adsorption is generally higher than that induced by CH₄, leading to a continuous decrease in permeability after CO₂ injection [74,125,127,128,129]. Syahrial [130] found that CO₂ injection could result in a 1000% reduction in permeability, and Kumar et al. [120] pointed out that swelling due to CO₂ adsorption reduced permeability by 500–1000%. The reduction in permeability is accompanied by fracture closure and inhibits CO₂ injection, which is a critical issue to be addressed for CO₂ sequestration in coal.

4.2. Effects of CO₂ Corrosion on Injection

Natural gas pipelines mostly utilize carbon steel, which is accompanied by excellent mechanical properties and low cost [131]. However, CO₂ solutions are acidic, leading to severe corrosion of pipelines [132,133,134,135,136]. The corrosion degree is related to CO₂ partial pressure, temperature, salinity, moisture content, phase, and pH [137,138,139], and the corrosion rates reach 20 mm/year at high CO₂ pressures without FeCO₃ protection [140]. Therefore, corrosion is a serious constraint to stable CO₂ injection.

4.3. Approaches to Enhance CO₂ Injection Efficiency

The acid corrosion and reduction in permeability restrict CO₂ injection efficiency and sequestration capacity, and many approaches have been proposed to enhance CO₂ injection efficiency.

4.3.1. Inhibiting the Reduction in Permeability

As the matrix swelling induced by CO₂ adsorption in CO₂ sequestration and CO₂-ECBM is similar, studies focusing on inhibiting the reduction in permeability during CO₂-ECBM are reviewed in this section. The approaches to increase coal permeability before and during injection can be classified into six categories. (1) Pre-fracturing: Pre-fracturing can effectively increase the initial permeability of coal and reduce stress sensitivity, thus enhancing CO₂ injection capacity [141], and hydraulic fracturing [82,142], cyclic freeze–heat action [143], and CO₂ phase-change fracturing are frequently utilized [144]. (2) Horizontal wells: Compared with straight wells, horizontal wells can increase the CO₂ transport range and the size of the fracture network, and field tests of horizontal wells in the Qinshui Basin, China, have shown that the CO₂ injection capacity does not show a significant reduction with increasing time [64,145,146]. (3) CO₂ + N₂ injection: N₂ injection is an important method to enhance CBM recovery (N₂-ECBM), which has been applied in Canada and China since 1993 [67,82,147,148]. Unlike CO₂-ECBM, the shrinkage induced by the N₂-ECBM increases permeability. The deformation of coal during CBM adsorption–desorption with/without nitrogen injection (the pressure is the same as the adsorption pressure) experiments were conducted in our previous studies. The results showed that the coal swelled after adsorption–desorption without nitrogen injection, and the coal shrank after adsorption-nitrogen injection–desorption, indicating that nitrogen injection leads to significant shrinkage of the matrix. Therefore, utilizing N₂ + CO₂ mixtures to balance the CO₂ adsorption-induced swelling is an effective method to enhance the CO₂ injection capacity [149,150,151,152]. The critical issue of CO₂ + N₂ injection is to determine the optimal gas compositions, as a high N₂ concentration is prone to N₂ breakthrough and difficulties in later gas treatment [153,154,155]. The optimal gas composition is closely related to coal rank and geomechanical characteristics, leading to a unique optimal concentration for each area [155,156,157,158]. For example, the optimal gas composition was 35%CO₂ + 65%N₂ in the Fanzhuang Area, Qinshui Basin, China, leading to an increase in CH₄ production of 59.4% [159], and the maximum CBM recovery was achieved when employing 30%CO₂ + 70%N₂ in the Hancheng Area, Ordos Basin, China [160]. Moreover, many studies consider that variable-component injection is superior to constant-component injection, and the injection should follow the principle of gradual increase in CO₂ concentration [159,161,162,163]. For example, Fan et al. [159] found that the maximum CBM recovery in the Fanzhuang Area, Qinshui Basin, China could increase by 5% when replacing constant-component injection by variable-component injection. (4) Delayed injection time: Delayed injection time facilitates higher shrinkage from CH₄ desorption, leading to an increase in permeability and CO₂ injection capacity [83,87,88]. (5) Optimizing injection pressure: As a high CO₂ injection pressure leads to significant velocity sensitivity and a large reduction in permeability [164,165], optimizing the injection pressure is an approach to enhance CO₂ injection capacity. Zhao et al. [166] found that, when the injection pressure was lower than the initial reservoir pressure, the swelling induced by CO₂ adsorption and pore pressure reduction was smaller than the shrinkage induced by CH₄ desorption, leading to an increase in permeability. Su et al. [167] proposed a gradually increasing CO₂ injection pressure approach based on the change in permeability, and the degree of permeability attenuation was lower adopting variable-pressure injection, which is favorable for continuous CO₂ injection. (6) Cycled injection: Similar to the variable-pressure injection, the reduction in permeability can be inhibited by injection–shutdown cycles, which in turn enhances CO₂ injection [60,117].

4.3.2. Inhibiting Corrosion

The approaches to inhibit CO₂ corrosion can be divided into three categories: (1) Using corrosion-resistant materials, such as 13% chromium stainless steel and high-nickel alloys. (2) Utilizing coatings as oil pipe linings, such as epoxy resin, phenolic resin, nylon, phenolic varnish, and glass fiber. (3) Employing corrosion inhibitors: Injecting chemical reagents to inhibit CO₂ corrosion, such as Cl, quaternary, amine, and imidazoline [138,168,169,170,171]. It is worth noticing that ScCO₂ has an extremely high corrosion rate on carbon steels, and ScCO₂ can even corrode the 13% chromium stainless steel [172].

5. Leakage Risk of CO₂ Sequestration in Coal

The migration and leakage are critical for CO₂ geological sequestration [173], and numerical simulations have shown that CO₂ in coal is prone to leakage to the overlying formations and outcrops under certain conditions, which can lead to negative effects, such as shallow groundwater pollution [174,175,176,177]. Therefore, this section reviewed the changes in coal/rocks properties induced by CO₂–water interactions and established the geological model of CO₂ leakage risk.

5.1. Changes in Integrity of Caprock Induced by CO₂–Water Interactions

CO₂ dissolution increases the acidity of groundwater, and the pH with CO₂ dissolution equilibrium is 2.84 when the temperature and pressure are 40 °C and 7 MPa, respectively [178]. Consequently, CO₂ injection leads to the dissolution or precipitation of minerals, such as carbonates like calcite, and chemical reactions which frequently occur in coal measures are as follows (Equations (5)–(20)) [25,49,179,180,181,182,183]:

$$C{O}_2\left(g\right)\to C{O}_2\left(aq\right)$$

(5)

$$C{O}_2\left(g\right)+H_{2}O\left(l\right)\rightleftharpoons H_{2}C{O}_3\left(aq\right)\rightleftharpoons H^{+}\left(aq\right)+HC{O_3}^{-}\left(aq\right)\rightleftharpoons H^{+}\left(aq\right)+{C{O}_3}^{2-}\left(aq\right)$$

(6)

$$A{l}_{2}S{i}_2{O}_5{\left(OH\right)}_4\left(Kaolinite, s\right)+6H^{+}\left(aq\right)\to 5H_{2}O+2Si{O}_2\left(aq\right)+2A{l}^{3+}\left(aq\right)$$

(7)

$$Illite+8H^{+}\left(aq\right)\to 5H_{2}O\left(l\right)+0.6K^{+}\left(aq\right)+0.25M{g}^{2+}\left(aq\right)+3.5Si{O}_2\left(aq\right)+2.3A{l}^{3+}\left(aq\right)$$

(8)

$$NaAlS{i}_3{O}_8\left(Na feldspar,s\right)+C{O}_2\left(g\right)+H_{2}O\left(l\right)\to NaAl\left(C{O}_3\right){\left(OH\right)}_2\left(s\right)+3Si{O}_2\left(s\right)$$

(9)

$$KAlS{i}_3{O}_8\left(K feldspar,s\right)+N{a}^{+}\left(aq\right)+C{O}_2\left(g\right)+2H_{2}O\left(l\right)\to NaAl\left(C{O}_3\right){\left(OH\right)}_2\left(s\right)+3Si{O}_2\left(s\right)+K^{+}\left(aq\right)$$

(10)

$$CaC{O}_3\left(Calcite, s\right)+H^{+}\left(aq\right)\to C{a}^{2+}\left(aq\right)+H{C{O}_3}^{-}\left(aq\right) \mathrm{only} \mathrm{at} \mathrm{high} \mathrm{Ph} \mathrm{values} \mathrm{only}$$

(11)

$$Chlorite+20H^{+}\left(aq\right)\to 5F{e}^{2+}\left(aq\right)+5M{g}^{2+}\left(aq\right)+4Al{\left(OH\right)}_3\left(aq\right)+6H_{4}Si{O}_4\left(aq\right)$$

(12)

$$CaMg{\left(C{O}_3\right)}_2\left(Dolomite, s\right)+2H^{+}\left(aq\right)+M{g}^{2+}\left(aq\right)+H{C{O}_3}^{-}\left(aq\right)$$

(13)

$$Si{O}_2\left(s\right)+2H_{2}O\rightleftharpoons H_{4}Si{O}_4\rightleftharpoons H^{+}+H_3{Si{O}_4}^{-}\rightleftharpoons H^{+}+{H_{2}Si{O}_4}^{2-}$$

(14)

$$C{a}^{2+}\left(aq\right)+{C{O}_3}^{2-}\left(aq\right)\to CaC{O}_3\left(Calcite, s\right)$$

(15)

$$F{e}^{2+}\left(aq\right)+{C{O}_3}^{2-}\left(aq\right)\to FeC{O}_3\left(Siderite, s\right)$$

(16)

$$M{g}^{2+}\left(aq\right)+{C{O}_3}^{2-}\left(aq\right)\to MgC{O}_3\left(Magnesite, s\right)$$

(17)

$$C{a}^{2+}\left(aq\right)+{S{O}_4}^{2-}\left(aq\right)\to CaS{O}_4\left(Anhydrite, s\right)$$

(18)

$$K^{+}\left(aq\right)+3A{l}^{3+}\left(aq\right)+{2S{O}_4}^{2-}\left(aq\right)+6H_{2}O\left(l\right)\to KA{l}_3{\left(S{O}_4\right)}_2{\left(OH\right)}_6\left(Alunite, s\right)+6H^{+}\left(aq\right)$$

(19)

$$C{a}^{2+}\left(aq\right)+M{g}^{2+}\left(aq\right)+{2HC{O}_3}^{-}\left(aq\right)\to CaMg {\left(C{O}_3\right)}_2\left(Dolomite, s\right)+2H^{+}\left(aq\right)$$

(20)

The mineral dissolution–precipitation equilibrium induced by CO₂ treatment is related to many conditions, and Kim and Santamarina [184] divided the area around the CO₂ injection well into four distinct zones (Figure 5). Zone I was unaffected by CO₂ injection, and Zone II was dominated by acidified brine with more mineral dissolution than precipitation. In Zone III, the ion concentration of the brine increased, and salt precipitation may occur. A sustained influx of “dry” CO₂ into Zone IV first displaced the brine and then dried out the residual brine, leading to salt precipitation.

The rock properties vary greatly when changing chemical compositions, and the integrity of caprocks is consistently a critical issue for CO₂ sequestration. An increase in the permeability of caprocks also leads to the CO₂ leakage risk. As the caprocks of coal are generally shale, siltstone, and sandstone, the changes in the properties of these rocks after CO₂ treatment indicate the integrity of caprocks for CO₂ sequestration in coal. Variations in mechanical properties and permeability induced by CO₂–water interaction depend on the competition of multiple effects (Figure 6): (1) Weakened mechanical properties and decreased permeability due to CO₂ adsorption [181,185,186,187]. (2) Weakened mechanical properties due to moisture loss in pores [188]. (3) Weakened mechanical properties and increased permeability induced by mineral dissolution, and enhanced mechanical strength and decreased permeability due to precipitation [183,189,190,191,192,193,194,195,196]. (4) Increased stress sensitivity due to weakened mechanical properties [197,198].

Some geological parameters affect the mentioned processes, leading to differential changes in mechanical properties and permeability. (1) Temperature: Changes in temperature affect both mineral dissolution–precipitation equilibrium rates and CO₂ adsorption capacity, and the effect of temperature on rock mechanical properties varies greatly in different studies. For example, Li et al. [199] found that the degradation of micromechanical parameters after CO₂ treatment was more pronounced at high temperatures, but Yang et al. [200] pointed out that the mechanical weakening was negatively correlated with temperature. (2) Pressure: Due to the significant compression effect at high pressure, the compressive strength and Young’s modulus decreased and then increased with increasing ScCO₂ treatment pressure [201]. Moreover, the CO₂ phase varies greatly when changing temperature and pressure. Compared with CO₂ and subcritical CO₂ (SubCO₂), ScCO₂ generally leads to a greater reduction in UCS and Young’s modulus due to its higher adsorption capacity and adsorption-induced swelling [202,203,204,205]. (3) Mineral compositions: After CO₂–water treatment, changes in permeability and mechanical strength in carbonate-rich rocks are generally higher than those in clay/quartz-rich rocks [191,206,207,208]. However, a high montmorillonite content exhibits strong hydration, leading to a significant reduction in mechanical strength [209]. (4) Moisture content: As the geochemical reactions are generally enhanced when adding aqueous fluids, and CO₂–water–montmorillonite interactions exert a secondary effect (hydration), changes in permeability and mechanical strength are positively correlated with moisture content [187,210,211,212,213,214]. (5) Pore structure: New pores and fractures are formed after mineral dissolution, but only connected pores lead to changes in permeability. For example, Hangx et al. [215] found that, although complete dissolution of calcite was observed in the sandstone, no measurable decrease in mechanical strength occurred, which is related to the fact that the grain contact is sufficiently cemented by quartz and unaffected by CO₂–water interactions.

CO₂ sequestration should ensure that the gas will not leak within at least a few decades, and it is impractical to conduct long-term CO₂–water–rock interaction experiments for each area. Some studies have mathematized the long-term changes in permeability and mechanical properties into the coupling of geomechanics and geological processes [71,216,217,218,219]. Accordingly, simulation programs have been established, such as FEFLOW [220], TOUGHREACT [221,222], and PHREEQC [223]. However, different limitations are shown in these models; for example, FEFLOW is limited by its weak geochemical capabilities, high computational costs, and limited support for complex reactions. TOUGHREACT faces challenges such as low grid flexibility, difficulties in chemical reaction convergence, and insufficient advanced transport functionalities. PHREEQC lacks flow/multidimensional transport capabilities and does not support multiphase flow. Therefore, model coupling is generally employed to compensate for the limitations of individual tools in practical applications.

5.2. Changes in Coal Properties Induced by CO₂–Water Interactions

Similar to the caprock, changes in the reservoir integrity are critical. Variations in the mechanical properties of coal induced by CO₂–water interaction depend on the competition of multiple effects (Figure 7): (1) Weakened mechanical properties due to decreasing surface energy caused by CO₂ adsorption [224,225,226,227]. (2) Weakened mechanical properties due to plasticization, which is caused by changes in macromolecular and microcrystalline structure [228,229,230,231]. (3) Weakened mechanical properties due to localized fractures, which are formed by differential swelling [232,233,234,235,236]. (4) Weakened mechanical properties due to mineral dissolution and less change in mechanical properties due to precipitation filling of fractures [237,238,239,240,241,242,243].

Differential changes in the mechanical properties of coal are related to some geological parameters: (1) Pressure: The adsorption capacity increases with increasing pressure, leading to a greater decrease in the mechanical strength, but this effect diminishes with increasing pressure [85,225,244,245,246,247,248,249,250,251,252,253,254,255,256,257,258]. For example, Liu et al. [249] found that the mechanical strength of the coal decreased rapidly (up to 35.6%) when the pressure increased from 7.5 to 15.0 MPa. Subsequently, a limited further reduction (<9%) occurred when the pressure further increased to 25.0 MPa. Moreover, a higher adsorption affinity of ScCO₂ generally leads to greater mechanical strength reduction [225,247,250]. Zhang et al. [247] found that the reduction in compressive strength of coal after CO₂ + water and ScCO₂ + water treatment was 5.29% and 9.69%, respectively. (2) Moisture content: Water accelerates mineral dissolution and organic matter extraction, exacerbating the degradation of mechanical properties [250,251,252,253]. For example, Yang et al. [253] found that the reduction in compressive strength of coal was less than 13% after ScCO₂ treatment in dry conditions, and the compressive strength decreased by 26.58–44.21% after water saturated. (3) Coal rank: Compared with low rank coal, the high rank coal has a high adsorption capacity and more fractures, leading to greater mechanical property deterioration [254,255].

As CO₂ is mostly sequestered in coal by physical/chemical adsorption, changes in adsorption capacity are critical, which are controlled by two competing actions (Figure 6). The organic matter is extracted by CO₂ (especially ScCO₂)–water interactions and oxygen-containing functional group contents decrease, leading to the change from adsorbed water to free water and enhanced physical adsorption [256,257]. However, CO₂ can occupy C=O groups and the reduction in oxygen-containing functional groups inhibits chemical adsorption [22,23,24,258]. On the other hand, organic matter extraction and mineral dissolution lead to changes in porosity, pore size distribution, and SSA, and variations in pore structure are affected by some parameters. (1) Temperature: Du et al. [259] found that, during CO₂–water–coal interactions, the pores with a size of 1.5–8.0 nm changed significantly, with SSA and pore volume decreasing with increasing temperature. (2) Pressure: Changes in SSA and pore volume generally increase and then decrease with increasing pressure [249,260]; for example, when the pressure was 9.8 MPa, the SSA decreased after ScCO₂ treatment, but when the pressure increased to 14.7 MPa, the SSA increased to be similar to that before treatment. (3) Coal rank: The SSA after CO₂ treatment shows a parabolic correlation with increasing coal rank [261,262,263], but the inflection variations are diverse. The SSA decreased after ScCO₂ treatment when the R_o was less than 1.0%, and increased when the R_o exceeded 1.0% [261]. The ScCO₂ treatment had a slight effect on the micropores, but significantly reduced the mesoporous SSA of the bituminous coal, and increased that of the anthracite [263]. (4) Mineral compositions: After ScCO₂ treatment, the SSA of high-ash coal decreases significantly, but that of low-ash coal generally increases, and the increase in SSA is positively correlated with the carbonate content [264,265]. (5) Moisture content: Gathitu et al. [266] found that, during ScCO₂–water treatment, the SSA of micropores increased by 8.1–73.5%, and that of mesopores and macropores decreased by 18.6–77.5%, but the opposite changes were observed under dry conditions. (6) Coal structure: Su et al. [267] pointed out that, after ScCO₂ treatment, the total pore volume, SSA, and pore connectivity of the tectonic coal increased more than those of the intact coal. (7) Coal type: Massarotto et al. [237] found that the increase in SSA exceeded 80% during ScCO₂–water treatment, and the increase in porosity was significantly higher in the bright coal than that in the dull coal.

The adsorption capacity generally has a positive correlation with SSA, and a reduction of 7.68–28.47% in SSA after CO₂ treatment led to a reduction of 0.80–7.85% in the Langmuir adsorption capacity [258]. Therefore, changes in adsorption capacity during long-term CO₂–water–rock interactions affect the CO₂ leakage risk.

6. Prospects for Future Studies

Compared with saline aquifers, the superiority of CO₂ sequestration in coal is rapid sequestration induced by adsorption and extra energy benefits. However, the CO₂ sequestration capacity in coal is lower than that in saline aquifers, and variations in the physicochemical properties of coal/rock after CO₂ injection cannot be accurately predicted in current studies, leading to uncertain leakage risk. Some critical issues remain to be issued for effective CO₂ sequestration in coal.

(1)

Increasing the CO₂ adsorption capacity of coal

The global annual CO₂ emissions still increase, and the current estimation shows that the CO₂ sequestration capacity in coal is lower than that in saline aquifers. As the CO₂ adsorption capacity directly determines the upper limit of sequestration, it may be possible to enhance this capacity through physical or chemical treatment. For example, Giraldo et al. [268] utilized silica nanoparticle inclusions to treat coal, and the CO₂ adsorption capacity increased from 0.05 to 0.75 mmol g⁻¹, with an increase of greater than 1000%. This can lead to significantly increasing CO₂ sequestration capacity, but it remains unclear whether this method can be applied to all coal.

(2)

Establishing optimal approaches for enhancing CO₂ injection efficiency

Various approaches have been proposed to increase CO₂ injection capacity, such as pre-fracturing. However, it is essential to clarify the optimal methods for different areas based on the specific conditions. For example, as the cost of pre-fracturing and horizontal wells is significantly higher, and fracturing may be ineffective for broken coal, the characteristics of coal suitable for increasing CO₂ injection through pre-fracturing and horizontal wells should be summarized. CO₂ + N₂ injection can inhibit the permeability reduction induced by matrix swelling, but the optimal gas compositions are related to coal rank and geomechanical characteristics [155,156,157], and how to efficiently determine the optimal concentration has not been clarified. Therefore, establishing a CO₂ injection assessment framework based on critical parameters, such as geological conditions and CBM resource value, is an issue to be addressed to ensure efficient CO₂ injection.

(3)

Predicting the long-term variations in coal/caprock properties induced by CO₂–water interactions

It is critical to prohibit CO₂ leakage after injection, and conducting long-term CO₂–water–rock interactions is impractical. Numerical simulation is an effective approach to address this problem, but the properties of coal/rock vary greatly, leading to significant differences in the types and rates of chemical reactions. A universally applicable chemical–mechanical model has not been established, and the critical input parameters for CO₂ leakage prediction remain unclear. Artificial intelligence widely applied in current studies has provided favorable ideas. Gorucu et al. [269] developed the PSU-COALCOMP software to generate a large number of datasets to train the artificial neural network, and screened thousands of possible operating conditions for optimizing the design parameters of a CO₂ sequestration project within seconds. Mohammadpoor et al. [270] predicted CO₂ sequestration capacity utilizing porosity, permeability, and other parameters based on a back-propagation learning algorithm and artificial neural network model. Roy and Singh [271] and Sampath et al. [272] predicted the change in mechanical properties of coal during CO₂ interactions based on experimental data and machine learning techniques, such as artificial neural networks, adaptive neuro-fuzzy inference systems, and statistical tools such as regression analysis. Therefore, based on these studies, integrating numerous experimental and simulation results in previous studies and conducting machine learning in combination with artificial intelligence can accurately predict the leakage risk of CO₂ sequestration in coal.

7. Conclusions

This study comprehensively reviewed the mechanism of CO₂ sequestration and variations in physical/chemical properties of coal/rock/CBM during and after CO₂ injection, and the main differences between CO₂ sequestration in coal and saline aquifers were summarized. Geological models of CO₂ leakage risk were established, and consequently, critical issues to be addressed in future studies were clarified. The main conclusions are as follows.

(1)

Compared with saline aquifers, the superiority of CO₂ sequestration in coal is rapid sequestration induced by adsorption and extra energy benefits.

(2)

The significant reduction in permeability induced by matrix swelling and corrosion inhibits the CO₂ injection efficiency, and utilizing coatings, corrosion inhibitors, pre-fracturing, horizontal well injection, CO₂ + N₂ injection, delayed/cycled injection, and optimizing injection pressure are effective methods to increase the capacity of CO₂ injection.

(3)

During long-term CO₂–water–rock interaction, the decreasing adsorption capacity due to organic matter extraction and variations in caprock/reservoir integrity leads to the CO₂ leakage risk.

(4)

Increasing the CO₂ adsorption capacity of coal, establishing optimal approaches for enhancing the CO₂ injection efficiency, and predicting the long-term variations in coal/caprock properties are critical issues to be addressed, which can be facilitated by material surface engineering and AI-based predictive modeling.