A Review on the Influence of CO 2 /Shale Interaction on Shale Properties: Implications of CCS in Shales

: Carbon capture and storage (CCS) is a developed technology to minimize CO 2 emissions and reduce global climate change. Currently, shale gas formations are considered as a suitable target for CO 2 sequestration projects predominantly due to their wide availability. Compared to conventional geological formations including saline aquifers and coal seams, depleted shale formations provide larger storage potential due to the high adsorption capacity of CO 2 compared to methane in the shale formation. However, the injected CO 2 causes possible geochemical interactions with the shale formation during storage applications and CO 2 enhanced shale gas recovery (ESGR) processes. The CO 2 /shale interaction is a key factor for the efficiency of CO 2 storage in shale formations, as it can significantly alter the shale properties. The formation of carbonic acid from CO 2 dissolution is the main cause for the alterations in the physical, chemical and mechanical properties of the shale, which in return affects the storage capacity, pore properties, and fluid transport. Therefore, in this paper, the effect of CO 2 exposure on shale properties is comprehensively reviewed, to gain an in ‐ depth understanding of the impact of CO 2 /shale interaction studies are needed to include various shale formations and identify how different shales’ mineralogy could affect the CO2 storage capacity in the long ‐ term. observed in shale strength with changing the bedding angles ( θ ); both tensile and shear failure could occur affecting the shale resistance and cracking propagation. This study found a strong connection between the damage in pore structure and the weakening of shale strength. The possible damage in shale macroscopic structure increases the stress–strain in the initial compaction stage, which results in reducing shale strength.


Introduction
The development of carbon capture and storage (CCS) stands as a suitable technology to reduce the massive increase in CO2 emissions in recent decades, as global climate change is becoming a serious concern to the public environment and economic growth [1]. CO2 geological sequestration was proposed as a reliable technique to mitigate the emissions of greenhouse gas from fossil fuels into the atmosphere, by injecting CO2 for long-term storage and enhancing gas recovery [2][3][4]. Conventional geological formations with high pore volume, including saline aquifers, depleted oil and gas fields, and un-minable coal seams, were utilized as suitable candidates for CCS projects [5]. However, some concerns related to these formations, including cost and long-term storage, prevent efficient CO2 storage [6]. The trapping mechanism during CO2 storage is usually associated with the CO2/rock interactions in the porous medium, including CO2 absorption, minerals dissolution, dissolution trapping, capillary trapping, rock heterogeneity and physical adsorption [7]. The trapping mechanism in deep saline aquifers, for instance, is mainly driven by structural trapping; when the injected CO2 diffuses into the formation, it reaches the top layer due to the buoyance factor, hence CO2 would be trapped by an impermeable caprock [1]. Coal seams that have been proven to have economic potential for CCS projects at extremely deep locations are driven by an adsorption trapping mechanism, yet the injection of CO2 is more likely to cause high swelling rates and many environmental issues [8]. In depleted reservoirs, gas absorption and structural trapping effectively work as CO2 trapping mechanisms. The injected CO2 will be absorbed by the immobile residual oil causing multiple-contact miscibility [7].

Development of Shale Formations
The success in developing shale formations in recent decades has shifted attention towards shale reservoirs, and considered them as promising candidates to store CO2 for extended periods [9], mainly because shales with their ultralow permeability play a major role as barriers or seals in a petroleum reservoir system, and also due to their wide availability worldwide [7,[10][11][12][13][14][15]. The breakthrough made in technology to utilize CO2 (instead of slick-water) in developing shale formation during drilling, fracturing, and enhanced shale gas recovery (ESGR) processes leads to minimizing many environmental issues during the operations, i.e., minimizing the amount of produced wastewater and increasing the production efficiency of gas while sequestering the adsorbed CO2 simultaneously [16][17][18]. These developed technologies, including hydraulic fracturing and horizontal drilling make commercial development of shale formations possible. In the US, shale gas production has increased since 2010 from about 6.16 trillion cubic feet to exceeding 20 trillion cubic feet in 2020, and is expected to reach about 35 trillion cubic feet in 2050. Forty-nine percent of the total US gas production is expected to come from shale reservoirs by 2035 [19], securing the gas production for the upcoming decades and providing the potential for CCS projects [20,21]. As illustrated in Figure 1, CCS applications hold good promise in reducing CO2 emissions in the coming decades, despite the increase in energy demands. However, effective utilization of depleted shale gas formations as storage sites for CO2 can significantly contribute to minimizing CO2 emissions, assuming good connectivity between induced and existing fractures and no pore space collapse [22].

Adsorption Capacity of CO2 in Shales
Carbon dioxide is a non-toxic fluid that is present at the reservoir in the supercritical phase when the temperature and pressure exceed 31.8 °C and 7.38 MPa, respectively. Supercritical CO2 (SCCO2) has low viscosity and no surface tension, with a high adsorption capacity relative to methane gas (CH4) to the shale formation [22,23]. CO2 sorption on clay and kerogen in partially depleted wells allows the displacement of CH4 and stores more CO2 [24][25][26]. As noted by many studies [13,15,[26][27][28], the high CO2 adsorption capacity is the main derive mechanism for CO2 storage in shale formation after production phase, as injecting CO2 continuously leads to the release of the natural pre-adsorbed CH4 during CO2 fracturing stimulation due to the displacement mechanism and higher chemical potential. Nuttall et al. [15] presented the adsorption isotherms between CO2 and CH4 in Devonian shale formations, showing stronger CO2 adsorption than CH4, providing the potential for CO2 sequestration in shales ( Figure 2). A study conducted by Kang et al. [7] on Barnett shales confirmed the strong adsorption capacity of CO2, which was 5-10 times higher compared to CH4. The adsorption of CO2 in most shales in the US indicated a similar tendency of higher adsorption than CH4, by 2-3 times [29]. The strong CO2 capacity provides high storage security in shale formation due to the existence of stable in-place CH4 in the reservoir, which can be related to the fact that five CO2 molecules can displace one CH4 molecule, which allows the CO2 to occupy the porous medium, providing the potential for storage application [28]. Later research has come to a similar conclusion from measuring the adsorption behavior of CO2 and CH4 on different shale formations, indicating that shale formations favor adsorbing CO2, enhancing the recovery of CH4, preventing massive leakage risks and reducing storage costs [29][30][31]. Tao and Clarens [6] estimated that Marcellus shale could store a total mass of CO2 ranging between 10.4 and 18.4 gigatonnes (Gt) (1 Gt = 10 12 kg), offering the potential to store around 50% of CO2 emissions in the US by 2030 [22]. Similarly, Edwards et al. [32] presented that Barnett Shale has a CO2 storage capacity ranging between 2.1-3.1 Gt. These studies provide a strong foundation for the investigation of the feasibility of CCS projects in shale formations, confirming the high possibility of storage capacity in shale formations by multiple trapping mechanisms [6,10,32,33].

CCS in Shales
The injection of CO2 into depleted shale formations may help to recover additional hydrocarbons through the ESGR process, which provides economic benefits in CCS compared to conventional storage sites. Shale formations are very promising targets for CCS, however, the rate of CO2 injection into the shale formation should be coupled with the rate of CO2 capture from industrial processes such as fossil fuels in power plants, ensuring the storage safety, stability and economic feasibility [4,32,33]. CO2 is a relatively reactive substance; once injected into the shale formation, it will be trapped in the adsorbed phase. In the long-term, formation brine will dissolve the injected CO2 and causes reactions with the shale rock, leading to mineral precipitation and dissolution which may affect the shale storage capacity [1,38]. The CO2/shale interaction is a key factor for the efficiency of CCS in shale formations; it can significantly alter the shale properties, which in return affect the rock geometry, fluid transportation, and storage capacity [39,40]. The presence of organic and inorganic components in a heterogeneous porous medium such as shale permits the injected CO2 to interact with clay minerals and organic matter through chemical dissolution [39]. This dissolution behavior of CO2 can be related to the creation of carbonic acid when meeting a brine formation, leading to major changes in the shale properties [41,42].
In the last decade, enormous work was directed towards understanding the fundamentals of the CO2-shale interaction at reservoir conditions for better CCS applications [42][43][44][45][46][47][48][49][50][51][52], by evaluating the impact of CO2 injection on shales. Earlier in 2008, Busch et al. [53] found that the rock properties of Muderong shale in Australia were affected by the dissolution behavior of SCCO2. These findings were supported later by several studies [54][55][56], confirming that SCCO2 can significantly alter the pore structure system of shale, leading to changes in the porosity and the specific surface area. Some recent studies have related the effect of CO2/shale interaction on shale properties to the mineral composition and specific reservoir conditions, including temperature, pressure, and CO2 phase states [39,52,57,58]. However, the knowledge of CO2-shale interaction is still evolving, and more investigations are needed to successfully apply CCS technology in shale formations technically and economically. It is crucial to address the potential interactions between CO2 and shale formation, and their influence on CCS, to ensure the longevity of CO2 containment [10].
In this regard, the related literature of CO2/shale interaction and its effect on shales are comprehensively reviewed, to gain a wide understanding of the effect of CO2 injection on shale properties. The overall assessment of CCS viability in depleted hydrocarbon shale formations depends on its reliability in terms of technical feasibility, long-term CO2 containment and economic viability. Several studies [6,10,32,33] have supported the functionality of shales to host CO2, related to CO2 injectivity, storage capacity, methane gas recovery and CO2/shale interactions. However, this paper focuses on reviewing the existing knowledge of CO2-shale interactions and describing the results achieved to date. Therefore, the following sections address this issue and evaluate the implications of the overall storage capacity. This review also highlights the topics on Life Cycle Assessment (LCA) and the economic viability of CCS applications in shales. Long-term CO2 sequestration in shale formations causes CO2/shale geochemical interactions, such as mineral dissolution, gas adsorption and changes in pore structure, which affect the sealing integrity of the shale [39,53,59]. Because of the heterogeneity of shale, it is crucial to address several factors that could have a direct influence on shale properties for the specific shale formation, such as shale mineralogy, total organic carbon (TOC) content, surface morphology, geometry, pressure, and temperature [11]. This will help to evaluate the functionality of the targeted shale formation to host CO2 for extended periods. Recently, characterization of shale formation associated with CO2 injection has received much attention in the literature, for its importance in applying a cost-effective CCS project [60,61]. Many characterization methods, i.e., X-ray diffraction, scanning electron microscopy, X-ray fluorescence, low-pressure gas adsorption, Fourier transform infrared (FTIR) spectroscopy and nuclear magnetic resonance (NMR) are being widely applied to investigate the effect of CO2/shale interactions on physical and chemical properties of shales [18,39,43].

CO2-Shale Interaction
For this paper, and according to the nature of shale, the shale properties can be categorized under physical, chemical and mechanical properties; this classification is made based on the potential changes caused by CO2 injection. This review discusses the impact of CO2 exposure on some of the major shale properties, which are: (1) Pore structure, (2) Mineral composition, (3) Chemical properties, (4) Surface wettability and (5) Mechanical properties.

Pore Structure
The pore structure is one of the most affected properties of shale formation by CO2 injection, therefore, any changes in pore structure may impact the efficiency of CO2 storage capacity. This may lead to affect the economic feasibility of the CCS application. The ability of CO2 to dissolve and extract clay minerals is the main cause of the changes in the pore morphology, this dissolution behavior of CO2 can be attributed to the creation of carbonic acid and the chemical reaction with the formation water [41,42]. Generally, when the CO2 is injected into the shale, it is stored as free gas in the macropores structure; over time, the CO2-shale interaction takes place within the nanopore system, which in return affects the pore structure and its specific surface area (SSA), fractal dimension, total pore volume (TPV) and pore size distribution (PSD) [39]. Several studies have discussed the alteration of pore structure parameters when shales are exposed to CO2, confirming that the alteration of pore structure system is affected by multiple factors including, the type of shale sedimentary, the presence of clay and non-clay mineral in the formation, and reservoir's pressure and temperature [30,39,49,50,55,56]. The alteration in the pore structure system during CO2 injection is mainly influenced by the minerals' dissolution and precipitation. Shales are usually composed of clay minerals, quartz, carbonate, and fragments of other minerals. Several studies have characterized different shale formations and provided their typical mineral composition, as illustrated in Figure 3 [39, [62][63][64]. Liu et al. [59] reported that the CO2 has a limited impact on the caprock due to the miner dissolution of K-feldspar and anhydrite, along with low precipitation of illite, smectite (a mineral that contains Ca ++ and Mg ++ ), and siderite. On the contrary, Armitage et al. [65] reported an increase in the porosity and permeability of mudstone, due to the high dissolution of chlorite and siderite by CO2. This indicates that the differences in mineral composition for shales would result in wide variations in the pore structure system. Lahann et al. [56] addressed the mineralogical and petrophysical alteration of New Albany shales associated with the CO2 injection, indicating that various alterations in Brunauer-Emmett-Teller (BET)-specific surface area of the mesopore and micropore structure system could occur. At high pressure and temperature (24 MPa and 150 °C, respectively), the BET-SSA of both mesopore and micropore has increased with extended CO2 injection treatment time, mainly because of the gradual increase in CO2 solubility to dissolve carbonate minerals such as Ca ++ and Mg ++ at high pressures ( Figure 4; Figure 5). A later study by Jiang et al. [55] has confirmed that SCCO2 injection led to increasing SSA and porosity of Longmaxi shales with extending the treatment time, due to the extraction of organic matter from shale by SCCO2, which can be related to the grain size of shale. Moreover, with increasing the pressure, the SCCO2 density rises, permitting more organic matter to be dissolved in shale, thus increasing shale porosity [66][67][68][69]. Figure 6 shows the relationship between SSA and porosity at different SCCO2 treatment pressures.   Recent studies [18,30,39,43,[49][50][51] have further investigated the changes in the structural system of shales associated with SCCO2 injection, and following points can be concluded: (1) the extraction of organic matter and the dissolution of carbonate minerals by SCCO2 are the main causes for altering the pore structure system of shales, with a significant effect on micropores' and mesopores structure.
(2) In the long-term, high pressure and temperature could result in more extraction of organic matter in shale, which in return reduces the CO2 storage capacity. (3) The changes in shale's SSA and TPV are strongly related to the type of shale formation in term of surface mineralogy, surface morphology, and TOC; for instance, organic-rich shales are more likely to exhibit an increase in pore system [49,51,55,56], while the porosity and SSA of silty and low thermal maturity shales may decrease after SCCO2 treatment [18,30,39,43].
The CO2-shale interaction can also affect the shale's fractal dimensions after SCCO2 exposure. Shales generally have complex inner porosity and irregular surface morphology, and the fractal dimension (D) index is used to quantitatively evaluate the structural complexity and surface roughness of solids [70]. Yin et al. [30] reported a reduction in the shale surface roughness caused by the CO2 adsorption-induced swelling, which gradually transformed the surface morphology of shales from an irregular-complex structure to a smooth-regular structure. Consistently, Pan et al. [39] concluded that the extraction of organic matter in shales is the main mechanism for reducing the fractal dimensions of micropores structure after SCCO2 treatment. However, a recent study by Luo et al. [50] reported opposite results, indicating an increase in the fractal dimensions and surface roughness of shale, which increases the complexity of the pore structure. This can be related to the dissolution of clay and carbonate minerals, which results in increasing the micropores' structure. This disagreement in results shows that the mineral genesis, mineral composition and sedimentary environment of shale could influence the fractal dimensions and surface roughness of shale. In the long-term, the alteration in pore structure can affect the hydrocarbon transport during ESGR process, the sealing mechanism, and lead to lower CO2 adsorption capacity [55]. The dynamic sealing efficiency of shales after SCCO2 exposure was examined by Rezaee et al. [51], over time, a possible CO2 leakage could occur due to the increase in pore volume, and the reduction in the capillary threshold pressure. This alteration in pore structure and capillary pressure is caused by the dissolution and precipitation of kaolinite, silica, and gypsum, which results in decreased CO2 adsorption capacity, which is not favorable for CO2 sequestration [18]. Alteration of pore structure during SCCO2 injection could have a direct impact on other shale properties, including chemical and mechanical properties, as explained later in this paper. Therefore, it is crucial to examine the changes in shale pore structure associated with SCCO2 injection. The related literature has addressed the significant impact of pore structure alteration on CO2 storage capacity and hydrocarbon flow pattern during ESGR, however, a different type of shales will indicate various alterations on pore structure, thus each shale formation should be evaluated separately before CCS projects [11]. Table 1 summarizes several studies that highlighted the effect of CO2 injection on pore structure system. This study confirms that CO2shale interactions have a strong influence on the micropores of shale, indicating an increase in SSA and pore volume. It was also found that fractal dimensions of shale have increased due to the dissolution of the clay and carbonate minerals.

Mineral Composition
Researchers initially explained the influence of mineralogical composition on the reactivity of shales during CO2 injection. SCCO2 has high diffusivity and acts as an organic solvent to extract some organic and inorganic minerals, which may lead to an increase in the porosity of shale [55,71]. Previous studies indicated that the alteration in shale mineralogy after SCCO2 treatment is mainly caused by the geochemical reaction with the formation brine in the presence of carbonate minerals such as dolomite and calcite [18,30,39,43,51,72]. Alemu et al. [72] found that carbonate-rich shales have high reactivity to CO2 compared to clay-rich shales, due to the dissolution of carbonate minerals and the formation of smectite, which results in a significant increase in calcite concentration. The diffusion of carbonic acid leads to a significant reduction in the pH [53,56,73], leading to changes in the mineral contents of shale through a series of chemical reactions and reversible reactions [43,74], mainly including: Few scholars [30,55] have analyzed the surface microstructure of shale and indicated various changes in clay minerals such as kaolinite montmorillonite, illite, and anorthite after SCCO2 treatment, caused by the extraction and dissolution of the in situ substance by SCCO2. Non-clay minerals such as quartz, pyrite, and feldspar are most likely to exhibit a relative increase in content after SCCO2 treatment because silicate minerals are rich in Ca +2 , Mg +2 and Al +3 ,and have high dissolving potential in acidified water during CO2 injection, which leads to precipitation as carbonate solids [30,43]. This is favorable for mineral trapping mechanisms during long-term CO2 storage. The phenomenon of mineral alteration in shales after SCCO2 treatment was reported by the latest studies [18,39,[49][50][51], indicating a high possibility for increasing quartz percentage and reduction in carbonate and clay minerals contents caused by CO2-induced swelling, which affects CO2 adsorption behavior.
During CO2 injection, carbonic acid can also mobilize major and trace elements, affecting the physical structure of shales [75][76][77]. Recently, a study by Luo et al. [50] concluded that the hydrolysis and carbonation of silicate minerals is the main cause of element mobilization; minerals such as calcite, calcium, magnesium, sodium, potassium, and aluminum could face varying degrees of mobilization, which is controlled by the mineral composition and occurrence. However, it is important to consider the minerals' alteration for shale formation before CCS projects, as some elements with a high mobility such as zinc, cobalt, barium, and strontium may cause severe groundwater contamination [50]. The mineralogical alteration after SCCO2 injection can cause major changes in the petro-physical properties of shales; as reported in the literature, the possible increase in micropore volumes might be beneficial for CCS and ESGR applications. Moreover, the long-term geochemical reactions provide a significant opportunity for mineralization trapping in shale formations, which plays an important role in increasing CO2 storage capacity. However, further studies are required to capture the long-term mineral trapping mechanisms, especially mineral carbonation associated with CO2 injection, and address the involved factors such as mineral type, pressure, and temperature [74].

Chemical Properties
Understanding the chemical reactions between CO2, shales and formation water are very crucial for the practical application of CO2 geological sequestration. The reactivity of shales to CO2 depends mainly on the rock mineralogy, which eventually affects the chemical properties of the shale. Additionally, the fluid chemistry of CO2 controls the dissolution and precipitation processes, and significantly impact the pore structure [72]. The alteration in shale chemical properties during CO2 injection can be understood by evaluating the surface chemistry of the shale and its functional groups' distribution through FTIR and X-ray photoelectron spectroscopy analysis [78]. Several studies [18,30,39,59,79] have reported that the presence of oxygen-containing groups on the shale surface such as −COOH, −H and −OH bonds, would have a severe impact for both CO2 and CH4 adsorptions on carbonate minerals at high pressures.
CO2 injection causes a reduction in the intensity of C-O bonds in shales as well as aliphatic hydrocarbon (C-H) groups, which is related to the extraction of organic matter [39,71]. Yin et al. [30] suggested that some inorganic vibrational bands of quartz and illite (Si-O, Al-O-H and Si-O-Al bonds) can exhibit high absorption in shales similar to calcite and dolomite. Additionally, a noticeable reduction in aliphatic hydrocarbon groups was observed after CO2 treatment, which confirms the associated changes in mineral contents. Recently, Pan et al. [39] proved that CO2 injection can decrease the adsorption of the aliphatic hydrocarbon group, caused by the ability of CO2 to dissolve the non-polar aliphatic and polar aromatic hydrocarbons. These alterations in hydroxyl functional groups (groups with oxygen) could increase CO2 adsorption and affect the overall storage capacity.
Similarly, Hui et al. [18] confirmed that the chemical reactions between SCCO2 and shales could decrease the oxygen-containing functional groups (C-O, O-C-O, C=O, COO−), and relatively increase the hydrogen groups (C-C/C-H) due to the ability of SCCO2 to extract organics from the shale surface. This conclusion was based on the results obtained from three different shale formations after being treated with SCCO2 as shown in Table 2. These relative alterations in oxygen and hydrogen functional groups can be explained by two points, (1) the evaporation and extraction behavior of SCCO2 [18], and (2) the ability of SCCO2 to extract organic matter and dissolve the polar kerogen moieties from shale surface [71,80]. As mentioned before, this alteration in surface chemistry and functional species after CO2 injection could increase the CO2 adsorption capacity in shales, thus more investigations are required to clarify the impact of chemical properties' alteration on the sequestration potential of CO2 in shales.

Surface Wettability
Shales' surface wettability is one of the major petro-physical properties that is affected by CO2 injection. Wettability is defined as the affinity of the rock surface to a particular fluid; it is mainly affected by the rock surface mineralogy and temperature [81,82]. Understanding the wettability of shales is important as it controls the capillary forces, the relative permeability and hydrocarbon production [83]. Characterizing the wettability of shales can be challenging because of the nano-Darcy permeability, the porous medium heterogeneity and the presence of clay minerals with the variety of organic and inorganic matrix [84]. Hence, it is necessary to address the complex nature of shales' wettability and analyze the factors involved, i.e., pressure, temperature, pH, mineral composition and TOC [85]. Several studies were conducted to evaluate the wetting behavior of different types of shales at the presence of different fluids, by using different methods and techniques, such as equilibrium contact angle (sessile drop) [44,[86][87][88][89][90], NMR [91], spontaneous imbibition [92][93][94][95][96], and liquid-liquid extraction [87].
Based on the related literature, it was reported that (1) shales usually have a mixed wettability, which can be related to the presence of organic matter [86], (2) the shale surface is originally hydrophilic at atmosphere pressure, due to the existence of clay minerals and other non-clay minerals such as quartz, feldspar, and dolomite in high fragments [60,83], and (3) the contact angle between CO2 and shales increases with increasing pressure and temperature [44]. A recent review by Siddiqui et al. [85] claimed that under in situ conditions, the wettability system of hydrocarbon/brine/shale is preferentially water-wet, regardless of the mineral composition and type of hydrocarbon. The strong water-wetting behavior of shales in the presence of hydrocarbons works in favor of storage applications, as it increases the structural storage capacity. However, in the presence of CO2, several studies suggested that pure minerals in the caprock are not entirely water-wet and highly influenced by the CO2-rock interactions [42,45,46,97]. A high possibility of CO2 migration may occur when shales become CO2-wet; CO2 could escape back into the atmosphere or the overlying aquifers [12]. This alteration in wettability will dramatically minimize CO2 storage capacities, and reduce the sealing efficiency, which is the main sealing mechanism [12,47].
During the first decades of CO2 storage, a possibility of CO2 leakage may occur, when the capillary threshold pressure is reached; this may lower the structural trapping capacity and the overall efficiency of CO2 sequestration [46,47,98]. Although shales display ultra-low permeability, they might still have a possibility of CO2 breakthrough depending on the presented minerals [42,48]. It is important to highlight the primary trapping mechanisms for CO2 sequestration in shales, which are: (1) structural trapping, where shale formations act as a caprock [65,99]; (2) residual trapping, where capillary forces restrict the movement of CO2 in the shale pores [100,101]. However, during ESGR processes, mineral trapping may also occur in some shale formations, due to the interactions between CO2 and shale mineralogy; this mineral dissolution allows the CO2 to enter the reservoir interlayers, and increases the CO2 storage capacity [40,47].
In the last decade, several scholars have investigated the factors affecting the CO2 wettability behavior of caprocks [12,[45][46][47]52,98,[102][103][104]. Mineral composition and surface chemistry were found to have significant influences on the structural trapping capacity, besides other factors including organic matter, brine salinity, pressure and temperature. Iglauer et al. [46] found that CO2 wettability of caprock increases with increasing pressure, indicating a poor water-wet or intermediate-wet, which may affect the sealing efficiency. Chaudhary et al. [103] also reported a high contact angle between CO2 and shale at 22.8 MPa, indicating a mixed-wet behavior. On the contrary, low contact angles between CO2 and silty shales were reported by Kaveh et al. [45], which indicate a strong hydrophilic caprock system even at high pressures. When the contact angles between CO2 and shale are low, CO2 becomes immobilized by the high capillary forces in the pore structure of the shale. However, increasing the contact angles decreases the capillary force and allows CO2 to move upward by the buoyancy forces, and thus increases the chances of capillary breakthrough. Surface wettability is mainly affected by the shale's mineralogical composition, therefore different wetting behaviors could occur for different shale geometries [47]. Factors including brine salinity, temperature, organic content and thermal maturity, were found to have minor impacts on CO2/shale contact angles. Strong water-wet behavior was observed in several studies despite the high concentrations of organic content, brine salinities and thermal maturities [12,45].
The injection of CO2 into shales was also found to increase the contact angle between brine and shales, and reduce the shale surface hydrophilicity [52]. This can be related to the release of water content from clay minerals during CO2 treatment. Moreover, the increase in shale-water contact angles causes a relative reduction in the surface tension between shale and water. This can be attributed to the adsorption capacity of solid surfaces and the CO2 diffusion into the shale matrix after CO2 treatment. Figure 7 shows the relationship between the SCCO2 treatment time and pressure on the shale-water contact angle. Accurate characterization of CO2 wettability of shales is useful to estimate CO2 storage capacity, and essential to determine the technical feasibility for CO2 sequestration and hydrocarbon flow dynamics during the ESGR process [22]. Despite the progress achieved in the related literature on CO2 wetting in shales, the knowledge on wettability alteration is still evolving, and more insights are required to answer some decisive questions, i.e., what is the wetting behavior of different shales at various length scales? What mineral composition will prevent CO2 capillary leakage [12]? Table 3 highlights the related work on the changes in shales' contact angles values associated with CO2 injection at different operating parameters, and the subsequent impact on shales' wettability.

Mechanical Properties
The dissolution and precipitation of minerals after CO2 injection causes significant alterations in the mechanical properties of shales, which raises stability concerns for the long-term CO2 sequestration. Generally, the changes in pore structure and mineral content caused by CO2 injection reflect the possible deformation and weakening in the strength of caprocks, and thus reduces the overall CO2 adsorption capacity [74]. Several studies were conducted to investigate the effect of CO2 injection on rocks' mechanical properties, and evaluate the associated factors including treatment time, pressure, CO2 phase state, and bedding angles [27,41,74,105]. The injection of acid gases such as CO2 and H2S together with carbonated water was found to alter the physical properties of chalk, and affect the displacement behavior under in situ conditions, which eventually reduced the chalk strength and ductility [106,107]. Similarly, deformation in sandstone and siltstone formations was observed after the injection of SCCO2 [108], which led to increasing the porosity and precipitation of calcite [109,110]. This deformation behavior in caprock can be attributed to the changes in effective stress and crack propagation, which increases the potential of CO2 leakage.
The alteration of coal mechanical properties is affected by pressure and CO2 phase state [111][112][113][114][115]. Coal seams are significantly weakened by the injection of SCCO2 compared to gaseous and Subcritical CO2. Viete and Ranjith reported a reduction of 13% and 26% in both compressive strength and elastic modulus, respectively, after SCCO2 injection [112]. Such an effect is caused by the high SCCO2 adsorption in coals and the permeability increase under in situ conditions. Shale formations have a strong ability to adsorb CO2, and such behavior causes a reduction in effective stress, increasing the compression and raising the pore pressure within the formation [43,116]. This results in shale swelling, decreasing strength and brittleness, and eventually damaging the shale formations. Few recent scholars have investigated the effect of different factors on shale mechanical properties after CO2 injection [27,41,43,49,74,105]. The analysis of uniaxial compressive strength (UCS) and Young's modulus (E), are commonly used to evaluate the stress conditions of shales through conducting uniaxial and triaxial compression tests [117].
Increasing the CO2 treatment time of black shale was found to reduce both UCS and E values drastically by 66.05% and 56.32%, respectively, after 30 days [74]. This also results in decreasing the shale's brittleness index, and increasing its plasticity and toughness. When CO2 interacts with black shale, carbonate minerals precipitate as calcite and cause a reduction in the stress in the formation. Besides, the dissolution of clay minerals exhibits possible damage in shale macroscopic structure, which, as a result, increases the initial compaction and reduces shale strength [49]. CO2 phases and saturation pressure were also found to affect shale mechanical properties. Saturating organic-rich shales with SCCO2 for 10 days reduced UCS and E by 22.86% and 23.10%, respectively [41]. SCCO2 has a stronger ability to increase the crack initiation pressure compared to gaseous CO2, and thus reduce the crack damage stress. This results in shale swelling and creating more micro-cracks within the shale formation, and subsequently reduces the strength [27,41]. Moreover, increasing saturation pressure beyond 12 MPa showed a minor impact on reducing UCS and E due to the compression effect of fluid [49]. The mechanical properties of shales could also be influenced by the bedding orientation and the various forces generated, i.e., normal, shear, and compressive stresses along the bedding plane [105]. The direction of normal and shear stresses is dependent on the bedding angle, which results in differences in the degree of deformation in shale. At a bedding angle of 0°, only normal stress exists, which promotes the development of tensile failure [105]. In such a case, the cracks deviate through the damaged bedding direction which causes shale weakening. However, increasing the bedding angle beyond 45° sustains the shale strength and the resistance to crack propagation, which is related to the development of both tensile and shear failures.
The weakening of shales was further clarified by later studies [27,43,49,105], which reported various reductions in mechanical strength after SCCO2 injection, due to the dissolution effect and adsorption strain within the pores. It should be highlighted that the resulted physical changes in shales after CO2 injection, were found to have a significant impact on the shale strength [49]. The associated reduction in mesopores volume can partially destroy the shale skeleton density and weakens the shale. Based on the related literature, it is apparent that CO2-shale interaction may significantly reduce the mechanical parameters and weaken strength and brittleness of the shales. This degradation in shale mechanical properties is caused by several factors, which require further assessment in the future. Because of the heterogeneity of shale, it is essential to characterize each shale formation on a case-by-case basis to ensure the stability of shale formations during CCS. Table 4 summarizes recent studies that highlighted the effect of CO2 injection on mechanical properties. This study found a strong connection between the damage in pore structure and the weakening of shale strength. The possible damage in shale macroscopic structure increases the stress-strain in the initial compaction stage, which results in reducing shale strength.

Environmental Evaluation of CCS
The environmental consequences of CCS are often evaluated through Life Cycle Assessment (LCA) studies. LCA is proven to provide a complete analysis of all environmental effects of applying CCS to power plants. Such studies are detailed and time-consuming and vary in scope, methodology and outcomes, but they provide a suitable assessment of many environmental effects, including global warming potential (GWP), acidification potential (AP), eutrophication potential (EP), photochemical ozone creation potential (POCP) and cumulative energy demand (CED) [118]. Several studies have performed LCA on different CCS power plants [119][120][121][122][123], and the majority of these studies indicated a clear reduction in GWP, regardless of the technology used in transport, injection and storage of CO2 [118]. Generally, there are three main factors incorporated to influence the environmental effects from the CCS systems [124]: (1) efficiency energy penalty, (2) purity and capture efficiency of CO2, and (3) origin and composition of the fuel. However, CO2 capturing is out of the scope of the current study.
Energy penalties are associated with the capture technology, generally, pre-combustion processes produce lower energy penalties compared to pre-combustion and oxyfuel processes [119,120]. For instance, 29.6% of post-combustion thermal efficiency for hard coal was reported by Schreiber et al. [122], while 48% thermal efficiency was reported with pre-combustion process [120]. This variation can be attributed to the different types of fuel composition (natural gas, coal), assumptions in time scale, and the different energy sources (gas, hard coal, bituminous, lignite) [124]. For an electricity production process, CO2 is produced in different purities and captured by the different systems. Therefore by minimizing the consumption of electricity for the CO2 capture, the energy penalty is reduced, and thus reduces the environmental effects from the CCS system [124]. Hard coal is considered as a valuable and wide available fuel to capture CO2; one LCA study shows that the power generation from hard coal has significantly reduced the GWP, indicating about 13% contribution to the total GWP for post-combustion [123]. Similarly, the power generation from lignite power plant reduces the GWP, with lower share to the global total GWP compared to hard coal [121], due to the production of mono-ethanolamine during the capture process. However, natural gas implies higher efficiency in capturing process compared to hard coal and lignite, with a reported thermal efficiency of 49.6% and 44.7% in post-combustion and oxyfuel processes, respectively [122]. This results in lowering the GWP of power plants and increases the efficiency in CO2 capture.
Other environmental effects including AP, EP, POCP and CED showed inconsistent results for different energy power plants and capture technology [124]. For instance, post-combustion hard coal power generation systems indicated an increase in the EP compared with the power plants without CCS [124], while a 15% reduction in EP was reported at the lignite oxyfuel system [121]. This inconsistency between hard coal and lignite can be related to the capture technology used (postcombustion and oxyfuel, respectively), and long transport distance required in hard coal systems [124]. However, for natural gas systems, the EP usually increases, as it is mainly dominated by emissions from operation regardless of the capture technology [118]. An increase in EP by 266%-403% was reported for natural gas systems when using a steam integrated system for CO2 delivery [118]. Similarly, a range between a 15% and 50% increase in EP was reported in several studies [119,[121][122][123]. Therefore, no solid conclusion can be made regarding the assessment of EP and other environmental effects, due to the lack of sufficient data in the literature. In LCA studies, the selection of the time scale is crucial for reliable evaluation. Considering the present and future power plants for extended duration allows us to predict the main production processes and consider future modification [120,125]. Moreover, sensitivity analysis on the time scale could help to assess the storage process and identifying possible leakage [119,121]. However, it is not clear how possible storage leakage will impact the environmental effects, as it is difficult to perform climate conditions forecasts. Other factors are considered in LCAs, including compression, pipeline transport, injection and storage of CO2 indicate almost negligible impacts for all environmental effects [118].
In summary, LCA studies vary in the technologies used for the CO2 capture and storage, and the existing literature is too scarce to draw a solid conclusion. However, LCA still provides an idea of the impact of CCS on environmental performance, and a general understanding of the influence of capture efficiency, energy penalty and fuel composition. In future LCA studies, several aspects shall be considered, including techniques for CO2 capture, modeling leakage potential and incorporating both conventional and renewable energy resources [124].

Economic Viability of CCS in Shales
Shale formations hold a promising potential to utilize CCS projects in terms of their technical feasibility. By combining ESGR operations with long-term CO2 storage applications, CH4 production can be maximized due to the strong adsorption capacity of CO2. However, the economic viability of CCS in shales has yet to be proven, as the related literature on this topic is limited. Considering the associated costs of CO2 capture, transport, and storage, together with infrastructure cost and petrophysical characteristics of shales could make CCS project costly [126,127]. Therefore, in this paper, we briefly highlight the main challenges facing the economic viability of CCS in shales. The costs of CO2 capture were studied and analyzed earlier in the 21st century, and enormous reports were presented based on the plant type (source) and capture technique (Table 5). Mainly, there are two components of the cost of CO2 capture. First is the cost of removing CO2 from industrial emissions, as, currently, chemical adsorption of CO2 is believed to be the best available technology [128]. Secondly, the cost of equipment and chemicals, as they increase the overall capture capital cost. CO2 capture is more of a technical factor, and innovative technologies are needed to reduce the costs of CO2 capture and deliver stable long-term benefits [34].
The costs of CO2 injection and transportation are dominant factors affecting the economic viability of CCS in shales. These costs are controlled by the potential revenue form CH4 production and other factors including well spacing, CO2 separation, and bottom-hole pressure [129]. The CO2 injection cost is related directly to the CO2 injectivity approach used, i.e., the applied huff-n-puff processes in the Big Sinking Field showed an increase in injection cost by USD 0.35/metric tonnes [130]. Although CO2 injection is costly, integrated CCS systems in shales estimated a reduction of 30% on the average of the CO2 injection cost, with an average of USD 5-10/metric tonnes lower cost compared to saline aquifer [131]. The main reasons behind this are as follows: one is the gradual reduction in pore pressure during CO2 injection in shales and the production of CH4; two is the large storage potential for shales.
However, the added cost of CO2 transportation is large compared to injection and capture costs. A study [129] on Marcellus shales estimated a cost of USD 60-70/metric tonnes to transport CO2 from industrial source to the site, added to the USD 22.4/metric cost of for CO2 injection. These results indicate that using shorter pipeline transport distances with smaller diameters could be a suitable method to reduce the transport cost, which eventually implies high incremental capital costs. Moreover, utilizing high bottom-hole pressure wells with a short distance between producer and injector wells could reduce the total cost of CCS to USD 39/metric tonnes and provide more storage potential due to high injection pressure. The cost of infrastructure-which includes CO2 storage hubs and pipelines-is less costly compared to CO2 injection, transport and capture, nevertheless, they should be carefully assessed and included in economic viability studies.
Apart from the consideration of the fixed costs, the application of CCS is derived by other factors, mainly related to the concerns regarding carbon price and carbon tax revenues [132]. Addressing this topic is within the gaps between the economic theory and reality that prevents CCS to have an international breakthrough [133]. Another concern about integrated CCS systems is how they can be utilized for large-scale fossil fuel power plants instead of refining industries only. However, reviewing and discussing these factors is out of the scope of this paper, yet it is reliable for generally highlighting these economic drivers and their impact on CCS deployment (Table 6). In summary, more studies are needed to provide clear assessments of economic viability of CCS in shales. Although the application of CCS in shales is encouraging, the lack of available knowledge regarding storage capacity, reservoir data for best sequestration settings and the effect of long-term CO2/shale interaction can affect its economic viability. Table 5. Early studies on estimated CO2 capture cost from different plants [129] .

Environmental Policy Cost of CCS Fossil Fuel Energy Costs Clean Energy Sources
This is the main driver for CCS technology, as it controls the economic market and energy generation. The demand for CCS will depend on the employed strategy that targets carbon emissions through "carbon tax" revenues.
When carbon emissions are optimally taxed, this allows for the nonenergy cost of CCS to drop, and thus lowers the emissions tax [132]. In this case, a lower carbon tax provides the opportunity for companies to apply CCS projects.
For the CCS project to be cost-effective, the unit cost to capture, transport and storage has to be lower than the emitting CO2 and pay the carbon price. A more advanced CCS technology will lead to an increase in energy generation from fossil fuels and reduce the unit cost of CCS. Moreover, the availability of geological sequestration sites will also result in a higher level of CCS.
Fossil fuel resources are limited in nature, and the increase of generating fossil fuel energy costs will affect the level of fossil fuel energy, carbon emissions, and overall CCS activity. Therefore, due to the exhaustibility and scarcity rent cost, renewable resources should be considered as a possible alternative for fossil fuels, which may help to achieve a higher level of CCS [139].
There is an approach to utilize carbon-free resources i.e., solar energy, wind and nuclear electric power to replace or at least contribute to energy generated from fossil fuels. It will be ideal to employ clean energy sources only, as generating energy cost is low, which puts CCS in high demand, but the full replacement of fossil fuels is not expected soon. As of today, 80% of the global energy needs are supplied by fossil fuels, however, by combining both sources with optimal timing, the cost of energy generation can be reduced, and thus increases the level of CCS [140].

Conclusions
CO2/shale interaction is a significant factor for the efficiency and the success of CCS technology in depleted shale formations, for its noticeable impact on altering shale physical, chemical, and mechanical properties. This paper presented the current knowledge of CO2/shale interactions and provided a comprehensive review of the impact of CO2 exposure on shale properties and the subsequent implications on CO2 storage. The accomplishments achieved through laboratory experiments confirm that the physical structure and surface chemistry of shales are highly influenced by CO2 injection, due to the formation of carbonic acid within shales, which, in the long-term, might reduce CO2 adsorption capacity and storage potential. Shale-sealing efficiency is also affected by the injection of CO2, as the presented minerals on the shale surface could decrease the shale surface hydrophilicity. Furthermore, CO2 injection causes a massive degradation in shale mechanical properties, and a noticeable reduction in shale brittleness and increases in its plasticity and toughness were observed, which results in shale weakening. The knowledge of CO2/shale interaction and its implications on CCS requires further study; systematic studies are in need to evaluate the feasibility of CCS in shales technically and commercially. With this evolving technology comes many technical and economical unknowns, which shall be addressed in future work.
Author Contributions: In this review paper, A.F. wrote the draft paper with support from Z.B. on the paper structure and organization. H.B.M. and R.G. contributed with their valuable suggestions on the overall quality of the manuscript and also on other parts including the introduction, chemical properties and CCS viability sections. M.H. submitted the manuscript as a corresponding author and assisted with other authors in revising the manuscript according to reviewers' comments. All authors have read and agreed to the published version of the manuscript.
Funding: This research received no external funding.