Feasibility Analyses and Prospects of CO₂ Geological Storage by Using Abandoned Shale Gas Wells in the Sichuan Basin, China

Abstract

The geological storage of CO₂ is a critical technique for reducing emissions, which significantly contributes to the mitigation of the greenhouse effect. Currently, CO₂ is often geologically stored in coal seams, hydrocarbon reservoirs, and saline aquifers in order to store CO₂ and improve the oil and gas recovery simultaneously. Shale formations, as candidates for CO₂ storage, are drawing more attention because of their rich volumes. CO₂ storage through shale formations in the Sichuan Basin, China, has tremendous potential because of the readily available CO₂ injection equipment, such as abandoned shale gas wells. Therefore, we review the potential of using these wells to store CO₂ in this paper. Firstly, we review the status of the geological storage of CO₂ and discuss the features and filed applications for the most studied storage techniques. Secondly, we investigate the formation properties, shale gas field development process, and characteristics of the abandoned wells in the Sichuan Basin. Additionally, after carefully studying the mechanism and theoretical storage capacity, we evaluate the potential of using these abandoned wells to store CO₂. Lastly, recommendations are proposed based on the current technologies and government policies. We hope this paper may provide some insights into the development of geological CO₂ storage using unconventional reservoirs.

1. Introduction

Recently, global warming has attracted more concern because of the increasing consumption of fossil fuels. Therefore, many countries are striving to alleviate global warming by proposing measures to control greenhouse gas emissions. To achieve this goal, a method of carbon neutrality has been proposed [1], the aim of which is to balance anthropogenic emissions via sources and removals via sinks of greenhouse gases in the second half of the 21st century. China has been the world’s largest emitter of greenhouse gases for 14 consecutive years since 2006, according to the statistics from the Global Carbon Atlas [2]. China attaches great importance to this. In September 2020, at the 75th United Nations General Assembly, China solemnly pledged to reach peak carbon dioxide emissions by 2030 and to strive to achieve carbon neutrality by 2060 [3].

A number of emission reduction measures have already been implemented, such as developing wind, solar, hydro, and nuclear energy sources. In particular, the utilization and geological storage of CO₂ are also critical matters for emission reductions. Coal seams, saline aquifers, and hydrocarbon reservoirs are the main places for CO₂ storage. The Sleipner Project, the world’s first commercial-scale CO₂ storage project in Norway, has successfully injected tens of millions of tons of CO₂ into the saline formation of Utsira sandstone [4]. The CO₂ injection in the Weyburn Project in Canada achieves CO₂ storage while enhancing oil recovery [5]. In China, demonstration projects for CO₂-enhanced oil and coal belt methane recovery have been implemented in the Jilin Oilfield, Shengli Oilfield, and Qinshui Coalfield [6]. In addition, pilot tests of CO₂ sequestration in coal seams have been conducted in Australia and Canada [7]. China’s first demonstration project for geological storage of CO₂ in deeply saline aquifers is located in the Ordos Basin of Inner Mongolia. During 2011–2015, CO₂ was injected into the saline aquifers at a rate of 100,000 tons/year [8]. The project has largely contributed to the development of CO₂ storage technology in China.

Inspired by the successful application of CO₂ storage in hydrocarbon reservoirs and saline aquifers, injecting CO₂ into abandoned shale gas wells for EOR and CO₂ storage has become a potential candidate approach for CO₂ storage. The low porosity and low permeability of shale reservoirs require an extensive well network to ensure the efficient extraction of shale gas, resulting in a large number of wells. These wells are abandoned after a certain period of time because of declining production rates or due to engineering factors such as casing damage, aging equipment, and downhole junk. The cost of shutting down and disposing of these abandoned wells is about $50,000, and it would be a huge waste if these abandoned wells are not used wisely [9]. It is critical to employ these abandoned shale gas wells to store CO₂ and thereby to further mitigate the greenhouse gas effect, as well as to enhance the recovery factor of shale resources.

China has actively explored the development of relevant theories and technologies and strived to shorten the gap with the international advanced level in terms of unconventional oil and gas recovery, geological storage, and CO₂ storage monitoring and early warning systems.

2. Advances in CO₂ Geological Storage

Carbon capture and storage (CCS) is one of the most effective ways to mitigate global warming and reduce carbon dioxide emissions [10,11,12]. The most studied techniques involve the storage of CO₂ in coal seams, hydrocarbon reservoirs, and saline aquifers [13,14,15]. CO₂ storage in shale has drawn growing attention recently. So far, CO₂ has been successfully stored in hydrocarbon reservoirs, saline aquifers, and non-profitable reservoirs, which significantly contributes to alleviating the effects of greenhouse gas. Different CO₂ storage mechanisms are involved in these geological storage processes, which are thoroughly reviewed below.

2.1. CO₂ Storage in Coal Seams

The deeply stored coalbed methane (CBM) formation is the targeted location for CO₂ storage. The impermeable overburden rock helps to store CO₂ in the pores and fractures of coal seams over the long term. Meanwhile, the injected CO₂ can displace the CBM, whose economic gains can lower the cost of the CO₂ storage [16].

Figure 1 shows a schematic diagram of the stored CO₂ in a coal seam. The compressor at the surface compresses the CO₂ into a supercritical state prior to injection. Then, supercritical CO₂ is injected into the specified coal seam through the injection wells. The injected CO₂ exists mainly in the adsorbed and free states. After about two months of soaking [17], the adsorbed and free gases reach equilibrium in the reservoir, and the injected CO₂ is fully adsorbed into the coal seam and displaces the CH₄ adsorbed on the inner surface of the coal pores [18]. Because the coal seams have approximately two times the adsorption capacity for CO₂ than for CH₄ [19,20,21], this implies that the coal seams are capable of adsorbing more CO₂. Meanwhile, the injection of CO₂ increases the formation energy at the wellhead of the injection well and pushes the gas in the coal seam to flow into the production well. The coalbed methane is then pumped out by deep well pumps and water–gas separation is performed to obtain high-purity coalbed methane.

The first tests of geological storage of CO₂ in coal seams and improved coal bed methane recovery were applied in the San Juan Basin, USA, in late 1993. Then, a pilot test of injecting pure CO₂ was conducted in the Allison coal seam of the San Juan basin; the stimulating effect was remarkable and the recovery factor of the coalbed methane was enhanced by about 18% [22]. Subsequently, pilot tests have been conducted in Alberta in Canada, Ishikari in Japan, and Silesian in Poland, as well as in other coal seams [23,24,25,26]. In 2004, mini-pilot tests involving CO₂ huff-puff injection were carried out in the Qin Shui Basin, whose preliminary results confirmed the stimulating effect of CO₂ injection and the feasibility of CO₂ storage [17]. Parson and Keith [27] estimated that the global CO₂ storage capacity of coal seams is about (36.6 − 110) × 10¹⁰ t. In fact, these projects have not achieved the desired effect of being able to store large amounts of CO₂. The problem of coal swelling due to CO₂ injection is still difficult to solve, which greatly limits the large-scale application of this method.

Currently, the storage of CO₂ in coal seams is still in the research and development phase, and commercialization and large-scale promotion projects have not yet been implemented. There are still many technical barriers to overcome; for example, the injected CO₂ will make the coal swell, reduce the permeability of the coal seams, and contaminate the gas flow path [28].

2.2. CO₂ Storage in Hydrocarbon Reservoirs

Mature hydrocarbon reservoirs, which are produced over a long time and exhibit low economic value, are used for CO₂ storage. When unexploited, most of the hydrocarbon reserves indicate the integrity of the reservoir when no oil or gas leaks occur for millions of years, which provides a safe location for future CO₂ storage. After years of research, this technology is one of the most mature storage technologies.

Existing facilities can be used to store CO₂ directly, which significantly increases the efficiency of the CO₂ storage. Once the storage depth is deeper than 800 m, the injected CO₂ will be in the supercritical state corresponding to the reservoir temperature, resulting in the large-scale and stable storage of CO₂ [29]. The majority of the CO₂ is stored in the pore space, while part of the CO₂ is dissolved in the residual fluid and a small part of the CO₂ mineralizes in the underground rock. Meanwhile, both the viscosity and interfacial tension of the crude oil can be lower after the dissolution of CO₂ [30]. Furthermore, the injection of CO₂ helps maintain the reservoir pressure and displaces hydrocarbon resources, which enhances the oil recovery and extends the producing period of the well [31].

The concept of CO₂ flooding was first proposed during the 1920s and matured in the 1980s. In the Weyburn Field, Canada, large-scale CO₂ flooding projects have been carried out since 2000; more than 15 billion tons of CO₂ have been injected so far [32]. The statistics show that the mass of CO₂ that can be stored using globally depleted hydrocarbon reservoirs is about 923 Gt, which is equivalent to 125 years of global CO₂ emissions from fossil-fuel-burning power plants [33]. Injecting CO₂ into reservoirs has obtained significant results in both EOR and CO₂ storage.

2.3. CO₂ Storage in Saline Aquifers

Saline aquifers are mostly sandstone, shale, and argillaceous rocks, which are widely distributed in inland and offshore sedimentary basins. Compared with coal seams and hydrocarbon reservoirs, saline aquifers possess better geological conditions for CO₂ storage in terms of their storage capacity, duration, technical difficulty, and environmental impact [34]. The CO₂ injected into the saline aquifers diffuses and flows into the porous media, which is stored underground after a series of physical and chemical processes.

The main mechanisms for storing CO₂ in saline aquifers are summarized in Figure 2, including structural trapping, hydrodynamic trapping, residual trapping, dissolution trapping, and mineralization trapping [7,35]. Structural trapping refers to the immobilization of CO₂ under the confinement of a cap rock or structural trap so that the CO₂ can be stored. Due to the effect of gas–liquid interfacial tension, part of the CO₂ is trapped in the pores, resulting in CO₂ storage as the form of residual gas. The hydrodynamic trapping mechanism involves the blockage of CO₂ by water, which occurs when the flow pressure of the groundwater is opposite to the buoyancy direction of the CO₂ migration and approximately equal to that of the buoyancy force of the CO₂. Meanwhile, part of the CO₂ can be dissolved in formation water and stored. The key influential factors affecting the solubility of CO₂ in water include the temperature, pressure, and salinity of the formation water. As the most stabilized trapping approach, mineralization trapping plays an important role in CO₂ storage. The principle of this process is the formation of stable carbonate minerals by the acidized water (H₂CO₃ (aq), HCO₃⁻ and CO₃²⁻) after the dissolution of CO₂ and mineral ions (Ca²⁺, Mg²⁺ and Fe²⁺) [36].

The CO₂ can be transformed into a supercritical fluid under supercritical conditions (T > 31.1 °C, p > 7.38 MPa) [37]. The supercritical CO₂ exhibits high density and low viscosity, resulting in great solubility and diffusivity in formation water [38]. Injecting CO₂ under supercritical conditions can significantly enhance the capacity of the CO₂ storage.

Demonstration projects of CO₂ storage have been carried out successively in many countries. The Sleipner Project in the North Sea of Norway, started in 1996, was the first demonstration project, with a designed storage capacity of 220 million tons of CO₂. In 2004, the United States also started the construction of the Frio Demonstration Project [39]. In China, one of the representative projects of CO₂ storage in deep saline aquifers is the CCS Demonstration Project in Shenhua, whose first phase was completed in 2016. A total of 300,000 tons of CO₂ was injected into a deep saline aquifer in the Ordos Basin, making it the largest CO₂ storage project in the saline aquifer in Asia [40].

From the existing worldwide experience of CO₂ injection, the geological storage of CO₂ in saline aquifers is feasible from a technical point of view. However, only in certain areas of the world are these saline aquifers available. Additionally, there are many problems to be solved, such as the distribution of storage projects in different subsurface environments around the world, the lack of site characterization information, the need for different monitoring techniques, as well as legal and regulatory issues.

2.4. CO₂-ESGR

Using CO₂ to enhance the shale gas recovery (CO₂-ESGR) is a new method of CO₂ geological storage and a shale gas development technique. This method employs CO₂ fracturing fluids to replace the conventional fracturing fluids, which can be applied in stimulation, primary recovery, secondary recovery, and CO₂ geological storage processes. The CO₂ can be massively recycled via this technique, which saves the company money and increases the operational efficiencies. However, this technique is still in the feasibility analysis and pilot testing phase.

Various scholars have demonstrated the great potential of CO₂ storage in shale [41,42]. Compared with coal seams, hydrocarbon reservoirs, and saline aquifers, shale is the safest geological site for CO₂ storage due to its extremely low permeability. In addition, the shale reservoirs are much more abundant than coal seams or hydrocarbon reservoirs, which further indicates the possibility for massive CO₂ storage.

3. Exploitation Status of Shale Gas in the Sichuan Basin

In this section, we review the exploitation status of shale gas in the Sichuan Basin, China. It is estimated that the recoverable reserves of shale gas in China exceed 36 × 10¹² m³. The total amount of shale gas resources in the Sichuan Basin is about 41.5 × 10¹² m³ [43], which ranks first for shale gas reserves in China. The abundant shale formations and considerable number of wells provide a guarantee for CO₂ injection and storage through abandoned shale gas wells. The production status of the shale gas indicates the formation characteristics and provides information for assessing the feasibility of the CO₂ storage, which needs to be studied thoroughly.

3.1. Shale Gas and Shale Reservoir Characteristics

Methane is the primary component of shale gas. The main occurrence forms of shale gas are adsorbed and free, and the proportion range of adsorbed gas is about 20–85% [44]. The origins are mainly biological, thermogenic, and a combination of the two [45,46,47].

Shale gas reservoirs are “self-generation and self-storage” gas reservoirs [48,49], with independent oil and gas systems. The reservoirs are characterized by low porosity and ultra-low permeability. The nanoscale pore throat systems are well developed, the porosity is generally less than 10% [50], and the permeability is generally less than 10⁻⁴ mD [51]. Shale reservoirs have the characteristics of a large area and wide range. Generally, reservoirs are stored at depths of 200–3500 m and have thicknesses ranging 90–180 m [52].

The shale mainly consists of organic content, quartz, and clay minerals. According to the exploration and development experiences, the threshold values for the average organic carbon content of prospective, favorable, and core areas are 0.5%, 1.5%, and 2.0%, respectively [53]. The total organic content (TOC) values of the shale gas reservoirs in the Wufeng Formation and Longmaxi Formation range from 0.2% to 12% [54], which are at a low level but are greater than the lower limit of shale gas hydrocarbon generation (TOC > 0.5%).

3.2. Exploration and Development Process of Shale Gas

Before 2009, there was a lack of geological understanding and evaluation of shale gas in the Sichuan Basin. After more than a decade of unremitting exploration, the large-scale commercial development of shale gas has occurred successively through formation selection, pilot testing, and demonstration area construction [55].

Since the discovery of the first giant gas field in Puguang, Sichuan Basin, large shale gas fields have been successively explored in the Changning, Weiyuan, and Fuling shale gas fields. The Changning, Weiyuan, and Fuling shale gas blocks are located in the southern, southwestern, and near the eastern boundary of the basin, respectively (Figure 3) [56]. The shale blocks have equivalent vitrinite reflectance (EqVRo, %) values ranging from 2.4% to 3.8%, indicating that they are largely thermally over-mature and in a dry gas generation stage [57,58,59].

Table 1. Production overview of the Changning, Weiyuan, and Fuling shale demonstration blocks [60,61,62,63,64,65,66,67].

Blocks	Daily Gas Production per Well/×104 m3	Stored Depth/m	Favorable Area/km2	EUR per Well/×108 m3	Well Numbers (2020)	Cumulative Production/×108 m3 (2020)	Accumulative Prove Geological Reserves/×108 m3
Changning block	23	<4000	4450	1.13	>1000	115	>6000
Weiyuan block	17		8500	0.78			6200
Fuling block	18.3		6000	0.85	>400	78	9000

shows the published production data for these areas. A total of about 13,703 million tons of shale gas has been produced in these areas; the production rate increases year-by-year.

Based on the production decline trend in the currently available production data, there is no stable production period for shale gas wells. Even if the production is allocated to less than 1/3 of the open flow rate, the production can only be stable for about 3 years, and the annual decline rate can reach 50% or more. The overall production and development cycle of shale gas wells is estimated to be less than 40 years [68]. To achieve a stabilized or enhanced production rate, we need infill wells that increase the total well number. As the production continues, a large number of wells will be abandoned due to production decline or flawed operations. Taking the Changning, Weiyuan, and Fuling blocks as examples, it is estimated that more than 500 wells will be abandoned shale gas wells by 2030, providing a large number of good injecting channels for storing CO₂.

3.3. Characteristics of Abandoned Shale Gas Wells

Due to the ultra-low porosity and permeability of shale reservoirs, fracturing is required to achieve an industrial production rate [69,70]. The stimulating effect of hydraulic fracturing directly affects the fluid flow capacity and CO₂ storage potential of the reservoir. Therefore, a better understanding of the fracturing performance is critical to the evaluation of the storage of CO₂ in fractured wells. At present, micro-seismic monitoring, post-fracturing evaluation, flow-back data, and production information are used to design and adjust the CO₂ storage scheme [71].

The statistics of the hydraulic fracturing operations show that the average lateral length of the stimulated section is about 1500 m and the average fracturing stage is about 21. Various scholars have attempted to understand the fracturing performance and fracture geometry from different perspectives. Some representative results are listed below.

Liu et al. [72] used the microseismic monitoring technique to interpret and analyze the fracture complexity of three fractured wells in Fuling. The results showed that the fracture heights are between 20 to 80 m, and the stimulated reservoir volume (SRV) is greater than 3.56 × 10⁷ m³. Applying the same methodology, the analyses of TYB well in Jiaoshiba showed that the main fracture length range is between 310 m and 1118 m and the SRV is about 3.273 × 10⁷ m³ [73].

Shu et al. [74] proposed a new post-fracturing analysis method using the material balance theory to evaluate the shale gas well productivity. They found that the fracture conductivity of the three tested wells in Jiaoshiba is greater than 673 mD·m. By combining pressure buildup tests and microseismic monitoring, Liu [75] found that the fracture half-length of the Weiyuan Shale Gas I well is about 10 m through curve fitting. The fracture complexity increases and the permeability enhances by several orders of magnitude.

Based on the flowback data, Wang et al. [76] used the aqueous phase seepage mathematical model for gas well production at a constant production rate in the calculation; the estimated fracture width of Longmaxi Well I is about 0.02 m and the fracture pore volume is about 12,572 m³.

The complex fracture network and large SRV provide excellent seepage channels and storage spaces for the injected CO₂. The fracturing performances, including the fracture length, number, and conductivity, determine the potential for CO₂ storage in fractured shale gas wells. Chen et al. [77] quantitively evaluated the CO₂ storage potential through shale gas wells.

Table 2. Impact of engineering factors on storage [77].

Influential Factors	Sensitivity Analysis	Recommendations
Fracture conductivity	The storage potential increases with the increase in fracture conductivity; the enhancement becomes stable once the fracture conductivity exceeds 300 mD·m.	Fracture conductivity > 10 mD·m.
Fracture number	The storage volume boosts significantly with the increase in fracture number.	Fracture numbers > 2; the more hydraulic fractures, the better storage performance.
Fracture length	The storage volume increases with the lengthened fracture.	Preference is given to the abandoned wells with multi-stage fracturing, which are preferred because of their large storage capacity.
Matrix permeability	Higher permeability yields a larger storage volume.	Massive fracturing is beneficial to store CO2.
Lateral section length	The longer the horizontal well, the larger SRV and the higher the storage capacity.	Longer lateral sections are preferred to store CO2.

summarizes the recommended indices and major influential factors of this process. Based on the typical fracture scales of hydraulic fracturing operations evaluated via the abovementioned different methods, the shale gas well in Sichuan Basin meets the storage requirement.

4. Feasibility Assessment of CO₂ Storage in Abandoned Shale Reservoirs

4.1. Analysis of Storage Mechanism

The mechanisms of CO₂ storage in shale reservoirs are similar to the aforementioned geological storage mechanisms, including structure, hydraulic, residual, dissolved, mineralization, and adsorption trapping mechanisms. Adsorption plays a critical role in CO₂ storage [78,79,80], as illustrated in Figure 4. The CO₂ storage potential and shale gas recovery significantly increase because of the competitive adsorption between CO₂ and CH₄ [81].

Various researchers have thoroughly examined the competitive adsorption mechanisms of CO₂ and CH₄ to increase the CO₂ storage potential in shale. The adsorption characteristics of the organic and inorganic contents are reviewed below.

4.1.1. Competitive Adsorption in Organic Matters of Shale

Effects of temperature and pressure. Sui et al. [82] and Sui et al. [83] used molecular simulation to explore the competitive adsorption behaviors of CH₄ and CO₂ under different molar ratios and pressures, and analyzed the effect of each atom in kerogen in affecting gas adsorption via a radial distribution function. Coussy [84] and Brochard et al. [85,86] pointed out that the adsorption in the low-pressure stage is the main cause of volumetric strain. Sun et al. [87] simulated the adsorption on a narrow slit kerogen fracture pore in the simulation. The results showed that the coefficient selective adsorption of CO₂/CH₄ decreased with increasing temperature but first increased and then decreased with rising pressure. Overall, kerogen is strongly affinitive to CO₂, which is consistent with the experimental results [88,89,90].

Effects of moisture. Billemont et al. [91] and Huang et al. [92] experimentally and numerically investigated the adsorption behavior of CH₄ and CO₂ in water-saturated carbon nanopores and found that the average equivalent heat of adsorption for CH₄ ranged from 20.42 kJ/mol to 22.10 kJ/mol with respect to the humidity range of 0 to 2.8%. The simulated results were close to the experimental data obtained for activated carbon (29.12 kJ/mol) [93]. At low humidity, the replacement effect of CO₂ enhances with increasing humidity content. At high humidity, water molecules tend to form a cage with cluster structures that worsen the effect of the CO₂ replacement of CH₄ and greatly reduce the amount of adsorbed gas [94]. When the pores are large, gas molecules mainly concentrate in the center of the pore channels [95].

4.1.2. Competitive Adsorption in Inorganic Matters of Shale

Competitive adsorption in quartz. Jing [96] and Xiong et al. [97] constructed pore models for quartz and investigated the effect of moisture on competing CH₄/CO₂ adsorption. The results showed that the moisture content significantly reduced the total adsorption of the gas mixture, while the adsorption preference of CO₂ over CH₄ in quartz increased with the increasing moisture content.

Competitive adsorption in montmorillonite. Jin and Firoozabadi [98] conducted a simulation to understand the effect of the moisture content on the competitive adsorption on montmorillonite; the obtained density distribution of CO₂/CH₄ showed that water inhibited the gas adsorption. In 1 nm pores, water and CO₂/CH₄ adsorb in the same layer, while in pores whose diameter is large than 2 nm, water molecules adsorb on the first layer and the CO₂/CH₄ forms a second layer. At relatively low pressure and a moderate water level, montmorillonite exhibits a more pronounced preference for CO₂ adsorption [99]. By examining the adsorption equilibrium configuration and calculating the adsorption heat, Yang et al. [100] examined the competitive adsorption mechanism of the mixed gas and found that the charged sodium montmorillonite resulted in stronger adsorption of CO₂.

Competitive adsorption in illite. Lu et al. [101] conducted isothermal sorption experiments and found that illite was favorable to increasing the amount of adsorbed gas in shale. Zhang et al. [102] used the GCMC method to examine the effects of the temperature, pressure, and CO₂ injection ratio affecting the CO₂/CH₄ adsorption and desorption in 1 M of illite. When the CO₂/CH₄ injection ratio was larger than 2 and the formation depth exceeded 2 km, the CO₂ adsorption gradually increased with increasing depth and then stabilized at a depth of 5 km. Additionally, their experimental results echoed well with the simulation results shown by Ou [103] and Wang [104].

Competitive adsorption in kaolinite. Heller and Zoback [105] studied competitive adsorption in different types of clay minerals and showed that the adsorption on illite was greater than that of kaolinite. Song et al. [106] constructed a kaolinite supercell model using the GCMC method; most of the CH₄ and CO₂ molecules were adsorbed in the micropores. Additionally, the adsorbed CH₄ and CO₂ amounts at different temperatures conformed with those calculated by the Langmuir model.

4.2. Evaluation of Storage Potential

Various models have been proposed to estimate the CO₂ storage potential in shale reservoirs [107,108]. Tao et al. [109] developed an algorithm to estimate the CO₂ storage capacity of the Marcellus Basin based on historical production data, the CH₄/CO₂ sorption equilibrium, and kinetic models. They also predicted that 1.04~1.84 billion tons of CO₂ would be stored in the region by 2030. Godec et al. [110] predicted that the same region had a CO₂ storage capacity of about 0.92 Mt/km². Sun et al. [111] proposed a dual pore transfer model to investigate the CO₂ storage capacity. The results showed that the storage capacity of CO₂ enhances with increasing injecting pressure. Zhou et al. [112] estimated the storage of the target shale reservoir using a self-developed CO₂ theoretical storage potential calculation formula, and the results showed that the shale has good prospects for CO₂ storage, which is larger than the shale gas reserves in the target reservoir. Busch et al. [42], Lu et al. [113], and Tang et al. [114] experimentally demonstrated the considerable storage capacity of shale for CO₂.

In this study, the equation we used to estimate CO₂ storage in shale was adapted from the method proposed by Zhou et al. [112]. This method was developed based on the mechanism of CO₂ storage, of which the competing adsorption mechanism is particularly important, which is where it differs from the mechanism of storing CO₂ in conventional oil and gas reservoirs. Adsorption increases the amount of CO₂ stored in the shale, which was described in detail in the previous section. We assumed that CO₂ is stored in the shale reservoir only in the adsorbed and free states. It was also assumed that the injected CO₂ can completely replace the free CH₄ in the pore space, ignoring the reservoir mineralization of CO₂ and the effect of moisture on the gas. This method requires fewer geological parameters and assumptions than traditional methods for estimating the geological storage of CO₂, such as the area method and the volume method [115,116,117,118], and can be calculated quickly when applied in the field as a guide for an initial estimation of a reservoir’s CO₂ storage potential. The method can be applied to various shale blocks in the Sichuan Basin, and we have carried out detailed calculations and analyses using the Changning shale gas block as an example. The model formula is as follows:

$$Q_{{\mathrm{CO}}_2}=\left[\left(1-X\right)+\frac{A_{{\mathrm{CO}}_2}}{A_{{\mathrm{CH}}_4}}X\right]Q_{{\mathrm{CH}}_4}$$

(1)

where X is the percentage of adsorbed CH₄ in the reservoir; $A_{{\mathrm{CO}}_2}$ and $A_{{\mathrm{CH}}_4}$ are the adsorption capacity of CO₂ and CH₄ in shale, respectively; and $Q_{{\mathrm{CH}}_4}$ is the shale gas storage volume, m³.

Shale reservoirs in different regions are located in different geological environments, with different formation temperatures and pressures, and have different rock compositions. All of these factors can affect the adsorption of gas by shale. By review, the percentage of absorbance state (X) range in shale is about 20% to 85% [43], and the amounts of CO₂ adsorbed in different regions of shale range from 2.68 to 19.41 times the amount of adsorbed CH₄, i.e., $\frac{A_{{\mathrm{CO}}_2}}{A_{{\mathrm{CH}}_4}}$ ranges between 2.68 and 19.41 [112]. This means that to replace 1 mole of adsorbed CH₄ gas, 2.68–19.41 moles of CO₂ are required. The shale gas reserves in the Changning block are 6 × 10¹¹ m³ (from Table 1), and the potential for storing CO₂ in the block can be calculated by substituting the data into Equation (1).

Using these parameters, we calculate the CO₂ storage potential of the Changning shale gas block, as shown in Figure 5. When X is 20% and $\frac{A_{{\mathrm{CO}}_2}}{A_{{\mathrm{CH}}_4}}$ is 2.68, the minimum CO₂ storage capacity of the Changning block is 8.016 × 10¹¹ m³ according to Equation (1); when X is 85% and $\frac{A_{{\mathrm{CO}}_2}}{A_{{\mathrm{CH}}_4}}$ is 19.41, the maximum CO₂ storage capacity of the Changning block is 9.821 × 10¹² m³ by calculation. Both of these are greater than the shale gas reserves of the block itself (6 × 10¹¹ m³).

Most of the reservoir storage depths in this block range from 2000 to 4000 m [69,119], and the average depth of storage is set at 3000 m. The formation pressure gradient in the Sichuan basin is 0.01 MPa/m, and the average geothermal gradient is 0.024 °C/m [120]. Assuming an average surface temperature of 20 °C and a storage depth of 3000 m, the formation pressure is 30 MPa and the temperature is 92 °C at this time. Thus, the corresponding CO₂ density can be derived as 695 kg/m³. After a simple transformation, the minimum CO₂ storage and the maximum CO₂ storage of the Changning block are about 5.57 × 10⁵ million tons and 6.83 × 10⁶ million tons, respectively. This shows that the Changning shale block has high potential for storing CO₂. The huge storage potential could help drive CO₂ shale-storage-related projects.

5. Conclusions and Prospects

This paper briefly reviewed CO₂ storage projects around the world, focusing on the applications and storage mechanisms related to CO₂ storage in coal seams, hydrocarbon reservoirs, and saline aquifers. Inspired by these CO₂ storage projects, we evaluated the potential for CO₂ storage through abandoned shale gas wells. The abundant shale gas resources and abandoned shale wells in the Sichuan Basin will provide sufficient and effective sites for the storage of CO₂, which was adopted here as the research topic.

In a review of the competitive adsorption of CO₂/CH₄ in shale, both the experimental and simulation results showed that the adsorption of CO₂ is significantly greater than that of CH₄ under different conditions of temperature and pressure, and the adsorption is more stable, which can help increase the storage of CO₂. We calculated the CO₂ storage capacity of the Changning shale block in the Sichuan Basin using a mechanistic approach model that considers only the adsorbed and free states of CO₂, and the results were greater than for its own shale gas reserves, proving that shale has great potential for CO₂ storage. The method is also applicable to other shale blocks in the Sichuan Basin. This provides guidance for initial assessments of reservoir CO₂ storage potential. However, the need for improved models that take into consideration the multiple storage states of CO₂ in shale is also more urgent to ensure the accuracy of the calculation results. In general, the potential for using abandoned shale gas wells to store CO₂ is high. This method is feasible and can effectively reduce carbon emissions and protect the environment.

Based on a review of available CO₂ storage techniques and an analysis of the CO₂ storage capacity of shale blocks in the Sichuan Basin, China, both technical and policy recommendations are made.

5.1. Technical Recommendations

• Due to the limitations related to the experimental setup and capability of numerical simulations, most studies are conducted in simplified reservoir conditions or assumed unrealistic ones. This will lead to errors in the results and in real life. We should further develop the technical means to ensure the maximum restoration of real situations.
• Storage analyses are conducted by assuming the wells are in relatively good condition. The differences between CO₂ storage in abandoned wells and integrity wells are not fully understood. The CO₂ injection and storage processes while considering the characteristics of abandoned wells require further investigation. Additionally, the optimization of the operation parameters (i.e., injection volume, time, and pressure) is required to achieve optimal storage.

5.2. Policy Recommendations

• Strengthen state and local government support measures, increase the amount of loans, and lower the interest rates for investment in CO₂ shale-storage-related projects, and increase the fiscal and tax incentives and subsidies. Support the implementation of demonstration projects and encourage research centers and key laboratories.
• The government should take the initiative to establish a data management and service system that allows information sharing, to establish a technology and experience exchange platform, and to provide services for enterprise development. The approval and licensing of projects related to CO₂ storage in shale optimized, and a safety and environmental protection emergency resource system should be provided. Meanwhile, an effective information disclosure and exchange platform should be established, so that enterprises can fully communicate with society.