Review of Competitive Adsorption of CO₂/CH₄ in Shale: Implications for CO₂ Sequestration and Enhancing Shale Gas Recovery

Abstract

The injection of CO₂ into shale gas reservoirs can not only enhance shale gas recovery (ESGR), but also realize CO₂ geological storage (CGS). In this study, the competitive adsorption behaviors of CO₂ and CH₄ in shale were systematically reviewed, and the implication for shale gas recovery efficiency and CO₂ storage potential were discussed. The adsorption advantage of shale for CO₂ compared to CH₄ provides a guarantee of the feasibility of supercritical CO₂ (ScCO₂) enhanced shale gas exploitation technology. The selective adsorption coefficient of CO₂ and CH₄ by shale (S_CO2/CH4) is an important parameter in evaluating the competitive adsorption behavior of CO₂/CH₄ in shale gas reservoirs, which is closely related to the mineral composition, reservoir temperature, pressure conditions, water content, and mixed gas composition ratio. In addition, the injection type, injection mode, and injection rate of gases also exhibit different effects on CO₂/CH₄ competitive adsorption. Furthermore, the interaction between ScCO₂ and the water–rock system will change the mineral composition and microstructure of shale, which will lead to changes in the adsorption behavior of shale on CO₂ and CH₄, so its influence on the competitive adsorption of CO₂/CH₄ cannot be ignored. Future research should integrate different research methods and combine with practical engineering to reveal the competitive adsorption mechanism of CO₂/CH₄ in shale reservoirs from both micro and macro aspects. This study can provide support for the integration technology of ScCO₂ enhanced shale gas exploitation and its geological storage.

1. Introduction

Shale gas is a kind of unconventional natural gas, which mainly exists in adsorbed and free states in organic matter, clay minerals, and pore and fracture structures of shale, with the adsorbed gas accounting for 20–85% of the total gas content.¹ Hydraulic fracturing is one of the main technical means of shale gas exploitation, but the recovery rate of shale gas is generally low (<30%).² The typical curve of shale gas production over time is represented in Figure 1, and the gas production process of shale reservoirs can be divided into three stages, namely, the rapid decay stage (<400 days), the slow decrease stage (400–1000 days), and the stable development stage (>1000 days). A widely accepted explanation is that the free gas is mainly recovered in the early stage of shale gas production and the adsorbed gas is predominantly recovered in the later stage.^3,4 In view of the fact that adsorbed gas mainly exists in the nanoscale pores of shale, its recovery requires a greater driving force, which is one of the predominant reasons for the low gas production in the later stage of shale gas development.

Figure 1.

Actual production amount of shale gas wells.⁵ (Photograph courtesy of Yang, R., copyright 2022, and the images in the figure are free domain.)

Numerous studies⁶⁻⁹ have indicated that the adsorption capacity of shale for CO₂ is significantly stronger than that of CH₄, thus the CO₂ huff-puff technology was suggested to be adopted in the later stage of shale gas development according to the shale oil reservoir development method. After injecting CO₂ into the shale gas reservoir, the CO₂ molecules will gradually enter the microscale or nanoscale pore structure along the fractured crack network and then exchange gas molecules with the residual adsorbed CH₄ in the form of competitive adsorption, which can promote the conversion of CH₄ from an adsorbed state to a free state, thereby improving the efficiency of shale gas recovery. Simultaneously, part of injected CO₂ will be captured by shale reservoirs to achieve CO₂ geological sequestration (Figure 2). Accordingly, the competitive adsorption behavior of CO₂/CH₄ after injecting CO₂ into the shale gas reservoir is a key factor affecting shale gas recovery and CO₂ storage.^9,10

Figure 2.

Schematic diagram of the integration of shale gas recovery and CO₂ geological storage.

In order to realize the efficient development of shale gas and CO₂ geological storage, a large number of scholars have conducted a series of studies and achieved significant results. This study systematically reviews and summarizes the previous research results, aiming to provide theoretical guidance for ScCO₂ enhanced shale gas exploitation technology. The targets and scope of this study include the following two parts:

• (1)The effects of different factors on the competitive adsorption behavior of CO₂ and CH₄ in shale are reviewed and summarized, including the content and type of organic matter, mineral composition, reservoir temperature and pressure conditions, water content, mixed gas composition ratio, injection type, injection mode, injection rate, and ScCO₂–water–rock interaction.
• (2)Based on the published relevant research, the shortcomings are pointed out, and then the directions of future attention and research are proposed.

2. CO₂/CH₄ Competitive Adsorption Behaviors in Shale

After CO₂ is injected into shale gas reservoirs, CO₂ and CH₄ actually exist in the form of mixed gas. In view of the remarkable differences in the adsorption behavior of CO₂ and CH₄ in shale, the two kinds of gas molecules will compete for adsorption sites in the micro- or nanoscale pores of shale in the form of competitive adsorption, which will generate a certain impact on shale gas recovery and CO₂ geological storage. A large number of pure component gas adsorption experiments manifest that the thermodynamic parameters such as adsorption heat, Gibbs free energy, and entropy loss of CO₂ in shale are higher than those of CH₄; moreover, the adsorption capacity of CO₂ in shale is about 2–10 times that of CH₄.¹¹⁻¹³ It can be concluded that a greater adsorption advantage for CO₂ existed in shale rather than CH₄.^7,13,14 Accordingly, after CO₂ injection into the shale reservoir, CO₂ molecules will compete with adsorbed CH₄ molecules for adsorption sites due to the difference in the adsorption of CO₂ and CH₄ in shale, which indirectly promotes the desorption of CH₄ and improves the recovery rate of shale gas. Simultaneously, part of the injected CO₂ will be captured and stored in shale reservoirs. Currently, laboratory experiments, molecular simulations, and numerical analyses were principally used to investigate the competitive adsorption behavior of CO₂/CH₄ in shale.^7,15,16

2.1. Methods

2.1.1. Laboratory Experiments

The mixed gas adsorption test is the most direct and effective means to characterize the competitive adsorption characteristics of different gases in porous materials, while it is different from the pure component gas adsorption test due to the relatively complex experimental system, resulting in increased difficulty in the experiment. Figure 3 illustrates the typical mixed gas adsorption device.¹⁵ It can be seen that the test device mainly consists of five parts: a gas mixing system, pressurization system, adsorption system, gas component calibration system, and computer control system. Compared with the pure component gas adsorption test, the main difficulties in the mixed gas adsorption test are as follows: 1) accurately configuring the composition ratio of the mixed gas; 2) accurately calculating the mixed gas adsorption capacity; and 3) obtaining kinetic adsorption data of mixed gases.

Figure 3.

Mixed gas adsorption system.¹⁵ (Photograph courtesy of Qin, C., copyright 2021, and the images in the figure are free domain.)

2.1.2. Molecular Dynamics Simulation

The difficulty with laboratory experiments is mainly reflected in the high accuracy requirements of experimental instruments, the complexity of the adsorption capacity calculation, and the challenge of analyzing various potential influencing factors. Thus, molecular simulation methods have gradually attracted the attention of scholars. Currently, density functional theory (DFT) based on quantum mechanics, the grand canonical Monte Carlo (GCMC) method based on statistical mechanics, and the molecular dynamics simulation (MD) based on Brownian motion are widely used.¹⁷ According to the types of adsorbents, the corresponding inorganic matter models and organic matter models along with inorganic and organic compound models have been established.^18,19 Among them, the commonly used inorganic models mainly include quartz and clay minerals (montmorillonite, illite) models,²⁰ the organic models mainly include graphene nanomodels and kerogen models (mainly containing three types of kerogen: types I–III),^12,21,22 and the composite models use multilayer graphene structures.²³ Generally, the molecular simulation method can be used to conduct targeted research on different variables so as to obtain the influence of different potential factors (organic matter type, mineral composition, pore structure, temperature, pressure, water content, gas component ratio, etc.) on the competitive adsorption of multicomponent gases. Figure 4 shows the construction method of a composite heterogeneous nanopore model containing organic and inorganic matter.

Figure 4.

Construction method of a composite heterogeneous nanopore model containing organic matter and inorganic matter.²⁴ (Photograph courtesy of Ma, J., copyright 2022, and the images in the figure are free domain.)

2.1.3. Numerical Analysis

Currently, the numerical simulation software applied to the competitive adsorption of multicomponent gases includes GEM, COMET, GCOMP, SIMED, and TOUGH2.²⁵⁻²⁹ Taking GEM software as an example, by determining the mass equation, the relative permeability equation, and the adsorption equation, setting reservoir-related parameters (mineral composition, porosity, permeability, etc.) and initial conditions (initial pressure, temperature, water saturation, etc.), the migration process of CO₂ and CH₄ in the target geological body can be simulated to obtain the final CH₄ yield and CO₂ storage capacity so as to analyze the adsorption and displacement mechanism of CO₂ replacement for CH₄ in shale (Figure 5).

Figure 5.

Schematic diagram of the double-porosity and double-permeability homogeneous model.³⁰

2.2. Influence Factors

A large number of competitive adsorption experiments of two-component and three-component gases on a coal matrix have been carried out and achieved remarkable results,^31,32 which have laid a theoretical foundation for studying the competitive adsorption characteristics of CO₂/CH₄ in shale. However, the adsorption capacity of shale for CO₂ and CH₄ is relatively weak compared to that of the coal matrix, and there are inevitable test errors in the mixed gas adsorption test, which makes it more difficult to conduct the multicomponent gas adsorption experiment in shale. According to the related report,³³ it can be found that the adsorption capacity of CO₂/CH₄ mixed gas in shale is between the values for pure CH₄ and pure CO₂ and displays an increasing trend with the increase in CO₂ concentration in the mixed gas. Based on the change in the molar fraction of each component in the free phase and the adsorbed phase of the mixed gas before and after adsorption, the selective adsorption coefficient can be used to evaluate the selective adsorption behavior of CO₂ and CH₄ in shale.¹⁵ The calculation procedure is shown in Figure 6

1

where S_CO2/CH4 is the selective adsorption coefficient of CO₂ and CH₄ in shale (dimensionless), which is closely related to the properties of shale samples, water content, system temperature, and pressure; x_CO2 and x_CH4 represent the molar fractions of CO₂ and CH₄ in the adsorption phase (dimensionless); y_CO2 and y_CH4 represent the mole fractions of CO₂ and CH₄ in the free phase (dimensionless). Some scholars use local density to indicate the difference in the adsorption capacity of gases, and the local density represents the number of gas molecules in a specific region or location. Due to its large molecular size and strong polarity, CO₂ interacts more strongly and generally binds to the surface of porous materials (such as shale and coal) more readily than CH₄. As a result, CO₂ exhibits a larger local density and exhibits an adsorption capacity different from that of CH₄ molecules. Qi³⁴ uses the simplified local density theory (SLD) of multicomponent gases to calculate the actual local densities of different gases in the pores. The competitive adsorption capacity of CH₄ and CO₂ gases on the pore surface was obtained by comparing the local densities. The CO₂/CH₄ competitive adsorption experiments conducted in shale are represented in Table 1, which mainly involve the effects of the shale physical structure, reservoir conditions, and gas component ratio on S_CO2/CH4, and the following conclusions can be drawn.

Figure 6.

Calculation procedure of S_CO2/CH4.

Table 1. CO₂/CH₄ Competitive Adsorption Experiments of Different Shale Samples.

References	Samples	Conditions	Main findings
Xie et al.35	Longmaxi	0–20 MPa 288–328 K	SCO2/CH4 decreases with the increases in CO2 molar fraction, temperature, and pressure but is in direct proportion to TOC and clay mineral content.
Gu et al.36,37	Longmaxi Wufeng	0–2 MPa 278–318 K	SCO2/CH4 decreases with the increases in TOC, microporous content, and temperature but is inversely proportional to clay mineral content.
Qin et al.15	Yanchang	0–6 MPa 313 K	The molar fraction of CO2 has no obvious effect on SCO2/CH4. SCO2/CH4 gradually decreases with growing pressure; the ScCO2–shale interaction resultes in a slight decline in SCO2/CH4.
Liu et al.9	Longmaxi	0–10 MPa 303 K	SCO2/CH4 is proportional to the molar fraction of CO2 and inversely proportional to the pressure.
Du et al.38	Wufeng	0–2 MPa 278–318 K	SCO2/CH4 enhances with the decreases in molar fraction of CO2 and pressure, but the effect of temperature is not obvious.
Ortiz et al.39	Outcropping shale in the Iberian Range (Spain)	0–2 MPa --	SCO2/CH4 increases first and then decreases as the pressure grows.
Qi et al.40	Wufeng–Longmaxi	0–20 MPa 303 K/353 K	SCO2/CH4 is proportional to the molar fraction of CO2 and temperature.
Liao et al.6	Wufen Longmaxi Yanchang	0–10 MPa 323 K	SCO2/CH4 increases first and then decreases with the molar fraction of CO2; the variation with pressure is affected by the CO2/CH4 mixing ratio.
Ma et al.41	Longmaxi	0–15 MPa 323–363 K	The molar fraction of CO2 in the mixed gas affects the trend of SCO2/CH4 with pressure.

2.2.1. Effect of Mineral Compositions

S_CO2/CH4 is generally proportional to the content of TOC and inversely proportional to the clay mineral content. The effect of TOC on S_CO2/CH4 is mainly related to the large number of micropore structures developed in shale organic matter.⁴² An acceptable explanation is that the micropores belong to high-energy adsorption sites in shale, and the adsorption advantage of shale for CO₂ is particularly prominent in high-energy adsorption sites.⁴³ In addition, relevant scholars⁴⁴⁻⁴⁷ have investigated the effect of organic matter type on the competitive adsorption behavior of CO₂ and CH₄ in shale, and the results indicated that the adsorption capacity and S_CO2/CH4 of different kerogens are listed as follows: IA < IID < IIC < IIB < IIA < IIIA. (IA is typical of hydrogen-rich kerogen, II is deposited in marine environments, and IIIA is deposited in deltaic environments. The chemical formulas of kerogen types of II-A, II-B, II-C, and II-D are C₂₅₂H₂₉₄O₂₄N₆S₃, C₂₃₄H₂₆₃O₁₄N₅S₂, C₂₄₂H₂₁₉O₁₃N₅S₂, and C₁₇₅H₁₀₂O₉N₄S₂, respectively) (Figure 7 (b)). In addition, they found that the N groups, S groups, and O groups in kerogen exhibit a stronger adsorption capacity for CO₂. A similar conclusion obtained by Huang et al.⁴⁶ showed that CO₂ gas was preferentially adsorbed in the S groups in the kerogen of IA and IIA models and the N groups in the kerogen of IIIA models. The influence of clay minerals on S_CO2/CH4 is also closely related to their mineral types, and the orders of S_CO2/CH4 for the clay minerals are montmorillonite > illite > kaolinite.⁴⁸ Specially, CO₂ molecules tend to occupy higher energy adsorption sites in montmorillonite and illite due to the cation exchange at low pressure, while a mixture of CO₂ and CH₄ begins to occupy the middle of the pore when the adsorption layer reaches saturation at higher pressures⁴⁶ (Figure 7 (a)).

Figure 7.

Effect of the types of clay minerals and organic matter on S_CO2/CH4. (a) Clay minerals;⁴⁸ (b) organic matter.⁴⁷ (Photograph courtesy of Hu, X., copyright 2019, and Sui, H., copyright 2020, and the images in the figure are free domain.).

It is worth noting that although S_CO2/CH4 is negatively correlated with the content of clay minerals, it exhibits a positive correlation with the content of clay minerals after standardizing clay minerals with TOC (Figure 8), indicating that the influence of TOC on S_CO2/CH4 may weaken the effects of clay minerals. The competitive adsorption behavior of CO₂ and CH₄ in clay minerals is not only related to its internal pore structure but also affected by its hydrophilic properties.⁴⁹ Water molecules will occupy part of the adsorption sites in clay minerals, thus affecting the adsorption behavior of CO₂ and CH₄. Therefore, it is necessary to consider the potential influence of hydrophilic properties on the competitive adsorption behavior of CO₂ and CH₄ in clay minerals. Through molecular simulation studies, Hu et al.⁴⁸ found that although cation exchange sites are mostly in clay minerals, the 1:1 layer structure of kaolinite lacks the interlayer space necessary for cation accommodation and exchange, coupled with the strong internal bonding and lack of charge-balancing requirements, so it does not have cation exchange. Cations may alter the adsorption sites’ energy landscape and significantly improve S_CO2/CH4; therefore, the selective adsorption capacity of kaolinite is not as good as that of montmorillonite and illite. Additionally, they consider that the charge effect may be the main factor that leads to a stronger adsorption capacity of CO₂ than CH₄ in clay minerals. Specifically, the presence of exchangeable cations will affect the ionic strength of shale pore water and the charge distribution on the shale surface, enhancing the solubility of CO₂ in the water phase. In addition, due to the different polarization properties of CO₂ and CH₄, the electrostatic interaction between CO₂ molecules and the shale surface is stronger than that of CH₄, so it is easier to adsorb.

Figure 8.

Relationship of S_CO2/CH4 versus TOC and clay content.³⁵ (Photograph courtesy of Xie, W., copyright 2022, and the images in the figure are free domain.)

2.2.2. Effects of Pore Size and Content

Aiming at the influence of micropores, Duan et al.³⁶ and Xie et al.³⁵ denoted that S_CO2/CH4 was directly proportional to the micropore content through experiments, while an unobvious correlation between micropore content and S_CO2/CH4 was represented in the study of Gu et al.³⁷ A possible interpretation is that the micropores obtained in the study of Gu et al.³⁷ are not the real micropore content of shale (the low-temperature N₂ adsorption method was used to measure the pore structure of shale in their study, while this method can test pores only above 1.5 nm). In addition, molecular simulation has been used to study the effect of different pore size ranges on the competitive adsorption of CO₂ and CH₄. Zhou et al.⁵⁰ indicated that S_CO2/CH4 decrease with the increase in pore size based on the model of kaolinite clay minerals, while a different result was obtained according to a graphene slit model of organic nanopores in shale.⁵¹ They⁵¹ discovered that S_CO2/CH4 first increased and then decreased in the pore size range of 1.0–4.0 nm, and there was a maximum value of around 1.5–2.0 nm (Figure 9). Furthermore, Qi et al.⁵² denoted that 0.42 nm is the critical size that determines which gas in CO₂ and CH₄ is preferentially adsorbed, and CH₄ will be preferentially adsorbed when the pore size is less than 0.42 nm; otherwise, CO₂ will be preferentially adsorbed. The possible explanations for this phenomenon are as follows: The pore wall exhibits a repulsive effect on gas molecules, and the repulsive effect on CO₂ in smaller pores (≤0.42 nm) is greater than that of CH₄, resulting in a weakened adsorption capacity for CO₂. The CO₂ molecule (carbon dioxide) is smaller than the CH₄ molecule (methane) and has a linear structure, whereas the CH₄ molecule is spherical. Thus, smaller CO₂ molecules are more likely to enter smaller nanopores. In addition, due to the interaction of the pore wall, the adsorption capacity of the gas molecules will be enhanced, and smaller CO₂ molecules can adapt to the pore geometry more easily and form stronger adsorption on the pore wall. In nanopores, the van der Waals forces between the gas molecules and the pore wall have a significant effect on the adsorption. Finally, because CO₂ molecules have stronger polarity and higher dipole moments, the van der Waals forces between CO₂ molecules and the pore wall are stronger than those for CH₄ molecules. In smaller pores, the diffusion rate of gas molecules is limited, while smaller CO₂ molecules diffuse at a faster rate than CH₄ molecules, which makes it easier for them to diffuse through pores and occupy adsorption sites.⁵²

Figure 9.

Effect of pore structure on S_CO2/CH4. (a) Shale samples,³⁷ (b) kaolinite,⁵⁰ and (c) organic matter.⁵¹ (Photograph courtesy of Gu, M., copyright 2017, Zhou, W., copyright 2019, and Zhou, W., copyright 2018. The images in the figure are free domain.)

It is worth mentioning that the variations of pore size can affect the adsorption behavior of CO₂ and CH₄ in shale. Related studies⁵³⁻⁵⁵ have demonstrated that CO₂ and CH₄ are mainly adsorbed in the form of micropore filling in micropores, while they are mainly adsorbed in the form of monolayers in mesopores and macropores. This is a topic of constant debate regarding whether the gas adsorption mechanism in shale is monolayer adsorption or micropore filling. Zhou et al.⁵⁰ pointed out that the strong adsorption layer is mainly due to the monolayer adsorption mechanism, while the weak adsorption layer is caused by micropore filling. Their research shows that in micropores, gas molecules first form a single layer of adsorption (strong adsorption layer) on the pore wall, and as the pressure increases or the pore diameter decreases, gas molecules begin to fill in the pores to form weak adsorption layers. The change in pore size (1–6 nm) has no obvious effect on monolayer adsorption but has a great effect on micropore filling adsorption. With the increase in pore size, the effect of micropore filling adsorption gradually weakens, and when the pore size is larger than 2 nm, the effect can be ignored (Figure 10). This may be related to factors such as gas pressure, temperature, fluid density, and pore size. Under high-pressure conditions, gas molecules are more inclined to form multilayer adsorption in the pores and the increase in temperature will reduce the density of gas molecules in the adsorption layer, so low temperature is conducive to gas adsorption. In addition, the increase in pore size will weaken the adsorption affinity of the pore structure to gas molecules, thus reducing the adsorption capacity of gas molecules. A similar conclusion was obtained by Zeng et al.,⁵⁶ and they manifested that the increase in pore size would weaken the adsorption affinity of the pore structure to gas molecules, thus reducing the number of adsorbed gas molecules. It should be noted that the development of pore fracture structure in shale is closely correlated with the diversity of mineral species, but the effect of the pore structure of different minerals on the S_CO2/CH4 has received little attention.

Figure 10.

Selectivities in different adsorption layers.⁵⁰ (Photograph courtesy of Zhou, W., copyright 2019, and the image in the figure is free domain.)

2.2.3. Effect of Reservoir Temperature and Pressure Conditions

S_CO2/CH4 is inversely proportional to the system temperature, but the influence of the system pressure remains to be further studied. Regarding the influence of temperature, although the adsorption capacity of shale for CO₂ and CH₄ decreases with increasing temperature,⁵⁷ the degree of decrease in CO₂ adsorption is higher than that of CH₄ due to the critical temperature of CO₂ being higher than that of CH₄, resulting in a decreasing trend of S_CO2/CH4 with increasing temperature. The conjecture can be verified by the research results in Figure 11. And Bai⁵⁸ studied the adsorption behavior of CO₂ molecules under subcritical and supercritical temperatures and found that the change law of gas adsorption-phase properties was determined by the special properties of near-critical fluid and the pore structure of adsorbent. Below the critical temperature, because the adsorption energy of gas molecules is usually lower than the thermal energy in the body phase, they are inclined to be adsorbed. However, as the temperature approaches or exceeds the critical temperature, the thermal energy increases, the interaction of gas molecules is weakened, and the active sites on the surface of the adsorbent are saturated faster, which may lead to the desorption of gas and reduce the adsorption amount. In addition, when the critical temperature is exceeded, the pores may expand or contract, affecting the accessibility of the pores and the availability of adsorption sites. Due to the high critical temperature of CO₂, there are differences between CO₂ and CH₄ in the adsorption process in terms of intermolecular force and adsorption heat, so its adsorption behavior is more sensitive when it is close to the critical temperature. The adsorption heat of CO₂ is usually higher than that of CH₄, so more heat is released during the adsorption process. At higher temperatures, the thermal movement of the CO₂ molecules is intensified, so they will be easier to desorb from the adsorbent surface.

Figure 11.

Effect of pressure (MPa) and temperature (K for (a) and (b),°C for (c) and (d)) on S_CO2/CH4. (a) Shale organic nanopores,⁵¹ (b) shale of the Longmaxi Formation,⁵⁹ (c) shale of the Longmaxi Formation,⁵⁴ and (d) shale of the Longmaxi Formation.⁵⁴ (Photograph courtesy of Zhou, W., copyright 2018, Lu, T., copyright 2022, and Xie, W., copyright 2021. The images in the figure are free domain.)

In view of the influence of pressure, relevant scholars^7,50 found that S_CO2/CH4 decreased with increasing adsorption pressure through laboratory tests, and they indicated that the gas molecules will be preferentially adsorbed at the high-energy adsorption site of kerogen under low-pressure conditions. In this case, the interactions between kerogen and gas molecules is dominant, and the adsorption advantage of CO₂ is reflected.⁶⁰ As the pressure increases, the high-energy adsorption sites are gradually occupied, and the gas molecules can compete for only the adsorption sites on the low-energy adsorption sites. In this case, the interaction force of the gas molecules is dominant, thus resulting in the weakening of the adsorption advantage of CO₂, and S_CO2/CH4 gradually tends to be balanced.⁴⁷ However, different results were discovered by Liao et al.⁶ and Ortiz et al.³⁹ They discovered that the S_CO2/CH4 of some shale samples increased first and then decreased with increasing pressure (Figure 12). A possible explanation is that the TOC and clay mineral (illite) content of the tested samples are relatively high, resulting in the adsorption capacity of the high-energy adsorption site in shale not reaching the saturation state under low-pressure conditions. In addition, the gas injection volume will increase with increasing pressure, while the adsorption capacity of CO₂/CH₄ in shale in the whole adsorption system is limited, which can lead to the increase of residual gas. Therefore, the influence of the free phase ratio on S_CO2/CH4 will be weakened according to eq 1; namely, the y_CO2/y_CH4 will gradually approach the original gas injection ratio with the increase in gas injection, thus resulting in the decrease in S_CO2/CH4.

Figure 12.

Change in S_CO2/CH4 with adsorption pressure in shale.⁶ (Photograph courtesy of Liao, Q., copyright 2023, and the image in the figure is free domain.)

2.2.4. Effect of Water Content

The variation of S_CO2/CH4 with water content is closely related to the type of organic matter in shale. Huang et al.⁶¹ indicated that the S_CO2/CH4 of the kerogen of IIA, IIC, and IID increased with increasing water content while that of kerogen with IIB decreased with increasing water content when the pressure is >3 MPa (Figure 13). In addition, the distribution of water molecules in kerogen varies significantly under different water content conditions. Relevant scholars^46,47,62 denoted that the water molecules will be irregularly dispersed in kerogen pores and mainly exist on the pore surface in the form of water film under the condition of low water content while most of the water molecules will form clusters and distribute in the pore center under the condition of high water content, which will lead to the pore space of kerogen being occupied by a large number of water molecules, thus reducing the adsorption capacity of kerogen for CO₂ and CH₄. On this basis, Zhou et al.⁵⁰ indicated that the polarity of water molecules is stronger than that of CO₂ and CH₄ molecules, which is the main reason that water molecules are more likely to occupy the adsorption site of kerogen. Simultaneously, the water molecules also tend to adsorb to each other and form clusters on hydrophilic clay minerals, which will further interfere with the adsorption of the CO₂ and CH₄ molecules. Furthermore, it is worth emphasizing that the molar ratio of mixed gas will change the variation of S_CO2/CH4 with the water content. Zhang et al.⁶³ discovered that the S_CO2/CH4 in kerogen decreased sharply with the increase in water content when the molar fraction of CO₂ is high while it increased with increasing water content when the molar fraction of CH₄ is high.

Figure 13.

Effect of the water content on S_CO2/CH4. (a) Different kerogen models;⁶¹ (b) type II-D kerogens (10 water, 50 water, and 100 water mean 10, 50, and 100 water molecules).⁴⁷ (Photograph courtesy of Huang, L., copyright 2018, and Sui, H., copyright 2020, and the images in the figure are free domain.).

2.2.5. Effect of the Proportion of Each Component in the Mixed Gas

The effect of the variation of the CO₂ molar fraction on S_CO2/CH4 remains to be further studied. With the increase in the CO₂ molar fraction in the CO₂/CH₄ gas mixture, S_CO2/CH4 exhibited a decreasing trend reported by Xie et al.³⁵ while it displayed a slightly increasing trend published by Qin et al.¹⁵ In addition, Liao et al.⁶ discovered that the S_CO2/CH4 obtained by the mixing ratio of 50%:50% was significantly higher than that of other mixing ratios (Figure 14). It is pointed out that the variation of S_CO2/CH4 with the proportion of mixed gas components may be related to the difference in molecular properties of different gases and the adsorption affinity of different adsorption sites in shale for gas molecules.^50,64 However, this inference is only given a qualitative description and lacks a sufficient explanation at present. Consequently, it is necessary to explore the interaction relationship of different gas molecules in shale from the molecular level, thereby providing a theoretical reference for the influence mechanism of the gas mixing ratio.

Figure 14.

Effect of the mixing ratio of CO₂/CH₄ on S_CO2/CH4.^6,15,35 (Photograph courtesy of Liao, Q., copyright 2023, Qin, C., copyright 2021, and Xie, W., copyright 2022, and the images in the figure are free domain.)

2.2.6. Effect of the Injection Gas

In addition to injecting CO₂ gas into shale reservoirs, the injection of N₂ or a mixture of N₂ and CO₂ can also improve the recovery rate of shale gas to a certain extent, while significant differences existed in the replacement mechanism of the two injected gases. Related studies through experiments and simulations⁶⁵⁻⁶⁸ have indicated that both CO₂ and N₂ injection can improve the recovery rate of shale gas to a certain extent (2–80%), but the injection effects of the two schemes are significantly different (Figure 15). They demonstrated that the injection effect of N₂ for shale gas recovery is obviously better than that of CO₂, which is mainly due to the fact that the injection of N₂ can promote the desorption of CH₄ by reducing the partial pressure of CH₄, and this effect is stronger than the influence of CO₂/CH₄ competitive adsorption on shale gas recovery. Accordingly, it is recommended to inject a mixed gas of CO₂ and N₂ into the shale reservoir in practical engineering projects, which can not only improve shale gas recovery but also achieve CO₂ geological storage. However, how to choose the appropriate injection ratio of CO₂ and N₂ is a problem worthy of attention, which may be related to the geological conditions, physical parameters, and construction technology of shale reservoirs and should be paid attention to in future practical projects.

Figure 15.

Effects of different CO₂/N₂ injection ratio on recovery efficiency of shale gas (solid lines mean <4 MPa overpressure injection and dashed lines mean <8 MPa overpressure).⁶⁵ (Photograph courtesy of Li, Z., copyright 2019, and the image in the figure is free domain.)

2.2.7. Effect of the Injection Mode and Injection Rate

Li et al.⁶⁹ used a reservoir simulation model of multicomponent transport in dual porosity sorbing and swelling media to compare different injection modes, and they found that compared with the continuous injection of CO₂ into shale reservoirs for improving shale gas recovery, the effect of huff and puff injection is more significant. In addition, the effectiveness of ESGR and CGS can be affected by the injection rate, and the increase of the gas injection rate is beneficial to ESGR and CGS when the injection rate is low while an opposite effect existed when the injection rate exceeds a certain threshold (Figure 16). Consequently, a reasonable gas injection rate should be selected according to the actual shale reservoir conditions.

Figure 16.

Effects of changes in CO₂ and N₂ injection rates on gas recovery and CO₂ storage.⁶⁷ (Photograph courtesy of Ma, H., copyright 2022, and the image in the figure is free domain.)

As can be seen from Figure 16, the increase in the injection rate can improve the recovery rate of shale gas before fracture breakthrough, and the main reason is that the permeability of the fracture cannot be effectively improved when the gas injection rate is low, thus leading to CH₄ molecules that cannot flow out. However, there is a threshold for the injection rate, and the shale gas recovery rate will decrease as the injection rate increases when the injection rate exceeds this threshold (Figure 16 (a) dark blue curve, 0.2 MMSCF/day, MMSCF is a measure of the natural gas volume and stands for million standard cubic feet). A possible interpretation is that the fracture breakthrough time may be shortened after exceeding the injection rate threshold and it is difficult to extract natural gas because the fracture permeability is not effectively improved. In addition, it can be seen from Figure 16 (b) that the injected CO₂ can be successfully sealed as long as the breakthrough point is not reached. Although more CH₄ can be recovered with the increase in the gas injection rate, the utilization efficiency of CO₂ is not improved as depicted in Figure 16 (c).

2.2.8. Effect of ScCO₂ Immersion

Simulation studies indicate that the effect of ScCO₂ immersion on ESGR and CO₂ sequestration is negligible,⁷⁰ but different conclusions have been obtained in laboratory experiments.^15,68,71 It can be clearly observed that all values of S_CO2/CH4 decreased to varying degrees after ScCO₂ immersion (Figure 17 (a)), signifying that ScCO₂ weakened the selective adsorption advantage of shale to CO₂ to a certain extent, and they indicated that the decrease in S_CO2/CH4 is mainly related to the change in the pore structure of shale. As described in Figure 17 (b), it can be seen that some micropores and mesopores in shale were converted to macropores after ScCO₂ immersion.⁷²⁻⁷⁵ Theoretically, CO₂ molecules can enter smaller pore structures compared with CH₄ molecules because the molecular diameter of CO₂ is smaller than that of CH₄. Therefore, the expansion of the pore structure in shale after ScCO₂ immersion will reduce the adsorption advantage of shale for CO₂, thus leading to a decrease in S_CO2/CH4.

Figure 17.

Effect of ScCO₂ immersion on S_CO2/CH4 and pore structure of shale.^15,74 (Photograph courtesy of Qin, C., copyright 2021, and Zhou, J., copyright 2021, and the images in the figure are free domain.)

In addition, the influence of changes in organic matter and the mineral composition of shale after ScCO₂ treatment on S_CO2/CH4 cannot be ignored. Relevant studies^76,77 indicated that after CO₂ is dissolved in water, water molecules will react to form carbonic acid, reducing the pH value of the solution, extracting organic matter from shale, dissolving some carbonates (calcite, dolomite) and clay minerals (illite, kaolinite, montmorillonite, etc.) in the shale, thus producing some secondary minerals (such as quartz, kaolinite, etc.), and finally resulting in an increase in the percentage content of quartz in shale (Figure 18). According to Figure 8 and Figure 18, it can be inferred that the decrease in the TOC content of shale after ScCO₂ treatment may result in a decrease in S_CO2/CH4.

Figure 18.

Variations in shale mineral composition before and after ScCO₂ exposure.⁷⁶

3. Implications for Shale Gas Recovery and CO₂ Geological Storage

After CO₂ injection into shale reservoirs, the competitive adsorption of CO₂/CH₄ will affect the efficiency of shale gas recovery and the potential for CO₂ storage, and relevant on-site experiments have been conducted in recent years.^10,78 For example, the first field test of CO₂ injection in the United States was conducted in the Chattanooga shale reservoir in Morgan County, Tennessee¹⁰ (Figure 19). About 500 tons of CO₂ was injected into the shale reservoir by engineering in 2 weeks, the well was sealed and soaked for four months. It is found that the shale gas recovery rate was improved, the recovery rate of shale gas after CO₂ injection was about 8 times higher than before injection, and the production life of the gas well was extended by 15 months.

Figure 19.

CO₂-ESGR project in the Chachattooga shale reservoir.¹⁰ (Copyright 2017 and the image in the figure is free domain.)

In practical engineering, in order to maximize shale gas recovery and CO₂ storage, the appropriate injection gas and injection scheme should be selected according to the geological conditions of the shale reservoir. In addition, the interactions between ScCO₂ and water–rock systems will change the mineral composition and pore structure of shale, which will lead to changes in the adsorption behavior of shale on CO₂ and CH₄, thus affecting the adsorption and replacement effect of CO₂ on CH₄ (Figure 20). Therefore, after CO₂ is injected into shale reservoirs, the appropriate soaking time is also an important factor to be considered, which can be determined through a combination of experimental research and numerical simulation.

Figure 20.

Schematic diagram of ScCO₂ enhanced shale gas exploitation and its geological storage integration.

In addition, the assessment of the CO₂ storage potential after the depletion of shale gas reservoirs is also an important issue that needs to be addressed. Currently, scholars⁷⁹⁻⁸² have carried out a large number of studies on deep saline aquifers, depleted oil and gas fields, deep unminable coal beds, and shallow seas as CO₂ storage geological bodies and have denoted that the CO₂ storage potential of geological bodies is not only affected by geological conditions such as scale, burial depth, porosity, permeability but also closely related to technology, economy, policy measures, and other factors. The calculation of the storage capacity is a key task for evaluating the CO₂ storage potential of geologic bodies. According to the differences in the purpose of evaluation and the understanding levels of geologic bodies, a technology–economic resource pyramid model was proposed by relevant scholars⁸³ to characterize the potential of CO₂ geological storage (Figure 21). This model divides the potential of CO₂ storage into four levels—theoretical storage capacity (TSC), effective storage capacity (ESC), actual storage capacity (ASC), and matching storage capacity (MSC)—and suggests that the initial assessment of the geological CO₂ storage potential should focus on TSC and ESC.

Figure 21.

Pyramid model of the CO₂ geological storage capacity.

Previous studies^80,82,84,85 have denoted that there are great differences in the CO₂ sequestration mechanism among different sequestration geological bodies, and the evaluation methods of the CSLF (Carbon Sequestration Leaders Forum), US-DOE (United States Department of Energy), UE (European Union), RIPED&CUP evaluation method, novel evaluation method, and three parameters method synchronous storage calculation method were established (Table 2). Among them, the current mainstream methods mainly include the US-DOE and USGS methods based on volume balance theory,^84,86 the CSLF method based on material balance theory,⁸² and the RIPED&CUP method based on the dissolution trapping mechanism.⁸⁷ In addition, it should be noted that the CO₂ storage capacity of the geological body is closely related to its TOC and micropore content. When the geological body has the characteristics of a shallow burial depth, abnormal pressure, and high temperature, it is difficult to reach the supercritical state after CO₂ injection, so it cannot be used as an ideal CO₂ storage site.⁸⁸ In general, there are significant differences in the CO₂ storage capacity calculated by different calculation models. Therefore, the combination of experimental and theoretical research methods should be used in practical engineering to comprehensively consider the potential impact of various factors.

Table 2. Calculation Methods for CO₂ Storage Capacity.

Measuring Methods	Mathematical model	Representative researchers
US-DOE-NETL method	GCO2 = VEV[ρCO2ϕEϕ + ρSCO2(1 – ϕ)Es(d) × Es(m)]M = ρr(CO2)·Ahφ(1 – Swi)·BE	Ma et al.83
CSLF	Mt(CO2) = ρr(CO2)·[RfAhφ(1 – Swi) – Viw+Vpw]Me(CO2) = CeMt(CO2)	Bachu et al.82
USGS	TASR = (RSV + BSV)ρr(CO2)	Brennan et al.89
RIPED&CUP		Shen et al.87
Novel evaluation methods		Rezk et al.90
Three-parameter calculation method of CSSP		Wang et al.91

4. Challenges and Perspectives

After CO₂ is injected into shale gas reservoirs, the composition and microstructure of shale are altered in the process of the ScCO₂–water–rock interaction, leading to variations in the adsorption behavior of CO₂, CH₄, and their mixed gases in shale, which affects the adsorption and displacement effect of CO₂ on residual CH₄. Currently, a large amount of research^15,92−94 has been carried out on the mineral composition, microstructure, and adsorption characteristics of shale under ScCO₂–water–rock action, but the following problems still need to be studied further.

CO₂/CH₄ competitive adsorption is a key factor affecting shale gas recovery and CO₂ geological storage.^9,46 However, there are currently difficulties in conducting mixed gas experiments and complex calculation processes for adsorption capacity, which leads to relatively enormous errors in the current test results and poor consistency among numerous research conclusions. Accordingly, it is necessary to improve the mixed gas adsorption test equipment and optimize the calculation method of the adsorption amount, thus systematically carrying out an in-depth analysis of the influence mechanism of different factors on the competitive adsorption of mixed gas via mixed gas adsorption tests combined with molecular simulation technology, finally revealing the competitive adsorption mechanism of CO₂/CH₄ in shale reservoirs.

Both CO₂ and N₂ injection can improve shale gas recovery to a certain extent,^67,95 but how to reasonably select the CO₂/N₂ mixed injection ratio from the perspectives of safety and economy is an important issue that needs to be addressed in future research. There is a threshold for the influence of the gas injection rate on ESGR and CGS, which may be closely related to shale reservoir geological conditions, gas injection modes (continuous injection, segmented injection, or pulsed injection), injected gas properties, etc. Future studies should pay attention to the influence of these potential factors. The effects of ScCO₂ injection on the composition and microstructure of shale cannot be ignored, thus the potential influences of ScCO₂–water–rock interaction on ESGR and CGS need to be considered in the future simulation process by combining with laboratory test results. In addition, there are significant differences in the CO₂ storage capacity calculated by different CO₂ storage calculation models, hence various factors should be considered comprehensively and the calculation method of the CO₂ storage capacity should be carefully selected in practical engineering.

5. Conclusions

This study systematically expounds on the competitive adsorption process of CO₂ and CH₄ in shale, analyzes the influence mechanism of different factors on S_CO2/CH4, and discusses the potential influence of CO₂/CH₄ competitive adsorption on shale gas recovery and CO₂ geological storage. The main conclusions are as follows:

• (1)S_CO2/CH4 is generally proportional to TOC and inversely proportional to clay mineral content, which can be interpreted by the abundant high-energy adsorption sites in organic matter and the hydrophobicity of clay minerals. S_CO2/CH4 decreases with increasing temperature while the effects of pressure and the proportion of mixed gas components on S_CO2/CH4 are relatively complex, which are mainly related to the changes in the adsorption site of gas molecules and the interactions among gas molecules in shale. In addition, the variation of S_CO2/CH4 with water content is controlled by the type of organic matter in shale and the molar ratio of mixed gas.
• (2)The injection type (CO₂ or N₂), injection mode (continuous injection or pulse injection), and injection rate of gases exhibit significant effects on shale gas recovery and CO₂ geological storage, and the CO₂/N₂ mixed gas injection scheme is recommended in actual engineering projects.
• (3)The ScCO₂–water–rock interaction can dissolve organic matter and minerals of shale, change the microscopic pore structure of shale, lead to changes in the adsorption behavior of CO₂ and CH₄ in shale, and affect the adsorption and replacement effects of CO₂ on CH₄ in shale during the soaking process. Therefore, the potential impact of ScCO₂ soaking on CO₂/CH₄ competitive adsorption in practical engineering cannot be ignored.
• (4)Both CO₂ and N₂ injection can improve the recovery rate of shale gas to a certain extent, but the injection effects of the two schemes are significantly different. It is recommended to use a CO₂/N₂ mixed gas injection scheme in practical engineering. The effect of CO₂ pulse injection is obviously better than that of continuous injection, and a reasonable gas injection rate should be selected according to actual shale reservoir conditions.
• (5)Significant differences existed in the CO₂ storage mechanism for different geological bodies, and the CO₂ storage capacity of a geological body is closely related to TOC and the micropore content while the geological body with a shallow burial depth, abnormal pressure, and high temperature is not an ideal place for CO₂ sequestration.

The authors declare no competing financial interest.