# Study on Competitive Adsorption and Displacing Properties of CO2 Enhanced Shale Gas Recovery: Advances and Challenges

Authors: Shuyang Liu; Baojiang Sun; Jianchun Xu; Hangyu Li; Xiaopu Wang
Journal: Geofluids
 (2020)

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## Abstract

CO2 enhanced shale gas recovery (CO2-ESGR) draws worldwide attentions in recent years with having significant environmental benefit of CO2 geological storage and economic benefit of shale gas production. This paper is aimed at reviewing the state of experiment and model studies on gas adsorption, competitive adsorption of CO2/CH4, and displacement of CO2-CH4 in shale in the process of CO2-ESGR and pointing out the related challenges and opportunities. Gas adsorption mechanism in shale, influencing factors (organic matter content, kerogen type, thermal maturity, inorganic compositions, moisture, and micro/nano-scale pore), and adsorption models are described in this work. The competitive adsorption mechanisms are qualitatively ascertained by analysis of unique molecular and supercritical properties of CO2 and the interaction of CO2 with shale matrix. Shale matrix shows a stronger affinity with CO2, and thus, adsorption capacity of CO2 is larger than that of CH4 even with the coexistence of CO2-CH4 mixture. Displacement experiments of CO2-CH4 in shale proved that shale gas recovery is enhanced by the competitive adsorption of CO2 to CH4. Although the competitive adsorption mechanism is preliminary revealed, some challenges still exist. Competitive adsorption behavior is not fully understood in the coexistence of CO2 and CH4 components, and more experiment and model studies on adsorption of CO2-CH4 mixtures need to be conducted under field conditions. Coupling of competitive adsorption with displacing flow is key factor for CO2-ESGR but not comprehensively studied. More displacement experiments of CO2-CH4 in shale are required for revealing the mechanism of flow and transport of gas in CO2-ESGR.


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## Body

## 1. Introduction

Due to increasing combustion of fossil fuels and the ensuing large-scale CO2 emissions, the high level of CO2 content in the global atmosphere is believed as the main driving force of global climate change [1, 2], which may cause climate disasters, seriously affecting human life and the earth’s ecology [3, 4]. CO2 capture, utilization, and storage (CCUS) technology is a promising and practical CO2 mitigation technology by injecting the captured CO2 into underground formation for permanent sequestration and enhanced oil/gas recovery and other underground energy recovery [5–8], drawing worldwide attentions.Natural gas is regarded as one of the most promising alternatives of traditional fossil fuels, such as coal and oil, as it is one of the efficient and clean energy sources for environmental protection. In recent years, large-scale shale gas reservoirs have been discovered worldwide as one of the typical unconventional natural gas resources. The global shale gas is reported as five times conventional gas reserves [9] with the large technically recoverable resources reported in China (1115 tcf), US (665 tcf), and Canada (573 tcf) [10]. The development of shale gas reservoir is imminent. Shale formations are commonly tight with low intrinsic permeability, and thus, it is difficult to be exploited by conventional development technologies. It is necessary to increase permeability and pore connectivity by fracturing technology for exploitation. At present, hydraulic fracturing is the main reservoir reconstruction technology to artificially fracture and extend natural microcracks for shale gas exploitation [6, 7]. However, hydraulic fracturing has many problems such as water consumption, chemical additive pollution, and reservoir damage [11].Compared to hydraulic fracturing, CO2 fracturing has many advantages such as reducing fracturing pressure, reducing flow blockage, and avoiding reservoir damage and pollution [6, 12]. The conception of CO2 enhanced shale gas recovery (CO2-ESGR) technology comes out by combining CO2 fracturing and CO2 injection for shale gas exploitation. CO2 replaces the adsorbed CH4 in shale matrix (kerogen or clay) through competitive adsorption and displaces the free CH4 in the fractured pores during the process of CO2-ESGR, thereby increasing the recovery of shale gas. Notably, CO2-ESGR is one of the promising CCUS technologies to store CO2 into the shale formation for greenhouse gas emission reduction [13]. Thus, CO2-ESGR has great application potential for both the economic benefit of efficient exploitation of shale gas reservoirs and the simultaneous environmental benefit of CO2 mitigation.CO2-ESGR contains several processes, such as shale fracturing, CO2 displacement of the free CH4 in pore and fractures, CH4 desorption and CO2 competitive adsorption, and CO2 geological storage. The schematic diagram of CO2-ESGR is shown in Figure 1. Therefore, in order to achieve effective development of CO2-ESGR technology, some relevant key scientific problems must be solved, including mechanism of CH4 adsorption/desorption, CO2/CH4 competitive adsorption mechanism in shale matrix, and CO2 displacement CH4 flow and mass transfer mechanism. The adsorption/desorption characteristic of single-component gas (CH4 or CO2) in shale has also been fundamentally studied [14–16]. Among these key scientific problems, mechanism of CO2/CH4 competitive adsorption in shale matrix and flow and mass transfer in the displacement of CO2-CH4 has not been fully understood and has attracted widespread attention and curiosity worldwide. Recently, more and more studies are focused on these issues.Figure 1
(a) Schematic diagram of CO2 enhanced shale gas recovery; (b) schematic diagram of CO2 displacing/replacing CH4 in shale during CO2 fracturing for enhanced shale gas recovery [12].
(a)(b)This work is aimed at addressing the issue of CO2 replacing and displacing shale gas in CO2-ESGR, link the study on adsorption/desorption of CO2/CH4 in shale and flow characteristics of CO2 displacing CH4. The advances on competitive adsorption of CO2/CH4 during CO2 displacing CH4 in shale related to CO2-ESGR are review, and the challenges and opportunities are address.


## 2. Gas Adsorption in Shale

The natural gas in shale is generated in situ from the organic-rich deposition through biogenic and thermogenic processes [17]. Shale gas is consisted of predominant CH4 (>94%), other higher hydrocarbons (ethane, propane, and butane), and minor fraction of inorganic gases [18]. Shale gas is mainly stored in three states: adsorbed gas on the micro/nano-scale pore of shale matrix, free gas in natural cracks and pores, and a small amount of solution gas dissolved in the connate water [19]. The adsorbed CH4 in the micro/nano-scale pores accounts for a great proportion (20-80%) of the total shale gas resources [14, 20, 21]. Therefore, gas adsorption in shale is one of the most important mechanism of gas storage. Thus, adsorption/desorption characteristics of CH4 in shale play a key role in the determination of economic feasibility and exploration mode of shale gas reservoirs. The knowledge of gas storage and transport mechanisms related to adsorption is required for resource quantification and evaluation of long-term production behavior. [22]


### 2.1. Adsorption Mechanism

Gas adsorption is the accumulation process of gas molecules on the rock surface by two kinds of mechanism: physisorption (physical adsorption) through van der Waals forces and chemisorption (chemical adsorption) through bonds by electron sharing or transfer [23]. Thereby, a high density in adsorbed phase is formed different from the free gas present in the surrounding [24]. Thus, the gas storage potential of shale is increased by twice or more than rocks in absence of adsorption due to the adsorption mechanism [25]. Commonly, the gas adsorption in shale is mainly considered as physisorption [26, 27]. Physisorption is an exothermic process, and the adsorption heat is in the range from 8 to 40 kJ/mol [28]. It is believed that two kinds of physisorption mechanism take place for gas adsorption in shale: monolayer adsorption at low pressures and multilayer adsorption at high pressures [23]. Desorption is regarded as the counter process of adsorption with gas released from shale matrix surface.The gas adsorption characteristics in shale are usually evaluated by the measurement of adsorption isotherms in laboratory, which involves measuring the uptake or release of either gas species on a shale sample at certain temperature and pressure conditions [29–32]. Adsorption isotherm curves are commonly measured by gravimetric, volumetric/manometric, and chromatographic methods [30, 33, 34]. Thus, the gas storage capacity in shale due to adsorption can be estimated under certain temperature and pressure according to the adsorption isotherms. Based on the experimental data of adsorption/desorption isotherm, models are established for predicting gas adsorption behavior in shale, such as Langmuir model and Brunauer-Emmett-Teller models.


### 2.2. Influence of Various Factors on CH4 Adsorption

Shale commonly consists of organic matter (kerogen), inorganic clay, and other mineral compositions, such as quartz and mica. The related mineral and geological properties of shale play a key role in controlling the gas adsorption characteristics in shale. For the purpose of evaluating shale gas reservoir resources, researchers concentrated on the adsorption/desorption mechanism of CH4 in shale in the early studies, and the main influencing factors were analyzed: organic matter content, kerogen type, mineralogy, thermal maturity (Ro), moisture, micropore structure and pore size distribution, etc. Thus, the main controlling mechanism of influencing factors is described, and no more details are introduced here because the influence of various factors on adsorption has been reviewed by Rani et al. [24] and Klewiah et al. [32].The organic matter content in shale is usually quantified by the total organic carbon (TOC), and it is one of the most significant controlling factors on adsorption characteristics. Some studies [22, 35] confirmed that the amount of adsorbed CH4 in shale is proportional to the organic matter content, and the larger TOC can improve the adsorption capacity of CH4. This phenomenon can take place in almost all kinds of shales. Klewiah et al. [32] summarized a lot of experimental data [22, 29, 35–45] in different shales and confirmed the strong correlation of gas capacity with TOC, shown in Figure 2. The adsorption capacities of CH4 have strong positive linearity with TOC for both dry and moist shales. The probable reason is that organic richness is believed to be primarily responsible for the microporous nature of shale and the main contributor to the surface area and total pore volume [43, 46]. Thus, gas adsorption capacity increases with rising content of TOC in shale.Figure 2
Correlation between TOC and CH4 and CO2 sorption capacity in dry and moisture shales [32]. Experimental data points are selected from literature [22, 29, 35–45].Besides TOC, kerogen type plays a significant role on controlling gas adsorption capacity. Considering the nature of organic matter and surroundings, kerogen is categorized as three types based on its composition and type of generating hydrocarbon [47–49]. Type I, Type II, and Type III kerogen are attributed to extensive aromatization from immature to overmature organic matter [32]. Type I kerogen mainly consists of algal and amorphous kerogen, which is mostly generated from lacustrine and marine environments. Type I kerogen is highly likely to generate oil and has ability to produce gas in the proper thermal maturity. Type II kerogen is rich in hydrogen and low in carbon, and it is formed from mixed terrestrial and marine source materials. Type II kerogen can generate both oil and gas. Type III kerogen is rich in oxygen and poor in hydrogen, and it is formed from terrestrial plant debris. Type III kerogen generally generates gas. Due to the different source rock material and deposition environments of kerogen, some studies [35, 50] have proved that the gas adsorption capacity is in the order of Type III > Type II > Type I.Thermal maturity (Ro) is another key influencing factor in gas adsorption capacity of shales. Thermal maturity is an indicator to show the heat-driven diagenetic changes of organic matter in sedimentary source rocks to generate hydrocarbons [32]. With the structural transformation of kerogen during maturation, more additional micro/nano-scale pores are generated [50–52]. Correspondingly, the gas adsorption capacity in shale increases with the higher thermal maturity in general, although a few studies found that the thermal maturity has little effect on adsorption [35] or CH4 adsorption capacity concomitantly decrease with increasing maturity [50, 53].The main inorganic compositions of shale include clay, quartz, mica, albite, pyrite, carbonate, and mineral, and these inorganic compositions, particularly the clay minerals, contribute enormously to the inner surface area and micropore volume and affect adsorption properties [54–56]. Thus, clay types (illite, smectite, kaolinite) and contents are one of the significant factors on gas adsorption in shale. The larger clay contents in shale are believed to increase the gas adsorption capacity [22, 57, 58]. However, the influence of inorganic mineral matters on different gas adsorption shows different behaviors in various studies. CH4 adsorption capacity is affected little by the inorganic matter in some studies [59], but several researches also show that the inorganic matter has significant influence on CO2 adsorption [29]. Nevertheless, more researchers have proven that the mineral components have appreciable sorption capacity for both CH4 and CO2 [22, 40].Moisture also plays a crucial role on analysis of gas adsorption characteristics. The effect of moisture in shale is always related to organic matters and clay contents [53, 60]. It is reported that water molecules would compete with gas for identical adsorption sites on organic matters via hydrogen bonding [22, 35, 45, 50] and interact with preadsorbed water and charged surfaces of mineral matter (especially chemisorptive clay) [32]. Thus, moisture weakens the adsorption capacity of CH4 in shale, shown in Figure 2.TOC content and shale mineral composition analysis may not fully explain the gas adsorption mechanism in shale; pore volume (especially micro/nano-scale pores) and inner surface area are crucial on the gas adsorption [61]. Rexer et al. [61] showed that the main controlling factor for the amount of adsorbed gas in shale is the volume of adsorption pores, and most of the adsorbed CH4 is in microscale pores with a diameter of less than 6 nm. Xue et al. [62] conducted on visualization study of shale micropore structure and mineral composition analysis and their influence on adsorption and found that the gas adsorption capacity is linearly related to the product of TOC and surface porosity.


### 2.3. Adsorption Difference between CO2 and CH4 in Shale

Due to the physical properties difference, CO2 and CH4 have significantly different adsorption behavior in shale. The typical adsorption isotherms for CH4 and CO2 have been studied by Weniger et al. [29], shown in Figure 3. Under different TOC condition, the excess adsorption of CH4 in shale consistently increases with pressure and gradually reach a constant value at high pressures [32, 63–65]. The adsorption of CO2 is closely related to the phase state: in gas state, the excess adsorption of CO2 increases with pressure by having a larger increasing rate than CH4 before supercritical point, then reaches the maximum in the vicinity of supercritical pressure and then decreases in supercritical state. The mentioned difference in adsorption characteristics between CO2 and CH4 has also been clearly reported in other experiments [45, 66–70].Figure 3
Adsorption isotherm (excess sorption vs. pressure) for (a) CH4 and (b) CO2 on crushed dry shale samples of the Parana Basin in Brazil at a temperature of 45°C [29].
(a)(b)Compared to CH4 adsorption in shale, some influencing factors have different performance for CO2 adsorption in shale, which will be described as follows. Similar with CH4, CO2 adsorption capacity increases with higher TOC, shown in Figure 3. More precisely, the adsorption capacities of both two gases have strong positive linearity with TOC, summarized by Klewiah et al. [32], illustrated in Figure 2. Generally, the adsorption capacity of CO2 is much larger than that of CH4 at the same TOC for both dry and moist shale, and the increasing rate of the former versus TOC is much higher than that of the latter in dry shale. In contrast to that, the adsorption capacity of CH4 in the moist shale is lower than that in dry one; CO2 adsorption capacity in moist shale may larger than that in dry one at low TOC, shown in Figure 2. Results of experiments and molecule grand canonical Monte Carlo (GCMC) simulations in Huang et al. [70] showed that the maximum adsorption capacity of gas molecules for both CO2 and CH4 on kerogen is proportional to the effective pore volumes, which increases with kerogen maturity but decreases with moisture content. The effect of other factors on adsorption, such as thermal maturity and inorganic components, shows similar for both CO2 and CH4, which was described by Isaac et al. [32]


### 2.4. Adsorption Models

Adsorption models, such as Langmuir model and Brunauer-Emmett-Teller models, are frequently built based on the experimental adsorption isotherms. For the main adsorption mechanism of CH4 in shale, Langmuir model is built for the evaluation of monolayer adsorption behavior, and Brunauer-Emmett-Teller (BET) and Freundlich’s isotherms are established for the multilayer adsorption (Table 1) [23].Table 1
Typical models for monolayer and multilayer adsorption.
ModelFormulaReferenceLangmuirq=Qlklp/1+klp[71]BETq=Qmkbp/ps−p1+kb−1p/ps[72]Freundlichq=kfpn[73]whereq is the gas adsorption, mg/g; p is the pressure, bar; Ql is the Langmuir maximum adsorption, mg/g; kl is the Langmuir constant; ps is the saturation pressure, bar; kb is the constants of BET isotherm; Qm is the maximum uptake, mg/g; and kf and n are the constants of Freundlich isotherm.Langmuir model and its improved model [15, 35, 61] are widely used for the adsorption/desorption of single-component gas under the conditions of low pressure in shale. Lu et al. [30] proved that the Langmuir model can accurately predict the adsorption characteristics at a single temperature, but the adsorption prediction of Langmuir under multitemperature conditions is not so accurate, while the bi-Langmuir model has a better prediction accuracy on the adsorption characteristics of single-component gas in shale by considering the influence of temperature changes.Most of shale gas reservoirs are usually located in depth of 2000-4000 m underground, and the reservoir temperatures are in the range of 96-122°C with the pore pressures of 15-25 MPa [69]. The critical conditions are 31.1°C and 7.4 MPa for CO2 and -82.6°C and 4.6 MPa for CH4 [74, 75], and thereby, CH4 and CO2 are both in supercritical state in shale reservoirs. As the conventional adsorption model, such as Langmuir model, cannot precisely predict the adsorption behavior under shale gas reservoir conditions of high temperature and high pressure, and more fine models are needed in response to this situation.The supercritical adsorption models based on adsorption potential theory, such as supercritical Dubinin-Radushkevich (SDR) model, are developed for accurate description of gas adsorption behaviors in shale under high-temperature and high-pressure reservoir conditions. However, Tian et al. [76] found that there is no significant improvement for SDR model in prediction of the maximum absolute CH4 adsorption in the Sichuan Basin shale by comparing to Langmuir model. Song et al. [77] proposed an adaptive L-SDR model based on the combination of SDR model and Langmuir model, and the comparison of the adaptive L-SDR, Langmuir, and SDR for prediction of gas adsorption isotherm in Tarim Basin shale showed that the L-SDR model more accurately predicts the adsorption characteristics of supercritical CH4 in shale at both low and high temperatures. The lattice density functional theory (LDFT) model is another supercritical adsorption model to predict the adsorption enthalpy. Hwang et al. [78] showed that even under high pressure, the predictive ability of the LDFT model was proved in revealing the pore-dependent adsorption behavior. Considering the difference in the adsorption mechanism of CH4 with different pore diameters, Zhou et al. [79] proved that the adsorption form of CH4 in shale is not only through single micropores or single layer adsorption and established a new supercritical adsorption model for shale gas. This supercritical adsorption model presents the adsorption mechanism in micro/nano-scale pores by comprehensively combining the coexistence of pore filling and single-molecule adsorption.


## 2.1. Adsorption Mechanism

Gas adsorption is the accumulation process of gas molecules on the rock surface by two kinds of mechanism: physisorption (physical adsorption) through van der Waals forces and chemisorption (chemical adsorption) through bonds by electron sharing or transfer [23]. Thereby, a high density in adsorbed phase is formed different from the free gas present in the surrounding [24]. Thus, the gas storage potential of shale is increased by twice or more than rocks in absence of adsorption due to the adsorption mechanism [25]. Commonly, the gas adsorption in shale is mainly considered as physisorption [26, 27]. Physisorption is an exothermic process, and the adsorption heat is in the range from 8 to 40 kJ/mol [28]. It is believed that two kinds of physisorption mechanism take place for gas adsorption in shale: monolayer adsorption at low pressures and multilayer adsorption at high pressures [23]. Desorption is regarded as the counter process of adsorption with gas released from shale matrix surface.The gas adsorption characteristics in shale are usually evaluated by the measurement of adsorption isotherms in laboratory, which involves measuring the uptake or release of either gas species on a shale sample at certain temperature and pressure conditions [29–32]. Adsorption isotherm curves are commonly measured by gravimetric, volumetric/manometric, and chromatographic methods [30, 33, 34]. Thus, the gas storage capacity in shale due to adsorption can be estimated under certain temperature and pressure according to the adsorption isotherms. Based on the experimental data of adsorption/desorption isotherm, models are established for predicting gas adsorption behavior in shale, such as Langmuir model and Brunauer-Emmett-Teller models.


## 2.2. Influence of Various Factors on CH4 Adsorption

Shale commonly consists of organic matter (kerogen), inorganic clay, and other mineral compositions, such as quartz and mica. The related mineral and geological properties of shale play a key role in controlling the gas adsorption characteristics in shale. For the purpose of evaluating shale gas reservoir resources, researchers concentrated on the adsorption/desorption mechanism of CH4 in shale in the early studies, and the main influencing factors were analyzed: organic matter content, kerogen type, mineralogy, thermal maturity (Ro), moisture, micropore structure and pore size distribution, etc. Thus, the main controlling mechanism of influencing factors is described, and no more details are introduced here because the influence of various factors on adsorption has been reviewed by Rani et al. [24] and Klewiah et al. [32].The organic matter content in shale is usually quantified by the total organic carbon (TOC), and it is one of the most significant controlling factors on adsorption characteristics. Some studies [22, 35] confirmed that the amount of adsorbed CH4 in shale is proportional to the organic matter content, and the larger TOC can improve the adsorption capacity of CH4. This phenomenon can take place in almost all kinds of shales. Klewiah et al. [32] summarized a lot of experimental data [22, 29, 35–45] in different shales and confirmed the strong correlation of gas capacity with TOC, shown in Figure 2. The adsorption capacities of CH4 have strong positive linearity with TOC for both dry and moist shales. The probable reason is that organic richness is believed to be primarily responsible for the microporous nature of shale and the main contributor to the surface area and total pore volume [43, 46]. Thus, gas adsorption capacity increases with rising content of TOC in shale.Figure 2
Correlation between TOC and CH4 and CO2 sorption capacity in dry and moisture shales [32]. Experimental data points are selected from literature [22, 29, 35–45].Besides TOC, kerogen type plays a significant role on controlling gas adsorption capacity. Considering the nature of organic matter and surroundings, kerogen is categorized as three types based on its composition and type of generating hydrocarbon [47–49]. Type I, Type II, and Type III kerogen are attributed to extensive aromatization from immature to overmature organic matter [32]. Type I kerogen mainly consists of algal and amorphous kerogen, which is mostly generated from lacustrine and marine environments. Type I kerogen is highly likely to generate oil and has ability to produce gas in the proper thermal maturity. Type II kerogen is rich in hydrogen and low in carbon, and it is formed from mixed terrestrial and marine source materials. Type II kerogen can generate both oil and gas. Type III kerogen is rich in oxygen and poor in hydrogen, and it is formed from terrestrial plant debris. Type III kerogen generally generates gas. Due to the different source rock material and deposition environments of kerogen, some studies [35, 50] have proved that the gas adsorption capacity is in the order of Type III > Type II > Type I.Thermal maturity (Ro) is another key influencing factor in gas adsorption capacity of shales. Thermal maturity is an indicator to show the heat-driven diagenetic changes of organic matter in sedimentary source rocks to generate hydrocarbons [32]. With the structural transformation of kerogen during maturation, more additional micro/nano-scale pores are generated [50–52]. Correspondingly, the gas adsorption capacity in shale increases with the higher thermal maturity in general, although a few studies found that the thermal maturity has little effect on adsorption [35] or CH4 adsorption capacity concomitantly decrease with increasing maturity [50, 53].The main inorganic compositions of shale include clay, quartz, mica, albite, pyrite, carbonate, and mineral, and these inorganic compositions, particularly the clay minerals, contribute enormously to the inner surface area and micropore volume and affect adsorption properties [54–56]. Thus, clay types (illite, smectite, kaolinite) and contents are one of the significant factors on gas adsorption in shale. The larger clay contents in shale are believed to increase the gas adsorption capacity [22, 57, 58]. However, the influence of inorganic mineral matters on different gas adsorption shows different behaviors in various studies. CH4 adsorption capacity is affected little by the inorganic matter in some studies [59], but several researches also show that the inorganic matter has significant influence on CO2 adsorption [29]. Nevertheless, more researchers have proven that the mineral components have appreciable sorption capacity for both CH4 and CO2 [22, 40].Moisture also plays a crucial role on analysis of gas adsorption characteristics. The effect of moisture in shale is always related to organic matters and clay contents [53, 60]. It is reported that water molecules would compete with gas for identical adsorption sites on organic matters via hydrogen bonding [22, 35, 45, 50] and interact with preadsorbed water and charged surfaces of mineral matter (especially chemisorptive clay) [32]. Thus, moisture weakens the adsorption capacity of CH4 in shale, shown in Figure 2.TOC content and shale mineral composition analysis may not fully explain the gas adsorption mechanism in shale; pore volume (especially micro/nano-scale pores) and inner surface area are crucial on the gas adsorption [61]. Rexer et al. [61] showed that the main controlling factor for the amount of adsorbed gas in shale is the volume of adsorption pores, and most of the adsorbed CH4 is in microscale pores with a diameter of less than 6 nm. Xue et al. [62] conducted on visualization study of shale micropore structure and mineral composition analysis and their influence on adsorption and found that the gas adsorption capacity is linearly related to the product of TOC and surface porosity.


## 2.3. Adsorption Difference between CO2 and CH4 in Shale

Due to the physical properties difference, CO2 and CH4 have significantly different adsorption behavior in shale. The typical adsorption isotherms for CH4 and CO2 have been studied by Weniger et al. [29], shown in Figure 3. Under different TOC condition, the excess adsorption of CH4 in shale consistently increases with pressure and gradually reach a constant value at high pressures [32, 63–65]. The adsorption of CO2 is closely related to the phase state: in gas state, the excess adsorption of CO2 increases with pressure by having a larger increasing rate than CH4 before supercritical point, then reaches the maximum in the vicinity of supercritical pressure and then decreases in supercritical state. The mentioned difference in adsorption characteristics between CO2 and CH4 has also been clearly reported in other experiments [45, 66–70].Figure 3
Adsorption isotherm (excess sorption vs. pressure) for (a) CH4 and (b) CO2 on crushed dry shale samples of the Parana Basin in Brazil at a temperature of 45°C [29].
(a)(b)Compared to CH4 adsorption in shale, some influencing factors have different performance for CO2 adsorption in shale, which will be described as follows. Similar with CH4, CO2 adsorption capacity increases with higher TOC, shown in Figure 3. More precisely, the adsorption capacities of both two gases have strong positive linearity with TOC, summarized by Klewiah et al. [32], illustrated in Figure 2. Generally, the adsorption capacity of CO2 is much larger than that of CH4 at the same TOC for both dry and moist shale, and the increasing rate of the former versus TOC is much higher than that of the latter in dry shale. In contrast to that, the adsorption capacity of CH4 in the moist shale is lower than that in dry one; CO2 adsorption capacity in moist shale may larger than that in dry one at low TOC, shown in Figure 2. Results of experiments and molecule grand canonical Monte Carlo (GCMC) simulations in Huang et al. [70] showed that the maximum adsorption capacity of gas molecules for both CO2 and CH4 on kerogen is proportional to the effective pore volumes, which increases with kerogen maturity but decreases with moisture content. The effect of other factors on adsorption, such as thermal maturity and inorganic components, shows similar for both CO2 and CH4, which was described by Isaac et al. [32]


## 2.4. Adsorption Models

Adsorption models, such as Langmuir model and Brunauer-Emmett-Teller models, are frequently built based on the experimental adsorption isotherms. For the main adsorption mechanism of CH4 in shale, Langmuir model is built for the evaluation of monolayer adsorption behavior, and Brunauer-Emmett-Teller (BET) and Freundlich’s isotherms are established for the multilayer adsorption (Table 1) [23].Table 1
Typical models for monolayer and multilayer adsorption.
ModelFormulaReferenceLangmuirq=Qlklp/1+klp[71]BETq=Qmkbp/ps−p1+kb−1p/ps[72]Freundlichq=kfpn[73]whereq is the gas adsorption, mg/g; p is the pressure, bar; Ql is the Langmuir maximum adsorption, mg/g; kl is the Langmuir constant; ps is the saturation pressure, bar; kb is the constants of BET isotherm; Qm is the maximum uptake, mg/g; and kf and n are the constants of Freundlich isotherm.Langmuir model and its improved model [15, 35, 61] are widely used for the adsorption/desorption of single-component gas under the conditions of low pressure in shale. Lu et al. [30] proved that the Langmuir model can accurately predict the adsorption characteristics at a single temperature, but the adsorption prediction of Langmuir under multitemperature conditions is not so accurate, while the bi-Langmuir model has a better prediction accuracy on the adsorption characteristics of single-component gas in shale by considering the influence of temperature changes.Most of shale gas reservoirs are usually located in depth of 2000-4000 m underground, and the reservoir temperatures are in the range of 96-122°C with the pore pressures of 15-25 MPa [69]. The critical conditions are 31.1°C and 7.4 MPa for CO2 and -82.6°C and 4.6 MPa for CH4 [74, 75], and thereby, CH4 and CO2 are both in supercritical state in shale reservoirs. As the conventional adsorption model, such as Langmuir model, cannot precisely predict the adsorption behavior under shale gas reservoir conditions of high temperature and high pressure, and more fine models are needed in response to this situation.The supercritical adsorption models based on adsorption potential theory, such as supercritical Dubinin-Radushkevich (SDR) model, are developed for accurate description of gas adsorption behaviors in shale under high-temperature and high-pressure reservoir conditions. However, Tian et al. [76] found that there is no significant improvement for SDR model in prediction of the maximum absolute CH4 adsorption in the Sichuan Basin shale by comparing to Langmuir model. Song et al. [77] proposed an adaptive L-SDR model based on the combination of SDR model and Langmuir model, and the comparison of the adaptive L-SDR, Langmuir, and SDR for prediction of gas adsorption isotherm in Tarim Basin shale showed that the L-SDR model more accurately predicts the adsorption characteristics of supercritical CH4 in shale at both low and high temperatures. The lattice density functional theory (LDFT) model is another supercritical adsorption model to predict the adsorption enthalpy. Hwang et al. [78] showed that even under high pressure, the predictive ability of the LDFT model was proved in revealing the pore-dependent adsorption behavior. Considering the difference in the adsorption mechanism of CH4 with different pore diameters, Zhou et al. [79] proved that the adsorption form of CH4 in shale is not only through single micropores or single layer adsorption and established a new supercritical adsorption model for shale gas. This supercritical adsorption model presents the adsorption mechanism in micro/nano-scale pores by comprehensively combining the coexistence of pore filling and single-molecule adsorption.


## 3. Competitive Adsorption between CH4 and CO2

The conception of CO2-ESGR for shale gas exploitation has a unique promising potential through CO2 competitive adsorption to release the adsorbed CH4 from shale matrix into the fractures and cracks for production and thus to increase shale gas recovery [32]. Thus, the competitive adsorption of CO2 to CH4 in shale plays the key role on CO2-ESGR. When CO2 injected into shale reservoir, CO2 will compete the adsorption sites on the inner surface of shale matrix with CH4. Then, the desorption of CH4 and adsorption of CO2 synchronize in the shale formation due to competitive adsorption, and the flow and mass transfer in this process are schematically shown in Figure 4.Figure 4
Schematic diagram of the competitive adsorption and transport of CO2 and CH4 in shales [13].


### 3.1. Experimental Study on CO2/CH4 Competitive Adsorption

The competitive adsorption characteristics of CO2 to CH4 were initially investigated by comparative analysis of the adsorption behavior between single-component gas of CO2 and CH4. Nuttall et al. [44] first observed that the adsorption capacity of pure CO2 is approximately 5 times greater than that of CH4 in Devonian black shales at the same conditions. The adsorption capacity of pure CO2 was also reported consistently higher than that of CH4 in various kinds of shale by many following research [16, 26, 29, 40, 41, 80–84]. Klewiah et al. [32] summarized some related adsorption experiments of single-component gas of CO2 and CH4, reported the CO2/CH4 adsorption ratio in the range of 1.3-10 for dry shale, and revealed moisture weakening the CO2/CH4 adsorption ratio. Similar to CH4, the increase in pressure and organic carbon content contributes to adsorption capacity of CO2 in shale, while the temperature is the opposite. Compared to CH4, the desorption process of CO2 has an obvious hysteresis effect, which is conducive to long-term CO2 storage [83, 85]. The moisture, matrix expansion, and pore throat size may affect the hysteresis of CO2 desorption behavior, but the mechanism of CO2 desorption hysteresis has not been thoroughly revealed [86, 87].The adsorption experiments of CO2-CH4 mixture system [42, 88–92] show that the greater adsorption affinity exists for CO2 in shales than CH4 even though sometimes CH4 is preferentially adsorbed in the adsorption experiment of CO2-CH4 mixture. It is revealed that CO2 has a higher adsorption capacity in the coexistence of CO2 and CH4, proving that competitive adsorption is beneficial to the implementation of CO2-ESGR. However, Qi et al. [91] confirmed that the adsorption characteristics are not only related to adsorption affinity but also affected by the partial pressure of the components in the mixture system, and the competitive adsorption ratio of CO2/CH4 in the mixture system may be smaller than that under condition of single-component adsorption. Thus, more experiments of CO2-CH4 mixture adsorption/desorption are needed for competitive adsorption characteristics and mechanism.Except the competitive adsorption of static gas adsorption experiments of single-component gas and CO2-CH4 mixture system, several researchers carried out dynamic competitive adsorption experiment on CO2-CH4 exchange characteristics [93–95]. The competitive adsorption ratio and enhanced recovery of shale gas by injection of CO2 were also proved by these dynamic experiments.


### 3.2. Mechanism of CO2/CH4 Competitive Adsorption

As for the mechanism of competitive adsorption between CO2 and CH4 in shale, the competition for adsorption sites plays a key role on CO2 replacing CH4. Specifically, molecular size of gas, interaction energy (thermodynamic forces) between gas and shale matrix, and accessibility of gas into the shale microporous network (steric forces) are considered as the important controlling factors of competitive adsorption between CO2 and CH4 [32]. The molecular characteristic difference between CO2 and CH4 is crucial: CH4 molecule is tetrahedral geometry with a relative larger kinetic diameter of 3.80 Ao, and CO2 molecule is linear molecular with a smaller kinetic diameter of 3.30 Ao [26, 74, 75, 96], shown in Table 2. Due to the smaller molecular size, CO2 can easily access into micro/nano-scale pores with smaller diameter which may be difficult for CH4, and thus, CO2 is favourable to contact larger surface and adsorption sites in shale matrix [32, 97]. Moreover, CO2 can interact more strongly with functional groups in kerogen because of higher quadrupole moment, and thus, CO2 is more prone to physical adsorption caused by van der Waals force than CH4 [26, 98, 99]. Zhao and Wang [95] revealed that the surface of shale organic matter has a stronger affinity for CO2 than CH4, and then, CO2 competes for adsorption sites to replace the adsorbed CH4 on the surface of the matrix. The higher critical temperature of CO2 also favour the competitive adsorption to replace CH4 [97]. As an endothermic reaction, desorption process of CH4 needs a relative lower of the adsorption heat than that of CO2, and thus, desorption of CH4 from shale can be more easily realized in the coexisting CO2 adsorption process. The unique supercritical properties of CO2, such as liquid-like density, gas-like diffusion, gas-like viscosity, and wetting to shale surface, facilitate the effective contact with shale surface and adsorption sites and thus improve competitive adsorption to CH4 [32, 100].Table 2
Physical properties and molecular parameters of CO2 and CH4 [104].
PropertyCO2CH4ReferenceMolecular mass,m (g/mol)4416—Critical temperature,Tc (K)304.2190.5[74, 75]Critical pressure,Pc (MPa)7.44.6[74, 75]Critical density,ρc (kg/m3)467.6162.7[105]Adsorbed phase density,ρa (kg/m3)1028372[74, 75]Molar polarizability,αM (cm3/mol)7.346.54[106, 107]Kinetic diameter,σk (Ao)3.303.80[74, 75, 96]Collision diameter,σcol (Ao)4.003.82[96]Effective molecule diameter,σeff=σk⋅σcol (Ao)3.633.81[96]Molecular simulation is a good method to investigate adsorption mechanisms from the view of molecular motion and reaction. Recently, some grand canonical Monte Carlo (GCMC) simulations [20, 70, 101–103], one typical molecular simulation method for adsorption, were conducted to explore the mechanism of CO2/CH4 competitive adsorption. Huang et al. [20, 70] studied the competitive adsorption behavior of CO2/CH4 in dry and moist realistic kerogen models of different organic types. The simulation results showed that the CO2/CH4 adsorption selectivity increases with increasing CO2 concentration at low pressure for kerogen models of higher maturity but decreases with CO2 mole fraction for lower mature kerogen models. Specifically, CO2/CH4 adsorption selectivity increases with the enterable pore volume fraction in the immature organic type. The CO2/CH4 adsorption selectivity decreases first and then increases with the moisture content while the adsorption of CO2 is more sensitive with moisture than that of CH4. However, moisture can potentially boost the displacement of CH4 by CO2 at certain conditions. Zhou et al. [101–103] also conducted a series of molecular simulations on CO2 and CH4 adsorption for enhanced shale gas recovery and explore the effect of moisture and brine (salinity). Zhou et al. [102] explored the shale gas recovery mechanisms of CO2 injection in kerogen slit pores and analyzed the effect of moisture. CH4 adsorption capacity in the CO2-CH4 mixture decreases with increasing moisture due to the accumulated H2O clusters impeding the pore filling of CH4 in the kerogen slit pores. Compared to pressure drawdown, CO2 injection can release CH4 molecules in the adsorption layer; the CH4 recovery ratio of CO2 injection increases with the increasing moisture. Zhou et al. [103] found that the total uptake of CH4 and CO2, including adsorption in kerogen surfaces and dissolution at kerogen/water interface and in water/brine, decreases linearly with increasing salinity. Salinity effects on CO2 uptake are proved as complicated. The CO2 adsorption decreases due to the pore volume in kerogen surfaces occupied by brine, but the remarkable enhancement in CO2 solubility in brine is observed. Moreover, the wettability of kerogen surface is transformed from a partially water-wetting into a less water-wetting interface caused by the existence of CO2 adsorption, though this effect is inhibited by salinity.The competitive adsorption mechanism is fundamentally revealed, but how to accurately quantify the competitive adsorption and evaluate the adsorption ratio of CO2/CH4 is not very clear, especially under the condition of mixture. More related experiments and models study should be conducted.


## 3.1. Experimental Study on CO2/CH4 Competitive Adsorption

The competitive adsorption characteristics of CO2 to CH4 were initially investigated by comparative analysis of the adsorption behavior between single-component gas of CO2 and CH4. Nuttall et al. [44] first observed that the adsorption capacity of pure CO2 is approximately 5 times greater than that of CH4 in Devonian black shales at the same conditions. The adsorption capacity of pure CO2 was also reported consistently higher than that of CH4 in various kinds of shale by many following research [16, 26, 29, 40, 41, 80–84]. Klewiah et al. [32] summarized some related adsorption experiments of single-component gas of CO2 and CH4, reported the CO2/CH4 adsorption ratio in the range of 1.3-10 for dry shale, and revealed moisture weakening the CO2/CH4 adsorption ratio. Similar to CH4, the increase in pressure and organic carbon content contributes to adsorption capacity of CO2 in shale, while the temperature is the opposite. Compared to CH4, the desorption process of CO2 has an obvious hysteresis effect, which is conducive to long-term CO2 storage [83, 85]. The moisture, matrix expansion, and pore throat size may affect the hysteresis of CO2 desorption behavior, but the mechanism of CO2 desorption hysteresis has not been thoroughly revealed [86, 87].The adsorption experiments of CO2-CH4 mixture system [42, 88–92] show that the greater adsorption affinity exists for CO2 in shales than CH4 even though sometimes CH4 is preferentially adsorbed in the adsorption experiment of CO2-CH4 mixture. It is revealed that CO2 has a higher adsorption capacity in the coexistence of CO2 and CH4, proving that competitive adsorption is beneficial to the implementation of CO2-ESGR. However, Qi et al. [91] confirmed that the adsorption characteristics are not only related to adsorption affinity but also affected by the partial pressure of the components in the mixture system, and the competitive adsorption ratio of CO2/CH4 in the mixture system may be smaller than that under condition of single-component adsorption. Thus, more experiments of CO2-CH4 mixture adsorption/desorption are needed for competitive adsorption characteristics and mechanism.Except the competitive adsorption of static gas adsorption experiments of single-component gas and CO2-CH4 mixture system, several researchers carried out dynamic competitive adsorption experiment on CO2-CH4 exchange characteristics [93–95]. The competitive adsorption ratio and enhanced recovery of shale gas by injection of CO2 were also proved by these dynamic experiments.


## 3.2. Mechanism of CO2/CH4 Competitive Adsorption

As for the mechanism of competitive adsorption between CO2 and CH4 in shale, the competition for adsorption sites plays a key role on CO2 replacing CH4. Specifically, molecular size of gas, interaction energy (thermodynamic forces) between gas and shale matrix, and accessibility of gas into the shale microporous network (steric forces) are considered as the important controlling factors of competitive adsorption between CO2 and CH4 [32]. The molecular characteristic difference between CO2 and CH4 is crucial: CH4 molecule is tetrahedral geometry with a relative larger kinetic diameter of 3.80 Ao, and CO2 molecule is linear molecular with a smaller kinetic diameter of 3.30 Ao [26, 74, 75, 96], shown in Table 2. Due to the smaller molecular size, CO2 can easily access into micro/nano-scale pores with smaller diameter which may be difficult for CH4, and thus, CO2 is favourable to contact larger surface and adsorption sites in shale matrix [32, 97]. Moreover, CO2 can interact more strongly with functional groups in kerogen because of higher quadrupole moment, and thus, CO2 is more prone to physical adsorption caused by van der Waals force than CH4 [26, 98, 99]. Zhao and Wang [95] revealed that the surface of shale organic matter has a stronger affinity for CO2 than CH4, and then, CO2 competes for adsorption sites to replace the adsorbed CH4 on the surface of the matrix. The higher critical temperature of CO2 also favour the competitive adsorption to replace CH4 [97]. As an endothermic reaction, desorption process of CH4 needs a relative lower of the adsorption heat than that of CO2, and thus, desorption of CH4 from shale can be more easily realized in the coexisting CO2 adsorption process. The unique supercritical properties of CO2, such as liquid-like density, gas-like diffusion, gas-like viscosity, and wetting to shale surface, facilitate the effective contact with shale surface and adsorption sites and thus improve competitive adsorption to CH4 [32, 100].Table 2
Physical properties and molecular parameters of CO2 and CH4 [104].
PropertyCO2CH4ReferenceMolecular mass,m (g/mol)4416—Critical temperature,Tc (K)304.2190.5[74, 75]Critical pressure,Pc (MPa)7.44.6[74, 75]Critical density,ρc (kg/m3)467.6162.7[105]Adsorbed phase density,ρa (kg/m3)1028372[74, 75]Molar polarizability,αM (cm3/mol)7.346.54[106, 107]Kinetic diameter,σk (Ao)3.303.80[74, 75, 96]Collision diameter,σcol (Ao)4.003.82[96]Effective molecule diameter,σeff=σk⋅σcol (Ao)3.633.81[96]Molecular simulation is a good method to investigate adsorption mechanisms from the view of molecular motion and reaction. Recently, some grand canonical Monte Carlo (GCMC) simulations [20, 70, 101–103], one typical molecular simulation method for adsorption, were conducted to explore the mechanism of CO2/CH4 competitive adsorption. Huang et al. [20, 70] studied the competitive adsorption behavior of CO2/CH4 in dry and moist realistic kerogen models of different organic types. The simulation results showed that the CO2/CH4 adsorption selectivity increases with increasing CO2 concentration at low pressure for kerogen models of higher maturity but decreases with CO2 mole fraction for lower mature kerogen models. Specifically, CO2/CH4 adsorption selectivity increases with the enterable pore volume fraction in the immature organic type. The CO2/CH4 adsorption selectivity decreases first and then increases with the moisture content while the adsorption of CO2 is more sensitive with moisture than that of CH4. However, moisture can potentially boost the displacement of CH4 by CO2 at certain conditions. Zhou et al. [101–103] also conducted a series of molecular simulations on CO2 and CH4 adsorption for enhanced shale gas recovery and explore the effect of moisture and brine (salinity). Zhou et al. [102] explored the shale gas recovery mechanisms of CO2 injection in kerogen slit pores and analyzed the effect of moisture. CH4 adsorption capacity in the CO2-CH4 mixture decreases with increasing moisture due to the accumulated H2O clusters impeding the pore filling of CH4 in the kerogen slit pores. Compared to pressure drawdown, CO2 injection can release CH4 molecules in the adsorption layer; the CH4 recovery ratio of CO2 injection increases with the increasing moisture. Zhou et al. [103] found that the total uptake of CH4 and CO2, including adsorption in kerogen surfaces and dissolution at kerogen/water interface and in water/brine, decreases linearly with increasing salinity. Salinity effects on CO2 uptake are proved as complicated. The CO2 adsorption decreases due to the pore volume in kerogen surfaces occupied by brine, but the remarkable enhancement in CO2 solubility in brine is observed. Moreover, the wettability of kerogen surface is transformed from a partially water-wetting into a less water-wetting interface caused by the existence of CO2 adsorption, though this effect is inhibited by salinity.The competitive adsorption mechanism is fundamentally revealed, but how to accurately quantify the competitive adsorption and evaluate the adsorption ratio of CO2/CH4 is not very clear, especially under the condition of mixture. More related experiments and models study should be conducted.


## 4. Displacement of CH4 by CO2 in Shale

### 4.1. Flow Mechanism in Shale

CH4/CO2 adsorption and desorption in shale are coupled with multiscale and multifield flow from shale matrix and fracture network to wellbore in the process of CO2-ESGR [97]. Therefore, the flow and mass transfer process is very complicated and involves different mechanisms. The flow and transport mechanisms in different scales related to CO2-ESGR are shown in Figure 5 [52].Figure 5
Multiscale migration mechanism of gas in shale [52].On the microscopic mechanism, the main interaction of gas flows in porous media is the collisions between gas molecules and the collisions between gas molecules and the walls of pores [108]. Thus, the mean free path of gas molecules and pore scales plays key roles on determination of flow regime in porous media. Knudsen number, Kn, is proposed to differentiate the flow regime in tight porous media. Knudsen number is defined as, Kn=λ¯/rpore, where λ¯ is the mean free path of gas molecules and rpore is the radius of pore in porous media. With the increase of Knudsen number, the collision probability between gas molecules decreases while the collision probability between gas molecules and the pore wall increases. Correspondingly, the flow in micropores is divided into [109] continuum flow (Darcy flow), slip flow, transition flow, and free molecular flow. Simultaneously, the microscopic mass transfer mechanism of shale gas is the viscous flow, Knudsen diffusion, free molecular diffusion (Fick diffusion), and surface diffusion [110]. The relationship between Knudsen number and gas flow regime under different pore scales and the corresponding governing equation are shown in Table 3.Table 3
Characteristics of various flow regime under different Knudsen number [111].
Flow regimeKn rangea,bModelsCommentsContinuum flowKn<0.01Darcy’s equation for laminar flow and Forchheimer’s equation for turbulent flowAssumes immobile fluid at the pore wall, and no permeability correction is generally required.Slip flow0.01<Kn<0.1Darcy’s equation with Klinkenberg’s correction or Knudsen’s correctionKlinkenberg’s correction is generally implemented due to its easiness, and Knudsen’s correction is more accurate.Transition flow0.1<Kn<10Darcy’s law with Knudsen’s correction can be applied. Alternative method is Burnett’s equation with slip boundary conditioncKnudsen’s diffusion equation is a more reliable approach, especially whenKn is closer to 10.Free molecular flowKn>10Knudsen’s diffusion equationd, alternative methods are DSMC and lattice BoltzmanncUsually occurs in shale formations where the pore throat radius is very small.aThis Knudsen number classification is taken from Karniadakis et al. [112]. bSome reference suggests (Kn<0.001) as a cut off for continuum flow [109]. cFor more details, see Agarwal et al. [113]. dKnudsen’s diffusion can coexist with bulk and surface diffusion.For single-component gas flow, Javadpour et al. [114, 115] analyzed the gas flow in shale and micropore structure characteristics of shale and believed that non-Darcy flow occurs in the micropores. The flow regime of this kind of non-Darcy flow should be determined based on the mean free path of gas molecules and Knudsen number. Freeman et al. [116] further pointed out that non-Darcy flow will occur when the pore throat diameter of shale is equivalent to the molecular mean free path length. At this time, there is a strong correlation between permeability and pore pressure. The gas flow is Darcy flow in natural cracks and artificial fractures while it is non-Darcy flow in the shale matrix [117]. Li et al. [118] believed that the gas flow in micropore throats is slip flow and transition flow, and the mass transfer mechanism is mainly the combination of viscous flow and Knudsen diffusion at the temperature of 300-360 K and pressure of 1-100 MPa in shale reservoirs. Knudsen diffusion is negligible, and viscous flow is dominant in cracks larger than 100 nm, which is applicable to Darcy’s law. In shale pores or fractures with a diameter less than 10 nm, molecular free flow comes into play, and surface diffusion is small [119]. Sun et al. [119] further explored the effects of the adsorption/desorption of CH4 in kerogen organic matter, the pore volume occupied by the adsorption layer, and the surface diffusion of the adsorption layer on the gas flow and mass transfer. Song et al. [120] combined non-Darcy flow (including Knudsen diffusion, gas adsorption, and surface diffusion) with the influence of critical pore space under real gas temperature and pressure conditions to study the gas migration mechanism.


### 4.2. Displacement Experiments of CO2-CH4

As for the process of CO2 displacing CH4 in shale, the gas flow and mass transfer are more complicated than single-component gas flow. Different from CH4 flow in shale, the competitive adsorption of CO2/CH4 and convective dispersion occur in the miscible displacement in the fracture-matrix dual media of fractured shales. The mass transfer characteristics of miscible displacement of CO2-CH4 in porous media under multifield coupling play the crucial role in CO2-ESGR. As an important physical property describing the degree of mixing of two phases in the porous media, the dispersion characteristics in the displacement of CO2-CH4 are one of the convective mass transfer characteristics that researchers focus on.The early studies on the displacement properties and dispersion characteristics of CO2-CH4 in porous media were mainly carried out for the CO2 enhanced gas recovery (CO2-EGR) in conventional natural gas reservoirs. Mamora and Seo [121] and Liu et al. [122] verified the technical feasibility of CO2-EGR by visualization CT experiments of CO2-CH4 displacement. Honari et al. [123] and Zhang et al. [124] proposed that residual water would delay the flow migration by blocking the pore pathway, causing the tailing of CO2 breakthrough curve and non-Fick phenomenon in CO2-CH4 displacement. However, the seepage mass transfer mechanism in the conventional natural gas reservoirs is different from that in shale reservoir due to the higher porosity and permeability.Compared to the conventional natural gas reservoirs, the seepage mass transfer characteristics in coalbed methane reservoirs are closer to that in shale reservoirs due to their similar geological attributes. Aiming at CO2 enhanced coalbed methane recovery (CO2-ECBM), Shi et al. [125] combined the extended Langmuir model and Fick’s law to explore the displacement properties of CO2-CH4 in the coal and analyzed the dynamic competitive desorption characteristics. Some studies also confirmed that the replacing efficiency of CH4 was enhanced by CO2 due to competitive adsorption effect with comparing N2 displacement experiments [126, 127]. It is also verified in the displacement experiments that the moisture can prevent the CO2 binding to adsorption sites and then affecting the displacement efficiency [128].There are relatively few studies on the displacement study of CO2-CH4 and the dynamic competitive adsorption in shale related to CO2-ESGR. Du et al. [129–131] conducted a series of CO2-CH4 displacement experiments in the crushed shale pack for the displacement properties and dispersion characteristics. Du et al. [129] first analyzed the CH4 recovery efficiency and CO2 storage efficiency in displacement experiments. The experimental results showed that CO2 has a larger dynamic adsorption rate and adsorption capacity, which ensures the feasibility of CO2-ESGR. It is also found that the competitive adsorption between CO2 and CH4 will cause fluctuations in pore pressure, which in turn will enhance dispersion and produce a wider range of CO2-CH4 mixed phase regions. Du et al. [130] further explored the influence of CO2 injection pressure on the dispersion characteristics in CO2-CH4 displacement experiment. Based on the convective dispersion theory, it is found that CO2 diffusion is dominant under the condition of lower CO2 injection pressure, and the mass transfer coefficient and the miscible area increase with the increasing injection pressure, while the competitive adsorption between CO2 and CH4 is becoming obvious. The comparison of CO2, N2, and CO2/N2 mixtures was also conducted; a higher CH4 recovery existed in CO2 displacement than that in N2 displacement [131]. The displacement efficient of CH4 by CO2 was also compared with N2 in simulation, and it is verified that competitive adsorption leads to a larger recovery for CO2 displacing shale gas [132].


## 4.1. Flow Mechanism in Shale

CH4/CO2 adsorption and desorption in shale are coupled with multiscale and multifield flow from shale matrix and fracture network to wellbore in the process of CO2-ESGR [97]. Therefore, the flow and mass transfer process is very complicated and involves different mechanisms. The flow and transport mechanisms in different scales related to CO2-ESGR are shown in Figure 5 [52].Figure 5
Multiscale migration mechanism of gas in shale [52].On the microscopic mechanism, the main interaction of gas flows in porous media is the collisions between gas molecules and the collisions between gas molecules and the walls of pores [108]. Thus, the mean free path of gas molecules and pore scales plays key roles on determination of flow regime in porous media. Knudsen number, Kn, is proposed to differentiate the flow regime in tight porous media. Knudsen number is defined as, Kn=λ¯/rpore, where λ¯ is the mean free path of gas molecules and rpore is the radius of pore in porous media. With the increase of Knudsen number, the collision probability between gas molecules decreases while the collision probability between gas molecules and the pore wall increases. Correspondingly, the flow in micropores is divided into [109] continuum flow (Darcy flow), slip flow, transition flow, and free molecular flow. Simultaneously, the microscopic mass transfer mechanism of shale gas is the viscous flow, Knudsen diffusion, free molecular diffusion (Fick diffusion), and surface diffusion [110]. The relationship between Knudsen number and gas flow regime under different pore scales and the corresponding governing equation are shown in Table 3.Table 3
Characteristics of various flow regime under different Knudsen number [111].
Flow regimeKn rangea,bModelsCommentsContinuum flowKn<0.01Darcy’s equation for laminar flow and Forchheimer’s equation for turbulent flowAssumes immobile fluid at the pore wall, and no permeability correction is generally required.Slip flow0.01<Kn<0.1Darcy’s equation with Klinkenberg’s correction or Knudsen’s correctionKlinkenberg’s correction is generally implemented due to its easiness, and Knudsen’s correction is more accurate.Transition flow0.1<Kn<10Darcy’s law with Knudsen’s correction can be applied. Alternative method is Burnett’s equation with slip boundary conditioncKnudsen’s diffusion equation is a more reliable approach, especially whenKn is closer to 10.Free molecular flowKn>10Knudsen’s diffusion equationd, alternative methods are DSMC and lattice BoltzmanncUsually occurs in shale formations where the pore throat radius is very small.aThis Knudsen number classification is taken from Karniadakis et al. [112]. bSome reference suggests (Kn<0.001) as a cut off for continuum flow [109]. cFor more details, see Agarwal et al. [113]. dKnudsen’s diffusion can coexist with bulk and surface diffusion.For single-component gas flow, Javadpour et al. [114, 115] analyzed the gas flow in shale and micropore structure characteristics of shale and believed that non-Darcy flow occurs in the micropores. The flow regime of this kind of non-Darcy flow should be determined based on the mean free path of gas molecules and Knudsen number. Freeman et al. [116] further pointed out that non-Darcy flow will occur when the pore throat diameter of shale is equivalent to the molecular mean free path length. At this time, there is a strong correlation between permeability and pore pressure. The gas flow is Darcy flow in natural cracks and artificial fractures while it is non-Darcy flow in the shale matrix [117]. Li et al. [118] believed that the gas flow in micropore throats is slip flow and transition flow, and the mass transfer mechanism is mainly the combination of viscous flow and Knudsen diffusion at the temperature of 300-360 K and pressure of 1-100 MPa in shale reservoirs. Knudsen diffusion is negligible, and viscous flow is dominant in cracks larger than 100 nm, which is applicable to Darcy’s law. In shale pores or fractures with a diameter less than 10 nm, molecular free flow comes into play, and surface diffusion is small [119]. Sun et al. [119] further explored the effects of the adsorption/desorption of CH4 in kerogen organic matter, the pore volume occupied by the adsorption layer, and the surface diffusion of the adsorption layer on the gas flow and mass transfer. Song et al. [120] combined non-Darcy flow (including Knudsen diffusion, gas adsorption, and surface diffusion) with the influence of critical pore space under real gas temperature and pressure conditions to study the gas migration mechanism.


## 4.2. Displacement Experiments of CO2-CH4

As for the process of CO2 displacing CH4 in shale, the gas flow and mass transfer are more complicated than single-component gas flow. Different from CH4 flow in shale, the competitive adsorption of CO2/CH4 and convective dispersion occur in the miscible displacement in the fracture-matrix dual media of fractured shales. The mass transfer characteristics of miscible displacement of CO2-CH4 in porous media under multifield coupling play the crucial role in CO2-ESGR. As an important physical property describing the degree of mixing of two phases in the porous media, the dispersion characteristics in the displacement of CO2-CH4 are one of the convective mass transfer characteristics that researchers focus on.The early studies on the displacement properties and dispersion characteristics of CO2-CH4 in porous media were mainly carried out for the CO2 enhanced gas recovery (CO2-EGR) in conventional natural gas reservoirs. Mamora and Seo [121] and Liu et al. [122] verified the technical feasibility of CO2-EGR by visualization CT experiments of CO2-CH4 displacement. Honari et al. [123] and Zhang et al. [124] proposed that residual water would delay the flow migration by blocking the pore pathway, causing the tailing of CO2 breakthrough curve and non-Fick phenomenon in CO2-CH4 displacement. However, the seepage mass transfer mechanism in the conventional natural gas reservoirs is different from that in shale reservoir due to the higher porosity and permeability.Compared to the conventional natural gas reservoirs, the seepage mass transfer characteristics in coalbed methane reservoirs are closer to that in shale reservoirs due to their similar geological attributes. Aiming at CO2 enhanced coalbed methane recovery (CO2-ECBM), Shi et al. [125] combined the extended Langmuir model and Fick’s law to explore the displacement properties of CO2-CH4 in the coal and analyzed the dynamic competitive desorption characteristics. Some studies also confirmed that the replacing efficiency of CH4 was enhanced by CO2 due to competitive adsorption effect with comparing N2 displacement experiments [126, 127]. It is also verified in the displacement experiments that the moisture can prevent the CO2 binding to adsorption sites and then affecting the displacement efficiency [128].There are relatively few studies on the displacement study of CO2-CH4 and the dynamic competitive adsorption in shale related to CO2-ESGR. Du et al. [129–131] conducted a series of CO2-CH4 displacement experiments in the crushed shale pack for the displacement properties and dispersion characteristics. Du et al. [129] first analyzed the CH4 recovery efficiency and CO2 storage efficiency in displacement experiments. The experimental results showed that CO2 has a larger dynamic adsorption rate and adsorption capacity, which ensures the feasibility of CO2-ESGR. It is also found that the competitive adsorption between CO2 and CH4 will cause fluctuations in pore pressure, which in turn will enhance dispersion and produce a wider range of CO2-CH4 mixed phase regions. Du et al. [130] further explored the influence of CO2 injection pressure on the dispersion characteristics in CO2-CH4 displacement experiment. Based on the convective dispersion theory, it is found that CO2 diffusion is dominant under the condition of lower CO2 injection pressure, and the mass transfer coefficient and the miscible area increase with the increasing injection pressure, while the competitive adsorption between CO2 and CH4 is becoming obvious. The comparison of CO2, N2, and CO2/N2 mixtures was also conducted; a higher CH4 recovery existed in CO2 displacement than that in N2 displacement [131]. The displacement efficient of CH4 by CO2 was also compared with N2 in simulation, and it is verified that competitive adsorption leads to a larger recovery for CO2 displacing shale gas [132].


## 5. Challenges and Opportunities

The adsorption/desorption of shale gas, competitive adsorption of CO2 to CH4, and flow mechanism play the key role on shale gas reservoir exploitation. To our knowledge, some challenges and opportunities on these research topics are arising in the process of CO2-ESGR.A lot of experimental and modelling studies on adsorption/desorption have been conducted in crushed shale samples, especially for CH4, and the adsorption mechanism of CH4 is fundamentally revealed. Due to some shale reservoirs are in deep formation, it is necessary to ascertain the gas adsorption mechanism under high temperature and high pressure. However, the gas adsorption experiments in intact shale cores under field condition are still scarce, and more relevant adsorption studies need to be carried out. Correspondingly, accurate supercritical adsorption models also need to be developed for enriching the comprehensive knowledge of gas adsorption mechanism in shale. Compared to CH4, CO2 has different physical properties and different adsorption behaviors, especially in the supercritical. The adsorption mechanism of CO2 is not fully revealed, especially under supercritical state, and thus, more experiments and models research on CO2 adsorption/desorption are urgently needed.The competitive adsorption of CO2 to CH4 is basically proved by a lot of comparative adsorption experiments of pure gas composition and some adsorption studies of CO2-CH4 mixtures in shale. However, the competitive adsorption has different behavior in the adsorption experiments of single-component gas and CO2-CH4 mixture system. To quantitatively evaluate the competitive adsorption, adsorption ratio of CO2/CH4 also shows different for the experiment of single-component gas and mixtures. The CO2-CH4 mixture adsorption is more close to realistic situation, but the related mixture adsorption experiments are in scarcity, especially under the field conditions. Notably, more dynamic competitive adsorption experiments are not adequate for revealing the dynamic exchange mechanism of CO2-CH4. Considering the different properties between CO2 and CH4, the competitive adsorption mechanism is qualitatively analyzed. However, how to accurately predict the adsorption CO2 or CH4 component in CO2-CH4 mixture system and quantify the competitive adsorption are still the important unsolved problems. Maybe, the future work should pay attention on establishment of quantification model on competitive adsorption of CO2 to CH4 in shale.The knowledge of flow mechanism in on certain flow regime has been relatively well developed and understood. The shale gas flows through pathway in different sizes of microscale/nano-scale pores and fractures in shale during the exploitation of shale gas reservoir. Thus, different flow regime is coexisted on this condition. The coupling of flow in different flow regime is one of the key controlling factors for accurately predicting shale gas transport, which has not been fully understood and needs thorough study. Concerning CO2-ESGR, the injection of CO2 makes the flow and gas transport more complicated. The mechanism of competitive adsorption of CO2 to CH4 coupled with flow and CO2-CH4 dispersion is not fully ascertained. CO2-CH4 dynamic displacement studies are scarce for comprehensive analysis of the coupling of competitive adsorption with various gas flow regime. In the opinion of this work, future studies may should concern the dynamic competitive coupling with different flow regime in aspects of experiments and models in the miscible displacement of CO2-CH4 for CO2-ESGR.


## 6. Conclusions

Due to both the environmental effect of CO2 geological storage and economic effect of shale gas exploitation, CO2 enhanced shale gas recovery (CO2-ESGR) draws worldwide concerns in recent years. This work summarizes the existing knowledge on the mechanism of single-component gas adsorption, competitive adsorption, and displacement of CO2-CH4 in shale related to CO2-ESGR. The advances of experimental and model studies on these research topics are reviewed. Some conclusions are drawn as follows:
(i)
As unconventional gas resources, shale gas is an important clean fuel with large reserves worldwide. CO2 enhanced shale gas recovery has great potential to exploit shale gas reservoirs with permanently storing CO2 into underground formation(ii)
Generally, gas absorption in shale is two types of physical adsorption: monolayer adsorption at low pressure and multilayer adsorption at high pressure. Gas adsorption capacity shows positive relationship with TOC, thermal maturity, and clay content of shale and negative with moisture(iii)
Adsorption capacity of CO2 in shale is much larger than that of CH4 even with the coexistence of CO2-CH4 mixture. Due to the unique properties of CO2, shale matrix shows a stronger affinity with CO2, and CO2 can be more easily adsorbed on the inner surface of shale matrix than CH4(iv)
Four types of flow regime exist in the gas flow related to shale gas exploitation. Generally, it is Darcy flow for shale gas flow in natural cracks and artificial fractures larger than 100 nm, slip flow and transition flow for gas flow in shale micropore throats in 10~100 nm, and free molecular flow for gas flow in micro/nano-scale pores and cracks(v)
Compared to single-component gas flow in shale, displacement flow of CO2-CH4 is very complicated with mass transfer between two gases. Dynamic studies on displacement of CO2-CH4 in shale prove that CH4 recovery is significantly enhanced due to the competitive adsorption(vi)
To our knowledge, some challenges and opportunities in these research topics are also proposed(vii)
More experiment adsorption study in intact shale cores under field condition for supercritical CH4 and CO2 is scarce, and the corresponding accurate supercritical adsorption model is urgently needed for revealing gas adsorption mechanism in shale(viii)
To ascertain competitive adsorption mechanism, more CO2-CH4 adsorption experiments under field conditions, especially dynamic experiments, should be conducted to determine the CO2/CH4 adsorption ratio. Corresponding, establishment of quantification model on competitive adsorption of CO2 to CH4 in shale should draw attentions in the future work(ix)
Dynamic competitive adsorption coupling with flow in the displacement of CO2-CH4 plays the key role on CO2-ESGR but is not fully understood. The future work should look into the coupling of various flow regime, competitive adsorption of CO2-CH4, convection dispersion, etc



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*Source: 6657995-2020-12-23.xml*