CO₂, N₂, and CO₂/N₂ mixed gas injection for enhanced shale gas recovery and CO₂ geological storage

Abstract

In this work, using fractured shale cores, isothermal adsorption experiments and core flooding tests were conducted to investigate the performance of injecting different gases to enhance shale gas recovery and CO₂ geological storage efficiency under real reservoir conditions. The adsorption process of shale to different gases was in agreement with the extended-Langmuir model, and the adsorption capacity of CO₂ was the largest, followed by CH_4, and that of N₂ was the smallest of the three pure gases. In addition, when the CO₂ concentration in the mixed gas exceeded 50%, the adsorption capacity of the mixed gas was greater than that of CH₄, and had a strong competitive adsorption effect. For the core flooding tests, pure gas injection showed that the breakthrough time of CO₂ was longer than that of N₂, and the CH₄ recovery factor at the breakthrough time () was also higher than that of N₂. The of CO₂ gas injection was approximately 44.09%, while the of N₂ was only 31.63%. For CO₂/N₂ mixed gas injection, with the increase of CO₂ concentration, the increased, and the for mixed gas CO₂/N₂ = 8:2 was close to that of pure CO₂, about 40.24%. Moreover, the breakthrough time of N₂ in mixed gas was not much different from that when pure N₂ was injected, while the breakthrough time of CO₂ was prolonged, which indicated that with the increase of N₂ concentration in the mixed gas, the breakthrough time of CO₂ could be extended. Furthermore, an abnormal surge of N₂ concentration in the produced gas was observed after N₂ breakthrough. In regards to CO₂ storage efficiency (), as the CO₂ concentration increased, also increased. The of the pure CO₂ gas injection was about 35.96%, while for mixed gas CO₂/N₂ = 8:2, was about 32.28%.

Graphical abstract

Keywords

shale gas / gas injection / competitive adsorption / enhanced shale gas recovery / CO₂ geological storage

1 Introduction

An increasing number of shale gas reserves are being discovered and the development of shale gas reserves in effective and sustainable approaches is extremely important under the background of a growing energy demand. The United States Energy Information Administration (EIA) report indicated that, as of 2015, the total reserve of shale gas worldwide was 457 trillion cubic meters (TCM), of which the technically recoverable shale gas was 187.40 TCM, which was close to the recoverable reserves of conventional natural gas (187.03 TCM) [1]. Benefiting from advanced technology, shale gas production in many countries such as the US, Canada, and China have been significantly increased in the last few years. However, due to the fact that shale gas is mainly distributed in organic-rich mud shale formations, the reservoirs generally have the geological characteristics of low porosity and low permeability. Therefore, the production efficiency of conventional methods is extremely low and the development cost is high [2,3]. The recovery factor of shale gas is only 20%–40% [4,5], which is really low, compared with that of conventional natural gas (60%–90%). Therefore, it is necessary to develop technologies to enhance shale gas recovery.

To effectively exploit shale gas, it is necessary to fracture shale reservoirs in advance [6,7]. After fracturing, shale reservoirs are generally exploited first using the direct depressurization method. The extracted shale gas mainly comes from three parts, free CH₄ in shale fractures, free CH₄ in the shale pore network, and adsorbed CH₄ in shale matrix. At the initial stage of exploitation, the gas flowing out of production wells mainly comes from free CH₄ in fractures, at which time the gas production rate is extremely high. With the depletion of free CH₄ in fractures, the free CH₄ in the shale pore network and the desorbed CH₄ in shale matrix become the key step of shale gas development. However, because the adsorption process of CH₄ on shale is in agreement with the Langmuir model [8], a large amount of adsorbed CH₄ could be desorbed only when the reservoir pressure drops to a low level, while maintaining high reservoir pressure is an indispensable condition for keeping the fluid flow in shale reservoirs [9]. Therefore, the direct depressurization method not only significantly reduces the production rate in the later stage of exploitation, but also limits the overall recovery factor of shale gas [10]. The CO₂-enhanced shale gas recovery (CO₂-ESGR) technology can effectively solve the above problems. On the one hand, while maintaining the shale reservoir pressure, the injected CO₂ can reduce the partial pressure of CH₄ in the reservoir and promote the rapid desorption of adsorbed CH₄. On the other hand, the injected gas can also effectively replace the adsorbed CH₄ in matrix pores. There have been many successful precedents and studies on the injecting of CO₂ into oil and gas reservoirs to enhance recovery factor. In 1996, the US took the lead in conducting the field test of CO₂-enhanced coalbed methane (CO₂-ECBM) technology in the Burlington Allison of San Juan Basin, and achieved good results [11–13]. In addition, through cooperation between the Canadian and Chinese governments, a single-well field test of CO₂-ECBM was studied in the Qinshui Basin of Shanxi, China [14]. The results show that CO₂-ECBM technology cannot only improve the recovery factor of coalbed methane, but also store the injected CO₂. Moreover, some researchers found that both coalbed and shale gas reservoirs had nanopore structures, and the gas reservoirs had similar accumulation conditions, gas composition, and gas properties [15–17]. Related research on coalbed extraction has laid the foundation for the efficient development of shale gas. Furthermore, the CO₂ gas injection technology has also been widely used for enhanced oil recovery (CO₂-EOR) of light oil [18–20], heavy oil [21–23], and tight oil reservoirs [24–26]. The results of existing studies demonstrate that most CO₂-EOR projects have achieved ideal effects, which effectively enhanced the recovery factor of oil reservoirs while storing a large amount of CO₂. Therefore, based on the CO₂-ECBM and CO₂-EOR technologies, it is feasible to inject CO₂ into shale reservoirs to enhance the recovery and storage of CO₂. The CO₂-ESGR technology has broad application prospects. Especially in recent years, with the increasingly serious greenhouse effect and environmental problems, CO₂-ESGR technology has gained great interest all over the world, and the related research has become a hot spot in the field of shale gas development.

At present, research on CO₂-ESGR technology mainly includes two aspects: mechanism analysis and influencing factors. The main mechanism of CO₂-ESGR is the competitive adsorption process between adsorbed CH₄ and injected CO₂ [27–29]. Many researchers have studied the mechanism of CO₂-ESGR by directly studying the adsorption capability of CO₂/CH₄ mixture gases on shale matrix, or by comparing the adsorption characteristics of pure CO₂ or CH₄ on shale matrix and calculating the selectivity coefficient according to the adsorption data. Duan et al. [30] and Sun et al. [31] determined the adsorption capacity of CO₂/CH₄ mixture gases on shale matrix by adopting the gravimetric method and the molecular dynamics method, respectively. The results suggest that CO₂ is in a dominant position in the adsorption process, and the adsorption amount of CO₂ in the mixture gases is greater than the adsorption capacity of CH₄. Zhu et al. [32] and Wang et al. [33] analyzed the adsorption characteristics of pure CO₂ and CH₄ on a shale matrix by utilizing experimental and simulation methods, respectively. The research results also indicate that the adsorption capability of pure CO₂ on shale is larger than that of pure CH₄, and the selectivity coefficient of pure CO₂ and CH₄ on shale is inversely proportional to temperature and pressure. This indicates that CO₂ has the ability to displace CH₄ molecules, and it is more favorable for CO₂ to displace adsorbed CH₄ at a low pressure. In addition, the performance of CO₂-ESGR is also affected by many factors, such as reservoir conditions (temperature and pressure), shale matrix structure (fracturing or nonfracturing), and injection fluid characteristics and conditions (composition, rate, and phase state). Huo et al. [34] took shale powder at a mesh number of 50–80 as the research object, and conducted a CO₂ displacement CH₄ experiment under normal temperature and pressure conditions. The results show that the increasing injection pressure is beneficial for enhancing the recovery factor of low porosity shale reservoirs. Du et al. [35] also used shale powder to perform a displacement experiment of gas injection by using CO₂/N₂ mixed gas as the injection medium. The results show that N₂ in the mixed gas has the effect of preventing premature breakthrough of CO₂, prolonging the retention of CO₂ in shale reservoirs, and further enhancing the recovery factor of CH₄. In addition, N₂ injection can also effectively reduce the partial pressure of CH₄ in the target reservoir, further promoting the desorption of adsorbed CH₄ in shale matrix pores. Sim et al. [36] and Sims et al. [37] carried out similar experiments and attributed the mechanism of N₂-ESGR to the ability to rapidly advance in shale reservoirs, thus increasing production in a short time. Zhang and Cao [38] conducted a sensitivity analysis using a shale analysis model verified by experiments, and found a positive correlation between the shale pores and the amount of CH₄ desorption and the amount of CO₂ adsorbed. According to the above analysis, the existing studies on CO₂-ESGR mainly take the crushed shale powder as the research object, and the experimental conditions are low/normal temperature and pressure, which is significantly different from the high temperature and pressure exploitation conditions of actual fractured shale reservoirs. Moreover, the gas injection fluid in the previous CO₂-ESGR experiment was mainly pure CO₂, and few studies have been conducted using other gases or mixed gases. Furthermore, the storage efficiency after CO₂ injection into shale reservoirs also needs further analysis and research.

In view of this, taking the fractured shale core as the research object, a high temperature and pressure isothermal adsorption apparatus and a self-designed core displacement device were used to study gas injection for enhanced shale gas recovery. In the isothermal adsorption experiment, the competitive adsorption mechanism of gas injection for enhanced shale gas recovery was analyzed, while in the shale core displacement experiment, the effects of the gas injection medium (CO₂, N₂, and CO₂/N₂ mixed gas) on enhancing the shale gas recovery factor were studied. Afterwards, based on the material balance theory, the storage efficiency of CO₂ in different gas injection schemes was calculated and obtained. This work is the first of its kind to inject mixed gas with different concentrations to enhance shale gas recovery by modeling real reservoir conditions (fractured shale under high temperature and pressure conditions), which provides an approach to optimize enhanced shale gas recovery through gas injection.

2 Experimental designs

2.1 Experimental material characterization and preparation

The core samples used in this study were from the shale reservoirs of the Longmaxi Formation in the Sichuan Basin, China. The depth of shale sample collection was between 3400 and 3569 m. The average total organic carbon (TOC) was 2.51 wt.%. The average porosity was 3.5% by helium intrusion measurement, and the gas permeability was 0.5 md. The shale samples for the experiments had a diameter of 2.54 cm, a length of 10.00 cm and an average dry weight of 255.45 g. The shale samples are shown in Fig.1.

Before starting the experiment, the shale samples were pretreated by a core crushing and cutting machine. The shale samples of the isothermal adsorption experiment were crushed by a crusher, whose powder was screened out at a particle size of 0.18–0.425 mm by a sieve. Then, the shale powder was dried in an oven at 110 °C for 24 h. The shale samples of the isothermal adsorption experiment after pretreatment are shown in Fig.2. According to the research results of Refs. [39–42], fracturing is required before shale reservoir development to improve the porosity and permeability of the shale matrix. Therefore, to meet the actual development conditions and simulate fracturing fractures of shale reservoirs, the high temperature and pressure shale displacement experimental samples were pretreated by a cutting machine. The core samples of the shale displacement experiment after pretreatment are displayed in Fig.3. The shale samples were separated into two equal parts along the horizontal direction, and then separated into 10 equal parts along the vertical direction. To prevent gas channeling due to fracture penetration during the shale displacement experiment, the last core column (Part 10) was not penetrated in the horizontal direction. The shale samples after cutting were also dried in an oven at 110 °C for 24 h. In addition, the experimental gases used in this study included methane (CH₄), carbon dioxide (CO₂), nitrogen (N₂) and helium (He) which were provided by Regina Gas Company, Ltd., SK, Canada, and the gas purity was greater than 99.9%.

2.2 Experimental setup and method

The experiment was conducted in two parts. First, the adsorption capacity of different gases on shale samples was tested to determine the maximum adsorption capacity and the critical pressure. Then, based on the actual reservoir high temperature and pressure conditions and the results of the adsorption experiment, the experimental temperature and pressure conditions were determined to conduct the shale displacement experiment. Finally, by changing the gas injection medium, the effect of different gases on enhanced shale gas recovery was compared and analyzed.

2.2.1 Isotherm adsorption experiment

The adsorption process is often determined by an isotherm, which indicates the amount gas adsorption versus gas pressure at a given temperature [43]. The adsorption capacities of CH₄, CO₂, N₂, and CO₂/N₂ mixed gas on shale samples were measured by using an automatic ultrahigh-pressure gas adsorption instrument (BSD-PHX, Beishide Instrument Technology (Beijing) Co., Ltd. (China)). The setup of the adsorption experiment is exhibited in Fig.4. The device is based on the isothermal adsorption volumetric method, and its test pressure ranges from high vacuum to 70 MPa, and the temperature ranges from –198 to 85 °C.

To compare and analyze the adsorption capability of different gases on shale samples and provide guidance for subsequent shale displacement experiments, six groups of parallel experiments were designed. The specific design is listed in Tab.1. The tested temperature was the actual reservoir temperature (80 °C), and the pressure range was from 0 to 50 MPa. Before the adsorption experiment, the samples were dried at 105 °C for 120 min. After being removed and placed in a drying box to cool to room temperature, they were weighted with an analytical balance (±0.0001 g). Then, the shale samples were loaded into the sample cylinder, and the experimental system was adjusted to the pre-designed temperature (80 °C). Next, the experimental system was checked for air tightness and the void volume was measured using He gas. Afterwards, the experimental system was evacuated by a vacuum pump and the isothermal adsorption and desorption tests were started. Finally, data processing and analysis (Eq.(1)) were performed based on the adsorption theory, the parameters of the gas adsorption characteristics were calculated, and the isotherm adsorption curves were drawn.

(1)A_{\text{ads}}=\frac{k_a\cdot \alpha \cdot b\cdot P}{k_d\cdot \sqrt{2\text{π}MRT}+k_a\cdot \alpha \cdot P}\text{=}\frac{abP}{1+aP}\cdots \left(EL-\text{model}\right),

where A_ads is the adsorption capacity, cm³/g; k_a and k_d are proportionality constants; α is the proportion of molecules that are adsorbed by the surface among all the molecules that collide with the surface, which is 1; b is the adsorption capacity when the adsorbent surface is completely covered, cm³/g; P is the equilibrium pressure, MPa; M is the molecular mass of the gas molecule, g/mol; R is the gas constant, usually taking the value of 8.314 J/(mol·K); and T is temperature, K.

2.2.2 High temperature and pressure shale displacement experiment

Based on the results of shale isotherm adsorption experiments, shale displacement experiments were conducted to improve CH₄ recovery under high temperature and pressure conditions. The device diagram of the shale displacement experiment is depicted in Fig.5, which is composed of a gas injection unit, a shale displacement unit, and a production and gas analysis unit. The gas injection unit comprises a high-pressure cylinder, a gas injection tank, and an ISCO pump which is used to inject high pressure fluid (CH₄, CO₂, N₂, and CO₂/N₂ mixed gas) into the system. The shale displacement unit consists of a confining pressure control (ISCO) pump, a core holder, and an oven. The core holder is equipped with sealant rubber sleeve and deionized water. The rubber sleeve is used to hold shale samples after fracturing, and the deionized water is used as the confining pressure control fluid. The rubber sleeve is 2.54 cm inner diameter and 38.0 cm in length. Therefore, two core columns after fracturing are selected for filling, and the remaining space is filled with several metal spacers. The actual experimental system and the internal rubber sleeve of the core holder are presented in Fig.6. The gas production and analysis unit includes a back pressure regulator (BPR) controller, an ISCO pump, a gas collection tank, and a gas chromatograph-mass spectrometer (GC-MS 6990). The BPR is used to control the output flow, and the GC-MS is used to analyze the production gas composition.

The scheme design of the high temperature and pressure shale displacement experiment is given in Tab.2.

The shale displacement experiment at a high temperature and pressure includes the following main procedures:

(1) Experimental platform construction. The pipelines, valves, and instruments were connected according to the experimental design scheme. The pipelines and valves used in the experiment were all high-temperature and pressure accessories. The experimental platform after construction is shown in Fig.6.

(2) Leaking test. After the experimental platform was constructed, the experimental system was vacuumized for 4 h. After injecting the He gas into the experimental system, the inlet and outlet valves were closed, and leaking test was performed after the system pressure was stabilized at (15 ±0.1) MPa.

(3) Porosity measurement. The whole system was vacuumed for 5 h until the vacuum pressure was stable. Then, the porosity test of shale samples was carried out using the gas measurement method.

(4) CH₄ pre-adsorption. First, after the porosity test, the experiment system was vacuumed for 4 h. Then, the oven temperature was raised to 80 °C. Finally, according to the experimental results of isothermal adsorption of CH₄ on shale, the CH₄ in the gas injection tank was injected into the core sleeve, and the system pressure was stabilized at (30 ± 0.1) MPa for 24 h by the ISCO pump.

(5) Shale displacement experiment. After the gas injection medium (CO₂, N₂, CO₂/N₂) was pressurized to the experimental temperature (80 °C) and pressure (30 MPa), the inlet and outlet valves were opened to start the shale displacement experiment. In the displacement experiment, the inlet flow rate was controlled at 0.01 mL/min by the ISCO pump, and the outlet pressure drop was kept at 100 kPa/min by a BPR controller. The gas volume and composition produced were obtained by a gas collection tank and a GC-MS, respectively. When the molar concentration of CH₄ decreased to 5.0%, the experiment was terminated. After the experiment, the experimental system was evacuated again with a vacuum pump, the gas injection medium was replaced, and the experiment was repeated.

3 Results and discussion

3.1 Isothermal adsorption experiments

3.1.1 Single component gas adsorption experiment

The isotherm adsorption results of different gases on shale samples are shown in Fig.7, and the measured results are the absolute adsorption amount. It can be seen from Fig.7(a) that the adsorption experimental data of the three adsorbed gases on shale have similar trends. As the pressure increases, the adsorption isotherm increases rapidly and then gradually stabilizes. When the difference in the absolute adsorption amount corresponding to the adjacent pressure is less than 1.0%, the adsorbed gas is considered to have reached a saturated state. This indicates that the adsorbed gas will reach a saturated state under certain temperature and pressure conditions, and the pressure at this time is called the equilibrium pressure. To determine the equilibrium pressure of different adsorption gases and to compare the adsorption capacity, the difference in the absolute adsorption amount is shown in Fig.7(b). The equilibrium pressure at which CH₄ reaches the saturated adsorption state is 23.49 MPa, and the absolute adsorption amount at this time is 0.09 mmol/g. The equilibrium pressure of CO₂ is 26.76 MPa, the absolute adsorption amount is 0.15 mmol/g, the equilibrium pressure of N₂ is 20.02 MPa, and the absolute adsorption amount is 0.04 mmol/g. The comparative analysis indicates that the adsorption capability of the three single component gases on shale is CO₂, CH₄, and N₂ in the order from high to low. The results of this experimental study are consistent with those of Refs. [44–47].

3.1.2 CO₂/N₂ mixed gas adsorption experiment

The single component gas adsorption experiments showed that the adsorption capability of CO₂ on shale was much greater than that of CH₄, so injecting CO₂ into the shale reservoir can effectively enhance the recovery factor. The above research results are consistent with the conclusions of coalbeds and sandstone reservoirs in Refs. [36,48–50]. Some studies [51–53] have also shown that although the adsorption capability of pure N₂ is smaller than that of pure CH₄, mixing it with CO₂ could result in better results. However, because the total adsorption amount of the mixture gases was small, it is difficult to analyze the adsorption capacity of a single fluid medium in the mixture gases. Consequently, the mixture gases of this study are analyzed as a whole, and the results are shown in Fig.8. The isothermal adsorption process of CO₂/N₂ mixture gases on shale is similar to the result of single component gas. When the pressure rises, the absolute adsorption amount increases rapidly, and then reaches the adsorption saturation state. The equilibrium pressure at which CO₂/N₂ = 8/2 reaches the saturated adsorption state is 29.35 MPa, and the absolute adsorption amount at this time is 0.14 mmol/g. The equilibrium pressure of CO₂/N₂ = 5/5 is 25.49 MPa, the absolute adsorption amount is 0.11 mmol/g, the equilibrium pressure of CO₂/N₂ = 2/8 is 22.02 MPa, and the absolute adsorption amount is 0.06 mmol/g. The comparative analysis suggests that with the decrease in CO₂ concentration (increase in N₂ concentration) in the mixture gases, the equilibrium pressure and absolute adsorption amount gradually decreases.

3.1.3 Comparison of adsorption capacity for different adsorption gases

The choice of gas injection medium has a significant influence on enhancing the recovery factor of CH₄ in shale reservoirs. The competitive adsorption relationship between different injection media and CH₄ is compared and analyzed. Fig.9(a) shows that the absolute adsorption amount of CH₄ on shale is 0.09 mmol/g. When the CO₂ concentration in the mixture gases exceeds 50%, the adsorption capability of the mixture gases is much higher than that of CH₄. This shows that pure CO₂, CO₂/N₂ = 8/2, and CO₂/N₂ = 5/5 have a better competitive adsorption capacity than CH_4. As a result, the recovery factor of CH₄ can be significantly enhanced. However, this does not mean that CO₂/N₂ = 2/8 and pure N₂ do not have the effect of enhancing CH₄ recovery. Therefore, it is necessary to conduct shale displacement experiments with different gas injection media. In addition, according to the above analysis, the equilibrium pressures at which different adsorbed gases reach the adsorption saturation state are different, and the maximum equilibrium pressure is 29.35 MPa. Therefore, to achieve the best production effect in the subsequent shale displacement experiments, the experimental pressure is set to 30 MPa.

The comparative analysis demonstrates that the concentration of CO₂ in the mixture gases has a strong correlation with the adsorption amount. Therefore, the experimental data are fitted with the CO₂ molar concentration and mass fraction, and the results are shown in Fig.9(b). The CO₂ molar concentration/mass fraction exhibits a linear negative correlation with the adsorption constant (a), and the correlation coefficient is –0.0023. The CO₂ molar concentration/mass fraction has a linear positive correlation with the total adsorption number (b), and the correlation coefficient is 0.0012. Moreover, the fitting result using the CO₂ mass fraction is better than that using the molar concentration. This conclusion provides a new direction for the follow-up study of mixed gas adsorption.

3.2 High temperature and pressure shale displacement experiment

Based on the experimental results of shale isotherm adsorption and the actual conditions of the reservoir, a self-designed displacement device was used to conduct gas injection to enhance shale gas recovery experiments. The displacement experiment is divided into one that injects pure CO₂ or N₂, and one that injects CO₂/N₂ mixture gases.

3.2.1 Effect of pure CO₂ or N₂ injection on enhanced shale gas recovery

3.2.1.1 Breakthrough time curves of pure CO₂ or N₂

The breakthrough time refers to the moment when the injected medium first appears at the outlet during the displacement process, which can directly reflect the residence time of the injection medium in the shale matrix, and indirectly reflect the effect of the injection medium on the displacement of CH₄. During the shale displacement experiment, sampling and analysis are performed every 30 min. Therefore, to accurately determine the breakthrough time of the gas injection medium, the data near the concentration mutation point of the gas injection medium are selected, and the linear extrapolation method is used for analysis and solution. The original data and solution methods are shown in Electronic Supplementary Material.

After injecting pure CO₂ or N₂, the gas injection medium molar concentration during the displacement process is shown in Fig.10. In the initial stage after the injection of CO₂ or N₂, the outlet of the displacement experiment is mainly free CH₄ in the shale fractures. As the displacement experiments proceed, the molar concentration of CH₄ at the outlet gradually decreases, and the molar concentration of CO₂ or N₂ gradually increases. The comparative analysis suggests that the breakthrough time of N₂ is shorter, approximately 49 min, while the breakthrough curve of CO₂ is longer, approximately 118 min. Moreover, the molar concentration curve of N₂ has a smaller slope, while the CO₂ curve has a larger slope. This indicates that, unlike N₂, CO₂ is transported slowly in shale samples, with a long residence time and a better diffusion effect. Therefore, the CO₂ concentration increases sharply after the breakthrough. This experimental result is in good agreement with studies on coalbeds and sandstone reservoirs in Refs. [49–51]. However, the performance difference of pure CO₂ or N₂ injection in coalbeds or sandstone reservoirs is more obvious than that in shale reservoirs. After injecting pure CO₂ or N₂ into the coalbeds or sandstone, the matrix expansion/contraction caused by the adsorption/desorption of the coalbeds or sandstone has a more significant effect on the formation permeability and fluid flooding diffusion process than in shale reservoirs. The reason for this is that the burial depth of the coalbeds or sandstone is shallow (less than 1000 m), while the shale reservoir is deeper (greater than 1000 m). Therefore, the shale matrix is significantly more constrained by the surrounding rock than the coalbed matrix [46]. In addition, the injection of adsorbed gas into the reservoir may result in a significant reduction in open pore volume and a rapid decrease in associated permeability, which is known as the “welling” phenomenon. Because the organic matter content of coalbeds (2%–10%) is much higher than that of shale reservoirs (75%–90%), the coalbed matrix is more obviously affected by the “swelling” phenomenon [54–56].

3.2.1.2 CH₄ recovery of pure CO₂ or N₂ injection during shale displacement experiment

The CH₄ recovery during the shale displacement experiment is obtained by Eq. (2).

(2)\begin{array}{rl}{R}_{\text{C}{\text{H}}_{\text{4}}}\left(\text{\%}\right)=& \frac{n_{\text{outlet}}\cdot M_{\text{C}{\text{H}}_{\text{4}}}}{n_{\text{inlet}-\text{C}{\text{H}}_4}}=\frac{P_{\text{outlet}}\cdot V_{\text{outlet}}\cdot Z_{\text{inlet}}\cdot T_{\text{inlet}}}{Z_{\text{outlet}}\cdot T_{\text{outlet}}\cdot P_{\text{inlet}}\cdot V_{\text{inlet}}}\\ & \cdot M_{\text{C}{\text{H}}_{\text{4}}}=\frac{16.5649\cdot P_{\text{outlet}}\cdot Z_{\text{inlet}}}{Z_{\text{outlet}}\cdot P_{\text{inlet}}}\cdot M_{\text{C}{\text{H}}_{\text{4}}},\end{array}

where R_{{\mathrm{C}\mathrm{H}}_4} is the CH₄ recovery factor during gas injection, %; n_outlet is the total gas molar concentration of the output, mol; M_{{\mathrm{C}\mathrm{H}}_4} is the proportion of CH₄ molar concentration in the output gas, mol; n_inlet is the gas molar concentration of the input, mol; P_outlet is the pressure of the outlet gas collecting tank, Pa; V_outlet is the volume of the outlet gas collecting tank, L; T_outlet is the temperature of the outlet gas collecting tank, °C; Z_outlet is the compression factor of the outlet gas produced; P_inlet is the pressure of the inlet gas collecting tank, Pa; V_inlet is the volume of the inlet gas collecting tank, L; T_inlet is the temperature of the inlet gas collecting tank, °C; and Z_inlet is the compression factor of the inlet gas produced.

After injection of pure CO₂ or N₂, the CH₄ recovery during the shale displacement experiment is shown in Fig.11. When the gas injection medium breaks through, the recovery factor of CH₄ (R_{{\mathrm{C}\mathrm{H}}_4}) of N₂ injection is 31.63%, and the R_{{\mathrm{C}\mathrm{H}}_4} of CO₂ is 44.09%. In combination with the research results in Section 3.2.1.1, the breakthrough time of N₂ is 49 min, which is much less than 118 min of that of CO₂. This phenomenon indicates that a longer breakthrough time can bring about a larger recovery factor. This also explains why N₂ is not injected separately: N₂ breaks through earlier, which can rapidly reduce the production efficiency of CH₄. Moreover, according to the trend of the CH₄ recovery curve, in the early stage, the slope of the N₂ injected to displace CH₄ is larger than that of the CO₂ injected, while in the later stage, the slope of the N₂ injected to displace CH₄ is gradually smaller than that of the CO₂ injected. This shows that the N₂ displacement experiment achieves good results in the early stage, and the production gas was mainly free-CH₄ during this time. In contrast, the CO₂ displacement experiments obtain good results in the late stage, and it can be speculated that CO₂ plays a role in promoting the desorption of adsorded CH₄. When the CH₄ molar concentration of the output is less than 5%, the experiment is terminated. After the experiment is terminated, the CH₄ final recovery (R_{{\mathrm{C}\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}}) injected with N₂ is 90.61%, and the R_{{\mathrm{C}\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} injected with CO₂ is 97.21%. The R_{{\mathrm{C}\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} injected with pure CO₂ or N₂ is greater than 90%, which fully verifies the feasibility of gas injection to enhance shale gas recovery. The comparative analysis demonstrates that the type of gas injection medium has a great influence on the ultimate recovery of CH₄. Furthermore, when CO₂ is used as the displacement fluid, more of the adsorbed CH₄ will be driven into the non-adsorbed/free state.

3.2.2 Effect of CO₂/N₂ mixed gas injection on enhanced shale gas recovery

3.2.2.1 Breakthrough time curves of CO₂/N₂ mixed gas

After injecting CO₂/N₂ mixed gas, the gas injection medium molar concentration during the displacement process is shown in Fig.12 and Tab.3. Based on Electronic Supplementary Material, it can be seen that in the different mixed gas injection experiments, the breakthrough time of N₂ does not change significantly, remaining between 49 and 58 min. However, as the CO₂ concentration in the mixture gases decreases and the N₂ concentration increases, the CO₂ breakthrough time is gradually prolonged. For example, when CO₂/N₂ = 8/2, the breakthrough time of CO₂ is about 125 min, and when CO₂/N₂ = 2/8, the breakthrough time of CO₂ is prolonged to 180 min, which shows that mixing N₂ with CO₂ can effectively increase the residence time of CO₂ in shale samples, which can enhance the recovery effect of CH₄ to a certain extent. However, as the CO₂ concentration in the mixed gas decreases, the content of the displacement medium (CO₂) used to replace CH₄ in the shale pores also reduces. As a result, the overall displacement efficiency may also be negatively affected. Therefore, it is necessary to consider the replacement capacity and efficiency, and then select the optimal mixed gas injection medium combination.

In addition, it can also be seen that in the mixed gas injection process, the breakthrough time curves of CH₄ and CO₂ are similar to the single component gas injection process, but the breakthrough time curve of N₂ is significantly different. In the late stage, the breakthrough time curve of N₂ in mixed gas injection rises sharply, and then gradually decreases to the initial concentration ratio. The reason for this is that the adsorption capability of N₂ is smaller than that of CH₄. Therefore, N₂ exists in a free state inside the shale reservoir and mainly flows in large shale pores and fractures. In contrast, since the adsorption capacity of CO₂ is greater than that of CH₄, it can enter the interior of shale micropores to displace the adsorbed CH₄, resulting in an increase in the amount of CH₄ desorption. However, due to the hysteresis of the desorption process, the desorption rate of CH₄ is lower than the adsorption rate of CO₂, resulting in a brief increase in the concentration of N₂ in the mixed gas. This phenomenon was consistent with the research results of coalbeds and sandstone reservoirs, i.e., in the process of CO₂/N₂ mixed injection, a sudden increase in N₂ concentration is observed [46,48,57,58].

To clarify the degree of N₂ increase in the later stage of mixed gas injection, the growth factor (G) is defined, and the calculation is shown in Eq. (3).

(3)G_{\left({\text{N}}_{\text{2}}\right)}= \frac{M_{\left({\text{N}}_2\right)max}-M_{\left({\text{N}}_2\right)\text{ini}}}{M_{\left({\text{N}}_2\right)\text{ini}}}\times 100\mathrm{\%},

where G_{\left({\text{N}}_{\text{2}}\right)} is the growth factor, %; M_{\left({\text{N}}_2\right)max} is the maximum ratio of N₂ molar concentration; and M_{\left({\text{N}}_2\right)\text{ini}} is the initial ratio of N₂ molar concentration.

The results of Eq. (3) are shown in Tab.4. The increase in N₂ at CO₂/N₂ = 5/5 was the largest, about 19.41%, followed by CO₂/N₂ = 8/2, about 5.85%, and the increase in N₂ at CO₂/N₂ = 2/8 is the smallest, only 3.83%. At CO₂/N₂ = 5/5, the N₂ molar concentration increases the most for the following two reasons. On the one hand, the N₂ adsorption capacity is small. Therefore, the un-adsorbed N₂ will gradually flow to the vicinity of the production well along the fracture. In contrast, the adsorption capacity of CO₂ is greater than that of CH₄. Consequently, it will be quickly adsorbed on the shale surface or inside the matrix, and then displace the adsorbed CH₄. Moreover, the adsorption rate of CO₂ is greater than the desorption rate of CH₄, and the increase in the desorption amount of CH₄ cannot compensate for the decrease in the adsorption amount of CO₂. Therefore, with the continuous injection of subsequent fluids, the N₂ in the mixed gas will increase for a short time and then decrease in the later stage. On the other hand, the un-adsorbed N₂ in the system can reduce the partial pressure of CO₂ and CH₄, thereby increasing the desorption of CH₄, and then part of the N₂ will be adsorbed on the shale surface or inside the matrix after CH₄ desorption. With the continuous migration of subsequent fluids, CO₂ will displace the absorbed N₂ and push it to the vicinity of the production well, resulting in the increase in the molar concentration of N₂. At CO₂/N₂ = 8/2, although the CO₂ has the largest molar concentration in the mixed gas, the degree of N₂ increase is not the highest. The reason for this is that the molar concentration of N₂ in the mixed gas is small, and its contribution to the reduction of CO₂ partial pressure is limited. Near production wells, the total amount of N₂ entering the matrix pores after CH₄ desorption is reduced. With the subsequent fluid flow, the content of the absorbed N₂ that can be displaced by CO₂ also decreases. Therefore, the increase in the molar concentration of N₂ is not the greatest. At CO₂/N₂ = 2/8, the N₂ increase is the lowest. The reason for this is that the molar concentration of CO₂ in the mixed gas is the lowest. As a result, its efficiency in replacing CH₄ is limited. In other words, the amount of CO₂ adsorption is not much different from the amount of CH₄ desorption. Therefore, the total amount of mixed gas is basically unchanged. Moreover, the initial molar concentration of N₂ in this case is the largest. Therefore, its increase degree is the smallest.

3.2.2.2 CH₄ recovery of CO₂/N₂ mixed gas during shale displacement experiment

After injection of CO₂/N₂ mixed gas, the CH₄ recovery during the shale displacement experiment is shown in Fig.13. When the CO₂ in the mixed gas breaks through, the R_{\mathrm{C}{\mathrm{H}}_4} at CO₂/N₂ = 8/2 is 40.24%, the R_{\mathrm{C}{\mathrm{H}}_4} at CO₂/N₂ = 5/5 is 40.10%, and the R_{\mathrm{C}{\mathrm{H}}_4} at CO₂/N₂ = 2/8 is 37.46%. When the experiment is completed, the R_{\mathrm{C}{\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} at CO₂/N₂ = 8/2 is 96.17%, the R_{\mathrm{C}{\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} at CO₂/N₂ = 5/5 is 93.98%, and the R_{\mathrm{C}{\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} at CO₂/N₂ = 2/8 is 92.15%. The comparative analysis exhibits that with the increase of CO₂ molar concentration in the mixed gas, both the R_{\mathrm{C}{\mathrm{H}}_4} and R_{\mathrm{C}{\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} gradually increase. Moreover, the difference in CH₄ recovery between pure CO₂ and CO₂/N₂ = 8/2 is small; the difference for R_{\mathrm{C}{\mathrm{H}}_4} is only 3.85%, and that for R_{\mathrm{C}{\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}} is 1.04%. In addition, CO₂/N₂ = 8/2 and CO₂/N₂ = 5/5 have similar effects on improving CH₄ recovery, with a difference of only 0.14% for R_{\mathrm{C}{\mathrm{H}}_4} and 2.19% for R_{\mathrm{C}{\mathrm{H}}_4\text{-}\mathrm{f}\mathrm{i}\mathrm{n}\mathrm{a}\mathrm{l}}. In contrast, CO₂/N₂ = 2/8 is the least effective for enhanced shale gas recovery. This shows that when the CO₂ concentration in the mixed gas is greater than 50%, the production is slightly greater than that when the concentration is less than 50%. This is also demonstrated in the isotherm adsorption experiments above in this study. The analysis results in Section 3.2.2.1 indicate that in the three groups of mixed gas injection displacement experiments, the breakthrough time of N₂ does not change significantly, while the breakthrough time of CO₂ extends with the increase of N₂ concentration. The research results indicate that N₂ can prevent the premature breakthrough of CO₂ in the process of mixed gas injection. However, it is not that the later the CO₂ breakthrough time, the better the CH₄ recovery effect obtained. The reason for this is that the increase of N₂ concentration can prolong the breakthrough time of CO₂, but at the same time, it will also reduce the CO₂ concentration in the mixed gas. Moreover, the reduction of CO₂ concentration directly affects its ability to compete for adsorption and displacement of CH₄. Therefore, in order to obtain the best CH₄ recovery, it is necessary to optimize the components and proportions of mixed gas injection media.

3.3 CO₂ storage efficiency of different gas injection cases

Injecting CO₂ into shale reservoirs cannot only enhance CH₄ recovery in the shale reservoir, but also sequester CO₂. To mitigate global warming, CO₂ storage capacity also needs to be considered. The calculation equation of the CO₂ storage efficiency of different gas injection cases is determined by Eq. (4).

(4)S_{\text{storage-C}{\text{O}}_2}=\frac{n_{\text{total, injected-C}{\text{O}}_2}-n_{\text{total, revovery-C}{\text{O}}_2}}{n_{\text{total, injected-C}{\text{O}}_2}}\times 100\text{\%},

where S_{\text{storage-C}{\text{O}}_2} is the CO₂ storage capacity, %; n_{\text{total, injected-C}{\text{O}}_2} is the total molar concentration of CO₂ injected, mol; and n_{\text{total, revovery-C}{\text{O}}_2} is the total molar concentration of recovered CO₂, mol.

To calculate the total mole amount of CO₂ injected, the temperature, pressure, and compressibility factor of the injected gas tank at the beginning and end of the experiment were recorded, and the difference in mole content was calculated according to the gas state equation [59,60]. Then, the same theory and method were used to calculate the total recovery of CO₂ in the collecting gas tank after the experiment. The CO₂ storage efficiencies of the pure CO₂ and CO₂/N₂ mixed gas displacement experiments are shown in Fig.14. It can be seen that S_{\text{storage-C}{\text{O}}_2} gradually decreases with the decrease of CO₂ concentration in the medium injected. In other words, adding CO₂-rich media into shale reservoirs cannot only improve CH₄ recovery efficiency, but also store large amounts of CO₂. However, for practical carbon capture and storage, as the CO₂ content or concentration in the mixed gas increases, the capture cost also increases. Therefore, it is necessary to comprehensively consider the CH₄ extraction efficiency, CO₂ storage efficiency, and operating cost to optimize the selection and proportion of gas injection medium. The comparative analysis illustrates that the S_{\text{storage-C}{\text{O}}_2} of the pure CO₂ injection experiment is 35.96%, and that of the 80%-CO₂ is 32.28%. This shows that when the CO₂ molar concentration in the gas injection medium is higher than 80%, the CO₂ storage efficiency of the shale reservoir after fracturing is greater than 30%. However, when the CO₂ molar concentration exceeds 80%, the CO₂ sequestration effect does not change significantly as the CO₂ molar concentration continues to increase. When the CO₂ molar concentration in the gas injection medium is 50% and 20%, the CO₂ storage efficiency is only 25.21% and 20.54%. Du et al. [46] and Wang et al. [61] also studied the carbon sequestration issue during gas injection in shale reservoirs, but the calculated results of carbon sequestration efficiency were greater than those of this experiment. The reason for this is that the experimental material they used is core powder. As a result, the porosity and permeability of the shale samples are magnified several times. However, to restore the production of the actual shale reservoir, the shale samples used in this study are shale core plugs after fracturing. Due to the smaller porosity and permeability of the fractured shale samples, its carbon sequestration capacity is reduced in comparison.

4 Conclusions

Based on competitive adsorption theory, this study, taking fractured shale core plugs as the research object, investigated the effect of injecting CO₂, N₂ and CO₂/N₂ mixed gas on enhancing shale gas recovery by using a self-designed core displacement experimental device. The main conclusions obtained are as follows:

(1) The adsorption process of gas adsorbate on shale conformed to the extended-Langmuir adsorption isotherm model, under the same temperature conditions, and the order of adsorption capacity was CO₂ > CO₂/N₂ (8/2) > CO₂/N₂ (5/5) > CH₄ > CO₂/N₂ (2/8). In other words, as the CO₂ concentration in the mixed gas increased, the adsorption capacity of the mixed gas was enhanced. Moreover, when the CO₂ concentration exceeded 50%, the adsorption capacity of the mixture gases was greater than that of CH₄, which formed a competitive adsorption effect.

(2) The single component gas injection experiment showed that the breakthrough time of CO₂ was greater than that of N₂, which were 118 min and 49 min, respectively. When the gas injection medium broke through, the recovery factor of N₂ injected was only 31.63%, while that of CO₂ injected was 44.09%. This showed that both CO₂ and N₂ injection into shale reservoirs can enhance the recovery factor, and CO₂ injection was more effective.

(3) The mixed gas injection experiment showed that the breakthrough time curve of N₂ did not change significantly, while the breakthrough time of CO₂ was prolonged with the increase of N₂ concentration. In other words, N₂ could effectively prevent the premature breakthrough of CO₂, thereby increasing the residence time of CO₂ inside shale samples. In addition, in the later stage of mixture gas injection process, the breakthrough time curve of N₂ all showed a short increasing trend. For the CH₄ recovery factor, with the CO₂ concentration increasing in the mixed medium, the recovery factor showed an increasing trend.

(4) As the CO₂ molar concentration in the mixed medium increased, the CO₂ storage efficiency gradually increased. However, when the CO₂ concentration in the mixed gas exceeded 80%, the CO₂ storage efficiency was not much different. Therefore, it is necessary to consider the storage capacity of CO₂ and the recovery efficiency of CH₄, and optimize the components and proportions of gas injection media.

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