Introduction

In recent years, the consumption of fossil fuels has been increasing. At the same time, a large amount of greenhouse gas—carbon dioxide (CO2) has been emitted into the atmosphere, leading to climate warming. CO2 capture and geological sequestration have been to proposed to alleviate the greenhouse effect caused by CO2 emissions. Among them, CO2-enhanced coalbed methane recovery (CO2-ECBM) has great application prospects1.

Previous studies show that the geological factors, including the buried depth of coal seam, gas properties, tectonics, etc., have a great influence on the production capacity of coalbed methane (CBM)/coalbed gas (CBG) wells2,3,4. Generally, gas content increases as buried depth increases, resulting in an increase in CBG production5,6. However, in deep coal seams, different changes in CBG production may occur beyond the critical depth7. The proportion of gas components in the formation has a relatively small impact on shale gas productivity, and the higher the adsorbed gas content in the formation, the longer the production period8. In addition, the production capacity of CBM/CBG wells is poor in areas with developed faults and synclinal axes. Conversely, in areas characterized by simpler geological structures, such as stable structural zones and synclinal wings, the production capacity is higher, and the stable production period is longer9,10. Vikram et al. focused on the CO2-enhanced CBG production for a block within the Jharia coalfield of eastern India by numerical simulation11. Mu et al. found that the increase of CO2 injection temperature and pressure would promote CO2 sequestration and enhance methane (CH4) recovery12, however Hou et al. discovered that with the increase of injection temperature, CO2 reserves and CH4 production would decrease13. Zhou discovered that coal shrinkage and skin factor have a significant role in the CBG production of horizontal wells14. Hu et al. considered that increasing the drainage rate can increase the gas production of CBM wells15. Huang et al. conducted numerical simulation studies on three well types for the development of shale gas reservoirs with large reservoir thickness and multiple layers, and compared the simulation results with actual production data to verify the reliability of the numerical simulation16. Zhang et al. optimized the traditional shale gas production capacity prediction method, established an effective prediction model, and applied the model to a gas reservoir in Southwest China17.

Due to the different affinities of various gases for coal, competitive adsorption occurs, resulting in differences in gas content and composition within coal seams, which further affects the CBG production capacity. In recent years, the theory of multi-component gas adsorption has yielded rich research results. Cui et al. simulated the adsorption rates of CO2, CH4, and nitrogen (N2) on the same coal by establishing a model, and the results showed that the adsorbate molecule size and pore structure of the coal play an important role in selective gas adsorption and diffusion18. Busch et al. studied the binary gas adsorption experiments of CH4 and CO2, CH4 and N2 respectively, and the results showed that CO2 was the most advantageous in the competitive adsorption, while CH4 was more advantageous than N219. Harphlani et al. showed that coals exhibit higher affinity to CO2 as compared to methane and the preferential adsorption ratio was between 2:1 and 4:120. Zhou et al. discovered that coal has a stronger adsorption force for CO2 compared to CH4, and multi-molecule layer adsorption happens during the adsorption of CO2 on coal matrix21. Asif et al. found that CO2 was adsorbed at faster rate, and that competitive adsorption of CO2/CH4 enhanced the displacement of CH4 when the CO2 mole fraction was less than 30%22. Therefore, it is of great significance to clarify the adsorption mechanism of coal in order to study the capacity of CBG wells.

In summary, there have been many achievements in research on the CBM/CBG production capacity. However, there are some problems. Firstly, most coal seams are rich in CH4, and the current ground development practices of CBM/CBG mainly focuses on CH4. There is little research on the production capacity of CBM/CBG wells affected by different gas components in coal seams. Furthermore, during the process of coal mining, the higher the CO2 concentration in the coal seam, the greater the probability of outburst accidents occurring23. For example, in Metropolitan colliery in Australia, approximately 200 tons of coal and 11,500 m3 of CO2 were released during the greatest known outburst24. The Yaojie coalfield in Gansu Province, China, is a typical CO2-rich coalfield, with CO2 concentration of 10–95% in mine gas, coal and CO2 outburst accidents have occurred several times in the coalfield since 1977. Therefore, in this study, we collected data from the No.2 coal seam of the Haishiwan coal mine in Yaojie coalfield, and summarized the characteristics of CBG in the study area. On the basis of geological data and drainage data, the characteristics of gas production in CBG wells were illustrated. Then, the production capacity of CO2-rich CBG wells was simulated through GEM software and the differences in production capacity were discussed. Finally, we revealed the thermodynamic mechanism of the impact of gas adsorption differences on production capacity, which is important for the exploitation of CBG in CO2-rich coalfields.

Fig. 1
Fig. 1
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Location and structure setting of the study area (this figure is generated in CorelDRAW 2020 software, https://www.coreldrawchina.com/).

Geological setting

Geological structure characteristics

The Haishiwan coal mine, located in the south of Yaojie coalfield on the western margin of Minhe Basin, covers a total area of approximately 28.6 km23. Structurally, the Haishiwan coal mine is divided into the secondary structural unit of Minhe Basin. The area experienced the Indochin-Yanshan-Himalayan tectonic movements, resulting in well-developed faults and fold structures. The F19 fault is the most prominent and developed fault. The basin stratum is Mesozoic-Cenozoic sedimentary, which generally lacks Paleozoic and Mesozoic sedimentary Triassic deposits, and the basement is Proterozoic metamorphic sedimentary25. The Haishiwan coal mine lies roughly in a NNW direction with the F19 fault located east of it. Due to the influence of tectonic changes in the basement of the coalfield, the Jurassic strata formed an asymmetric oblique fold with a high north and low south pattern, which together with the F19 fault, forms the main tectonic framework of the coal-bearing basin (Fig. 1).

Fig. 2
Fig. 2
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Columnar section of coal-bearing strata in Haishiwan coal mine.

Coal-bearing strata

The coal-bearing strata in Haishiwan coal mine is the second group formation of Yaojie Group, which belongs to Mesozoic Middle Jurassic (Fig. 2). Two of the three coal seams are suitable for mining, namely No.1 coal seam and No.2 coal seam. The No.2 coal seam is the main mining, which is a gently inclined coal seam and dip angle changes from 5° to 15°. No.2 coal seam grows most broadly and steadily, with a thickness ranging from 0 to 59.28 m, a buried depth of 506.72 m to 1,013.14 m, and a gradual deepening from north to south. Coal with an average Ro, max value of 1.02% is either a non-caking coal or weakly caking coal, exhibiting a medium degree of metamorphosis.

Fig. 3
Fig. 3
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CO2 concentration and δ13CCO2 (PDB) values for CO2 from the No.2 coal seam in the Yaojie coalfield (data from Tao et al.26 and Li et al.27).

Genesis and formation of CO2

According to the literature26,27, the measured δ13CCO2 values range from + 1.12‰ to -20.00‰, and most of them are heavier than 8‰ (Fig. 3). The higher the CO2 concentration, the heavier the δ13CCO2. Meanwhile, most of the CO2 component accounts for more than 60% of the mine gas, indicating that the CO2 in the Yaojie coalfield is of inorganic origin28. Previous studies have shown that 3He/4He values range from (0.6 ± 0.6)×10− 8 to (25.9 ± 0.3)×10− 8, and R/Ra values range from 0.0042 to 0.185 (where Ra is the atmospheric value of 3He/4He and R is the sample value of 3He/4He)26,27. These indicate that He is derived from the crust and imply that CO2 in the Yaojie coalfield is of crustal origin. During the late Jurassic to the early Cretaceous, dynamic-thermal metamorphism of the F19 fault led to significant decarbonization of carbonate rocks in the bottom layer of the No.2 coal seam during hydrothermal activity. This decarbonization is the inorganic source of CO2 in the Yaojie coalfield. The regional geological evolution and multi-periodic movements of the F19 fault control the formation, migration, and accumulation of CO2, ultimately resulting in the high CO2 contents observed in the Yaojie coalfield27.

Engineering overview

The Haishiwan coal mine have started the drilling work of CBG wells from 2019, and 30 CBG wells have been built so far. The well type has evolved from vertical wells to directional and L-shaped horizontal wells. According to the geological background, gas composition and characteristics of gas production, four vertical wells (D2#, D5#, D6#, D8#) were selected as the study objects and the engineering overview of these wells is shown in Table 1. Well D2# is located in the east part of the coal mine, close to the mining face in the west and the F19 fault in the east. Wells D5#, D6#, and D8# are situated in the south part of the coal mine and far from the F19 fault.

Table 1 Engineering overview of CBG wells.
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Samples and methods

Gas content test

Coal samples were collected through the rope coring method from CBG wells in the Haishiwan coal mine. First, the desorption gas from coal samples was measured and collected by the canister desorption method employing a standard desorption device in the field test in accordance with the national standard GB/T 19,559 − 2008. It should be emphasized that the gas content on the basis of air-drying is determined by the sum of the natural desorption gas content, escaped gas content and residual gas content. And the escaped gas content was measured using the direct method of the United States Bureau of Mines (USBM)29,30. In this paper, the gas content is expressed on the basis of air-drying.

Gas composition analysis

20 groups of gas samples were collected from 20 boreholes in the Haishiwan coal mine. These samples were collected using the drainage gas collection method and stored in water-sealed glass bottles. Each gas sample was collected about 200–400 mL for gas composition analysis. Gas composition was performed using a GC9720Plus gas chromatograph manufactured by Foley Analytical Instruments in accordance with the national standard GB/T 13,610 − 2020 “Gas Chromatography for Compositional Analysis of Natural Gas”.

Numerical simulation method

GEM software is capable of simulating dual-porosity dual-permeability reservoirs, including gas adsorption, gas diffusion, and two-phase flow through the natural fracture system31. The coal seam is a dual-porosity medium, and the nonlinear desorption of CH4 in the coal matrix varies over time, described by isotherms related to the gas content and pressure of the matrix. Therefore, to investigate the impact of CO2 concentration on CBG production, this study employs GEM for numerical simulation. By constructing a model that aligns with the geological background of the study area’s CBG development, the study explores the production characteristics. Simulation of multi-component adsorption uses the extended Langmuir isotherm. In this study, No.2 coal seam was selected as an example for simulation reaseach. The model was 30 × 30 blocks each with a length of 10 m. The model doesn’t take into account the inclusion of gangue in the coal seams. Table 2 reveals the Model description.

Table 2 Model description and assumptions.
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Adsorption heat measurement

In this study, C80 microcalorimeter was used to investigated the exothermic characteristics of the adsorption process. The C80 microcalorimeter was produced by Setaram Company, France, and consisted of a C80 host and a gas circulating pool. Coal sample was crushed and graded using standard sifters (0.18 mm to 0.15 mm), and dried for 24 h in a drying oven at 65℃ until the change between successice weights was < 0.001 g. The experimental temperature and pressure were set at 20 ℃, 30 ℃, 40 ℃, 50 ℃ and 1 MPa, 2 MPa, 3 MPa, 4 MPa, respectively. Meanwhile, CO2 was selected as the adsorbed gas and the experimental time was set to 2 h.

Fig. 4
Fig. 4
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Contour maps of gas distribution in the No.2 coal seam. (a) CBG, (b) CO2 content, (c) CH4 content (this figure is generated in DoubleFox V5.3.CO software, https://www.gdfoil.com/).

Results and discussion

Gas component characteristics

CO2 is the main gas component of CBG in the No.2 coal seam, among which the CO2 concentration ranges from 15.47 to 90.67% (average 53.06%), and its content ranges from 1.1 m3/t to 10.22 m3/t. The CH4 concentration in the No.2 coal seam varies from 2.02 to 80.04% (average 31.35%), and its content ranges from 0.17 m3/t to 11.82 m3/t. From Fig. 4a, No.2 coal seam has high contents of CBG in the east and central portion, contrasting with comparatively low contents in the west. The CO2 content follows this pattern (Fig. 4b), while the CH4 content shows different characteristics, with high levels in the south and west but lower levels in the north and east (Fig. 4c).

Characteristics of CBG well drainage

The dynamic curves of gas and water production over time of four CBG wells are shown in Fig. 5. It can be seen that, (1) when the casing pressure was present in each well, the pressure of No.2 coal seam was 8 MPa to 9 MPa after adjusting for the bottom hole pressure. (2) The steady increase stage of gas production in each well is the uniformly decreasing stage of bottom hole flowing pressure, independent of casing pressure variations. (3) The water production of each well has a significant effect on its production capacity. The water production of the wells shows an evident downward trend after gas production. It is concluded that the production capacity of each well continues to decline after the steady pressure drainage. The reason for this is that the drainage intensity decreases and the water production decreases. Water turbulence is a mass transfer process, and the desorption of the coal seam requires the energy provided by water turbulence32.

The gas production of wells D8#, D6#, and D2# declines after the production peak, while the gas production of well D5# continues to increase. According to the gas production characteristics of four CBG wells, the gas production types of CBG wells can be classified into three categories. (1) Rising. The gas production continues to increase over the drainage time, as seen in well D5#. (2) Multi-peak. Multiple peaks in gas production, such as those at wells D6# and D8#, are a regular occurrence. The maximum daily gas production of well D6# during drainage after 108 days is 1,210 m3/d, decreasing to 900 m3/d after 200 days. Then the gas production began to rise to 1,173 m3/d after 228 days, decreasing to 825 m3/d after 270 days. The production decline rate during the drainage time is 31.82%, and the average daily decline rate is 0.20%. The maximum daily gas production of well D8# during drainage after 179 days is 1,015 m3/d, decreasing to 800 m3/d after 244 days. The production decline rate during this period is 21.18%, and the average daily decline rate is 0.32%. The pump accidence happened around the 200st day of drainage, resulting in the occurrence of multiple peaks in the gas production curve. (3) Steady. The primary features of the gas production curve of this type, like well D2#, are a long constant production period and a reasonably stable gas production rate. The maximum daily gas production of well D2# during drainage after 117 days is 1,100.7 m3/d, decreasing to 562.5 m3/d after 535 days. The production decline rate during this period is 48.90%, and the average daily decline rate is 0.12%.

Fig. 5
Fig. 5
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Drainage curves of CBG wells. (a) well D8#, (b) well D5#, (c) well D6#, (d) well D2#.

Well D2# took a longer drainage time with 535 days. Combined with the mechanism of CBG drainage, its drainage process can be classified into four stages. (I) Water production stage. During this stage with the maintenance time of 81 days, while the cumulative water production is 358.91 m3, and the average water production is 4.49 m3/d. (II) Rapid increase stage of gas production. This stage is characterized by a sharp increase in gas production and a decrease in water production, while the maximum gas production of 1,100.7 m3/d was achieved after 117 days. (III) Stable stage of gas production. The gas production gradually declines from its peak and tends to stabilize, while the water production remains relatively stable at lower level. The cumulative gas production is 228,331.5 m3, and the average gas production is 864.89 m3/d. (IV) Decline stage of gas production. During this stage, gas production begins to decline slowly and will continue for an extended period of time.

Study on capacity simulation of CBG wells

Historical fitting of CBG wells

According to the CO2 content of CBG wells based on Table 3, the gas production changes under different CO2 concentrations of 20%, 50%, 60%, and 70% were simulated.

Table 3 Gas component content of CBG wells.
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The key parameters for numerical simulation include buried depth, coalbed thickness, gas content of coalbeds, CH4 content, CO2 content, reservoir temperature, porosity, permeability, etc. The accuracy of parameter selection influences the numerical simulation results33. Based on the analysis of production data and referencing the geological parameters of four wells, the porosity, permeability, gas content, reservoir temperature, and other parameters were determined. After multiple parameter adjustments and fitting, the actual curve was visually compared with the fitted curve to determine the accuracy of the fitting results. The daily gas production fitting curves are shown in Fig. 6, and the parameters are detailed in Table 4.

Fig. 6
Fig. 6
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Comparison of fitted and initial gas production curves. (a) well D8#, (b) well D5#, (c) well D6#, (d) well D2#.

Table 4 Comparison of initial parameter values and historical fitting values.
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Fig. 7
Fig. 7
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Capacity prediction curves of CBG wells in the next decade.

Table 5 Drainage data of CBG wells.
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Effect of various CO2 concentrations on CBG production capacity

Based on the historical fitting parameters, the gas production of four wells in the next decade was simulated (Fig. 7), and the drainage data is shown in Table 5. The time from the start of drainage to continuous gas production is defined as the gas breakthrough time. The time from the start of gas breakthrough to the peak of gas production is defined as the peak production period. In the next decade, well D5# will continue to expand its gas production range, and the gas production rate will gradually decrease after reaching a peak of 3,150 m3/d. Well D8# has the lowest gas production, with a maximum gas production of only 1,015 m3/d. The gas production of four wells will decrease and gradually stabilize in the next decade, but the average gas production of wells D5# and D6# will remain above 800 m3/d, with good gas production efficiency. The production decline rate of each well is different, among which well D5# has the largest production decline rate of 53.97%. In addition, the gas breakthrough time of CBG wells increases linearly with the increase of CO2 concentration, in the order of 38→35→68→81 d.

Dewatering is a crucial stage for gas production in CBG reservoirs, and more dewatering means that the methane recovery factor would be lower34. As shown in Fig. 8, gas content changes synchronously with gas production, water production has a negative correlation between gas content and gas production. That is, CBG wells with higher water production have lower gas content and poorer gas production efficiency. This is consistent with the findings of Stevens et al.35 and Asif et al.34. At the CO2 concentration of 20%, the gas production and peak production period are low, while the water production is high. When the CO2 concentration reaches 50%, the performance of CBG production increases, specifically with the maximum daily gas production increasing to 1,450.04 m3/d and the peak production period increasing to 329 days. Meanwhile, the water production decreases. As the CO2 concentration continues to increase, the gas production and peak production period decrease to the lowest point, while the water production increases (Fig. 9). This indicates that CBG wells with higher CO2 concentration have lower gas production, higher water production, slower declines in gas production rate, and longer gas production period.

Compared with previous studies, there exists a critical mole fraction (~ 30%) in the binary gas adsorption process involving CO2 and CH4. Above this threshold, CO2 becomes the predominant adsorbed phase on coal surfaces22, leading to enhanced CH4 desorption. This finding shares similarities with the results of our study. However, during the CO2-ECBM process, the injection of CO2 results in an increase in the CH4 recovery rate. As the amount of injected CO2 increases, the CH4 production rate decreases, while the cumulative gas production initially rises and subsequently stabilizes36,37. This means that as the CO2 concentration in the coal seam increases, so does the gas production. This differs from the results of this study. The reason for this discrepancy is that previous research has focused on reservoirs with high CH4 content. Based on the competitive adsorption between CO2 and CH4, an increase in CO2 injection results in a stronger displacement ability and a more thorough desorption of CH4. In contrast, the research object in our study is a high CO2 content reservoir, where the coal seam itself has a low CH4 content. Consequently, the gas production after drainage and desorption is relatively low in that case.

Fig. 8
Fig. 8
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Relationship between water production, gas content, and gas production.

Fig. 9
Fig. 9
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The trend of changes in gas production, water production, and peak production period with CO2 concentration.

Thermodynamic reasons affecting productivity differences of CBG wells

Geological reasons for changes in CBG production capacity

Previous studies have shown that buried depth and tectonics are key geological factors affecting the production capacity of CBG wells, mainly achieved through influencing gas adsorption. From Figs. 10 and 11, as the buried depth and distance to the F19 fault increase, CO2 concentration decreases while CH4 concentration increases. The reason is that the F19 fault is the main channel for CO2 migration, and tectonic movements cause the rupture of coal seams near the F19 fault zone, increasing their porosity. Due to the significant adsorption capacity of coal seams for CO2, they become the primary reservoir for CO2 migration, leading to high CO2 concentrations in the coal seams close to the F19 fault. Subsequently, CO2 migrates from east to west in the coal seam, displacing CH4 in the process. Tectonic movements have also caused the coal seams in the central and southern parts of the coalfield to be deeper, while those in the northern and eastern parts are relatively shallower (Fig. 12). Thus, with increasing distance to the F19 fault, buried depth increases, and CO2 concentration decreases.

As shown in Fig. 13, the gas content and gas production of CBG wells change synchronously, both showing a trend of initially increasing and then decreasing with the increase of buried depth. This indicates a clear positive correlation between gas content and gas production. This is because the positive and negative effects of pressure and temperature on gas adsorption, which alter the gas content and consequently influence gas production. According to Fig. 14, at buried depths shallower than 950 m, pressure plays a dominant role in promoting gas adsorption, leading to an increase in gas content. Conversely, at buried depths deeper than 950 m, temperature becomes the dominant factor, inhibiting gas adsorption and resulting in a decrease in gas content2. Coal seams provide a space for the adsorption of multiple gases. However, competitive adsorption occurs due to the different affinities of CH4 and CO2 for coal, leading to variations in gas content and composition. This will be elaborated in “Thermodynamic mechanism of the impact of gas adsorption differences on productioncapacity” section.

Fig. 10
Fig. 10
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Relationship between buried depth and CO2/CH4 concentration.

Fig. 11
Fig. 11
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Relationship between distance to the F19 fault and CO2/CH4 concentration.

Fig. 12
Fig. 12
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Contour map of buried depth of No.2 coal seam (this figure is generated in DoubleFox V5.3.CO software, https://www.gdfoil.com/).

Fig. 13
Fig. 13
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Relationship between buried depth, gas content, and gas production of CBG wells.

Fig. 14
Fig. 14
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Relationship between buried depth and gas content in Haishiwan coal mine.

Thermodynamic mechanism of the impact of gas adsorption differences on production capacity

To explore the thermodynamic mechanism affecting production capacity differences, experiments were conducted on the adsorption heat of CO2 and CH4 on coal with medium metamorphic degree under different temperature and pressure conditions, as shown in Figs. 15, 16 and 17. The adsorption heat of CO2 and CH4 increases with the increase of pressure and the decrease of temperature. And under constant pressure, the variation in CH4 adsorption heat across different temperatures is relatively minor, whereas the difference in CO2 adsorption heat is significant. This suggests that temperature has a lesser impact on CH4 adsorption heat compared to CO2, which is more sensitive to temperature changes. On one hand, as the temperature increases, the movement of gas molecules intensifies and then gas molecules are less likely to be adsorbed on coal, leading to the adsorption heat of CO2 and CH4 decrease. On the other hand, increased pressure results in a decline in the distance between the coal surface and gas molecules, which increases Van der Waals forces and promotes collision frequency between the coal surface and gas molecules, thereby promoting coal adsorption onto the gas39,40. This results in an increase in the adsorption heat of CO2 and CH4. That is, in high-temperature and high-pressure environments, CO2 cannot be adsorbed in significant quantities and remains in a free state, thereby providing more opportunities for CH4 to be adsorbed.

Notably, the heat released during the adsorption of CO2 is greater than that released during the adsorption of CH4 (Fig. 16), suggesting that CO2 has a stronger adsorption capacity than CH4. Li42 and Wang43 conducted isothermal adsorption experiments of CO2/CH4 mixed gas on coal samples from Haishiwan coal mine, confirming that CO2 has a stronger adsorption capacity than CH4. Moreover, as the CO2 concentration in the mixed gas increases, the total adsorption capacity of coal on the mixed gas also increases (Fig. 18). Because of the quadrupole moment structure of CO2 molecules, which is highly sensitive to polarity, the presence of polar oxygen-containing functional groups in coal creates additional adsorption sites for CO2, thereby enhancing its adsorption on the coal surface44. In contrast, CH4 molecules, being non-polar, exhibit a weaker interaction with the coal surface and consequently possess a reduced adsorption capacity. Meanwhile, the kinetic diameter of CO2 (0.33 nm) is smaller than that of CH4 (0.38 nm), making it easier to diffuse into micropores, resulting in an increase in CO2 adsorption45. Therefore, the higher the CO2 concentration in the coal seam, the greater the gas content. Combined with  “Geological reasons for changes in CBG production capacity” section, it can be seen that near the F19 fault, the coal seam is shallow, exhibiting a high CO2 concentration and a correspondingly high gas content.

CBG drainage is a dynamic process of adsorption and desorption. During the drainage process, CH4 continuously desorbs, adding adsorption sites for CO2, resulting in an increase in CO2 concentration. The higher the CO2 content, the greater the pressure reduction required to achieve the same desorption amount, which is not conducive to gas desorption and makes CBG drainage more difficult. Therefore, CBG wells with high CH4 concentration usually have earlier gas breakthrough time and higher gas content. Correspondingly, CBG wells with high CO2 concentration have slower ga breakthrough and lower gas production. However, it is should be noted that gas produced from CBG wells is a mixture of free gas and adsorbed gas. The gas production is not solely determined by the content of adsorbed gas, but this underscores the complexity and variability of coal adsorption mechanisms and their role in CBG drainage. Therefore, it highlights the need for further research to deepen our understanding of the exploitation mechanisms of CO2-rich CBG wells.

Fig. 15
Fig. 15
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CO2 adsorption heat characteristics of the coal.

Fig. 16
Fig. 16
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Adsorption heat of CO2 and CH4 at different pressure (at 30 ℃) (data from Zhang et al.38).

Fig. 17
Fig. 17
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Adsorption heat of CH4 at different temperatures (at 1 MPa) (data from Zhang et al.38, and Li et al.41).

Fig. 18
Fig. 18
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Adsorption isotherm of CO2/CH4 mixed gas (at 30 ℃) (data from Li42).

Conclusions

  1. (1)

    The production types of CBG wells are classified into rising, multi-peak, and stable types based on gas production characteristics. The rising type shows continuous gas production growth with a good gas production performance, while the multi-peak type fluctuates significantly. The stable type has a longer gas production period with stable gas production.

  2. (2)

    Simulation results indicate that CO2 concentration limits the CBG production capacity. A higher CO2 concentration in a CBG well is associated with a later gas breakthrough time, increased water production, a longer gas production period, and poorer CBG production capacity.

  3. (3)

    CBG production capacity is affected by geological factors, mainly through the influencing of temperature and pressure on gas adsorption. High pressure increases gas content by promoting adsorption, thereby boosting production. However, CO2’s stronger adsorption compared to CH4 raises CO2 concentrations, hindering desorption, causing slower gas breakthrough, and a longer production period. Conversely, high temperature inhibits adsorption, lowering CO2 concentration and gas content, which promotes CH4 desorption, accelerates gas breakthrough, ultimately reduces production.

The findings from this comprehensive experiments and numerical simulation provide valuable guidance for future CBG development in CO2-rich coalfields, similar to the Yaojie coalfield. However, further studies of the impact of reservoir properties on the coal adsorption mechanism is crucial for advancing our understanding of the development mechanisms of CO2-rich CBG wells.