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The old wells in Hancheng Block face the problem of production decline after long-term exploitation, and need to be re-fractured to form new fractures to communicate with CBM rich areas, so as to achieve stable CBM production. Due to the small difference of initial stress in coal seam, the magnitude and direction of in-situ stress change significantly after fracturing and long-term drainage, which directly affects the choice of re-fracturing time. Therefore, we firstly obtain the initial ground stress of well Y3 in the research block combined with logging data, then simulate the change of coal seam ground stress during fracturing by using finite element model, then study the change of pore pressure during drainage and production, and determine the horizontal principal stress and induced stress according to the steering mechanism of refracturing, so as to obtain the best time for refracturing. Field tests were carried out on well Y3. It is found that the stress produced by the first fracturing in coal seam has little influence and does not cause stress reversal. After about 1 500 days of drainage, the difference of non-uniformity of pore pressure is about 0.6 MPa, which is equal to the difference of initial in-situ stress in the coal seam section, that is, the stress direction reverses. Secondary fracturing at this time is conducive to generate new fractures that can extend 70 m near the hole and communicate the CBM rich area at the bottom of the hole; according to the method proposed in this paper, the daily gas production of well Y3 increased from 114 m3 to 1 626 m3 after the same zone re-fracturing, and the effect is remarkable.

Abstract In-situ stress plays a pivotal role in influencing the desorption, adsorption, and transportation of coalbed methane. The reservoir gas content represents a pivotal physical parameter, encapsulating both the coalbed methane enrichment capacity and the underlying enrichment law of the reservoir. This investigation collates, computes, and consolidates data concerning pore pressure, breakdown pressure, closure pressure, triaxial principal stress, gas content, lateral pressure coefficient, and other pertinent variables from coal reservoirs within several coal-bearing synclines in the Liupanshui coalfield, China. This study elucidates the characteristics of longitudinal stress development in the study area, the gas content of the longitudinal reservoirs and their interrelationships. The study area is situated within the middle-high stress zone, exhibiting discernible evolution patterns from reverse fault mechanism to strike-slip fault mechanism to normal fault mechanism, progressing from shallow to deep. In the deeper stratigraphy, a strike-slip-normal fault mechanism emerges. The relationship between burial depth and triaxial principal stress is subjected to linear regression, resulting in the proposal of a simplified model for vertical in-situ stress. The hyperbolic regression algorithm was employed in order to derive both the envelope and median formulas for lateral pressure coefficient (k values). The k value displays discrete behavior along the vertical axis in shallow depths, gradually converging in deeper strata and ultimately stabilising at approximately 0.65 with increasing depth. A comprehensive examination of the k value substantiates the efficacy of the simplified in-situ stress model along the vertical axis, offering profound insights into the vertical interrelationships and evolving patterns of the triaxial principal stresses. The mean gas content in the study area was found to be 11.89 m³/t, exhibiting a general increase in depth, followed by a subsequent decrease. The pore pressure (P p) displays a discernible positive correlation with gas content. This study comprehensively elucidates the developmental patterns of the stress field, the simplified model of vertical in-situ stress, the attributes of the stress ratio (K H, k h, lateral pressure coefficient k), the characteristics of reservoir gas content, and the corresponding and transformative relationships between coupled geostress field parameters and gas content. The lateral pressure coefficient conversion depth, in-situ stress conversion depth, and gas inversion depth are delineated, accompanied by a detailed exposition of their definition process, physical significance, and interrelations. Within the study area, the lateral pressure coefficient conversion depth is estimated to range between 450 and 500 m, while the critical depth for in-situ stress conversion is approximately 670 m. Moreover, the critical depth for gas content conversion falls within the range of 700–800 m. It is noteworthy that the critical depth for deep coalbed methane within the Liupanshui coalfield has been identified as approximately 800 m. Subsequently, a vertical “in-situ stress-gas content mode” relationship model for coalbed methane development was formulated, thereby providing a structured framework for understanding the dynamic interactions between vertical in-situ stress and gas content.

In the development of coalbed methane (CBM), due to the generally low permeability of coal beds, effective permeability enhancement technology is needed to improve the extraction efficiency of CBM. Among them, low-temperature fracturing and permeability enhancement technology has been widely studied and applied. In this paper, we simulate the low-temperature environment in actual mining by applying low-temperature cold impact water saturation treatment to the coal body, in order to investigate the mechanical properties and seepage law of the coal body saturated with cold impact water at different temperature conditions. Negative pressure water-saturated device is used to saturate the specimen, after the specimen is completely saturated with water, it is put into the high and low temperature test chamber, and different specimens are impacted at room temperature, 0 ℃, −20 ℃ and −40 ℃, respectively. After the cold shock treatment of water-saturated specimens was completed, a triaxial percolation meter was used to carry out percolation test and triaxial compression test. The test results show that: cold shock treatment of water-saturated specimens will cause damage to the specimen, the development and expansion of internal cracks in the coal body, the specimen compressive strength decreases, and the permeability increases. And with the decrease of cold impact temperature, the permeability of the specimen gradually increases. The initial permeability of the specimen impacted at −40 ℃ was the largest, which increased by 202.9% compared with the normal temperature specimen.

Rock-breaking drilling using a self-rotating jet bit with a controllable speed can improve the efficiency of coalbed methane development using the water jet tree-type borehole technology. The viscous torque generated by filling silicone oil inside the bounded annular column of the bit can control the speed, but its characteristics are unclear. The rheological properties of silicone oil with different viscosities were quantitatively analyzed. The viscous torque at various rotational speeds and inner diameters was tested by a self-developed fluid-bounded annular column forced flow dynamics device. The flow state of silicone oil was elucidated, and viscous torque models were derived and discussed for applicability. The research findings are as follows: when the viscosity of silicone oil is below 5 Pa·s, the silicone oil can be approximated as a Newtonian fluid, however, at viscosities exceeding 5 Pa·s, the silicone oil exhibits a shear-thinning behavior that can be described by the Cross rheological model. The apparent viscosity of the Newtonian-type silicone oil is unchanged when it is forced to flow in the bounded annular column, thus its viscous torque increases linearly with its viscosity and rotational speed, and the growth rate is accelerated with the increase of the inner diameter, which is favorable for the rotational speed control under multiple pressure gradients. However, the shear stress of the Cross-type silicone oil with the shear rate shows a trend of increasing, decreasing, and then increasing, resulting in the existence of the peak in its viscous torque that is synergistically controlled by rotational speed and inner diameter, and the greater the viscosity of the silicone oil, the more the combination of rotational speed and inner diameter. To prevent a decrease in the viscous torque of the Cross-type silicone oil, leading to a loss of control over the bit speed, it is necessary to select the viscosity and inner diameter according to the speed control range. At 84% of the tested rotational speed and inner diameter combinations, the Cross-type silicone oil viscous torque is greater than that of the Newtonian-type silicone oil under the same conditions, suggesting that the former is better suited for rotational speed control at high pressures, and the latter is better suited for low pressures. Under the present experimental conditions, the forced flow of silicone oil is laminar, and the derived Newton-type and Cross-type viscous torque models have a high reliability with a maximum error of 14.3% under the inner diameters up to 14.5 mm and equal to 14.5 mm, respectively.

Due to the rapid changes in burial depth in steeply inclined reservoirs (SICR), there is a significant change in stress in the up-dip and down-dip directions within the drainage range of CBM wells, and the expansion of fracturing fractures is different from that of near horizontal reservoirs. Based on the field fracturing data of steeply inclined reservoirs in Fukang West Block of southern Junggar Basin, this study analyzed the bottom hole pressure and fracture morphology characteristics in the process of hydraulic fracture of steeply inclined reservoirs, studied the fracture propagation characteristics of steeply inclined reservoirs by using the finite element numerical method, and expounded the impact of dip angle (stress gradient) on the fracture propagation of coal reservoirs. The results show that according to the stress and fracture propagation characteristics in the up-dip and down-dip dip directions, steeply dipping reservoirs are divided into shallow-steeply dipping reservoirs, middle-steeply dipping reservoirs, and deep-steeply dipping reservoirs. The hydraulic fracture propagation of shallow-steeply inclined reservoirs (with vertical stress less than horizontal stress) can be divided into three stages: fracture propagation in the up-dip direction, fracture stopping propagation, and fracture propagation in the down-dip direction; the fractures in the middle-steeply inclined reservoirs (with the vertical stress in the up-dip direction is less than the horizontal stress, and the vertical stress in the down-dip direction is greater than the horizontal stress) first expand in the up-dip direction, and then the fractures begin to turn perpendicular to the dip direction along the boundary of the up-dip direction and where the vertical stress is greater than the horizontal stress; deep-steeply inclined reservoirs (with vertical stress greater than horizontal stress) fractures propagate perpendicular to the dip direction. As the dip angle of the reservoir increases, the propagation rate of shallow reservoirs increases in the up-dip direction, while the rate decreases in the down-dip direction; the fractures in the middle-steeply inclined reservoirs gradually propagated from along the dip direction to perpendicular to the direction. The difference in fracture propagation in up-dip and down-dip direction of steeply inclined reservoirs is mainly due to the difference in fracture pressure caused by stress changes at different burial depths, causing the fractures to first propagate along the dominant channel with low stress.

Coal rock has well-developed bedding and joint, strong brittleness, oil-wet surface, poor affinity with cement, and poor mechanical properties. Therefore, it cannot provide high-quality wellbore sealing, which further restricts the development of coal seam gas through subsequent hydraulic fracturing. In order to further improve the bonding quality of the coal rock-cement interface, the weakening mechanism of coal rock-cement bonding was studied in this paper firstly based on the properties of coal rock itself and the microscopic and macroscopic performance analysis tests. Then the interface enhancement approaches were proposed and a dual-affinity coal rock-cement interface agent GSK-II was prepared at last by surface modification of wollastonite partially, in which the modifier are KH570 and zinc stearate. The optimum preparation conditions were as follows: slurry concentration was 10 %, concentration of modifier KH570 and zinc stearate were 1 % separately, modification time was 50 min, and modification temperature was 60℃. The results showed that the coal rock-cement interface bonding strength was increased by 4.49 times after the amphiphilic interface affinity agent GSK-II was added into the drilling fluid, showing a significant interface enhancement effect. In addition, the results also indicated that the generation of solid particles accumulation zone in coal rock fractures and the hydrophobicity of coal rock surfaces were the main reasons for the deterioration of coal rock-cement interface bonding quality. The main ways to enhance the interface bonding effect are to improve the solidification and compactness of the solid particles accumulation zone, as well as to improve the hydrophilicity of coal rock surfaces. The results of the study provided theoretical guidance for improving the interfacial bonding quality of the wellbore in coalbed methane wells with developed fractures, and laid a solid foundation for the safe and effective implementation of subsequent volume fracturing and other mining technologies for coalbed methane wells, and also provided new ideas for the research and development of interface enhancers in this field in the future.

To reveal the enrichment conditions and resource potential of coal-rock gas in the Ordos Basin, this paper presents a systematic research on the sedimentary environment, distribution, physical properties, reservoir characteristics, gas-bearing characteristics and gas accumulation play of deep coals. The results show that thick coals are widely distributed in the Carboniferous–Permian of the Ordos Basin. The main coal seams Carboniferous 5# and Permian 8# in the Carboniferous–Permian have strong hydrocarbon generation capacity and high thermal evolution degree, which provide abundant materials for the formation of coal-rock gas. Deep coal reservoirs have good physical properties, especially porosity and permeability. Coal seams Carboniferous 5# and Permian 8# exhibit the average porosity of 4.1% and 6.4%, and the average permeability of 8.7×10−3 μm2 and 15.7×10−3 μm2, respectively. Cleats and fissures are developed in the coals, and together with the micropores, constitute the main storage space. With the increase of evolution degree, the micropore volume tends to increase. The development degree of cleats and fissures has a great impact on permeability. The coal reservoirs and their industrial compositions exhibit significantly heterogeneous distribution in the vertical direction. The bright coal seam, which is in the middle and upper section, less affected by ash filling compared with the lower section, and contains well-developed pores and fissures, is a high-quality reservoir interval. The deep coals present good gas-bearing characteristics in Ordos Basin, with the gas content of 7.5–20.0 m3/t, and the proportion of free gas (greater than 10%, mostly 11.0%–55.1%) in coal-rock gas significantly higher than that in shallow coals. The enrichment degree of free gas in deep coals is controlled by the number of macropores and microfractures. The coal rock pressure testing shows that the coal-limestone and coal-mudstone combinations for gas accumulation have good sealing capacity, and the mudstone/limestone (roof)-coal-mudstone (floor) combination generally indicates high coal-rock gas values. The coal-rock gas resources in the Ordos Basin were preliminarily estimated by the volume method to be 22.38×1012 m3, and the main coal-rock gas prospects in the Ordos Basin were defined. In the central-east of the Ordos Basin, Wushenqi, Hengshan–Suide, Yan'an, Zichang, and Yichuan are coal-rock gas prospects for the coal seam #8 of the Benxi Formation, and Linxian West, Mizhi, Yichuan–Huangling, Yulin, and Wushenqi–Hengshan are coal-rock gas prospects for the coal seam #5 of the Shanxi Formation, which are expected to become new areas for increased gas reserves and production.

Abstract With the continuous advance of coal mining, the normal stress in front of coal seams will continue to increase, resulting in changes of internal structure and permeability of coal seams. During the continuous advance of mining face, the increase of vertical stress somewhere in front of coal seams may not be a transient process, but a gradual change process. Therefore, this paper carried out the seepage test of gas-containing coal under discontinuous loading axial stress. The stress, deformation and permeability of coal specimens were measured and recorded during the test, and the influence of discontinuous loading axial stress on the deformation, internal structure and seepage properties of coal specimens were discussed. On this basis, considering the influence of stress on the gas adsorption state, Klinkenberg effect and other factors, combined with Shi-Durucan permeability model, a new permeability model considering the dynamic adsorption state of coal specimens was developed.

Abstract The coal-rock reservoir exhibits a dual porous medium characteristic, where fractures are the primary contributor to permeability, while pore structure influences the gas adsorption properties of coal rock. Gas adsorption induces swelling in the coal matrix, leading to a reduction in fracture width and subsequently causing decreased permeability and reduced well production. Investigating the impact of geological characteristics of coal-rock on gas adsorption and desorption properties can enhance our understanding of the patterns governing changes in coal-layer production. This study focused on the 3# coal seam in China's Qinshui Basin as its research subject. It involved an analysis of mineral composition, physical properties, gas content, and pore structure characteristics to explore the adsorption traits of different gases and conduct experimental studies on variations in gas adsorption and desorption capabilities under diverse conditions. The research findings suggest that the coal rock in the study area is primarily characterized by micropores and small pores, with well-developed larger pores and fractures. The pore connectivity is somewhat limited, and the predominant pore size ranges from 100 to 200 nm. The average permeability measures 0.198 × 10–3 µm2, while the mean specific gas content stands at 21.7 m3/t. Analysis of the isothermal adsorption curve reveals a substantial increase in adsorption when pressure falls below 3.5 MPa due to a steep slope; as pressure continues to rise, there is a gradual upward trend in adsorption until reaching 8 MPa, after which point adsorption increases slowly and stabilizes. Results from binary gas adsorption–desorption experiments indicate low desorption levels and rates for CO2 components compared to relatively higher desorption amounts and rates for CH4 components. Furthermore, it was observed that CO2 has a displacement effect on CH4; higher CO2 concentrations are more conducive to CH4 release and CO2 storage.

Abstract In coalbed methane (CBM) development, it is imperative to evaluate the reservoir’s potential and identify the favorable areas to achieve higher production. This paper presents a novel quantified model inspired by the reservoir hydrodynamic heterogeneity. Treating the groundwater hydrodynamic zones as the computation units, the maximal information coefficient (MIC) and the geodetector model (GDM) were applied to measure the correlation between reservoir parameter and average daily gas production. An evaluation index system was then established, and its weight vector was obtained from a game theory model which couples the MIC scores with the GDM q-values. Taking the Gujiao mining area in the northern Qinshui Basin as a case study, the proposed model demonstrates a reliable classification of reservoir potential in alignment with the prior studies. The result indicates that the proposed model provides an insight into the relationship between CBM production and the reservoir heterogeneity, e.g., the distinction of hydrodynamics leads to the importance variation of the primary reservoir parameters and results in the uneven CBM production. Moreover, the model offers a quantified measurement of the correlation between reservoir heterogeneity and CBM production, and eliminates the subjective influence from the conventional methods.

Abstract Coalbed methane (CBM), a current global legislative priority for climate change mitigation, is an unconventional and eco-friendly clean source of energy that is considered a veritable alternative to conventional fossil fuels. Despite its overwhelming advantages, CBM evaluation studies of Nigerian coals have received little or no attention. To bridge the gap in knowledge, we have for the first time in Jangwa-Shankodi and Lafia-Obi, described the potential of harnessing CBM for its gainful utilization in Nigeria using some coal deposits in its north-central region as a case study. The gas contents of the coals were determined empirically by taking account of their ultimate and proximate properties. Other coal parameters such as fuel ratio and vitrinite reflectance (R o (%)) have also been computed and discussed. Proximate analyses of the studied coal samples show moisture contents that vary between 2.28 and 2.56%, whereas, volatile matter yield is placed in the range of 29.98–30.34%. Ash yield ranges from 7.83 to 8.64%. Fixed carbon content varies from 55.97 to 56.30%. Variation in fuel ratio shows a restricted range from 1.72 to 1.87. All the coal samples were found to be low in sulphur (

The liquidation of coal mines and the need to ensure Ukraine’s energy independence raise the issue of methane production from abandoned mines or mined-out horizons. Over the 250 years of coal mining in Donbas, hundreds of mines have been closed, creating man-made reservoirs filled with gas or water-gas mixtures. The gas from the mine workings migrates to the surface due to the newly formed fractures in the rock mass, posing a threat to communications and facilities. Over the past decade, a number of field works have been carried out within the mined-out areas of mines and laboratory studies of gas mixtures from coal-bearing massifs, isolated workings and mine waters in the Donets basin. Mined coal seams at mines form complex multi-level systems in the rocks, which may consist of two or more mined horizons. Depending on the thickness of the mined-out coal seams and the lithological characteristics of the underlying rocks, the newly formed man-made reservoirs can increase their vertical dimensions by an average of 1.5 to 2.5 times compared to the coal seam, i.e. in some cases reach up to 5.0 to 7.0 m. The mined-out space of operating mines is a new man-made reservoir suitable for accumulation of gaseous hydrocarbons. The active processes of gas migration in the waste space are indicated by the components of the gas mixture represented by helium, hydrogen and hydrocarbon gases. According to their genetic origin, the gases in the waste space of operating mines can be classified as biogenic, deep horizon gas and atmospheric gas. When mining the massif and creating an anthropogenic reservoir, the gas component is renewed over time and conditions are created for degassing the waste space. For optimal use of such zones, it is advisable to use a specific regime, namely the alternation of degassing and a rest period, which will allow filling the reservoir with gas. Determination of the mode of an anthropogenic collector is individual and based on monitoring of changes in indicators according to gas chromatography, which will ensure a long period of safe gas utilisation.

Abstract Gas saturation is a critical parameter for the selection and development of coalbed methane, as well as a key indicator reflecting the challenges in coalbed methane development and productivity evaluation of coalbed methane wells. As one of the significant factors influencing gas saturation, gas content plays a vital role in comprehensively investigating coal pore properties to fully comprehend the process and conditions of methane adsorption and desorption. In this study, 3# and 15# coals from Qinshui Basin, China was selected as research subjects. The experimental evaluation encompassed an examination of composition, pore characteristics, permeability characteristics of coal, rock mechanical parameters while discussing the impact of temperature and pressure on coal's adsorption and desorption capacity. The mineral characteristics analysis revealed that vitrinite is the main component with varying percentages and reflectance values in both 3# and 15# coal seams. The gas content and methane concentration in the 15# coal seam are higher than those in the 3# coal seam. The relationship between gas content within a coal seam and burial depth depends on achieving a balance between positive pressure effects caused by overburden stress exertion on gases trapped within pores under high pressures during burial history versus negative temperature effects due to cooling during geological processes over time. Predictions were made regarding deep-coal gas content which holds significant implications for accurately understanding variations in desorption behavior along with optimizing fracturing engineering.

Accurate description of micro and nano pores in coal reservoir plays an important role in evaluating the reservoir and gas production capacity of coalbed methane, we used 6 continuous samples of high rank coal in Daning-Jixian area on the eastern margin of Ordos Basin as the research object, and combined with high pressure mercury injection, low temperature N2 adsorption and low pressure CO2 adsorption experiments to characterize the pore structure characteristics. The aim of this study is to have an in-depth understanding of the full-size pore size distribution and explore the influencing factors of coal reservoir pore structure. The results show that the pore volume and specific surface area of coal sample in the study area have obvious differences with the pore size distribution, and the contribution rate of coal sample micropores to pore volume and specific surface area is significant, especially the diameter less than 1.5 nm micropore provides storage space for most of the adsorptive gas. The contribution of mesoporous and macroporous to pore volume and surface area is relatively small, which is not conducive to coalbed methane seepage. The vitrinite content of coal samples in the study area is positively correlated with pore volume and specific surface area, which contributes significantly to pore development. The relationship between inertinite content and pore volume and surface area is not obvious. With the increase of Mad, more adsorption pores are developed in coal samples, and pore volume and specific surface area are negatively correlated with Ad, indicating that the increase of Ad will lead to the decrease of pore volume and specific surface area.

In recent years, great breakthroughs have been made in the exploration and development of natural gas in deep coal-rock reservoirs in Junggar, Ordos and other basins in China. In view of the inconsistency between the industrial and academic circles on this new type of unconventional natural gas, this paper defines the concept of “coal-rock gas” on the basis of previous studies, and systematically analyzes its characteristics of occurrence state, transport and storage form, differential accumulation, and development law. Coal-rock gas, geologically unlike coalbed methane in the traditional sense, occurs in both free and adsorbed states, with free state in abundance. It is generated and stored in the same set of rocks through short distance migration, occasionally with the accumulation from other sources. Moreover, coal rock develops cleat fractures, and the free gas accumulates differentially. The coal-rock gas reservoirs deeper than 2000 m are high in pressure, temperature, gas content, gas saturation, and free-gas content. In terms of development, similar to shale gas and tight gas, coal-rock gas can be exploited by natural formation energy after the reservoirs connectivity is improved artificially, that is, the adsorbed gas is desorbed due to pressure drop after the high-potential free gas is recovered, so that the free gas and adsorbed gas are produced in succession for a long term without water drainage for pressure drop. According to buried depth, coal rank, pressure coefficient, reserves scale, reserves abundance and gas well production, the classification criteria and reserves/resources estimation method of coal-rock gas are presented. It is preliminarily estimated that the coal-rock gas in place deeper than 2 000 m in China exceeds 30×1012 m3, indicating an important strategic resource for the country. The Ordos, Sichuan, Junggar and Bohai Bay basins are favorable areas for large-scale enrichment of coal-rock gas. The paper summarizes the technical and management challenges and points out the research directions, laying a foundation for the management, exploration, and development of coal-rock gas in China.

Abstract Coalbed methane (CBM) recovery is attracting global attention due to its huge reserve and low carbon burning benefits for the environment. Fully understanding the complex structure of coal and its transport properties is crucial for CBM development. This study describes the implementation of mercury intrusion and μ-CT techniques for quantitative analysis of 3D pore structure in two anthracite coals. It shows that the porosity is 7.04%–8.47% and 10.88%–12.11%, and the pore connectivity is 0.5422–0.6852 and 0.7948–0.9186 for coal samples 1 and 2, respectively. The fractal dimension and pore geometric tortuosity were calculated based on the data obtained from 3D pore structure. The results show that the pore structure of sample 2 is more complex and developed, with lower tortuosity, indicating the higher fluid deliverability of pore system in sample 2. The tortuosity in three-direction is significantly different, indicating that the pore structure of the studied coals has significant anisotropy. The equivalent pore network model (PNM) was extracted, and the anisotropic permeability was estimated by PNM gas flow simulation. The results show that the anisotropy of permeability is consistent with the slice surface porosity distribution in 3D pore structure. The permeability in the horizontal direction is much greater than that in the vertical direction, indicating that the dominant transportation channel is along the horizontal direction of the studied coals. The research results achieve the visualization of the 3D complex structure of coal and fully capture and quantify pore size, connectivity, curvature, permeability, and its anisotropic characteristics at micron-scale resolution. This provides a prerequisite for the study of mass transfer behaviors and associated transport mechanisms in real pore structures.

Spontaneous gas and coal combustion represent primary disasters threatening the safety of underground coal mines. Achieving the collaborative governance of the two disasters and enhancing the ability to prevent and mitigate mine disasters are technical challenges faced by high-gas/outburst mines. CO2 has become the primary choice for collaborative disaster governance because of its efficient control of the oxidation process of residual coal in goaf, enhanced coalbed methane (ECBM) recovery, and the goal of “2030 carbon peak and 2060 carbon neutralisation”. Therefore, this study adopted summary and engineering verification methods. Firstly, the basic physical and chemical properties of CO2 were analysed, and the three mechanisms of action of liquid CO2 for preventing coal spontaneous combustion (CSC), namely, “CO2 adsorbed and hindered oxidation reactions, absorbs ambient heat and reduces ambient temperature, and reduce the oxygen concentration in the goaf and inhibiting gas explosion”, and the six mechanisms of action of liquid CO2 ECBM recovery, namely, “pressure fracturing, low-temperature frostbite, physical extraction and chemical corrosion, low-viscosity permeability, phase change pressurisation, and competitive adsorption”, were summarised. Second, the effect was verified by the field application of liquid CO2 CSC emergency prevention and control at the Qinggangping Coal Mine and the engineering test of liquid CO2 ECBM recovery in the Shuanglong Coal Mine. Finally, based on the application status of liquid CO2 in coal mines, a new model of “liquid CO2 prevention and control of CSC and enhancing coalbed methane recovery comprehensive disaster reduction technology” is proposed. The results of the emergency prevention and control of liquid CO2 CSC show that CO2 sinking drives CH4 out of the roadway, avoids the accumulation of CH4 near the fire area, and achieves explosion suppression. The concentrations of C2H2 and C2H4 in the mine decreased rapidly to 0. No open fire or severe combustion occurred in the mine, and the fire area was effectively controlled. After the ventilation of the mine was restored, the isolated and closed 42108 working face was injected with liquid CO2 again. The CO concentration of the inlet and return air along the channel gradually decreased to zero, and the fire area of the working face was further controlled. The engineering test of liquid CO2-ECBM recovery showed that the dominant seepage range was 1215 m from the injection hole, and the dominant diffusion range was 2530 m from the injection hole. The average CH4 flow rate in the field extraction test was more than three times that of the original area. Through two field cases, long-distance liquid CO2 prevention and control of CSC and an ECBM recovery technical framework were proposed, which are of great significance for further improving mine disaster prevention and mitigation.

Liquid CO2 enhancing coalbed methane recovery (CO2-ECBM) is an effective and intrinsically reliable gas drainage technology. Injection of liquid CO2 into coal seam has the dual effect of increasing the permeability of the coal and rock and strengthening the recovery of gas, which is manifested primarily as “pressure cracking, low temperature frostbite, physical extraction and chemical corrosion, phase change pressurization, low viscosity permeability, competitive adsorption”. In this paper, the acidification and corrosion of CO2-H2O-coal was studied in physical and chemical extraction by experimental test and comparative analysis. The liquid CO2 acidification reference group and the variable group experiment were designed. On the basis of the pH value of the aqueous solution, the content of major elements and minerals in coal, the minerals involved in chemical reaction, and their specific gravity were deduced. Variation in pore volume, specific surface area, and pore fractal characteristics were quantitatively and qualitatively analyzed. The experimental results show that the higher the pressure, the higher the content of carbonic acid dissolved in water and the amount of H+ ionized by carbonic acid. The longer the reaction time, the greater the mineral content involved in the chemical reaction, and the H+ in the water sample is consumed in large quantities. The elements of Na, K, Ca, Mg, Al, Si, S, P, and Ti decreased with increasing pressure, and the maximum decreases were 0.004 %, 0.024 %, 1.095 %, 0.028 %, 0.220 %, 0.304 %, 0.006 %, 0.003 % and 0.029 %, respectively. The decrease in Ca element was the largest, indicating that Ca-bearing minerals participate in the reaction. Calcite, kaolinite, and illite were the main minerals involved in the chemical reaction of CO2-H2O-coal. The pores (d > 100 nm) and transition pores (10 < d < 100 nm) in the sample were further developed, and the pore volume increased significantly, forming a good gas migration channel. In addition, the number of new micropores (2 < d < 10 nm) increases, the specific surface area increases significantly, and the complexity of the pores increases, forming a good reservoir.

Abstract The coalbed methane (CBM) productivity is directly determined by the fracture permeability during hydraulic fracturing, which is regulated by the distribution of proppants. The proppant may be unevenly distributed in the fracture because of variables like the architecture of the fracture and the characteristics of the sand‐carrying fluid. This study used two types of random functions to produce different ununiform distributions of proppant clusters in large‐scale fractures, with the aim of investigating the effect of these distributions on the overall permeability of the fracture. A model of fluid‐structure coupling is proposed. The closure of large‐scale fractures under in‐situ stress is analyzed using solid mechanics and the penalty function; the CBM flowing in proppant clusters and the high‐speed channel between them is simulated using Darcy's law and the Navier–Stokes equation, respectively; and the overall permeability of fractures is computed using the fluid pressure drop throughout the fracture and the fluid flowing velocity in the fracture's outlet. Since most CBM flows along high‐speed channels between the proppant clusters, the simulated findings show that the overall permeability of fractures with an uneven distribution of proppant clusters is significantly higher than that of the proppant cluster itself. As CBM becomes more discretely distributed, the proportion of CBM flowing within the proppant cluster continuously drops. As the permeability of the proppant cluster increases, the volume ratio of proppant clusters decreases, and the distribution of proppant clusters becomes more discrete, the overall permeability of the fracture continuously increases.

There are various forms of multilateral horizontal wells for developing coalbed methane, and the role of cleats in the development process is unclear. It is necessary to investigate the impact of the discrete cleat distribution in coal seams and the multilateral horizontal well configuration on gas well productivity. Based on the density and orthogonal characteristics of face and butt cleats in coal seams, the low density, medium density, and high density discrete cleat systems in coal seams are constructed using random methods. Combined with four different forms of multilateral horizontal wells, namely equal-length type, spindle type, staggered type, and dumbbell type, a physical model for developing coalbed methane using multilateral horizontal wells is constructed. The stress sensitive model of coal matrix and cleat system is established considering the effective stress change of coal seams and the matrix shrinkage effect in the development process. The desorption of coal-bed methane is calculated using Langmuir theorem, and a development model of compressible coal-bed methane flowing in the coupling of coal matrix, cleat system and multi branch horizontal wells is established. Furthermore, the influence of the cleat density and the configuration of multilateral horizontal wells on the development of coal-bed methane is studied. The results show that the discrete cleats in coal seams can greatly increase the drainage area of multilateral horizontal wells in a short period of development time, but are only limited to the cleats directly connected to multilateral horizontal wells and surrounding matrix areas. The parts that are not connected to multilateral horizontal wells require longer development time, which is also an important reason for gas wells to achieve peak production in a short period of time and quickly reduce production. The drainage area controlled by equal-length multilateral horizontal wells is the largest, while the drainage area of staggered type, dumbbell type, and spindle type decreases sequentially. When the cleat density is the same in the coal seams, the daily peak production and cumulative production within 20 years of the equal-length multilateral horizontal wells are higher than those of the other three types of multilateral horizontal wells, which can achieve better development results. By increasing the angle between the main and secondary wellbore of multilateral horizontal wells, the development effect of equal-length multilateral horizontal wells becomes much better, and the peak daily production of spindle multilateral horizontal wells is significantly improved. The peak daily production of staggered and dumbbell multilateral horizontal wells is more sensitive to the number of branches. The number of branches in spindle multilateral horizontal wells should not be less than eight, while the number of branches in the dumbbell multilateral wells should not be more than six.

To achieve CO2 storage in organic-rich rocks such as coal and shale, the influence of H2O generated by organic matter and co-occurring CH4 and N2 cannot be neglected. Based on the molecular model of coal and kerogen established using Materials Studio, and verification of CH4 isothermal adsorption from 20 to 100 oC, the competitive adsorption between CH4、CO2、N2 and H2O is discussed. Both the coal and shale kerogen molecular models show similar relative adsorption capacities, namely H2O > CO2 > CH4 > N2. Competitive adsorption is more obvious in small pores with a greater apparent inhibiting effect of H2O on the gases. The adsorption of CO2, CH4 and N2 decreases to zero at 75 ℃ in the kerogen model. A positive correlation is shown between the charge transfer and the adsorption capacity, and the adsorption onto carboxyl group occurs indicate that H2O has the highest adsorption preference. The oxygen-containing functional group is the dominant adsorption site for H2O, with the carboxyl group being the best adsorption site. The hydroxyl group is the optimal site for all gases, while all lower than H2O. The adsorption heat released are of H2O>CO2 >CH4 >N2 sequences, which is consistent with the change in the amount adsorbed.

Abstract The influencing mechanism of impact loads on the pore morphology of high‐rank coal has been extensively investigated since mining safety is greatly determined by the ensuing state of gas occurrence. In this work, we propose a combined use of a scanning electron microscope and Image Pro Plus software to examine the impact‐induced changes in pore characteristics. Impact loads of 0, 28.46, 51.8, and 58.7 MPa were applied to the coal samples in various directions (parallel/vertical/45° oblique). The results show that the pore connectivity of coal samples is enhanced following the impact load, and the number and diameter of pores are significantly increased on the whole. Surface porosity and roundness of the coal body first rise and then fall as the impact load increases. Following the impact load, surface porosity and roundness of the coal body significantly increase in the vertical and oblique bedding directions, while decreasing in the horizontal bedding direction.

Abstract As the mechanization of the CBM extraction process advances and geological conditions continuously evolve, the production data from CBM wells is deviating increasingly from linearity, thereby presenting a significant challenge in accurately predicting future gas production from these wells. When it comes to predicting the production of CBM, a single deep-learning model can face several drawbacks such as overfitting, gradient explosion, and gradient disappearance. These issues can ultimately result in insufficient prediction accuracy, making it important to carefully consider the limitations of any given model. It’s impressive to see how advanced technology can enhance the prediction accuracy of CBM. In this paper, the use of a CNN model to extract features from CBM well data and combine it with Bi-LSTM and a Multi-Head Attention mechanism to construct a production prediction model for CBM wells—the CNN-BL-MHA model—is fascinating. It is even more exciting that predictions of gas production for experimental wells can be conducted using production data from Wells W1 and W2 as the model’s database. We compared and analyzed the prediction results obtained from the CNN-BL-MHA model we constructed with those from single models like ARIMA, LSTM, MLP, and GRU. The results show that the CNN-BL-MHA model proposed in the study has shown promising results in improving the accuracy of gas production prediction for CBM wells. It’s also impressive that this model demonstrated super stability, which is essential for reliable predictions. Compared to the single deep learning model used in this study, its prediction accuracy can be improved up to 35%, and the prediction results match the actual yield data with lower error.

The research on the geochemical characteristics and genesis of coalbed methane (CBM) is of great significance to the formation and resource exploration-development. In order to investigate the genesis and geochemical characteristics of CBM in the Yuwang Block in eastern Yunnan, the gas samples from six typical CBM wells in the area were collected, and the composition determination, carbon isotope and rare gas isotope tests were carried out. The genesis of CH4, N2 and other gases in coal seam were systematically analyzed. Combined with the hydrogeological environment, the isotope variation of gases and their controlling factors during the CBM drainage process in Yuwang Block were investigated. The results shown that, the volume fraction of CH4 in the gas produced from CBM wells in the Yuwang Block averaged 73.95%-92.90%, and those of ethane, CO2 and N2 were 0.20% - 0.40%, 0.05% - 1.05% and 6.15% - 25.32%, respectively. In addition, helium was only detected on the first day of gas production, while hydrocarbons with a carbon atom number greater than 2 were not detected. The drying coefficient (C1/C1 ~ 5) of coalbed methane was 0.999 5 - 0.999 7, which belonged to high mature dry gas. The δ13C value of CH4 was −36.7‰ - −27.6‰, which was an organic matter thermogenic gas. The δ13C value of CO2 was −19.1‰- −6.6‰, with the main distributed from −18.0‰ to −14.3‰, which was of organic origin. The volume fraction of nitrogen averaged 12.63%, with relatively high content, and its φ(N2)/φ(Ar) value was much larger than 84, dominated by organic genesis. The average content of argon was 0.06%, much larger than 0.017%, dominated by atmospheric genesis. The volume fraction of helium averaged 0.02%, φ(3He)/φ(4He) was 0.29×10−8 - 19.6×10−8, with the main distributed from 2.00×10−8 to 9.38×10−8, the ratio of φ(3He)/φ(4He) to atmospheric helium was 0.01 ~ 0.09, which was typical shell source helium, and the variation trends of φ(4He) and φ(20Ne) were consistent with φ(4He)/φ(20Ne). The alkane isotope values of the produced gas shown a tendency to become progressively lighter as the increasing discharge time and gas purity. The study concluded that the “drying and lightening” of CBM in Yuwang Block was the result of the comprehensive influence of gas desorption, diffusion and water dissolution.

Desorption rates have an important influence on coal seam gas emergence patterns, the time to gas and the service life of coal bed methane wells. As the depth of the coal seam increases temperature and pressure have a significant control on methane adsorption, but relatively little attention has been paid to the effect of temperature and pressure on desorption rates. To investigate the effect of temperature and pressure on the desorption rate of coalbed methane, isothermal adsorption/desorption experiments were carried out with the same sample at different temperature and pressure conditions to obtain adsorption amount-time data at different equilibrium pressures. It is shown that the desorption rate at different pressures decreases exponentially with time. The desorption rate constant, the relative initial desorption rate and the median desorption time can reflect the change of desorption rate from different perspectives, where the desorption rate constant and the relative initial desorption rate increase with increasing temperature and pressure, and the median desorption time decreases with increasing temperature and pressure. Combined with the temperature/pressure gradient of the Baode Block in the Ordos Basin, it can be seen that the desorption rate is controlled by both temperature and pressure at shallower depths of 1000 m, and increases with depth; the pressure effect gradually decreases with depth between 1 000 and 1 735 m, while the temperature effect remains obvious.

It is of great significance to reveal the law of fracturing fracture propagation and influencing factors in coalbed methane (CBM) reservoirs for the formulation of fracturing technology and the efficient development of CBM resources. In this paper, the data of core drilling, well logging, downhole observation, fracturing construction and microseismic monitoring in Shizhuangbei CBM block, Qinshui Basin, China, are used to systematically analyze the hydraulic fracturing fracture propagation law and influencing factors. The research results show that clean water fracturing fluid is mainly used in the study area. According to the change in construction pressure, the fracture curves can be divided into four types: descending, stable, ascending, and fluctuating. Hydraulic fracture strikes are mainly N37°–55°W and N42°–70°E, with lengths varying between 69.5 m and 157.5 m and heights of 35 m to 68.5 m. In the type I stress state(σv>σH>σh), the fracturing fractures tend to expand vertically, and most fracturing curves are descending or stable. In the type II in-situ stress state(σH>σh>σv), the propagation direction of fracturing fractures is relatively single, and most of them are vertical fractures of a single shape. The width of the fracture network is small. Under the type III in-situ stress state(σH>σv>σh), the fracturing fractures expand along the horizontal direction, and the fracturing fractures have more complex shapes. The principal stress difference coefficient (λ)is positively correlated with the length of the fracture network and negatively correlated with the width. For fracturing fracture lengths >90 m, the λ is higher than 0.3. The hydraulic fractures can be communicated, penetrated, or captured by natural fractures. The effect of communication fracturing is better, and most coalbed methane wells have the characteristics of high and stable production. The extension length of the penetrated fracturing fractures is limited, and most of the captured fracturing fractures overlap with joints. The gas production effect of penetrated and captured fracturing wells is poor. With the increase of the proportion of primary and cataclastic coal thickness, the length of the fracture network gradually increases and the width gradually decreases. For fracturing fracture lengths >110 m, the proportion of primary and cataclastic coal thickness is higher than 40%. The research results provide a theoretical basis and geological guarantee for coal seam fracturing reconstruction.

Abstract The methane in the coal seams of abandoned mines is a valuable natural gas resource. However, the ultra-low permeability of coal seams restricts the extraction of coalbed methane. The liquid nitrogen fracturing technology is a novel approach suitable for enhancing the permeability of coal seams in abandoned mines. The ultra-low temperature could potentially facilitate the growth and propagation of pores and fractures in coal seams. In this study, we observed inconsistent alterations in coal properties measured by multiple instruments at different scales, whether in dry or wet coal specimens. This suggests that the mechanisms influencing the pore structure due to LN2 treatment differ across various scales in dry and wet coal specimens. For dry specimens, heterogeneous thermal deformation and freezing shrinkage exhibited opposing effects during LN2 treatment. Thermal stress-induced micro-fractures might counteract the freezing contraction of micropores in coal matrices, preventing a significant decrease in coal macropores and fractures. In wet specimens, the effects of LN2 treatment on wet coal specimens were predominantly controlled by frost heaving. However, due to low water saturation, LN2 treatment had negligible effects on coal micropores, even in the presence of local frost heaving. In field applications, water migration from smaller to larger pores could further diminish the impact of LN2 treatment on micropores.

With the development of the coalbed methane industry and the requirements for the integration of unconventional resource exploration and development, the current exploration of coalbed methane is gradually advancing from the favorable area stage to the sweet spot stage. However, limited by the stage of exploration and development or the degree of data possession, most of the current area selection evaluation systems do not take into account the fracability of coal reservoir and the recoverability of coalbed methane. Evaluation results are not effective in guiding development well location selection or infill wells. Based on the data of more than 100 coalbed methane parameter wells and development wells, this paper analyzes the resource conditions, reservoir fracturing improvement and coalbed methane recoverability of the No.3 coalbed methane development in Shizhuangbei Block, Qinshui Basin. An evaluation model was built with the gray fixed weight clustering method, and the sweet spot of ​​the coalbed methane project was evaluated, in an effort to provide a basis for the deployment of new wells and infill wells in the block. It was used coal seam gas content and coal thickness to reflect coal bed methane resource conditions; it was comprehensively considered the in-situ stress environment and rock mechanical properties to construct the reservoir fracability parameter, and then evaluates reservoir fracturing improvement; it was used the proportion of original structure coal and fragmented coal , temporary-reservoir ratio and original reservoir permeability to reflect the recoverability of coalbed methane. Each parameter is graded by the word clustering method, and the comprehensive goodness of each point (each well) is calculated and sorted, and finally the sweet spot for coalbed methane development is divided. The evaluation results show that the central part with the comprehensive goodness value >65 is the sweet spot for further development in the study area.

Coalbed methane (CBM) development and underground coal gasification (UCG) are important sources for coal-based natural gas production in China, and coal and CBM resources are abundant in the inclined coalbed development area of the Xinjiang foreland thrust belt. To deeply analyze the feasibility of coordinated development of CBM and UCG in inclined coal seams, the existing key technologies of CBM and UCG and their significances for coordinated development of CBM- UCG was systematically analyzed, the advantages, the technical routes, major problems and future research directions of coordinated development of CBM and UCG in inclined coal seams were also elaborated, the major problems faced and the direction of future research were proposed, and the following understanding was obtained. ① The coordinated development of CBM-UCG under the “CBM development dredging effect”, “UCG thermal desorption effect”, and “UCG mining pressure releasing effect” can form a virtuous cycle of mutual promotion. ② The coordinated development technology routes was proposed, such as vertical wells + inclined well along coal seam with “first drainage and then gasification”, multiple inclined wells along the coal seam with “simultaneous drainage and gasification”, directional L-typed CBM wells + UCG wells along the coal seam direction with “simultaneous gasification and drainage”, UCG wells along inclined wells in the lower coal + directional L-typed CBM wells in the upper coal seam with “first drainage, then gasification, and then drainage again”, and the “well factory” arrangement of complex well type. ③ The coordinated development of CBM and UCG faces theoretical issues such as weak theoretical foundation research on geological constituency evaluation, unclear expansion range of UCG thermal action under the condition of fracture network, and the undetermined range of rock movement and pressure relief in the UCG process of inclined coal seams. It also faces the engineering issues such as coordinated development of CBM-UCG “well factory” drilling technology, coordinated development of CBM wells and UCG wells production system, coordinated development of CBM and UCG wells geodynamic measurement and control, and the sealing and high-temperature-resistant protection of CBM wells. ④ It is necessary to strengthen the study on the evaluation of geological site selection for the coordinated development of CBM and UCG in inclined coal seams, the theoretical research on the development dynamics, and the pioneering experimental study on engineering coordination technology, so as to ensure that the coordinated development is safe, orderly, controllable and efficient.

This research developes an innovative thermodynamic coupling model for gas-bearing coal, improving temperature change simulations during coalbed methane desorption. The model distinctively integrates adsorption/desorption heat effects, free gas expansion, dynamic diffusion, the Klinkenberg effect, and moisture influence, offering a more comprehensive perspective of thermodynamic behavior. Comparisons with empirical data and previous models demonstrate that the predicted temperature changes closely match experimental results, indicating superior accuracy. The investigation finds a 23.51 % increase in desorption temperature as gas pressure rises from 0.4 MPa to 1.2 MPa, with temperature changes following the sequence CO2 > CH4 > N2, in the ratio ΔT(CO2): ΔT(CH4): ΔT(N2) = 1.76: 1.35: 1. Adsorbed gas desorption and free gas expansion are recognized as the primary drivers, especially near 0.5 MPa, where adsorbed gas contributes nearly 70 %. Sensitivity to variables such as gas pressure, adsorption heat, and permeability diminishes over time, with moisture exerting minimal impact. The study highlights a close thermodynamic connection between temperature changes and gas outbursts, proposing temperature variation as an reliable indicator for predicting and evaluating outburst risks. These findings enhance understanding of coalbed methane desorption and provide new theoretical foundations for efficient resource development and disaster prevention.

Although significant amounts of methane are present in anthracite coal seams, coalbed methane resources cannot be extracted effectively and quickly. This study mainly focused on investigating the pore system and methane adsorption capacity to clarify the storage of coalbed methane. Anthracite coal samples from the Anzenan coalbed methane block in China were collected, and pore characterization methods (low-pressure N2 adsorption, mercury injection experiments, and scanning electron microscopy (SEM) observations) and methane isothermal adsorption experiments were conducted. The results showed that few mesopores and nanoscale macropores were present in the anthracite coal samples. The volume of the 2–300 nm pores in these coal samples obtained from the N2 adsorption experiment was lower than 0.01 cm3/g. SEM observations also revealed that only a small number of mesopores and nanoscale macropores could be seen, and most of these pores were isolated. In terms of the methane isothermal adsorption data, it was found these anthracite coals have a large methane adsorption capacity, and the Langmuir volume ranges from 19.5 to 28.4 cm3/g, with an average of 22.2 cm3/g. With increasing ash yield, the Langmuir volume decreased linearly, indicating that methane molecules were mainly adsorbed in the organic matter of coal. As methane is mainly adsorbed in the micropores of coal organic matter and there are few mesopores and nanoscale macropores in the organic pores in coal, there are not enough tunnels to transport the adsorbed methane molecules to the outside. Thus, it is difficult to extract coalbed methane from anthracite. This study reveals the impact of pore system limitations on the storage and extraction of coalbed methane in anthracite coal. The findings can be applied to the extraction of coalbed methane from anthracite coal seams worldwide.

Guizhou Province has many multi-layer, thin-thick coal seams; however, complex geology, incomplete reservoir characterization, and sweet-spot selection technology prevent large-scale coalbed methane (CBM) development. This study evaluates the CBM reservoir properties within the Dahebian block using logging data, coal sample analysis, and well-testing data and develops a 3D static reservoir properties model to analyze their spatial and vertical propagation. A sweet spot evaluation model was established using a multi-level fuzzy method based on 9 parameters extracted from a 3D static reservoir properties model. The coal measure has 22 coal seams, and seams >2 m thick have 2 or 3 thin non-coal layers intercalated. Coal seams 1#, 7#, and 11# are thin to thick, deeply buried, widely distributed, and have high gas content and saturation. Undeformed and cataclastic coal predominates the coal seam 1# and 7#, whereas coal seam 11# is dominated by cataclastic and granulated coal. The southern and central parts of coal seam 7# and 11# have less tectonically deformed coal (TDC). Coal seams 1# and 7# have low permeability relative to seam 11# and are localized, while coal seams 11# have high permeability, are extensively distributed, and contain substantial gas concentrations. Comparative analysis of evaluation scores and CBM production statistics shows that high scores indicate sweet spots for CBM development. Sweet-spot potential was classified as high, medium, and low. Scattered sweet spots are found in single layers, while combined development (1# + 7#+11#) reveals a wider high-potential area in the south-central region. This area, featuring deep, thick coal seams, high permeability, gas saturation, reservoir pressure, and low TDC proportion, indicates significant development potential. This study validates CBM development statistics, identifies future development areas, and guides the development of geologically complex Guizhou CBM.

In order to study the spatio-temporal evolution law of coal seam permeability in the process of CO2-ECBM, a CO2-ECBM fluid-solid-thermal multi-field coupling numerical model is established by using COMSOL Multiphysics numerical simulation method based on the geological conditions of Liliu Mining Area as the engineering background. The CO2-ECBM process is numerically simulated by five-point well layout method, and the spatio-temporal evolution of coal permeability with CO2 injection is discussed. The results show that gas pressure, CO2 injection and shrinkage/expansion deformation of coal matrix are the key factors affecting permeability evolution. After the adsorption of CO2, the expansion deformation of coal matrix plays a leading role, occupying the pore space, resulting in the decrease of permeability, the mean permeability in the range affected by CO2 decreased by 40%. Along the CO2 injection well to the extraction well, the permeability is less and less affected by CO2, it shows a monotonic upward trend. The mean permeability increased by 14% outside the influence range of CO2.

The deposition of coal fines in fractures can reduce the fracture conductivity and restrict the efficient and stable development of coalbed methane wells. A visual physical simulation experiment scheme for coal fines migration and blockage removal in fractures was designed. The variation of coal fines particle deposition area and sedimentary morpho-logical characteristics at different positions of fractures were analyzed and the dynamic law of coal fines migration and deposition was revealed based on the visual physical simulation experiment of coal fines migration in fractures. Using the visual physical simulation experiment of coal fines blockage removal in fractures, the influence of plugging time and flow rate on the area of deposited coal fines blockage removal in fractures was investigated and the dynamic law of coal fines starting and blockage removal was found. The experimental results show that the coal fines particles have different aggregation states in different directions and positions of the fractures. The deposition area of coal fines particles gradually decreases from the entrance to the two ends of the vertical main migration direction and the main migration direction, and the deposition area of coal fines particles gradually increases along the main migration direction in the branch channel. The morphology of coal fines deposition at the fracture throat, branch channel and main channel is eagle’s mouth shaped, layered and streamlined, respectively. The reason is that the resistance of different positions of the fracture to the coal fines-containing fluid is different, resulting in different deposition morphology of coal fines at different positions. At the same flow rate, with the increase of blockage removal time, the blockage removal effect of coal fines is better, but the area of blockage removal in the early stage is large, and the area of blockage removal in the later stage is small. The blockage removal effect of coal fines at the fracture throat is obviously better than that in the branch channel. The reason is that the loose and easy blockage removal coal fines particles will be deblocked first, and as time goes on, the remaining unblocked coal fines particles need a larger starting flow rate. The larger the flow rate is, the larger the area of coal fines blockage removal at the fracture throat and branch channel is. The reason is that increasing the flow rate can enhance the fluidity of coal fines particles.

Accurate determination of gas content in deep coal mine is the premise for the prevention and control of gas disaster, as well as the efficient development and utilization of coalbed methane. Traditional coring technology of coal seam is generally open-ended and requires to obtain the amount of gas loss during the coring process by using estimation methods, making it difficult to ensure the accuracy and validity of the in-situ parameters of coalbed methane. Based on the academic idea of “in-site condition-maintaining coring”, the in-situ pressure- and gas-maintaining coring technology for deep coal seam was proposed, and the in-situ pressure- and gas-maintaining corer for deep coal seam was developed. The strength verification for corer outer tube, pressure-maintaining chamber and key weak parts were conducted based on three-dimensional numerical simulation. Meanwhile, the pressure-maintaining capacity of controller was measured and analysed relied on the self-developed pressure-maintaining coring laboratory simulation test platform, and the reliability of corer was verified through field tests in coal mine. The results shown that, the self-developed corer had the advantages of strong pressure-maintaining capacity, long pressure-maintaining time and stable anti-disturbance performance. The equivalent stress of the corer under internal fluid pressure of 20 MPa and torque of 1000 N·m was 121.1 MPa, which was much smaller than the yield strength of the material and met the strength design requirements. The equivalent stress of corer under the pressure of 20 MPa was 63.9 MPa, which met the strength design requirements. The corer can operate continuously and stably at the pressure of 19.4 MPa, which met the demand for gas testing in most of deep coal mines. The field test shown that, the pressure-maintaining controller of the pressure- and gas-maintaining corer closed well, with 100% of coring rate in the field. The research provides a theoretical, technical and equipment foundation for the accurate determination of gas content in deep coal seams, which is of great significance for the prevention and control of coal mine gas disasters and the exploration and development of coalbed methane.

In order to study the effect of water on the competitive adsorption of CH4/CO2 and mixed gases in coal, the self-developed multi-gas competitive adsorption experimental system of coal containing gas was used to conduct the research on the single component adsorption of CH4 and CO2 by coal with different water content. The experimental results show that: Water does not change the basic law of the isothermal adsorption curve of CH4 and CO2, and under the same conditions, water does not affect the ordering of coal's adsorption capacity for a single component of gas, and the adsorption capacity of coal for CO2 is always greater than that of CH4. Under the same conditions, the inhibition rate of water on CH4 is greater than that of CO2 adsorption capacity, indicating that the inhibition degree of water on coal's adsorption of weakly adsorbent gases is greater. The research on the effect of water on the competitive adsorption of mixed gas shows that: when the proportion of gas injected into the coal remains unchanged, under the same adsorption equilibrium pressure, the total adsorption of mixed gas decreases with the increase of water content, and the adsorption amount of CH4 and CO2 after adsorption equilibrium decreases with the increase of water content in the coal. When the water content is unchanged, the greater the gas adsorption equilibrium pressure under the same gas injection ratio, the greater the adsorption amount of CH4 and CO2 after adsorption equilibrium. The volume fraction of CO2 in the free phase is always lower than that of the gas source, while the volume fraction of CH4 is always higher than that of the gas source. Under different conditions, the values of CO2/CH4 selection coefficients are greater than 1, ranging from 4.8 to 5.4, and the adsorption affinity of coal for CO2 is greater than that of CH4. The selection coefficients of CO2/CH4 decrease with the increase of water content of coal samples under the same gas adsorption conditions. This study further improves the theoretical analysis of factors affecting coal gas adsorption, and provides a theoretical basis for engineering practice for underground gas injection and gas extraction technology.

The coalbed methane resource under goaf is rich, but has not been effectively developed for a long time. Hydraulic fracturing technology stands as an effective means to augment coalbed methane recovery. The extraction and re-compaction of overlying coal seam will directly affect the expansion behavior of hydraulic fractures in the underlying coal seam. Though the large-scale (300 mm×300 mm×300 mm) true triaxial hydraulic fracturing experiments, the mechanical and acoustic emission response characteristics of coal were analyzed under different levels of loading and unloading stress perturbations. The damage variable T was proposed to characterize the degree of coal damage, and the relationship between damage and the initiation and expansion patterns of hydraulic fractures was elucidated. The results revealed that, the damage induced by vertical stress loading in the underlying coal significantly exceeded that in the unloading stage. When the vertical loading stress was below 11 MPa, the coal remained in an elastic stage with minimal damage. Loading between 11~15 MPa corresponded to the yielding stage, witnessing a substantial increase in damage. Loading between 15~18 MPa led to the strengthening stage, the pores and fractures of coal were gradually compacted. Damage variables T can effectively characterize the degree of internal damage of coal. When T=Tc, the internal damage of coal was comparable to that of a coal that has not disturbed by loading and unloading stress.Tc is the damage variable of coal without loading and unloading stress disturbance. When T＞Tc , the coal exhibited a stress-damaged state, with higher values of T corresponding to increasing damage levels. Conversely, when T＜Tc, the coal demonstrated a stress-compacted state, with smaller values of T indicating higher compaction degrees. The degree of stress damage in coal was negatively correlated with the fracture pressure, a high degree of damage made coal more prone to fracture, and it was favor to form the primary hydraulic fractures near the wellbore, which was conducive to hydraulic fracturing. The degree of compaction of coal was positively correlated with fracture pressure. The high degree of compaction weakened the effect of horizontal stress difference on hydraulic fracture expansion, and the hydraulic fracture near the wellbore was more developed, which hindered the formation of primary hydraulic fractures. Based on the research results, the principle of hydraulic fracturing construction scheme optimization for underlying coal seam in goaf was formulated and applied in the field. The hydraulic fracturing ability of the optimized scheme was significantly improved.

China has abundant coalbed methane (CBM) resources, and most of them are low-permeability and tight reservoirs, with generally low production rate and small recovery factor. Existing technologies face great challenges to meet the demand on CBM in China. It is desirable to develop new methods to improve the production rate and enhance recovery factor. In addition to physical stimulation methods such as hydraulic fracturing and open-hole cave completion, the use of chemical methods to improve physical properties of coal reservoirs has also been a hot research topic in recent years. Coal reservoir acidification and oxidation technology can promote desorption of gas and enlarge permeability of reservoir. But for different coal rank coal reservoirs, the acidification and oxidation agents need to be optimized and their performance evaluated. Laboratory experiments are conducted to compare and analyze the physical properties coal samples from Baode, Mu’ai, and Xinjiang blocks, including coal rank, texture, macroscopic characteristics, quality, porosity, permeability, element, and mineral composition. The optimal concentration of hydrochloric acid is determined through pre-dissolution experiment of coal powder in acid solution. Then a five-factor and three-level orthogonal experiment for acid solution optimization is designed and performed by using Design-Expert software, which identifies the sensitive factors affecting the dissolution. For the coal samples in Baode, Mu’ai, and Xinjiang blocks, the oxidant types and the corresponding acidification and oxidation agent systems are optimized. Applying these acidification and oxidation agent systems to coal samples from Baode, Mu’ai, and Xinjiang blocks, the change of porosity, permeability, and wettability are compared and analyzed. Finally, through numerical simulation, the gas production is predicted for acidification and oxidation in typical well group in Block Mu’ai. Results show that the acid solution has the best dissolution at a concentration of hydrochloric acid of 3 mol/L to 4 mol/L; Top factors played in the experiment are soaking time, acid type, soaking temperature, coal sample type, and acid concentration, in descending order of importance; The optimal oxidant is a hydrogen peroxide solution with a concentration of 3%; the mixed acidification oxidant formula in Baode block is 10% HCl + 2% CH3COOH + 2% HF + 3% H2O2; The optimal mixed acidification oxidant formula in Mu’ai block is 8% HCl + 2% CH3COOH + 4% HF + 3% H2O2; the optimal mixed acidification oxidant formula in Xinjiang block is 12% HCl + 1% CH3COOH + 1% HF + 3% H2O2; The higher the coal rank, the greater the HF content in the optimal acidification oxidant system. Both acidification and oxidation improve the porosity and permeability of coal samples to some extent, and the improvement in low-rank coal is more significant than that in high-rank coal. Acidification and oxidation have different effects on the wettability of coal: Acidification increases the hydrophilicity of coal, whereas oxidation reduce the hydrophilicity of coal; and the hydrophilicity of coal samples treated by the optimized acidification and oxidation system is weakened. Reservoir simulation results show that acidification and oxidation lead to a recovery factor of 64.64% after 10 years of production, which is 19.72% higher than that without acidification and oxidation. The advantage of acidification and oxidation is 0.97% after 18 years of production. However, the acidification and oxidation saved 8 years of production time to achieve a close final recovery factor, which greatly reduces the operating costs. The optimized acidizing oxidation agent systems for CBM reservoirs with low, medium, and high ranks improved the desorption and permeability of the target reservoirs, and increase well production and recovery factor. This research provides technical support for stimulation practices of CBM reservoirs in the aforementioned blocks in China, as well as similar coal reservoirs in the world.

Coalbed methane (CBM) is one of the realistic and reliable strategic supplementary resources of conventional natural gas in China, and intelligent calibration of CBM production capacity is of great importance for developing the natural gas industry. Actual geological and production data were collected and preprocessed for CBM wells in a CBM block in the Qinshui Basin, Shanxi Province. For CBM wells that have been exploited for a long time, a calculation formula based on production well history was proposed for single well productivity based on formation pressure in static data, daily gas production, and bottom-hole flow pressure in production data. The accuracy of the calculation formula was determined using the maximum daily gas production curve of CBM wells. Using the preprocessed production and reservoir data, an intelligent algorithm was developed for CBM productivity calibration based on deep neural network (DNN), support vector regression machine, and random forest for predicting the productivity of a single CBM well. A comparison of the prediction results of three machine learning models was performed, and the effect of production data for different discharge days as input parameters on model accuracy was examined. Based on the machine learning model with the best prediction effect, the importance of dynamic parameters (daily gas production, daily water production, and bottom-hole flow pressure in the early stage of drainage and production) and static parameters (coal seam depth, porosity, permeability, coal seam thickness, and gas content) to CBM was explored. The findings revealed that the fluctuation coefficient for 100 CBM wells is approximately zero, and the fluctuation range is small, indicating high calculation accuracy. The average coefficient of determination of CBM well productivity calibrated using the three machine learning models is 0.828, and the coefficient of determination of the DNN model is the highest, attaining 0.923, with mean absolute error and root mean square error values of 194.44 and 214.66 m3·d−1, respectively. With increasing days of production data collection in the early stage, the coefficient of determination clearly increases, and then the growth trend slows down and finally becomes stable. Daily gas production, daily water production, production pressure difference, gas content, and permeability are important factors affecting coalbed methane productivity in the early stage of drainage and production. Productivity is highly sensitive to dynamic and static parameters in the early stage of drainage and production,and these two types of parameters contribute 48% and 52%, respectively, to the capacity prediction model.

Purposes Increasing the permeability of coal reservoirs is a key technology to improve the recovery rate of coalbed methane, and in-situ thermal injection mining is an effective method to enhance coalbed methane production. Methods In order to explore the change rule of coal reservoir permeability under the coupling of heat, fluid, and solid, pyrolysis seepage experiments of anthracite with different burial depths and temperatures were conducted, and theoretical analysis and research were conducted on the experimental results. Findings The results showed that: 1) Under three-dimensional effective stress, the permeability of pyrolysis anthracite varies with temperature and pore pressure in a "V" shape, with a significant rebound phenomenon, which decreases with the increase of burial depth. When the pore pressure is less than the critical pore pressure and the temperature is lower than 70 ℃, the permeability of the coal body mainly depends on the slippage effect. When the pore pressure is greater than the critical pore pressure and the temperature is higher than 70 ℃, the permeability mainly depends on thermal expansion and the opening degree of pore pressure on the fracture, and the impact of thermal stimulation on the permeability is much greater than that of pore pressure. 2) The critical pore pressure is between 1 and 1.5 MPa, the influence of slippage effect on permeability gradually decreases with the increase of temperature, and the gradient of influence reduction increases with the increase of burial depth. 3) The fracture opening coefficient increases with the increase of temperature and burial depth, but the higher the temperature, the smaller the change in the sensitivity of permeability to pore pressure under different burial depths. Conclusions These research results further enrich the theory of in-situ thermal injection mining of coalbed methane, and provide valuable data reference for enhanced permeability of coalbed methane.

In order to explore the fracturing characteristics of coalbed methane wells in the Tunlan block, the No.2 coal seam in the Tunlan block, Xishan, Taiyuan was taken as the research object. The fracturing characteristics of the coal seams from multiple scales was studied through geological cataloguing, macroscopic characterization of coal samples and CT (Computed Tomography) analysis for four coal bed methane wells of XST-167, XST-168, XST-176 and XST-177, which were exposed at the coal mining face. The results shown that, the coal seam near the wells in the study area were mainly distributed with “X” type fractured fractures consisting of diagonally intersecting fractures, and there were “T” type fractured fractures near the XST-177 coalbed methane well. Collision and friction of quartz sand with fractured fracture walls produced pulverized coal, which filled in the fracture and hindered the output of coalbed methane. By comparing the drill holes exposed by the two coalbed methane wells of XST-168 and XST-177, it was found that the fracturing effect of the XST-177 coalbed methane well was better and more conductive to the output of coalbed methane. Most of the coals near coalbed methane wells were fragmented and crushed coal, and hydraulic fracturing destroyed the original structure of coal, which reduced the hardness of coal and significantly increased the cracks. Embedded quartz sand can be observed on some of the coal samples, which was mainly concentrated on the bedding surface, indicating that the quartz sand, after being pressed into the coal seam, mainly extended into the seam along the horizontal fracture, which was consistent with the direction of the maximum principal stress. By CT scanning technology, the coal samples affected by fracturing (fractured coal) and not affected by fracturing (normal coal) were scanned. It was found that, the fractures with a width greater than 100 μm in the fractured coals of T1 and T2 accounted for 58.8% and 48.5% of the total fracture volume, and the numbers of the fractures was 23407 and 19679, respectively. In normal coal T3, the fractures with width greater than 100 μm only accounted for 1.7% of the total fracture volume, and the number of fractures was only 3504. The width of the fractures in T1 and T2 was wider and the number of fractures was more than that in T3, which indicated that the width and number of fractures in the coal sample were significantly increased by the fracturing action, and the pores and fractures in the fractured coal were more developed.

In order to compare and analyze the on-site desorption performance and numerical simulation desorption performance of low coalification reservoir coal core, the on-site gas content of coal core of a coalbed methane (CBM) well in Xinjiang was measured, and a numerical model of coal core in undersaturated reservoir with adsorbed gas is established, and based on this, the loss gas content calculation method was analyzed. The results show that the loss gas, desorption gas and residual gas contents calculated by the desorption numerical model of the unsaturated coal core (adsorbed gas saturation 54.77%, 77.51%, and 99.79%, respectively) were close to the corresponding results measured in the field (error

The southern Qinshui Basin is rich in coalbed methane resources, but the geological and engineering conditions are complex, the adaptability of Fanzhuang mature technology popularization in neighboring areas is poor, and the development of coalbed methane scale benefits faces severe challenges. In order to solve the problems of coalbed methane in the southern Qinshui Basin, such as “difficult well location deployment, long drilling cycle, easy collapse of naked eye wells, and low single well production”, a number of key technologies such as integrated geological engineering technology have been carried out, and a number of key technologies have been formed, such as “three properties” coal reservoir evaluation, controllable horizontal well drilling and completion, segmented fracturing, and dredging-type drainage, and field tests and promotion have been carried out. The research results show that through the organic combination of geology and engineering, the geological model provides technical support for engineering technology optimization, and engineering practice continuously corrects the geological model to improve the accuracy; the coal seam drilling rate of horizontal well is 95%, the drilling complexity of single well is reduced by 40% on average, the production capacity reaches 90%, and the average daily production of single well is more than 8 000 m3.

In order to further improve the development effect of coalbed methane wells, a variety of seismic attributes of the target coal seam are extracted, and production distribution samples of developed wells are established. On this basis, through the fitting analysis of all seismic attributes and yield samples, the index weight method is used to calculate that the cumulative contribution rate of coherence and root mean square amplitude to yield is more than 85%, so the two seismic attributes of coherence and root mean square amplitude are selected. Finally, through the fitting correlation coefficient between the two attributes and the yield, the comprehensive attribute prediction formula was established, and the favorable development units were divided. The correlation between forecast results and developed well production is enhanced. The results show that development units can be accurately divided through well data and seismic attribute optimization technology.

The expansion of hydraulic fractures in coalbed methane (CBM) reservoirs is key to effective stimulation, making it essential to understand fracture propagation and its influencing factors for efficient resource development. Using petrological characteristics, logging data, microseismic monitoring, and fracturing reports from the Baode Block on the eastern Ordos Basin, this study systematically investigates the geological and engineering factors influencing hydraulic fracture propagation. The real-time monitoring of fracture propagation in 12 fractured wells was conducted using microseismic monitoring techniques. The results indicated that the fracture orientations in the study area ranged from NE30° to NE60°, with fracture lengths varying between 136 and 226 m and fracture heights ranging from 8.5 to 25.3 m. Additionally, the fracturing curves in the study area can be classified into four types: stable, descending, fluctuating, and falling. Among these, the stable and descending types exhibit the most effective fracture propagation and are more likely to generate longer fractures. In undeformed–cataclastic coals and bright and semi-bright coals, long fractures are likely to form. When the Geological Strength Index (GSI) of the coal rock ranges between 60 and 70, fracture lengths generally exceed 200 m. When the coal macrolithotype index (Sm) is below 2, fracture lengths typically exceed 200 m. When the difference between the maximum and minimum horizontal principal stresses exceeds 5 MPa, fractures with length >180 m are formed, while fracture heights generally remain below 15 m. From an engineering perspective, for the study area, hydraulic fracturing measures with a preflush ratio of 20–30%, an average sand ratio of 13–15%, and a construction pressure between 15 MPa and 25 MPa are most favorable for coalbed methane production.

Multi-stage fracturing in Horizontal well increases the permeability of coalbed methane by generating multiple fractures. However, the heterogeneity of coal reservoirs is a crucial factor that cannot be ignored in the study of multiple hydraulic fracture propagation. Therefore, we established a two-dimensional model for multiple hydraulic fracture propagation based on the combined finite-discrete element method (FDEM) and assigned a Weibull distribution function to the heterogeneity of the physical parameters of the cohesive elements in the model. The objective was to simulate and study the fracture propagation law of multi-cluster fracturing in horizontal wells in heterogeneous coal reservoirs. The research results indicated that: 1) as the heterogeneity of the coal reservoir weakened, the deflection angle of the main fracture increased. More secondary fractures were generated in the coal reservoir, leading to significant discontinuity. 2) The fracturing disturbance area was always concentrated at the tip of the main fracture, with a double wing shape. However, the fracturing disturbance areas at the tips of multiple main fractures could easily converge, with a square shape; 3) It is recommended to use a moderate injection rate and increase the perforation spacing appropriately when hydraulic fracturing is carried out in coal reservoirs with a heterogeneity coefficient m=5.

This study focuses on coalbed methane (CBM) wells in high-ranking coal seam as the research subject. Considering the influence of effective stress and matrix shrinkage, a comprehensive permeability calculation model for CBM reservoirs is established. Based on this model, the variations in pressure and permeability during well production are quantified. By integrating static geological parameters, a finely classified classification of CBM wells is achieved using self-organizing map (SOM) neural network. Subsequently, an analysis of production dynamic characteristics and productivity differences among different types of CBM wells is performed, followed by providing drainage optimization suggestions. The results of SOM analysis show that 7,000 m3/d and 1,500 m3/d can be used as the production boundaries for the wells with different productivity in Block P. The daily gas production of exceptional well exceeds 7,000 m3/d, and the permeability remains relatively stable throughout the drainage process of this well. The daily gas production of the potential well ranges from 1,500 to 7,000 m3/d, and the permeability exhibits a significant decrease during the drainage process. The daily gas production of Inefficient well is consistently below 1,500 m3/d with moderate permeability variation. In addition to well location and structural geology, production variability is also influenced by the matching of reservoir conditions and drainage systems. This is primarily manifested in discontinuous drainage systems and rapid decline in bottom hole pressure (BHP) during early production. The analysis of drainage parameters indicates that in order to achieve optimal production from CBM wells, the BHP should exhibit an initial rapid decline followed by a slowly decrease during the early production period, with an average pressure drop ranging from 0.005 to 0.02 MPa/d. The research findings can offer technical guidance for the future advancement of CBM in the P Block.

Abstract Indirect fracturing in the roof of broken soft coal seams has been demonstrated to be a feasible technology. In this work, the No. 5 coal seam in the Hancheng block was taken as the research object. Based on the findings of true triaxial hydraulic fracturing experiments and field pilot under this technology and the cohesive element method, a 3D numerical model of indirect fracturing in the roof of broken soft coal seams was established, the fracture morphology propagation and evolution law under different conditions was investigated, and analysis of main controlling factors of fracture parameters was conducted with the combination weight method, which was based on grey incidence, analytic hierarchy process and entropy weight method. The results show that “士”-shaped fractures, T-shaped fractures, cross fractures, H-shaped fractures, and “干”-shaped fractures dominated by horizontal fractures were formed. Different parameter combinations can form different fracture morphologies. When the coal seam permeability is lower and the minimum horizontal principal stress difference between layers and fracturing fluid injection rate are both larger, it tends to form “士”-shaped fractures. When the coal seam permeability and minimum horizontal principal stress between layers and perforation position are moderate, cross fractures are easily generated. Different fracture parameters have different main controlling factors. Engineering factors of perforation location, fracturing fluid injection rate and viscosity are the dominant factors of hydraulic fracture shape parameters. This study can provide a reference for the design of indirect fracturing in the roof of broken soft coal seams.

Broken soft and low permeability (BSLP) coal reservoirs are widely distributed in China. However, due to its soft and broken structure and low permeability, the conventional vertical/horizontal well direct fracturing technology is not ideal for the enhancement of BSLP coal seams and the surface development of coalbed methane (CBM). The efficient development of CBM in BSLP coal reservoirs has been an important technical bottleneck restricting the large-scale development of CBM industry and the efficient treatment of coal mine gas control in China. Based on the systematic analysis of the characteristics of BSLP coal reservoirs and the problems existing in the surface development of CBM, the current technological progress in the enhancement of BSLP coal reservoirs and surface development of CBM were reviewed by taking horizontal well as the base well type and focusing on three different technical directions: indirect fracturing, stress relief and consolidation before fracturing. The CBM development technologies of indirect fracturing, including roof indirect fracturing, gangue indirect fracturing and hard coal stratification indirect fracturing were summarized. The stress release CBM development technologies using different stress release methods, such as hydraulic jet cavitation, gas dynamic cavitation, mechanical + hydraulic + induced instability coupling cavitation and hydraulic slit, were reviewed. Furthermore, the CBM development technology of first consolidation and then fracturing of BSLP coal reservoirs induced by microorganisms was also summarized. The exploration of indirect fracturing technology has accumulated a lot of engineering practice, and has achieved a good effect on enhancing the BSLP coal reservoirs in areas with suitable geological conditions. The exploration of new technology for enhancing BSLP coal reservoir represented by stress release has also made great progress, and has entered the stage of engineering tests and verification. According to the characteristics of BSLP coal reservoir and the new development principle, the horizontal well stress release technology has greater potential for reservoir reconstruction and better effect for CBM development. Based on the horizontal well stress release method, the development trend of BSLP coal reservoir enhancement and surface CBM development technology was forecasted in three aspects: expanding the stress release range, improving the development effect of CBM and achieving the co-production of coal and CBM. It is expected to provide reference for improving the stimulation effect of BSLP coal reservoir and increasing the production of CBM well in China.