The eastern margin of the Ordos Basin has emerged as a critical area for the exploration and development of deep coalbed methane （CBM）. However， the unclear distribution patterns and controlling factors of deep CBM in the Linxing area， particularly within the Nos.8+9 coalbeds， have impeded the efficient utilization of these resources. This study investigates the hydrocarbon generation， reservoir conditions， and the thermal， pressure， and geological factors influencing the accumulation of deep coalbed methane through an analysis of drilling， logging， seismic， and geological data. It examines the effects of thermal evolution， tectonics， and preservation on coalbed methane accumulation， clarifying the temporal relationship between key tectonic events and the accumulation of both coalbed methane and overlying tight sandstone gas， while highlighting the essential role of structural preservation in the enrichment of deep CBM. The findings indicate that： （1） The hydrocarbon generation and reservoir conditions in the Nos.8+9 coalbeds are adequate， with the coal-bearing source rocks undergoing a slow hydrocarbon generation phase during the Early to Middle Jurassic， followed by a rapid generation phase during the Late Jurassic to Early Cretaceous， resulting in the earliest formation of coalbed methane reservoirs in the Early Cretaceous. （2） Three phases of tectonic activity-Early to Middle Yanshanian （characterized by high-angle reverse thrusting）， Himalayan Period III （compressional twisting）， and Himalayan Period IV （extensional twisting）-have produced a structural pattern comprising step-faulted zones， low-amplitude uplift areas， and graben zones. The CBM reservoirs in the positive structural areas of the step-faulted zones and low-amplitude uplifts have been influenced by adjustments from the Zijinshan uplift and the tectonics of Himalayan Periods III and IV， while the negative structural areas of the graben zones have been modified solely by Himalayan Period IV， resulting in higher gas content in the graben zones compared to the positive structural units. （3） A model for the accumulation of deep coalbed methane influenced by fault adjustments has been developed， providing a foundation for the strategic deployment of coalbed methane resource utilization.
Breakthrough progress has been made in the exploration of deep-seated coal-rock gas in the Carboniferous Benxi Formation in the Yichuan area of the Ordos Basin， and a number of appraisal wells have gained high-yield industrial gas flow， which confirms that the deep-seated coal rock gas resources in this area have the potential for large-scale development. However， there are fewer systematic studies on the reservoir characteristics of deep-seated coal-rock gas in this area， and the laws of reservoir characteristics are not well understood. Based on this， this study selected the No.1 coal seam of the Benxi Formation as the research object， and systematically investigated the characteristics of the coal-rock-gas reservoir of the Benxi Formation in terms of lithology， physical properties， pore-fracture development， and gas-bearing properties by synthesizing the experimental data of core observation， scanning electron microscope analysis， and physical properties testing. Research results show： （1） The coal body structure of No.8 coal of Benxi Formation is dominated by primary structural coal， the macroscopic type is dominated by bright coal and semi-bright coal， the microscopic group is dominated by specular group， the ash content is low， the average value is 12.76%， and the maximal reflectivity of specular body is from 2.04% to 2.53%， and it is dominated by anemic and anthracite， which is at the high maturity gas generation stage. （2） The reservoir type of No.8 coal in Benxi Formation is dominated by intergranular pores， cytosolic pores， cast pores， pneumatic pores and fissures， and some of the pores are filled by clay minerals or calcite， of which the fissures include macroscopic cuttings and microscopic fissures； the pore fissures are mainly micropores， followed by microcracks； the specific surface area is dominated by micropores， followed by macropores. （3） The physical properties of the No.8 coal of Benxi Formation show low porosity， with porosity ranging from 4.22% to 4.96% and averaging 4.59%； permeability ranging from 0.02×10-3 μm2 to 3.48×10-3 μm2 and averaging 1.21×10-3 μm2， and the coal rock has good permeability in the stratigraphic state. （4） The adsorption capacity of No.8 coal of Benxi Formation is strong， with an air-dried basis Langmuir volume of 21.25–31.34 m3/t （averaging 27.61 m3/t） and a Langmuir pressure of 1.98–3.77 MPa （averaging 3.08 MPa）. The adsorption capacity of the coal rock has a negative correlation with the ash content， and a positive correlation with the maturity degree. The results not only provide quantitative evaluation indexes for the preferred selection of deep coal gas sweet spot in Yichuan area of Ordos Basin， but also reveal the new exploration direction of deep coal system unconventional gas reservoirs.
The Ordos Basin is a key area for coal reservoir development in China. The deep coal reservoirs of the Benxi Formation in the northeastern part of the basin exhibit significant thickness， making them favorable targets for deep coalbed methane exploration. Through core observation， coal quality analysis， and pore structure characterization of planar samples from the No.8 coal reservoir in the Benxi Formation， this study investigates the coal quality and distribution characteristics of deep coal reservoirs， elucidates their genetic mechanisms， and provides theoretical guidance for optimizing coalbed methane exploitation. The deep coal reservoirs in the Ordos Basin show strong planar heterogeneity. From the tidal flat-swamp to the lagoon-swamp depositional systems， ash content gradually decreases， while thermal maturity， sulfur content， and vitrinite-inertinite ratio increase with increasing distance from the proximal source area within the lagoon-swamp system. This indicates that the tidal flat-swamp coal reservoirs formed in a relatively oxidized environment with substantial terrigenous clastic input， whereas the lagoon-swamp system developed under deeper water columns and more reducing conditions influenced by marine transgression-regression cycles. Pore development in the tidal flat-swamp system is inferior to that in the lagoon-swamp system， with better connectivity observed in distal areas of the latter. Micropores （predominantly 0.6 nm in diameter） dominate pore volume， followed by macropores， suggesting micropores are the primary pore type. The deep coal reservoirs are synergistically controlled by terrigenous clastic input and thermal evolution. In the tidal flat-swamp system， clay mineral infilling from clastic materials degrades reservoir quality， while in distal lagoon-swamp areas， reduced clastic influence and higher thermal maturity enhance hydrocarbon generation， promoting gas pore formation and improving reservoir properties. Consequently， the distal lagoon-swamp system represents the most favorable zone for natural gas exploration in the No.8 coal reservoir of the Benxi Formation.
In recent years， the study of deep coal-rock gas has become a hot topic. However， research on the pore structure of deep coal-rock reservoirs in the Permian Longtan Formation in the Sichuan Basin is still relatively weak. To address this， taking the Well NT1 in the central Sichuan region as an example， deep coal-rock reservoir core samples were selected. Combined with experimental methods including coal petrophysical properties， geochemical characteristics， and pore structure analysis， it is shown that the deep coal structure in the central Sichuan region of the Sichuan Basin is primarily characterized by primary structures， with well-developed cleats， high organic matter content， good petrophysical properties， and overall superior coal quality conditions. Using a combination of micro-CT， scanning electron microscopy， gas adsorption methods， and high-pressure mercury intrusion porosimetry， a multi-scale quantitative characterization of the pore structure of deep coal-rock reservoirs was conducted. The results show that the storage space of the coal reservoir is mainly composed of pores and cleat fractures. The pores are predominantly semi-closed pores with one end sealed and the other end open. The organic pore surface area ratio is high， and micropores contribute significantly to the pore size distribution. The pore volume distribution is “dumbbell-shaped”， with micropores accounting for as much as 87% of the total pore volume and macropores accounting for 11%. The specific surface area of pores shows a "single-peak" distribution， with micropores making up 99% of the total. The development of nanoscale pores and microscale fractures in deep coal seams jointly controls the gas content characteristics of coal-rock gas. The initial findings suggest that the factors influencing gas content are primarily the coal quality and pore size distribution characteristics.
The Junggar Basin is a large Jurassic low-rank coal-bearing basin in the western China. The coal measures of the Xishanyao and Badaowan formations are thick and stably distributed， with the basin-wide coal-rock gas resource amount exceeding 3×10¹² m³. The well Caitan1H has achieved a major breakthrough， with a maximum daily gas production of 5.7×10⁴ m³. Aiming at the unclear problems of coal rock gas accumulation characteristics and en-richment laws， this paper conducts a comprehensive analysis from multiple dimensions such as coal seam quality， reservoir characteristics， and gas-bearing properties， and draws the following understandings： （1） The southeastern margin of the Junggar Basin has superior coal rock gas accumulation conditions. The Jurassic coal seams are widely distributed and thick， with good coal quality. The reservoir physical properties and adsorption capacity are medium to poor， and coal-rock gas resources are abundant. （2） The accumulation is controlled by multiple factors， including various gas source conditions， structural conditions， and preservation conditions. There are accumulation models such as exogenous fault-blocking type， exogenous anticline type， autochthonous pore type， stratigraphic pinch-out type， and exogenous fracture type gas reservoirs. （3） The enrichment law of coal-rock gas shows the characteristics of “better in the south than in the north， and better in the west than in the east” in planar distribution. The main controlling factors include coal quality， thermal evolution degree， sealing property of coal seam roof and floor， and hydrogeological conditions. （4） The volumetric method and volume method are used to estimate the coal rock gas resources in the weathering zone to 5 000 m of the whole basin. The resource amount in the area within 2 000 m shallow， such as Urumqi-Fukang， is 16 238.2×10⁸ m³； that in the 2 000~5 000 m range is 13 163.6×10⁸ m³. According to the favorable area optimization index system， areas such as Urumqi-Dahuangshan and Baijiahai are identified as favorable exploration blocks， with a total area of 2 630 km² and a predicted resource amount of 3 200×10⁸ m³， showing rich resources and favorable accumulation conditions.
With the great breakthrough of deep coal-rock gas exploration in central and western China， Turpan-Hami Basin， which is rich in coal resources， has been paid more and more attention. However， there is a lack of research on deep coal-rock gas in Turpan-Hami Basin， which seriously affects the exploration and implementation of coal-rock gas in the basin. Based on the distribution of coal-rock in the whole basin， combined with the analysis and comparison of maceral components and trace elements of coal-rock samples in the basin， the results show that： （1） The main layer of deep coal-rock gas exploration in the Turpan-Hami Basin is the second member of the Xishanyao Formation， especially the thick coal seam at the bottom of the second member， and the coal accumulation center is located in the northern part of the Taibei Depression. （2） Vitrinite is the main component of the maceral of the main coal seam， and the content of inertinite is high in some areas. Through the identification of the maceral facies， five types of coal facies are identified in the second member of Xishanyao Formation. （3） Based on the distribution range of trace element values of typical coal facies， the paleoenvironmental characteristics of different coal facies during the coal accumulation period are defined， and the coal facies distribution map of the main coal seam in the whole basin is established based on the distribution interval values of different sensitive trace elements. In Turpan Depression， the open water swamp phase and deep water forest swamp phase are mainly developed. （4） From the perspective of paleosedimentary environment and coal-forming plants， the hydrocarbon generation of coal rocks in different coal facies is analyzed， and it is pointed out that the coal-rocks in deep forest swamp facies and open water swamp facies have good gas potential. The research results provide effective guidance for the exploration target layer and selection zone of coal-rock gas in the Turpan-Hami Basin.
Currently， there is limited research on coal-rock gas in the Jurassic Kezilour Formation of the Kuqa Depression， with unclear geological characteristics and favorable accumulation models for coal-rock gas. To address these issues， this study utilized drilling， testing， and sampling data， combined with seismic data processing， well correlation analysis， sample observation， and gas experiments on core samples， to investigate the geological features of coal-rock gas， including their occurrence state and genesis types and favorable accumulation models in the coal-bearing strata of this block. The results demonstrate： （1） In the study area， the macroscopic coal types of the coal seams in the Kezilour Formation are dominated by semi-bright coals， characterized by very low ash content， medium to high volatility， and very low sulfur content. These are intermediate to low-rank coals with porosity of 6.53% and permeability of 0.68×10-3 μm2 in deeper coal seams. The pore types of coal seams are mainly mesopores， which are more conducive to the occurrence of free gas. （2） The coal-rock gas components of the Kizilnur Formation are mainly methane， with a dry coefficient of 0.95-0.99， indicating predominantly thermogenic gas with both autochthonous and external sources， occurring mainly as free gas and adsorbed gas in the coal seams. （3） The Neogene is the peak period of gas production in the Ke-4 coal seam of the Yiqikelike tectonic belt， as well as a critical period of fault activity and reservoir formation. Preservation conditions will be a key factor in the formation of coal-rock gas reservoirs. The gentle-slope zone and low-potential area formed by the structure are favorable locations for coal-rock gas exploration， and the coal thickness condition is a key factor affecting the abundance of coal-rock gas resources. Considering the lower maturity and relatively high adsorption capacity of the coal seams of Jurassic Kizilnur Formation in the Kuqa Depression， it would be more advantageous to choose high positions or gentle slope areas where thick coal seams are developed and free gas is enriched. Therefore， the northern gentle slope area with thick coal seams will be the focus of coal-rock gas exploration， while the formation mode of micro uplifts and fault-block platforms are the favorable formation modes for coal-rock gas exploration in the Kuqa Depression.
Deep coalbed methane （CBM） represents a critical new frontier for increasing natural gas reserves and production in China. Macrolithotypes govern the storage and production of CBM. This study focused on the No. 8 coal reservoir in the Benxi Formation of the Ordos Basin. Through vitrinite reflectance testing， maceral analysis， proximate analysis， CO₂ adsorption， low-temperature N₂ adsorption， and high-pressure mercury intrusion porosimetry， the pore structure characteristics and heterogeneity of deep coal reservoirs constrained by macrolithotypes were systematically analyzed. The study reveals that from bright to dull coal， vitrinite content decreases， ash yield increases， the specific surface area （CO₂-SSA） and pore volume （CO₂-TPV） of ultra-micropores gradually decrease， while the specific surface area （N₂-SSA） and pore volume （N₂-TPV） of micropores gradually increase， the pore volume of meso-macropores gradually decreases， and the cross-scale effects between pore structures relatively weaken. From bright coal to dull coal， the fractal dimension of ultra-micropores （D C） gradually decreases， the surface fractal dimension of micropores and transition pores （D N1） decreases， the pore structure fractal dimension of micropores and transition pores （D N2） increases， and the fractal dimension of meso-macropores （D M） is generally higher. D C is positively correlated with vitrinite content， CO₂-TPV， and CO₂-SSA， and negatively correlated with ash yield. D N1 is negatively correlated with inertinite content， ash yield， N₂-TPV， and N₂-SSA， while D N2 is positively correlated with these parameters. The heterogeneity of pores at different scales is influenced by the source of organic pores， mineral filling， and complex geological conditions in deep formations across macrolithotypes. In bright and semi-bright coals， the aromatic layer stacking densification and reduced interlayer spacing caused by high coalification promote ultra-micropore development and higher D C values. Endogenous fractures in bright and semi-bright coals provide more meso-macropore spaces. Semi-dull/dull coals dominated by durain and fusain exhibit cellular cavity pores and mineral-supported micropores with lower D N1. Complex deep geological conditions induce pore deformation， combined with mineral filling and supplementation， resulting in higher D N2 and D M values.
Multiple sets of thick coal rock are developed in the deep strata of Ordos Basin， which is a favorable target layer for coal-rock gas exploration breakthrough. Several well areas of Benxi Formation in the basin have obtained high-yield industrial gas flow， showing great development potential. In order to further clarify the genesis of coal-rock gas in Benxi Formation of Ordos Basin， based on the characteristics of molecular composition and stable carbon isotopes of coal-rock gas in Benxi Formation of Ordos Basin and， a comparative analysis was carried out with the tight gas of Benxi Formation and the shallow coalbed methane in the eastern margin of the basin. The research shows that the methane content of coal-rock gas， coalbed methane and tight sandstone gas is high， all of which are dry gas. The content of hydrocarbon components in coal gas is high， with an average of 94.14%， and the content of N2 is low， with an average of 0.63%. The methane content of coalbed methane in the eastern margin varies greatly， and the content of N2 is high， with an average of 7.66%. The carbon isotope values of methane in the coal-rock gas of the Benxi Formation are mainly distributed between -37.6‰ and -28.7‰， with an average of -32.7‰， and the carbon isotope values of ethane are mainly distributed between -27.0‰ and -19.9‰. The carbon isotope composition of methane in the coal-rock gas is similar to that of tight sandstone gas， but it is generally heavier than that of coalbed methane in the eastern margin. Desorption fractionation and hydrodynamic fractionation are the main factors causing the lighter carbon isotope of coalbed methane in the eastern margin of the basin. The carbon isotope composition of ethane in coal-rock gas is similar to that of coalbed methane in the eastern margin of the basin， but different from that of tight sandstone gas. Both coal-rock gas and coalbed methane in Hancheng in the eastern margin of the basin are coal-derived gas accumulated within the source. The tight sandstone gas mainly comes from the coal rocks of Benxi Formation， with some being affected by Type I and Type II1 mud shale source rocks of Benxi Formation.
In view of the unclear conversion process of free gas and adsorbed gas during the production of coal-rock gas， this paper focused on the 8# coal rocks of the Carboniferous Benxi Formation from 18 well cores in the Nalinhe， Mizhibei and Suide areas of the Ordos Basin. The research analyzed the variation characteristics of methane carbon isotopes during the desorption process of coal-rock gas， and revealed the dynamic changes in free gas/adsorbed gas ratio during the process of coal-rock gas production. Furthermore， combining the above research results with the characteristics of macerals， maturity， porosity and gas content of coal rock， the genesis of differences in the free gas/adsorbed gas ratios of coal-rock gas was discussed comprehensively. The results showed that the δ13C1 values of desorbed gas from 8# coal rocks gradually became higher with the increasing desorption time， shifting from -44.3‰ to -30.2‰ at the beginning to -25.6‰~-10.7‰ at the end， with a degree of enrichment of 12.6‰–22.5‰. Based on the variation characteristics of the δ13C1 values at different desorption time ranges， the δ13C1 desorption curves of coal-rock gas were divided into four types： （1） Type Ⅰ： δ13C1 initially remained relatively stable and then slowly became higher； （2） Type Ⅱ： δ13C1 initially kept unchanged， and then rapidly became higher to a certain extent and subsequently became slightly higher； （3） Type Ⅲ： δ13C1 continuously became higher； （4） Type Ⅳ： δ13C1 rapidly became higher to a certain extent and then became slightly higher. Furthermore， combining the carbon isotope fractionation mechanism during the methane migration， it was revealed that the desorption process of coal-rock gas consisted of three stages. The first stage： methane in a free state primarily undergoes Darcy seepage driven by pressure differential， with δ13C1 remaining relatively stable during this stage. The second stage： In the initial desorption period， methane included both free and adsorbed states， and as the desorption process continued， the pressure drop within the core sample enhances adsorption/desorption， with the proportion of adsorbed CH4 continuously increasing， causing δ13C1 to become progressively higher. The third stage： a small amount of residual adsorbed methane within the coal rock undergo slow desorption， which may be accompanied by diffusion driven by concentration differences， causing δ13C1 to become slightly higher. Among them， coal-rock gas with the Type Ⅰ and Type Ⅱ δ13C1 desorption curves exhibited relatively high free gas/adsorbed gas ratios due to the presence of the first desorption stage. In the Benxi Formation in Ordos Basin， the higher free gas/adsorbed gas ratios of 8# coal-rock gas indicated the greater gas contents， exhibiting a positive correlation with maturity and porosity of coal rock. Additionally， high-quality reservoir-cap combination （limestone-coal and mudstone-coal） can form pressure seals on the coal reservoirs， leading to high free gas/adsorbed gas ratios in coal-rock gas.
Deep coal-rock gas reservoirs in the Ordos Basin are characterized by high-salinity formation water， low water saturation and high gas saturation. During hydraulic fracturing， injected fluid is easy to invade coalbed， which restricts the development of coal-rock gas to further increase the production. The No.8 deep coal of Benxi Formation in Ordos Basin was selected， and the salinity sensitivity experiment by pressure decay method， soluble substance immersion experiment and thermal evolution-hydrogeological analysis were synthesized. We analyzed the genesis of high-salinity CaCl2 type formation water and quantitatively evaluated the permeability damage of different salt fractions on the coal rock. The study shows that： the high-salinity formation water in deep coal rock of the Ordos Basin mainly originates from the synergistic effect of the thermally evolved hydrocarbon drainage-driven primary water and the deep formation water extrusion from the karst layer. The proportion of Ca2+ and Mg2+ in the cationic fraction of formation water is as high as 16%-66%. The coal rock salinity sensitivity damage is significantly enhanced with the increase of salinity， up to 61.93%. The damage rate of divalent calcium and magnesium was much higher than that of monovalent sodium and potassium， which were 72.15%- 85.92% and 36.82%-45.40%，respectively. The brine with salinity lower than 20 000 mg/L can enhance the permeability， but the intrusion of high-salinity fluid is easy to trigger irreversible salinity sensitivity damage. Deionized water can dissolve a small amount of soluble salts and trace organic matter in coal rock. Based on the study， the countermeasures of using clear water fracturing fluid and flowback fluid softening are proposed to provide theoretical basis for reservoir protection and efficient development of deep coal rock gas reservoirs.
Aiming at the decay and failure of long-term conductivity of propped fractures in deep coal-rock fracturing， long-term conductivity test was carried out by the FCES-100 fracture conductivity test device to evaluate the influence of coal-rock environment （comparing steel plate and coal rock）， proppant grain size （40/70 mesh and 70/140 mesh）， proppant concentration （2.5， 5， 10 kg/m2） and stress conditions （30 and 40 MPa） on the long-term conductivity law. The attenuation and prediction of long-term conductivity of propped fractures under actual production conditions were carried out， and the evaluation of the decreasing production law of deep CBM horizontal wells was carried out in combination with actual production data. The study shows that： （1） the long-term conductivity under different conditions shows a trend of rapid decline followed by slowing down with time. In the first 40 hours of the test， the decline of flow conductivity under different conditions was more than 94%， and in the second 40 hours of the test， the difference of flow conductivity under different conditions tended to stabilize. （2） When the proppant particle size is 40/70 mesh， the conductivity under the steel plate condition is larger than that under the coal rock condition， and the opposite is true when the proppant particle size is 70/140 mesh. The hydration of coal rock has a relatively large effect on the embedding of proppant. （3） The reduction of proppant particle size can effectively reduce the effect of proppant embedding on the inflow capacity. （4） The increase of proppant concentration can effectively weaken the effect due to proppant embedding under coal rock conditions. （5） The reduction of proppant particle size can shorten the failure time of inflow capacity， and too low proppant concentration can lead to the significant shortening of the failure time of inflow capacity. （6） The production decay coefficient shows a slow decline， then a rapid decline， and then a gentle decline with the increase of mining time. The error of predicting the field cumulative production data with the exponential decay law is only 2.9%. The study on the evaluation of long-term conductivity of fractured propped fractures in deep coal rocks can help the optimal design and beneficial development of fracturing for deep coalbed methane.
Understanding dynamic desorption characteristics and seepage mechanisms in deep coalbed methane （CBM） reservoirs is critical for optimizing drainage strategies and enabling large-scale development. Taking the coal of the Benxi Formation in Ordos Basin as the object， the dynamic production behavior is analyzed and a mathematical model for desorption of adsorbed gas from continuous coal matrix and gas-water two-phase flow in discrete fractures. The model was solved using the finite element method. Based on simulation results， gas migration patterns during drainage were analyzed and desorption characteristics in water-saturated coal and their impact on gas production were discussed. （1） The sensitive pressure， turning pressure， and starting pressure of the CBM are 1.87 MPa， 4.77 MPa， and 7.15 MPa， respectively. （2） CBM desorption continues to expand from the near-wellbore region to the reservoir boundary. After 500 days （1.4 years） of production， the entire reservoir pressure declines below the critical desorption pressure. （3） After 1 725 days （4.7 years）， desorption efficiency transitions from low-efficiency to high-efficiency desorption， and gas production shifts from free gas dominance to primarily adsorbed gas contribution. （4） Daily gas production strongly correlates with desorption behavior within 100 m of the wellbore. Stabilizing near-wellbore desorption efficiency maintains stable gas production. The conclusions will provide theoretical support for the formulation of optimization measures of drainage and production system.
The deep CBM （coalbed methane） industry of Chine has ushered in an important period of development opportunities， and it is imperative to accelerate the efficient development technology of horizontal wells. In this study， based on the coal characteristics and logging response， drilling parameters， the K coefficient is established from the aspects of coalification degree， physical property， structure， and gas-bearing property， and the coal reservoirs of Benxi Formation in the eastern Ordos Basin is divided into three types. The K coefficient of class I reservoir is more than 2， which is composed of cataclastic bright coal， primary bright coal and cataclastic semi-bright coal. The contribution rate per meter of the class I reservoir can reach three times that of the class III reservoir. The cataclastic structures are superior to primary structures. The cataclastic coal generally has better drill ability， permeability and gas content， which has a high proportion in the Class I reservoirs. Comprehensively considering the geological conditions such as coal thickness， the drilling encounter rate of coal， and the fracturing intensity， it is clearly that class I reservoirs are the “black gold targets” for the development of CBM in the horizontal wells and are the main cause for productivity. The 1 500 m horizontal length， 500 m class I reservoir length， 4-6 t/m sand intensity are the lower limits of the economic development with 5.5×104 m3/d production. If the class I reservoir length exceeds 1 000 m， under the same horizontal length and fracturing intensity， the production of horizontal wells can economically increase with 7.0×104 m3/d. Based on the geology， structure and reservoir types， this paper summarizes the coal-rock sedimentary models into three types： high coalification + gentle structure， transitional coal-rock + micro-structure， and cataclastic coal + complex structure. The first two models are suitable for large-scale deployment of cluster horizontal well groups， fully utilizing geological reserves and releasing production capacity. The model of cataclastic coal + complex structure has huge gas-bearing potential， which will be the key target for increasing the production of horizontal wells in the future.The guidance of horizontal well is a key process control for enhancing the drilling encounter rate of “black gold targets”. This paper proposes that the drilling quality of horizontal wells can be identified according to the changes of K coefficient， and the drilling decision can be adjusted in time. This technology will promote the iteration of coal guidance technology to “black gold target” guidance technology， and help the high-quality development of deep CBM.
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