China boasts abundant deep coalbed methane （CBM） resources. Positive progress in the exploration in recent years has established CBM as a strategic replacement for current unconventional natural gas in the future. However， the commercial exploitation of deep CBM faces challenges of complex geological and engineering conditions. In this study， we investigate the geology of deep CBM in typical regions across China and review advances in relevant theoretical and technical study， proposing the prospects for the exploration and production of deep CBM. The results indicate that deep CBM reservoirs exhibit the geological and engineering characteristics of strong heterogeneity， enrichment in both free and adsorbed gas， and high plasticity compared to their shallow counterparts. Deep medium- to low-rank coal reservoirs provide substantial storage space dominated by primary plant tissue pores. In contrast， deep medium- to high-rank coal reservoirs contain micropores and fissures， with the former dominated by organic pores and the latter consisting primarily of cleats and exogenetic fractures. Over years of addressing technological challenges， SINOPEC has preliminarily developed a series of technologies for the selection and assessment of deep CBM target areas， sweet spot prediction， horizontal well drilling， and hydraulic fracturing with fractures effectively propped， which serve to provide effective support for breakthroughs achieved in deep CBM exploration. It is recommended to focus on the accumulation patterns， sweet spot identification， production technologies and policies， and production rules of deep CBM in future study. Additionally， it is advisable to develop efficient drilling and completion technologies for horizontal wells in thin coal seams， along with technologies for fracturing with reduced cost and enhanced efficiency for reservoir stimulation.

Macerals and microfractures are identified as important microscopic characteristics of coal reservoirs， as they are factors affecting the reservoirs’ gas production capacity and mechanical properties. Based on coal samples from the No. 8 coal seam of the Carboniferous Benxi Formation in deep coalbed methane wells in the Ordos Basin， we investigate the developmental characteristics of macerals and microfractures using a residual neural network （ResNet）. With 305 maceral and 65 microfracture sample points from the sampled coal， we develop a ResNet-based methodology for identifying macerals and microfractures in coals， and construct an identification and classification model for macerals and microfractures in deep coal reservoirs through the inversion of microscopically observed data using the ResNet technique. The results indicate that the model is reliable， as jointly corroborated by geological characteristics and clustering algorithm-derived results. The model demonstrates a prediction accuracy of 0.90 for macerals and 0.80 for microfractures， enabling the effective prediction of macerals and microfractures in coals. The identification and prediction results of the model reveal correlations between fracture morphologies and macerals. Notably， the fracture formation is the most closely correlated with vitrinites in macerals， with the predicted fracture types and numbers agreeing well with macerals.

The low-rank coalbed methane （CBM） is distributed in both the northwest and northeast regions of China， as dominated by the Jurassic， Cretaceous， and Paleogene with coal seams exhibiting large quantities and considerable thicknesses but low gas content. With resources estimated at approximately 14.7 × 10¹² m³， the low-rank CBM at burial depths of 2 000 m or less holds tremendous potential for exploration and production. Through a systematic analysis of low-rank CBM resources in four typical basins in China， we investigate the typical accumulation characteristics and the exploration and production potential of low-rank CBM under various burial depth-geology combinations. The results indicate that low-rank CBM reservoirs in China manifest low permeability （<1 × 10^-3 μm²）， and relatively high salinity of coal seam water （>5 000 mg/L）. An analysis of the factors governing the accumulation of low-rank CBM under the synergistic effects of tectonism and hydrodynamic， temperature， and pressure fields reveals a gas enrichment-controlling pattern consisting of sedimentary microfacies-controlled coal occurrence， hydrogeology-controlled gas generation and preservation， burial depth-controlled reservoir properties， and tectonism-controlled gas accumulation. Six enrichment patterns of low-rank CBM are identified based on the analysis of typical zones. In combination with the geological characteristics and production practice of low-rank CBM in the Powder River Basin of the United States and the Surat Basin of Australia， we propose two enrichment patterns of low-rank CBM in China featuring high productivity， that is， the accumulation of gas from multiple single thin-bedded coal seams and deep CBM multiple factor-controlled storage. An assessment methodology and index system for the selection of CBM target areas are developed based on the analysis of five crucial factors for the efficient production of low-rank CBM： coal composition， resource potential， preservation conditions， production conditions， and fracability. Future exploration targets include the footwalls of piedmont overthrust faults along basin margins and the deep-central uplifted areas of slope zones within basins.

Breakthroughs have been achieved in the exploration and production of middle-rank coalbed methane （CBM） at a depth of 2 800 m and even deeper in the Daniudi gas field within the Ordos Basin. Notably， well YM-1HF exhibits a maximum single-well production of over 104 000 m³/d， an average stable production of 63 000 × 10⁴ m³/d over one consecutive year， and an accumulative gas production exceeding 23 million m³. By analyzing the geological characteristics of deep middle-rank coals and CBM in the Daniudi gas field， we propose and practically apply a production capacity improvement approach that integrates play selection， interval-based drilling， volume fracturing， and fine coalbed gas production. For play selection， we assess the Yuyang area from the perspectives of gas content， coal seam thicknesses and characteristics， roof conditions， and thermal maturity. The results indicate that coals in the Yuyang area are dominated by semi-bright coals with primary texture， exhibiting gas content ranging from 16.50 to 26.00 m³/t， free gas accounts for 25 % to 30 % of the total gas content， an average porosity of 4.68 %， and an average permeability of 0.24 × 10^-3 μm². Cleats and fissures are well-developed in the coals and are partly filled with calcite. The substantial total thickness of bright and semi-bright coals and high gas content provide the foundation for high gas production， while high injection rates of fracturing fluids and large-scale hydraulic-fracture stimulation are critical to high gas production. To achieve volume fracturing， it is recommended to employ effective technical approaches including multi-cluster closely spaced perforation， high injection rates of fracturing fluids， and high-intensity proppant injection based on a work philosophy that integrates saturated proppant injection， fracturing fluid control for creating large-scale primary fractures near wellbores and more secondary fractures far away from wellbores， and effective propping of induced fractures. In addition， proper control of the depressurization rate is vital for stable， high production of deep CBM wells， and the production concept of preventing proppant production while promoting coal fines is adopted. Bare casing should be utilized in the fluid drainage and rapid production stage， and in the flowing production stage， it is necessary to employ production strings to achieve continuous and stable production under pressure control. This production concept has proven effective in the pressure-controlled production of well YM-1HF.

The Ordos Basin is recognized as the most significant region for the development of the Carboniferous-Permian coal seams in China. In recent years， constant breakthroughs have been achieved in coalbed methane （CBM） exploration at depths exceeding 2 000 m along the eastern margin of this basin， establishing deep CBM as the most promising target for the additions to reserves from reserve growth of CBM. In this study， we perform systematic tests and analysis of well Yangmei-1HF in the Daniudi gas field of the northern Ordos Basin， which produces high-yield industrial gas flow at a depth of 2 800 m. Accordingly， we explore the geology of the Upper Paleozoic gas reservoirs in the gas field and analyze the quality， gas-bearing properties， and physical properties of coals in the Taiyuan Formation within the gas field. Furthermore， the geologic factors governing the high production of deep CBM are explored and the key technology for achieving high CBM production is determined as hydraulic fracturing-induced regional fracture network characterized by high proppant loading and the effective propping of induced fractures’ distal ends. This technology can be used to create regional fracture networks. The results indicate that the No. 8 coal seam of the Taiyuan Formation and the No. 5 coal seam of the Shanxi Formation in the Upper Paleozoic exhibit favorable geologic conditions for CBM exploitation， including stable continuous distribution， considerable thickness， high thermal maturity， and abundant free gas， which distinguish them from the occurrence and production characteristics of shallow CBM. Major factors contributing to the deep CBM enrichment in the Daniudi gas field include the high thermal maturity of coals and effective sealing capacities provided by the overlying limestone and mudstone roofs. It can be inferred that China boasts abundant CBM resources at depths exceeding 2 000 m， which hold considerable potential for exploration and exploitation， representing a new target for natural gas resources in China with significant development prospects.

The No. 8 coal seam of the Carboniferous Benxi Formation in the Ordos Basin exhibits great thickness and extensive， continuous distribution， establishing itself as a favorable interval for the exploration of deep coal-rock gas in this region. In this study， we examine the characteristics and genesis of the vertical heterogeneity in the No. 8 coal seam by conducting tests and analysis of the macroscopic characteristics， properties， reservoir characteristics， and gas content of coal samples collected from key well M172 in the eastern Ordos Basin. The results indicate that the No. 8 coal seam exhibits pronounced vertical heterogeneity with dominated semi-bright coals， high ash content and high inertinite content in the lower section， indicating a slightly oxidizing coal-forming environment. In contrast， its middle and upper parts contain bright and semi-bright coals and feature low ash content and high vitrinite content， reflecting a reducing coal-forming environment with limited terrestrial input. The coal rock properties and reservoir development characteristics of the No. 8 coal seam are controlled by changes in the sedimentary environment. The reservoir heterogeneity， to be specific， is influenced by both the input of terrigenous minerals to fill primary pores and the formation of abundant pores during hydrocarbon generation with high vitrinite content. For the sake of the stable sedimentary environment， the upper section of the No. 8 coal seam exhibits favorable coal-forming conditions and low ash content. Furthermore， the pores and fractures of the coal reservoirs in this part are minimally filled with detrital minerals， resulting in improvement in reservoir properties and gas adsorption and preservation. In contrast， the middle and upper sections demonstrate high vitrinite content and a significant gas generation capacity， providing more favorable material conditions for the generation of coal-rock gas and resulting in higher coal-rock gas content. Therefore， the middle and upper sections of the No. 8 coal seam represent favorable intervals for natural gas exploration and production in the Ordos Basin.

The Changqing Oilfield Company of PetroChina has achieved significant advances in exploring deep coal-rock gas within the Ordos Basin， discovering that methane （CH₄） largely occurs in coals as both adsorbed and free gas， which contributes to the formation of self-sourced coal-rock gas reservoirs. In this study， we comprehensively investigate the characteristics of coal-rock gas reservoirs represented by the No. 8 coal seam of the Benxi Formation. The results indicate that the Ordos Basin contains 10 coal seams from top to bottom. The Nos. 5 and 8 coal seams， among others， predominate， exhibiting stable distribution and great thickness. Compared to shallow coalbed methane （CBM）， the deep coal-rock gas occurring in the No. 8 coal seam of the Paleozoic Benxi Formation is characterized by high formation pressure， high formation temperature， high gas content， high gas saturation， and high free gas content. Specifically， these coal-rock gas reservoirs exhibit average formation pressure ranging from 22 to 35 MPa， suggesting high formation pressure. However， their formation pressure coefficients vary between 1.0 and 1.1， indicating a normal pressure system. The coal-rock gas reservoirs present average formation temperatures ranging from 67 to 92 ℃ and an average geothermal gradient of 2.94 ℃/km， suggesting normal geothermal gradients. The composition of coal-rock gas in these reservoirs manifests an average CH₄ content of 96.92 %， average C₂H₆ content of 0.61 %， average CO₂ content of 0.85 %， and average N₂ content of 1.47 %， establishing these reservoirs of dry gas type. The formation water in these reservoirs has total dissolved solids （TDS） concentrations ranging from 41 644 to 89 776 mg/L （average： 62 228 mg/L）， indicating primary CaCl₂-rich formation water. Unaffected by shallow groundwater， the coal-rock gas reservoirs exhibited high gas production rates in tests and stable production at a low pressure drop rate. A systematic comparison between deep coal-rock gas reservoirs in the No. 8 coal seam of the Benxi Formation and tight-sand gas reservoirs in the 8^th member of the Xiashihezi Formation （He 8 Member） and the 1st member of the Shanxi Formation （Shan 1 Member） in the Sulige gas field reveals similarities in major reservoir characteristics， including reservoir type， reservoir pressure and temperature， gas composition， formation water properties， and production capacity. These similarities will provide a valuable guide for future large-scale exploitation and production capacity construction of deep coal-rock gas.

The No. 8 coal seam in the Nalinhe area， Ordos Basin， with a burial depth exceeding 3 000 m， exhibits reservoir temperature and pressure fields significantly different from those of shallow to moderately coal-rock gas reservoirs. Investigating the coal-rock gas accumulation characteristics of this coal seam holds great significance for deep coal-rock gas exploration. This study systematically analyzes the geologic factors controlling deep coal-rock gas accumulation in the Nalinhe area， delves into the geological characteristics concerning coal quality， reservoir characteristics， temperature and pressure fields， gas-bearing properties， and coal-rock gas preservation conditions in the area. Using data from well M1H， which has undergone prolonged coal-rock gas production， we analyze the production characteristics and predict the coal-rock gas productivity of the Nalinhe area. The results indicate that the coal-rock gas reservoirs in the No. 8 coal seam at burial depths exceeding 3 000 m exhibit characteristics significantly different from shallow coal-rock gas reservoirs at burial depths less than 1 500 m， which feature low pressure， porosity， and permeability and gases dominated by undersaturated adsorbed gas. The specific characteristics of the No. 8 coal seam are as follows： （1） This coal seam is thick and mainly composed of semi-bright coals， and of the medium to high rank； （2） Under compaction and coalification， the medium to high-rank coal reservoirs are dominated by micropores smaller than 2 nm， which account for up to 79.8 % of the total pore volume. Additionally， micron-scale endogenetic microfractures， which remain open under deep in-situ stress field， are well-developed in these reservoirs， leading to a high matrix permeability of up to 3.949 × 10^-3 μm²； （3） At burial depths exceeding 3 000 m in the Ordos Basin， the formation temperature and pressure reach up to 97 ℃ and 32 MPa， respectively. The formation pressure tends to exert stabilized impacts on the adsorption capacity of coals， which predominantly hinges on the negative effect of temperature. Consequently， the adsorbed gas in the coals is in supersaturation， with free gas accounting for approximately 30 %； （4） The deep coal reservoirs in the study area are situated in a confined aquifer zone， while the coal seam itself manifests a low water-yielding capacity. The formation water produced is identified as the primary depositional water remaining in the roof and floor of the coal seam； （5） The consistency between the production curve characteristics of well M1H and the traced coal-rock gas geochemical characteristics demonstrates the stable production and great exploitation potential of coal-rock gas in deep reservoirs at burial depths exceeding 3 000 m.

Investigating the geochemical characteristics of gas and water produced from deep coalrock methane wells is significant for understanding the enrichment mechanisms and development patterns of coal rock mathane. Focusing on nine deep coal rock mathane horizontal wells along the eastern margin of the Yishan slope in the Ordos Basin， we examine the components and carbon isotopes in the produced gas， as well as the conventional ions and hydrogen and oxygen isotopes in the formation water to identify the genetic types of coal rock mathane， the gas fractionation effect in the process of coal rock mathane production， and the sources of the produced water. The results show that the coal rock mathane in the study area is of middle- to late-stage thermogenic gas with methane （CH₄） as the main component while heavy hydrocarbons and non-hydrocarbon gases as the minor components， exhibiting positive carbon isotope sequence. The methane carbon isotope value （δ¹³C₁） of the produced gas during coal rock mathane production can be used to assist in the calibration and determination of the production stages of free and adsorbed gases and presents a relatively large lightening trend as the coal rock mathane production goes on. Specifically， the produced gas is dominated by free gas initially and then exhibits both desorption and fractionation of adsorbed gas in the late stage. This finding aligns with the change pattern in the δ¹³C₁ of the pressure-retaining free gas and initially desorbed gas releasing stages of the gas content test. A longer period of high-to-low transition of δ¹³C₁ is associated with a higher possibility of high coal rock mathane yield. The water produced from a typical coal rock mathane well exhibits a total dissolved solids （TDS） of up to 193.08 g/L， suggesting a calcium-chloride （Ca-Cl） type water. Such water consists primarily of connate water trapped in sediments. Its low Na/Cl ratio， desulfurization coefficient， and Mg/Ca ratio， along with high metamorphism and salinization coefficients， indicate excellent stratigraphic sealing performance and favorable coal rock mathane preservation conditions. The hydrogen and oxygen isotope values of the produced water deviate from the local meteoric water line （LMWL）， largely exhibiting significant oxygen （¹⁸O） shifts. This is inferred to be influenced by recharge with water from the roof and floor strata of coal seams in a high-temperature stratigraphic environment.

In recent years， significant breakthroughs have been achieved in the exploration of deep coalbed methane （CBM） in the Daniudi area， northern Ordos Basin. This study aims to determine the potential for deep CBM exploration in this area. Based on regional geology and data derived from core and maceral observations， scanning electron microscopy （SEM） image analysis， proximate analysis， mercury injection capillary pressure （MICP） analysis， low-temperature liquid-nitrogen adsorption measurements， and CO₂ adsorption and methane isothermal adsorption experiments， along with on-site gas content tests， we delve into the geological characteristics of deep coal seams in the Daniudi area in terms of their spatial distribution， lithotypes， coal quality， reservoir properties， and gas-bearing properties. The No. 8 coal seam of the Taiyuan Formation is identified as the dominant coal reservoir in the Daniudi area. The results indicate that this coal seam is consistently distributed throughout the Daniudi area， with a thickness ranging from 2 to 14 m and vitrinite reflectance （R_o） of 1.7 %. Bright to semi-bright coals occur in the upper part of the coal seam as featuring low ash content， indicating high coal quality and providing a material basis for CBM accumulation. The No. 8 coal seam shows well-developed micropores and macropores， with micropores being predominant， accounting for 67.5 %. The bright to semi-bright coals with low ash content therein display high total pore volume， specific surface area of pores， micropore proportion， and porosity. The roof of the coal seam contains thickly laminated limestones and dark mudstones， as characterized by simple structure and low formation water content， suggesting a dry-coal gas-bearing system. With total gas content ranging from 20.3 to 47.1 m³/t and free gas proportion from 33.2 % to 66.2 %， the No. 8 coal seam is rich in both adsorbed and free gases. This coal seam manifests a gas-bearing area of 2 003 km²， CBM resources of 5 422 × 10⁸ m³， and CBM resource abundance of 2.71 × 10⁸ m³/km². These findings indicate that deep coals in the Ordos Basin are characterized by favorable geological condition for CBM generation， representing a significant exploration and development target.

JThe Jiaxian area emerges as a new target for the exploration and development of deep coalbed methane （CBM） in the Ordos Basin. However， the lack of studies on its in-situ stress and the undefined relationships between the in-situ stress and the physical properties of coal seams have hindered efficient CMB production in this area. Using data from logging and core analysis， we develop a logging-based in-situ stress calculation model as constructed by the combined spring model， investigate the in-situ stress distribution in the area and explore the controlling effects of in-situ stress on the fissures， porosity， and permeability of coal reservoirs. The results indicate that the planar distribution of the in-situ stress in the No. 8 coal seam within the Jiaxian area features high in the west and low in the east. The three principal stresses decrease in the order of vertical principal stress （averaging 56.72 MPa）， maximum horizontal principal stress （averaging 41.08 MPa）， and minimum horizontal principal stress （averaging 37.77 MPa）， suggesting a normal-faulting stress regime. The No. 8 coal seam has an average coefficient of lateral pressure of 0.70， indicating that this coal seam resides in a tensile setting overall， which creates favorable conditions for the formation of tensile fissures. The relationships between the reservoir physical properties and various in-situ stress parameters indicate that the physical properties of the No. 8 coal seam in the study area result from the combined effects of the three principal stresses， in which the horizontal principal stress play a predominant role. The porosity and permeability of the coal reservoirs trend downward with an increase in the lateral pressure coefficient and a decrease in the horizontal principal stress difference. The test results of deep CBM content in the study area indicate that the lateral pressure coefficient and the horizontal principal stress difference are reliable indicators of the physical properties of coal reservoirs， establishing them as effective tools for identifying the geologic sweet spots of deep CBM.

Using the latest 2D framework section of the Ordos Basin， along with high-precision 3D seismic data and drilling data， we systematically reinvestigate the Wushenqi and Central paleo-uplifts within the basin. Accordingly， the Cambrian-Ordovician sedimentary structural framework of the basin is reestablished and the evolutionary history of these two paleo-uplifts is clarified. The results indicate that during the Ordovician， the Wushenqi paleo-uplift exhibited a structural framework characterized by high in the north and low in the south. The Wushenqi and Central paleo-uplifts produced significant controlling effects on the deposition of the Cambrian and Ordovician strata， respectively. The 3D seismic data reveal that during （or even before） the Huaiyuan movement， the Wushenqi paleo-uplift underwent greater exposure and denudation compared to the Central paleo-uplift， though remaining higher in altitude during the pre-Ordovician. The Wushenqi paleo-uplift was active during the Precambrian， followed by gradual diminishment until the Ordovician when it became largely inactive. In contrast， the Central paleo-uplift got uplifted and came into being in L shape connecting the Yimeng paleo-uplift in the north and the Qingyang paleo-uplift in the south before the deposition of the Ordovician Majiagou Formation， prior to which the Qingyang and Yimeng paleo-uplifts， located in the southwestern and northern parts of the Ordos Basin， respectively， were independently active. The Wushenqi and Central paleo-uplifts jointly govern the distribution of sedimentary facies zones， resulting in the favorable reservoir-caprock assemblages in the eastern and central Ordos Basin. Promising targets for hydrocarbon exploration in the Ordos Basin include the Pre-Ordovician gas play s in weathering crust， lithologic gas plays in the central part， and fault-fractured gas plays in the eastern part.

In recent years， deep coal-rock gas has gradually become a popular target for the exploration of unconventional hydrocarbons. In China， the deep coal-rock gas exploration is concentrated in the Ordos Basin， where breakthroughs in the exploration and production pilot tests have been achieved. In contrast， the exploration of deep coal-rock gas in the Bohai Bay Basin remains in its initial stage. Using geologic data of coal seams obtained from core observations and well logging， we systematically analyze the characteristics and favorable accumulation factors of the deep Upper Paleozoic coal seams in the Dagang exploration area. Furthermore， the mechanisms underlying the gas generation， storage， and preservation in deep coal seams are explored and the developmental model of the deep Upper Paleozoic coal-rock gas is thereby clarified. The results indicate that the Dagang exploration area contains multiple favorable sweet spot intervals for the deep Upper Paleozoic coal-rock gas occurrence， where the coal seams exhibit high organic matter abundance， moderate thermal maturity， and high gas-generating intensity. In terms of pore structure， these coal seams manifest multi-scale pores and fractures， with the large-scale， intensively distributed microfractures providing effective storage spaces. The roofs and floors of the coal seams are composed predominately of mudstones， creating favorable preservation conditions. The coal seams experienced two large-scale gas-generating processes under the influence of multistage tectonic movements. Against the backdrop of complex fault-bounded depressions， the coal seams exhibit weathering-degradation zones， saturated adsorption zones， and structural hydrocarbon accumulation zones， with its deep parts characterized by supersaturated gas-bearing properties and coexistence of adsorbed and free gas. Based on these findings， we establish a developmental model for the complex accumulation of deep coal-rock gas in a complex fault-bounded basin. The theoretical research and exploration practices of the deep Upper Paleozoic coal-rock gas in the Dagang exploration area serve as a significant guide and reference for the exploration and development of deep coal-rock gas in the Bohai Bay Basin.

To investigate the exploration potential of deep coalbed methane （CBM） in the Longtan Formation， Sichuan Basin， we conduct coring of coal seams in risk exploratory well NT1H. Through experiments and tests on the coal quality and the physical properties， adsorption， and gas-bearing properties of coal reservoirs in the Longtan Formation， we examine the geological characteristics and exploration potential of deep CBM in the formation. The results indicate that the deep coal seams in the Longtan Formation exhibit coals with intact structure and well-developed cleats， vitrinite reflectance （R_o） ranging from 2.70 % to 3.13 %， average vitrinite， inertinite， and inorganic component contents of 60.6 %， 23.4 %， and 16.0 %， respectively， and minerals dominated by clay. These coal seams feature high total porosity， with a porosity varying from 4.83 % to 10.13 % and effective porosity from 2.82 % to 9.66 % （average： 6.53 %）. Their pores， with strong structural heterogeneity， are dominated by micropores with sizes less than 2 nm， followed by macropores or fractures with sizes greater than 10 μm， while pores with sizes ranging from 2 to 50 nm are relatively underdeveloped. The coals in the Longtan Formation display Langmuir volume generally exceeding 25 m³/t and average Langmuir pressure of 3.24 MPa at 120 ℃. Pressure coring reveals that the coal seams manifest gas content varying from 26.52 to 31.24 m³/t， gas saturation from 123 % to 146 %， free gas content from approximately 5 to 10 m³/t， and low in-situ water saturation from 18.2 % to 48.6 %. Their total gas content increases with burial depth. In all， the comprehensive investigation suggests that the deep coal reservoirs in the Longtan Formation exhibit conditions favorable for gas-bearing properties. Therefore， the deep reservoirs with supersaturated CBM in the Upper Permian Longtan Formation in the Sichuan Basin have great exploration potential. For these reservoirs， it is recommended to target closely spaced coal seams for integrated volume fracturing and three-dimentional reconstruction for CBM recovery.

The rock mechanical properties of coal seams and their roofs and floors are critical factors influencing the initial cracking and fracture propagation of coal reservoirs during fracturing. However， a limited understanding of these properties has constrained the large-scale commercial production of deep coalbed methane （CBM）. This study aims to investigate the mechanical characteristics and fracture propagation patterns of coal-rock assemblages during fracturing. Based on the acoustic emission signals monitored， we perform uniaxial compressive stress tests and finite element analysis （FEA） on coal-rock assemblages from the Wuxiang block in the east-central Qinshui Basin， with the impacts of different coal/rock thickness ratios， lithologies， and coal-rock interfacial angles on the compressive strength， elastic modulus， features of acoustic emission signals， and breakup characteristics of the coal-rock assemblages delved into. Additionally， we explore the fracture propagation behavior under varying coal-rock configurations. The results indicate that the compressive strength and elastic modulus of the coal-rock assemblages decrease with an increase in the coal-rock ratio in thickness and the coal-rock interfacial angle. The coal-rock assemblages with varying lithologies exhibit elastic modulus and compressive strength ranging from 1.75 to 5.44 GPa and from 11.20 to 20.60 MPa， respectively， with the coal-argillaceous shale and coal-sandstone assemblages displaying the weakest and strongest mechanical properties， respectively. A higher coal-rock thickness ratio tends to exacerbate the breakup of the coal-rock assemblages and results in more fractures within. At a given coal-rock ratio in thickness， the energy released from coal fracturing would continue to diffuse to adjacent layers， culminating in the breakup of the whole coal-rock assemblage. The susceptibility to failure among the various coal-rock assemblages decreases in the order of coal-sandstone， coal-limestone， and coal-argillaceous shale assemblages. The coal-rock assemblages are increasingly prone to failure， instability， and fracturing as the interfacial angle increases. As the coal thickness increases， fractures in the coal-rock assemblages evolve from tensile fissures to X-shaped shear fissures while gradually propagating from within coals to the entire assemblages. In contrast， with an increase in the mechanical strength of the coal-rock assemblages of diverse lithologies， fractures in the assemblages tend to evolve from X-shaped shear fissures to tensile fissures， with the propagation range shrinking from the entire assemblages to within coals. Besides， an increase in the interfacial angle between coals and rocks in the coal-rock assemblages leads to larger X-shaped shear fissures within， exacerbating the assemblage failure.

The hydrocarbon transport effectiveness along faults is a key factor influencing hydrocarbon accumulation and enrichment in moderately shallow reservoirs. Assessing this factor holds great significance for the emplacement of hydrocarbon exploratory wells in medium-shallow reservoirs in the central Sichuan Basin. This study focuses on the Shaximiao Formation in the central Sichuan Basin. Following the analysis of fault distributions and origins， we assess the gas transport capacity of source rock-rooted faults， investigate the fault-sand configuration and its evolution， and reveal the controlling effects of fault-sand configuration on the migration and differential enrichment of gas， based on fault activity rates， compressive stress directions， and normal stress on fault plane. The results indicate that the reverse and normal faults cutting through the Upper Triassic Xujiahe Formation and the Lower Jurassic source rocks in the central Sichuan Basin serve as the source rock-rooted faults of the Shaximiao Formation. The reverse faults， among others， are governed by the tectonic compression in different tectonic movement periods， whereas the normal faults are formed due to the differential subsidence with uplifting and sagging in a weak extensional setting during the early to middle sedimentary stages of the Shaximiao Formation. The reverse faults， Longquanshan， Jiao-1， and Jianyang-1， as well as normal faults in the central Sichuan Basin exhibit high transport capacity during the Late Yanshanian and the Late Himalayan. Considering factors such as fault size and the hydrocarbon generation intensity of underlying gas sources， it can be inferred that the Longquanshan and Jiao-1 faults play the most significant role in hydrocarbon transport. The source rock-rooted faults in the central Sichuan Basin are mostly of the inherited type， conducive to the continuous gas charge into favorable sand bodies in different charging periods. In contrast， the Jiao-1 fault is of the inverted type， exhibiting different gas charge directions in the early and late stages and allowing for natural gas charge on both sides. Major factors governing the differences in natural gas enrichment include the size of source rock-rooted faults， fault-sand configuration， and the hydrocarbon generation intensity of source rocks.

Some shale gas sweet spots preferentially selected based on traditional selection criteria are still of low production， the reason for which has been attributed to poor pore connectivity according to many researchers and engineers. Although hydraulic fracturing can enhance the effective exploitation area of shale reservoirs， the migration of shale gas from the matrix to hydraulic fractures depends solely on the pore connectivity within. For shale reservoirs in the Luzhou block of the Sichuan Basin， revealing the pore connectivity of the reservoirs and establishing reservoir identification and assessment model are crucial to guiding the pore connectivity assessment and selecting optimal target zones. In this study， we analyze typical shale samples collected from wells in the Luzhou block using experiments and tests， including nuclear magnetic resonance （NMR）， mercury intrusion porosimetry （MIP）， focused ion beam-scanning electron microscopy （FIB-SEM）， and large-field splicing scanning electron microscopy （MAPS）. Based on connected porosity and the proportion of connected pores， the shale reservoirs in the Wufeng-Longmaxi formations in the Luzhou block are categorized into types A， B， and C in terms of pore connectivity. Type A reservoirs with connected pore volume exceeding 0.006 7 cm³/g and connected porosity going beyond 1.75 %， generally exhibit trimodal NMR-derived pore size distribution curves， suggesting high connectivity among small pores， mesopores， and macropores， together with well-developed connected， gas-expansion-type， organic matter-hosted pores， and inorganic mineral-hosted pores. Type B reservoirs， as characterized by connected pore volume ranging from 0.005 7 to 0.006 7 cm³/g and connected porosity from 1.55 % to 1.70 %， exhibit approximate bimodal NMR-derived pore size distribution curves， reflecting high connectivity among small pores and mesopores but low connectivity among mesopores and macropores. The pores in these reservoirs are dominated by isolated， sponge-like organic matter-hosted pores， with the presence of substantial inorganic mineral-hosted pores. Type C reservoirs， featuring connected pore volume of less than 0.005 7 cm³/g and connected porosity below 1.55 %， manifest unimodal NMR-derived pore size distribution curves， reflecting an absence of connectivity among pores with different sizes. In these reservoirs， organic matter generally contains no pores， and inorganic mineral-hosted pores are also poorly developed. The results of this study indicate that a reasonable configuration of pores with varying sizes contributes to pore connectivity improvement in shales. The extensively distributed inorganic mineral-hosted pores play a role in connecting locally connected organic matter-hosted pores， ultimately forming the interconnected pore networks in the shales. Among various shale facies， clay-rich siliceous shales demonstrate the highest pore connectivity. The chart for the qualitative and quantitative identification of the pore connectivity of shale reservoirs， established based on reservoir connectivity characteristics， and MAPS and FIB-SEM data， along with the three classes of pore connectivity pattern， provide a basis for determining the pore connectivity of shale reservoirs and offer support for selecting the optimal target zones of high-quality shale reservoirs in the future.

Hydrocarbon reservoirs have been identified in the 2^nd member of the Cretaceous Nantun Formation （also referred to as the Nan 2 Member） in the Huhehu Sag， Hailar Basin. However， limited studies have been conducted on the occurrence conditions and exploration targets of deep coal-rock gas therein. In this study， we analyze the fundamental conditions for hydrocarbon accumulation， including source rocks， deposits， and structures， in the Huhehu Sag and examine the developmental characteristics and gas-bearing features of deep coal reservoirs. Accordingly， we explore the occurrence conditions of deep coal-rock gas in the sag and propose potential exploration targets. The findings reveal that in Nantun Formation there are two suites of mature source rocks in the mudstones and coals， which provide a favorable material basis for the deep coal-rock gas generation and accumulation. During the deposition of the Nan 2 Member， Hailar Basin， a faulted lacustrine basin， exhibits swamps， which create a favorable coal-forming setting. The initial extension stage of the basin witnessed the formation of thick coals and coal-mudstone coexistence， while its stable extension and contraction stages featured thin coals and sandstone-coal coexistence. The ramp-faulted terrace zone exhibits thin coals and low gas content. In contrast， the trough and steep slope zones are characterized by thick coal rocks and well-developed cleats， with organic pores interconnected by microfractures， contributing to high connectivity and a well-developed pore-fracture system. So it is rich in free gas. The fault system formed in the early extension stage provides pathways for the vertical and lateral migration of deep coal-rock gas. The Huhehu Sag exhibits deep coal-rock gas resources predicted at 1.79×10¹² m³， suggesting considerable exploration potential and establishing this sag as an important new risk exploration target in the faulted lacustrine basin. Additionally， the trough and steep-slope zones are identified as the most favorable exploration targets for deep coal-rock gas.

The continental coal-accumulating Tuha Basin is recognized as a significant petroliferous basin in western China. The Jurassic Shuixigou Group contains multiple suites of high-quality source rock sequences bearing coal seams， as well as high-quality sandstone and coal reservoirs， emerging as a primary target for hydrocarbon exploration and a field for strategic breakthroughs in deep coal-rock gas exploration within the basin. In this study， we investigate the impacts of the basin's tectonic and sedimentary evolution on the formation of source rocks. Based on the response characteristics of trace elements to the sedimentary environment， we analyze the developmental and distribution patterns of various types of source rocks and identify favorable locations for natural gas （coal-rock gas） preservation in coal reservoirs. The results suggest that during the deposition of the Shuixigou Group， the tectonic uplift and subsidence processes governed the formation and evolution of the depocenter of the Tabei Sag， driving the depocenter to migrate gradually from north to south. At the end of the Late Jurassic， the northern part of the Tuha Basin underwent significant tectonic uplift， resulting in the continuous migration of the depocenter toward the basin's hinterland and the development of the terrain featuring highs in the east and lows in the west. Consequently， three present-day subsidence centers， i.e.， the Shengbei， Qiudong， and Xiaocaohu sub-sags， are formed， which tend to rise and grow shallower eastward. The depocenter evolution determines the changes in the depth and salinity of water bodies in the sub-sags of the Taibei Sag. Specifically， the water bodies exhibited an increasing depth and decreasing salinity during the deposition of the Badaowan and Sangonghe formations of the Shuixigou Group. In contrast， the water bodies displayed a gradually decreasing depth and increasing salinity during the deposition of the Sangonghe and Xishanyao formations of the group. Mudstones are primarily distributed in the northern part of the basin， thickening from west to east. Influenced by the salinity of paleo-water bodies， the Badaowan—Xishanyao formations are characterized by vertically improving organic matter both in types and abundance. The Shuixigou Group underwent frequent fluctuations in water bodies during its deposition， with coals forming in sedimentary environments with relatively shallow water bodies. This group exhibited shallow water bodies during the initial water transgression in the early deposition of the Badaowan Formation， along with the late water regression in the late deposition of the Badaowan Formation and the early-middle deposition of the Xishanyao Formation， creating favorable coal-accumulation environments. Therefore， the Shuixigou Group represents the primary interval for coal occurrence in the Tuha Basin. Ten types of roof-floor assemblages of coal seams are identified in coal-bearing areas of the basin. Five favorable roof-floor assemblages for the preservation of coal-rock gas， as well as their locations， are determined， serving as the targets for future coal-rock gas exploration.

The deep coal seams rich in coalbed methane （CBM） resources feature strong heterogeneity， high stress， high pressure， and challenging stimulation， rendering the accurate sweet spot evaluation crucial to the large-scale production of deep CBM. This study focuses on the logging-based evaluation of integrated geological-engineering sweet spots in deep coal seams， establishing an evaluation model with 12 evaluation indices using the analytic hierarchy process （AHP） method. Employing this model， we carry out sweet spot assessment of deep coal seams in over 20 wells in the DJ block. The results indicate that the major determinants of the geological-engineering sweet spots are strongly correlated with the ratio of a CBM well’s daily gas production to its construction pressure in the proppant transport stage （I_p）. The upper part of deep coal seams in the DJ block generally exhibits superior sweet spots compared to its middle and lower counterparts. Specifically， the upper， middle-lower， and lower parts predominantly exhibit Class Ⅰ， Ⅲ， and Ⅱ sweet spots， respectively. Gas content and brittleness index are identified as the primary factors controlling high-quality reservoirs and engineering sweet spots. The coal seams’ roofs and floors consist of thick limestones and mudstones， which exhibit significantly different mechanical properties from the coal seams and thus effectively block the propagation of induced fractures across the coal seams. The fracturing conditions and production test results indicate promising outcomes of the logging-based evaluation model. Therefore， this model can be applied to the logging-based selection and evaluation of the optimal perforation sections for the hydraulic fracturing of deep coal seams.