Breakthroughs in the exploration and production of deep coalbed methane (CBM) in the Daning-Jixian block on the eastern margin of the Ordos Basin exert a profound influence on the CBM industry, arousing extensive concern and follow-up. Although previous studies delved into the theoretical and technical challenges and corresponding solutions of deep CBM exploration and production, there is a lack a systematic summary of pilot tests for typical gas field exploitation. Through an in-depth dissection of the geological characteristics and challenges of cost-effective production of deep CBM, this study summarized the advances and outcomes of the pilot test projects in the Daning-Jixian block, determined the production patterns, and proposed strategies for cost-effective production. The results show that: (1) Deep coal seams exhibit extensive distributions, high gas content, rich free gas, favorable preservation conditions and coal structures, high brittleness index, and high sealing capacities of coal seam roof and floor. However, factors such as the presence of microstructures, extremely low permeability, and high total dissolved solids (TDS) content restrict the cost-effective production of deep CBM. (2) Different geological conditions result in significantly distinct production characteristics of gas wells. Therefore, by determining the production capacity of gas wells and the adaptive production technologies through pilot tests, the production risks caused by the high heterogeneity of coal seams can be effectively reduced using the progressive production mode. (3) Artificial gas reservoirs with highly bridged well patterns and fracturing networks, constructed based on the optimized geo-engineering integrated well pattern design, can maximize resource production and recovery. (4) The large-scale, high-injection-rate limit volume fracturing technology characterized by long horizontal sections, multiple sections and clusters, and large proppant volumes can increase effective stimulated reservoir volumes and well-controlled reserves, thus substantially enhancing single-well production. (5) deep CBM wells can achieve short-term rapid large-scale production growth owing to their production characteristics such as early gas production, rapid production addition, high initial gas production, and rapid decline. Nevertheless, long-term stable production of gas fields requires continuous drilling of new wells. (6) Given high early-stage production costs, it is necessary to constantly improve the engineering operation efficiency and reduce production costs in order to achieve cost-effective production. Overall, deep CBM resources, manifesting high quality and a production possibility, meet the requirements of rapid technological promotion and duplication. The deep CBM production in the Daning-Jixian block can provide a technical reference for the large-scale production of deep CBM in China's other blocks, holding great significance for accelerating the exploration and production of deep CBM in the country.

The Jurassic coals in the Baijiahai uplift, with breakthroughs made in the deep coalbed methane (CBM) production of vertical wells in the early stage in China, serve as an important exploration target of the Junggar Basin. Their coal reservoirs feature an ultra-low ash content, a low moisture content, medium-to-high volatility, and favorable porosity and permeability systems. With gas accumulation modes, namely, the paleo-source and young-reservoir made and the self-source and self-reservoir mode, the coal seams enjoy favorable gas-bearing properties, such as a high gas content, a high proportion of free gas, and high gas saturation, which establish them as high-quality CBM reservoirs. As corroborated by many years of exploration and exploitation practice of Jurassic coals in the Baijiahai uplift, the trial production of most vertical wells can quickly yield gas (2‒5 days), without requiring drainage and pressure reduction. The early-stage trial production tends to exhibit relatively high daily gas production (2100‒9890 m³), low or even zero daily water production (<5 m³), a capacity of natural flowing, and a low backflow rate. In contrast, the prolonged pilot production experiences a uniform pressure drop and a certain period of steady production (25‒60 days). The outcomes of the vertical-well-based pilot production can be influenced by the perforation layer thickness of coal seams, the fracturing fluid system, and the proppant ratio for fracturing. For the fracturing fluid system, gelled and guanidine gel systems outperform the active water-clean systems. The newly constructed horizontal well Caitan 1H yielded high production after fracturing, with a maximum daily gas production of 57000 m³ and a small daily water production (0.5‒3.0 m³), characteristic of conventional natural gas. Subsequently, the production of this well exhibited decayed and stabilized, with adsorbed and free gas produced jointly. Compared to vertical wells, this horizontal well featured higher production, a longer period of steady production, and a lower pressure drop rate. Based on the reservoir characteristics and gas bearing characteristics of the study area, as well as the exploration and exploitation histories of the reservoirs, this study achieved implications in three aspects: (1) Regarding the further understanding of the enrichment patterns of multiple types of deep gas reservoirs, it is necessary to highlight the research on the formation and evolution of traps for hydrocarbon migration and accumulation, as well as the spatial distribution and enrichment pattern of deep gas and water. (2) Concerning the compressibility evaluation of medium- and low-rank deep coal reservoirs, a suitable fracturing process system should be developed for such reservoirs with favorable porosity and permeability systems in high-lying areas. (3) Regarding the optimization of methods for exploiting multiple types of deep gas reservoirs, for gas reservoirs with a high proportion of free gas, the drainage and production control is crucial to achieving sequential production of free and adsorbed gas and to maintaining stable expansion of a depressurization area.

Contrasting with shallow to moderately deep coalbed methane (CBM) reservoirs, deep CBM reservoirs exhibit favorable coal structures, high formation pressure, high free gas ratios, and high contents of total dissolved solids (TDS) and CO₂. Extensive fracturing allows for CBM flowing at the initial stage, while the production parameters vary significantly throughout the CBM production. This requires wide technological boundaries of the main production technologies. Compared to shale gas and tight gas, deep CBM manifests different production mechanisms and relatively low free gas ratios, which lead to short flowing cycles of CBM. This necessitates timely water withdrawal for CBM production. Moreover, deep CBM wells remain in a low-production stage dominated by desorption for a long time. Based on the geological characteristics of deep coal reservoirs, this study investigated the Daning-Jixian block on the eastern margin of the Ordos Basin. It systematically analyzed the factors influencing deep CBM production, like stress sensitivity effect, velocity sensitivity, scaling blockage, Jamin effect, and free gas ratio, as well as their characteristics. Accordingly, this study pinpointed some technological challenges in deep CBM production: unknown conversion time limit between free and desorption gases, prominent corrosion and scaling caused by CO₂ and water with high TDS content, and short pump inspection cycles of horizontal wells. To minimize the bottomhole pressure, boost CBM desorption, and enhance the single-well estimated ultimate recovery (EUR), this study proposed the hydraulic jet pump lifting technology, which is the most suitable for horizontal well production currently and yields the optimal economic efficiency. Moreover, this study pointed out the research directions of production and hydraulic jet pump lifting technologies for deep CBM to transition into green and intelligent gas field development, including strengthening integrated geological-engineering research, establishing efficient CBM production systems, and exploring and testing integrated rodless lifting production technology.

Deep coalbed methane (CBM) boasts abundant resources and great potential for exploitation. However, there is a lack of in-depth studies on the internal connections between deep and shallow CBM. This study investigated the Upper Paleozoic coalbed in the Ordos Basin. From the perspective of coalbed formation and evolution, it obtained three burial depth evolution modes of coalbed through summaries: both the maximum and present burial depths exceeding 2000 m, the maximum burial depth over 2000 m while the present burial depth less than 2000 m, and both the maximum and present burial depths less than 2000 m. This study systematically analyzed the differences in the temperature and pressure conditions, gas content, in-situ stress, reservoir permeability, metamorphic grade, and water content of deep and shallow coal seams, as well as their formation mechanisms. The results indicate that, due to the influence of burial depth and evolutionary process, deep and shallow coal reservoirs show maximum temperature and pressure differences of up to 100°C and about 40 MPa, respectively. As a result, from deep to shallow, the CMB occurrence state transitions from the predominance of adsorbed gas to the coexistence of adsorbed state and free gas, the in-situ stress field shifts from the predominance of horizontal stress to that of vertical stress, and coal reservoirs’ porosity, permeability, and water content gradually decreased. Accordingly, this study ascertained the typical characteristics of deep CBM. Specifically, under high-temperature and high-pressure conditions, deep CBM occurs as coexisting adsorbed and free gas in coal reservoirs below a certain depth. Under the action of predominant vertical stress, the coal reservoirs of deep CBM feature extremely compressed pore and fissure spaces, an extremely low water content, and an extremely high degree of mineralization, with microfissures acting as major seepage channels. Based on the differences in the critical depth for gas-bearing property and the transformation depth of in-situ stress field between deep and shallow coal reservoirs, this study proposed that there exist transitional zones between shallow and deep coal seams, exhibiting the characteristics of atypical deep CBM or the coexistence of geological conditions for deep and shallow CBM. During exploration and exploitation, it is necessary to figure out a tailored scheme based on specific analysis to achieve efficient and coordinated development of shallow and deep CBM.

Accurately understanding of the occurrence states, relative content, and distribution characteristics of gas - water under deep conditions has important guiding significance for efficient exploration and development of coalbed methane (CBM). Based on the theoretical model, molecular simulation and systematic analysis of gas-water, the occurrence states of gas-water in coal seam is clarified, and the boundary and dynamic evolution process of gas-water dynamic migration and accumulation are revealed. Considering the coal - water interface interaction, the mobility and occurrence states of water, the coalbed water can be divided into movable water (gravity water and capillary water), bound water (adsorbed water, zeolite water, crystallization water and interlayer water) and structural water. The adsorbed water, capillary water and gravity water are dominated by pores, and zeolite water, structural water, crystallization water and interlayer water are dominated by minerals. The molecular simulation results show that water molecules are saturated and filled in 0.7 nm pores, with consistent adsorption and desorption processes, while weak adsorption layers and free states appear in larger pores. The adsorption process of water molecules is manifested in stages: single molecule oxygen-containing group adsorption, monolayer strong adsorption, multi-layer weak adsorption, water clusters formation, and pore filling. Methane molecules stably fill pores (1.5 nm) with 3 layers of adsorption, and coexist in monolayer adsorption and free state in the larger pores(>1.5 nm), resulting in the widespread presence of free state in pores above mesopores. According to the boundary between adsorption and free gas mentioned above, the theoretical calculation formulas for free gas and adsorption gas have been improved to provide new ideas for gas content calculation. Deep thermogenic CBM is the residual gas generated after large-scale hydrocarbon generation and expulsion from coal. During the hydrocarbon expulsion process, the water is driven by methane and the evaporation diffusion process results in a small amount of residual water (bound water and structural water) remaining in the pores, which cannot be changed in the later stage. Assuming a static water pressure of 20 MPa, under reservoir pressures of 0, 5, 10, 15, and 20 MPa, the maximum pore size that external water can invade is 7, 9, 13, 27 nm and non-invasive. Controlled by differential preservation conditions, coal-derived gas not only forms overpressure and under pressure differential gas bearing systems, but also forms multiple types of gas bearing modes in coal measures. The above work has clarified the micro-occurrence mechanism and evolution mode of CBM and water, which has guiding significance for the enrichment characteristics and efficient development design of deep CBM.

Burial depth serves as a comprehensive factor influencing coalbed methane (CBM) accumulation. Understanding the effects of depth on gas-bearing properties is critical for ascertaining the occurrence states and accumulation mechanisms of deep/shallow CBM. Based on the present situation of CBM exploration and the dissection of data from CBM exploration wells on the eastern margin of the Ordos Basin, this study explored the effects of burial depth on the gas content, saturated adsorbed gas capacity, and gas saturation of coal seams, as well as their coupling relationship with accumulation processes, using conventional and unconventional petroleum accumulation. The results indicate that CBM accumulation results from the coupling of hydrocarbon generation and gas supply in the tectonic subsidence stage with the phase transformation and dissipation of gas during the rollback and uplift of strata. This is manifested as a deep coupling of self-sealing- and buoyancy-driving gas accumulation. The variations in gas-bearing properties involve two critical depth thresholds: one for the turning of saturated adsorbed gas capacity and one for free gas retention. Notably, the two thresholds do not exhibit absolute synchronicity: (1) The saturated adsorbed gas capacity is an intrinsic property of coals under specific temperature and pressure conditions, not strictly constrained by preservation conditions. Its depth-varying evolutionary process governs the phase transformation of methane. The compensating effects of pressure gradients and metamorphic grades lead to a significantly deeper turning point (zone) of current regional saturated adsorbed gas capacity. (2) The migration and accumulation, along with transformation and shaping, of free gas are dictated by the cap rock conditions during the rollback and uplift of strata, involving the comprehensive influence from burial depth - structure - hydrodynamic field coupling effects, as well as buoyancy and reservoir/cap rock capillary pressures. Minor uplift amplitude and low transformation intensity are necessary for free gas retention and preservation. Free gas will dissipate extensively in strata shallower than the retention depths due to reduced sealing properties. In the Liulin-southern Yanchuan area on the eastern margin of the Ordos Basin, the total gas content of coal seams increases almost linearly with the burial depth, exhibiting a subtle convergence trend in deep layers. Coals with different metamorphic grades in this area show depth thresholds ranging from 1600 to 2200 m for the turning of theoretical saturated adsorbed gas capacity. However, regional differentiation of coal ranks causes a continuous increase in the in-situ saturated adsorbed gas capacity with the burial depth. The Daning-Jixian block has a critical depth of approximately 2000 m for free gas retention, with an average gas saturation of 120% at a depth of 2500 m and an estimated gas saturation of 136% at a depth of 3000 m. Different areas exhibit differential CBM accumulation settings and geological conditions, necessitating a specific analysis of the effects of depth on gas-bearing properties. The analysis should focus on the comprehensive influence of the spatio-temporal evolution of both the phase transformation of methane and the sealing conditions of strata on current gas and water distributions. This is crucial for achieving the zone-orientated evaluation and efficient production design of deep CBM.

Inner Mongolia boasts abundant coalbed methane (CBM) resources in low-rank coals. Investigating the origin and accumulation mechanisms of CBM is crucial for the siting and assessment of these CBM resources. This study examined the CBM in low-rank coals in major gas-rich sags of the Erlian Basin through various experiments, including tests of the composition and carbon/hydrogen isotopes of CBM, as well as tests of the water quality, hydrogen/oxygen isotopes, and radioisotopes (³H and ¹⁴C) of coal seam water. By analyzing the geochemical characteristics of both CBM and coal seam water, this study revealed the origin, sources, and accumulation mechanisms of CBM in low-rank coals within the study area. Key findings are as follows: (1) The CBM in the Erlian Basin is all dry gas and dominated by methane (CH₄). With an increase in the burial depth, the CH4 volume fraction increases, whereas the CO₂ volume fraction first increases and then decreases, peaking at depths between 300 and 500 m. The CH₄ exhibits generally lighter carbon and hydrogen isotopic values, with δ¹³C(CH₄), δD(CH₄), and δ¹³C(CO₂) values ranging from −70.3‰ to −48.0‰, from −285.5‰ to −189.0‰, and from −37.6‰ to 1.94‰, respectively. (2) The coal seam water primarily has hydrochemical types of HCO₃-Na and Cl·HCO₃-Na. The current coal seams feature a relatively stable water environment, with weak hydrodynamic conditions. The coal seam water, with apparent ages between 1020 and 47490 a, principally originates from Quaternary meteoric water, with no or little recharge from modern surface water. (3) The CBM in the Erlian Basin is predominantly composed of original biogenic gas, mixed with a minor amount of early thermogenic gas. With an increase in the burial depth, the stratigraphic environment and types of methanogenic archaea change, with the generation paths of biogenic methane also shifting. In the early stage, the biogenic methane in the Jiergalangtu sag was primarily derived from acetic acid fermentation. In the late stage, it predominantly originated from CO₂ reduction in the late stage, mixed with a small quantity of low-maturity thermogenic gas. In contrast, the biogenic methane in both Bayanhua and Huolinhe sags was principally sourced from acetic acid fermentation. Besides, the biogenic methane in the Huolinhe sag contains a trace amount of biogenic gas from methyl fermentation. (4) The study area has coal seam conditions favorable for biogenetic gas generation, such as low geotemperatures, low total dissolved solids (TDS) content, and low thermal maturity. The Jiergalangtu sag exhibits a graben-type biogenetic-gas accumulation mode in shallow thick coal seams, while the Bayanhua and Huolinhe sags display a half-graben-type biogenetic-gas accumulation mode with hydraulic sealing in moderately deep confined areas. Identifying favorable target areas for the formation and enrichment of biogenic gas should be the focus of subsequent exploration and production of CBM in the Erlian Basin. Besides, it is practically significant for reserve growth and production addition of CBM in low-rank coals in the basin.

China boasts abundant coalbed methane (CBM) resources in deep layers (burial depths: greater than 2000 m), with considerable potential for CBM exploration and development. Compared to medium and shallow CBM, deep CBM differs significantly in enrichment and accumulation patterns and exploitation means. Therefore, there is an urgent need to dissect key CBM blocks. The Shenmu-Jiaxian block, situated in the northeastern Ordos Basin, is currently in the early stages of deep CBM exploration, with enrichment characteristics and exploration potential remaining undefined. Based on recently obtained seismic data, logging data from over 300 wells, and analytical results from four cored wells, this study conducted a comprehensive analysis of the fundamental geological characteristics of coal reservoirs, identified the primary controlling factors and patterns for CBM enrichment, and analogically dissected the potential for deep CBM exploration in the study area. The No.8 deep coal exhibits vitrinite reflectance of 0.7%‒1.8%, indicating that the coalification in most parts of the study area is currently in the peak stage of pyrolytic gas generation. The No.8 deep coal seam exhibits regional net thicknesses of up to 7‒8 m, stable distribution, comparably simple structures, highly closed hydrodynamic conditions, and favorable roof and floor sealing conditions, which create favorable conditions for widespread, continuous CBM accumulation. Across the study area, the southern portion of Jiaxian County demonstrates the optimal CBM resource conditions. Compared to other deep blocks in the eastern Ordos Basin, the No.8 coal seam in the study area exhibits significantly higher proportions of free gas (15.21%‒46.47%). Moreover, its adsorbed gas is primarily governed by adsorption pressure-induced trapping, whereas its free gas is subjected to the dual controls of capillary pressure and buoyancy-gravity differentiation. Both trapping mechanisms jointly determine the vertical and planar zoning of gas content in the deep part of the coal seam. Taking the southern area of Jiaxian County as an example, this study summarized a typical deep CBM enrichment pattern, which consists of the predominant control of the adsorption pressure for adsorbed gas, followed by the control of the coupling of capillary pressure and buoyancy-gravity differentiation for free gas. The comparative analysis with the Linxing and Daning-Jixian blocks indicates that the Shenmu-Jiaxian block enjoys a solid resource foundation of CBM, favorable reservoir stimulation, and great potential for high production, hinting at a promising prospect for large-scale exploitation of deep CBM in this block. In addition, the deep part of the Daning-Jixian block is characterized by high-rank coals, while that of the Shenmu-Jiaxian block features medium-rank coals. Therefore, this study contributes to the enrichment and improvement of the theory about deep CBM enrichment, serving as indicators for the exploration and exploitation of deep CBM in China.

The Shenfu block on the eastern margin of the Ordos Basin is a typical deep coalbed methane (CBM) field with abundant resources and considerable potential for exploration and exploitation. In October 2023, the large-scale Shenfu deep CBM field successfully reported proven geological reserves exceeding 110 billion m³. The Fugu area, located in the central part of the Shenfu block, is the earliest experimental area for deep CBM production. However, there is a lack of a clear understanding of CBM enrichment and accumulation patterns, as well as the potential for exploration and development, of this area. By comprehensively utilizing the data from seismic surveys, logging, drilling, and coal tests, this study identified the geological characteristics, enrichment and accumulation patterns, and favorable area distribution of deep CBM in the Fugu area. The results show that the dominant coal seams 4+5 and 8+9 exhibit stable distribution and large thicknesses (coal seams 4+5: 3.2‒5.8 m; coal seams 8+9: 8.7‒13.5 m), with favorable intervals primarily occurring in the middle-upper parts. Macroscopically, the coals are dominated by bright to semi-bright coals, and their structures predominantly include primary and cataclastic structures. Due to the influence of plutonic metamorphism, the coals mainly comprise gas coal, fat coal, and coking coal. Regarding the metamorphic degree, the coals are at the peak of pyrolysis and gas generation, with coal reservoirs exhibiting medium to high gas contents (coal seams 4+5: 3.0‒12.0 m³/t; coal seams 8+9: 7.5‒18.5 m³/t) and medium to high gas saturation (35.0%‒115.0%). The dominant coal seams are low-permeability reservoirs (permeability: (0.01‒0.09) ×10⁻³ μm²), with pores primarily consisting of micropores and small pores. This study proposed a CBM enrichment and accumulation mode involving flexural folds, faults, and hydrodynamic force, determining that the CBM enrichment areas include the gentle tectonic zone and the slope zone. Furthermore, this study established an evaluation system for geological and engineering double sweet spots of deep CBM, identifying that the Class I geological and engineering sweet spots are located in the eastern and southwestern parts, which serve as the preferred areas for deep CBM exploration and exploitation in the study area. This study further enriches the theory on deep CBM enrichment and accumulation, serving as an important guide for the exploration and exploitation of deep CBM on the eastern margin of the Ordos Basin.

Temperature acts as an important factor affecting the gas-bearing properties of deep coal reservoirs, further affecting the development performance of deep coalbed methane (CBM). Therefore, ascertaining the geothermal conditions of coal reservoirs and their effects on the gas-bearing properties of deep coal reservoirs is critical to the systemic understanding of the enrichment characteristics and production patterns of deep CBM. For coal seam No.9 in the Taiyuan Formation within the Ningwu Basin, over 90% of the area has burial depths exceeding 1000 m. In the hinterland of the basin, coal seams generally exhibit burial depths greater than 1500 m, with a maximum exceeding 2500 m. These findings suggest typical deep CBM. Based on the log data, experiments data, and well test data, this study determined the geothermal field characteristics of the coal reservoirs in the Ningwunan block and their effects on the gas-bearing properties. The results show that coal seam No.9 in the Ningwunan block exhibits reservoir temperature ranging between 15.5℃ and 40.1℃ and there is a significant positive correlation between the reservoir temperature and the burial depth. The coal reservoirs have geothermal gradients ranging from 1.27 to 1.95℃/hm, with an average of 1.52℃/hm, indicating the characteristics of low geothermal fields. These reservoirs demonstrate gas saturation ranging from 40.1% to 93.7%, with an average of 71.7%, suggesting low gas saturation of the deep coal reservoirs. With an increase in the burial depth, the coal reservoir temperature increases slowly due to the low geothermal gradients. This results in significantly reduced negative effects of temperature on the adsorption capacity of deep coal reservoirs in the study area compared to deep CBM-bearing blocks at similar burial depths, such as Daning-Jixian and Linxing. Accordingly, the depth at which adsorbed gas transitions into free gas increases for coal reservoirs in the study area, with the transition ratio between both types of gases decreasing. Low temperature serves as an important factor affecting the gas-bearing properties of deep coal reservoirs in the study area, further influencing their recoverable degree. Therefore, the geothermal conditions of coal reservoirs should be highlighted in the exploration and recovery of deep CBM.

Breakthroughs have been achieved in the high-yield gas flow of coalbed methane (CBM) wells with burial depths ranging from 1000 to 2500 m in the Cainan area of the Junggar Basin and the Daning-Jixian and southern Yanchuan blocks on the eastern margin of the Ordos Basin, signifying the enormous potential for the production of deep CBM. In the Sichuan Basin, the thin to moderately thick coal seam groups (7‒15 layers) in the Upper Permian Longtan Formation primarily exhibit burial depths ranging between 2000 and 4500 m. In the central Sichuan Basin, characterized by north-dipping monoclines and local low-amplitude uplifts, deep coal seams display superior critical production parameters, including gas content, gas saturation, and reservoir pressure, to shallow ones, demonstrating considerable potential for supporting China’s natural gas development strategy of reserve growth and production addition. Key findings are as follows: (1) The Longtan Formation coal measures manifest frequent coal-mudstone interbeds, a large number of coal seams, and huge cumulative resources. Notably, the No. 19 coal seam is well-developed laterally, with an average thickness of 3.2 m and a favorable area (thickness: >4 m) of 700 km². (2) The high thermal maturity (2.53%‒3.18%) of coals suggest a high hydrocarbon generation capacity. The gas logging-derived total hydrocarbon value of coal measures reveals favorable results, with measured gas content, gas saturation, and free gas content at a burial depth of 2500 m varying in ranges of 16.64‒17.61 m³/t, 138%‒151%, and 4.84‒5.60 m³/t, respectively. (3) The reservoirs at a burial depth exceeding 800 m in the southern Sichuan Basin exhibit measured pressure coefficients of above 1.1, and those in the central Sichuan Basin display predicted pressure coefficients of above 1.8, indicating potential abnormally ultra-high pressure reservoirs. Based on the deep to ultradeep, overpressure, and supersaturated resource endowment characteristics of coal seams in the Sichuan Basin and referencing the successful experience in deep CBM production in the Daning area, this study determined the resource potential and gas reservoir characteristics of the No.19 coal seam and established a technology system for the three-dimensional exploration and exploitation of deep to ultradeep thin coal seams. Therefore, this study is significant for large-scale CBM production capacity construction.

The Wangfu fault depression in the southern Songliao Basin is rich in coalbed methane (CBM) resources. However, CBM exploration in this area has been restricted by the low-level exploration of deep CBM and a lack of systematic studies on the geological characteristics of CBM, primary factors controlling CBM enrichment and accumulation, and the selection of favorable targets. Therefore, based on the systematical analysis of the geological characteristics of coal-bearing strata, this study identified the major factors controlling deep CBM accumulation, established the index system for favorable area selection, and predicted the favorable areas of CBM enrichment. The results show that: (1) Macroscopically, coals in the Huoshiling Formation in the Wangfu fault depression can be primarily categorized into bright and semi-bright coals, possessing the characteristics of low moisture, low volatile constituents, and low ash content. They exhibit vitrinite reflectance > 1.8%, average porosity of 5.01%, and average gas content of 21.80 m³/t (calculated based on well CS38). (2) The sedimentary environment, filled and leveled through volcanic eruption, of the Huoshiling Formation in the Wangfu fault depression is conducive to the formation of coal seams. Specifically, coal seams primarily occur between the double steep slope zones and in the shallow water areas of the central and eastern Wangfu fault depression, which were formed by the filling and leveling effects of volcanic eruption. In this manner, the coal formation mode featuring filling and leveling is formed. Additionally, the presence of large-area thick mudstone roofs and closed faults allow for CBM enrichment and preservation in the fault depression. (3) Class I favorable areas in the Wangfu fault depression predominantly occur in the northern and central parts of the fault depression, with coal seam thicknesses > 5m, fault throw <50 m, cover thicknesses > 80 m, and gas logging-derived total hydrocarbon values > 15%. These suggest great potential for exploration and exploitation. Classes Ⅱ and Ⅲ favorable areas are mainly found in the northern and southern parts of the fault depression, with coal seam thicknesses < 5m, cover thicknesses < 80 m, and gas logging-derived total hydrocarbon values < 15%. Weak-sealing or open faults and greatly different cover thicknesses pose risks to CBM exploration and exploration in these areas.

This study investigated the northern Zhengzhuang-western Qinnan block for the purpose of achieving effective exploitation of moderately deep coalbed methane (CBM) reservoirs in the southern Qinshui Basin. Based on results from the analyses and tests of parametric wells, including core analysis and tests, injection/falloff tests, and in situ stress cyclic tests, as well as a large amount of dynamic and static data, this study expounded on the characteristics of moderately deep CBM reservoirs in the study area by comparison with shallow counterparts. Then, it explored the technical improvements in fracturing through vertical wells and staged fracturing through horizontal wells for shallow to moderately deep coal seams. Accordingly, this study proposed the primary technology for exploiting moderately deep CBM reservoirs. The results indicate that the No. 3 coal seam in the northern Zhengzhuang-western Qinnan block has an average burial depth of around 1200 m, suggesting moderately deep CBM reservoirs. With an increase in the burial depth, both the gas content and adsorption time increase at first and then decrease, peaking at depths from 1100 m to 1200 m and from 800 m to 1000 m, respectively. The in situ stress field in the study area shifts twice as the burial depth increases. Specifically, the study area exhibits a reverse fault type of in situ stress field at burial depths less than 600 m, where long horizontal fractures are prone to form through hydraulic fracturing. In contrast, the study area displays a strike-slip fault type of in situ stress field at burial depths exceeding 1000 m, where short vertical fractures tend to be generated through hydraulic fracturing. At burial depths from 600-1000 m, the in situ stress field transitions from the reverse fault type to the strike-slip fault type, with an intricate fracture system tending to form via hydraulic fracturing. Compared to shallow counterparts, moderately deep CBM reservoirs in the study area manifest significantly different gas content, desorption efficiency, and stress field. As a result, to achieve higher fracturing performance, a larger fracturing scale is required for both vertical (directional) and horizontal wells as the burial depth increases. For vertical wells, the single-well daily gas production can exceed 1000 m³ at burial depths exceeding 800 m under fracturing fluid volumes greater than 1500 m³, injection rates of fracturing fluids above 12-15 m³/min, and proppant concentrations greater than 10%-14%. For horizontal wells, the single-well daily gas production can exceed 18000 m³ at burial depths greater than 800 m under fracturing intervals less than 70-90 m, single-stage fracturing fluid volumes above 2000 m³, single-stage proppant volumes above 150 m³, and injection rates of fracturing fluids greater than 15 m³/min. Horizontal wells significantly outperform vertical wells at large burial depths. Horizontal wells with a two-spud-in structure and full bore sleeve each, combined with the technique for identifying high-quality CBM intervals and fracture-network fracturing with high fracturing fluid injection rates, serve as the main technology for the efficient exploitation of moderately deep CBM reservoirs in the southern Qinshui Basin.

In recent years, breakthroughs have been achieved in the exploration of deep coalbed methane (CBM) in China based on fine-scale geological research and techniques such as multistage hydraulic fracturing using proppants in a horizontal well. As a result, some wells yielded daily gas production of up to 100000 m³, inspiring confidence again in the CBM industry. However, since deep coal reservoirs occur in a complex geological environment characterized by high in-situ stress, high geotemperature, high pore pressure, and low permeability, there is an urgent need to reveal the typical parameters of coal reservoirs at different depths and the distribution of CBM in varying occurrence forms in the reservoirs, as well as their effects on CBM reserves and production. Based on Langmuir equation of isothermal adsorption, Henry's law, and the material balance principle, this study established a calculation model of free gas saturation of deep CBM reservoirs by considering the effects of adsorption layers and dissolved gas. With the deep CBM reservoirs in the Daning-Jixian block in the Ordos Basin in China as a case study, this study investigated the occurrence forms and distribution of deep CBM at varying depths and assessed the effects of free gas saturation on the reserves, production, and rational production allocation of deep CBM. Key findings include: (1) Free gas appears only when the coal seams’ burial depth exceeds the depth corresponding to the dissolution saturation of CBM reservoirs, with the free gas saturation increasing rapidly initially and then slowly as the burial depth increases. In the Daning-Jixian block, free gas emerges at a burial depth of 1875 m, and the free gas saturation reaches 90% at a burial depth of 2800 m, where the free gas accounts for up to 17.3%. (2) The free gas saturation has significant effects on the reserves calculation, gas production characteristics, and reasonable production allocation of deep CBM. With an increase in the free gas saturation, the CBM reserves linearly increase, and the cumulative gas production keeps rising, with the increased amplitude gradually decreasing in the late stage. Furthermore, an increase in the free gas saturation is accompanied by an increase in the optimal production allocation of a deep CBM well, an increase in the drop rate of bottomhole pressure, a decrease in the pressure difference between the stimulated reservoir volume (SRV) and the unstimulated reservoir volume (USRV), and an increase in the producing degree of the USRV. The dominant coal seams to be exploited in the target block are located at depths between 2100 and 2300 m, with free gas saturation ranging from 48% to 68% and a proportion of free gas varying between 10% and 13%. It is recommended that the rational production allocation of gas wells in the target block should be (4−10)×10⁴ m³/d. The results of this study will provide a theoretical basis and methods for the further exploitation of deep CBM.

The Daning-Jixian block on the eastern margin of the Ordos Basin exhibits high-abundance deep coalbed methane (CBM) resources, well-developed natural fractures of coal reservoirs, well-developed cleats and fractures in coals themselves, coals with excellent structures and high mechanical strength, and strong sealing ability of coal roofs and floors. All these create favorable conditions for the formation of a large-scale fracture network through volume fracturing. The ultra-large-scale fracturing process has contributed to a major breakthrough in the single-well output of deep CBM. However, the tracer monitoring results show that various fracturing stages of horizontal wells exhibited different contribution rates to gas production, there exhibited blind zones of resource production, and expected comprehensive benefits were not achieved. This study proposed two major challenges posed to the formation of ultra-large-scale effective fracture networks in deep coal reservoirs: (1) unclear understanding of fracture propagation patterns in deep coal seams and (2) the presence of areas subjected to over and insufficient stimulation using current fracturing technologies. Given these challenges, this study developed a multi-round diverting fracturing technology to form a merged fracture network for the stimulation of deep coal reservoirs. This technology involved: (1) analyzing the feasibility of the formation of a super-large fracture network of deep coal seams. (2) determining the effects of microstructures, such as the curvatures and dip angles of strata, on fracture propagation based on the field fracturing data and microseismic monitoring results. (3) Establishing a stress field calculation method, which laid the foundation for the process optimization and field experiments of multi-round fracturing diverting. This technology was verified through field experiments in the Daning-Jixian block. The results revealed the uniform propagation of hydraulic fractures in areas with nonuniform micro-stress fields around wells. This uniform propagation increased the overall fractured volume, with single-well gas production in the experiment area significantly improving compared to surrounding wells. Well DJ55, experiencing five rounds of fracturing, exhibited a stimulated reservoir volume of up to 243.6×10⁴ m³, 340-day cumulative gas production of 970.5×10⁴ m³, and an average daily gas production of 2.85×10⁴ m³, with daily gas production and pressure remaining stable. These results indicate excellent stimulation results. With an estimated ultimate recovery greater than 3000×10⁴ m³, this well had great potential for gas production. Well JS8-6P05 in the block yielded a daily gas production of 8.59×10⁴ m³ after 2‒3 rounds of fracturing at fracturing stages 1‒7. Compared to well JS8-6P04, which employed single-round fracturing at each fracturing stage, well JS8-6P05 witnessed reductions in the proppant volume and fracturing cost by 21% and 41.9%, respectively. However, the horizontal sections of both wells produced comparable daily gas production. The experimental results indicate that the multi-round diverting fracturing technology, partially solving the problem that fractures propagate on one side of a horizontal well due to the stress differences on both sides, promotes the uniform propagation of induced fractures on both sides of a wellbore and thus ensures a high production degree and post-fracturing production of deep coal reservoirs. This technology serves as a main technical method for reducing the costs and increasing the efficiency of fracturing technology for deep CBM.

China boasts abundant deep coalbed methane (CBM) resources, which play a significant role in further CBM production. However, deep coal seams exhibit low porosities and ultra-low permeabilities due to intricate geological conditions. In the drilling process, drilling fluids enter the reservoirs, prone to cause near-wellbore contamination. Although conventional hydraulic fracturing technology tends to create fractures in the direction of the maximum horizontal principal stress, it is challenging for this technology to achieve blockage removing throughout the whole borehole. Laser thermal fracturing technology can break rocks in a short time. Furthermore, it allows for the laser irradiation angle to change freely by regulating mechanical equipment, thus forming radial fractures and reducing near-wellbore contamination. Using the ABAQUS finite element software, this study, establishing a model of laser thermal fracturing of coal seams, explored the fracturing mechanisms and the influence of laser technological parameters. Through analyses of the variation patterns of fracture length and number, this study determined the optimal laser parameters targeting near-wellbore contamination areas. Key findings include: (1) Laser thermal fracturing can cause thermal stress on the surfaces of coal seams through temperature differences, ultimately fracturing coal seams. (2) There was a positive correlation between the fracture number and the laser power and irradiation time. Specifically, the number increased from 10 to 37 as laser power expanded from 400 to 1 000 W. At a laser power of 600 W, the number increases from 24 to 36 as the irradiation time prolonged from 1 to 15 s. In contrast, the fracture number negatively correlated with the laser frequency. With an increase in the laser irradiation distance, the fracture number increased initially and then decreased, peaking at an irradiation distance of 10 cm. (3) The fracture length positively correlated the laser power, irradiation time, and laser frequency but negatively correlated the laser irradiation distance. Among these factors, the laser irradiation time produced the most significant influence on the fracture length, which soared from 1.52 to 57.6 mm as the irradiation time increased from 1 to 5 s. For instance, for samples collected from Hancheng, Shaanxi Province through deep coring, the optimal laser power and irradiation time of laser thermal fracturing for the near-wellbore contamination area of deep coal seams extending within 2 m were 20 kW and 2 280 s, respectively. Compared to hydraulic fracturing, laser thermal fracturing can form more complex but shorter fractures. In practical application, the approach combining hydraulic fracturing with laser thermal fracturing is recommended for blockage removing and permeability enhancement.

This study aims to gain an in-depth understanding of factors restricting the commingled production of coal-measure gas and boost the contributions of various pay zones to gas production. To this end, it analyzed the essential factors of the dynamic, channel, and gas source conditions in the commingled production. The dynamic conditions for the commingled exploitation of multiple reservoirs can be met by (1) enhancing the flow conductivity of reservoirs by altering the crustal stress state and (2) changing reservoir fluid pressure by layers. Following this principle, this study proposed a method for the commingled production of coal-measure gas through layered pressure relief in surface wells. This method involves directional drilling on the surface and then high-pressure water jet in target reservoirs to artificially create pressure-relief spaces (e.g., fractures, slots, and cavities) and alter the crustal stress state. This can reduce the damage caused by effective stress, increase the number and aperture of diversion channels in reservoirs, and accelerate pressure drop transfer in target reservoirs. Afterward, commingled production can be conducted after the reservoir pressure decreases to the dynamic conditions for the commingled production of coal-measure gas, thus enhancing the contributions of pay zones to gas production. Compared to conventional reservoir stimulation, this method can reduce the damage of effective stress to coal-measure gas reservoirs, improve the transfer efficiency of pressure drop, enhance the desorption and diffusion of coal-measure gas, and decrease the interlayer interference during the commingled production of multiple coal-measure gas reservoirs. Based on these findings, this study proposed that the commingled production of coal-measure gas through layered pressure relief in surface wells is primarily applicable to coal-measure gas reservoirs with high crustal stress and small spacings between pay zones. Furthermore, this method is expected to be widely applied to the stimulation of coal-measure gas reservoirs with thin interbeds for production growth and to the exploitation of superimposed paragenetic coal-measure reservoirs with severe interlayer interference.

Driven by the dual demands for achieving the goals of peak carbon dioxide emissions and carbon neutrality and for ensuring national energy security, underground coal gasification (UCG) in China is embracing a new historical development opportunity. To scientifically formulate a route for making technological breakthroughs in UCG and accelerate its industrialization, this study analyzed the history of UCG field tests, dividing UCG into three stages: UCG based on coal mines, vertical/directional wells, and horizontal wells. By exploring the underlying logic that propelled innovations in UCG technologies in different stages, this study delved into the technical and non-technical reasons for the failure of UCG industrialization and finally proposed suggestions. Key findings are as follows: (1) The UCG technology combining horizontal wells with the controlled retracting injection point (CRIP) process can effectively avoid the risks of surface subsidence and freshwater pollution caused by shallow gasification. Furthermore, this technology enjoys advantages in terms of expanding the vertical coal mining range, increasing single-well-controlled coals, improving the quality of raw gas, and ensuring continuous gasification. Hence, this technology serves as a mainstream technical route currently and in the future. (2) After the longest field test period, China has remained long in the stage of UGS based on coal mines. Although China is still in the initial stage of tests for breakthroughs in moderately deep UCG, it roughly keeps the same pace with other major coal-rich countries in terms of technical research and development due to the challenging technology research and low technological maturity. Therefore, China is expected to overtake these countries in the technology for UCG based on drilled wells. (3) Regarding technical reasons, limited technology applicability poses challenges in the industrialization of UCG based on coal mines and vertical wells, while low technological maturity predominantly restricts the industrialization of UGS based on horizontal wells. Consequently, long-term stable and high gas production is yet to be achieved. (4) Concerning non-technical reasons, the termination of UCG tests abroad is primarily caused by low-cost production of conventional natural gas, the influence of the shale gas revolution, public concerns about environmental pollution caused by shallow gasification, and governments' UCG policy shift. In contrast, China's UCG industrialization is principally hindered by a prolonged gap in development planning, relatively limited entities engaging in scientific research and tests, insufficient investment in scientific research, a lack of industrial support policies, and the absence of joint innovation mechanisms. This study proposed suggestions for China's UCG industrialization. In the new era, it is necessary to thoroughly identify the complexity and challenges of UCG technology. Then, great efforts should made to achieve long-term stable production with considerably high quality. It is recommended that the technological maturity should be constantly improved through synchronous scientific research and field tests. The cascade production mode featuring physical gas extraction followed by chemical gasification should be employed to avoid competition with coalbed methane production. Meanwhile, it is necessary to actively explore the utilization mode that integrates oil and gas, new energy, and coal chemical industry for elevated economic benefits. As a revolutionary production technology for artificially created gas reservoirs, UCG, after successful achievement, can provide a technical reference for the fluidization exploitation of other mineral resources and push China's unconventional technology for fossil energy development to a new level.