Coal measure gas is an important type of unconventional natural gas, and its formation and accumulation are the result of the coupling configuration of tectonic sedimentation. The Lesser Himalayan orogenic belt in Nepal is a key area for studying the development and enrichment patterns of coal measure gas reservoirs in complex structural areas. In this study, the coal measure gas reservoirs of the Gondwana Group and Surkhet Group in the Tansen area of the Lesser Himalayan orogenic belt in Nepal were taken as the research objects. The types and combination characteristics of coal measure gas reservoirs in Gondwana and foreland basins were analyzed. The development of microscopic pore-fracture system morphology and pore structure characteristics of different coal measure gas reservoirs were analyzed. The evolution process of pore-fracture systems and the formation mechanisms of dominant pore-fracture systems in coal measure gas reservoirs under the action of thrust nappe were discussed. Finally, potential favorable reservoirs, favorable areas, and resource potential of coal measure gas were preliminarily predicted. The results showed that: (1) The combination types of coal measure gas reservoirs in the Lesser Himalayan orogenic belt of Nepal mainly included the “source-reservoir integration” type of coal-shale gas, the “lower source-upper reservoir” type of coal-tight sandstone gas and shale gas-tight sandstone gas, and the “source-reservoir adjacent” type of coal-shale gas-tight sandstone gas. (2) The mesopores and organic matter micropores related to shale minerals were well developed, accounting for 64.6% of total pore volume and 98.1% of total specific surface area. The coal seam mainly developed micropores, and the total specific surface area reached 8.22 m²/g. In tight sandstones, intergranular pores and microfractures were predominant, demonstrating the highest permeability among all types of reservoirs. (3) The shale pore-fracture system had the dual effects of destruction and regeneration. The evolution of pore-fracture system in coal measure gas reservoirs with different lithologies varied under the action of thrust nappe. The coal seam mainly experienced cataclastic deformation, resulting in the development of more micropores, while the tight sandstones were mainly characterized by the formation and propagation of structural fractures. (4) The coal-shale combination of the Bhainskati Formation of the Surkhet Group in the Tansen area was the dominant coal measure gas reservoir type. The Jhadewa mining area in the southeast of Tansen area was a potential favorable area for coal measure gas. It was preliminarily estimated that the coal measure gas resources in this area reached 5.04×10⁸ m³. This study preliminarily identifies the potential favorable reservoirs and favorable areas of coal measure gas in the Lesser Himalayan orogenic belt of Nepal, providing direction for the evaluation and exploration of oil and gas resources in Nepal.

Xinjiang has significant advantages in oil-rich coal resources. The efficient and clean utilization of these resources can ensure the supply of oil and gas resources, promote the effective utilization of deep coal resources, and mitigate environmental issues caused by traditional coal combustion. Currently, Xinjiang has achieved certain breakthroughs in understanding the occurrence characteristics, distribution patterns, and shallow development and utilization of oil-rich coal resources. However, bottlenecks remain in key technologies such as the in-situ conversion of deep oil-rich coal and multi-energy collaborative development. This study analyzed the resource of oil-rich coal in Xinjiang and the current status of its development and utilization industry from the perspectives of the geological resource quantity of oil-rich coal, the resource quantity of coal-based oil and gas, the techniques for surface chemical development and utilization, the techniques for underground in-situ pyrolysis and gasification development, geological utilization and storage of by-product CO₂, integrated development of multiple energy sources, and the construction of national-level demonstration zones. Additionally, it proposed suggestions for industrial development. The results showed that: (1) Oil-rich coal resources in Xinjiang were mainly concentrated in the east, including Sandanghu Basin, Balikun Basin, and Tuha Basin. Using the geological block method, volumetric method, and abundance method, it was preliminarily predicted that the oil-rich coal resource quantity in the Jurassic strata within 1 000 meters in eastern Xinjiang was 556.6×10⁸ t, and the coal tar resource was 65.9×10⁸ t. (2) The technologies of surface gasification and pyrolysis upgrading of oil-rich coal and preparation of coal-based chemicals in Xinjiang were relatively mature, having realized the production of clean coal using oil-rich coal as raw material, the production of coal-based hydrogenated oil using coal tar as raw material, and the production of methanol and ethylene glycol using purified coal gas as raw material. (3) An integrated in-situ pyrolysis and gasification development technology system for oil-rich coal was proposed, including the evaluation technology for geological site selection, in-situ furnace construction technology, in-situ coal seam heating technology, and enhanced extraction technology. (4) A technological pathway for the coordinated development of oil-rich coal chemical industry and new energy through multi-energy complementarity was developed. It mainly included using new energy to produce hydrogen, which serves as a raw material for the pyrolysis and hydrogenation of oil-rich coal to prepare chemical products and oil products, provide thermal energy for the pyrolysis and gasification furnace of oil-rich coal, and supply hydrogen as a raw material for pyrolysis upgrading and coking of oil-rich coal. (5) It is recommended that Xinjiang establishes national-level demonstration zones for the development and utilization of oil-rich coal, including a demonstration zone for the surface pyrolysis and gasification of oil-rich coal for the coal chemical industry, an in-situ pyrolysis and gasification demonstration zone for oil and gas industries based on deep oil-rich coal, a geological utilization demonstration zone for by-product CO₂ from oil-rich coal chemical processes, a demonstration zone for CO₂ storage of semi-coke from in-situ pyrolysis of deep oil-rich coal, and a multi-energy complementary coordinated development demonstration zone for “oil-rich coal and new energy”, promoting the efficient and sustainable development of Xinjiang’s oil-rich coal industry.

Coalbed methane (CBM) is a hazardous gas that leads to gas explosions, coal and gas outbursts, and contributes to atmospheric greenhouse effects in coal mines. At the same time, CBM is a clean and efficient energy source. Developing CBM in coal mining areas offers significant benefits for enhanced safety, energy production, and environmental protection. In China, the estimated CBM resource is 32.86 × 10¹² m³ at depths shallower than 2 000 meters and 40.71 × 10¹² m³ at depths beyond 2 000 meters. Since the “12th Five-Year Plan”, an extraction model of “four-zone coordination” has been developed through practical exploration to ensure both CBM resource development and the safe, efficient operation of coal mines. This model is tailored to mining engineering deployment, mining-induced disturbances, and coal seam geological conditions. It involves coordinated CBM development in planning, preparation, production, and goaf areas, demonstrating significant effectiveness in practice. The key outcomes include: (1) Three technologies have been developed for use in planning areas, namely, surface vertical well fracturing, staged fracturing in coal-seam horizontal well, and staged fracturing and extraction. In the Haishiwan Mine of Yaojie, Gansu, vertical well interlayer temporary plugging and diverting fracturing technology is used in the target coal seam, and the CBM well production reaches 2 607 m³/day. In Sihe mine of the Jincheng Mining Area, Shanxi, bottom-sealed coiled tubing pulling hydraulic jet and annulus sand fracturing technology is used in coal seam 15. The length of the horizontal well is 820.53 m with 8 fracturing sections. The maximum well production is 9 100 m³/day, and the stable gas production is 7 000-8 000 m³/day. U-shaped horizontal well staged fracturing is used in the roof of fragmented and soft coal seam 8 of Luling Mine in the Huaibei Mining Area, Anhui Province. The horizontal well length is 585.96 m with 7 fracturing sections. The maximum well production is 10 760 m³/day, and the total production is 7.5 million m³. (2) Directional long borehole staged fracturing and extraction technology in underground coal mines have been developed in preparation areas. In the Dafosi Mine of Binchang, Shaanxi Province, long borehole staged fracturing is used in coal seam 4. The horizontal well length is 600 m with 8 fracturing sections. The maximum pure gas production is 3 600 m³/day, and the average is 1 000-2 500 m³/day. Pure gas production per 100 meters is 4.9-11.0 times that of unfractured boreholes in the same area. In the Xinjing Mine of the Yangquan Mining Area, Shanxi Province, the roof of fragmented and soft coal seam 3 is sand fractured in stages. The drilling length reaches 609 m with 10 fracturing sections. The maximum pure gas production is 2 811 m³/day, and the pure gas production per 100 meters is 5.6-15.4 times that of unfractured boreholes in the same area. (3) For fragmented and soft coal seams, technologies such as high-pressure sand hydraulic fracturing and pneumatic directional drilling have been developed in production areas. In the Pansan Mining Area, Anhui Province, sand hydraulic fracturing technology is used in coal seam 13-1. The pure gas production per 100 meters of sand-fractured borehole is 2.38 times that of conventional water fracturing. In the No.2 Mine of Yangquan, Shanxi Province, to address the difficulties of drilling in fragmented and soft coal seams and the tendency of borehole collapse upon encountering water, pneumatic directional drilling drainage technology is used in coal seam 8. The drilling depth is 607 m, and the pure gas production is 971.6 m³/day. (4) A ground vertical well and L- shaped horizontal well gas extraction model is developed for goaf areas in coal mines. In the Panyi Mine of the Huainan Mining Area, Anhui Province, due to the depressurization mining of coal seam 11-2, ground vertical wells are used to drain gas from coal seam No.13-1, and gas production reaches 50 000 m³/day. In the Sihe Mine, Jincheng Mining Area, Shanxi Province, the L-shaped horizontal well is used in the roof coal seam 3, and the pure gas production is 30 000 m³/day. Innovative technologies such as large-scale staged fracturing both at the surface and underground and deep CBM development have been proposed to promote technological advancement in coal mining areas and ensure the safe mining and efficient development of CBM resources.

The eastern margin of the Ordos Basin is rich in tight gas resources. However, the reservoirs are characterized by low pressure coefficients, poor physical properties, a high concentration of sensitive minerals such as clay minerals, and complex pore structures. These features result in a high degree of potential reservoir damage, which constrains stable and high gas production. To clarify the sensitivity characteristics of tight gas reservoirs in the study area, the study used tight sandstones from the first member of the Permian Shanxi Formation (Shan-1 member) and the eighth member of the Permian Shihezi Formation (He-8 member) as the research objects. Cast thin-section analysis, scanning electron microscopy (SEM), X-ray diffraction, and core fluid displacement tests were employed to investigate reservoir sensitivity. Based on the results, targeted strategies for reservoir protection were proposed. Experimental results indicated that the reservoir rocks were fine to medium grained lithic sandstones, with an average clay mineral content of 21.59%, primarily consisting of mixed-layer illite-smectite. The main pore types were residual intergranular pores and secondary dissolution pores. Nanopores were well-developed, with poor connectivity between micro- and nanopores. In cores from the He-8 member, the median porosity and permeability were 6.43% and 0.149 × 10^-3 μm², respectively. In cores from the Shan-1 member, the median porosity and permeability were 6.46% and 0.387 × 10^-3 μm², respectively. The pH values of the formation water ranged from 5.47 to 6.83, with an average total salinity of 118 077.21 mg/L. The reservoirs in the study area were low-temperature, low-pressure tight gas reservoirs, exhibiting weak velocity sensitivity, weak to moderately weak water sensitivity, weak to moderately weak salt sensitivity, moderately weak to moderately strong acid sensitivity, weak to moderately strong alkali sensitivity, and moderately strong to strong stress sensitivity. The average critical flow velocity was 0.3 mL/min, the critical salinity was 60 000 mg/L, and the average critical pH value was 7.79. During development, attention should be paid to the low pressure, low temperature, and high nanopore proportion of the reservoirs. Acid sensitivity, alkali sensitivity, and stress sensitivity should be prioritized, and improvements and optimizations should be made in drilling, completion, fracturing, and production practices. The research findings provide significant guidance for the efficient development of low-pressure tight sandstone gas resources.

Injecting CO₂ into deep coal seams to enhance coalbed methane (CBM) extraction has both environmental and economic benefits, indicating broad development prospects. To investigate the structural changes of different types of coal after CO₂ injection, five samples with different maximum vitrinite reflectance (R_{o, max}) were selected to conduct supercritical CO₂ injection experiments under conditions simulating a coal seam burial depth of 1 500 m. The pore and fracture structures of the coal samples before and after injection were characterized using low-temperature N₂ adsorption and mercury intrusion porosimetry. The extent of changes was quantitatively compared using fractal theory. The results of N₂ adsorption experiments showed that the pore volume of the coal samples before and after supercritical CO₂-H₂O reaction initially decreased and then increased with increasing coal rank. An inflection point was formed at coking coal, with the most significant increase in pore volume observed within the micropore range (pore diameter 0~2 nm). The changes in pore volume observed in mercury intrusion porosimetry experiments were relatively complex, with significant increases in the transition pore range (pore diameter>2~50 nm) and fracture range (pore diameter>1 000 nm). This was because the supercritical CO₂-H₂O reaction increased the proportion of non-effective connected pores in the coal, enhancing the local connectivity of the coal samples. Furthermore, the total pore volume of some samples even showed a decreasing trend after reaction, likely due to the blockage of pores and fractures by detached minerals. The fractal analysis results of pore parameters before and after reaction showed that the changes in pore and fracture structure depended on the characteristic coal parameters. The changes in pore volume were more pronounced in low-rank and high-rank coals after the reaction, and the extent of change was more significant in samples with higher mineral content. This study contributes to a deeper understanding of how CO₂ injection changes the pore structure of deep coal seams and can provide a reference for site selection in CO₂ geological storage and enhanced coalbed methane development (CO₂-ECBM) projects.

Shale is at the forefront of oil and gas geological research and a hotspot for exploration; however, research has mainly focused on marine and lacustrine shale systems, while studies on shale within transitional coal-measure strata are relatively limited. The Carboniferous-Permian coal-measure strata in the Bohai Bay Basin are well-developed, characterized by widely distributed, regionally stable, and thick shale layers. These strata represent excellent source rocks and reservoirs, indicating significant potential for oil and gas exploration and development. This study investigated the coal-measure shale of the Carboniferous-Permian Taiyuan and Shanxi Formations in the Huanghua Depression of the Bohai Bay Basin. Using data from core analysis, thin sections, well logging, organic carbon content, Rock-Eval pyrolysis, and vitrinite reflectance (R₀), this study examined the depositional environment types of coal-measure shale, the vertical evolution of the depositional environments, and the organic geochemical properties of the shale from different depositional environments. This research aims to provide a theoretical basis for oil and gas exploration in the Carboniferous-Permian coal-measure strata of the Bohai Bay Basin. The Carboniferous-Permian coal-measure strata in the Huanghua Depression were divided into the Taiyuan Formation and the Shanxi Formation. The Taiyuan Formation was mainly characterized by barrier coastal facies, while the Shanxi Formation was dominated by deltaic facies. The shale of the Taiyuan Formation was primarily deposited in lagoon and tidal flat environments of the barrier coastal system, whereas the shale of the Shanxi Formation was mainly deposited in subaqueous distributary channels and interdistributary bay environments of the deltaic system. The lithological and logging characteristics of shale from different sedimentary facies were identified. Lagoon shale was gray-black, with well-developed horizontal laminations. Under the microscope, felsic material was visible, with fine particle sizes generally at the silt grade. Brownish-red siderite concretions were common, often exhibiting irregular ellipsoidal shapes with their long axes typically aligned parallel to the bedding planes. Lagoon shale exhibited distinct logging responses, characterized by high natural gamma and high resistivity on conventional logs, and bright yellow to bright red backgrounds with faint lamination structures on image logs. Tidal flat shale was mainly deposited in tidal flat environments. It was predominantly gray to black or dark gray. In core samples, well-developed felsic bands with a thickness of approximately 1 mm were visible. These felsic bands were laterally discontinuous and tapered off within the core samples. The particles within the bands were fine-grained, mainly silt-sized. Compared to lagoon shale, the tidal flat shale exhibited significantly lower resistivity. In imaging logs, the color appeared noticeably darker. The low response was attributed to the development of felsic bands within the tidal flat shale. The interbedding of thin sand and mud layers resulted in individual shale layers that were thinner than the vertical resolution of resistivity logging tools, leading to the measured apparent resistivity values being lower than the true formation resistivity. Consequently, the resistivity of tidal flat shale in the study area was significantly lower than that of the lagoon shale. Shale in subaqueous distributary channels was dark gray to gray-black and contained abundant siderite concretions occurring in banded and irregularly massive forms. These concretions mainly consisted of microcrystalline siderite grains, with minor felsic detrital particles, and were commonly associated with carbonaceous debris. Carbon and oxygen isotope analyses indicated that the formation of siderite in the delta front was influenced by organic matter and the water chemistry of the depositional environment. After deposition in the delta front, terrestrial carbonaceous debris decomposed, releasing CO₃^2-, which combined with Fe²⁺ in the pore water to form siderite. The water coverage in the delta front also provided favorable conditions for siderite development. The abundant siderite in the shale reduced the formation conductivity and radioactive element content, resulting in low resistivity, uranium, and thorium readings on logs. Conversely, the high photoelectric absorption cross-section (P_e) of siderite increased the P_e value of the formation. Shale in interdistributary bays exhibited diverse colors, including dark gray, gray, and variegated colors, indicating strong water-level fluctuations during deposition and the presence of both subaqueous and emergent environments. Siderite was less developed in the interdistributary bay shale. Consequently, its resistivity and radioactive element content were significantly higher, and its P_e value was significantly lower than those of the subaqueous distributary channel shale. The depositional evolution of the Taiyuan and Shanxi Formations recorded a transition from the peak of the Late Paleozoic marine transgression to subsequent regression. Consequently, the depositional environments of shale transitioned from barrier coastal to deltaic facies, with shale sequentially developing in lagoon, tidal flat, delta front, and delta plain subfacies from bottom to top. The measured total organic carbon content of the shale varied among depositional environments: lagoon shale (0.11%~19.30%, avg. 3.81%), tidal flat shale (0.70%~17.99%, avg. 4.18%), subaqueous distributary channel shale (0.29%~5.91%, avg. 2.45%), and interdistributary bay shale (0.03%~7.36%, avg. 2.21%). A comparison showed that the tidal flat shale had the highest average total organic carbon abundance, followed by lagoon shale, subaqueous distributary channel shale, and interdistributary bay shale. Overall, the organic matter abundance of shale from barrier coastal facies was higher than that from deltaic facies. The organic matter types of shales from different depositional environments were similar, primarily Type III kerogen with some Type II₂, indicating a mixed input of terrestrial higher plants and aquatic lower organisms, with terrestrial higher plants being the dominant source. The measured R₀ values ranged from 0.60% to 1.12%, indicating that the organic matter was generally in a low-maturity to mature stage. The total organic carbon abundance of tidal flat shale (avg. 4.18%) was slightly higher than that of lagoon shale and significantly higher than that of deltaic shales, making it favorable for shale gas generation. The higher content of felsic particles in tidal flat shale enhanced the development of macropores and micropores, which were beneficial for shale gas storage. Meanwhile, the felsic particles increased the brittle mineral content, thereby enhancing the stimulation potential of the shale. Gas logging data also indicated gas-rich intervals within the shale. Overall, the Taiyuan Formation exhibited stronger gas logging responses than the Shanxi Formation, and tidal flat shale outperformed lagoon shale. These characteristics indicated that the tidal flat shale in the upper Taiyuan Formation was the most promising gas-rich interval. During the Early Permian deposition of the upper Taiyuan Formation, the marine transgression in North China mainly originated from the southeast. Tidal flat deposits were extensively developed across most of the Huanghua Depression, while barrier islands and lagoon deposits were confined to the eastern Chenghai area. Tidal flats were primarily distributed in the western part of the Huanghua Depression, with a northeast-southwest trend. Within this trend, the Cangxian uplift, Dongguang, Wumaying, Kongdian, Beidagang, Qibei, and Qinan buried hills were identified as favorable areas for shale gas exploration.

The Xihu Sag in the East China Sea Shelf Basin is a large Mesozoic-Cenozoic oil and gas-bearing sag with abundant oil and gas resources. However, coal-bearing strata are widely developed in this area. In the Pingbei slope zone, the oil and gas-bearing Pinghu Formation strata develop tide-influenced deltaic deposits, characterized by thin interbedded layers of sandstone, mudstone, and coal. The coal seams are thin and develop along with sand bodies. The lithology is mainly dominated by sandstone-mudstone interlayers interbedded with coal, featuring thin single layers, multiple layers, and rapid lateral changes. The thin coal layers in the coal seam section show abnormal features in logging curves, including low velocity, low density, high neutron values, and high resistivity. When conventional acoustic logging curves are used for inversion, the accuracy of sand body prediction is reduced. Therefore, eliminating the influence of coal seams and accurately identifying sand bodies has become an urgent issue. Based on an analysis of the logging curve characteristics of coal-bearing sections, a fitting method for acoustic logging curves in coal measure strata was proposed. Using drilling data, logging observations, and core analysis, the strata were divided into coal-bearing sections and non-coal sections. For non-coal sections, a petrophysical model was constructed for logging curve fitting, which was commonly applied in conventional clastic rock analysis. For coal-bearing sections, fitting was carried out using statistical regression techniques based on empirical formula methods. Subsequently, the results for coal-bearing and non-coal sections were matched and combined. The fitted acoustic primary wave velocity curve corrected the abnormal values caused by borehole collapse in coal seams. The correlation coefficient between the original curve and the fitted curve was 0.82. The fitted and corrected velocity curve was then used for inversion to delineate sand bodies. Application in a gasfield showed that the fitted and corrected acoustic primary wave velocity curve based on this method effectively predicted sand bodies in inversion, and the prediction results were consistent with drilling data, proving useful for identifying lithologic structural traps. This study provides an effective method for reservoir prediction in thin coal measure strata. By separately fitting the acoustic logging curves of coal-bearing and non-coal sections, the interference from coal seams is eliminated, and high-precision sand body prediction is achieved.

During coalbed methane (CBM) production, coal fines within the reservoir can migrate, potentially blocking pore throats and resulting in a significant reduction in reservoir permeability. This process adversely affects the final CBM yield. To investigate the influence of coal fines migration on the porosity and permeability of cataclastic coal reservoirs, this study focuses on the processes of fines initiation, migration, and deposition within reservoir channels. The pore size distribution characteristics of cataclastic coal were analyzed using low-field nuclear magnetic resonance and low-temperature liquid nitrogen adsorption experiments. Subsequently, a three-dimensional pore network model was constructed, and a numerical model for coal fines migration and deposition in pore throat channels was developed. By integrating with an existing mechanical model for coal fines initiation and a probabilistic model for particle deposition and throat blockage, the Monte Carlo method was used to simulate the migration and blockage of coal fines within reservoir pores. A numerical simulation program written in Python was developed to simulate coal fines migration within the pore network of the cataclastic coal matrix. The variations in porosity and permeability of the reservoir during coal fines migration, as well as the influence of this migration, were discussed. The analysis revealed the internal mechanisms by which pressure difference and coal fines particle size influenced coal fines output and model permeability. Both factors were significant, and their interactions were complicated. Specifically, the particle size of coal fines directly affected their migration, deposition, and output characteristics under different hydrodynamic conditions. Under low pressure difference and low flow velocity, large coal fines particles were difficult to mobilize and initiate migration. In contrast, under high pressure difference and high flow velocity, these particles became mobile but were more likely to block effective pores, resulting in a sharp decline in permeability. In addition, an increase in pressure difference had dual effects. It promoted coal fines output but also accelerated permeability decline rate. As the displacement pressure difference increased, the deposition location of coal fines shifted toward the outlet end, accompanied by a higher proportion of small throats. When the coal fines particle size was constant and smaller than the throat radius, a displacement pressure threshold was observed. On either side of this threshold, the relationship between the permeability decline rate and the displacement pressure showed distinct trends. During the drainage and depressurization stages of actual CBM production, the output characteristics and particle size distribution of coal fines served as important indicators for evaluating production efficiency and reservoir permeability changes. As drainage intensity gradually increased, the output intensity of coal fines experienced an initial slow growth followed by a rapid decline. Simultaneously, the particle size distribution of the produced coal fines reached its widest range, encompassing sizes from small to large, particularly during the initial drainage stage. When the drainage intensity was low, only small coal fines particles were mobilized and produced by fluid flow. To further investigate this, numerical simulations were conducted to replicate low drainage intensity conditions by setting a low pressure difference. The simulation results indicated that under low flow rates, small coal fines could indeed migrate and be produced, accompanied by a relatively gentle decline in reservoir permeability. These results were consistent with field observations under low drainage intensity, confirming the accuracy and reliability of the numerical simulation in predicting coal fines migration behavior. Furthermore, the numerical simulation results were compared with those from physical simulation experiments on coal fines migration. The model simulation results showed that as drainage continued, large coal fines particles settled preferentially within the pores. The deposition of these large particles formed channel barriers, blocking pore throats and significantly reducing permeability. Simultaneously, the deposition probability of small coal fines also increased rapidly. This made subsequent migration and production of coal fines increasingly difficult, resulting in a rapid decrease in coal fines production over time. In addition, physical simulation experiments of coal fines migration in cataclastic coal reservoirs provided valuable reference data. The experimental results showed that the permeability decrease of coal samples primarily occurred during the early stage of water flooding, and a higher fracture density corresponded to a higher average permeability. Pores and fissures with diameters greater than 1 000 nm served as the main channels for coal fines migration and blockage. The migrating coal fines further reduced permeability by plugging connected pores larger than 10 000 nm. These findings were consistent with the numerical simulation results, further confirming the alignment between permeability evolution and coal fines production during migration in cataclastic coal reservoirs. In simulations, high drainage intensity was simulated by setting a high pressure difference. When large coal fines were introduced, their deposition locations shifted compared with those under low pressure differences. Also, fines output decreased, and deposition became concentrated near the outlet end. When small coal fines were introduced, fines output increased significantly, and the permeability reduction was less severe than that caused by large coal fines. Overall, the model simulation results were consistent with coal fines output observed in actual production under increased drainage intensity. The numerical simulation results indicated that larger coal fines particles led to more concentrated deposition and blockage near the inlet end, with a smaller overall deposition range. Under low pressure difference, coal fines deposition was mainly concentrated near the inlet end. As the pressure difference increased, the deposition locations of coal fines shifted closer to the outlet end, and the deposition range expanded. In visual physical simulations of coal fines migration within fractures, the deposition area gradually decreased from the inlet toward both ends along and perpendicular to the main migration direction. In summary, the numerical simulation results were consistent with the permeability changes and coal fines deposition patterns observed during coal fines migration in physical simulation experiments.