Significant breakthroughs have been achieved in the exploration and exploitation of deep coalbed methane (CBM) in China, establishing CBM as an emerging focus of academic research. The San Juan Basin stands out as the most successful basin in CBM development to date. Therefore, the geological understanding and development experience of this basin can provide critical implications. In this study, we systematically organize geological insights into CBM in the San Juan Basin and analyze gas well production data up to 2019. The results indicate that the gas produced from the fairway zone of the basin consists of approximately 25%~50% in-situ thermogenic gas, 12%~60% migrated thermogenic gas, and 15%~30% secondary biogenic gas. The basin contains three pressure systems: overpressured, transitional, and underpressured. The overpressured zones are characterized by vitrinite reflectance (R_o) values of coals generally exceeding 0. 8% and an average CO₂ content of up to 6. 5%, with dry gas predominating. In contrast, the underpressured zones show R_o values of coals below 0. 7% and CO₂ contents generally below 2. 0%, with wet gas being dominant. The primary factors governing the high productivity of the fairway zone include a favorable sedimentary setting (thick coal seams + shale roof), moderate coalification (generation of thermogenic gas and suitable for the generation of biogenic gas), and significant hydrological regulation and well-developed structural framework for preservation. The productivity of CBM wells in the basin is jointly controlled by pressure systems, reservoir physical properties, and hydrogeological regulation, with gas and water contributions varying across different pay zones. The San Juan Basin has cumulative CBM production exceeding 650 × 10~9 m³ of CBM. Within the fairway zone, approximately one-third of CBM wells have single-well cumulative production of greater than 113 × 10~6 m³. Wells in this zone exhibit gas production cycles lasting more than 300 months, with most yielding over 18. 2 × 10~6 m³ of gas in the first 24 months of production. To date, two high-production models of CBM development have been identified worldwide. The first model is exemplified by the San Juan, Powder River, and Surat basins, where large-scale stable gas production is primarily supported by favorable natural conditions, including shallow burial depths, large coal seam thickness, high permeability, and recharge by secondary biogenic gas. The second model is represented by the Ordos Basin, characterized by great burial depths, high coal ranks, low permeability, favorable preservation conditions, and the predominance of in-situ thermogenic gas. In this case, the effective CBM recovery relies heavily on stimulation technologies. For the future development of the CBM industry, it is necessary to continuously advance the integrated geological and engineering understandings to achieve large-scale commercial CBM recovery across different coal ranks and basin types.

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 2000 m or less holds tremendous potential for exploration and production. Through a systematic analysis of lowrank 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 (>5000 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 depthcontrolled 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 thinbedded 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.

Multiple tight gas reservoirs are well developed in the Upper Paleozoic sequences at the eastern margin of the Ordos Basin. An accurate understanding of the pressure evolution process of gas reservoirs will be of guiding value to gaining more insights into tight gas accumulation and achieving high and stable gas production in this region. In this study, drilling, logging, and core fluid inclusion test data, as well as simulations of burial and thermal evolution histories are integrated to reveal the pressure evolution of the Upper Paleozoic gas-bearing systems at the eastern margin of the Ordos Basin. The results show that reservoirs in the study area exhibit underpressure, slightly underpressure, and normal pressure systems from bottom to top. The homogenization temperature and salinity of fluid inclusions exhibit continuous distributions overall, suggesting a continuous hydrocarbon charging process. The Taiyuan, Shanxi, and Lower Shihezi formations demonstrate a positive correlation between the homogenization temperature and salinity of fluid inclusions, suggesting a rapid hydrocarbon charging process following near-source hydrocarbon generation. In contrast, the Upper Shihezi and Shiqianfeng formations exhibit a negative correlation between the homogenization temperature and salinity due to the long-distance fluid migration and charging, as well as the rebalancing of fluid inclusions in gas reservoirs under the influence of the Zijinshan tectono-thermal event. During the Mid-Cretaceous, the study area experienced the generation of large quantities of hydrocarbons, leading to the anomalously high reservoir pressure ranging from 34.89~38.26 MPa, followed by a decrease at later stages under the uplifting of strata. For the pressure drop, 50.31%~57.85% was caused by the decline in formation temperature, 28.25%~41.95% by natural gas swelling-induced gas migration (predominantly in upper strata), and 0.37%~0.79% by pore rebound. The findings of this study systematically reveal the pressure system evolution of the Upper Paleozoic tight gas reservoirs in the Ordos Basin and the origin of the current reservoir pressure formation. These will be of referential value to understanding the enrichment and accumulation patterns of tight gas in the Ordos Basin and the like.