The deep coalbed methane (CBM) resources (buried deeper than 1500 m) in North China exceed 30 trillion cubic meters, with significant breakthroughs in exploration, making it a new frontier for natural gas production growth. However, it faces key issues, including complex preservation conditions, unclear controls on enrichment and high productivity, and large production variations. In order to clarify the control factors of preservation conditions of deep CBM, the coal quality, lithology combination, and structural preservation characteristics of typical deep CBM exploration wells in North China are systematically analyzed with multidisciplinary analysis methods of geology, geochemistry, and geophysics. This study reveals that the differential preservation of deep CBM is controlled by the dynamic coupling mechanism of adsorption self-sealing, physical property sealing, and structural preservation system: (1) Favorable coal quality is the basis of strong adsorption. Coal with low ash content and a high evolution degree is characterized by a large Langmuir volume, a great critical depth, and strong self-sealing ability. (2) Tightly lithology combination is a barrier to deep free gas dissipation. Limestone and mudstone exhibit low porosity, a small throat radius, and high breakthrough pressure, resulting in good physical sealing conditions and a high total retained gas content. (3) Continuous and stable structural preservation is the key to free gas enrichment. Late-stage uplift with low amplitude and weak tectonic activity is conducive to free gas accumulation, resulting in a high-pressure coefficient. In summary, areas characterized by deep burial, low-ash coal, limestone/mudstone roof rocks, and structural stability are favorable for deep CBM preservation. The study of differential preservation of deep CBM deepens the understanding of enrichment and high productivity, and provides a theoretical basis for optimizing favorable exploration and development targets.

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

By analyzing the tectonic and sedimentary environments for the formation of organic-rich shales in China’s continental lacustrine basins, we identify significant differences in the development of high-quality continental source rocks across various types of lacustrine basins. For shale sequences deposited in fresh-water lacustrine basins, the main lithofacies are felsic and clayey shales, as observed from the 1^st member of the Upper Cretaceous Qingshankou Formation (K₂qn¹ section) in the Songliao Basin and the 7^th member of the Triassic Yanchang Formation (T₃yc⁷ section) in the Ordos Basin. For shale sequences developed in a saline lacustrine environment, however, carbonates and evaporites are dominant lithofacies, as represented by the Paleogene Shahejie Formation in the Jiyang Depression. There are three types of lithofacies assemblages for Chinese lacustrine shales, that is, the shale interbedded/intercalated with sand, mixed shale, and clayey shale. These lithofacies assemblages determine the hydrocarbon source-reservoir coupling characteristics, differential evolution of hydrocarbon generation, and property differences of in-situ fluids in the lacustrine organic-rich shales. The shale interbedded/intercalated with sand assemblage is characterized by source-reservoir separation and near-source migration. The mixed shale assemblage shows macroscopic integration and microscopic separation between source rock and reservoir. In contrast, the clayey shale acts as both the source and reservoir of in-situ generated hydrocarbons, featuring pervasive oil distribution. As revealed by evidence, inorganic pores provide the most favorable storage space for lacustrine shale oil in medium-low maturity, and form effective pore-fracture networks for hydrocarbon transport together with multi-type and multi-scale microfractures. Self-sealing capacity of shale is conducive to the in-situ or proximal preservation of shale oil and gas. Comparison of typical continental shale sequences in the Chinese sedimentary basins indicates that favorable source-reservoir coupling, suitable thermal maturity level, and self-sealing capacity of shale are the major controls for oil enrichment in lacustrine shale. This study also presents a preliminary model for differential enrichment of lacustrine shale oil in China. Therefore, the laminated shales in medium-low maturity in gentle slope zones and the clayey shale-rich strata in medium-high maturity in deep sags should be prioritized in lacustrine shale oil exploration in downfaulted lacustrine basins. Moreover, both the shale interbedded/intercalated with sand and the clayey shale in medium-high maturity are crucial to making breakthroughs in lacustrine shale oil exploration therein.