The potential of deep coalbed methane resources is substantial. Gas content is an important parameter for resource assessment. At present, the gas content test method commonly used for shallow coal reservoirs is not suitable for determining deep coalbed methane gas content. Therefore, it is urgent to establish a prediction method for deep coalbed methane gas content. This study aims to quantitatively predict the gas content of coalbed methane in deep coal reservoirs and uncover its influencing factors. For this purpose, we selected the Daning-Jixian area, a region in China with relatively advanced development of deep coalbed methane, as a case study. It established a prediction model for adsorbed gas and free gas content in deep coal reservoirs through a series of experimental tests, encompassing gas content, coal quality, isothermal adsorption, and nuclear magnetic resonance. The model sheds light on the impact of coal-rock characteristics, coal quality attributes, and pore characteristics on adsorbed gas and free gas content. The results show that adsorbed gas dominates in deep coal reservoirs with a high metamorphic degree and that the average proportion of adsorbed gas under reservoir burial depth is 80.15%. At a depth of approximately 1800~2000 m, a turning point is observed where adsorbed gas content begins to decline. Beyond this depth range, the detrimental effect of temperature on coalbed methane content surpasses the beneficial impact of pressure. Coal quality characteristics play a major role in controlling adsorbed gas content, and an increase in water content and ash yield significantly reduces the adsorption performance of coal reservoirs. The content of free gas increases with the increase in burial depth, with its controlling factors primarily being confining pressure and porosity. The increase in the proportion of micropores in the pores of deep coal reservoirs has an adverse effect on the content of free gas. The proportion of adsorbed gas in deep coal reservoirs gradually decreases with the increase in burial depth, while the proportion of free gas gradually rises with the increase in burial depth. The development potential of free gas cannot be overlooked in the exploration and development of deep coalbed methane.

The in situ stress plays a crucial role in variations in coal permeability, hydraulic fracturing behavior, and accordingly coalbed methane (CBM) productivity. As the depth increases, the effects of in situ stress will become more prominent. In the Shizhuang block, present-day stress magnitude and permeability of coals at depths >800 m were measured with multiple-cycle hydraulic fracturing and injection falloff test, respectively. The results show that most seams are under pressure reservoirs with pressure gradient 1200 m) with increasing depth. Strike-slip fault stress regimes are predominant, while seams with depth >1400 m are subjected to a normal fault stress regime. Coal permeability tends to decrease gradually with depth and tends to be convergence to 0.01 mD. Considering extremely low permeability of these deep seams, hydraulic fracturing must be applied to create seepage channels for gas and water drainage. Although the high horizontal stress difference in deep seams is favorable for the generation of longer and simple hydraulic fractures, there is no obvious relations between fracture length and gas productivity as poor-support fractures and limited sand migration distance. The current hydraulic fracturing missed the variable stress regimes and permeability at various depth, but used the similar fracturing schemes, leading to significant reduction in gas productivity with depth. Using the high viscosity fracturing fluid, great sand volume, big injection rate, and low sand concentration are recommended for hydraulic fracturing. Single-branch horizontal well with staged fracturing show better applicability for deep CBM extraction.

The Zhuozishan coalfield at the western margin of the Ordos Basin is one of the main coal-mining areas in China, and recent explorations have revealed the great potential for coalbed methane (CBM) resources in its Carboniferous and Permian strata. In this paper, the controlling factors of CBM enrichment of the major coals are studied in this coalfield and the CBM resources are estimated based on the analysis of the coal petrology and compilation of literature data on the gas content. The result of the coal petrology analysis of 10 samples shows that the vitrinite content of No. 16 coal (71.9-77.3%) is higher than that of No. 9 coal (59.1-65.1%), and the inertinite content of No. 16 coal (18.9-23.5%) is lower than that of No. 9 coal (30.1-34.9%). The R _o,max value of No. 16 coal (1.18-1.35%) is higher than that of No. 9 coal (1.04-1.13%), and both coals are of medium rank. Due to greater thickness, deeper burial depth, and better coal petrology characteristics, the No. 16 coal seam of the Taiyuan Formation is selected as the major coal seam for CBM resource estimation, which has a thickness of 1-6 m and a present-day burial depth of 200-1100 m. The gas content of this coal seam varies mostly between 4 and 10 m³/t. Positive correlation between the coal seam thickness as well as present-day burial depth and the gas content suggests that the thick and deeply buried coal seams are favorable for CBM preservation. The ash yield shows an insignificant negative correlation with the gas content, indicating that ash yield is not an important factor for CBM enrichment. The syncline hinges located below the thrust zones show higher gas content due to greater burial depths. In contrast, the anticline hinges at shallower depths tend to have lower gas contents. Based on the combined information about sedimentary environments, structural patterns, and hydrogeology, two CBM accumulation models are put forward in the study area that include syncline-hydraulic plugging below thrust nappe and fault-confined aquifer plugging. The volumetric method is used to estimate the CBM resources, and results indicate that the CBM resource in the whole coalfield is 428.78 × 10⁸ m³, and the total resource abundance is 0.74 × 10⁸ m³/km². Two favorable areas for the CBM exploration are optimized based on the resource amount and resource abundance. One of the favorable areas is the Kabuqi area in the northern part of the coalfield, and another is the Baiyunwusu area in the central part of the coalfield. These two areas will be the CBM priority exploration areas at the western margin of the Ordos Basin.

Important breakthroughs have recently been achieved in deep coalbed methane (CBM) exploration and development in regions such as the eastern margin of the Ordos Basin, China. Investigating the development characteristics of various-scale pores in deep coalbeds is of great significance for resource assessment and selection of favorable zones for CBM exploration. Herein, six deep coal samples were selected from the Shanxi and Taiyuan Formations in the Daning-Jixian block on the eastern margin of the Ordos Basin. Low-pressure CO₂/N₂ adsorption (LP-CO₂/N₂GA) and high-pressure mercury intrusion (HPMI) methods were employed to analyze pore volume, specific surface area, and pore size distribution, thereby evaluating the full-scale pore characteristics. Furthermore, the fractal dimension characteristics of deep coal rock pores were elucidated, revealing the influence of pore structure, burial depth, and coal composition. The results indicate that micropores in deep coal rocks have the highest volume and specific surface area proportions, while mesopores have the smallest volume proportion, and macropores make the least contribution to the total specific surface area. The V-S, Frenkel-Halsey-Hill, and Sierpinski models were suitable for calculating the fractal dimensions of micropores, mesopores, and macropores with LP-CO₂GA, LP-N₂GA, and HPMI experimental data, respectively. Other than the relatively smaller mesopore fractal dimension of samples 20-8 and 20-10, the micropore, mesopore, and macropore fractal dimensions successively increased in the other four samples. The comprehensive fractal dimension, which exhibited a decreasing trend with increasing pore volume and specific surface area, was negatively correlated with burial depth, mineral and moisture contents, and ash and volatile component yields, while it was positively correlated with vitrinite and fixed carbon contents.

Coal texture is important for predicting coal seam permeability and selecting favorable blocks for coalbed methane (CBM) exploration. Drilled cores and mining seam observations are the most direct and effective methods of identifying coal texture; however, they are expensive and cannot be used in unexplored coal seams. Geophysical logging has become a common method of coal texture identification, particularly during the CBM mining stage. However, quantitative methods for identifying coal texture based on geophysical logging data require further study. The support vector machine (SVM), a machine-learning method, has received great interest due to its remarkable generalization performance, and it has been used to quantitatively identify hard and soft coal using geophysical logging data. In this study, four well-logging curves, the acoustic time difference (AC), caliper log (CAL), density (DEN), and natural gamma (GR), were used for coal texture analysis. Hard coal (undeformed and cataclastic coal) exhibited higher DEN, GR, lower CAL, and lower AC than soft coal. The accuracy rate of coal texture identification was highest (97%) when the linear kernel function was applied, and the maximum training accuracy rate was achieved when the penalty parameter value of the linear kernel increased to 1. The results of verification with a newly cored CBM exploration well indicated that the SVM-based identification method was effective for coal texture analysis. With the increasing availability of data, this method can be used to distinguish hard and soft coal in a coal-bearing basin under numerous sample learning conditions.

The southern Junggar Basin, Xinjiang, has abundant coalbed methane (CBM) resources. Currently, the Baiyang River development pilot test area (BYR block for short) in the Fukang east block has achieved large-scale CBM development, but the productivity characteristics and its controlling factor are still unclear. Based on the field production data of the BYR block and experimental tests, this paper summarizes the gas and water production characteristics and presents the analysis results of the geological and geochemical responses to the productivity of CBM wells. The productivity of CBM wells in the BYR block was generally characterized as medium-to-low yield. The productivity was jointly controlled by the burial depth, structure condition, thickness and number of co-production coal seams, and hydrogeological conditions. The gas production first increased and then decreased with the increase in the burial depth of the coal seam, and a burial depth between 750 and 1000 m was the most beneficial to increasing the gas production due to the good gas preservation conditions and suitable permeability and stress conditions. The total thickness of the co-production coal seams had a positive effect on the productivity of gas wells, but the productivity was also affected by the number of co-production coal seams and interlayer interference. In the BYR block, the co-production of the nos. 41 and 42 coal seams was the most favorable combination form for CBM drainage. The productivity of CBM wells had a good response to the Na⁺, K⁺ and HCO₃⁻ concentrations but a poor response to δD-H₂O and δ18O-H₂O. Based on the concentrations of the main ions and TDSs of the coal seam water, a productivity response index δ* was established, and there was a good positive correlation between the productivity and δ*.