Effect of Stress Relief on Coal Seam Gas Migration: Experiment and Application Discussion.

Stress relief-induced enhanced permeability is one of the crucial measures for promoting gas desorption flow and strengthening gas extraction. In order to examine the impact of stress relief and its magnitude on gas migration, this article explores the gas desorption flow during the stress relief process and elucidates the influence of stress relief degree on gas extraction. The results indicate that considering the analysis of the pore structure effect on gas seepage, the four coal samples' permeability is ranked as PDS > CSL > JZS > GHS. Throughout the stress relief process, the gas desorption rates of different coal samples under various stress paths exhibit varying degrees of increase. As an illustration, following 3600 s of stress alterations, the gas desorption rate of CSL1# experiences a notable increase, surging by 2.57 times; PDS2# shows 55.93 times increase after 4200 s, and JZS3# exhibits 3.13 times increase after 5400 s. A stress relief degree model is established to investigate the variation of horizontal stress and stress relief degrees under different borehole spacings, vertical stresses, cohesion, and internal friction angles for various borehole diameters (coal output). Optimal stress relief is achieved with a borehole diameter greater than 1.52 m with a borehole spacing set at 4 m. When the stress relief degree exceeds 30%, the corresponding borehole diameter ranges for different vertical stresses are 1.49-1.6 m. Similarly, for cohesion, the ranges are 1.25-1.68 m, and for internal friction angles, the ranges are 1.39-1.53 m. The research results can provide valuable insights for determining parameters in the on-site construction of stress relief boreholes.

Effects of Mechanical Properties on Gas-Water Flow Characteristics around Boreholes: Implementation of Damage-Based Coupling Models.

Neglecting the coal damage effect around a borehole could result in low accuracy of gas extraction seepage analysis. A fluid-solid coupling model incorporating coal stress and damage, gas diffusion, and seepage was established. Reliability of the proposed model was validated using field data. Variation characteristics of gas-water phase parameters in the borehole damage zone during gas drainage were analyzed. Meanwhile, effects of equivalent plastic strain, lateral pressure coefficient, internal friction angle, cohesion, Young's modulus, and Poisson's ratio on the damage state and spatiotemporal change properties of gas extraction flow were investigated. Results indicate that due to coal damage, permeability shows a three-zone distribution around the borehole, among which the fracture zone has the highest permeability, approximately 40 times of the original value. Permeability in the plastic zone decreases rapidly, while permeability is the smallest in the elastic zone. Coal permeability within the damage zone increases with continuous gas extraction. A smooth and low-value zone occurs for both fracture and matrix gas pressures. With the increase in equivalent plastic strain, the damage zone decreases, while peak permeability in the damage zone rises, and gas pressure in the smooth low-pressure zone continues to drop. The damage zone becomes smaller with an increasing lateral pressure coefficient, while those plastic and elastic zones become larger. The damage zone area corresponding to the lateral pressure coefficient of 0.89 is 82.3% smaller compared with that of 0.56. As internal friction angle and cohesion rise, the damage zone gradually decreases and shifts from a butterfly shape to elliptical shape. When Young's modulus is heterogeneously distributed, except for concentrated shear damage zones around the borehole, punctate microdamage zones are also found at positions far from the borehole. Those damage zones gradually become smaller as shape parameters of the Weibull distribution get larger. The above findings are expected to offer theoretical support and practical guidance for borehole drilling and efficient extraction of clean methane resources.

Oil Has a Higher Methanogenic Potential than Coal in an Oil-Bearing Coal Seam.

The presence of oil in coal seams from coal-oil symbiosis areas poses a serious threat to the safe and efficient mining of coal. However, the information about the application of microbial technology in oil-bearing coal seams was insufficient. In this study, the biological methanogenic potential of coal and oil samples in an oil-bearing coal seam was analyzed by anaerobic incubation experiments. The results showed that the biological methanogenic efficiency of the coal sample increased from 0.74 to 1.06 from day 20 to day 90, and the biological methanogenic potential of the oil sample was about twice as high as that of the coal sample after 40 days of incubation. The Shannon diversity and observed operational taxonomic unit (OTU) number of oil were lower than those in coal. The major genera in coal were Sedimentibacter, Lysinibacillus, Brevibacillus, etc., and the major genera in oil mainly included Enterobacter, Sporolactobacillus, and Bacillus. The methanogenic archaea in coal mainly belonged to the order Methanobacteriales, Methanocellales, Methanococcales, etc., and the methanogenic archaea in oil mainly belonged to the genera Methanobacterium, Methanobrevibacter, Methanoculleus, and Methanosarcina. In addition, metagenome analysis showed that functional genes belonging to processes such as methane metabolism, microbial metabolism in different environments, and benzoate degradation were in a higher abundance in the oil culture system, while genes belonging to sulfur metabolism, biotin metabolism, and glutathione metabolism were in a higher abundance in the coal culture system. The metabolites specific to coal samples mainly belonged to phenylpropanoids, polyketides, lipids, and lipid-like molecules; meanwhile, the metabolites specific to oil were mainly organic acids and their derivatives. In summary, this study has a reference value for the elimination of oil from coal in oil-bearing coal seams and can be used to separate oil from oil-bearing coal seams and reduce the hazard brought by oil for coal seam mining.

Effective Approach with Extra Desorption Time to Estimate the Gas Content of Deep-Buried Coalbed Methane Reservoirs: A Case Study from the Panji Deep Area in Huainan Coalfield, China.

In this study, 11 core coal samples were collected from deep-buried coalbed methane (CBM) reservoirs with burial depth intervals of 900-1500 m for gas estimation content by a direct method. In desorption experiments, the cumulative gas desorption data were recorded within 2 h in the field on the basis of the China National Standard method. For accuracy, two improved methods were proposed. The results show that the gas contents of deep-buried coal samples based on the China National Standard and mud methods are 3.58-9.89 m3/t (average of 6.03 m3/t) and 3.74-10.05 m3/t (average of 6.20 m3/t), respectively. The proposed Langmuir equation and logarithmic equation methods exhibited nonlinear relationships between the cumulative desorption volume and desorption time, which yield values of 6.33-13.34 m3/t (average of 9.36 m3/t) and 6.15-13.86 m3/t (average of 10.37 m3/t), respectively. In addition, the two proposed methods combine the raw data within 2 h by the China National Standard method and additional desorption points during extra time, which are helpful for the ability of the hypothetical methods to calculate the gas content. The Langmuir equation method is a relatively more accurate method to estimate the gas content in comparison with the proposed logarithmic method, which is based on the relative error and comparison plots of actual data and simulated results. From the perspective of numerical value, the Langmuir equation method gives values 1.06-3.39 times (average of 1.86 times) those of the China National Standard method. These analyses show that the proposed Langmuir equation method with extra desorption points is an effective method to determine the gas content of deep-buried CBM reservoirs.