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Microorganisms are one of the main driving forces of the cycle of carbon and other life elements in the underground environment. The natural environment is the comprehensive result of these microorganisms. In contrast, the study of coal reservoir microorganisms is mostly under laboratory conditions, which limits people's understanding of the symbiotic relationship between microorganisms, the interaction between microorganisms and the environment, and the distribution differences of microbial communities in the region. Similarly, the carbon cycle of the underground environment driven by essential microorganisms in coal reservoirs cannot be further studied. The geochemical process of underground methane generation and oxidation is critical in discussing the production and consumption of biomethane in the underground environment and the metabolic behavior of microorganisms. For this reason, we conducted biogeochemical tests and microbial sequencing on the water produced by coalbed methane wells in the south of the Qinshui Basin to analyze and improve the understanding of the distribution difference and metabolic behavior of microbial communities in coal reservoirs. The concentration of Cl− and HCO3− in the detention environment in the study area increases, while the concentration of SO42−, NO3−, NO2−, and Fe3+ decreases with the increase of coal seam depth, reflecting the distribution difference of hydrochemical environment and redox conditions of the underground reservoir in the study area. The results of microbial sequencing showed microbial methanogenesis in the study area, but it could also be consumed by microbial oxidation simultaneously. The microbial communities related to methane production and consumption had diversity distributions similar to geochemical parameters and geographical patterns. Methanogens and dissolved inorganic carbon isotopes confirmed the potential of in situ methane generation. Still, biomethane's enrichment and accumulation conditions and the impact of aerobic/anaerobic oxidation of methane need further study. [ABSTRACT FROM AUTHOR]

Geological sequestration of carbon dioxide (CO2) is one of the key methods to attain peak CO2 emissions and carbon neutrality in unworkable or abandoned coal seams. To study displacement characteristics and effect of geological sequestration of CO2 in water-saturated coal seams, the pore structure of coal samples from three different mines was first investigated by nuclear magnetic resonance technique. Then, the CO2 was injected into water-saturated coal sample, and helium was used as the control group. Next, the CO2-injected coal sample was sealed with water. Finally, water was returned by unloading pressure. The results showed that the pores of the three types of coals were mainly micropores and transition pores. Moreover, the fractal dimension of the pores was distributed in the range of 2.236–2.655. The displacement experiment found that the water displaced by CO2 and helium was mainly movable water in macropores, but there were significant differences in the displacement characteristics of the two. On the whole, the amount of water displaced by CO2 was more than that by helium, and the difference between the water volume displaced by CO2 and helium was reflected mainly in the adsorption of CO2 on the coal surface. CO2 occupied the adsorption sites on the coal matrix surface, which reduced the interaction between water and coal matrix surface and improved the displacement efficiency. In contrast, helium did not show adsorption capacity on the coal surface. In the water injection stage, water can only enter the larger pores due to the retention and adsorption of CO2 in the coal. The water saturation of the coal sample after the return drainage increased by 10.24% compared with that before water injection, indicating that the water injected into the coal sample was not discharged completely. This study provides an experimental basis for investigating the characteristics of pore structure in coal, CO2 displacement in water-saturated coal seams, and CO2 geological sequestration. [ABSTRACT FROM AUTHOR]

Due to the large non-homogeneity of coal reservoirs, there is a large uncertainty about the extent of the impact on coal bed methane production capacity. The Hanchengbei Block has the problems of early exploration, less available production data, and large variations in developed production capacity within a single well group during test production. Therefore, how to use the existing data to analyze the geological factors affecting the development of coalbed methane in the Hanchengbei Block is particularly important. In this paper, based on the coal seam properties and production characteristics of the Hanchengbei Block, a three-dimensional geological model of the area was meticulously constructed using Petrel 2015 modeling software. Through the utilization of stochastic modeling techniques, reservoir attributes were visualized in three dimensions, and probability distribution functions as well as confidence intervals for different geological parameters were derived through geological statistics. Building upon this foundation, a dual-layer geological model incorporating multiple factors was established using Comet3.0 numerical simulation software. Monte Carlo simulation methods were then employed to simulate the effects of various geological parameters on gas production, yielding corresponding simulation results. Through normalization processes, parameter sensitivity was analyzed to determine the primary controlling factors influencing production capacity. The results show that the thickness of the No. 5 coal seam in the Hanchengbei Block is mainly distributed in the range of 1.35–6.89 m; the gas content is 10.28–15.52 m3/t; and the permeability is 0.014–0.048 mD. Under their joint influence, the average gas production of Hanchengbei Block is between 310–720 m3/d. The main factors affecting the capacity of Hanchengbei Block are the thickness and gas content of the coal seam. This study can provide a basis for the subsequent optimization of favorable areas, the formulation of drainage systems, and the design and optimization of development well networks. [ABSTRACT FROM AUTHOR]

Fine-grained organic matter (OM) particles are commonly widely dispersed in shale deposits. However, carrying out investigations of pores hosted by OM particles and the nature of grain interactions in OM particles and associated detrital grains using optical microscopy is difficult at best. Scanning electron microscopy (SEM) is much better suited for characterizing the microstructure of dispersed OM particles and has found wide application in the study of unconventional oil and gas systems. Scanning electron microscopy was used to define the types of OM contained in marine shale deposits of the Wufeng and Longmaxi Formations spanning the Ordovician–Silurian transition in South China. Of particular interest was the development of OM-hosted pores and the identification of the factors that controlled their formation. The dominant OM type contained in the studied deposits is pyrobitumen, with subordinate graptolitic OM and sparse OM of unknown origin. Pyrobitumen is present in four forms, including pore fillings among authigenic quartz grains, within framboidal pyrite, and between authigenic clay grains and massive material. Diagenetic alteration has given rise to OM pores of differing morphology, size, and time of formation. Common small, equisized circular or oval OM pores are most developed and appear to have formed in association with the generation of hydrocarbons. Shale deposits containing abundant pyrobitumen filling interparticle pores among authigenic quartz crystals display robust reservoir and fracturing capacity. A sedimentary environment appears to have been the main factor affecting the type of OM and the nature of its association with detrital and authigenic minerals. Results of this study demonstrate that a sedimentary environment is a primary requisite for the formation of highly prospective/high-yielding hydrocarbon shale reservoir deposits. [ABSTRACT FROM AUTHOR]