Research on the physicochemical reactions between supercritical carbon dioxide (Sc-CO₂) and shale at different temperature is essential for geological CO₂ sequestration. In this paper, shale from the Longmaxi formation in Sichuan basin of China was collected to study the changes in mineral composition, pore structure, and organic functional groups treated with Sc-CO₂ at fixed pressure 8 MPa and temperatures 40 °C to 80 °C. Samples were analyzed with x-ray diffraction, CO₂/N₂ gas adsorption, and Fourier transform infrared spectroscopy. The results show that the dissolution of clay minerals by Sc-CO₂ first declined, but then increased when the temperature increased; dissolution reached a minimum at 60 °C. The specific surface area, total pore volume, predominant pore type (mesopores), and fractal dimension of the shale pore structure first increases and then decreases with increasing temperature. The destruction of hydroxyl structures by Sc-CO₂ is related to the destruction of OH–N and ring hydroxyls. As the temperature increases, the hydroxyl destruction first increases and then decreases. The aromatic hydrocarbons are mainly dominated by 3H and 2H, and their abundances increase significantly as temperature increases, whereas the 4H shows a decreasing trend; the 1H abundance does not change appreciably. The relative abundances of aromatic and aliphatic hydrocarbons decrease linearly as the temperature increases. These research results provide theoretical support for the geological storage of Sc-CO₂ in shale at different temperatures.

Coalbed methane (gas) is a high quality and clean resource, but it also causes disasters in coal mines in China. The low permeability of coal seams is the main reason that developing coalbed methane (CBM) as an energy resource is difficult, so increasing coal seam permeability is the key to CBM development in China. In this paper, the principal techniques for seam permeability enhancement are presented. The paper focuses on hydraulic technology for seam permeability enhancement (HTSPE), which is considered an economic and highly efficient technology for seam permeability enhancement. The process of HTSPE development is reviewed and the current status of the theories behind HTSPE and the technology and equipment for its use are summarized. The goal is to identify the gaps in HTSPE research and the problems in its implementation. In the future, integration and diversification of the technologies along with on-board intelligence and miniaturization may be the trends for the equipment. Finally, it is shown that tree-shaped borehole fracturing can be used to develop CBM in underground coal mines. This study could be used as a valuable example for other coal deposits being mined under similar geological conditions.

The buried depth of a coal seam determines the temperature at which CO₂ and coal interact. To better understand CO₂ sequestration, the pore structure and organic functional groups of coal treated with different ScCO₂ temperatures were studied. In this study, three different rank coals were treated with ScCO₂ at different temperatures under 8 MPa for 96 h in a geochemical reactor. The changes in pore structure and chemical structure of coal after ScCO₂ treatment were analyzed using mercury intrusion porosimetry, attenuated total reflection Fourier transform infra-red spectroscopy, fractal theory, and curve fitting. The results show that the enhancement effect of ScCO₂ on pore structure of coal becomes less significant as the increase of buried depth. In most of the treated coal samples, the variation proportion of mesopores decreased and the variation proportion of macropores increased. In the relatively higher rank coals, the degree of condensation (DOC) of aromatic rings decreased after treatment with ScCO₂. The DOC values showed a U-shape relationship with temperature, and the aromaticity showed a downward trend with increasing temperature. The chemical structural changes in the relatively lower rank coal sample were complex. These findings will provide an understanding of mechanisms relevant to CO₂ sequestration with enhanced coalbed methane recovery under different geothermal gradients and for different ranks of coal.

High-pressure hydraulic fracturing technology in coal and coal bed methane mines can lead to roof and floor damage, and fracture initiation disorder that leads to a “blank area”, and other issues. A new method of hydraulic fracturing is proposed to increase the homogeneous permeability of coal in underground coalmines. Numerical and other simulation tests for different forms of a tree-type, branched borehole model are presented. The results show that the branched array causes cracks to initiate from the bottom of the array, and these extend along the direction of the adjacent boreholes. Generally, as the number of branched boreholes increases, the coal seam fracture network also increase, improving the distribution of the fracture network, making the fracturing effect better. The branched boreholes appear to reduce initiation pressure and, with increasing branches, the initiation pressure decreases. A model with four tree-type, branched boreholes leads to a reduction in initiation pressure of 69%. In terms of permeability improvement technology in underground coalmines, a branched hydraulic fracturing borehole array has the advantages of reducing initiation pressure, controlling crack initiation and extension, enhancing the fracturing effect and reducing the destruction of the roof and floor.

When drilling coal-bearing sequences to enhance coal seam permeability by hydraulic fracturing (HF), the location where fractures are initiated is important. To date, most research on fracture initiation has studied the problem in two dimensions. In this study, a three-dimensional model to assess initiation location is developed. The model analyzes the stress state of both the borehole wall and the coal-rock interface and the model shows that the fracture initiation location is affected by in situ stress, the dip of the coal seam, and the angle between the borehole and the coal seam. How the initiation location changes near different types of geological faults is calculated by assuming typical in situ stresses for the faults. Following these calculations, physical experiments were carried out to emulate cross-measure hydraulic fracturing under stress conditions equivalent to those in the Chongqing Tonghua coal mine, China. Fracture initiation during the experiments was monitored by an acoustic emission system. The experimental results were consistent with the theoretical calculations. This implies that the three-dimensional model for assessing the locations of fracture initiation can be applied to forecast the initiation location of fractures generated by cross-measure drilling. The assessment model provides reference values for this type of drilling in underground mines.

Non-aqueous or gaseous stimulants are alternative working fluids to water for hydraulic fracturing in shale reservoirs, which offer advantages including conserving water, avoiding clay swelling and decreasing formation damage. Hence, it is crucial to understand fluid-driven fracture propagation and morphology in shale formations. In this research, we conduct fracturing experiments on shale samples with water, liquid carbon dioxide, and supercritical carbon dioxide to explore the effect of fluid characteristics and in situ stress on fracture propagation and morphology. Moreover, a numerical model that couples rock property heterogeneity, micro-scale damage and fluid flow was built to compare with experimental observations. Our results indicate that the competing roles between fluid viscosity and in situ stress determine fluid-driven fracture propagation and morphology during the fracturing process. From the macroscopic aspect, fluid-driven fractures propagate to the direction of maximum horizontal stress direction. From the microscopic aspect, low viscosity fluid easily penetrates into pore throats and creates branches and secondary fractures, which may deflect the main fracture and eventually form the fracture networks. Our results provide a new understanding of fluid-driven fracture propagation, which is beneficial to fracturing fluid selection and fracturing strategy optimization for shale gas hydraulic fracturing operations.