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Limited-entry fracturing (LEF) technology is a widely used method to realize the simultaneous propagation of multiple fractures in horizontal wells. The key of this technology is to create high perforation friction to maintain the high treatment pressure in the wellbore and realize the uniform fluid entry of multi-fractures; however, high perforation friction cannot be effectively maintained due to the serious perforation erosion effect. Considering that the current laboratory studies mostly used small fluid injection flowrate, low injection pressure, and small proppant dosage, this study has developed a field-scale flow system to investigate the effect of various factors on perforation erosion under real field conditions. The filed-scale flow system uses the real fracturing trucks, proppant, and perforated wellbore, the fluid flow rate through perforation could reach 200 m/s and the injection pressure could reach 105 MPa. The effects of different parameters, such as injection flow rates, proppant concentration, proppant type, proppant size, and carrying fluid viscosity, on the perforation erosion were investigated. The experimental results show that: (1) The perforation friction during erosion goes through two stages, i.e., the roundness erosion stage and the diameter erosion stage. The reduction of perforating friction mainly occurred in the first stage, which was completed after injecting 1 m3 proppant. (2) After erosion, the perforation changes from the original circular shape to a trumpet shape, the inner diameter is much larger than the outer diameter. (3) The more serious perforation erosion is caused by the conditions of high injection flow rate, large proppant size, using ceramic proppant, and low viscosity fluid. The findings of this study can help for a better understanding of perforation erosion during the limited-entry fracturing in the horizontal wells, and also could promote the establishment of a theoretical model of perforation erosion under the field-scale conditions. [ABSTRACT FROM AUTHOR]

The permeability anisotropy of shales can be attributed largely to bedding planes. It is critical to study the bedding effect on permeability evolution for shales. We conducted an experiment on shale permeability anisotropy under true triaxial stress conditions. Even though the mean stress of shales was different, the permeability still exhibits obvious bedding dependent. In this study, we present a new permeability model considering bedding planes. The introduction of characteristic functions and parameters characterizes the transformation process from bedding to non-bedding during compression. Compared with the experimental data, we obtained a good fitting result. Owing to the increase in the resistance of the pressurized gas into the fracture system, Biot's coefficient α decreases with increasing mean stress. The porosity sensitivity exponent s parallel to the bedding planes are larger than those perpendicular to the bedding planes. In our opinion, owing to the smaller stiffness of the bedding plane, the relatively large amount of pore deformation is caused by the loading on the vertical bedding planes. Furthermore, we introduce η to characterize the effect of non-bedding and bedding on permeability. The permeability of shale or bedding is more sensitive at lower stress than at higher stress and the fluid flow through the non-bedding in shales cannot be ignored. • Characteristic functions and parameters show the deformation evolution of bedding. • We established the stress-dependent permeability model considering bedding effect. • Biot's coefficient α decreases with increasing mean stress. • The porosity sensitivity exponent s exhibits anisotropy. [ABSTRACT FROM AUTHOR]

Permeability is a crucial parameter for characterizing gas transport and exchange in coal seams and is fundamental for designing and optimizing gas extraction and control methods. However, the permeability of coal seams is mainly determined through laboratory tests, with few studies using in-situ tests. To address the limitations of laboratory tests, such as their small scale and poor ability to provide engineering guidance, this study proposes a novel in-situ permeability test (IPT) system to investigate the fluid-flow aspects of geological formations. The system comprises the water-injection sealing and gas-injection testing subsystems. By considering the coal seam surrounding a gas injection borehole interval as a filter, the equation for calculating the in-situ coal seam permeability was derived based on steady-state gas-seepage theory. The IPT system was then assembled and used to test the in-situ permeability of the JI 15 coal seam at the Pingdingshan XII coal mine. The study estimated the representative elementary volume (REV) of the tested coal seam permeability, analyzed the applicability of Darcy's law during the tests, and obtained the anisotropic permeability of the coal seam by drilling test boreholes in different directions within the coal seam. Finally, the reliability of the new test method was verified by comparing its results with laboratory and well test data. The results demonstrated the effectiveness and reliability of the novel IPT system and encouraged further investigations into efficient gas extraction and control in deep coal seams. • A novel in-situ permeability test system based on steady-state flow theory is proposed. • The anisotropic permeability of in-situ coal seams is tested at engineering scale. • Τhe tested in-situ permeability are compared with the laboratory and well test results. [ABSTRACT FROM AUTHOR]

The greenhouse effect has attracted increasing attention globally. The geologic sequestration of CO 2 is considered as an effective method for reducing the amount of CO 2 in the atmosphere. Carbon-dioxide enhanced coalbed methane (CO 2 -ECBM) recovery is extremely attractive owing to its ability to store CO 2 in coal seams while simultaneously enhancing the production of methane. However, the injection of CO 2 can induce a deformation of the coal matrix, which has a significant effect on the fluid flow and stability of the coal seams. In this study, the sorption kinetics experiments indicated the high anisotropy and heterogeneity of local sorption deformation in coal samples and a unique kinetic behavior of sorption deformation which was rarely reported and analyzed in detail in previous studies. This kinetic behavior demonstrated a rapid increase of sorption strain followed by a slight or significant falloff until the equilibrium state reached. The characteristics of component distribution in coal samples were investigated using CT scanning and micro-lithotype and EDS analysis. An extensive analysis of the experiment results indicated the following: 1) Carbon dioxide dissolved during the first sorption process induced a rearrangement of the coal structure, leading to a drastic variation of deformation behavior between the first and subsequent sorption process. 2) The unique kinetic behavior of sorption deformation could be induced by either the loss of moisture in coal or the interaction of different coal components. The mechanism of these two factors induced coal shrinkage was different and had a distinct effect on the global behavior of sorption deformation. 3) The quantitative relationship between compressional and dilative components directly verified the significant compression of inertinite-rich regions by the slow swelling of vitrinite-rich regions. 4) The kinetic behavior of sorption deformation was affected by the combination of the macroscopic bedding structure and the heterogeneous component distribution in coal. • CO 2 dissolved during the first sorption process induces a rearrangement of the coal structure. • Kinetic behavior of local sorption deformation strongly depends on coal heterogeneity. • The slow swelling of vitrinite compressed inertinite in coal during sorption process. • A quantitative relationship between vitrinite and inertinite sorption strain was investigated. [ABSTRACT FROM AUTHOR]