Zhihong Zhao

To achieve efficient development of medium-depth and shallow high-rank coalbed methane in the Qinshui Basin of Shanxi Province, the authors focused on the microscopic methane release mechanism. Through scanning electron microscopy, nuclear magnetic resonance, and isothermal adsorption experiments, the pore structure, distribution patterns, and influence of hydration effects in this type of coal were revealed. It was clarified that the ineffective utilization of “bound-state” methane within nanopores is the key factor leading to low productivity and efficiency in coalbed methane development. Further, based on molecular simulations, the competitive adsorption characteristics between water and methane molecules were quantified, indicating that about 78% of the methane in the internal pores of 4 nm coal molecular clusters cannot be desorbed through pressure reduction. Meanwhile, the production enhancement mechanism of hydraulic fracturing on coal seam depressurization, permeability enhancement, reduction in low-speed diffusion distance, and enhancement of high-speed linear flow was clarified. Through large-scale pad water injection and stepwise slow production increase, the coal seam can be fully communicated, the reservoir effectively stimulated, and the adsorbed methane sufficiently released. This paper establishes a “channeled” fracturing concept and its supporting technological system for medium-depth and shallow high-rank coal, which has been successfully applied in field operations. The pilot well group achieved stable daily production exceeding 50,000 cubic meters per day, laying a solid foundation for the continuous and stable production increase in medium-depth and shallow high-rank coalbed methane in the Qinshui Basin.

Permeability of fissured sorbing rocks, such as coal and shale, controls gas transport and is relevant to a variety of scientific problems and industrial processes. Multiple gas transport and rock deformation mechanisms affect permeability evolution, including gas rarefaction effects, gas-sorption-induced anisotropic matrix–fracture interaction, and anisotropic deformation induced by effective stress variation. In this paper, a generic anisotropic permeability model is proposed to address the impacts of the above mechanisms and effects. Specifically, the influence of matrix–fracture interactions on permeability evolution is depicted through the nonuniform matrix swelling caused by the gas diffusion process from fracture walls into the matrix. The following characteristics are also incorporated in this model: (1) anisotropic mechanical and swelling properties, (2) arbitrary box-shaped matrix blocks due to the anisotropic rock structure, (3) adsorbability variation of different matrix blocks because of complex rock compositions, (4) adsorption hysteresis, and (5) dynamic tortuosity. The directional permeability models are derived based on the anisotropic poroelasticity theory and anisotropic swelling equations considering adsorption hysteresis. We use a gas-invaded-volume ratio to describe the nonuniform swelling of matrix blocks. Additionally, swelling of blocks with different adsorption and mechanical properties are characterized by a volume-weighted function. Finally, the anisotropic tortuosity is defined as a power law function of effective porosity. The model is verified against experimental data. Results show that four-stage permeability evolution with time can be observed. Permeability evolution in different directions follows its own ways and depends on anisotropic swelling, mechanical properties, and structures, even when the boundary conditions are identical. Adsorption hysteresis controls the local shrinkage region. Tortuosity variation significantly affects permeability but has the smallest influence on the local swelling region. The existence of multiple matrix types complicates the permeability evolution behavior.

The fracture propagation pattern following hydraulic fracturing in deep coal rock significantly influences the effectiveness of reservoir stimulation. Understanding the characteristics and evolution of hydraulic fractures in deep coal rock under varying injection modes is essential for the efficient development of coalbed methane. To elucidate the fracture evolution patterns in deep coal rock and explore methods for forming fracture networks, large-scale true triaxial hydraulic fracturing physical simulation experiments were conducted. These experiments integrated acoustic emission monitoring with post-fracturing 3D fracture reconstruction technology. Testing was performed on the #8 deep coal seam of the Ordos Basin, utilizing various injection parameters and modes. The findings were corroborated by on-site reservoir reconstruction results in the Ordos deep coal rock area. The results indicate that: (1) the number of fractures and the fracture area ratio in deep coal rock are strongly correlated with the viscosity of the fracturing fluid. Low-viscosity fluids yield the highest fracture count and area ratio, albeit with lower fluid efficiency. As fluid viscosity increases, the fracture count decreases by 91%, the fracture area ratio decreases by 86%, and fracture complexity diminishes. (2) At low viscosities, natural fractures (e.g., cleats and bedding planes) predominantly dictate the direction of hydraulic fractures. With increasing viscosity, the minimum resistance plane, influenced by in-situ stress and rock anisotropy, becomes the primary controlling factor. (3) During variable-rate fracturing processes, a higher injection rate results in increased fracture initiation pressure in rock specimens, reduced fracture initiation time, and heightened intensity of acoustic emission ring-down counts, thereby facilitating the formation of dominant hydraulic fractures. (4) The injection mode of “high viscosity first, low viscosity later” effectively maintains fracture complexity while minimizing fluid loss, enhancing fluid efficiency, and achieving a fluid efficiency 2.06 times that of the low-viscosity-only injection mode. The application of a variable-viscosity injection mode combined with high-rate fracturing technology in the deep coal seams of the Ordos Basin demonstrates significant effectiveness, with post-fracturing daily average production per well reaching 4.4 times that achieved through conventional fracturing techniques.

Poorly producing wells in sandstone gas reservoirs are often refractured to enhance production. Considering the mutual interference of initial/refractured fractures, conductivity dynamic evolution, non-uniform inflow, and variable mass flow in the fracture comprehensively, a semi-analytical reservoir-fracture coupled production model fusing spatial and time separation methods is introduced to model refractured well performance. The proposed model is verified by CMG. The field applications indicate that the refracture job should be carried out when production is lower than the desired value. Restoring the C_f-ini and constructing the C_f-ref can increase productivity, which increases over 8 D•cm. The production growth rate just obtained a slight improvement. The production increased significantly with L_f-ini increasing from 120~270 m and L_f-ref increasing from 100~150 m. Hence, it is essential to extend the L_f-ini under engineering conditions. The k_s/k_m = 10 can obviously increase production, but further enlarging k_s does not contribute to well performance. Conversely, further producing larger b_s is vital to enhancing production. Subsequently, the optimal parameter combinations (d_s > L_f-ini > L_f-ref > C_f-ini > k_s > C_f-ref) for well(X1) are carried out by orthogonal experiments. This work proposes a novel method to simulate refractured vertical well performance in tight gas reservoirs for refracture optimization.

Exploration and development practices have proved that fracturability evaluation is the primary basis for successful fracturing operations. Current studies mainly rely on using traditional physical parameters to evaluate shale fracturability. However, fracture morphology and the extension of natural fractures during fracturing are also crucial for shale fracturability evaluation. In this study, correlations between factors and rock fracture complexity and the degree of natural fracture opening were analysed using 40 sets of related experiments, and a new method is proposed for shale fracturability evaluation that considers Young's modulus, the shear expansion angle, residual strain, the approach angle and the stress variance coefficient. Finally, taking the shale gas field in the Sichuan Basin as an example, a comprehensive evaluation model of shale fracturability was established using the grey correlation method combined with core experimental data. One well was selected in order to compare and analyse the fracturability profile with the stimulated reservoir volume. The results show that peak strain has the most significant influence on shale fracture complexity, followed by the shear expansion angle and Young's modulus. The approach angle and the stress difference coefficient affect the degree of natural fracture opening at the same time. The model is accurate because the fracturability values match the study block's stimulated reservoir volume data. This new method of shale fracturability evaluation provides important technology for predicting the fracturability of shale gas reservoirs and optimizing operation schemes.

Fiber sand control is widely used on site due to its advantages such as easy operation, significant effects, and low cost. However, the mechanism of fiber control proppant flowback is currently unclear, and the main controlling factors affecting the critical flow velocity are not yet clear. There is a lack of relevant theoretical support to optimize the design of fiber sand control. This article uses composite material theory to analogically calculate the tensile strength of fiber-reinforced sand and friction reinforcement theory to analogically calculate the shear strength of fiber-reinforced sand. The relationship between fiber strength force and tensile strength and shear strength is proposed, combined with the different stress conditions of proppant particles before and after fracture closure, and a fiber-controlled proppant flowback strength model is established based on the force arm balance. The critical velocity of proppant was calculated and compared through the stability experiment of fiber-reinforced proppant filling layer, and the accuracy of the model was verified and the influencing factors were analyzed. The results show that the influence of tensile strength and shear strength on fiber strength at the early stage of fracture closure is 0.2 and 0.8, respectively, and that after fracture closure is 0.1 and 0.9, respectively. The critical velocity calculated by the model is basically consistent with the experimental results. The critical velocity is most affected by the particle size and closure pressure of proppant, followed by the amount of fiber, and the influence of fiber length and diameter is relatively small.

Water imbibition is a key factor affecting the flowback regime of shale gas wells after volume fracturing. In this study, a set of experimental apparatus and corresponding test and evaluation methods were developed to analyze the laws of forcible imbibition of water in a shale reservoir, characterize the initiation time of microfractures induced by shale hydration quantitatively, and optimize the shut-in time of shale gas wells; the imbibition depths of different pore types are quantitatively calculated based on the multiple pore imbibition analytical model. The experimental results show that: according to imbibition saturation growth rate, the shale forcible imbibition can be divided into three periods, imbibition diffusion, imbibition transition, and imbibition balance. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The reason for this phenomenon is that due to the fluid pressure difference effect, the shale fills its large pores and microfractures rapidly in the early stage, and in the percolation transition period, the percolation rate decreases continuously due to the gradual increase of fluid saturation. Due to the Jamin effect, it is difficult for the fluid to enter the small pores and the fluid fills the pore roar channel, the seepage saturation tends to stabilize, and the seepage equilibrium period appears. In the early period of shut-in, the imbibition capacity of shale increases significantly under the action of fluid pressure, providing a large amount of imbibition fluid for the spontaneous imbibition later. The imbibition depth of a clay pore was much greater than that of a brittle mineral pore and an organic pore. The reservoir confining pressure has prohibition on shale imbibition, but even under reservoir confining pressure, imbibition can still improve the fracturing effect of the reservoir, resulting in an increase in porosity of 0.42–1.63 times and an increase in permeability of 17.6–67.3 times. Under the experimental conditions, the initiation time of induced microfractures is 98.5 h on average and is in negative correlation with imbibition capacity. On this basis, the optimized shortest shut-in time of a shale gas well is 5 days. The study results can provide a scientific basis for the optimization of the flowback regime of shale gas reservoirs.