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The extension, penetration and expansion of coal and rock fracture structure caused by deep mining are the key factors that cause coal and rock damage.Therefore, the accurate characterization of the fracture structure is one of the core elements for understanding the coal and rock failure mechanism and developing coal and gas green co-mining.In this study, the Waifu2x convolutional neural network model was used to process the fractured coal and rock CT images to obtain CT images with higher resolution.And put forward the "seven-step processing method of fissure coal and rock labeling", which improves the efficiency of labeling, and uses image enhancement technology to expand the training set, which meets the model's requirements for the quantity and quality of the training set.The trained U-Net convolutional neural network is used for image segmentation to extract the fracture information in the coal and rock.Through comparison, it is found that the fracture connectivity, opening and distribution obtained by this method are closer to the real CT images, and the four quantitative indicators of the extracted fractures are better than other extraction methods.This study can provide a research foundation for the physical and mechanical behavior and mechanism analysis of fractured coal.

Understanding preferential flow in porous media holds substantial theoretical significance on the design and optimization of hydrocarbon exploitation in shale reservoir. Previous researches discussed the competition of imbibition front in layered porous media while the underlining mechanism for interfacial dynamics and induced displacement efficiency of multiphase flow remains ambiguous. In this paper, we investigate the spontaneous imbibition in dual permeable media and analyze the flux exchange between the neighboring porous zones with permeability contrast using dynamic pore network model. The impact of fluid viscosity ratio and permeability contrast on the spontaneous imbibition preference have been addressed, and finally a phase diagram for displacement efficiency has been obtained. The results reveal that the dual permeable structure enhances the invasion rate of wetting fluid in the low‐permeable zone and induces unstable displacement patterns, leading to reduction of the long‐term displacement efficiency. The interfacial pattern transition from stable displacement to unstable pattern in dual permeable media could be ascribed into the flux exchange between dual permeable zones, which shows a contrary impact on the fluid flow within the low‐permeable zone under favorable and unfavorable viscosity ratios. The permeability contrast in dual permeable media intensifies this impact during spontaneous imbibition. These results help us to understand the occurrence and mutual interaction of multiphase flow in layered porous media, and provide a theoretical guidance for the hydrocarbon exploitation in shale reservoir. Plain Language Summary: The shale oil reservoir has emerged as a crucial contributor to the global energy supply, primarily attributed to stimulation techniques such as hydraulic fracturing. The geological composition of shale rock encompasses stratified layers characterized by varying permeability, leading to diverse multiphase flow patterns at the pore scale during the shut‐in period. These intricate flow patterns significantly impact shale oil recovery during subsequent exploitations. However, a gap exists in comprehending the optimal design of injection conditions by controlling the multiphase flow pattern for a high‐efficiency exploitation strategy. The elucidation of multiphase displacement mechanisms within the complex porous structure featuring staggered layers are imperative. To address this gap, pore‐scale modeling and analysis were conducted to visualize spontaneous imbibition behaviors across varying fluid viscosity ratios and permeability contrasts. The findings indicate that the imbibition flux in low‐permeable zone is augmented by fluid flow in high‐permeable zone. Furthermore, an escalating permeability contrast intensifies the flux enhancement and reduce the displacement efficiency in dual permeable media by changing the displacement pattern from stable to unstable distribution. These outcomes serve as a theoretical foundation, providing insights for the selection and optimization of an effective exploitation strategy to enhance shale oil recovery under complex engineering conditions. Key Points: A dynamic pore network model for studying spontaneous imbibition in dual permeable media is presentedThe contrary effect of flux exchange on spontaneous imbibition within low‐permeable zone under various viscosity ratios is observedTransition of interface dynamics from stable to unstable pattern is induced by unfavorable viscosity ratio and large permeability contrast [ABSTRACT FROM AUTHOR]

The irregular morphology of single rock fracture significantly influences subsurface fluid flow and gives rise to a complex and unsteady flow state that typically cannot be appropriately described using simple laws. Yet the fluid flow in rough fractures of underground rock is poorly understood. Here we present a numerical method and experimental measurements to probe the effect of fracture roughness on the properties of fluid flow in fractured rock. We develop a series of fracture models with various degrees of roughness characterized by fractal dimensions that are based on the Weierstrass-Mandelbrot fractal function. The Lattice Boltzmann Method (LBM), a discrete numerical algorithm, is employed for characterizing the complex unsteady non-Darcy flow through the single rough fractures and validated by experimental observations under the same conditions. Comparison indicates that the LBM effectively characterizes the unsteady non-Darcy flow in single rough fractures. Our LBM model predicts experimental measurements of unsteady fluid flow through single rough fractures with great satisfactory, but significant deviation is obtained from the conventional cubic law, showing the superiority of LBM models of single rough fractures.

The production rate of a typical shale gas well generally has steep decline trend at the initial stage but small declines at later times. Some empirical relationships have been proposed to describe the declining production rates and thus forecast the final cumulative production of a shale gas well. However, these empirical relationships can hardly elucidate the mechanisms that cause the special shale gas production trend. In this study, a novel two-part Hooke's model (TPHM) for the permeability and effective stress relationship is developed and incorporated into the hydro-mechanical COMSOL solver to determine the production rate of shale gas wells against time. The TPHM conceptualizes shale rock into soft part and hard part, which comply with the natural-strain-based and engineering-strain-based Hooke's laws, respectively, and contribute differently to the decreasing permeability with increasing effective stresses. The simulation results are analyzed and compared with those for which the permeability change effect is not considered. The analysis indicates that the decrease in stress-induced permeability plays a non-negligible part in the decline of the production rate.

As a critical technological approach, multistage fracturing is frequently used to boost gas recovery in compact hydrocarbon reservoirs. Determining an ideal cluster distance that effectively integrates pre-existing natural fractures in the deposit creates a fracture network conducive to gas movement. Fracturing fluid leak-off also impacts water resources. In our study, we use a versatile finite element–discrete element method that improves the auto-refinement of the grid and the detection of multiple fracture movements to model staged fracturing in naturally fractured reservoirs. This computational model illustrates the interaction between hydraulic fractures and pre-existing fractures and employs the nonlinear Carter leak-off criterion to portray fluid leakage and the impacts of hydromechanical coupling during multistage fracturing. Numerical results show that sequential fracturing exhibits the maximum length in unfractured and naturally fractured models, and the leak-off volume of parallel fracturing is the smallest. Our study proposes an innovative technique for identifying and optimizing the spacing of fracturing clusters in unconventional reservoirs. [ABSTRACT FROM AUTHOR]