Search Results (274)

The topological structure of fracture networks fundamentally controls the mechanical behavior and fluid-driven failure of brittle materials. However, a systematic understanding of how topology dictates hydraulic fracture propagation remains limited. This study conducted experimental investigations on granite specimens containing 10 different topological fracture structures using a self-developed visual hydraulic fracturing test system and an improved Digital Image Correlation (DIC) method. It systematically revealed the macroscopic control laws of topological nodes on crack initiation, propagation path, and peak pressure. The experimental results indicate that hydraulic crack initiation follows the “proximal-to-loading-end priority” rule. Macroscopically, the breakdown pressure shows a significant negative correlation with topological parameters (number of nodes, number of branches, normalized total fracture length). However, specific configurations (e.g., X-shaped nodes) can exhibit a configuration-strengthening effect due to dispersed stress concentration, leading to a higher breakdown pressure than simpler topological configurations. Discrete Element Method (DEM) simulations revealed the underlying mechanical essence at the meso-scale: the topological structure governs crack initiation behavior and initiation pressure by regulating the distribution of force chains and the mode of stress concentration within the rock mass. These findings advance the fundamental understanding of fracture–topology–property relationships in rock masses and provide insights for optimizing fluid-driven fracturing processes in engineered materials and reservoirs. Full article

Studying the propagation behavior of hydraulic fracturing fractures is of great significance for understanding the mechanism of fracture propagation in deep unconventional reservoirs. The goal of unconventional oil and gas reservoir fracturing transformation is to form a complex fracture network system and increase the effective transformation volume of the reservoir. This article conducts physical model experiments on fracturing under different reservoir stress conditions to determine whether complex pressure fractures can be formed. The main controlling factors for the formation of complex pressure fractures are analyzed, and the influence of each factor is quantitatively studied through numerical simulation. The results indicate that the difference in geostress has a significant impact on the formation of pressure cracks. As the difference in geostress increases, the lateral extension range of pressure cracks significantly decreases, resulting in a phenomenon parallel to the direction of maximum horizontal geostress. As the injection volume decreases, the phenomenon of early fracturing bifurcation propagation gradually decreases, with a small number of bifurcations appearing. In the subsequent fracturing process, the main trend of fracture extension is more pronounced in reservoirs with lower fluid injection rates. In addition, low-viscosity fracturing fluids seem to be more prone to forming fracture zones with more developed branching fractures. This study can provide technical support and reference for fracturing construction in deep tight oil reservoirs. Full article

Deep coal mining encounters substantial challenges associated with diminished permeability and elevated gas pressure under multi-physics coupling conditions. This paper introduces an innovative methodology that integrates the staged high-pressure hydraulic fracturing of roof key strata with the static expansion fracturing of coal seams using solid expansive materials. The proposed technique facilitates the coordinated regulation of the stress and fracture fields, enabling efficient stress relief, long-term anti-reflection performance, and low-damage seam modification. By employing theoretical modeling based on Hamilton’s canonical equations, conducting experimental impact tests, and performing field validation, this research demonstrates that the synergistic strategy markedly alleviates stress concentration by more than 25%, increases permeability by a factor of 3.7, and enhances gas extraction efficiency while preserving fracture network stability. The results indicate sustainable gas drainage characterized by reduced decay coefficients, offering a reliable and efficient approach for strata pressure management and gas disaster mitigation in deep mining operations. This integrated solution contributes to both safety enhancement and resource recovery optimization under complex geo-mechanical conditions. Full article

The development of deep coalbed methane is hindered by the strong heterogeneity of coal mechanical properties and complex hydraulic fracturing behavior. To identify the key factors controlling fracture geometry and permeability enhancement, this study developed a thermo-hydro-mechanical-damage coupled model within a COMSOL Multiphysics 6.3-MATLAB R2022b co-simulation framework, incorporating a Weibull random field to characterize mechanical heterogeneity. Sensitivity analysis demonstrates that tensile strength is the predominant factor governing both the fracturing damage zone and permeability-enhanced area, with its damage area extreme difference (10.094) and coefficient of variation (0.85) significantly surpassing those of other parameters. Poisson’s ratio and elastic modulus emerge as key secondary parameters, while compressive strength shows the lowest sensitivity. The parametric influences exhibit distinct patterns: tensile strength shows a strong negative correlation with damage and permeability-enhanced areas (up to 85% reduction), whereas the maximum permeability enhancement rate follows a non-monotonic trend, peaking at 215 when tensile strength reaches 3.33 MPa. Compressive strength minimally affects the damage area (~15%) but steadily improves the maximum permeability enhancement rate (7.5% increase). Elastic modulus exhibits an optimal value (8.93 GPa) for maximizing damage area, while negatively correlating with maximum permeability enhancement rate (9.1% decrease). Fracture morphology is differentially controlled by multiple parameters: low compressive strength promotes fracture deflection and branching, elastic modulus regulates fracture network complexity, and low Poisson’s ratio enhances coal brittleness to effectively activate natural fractures, thereby facilitating complex fracture network formation. Full article

The increasing burial depth of deep shale formations in the southern Sichuan leads to more complex in situ stresses and geological structures, which in turn raises the challenges of hydraulic fracturing. Although enlarging the treatment scale and injection rate can enhance reservoir stimulation, the intensive development of faults and fractures in deep shale formations aggravates stress instability, inducing casing deformation, fracture communication, and other engineering risks that constrain efficient shale gas production. In this study, a cross-scale geomechanical model linking the regional to near-wellbore domains was constructed. A dynamic evolution equation was established based on flow–stress coupling, and a numerical conversion from the geological model to the finite element model was implemented through self-programming, thereby developing a simulation method for dynamic geomechanical evolution during hydraulic fracturing. Results indicate that dynamic variations in pore pressure dominate stress redistribution, while near-wellbore heterogeneity and mechanical property distribution significantly affect prediction accuracy. The injection of fracturing fluid generates a high-pressure gradient that drives pore pressure diffusion along fracture networks and faults, exhibiting a strong near-wellbore but weak far-field non-steady spatial attenuation. As the pore pressure increases, the peak value reaches 1.4 times the original pressure. The triaxial stress shows a negative correlation and decreases. The horizontal minimum principal stress shows the most significant drop, with a reduction of 15.79% to 20.68%, while the vertical stress changes the least, with a reduction of 5.7% to 7.14%. Compared with the initial stress state, the horizontal stress difference increases during fracturing. Rapid pore-pressure surges and fault distributions further trigger stress reorientation, with the magnitude of rotation positively correlated with the intensity of pore-pressure variation. The high porosity and permeability characteristics of the initial fracture network lead to a rapid attenuation of the stress around the wellbore. In the middle and later stages, as the pressure balance is achieved through fracture filling, the pore pressure rises and the stress decline tends to stabilize. The findings provide significant insights into the dynamic stress evolution of deep shale reservoirs during fracturing and offer theoretical support for optimizing fracturing design and mitigating engineering risks. Full article

Hot dry rock (HDR) is a promising renewable energy resource whose vast reserves and wide distribution have attracted extensive attention in recent years. However, exploiting HDR resources requires hydraulic stimulation, which is typically accompanied by substantial microseismic activity, posing significant risks to project safety and public acceptance. Current understanding of microseismic mechanisms, particularly the role of fracture geometry under varying injection schemes, remains inadequate. This study employs a three-dimensional block-based discrete element method to construct a fluid–mechanics coupled model founded on a discrete fracture network, aimed at investigating the mechanical behavior of fractures and the spatial distribution of microseismicity during hydraulic stimulation. Our results quantitatively demonstrate that fractures oriented at 45° to the maximum principal stress are most susceptible to shear reactivation and microseismic clustering, with event magnitudes strongly correlated to both fracture orientation and intra-fracture fluid pressure. Consequently, preventing critically high fluid pressures in natural fractures near the injection well, particularly those at approximately 45° to the maximum principal stress direction, is essential for risk mitigation. Cyclic injection can shear more fractures and slightly reduce magnitudes via staged pressure relaxation, but its effectiveness in controlling microseismic magnitude is limited. Therefore, it is recommended to implement measures to control the entry of fracturing fluid into these high-risk fissures, such as segmented fracturing or temporary plugging techniques. This strategy is expected to enhance seismic risk mitigation, thereby contributing to the safe and efficient exploitation of deep geothermal resources. Full article

Accurate differentiation between microseismic signals induced by hydraulic fracturing and those from roof fracturing is vital for optimizing fracturing efficiency, assessing roof stability, and mitigating mining-induced hazards in coal mining operations. We propose an automatic identification method for microseismic signals generated by hydraulic fracturing in coal seam roofs. This method first transforms the microseismic signals induced by hydraulic fracturing and roof fracturing into time-frequency feature images using the Frequency Slice Wavelet Transform (FSWT) technique, and then employs a sliding window (Swin) Transformer network to automatically identify and classify these two types of time-frequency feature maps. A comparative analysis is conducted on the performance of three methods—including the signal energy distribution method, Residual Network (ResNet) model, and VGG Network (VGGNet) model—in identifying microseismic signals from hydraulic fracturing in coal seam roofs. The results demonstrate that the Swin Transformer recognition model combined with FSWT achieves an accuracy of 92.49% and an F1-score of 92.96% on the test set of field-acquired microseismic signals from hydraulic fracturing and roof fracturing. These performance metrics are significantly superior to those of the signal energy distribution method (accuracy: 64.70%, F1-score: 64.70%), ResNet model (accuracy: 88.04%, F1-score: 89.24%), and VGGNet model (accuracy: 88.47%, F1-score: 89.52%). This advancement provides a reliable technical approach for monitoring hydraulic fracturing effects and ensuring roof safety in coal mines. Full article

The evaluation of the fracturing effect of coalbed methane (CBM) wells is crucial for the efficient development of CBM reservoirs. Currently, studies focusing on the evaluation of the hydraulic fracture stimulation effect of coal seams and the integrated analysis of “drilling-fracturing-monitoring” are relatively insufficient. Therefore, this paper takes three drainage and production wells in the coalbed methane block on the northwest wing of the Xiangxia anticline in the Bijie Experimental Zone of Guizhou Province as the research objects. In view of the complex geological characteristics of this area, such as multiple and thin coal seams, high gas content, and high stress and low permeability, the paper systematically summarizes the results of drilling and fracturing engineering practices of the three drainage and production wells in the area, including the application of key technologies such as a two-stage wellbore structure and the “bentonite slurry + low-solid-phase polymer drilling fluid” system to ensure wellbore stability, low-solid-phase polymer drilling fluid for wellbore protection, and staged temporary plugging fracturing. On this basis, a study on microseismic signal acquisition and tomographic energy inversion based on a ground dense array was carried out, achieving four-dimensional dynamic imaging and quantitative interpretation of the fracturing fractures. The results show that the fracturing fractures of the three drainage and production wells all extend along the direction of the maximum horizontal principal stress, with azimuths concentrated between 88° and 91°, which is highly consistent with the results of the in situ stress calculation from the previous drilling engineering. The overall heterogeneity of the reservoir leads to the asymmetric distribution of fractures, with the transformation intensity on the east side generally higher than that on the west side, and the maximum stress deformation influence radius reaching 150 m. The overall transformation effect of each well is good, with the effective transformation volume ratio of fracturing all exceeding 75%, and most of the target coal seams are covered by the fracture network, significantly improving the fracture connectivity. From the perspective of the transformed planar area per unit fluid volume, although there are numerical differences among the three wells, they are all within the effective transformation range. This study shows that microseismic fracture monitoring technology can provide a key basis for the optimization of fracturing technology and the evaluation of the production increase effect, and offers a solution to the problem of evaluating the hydraulic fracture stimulation effect of coal seams. Full article

Hydraulic fracturing is a key technique for creating complex fractures in unconventional reservoirs to enhance energy recovery. Asymmetric branched fractures, as fundamental units, are widely observed in complex fracture networks. Effective proppant distribution within such structures is critical but remains poorly understood. To investigate this, a rough-walled slot with two branches was developed, where asymmetry was introduced by inserting plates with different geometries on one side. The results show that the structural asymmetry between the left and right branches can significantly induce non-uniform transport and irregular sand bed morphology. Reducing the height and width of branch fractures increases fluid velocity, limiting proppant settling within the branch. As the flow area decreases, the fluid velocity increases, driving more proppant through the branch toward the distal fracture region. Injection pressure increases as the flow area of the branch fracture decreases. At a height ratio of 0.25, sand plugging and ineffective proppant placement probably occur within the natural fracture. When the branch is located at the upper section, proppants hardly settle to form a bed, leading to closure of the fracture. The study provides new insights into optimizing proppant placement in complex fractures. Full article

The lithological composition of deep coal rock reservoirs in the Ordos Block is complex. The characteristics of hydraulic fracture propagation directly impact reservoir stimulation effectiveness. Therefore, efficient development requires an in-depth understanding of the cross-layer propagation mechanisms of fractures in deep coal rock. To clarify the cross-layer patterns and explore the controlling factors in deep coal rock, large-scale laboratory true triaxial hydraulic fracturing physical simulation experiments were conducted. These experiments, combined with CT scanning and post-fracture 3D reconstruction technology, investigated Ordos Block deep coal rock under different perforation locations, and the complexity of fractures was quantitatively characterized. Due to the well-developed weak planes such as natural fractures in coal rock, perforations in coal rock significantly reduce the breakdown pressure compared to perforations in sandstone. The complexity of perforation fractures in coal rock is far greater than in sandstone. Quantitative characterization of fracture complexity shows that the number of perforation fractures in coal rock fracturing reached 450% of that in sandstone, and the fracture area ratio reached 131.7%. Under high-rate and high-viscosity fracturing conditions, dominant hydraulic fractures tend to form, while the well-developed natural fractures in the coal rock interact with each other, resulting in a complex fracture network. Perforations in coal rock can effectively connect adjacent sandstone layers through cross-layer propagation, whereas perforations in sandstone form dominant hydraulic fractures without connecting the adjacent coal rock layers. The findings can provide operational guidance for optimizing field fracturing operations. Full article

The shale oil reservoir in Block Y of the Ordos Basin exhibits low porosity and low permeability, yet it features distinct stratification and developed micro-fractures. During the development process using “horizontal wells + volume fracturing”, the differential in geostress exerts a certain influence on the initiation and propagation of fractures. This paper employs the Cohesive element simulation method to investigate the formation patterns of fracture networks in fractured formations. By prefabricating natural fractures, the study explores the impact of natural fractures on the direction of hydraulic fractures during the hydraulic fracturing process. The study considers the fracture initiation and propagation patterns as well as the interaction between hydraulic fractures and natural fractures under differential geostress conditions of 0 MPa, 1 MPa, and 5 MPa. The numerical simulation results reveal that the presence of natural fractures significantly affects the direction of hydraulic fractures, with the tip of the hydraulic fracture deflecting towards the natural fracture. The smaller the geostress difference, the more complex the fractures become with more branching fractures. Conversely, a larger geostress difference leads to the formation of a single double-wing fracture perpendicular to the minimum principal stress, resulting in a simpler fracture morphology. The pore pressure variation at the injection point generally experiences a rapid increase followed by a slight decrease, subsequently undergoing wavy changes. The occurrence of wavy pressure variations indicates the continuous generation of micro-fractures. The fracture width at the injection point generally exhibits an increasing trend followed by a decreasing trend. When the stress difference is 0 MPa, 1 MPa, and 5 MPa, the peak rupture pressures are 12.63 MPa, 13.42 MPa, and 18.33 MPa, respectively; the maximum crack openings are 0.797 cm, 0.779 cm, and 0.771 cm, respectively. The study on fracture initiation and propagation in shale reservoirs provides guidance for the field application of multi-cluster fracturing in horizontal well sections. Full article

In response to the problems encountered during the pressure-driven oil recovery process in low-permeability oil reservoirs, such as slow pressure transmission, poor liquid supply, vulnerability of the reservoir to damage, and difficulties in injection and production, in order to achieve the goal of high-quality water injection development, based on the theories of rock mechanics and seepage mechanics, combined with large-scale physical model experiments, acoustic emission crack monitoring, and microscopic scanning technology, an oil reservoir and fracture model was established to conduct a feasibility analysis of pressure-driven assisted pressure reduction and enhanced injection, and it was successfully applied in the exploration and development practice of the Shengli Oilfield. The research shows the following: (1) During the pressure-driven process, the distribution of the fracture network system is relatively limited. In the early stages of the process, there will be minor fractures, but they do not communicate or activate effectively. The improvement of physical properties and pore-throat structure is negligible. As the injection flow rate increases, the effective fracture network system begins to be established, and the range of fluid coverage begins to expand. With the progress of the pressure-driven process, the hydraulic fractures gradually extend, the number of activated original fractures gradually increases, the communication area between hydraulic fractures and original fractures gradually increases, and the reservoir modification effect gradually improves. (2) Based on the compression cracking experiment of large object molds, it is concluded that generating effective micro-cracks and activating them to form efficient diversion channels is the key to pressure flooding injection. Combining the mechanical characteristics of the rock in the target layer to precisely control the injection speed and injection pressure can maximize the fracture network, thereby improving the reservoir to achieve the purpose of pressure reduction and injection increase. (3) Different pressure flooding injection parameters were set for the low-permeability oil reservoirs in the study area to simulate the fracture network expansion. Finally, it was concluded that the optimal injection speed for fracture expansion was 1.2 m³/min and the optimal total injection volume was 20,000 m³. Through research, the mechanism of pressure-driven injection and the extent of reservoir modification caused by this pressure-driven process have been enhanced in terms of understanding. Full article

In the shale oil reservoirs, sandstone and shale often overlie each other. This significantly affects the vertical propagation of hydraulic fractures (HFs); however, the underlying mechanisms still remain unclear. This study employs Xsite software to investigate the influence of rock fracture toughness, tensile strength, elastic modulus, Poisson’s ratio, interlayer stress contrast, and the flow rate and viscosity of fracturing fluid on the propagation behaviour of HFs in sandstone–shale interbeds. As the type-I fracture toughness of the shale layer increases, the area of the vertical HF decreases and the average HF width becomes smaller. As the tensile strength of the sandstone layer increases, the distribution range of fluid pressure at the interface expands. The HF prefers to propagate in the softer rock rather than the harder one. A relatively narrower HF width is created in the layer with a higher elastic modulus resulting in a higher flow resistance to fracturing fluid. A shale layer with a high Poisson’s ratio is more likely to undergo a lateral expansion, causing stress at the fracture tip to be dispersed. When the effect of lithological interfaces is considered, an increasing interlayer stress contrast causes HFs to gradually transition from penetrating the interfaces to becoming confined between the two interfaces. When the influence of the lithological interface is not considered, an increasing interlayer stress contrast causes the HF to gradually transition from a penny-shaped fracture to a blade-shaped fracture. The HF penetrates the interfaces more easily at a higher injection rate and fluid viscosity, because most of the injected energy is used to create new fractures rather than leakoff into the interfaces. Understanding the influence of these factors on the HF propagation behaviour is of great significance for optimising hydraulic fracturing design. Full article

This study presents an integrated geophysical and hydrogeological characterization of fault systems in the sandstone-hosted uranium deposit within the K₁b² Ore Horizon of the Bayin Gobi Basin. Employing 3D seismic exploration with 64-fold coverage and advanced attribute analysis techniques (including coherence volumes, ant-tracking algorithms, and LOW_FRQ spectral attenuation), the research identified 18 normal faults with vertical displacements up to 21 m, demonstrating a predominant NE-oriented structural pattern consistent with regional tectonic features. The fracture network analysis reveals anisotropic permeability distributions (31.6:1–41.4:1 ratios) with microfracture densities reaching 3.2 fractures/km² in the central and northwestern sectors, significantly influencing lixiviant flow paths as validated by tracer tests showing 22° NE flow deviations. Hydrogeological assessments indicate that fault zones such as F11 exhibit 3.1 times higher transmissivity (5.3 m²/d) compared to non-fault areas, directly impacting in situ leaching (ISL) efficiency through preferential fluid pathways. The study establishes a technical framework for fracture system monitoring and hydraulic performance evaluation, addressing critical challenges in ISL operations, including undetected fault extensions that caused lixiviant leakage incidents in field cases. These findings provide essential geological foundations for optimizing well placement and leaching zone design in structurally complex sandstone-hosted uranium deposits. The methodology combines seismic attribute analysis with hydrogeological validation, demonstrating how fault systems control fluid flow dynamics in ISL operations. The results highlight the importance of integrated geophysical approaches for accurate structural characterization and operational risk mitigation in uranium mining. Full article

In horizontal well technology, hydraulic fracturing has been established as an essential technique for enhancing hydrocarbon production. However, the complex architecture of fracture networks challenges conventional monitoring methods. Micro-seismic monitoring, recognized for its superior resolution and sensitivity, enables precise fracture morphology characterization. This study advances diagnostic capabilities through integrated field–laboratory investigations and multi-domain signal processing. Hydraulic fracturing experiments under varied geological conditions generated critical micro-seismic datasets, with quantitative analyses revealing asymmetric propagation patterns (total length 312 ± 15 m, east wing 117 m/west wing 194 m) forming a 13.37 × 10⁴ m³ stimulated reservoir volume. Spatial event distribution exhibited density disparities correlating with geophone offsets (west wing 3.8 events/m vs. east 1.2 events/m at 420–794 m distances). Advanced time–frequency analyses and inversion algorithms differentiated signal characteristics demonstrating logarithmic SNR (Signal-to-Noise Ratio)–magnitude relationships (SNR 0.49–4.82, R² = 0.87), with near-field events (<500 m) showing 68% reduced magnitude variance compared to far-field counterparts. Coupled numerical simulations confirmed stress field interactions where fracture trajectories deviated 5–15° from principal stress directions due to prior-stage stress shadows. Branch fracture networks identified in Stages 4/7/9/10 with orthogonal/oblique intersections (45–65° dip angles) enhanced stimulation reservoir volume (SRV) by 37–42% versus planar fractures. These geometric parameters—including height (20 ± 3 m), width (44 ± 5 m), spacing, and complexity—were quantitatively linked to micro-seismic response patterns. The developed diagnostic framework provides operational guidelines for optimizing fracture geometry control, demonstrating how heterogeneity-driven signal variations inform stimulation strategy adjustments to improve reservoir recovery and economic returns. Full article