Search Results (218)

Because of its strong bearing capacity and large size, a thick and hard roof is the main source of strong ground pressure in a stope, and its breaking and migration mechanism and effective control are very important for realizing safe and efficient mining in coal mines. In this paper, by constructing a numerical model that fully considers the actual occurrence conditions of such a roof, the control law of the occurrence conditions of a thick and hard roof on its fracture law and strata behavior is systematically studied, and the control mechanism of the movement and hydraulic fracturing of this kind of roof is revealed. The results show that (1) the fracture process of a thick hard roof is characterized by three stages—crack initiation, extension, and overall instability—and the “pressure arch” structure formed by the overlying huge hard rock stratum is the fundamental force source leading to strong ground pressure; (2) the roof thickness and horizon significantly control the stress distribution and fracture behavior of coal and rock mass, and the peak stress of coal and rock mass is positively correlated with the roof thickness, but negatively correlated with its horizon; (3) with the increase in roof thickness, the dominant fracture mechanism changes from tension type to tension–shear composite type, which leads to a significant increase in fracture step. Hydraulic fracturing technology can effectively cut off the “pressure arch” structure and optimize the stress field of surrounding rock. After fracturing, the first weighting step and weighting strength are reduced by 36% and 38.1%, respectively. An industrial test shows that a fracturing treatment realizes timely and orderly roof caving and achieves the controllable weakening and safe promotion of the thick and hard roof. This study provides a solid theoretical basis and a successful engineering practice model for roof disaster prevention and control under similar geological conditions. Full article

The Chang 7 shale oil reservoirs of the Yanchang Formation in the Heishui Area of the Ordos Basin display typical tight sandstone characteristics, marked by complex microscopic pore structures and limited flow capacity, which severely constrain efficient development. Using a suite of laboratory techniques—including nuclear magnetic resonance, mercury intrusion porosimetry, oil–water relative permeability, spontaneous imbibition experiments, scanning electron microscopy, and thin section analysis—this study systematically characterizes representative tight sandstone samples and examines the microscopic distribution of remaining oil, flow behavior, and their controlling factors. Results indicate that residual oil is mainly stored in nanoscale micropores, whereas movable fluids are predominantly concentrated in medium to large pores. The bimodal or trimodal T₂ spectra reflect the presence of multiscale pore–fracture systems. Spontaneous imbibition and relative permeability experiments reveal low displacement efficiency (average 41.07%), with flow behavior controlled by capillary forces and imbibition rates exhibiting a three-stage pattern. The primary factors influencing movable fluid distribution include mineral composition (quartz, feldspar, lithic fragments), pore–throat structure (pore size, sorting, displacement pressure), physical properties (porosity, permeability), and heterogeneity (fractal dimension). High quartz and illite contents enhance effective flow pathways, whereas lithic fragments and swelling clay minerals significantly impede fluid migration. Overall, this study clarifies the coupled “lithology–pore–flow” control mechanism, providing a theoretical foundation and practical guidance for the fine characterization and efficient development of tight oil reservoirs. The findings can directly guide the optimization of hydraulic fracturing and enhanced oil recovery strategies by identifying high-mobility zones and key mineralogical constraints, enabling targeted stimulation and improved recovery in the Chang 7 and analogous tight reservoirs. Full article

High rock slopes are extensively distributed in areas of major engineering constructions, such as transportation infrastructure, hydraulic projects, and mining operations. The stability and failure evolution mechanism during their multi-stage excavation process have consistently been a crucial research topic in geotechnical engineering. In this paper, a series of two-dimensional rock slope models, incorporating various combinations of slope height and slope angle, were established utilizing the Discrete Element Method (DEM) software PFC2D. This systematic investigation delves into the meso-mechanical response of the slopes during multi-stage excavation. The Parallel Bond Model (PBM) was employed to simulate the contact and fracture behavior between particles. Parameter calibration was performed to ensure that the simulation results align with the actual mechanical properties of the rock mass. The research primarily focuses on analyzing the evolution of displacement, the failure modes, and the changing characteristics of the force chain structure under different geometric conditions. The results indicate that as both the slope height and slope angle increase, the inter-particle deformation of the slope intensifies significantly, and the shear band progressively extends deeper into the slope mass. The failure mode transitions from shallow localized sliding to deep-seated overall failure. Prior to instability, the force chain system exhibits an evolutionary pattern characterized by “bundling–reconfiguration–fracturing,” serving as a critical indicator for characterizing the micro-scale failure mechanism of the slope body. Full article

The ZN Oilfield shale reservoir is characterized by thin sand–shale interbeds, strong lateral and vertical heterogeneity, poor porosity–permeability, low formation pressure coefficient, and low brittleness, which together limit fracture propagation and suppress production after conventional hydraulic fracturing. To overcome these constraints, we propose an intensive-stage, closely spaced volumetric fracturing technology that couples energy-replenishment pressurization with differentiated parameter design. Numerical simulations were used to quantify how injected fluid volume affects the post-fracturing formation pressure coefficient and estimated ultimate recovery (EUR), and to determine economically optimal energy-replenishment scales. Guided by a “dual sweet spot” evaluation (geological + engineering), field designs reduced stage spacing from 80–100 m to 30–50 m and cluster spacing from 10–20 m to 6–10 m, and increased proppant and fluid intensities to ~5.0 t/m and 22.0 m³/m, respectively. Field monitoring and production data show average fracture half-length increased to 193 m, and average initial oil production per well rose from 8.8 t/d to 12.9 t/d (≈46% increase). These results demonstrate that the proposed approach effectively enlarges fracture-controlled reservoir volume, enhances formation energy, and substantially improves single-well performance in low-pressure shale oil systems. Full article

Unconventional shale oil reservoirs, characterized by ultra-low porosity and permeability, severely constrain oil recovery. CO₂-enhanced oil recovery (CO₂-EOR) following hydraulic fracturing is an effective approach that combines incremental oil recovery with long-term CO₂ storage. However, CO₂ transport in the fracture–matrix system is complex, especially when molecular diffusion and geochemical reactions are coupled. This study conducts numerical simulations on a representative shale reservoir in the Ordos Basin, incorporating both mechanisms under post-fracturing injection–soaking conditions. The results show that molecular diffusion enhances CO₂ mass transfer across the fracture–matrix interface, increasing the final CO₂ sweep efficiency by 0.17 percentage points relative to convection alone, whereas geochemical reactions reduce it by about 0.3 percentage points. When both mechanisms coexist, the net effect is a decrease of approximately 0.2 percentage points in CO₂ sweep efficiency. In contrast, pressure sweep efficiency differs by less than 0.5 percentage points among all cases and stabilizes near 47%, suggesting that pressure propagation is only weakly affected by diffusion and reactions. Sensitivity analysis reveals that, among operational parameters, injection pressure and injection rate strongly affect CO₂ sweep efficiency, whereas soaking time governs pressure propagation. Among reservoir parameters, permeability has the most pronounced influence on both CO₂ and pressure sweep efficiencies, followed by temperature, while initial reservoir pressure has minimal impact. This work quantitatively elucidates the coupled roles of molecular diffusion and geochemical reactions in shale reservoirs and provides practical guidance for optimizing post-fracturing CO₂-EOR operations. Full article

Accurate phase association and arrival time picking are pivotal for reliable microseismic event location and source characterization. However, the complexity of downhole microseismic wavefields, arising from heterogeneous subsurface structures, variable propagation paths, and ambient noise, poses significant challenges to conventional automatic picking methods, even when the signal-to-noise ratio (SNR) is moderate to high. Specifically, P-wave coda energy can obscure S-wave onsets analysis, and shear wave splitting can generate ambiguous arrivals. In this study, we propose a novel multi-channel arrival picking framework based on Constrained Dynamic Time Warping (CDTW) for phase identification and simultaneous P- and S-wave arrival estimation. The DTW algorithm aligns microseismic signals that may be out of sync due to differences in timing or wave velocity by warping the time axis to minimize cumulative distance. Time delay constraints are imposed to ensure physically plausible alignments and improve computational efficiency. Furthermore, we introduce a Multivariate CDTW approach to jointly process the three-component (3C) data, leveraging inter-component and inter-receiver arrival consistency across the entire downhole array. The method is validated against the Short-Term Average/Long-Term Average (STA/LTA) and waveform cross-correlation techniques using field data from a shale gas hydraulic fracturing. Results demonstrate that the proposed algorithm significantly enhances arrival time accuracy and inter-receiver consistency, particularly in scenarios involving P-wave coda interference and shear wave splitting. Full article

High-pressure water injection (HPWI) refers to injecting water into the formation under conditions where the injection pressure is higher than or close to the formation fracture pressure. This technique can effectively improve the water absorption capacity of low-permeability reservoirs and maintain the formation pressure above the bubble point. It is a key technology for solving the problem of “difficult injection and difficult recovery” in low-permeability reservoirs, thereby achieving increased injection and enhanced production. However, due to the lack of a unified understanding of the mechanisms of dynamic micro-fractures and the mechanism of pore volume expansion and permeability enhancement during HPWI, the technology has not been widely promoted and applied. Based on an in-depth analysis of the mechanism of high-pressure water injection and by building a geological model for an actual oilfield development block, the “compaction–expansion” theory of rocks is used to characterize the variation in reservoir properties with pore pressure. This model is used to simulate the reservoir’s pore volume expansion and permeability enhancement effects during high-pressure water injection. The research results show the following: (1) HPWI can increase the effective distance of injected water by changing the permeability of the affected area. (2) During HPWI, the effective areas in the reservoir are divided into three regions: the enhanced-permeability zone (EPZ), the swept zone without permeability enhancement, and the unswept zone. Moreover, the EPZ expands significantly with higher injection pressure, rate, and volume. However, the degree of reservoir heterogeneity will significantly affect the effect of HPWI. (3) Simulation of two production modes—“HPWI–well soaking–oil production” and “simultaneous HPWI and oil production”—shows that under the first production mode, the degree of uniformity of the production wells’ response is higher. However, in the production wells in the EPZ, after a certain stage, an overall water flooding phenomenon occurs. In the second mode, the production wells in the water channeling direction show an alternating and rapid water-flooding phenomenon, while the production wells in the non-water channeling areas are hardly affected. Meanwhile, for local production wells with poor effectiveness of high-pressure water injection, hydraulic fracturing can be used as a pilot or remedial measure to achieve pressure-induced effectiveness and improve the sweep efficiency of the injected water. The results of this study explain the mechanisms of volume expansion and permeability enhancement during high-pressure water injection, providing guiding significance for the on-site application and promotion of high-pressure water injection technology in low-permeability 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

Numerical simulation of groundwater level dynamics plays a crucial role in the safety assessment of near-surface radioactive waste disposal facilities. Such disposal sites are typically located in regions characterized by extensive bedrock outcrops. However, accurately characterizing the permeability of fractured media is challenging, and the scarcity of groundwater level data poses significant difficulties for constructing reliable numerical models. This study focuses on a near-surface disposal site in northwestern China. By integrating field packer tests with hydraulic conductivity tensors computed from borehole televiewer data, we quantitatively evaluated the permeability of fractured rocks of different lithologies to provide accurate parameters for numerical modeling. The constructed groundwater flow model was further calibrated and validated using long-term groundwater level monitoring data and field tracer-based groundwater flow direction tests, ensuring high model reliability. Using the calibrated model, groundwater level variations were simulated under various rainfall and pumping scenarios. The results show that pumping intensity in the downstream farmland area exerts a limited influence on groundwater levels beneath the disposal site, while rainfall intensity plays a dominant role. Under the heavy rainfall scenario, the groundwater level at the disposal site rises by approximately 5.2 m after 50 years, leaving a 6 m gap above the base of the disposal unit. Under prolonged heavy rainfall conditions, implementing drainage measures may be necessary to ensure the repository’s long-term safety. 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

Shale reservoirs contain abundant organic matter, pyrite, and clay minerals, making them highly susceptible to fluid-sensitivity damage; consequently, conventional hydraulic fracturing often yields poor stimulation performance, with low fracturing fluid flowback and rapid post-treatment production decline. Oxidative dissolution, however, can significantly alter the physical properties of shale reservoirs and improve stimulation effectiveness. In this study, nuclear magnetic resonance (NMR), contact-angle measurements, and triaxial compression tests are combined to systematically evaluate the effects of oxidative dissolution on the pore structure, wettability, and mechanical properties of Wufeng Formation shale from the Sichuan Basin. Core-flooding experiments with NaClO solutions show that, as the oxidant dosage (pore volume) increases, shale permeability rises by 66.67–266.67% and porosity by 1.79–9.58%, while the hydrophilic surface fraction increases from 5.45% to 61.73%. These changes are accompanied by a steady reduction in rock strength: the compressive strength decreases by up to 57.8%, and the elastic modulus exhibits a non-monotonic response to oxidation. Oxidative dissolution preferentially enlarges micropores, improves pore connectivity, and strengthens water wetness by consuming oil-wet organic matter and pyrite, which also enhances gel-breaking efficiency. Based on the experimental results, a series of characterization models are developed for oxidized shale reservoirs, including quantitative relationships linking porosity to compressive strength, elastic modulus, and contact angle, as well as a model relating oxidant dosage to microscopic pore structure evolution and imbibition enhancement. Overall, the coupled modifications of pore structure, wettability, and mechanical behavior produced by oxidative dissolution synergistically broaden the effective action range of fracturing fluids, promote shale gas desorption, and improve hydrocarbon seepage, providing a theoretical basis and practical guidance for oxidation-assisted stimulation in shale reservoirs. Full article

This study investigated the geohydraulic properties of the Chaouia coastal aquifer in western Morocco through two-dimensional Electrical Resistivity Tomography (ERT). Five resistivity profiles were carried out and inverted to define subsurface lithology and estimate hydraulic conductivity (K), effective porosity (Φ_eff), and transmissivity (T) using the empirical relationships.The obtained results showed that K ranged from 1.2 m/day to more than 217.4 m/day, Φ_eff varied between 20.3% and 47.8%, and T varied between 0.4 and 159.3 m²/day. These findings highlight considerable lithological variability, with low to intermediate values in Plio-Quaternary deposits and higher values in fractured Cretaceous marly limestones. Comparison with available pumping test data and numerical modeling validated the consistency of the ERT-derived estimates with independent hydrogeological evidence. The present study demonstrates that, in areas where pumping tests are limited or impractical, ERT provides an effective, non-invasive, and cost-efficient tool for aquifer characterization. These findings offer valuable insights for groundwater assessment and support the development of sustainable management strategies to mitigate overexploitation and seawater intrusion in vulnerable coastal aquifers and propose sustainable strategies for conserving these water resources. Full article

Gas injection displacement technology plays a critical role in enhancing coalbed methane (CBM) and mine gas extraction efficiency. Numerical simulation is essential for revealing multi-field coupling mechanisms and optimizing process parameters, effectively addressing challenges such as high field test costs and limited laboratory scalability. This study systematically reviews progress in modeling physical fields (e.g., flow and diffusion), focusing on multi-physical field coupling mechanisms and permeability model evolution. It conducts iterative numerical model analysis—from basic flow–diffusion to fully coupled THMC models—compares simulation software (COMSOL shows greater coupling depth and compatibility than COMET3), and characterizes key mechanisms. By systematically reviewing the key advancements in the fields of numerical simulation in recent years (including important achievements such as the Buddenberg–Wilke equation and the improved Palmer–Mansoori model), a decision-making framework was proposed based on these achievements, covering “Multi-physical Field Coupling Equation Selection, Key Parameter Calibration, Permeability Equation Selection, Model Validation and Error Correction” simulation error ≤10% in heterogeneous coal seams. Although general-purpose tools enable high-precision multi-physics coupling, improvements are still needed in modeling flow–diffusion mechanisms, heterogeneity, and chemical field integration. This study provides a systematic methodological reference for the engineering application of gas injection displacement numerical simulation, and the framework constructed hereby can also be extended to shale hydraulic fracturing and other related fields. Full article

Tight conglomerate reservoirs are characterized by dense lithology, significant compositional contrasts between cement and gravel, strong stress gravel content, strong heterogeneity, and uneven spatial distribution, which collectively result in low porosity, complex pore–throat structures, and low permeability. After hydraulic fracturing, the stress sensitivity of tight conglomerate reservoirs is jointly governed by the rock matrix and induced fractures. In this study, the Mahu tight conglomerate reservoir in the Xinjiang Oilfield was selected as the research target. Stress sensitivity experiments were conducted on conglomerate matrix cores and on cores with varying fracture conditions. After stress loading, the degrees of permeability damage of the matrix, through-fracture, double short-fracture, and microfracture cores were 41%, 69%, 93%, and 97%, respectively. The matrix exhibited moderate-to-weak stress sensitivity, the through-fracture cores showed moderate-to-strong stress sensitivity, while the double short-fracture and microfracture cores exhibited strong stress sensitivity. Experimental results indicate that when fractures are present, the stress sensitivity of the core is primarily controlled by fracture closure and matrix compression. As fracture development increases, core permeability is significantly enhanced; however, stress sensitivity also increases accordingly. Under net stress, gravel protrusions embed into fracture surfaces, reducing surface roughness, while irreversible alteration of fracture geometry becomes the dominant factor driving stress sensitivity in fractured cores. These findings provide a scientific basis for predicting stress-sensitivity-induced damage in tight conglomerate reservoirs. 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