Shale reservoirs are highly tight and heterogeneous, with bedding planes and natural fractures pervasively developed. Multi-well fracturing is an emerging approach for the efficient development of shale reservoirs. However, previous studies scarcely consider the influence of complex natural fractures on the performance of multi-well fracturing. A fully coupled numerical framework for fracture propagation was developed through the continuous–discontinuous element method to simulate multi-well fracturing in a naturally fractured shale reservoir. The results indicate that preferentially fracturing the low-stress reservoir promotes different well groups stimulate its corresponding reservoir independently. However, affected by natural fractures, the fractures are prone to deflect, and there is a risk of frac hit as the fractures between wells may communicate with each other through natural fractures. As the average length of natural fractures increases, the stimulation disparity between high-stress and low-stress reservoirs decreases, but the probability of frac hit risk rises. The higher the density of natural fractures, the larger the fracture area. Moreover, a relatively high density of natural fractures is more likely to exacerbate the stress interference, thereby leading to frac hit risk. When the angle of natural fractures increases, the fracture control extent expands. When the angle is in the range of 30°–60°, the fracture morphology is more tortuous, and the frac hit risk reaches the peak. Either relatively small or large angles of natural fractures are not conducive to minimizing the stimulation disparity. The natural fractures in contact with hydraulic fractures tend to experience shear failure preferentially and can be mainly classified into "wet fractures" and "dry fractures". The former has a more pronounced impact on the performance of multi-well fracturing and can directly cause the deflection of hydraulic fractures. The findings of this study can offer theoretical underpinnings for the efficient development of shale reservoirs.

Methane deflagration fracturing in shale reservoirs is a novel waterless fracturing technology with the potential for transient high-pressure fracturing and rapid near-wellbore stimulation. However, under realistic wellbore constraints and confining stress conditions, the mechanisms by which different perforation modes influence deflagration energy release, fracture initiation and propagation, and casing integrity remain unclear. To address this issue, an ultra-large-scale true triaxial physical simulation platform was employed to establish an integrated casing-perforation-reservoir-deflagration physical simulation system. Large-scale methane deflagration fracturing experiments with dimensions of 2 m × 2 m × 1 m were conducted, involving two typical perforation schemes, namely 180° oriented perforation and 60° spiral perforation. The effects of different perforation modes on deflagration pressure response, perforation-hole conditions, post-fracturing fracture morphology, and casing integrity were comparatively investigated. The results show that: methane deflagration can generate high-amplitude transient pressure within an extremely short duration. The peak chamber pressures in the two experiments reached 1 219.00 MPa and 967.13 MPa, respectively, while the pressures transmitted to the casing wall rapidly decreased to 316.97 MPa and 256.63 MPa, corresponding to peak attenuation rates of approximately 74% and 73%, respectively; deflagration fracturing can weaken, to some extent, the dominant control of horizontal stress difference on fracture orientation, promoting the propagation of main fractures along the wellbore axis; after deflagration, only slight wear occurred at several perforation holes in both casing samples, with no obvious buckling, enlargement, tearing, or plastic deformation observed. This indicates that the P110 casing exhibited good resistance to deflagration-induced transient impact loading under the confining stress and perforation conditions adopted in this experiment; perforation parameters are critical factors controlling the release pathway of deflagration gas and fracture geometry. Under the experimental conditions, the 180° oriented perforation scheme generated a complex fracture network dominated by longitudinal fractures, accompanied by transverse fractures and multiple branches, whereas the 60° spiral perforation scheme produced main fractures with stronger connectivity, longer extension, and more regular morphology. This study reveals the regulating effect of perforation mode on methane deflagration energy release and fracture formation under confining stress constraints. The findings provide experimental support for optimizing methane deflagration fracturing parameters, evaluating wellbore integrity, and assessing engineering applicability.

Multi-cluster hydraulic fracturing in highly deviated wells is a key technology for developing stacked shale oil reservoirs, yet the 3D coupled mechanisms governing fracture propagation in naturally fractured formations remain unclear, limiting optimal stimulation design. This study presents a fully coupled hydro-mechanical 3D discrete lattice model integrated with stochastically generated natural fracture networks to simulate multi-cluster fracturing in highly deviated wells. The model, validated against true triaxial experiments, XFEM, DDM, and EFRAC-3D results, incorporates local mesh refinement for improved computational efficiency. A systematic parametric study of 30 numerical cases quantifies the effects of geological parameters (natural fracture density and horizontal stress anisotropy) and operational parameters (well inclination, cluster spacing, injection rate, and fluid viscosity) on fracture network complexity, total fracture area, and propagation uniformity. Results indicate that a natural fracture count of approximately 1000 maximizes stimulated area, whereas excessive fractures (≥1500) cause detrimental inter-cluster merging. Increasing horizontal stress difference from 1 MPa to 13 MPa enhances total fracture area by 19.92%. Regarding operational parameters, a 75° well inclination yields the largest fracture area (8043.34 m²), while 12 m cluster spacing optimizes network complexity. An injection rate of 0.15-0.175 m³/s represents a critical growth inflection point, and a fluid viscosity of 40 mPa·s maximizes total fracture area. The governing mechanism is identified as the synergistic coupling of natural fracture weak-plane effects, in-situ stress redistribution, and inter-cluster stress interference. This work provides a quantitative framework for optimizing multi-cluster fracturing in highly deviated shale oil wells.

The extreme downhole conditions in deep/ultra-deep reservoirs, such as high temperature and pressure, severely compromise conventional temporary plugging agents (TPAs), leading to inadequate mechanical strength and uncontrollable degradation during fracturing. To address this challenge, this study presents a novel hydrogel-based TPA engineered through a double-network synergy and nanocomposite enhancement strategy. Utilizing a one-pot method, a multi-level structure was constructed featuring a rigid curdlan (Cur.) first network, a flexible poly(acrylamide-co-sodium p-styrenesulfonate) (P(AM-co-SSS)) second network, and nano-laponite (Laponite) as reinforcement. The resulting material exhibits outstanding mechanical properties (compressive strength of 12.7 MPa at 100% strain, storage modulus of 34.2 kPa), excellent high-temperature adaptability, and controllable degradability (16.2% degradation after 8 h at 200°C; complete within 12 h). Orthogonal experiments and fuzzy comprehensive evaluation identified the optimal formulation: Cur. 5 wt%, AM+SSS 24 wt%, crosslinker 0.2 wt%, and Laponite 6 wt%. This study thus provides a robust material solution that integrates high strength-toughness with controllable degradation for temporary plugging in ultra-deep reservoir fracturing, offering significant potential for advancing stimulation technologies.

Fluid-driven fracture initiation and path selection in confined porous quasi-brittle media are strongly influenced by stress anisotropy and geometric boundary conditions. In this study, a cement-based analog material and a true-triaxial loading system were used to investigate how wellbore orientation and perforation geometry affect measurable fracture initiation and propagation responses in a high-angle-well fracturing context. The results indicate that in vertical wells, fractures consistently initiate along the direction of the maximum horizontal principal stress σH, with fracture pressure increasing alongside the perforation phase angle. In contrast, for directional wells, the fracture pressures are governed by a combination of the wellbore azimuth, perforation phase angle, and well deviation angle. When a directional well's azimuth is aligned with σH, its fracture initiation behavior resembles that of a vertical well. Conversely, when the azimuth is aligned with σh, fracture complexity and steering increase with the well deviation angle. Beyond a critical deviation angle, the fracture reorients to the vertical plane, resulting in a T-shaped fracture after stimulation. When the wellbore azimuth is misaligned with either principal horizontal stress direction, fracture steering typically occurs, although subsequent propagation generally follows σH. These findings provide controlled experimental guidance for stress-dominated fracture initiation and near-wellbore path selection in high-angle wells under conditions broadly similar.

The forward model of optical fiber strain induced by fractures, together with the associated model resolution matrix, is used to demonstrate the interpretability of fracture parameters once the fracture intersects the fiber. A regularized inversion framework for fracture parameters is established to evaluate the influence of measured data quality on the accuracy of iterative regularized inversion. An interpretation approach for both fracture width and height is proposed, and the synthetic forward data with measurement error and field examples are employed to validate the accuracy of the simultaneous inversion of fracture width and height. The results indicate that, after the fracture contacts the fiber, the strain response is strongly sensitive only to the fracture parameters at the intersection location, whereas the interpretability of parameters at other locations remains limited. The iterative regularized inversion method effectively suppresses the impact of measurement error and exhibits high computational efficiency, showing clear advantages for inversion applications. When incorporating the first-order regularization with a Neumann boundary constraint on the tip width, the inverted fracture-width distribution becomes highly sensitive to fracture height; thus, combined with a bisection strategy, simultaneous inversion of fracture width and height can be achieved. Examination using the model resolution matrix, noisy synthetic data, and field data confirms that the iterative regularized inversion model for fracture width and height provides high interpretive accuracy and can be applied to the calculation and analysis of fracture width, fracture height, net pressure and other parameters.

Optimizing hydraulic fracturing parameters is essential for improving the long-term performance of enhanced geothermal systems (EGS) in hot dry rock (HDR) reservoirs. In this study, an integrated numerical simulation framework is developed by coupling a 3D thermo-hydro-mechanical fracture propagation model with a post-fracturing geothermal extraction model. The effects of key fracturing parameters, including injection flow rate, fracturing fluid viscosity, fracturing fluid volume, and fracturing sequence, are systematically investigated. The results show that higher injection flow rates and higher fluid viscosities reduce fracture area and stimulated reservoir volume (SRV), thereby decreasing the heat extraction rate. Insufficient fracturing fluid volume limits fracture connectivity, whereas excessive fluid volume accelerates thermal breakthrough. Sequential fracturing generates a larger SRV and fracture area than simultaneous fracturing, but it also leads to a faster decline in heat extraction rate. A comprehensive evaluation model is further established by integrating the analytic hierarchy process (AHP) and the entropy weight method (EWM). This model quantitatively optimizes fracturing parameters by considering both fracture-network morphology and long-term geothermal recovery performance. Under the present model conditions, the optimal scheme is simultaneous fracturing with a fluid volume of 744 m3, fluid viscosity of 1 mPa s, and injection flow rate of 4.5 m3 min−1. This study provides a simulation-based optimization framework for efficient EGS development and offers theoretical support for the engineering design of geothermal reservoir stimulation.

Distributed strain sensing (DSS), benefiting from its high sensitivity, high spatial resolution, real-time capability, and continuous distributed measurement, has become an important technique for hydraulic fracturing diagnostics. To provide a comprehensive understanding of recent advances in DSS for hydraulic fracturing monitoring, this paper reviews three representative DSS technologies, namely low-frequency distributed acoustic sensing (LF-DAS), rayleigh frequency-shift distributed strain sensing (RFS-DSS), and optical frequency domain reflectometry-distributed strain sensing (OFDR-DSS), with respect to their sensing principles, downhole fiber-deployment methods, field applications in hydraulic fracturing, and associated diagnostic theories, and further outlines key directions for future development. The review indicates that: (1) LF-DAS, based on interferometric detection of coherent Rayleigh-scattering phase variations, is primarily sensitive to far-field strain-rate perturbations in offset wells and is therefore well suited for monitoring fracture hits, fracture propagation, and inter-well interference. RFS-DSS, which relies on coherent Rayleigh-scattering spectral-shift interrogation, is designed for high-resolution quasi-static strain measurements in the treatment well and is particularly effective for post-fracturing production monitoring. OFDR-DSS, employing swept-frequency coherent detection, is mainly used in laboratory experiments and numerical-model validation; (2) Downhole fiber-optic deployment has evolved from permanent behind-casing installation to permanent/semi-permanent outside-tubing configurations and fully retrievable inside-tubing configurations. Among these, behind-casing installation provides the best coupling to the formation, outside-tubing installation offers improved maintainability and flexibility, and inside-tubing installation provides the greatest operational convenience; (3) The diagnostic theory of DSS has evolved from qualitative interpretation of field measurements and qualitative multi-physics forward modeling to quantitative inversion of fracture parameters using optimization-based methods. With the integration of artificial intelligence, a comprehensive diagnostic workflow is emerging that consists of physical signal acquisition, forward modeling, inversion and interpretation, and intelligent diagnosis; (4) DSS still faces limitations in spatial coverage and temperature sensitivity. Consequently, multiwell deployment and the integration of DSS with DTS, DAS, microseismic monitoring, and other monitoring techniques are increasingly adopted, making multimodal cooperative monitoring an important direction for future development. Looking ahead, DSS is expected to achieve enhanced sensing performance and more robust diagnostic theories, becoming one of the key technologies for hydraulic fracturing monitoring.

During shale reservoirs stimulating, well factory fracturing can realize the maximization of stimulated reservoir volume by taking advantage of the inter-well induced stress. Currently, the research on well factory fracturing is relatively limited. The fracture evolution behavior during multi-well fracturing remains ambiguous. Moreover, no studies have been reported regarding the evaluation and optimization methods of well factory fracturing. A 3D fracture propagation model based on the continuous-discontinuous element method was utilized to simulate the dual-layer and four-well fracturing process in a shale reservoir and investigate the fracture evolution characteristics under inter-well interference. Utilizing the Analytic Hierarchy Process (AHP) and Entropy Weight Method (EWM), a quantitative evaluation model for well factory fracturing was developed. Further combined with the Box-Behnken design (BBD) response surface method, an optimization method for well factory fracturing was formed. The results show that the preferential fracturing of the low-stress reservoir can induce complex fracture morphologies in the high-stress reservoir, but they are primarily constrained to propagate within the target reservoir. Through the AHP and EWM, the weights of fracture-controlled range, stimulated difference between reservoirs, hydraulic fracture area, and opened bedding plane area with respect to fracturing performance are determined to be 0.5165, 0.271, 0.1354, and 0.077, respectively. The optimized parameter combinations of injection flow rate, well spacing, and cluster spacing based on the BBD response surface method are consistent with the on-site fracturing idea and exhibit better fracturing performance. This study can provide theoretical guidance for the optimization of well factory fracturing in shale reservoirs.

Temporary plugging staged fracturing (TPSF) is a critical technique for enhancing stimulated reservoir volume (SRV) in shale gas horizontal wells by promoting competitive propagation among multiple fracture clusters. However, the optimization of plugging timing and its interaction mechanism with operational parameters remain insufficiently investigated. In this study, a coupled discrete fracture network-finite element method (DFN-FEM) model integrated with cohesive elements and a custom developed UEL perforation element was established to simulate the dynamic fluid redistribution and competitive fracture propagation during TPSF. Parametric studies were conducted to investigate the effects of horizontal stress difference, injection rate, cluster spacing, and plugging times in conjunction with the evolution of plugging timing. The results demonstrate that the number of plugging events plays a decisive role in single stage plugging yields fracture lengths below 80 m, whereas two stage plugging consistently exceeds 90 m. The superior performance of two stage plugging is attributed to the initial plugging disrupts single fracture dominance and promotes multiple fracture initiation, while the subsequent plugging applied at the mid-to-late stage capitalizes on the established stress shadow to redirect fractures and activate branches. An optimal operational window is located at moderate injection rates and intermediate stress differences. Excessively small cluster spacing induces severe stress suppression, while overly large spacing eliminates beneficial inter-fracture competition. Furthermore, plugging timing dynamically regulates the interference stress intensity, dictating whether fractures propagate in an interleaved or sequential manner. This study provides quantitative guidance for field TPSF design and offers a robust numerical framework for optimizing plugging schedules.

Re-fracturing technology is currently one of the most effective stimulation ways to recover or enhance the well performance. However, the effectiveness of re-fracturing may be diminished due to inaccurate refracturing time and refracturing fracture propagation. In this study, the dynamic stress and pore pressure due to water injection and depletion are considered during the re-fracturing process using fully coupled method. Numerical simulations demonstrate that the distribution of pore pressure undergo alterations, thus resulting changes in the magnitude and orientation of in-situ stress. The optimal time window of refracturing can be obtained from the stress field and the stress redirection distance reached its highest value after 200-300d of production and 300d of injection for this given case. The deflection angle and fracturing pressure was used to examine the effect of different geological parameters on refracturing fracture morphologies. The fracture deflection angle increases with the raise of Young's modulus, injection pressure, and pumping rate. On the contrary, the injection well distance and the intersection angle between the direction of well arrays and initial fracture were behaviors the opposite influences on the fracture deflection angle. This work provides more insights to optimize the refracturing treatment for the waterflooded reservoir.

Temporary plugging and diverting fracturing is an effective strategy to enhance fracture network complexity and expand the stimulated reservoir volume. However, in ultra-deep reservoirs, temporary plugging agents face a critical contradiction between maintaining high pressure-bearing capacity and achieving rapid deplugging under ultra-high temperatures, as dense structure is usually accompanied by slower degradation rate. And also, after deplugging, fractures tend to close under ultra-high in-situ stress, significantly reducing conductivity. Inspired by the stage-specific functionality and core utilization strategy of chia seeds, this study proposes an innovative, resource-efficient "soft shell-rigid core" plugging structure. A dense yet rapidly self-degradable soft shell, formed from high-temperature-resistant polymers and degradable crosslinkers, is employed to encapsulate a high-strength core to form a core-shell structure. This design balances high pressure resistance with rapid degradation, while providing sustained fracture support post-deplugging. The prepared Gel@CP undergoes a sequential process of "injection-plugging-degradation-fracture support." It exhibits excellent fluid compatibility and suspension stability in the carrier fluid (static >3 h). Under 200 degrees C and 170,000 ppm salinity, the material reaches a maximum plugging pressure of 21.5 MPa, maintains 20 MPa for over 240 min, and shows a degradation rate above 99.9 % within 12 h, converting into environmentally benign water-soluble polymer fragments. After degradation, the exposed CP core effectively supports fractures, maintaining conductivity above 876 mD & centerdot;cm under 70 MPa closure stress. This delicate biomimetic core-shell design endows this material with superior performance simultaneously in pressure bearing, fast degradation, and post-deplugging fracture support, which is reported for the first time, providing an innovative, sustainable, and practical solution for temporary plugging and propping under extreme reservoir conditions.

Hydraulic fracturing serves as a critical technology for reservoir stimulation in deep coalbed methane (CBM) development, where the mechanical properties of gangue layers exert a significant control on fracture propagation behavior. To address the unclear mechanisms governing fracture penetration across coal-gangue interfaces, this study employs the Continuum-Discontinuum Element Method (CDEM) to simulate and analyze the vertical propagation of hydraulic fractures initiating within coal seams, based on geomechanical parameters derived from the deep Benxi Formation coal seams in the southeastern Ordos Basin. The investigation systematically examines the influence of geological and operational parameters on cross-interfacial fracture growth. Results demonstrate that vertical stress difference, elastic modulus contrast between coal and gangue layers, interfacial stress differential, and interfacial cohesion at coal-gangue interfaces are critical factors governing hydraulic fracture penetration through these interfaces. High vertical stress differences (>3 MPa) inhibit interfacial dilation, promoting predominant cross-layer fracture propagation. Reduced interfacial stress contrasts and enhanced interfacial cohesion facilitate fracture penetration across interfaces. Furthermore, smaller elastic modulus contrasts between coal and gangue correlate with increased interfacial aperture. Finally, lower injection rates effectively suppress vertical fracture propagation in deep coal reservoirs. This study elucidates the characteristics and mechanisms governing cross-layer fracture propagation in coal–rock composites with interbedded partings, and delineates the dynamic evolution laws and dominant controlling factors involved. The findings provide critical theoretical insights for the optimization of fracture design and the efficient development of deep coalbed methane reservoirs.

The influence of CO2-water-rock interactions on the fracture mechanical performance of transversely isotropic shale is a critical factor affecting the long-term safety of CO2 sequestration in depleted shale reservoirs. In this study, a series of CO2-water-rock reaction experiments combined with semi-circular bend (SCB) tests were conducted to investigate the macro- and microscopic mechanisms underlying the impact of CO2-water-rock interactions on shale fracture performance. Shale specimens were exposed to CO2 and water at a constant temperature of 50 degrees C prior to fracture toughness testing, with exposure times of 0, 10, 20, and 30 d and pressures of 6, 11, and 16 MPa. Control groups subjected to water-bath treatment and pure CO2 treatment were also established. The experimental results indicate that reaction pressure is the primary factor governing the onset of fracture toughness degradation induced by CO2-water-rock interactions: higher pressures lead to a more pronounced weakening effect. The phase transition of CO2 under different reaction pressures markedly alters the evolution pathway of shale fracture toughness and the influence exerted by CO2-water-rock interactions on fracture toughness. The presence of water significantly enhances both the reactivity and pressure sensitivity of CO2-rock reactions. As exposure time increases, the effect of CO2-water-rock interactions on shale fracture toughness transitions from a strengthening to a weakening effect. In the short-term reaction, extensive contact between shale, CO2, and water induces the formation of widely dispersed physical dissolution micropores, enhancing the fracture resistance of shale. In contrast, long-term reaction promotes sustained chemical dissolution of locally reactive minerals, producing enlarged dissolved pores and a pronounced deterioration in both material strength and fracture toughness. The evolution of clay mineral content plays a decisive role in the timedependent behavior of shale fracture toughness. These findings enhance the understanding of the macro- and microscopic mechanisms governing CO2-water-rock interactions in the context of CO2 geological sequestration in depleted shale reservoirs, and provide essential theoretical support for evaluating storage potential and ensuring long-term reservoir integrity.

Distributed optical fiber sensing (DOFS) technology, with its high spatial resolution, long-distance monitoring capability, and resistance to electromagnetic interference, demonstrates significant application potential in hydraulic fracturing crack monitoring. However, due to the complexity of signals during crack propagation and their susceptibility to noise interference, accurately inverting crack geometric parameters remains a technical challenge. To address this issue, we propose an innovative forward-reverse interactive (FRI) long short-term memory (LSTM) (FRI-LSTM) model based on deep learning techniques. The model utilizes strain data from a forward model of crack propagation to invert crack parameters, including fracture length, inlet width, and average width. First, the study compares the performance of models such as recurrent neural network (RNN), gated recurrent unit (GRU), LSTM, and Transformer in inverting distributed optical fiber strain signals. The results show that traditional LSTM outperforms other models in capturing dynamic features and modeling nonlinear relationships. Building on this, the proposed FRI-LSTM model leverages forward and reverse feature interaction modeling and a joint optimization mechanism to significantly enhance the global modeling capability and prediction accuracy of the LSTM model. Compared with traditional LSTM, the proposed model achieves a 47% reduction in mean absolute error (MAE), a 47% reduction in root mean square error (RMSE), and an increase in R-2 from 0.6179 to 0.7500. This study is the first to introduce neural networks into the field of distributed optical fiber strain data interpretation, providing an innovative solution for efficient crack parameter interpretation. The findings provide a new interpretation approach for hydraulic fracturing crack monitoring, while also offering a methodological reference for addressing complex time-series modeling challenges in broader applications such as pipeline surveillance and seismic signal analysis.

Gravel-packed completion has been widely recognized as the optimal solution for sand control, but due to the limitation of the simulation method, the gravel phase is approximated as the liquid phase, and the numerical simulation is carried out by the Eulerian-Eulerian method, which is more efficient in calculation but reduces the calculation accuracy and is not realistic enough, leading to the optimisation of some of the construction parameters in the field is still problematic. In this study, a numerical model of gravel filling in horizontal wells is constructed based on the coupled DEM-CFD method which can achieve accurate particle tracking, and the influence of gravel density, viscosity, gravel concentration and sand-carrying liquid discharge on the gravel filling degree is investigated, and the degree of densification is proposed as a new evaluation index, and the results of the study can provide theoretical guidance for the construction in the field.

Non-uniform proppant placement during horizontal well hydraulic fracturing significantly impairs fracture conductivity and well productivity. Most existing models oversimplify conductivity distribution and lack integration between proppant transport and production prediction. This study presents a novel integrated numerical framework that fully couples fracture propagation, proppant transport, and post‑fracturing production. Unlike previous approaches that treat conductivity as uniform or decouple the physical processes, our model incorporates a dynamic conductivity evolution submodel that updates fracture conductivity in real time based on local closure stress and proppant concentration, enabling a more realistic representation of proppant placement effects. The model is validated against the commercial reservoir simulator ECLIPSE, with a cumulative production mismatch of less than 8% over 300 days, confirming its reliability. A two‑way coupled approach then systematically evaluates the impact of key pumping parameters: sand injection method, proppant size, injection rate, fluid viscosity, sand concentration, and perforation design. Results demonstrate that parameter sensitivity strongly depends on reservoir permeability. In ultra‑low permeability reservoirs (1 × 10⁻⁶ µm²), propped fracture area is the dominant productivity control, favoring constant‑concentration sand addition with finer proppant (70/140 mesh), lower injection rates, and lower viscosities to maximize fracture length. In higher permeability reservoirs (1 × 10⁻³ µm²), fracture conductivity becomes critical, with optimal performance achieved using constant‑concentration addition of coarser proppant (30/50 mesh), higher injection rates, and higher viscosities. Increasing sand ratio improves production in both reservoir types, though with diminishing returns. These findings provide clear, permeability‑specific guidelines for optimizing fracturing design and enhancing well performance.

Intra-fracture temporary plugging fracturing is an effective technique for the creation of multi-level branched fractures. The transport and plugging performance of temporary plugging agents (TPAs) within fractures directly determines the efficiency of the fracturing operation. However, there are few studies addressing the growth mechanisms of the plugging layer, and the influence of key TPA physical properties (such as particle shape and friction coefficient) on plugging efficiency remains poorly understood. This lack of understanding hinders the theoretical foundation necessary for the optimized design of intra-fracture temporary plugging strategies. In this study, a high-fidelity numerical model based on a coupled CFD-DEM approach, which accurately accounts for particle-particle contact and collision behaviors, was developed to simulate the transport and plugging process of TPAs within fractures. A comprehensive investigation was conducted to understand the plugging behavior under varying operational parameters. The results indicate that the growth of the plugging layer follows four distinct stages, different operational parameters primarily influence the growth characteristics by altering the particle sedimentation rates at the front and rear of the accumulation zone. An increase in friction coefficient enhances bridging capability and results in a 74.07 % reduction in plugging layer length. Small-diameter TPAs (1.2 mm) exhibit poor plugging performance due to their low bridging probability, which can be improved through synergistic injection of mixed particle sizes. Irregular-shaped particles form interlocking structures via multi-point contacts, enhancing the mechanical stability of the plugging layer. An optimal TPA density range of 1120-1300 kg.m-3 is recommended.