To address the difficulty of proppant penetration into narrow and horizontal fractures within complex fracture systems of shale gas reservoirs, this study proposes an optimized co-injection strategy utilizing 200/400-mesh micro-proppants and conventional 70/140-mesh proppants. A visualized parallel-plate fracture experimental apparatus, incorporating mult-stage orthogonal secondary fractures and horizontal fractures, was constructed. Furthermore, a multi-size proppant transport numerical model was established based on the Eulerian-Eulerian multiphase flow framework to systematically investigate the transport and placement behaviors of proppants under varying blending ratios and particle size combinations in complex fractures. The results demonstrate that the incorporation of micro-proppants significantly alters the placement pattern of 70/140-mesh proppants, transitioning it from preferential accumulation at the near-wellbore region to a uniform laminated distribution along the fracture height. By enhancing suspension capacity, attenuating inter-particle collisions, and forming an upper suspension layer, micro-proppants effectively facilitate the entry of other-sized proppants into secondary and horizontal fractures. However, an excessive proportion of micro-proppants is found to inhibit particle settling, thereby reducing the equilibrium height of the proppant dune in the main fracture. Furthermore, two distinct mechanisms governing proppant entry into horizontal fractures are elucidated: the carrying effect of the fluidized layer dependent on the proppant dune height, and the suspension-driven diversion dominated by micro-proppants. These findings elucidate the synergistic transport mechanisms of multi-size proppants in complex fractures from both experimental and numerical perspectives, providing a robust theoretical foundation for optimizing proppant ratios in hydraulic fracturing operations.

Mud leakage during workover can contaminate existing fractures and lead to significant deviations in refracturing treatment-pressure designs. This study aims to characterize mud leakage behaviour in fractured reservoirs and predict its impact on refracturing treatment pressure. A two-phase Darcy flow framework was established to simulate mud leakage and to obtain the spatial distribution of mud saturation. Based on the simulated mud-retention geometry in existing fractures, a treatment-pressure prediction model was developed by partitioning the fracture into mud-occupied and unleaked flow regions and incorporating permeability damage. The workflow was validated using field data from two mud-contaminated refracturing wells in the Tarim Basin, NW China (wells A and B). Field data indicate leaked mud volumes of 13.0 m(3) (Well A) and 9.6 m(3) (Well B), accompanied by substantial productivity degradation (the unrestricted flow rates decreased from 142.3 & times; 10(4) to 52.2 & times; 10(4) m(3)/day in Well A and from 38 & times; 10(4) to 1 & times; 10(4) m(3)/day in Well B) and residual permeability ratios of 0.366 and 0.026, respectively. A baseline pressure prediction that ignores mud impact underestimates the observed treatment-pressure window (110-120 MPa for Well A; 120-130 MPa for Well B) by 20.3-36.2 and 14.6-42.2 MPa, respectively. After incorporating mud retention and permeability damage, the predicted pressure ranges shift to 109.6-117.4 MPa (Well A) and 122.4-146.9 MPa (Well B), yielding a clear overlap with the measured pressure windows and substantially reducing the mismatch. This study provides an additive and practically applicable method for pressure-design correction and risk assessment in mud-contaminated refracturing operations.

The concept of "full fracture propping" aims to improve fracture placement morphology by the efficient placement of main fractures and hierarchical propping of multi-scale fractures, effectively addressing the limited effective propped volume in unconventional oil and gas reservoirs. Using proppant-fiber clusters instead of pure proppant as the basic transport unit in fractures can effectively increase the lateral migration distance and vertical placement height of proppant in main fractures, serving as a key technical approach to achieving efficient placement. This study systematically investigated the structural characteristics and sedimentation mechanisms of proppant-fiber clusters through experimental methods, establishing a physical model of the cluster unit network structure and revealing the sedimentation and placementmechanisms of clustered bodies within the main fractures. The results indicate that proppant-fiber clusters are a composite system jointly composed of a fiber framework that traps proppant particles, a filamentous network of friction reducer polymers, and a flaky structure of stabilizer. Characterization of cluster units and their size distributions revealed that increasing fiber mass fraction and length facilitates the formation of larger cluster units.Specifically, the average proppant placement height increased by 116.6% with the addition of 0.5% fibers compared to the proppant-only system. At 30 seconds of sedimentation, the average sizes of the cluster units formed by 6 mm and 12 mm fibers are 2.15 mm and 4.26 mm, respectively. However, the relationship between slickwater viscosity and cluster size is nonlinear. Transport experiments in the multi-stage fracture show that increasing fiber mass fraction and fiber length can elevate proppant placement height in the main fracture, but fiber-induced proppant blockage occurs at fracture intersections.Therefore, optimizing material intrinsic properties and injection parameters is of significant engineering importance for realizing full fracture domain propped technology centered on proppant-fiber cluster transport. The research findings also provide theoretical support for the optimal design and field application of fiber-assisted fracturing technology.

As a low-pollution unconventional energy source, shale gas development relies on fracturing to address inherent low reservoir permeability. However, post-fracturing reservoir/wellbore changes combined with weak gas-liquid carrying capacity cause widespread liquid loading in shale gas wells, increasing backpressure, reducing production, and even leading to reservoir water flooding. Traditional detection methods have limitations: mechanistic models suffer from high errors due to simplified assumptions, existing data-driven models are mostly binary classifiers that fail to distinguish severity, and data-driven liquid level detection is costly. To solve these issues, this study proposes a contrastive learning-enhanced feature fusion classification model (CL-FFCM), consisting of a "fusion network" for multi-source latent feature extraction and a "head network" for four-level classification. The SupCon loss function enhances inter-class differences to resolve ambiguous feature boundaries. Experiments on 142 shale gas wells show CL-FFCM achieves 0.94-0.95 accuracy. Contrastive learning stably improves five mainstream models' accuracy by 6%-9%. Field applications in southern Sichuan indicate an average early warning deviation of 3-8 h. This model provides a reliable tool for precise liquid loading management, with great significance for efficient shale gas development.

Summary Novel knotted temporary plugging balls have been widely applied in various fields, owing to their unique geometric structure. The optimization of temporary plugging in multicluster horizontal wells is a critical challenge for enhancing hydraulic fracturing efficiency. For this study, we developed and experimentally validated a computational fluid dynamics-discrete element method (CFD-DEM) coupled model to simulate the migration and plugging behavior of novel knotted temporary plugging balls. An innovative discrete ball-chain method was introduced to characterize the flexibility of fibrillated tails, while the immersed boundary method (IBM) was applied to directly resolve fluid/solid interactions. The simulation results revealed a three-stage plugging mechanism comprising axial migration, adaptive alignment, and compliant deformation. In the second stage, the critical capture distance between the ball and perforation is defined as the key parameter governing successful plugging. The tail structure significantly extends this distance, which scales with the tail length and number. Plugging placement can be steered by adjusting the density contrast between the tails and the core. Furthermore, multicore knotted balls exhibited self-adaptive selective and secondary plugging under nonuniform erosion. Based on these findings, a variable-density multicore adaptive plugging strategy is proposed that integrates low-, medium-, and high-density designs to improve the perforation plugging probability in multicluster completions. The results provide guidance for material design and operational optimization.

Our country has abundant coal rock gas resources. Hydraulic fracturing is a key technology for effectively developing coal rock gas reservoirs. Due to the differences in the mechanical properties, microstructure, gas occurrence states, and productivity-controlling factors of deep coal rock compared with shallow and medium-depth coal reservoirs, as well as the significant property variation in reservoirs between blocks, the adaptability of current fracturing technologies still faces challenges. Innovation in reservoir stimulation technologies is essential for the efficient development of coal rock gas. The difficulties in reservoir stimulation brought by the geological characteristics of coal rock gas reservoirs are discussed first. To deal with the geological features and the challenges of fracturing technology, an efficient development concept of matrix pore-cleat/fracture simultaneous stimulation, summarized as “point desorption, line dredging, fracture geometry improvement, and propped bulk fracture network”, is proposed, and the following key issues are figured out based on its connotation: ① fracturing-induced matrix pore structure and pore surface property modification, enhanced gas desorption, imbibition displacement, and adsorbed-phase and free-phase methane collaborative and efficient gas supply; ② activate cleats/fractures, shorten gas diffusion distances, and facilitate matrix reserves releasing; ③ promote uniform fracture propagation, enhance fracture complexity, and precisely control fracture morphology; ④ full-scale proppant support for coal rock reservoirs that “precisely matches proppant particle size with multi-level fracture widths, supports bedding-plane fractures, and provides three-dimensional support for cleat and main fractures”. Results indicate that it is necessary to further study the relationship between fracture parameters and production dynamics based on the gas storage and production characteristics of deep coal rocks, in order to identify fracture parameters that can realize the adsorbed and free gas “continuous-cooperative” supply, and to provide support for fracture property control and treating design optimization. Conduct in-depth research on hydraulic fracture network propagation rules in coal rock reservoirs and fracture propagation numerical simulation technologies, and combine the net pressure log-log diagram during fracturing to effectively control the fracture network propagation behavior in coal rock gas reservoirs. Use high-viscosity and leakage-weakening fluid first to create the main fractures, then use low-viscosity fluid to create complex fractures, achieving “controlled near-wellbore fracture complexity and sufficiently extended fractures” to form a “long fracture network”. To deal with the requirement of high conductivity and larger volume for fracture networks in deep coal rock formations, maximizing fracture volume and optimizing flow capacity with limited proppant and fluid is an effective way to reduce costs and increase efficiency. Propose the full-scale proppant-support fracturing technology for deep coal rock reservoirs to achieve long-term connectivity of “main fractures + bedding planes + cleats” and increase the effective support volume of fractures. Optimize different proppants and fiber combinations through long-term fracture conductivity tests for multi-size fractures with different proppant placement patterns. Improve existing fracturing fluid systems, explore water-reducing, high-sand-ratio, low-cost fracturing fluids, and clean desorption-promoting agents.

Fracability is a critical indicator for evaluating the exploration and development potential of coalbed methane reservoirs and assessing the effectiveness of hydraulic fracturing stimulation operations. Its core function is to characterize the complexity of the induced fracture network and the resulting effective stimulated volume. In this study, we quantified fracture area and geometric complexity using true triaxial fracturing experiments and computed tomography three-dimensional (3D) reconstruction technology, combined with the box-counting method to calculate the 3D fractal dimension of the fracture surfaces. The results revealed that the total fracture surface area per unit volume of the stimulated reservoir effectively characterized reservoir fracability; specifically, both a larger total fracture surface area and a higher fractal dimension corresponded to better reservoir fracability. Fracture complexity was enhanced by a decrease in the horizontal principal stress difference or an increase in the injection rate. Under optimal conditions of a 3 MPa stress difference and an injection rate of 60 mL/min, fracability improved by 27.6 %. Furthermore, liquid carbon dioxide (CO2) improved fracability by 50.7 % compared to using water as the fracturing fluid, a result attributed to its low viscosity and strong diffusion capacity, which activated a greater number of natural fractures. A fracability evaluation model integrating brittleness, fracture toughness, and dimensionless net pressure was developed using regression analysis, which demonstrated high reliability with a strong determination coefficient (R2) of 0.9019. This study clarifies the logical relationships among fracture area, complexity, and fractal dimension, providing a novel method for evaluating the fracability of coal reservoirs.

Multi-cluster fracturing in vertically multi-layered formations faces critical challenges due to pronounced interlayer heterogeneity and uneven flow distribution among lateral fractures, resulting in unclear regulatory mechanisms of operational parameters on hydraulic fracture propagation. In this study, based on the equilibrium height growth model and the PKN-C model, the coupled solution of fracture length and height propagation is achieved through pressure iteration. By integrating the dynamic flow distribution mechanism of the resistance method, a simultaneous propagation model for multiple fractures in multi-layered formations is established. Furthermore, regulatory mechanisms of stimulation parameters on vertical-lateral competitive fracture propagation are systematically analyzed. The results demonstrate that interlayer mechanical contrasts induce non-smooth abrupt transitions in hydraulic fracture height profiles. The uniformity of multi-cluster fractures exhibits positive correlations with cluster number and spacing, while showing a negative correlation with injection rate. Additionally, cluster number and small cluster spacing (6-8 m) predominantly regulate vertical propagation, whereas injection rate and larger cluster spacing (>= 10 m) exert stronger control over lateral propagation. The proposed workflow provides theoretical guidance for parameter optimization in multi-layered formations stimulation.

Integrated fracturing-flooding is a key technology to solve the problem of “difficult injection and difficult extraction” in tight oil and gas reservoirs. Focusing on three key physical processes in the fracturing-flooding development of tight reservoirs: fracture propagation during water injection, imbibition displacement during well soaking, and oil recovery during production, taking into account the impacts of osmotic pressure and flooding agents, and integrating continuous damage theory, a mathematical model for fracturing flooding coupling hydro-mechanical-damage (H-M-D) in tight reservoirs was established. Furthermore, numerical simulations of the integrated “fracturing-soaking-production” process were conducted to clarify the impacts of geological parameters and fracturing-flooding engineering parameters on the development effects. The study shows that when matrix permeability is low, the formation’s water absorption capacity is weak, and the rock damage degree is high, resulting in the formation of “long and narrow” fracture networks. As matrix permeability increases, the rock damage degree decreases, leading to the formation of “short and wide” fracture networks. The density of natural fractures affects the direction and distance of hydraulic fracture propagation. As the injection volume increases, the length of the fracture network increases, and the overall water absorption capacity of the fracture network improves, making it easier for the fractures to extend in the direction of stress dominance. During the soaking process, formation pressure diffuses, and under the influence of imbibition, the oil phase gradually migrates toward the fractures. Based on the research findings, an integrated “fracturing-soaking-production” stimulation engineering parameter optimization technique was developed, and an optimization chart for stimulation engineering parameters was established. Taking the fracturing-flooding case of the tight reservoirs in the upper S4 sub-member in the Dongying sag as an example, the optimized injection volume within a single layer for fracturing flooding ranges from 3×104 m3 to 3.5×104 m3, with injection rates ranging from 1000 m3/d to 1200 m3/d and a soaking duration of 20–30 days, and the development effects of the reservoirs with fracturing flooding are much better than that without fracturing flooding.

Effective staged hydraulic fracturing is essential for improving deep shale gas production while limiting interwell pressure channelling (IPC). This study evaluated how fluid system, proppant loading, and stage spacing control fracture geometry, pressure communication, and production risk in southern Sichuan shale. Core plugs from 3,500 to 3,550 m were characterised for porosity (6.2–8.7%), permeability (0.015–0.060 mD), UCS (95–120 MPa), Young’s modulus (25.4–34.6 GPa), mineralogy, and fracture toughness. High-pressure hydrofracture tests compared slickwater, gelled fluid, and hybrid fluid systems at 1.0–3.0 lbm/gal proppant loading, using AE monitoring and post-test CT reconstruction. Field diagnostics integrated production logging, tracer arrival, pressure response, and microseismic (MS) monitoring from staged horizontal-well treatments. Results showed that gelled fluid generated dense branching but lower connected fracture-volume ratio because polymer residue increased to 5.8 ± 0.9 mg/cm². Hybrid fluid produced reproducible moderate branching, the highest connected fracture-volume ratio (0.79 ± 0.04), and lower pressure communication risk. WX-01 Stage 2 showed confirmed IPC, with tracer arrival at 46 h, 410 MS events, and 286 kPa pressure differential. MC simulations identified the optimised hybrid design as the best-performing scenario, with 2.70 MMscf/d mean production, 7% frac-hit probability, and 200 ± 25 kPa pressure differential, supporting field-calibrated fracturing decisions for deep shale.

Ultra-deep fractured carbonate reservoirs suffer severe fluid loss and formation damage, requiring accurate characterization of natural fracture parameters and contamination behavior. Current field evaluation methods rely solely on logging data, which cannot obtain parameters such as the number and width of fractures. Taking the Shunbei Block as an example, this study integrates laser particle size analysis, HTHP flooding experiments, and a fracture loss model incorporating dynamic mud cake growth to clarify single-fracture loss behavior for fractures of different widths. Using fracture parameters interpreted from field logging, together with loss data and simulation results, we developed a method to determine fracture parameters and characterize contamination. Experiments reveal that effective plugging becomes difficult when fracture width exceeds 138 μm. Simulations indicate that cumulative loss volume increases with fracture width. The field loss volumes of 40–6600 m3 correspond to single-fracture widths of 0.9–6.2 mm. Based on the simulated width–loss volume relationship, correction coefficients for fracture count and width for two wells were calibrated. The method was applied to 9 wells, yielding an R2 of 0.86 between predicted and measured loss volumes. The method effectively identifies fracture parameters and assesses contamination, supporting lost circulation control in fractured carbonate reservoirs.

A drag reducer for slick-water fracturing fluids is crucial for enhancing oil and gas recovery, especially in high-salinity reservoirs where conventional polymers suffer. This study presents the synthesis and comprehensive evaluation of PAAAC, a novel hydrophobically associating polymer designed to overcome these limitations. Synthesized by copolymerizing acrylamide (AM), acrylic acid (AA), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and a long-chain alkyl quaternary ammonium salt (DMDAC-18), PAAAC leverages hydrophobic associations to form a stable, interconnected three-dimensional network. Molecular dynamics simulations reveal that PAAAC exhibits a larger radius of gyration, a smaller diffusion coefficient, and stronger hydrophobic association compared to its unmodified counterpart, PAAA. Experimentally, PAAAC demonstrates superior salt tolerance, maintaining high viscosity and excellent drag reduction rates (up to 76.59%) across diverse saline environments (NaCl, CaCl2, NaHCO3, and simulated brine), far exceeding the performance of PAAA. This resilience is attributed to the hydrophobic aggregation, which builds a robust network that effectively mitigates ion shielding effects. Furthermore, PAAAC exhibits enhanced pseudoplastic behavior, improved viscoelasticity, and notably, superior sand-carrying capacity, a critical advantage for proppant transport in hydraulic fracturing. These combined attributes make PAAAC a promising, high-performance drag reducer for improving fracturing efficiency and economic viability in challenging, high-salinity reservoir conditions, offering a sustainable solution for unconventional resource development.

Tight sandstone reservoirs are commonly stimulated by large-scale volume fracturing. Slickwater has become the dominant fracturing fluid; however, its low viscosity causes rapid proppant settling within the fracture, creating heterogeneous placement with a sandbank at the bottom and an open fluid channel above. Existing studies largely assume uniform proppant placement and homogeneous conductivity within the fracture, deviating from the actual transport behavior of slickwater and providing an inadequate understanding of the overall fracture closure shape and intrafracture fluid flow mechanism under nonuniform proppant distribution. Therefore, this study established an equilibrium height prediction model incorporating the stable dune angle of the proppant to reveal the proppant placement morphology in field-scale hydraulic fractures. Subsequently, the finite element method was used to simulate the fracture closure process and clarify the overall fracture closure geometry. A productivity model integrating the closure morphology of tight gas fractured wells was then constructed to analyze the intrafracture fluid flow mechanism. This forms a systematic research framework that links “proppant placement morphology” to “overall fracture closure shape” and finally to “well productivity.” The results show that during slickwater fracturing, proppants form a sandbank along the fracture bottom, which is divided into frontal, equilibrium height, and trailing edge areas. After closure, the fracture segments into propped, arch, and unpropped areas from bottom to top. The arch area exhibits high conductivity and lower fluid pressure, attracting fluid from the propped and unpropped areas to converge before flowing toward the fracture entrance. While occupying only 0.85% of the fracture volume, the arch area contributes 37% of the total gas flux, and the propped area contributes 52%, forming dominant flow pathways. The high conductivity of the arch area expands pressure drainage area and enhances well productivity, particularly in lower-permeability reservoirs. Based on these findings, this study proposes a novel “multiarch areas for productivity enhancement” concept, shifting from pursuing uniform proppant placement toward actively optimizing heterogeneous placement. The simulation results also show that cumulative gas production increases with arch numbers, although gains diminish gradually, suggesting that an optimal arch count exists for maximizing well production. This study provides a theoretical basis for optimizing fracture design in tight gas reservoirs and offers a new perspective for improving unconventional reservoir recovery.

Deep shale stimulation commonly involves a large temperature contrast between hot formations and cold fracturing fluid, yet its effect on hydraulic fracture (HF) interaction with cemented natural fractures (NFs) remains insufficiently quantified. This study applies a thermo-hydro-mechanical phase-field framework to isolate how cooling-induced stress redistribution affects natural fracture activation, fracture capture, reinitiation, and competitive growth. Cemented natural fractures are represented as intact weak planes with reduced fracture resistance, rather than as pre-opened fractures. Paired hydro-mechanical (HM) and thermo-hydro-mechanical (THM) simulations are performed for single NF, orthogonal multiple NFs, and oblique multiple NFs configurations after verification against thermal consolidation, fracture interaction, and ceramic quenching benchmarks. The results show that cold-fluid injection increases local tensile driving force near fracture walls and tips, enabling weak plane activation even without direct contact. In multiple NFs systems, thermal stress counteracts compressive shielding and promotes reinitiation after fracture capture. In oblique multiple NFs case, activated length increases from 205 mm in HM case to 364 mm in THM case, and normalized activated length increases from 0.315 to 0.560. These findings indicate that thermal shock substantially alter local HF-NF interaction topology in deep shale and should be considered when interpreting fracture complexity under high temperature reservoir conditions.

The success of acid stimulation in tight carbonate reservoirs relies on the formation of non-uniform etching on fracture walls. However, existing research on the influence of the fracture surface morphology on non-uniform etching and fracture conductivity predominantly employed non-replicable tensile fracture surfaces. Previous studies were unable to use identical fracture surfaces to conduct single-factor analysis and clarify the impact of roughness. This study utilized digital engraving technology to fabricate multiple artificial carbonate rock samples with a homogeneous lithology and completely consistent fracture surface morphology. Using the Triangular Prism Method (TPM), the initial fracture roughness of the rock samples was decomposed into large-scale waviness and small-scale unevenness. Through controlled injection parameters, single-factor acid etching experiments were conducted. For the first time, the effects of large-scale waviness and small-scale unevenness on acid etching were investigated, along with the influences of the acid injection rate and injection time. The existence of an optimal injection rate and an optimal injection time was clarified. The results demonstrate that the engraved carbonate samples' surfaces exhibit good consistency with the original natural fracture surfaces. The acid solution acts to shave the "peaks" and deepen the "valleys" of rough fractures. The large-scale waviness characteristics of the initial rough surfaces determine the overall post-etching morphology, leading to poor surface contact within the fracture. This is the primary reason for the high fluid flow capacity of acid-etched fractures under low closure stresses. However, the small-scale unevenness characteristics of the initial rough surfaces determine the formation and the distribution of small protruding support points on the post-etching surface. This is the primary reason for the retention of high conductivity in acid-etched fractures under high closure stresses. An increase in the acid injection rate or acid injection time does not lead to a linear decrease in linear roughness, surface mismatch, or fracture aperture. A critical acid injection rate or critical acid injection time exists. Optimizing the injection rate or time can achieve an ideal etching morphology-the protrusions formed by punctate etching enable the fractures to maintain a certain level of conductivity even under a high closure stress of 55.2 MPa, while channel etching can increase the conductivity under high closure stress by 20-25%, providing a key direction for optimizing acid etching effects.

Deep coalbed methane, as a new type of unconventional natural gas resource, has been successfully developed through massive hydraulic fracturing. However, the difficulty in desorbing bound CH4 in the nanopores is the key bottleneck restricting the recovery improvement. This study analyzes a multiscale mechanism by which surfactant-based fracturing fluids enhance methane desorption. The imbibition fundamentally dissolves the narrow necks of ink-bottle pores, transforming them into slit-shaped geometries to reconstruct the nanopore structure. This leads to a 59.6% increase in nanopore (0.3-1.5 nm) scale and a 44.8% rise in larger micropore (2-10 nm). Four types of dodecyl-based surfactant fracturing fluids can significantly achieve a wettability alteration from hydrophobic to hydrophilic, and the CMC range is between 0.15% and 0.2%. SDBS at a concentration of 0.2% can reduce the contact angle from 92.48 degrees to 42.76 degrees, driven by the rigid benzene ring, enabling strong pi-pi interactions with the coal aromatic surface. NMR analysis confirms that SDBS treatment enables the aqueous phase to progressively invade the nanopore network (T-2 < 1 ms), significantly expanding the water-adsorbed methane interface, which is directly evidenced by CH4 isotherms comparatively showing a weakened CH4-coal affinity and a 57% reduction in hysteresis area. Molecular simulation indicates that the density of the adsorbed CH4 on the coal surface decreases, while the density of free CH4 in the slit increases simultaneously, verifying the wetting-induced desorption mechanism. The diffusion coefficient of CH4 rises to 3.86 & Aring;(2)/ps (SDBS system), indicating that its transferability is significantly enhanced, facilitating efficient CH4 transport to the channel. The C-N of CH4-coal decreases from 16.2 to 12.3 (a 24% decrease), while the C-N of H2O-coal jumps from 0 to 9.6. The first peak intensity of the RDF of H2O-coal significantly increases, and the RDF of CH4-coal collapses from a double peak to a single peak. This indicates that the dense multilayer adsorbed water film rapidly forms and remains stable, competing with CH4 for adsorption sites, which significantly weakens the interaction energy between CH4 and coal, reduces the activation energy from 1500 kJ/mol to approximately 800 kJ/mol, and decomposes the single high-energy barrier desorption into multiple low-energy barriers. This research provides a solid theoretical basis for surfactants promoting CH4 desorption and improving the coal rock gas recovery.

Tight sandstone reservoirs are stimulated through slickwater fracturing. But slickwater's limited proppant-carrying capacity leads to proppant settling and heterogeneous placement. Current research lacks understanding of fracture closure morphology under non-uniform proppant placement and its impact on conductivity, causing deviations between predicted and actual production. This study combined experimental and theoretical approaches to predict proppant placement morphology and developed a finite element simulation to characterize fracture closure under different placement morphologies. A productivity model incorporating closure morphology was created to analyze the influence of proppant placement morphology and conductivity on production. Results show that a closed fracture under non-uniform proppant placement forms propped, arch, and self-propped areas. The arch's higher conductivity creates a low-pressure region that converges fluid before flowing to the wellbore, enhancing flow efficiency. Increasing proppant placement length expands high-conductivity areas, improving production. The arch reduces the impact of conductivity loss on production; replacing ceramic with quartz sand decreases conductivity by 35% but reduces cumulative production by only 2.83%. Field testing showed Well ZJ2, using quartz sand, achieved 6.6% higher production than the adjacent well using ceramic while reducing costs by 60.7%. This study established an analytical framework for proppant placement prediction, fracture closure simulation, and productivity evaluation, providing a proppant placement strategy for efficient reservoir development.

Effective propping of multi-stage fractures is challenging in shale oil and gas reservoirs stimulated by full-domain propped fracturing. This paper discusses the three-dimensional multi-level fracture propping technique, a component of the full-domain propped fracturing technology. The mechanism of proppant transport within multi-level fractures is thoroughly analyzed, and the control strategies for three-dimensional multi-level fracture propping and proper implementation paths are elaborated. Due to retardation by narrow fracture walls and severe fracturing fluid leakoff, proppant exhibits poor transport capacity and high settling velocity within shale fractures, resulting in limited longitudinal and lateral placement coverage. Additionally, proppant struggles to divert into branch fractures at fracture junctions, which ultimately reduces the effective propped volume of multi-level fractures. Adjusting pumping rate, fracturing fluid viscosity and proppant particle size can modify the intra-fracture proppant placement pattern to a certain extent, yet such measures show limited performance in improving far-fracture placement. To achieve three-dimensional multi-level fracture propping in shale, two targeted technologies are proposed. One is high-efficiency proppant placement in main fractures based on structure-driven proppant transport, which adopts proppant-fiber clusters as fundamental transport units instead of pure proppant grains to alter particle settling and packing behaviors, thereby greatly expanding the propped volume of main fractures. The other is graded propping by optimizing transport unit dimensions and improving particle entry capacity to mitigate insufficient propping in branch fractures. The full-domain propped fracturing technology has been fully or partially applied in pilot and comparative tests at nearly 300 wells in 11 oil and gas fields within China, with satisfactory results obtained. This technology is expected to be widely deployed for developing various unconventional oil and gas reservoirs in the future.

Deep coal rocks exhibit complex nonlinear rheological properties under high-stress environments, so conventional integer-order creep models cannot describe the full creep process, especially the accelerated phase. This paper introduces a novel variable-order fractal dashpot into the constitutive modeling of coal rocks. The fractal derivative is a strictly local operator that avoids the convolutional integration required by fractional derivatives, offering closed-form analytical solutions, the ability to accommodate variable-order and damage-coupled parameters without inflating computation, and concise expressions free of special functions. Defining the fractal order as a function of time and cleat-damage evolution lets the dashpot capture the progressive deterioration of the rock’s mechanical properties. Replacing the Newtonian dashpot in the classical Maxwell model with this element yields a new nonlinear creep damage model. An intelligent parameter-identification method based on Adaptive Particle Swarm Optimization (APSO) is proposed for the hard-to-invert nonlinear equation. Analytical solutions are derived and validated against cited triaxial creep data of coal rocks. The APSO-based fitting shows that the model reproduces the primary, steady-state, and highly nonlinear tertiary creep stages with physically reasonable parameters ( R^2=0.9984 ), outperforming the integer-order Nishihara model and a constant-order fractional model. A quantitative comparison further shows that the local fractal operator is roughly two orders of magnitude faster than the global fractional operator, with the gap widening as the number of evaluation points increases. The scope and limitations are discussed explicitly.

Shale gas has emerged as a strategic resource in the global energy transition. Constrained by high operational costs, shale gas development typically adopts a platform model, resulting in only a handful of exploration wells possessing complete logging data. The vast majority of development wells retain only readily accessible gas and geochemical logging data. This severe data gap significantly hinders the precise identification of geological sweet spots. Existing logging reconstruction studies primarily focus on interpolation or completion of intra-domain data, making them difficult to directly apply to multi-source heterogeneous reconstruction under severe sampling-resolution mismatch. Addressing the core challenge of significant resolution gaps and complex nonlinear mappings between gas logging, geochemical logging, and well logging data, this paper proposes a two-stage hybrid framework that couples improved fractal kriging with a Dynamic Multi-Scale Context Network (DMC-Net) for multi-source heterogeneous well-log reconstruction at mismatched depth scales. First, improved fractal kriging interpolation is employed to upsample sparse logging data, mitigating scale heterogeneity while preserving shale stratigraphic self-similarity and local variations. Subsequently, the proposed DMC-Net is introduced as a multi-scale conditional regression network that maps the upsampled multi-source inputs to the high-resolution target logs. By integrating feature selection, multi-scale convolution, and context fusion modules, the model is designed to capture both broader geological trends and finer lithological details from multi-source heterogeneous data. An additional evaluation on the independent Weiyuan block, using the same workflow after block-wise retraining, further indicates that the framework can be reproduced across independent blocks within the Longmaxi shale play. These results demonstrate the effectiveness of DMC-Net for multi-source heterogeneous well-log reconstruction in the studied platform-based shale gas development setting.