Tight conglomerate reservoirs exhibit strong pore-scale heterogeneity and extremely low permeability, in which spontaneous imbibition is primarily governed by capillary and viscoelastic effects. In this study, the imbibition dynamics of four representative fracturing fluid systems, including slickwater, 3% potassium chloride (KCl) brine, hydrolyzed polyacrylamide (HPAM) viscoelastic fluid, and a nanoemulsion (NE), were investigated using a temperature-controlled nuclear magnetic resonance (NMR) monitoring system. This approach enables real-time quantification of fluid uptake and pore-scale redistribution through time-resolved T-2 spectral analysis. The experimental results reveal a three-stage imbibition process consisting of rapid capillary-driven uptake, viscoelastic-retarded transition, and final equilibrium. Among the four fracturing fluid systems, the nanoemulsion exhibits the lowest interfacial tension (1.72 mN/m), the strongest wettability alteration, and the highest equilibrium recovery (0.76), which is nearly 80% greater than that of slickwater. Based on these observations, a multiscale capillary-viscoelastic coupling model was developed by extending the Lucas-Washburn framework to incorporate pore-size distribution, time-dependent wettability evolution, and viscoelastic damping. The model fits the experimental data well (R-2 > 0.90) and identifies viscosity as the most influential parameter controlling the imbibition rate (sensitivity = 0.78). Energy analysis further indicates that capillary energy dominates the early stage, whereas viscoelastic energy storage sustains fluid transport during the later stage. SEM observations were further used to qualitatively corroborate pore heterogeneity and pore-mineral associations, supporting the NMR-based pore-scale interpretation. This study provides a quantitative framework for describing non-Newtonian capillary flow in tight conglomerate rocks and enhances the understanding of capillary-viscoelastic interactions relevant to multiphase fluid migration.

[Objectives and Methods]Deep coalbed methane(CBM)reservoirs commonly exhibit well-developed bed-dings,strong mechanical heterogeneity,and high in-situ stress gradients.These characteristics result in pronounced non-linear fracture propagation and strong multi-field coupling effects during hydraulic fracturing.Consequently,it is chal-lenging to accurately describe the mechanisms governing fracture complexity in deep coal reservoirs using conventional mechanical models for fractures.Using a super-large true triaxial system with dimensions of 2.0 m × 2.0 m × 1.0 m,this study conducted physical simulation experiments on hydraulic fracturing under varying injection rates and viscosities of fracturing fluids.In combination with fracture mechanics and energy conservation theory,this study established an en-ergy balance equation for fracture propagation,a convection-diffusion equation for proppant transport and settling,and a model for the coupling relationships among fracture complexity and the injection rate and viscosity of fracturing fluids.Accordingly,both the dynamic mechanisms behind fracture evolution and the pattern governing the fracture network complexity were systematically elucidated.[Results]The results indicate that fracture propagation is jointly controlled by the in-situ stress field,fluid pressure field,and bedding structures,representing a unsteady energy conversion process.The fracture propagation rate exhibits a power-law relationship with the energy release rate.The injection rate of fractur-ing fluids primarily determines the energy input rate and fracture propagation velocity.A high injection rate results in energy concentration in the front of the primary fracture,promoting fracture interconnectivity while suppressing branch development.Accordingly,fracture complexity is reduced.In contrast,a low injection rate corresponds to a more uni-form energy distribution,enhancing the accumulation and lateral diffusion of energy.This facilitates multi-point initial cracking and fracture branching,increasing fracture complexity by approximately 25％-35％.Fracturing fluid viscosity significantly influences the energy transfer between fluids and solids,as well as proppant settling behavior.A high vis-cosity(45 mPa·s)is associated with a significant decrease in the proppant settling velocity.Compared to a low viscosity of 15 mPa·s,the high viscosity increases the proppant transport capacity by approximately 40％,promoting more uni-form proppant placement in far-wellbore zones and creating favorable conditions for the formation of continuous hy-draulically conductive pathways.[Conclusions]Empirical relationships derived from experiments and fitting indicate that the fracture complexity exhibits power-law coupling relationships with the injection rate and viscosity of fracturing fluids.Notably,the low-injection-rate and high-viscosity combination is more favorable for the development of 3D frac-ture networks,with a fractal dimension reaching up to 1.46.The proposed theoretical-experimental coupling framework reveals the energy transfer mechanisms governing fracture propagation and proppant transport in deep coal reservoirs,providing a quantitative theoretical basis for optimizing hydraulic fracturing parameters and predicting fracture complex-ity in deep unconventional reservoirs.

Efficient proppant transport in conglomerate reservoirs is severely constrained by rough fracture surfaces and strong geometric heterogeneity, leading to premature near-wellbore deposition and insufficient distal support. To address this challenge, this study aims to clarify the transport and deposition mechanisms of proppants in rough-wall fractures representative of the Mahu conglomerate reservoir. A large-scale visualized physical simulation system with an artificial rough fracture (20 m length & times; 4.5 m height) was developed based on dynamic similarity principles, enabling long-distance proppant transport observation under controlled pumping rate, fluid viscosity, proppant size, and sand concentration. Ten systematic experiments were conducted, and real-time particle motion and sand ridge evolution were captured using high-speed imaging and pressure monitoring. The results show that proppants form longitudinally layered sand ridges that evolve through three stages: leading-edge initiation, equilibrium-height growth, and distal extension. Viscosity and sand concentration primarily control propped-area continuity, while pumping rate governs transport distance and particle size affects structural stability. Rough fracture surfaces significantly intensify near-wellbore accumulation by enhancing energy dissipation and local flow heterogeneity. These findings provide mechanistic insights into proppant transport in rough fractures and offer quantitative guidance for optimizing fracturing parameters in conglomerate reservoirs.

A tight conglomerate is mechanically heterogeneous because gravel particles, the matrix, and their contacts can perturb hydraulic-fracture paths. This study presents an exploratory comparison of three 2.0 m × 2.0 m × 1.0 m reconstituted conglomerate specimens, identified as specimen 97 (Condition A), specimen 98 (Condition B), and specimen 99 (Condition C). One meter-scale specimen was tested under each formulation condition using the same applied boundary stresses, nominal pumping rate, and fluid viscosity. Post-fracturing surface observations, inlet-pressure histories, and laboratory acoustic-emission (AE) event locations were examined. After event-quality control, DBSCAN-based spatial filtering was performed in Z-score-standardized coordinates, and three-dimensional alpha shapes were constructed from the retained event coordinates in meters to calculate geometric AE-event-envelope volumes. The external surface-fracture traces were more spatially distributed in specimen 97 and more localized in specimen 99. The available DBSCAN–alpha-shape calculation outputs yielded geometric AE-event-envelope volumes of 0.2832, 0.2460, and 0.0937 m3 for specimens 97, 98, and 99, respectively. Because only one specimen was tested under each condition, the specimen formulations and gravel characteristics were not identical, the gravel–matrix interfacial properties were not measured directly, and the pumping histories differed, the observations were interpreted as descriptive case differences rather than as a statistically validated single-factor relationship.

Coalbed methane (CBM) is an important alternative energy source, while its efficient development relies on multistage hydraulic fracturing technology. A large amount of fracturing fluid is injected underground; however, an accurate evaluation of fracture network properties is a challenge. Meanwhile, the massive consumption of water resources and flowback efficiency has also drawn concern from the industry. In this study, we first identify the flow regimes of successive depletion of primary and secondary fractures based on flowback data from field cases, using the traditional flowing-material-balance (FMB) method. Based on this finding, a subdivided FMB model is proposed to analyze two pseudosteady-state (PSS) flows during flowback. Then, a workflow is established to extract the information on primary and secondary fractures, and its accuracy has been validated through numerical simulations conducted by a commercial simulator. Furthermore, the new approach is applied to flowback data from five multifractured wells, and the correlation analysis between the inversion results and the fracturing completion parameters is conducted. The results show that the porosity of primary fractures has no significant correlation with the amounts of proppants injected but increases with the sand-to-liquid ratio. The volume of secondary fractures is positively correlated with the total injected fluid volume. However, as the vertical depth and closure pressure increase, an obvious reduction in fracture volume is demonstrated, attributable to fracture closure. For shallow CBM, the forecasted flowback efficiency is generally higher than 67%, which is recommended to determine the appropriate treatment processes for recycling and reuse. For deep CBM, to ensure the effectiveness of proppant filling within fractures, it is advisable to increase the proportion and amounts of small-particle proppants.

Multi-stage multi-cluster hydraulic fracturing in conglomerate reservoirs is often characterized by strong cluster-to-cluster variability in fluid distribution, which can reduce stimulation efficiency. However, field-scale observations that constrain how injected fluid is partitioned among clusters remain limited, especially in strongly heterogeneous formations. In this study, wide-field electromagnetic (WFEM) monitoring was applied to a horizontal well completed in the Baikouquan Formation sandstone–conglomerate reservoir of the Mahu Sag, Junggar Basin. The monitored treatment consisted of 13 fracturing stages, each containing six perforation clusters. Time-lapse electromagnetic data acquired during pumping were inverted to reconstruct the spatiotemporal evolution of the effective conductive fluid-swept region. Based on the inversion results, we introduce a set of quantitative proxy indicators (swept area, swept length, cluster-specific sweep, and an asymmetric index) to support relative comparison of fluid distribution patterns at both stage and cluster scales. Results show pronounced non-uniformity within and between stages, even under similar pumping conditions. A limited number of clusters exhibit stronger and farther-reaching WFEM-inferred conductive-fluid responses, whereas other clusters show weaker or more localized responses. Asymmetric sweep patterns on opposite sides of the wellbore are also commonly observed. These patterns are consistent with the combined influences of reservoir heterogeneity, local structural/stress disturbances, and operational factors, although WFEM alone does not uniquely validate causal mechanisms of fracture growth. Overall, this study demonstrates that WFEM monitoring provides a field-scale proxy tool for delineating effective conductive fluid-swept regions and for evaluating cluster-to-cluster variability under consistent acquisition and inversion settings. The findings offer practical guidance for interpreting fluid distribution and optimizing multi-cluster fracturing in strongly heterogeneous unconventional reservoirs.

Rough-walled fractures in conglomerate reservoirs promote near-wellbore proppant deposition, nonuniform flow, and insufficient distal support, making proppant-schedule screening difficult using small-scale smooth-slot tests alone. This study develops a benchmark-constrained and cost-aware hierarchical screening workflow by integrating a 20 m rough-wall physical experiment, transient Fluent simulations, and archived short-time EDEM sensitivity records. The benchmark experiment used a 20 m & times; 4.5 m & times; 10 mm artificial rough-wall fracture and ten operating conditions involving pumping rate, fluid viscosity, proppant size, and sand concentration. In the Fluent model, wall roughness was treated as a regularized roughness representation, and the carrier fluids were modeled using Newtonian constant viscosities measured from laboratory calibration. The experimental effective propped area ranged from 25.5% to 65.1%. Within single-factor comparison subsets, medium viscosity improved support continuity, pumping-rate gains became limited near 0.20 m3/min, particle size affected the balance between distal coverage and bed stability, and 300 kg/m3 sand concentration caused blockage. Image-segmentation-based comparison showed that Fluent captured the main wedge-shaped deposition morphology and screening-level geometric trends. The archived EDEM records indicated that grid-resolution refinement and mixed particle-size representation substantially increased computational cost. A Case 10 mesh-sensitivity check further confirmed that mesh refinement did not alter the first-order deposition morphology. The proposed workflow uses Fluent for whole-domain rapid screening and reserves EDEM/CFD-DEM for targeted short-time sensitivity checks.

Deep-seated coalbed methane (CBM) resources in the Daniudi Gas Field of the Ordos Basin are abundant; however, conventional laboratory-scale hydraulic fracturing experiments are unable to realistically reproduce fracture propagation behavior due to pronounced reservoir heterogeneity and the complex development of bedding and cleat structures. In this study, a self-developed 10,000-ton true triaxial hydraulic fracturing simulation platform was employed to conduct mine-scale experiments using large 2 m & times; 2 m & times; 1 m No. 8 coal-rock outcrop specimens. A full-scale steel-casing wellbore and an industrial fracturing fluid system were incorporated to replicate field conditions. Experiments were performed under varying pumping rates (0.2-0.4 m(3)/min) and fracturing fluid viscosities (10-50 mPa & centerdot;s). The results indicate that post-failure fractures in deep coal formations primarily develop into complex fracture zones extending vertically from the wellbore. Their morphology is strongly governed by bedding planes and cleats, producing tortuous, banded, and mesh-like patterns. When the fracturing fluid viscosity is maintained between 18 and 27 mPa & centerdot;s, longitudinal fracture diversion along the wellbore is effectively suppressed, while the increased static pressure promotes the activation of natural fractures. Increasing the pumping rate to 0.4 m(3)/min markedly enhances the stimulated reservoir volume (SRV), with an increase of approximately 1354%, and significantly increases fracture branch density. However, higher viscosities (>27 mPa & centerdot;s), despite promoting fracture complexity, reduce proppant transport efficiency due to increased in-fracture tortuosity. This study quantitatively characterizes the coupled responses of fracture volume fraction, branch density, and fracture-surface roughness, and elucidates the interplay between displacement and viscosity in governing fracture network evolution. The findings provide an important experimental foundation for optimizing hydraulic fracturing parameters in the efficient development of deep-seated CBM reservoirs.

In carbonate reservoir stimulation, acid fracture conductivity is a paramount parameter for acid fracturing performance evaluation. Contemporary modeling paradigms exhibit limitations by concentrating primarily on simplified, geometrically ideal fractures at laboratory scales – a stark contrast to the intricate, heterogeneous fracture architectures encountered in actual field operations. More critically, the industry lacks methodologies for evaluating interconnected fracture systems’ conductive properties. In light of this, a conductivity calculation model for complex acid-etched fractures through large-scale acid fracturing experiments was developed. Utilizing 2 m × 2 m × 1 m specimens, the research first obtains acid-etched fracture geometry and zero-closure-stress conductivity data. The methodology combines 3D laser scanning for fracture morphology and triaxial compression tests for post-etching mechanical properties, providing key inputs for model development and validation. The developed model combines an acid fracture closure mechanism based on linear elastic theory with continuity equations, enabling comprehensive conductivity calculations for complex fracture systems. Based on experimental results, the ultra-large-scale acid fracture network exhibits a fracture conductivity exceeding 103 D·cm under zero closure stress, which is close to that calculated from the established model, verifying the accuracy of the model. The numerical simulation results indicate that the conductivity of complex fracture networks is significantly influenced by the characteristics of branch fractures. When the density of branch fractures is high, the connectivity between fractures improves, forming continuous flow channels that enhance overall fracture conductivity. The orientation of branch fractures, in conjunction with the dominant flow direction, also affects the conductivity of complex fracture systems. When the orientation of branch fractures aligns with the dominant flow direction, the conductivity of the complex fracture network improves significantly. Increasing the length of branch fractures not only enhances connectivity between fractures, but longer fractures also improve overall reservoir permeability by connecting a larger portion of the reservoir, thereby further enhancing the conductivity of the complex fracture network. As closure stress increases, the conductivity of branch fractures decreases rapidly, and the overall conductivity of the system becomes increasingly dominated by the primary fracture, with the contribution of branch fractures diminishing. This newly developed acid-etched conductivity model for complex fracture systems is expected to provide fundamental tools for field treatment design.

This study utilizes pioneering large-scale true triaxial experiments to investigate the hydraulic fracture propagation mechanisms in deep fault-controlled carbonate reservoirs. Synthetic specimens (2.0 m × 2.0 m × 1.0 m), featuring biomimetic fault-compartmented architectures including fault zones, cavernous zones, and disordered zones, were subjected to in-situ stress conditions and field-scale injection parameters (0.1-0.4 m3/min through TP125V casing) to transcend the limits of conventional laboratory tests. It is demonstrated through the utilization of Acoustic Emission (AE) monitoring and detailed fracture mapping that the spatial relationship between wellbore trajectory and natural fracture zones exerts fundamental control over fracture complexity and Stimulated Reservoir Volume (SRV). Oblique intersections, non-orthogonal to the maximum horizontal principal stress, have been shown to promote shear-induced branching and complex 3D networks, increasing SRV by 19.35% and shear failure proportion to 67.81%. Although diverters generate multimodal pressure responses, their efficacy remains limited by heterogeneity. Fractures continue to propagate along pre-existing weak planes, resulting in planar morphologies. Optimized well placement to activate shear slippage along natural weaknesses is critical for enhancing network complexity, necessitating integrated engineering-geological strategies for effective stimulation.

Tight conglomerate reservoirs exhibit strong heterogeneity and complex stress-rock coupling. Hydraulic fractures form tortuous paths due to gravel interactions, complicating proppant migration and placement. Traditional smooth-plate models fail to capture real fracture features. This study uses large-scale true triaxial tests to generate fractures, three-dimensional (3D) scanning for digital reconstruction, and quantitative surface characterization. A Discrete Element Method-Computational Fluid Dynamics fluid-solid coupling model analyzes the effects of gravel content, proppant combinations, injection velocity, and branch fractures on proppant behavior. Results show: (1) Gravel-induced deflection/penetration increases roughness, raising proppant coverage by 8.99% and dune height by 15.61 mm, but hinders distal transport and accelerates settling; (2) mixed-size proppant causes "bridging;" a "small-to-large" sequence reduces blockage risk; (3) increasing injection velocity from 0.1 to 0.4 m/s cuts proppant coverage by 80.5% and dune height by 19.06 mm; near-wellbore filling suffers due to turbulence despite a longer migration distance; (4) branch fractures accelerate sedimentation and elevate the main fracture dune by approximately 8.85 mm, moderate velocity increases help; (5) mixed-size proppant improves sedimentation and packing; smaller particles (>50%) effectively fill voids. The proposed 3D reconstruction and multi-factor fluid-solid model offer theoretical guidance for optimizing fracturing in conglomerate reservoirs, enhancing conductivity and field performance.

Fracturing is an effective means of improving oil recovery in reservoirs, and controllable shock wave is a new type of fracturing technology. In this paper, firstly, combining a large-scale true tri-axial fracturing simulation experimental device with a pulse type controllable shock wave fracturing rock system, pulse type repetitive controllable shock wave induced rock fracturing experiments under tri-axial stress loading conditions is conducted. Then, the complexity of crack propagation and the direction of crack propagation are analyzed. Thirdly, the oilfield application effect of oil well stimulation is analyzed. Results show that: (a) The transverse seam breaks through the boundary in the form of multiple main seams and branch seams. The cracks are intricate and intertwined, with a high degree of complexity. (b) The optimal number of pulse type controllable shock waves for wells of 9NAN242-S264, 9NAN256-240, 9NAN234-S268, 9NAN234-S274, and 9NAN202-S288 are 36, 30, 30, 30, and 36, respectively. (c) Oilfield production operations were completed for 5 oil wells, with an average daily increase of 2.7 t of liquid and 2.6 t of oil per well in the initial stage after the measures were implemented.

Understanding fracture evolution is essential for evaluating hydraulic stimulation performance. Conventional monitoring methods, such as sparse geophone arrays and piezoelectric sensors, often lack sufficient spatial resolution or temporal coverage. In this study, we demonstrate that distributed acoustic sensing (DAS) provides a robust alternative for real-time, full-cycle monitoring of hydraulic fracturing. A large-scale laboratory experiment was conducted on a 2 m x 2 m x 1 m artificial sand-conglomerate block under true triaxial stress. Embedded optical fibers recorded both high-frequency acoustic emission (AE) events and low-frequency strainrate responses. The high-frequency DAS data captured 1333 AE events correlated with pressure variations, revealing distinct rupture stages and suggesting a fluid-driven fracturing mechanism (b = 1.26). The lowfrequency responses resolved evolving three-dimensional strain-rate fields, identifying fracture propagation, polarity reversals, and delayed reactivation. Numerical simulations using a 3D displacement discontinuity method reproduced observed strain features and validated their link to fracture geometry and mechanical slip. These results highlight the potential of DAS to characterize fracture dynamics at high resolution, with implications for stimulation optimization, fracture modeling, and geohazard assessment in complex lithologies.

Temporary plugging and fracturing is an important technology for the efficient development of unconventional reservoirs. Due to the diverse physical properties of unconventional reservoirs and the complex stress environment, the evaluation of temporary plugging effect needs to consider the working conditions in the wells, and it also needs to focus on the transport and placement of temporary plugging agent in the near-well fracture region, so it is impossible to predict the effect of temporary plugging and fracturing effectively. In this paper, a numerical simulation study is carried out to investigate the transport and placement of temporary plugging agent in the near-well area, and a finite element model of “wellbore-near-well fracture” is established based on computational fluid dynamics, and numerical simulation and verification of temporary plugging and fracturing are carried out based on the fiber-optic monitoring data of temporary plugging and fracturing in Well A, as well as the optimization of some construction parameters. The results show that: as the volume concentration of temporary plugging agent increases, the temporary plugging effect is weakened and then strengthened, and the temporary plugging agent will enter into the heel cluster in advance when the concentration is small; at the initial stage, the increase in the quality of temporary plugging agent will cause some clusters to form incomplete plugging, but the quality of the plugging agent will not be changed after the quality is greater than 360kg; the temporary plugging effect is mainly reflected in the heel cluster, and the toe cluster is not obvious. This paper forms a set of temporary plugging and fracturing simulation methods based on the actual fiber-optic monitoring data in the field, which provides a reference for the optimization design of the type, particle size and dosage of temporary plugging agent during the temporary plugging construction process.

Conglomerate reservoirs exhibit pronounced heterogeneity owing to the inclusion of gravel,and the fracturing process within conglomerate formations is intricate.Due to the limitation of rock sample size and experimental conditions,the indoor fracturing physical simulation is subject to significant gravel size effect and small time scale of fracture expansion.To comprehensively capture the dynamic expansion process and depict the macroscopic morphology of the fractures post-hydraulic fracturing within actual field conditions,this study builds a set of large-size(2.0 m×2.0 m×1.0 m)true triaxial hydraulic fracturing mining experimental platform,which realizes the simulation of hydraulic fracturing of conglomerate under the real working conditions in the field by means of the 1×104 t grade stress loading device,real pipeline confluence,and fracturing pumping truck.Based on this platform,the investigation encompasses an analysis of the impact of variations in horizontal stress difference,fracturing fluid viscosities and single-hole feed rates on the dynamic expansion mechanism of fractures within conglomerate fractured cracks and the subsequent macroscopic characteristics of the fracture patterns following hydraulic fracturing.The experimental results show that conglomerate fracturing tends to form a complex multi-fracture morphology of"longitudinal fractures and transverse fractures"at the wellbore,and after gradually moving away from the wellbore,the extension advantage of transverse main fracture appears,and branching fracture is formed in the local gravel;under the condition of high level stress difference of 12 MPa,the near-well area forms a complex fracture zone of multi-fracture competition and extension advantage of transverse main fracture is weakened towards the distal end.In the presence of a high level stress difference of 12 MPa,the post-compression near-well region forms a complex fracture zone with multiple competing fractures,and the advantage of extending the main transverse fracture to the distal end is weakened.When the viscosity of the fracturing fluid is below 50 mPa·s,the expansion advantage of transverse main fractures after fracturing is significant.When the viscosity exceeds 50 mPa·s,a complex multi-fracture morphology is formed in the near-wellbore area.After the single-hole fluid injection rate exceeds 0.3 m3/min,multiple vertical fractures tend to form near the wellbore,which may lead to inter-stage pressure interference.The research findings contribute to a deeper understanding of the true morphology of fractures in conglomerate reservoirs and provide theoretical guidance for the design of hydraulic fracturing programs in conglomerate reservoirs.

限流压裂过程中,携砂液高速流经射孔孔眼会产生严重的冲蚀现象,孔眼形态发生改变,导致孔眼限流作用失效,直接影响压裂改造效果.为明确限流压裂条件下孔眼冲蚀规律,本研究设计并搭建了孔眼冲蚀大型现场实验模拟系统,孔眼流速可达到191 m/s,套管压力达到35 MPa以上,采用真实压裂材料进行模拟实验,针对压裂施工的主要参数对套管内壁孔眼冲蚀规律进行实验研究.实验结果表明:井筒内壁孔眼冲蚀分布存在明显的不均匀性,孔眼优先沿跟端侧发生形变;压裂液黏度增大有助于孔眼限流作用保持;相同工况条件下,陶粒组冲蚀速率大于石英砂组;冲蚀速率对排量较为敏感,排量增大会加速孔眼限流失效;冲蚀速率与砂比间呈非线性关系,孔眼冲蚀速率在砂比7％～16％范围内相对稳定,砂比超过16％后,孔眼冲蚀速率急剧增大,在施工过程中建议将砂比控制在16％以下,可减缓孔眼冲蚀导致的孔眼形变.

In order to solve problems with conventional in-house fracturing fluid friction test device, such as small size, low pipe flow velocity, and large difference from the real flow situation on site, we use a large-scale field experimental simulation method and the fracturing pump truck as the power source to realize the friction resistance test of fracturing fluid under ultra-high-speed flow, and test a total of 16 groups of fracturing fluid samples. The results show that the friction properties of fracturing fluids prepared with different kinds of polymers are obviously different. The drag reduction rate of low-viscosity fracturing fluid and medium viscosity fracturing fluid show 4 kinds of trend with the increase of flow rate: decreasing linearly, increasing linearly, increasing first and then decreasing, and decreasing first and then increasing. The experimental device adopts a pipeline system with multiple pipe diameters and lengths, and the experimental flow rate can reach up to 100 m/s. It is currently the highest flow rate fracturing fluid flow testing experimental device known in China, which can meet the experimental requirements of future on-site large displacement construction. The experimental results have important guiding significance for the field application of fracturing fluid.

Staged multi-cluster fracturing of horizontal wells is one of the most important tools to achieve efficient development of unconventional oil and gas reservoirs. The multi-stage fracturing technique forms complex fractures with multiple clusters and branches in the formation, causing competing diversions leading to more complex proppant transport patterns, and the proppant placement method determines the flow conductivity of complex fractures, so it is necessary to investigate the proppant transport patterns in complex fractures. To address this issue, a field-scale geometric model is established for numerical simulation, and the multiphase flow diversion pattern in the wellbore, the proppant distribution pattern under different network conditions, and the optimization of different construction parameters are investigated. The results are obtained as follows: the distribution of solid and liquid phases in each cluster of the well conforms to the trend of variable mass flow; the proppant is distributed at the heel end in multiple clusters of fractures, and the sand and liquid are unevenly distributed among clusters of fractures, and the number of branching affects the proppant transport; through sensitivity analysis of the influencing factors, the pumping displacement, fracturing fluid viscosity and proppant particle size are optimized, and the construction parameters of 14 m3/min, 5 mPa·s, 70/140 mesh, 12% sand ratio are determined. This study has a certain guiding significance for the optimization of fracturing parameters in this block.

The temporary plugging and diverting fracturing (TPDF) technique is important for improving the production capacity of hot dry rock (HDR) reservoirs. The key to this technique is to form effective plugged layers in existing fractures. However, HDR reservoirs have a high temperature, high pressure, and tight rocks. Accordingly, temporary plugging agents (TPAs) deliver different plugging performances for HDR fractures and conventional tight reservoirs. To investigate the plugging mechanisms of TPAs for rough fractures in HDRs, this study first reconstructed the physical models of rough fractures in HDRs using the computed tomography (CT) and 3D printing techniques. Second, it proposed a computational method of fracture surface roughness based on the joint roughness coefficient (JRC) theory. Using this method, the surface roughness of the physical models was calculated and then compared with the rock roughness spectra recommended by the International Society for Rock Mechanics and Rock Engineering (ISRM). Third, with the aid of the temporary plugging characteristic experimental system, this study designed and conducted temporary plugging characteristic experiments on rough fractures in HDRs under a high temperature. Last, this study analyzed the influences of different factors, including fracture surface roughness and the particle concentration and type of TPAs, on the fracture plugging efficiency under a high temperature. The results of this study are as follows: Under the same conditions, the temporary plugging efficiency for fractures in HDRs increased by 67.6% when the fracture surface roughness increased by 10.44; the amount of the required TPA mixture increased by 82.5% when the temperature doubled in value, and the optimal particle concentration of TPAs was 1.5% in this experiment. These results can be used as a reference for the hydraulic fracturing of HDRs.

As an important energy replacement block in China, the tight conglomerate oilfields in the Mahu area are difficult to develop and are characterized by strong heterogeneity, large horizontal stress differences, and undeveloped natural fractures. However, new development processes including temporary blocking diversion and large section-multiple clusters have been implemented on the oilfields in the past few years. In 2020, two adjacent horizontal wells in the MD well area experienced a poor fracturing development effect compared with the earlier wells in this area. Analysis suggests that the main reasons are water sensitivity of the reservoir, insufficient fracturing scale, and/or interference from the adjacent old wells. To ameliorate the problem, this study presents an experimental study of multiple temporary plugging and refracturing technology in long horizontal well sections, in combination with electromagnetic and microseismic monitoring. Results from the study show a great difference between the two monitoring techniques, which is attributed to their different detection principles. Interestingly, the combination of the two approaches provides a greater performance than either approach alone. As the fracturing fluid flow diversion is based on temporary plugging diversion and electromagnetic monitoring of fracturing fluid is advantageous in temporary plugging diversion monitoring, both approaches require further research and development to address complex situations such as multiple temporary plugging and refracturing in long intervals of adjacent older wells.