The development characteristics of microfractures in shale reservoirs directly control hydrocarbon seepage capacity and the effectiveness of hydraulic fracturing stimulation,and thus constitute a key geological factor for the economical and efficient development of shale oil and gas.However,microfracture systems are characterized by large-scale spans,strong spatial heterogeneity and low identification accuracy,so their precise characterization and prediction have long remained core challenges in shale oil and gas geology.In response to the problem,this study systematically reviews the current status of microfracture characterization methods,including field outcrop observation,core and cast thin-section analysis,well-log identification,gas adsorption and high-pressure mercury intrusion,and electron microscopy.It also summarizes the theoretical progress in fracture prediction methods,such as equivalent continuum models,discrete fracture network models and hybrid models,and discusses development trends in shale microfracture characterization technology.The study shows that the integration of multiple techniques and coordinated multiscale characterization is an effective way to improve the recognition accuracy of shale microfractures.In the future,a continuous and complete pore-fracture evaluation system should be established,and the combinations of fracturing fluids and proppants should be optimized so as to achieve effective support and full-scale prediction from microscopic fractures to macroscopic fracture networks,thereby promoting the intelligent and precise development of shale oil and gas exploration and exploitation.This study provides a theoretical reference for microfracture characterization and hydraulic fracturing stimulation of shale reservoirs.

Deep and ultra-deep wells are highly prone to drilling-fluid loss because of geological,engineering,environmental,and human factors,which can seriously endanger drilling operations.However,current research achievements on lost-circulation control in deep and ultra-deep wells are relatively scattered and lack systematic synthesis.Through a literature review,this paper analyzes the causes of drilling-fluid loss in deep and ultra-deep wells,summarizes progress in lost-circulation control technologies and in different categories of plugging materials,and discusses existing problems and future development directions.The study indicates that significant improvement in lost-circulation control for deep and ultra-deep wells can be achieved by organically integrating geology,engineering,materials,and intelligent plugging technologies;improving the formulations and the temperature resistance,salt resistance,and pressure-bearing capacity of plugging materials.Besides,the following measures can also help,such as optimizing process parameters such as injection mode,injection pressure,and injection volumefully considering the coupled flow among the wellbore,loss zone,and formation,comprehensively utilizing reservoir plugging and plug-removal technologies,and applying artificial intelligence to perform deep learning on previous lost-circulation cases and to make intelligent decisions for plugging programs in new wells.This study provides a reference and guidance for the application of lost-circulation control technologies in deep and ultra-deep wells.

In view of the large number of low-production wells and the widespread occurrence of water production in the Qingjian area,constant-rate mercury injection and gas-water relative permeability experiments were carried out to investigate the petrophysical properties and pore characteristics of tight sandstone gas reservoirs in the He 8 and Shan 2 members in the study area.The study clarified the controlling effects of key parameters,including pore size,distribution,throat morphology,and connectivity,on natural gas flow capacity.The results show that the reservoirs in the study area are characterized overall by low porosity and low permeability.Among them,samples from the Shan 2₃ Submember with permeability greater than 1.00 mD occur at a higher frequency than those from the He 8 Member,and their rock type,interstitial materials and pore-throat structure are all superior to those of the He 8 Member.The study confirms that porosity is the decisive factor governing hydrocarbon enrichment,whereas the structural matching between pores and throats directly determines reservoir flow capacity.At the same time,reservoir tightness is positively correlated with bound water saturation,which directly weakens natural gas flow capacity.This study provides an important technical basis for the evaluation and development of regional tight sandstone gas reservoirs.

Shale gas reservoirs in the Longmaxi Formation of the Weiyuan Area show significant single-well productivity differences,and the main controlling factors affecting gas content remain unclear,constraining effective exploration and development of shale gas in this area.Therefore,organic-riched shale reservoirs of the Long 1-1 submember in the Longmaxi Formation of the Weiyuan Area were investigated.By integrating X-ray diffraction(XRD) mineral analysis,organic geochemical tests,SEM observations,and rock petrophysical tests,the basic characteristics of shale gas reservoirs were systematically analyzed,and their controlling effects on gas content were discussed.The results show that shale reservoirs of the Long 1-1 submember have relatively high quartz content,total organic carbon(TOC) content and thermal maturity.The storage space is dominated by organic-matter pores,and both porosity and gas content are relatively high,indicating good resource potential.Shale gas-bearing properties are jointly controlled by material basis,storage space and preservation conditions.High TOC content,large effective reservoir thickness,high brittle-mineral content and a well-developed pore system provide favorable conditions for shale gas generation and storage,whereas strong sealing capacity of roof and floor and a high formation pressure coefficient are key to shale gas enrichment and preservation.Hydrocarbon expulsion in the study area is relatively weak,leading to high present-day residual gas content;moreover,shale gas wells in synclinal structural zones generally have higher production than those in anticlinal structural zones.The results provide a geological basis for favorable area selection and efficient development of shale gas reservoirs in the Longmaxi Formation.

The Jurassic Lianggaoshan Formation in the northeastern Sichuan Basin contains considerable shale oil and gas resources.In recent years,several zones in the basin have yielded high-production oil and gas wells,demonstrating favorable exploration prospects.However,reserve growth and production enhancement remain challenging because of the complex lithofacies of fine-grained sedimentary rocks,relatively low organic matter abundance,and complex pore structures.Based on geochemical data,petrographic-mineralogical analyses,and multi-scale pore characterization results,this study examined the microscopic pore structure of shale in the first member of the Lianggaoshan Formation and discusses the genesis of favorable reservoirs.The results show that six lithofacies types are mainly developed in the first member,including felsic,mixed and clay-rich shales under both low-organic-matter and high-organic-matter conditions(hereinafter referred to as low- organic matter and high-organic matter).Among them,high-organic-matter felsic shale and high-organic-matter clay-rich shale exhibit relatively high proportions of macropores and thus favorable reservoir properties.Lithofacies with higher content of brittle minerals have stronger resistance to compaction,which is conducive to the preservation of primary pores and to higher proportions of mesopores to macropores.Organic matter exerts a dual effect on the development of favorable reservoirs:an appropriate organic matter content promotes pore development,whereas excessively high organic matter content fills pore space,thereby weakening rock compaction resistance and hindering the preservation of mesopores to macropores.Through analysis of the favorable lithofacies and the main controlling factors of pore structure in lacustrine shale reservoirs,it is concluded that the shale reservoir of the Lianggaoshan Formation in the northeastern Sichuan Basin is governed by a dual-threshold control model,and that an organic-matter-mineral composite pore system is critical to the formation of favorable shale reservoirs.This study provides support for sweet-spot prediction and subsequent exploration deployment of shallow lacustrine shale oil and gas in the northeastern Sichuan Basin.

Helium is a scarce strategic resource,and it is imperative to advance helium resource exploration and related technological research.The Weihe Basin is well endowed with helium resources,but its overall exploration level remains low.The lack of mature identification techniques and evaluation criteria for helium-bearing strata has constrained the large-scale exploration and development of helium resources.To slove this problem,and in combination with the conditions for helium accumulation and helium-content detection methods,this study established a set of identification techniques and evaluation criteria for helium-bearing strata based on the latest exploration results from the southern slope of the Gushi Sag in the Weihe Basin.The results show that helium reservoirs strictly follow the three core elements of “generation-migration-accumulation”,which control the entire process of helium generation,migration,and accumulation.By integrating while-drilling helium detection,conventional mud logging procedures for oil and gas wells,and well-log interpretation and evaluation,a technical standard system for identifying helium-bearing strata was established.The key parameter indicators were defined as helium content of 0.050‰-0.100‰,total hydrocarbon content of 2%-3%,P-/S-wave velocity ratio of 1.6-1.8,gas saturation of 20%-30%,acoustic travel time of 330-380 μs/m,bulk density of 2.2-2.4 g/cm³,and lithologies including siltstone,sandstone,and mudstone.Through field application,multiple Class Ⅰ,Class Ⅱ,and Class Ⅲ helium-bearing reservoirs were delineated in several exploration wells on the southern slope of the Gushi Sag.The establishment and application of the helium-bearing strata identification technology further demonstrate the local occurrence of helium reservoirs on the southern slope of the Gushi Sag,and provide useful guidance for the future direction of helium resource exploration and development in the Weihe Basin.

Accurate production prediction remains difficult for hydraulically fractured horizontal wells in mud shale oil reservoirs because numerous geological and engineering factors jointly affect well performance.To solve this problem,a big-data preprocessing method for shale oil production prediction was proposed by combining retrieval-augmented generation(RAG) technology with the DeepSeek large language model,increasing data collection efficiency by six times.A RIME-XGBoost model suitable for production prediction in mud shale reservoirs was constructed to achieve intelligent prediction of cumulative oil production from hydraulically fractured horizontal wells,and SHAP-based interpretability analysis was used to identify the key factors controlling production.The results show that the main controlling factors of mud shale oil production are vitrinite reflectance (R_o),compensated neutron,proppant intensity,sand-fluid ratio,logging-derived effective porosity,maximum horizontal principal stress,and total hydrocarbon from gas logging.The RIME-XGBoost model yields a coefficient of determination(R²) of 0.936 and a prediction accuracy of 91.04%,demonstrating both high accuracy and strong interpretability.This study effectively addresses problems such as low efficiency in data preprocessing and poor model interpretability in traditional production prediction,and provides a data-driven solution for accurate productivity prediction and fracturing parameter optimization in mud shale oil development,which is of great significance for the efficient development of mud shale oil.

After more than 20 years of high-rate and high-efficiency steam-injection development,the heavy oil reservoir in the Keqian 10 well Area of the Junggar Basin has entered the“dual-high”stage and become a“dual-negative”reservoir,resulting in the shutdown of oil wells over a large area.To investigate the potential for resuming production in this well area,the characteristics of microbial communities under steam-flooding conditions were studied through experimental evaluation,reservoir engineering analysis and numerical simulation,and a microbial enhanced oil recovery system was established.The results show that the steam-unswept zone in the Keqian 10 well Area is rich in functional microorganisms for oil recovery,providing a basis for the activation and utilization of indigenous microorganisms.The microbial enhanced oil recovery system is indigenous microorganisms+Strain 6-2+an activator.The field test was conducted using an inverted five-spot well pattern,achieving a cumulative oil production of 8 750 t;basic operating costs decreased from RMB 2 057/t under steam flooding to RMB 577/t.This study provides a reference for improving the quality and efficiency of shallow heavy oil development,enhancing oil recovery,and establishing replacement technologies for green and low-carbon development of heavy oil.

Chang 7 shale oil in Ordos Basin is characterized by high initial output,rapid decline and low depletion development recovery efficiency,thus requiring urgent and effective enhanced oil recovery(EOR) methods.Based on core analysis results from high-pressure mercury intrusion(HPMI),scanning electron microscopy(SEM),casting thin sections(CTS),and low-field nuclear magnetic resonance(NMR),the pore structure of the target reservoir was classified and evaluated.Experiments were then carried out on oil displacement by fracturing fluid imbibition,fracturing fluid+surfactant imbibition displacement,and CO₂ huff-and-puff displacement,to investigate the crude oil production characteristics in different pore size ranges and the EOR effectiveness of the three patterns.An EOR method integrating fracturing and displacement was proposed to improve shale oil recovery.The experimental results show that the pore structure of the target shale reservoir can be classified into types I-Ⅲ,with reservoir physical properties deteriorating sequentially from I to Ⅲ.Among the three oil displacement patterns,CO₂ huff-and-puff achieves the highest recovery efficiency,followed by fracturing fluid+surfactant imbibition,and fracturing fluid imbibition the lowest.For a given pattern,type I shale yields the highest recovery,with types Ⅱ and Ⅲ decreasing in turn.For type I shale,ordinary slickwater can be used as the fracturing fluid;for type Ⅱ,adding a surfactant to the fracturing fluid is recommended;for type Ⅲ,CO₂ can be used as a pre-slug in the fracturing fluid.Compared with ordinary slickwater,adding an anionic surfactant(LAS) to the fracturing fluid increases the average daily oil output per well by 2.4 times.The research results can provide reference for improving shale reservoir development efficiency.

A set of mixed shale oil reservoirs deposited in a littoral-shallow lacustrine environment is developed in the fourth member of the Shahejie Formation in the Leijia Area of the Liaohe region.The rocks are lithologically diverse with well-developed laminae and natural fractures,leading to complex and variable hydraulic fracture geometries.To reveal the effects of laminae and natural fractures on hydraulic fracture propagation in shale oil reservoirs,based on typical geological and mechanical parameters of shale oil in the Leijia Area,this study combined the continuous-discontinuous element method(CDEM) and the finite volume method(FVM) to establish a numerical simulation model coupling block deformation,fracture failure and fracture flow.Three representative geological models,namely,laminae-dominated,natural-fracture-dominated and interlayer-dominated,were constructed.Under a fixed injected-fluid volume,the effects of injection rate and fracturing-fluid viscosity on hydraulic fracture propagation in these three geological models were investigated.The results show that increasing injection rate can significantly enhance the maximum aperture of the main fracture,and increasing viscosity also helps enlarge fracture aperture.In natural-fracture systems,medium-to-low injection rates or low-viscosity conditions more readily promote fracture propagation along natural fractures,whereas under high injection rates and high viscosity the main fracture is more likely to cross natural fractures and alter branch connectivity patterns.In interlayer systems,increasing injection rate and viscosity helps reduce differences in fracture aperture between layers and improve the average aperture of the main fracture.The results can provide technical support for hydraulic fracture geometry design and pumping-parameter optimization in similar shale oil reservoirs.

During the proppant injection stage of hydraulic fracturing,fractures remain in a state of continuous propagation.To investigate the influence of fracture propagation on proppant placement,on the basis of previous studies,this paper used a physical simulation apparatus for proppant transport with dynamically variable fracture width.Using a single-factor analytical method,proppant transport simulation experiments were conducted under different branch-fracture opening times,different injection rates,different sand ratios,different fracturing-fluid viscosities and were compared with experiments conducted under fixed fracture conditions.The results show that fracture propagation exerts a significant influence on proppant placement.Compared with the results of fixed-fracture-width experiments,the horizontal decline rate of the equilibrium proppant-bank height reached 24.68%,and the increase rate of the distance to the leading edge of the proppant bank reached 45.09%.This difference decreased with increasing injection rate,sand ratio and viscosity.During the sand-adding stage of fracturing,targeted filling of branch fractures with proppant is conducive to improving proppant placement within fractures.During the early stage of proppant injection,pumping with a high injection rate,low sand ratio and high viscosity is favorable,whereas during the later stage,pumping with a high injection rate,high sand ratio and low viscosity is favorable.Alternating pumping is conducive to efficient proppant placement.This study reveals the influence law of dynamic fracture propagation on proppant placement and provides a theoretical basis for optimizing fracturing parameters and achieving efficient proppant placement.

To accurately predict the locations of casing deformation in hydraulically fractured horizontal shale wells,this study took deep shale oil wells in the Huazhuang area of the Gaoyou Sag,Subei Basin,as the research target.Based on microseismic inversion data,a coupled finite element model of the fractured zone,casing-cement sheath,and casing was established.Combined with shale hydration experiments and mechanical parameter tests,the geostress field and casing deformation characteristics during hydraulic fracturing were quantitatively analyzed,and a prediction method for casing deformation locations in hydraulically fractured horizontal shale wells considering hydration effects was established.The results show that,under hydration,the deep shale of the second member of the Funing Formation in the Huazhuang Area exhibits a marked decrease in rock stiffness and an obvious swelling effect,thereby disturbing the geostress field.During hydraulic fracturing,the geostress within the fractured zone increases significantly and destroys the original geostress equilibrium.Particularly in asymmetrical fractured zones,the shear action of the geostress field causes pronounced axial S-shaped deformation and radial ovalization of the casing,with ovalization being the principal failure mechanism.Compared with actual field casing deformation,the simulated deformation locations are consistent with the observed casing failure locations.Based on the analysis,a series of preventive and optimization measures are proposed.The study has important engineering significance for the efficient development of shale oil and gas reservoirs.

After large-scale fracturing of shale oil horizontal wells,unreasonable shut-in and flowback-production regimes may cause sand production,wellbore blockage and other problems,thereby seriously affecting development performance.To solve this problem,a study was conducted on optimizing shut-in time and flowback-production regimes after large-scale fracturing of shale oil horizontal wells with the aim of determining the shut-in time and appropriate production regime under the current fracturing-fluid system.The results show that reservoir wettability experiments,spontaneous imbibition experiments,pressurized imbibition experiments,matrix damage experiments and fracturing-fluid flowback experiments were carried out to determine the imbibition time of reservoir cores,imbibition recovery factor,degree of reservoir damage and flowback rate of fracturing fluid,based on which the shut-in time was preliminarily determined to be 20-28 d.A shale oil horizontal well model considering imbibition was then established to simulate the velocity field,pressure field,pressure-gradient field and production performance at different times during imbibition,based on which the shut-in time was preliminarily determined to be 25-30 d.By integrating laboratory experiments,numerical simulation and production practice,the reasonable shut-in time was ultimately determined to be 20-40 d or until the daily pressure decline remained below 0.1 MPa for 7 consecutive days.By establishing a proppant flowback model and a fracturing-fluid velocity calculation model,the relationships among nozzle size,maximum flowback rate and different pressures were investigated,the nozzle size and flowback rate under different pressures were clarified,thereby establishing a reasonable flowback-production regime after fracturing.The research results were applied to the N4-2H Well area,and the initial daily oil production increased by more than 9%.These findings are of great significance for improving the initial productivity and development performance of shale oil horizontal wells in the Ordos Basin,and can also provide guidance for establishing production regimes in similar reservoirs.

In the middle and late stages of development of the Moxi Gas Field in central Sichuan,there is an urgent need for gas wells to restore and enhance production,and consequently an evaluation method for the effectiveness of gas production engineering measures is required.To solve this problem,an evaluation method for gas production engineering measures in the Moxi Gas Field was established,enabling comprehensive quantitative evaluation of the implementation effect of such measures.This method selects the increase in maximum wellhead deliverability,the proportion of cumulative incremental gas production,the proportion of cumulative incremental water production,and the effective period of the engineering measure before and after implementation as quantitative evaluation indices,and determines the weight of each index.The fuzzy analytic hierarchy process was used to integrate multiple categories of evaluation indices into a comprehensive evaluation index for gas production engineering measures.A higher value of the comprehensive index indicates a better implementation effect of the corresponding gas production technology.The proposed method was applied to 60 producing wells in the Moxi Gas Field,and practical evaluation of the effectiveness of gas production engineering measures was completed.The results show that the overall effect of gas production engineering measures is relatively good for wells in the central part of the Moxi Gas Field,whereas the effect is moderate for some wells on the eastern and western flanks.The overall effect is relatively poor in low-productivity wells but comparatively good in high-productivity wells.The growth ratio of maximum wellhead deliverability before and after implementation is positively correlated with the comprehensive engineering index I,and gas wells with an effective period longer than 50 d exhibit better engineering performance.This work provides important theoretical reference and practical guidance for improving the evaluation system of gas production engineering measures for gas wells and for supporting efficient development and sustainable stable production of gas fields.

Deep shale gas reservoirs are characterized by great burial depth,complex flow mechanisms,and multi-physical-field coupling.Incomplete understanding of fracture propagation and seepage mechanisms has constrained the accuracy of productivity evaluation for such reservoirs.To solve this problem,based on the concept of geology-engineering integration and relying on the Mangrove software platform,this study incorporated field data on drilling,logging,natural fractures,geomechanics,and treatment parameters,together with an unconventional fracture model,to establish a hydraulic fracturing model for the Zu 201 Well area in western Chongqing.The model was validated by microseismic monitoring,and the effects of single-well fracturing treatment parameters on fracture propagation geometry and fracture parameters were investigated.The results show that fracture propagation exhibits dynamic characteristics of vertical layer crossing and lateral extension.Numerical simulation results are consistent with microseismic monitoring data,with an error of only 8.1%.For the typical Well YX2 in the Zu 201 Well Area,the optimal fluid intensity is 40 m³/m;excessive fluid intensity leads to interfracture interference.The optimal fracturing-fluid injection rate is 21 m³/min.The optimal proppant intensity is 4.0 t/m;an excessively high proppant intensity is prone to causing local sand plugging and restricting the extension of some fractures.The stimulated reservoir volume under the optimized scheme is 2 585.44×10⁴ m³,which is 4% higher than that under the original scheme (2 475.40×10⁴ m³).Following the geology-engineering integrated approach,this study validates the fracture propagation model for deep shale gas fracturing through microseismic monitoring and clarifies the propagation pattern of fractures and the influence mechanisms of key treatment parameters,thus providing guidance for hydraulic fracturing stimulation of deep shale gas reservoirs.

Pipeline corrosion is a critical safety hazard in oil and gas transportation systems.This is especially the case when multiple corrosive factors such as CO₂,H₂S,and Cl^- coexist,under which corrosion behavior becomes highly nonlinear and difficult to predict,posing challenges to traditional prediction methods based on experimental data or single-factor modeling.To address the limitations of existing prediction methods in terms of generalization ability,interpretability of key factors and real-time responsiveness,120 groups of high-frequency corrosion-monitoring data acquired by a field multisource sensing system integrating electrochemical,environmental,and compositional measurements were used.Spearman-Kendall correlation analysis,partial dependence plot(PDP) visualization,and an L_GL_1/2-regularized extreme learning machine(LF-ELM) were employed to establish a method for corrosion prediction and key-factor identification.The results show that inlet temperature has the most significant effect on corrosion rate,with a Spearman correlation coefficient of ρ=0.79,whereas CO₂ and H₂S exhibit threshold effects at concentrations of 33 mg/L and 5 682 mg/L respectively.In full-sample testing,the proposed method reduces the average absolute error (E_MAE) to 0.001 15 mm/a with R² reaching 0.864 5 and the number of redundant nodes reduced by 63%.In future time-series testing,it still maintains high stability,with E_MAE=0.001 28 mm/a.The model not only achieves high-accuracy prediction,but also has good engineering practicability,thus providing a theoretical basis and an intelligent tool for corrosion-risk management of oil and gas pipelines.

Large-scale volumetric fracturing can generate complex fracture networks,leading to extensive redistribution of the in-situ stress field.Variations in the in-situ stress field may alter casing loads and induce casing deformation and failure.To solve this problem,a method was proposed to invert hydraulic fracture networks on the basis of microseismic monitoring data and thereby investigate casing damage.This method can characterize both the stimulated reservoir volume and the degree of rock fragmentation during fracturing.The traction-separation law of cohesive elements was adopted to describe the damage evolution of fractured zones.With the multistage volumetric fracturing of Well GS-HF as a case study,a finite element model describing the interaction among casing,cement sheath and formation was established and staged fracturing simulations were performed.The results show that the simulated casing deformation locations are generally consistent with field observations.During multistage volumetric fracturing,the original formation volume is fragmented,causing the fractured zones to“temporarily”lose confinement from the in-situ stress field and thus forming stress reversal regions,namely stress deficit zones.The asymmetric stimulated reservoir volume causes the in-situ stress field to exert lateral shear forces on both the casing and formation rock,resulting in a certain degree of radial or axial casing deformation.By progressively simulating the staged fracturing process with a finite element model and analyzing its effect on casing failure,this method can accurately identify high-risk zones of casing deformation,and thus provide a basis for timely adjustment of fracturing schemes and optimization of well pattern deployment in the field.

In response to the insufficient understanding of multi-scale fluid flow behavior under fluid-solid coupling in shale reservoirs,stress sensitivity experiments and Biot coefficient measurements were employed to study the inherent characteristics of shale matrix and fractures and their sensitivity to stress respectively.The interactions between micro-scale seepage and macro-scale effective stress were analyzed.Based on the effective stress principle,mathematical models were established for shale reservoir matrix-fracture porosity and permeability under effective stress,and the impacts of various fluid-solid coupling parameters on multi-scale flow in shale reservoirs were analyzed.The results show that the average stress sensitivity coefficients of the matrix and fractures are 0.220 and 0.081 respectively,indicating the matrix is more stress-sensitive than fractures.The average Biot coefficients of the matrix and fractures are 0.310 and 0.710 respectively,indicating the matrix's Biot coefficient is smaller than that of the fractures,thus pore pressure in fracture-developed reservoirs has a non-negligible impact on reservoir productivity.The smaller the normal stiffness,elastic modulus,Poisson's ratio,and initial porosity,the larger the Biot coefficient,and the stronger the fluid-solid coupling interaction between the matrix and fracture network,resulting in more obvious permeability reduction.Gas desorption-induced expansion causes deformation of shale matrix grains,enhancing fluid-solid coupling in the matrix.In proppant-filled fractures,larger proppant size and more layers of sand increase the normal stiffness of fractures,thereby improving fracture flow conductivity and weakening fluid-solid coupling effects.The proposed seepage model more comprehensively considers the influence of fluid-solid coupling mechanical parameters and can more accurately analyze the impact of fluid-solid coupling on multi-scale seepage behavior in shale,greatly simplifying calculations and improving computation speed.The findings provide a theoretical basis for the effective development of shale reservoirs.

Fracture network conductivity is one of the key factors for achieving efficient shale gas development,yet its influencing factors and evolution patterns remain unclear.To evaluate the conductivity of fracture networks with different structures,a proppant conductivity evaluation device was used to determine the variation patterns of fracture network conductivity under different numbers of branch fractures,different included angles between branch fractures,and different propping types.On this basis,and following the hydraulic-electric analogy principle,a prediction method for fracture network conductivity was established.The results show that the greater the number of branch fractures and the smaller the included angle between branch fractures and the main fracture,the higher the fracture network conductivity.Under low closure pressure,the conductivity of self-propped fracture networks is greater than that of propped fracture networks,whereas under high closure pressure,propped fracture networks are significantly superior to self-propped fracture networks in conductivity.Based on the established prediction model for fracture network conductivity,the calculated values agree well with the experimental values,with an overall root-mean-square error of 10.22%.These results can provide theoretical guidance for the formation of complex fracture networks with high conductivity during volume fracturing of shale gas reservoirs.