Proppant diversion in branched fractures is a confined particle-laden flow process that governs effective support in complex fracture networks; however, the particle-scale mechanisms controlling diversion across branch geometries remain insufficiently understood. In this study, coupled computational fluid dynamics-discrete element method simulations were performed to investigate proppant diversion from a primary fracture (PF) into vertical and horizontal secondary fractures (SFs). The diversion process was quantified using sand-dune geometry, particle trajectories, velocity responses, and statistical comparisons between captured and bypassed particles. The results reveal a junction-scale capture-bypass mechanism in which diversion is controlled by the competition between branch-directed drag induced by flow deflection and the streamwise inertial persistence of particles approaching the junction. In the vertical SF, diversion evolves from a drag-gravity-coupled regime to a shear-enhanced, drag-dominated regime. By contrast, diversion into the horizontal SF is mainly drag-driven; gravity promotes particle settling in the PF but contributes little to lateral entry. Within the investigated ranges, the proppant diversion ratio increases with injection velocity, decreases with proppant concentration and proppant size, and varies non-monotonically with fluid viscosity. Parametric response identifies injection velocity and proppant concentration as the primary controls on diversion, whereas fluid viscosity and proppant size play secondary roles. These findings clarify the mechanisms governing capture and bypass in confined particle-laden branching flows and provide a physical basis for interpreting proppant partitioning in complex fracture networks.

Natural weak discontinuities, such as natural fractures, bedding planes, and coal-rock interfaces, are widely developed in deep coal reservoirs. During hydraulic fracture propagation, induced fractures readily interact with these weak planes through crossing, deflection, and combined activation, thereby forming complex fracture geometries and significantly affecting proppant transport and placement. To clarify the transport behavior of proppant under different fracture geometries, four representative tortuous wedge-shaped fractures were constructed to characterize typical fracture propagation patterns in deep coal reservoirs, namely a vertical straight fracture ("|"), a horizontal straight fracture ("-"), a T-shaped fracture, and a cross-shaped fracture ("+"). On this basis, a two-way coupled fluid-particle model was established using the CFD-DEM method to systematically investigate proppant migration, settling, and placement in different fractures, as well as the effects of injection velocity, particle size, and fluid viscosity. The results show that fracture geometry exerts a significant influence on proppant transport patterns and placement performance. Specifically, proppant transport in the "|"-shaped, T-shaped, and "+"-shaped fractures can be divided into three distinct stages: rapid start-up, stratified transport, and front advancement. In contrast, particles in the "-"-shaped fracture are only weakly affected by gravity and remain almost entirely in an orderly front-advancement regime, exhibiting the most stable and continuous placement behavior. Increasing injection velocity and fluid viscosity both improve proppant placement uniformity and markedly promote branch entry in the T-shaped fracture, whereas their improvement in the "+"-shaped fracture is relatively limited. When the fluid viscosity increases from 1 mPa & centerdot;s to 5 mPa & centerdot;s, the placement uniformity coefficient (PUC) of the "-"-shaped, "|"-shaped, T-shaped, and "+"-shaped fractures increases by approximately 3.2%, 5.6%, 6.3%, and 7.1%, respectively. These findings provide mechanistic insight into geometry-dependent proppant transport and placement in complex fractures of deep coal seams, and offer theoretical support for hydraulic fracturing design and parameter optimization.

The investigation of the origin, occurrence, and migration mechanisms of coalbed methane (CBM) in high-rank coal reservoirs was reported in this study via a comprehensive analysis of CBM geochemical data from the Zhengzhuang and Fanzhuang blocks to establish the distribution pattern of methane carbon isotopes. Combined with reservoir information, geological characteristics, and hydrodynamic conditions, the CBM genesis and its control factors were elucidated and further quantitatively evaluated by gray correlation analysis. The results demonstrate that the carbon isotope ratio of methane (δ13C1 value) mainly varies between -57.80‰ and -27.35‰ with an average of -34.21‰, indicating that CBM is dominated by thermogenic gas in the study area. While the δ13C1 value is light at the center and heavy in the surroundings of the plane. When the maximum reflectance of vitrinite (R o,max) is between 3.00% and 4.50%, the δ13C1 value slightly decreases with an increase in thermal evolution degree. In addition, the δ13C1 value exhibits a positive correlation with vitrinite, gas content, coal thickness, and burial depth. Further, by means of the gray correlation analysis, the order of the influence of various factors on methane carbon isotopes is determined as follows: thermal evolution degree > vitrinite content > gas content > coal seam thickness > gas saturation > inert matter content > burial depth. Thus, the distinctive geochemical characteristics of high-rank coal reservoirs were formed via the synergistic effects of thermal evolution, macerals, and gas content. On the one hand, during high thermal evolution, massive micropores are generated to promote the partial retention of 12CH4 within the coal matrix, resulting in a relatively light trend in δ13C1. Meanwhile, a high vitrinite content implies the presence of excess aromatic macromolecular condensates to facilitate the occurrence of more 13CH4, thus appearing as a heavy δ13C1 value. On the other hand, considerable burial depth, complex geological structures, and strong hydrodynamic activity are highly prone to induce the fractionation effect of methane carbon isotopes, including diffusion, migration, water solubility, and secondary biogenic gas.

This study conducted Tetrahydrofuran Soxhlet extraction experiments and multiple test technologies (including gas chromatography/mass spectrometry (GC/MS), Fourier-transform infrared spectroscopy (FTIR), microcalorimeter) to examine the the organic chemical composition, molecular structure, and gas adsorption behaviors in different metamorphic deformed coals. Then, the microscopic control mechanism was revealed by clarifying the relationships between chemical composition and structure and the adsorption heat. The results show that oxygen-containing and aliphatic compounds from low molecular weight compounds(LMWCs) occupy a more obvious position in high rank coals, but aromatic compounds with low aromatic condensation degree only appear in medium rank coals. While a greater variety of LMWCs, especially oxygen-containing and other heteroatom-containing compounds, are released under tectonic deformation and failure effects. Then, on the basis of functional group characteristics, it finds that tectonic stresses not only cause the detachment effect in high rank coals to form short-chain aliphatic structures, but also induce the cyclization effect in medium rank coals to form alicyclic structures. Additionally, tectonic heat generation can promote the reduction or disappearance of unstable oxygen-containing functional groups. And the advanced evolution feature of the molecular structure for tectonically deformed coals is more pronounced under the high metamorphic stage. Further, combined with the adsorption heat results, both oxygen-containing functional groups and aromatic structures can strengthen gas adsorption, but long-chain aliphatic structures exhibit more obvious negative correlation to weaken gas adsorption. Meanwhile, tectonically deformed coals consistently manifest a stronger adsorption capacity than intact coal before and after LMWCs dissolution. However, affected by adsorption sites and pore spaces, medium and high rank coals exhibit an inverse adsorption heat response following LMWCs dissolution.

The application of CO2 pre-fracturing in shale oil development demonstrates promising prospects. However， current research predominantly focuses on single-phase CO2 injection optimization， neglecting the synergistic interactions between CO2 and water-based fluids during actual field production for the enhancement of energy and shale oil recovery. This study utilized shale core samples from Member 1 of the Qingshankou Formation in the Songliao Basin. A high-temperature and high-pressure oil recovery simulation system combined with two-dimensional nuclear magnetic resonance （2D NMR） technology was employed to conduct synergistic enhancement of energy and shale oil recovery experiments of CO2 and water-based fluids. The impacts of injection fluid type， injection sequence， injection ratio， injection volume， and shut-in time on shale oil recovery were systematically investigated. Furthermore， the contribution of multi-scale pores to the recovery process was quantitatively analyzed from a microscopic perspective. The results show that the mobilization efficiency of different media differs markedly across pore sizes. Water-based fluids exhibit superior mobilization of clay interlayer pore oil （pore size： 3-111 nm）， while CO2 dominates in medium-large pores （>201 nm）. The combination of CO2 and slickwater breaker fluid achieves optimal enhanced oil recovery performance， significantly improving clay interlayer pore oil mobilization by 8.2%. Compared with injecting water-based fluid first， pre-injecting CO2 yields an average 3.2% higher recovery. Increasing the CO2 injection proportion enhances recovery， with the optimized ratio at 1∶1. Recovery increases with energy-enhancing injection volume but exhibits diminishing returns. The optimal injection volume corresponds to elevating the formation pressure coefficient to approximately 1.7. Recovery rises with shut-in time， particularly within the first 20 days， suggesting an optimal shut-in duration of 10-20 days. Applying these optimized parameters to a shale oil test well resulted in a 18% increase in daily oil production compared to conventional fracturing wells in the same formation， demonstrating significant recovery enhancement.

During horizontal salt cavern construction, factors such as concentration, temperature, flow rate, pressure, and dissolution angle significantly influence salt rock dissolution rates. Unlike static dissolution, which occurs without significant fluid movement, dynamic dissolution involves fluid flow under specific pressure conditions, better simulating real-world scenarios. An experimental setup was designed to study dynamic dissolution, focusing on the effects of flow rate, dissolution angle, concentration, and temperature. Results show that flow rate and positive angles significantly impact dissolution rates, while concentration and temperature affect dissolution exponentially and logarithmically, respectively. An empirical equation incorporating these factors was developed and validated with a 6.43% fitting error, demonstrating its reliability. This model enhances understanding of horizontal salt cavern construction dynamics, supports the development of advanced dissolution and coupled flow models, and aids in optimizing salt cavern storage design and operation.

It is of great significance to clarify the evolution law and control mechanism of fracture conductivity in different production stages for the efficient development of coalbed methane. However, research on fracture conductivity in coal-rock remains limited, and the existing models are inadequate for predicting fracture conductivity with a consideration of staged proppant crushing. To address this gap, long-term conductivity tests were conducted on deep coal-rock under varying closure pressures and proppant gradation ratios. Within a coupled computational fluid dynamics and discrete element method (CFD-DEM) framework, a particle substitution scheme was integrated with the energy-based breakage model (Tavares breakage model) to develop a fracture conductivity predictor that incorporates proppant crushing and captures the time-dependent kinetics of proppant breakage during fracture conductivity evaluation. The model's predictions align well with the experimental data, with an average error of less than 5%. The results indicate that fracture conductivity evolution can be delineated into three stages according to particle-breakage characteristics, (i) proppant pack compaction, (ii) the primary crushing of coarse proppant grains, and (iii) the secondary crushing of proppant fines, and the contributions of these three stages to the total conductivity loss are approximately 60%, 30%, and 10%, respectively. At a low closure pressure, fracture conductivity varies markedly among proppant packs with different particle sizes; once the closure pressure exceeds 40 MPa, the proppant pack enters the fines-breakage stage, and the conductivity differences among various particle size blends become marginal. Furthermore, a semi-empirical prediction model incorporating a composite crushing factor (CCF) was developed based on the Kozeny-Carman relationship, enabling a rapid evaluation of fracture conductivity in deep coal-rock fractures. Overall, these results provide a practical basis for fracture conductivity prediction and hydraulic fracturing parameter optimization in coal-rock reservoirs.

When developing weakly consolidated reservoirs by horizontal wells and facing the problems of sand production and water breakthrough, a poor understanding of the particle-water-oil transport and interaction mechanisms in the porous media can seriously affect the comprehensive benefits of well production. In this paper, an unresolved discrete element method-volume of fluid (DEM-VOF) coupling method is proposed for the oil-water two-phase flow containing fine particles within a pore-scale porous media. The method is characterized by the discrete element method calculation for particle displacements and collisions, the volume of fluid method for fluid flow and free surface capture, and a porous sphere model for calculating the local porosity of the fluid to overcome the difficulty in calculating the volume fraction when the particle size being larger than the fluid mesh. The accuracy of the coupled method was verified by a series of single particle sedimentation cases. The model reveals the microscopic mechanism of particle-water-oil transport within the porous media, and the results show that the presence of particles perturbs the oil-water interface, resulting in a lower average oil content volume fraction within the porous media during water drive. The production of particles also increases due to the greater pressure difference and drag force associated with water drives. The permeability decrease due to particle migration in porous media is proportional to particle diameter and inversely proportional to fluid flow rate and fluid viscosity. This study provides a coupled computational method for analyzing the interaction between particles and multiphase fluids.

During hydrogen or carbon dioxide storage in deep coal reservoirs, the permeability and deformation of coal exhibit dynamic characteristics, which are induced by the increase in pressure and enhanced sorption. It is crucial to investigate the time dependency of the permeability and deformation of coal during gas storage and the influence of the confining pressure on the permeability evolution induced by gas pressure and sorption. In this study, we conducted a series of gas seepage experiments on a low-permeability coal sample and periodically measured the overall strain and permeability of the coal during CO2 injection for 150 h under confining pressures of 5 MPa-19 MPa. The experiment results demonstrated that the low-permeability coal had significant stress sensitivity. The permeability of the coal initially increased and subsequently decreased during CO2 injection. Moreover, increasing the confining pressure extended the time scale and reduced the peak values of the permeability evolution considerably. The overall deformation was not synchronous with the permeability evolution. In addition, based on the non-equilibrium hypothesis, we established a transient model to comprehensively depict the map of the permeability evolution and to analyze how pressure and sorption influence changes in the permeability and deformation of coal during gas injection. The increase in the gas pressure exerts a positive influence on the enhancement of the coal permeability, while sorption has the opposite effect. The results demonstrate that the time dependency of the deformation and permeability of coal are significant and cannot be ignored in hydrogen and carbon dioxide sequestration of applications. This study provides a significant reference for predicting hydrogen and carbon dioxide storage in deep coal reservoirs.

Deep coal reservoirs in the Daji region of China have achieved high industrial gas production rates through large-scale volumetric fracturing. However, severe proppant flowback has significantly undermined coalbed methane recovery. Choke size management presents a practical and cost-effective approach to controlling proppant flowback. To quantify the relationship between proppant flowback and flow rate, this study conducted flowback experiments on actual coal fracture surfaces under both single-phase water production and gas-water two-phase coproduction conditions. The experiments examined the time-varying characteristics of flowback under constant flow rate, and a semitheoretical model for predicting cumulative proppant flowback was developed based on dimensional analysis. The results showed that flow velocity variations at the boundaries of flowback channels significantly influence proppant flowback rates. Under equivalent total flow conditions, the cumulative proppant flowback during the gas-liquid two-phase stage increased by 98.19% compared to the single-phase water production stage. When the fracture width increased to 6 mm, compression from the fracture walls significantly intensified proppant flowback, though the increase in flowback ratio tended to level off. When closure stress exceeded 15-20 MPa, the differences in cumulative proppant flowback became less pronounced. These findings provide theoretical guidance for choke size management, aiding in the optimization of production strategies while effectively controlling proppant flowback.

During PEMEC operation, anode oxygen accumulation represents a significant contributor to the deterioration of electrolytic cell performance. Effective bubble management has a significant impact on the improvement of PEMEC performance. In this paper, a two-dimensional, transient, two-phase numerical model is established and simulated by COMSOL Multiphysics using the phase-field model to study the patterns of gas-liquid two-phase flow under the rib with various pressure differentials. The porous transport layer (PTL) is replaced with randomly generated circular fibers using MATLAB. The gas-liquid two-phase flow behavior under the rib at various pressure differentials on both sides of the rib is investigated. Furthermore, the impact of graded PTL and perforated PTL on gas-liquid two-phase flow under the rib is examined. The results show that in the range of pressure differential studied, the increase of pressure differential enhances the gas-liquid two-phase flow and reduces the oxygen accumulation under the ribs. Oxygen accumulation, reflux, and movement along the CL side may manifest at different pressure differentials. Both the graded structure and perforated structure of PTL can promote the elimination of oxygen under the ribs. Overall, the collaborative optimization of pressure differential and PTL structure can effectively optimize the gas-liquid two-phase flow under ribs.

Matrix pores and the cleat system are widely developed in coal reservoirs. To simultaneously characterize the permeability of the matrix region and the cleat system, we have established a trans-scale flow model of coal reservoirs based on the revised gray lattice Boltzmann method (GLBM) and Shan-Chen model. By associating the partial rebound coefficient ns with the specific spatial position of matrix pores, we consider the permeability of the matrix region in the overall flow. Meanwhile, by adding virtual potential between particles to the evolution equation directly through the force format, we improve the stability of the model and expand the range of density and viscosity ratios for multiphase and multiple-component flow simulation. Finally, based on the flow simulation results, we propose the trans-scale interporosity flow coefficient and revise the macroscopic reservoir numerical model. The results show that for multiscale digital cores with homogeneous characteristics of matrix pores, as the permeability of the matrix region increases, the overall flow velocity at the outlet increases, especially in the face cleat region. Compared with the case without considering the permeability of the matrix region, when the permeability of the matrix region is 0.08 md, the average flow rate increase can reach 10.9%. For multiscale digital cores with heterogeneity characteristics of matrix pores, when the matrix pores' connectivity direction is perpendicular to the flow direction, the average flow velocity at the outlet is significantly increased, with an average increase of 6.0%. Besides, the trans-scale flow model established in this study successfully characterized the fluid-solid interaction force. Compared with the case without considering the fluid-solid interaction force, the average flow velocity at the outlet increases when the fluid-solid interaction force is attraction and decreases when the fluid-solid interaction force is repulsion. In addition, for reservoir-scale numerical simulation, when considering matrix permeability, the production prediction results are higher than those without considering matrix permeability, especially when the matrix heterogeneity is considered and the matrix pores' connectivity direction is perpendicular to the flow direction. For reservoir parameter inversion, this will lead to an overestimation of fracture permeability. When the matrix permeability is 0.08 md and the matrix pores' connectivity direction is perpendicular to the flow direction, the increase in average velocity is 18.4% and the maximum overestimation can be 11.8%.

Coal, as a heterogeneous porous medium, exhibits substantial adsorption capacity for coalbed methane, highlighting the necessity to comprehend methane storage mechanisms for reserve evaluation and production optimization. To investigate the adsorption characteristics of methane, a novel approach for calculating thermodynamic parameters is developed based on phase equilibrium and fugacity principles. Isothermal adsorption experimental results are utilized to assess the influence of moisture on the adsorption mechanism, disclosing variations in enthalpy, entropy, and Gibbs free energy for supercritical methane. The findings reveal a pronounced reduction in adsorption capacity under hydrated conditions. Methane adsorption onto coal is identified as an exothermic, entropy-decreasing, non-spontaneous process dominated by microporous filling and monolayer adsorption. The supercritical Langmuir and Dubinin–Radushkevich model confirms that microporous filling accounts for over 10% of the total adsorption capacity under high-temperature and high-pressure conditions. Additionally, temperature changes within coal seams during distinct production phases, ranging from 1 to 18 K, are quantified. A predictive method for isothermal adsorption curves using thermodynamic parameters is introduced, with an accuracy within a 6% error margin. These insights offer theoretical support for modeling gas–water flow dynamics in coalbed methane reservoirs.

ObjectiveThe Daning-Jixian block on the eastern margin of the Ordos Basin has achieved large-scale production of deep coalbed methane (CBM), with nearly 150 horizontal wells having been put into production. However, with a gradual decrease in formation energy during CBM production, gas wells exhibit declining liquid-carrying capacity. Consequently, liquid accumulation in wellbores has become a major factor affecting deep CBM production. Recovery of deep CBM shows the coexistence of free and desorbed gases, accompanied by significantly varying gas/liquid ratios. Moreover, gas production channels and techniques vary in different production stages. Hence, there is an urgent need to develop a method for liquid accumulation diagnosis and prediction that is suitable for the production characteristics of horizontal wells for deep CBM, aiming to provide a basis for the prevention and control of liquid accumulation and to avoid damage to reservoirs and their productivity caused by liquid accumulation. [Methods and Results] Using the Reynolds-averaged Navier-Stokes (RANS) κ-ε equation for incompressible viscous fluids and the volume of fluid (VOF) method, as well as the physical simulation experimental results of gas-liquid two-phase flow in a circular tube and an annulus, this study developed a numerical model of gas-liquid two-phase flow in horizontal wells for deep CBM utilizing the Fluent computational fluid dynamics tool and its secondary development. Based on the numerical simulation results, this study plotted the gas-liquid two-phase flow patterns in horizontal wells under different wellbore pressures, different inclinations, along with the circular tube and annulus conditions. Furthermore, this study established the corresponding relationship between the flow pattern and liquid accumulation based on the regularity and pattern evolution of gas-liquid two-phase flow in the production process. The results indicate that bubble and slug flows correspond to the liquid accumulation state. In contrast, churn flow corresponds to the transition state where liquid accumulation will occur, while annular flow corresponds to the state with no or low risk of liquid accumulation. Additionally, the well inclination is directly proportional to the liquid accumulation risk, whereas the pressure is inversely proportional to the risk. ConclusionsThe flow pattern chart board-based method for diagnosing liquid accumulation proposed in this study was applied to the horizontal wells for deep CBM in the Daning-Jixian block, providing guidance for proposing the intervention timing, taking control measures in time, with the efficiency of measures having been improved. In subsequent studies, this method will be optimized for intelligent analysis and prediction using artificial intelligence (AI) techniques. This will provide robust technical support for the prediction, prevention, and control of liquid accumulation in CBM wellbores.

In order to investigate the essence of CH4/CO2 adsorption in coal for CO2-enhanced coalbed methane recovery (CO2-ECBM), this study established the coal structure models from the chemical composition and structure information on different rank coals to conduct CH4 and CO2 adsorption simulation under different environmental conditions. Thus, the differences and connections between integral heat and isosteric heat of CH4/CO2 adsorption in coal and its micro-mechanism were discussed. The results show that as the coal metamorphism degree deepens, the integral heat of CH4/CO2 adsorption, similar to adsorption capacity, presents a decreasing first and then increasing trend. While the adsorption equilibrium time of high-rank coal gives a significantly decreasing characteristic with pressure. Then, on the basis of adsorption simulation behavior, it finds that because complex functional groups exist in the coal macromolecular structure, the adsorption capacity shows a different characteristic compared with the experimental results; that is, it decreases with the coal metamorphism degree. Meanwhile, compared to CO2 adsorption, the isosteric heat of CH4 adsorption appears to have an obvious downward trend with increasing pressure and then gradually stabilizes. Further, there is always a clear linear relationship between CH4 adsorption capacity, and isosteric heat for aromatic pores in different rank coals. While for slit pores, both CH4 and CO2 molecules exhibit significant parabolic relationships between adsorption capacity and isosteric heat. In addition, on the one hand, except for the obvious chemical adsorption of low-rank coal in the high-pressure stage, affected by pore morphology and size, the isosteric heat of CH4 or CO2 adsorption manifests lower values in slit pores and large pore sizes. On the other hand, based on the adsorption systems of similar structural fragments with different functional groups, -OH has been identified as the functional group with the strongest adsorption effect on gas molecules and is also the main functional group causing CO2 chemical adsorption.

Deep coalbed methane (DCBM) reservoirs often experience severe proppant flowback during large-scale hydraulic fracturing, which undermines fracture conductivity and limits long-term recovery. The critical flowback velocity (CFVP) is the key parameter controlling proppant pack instability and flowback. In this study, the instability and flowback behavior of proppant packs throughout the entire production process, from early water flowback to late gas-dominated stages, were systematically investigated. Proppant flowback under closure stress was simulated using a CFD–DEM approach to clarify the flowback process and mechanical mechanisms. Laboratory experiments on coal fracture surfaces under gas-liquid two-phase and gas-liquid-solid three-phase conditions were then conducted to quantify CFVP and its variation across different production stages. Finally, a semi-empirical CFVP predictive model was developed through dimensional analysis. Results show that proppant flowback proceeds through three distinct stages—no flowback, gradual flowback, and rapid flowback. Increasing fracture width reduces proppant pack stability and lowers CFVP but allows higher flow capacity, and within the typical gas and water production ranges of deep coalbed methane reservoirs, flowback is significantly reduced when the width exceeds about 8 mm. Closure stress enhances CFVP below 15 MPa but has little effect above this threshold, while higher stresses progressively stabilize the proppant pack and minimize flowback. Larger average proppant size raises CFVP and preserves conductivity, whereas higher gas–liquid ratios elevate CFVP and reduce flowback, with ratios above 40 sustaining consistently low flowback levels. These findings clarify the mechanisms and threshold conditions of proppant flowback, establish quantitative CFVP benchmarks, and deliver theoretical as well as experimental guidance for optimizing DCBM production.

ABSTRACT: Migration and packing patterns of proppants play a critical role in the conductivity of hydraulic fractures and unconventional oil and gas production. However, the fracture surface is usually tortuous with gradually narrow walls (tortuous - wedge fractures). Existing fracture models only consider tortuosity, and more efforts are needed in this regard. In this study, a numerical model of proppant transport in tortuous wedge-shaped fractures is established based on CFD-DEM method, used to investigate the effects of tortuosity, wedge angle, diameter of proppant, fluid velocity on the migration and placement of proppants. The results reveal that the migration and distribution of proppant in tortuous-wedge fractures exhibit significant disparities when compared with straight fractures or tortuous fractures. Proppant migration in tortuous-wedge fractures is divided into the suspended sand stage, sand bed rapid growth stage and top suspended sand stage according to the main force. The proppant transport distance increases with the increase of the wedge angle. Compared with the tortuous fractures with a wedge angle of 0°, the migration distance of proppant in the tortuous wedge fractures, t = 1 s, wedge angles of 1° and 2° increased by 16% and 29%. However, with the increase of it, the congestion of the proppant may also occur, and there is a critical angle. The greater the tortuosity, the greater the kinetic energy loss of particles and the advancing angle of the dune. Compared with the straight fracture, t=3 s, and the average velocity is reduced by 36%, and 45%. In addition, the proppant migration in tortuous-wedge fractures is non-uniform distribution, and the dune is higher in the tortuous place. This study benefits to understand the migration mechanism of proppant in fractures. It can provide theoretical guidance for the stimulation of unconventional reservoirs. 1. INTRODUCTION Hydraulic fracturing is an important means of reservoir stimulation and improving oil and gas recovery. By pumping high - pressure fluid, the reservoir is broken and proppant particles are injected to fill the fractures, forming a long - term high conductivity channel for oil and gas in the reservoir. Proppant migration in fractures is a fluid - solid coupling problem among reservoir fluid, proppant particles and fracture walls. The migration and distribution of proppant depend on the physical parameters of particles, fluids and fractures, the distribution of flow field and pressure field in complex fractures, and the mechanism of action is complex. Scholars have carried out a lot of research based on indoor physical experiments and numerical simulation methods.

Abstract In order to effectively alleviate the problem of premature water breakthrough in horizontal wells, sectionalized variable-density perforation completion, stinger completion, ICDs and sliding sleeve based on control valve completion technology have been proposed. The sliding sleeve based on control valve completion technology can realize infinite adjustment and real-time control of the sliding sleeve opening to balance inflow effectively. In order to study the interference of the sliding sleeve completion to the flow near the wellbore, a calculation model for the skin factor of sliding sleeve is established in this paper. Based on numerical simulation, the flow area is divided according to the pressure distribution characteristics during the flow process of the sliding sleeve completion. At the same time, the linear flow boundary and the radial flow boundary are determined by combining the geometric boundary and roundness. Finally, the skin factor is determined according to the flow difference between the fluid passing through the sliding sleeve completion and the open hole completion, and it is compared and verified with the theoretical prediction value. The research shows that the flow in the near-wellbore of the sliding sleeve can be divided into six different zones according to the distribution characteristics of the pressure equipotential line. The radius of disturbance in the near-wellbore predicted by roundness is within 6% error of the numerical simulation results. By simulating the flow difference during constant pressure production, the error between the skin coefficient obtained by inverse calculation and the theoretical prediction value is within 12%. It was also observed that the water-cut decreased by 6.4% with the application of sliding sleeve completion compared to the normal screen pipe completion after 2 years of production. The proposed model is robust and reliable. The skin factor model in this study can be applied not just to the optimal design of water control completion parameters, but to provide theoretical guidance for the real-time regulation of the sliding sleeve opening during production.

Accurate measurement of coal seam gas pressure (CSGP) is critical to the evaluation of coal mine gas hazards and the potential of coal seam gas extraction. In this study, we investigate gas leakage from chambers and its influences on CSGP measurement results (MR) through numerical simulations. Furthermore, we propose, analyze and validate a novel method that balances gas pressure between two chambers, i.e. the measurement and regulation chambers, in a borehole. The results demonstrate that: (1) Traditional CSGP measurement method utilizing boreholes with a single chamber exhibit a gradual expansion of the gas pressure dropping region around the borehole, accompanied by an initial increase in chamber gas pressure followed by stabilization. The gas leakage process within the chamber undergoes three typical stages. (2) The increase of gas leakage lowers the MR value and raises the CSGP measurement error ratio (R). R ). The relationship between MR, R and the stable value of gas leakage is nearly linear. (3) The proposed novel CSGP measurement method involves continuous gas injection into the regulation chamber to establish a dynamic gas pressure balance region between the two chambers. This approach minimizes gas leakage in the measurement chamber and accelerates gas pressure recovery. Maintaining dynamic pressure equality between the dual chambers is essential for minimizing R . (4) An automatic regulation unit is developed to achieve dynamic gas pressure balancing between the two chambers. With the novel method, R values remain below 3%, yielding higher CSGP measurement accuracy compared to alternative approaches.