Haiyang Wang

Bedding planes widely exist in stratified reservoirs and strongly restrict the vertical cross-layer growth of hydraulic fractures. Traditional displacement discontinuity method (DDM) tends to produce spurious negative apertures for compressed weak bedding interfaces and neglects multi-cluster stress superposition in inclined formations. This work proposes an improved DDM incorporating bedding-plane normal-tangential support-stiffness contact constraints together with Mohr–Coulomb-based opening-slip-closure discrimination, which removes non-physical negative-aperture artifacts of closed weak interfaces. The proposed numerical framework is adopted to model fracture initiation, propagation and bedding-interface penetration under multi-fracture interference. Key coupled influences of net pressure, bedding-plane dip angle and fracture-cluster number are quantitatively investigated. Numerical simulations reveal that higher net pressure enhances the lasting cross-layer propagation capacity of hydraulic fractures. Among the examined cases, a bedding dip angle of 60° facilitates fracture penetration through interfaces. Bedding features amplify inter-cluster mechanical interference and lead to asymmetric fracture evolution, tip arrest and interface-parallel fracture propagation, which becomes more pronounced as the number of fracture clusters increases. This study provides theoretical references for multi-cluster fracturing design in low-permeability layered reservoirs.

To address the unclear fracture propagation behavior and the insufficient understanding of the influence mechanisms of fracturing parameters during the hydraulic fracturing of deep coalbed methane reservoirs in the Yan’an Gas Field, Well JY1 in the No. 8 coal seam of the Benxi Formation in Block N was selected as the study object. An integrated three-dimensional geomechanics–fracture propagation model coupling geomechanical conditions, cleat characteristics, and fracture propagation was established. Fracture propagation simulations were conducted under different injection rates, fluid volumes per stage, and proppant volumes per stage. The results indicate that when main fractures intersect with cleats, they may exhibit deflection, branching, or direct crossing. Increasing the injection rate enhances the driving force at the fracture tip and improves the penetration capability of main fractures. Increasing the fluid volume improves fracture coverage and inter-cluster connectivity. Increasing the proppant volume contributes to greater residual fracture width, higher proppant placement concentration, and improved fracture conductivity. An injection rate of 19–21 m³/min, a fluid volume per stage of 2500–2700 m³, and a proppant volume per stage of 280–320 m³ provide a favorable balance between fracture network development and effective proppant support under the studied reservoir conditions.

Deep coalbed methane (CBM) resources are abundant and represent a critical component of future energy supply and carbon reduction strategies. However, deep coal seams are characterized by well-developed cleat systems and high Poisson’s ratios, rendering the mechanisms of hydraulic fracture initiation, propagation, and complex fracture network development insufficiently understood. In this study, deep coal rock at a burial depth of 2700 m is investigated. A finite element–based hydraulic fracturing model incorporating complex face-cleat and end-cleat networks is established by explicitly representing cleat geometry, mechanical properties, fluid leak-off behavior, and hydraulic loading conditions. Using this model, the effects of cleat inclination angle, horizontal stress difference, and displacement on fracture evolution are systematically analyzed. The results indicate that when face cleats are orthogonal to the maximum horizontal principal stress, fractures preferentially penetrate cleats and propagate along the maximum stress direction. In contrast, when face cleats form acute angles with the maximum horizontal stress, pronounced branching fractures develop along both face and end cleats, with propagation increasingly dominated by face cleats as the angle decreases. Increasing horizontal stress difference suppresses fracture branching, leading to simpler fracture networks but greater total fracture length and maximum fracture width. Moreover, under identical injection pressures, the equal-pressure fracture length increases, indicating enhanced fracture propagation capacity. With increasing displacement, fracture networks evolve from simple to complex patterns, accompanied by accelerated propagation and enlarged fracture widths; however, excessive displacement intensifies fluid leak-off, ultimately reducing the equal-pressure fracture length.

With the exploitation of tight sandstone gas, the corrosion problem of wellbores in the X block of the Ordos Basin has become increasingly severe, necessitating the implementation of effective measures to mitigate tubing corrosion and enhance corrosion inhibition efficiency. This study conducted field corrosion monitoring in conjunction with laboratory experiments, employing weight loss method, scanning electron microscopy (SEM), energy dispersive spectroscopy (EDS), and X-ray diffraction (XRD) to comprehensively characterize the corrosion of gas wells from both macro and micro perspectives. The results show that the gas wells in the X block of the Ordos Basin are exposed to a complex corrosion environment, where the electrochemical corrosion risk in the aqueous phase and the acidic gas corrosion risk in the gas phase coexist, posing a potential threat to wellbore integrity. Corrosion in X-1 and X-2 wells is mainly attributed to CO₂, while corrosion in X-3 well is primarily caused by sulfides. The field application of corrosion inhibitor M exhibited significant corrosion inhibition effects on steels, with the best performance at a dosage of 2000 mg/L. Based on experimental data, a corrosion inhibitor dosage prediction model for the X block gas wells was constructed. By increasing the dosing frequency and reducing the dosing concentration, the optimized dosing scheme can annually save approximately 566.4 L of corrosion inhibitor per well, providing a scientific basis for extending the service life of the gas well tubing. Given the prevalence of CO₂- and H₂S-induced corrosion in many global reservoirs, these findings provide valuable insights for corrosion management in similar international oil and gas fields, enhancing the broader applicability of the study.

This study employs a finite element approach to investigate wellbore stability in interbedded weak formations, such as unconsolidated layers, with a focus on the failure-tendency method, which is derived according to the principle of Mohr–Coulomb theory. The numerical model is successfully verified through analytical solutions for stress distributions around a borehole. Through finite element modeling, the method captures critical shear failure thresholds, exemplifying how variations in horizontal stress anisotropy, orientation of interbedded weak layers, and mechanical properties of layered geological formations impact wellbore stability in stratified formations. Results indicate that the potential unstable regions, aligned in the direction of minimum principal stress, and the range of unstable regions gradually enlarge as the internal cohesive strength decreases. By modeling heterogeneous rock sequences with explicit representation of interbedded weak layers and stress anisotropy, the analysis reveals that interbedded weak layers are prone to shear-driven borehole breakouts due to stress redistribution and relatively lower internal cohesive strength. As compressive stresses concentrate at interfaces between stiff and compliant layers, breakouts are induced at those weak layers along the interfaces; this type of failure is also manifested through a field borehole breakout observation. Simulation results reveal the significant influences of the mechanical properties of layered formations and in situ stress on the distribution of instability regions around a borehole. The study underscores the necessity of layer-specific geomechanical models to predict shear failure in complex layered geological formations and offers insights for optimizing drilling parameters to enhance wellbore stability in anisotropic, stratified subsurface environments.

Deep coalbed methane reservoirs must utilize hydraulic fracturing technology to create high-conductivity sand-filled fractures for economical development. However, the mechanism by which proppant embedment affects fracture width in coal rock is not yet clear. In this article, using the discrete element particle flow method, we have developed a numerical simulation model that can replicate the dynamic process of proppant embedment into the fracture surface. By tracking particle positions, we have accurately characterized the dynamic changes in fracture width and proppant embedment depth. The consistency between experimental measurements of average fracture width and numerical results demonstrates the reliability of our numerical model. Using this model, we analyzed the mechanisms by which different proppant particle sizes, number of layers, and closure stresses affect fracture width. The force among particles under different proppant embedment conditions and the induced stress field around the fracture were also studied. Numerical simulation results show that stress concentration formed by proppant embedment in the fracture surface leads to the generation of numerous induced micro-fractures. As the proppant grain size and closure stress increase, the stress concentration formed by proppant embedment in the fracture surface intensifies, and the variability in fracture width along the fracture length direction also increases. With more layers of proppant placement, the particles counteract some of the closure stress, thereby reducing the degree of proppant embedment around the fracture surface.

Deep coalbed methane (CBM) reservoirs hold substantial resource potential and play a crucial role in China’s unconventional natural gas development. However, the vertical propagation behavior of hydraulic fractures in deep CBM formations remains inadequately understood, posing challenges for optimizing fracturing parameters to control fracture height growth and enhance fracture development within the coal seam. To address this, this study establishes numerical simulation models to investigate hydraulic fracture propagation in directional wells, incorporating three typical lithological combinations representative of deep CBM reservoirs. Through these models, the influence mechanisms of bedding density, stress ratio, rock friction coefficient, and fracturing parameters on vertical fracture propagation and post-fracture productivity were systematically analyzed. The results reveal that the fracture propagation characteristics vary significantly with lithological combinations. Initially, hydraulic fractures penetrated adjacent formations near the wellbore while simultaneously generating branched fractures, leading to the formation of a complex fracture network. As propagation continues, branch fractures exhibited reduced width compared to the primary fracture. Well-developed bedding planes in the roof or floor, combined with lower stress ratios and friction coefficients, effectively constrained vertical fracture growth. Furthermore, optimizing fracturing fluid volume, reducing injection rate, and lowering proppant concentration promoted fracture development within the coal seam, thereby enhancing post-fracture well productivity. These findings provide a theoretical foundation for the optimization of hydraulic fracturing strategies in deep CBM reservoirs, contributing to more effective reservoir stimulation and resource recovery.

Frequent wellbore loss incidents in the Mesozoic reservoirs of the Zhengning oilfield in the Ordos Basin, China, have severely impacted the development of tight oil and gas reservoirs in the basin. This study analyzed the mineral composition, microstructure, natural fracture distribution, and hydration–dispersion characteristics of rocks in the loss-prone intervals of the Mesozoic reservoirs using a laboratory experimental system. The effects of natural fractures and drilling fluid immersion on the mechanical properties and failure behavior of the rocks were investigated, and the wellbore loss mechanisms in the Mesozoic reservoirs of the Zhengning oilfield were comprehensively analyzed. Experimental results show that the reservoir rocks in the loss-prone intervals are widely distributed, with natural fractures having a width of 0.2–0.3 mm, and the clay mineral content is generally above 40%. When the relative content of illite/smectite interstratification exceeds 80%, the rock exhibits strong hydration–dispersion behavior, with a thermal recovery rate of less than 85%. Drilling fluid immersion causes the rock mass to become unstable. The presence of natural fractures and the hydration–dispersion effect significantly weaken the strength of the surrounding rock mass, leading to enhanced rock plasticity. During drilling, the expansion and interconnection of natural fractures, combined with the hydration–dispersion effect, are the main causes of wellbore loss incidents. Our study clarifies the mechanisms underlying wellbore loss incidents in the Zhengning oilfield and provides reliable experimental evidence for preventing such incidents in this area.

Tight sandstone gas reservoirs are rich in reserves and are an important part of unconventional oil and gas resources. However, natural fractures’ impact on hydraulic fracture propagation behavior and network formation mechanisms remain unclear. Exploring how to optimize fracturing parameters to maximize post-fracturing productivity requires further investigation. Therefore, this study focused on the characteristics of tight sandstone gas reservoirs and established a three-dimensional numerical simulation model for hydraulic fracture propagation and post-fracturing productivity using production history matching to validate the reliability of the model. Based on this model, this study investigated the influence mechanisms of natural fracture angles, density, and lengths on hydraulic fracture propagation behavior and network formation. The spatial distribution of hydraulic fracture widths in three dimensions is also explored. When natural fracture angles are lower, a greater number of natural fractures are activated, leading to more developed secondary hydraulic fractures and the formation of complex fracture networks. Hydraulic fractures tend to penetrate directly through high-angle natural fractures. Single-well cumulative gas production increases initially with increasing natural fracture angles, then decreases, but increases with higher natural fracture density and length. Optimal fracturing in areas with longer natural fractures, lower angles, and higher density distribution enhances single-well productivity effectively.

A comprehensive understanding of the mechanical characteristics of deep coalbed methane reservoir rocks (DCMRR) is crucial for the safe and efficient development of deep coalbed gas resources. In this study, the microstructural and mechanical features of the coal seam roof, floor, and the coal seam itself were analyzed through laboratory experiments. The impact mechanisms of drilling fluid and fracturing fluid hydration on the mechanical properties and failure behavior of coal seam rocks were investigated. The experimental results indicate that the main minerals in coal seams are clay and amorphous substances, with kaolinite being the predominant clay mineral component in coal seam rocks. The rock of the coal seam roof and floor exhibits strong elasticity and high compressive strength, while the rock in the coal seam section shows a lower compressive capacity with pronounced plastic deformation characteristics. The content of kaolinite shows a good correlation with the mechanical properties of DCMRR. As the kaolinite content increases, the strength of DCMRR gradually decreases, and deformability enhances. After immersion in drilling fluid and slickwater, the strength of coal seam rocks significantly decreases, leading to shear fracture zones and localized strong damage features after rock compression failure. The analysis of the mechanical properties of DCMRR suggests that the horizontal well trajectory should be close to the coal seam roof, and strong sealing agents should be added to drilling fluid to reduce the risk of wellbore collapse. Enhancing the hydration of slickwater is beneficial for the formation of a more complex fracture network in deep coalbed methane reservoir.