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.

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.

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.

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.