The problem of wellbore stability in hard brittle shale formations is an important research topic in the exploration and development of shale gas. To solve this problem, the adaptability of the plugging drilling fluid to wellbore stability in the hard brittle shale of the tertiary Dongying formation in Bohai Bay Basin, China, was investigated. The results show that the clay content of the hard brittle shale in the study block is as high as 39.2% on average, with great possibility for hydration. The pore structure in the shale is dominated by micron-scale fractures and pores. A dense structure was formed on the surface of the shale after being immersed in plugging drilling fluid, and the matrix permeability of the shale was reduced by 91.1% and the fracture permeability by 98.7%. The water content increment of the shale after immersion was merely 0.75%, which reduced the probability of hydration greatly. Compared with the field-inhibitive drilling fluid, the plugging drilling fluid improved the uniaxial compressive strength of shale by 28%, which is more conducive to maintaining the wellbore stability. The seepage stress aggravates the risk of wellbore instability, while the hydration stress does not, but both increase the risk of rock instability at positions away from the well wall. The plugging drilling fluid affects the seepage stress and hydration stress by reducing the shale permeability and water content. With the decrease of permeability and water content, the potential instability zone of a wellbore becomes smaller.

The induced hydraulic fracturing in reservoirs is the result of interactions between a fluid-driven pressure increase in the reservoir and different lithology. To investigate the fracture height containment in a transitional shale formation, a three-layer medium fracturing model with the shale layer being used as an injection layer was first established. Then, based on the logging lithology, the propagation behavior of hydraulic fractures under real lithological sedimentary sequences was investigated. The results show that the hydraulic fracture can either cross through the lithological interface, be arrested by the interface, or stopped at the adjacent layer after crossing through the interface. Some specific properties of different lithologies may contain fracture height, such as sandstone with high tensile strength, coal with low stiffness, as well as clay shale with very low permeability. In the real lithological sedimentary sequence, hydraulic fractures are often blocked at the interface between a sandstone-shale combination or stop at the shale layer after crossing through the interface, and even increasing the injection rate cannot change this situation. The research results have of great significance for optimizing the trajectory of horizontal wells and fracturing operation parameters in reservoirs with frequent interbedded lithology.

The tight sandstone gas reservoirs of the Xujiahe Formation are critical targets for tight gas exploration and development in the Sichuan Basin. While Class I reservoirs have been successfully developed using staged volume fracturing technology, efforts are being increasingly directed toward Class II and III matrix-type blocks. These reservoirs are characterized by a low permeability, high geo-stress differentials, strong heterogeneity, and limited fracture development. These properties result in several challenges, including ambiguous gas production sources, low reservoir utilization rates, significant variability in horizontal well performance, and rapid early-stage production decline—all of which hinder the effective development of matrix-type reservoirs. This study examines two representative fractured wells, Xin 8-5H and Xinsheng 204-1H, located in Class II and III blocks of the Xujiahe Formation gas reservoir. To identify gas production sources, we establish full-fracturing-section productivity models. Furthermore, accounting for variations in geological characteristics, we develop distinct productivity models for three key zones, the matrix area, fracture area, and fault area, to evaluate the productivity controls. The findings reveal that well Xin 8-5H primarily produces gas from the matrix and fault zones, whereas well Xinsheng 204-1H derives most of its production from the matrix and natural fractures. In matrix-dominated zones, generating complex fracture networks enhances productivity. An optimal cluster spacing of approximately 14 m ensures broad pressure sweep coverage while maintaining effective inter-cluster fracture connectivity. Additionally, natural fractures in the Xu-2 matrix reservoirs play a vital role in fluid communication. To maximize reservoir contact, well trajectories should be designed such that natural fractures are oriented either parallel or perpendicular to the wellbore, thereby improving lateral and vertical development. Near fault zones, adjusting cluster spacing to 14–25 m—while keeping the distance between faults and fracturing stages below 50 m—effectively connects faults and substantially increases production. This study introduces a systematic methodology for identifying gas sources in matrix reservoirs and optimizes key productivity-influencing parameters. The results provide both theoretical insights and practical strategies for the efficient development of Xu-2 matrix reservoirs.