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.

The laminated structure in shale rock plays a crucial role in fluid migration during shale gas exploitation. This study investigated the evolution patterns and mechanisms of shale permeability under the influence of laminae through multiple permeability experiments, including steady-state flow tests, confined pressure permeability tests, thermo-hydro-mechanical coupled permeability tests, fracture permeability tests, and fracturing fluid damage experiments. The results show that the permeability of the shale is significantly controlled by the laminated structure. Pores and micro-cracks develop along the laminated structure direction, which is conducive to the formation of seepage channels in vertical laminated specimens, while parallel laminated specimens are affected by multiple laminated structures, resulting in lower permeability. Increasing confining pressure leads to a rapid decrease in permeability, indicating that the closure of fractures is the key factor controlling the permeability characteristics of shale. Increasing temperature causes shale to further increase permeability under the effects of thermal stress, but the enhancement effect is weakened under high confining pressure. Artificial fractures significantly enhance the permeability of shale under low confining pressure, but the closure of artificial fractures reduces the permeability effect under high confining pressure. The effect of fracturing fluid leads to a decrease in shale permeability, and the damage to shale is more significant under high confining pressure.