The reservoir in the Anyue gas field, located in the Sichuan basin of China, belongs to the second member of the Dengying formation and has distinctive geological features. It is characterized by strong heterogeneity, low porosity, low permeability, and locally developed natural fractures. The reservoir space consists primarily of corrosion holes, natural fractures, and similar voids. Moreover, the lower reservoir exhibits high water saturation and a homogeneous bottom-water interface. Since it is a carbonate-based hydrocarbon reservoir with low porosity and permeability, deep acid fracturing has proven to be an efficient method for enhancing individual well production. However, the reconstruction of the second member of the Dengying formation reservoir poses significant challenges. The reservoir contains high-angle natural fractures, small vertical stress differences, and is located in close proximity to the gas–water interface. As a result, it becomes difficult to control the height of the acid break. Improper acid break treatment may easily result in water production affecting gas well production. To explore ways to control the longitudinal extension of acid fractures, 3D numerical models focusing on the initiation and expansion of acid fractures have been developed. This model takes into account geological and engineering factors such as stress differences, acid fracture displacements and scales, and their effects on the longitudinal extension of acid fractures. It was revealed that the pressure difference is the main controlling factor for the acid fracture height, followed by the reservoir thickness, the interlayer thickness, and the viscosity of the working fluid. Technical countermeasures for controlled fracture and high-acid fracturing tailored to different reservoir characteristics have been proposed, and design parameters for controlled fracture and high-acid fracturing can be optimized. By effectively controlling the vertical extension of the acid fracture, it is possible to maximize production from a single well while avoiding interference from the lower water layer. This study provides theoretical guidance for the application of deep-acid-fracturing techniques in low-permeability bottom-water gas reservoirs.

Wellbore instability severely constrains the exploration and development of shale gas. In order to evaluate the impacts of anisotropy and water on wellbore instability, three different types of criteria are fitted to strength data of LMX shales with different moisture contents. A new model of transversely isotropic borehole stability considering compliance incremental tensor induced by natural fractures is proposed, then a more preferred drilling direction is performed by the new model. Results indicated that, Pariseau’s model is more attractive in predicting shale strength, including the difference of strength between vertical bedding and parallel bedding. Based on Pariseau’s model, the prediction accuracy of shale strength is improved by 33.04%. The Pariseau’ model gives a disparate collapse pressure from Jæger’s weak plane criterion, the most unstable drilling area shifts from northeast and southwest to the central area corresponding to relatively lower inclination. The collapse pressure only decreased by 0.55 MPa with considering the anisotropy of elastic parameters, but the strength criteria have a distinct influence. Compared with the results predicted by Jæger’s plane of weakness, the collapse pressure increased by 8.55 MPa using Pariseau’ model. Besides, invasion of water in bedding plane will aggravate borehole instability, especially in late drilling period, collapse pressure for the vertical wellbore increased by 6.35 MPa. Shale strength depends not only on the hydrostatic pressure and orientation angle, but also on the water content, which should be considered in mud weight design and well trajectory optimum.