Lessons Learned from Specified Fracturing Design for Pilot Deep Shale Gas Wells with High Risk of Fracture Hits and Casing Deformation: A Successful Story in the Southern Sichuan Basin
Authors: Zeng Jie , Wang Yezhong , Chen Ke , Wang Jiaxin , Qin Meng , Guo Jianchun , Zhao Zhihong , Lu Cong , Ren Shan , Liu Bin , Li Yangyang 
Published: April 2024

Abstract
Over 65% of shale gas resources in the Sichuan Basin are stored in deep shale formations with a depth larger than 3500 m. Due to the complex tectonic deformations throughout the geological history, there are remarkable challenges for efficient stimulation of these reservoirs. First, the horizontal wells drilled from the same platform are usually penetrated by single large-scale natural fractures/faults, providing high risk of fracture hits. Secondly, natural fracture slip induces casing deformation, resulting in the failure of wellbore integrity and loss of potential fracturing stages. Thirdly, the high horizontal principal stress difference makes it difficult to create complex fracture networks, while the tractive effect makes hydraulic fracture propagates along large-scale natural fractures/faults, reducing fracture complexity.
To overcome these challenges, specified fracturing strategies were designed and applied to different stages of seven pilot wells to evaluate their efficiency. The contribution of each stage is analyzed via production logging. For less naturally fractured stages, high-intensity fracturing (highest fluid pumping rate: 13.5~20.2 m3/min and sand loading value: 1.5~3.1 t/m) was applied to maximize stimulated reservoir volume (SRV). For some stages from different wells but penetrated and connected by a single large-scale natural fracture/fault, the stage in one well used the perforation-only strategy, while the adjacent wells’ stages utilized lower-intensity fracturing (highest fluid pumping rate: 14~16 m3/min and sand loading value: 1~2.1 t/m) to mitigate fracture hits. For all the stages in highly naturally fractured area (HNFA), longer-stage and more-cluster design (generally 80~100 m per stage with 8~12 clusters) was used to prevent casing deformation and reduce the cost. Moreover, in well E, two stages with high risk of fracture hits tested a novel fracture-hit-mitigation method involving temporary plugging of fracture tips of the SRV to control fracture propagation towards adjacent wells and initiate fracture branches to increase fracture complexity. All these strategies work synergistically to reduce casing deformation, mitigate cross-well communication, and create more complex fractures.
No casing deformation and slight fracture hits (less than 5.6 MPa pressure rise of adjacent wells) were observed. Several perforation-only stages offer similar productivity compared with high-intensity fractured adjacent stages of the same well, indicating the success of the perforation-only strategy in HNFA. For the stages in different wells but penetrated by a single large-scale natural fracture/fault, lower-intensity fractured stages perform normally better than the perforation-only stages (1 to 1.55 times in productivity). The novel temporary-plugging-treated stage with low fracturing intensity even shows higher productivity compared with the adjacent high-intensity stimulated stage of the same well (1.53 times).
Perforation-only stages should be sandwiched by lower-intensity fractured stages to reduce the cost and minimize fracture hits and casing deformation in HNFA.