Numerical investigation of fracture competitive propagation mechanisms for temporary plugging staged fracturing (TPSF) in shale gas reservoirs

Abstract

Temporary plugging staged fracturing (TPSF) is a technique rapidly growing for enhancing the uniform growth of multiple fractures in shale gas reservoirs. However, the mechanisms of fracture competition during TPSF remain incompletely understood, primarily due to pre-existing natural fractures and stress interference. This study presents a fully coupled Finite Element Method (FEM) model incorporating the pore pressure cohesive zone method to investigate how fractures compete for growth in TPSF. Moreover, a user-defined perforation element connected to a discrete fracture network model is employed to analyze how fluid flow is partitioned. The results indicate that denser natural fractures (NFs) create more connections for hydraulic fractures (HFs), thereby increasing the complexity of the fracture network. Reduction in cluster spacing can result in distorted fracture morphologies and altered propagation pathways, potentially halting fracture growth. Higher injection rates elevate injection pressure, which may inhibit fracture growth but could aid in penetrating stress interference zones to generate asymmetrical fractures. Fractures tend to propagate towards larger inclination angles, with an inclination angle close to 45° being optimal for enhancing fracture growth and reservoir stimulation. This study offers valuable insights into the competitive propagation mechanism of fractures and provides guidance on optimal field design for TPSF.