High-Precision Numerical Simulation of Fracturing Flowback in Shale Gas Wells: A Case Study of Changning Block

Multi-stage fracturing of shale gas is currently the core technology for achieving the economic development of shale gas. However, during post-fracturing production, issues such as fracture closure, proppant backflow, and fracturing fluid loss can inevitably occur, causing damage to the reservoir. To investigate the backflow performance of shale gas fracturing, this study establishes a high-precision fluid–solid coupled geomechanical model based on actual data from Changning shale gas wells and performs history matching. The history matching results indicate that neglecting factors such as geomechanics and capillary pressure leads to overly smooth curves, poor convergence, and results inconsistent with the actual production trends. A comprehensive model incorporating gas adsorption, geomechanics, capillary pressure, and secondary fractures provides the best fit. After validating the model’s accuracy, the effects of proppant concentration, proppant injection method, fracture parameters, well spacing, and fracturing design on fracturing backflow were analyzed. The study shows that proppant concentration, distribution pattern, fracture geometry, and well spacing are key factors influencing the effectiveness of shale gas fracturing stimulation. An optimal proppant concentration exists, as excessively high concentrations accelerate fracture closure and reduce production gains. Proppants should be primarily distributed near the wellbore to ensure high production and sufficient backflow. Fracture spacing and half-length should be optimized to balance production increase and fracturing fluid retention. Among the vertically non-uniform fracture distributions, staggered patterns offer the highest production potential, while uniform distributions yield the best backflow performance. In the Changning shale gas region, a well spacing of 300 m is recommended, and zipper fracturing can improve backflow efficiency.