Fracture characterization is necessary to evaluate fracturing operations and forecast well performance. However, it is challenging to quantitatively characterize the complex fracture network in shale gas reservoirs because of the unknown density and reactivation of natural fractures. The flowback water transients can provide useful information about the complexity of the fracture network after the fracturing operations. In this paper, a mathematical model for modeling fracturing fluid flowback of hydraulically fractured shale gas wells is established. This proposed model characterizes the flow of water and gas in a hydraulic fracture-induced natural fracture–shale matrix system. Hydraulic, capillary, and osmotic convections; gas adsorption; and natural fracture closure are considered in this model. Flowback simulation of a hydraulically fractured shale gas well is conducted using the developed numerical simulator, and the water/gas transients between hydraulic fractures, natural fractures, and matrix are obtained. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China, are used for comparison of the flowback data with the model results. The good match of the two water transients provides a group of fracture network parameters, that is, the effective length and conductivity of main hydraulic fractures and the density of induced natural fractures. The proposed model for describing the flowback process and its meaningful relationship with the fracture–network complexity provides an alternative approach for post-stimulation evaluation.