A complex fracture networks formed by hydraulic fracturing is an important guarantee for gaining a high production of shale gas Wells. Objective evaluation of the distribution characteristics of the fracture networks is conducive to guiding the optimization of fracturing construction parameters and development technology policies. However, it is difficult to accurately reveal the matching relationship between the control area of secondary fracture zone and primary fracture zone by existing methods. In this study, a numerical well-testing model for shale gas Wells is constructed to analyze the gas flow characteristics under the differential distribution of fracture networks, and to explore a method to quantitative characterize the distribution of the fracture networks. The results show that the gas flow in shale gas wells can be divided into the following stages: wellbore accumulation effect, fracture transition flow, fracture linear flow, fracture radial flow, system transition flow, system linear flow, system radial flow and boundary effect. The larger the area proportion of the main fracture zone (DRV), the larger the difference between the pressure and the pressure derivative of the fracture radial flow phase of on the well-testing characteristic curve. The larger the proportion of secondary fracture area, the larger the slope of the system linear phase of the curve. The larger the distribution index (FNDI) is, the higher the proportion of DRV is. The smaller the FNDI value, the lower the DRV ratio and the higher the secondary fracture density. It indicated that FNDI calculation method established in this study can provide a basis for the optimal design of production pressure drop path under different fracture networks distribution, which can support the optimization of pressure controlled production system considering the protection of fracture networks diversion capacity for shale gas wells.