Refracturing can effectively enhance hydrocarbon production from hydraulically fractured wells. Using self-degradable diverting agents, people can temporarily plug previously generated fractures, and generate a new pair of fractures perpendicular to the direction of the original maximum principle stress (i.e., near-wellbore temporary plugging and diverting technique). To simulate the plugging and diverting process, a numerical model is established using the cohesive zone model (CZM) based on the extended finite element method (XFEM). After this model is verified by the published laboratory testing results, it is applied to understand the influences of stress contrast, formation permeability, rock tensile strength, Young's modulus and injection rate, so as to improve the applicability of temporary plugging and diverting technique under various reservoir conditions. Furthermore, “deflection angle” is proposed to quantitatively analyze the simulation results. This new concept enables the comparison among various cases without the restrictions of fracture length and simulation time. Simulation results indicate that: (1) with increases of stress contrast, rock permeability and Young's modulus, the diverting fractures reorient to the direction of the preferred fracture plane (PFP) more rapidly, which reduces the effectiveness of this technique; (2) propping previously-formed fractures can create higher defection angles of the diverting fractures, which enhances the effectiveness of this technique; (3) enhancing the injection rate can also enhance the effectiveness of this technique, yet there is one optimal injection rate for a given reservoirs. This study provides a systematic guideline for optimizing the temporary plugging and diverting technique under different reservoir conditions.