Sand production from unconsolidated sandstone reservoirs is one of the fundamental challenges in the oil industry, leading to equipment erosion, reduced productivity, and increased operational costs. Hydraulic fracturing, although primarily performed to enhance permeability and stimulate the reservoir, can affect wellbore stability and the phenomenon of sand production. However, a quantitative understanding of how the geometric characteristics of hydraulic fractures (such as density and length of cracks) influence sand production rates, especially in moderately cemented reservoirs, remains limited. In this study, a two-dimensional model based on the Discrete Element Method (DEM) has been developed in the PFC2D software to integrally simulate the hydraulic fracture propagation process and the subsequent sand production in three different sections of a real well in the Azadegan oil field. The model was calibrated using triaxial laboratory data, and the relative error in predicting the uniaxial compressive strength was about 10.5%. After applying realistic boundary conditions including in-situ stresses, reservoir pressure, and production pressure, the model was run for three sections with different fracturing histories. Quantitative results showed that in Section 1, which had the highest fracture density and length, the cumulative sand production after two days was significantly lower than in Section 3, which had the least fracturing. The key finding indicates that, under the studied geomechanical conditions, the presence of extensive and dense hydraulic fracturing is associated with reduced sand production. This phenomenon can be attributed to the formation of stable stress arches behind the fractured zones, which counteract the fluid drag force and prevent particle detachment. This integrated simulation approach provides a powerful tool for petroleum engineers to simultaneously optimize hydraulic fracturing design and manage sand production.