Tight conglomerate reservoirs commonly develop tortuous fractures with pronounced three-dimensional geometric heterogeneity during hydraulic fracturing. Fracture-surface undulation and spatial tortuosity exert significant control on fluid distribution and proppant deposition within fractures. However, most existing studies are based on two-dimensional or idealized fracture models, which fail to capture the true geometric characteristics of conglomerate fractures. Large-scale true triaxial hydraulic-fracturing physical simulation experiments were conducted to obtain the three-dimensional fracture-surface morphology of the Mahu tight conglomerate reservoir, and the spatial distributions of fracture tortuosity and relative undulation were quantified. Based on these experimental observations, a three-dimensional tortuous fracture numerical model incorporating wellbore-multi-cluster coupling and fracture-surface undulation was established. Proppant transport and placement behavior within fractures were simulated using an Euler-Euler two-phase flow approach. Model reliability was verified by comparison with published experimental results of sand-pile morphology and height distribution, yielding a combined relative error of 6.3% for the main-fracture sand-pile height. The results indicate that fracture tortuosity significantly alters the local flow field, promoting the formation of low-velocity and proppant-retention zones at tortuous segments and leading to segmented proppant deposition. In multi-cluster fracture systems, tortuous structures modify local flow resistance and pressure gradients, intensifying inter-cluster flow competition and resulting in pronounced nonuniform proppant intake. When the tortuosity ranges from 1.0 to 1.5, proppant distribution among clusters becomes most uneven. These findings provide technical guidance for multi-cluster fracturing design and proppant placement optimization in tight conglomerate reservoirs.