In this study, simulation experiments were conducted to study the evolution of fluid inflow profiles and the formation mechanism of hotspots in non-homogeneous sand production horizontal wells using a large-scale horizontal well testing equipment. Three non-homogeneous reservoir rock models were constructed by an artificially cementing method. The experimental results show that fluid and sand production can exhibit a synergistic effect, with the difference of sand-out intensity between strongly and weakly consolidated reservoir regions increasing with the fluid production. Eventually, the sand production profile distribution is inverse to the initial compressive strength distribution, resembling the initial rock porosity and permeability distribution. Under the influence of the sand-fluid synergistic production mechanism, local high-rate inflow hotspots may emerge after long production periods. The experiments reveal that a hotspot area can contribute over 80% of the total fluid production. Due to the formation of high-rate inflow hotspots, the inflow coefficient in low consolidation strength/high porosity/high permeability regions can increase from an initial range of 0.2-0.4 to over 0.8. Meanwhile, the permeability distribution of the reservoir can shift from an initial gradual variation along the horizontal well to a highly heterogeneous distribution, with the values of permeability increasing by up to 17.5 times.