Sand-conglomerate reservoir has been scarcely studied, and there is no effective method available for quantitative characterization of pore structure of such a reservoir. In this paper, a multifractal study was made on the Triassic Karamay Formation sand-conglomerate reservoir in the Mahu rim region, the Junggar Basin, by using a variety of high-resolution analysis methods, such as Micro-CT, QEMSCAN, and MAPS, in order to quantitatively characterize the heterogeneity of pore size distribution, relative differentiation of large and small pores, and mineral composition. The results reveal that the multifractal parameters have more influence on permeability than on porosity. The smaller the Delta alpha (the multifractal spectral width) and the larger the Of (the difference in fractal dimension of the maximum and minimum probability subsets), the better the reservoir physical property. To some extent, the relationship between multifractal parameters and mineral composition provides an opportunity to reflect the diagenesis. There is a positive correlation between the clay mineral content and the heterogeneity of the microscopic pore structure of the reservoir. Kaolinite and chlorite cementations are the most significant factors that damage the reservoir pore space. This understanding matches well with the MAPS and QEMSCAN results. With outstanding advantage in quantitatively evaluating the heterogeneity of pore structure of sand-conglomerate reservoir, multifractal theory provides a new idea and method for quantitative characterization of pore structure of other types of heterogeneous oil reservoirs.