Sandstone injectite intrusions are generally developed by the fluidization of weakly cemented sandstones and their subsequent injection into fractured reservoirs. In this work, a continuum coupled hydromechanical model TOUGH-FLAC3D is applied to simulate the discrete fracture network in large-scale sand injectite complexes. A sand production constitutive model is incorporated to consider the formation of sand through plastic deformation and its influence on evolution of fracture permeability. Overpressures in the fluidized sand slurry drives the injection with sand dikes intruded upwards, typically into previously low permeability tight mudstone formations. The contrast in poroelastic properties of the underlying weak sandstone and overlying injectite receptor directly affects the evolution of fracture aperture both during and after intrusion. Fluid drainage into the unconsolidated matrix may reduce the extent of fracture aperture growth, through the formation of shear bands. The results of this work have broad implications related to the emplacement of sandstone intrusions and subsequent hydrocarbon accumulation, maturation and then production.