We compare hydromechanical simulation results that use two alternative sources of 3D digital rock input: microCT analysis and synthetic rocks created using a newly developed process simulation methodology that more rigorously reflects knowledge from sedimentary petrology compared to previous efforts. We evaluate performance for these alternative representations using St. Peter Sandstone samples where dry static bulk modulus (K) and shear modulus (G) are simulated using a new extension of the Material Point Method that resolves contacts using high-resolution surface meshes and that considers three alternative contact modeling approaches: purely frictional, fully bonded, and cohesive zones. We evaluate model performance on two samples from the dataset with multiple static moduli measurements (sample 1_2: porosity 24.6 vol%: K 10.2 14.7 GPa, G 11.6 14.0 GP; sample 11_2: porosity 12.4 vol%: K 13.5 24.6 GPa, G 12.8 17.9 GPa). Purely frictional results underpredict measured modulus values whereas fully bonded results overpredict them. Measured values are most closely approximated by results with cohesive zones that consider sets of discrete spring-like features at contacts. Shear modulus results from FEM simulations on structured grids, by contrast, tend to be significantly greater than measured values, particularly for samples with lt; 18 vol% porosity. Permeability values from digital rock physics simulations for the studied samples are within factors of 2 5 of conventional core analysis measurements (2860 and 58 md for sample 1_2 and 11_2, respectively). We demonstrate that the process modeling approach (1) accurately reproduces measured rock microstructure parameters from thin section analysis, (2) leads to simulation results for dry static moduli and permeability of comparable accuracy to simulations that employ microCT samples, and (3) provides a rigorous basis for predicting diagenetically induced variations in hydromechanical properties over the range from unconsolidated sand to indurated rock.