Oil and gas operations in sedimentary basins have revealed significant temperatures at depth, raising the possibility of major geothermal resource potential in the sedimentary sequences. The efficient development of such a resource may require enhancement by hydraulic stimulation. However, effective stimulation relies on an initial assessment of in-situ mechanical properties and a Discrete Fracture Network (DFN) model of the rock response. Here, we examine the distribution of mechanical properties (unconfined compressive strength, UCS ; ultrasonic velocity-derived Poisson ratio, ν; and, scratch-derived fracture toughness, K s ) along the cored interval of a sedimentary formation with a known geothermal anomaly in the Permian Basin, U.S. Our results reveal the mechanical heterogeneity of the rock, demonstrated by four distinct alternating mechanical zones, which include: (1.) mechanically weaker 0.17 m-thick Zone-A and 0.18 m-thick Zone-C with mean UCS = 110 MPa, ν = 0.25, K s = 1.89 MPa·√m; and (2.) mechanically stronger 0.41 m-thick Zone-B and 0.15 m-thick Zone-D which show mean UCS = 166 MPa, ν = 0.22, and K s = 2.87 MPa·√m. Although X-ray Diffraction analyses of the samples suggest that the entire rock matrix is dominated by dolomite, the stronger zones show a higher abundance of quartz (>30%) and relatively lower phyllosilicate mineral content (<2%) than the weaker zones. Further, we observe that the mechanically stronger zones have the greatest occurrences of hydrothermal alterations (anhydrite veins and nodules ), indicating that the cored interval had experienced hydrothermal fluid circulation in the past. We infer that the denser clustering of fractures in the stronger zones which facilitated the hydrothermal vein development was due to the influence of mechanical stratigraphy on the brittle deformation and alteration of the sedimentary-hosted hydrothermal reservoir. Thus, we suggest that the stronger zones represent viable targets for hydraulic stimulation of a geothermal reservoir, both for the emplacement of new fractures and the linkage of pre-existing fractures. Our findings in this study provide an analog for hydraulic stimulation of viable geothermal reservoir targets at higher in-situ temperatures and higher geothermal gradients.