Laboratory derived geomechanical properties from core samples and well logs are always associated with some degree of uncertainty due to difficulties of mimicking actual reservoir conditions in the laboratory. Narrowing down this uncertainty is essential for proper design of drilling programs, surface water injection facilities and downhole completions, especially in the case of newly discovered and undeveloped reservoirs. For tight oil and gas reservoirs, where multistage hydraulic fracturing is being utilized for enhanced well productivity and injectivity through multiple transverse and longitudinal fractures, the success of field development depends directly on the ability to establish accurate geomechanical properties for use in the design of these fractures. In fact, achieving the right design parameters during hydraulic fracture execution using accurate rock mechanical properties has direct and positive effect on the productivity or injectivity of the fractured well. This paper presents a methodology of incorporating data from the microfracturing test into a comprehensive geomechanical model to determine the direction and magnitudes of in-situ reservoir stresses and other rock mechanical properties. A field case involving a recent microfracturing test conducted in a new tight oil reservoir under development in Saudi Arabia will be used to demonstrate how uncertainties in the geomechanical properties is significantly minimized to achieve better rock parameters for multistage fracture design. Finally, the results are validated with an actual hydraulic acid fracture job.