The Late Devonian-Early Mississippian Woodford shale is known as the main source rock in the state of Oklahoma, and one of the most attractive unconventional plays in the U.S. Early Woodford’s exploration and development was primarily focused on gas-rich plays, especially those in the Arkoma Basin. Nonetheless, liquid-rich plays have been rapidly emerging in recent years. The liquid-rich SCOOP (South Central Oklahoma Oil Province) play within Oklahoma’s Anadarko Basin has become of great interest for oil companies due to its noteworthy production of oil and condensates. The Woodford shale is categorized as an organic-rich siliceous shale and consists of alternating beds of fissile and non-fissile shales with cherty beds. Its varying thickness intervals and variable stratigraphy make it one of the most complex shales in North America. High treatment pressures and fracture gradients, proppant flowback, and pressure-dependent leakoff are some of the factors that have a significant impact on the success of the fracturing treatments in the Woodford. Hence, for the economic development of the Woodford, or any other shale play, it is important to be able to predict and evaluate well performance accurately considering all possible outcomes. The scope of this study is to integrate geologic and hydraulic fracture models to accurately predict and evaluate production performance of multi-stage hydraulic fractured well in the SCOOP play of the Woodford shale. A 3D static reservoir model was built based on log data from eight wells located in Grady County, Oklahoma. Interpretations from outcrops and previous studies were also used to create the stratigraphic/structural framework. Principal component analysis (PCA) and k-means clustering techniques were implemented to classify rock types and generate the lithofacies model using Sequential Indicator Simulation (SIS). Petrophysical and geomechanical properties were estimated from well log data and modeled using Sequential Gaussian Simulation (SGS). The resulting geomechanical model was used as input for hydraulic fracture modeling. Eight stimulation treatment designs were evaluated on a single horizontal well to understand the impact of key factors, such as stress, proppant type, and pressure-dependent leakoff on the resulting stimulated reservoir volume. Lastly, the geologic and hydraulic fracture models were coupled into a numerical reservoir simulator to predict and evaluate well performance. This study illustrated the importance of reservoir characterization and geomechanical modeling for hydraulic fracture design and well performance evaluation. The 3D geologic model confirmed the lateral and vertical heterogeneity of the Woodford shale and its adjacent formations within the study area. The stratigraphic variability captured in the model had an impact on the geomechanical properties and hydraulic fracture modeling. Total stress, pressure-dependent leakoff, and proppant type demonstrated to have a significant effect on the stimulated reservoir volume size and fracture conductivity. Additional work should be performed to understand the coupling of geomechanics and reservoir simulation further.