A large fraction of hydrocarbons is recovered from gas condensate reservoirs. A major production challenge from gas condensate reservoirs is condensate dropout, as condensate liquid saturation will build up due to drawdown below dewpoint level. Condensate Gas Ratio (CGR) decrease during production is a clear indication of condensate dropout, which reduces well deliverability. Determining the well productivity index (PI) and methods to optimize productivity is paramount to the industry. The aim of this research is to investigate fluid phase change behavior during depletion in a hydraulically fractured well in an extremely low-permeability gas condensate reservoir. Here it is considered the case where condensate dropout occurs over a large volume of reservoir, rather than just near the fracture face (condensate banking). Reservoir simulation with local grid refinement (LGR) was used to understand this phenomenon and its impact on well PI, and to quantify pressure drop in the reservoir as a result of condensate dropout. The relationship of condensate dropout, pressure drop, gas rate and reservoir permeability are investigated by comparing conventional tight reservoirs, and very tight unconventional gas condensate reservoirs, both of which are produced with propped fracture stimulation. A commercial 3-D compositional simulator with LGR around the fracture was utilized to simulate such a reservoir with both synthetic and field data by observing the compositional changes (i.e., C1, C2, C3,..) in hydrocarbon content over time and distance from the fracture face, and the results were used in turn to generate more realistic production profiles over time. Additionally, a comprehensive discussion of the model assumptions and limitations is also included. The result shows a significant change in the composition and relative permeability to gas in the reservoir as the pressure declines during depletion. The simulation is done in two parts: synthetic and field data history matching. The results illustrate the complications in understanding the PI evolution of hydraulically fractured wells in “unconventional” gas condensate reservoirs and shows how to correctly evaluate fracture performance in such a situation. This research includes a review of several techniques and methods to calculate the occurrence of condensate at various distances from the well and fracture and includes a sensitivity analysis of the different parameters and how they affect well PI over time and ultimate recovery of gas and condensate. This findings and novel approach of this study aim to more accurately predict post-fracture performance and provide a better understanding of the hydrocarbon phase change not only near the wellbore and fracture, but also deep in the reservoir, which is critical in unconventional gas condensate reservoirs.