Due to gas pipeline infrastructure constraints, gas produced in many basins remains stranded. Innovative ways to utilize the produced gas are required. Additionally, the cost of frac-water is high in many areas. In this paper, we conduct a detailed technical feasibility study on using this excess natural gas (NG) as a fracturing fluid. Comparison is also made with typical water-based fluids in terms of fracture propagation, flowback efficiency, and long-term oil and gas production. In this study, we present and utilize a fully integrated 3-D geomechanical, equation-of-state (EOS) compositional hydraulic fracturing and reservoir simulator. The fracturing and reservoir simulations were performed using published datasets from the Permian Basin and experiments on NG foam rheology. The phase behavior of the injected water/gas/foam and reservoir hydrocarbon fluids is considered using an EOS-based compositional calculation. Differences in fracture geometry and fracture/matrix conductivity (proppant embedment and oil flowback relative permeabilities) for foam-based vs slick-water fracturing fluids are compared. An empirical fracture closure model from published experimental studies is incorporated into the simulator during flowback to accurately model the changes in fracture conductivity during production. Well flowback, productivity, and oil/gas production when using NG foams are compared with conventional water-based fluids. Simulation results clearly show that NG foam fracturing fluids achieved improved breakdown pressures, lower fluid leakoff and higher cluster efficiency than slick-water fluids. Due to their higher viscosity NG foams resulted in shorter created fracture lengths with larger fracture width. However, since proppant settling is drastically reduced, the created fractures are much more uniformly propped. Our results clearly show that the improved proppant placement, enhanced stimulated rock volume (SRV) permeability as well as the presence of expandable natural gas around the fractures leads to higher oil production and significantly better unloading and flowback of frac fluids in the case of NG foam. Our results also shown a significant reduction of water usage and considerable natural gas consumption using NG foam for fracturing. In this work we present, for the first time, the detailed technical feasibility of using stranded natural gas as a fracturing fluid. A new fully compositional fracturing-reservoir simulator that captures phase behavior and fracture closure effects while designing completions using non-water based fracturing fluids makes this analysis possible. This study will help shale operators to evaluate the viability of utilizing their stranded gas as a fracturing fluid.