The Upper Devonian-age black shale of the Central Appalachian basin has been a major natural gas production reservoir since the initial discovery in 1921. In the ensuing 80 years, an assortment of drilling and completion techniques have been applied to the black shale with varying degrees of success. Recent efforts at improving well productivity have focused on improving the hydraulic fracturing operations, especially the minimization of fluid damage to the targeted shale reservoirs. The development of fluid systems with lower polymer loadings has been an important achievement in this effort. Recently, polymer-free viscoelastic surfactant-based (VES) fluid systems have been used in the hydraulic fracturing industry as a final step in the elimination of polymer-based damage. A statistical study of the application of a VES foam fracturing fluid in the Central Appalachian basin was performed. The study compared recent results of polymer-free treatments to traditional completions throughout the field. Results from the polymer-free completions were compared to immediate offsets drilled in the same time frame and completed in correlated intervals. In general, the use of polymer-free fluids improved well productivity, when compared to wells that were completed with a conventional polymer-based fluid. The study also compared the economic impact of the use of VES completion fluids from both an operations and production perspective. Introduction Fracturing fluid is a critical component of a hydraulic fracturing treatment. The characteristics of this fluid includesufficient viscosity to suspend and transport the proppant in the created fracture andability to break into a low-viscosity fluid after the completion of the treatment so that a rapid flowback of the fluid to the surface is achieved, andnon-damaging to the reservoir. Polymers (guar or their derivatives) have historically been used for this purpose because of their excellent viscosifying characteristics. However, a recent study has shown that only 30 to 45% of the of the guar-based polymers pumped during a treatment returned to surface during the flowback period.[1] This indicated that a substantial amount of the polymer remained in the proppant pack or as a filtercake on the fracture face. Further, studies have shown that polymer residues that remain in the proppant pack reduce the proppant-pack permeability, thus resulting in a loss of effectiveness of the hydraulic fracture treatment.[2] To offset the negative effects of polymer residue, a VES polymer-free fluid system has been developed. This VES fluid relies on the presence of a hydrophilic water-soluble ionic group and hydrophobic hydrocarbon-soluble chain within a single molecule of the surfactant. In the presence of water the molecules form micelles similar in shape to polymer molecules. The resulting fluid is similar to a cross-linked guar-based gel but without the need for a cross-linker. When organics (such as oil or natural gas) dissolve in this VES fluid, the micelles change from a rod shape to a spherical shape. This change reduces the viscosity of the VES fluid to that of a brine without the need of a chemical or enzyme breaker.[3] Therefore, a VES fluid rapidly flows back after a hydraulic fracture treatment with no gel residue or filtercake remaining in the proppant pack. To assess the impact of this VES fluid on well performance, a comparative statistical study was performed in the Central Appalachian basin gas field. The reservoirs in this area are normally under-pressured and nitrogen foam fluids are typically used. In this study, wells that were hydraulically fractured with the VES fluid were compared with wells fractured with conventional guar-based fluids. Production indicators--- gas production rate, best 6 months of production, etc.---were the basis for comparison and economic analysis and provide the basis for measurement of the effect.

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