As the development of unconventional (e.g., tight gas, shales, coalbed methane) and under-pressured reservoirs has increased, so has the demand for innovative hydraulic fracture designs. The use of gases and foams has experienced a significant resurgence in popularity with the development of unconventional reservoirs and with the growing limitations on water supply in some areas. Until recently, the tools available for fracture design were not capable of modeling hydraulic fracturing with compressible fluids and non-isothermal treatments. Ribeiro and Sharma (2012b) presented a model that was capable of simulating hydraulic fracturing treatments with multi-phase, compressible fracturing fluids with changing temperature, phase behavior, and multi-phase leak-off during the treatment. The main objective of this paper is to show how such a model can be used for screening fracturing fluid candidates and for optimizing energized fracture treatments.

In conducting this study, we have combined this 3-D compositional fracturing model with a multi-phase well-productivity model for hydraulically fractured wells. This paper presents results for slick water, linear gel, gelled CO2, gelled LPG, N2 foams and CO2 foams in a low permeability reservoir. The simulations showed that good proppant placement and high fracture conductivities can be achieved with foams and gelled fluid formulations. LPG, CO2, and high-quality foams prevent water invasion so they do not impede gas recovery because of water blocking or gel induced damage. In addition, several reservoir parameters appear to control well productivity and therefore fluid selection: (1) relative permeability curves, (2) initial gas saturation, (3) reservoir pressure, and (4) sensitivity to water. The benefits and disadvantages that must be considered when selecting a fracturing fluid are highlighted in this paper and a methodology is proposed to quantify these pros and cons.

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