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Abstract
The fracture propagation process using polymer-based fracturing fluids is commonly applied to increase the productivity of producing wells, especially in tight gas formations. During the fracturing operation a layer of concentrated polymer (filter cake) forms on the fracture faces, which limits the loss of fluid to the formation. However, during the production phase, the partially broken filter cake and remaining residues damage the fracture conductivity. The fracture cleanup process is complex and may suffer from the presence of a yield stress, non-Newtonian fluid in place, non-Darcy flow effects in both the fracture and matrix, crushed proppant, embedded proppant and formation spalling as well as both mechanical and hydraulic damage to the matrix near the fracture face. A previously published fast and robust single well model was applied to study the important parameters involved during the fracture cleanup process. This 3-phase, 2-D model is capable of modeling multiple parameters separately. However, the simulator code which was employed did not address the modeling of non-Darcy flow or the rock stress effects on permeability, but focused on the yield stress effects of the fracturing fluid. The simulator proved very useful for assessing the significance of reservoir capillary pressure, fracturing fluid viscosity and yield stress, formation damage, and fracture conductivity on low permeability gas reservoir production with permeabilities from 0.005 to 5 mD. These trends may not carry over to nanodarcy reservoirs, such as the gas shales. The three phases included gas, water and fracturing fluid.

Introduction
Hydraulic fracturing has been used as a successful technology to increase productivity via significantly increased contact between the wellbore and the producing formation. To propagate an open fracture into a reservoir, fracturing fluids have been used to provide the two main functions of initiating and propagating the fracture and transporting propping agents along the fracture. Guar gum is the earliest example of aqueous, viscous fluids used during the injection. The fracturing fluid must be viscous to allow the transport of the proppant during the injection and have the ability to be broken easily after the injection to maintain high conductivity during the production phase. To accomplish these tasks, cross-linkers (like borate and zirconate) and delayed breakers (either oxidizers or enzymes) are typically added to the fluid.¹

Injecting the viscous fracturing fluid results in fluid loss to the matrix and filter cake formation. Filter cakes with high polymer concentration form on the two faces of the fracture during the injection. Original fracturing fluid may remain in the fracture unless the fracture-face filter cakes occupy the entire pore space of the propped fracture following closure.² Different exposure times to fracturing fluid,³ and different proppant concentrations along the fracture cause local polymer concentration changes along the fracture. Thus breakers are seldom uniformly distributed to break the concentrated fluid completely.

At the end of a fracture treatment, there is normally a shut-in period to allow fracture closure and fluid continues to leak off into the reservoir during this stage. Alternatively, the fracture can be forced to close by flowing back some of the fracturing fluid at controlled rates to prevent disturbing the proppant pack significantly. Hydraulic fractures contain partially broken fracturing fluid, and residues remain after the breaker reacts with the guar. It has been postulated that fracturing fluids need a minimum pressure gradient to begin the cleanup process in the proppant pack,4 and this has been verified experimentally.²