Effects of High Temperature on Polymer Degradation and Cleanup
Authors: Samuelson M.L. , Constien V.G. 
Published: December 2007

Abstract
Production from high temperature gas wells is strongly related to effective fracture length. Previous literature has described the importance of degrading gelling agents to very low molecular weights in order to minimize mobility ratio differences between the fracturing fluid and gas during cleanup, so that viscous fingering and channeling do not leave large unproductive areas in the propped fractures. However, degraded guar-based fluids at high temperature tend to form insoluble fragments as the backbone is reduced to low molecular weights. The problem in maximizing cleanup and effective frac length is then one of degrading the guar sufficiently so that viscous fingering is minimized while preventing the formation of insoluble material. Recent analysis of flowback from gas wells indicates that channeling is indeed a problem.
This paper presents laboratory data of degraded fracturing fluids at temperatures above 180 F using laboratory fracture conductivity results and residual polymer analysis. Field data is presented which indicate current trends in polymer cleanup at these temperatures.

Introduction
The success of a fracturing operation ultimately depends on the cumulative production increase resulting from the treatment. The chemistry of the fracturing fluid which is utilized in high temperature gas wells and the physical processes during the multiphase flow cleanup determine the fracture area from which production will occur.
To provide the industry better fracture stimulation at lower cost, an improved understanding of guar/breaker interactions and the flow processes which occur at high temperatures is needed. Recent work by Pope et al and Penny and Jin have given insight into the impact of gel concentration, multiphase flow and viscous fingering on cleanup of fracturing fluids in gas wells. In a field flowback study by Pope et al, a relationship was suggested between gas production and fracturing fluid polymer returned from the well. Concurrent with this field study, laboratory work was being completed which defined the relationship between polymer mass remaining in the proppant pack and loss of pack porosity. This paper will illustrate these results.

Damage Mechanisms
Permeability reduction in a proppant pack is the result of a reduction of pack porosity. Factors such as viscous fingering, fines generated by proppant crushing and polymer residue from fracturing fluids can physically occupy pore spaces in the proppant pack, thus reducing its porosity and permeability. The effect of viscous fingering on fracture conductivity damage was discussed in reference 1 for the temperature range of 125-175 F. Other factors in addition to purely viscous effects become important in conductivity damage at higher temperatures. For example, the intrinsic viscosity of a guar molecule has been found to decrease with increasing temperature indicating the polymer is becoming less soluble. This hydrophobic property of the polymer will tend to make the molecules conglomerate together, especially after they are broken down into fragments by chemical breakers or hydrolysis by temperature. This aggregation may increase their ability to block pore spaces in the proppant pack or more importantly, pore throat spaces. Blocking a pore throat will essentially remove the corresponding pore volume from availability for flow. Therefore, the resulting aggregates may block an effective volume to flow that is much larger than the volume which they physically occupy. In order to maximize retained permeability, it is necessary to either prevent the aggregates from forming or mobilize them once they have formed.
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