Effect of Fracturing Fluids on Fracture Conductivity
Authors: Cooke C.E. 
Published: December 2007

Several types of fracturing fluids were tested for potential adverse effects on fracture conductivity. A predictive method based on the volume of residue in a fluid after it degrades was developed that describes the local effect of fluid residue on fracture conductivity.

Introduction
Fracturing fluids containing water normally are increased in viscosity by adding water-soluble polymers to the water phase. The fluids are designed to decrease in viscosity after the treatment is complete to facilitate fracturing fluid recovery and to allow greater production rates from the well soon after the treatment. The viscosity decrease results from thermal degradation of the polymers or from chemical "breakers" in the water that polymers or from chemical "breakers" in the water that degrade the polymers. The degraded polymer consists of smaller, water-soluble molecules and any residue that is not made water-soluble by the breaker.
The polymer most commonly used to increase the viscosity of fracturing fluids is guar gum, a natural product extracted from the guar bean. Degraded guar gum product extracted from the guar bean. Degraded guar gum is not completely water soluble; Fig. 1 shows the residue left after guar polymer solution was degraded. Another polymer (less commonly used because it is more expensive polymer (less commonly used because it is more expensive than guar) is modified cellulose. The amount of residue left by this polymer is much less than from guar. A third type of water-soluble polymer sometimes used for fracturing fluids (mainly high-temperature applications) is polyacrylamide, a completely synthetic polymer that leaves polyacrylamide, a completely synthetic polymer that leaves no residue after degradation.
A fracturing fluid commonly used in many fields is an emulsion of brine and hydrocarbon; it contains about one-third by volume brine phase and two-thirds by volume oil phase. This polymer emulsion is widely accepted because of phase. This polymer emulsion is widely accepted because of its lower cost and its desirable viscosity behavior for a wide range of applications. The emulsion can be used with any of the three types of water-soluble polymers added to the aqueous phase, but guar gum is the polymer that is normally used.
During a fracturing operation it is desirable to minimize loss of fracturing fluids from the fracture into the reservoir. This is accomplished by adding finely divided solids, called fluid-loss additives, to the fracturing fluid. The function of these materials is to plug the pore spaces of the rock at the faces of the fracture. plug the pore spaces of the rock at the faces of the fracture. Some questions concerning the use of these additives naturally arise: Do they have a significant effect on the permeability of the proppant in the fracture? Are they displaced off the face of the fracture after being deposited there? Are they mobile and free to move through the fracture when the well is put on production? A recent papers reported that fluid-loss additives do cause very large decreases in sand permeability. It should be noted, however, that the tests were not performed under conditions that simulated stress on a fracture.
For a given fracture geometry, fluid conductivity of the fracture determines the amount of stimulation that is achieved. In gas wells, turbulent flow normally decreases conductivity, and this significantly increases the importance of avoiding damage to conductivity by the fracturing fluid.
This paper describes a theoretical model that can be used in evaluating the effect of fracturing fluids on fracture conductivity, gives results of experiments in which fluids were tested in simulated fractures, compares model predictions with results of the laboratory experiments, predictions with results of the laboratory experiments, and discusses implications of the results.
JPT
P. 1273