Polysaccharide Derivatives Provide High Viscosity and Low Friction at Low Surface Fluid Temperatures
- J.L. White (Dowell Div. of Dow Chemical U.S.A.) | J.O. Means (Dowell Div. of Dow Chemical U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1975
- Document Type
- Journal Paper
- 1,067 - 1,073
- 1975. Society of Petroleum Engineers
- 0 in the last 30 days
- 171 since 2007
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A relatively new, low-damage aqueous thickener with improved fracturing fluid properties is described. The polysaccharide derivative is effective in continuous mixing with low surface fluid temperatures and achieves high viscosity and low friction much more rapidly than conventional thickeners.
Continuous mixing of gelled aqueous fracturing fluids is desirable because it reduces treating time and equipment and storage requirements, and eliminates batch mixing of large volumes of fluid that might not be used. In the past, the time required for conventional thickeners to achieve friction reduction and viscosity, particularly with cold fluids, has limited continuous mixing as a treating technique during cold weather and in shallow wells with low bottom-hole temperatures. New, low-residue polysaccharide derivatives have now been developed, however, that achieve high viscosity and low friction much more rapidly than conventional thickeners. For example, in 40 degree water, the new thickener can reduce friction up to three times more effectively than the conventional thickeners and can also provide viscosities up to four times greater. The advantages of low-residue fluids for minimizing damage and, hence, potential losses in production are discussed. The proper use and design criteria for low-residue systems are examined.
Continuous mixing with the thickener permits using higher breaker concentrations to reduce shut-in times, thus providing faster, more effective well cleanup. In conjunction with the new gelling agent, additives such as clay control agents and new surfactants are used to shorten cleanup times by as much as one-half and to increase fracturing fluid recovery two to three times over conventional water-based treatments. It appears to be a growing opinion in the industry that short shut-in times for minimizing fluid retention may be a key to improved production by fracturing.
During the past several years, many new fracturing fluids have been developed. In many cases, these fluids met specific requirements such as high temperature stability, low formation damage, more rapid cleanup, or ultrahigh viscosity.
Guar gum has been an effective gelling agent in fracturing fluids for many years. In most aqueous-base conventional fracture treatments, guar gum is still the thickener most commonly used. Guar gum generally meets the basic requirements of an efficient and economical fracturing fluid. Guar gum gives low friction pressures, good viscosity in a variety of brines, low fluid loss, pressures, good viscosity in a variety of brines, low fluid loss, and effective breakdown control following the treatment. The fluid-loss control of guar gum is particularly effective as compared with other aqueous thickeners.
The major objection to guar gum has been an insoluble residue component that potentially could cause damage. Although petroleum guar products are more highly refined than other guar products, they contain almost 10 percent residue. Guar gum residue may or may not be detrimental to formation permeability or fracture conductivity, depending on conditions. permeability or fracture conductivity, depending on conditions. If damage occurs to permeability or fracture conductivity, the effect on productivity should be based on the well and treating conditions. Pye and Smith and Cooke have discussed the effect of guar gum and fluid-loss additives on formation damage and damage to fracture conductivity.
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