Various clay stabilizers are discussed, and methods are proposed for evaluating their effectiveness. Laboratory tests are used to rate the relative efficiency of potassium chloride vs other salts and organic compounds. Advantages and limitations of the various clay stabilizers are described. These studies show that increased temperature improves the efficiency or KCI and that pH Is not a significant factor, except In low-salinity solutions. Alternate materials are sometimes superior to KCI, but care must be taken when using substitute products.


The control of clay swelling and migration is an important consideration in the design of any stimulation treatment. The response of water-sensitive formations to contact with stimulation fluids can exert a major influence upon ultimate well productivity. It is important to carefully evaluate formation sensitivity and select the most compatible completion and stimulation fluids.

References and illustrations at end of paper.

Clay stabilizers are routinely added to aqueous stimulation and completion fluids to prevent damage to the formation. These clay stabilizers can be of either a temporary or permanent type and are often used in combination. Temporary clay stabilizers are materials such as KCI, NH4CI, CaCI2 and NaCI which, when added to fresh water, prevent the injected fluid from swelling or dispersing clays. While these products prevent aqueous treating fluids from damaging the formation, they provide no long-term protection.

Permanent clay stabilizers, such as zirconium salts, hydroxyl-aluminum and certain polycationic polymers, irreversibly attach to action exchange sites on the clays and are not displaced by other actions present in formation water. These materials permanently stabilize sensitive clays. The permanent clay stabilizers are usually applied using a carrier fluid containing a temporary stabillzer, such as KCI, to prevent the carrier fluid itself from damaging the formation.

Of the temporary clay stabilizers, KCI is the product most commonly used. It is quite effective and is routinely added to aqueous fracturing fluids at concentrations or 1% to 3%. Other salts, such as NaCI, NH4CI and CaCI2, have also occasionally been used. Recently, some organic compounds have also been proposed for this application.

Jones1 was one of the first to perform water sensitivity studies and concluded that formation damage resulted from abrupt changes in salinity between the fluid naturally present in the formation and any injected fluid. He found that damage could be prevented by adding salts to water injected into the formation. Mungan2 also studied this problem and showed that damage was a function of the rate of salinity change, and that it could be completely prevented if this rate of change was sufficiently slow. Damage observed during his core tests was most pronounced at the entry end of the core and diminished with increased distance from the fluid entry point. This is a result of fluid mixing during flow through the core, thus reducing the ionic shock effect. During long-term water injection procedures, one might expect similar mixing to reduce the tendency toward formation damage.

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