Effect of Acid Corrosion Inhibitors On Matrix Stimulation Results
- C.W. Crowe (Dowell Div. of Dow Chemical U.S.A.) | S.S. Minor (Dowell Div. of Dow Chemical U.S.A.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1985
- Document Type
- Journal Paper
- 1,853 - 1,860
- 1985. Society of Petroleum Engineers
- 3.2.4 Acidising, 4.1.2 Separation and Treating, 2.5.2 Fracturing Materials (Fluids, Proppant), 2 Well Completion, 4.2.3 Materials and Corrosion, 1.8 Formation Damage, 1.6.9 Coring, Fishing, 5.4.10 Microbial Methods
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Acid corrosion inhibitors provide protection by adsorbing on metal surfaces, thus forming a barrier against acid attack. On entering the formation, the inhibitor strongly adsorbs on clays and other minerals present within the matrix of the rock. In some cases. inhibitors contain acid-insoluble residues that can cause surface plugging of the formation face. Inhibitor adsorption and formation plugging by inhibitor residues can have a major influence on plugging by inhibitor residues can have a major influence on cleanup rate and on the ultimate effective permeability of the treated zone. Consequently, acid corrosion inhibitors should be evaluated both for their ability to protect metal and for their potentially damaging effect on stimulation results. Laboratory tests with a computerized core-test permeameter demonstrate the strong influence of acid permeameter demonstrate the strong influence of acid inhibitors on acid injectivity, cleanup rate, and stabilized, long-term effective permeability. The adsorption characteristics of the inhibitor were shown to influence test results significantly. The beneficial effects of mutual solvent on injection rate and, in some cases, well cleanup were demonstrated also. Data showing the influence of temperature, differential pressure, and mutual solvent on injectivity, cleanup rate, and apparent stabilized oil permeability are presented. Various inhibitors were evaluated under a presented. Various inhibitors were evaluated under a variety of test conditions. In general, damage resulting from the corrosion inhibitors was more pronounced at lower temperatures, and mutual solvents reduced the magnitude of the problem.
Corrosion inhibitors are used routinely in acidizing to prevent acid attack on tubing, and other downhole metal prevent acid attack on tubing, and other downhole metal equipment. These inhibitors tenaciously adsorb on metallic surfaces, thus forming a protective film between the acid and metal. Acid inhibitors are normally evaluated only for their ability to control acid corrosion under simulated treating conditions. Formation damage resulting from insoluble materials in the inhibitor and from inhibitor adsorption on clays and other minerals present in the matrix of the rock is seldom considered. This is unfortunate because most of the inhibitor is adsorbed eventually within the formation instead of on the metal surfaces it is designed to protect. Adsorbed inhibitor can produce altered wettability or can result in severe emulsion problems, resulting in slow or incomplete cleanup after the treatment.
Acid corrosion inhibitors usually are rather complex in nature and commonly consist of such materials as amines, quaternary amines, various nitrogen heterocyclics, thioureas. Mannich reaction products, sulfonium salts, and acetylenic alcohols. They usually contain surfactants to disperse the inhibitor in the acid and solvents necessary to formulate the product. Cationic in nature, the various nitrogen compounds strongly adsorb on clay surfaces. The surfactants also adsorb on the clays. These adsorbed materials can have a major influence on cleanup rate and, in some cases, the long-term capacity of the well.
Laboratory Test Method
To study the effect of inhibitor adsorption on acid injectivity and cleanup, laboratory tests designed to simulate well treatments were performed. The equipment used in these tests is described in Fig. 1. The test sequence basically consisted of the determination of the apparent permeability to oil of a previously brine-saturated Berea sandstone core. Treating acid that contained the inhibitor was then injected from the opposite direction. Flow of oil from the original direction was resumed and continued until a stable flow rate was established. Test results were monitored carefully by a minicomputer that recorded time, flow rate, cumulative flow, and differential pressure across the core; it also calculated the effective permeability. Of primary interest in these tests were the effect of inhibitor on acid injectivity. the effect of inhibitor on cleanup rate, and the effect of inhibitor on final effective permeability. Acid corrosion inhibitors evaluated in this study and a general description of their chemical composition are listed in Table 1. Selected inhibitors were commercial products that are commonly used; they represented a products that are commonly used; they represented a broad spectrum of chemical types. For example, Inhibitor A contained only acetylenic alcohol and was nonionic: consequently, it showed little, if any, adsorption on clay surfaces. Other inhibitors tested were at least partially cationic and exhibited various degrees of adsorption.
Test Conditions. A detailed description of the core test procedure is provided in the Appendix. Although both procedure is provided in the Appendix. Although both 15% HCl and 12% HCl/3% HF acids were used in these studies, the majority of the tests were performed with HCl because these tests were more reproducible. Tests were performed in duplicate or triplicate to confirm performed in duplicate or triplicate to confirm reproducibility of the data.
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